United States
Environmental Protection
Agency
EPA-452/R-96-001giX
June 1996
Air
Mercury Study
Report to Congress
Volume VII:
An Evaluation of Mercury
Control Technologies and Costs
SAB REVIEW DRAFT
oEPA
Office of Air Quality Planning ft Standards
and
Office of Research and Development
C66011-2-7
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MERCURY STUDY REPORT TO CONGRESS
VOLUME VII:
AN EVALUATION OF MERCURY CONTROL
TECHNOLOGIES AND COSTS
SAB REVIEW DRAFT
June 1996
U.S. Environmental Protection Agency
Region 5, Library (PL-12J)
77 West Jackson Boulevard, 12th Floor
Chicago, IL 60604-3590
Office of Air Quality Planning and Standards
and
Office of Research and Development
U.S. Environmental Protection Agency
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v t TABLE OF CONTENTS
Vv U.S. EPA AUTHORS iii
t-j SCIENTIFIC PEER REVIEWERS iv
o LIST OF TABLES vi
^ LIST OF FIGURES viii
LIST OF SYMBOLS, UNITS .AND ACRONYMS .' ix
EXECUTIVE SUMMARY ES-1
1. INTRODUCTION 1-1
4
1.1 Risk Management Principles 1-1
1.2 Report Organization 1-2
2. MERCURY CONTROLS 2-1
2.1 Pollution Prevention and Other Management Measures 2-1
2.1.1 Product Substitution 2-1
2.1.2 Process Modification for Mercury Cell Chlor-Alkali Plants 2-6
2.1.3 Materials Separation 2-7
2.1.4 Coal Cleaning 2-10
2.1.5 Other Management Measures 2-11
2.2 Flue Gas Treatment Technologies 2-13
2.2.1 Carbon Filter Beds 2-13
2.2.2 Wet Scrubbing 2-17
2.2.3 Depleted Brine Scrubbing 2-19
2.2.4 Treated Activated Carbon Adsorption 2-19
2.2.5 Selenium Filters 2-20
2.2.6 Activated Carbon Injection , 2-22
2.3 Activated Carbon Injection for Utility Boilers 2-24
2.3.1 Utility Flue Gas Factors Affecting Mercury Removal 2-25
2.3.2 Current Research on Activated Carbon Injection for Utilities 2-31
2.4 Emerging Technologies for Controlling Mercury Emissions from Utilities 2-31
3. COST AND FINANCIAL IMPACTS OF MERCURY CONTROLS 3-1
3.1 Cost Effectiveness 3-1
3.2 Financial Analysis 3-1
3.2.1 Methodology 3-1
3.2.2 Results 3-6
4. MERCURY CONTROL STRATEGIES 4-1
4.1 Ongoing Federal and State Activities 4-1
4.1.1 Federal Activities 4-1
4.1.2 State Activities 4-8
4.2 Management Alternatives and Statutory Authorities 4-15
4.2.1 Management Alternatives 4-15
4.2.2 Clean Air Act Authorities 4-17
June 1996 i , SAB REVIEW DRAFT
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TABLE OF CONTENTS (continued)
Page
5. CONCLUSIONS 5-1
6. RESEARCH NEEDS 6-1
7. REFERENCES 7-1
APPENDIX A TEST DATA ON THE EFFECTIVENESS OF ACTIVATED
CARBON INJECTION FOR UTILITY BOILERS A-l
APPENDIX B MODEL PLANT COST EVALUATION B-l
June 1996 ii - SAB REVIEW DRAFT
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U.S. EPA AUTHORS
Martha H. Keating
Office of Air Quality Planning and Standards
.Research Triangle Park, NC
William H. Maxwell, P.E.
Office of Air Quality Planning and Standards
Research Triangle Park, NC
June 1996 iii SAB REVIEW DRAFT
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SCIENTIFIC PEER REVIEWERS
Brian J. Alice, Ph.D.
Harza Northwest, Incorporated
Thomas D. Atkeson, Ph.D.
Florida Department of Environmental
Protection
Steven M. Bartell, Ph.D.
SENES Oak Ridge, Inc.
Mike Bolger, Ph.D.
U.S. Food and Drug Administration
James P. Butler, Ph.D.
University of Chicago
Argonne National Laboratory
Rick Canady, Ph.D.
Agency for Toxic Substances and Disease
Registry
Rufus Chaney, Ph.D.
U.S. Department of Agriculture
Tim Eder
Great Lakes Natural Resource Center
National Wildlife Federation for the
States of Michigan and Ohio
William F. Fitzgerald, Ph.D.
University of Connecticut
Avery Point
Robert Goyer, Ph.D.
National Institute of Environmental Health
Sciences
George Gray, Ph.D.
Harvard School of Public Health
Terry Haines, Ph.D.
National Biological Service
Joann L. Held
New Jersey Department of Environmental
Protection & Energy
Gerald J. Keeler, Ph.D.
University of Michigan
Ann Arbor
Leonard Levin, Ph.D.
Electric Power Research Institute
Malcom Meaburn, Ph.D.
National Oceanic and Atmospheric
Administration
U.S. Department of Commerce
Paul Mushak, Ph.D.
PB Associates
Jozef M. Pacyna, Ph.D.
Norwegian Institute for Air Research
Ruth Patterson, Ph.D.
Cancer Prevention Research Program
Fred Gutchinson Cancer Research Center
Donald Porcella, Ph.D.
Electric Power Research Institute
Charles Schmidt
U.S. Department of Energy
Pamela Shubat, Ph.D.
Minnesota Department of Health
Alan H. Stern, Dr.P.H.
New Jersey Department of Environmental
Protection & Energy
Edward B. Swain, Ph.D.
Minnesota Pollution Control Agency
M. Anthony Verity, M.D.
University of California
Los Angeles
June 1996
IV
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WORK GROUP AND U.S. EPA/ORD REVIEWERS
Core Work Group Reviewers:
Dan Axelrad, U.S. EPA
Office of Policy, Planning and Evaluation
Angela' Bandemehr, U.S. EPA
Region 5
Jim Darr, U.S. EPA
Office of Pollution Prevention and Toxic
Substances
Thomas Gentile, State of New York
Department of Environmental Conservation
Arnie Kuzmack, U.S. EPA
Office of Water
David Layland, U.S. EPA
Office of Solid Waste and Emergency
Response
Karen Levy, U.S. EPA
Office of Policy Analysis and Review
Steve Levy, U.S. EPA
Office of Solid Waste and Emergency
Response
Lorraine Randecker, U.S. EPA
Office of Pollution Prevention and Toxic
Substances
Joy Taylor, State of Michigan
Department of Natural Resources
U.S. EPA/ORD Reviewers:
Robert Beliles, Ph.D., D.A.B.T.
National Center for Environmental Assessment
Washington, DC
Eletha Brady-Roberts
National Center for Environmental Assessment
Cincinnati, OH
Annie M. Jarabek
National Center for Environmental Assessment
Research Triangle Park, NC
Matthew Lorber
National Center for Environmental Assessment
Washington, DC
Susan Braen Norton
National Center for Environmental Assessment
Washington, DC
Terry Harvey, D.V.M.
National Center for Environmental Assessment
Cincinnati, OH
June 1996
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LIST OF TABLES
Page
ES-1 Cost Effectiveness of Control Technologies ES-2
ES-2 Estimated Annual Revenues and Potential Cost Increases for MWCs, MWIs and Lead
Smelters ES-5
ES-3 Estimated Annual Profits, Expenditures, Revenues and Financial Impacts. . ES-6
ES-4 Model Utility Boilers: Estimated Annual Revenues and Potential Cost Increases ES-7
ES-5 Potential Mercury Emission Reductions and Costs for Selected Source Categories .... ES-13
2-1 Summary of Mercury Control Techniques for Selected Source Types 2-2
2-2 Comparison of Typical Uncontrolled Flue Gas Parameters at Utilities and MWCs 2-24
2-3 Mercury Speciation in 33 Samples of Coal-Fired and 3 Samples of Oil-Fired Utility
Flue Gas 2-28
3-1 Cost Effectiveness of Control Technologies 3-4
3-2 Estimated Annual Revenues and Potential Cost Increases for MWCs, MWIs and Lead
Smelters 3-7
3-3 Estimated Annual Profits, Expenditures, Revenues and Financial Impacts 3-9
3-4 Model Utility Boilers: Estimated Annual Revenues and Potential Cost Increases 3-11
4-1 Federal Mercury Controls 4-2
4-2 Examples of State Mercury Controls 4-9
4-3 Potential Mercury Emission Reductions and Costs for Selected Source Categories 4-19
A-l Activated Carbon Injection Before Fabric Filter Data A-2
A-2 Activated Carbon Injection Before Spray Dryer Absorption Data A-4
B-l Cost Estimates for Activated Carbon Injection on MWCs B-3
B-2 Sensitivity Analysis for Activated Carbon Injection System on MWCs B-4
B-3 Cost Estimate for Carbon Filter Bed on MWCs B-6
B-4 Sensitivity Analysis for a Carbon Filter Bed System on MWCs B-7
B-5 Cost Estimate for a Polishing Wet Scrubbing System on MWCs B-8
B-6 Sensitivity Analysis for a Polishing Wet Scrubbing System on a MWCs B-9
B-7 Cost Estimate for Activated Carbon Injection on MWIs B-ll
B-8 Sensitivity Analysis for an Activated Carbon Injection System on MWIs B-12
B-9 Cost Estimate for a Polishing Wet Scrubbing Systam on MWIs B-l3
B-10 Sensitivity Analysis for a Wet Scrubbing System on MWIs B-14
B-ll Model Utility Boilers and Mercury Controls Used in Cost Analysis B-15
B-12 Carbon Injection Rates for Utility Boiler Models with Mercury Control B-17
B-l3 Cost Estimates for Applying a Carbon Injection System on 975- and 100-MW Coal-
Fired Utility Boilers B-19
B-14 Cost Estimates for Applying a Carbon Injection System in Conjunction with a Spray
Cooler and a Fabric Filter on a 975-MW Coal-Fired Utility Boiler (Model Ib) B-20
B-15 Cost Estimates for Applying a Carbon Injection System in Conjunction with a Spray
Cooler and a Fabric Filter on a 100-MW Coal-Fired Utility Boiler (Model 3b) B-21
B-l6 Cost Estimates for Applying a Carbon Injection System in Conjunction with a Spray
Cooler on a 975-MW Coal-Fired Utility Boiler (Model Ic) B-22
B-17 Sensitivity Analysis for Carbon Injection on Coal-Fired Utility Boilers with Different
Ratios of Elemental to Oxidized Mercury B-23
B-18 Sensitivity Analysis for Carbon Injection Feed Rates on Utility Boilers B-24
B-19 Cost Estimates for a Carbon Filter Bed on Utility Boilers B-25
B-20 Cost Estimates for a Depleted Brine Scrubbing on a Mercury Cell Chlor-Alkali Plant . . B-28
B-21 Cost Estimates for Treated Activated Carbon Adsorption on a Mercury Cell Chlor-
Alkali Plant B-29
June 1996 vi SAB REVIEW DRAFT
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LIST OF TABLES (continued)
Page
B-22 Cost Estimates for Selenium Filters on a Copper Smelting Plant B-31
B-23 Sensitivity Analysis for Selenium Filters on a Copper Smelting Plant B-32
B-24 Cost Estimate for a Selenium Filter on a Lead Smelting Plant (Sintering Stream) B-34
B-25 Cost Estimate for a Selenium filter on a Lead Smelting Plant (Furnace Stream) B-35
B-26 Sensitivity Analysis for Selenium Filters on a Lead Smelter Sintering Stream B-37
B-27 Sensitivity Analysis for Selenium filters on a Lead Smelter Furnace Stream B-37
June 1996 vii SAB REVIEW DRAFT
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LIST OF FIGURES
Page
2-1 Mercury Cell Replacement with Membrane Cells for Chlor-Alkali Production Facilities . . 2-7
2-2 Carbon Filter Bed Design 2-14
2-3 Comparison of Mercury Removal Efficiencies with Activated Carbon Injection 2-26
B-l Spray Cooling System B-16
B-2 Carbon Injection System B-16
June 1996 viii SAB REVIEW DRAFT
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LIST OF SYMBOLS, UNITS AND ACRONYMS
AC
APCD
ASME
CAA
CaS
cf
CFB
cm
CRF
dscf
dscm -
ESP
DSl
EPRI
FFDCA
FFs
FGD
FIFRA
FWS
GACT
GLFCATF
GLNPO
g
gr
HAPs
HC1
Hg
HgCl
Hgl
HgO
HgS
HgSe
HMTA
HVAC
IDLH
INGAA
kg
kW
MACT
MB
MCL
Mg
MSW
MW
MWCs
MWIs
Activated carbon
Air pollution control device
American Society of Mechanical Engineers
Clean Air Act as Amended in 1990
Calcium sulfide
Cubic feet
Circulating fluidized bed
Cubic meter
Capital recovery factor
Dry standard cubic feet
Dry standard cubic meter
Electrostatic precipitator
Dry sorbent injection
Electric Power Research Institute
Federal Food, Drug, Cosmetic Act
Fabric filters
Flue gas desulfurization
Federal Insecticide, Fungicide, Rodenticide Act
U.S. Fish and Wildlife Service
Generally available control technology
Great Lakes Fish Consumption Advisory Task Force
Great Lakes National Program Office
Gram
Grains
Hazardous air pollutants
Hydrochloric acid
Mercury
Mercuric chloride •
Mercuric iodide
Mercuric oxide
Mercuric sulfide
Mercuric selenite
Hazardous Materials Transportation Act
Heating, ventilating and air conditioning
Immediately dangerous to life and health
Interstate Natural Gas Association Of America
Kilogram
Kilowatt
Maximum achievable control technology
Mass burn
Maximum contaminant level
Megagram
Municipal solid waste
Megawatt
Municipal waste combustors
Medical waste incinerators
June 1996
IX
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LIST OF SYMBOLS, UNITS AND ACRONYMS
(continued) .
NaCl Sodium chloride
NaOH Sodium hydroxide
ng Nanogram
NIOSH National Institute for Occupational Safety and Health
Nm Normal cubic meter
NOAA National Oceanic and Atmospheric Administration
NPDES National Pollutant Discharge Elimination System
NSP Northern States Power
NSPS New source performance standard
OAQPS Office of Air Quality Planning and Standards (U.S. EPA)
OECD Organization for Economic Co-operation and Development
O&M Operation and maintenance '
OSHA Occupational Safety and Health Administration
PCBs Polychlorinated biphenyls
PELs Permissible exposure limits
PM Paniculate matter
ppm parts per million
ppmv parts per million by volume
RQ Reportable quantity
SARA Superfund Amendments and Reauthorization Act
scf Standard cubic feet
scm Standard cubic meter
SD Spray dryer
SDAs Spray dryer absorbers
TCC Total capital cost
TCLP Toxicity characteristic leaching procedure
TMT Trimercapto-s-triazine
tpd Tons per day
TRI Toxic Release Inventory •
ug Microgram
UNDEERC University of North Dakota Energy and Environmental Research Center
WS Wet scrubber
WW Waterwall
June 1996
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EXECUTIVE SUMMARY
Section 112(n)(l)(B) of the Clean Air Act (CAA), as amended in 1990, requires the U.S.
Environmental Protection Agency (U.S. EPA) to submit a study on atmospheric mercury emissions to
Congress. The sources of emissions that must be studied include electric utility steam generating
units, municipal waste combustion units and other sources, including area sources. Congress directed
that the Mercury Study evaluate many aspects of mercury emissions, including the rate and mass of
emissions, health and environmental effects, technologies to control such emissions and the costs of
such controls.
In response to this mandate, U.S. EPA has prepared a seven-volume Mercury Study Report to
Congress. This report — Volume VII of the Mercury Study Report to Congress - provides
information on mercury control technologies, associated costs and regulatory issues. It describes and
analyzes additional technologies that could bring about reductions of mercury emissions, and existing
state and federal programs that control the use and release of mercury. This, report also describes
management alternatives and U.S. EPA's statutory authority to control mercury emissions under the
CAA.
Control Technologies and Associated Costs and Impacts
This report focuses on mercury control technologies, costs, and financial impact estimates for
six industries: municipal waste combustors (MWCs), medical waste incinerators (MWIs), utility
boilers, chlor-alkali plants, primary copper smelters and primary lead smelters. These source
categories were chosen for control technology and cost analyses on the basis of either their source
category emissions in the aggregate or their potential to be significant point sources of emissions.
Consideration was also given to whether a particular source category was a feasible candidate for
application of control technology (e.g., fluorescent lamp breakage would not be considered an
appropriate mercury emission source category for a technology-based standard under section 112 of the
Clean Air Act). Although this narrowed the analyses to a certain group of source categories, it was
believed that this approach would give an overall sense of what could be required in terms of
technologies and costs for the selected source categories. •
Control technology performance and cost information was obtained from the literature and
pollution control technology vendors to develop cost effectiveness values for the various mercury
controls applied to model plants for each industry. The estimated cost effectiveness values represent
generalized costs and are not intended to be site-specific. Table ES-1 summarizes the results of the
cost analysis. For each of the six emission sources, the applicable mercury controls and the estimated
level of control and cost effectiveness are presented in units of dollars per pound of mercury removed
and other measures (e.g., dollars per pound of medical waste incinerated for MWIs and dollars per
pound of copper produced for primary copper smelters).
The financial impact of mercury controls was determined for each of the model plants
representing the six industries examined. Affordability was based on financial ratios that were
determined on the basis of whether an industry could pass the cost of mercury control on to
consumers. For industries that can potentially pass control costs onto consumers (MWCs, MWIs and
utility boilers), affordability was determined based on the ratio of total annual control costs to
revenues. This ratio defines the potential increase in service price arising from the mercury control
costs. For two of the industries that have little control over the price they are able to receive for their
products and thus cannot pass mercury control costs on to consumers (chlor-alkali plants and primary
June 1996 ES-1 SAB REVIEW DRAFT
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Table ES-1
Cost Effectiveness of Control Technologies
Source
Mercury Control
Technique
Cost Effectiveness
$/lh Hg Removed
Other Measures
Cost Comments
MWCs
Material separation
(batteries)
Production substitution
(e.g., batteries, fluorescent
lights)
Activated carbon injection
Carbon filter beds
Polishing wet scrubber
1,450
$0.37/ton MSW
211-870
513-1,083
1,600-3,320
$0.7-3.5/ton MSW
$5.44-9.39/1011 MSW
$5.3-13.5/ton MSW
Costs are very community specific; Results shown
are based on one community's program
The potential for product substitutions requires (hat
the specific circumstances of each situation be
examined; general cost estimates are not possible
Costs assume an 85% reduction; range of costs
cover the two model plants
Range of costs cover the two model plants
Costs assume an 85 percent reduction; range of
costs cover the two model plants
MWls
Material separation
(batteries)
Activated carbon injection
Polishing wet scrubber
228-955
310
$10.3-43/ton
medical waste
$12/lon
medical waste
Costs vary on a site-specific basis; no costs were
available; cost effectiveness for a hospital program
would be assumed to be better than for a
community program
Costs assume an 85 percent mercury reduction; acid
gas controls are assumed to be in place; range of
costs cover the two model plants
Costs developed for die large model plant only (see
box on page 3-2 and 3-3); acid gas controls are
assumed to be in place
June 1996
ES-2
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Table ES-1
Cost Effectiveness of Control Technologies
(continued)
Source
Utility Boilers
Chlor-Alkali Plants
Using Mercury Cell
Process
Primary Copper
Smelters
Primary Lead
Smellers
Sintering Stream
Furnace Stream
Mercury Control
Technique
Carbon tiller beds
Activated carbon injection
(coal fired) 100% of Hg as
HgCI2
80% of Hg as HgCl2
50% of Hg as HgCI2
30% of Hg as HgCI2
Process modification
Depleted brine scrubbing
Treated activated carbon
adsorption
Selenium filters
Selenium filters
Selenium tillers
Cost Effectiveness
$/lb Hg Removed
33,000-38,000
4,970-27,700
6,190-34,600
9,840-55,400
16,300-92,000
4,590
1,040
•
769
497
541
520
Olher Measures
2.7-3.1 mills/kWh
0.41-2.26
0.41-2.26
0.40-2.25
0.40-2.25
$39.6/lon chlorine
produced
$6.7/t0n chlorine
produced
$5.1 /ton chlorine
produced
$ 1 1 .3/lon copper
produced
$2.7/l0n lead produced
$5.8/ion lead produced
Cost Comments
Range of costs covers two model plants (Models Id
and 2 in (lie box on page ES-2)
Range of costs covers model plants burning coal
(Models la, 3a, Ib, 3b and Ic)
Cost effectiveness calculated using capital and
electrical costs only
Cosl dala were scaled from 1972 dollars
Cost dala were scaled from 1972 dollars
Cosl dala and information on mercury emissions al
copper smellers are very limited
Cosl dala and infonnalion on mercury emissions al
lead smellers are very limited
Cosl dala and information on mercury emissions al
lead smellers are very limited
June 1996
ES-3
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copper smelters), financial impact was determined based on both the ratio of total annual control cost
to profits and the ratio of annual capital costs to total annual expenditures. These ratios define the
financial impact of installing and operating the mercury controls. Information on profits and
expenditures was not available for the primary lead smelter industry. Consequently, financial impact
was estimated as the price increase in lead necessary to recover the control costs based on the ratio of
total annual control costs to revenues.
The estimated financial impact of mercury controls for each industry examined is in Tables
ES-2 and ES-3. These tables also present estimated annual revenues, profits and expenditures that
were used to determine affordability.
For utility boilers, potential cost increases were calculated for a total of seven control
technology-model plant combinations. The results of the financial analysis for utility boilers are
summarized in Table ES-4.
Existing Federal and State Control Programs
Several federal agencies have authority and responsibility for controlling mercury uses,
releases and exposures. For example, U.S. EPA has addressed for many years and continues to
address the risks posed by mercury through regulations designed to limit releases to air, water and
land. These regulations have been promulgated under the authority of the Safe Drinking Water Act,
the Clean Water Act, the Clean Air Act, the Resource Conservation and Recovery Act and the
Comprehensive Environmental Response, Compensation, and Liability Act. Other federal agencies
that have mercury-related standards include the Food and Drug Administration (which regulates
mercury in cosmetics, food and dental products), the Occupational Safety and Health Administration
(which regulates mercury exposures in the workplace) and the Department of Transportation (which
limits the potential for mercury releases during transportation). In general, existing federal standards
can be categorized as environmental media standards, environmental source controls, or product
controls.
Mercury control regulations are increasing rapidly at the state level. Many states are
developing new regulations that will control the release of«mercury from different environmental
sources. Minnesota, for example, is currently drafting management standards for facilities that recycle
mercury-containing waste and has proposed new combustion rules. States also have developed new
monitoring and reporting requirements on mercury release from air and water point sources. In
addition to health-based concerns, states are focusing on waste disposal problems associated with
mercury-containing products. Many states have regulations that ban or limit the amount of mercury in
products, establish recycling requirements and impose disposal restrictions on products containing
mercury. For example, certain types of batteries containing mercury are banned in a number of states
and 12 states have enacted laws that limit the amount of mercury in alkaline batteries to 0.025 percent
by weight.
Management Alternatives
Effective control of mercury emissions may require a mix of strategies including pollution
prevention, materials separation and conventional regulatory strategies to control mercury emissions at
the stack. Pollution prevention would be suitable for those processes or industries where a mercury
substitute is demonstrated and available (e.g., mercury cell chlor-alkali plants). Material separation is
an appropriate approach for processes where mercury-containing products are disposed of by
incineration, or where mercury can be reduced in the fuel prior to the fuel being combusted (e.g.,
June 1996 ES-4 SAB REVIEW DRAFT
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Table ES-2
Estimated Annual Revenues and Potential Cost Increases'* for MVVCs, MVVIs and Lead Smelters
Parameter
Total Annual Revenues
(millions of dollars)
Potential Cost Increases
Activated Carbon
Injection
Carbon Filter
Beds
Selenium Filter
Municipal Waste
Combustors
Smallb: $3.4
Largec: $38
Smallb: 6.9%
Largec: 1.3%
Smallb: 83%
Largec: 35%
N/Ad
Medical Waste Incinerators
Hospital: $32.5
Commercial: $2.0
Hospital: 0.02%
Commercial: 2.0%
_.e
__e
N/A
Primary Lead Smelters
$66.8
N/A
N/A
1.3%
a Potential cost increase = total annual operating cost divided by total annual revenue. Represents the potential cost increase in service or product to cover the cosl of controls.
b Capacity = 180 Mg/day. •
c Capacity = 2,045 Mg/day.
d N/A = control technology is not applicable.
e The costs of the carbon filter beds were not estimated for this model plant.
June 1996
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Table ES-3
Estimated Annual Profits, Expenditures,
Revenues and Financial Impacts9
Parameter
Total Annual Profits
(millions of dollars)
Total Annual Expenditures
(millions of dollars)
Financial Impact
Membrane Cell Process
Depleted Brine
Scrubbing
Treated Activated
Carbon Adsorption
Selenium Filters
Chlor-Alkali Plants
$12.9
$26.7
12% of Expenditures
5.1% of Profits
0.7% of Expenditures
3.9% of Profits
0.5% of Expenditures
N/A
Primary Copper
Smelters
$22.0
$204
N/Ah
N/A
N/A
4.4% of Profits
0.2%) of Expenditures
a Financial impact = total annual control costs divided by profits and annual capital costs divided by total expenditures.
N/A = control technology is not applicable.
Note: The percentage of annual profits represents the amount of profit that would be needed to absorb the control costs. The percentage of annual expenditures provides a
measure of the industry's ability to acquire the capital needed for the controls while still remaining competitive.
June 1996
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Table ES-4
Model Utility Boilers: Estimated Annual Revenues and Potential Cost Increases3
Modelb
la
Ib
Ic
Id
2
3a
3b
Size
(MW)
975
975
975
975
975
100
100
Fuel
Low-sulfur coal
Low-sulfur coal
Low-sulfur coal
Low-sulfur coal
High-sulfur coal
Low-sulfur coal
Low-sulfur coal
Prc-Existing
Controls
ESP
ESP
ESP
ESP
ESP/FGD
ESP
ESP
Estimated
Revenues
($ Million)
287
287
287
287
287
29
29
Mercury Control
AC injection1-
Spray cooler, AC injection, FF
Spray cooler, AC injection
Carbon filter bed
Carbon filter bed
AC injection
Spray cooler, AC injection, FF
Annual
Control Costs
. ($ Million)
10.1
7.9
2.4
59.9
60.7
0.64
1.3
Potential Cost
Increase
%
3.5
2.8
0.8
21
21
2.2
4.4
a Potential cost increase = total annual operating costs divided by total annual revenues, which represents (he potential increase in electricity costs to cover the costs ol' conliol.
b See model plant description in box on pages 3-2 mid 3-3 as wetl as Appendix B.
c AC = activated carbon.
June 1996
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medical waste incineration). The third approach, conventional regulatory strategies, may be applicable
when mercury is emitted to the environment as a result of trace contamination in fossil fuel or other
essential feedstock in an industrial process (e.g., smelting). Other non-traditional approaches such as
emissions trading or application of a use tax, or other market-based approaches may also prove
feasible for mercury control. In addition, emissions control is only one possible means for risk
control: reduced human exposure, for example through the use of fish advisories, is another alternative
that would need to be explored when selecting among strategies for reducing risks to human health
(though not to ecosystems).
The analyses of control technologies and costs presented in this Report are not intended to
replace a thorough regulatory analysis, as would be performed for a rulemaking. The information
presented is intended to present the range of available options and provide a relative sense of the
extent of mercury reductions achievable and the general magnitude of the cost of such reductions.
The three major types of control techniques reviewed are:
• Pollution prevention measures, including product substitution and process modification:
• Materials separation; and
• Flue gas treatment technologies.
Pollution Prevention Measures
One possible means of achieving reductions in mercury emissions is through the use of
pollution prevention or source reduction. Such approaches to achieving reductions involve changes in
processes or inputs to reduce or eliminate emissions of mercury from a particular product or process.
They could include, for example, the replacement of mercury with an appropriate substitute or the use
of low-mercury content inputs.
In considering opportunities for pollution prevention or source reduction it is important to
consider both the potential reductions achievable and the cpsts of these options. Any consideration of
the potential reductions, should examine whether (and the extent to which) emission reductions from
the particular sources in question will yield reductions in risk to public health and the environment. It
is also essential to understand the costs associated with implementing a pollution prevention measure,
including any changes in the quality of the end product.
Materials Separation
Removing mercury-containing products such as batteries, fluorescent lights and thermostats
from the waste stream can reduce the mercury input to waste combustors without lowering the energy
content of the waste stream. The mercury removal efficiency would vary, however, depending on the
extent of the separation. Many materials in wastes contain mercury. Materials that comprise a large
portion of the waste stream, such as paper, plastic, dirt and grit and yard waste, contain very low
concentrations of mercury. Therefore, obtaining appreciable mercury reduction from separation of
these types of materials would require separating a large fraction of the total waste stream. Separating
these materials would counter the intended purpose of the combustion process, which is to disinfect
and reduce the volume of waste materials.
June 1996 ES-8 SAB REVIEW DRAFT
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Other materials contain higher concentrations of mercury, but make up only a very small
portion (less than 1 percent) of the waste stream. These materials include mercuric oxide batteries,
fluorescent lights, thermostats and other electrical items. Separation of such materials can reduce
mercury input to a combustor without removing any of the energy content of the waste stream. To
evaluate a materials separation program, the feasibility and costs of separating a particular material
should be compared with the mercury emission reduction achieved. Furthermore, the current and
future mercury reduction achieved by separating a certain material should be considered since the
mercury contribution of some materials such as household batteries has already declined considerably
Coal cleaning is another option for removing mercury from the fuel prior to combustion. In
some states, certain kinds of coal are commonly cleaned to increase its quality and heating value.
Approximately 77 percent of the eastern and midwestern bituminous coal shipments are cleaned in
order to meet customer specifications for heating value, ash content and sulfur content.
There are many types of cleaning processes, all based on the principle that coal is lighter than
the pyritic sulfur, rock, clay, or other ash-producing impurities that are mixed or embedded in it.
Mechanical devices using pulsating water or air currents can physically stratify and remove impurities.
Centrifugal force is sometimes combined with water and air currents to aid in further separation of
coal from impurities. Another method is dense media washing, which uses heavy liquid solutions
usually consisting of magnetite (finely ground particles of iron oxide) to separate coal from impurities.
Smaller sized coal is sometimes cleaned using froth flotation. This technique differs from the others
because it focuses less on gravity and more on chemical separation.
Some of the mercury contained in coal may be removed by coal cleaning processes. Volume
II of this report (An Inventory of Anthropogenic Mercury Emissions in the United States) presents
available data on the mercury concentrations in raw coal, cleaned coal and the percent reduction
achieved by cleaning. These data, which cover a number of different coal seams in four states
(Illinois, Pennsylvania, Kentucky and Alabama), indicate that mercury reductions range from 0 to 64
percent, with an overall average reduction of 21 percent. This variation may be explained by several
factors, including different cleaning techniques, different mercury concentrations in the raw coal and
different mercury analytical techniques. It is expected that significantly higher mercury reductions can
be achieved with the application of emerging coal preparation processes. These include selective
agglomeration and advanced column flotation. Bench-scale testing is also being carried out to
investigate the use of naturally-occurring microbes to reduce the mercury and other trace elements
from coal.
Any reduction in mercury content achieved by coal cleaning results in a direct decrease in
mercury emissions from boilers firing cleaned coals. The mercury removed by cleaning processes is
transferred to coal-cleaning wastes, which are commonly in the form of slurries. No data are available
to assess the emissions of mercury from coal-cleaning slurries.
Flue Gas Treatment Technologies
With the exception of mercury, most metals have sufficiently low vapor pressures at typical air
pollution control device operating temperatures that condensation onto paniculate matter is possible.
Mercury, on the other hand, has a high vapor pressure at typical control device operating temperatures,
and collection by paniculate matter control devices is highly variable. Factors that enhance mercury
control are low temperature in the control device system (less than 150 "Celsius [°C] [300 to 400
°Fahrenheit (°F)]), the presence of an effective mercury sorbent and a method to collect the sorbent.
In general, high levels of carbon in the fly ash enhance mercury sorption onto paniculate matter which
June 1996 ES-9 SAB REVIEW DRAFT
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is subsequently removed by the paniculate matter control device. Additionally, the presence of
hydrogen chloride (HC1) in the flue gas stream can result in the formation of mercuric chloride
(HgCl2), which is readily adsorbed onto carbon-containing paniculate matter. Conversely, sulfur
dioxide (SCb) in flue gas can act as a reducing agent to convert oxidized mercury to elemental
mercury, which is more difficult to collect.
Add-on controls to reduce mercury emissions are described in detail in this volume, including
information on commercial status, performance, applicability to the specified mercury emission
sources, and secondary impacts and benefits. The controls described are:
• Carbon filter beds;
• Wet scrubbing;
• Depleted brine scrubbing;
• Treated activated carbon adsorption;
• Selenium filters; and
• Activated carbon injection.
The most important conclusions from the assessment of flue gas treatment technologies include:
• Conversion of mercury cell chlor-alkali plants to a mercury-free process is technically
feasible and has been previously demonstrated.
• Control technologies designed for control of pollutants other than mercury (e.g., acid
gases and paniculate matter) vary in their mercury-removal capability, but in general
achieve reductions no greater than 50 percent.
• Selenium filters are a demonstrated technology in Sweden for control of mercury
emissions from lead smelters. Carbon filter beds have been used successfully in
Germany for mercury control on utility boilers and MWC's. These technologies have
not been demonstrated in the U.S for any of these source types.
• Injection of activated carbon into the flue gas of MWC's and MWI's can achieve
mercury reductions of at least 85 percent. The addition of activated carbon to the flue
gas of these source types would not have a significant impact on the amount of
paniculate matter requiring disposal.
• No full-scale demonstrations of mercury controls have been conducted in the U.S. for
utility boilers. Based on limited pilot-scale testing, activated carbon injection provides
variable control of mercury for utility boilers (e.g., the same technology might capture
20 percent of the mercury at one plant and 80 percent at another). The most important
factors affecting mercury control on utility boilers include the flue gas volume, flue
gas temperature and chloride content, the mercury concentration and chemical form of
mercury being emitted.
i
• The chemical species of mercury emitted from utility boilers vary significantly from
one plant to another. Removal effectiveness depends on the species of mercury
present. To date, no single control technology has been identified that removes all
forms of mercury.
June 1996 ES-10 SAB REVIEW DRAFT
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• The addition of activated carbon to utility flue gas for mercury control would
significantly increase the amount of paniculate matter requiring disposal.
Cost of Controls
The overall approach for assessing the cost of flue gas treatment technologies was to select a
subset of source categories on the basis of either their source category emissions in the aggregate or
their potential to be significant point sources of emissions. Consideration was also given to whether a
particular source category was a feasible candidate for application of a control technology-based
standard under section 112 of the CAA. This narrowed the analyses to six source categories:
municipal waste combustors (MWC), medical waste incinerators (MWI), chlor-alkali plants, utility
boilers, and primary lead and copper smelters.
In addition to determining the cost effectiveness of applying mercury control technology, a
financial analysis was performed to evaluate the affordability of mercury control (in terms of potential
price increases or impacts on financial impact) for the selected source categories.
Table ES-5 presents the six source categories for which a control technology and cost analysis
was performed. The table presents the number of facilities in each category and the percent
contribution of each to the national inventory. Potential national mercury reductions, potential national
control costs and cost-effectiveness estimates are also presented. These estimates are based on the
assumption that all plants within a source category will achieve the same reductions and incur the
same costs as the model plants used in the analysis. Because this assumption would not be applicable
in all circumstances, the estimates of potential reductions and costs should be used only for relative
comparisons among the source categories to give an initial indication as to where mercury controls
could provide the most emission reduction for the least cost.
The cost of mercury control incurred by any specific facility may be underestimated by the
cost analysis presented in this Report because of variability inherent in the assumptions that were made
in the analyses. These include the efficiency of the various control techniques for reducing mercury,
the amount of mercury in the flue gas stream and other site-specific factors such as down-time and
labor costs. In addition, costs for monitoring and record keeping were not included in the cost
analyses. On the other hand, the costs represent retrofit application of controls. Installation of
controls at new facilities can be significantly less expensive than retrofitting an existing facility.
The estimates of cost for mercury reduction also do not illustrate two important considerations.
One is that all of the cost of control is attributed to mercury removal. Many of these controls achieve
reductions of other pollutants as well. The benefits of these additional reductions should also be
considered. Second, the technologies available for mercury control represent relatively new
applications of these technologies. Thus, it is possible that new or emerging control technologies will
improve the cost-effectiveness.
Clean Air Act Authorities
Mercury is a priority pollutant across numerous U.S. EPA programs including air, water,
hazardous waste and pollution prevention. The statutory authorities under the CAA that could be used
to control mercury emission sources are briefly summarized below.
June 1996 ES-11 SAB REVIEW DRAFT
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Table ES-5
Potential Mercury Emission Reductions and Costs for Selected Source Categories
Mercury Source Category
Municipal waste combuslors
Medical waste incinerators
Coal-fired utility boilers
Chlor-alkuli plants using Ihe
mercury cell process
Primary copper smelters
Primary lead smelters
Total
Number
of
Facilities
149
-3,700
426
(1,043
boilers)
14
8
3
-4,900
% of U.S.
Mercury
Emission
Inventory
23
27
21
2.7
0.3a
3.7
78
Mercury Control Techniques
Material separation
Product substitution
Activated carbon injection
Carbon filter beds
Polishing wet scrubber
Material separation
Activated carbon injection
Polishing wet scrubber
Fuel switching
Advanced coal cleaning
Carbon filter beds
Activated carbon injection
Process modification
Depleted brine scrubbing
Treated activated carbon adsorption
Selenium fillers
Selenium filters
Potential National
Reductions'*
50 Ions
(90% reduction)
60 tons
(90% reduction)
24-44 tons
(50-90% reduction)6
6.5 tons
(100% reduction)
>0.7 Ions
(90% reduction)
8 tons
(90% reduction)
Potential
National Annual
Costs'
$56 million
$24 million
$2.9 billion
$70 million
$7.7 million
$0.8 million
~$3 billion
Cost-
Uffuctiveness
($/!!> of mercury
removed)1*
$211-870
$228-955
$5,240-28,000
$4,590
$497
$1,061
NOTE: The underlined mercury control techniques are Ihe techniques on which potential national reductions and potential national annual costs are based.
a Reflects one smelter only; a national estimate would be higher.
b Estimated reductions assuming every facility could achieve Ihe reduction listed.
c Potential national costs are estimates only and assume all lacililies would incur the same costs as the model plants used in the analysis.
J Where cost-ellecliveness values are presented us a range, the values reflect Ihe range across facilities of different sizes.
e The range in potential national reductions reflects Ihe variable efficiency of activated carbon injection lo control mercury emissions from coal-fired utility boilers. Activated cuihon Injection
has not been demonstrated for a full-scale utility boiler application. Control costs are based on Ihe installation of spray cooler, fahiic liller and caibon injection systems
June 1996
ES-12
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Section 112(a) Lesser Quantity Emission Rates
The U.S. EPA Administrator has the discretion to redefine major sources by setting an
emissions cutoff lower than the 10 tons per year emission rate level for a single pollutant or 25 tons
per year emission rate for a mixture of pollutants. This is referred to as a lesser quantity emission rate
(LQER). The CAA states that LQERs are pollutant-specific and should be based on public health or
environmental effects.
The major implications of setting an LQER are that all the requirements for a major source,
including setting maximum achievable control technology (MACT) standards, mandatory residual risk
analyses, calculation of the MACT floor, modification provisions and Title V permitting requirements
become^ applicable to what was previously defined as an area source category.
Section 112(cK6) List of Specific Pollutants
Section 112(c)(6) requires that by 1995, sources accounting for not less than 90 percent of the
aggregate emissions of each of seven specific pollutants must be listed on the source category list, and
be subject to standards under 112(d)(2) or (4) no later than 2005. The pollutants are: alkylated lead
compounds: polycyclic organic matter; hexachlorobenzene; mercury; polychlorinated biphenyls;
2,3,7,8-tetrachlorodibenzo-p-dioxin; and 2,3,7,8-tetrachlorodibenzofuran. This provision makes a
specific reference to utility boilers. It reads: "This paragraph shall not be construed to require the
Administrator to promulgate standards for such pollutants emitted by electric steam generating units."
Section 112(d) Emission Standards
Section 112(d) requires that emission standards be established for each source category listed
on the source category list. The emission standards are applicable to both new and existing sources
and are based on the application of MACT. MACT is defined differently for new and existing sources
as explained by 112(d)(2) and (3). Under 112(d)(4), if the pollutant is a threshold pollutant (i.e.,
noncarcinogen), the emission standard can be based on a health threshold with an ample margin of
safety. A health threshold is a level where the risk of an adverse effect from exposure to the pollutant
is negligible. Section 112(d)(5) allows the Administrator the discretion to apply generally available
control technology (GACT) to area sources rather than MACT (or any other technologies that may be
required of the source category on account of residual risk analyses under 112(f)).
Section 112(f) Residual Risk Program
Section 112(f) required the U.S. EPA to report to Congress on the methods that will be used
to calculate the risk remaining after the promulgation of MACT emission standards under Section
112(d). This report should address the public health significance of the risk and the actual health
effects experienced by persons living in the vicinity of emitting sources, and make recommendations
on legislation regarding the risk. This report is due to Congress on November 15, 1996. If Congress
does not accept any of the recommendations provided for reducing the residual risk, the Administrator
has the authority to promulgate any additional standards required in order to protect public health with
an ample margin of safety. The report is currently under development.
Section 112(k) Urban Area Source Program
By 1995, a national strategy to control emissions of hazardous air pollutants (HAPs) from area
sources in urban areas must be transmitted to Congress. The strategy must identify not less than 30
June 1996 ES-13 SAB REVIEW DRAFT
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HAPs which present the greatest threat to public health in the largest number of urban areas. Source
categories accounting for at least 90 percent of the aggregate emissions of each HAP must be listed on
the source category list and be subject to 112(d) standards. The strategy, when implemented, is to
achieve a 75 percent reduction in cancer incidence attributable to these sources.
The urban area source program is a section 112 authority that does not require that a finding
of adverse effects be made for the area source category (as required for listing by 112(c)(3)). Mercury
is a likely candidate for the urban area source program.
112(m) Atmospheric Deposition to Great Lakes and Coastal Waters (Great Waters)
The Great Waters study is an ongoing study with periodic reports to Congress required. This
program must identify and assess the extent of atmospheric deposition of HAPs to the Great Waters,
the environmental and public health effects attributable to atmospheric deposition and the contributing
sources. The first report was submitted in May 1994 and is to be submitted biennially hereafter.
Mercury was identified as a priority pollutant under the Great Waters program. The Administrator
must determine if other provisions under Section 112 will adequately control these sources. If not, by
1995, further emission standards to control these sources must be promulgated.
The recommendations of the first Great Water Report to Congress were (1) the U.S. EPA
should strive to reduce emissions of the identified pollutants of concern through implementation of the
CAA; (2) a comprehensive approach should be taken both within the U.S. EPA and between the U.S.
EPA and other federal agencies to reduce and preferably prevent pollution in the air, water, and soil;
and (3) the U.S. EPA should continue to support research for emissions inventories, risk assessment
and regulatory benefits assessment.
112(n)(l)(A) Study of Hazardous Air Pollutants for Electric Utility Steam Generating Units
The Utility Study is required to address the hazards to public health that are reasonably
anticipated to occur as a result of emissions by electric utility steam generating units of ... [hazardous
air pollutants] ... after imposition of the requirements of the Act. The list of 189 HAPs is presented in
section 112(b) of the CAA. In the study, the U.S. EPA must develop and describe alternative control
strategies for HAPs that may require regulation under section 112, and, if appropriate and necessary,
the U.S. EPA is to proceed with rulemaking to control HAP emissions form utility boilers. Mercury is
one of the pollutants of concern for utilities.
Section 129 Solid Waste Combustion
Under this section, the Administrator must establish emission guidelines and standards for
solid waste incineration units, including municipal waste combustors, medical waste incinerators and
commercial and industrial waste incinerators. The performance standards must specify numerical
emission limits for mercury as well as a number of other pollutants. The U.S. EPA has already issued
final rules for municipal waste combustors (59 FR 48198) and proposed rules for medical waste
incinerators (60 FR 10654). Emission limits for hazardous waste combustors will be forthcoming
under the Agency's Combustion Strategy.
June 1996 ES-14 SAB REVIEW DRAFT
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Conclusions
The following conclusions are presented in approximate order of degree of certainty in the
conclusion, based on the quality of the underlvine database. The conclusions progress from
those with greater certainty to those with lesser certainty.
• Conversion of mercury cell chlor-alkali plants to a mercury-free process is technically
feasible and has been previously demonstrated.
• Energy conservation and switching to low-mercury fuels would reduce the amount of
mercury being emitted by utility boilers.
• Injection of activated carbon into the flue gas of MWC's and MWI's can achieve
mercury reductions of at least 85 percent. The addition of activated carbon to the flue
gas of these source types would not have a significant impact on the amount of
paniculate matter requiring disposal.
• Numerous opportunities exist for replacing mercury in various products with other
materials, such as solid state electronics for mercury switches, digital thermometers for
mercury thermometers and zinc-air batteries for mercury batteries.
• Removing mercury-containing products such as batteries, fluorescent lights and
thermostats from the waste stream can reduce the mercury input to waste combustors
without lowering the energy content of the waste stream. The mercury removal
efficiency would vary, however, depending on the extent of the separation.
• Selenium filters are a demonstrated technology in Sweden for control of mercury
emissions from lead smelters. Carbon filter beds have been used successfully in
Germany for mercury control on utility boilers and MWC's. These technologies have
not been demonstrated in the U.S.
• Activated carbon injection provides variable control of mercury for utility boilers,
based on limited pilot-scale testing. The most important factors affecting mercury
control on utility boilers include the flue gas volume, flue gas temperature and chloride
content, the mercury concentration and chemical form of mercury being emitted. The
addition of activated carbon to utility flue gas for mercury control would significantly
increase the amount of paniculate matter requiring disposal.
• The available data on coal cleaning indicate that mercury reductions ranged from zero
to 64 percent. The average reduction was 21 percent This variation may be due to
several factors including different cleaning methods, different mercury concentrations
in the raw coal and different mercury analytical techniques. There are no data
available to assess the potential for mercury emissions from coal-cleaning slurries.
• Control technologies designed for control of pollutants other than mercury (e.g., acid
gases and paniculate matter) vary in their mercury-removal capability, but in general
achieve reductions no greater than. 50 percent
June 1996 ES-15 SAB REVIEW DRAFT
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There are many uncertainties associated with the cost analysis for individual source categories
due to assumptions inherent in a model plant approach. The impact of these uncertainties on
the analyses include the following:
• The cost of mercury control incurred by any specific facility may be underestimated by
the cost analysis presented in this Report because of variability inherent in the
assumptions that were made in the analyses. These include the efficiency of the
various control techniques for reducing mercury, the amount of mercury in the flue gas
stream and other site-specific factors such as down-time and labor costs. In addition,
costs for monitoring and record keeping were not included in the cost analyses.
• The financial impacts calculated in this Report may not represent the financial status of
all facilities within a source category. The affordability of mercury control will
depend on a given facility's profits and expenditures.
• In the control technology analysis, the cost of control was attributed to mercury
reduction only. Because many of the controls also reduce emissions of other
pollutants, apportioning the costs across all pollutants reduced would better
characterize the cost of mercury control.
To improve the control technology, cost and impacts assessment, the U.S. EPA would need the
following:
• Data from full-scale testing of activated carbon injection at a coal-fired utility boiler.
• Additional data are needed on the efficiency of activated carbon injection, and various
impregnated carbons, in reducing the different chemical species of mercury present in
flue gas.
• Additional information on the efficiency and cost of other technologies for mercury
control that are currently in the research stage. These include impregnated activated
carbon, sodium sulfide injection and activated carbon fluidized bed.
• More data are needed on both the ability of conventional or advanced coal cleaning
techniques to remove mercury from raw coal and advanced coal cleaning techniques
such as selective agglomeration and advanced column floatation. The potential for
mercury emissions from coal-cleaning slurries needs to be characterized.
• Additional analyses are required on the feasibility, cost effectiveness of other mercury
emission prevention measures such as emissions trading, emissions averaging, energy
conservation, renewable energy, and fuel switching.
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1. INTRODUCTION
Section 112(n)(l)(B) of the Clean Air Act (CAA), as amended in 1990, requires the U.S.
Environmental Protection Agency (U.S. EPA) to submit a study on atmospheric mercury emissions to
Congress. The sources of emissions that must be studied include electric utility steam generating
units, municipal waste combustion units and other sources, including area sources. Congress directed
that the Mercury Study evaluate many aspects of mercury emissions, including the rate and mass of
emissions, health and environmental effects, technologies to control such emissions and the costs of
such controls.
In response to this mandate, U.S. EPA has prepared a seven-volume Mercury Study Report to
Congress. The seven volumes are as follows:
I. Executive Summary
II. An Inventory of Anthropogenic Mercury Emissions in the United States
III. An Assessment of Exposure from Anthropogenic Mercury Emissions in the United
States
IV. Health Effects of Mercury and Mercury Compounds
V. An Ecological Assessment for Anthropogenic Mercury Emissions in the United States
VI. Characterization of Human Health and Wildlife Risks from Anthropogenic Mercury
Emissions in the United States
VII. An Evaluation of Mercury Control Technologies and Costs
This report, Volume VII, includes a description and analysis of additional technologies that
could bring about greater controls of mercury emissions, and existing state and federal programs that
control the use and release of mercury. This report also describes management alternatives and the
U.S. EPA's statutory authority under the CAA to control mercury emissions.
1.1 Risk Management Principles
Risk management is the process by which the U.S. EPA arrives at a regulatory decision. The
analyses of human health effects, ecological effects and the exposure assessment presented in previous
volumes of this Report were combined in the risk characterization (Volume VI). The risk
characterization is designed to provide decision makers with the essential risk information they need
for making risk management decisions. Risk managers must take into account not only the findings of
the risk assessment, but also consider non-scientific factors such as statutory authorities, technological
limitations and feasibility and economic and social consequences before reaching a regulatory decision.
This volume of the Mercury Study Report to Congress focuses on the risk management issues
that decision makers need to weigh against the findings of the risk assessment and risk
characterization. The first goal of this volume is to describe the analyses that were performed to
characterize the non-scientific risk management factors listed above, and to present the results of these
analyses. The second goal is to illustrate where there are regulatory gaps with respect to sources of
airborne mercury by summarizing regulations already in place and describing other non-regulatory
programs the U.S. EPA has underway to address emissions of mercury. Third, this report summarizes
the regulatory options that are both available and feasible under the statutory authority of the CAA. In
particular, sections 112 and 129 of the CAA contain provisions most pertinent to the control of
mercury emissions.
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The overall approach for the analyses was as follows. First, a subset of source categories was
chosen for control technology and cost analyses on the basis of either their source category emissions
in the aggregate or their potential to be significant point sources of emissions. Consideration was also
given to whether a particular source category was a feasible candidate for application of control
technology (e.g., fluorescent lamp breakage would not be considered an appropriate mercury emission
source category for a technology-based standard under section 112 of the CAA). Although this
narrowed the analyses to a certain group of source categories, it was believed that this approach would
give the risk manager an overall sense of what could be required in terms of technologies and costs for
the source categories potentially posing the greatest impact.
As mandated by the CAA, an analysis of control technologies and the costs of such
technologies was undertaken. The analyses were primarily focused on "end-of-pipe" technologies and
some pollution prevention options for six specific source categories. It is recognized that for a number
of source categories, "end-of-pipe" technologies may not be the only remedy. For example, for the
combustion source categories, a fuel switch could also be an effective way to achieve emission
reductions. Removal of mercury-containing materials from the waste stream is another possible
control option. Although these types of remedies are described qualitatively in the report, it was
believed that it was beyond the scope of the analysis to quantitatively assess every combination of
potential controls. In addition, it should be noted that the analyses presented here should not be
considered to substitute for a regulatory analysis. Any source category that becomes subject to
regulatory action should be thoroughly evaluated for a range of control options and not limited to
those presented here.
In addition to determining the cost effectiveness of applying mercury control technology, a
financial analysis was performed to evaluate the affordability of mercury control (in terms of potential
price increases or impacts on financial impact) for the selected source categories.
Finally, existing state and Federal regulatory programs for mercury are described to help
identify regulatory gaps, particularly for air emissions of mercury. Management alternatives and
statutory authorities under the CAA are also summarized.
1.2 Report Organization •
The remainder of this report is organized into the following five chapters:
• Chapter 2 describes opportunities for further mercury controls over and above the
status quo, including pollution prevention measures (i.e., product substitution, process
modification, and materials separation), coal cleaning, other management measures for
utilities (e.g., emissions trading, conservation, renewable energy options and fuel
switching) and end-of-pipe emission control technologies.
• Chapter 3 addresses the costs and financial impacts associated with further mercury
controls.
• Chapter 4 summarizes mercury control strategies, including Federal and state
authorities and activities that impact mercury emissions.
• Chapter 5 summarizes conclusions.
• Chapter 6 identifies research needs.
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All references cited in the volume are listed after Chapter 6. The report also contains two
appendices: Appendix A presents pilot test data on the mercury removal efficiency of activated carbon
injection for utility boilers, and Appendix B presents model plant cost analyses for installing and
operating applicable mercury control techniques at selected source types.
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2. MERCURY CONTROLS
This chapter provides information on mercury controls that provide opportunities for
significant further reductions of mercury emissions. Unlike the technologies described in Volume II of
this Mercury Study, which are generally used to control other pollutants and reduce mercury emissions
incidentally, the controls described in this chapter were assessed specifically for their potential to
reduce mercury emissions.
The discussion focuses on mercury emission controls for six source categories: municipal
waste combustors (MWCs), medical waste incinerators (MWIs), utility boilers, chlor-alkali plants,
primary copper smelters and primary lead smelters. As discussed in Chapter 1, these sources were
selected for analysis on the basis of their source category emissions in the aggregate, or their potential
to be significant point sources of emissions. Three major types of control techniques are described:
• Pollution prevention measures, including product substitution and process modification;
• Management measures, including materials separation; and
• Flue gas treatment technologies.
Table 2-1 summarizes information on the control techniques applicable to the different source
categories studied, including the level of mercury control and the present frequency of use. Each of
the techniques is described in more detail in the sections that follow.
2.1 Pollution Prevention and Other Management Measures
Discussed below are four measures for reducing mercury emissions: substitution of non-
mercury-containing products to reduce the amount of mercury entering waste streams ultimately
managed in MWCs and MWIs; the conversion of mercury cell chlor-alkali plants to the membrane cell
process, thereby eliminating all mercury emissions from that source category; separation of mercury-
containing materials from the waste streams of MWCs and MWIs; and coal cleaning, which may
remove some of the mercury contained in coal in addition
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Table 2-1
Summary of Mercury Control Techniques for Selected Source Types
Mercury Control
Technique
Product substitution (e.g.,
batteries, fluorescent lights)
Process modification
Materials separation
Applicable Source
Type
MWCs, MWIs
Mercury cell chlor-
alkali plants
MWCs and MWIs
Estimated Mercury
Removal Efficiency
Variable, depending on the
extent of substitution
100%
•
Variable, depending on the
extent of separation
Cross-Media
Impacts?"
Yes
Yes
Yes
Other Pollutants
Controlled
Could include other
components of
mercury-containing
batteries, fluorescent
lights and other
products
None directly
Could include other
components of
mercury-containing
wastes burned in
MWCs or MWIs
Comments
• Product substitution has reduced the use of
mercury in household batteries
• Use of mercury-containing fluorescent lights has
increased because of their energy efficiency, but
lower mercury content is being achieved
• The impact of product substitution to other areas
depends on specific circumstances, including
technical and economic feasibility
« In 1994, about one-half of the chlor-alkali plants
used mercury- free processes
• Because the membrane cell process has lower
electricity demands than the mercury cell process,
plant conversion results in an energy savings
• Additional savings presumably also result by
avoiding costs of recycling or disposing of
mercuric wastes
• Separation of low-volume materials containing
high mercury concentrations (e.g., batteries,
fluorescent lights, thermostats and other electrical
items) can reduce mercuiy input to a comhuslor
without removing energy content of the waste
stream
• Household battery separation has been
implemented by several communities; program
efficiency ranges from 3 to 25 percent
• Pilot studies conducted at hospitals have been
successful
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Table 2-1 (continued)
Summary of Mercury Control Techniques for Selected Source Types
Mercury Control
Technique
Carbon filter beds
Wet scrubbing (single-
slaged polishing scrubbers)
Depleted brine scrubbing
Treated activated carbon
adsorption
Applicable Source
Type
MWCs, utility
boilers, industrial
boilers
MWCs, MWIs,
boilers
Chlor-ulkali plants
Chlor-alkali plants
Estimated Mercury
Removal Efficiency
99%
Can be >90% for water-
soluble species; limited for
elemental mercury
•
98%
90%
Cross-Media
Impacts?"
Yes
Yes
Yes
Yes
Other Pollutants
Controlled
Residual organic
compounds, other
heavy metals, S09, acid
gases
Acid gases, metals,
paniculate matter,
dioxins, I'urans
None
Residual organic
compounds, other
heavy metals, SO2, acid
gases
Comments
• Currently applied to five full-scale power plants in
Germany, and planned to be installed on five
hazardous waste incinerators in hurope
• Technically feasible to other sources, such as
MWIs or smelters, hut has not been applied
• Potential negative effects associated with the
disposal of spent carbon and the potential for fires
in the bed
• Applied to one MWI in the U.S.
• Have not been applied to MWCs or boilers in the
U.S., although they have been used at MWCs in
Europe
• Requires treatment of waslewater prior to disposal
» May form more toxic, lesser-chlorinated dioxin
and furan congeners
• Very little information is available on this
technique
• Very little information is available on this
technique
• In 1984, carbon bed systems were in use at 8 of
the 20 chlor-alkali plants in o|ieralion in the U.S.
at that lime
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Table 2-1 (continued)
Summary of Mercury Control Techniques for Selected Source Types
Mercury Control
Technique
Applicable Source
Type
Estimated Mercury
Removal Efficiency
Cross-Media
Impacts?"
Other Pollutants
Controlled
Comments
Selenium fillers
Primary copper
smelters, primary
lead smellers, and
(more limited)
MWCs, crematories,
power plants
90%
Yes
Parliculale matter, acid
gases
Factors that influence perlormance include inlet
mercury concentrations, Hue gas temperature and
Hue gas dust conical
Four known applications at smellers as well us a
MWC and a crematory in Sweden; known
installation ut a German power plan; potentially
applicable lo MWIs
Spent filter containing selenium and mercury must
be landfilled after use
More information needed on the |x>ssibilily of
selenium being emitted from I lie filler itself
Activated carbon injection
MWCs, MWIs,
utility boilers
50-90+%
Yes
Chlorinated dioxins and
furans, potentially other
semi-volatile organics
Activated carbon injection efficiencies reported
for utility boilers are based on pilot-scale data and
as sych have a high degree of uncertainty
Factors that influence performance include Hue
gas temperature, amount of activated carbon
injected, type of parliculale mallei collector,
concentration and species of mercuiy in flue gas
and type of carbon used
Addition of carbon could have significant impact
on amount of pailiculule mailer requiting disposal
from utility boilers, but not fioin MWCs or MWIs
" For the purpose of this table, cross-media impacts refer lo the potential lo transfer and release mercury lo media other than air, such as soil, ground water, and surface water. For example,
carbon filler beds and wet scrubbers remove mercury from air emissions hut result in the generation and disposal of mercury-conlaining solid and liquid wastes, respectively. In the case of
product substitution, cross-media impacts refer to the potential to decrease airborne emissions of mercury ut one sile hul increase such emissions elsewhere.
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2.1.1.1 Batteries
The battery industry has undertaken two initiatives to reduce the amount of mercury used in
battery manufacturing. The first initiative is directed toward reducing and eventually eliminating
mercury in household batteries. Historically, mercury has been used (1) to inhibit side reactions and
corrosion of the battery casing material used with carbon-zinc and alkaline batteries, and (2) as a
component in the zinc amalgam that forms the electrical anode of alkaline batteries. Through recent
production improvements, use of mercury to inhibit casing material reactions and corrosion has been
eliminated, and the level of mercury in the zinc amalgam has been reduced to trace levels (White and
Jackson, 1992).
The battery industry's second initiative has been to develop alternatives to mercuric oxide
batteries where small size and constant current supply are critical. These batteries use mercury as the
cathode material. Unlike alkaline batteries, mercuric oxide batteries cannot maintain their performance
at reduced mercury levels. The battery industry has developed alternative battery designs, such as
zinc-air and silver-oxide batteries, that are capable of delivering comparable levels of performance at
reasonable cost. As a result, the use of mercuric oxide batteries has declined, lowering the amount of
mercury put into the municipal and medical waste streams (White and Jackson, 1992).
The applicability of product substitution to other areas will vary based on technical and
economic feasibility — both on the part of product manufacturer and user. For example, zinc-air
batteries, although having similar current delivery performance to mercuric oxide batteries, have a
shorter operating life. Because the number of batteries required on an annual basis would increase if
consumers use zinc-air batteries, the annualized cost of zinc-air batteries would be higher than for
mercury-zinc batteries.
Industry initiatives, combined with recent Federal and state control programs, have brought
about a dramatic reduction in the mercury content of batteries (see Volume II of this Report for a
more detailed discussion of battery trends). For example, alkaline batteries in the U.S. in the mid-
1980s contained mercury in amounts from about 0.8 percent to about 1-2 percent of the battery
weight. Between late 1989 and early 1991, all U.S. manufacturers converted production so thauthe
mercury content, except in button and "coin" cells, did nofcexceed 0.025 percent mercury by weight
(National Electrical Manufacturers Association, 1995). Such efforts have resulted in a corresponding
decline in the amount of mercury entering the municipal solid waste stream. One U.S. EPA study
(U.S. EPA, 1992a) estimates that the discard of mercury in batteries has decreased from approximately
306 tons in 1970 to 176 tons in 1995, a 43 percent decrease. The actual discards in 1995 are expected
to be even lower than this estimate, which does not reflect recent state, Federal, or battery
manufacturer's efforts to limit the mercury content of batteries, discussed in Chapter 4 of this volume.
2.1.1.2 Fluorescent Lights and Other Products
Similarly, the use of mercury-containing fluorescent and other high-efficiency lighting systems
is increasing because of the energy efficiency of these systems. Reducing or eliminating the use of
mercury in these applications could result in continued use of less efficient technology thereby
requiring increased electricity generation and associated air emissions.
As discussed in Volume II of this Report, the mercury content of fluorescent lamps has
decreased by 53 percent between 1989 and 1995 to 22.8 mg of mercury per lamp. Assuming a 4
percent increase in sales and a 53 percent decrease in mercury, estimated discards of mercury in
June 1996 2-5 SAB REVIEW DRAFT
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fluorescent lamps in 1995 would be 14.7 tons. This would represent a 44 percent decrease from the
estimated 26 tons of mercury discarded along with fluorescent lamps in 1989.
Alternatives currently available to mercury amalgams in dental preparations include gold,
ceramic, porcelain, polymers, composites and glass ionomers. The cold silver technique and gallium
are among the most promising currently in the development phase. While alternatives to mercury
amalgam have been developed, these alternatives have very limited use for a variety of reasons. Some
of these variables are the location of the defect in the tooth, the extensiveness of the defect, the
location of the afflicted tooth in the mouth, the amount of stress placed on the filling, and the
probability for contact with moisture during placement of the filling material. Amalgam use is favored
over composite resins by differences in strength durability, ease-of-placement, and the lower cost
between mercury amalgam and alternatives. Amalgams resist dissolution and wear better, require a
less precise technique during placement, and are lower in cost.
Mercury use by the dental profession decreases each year. Reduction of mercury used by the
dental profession has resulted from an increased emphasis on prevention of dental decay. Fewer
fillings are removed now than in previous years, and this trends is likely to continue. It has ben
suggested that with the technological progress being made in amalgam substitutes, these will become
competitive and likely displace traditional amalgam within the next decade or two. However, since the
general populace already has a great number of dental amalgam restorations in their teeth, the
decreasing amount of amalgam discharge during replacement into the waste stream will remain a
challenge for some time.
Finally, product substitutions are also expected to decrease the amount of mercury contained
in such items as thermometers, thermostats, and solid state electronic equipment. For example,
mercury thermometers and thermostats are being replaced with digital devices.
2.1.2 Process Modification for Mercury Cell Chlor-Alkali Plants
In mercury cell chlor-alkali plants, mercury is used as a flowing cathode in electrolytic cells.
The mercury electrolytic cell consists of an electrolyzer and a decomposer. In the electrolyzer section,
a brine solution (usually sodium chloride [NaCl]) flows concurrently with the mercury cathode. A
high current density is applied between the mercury cathode and the carbon or metal anodes. Chlorine
gas forms at the anode and an alkali amalgam forms at the mercury cathode. The amalgam is
separated from the brine in a discharge end-box and then enters the decomposer section, where water
is added. In the decomposer, the amalgam becomes the anode to a short-circuited graphite cathode
resulting in formation of hydrogen gas and alkali metal hydroxide, and conversion of the amalgam
back to mercury. The mercury is then recycled to the inlet end-box, where it reenters the electrolyzer.
The major emissions of mercury from this process occur with the hydrogen gas, the end-box
ventilation system and the electrolytic cell room ventilation air (U.S. EPA, 1973).
Mercury emissions from chlor-alkali operations can be eliminated by converting to the
membrane cell process. Because the membrane cell process is more energy efficient (Faun, 1991), the
use of mercury cells is declining.
In the membrane cell, a synthetic cation exchange membrane separates the electrolytic reaction
products. Chlorine gas is generated at the anode on one side of the membrane, and caustic soda and
hydrogen gas are produced at the cathode on the other side. The membrane allows passage of only
sodium ions from the anode to the cathode compartment. This produces caustic that is purer and more
concentrated than that from other nonmercury technologies, such as the diaphragm cell. The solution
June 1996 2-6 • SAB REVIEW DRAFT
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produced by membrane cells can be as much as 25 to 30 percent caustic by weight. This solution is
then evaporated to obtain a 50 percent product (U.S. EPA, 1984).
When a mercury cell process is converted to a membrane cell process, certain parts of the
process remain the same. Figure 2-1 presents a block diagram of the new process areas required when
the mercury cells are replaced with membrane cells (Horvath, 1986). Because mercury levels
exceeding 10 parts per million (ppm) in the brine system can greatly affect the membrane performance
(O'Brien, 1983), a mercury removal system is required. The mercury removal process is needed until
mercury is sufficiently purged from the brine (typically 1 or 2 years). The filters used for mercury
removal can later be used for secondary brine treatment (Horvath, 1986). More detail on the
conversion process is contained in the reference by O'Brien (1983).
The membrane cell process has lower electricity costs than the mercury cell process. As a
result, there are electricity savings associated with plant conversion. As described in detail in Chapter
3 of this Volume, the estimated annual capital cost of converting the model plant to a membrane
process from the mercury cell process (after deducting electricity savings) is about $3.3 million, or
about 12 percent of total annual expenditures. Additional savings would presumably also result from
the avoidance of costs of recycling or disposing of mercuric wastes, although these management costs
are unknown.
2.1.3 Materials Separation
Unlike other metals, mercury has a high vapor pressure at the temperatures typically present in
MWC and MWI air pollution control devices (APCD's). As a result, mercury does not condense as
readily onto paniculate matter (PM) and capture by the PM control device is highly variable.
Separation of mercury-containing materials from the waste stream before combustion can reduce the
amount of mercury in the exhaust gases from MWCs and MWIs (upstream of the APCD).
Many materials in wastes burned in MWCs and MWIs contain mercury. Materials that
compose a large portion of the waste stream, such as paper, plastic, dirt and grit and yard waste
(MWCs only), contain very low concentrations of mercury (U.S. EPA et al., 1992). Therefore,
obtaining appreciable mercury reduction from separation of these types of materials would require
separating a large fraction of the total waste stream. Separating these materials would counter the
intended purpose of the combustion process, which is to disinfect and reduce the volume of waste
materials.
Other materials contain higher concentrations of mercury, but make up only a very small
portion (less than 1 percent) of the waste stream. These materials include mercuric oxide batteries,
fluorescent lights, thermostats and other electrical items. Separation of such materials can reduce
mercury input to a combustor without removing any of the energy content of the waste stream.
To evaluate a materials separation program, the feasibility and costs of separating a particular
material should be compared with the mercury emission reduction achieved. Furthermore, the current
and future mercury reduction achieved by separating a certain material should be considered since the
mercury contribution of some materials such as household batteries has already declined considerably
because of the substitution of mercury-free batteries. The pros and cons of separating several different
materials are presented below.
June 1996 • 2-7 SAB REVIEW DRAFT
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Figure 2-1
Mercury Cell Replacement with Membrane Cells for
Chlor-Alkali Production Facilities
H2O NaCI
Atmosphere
Brine
Product
H20
Mercury
Removal
Ion-exchanger j
Brine
Treatment
Caustic Solution
50%
NaOH
Product
I | Existing Mercury Cell Process
New Membrane Cell PRocess
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2.1.3.1 Household B arteries
Batteries are usually the focus of materials separation efforts aimed at reducing mercury
emissions. Household batteries, including alkaline and mercuric oxide batteries, are the largest source
of mercury in MSW (U.S. EPA, 1992a). Both, the type and composition of batteries used in
households affect the amount of mercury in the waste stream.
In 1989, household batteries accounted for an estimated 88 percent of all mercury from
manufactured ite'ms in MSW and are expected to account for less than 68 percent by 2000 (U.S. EPA,
1992a). The expected mass of mercury from batteries discarded in MSW is expected to decline from
565 to 90 Mg (620 to 99 tons) by 2000 (U.S. EPA, 1992a; Shepherd, 1993). This decline is due
largely to the reduction in mercury used in alkaline batteries (the type used, for example, in flashlights,
toys and radios). In 1989, alkaline batteries contributed about 60 percent of the mercury from
batteries in MSW. Because the use of mercury in alkaline batteries is rapidly declining, however, it is
projected that alkaline batteries will contribute less than 1 percent to the total mercury from batteries
by 2000 (U.S. EPA, 1992a; Shepherd, 1993).
By 2000, 99 percent of the battery-related mercury in MSW is expected to come from
mercuric oxide button cells (the type used, for example, in hearing aids, watches and cameras) (U.S.
EPA, 1992a). Therefore, any program to remove household batteries from MSW should target
mercuric oxide button cells.
Several communities in the United States have implemented household battery separation
programs in an effort to reduce mercury in the waste stream destined for MWCs. In Hennepin
County, Minnesota, for example, small cardboard drop boxes are located at jewelry stores, camera
shops and other establishments that sell button cells (Michaud, 1993). Customers can deposit used
batteries in the box, free of charge. The batteries in the box are then collected by the county and sent
to a vocational center for hand sorting to separate the batteries by type (mercury-zinc, silver-oxide,
zinc-air and lithium). The mercury-zinc and silver-oxide batteries are sent to a company in New York
to recover the metals in the batteries. A fee must be paid to the recycling company for acceptance of
the mercury-zinc button cells, and a credit is provided for the silver button cells (Michaud, 1993).
•
Hennepin County also operates a program to separate other types of household batteries such
as alkaline and carbon-zinc batteries. Collection barrels are located in shopping malls, drug stores,
high schools and other locations. The county collects these batteries and ships them to a hazardous
waste landfill, since there are no facilities in the United States for recycling them. Most other
programs for separating button cells or larger household batteries in the United States are very similar
to the Hennepin County program.
The proportion of batteries recovered through community materials separation programs in the
United States (versus the proportion discarded in the MSW stream) is difficult to determine. Most
estimates of the battery recovery efficiency of household battery separation programs, however, range
from 3 to 25 percent (U.S. EPA, 1991b).
2.1.3.2 Medical Batteries
The concentration of mercury-zinc batteries in hospital waste may be even greater than in
MSW, because industrial-type mercury-zinc instrument batteries are used in hospital diagnostic
equipment (Shepherd, 1993; Cooper, 1993) and there is potential for a high proportion of elderly
persons at hospitals to use hearing aids. Mercury-zinc instrument batteries contain over 20 times more
June 1996 2-9 SAB REVIEW DRAFT
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mercury per battery than button cells (14 grams (g) of mercury per cell versus 0.63 g of mercury per
cell, respectively) (Shepherd, 1993). Industrial mercury-zinc batteries have been poorly characterized
in most nationwide inventories of batteries in the waste stream. Therefore, they may be a more
important source of mercury from MWIs than has been reported. Thus, the primary targets for
separation at hospitals should be mercury-zinc button cells and instrument batteries.
Several successful programs have been implemented at hospitals to separate mercury-zinc
button cells and instrument batteries from the waste stream. Initial results from these programs
indicate that they are highly effective in removing mercury from the waste stream at hospitals
(Shepherd, 1993). Results of emissions tests from the MWI at the Mayo Clinic in Rochester,
Minnesota, showed a significant decline in mercury emissions after a battery separation program was
established (White and Jackson, 1992). Similar types of separation programs designed to remove
specific items containing high concentrations of mercury may also be feasible for some industrial,
commercial, or military facilities.
2.1.3.3 Fluorescent Lights
Fluorescent lights accounted for about 3.8 percent of the mercury in MSW streams in 1989.
It is projected that by 2000, fluorescent lights will account for about 8 percent of the mercury in MSW
(U.S. EPA, 1992a). Currently, there are very few locations in the United States where the mercury
from such lights can be recovered (in 1989, there were five mercury recycling facilities in the U.S.);
however, the recycling capacity probably encompasses a majority of the lamps used in the U.S. In
addition, recycling capacity is increasing as state regulations requiring recycling take effect. A
program to separate such lights would be beneficial in reducing mercury emissions only if there are
facilities available to accept and process the discarded lights in an environmentally sound manner.
Because fluorescent lights are widely used in homes, schools, commercial facilities and other types of
buildings, a program to separate, store and safely transport them to a processing facility would require
a far-reaching program of education, training and cooperation throughout a community.
It also should be recognized that discarded fluorescent lights can break during handling,
resulting in the direct release of mercury into the environment. Therefore, while separating fluorescent
lights may reduce mercury inputs to waste combustors, cogsideration must also be given to the
potential for mercury emissions from handling, storing, recycling and disposing of fluorescent lights by
other means.
2.1.4 Coal Cleaning
In some states, certain kinds of coal are commonly cleaned to increase its quality and heating
value. Approximately 77 percent of the eastern and midwestern bituminous coal shipments are
cleaned in order to meet customer specifications for heating value, ash content and sulfur content
(Akers et al., 1993).
There are many types of cleaning processes, all based on the principle that coal is lighter than
the pyritic sulfur, rock, clay, or other ash-producing impurities that are mixed or embedded in it.
Mechanical devices using pulsating water or air currents can physically stratify and remove impurities.
Centrifugal force is sometimes combined with water and air currents to aid in further separation of
coal from impurities. Another method is dense media washing, which uses heavy liquid solutions
usually consisting of magnetite (finely ground particles of iron oxide) to separate coal from impurities.
Smaller sized coal is sometimes cleaned using froth flotation. This technique differs from the others
because it focuses less on gravity and more on chemical separation,
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Some of the mercury contained in coal may be removed by coal cleaning processes. Volume
II of this Mercury Study Report to Congress (An Inventory of Anthropogenic Mercury Emissions in the
United States) presents available data on the mercury concentrations in raw coal, cleaned coal and the
percent reduction achieved by cleaning. These data, which cover a number of different coal seams in
four states (Illinois, Pennsylvania, Kentucky and Alabama), indicate that mercury reductions range
from 0 to 64 percent, with an overall average reduction of 21 percent. This variation may be
explained by several factors, including different cleaning techniques, different mercury concentrations
in the raw coal and different mercury analytical techniques.
It is expected that significantly higher Hg reductions can be achieved with the application of
emerging coal preparation processes. Proof-of-concept scale testing of selective agglomeration and
advanced column flotation have indicated Hg removals as high as 80%. Bench-scale testing is also
being carried out to investigate the use of naturally-occurring microbes to reduce the Hg (and other
trace elements) from coal.
Any reduction in mercury content achieved by coal cleaning results in a direct decrease in
mercury emissions from utility boilers firing cleaned coals. The mercury removed by cleaning
processes is transferred to coal-cleaning wastes, which are commonly in the form of slurries. No data
are available to assess the emissions of mercury from coal-cleaning slurries.
2.1.5 Other Management Measures
In addition to the pollution prevention measures and emission control technologies discussed
above, there are a variety of flexible approaches for reducing the emissions of hazardous air pollutants.
For example, under Title IV of the Clean Air Act Amendments of 1990, U.S. EPA established a new
approach as part of its Acid Rain Program for limiting SO2 and NOx emissions from the electric-
generating industry. This approach, built on the concept of allocating "emissions control allowances,"
represents a significant departure from the more traditional "command and control" approach to
regulation. Overall, the emissions allowance approach will help improve efficiency and reduce
compliance costs, while leaving intact the environmental benefits intended by regulation. Although
this and other flexible programs administered by U.S. EPA have not been rigorously analyzed to
determine their applicability and potential cost-effectivenes^ for mercury controls, such approaches are
briefly described below.
2.1.5.1 Emissions Allowance Trading
Under emissions allowance trading, individual units that release SO2 or NOx from a utility are
not assigned rigid emissions limits. Instead, each unit is allocated transferable emissions "allowances,"
each of which permits the holder to emit specified amounts of a pollutant. If the unit exceeds its
allowances, it can still comply with the program by obtaining additional allowances from units whose
emissions are smaller than their allowance allocations. Units with sources that are relatively
inexpensive to control can reduce emissions more than would be required under uniform standards, to
create a surplus of allowances. These surplus allowances can then be traded to other sources that are
more costly to control, allowing these latter sources to reduce emissions less than would be otherwise
required, while still achieving the same level of aggregate emission reductions.
A potential market for emissions allowances is created by this transferability, in which
allowances may be bought, sold, auctioned and banked. The flexibility of this system will lower the
costs of reducing emissions considerably, since the emissions reduction at the units with the lowest
June 1996 2-11 SAB REVIEW DRAFT
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costs of control will be able to substitute for the more costly emissions reduction by other units that
would otherwise have been required.
A market for these allowances creates an incentive to develop more effective emissions
control techniques. These incentives, in the long run, are intended to result in technological advances
that make even tighter emissions standards feasible.
2.1.5.2 Emissions Averaging
In the emissions averaging program, sources for which emissions control is expensive need
not meet a specific target, as long as other sources in the same "averaging group" reduce their
emissions below their targets to compensate. When the necessary emissions reductions are made at
other sources where emissions can be reduced at the lowest cost, the pool will meet the target "on
average." If reducing emissions at one source is assumed to be equivalent to reducing emissions at
any other source in the same averaging pool, an averaging program would likely result in a pure
economic gain. Like emissions allowance trading, emissions averaging also could result in lower
emission reductions. Further, emissions averaging can, in many instances, reduce the total cost of
reaching a given emission limit.
2.1.5.3 The Opt-In Program
Though the Acid Rain Program is mandated only for utility sources, section 410 of Title IV
provides opportunities for other SO2 emitting sources to "opt in" to the program. The opt-in program
is a voluntary economic incentive provision, developed to further help lower the cost of complying
with acid rain limitations. Sources are given economic incentives to opt in if they can reduce
emissions at costs lower than those for affected utility units. These reductions generate acid rain
allowances that can then be transferred to utilities to meet mandatory reduction requirements in the
utility sector. In this way, the program reduces the overall cost of the Acid Rain Program.
2.1.5.4 Energy Conservation and Renewable Energy
Title IV also encourages energy conservation measures and use of renewable energy as a
long-term strategy for reducing air pollution and other adverse effects of energy production and use.
Energy conservation is a cost-effective measure that increases the efficiency of the use of electricity
provided by an electric utility to its customers. Renewable energy is defined as energy that is derived
from biomass, solar, geothermal or wind.
As an incentive, qualified electric utilities receive allowances for SO2 emissions avoided
through implementing energy conservation measures or by the use of renewable energy. For example,
for each ton of SO2 emissions avoided by an electric utility through the use of qualified energy
conservation measures or qualified renewable energy, the utility will be allocated a single allowance.
These allowances can be banked, traded, or used for other sources that require expensive emissions
control measures. U.S. EPA will allocate up to 300,000 allowances for all utilities from the
Conservation and Renewable Energy Reserve.
2.1.5.5 Fuel Switching
Fuel switching refers to switching from one fuel to another (e.g., high-sulfur coal to low-
sulfur coal, or coal to natural gas) for better environmental and economic benefits. For example, coal-
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fired utilities could lower their mercury emissions by switching to a lower-mercury fuel (e.g., natural
gas).
Installing pollution control equipment may not be cost-effective for sources that are not
affected by Title IV regulations, which are generally smaller than affected utilities. Given the
economic benefits of the opt-in program, fuel switching can be more cost-effective for such smaller
sources.
2.2 Flue Gas Treatment Technologies .
With the exception of mercury, most metals have sufficiently low vapor pressures at typical
APCD operating temperatures that condensation onto PM is possible. Mercury, on the other hand, has
a high vapor pressure at typical APCD operating temperatures, and collection by PM control devices is
highly variable. Factors that enhance mercury control are low temperature in the APCD system (less
than 150 °Celsius [°C] [300 to 400 "Fahrenheit (°F)]), the presence bf an effective mercury sorbent
and a method to collect the sorbent (Nebel and White, 1991). In general, high levels of carbon in the
fly ash enhance mercury sorption onto PM. The ash is then removed by the PM control device.
Additionally, the presence of hydrogen chloride (HC1) in the flue gas stream can result in the
formation of mercuric chloride (HgCl2), which is readily adsorbed onto carbon-containing PM.
Conversely, sulfur dioxide (SC>2) in flue gas can act as a reducing agent to convert oxidized mercury
to elemental mercury, which is more difficult to collect (Schager, 1990).
Add-on controls to reduce mercury emissions are discussed in the sections below. These
include:
• Carbon filter beds;
• Wet scrubbing;
• Depleted brine scrubbing;
• Treated activated carbon adsorption;
• Selenium filters; and
• Activated carbon injection.
•
Each of these control technologies is described, including information on commercial status,
performance, applicability to the specified mercury emission sources, and secondary impacts and
benefits.
2.2.1 Carbon Filter Beds
2.2.1.1 Process Description
Carbon filter beds have been developed in Europe for use as a final cleaning stage to remove
heavy metals (e.g., mercury), organic pollutants (e.g., dioxins and furans) and acid gases (e.g., S(>>,
HC1) (Hartenstein, 1993a).
Three filter designs have been used in Europe: cross flow, counter current and counter-cross
flow. The cross flow design has been applied to both utility boilers and waste combustors, the counter
current design to waste combustors and the counter-cross flow design to utility boilers (Hartenstein,
1993a). Most of the information available on carbon filter beds pertains to the cross flow design.
Therefore, this discussion focuses on cross flow design.
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Figure 2-2 presents a basic diagram of the cross flow filters. The flue gas flows horizontally
through the filter bed, while the adsorbent migrates through the filter from top to bottom. The bed is
approximately 1 meter (m) (3 feet [ft]) thick and is divided into three layers. The thickness of each
layer is approximately 100 to 150 millimeters (mm) (4 to 6 inches [in.]), 700 to 800 mm (28 to
31 in.), and 100 to 150 mm (4 to 6 in.), respectively. The first layer removes PM, heavy metals
(including mercury), organic compounds and SCb. Removal of HC1 occurs primarily in the second
layer. The third layer acts as a safety layer.
The three layers are separated by perforated metal sheets. On the outlet side, there is a slotted
sheet designed to prevent particles from being carried out of the filter with the flue gas.
Additionally,.an impact separator is located downstream of the slotted sheet, functioning as a safety
barrier against particle emissions (Hartenstein, 1993a; Hartenstein et al., 1991).
Fresh carbon is conveyed to and distributed within the bed by a screw conveyor on the top of
the bed. Discharge cylinders at the bottom of each layer allow extraction of carbon from each layer.
Pressure drop is the primary parameter for determining the rate of carbon removal from the bed. The
designed pressure drop across the bed is 150 to 190 mm (6 to 7.5 in.) of water. The pressure drop
across the whole system including fans and ducting is approximately 305 mm (12 in.) of water.
Because of dust collection in and compaction of each layer, approximately 100 to 130 mm (4 to 5 in.)
of material is periodically sloughed from each layer. Because of greater vibration of particles and,
thus, greater settling of the particles within the first layer, carbon is sloughed from this layer on the
shortest time interval, typically once every 6 to 8 hours. The second layer is sloughed once per day,
and the third layer is sloughed once every 2 weeks. Based on these removal rates and bed thicknesses,
the mass of carbon in the filter is fully replaced at an average rate of once per year. For MWCs, this
equates to approximately 2 kilograms (kg) carbon/Mg (4 pounds [Ib] carbon/ton) of MSW burned
(Hartenstein, 1993a).
Spent carbon can be disposed of by combustion if the unit is equipped with a wet scrubbing
(WS) system. The combustion process destroys the organic compounds captured in the carbon, and
the wet scrubber collects the heavy metals and acid gases. Another disposal option more applicable to
U.S. sources equipped with dry or semidry flue gas cleaning systems is to dispose of the carbon in a
landfill. Because of the adsorbed pollutants, this waste ma# require disposal as a hazardous waste.
Another option is to desorb the pollutants from the carbon. A pilot-scale desorption project is being
constructed in Germany (Hartenstein et al., 1991; Hartenstein, 1990).
The size of a carbon filter bed is dependent on flue gas flow rate. The size of an individual
carbon filter bed is limited by the height of the bed and the length of the screw conveyors and the
discharge cylinders. To accommodate larger volumes of flue gas, a unit can include multiple beds, in
which case each bed acts as a module within the filter. Filters with flow rates between 5,400 and
270,000 dry standard cubic meters per hour-(dscm/hr) (190,000 and 9,500,000 dry standard cubic feet
per hour [dscf/hr]),1 containing one to eight modules, are in operation in Germany (Hartenstein,
1993a).
2.2.1.2 Commercial Status and Performance
Carbon filter beds have been used on power plants in Germany since the late 1980s. There
are currently five full-scale applications of carbon filter beds on power plants in Germany. The
1 At 11 percent oxygen ((>>), on a wet basis.
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Figure 2-2
Carbon Filter Bed Design
Inlet Gas
Distribution System
INLET
Perforated Tin
Discharge Cylinde
Reactor Head
Slotted Tin Sheet
> OUTLET
Impaction
Separator
Gas Expansion
Space
Spent Material
Source: Hartenstein, 1993a
June 1996
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primary purpose of these filters is to remove residual SC>2 downstream of flue gas desulfurization
(FGD) systems to prevent formation of ammonium sulfate in low-dust selective catalytic reduction
systems. In one of the applications, a second filter module with catalytically active coke is used with
ammonia injection for the catalytic reduction of nitrogen oxides (NOX) (Hartenstein, 1993a). Although
mercury control was not the primary purpose for installing the carbon filter beds on the boilers,
reduction of mercury is inherent to the control system. A mercury level of under 1 microgram
(ug)/dscm has been guaranteed by one vendor (Petersen, 1993).2
Application of carbon filter bed technology to MWCs in Europe was undertaken primarily for
the purpose of reducing emissions of residual organic compounds, in addition to reducing heavy metals
and acid gases. Mercury emissions from a pilot-scale MWC application in Germany were below the
detection limits, corresponding to greater than 99 percent removal. Organic compounds were also
removed by over 99 percent. No data were available on acid gas removal (Hartenstein, 1993). A full-
scale application on a German industrial hazardous waste incinerator was installed in 1991, and low
emissions of metals, organic compounds and acid gases wefte recorded (less than 1 ug/dscm [less than
0.44 grains (gr) per million dscfj for mercury, cadmium and lead; less than 0.6 nanograms [ng]/dscm
[0.26 gr/billion dscf] for dioxins and furans; less than 1 ppm by volume (ppmv) for SCb and HC1).
Inlet measurements, which would help characterize the hazardous waste stream, were not made
(Hartenstein, 1993b). Without these measurements, the data cannot be used to directly assess the
performance of the carbon filter beds. As noted, a mercury emission rate of under 1 |ug/dscm has been
quoted by a vendor (Petersen, 1993).
Future European installations of carbon filter beds on waste combustors include 5 units for
hazardous waste incinerators and 11 for MWCs (Hartenstein, 1993a).3
2.2.1.3 Applicability
In Europe, carbon filter beds have been installed on waste incinerators and utility boilers.
Carbon filter beds are also technically feasible applications to sources such as MWIs or smelters. This
technology, however, has not been applied to these sources. Carbon filter beds have not been put into
commercial practice in the U.S. for any of these source types.
•
2.2.1.4 Secondary Impacts and Benefits
In addition to mercury removal, carbon filter beds provide removal of residual organic
compounds, other heavy metals and acid gases.
A potential negative impact associated with the carbon filter technology is disposing of the
spent carbon. Options for disposal include burning the carbon or disposing of it in a hazardous waste
landfill. Based on revolatilization data from ash samples collected during activated carbon injection
testing, mercury revolatilization from the ash is not expected (Kilgroe et al., 1993). As a result, this
potential negative impact may not be significant. Costs associated with hazardous waste disposal,
however, must be considered.
2 All concentrations in this report are corrected to 7 percent 02 unless otherwise noted.
3 These totals are for the Steinmuller-Hugo Petersen cross flow filter. All of the units are in Europe.
Additional units manufactured by other vendors may also be planned.
June 1996 2-16 SAB REVIEW DRAFT
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Another concern with this technology is the formation of "hot spots" in the bed that can result
in bed fires. The cross flow filter is designed to evenly distribute the flue gas throughout the bed and
to constantly remove excessive heat from the bed. To monitor hot spot formation, carbon monoxide
concentrations in the flue gas are monitored upstream and downstream of the coke bed, and grate
temperature measurements are taken. Gas probes are used to pinpoint any hot spot that forms. This
system gives operators sufficient time to evaluate and troubleshoot problems (Hartenstein, 1990).
Another possible negative impact associated with this technology, or any carbon technology, is
the potential release of mercury or other emissions during the coal-charring segment of the carbon
activation processes. During the charring segment, when all volatiles are vaporized from the coal,
mercury in the coal will be released. The level of mercury release is insignificant compared with the
amount of mercury removed from the flue gas when using carbon filter beds. For example, if a
mercury concentration in coal of 1 ppm and a 35 percent yield of activated carbon from a unit of
bituminous coal is assumed (Rester, 1993), the mercury released during coal charring is less than
0.4 percent of the mercury captured using carbon filter beds. (Note that a 1 ppm level of mercury in
coal is at least an order of magnitude higher than found in raw coal in the U.S. Thus, potential
emissions would be commensurately lower.) Furthermore, the estimate of mercury emitted during
charring assumes that all the mercury is released to the atmosphere. One activated carbon producer
routes flue gas from the charring and activation process to a combustion unit and then through a wet
scrubber (Rester, 1993). It can be assumed in this case that some of the mercury resulting from the
charring is captured and not emitted to the atmosphere.
2.2.2 Wet Scrubbing
2.2.2.1 Process Description
Wet scrubbing (WS) systems can be used to control acid gases, metals, PM and dioxins and
furans. Depending on the intended purpose of the WS system, different designs are available and
include:
• Single-stage scrubbers designed primarily for control of acid gases;
•
• Two-stage scrubbers designed for control of acid gases and metals;
• Three-stage systems consisting of a two-stage scrubber followed by a high-efficiency
wet paniculate control system designed for improved control of fine particulates,
metals and dioxins and furans; and
• Single-stage scrubbers, referred to as "polishing" scrubbers, that are installed following
other APCD's and are designed for increased pollutant control (polishing).
Single-stage alkaline scrubbers are used on utility and industrial boilers for FGD, as well as
on some small MWCs and MWIs. The effectiveness of such WS systems for mercury control on
boilers is unclear at this time, but it is theorized that sulfites in the alkaline scrubber may act as a
reducing agent to convert ionic mercury compounds into elemental mercury (Schager, 1990; Lerner,
1993a). Elemental mercury is not soluble in water and, therefore, is not retained by the scrubber
solution.
This section focuses on single-stage polishing scrubbers, a type designed specifically for use
as an add-on control for enhanced removal of mercury and other pollutants (PM, dioxins and furans).
June 1996 2-17 SAB REVIEW DRAFT
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The polishing WS system includes a single-tower water scrubber, which is installed at the outlet of an
existing APCD such as a spray dryer/fabric filter (SD/FF). Soluble species of mercury compounds,
such as HgCl2 and mercuric oxide (HgO), can be effectively captured (greater than 90 percent) in the
wet scrubber. If there is significant elemental mercury in the flue gas, however, collection efficiencies
will be limited. The captured mercury is precipitated out during wastewater treatment through the use
of any of several additives (e.g., sodium sulfide, trimercapto-s-triazine [TMT-15] and dithiocarbamate)
(Reimann, 1993).
2.2.2.2 Commercial Status and Performance
Polishing WS systems for the purpose of enhanced mercury control and advanced two- and
three-stage WS systems have not been applied to MWCs or boilers in the United States, although these
WS polishing systems have been applied to MWCs in Europe. There is one application on an MWI in
the United States (Lemer, 1992). Performance data are not available for a polishing wet scrubber on
the MWI, but are available for three-stage systems and indicate mercury removal efficiencies of over
90 percent. Discussions with a vendor of WS systems indicated that a polishing scrubber on an MWC
could reduce mercury by over 90 percent (Nebel et al., 1994).
2.2.2.3 Applicability
Polishing WS systems can be applied on MWCs, MWIs and boilers downstream of other acid
gas and PM controls. As noted above, a factor determining effectiveness of this control is the amount
of water-soluble mercury in the flue gas stream. For MWCs and MWIs, there is typically enough HC1
in the flue gas to form HgCl2 as the predominant mercury species.
2.2.2.4 Secondary Impacts and Benefits
As noted above, the use of WS systems requires treatment of wastewater before its disposal.
The wastewater from WS systems on MWCs and MWIs generally contains more concentrated
contaminants than other wastewater streams from the combustion of more homogenous fuels, such as
coal. Even after standard neutralization and purification of the wastewater, excessive metal chloride
complexes (including mercury) can remain. The use of TMT-15 or other similar precipitants can
reduce these contaminants (Reimann, 1993). The manufacturer of TMT-15 (Degussa Corp.) claims
that TMT-15 can reduce mercury levels in the wastewater to below 1 part per billion (Knivanek,
1993).
Zero water discharge is another alternative to handle the wastewater. Under this option, the
scrubber water is evaporated using process heat, or in an upstream quench chamber or SD. It is still
important to precipitate mercury out of the wastewater, so that revolatilization does not occur in the
quench chamber or SD (Knivanek, 1993).
Another concern regarding WS systems is dechlorination of dioxins and furans isomers.
Dechlorination raises concerns because the lesser-chlorinated dioxins and furans congeners are believed
to be more toxic. Shifts in congener profiles have been observed at three wet-scrubber- equipped
MWCs in the United States (Lerner, 1992), along with two wet-scrubber-equipped MWCs in Europe
(Vogg, 1990; Marklund et al., 1993). Based on test data from other European facilities, however, this
shift does not appear to occur in all WS systems (Jones, 1993). It is theorized that a reagent can be
added to the scrubber water to control dioxin and furan shifts across all isomer classes (Krivanek,
1993).
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2.2.3 Depleted Brine Scrubbing
2.2.3.1 Process Description
Depleted brine scrubbing is a WS process used to further reduce mercury emissions from
mercury-cell chlor-alkati plants, specifically from the hydrogen and end-box ventilation gases. This
scrubbing system is installed downstream of a primary and secondary cooling system, which includes a
knockout drum and mist eliminator (U.S. EPA, 1973).
The depleted brine scrubbing technique uses discharged brine4 from the chlorine cell as a
scrubbing liquor in a sieve plate tower or in a packed bed scrubber. Upon contact with the brine
scrubbing solution, mercury vapor and mist form soluble mercury complexes. The mercury is
subsequently recovered by electrolysis when the scrubbing solution is returned to the mercury
chlor-alkali cell. Some systems are designed with an alkaline scrubber installed downstream of the
brine scrubber to remove entrained chlorine and acid gases (U.S. EPA, 1973).
2.2.3.2 Commercial Status and Performance
Based on compliance test results provided in a 1984 U.S. EPA report, a brine scrubber
installed to control mercury from the end-box stream of a chlorine plant with a 100 Mg/day (110-tons
per day [tpd]) production capacity had mercury emissions of 48 g/day (0.11 Ib/day) and 16 g/day
(0.04 Ib/day) during two tests (U.S. EPA, 1984). A 1973 study reported mercury emissions from a
depleted brine scrubber followed by an alkaline scrubber to be 4.5 g/day (0.01 Ib/day) for a 90-Mg/day
(100-tpd) chlorine production facility (U.S. EPA, 1973). Without the alkaline scrubber, mercury
emissions of 270 to 410 g/day (0.16 to 0.9 Ib/day) were reported (U.S. EPA, 1973). More current
information was not available.
2.2.3.3 Applicability
This technique is specific to chlor-alkali plants only. It cannot be used for other mercury
source categories.
•
2.2.3.4 Secondary Impacts and Benefits
Very little information is available on this control technique. No data on secondary impacts
or benefits from this system were identified.
2.2.4 Treated Activated Carbon Adsorption
2.2.4.1 Process Description
This mercury control technique uses a packed bed of sulfur- or iodine-impregnated carbon to
reduce emissions of elemental and oxidized mercury compounds. This technique is similar in concept
to the carbon filter bed (section 2.2.1) but is smaller in scale and does not involve the continual
addition and sloughing of carbon. This technique has been applied to the hydrogen and end-box
streams of chlor-alkali plants. The carbon adsorption bed is typically placed after the primary and
4 This depleted brine contains about 250 g (0.55 Ib) per liter of NaCl and 0.6 to 0.9 g (0.001 to 0.002 Ib) per
liter of available chlorine. The pH of the brine solution is typically 2 to 4.
June 1996 2-19 SAB REVIEW DRAFT
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secondary cooling and mist elimination systems, and removes about 90 percent of the mercury content
of the stream. The remaining mercury vapor is adsorbed by the carbon and chemically reacts with
sulfur or iodine to form stable mercury compounds. Reduction of mercury to levels of 5 to
10 ug/cubic meter (m3) (at actual 02 levels) was reported (U.S. EPA, 1973). The treated activated
carbon can adsorb from 10 to 20 percent of its weight in mercury before it requires replacement (U.S.
EPA, 1973). Several adsorber beds can be placed in series (U.S. EPA, 1984).
2.2.4.2 Commercial Status and Performance
Carbon filter beds have had widespread use in the chlor-alkali industry. Based on a 1984
mercury report (U.S. EPA, 1984), carbon bed systems were in use at 8 of the 20 chlor-alkali plants in
operation at that time. Emissions of mercury reported for the seven plants equipped with the carbon
beds on their hydrogen streams ranged from 1 to 264 g/day (0.002 to 0.58 Ib/day). At the one plant
with a carbon bed on the end-box stream, mercury emissions ranged from 5 to 120 g/day (0.01 to
0.26 Ib/day) (U.S. EPA, 1984). These results are from plants of different capacities: therefore, the
results cannot be compared directly. Additionally, there may be differences between the cooling
systems at the plants and the designs of the carbon beds, which could affect emissions. In general,
carbon bed systems should remove 90 percent of the mercury in the stream (U.S. EPA, 1973).
2.2.4.3 Applicability
This technology has been applied to hydrogen and end-box streams from chlor-alkali plants.
It cannot be used for other mercury source categories.
2.2.4.4 Secondary Impacts and Benefits
Very little information is available on this control technique. No data on secondary impacts
or benefits from this system for chlor-alkali plants were identified.
2.2.5 Selenium Filters
2.2.5.1 Process Description ,
Selenium filters have been developed to reduce elemental mercury emissions. The filters
operate based on the affinity between mercury and metallic selenium. The mercury-laden flue gas
passes through the filter, which is constructed of ceramic grains impregnated with metallic selenium.
The gas pathway through the filter is tortuous, which increases the contact between the mercury and
the selenium, forming mercury selenite (HgSe) (Edlund, 1993a). Standard filter sizes range from 535
to 53,500 standard cubic meters per hour (scm/hr) (18,900 to 1,890,000 standard cubic feet per hour
[scf/hr]).5 For flows larger than 53,500 scm/hr (1,890,000 scf/hr), multiple filters in parallel can be
used (Edlund, 1993b).
Selenium filters are effective on flue gas streams with inlet mercury concentrations of up to
9 milligrams (mg)/scm (3,900 gr/million scf). At higher mercury concentrations, the lifetime of the
filter is short and an alternative control system, such as wet scrubbing, is recommended. At very low
mercury concentrations, the removal efficiency decreases because of reduced mercury-selenium
molecular collisions (Edlund, 1993a).
Oxygen levels not provided for flows or concentrations.
June 1996 2-20 SAB REVIEW DRAFT
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Based on vendor-provided information, a residence time of more than 2 seconds is
recommended to achieve a constant degree of removal. Additionally, a flue gas temperature of less
than 120°C (250°F) is recommended for maximum removal. Up to about 120°C (250°F), the
removal efficiency remains fairly constant, but decreases at higher temperatures. With an inlet
mercury concentration of less than 9 mg/scm (3,900 gr/million scf), a residence time of 4 seconds and
a flue gas temperature of 120°C (250°F), an outlet mercury concentration of less than 40 ug/scm
(17 gr/million scf)6 is claimed by the vendor (Edlund, 1993b).
Parameters to be considered when applying selenium filters include the dust content of the
flue gas and the pressure drop through the filter. A maximum dust content of 9 mg/scm
(3,900 gr/million set) is recommended.6 Higher levels of dust necessitate frequent washing of the
filter. The normal arrangement of the filter allows for a pressure drop of about 50 mm (2 in.) of
water; however, it might be possible to accommodate higher pressure drops through alternate designs
(Edlund, 1993a).
Because the removal of mercury in the filter is based on the formation of HgSe, the selenium
in the filter is eventually exhausted. The selenium filter is designed to convert approximately 50 kg of
mercury to HgSe per cubic meter of filter material (3 Ib/cubic [ft^]) (Edlund, 1993a). The
combination of pressure drop, mercury content in the flue gas and the mechanical construction of the
filter determine the ultimate lifetime of the filter. On average, the filter lifetime is 5 years, after which
the filter element is replaced (Edlund, 1993b). Once the lifetime of the filter mass has expired, the
HgSe mass is landfilled (it is not combustible). Mercury selenite is a very stable compound, and the
filter vendor indicated that laboratory leach tests showed negligible leaching, although no leaching data
were provided. Also it is not clear whether mercury is recoverable through retorting (Edlund, 1993c).
2.2.5.2 Commercial Status and Performance
Selenium filters were first developed in Sweden in the 1970s for use on smelter flue gas
streams, upstream of sulfuric acid plants (Lindquist, 1992). There is also one application on a
crematory in Sweden. In total, there are four applications of selenium filters (Edlund, 1993c), all
located in Sweden. Performance data were not available for any of the installations. Vendor
information, however, indicates that mercury emissions les# than 40 ug/scm (17 gr/million scf)7 are
achievable (Edlund, 1993b). Since the application of selenium filters is limited and performance is
based solely on vendor information, this technology should be viewed as an indicator of what may be
feasible. This evaluation of this technology is not intended to be definitive.
2.2.5.3 Applicability
While use of this technology has been demonstrated in Sweden for metal smelters and
crematories, it has not been demonstrated for a utility boiler. Use of these filters on MWCs and
MWIs may also be technically feasible, although this application was not cited by the vendor.
6 Oxygen levels not provided for concentrations.
Oxygen levels not provided for concentrations.
June 1996 2-21 SAB REVIEW DRAFT
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2.2.5.4 Secondary Impacts and Benefits
A selenium filter consists of ceramic grains impregnated with metallic selenium. More
information is needed about the possibility of selenium being emitted from the filter itself, particularly
in the presence of hydrogen fluoride. Hydrogen fluoride gas from waste incineration could potentially
generate volatile selenium compounds such as selenium hexafluoride. No data were located, however,
to confirm this hypothesis.
2.2.6 Activated Carbon Injection
2.2.6.1 Process Description
Activated carbon injection involves the injection of powdered activated carbon into flue gas
upstream of an APCD. Activated carbon is a specialized form of carbon produced by pyrolyzing coal
or various hard, vegetative materials (e.g., wood) to remove volatile material. The resulting char then
undergoes a steam or chemical activation process to produce an activated carbon that contains multiple
internal pores and has a very high specific surface area. With this internal pore structure, the activated
carbon can adsorb a broad range of trace contaminants, including mercury. After injection into the
flue gas and adsorption of mercury and other contaminants, the activated carbon is captured in the PM
control device.
The factors affecting the performance of activated carbon injection are the temperature of the
flue gas, the amount of activated carbon injected, the concentration and species of mercury in the flue
gas, the extent of contact between the carbon and mercury and the type of carbon used. Flue gas
temperature, as noted above, is important because mercury is a vapor at temperatures above 150 to
200°C [300 to 400°F]. The flue gas temperature needs to be within, or preferably below, this range
for the mercury to adsorb onto the carbon. The combustion device and the corresponding composition
of the flue gas will affect this temperature range. In an MWC, where there is a substantial amount of
HC1 resulting in the formation of HgCl2, temperatures within and below the noted range have proven
to be effective when injecting carbon (U.S. EPA, 1992b; Kilgroe et al., 1993; Richman et al., 1993).
Test data from an MWC retrofitted with activated carbon injection indicate mercury removals greater
than 95 percent (Ogden Martin, 1994). Pilot testing on a (joal-fired utility boiler indicated that a
temperature under 90 to 120°C (200 to 250°F) was necessary for effective mercury removal (Chang et
al., 1993).
With activated carbon injection, efficient distribution of the carbon in the flue gas is also
important. The amount of carbon needed to achieve a specific level of mercury removal will vary
depending on the fuel being burned, the amount of carbon inherent to the system and the type of PM
control device. At a given carbon feed rate, a FF provides more mercury control than an electrostatic
precipitator (ESP) because of the additional mercury adsorption that occurs on the bags of the FF (due
to the increased gas contact time). As a result, an ESP-equipped facility may require a higher carbon
feed rate to achieve the same level of control as a FF-equipped facility.
With chemically impregnated activated carbon, the contaminant reacts with the chemical that
is bound to the carbon, and the carbon is removed by an APCD. For instance, with sulfur-
impregnated carbon, mercury and the impregnated sulfur react to form mercury sulfide on the carbon.
One pilot-scale study suggests that mercury removal efficiencies for sulfur- and iodide-impregnated
carbons were 25 to 45 percent greater than those achieved with an equivalent amount of
nonimpregnated carbon (Felsvang et al., 1993). Other studies however, have shown that the
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effectiveness of different carbons is dependent on the mercury species, and in some cases, activated
carbon had better mercury removal than iodated carbon (Miller, 1995; Krishnan, 1994). .
2.2.6.2 Commercial Status and Performance
Activated carbon injection is being used commercially on one MWC in Europe and has been
tested in the United States on three MWCs, two MWIs and a 1-megawatt (MW) slip stream from a
coal-fired boiler. The U.S. test programs have shown mercury removals of 50 to over 95 percent,
depending on the carbon feed rate (U.S. EPA, 1992b; Kilgroe et al., 1993; Richman et al., 1993:
Chang et al., 1993; U.S. EPA, 1991c; U.S. EPA, 1992d). As of January 1995, there were four MWCs
in the U.S. that had been retrofitted with activated carbon injection. Test results from the Hennepin
County Energy Resource Company in Minnesota indicate that this technology is achieving mercury
reductions greater than 95 percent. Currently, research is being done on activated carbon injection at
two pilot-scale utility boilers. Tests on a full-size electric utility boiler are planned by the Electric
Power Research Institute.
2.2.6.3 Applicability
Activated carbon injection is applicable to MWCs, MWIs and utility boilers. There are
considerable data describing the efficacy of activated carbon injection for controlling mercury
emissions from MWIs and MWCs. These data have been previously published by U.S. EPA and are
not discussed in detail in this report. The reader is encouraged to review the Background Information
Documents for MWIs and MWCs for activated carbon test results (U.S. EPA, 1989a; U.S. EPA,
1989b; U.S. EPA, 1994d; U.S. EPA, 1994e). Activated carbon injection test results for utility boilers
have not been previously published by U.S. EPA. To inform the reader, therefore, a detailed
discussion of the applicability of activated carbon injection to utility boilers is presented in Section
2.3. Activated carbon injection may also be technically feasible for smelters. No information,
however, is available on the use of activated carbon injection for smelters.
2.2.6.4 Secondary Impacts and Benefits
In addition to removing mercury, injection of activated carbon will increase the removal of
chlorinated dioxins and furans and potentially other semivolatile organics. Data from tests with
activated carbon injection on an MWC, equipped with an SD/ESP, show 95 to 98 percent reduction of
dioxin and furan emissions, versus a reduction of 78 to 80 percent without carbon injection (Richman
et al., 1993). Similar dioxin and furan removal efficiencies were achieved during a test on an SD/FF-
equipped MWI (U.S. EPA, 1991c).
The addition of carbon to MWCs and MWIs has a minimal impact on the quantity of
collected PM requiring disposal. By comparison, the injection of activated carbon into a utility flue
gas stream could have a significant impact on the quantity of PM requiring disposal. For example, as
described in Appendix B, a 100 MW coal-fired boiler with an ESP could potentially inject almost 490
tons of activated carbon per year.
Testing conducted on ash samples collected during carbon injection testing at a U.S. MWC
demonstrated the mercury collected on the carbon was stable at temperatures typical of landfills. As a
result, there is a low potential for the mercury to be reemitted to the atmosphere (U.S. EPA, 1992b).
The issue of mercury released during the production of activated carbon, as discussed above,
is also applicable to activated carbon injection. As with carbon filter beds, the amount of mercury
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released during the charring is very small compared with the amount of mercury captured by the
injected carbon. The amount of mercury released during charring is estimated to be less than
0.2 percent of the amount of mercury captured in injected carbon. This is slightly less than for carbon
beds because a smaller quantity of carbon is used in activated carbon injection.
2.3 Activated Carbon Injection for Utility Boilers
The effectiveness of activated carbon injection in controlling mercury emissions from MWCs
has been demonstrated (U.S. EPA, 1989a; U.S. EPA, 1989b). The application of activated carbon
injection to utility flue gas, however, cannot be directly scaled from the application at MWCs due to
differences in the amount and composition of flue gas at utility plants and MWCs. At utility plants,
small concentrations of mercury are contained in a large volume of flue gas, and large amounts of
activated carbon may be needed to provide adequate contact between the carbon particles and mercury.
The differences in flue gas characteristics at MWCs and utility plants must be carefully examined
before considering any technology transfer assumptions. Because fewer references are available on the
application of activated carbon injection to utility boilers, a greater level of detail is presented here for
this application than for MWCs.
The level of mercury control achieved in utility flue gas may depend upon flue gas
characteristics such as volume, temperature, and chloride and mercury content. These properties are
distinctly different from those in MWC flue gas.
As shown in Table 2-2, typical MWC flue gas is hotter than utility flue gas after leaving an
air preheater. The air preheater cools the utility flue gas by transferring heat to the incoming
combustion air. Moreover, the mercury concentration of the two gas streams differs significantly.
Mercury concentrations in MWC flue gas streams may be up to several orders of magnitude greater
than those seen in utility flue gas streams. Likewise, the chloride content of MWC flue gas may be
from 1.4 to 400 times greater than the content seen in utility flue gas. Finally, with regard to the
volume of flue gas, a utility boiler may have flow rates up to 30 times that of an MWC.
Table 2-2
Comparison of Typical Uncontrolled Flue Gas Parameters at Utilities and MWCsa'b
Uncontrolled Flue Gas Parameters
Temperature (°C)
Mercury Content (ng/dscm)
Chloride Content (pg/dscm)
Flow Rate (dscm/min)'
Coal-Fired Utility
Boilersc-d
121 - 177
1 -25
1,000 - 140.000
11,000-4,000.000
Oil-Fired
Utility Boilersd-e-f
121 - 177
0.2 - 2l
1,000 - 3.000
10.000 - 2.000,000
MWCS-h
177 - 299
400 - 1.400
200.000 - 400,000
80.000 - 200.000
Standard conditions are 0°C and 1 atmosphere.
Moisture content in the MWC flue gas was assumed to be 13.2 percent
c Radian Corporation, 1993a.
d Heath. 1994
e Radian Corporation, 1994.
f Radian Corporation, 1993b.
g Brown and Felsvang
h Nebel and White, 1991.
1 It is not known if oil-fired utility boilers release less mercury overall than coal-fired boilers because the mercury release during oil refining is essentially
unstudied.
1 Min = minute
June 1996
2-24
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Because of differences in the amount and composition of flue gas at utility plants and MWCs,
pilot-scale studies of activated carbon injection were conducted on utility flue gas. Preliminary results
from a limited number of pilot-scale tests on utility flue gas are summarized in Figure 2-3 and
presented in greater detail in Appendix A. These data indicate that the effectiveness of activated
carbon injection varies with several factors. The mercury removal efficiency for fabric filter and
activated carbon systems ranged from a low of 14 to 47 percent with a median of 29 percent (107-
121°C, low carbon injection) to a high of 95 to 99 percent with a median of 98 percent (88-107°C,
high carbon injection). When activated carbon injection was used ahead of a spray dryer absorber,
mercury removal efficiency ranged from 50 to 99 percent with a median of 60 percent when a fabric
filter was used for paniculate control, and from 75 to 91 percent with a median of 86 percent when an
ESP was used for particulate control.
2.3.1 Utility Flue Gas Factors Affecting Mercury Removal
The level of mercury control achieved in utility flue gas may depend upon flue gas
characteristics such as temperature, volume, form of the mercury present, the possible effect of
chloride concentration in coal on mercury speciation and the type of activated carbon injected into the
flue gas. These factors are reviewed below.
Temperature. Mercury is found predominantly in the vapor phase in utility flue gas (Clarke
and Sloss, 1992). If the vapor-phase mercury were condensed onto PM, the PM could be removed
with existing particulate control devices. Theoretically, cooler temperatures will increase mercury
condensation onto PM (Clarke and Sloss, 1992) and, subsequently, increase mercury removal with
existing PM control devices.
There is limited, preliminary evidence for the temperature dependence of mercury removal in a
pilot-scale FF study. The pilot study suggests that mercury removal efficiencies apparently increase as
the temperature of the flue gas decreases. Specifically, as the flue gas temperature decreased from 107
to 99 to 96°C (225 to 210 to 205°F), the mercury removal efficiency percentages for a pilot-scale FF
correspondingly increased from 27 to 33 to 51 percent (Chang et al., 1993).
Mercury removal efficiencies and the required amQunt of activated carbon injection were
apparently temperature dependent within a range of 88 to 121 °C (190 to 250°F) in a pilot-scale study
on the effect of reducing mercury levels in utility flue gas through activated carbon injection upstream
of a FF (Chang et al., 1993). At the lower temperatures within this range (88 to 96°C [190 to
205°F]), mercury concentrations were reduced by 97.7 percent with an activated carbon injection rate
of approximately 155 ug carbon/ug of inlet mercury, while at higher temperatures (110 to 121°C [230
to 250°F]) mercury concentrations were reduced by only 75 to 87 percent with an activated carbon
injection rate of approximately 3,500 ug carbon/ug of inlet mercury.
The pilot-scale activated carbon injection study indicated that more mercury was removed and
less carbon was needed at lower flue gas temperatures or, in other words, the ideal use of activated
carbon is at lower flue gas temperatures. It may not be possible, however, to lower the flue gas
temperature at a given utility plant because utility plants typically operate with a stack gas temperature
between 121 and 177°C (250 to 351°F) upstream of any particulate control device to avoid acid
condensation and, consequently, equipment corrosion. The stack gas temperature may be lowered
below 96°C (205°F) and acid condensation be avoided provided low-sulfur coals (less than about 1
weight percent sulfur) are burned (McKenna and Turner, 1989). If a utility burns low sulfur coal and
uses an ESP for particulate control, however, the flue gas will probably require conditioning to reduce
June 1996 2-25 SAB REVIEW DRAFT
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Figure 2-3
Comparison of Mercury Removal Efficiencies with Activated Carbon Injection
100
90
80
70
5
260
50
50
a 40
gao
20
10
0
i
i
i
_L
J_
_L
Fabric Filter +
Activated Carbon
(107-121 °C,
225-250 °F.
Low Carbon
Injection Rate
5 Data Points)
Fabric Filter +
Activated Carbon
(88-107 °C.
190-225 °F,
Low Carbon
Injection Rate
4 Data Points)
Fabric Filter +
Activated Carbon
(107-121 °C.
225-250 °F,
High Carbon
Injection Rate
4 Data Points)
Fabric Filter +
Activated Carbon
(88-107 °C,
190-225 °F,
High Carbon
Injection Rate
5 Data Points)
Carbon Injection
Ahead of
Spray Dryer
(< 93 °C. < 200 °F)
Absorber
-i- Fabric Filter
(3 Data Points)
Carbon Injection
Ahead of
Spray Dryer
Absorber
+ ESP
(9 Data Points)
Median
Source: Chang et al., 1993; Felsvang, 1993
June 1996
2-26
SAB REVIEW DRAFT
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the high resistivity of the fly ash because high resistivity makes the fly ash difficult to collect with an
ESP.
Based upon the preliminary pilot-scale studies conducted at temperatures below 121°C
(250°F), the least efficient use of carbon injection for mercury control is at higher temperatures with
greater injection rates.
Volume. At utility plants, mercury control techniques must adequately treat the entire volume
of gas in order to remove relatively small concentrations of mercury (0.2 to 21 ug/dscm, at 7 percent
O2).
Mercury Speciation and Type of Activated Carbon. The speciation of mercury will indicate
potential ways to reduce mercury emissions. For example, the ionic mercury form (i.e., Hg++) is water
soluble and is less volatile than elemental mercury (i.e., Hg°). Thus, reducing the temperature of the
flue gas and wet scrubbing of the flue gas may result in increased ionic mercury removal.
No validated methods are available at this time for quantifying mercury speciation in utility"
flue gas; however, preliminary results from an analytical technique that is under development by
Bloom et al., (1993) are summarized in Table 2-3 for coal- and oil-fired utility flue gas streams.
As shown in Table 2-3, the distribution of ionic mercury, most likely HgCl2 in coal-fired
utility flue gas, ranged from 12 to 99 percent of the total mercury content and averaged 79 percent; the
distribution of elemental mercury in coal-fired utility flue gas ranged from 0.8 to 87.5 percent of the
total mercury content and averaged 21 percent. Analysis of two samples of flue gas taken from oil-
fired boilers, however, suggests that mercury in oil-fired boiler flue gas is predominantly in the
elemental form (see Table 2-3). The variability in the speciation of vapor-phase mercury in coal-fired
flue gas may explain the variation in mercury removal that is seen with existing control devices
(DeVito et al., 1993); however, validated methods are needed to establish the speciation of mercury
before any relationship between mercury speciation and control device performance can be inferred.
The variability in the distribution of vapor-phase mercury species in coal-fired flue gas may
depend upon the chloride concentration in coal. Using the, analytical techniques developed by Bloom
et al., (1993), it has been observed that higher concentrations of ionic mercury are obtained in utility
flue gas when the combusted coal has a high chloride concentration (0.1 to 0.3 weight percent)
(Felsvang et al., 1993; Noblett et al., 1993), but more data are needed to verify this association. The
distribution of mercury species in coal-fired flue gas also appears to vary with the type of coal (e.g.,
bituminous, subbituminous, or lignite) (Chang, 1994; Boyce, 1994).
The association between chloride content of the fuel and the concentration of ionic mercury in
the flue gas also may apply to fuel oil. This association, however, has not been examined.
Although the speciation of mercury is important in planning control strategies, it is still in the
early stages of investigation. Studies of a pilot-scale wet FGD system treating coal-fired flue gas
indicate that more than 90 percent of the ionic mercury was removed while hardly any of the
elemental mercury was removed (Noblett et al., 1993). Similarly, studies at a pilot-scale SDA/ESP
system treating coal-fired flue gas suggest that 95 percent of the ionic mercury and essentially none of
the elemental mercury were removed (Felsvang et al., 1993). The effectiveness of activated carbon
injection in recovering different forms of mercury is still being studied. Preliminary results are
available, however, from two studies at three separate pilot-scale facilities.
June 1996 2-27 SAB REVIEW DRAFT
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Table 2-3
Mercury Speciation in 33 Samples of Coal-Fired and 3 Samples of Oil-Fired Utility Flue Gas
Hg/Nm^
Ionic
Other Hg Speciesc
Elemental
Totalh
(Ht'/Nm3)
Percent
Total lonicj
Elcmentul
COAL-FIRED BOILERS
5.17
4.24
296
2.84
8.7
8.6
10.8
7.86
7.7
9.4
7.7
6.03
6.46
3.03
5.36
5.98
3.5
3.1
0.29
0.41
0.41
0.56
—
—
—
„.
—
—
—
—
—
—
—
—
—
—
1.6
0.59
0.31
0.15
0.29
0.2
0.22
0.06
•
0.07
0.1
0.08
1.94
1.29
1.52
1.54
2.54
1.67
1.72
7.06
5.24
3.68
3.55
8.99
8.8
11
7.92
7.77
9.5
7.7
7.97
7.75
4.55
6.9
8.52
5.17
4.82
77.34
88.74
91.57
95.77
96.77
97.73
98.00
99.24
99.1
98.95
98.97
75.66
83.35
66.59
7768
70.19
67.7
6432
22.66
11.26
8.42
4.23
3.23
2.27
2.00
0.76
0.90
1.05
1.03
24.34
16.65
33.41
2232
2981
32.30
35.68
Reference
e
c
e
e
r
f
f
f
f
I
r
g
g
g
g
g
g
g
June 1996
2-28
SAB REVIEW DRAFT
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Table 2-3 (continued)
Mercury Speciation in 33 Samples of Coal-Fired and 3 Samples of Oil-Fired Utility Flue Gas
oa
Hg/Nrrr
Ionic
2.99
2.83
3.33
3.83
2.2
—
7.37
5.01h
5.72
4.49
2.93
2.79
5.71
7.01
4.11
1.14
Other Hg Species0
—
—
—
—
—
—
0.0021
...
1.39
0.40
0.07
0.32
1.37
1.02
0.62
0.30
Elemental
1.51
0.88
1*26
1.52
1.57
—
1.85
1.26 .
<0.1
0.8$
0.16
1.02
2.99
0.11
2.32
3.12
Total15
(pg/Nm3)
4.5
3.71
4.59
5.35
3.77
.„
9.22
6.28
7.10
5.78
3.15
4.13
10.22
8.13
7.05
4.56
Percent
Total lonicd
66.44
76.28
72.55
71.59
58.36
12.5
79.92
79.90
98.61
84.60
94.94
75.30
70.31
98.65
67.09
31.58
Elemental
33.56
23.72
2745
28.41
41.64
87.5
20.07
20.10
1.39
15.40
5.06
24.70
29.69
1.35
32.91
6842
Reference
&
&
&
g
g
h
1
j
j
i
j
,i
j
j
j
j
June 1996
2-29
SAB REVIEW DRAFF
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Table 2-3 (continued)
Mercury Speciation in 33 Samples of Coal-Fired and 3 Samples of Oil-Fired Utility Flue Gas
qa
Hg/Nnr
Ionic
Other Hg Species0
Elemental
Total13
(Hg/Nm3)
Percent
Total Ionicd
Elemental
Reference
COAL-FIRED BOILER DATA RANGES
1.1 - 10.8
0.002 - 1.4
0.06-3.1
3.1 - 11
12 - 99
1.8-88
—
OIL-FIRED BOILERS
0.03
<0.02
0.02
OIL FIRED BOILER
0.02 - 0.03
0.01
0.01
0.01
DATA RANGES
—
0.15
<0.02
0.09
0.19
—
0.12
21.05
...
25.00
78.95
—
75 .00
j
j
j
0.02-0.15
0.12-0.19
23
77
—
ug/Nm = micrograms per normal cubic inelcr (al 0"C').
b Value is a combination ol ionic and other llg species. m
c For other Hg species, the relerences list this value as an organic mercury species. According to Chang (1994), however, the oiganic meicury species values are uivalid hut could be added to the ionic
species concentrations to give a total ionic mercury value.
d The total ionic percentage represents the ionic and other llg species concentrations.
" ("hang et al., 1993. Hue gas sampled at FF inlet.
' Noblett et al., 1993. Flue gas sampled al wet scrubber inlet.
* Felsvang el al., 1993. Flue gas sampled at inlet to pilot-scale spray dryer ahsorplion (SDAVESP system.
11 Felsvang et al., 1993. Flue gas sampled at inlet to full- and pilot-scale SUA/FF system.
1 Dismukes et al., 1993.
> Bloom el al., 1993.
June 1996
2-30
SAB REVIEW DRAFT
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In testing at the first facility, a pilot-scale SDA/ESP system in Denmark (Felsvang et al.,
1993), the flue gas contained from 66.6 to 83.4 percent ionic mercury, with an average of 75.2 percent
ionic mercury, and elemental mercury comprised the remainder of the total mercury concentration in
the flue gas. Without activated carbon injection, the pilot-scale SDA/ESP system removed 96.8
percent of the ionic mercury and essentially none of the elemental mercury from coal-fired flue gas or.
in other words, the system removed 72.5 percent of the total mercury. During testing with activated
carbon injection, the flue gas contained from 58.4 to 77.7 percent ionic mercury, w;th an average of
69.5 percent ionic mercury, and elemental mercury comprised the remainder of the total mercury
concentration in the flue gas. Activated carbon injection ahead of the SDA/ESP system removed 46.4
percent of the elemental mercury and 84.3 percent of the total mercury (Felsvang et al., 1993).
In testing by Joy/Niro and Northern States Power at the second facility that had a full- and
pilot-scale SDA/FF system, the flue gas contained 85 to 90 percent elemental mercury. 'Without
activated carbon injection, the full- and pilot-scale SDA/FF systems removed 10 to 20 percent of the
total mercury from the coal-fired flue gas (Felsvang et al., 1993), and the low removal of total
mercury may be attributed to essentially complete removal of the ionic mercury and poor removal of
the elemental mercury. Activated carbon injection ahead of the pilot-scale SDA/FF system increased
the removal of total mercury to approximately 55 percent, and injection of iodide- and sulfur-
impregnated activated carbon increased the removal of total mercury to approximately 90 percent
(Felsvang et al., 1993). Thus, the studies at this SDA/FF system suggest that sulfur- and iodide-
impregnated carbons are needed for total mercury removals of 90 percent, when elemental mercury is
the predominant mercury species. Furthermore, the studies suggest that total mercury removal
efficiencies are dependent upon mercury speciation.
Finally, recent tests conducted at a third facility, the pilot-scale combustor and FF at the
University of North Dakota Energy and Environmental Research Center (UNDEERC), also suggest
that mercury removal is dependent upon mercury speciation and the type of carbon used (Chang,
1994). The details of the tests conducted at UNDEERC were not available when this report was
prepared.
2.3.2 Current Research on Activated Carbon Injection for Utilities
•
Currently, research is being done on activated carbon injection at a pilot-scale SDA/FF plant
by Joy/Niro and Northern States Power Company (Felsvang et al., 1993), at a pilot-scale pulse-jet FF
plant by the Electric Power Research Institute (EPRI) (Chang et al., 1993) and at a pilot combustor
and FF plant by UNDEERC and EPRI (Chang, 1994). The EPRI plans to test activated carbon
injection on a full-size electric utility boiler.
2.4 Emerging Technologies for Controlling Mercury Emissions from Utilities
Research continues on developing potential technologies for mercury emission reduction from
utility plants. Although activated carbon injection has been shown to be a promising technology,
research with impregnated activated carbons, sodium sulfide (Na2S) injection and an activated carbon
circulating fluidized bed (CFB) suggest that even greater mercury removal is possible.
With sulfur-impregnated activated carbon injection, the carbon-bound sulfur reacts with
mercury to form mercuric sulfide (HgS) on the carbon, and the carbon is removed by a paniculate
control device. In a pilot-scale study, sulfur-impregnated carbon increased mercury removal to 80
percent, an increase of 25 percent over results achieved with an equal amount of nonimpregnated
activated carbon (Felsvang et al., 1993).
2-31
-------
With iodide-impregnated activated carbon injection, the carbon-bound iodide reacts with
mercury to form mercuric iodide (Hgl2) on the carbon, and the carbon is removed by a paniculate
control device. In a pilot-scale study, iodide-impregnated carbon increased mercury removal to nearly
100 percent, an increase of 45 percent over results achieved with an equal amount of nonimpregnated
activated carbon (Felsvang et al., 1993).
Chloride-impregnated activated carbon injection has only been tested on MWCs in Europe.
The chloride reacts with mercury to form HgCl2 on the carbon, and the carbon is removed by a
particulate control device. European MWC experiments have shown that impregnating activated
carbon with chloride salts increases adsorptive capacity of the activated carbon 300-fold (New Jersey
Department of Environmental Protection and Energy, 1992).
Another potential way for improving Hg collection efficiency is combining calcium hydroxide
(Ca(OH)2) with activated carbon. This reagent, consisting of approximately 95 to 97 percent lime and
3 to 5 percent activated carbon, is known under the product name Sorbalit® (Nebel and White, 1991).
Sorbalit® has only been tested on European MWCs and MWIs.
Sulfur-, iodide-, chloride salt- and Ca(OH)2-impregnated activated carbons show promise for
increasing the mercury removal efficiency, but further testing is needed. The cost of these modified
carbons can be as much as 20 times higher than that of unmodified activated carbon (Maxwell, 1993).
Mercury reduction has been achieved at MWCs through the injection of NaoS solution into the
flue gas prior to the acid gas control device. The specific reactions of Na2S and mercury (Hg) are not
totally clear but appear to be (Nebel and White, 1991):
Hg (gas) + Na2S + 2H2O =»• HgS (Solid) + 2NaOH + H2 and
HgCl2 (gas) + Na2S =*• HgS (Solid) + 2NaCl.
The resulting solid, HgS, can be collected by a FF.
There are several potential limitations to Na2S injection. These include reaction of Na2S with
calcium (Ca) in the sorbent (as found in Sorbalit®) to form calcium sulfide (CaS), reduction of the
amount of sulfur available to react with mercury (CaS can also cause scaling of the sorbent feed line),
corrosion of ductwork (Na2S is a corrosive material), clogging and plugging of the screw conveyor
due to solidification of Na2S and sludge formation due to the presence of inorganic salts in the mixing
water (Nebel and White, 1991).
At present, full-scale operational injection of Na2S has been done only in MWCs. No plans
have been announced to test this technology on fossil fuel-fired electric steam-generating units.
Another potential process for the reduction of mercury emissions is the use of activated carbon
in a CFB (Clarke and Sloss, 1992). In a CFB, the activated carbon is continuously fed to the reactor
where it is mixed with the flue gas at a relatively high velocity, separated in the subsequent FF and
recycled to the reactor. A small part of the used activated carbon is withdrawn from the process and
replaced by fresh material (New Jersey Department of Environmental Protection and Energy, 1992).
The main advantages to CFB's over fixed carbon beds are the increased flue gas-to-carbon
contact area and the smaller overall pressure drop. No pilot- or full-scale utility boiler testing has yet
been done with this system, although it has been used in Germany for MWC operation.
2-32
-------
Additional developing technologies for utility boilers also include a condensing heal
exchanger, wet FGD additives, gold-impregnated monoliths, and advanced coal cleaning.
2-33
-------
3. COST AND FINANCIAL IMPACTS OF MERCURY CONTROLS
Several technologies are available for the control of mercury emissions. This section
summarizes the cost effectiveness of a variety of technologies (Section 3.1). It also presents an
analysis of the potential financial impacts associated with the use of each technology (Section 3.2).
3.1 Cost Effectiveness
Cost information on each of the control technologies described in Chapter 2 was obtained from
the literature and pollution control technology vendors. This information was used to estimate the cost
of installing and operating applicable mercury control techniques at model plants within the six source
categories studied. Each of the model plants considered in the cost evaluation is defined in the box on
the next two pages. The cost estimates for these model plants reflect generalized costs and are not
intended to be site-specific. Plant-to-plant variations can result in higher or lower technology
performance and associated costs. Detailed documentation and analysis of model plant cost is
provided in Appendix B.
The cost estimates were combined with the mercury removal efficiencies presented in Chapter
2 to develop cost effectiveness values for various mercury controls applied to model plants for each
industry. Table 3-1 summarizes the results of the cost effectiveness analysis. This table presents, for
each of the six emission sources, the applicable mercury controls and the estimated cost effectiveness,
both in dollars per pound of mercury ($/lb Hg) removed and other measures (e.g., $/ton of medical
waste for MWIs and $/ton of copper produced from primary copper smelters).
To determine how the cost-effectiveness of carbon injection might vary with different chlorine
levels in the coal, a sensitivity analysis was performed which assumed various levels of HgCl2 in the
flue gas. These results are shown in Table 3-1 and also described in Section B.3.2. (Note that utility
deregulation could impact the competitiveness of certain utilities and affect their ability to pass costs to
consumers.)
3.2 Financial Analysis •
This section presents an analysis of the ability of the six industries studied (MWCs, MWIs,
utility boilers, chlor-alkali plants, primary copper smelters and primary lead smelters) to finance the
mercury controls for which the capital and annual costs have been estimated on a model plant basis.
The methodology for conducting the financial analysis is described first followed by the results. The
financial impact of installing polishing wet scrubbers to control mercury in MWC and MWI emissions
was not analyzed because the activated carbon technology is less expensive and as effective, so it is
more likely to be the technology of choice.
3.2.1 Methodology
MWCs, MWIs and utility boilers provide a service to consumers whom, in general, do not
have other options for acquiring the same service. Consequently, all or part of the cost of control
usually can be passed on directly to the consumer in the form of a cost increase for the service. For
these industries, financial impact was determined from the potential increase in product or
June 1996 3-1 SAB REVIEW DRAFT
-------
Definition of Model Plants Considered in the Cost Evaluation
Municipal Waste Combustors fMWCs)
Two model plants, both assumed to operate at full capacity 90 percent of the year.
(1) A small mass burn/waterwall (MB/WW) MWC with two units and a total plant capacity of 180 Me/day
(200 tpd); equipped with dry sorbent injection (DSI) and an ESP.
(2) A large MB/WW MWC with three units and a total plant capacity of 2,045 Mg/day (2.250 tpd) of MSW;
equipped with a SD/FF pollution control system.
Medical Waste Incinerators (MWls)
Two model plants, both assumed to have an inlet mercury level of 3,000 ng/dscm (1,310 g/million dscf); no
mercury control across the DSI/FF system; and DSI/FF systems that operate at a temperature of 160°C across the
FF.
(1) A small batch-run MWI with design capacity of 90 kg/hr (200 Ib/hr), but operating at an average
throughput of 60 kg/hr (130 Ib/hr) because of the high heat content of the waste; assumed to operate 5.5
hr/day, 5 days/week (which equals a capacity factor of 20 percent); equipped with a DSI/FF system.
(2) A larger, commercial MWI; design capacity of 680 kg/hr (1,500 Ib/hr), but operates at 455 kg/hr (1.000
Ib/hr); operates 24 hr/day, 7 days/week; operates 90 percent of the year; equipped with a DSI/FF system.
Utility Boilers
Three model plants; all three assumed to operate with a capacity factor of 65 percent (5.694 hr/yr); chloride levels
in fuel assumed to be sufficiently high that all mercury in the flue gas is in the form of HgCl,; inlet mercury level
to the control systems associated with each coal-fired model plant is 10 ng/dscm (4.4 g/million dscf) at 20°C.
(1) A 975-MW coal-fired boiler firing low-sulfur coal; has a flue gas volume of 4.050,000 dscm/hr and is
equipped with a cold-side ESP; temperature ahead of the ESP is 157°C and the temperature exiting the
ESP is 150°C; no mercury control across the ESP is assumed; four mercury control variations considered:
(a) activated carbon (AC) injection
(b) spray cooler, AC injection, FF
(c) spray cooler, AC injection
(d) carbon filter bed
(2) A 975-MW coal-fired boiler firing high-sulfur coal; equipped with a cold-side ESP (150°C) and a FGD
system; FGD system assumed to be 50 percent efficient for mercury control and the controlled mercury
level is 5 |ag/dscm (2.2 g/million dscf); also equipped with a carbon filter bed for mercury control.
June 1996 3-2 SAB REVIEW DRAFT
-------
Definition of Model Plants Considered in the Cost Evaluation
(continued)
Utility Boilers (continued)
(3) Identical to model plant (1), except that it has a capacity of 100 MW; assumed to have a flue gas volume
of 411,000 dscm/hr. the gas temperature ahead of the ESP is 146°C and the ESP outlet temperature is
137°C; no mercury control across the ESP is assumed, but two variations of the model plant are equipped
with the following for mercury control:
(a) AC injection
(b) spray cooler, AC injection, FF
Chlor-alkali Plants
One model plant that produces 273 Mg (300 tons) of chlorine per day (represents the mid-range size of chlor-alkali
plants in operation); assumed to have individual flow rates from the hydrogen and end-box streams of 4.080
dscm/hr (144,000 dscf/hr) each at 21 percent 0-, (combined to equal 8,160 dscm/hr): baseline control systems for
both streams consist of a heat exchanger to cool the gas followed by a knockout drum to separate the condensed
mercury from the hydrogen and end-box streams; a mercury level of 1,000 g/day after this baseline control is
assumed: mercury control options considered were conversion to the membrane cell process and control of the
hydrogen and end-box streams through the use of brine scrubbing and treated AC adsorption; no additional controls
examined for the cell room.
Primary Copper Smelters
One model plant consisting of a flash furnace and three Fierce-Smith converters; off-gases from the furnace are
combined with the off-gas from the converters to form the feed to a single-stage acid plant; the feed to the acid
plant has a maximum flow rate of 124,000 scm/hr (4,370,000 scf/hr); the plant has a capacity to process 910
Mg/day (1,000 tpd) of ore consisting of 27 percent copper and 32 percent sulfur, which corresponds to a
production capacity of 78,000 Mg/yr of copper; a capacity factor of 90 percent is assumed, corresponding to 236
Mg/day (260 tpd) copper production capacity.
Primary Lead Smelters
One model plant consisting of a sintering machine, which feeds to a blast furnace and a dross furnace; because the
singeing machine is an updraft machine (which does not employ recirculation of the weak gas), there are two
offgas streams — one strong SO, stream and one weak SO-, stream; the strong stream is fed to a single-stage acid
plant at a flow rate of 31,600 scm/hr (1,120,000 scf/hr); the weak stream, with a flow rate of 138,000 scm/hr
(4,860,000 scf/hr) is sent to an FF for paniculate control and emitted to the atmosphere; the offgases from the
dross furnace are fed to an FF at a flow rate of 72,000 scm/hr (2.550,000 scf/hr) for PM control and emitted to the
atmosphere; the lead production capacity is assumed to be 90,900 Mg/yr (100,000 tons/yr) from concentrate
containing 55 percent lead and 16 percent sulfur, the plant is assumed to operate 90 percent of the year,
corresponding to a daily capacity of 276 Mg/day (304 tpd).
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Table 3-1
Cost Effectiveness of Control Technologies
Source
Mercury Control
Technique
Cost Effectiveness
$/lb Hg Removed
Other Measures
Cost Comments
MWCs
Material separation
(batteries)
Production substitution
(e.g., batteries, fluorescent
lights)
Activated carbon injection
Carbon filter beds
Polishing wet scrubber
1,450
$0.37/ton MSW
211-870
513-1,083
1,600-3,320
$0.7-3.5/ton MSW
$5.44-9.39/ton MSW
$5.3-13.5/lon MSW
Costs are very community specific; Results shown
are based on one community's program
The potential for product substitutions requires dial
the specific circumstances of each situation be
examined; general cost estimates are not possible
Costs assume an 85% reduction; range of costs
cover the two model plants
Range of costs cover the two model plants
Costs assume an 85 percent reduction; range of
costs cover the two model plants
MWls
Material separation
(batteries)
Activated carbon injection
Polishing wet scrubber
228-955
310
$10.3-43/ton
medical waste
$12/lon
medical waste
Costs vary on a site-specific basis; no costs were
available; cost effectiveness for a hospital program
would be assumed to be better than for a
community program
Costs assume an. 85 percent mercury reduction; acid
gas controls are assumed to be in place; range of
costs cover Die two model plants
Costs developed for the large model plant only (see
box on pages 3-2 and 3-3); acid gas controls are
assumed to be in place
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Table 3-1
Cost Effectiveness of Control Technologies
(continued)
Source
Utility Boilers
Chlor-Alkali Plants
Using Mercury Cell
Process
Primary Copper
Smellers
Primary Lead
Smelters
Sintering Stream
Furnace Stream
Mercury Control
Technique
Carbon filler beds
Activated carbon injection
(coal fired) 100% of Hg as
HgCI2
80% of Hg as HgCl2
50% of Hg as HgCI2
30% of Hg as HgCI2
Process modification
Depleted brine scrubbing
Treated activated carbon
adsorption
Selenium filters
Selenium filters
Selenium fillers
Cosl Effectiveness
$/lb Hg Removed
33,000-38,000
4,970-27,700
6,190-34,600
9,840-55,400
16,300-92,000
4,590
1,040
•
769
497
541
520
Olher Measures
2.7-3.1 mills/kWh
0.41-2.26
0.41-2.26
0.40-2.25
0.40-2.25
$39.6/ton chlorine
produced
$6.7/lon chlorine
produced
$5.1 /ion chlorine
produced
$11.3/ton copper
produced
$2.7/ton lead produced
$5.8/lon lead produced
Cost Comments
Range of costs covers two model plants (Models Id
and 2 in the box on pages 3-1 and 3-2)
Range of cosls covers model plants burning coal
(Models la, 3a, Ib, 3b, and Ic)
Cost effectiveness calculated using capital and
electrical costs only
Cosl data were scaled from 1972 dollars
Cost data were scaled from 1972 dollars
Cost dala and information on mercury emissions at
copper smellers are very limited
Cost dala and information on mercury emissions at
lead smelters are very limited
Cosl dala and information on mercury emissions at
lead smelters are very limited
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service cost to the consumer arising from the cost of the mercury controls. This ratio, calculated as
the ratio of annual control costs to revenues, reflects the potential percent cost increase necessary to
recover the control costs.
For chlor-alkali plants, primary copper smelters and primary lead smelters, individual
companies have little control over the price they are able to receive for their respective products. In
each industry, individual companies are competing against other domestic producers and against
foreign producers of the same products. Therefore, prices are often determined by international
markets. In addition, primary copper smelters and primary lead smelters must also compete against
domestic and foreign secondary producers that recover copper and lead from scrap materials, rather
than from ores mined from the earth.
Because fndividual companies in these industries have little control over the price they receive
for their products, mercury control costs cannot be passed on to the consumer. Therefore, the funds to
purchase mercury controls must be financed with existing profits. The financial impact from installing
and operating the mercury controls for these industries was determined from the ratio of total annual
control costs to profits and the ratio of annual capital costs to annual expenditures. The annual capital
costs of control equipment are the initial capital costs of equipment distributed over the lifetime of the
equipment. These measures of financial impact represent the ability of the industries to absorb the
annual control costs and to acquire the capital needed to purchase the controls while still remaining
competitive.
Information on profits and expenditures was not available for the primary lead smelter industry
because there are only two companies in the U.S. industry and this information is considered
confidential. Consequently, potential increases in lead prices necessary to recover control costs were
determined for this industry using the same methodology as was used for MWCs, MWIs, and utilities.
3.2.2 Results
The financial impact of installing mercury emission controls for the above-referenced
industries is summarized in this section. Activated carbon injection costs were calculated for MWCs,
MWIs and utility boilers. Costs of carbon filter beds were, calculated for MWCs and utility boilers.
The costs of membrane cell process conversion, depleted brine scrubbing and treated activated carbon
adsorption were calculated for chlor-alkali plants. Selenium filter costs were calculated for primary
copper smelters and primary lead smelters.
Municipal Waste Combustors.- For the small and large MWC model plants, which are
described in Appendix B, total revenues are estimated to be $3.4 million and $38.0 million,
respectively (see Table 3-2). Revenues for MWCs are typically derived from energy production,
tipping fees (the fee received by the MWC for each ton of MSW received), and sale of materials
collected on site for recycling. Because information on revenues from tipping fees and recycling sales
are not available, total revenues for the MWCs were estimated from electricity sales. An industry
source estimates that electricity sales typically account for 35 to 50 percent of a facility's revenues
(Kiser and Burton, 1992). Therefore, total revenues were estimated to be equal to twice the value of
electricity sales. Electricity sales were estimated based on the average net kilowatt-hours generated per
ton of MSW combusted (533 kWh/Mg [485 kWh/ton]), the annual amount of MSW combusted for the
model plants (60,000 Mg/yr [66,000 tons/yr] for the small MWC and 672,000 Mg/yr [739,000 tons/yr]
for the large MWC), and the average price paid for electricity ($0.053/kWh) (Berenyi and Gould,
1993).
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Table 3-2
Estimated Annual Revenues and Potential Cost Increases9 for MWCs, MWIs and Lead Smelters
Parameter
Total Annual Revenues
(millions of dollars)
Potential Cost Increases
Activated Carbon
Injection
Carbon Filter
Beds
Selenium Filter
Municipal Waste
Combustors
Smallb; $3.4
Largec: $38
Smallb: 6.9%
Largec: 1.3%
Smallb: 83%
Largec: 35%
N/Ad
Medical Waste Incinerators
Hospital: $32.5
Commercial: $2.0
Hospital: 0.02%
Commercial: 2.0%
_.e
~e
N/A
Primary Lead Smelters
$66.8
N/A
N/A
1.3%.
a Potential cost increase = total annual operating cost divided by total annual revenue. Represents the potential cost increase in service or product to cover the cost of controls.
b Capacity = 180 Mg/day. .
c Capacity = 2,045 Mg/day.
d N/A = control technology is not applicable.
e The costs of the carbon filter beds were not estimated for this model plant.
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The MWC mercury control costs for activated carbon injection and carbon filter beds were
estimated in Appendix B. The estimated annual control costs for activated carbon injection for the
small MWC are $232,000, indicating a potential 6.9 percent cost increase. For the large MWC, the
estimated annual control costs for activated carbon injection are $520,000, indicating a potential
1.3 percent cost increase. The estimated annual control cost for carbon filter beds are $2.81 million or
an 83 percent potential increase for the small MWC, and $13.2 million or a 35 percent potential cost
increase for the large MWC. Reliable cost data on battery separation programs as mercury control
options were not available, so cost increases arising from these programs could not be estimated.
Medical Waste Incinerators. -Control costs for activated carbon injection were estimated in
Appendix B for a small batch-operated MWI and a large continuously operated MWI. The small
MWI, which incinerates about 100 Mg/yr (90 tons/yr) of medical waste, is assumed to be operated by
a hospital. The large MWI, which incinerates about 3,600 Mg/yr (3,300 tons/yr) of medical waste, is
assumed to be part of a commercial MWI operation.
As summarized in Table 3-2, average hospital revenues are estimated to be about $32.5.million
annually and about 46 percent of all hospitals operate an MWI (U.S. EPA, 1991a; U.S. EPA, 1994d).
The total annual control costs for activated carbon injection on the small MWI are estimated to be
$5,040, indicating a potential 0.02 percent increase in the cost of hospital services.
Average annual revenues for commercial MWIs are estimated to be about $2 million, based on
a typical commercial incineration fee of $660/Mg ($600/ton) and a throughput of 3,000 Mg/yr (3,300
tons/yr) of medical waste (U.S. EPA, 199la). The estimated total annual control costs for activated
carbon injection on the large commercial MWI are about $40,600, indicating a potential 2.0 percent
increase in the cost of services.
Primary Lead Smelters. Control costs for selenium filters were estimated in Appendix B for a
model primary lead smelter. Because there are only two U.S. lead smelters, information on profits and
expenditures is considered confidential and was not available. Therefore, the potential lead price
increase necessary to recover control costs was calculated for this industry as a measure of financial
impact. The actual financial impact of this control, however, should be lower than this measure would
indicate because this industry operates at a very narrow profit margin. The average revenue for
primary lead smelters was estimated from the model plant's annual lead production and the average
North American producer price for lead from 1992 and 1993 of $0.73/kg ($0.33/lb). Average smelter
revenue is estimated to be $66.8 million.
The estimated annual costs for a selenium filter controlling the sintering flue gas stream
upstream of the acid plant are $266,000. The estimated annual costs of two selenium filters
controlling the blast furnace and dross furnace flue gas streams after the FF on the model plant are
$584,000. The combined total annual costs of control on the model plant are estimated to be about
$850,000, indicating a 1.3 percent potential increase in lead prices necessary to recover control costs
(see Table 3-2).
Chlor-Alkali Plants. Control costs were estimated for three different control scenarios:
(1) conversion of the model plant to a membrane cell process; (2) control of emissions from the
existing mercury cell plant with depleted brine scrubbing; and (3) control of emissions with treated
activated carbon adsorption. Results of the analysis are summarized in Table 3-3.
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Table 3-3
Estimated Annual Profits, Expenditures,
Revenues and Financial Impacts3
Parameter
Chlor-Alkali Plants
Primary Copper
Smelters
Total Annual Profits
(millions of dollars)
Total Annual Expenditures
(millions of dollars)
$12.9
$26.7
$22.0
$204
Financial Impact
Membrane Cell Process
Depleted Brine
Scrubbing
Treated Activated
Carbon Adsorption
Selenium Filters
12% of Expenditures
5.1% of Profits
0.7% of Expenditures
3.9% of Profits
0.5% of Expenditures
N/A
N/Ab
N/A
N/A
4.4% of Profits
0.2% of Expenditures
a Financial impact = total annual control costs divided by profits and annual capital costs divided by total expenditures.
b N/A = control technology is not applicable.
Note: The percentage of annual profits represents the amount of profit that would be needed to absorb the control costs.
The percentage of annual expenditures provides a measure of the industry's ability to acquire the capital needed for the
controls while still remaining competitive.
Information on profits and expenditures for the chlor-alkali industry were obtained from the
1987 Census of Manufacturers, which reported 27 companies operating 45 plants. Financial data
specific to the 14 chlor-alkali plants that use the mercury cell process could not be obtained. Financial
data were subsequently corrected to 1990 dollars using the Consumer Price Index. Total annual profits
were $581.2 million, or an estimated average of $12.9 million per plant. Total annual expenditures for
the industry were $1.20 billion, or an estimated average of $26.7 million per plant (U.S. Department of
Commerce, 1990a).
The membrane cell process has lower electricity costs than the mercury cell process and,
consequently, electricity savings were considered in estimating plant conversion costs. The estimated
net annual capital cost of converting the model plant to a membrane cell process, after deducting
estimated electricity savings, is about $3.3 million, or about 12 percent of total annual expenditures.
Comprehensive data on other annual operating expenses for the membrane cell process were not
available, so the total annual operating expenses for the membrane cell process could not be
determined. Consequently, the financial impact of this control, measured by annual costs as a
percentage of profits, could not be determined.
The estimated total annual costs for depleted brine scrubbing on the combined hydrogen and
end-box stream, including the costs for secondary cooling and mist elimination, are estimated to be
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$662,000, or 5.1 percent of annual profits. The estimated annual capital recovery cost for this control
is $177,000, or 0.1 percent of annual expenditures. These numbers provide a measure of the ability of
the industry to absorb the control costs, and the ability of the industry to acquire the capital needed for
the controls while still remaining competitive.
The total annual costs for treated activated carbon adsorption on the combined hydrogen and
end-box stream, including the costs for secondary cooling and mist elimination, are estimated to be
$500,000, or 3.9 percent of profits. The estimated annual capital recovery cost for this control is
$134,000, or 0.5 percent of annual expenditures.
Primary Copper Smelters. Control costs for selenium filters were estimated for a model
primary copper smelter (see Table 3-3). Information on profits and expenditures was obtained from
the 1987 Census of Manufactures and subsequently corrected to 1990 dollars using the Consumer
Price Index (U.S. Department of Commerce, 1990b). In 1987, there were 8 companies operating
13 plants. As of 1994, however, there are eight plants operated by six companies, which indicates a
change in industry structure. The 1987 financial .data were the most recent available for this analysis.
Total annual profits in 1987 were $285.8 million, or an average of $22.0 million per smelter. Total
primary copper smelter annual expenditures in 1987 were $2.66 billion, or an average of $204 million
per smelter (U.S. Department of Commerce, 1990b).
Estimated annual costs for selenium filters for the model copper smelter are $961,000, or
4.4 percent of profits. The estimated annual capital recovery cost for the selenium filters is $355,000,
or 0.2 percent of expenditures. These numbers provide a measure of the ability of the industry to
absorb the control costs, and the ability of the industry to acquire the capital needed for the controls
while still remaining competitive.
Utility Boilers. Control costs were estimated for activated carbon injection (with and without
spray coolers and FFs) and carbon filter beds for three models of coal-fired utility boilers. Revenues
were also estimated for each of the models and a potential cost increase for electricity was determined
for each of the model boiler/control technology combinations.
The models included two large boilers (975-MW sapacity). The first model boiler fired low-
sulfur coal and was controlled by an ESP. The second model boiler fired high-sulfur coal and was
controlled by an ESP and FGD. The third model was a small utility boiler (100-MW capacity) firing
low-sulfur coal and controlled by an ESP. The different utility boiler models and the mercury controls
applied to each are summarized in Table 3-4, along with estimated annual revenues for each model
boiler, the estimated cost of control and the potential cost increase for each model/control technology
combination.
Annual revenues were estimated for the model boilers based on revenues from electricity sales
and electric generating capacity for 20 utility companies (Value Line Publishing, 1994a and 1994b).
The median annual revenues per megawatt of generating capacity from these 20 companies was
$453,000; the range was $268,000 to $723,000/MW of generating capacity. Revenues were estimated
for the model boilers from the revenue factor of $453,000/MW of capacity and by applying a load
factor of 65 percent (i.e., only 65 percent of generating capacity is utilized on an annual basis).
The estimated revenues for the 975-MW boiler are $287 million; estimated revenues for the
100-MW boiler are $29 million. Potential electricity cost increases for each model plant and control
scenario are presented in the last column of Table 3-4.
June 1996 3-10 SAB REVIEW DRAFT
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Table 3-4
Model Utility Boilers: Estimated Annual Revenues and Potential Cost Increases21
Modelb
la
Ib
Ic
Id
2
3a
3b
Size
(MW)
975
975
975
975
975
100
100
Fuel
Low-sulfur coal
Low-sulfur coal
Low-sulfur coal
Low-sulfur coal
High-sulfur coal
Low-sulfur coal
Low-sulfur coal
Pre-Existing
Controls
ESP
ESP
ESP
ESP
ESP/FGD
ESP
ESP
Estimated
Revenues
($ Million)
287
287
287
287
287
29
29
Mercury Control
AC injection0
Spray cooler, AC injection, FF
Spray cooler, AC injection
Carbon filter bed
Carbon filter bed
AC injection
Spray cooler, AC injection, FF
Annual
Control Costs
($ Million)
10.1
7.9
2.4
59.9
60.7
0.64
1.3
Potential Cost
Increase
%
3.5
2.8
0.8
21
21
2.2
4.4
a Potential cost increase = tolal annual operating costs divided bj^total annual revenues, which represents the potential increase in electricity costs to cover the costs of contiol.
b See model plant description in box on pages 3-2 and 3-3 as well as Appendix B.
c AC = activated carbon.
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4. MERCURY CONTROL STRATEGIES
There are a number of laws, regulations and other initiatives designed to control mercury uses.
releases to the environment and exposures among people and ecological receptors. Many of these
programs have a direct bearing on the extent and effects of mercury emissions to the atmosphere.
This chapter summarizes existing and emerging authorities and activities that influence
mercury emissions. This review is not intended to be comprehensive or complete, but rather focuses
on major federal initiatives and relevant activities in selected states (principally states in the Great
Lakes region). The chapter starts with an overview of ongoing federal and state activities in Section
4.1. Management alternatives and statutory authorities for controlling mercury emissions under the
Clean Air Act are then presented in Section 4.2.
4.1 Ongoing Federal and State Activities
Mercury regulation and control spans multiple federal and state statutes. Ongoing programs to
control mercury uses, releases and exposures under a spectrum of environmental laws are summarized
below, first at the federal level and then at the state level.
4.1.1 Federal Activities
Several federal agencies have authority and responsibility for controlling mercury uses,
releases and exposures. For example, U.S. EPA has addressed for many years and continues to
address the risks posed by mercury through regulations designed to limit releases to air, water and
land. The Food and Drug Administration (FDA) regulates mercury in cosmetics, food and dental
products. The Occupational Safety and Health Administration (OSHA) regulates mercury air
exposures in the workplace.
Table 4-1 summarizes major federal activities to control mercury uses, releases and exposures.
In general terms, these activities can be grouped into environmental media standards, use- or release-
related regulations and other standards and programs.
•
• Environmental media standards are numeric criteria that specify a maximum acceptable
mercury concentration for different media, based on scientific or risk-based criteria.
These standards have an indirect effect on individual sources. For instance, mercury
standards shown in Table 4-1 for different media influence how much mercury
different sources can release into the environment, both individually and cumulatively.
• Use- or release-related regulations have a direct effect on sources that use mercury or
release mercury into the environment. These regulations specify, for individual
sources or types of waste materials, the conditions associated with mercury disposal
and release. Additionally, these regulations specify the conditions associated with
using mercury in the manufacture of different products (batteries, paints, pesticides,
etc.).
• Other standards and programs, for the purpose of this review, include regulations
designed to limit mercury exposures in the workplace and during transportation, as
well as special government initiatives to address mercury problems in an integrated
manner (i.e., the Virtual Elimination Project and U.S. EPA's Mercury Task Force).
June 1996 4-1 SAB REVIEW DRAFT
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Table 4-1
Federal Mercury Controls"
SPECIFIC SOURCES/FOCUS
CONTROL/ACTION
ENVIRONMENTAL MEDIA
Drinking Water
Surface Water
Air
Soil
Air Point Sources
Water Point Sources
Sewage Sludge
« Maximum contaminant level (MCL) = 0.002 mg/L (40 CFR 141.62, 21 CFR 103.35).
• Ambient Water Quality Criteria; water and organisms = 0.012 fig/L (40 CFR 401, 403, Appendix B).
• Water Quality Guidance for the Great Lakes System: aquatic life = 1.44 ng/L (acute) and 0.77 pg/L (chronic);
human health = 0.0018 ug/L; wildlife = 0.0013 ug/L (40 CFR 132).
• No ambient air standard.
• No soil standard.
ENVIRONMENTAL SOURCES
• Emissions Itom mercury ore processing facilities and mercury cell chlor-alkuli plants are limited to a maximum ol 2,300 g/24
hours (40 CFR 61.01).
» Emissions from sludge incineration plants, sludge drying plants, or a combination of these that process wastewaler treatment
plant sludges are limited to a maximum of 3,200 g/24 hours (40 CFR 61.52).
• Industrial sources emitting mercury and mercury compounds may be subject to Maximum Achievable Control Technology
(MACT) standards for major stationary sources and Generally Available Control Technology (GACT) standards for area
sources.1*
• Emission guideline? on mercury emissions from municipal waste combustors under §§111 and 129 of the 1990 Clean Air Act
Amendments.
• Regulations on mercury emissions from medical waste incinerators under §§111 and 129 of the 1990 Clean Air Act
Amendments were proposed in 1995 (60 FR 10654, February 27, 1995).
• Airborne emissions of mercury and other substances from the burning of hazardous waste in boilers and industrial lurnaces,
including cement kilns, are regulated under the Resource Conservation and Recovery Act (40 CFR 266).
• Effluents from industrial facilities and municipal wastewater treatment facilities are regulated through industry-specific
pre'treatment standards and effluent guidelines for existing and new sources of pollution and are based on the limits of the
available control technology (40 CFR 401, 403, Appendix B).
• Groundwater at hazardous waste treatment, storage and disposal facilities must be monitored for the presence of mercury (40
CFR 302.4, 264.94).
• Permissible levels of mercury in municipal waslewater treatment sludges: 17 nig/kg dry wt. and cumulative load ol 17
kg/hectare for agricultural land; 17 mg/kg dry wt. and annual load of 0.85 kg/hectare for home gaiden or lawn; 57 mg/kg dry
wl. for other land applications; and 100 kg/hectare lor surface disposal (CWA).
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Table 4-1
Federal Mercury Controls (continued)
SPECIFIC SOURCES/FOCUS
Mercury-Containing Wastes
Any Environmental Release
Foodstuffs or Feed
CONTROL/ACTION
• Any solid waste (including soil that is being disposed) is considered a hazardous substance and prohibited from disposal in
RCRA Subtitle D (non-hazardous) landfills if its leachate contains 0.2 mg/L mercury or greater (40 CFR 261.24); land
disposal in RCRA Subtitle C (hazardous) landfills is allowed only after prescribed treatment to reduce mercury in extract to
0.2 mg/L (40 CFR 268).
• Certain wastes are listed as hazardous due, at least in part, to the presence of mercury (e.g., K071 = brine purification muds
from the mercury cell process in chlorine production, and K106 = waslewater treatment sludge from the mercuiy cell process
in chlorine production).
• The amount of mercury in a number of hazardous waslewaters (e.g., F039, K071, K106, P065, P092) must be treated down to
specified levels to meet the land disposal restrictions. ,
• Any release of 1 pound or more of mercury into the environment in a 24-hour period (the reportable quantity) must be
reported immediately to the National Response Center if the release is not federally permitted (40 CFR 302).
• Certain facilities that release more than a reportable quantity of mercury must immediately report the release to stale and local
entities.
• Any release or transfer of mercury by facilities that exceed use or manufacturing thresholds is reporlahle under the Toxic
Release Inventory.
• Action level for melhylmercury in fish, shellfish and other aquatic animals = 1 ppm (FDA CPG 7180.07).
• The import of foods containing the residue of mercury-containing pesticides that are not registered for use in the U.S. is
prohibited.
PRODUCTS
Batteries
Paints and Pigments
Dental Uses
• By early 1991, all U.S. manufacturers converted production so that the mercury content of batteries, except in button and coin
cells, did not exceed 0.025% by weight.
• Federal legislation pending concerning the manufacture of only "non-mercury" formula batteries of all types by 1-1-97.
• Federal ban on mercury button cell batteries pending as of 1-1-95.
• Federal legislation permitting only the manufacture of "no mercury" formula zinc carbon batteries pending as of 1-1-95.
• All uses of mercury in paints have been discontinued.
• Dental mercury is classified as a Class I medical device, with extensive safely regulations on its use. Dental amalgam alloy is
classified as a Class 11 device, subject to additional special controls.
• U.S. Public Health Service has recently studied risks Irom mercury amalgams and recommended lighter controls on denial
uses of mercury and further research to reach more definitive conclusions on risk.
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Table 4-1
Federal Mercury Controls (continued)
SPECIFIC SOURCES/FOCUS
Lighting
Pesticides
Special Paper Coatings
Pharmaceuticals
Cosmetics
CONTROL/ACTION
• Because many fluorescent lamps are classified as RCRA hazardous wastes under current lest procedures, U.S. BPA is
evaluating options for lamp disposal. Major options are 1) conditional exclusion of lamps from hazardous waste management
requirements, and 2) handling lamps in a special collection system for other "loV grade" and small quantity hazardous wastes
(such as batteries and household pesticides).
• No current production of mercury-containing pesticides; all former registrations have been cancelled or requests for voluntary
cancellation have been received.
• The only two companies that manufacture these products have announced that plans are being developed to phase out the use
of mercury in the coatings. ,
• It is predicted that mercury will be eliminated entirely from this application by 1995.
• Removal or restriction of mercury in "over-the-counter" (OTC) drugs such as anorectal products and topical antiseptics.
• Request for additional data on other OTC mercury antimicrobials.
• The use of mercury as a preservative or antimicrobial is limited to eye-area cosmetics or ointments in concentrations less than
60ppm(21 CFR700.13).
OTHER STANDARDS AND PROGRAMS
Occupational Standards
Transportation Standards
Virtual Elimination Project
• OSHA Standards: ceiling limit of 0.1 mg/m3 for inorganic and elemental mercury, 0.01 mg/m3 as an 8-hr lime weighted
average for alkylmlrcury compounds, and a ceiling limit of 0.04 mg/m for alkylmcrcury compounds.^
• All forms of mercury are assigned a skin notation, indicating that the substance is absorbed through the skin and therefore
skin contact should be avoided.
• As an OSHA hazardous chemical, the presence of mercury at a facility requires submittal of a Material Safely Data Sheet.
• Designated as hazardous substances by the Department of Transportation and subject to requirements for packaging, shipping
and transportation (40 CFR 172.101).
• U.S. EPA and other mercury stakeholders are looking holislically at mercury sources and policies to identify and promote
"cleaner, cheaper, smarter" ways of reducing mercury levels in the Great Lakes region.
• Efforts are designed to (1) reduce uses at the source through pollution prevention measures, (2) reduce releases through
treatment or other management techniques and (3) clean up sites of past contamination.
Adapted from O12CD, 1995.
Auapieu iroin VJUV.L*, ivyj.
Under (he 1990 Clean Air Act Amendment.*, mercury and mercury compounds are regulated as hazardous air pullulaius (HAPs). MAC]' standards will apply lo major stationary sources emitting
more than 10 ton/yr ot mercury or any other one HAP, or 25 lunVyr of any combination of HAPs.
More stringent standards were recently overturned in U.S. court.
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Environmental Media Standards. Different U.S. EPA program offices have established
acceptable mercury concentration limits for environmental media. U.S. EPA's Office of Ground Water
and Drinking Water, as pan of the National Drinking Water Standards required under the Safe
Drinking Water Act of 1986, has established a Maximum Contaminant Level (MCL) for inorganic
mercury in drinking water. U.S. EPA's Office of Water also has set Ambient Water Quality Criteria
that establish acceptable concentrations of mercury for the protection of human health and aquatic
species. At present, there are no federal standards establishing mercury concentration limits for
ambient air or soil, although U.S. EPA is in the process of developing clean-up levels for soil.
U.S. EPA recently published Final Water Quality Guidance for the Great Lakes System (60 FR
15366, March 23, 1995). The Guidance established water quality criteria for 29 pollutants - including
mercury ~ to protect aquatic life, wildlife and human health. The Guidance also con-sists of detailed
methodologies to develop criteria for additional pollutants; implementation procedures to develop more
consistent, enforceable water quality-based effluent limits in dis-charge permits, as well as total
maximum daily loads of pollutants that can be allowed to reach the Lakes and their tributaries from all
sources; and antidegradation policies and procedures* Great Lakes States and tribes will use the water
quality criteria, methodologies, policies and procedures in the Guidance to establish consistent,
enforceable, long-term protection for fish and shellfish in the Great Lakes and their tributaries, as well
as for the people and wildlife who consume them.
Environmental Source Controls. As shown in Table 4-1, regulations that control mercury
releases into the environment include limits on air and water point sources, solid waste disposal
restrictions and requirements for reporting and public disclosure of releases. These regulations have
been established under the authority of various environmental statutes.
Under the 1990 Clean Air Act Amendments, mercury and mercury compounds are regulated as
Hazardous Air Pollutants (HAPs). U.S. EPA has established National Emission Standards for three
major point source categories of mercury emissions: ore processing facilities, mercury cell chlor-alkali
plants and sewage sludge driers. Industrial sources emitting mercury and mercury compounds may be
subject to Maximum Achievable Control Technology (MACT) standards for major stationary sources
(emissions exceeding 10 ton/yr) and Generally Available Control Technology (GACT) standards for
area sources. U.S. EPA also recently finalized regulations,goveming mercury emissions from
municipal waste combustors under §§111 and 129 of the 1990 Clean Air Act Amendments and is in
the process of developing similar rules for medical waste incinerators.
Under the Clean Water Act, mercury is listed as a toxic pollutant and mercury discharges from
certain categories of industries are subject to technology-based effluent limits. The National Pollutant
Discharge Elimination System (NPDES) implemented under the Clean Water Act regulates direct
discharges to surface water bodies. Facilities are assigned a specific mercury discharge limit and/or
are required to monitor their discharge for mercury levels. Discharge Monitoring Reports submitted
by facilities serve as the basis for determining compliance with NPDES requirements. Indirect
dischargers (facilities that discharge to publicly owned treatment works) are regulated by industry-
specific pretreatment standards and effluent guidelines that are based on limits of the available control
technology.
Under the Resource Conservation and Recovery Act (RCRA), U.S. EPA has established
specific classification and disposal requirements for wastes that contain mercury. RCRA regulations
are waste-specific, not source-specific, and thus may apply to any facility that generates mercury-
containing wastes. Under current RCRA regulations, certain mercury-containing wastes are classified
either as a "characteristic" or a "listed" waste. Wastes are considered characteristic hazardous wastes if
June 1996 4-5 SAB REVIEW DRAFT
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they exhibit any of four specified characteristics: ignitability, corrosivity, reactivity, or toxicity. A
specific "D" waste code identifies the contaminant(s) for which a waste exhibits the toxicity
characteristic. Waste code D009 identifies wastes that exhibit the toxicity characteristic for mercury
(i.e., leaches mercury at or above 0.2 mg/1 when analyzed using the Toxicity Characteristic Leaching
Procedure). Listed wastes are specifically identified wastestreams or discarded products under RCRA,
with each listed waste being assigned a different waste code. Six different mercury-containing wastes
or discarded chemical products have been listed as hazardous wastes.1 RCRA regulations prescribe
specific treatment, storage and disposal requirements for individual waste codes. All mercury-bearing
wastes are subject to land disposal restrictions, meaning that they have to be treated in accordance with
RCRA regulations before they are allowed to be land disposed (such as in a landfill). Additionally,
RCRA regulations limit the airborne emission of mercury and other substances from boilers and
industrial furnaces, including cement kilns, that burn hazardous wastes.
The Superfund Amendments and Reauthorization Act of 1986 (SARA), which amended the
Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), provides broad
Federal authority for responding to rdeases of listed hazardous substances, including mercury. The
Emergency Planning and Community Right-to-Know Act also establishes emergency release, inventory
and release reporting requirements. All facilities in the manufacturing sector (SIC 20-39) that meet the
threshold reporting requirements are required to report releases to air, water and land for all listed
chemicals, including mercury, in the Toxics Release Inventory (TRI).
Under section 302 of SARA, any facility that produces, uses, or stores "extremely hazardous"
substances must notify the State Emergency Response Commission. Mercuric acetate, mercuric
chloride and mercuric oxide are considered extremely hazardous substances (40 CFR 355).
Additionally, any facility that releases a reportable quantity (RQ) or more of a hazardous substance
into the environment must notify the National Response Center, State Emergency Response
Commission and Local Emergency Planning Committee. The RQ for mercury is one pound. Finally,
facilities that keep hazardous substances on-site in quantities greater than threshold levels must submit
a chemical inventory to the State Emergency Response Commission, the Local Emergency Planning
Committee and the local fire department. The threshold for mercury (a hazardous substance) is 10,000
pounds, and the threshold for mercury compounds listed as extremely hazardous substances is 500
pounds. ,
Product Controls. Mercury is a component of certain pesticides, special paper coatings,
Pharmaceuticals, cosmetics and a variety of household products, including batteries, paints, fluorescent
light bulbs, electrical switches and thermometers. Such mercury-containing products are presently
regulated under two federal statutes, the Federal Insecticide, Fungicide, and Rodenticide Act (FIFRA)
and the Federal Food, Drug, and Cosmetic Act (FFDCA). FIFRA regulates the sale and use of
pesticides, including the registration of chemicals that meet health and safety tests. Until recently,
several mercury compounds were registered as pesticides, bactericides and fungicides. By 1993,
however, ail registrations for mercury compounds in paints and pesticides had been either cancelled by
U.S. EPA or voluntarily withdrawn by the manufacturer. The Food and Drug Administration regulates
mercury in food, drugs, cosmetics and dental amalgam under FFDCA. Particular controls on these
1 These wastes are: F039 (leachate resulting from the disposal of more than one restricted waste), K071
(brine purification muds from the mercury cell process in chlorine production where separately prepuriiied brine
is not used), K106 (wastewater treatment sludge from the mercury cell process in chlorine production), P065
(mercury fulminate — a mercury compound used in explosives — is listed as an acute hazardous waste when
discarded), P092 (phenylmercuric acetate - a mercury compound used in paints - is listed as an acute hazardous
waste when discarded), and U151 (the chemical mercury is considered hazardous when discarded).
June 1996 4-6 SAB REVIEW DRAFT
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products include restrictions on the mercury content, specified conditions for use and labeling
requirements. With regard to mercury-containing batteries, Federal legislation is pending that would
eliminate the use of mercury in all types of batteries used in both industrial and household activities
by January 1, 1997 (Ross & Associates, 1994). The battery industry already has converted production
processes so that the mercury content of batteries, except in button and coil cells, does not exceed
0.025 percent by weight (National Electrical Manufacturers Association, 1995).
Other Standards and Programs. The Occupational Safety and Health Administration (OSHA)
regulates exposures to mercury in the workplace by establishing Permissible Exposure-Limits (PELs).
The PELs for different mercury compounds are presented in Table 4-1. The National Institute for
Occupational Safety and Health (NIOSH) defines an additional limit called the Immediately Dangerous
to Life and Health (IDLH) level, defined as the maximum environmental concentration of a
contaminant from which one could escape within 30 minutes without any escape-impairing symptoms
or irreversible health effects. The IDLH is 28 mg/m3 for elemental mercury vapor and 10 mg/m3 for
organo-mercury compounds.
Under the Hazardous Materials Transportation Act (HMTA), the Department of Transportation
limits the potential for mercury releases during routine transportation and from transportation
accidents. Mercury and mercury compounds are designated as hazardous substances and are subject to
requirements for packaging, shipping and transportation under HMTA.
U.S. EPA and other organizations are actively developing strategies to achieve the Great Lakes
Water Quality Agreement's goal that persistent toxic substances should be "virtually eliminated" from
the Great Lakes. Because toxic substances enter the Great Lakes from ongoing economic activities, as
well as from sites contaminated by past activities, eliminating toxic substances from the Great Lakes
requires a three-pronged approach that:
• Reduces the use of toxic substances at the source, through pollution prevention efforts;
• Reduces toxic substance discharges, emissions and other ongoing releases through
treatment or other management techniques; and
•
• Cleans up sites of past contamination, such as contaminated sediments or areas of
concern, through remediation efforts.
U.S. EPA's Virtual Elimination Project has been studying mercury and polychlorinated
biphenyls (PCBs). A systematic review of the sources has taken place under this effort. Currently, an
analysis of options to further reduce and eliminate the use of these chemicals is being undertaken.
A central theme underlying the virtual elimination project is that opportunities may exist to
alter the decisionmaking environment in which individuals and firms choose to use and release toxic
chemicals in their ongoing activities. An individual or firm is likely to minimize its use and/or release
of toxic substances when it understands:
• The full cost of environmental regulation pertaining to a particular chemical or waste
(the cost of current practices), including costs such as liability, compliance, inputs,
waste disposal and adverse public perception;
• Whether or not an alternative input, process, or product exists that serves the same
purpose, but is less harmful to the environment (the availability of alternatives); and
June 1996 4-7 SAB REVIEW DRAFT
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• How much of the current cost associated with using or releasing a particular chemical
can be avoided by adopting less costly alternative practices that are less harmful to the
environment (the cost of alternatives).
In choosing to modify current activities, an individual or firm will evaluate the costs associated with
its current practices against the cost of available alternatives.
Government actions can enhance pollution prevention opportunities and stimulate toxic
substance reduction by (1) re-aligning the costs and/or regulatory structure to provide greater
incentives and flexibility for individuals and/or companies to reduce their use and release of toxic
substances and/or (2) reducing the cost of adopting alternatives that are less harmful to the
environment.
The Virtual Elimination Project focuses on government actions — or "signals" ~ such as
regulatory or voluntary programs that influence the economic and legal costs and benefits associated
with using a particular chemical. These signals, which translate into costs for an affected entity, can
motivate individuals and firms to choose pollution prevention based on their own economic interests.
4.1.2 State Activities
Mercury control regulations are increasing rapidly at the state level. Many states are
developing new regulations that will control the release of mercury from different environmental
sources. Minnesota, for example, is currently drafting management standards for facilities that recycle
mercury-containing wastes, and has proposed new combustion rules. States also have developed new
monitoring and reporting requirements on mercury release from air and water point sources. Table 4-2
summarizes examples of mercury control measures adopted by various states for different
environmental sources.
Regulations on mercury-containing products differ by state. In addition to health-based
concerns, states are focusing on waste disposal problems associated with mercury-containing products.
Many states have regulations that ban or limit the amount of mercury in products, establish recycling
requirements and impose disposal restrictions on products containing mercury. For example, certain
types of batteries containing mercury are banned in a number of states, and 12 states have enacted
laws that limit the amount of mercury in alkaline batteries to 0.025 percent by weight (Ross &
Associates, 1994). Minnesota also requires removal of mercury from electric lamps and thermostats .
before they are disposed. Illinois restricts disposal of white goods containing mercury and limits the
amount of mercury in packaging. Many states also have mercury waste collection programs in place
to control the release of mercury into the environment. Table 4-2 summarizes the regulations and
programs adopted by selected states for various products, including legislation and detailed regulations
that apply to mercury-containing batteries.
In addition, states follow the reporting requirements and other standards developed and
implemented by U.S. EPA and other federal agencies. Some states have regulations in addition to the
federal regulations. For example, Michigan's Water Pollution Control Act requires businesses to
report the amount of mercury used and released. This information is used to assist in permit
development and compliance monitoring in the state water program (Ross and Associates, 1994).
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Table 4-2
Examples of State Mercury Controls"
MERCURY SOURCES/TARGETS
Air Point Sources
Water Point Sources
Hg-Containing Wastes
STATES WITH
CONTROLS
Florida
Minnesota
New Jersey
Ohio
Wisconsin
Michigan
Minnesota
•
CONTROL/ACTION
ENVIRONMENTAL SOURCES
• Mercury emission standard for municipal solid waste incinerators (65 micrograms/m3).
• Proposed waste combustion rules include emission limits.
• New incinerator permits with mercury limits will require air monitoring systems and periodic stack
testing.
• Mercury emission standard for municipal solid waste incinerators (65 micrograms/m3', with further
reductions to be phased in.
• Considering installing mercury-emission control equipment.
• Medical waste incinerators with capacity greater than 5 tons per day must be tested for mercury
during the first 90 day period of operation and once the following year.
• Businesses must report use and discharge information for mercury under the Water Pollution Control
Act.
• Management standards for facilities recycling mercury-containing hazardous wastes (currently being
drafted).
• Mercury must be removed from products before disposal.
PRODUCTS
White Goods
Batteries
Illinois
Minnesota
Arkansas
• Mercury components must be removed from discarded white goods before disposal.
• Products containing mercury must be labeled, and the labels must include any disposal restrictions.
• Mercury components must be removed prior to disposal.
• The distribution of mercury-containing fever thermometers is restricted.
• Manufacturers must provide information and incentives regarding recycling or proper management.
• HVAC dealers are required to properly manage or recycle used mercury thermostats.
• Mercury in repaired or replaced items must be recycled.
• Ban on the manufacture of alkaline batteries containing any mercury effective 1-1-96.
• Ban on the manufacture of mercury-containing zinc carbon and mercury hutlon cell batteries effective
1 1-94.
• State issued regulations defining collection procedures and responsibilities of the manufacturer and
user of mercury batteries effective 1-1-94.
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Table 4-2
Examples uf State Mercury Controls (continued)
MERCURY SOURCES/TARGETS
STATES WITH
CONTROLS
CO NTKOJ7ACT1ON
Butteries (continued)
California
Required manufacturer to reduce the level of mercury to 0.025% by weight in alkaline batteries
effective 1-1-94, and ban on the manufacture of alkaline batteries containing any mercury effective 1-
1-96.
Ban on the manufacture of mercury-containing zinc carbon and mercury button cell batteries effective
1-1-94.
Connecticut
Florida
Illinois
Iowa
Maine
Required manufacturer to reduce the level of mercury to 0.025% by weight in alkaline butteries
effective 1-1-92.
Ban on the manufacture of mercury-containing zinc carbon batteries effective 1-1-93.
Collection of mercury button cell batteries required by retailer effective 1-1-92.
State issued regulations defining responsibilities of manufacturer, supplier and user effective 1-1-92.
Ban on the sale of alkaline batteries containing mercury greater than 0.025% by weight effective 7-1-
95, and ban on the retail sale of alkaline and zinc carbon batteries containing any mercury effective
1-1-96.
Ban on the sale of mercury button cell batteries effective 10-1-93.
Stale issued regulations defining collection procedures and responsibilities of the manulaclurer and
user of mercury batteries effective 1-1-94.
Ban on the sale of mercury containing batteries if manufacturer fails to meet collection procedures
and other responsibilities effective 1-1-94.
» Task force to study storage, transport, disposal and recycling.
Ban on the sale of alkaline batteries containing mercury greater than 0.025% by weight eflective 7-1-
93, and ban on the retail sale of alkaline batteries containing any mercury effective 1-1-96.
State issued regulations defining responsibilities of manufacturer, supplier and user effective 7-1-96.
Bun on the sale of mercury-containing butteries (including button cells) if manufacturer fails to meet
collection procedures and other responsibilities effective 7-1-96.
Collection of mercury button cell batteries required by retailer effective 7-1-96.
Ban on the sale of alkaline batteries containing mercury greater Ihun 0.025%. by weight efleclive 1-1-
94, and ban on the manufacture of alkaline batteries containing any mercury effective 1-1-96.
Ban on (he sale of mercury containing zinc caibon batteries and mercury button cell batteries
effective 1-1-93.
Slate issued regulations defining collection procedures and responsibilities of the manufacturer and
user of mercury batteries effective 1-1-94.
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Table 4-2
Examples of State Mercury Controls (continued)
MERCURY SOURCES/TARGETS
STATES WITH
CONTROLS
CONTROL/ACTION
Batteries (continued)
Maryland
Massachusetts
Michigan
Minnesota
Collection of mercury button cell batteries required by retailer effective 7-1-94.
Ban on the sale of mercury button cell butteries if manufacturer fails to meet collection,
transportation, disposal and consumer education responsibilities effective 7-1-94.
General ban on the sale of mercury containing batteries effective 7-1 -94, hut state authorized to grant
exemptions if certain requirements are met.
State issued regulations defining responsibilities of manufacturer, supplier and user effective 7-1-94.
Ban on the retail sale of mercury-containing alkaline batteries effective 1-1-95 is pending.
State regulations defining collection procedures and responsibilities of the manufacturer and user of
mercury batteries are pending.
Ban on the sale of mercury button cell batteries is pending.
A new battery law signed on June 29, 1995.
This law bans the sale of alkaline batteries containing mercury (with the exception of alkaline
manganese button cells containing less than 25 mg of mercury) and zinc carbon batteries containing
mercury beginning January 1, 1996.
The sale of mercuric oxide batteries (with the exception of button cells) are also banned for sale after
January 1, 1996, unless the manufacturer identifies a collection site for recycling, informs users of
the locations and informs the purchasers of a telephone number that can be called to gel information
about returning mercuric oxide batteries for recycling or proper disposal.
Required manufacturer to sell alkaline batteries containing no more than 0.025% mercury by weight
effective 2-1-92, and has banned manufacturer sale of alkaline batteries containing any mercury
effective 1-1-96.
General ban on the sale of mercury-containing batteries effective 2-1-92, but state authorized to grant
exemptions if certain requirements are met.
Mercury batteries may not contain more than 25 mg of mercury unless an exemption is granted.
Sale of dry cell batteries with mercuric oxide ahd electrode batteries prohibited without exemption.
Ban on mercury button cell batteries effective 2-1-92.
Manufacturers must set up collection, transport, recycling and consumer education programs.
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Table 4-2
Examples of State Mercury Controls (continued)
MERCUKY SOURCES/TARGETS
STATES WITH
CONTROLS
CONTROL/ACTION
Batteries (continued)
New Hampshire
New Jersey
New York
Oregon
Rhode Island
Required manufacturer to reduce the level of mercury in alkaline butteries to 0.025% by weight
effective 1-1-93, and has banned (he manufacturer sale of alkaline batteries containing any mercury.
effective 1-1-96.
Ban on the manufacture of mercury-containing zinc carbon batteries effective 1-1-93.
State issued regulations defining collection procedures and responsibilities of the manufacturer and
user of mercury batteries effective 1-1-93.
State issued regulations regarding the collection of mercury button cell batteries effective 1-1-93.
Required manufacturer to reduce the level of mercury to 0.025% by weight in alkaline batteries
effective 1-1-92, and ban on the manufacture of alkaline batteries containing any mercury effective I-
1-96.
Ban on the manufacture of mercury-containing zinc carbon batteries effective 1-1-92.
Ban on mercury button cell batteries effective 1-1-94.
State issued regulations defining collection procedures and responsibilities of the manufacturer and
user of mercury batteries effective 1-20-93.
Sale of mercury batteries banned if manufacturer fails to meet collection and other responsibilities
effective 1-20-93.
Required manufacturer to reduce the level of mercury to 0.025% by weight in alkaline batteries
effective 1-1-92.
Ban on the manufacture of mercury-containing.zinc carbon batteries effective 1-1-93
Mercury oxide battery ban pending.
Required manufacturer to reduce the level of mercury to 0.025% by weight in alkaline batteries
effective 1-1-92.
Required manufacturer to reduce the level of mercury to 0.025% by weight in alkaline batteries
effective 1-1-92.
Stale issued regulations defining collection procedures and responsibilities of the manufacturer and
user of mercury batteries effective 1-1-94.
Ban on mercury button cell batteries effective 1-1-93.
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Table 4-2
Examples uf State Mercury Controls (continued)
MERCURY SOURCES/TARGETS
Batteries (continued)
Electrical Components
Paints and Pigments
Dental Uses
Toys
Lighting
STATES WITH
CONTROLS
Vermont
Wisconsin
Pennsylvania
Minnesota
Minnesota
Michigan
Minnesota
Wisconsin
Florida
Ohio
CONTROL/ACTION
• Required manufacturer to reduce the level of mercury in alkaline batteries by 0.025% by weight
effective 2-1-92, and ban on the retail sale of alkaline batteries containing any mercury effective 1-1,
96.
• Ban on mercury button cell batteries effective 1-1-93.
• State issued regulations defining collection procedures and responsibilities of the manufacturer and
user of mercury batteries effective 1-1-93.
• Ban on the manufacture of mercury -containing alkaline batteries effective 1-1-96, and ban on the
manufacture of mercury -containing zinc carbon batteries effective 7-1-94.
• Slate issued regulations defining collection procedures and responsibilities of the manufacturer and
user of mercury batteries effective 7-1-94.
• Ban on the manufacture of mercury-containing batteries if manufacturer fails to meet collection
procedures and other responsibilities effective 7-1-94.
• Mercury use in mining equipment (i.e., electrical machinery) is limited.
• No mercury can be deliberately introduced into products intended for use in Minnesota, except for art
supplies.
, • Disposal of dental equipment and supplies containing mercury is banned, unless the mercury is
reused, recycled, or managed to ensure compliance.
• Purchaser must sign an agreement of use for medical or dental uses.
• No sale of toys containing mercury (pending).
• Toys with mercury are banned and fines are imposed on retail sales of toys containing mercury.
• Ban on incineration of lamps. Crushing, landfilling and recycling of lamps allowed with appropriate
controls (proposed).
• Florida also will control management of residual mercury from recycling operations.
• Lamps are viewed as by-products that can be recycled, and exempt from RCRA.
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Table 4-2
Examples of State Mercury Controls (continued)
MERCURY SOURCES/TARGETS
Lighting (continued)
Poisons
Packaging
Pharmaceuticals
Explosives/Fireworks
STATES WITH
CONTROLS
Minnesota
New York
Ohio
Pennsylvania
Florida
Illinois
Minnesota
New York
Wisconsin
Pennsylvania
Illinois
Indiana
New York
Ohio
Pennsylvania
Minnesota
Wisconsin
CONTROL/ACTION
• Fluorescent lamps and high intensity lamps sold to managers of industrial, commercial, office, or
multi-unit buildings must be labeled and building contractors must specify mercury management
plans for removed lamps.
• Lamps in state-owned buildings must be recycled.
• Mercury must be removed from mercury vapor lights before disposal and lamp sellers and contractors
must provide public education about mercury management requirements.
• The production and distribution of mercury vapor lights are limited.
• Mercury vapor lights must be self-extinguishing or have protective shield.
• The sale of mercury and mercury compounds is restricted.
• Levels established for mercury products considered to be safe.
» The mercury content in packaging and packaging components is restricted.
• Restrictions on mercury content in packaging are being phased in. (Dales and concentrations vary by
state.)
• Intentionally introduced mercury in packaging is prohibited (pending).
• Manufacturers must list the quantity of mercury in products.
• Explosives containing mercury are Class A maximum hazards.
• Permits required for fireworks with mercury (Minnesota only).
Adapted from Ross & Associates, 1994.
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4.2 Management Alternatives and Statutory Authorities
4.2.1 Management Alternatives
Control of mercury emissions may require a mix of strategies including pollution prevention,
materials separation and conventional regulatory strategies to control mercury emissions at the stack.
Pollution prevention would be suitable for those processes or industries where a mercury substitute is
demonstrated and available. Material separation is an appropriate approach for processes where
mercury-containing products are disposed of by incineration, or where mercury can be reduced in the
fuel prior to the fuel being combusted (e.g., coal cleaning). The third approach, conventional
regulatory strategies, may be applicable when mercury is emitted to the environment as a result of
trace contamination in fossil fuel or other essential feedstock in an industrial process (e.g., smelting).
Other non-traditional approaches such as emissions trading or application of a use tax, or other
market-based approaches may also prove feasible for mercury control. However, these options are not
presented in detail in this Report as the control technology analyses focused on what might be
achievable under the statutory language of sections 112 and 129 of the CAA.
The analyses on control technologies and costs presented in this Report are not intended to
replace a thorough regulatory analyses as would be performed for a rulemaking. The information
presented is intended to present the range of available options and provide a relative sense of the
extent of mercury reductions achievable and the general magnitude of the cost of such reductions.
One possible means of achieving reductions in mercury emissions is through the use of
pollution prevention or source reduction. Such approaches to achieving reductions involve changes in
processes or inputs to reduce or eliminate emissions of mercury from a particular product or process.
They could include, for example, the replacement of mercury with an appropriate substitute or the use
of low-mercury content inputs.
In considering opportunities for pollution prevention or source reduction it is important to
consider both the potential reductions achievable and the costs of these options. Any consideration of
the potential reductions, should examine whether (and the extent to which) emission reductions from
the particular sources in question will yield reductions in risk to public health and the environment. It
is also essential to understand the costs associated with implementing a pollution prevention measure,
including any changes in the quality of the end product.
Table 4-3 presents the six source categories for which a control technology and cost analysis
was performed. The table presents the number of facilities in each category, the percent contribution
of each to the national inventory and the relative potential for individual facilities within the source
category to impact the area within 50 km of the facility. Potential national mercury reductions and
potential national control costs are also presented. These estimates are based on the assumption that
all plants within a source category will achieve the same reductions and incur the same costs as the
model plants used in the analysis. Because this certainly would not be true in all circumstances, the
estimates of potential reductions and costs should be used only for relative comparisons among the
source categories to give an initial indication as to where mercury reductions would provide the most
emission reduction far the least cost.
The estimates of cost for mercury reduction do not illustrate two important considerations.
One is that all of the cost of control is attributed to mercury removal. As described previously in this
Report, many of these controls achieve reductions of other pollutants as well (e.g., dioxin). The
benefits of these additional reductions should also be considered. Second, the technologies available
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Table 4-3
Potential Mercury Emission Reductions and Costs for Selected Source Categories
Mercury Source Category
Municipal waste combustors
Medical waste incinerators
Coal-fired utility boilers
Chlor-alkali plants using the
mercury cell process
Primary copper smelters
Primary lead smelters
Total
Number
of
Facilities
149
-3,700
426
(1,043
boilers)
14
8
3
-4,900
% of UJS.
Mercury
Emission
Inventory
23
27
21
2.7
0.3"
3.7
78
Mercury Control Techniques
Material separation
Product substitution
Activated carbon injection
Carbon filter beds
Polishing wet scrubber
Material separation
Activated carbon injection
Polishing wet scrubber
Fuel switching
Advanced coal cleaning
Carbon filter beds
Activated carbon injection
Process modification
Depleted brine scrubbing
Treated activated carbon adsorption
Selenium filters
Selenium filters
Potential National
Reductions11
50 tons
(90% reduction)
60 Ions
(90% reduction)
24-44 tons
(50-90% reduction)6
6.5 tons
(100% reduction)
>0.7 tons
(90% reduction)
8 tons
(90% reduction)
Potential
National Annual
Costs1
$56 million
$24 million
$2.9 billion
$70 million
$7.7 million
$0.8 million
~$3 billion
Cost-
Effectiveness
($/)!> of mercury
removed)*1
$211-870
$228-955
. $5,240-28,000
$4,590
$497
$1,061
NOTE: The underlined mercury control techniques are the techniques on which potential national reductions and potential national annual costs are based.
a Reflects one smeller only; a national estimate would be higher.
b Estimated reductions assuming every facility could achieve the reduction listed.
c Potential national costs are estimates only and assume all facilities would incur the same costs as the model plants used in the analysis.
J Where cost-effectiveness values are presented as a range, the values reflect the range across facilities of different siy.es.
e The range in potential national reductions reflects the variable efficiency of activated carbon injection to control mercury emissions fiom coal-fired utility boilers. Activated carbon injection
has not been demonstrated for a full-scale utility boiler application. Control costs are based on the installation of spray cooler, fabiic filler and caibon injection systems.
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for mercury control represent relatively new applications of these technologies. Thus, in the future, it
is possible that as new or emerging technologies develop, the cost-effectiveness of control may
improve.
4.2.2 Clean Air Act Authorities
Mercury is a priority pollutant across numerous U.S. EPA programs including air, water,
hazardous waste and pollution prevention. The focus of this section is the statutory authority under
the CAA that could be used to control mercury emission sources. A brief summary of these
authorities is presented below.
Section 112(a) Lesser Quantity Emission Rates (LQERs)
The U.S. EPA Administrator has the discretion to redefine major sources by setting an
emissions cutoff lower than the 10 tons per year emission rate level for a single pollutant or 25 tons
per year emission rate for a mixture of pollutants. This is referred to as a lesser quantity emission rate
(LQER). The CAA states that LQERs are pollutant-specific and should be based on public health or
environmental effects.
The major implications of setting an LQER are that all the requirements for a major source,
including setting maximum achievable control technology (MACT) standards, mandatory residual risk
analyses, calculation of the MACT floor, modification provisions and Title V permitting requirements
become applicable to what was previously defined as an area source category.
Section 112(c)(6) List of Specific Pollutants
Section 112(c)(6) requires that by 1995, sources accounting for not less than 90 percent of the
aggregate emissions of each of seven specific pollutants must be listed on the source category list, and
be subject to standards under 112(d)(2) or (4) no later than 2005. The pollutants are: alkylated lead
compounds; polycyclic organic matter; hexachlofobenzene; mercury; polychlorinated biphenyls;
2,3,7,8-tetrachlorodibenzo-p-dioxin; and 2,3,7,8-tetrachlorodibenzofuran. This provision makes a
specific reference to utility boilers. It reads: "This paragraph shall not be construed to require the
Administrator to promulgate standards for such pollutants emitted by electric steam generating units."
Section 112(d) Emission Standards
Section 112(d) requires that emission standards be established for each source category listed
on the source category list. The emission standards are applicable to both new and existing sources
and are based on the application of MACT. MACT is defined differently for new and existing sources
as explained by 112(d)(2) and (3). Under 112(d)(4), if the pollutant is a threshold pollutant (i.e.,
noncarcinogen), the emission standard can be based on a health threshold with an ample margin of
safety. A health threshold is a level where the risk of an adverse effect from exposure to the pollutant
is negligible. Section 112(d)(5) allows the Administrator the discretion to apply generally available
control technology (GACT) to area sources rather than MACT (or any other technologies that may be
required of the source category on account of residual risk analyses under 112(f)).
Section 112(f) Residual Risk Program
Section 112(f) required the U.S. EPA to report to Congress on the methods that will be used
to calculate the risk remaining after the promulgation of MACT emission standards under Section
June 1996 4-17 SAB REVIEW DRAFT
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112(d). This report should address the public health significance of the risk and the actual health
effects experienced by persons living in the vicinity of emitting sources, and make recommendations
on legislation regarding the risk. This report is due to Congress on November 15, 1996. If Congress
does not accept any of the recommendations provided for reducing the residual risk, the Administrator
has the authority to promulgate any additional standards required in order to protect public health with
an ample margin of safety. The report is currently under development.
Section 112(k) Urban Area Source Program
By 1995, a national strategy to control emissions of hazardous air pollutants (HAPs) from area
sources in urban areas must be transmitted to Congress. The strategy must identify not less than 30
HAPs which present the greatest threat to public health in the largest number of urban areas. Source
categories accounting for at least 90 percent of the aggregate emissions of each HAP must be listed on
the source category list and be subject to 112(d) standards. The strategy, when implemented, is to
achieve a 75 percent reduction in cancer incidence attributable to these sources.
The urban area source program is a section 112 authority that does not require that a finding
of adverse effects be made for the area source category (as required for listing by 112(c)(3)). Mercury
is a likely candidate for the urban area source program.
112(m) Atmospheric Deposition to Great Lakes and Coastal Waters (Great Waters)
The Great Waters study is an ongoing study with periodic reports to Congress required. This
program must identify and assess the extent of atmospheric deposition of HAPs to the Great Waters,
the environmental and public health effects attributable to atmospheric deposition and the contributing
sources. The first report was submitted in May 1994 and is to be submitted biennially hereafter.
Mercury was identified as a priority pollutant under the Great Waters program. The Administrator
must determine if other provisions under Section 112 will adequately control these sources. If not, by
1995, further emission standards to control these sources must be promulgated.
The recommendations of the first Great Water Report to Congress were (1) the U.S. EPA
should strive to reduce emissions of the identified pollutants of concern through implementation of the
CAA; (2) a comprehensive approach should be taken both within the U.S. EPA and between the U.S.
EPA and other federal agencies to reduce and preferably prevent pollution in the air, water, and soil;
and (3) the U.S. EPA should continue to support research for emissions inventories, risk assessment
and regulatory benefits assessment
112(n)(l)(A) Study of Hazardous Air Pollutants for Electric Utility Steam Generating Units
The Utility Study is required to address the hazards to public health that are reasonably
anticipated to occur as a result of emissions by electric utility steam generating units of ... [hazardous
air pollutants] ... after imposition of the requirements of the Act. The list of 189 HAPs is presented in
section 112(b) of the CAA. In the study, the U.S. EPA must develop and describe alternative control
strategies for HAPs that may require regulation under section 112, and, if appropriate and necessary,
the U.S. EPA is to proceed with rulemaking to control HAP emissions from utility boilers. Mercury is
one of the pollutants of concern for utilities.
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Section 129 Solid Waste Combustion
Under this section, the Administrator must establish emission guidelines and standards for
solid waste incineration units, including municipal waste combustors, medical waste incinerators and
commercial and industrial waste incinerators. The performance standards must specify numerical
emission limits for mercury as well as a number of other pollutants. The U.S. EPA has already issued
final rules for municipal waste combustors (FR notice for final) and proposed rules for medical waste
incinerators (60 FR 10654). Emission limits for hazardous waste combustors will be forthcoming
under the Agency's Combustion Strategy.
June 1996 4-19 SAB REVIEW DRAFT
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5. CONCLUSIONS
The following conclusions are presented in approximate order of degree of certainty in the
conclusion, based on the quality of the underlying database. The conclusions progress from
those with greater certainty to those with lesser certainty.
• Conversion of mercury cell chlor-alkali plants to a mercury-free process is technically feasible
and has been previously demonstrated.
• Energy conservation and switching to low-mercury fuels would reduce the amount of mercury
being emitted by utility boilers.
• Injection of activated carbon into the flue gas of MWC's and MWI's can achieve mercury
reductions of at least 85 percent. The addition of activated carbon to the flue gas of these
source types would not have a significant impact on the amount of paniculate matter requiring
disposal.
• Numerous opportunities exist for replacing mercury in various products with other materials,
such as solid state electronics for mercury switches, digital thermometers for mercury
thermometers and zinc-air batteries for mercury batteries.
• Removing mercury-containing products such as batteries, fluorescent lights and thermostats
from the waste stream can reduce the mercury input to waste combustors without lowering the
energy content of the waste stream. The mercury removal efficiency would vary, however,
depending on the extent of the separation.
• Selenium filters are a demonstrated technology in Sweden for control of mercury emissions
from lead smelters. Carbon filter beds have been used successfully in Germany for mercury
control on utility boilers and MWC's. These technologies have not been demonstrated in the
U.S.
• Activated carbon injection provides variable control of mercury for utility boilers, based on
limited pilot-scale testing. The most important factors affecting mercury control on utility
boilers include the flue gas volume, flue gas temperature and chloride content, the mercury
concentration and chemical form of mercury being emitted. The addition of activated carbon
to utility flue gas for mercury control would significantly increase the amount of paniculate
matter requiring disposal.
• The available data on coal cleaning indicate that mercury reductions ranged from zero to 64
percent. The average reduction was 21 percent. This variation may be due to several factors
including different cleaning methods, different mercury concentrations in the raw coal and
different mercury analytical techniques. There are no data available to assess the potential for
mercury emissions from coal-cleaning slurries.
» Control technologies designed for control of pollutants other than mercury (e.g., acid gases and
paniculate matter) vary in their mercury-removal capability, but in general achieve reductions
no greater than 50 percent.
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There are many uncertainties associated with the cost analysis for individual source categories
due to assumptions inherent in a model plant approach. The impact of these uncertainties on
the analyses include the following:
• The cost of mercury control incurred by any specific facility may be underestimated by the
cost analysis presented in this Report because of variability inherent in the assumptions that
were made in the analyses. These include the efficiency of the various control techniques for
reducing mercury, the amount of mercury in the flue gas stream and other site-specific factors
such as down-time and labor costs. In addition, costs for monitoring and record keeping were
not included in the cost analyses.
• The financial impacts calculated in this Report may not represent the financial status of all
facilities within a source category. The affordability of mercury control will depend on a
given facility's profits and expenditures.
• In the control technology analysis, the cost of control was attributed to mercury reduction
only. Because many of the controls also reduce emissions of other pollutants, apportioning the
costs across all pollutants reduced would better characterize the cost of mercury control.
June 1996 5-2 SAB REVIEW DRAFT
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6. RESEARCH NEEDS
To improve the control technology, cost and impacts assessment, the U.S. EPA would need the
following:
1. Data from full-scale testing of activated carbon injection at a coal-fired utility boiler.
2. Additional data are needed on the efficiency of activated carbon injection, and various
impregnated carbons, in reducing the different chemical species of mercury present in
flue gas.
3. Additional information on the efficiency and cost of other technologies for mercury
control that are currently in the research stage. These include impregnated activated
carbon, sodium sulfide injection and activated carbon fluidized bed.
4. More data are needed on both the ability of conventional or advanced coal cleaning
techniques to remove mercury from raw coal and advanced coal cleaning techniques
such as selective agglomeration and advanced column floatation. The potential for
mercury emissions from coal-cleaning slurries needs to be characterized.
5. Additional analyses are required on the feasibility, cost effectiveness of other mercury
emission prevention measures such as emissions trading, emissions averaging, energy
conservation, renewable energy, and fuel switching.
June 1996 6-1 SAB REVIEW DRAFT
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Technical Work Paper on Mercury Emissions from Waste Combustors. Prepared for Minnesota
Pollution Control Agency, Air Quality Division, St. Paul, Minnesota. December 1992.
White, D. and A. Jackson, 1993. The Potential of Materials Separation as a Control Technique for
Compliance with Mercury Emission Limits. Presented at the 1993 International Conference on
Municipal Waste Combustion, Williamsburg, Virginia. March 1993. •
June 1996 7-8 SAB REVIEW DRAFT
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APPENDIX A
TEST DATA ON THE EFFECTIVENESS OF
ACTIVATED CARBON INJECTION
FOR UTILITY BOILERS
Limited test data indicate that activated carbon (AC) injection effectively reduces mercury
emissions when used in conjunction with existing control devices, such as fabric filters (FFs) and
spray dryer absorbers (SDAs).
Table A-l presents pilot-scale test data on the mercury removal efficiency of AC injection
when used ahead of FFs. Such a configuration, with no prior PM control, has a median mercury
removal efficiency that varies with temperature and AC injection rate. With a low AC injection rate
(< 1,000 wt C/wt inlet Hg) and an average flue gas temperature between 107°C (225 °F) and 121°C
(250°F), a median mercury removal efficiency of 29 percent was found, with a range from 14 percent
to 47 percent removal. With a low AC injection rate (same as above) and an average flue gas
temperature between 88°C and 107°C, a median mercury removal efficiency of 97 percent was found,
with a range from 76 percent to 99 percent removal. A high AC injection rate (> 1,000 wt C/wt inlet
Hg) and an average Hue gas temperature between 107°C (225 °F) and 121 °C (250°F) produced a
median mercury removal efficiency of 82 percent, with a range from 69 percent to 91 percent removal.
A high AC injection rate (same as above) and an average flue gas temperature between 88°C (190°F)
and 107°C (225 °F) produced a median mercury removal efficiency of 98 percent, with a range from
95 percent to 99 percent removal (Chang et al., 1993).
Table A-2 presents test data for AC injection when used before SDA systems. Tested
SDA/ESP systems with AC injection had a median mercury removal efficiency of 85.9 percent, with a
range from 74.5 percent to 90.9 percent removal (Felsvang, 1993). Pilot-scale testing of a SDA/FF
system with AC injection had a median mercury removal efficiency of 60 percent, with a range from
50 percent to 99 percent removal (Felsvang, 1993).
June 1996 A-l SAB REVIEW DRAFT
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Table A-l
Activated Carbon Injection Before Fabric Filter Data3
Unit
Control Device
Hg removal
%
Low temperature + low carbon injection rate (< 1000 wt C/wt Hg) based on inlet Hg
Test #4, Run #1
Test #4, Run #2
Test #4, Run #3
Test #6, Run #3
AC + FF (88°C (190°F) and 216 wt C/wt inlet Hg;
inlet Hg concentration of 5.35 ug/dscm)
AC + FF (88°C (190°F) and 126 wt C/wt inlet Hg;
inlet Hg concentration of 8.19 ug/dscm)
AC + FF (91 °C (196°F) and 123 wt C/wt inlet Hg;
inlet Hg concentration of 8.62 ug/dscm)
AC + FF (102°C (216°F) and 727 wt C/wt inlet Hg;
inlet Hg concentration of 1.94 ug/dscm)
97
99
97
76
High temperature + low carbon injection rate << 1000 wt C/wt Hg) based on inlet Hg
Test #5, Run #1
Test #5, Run #2
Test #5, Run #3
Test #6, Run #1
Test #6, Run #2
AC + FF (107°C (225 °F) and 362 wt C/wt inlet Hg;
inlet Hg concentration of 5.53 ug/dscm)
AC + FF (110°C (230°F) and 373 wt C/wt inlet Hg;
inlet Hg concentration of 4.45 ug/dscm)
AC + FF (116°C (241°F) and 457 wt C/wt inlet Hg;
inlet Hg concentration of 3.47 ug/dscm)
AC + FF (121°C (250°F) and 286 wt C/wt inlet Hg;
inlet Hg concentration of 5.04 ug/dscm)
AC + FF (118°C (244°F) and, 367 wt C/wt inlet Hg;
inlet Hg concentration of 4.22 ug/dscm)
14
28
47
29
35
Low temperature + high carbon injection rate (> 1000 wt C/wt Hg) based on inlet Hg
Test #2, Run #1
Test #2, Run #2
Test #2, Run #3
Test #3, Run #2
AC + FF (91°C (196°F) and 2843 wt C/wt inlet Hg;
inlet Hg concentration not measured but assumed to
be 7.00 ug/dscm)
AC + FF (96°C (205 °F) and 3132 wt C/wt inlet Hg;
inlet Hg concentration not measured but assumed to
be 7.00 ug/dscm)
AC + FF (93°C (199°F) and 3121 wt C/wt inlet Hg;
inlet Hg concentration not measured but assumed to
be 7.00 ug/dscm)
AC + FF (93°C (199°F) and 4361 wt C/wt inlet Hg;
inlet Hg concentration of 6.23 ug/dscm)
95
98
98
99
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Table A-l
Activated Carbon Injection Before Fabric Filter Data
(continued)
Unit
Test #3, Run #3
Control Device
AC + FF (96°C (205 °F) and 3850 wt C/wt inlet Hg;
inlet Hg concentration of 6.91 ug/dscm)
Hg removal
%
99
High temperature + high carbon infection rate (> 1000 wt C/wt Hg) based on inlet Hg
Test #3, Run #1
- " • -•• \
Test #7, Run #1
Test #7, Run #2
Test #7, Run #3
AC + FF (110°C (230°F) and 3332 wt C/wt inlet Hg;
inlet Hg concentration of 7.95 ug/dscm)
AC + FF (121°C (250°F) and 1296 wt C/wt inlet Hg;
inlet Hg concentration of 4.66 ug/dscm)
AC + FF (121°C (250°F) and 1954 wt C/wt inlet Hg;
inlet Hg concentration of 4.30 ug/dscm)
AC + FF (116°C (241°F) and 3649 wt C/wt inlet Hg;
inlet Hg concentration of 2.09 ug/dscm)
91
69
76
87
Source: Chang et al., 1993
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Table A-2
Activated Carbon Injection Before Spray Dryer Absorption Data3
Unit
Denmark
NSP Sherco 3 (pilot
unit)
Plant D2
Control Device
SDA/ESP
AC + SDA/ESP (inlet Hg concentration
ranges from 3.5 - 7.9 |ag/dscm)
SDA/FF
AC + SDA/FF (inlet Hg concentration
unknown)
AC + SDA/FF (inlet Hg concentration of
3.9 ng/dscm)
Hg Removal %
80.3, 85.8, 75.8, 74.5, 90.9,
89.5, 89.3, 86.7. 85.9
50-60
>99
' Source: Felsvang, 1993
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APPENDIX B
MODEL PLANT COST EVALUATION
This appendix presents model plant cost analyses for installing and operating applicable
mercury control techniques at each of the six source types described in Chapter 2. The cost estimates
are based on information supplied by various vendors and taken from the literature, and may not
reflect commercial considerations such as vendor guarantees. The cost estimates reflect generalized
costs and are not intended to be site specific. Plant-to-plant variations can result in higher or lower
technology performance and associated costs.
An effort was made to convert the dollars to reflect the currency rate in the early 1990s. For
carbon filter beds and selenium filters, conversion from foreign currencies to U.S. dollars is based on a
June 1993 exchange rate.
B.I Municipal Waste Combustors
B.I.I Model Plant Description
Two model plants were selected to represent MWCs based on the model plants used in the
EPA's model plant cost report for MWCs (U.S. EPA, 1989a). The first is a small mass
burn/waterwall (MB/WW) MWC with two units and a total plant capacity of 180 Mg/day (200 tpd).
This model plant is equipped with dry sorbent injection (DSI) and an ESP. Few MWCs are currently
equipped with this control device combination (Fenn and Nebel, 1992), but it is expected that a
number of MWCs will be installing this technology in the future. The second model plant is a large
MB/WW MWC with three units and a total plant capacity of 2,045 Mg/day (2,250 tpd) of MSW.
This model plant is equipped with a SD/FF pollution control system. Both model plants are assumed
to operate at full capacity 90 percent of the year.
Inlet mercury levels for the two model plants are assumed to be 700 ug/dscm (306 gr/million
dscf) based on typical inlet levels at MWCs (U.S. EPA, 1993). The model plant analyses assume a
baseline DSI/ESP mercury reduction of 15 percent and a b'kseline SD/FF mercury reduction of
30 percent. This results in a mercury level before add-on controls of 595 ug/dscm (260 gr/million
dscf) for the small model plant and 490 ug/dscm (214 gr/million dscf) for the large model plant. The
assumed baseline control efficiency reflects typical MWC operation; however, actual values vary from
plant to plant.
The following sections present the cost analyses of different mercury control options for
MWCs. Section B.I.2 provides a qualitative cost discussion on material separation costs for batteries.
Sections B.I.3 through B.I.5 provide quantitative cost information on applying activated carbon
injection, CFB's and a polishing wet scrubber to the MWC model plants. A sensitivity analysis of the
effect of lower mercury levels in the flue gas is also included.
B.I.2 Material Separation
Comprehensive cost data on battery separation programs in the United States are not available.
Most programs are operated by local governments, and the expenses for administration, overhead and
educational/promotional efforts typically are not reported. Hennepin County, Minnesota, reported that
their voluntary drop-off program for household batteries costs an average of $175,000 per year, which
June 1996 B-l SAB REVIEW DRAFT
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is roughly equivalent to $0.40/Mg ($0.37/ton) of MSW combusted. This cost included collection,
sorting, disposal and associated administration costs (Shepherd, 1993; White and Jackson, 1993).
During the first 3 years of operation, this program collected an estimated 330 kg (730 Ib) of mercury-
equivalent to reducing the mercury content of the waste stream by approximately 13 percent (White
and Jackson, 1993). Assuming a 50 percent mercury control efficiency by the SD/FF system at the
Hennepin County MWC, this equates to a cost effectiveness of approximately $3,180/kg1 ($l,450/lb)
of reduced mercury emissions. Costs of other community household battery separation programs are
not readily available, and they will vary depending on community-specific conditions.
Once household batteries that test hazardous have been collected, they must be disposed of at
a hazardous waste facility or sent to a metals recycler. The only mercury-containing batteries that can
be recycled currently in the United States are mercury-zinc batteries and mercuric oxide batteries that
have been sorted by type. Mercury Refining Company in Lathem, New York, accepts sorted mercury-
zinc button cells for a fee of $3.30/kg ($1.50/lb) of batteries (shipping not included) (Shepherd, 1993).
B.I.3 Activated Carbon Injection
Table B-l presents estimated costs for using activated carbon injection on the 180-Mg/day
(200-tpd) and the 2,050-Mg/day (2,250-tpd) MWCs. Carbon injection is assumed to achieve an
average mercury reduction of 85 percent with a carbon feed rate of 320 mg/dscm (0.14 gr/dscf) for the
DSI/ESP-equipped plant (Kilgroe et al., 1993) and 75 mg/dscm (0.033 gr/dscf) for the SD/FF-equipped
plant (U.S. EPA, 1992c).2 This results in outlet mercury levels after carbon injection of
approximately 90 and 75 ug/dscm (35 and 26 gr/million dscf) for the two MWCs respectively. The
DSI/ESP-equipped plant requires a higher feed rate because the ESP does not provide secondary
reaction between the carbon and the flue gas, as occurs on the bags of the FF. Also, the flue gas
temperature is higher with the DSI/ESP system than with the SD/FF system (177°C [350°F] vs. 135°C
[275°F]).
The capital cost listed in Table B-l includes purchased equipment (PE), installation, indirect
and contingency costs for the mercury control system. The major equipment items include a carbon
holding tank and metering system, a^pneumatic feed system and injection ports into the ductwork.
These costs are estimated to be approximately $87,100 and $372,000 for the small and large MWCs,
respectively, and include the costs of installation (Guest and Knizek, 1991). Indirect costs are
estimated to be 33 percent of PE costs, and contingency costs are estimated to be 20 percent of PE
costs plus indirect costs. These costs are based on the cost factors used for a DSI system in the MWC
cost procedures (U.S. EPA, 1989b). Installation is assumed to occur during a regular plant outage, so
no cost associated with downtime is included in the capital costs.
The operating and maintenance (O&M) cost includes labor; maintenance materials; activated
carbon costs; disposal; overhead; and taxes, insurance and administrative charges. With the exception
of carbon, disposal costs and capital recovery, costs are based on the MWC
1 S175,000/yr divided by 110 kg/yr divided by 0.50 = S3,180/kg.
2 Mercury reduction can be increased with higher levels of carbon.
June 1996 , B-2 SAB REVIEW DRAFT
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Table B-l
Cost Estimates for Activated Carbon Injection on Municipal Waste Combustorsa
Parameter
Unit Size (Mg/day)
Number of Units
Plant Size (Mg/day)
Flue Gas Flow (dscm/hr @ 7% O2)
Air Pollution Control Device
Hg Level Before Carbon (pg/dscm @ 7% O2)
Hg Level After Carbon (ng/dscm @ 7% O2)
Capacity Factor (%)
CAPITAL COST (S)
Purchased Equipment (PE)b
Installation0
Indirect*1
Contingency*
Total Capital Cost (TCC)
OPERATING AND MAINTENANCE (O&M)
(S/yr)
Operating Labo/
Supervision8
Maintenance Labor11
Maintenance Materials1
Power1
Carbonk
Disposal1
Overhead"1
Taxes, Insurance, Administration"
Capital Recovery0
Total (S/yr)P
S/Mg MSW
S/ton MSW
Mercury Reduction (kg/yr)
Mercury Reduction (Ib/yr)
S/kg Mercury
S/lb Mercury
Small Model Plant
90
2
180
30,500
DSI/ESP
595
90
90
87,100
0
28,700
23,200
139,000
52,600
7,880
14,500
4,350
0
84,800
0
47,600
5,560
15,300
232,000
3.90
3.50
121
267
1,910
870
Large Model Plant
682
3
2,045
343.000
SD/FF
490
75
90
372,000
0
123,000
99,000
594.000
78,800
11,800
21,700
18,600
0
222,000
0
78,600
23,700
65,200
520,000
0.77
0.70
1,120
2,470
464
211
Cost numbers may not add exactly due to round-off.
Based on 5200,000 equipment costs for a 730-Mg/day MWC. Equipment costs scaled based on 0.6 rule.
Included in PE costs.
33 percent of PE costs.
20 percent of PE + indirect costs.
2 hr/smft @ $12/hr (per unit).
15 percent of operating labor costs.
0.5 hr/shift @ 10 percent wage rate premium over labor wage (per unit).
5 percent of operating labor costs.
Power costs associated with the active carbon injection system are assumed to be negligible.
Based on Sl.lO/kg of carbon and a carbon feed rate of 320 and 75 mg/dscm for the two plants, respectively.
Increase in disposal costs due to carbon injection are assumed to be negligible.
60 percent of labor and maintenance costs.
4 percent of TCC.
Using a capital recovery factor of 0.1098 (7 percent interest rate for 15 years).
Total costs equal capital recovery costs plus O&M costs.
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cost procedures. The cost of activated carbon ranges from $1.10 to $2.20/kg ($0.50 to 1.00/lb)
depending on the raw material used to produce the carbon and the specific surface area of the carbon
(Brown, 1991). Based on a carbon cost of $1.10/kg ($0.50/lb) and a carbon feed rate of 75 mg/dscm
(0.033 gr/dscf), the carbon costs are roughly $0.33/Mg ($0.30/ton) of MSW. At a feed rate of 320
mg/dscm (0.14 gr/dscf), carbon costs are approximately $1.40/Mg ($1.30/ton) of MSW. The addition
of carbon into the flue gas has a negligible impact on the quality of collected PM requiring disposal.
Therefore, the ash disposal costs associated with an activated carbon injection system are assumed to
be negligible. The capital recovery factor (CRF) is based on a 7 percent interest rate annualized over
15"years (CRF = 0.1098). Total costs include the capital recovery costs and O&M costs. The largest
contributions to the cost of an activated carbon system are typically carbon and labor costs.
The overall estimated costs for an activated carbon injection system are approximately
$3.9/Mg ($3.5/ton) of MSW for the 180-Mg/day (200-tpd) MWC and $0.77/Mg ($0.70/ton) of MSW
for the 2,045-Mg/day (2,250-tpd) MWC. Of this amount, operating expenses account for
approximately 80 percent of the total. On the basis of dollars per kilogram of mercury removed from
the flue gas, the costs are $l,910/kg ($870/lb) and $464/kg ($211/lb) for the 180-Mg/day (200-tpd)
and the 2,045 Mg/day (2,250-tpd) MWCs, respectively.
Table B-2 provides a sensitivity analysis showing the impact of mercury input level on the
costs expressed in dollars per megagram of MSW burned and dollars per kilogram of mercury
removed. For the .purpose of the sensitivity analysis, the mercury input level was assumed to be
reduced by 50 percent through materials separation or other means while the carbon feed rate is
maintained at the same level. Under these assumptions, the outlet mercury levels are reduced to
45 ug/dscm (20 gr/million dscf) and 35 ug/dscm (15 gr/million dscf). The total annualized cost of the
carbon system remains the same, but the cost per kilogram of mercury removed increases. For the
180-Mg/day (200-tpd) MWC, the cost increases to $3,790/kg ($l,720/lb) of mercury removed. For the
2,045-Mg/day (2,250-tpd) MWC, the cost increases to $915/kg ($416/lb) of mercury removed. Costs
for a materials separation program are not included in the sensitivity analysis.
Table B-2
Sensitivity Analysis for
Activated Carbon Injection System on MWCs
Operating Assumptions
Base Case (Table A-l)
50% Lower Hg Input3
180-Mg/day MWC
$/Mg MSW
3.9
3.9
$/kg Hg
1,910
3,790
2,045-Mg/day MWC
$/Mg MSW
0.77
0.77
$/kg Hg
464
915
a Inlet mercury level (upstream of APCD) is reduced to 350 ng/dscm. There is no change in capital or operating costs. The
amount of mercury removed is the only factor affected. The outlet mercury level is 40 jig/dscm and 30 ng/dscm for the small
and large plants, respectively.
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B.1.4 Carbon Filter Beds
Table B-3 presents estimated costs for applying a carbon bed filter to the 180-Mg/day (200-
tpd) and the 2,045-Mg/day (2,250-tpd) MWCs. The carbon filter bed is assumed to achieve greater
than 99 percent reduction of mercury emissions, with outlet levels for both MWCs of 1 (ig/dscm
(0.44 gr/million dscf) (Hartenstein, 1993c).
The capital cost includes PE, installation, indirect and contingency costs. The major
equipment items include the filter, the steel structure, carbon conveyors and storage and ducting.
These costs are estimated to be $10,500,000 for the 180-Mg/day (200-tpd) MWC and $45,000,000 for
the 2,045-Mg/day (2,250-tpd) MWC (Petersen, 1993). Indirect costs are estimated to be 28 percent of
the PE costs based on the cost factor used for carbon adsorbers in the OAQPS Control Cost Manual
(U.S. EPA, 1992d). Contingency costs are estimated to be 10 percent of PE costs. This contingency
factor is limited to process uncertainties and reflects the technical and economic risks associated with a
new process application (Electric Power Research Institute, 1986). For the small MWC, no cost
associated with downtime for installing the filter bed is included. It is assumed that this retrofit will
occur during other retrofits (e.g., of the DSI system) needed to comply with anticipated new source
performance standard (NSPS) revisions under the Clean Air Act. For the large MWC, which is
assumed to already have the SD/FF system in place, 1 month of downtime is included for installation
of the filter system. Costs associated with the downtime are based on the EPA's MWC cost
procedures'(U.S. EPA, 1989b).
The O&M costs include labor; maintenance materials; carbon; power; disposal; overhead;
taxes, insurance and administrative charges; and capital recovery. With the exception of carbon,
power, disposal and capital recovery, these costs are based on the MWC cost procedures (U.S. EPA,
1989b). The annual carbon cost is based on the activated carbon price of $1.10/kg ($0.50/lb) and a
usage rate of 2.20 kg carbon/Mg (4.4 Ib carbon/ton) of MSW (Hartenstein, 1993a). Activated carbon
is used in this estimate instead of the cheaper German Hearth Oven Coke (HOC) (~$0.35/kg
[$0.15/lb]) because the availability of HOC in the United States is unknown.
The cost of power is based on a pressure drop of 305 mm (12-in. water) and a cost of 46 mills
per kilowatt-hour (mills/kWh) (Hartenstein, 1990; U.S. EPA, 1989b). Disposal costs are based on a
hazardous waste disposal rate of $200/ton. A CRF of 0.1098 (7 percent over 15 years) was used to
annualize the capital costs.
The estimated costs for a filter bed system are approximately $10/Mg ($9/ton) and $6/Mg
($5/ton) for the 180-Mg/day (200-tpd) and 2,045-Mg/day (2,250-tpd) MWCs, respectively. Of this
amount, 75 to 80 percent is directly related to the capital cost of the system (including taxes, insurance
and administration). On the basis of dollars per kilogram of mercury removed, the costs are $2,378/kg
($l,083/lb) and $l,130/kg ($513/lb) for the two unit sizes, respectively.
Table B-4 shows the results of a sensitivity analysis to determine the impact of reduced
mercury input on the costs expressed in dollars per megagram of waste burned and dollars per
kilogram of mercury removed. As discussed in section 2.2.1, the size of the filter and the amount of
carbon used depend on flue gas flow rate and pressure drop, not mercury inlet level. As a result,
when the mercury inlet level is reduced by 50 percent through materials separation or other means, the
capital and operating costs do not change. The cost per kilogram of mercury removed, however,
increases substantially because of the decreased amount of mercury removed annually by the filter bed.
For the 180-Mg/day (200-tpd) MWC, the cost increases to $4,756/kg ($2,161/lb) of mercury removed.
For the 2,045-Mg/day (2,250-tpd) MWC, the cost increases to $2,260/Mg ($l,027/lb) of mercury
June 1996 B-5 SAB REVIEW DRAFT
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Table B-3
Cost Estimate for a Carbon Filter Bed on MWC'sa
Parameter
Unit Size (Mg/day)
Number of Units
Plant Size (Mg/day)
Flue Gas Flow (dscm/hr @ 1% O,)
Air Pollution Control Device
Hg Level Before Filter (ng/dscm @ 7% O2)
Hg Level After Filter (ng/dscm @ 7% O2)~
Capacity Factor (%)
CAPITAL COST (S)
Purchased Equipment (PE)b
Installation0
Indirect*1
Contingency8
Total Capital Cost (TCC)
Downtimef
TCC + Downtime
OPERATING AND MAINTENANCE (O&M) (S/yr)
Operating Labor8
Supervision11
Maintenance Labor1
Maintenance Materials'
Carbon*
Power1
Disposal1"
Overhead0
•Taxes. Insurance, Administration0
Capital Recovery1*
Total (S/yr)l
S/Mg MSW
S/ton MSW
Mercury Reduction (kg/yr)
Mercury Reduction (Ib/yr)
S/kg Mercury
S/lb Mercury
Small Model Plant
90
2
180
30.500
DSI/ESP •
595
1
90
330.834
0
92.634
33.083
456.551
0
456.551
105,000
15,750
14,500
4,566
16,278
29.700
1,978
83.889
18.262
60,129
340,052
10.35
9.39
143
314
2,378
1.083
Large Model Plant
682
3
2.045
343.000
SD/FF
490
1
90
2,315.284
0
648,280
231.528
3,195.092
1.325.000
4.520.092
158.000
23.700
21.700
31.951
166.084
307.000
20.179
141,211
127.804
496.306
1.493.934
6.00
5.44
1.322
2.910
1.130
513
Cost numbers may not add exactly due to round-off.
Based on order of magnitude estimates for carbon usage.
Included in PE costs.
28 percent of PE costs.
10 percent of PE costs.
Downtime of 15 days assumed for large MWC. For small MWC, installation assumed to occur during other retrofits, so
downtime costs are zero.
4 hr/shift @ S12/hr (per unit).
15 percent of operating labor costs.
0.5 hr/shift @ 10 percent wage rate premium over labor wage (per unit).
1 percent of TCC.
Based on Sl.lO/kg of carbon and 2.2 kg carbon/Mg MSW.
Using a pressure drop of 305 mm (water) and 46 mills per kilowatt-hour (mills/kWh).
Based on a hazardous waste disposal rate of S220/Mg.
60 percent of labor and maintenance costs.
4 percent of TCC.
Using a capital recovery factor of 0.1098 (7 percent interest rate for 15 years).
Total costs equal capital recovery costs plus O&M costs.
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Table B-4
Sensitivity Analysis for a Carbon Filter Bed System on MWCs -
Operating Assumptions
Base Case (Table B-3)
50% Lower Hg Inputa
' 180-Mg/day MWC
$/Mg MSW
10
20
$/kg Hg
2,378
4,756
2,045-Mg/day MWC
$/Mg MSW
6
12
$/kg Hg
1,130
2,260
Inlet mercury level (upstream of APCD) is reduced to 325 ng/dscm. There is no change in capital or operating costs. The
amount of mercury removed is the only factor affected. The outlet mercury level remains at 1 ^g/dscm.
removed. Costs associated with a materials separation program are not included in the sensitivity
analysis.
B.1.5 Wet Scrubbing
Table B-5 presents estimated costs for applying a polishing WS system on the 180-Mg/day
(200-tpd) and the 2,0450 Mg/day (2,250-tpd) MWCs. The polishing WS system is assumed to achieve
85 percent reduction of the mercury level after the APCD, resulting in outlet mercury levels of
approximately 90 and 75 ug/dscm (35 and 26 gr/million dscf) for the two MWCs, respectively.
The capital cost includes PE, installation, indirect, contingency and downtime costs. The PE
costs are estimated to be $2,600,000 and $13,000,000 for the small and large MWCs, respectively and
include the costs of installation (Nebel et al, 1994). Indirect costs are estimated to be 33 percent of
PE costs and contingency costs are estimated to be 20 percent of PE costs plus indirect costs. These
costs are based on the cost factors used in the MWC cost procedures (U.S. EPA, 1989b). For the
small MWC, no cost associated with downtime for installing the WS system is included. It is assumed
that this retrofit will occur during other APCD retrofits. Fpr the large MWC, which is assumed to
already have the SD/FF system in place, 1 month of downtime is included for installation of the WS
system. Costs associated with the downtime are based on the EPA's MWC cost procedures (U.S.
EPA, 1989b).
The costs for operating and maintenance labor, electric power, lime, water, water treatment and
residue disposal are based on information provided from a wet scrubber vendor (Nebel et al., 1994).
Costs for overhead and taxes, insurance and administration charges are based on the EPA's MWC cost
procedures (U.S. EPA, 1989b). A CRF of 0.1098 (7 percent over 15 years) was used to annualize the
capital costs.
The overall estimated costs for a polishing WS system equate to approximately $14.9/Mg
($13.5/ton) and $5.9/Mg ($5.3/ton) of MSW for the small and large model plants, respectively. The
cost effectiveness values are $7,300/kg ($3,320/lb) of mercury removed for the small MWC and
$3,520/kg ($l,600/lb) of mercury removed for the large MWC.
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Table B-5
Cost Estimate for a Polishing Wet Scrubbing
System on Municipal Waste Combustors3
Parameter
Unit Size (Mg/day)
Number of Units
Plant Size (Mg/day)
Flue Gas Flow (dscm/hr @ 7% O2)
Air Pollution Control Device
Inlet Hg Level (Mg/dscm @ 7% O2)
Outlet Hg Level (ug/dscm @ 7% 62)
Capacity Factor (%)
CAPITAL COST (S)
Purchased Equipment (PE)b
Installation0
Indirect4
Contingency*
Total Capital Cost (TCC)
Downtime
TCC + Downtime
OPERATING AND MAINTENANCE (O&M) (S/yr)s
Operating Labor
Supervision
Maintenance Labor
Electric Power
Reagent (Lime)
Water
Water Treatment
Residue Disposal
Overhead11
Taxes. Insurance, Administration1
Capital Recovery1
Total (S/yr)k
S/Mg MSW
S/ton MSW
Mercury Reduction (kg/yr)
Mercury Reduction (Ib/yr)
S/kg Mercury
S/lb Mercury
Small Model Plant
90
2
180
30,490
DSI/ESP
595
90
90
2,590,000
0
854,000
688,000
4,130.000
0
4,130.000
80,000
12,000
54,700
20,900
0
3,300
3,800
4,900
88,100
165,000
453,000
886.000
14.9
13.5
121
267
7,300
3,320
Large Model Plant
682
3
2.045
343.000
SD/FF
490
75
90
13,000,000
0
4.290.000
3.460.000
20,750.000
270.000
21.020,000
80,000
12.000
177,000
235.000
0
37.100
42.800
55.100
161.000
830.000
2.310,000
3.940.000
5.9
5.3
1.120
2,470
3,520
1.600
a Cost numbers may not add exactly due to round-off.
b Based on cost estimates from Belco Technologies Corporation (35 percent less than PE cost for a two-stage system).
0 Included in PE costs.
33 percent of PE costs.
* 20 percent of PE + indirect costs.
f Downtime of 1 month assumed for large MWC. For small MWC, installation assumed to occur during other retrofits, so downtime costs
are zero.
8 Operating and maintenance costs are based on costs provided by Belco for a three-stage wet scrubbing system. Costs for electric power,
water, water treatment and residue disposal were cut in half in attempt to account for the smaller system.
11 60 percent of labor and maintenance costs.
1 4 percent of TCC.
1 Using a capital recovery factor of 0.1098 (7 percent interest for 15 years).
Total costs equal capital recovery costs plus O&M costs.
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Table B-6 provides a sensitivity analysis showing the impact of mercury input level on the
costs expressed in dollars per megagram.of MSW burned and dollars per kilogram of mercury
removed. Assuming the mercury input is reduced by 50 percent through materials separation or other
means, the total annualized cost remains the same, since capital and operating costs of the WS system
do not change. Outlet mercury levels are reduced to 45 ug/dscm (17 gr/million dscf) and 35 ug/dscm
(13 gr/dscf) for the small and large MWCs, respectively. The cost per kilogram of mercury removed,
however, increases substantially because of the decreased amount of mercury removed annually by the
WS system. For the 180-Mg/day (200-tpd) MWC, the cost increases to $14,570/kg ($6,590/lb) of
mercury removed. For the 2,045-Mg/day (2,250-tpd) MWC, the cost increases to $6,930/kg
($3,140/lb) of mercury removed. Costs for a materials separation program are not included in the
sensitivity analysis.
Table B-6
Sensitivity Analysis for a
Polishing Wet Scrubbing System on MWCs \
Operating Assumptions
Base Case (Table B-5)
50% Lower Hg Inputa
180-Mg/day MWC
$/Mg MSW
14.9
14.9
$/kg Hg
7,300
14,570
2,045-Mg/day MWC
$/Mg MSW
5.9
5.9
$/kg Hg
3,520
6,930
Inlet mercury level (upstream of APCD) is reduced to 350 |ag/dscm. There is no change in capital or operating costs. The
amount of mercury removed is the only factor affected. The outlet mercury level is 45 jag/dscm and 35 |ag/dscm for the small
and large plants, respectively.
B.2 Medical Waste Incinerators
B.2.1 Model Plant Description
•
Two model plants have been selected to represent the MWI category based on the model
plants used in the EPA's MWI study (U.S. EPA, 1991d; U.S. EPA, 1994e). The first is a small batch-
run MWI with a design capacity of 90 kg/hr (200 Ib/hr), but operating at an average throughput of
60 kg/hr (130 Ib/hr) because of the high heat content of the waste. This plant is assumed to operate
5.5 hr/day, 5 days/week (which equals a capacity factor of 20 percent), and is equipped with a DSI/FF
system. Currently, few MWIs have this level of control. For the purpose of evaluating mercury
controls on MWIs, however, it was assumed that acid gas and PM controls would be installed to
comply with other regulatory requirements. Costs for DSI/FF controls are not included in the mercury
cost analysis since it is not appropriate to attribute the cost of acid gas and PM controls solely to the
removal of mercury.
The second model plant is a larger, commercial MWI. It has a design capacity of 680 kg/hr
(1,500 Ib/hr), but operates at 455 kg/hr (1,000-lb/hr). It operates 24 hr/day, 7 days/wk, and is assumed
to operate 90 percent of the year. This MWI is also assumed to be equipped with a DSI/FF system.
The inlet mercury level for the MWI model plants is assumed to be 3,000 ug/dscm
(1,310 gr/million dscf). No control of mercury is assumed to occur across the DSI/FF system (U.S.
June 1996
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EPA, 19915; U.S. EPA, 1992c; Lerner, 1992). Both DSI/FF systems operate at a temperature across
the FF of 160°C (325°F).
The following sections present a cost analysis of different mercury control options for MWIs.
Section B.2.2 provides a qualitative cost discussion on material separation costs and sections B.2.3 and
B.2.4 provide more quantitative cost information on applying activated carbon injection to both MWI
model plants and a polishing WS system to the large MWI model plant.
A sensitivity analysis presenting the effect that lower mercury levels in the flue gas (from
materials separation or other means) would have on these costs is included.
B.2.2 Materials Separation
There is no report of costs of materials separation programs at medical facilities. The cost
effectiveness of a battery separation program at a hospital may be better than in the general population
if the hospital staff is well-trained and motivated. In general, the high-mercury-content instrument
batteries used in hospitals are handled by a limited number of staff. Therefore, the administrative and
educational costs associated with a separation program should be minimal. The collection and
handling costs of separating a relatively small number of high- concentration mercury batteries would
also be small.
B.2.3 Activated Carbon Injection
Table B-7 presents estimated costs for using activated carbon injection on the 60-kg/hr (130-
Ib/hr) and 455-kg/hr (1,000-lb/hr) MWIs. The carbon injection is assumed to achieve 85 percent
reduction with a carbon feed rate of 676 mg/dscm (0.30 gr/dscf). This results in an outlet mercury
concentration of 450 ug/dscm (197 gr/million dscf).
The cost components presented in Table B-7 are the same as those discussed in Section B.I.3.
The total capital costs are estimated to be $7,660 for the smaller batch MWI and $25,700 for the
larger commercial MWI (U.S. EPA, 1991d). The overall estimated costs for an activated carbon
injection system are $48/Mg ($43/ton) of medical waste for the batch MWI and $11.3/Mg ($10.3/ton)
of medical waste for the commercial MWI. This produces a cost effectiveness of $2,110/kg ($955/lb)
of mercury removed and $503/kg ($228/lb) of mercury removed for the batch and commercial MWIs,
respectively.
Table B-8 provides a sensitivity analysis showing the impact of mercury input level and
capacity factor on the costs expressed in dollars per megagram of medical waste and dollars per
kilogram of mercury removed. For the purpose of the sensitivity analysis, the mercury input level was
assumed to be reduced by 50 percent through materials separation or other means while the carbon
feed rate remained at 676 mg/dscm (0.30 gr/dscf). Under these assumptions, the outlet mercury level
is 225 ug/dscm (98 gr/million dscf). The total annualized cost remains the same, since the capital and
operating costs do not change. The cost per kilogram of mercury removed, however, increases
substantially because less mercury is removed annually. For the 60-kg/hr (130-lb/hr) MWI, the cost
increases to $4,220/kg. ($l,910/lb) of mercury removed. For the 455-kg/hr (1,000-lb/hr) MWI, the cost
increases to $l,000/kg ($452/lb) of mercury removed. If the capacity factor for the larger MWI is
decreased to 20 percent (the same level as assumed for the small MWI), the cost increases to
$l,695/kg ($767/lb).
June 1996 B-10 SAB REVIEW DRAFT
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Table B-7
Cost Estimate for Activated Carbon Injection
on Medical Waste Incinerators3
Parameter
Unit Size (kg/hr)
Number of Units
Plant Size (kg/hr)
Flue Gas Flow (dscm/hr @ 7% O,)
Air Pollution Control Device
Hg Level Before Carbon (pg/dscm @ ~l% O-,)
Hg Level After Carbon (ng/dscm @ 7% O,)
Capacity Factor (%)
CAPITAL COST (S)
Purchased Equipment (PE)b
Installation0
Indirect"1
Contingency8
Total Capital Cost (TCC)
OPERATING AND MAINTENANCE (O&M) (S/yr)
Operating Labor
Supervision8
Maintenance Labor1
Maintenance Materials'
Power1
Carbon*
Disposal1
Overhead™
Taxes, Insurance, Administration11
Capital Recovery0
Total (S/yr)P
S/Mg Medical Waste
S/ton Medical Waste
Mercury Reduction (kg/yr)
Mercury Reduction (Ib/yr)
S/kg Mercury
S/lb Mercury
Small Model Plant
60
1
60
537
DSI/FF
3,000
450
20
4,800
0
1,580
1,280
7,660
780
117
858
240
0
700
0
1,200
305
840
5,040
48
43
• 2.1
4.5
2,110
955
Large Model Plant
455
1
455
4.033
DSI/FF
3.000
450
90
16.100
0
5,310
4.280
25.700
3.290
495
3.610
805
0
23,644
0
4.920
1.030
2.820
40,600
11.3
10.3
80
178
503
228
a Cost numbers may not add exactly due to round-off.
b Based on $200,000 for an 730-Mg/day MWC. Scaled based on 0.6 rule.
c Included in PE costs.
d 33 percent of PE costs.
e 20 percent of PE + indirect costs.
f 0.25 hr/shift @ $12/hr (per unit).
g 15 percent of operating labor costs.
0.25 hr/shift @ 10 percent wage rate premium over labor wage (per unit).
1 5 percent of PE costs.
J Power costs associated with the active carbon injection system are assumed to be negligible.
Based on Sl.lO/kg of carbon and a carbon feed rate of 676 mg/dscm.
Increase in disposal costs due to carbon injection are assumed to be negligible.
m 60 percent of labor and maintenance costs.
Q 4 percent of TCC.
0 Using a capital recovery factor of 0.1098 (7 percent interest rate for 15 years).
p Total costs equal capital recovery costs plus O&M costs.
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Table B-8
Sensitivity Analysis for an
Activated Carbon Injection System on MWIs
Operating Assumptions
Base Case (Table A-7)
50% Lower Hg Input**
20% Capacity Factor0
60-kg/hr MWI
$/Mg MWa
48
48
—
$/kg Hg
2,110
4,220
—
455-kg/hr MWI
$/Mg MW
11.3
11.3
38.5
$/kg Hg
503
1,000
1,695
MW = medical waste on this table only.
b Inlet mercury level (upstream of APCD) is reduced to 1,500 |ug/dscm. There is no change in capital or operating costs. The
amount of mercury removed is the only factor affected. The outlet mercury level is 225 ng/dscm.
c Base case capacity factor for 60-kg/hr MWI already 20 percent.
B.2.4 Wet Scrubbing
Table B-9 presents estimated costs for using a polishing WS system on the 455-kg/hr
(1,000 Ib/hr) MWI. The application of a WS system to the batch MWI was initially considered.
Based on the small size of the MWI and the complexity of wet scrubbers, however, it was determined
that this control option is not feasible. The WS system is assumed to achieve 85 percent reduction,
resulting in an outlet mercury level of 450 ug/dscm (196 gr/million dscf).
The capital cost components presented in Table B-9 are the same as those discussed in
section B.1.4. The PE costs are $114,000 and the total capital costs are estimated to be $182,000
(Lerner, 1993b).
The overall estimated costs for the WS system are«$13.2/Mg ($12.0/ton) of medical waste.
The cost effectiveness for the system is $682/kg ($310/lb) of mercury removed.
Table B-10 provides a sensitivity analysis showing the impact of mercury input level and
capacity factor on the costs expressed in dollars per megagram of medical waste and dollars per
kilogram of mercury removed. If the mercury input is reduced by 50 percent through materials
separation or other means, the outlet mercury level would be 225 ug/dscm (98 gr/million dscf). The
total annualized cost remains the same, since the capital and operating costs do not change. The cost
per kilogram of mercury removed, however, increases substantially because of the decreased amount of
mercury removed annually by the WS system. For the 455-kg/hr (1,000-lb/hr) commercial MWI, the
cost increases to $l,370/kg ($621/lb) of mercury removed. If the capacity factor is decreased to
20 percent, the cost increases to $3,067/kg ($l,394/lb).
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Table B-9
Cost Estimate for a Polishing Wet Scrubbing System
on Medical Waste Incinerators3
Parameter
Unit Size (kg/hr)
Number of Units
Plant Size (kg/hr)
Flue Gas Flow (dscm/hr @ 7% O2)
Air Pollution Control Device
Inlet Hg Level (ng/dscm @ 7% O2)
Outlet Hg Level (pg/dscm @ 7% 62)
Capacity Factor (%)
CAPITAL COST (S)
Purchased Equipment (PE)b
Installation'
Indirect*1
Contingency*
Total Capital Cost (TCC)
OPERATING AND MAINTENANCE (O&M) (S/yr)
Operating Labor
Supervision8
Maintenance Labor1
Maintenance Materials'
O&M ExpensesJ
Water/Wastewater Treatment*
Overhead1
Taxes, Insurance, Administration"1
Capital Recovery"
Total (S/yr)°
S/Mg Medical Waste
S/ton Medical Waste
Mercury Reduction (kg/yr)
Mercury Reduction (Ib/yr) •
S/kg Mercury
S/lb Mercury
Commercial MWI
455
1
455
3,460
DSI/FF
3.000
450
90
114,000
0
37.700
30.400
182.000
3,290
495
3.610
2.300
4,600
115
5.800
7,290
20,000
47,400
13.2
12.0
70
153
682
310
a Cost numbers may not add exactly due to round-off.
b Based on cost estimates from Belco Engineering.
c Included in PE costs.
d 33 percent of PE costs.
* 20 percent of PE + indirect costs.
1 0.25 hr/shift @ S12/hr (per unit).
8 15 percent of operating labor costs.
h 0.25 hr/shift @ 10 percent wage rate premium over labor wage (per unit).
1 2 percent of PE costs.
1 4 percent of PE costs.
k Using 2.3 liters/mm @ SO. 11/1.000 liters.
1 60 percent of labor and maintenance costs.
m 4 percent of TCC.
n Using a capital recover factor 0.1098 (7 percent interest rate for 15 years).
0 Total costs equal capital recovery costs plus O&M costs.
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Table B-10
Sensitivity Analysis for a Wet Scrubbing System on MWIs
Operating Assumptions
Base Case (Table B-9)
50% Lower Hg Inputb
20% Capacity Factor
Commercial (445-kg/hr) MWI
$/Mg MWa
13.2
13.2
59.5
$/kg Hg
682
1,370
3,067
MW = medical waste on this table only.
b Inlet mercury level (upstream of APCD) is reduced to 1,500 ng/dscm. There is no change in capital or operating costs. The
amount of mercury removed is the only factor affected. The outlet mercury level is 225 (ig/dscm.
B3 Utility Boilers
B.3.1 Model Plant Description
Three model coal-fired utility plants were developed to represent different methods of
controlling mercury emissions. All three operate with a capacity factor of 65 percent; that is
5,694 hr/yr. Fuel characteristics include chloride levels assumed to be sufficiently high that all the
mercury in the flue gas is in the form of HgCl2. (It should be noted that the assumption of mercury in
the form of 100 percent HgCl2 in the utility flue gas was made because the highest, or worst case,
activated carbon injection rates were projected for the case of 100 percent HgCl2 [Heath and Turner,
1994]). The inlet mercury level to the control systems associated with each coal-fired model plant is
10 ug/dscm (4.4 gr/million dscf) at 20°C (68°F).
Model plant 1 is a 975-megawatt (MW) coal-fired boiler firing low-sulfur coal with a chloride
content of 0.1 percent. The model plant has a flue gas vokime of 4,050,000 dscm/hr and is equipped
with a cold-side ESP. The temperature ahead of the ESP is 157°C (314°F) and the temperature exiting
the ESP is 150°C (300°F). No mercury control across the ESP is assumed.
Model plant 2 is a 975-MW coal-fired boiler firing high-sulfur coal (chloride content of
0.1 percent) and is equipped with a cold-side ESP (150°C [300°F]) and an FGD system. The FGD
system is assumed to be 50 percent efficient for mercury control and the controlled mercury level is
5 ug/dscm (2.2 gr/million dscf) (Noblett et al., 1993).
Model plant 3 is identical to Model plant 1, except that it has a capacity of 100 MW (Noblett
et al., 1993). The model plant has a flue gas volume of 411,000 dscm/hr. The gas temperature ahead
of the ESP is 146°C (295°F) and the ESP outlet temperature is 137°C (280°F). Again, no mercury
control across the ESP is assumed.
Seven control variations of the model plants were analyzed; five of the seven involved
controlling emissions using activated carbon injection. Mercury control of the units is accomplished
by one of the following methods:
• Direct injection of activated carbon ahead of the existing PM control device;
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• Spray cooling of the flue gas after the existing PM control device (or after the air
preheater for oil-fired boilers with no PM control device), followed by activated
carbon injection and an FF to collect the mercury-laden carbon;
• Spray cooling of the flue gas after the air preheater, followed by activated carbon
injection before the existing PM control device; or
• A carbon filter bed.
Table B-ll summarizes the model utility boilers and mercury controls used in the cost analysis.
Table B-ll
Model Utility Boilers and Mercury Controls Used in Cost Analysis
Model
la
Ib
Ic
Id
2
3a
3b
Size (MW)
975
975
975
975
975
100
100
Fuel
Low-sulfur Coal
Low-sulfur Coal
Low-sulfur Coal
Low-sulfur Coal
High Sulfur Coal
Low-sulfur Coal
Low-sulfur Coal
Pre-Existing Controls
ESP
ESP
ESP
ESP
ESP/FGD
ESP
ESP
Mercury Control
AC injection3
Spray cooler, AC injection, fabric filter
Spray cooler. AC injection
Carbon filter bed
Carbon filter bed
AC injection
Spray cooler, AC injection, fabric filter
a AC = activated carbon.
The coal-fired boiler flue gas is at 150°C (302°F) and 5 percent moisture at the ESP outlet. It
was assumed that the carbon injection would remove 90 percent of the mercury from coal-fired flue
gas. Carbon with adsorbed mercury is assumed to be a hazardous waste if collected in a dedicated FF.
When collected with fly ash in an existing ESP, the concentration of mercury is assumed to be too
small to require the ash-carbon mixture to be classified as hazardous. Waste disposal costs are
included in the cost estimates.
Simplified diagrams of the spray cooling and activated carbon injection systems are shown in
Figures B-l and B-2. As discussed in Section 2.2.7, each of these methods may not be applicable
under certain conditions. Depending on the characteristics of the activated carbon, it may not be
collected effectively in an existing ESP. High activated carbon injection rates were projected for the
models that did not use spray cooling. The highest activated carbon injection rate may add a
concentration of about 345 mg/actual cubic meter (acm) (0.15 gr/actual cubic feet [acf]), or about 5
percent of the typical fly ash loading in coal-fired utility flue gas. The increased carbon content of the
fly ash may adversely affect ESP performance. Spray cooling the flue gas may cause corrosion and
ash handling problems if the dew point is reached or if the spray is not completely evaporated.
Alternately, spray cooling the particulate-laden flue gas may improve PM collection efficiency
(especially if switching to low-sulfur coal) and the addition of small amounts of carbon may also
improve collection efficiency. Whether the activated carbon has a positive or
June 1996
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Figure B-l
Spray Cooling System
Bars
%;""!- and Nozzle
Water
Supply
Compressor
Sensors for
Temperature Control
Figure B-2
Carbon Injection System
Feed Auger
& Metenng System
Fluidization
Compressor
June 1996
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negative effect on ESP performance depends on site-specific operating and flue gas conditions. For
model plants where a FF is added to collect mercury-laden carbon, the design is assumed to be
appropriate for handling flue gas at 93°C (199°F) without "blinding" the FF bags.
The following sections present the cost analyses of different mercury control options for the
model plant boilers. Cost information for the model plants using activated carbon injection alone, and
in combination with spray cooling and additional PM control, is presented in section B.3.2. It should
be stressed that the effectiveness of carbon injection in controlling mercury emissions from MWCs has
been proven, but the technology is undergoing testing for application to utility boilers at only pilot-
scale facilities. Section B.3.3 provides cost information on applying a carbon filter bed to the model
plants.
B.3.2 Activated Carbon Injection
Activated carbon injection rates for model utility boilers used in costing carbon injection are
shown in Table B-12. The table shows each model, its size, concentration of mercury in the flue-gas,
temperature at the point of carbon injection and the mass ratio of carbon to mercury in the entering
flue gas.
Table B-12
Carbon Injection Rates for Utility Boiler Models with Mercury Control
Model
la
Ib
Ic
3a
3b •
Size
(MW)
975
975
975
100
100
Rue Gas Hg
Concentration at
Point of Injection
(ug/dscm)
10
10
10
10
10
Flue Gas
Temperature at
Point of Injection
(°C)
157
93
93
146
93
Carbon Usage
(g carbon/g Hg)
34,200
460
460
17,200
460
Carbon to mercury ratios were selected by using two equations obtained from Calgon
Corporation and described by Heath and Turner (1994). The equations depend on temperature as the
only variable not attributable to adsorbate characteristics when used for a specific activated carbon.
For this work, the carbon was assumed to be Calgon PCB 6x6.
As indicted in the table, only three flue-gas temperatures were used for the various models.
For those with waste spray cooling, 93°C (199°F) was assumed to be the temperature at the point of
carbon injection. For models not using water spray cooling, the temperatures were 157°C (315°F) and
146°C (295 °F) for the 975 MW and 100 MW plants, respectively.
The carbon injection rates used for the cost models were based on information available at the
time this Report was prepared. The rates seemed comparable (or conservative) compared to early
EPRI work (Chang et al. 1993) for the low temperature injection, but were less certain for the higher
temperatures. More current information may suggest using different injection rates.
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Tables B-13 through B-16 present the costs of applying activated carbon injection to the model
plants. The cost components presented in these tables are similar to those presented in section 2.1.3
with some exceptions. Purchased equipment costs for spray coolers and activated carbon injection
systems are based on vendor contacts (Durham and Ebner, 1993: Hoagland, 1993) and FF costs are
estimated from the EPA's OAQPS Control Cost Manual (U.S. EPA, 1992d). Costs from the OAQPS
manual are based on average costs for baghouses in many industries and may not reflect the
conservative nature of utility designs. This factor, and difficult retrofit- installations, may increase
baghouse costs by 50 percent or more. (No credit is taken for SO2 or other pollutants such as dioxin
that might be captured by the carbon nor were costs added for additional ductwork.) Cost factors in
the EPA's OAQPS Control Cost Manual are also used to estimate installation costs and indirect costs.
Contingency costs are included in the indirect costs. Labor usage for activated carbon injection
systems is proportionally higher for models without spray cooling than for models with cooling
because of significantly larger amounts of carbon that must be handled. Maintenance labor is
calculated using a labor charge rate of $13.20/hr, and maintenance materials are assumed to be equal
to maintenance labor costs. The CRF is based on a 7 percent interest rate annualized over 20 years
(CRF = 0.09439). The activated carbon injection system is assumed to reduce the mercury in the flue
gas to less than 1 ug/dscm (0.44 gr/million dscf) equal to 90 percent control for coal-fired boilers and
50 percent control for oil-fired boilers.
Table B-13 presents the costs for applying activated carbon injection to the 975- and 100-MW
ESP-equipped boilers firing low-sulfur coal (models la and 3a). The carbon injection system is
installed in existing ductwork ahead of the ESP. This arrangement requires high carbon usage
(1,385 kg/hr [3,050 Ib/hr] for the 975-MW boiler and 70.9 kg/hr [156 Ib/hr] for the 100-MW boiler)
because of the elevated gas temperature at the injection location. A size increase from 100 to
975 MW increases the total capitol cost for the control arrangement by a factor of 7.4 and increases
the annualized cost by a factor of 6.1; the cost effectiveness value decreases by 38 percent and the
annualized mills/kWh cost impact decreases by 32 percent. The total capital cost for the activated
carbon injection system is $1,260,000 for the 975-MW boiler and $167,100 for the 100-MW boiler.
The total annualized cost is $10,110,000/yr for the 975-MW boiler and $640,000/yr for the 100-MW
boiler.
Tables B-14 and B-15 present the costs for the 975- and 100-MW ESP-equipped low-sulfur
coal-fired boilers using activated carbon injection in conjunction with spray cooling and additional PM
control using a reverse-air FF (models Ib and 3b). This arrangement requires accurate temperature
control to prevent problems with excess acidic moisture condensation on ductwork and ash
agglomeration, which leads to higher maintenance and operating costs. This combination is also
expected to enhance the control of mercury. The spray cooling, which is upstream of the carbon
injection and after the existing ESP, serves to reduce the temperature of the flue gas where the carbon
is injected to 93°C (199°F). The FF is located after the injection system and before the stack. The FF
enhances the capture of the injected carbon. As a result, the carbon injection rate is reduced to
approximately 1 percent of the rate assumed in Table B-13. The activated carbon injection rate is 1.9
kg/hr (4.2 Ib/hr) for the 100-MW coal-fired boiler (model 3b) and 18.8 kg/hr (41 Ib/hr) for the 975-
MW coal-fired boiler (model Ib). Greater than 80 percent of the total capital cost for this control
arrangement is contributed by the FF and less than 3 percent is contributed by the activated carbon
injection system. A size increase from 100- to 975-MW increases the total capital cost for the control
arrangement by 86 percent and increases the annualized cost by 83 percent; the cost effectiveness
value decreases by 37 percent and the annualized mills/per kilowatt-hour cost impact decreases by
30 percent.
June 1996 B-18 SAB REVIEW DRAFT
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Table B-13
Cost Estimates for Applying a Carbon Injection System on
975- and 100-MW Coal-Fired Utility Boilers
Parameter
Unit Size (MW)
Flue Gas Flow (dscm/hr)
Air Pollution Control Device
Hg Level Before Injector (pg/dscm, 68°F)
Hg Level After Injector (|ug/dscm, 68°F)
Capacity Factor (%)
CAPITAL COST (S)
Purchased Equipment (PE)
Installation
Indirect
Total Capital Cost (TCC)
OPERATING AND MAINTENANCE (O&M) (S/yr)
Operating Labor0
Supervision Labor'1
Maintenance Labor6
Maintenance Materialsf
Carbon8
Power11
Disposal
Overheadk
Taxes, Insurance, Administration1
Capital Recovery"1
Total (S/yr)n
mills/kWh
Mercury Reduction (kg/yr)
Mercury Reduction (Ib/yr)
S/kg Mercury
S/lb Mercury
Model la
975
4.050.000
ESP1
10
1
65
869,830
130,474
260,949
1,260,000
103,680
15,552
57,024
57,024
9,556,509
13,675
316,068'
139,968
50,450
119,050
10,110.000
1.82
208
457
48,700
22,100
Model 3a
100
411,000
ESP5
10
1
65
115.226
17,284
34,568
167.100
38.880
5,832
19,008
19,008
488,980
700
16.1731
49.637
6.683
15,770
660.000
1.16
21
46
31,000
14.200
ESP outlet temperature of 150°C, moisture content of 5 percent.
ESP outlet temperature of 137°C, moisture content of 11 percent.
S12/hr.
15 percent of operating labor costs.
S13.20/hr.
Same as maintenance labor.
Based on $1.10/kg of carbon, plus 10 percent for shipping.
Based on 46 mills/kWh.
Based on a nonhazardous waste disposal rate of S33/Mg.
Based on a nonhazardous waste disposal rate of $36.36/Mg.
60 percent of labor and maintenance costs.
4 percent of TCC.
Using a capital recovery factor of 0.09439 (7 percent interest for 20 years).
Total costs equal capital recovery costs plus O&M costs.
June 1996
B-19
SAB REVIEW DRAFT
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Table B-14
Cost Estimates for Applying a Carbon Injection System in
Conjunction with a Spray Cooler and a Fabric Filter on a
975-MW Coal-Fired Utility Boiler (Model Ib)
Parameter
Unit Size (MW)
Flue Gas Flow (dscm/hr)
Air Pollution Control Device
Hg Level Before Injector (|ag/dscm, 68°F)
Hg Level After Filter (ug/dscm, 68°F)
Capacity Factor (%)
CAPITAL COST (S)
Purchased Equipment (PE)
Installation
Indirect
Total Capital Cost (TCC)
OPERATING AND MAINTENANCE
(O&M) (S/yr)
Operating Labor*5
Supervision Labor0
Operating Materials
Maintenance Labord
Maintenance Materials6
Carbonf
Power8
Disposal11
Overhead1
Taxes, Insurance, Administration1
Capital Recovery*
Total (S/yr)1
mills/kWh
Mercury Reduction (kg/yr)
Mercury Reduction (Ib/yr)
S/kg Mercury
SAb Mercury
Model Plant
975
4.050.000
ESPa
10
1
65
Cooling
2,993,796
1,017,891
1,347,208
5,358.894
25,920
3,888
219,572
19,008
19,008
958,363
—
40,694
214,356
505,826
2,006,635
0.36
—
—
9,668
4,393
Injection
109,448
16,417
32,835
158,700
25,920
3,888
—
14,256
14,256
129,628
185
—
34,992
6,348
14,980
244,453
" 0.04
—
—
1,178
535
Fabric Filter
12,978,750
9,344,700
5,840,438
28.163,888
155,520
23,328
302,102
85,536
85,536
1,088,412
50,503
209,952
1,126,556
2,561,802
5,689,245m
1.02
—
—
27,412
12,454
Total
16,081,994
10,379,008
7,220,480
33,700,000
207,360
31,104
521,674
118,800
118,800
129,628
2,046,960
50,503
285,638
1,347,259
3,082,607
7,940,000
1.43
208
457
38,300
17,400
a ESP outlet temperature of 150°C, moisture content of 5 percent.
b S12/hr.
c 15 percent of operating labor costs.
d S13.20/hr.
' Same as maintenance labor.
f Based on Sl.lO/kg of carbon, plus 10 percent for shipping.
g Based on 46 mills/kWh.
h Based on a hazardous waste disposal rate of S220/Mg.
1 60 percent of labor and maintenance costs.
J 4 percent of TCC.
k Using a capital recovery factor of 0.09439 (7 percent interest for 20 years).
1 Total costs equal capital recovery costs plus O&M costs.
m See text for factors that may increase fabric filter costs.
June 1996
B-20
SAB REVIEW DRAFT
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Table B-15
Cost Estimates for Applying a Carbon Injection System in
Conjunction with a Spray Cooler and a Fabric Filter on a
100-MW Coal-Fired Utility Boiler (Model 3b)
Parameter
Unit Size (MW)
Flue Gas Flow (dscm/hr)
Air Pollution Control Device
Hg Level Before Injector (pg/dscm, 68°F)
.Hg Level After Filter (|ag/dscm, 68°F)
Capacity Factor (%)
CAPITAL COST (S)
Purchased Equipment (PE)
Installation
Indirect
Total Capital Cost (TCC)
OPERATING AND MAINTENANCE
(O&M) (S/yr)
Operating Laborb
Supervision Labor0
Operating Materials
Maintenance Labord
Maintenance Materials*
Carbonf
Power8
Disposal11
Overhead'
Taxes, Insurance, Administration1
Capital Recovery1'
Total (S/yr)1
mills/kWh
Mercury Reduction (kg/yr)
Mercury Reduction (Ib/yr)
S/kg Mercury
S/lb Mercury
Model Plant
100
411,000
ESP"
10
1
65
Cooling
258,627
87,933
116,382
462.941
17,280
2,592
18,968
9,504
9,504
—
82,791
—
23,328
18.518
43,697
226,182
0.22
-
-
10,739
4,879
Injection
109,448
16,417
32,835
158,700
25,920
3,888
—
14,256
14,256
13,152
188
—
34,992
6,348
14,980
127,980
* 0.25
--
--
6,076
2,761
Fabric Filter
1,813,479
1,305,705
816.066
3,935.249
51,840
7,776
60,816
42,768
42,768
...
116,956
4,660
87,091
157,410
361,069
933,155m
1.64
--
-
44,305
20.129
Total
2,181,554
1.410,055
965.282
4,560.000
95,040
14,256
79,785
66,528
66,528
13,152
199,935
4,660
145,411
182.276
419,746
1.290,000
2.09
21
41
61,000
27,700
ESP outlet temperature of 137°C, moisture content of 11 percent.
S12/hr.
15 percent of operating labor costs.
$13.20/hr.
Same as maintenance labor.
Based on Sl.lO/kg of carbon, plus 10 percent for shipping.
Based on 46 mills/kWh.
Based on a hazardous waste disposal rate of 5220/Mg.
60 percent of labor and maintenance costs.
4 percent of TCC.
Using a capital recovery factor of 0.09439 (7 percent interest for 20 years).
Total costs equal capital recovery costs plus O&M costs.
See text for factors that may increase fabric filter costs.
June 1996
B-21
SAB REVIEW DRAFT
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Table B-16
Cost Estimates for Applying a Carbon Injection System in
Conjunction with a Spray Cooler on a
975-MW Coal-Fired Utility Boiler (Model Ic)
Parameter
Unit Size (MW)
Flue Gas Flow (dscm/hr)
Air Pollution Control Device
Hg Level Before Injector (ng/dscm, 68°F)
Hg Level After Injection (ug/dscm, 68°F)
Capacity Factor (%)
CAPITAL COST (S)
Purchased Equipment (PE)
Installation
Indirect
Total Capital Cost (TCC)
OPERATING AND MAINTENANCE (O&M) (S/yr)
Operating Laborb
Supervision Labor0
Operating Materials
Maintenance Labord
Maintenance Materials6
Carbonf
Power8
Disposal11
Overhead1
Taxes. Insurance, Administration1
Capital Recovery1'
Total (S/yr)1
mills/kWh
Mercury Reduction (kg/yr)
Mercury Reduction (Ib/yr)
S/kg Mercury
SAb Mercury
Model Plant
975
4,050,000
ESPa
10
1
65
Cooling
2,993,796
1.017,891
1,347,208
5,358.894
25,920
3,888
219,572
19,008
19,008
958,363
—
40,694
214,356
505,826
2,006,635
0.36
•
—
9,668
4,393
Injection
109,448
16,417
32,835
158,700
25,920
3,888
—
14,256
14.256
129,488
185
4,288
34,992
6,348
14,980
248.601
0.04
—
—
1,198
544
Total
3.103,244
1,034.308
1,380.043
5,520,000
51,840
7,776
219.572
33.264
33,264
129.488
958,548
4,288
75.686
220,704
520,806
2.260.000
0.40
208
457
10,900
4.940
' ESP outlet temperature of 150°C, moisture content of 5 percent.
b $12/hr.
c 15 percent of operating labor.
d S13.20/hr.
* Same as maintenance labor.
' Based on Sl.lO/kg of carbon, plus 10 percent for shipping.
g Based on 46 mills/kWh.
h Based on a hazardous waste disposal rate of S33/Mg.
1 60 percent of labor and maintenance costs.
1 4 percent of TCC.
k Using a capital recovery factor of 0.09439 (7 percent interest for 20 years).
1 Total costs equal capital recovery costs plus O&M costs.
June 1996
B-22
SAB REVIEW DRAFT
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Table B-14 shows that the total capital cost for a 975-MW boiler controlled with a spray
cooler, activated carbon injection system and FF is $33,700,000, the annualized cost is $7,940,000/yr
and the cost effectiveness is $38,300/kg ($17,400/lb) of mercury. Table B-15 shows that the total
capital cost for a 100-MW boiler controlled with a spray cooler, activated carbon injection system and
FF is $4,560,000, the annualized cost is $l,300,000/yr and the cost effectiveness is $61,700/kg
($28,000/lb) of mercury.
Table B-16 presents the cost for the 975-MW ESP-equipped coal-fired boiler using activated
carbon injection in combination with spray cooling (model Ic). The activated carbon injection rate is
18.8 kg/hr (41 Ib/hr). The temperature after the spray cooler, where the carbon is injected, is 93°C
(200°F). The total capital cost for this control arrangement is $5,520,000, with 98 percent of the cost
contributed by the spray ccroler and 2 percent contributed by the activated carbon injection system.
The annualized cost is $2,390,000, with 88 percent of the cost contributed by the spray cooler and
12 percent contributed by the activated carbon injection system.
Injection systems installed on units without cooling the flue gas stream have much lower
capital investment costs than the more complex systems, but have increased annualized costs because
of high activated carbon usage. The units that reduce temperature after the paniculate control device
to reduce carbon usage must spend more money for capital equipment, primarily for added PM control
to capture the mercury-laden carbon. Their annualized costs are also increased because of operating
costs for the cooling and PM collection systems.
Table B-17 presents the results of a sensitivity analysis for mercury species in the flue gas
(elemental mercury vs mercuric chloride). As shown in the table, cost effectiveness as measured by
additional cost of producing electricity (mills/kWh) does not change significantly as the HgCl2 fraction
of total mercury decreases. This lack of change occurs for two reasons: less carbon is used for lower
amounts of HgCl2 and equipment costs are relatively insensitive to small changes in particle
concentration in the flue gas. However, cost effectiveness as measured by quantity removed from the
flue gas stream ($/lb of mercury), increases by a factor of about 3.3 in changing from 100 percent
HgCl2 to 30 percent HgCl2. This increase occurs because the costs of flue gas treatment decrease only
slightly while the quantity of collectible mercury decreases by 70 percent.
•
Table B-17
Sensitivity Analysis for Carbon Injection on Coal-Fired Utility
Boilers with Different Ratios of Elemental to Oxidized Mercury
Oxidized Mercury in Flue Gas
100% of Hg as HgCl2
80% of Hg as HgCl2
50% of Hg as HgCl2
30% of Hg as HgCl2
Cost Effectiveness $/lb Hg
Removed
4,970-27,700
6,190-34,600
9,840-55,400
16,300-92,000
Cost Effectiveness mills/kWh
0.41-2.26
0.41-2.26
0.40-2.25
0.40-2.25
For the models operating at 200 °F, the small amounts of carbon injected may be insufficient
for proper mixing with the gas stream. Table B-18 shows the results of a sensitivity analysis for
carbon feed rates at the amount used for estimating cost effectiveness (3.5 mg carbon/m3 of flue gas)
and a suggested value of 73 mg/m3. As shown in the table, increasing the carbon injection rate by a
June 1996
B-23
SAB REVIEW DRAFT
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factor of 20 increases the cost of operating the controls systems (mills/kWh) by about 400 to 120
percent depending on the model. Cost effectiveness values in $/lb of Hg removed increase by similar
percentages. The cost increases are caused by increased values for carbon usage and disposal. Carbon
injection system costs for the 100 MW boiler have relatively modest increases because a minimum
cost for the injection system is built into the model, i.e., the system will not cost less than about
$110,000 for any of the models.
Table B-18
Sensitivity Analysis for Carbon Injection
Feed Rates on Utility Boilers
Model
ob (975 MW)
Ic (975 MW)
2b (100 MW)
Feed Rate, mg
carbon/actual m3 flue
gas
3.5
73
3.5
73
3.5
73
Cost Effectiveness, $/lb
of Hg Removed
17,300
24,400
4,970
10,990
27,700
34,800
Cost Effectiveness,
mills/kWh
1.43
2.01
0.41
0.90
2.26
2.83
B.3.3 Carbon Filter Beds
Table B-19 presents the costs for applying the carbon filter bed to the two 975-MW boilers
(models Id and 2). As noted in Section 2.2.1.1, the size of the carbon filter bed is dependent on the
flue gas flow rate. The flow rate (on a wet basis) for the FGD-equipped model plant (model plant 2)
is slightly higher because of the higher moisture content of the flue gas from the FGD system.
Therefore, a slightly larger carbon filter bed was assumed. The carbon filter bed is assumed to reduce
the mercury in the flue gas to less than 1 ug/dscm (0.44 gr/million dscf) (Hartenstein, 1993a).
The total capital costs for the boilers are approximately $40,000,000 for the ESP-equipped
boiler and $44,000,000 for the ESP/FGD-equipped boiler. The total annualized costs for the two
plants are essentially equal, at about 3 mills/kWh. The cost per kilogram of mercury removed,
however, is different. For the ESP-equipped boiler, the cost is approximately $72,146/kg ($32,679/lb)
of mercury removed. For the ESP/FGD- equipped boiler, the cost is higher, at $187,615/kg
($37,769/lb) of mercury removed because of the lower mercury level. (Note that the cost estimates
were derived from retrofit costs, which can easily be 50 percent higher than new installation costs.)
June 1996
B-24
SAB REVIEW DRAFT
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Table B-19
Cost Estimates for a Carbon Filter Bed on Utility Boilers3
Parameter
Unit Size (MW)
Number of Units
Plant Size (MW)
Air Pollution Control Device
Flue Gas Flow (Nm3/hr @ 11% O, wet)
Flue Gas Flow (dscm/hr @ 7% O, wet)
Hg Level Before Filter (ug/dscm @ 7% O-,)
Hg Level After Filter (ug/dscm @ 7% O,)
Capacity Factor (%)
CAPITAL COST (S)
Purchased Equipment (PE)d
Installation2
Indirect
Contingency8
Total Capital Cost (TCC)
OPERATING AND MAINTENANCE (O&M) (S/yr)
Operating Labor11
Supervision Labor1
Maintenance Labor1
Maintenance Materials1'
Carbon1
Power™
Disposal"
Overhead0
Taxes, Insurance, Administration1*
Capital Recovery'
Total (S/yr)r
mills/kWh
Mercury Reduction (kg/yr)
Mercury Reduction (Ib/yr)
S/kg Mercury
S/lb Mercury
Model Id
975
1
975
ESP6
5,560.000
4.050.000
10
1
65
28.573,974
0
8,000,713
2.857,397
39.432,084
210,400
31,520
28.920
394,321
5,245,319
1,670.000
1,047.804
399,097
1.577,283
4.329,643
14,934,306
2.7
207
i 457
72,146
32,679
Model 2
975
1
975
ESP + FGDC
5,810.000
4.050.000
5
1
. 65
31,540.388
0
8.831.309
3.154,039
43,525.735
210,400
31.520
28.920
435.257
6,543,801
1,670,000
1,396.879
423,658
1,741,029
4,779.126
17.260.591
3.1
92
457
187,615
37.769
a Cost numbers may not add exactly due to round-off.
b ESP outlet temperature of 150°C, moisture content of 5 percent.
c FGD outlet temperature of 65°C, moisture content of 9 percent.
d Based on order of magnitude estimates for carbon usage.
5 Included in PE costs.
f 28 percent of PE costs.
8 10 percent of PE costs.
h 16 hr/shift @ $12/hr.
1 15 percent of operating labor costs.
1 2 hr/shift @ 10 percent wage rate premium over labor wage.
k 1 percent of TCC.
1 Based on Sl.lO/kg of carbon and 545 mg carbon/dscm.
m Using a 305-mm (water) pressure drop and 46 mills/kWh.
n Based on a hazardous waste disposal rate of S220/Mg.
0 60 percent of labor and maintenance costs.
p 4 percent of TCC:
q Using a capital recovery factor of 0.1098 (7 percent interest for 15 years).
r Total costs equal capital recovery costs plus O&M costs.
June 1996
B-25
SAB REVIEW DRAFT
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B.4 Chlor-Alkali Plants
B.4.1 Model Plant Description
One chlor-alkali model plant, which produces 273 Mg (300 tons) of chlorine per day, was
used for the cost analysis. This model plant represents the mid-range size of chlor-alkali plants in
operation (U.S. EPA, 1984). The model plant has individual flow rates from the hydrogen and
end-box streams of 4,080 dscm/hr (144,000 dscf/hr) each at 21 percent C>2 (combined to equal
8,160 dscm/hr [288,000 dscf/hr]) (U.S. EPA, 1973).
Baseline control systems for both streams consist of a heat exchanger to cool the effluent gas,
followed by a knockout drum to separate the condensed mercury from the hydrogen and end-box
streams. A mercury level of 1,000 g/day (2.2 Ib/day) after this baseline control is assumed for the
purpose of the cost analysis. This is consistent with federally mandated mercury standards for the
hydrogen and end-box streams at all chlor-alkali plants (U.S. EPA, 1984). The mercury control
options considered were conversion to the membrane cell process and control of the hydrogen and
end-box streams through the use of brine scrubbing and treated activated carbon adsorption. No
additional controls were examined for the cell room, since housekeeping practices are in use at all of
the plants (U.S. EPA, 1984). The different control options are discussed in the following sections.
B.4.2 Conversion to the Membrane Cell Process
Cost data on converting to the membrane cell process are limited. Estimates to convert a
mercury cell plant to a membrane cell operation vary between $110,000 and $220,000/Mg ($100,000
and $200,000/ton) of chlorine produced per day (Curlin, 1992). Representatives of the European
chlor-alkali industry cite higher costs on the order of $285,000/Mg ($260,000/ton) chlorine produced
per day (Euro-Chlor, 1993). Using the mid-point of the first cost range, the capital cost of conversion
for the 270-Mg/day (300-tpd) model plant would be on the order of $45 million. This is an
annualized cost of approximately $5 million/yr. For the conversion, the cost of cells and the
membranes accounts for 60 percent of the total investment (Curlin, 1992). Other costs include
additional brine treatment systems (i.e., the mercury removal system and ion-exchanger), the caustic
recycle and evaporization system and piping modifications«to the cell room (Horvath, 1986).
The operating cost differential between mercury and membrane cell plants is due to power
requirements. The energy consumption is estimated to be 3,500 to 4,000 kWh/Mg (3,200 to
3,600 kWh/ton) of chlorine for the mercury cell and 3,100 to 3,400 kWh/Mg (2,800 to 3,100 kWh/ton)
of chlorine for the membrane cell (Curlin, 1992).
Information on other operating costs was not available. Therefore, annualized costs and cost
effectiveness were calculated using only capital and electrical costs. If an estimated electricity savings
of 400 kWh/Mg (440 kWh/ton) of chlorine and an energy cost of 46 mills/kWh are assumed, the
energy savings is approximately $1,630,000. This is subtracted from the annualized capital cost,
leaving a net cost of $3,310,000, which is roughly equivalent to $43.5/Mg ($39.6/ton) of chlorine
produced. The cost effectiveness, assuming 1,000 g/day of mercury removed through conversion, is
approximately $10,100/kg ($4,590/lb) of mercury removed. For plants with mercury controls already
in place (e.g., effective cooling, carbon beds and scrubbing), the cost per kilogram of mercury
removed would be much higher. Additionally, local energy costs are a determining factor when
considering conversion from the mercury cell to the membrane cell process.
June 1996 B-26 SAB REVIEW DRAFT
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B.4.3 Hydrogen and End-Box Stream Controls
As noted, the two control options evaluated for these streams are depleted brine scrubbing and
treated activated carbon. Costs for secondary cooling and mist elimination are included in the cost
estimate, since these elements are necessary when employing both of the control options.
The capital and annual operating costs for the two control options are based on 1972
equipment cost estimates (U.S. EPA, 1973). The capital cost estimates were scaled to 1993 values
using chemical engineering plant cost indices (Chemical Engineering, 1972; Chemical Engineering,
1993). As a result of scaling the costs over such a long time period, there is a high level of
uncertainty associated with these costs.
Tables B-20 and B-21 present the capital and annualized costs for the depleted brine scrubbing
system and the treated activated carbon adsorption system, respectively. The capital cost for the
control equipment includes PE costs, installation, indirect costs-and contingency (U.S. EPA, 1973).
Installation costs equal PE costs, and indirect costs are 90 percent of PE costs. Contingency costs
equal 30 percent of PE costs (U.S. EPA, 1973). Based on these additional capital requirements, the
estimated total capital cost ranges from 320 to 380 percent of the equipment cost (U.S. EPA, 1973).
Operating and maintenance costs are assumed to be 30 percent of the total capital cost (U.S. EPA,
1973). For the depleted brine scrubbing system, the total capital cost for the secondary cooling, mist
elimination and scrubbing is approximately $1,620,000 for the combined hydrogen and end-box
streams. The total annualized cost, including O&M, is $662,000. This equals into $7.4/Mg ($6.7/ton)
of chlorine produced. Assuming a reduction in mercury to 90 jig/dscm (at 21 percent 62) (U.S. EPA,
1973), the cost effectiveness is $2,280/kg ($l,040/lb) of mercury removed.
For the carbon adsorption system on both streams, including secondary cooling and mist
elimination, the total capital cost is $1,222,000. The annualized cost including O&M is $500,000,
which equals $5.6/Mg ($5.I/ton) of chlorine produced. Assuming an outlet mercury concentration of
ID ug/dscm (at 21 percent ©2), the cost effectiveness is $l,690/kg ($769/lb) of mercury removed.
More information is needed on the current level of controls on mercury cell plants and their
respective emission levels to more accurately estimate the costs for these two technologies.
B.5 Primary Copper Smelters
B.5.1 Model Plant Description
The primary copper smelter model plant was selected from the model plants presented in the
background information document for primary copper, zinc and lead smelters (U.S. EPA, 1974). It
consists of a flash furnace and three Pierce-Smith converters. Off-gases from the furnace are
combined with the off-gas from the converters to form the feed to a single-stage acid plant. The feed
to the acid plant has a maximum How rate of 124,000 scm/hr (4,370,000 scf/hr).3
3 At 10.25 percent 02-
June 1996 B-27 SAB REVIEW DRAFT
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Table B-20
Cost Estimates for a Depleted Brine Scrubbing
on a Mercury Cell Chlor-Alkali Planta'b
Parameter
Unit Size (Mg/day)
Flue Gas Flue Hydrogen Stream (dscm/hr @ 21% O-,)
Flue Gas Flue End-Box Stream (dscm/hr @ 21% O,)
Total Flue Gas Flow (dscm/hr @ 21% O,)
Combined Hg Level Before Scrubbing (ug/dscm @ 21% O,)
Combined Hg Level After Scrubbing (ug/dscm @ 21% O,)c
Capacity Factor (%)
CAPITAL COST ($)d
Secondary Cooler
Chiller
Mist Eliminator
Depleted Brine Scrubber with Alkaline Scrubber
Total Capital Costs (TCC)
COMBINED ANNUAL OPERATING COSTS (S/yr)
Operating Costs8
Capital Recover/
Total (S/yr)8
S/Mg Chlorine
S/ton Chlorine
Mercury Reduction (kg/yr)
Mercury Reduction (Ib/yr)
S/kg Mercury
S/lb Mercury
Model Plant
273
4.080
4.080
8.160
4,600
90
90
Hydrogen Stream
117.000
165.000
133,000
425,000
839.000
—
—
—
...
—
End-Box Stream
106,000
165,000
120.000
386.000
777,000
—
...
—
Combined Stream
—
...
1.620.000
485.000
177.000
662.000
7.4
6.7
296
639
2.280
1.040
a Costs were scaled from 1972 dollars to 1993 dollars using chemical engineering plant cost indices.
b Cost numbers may not add exactly due to round-off. t
c Includes a 90 percent reduction by the cooling and mist elimination system.
d The fixed capital requirement for the control equipment includes purchase price (freight-on-board), installation and indirect
and contingency costs.
e 30 percent of TCC.
f Using a capital recovery factor of 0.1098 (7 percent interest rate for 15 years).
s Total costs equal capital recovery costs plus operating cost.
June 1996
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SAB REVIEW DRAFT
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Table B-21
Cost Estimates for Treated Activated Carbon Adsorption
on a Mercury Cell Chlor-Alkali Planta'b
Parameter
Unit Size (Mg/day)
Flue Gas Flue Hydrogen Stream (dscm/hr @ 21% O2)
Flue Gas Flue End-Box Stream (dscm/hr @ 21% O-,)
Total Flue Gas Flow (dscm/hr @ 21% O2)
Combined Hg Level Before Carbon (ng/d~scm @ 21% O2)
Combined Hg Level After Carbon (ug/dscm @ 21% O2)c
Capacity Factor (%)
CAPITAL COST (S)d
Secondary Cooler
Chiller
Mist Eliminator
Carbon Adsorption Bed
Total Capital Costs (TCC)
COMBINED ANNUAL OPERATING COSTS (S/yr)
Operating Costs6
Capital Recovery*
Total (S/yrt*
S/Mg Chlorine
S/ton Chlorine
Mercury Reduction (kg/yr)
Mercury Reduction (Ib/yr)
S/kg Mercury
S/lb Mercury
Model Plant
273
4.080
4.080
8,160
4.600
10
90
Hydrogen Stream
117.000
165.000
133.000
217,000
- 631,000
—
—
—
—
—
End-Box Stream
106,000
165.000
120,000
197,000
588,000
—
—
—
...
---
Combined Stream
1.222.000
366,000
134.000
500.000
5.6
5.1
296
650
1,690
769
a Costs were scaled from 1972 dollars to 1993 dollars using chemical engineering plant cost indices.
b Cost numbers may not add exactly due to round-off.
c Includes a 90 percent reduction by the cooling and mist elimination system.
d The fixed capital requirement for the control equipment includes purchase price (freight-on-board), installation and indirect
and contingency costs.
e 30 percent of TCC.
f Using a capital recovery factor of 0.1098 (7 percent interest rate for 15 years).
8 Total costs equal capital recovery cost plus operating cost.
June 1996
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SAB REVIEW DRAFT
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The plant has a capacity to process 910 Mg/day (1,000 tpd) of ore consisting of 27 percent
copper and 32 percent sulfur. This corresponds to a production capacity of 78,000 Mg/yr
(86,000 tons/yr) of copper. A capacity factor of 90 percent is assumed for this plant. This
corresponds to 236 Mg/day (260 tpd) copper production capacity. The cost of applying selenium
filters on the stream entering the acid plant is evaluated below.
B.5.2 Selenium Filters
Table B-22 presents the cost estimate for applying three selenium filters to the flue gas stream
upstream of the acid plant. Individual filters can handle flows up to 53,500 scm/hr (1,890,000 scf/hr)
(Edlund, 1993b),4 and since the flow to the acid plant is 124,000 scm/hr (4,370,000 scf/hr), three
selenium filters are needed with flows to each of 41,200 scm/hr. There are no data available on the
mercury level upstream of the acid plant. For the purpose of this cost estimate, a mercury level of
1,000 ug/scm (436 gr/million scf) is assumed. Ninety percent reduction across the filter is assumed, so
that the mercury outlet level is 100 ug/scm (44 gr/million scf). Vendor-quoted removal is typically
between 95 and 99 percent, but in this case the 90 percent assumption was cited by the vendor since
more detailed information on the mercury content of the stream was not available (Edlund, 1993c).
The PE cost (covering all three filters) is estimated at $2,050,000 (Edlund, 1993b). This is a
freight-on-board (FOB) cost and does not include installation and transportation. Information on the
cost of installation was not available; it was assumed to be 30 percent of the PE cost (which includes
transportation). The vendor indicated that erection of the filter is relatively simple (Edlund, 1993c).
The vessel is delivered in one main piece (the hull), along with the top hatch and the baskets
containing the selenium mass. A mobile crane places the baskets into the vessel and lifts the top hatch
in place. The tie-in of the filter to existing duct work takes 1 to 2 days (Edlund, 1993c).
Indirect and contingency costs are based on the MWC cost procedures for SD/FF and DSI
systems (U.S. EPA, 1989b). The total capital cost is estimated to be $4,260,000.
According to the vendor, there are no labor costs associated with the filter. The filter may
require periodic cleaning if the dust content is high. For cleaning, the baskets must be removed and
the selenium mass is cleaned with water. Afterwards, the baskets are replaced in the vessel. It may
be necessary to add filter mass (approximately 5 percent) after the cleaning (Edlund, 1993c). To
account for periodic cleaning, 40 hours of maintenance labor are included. Costs for additional filter
mass are not included, but costs for refilling the filter mass at the end of the filter life (approximately
every 5 years in the model plant case) are included. Costs for refilling are 50 percent of the original
filter cost (Edlund,- 1993b). These costs have been annualized over the life of the filter, which is
calculated assuming 50 kg (110 Ib) of elemental mercury is captured per cubic meter (cubic foot) of
the filter mass (Edlund, 1993b). The mercury content in the flue gas directly impacts filter life and,
thereby, affects the economics of this technology.
Overhead and taxes, insurance and administrative costs are based on the MWC cost procedures
(U.S. EPA, 1989b). A CRF of 0.1098 (7 percent over 15 years) was used to annualize the capital
costs.
4 Oxygen level not specified.
June 1996 B-30 SAB REVIEW DRAFT
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Table B-22
Cost Estimates for Selenium Filters on a Copper Smelting Plant3
Parameter
Production Capacity (Mg/day)b
Flue Gas Flow (scm/hr @ 10% O2)
Number of Filters
Flow Thru Each Filter (scm/hr)
Individual Filter Mass (m-h
Hg Level Before Filter (|jg/scm)
Hg Level After Filter (jag/scm)
Capacity Factor (%)
CAPITAL COST (5)
Purchased Equipment (PE)°
Installation
Indirect*
Contingency*
Total Capital Cost (TCC)
OPERATING AND MAINTENANCE (O&M) COST (S/yr)
Operating Labor8
Maintenance Labor11
Maintenance Materials1
Power1
Disposal1
Overhead1
Taxes, Insurance, Administration™
Capital Recovery"
Total (S/yr)°
S/Mg Copper
S/ton Copper
Mercury Reduction (kg/yr)
Mercury Reduction (Ib/yr)
Filter Capability (kg of Hg)
Filter Capability (Ib of Hg)
Filter Life (yr) *
S/kg Mercury
S/lb Mercury
Model Plant
236
124.000
3
41,200
30
1.000
100
90
2,050.000
616.000
881,000
710.000
4.260.000
0
1,580
248,000
30.700
6,200
150,000
170,000
355.000
961.000
12.4
11.3
879
1,930
4,450
9,790
5.1
1,094
497
Cost numbers may not add exactly due to round-off.
Production capacity of copper.
Based on $800.000 FOB cost for a 53,500 scm/hr filter scaled based on 0.6 rule; $400,000 associated with initial filter mass.
30 percent of PE costs.
33 percent of PE and installation costs.
20 percent of direct and indirect costs.
No labor required.
For yearly filter cleaning; 40 hours/yr @ $13.2/hr.
For replacing filter mass (annualized over life of filter).
Using 50-mm pressure drop (water) and 46 mills/kWh.
Assuming 1.600 kg/m of filter mass and disposal of S220/Mg.
60 percent of labor and maintenance costs.
4 percent of TCC.
Using a capital recovery factor of 0.1098 (7 percent interest for 15 years) applied to TCC excluding initial filter mass cost.
Total costs equal capital recovery cost plus O&M costs.
June 1996
B-31
SAB REVIEW DRAFT
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The annualized cost for the copper model plant is $12.4/Mg ($11.3/ton) of copper produced.
With the assumed mercury concentrations, this cost equals $l,094/kg ($497/lb) of mercury removed.
Actual mercury emission data are necessary to provide a more realistic cost evaluation of this
technology. Table B-23 presents a sensitivity analysis of the effect of mercury inlet level on the costs
associated with the selenium filters. At a mercury inlet of 5,000 ug/scm (2,180 gr/million scf), the
filter life decreases to 1 year. As a result, the annualized cost increases to $30/Mg ($27/ton) of copper
produced. The cost effectiveness value, however, improves to $529/kg ($240/lb) of mercury removed
because of the additional mercury collected annually. At an inlet of 10,000 |ag/scm (4,360 gr/million
scf), filter life decreases to 0.5 years, the annualized cost increases to $52/Mg ($47/ton) of copper and
the cost effectiveness value improves to $459/kg ($209/lb) of mercury removed.
Table B-23
Sensitivity Analysis for Selenium Filters
on a Copper Smelting Plant
Operating Assumptions
Base Case (Table B-20)
Inlet Hg Levela
5,000 ug/dscm
10,000 ng/dscm
Installation Cost
50% of Purchased Equipment
75% of Purchased Equipment
$/Mg Copper
12.4
29.9
51.9
13.6
15.2
$/kg Hg
1,090
529
459
1,210
1,350
A mercury reduction of 90 percent is assumed for all cases.
Because of the lack of information on installation costs for selenium filters, the impact of the
30 percent of PE. assumption was examined in a sensitivity analysis also. As shown in Table B-23,
increasing the installation cost to 50 percent and 75 percent of PE costs has a relatively small impact
on the annualized costs (increasing to $13.6/Mg [$12.4/ton] and $15.2/Mg [$13.8/ton] of copper,
respectively). Cost effectiveness values increase to $l,210/kg ($550/pound) and $l,350/kg
($614/pound), respectively.
B.6 Primary Lead Smelters
B.6.1 Model Plant Description
The primary lead smelter model plant was selected from a U.S. EPA document on this
industry (U.S. EPA, 1974). The model plant consists of a sintering machine, which feeds to a blast
furnace and a dross furnace. The sintering machine is an updraft machine, which does not employ
recirculation of the weak gas. Therefore, there are two off-gas streams, one strong SC>2 stream and
one weak SC>2 stream. The strong stream is fed to a single-stage acid plant at a flow rate of
June 1996
B-32
SAB REVIEW DRAFT
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31,600 scm/hr (1,120,000 scf/hr);5 the weak stream, with a flow rate of 138,000 scm/hr
(4,860,000 scf/hr),6 is sent to an FF for paniculate control and emitted to the atmosphere. The
off-gases from the dross furnace are fed to an FF, at a flow rate of 72,200 scm/hr (2,550,000 scf/hr)7
for PM control and emitted to the atmosphere. The lead production capacity for this facility is
90,900 Mg/yr (100,000 tons/yr) from concentrate containing 55 percent lead and 16 percent sulfur.
The plant is assumed to operate 90 percent of the year. This corresponds to a daily capacity of
276 Mg/day (304 tpd).
Cost estimates are provided below for applying selenium filters on the sintering stream leading
to the acid plant and on the blast and dross furnace flue gas stream (after the FF).
B.6.2 Selenium Filters
Tables B-24 and B-25 present the costs for applying selenium filters to the sintering flue gas
stream upstream of the acid plant and the combined furnace flue gas stream after the FF, respectively.
These streams are assumed to contain higher levels of mercury emissions than those from other plant
processes because of the high temperatures in the sintering and furnace operations (U.S. EPA, 1994).
For the sintering stream (Table B-24), only one filter is required. There are no data on the
mercury levels in this stream, so for the purpose of this estimate, 1,000 ug/scm (436 gr/million scf) is
assumed. A 90 percent mercury reduction to 100 ug/scm (44 gr/million scf) is assumed (Edlund,
1993c).
The cost assumptions for applying the filter to this stream are the same as those discussed in
Section B.5.2. The total capital costs are $1,210,000 and the annualized costs are $266,000/yr. This
equals $3.0/Mg ($2.7/ton) of lead produced and a cost effectiveness of $l,190/kg ($541/lb) of mercury
removed. As with the copper smelter, emissions data are needed to determine actual costs of applying
this technology.
For the furnace flue gas stream following the FF (Table B-23), two filters are required.
Because data were not available on mercury emissions, 1,000 ug/scm (435 gr/million scf)8 was
assumed, with an outlet of 100 ug/scm (44 gr/million scf).*
The total capital cost for applying the filters to this stream is $2,620,000 and the annualized
costs are 584,000/yr. This equals $6.4/Mg ($5.8/ton) of lead produced. Cost effectiveness is
$l,140/kg ($520/lb) of mercury removed. Again, emissions data are needed to accurately reflect the
costs of applying this control technology.
5 At 12 percent (>>.
6 Oxygen level not specified.
7 At 19 percent O2.
8 At 19 percent C^-
June 1996 B-33 SAB REVIEW DRAFT
-------
Table B-24
Cost Estimate for a Selenium Filter
on a Lead Smelting Plant (Sintering Stream)3
Parameter
Production Capacity (Mg/day)b
Flue Gas Flow (scm/hr @ 10% O,)
Number of Filters
Flow Thru Each Filter (scm/hr)
Individual Filter Mass (m^)
Hg Level Before Filter (ng/scm)
Hg Level After Filter (ng/scm)
Capacity Factor (%)
CAPITAL COST (SI
Purchased Equipment (PE)C
Installation11
Indirect*
Contingencyf
Total Capital Cost (TCC)
OPERATING AND MAINTENANCE (O&M) COST (S/yr)
Operating Labor8
Maintenance Labor*1
Maintenance Materials'
Power1
Disposal*
Overhead
Taxes, Insurance. Administration111
Capital Recovery"
Total (S/yr)°
S/Mg Lead
S/ton Lead
Mercury Reduction (kg/yr)
Mercury Reduction (Ib/yr)
Filter Capability (kg of Hg)
Filter Capability (Ib of Hg) '
Filter Life (yr)
S/kg Mercury
S/lb Mercury
Model Plant
276
31,500
1
31.500
23
1.000
100
90
583.000
175.000
250,000
201.000
1.210.000
0
528
70.200
2.610
1.580
42.500
48.300
101.000
266.000
3.0
2,7
224
493
1.130
2,500
5.1
1,190
541
f
Cost numbers may not add exactly due to round-off.
Production capacity of copper.
Based on 5800,000 FOB cost for a 53,500 scm/hr filter scaled based on 0.6 rule; $400,000 associated with initial filter mass.
30 percent of PE costs.
33 percent of PE and installation costs.
20 percent of direct and indirect costs.
No labor required.
h For yearly filter cleaning; 40 hr/yr @ S13.2/hr.
1 For replacing filter mass (annualized over life of filter).
j
Using 50-mm pressure drop (water) and 46 rmlls/kWh.
Assuming 1,600 kg/m of filter mass and disposal of $220/Mg.
60 percent of labor and maintenance costs.
4 percent of TCC.
Using a capital recovery factor of 0.1098 (7 percent interest for 15 years) applied to TCC excluding initial filter mass cost.
Total costs equal capital recovery cost plus O&M cost.
June 1996
B-34
SAB REVIEW DRAFT
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Table B-25
Cost Estimate for a Selenium Filter
on a Lead Smelting Plant (Furnace Stream)"
Parameter
Production Capacity (Mg/day)b
Flue Gas Flow (scm/hr @ 10% O2)
Number of Filters
Flow Thru Each Filter (scm/hr)
Individual Filter Mass (m^)
Hg Level Before Filter (ug/scm)
Hg Level After Filter (ng/scm)
Capacity Factor (%)
CAPITAL COST (S)
Purchased Equipment (PE)C
Installation*1
Indirect6
Contingency^
Total Capital Cost (TCC)
OPERATING AND MAINTENANCE (O&M) COST (S/yr)
Operating Labor8
Maintenance Labor11
Maintenance Materials'
Power1
Disposal
Overhead1
Taxes, Insurance, Administration01
Capital Recovery0
Total (S/yr)°
S/Mg Lead
S/ton Lead
Mercury Reduction (kg/yr)
Mercury Reduction (Ib/yr) •
Filter Capability (kg of Hg)
Filter Capability (Ib of Hg)
Filter Life (yr)
S/kg Mercury
S/lb Mercury
Model Plant
276
72,000
2
36,000
26
1.000
100
90
1,260,000
379.000
541,000
436.000
2.620.000
0
1.060
152.000
11,900
3.600
92,000
105.000
218,000
584.000
6.4
5.8
512
1.130
2.590
5.700
5.1
1.140
520
a Cost numbers may not add exactly due to round-off.
Production capacity of lead.
c Based on 5800,000 FOB cost for a 53,500 scm/hr filter scaled based on 0.6 rule; $400,000 associated with initial filter mass.
d 30 percent of PE costs.
e 33 percent of PE and installation costs.
20 percent of direct and indirect costs.
s No labor required.
h For yearly filter cleaning; 40 hr/yr @ S13.2/hr.
1 For replacing filter mass (annualized over life of filter).
1 Using 50-mm pressure drop (water) and 46 mills/kWh.
k Assuming 1,600 kg/nr of filter mass and disposal of S220/Mg.
1 60 percent of labor and maintenance costs.
m 4 percent of TCC.
n Using a capital recovery factor of 0.1098 (7 percent interest for 15 years) applied to TCC excluding initial filter mass cost.
° Total costs equal capital recovery cost plus O&M costs.
June 1996
B-35
SAB REVIEW DRAFT
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Tables B-26 and B-27 present the sensitivity analyses examining the impact of mercury inlet
levels on costs arid the impact of installation cost assumptions on costs. As with the copper smelter
sensitivity analysis, increased mercury levels increase the annualized costs but decrease the cost per
kilogram of mercury removed. The effect of varying installation cost assumptions is also similar.
June 1996 * B-36 SAB REVIEW DRAFT
-------
Table B-26
Sensitivity Analysis for Selenium Filters
on a Lead Smelter Sintering Stream
Operating Assumptions
Base Case (Table B-22)
Inlet Hg Level3
5,000 ug/dscm
10,000 ug/dscm
Installation Cost
50% of Purchased Equipment .
75% of Purchased Equipment
$/Mg Lead
3.0
7.2
12.5
3.2
3.6
$/kg Hg
1,190
583
508
1,320
1,470
A mercury reduction of 90 percent is assumed for all cases.
Table B-27
Sensitivity Analysis for Selenium Filters
on a Lead Smelter Furnace Stream
Operating Assumptions
Base Case (Table B-23)
Inlet Hg Levela
5,000* ug/dscm
10,000 ug/dscm
Installation Cost
50% of Purchased Equipment
75% of Purchased Equipment
$/Mg Lead
6.4
15.6
27.2
7.1
7.9
$/kg Hg
1,140
556
483
1,260
1.470
A mercury reduction of 90 percent is assumed for all cases.
June 1996
B-37
SAB REVIEW DRAFT
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TECHNICAL REPORT DATA
(Please read Instructions on reverse before completing)
[.REPORT NO.
EPA-452/R-96-001g
3. RECIPIENTS ACCESSION NO.
4. TITLE AND SUBTITLE
Mercury Study Report to Congress. Draft Submitted to U.S.
EPA's Science Advisory Board. Volume VII. An Evaluation
Mercury Control Technologies and Costs.
5. REPORT DATE
1996
of
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
Ms. Martha H. Keating
9. PERFORMING ORGANIZATION NAME AND ADDRESS
U.S. Environmental Protection Agency
Office of Air Quality Planning and Standards
Research Triangle Park, NC 27711
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
12. SPONSORING AGENCY NAME AND ADDRESS
Director
Office of Air Quality Planning and Standards
Office of Air and Radiation
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Draft. June, 1996.
14. SPONSORING AGENCY CODE
EPA/200/04
15. SUPPLEMENTARY NOTES
U.S. EPA Project Officer: Martha H. Keating
16. ABSTRACT
This volume of the draft Mercury Study Report to Congress focuses on mercury control technologies, costs,
and financial impact estimates for six industries: municipal waste combustors, medical waste incinerators,
utility boilers, chlor-alkali plants, primary copper smelters, and primary lead smelters. Control technologies
reviewed for feasibility are pollution prevention measures (including product substitution and process
modification), materials separation, and flue gas treatment methods. The estimated cost effectiveness values
represent generalized costs and are not intended to be site-specific. Analysis of Clean Air Act Authorities that
could be used to control mercury emission sources are summarized. Specific technological approaches to
limiting mercury emissions for these six industries are described along with data needed to improve these
assessments.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b. IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Mercury; Methylmercury; Clean Air Act; Control
technology; Air pollutants, environmental; Water
pollutants, chemical; Indirect exposure.
Air Pollution Control
18. DISTRIBUTION STATEMENT
Release Unlimited
19. SECURITY CLASS (Report)
Unclassified
21. NO OF PAGES
154pp.
20. SECURITY CLASS (Page)
Unclassified
22. PRICE
EPA Form 2220-1 (Rev. 4-77)
PREVIOUS EDITION IS OBSOLETE
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