EPA-600/R-00-083
9000
x>EPA Research and
Development
PERFORMANCE AND COST OF
MERCURY EMISSION CONTROL
TECHNOLOGY APPLICATIONS ON
ELECTRIC UTILITY BOILERS
Prepared for
Office of Air and Radiation
Prepared by
National Risk Management
Research Laboratory
Research Triangle Park, NC 27711
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FOREWORD
The U. S. Environmental Protection Agency is charged by Congress with pro-
tecting the Nation's land, air, and water resources. Under a mandate of national
environmental laws, the Agency strives to formulate and implement actions lead-
ing to a compatible balance between human activities and the ability of natural
systems to support and nurture life. To meet this mandate, EPA's research
program is providing data and technical support for solving environmental pro-
blems today and building a science knowledge base necessary to manage our eco-
logical resources wisely, understand how pollutants affect our health, and pre-
vent or reduce environmental risks in the future.
The National Risk Management Research Laboratory is the Agency's center for
investigation of technological and management approaches for reducing risks
from threats to human health and the environment. The focus of the Laboratory's
research program is on methods for the prevention and control of pollution to air,
land, water, and subsurface resources, protection of water quality in public water
systems; remediation of contaminated sites and-groundwater; and prevention and
control of indoor air pollution. The goal of this research effort is to catalyze
development and implementation of innovative, cost-effective environmental
technologies; develop scientific and engineering information needed by EPA to
support regulatory and policy decisions; and provide technical support and infor-
mation transfer to ensure effective implementation of environmental regulations
and strategies.
This publication has been produced as part of the Laboratory's strategic long-
term research plan. It is published and made available by EPA's Office of Re-
search and Development to assist the user community and to link researchers
with their clients.
E. Timothy Oppelt, Director
National Risk Management Research Laboratory
EPA REVIEW NOTICE
This report has been peer and administratively reviewed by the U.S. Environmental
Protection Agency, and approved for publication. Mention of trade names or
commercial products does not constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Information Service,
Springfield, Virginia 22161.
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EPA-600/R-00-083
September 2000
Performance and Cost of Mercury Emission
Control Technology Applications on Electric
Utility Boilers
Prepared by:
Ravi K. Srivastava, Charles B. Sedman, and James D. Kilgroe
U.S. Environmental Protection Agency
Office of Research and Development
National Risk Management Research Laboratory
Research Triangle Park, NC 27711
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ABSTRACT
Under the Clean Air Act Amendments of 1990, the Environmental Protection Agency (EPA) has
to determine whether mercury emissions from coal-fired power plants should be regulated. To
aid in this determination, estimates of the performance and cost of powdered activated carbon
(PAC) injection-based mercury control technologies have been developed. This report presents
these estimates and develops projections of costs for future applications.
Estimates based on currently available data using PAC range from 0.305 to 3.783 mills/kWh.
However, the higher costs are associated with the minority of plants using hot-side electrostatic
precipitators (HESPs). If these costs are excluded, the estimates range from 0.305 to 1.915
mills/kWh. Cost projections, developed based on using a composite lime-PAC sorbent for
mercury removal, range from 0.183 to 2.270 mills/kWh with the higher costs being associated
with the minority of plants using HESPs.
A comparison of mercury control costs with those of nitrogen oxides (NOX) controls reveals that
total annual costs for mercury controls lie mostly between applicable costs for low NOX burners
(LNBs) and selective catalytic reduction (SCR). As mentioned above, estimates of total annual
cost are higher for cases that are applicable to the minority of plants using HESPs. Excluding
these costs, both currently estimated and projected mercury control costs are in the spectrum of
LNB and SCR costs.
The performance and cost estimates of the PAC injection-based mercury control technologies
presented in this report are based on relatively few data points from pilot-scale tests and,
therefore, are considered to be preliminary. Factors that are known to affect the adsorption of
mercury on PAC or other sorbent include the speciation of mercury in flue gas, the effect of flue
gas and ash characteristics, and the degree of mixing between flue gas and sorbent. This mixing
may be especially important where sorbent has to be injected in relatively large ducts. The effect
of these factors may not be entirely accounted for in the relatively few pilot-scale data points that
comprised the basis for this work. Ongoing research is expected to address these issues and to
improve the cost effectiveness of using sorbents for mercury control. Further research is also
needed on ash and sorbent residue to evaluate mercury retention and the potential for release
back into the environment.
ACKNOWLEDGEMENTS
The authors thank Dennis Smith and Scott Renninger of DOE's National Energy Technology
Laboratory for their support and insights that led to successful completion of this work. The
authors also acknowledge the invaluable contributions of Jay Ratafia-Brown of Science
Applications International Corporation and Mike Birkenpass of Carnegie Mellon University.
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Contents
Abstract ii
Acknowledgements ii
List of Figures iv
List of Tables iv
List of Acronyms and Abbreviations v
1.0 Introduction 1
2.0 Mercury Speciation and Capture 2
3.0 Mercury Control Technology Applications 3
3.1 PAC Injection-based Technologies 3
3.2 PAC Injection Rates 5
3.3 Model Plants 6
4.0 Costs of Reducing Mercury Emissions 7
4.1 NETL Mercury Control Cost Model 8
4.2 Cost Model Results 8
4.3 Cost Impacts of Selected Variables 15
4.4 Cost Indications for Other Model Plants 19
4.5 Summary of Mercury Control Costs and Proj ections for Future Applications 20
4.6 Comparison of Mercury andNOxControl Costs 22
5.0 Summary 22
6.0 References 24
Appendix: Assessment of mercury control options for coal-fired power
plants (U.S.DOE) A-i
in
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List of Figures
1. Change in total annual cost resulting from addition of ductwork to provide additional
residence time 18
2. Change in total annual cost resulting from use of a composite PAC-time sorbent
instead of PAC 19
List of Tables
1. Mercury control technologies for coal-fired electric utility boilers 4
2. Mercury control technology applications and cobenefits 7
3. Mercury control and costs for boilers firing bituminous coals and utilizing
ESPs 11
4. Mercury control options and costs for boilers firing subbituminous coals and
utilizing ESPs 13
5. Mercury control costs for boilers firing subbituminous coals and
utilizing FFs 14
6. Mercury control costs for boilers using SCRs 14
7. Impact on mercury control costs resulting from increase in approach to
ADP and recycling of sorbent for boilers firing bituminous coals and
utilizing ESPs 16
8. Impact on mercury control costs resulting from increase in approach to
ADP and recycling of sorbent for boilers firing subbituminous coals and
utilizing ESPs 17
9. Impact on mercury control costs resulting from increase in approach to
ADP for boilers firing subbituminous coals and FFs 17
10. Mercury control technology application cost estimates based on currently
available data and projections for future 21
11. Comparison of mercury control costs with NOX control costs 22
IV
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List of Acronyms and Abbreviations
ADP Acid Dew Point
CAAA Clean Air Act Amendments of 1990
EPA United States Environmental Protection Agency
ESP Electrostatic Precipitator
FF Fabric Filter
FGD Flue Gas Desulfurization
HC1 Hydrogen Chloride
HESP Hot-side Electrostatic Precipitator
Hg Mercury
HgCb Mercuric Chloride
Hg° Elemental Mercury
Hg++ Ionic Mercury
HgO Mercury Oxide
HgSO4 Mercury Sulfate
ICR Information Collection Request
IPM Integrated Planning Model
kWh Kilowatt Hour
LNB Low NOX Burner
MW Megawatt
MWCs Municipal Waste Combustors
NETL National Energy Technology Laboratory
NOX Nitrogen Oxides
OAR EPA's Office of Air and Radiation
O&M Operation and Maintenance
PAC Powdered Activated Carbon
PFF Polishing Fabric Filter
PM Parti cul ate Matter
R&D Research and Development
SC Spray Cooling
SCR Selective Catalytic Reduction
SD Spray Dryer
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SNCR Selective Noncatalytic Reduction
SO2 Sulfur Dioxide
VI
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1.0 INTRODUCTION
Since mercury is an element, it cannot be created or destroyed. In the atmosphere, mercury exists
in two forms: elemental mercury vapor (Hg°) and ionic mercury (Hg++). Hg° can circulate in the
atmosphere for up to 1 year and, consequently, can undergo dispersion over regional and global
scales. Hg++ in the atmosphere either is bound to airborne particles or exists in gaseous form.
This form of mercury is readily removed from the atmosphere by wet and dry deposition. After
deposition, mercury is commonly re-emitted back to the atmosphere as either a gas or a
constituent of particles and redeposited elsewhere. In this fashion, mercury cycles in the
environment.1
A number of human health and environmental impacts are associated with exposure to mercury.
Mercury is known to bioaccumulate in fish and animal tissue in its most toxic form,
methylmercury. Human exposure to methylmercury has been associated with serious
neurological and developmental effects. Adults exposed to methylmercury show symptoms of
tremors, loss of coordination, and memory and sensory difficulties. Offspring exposed during
pregnancy show atrophy of the brain with delayed mental development. The incidence and extent
of such effects depend on the level of exposure to methylmercury. Hg°is readily absorbed
through lungs and, being fat-soluble, is rapidly distributed throughout the body. Subsequently, it
slowly oxidizes to Hg++, which accumulates in the brain and can lead to tremors, memory
disturbances, sensory loss, and personality changes. Hg++ is absorbed through the digestive tract,
accumulates in the kidneys, and can lead to immune-mediated kidney toxicity. Adverse effects of
mercury on fish, birds, and mammals include reduced reproductive success, impaired growth,
behavioral abnormalities, and even death. Details of the risks associated with exposure to
mercury are discussed in the literature.1 A severe case of human exposure occurred in Minamata,
Japan in the 1950s.2
Under the Clean Air Act Amendments of 1990, the Environmental Protection Agency (EPA) has
to determine whether mercury emissions from coal-fired power plants should be regulated.3 To
aid in this determination, this report presents preliminary estimates of the performance and cost
of promising mercury control technologies applicable to coal-fired electric utility boilers. As
explained later in this report, most of these technologies are based on injection of powdered
activated carbon (PAC) into boiler flue gas.
The report layout is as follows. First, promising mercury control technologies for coal-fired
electric utility boilers are identified. Second, performance characteristics of these technologies
are estimated. These include characterization of mercury removal performance possible as a
function of PAC injection rate. Third, model plants representing the spectrum of retrofit
possibilities are identified. Next, costs of controlling mercury emissions from these model plants
are examined. Finally, potential future improvements in these costs are discussed. During
discussion of cost and potential improvements, research and development (R&D) areas are
identified for near-term emphasis.
The performance and cost estimates of the PAC injection-based mercury control technologies
presented in this report are based on relatively few data points from pilot-scale tests and,
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therefore, are considered to be preliminary. Factors that are known to affect the adsorption of
mercury on PAC or other sorbent include the speciation of mercury in flue gas, the effect of flue
gas and ash characteristics, and the degree of mixing between flue gas and sorbent. This mixing
may be especially important where sorbent has to be injected in relatively large ducts. The effect
of these factors may not be entirely accounted for in the relatively few pilot-scale data points that
comprised the basis for this work. Ongoing research is expected to address these issues and to
improve the cost effectiveness of using sorbents for mercury control.
Use of sorbent injection technologies to control mercury emissions from electric power plants
would result in mercury-impregnated sorbent waste, which would need to be disposed off either
by itself or in mixture with flyash. One of the more commonly practiced solid waste disposal
options is landfilling. However, information is not currently available on the stability of mercury
in ash and sorbent residue. Therefore, it is unclear whether any potential exists for the release of
mercury back into the environment from landfilled mercury-impregnated solid waste. Further
research is needed on ash and sorbent residue to evaluate mercury retention and the potential for
release back into the environment. Due to lack of information, this report does not address any
potential costs that may result if mercury has to be stabilized in sorbent waste.
2.0 MERCURY SPECIATION AND CAPTURE
Mercury is volatilized and converted to Hg° in the high temperature regions of combustion
devices. As the flue gas cools, Hg° is oxidized to Hg++. The rate of oxidization is dependent on
the temperature, flue gas composition and properties, and amount of flyash and any entrained
sorbents. In coal-fired combustors, where the concentrations of hydrogen chloride (HC1) are low,
and where equilibrium conditions are not achieved, Hg° may be oxidized to mercuric oxide
(HgO), mercuric sulfate (HgSO4), mercuric chloride (HgCb), or some other mercury compound.4
The oxidization of Hg° to HgCb and to other ionic forms of mercury is abetted by catalytic
reactions on the surface of flyash or sorbents and by other compounds that may be present in the
flue gas. Consequently, applications of nitrogen oxides (NOX) control technologies such as
selective catalytic reduction (SCR) and selective noncatalytic reduction (SNCR) may assist in
oxidation of Hg°.
Hg°, HgCb, and HgO are primarily in the vapor phase at flue gas cleaning temperatures.
Therefore, each of these forms of mercury can potentially be adsorbed onto porous solids such as
flyash, PAC, and calcium-based acid gas sorbents for subsequent collection in a particulate
matter (PM) control device. These mercury forms may also be captured in carbon bed filters or
other reactors containing appropriate sorbents.
Mercury removal with wet scrubbers also appears to be possible. HgCb is water-soluble and
reacts readily with alkali metal oxides in an acid-base reaction; therefore, conventional acid gas
scrubbers used for sulfur dioxide (802) control can also effectively capture HgC^. The total
mercury removal efficiency of wet scrubbers has been reported to range from 30 to 90%.5
However, Hg° is insoluble in water and must be adsorbed onto a sorbent, or converted to a
soluble form of mercury that can be collected by wet scrubbing. HgO has low solubility and
probably has to be collected by methods similar to those used for Hg°.
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3.0 MERCURY CONTROL TECHNOLOGY APPLICATIONS
Based on published literature,1'5"9 control technologies using injection of PAC into the flue gas
appear to hold promise for reducing mercury emissions from utility boilers. These technologies
have been applied successfully on municipal waste combustors (MWCs). Also, pilot-scale tests
indicate that these technologies may be able to provide significant mercury removal from the flue
gas of coal-fired utility boilers. Accordingly, this evaluation focused on characterization of
performance and total annual cost of PAC injection-based technologies.
This section describes PAC injection-based control technologies that can be retrofitted to
existing boilers for control of mercury emissions, PAC injection estimates for these technologies,
and model plants used in this work. Subsequently, control technology applications on model
plants are used to develop estimates of total annual costs.
3.1 PAC Injection-Based Technologies
Table 1 lists the PAC injection-based technologies evaluated in this work. Pilot-scale
applications of most of these technologies have been reported in published literature. The table
gives technology names, corresponding components, and existing equipment to which these
retrofit technologies are applied. The current understanding is that particle-bound mercury is
well collected in PM or SC>2 control systems, Hg° is not so well collected, and Hg++ is collected
to a greater or lesser degree depending on characteristics of the control device and conditions
within it. Therefore, for a specified mercury removal requirement, the rate of PAC injection
needed will depend, in part, on the ability of existing controls to remove the three species of
mercury.
In ESP-1, PAC is injected between the air preheater and the cold-side ESP (i.e., an ESP located
downstream of the boiler's air preheater). This technology is relatively simple and lower in
capital cost compared to more complex technologies. Activated carbon consumption is expected
to be relatively high because the high temperature of the flue gas inhibits adsorption of mercury
onto PAC. Increased carbon consumption would lead to higher total annual costs.
In ESP-3, PAC is injected downstream of the cold-side ESP and is collected using a polishing
fabric filter (PFF). This technology permits recycling of the PAC sorbent to increase its
utilization. Typically, this recycling is achieved by transferring a portion of used sorbent from
the PM control device (e.g., PFF) to the sorbent injection location using a chain or a belt
conveyor, mixing the used sorbent with fresh sorbent, and injecting the resulting sorbent mixture
into the flue gas. Further, the technology provides a contact bed (i.e., filter cake on PFF) for
increased adsorption of mercury. Capital and total annual costs are expected to be higher than for
ESP-1 because of more equipment and supplies (primarily bags), but carbon cost may be lower.
ESP-4 is similar to ESP-1, but adds spray cooling (SC) upstream of the PAC injection location.
Cooling the flue gas aids adsorption and reduces PAC injection requirements. As with ESP-3,
capital costs are increased over ESP-1 because of added SC equipment, but total annual costs
may be decreased because PAC requirements are significantly reduced. Adding too much water
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to the flue gas could cause acid condensation, which would tend to corrode ductwork and
equipment. For cost modeling, flue-gas temperatures are not allowed to reach the acid dewpoint
(ADP).
ESP-6 is similar to ESP-3, but provides SC upstream of PAC injection. Cooling the flue gas aids
adsorption and reduces PAC injection requirements. Also, use of PFF permits sorbent recycling,
leading to improved sorbent utilization. Capital costs for this configuration are expected to be
higher than for most other configurations because of the several pieces of equipment required.
Total annual costs would be reduced due to relatively lower carbon consumption, but be
increased due to higher maintenance and materials requirements.
Table 1. Mercury control technologies for coal-fired electric utility boilers.
Mercury
Control
ESP-1
ESP-3
ESP-4
ESP-6
ESP-7
HESP-1
FF-1
FF-2
SD/FF-1
SD/ESP-1
Existing
Equipment3'1"
ESP
HESP
FF
SD + FF
SD + ESP
Retrofit Technology"
PAC injection
PAC injection + PFF
SC + PAC injection
SC + PAC injection + PFF
SC + PAC injection + lime
injection + PFF
SC + PAC injection + PFF
PAC injection
SC + PAC injection
PAC injection
PAC injection
a. ESP = cold-side electrostatic precipitator; HESP = hot-side electrostatic precipitator; FF= fabric filter;
SD = spray dryer; PACI = powdered activated carbon; PFF = polishing fabric filter, SC=spray cooling.
b. Existing equipment may include wet scrubber and NOX controls such as selective catalytic reduction
(SCR).
ESP-7 is the same as ESP-6 except for the addition of a second sorbent, lime. In addition to
mercury removal, this technology would remove acid gases from the flue gas. Pilot-scale results
have indicated that this may result in significant lowering of PAC injection rates. Capital and
total annual costs would increase due to addition of the lime system components, but total annual
costs would decrease due to lower PAC requirements.
In HESP-1, spray cooling, PAC injection, and a PFF are inserted downstream from a hot-side
ESP. This configuration is identical to ESP-6; only the location of the ESP is different.
Performance and costs should be similar to those found for ESP-6.
FF-1 is the baghouse analogue of ESP-1. However, mercury collection should be better than that
in ESP-1 because the FF provides added residence time and a contact bed (filter cake on the
bags) for increased adsorption of mercury. Consequently, PAC injection requirements in an FF-1
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application are expected to be lower that those in the corresponding ESP-1 application, thereby
resulting in lower total annual costs.
FF-2 is the baghouse analogue of ESP-4; spray cooling and PAC injection are installed upstream
of an existing baghouse. As with ESP-4, cooling reduces PAC requirements, which reduces total
annual PAC costs for FF-2 compared to FF-1. Capital costs should increase over FF-1 because of
the added equipment. Overall total annual costs are increased by water usage and maintenance of
the cooling system, but are not expected to increase sufficiently to offset savings from the
reduced PAC costs.
In SD/FF-1, PAC is injected into flue gas of a boiler that uses a spray dryer (SD)/FF combination
for SC>2 control. In this technology, the spray dryer provides flue gas cooling, so good collection
of mercury is expected. Because only PAC injection equipment is added to the existing air
pollution control system, capital and total annual costs are expected to be relatively low.
SD/ESP-1, like SD/FF-1, adds PAC injection in an existing SD/ESP combination. The
advantages of this technology should be similar to those of SD/FF-1; however, higher amounts
of PAC may be needed, relative to SD/FF-1. As such, total annual costs of this technology may
be higher than those associated with SD/FF-1.
3.2 PAC Injection Rates
The major factor affecting the cost of PAC injection-based technologies is the rate of PAC
injection needed for the required mercury removal efficiency. This rate depends on the
temperature of the flue gas and the type of coal fired in the boiler. For this work, PAC injection
rates at specific flue gas temperatures and mercury removal efficiencies achieved in pilot-scale
tests were fitted to the form of Equation (1) with curve-fit parameters a, b, and c (see Attachment
2 in the Appendix). For each technology for which pilot-scale test data are available, separate
correlations of mercury removal efficiency and PAC injection rate were determined for
bituminous and subbituminous coals. These coals are predominantly used at utility boilers and,
therefore, were chosen for this work.
Mercury Removal Efficiency (%) = 100 -- (1)
[PAC Injection Rate (lb/106 acf)+b] c
Equation (1) can be used to calculate the PAC injection rate (lb/106 acf) needed to achieve
specified mercury removal efficiency (%) for the control technology of interest. Note that
mercury removal efficiency (%) is based on totala mercury removed from the flue gas and is
defined as
Mercury Removal Effrcrency (
=
Emission
a Total refers to the sum of Hg°, Hg^, and mercury adsorbed on PM (e.g., flyash).
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where:
Emissionin = total flue gas mercury concentration at the inlet to the first air pollution control
device; and
Emission^ = total flue gas mercury concentration at the outlet of the last air pollution
control device.
Preliminary analysis of data obtained through EPA's Information Collection Request (ICR)10
reflected that, at boilers firing bituminous coals and using a cold-side ESP for PM capture,
higher levels (more than 50%) of mercury were being removed with flyash than found in earlier
pilot-scale tests (see Attachment 2 in the Appendix). Accordingly, for each of technologies ESP-
1, ESP-3, ESP-4, and ESP-6, two separate sets of correlations, relating PAC injection rate (lb/106
acf) to mercury removal efficiency (%), were created for use with bituminous-coal-fired boilers.
The first of these sets, hereafter referred to as the pilot-scale PAC injection rate, was derived
using presently available pilot-scale test data. The other set, hereafter referred to as the
ICR/pilot-scale PAC injection rate, was derived using preliminary ICR results for flyash capture
of mercury (i.e., no PAC injection) and pilot-scale results for PAC injection.
Note that the above data fitting procedure resulted in correlations of PAC injection rate (lb/106
acf) versus mercury removal efficiency (%), as a function of flue gas temperature, for most of the
technologies except (1) FF-1, FF-2, and SD/FF-1, applied on boilers firing bituminous coals, for
which no data are available; (2) HESP-1 applied on boilers firing either bituminous or
subbituminous coals, for which no data are available; and (3) ESP-7 and FF-3 applied on boilers
firing either bituminous or subbituminous coals, for which pilot-scale data are presently available
for ESP-7 application on a boiler firing a bituminous coal.11 These data reflect that more than
90% of mercury can be removed by injecting relatively small amounts of PAC with lime.
Therefore, in this work, application of ESP-7 was evaluated at 90% mercury removal efficiency
in a sensitivity analysis.
The algorithms describing sorbent injection rates for various technologies can be found in
Attachment 2 in the Appendix.
3.3 Model Plants
Costs for installing and operating the PAC injection-based technologies described above are
estimated with model plants. Approximately 75% of the existing coal-fired utility boilers in the
U.S. are equipped with electrostatic precipitators (ESPs) for the control of PM.4 The remaining
boilers employ fabric filters (FFs), particulate scrubbers, or other equipment for control of PM.
Additionally, units firing medium to high sulfur coals may use flue gas desulfurization (FGD)
technologies to meet their 862 control requirements. Generally, larger units firing high sulfur
coals employ wet FGD, and smaller units firing medium sulfur coals use spray dryers. While
developing the model plants, these PM and SC>2 control possibilities were taken into account.
Eighteen model plants with possible flue gas cleaning equipment configurations and firing either
bituminous or subbituminous coal were used in this work. Table 2 exhibits these model plants.
Note that boiler sizes of 975 and 100 MW used in this work were selected to approximately span
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the range of existing boiler sizes, and to be consistent with the size of the model plants used in
previous work.1 It was also envisioned that use of post-combustion NOX controls such as
selective catalytic reduction (SCR) and selective non-catalytic reduction (SNCR) may enhance
oxidation of mercury in flue gas and result in the "cobenefit" of increased mercury removal in
wet FGD. However, at present data on this cobenefit are available for SCR applications only.
Since SCR is a capital-intensive technology, generally its use is cost-effective on larger boiler
sizes. Accordingly, in this work, the mercury cobenefit resulting from SCR use was evaluated for
model plants 1, 2, and 3 utilizing large (975 MW) boilers and wet FGD.
Table 2. Mercury control technology applications and cobenefits.
Model
Plant
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
Size
(MW)
975
975
975
975
975
975
975
975
975
100
100
100
100
100
100
100
100
100
Coal
Type3
Bit
Bit
Bit
Bit
Bit
Bit
Subbit
Subbit
Subbit
Bit
Bit
Bit
Bit
Bit
Bit
Subbit
Subbit
Subbit
%S
3
3
3
0.6
0.6
0.6
0.5
0.5
0.5
3
3
3
0.6
0.6
0.6
0.5
0.5
0.5
Existing
Controls
ESP + FGD
FF + FGD
HESP + FGD
ESP
FF
HESP
ESP
FF
HESP
SD + ESP
SD+FF
HESP + FGD
ESP
FF
HESP
ESP
FF
HESP
Mercury Control(s)b
ESP-1, ESP-3
FF-1
HESP-1
ESP-4, ESP-6
FF-2
HESP-1
ESP-4, ESP-6
FF-2
HESP-1
SD/ESP-1
SD/FF-1
HESP-1
ESP-4, ESP-6
FF-2
HESP-1
ESP-4, ESP-6
FF-2
HESP-1
Cobenefit
Case(s)
with
SCR
SCR
SCR
a. Bit = bituminous coal; Subbit = subbituminous coal.
b. Mercury controls are shown in Table 1.
4.0 COSTS OF REDUCING MERCURY EMISSIONS
In general, capital costs of PAC injection-based technologies comprise a relatively minor
fraction of the total annual costs of these technologies; the major fraction is associated with the
1 9
costs related to the use of PAC. As an example, for application of SC+PAC injection (ESP-4)
to achieve 80% mercury reduction on a 975 MW boiler firing bituminous coal and using ESP,
the capital cost contributes about 23% of total annual cost. Therefore, for such technologies, an
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assessment of costs needs to be based on total annual costs. Accordingly, total annual costs of
controlling mercury emissions from coal-fired electric utility boilers are examined in this section.
These costs include annualized capital charge, annual fixed operation and maintenance (O&M)
costs, and annual variable O&M costs.
First, costs are estimated for some of the model plants'3 using the NETL Mercury Control Cost
Model described briefly below. Second, the cost impacts of some selected variables are
determined. Third, the NETL model results are used to develop indications of cost estimates for
those plants for which such results are not available. Next, potential future improvements in
these cost estimates are discussed. Finally, mercury control costs are discussed in light of current
costs of NOX controls. During discussions of cost estimates, R&D areas are identified for near-
term emphasis.
4.1 NETL Mercury Control Cost Model
The Department of Energy's National Energy Technology Laboratory (NETL) has developed a
cost model for estimating the costs of mercury control options for coal-fired electric utility
boilers. This cost model, called the NETL Mercury Control Cost Model (hereafter referred to as
the cost model), can provide capital and O&M costs estimated in 2000 constant dollars for power
plant applications of selected mercury control technologies. The model has been used in the past
to characterize costs associated with PAC injection on certain model boilers.13 For this work, the
PAC injection rate algorithms described in Section 3.2 were incorporated into this model. An
overview of this model can be seen in Attachment 1 in the Appendix.
4.2 Cost Model Results
This section describes the estimates of total annual cost for mercury control technology
applications on some0 model plants obtained using the cost model. It is noted that these estimates
are based on currently available data and, as explained later, may be improved with R&D efforts.
While developing the cost estimates for the model plant applications, the following
specifications were used with the cost model.
(1) Mercury concentration in the flue gas was taken to be 10 |ig/Nm3. This concentration has
been used in previous cost studies and is in the range of concentration reported for utility
boilers.1'12
(2) As mentioned in Section 3.2, for each of technologies ESP-1, ESP-3, ESP-4, and ESP-6, two
separate sets of correlations, relating PAC injection rate (lb/106 acf) to mercury removal
efficiency (%), were created for use with bituminous-coal-fired boilers. The first of these
sets, hereafter referred to as the pilot-scale PAC injection rate, was derived using presently
available pilot-scale test data. The other set, hereafter referred to as the ICR/pilot-scale PAC
b As described in Section 3.2, PAC injection rate algorithms could not be determined for the technologies used in
model plant applications 2, 3, 5, 6, 9, 11, 12, 14, 15, and 18. As such, costs associated with these applications could
not be modeled with the NETL cost model.
0 See footnote b.
-------
injection rate, was derived using preliminary ICR results for flyash capture of mercury (i.e.,
no PAC injection) and pilot-scale results for PAC injection. Accordingly, the cost of
applications of technologies ESP-1, ESP-3, ESP-4, and ESP-6 was determined using pilot-
scale PAC injection rate and ICR/pilot-scale PAC injection rate correlations.
(3) PAC injection rate correlations (see Section 3.2) generally reflect that PAC injection
requirements increase nonlinearly with increase in mercury removal efficiency. To
characterize the impact of this behavior, wherever possible, model plant cost estimates were
obtained for mercury removal efficiencies of 60, 70, 80, and 90%.
(4) In general, for any given mercury removal requirement, the PAC injection rate goes down if
the temperature of the flue gas is lowered. For this reason, the flue gas is cooled by water
injection in some technologies (see Table 1). However, water injection into acidic flue gas
can potentially lead to corrosion of downstream equipment. To avoid this, an approach to
acid dew point (ADP) of 18 °F was used in applications of technologies with SC (i.e., ESP-4,
ESP-6, ESP-7, and FF-2).14 For these technology applications, the extent of SC provided was
determined based on the temperature of the flue gas before cooling and the temperature
nearest to the above approach to ADP for which a PAC injection rate correlation was
available.
Note that, in the high sulfur coal applications with relatively high ADPs, this constraint
resulted in no SC if the 862 control technology was wet FGD. However, in applications
using SD for 862 control, SC is inherent and acid gases are removed prior to PAC injection;
therefore, this constraint was not applied.
(5) No data are currently available for recycling of sorbent in technology applications utilizing
PAC injection and PFF. Accordingly, no sorbent recycle was used in applications of ESP-3
and ESP-6 technologies.
(6) In flue gas of bituminous-coal-fired boilers, 70% of the total mercury is oxidized and 30% is
Hg°. Corresponding numbers for boilers firing subbituminous coals are 25% oxidized and
75% Hg°. These mercury speciation numbers were determined from a preliminary analysis of
ICR data (see Attachment 2 in the Appendix).
(7) Wet FGD removes 100% of oxidized mercury and no Hg°. This is based on the fact that
mercuric chloride (the assumed major oxidized species) is soluble in water while Hg° is
insoluble. It is anticipated that ongoing research on wet scrubbers will result in improved
performance through the use of reagents or catalysts to convert mercury to chemical
compounds that are soluble in aqueous-based scrubbers.
(8) SCR use increases oxidized mercury content in flue gas by 35% for both bituminous- and
subbituminous-coal-fired boilers. This increase in mercury oxidation was determined from a
preliminary analysis of ICR data (see Attachment 2 in the Appendix).
(9) In each of the model plant cost determinations, a plant capacity factor of 65% was used.
-------
(10) The cost of PAC was taken to be $1.0/kg.12
Other specifications can be seen in Attachments 1, 2, and 3 in the Appendix.
Boilers firing bituminous coals and utilizing cold-side ESPs
As shown in Table 3, there are several potential options to reduce mercury emissions from
boilers that fire bituminous coals and use ESPs for PM control. For low-sulfur bituminous-coal-
fired boilers, these options include SC + PAC injection (ESP-4) and SC + PAC Injection + PFF
(ESP-6). For large boilers firing high-sulfur bituminous coals, these options include PAC
injection (ESP-1) + wet FGD and PAC injection + PFF (ESP-3) + wet FGD. For smaller boilers
(typically less than 300 MW), these options include SD + PAC injection + ESP (SD/ESP-1).
As seen in Table 3, for ESP-4 application on low-sulfur bituminous-coal-fired boilers using
pilot-scale PAC injection rates, estimated total annual cost ranges from 2.81 mills/kWh for a 100
MW boiler removing 90% of total mercury to 0.53 mill/kWh for a 975 MW boiler removing
60% of total mercury. The corresponding costs with ICR/pilot-scale PAC injection rates are 1.65
mills/kWh for the 100 MW boiler and 0.24 mill/kWh for the 975 MW boiler. In general, these
results reflect that, for a given boiler, the total annual cost increases non-linearly with increase in
mercury reduction requirement in concert with the behavior of the PAC injection rate algorithms
(see Attachment 2 in the Appendix). A comparison of results obtained with pilot-scale and
ICR/pilot-scale PAC injection rates also indicates that R&D efforts aimed at ensuring broad
availability of relatively high levels offlyash capture of mercury have the potential of providing
significant reductions in mercury control costs.
Another option for boilers firing low-sulfur bituminous coals is to utilize ESP-6 for mercury
control. For this option, using the pilot-scale PAC injection rates, estimated total annual cost
ranges from 4.966 mills/kWh for a 100 MW boiler removing 90% of total mercury to 1.528
mills/kWh for the 975 MW boiler removing 60% of total mercury. The corresponding costs with
ICR/pilot-scale PAC injection rates are 3.08 mills/kWh for the 100 MW boiler and 1.353
mills/kWh for the 975 MW boiler. In general, these results reflect that ESP-6 control option is
more expensive than ESP-4 because of the capital cost associated with the PFF. To make this
control option more cost-effective, R&D efforts are needed to develop less expensive PFF
designs and high capacity sorbents, which may be recycled sufficiently to improve sorbent
utilization.
10
-------
Table 3. Mercury controls and costs for boilers firing bituminous coals and utilizing ESPs.
Model
Plants
4, 13
1,10
Existing
Control(s)
ESP
ESP + FGD
(SD for 100
MW boiler)
Coal
Low-sulfur
bituminous
High-sulfur
bituminous
Mercury Control
Technology
SC +PAC Injection
(ESP-4)
SC +PAC Injection
+ PFF (ESP-6)
PAC Injection
(ESP-1, SD/ESP-1)
PAC Injection +
PFF (ESP-3)
Removal
(%)
90
80
70
60
90
80
70
60
90
80
70
60
90
80
70
60
975 MW
(mills/kWh)
1.966
0.883 (ICR)
1.017
0.464 (ICR)
0.696
0.3 19 (ICR)
0.533
0.240 (ICR)
2.381
.735 (ICR)
.817
.485 (ICR)
.625
.397 (ICR)
.528
.353 (ICR)
2.594
0.427 (ICR)
0.727
NA (ICR)a
0.006b
NA(ICR)3
NAb
NA (ICR) a
2.086
1.416 (ICR)
1.501
NA (ICR) a
1.273
NA(ICR)3
NAb
NA (ICR) a
100 MW
(mills/kWh)
2.810
.647 (ICR)
.793
.184 (ICR)
.442
.018 (ICR)
.262
0.922 (ICR)
4.966
3.080 (ICR)
3.783
2.798 (ICR)
3.170
2.695 (ICR)
2.957
2.637 (ICR)
1.925
1.094 (ICR)
1.197
0.759 (ICR)
0.945
0.637 (ICR)
0.815
0.008 (ICR)
c
c
c
c
a. NA = Not available. Based on 70% of total mercury being oxidized, mercury removal with flyash being
about 58%, and all of oxidized mercury being removed in wet FGD, a minimum of about 87% of total mercury
is removed.
b. The cost of monitoring of mercury emissions is 0.006 mill/kWh. Based on 70% of total mercury being
oxidized, no mercury removal with flyash, and all of oxidized mercury being removed in wet FGD, a minimum
of 70% of total mercury is removed.
c. No mercury control technology with PFF is utilized.
As seen in Table 3, for ESP-1 application on a large (975 MW) high-sulfur bituminous-coal-fired
boiler that uses wet FGD for 862 control, using pilot-scale PAC injection rates, estimated total
annual cost ranges from 2.594 mill/kWh for removing 90% of total mercury to 0.006 mill/kWh
(cost of monitoring of mercury emissions) for removing 70% of total mercury. The costs with
ICR/pilot-scale PAC injection rates are 0.427 mill/kWh for 90% removal and 0.006 mill/kWh for
about 87% removal. Note that, with the assumptions of this work, a minimum of 70% of total
11
-------
mercury is removed in wet FGD if no mercury is removed with flyash (pilot-scale test results)
and a minimum of about 87% is removed if about 58% of mercury is removed with flyash
(preliminary ICR data analyses results). These results reflect that, if significant amounts of
mercury can be captured along with flyash in ESP and in wet FGD, cost of achieving high levels
of mercury removal would be quite low. Considering these results, R&D efforts are needed to
ensure that these mercury capture mechanisms are broadly available.
Another option for large boilers firing high-sulfur bituminous coals and using wet FGD is to
utilize ESP-3 for mercury control. Using this option on a 975 MW boiler, with pilot-scale PAC
injection rates, estimated total annual cost ranges from 2.086 mills/kWh for removing 90% of
total mercury to 1.273 mills/kWh for removing 70% of total mercury. The costs with ICR/pilot-
scale PAC injection rates are 1.416 mills/kWh for removing 90% of total mercury and 0.006
mills/kWh for about 87% removal. Interestingly, this control option is more cost-effective than
the one using PAC injection (ESP-1) at 90% mercury removal. However, at or below 80%
removal, this option is more expensive because PAC injection rate decreases more rapidly than
capital cost of PFF. It may be possible to make this option competitive across a wide range of
mercury removal efficiency by conducting R&D efforts directed towards reducing both PFF
capital cost and operating cost through sorbent recycling.
Finally, as seen in Table 3, for ESP-1 application on a relatively small boiler (100 MW) that fires
a high-sulfur bituminous coal and uses a SD for SC>2 control, with pilot-scale PAC injection
rates, estimated total annual cost ranges from 1.925 mills/kWh for removing 90% of total
mercury to 0.815 mills/kWh for removing 60% of total mercury. The corresponding costs with
ICR/pilot-scale PAC injection rates are 1.094 and 0.008 mills/kWh, respectively. A significant
increase in costs is observed on increasing the mercury control requirement from 80 to 90%.
Again, considering the differences in total annual costs obtained using ICR/pilot-scale and pilot-
scale PAC injection rates, R&D efforts aimed at providing broad availability of relatively high
levels of flyash capture of mercury are needed.
Boilers firing subbituminous coals and utilizing cold-side ESPs
Shown in Table 4 are two potential options to reduce total mercury emissions from boilers that
fire subbituminous coals and use ESPs for PM control. These options include SC + PAC
injection (ESP-4) and SC + PAC injection + PFF (ESP-6).
12
-------
Table 4. Mercury control options and costs for boilers firing subbituminous coals and utilizing
ESPs.
Model
Plants
7,16
Existing
Controls
ESP
Coal
Low-sulfur
subbituminous
Mercury Control
Technology
SC +PAC Injection
(ESP-4)
SC +PAC Injection +
PFF (ESP-6)
Removal
(%)
90
80
70
60
90
80
70
60
975 MW
(mills/kWh)
2.384
1.150
0.731
0.473
1.444
1.419
1.410
1.405
100 MW
(mills/kWh)
3.232
1.915
1.460
1.174
2.754
2.723
2.712
2.703
For ESP-4 application on boilers firing subbituminous coals, estimated total annual costs range
from 3.232 mills/kWh for a 100 MW boiler removing 90% of total mercury to 0.473 mill/kWh
for the 975 MW boiler removing 60% of total mercury. Further, total annual cost appears to drop
sharply as mercury removal requirement is reduced from 90% to 80% due to the nonlinear nature
of the PAC injection rate algorithms.
For ESP-6 application on boilers firing subbituminous coals, estimated total annual cost ranges
from 2.754 mills/kWh for a 100 MW boiler removing 90% of total mercury to 1.405 mills/kWh
for the 975 MW boiler removing 60% of total mercury. Interestingly, this control option is more
cost-effective than the one using SC + PAC injection (ESP-4) at 90% mercury removal.
However, at or below 80% removal, this option is more expensive because PAC injection rate
decreases more rapidly than capital cost of PFF. These results again point towards possibilities
of making this option competitive across a wide range of mercury removal efficiency by
conducting R&D efforts directed towards reducing both the PFF capital cost and operating cost
through sorbent recycling.
A comparison of the results shown in Tables 4 and 3 reveals that applications of SC+PAC
injection (ESP-4) to achieve mercury reductions in excess of 70% would cost more for boilers
firing subbituminous coals compared to boilers firing bituminous coals. Further, in general,
relatively few wet scrubbers would be used on subbituminous-coal-fired boilers. Considering
these factors, R&D efforts are needed to ensure that cost-effective control of mercury is achieved
at these boilers.
13
-------
Boilers firing subbituminous coals and utilizing FFs
As seen in Table 5, for boilers firing subbituminous coals and utilizing SC + PAC injection (FF-
2) for mercury control, estimated total annual cost ranges from 1.120 mills/kWh for a 100 MW
boiler removing 90% of total mercury to 0.219 mill/kWh for the 975 MW boiler removing 60%
of total mercury. These cost estimates reflect that the combination of SC + PAC injection + FF is
quite efficient in removing mercury.
Table 5. Mercury control costs for boilers firing subbituminous coals and utilizing FFs.
Model
Plants
8, 17
Existing
Controls
FF
Coal
Low-sulfur
subbituminous
Mercury Control
Technology
SC +PAC Injection
(FF-2)
Removal
(%)
90
80
70
60
975 MW
(mills/kWh)
0.423
0.299
0.226
0.219
100 MW
(mills/kWh)
1.120
0.977
0.888
0.879
Boilers utilizing SCRs for N(X control
Table 6 shows the total annual cost resulting from application of SCR on a large (975 MW)
boiler firing a high-sulfur bituminous coal and using wet FGD for SC>2 control. As mentioned
before, in this work it has been assumed that flue gas resulting from bituminous coal combustion
has an oxidized mercury content of 70%, and SCR augments this by 35%. This leads to a total of
94.5% of total mercury being oxidized mercury after SCR.
Using the results of ICR data analysis (see Section 3.2), about 58% of total mercury is captured
along with flyash in ESP and all of the remaining oxidized mercury is captured in wet FGD.
Thus, a total mercury capture of 97.6% is achieved, and the cost of this removal is 0.006
mills/kWh, which is simply the cost of monitoring of mercury emissions. On the other hand,
using pilot-scale test results, no mercury is captured along with flyash in ESP and all of the
oxidized mercury is captured in wet FGD. Therefore, a total mercury capture of 94.5% is
achieved, and the cost of this removal is 0.006 mill/kWh; i.e., the cost of monitoring of mercury
emissions.
Table 6. Mercury control costs for boilers using SCRs.
Model
Plant
1
Existing
Controls
ESP + wet
FGD
Coal
High-sulfur
bituminous
Mercury Control
Technology
None
Removal
(%)
97.6
94.5
975 MW
(mill/kWh)
0.006 (ICR)
0.006
14
-------
4.3 Cost Impacts of Selected Variables
In addition to estimating mercury control costs described above, impacts of certain selected
variables on these costs were examined via sensitivity analyses conducted using the cost model
with pilot-scale PAC injection rates. These analyses are described below, and additional
information on these analyses is presented in Attachment 3 in the Appendix. Note that the boiler
size of 500 MW is approximately the midpoint of the range of boiler sizes in the model plant
applications and, therefore, is representative of this range. As such, the sensitivity analyses use
the results obtained for a 500 MW boiler.
(1) Approach to acid dew point. In determinations of mercury control costs for model plant
applications described above, the approach to acid dew point was kept at 18 °F. However,
there was a concern that in some cases this may not be adequate to prevent corrosion of
downstream equipment. For this analysis, this approach was increased to 40 °F for model
plant applications 4, 7, and 8 evaluated with a boiler size of 500 MW. Note that the
approach to dew point is a concern when SC is used; i.e., in applications with low-sulfur
bituminous and subbituminous coals.
Shown in Tables 7, 8, and 9 are the costs at nominal (ADP +18 °F) conditions and at
ADP + 40 °F. As seen in Table 7, for a 500 MW boiler firing low-sulfur bituminous coal
and using ESP-4, the total annual cost increase ranges from 126.3 to 38.2%. Again for the
same boiler using ESP-6, the cost increase ranges from 18.8 to 2%. Interestingly, the
results for subbituminous coal presented in Tables 8 and 9 reflect that total annual cost
decreases with an increase in approach to ADP. This is due to a significant decrease in
water injection requirements, while PAC injection does not increase much to provide the
required mercury removal. These results indicate that, for bituminous-coal-fired boilers
using ESPs, increase in approach to ADP can influence costs significantly. However, the
same is not true for subbituminous-coal-fired boilers. The results also reveal that
sorbents with reduced temperature dependence of the mercury adsorption process need
to be developed for use with ESPs.
(2) Sorbent recycle. As discussed above, estimates of mercury control costs for model plants
using PFF obtained using no sorbent recycle, are, in general, higher than those of other
options. The purpose of this sensitivity analysis was to examine the impact of increasing
sorbent utilization in ESP-3 and ESP-6 applications on associated costs. Specifically, cost
estimates were obtained with 20% of PAC recycled in the following applications
evaluated with a 500 MW boiler: model plant 1 retrofitted with ESP-3; model plant 4
retrofitted with ESP-6; and model plant 7 retrofitted with ESP-6.
The results shown in Tables 7 and 8 reflect that a recycle rate of 20% does not have much
of an impact on total annual costs because capital cost of PFF is the dominant cost
component. In order to utilize benefits of increased sorbent utilization, higher recycle
rates would be needed, but such rates would require that sorbents used have relatively
high adsorption capacities. This indicates that R&D efforts aimed at developing such
sorbents are needed.
15
-------
Table 7. Impact on mercury control costs resulting from increase in approach to ADP and
recycling of sorbent for boilers firing bituminous coals and utilizing ESPs.
Model
Plant
4
1
Existing
Controls
ESP
ESP + wet
FGD
Coal
Low-sulfur
bituminous
High-sulfur
bituminous
Mercury Control
Technology
SC + PAC injection
(ESP-4)
SC + PAC injection
+ PFF (ESP-6)
PAC injection +
PFF (ESP-3)
Removal
(%)
90
80
70
60
90
80
70
60
90
80
70
60
500 MW
(mills/kWh)
2.095
4.741 (ADP + 40)
1.132
2.282 (ADP + 40)
0.804
1.451 (ADP + 40)
0.637
1.030 (ADP + 40)
2.650
3. 263 (ADP + 40)
2.457 (Recycle)
2.075
2.307 (ADP + 40)
1.989 (Recycle)
1.879
1.982 (ADP + 40)
1.829 (Recycle)
1.779
1.816 (ADP + 40)
1.747 (Recycle)
2.324
2. 173 (Recycle)
1.727
1.686 (Recycle)
0.006
0.006 (Recycle)3
NAa
a. The cost of monitoring of mercury emissions is 0.006 mill/kWh. Based on 70% of total mercury being
oxidized, no mercury removal with flyash, and all of oxidized mercury being removed in wet FGD, a minimum
of 70% of total mercury is removed.
16
-------
Table 8. Impact on mercury control costs resulting from increase in approach to ADP and
recycling of sorbent for boilers firing subbituminous coals and utilizing ESPs.
Model
Plant
7
Existing
Controls
ESP
Coal
Low-sulfur
subbituminous
Mercury Control
Technology
SC + PAC injection
(ESP-4)
PAC injection + PFF
(ESP-6)
Removal
(%)
90
80
70
60
90
80
70
60
500 MW
(mill/kWh)
2.513
2.392 (ADP + 40)
1.261
1.140 (ADP + 40)
0.835
0.7 14 (ADP + 40)
0.571
0.478 (ADP + 40)
.693
.683 (ADP + 40)
.686 (Recycle)
.667
.597 (ADP + 40)
.664 (Recycle)
.658
.567 (ADP + 40)
.657 (Recycle)
.652
.550 (ADP + 40)
.652 (Recycle)
Table 9. Impact on mercury control costs resulting from increase in approach to ADP for boilers
firing subbituminous coals and utilizing FFs.
Model
Plant
8
Existing
Controls
Fabric Filter
Coal
Low-sulfur
subbituminous
Mercury Control
Technology
SC +PAC Injection
(FF-2)
Removal
(%)
90
80
70
60
500 MW
(mill/kWh)
0.520
0.399 (ADP + 40)
0.392
0.271 (ADP + 40)
0.315
0.2 16 (ADP + 40)
0.308
0.197 (ADP + 40)
(3) Addition of ductwork to increase flue gas residence time. Adsorption of mercury on PAC is
dependent on the time of contact between the flue gas and PAC. In general, about half of the
existing utility boilers have a flue gas residence time in the duct of 1.0 s and about 30% have
a time of 2.0 s.15 Although it is not clear at this time as to how much time is needed for
particular levels of mercury capture, in this sensitivity analysis the impact of adding
ductwork to increase the flue gas residence time by 1 s on the cost of mercury control was
evaluated as a conservative measure. This analysis was conducted using model plant 4 with a
500 MW boiler retrofitted with ESP-4.
17
-------
The results shown in Figure 1 reflect that the impact of adding ductwork on total annual cost
is quite small. The increase in cost ranges from 16.4% at the lowest cost of 0.535 mill/kWh
to 4.3% at the highest cost of 2.095 mills/kWh. Based on this analysis, it appears that
addition of ductwork is not a sensitive cost parameter.
f
^
2
I/)
o
o
ra
c
c
<
3
°
MODEL PLANT 4, ESP-4, 500 MW, Bituminous Coal, 0.6% Sulfur,
With and Without Added Ductwork
2.50 -.
2.25 -
2.00 -
.75 -
1 25 ~
i r\r\
l.UU
0.75 -
OCA
0.25 -
/>
ff
//
//
//
^/
J
^^-~~~*r
1
W/O Ductwork
W/ Ductwork
40 60 80 100
Total Hg Removed, %
Figure 1. Change in total annual cost resulting from addition of ductwork to provide additional
residence time.
(4) Use of a composite PAC and lime sorbent. As discussed before, high levels of mercury have
been removed in pilot-scale tests using lime and PAC with PFF.11 To assess the potential
economic impact, this analysis was based on removing 90% of mercury from model plant 4
retrofitted with ESP-7 and using a composite PAC-lime sorbent, with a PAC:lime mass ratio
of2:19.
11
The results of this analysis shown in Figure 2 reflect that use of the composite sorbent lowers
the total annual cost by 34.7 to 38.1%. Based on these results, the use of composite PAC-lime
sorbent needs to be examined in future R&D efforts.
18
-------
MODEL PLANT 4, ESP-6 & 7, 500 MW, Bituminous Coal, 0.6% Sulfur,
Comparison of PAC and Lime-PAC Sorbents
tn
I
O
O
"ra
3
1
2.75
2.50
2.25
2.00
1.75
1.50
T
ESP-6, ACsorbent
-ESP-7, Lime-AC Sorbent
40 50 60 70 80
Total Hg Removed, %
90
100
Figure 2. Change in total annual cost resulting from use of a composite PAC-lime sorbent
instead of PAC.
4.4 Cost Indications for Other Model Plants
As discussed in Section 3.2, since data are not available on mercury control technology
applications involving HESPs or boilers firing bituminous coals and using FFs, PAC injection
rate algorithms could not be developed for these applications. Consequently, cost estimates for
these applications (i.e., model plants 2, 3, 5, 6, 9, 11, 12, 14, 15, and 18) could not be obtained
using the cost model. In this section, estimates of cost for these latter applications are developed
using the estimates described in previous sections.
Cooling the flue gas after the air preheater, injecting PAC, and collecting the spent PAC in a
downwind PFF may achieve mercury control on boilers equipped with HESPs. This
configuration is identical to ESP-6, with only the location of the ESP being different. Therefore,
mercury reduction performance and costs should be similar to those found for ESP-6. However,
on boilers equipped with HESPs and firing high-sulfur bituminous coals, application of SC may
not be possible due to corrosion concerns; for such boilers, mercury control may be achieved
using ESP-3. With these considerations, cost of mercury control technology applications
involving HESPs are: model plant 3 costs are the same as those for model plant 1 with ESP-3;
model plant 6 costs are the same as those for model plant 4 with ESP-6; model plant 9 costs are
the same as those for model plant 7 with ESP-6; model plant 12 costs are the same as those for
model plant 12 with ESP-3; model plant 15 costs are the same as those for model plant 13 with
ESP-6; and model plant 18 costs are the same as those for model plant 16 with ESP-6.
19
-------
The combination of PAC injection and FF provides better sorbent utilization than the
corresponding PAC injection and ESP combination because FF provides added residence time
and a contact bed for increased adsorption of mercury. This superior performance of FF has been
validated in full-scale tests on MWCs and pilot-scale tests on coal-fired combustors. Field tests
have shown that it takes 2 to 3 times more PAC to achieve the same performance on MWCs
equipped with dry scrubbers and ESPs than with dry scrubbers and FFs.16 As a result of
increased sorbent utilization, total annual cost of a PAC injection and FF application would be
lower than that of the corresponding PAC injection and ESP combination. An analysis of cost
data for ESP-4 applications on Model Plants 7 and 16 and FF-2 applications on Model Plants 8
and 17 (see Tables 4 and 5) reveals that, in reducing mercury emissions between 60 to 90% using
FFs instead of ESPs, total annual cost decreases by an average of about 70% for the 975 MW
boiler and 45% for the 100 MW boiler. Considering these numbers, on average about 58%
decrease in total annual cost may be expected if FFs are used in place of ESPs for mercury
removal.
4.5 Summary of Mercury Control Costs and Projections for Future
Applications
Shown in Table 10 below is a summary of costs of mercury control technology applications
developed in the previous sections. This summary presents current estimates of cost developed
using the pilot-scale PAC injection rates and projections based on use of potentially more
effective sorbent. The following assumptions were used in developing these estimates.
(1) A mercury capture of 80% is obtained in technologies using ESPs and 90% in
technologies using FFs. This is based on the consideration that it is more cost-effective to
remove mercury on boilers equipped with FFs.
(2) For technology applications on bituminous-coal-fired boilers using ESPs, current
estimates are based on levels of mercury capture on flyash derived from pilot-scale test
data. ICR data, however, reflect that levels of capture higher than those seen in pilot-scale
tests may be occurring. In this light, these cost estimates may be conservative.
(3) Current estimates for boilers using FtESPs, as well as boilers firing bituminous coals and
using FFs, are based on the information presented in Section 4.4. For other cases, these
estimates are based on the results obtained with the cost model.
(4) Results of sensitivity analyses presented in Section 4.3, especially impacts of increase in
approach to acid dew point at boilers firing bituminous coals and using ESP-4, are not
included in the current estimates because the estimates are preliminary in nature and
because it is not clear whether such an increase is broadly applicable. Generally an
approach of ADP + 18 °F is considered to be optimum.14 Where a higher approach is
desired, use of ESP-6 may be less expensive.
(5) Finally, sensitivity analyses reflect that use of a composite sorbent such as PAC + lime
may remove mercury quite cost-effectively. Although some data are currently available
20
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for applications using a PFF, there does not appear to be any significant technical
constraint to using such sorbents in other applications. Consequently, projected costs of
mercury controls are based on using such sorbents. Specifically, sensitivity analyses
reflected that a 35 - 40% decrease in total annual cost might be experienced if a
composite sorbent is used. Since these indications are based on using PFF, the capital
cost of which is a dominant component of the corresponding total annual cost, in
applications without PFF greater benefits may be possible. Considering these factors, a
40% reduction in total annual cost is used to arrive at the cost projections shown in Table
10.
Earlier, EPA's Office of Air and Radiation (OAR) conducted preliminary analyses examining
potential pollution control options for the electric power industry to lower the emissions of its
most significant air pollutants, including mercury. These analyses were conducted using the
Integrated Planning Model (TPM)17, which was supplemented with previously developed
estimates of performance and cost of mercury emission control technologies. These estimates
were based on using lime with PAC injection. In these previous estimates, mercury control costs
1 9
ranged from 0.17 to 1.76 mills/kWh for boilers ranging in size from 100 to 1000 MW. As seen
from Table 10, the range of projected cost estimates (i.e., 0.183 to 2.27 mills/kWh) is
comparable to the range of previously developed estimates.
Table 10. Mercury control technology application cost estimates based on currently available
data and projections for future.a
Coal
Type
Bit
Bit
Bit
Bit
Bit
Bit
Subbit
Subbit
Subbit
%S
o
J
o
J
o
J
0.6
0.6
0.6
0.5
0.5
0.5
Existing
Controls
ESP + FGD
FF + FGD
HESP + FGD
ESP
FF
HESP
ESP
FF
HESP
Mercury
Control
ESP-1,
SD/ESP-1
FF-1
ESP-3
ESP-4
FF-2
HESP-1
ESP-4
FF-2
HESP-1
Current
Estimates of
Mercury
Control Cost
(mills/kWh)
0.727-1.197
0.305-0.502
1.501-NAb
1.017-1.793
0.427 - 0.753
1.817-3.783
1.150-1.915
0.423-1.120
1.419-2.723
Projected
Cost of
Mercury
Controls
(mills/kWh)
0.436-0.718
0.183-0.301
0.901-NAb
0.610-1.076
0.256-0.452
1.090-2.270
0.69-1.149
0.254 - 0.672
0.851-1.634
a. The boiler size range is 975-100 MW.
b. NA = not available.
21
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Finally, it is noted that, in the wake of recent NOX control regulations, many plants may elect to
install SCRs. As discussed in Section 4.2, mercury control costs may be negligible at plants
using SCR and wet FGD.
4.6 Comparison of Mercury and NOX Control Costs
An understanding of the mercury control costs may be gained by comparing these with costs of
currently used controls for NOX. Shown in Table 11 are the ranges of total annual costs in 2000
constant dollars for the mercury controls examined in this work and for two of the currently used
NOX control technologies; i.e., low NOX burner (LNB) and SCR. NOX control costs are shown for
applications on dry-bottom, wall-fired boilers ranging in size from 100 to 1000 MW and being
operated at a capacity factor of 0.65. In general, costs associated with LNB and SCR are
expected to span the costs of currently used NOX controls; therefore these costs were chosen for
comparison with mercury control costs. The LNB and SCR costs were derived from the
information available in Reference 16.
As seen from Tables 10 and 11, total annual costs for mercury controls lie mostly between
applicable costs for LNB and SCR. However, Table 10 shows total annual costs of mercury
controls to be higher for the minority of plants using HESPs. Excluding these costs, both
currently estimated and projected mercury control costs are in the spectrum of LNB and SCR
costs.
Table 11. Comparison of mercury control costs with NOX control costs.
Control
Mercury Control Costs
LNB Costs
SCR Costs
Total Annual Cost
(mills/kWh)
0.305 -3.783a
0.183 to 2.270b
0.210-0.827
1.846-3.619
a.
b.
Estimated costs based on currently available data.
Projected costs.
5.0 SUMMARY
Preliminary estimates of costs of PAC injection-based mercury control technologies for coal-
fired electric utility boilers have been determined. These estimates include those based on
currently available data from pilot-scale PAC injection tests, as well as projections for future
applications of more effective sorbent. Estimates based on currently available data range from
0.305 to 3.783 mills/kWh. However, the higher costs are associated with the minority of plants
using HESPs. If these costs are excluded, the estimates range from 0.305 to 1.915 mills/kWh.
22
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Cost projections, developed based on using a composite lime-PAC sorbent for mercury removal,
range from 0.183 to 2.270 mills/kWh with the higher costs being associated with the minority of
plants using HESPs.
For technology applications on bituminous coal-fired boilers using ESPs, current estimates are
based on levels of mercury capture on flyash derived from pilot-scale test data. ICR data,
however, reflect that levels of capture higher than those seen in pilot-scale tests may be
occurring. In this light, the cost estimates for technology applications on bituminous-coal-fired
boilers using ESPs may be conservative.
Results of sensitivity analyses conducted on total annual cost of mercury controls reflect that: (1)
addition of ductwork to increase residence time does not have a significant impact on cost, (2) a
sorbent recycle rate of 20% is not adequate to reflect significant improvement in sorbent
utilization, (3) increasing approach to ADP from ADP + 18 °F to ADP + 40 °F can have a
significant impact on total annual costs of mercury controls applicable to bituminous-coal-fired
boilers, and (4) a composite sorbent containing a mixture of PAC and lime offers great promise
of significantly reduced control costs.
A comparison of mercury control costs with those of NOX controls reveals that total annual costs
for mercury controls lie mostly between applicable costs for LNB and SCR. As mentioned
above, estimates of total annual cost are higher where applicable to the minority of plants using
HESPs. Excluding these costs, both currently estimated and projected mercury control costs are
in the spectrum of LNB and SCR costs.
Based on this work, some R&D areas are identified for near-term emphasis. In general,
development of sorbents with reduced temperature dependence of the mercury adsorption
process would provide reduction in mercury control costs and potential for broad use.
Considering the differences in total annual costs obtained using ICR/pilot-scale and pilot-scale
PAC injection rates, R&D efforts aimed at ensuring broad availability of relatively high levels of
flyash capture of mercury have the potential of providing significant reductions in mercury
control costs, especially for ESP-based controls. The costs of PFF-based mercury control options
may be improved by developing less expensive PFF designs and high capacity sorbents, which
may be recycled sufficiently to improve sorbent utilization. Such recycling would require that
sorbents used have relatively high adsorption capacities. Finally, the use of composite PAC-lime
sorbent needs to be examined in future R&D efforts.
The performance and cost estimates of the PAC injection-based mercury control technologies
presented in this report are based on relatively few data points from pilot-scale tests and,
therefore, are considered to be preliminary. Factors that are known to affect the adsorption of
mercury on PAC or other sorbent include the speciation of mercury in flue gas, the effect of flue
gas and ash characteristics, and the degree of mixing between flue gas and sorbent. This mixing
may be especially important where sorbent has to be injected in relatively large ducts. The effect
of these factors may not be entirely accounted for in the relatively few pilot-scale data points that
comprised the basis for this work. Ongoing research is expected to address these issues and to
improve the cost effectiveness of using sorbents for mercury control. Further research is also
23
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needed on ash and sorbent residue to evaluate mercury retention and the potential for release
back into the environment.
6.0 REFERENCES
1. Keating, M.H.; Mahaffey, K.R. Mercury Study Report to Congress, Office of Air Quality
Planning and Standards and Office of Research and Development, U.S. Environmental
Protection Agency, Research Triangle Park, NC, December 1997, EPA-452/R-97-003 (NTIS
PB98-124738). Also available at the web site http://www.epa.gov/ttn/oarpg/t3re.html.
2. Mishima, Akio. Bitter Sea: The Human Cost ofMinamata Disease, Kosei Publishing Co.,
Tokyo, Japan, 1992.
3. Analysis of Emissions Reduction Options for the Electric Power Industry, Office of Air and
Radiation, U.S. Environmental Protection Agency, Washington, DC, March 1999. Available
at the web site http://www.epa.gov/capi/multipol/mercury.htm.
4. Brown, T.D.; Smith, D.N.; Hargis, R.A.; O'Dowd, WJ. "1999 Critical Review, Mercury
Measurement and Its Control: What We Know, Have Learned, and Need to Further
Investigate," Journal of the Air & Waste Management Association, June 1999, pp. 1-97.
5. Study of Hazardous Air Pollutant Emissions from Electric Utility Steam Generating Units -
Final Report to Congress, Volume 1, Office of Air Quality Planning and Standards, U.S.
Environmental Protection Agency, Research Triangle Park, NC, February 1998, EPA-453R-
98-004a (NTIS PB98-131774).
6. Waugh, E.G.; Jensen, B.K.; Lapatnick, L.N.; Gibbons, F.X.; Sjostrom, S.; Ruhl, J.; Slye, R.;
Chang, R. "Mercury Control in Utility ESPs and Baghouses through Dry Carbon-Based
Sorbent Injection Pilot-Scale Demonstration," EPRI-DOE-EPA Combined Air Pollutant
Control Symposium, Particulates and Air Toxics, Volume 3, EPRI TR-108683-V3, Electric
Power Research Institute, Palo Alto, CA, August 1997, pp. 1-15.
7. Haythornthwaite, S.M.; Smith, J.; Anderson, G.; Hunt, T.; Fox, M.; Chang, R.; Brown, T.
"Pilot-Scale Carbon Injection for Mercury Control at Comanche Station," presented at the
A&WMA 92nd Annual Meeting & Exhibition, St. Louis, MO, June 1999.
8. Haythornthwaite, S.M.; Sjostrom, S.; Ebner, T.; Ruhl, J.; Slye, R.; Smith, J.; Hunt, T.;
Chang, R.; Brown, T.D. "Demonstration of Dry Carbon-Based Sorbent Injection for Mercury
Control in Utility ESPs and Baghouses," EPRI-DOE-EPA Combined Air Pollutant Control
Symposium, Parti culates and Air Toxics, Volume 3, EPRI TR-108683-V3, Electric Power
Research Institute, Palo Alto, CA, August 1997.
9. Redinger, K.E.; Evans, A.P.; Bailey, R.T.; Nolan, P.S. "Mercury Emissions Control in FGD
Systems," EPRI-DOE-EPA Combined Air Pollutant Control Symposium, Parti culates and
Air Toxics, Volume 3, EPRI TR-108683-V3, Electric Power Research Institute, Palo Alto,
CA, August 1997.
24
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10. Electric Utility Steam Generating Unit Mercury Emissions Information Collection Effort,
OMB Control No. 2060-0396, EPA, Office of Air Quality Planning and Standards, Research
Triangle Park, NC.
11. Butz, J.R.; Chang, R.; Waugh, E.G.; Jensen, B.K.; Lapatnick, L.N. "Use of Sorbents for Air
Toxics Control in a Pilot-Scale COHPAC Baghouse," presented at the A&WMA 92nd
Annual Meeting & Exhibition, St. Louis, MO, June 1999.
12. Srivastava, R.K.; Sedman, C.B.; Kilgroe, J.D. "Preliminary Performance and Cost Estimates
of Mercury Emission Control Options for Electric Utility Boilers," presented at the
A&WMA 93rd Annual Conference & Exhibition, Salt Lake City, UT, June 2000.
13. Brown T.; O'Dowd, W.; Reuther, R.; Smith, D. "Control of Mercury Emissions from Coal-
Fired Power Plants: A Preliminary Cost Assessment," in Proceedings of the Conference on
Air Quality, Mercury, Trace Elements, and Particulate Matter, Energy & Environmental
Research Center, McLean, VA, December 1998, pp. 1-18.
14. Dotson, R.L.; Sodhoff, F.A.; Burnett, T.A. Lime Spray Dryer Flue Gas Desulfurization
Computer Model Users Manual, Air and Energy Engineering Research Laboratory, U.S.
Environmental Protection Agency, Research Triangle Park, NC, June 1986, EPA-600/8-86-
016 (NTIS PB87-140968), p. 15.
15. DOE's Duct Injection Survey Results, Department of Energy, Pittsburgh Energy Technology
Center, Pittsburgh, PA, August 1988.
16. Kilgroe, J.D. Journal of Hazardous Materials, 1996, 47, pp. 163-194.
17. Analyzing Electric Power Generation Under CAAA, Office of Air and Radiation, U.S.
Environmental Protection Agency, Washington, DC, March 1998. Available at the web site
http ://www. epa. gov/capi/ipm/update. htm.
25
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APPENDIX
Assessment of Mercury Control Options for
Coal-fired Power Plants (DOE)
A-i
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U.S. Department of Energy
National Energy Technology Laboratory
August 11,2000
Mr. James D. Kilgroe
United States Environmental Protection Agency
National Risk Management Research laboratory
Air Pollution Prevention and Control Division
Research Triangle Park, NC 27711
Dear Jim:
As part of our collaboration in the study and evaluation of mercury control options for coal-fired
power plants, a technical evaluation of commercial emission control technologies and emerging
technologies has been performed by the National Energy Technology Laboratory (NETL) using
our Mercury Control Performance and Cost Model (MCPCM).
Four individual attachments to this letter document the results of our work as follows:
1) Description of NETL's Mercury Control Performance and Cost Model;
2) Description of Mercury Control Performance Algorithms Used in the
NETL Mercury Control Performance and Cost Model;
3) Summary of Mercury Control Cases Analyzed with NETL's Mercury Control
Performance and Cost Model; and
4) Results of all Model Runs (Excel Spreadsheet Format).
The first attachment contains a detailed description of MCPCM, including a discussion of the
model's layout, documentation of the reference power plants used in the model, and documentation
of the methodology used to estimate capital and O&M costs. The second attachment documents
the mercury control performance algorithms used in the model for the various control
configurations specified by EPA. The third attachment defines all of the mercury control cases that
were requested by EPA. Different control configurations account for designated combinations of
wet scrubbers, fabric filters, spray dryers, electrostatic precipitators, SCR, and sorbent injection
systems to control pollutants. The final attachment, an Excel spreadsheet, presents the cost results
for all case runs. The total number of individual cases run with MCPCM is 306. Results are
presented in both tabular and graphical formats. For each case, the model estimates the cost of
control in mills/kWh associated with the designated mercury removal level as a percentage of the
inlet mercury concentration.
A-ii
3610 Collins Ferry Road. P.O. Box 880, Morgantown, WV 26507-0880 » 626 Cochrans Mill Road, P.O. Box 10940, Pittsburgh, PA 15236-0940
REPLY TO: Pittsburgh Office
-------
As you are aware, through your involvement in the model development process, there are
significant data gaps for mercury control system performance. NETL believes that the results of
this analysis should be viewed as preliminary. Our technical evaluation identifies the source of
information used in the analysis as well as all major assumptions.
The performance of mercury control technology options is fundamentally based on sorbent
injection testing obtained from pilot-scale systems. These data provide the firmest foundation to
develop performance algorithms. Although an attempt has been made to include EPA's Mercury
Information Collection request (ICR) data, it is highly recommended that such data not be used in
the evaluation of mercury control performance at this time. However, in the cases where the
mercury control configuration includes additional flue gas control systems such as flue gas
desulfurization (FGD) or Selective Catalytic Reduction (SCR), incremental mercury removal has
been demonstrated from ICR tests and this preliminary data appropriately incorporated into the
performance model. The model assumes 100% capture of oxidized mercury by the scrubber but a
more realistic number may be 90%. A special note should be made that the model considers
modern forced oxidation wet FGD systems. Existing wet FGD systems that have a low liquid-to-
gas ratio or use inhibited oxidation technology may have significantly different incremental
mercury removal levels.
Secondary effects that have not been investigated in the present study include a sensitivity analysis
of power plant efficiency and mercury concentration in the flue gas. Variations in these parameters
may have a significant impact on control design parameters that could also impact the control
costs.
If you have any questions, don't hesitate to contact either of us.
Sincerely,
Charles E. Schmidt Scott Renninger
Product Manager Project Manager
CC: Dennis Smith, NETL
Harvey Ness, NETL
Massood Ramezan, SAIC
Jay Ratafia-Brown, SAIC
Ravi Srivastava, EPA
A-iii
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LIST OF ATTACHMENTS
age
ATTACHMENT 1. Description of National Energy Technology Laboratory
Mercury Control Performance and Cost Model A-l-i
ATTACHMENT 2. Description of Mercury Control Performance Algorithms
Used in the National Energy Technology Laboratory
Mercury Control Performance and Cost Model A-2-i
ATTACHMENT 3. Summary of Mercury Control Cases Analyzed with
National Energy Technology Laboratory Mercury Control
Performance and Cost Model A-3-i
ATTACHMENT 4. Results of all Model Runs A-4-i
A-v
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ATTACHMENT 1
Description of
National Energy Technology Laboratory
Mercury Control Performance and Cost Model
A-l-i
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Description of the National Energy Technology Laboratory
Mercury Control Performance and Cost Model
1. Model Description
The National Energy Technology Laboratory (NETL) Mercury Control Performance and Cost Model
(MCPCM) is an Excel spreadsheet model that can be used to assess the performance and cost of mercury
(Hg) control systems that utilize activated carbon injection (ACI) and other methods. The primary goal of
the model is to calculate key performance parameters that are then used to calculate detailed capital costs
and O&M costs of a mercury control technology for either of two types of power plant applications - either
a bituminous or subbituminous coal-fired power plant configuration. This overview describes the model
layout, its specific capabilities, and its current limitations.
1.1 MCPCM Layout
The spreadsheet model is currently divided into seven (7) different, functional sheets that are integrated
together to perform the costing goal defined above. The five sheets are identified below:
Hg Control Scenario Definition Sheet Characterization of Control Technology Retrofit
Configurations
Hg Control Performance Models Sheet Performance Algorithms for Different Control
Technology Retrofit Configurations
Application Input Sensitivity Sheet User Data Input
Technical Model Results Sheet PowerPlant and Mercury Control Technical
Performance Results
Combustion Calculations Sheet Power Plant Performance Calculations
Capital Cost Model Sheet Capital Cost Calculations
System Economic Model Sheet O&M Cost Calculations and Levelized Cost
Calculations
1.1.1 Hg Control Scenario Definition Sheet
This sheet documents the different mercury control technology retrofit scenarios that can potentially be
evaluated by the model. The information provided for each scenario is presented below:
Scenario Number: Number, no units
This number uniquely identifies each control scenario within the program.
Configuration Designation: Abbreviation that identifies a control technology scenario, e.g., ESP-1
(activated carbon injection upstream of ESP with no spray cooling)
Configuration Definition: Brief description that uniquely defines a control technology scenario, e.g., ESP-
1, "ACI upstream of existing ESP"
Comment: Further descriptive information that qualifies the functionality of the control technology
scenario within the model.
Data Sources: Identifies and documents specific data and information sources used to establish the
performance of a control technology.
A-l-1
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1.1.2 Hg Control Performance Models Sheet
This sheet contains performance models for each control technology configuration identified in the Hg
Control Scenario Definition Sheet (as currently available). These models currently calculate total sorbent
feed (Ib/MMacf of flue gas) based on a specified total mercury control efficiency (e.g., 50%) and flue gas
temperature.
Currently, each control configuration (e.g., ESP-1) makes use of separate algorithms for mid- to high-sulfur
bituminous coals (e.g., Pittsburgh (Pgh) #8) and Western subbituminous coals (e.g., Wyoming PRB).
Therefore, the coal type that is specified in the Application Input Sensitivity Sheet will determine the
specific algorithm that is used for a specified control configuration and application case. These algorithms
were developed based on curve-fitting available pilot- and full-scale test data. The data sources are also
documented in the sheet.
1.1.3 Application Input Sensitivity Sheet
This sheet is intended as the primary user interface to run up to 20 different mercury control cases
simultaneously. For each control case, the sheet defines the desired mercury control requirements, a
specific power plant variant of either of two power plant application types, and some key economic
parameters used for costing purposes. Additional parametric changes can be made to the model to add
greater evaluation flexibility, but these need to be made within the other functional sheets of the model.
Model parameters included here are:
1.1.3.1 Mercury Control Parameters
Case Number: Numerical value, Fixed (e.g., 1,2, etc.) -
Sequentially identifies each application case. Up to 20 cases can be specified.
Hg Removal Configuration Type: Numerical entry by user (e.g., 1,2, etc.)
Specifies the mercury control configuration as documented in the Hg Control Scenario Definition Sheet.
The user must select a configuration type.
Hg Control Flue Gas Temperature Specification: Number, units = °F (e.g., 250)
Specifies the temperature at which mercury control is to take place. The program calculates this
temperature as follows:
Control Temperature = Flue Gas Acid Dew Point Temperature <°F) + 18 °F
(For Configurations 1 to 11)
Control Temperature = 200 °F
(Current default for all other configurations)
Injection of cooling water can be used to lower the flue gas temperature below the power plant air heater
outlet temperature for configurations 1 to 11. Configurations 12 to 18 incorporate wet or dry scrubbing,
which yield a relatively low flue gas temperature at their outlet. A default temperature of 200 °F is
currently used because it represents a value that is below the lower limit of the algorithms contained in the
Hg Control Scenario Definition Sheet.
Mercury Concentration: Number, units = \ag/Nm3 (e.g., 10)
The total mercury concentration within the flue gas at the exit of the air heater. The user specifies this
value.
Mercury Speciation as % Hg°: Number as a percentage, no units (e.g., 50)
A-1-2
-------
The percentage of total mercury that is elemental mercury. The difference is assumed to be oxidized
mercury in the form of HgCl2. The user specifies this value.
Total SI (sorbent injection) Mercury Removal Efficiency - % of Hg Removed: Number as a
percentage, no units (e.g., 50)
The percentage of total mercury that is removed by the control technology.
SI Mercury Removal Efficiency - % Hg° Removed: Number as a percentage, no units (e.g., 50)
The percentage of elemental Hg that is removed by the control technology. This value is currently assumed
to be calculated by the performance model, but this capability is currently not available.
ACI Mercury Removal Efficiency - % HgCl2 Removed: Number as a percentage, no units (e.g., 50)
The percentage of HgCl2 that is removed by the control technology, but this capability is currently not
available.
Sorbent Injection Ratio: Number, units = Ib/MMacf (e.g., 3)
The primary feed of sorbent (based on Ib sorbent per MMacf of flue gas) that corresponds to the specified
Hg removal efficiency. The configuration performance model calculates this value.
Sorbent Recycle Split: Percent, no units (e.g., 10)
The ratio of recycled spent sorbent to total sorbent feed into the flue gas (expressed as a percentage). This
value is currently assumed to be calculated by the performance model, but this capability is currently not
available.
FGD Mercury Removal Efficiency - % Hg° Removed: Number as a percentage, no units (e.g., 50)
The percentage of Hg° (in the flue gas) that is removed by an existing wet FGD system. Mercury removal
via an FGD system can be incorporated manually if desired. This is permitted as an option in case the user
wants to combine FGD with other mercury removal technologies such as ACI. Set values equal to zero if
no wet FGD exists or mercury control scenarios 14 - 18 are being used. If utilized, total mercury control is
calculated within the "Technical Model Results Sheet."
FGD Mercury Removal Efficiency - % HgClj Removed: Number as a percentage, no units (e.g., 50)
The percentage of HgCl2 (in the flue gas) that is removed by the wet FGD system. Mercury removal via an
FGD system can be incorporated manually if desired. This is permitted as an option in case the user wants
to combine FGD with other mercury removal technologies such as ACI. Set value equal to zero if no wet
FGD exists or mercury control scenarios 14 - 18 are being used. If utilized, total mercury control is
calculated within the "Technical Model Results Sheet."
If Hg speciation is unknown set value equal to "% Hg° removal efficiency." For example, if total Hg
removal via FGD is to be set at 80% and speciation is unknown, then set both Hg° and HgCl2 removal
efficiencies equal to the 80% value.
Fabric Filter Pressure Drop: Number, units = inches H2O (e.g., 6)
Differential pressure across baghouse tubesheet. Input a value if a pulse-jet FF will be added to the plant
after the primary paniculate collector to collect Hg sorbent. This applies to retrofit scenarios 3, 6, 7, 8, and
11.
Fabric Filter Air/cloth Ratio: Number, units =/?/min (e.g., 12)
Ratio of volumetric gas flow into baghouse (ft3/min) to total bag surface area (ft2). Input a value if a pulse-
jet FF will be added to the plant after the primary paniculate collector to collect Hg sorbent. This applies to
retrofit scenarios 3, 6, 7, 8, and 11.
Fabric Filter Particle Collection Efficiency: Number as a percentage, no units (e.g., 99.98)
A-1-3
-------
Mass flow of paniculate into baghouse/mass flow of paniculate emitted from baghouse. Input a value if a
pulse-jet FF will be added to the plant after the primary paniculate collector to collect Hg sorbent. This
applies to retrofit scenarios 3, 6, 7, 8, and 11.
1.1.3.2 Power Plant Design Parameters
Gross Power Plant Size: Number, units =MWe (e.g., 500)
Gross power plant electricity output (excludes plant auxiliary power).
Reference Power Plant Type: Alphanumeric entry (HS or LS)
HS refers to the high sulfur reference power plant and LS refers to the low sulfur reference plant.
Plant Capacity Factor: Number as a percentage, no units (e.g., 65)
Ratio of the energy generated during some time period to the total energy that could have been generated
had the plant run at its full rating over the entire time period.
Power Plant Coal Type: Alphanumeric entry (e.g., Pgh #8)
Select a coal type from a menu list of six coals. The coal types are Illinois #6, Wyoming PRB, Texas
Lignite, Utah Bituminous (LS), Appalachian (HS), Pittsburgh #8, and bituminous process derived fuel (LS).
The Combustion Calculations Sheet contains detailed analysis data for each coal (cell range AE61 to
AP141).
1.1.3.3 Economic Assessment Parameters
Levelized Carrying Charge Rate: Number, no units (e.g., 0.133)
The levelized amount of revenue per dollar of investment in the mercury control system that must be
collected in order to pay the carrying charges on the investment.
Sorbent Unit Cost: Number, units = $/lb (e.g., 0.5)
Unit cost of the activated carbon or other sorbent, including the cost of the material and shipping.
Waste Disposal Removal Service?: Yes or No
This logical question is asked to identify the need to treat the mercury laden AC as hazardous waste. Yes =
hazardous, in which case the AC is removed and processed to remove the mercury; a processing cost can
be specified by the user. No = non-hazardous, in which case the AC is disposed of with the fly ash; a
disposal cost can be specified by the user.
Normal Waste Disposal Cost: Number, units =$/ton (e.g., 30)
Unit cost of disposing non-hazardous power plant waste, such as fly ash. Use of a negative number
indicates a waste byproduct credit.
Hazardous Waste Disposal Cost: Number, units =$/ton (e.g., 1,750)
Unit cost of disposing hazardous power plant waste materials. AC is removed and processed to remove the
mercury.
Power Cost: Number, units =$/MW-Hr (e.g., 25)
Unit cost of power the plant charges for running auxiliary equipment.
Mercury By-Product Cost: Number, units =$/ton (e.g., 50)
Unit cost of recovered mercury that could be sold in the marketplace.
1.1.4 Technical Model Results Sheet
The purpose of this sheet is to document the case study input data for the power plant and the mercury
control technology, as well as the results of the performance calculations from the Power Plant Combustion
A-1-4
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Model Sheet. Up to twenty case studies can be simultaneously created and documented in the sheet. Two
reference power plants are documented; additional changes to the reference plant design and operating
conditions can be made in this sheet in order to modify plant performance.
For the power plant definition, the sheet uses the input data from the Application Input Sensitivity Sheet and
combines it with the reference plant data to create a specific plant for each case study. For example, if the
high sulfur power plant gross power rating is input as 900 MWe in the input sensitivity sheet, then this
overrides the reference plant rating of 541.9 MWe; plant auxiliary power is scaled accordingly. Sheet data
for the reference plants should not be changed unless modifications are needed to simulate a different plant.
For example, if a different net heat rate were desired, then the reference plant value would need to be
replaced with a new value.
The mercury control data inputs are taken directly from both the Input Sensitivity Sheet and the Hg Control
Performance Models Sheet and are listed for the sake of documentation and use by other parts of the
spreadsheet.
Calculated power plant performance results from the Power Plant Combustion Model Sheet are returned to
this sheet for documentation and use by the sheet to calculate specific performance results for the mercury
control technology.
This sheet also uses results returned from the Combustion Model Sheet to calculate the flue gas acid dew
point. This is an important design parameter given the significant influence of temperature on sorbent-
based mercury control. While test data indicates that lower temperatures enhance mercury capture from the
flue gas, reducing the gas temperature (via water injection) must be limited to a specified temperature
approach to the acid dew point. Maintaining the gas temperature at such an increment will help prevent
corrosion within the ductwork and paniculate control devices. The sulfuric acid dew point calculation is
based on the following algorithms:
1000/Tdp = 2.276-0.0294*ln(PH2O)-.0858*ln(PH2SO4) + 0.0062*ln(PH2O)*ln(PH2SO4)
Where,
Tdp = Acid Dew Point
PH2O = Partial pressure of water in the flue gas
PH2SO4 = Partial pressure of sulfuric acid in the flue gas
The dew point is in degree K and partial pressures in mm Hg.
For example, if a flue gas contains 12 % volume of water vapor and 0.02 % volume SO2 and say 2 % of
SO2 converts to SOS, compute the sulfuric acid dew point.
Gas pressure = 10 in wg or (10/407) =0.02457 atmg or 1.02457 atma.
PH2O =0.12 * 1.02457 * 760 = 93.44 mm Hg.
ln(PH2O) = 4.537
PSO3 = PH2SO4.
PSO3 = 0.02 * .0002 * (64/80) * 760 * 1.02457 = 0.0024917
ln(SO3)= -6
Note that 2 % conversion is on weight basis and hence we multiplied and divided by the molecular weights
of SO2 and SO3 in the above calculation.
1000/Tdp = 2.276 - 0.0294 * 4.537 + 0.0858 * 6-0.0062 * 4.537 * 6 = 2.489
Or Tdp=402 K or 129 C or 264 F
The percent conversion of SO2 to SO3 is calculated in the Combustion Model Sheet based on an algorithm
that accounts for the sulfur in the coal and specific ash constituents (Fe2O3).
A-1-5
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1.1.5 Combustion Calculations Sheet
The purpose of this sheet is to take the power plant case study design and operating data from the Technical
Model Results Sheet and calculate the power plant technical performance parameters, such as combustion
gas constituent flows and total gas flows at strategic boiler locations (e.g., after the air heater). Also, if flue
gas cooling via water injection is specified by the user (by specifying a flue gas temperature lower than the
reference plant's post air heater temperature), then this sheet will calculate the quantity of water required via
energy balance calculations. This sheet also contains the coal analysis data described previously. The coal
types are Illinois #6, Wyoming PRB, Texas Lignite, Utah Bituminous (LS), Appalachian (HS), Pittsburgh
#8, and bituminous process derived fuel (LS). Detailed analysis data for each coal can be found within cell
range AE61 to AP141.
1.1.6 Capital Cost Model Sheet
The Capital Cost Model Sheet makes use of the power plant and mercury control performance data to
calculate the capital costs associated with a case study's mercury control design configuration. The costing
currently covers the following equipment sections:
Spray Cooling Water System
Sorbent Injection System
Sorbent Recycle System
Pulse-Jet Baghouse and Accessories
Ash/Spent Sorbent Handling System
Continuous Emissions Monitoring System (CEMS) Upgrade
A total mercury control system cost is calculated from the following cost components: 1) equipment, 2)
related materials, 3) field and indirect labor, 4) sales tax, 5) base erected cost, 6) Engineering design, 7)
process and project contingencies, and 8) general facilities. Maintenance costs are also calculated as a
percentage of the bare erected cost (e.g., 2%). This sheet also contains an "Economic Master Table" in
which a number of key costing parameters, such as contingency factors, can be changed and incorporated
into the case study calculations. Twenty case studies can be handled simultaneously in this sheet.
1.1.7 System Economic Model Sheet
This sheet calculates mercury control system O&M, total system investment, total system capital
requirement, and then levelizes the capital and O&M to establish single value for $/lb of mercury removed.
Twenty case studies can be handled simultaneously in this sheet.
1.1.7.1 Mercury Control System O&M Costs
Operating Labor: cost of system operating and administrative personnel; unit labor rates and manpower
requirements/shift are specified in the case study O&M table and can be specified independently for each
case study.
Maintenance Labor: 40% of the total maintenance cost calculated in the Capital Cost Model Sheet
Maintenance Material: 60% of the total maintenance cost calculated in the Capital Cost Model Sheet
Administrative and Support Labor: Calculated as a percentage (labor overhead charge rate) of the sum
of the operating and maintenance labor cost; overhead charge specified in the case study O&M table and
can be specified independently for each case study.
Consumable values are taken from the Technical Model Results Sheet. The O&M cost consists of the
following consumable components:
A-1-6
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Water (for flue gas humidification), gallons/Hr: unit cost = $/l000 gallons (e.g., 0.80), specified in case
study table
Sorbent (e.g., Activated Carbon), tons /Hr: unit cost = $/ton (e.g., 1,100), specified in case study table
Incremental Power, kW-Hr: unit cost = $/MW-Hr (e.g., 30), specified in case study table
Fan power accounts for the added pressure drop across the mercury control equipment, such as the fabric
filter. Sorbent injection system power is required to transport the sorbent to the flue gas duct.
Humidification system power is required to pump water to an injection grid in the ductwork.
Waste Disposal, tons/Hr: unit cost = S/ton (e.g., 30), specified in case study table
Waste AC is generated by the mercury control system. This mercury-laden AC must be disposed of or
processed for mercury removal and recovery. This material can be disposed of with the rest of the plant's
fly ash or it can be processed separately if deemed a hazardous material.
Mercury Byproduct, Ib/Hr: unit cost = S/ton (e.g., 30), specified in case study table
If the spent AC is processed for recovery of mercury, then a by-product credit can be applied. This will be
applied only if the user has designated the spent AC as hazardous waste material.
1.1.7.2 Total Mercury Control System Capital Requirement
The total calculated investment in the mercury control system includes the total capital investment
calculated in the Capital Cost Model Sheet, interest during construction (AFUDC), and the following
additional cost components:
Royalty allowance ~ possible technology royalty charges may apply
Preproduction Costs ~ covers the cost of operator training, equipment checkout, major modifications to
equipment, extra maintenance, and inefficient use of consumables. Calculated as 1 month of fixed
operating costs (O&M labor, admin and support labor, and maintenance materials); 1 month of variable
operating costs (all consumables) at full capacity; and 2 % of the total system investment.
Inventory Capital ~ value of initial inventory of activated carbon that is capitalized. This accounts for an
initial storage supply of AC (e.g., 30 day supply).
Initial Catalysts and Chemicals Charge - the initial cost of any catalysts or chemicals contained in the
process equipment, but not in storage. Does not apply to the mercury control systems.
1.1.7.3 Levelized Cost of Mercury Control
The total cost of mercury control must account for the total capital requirement (expressed as $/kW) and
the total operating and maintenance expenses (expressed as mills/kWh). In order to calculate an annualized
cost that accounts for both of these, the capital requirement is annuitized via use of the "Levelized Carrying
Charge Rate." The Levelized Carrying Charge Rate assumes a 30-year operating period and accounts for
return on debt, return on equity, income taxes, book depreciation, property tax, and insurance payments.
The Levelized Carrying Charge Rate is specified in this sheet in the section called "Financial Data-Factors."
It is multiplied times the total system capital requirement to derive the annualized value and converted to
units of mills/kWh based on the annual operating hours of the plant (capacity factor x 8,760 h/yr).
The first-year O&M costs that are calculated in this sheet are also levelized in order to account for both
apparent and real escalation rates of labor, materials, and consumables over the expected operating time
period (e.g., 30 years). A levelization factor is specified in this sheet in the section called "Financial
Data-Factors." It is multiplied by the total O&M cost.
A-1-7
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The levelized carrying charge and the levelized O&M are summed to yield a total annualized cost which is
divided by the annual mercury removed in order to derive a unique cost of removal with units of $/ton
mercury removed.
A-1-8
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2. DOCUMENTATION OF REFERENCE POWER PLANTS USED IN MERCURY
CONTROL MODEL.
Two (2) representative power plant applications are being employed in this study to investigate the mercury
control costs for the baseline designs as well as parametric variations of these baseline plants. These plants
are characterized as:
1) Plant firing high-sulfur, bituminous coal (Pgh #8) with low-NOx burners for NOX control,
cold-side ESP for paniculate control, and a wet FGD system for SO2 control.
2) Plant firing low-sulfur coal with low-NOx burners for NOX control and a cold-side ESP
for paniculate control.
This section develops the basic specifications for each power plant variant: plant size, coal analysis, boiler
performance parameters, flue gas mass/volumetric flow rates, gas constituents (including HC1), gas
temperature/pressure profiles, total mercury concentration, and mercury speciation.
2.1 High Sulfur Power Plant Reference Case
The high sulfur reference coal (PC) plant design is comprised of a balanced draft, natural circulation steam
generator, providing steam for a turbine generator set, condensing at 2.5 inches Hg absolute back pressure
at the design point. The plant design and performance reflect current commercial practice in the U.S. utility
industry. The turbine-generator is a tandem compound machine, with high pressure (HP), intermediate
pressure (IP), and low pressure (LP) sections. The LP turbine is comprised of two double flow sections
exhausting downward into the condenser sections. The plant uses a 2400 psig/1000 °F/1000 °F single reheat
steam power cycle. The boiler and the turbine are designed for a main steam flow of 3,621,006 pounds of
steam per hour at 2520 pounds per square inch, gauge (psig) and 1000 °F at the superheater outlet, throttled
to 2415 pounds per square inch, absolute (psia) at the inlet to the high pressure turbine. The cold reheat
flow is 3,233,808 Ib/hr of steam at 590 psia and 637 °F, which is reheated to 1000 °F before entering the
intermediate pressure turbine section. The net plant output power, after plant auxiliary power requirements
are deducted, is nominally 508 MWe. The overall net plant higher heating value (HHV) efficiency is
nominally 36.8 percent. Refer to Table 2-1 for the plant performance summary information.
Applicable Federal, State, and Local environmental standards relating to air, water, solid waste and noise
have been designed into the high sulfur reference plant. Projected plant air emissions are identified in
Table 2-2. The wet, limestone FGD system ensures an SO2 emission rate of less than 0.371 Ib/MMBtu
(92% reduction). The use of low NOX burner technology, combined with over fire air, results in NOX
emissions of less than 0.30 Ib/MMBtu. The control or reduction of N2O has not been addressed in this
design because N2O levels are presently unregulated. The flue gas scrubber is a wet limestone type system,
with scrubbing and demisting occurring in the same vessel. An organic acid is added to the circulating
reagent to enhance the scrubbing performance. Air is blown into the scrubber module sump to promote
forced oxidation of the sulfite to sulfate. The gypsum byproduct is dried to a cake-like consistency in a
train of centrifuges, and is ready to landfill.
A-1-9
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TABLE 2-1
HIGH SULFUR PLANT PERFORMANCE SUMMARY -100 PERCENT LOAD
STEAM CYCLE
Throttle Pressure, psig
Throttle Temperature, °F
Reheat Outlet Temperature °F
POWER SUMMARY
3600 rpm Generator
GROSS POWER, kWe (Generator terminals)
AUXILIARY LOAD SUMMARY, kWe
Pulverizers
Primary Air Fans
Forced Draft Fans
Induced Draft
Seal Air Blowers
Main Feed Pump (Note 1)
Steam Turbine Auxiliaries
Condensate Pumps
Circulating Water Pumps
Cooling Tower Fans
Coal Handling
Limestone Handling & Reagent Prep.
FGD Pumps and Agitators
Ash Handling
Dewatering Centrifuges (FGD byproduct)
Precipitators
Soot Blowers (Note 2)
Miscellaneous Balance of Plant (Note 3)
Transformer Loss
TOTAL AUXILIARIES, kWe
Net Power, kWe
Net Efficiency, % HHV
Net Heat Rate, Btu/kWh (HHV)
CONDENSER COOLING DUTY, 106 Btu/hr
CONSUMABLES
As-Received Coal Feed, Ib/hr
Sorbent, Ib/hr
2,400
1,000
1,000
541,900
2,000
1,840
1,350
7,500
60
2,400
900
1,100
5,070
2,400
230
1,160
3,000
2,000
1,100
1,100
neg.
2,000
1,300
34,100
507,800
36.8
9,279
2,350
378,550
46,790
Note 1 - Driven by auxiliary steam turbine, electric equivalent not included in total.
Note 2 - Soot blowing medium is boiler steam. Electric power consumption is negligible.
Note 3 - Includes plant control systems, lighting, HVAC, etc.
A-l-10
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TABLE 2-2
HS PLANT AIR EMISSIONS - 65% CAPACITY FACTOR
sox
NOx
Particulate
Ib/MMBtu
0.46
0.30
0.01
Tons/Year
5,880
3,840
125
The following indicates the state point conditions at various flue gas stream locations;
Flue gas mass flow rate, boiler exit
Flue gas temperature at boiler exit
Flue gas temperature at ESP exit
Flue gas temperature at FGD exit
4,966,633 Ib/hr (1,561,834 acfm)
290 °F
290 °F
128 °F
The flue gas composition and temperatures at various points of the gas stream are detailed in Table 2-3.
This data was calculated using the ACI Mercury Control Cost Model described in Section 3.
2.1.1 Plant Site Ambient Conditions
The plant site is assumed to be in the Ohio River Valley of western Pennsylvania/eastern Ohio/ northern
West Virginia. The site consists of approximately 300 usable acres, not including ash disposal, within 15
miles of a medium sized metropolitan area, with a well established infrastructure capable of supporting the
required construction workforce.
The site is within Seismic Zone 1, as defined by the Uniform Building Code, and the ambient design
conditions will be:
Pressure
Dry bulb temperature
Dry bulb temperature range
Wet bulb temperature
14.4 psia
60 °F
(-)IO to(+) 110°F
52 °F
2.1.2 Fuel and Sorbent Composition
The plant performance will be based on the Pittsburgh #8 Coal and Greer limestone compositions and data
listed in Tables 2-4 and 2-5. Unit start-up will use No.2 fuel oil.
A-l-11
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TABLE 2-3
HIGH SULFUR (HS) REFERENCE POWER PLANT GAS STREAM DATA
Boiler & Plant Data Summary PGH #8 (HS)
Btu Input Rate (MMBtu/h) 4,711.88
Coal Input Rate (tons/h) 188.337
Coal Mass-Energy Ratio (Ib/MMBtu) 79.94
MMBtu/hr Out of Boiler 4,162.49
Flue Gas @ Economizer Outlet (SCFM/MMBtu) 12,503
Flue Gas @ Economizer Outlet (SCFM) 981,877
Wet Flue Gas @ Economizer Outlet (Ib/h) 4,598,641
Wet Air Based on Economizer Outlet (SCFM) 934,407
Wet Air Based on Economizer Outlet (Ib/h) 4,260,670
Total Air, % (Economizer Outlet) 120.0
Excess Air, % (Economizer Outlet) 20.0
Flue Gas @ Air Heater Outlet (SCFM/MMBtu) 13,753
Flue Gas @ Air Heater Outlet (SCFM) 1,080,065
Wet Flue Gas @ Air Heater Outlet (Ib/h) 5,042,924
Wet Air Based on Air Heater Outlet (SCFM) 1,031,843
Wet Air Based on Air Heater Outlet (Ib/h) 4,704,952
Wet Air Leakage @ Air Heater (SCFM) 97,436
Wet Air Leakage @ Air Heater (Ib/h) 444,283
Equivalent Total Air, % (Air Heater Outlet) 132.5
Equivalent Excess Air, % (Air Heater Outlet) 32.5
Wet Flue Gas @ Air Heater Outlet (ACFM) 1,689,826
Air Heater Outlet Flue Gas Temperature, °F 290
Air Heater Outlet Pressure, inches Hg. 29.31
Fly Ash (ton/h) 15.48
Bottom Ash (ton/h) 3.87
Total Ash (ton/h) 19.35
NOTE: Standard Conditions = 60 °F, 29.92 inches Hg
A-l-12
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TABLE 2-4
GREEK LIMESTONE ANALYSIS
Calcium Carbonate, CaCO3
Magnesium Carbonate MgCO3
Silica, SiO2
Aluminum Oxide, A12O3
Iron Oxide, Fe2O3
Sodium Oxide, Na2O
Potassium Oxide, K2O
Balance
Dry Basis. %
80.4
3.5
10.32
3.16
1.24
0.23
0.72
0.43
A-l-13
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TABLE 2-5
PITTSBURGH NO.8 COAL ANALYSIS
Constituent
Carbon
Hydrogen
Nitrogen
Sulfur
Ash
Oxygen
Total
Moisture
Ash
Volatile Matter
Fixed Carbon
Total
Cl, ppm in Coal
Hg, ppb in Coal
Sulfur
Btu Content
Moisture and Ash Free (MAP), Btu
Silica, SiO2
Aluminum Oxide, A1O3
Iron Oxide, Fe2O3
Titanium Dioxide, TiO2
Calcium Oxide, CaO
Magnesium Oxide, MgO
Sodium Oxide, Na2O
Potassium Oxide, K2O
Sulfur Trioxide, SO3
Phosphorous Pentoxide, P2O5
Total
Initial Deformation
Spherical
Hemispherical
Fluid
Air Dry. %
71.88
4.97
1.26
2.99
10.30
8.60
100.00
Dry Basis. %
10.57
38.20
51.23
100.00
650
78 ±24
3.07
13,244
14,810
Ash Analysis. %
48.1
22.3
24.2
1.3
1.3
0.6
0.3
1.5
0.8
0.1
100.5
Ash Fusion Temperature. °F
Reducing
Atmosphere
2015
2135
2225
2450
Dry. % As Received. %
73.79 69.36
4.81 5.18
1.29 1.22
3.07 2.89
10.57 9.94
6.47 11.41
100.00 100.00
As Received. %
6.00
9.94
35.91
48.15
100.00
2.89
12,450
Oxidizing
Atmosphere
2570
2614
2628
2685
A-l-14
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2.1.3
Air Quality Standards
The plant pollution emission requirements for the High Sulfur Reference Case reflect current environmental
emissions standards for a plant sited in a non-attainment area with respect to ambient air standards for
ozone. Table 2-2 presents emissions for the plant without site sensitive NOX reduction enhancements.
2.1.4 Flue Gas Acid Dew Point. 1.4
Based on a flue gas SO3 concentration of 22 ppm and a water concentration of 7.65% at the exit of the air
heater, the acid dew point is estimated to be approximately 280 °F.
2.1.5 Mercury Emission Assumptions
Table 2-6, presented below, provides basic data for baseline and variant mercury emissions.
TABLE 2-6
MERCURY EMISSIONS DATA
Total Mercury
Concentration
Glg/Nm3)
10
(Baseline)
3
30
Total Mercury
Emissions Rate
(g/h)
18.35
5.5
55.05
Total Annual Mercury
Release1
(Kg/yr)
104.4
31.3
313.2
2.2
1. Based on a 65% plant capacity factor.
Low Sulfur Power Plant Reference Case
The low sulfur reference pulverized coal (PC) plant design utilizes a balanced draft, natural circulation type,
pulverized coal subcritical fired boiler, providing steam for a turbine generator set. The boiler design and
performance reflect current commercial practice in the U.S. utility industry. The turbine-generator is a
tandem compound machine, with high pressure (HP), intermediate pressure (IP), and low pressure (LP)
sections. The LP turbine is comprised of two double flow sections exhausting downward into the condenser
sections. The low sulfur reference plant uses a 2400 psig/1000 °F/1000 °F single reheat steam power cycle.
The boiler and the turbine are designed for a main steam flow of 2,734,000 pounds of steam per hour at
2520 psig and 1000 °F at the superheater outlet, throttled to 2415 psia at the inlet to the high pressure
turbine. The cold reheat flow is 2,425,653 Ib/hr of steam at 604 psia and 635 °F, which is reheated to
1000 °F before entering the intermediate pressure turbine section. The net plant output power, after plant
auxiliary power requirements are deducted, is nominally 404 MWe. The overall net plant higher heating
value (HHV) efficiency is nominally 39.1 percent. Refer to Table 2-7 for the plant performance summary
information.
The plant also is designed to meet applicable Federal, State, and Local environmental standards relating to
air, water, solid waste and noise. The plant has baseline SO2 emissions of about 0.70 Ib/MMBtu, and it is
designed to utilize in-duct spray drying of lime to provide a removal efficiency of 50%. Lime slurry is
sprayed into the flue gas duct, where it dries and captures SO2 as a particle. The paniculate is then
collected in the electrostatic precipitator for disposal. If placed in service, the FGD system results in a SO2
emission rate of less than 0.35 Ib/MMBtu; the current investigation assumes that the FGD system will not
be in operation. The use of low NOx burner technology, combined with over-fire air, results in NOX
A-l-15
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emissions of less than 0.30 Ib/MMBtu. The control or reduction of N2O has not been addressed in this
design because N2O levels are presently unregulated.
The low Sulfur Case Reference plant achieves a net plant efficiency of 39.1%, which is an increase of over
6% above that achieved by the High Sulfur Reference plant (36.8%). This increase in efficiency is achieved
although the units are virtually identical in terms of size, boiler selection, steam cycle configuration, heat
sink, and other considerations. The net efficiency improvements are due to the following:
The low sulfur reference auxiliary plant load is lower than the high sulfur plant's auxiliary load.
This reduction occurs because of the reduced ID fan power requirements, which result from the
elimination of the pressure losses due to a scrubber. In addition, elimination of the reagent and
byproduct handling systems associated with a wet scrubber reduce the auxiliary load but is offset
by the atomizing air compressors for the duct injection system.
The low sulfur plant gas temperature leaving the boiler is set at 270 °F versus 290 °F for the high
sulfur plant. This reduction in exhaust temperature, which improves the boiler efficiency, is
feasible because of the low SO2 concentrations in the gas leaving the boiler, and the gas passes
directly into the duct injection system that is upstream of the ESP.
2.2.1 Plant Site Ambient Conditions
The plant site is assumed to be in the Ohio River Valley of western Pennsylvania/eastern Ohio/ northern
West Virginia. The site consists of approximately 300 usable acres; not including ash disposal, within 15
miles of a medium sized metropolitan area, with a well established infrastructure capable of supporting the
required construction workforce. The site is within Seismic Zone 1, as defined by the Uniform Building
Code, and the ambient design conditions will be:
Pressure 14.4 psia
Dry bulb temperature 60 °F
Dry bulb temperature range -10to+110°F
Wet bulb temperature 52 °F
A-l-16
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TABLE 2-7
LOW SULFUR POWER PLANT PERFORMANCE SUMMARY -
100 PERCENT LOAD
STEAM CYCLE
Throttle Pressure, psig
Throttle Temperature, °F
Reheat Outlet Temperature
POWER SUMMARY
3600 rpm Generator
GROSS POWER, kWe (Generator terminals)
AUXILIARY LOAD SUMMARY, kWe
Pulverizers
Primary Air Fans
Forced Draft Fans
Induced Draft
Seal Air Blowers
Main Feed Pump (Note 1)
Steam Turbine Auxiliaries
Condensate Pumps
Circulating Water Pumps
Cooling Tower Fans
Coal Handling
Limestone Handling & Reagent Prep.
Ash Handling
Atomizing Air compressors (Duct Injection)
Precipitators
Soot Blowers (Note 2)
Miscellaneous Balance OF Plant (Note 3)
Transformer Loss
TOTAL AUXILIARIES, kWe
Net Power, kWe
Net Efficiency, %HHV
Net Heat Rate, Btu/kWh (HHV)
CONDENSER COOLING DUTY, 106 Btu/h
CONSUMABLES
As-Received Coal Feed, Ib/h
Sorbent, Ib/h
2,400
1,000
1,000
427,060
1,600
1,410
1,020
3,230
50
8,660
800
800
3,400
1,800
180
230
1,600
2,700
900
neg.
2,000
1,020
22,740
404,320
39.1
8,726
1,722
299,204
4,277
Note 1 - Driven by auxiliary steam turbine, electric equivalent shown.
Note 2 - Soot blowing medium is boiler steam. Electric power consumption is negligible.
Note 3 - Includes plant control systems, lighting HVAC, etc.
A-l-17
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2.2.2 Fuel and Sorbent Composition
The plant performance will be based on a, sub-bituminous, western Powder River Basin (PRB) coal that
has undergone a moisture reduction and stabilization process. The coal analysis and data are listed in
Tables 2-8 and 2-9. Unit start-up will use No.2 fuel oil.
2.2.3 Air Quality Standards
The plant pollution emission requirements for the Low Sulfur Reference Case adhered to Federal and State
control emission regulations. Although, some environmental regulations may apply on a site specific basis
(National Environmental Policy Act, Endangered Species Act, National Historic Preservation Act, etc.) will
not be considered in this project. The following ranges will generally cover most cases:
SOX: 92 to 95% reduction
NOX: 0.2 to 0.45 Ib per MMBtu
Paniculate: 0.015 to 0.03 Ib per MMBtu
Opacity: 10 to 20 percent
2.2.4 Flue Gas Acid Dew Point.
Based on a flue gas SO3 concentration of 0.5 ppm and a water concentration of 6.5% at the exit of the air
heater, the acid dew point is estimated to be approximately 175 °F.
2.2.5 Mercury Emission Assumptions
Table 2-10 provides basic data for baseline and variant mercury emissions.
2.2.6 LS Reference Power Plant Gas Stream Data
The following indicates the state point conditions at various flue gas stream locations.
Flue gas mass flow rate, boiler exit 3,821,126 Ib/hr (1,309,735 cfrn)
Flue gas temperature at AH exit 270 °F
Flue gas temperature at ESP exit 270 °F
The flue gas composition and temperatures at various points of the gas stream are detailed in Table 2-11.
This data was calculated using the MCPCM described in Section 1 and coal properties for a low sulfur
processed derived PRB coal.
A-l-18
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TABLE 2-8
TYPICAL PROCESSED PRB COAL ANALYSIS
Constituent
Carbon
Hydrogen
Nitrogen
Sulfur
Ash
Oxygen
Total
Moisture
Ash
Volatile Matter
Fixed Carbon
Total
Sulfur
Btu Content
Moisture and Ash Free (MAP), Btu Content
Silica, SiO2
Aluminum Oxide, Al
Iron Oxide,
Titanium Dioxide, TiO2
Calcium Oxide, MgO
Magnesium Oxide, MgO
Sodium Oxide, Na2O
Potassium Oxide, K2O
Sulfur Trioxide, SO3
Phosphorous Pentoxide, P2O5
Strontium Oxide, SrO
Barium Oxide, BaO
Manganese Oxide, Mri4
Total
Ash Fusion Temperature. "F
Initial Deformation
Spherical
Hemispherical
Drv. % As Received. %
75.25 70.98
3.46 4.00
1.13 1.07
0.56 0.53
8.19 7.72
11.41 15.70
100.00 100.00
Drv Basis, % As Received. %
4.83
8.19 7.72
27.00 25.72
64.81 61.73
100.00 100.00
0.56 0.53
12,389 11,791
13,494
Ash Analysis, %
22.5
13.8
7.4
0.8
26.6
5.9
1.8
0.2
19.3
0.6
0.4
0.6
0.1
100.00
Reducing Oxidizing
Atmosphere Atmosphere
2295 2395
2300 2405
2305 2415
2310 2425
A-l-19
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TABLE 2-9
COMPARISON OF FEED COAL AND MODIFIED COAL BASIS
Heating Value (Btu/lb)
Carbon (%)
Hydrogen (%)
Nitrogen (%)
Volatiles (%)
Feed Coal
12,740
73.4
5.5
1.1
47.0
Process Derived Fuel
13,840
84.0
3.6
1.3
32.0
TABLE 2-10
MERCURY EMISSIONS DATA
Total Mercury
Concentration
Glg/Nm3)
10
(Baseline)
3
30
Total Mercury
Emissions Rate
(g/Hr)
13.8
3.5
138
Total Annual Mercury
Release1
(Kg/Yr)
78.5
23.5
235.5
1. Based on a 65% plant capacity factor.
A-1-20
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TABLE 2-11
LS REFERENCE POWER PLANT GAS STREAM DATA
Boiler & Plant Data Summary LS PDF (LS)
Btu Input Rate (MMBtu/h) 3,528.10
Coal Input Rate (tons/h) 150.739
Coal Mass-Energy Ratio (Ib/MMBtu) 85.45
MMBtu/hr Out of Boiler 3,119.59
Flue Gas @ Economizer Outlet (SCFM/MMBtu) 12,656
Flue Gas @ Economizer Outlet (SCFM) 744,192
Wet Flue Gas @ Economizer Outlet (Ib/h) 3,518,066
Wet Air Based on Economizer Outlet (SCFM) 710,817
Wet Air Based on Economizer Outlet (Ib/h) 3,241,152
Total Air, % (Economizer Outlet) 120.0
Excess Air, % (Economizer Outlet) 20.0
Flue Gas @ Air Heater Outlet (SCFM/MMBtu) 13,795
Flue Gas @ Air Heater Outlet (SCFM) 811,169
Wet Flue Gas @ Air Heater Outlet (Ib/h) 3,821,126
Wet Air Based on Air Heater Outlet (SCFM) 777,281
Wet Air Based on Air Heater Outlet (Ib/h) 3,544,213
Wet Air Leakage @ Air Heater (SCFM) 66,464
Wet Air Leakage @ Air Heater (Ib/h) 303,061
Equivalent Total Air, % (Air Heater Outlet) 131.2
Equivalent Excess Air, % (Air Heater Outlet) 31.2
Wet Flue Gas @ Air Heater Outlet (ACFM) 1,309,735
Air Heater Outlet Flue Gas Temperature, °F 314
Air Heater Outlet Pressure, inches Hg. 29.31
Fly Ash (ton/h) 9.83
Bottom Ash (ton/h) 2.46
Total Ash (ton/h) 12.28
NOTE: Standard Conditions = 60 °F, 29.92 inches Hg
A-l-21
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3.
Bituminous and Subbituminous Coals Used in Mercury Control Model Runs
EPA's mercury control technology application matrix cites three different coals for the model runs. The
purpose of this section is to identify and document these three coals.
The two bituminous coals are from West Virginia - ultimate analysis and ash analysis data were obtained
from the USGS Coal Quality Database. The high sulfur coal has a 3% sulfur content (by weight) and a
HHV of 12,721 Btu/Lb, while the other has a 0.6% S content (by weight) and a HHV of 14,224 Btu/Lb.
The subbituminous coal is from Wyoming's Powder River Basin (PRB) and was already contained in the
model's coal library. Data originally came from EPRI's FGD Cost Program. This coal has a coal sulfur
content of 0.5% (by weight) and a HHV of 8,335 Btu/Lb.
TABLE 3-1
Bituminous and Subbituminous Coals Used in Mercury Control Model Runs
WYOMING PRB (LS) E. Bituminous (HS)
COAL ULTIMATE ANALYSIS
(ASTM, as received, weight percent)
E. Bituminous (LS)
Moisture
Carbon
Hydrogen
Nitrogen
Chlorine
Sulfur
Ash
Oxygen
TOTAL
30.40%
47.85%
3.40%
0.62%
0.03%
0.48%
6.40%
10.82%
100.00%
3.10%
69.82%
5.00%
1.26%
0.12%
3.00%
9.00%
8.70%
100.00%
2.20%
78.48%
5.50%
1.30%
0.12%
0.60%
3.80%
8.00%
100.00%
Mott Spooner HHV (Btu/lb)
Acid Dew Point, °F
8,335
224
12,721
215
14,224
292
COAL ASH ANALYSIS
WYOMING PRB (LS) E. Bituminous (HS)
E. Bituminous (LS)
SiO2 31.60%
A12O3 15.30%
TiO2 1.10%
Fe2O3 4.60%
CaO 22.80%
MgO 4.70%
Na2O 1.30%
K2O 0.40%
P2O5 0.80%
SOS 16.60%
Other Unaccounted for 0.80%
TOTAL 100.00%
29.00%
17.00%
0.74%
36.00%
6.50%
0.83%
0.20%
1.20%
0.22%
7.30%
1.01%
100.00%
51.00%
30.00%
1.50%
5.60%
4.20%
0.76%
1.40%
0.40%
1.80%
2.60%
0.74%
100.00%
A-1-22
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4. COST ESTIMATION BASIS
4.1 Introduction
This section defines the methodology used to estimate capital and O&M costs within the NETL Mercury
Control Performance and Cost Model. Two different spreadsheets within the model provide for cost
estimation. The Capital Cost Model Sheet makes use of the power plant and mercury control performance
data to calculate the capital costs associated with a case study's mercury control design configuration. The
costing covers the following equipment sections:
Spray Cooling Water System (Equipment: water storage tank, pumps, transport piping, and
injection grid with nozzles, and control system)
Solid Sorbent Storage and Injection System (Equipment: silo pneumatic loading system,
storage silos, hoppers, blowers, transport piping, control system)
Sorbent Recycle System (Equipment: hoppers, blowers, transport piping, control system)
Pulse-Jet Fabric Filter and Accessories (Equipment: pulse-jet FF, filter bags, ductwork, dampers,
andMCCs and instrumentation and PLC controls for baghouse operation. Excludes Ash Removal
System, power distribution and power supply, and distributed control system)
Sorbent Disposal System (Equipment: hoppers, blowers, transport piping, control system)
CEMS Upgrade
Flue Gas Desulfurization (FGD) System (cost algorithms are currently not provided)
FGD System Enhancements (cost algorithms are currently not provided)
Circulating Fluidized Bed Absorber System (cost algorithms are currently not provided)
A total mercury control system cost is calculated from the following cost components: 1) equipment, 2)
related materials, 3) field and indirect labor, 4) sales tax, 5) engineering and home office fees, 6) process
and project contingencies, 7) retrofit factors, and 9) general facilities. Maintenance costs are also calculated
as a percentage of the bare erected cost (e.g., 2%). Section 4.2 fully describes the methodology used to
estimate the total installed retrofit capital cost. Section 4.3 defines specific algorithms used calculate
specific equipment and installation labor costs.
The System Economic Model Sheet calculates mercury control system O&M, total system investment,
total system capital requirement, and then levelizes the capital and O&M to establish single value for $/lb of
mercury removed. Twenty case studies are handled simultaneously in this sheet. Sections 4.4 and 4.5 fully
describe the methodology used to estimate these costs.
4.2 Capital Cost Estimation Basis
The cost of each equipment section, as identified in Section 4.1, is estimated according to the following
procedure:
Bare Installed Retrofit Cost = (Process Equipment + Related Field Materials + Field Labor +
Indirect Field Costs + Sales Tax) x Retrofit Factor
Equipment, field materials and field labor are specified via algorithms.
A-1-23
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Indirect field costs are calculated as percentage of field labor (7% currently specified).
Sales tax is calculated as a percentage of the sum of the four cost elements (0% currently
specified)
Retrofit Factor (accounts for retrofit difficulty) = 1.15 (Specified by EPA on 4/4/00)
Engineering & Home Office Overhead/Fees = Bare Installed Retrofit Cost x E&HO Percentage
EH&O Percentage = 10% (Specified by EPA on 4/4/00)
Process Contingency = Bare Installed Retrofit Cost x Process Contingency Percentage
Process Contingency Percentage = 5% (Specified by EPA on 4/4/00)
Project Contingency = (Bare Installed Retrofit Cost + Engineering & Home Office
Overhead/Fees + Process Contingency) x Project Contingency Percentage
Project Contingency Percentage = 15% (Specified by EPA on 4/4/00)
Total Cost of Each Equipment Section = Bare Installed Retrofit Cost + Engineering & Home
Office Overhead/Fees + Process Contingency + Project Contingency
The total capital cost of the mercury control system is calculated to include the sum of all equipment
sections and the total cost of general facilities as follows:
General Facilities Cost = (Bare Installed Retrofit Cost x General Facilities Percentage
General Facilities Percentage = 5% (Specified by EPA on 4/4/00)
Project Contingency Percentage defined above
Total Control Capital Cost = Sum of Equipment Section Total Costs + General Facilities Cost
4.3 Equipment and Installation Labor Cost Estimation
This section of the memo defines the equipment cost algorithms used in the Capital Cost Model Sheet.
Each equipment section is defined separately below. Costs are updated from their baseline year values via
use of the Chemical Engineering Annual Plant Index (CEI). The costing algorithms relate to a December
1998 baseline for which the CI value equals 389.5. The ratio of the current index value (e.g., December
1999) and the baseline value therefore yields a cost inflator that adjusts control costs to the specified year.
4.3.1 Spray Cooling Water System
Process Equipment (x $1000). $E
$E = 1900 x (GPM/215)065 x CEI/389.5
GPM = Water flow in gallons/minute
Field Materials (x $1000). $FM
$FM = 1700 x (GPM/215)065 x CEI/389.5
A-1-24
-------
Field Labor (x $1000). $FL
$FL = 1500 x (GPM/215)065 x CEI/389.5
Indirect Field Costs (x $1000). $IF
$IF = $FL x 0.07
Bare Installed Cost (x $1000) = $E + $FM + $FL + $IF
Example: GPM = 27.4 gpm (Cools flue gas from 290 F to 270 F, 472 MWe,net)
CEI = 399.7 (November 1999)
Bare Installed Cost (x $1000) = 511 + 457+ 404 + 28 = 1,611 or $3.41/kW
4.3.2 Solid Sorbent Injection System
Process Equipment (x $1000). $E
$E = 400 x ((SF x 1000/454)75486)°65 x CEI/389.5
SF = Sorbent Feed, Kg/Hr
Field Materials (x $1000). $FM
$FM = 900 x ((SF x 1000/454)/5486)065 x CEI/389.5
Field Labor (x $1000). $FL
$FL = 2600 x ((SF x 1000/454)/5486)065 x CEI/389.5
Indirect Field Costs (x $1000). $IF
$IF = $FL x 0.07
Bare Installed Cost (x $1000) = $E + $FM + $FL + $IF
Example: SF = 157 Kg/Hr (Based on 3.73 Ib/MMacf, 472 MWe,net)
CEI = 399.7 (November 1999)
Bare Installed Cost (x $1000) = 68+ 153 + 442 + 31 = 799 or $1.69/kW
4.3.3 Sorbent Recycle System
Process Equipment (x $1000). $E
$E = 1200 x (RR/13) x CEI/389.5
RR = Recycle (sorbent and ash), Tons/Hr
Field Materials (x $1000). $FM
A-1-25
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$FM = $E
Field Labor (x $1000). $FL
$FL = $E
Indirect Field Costs (x $1000). $IF
$IF = $FL x 0.07
Bare Installed Cost (x $1000) = $E + $FM + $FL + $IF
4.3.4 Pulse-Jet Fabric Filter and Accessories
Process Equipment (x $1000). $E
$E = 4800 x ((GFR/ACR)/84,326))080 x CEI/389.5
GFR = Flue Gas Flow Rate, acfm
ACR = PJFF air/clothi
Field Materials (x $1000). $FM
ACR = PJFF air/cloth ratio, ft3/min/ft2
$FM = 500 x ((GFR/ACR)/84,326))080 x CEI/389.5
Field Labor (x $1000). $FL
$FL = 2700 x ((GFR/ACR)/84,326))080 x CEI/389.5
Indirect Field Costs (x $1000). $IF
$IF = $FL x 0.07
Bare Installed Cost (x $1000) = $E + $FM + $FL + $IF
Example: GFR = 1,547,360 acfm (Based on 472 MWe,net)
ACR = 10 ftVmin/ft2
CEI = 399.7 (November 1999)
Bare Installed Cost (x $1000) = 8,006+ 834 + 4,503 + 315 = 15,707 or $33/kW
4.3.5 Sorbent Disposal System
Process Equipment (x $1000). $E
$E = 100 x (DS/6) x CEI/389.5
DS = Disposal Solids (spent sorbent and ash), Tons/Hr
Field Materials (x $1000). $FM
A-1-26
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$FM = 2 x $E
Field Labor (x $1000). $FL
$FL = 6 x $E
Indirect Field Costs (x $1000). $IF
$IF = $FL x 0.07
Bare Installed Cost (x $1000) = $E + $FM + $FL + $IF
4.3.6 CEMS Upgrade
Process Equipment (x $1000). $E
$E = 10 x (MW/290.4)075 x CEI/389.5
MW = Power Plant Application Net Capacity, MWe,net
Field Materials (x $1000). $FM
$FM = 0
Field Labor (x $1000). $FL
$FL= 1.2 x$E
Indirect Field Costs (x $1000). $IF
$IF = $FL x 0.07
Bare Installed Cost (x $1000) = $E + $FM + $FL + $IF
4.4 Mercury Control System O&M Cost Estimation
4.4.1 O&M Cost Parameters
The O&M cost consists of the following labor and maintenance components:
Operating Labor: cost of system operating and administrative personnel; unit labor rates and
manpower requirements/shift are specified in the case study O&M table and can be specified
independently for each case study.
Maintenance Labor: 40% of the total maintenance cost calculated in the Capital Cost Model
Sheet
Maintenance Material: 60% of the total maintenance cost calculated in the Capital Cost Model
Sheet
Administrative and Support Labor: Calculated as a percentage (labor overhead charge rate) of
the sum of the operating and maintenance labor cost; overhead charge specified in the case study
O&M table and can be specified independently for each case study.
A-1-27
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Consumable values are taken from the Technical Model Results Sheet. The O&M cost consists of the
following consumable components:
Water (for flue gas humidification), gallons/Hr: unit cost = S/1000 gallons (e.g., 0.80),
specified in case study table
Water quantity is taken from Combustion Calculations Sheet.
Sorbent (e.g., Activated Carbon), tons /Hr: unit cost = $/ton (e.g., 1,100), specified in case study
table
Sorbent unit cost is an input in the Application Input Sensitivity Sheet
Incremental Power, kW-Hr: unit cost = $/MW-Hr (e.g., 30), specified in case study table
Fan power accounts for the added pressure drop across the mercury control equipment, such as the
fabric filter. AC injection system power required to transport sorbent to flue gas duct.
Humidification system power required to pump water to an injection grid in the ductwork.
Waste Disposal, tons/Hr: unit cost = S/ton (e.g., 30), specified in case study table
Waste sorbent is generated by the mercury control system. This mercury-laden sorbent must be disposed of
or processed for mercury removal and recovery. For some design configurations, spent sorbent is captured
with the fly ash and must be disposed of with the ash at the cost of ash disposal. For some design
configurations, spent sorbent is collected with residual ash from the ESP. This material can be disposed of
with the rest of the plant's fly ash or it can be processed separately if deemed a hazardous material.
The user specifies sorbent to be hazardous or non-hazardous in the Application Input Sensitivity
Sheet. Unit costs for both conventional and hazardous waste disposal are also specified there.
Mercury Byproduct, Ib/Hr: unit cost = $/ton (e.g., 30), specified in case study table
If the spent sorbent is processed for recovery of mercury, then a by-product credit can be applied.
This will be applied only if the user has designated the spent AC as hazardous waste material.
4.4.2 Key O&M Cost Parameter Values
Labor:
Operating Labor Rate (base) - $25/Hr (specified by EPA 4/4/00)
Total Operating Jobs - 0.833 OJ/Shift
Consumables:
Water - 0.42 Mills/gallon (specified by EPA 4/4/00)
Activated Carbon - $l/Kg (specified by EPA 4/4/00)
Sorbent Storage Capacity - 30 days (specified by EPA 4/4/00)
Electricity - 25 Mills/kW-Hr (specified by EPA 4/4/00)
Waste Disposal (ash, AC, mercury) - $30/Ton
Waste Disposal (Hazardous waste designation) ~ $1700/Ton
Plant Capacity Factor - 65% (specified by EPA 4/4/00)
4.5 Total Mercury Control System Capital Requirement
A-1-28
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The total calculated investment in the mercury control system includes the total capital investment
calculated in the Capital Cost Model Sheet, interest during construction (AFUDC), and the following
additional cost components:
Royalty allowance ~ possible technology royalty charges may apply
Preproduction Costs ~ covers the cost of operator training, equipment checkout, major
modifications to equipment, extra maintenance, and inefficient use of consumables. Calculated as
1 month of fixed operating costs (O&M labor, admin and support labor, and maintenance
materials); 1 month of variable operating costs (all consumables) at full capacity; and 2 % of the
total system investment.
Inventory Capital - value of initial inventory of activated carbon that is capitalized. This
accounts for an initial storage supply of AC (e.g., 30 day supply).
Initial Catalysts and Chemicals Charge - the initial cost of any catalysts or chemicals contained
in the process equipment, but not in storage. Does not apply to the mercury control systems.
4.5.1 Levelized Cost of Mercury Control
The total cost of mercury control must account for the total capital requirement (expressed as $/kW) and the
total operating and maintenance expenses (expressed as mills/kW-Hr). In order to calculate an annualized
cost that accounts for both of these, the capital requirement is annuitized via use of the "Levelized Carrying
Charge Rate." The Levelized Carrying Charge Rate assumes a 30 year operating period and accounts for
return on debt, return on equity, income taxes, book depreciation, property tax, and insurance payments.
The Levelized Carrying Charge Rate is specified in this sheet in the section called "Financial Data-Factors."
It is multiplied times the total system capital requirement to derive the annualized value and converted to
units of mills/kW-Hr based on the annual operating hours of the plant (capacity factor x 8,760 hrs/yr).
The first-year O&M costs that are calculated in this sheet are also levelized in order to account for both
apparent and real escalation rates of labor, materials, and consumables over the expected operating time
period (e.g., 30 years). A levelization factor is specified in this sheet in the section called "Financial
Data-Factors." It is multiplied by the total O&M cost.
The levelized carrying charge and the levelized O&M are summed to yield a total annualized cost which is
divided by the annual mercury removed in order to derive a unique cost of removal with units of $/ton
mercury removed.
4.5.2 Financial Parameter Values
Apparent General Escalation Rate - 2.9%/Year
Royalty Allowance ~ $0
Levelized Carrying Charge Rate - 0.133
Federal Income Tax Rate - 34%
Weighted Cost of Capital (after tax) - 9.4%
Design and Construction - 1 year
Book Life - 30 Years
A-1-29
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ATTACHMENT 2
Description of
Mercury Control Performance Algorithms Used in the
National Energy Technology Laboratory
Mercury Control Performance and Cost Model
A-2-i
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Description of Mercury Control Performance Algorithms Used in the
NETL Mercury Control Performance and Cost Model
The purpose of this report is to document the mercury control performance models that are currently incorporated
into the NETL Mercury Control Cost Model. CMU staff based on available pilot- and full-scale data has developed
these models, in the form of basic curve-fitting algorithms. The algorithms calculate the activated carbon feed
(Lb/MMacf basis) required to achieve specified mercury removal efficiency for a particular control method (e.g.,
activated carbon injection upstream of an existing ESP). The performance prediction is based solely on control
method, flue gas temperature and coal type (bituminous vs. subbituminous).
1. Mercury Control Retrofit Configurations: ESP-1, ESP-4, SD/ESP-1, and SD/ESP-2
Description: Activated carbon injected upstream of existing ESP. ESP-1 ~ no flue gas temperature
control, ESP-4 - flue gas temperature control via water injection.
1.1 Bituminous Coal
Coal Source: Eastern bituminous coal, West Virginia (< 1%S and 0.1% chlorine)
Data Sources:
PROJECT: ADA Technologies/Public Service Electric and Gas Company/EPRI - Mercury Control
in Utility ESPs and Baghouses through Dry Carbon-Based Sorbent Injection Pilot-Scale
Demonstration
Pilot-Scale Tests: 160 acfm slipstream from the 620 MWe Hudson Generating Station, Unit 2,
opposed-fired furnace, Eastern bituminous coal from West Virginia (< 1%S and 0.1% chlorine), ESP
SCA = 287 ft2/Kacfm
Literature Source: Waugh, E., B. Jensen, L. Lapatnick, F. Gibbons, S. Sjostrom, J. Ruhl, R. Slye,
and R. Chang, "Mercury Control in Utility ESPs and Baghouses through Dry Carbon-Based Sorbent
Injection Pilot-Scale Demonstration," EPRI-DOE-EPA Combined Utility Air Pollutant Control
Symposium, August 1997.
ICR Data: Baseline removal due to ash alone is from preliminary ICR report data compiled by
Dennis Smith, DOE/NETL (5/1/00)
Low sulfur bit coal ash removes constant 57% mercury
Total removal is 57% from ash and 0 ==> 43% from ACI
Baseline mercury removal (ash alone) is an average of 2 plants with 250F inlet and 4
plants with >300F inlet, both approximately 57%
Correlation for 225F not included; no baseline removal available and temperature below
H2SO4 dewpoint.
ICR Results and Pilot-Scale Test Results Combined:
Mercury removal due to ash for both temperatures is 57% and is not a function of ACI
Mercury removal due to ACI is not a function of ash but is a function of temperature
The two removals can be combined: 57% from ash and between 0% and 43% from ACI
A-2-1
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Algorithm 1: Incorporates ICR Results
Hg Removal = 100 - [a/(ACI+b)c
Coefficient
Flue Gas Temperature, "F
a
b
c
RA2 (error)
ACI Range
(Lb/MMacf)
225
55.536
1.4351
1
0.99
0-5
250
159.27
3.6838
1
0.85
0-5
275
494.64
11.554
1
0.82
0-5
Algorithm 2: Excludes ICR Results
Hg Removal = 100 - [a/(ACI+b)c
Coefficient
Flue Gas Temperature, "F
Where,
a
b
c
RA2 (error)
ACI Range
(Lb/MMacf)
225
128.69
1.4284
1
0.99
0-5
250
370.98
3.6937
1
0.85
0-5
275
1218.6
12.14
1
0.89
0-5
a,b,c = numerical coefficients
ACI = Activated Carbon Injection Feed rate, Lb/MMacf
Hg Removal = % total mercury removed, inlet to outlet
1.2 Subbituminous Coal
Coal Source: PRB Subbituminous coal
Data Source:
PROJECT:
Pilot-Scale Carbon Injection for Mercury Control at Comanche Station
Pilot-Scale Tests: 600 acfm slipstream from the 350 MWe Comanche Station, Unit 2 PSCo,
opposed-fired furnace, PRB coal from Belle Ayr mine, Pulse-Jet with A/C ratio = 12 ft/min, most
fly ash removed upstream, Flue gas contained little HC1, 275 to 325 ppm SO2 (@ 3% O2 dry), 180
to 250 ppm NOX (@ 3% O2 dry)
Literature Source: AWMA 99-524, S.M. Haythornthwaite, J. Smith, G. Anderson, T. Hunt, M.
Fox, R. Chang, T. Brown, 1999
A-2-2
-------
Algorithm:
Hg Removal = 100 - [a/(ACI+b)c
Coefficient Flue Gas Temperature, "F
a
b
c
RA2 (error)
ACI Range
(Lb/MMacf)
230
1373.11
32.1071
1
0-1
280
247.772
3.3867
1
0.89
0-5
300
296.714
4.2911
1
0.84
0-5
345
319.587
3.6636
1
0.83
0-5
Where, a,b,c = numerical coefficients
ACI = Activated Carbon Injection Feed rate, Lb/MMacf
Hg Removal = % total mercury removed, inlet to outlet
2. Mercury Control Retrofit Configurations: ESP-3, ESP-6
Description: Pulse-Jet FF (PJFF) retrofitted after existing ESP. Activated carbon injected upstream of PJFF.
ESP-3 - no flue gas temperature control, ESP-6 ~ flue gas temperature control via water
injection.
2.1 Bituminous Coal
Coal Source: Eastern bituminous coal, West Virginia (< 1%S and 0.1% chlorine)
Data Source:
PROJECT: ADA Technologies/Public Service Electric and Gas Company/EPRI - Mercury
Control in Utility ESPs and Baghouses through Dry Carbon-Based Sorbent Injection
Pilot-Scale Demonstration
Pilot-Scale Tests: 4,000 acfm slipstream from the 620 MWe Hudson Generating Station, Unit 2,
opposed-fired furnace, Eastern bituminous coal from West Virginia (< 1%S and 0.1% chlorine),
Pulse-jet FF installed downstream of cold ESP. A/C ratio =12 ft/min, tests conducted with AC and
fly ash
Literature Source: Waugh, E., B. Jensen, L. Lapatnick, F. Gibbons, S. Sjostrom, J. Ruhl, R. Slye,
and R. Chang, "Mercury Control in Utility ESPs and Baghouses through Dry Carbon-Based
Sorbent Injection Pilot-Scale Demonstration," EPRI-DOE-EPA Combined Utility Air Pollutant
Control Symposium, August 1997.
ICR Results and Pilot-Scale Test Results Combined:
Mercury removal due to ash for both temperatures is 57% and is not a function of ACI
Mercury removal due to ACI is not a function of ash but is a function of temperature
The two removals can be combined: 57% from ash and between 0% and 43% from ACI
A-2-3
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Algorithm 1: Incorporates ICR Results
Hg Removal = 100 - [a/(ACI+b)c
Coefficient
Flue Gas Temperature, "F
a
b
c
RA2 (error)
ACI Range
(Lb/MMacf)
240
51.038
1.3194
1
0.73
0-5
285
159.4
3.5606
1
0.66
0-5
285
159.4
3.5606
1
0.66
0-5
Where,
a,b,c = numerical coefficients
ACI = Activated Carbon Injection Feed rate, Lb/MMacf
Hg Removal = % total mercury removed, inlet to outlet
Algorithm 2: Excludes ICR Results
Hg Removal = 100 - [a/(ACI+b)c
Coefficient
Flue Gas Temperature, "F
a
b
c
RA2 (error)
ACI Range
(Lb/MMacf)
240
118.69
1.3194
1
0.73
0-5
285
370.69
3.5606
1
0.66
0-5
Where,
a,b,c = numerical coefficients
ACI = Activated Carbon Injection Feed rate, Lb/MMacf
Hg Removal = % total mercury removed, inlet to outlet
2.2 Subbituminous Coal
Coal Source: PRB Subbituminous coal
Data Source:
PROJECT: ADA Technologies/PS Colorado/EPRI/NETL - Pilot-Scale Demonstration of Dry
Carbon-Based Sorbent Injection for Hg Control in Utility ESPs and FFs - Phase I
Pilot-Scale Tests: 600 acfm slipstream from the 350 MWe Comanche Station, Unit 2 PSCo,
opposed-fired furnace, PRB coal from Belle Ayr mine, Pulse-Jet with A/C ratio = 12 ft/min, most
fly ash removed upstream, Flue gas contained little HC1, 275 to 325 ppm SO2 (@ 3% O2 dry), 180
to 250 ppm NOX (@ 3% O2 dry)
Literature Source: Ebner, T., J. Ruhl, R. Slye, J. Smith, T. Hunt, R. Chang, and T. Brown, "
Demonstration of Dry Carbon-Based Sorbent Injection for Mercury Control in Utility ESPs and
Baghouses," EPRI-DOE-EPA Combined Utility Air Pollutant Control Symposium, August 1997.
A-2-4
-------
Algorithm:
Hg Removal = 100 - [a/(ACI+b)c
Coefficient
Flue Gas Temperature, "F
a
b
c
RA2 (error)
ACI Range
(Lb/MMacf)
250
4.2774
0.04793
1
0.99
0-3
280
27.5595
0.31345
1
0.8
0-3
300
148.0419
0.92051
1
0.96
0-3
Where, a,b,c = numerical coefficients
ACI = Activated Carbon Injection Feed rate, Lb/MMacf
Hg Removal = % total mercury removed, inlet to outlet
3. Mercury Control Retrofit Configurations: FF-1, FF-2, SD/FF-1, and SD/FF-2
Description: Activated carbon injected upstream of existing reverse-gas baghouse. FF-1 - no flue gas
temperature control, FF-2 - flue gas temperature control via water injection.
3.1 Bituminous Coal
No data for bituminous coal applications.
3.2 Subbituminous Coal
Coal Source: PRB coal from Belle Ayr mine
Data Source:
PROJECT: ADA Technologies/PS Colorado/EPRI/NETL - Pilot-Scale Demonstration of Dry
Carbon-Based Sorbent Injection for Hg Control in Utility ESPs and FFs
Pilot-Scale Tests: 600 acfm slipstream from the 350 MWe Comanche Station, Unit 2 PSCo,
opposed-fired furnace, PRB coal from Belle Ayr mine, Flue gas contained little HC1, 275 to 325
ppm SO2 (@ 3% O2 dry), 180 to 250 ppm NOX (@ 3% O2 dry)
Literature Source: AWMA 99-524, S.M. Haythornthwaite, J. Smith, G. Anderson, T. Hunt, M.
Fox, R. Chang, T. Brown, 1999
A-2-5
-------
Algorithm:
Hg Removal = 100 - [a/(ACI+b)c
Coefficient
Flue Gas Temperature, "F
a
b
c
RA2 (error)
ACI Range
(Lb/MMacf)
230
266.119
11.1359
1
0.03
0-1
275
23.20196
0.43006
1
0.88
0-5
330
27.9742
0.31913
1
0.87
0-5
Where, a,b,c = numerical coefficients
ACI = Activated Carbon Injection Feed rate, Lb/MMacf
Hg Removal = % total mercury removed, inlet to outlet
4. Mercury Control Retrofit Configurations: WS-1
Description: Existing ESP for paniculate control and wet FGD for SO2 control.
4.1 Bituminous Coal
Coal Source: Bituminous coal
Data Source:
Mercury Speciation and Wet FGD removal: Memo from D. Smith, DOE/NETL, 4/29/2000
Methodology:
Hg speciation for Bituminous coal: 70% oxidized, 30% elemental
Existing ESP assumed to remove Hg at rate predicted by ESP-1, ESP-4 algorithm for
bituminous coal (Section 1.1)
Wet FGD removes 100% of oxidized Hg and 0% elemental Hg
4.2 Subbituminous Coal
Coal Source: Subbituminous coal
Data Source:
Mercury Speciation and Wet FGD removal: Memo from D. Smith, DOE/NETL, 4/29/2000
Methodology:
Hg speciation for Subbituminous coal: 25% oxidized, 75% elemental
Existing ESP assumed to remove Hg at rate predicted by ESP-1, ESP-4 algorithm for
Subbituminous coal (Section 1.2)
Wet FGD removes 100% of oxidized Hg and 0% elemental Hg
A-2-6
-------
5. Mercury Control Retrofit Configurations: WS-2
Description: Existing SNCR for NOx control, existing ESP for paniculate control and wet FGD for SO2
control.
5.1 Bituminous Coal
Coal Source: Bituminous coal
Data Source:
Mercury Speciation and Wet FGD removal: Memo from D. Smith, DOE/NETL, 4/29/2000
Impact of SNCR: Not specified
Methodology:
Hg speciation for Bituminous coal: 70% oxidized, 30% elemental
Existing ESP assumed to remove Hg at rate predicted by ESP-1, ESP-4 algorithm
(Section 1.1)
SNCR installation increases oxidized Hg by 0% (e.g., 70% total)
Wet FGD removes 100% of oxidized Hg and 0% elemental Hg
5.2 Subbituminous Coal
Coal Source: Subbituminous coal
Data Source:
Mercury Speciation and Wet FGD removal: Memo from D. Smith, DOE/NETL, 4/29/2000
Impact of SNCR: Not specified
Methodology:
Hg speciation for Subbituminous coal: 25% oxidized, 75% elemental
Existing ESP assumed to remove Hg at rate predicted by ESP-1, ESP-4 algorithm for
Subbituminous coal (Section 1.2)
SNCR installation increases oxidized Hg by 0% (e.g., 25% total)
Wet FGD removes 100% of oxidized Hg and 0% elemental Hg
6. Mercury Control Retrofit Configurations: WS-3
Description: Existing SCR for NOx control, existing ESP for paniculate control and wet FGD for SO2
control.
6.1 Bituminous Coal
Coal Source: Bituminous coal
Data Source:
Mercury Speciation and Wet FGD removal: Memo from D. Smith, DOE/NETL, 4/29/2000
Impact of SCR: Mercury control phone meeting 4/28/2000
Methodology:
Hg speciation for Bituminous coal: 70% oxidized, 30% elemental
Existing ESP assumed to remove Hg at rate predicted by ESP-1, ESP-4 algorithm
(Section 1.1)
SCR installation increases oxidized Hg by 35% (e.g., 94.5% total)
Wet FGD removes 100% of oxidized Hg and 0% elemental Hg
A-2-7
-------
6.2 Subbituminous Coal
Coal Source: Subbituminous coal
Data Source:
Mercury Speciation and Wet FGD removal: Memo from D. Smith, DOE/NETL, 4/29/2000
Impact of SCR: Mercury control phone meeting 4/28/2000
Methodology:
Hg speciation for Subbituminous coal: 25% oxidized, 75% elemental
Existing ESP assumed to remove Hg at rate predicted by ESP-1, ESP-4 algorithm for
Subbituminous coal (Section 1.2)
SCR installation increases oxidized Hg by 35% (e.g., 33.75% total)
Wet FGD removes 100% of oxidized Hg and 0% elemental Hg
7. Mercury Control Retrofit Configurations: ESP-7, Combined AC + Lime Sorbent
Description: Pulse-Jet FF (PJFF) retrofitted after existing ESP. Combined activated carbon/Lime sorbent
injected upstream of PJFF.
7.1 Bituminous Coal
Coal Source: Bituminous coal
Data Source:
Butz, J.R., R. Chang, E.G. Waugh, "Use of Sorbents for Air Toxics Control in a Pilot-Scale
COHPAC Baghouse," paper presented at the Air and Waste Management Association's 92nd
annual meeting and exhibition, June 20-24, 1999, St. Louis, Mo.
Methodology:
Assumes AC:Lime ratio = 2:19
Assume 90%+ Hg Removal based on ADA Technologies tests at PSE&G
1- 4 Ib/MMacf Sorbent Concentration yields 90-95% Hg Removal
A-2-8
-------
ATTACHMENT 3
Summary of Mercury Control Cases Analyzed with National
Energy Technology Laboratory
Mercury Control Performance and Cost Model
A-3-i
-------
Summary of Mercury Control Cases Analyzed with NETL's Mercury Control
Performance and Cost Model
The purpose of this document is to summarize the mercury control cases evaluated with NETL's Mercury
Control Performance and Cost Model.
1. Original Cases Designated by EPA
Table 1 identifies the original matrix of cases that were designated by EPA for evaluation. Of those
designated in the table, the following model plant types were actually evaluated: 1, 4, 7, 8, 10, 13, 16, and
17. The others were not assessed due to lack of control performance data or similarity to another model
plant type. Table 2 describes the mercury control retrofit scenario configurations used in Table 1.
2. EPA Evaluation Requirements
For each combination of model plant and pertinent mercury control technology (see Tables 1 and 2), EPA
requested estimates of capital cost ($/kW), fixed O&M cost (mills/kWh), and variable O&M cost
(mills/kWh) using the EPRI TAG methodology. These cost estimates were in 1999 constant dollars. EPA
also designated the following analysis assumptions:
(1) Mercury removal of 50%, 60%, 70%, 80%, and 90% for each of the model plants;
(2) Flue gas temperature at activated carbon injection location of 150 C for cases without spray cooling
(SC) and an approach to saturation of 10 degrees Celsius (18 degrees F) for cases with SC;
(3) plant capacity factor of 65%;
(4) activated carbon cost of $1.0/kg;
(5) water cost of 0.42 mills/gallon;
(6) energy cost 25 mills/kWh;
(7) 30 days of sorbent storage;
(8) labor cost of $25/h; and
(6) other economic assumptions
(i) general facilities - 5% of direct process capital (DPC)
(ii) engineering and home office expense - 10% of DPC
(iii) process contingency - 5% of DPC
(iv) project contingency - 15% of DPC + (i) + (ii) + (iii)
(v) pre-production cost - 2% of total plant investment (TPI)
(vi) retrofit factor -1.15
(vii) fixed O&M - 1.5% of TPI
A-3-1
-------
TABLE 1
ORIGINAL MERCURY CONTROL CASES DESIGNATED BY EPA
MODEL
PLANT
#
1
2
3
Same as 1
4
5
6
Same as 4
7
8
9
10
11
12
13
14
15
Same as 13
16
17
18
Same as 16
POWER
PLANT
SIZE
(MW)
975
975
975
975
975
975
975
975
975
100
100
100
100
100
100
100
100
100
COAL
Type3
Bit
Bit
Bit
Bit
Bit
Bit
Subbit
Subbit
Subbit
Bit
Bit
Bit
Bit
Bit
Bit
Subbit
Subbit
Subbit
S%
3
o
J
3
0.6
0.6
0.6
0.5
0.5
0.5
3
o
J
3
0.6
0.6
0.6
0.5
0.5
0.5
EXISTING
PLANT
EMISSION
CONTROLS
ESP + FGD
FF + FGD
HESP + FGD
ESP
FF
HESP
ESP
FF
HESP
SD + ESP
SD + FF
HESP + FGD
ESP
FF
HESP
ESP
FF
HESP
MERCURY
CONTROL(S)
ESP-1, ESP-3
FF-1
HESP-1
ESP-4, ESP-6
FF-2
HESP-1
ESP-4, ESP-6
FF-2
HESP-1
SD/ESP-1
SD/FF-1
HESP-1
ESP-4, ESP-6
FF-2
HESP-1
ESP-4, ESP-6
FF-2
HESP-1
CO-BENEFIT
CASE(S)
with
SCR
SCR
SCR
SCR
SCR
SCR
SCR
SCR
SCR
a.
Bit = bituminous coal; Subbit = subbituminous coal.
A-3-2
-------
Table 2
Mercury Control Technology Retrofit Scenarios
CASE
ESP-1
ESP-3
ESP-4
ESP-6
ESP-7
ESP-8
ESP-9
HESP-1
FF-1
FF-2
FF-3
SD/FF-1
SD/ESP-1
WS-1
WS-2
WS-3
SCR-SD-1
EXISTING EQUIPMENT
Cold-side ESP (ESP)
Hot-side ESP (HESP)
Fabric filter (FF)
Spray dryer (SD) + FF
SD + ESP
ESP + wet scrubber (WS)
SNCR + ESP + WS
SCR + ESP + WS
SCR + SD + FF
RETROFIT SCENARIO
ACI
ACI + PFF
SC + ACI
SC + ACI + PFF
SC + AC + lime + PFF
SC + ACI + CFBA
SC + AC + lime + CFBA
SC + ACI + PFF
ACI
SC + ACI
SC + AC + lime + PFF
ACI
ACI
A-3-3
-------
3. Sensitivity Cases
In addition to the original cases described above, EPA also requested five sensitivity cases that are
described below.
3.1 Power Plant Size
The purpose of this sensitivity analysis was to add 500 MWe cases for Model Plant Applications 1, 4, 7, 8.
This work was originally completed on 6/6/2000. The sensitivity runs were updated on 6-14-2000 to
correct a programming error. The results are presented via table and graphs in Excel file "Mercury
Control Results 6-15-OO.xls."
3.2 Mercury Control Operating Temperature
The purpose of this sensitivity analysis was to change the mercury control operating temperature to: Acid Dew
Point (ADP) + 40 F for the following cases:
Plant 4, 500 MW
Plant 7, 500 MW
Plant 8, 500 MW
Plant 13, 100 MW
Plant 16, 100 MW
Plant 17, 100 MW
High sulfur cases are not impacted by the change. 975 MW cases were not run.
This work was originally completed on 6/6/2000. The sensitivity runs were updated on 6-14-2000 to
correct a programming error. The results are presented via table and graphs in Excel file "Mercury
Control Results 6-15-OO.xls."
3.3 COHPAC with Recycle
The purpose of this sensitivity analysis was to add 20% recycle of AC to the COHPAC-type mercury
control scenarios (ESP-3 and ESP-6). This sensitivity applies only to retrofit scenarios ESP-3 and ESP-6.
Mercury control temperature was set at ADP+18 F (ADP+40 F cases were not run) for the following model
plant applications:
Plant 1, 500 MW (ESP-3)
Plant 4, 500 MW (ESP-6)
Plant 7, 500 MW (ESP-6)
Plant 13, 100 MW (ESP-6)
Plant 16, 100 MW (ESP-6)
This work was originally completed on 6/6/2000. The sensitivity runs were updated on 6-14-2000 to
correct a programming error. The results are presented via table and graphs in Excel file "Mercury
Control Results 6-15-OO.xls."
A-3-4
-------
3.4 Addition of Ductwork to Increase Flue Gas Residence Time
The purpose of this sensitivity analysis was to add the capital cost of additional ductwork to the cost of
mercury control for a specified model plant application. The model plant application that was selected was
Plant 4, ESP-4, 500 MW. The following assumptions were used to complete this effort:
Application: Plant 4, ESP-4, Ductwork added upstream of ESP
Results presented with and without added ductwork
Plant sizes: 975, 500 and 100 MWe
Type of ductwork: carbon steel, polymer-lined, insulated (reflects a conservative
selection of material)
Cost of ductwork: $134/sq ft
Installation labor: 0.8 hrs/sq ft
Number of ducts: 2
Duct gas velocity: 2800 ft/min
Retrofit factor: 1.3
Gas residence time in new duct: 1 second
This work was completed on 6/14/2000. The capital costing results indicate the following:
975 MW application: $2.51/kW for 2 ducts @ 47 feet long (22.3 ft x 22.3 ft)
500 MW application: $3.50/kW for 2 ducts @ 47 feet long (16 ft x 16 ft)
100 MW application: $5.54/kW for 2 ducts @ 47 feet long (10 ft x 10 ft)
The complete cost results are presented via table and graphs in Excel file "Mercury Control Results 6-15-
OO.xls" (Plant 4, W&WO Added Ductwork).
3.5 Use of a Combined AC/Lime Sorbent
The purpose of this sensitivity analysis was to assess the potential economic impact of using a sorbent
consisting of AC and lime. The assumptions were:
Application: Model Plant 4, ESP-6, AC sorbent (50-90% Removal); Model Plant 4, ESP-7,
AC-Lime Sorbent (90%+ removal)
Plant size: 500 MWe
AC sorbent Cost = $908/Ton
AC+Lime Sorbent Cost = $149/Ton, Assumes ACLime ratio = 2:19
ESP-7 Sensitivity Cases Assume 90%+ Hg Removal based on ADA Technologies tests at PSE&G
ESP-7 Sensitivity Cases run for 1, 2, 3, and 4 Ib/MMacf Sorbent Concentration
ESP-6 Comparison Cases Run for 50, 60, 70, 80, 90% Hg Removal
The complete cost results are presented via table and graphs in Excel file "Mercury Control Results 6-15-
OO.xls" (Plant 4,500 MW, Lime-AC Sorbent).
A-3-5
-------
ATTACHMENT 4
Results of all Model Runs
A-4-i
-------
Table 1. Mercury Control Technology Retrofit Configurations
Mercury Control Existing Equipment (a,b) Retrofit Technology (a)
ESP-1 ESP ACI
ESP-3 ACI + PFF
ESP-4 SC + ACI
ESP-6 SC + ACI + PFF
ESP-7 SC + AC + lime + PFF
ESP-8 SC + ACI + CFBA
ESP-9 SC + AC + lime + CFBA
HESP-1 HESP
SC + ACI + PFF
FF-1 FF ACI
FF-2 SC + ACI
FF-3 SC + AC + lime + PFF
SD/FF-1 SD + FF ACI
SD/ESP-1 SD + ESP ACI
a. ESP = cold-side electrostatic precipitator; HESP = hot-side electrostatic precipitator; FF= fabric filter; SD = spray dryer;
ACI = activated carbon injection; PFF = polishing fabric filter.
b. Existing equipment may include wet scrubber and NOx controls such as selective catalytic reduction (SCR).
A-4-1
-------
Table 2. Mercury Control Technology Applications and Cobenefits Definition
Power Coal
Model
Plant #
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
Plant
Size,
MWe
975
975
975
975
975
975
975
975
975
100
100
100
100
100
100
100
100
100
Coal Sulfur
Type Content,
%S
Bit
Bit
Bit
Bit
Bit
Bit
Subbit
Subbit
Subbit
Bit
Bit
Bit
Bit
Bit
Bit
Subbit
Subbit
Subbit
3
3
3
0.6
0.6
0.6
0.5
0.5
0.5
3
3
3
0.6
0.6
0.6
0.5
0.5
0.5
Existing
Controls
ESP + FGD
FF + FGD
HESP + FGD
ESP
FF
HESP
ESP
FF
HESP
SD + ESP
SD + FF
HESP + FGD
ESP
FF
HESP
ESP
FF
HESP
Mercury
Controls
ESP-1 , ESP-3
FF-1
HESP-1
ESP-4, ESP-6
FF-2
HESP-1
ESP-4, ESP-6
FF-2
HESP-1
SD/ESP-1
SD/FF-1
HESP-1
ESP-4, ESP-6
FF-2
HESP-1
ESP-4, ESP-6
FF-2
HESP-1
CoBenefit
Case(s) with
SCR
SCR
SCR
SCR
SCR
SCR
a. Bit = bituminous coal; Subbit = subbituminous coal.
b. Mercury controls are shown in Table 1.
A-4-2
-------
RESULTS FOR MODEL PLANTS 1 AND 4 DATE: 5/22/00
(Accounts for ICR Data Modification)
Comments:
1) Model Plant 1, ESP-1: Minimum Hg removal = 87% for ESP and FGD Combination with Eastern Bituminous Coals
2) Model Plant 1, ESP-1: Minimum Hg removal = 97.6% for ESP, FGD, and SCR Combination with Eastern Bituminous Coals
3) Model Plant 1, ESP-3: Minimum Hg removal = 86.6% for ESP and FGD Combination with Eastern Bituminous Coals
4) Model Plant 1, ESP-3: Minimum Hg removal = 97.6% for ESP, FGD, and SCR Combination with Eastern Bituminous Coals
5) Model Plant 4, ESP-4: Minimum Hg removal = 58% for ESP with Eastern Bituminous Coals
7) Model Plant 4, ESP-6: Minimum Hg removal = 61.3% for ESP with Eastern Bituminous Coals
See plot of results below table
Model
Plant #
1
1
1
1
1
1
1
1
4
4
4
4
4
4
4
4
4
4
Plant
Size,
MWe
975
975
975
975
975
975
975
975
975
975
975
975
975
975
975
975
975
975
Total
Mercury
Removed,
%
87.16%
90.00%
95.00%
97.64%
86.58%
90.00%
95.00%
97.54%
58.00%
60.00%
70.00%
80.00%
90.00%
61 .30%
70.00%
80.00%
90.00%
95.00%
Coal
Type
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Coal
Sulfur
Content,
% by Wt
3
3
3
3
3
3
3
3
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
Existing
Pollutant
Controls
ESP, FGD
ESP, FGD
ESP, FGD
ESP, FGD
ESP, FGD
ESP, FGD
ESP, FGD
ESP, FGD
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
Hg Control
Configuration
ESP-1
ESP-1
ESP-1
ESP-1
ESP-3
ESP-3
ESP-3
ESP-3
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-6
ESP-6
ESP-6
ESP-6
ESP-6
Added
Equipment
forHg
Control
None
SI System
SI System
SI System
SI System,
PJFF
SI System,
PJFF
SI System,
PJFF
SI System,
PJFF
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
Co-Benefit
Cases with
N/A
N/A
N/A
SCR
N/A
N/A
N/A
SCR
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Comments
No FG Cooling
No FG Cooling
No FG Cooling
No FG Cooling
No FG Cooling
No FG Cooling
No FG Cooling
No FG Cooling
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
MERCURY
SORBENT
INJECTION
RATIO
Ib/MMacf
0.00
3.29
18.12
0.00
0.00
1.22
6.00
0.00
0.00
0.06
0.79
2.24
6.61
0.00
0.38
1.23
3.78
8.89
Capital
Cost,
$/kW
0.11
2.48
8.54
0.11
43.45
44.59
47.10
43.45
5.88
6.01
6.67
7.54
9.53
46.02
46.50
47.11
48.46
50.59
Levelized
Carrying
Charges,
Mills/kW-
Hr
0.002
0.058
0.200
0.002
1.015
1.041
1.100
1.015
0.137
0.140
0.156
0.176
0.223
1.075
1.086
1.100
1.132
1.182
Fixed
O&M Cost,
Mills/kW-Hr
0.000
0.040
0.048
0.000
0.116
0.118
0.121
0.116
0.047
0.047
0.048
0.050
0.052
0.121
0.122
0.122
0.124
0.127
Variable
O&M Cost,
Mills/kW-Hr
0.000
0.022
0.026
0.000
0.063
0.064
0.065
0.063
0.025
0.025
0.026
0.027
0.028
0.065
0.065
0.066
0.067
0.068
Consuma
bles,
Mills/kW-
Hr
0.003
0.307
1.683
0.003
0.080
0.193
0.637
0.080
0.022
0.027
0.088
0.211
0.580
0.092
0.124
0.196
0.412
0.845
Total
Annual
Cost,
Mills/kW-
Hr
0.006
0.427
1.956
0.006
1.274
1.416
1.924
1.274
0.232
0.240
0.319
0.464
0.883
1.353
1.397
1.485
1.735
2.222
-------
ECONOMIC RESULTS - GRAPHICAL FORMAT
MODEL PLANT #1
MERCURY CONTROL COST - MODEL PLANT 1 (Highest Value of Hg
Removal Includes SCR), 975 MWe, Bituminous Coal, 3% Sulfur
i
8
c
c
3
1.956
1.274 1.416^ '^/1.924\X
/ \ 1.274
/
0 006 ^^-^^0.427
\
\ 0.006
--ESP-1
--ESP-3
86% 88% 90% 92% 94% 96% 98% 100%
Total Hg Removed, %
MODEL PLANT #4
MERCURY CONTROL COST - MODEL PLANT 4, 975 MWe,
Bituminous Coal, 0.6% Sulfur
Total Annual Cost, Mills/kW-H
1 .500 -
2.222^
"*1.735
^ ^ ^5
^^--^0883
*~0240 0319 °'464
55% 65% 75% 85% 95%
Total Hg Removed, %
-»-ESP-6
-m-ESP-4
-------
RESULTS FOR MODEL PLANTS 1 AND 4 (ADP+40) DATE: 6/6/00
(Utilizes Original Performance Algorithms - Excludes ICR Data Modification)
Comments:
1) Model Plant 1, ESP-1: Minimum Hg removal = 70% for ESP and FGD Combination with Eastern Bituminous Coals
2) Model Plant 1, ESP-1: Minimum Hg removal = 94.5% for ESP, FGD, and SCR Combination with Eastern Bituminous Coals
3) Model Plant 1, ESP-3: Minimum Hg removal = 70% for ESP and FGD Combination with Eastern Bituminous Coals
4) Model Plant 1, ESP-3: Minimum Hg removal = 94.5% for ESP, FGD, and SCR Combination with Eastern Bituminous Coals
See plot of results below table
Model
Plant #
1
1
1
1
1
1
1
1
4
4
4
4
4
4
4
4
4
4
Plant Size,
MWe
500
500
500
500
500
500
500
500
500
500
500
500
500
500
500
500
500
500
Total
Mercury
Removed,
%
70.00%
80.00%
90.00%
94.50%
70.00%
80.00%
90.00%
94.50%
50.00%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
Coal Type
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Coal
Sulfur
Content,
% by Wt
3
3
3
3
3
3
3
3
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
Existing
Pollutant
Controls
ESP, FGD
ESP, FGD
ESP, FGD
ESP, FGD
ESP, FGD
ESP, FGD
ESP, FGD
ESP, FGD
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
Hg Control
Configuration
ESP-1
ESP-1
ESP-1
ESP-1
ESP-3
ESP-3
ESP-3
ESP-3
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-6
ESP-6
ESP-6
ESP-6
ESP-6
Added
Equipment
forHg
Control
None
SI System
SI System
SI System
SI System,
PJFF
SI System,
PJFF
SI System,
PJFF
SI System,
PJFF
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
Co-Benefit
Cases with
N/A
N/A
N/A
SCR
N/A
N/A
N/A
SCR
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Comments
No FG Cooling
No FG Cooling
No FG Cooling
No FG Cooling
No FG Cooling
No FG Cooling
No FG Cooling
No FG Cooling
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
MERCURY
SORBENT
INJECTION
RATIO
Ib/MMacf
0.00
6.14
24.42
0.00
0.00
2.00
7.56
0.00
5.31
7.96
12.37
21.19
47.64
1.98
2.98
4.65
8.00
18.05
Capital
Cost,
$/kW
0.12
4.61
12.54
0.12
49.65
51.64
54.83
49.65
7.95
9.22
11.13
14.55
23.42
51.91
52.53
53.46
55.10
59.25
Levelized
Carrying
Charges,
Mills/kW-
Hr
0.003
0.108
0.293
0.003
1.160
1.206
1.281
1.160
0.186
0.215
0.260
0.340
0.547
1.212
1.227
1.249
1.287
1.384
Fixed
O&M Cost,
Mills/kW-Hr
0.000
0.078
0.089
0.000
0.163
0.166
0.170
0.163
0.084
0.086
0.088
0.093
0.103
0.166
0.167
0.168
0.170
0.176
Variable
O&M Cost,
Mills/kW-Hr
0.000
0.042
0.048
0.000
0.088
0.089
0.091
0.088
0.045
0.046
0.048
0.050
0.056
0.089
0.090
0.090
0.092
0.095
Consuma
bles,
Mills/kW-
Hr
0.003
0.572
2.266
0.003
0.080
0.266
0.782
0.080
0.459
0.683
1.055
1.800
4.035
0.248
0.333
0.474
0.758
1.609
Total
Annual
Cost,
Mills/kW-
Hr
0.006
0.800
2.695
0.006
1.489
1.727
2.324
1.489
0.774
1.030
1.451
2.282
4.741
1.715
1.816
1.982
2.307
3.263
-------
ECONOMIC RESULTS S GRAPHICAL FORMAT
MODEL PLANT#1
MODEL PL
MERCURY CONTROL COST -MODEL PLANT 1 (Highest Value
Removal Includes SCR), 500 MWe, Bituminous Coal, 3% Sulf
I
_*:
to
0 1.500 -
g 1 nnn
C
C
2£95
1 727 -^ 2-324-^Nr
1.489_ -*^^/ \ 1.489
/ \
^r'O.SOO \
°-°26^ -^ Y 0.006
of Hg
ur
ESP-1
--ESP-3
65% 70% 75% 80% 85% 90% 95% 1 00%
Total Hg Removed, %
fl
NT #4
MERCURY CONTROL COST - MODEL PLANT 4,500 MWe,
Bituminous Coal, 0.6% Sulfur
0 I J'bUU
3 W 2-5°°
o = 2.000 -
o> s 1 ^nn
5 1.000-
/4.741
/ ^» 3.263
2.307/^^
1.715 1.816 1_982___^X^
« _^-^2.282
""1*451
" 1 030
UY/4 '---
- ESP-6
--ESP-4
40% 50% 60% 70% 80% 90% 100%
Total Mercury Removed, %
-------
RESULTS FOR MODEL PLANTS 1 AND 4 (w Recycle for ESP-3 and ESP-6) 06/06/2000
(Utilizes Original Performance Algorithms - Excludes ICR Data Modification)
Comments:
1) Model Plant 1, ESP-1: Minimum Hg removal = 70% for ESP and FGD Combination with Eastern Bituminous Coals
2) Model Plant 1, ESP-1: Minimum Hg removal = 94.5% for ESP, FGD, and SCR Combination with Eastern Bituminous Coals
3) Model Plant 1, ESP-3: Minimum Hg removal = 70% for ESP and FGD Combination with Eastern Bituminous Coals
4) Model Plant 1, ESP-3: Minimum Hg removal = 94.5% for ESP, FGD, and SCR Combination with Eastern Bituminous Coals
See plot of results below table
Model
Plant #
1
1
1
1
1
1
1
1
4
4
4
4
4
4
4
4
4
4
Plant Size,
MWe
500
500
500
500
500
500
500
500
500
500
500
500
500
500
500
500
500
500
Total
Mercury
Removed,
%
70.00%
80.00%
90.00%
94.50%
70.00%
80.00%
90.00%
94.50%
50.00%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
Coal Type
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Coal
Sulfur
Content,
% by Wt
3
3
3
3
3
3
3
3
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
Existing
Pollutant
Controls
ESP, FGD
ESP, FGD
ESP, FGD
ESP, FGD
ESP, FGD
ESP, FGD
ESP, FGD
ESP, FGD
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
Hg Control
Configuration
ESP-1
ESP-1
ESP-1
ESP-1
ESP-3
ESP-3
ESP-3
ESP-3
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-6
ESP-6
ESP-6
ESP-6
ESP-6
Added
Equipment
forHg
Control
None
SI System
SI System
SI System
SI System,
PJFF
SI System,
PJFF
SI System,
PJFF
SI System,
PJFF
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
Co-Benefit
Cases with
N/A
N/A
N/A
SCR
N/A
N/A
N/A
SCR
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Comments
No FG Cooling
No FG Cooling
No FG Cooling
No FG Cooling
No FG Cooling
No FG Cooling
No FG Cooling
No FG Cooling
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
MERCURY
SORBENT
INJECTION
RATIO
Ib/MMacf
0.00
6.14
24.42
0.00
0.00
2.00
7.56
0.00
1.94
2.95
4.64
8.03
18.17
1.07
1.66
2.65
4.63
10.58
Capital
Cost,
$/kW
0.12
4.61
12.54
0.12
49.67
51.39
54.15
49.67
9.23
9.86
10.79
12.44
16.62
54.33
54.71
55.26
56.23
58.64
Levelized
Carrying
Charges,
Mills/kW-
Hr
0.003
0.108
0.293
0.003
1.160
1.200
1.265
1.160
0.216
0.230
0.252
0.291
0.388
1.269
1.278
1.291
1.313
1.370
Fixed
O&M Cost,
Mills/kW-Hr
0.000
0.078
0.089
0.000
0.163
0.165
0.169
0.163
0.087
0.088
0.090
0.092
0.097
0.170
0.171
0.172
0.173
0.177
Variable
O&M Cost,
Mills/kW-Hr
0.000
0.042
0.048
0.000
0.088
0.089
0.091
0.088
0.047
0.047
0.048
0.049
0.052
0.092
0.092
0.093
0.093
0.095
Consuma
bles,
Mills/kW-
Hr
0.003
0.572
2.266
0.003
0.081
0.231
0.648
0.081
0.185
0.271
0.414
0.700
1.557
0.166
0.206
0.274
0.409
0.816
Total
Annual
Cost,
Mills/kW-
Hr
0.006
0.800
2.695
0.006
1.491
1.686
2.173
1.491
0.535
0.637
0.804
1.132
2.095
1.697
1.747
1.829
1.989
2.457
-------
ECONOMIC RESULTS S GRAPHICAL FORMAT
MODEL PLANT#1
MERCURY CONTROL COST -MODEL PLANT 1 (Highest Value of Hg
Removal Includes SCR), 500 MWe, Bituminous Coal, 3% Sulfur
65% 70% 75% 80% 85% 90%
Total Hg Removed, %
95% 100%
oo
MODEL PLANT#4
MERCURY CONTROL COST - MODEL PLANT 4,500 MWe,
1
i
^j-
8
c
i-
Bituminous Coal,
3.000 -
9 nnn
1 .500 -
0.6% Sulfur
2.457
_^^~
-i
* r 1.829
/ 2 095
1.989 /
1.697 1.747 ^/
_______--
0 . 804
1.132
0.535 0.637
40% 50% 60% 70%
CQ p R
--ESP-4
80% 90% 100%
Total Mercury Removed, %
-------
RESULTS FOR MODEL PLANTS 1 AND 4 06/05/2000
(Utilizes Original Performance Algorithms Excludes ICR Data Modification)
Comments:
1) Model Plant 1, ESP-1: Minimum Hg removal = 70% for ESP and FGD Combination with Eastern Bituminous Coals
2) Model Plant 1, ESP-1: Minimum Hg removal = 94.5% for ESP, FGD, and SCR Combination with Eastern Bituminous Coals
3) Model Plant 1, ESP-3: Minimum Hg removal = 70% for ESP and FGD Combination with Eastern Bituminous Coals
4) Model Plant 1, ESP-3: Minimum Hg removal = 94.5% for ESP, FGD, and SCR Combination with Eastern Bituminous Coals
See plot of results below table
Model
Plant #
1
1
1
1
1
1
1
1
4
4
4
4
4
4
4
4
4
4
Plant Size,
MWe
500
500
500
500
500
500
500
500
500
500
500
500
500
500
500
500
500
500
Total
Mercury
Removed,
%
70.00%
80.00%
90.00%
94.50%
70.00%
80.00%
90.00%
94.50%
50.00%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
Coal Type
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Coal
Sulfur
Content,
% by Wt
3
3
3
3
3
3
3
3
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
Existing
Pollutant
Controls
ESP, FGD
ESP, FGD
ESP, FGD
ESP, FGD
ESP, FGD
ESP, FGD
ESP, FGD
ESP, FGD
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
Hg Control
Configuration
ESP-1
ESP-1
ESP-1
ESP-1
ESP-3
ESP-3
ESP-3
ESP-3
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-6
ESP-6
ESP-6
ESP-6
ESP-6
Added
Equipment
forHg
Control
None
SI System
SI System
SI System
SI System,
PJFF
SI System,
PJFF
SI System,
PJFF
SI System,
PJFF
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
Co-Benefit
Cases with
N/A
N/A
N/A
SCR
N/A
N/A
N/A
SCR
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Comments
No FG Cooling
No FG Cooling
No FG Cooling
No FG Cooling
No FG Cooling
No FG Cooling
No FG Cooling
No FG Cooling
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
MERCURY
SORBENT
INJECTION
RATIO
Ib/MMacf
0.00
6.14
24.42
0.00
0.00
2.00
7.56
0.00
1.94
2.95
4.64
8.03
18.17
1.07
1.66
2.65
4.63
10.58
Capital
Cost,
$/kW
0.12
4.61
12.54
0.12
49.65
51.64
54.83
49.65
9.23
9.86
10.79
12.44
16.62
54.48
54.91
55.55
56.67
59.46
Levelized
Carrying
Charges,
Mills/kW-
Hr
0.003
0.108
0.293
0.003
1.160
1.206
1.281
1.160
0.216
0.230
0.252
0.291
0.388
1.273
1.283
1.298
1.324
1.389
Fixed
O&M Cost,
Mills/kW-Hr
0.000
0.078
0.089
0.000
0.163
0.166
0.170
0.163
0.087
0.088
0.090
0.092
0.097
0.171
0.171
0.172
0.174
0.178
Variable
O&M Cost,
Mills/kW-Hr
0.000
0.042
0.048
0.000
0.088
0.089
0.091
0.088
0.047
0.047
0.048
0.049
0.052
0.092
0.092
0.093
0.094
0.096
Consuma
bles,
Mills/kW-
Hr
0.003
0.572
2.266
0.003
0.080
0.266
0.782
0.080
0.185
0.271
0.414
0.700
1.557
0.182
0.232
0.316
0.484
0.987
Total
Annual
Cost,
Mills/kW-
Hr
0.006
0.800
2.695
0.006
1.489
1.727
2.324
1.489
0.535
0.637
0.804
1.132
2.095
1.717
1.779
1.879
2.075
2.650
-------
ECONOMIC RESULTS S GRAPHICAL FORMAT
MODEL PLANT#1
MERCURY CONTROL COST - MODEL PLANT 1 (Highest Value of Hg
Removal Includes SCR), 500 MWe, Bituminous Coal, 3% Sulfur
65% 70% 75% 80% 85% 90% 95% 100%
Total Hg Removed, %
MODEL PLANT#4
MERCURY CONTROL COST --MODEL PLANT 4,500 MWe,
Bituminous Coal, 0.6% Sulfur
o =
2.650>
^-»
. . 1 879
1.717 TTTTS ./
^_ -^7" "1-132
o.s^T" u'°3'
-»-ESP-6
--ESP-4
40% 50% 60% 70% 80% 90% 100%
Total M ercury Removed, %
-------
RESULTS FOR MODEL PLANTS 1 AND 4 05/22/2000
(Utilizes Original Performance Algorithms Excludes ICR Data Modification)
Comments:
1) Model Plant 1, ESP-1: Minimum Hg removal = 70% for ESP and FGD Combination with Eastern Bituminous Coals
2) Model Plant 1, ESP-1: Minimum Hg removal = 94.5% for ESP, FGD, and SCR Combination with Eastern Bituminous Coals
3) Model Plant 1, ESP-3: Minimum Hg removal = 70% for ESP and FGD Combination with Eastern Bituminous Coals
4) Model Plant 1, ESP-3: Minimum Hg removal = 94.5% for ESP, FGD, and SCR Combination with Eastern Bituminous Coals
See plot of results below table
Model
Plant #
1
1
1
1
1
1
1
1
4
4
4
4
4
4
4
4
4
4
Plant Size,
MWe
975
975
975
975
975
975
975
975
975
975
975
975
975
975
975
975
975
975
Total
Mercury
Removed,
%
70.00%
80.00%
90.00%
94.50%
70.00%
80.00%
90.00%
94.50%
50.00%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
Coal Type
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Coal
Sulfur
Content,
% by Wt
3
3
3
3
3
3
3
3
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
Existing
Pollutant
Controls
ESP, FGD
ESP, FGD
ESP, FGD
ESP, FGD
ESP, FGD
ESP, FGD
ESP, FGD
ESP, FGD
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
Hg Control
Configuration
ESP-1
ESP-1
ESP-1
ESP-1
ESP-3
ESP-3
ESP-3
ESP-3
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-6
ESP-6
ESP-6
ESP-6
ESP-6
Added
Equipment
forHg
Control
None
SI System
SI System
SI System
SI System,
PJFF
SI System,
PJFF
SI System,
PJFF
SI System,
PJFF
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
Co-Benefit
Cases with
N/A
N/A
N/A
SCR
N/A
N/A
N/A
SCR
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Comments
No FG Cooling
No FG Cooling
No FG Cooling
No FG Cooling
No FG Cooling
No FG Cooling
No FG Cooling
No FG Cooling
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
MERCURY
SORBENT
INJECTION
RATIO
Ib/MMacf
0.00
6.14
24.42
0.00
0.00
2.00
7.56
0.00
1.94
2.95
4.64
8.03
18.17
1.07
1.66
2.65
4.63
10.58
Capital
Cost,
$/kW
0.11
3.85
10.73
0.11
43.43
45.08
47.78
43.43
7.37
7.90
8.70
10.10
13.72
47.00
47.37
47.90
48.84
51.23
Levelized
Carrying
Charges,
Mills/kW-
Hr
0.002
0.090
0.251
0.002
1.014
1.053
1.116
1.014
0.172
0.185
0.203
0.236
0.320
1.098
1.106
1.119
1.141
1.197
Fixed
O&M Cost,
Mills/kW-Hr
0.000
0.042
0.050
0.000
0.116
0.119
0.122
0.116
0.049
0.050
0.051
0.053
0.057
0.122
0.123
0.124
0.125
0.128
Variable
O&M Cost,
Mills/kW-Hr
0.000
0.023
0.027
0.000
0.063
0.064
0.066
0.063
0.027
0.027
0.028
0.029
0.031
0.066
0.066
0.067
0.067
0.069
Consum
ables,
Mills/kW-
Hr
0.003
0.572
2.266
0.003
0.080
0.266
0.782
0.080
0.185
0.271
0.414
0.700
1.557
0.182
0.232
0.316
0.484
0.988
Total
Annual
Cost,
Mills/kW-
Hr
0.006
0.727
2.594
0.006
1.273
1.501
2.086
1.273
0.434
0.533
0.696
1.017
1.966
1.468
1.528
1.625
1.817
2.381
>
-------
ECONOMIC RESULTS S GRAPHICAL FORMAT
MODEL PLANT#1
to
MERCURY CONTROL COST -- MODEL PLANT 1 (Highest Value of Hg
Removal Includes SCR), 975 MWe, Bituminous Coal, 3% Sulfur
o 0.000
65% 70% 75% 80% 85% 90%
Total Hg Removed, %
95% 100%
MODEL PLANT#4
MERCURY CONTROL COST -MODEL PLANT 4,975 P
Bituminous Coal, 0.6% Sulfur
to
(3 1.500 -
< 0.500 -
2J38J^»
_, -*~" ^X^-966
1.468 1.528 1-625 "^^
-z-fT, L°1I
n I^QQ u.by b
0.434 U'bJJ
i^We,
ESP-6
--ESP-4
H 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100
Total Hg Removed, %
-------
RESULTS FOR MODEL PLANTS 7 AND 8 (w Recycle for ESP-6)
DATE:
6/6/00
Comments:
1) Model Plant 7, ESP-4: Minimum Hg removal = 56.2% for ESP with Western Subbituminous Coals
2) Model Plant 8, FF-2: Minimum Hg removal = 50% for Reverse-Gas FF with Western Subbituminous Coals
See plot of results below table
Model
Plant #
7
7
7
7
7
7
7
7
7
7
8
8
8
8
8
Plant Size,
MWe
500
500
500
500
500
500
500
500
500
500
500
500
500
500
500
Total Mercury
Removed, %
56.20%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
Coal Type
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Coal
Sulfur
Content,
% by Wt
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
Existing
Pollutant
Controls
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
FF
FF
FF
FF
FF
Hg Control
Configuration
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-6
ESP-6
ESP-6
ESP-6
ESP-6
FF-2
FF-2
FF-2
FF-2
FF-2
Added
Equipment
forHg
Control
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System,
PJFF
SI System,
Wl System,
PJFF
SI System,
Wl System,
PJFF
SI System,
Wl System,
PJFF
SI System,
Wl System,
PJFF
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
Co-Benefit
Cases with
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Comments
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
MERCURY
SORBENT
INJECTION
RATIO
Ib/MMacf
0.00
2.36
4.87
9.00
21.39
0.04
0.06
0.09
0.17
0.38
0.01
0.04
0.09
0.73
1.89
Capital
Cost,
$/kW
6.59
8.79
10.27
12.34
17.55
55.15
55.19
55.25
55.34
55.57
6.65
6.74
6.84
7.56
8.47
Levelized
Carrying
Charges,
Mills/kW-
Hr
0.154
0.205
0.240
0.288
0.410
1.288
1.289
1.290
1.293
1.298
0.155
0.157
0.160
0.177
0.198
Fixed
O&M Cost,
Mills/kW-Hr
0.083
0.086
0.088
0.091
0.098
0.172
0.172
0.172
0.172
0.173
0.083
0.083
0.083
0.085
0.086
Variable
O&M Cost,
Mills/kW-Hr
0.045
0.046
0.048
0.049
0.053
0.093
0.092
0.093
0.093
0.093
0.045
0.045
0.045
0.046
0.046
Consuma
bles,
Mills/kW-
Hr
0.019
0.233
0.459
0.833
1.953
0.097
0.099
0.101
0.107
0.122
0.020
0.023
0.027
0.085
0.190
Total
Annual
Cost,
Mills/kW-
Hr
0.300
0.571
0.835
1.261
2.513
1.650
1.652
1.657
1.664
1.686
0.303
0.308
0.315
0.392
0.520
-------
ECONOMIC RESULTS S GRAPHICAL FORMAT
MODEL PLANT#7
I
1
5
g
o
O
"ro
c
c
"ro
K
1
1
MERCURY CONTROL COST --MODEL PLANT 7, 500 MWe,
Subbituminous Coal, 0.5% Sulfur
nn
50 -
cn
nn
2.513
1.650 1.652 1.657 1.664 /I 686
_ _ _ - /
^x^fnc
0.835 ^^*"l.261
0.571 ^___^
0.300 ^* '
^
-»-ESP-4
ESP-6
45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%
Total Hg Removed, %
>
MODEL PLANT#8
X
^
to
O
O
ro
c
^
0
MERCURY CONTROL COST -- MODEL PLANT 8, 500 MWe,
Subbituminous Coal, 0.5% Sulfur
25 -
y» 0.520
~7
/
/
^T
s* 0.392
0.303 0.308 0.315^^^
_i »
-»-FF-2
40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%
Total Hg Removed, %
-------
RESULTS FOR MODEL PLANTS 7 AND 8
DATE: 06/06/2000
Comments:
1) Model Plant 7, ESP-4: Minimum Hg removal = 56.2% for ESP with Western Subbituminous Coals
2) Model Plant 8, FF-2: Minimum Hg removal = 50% for Reverse-Gas FF with Western Subbituminous Coals
See plot of results below table
Model
Plant #
7
7
7
7
7
7
7
7
7
7
8
8
8
8
8
Plant Size,
MWe
500
500
500
500
500
500
500
500
500
500
500
500
500
500
500
Total Mercury
Removed, %
56.20%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
Coal Type
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Coal
Sulfur
Content,
% by Wt
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
Existing
Pollutant
Controls
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
FF
FF
FF
FF
FF
Hg Control
Configuration
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-6
ESP-6
ESP-6
ESP-6
ESP-6
FF-2
FF-2
FF-2
FF-2
FF-2
Added
Equipment
forHg
Control
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System,
PJFF
SI System,
Wl System,
PJFF
SI System,
Wl System,
PJFF
SI System,
Wl System,
PJFF
SI System,
Wl System,
PJFF
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
Co-Benefit
Cases with
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Comments
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
MERCURY
SORBENT
INJECTION
RATIO
Ib/MMacf
0.00
2.36
4.87
9.00
21.39
0.04
0.06
0.09
0.17
0.38
0.01
0.04
0.09
0.73
1.89
Capital
Cost,
$/kW
6.59
8.79
10.27
12.34
17.55
55.15
55.20
55.26
55.37
55.64
6.65
6.74
6.84
7.56
8.47
Levelized
Carrying
Charges,
Mills/kW-
Hr
0.154
0.205
0.240
0.288
0.410
1.288
1.289
1.291
1.293
1.300
0.155
0.157
0.160
0.177
0.198
Fixed
O&M Cost,
Mills/kW-Hr
0.083
0.086
0.088
0.091
0.098
0.172
0.172
0.172
0.172
0.173
0.083
0.083
0.083
0.085
0.086
Variable
O&M Cost,
Mills/kW-Hr
0.045
0.046
0.048
0.049
0.053
0.093
0.092
0.093
0.093
0.093
0.045
0.045
0.045
0.046
0.046
Consuma
bles,
Mills/kW-
Hr
0.019
0.233
0.459
0.833
1.953
0.097
0.099
0.102
0.108
0.128
0.020
0.023
0.027
0.085
0.190
Total
Annual
Cost,
Mills/kW-
Hr
0.300
0.571
0.835
1.261
2.513
1.650
1.652
1.658
1.667
1.693
0.303
0.308
0.315
0.392
0.520
>
-------
ECONOMIC RESULTS S GRAPHICAL FORMAT
MODEL PLANT#7
>
^ MODEL PLANT #8
J-
g
1
5
'H
3
03
c
c
"ro
K
2
2
1
MERCURY CONTROL COST -MODEL PLANT 7, 500 MWe,
Subbituminous Coal, 0.5% Sulfur
50 -
00 -
50 -
2.513
1.650 1.652 1.658 1.667 /
/ _ 1.693
0.835 ___^«n.261
0.571 _____-»
0.300 ^»
*^~
-» ESP-4
--ESP-6
45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%
Total Hg Removed, %
Total Annual Cost, Mills/kW-H
0
0
0
0
0
0
0
MERCURY CONTROL COST -MODEL PLANT 8, 500 MWe,
Subbituminous Coal, 0.5% Sulfur
25 -
40
J» 0.520
/
/
-x^O.392
0.303 0.308 0.315^^-^
FF-2
% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%
Total Hg Removed, %
-------
RESULTS FOR MODEL PLANTS 7 AND 8 (ADP+40)
DATE: 6/6/00
Comments:
1) Model Plant 7, ESP-4: Minimum Hg removal = 56.2% for ESP with Western Subbituminous Coals
2) Model Plant 8, FF-2: Minimum Hg removal = 50% for Reverse-Gas FF with Western Subbituminous Coals
See plot of results below table
Model
Plant #
7
7
7
7
7
7
7
7
7
7
8
8
8
8
8
Plant Size,
MWe
500
500
500
500
500
500
500
500
500
500
500
500
500
500
500
Total
Mercury
Removed,
%
56.20%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
Coal Type
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Coal
Sulfur
Content,
% by Wt
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
Existing
Pollutant
Controls
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
FF
FF
FF
FF
FF
Hg Control
Configuration
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-6
ESP-6
ESP-6
ESP-6
ESP-6
FF-2
FF-2
FF-2
FF-2
FF-2
Added
Equipment for
Hg Control
SI System, Wl
System
SI System, Wl
System
SI System, Wl
System
SI System, Wl
System
SI System, Wl
System
SI System, Wl
System, PJFF
SI System, Wl
System, PJFF
SI System, Wl
System, PJFF
SI System, Wl
System, PJFF
SI System, Wl
System, PJFF
SI System, Wl
System
SI System, Wl
System
SI System, Wl
System
SI System, Wl
System
SI System, Wl
System
Co-Benefit
Cases with
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Comments
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
MERCURY
SORBENT
INJECTION
RATIO
Ib/MMacf
0.00
2.36
4.87
9.00
21.39
0.04
0.06
0.09
0.17
0.38
0.01
0.04
0.09
0.73
1.89
Capital
Cost,
$/kW
3.92
4.83
6.15
8.22
13.42
51.17
51.28
51.44
51.70
52.36
2.57
2.75
2.95
3.44
4.35
Levelized
Carrying
Charges,
Mills/kW-
Hr
0.092
0.113
0.144
0.192
0.313
1.195
1.198
1.201
1.208
1.223
0.060
0.064
0.069
0.080
0.102
Fixed
O&M Cost,
Mills/kW-Hr
0.078
0.079
0.081
0.084
0.090
0.165
0.164
0.165
0.166
0.167
0.076
0.076
0.076
0.077
0.078
Variable
O&M Cost,
Mills/kW-Hr
0.042
0.043
0.044
0.045
0.049
0.089
0.089
0.089
0.089
0.090
0.041
0.041
0.041
0.041
0.042
Consuma
bles,
Mills/kW-
Hr
0.125
0.243
0.446
0.820
1.939
0.093
0.100
0.111
0.134
0.204
0.009
0.017
0.030
0.072
0.177
Total
Annual
Cost,
Mills/kW-
Hr
0.336
0.478
0.714
1.140
2.392
1.541
1.550
1.567
1.597
1.683
0.185
0.197
0.216
0.271
0.399
-------
ECONOMIC RESULTS S GRAPHICAL FORMAT
MODEL PLANT#7
MERCURY CONTROL COST -MO DEL PLANT 7, 500 MWe,
Subbituminous Coal, 0.5% Sulfur
I
"> 1 IK
w" 1 75 -
o
O
15 1-25 -
c
C n yc
S n oc;
y» 2.392
/f
1541 1.550 1.567 1 .597^/_^83
y^
0.478 0.714^^-^1.140
0.336^_
- ESP-4
--ESP-6
45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%
Total Hg Removed, %
MODEL PLANT #8
oo
Total Annual Cost, Mills/kW-H
MERCURY CONTROL COST -- MODEL PLANT 8, 500 MWe,
Subbituminous Coal, 0.5% Sulfur
0.399
/*
/
^.27^
0.185 0.197^___°_2JjJ^-^'
- FF-2
40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%
Total Hg Removed, %
-------
RESULTS FOR MODEL PLANTS 7 AND 8
DATE: 05/22/2000
Comments:
1) Model Plant 7, ESP-4: Minimum Hg removal = 56.2% for ESP with Western Subbituminous Coals
2) Model Plant 8, FF-2: Minimum Hg removal = 50% for Reverse-Gas FF with Western Subbituminous Coals
See plot of results below table
Model
Plant #
7
7
7
7
7
7
7
7
7
7
8
8
8
8
8
Plant Size,
MWe
975
975
975
975
975
975
975
975
975
975
975
975
975
975
975
Total Mercury
Removed, %
56.20%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
Coal Type
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Coal
Sulfur
Content,
% by Wt
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
Existing
Pollutant
Controls
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
FF
FF
FF
FF
FF
Hg Control
Configuration
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-6
ESP-6
ESP-6
ESP-6
ESP-6
FF-2
FF-2
FF-2
FF-2
FF-2
Added
Equipment for
Hg Control
SI System, Wl
System
SI System, Wl
System
SI System, Wl
System
SI System, Wl
System
SI System, Wl
System
SI System, Wl
System, PJFF
SI System, Wl
System, PJFF
SI System, Wl
System, PJFF
SI System, Wl
System, PJFF
SI System, Wl
System, PJFF
SI System, Wl
System
SI System, Wl
System
SI System, Wl
System
SI System, Wl
System
SI System, Wl
System
Co-Benefit
Cases with
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Comments
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
MERCURY
SORBENT
INJECTION
RATIO
Ib/MMacf
0.00
2.36
4.87
9.00
21.39
0.04
0.06
0.09
0.17
0.38
0.01
0.04
0.09
0.73
1.89
Capital
Cost,
$/kW
5.25
7.07
8.32
10.09
14.61
47.74
47.78
47.83
47.92
48.14
5.30
5.37
5.45
6.04
6.80
Levelized
Carrying
Charges,
Mills/kW-
Hr
0.123
0.165
0.194
0.236
0.341
1.115
1.116
1.117
1.119
1.124
0.124
0.125
0.127
0.141
0.159
Fixed
O&M Cost,
Mills/kW-Hr
0.046
0.049
0.050
0.053
0.058
0.124
0.124
0.124
0.124
0.125
0.046
0.046
0.046
0.047
0.048
Variable
O&M Cost,
Mills/kW-Hr
0.025
0.026
0.027
0.028
0.031
0.067
0.067
0.067
0.067
0.067
0.025
0.025
0.025
0.025
0.026
Consuma
bles,
Mills/kW-
Hr
0.019
0.233
0.459
0.833
1.953
0.097
0.099
0.102
0.109
0.128
0.020
0.023
0.027
0.085
0.190
Total
Annual
Cost,
Mills/kW-
Hr
0.212
0.473
0.731
1.150
2.384
1.403
1.405
1.410
1.419
1.444
0.214
0.219
0.226
0.299
0.423
VO
-------
ECONOMIC RESULTS S GRAPHICAL FORMAT
MODEL PLANT#7
I
1
ii
"w
"ro
c
c
"ro
H
3
2
2
1
-i
MERCURY CONTROL COST --MODEL PLANT 7, 975 MWe, Subbitum inous Coal,
0.5% Sulfur
00 -i
50 -
00 -
50
nn
en
nn
j» 2.384
1.403 1.405 1.410 1.419 / 1 .444
^^
0.473 °-^L-*
0.212 ^^'
-» ESP-4
--ESP-6
45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%
Total Hg Removed, %
MODEL PLANT#8
MERCURY CONTROL COST -- MODEL PLANT 8, 975 MWe, Subbituminous Coal, 0.5%
Sulfur
0.45
0.40
-- 0.35
o
O
B 0.30
- 0.25
I
0.20
0.299
0.214
0.219
0.423
+
40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%
Total Hg Removed, %
-------
RESULTS FOR MODEL PLANTS 10 AND 13
DATE: 5/22/00
Comments:
1) Model Plant 10, DS/ESP-1: Minimum Hg removal = 57.2% for DS/ESP Combination with Eastern Bituminous Coals
2) Model Plant 10: Capital Cost Only Includes Sorbent Injection Equipment (accounts for storage/transfer of sorbent)
3) Model Plant 13, ESP-4: Minimum Hg removal = 58.8% for ESP with Eastern Bituminous Coals
4) Model Plant 13, ESP-6: Minimum Hg removal = 61.3% for ESP with Eastern Bituminous Coals
See plot of results below table
Model
Plant #
10
10
10
10
10
13
13
13
13
13
13
13
13
13
13
Plant Size,
MWe
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
Total
Mercury
Removed,
%
57.20%
60.00%
70.00%
80.00%
90.00%
58.80%
60.00%
70.00%
80.00%
90.00%
61 .30%
70.00%
80.00%
90.00%
95.00%
Coal
Type
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Coal
Sulfur
Content,
% by Wt
3
3
3
3
3
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
Existing
Pollutant
Controls
DS, ESP
DS, ESP
DS, ESP
DS, ESP
DS, ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
Hg Control
Configuration
DS/ESP-1
DS/ESP-1
DS/ESP-1
DS/ESP-1
DS/ESP-1
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-6
ESP-6
ESP-6
ESP-6
ESP-6
Added
Equipment for
Hg Control
SI System
SI System
SI System
SI System
SI System
SI System, Wl
System
SI System, Wl
System
SI System, Wl
System
SI System, Wl
System
SI System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
Co-Benefit
Cases with
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Comments
Costs for SI
Equipment Only
Costs for SI
Equipment Only
Costs for SI
Equipment Only
Costs for SI
Equipment Only
Costs for SI
Equipment Only
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
MERCURY
SORBENT
INJECTION
RATIO
Ib/MMacf
0.00
0.00
0.42
1.34
4.12
0.00
0.06
0.79
2.24
6.61
0.00
0.38
1.23
3.78
8.89
Capital
Cost,
$/kW
0.18
0.18
1.58
2.95
5.84
13.11
13.39
14.72
16.40
20.05
76.37
77.36
78.56
81.10
84.94
Levelized
Carrying
Charges,
Mills/kW-
Hr
0.004
0.004
0.037
0.069
0.136
0.306
0.313
0.344
0.383
0.468
1.784
1.807
1.835
1.894
1.984
Fixed
O&M Cost,
Mills/kW-Hr
0.000
0.000
0.363
0.365
0.370
0.378
0.378
0.381
0.383
0.389
0.495
0.497
0.499
0.503
0.509
Variable
O&M Cost,
Mills/kW-Hr
0.000
0.000
0.195
0.197
0.199
0.203
0.204
0.205
0.206
0.210
0.266
0.267
0.268
0.271
0.274
Consuma
bles,
Mills/kW-
Hr
0.003
0.003
0.042
0.128
0.388
0.022
0.027
0.088
0.211
0.580
0.092
0.124
0.196
0.412
0.844
Total
Annual
Cost,
Mills/kW-
Hr
0.008
0.008
0.637
0.759
1.094
0.909
0.922
1.018
1.184
1.647
2.637
2.695
2.798
3.080
3.611
-------
ECONOMIC RESULTS S GRAPHICAL FORMAT
MODEL PLANT#10
f
K>
to
MERCURY CONTROL COST - MODEL PLANT 10, 100 MWe,
Bituminous Coal, 3% Sulfur
I 1'20 "
§ 1 nn
j/>
"w
.,9 n Rn
"ro
^ n An
<
~o
n nn
> 1 .094
0759/_
0.637^-
/
/
0.008/
0.008^ /
-^DS/ESP-1
50% 60% 70% 80% 90% 100%
Total Hg Removed, %
MODEL PLANT#13
i
i
ii
"55
o
O
03
c
"TO
12
MERCURY CONTROL COST -MODEL PLANT 13,100 MWe,
Bituminous Coal, 0.6% Sulfur
3.00 -
3.611
/
3 080 ,/
2 637 2 695
-------
RESULTS FOR MODEL PLANTS 10 AND 13 (ADP+40)
Comments:
DATE: 6/6/00
See plot of results below table
Model
Plant #
10
10
10
10
10
13
13
13
13
13
13
13
13
13
13
Plant Size,
MWe
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
Total
Mercury
Removed,
%
50.00%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
Coal Type
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Coal
Sulfur
Content,
% by Wt
3
3
3
3
3
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
Existing
Pollutant
Controls
DS, ESP
DS, ESP
DS, ESP
DS, ESP
DS, ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
Hg Control
Configuration
DS/ESP-1
DS/ESP-1
DS/ESP-1
DS/ESP-1
DS/ESP-1
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-6
ESP-6
ESP-6
ESP-6
ESP-6
Added
Equipment
forHg
Control
SI System
SI System
SI System
SI System
SI System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
Co-Benefit
Cases with
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Comments
Costs for SI
Equipment Only
Costs for SI
Equipment Only
Costs for SI
Equipment Only
Costs for SI
Equipment Only
Costs for SI
Equipment Only
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
MERCURY
SORBENT
INJECTION
RATIO
Ib/MMacf
1.15
1.79
2.86
5.01
11.44
5.31
7.96
12.37
21.19
47.64
1.98
2.98
4.65
8.00
18.05
Capital
Cost,
$/kW
2.69
3.49
4.64
6.62
11.49
13.49
15.43
18.31
23.36
36.04
73.77
74.76
76.20
78.71
84.91
Levelized
Carrying
Charges,
Mills/kW-
Hr
0.063
0.081
0.108
0.155
0.268
0.315
0.360
0.428
0.546
0.842
1.723
1.746
1.780
1.839
1.983
Fixed
O&M Cost,
Mills/kW-Hr
0.365
0.366
0.368
0.371
0.379
0.377
0.380
0.385
0.392
0.410
0.490
0.491
0.493
0.497
0.506
Variable
O&M Cost,
Mills/kW-Hr
0.196
0.197
0.198
0.200
0.204
0.203
0.205
0.207
0.211
0.221
0.264
0.264
0.266
0.268
0.273
Consuma
bles,
Mills/kW-
Hr
0.110
0.170
0.270
0.471
1.073
0.459
0.683
1.055
1.800
4.035
0.248
0.333
0.474
0.758
1.609
Total
Annual
Cost,
Mills/kW-
Hr
0.734
0.815
0.945
1.197
1.925
1.355
1.628
2.074
2.948
5.507
2.724
2.834
3.013
3.362
4.371
to
oo
-------
ECONOMIC RESULTS S GRAPHICAL FORMAT
MODEL PLANT#10
o
1.925
MERCURY CONTROL COST-MODEL PLANT 10, 100 MWe,
Bituminous Coal, 3% Sulfur
2.10 T
1.90
1.70
1.50
1.30
1.10
0.90
0.70
0.50
1.1 97
7/
0.815
0.734
40% 50% 60% 70% 80% 90% 100%
Total Hg Removed, %
_k_ MODEL PLANT #13
to
MERCURY CONTROL COST -MODEL PLANT 13,100 MWe,
Bituminous Coal, 0.6% Sulfur
=*
=
c
c
~03
£
5.507
/
/X" 4.371
2.834 3-°13__ -"/
2.724. X 2.948
,/
_^-^^I
?T^ 1.628
-^ESP-4
--ESP-6
40% 50% 60% 70% 80% 90% 100%
Total Hg Removed, %
-------
Sensitivity Results: Plants 4, ESP-4, W & WO Ductwork for Added Residence Time
DATE: 6/14/00
Comments:
Application: Plant 4, ESP-4, Ductwork added upstream of ESP
Results presented with and without added ductwork
Plant sizes: 975, 500 and 100 MWe
Type of ductwork: carbon steel, polymer-lined, insulated (reflects a conservative selection of material)
Cost of ductwork: $134/sq ft
Installation labor: 0.8 hrs/sq ft
Number of ducts: 2
Duct gas velocity: 2800 ft/min
Retrofit factor: 1.3
Gas residence time in new duct: 1 second
See plot of results below table
Model
Plant #
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
13
13
13
13
13
13
13
13
13
13
Plant
Size,
MWe
975
975
975
975
975
975
975
975
975
975
500
500
500
500
500
500
500
500
500
500
100
100
100
100
100
100
100
100
100
100
Total
Mercury
Removed,
%
50.00%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
Coal Type
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Coal
Sulfur
Content,
% by Wt
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
Existing
Pollutant
Controls
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
Hg Control
Configuration
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
Added
Equipment
for Hg
Control
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System,
Ductwork
SI System,
Wl System,
Ductwork
SI System,
Wl System,
Ductwork
SI System,
Wl System,
Ductwork
SI System,
Wl System,
Ductwork
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System,
Ductwork
SI System,
Wl System,
Ductwork
SI System,
Wl System,
Ductwork
SI System,
Wl System,
Ductwork
SI System,
Wl System,
Ductwork
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System,
Ductwork
SI System,
Wl System,
Ductwork
SI System,
Wl System,
Ductwork
SI System,
Wl System,
Ductwork
SI System,
Wl System,
Ductwork
Co- Benefit
Cases with
N/A
N/A
N/A
SCR
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
SCR
N/A
N/A
N/A
N/A
N/A
N/A
Comments
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
MERCURY
SORBENT
INJECTION
RATIO
Ib/MMacf
1.94
2.95
4.64
8.03
18.17
1.94
2.95
4.64
8.03
18.17
1.94
2.95
4.64
8.03
18.17
1.94
2.95
4.64
8.03
18.17
1.94
2.95
4.64
8.03
18.17
1.94
2.95
4.64
8.03
18.17
Capital
Cost,
$/kW
7.37
7.90
8.70
10.10
13.72
10.04
10.57
11.37
12.77
16.39
9.23
9.86
10.79
12.44
16.62
12.95
13.58
14.52
16.17
20.43
16.08
17.08
18.54
21.06
27.30
21.98
22.97
24.43
26.96
33.19
Levelized
Carrying
Charges,
Mills/kW-Hr
0.17
0.18
0.20
0.24
0.32
0.23
0.25
0.27
0.30
0.38
0.22
0.23
0.25
0.29
0.39
0.30
0.32
0.34
0.38
0.48
0.38
0.40
0.43
0.49
0.64
0.51
0.54
0.57
0.63
0.78
Fixed
O&M Cost,
Mills/kW-Hr
0.049
0.050
0.051
0.053
0.057
0.050
0.050
0.051
0.053
0.058
0.087
0.088
0.090
0.092
0.097
0.088
0.088
0.090
0.092
0.098
0.383
0.385
0.387
0.391
0.400
0.383
0.385
0.387
0.391
0.400
Variable
O&M Cost,
Mills/kW-Hr
0.027
0.027
0.028
0.029
0.031
0.027
0.027
0.028
0.029
0.031
0.047
0.047
0.048
0.049
0.052
0.047
0.048
0.048
0.050
0.053
0.206
0.207
0.208
0.210
0.215
0.206
0.207
0.209
0.211
0.216
Consuma
bles,
Mills/kW-
Hr
0.185
0.271
0.414
0.700
1.557
0.185
0.271
0.414
0.700
1.557
0.185
0.271
0.414
0.700
1.557
0.185
0.271
0.414
0.700
1.557
0.185
0.271
0.414
0.700
1.557
0.185
0.271
0.414
0.700
1.557
Total
Annual
Cost,
Mills/kW-
Hr
0.434
0.533
0.696
1.017
1.966
0.496
0.596
0.759
1.080
2.029
0.535
0.637
0.804
1.132
2.095
0.623
0.724
0.891
1.219
2.185
1.150
1.262
1.442
1.793
2.810
1.288
1.400
1.580
1.931
2.948
A-4-25
-------
ECONOMIC RESULTS S GRAPHICAL FORMAT
MODEL PLANT # 4, 975 MW
MERCURY CONTROL COST - MODEL PLANT 4, ESP-4, 975 MWe, Bituminous
Coal, 0.6% Sulfur, With and Without Added Ductwork
* om
J1.50
o 125-
o ^^
c
g U.bU
2.029
m
/ 1.986
/
/
1.080^
n^ 0.759^1. 017
0.496^^33
JST 0.533
-»-975 MW, No Ductwork
--975 M
-------
RESULTS FOR MODEL PLANTS 10 AND 13 (Recycle for ESP-6)
Comments:
DATE: 6/6/00
See plot of results below table
Model
Plant #
10
10
10
10
10
13
13
13
13
13
13
13
13
13
13
Plant
Size,
MWe
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
Total
Mercury
Removed,
%
50.00%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
Coal
Type
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Coal
Sulfur
Content,
% by Wt
3
3
3
3
3
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
Existing
Pollutant
Controls
DS, ESP
DS, ESP
DS, ESP
DS, ESP
DS, ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
Hg Control
Configuration
DS/ESP-1
DS/ESP-1
DS/ESP-1
DS/ESP-1
DS/ESP-1
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-6
ESP-6
ESP-6
ESP-6
ESP-6
Added
Equipment
forHg
Control
SI System
SI System
SI System
SI System
SI System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
Co-Benefit
Cases with
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Comments
Costs for SI
Equipment Only
Costs for SI
Equipment Only
Costs for SI
Equipment Only
Costs for SI
Equipment Only
Costs for SI
Equipment Only
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
MERCURY
SORBENT
INJECTION
RATIO
Ib/MMacf
1.15
1.79
2.86
5.01
11.44
1.94
2.95
4.64
8.03
18.17
1.07
2.65
4.63
10.58
22.47
Capital
Cost,
$/kW
2.69
3.49
4.64
6.62
11.49
16.08
17.08
18.54
21.06
27.30
78.11
79.59
81.10
84.78
90.73
Levelized
Carrying
Charges,
Mills/kW-
Hr
0.063
0.081
0.108
0.155
0.268
0.376
0.399
0.433
0.492
0.638
1.824
1.859
1.894
1.980
2.119
Fixed
O&M Cost,
Mills/kW-Hr
0.365
0.366
0.368
0.371
0.379
0.383
0.385
0.387
0.391
0.400
0.498
0.500
0.503
0.508
0.517
Variable
O&M Cost,
Mills/kW-Hr
0.196
0.197
0.198
0.200
0.204
0.206
0.207
0.208
0.210
0.215
0.268
0.269
0.271
0.274
0.279
Consuma
bles,
Mills/kW-
Hr
0.110
0.170
0.270
0.471
1.073
0.185
0.271
0.414
0.700
1.557
0.166
0.274
0.409
0.816
1.629
Total
Annual
Cost,
Mills/kW-
Hr
0.734
0.815
0.945
1.197
1.925
1.150
1.262
1.442
1.793
2.810
2.756
2.903
3.077
3.578
4.544
to
-------
ECONOMIC RESULTS S GRAPHICAL FORMAT
MODEL PLANT#10
MERCURY CONTROL COST -MODEL PLANT 10, 100 MWe,
Bituminous Coal, 3% Sulfur
V 1
"^ 1 ?n
1 ^n
-------
RESULTS FOR MODEL PLANTS 10 AND 13
Comments:
DATE: 5/22/00
See plot of results below table
Model
Plant #
10
10
10
10
10
13
13
13
13
13
13
13
13
13
13
Plant
Size,
MWe
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
Total
Mercury
Removed,
%
50.00%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
Coal
Type
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Coal
Sulfur
Content,
% by Wt
3
3
3
3
3
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
Existing
Pollutant
Controls
DS, ESP
DS, ESP
DS, ESP
DS, ESP
DS, ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
Hg Control
Configuration
DS/ESP-1
DS/ESP-1
DS/ESP-1
DS/ESP-1
DS/ESP-1
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-6
ESP-6
ESP-6
ESP-6
ESP-6
Added
Equipment
forHg
Control
SI System
SI System
SI System
SI System
SI System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
Co-Benefit
Cases with
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Comments
Costs for SI
Equipment Only
Costs for SI
Equipment Only
Costs for SI
Equipment Only
Costs for SI
Equipment Only
Costs for SI
Equipment Only
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
MERCURY
SORBENT
INJECTION
RATIO
Ib/MMacf
1.15
1.79
2.86
5.01
11.44
1.94
2.95
4.64
8.03
18.17
1.07
2.65
4.63
10.58
22.47
Capital
Cost,
$/kW
2.69
3.49
4.64
6.62
11.49
16.08
17.08
18.54
21.06
27.30
78.36
80.07
81.81
86.06
92.95
Levelized
Carrying
Charges,
Mills/kW-Hr
0.063
0.081
0.108
0.155
0.268
0.376
0.399
0.433
0.492
0.638
1.830
1.870
1.911
2.010
2.171
Fixed
O&M Cost,
Mills/kW-Hr
0.365
0.366
0.368
0.371
0.379
0.383
0.385
0.387
0.391
0.400
0.498
0.501
0.504
0.510
0.520
Variable
O&M Cost,
Mills/kW-Hr
0.196
0.197
0.198
0.200
0.204
0.206
0.207
0.208
0.210
0.215
0.268
0.270
0.271
0.275
0.280
Consuma
bles,
Mills/kW-
Hr
0.110
0.170
0.270
0.471
1.073
0.185
0.271
0.414
0.700
1.557
0.182
0.316
0.484
0.987
1.994
Total
Annual
Cost,
Mills/kW-
Hr
0.734
0.815
0.945
1.197
1.925
1.150
1.262
1.442
1.793
2.810
2.779
2.957
3.170
3.783
4.966
f
to
VO
-------
ECONOMIC RESULTS S GRAPHICAL FORMAT
MODEL PLANT#10
1.925
MERCURY CONTROL COST -- MODEL PLANT 10,100 MWe,
Bituminous Coal, 3% Sulfur
2.10
1.90
1.70
1.50
1.30
1.10
0.90
0.70
0.50
DS/ESP-1
1.1 97
7/
0.815
40% 50%
60% 70% 80%
Total Hg Removed, %
90% 100%
MODEL PLANT#13
Annual Cost, Mills/kW-Hr
£
o
H
5
5
4
4
3
2
2
1
0
MERCURY CONTROL COST -- MODEL PLANT 13, 100 MWe,
Bituminous Coal, 0.6% Sulfur
00
00
00 -
00 -
50 -
00 -
50
4.966
x-1*
3.7S3,/
3.170 s*
^'aa' ^^-a-""""
2.779a .»2.810
I.TQS^X^
1.262 1.44^^__^^
1.150 « * *^
--ESP-6
40% 50% 60% 70% 80% 90% 100%
Total Hg Removed, %
-------
RESULTS FOR MODEL PLANTS 16 AND 17
05/22/2000
Comments:
1) Model Plant 16, ESP-4: Minimum Hg removal = 56.2% for ESP with Western Subbituminous Coals
2) Model Plant 17, FF-2: Minimum Hg removal = 75.7% for Reverse-Gas FF with Western Subbituminous Coals
See plot of results below table
Model
Plant #
16
16
16
16
16
16
16
16
16
16
17
17
17
17
17
Plant Size,
MWe
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
Total
Mercury
Removed,
%
56.20%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
Coal Type
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Coal
Sulfur
Content,
% by Wt
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
Existing
Pollutant
Controls
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
FF
FF
FF
FF
FF
Hg Control
Configuration
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-6
ESP-6
ESP-6
ESP-6
ESP-6
FF-2
FF-2
FF-2
FF-2
FF-2
Added
Equipment
forHg
Control
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System,
PJFF
SI System,
Wl System,
PJFF
SI System,
Wl System,
PJFF
SI System,
Wl System,
PJFF
SI System,
Wl System,
PJFF
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
Co-Benefit
Cases with
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Comments
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
MERCURY
SORBENT
INJECTION
RATIO
Ib/MMacf
0.00
2.36
4.87
9.00
21.39
0.04
0.06
0.09
0.17
0.38
0.01
0.04
0.09
0.73
1.89
Capital
Cost,
$/kW
11.63
15.21
17.52
20.68
28.38
78.65
78.73
78.84
79.02
79.46
11.73
11.88
12.05
13.25
14.71
Levelized
Carrying
Charges,
Mills/kW-Hr
0.272
0.355
0.409
0.483
0.663
1.837
1.839
1.841
1.846
1.856
0.274
0.278
0.282
0.310
0.344
Fixed
O&M Cost,
Mills/kW-Hr
0.375
0.381
0.385
0.390
0.401
0.499
0.498
0.499
0.500
0.500
0.376
0.376
0.377
0.379
0.381
Variable
O&M Cost,
Mills/kW-Hr
0.202
0.205
0.207
0.210
0.216
0.269
0.268
0.269
0.269
0.269
0.203
0.203
0.203
0.204
0.205
Consuma
bles,
Mills/kW-
Hr
0.019
0.232
0.459
0.832
1.953
0.097
0.099
0.102
0.108
0.128
0.019
0.022
0.027
0.085
0.189
Total
Annual
Cost,
Mills/kW-
Hr
0.868
1.174
1.460
1.915
3.232
2.701
2.703
2.712
2.723
2.754
0.872
0.879
0.888
0.977
1.120
-------
ECONOMIC RESULTS S GRAPHICAL FORMAT
MODEL PLANT#16
MER
-r- 3.50 -
to
"ro
c
"o
CD RY CONTROL COST --MODEL PLANT 16, 100 M We,
Subbituminous Coal, 0.5% Sulfur
y> 3.232
2701 2.703 2.712 2.723 / ,
/
1.460^^x^1-915
1.174^_-^"
0.868 *
ESP-4
--ESP-6
40% 50% 60% 70% 80% 90% 100%
Total Hg Removed, %
MODEL PLANT#17
to
MERCURY CONTROL COST -MODEL PLANT 17, 100 MWe,
Subbituminous Coal, 0.5% Sulfur
otal Annual Cost, Mills/kW-
1 nn
)» 1.120
/
/
X0.977
0.872 Q879 0.888^X
- FF-2
40 45 50 55 60 65 70 75 80 85 90 95 100
Total Hg Removed, %
-------
RESULTS FOR MODEL PLANTS 16 AND 17 (Recycle for ESP-6)
DATE: 6/6/00
Comments:
1) Model Plant 16, ESP-4: Minimum Hg removal = 56.2% for ESP with Western Subbituminous Coals
2) Model Plant 17, FF-2: Minimum Hg removal = 75.7% for Reverse-Gas FF with Western Subbituminous Coals
See plot of results below table
Model
Plant #
16
16
16
16
16
16
16
16
16
16
17
17
17
17
17
Plant Size,
MWe
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
Total Mercury
Removed, %
56.20%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
Coal Type
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Coal
Sulfur
Content,
% by Wt
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
Existing
Pollutant
Controls
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
FF
FF
FF
FF
FF
Hg Control
Configuration
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-6
ESP-6
ESP-6
ESP-6
ESP-6
FF-2
FF-2
FF-2
FF-2
FF-2
Added
Equipment
forHg
Control
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System,
PJFF
SI System,
Wl System,
PJFF
SI System,
Wl System,
PJFF
SI System,
Wl System,
PJFF
SI System,
Wl System,
PJFF
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
Co-Benefit
Cases with
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Comments
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
MERCURY
SORBENT
INJECTION
RATIO
Ib/MMacf
0.00
2.36
4.87
9.00
21.39
0.04
0.06
0.09
0.17
0.38
0.01
0.04
0.09
0.73
1.89
Capital
Cost,
$/kW
11.63
15.21
17.52
20.68
28.38
78.64
78.70
78.80
78.96
79.30
11.73
11.88
12.07
13.28
14.67
Levelized
Carrying
Charges,
Mills/kW-Hr
0.272
0.355
0.409
0.483
0.663
1.837
1.838
1.841
1.844
1.852
0.274
0.278
0.282
0.310
0.343
Fixed
O&M Cost,
Mills/kW-Hr
0.375
0.381
0.385
0.390
0.401
0.499
0.498
0.499
0.500
0.500
0.376
0.376
0.377
0.379
0.381
Variable
O&M Cost,
Mills/kW-Hr
0.202
0.205
0.207
0.210
0.216
0.269
0.268
0.269
0.269
0.269
0.203
0.203
0.203
0.204
0.205
Consuma
bles,
Mills/kW-
Hr
0.019
0.232
0.459
0.832
1.953
0.097
0.099
0.101
0.106
0.122
0.019
0.022
0.027
0.085
0.189
Total
Annual
Cost,
Mills/kW-
Hr
0.868
1.174
1.460
1.915
3.232
2.701
2.703
2.710
2.719
2.744
0.872
0.879
0.889
0.978
1.118
-------
ECONOMIC RESULTS S GRAPHICAL FORMAT
MODEL PLANT#16
MERC DRY CONTROL COST -MODEL PLANT 16, 100 M We,
Subbituminous Coal, 0.5% Sulfur
tf)
"ro
c
J3 -°°
2.701 2.703 2.710 2.719 / 3.232
/
1.460^X*1-915
1-17^-""~
0.868 *
ESP-4
--ESP-6
40% 50% 60% 70% 80% 90% 100%
Total Hg Removed, %
' MODEL PLANT#17
_^
il
to"
0
O
"ro
c
c
"o
MERCU RY CONTROL COST -MODEL PLANT 17,1 00 MWe,
SubbituminousCoal,0.5% Sulfur
1 .00 -
0.95 -
y» 1 .118
/
/
/
>/0.978
f
0.872 0.879 0.889^^
FF-2
40 45 50 55 60 65 70 75 80 85 90 95 100
Total Hg Removed, %
-------
RESULTS FOR MODEL PLANTS 16 AND 17 (ADP+40)
05/22/2000
Comments:
1) Model Plant 16, ESP-4: Minimum Hg removal = 56.2% for ESP with Western Subbituminous Coals
2) Model Plant 17, FF-2: Minimum Hg removal = 50% for Reverse-Gas FF with Western Subbituminous Coals
See plot of results below table
Model
Plant #
16
16
16
16
16
16
16
16
16
16
17
17
17
17
17
Plant Size,
MWe
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
Total
Mercury
Removed,
%
56.20%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
50.00%
60.00%
70.00%
80.00%
90.00%
Coal Type
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Subbit
Coal
Sulfur
Content,
% by Wt
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
Existing
Pollutant
Controls
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
FF
FF
FF
FF
FF
Hg Control
Configuration
ESP-4
ESP-4
ESP-4
ESP-4
ESP-4
ESP-6
ESP-6
ESP-6
ESP-6
ESP-6
FF-2
FF-2
FF-2
FF-2
FF-2
Added
Equipment
forHg
Control
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System,
PJFF
SI System,
Wl System,
PJFF
SI System,
Wl System,
PJFF
SI System,
Wl System,
PJFF
SI System,
Wl System,
PJFF
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
Co-Benefit
Cases with
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Comments
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
FG Cooling,
ADP+40F
MERCURY
SORBENT
INJECTION
RATIO
Ib/MMacf
1.32
2.62
4.87
9.00
21.39
0.13
0.21
0.34
0.59
1.36
0.03
0.11
0.26
0.73
1.89
Capital
Cost,
$/kW
6.84
8.28
10.33
13.49
21.18
71.70
71.89
72.15
72.59
73.65
4.63
4.92
5.26
6.06
7.52
Levelized
Carrying
Charges,
Mills/kW-
Hr
0.160
0.194
0.241
0.315
0.495
1.675
1.679
1.685
1.696
1.720
0.108
0.115
0.123
0.142
0.176
Fixed
O&M Cost,
Mills/kW-Hr
0.366
0.368
0.372
0.376
0.388
0.486
0.485
0.487
0.488
0.489
0.363
0.364
0.364
0.366
0.368
Variable
O&M Cost,
Mills/kW-Hr
0.197
0.198
0.200
0.203
0.209
0.262
0.261
0.262
0.263
0.264
0.195
0.196
0.196
0.197
0.198
Consuma
bles,
Mills/kW-
Hr
0.125
0.243
0.446
0.820
1.939
0.093
0.100
0.111
0.134
0.204
0.009
0.016
0.030
0.072
0.177
Total
Annual
Cost,
Mills/kW-
Hr
0.848
1.003
1.259
1.714
3.030
2.515
2.525
2.546
2.580
2.677
0.675
0.691
0.713
0.776
0.919
-------
ECONOMIC RESULTS S GRAPHICAL FORMAT
MODEL PLANT#16
MERCURY CONTROL COST -- MODEL PLANT 16, 100 MWe,
Subbituminous Coal, 0.5% Sulfur
i 3'50 "
to
O ^-uu
"ro
c
"o
3.030
2.515 2.525 2.546 2^f°__//« 2 677
/
1.259 j/1.714
1^- ^^^
0.848 «^"^
» ESP-4
--ESP-6
40% 50% 60% 70% 80% 90% 100%
Total Hg Removed, %
MODEL PLANT#17
MERCURY CONTROL COST -MODEL PLANT 17, 100 MWe,
Subbituminous Coal, 0.5% Sulfur
X
^
«
1
O
1
C
1
OQn
Don
Oyc
0.70 -
* 0.919
/
/
V0.776
0.713^^
0.675 0.691 __Jr-^
« "*""""
45% 55% 65% 75% 85% 95%
Total Hg Removed, %
-» FF-2
-------
Sensitivity Results: Plant 4, ESP-6 & ESP-7, No ICR Mod, Combined Lime-Carbon Sorbent DATE: 6/14/00
500 MW
Comments:
Application: Plant 4, ESP-6, AC sorbent (50-90% Removal); Plant 4, ESP-7, AC-Lime Sorbent (90%+ removal)
Plant size: 500 MWe
AC sorbent Cost = $908/Ton
AC-Lime Sorbent Cost = $149/Ton, Assumes C:Lime ratio = 2:19
ESP-7 Sensitivity Cases Assume 90%+ Hg Removal based on ADA Technologies tests at PSE&G
ESP-7 Sensitivity Cases run for 1, 2, 3, 4 Ib/Mmacf Sorbent Concentration
ESP-6 Comparison Cases Run for 50, 60, 70, 80, 90% Hg Removal
See plot of results below table
Model
Plant #
4
4
4
4
4
4
4
4
4
Plant
Size,
MWe
500
500
500
500
500
500
500
500
500
Total
Mercury
Removed,
%
50.00%
60.00%
70.00%
80.00%
90.00%
90.00%
90.00%
90.00%
90.00%
Coal Type
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Bit
Coal
Sulfur
Content,
% by Wt
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
Existing
Pollutant
Controls
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
Hg Control
Configuration
ESP-6
ESP-6
ESP-6
ESP-6
ESP-6
ESP-7
ESP-7
ESP-7
ESP-7
Added
Equipment
forHg
Control
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
SI System,
Wl System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
PJFF, SI
System, Wl
System
Co-Benefit
Cases with
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Comments
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
FG Cooling,
ADP+18F
MERCURY
SORBENT
INJECTION
RATIO
Ib/MMacf
1.07
1.66
2.65
4.63
10.58
1.00
2.00
3.00
4.00
Capital
Cost,
$/kW
54.48
54.91
55.55
56.67
59.46
54.33
54.94
55.46
55.93
Levelized
Carrying
Charges,
Mills/kW-Hr
1.27
1.28
1.30
1.32
1.39
1.27
1.28
1.30
1.31
Fixed O&M
Cost,
Mills/kW-Hr
0.171
0.171
0.172
0.174
0.178
0.171
0.172
0.173
0.173
Variable
O&M Cost,
Mills/kW-Hr
0.092
0.092
0.093
0.094
0.096
0.092
0.092
0.093
0.093
Consumables,
Mills/kW-Hr
0.182
0.232
0.316
0.484
0.988
0.108
0.125
0.141
0.158
Total Annual
Cost,
Mills/kW-Hr
1.717
1.779
1.879
2.075
2.650
1.640
1.672
1.702
1.731
-------
ECONOMIC RESULTS S GRAPHICAL FORMAT
MODEL PLANT # 4, 500 MW, Comparison of ESP-6 and ESP-7
>
oo
MODEL PLANT # 4, 1 00 MW
MERCURY CONTROL COST - MODEL PLANT 4, ESP-6 & 7, 500 MWe, Bituminous
Coal, 0.6%Sulfur, Comparison of AC Sorbent and LJme-AC Sorbent
2.75
2.50
« 2.00
< 1.75
I
1.50
/2.650
_/2.
2.075
1731
1779
1.672I1702
1.640
-"ESP-6, ACsorbent
-ESP-7, Lime-ACSorbent
40% 50% 60% 70% 80% 90% 100%
Total Hg Removed, %
MERCURY CONTROL COST -- MODEL PLANT 4, ESP-4, 1 00 MWe,
Bituminous Coal, 0.6% Sulfur, With and Without Added Ductwork
T ^ nn
^ 250
^ 225 -
S 9nn
o Z.UU
< A pC
(0 L"
2.948
/?
72.810
//
1 .931/7
1.580 ^7Q,
1 .400 ^Jf^/
1 .288» J^---^*l".442
1*150 1-262
-100 MW, No Ductwork
--100 MW, W Ductwork
40% 50% 60% 70% 80% 90% 100%
Total Hg Removed, %
-------
1. REPORT NO. 2.
EPA-600/R-00-083
4. TITLE AND SUBTITLE
Performance and Cost of Mercury Emission Control
Technology Applications on Electric Utility Boilers
7. AUTHORS
Ravi K. Srivastava, Charles B. Sedman, and
James D. Kilgroe
9. PERFORMING ORGANIZATION NAME AND ADDRESS
See Block 12
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Air Pollution Prevention and Control Division
Research Triangle Park, NC 27711
3. RECIPIENT'S ACCESSIONNO.
5. REPORT DATE
Seotember 2000
6. PERFORMING ORGANIZATION CODE
8. PERFORMING ORGANIZATION REPORT NO.
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
NA(lnhouse)
13. TYPE OF REPORT AND PERIOD COVERED
Final; 2/00 - 9/00
14. SPONSORING AGENCY CODE
EPA/ 600/1 3
TECHNICAL REPORT DATA
15. SUPPLEMENTARY NOTES AppcD project officer is Ravi K. Snvastava, Mail Drop 65, 919/
541.3444.
16. ABSTRACT
The report presents estimates of the performance and cost of powdered ac-
tivated carbon (PAC) injection-based mercury control technologies and projections of
costs for future applications. (NOTE: Under the Clean Air Act Amendments of 1990,
the U.S. EPA has to determine whether mercury emissions from coal-fired power plants
should be regulated. These estimates and projections were developed to aid in this
determination.) Estimates based on currently available data using PAC range from
0.305 to 3.783 mills/kWh. However, the higher costs are associated with the minority
of plants using hot-side electrostatic precipitators (HESPs). If these costs are excluded,
the estimates range from 0.305 to 1.915 mills/kWh. Cost projections, developed based
on using a composite lime-PAC sorbent for mercury re-moval, range from 0.183 to
2.270 mills/kWh, with the higher costs being associated with the minority of plants
using HESPs. A comparison of mercury control costs with those of nitrogen oxides
(NOx) controls reveals that total annual costs for mer-cury lie mostly between
applicable costs for low Nox burners and selective catalytic reduction. The performance
and cost estimates of the PAC injection-based mercury control technologies presented in
the report are based on a relatively few data points from pilot-scale tests and, therefore,
are considered to be preliminary.
KEY WORDS AND DOCUMENT ANALYSIS
a. DESCRIPTORS
Pollution
Mercury (Metal)
Emission
Electric Utilities
Boilers
Coal
Combustion
Activated Carbon
Performance
Cost Estimates
Electrostatic Pre-
cipitators (ESPs)
18. DISTRIBUTION STATEMENT
Release to Public
b. IDENTIFIERS/OPEN ENDED TERMS
Pollution Control
Stationary Sources
19. SECURITY CLASS (This Report)
Unclassified
20. SECURITY CLASS (This Page)
Unclassified
c. COSATI Field/Group
13B 21B
07B 11G
14G
13B 05A, 14A
21D 13K
21. NO. OF PAGES
121
22. PRICE
EPA Form 2220-1 (Rev. 4-77 ) PREVIOUS EDITION IS OBSOLETE
A-4-39
------- |