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Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc
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Northshore Mining Company Analysis of Best Available Retrofit Technology (BART)
Table of Contents
1. Executive Summary............................................................................................................................. iv
2. Introduction........................................................................................................................................... 1 2.A BART Eligibility......................................................................................................................... 3
2.B BART Determinations ................................................................................................................ 4
3. Streamlined BART Analysis ................................................................................................................ 9 3.A Indurating Furnaces .................................................................................................................... 9
3.B PM-Only Taconite MACT Emission Units ................................................................................ 9
3.C Sources of fugitive PM that are subject to MACT standards.................................................... 10
3.D Non-MACT Units and Fugitive Sources (PM only) ................................................................. 10
3.E Other Combustion Units ........................................................................................................... 10
3.F Visibility Impact Modeling for Negligible Impacts.................................................................. 11
4. Baseline Conditions and Visibility Impacts for BART Eligible Units ............................................... 13 4.A MPCA Subject-to-BART Modeling ......................................................................................... 13
4.B Facility Baseline Modeling ....................................................................................................... 14
4.C Facility Baseline Modeling Results .......................................................................................... 19
5. Full BART Analysis for BART Eligible Emission Units................................................................... 21 5.A Indurating Furnace .................................................................................................................... 21
5.A.i Sulfur Dioxide Controls............................................................................................... 22
5.A.i.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 22
5.A.i.b STEP 2 – Eliminate Technically Infeasible Options.................................... 22
5.A.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies ................................................................................................ 27
5.A.i.d STEP 4 – Evaluate Impacts and Document the Results ............................... 28
5.A.i.e STEP 5 – Evaluate Visibility Impacts.......................................................... 30
5.A.ii Nitrogen Oxide Controls.............................................................................................. 30
5.A.ii.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 31
5.A.ii.b STEP 2 – Eliminate Technically Infeasible Options.................................... 31
5.A.ii.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies ................................................................................................ 43
5.A.ii.d STEP 4 – Evaluate Impacts and Document the Results ............................... 44
5.A.ii.e STEP 5 – Evaluate Visibility Impacts.......................................................... 45
5.B External Combustion Sources................................................................................................... 47
5.B.i Sulfur Dioxide controls................................................................................................ 47
5.B.i.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 47
5.B.i.b STEP 2 – Eliminate Technically Infeasible Options.................................... 47
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5.B.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies ................................................................................................ 51
5.B.i.d STEP 4 – Evaluate Impacts and Document the Results ............................... 51
5.B.i.e STEP 5 – Evaluate Visibility Impacts.......................................................... 53
5.B.ii Nitrogen Oxide Controls.............................................................................................. 54
5.B.ii.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 54
5.B.ii.b STEP 2 – Eliminate Technically Infeasible Options.................................... 54
5.B.ii.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies ................................................................................................ 61
5.B.ii.d STEP 4 – Evaluate Impacts and Document the Results ............................... 62
5.B.ii.e STEP 5 – Evaluate Visibility Impacts.......................................................... 64
6. Visibility Impacts................................................................................................................................ 67 6.A Post-BART Modeling Scenarios............................................................................................... 67
6.B Post-BART Modeling Results .................................................................................................. 67
7. Select BART....................................................................................................................................... 71
List of Tables
Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis ....12
Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions Data ..15
Table 4-2 Baseline Visibility Modeling Results ..........................................................................20
Table 5-1 Indurating Furnace SO2 Control Technology – Availability, Applicability, and Technical Feasibility ..................................................................................................27
Table 5-2 Indurating Furnace SO2 Control Technology Effectiveness .........................................27
Table 5-3 Indurating Furnace SO2 Control Cost Summary ..........................................................29
Table 5-4 Indurating Furnace NOx Control Technology – Availability, Applicability, and Technical Feasibility ..................................................................................................43
Table 5-5 Indurating Furnace NOx Control Technology Effectiveness ........................................43
Table 5-6 Indurating Furnace NOx Control Cost Summary .........................................................44
Table 5-7 Backup Process Boiler SO2 Control Technology – Availability, Applicability, and Technical Feasibility ..................................................................................................51
Table 5-8 Backup Process Boiler SO2 Control Technology Effectiveness ...................................51
Table 5-9 Backup Process Boiler SO2 Control Cost Summary....................................................52
Table 5-10 Backup Process Boiler NOx Control Technology – Availability, Applicability and Technical Feasibility ..................................................................................................61
Table 5-11 Backup Process Boiler NOx Control Technology Effectiveness ..................................61
Table 5-12 Backup Process Boiler NOx Control Cost Summary....................................................62
Table 5-13 Backup Process Boiler NOx Control Technology – Other Impacts Assessment............63
Table 5-14 Backup Process Boiler NOx Post- BART Emission Rates for Emission Unit EU003 and EU004........................................................................................................................64
Table 5-15 Backup Process Boiler Post-BART Modeling Scenarios .............................................65
Table 5-16 Backup process Boiler Post-BART NOx Modeling Scenarios - Modeling Input Data ..66
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Table 5-17 Backup Process Boiler Post-BART NOx Modeling Scenarios - Visibility Modeling Results .......................................................................................................................66
Table 5-18 Backup Process Boiler Post-BART NOx Modeling Scenarios – Comparison of Visibility Modeling Results to Baseline Modeling Results ..........................................66
Table 6-1 Post-BART Modeling Scenarios .................................................................................69
Table 6-2 Post-BART Modeling Scenarios - Visibility Modeling Results ...................................70
Table 6-3 Post-BART Modeling Scenarios – Comparison of Visibility Modeling Results to Baseline Modeling Results .........................................................................................70
List of Figures
Figure 2-1 Minnesota’s BART Geography.....................................................................................2
List of Appendices
Appendix A Control Cost Analysis Spreadsheets
Appendix B Changes to MPCA BART Modeling Protocol
Appendix C Visibility Impacts Modeling Report
Appendix D Applicable and Available Retrofit Technologies for Indurating Furnaces
Appendix E Clean Air Interstate Rule (CAIR), Cost-Effective Air Pollution Controls
Appendix F Applicable and Available Retrofit Technologies for Process Boilers
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1. Executive Summary
Northshore Mining Company (NMC) is located in northern Minnesota, with mining facilities located
at Babbit and a taconite processing plant located at Silver Bay. This report describes the background
and methods for the selection of the Best Available Retrofit Technology (BART) as proposed by
NMC for its taconite processing plant.
Minnesota Pollution Control Agency MPCA identified 36 pieces of equipment at NMC that were
installed within the time window (1962-1977) that makes them subject to BART. The equipment
includes two straight-grate indurating furnace lines (Furnaces 11 and 12) and two backup steam
process boilers ( Process Boilers 1 and 2) that use natural gas and oil for fuel, as well material
handling and/or storage units for ore, product, and additives. Preliminary visibility modeling
conducted by the Minnesota Pollution Control Agency MPCA found that air emissions from NMC
“cause or contribute to visibility impairment” in a federally protected Class I area, therefore making
the facility subject to BART.
Guidelines included in 40 CFR §51 Appendix Y and MPCA Attachments 2 and 3 were used to
propose BART. The existing pollution control equipment on the furnace lines includes a wet walled
electrostatic precipitator (WWESP) designed to control of particulate matter (PM) and sulfur dioxide
(SO2). A dispersion modeling sequence of CALMET, CALPUFF, and CALPOST was used to assess
the visibility impacts of the baseline emissions and after the application of candidate BART controls.
Visibility impacts were evaluated in the selection of BART. Other criteria that the BART rules
require to be considered include the availability of technology, costs of compliance, energy and
environmental impacts of compliance, existing pollution control technology in use at the source, and
the remaining useful life of the source.
Based on consideration of all of the above criteria, NMC proposes the following as BART:
• SO2 emissions will be controlled by the existing WWESPs on the taconite furnaces. The
process boilers will have no additional controls. NOx emissions will be controlled by good
combustion practices for the taconite mining process for the furnaces and process boilers.
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• PM emissions at the furnaces will be controlled as prescribed by the taconite maximum
achievable control technology (MACT) standard1. The existing WWESPs adequately control
PM emissions from the furnaces to meet the MACT standard. The process boilers will have
no additional controls.
The CALPUFF model is conservative, resulting in an over prediction of impacts2. This modeled
high impact from the BART eligible sources is 1.1 deciviews (dV), slightly above perceptible levels
of one to two dV. The modeling also shows that these sources do affect Class I area visibility at less
than 10 percent of the time based on the model predicting an impact greater than 0.5dV only 34 to 38
days per year. Real impacts to the Class I areas from NMC are expected to be even less than these
modeled impacts. NMC will continue to evaluate energy efficiency projects and other mechanisms
to reduce their visibility impairment pollutants emission rates.
1 40 CFR 63 Subpart RRRRR-and DDDDD NESHAPS: Taconite Iron Ore Processing and Industrial Commercial and Institutional Boilers and Process Heaters 2 Federal Register 70, 128 (July 6, 2005): 39123
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2. Introduction
Northshore Mining Company (NMC) is located in northern Minnesota, with mining facilities located
at Babbit and a taconite processing plant located at Silver Bay.. This report describes the background
and methods for the selection of the Best Available Retrofit Technology (BART) as proposed by
NMC for its taconite processing plant.
To meet the Clean Air Act’s requirements, the U.S. Environmental Protection Agency (U.S. EPA)
published regulations to address visibility impairment in our nation’s largest national parks and
wilderness (“Class I”) areas in July 1999. This rule is commonly known as the “Regional Haze
Rule” [64 Fed. Reg. 35714 (July, 1999) and 70 Fed. Reg. 39104 (July 6, 2005)] and is found in 40
CFR part 51, in 300 through 309.
Within its boundary, Minnesota has two Class I areas – the Boundary Waters Canoe Area Wilderness
and Voyageurs National Park. In addition, emissions from Minnesota may contribute to visibility
impairment in other states’ Class I areas, such as Michigan’s Isle Royale National Park and Seney
Wilderness Area. By December 2007, MPCA must submit to U.S. EPA a Regional Haze State
Implementation Plan (SIP) that identifies sources that cause or contribute to visibility impairment in
these areas. The Regional Haze SIP must also include a demonstration of reasonable progress toward
reaching the 2018 visibility goal for each of the state’s Class I areas.
One of the provisions of the Regional Haze Rule is that certain large stationary sources that were put
in place between 1962 and 1977 must conduct a Best Available Retrofit Technology (BART)
analysis. The purpose of the BART analysis is to analyze available retrofit control technologies to
determine if a technology should be installed to improve visibility in Class I areas. The chosen
technology is referred to as the BART controls, or simply BART. The SIP must require BART on all
BART-eligible sources and mandate a plan to achieve natural background visibility by 2064.
Figure 2-1 illustrates the BART-eligible facilities and the two Class I areas in Minnesota. When
reviewing Figure 2-1, it is important to note that Minnesota Steel Industries (MSI) and Mesabi
Nugget (Nugget), which are illustrated in the figure, are not currently in operation. The SIP must
also include milestones for establishing reasonable progress towards the visibility improvement goals
and plans for the first five-year period. Upon submission of the Regional Haze SIP, states must make
the requirements for BART sources enforceable through rules, administrative orders or Title V
permit amendments.
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Figure 2-1 Minnesota’s BART Geography The Minnesota SIP will address the 2 PSD Class I Areas [Voyageurs National Park (VPN) and Boundary Waters Canoe Area (BWCA)] and BART-eligible units illustrated above. Facilities indicated in yellow are
future facilities. (Source MPCA BART-Strategy October 4, 2005)
By U. S. EPA’s definition, reasonable progress means that there is no degradation of the 20 best-
visibility days, and the 20 worst-visibility days must have no more visibility impairment than the 20
worst days under natural conditions by 20643. Assuming a uniform rate of progress, the default glide
path would require 1 to 2 percent improvement per year in visibility on the 20 worst days. The state
must submit progress reports every five years to establish their advancement toward the Class I area
natural visibility backgrounds. If a state feels it may be unable to adopt the default glide path, a
slower rate of improvement may be proposed on the basis of cost or time required for compliance and
non-air quality impacts.
3 See the preamble to the final BART and Regional Haze Rules, 70 FR No. 178, pp. 39104-39172
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Note that the improvements required under the Regional Haze regulations are different from the
BART requirements. Facilities subject to BART are not required to make all of the reasonable
progress towards improving regional haze in Class I areas. Rather, BART is but one of many
measures which state may rely upon in making ‘reasonable progress” towards regional haze
improvement goals.
2.A BART Eligibility BART eligibility is established on the basis on three criteria. In order to be BART-eligible, sources
must meet the following three conditions:
1. Contain emission units in one or more of the 26 listed source categories under the PSD rules
(e.g., taconite ore processing plants, fossil-fuel-fired steam electric plants larger than 250
MMBtu/hr, fossil-fuel boilers larger than 250 MMBtu/hr, petroleum refineries, coal cleaning
plants, sulfur recovery plants, etc.);
2. Were in existence on August 7, 1977, but were not in operation before August 7, 1962;
3. Have total potential emissions greater than 250 tons per year for at least one visibility-
impairing pollutant from the emission units meeting the two criteria above.
Under the BART rules, large sources that have previously installed pollution-control equipment
required under another standard (e.g., MACT, NSPS and BACT) will be required to conduct
visibility analyses. Installation of additional controls may be required to further reduce emissions of
visibility impairing pollutants such as PM, PM10, PM2.5, SO2, NOx, and possibly Volatile Organic
Compounds (VOCs) and ammonia. Sources built before the implementation of the Clean Air Act
(CAA), which had previously been grandfathered, may also have to conduct such analyses and
possibly install controls, even though they have been exempted to date from any other CAA
requirements.
Once BART eligibility is determined, a source must then determine if it is “subject to BART.” A
source is subject to BART if emissions “cause or contribute” to visibility impairment at any Class I
area. Visibility modeling conducted with CALPUFF or another U.S. EPA -approved visibility model
is necessary to make a definitive visibility impairment determination (>0.5 deciviews). Sources that
do not cause or contribute to visibility impairment are exempt from BART requirements, even if they
are BART-eligible.
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2.B BART Determinations Each source that is subject to BART must determine BART on a case-by-case basis. Even if a source
was previously part of a group BART determination, individual BART determinations must be made
for each source. The BART analysis takes into account six criteria and is analyzed using five steps.
The six criteria that comprise the engineering analysis include: the availability of the control
technology, existing controls at a facility, the cost of compliance, the remaining useful life of a
source, the energy and non-air quality environmental impacts of the technology, and the visibility
impacts.4 The five steps of a BART analysis are:
Step 1 - Identify all Available Retrofit Control Technologies The first step in the analysis is to identify all retrofit control technologies which are
generally available for each applicable emission unit. Available retrofit control
technologies are defined by U.S. EPA in Appendix Y to Part 51 (Guidelines for BART
Determinations Under the Regional Haze Rule) as follows:
Available retrofit technologies are those air pollution control technologies
with a practical potential for application to the emissions unit and the
regulated pollutant under evaluation. Air pollution control technologies can
include a wide variety of available methods, systems, and techniques for
control of the affected pollutant. Technologies required as BACT or LAER
are available for BART purposes and must be included as control
alternatives. The control alternatives can include not only existing controls
for the source category in question, but also take into account technology
transfer of controls that have been applied to similar source categories or gas
streams. Technologies which have not yet been applied to (or permitted for)
full scale operations need not be considered as available; we do not expect
the source owner to purchase or construct a process or control device that
has not been demonstrated in practice.5
Step 2 - Eliminate Technically Infeasible Options
In the second step, the source-specific technical feasibility of each control option
identified in step one is evaluated by answering three specific questions:
4 40 CFR 51 Appendix Y 5 Federal Register 70, No. 128 (July 6, 2005): 39164
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1. Is the control technology “available” to the specific source which is undergoing the
BART analysis?
The U.S. EPA states that a control technique is considered “available” to a specific
source “if it has reached the stage of licensing and commercial availability.6”
However, the U.S. EPA further states that they “do not expect a source owner to
conduct extended trials to learn how to apply a technology on a totally new and
dissimilar source type.7”
2. Is the control technology an “applicable technology” for the specific source which
is undergoing the BART analysis?
In general, a commercially available control technology, as defined in question 1,
“will be presumed applicable if it has been used on the same or a similar source
type.8” If a control technology has not been demonstrated on a same or a similar
source type, the technical feasibility is determined by “examining the physical and
chemical characteristics of the pollutant-bearing stream and comparing them to the
gas stream characteristics of the source types to which the technology has been
applied previously.9”
3. Are there source-specific issues/conditions that would make the control technology
not technically feasible?
This question addresses specific circumstances that “preclude its application to a
particular emission unit.” This demonstration typically includes an “evaluation of
the characteristics of the pollutant-bearing gas stream and the capabilities of the
technology10.” This also involves the identification of “un-resolvable technical
difficulties.” However, when the technical difficulties are merely a matter of
increased cost, the technology should be considered technically feasible and the
technological difficulty evaluated as part of the economic analysis11.
6 Federal Register 70, No. 128 (July 6, 2005): 39165 7 IBID 8 IBID 9 IBID 10 IBID 11 IBID
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It is also important to note that vendor guarantees can provide an indication of
technical feasibility but the U.S. EPA does not “consider a vendor guarantee alone
to be sufficient justification that a control option will work.” Conversely, the U.S.
EPA does not consider as “sufficient justification that a control option or emission
limit is technically infeasible. In general, the decisions on technical feasibility
should be based on a combination of the evaluation of the chemical and engineering
analysis and the information from vendor guarantees12.
Step 3 - Evaluate Control Effectiveness In step three, the remaining controls are ranked based on the control efficiency at the
expected emission rate (post BART) as compared to the emission rate before addition
of controls (pre-BART) for the pollutant of concern.
Step 4 - Evaluate Impacts and Document Results In the fourth step, an engineering analysis documents the impacts of each remaining
control technology option. The economic analysis compares dollar per ton of pollutant
removed for each technology. In addition it includes incremental dollar per ton cost
analysis to illustrate the economic effectiveness of one technology in relation to the
others. Finally, Step Four includes an assessment of energy impacts and other non-air
quality environmental impacts.
Economic impacts were analyzed using the procedures found in the U.S. EPA Air
Pollution Control Cost Manual – Sixth Edition (EPA 452/B-02-001). Equipment cost
estimates from the U.S. EPA Air Pollution Control Cost Manual or U.S. EPA’s Air
Compliance Advisor (ACA) Air Pollution Control Technology Evaluation Model
version 7.5 were used. Vendor cost estimates for this project were used when
applicable. The source of the control equipment cost data are noted in each of the
control cost analysis worksheets as found in Appendix A.
Step 5 - Evaluate Visibility Impacts
The fifth step requires a modeling analysis conducted with U.S. EPA -approved models
such as CALPUFF. The modeling protocol13, including receptor grid, meteorological
data, and other factors used for this part of the analysis were provided by the Minnesota
12 IBID 13 MPCA. October 10, 2005. Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject to
BART in the State of Minnesota.
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Pollution Control Agency. The model outputs, including the 98th percentile dV value
and the number of days the facility contributes more than a 0.5 deciview (dV) of
visibility impairment at each of the Class I areas, are used to establish the degree of
improvement that can be reasonably attributed to each technology.
The final step in the BART analysis is to select the “best” alternative using the results of steps 1
through 5. In addition, the U.S. EPA and MPCA guidance states that the “affordability” of the
controls should be considered, and specifically states:
1. Even if the control technology is cost effective, there may be cases where the installation
of controls would affect the viability of plant operations.
2. There may be unusual circumstances that justify taking into consideration the conditions
of the plant and the economic effects requiring the use of a given control technology.
These effects would include effects on product prices, the market share, and profitability
of the source. Where there are such unusual circumstances that are judged to affect
plant operations, you may take into consideration the conditions of the plant and the
economic effects of requiring the use of a control technology. Where these effects are
judged to have severe impacts on plant operations you may consider them in the selection
process, but you may wish to provide an economic analysis that demonstrates, in
sufficient detail for public review, the specific economic effects, parameters, and
reasoning. (We recognize that this review process must preserve the confidentiality of
sensitive business information). Any analysis may also consider whether competing
plants in the same industry have been required to install BART controls if this
information is available.14
To complete the BART process, the analysis must “establish enforceable emission limits that reflect
the BART requirements and requires compliance within a reasonable period of time15.” Those limits
must be developed for inclusion in the state implementation plan (SIP) that is due to U.S. EPA in
December of 2007. In addition, the analysis must include requirements that the source “employ
techniques that ensure compliance on a continuous basis16.” which could include the incorporation of
other regulatory requirements for the source, including Compliance Assurance Monitoring (40 CFR
14 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 20. 15 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 23. 16 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 23.
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64), Periodic Monitoring (40 CFR 70.6(a)(3)) and Sufficiency Monitoring (40 CFR 70(6)(c)(1)). If
technological or economic limitations make measurement methodology for an emission unit
infeasible, the BART limit can “instead prescribe a design, equipment, work practice, operation
standard, or combination of these types of standards17.”
Compliance with the BART emission limits will be required within 5 years of U.S. EPA approval of
the Minnesota SIP.
17 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 23.
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3. Streamlined BART Analysis
Within the preamble to the final federal BART rule, U.S. EPA explicitly encouraged states to include
a streamlined approach for BART analyses18. The streamlined approach will allow both states and the
facilities to focus their resources on the main contributors to visibility impairment. This section of
the report follows the MPCA approved streamlined BART analysis for taconite facilities and presents
the results of the streamlined approach.
3.A Indurating Furnaces The indurating furnaces are sources of three visibility impairing pollutants: NOx, SO2, and PM. The
indurating furnaces is subject to the taconite MACT standard19 for the PM emissions. MPCA’s
guidance for conducting a BART review states that “MPCA will rely on MACT standards to
represent BART level of control for those visibility impairing pollutants addressed by the MACT
standard unless there are new technologies subsequent to the MACT standard, which would lead to
cost-effective increases in the level of control.” [Attachment 2, March 2006, page 2]. Since the
MACT standard was established very recently and becomes effective in 2006, the technology
analysis is up-to-date. As a result, BART will be presumed to be equivalent to MACT for PM and no
further analysis will be required to establish BART for PM for this source.
A full BART analysis will be conducted for NOx and SO2 where applicable.
3.B PM-Only Taconite MACT Emission Units In addition to the indurating furnaces, the taconite MACT standard also regulates PM emissions from
Ore Crushing and Handling operations, Pellet Coolers, and Finished Pellet Handling operations.
These sources operate near ambient temperature, only emit PM, and do not emit NOx or SO2. The
Ore Crushing and Handling sources and the Finished Pellet Handling sources operate with control
equipment to meet the applicable MACT limits (0.008 gr/dscf for existing sources and 0.005 gr/dscf
for new sources). The Pellet Cooler sources are excluded from additional control under the MACT
standard due to the large size of the particles and the relatively low concentration of particle
emissions [FR, December 18, 2002, page 77570]. Therefore, the emissions from the pellet coolers
are considered to have a negligible impact on visibility impairment, and no control requirements
under the MACT standard is consistent with the intention of the BART analysis.
18 Federal Register 70, no. 128 (July 6, 2005): 39107 and 39116 19 40 CFR 63 Subpart RRRRR-NESHAPS: Taconite Iron Ore Processing
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Since the MACT standard was established recently and will become effective in 2006, the technology
analysis is up-to-date. Again, for these units subject to a MACT standard, BART will be presumed
to be equivalent to MACT according to MPCA guidance.
No further analysis will be required to establish BART for these sources.
3.C Sources of fugitive PM that are subject to MACT standards The taconite MACT standard also regulates fugitive PM emissions (fugitive PM emissions from non-
MACT sources are addressed in section 3.D). No equipment that emits fugitive PM has been
identified at NMC as potentially BART-eligible equipment, so these sources are not required to be
addressed. Therefore, no further analysis will be required to establish BART for these sources.
3.D Non-MACT Units and Fugitive Sources (PM only) A few sources of PM emissions and sources of fugitive PM are not subject to a MACT standard.
They include units such as:
• Bentonite storage and handling
• Additive storage and handling
• Concentrate storage and handling Considering all PM emissions which are subject to the BART standard, the PM emissions from the
above units typically represent less than 2.5% of PM emissions from the facility, which are subject to
BART.
The point source emission units are controlled by baghouses, which is a technology that achieves a
high level of control for PM. Since these units already have control equipment for PM emissions,
and since the PM emissions from these sources are small relative to the total PM emissions that are
subject to the BART standard, additional control of these sources can be presumed to have minimal
impact on visibility improvement in Class I areas. Existing controls will be considered BART
consistent with direction from MPCA in the May 18, 2006 meeting.
No equipment that emits fugitive PM has been identified at NMC as potentially BART-eligible
equipment, so these sources are not required to be addressed. No further analysis will be required to
establish BART for these sources.
3.E Other Combustion Units The combustion units are sources of three visibility impairing pollutants: NOx, SO2, and PM.
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NMC facility has two process boilers that are subject to the boiler MACT20. Since the boiler MACT
standards were established recently and become effective in 2007, the technology analysis is up-to-
date. For the units subject to the boiler MACT standard, BART will be presumed to be equivalent to
MACT for PM according to MPCA guidance. A full BART analysis will be conducted for NOx and
SO2.
The Northshore facility also has a powerhouse which will require a full BART analysis. That
analysis is provided in a separate report.
3.F Visibility Impact Modeling for Negligible Impacts The streamlined BART approach allows for a screening modeling demonstration of negligible
visibility impacts for fugitive sources and combustion units other than indurating furnaces and
process boilers. NMC does not have any potentially BART eligible sources that require screening
modeling.
20 40 CFR 63 Subpart DDDDD-NESHAPS: ICI Boilers and Process Heaters
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Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis
Emission Unit # Emission Unit Description
Visibility-Impairing Pollutant
Applicable Limit
1
gr/dscf Maximum Daily
lbs/day2
3.A Indurating Furnaces EU 100 Furnace 11 Hood Exhaust PM 0.01 272 EU 100 Furnace 11 Hood Exhaust PM 0.01 272 EU 100 Furnace 11 Hood Exhaust PM 0.01 272 EU 104 Furnace 11 Waste Gas PM 0.01 255 EU 104 Furnace 11 Waste Gas PM 0.01 255 EU 110 Furnace 12 Hood Exhaust PM 0.01 272 EU 110 Furnace 12 Hood Exhaust PM 0.01 272 EU 110 Furnace 12 Hood Exhaust PM 0.01 272 EU 114 Furnace 12 Waste Gas PM 0.01 255 EU 114 Furnace 12 Waste Gas PM 0.01 255
3.B PM-Only Taconite MACT Emission Units EU 008 East Car Dump PM 0.008 32 EU 010 Fine Crusher Bin Storage – East PM 0.008 45 EU 016 Crushed Ore Conveyors – East PM 0.008 12 EU 017 Fine Crushing Line 101 PM 0.008 8 EU 018 Fine Crushing Line 102 PM 0.008 8 EU 019 Fine Crushing Line 103 PM 0.008 8 EU 020 Fine Crushing Line 104 PM 0.008 8 EU 031 Concentrator Transfer Bin – East PM 0.008 8 EU 044 Concentrator Bin - Section 101 PM 0.008 18 EU 045 Concentrator Bin - Section 102 PM 0.008 18 EU 046 Concentrator Bin - Section 103 PM 0.008 18 EU 047 Concentrator Bin - Section 104 PM 0.008 18 EU 048 Concentrator Bin - Section 105 PM 0.008 18 EU 049 Concentrator Bin - Section 106 PM 0.008 18 EU 050 Concentrator Bin - Section 107 PM 0.008 18 EU 051 Concentrator Bin - Section 108 PM 0.008 18 EU 052 Concentrator Bin - Section 109 PM 0.008 18 EU 053 Concentrator Bin - Section 110 PM 0.008 18 EU 120 Furnace 11 Discharge PM 0.008 95 EU 121 Furnace 12 Discharge PM 0.008 95 EU 122 Furnace 11 Screening PM 0.008 95 EU 124 Furnace 12 Screening PM 0.008 95
3.D Non-MACT Emission Units and Fugitive Sources (PM-Only) EU 077 Furnace 11 Day Bin Collector PM 0.01 4 EU 078 Furnace 11 Air Slide Collector PM 0.01 4 EU 079 Furnace 12 Day Bin Collector PM 0.01 4 EU 080 Furnace 12 Air Slide Collector PM 0.01 4 EU 081 East Pelletizer Bentonite Storage - Bin 3,4 PM 0.01 4 EU 082 East Pelletizer Bentonite Storage - Bin 5,6 PM 0.01 4 EU 083 Bentonite Unloading Collector PM 0.01 4 EU 084 Supplemental Bentonite Unloading Collector PM 0.01 10
3.E Other Combustion Units lb/mmBtu EU 003 Process Boiler #1 PM 0.6 45 EU 004 Process Boiler #2 PM 0.6 45 1PM – Filterable PM only as measured by U.S. EPA Method 5 including the applicable averaging and grouping
provisions, as presented in the MACT regulation, effective October 26, 2006. 2Based on baseline flow rates.
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4. Baseline Conditions and Visibility Impacts for BART Eligible Units
As indicated in U.S. EPA’s final BART guidance21, one of the factors to consider when determining
BART for an individual source is the degree of visibility improvement resulting from the retrofit
technology. The visibility impacts for this facility were estimated using CALPUFF, an U.S. EPA
approved model recommended for comparing the visibility improvements of different retrofit control
alternatives22 (REFERNECE FED. GUIDANCE PREAMBLE pages 39127 – 39129 as appropriate).
However it is important to note that CALPUFF is a conservative model that over estimates real
impacts. Therefore, although the CALPUFF baseline modeling results are important to comparing
control alternatives on a relative basis they are do not accurately predict real impacts.
The CALPUFF program models how a pollutant contributes to visibility impairment with
consideration for the background atmospheric ammonia, ozone and meteorological data.
Additionally, the interactions between the visibility impairing pollutants NOx, SO2, PM2.5 and PM10
can play a large part in predicting impairment. It is therefore important to take a multi-pollutant
approach when assessing visibility impacts.
In order to estimatedetermine the visibility improvement resulting from the retrofit technology, the
source must first be modeled at baseline conditions. Per MPCA guidance, the baseline, or pre-BART
conditions, shall represent the average emission rate in units of pounds per hour (lbs/hr) and reflect
the maximum 24-hour actual emissions23.
4.A MPCA Subject-to-BART Modeling In order to determine which sources are “Subject-to-BART” in the state of Minnesota, the MPCA
completed modeling of the BART-eligible emission units at various facilities in Minnesota in
accordance with the Regional Haze rule. The modeling by MPCA was conducted using CALPUFF,
as detailed in the “Best Available Retrofit Technology (BART) Modeling Protocol to Determine
Sources Subject-to-BART in the State of Minnesota,” finalized in March 2006. The modeling by
MPCA was conducted using emission rate information submitted by the facility. The emissions were
21 Federal Register 70, no. 128 (July 6, 2005): 39106. 22 Federal Register 70, no. 128 (July 6, 2005): 39125 23 MPCA. March 2006. Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources
Subject-to-BART in the State of Minnesota. Page 8.
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reported in units of pounds per hour (lbs/hr) and were to reflect the maximum actual emissions
during a 24-hour period under steady-state operating conditions during periods of high capacity
utilization. The results of the modeling were presented in the document titled “Results of Best
Available Retrofit Technology (BART) Modeling to Determine Sources Subject-to-BART in the
State of Minnesota ,” finalized in March 2006. The modeling conducted by MPCA demonstrated that
this facility is subject-to-BART.
4.B Facility Baseline Modeling Prior to re-creating the MPCA visibility impairment model, the modeling protocol was re-revaluated.
On behalf of NMC and the other Minnesota taconite facilities, Barr Engineering proposed changes to
the modeling protocol. The changes, as submitted to MPCA on May 16, 2006 are presented in
Appendix B.
In addition, the maximum 24-hour emission rates were re-evaluated internally within NMC to
confirm that the emission rates represent the maximum steady-state operating conditions during
periods of high capacity utilization. The maximum 24-hour emission rates were not adjusted.
The facility baseline data is summarized in the Table 4-1. The full modeling analysis is presented in
Appendix C.
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Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions Data
EU #
EU
Descriptio
n
SO2
Maximum
24-hr
Emission
Rate
(lbs/day)
Basis for
SO2 24-
hour
Actual
Emission
NOx
Maximu
m
24-hr
Emission
Rate
(lbs/day)
Basis for
NOx 24-
hour
Actual
Emission
PM2.5
Maximu
m
24-hr
Emission
Rate
(lbs/day)
Basis for
PM2.5 24-
hour
Actual
Emission
PM10
Maximu
m
24-hr
Emission
Rate
(lbs/day)
Basis for
PM10 24-
hour
Actual
Emission SV #
Stack
Easting
(utm)
Stack
Northing
(utm)
Height of
Opening
from
Ground
(ft)
Base
Elevation
of Ground
(ft)
Stack
length,
width, or
Diameter
(ft)
Flow
Rate at
exit
(acfm)
Exit
Temp
(oF)
EU 003
Process Boiler #1
402 279 45 SV003 631471.5 5238482.8 131 611 6.5 59900 450
EU 004
Process Boiler #2
402 279 45 SV003 631471.5 5238482.8 131 611 6.5 59900 450
EU 008
East Car Dump
NA NA NA NA 32 SV008 631224.7 5238953.7 83 870 5.0 62600 77
EU 010
Fine Crusher
Bin Storage -
East
NA NA NA NA 45 SV010 631316.0 5238925.9 101 767 6.0 90100 77
EU 016
Crushed Ore
Conveyors - East
NA NA NA NA 12 SV016 631314.1 5238884.6 69 767 3.3 22400 77
EU 017
Fine Crushing Line 101
NA NA NA NA 8 SV017 631322.8 5238896.8 69 767 2.7 15,000 77
EU 018
Fine Crushing Line 102
NA NA NA NA 8 SV018 631328.6 5238905.9 69 767 2.7 15,000 77
EU 019
Fine Crushing Line 103
NA NA NA NA 8 SV019 631334.4 5238915.1 69 767 2.7 15,000 77
EU 020
Fine Crushing Line 104
NA NA NA NA 8 SV020 631341.2 5238924.2 69 767 2.7 15,000 77
EU 031
Concentrator
Transfer Bin - East
NA NA NA NA 8 SV031 631455.6 5238785.1 83 696 2.7 18000 77
EU 044
Concentrator Bin - Section
101
NA NA NA NA 18 SV044 631473.1 5238808.5 93 716 3.3 29200 77
EU 045
Concentrator Bin - Section
102
NA NA NA NA 18 SV045 631486.7 5238828.7 93 716 3.3 29200 77
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EU #
EU
Descriptio
n
SO2
Maximum
24-hr
Emission
Rate
(lbs/day)
Basis for
SO2 24-
hour
Actual
Emission
NOx
Maximu
m
24-hr
Emission
Rate
(lbs/day)
Basis for
NOx 24-
hour
Actual
Emission
PM2.5
Maximu
m
24-hr
Emission
Rate
(lbs/day)
Basis for
PM2.5 24-
hour
Actual
Emission
PM10
Maximu
m
24-hr
Emission
Rate
(lbs/day)
Basis for
PM10 24-
hour
Actual
Emission SV #
Stack
Easting
(utm)
Stack
Northing
(utm)
Height of
Opening
from
Ground
(ft)
Base
Elevation
of Ground
(ft)
Stack
length,
width, or
Diameter
(ft)
Flow
Rate at
exit
(acfm)
Exit
Temp
(oF)
EU 046
Concentrator Bin - Section
103
NA NA NA NA 18 SV046 631501.3 5238849.0 93 716 3.3 29200 77
EU 047
Concentrator Bin - Section
104
NA NA NA NA 18 SV047 631514.8 5238870.3 93 716 3.3 29200 77
EU 048
Concentrator Bin - Section
105
NA NA NA NA 18 SV048 631529.4 5238890.7 93 716 3.3 29200 77
EU 049
Concentrator Bin - Section
106
NA NA NA NA 18 SV049 631544.0 5238911.0 93 716 3.3 29200 77
EU 050
Concentrator Bin - Section
107
NA NA NA NA 18 SV050 631557.6 5238932.3 93 716 3.3 29200 77
EU 051
Concentrator Bin - Section
108
NA NA NA NA 18 SV051 631572.1 5238952.6 93 716 3.3 29200 77
EU 052
Concentrator Bin - Section
109
NA NA NA NA 18 SV276 631590.6 5238980.0 93 716 3.3 29200 77
EU 053
Concentrator Bin - Section
110
NA NA NA NA 18 SV053 631605.2 5239000.3 93 716 3.3 29200 77
EU 077
Furnace 11 Day
Bin Collector
NA NA NA NA 4 SV077 631274.7 5238341.3 97 670 0.8 1,800 77
EU 078
Furnace 11 Air Slide
Collector
NA NA NA NA 4 SV078 631315.5 5238399.2 97 670 0.8 1,800 77
EU 079
Furnace 12 Day
Bin Collector
NA NA NA NA 4 SV079 631276.6 5238344.4 97 670 0.7 1,800 77
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EU #
EU
Descriptio
n
SO2
Maximum
24-hr
Emission
Rate
(lbs/day)
Basis for
SO2 24-
hour
Actual
Emission
NOx
Maximu
m
24-hr
Emission
Rate
(lbs/day)
Basis for
NOx 24-
hour
Actual
Emission
PM2.5
Maximu
m
24-hr
Emission
Rate
(lbs/day)
Basis for
PM2.5 24-
hour
Actual
Emission
PM10
Maximu
m
24-hr
Emission
Rate
(lbs/day)
Basis for
PM10 24-
hour
Actual
Emission SV #
Stack
Easting
(utm)
Stack
Northing
(utm)
Height of
Opening
from
Ground
(ft)
Base
Elevation
of Ground
(ft)
Stack
length,
width, or
Diameter
(ft)
Flow
Rate at
exit
(acfm)
Exit
Temp
(oF)
EU 080
Furnace 12 Air Slide
Collector
NA NA NA NA 4 SV080 631318.4 5238402.2 97 670 0.8 1,800 77
EU 081
East Pelletizer Bentonite Storage - Bin 3,4
NA NA NA NA 4 SV081 631311.2 5238408.2 129 670 0.7 1,800 77
EU 082
East Pelletizer Bentonite Storage - Bin 5,6
NA NA NA NA 4 SV082 631318.0 5238419.3 130 670 0.7 1,800 77
EU 083
Bentonite Unloadin
g Collector
NA NA NA NA 4 SV083 631320.9 5238422.4 127 670 0.7 1,300 77
EU 084
Supplemental
Bentonite Unloadin
g Collector
NA NA NA NA 10 SV084 631331.9 5238426.5 117 670 1.7 4,900 77
EU 100
Furnace 11 Hood Exhaust
284 410 272 SV101 631339.1 5238341.2 121 636 6.0 70700 142
EU 100
Furnace 11 Hood Exhaust
284 410 272 SV102 631344.3 5238338.3 121 636 6.0 74300 142
EU 100
Furnace 11 Hood Exhaust
284 410 272 SV103 631348.4 5238335.3 121 636 6.0 77400 142
EU 104
Furnace 11 Waste
Gas 142 1498 255 SV105 631343.4 5238298.9 134 636 6.0 93,000 140
EU 104
Furnace 11 Waste
Gas 142 1498 255 SV104 631334.2 5238298.9 134 636 6.0 93,000 140
EU 110
Furnace 12 Hood Exhaust
284 410 272 SV111 631361.5 5238372.7 121 636 6.0 70700 142
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EU #
EU
Descriptio
n
SO2
Maximum
24-hr
Emission
Rate
(lbs/day)
Basis for
SO2 24-
hour
Actual
Emission
NOx
Maximu
m
24-hr
Emission
Rate
(lbs/day)
Basis for
NOx 24-
hour
Actual
Emission
PM2.5
Maximu
m
24-hr
Emission
Rate
(lbs/day)
Basis for
PM2.5 24-
hour
Actual
Emission
PM10
Maximu
m
24-hr
Emission
Rate
(lbs/day)
Basis for
PM10 24-
hour
Actual
Emission SV #
Stack
Easting
(utm)
Stack
Northing
(utm)
Height of
Opening
from
Ground
(ft)
Base
Elevation
of Ground
(ft)
Stack
length,
width, or
Diameter
(ft)
Flow
Rate at
exit
(acfm)
Exit
Temp
(oF)
EU 110
Furnace 12 Hood Exhaust
284 410 272 SV112 631365.6 5238369.7 121 636 6.0 74300 142
EU 110
Furnace 12 Hood Exhaust
284 410 272 SV113 631370.7 5238366.8 121 636 6.0 77400 142
EU 114
Furnace 12 Waste
Gas 142 1498 255 SV114 631354.5 5238331.4 134 636 6.0 93,000 140
EU 114
Furnace 12 Waste
Gas 142 1498 255 SV115 631362.7 5238325.5 134 636 6.0 93,000 140
EU 120
Furnace 11
Discharge
NA NA NA NA 95 SV120 631383.5 5238300.6 91 636 3.8 48000 150
EU 121
Furnace 12
Discharge
NA NA NA NA 95 SV121 631405.9 5238332.1 91 636 3.8 48000 150
EU 122
Furnace 11
Screening
NA NA NA NA 95 SV122 631387.6 5238297.7 91 636 3.8 48000 150
EU 124
Furnace 12
Screening
NA NA NA NA 95 SV124 631380.9 5238282.5 91 636 3.8 48000 130
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4.C Facility Baseline Modeling Results The Minnesota BART modeling protocol24 describes the CALPUFF model inputs, including the
meteorological data set and background atmospheric ammonia and ozone concentrations, along with
the functions of CALPOST post processing.. The CALPOST output files provide the following two
methods to assess the expected post-BART visibility improvement:
• 98th Percentile: As defined by federal guidance and as stated in the MPCA’s document which
identifies the Minnesota facilities that are subject to BART25, a source "contributes to
visibility impairment” if the 98th percentile of any year’s modeling results (i.e. 7th highest
day) meets or exceeds the threshold of five-tenths (0.5) of a deciview (dV) at a Federally
protected Class I area receptor.
• Number of Days Exceeding 0.5 dV: The severity of the visibility impairment contribution, or
reasonably attributed visibility impairment, can be gauged by assessing the number of days
on which a source exceeds a visibility impairment threshold of 0.5 dV.
A summary of the baseline visibility modeling is presented in Table 4-2. As illustrated in the table,
this facility is considered to contribute to visibility impairment in Class I areas because the modeled
98th percentile of the baseline conditions exceeds the threshold of 0.5 dV However, the results also
indicate that the highest modeled impact may not exceed human perceptibility which is on the order
of one to two dV. In addition, the modeling shows that these emission sources cause or contribute to
visibility impairment less than 10 % of the time, based on the modeling results predicting 34 to 38
days annually above 0.5dV. The results of this modeling are also utilized in the post-BART modeling
analysis in section 6 of this document.
The full modeling analysis is presented in Appendix C.
24 MPCA. March 2006. Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources
Subject-to-BART in the State of Minnesota. Page 8. 25 MPCA. March 2006. Results of Best Available Retrofit Technology (BART) Modeling to Determine Sources
Subject-to-BART in the State of Minnesota.
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Table 4-2 Baseline Visibility Modeling Results
2002 2003 2004 2002 – 2004 Combined
Class I Area with
Greatest Impact
Modeled 98
th
Percentile Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98
th
Percentile Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98
th
Percentile Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98
th
Percentile Value
(deciview)
No. of days
exceeding 0.5
deciview
BWCA 1.1 34 1.1 34 1.3 38 1.1 106
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5. Full BART Analysis for BART Eligible Emission Units
BART eligible sources at NMC can be divided into groups based upon type of process.
5.A Indurating Furnace The primary function of taconite indurating furnaces is to convert magnetic iron concentrate to a
more highly oxidized iron in the form of a pellet that is sold to metallic iron and steel production
facilities. “Soft” or “green” pellets are oxidized and heat-hardened in the induration furnace. The
induration process involves pellet pre-heating, drying, hardening, oxidation and cooling. The process
requires large amounts of air for pellet oxidation and cooling. Process temperature control in all
parts of the furnace is critical to minimize product breakage in the initial process stages, allow
required oxidation reactions to occur, and adequately cool the product prior to subsequent handling
steps. Directed air flow, heat recovery and fuel combustion are critical to controlling temperature
and product quality in all parts of the furnace. NMC uses a straight grate furnace, in which pellets
move through the entire furnace on a traveling grate. The pellet hardening and oxidation section of
the induration furnace is designed to operate at 2,400 ºF. This temperature is required to meet
taconite pellet product specifications. Direct-fired fuel combustion in the induration furnace is
carried out at 300 % to 400 % excess air required to provide sufficient oxygen for pellet oxidation.
Air is used for combustion, pellet cooling, and as a source of oxygen for pellet oxidation. Due to the
high-energy demands of the induration process, induration furnaces have been designed to recover as
much heat as possible using hot exhaust gases to heat up incoming pellets. Pellet drying and preheat
zones are heated with the hot gases generated in the pellet hardening/oxidation section and the pellet
cooler sections. Each of these sections is designed to maximize heat recovery within process
constraints. The pellet coolers are also used to preheat combustion air so more of the fuel’s energy is
directed to the process instead of heating ambient air to combustion temperatures.
NMC process has two straight-grate furnaces, Line 11 and Line 12 that are subject to BART. Line
11 and 12 are permitted to burn natural gas and fuel oil. Both line’s emissions are controlled by wet
walled electrostatic precipitators (WWESP) using caustic reagent. The existing WWESP already
provides excellent control and removal of PM and SO2.
Emissions of SO2 result from low amounts of sulfur present in the ore and potentially from fuel oil
use. Stack testing using natural gas fuel has demonstrated the WWESP effectively removes SO2 to
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one to two parts per million in the exhaust from the WWESPs. A recent BACT analysis for a similar
furnace at NMC established an emissions limit of 10 parts per million SO2 using existing WWESPs.
NOx is controlled through furnace design. The NMC furnaces emit the lowest tons of NOx/long ton
product of any taconite producer making similar pellets. NMCs furnaces are of an early vintage.
Furnaces 11 and 12 have numerous burners critically located to supply heat to the various furnace
sections. The burner layout limits production capability for the size of the furnace. This furnace
design is not used by any other taconite producer.
The primary source of SO2 emissions in taconite production is from trace amounts of sulfur in the
iron concentrate and binding agents present in the green balls. Sulfur is also present in distillate fuel
oil that is one of the permitted fuels.
5.A.i Sulfur Dioxide Controls
5.A.i.a STEP 1 – Identify All Available Retrofit Control Technologies
See Appendix D for a comprehensive list of all potential retrofit control technologies that were
evaluated. Many emerging technologies have been identified that are not currently commercially
available. A preliminary list of technologies was submitted to MPCA on May 9 with the status of the
technology as it was understood at that time. As work on this evaluation progressed, new
information became apparent of the limited scope and scale of some of the technology applications.
Appendix D presents the current status of the availability and applicability of each technology.
5.A.i.b STEP 2 – Eliminate Technically Infeasible Options
Step 1 identified the available and applicable technologies for SO2 emission reduction. Within
Step 2, the technical feasibility of the control option is discussed and determined. The following
section describes retrofit SO2 control technologies that were identified as available and applicable in
the original submittal and discusses aspects of those technologies that determine whether or not the
technology is technically feasible for indurating furnaces.
Wet Walled Electrostatic Precipitator (WWESP)
An electrostatic precipitator (ESP) applies electrical forces to separate suspended particles from the
flue gas stream. The suspended particles are given an electrical charge by passing through a high
voltage DC corona region in which gaseous ions flow. The charged particles are attracted to and
collected on oppositely charged collector plates. Particles on the collector plates are released by
rapping and fall into hoppers for collection and removal.
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A wet walled electrostatic precipitator (WWESP) operates on the same collection principles as a dry
ESP and uses a water spray to remove particulate matter from the collection plates. For SO2 removal,
caustic is added to the water spray system, allowing the WWESP spray system to function as an SO2
absorber. WWESPs are designed to remove emissions to levels less than 10 parts per million SO2 .
The SO2 control efficiency for a WWESP is dependent upon various process specific variables, such
as SO2 flue gas concentration, fuel used, and ore composition. NMC currently employs a WWESP
designed for removal of particulate matter and SO2. The addition of a secondary WWESP would act
as a polishing scrubber and would experience reduced control efficiency due to lower SO2 inlet
concentrations. A control efficiency as a polishing WWESP ranges from 30-80% dependent upon the
process specific operating parameters.
Based on the definitions contained within this report, a polishing WWESP is considered an available
technology for SO2 reduction for this BART analysis. The existing WWESP already removes SO2 to
a very low concentration. No other improvements are available to enhance the removal efficiency of
the existing controls. Installation of a secondary WWESP is carried forward in this analysis.
Wet Scrubbing (High and Low Efficiency)
Wet scrubbing, when applied to remove SO2, is generally termed flue-gas desulfurization (FGD).
FGD utilizes gas absorption technology, the selective transfer of materials from a gas to a contacting
liquid, to remove SO2 in the waste gas. Crushed limestone, lime, or caustic are used as scrubbing
agents. Most wet scrubbers recirculate the scrubbing solution, which minimizes the wastewater
discharge flow. However, higher concentrations of solids exist within the recirculated wastewater.
For a wet scrubber to be considered a high efficiency SO2 wet scrubber, the scrubber would require
designs for removal efficiency up to 95% SO2. Typical high efficiency SO2 wet scrubbers are
packed-bed spray towers using a caustic scrubbing solution. Whereas, a low efficiency SO2 wet
scrubber could be as low as 30% control efficiency. A low efficiency SO2 could be a venturi rod
scrubber design using water as a scrubbing solvent. Venturi rod scrubbers, which are frequently used
for PM control at taconite facilities, will also remove some of the SO2 from the flue gas as collateral
emission reduction.
Limestone scrubbing introduces limestone slurry with the water in the scrubber. The sulfur dioxide is
absorbed, neutralized, and partially oxidized to calcium sulfite and calcium sulfate. The overall
reactions are shown in the following equations:
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CaCO3 + SO2 → CaSO3 • 1/2 H2O + CO2
CaSO3 •1/2 H2O + 3H2O + O2 → 2 CaSO4 •2 H2O
Lime scrubbing is similar to limestone scrubbing in equipment and process flow, except that lime is a
more reactive reagent than limestone. The reactions for lime scrubbing are as follows:
Ca(OH)2 +SO2 → CaSO3• 1/2 H2O + 1/2 H2O
Ca(OH)2 + SO2 + 1/2 O2 + H2O → CaSO4•2 H2O
When caustic (sodium hydroxide solution) is the scrubbing agent, the SO2 removal reactions are as
follows:
Na+ + OH- + SO2 + → Na2SO3
2Na+ + 2OH- + SO2 + → Na2SO3 + H2O
Caustic scrubbing produces a liquid waste, and minimal equipment is needed as compared to lime or
limestone scrubbers.. If lime or limestone is used as the reagent for SO2 removal, additional
equipment will be needed for preparing the lime/limestone slurry and collecting and concentrating
the resultant sludge. Calcium sulfite sludge is watery; it is typically stabilized with fly ash for land
filling. The calcium sulfate sludge is stable and easy to dewater. To produce calcium sulfate, an air
injection blower is needed to supply the oxygen for the second reaction to occur.
The normal SO2 control efficiency range for SO2 scrubbers on coal-fired utility boilers with excess
oxygen of 2-3% is 80% to 90% for low efficiency scrubbers and 90% to 95% for high efficiency
scrubbers. The highest control efficiencies can be achieved when SO2 concentrations are the highest.
Unlike coal-fired boilers, indurating furnaces operate with maximum excess air to enable proper
oxidation of the pellet. The excess air dilutes the SO2 concentration as well as creates higher flow
rates to control. Additionally, the varying sulfur concentration within the pellet causes fluctuations of
the SO2 concentrations in the exhaust gas stream. This could also impact the SO2 control efficiency
of the wet scrubber.
As stated in the beginning of this section, WWESPs are currently in place on the furnace exhausts
and are believed to remove 80 to 95% of the SO2 in the exhaust. Taking into consideration of the
removal of SO2 from the existing primary WWESP as well as a high efficiency SO2 polishing wet
scrubber, an overall efficiency of the control train would then be well over 90%.
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Based on the information contained within this report, a secondary wet scrubber is considered an
available technology for SO2 reduction for this BART analysis.
Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection)
Lime/limestone injection is a post-combustion SO2 control technology in which pulverized lime or
limestone is directly injected into the duct upstream of the fabric filter. Dry sorption of SO2 onto the
lime or limestone particle occurs and the solid particles are collected with a fabric filter. Further SO2
removal occurs as the flue gas flows through the filter cake on the bags. The normal SO2 control
efficiency range for dry SO2 scrubbers is 70% to 90% for coal fired utility boilers.
Induration waste gas streams are high in water content and are exhausted at or near their dew points.
Gases leaving the induration furnace are currently treated for removal of particulate matter using a
WWESP. The exhaust temperature is typically in the range of 100 °F to 150 °F and is saturated with
water. For comparison, a utility boiler exhaust operates at 350 °F or higher and is not saturated with
water. Under induration furnace waste gas conditions, the baghouse filter cake would become
saturated with moisture and plug both the filters and the dust removal system. Although this may be
an available and applicable control option, it is not technically feasible due to the high moisture
content and will not be further evaluated in this report.
Spray Dryer Absorption (SDA)
Spray dryer absorption (SDA) systems spray lime slurry into an absorption tower where SO2 is
absorbed by the slurry, forming CaSO3/CaSO4. The liquid-to-gas ratio is such that the water
evaporates before the droplets reach the bottom of the tower. The dry solids are carried out with the
gas and collected with a fabric filter. When used to specifically control SO2, the term flue-gas
desulfurization (FGD) may also be used.
Under induration furnace waste gas conditions, the baghouse filter cake would become saturated with
moisture and plug both the filters and the dust removal system. In addition, because of the moisture
in the exhaust, the lime slurry would not dry properly and it would plug up the dust collection
system. Similarly to the dry sorbent injection control option, this is an available and applicable
control option, but is not technically feasible due to the high moisture content. This option will not
be further evaluated in this report.
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Energy Efficiency Projects
Energy efficiency projects provide opportunities for a company to reduce their fuel consumption,
which results in lower operating costs. Typically reduced fuel usage translates into reduced pollution
emissions. An example of an energy efficiency project could be to preheat incoming make-up air or
pellet feed. Each project is very dependent upon the fuel usage, process equipment, type of product
and many other variables.
Due to the increased price of fuel, the facilities have already implemented energy efficiency projects.
Each project carries its own fuel usage reductions and potentially emission reductions. It would be
impossible to assign a general potential emission reduction for the energy efficient category. Due to
the uncertainty and generalization of this category, this will not be further evaluated in this report.
However, it should be noted that facilities will continue to evaluate and implement energy efficiency
projects as they arise.
Alternate Fuels
As described within the energy efficiency description, increased price of fuel has pushed companies
to evaluate alternate fuel sources. These fuel sources come in all forms – solid, liquid and gas. To
achieve reduction of SO2 emissions through alternative fuel usage, the source must use fuels with
lower sulfur content. NMC has the capability to only burn natural gas and distillate fuel oil in its
furnaces. Therefore this option is not applicable for SO2 reductions at NMC.
It is also important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as their
option, not to direct the fuel choice.26
However, NMC will continue to evaluate and implement alternate fuel usage as the feasibility arises.
26 Federal Register 70, no. 128 (July 6, 2005): 39164
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Coal Processing
Since NMC does not burn coal in Furnaces 11 and 12, this option is not applicable for SO2 reductions
at NMC.
Step 2 Conclusion
Based upon the determination within Step 2, the remaining SO2 control technologies that are
available and applicable as secondary controls to the existing indurating furnace WWESPs are
identified in Table 5-1. The technical feasibility as determined in Step 2 is also included in Table 5-1.
Table 5-1 Indurating Furnace SO2 Control Technology – Availability, Applicability, and Technical Feasibility
SO2 Pollution Control Technology Available? Applicable? Technically Feasible?
Secondary Wet Scrubbing (High Efficiency)
Yes Yes Yes
Secondary Wet Scrubbing (Low Efficiency)
Yes Yes Yes
Secondary Wet Walled Electrostatic Precipitator (WWESP)
Yes Yes Yes
Dry sorbent injection Yes Yes No
Spray Dryer Absorption (SDA) Yes Yes No
Alternative Fuels Yes No No
Energy Efficiency Projects Yes Yes No
Coal Processing Yes No No
5.A.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies
Table 5-2 describes the expected control efficiency from each of the remaining feasible control
options. The WWESP and high efficiency wet scrubbing control options listed in Table 5-2 would be
considered a polishing scrubber since a highly effective SO2 control WWESP currently exists.
Table 5-2 Indurating Furnace SO2 Control Technology Effectiveness
SO2 Pollution Control Technology Approximate Control Efficiency
Secondary Wet Walled Electrostatic Precipitator (WWESP) 80
Secondary Wet Scrubber 60
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5.A.i.d STEP 4 – Evaluate Impacts and Document the Results
As illustrated in Table 5-2 above, the technically feasible control remaining provide varying levels of
emission reduction. Therefore, it is necessary to consider the economic, energy, and environmental
impacts to better differentiate as presented below.
Economic Impacts
Table 5-3 details the expected costs associated with installation of a secondary WWESP after the
existing WWESP on each stack. Equipment design was based on the maximum 24-hour emissions,
vendor estimates, and U.S. EPA cost models. Capital costs were based on a recent vendor quotation.
The cost for that unit was scaled to each stack’s flow rate using the 6/10 power law as shown in the
following equation:
Cost of equipment A = Cost of equipment B * (capacity of A/capacity of B)0.6
Direct and indirect costs were estimated as a percentage of the fixed capital investment using U.S.
EPA models and factors. Operating costs were based on 93% utilization and 8339 operating hours
per year. Operating costs of consumable materials, such as electricity, water, and chemicals were
established based on the U.S. EPA control cost manual27 and engineering experience, and were
adjusted for the specific flow rates and pollutant concentrations.
Due to space considerations, 60%28 of the total capital investment was included in the costs to
account for a retrofit installation. After a tour of the facility and discussions with facility staff, it was
determined the space surrounding the furnaces is congested and the area surrounding the building
supports vehicle and rail traffic to transport materials to and from the building. Additionally, the
structural design of the existing building would not support additional equipment on the roof.
Therefore, the cost estimates provide for additional site-work and construction costs to accommodate
the new equipment within the facility. A site-specific estimate for site work, foundations, and
structural steel was added to arrive at the total retrofit installed cost of the control technology. The
site-specific estimate was based on Barr’s experience with similar projects. See Appendix C for an
aerial photo of the facility. The detailed cost analysis is provided in Appendix A.
27 U.S. EPA, January 2002, EPA Air Pollution Control Cost Manual, Sixth Edition. 28 U.S. EPA, CUE Cost Workbook Version 1.0. Page 2.
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Table 5-3 Indurating Furnace SO2 Control Cost Summary
Control Technology
Installed Capital Cost
(MM$) Operating Cost
(MM$/yr)
Annualized Pollution
Control Cost ($/ton)
Incremental Control
Cost ($/ton)
Secondary Wet Scrubber
Furnace 11 Hood Exhaust
$16,952,864 $2,401,349 $139,872 NA
Furnace 11 Waste Gas
$15,859,420 $2,201,975 $384,034 NA
Furnace 12 Hood Exhaust
$16,952,864 $2,401,349 $152,149 NA
Furnace 12 Waste Gas
$15,859,420 $2,201,975 $417,742 NA
Secondary Wet Walled Electrostatic Precipitator (WWESP)
Furnace 11 Hood Exhaust
$23,617,556 $4,188,875 $182,993 NA
Furnace 11 Waste Gas
$21,846,389 $3,799,211 $496,949 NA
Furnace 12 Hood Exhaust
$23,617,556 $4,294,171 $204,058 NA
Furnace 12 Waste Gas
$21,846,389 $3,764,113 $535,575 NA
Based on the BART final rule, court cases on cost-effectiveness, guidance from other regulatory
bodies, and other similar regulatory programs like Clean Air Interstate Rule (CAIR), cost-effective
air pollution controls in the electric utility industry for large power plants are in the range $1,000 to
$1,300 per ton removed as illustrated in Appendix E. This cost-effective threshold is also an indirect
measure of affordability for the electric utility industry used by USEPA to support the BART rule-
making process. For the purpose of this taconite BART analysis, the $1,000 to $1,3000 cost
effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not
afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the
electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater
business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for
proposing BART in lieu of developing industry and site specific data.
The annualized pollution control cost value was used to determine whether or not additional impacts
analyses would be conducted for the technology. If the control cost was less than a screening
threshold established by MPCA, then visibility modeling impacts, and energy and other impacts are
evaluated. MPCA set the screening level to eliminate technologies from requiring the additional
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impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled pollutant29.
Therefore, all air pollution controls with annualized costs less than this screening threshold will be
evaluated for visibility improvement, energy and other impacts.
The incremental control cost column in Table 5-3 is intended to present the incremental value of each
technology as compared to the next most effective alternative. Since none of the secondary SO2
control technologies are cost effective, the incremental cost is not applicable.
Energy and Environmental Impacts
Because the cost of SO2 controls for the NMC furnaces is so high and does not meet a reasonable
definition of cost effective technology, these technologies are removed from further consideration in
this analysis.
5.A.i.e STEP 5 – Evaluate Visibility Impacts
As previously stated in section 4 of this document, states are required to consider the degree of
visibility improvement resulting from the retrofit technology, in combination with other factors such
as economic, energy and other non-air quality impacts, when determining BART for an individual
source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this
document. The economic impacts of additional, secondary controls for SO2 are not reasonably cost
effective, so visibility impacts were not modeled for SO2 controls. Refer to Table 4-2 for a summary
of the modeled 24-hour maximum emission rates and their computational basis for the existing
controls for SO2.
Visibility impacts with NOx controls are presented in section 6. Table 6-1 provides a summary of the
SO2, NOx, and PM10 emissions for each modeling scenario.
5.A.ii Nitrogen Oxide Controls
To be able to control NOx it is important to understand how NOx is formed. There are three
mechanisms by which NOx production occurs in the furnaces: thermal, fuel and prompt NOx.
• Fuel bound NOx is formed as nitrogen compounds in the fuel is oxidized from fuel
combustion.
29 Minnesota Pollution Control Agency (MPCA). Air Permit for Cenex Harvest States Cooperative Soybean Processing Plant, Fairmont, MN Permit 09100059-002.
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• Thermal NOx production arises from the thermal dissociation of nitrogen and oxygen
molecules within the furnace. Combustion air is the primary source of nitrogen and oxygen.
In taconite furnaces, thermal NOx production is a function of the residence time, free oxygen,
and temperature, primarily in the flame area of the furnace.
• Prompt NOx is a form of thermal NOx which is generated at the flame boundary. It is the
result of reactions between nitrogen and carbon radicals generated during combustion. Only
minor amounts of NOx are emitted as prompt NOx.
The majority of NOx is emitted as NO. Minor amounts of NO2 are formed in the furnaces.
The NMC furnaces are first and second generation straight-grate furnaces that were built with lower
grade steel and less refractory lining than the newer generations. As a result, the furnaces cannot
survive the higher temperature conditions (both flame temperature and roof air conditions) achieved
in newer indurating furnaces. Consequently, the ambient air in the ignition and combustion zone is
much cooler, leading to lower thermal NOx generation.
5.A.ii.a STEP 1 – Identify All Available Retrofit Control Technologies
With the understanding of how NOx is formed, available and applicable control technologies were
evaluated. See Appendix D for the current status of the availability and applicability of retrofit
control technologies.
5.A.ii.b STEP 2 – Eliminate Technically Infeasible Options
Step 1 identified the available and applicable technologies for NOx emission reduction. Within
Step 1, the technical feasibility of the control option was also discussed and determined. The
following describes retrofit NOx control technologies that were identified as available and applicable
in the original submittal and discusses aspects of those technologies that determine whether or not
the technology is technically feasible for indurating furnaces.
External Flue Gas Recirculation (EFGR)
External flue gas recirculation (EFGR) uses flue gas as an inert material to reduce flame temperatures
thereby reducing thermal NOx formation. In an external flue gas recirculation system, flue gas is
collected from the heater or stack and returned to the burner via a duct and blower. The flue gas is
mixed with the combustion air and this mixture is introduced into the burner. The addition of flue gas
reduces the oxygen content of the “combustion air” (air + flue gas) in the burner. The lower oxygen
level in the combustion zone reduces flame temperatures; which in turn reduces NOx emissions. For
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this technology to be effective, the combustion conditions must have the ability to be controlled at
the burner tip.
The normal NOx control efficiency range for EFGR is 30% to 50%.
Application for EFGR technology in taconite induration is problematic for three reasons:
1. The waste gas in an induration furnace typically has near atmospheric oxygen vs. a boiler
which has 2% - 3% oxygen. In a boiler, the flue gas is relatively inert so it can be used as
a diluent for flame temperature reduction. Taconite waste gas has much higher oxygen
level; thus use of taconite waste gas for EFGR would be equivalent to adding combustion
air instead of an inert gas.
2. The oxidation zone of induration furnaces needs to be above 2,400oF in order to meet
product specifications. Existing burners are designed to meet these process conditions.
Application of EFGR would reduce flame temperatures. Lower flame temperatures
would reduce furnace temperatures to the point that product quality could be jeopardized.
3. Application of EFGR technology increases flame length. Dilution of the combustion
reactants increases the reaction time needed for fuel oxidation to occur; so, flame length
increases. Therefore, application of EFGR could result in flame impingement on furnace
components. That would subject those components to excessive temperatures and cause
equipment failures.
Although this may be an available and applicable control option, it is not technically feasible due to
the high oxygen content of the flue gas and will not be further evaluated in this report.
Low- NOx Burners
Low- NOx burner (LNB) technology utilizes advanced burner design to reduce NOx formation
through the restriction of oxygen, flame temperature, and/or residence time. LNB is typically a
staged combustion process that is designed to split fuel combustion into two zones, primary
combustion and secondary combustion. This analysis utilizes the staged fuel design in the cost
analysis because lower emission rates can be achieved with staged fuel burner than with a staged air
burner.
In the primary combustion zone of a staged fuel burner, NOx formation is limited by a rich (high
fuel) condition. Oxygen levels and flame temperatures are low; this results in less NOx formation. In
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the secondary combustion zone, incomplete combustion products formed in the primary zone act as
reducing agents. In a reducing atmosphere, nitrogen compounds are preferentially converted to
molecular nitrogen (N2) over nitric oxide (NO). The estimated NOx control efficiency for low NOx
burners in high temperature applications is 10%. Low NOx burners have been installed to the
preheating section of a straight grate furnace at another taconite plant. If LNB were to be applied in
the indurating section of the furnace, the reduced flame temperatures associated with LNB would
adversely affect taconite pellet product quality. Low NOx burners have not been applied to the
indurating section of any straight grate taconite furnace.
However, NMC has a completely different combustion design compared to other furnaces. NMCs
furnace design does not separate the preheat zone from the combustion zone and temperature control
becomes a controlling variable for operation. Because the temperature in the indurating zone is
critical to product quality, and because this is dependent on the preheat zone operation, it is not
practical to control the furnace conditions in the preheat zone adequately to make low NOx burners a
feasible option at NMC.
It is also important to note that there are other methods being developed for low NOx burners which
are not yet commercially available. Some incorporate various fuel dilution techniques to reduce
flame temperatures; such as mixing an inert gas like CO2 with natural gas. Water injection to cool
the burner peak flame temperature is also being investigated. This technique has already been
successfully used for reducing NOx emissions from gas turbines and a straight grate taconite
indurating furnace in the Netherlands. The water injection technique shows promise for high
temperature applications, but will not be further investigated in this report as the technology is still in
the development phase.
Induced Flue Gas Recirculation Burners
Induced flue gas recirculation burners, also called ultra low- NOx burners, combine the benefits of
flue gas recirculation and low- NOx burner control technologies. The burner is designed to draw flue
gas to dilute the fuel in order to reduce the flame temperature. These burners also utilize staged fuel
combustion to further reduce flame temperature. The estimated NOx control efficiency for IFGR
burners in high temperature applications is 25-50%.
As noted above, taconite furnaces are required to operate at high oxygen levels.. At these oxygen
levels, flue gas recirculation is ineffective at NOx reduction, and it would adversely affect
combustion because excessive amounts of oxygen would be injected into the flame pattern. In
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addition, IFGR relies on convective flow of flue gas through the burner and requires burners to be
up-fired; meaning that the burner is mounted in the furnace floor and the flame rises up.
Furthermore, IFGR is not feasible because the reduced flame temperatures associated with IFGR
would adversely affect taconite pellet product quality.
Although this may be an available and applicable control option, it is not technically feasible due to
the high oxygen content of the flue gas and will not be further evaluated in this report.
Energy Efficiency Projects
Energy efficiency projects provide opportunities for a company to reduce their fuel consumption.
Typically reduced fuel usage translates into reduced pollution emissions. An energy efficiency
project could be preheat incoming make-up air or pellet feed. Each project is very dependent upon
the fuel usage, process equipment, type of product and so many other variables.
Due to the increased price of fuel, the facilities have already implemented energy efficiency projects.
Each project carries its own fuel usage reductions and potentially emission reductions. It would be
impossible to assign a general potential emission reduction for the energy efficient category. Due to
the uncertainty and generalization of this category, this will not be further evaluated in this report.
However, it should be noted that facilities will continue to evaluate and implement energy efficiency
projects as they arise.
Ported Kilns
Ported kilns are rotary kilns that have air ports installed at specified points along the length of the
kiln for process improvement. The purpose of the ports is to allow air injection into the pellet bed as
it travels down the kiln bed. Ports are installed about the circumference of the kiln. Each port is
equipped with a closure device that opens when it is at the bottom position to inject air in the pellet
bed, and closed when it rotates out of position.
The purpose of air injection is to provide additional oxygen for pellet oxidation. The oxidation
reaction extracts enough heat to offset the heat loss associated with air injection. Air injection
reduces the overall energy use of the kiln and produces a higher quality taconite pellet. Air injection
also prevents carry over of the oxidation reaction into the pellet coolers.
Ported kilns are applicable to grate kilns but not to straight grate indurating furnaces, as are present at
NMC. Therefore, the ported kilns are not an applicable technology for this facility.
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Alternate Fuels
As described within the energy efficiency description, increased price of fuel has moved companies
to evaluate alternate fuel sources. These fuel sources come in all forms – solid, liquid and gas.
Reduction of NOx emissions through alternative fuel usage has been achieved at taconite grate kilns
through the use of solid fuel. In these cases the reduction resulted due to changes from pulverized
solid fuel dispersal in the kiln that results in lower flame temperature compared to other fuels.
Switching from natural gas or oil to solid fuel has a potential drawback in that it can exchange one
visibility impairment pollutant (NOx) for another (SO2). More importantly, the design of the straight
grate furnaces at NMC does not allow the use of solid fuels. Therefore, this option will not be
further evaluated in this report.
It is also important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as their
option, not to direct the fuel choice.30
However, similar to energy efficiency, facilities will continue to evaluate and implement alternate
fuel usage as the feasibility arises.
Process Optimization with NOx CEMS or Other Parametric Monitoring
MPCA guidance lists “NOx CEMS” as a work practice/operational change for controlling NOx
emissions31. Parametric monitoring is a possible derivative of this alternative.
Based on conversations with MPCA staff, this work practice would include process adjustments, or
optimization, to minimize NOx emissions. The impact of the process adjustments would be measured
using the NOx CEMS. This approach has been used in the electric utility industry to fine tune NOx
emissions from boilers.
One taconite plant has installed NOx CEMS to monitor emissions but not to optimize NOx emissions
through process fine tuning. That plant has experienced some reduction in NOx emissions but these
encompass multiple variables and are not directly attributed to process fine tuning with the NOx
CEMS. Therefore, this alternative has not been demonstrated in the taconite industry.
30 Federal Register 70, no. 128 (July 6, 2005): 39164
31 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 4.
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There are several concerns with utilizing process optimization as an available, applicable and
technically feasible control option for the taconite industry:
• Taconite furnaces are designed and operated to convert magnetite to hematite in the presence
of excess oxygen and require heat input to initiate the reaction which is exothermic and
releases heat once initiated. Fuel combustion is only part of the process and therefore this
process is different from a boiler.
• The quality of the process feed materials to the furnace is variable at some taconite
operations and product quality may be compromised by attempting to fine tune heat input to
minimize NOx formation.
• At some operations, the operating parameters which generally influence the rate of NOx
generation such as flame temperature, fuel usage and excess air are relatively constant during
operation of the furnace, independent of process operation variability. This indicates that NOx
formation may not be dependent upon controllable operating parameters. In the absence of
controllable parameters, process optimization would not be effective at controlling NOx
emissions.
Based upon this information, there is no indication that further emission reductions would be
achieved through the use of the process optimization, using NOx CEMS or other parametric
monitoring, as a control technology. Therefore, process optimization as a control option will not be
evaluated further in this report.
Post Combustion Controls
NOx can be controlled using add-on systems located downstream of the furnace area of the
combustion process. The two main techniques in commercial service include the selective non
catalytic reduction (SNCR) process and the selective catalytic reduction (SCR) process. There are a
number of different process systems in each of these categories of control techniques.
In addition to these treatment systems, there are a large number of other processes being developed
and tested on the market. These approaches involve innovative techniques of chemically reducing,
absorbing, or adsorbing NOx downstream of the combustion chamber. Examples of these alternatives
are nonselective catalytic reduction (NSCR) and Low Temperature Oxidation (LTO). Each of these
alternatives is described below.
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Non-Selective Catalytic Reduction (NSCR)
A non-selective catalytic reduction (NSCR) system is a post combustion add-on exhaust gas
treatment system. NSCR catalyst is very sensitive to poisoning; so; NSCR is usually applied
primarily in natural gas combustion applications.
NSCR is often referred to as “three-way conversion” catalyst because it simultaneously reduces NOx,
unburdened hydrocarbons (UBH), and carbon monoxide (CO). Typically, NSCR can achieve NOx
emission reductions of 90 percent. In order to operate properly, the combustion process must be near
stoichiometric conditions. Under this condition, in the presence of a catalyst, NOx is reduced by CO,
resulting in nitrogen (N2) and carbon dioxide (CO2). The most important reactions for NOx removal
are:
2CO + 2NO → 2CO2 + N2 (1)
[UBH] + NO → N2 + CO2 + H2O (2)
NSCR catalyst has been applied primarily in clean combustion applications. This is due in large part
to the catalyst being very sensitive to poisoning, making it infeasible to apply this technology to the
indurating furnace. In addition, we are not aware of any NSCR installations on taconite induration
furnaces or similar combustion equipment. Therefore, this technology will not be further evaluated in
this report.
Selective Catalytic Reduction and Regenerative Selective Catalytic Reduction
SCR is a post-combustion NOx control technology in which ammonia (NH3) is injected into the flue
gas stream in the presence of a catalyst. NOx is removed through the following chemical reaction:
4 NO + 4 NH3 + O2 → 4 N2 + 6 H2O (1)
2 NO2 + 4 NH3 + O2 → 3 N2 + 6 H2O (2)
A catalyst bed containing metals in the platinum family is used to lower the activation energy
required for NOx decomposition. SCR requires a temperature range of about 570°F – 850°F for a
normal catalyst. At temperature exceeding approximately 670ºF, the oxidation of ammonia begins to
become significant. At low temperatures, the formation of ammonium bisulfate causes scaling and
corrosion problems.
A high temperature zeolite catalyst is also available; it can operate in the 600 °F – 1000°F
temperature range. However, these catalysts are very expensive.
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Ammonia slip from the SCR system is usually less than 3 to 5 ppm. The emission of ammonia
increases during load changes due to the instability of the temperature in the catalyst bed as well as at
low loads because of the low gas temperature.
Regenerative Selective Catalytic Reduction (RSCR) applies the Selective Catalytic Reduction (SCR)
control process as described below with a preheat process step to reheat the flue gas stream up to
SCR catalyst operating temperatures. The preheating process combines use of a thermal heat sink
(packed bed) and a duct burner. The thermal sink recovers heat from the hot gas leaving the RSCR
and then transfers that heat to gas entering the RSCR. The duct burner is used to complete the
preheating process. RSCR operates with several packed bed/SCR reactor vessels. Gas flow
alternates between vessels. Each of the vessels alternates between preheating/treating and heat
recovery.
The benefits of RSCR are:
• Its high energy efficiency allows it to be used after SO2 and particulate controls.
• RSCR has a thermal efficiency of 90% - 95% vs. standard heat exchangers which have a
thermal efficiency of 60% to 70%.
• Application of RSCR after SO2 and PM controls significantly reduces the potential for
problems associated with plugging and catalyst poisoning and deactivation.
There are several other concerns about the technical feasibility and applicability of RSCR on an
indurating furnace:
• The composition of the indurating furnace flue gas is significantly different from the
composition of the flue gas from the boilers that utilize RSCR;
• The taconite dust is highly erosive and can cause significantly equipment damage. RSCR has
a number of valves which must be opened and closed frequently to switch catalyst/heat
recovery beds. These valves could be subject to excessive wear in a taconite application due
to the erosive nature of the taconite dust;
• RSCR has not been applied downstream of a wet scrubber. Treating a stream saturated with
water may present design problems in equipment sizing for proper heat transfer and in
corrosion protection;
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• RSCR catalyst had been shown to oxidize mercury. Oxidized mercury can be absorbed by
the local environment and have adverse impact. The impact of RSCR on mercury emissions
needs to be studied to determine whether or not mercury oxidation is a problem and to
identify mitigation methods if needed.
To date, RSCR has been applied to wood-fired utility boilers. Application of this technology has not
been applied to taconite induration furnaces, to airflows of the magnitude of taconite furnace
exhausts, nor to exhaust streams with similar, high moisture content. Using RSCR at a taconite plant
would require research, test runs, and extended trials to identify potential issues related to catalyst
selection, and impacts on plant systems, including the furnaces and emission control systems. It is
not reasonable to assume that vendor guarantees of performance would be forthcoming in advance of
a demonstration project. The timeline required to perform such a demonstration project would likely
be two years to develop and agree on the test plan, obtain permits for the trial, commission the
equipment for the test runs, perform the test runs for a reasonable study period, and evaluate and
report on the results. The results would not be available within the time window for establishing
emission limits to be incorporated in the state implementation plan (SIP) by December 2007.
Recalling U.S. EPA’s intention regarding “available” technologies to be considered for BART, as
mentioned in Section 2.B, facility owners are not expected to undergo extended trials in order to
learn how to apply a control technology to a completely new and significantly different source type.
Therefore, RSCR is not considered to be technically feasible, and will not be analyzed further in this
BART analysis.
SCR with reheat through a conventional duct burner (rather than using a regenerative heater) has
been successfully implemented more widely and in higher airflow applications and will be carried
forward in this analysis as available and applicable technology that is reasonably expected to be
technically feasible.
Low Temperature Oxidation (LTO)
The LTO system utilizes an oxidizing agent such as ozone to oxidize various pollutants including
NOx. In the system, the NOx in the flue gas is oxidized to form nitrogen pentoxide (equations 1, 2,
and 3). The nitrogen pentoxide forms nitric acid vapor as it contacts the water vapor in the flue gas
(4). Then the nitric acid vapor is absorbed as dilute nitric acid and is neutralized by the sodium
hydroxide or lime in the scrubbing solution forming sodium nitrate (5) or calcium nitrate. The
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nitrates are removed from the scrubbing system and discharged to an appropriate water treatment
system. Commercially available LTO systems include Tri-NOx® and LoTOx®.
NO + O3 → NO2 + O2 (1)
NO2 + O3 → NO3 + O2 (2)
NO3 + NO2 → N2O5 (3)
N2O5 + H2O → 2HNO3 (4)
HNO3 + NaOH → NaNO3 + H2O (5)
Low Temperature Oxidation (Tri-NOx®)
This technology uses an oxidizing agent such as ozone or sodium chlorite to oxidize NO to NO2 in a
primary scrubbing stage. Then NO2 is removed through caustic scrubbing in a secondary stage. The
reactions are as follows:
O3 + NO → O2 + NO2 (1)
2NaOH + 2NO2 + ½ O2 → 2NaNO3 + H2O (2)
Tri-NOx® is a multi-staged wet scrubbing process in industrial use. Several process columns, each
assigned a separate processing stage, are involved. In the first stage, the incoming material is
quenched to reduce its temperature. The second, oxidizing stage, converts NO to NO2. Subsequent
stages reduce NO2 to nitrogen gas, while the oxygen becomes part of a soluble salt. Tri-NOx® is
typically applied at small to medium sized sources with high NOx concentration in the exhaust gas
(1,000 ppm NOx). NOx concentrations in taconite exhaust at HTC are typically less than 200 ppm.
Therefore, Tri-NOx® is not applicable to taconite processing and will not be analyzed further in this
BART analysis.
Low Temperature Oxidation (LoTOx®)
BOC Gases’ Lo-TOx® is an example of a version of an LTO system. LoTOx® technology uses ozone
to oxidize NO to NO2 and NO2 to N2O5 in a wet scrubber (absorber). This can be done in the same
scrubber used for particulate or sulfur dioxide removal, The N2O5 is converted to HNO3 in a
scrubber, and is removed with lime or caustic. Ozone for LoTOx® is generated on site with an
electrically powered ozone generator. The ozone generation rate is controlled to match the amount
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needed for NOx control. Ozone is generated from pure oxygen. In order for LoTOx® to be
economically feasible, a source of low cost oxygen must be available from a pipeline or on site
generation.
The first component of the technical feasibility review includes determining if the technology would
apply to the process being reviewed. This would include a review and comparison of the chemical
and physical properties required. Although it appears that the chemistry involved in the LTO
technology may apply to an indurating furnace, the furnace exhaust contains other ore components
that may participate in side reactions. This technology has not been demonstrated on a taconite pellet
indurating furnace. This raises uncertainties about how or whether the technology will transfer to a
different type of process.
The second component of the technical feasibility review includes determining if the technology is
commercially available. Evaluations of LTO found that it has only been applied to small to medium
sized coal or gas fired boiler applications, and has never been demonstrated on a large-scale facility.
For example, the current installations of LoTOx® are on sources with flue gas flow rates from 150 –
35,000 acfm, which is quite small, compared to the indurating furnace flue gas flow rates of over
400,000 acfm. Therefore, the application of LTO would be more than an order of magnitude larger
than the biggest current installation. This large scale-up is contrary to good engineering practices
and could be problematic in maintaining the current removal efficiencies.
In addition, only two of BOC’s LoTOx® installations are fully installed and operational applications.
Therefore, although this is an emerging technology, the limited application means that it has not been
demonstrated to be an effective technology in widespread application.
There are several other concerns about the technical feasibility and applicability of LTO on an
indurating furnace:
• The composition of the indurating furnace flue gas is significantly different than the
composition of the flue gas from the boilers and process heaters that utilize LTO;
• The taconite dust in the flue gas is primarily magnetite (Fe3O4) which would react with the
ozone to form hematite (Fe2O3); since the ozone injection point would be before the scrubber,
there can be more than 400 pounds per hour of taconite dust in the flue gas which could
consume a significant amount of the ozone being generated which may change the reaction
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kinetics; consequently, this would necessitate either an increase in the amount of ozone
generated or a decrease in the estimated control efficiency;
• The ozone that would be injected into the flue gas would react with the SO2, converting the
material to SO3 which could result in the generation of sulfuric acid mist from the scrubber;
• Since LTO has not been installed at a taconite plant, it is likely that the application of LTO to
an indurating furnace waste gas could present technical problems which were not
encountered, or even considered, in the existing LTO applications;
• An LTO system at a taconite facility would also be a source of nitrate discharge to the
tailings basin which would change the facility water chemistry which could cause operational
problems and would likely cause additional problems with National Pollutant Discharge
Elimination System (NPDES) discharge limits and requirements.
Application of this technology has not been applied to taconite induration furnaces, to airflows of the
magnitude of taconite furnace exhausts, nor to exhaust streams with similar, high moisture content.
Using LTO at a taconite plant would require research, test runs, and extended trials to identify
potential issues related to design for high airflows and impacts on plant systems, including the
furnaces and emission control systems. It is not reasonable to assume that vendor guarantees of
performance would be forthcoming in advance of a demonstration project. The timeline required to
perform such a demonstration project would likely be two years to develop and agree on the test
plan, obtain permits for the trial, commission the equipment for the test runs, perform the test runs
for a reasonable study period, and evaluate and report on the results. The results would not be
available within the time window for establishing emission limits to be incorporated in the state
implementation plan (SIP) by December 2007.
Recalling U.S. EPA’s intention regarding “available” technologies to be considered for BART, as
mentioned in Section 2.B, facility owners are not expected to undergo extended trials in order to
learn how to apply a control technology to a completely new and significantly different source type.
Consequently, the technical feasibility of LTO on an indurating furnace is technically infeasible for
this application and will not be evaluated further.
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Step 2 Conclusion
Based upon the determination within Step 2, the remaining NOx control technologies that are
available and applicable to the indurating furnace process are identified in Table 5-4. The technical
feasibility as determined in Step 2 is also included in Table 5-4.
Table 5-4 Indurating Furnace NOx Control Technology – Availability, Applicability, and Technical Feasibility
NOx Pollution Control Technology Available? Applicable?
Technically Feasible?
External Flue Gas Recirculation (EFGR)
Yes Yes No
Low- NOx Burners Yes Yes No
Induced Flue Gas Recirculation Burners
Yes Yes No
Energy Efficiency Projects Yes Yes No
Ported Kilns Yes No No
Alternative Fuels Yes Yes No
Process Optimization using NOx CEMS
Yes No No
Non-Selective Catalytic Reduction (NSCR)
Yes No No
Selective Catalytic Reduction (SCR) with conventional reheat
Yes Yes Yes
Regenerative SCR Yes No No
Selective Non-Catalytic Reduction (SNCR)
Yes No No
Low Temperature Oxidation (LTO)
Yes No No
5.A.ii.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies
Table 5-5 describes the expected control efficiency from each of the remaining technically feasible
control options as identified in Step 2.
Table 5-5 Indurating Furnace NOx Control Technology Effectiveness
NOx Pollution Control Technology
Approximate Control Efficiency
SCR with Conventional Reheat 80%
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5.A.ii.d STEP 4 – Evaluate Impacts and Document the Results
Table 5-6 details the expected costs associated with installation of Low NOx burners. Capital costs
were calculated based on the maximum 24-hour emissions, U.S. EPA cost models, and vendor
estimates. Vendor estimates for capital costs based on a specific flow rate were scaled to each
stack’s flow rate using the 6/10 power law to account for the economy of scale. Operating costs were
based on 93% utilization and 8339 operating house per year. Operating costs were proportionally
adjusted to reflect site specific flow rates and pollutant concentrations.
After a tour of the facility and discussions with facility staff, it was determined the space surrounding
the furnaces is congested and the area surrounding the building supports vehicle and rail traffic to
transport materials to and from the building. A site-specific estimate for site-work, foundations, and
structural steel was added based upon the facility site to arrive at the total retrofit installed cost of the
control technology. The site specific estimate was based on Barr’s experience with similar projects.
See Appendix C for a site plan of the facility. Additionally, the structural design of the existing
building would not support additional equipment on the roof. The detailed cost analysis is provided
in Appendix A.
Table 5-6 Indurating Furnace NOx Control Cost Summary
Control Technology
Installed Capital Cost
(MM$)
Total Annual Cost
(MM$/yr)
Annualized Pollution
Control Cost ($/ton)
Incremental Control Cost
($/ton) Selective Catalytic Reduction (SCR)
With Reheat
Furnace 11 Hood Exhaust
$25,735,488 $11,314,358 $155,784 NA
Furnace 11 Waste Gas
$23,344,084 $8,274,322 $46,771 NA
Furnace 12 Hood Exhaust
$25,912,320 $11,387,084 $162,309 NA
Furnace 12 Waste Gas
$24,026,527 $10,442,659 $61,107 NA
Based on the BART final rule, court cases on cost-effectiveness, guidance from other regulatory
bodies, and other similar regulatory programs like Clean Air Interstate Rule (CAIR), cost-effective
air pollution controls in the electric utility industry for large power plants are in the range $1,000 to
$1,300 per ton removed as illustrated in Appendix E. This cost-effective threshold is also an indirect
measure of affordability for the electric utility industry used by USEPA to support the BART rule-
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making process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost
effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not
afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the
electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater
business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for
proposing BART in lieu of developing industry and site specific data.
The annualized pollution control cost value was used to determine whether or not additional impacts
analyses would be conducted for the technology. If the control cost was less than a screening
threshold established by MPCA, then visibility modeling impacts, and energy and other impacts are
evaluated. MPCA set the screening level to eliminate technologies from requiring the additional
impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled pollutant32.
Therefore, all air pollution controls with annualized costs less than this screening threshold will be
evaluated for visibility improvement, energy and other impacts.
The incremental control cost column in Table 5-6 is intended to present the incremental value of each
technology as compared to the technology with the next most effective alternative. Since none of the
NOx reduction technologies are cost effective, the incremental cost is not applicable.
Energy and Environmental Impacts
Because the cost of NOx controls for NMC furnaces is so high and does not meet a reasonable
definition of cost effective technology, this technology is removed from further consideration in this
analysis.
5.A.ii.e STEP 5 – Evaluate Visibility Impacts
As previously stated in section 4 of this document, states are required to consider the degree of
visibility improvement resulting from the retrofit technology, in combination with other factors such
as economic, energy and other non-air quality impacts, when determining BART for an individual
source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this
document. The economic impacts of controls for NOx are not reasonably cost effective, so visibility
impacts were not modeled for NOx controls. Refer to Table 4-2 for a summary of the modeled 24-
hour maximum emission rates and their computational basis for the existing controls for NOx.
32 Minnesota Pollution Control Agency (MPCA). Air Permit for Cenex Harvest States Cooperative Soybean Processing Plant, Fairmont, MN Permit 09100059-002.
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Visibility impacts with SO2 controls are presented in section 6. Table 6-1 provides a summary of the
SO2, NOx, and PM10 emissions for each modeling scenario,
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5.B External Combustion Sources
Two natural gas and fuel oil fired process boilers require BART analysis. These boilers are back-up
boilers to the main NMC Power House boilers to provide steam required to operate the taconite plant
during Power House outages. These boilers are only permitted to use gas and distillate oil for fuel.
5.B.i Sulfur Dioxide controls
Sulfur in the fuel is the only source of SO2 emissions from these boilers. The boilers only have low
emissions of SO2 due to the low sulfur content of the permitted fuels.
5.B.i.a STEP 1 – Identify All Available Retrofit Control Technologies
See Appendix F for a comprehensive list of all potential retrofit control technologies that were
evaluated.
5.B.i.b STEP 2 – Eliminate Technically Infeasible Options
Step 1 identified the available and applicable technologies for SO2 emission reduction. Within
Step 2, the technical feasibility of the control option is discussed and determined. The following
section describes retrofit SO2 control technologies that were identified as available and applicable
and discusses aspects of those technologies that determine whether or not the technology is
technically feasible for the process boilers.
Wet Walled Electrostatic Precipitator (WWESP)
An electrostatic precipitator (ESP) applies electrical forces to separate suspended particles from the
flue gas stream. The suspended particles are given an electrical charge by passing through a high
voltage DC corona region in which gaseous ions flow. The charged particles are attracted to and
collected on oppositely charged collector plates. Particles on the collector plates are released by
rapping and fall into hoppers for collection and removal.
A wet walled electrostatic precipitator (WWESP) operates on the same collection principles as a dry
ESP and uses a water spray to remove particulate matter from the collection plates. For SO2 removal,
caustic is added to the water spray system, allowing the WWESP spray system to function as an SO2
absorber.
The SO2 control efficiency for a WWESP is dependent upon various process specific variables, such
as SO2 flue gas concentration and fuel used. Based on the definitions contained within this report, a
WWESP is considered an available technology for SO2 reduction for this BART analysis.
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Wet Scrubbing (High and Low Efficiency)
Wet scrubbing, when applied to remove SO2, is generally termed flue-gas desulfurization (FGD).
FGD utilizes gas absorption technology, the selective transfer of materials from a gas to a contacting
liquid, to remove SO2 in the waste gas. Crushed limestone, lime or Caustic is used as scrubbing
agents.
Limestone scrubbing introduces limestone slurry with the flue gas in a spray tower. The sulfur
dioxide is absorbed, neutralized, and partially oxidized to calcium sulfite and calcium sulfate. The
overall reactions are shown in the following equations:
CaCO3 + SO2 → CaSO3 • 1/2 H2O + CO2
CaSO3 •1/2 H2O + 3H2O + O2 → 2 CaSO4 •2 H2O
Lime scrubbing is similar to limestone scrubbing in equipment and process flow, except that lime is a
more reactive reagent than limestone. The reactions for lime scrubbing are as follows:
Ca(OH)2 +SO2 → CaSO3• 1/2 H2O + 1/2 H2O
Ca(OH)2 + SO2 + 1/2 O2 + H2O → CaSO4•2 H2O
When that caustic (sodium hydroxide solution) is the scrubbing agent, the SO2 removal reactions are
as follows:
Na+ + OH- + SO2 + → Na2SO3
2Na+ + 2OH- + SO2 + → Na2SO3 + H2O
Caustic scrubbing produces a liquid waste, and minimal equipment is needed as compared to lime or
limestone scrubbers. If lime or limestone is used as the reagent for SO2 removal, additional
equipment will be needed for preparing the lime/limestone slurry and collecting and concentrating
the resultant sludge. Calcium sulfite sludge is watery; it is typically stabilized with fly ash for land
filling. The calcium sulfate sludge is stable and easy to dewater. To produce calcium sulfate, an air
injection blower is needed to supply the oxygen for the second reaction to occur.
The normal SO2 control efficiency range for SO2 scrubbers on coal fired utility boilers is 80% to 90%
for low efficiency scrubbers and 90% and more for high efficiency scrubbers. The highest control
efficiencies can be achieved when SO2 concentrations are the highest. The process boiler exhaust
would not have a high SO2 concentration, so the low end of the efficiency range would be expected.
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Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection)
Dry sorbent injection involves the injection of a lime or limestone powder into the exhaust gas
stream. The stream is then passed through a baghouse or ESP to remove the sorbent and entrained
SO2. The process was developed as a lower cost FGD option because the mixing occurs directly in
the exhaust gas stream instead of in a separate tower. Depending on the residence time and gas
stream temperature, sorbent injection control efficiency is approximately 55%. Therefore DSI is
technically feasible.
Spray Dryer Absorption (SDA)
Spray dryer absorption (SDA) systems spray lime slurry into an absorption tower where SO2 is
absorbed by the slurry, forming CaSO3/CaSO4. The liquid-to-gas ratio is such that the water
evaporates before the droplets reach the bottom of the tower. The dry solids are carried out with the
gas and collected with a fabric filter. The normal SO2 control efficiency range for SDA is up to 90%.
Based on the information contained with this report, SDA is considered an available technology for
SO2 reduction for this BART analysis.
Energy Efficiency Projects
Energy efficiency projects provide opportunities for a company to reduce their fuel consumption,
which results in lower operating costs. Typically reduced fuel usage translates into reduced pollution
emissions. Due to the increased price of fuel, the facilities have already implemented energy
efficiency projects. Each project carries its own fuel usage reductions and potentially emission
reductions. It would be impossible to assign a general potential emission reduction for the energy
efficient category. Due to the uncertainty and generalization of this category, this will not be further
evaluated in this report. However, it should be noted that facilities will continue to evaluate and
implement energy efficiency projects as they arise.
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Alternate Fuels
As described within the energy efficiency description, increased price of fuel has pushed companies
to evaluate alternate fuel sources. These fuel sources come in all forms – solid, liquid and gas. To
achieve reduction of SO2 emissions through alternative fuel usage, the source must use fuels with
lower sulfur content. NMC has the capability to only burn low sulfur fuels, natural gas and distillate
oil, in these process boilers. Therefore this option is not applicable to the process boilers.
It is also important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as their
option, not to direct the fuel choice.33
Therefore, due to the limited fuel burning capabilities of the boilers and the fact that BART is not
intended to mandate a fuel switch, alternative fuels as an air pollution control technology will not be
further evaluated in this report.
However, similar to energy efficiency, facilities will continue to evaluate and implement alternate
fuel usage as the feasibility arises.
Coal Processing
Since NMC process boilers are not capable of burning solid fuel, this option is not applicable for SO2
reductions at NMC.
STEP 2 Conclusion
Based upon the determination within Step 2, the remaining SO2 control technologies that are
available and applicable to the process boilers are identified in Table 5-7. The technical feasibility as
determined in Step 2 is also included in Table 5-7.
33 Federal Register 70, no. 128 (July 6, 2005): 39164
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Table 5-7 Backup Process Boiler SO2 Control Technology – Availability, Applicability, and Technical Feasibility
SO2 Pollution Control Technology Available? Applicable? Technically Feasible?
WWESP Yes Yes Yes
Wet Scrubber Yes Yes Yes
Spray Dry Absorption (SDA) Yes Yes Yes
Dry Sorbent Injection (DSI) Yes Yes Yes
Energy Efficiency Projects Yes Yes No
Alternative Fuels Yes Yes No
5.B.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies
Table 5-8 describes the expected control efficiency from each of the remaining feasible control
options when burning liquid fuels.
Table 5-8 Backup Process Boiler SO2 Control Technology Effectiveness
SO2 Pollution Control Technology Approximate Control Efficiency
Wet Walled Electrostatic Precipitator (WWESP) 80%
Wet Scrubbing (High Efficiency) 80%
Dry Sorbent Injection 55%
Spray Dryer Absorption 90%
5.B.i.d STEP 4 – Evaluate Impacts and Document the Results
As illustrated in Table 5-8 above, the technically feasible control remaining provide varying levels of
emission reduction. Therefore, it is necessary to consider the economic, energy, and environmental
impacts to better differentiate as presented below.
Economic Impacts
Table 5-9 details the expected costs associated with installation of a WWESP, wet scrubber, DSI and
SDA on each stack. Equipment design was based on the maximum 24-hour emissions, vendor
estimates, and U.S. EPA cost models. Capital costs were based on a recent vendor quotation. The
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cost for that unit was scaled to each stack’s flow rate using the 6/10 power law as shown in the
following equation:
Cost of equipment A = Cost of equipment B * (capacity of A/capacity of B)0.6
Direct and indirect costs were estimated as a percentage of the fixed capital investment using U.S.
EPA models and factors. Operating costs were based on 93% utilization and 7650 operating hours
per year, which is very conservative, considering these are backup boilers. Operating costs of
consumable materials, such as electricity, water, and chemicals were established based on the U.S.
EPA control cost manual34 and engineering experience, and were adjusted for the specific flow rates
and pollutant concentrations.
See Appendix C for an aerial photo of the facility. The detailed cost analysis is provided in Appendix
A.
Table 5-9 Backup Process Boiler SO2 Control Cost Summary
Control Technology
Installed Capital Cost
($)
Total Annual Cost
($/yr)
Annualized Pollution
Control Cost ($/ton)
Incremental Control Cost
($/ton)
Wet ESP $11,808,857 $2,247,725 $36,558 NA
Wet Scrubber $13,618,522 $1,869,933 $31,845 NA
Dry Sorbent Injection and Baghouse
$4,890,063 $1,409,010 $22,917 NA
Spray Dryer and Baghouse $16,134,577 $2,751,525 $44,752 NA
Based on the BART final rule, court cases on cost-effectiveness, guidance from other regulatory
bodies, and other similar regulatory programs like Clean Air Interstate Rule (CAIR), cost-effective
air pollution controls in the electric utility industry for large power plants are in the range $1,000 to
$1,300 per ton removed as illustrated in Appendix E. This cost-effective threshold is also an indirect
measure of affordability for the electric utility industry used by USEPA to support the BART rule-
making process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost
effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not
afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the
electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater
34 U.S. EPA, January 2002, EPA Air Pollution Control Cost Manual, Sixth Edition.
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business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for
proposing BART in lieu of developing industry and site specific data.
The annualized pollution control cost value was used to determine whether or not additional impacts
analyses would be conducted for the technology. If the control cost was less than a screening
threshold established by MPCA, then visibility modeling impacts, and energy and other impacts are
evaluated. MPCA set the screening level to eliminate technologies from requiring the additional
impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled pollutant35.
Therefore, all air pollution controls with annualized costs less than this screening threshold will be
evaluated for visibility improvement, energy and other impacts.
The incremental control cost column in Table 5-9 is intended to present the incremental value of each
technology as compared to the next most effective alternative. Since none of the technologies are
cost effective, the incremental control cost is not applicable.
Energy and Environmental Impacts
Because the cost of SO2 controls for the NMC process boilers is so high and does not meet a
reasonable definition of cost effective technology, these technologies are removed from further
consideration in this analysis.
5.B.i.e STEP 5 – Evaluate Visibility Impacts
As previously stated in section 4 of this document, states are required to consider the degree of
visibility improvement resulting from the retrofit technology, in combination with other factors such
as economic, energy and other non-air quality impacts, when determining BART for an individual
source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this
document. The economic impacts of controls for SO2 are not reasonably cost effective, so visibility
impacts were not modeled for SO2 controls. Refer to Table 4-2 for a summary of the modeled 24-
hour maximum emission rates and their computational basis for the existing controls for SO2.
Visibility impacts with NOx controls are presented in Section 6. Table 6-1 provides a summary of
the SO2, NOx, and PM10 emissions for each modeling scenario.
35 Minnesota Pollution Control Agency (MPCA). Air Permit for Cenex Harvest States Cooperative Soybean Processing Plant, Fairmont, MN Permit 09100059-002.
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5.B.ii Nitrogen Oxide Controls
To be able to control NOx it is important to understand how NOx is formed. There are three
mechanisms by which NOx production occurs: thermal, fuel and prompt NOx.
• Fuel bound NOx is formed as nitrogen compounds in the fuel is oxidized in the combustion
process.
• Thermal NOx production arises from the thermal dissociation of nitrogen and oxygen
molecules within the furnace. Combustion air is the primary source of nitrogen and oxygen.
Thermal NOx production is a function of the residence time, free oxygen, and temperature.
• Prompt NOx is a form of thermal NOx which is generated at the flame boundary. It is the
result of reactions between nitrogen and carbon radicals generated during combustion. Only
minor amounts of NOx are emitted as prompt NOx.
The majority of NOx is emitted as NO. Minor amounts of NO2 are formed in the heater.
5.B.ii.a STEP 1 – Identify All Available Retrofit Control Technologies
With the understanding of how NOx is formed, available and applicable control technologies were
evaluated. See Appendix F for the current status of the availability and applicability of retrofit
control technologies.
5.B.ii.b STEP 2 – Eliminate Technically Infeasible Options
Step 1 identified the available and applicable technologies for NOx emission reduction. Within
Step 2, the technical feasibility of the control option was discussed and determined. The following
describes retrofit NOx control technologies that were identified as available and applicable and
discusses aspects of those technologies that determine whether or not the technology is technically
feasible for the process boilers.
External Flue Gas Recirculation (EFGR)
External flue gas recirculation (EFGR) uses flue gas as an inert material to reduce flame temperatures
thereby reducing thermal NOx formation. In an external flue gas recirculation system, flue gas is
collected from the heater or stack and returned to the burner via a duct and blower. The flue gas is
mixed with the combustion air and this mixture is introduced into the burner. The addition of flue gas
reduces the oxygen content of the “combustion air” (air + flue gas) in the burner. The lower oxygen
level in the combustion zone reduces flame temperatures; which in turn reduces NOx emissions. For
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this technology to be effective, the combustion conditions must have the ability to be controlled at
the burner tip. Process boilers 1 and 2 do not have the capability of control at the burner tip.
Therefore, this option is not technically feasible and will not be further evaluated in this report.
Low NOx Burners (LNB)
Low- NOx burner (LNB) technology utilizes advanced burner design to reduce NOx formation
through the restriction of oxygen, flame temperature, and/or residence time. LNB is a staged
combustion process that is designed to split fuel combustion into two zones. In the primary zone,
NOx formation is limited by either one of two methods. Under staged air rich (high fuel) condition,
low oxygen levels limit flame temperatures resulting in less NOx formation. The primary zone is
then followed by a secondary zone in which the incomplete combustion products formed in the
primary zone act as reducing agents. Alternatively, under staged fuel lean (low fuel) conditions,
excess air will reduce flame temperature to reduce NOx formation. In the secondary zone,
combustion products formed in the primary zone act to lower the local oxygen concentration,
resulting in a decrease in NOx formation. Low NOx burners typically achieve NOx emission
reductions of 25% - 50% for process boilers.
Overfire Air (OFA)
Overfire air diverts a portion of the total combustion air from the burners and injects it through
separate air ports above the top level of burners. OFA is a NOx control technology typically used in
boilers and is primarily geared to reduce thermal NOx. Staging of the combustion air creates an initial
fuel-rich combustion zone for a cooler fuel-rich combustion zone. This reduces the production of
thermal NOx by lowering combustion temperature and limiting the availability of oxygen in the
combustion zone where NOx is most likely to be formed. OFA is considered compatible with the
LNB and is a technically feasible option for further NOx reduction. However, due to the small size
and number of burners, OFA is not desirable alternative for NMC process boilers and will not be
considered for further BART analysis.
Induced Flue Gas Recirculation Burners
Induced flue gas recirculation burners, also called ultra low- NOx burners, combine the benefits of
flue gas recirculation and low-NOx burner control technologies. The burner is designed to draw flue
gas to dilute the fuel in order to reduce the flame temperature. These burners also utilize staged fuel
combustion to further reduce flame temperature. The estimated NOx control efficiency for IFGR
burners in high temperature applications is 50-75%.
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Energy Efficiency Projects
Energy efficiency projects provide opportunities for a company to reduce their fuel consumption.
Typically reduced fuel usage translates into reduced pollution emissions. An energy efficiency
project could be preheat incoming make-up air or pellet feed. Each project is very dependent upon
the fuel usage, process equipment, type of product and so many other variables.
Due to the increased price of fuel, the facilities have already implemented energy efficiency projects.
Each project carries its own fuel usage reductions and potentially emission reductions. It would be
impossible to assign a general potential emission reduction for the energy efficient category. Due to
the uncertainty and generalization of this category, this will not be further evaluated in this report.
However, it should be noted that facilities will continue to evaluate and implement energy efficiency
projects as they arise.
Alternate Fuels
As described within the energy efficiency description, increased price of fuel has pushed companies
to evaluate alternate fuel sources. These fuel sources come in all forms – solid, liquid and gas. To
achieve reduction of NOx emissions through alternative fuel usage, the source must be currently
burning a high NOx emitting fuel relative to other fuels. The boilers are only capable of burning
natural gas and distillate oil. Therefore the use of alternate fuels is not a viable option for the process
boilers and will not be considered further in this analysis.
It is also important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as their
option, not to direct the fuel choice.36
Therefore, due to the limited boiler fuel capabilities and the fact that BART is not intended to
mandate a fuel switch, alternative fuels as an air pollution control technology will not be further
evaluated in this report
However, similar to energy efficiency, facilities will continue to evaluate and implement alternate
fuel usage as the feasibility arises.
36 Federal Register 70, no. 128 (July 6, 2005): 39164
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Post Combustion Controls
NOx can be controlled using add-on systems located downstream of the combustion process. The
two main techniques in commercial service include the selective non catalytic reduction (SNCR)
process and the selective catalytic reduction (SCR) process. There are a number of different process
systems in each of these categories of control techniques.
In addition to these treatment systems, there are a large number of other processes being developed
and tested on the market. These approaches involve innovative techniques of chemically reducing,
absorbing, or adsorbing NOx downstream of the combustion chamber. Examples of these alternatives
are nonselective catalytic reduction (NSCR) and Low Temperature Oxidation (LTO). Each of these
alternatives is described below.
Non-Selective Catalytic Reduction (NSCR)
A non-selective catalytic reduction (NSCR) system is a post combustion add-on exhaust gas
treatment system. NSCR catalyst is very sensitive to poisoning; so; NSCR is usually applied
primarily in natural gas combustion applications.
NSCR is often referred to as “three-way conversion” catalyst because it simultaneously reduces NOx,
unburdened hydrocarbons (UBH), and carbon monoxide (CO). Typically, NSCR can achieve NOx
emission reductions of 90 percent. In order to operate properly, the combustion process must be near
stoichiometric conditions. Under this condition, in the presence of a catalyst, NOx is reduced by CO,
resulting in nitrogen (N2) and carbon dioxide (CO2). The most important reactions for NOx removal
are:
2CO + 2NO → 2CO2 + N2 (1)
[UBH] + NO → N2 + CO2 + H2O (2)
NSCR catalyst has been applied primarily in clean combustion applications. This is due in large part
to the catalyst being very sensitive to poisoning, making it infeasible to apply this technology to
liquid fuels. Therefore, this technology will not be further evaluated in this report.
Selective Catalytic Reduction and Regenerative Selective Catalytic Reduction
SCR is a post-combustion NOx control technology in which ammonia (NH3) is injected into the flue
gas stream in the presence of a catalyst. NOx is removed through the following chemical reaction:
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4 NO + 4 NH3 + O2 → 4 N2 + 6 H2O (1)
2 NO2 + 4 NH3 + O2 → 3 N2 + 6 H2O (2)
A catalyst bed containing metals in the platinum family is used to lower the activation energy
required for NOx decomposition. SCR requires a temperature range of about 570°F – 850°F for a
normal catalyst. At temperature exceeding approximately 670ºF, the oxidation of ammonia begins to
become significant. At low temperatures, the formation of ammonium bisulfate causes scaling and
corrosion problems.
A high temperature zeolite catalyst is also available; it can operate in the 600 °F – 1000°F
temperature range. However, these catalysts are very expensive.
Ammonia slip from the SCR system is usually less than 3 to 5 ppm. The emission of ammonia
increases during load changes due to the instability of the temperature in the catalyst bed as well as at
low loads because of the low gas temperature.
Regenerative Selective Catalytic Reduction (RSCR) applies the Selective Catalytic Reduction (SCR)
control process as described below with a preheat process step to reheat the flue gas stream up to
SCR catalyst operating temperatures. The preheating process combines use of a thermal heat sink
(packed bed) and a duct burner. The thermal sink recovers heat from the hot gas leaving the RSCR
and then transfers that heat to gas entering the RSCR. The duct burner is used to complete the
preheating process. RSCR operates with several packed bed/SCR reactor vessels. Gas flow
alternates between vessels. Each of the vessels alternates between preheating/treating and heat
recovery.
The benefits of RSCR are:
• Its high energy efficiency allows it to be used after SO2 and particulate controls.
• RSCR has a thermal efficiency of 90% - 95% vs. standard heat exchangers which have a
thermal efficiency of 60% to 70%.
• Application of RSCR after SO2 and PM controls significantly reduces the potential for
problems associated with plugging and catalyst poisoning and deactivation.
To date, RSCR has been applied to wood-fired utility boilers. Application of this technology has not
been applied to liquid and natural gas fired boilers. Using RSCR would require research, test runs,
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and extended trials to identify potential issues related to catalyst selection, and impacts on plant
systems. It is not reasonable to assume that vendor guarantees of performance would be forthcoming
in advance of a demonstration project. The timeline required to perform such a demonstration project
would likely be two years to develop and agree on the test plan, obtain permits for the trial,
commission the equipment for the test runs, perform the test runs for a reasonable study period, and
evaluate and report on the results. The results would not be available within the time window for
establishing emission limits to be incorporated in the state implementation plan (SIP) by December
2007.
Recalling U.S. EPA’s intention regarding “available” technologies to be considered for BART, as
mentioned in Section 2.B, facility owners are not expected to undergo extended trials in order to
learn how to apply a control technology to a completely new and significantly different source type.
Therefore, RSCR is not considered to be technically feasible, and will not be analyzed further in this
BART analysis.
Selective Non-Catalytic Reduction (SNCR)
In the SNCR process, urea or ammonia-based chemicals are injected into the flue gas stream to
convert NO to molecular nitrogen, N2, and water. SNCR control efficiency is typically 25% - 60%.
Without a catalyst, the reaction requires a high temperature range to obtain activation energy. The
relevant reactions are as follows:
NO + NH3 + ¼O2 → N2 + 3/2H2O (1)
NH3 + ¼O2 → NO + 3/2H2O (2)
At temperature ranges of 1470 to 1830°F reaction (1) dominates. At temperatures above 2000°F,
reaction (2) will dominate. This control option is considered feasible.
Low Temperature Oxidation (LTO)
The LTO system utilizes an oxidizing agent such as ozone to oxidize various pollutants including
NOx. In the system, the NOx in the flue gas is oxidized to form nitrogen pentoxide (equations 1, 2,
and 3). The nitrogen pentoxide forms nitric acid vapor as it contacts the water vapor in the flue gas
(4). Then the nitric acid vapor is absorbed as dilute nitric acid and is neutralized by the sodium
hydroxide or lime in the scrubbing solution forming sodium nitrate (5) or calcium nitrate. The
nitrates are removed from the scrubbing system and discharged to an appropriate water treatment
system. Commercially available LTO systems include Tri-NOx® and LoTOx®.
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NO + O3 → NO2 + O2 (1)
NO2 + O3 → NO3 + O2 (2)
NO3 + NO2 → N2O5 (3)
N2O5 + H2O → 2HNO3 (4)
HNO3 + NaOH → NaNO3 + H2O (5)
Low Temperature Oxidation (Tri-NOx®)
This technology uses an oxidizing agent such as ozone or sodium chlorite to oxidize NO to NO2 in a
primary scrubbing stage. Then NO2 is removed through caustic scrubbing in a secondary stage. The
reactions are as follows:
O3 + NO → O2 + NO2 (1)
2NaOH + 2NO2 + ½ O2 → 2NaNO3 + H2O (2)
Tri-NOx® is a multi-staged wet scrubbing process in industrial use. Several process columns, each
assigned a separate processing stage, are involved. In the first stage, the incoming material is
quenched to reduce its temperature. The second, oxidizing stage, converts NO to NO2. Subsequent
stages reduce NO2 to nitrogen gas, while the oxygen becomes part of a soluble salt. Tri-NOx® is
typically applied at small to medium sized sources with high NOx concentration in the exhaust gas
(1,000 ppm NOx).
Low Temperature Oxidation (LoTOx®)
BOC Gases’ Lo-TOx® is an example of a version of an LTO system. LoTOx® technology uses ozone
to oxidize NO to NO2 and NO2 to N2O5 in a wet scrubber (absorber). This can be done in the same
scrubber used for particulate or sulfur dioxide removal, The N2O5 is converted to HNO3 in a
scrubber, and is removed with lime or caustic. Ozone for LoTOx® is generated on site with an
electrically powered ozone generator. The ozone generation rate is controlled to match the amount
needed for NOx control. Ozone is generated from pure oxygen. In order for LoTOx® to be
economically feasible, a source of low cost oxygen must be available from a pipeline or on site
generation.
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In addition, only two of BOC’s LoTOx® installations are fully installed and operational applications.
Therefore, although this is an emerging technology, the limited application means that it has not been
demonstrated to be an effective technology in widespread application. Consequently, the technical
feasibility of LTO as technically infeasible for this application and will not be evaluated further.
Step 2 Conclusion
Based upon the determination within Step 2, the remaining NOx control technologies that are
available and applicable to the process boilers are identified in Table 5-10. The technical feasibility
as determined in Step 2 is also included in Table 5-10.
Table 5-10 Backup Process Boiler NOx Control Technology – Availability, Applicability and Technical Feasibility
NOx Pollution Control Technology Available? Applicable? Technically Feasible?
External Flue Gas Recirculation (EFGR) Yes Yes No
Low-NOx Burners Yes Yes Yes
Overfired Air Yes Yes No
Induced Flue Gas Recirculation (IFGR) Yes Yes Yes
Energy Efficiency Projects Yes Yes No
Alternative Fuels Yes Yes Not required
Non-Selective Catalytic Reduction (NSCR) Yes Yes No
Selective Catalytic Reduction (SCR) Yes Yes Yes
Regenerative SCR Yes Yes No
Selective Non-Catalytic Reduction (SNCR) Yes Yes Yes
Low Temperature Oxidation (LTO) Yes No No
5.B.ii.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies
Table 5-11 describes the expected control efficiency from each of the remaining technically feasible
control options as identified in Step 2.
Table 5-11 Backup Process Boiler NOx Control Technology Effectiveness
NOx Pollution Control Technology Approximate Control
Efficiency
Low-NOx Burners 50%
Low-NOx Burners with IFGR 75%
SCR 90%
Selective Non-Catalytic Reduction (SNCR) 50%
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5.B.ii.d STEP 4 – Evaluate Impacts and Document the Results
Table 5-12 details the expected costs associated with installation of NOx controls. Capital costs were
calculated based on the maximum 24-hour emissions, U.S. EPA cost models, and vendor estimates.
Vendor estimates for capital costs based on a specific flow rate were scaled to each stack’s flow rate
using the 6/10 power law to account for the economy of scale. Operating costs were based on 93%
utilization and 7650 operating hours per year, which is extremely conservative, since they are backup
boilers. Operating costs were proportionally adjusted to reflect site specific flow rates and pollutant
concentrations.
After a tour of the facility and discussions with facility management, it was determined the space
surrounding the boilers is congested and the area surrounding the building supports vehicle and rail
traffic to transport materials to and from the building. A site-specific estimate for site-work,
foundations, and structural steel was added based upon the facility site to arrive at the total retrofit
installed cost of the control technology. See Appendix C for a site plan of the facility. Additionally,
the structural design of the existing building would not support additional equipment on the roof. The
detailed cost analysis is provided in Appendix A.
Table 5-12 Backup Process Boiler NOx Control Cost Summary
Control Technology
Installed Capital Cost
($) Operating Cost
($/yr)
Annualized Pollution
Control Cost ($/ton)
Incremental Control
Cost ($/ton)
Low NOx Burner $90,775 $14,915 $723 NA
Low NOx Burner / IFGR
$518,713 $330,367 $10,675 $30,626
Selective Catalytic Reduction (SCR)
$5,563,529 $1,120,061 $30,160 NA
Selective Non-Catalytic Reduction
(SNCR) $925,876 $250,181 $12,126 NA
Based on the BART final rule, court cases on cost-effectiveness, guidance from other regulatory
bodies, and other similar regulatory programs like Clean Air Interstate Rule (CAIR), cost-effective
air pollution controls in the electric utility industry for large power plants are in the range $1,000 to
$1,300 per ton removed as illustrated in Appendix E. This cost-effective threshold is also an indirect
measure of affordability for the electric utility industry used by USEPA to support the BART rule-
making process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost
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effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not
afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the
electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater
business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for
proposing BART in lieu of developing industry and site specific data.
The annualized pollution control cost value was used to determine whether or not additional impacts
analyses would be conducted for the technology. If the control cost was less than a screening
threshold established by MPCA, then visibility modeling impacts, and energy and other impacts are
evaluated. MPCA set the screening level to eliminate technologies from requiring the additional
impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled pollutant37.
Therefore, all air pollution controls with annualized costs less than this screening threshold will be
evaluated for visibility improvement, energy and other impacts.
The incremental control cost listed in Table 5-12 represents the incremental value of each technology
as compared to the technology with the next highest level of control.
Energy and Environmental Impacts
The energy and non-air quality impacts for LNB and LNB with IFGR are presented in Table 5-13.
Because the cost of the remaining NOx control technologies for the NMC process boilers is so high
and does not meet a reasonable definition of cost effective technology, these technologies are
removed from further consideration in this analysis.
Table 5-13 Backup Process Boiler NOx Control Technology – Other Impacts Assessment
Control
Option Energy Impacts Other Impacts
LNB - Minimal energy impacts - Increase in CO emissions - Potential for steam tube wastage due to
longer combustion flame
IFGR/LNB - Minimal energy impacts. - Increase in CO emissions - Potential for steam tube wastage due to
longer combustion flame.
37 Minnesota Pollution Control Agency (MPCA). Air Permit for Cenex Harvest States Cooperative Soybean Processing Plant, Fairmont, MN Permit 09100059-002.
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5.B.ii.e STEP 5 – Evaluate Visibility Impacts
As previously stated in section 4 of this document, states are required to consider the degree of
visibility improvement resulting from the retrofit technology, in combination with other factors such
as economic, energy and other non-air quality impacts, when determining BART for an individual
source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this
document. This section of the report evaluates the visibility impacts of BART NOX control and the
resulting degree of visibility improvement.
Predicted 24-Hour Maximum Emission Rates
Consistent with the use of the highest daily emissions for baseline, or pre-BART, visibility impacts,
the post-BART emissions to be used for the visibility impacts analysis should also reflect a
maximum 24-hour average project emission rate. In the visibility impacts NOX modeling analysis,
the emissions from the sources undergoing a full BART NOX analysis were adjusted to reflect the
projected 24-hour maximum NOX emission rate when applying the control technologies that met the
threshold requirements of steps 1 – 4. The emissions from all other Subject-to-BART sources were
not changed. Table 5-14 provides a summary of the modeled 24-hour maximum emission rates and
their computational basis for the evaluated NOX control technologies. Table 5-15 provides a
summary of the SO2, NOX, and PM10 emissions for each modeling scenario, and Table 5-16 provides
a summary of the modeling input data.
Table 5-14 Backup Process Boiler NOx Post- BART Emission Rates for Emission Unit EU003 and EU004
Control Scenario SV #
Emission Unit Description
NOx Control
Technology % NOx
Reduction
NOx Annual Emission Rate
(tons/year)
NOx 24-hour Maximum Emission
Rate (lb/day)
1 SV003 Process Boiler 1 Low Nox Burners
50% 25.5 279
1 SV003 Process Boiler 2 Low Nox Burners
50% 25.5 279
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Table 5-15 Backup Process Boiler Post-BART Modeling Scenarios
Scenario Control Scenario Technology Modeling Emission Rate Input
SO2 NOx PM2.5/PM10
SO2 NOx PM %
Reduced 24-hr Max
lb/hr %
Reduced 24-hr Max
lb/hr %
Reduced
PM2.5 24-hr Max.
lb/hr %
Reduced
PM2.5-10 24-hr Max.
lb/hr
0 Base Base Base
SV003 Process Boilers 1 & 2
0 33.5 0 23.3 0 0 1.9
1 Base LNB with IFGR
Base
SV003 Process Boilers 1 & 2
0.0% 33.5 50.0% 11.6 0 0 1.9
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Table 5-16 Backup process Boiler Post-BART NOx Modeling Scenarios - Modeling Input Data
Control Scenario SV #
Emission Unit Stack Easting
LCC (km)
Stack Northing LCC (km)
Height of Opening
from Ground (m)
Base Elevation of Ground
(m)
Stack Diameter
(m)
Flow Rate at exit (acfm)
Exit Temp (oF)
1 SV003 Process
Boilers 1 & 2 631471.5 5238482.8 131 611 6.5 59900 450
Post-BART Visibility Impacts Modeling Results
Results of the post-BART visibility impacts modeling for NOX for the process boilers are presented
in Table 5-17. The results summarize 98th percentile dV value and the number of days the facility
contributes more than a 0.5 dV of visibility impairment at each of the Class I areas. The comparison
of the post-BART modeling scenarios to the baseline conditions is presented in Table 5-18.
Visibility impacts with SO2 controls are presented in section 6.
Table 5-17 Backup Process Boiler Post-BART NOx Modeling Scenarios - Visibility Modeling Results
2002 2003 2004 2002 – 2004 Combined
Scenario #
Class I Area with Greatest Impact
Modeled 98
th
Percentile Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98th
Percentile
Value (deciview)
No. of days exceeding
0.5 deciview
Modeled 98th
Percentile
Value (deciview)
No. of days exceeding
0.5 deciview
Modeled 98th
Percentile
Value (deciview)
No. of days exceeding
0.5 deciview
0 BWCA 1.1 34 1.1 34 1.3 38 1.1 106 1 BWCA 1.1 33 1.1 34 1.3 38 1.1 105
Table 5-18 Backup Process Boiler Post-BART NOx Modeling Scenarios – Comparison of Visibility Modeling Results to Baseline Modeling Results
2002 2003 2004 2002 – 2004 Combined
Scenario #
Class I Area with Greatest Impact
Improved Modeled
98th
Percentile
Value (∆-dV)
Decreased No. of days
exceeding 0.5
deciview
Improved Modeled 98
th
Percentile Value (∆-dV)
Decreased No. of days exceeding
0.5 deciview
Improved Modeled 98
th
Percentile Value (∆-dV)
Decreased No. of days exceeding
0.5 deciview
Improved Modeled 98
th
Percentile Value (∆-dV)
Decreased No. of days exceeding
0.5 deciview
0 BWCA 1.1 34 1.1 34 1.3 38 1.1 106 1 BWCA 0.0 1 0.0 0 0.0 0 0.0 1
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6. Visibility Impacts
As previously stated in section 4 of this document, states are required to consider the degree of
visibility improvement resulting from the retrofit technology, in combination with other factors such
as economic, energy and other non-air quality, when determining BART for an individual source.
The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this document.
The visibility impacts of individual control technologies were presented in Step 5 of section 5 of this
document. This section of the report evaluates the various BART control scenarios utilizing both
SO2 and NOx controls, and estimates the resulting degree of visibility improvement.
6.A Post-BART Modeling Scenarios Steps 1-4 of the BART analysis identified the control technologies that were:
• Available and applicable;
• Technically feasible; and
• Below the screening cost threshold for further BART analysis.
Step 5 of the BART analysis evaluated the visibility impacts of each of the control technologies that
met the requirements of the screening analysis of steps 1-4.
However, because there are limited control options available that meet the above criteria, there are
limited available control combinations, or control scenarios, that must be considered. Additionally,
the interactions between the visibility impairing pollutants NOx, SO2 and PM10 can play a large part
in predicting impairment. It is therefore important to take a multi-pollutant approach when assessing
visibility impacts. Accordingly, this visibility improvement analysis evaluates several operating
control scenarios that account for the various combinations of available SO2 and NOx controls. In
addition, two site-specific scenarios were developed so that the evaluation includes other operating
scenarios and conditions that would improve visibility impairment. The post-BART modeling
scenarios, including those presented in Step 5 of section 5, are presented in Table 6-1.
6.B Post-BART Modeling Results Results of the post-BART modeling scenarios are presented in Table 6-2. The results summarize
98th percentile dV value and the number of days the facility contributes more than a 0.5 dV of
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68
visibility impairment at each of the Class I areas. The comparison of the post-BART modeling
scenarios to the baseline conditions is presented in Table 6-3.
While the cost per ton of low NOx burners is $723, and is below the threshold of $1,000 to $1,300 per
ton, they result in essentially no visibility improvement to the Class I areas. In the three years,
additional controls would result in only one fewer day with a visibility impact of greater than 0.5 dV
and the change in the modeled worst day (98th percentile) is 0.007 deciviews, which is less than 1%
of the total modeled BART impact. The cost of this marginal improvement is $4.3 million per
deciview, considering the capital cost of $91,000 and the total annual cost of $15,000.
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69
Table 6-1 Post-BART Modeling Scenarios
Scenario Control Technology SO2 NOx Particulate Matter
Control Scenario SV # Emission Unit SO2 NOx
% Reduction
Max 24-hour lbs/hr % Reduction
Max 24-hour lbs/hr
PM10 Max 24-hr lbs/hr
PM2.5 Max 24-hr lbs/hr
PMcoarse Max 24-hr lbs/hr
0 Base
(existing design)
Base (existing design)
SV101 Furnace 11 Hood Exh --- 11.8 --- 17.1 11.3
SV102 Furnace 11 Hood Exh 11.8 17.1 11.3
SV103 Furnace 11 Hood Exh 11.8 17.1 11.3
SV104 Furnace 11 Waste Gas --- 5.9 --- 62.4 10.6
SV105 Furnace 11 Waste Gas 5.9 62.4 10.6
SV111 Furnace 12 Hood Exh --- 11.8 --- 17.1 11.3
SV112 Furnace 12 Hood Exh 11.8 17.1 11.3
SV113 Furnace 12 Hood Exh 11.8 17.1 11.3
SV114 Furnace 12 Waste Gas --- 5.9 --- 62.4 10.6
SV115 Furnace 12 Waste Gas 5.9 62.4 1.6
SV003 Process Boilers 1 & 2 33.5 23.3 1.9
1 Base
Base on indurating
furnace and Low NOx
Burners on the backup
process boilers
SV101 Furnace 11 Hood Exh 11.8 --- 17.1 11.3
SV102 Furnace 11 Hood Exh 11.8 17.1 11.3
SV103 Furnace 11 Hood Exh 11.8 17.1 11.3
SV104 Furnace 11 Waste Gas 5.9 --- 62.4 10.6
SV105 Furnace 11 Waste Gas 5.9 62.4 10.6
SV111 Furnace 12 Hood Exh 11.8 --- 17.1 11.3
SV112 Furnace 12 Hood Exh 11.8 17.1 11.3
SV113 Furnace 12 Hood Exh 11.8 17.1 11.3
SV114 Furnace 12 Waste Gas 5.9 --- 62.4 10.6
SV115 Furnace 12 Waste Gas 5.9 62.4 1.6
SV003 Process Boilers 1 & 2 33.5 50.0% 11.6 1.9
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70
Table 6-2 Post-BART Modeling Scenarios - Visibility Modeling Results
2002 2003 2004 2002 – 2004 Combined
Scenario #
Class I Area with
Greatest Impact
Modeled 98
th
Percentile Value
(deciview)
No. of days exceeding
0.5 deciview
Modeled 98th
Percentile
Value (deciview)
No. of days exceeding 0.5
deciview
Modeled 98th
Percentile
Value (deciview)
No. of days exceeding 0.5
deciview
Modeled 98th
Percentile
Value (deciview)
No. of days exceeding 0.5
deciview
0 BWCA 1.1 34 1.1 34 1.3 38 1.1 106
1 BWCA 1.1 33 1.1 34 1.3 38 1.1 105
Table 6-3 Post-BART Modeling Scenarios – Comparison of Visibility Modeling Results to Baseline Modeling Results
Modeling Results
0 2002 2003 2004 2002-2004
Scenario Limiting Class I Area
Improved Modeled
98th Percentile
Value (∆-dV)
Decreased No. of Days
exceeding 0.5 dV
Improved Modeled 98th
Percentile Value (∆-dV)
Decreased No. of Days exceeding
0.5 dV
Improved Modeled 98th
Percentile Value (∆-dV)
Decreased No. of Days exceeding
0.5 dV
Improved Modeled
98th Percentile
Value (∆-dV)
Decreased No. of Days
exceeding 0.5 dV
0 BWCA 1.1 34 1.1 34 1.3 38 1.1 106
1 BWCA 0.0 1 0.0 0 0.0 0 0.0 1
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71
7. Select BART
BART for NMC is proposed to be as follows:
Indurating Furnaces
For SO2, polishing add-on controls are not cost effective. Therefore, BART is proposed to be
existing controls. The corresponding SO2 emissions limit would be 2.0 lbs/mmBtu, which equates to
300 lb/hr per furnace based upon each furnace heat input rating of 150 mmBtu.
For NOx, add on control are not cost effective. Therefore, BART is proposed to be the existing
furnace design and permitted fuels. The corresponding NOx limit would be 176 lb/hr for each
furnace.
For PM, requirements compelled by the upcoming MACT standard constitute BART. The
corresponding emissions limit would be 0.01 grains per dscf for the furnaces.
Process Boilers
The process boilers are backup boilers for steam production normally supplied to the taconite plant
from the power boilers. For SO2, add-on controls are not cost effective. Therefore, BART is
proposed to be existing design and permitted fuels. The corresponding SO2 emissions limit would be
0.6 lb/mmBtu for each boiler.
For NOx, add-on controls would not accomplish a meaningful improvement in visibility. Therefore,
BART is proposed to be existing design and permitted fuels. The corresponding NOx limit would be
0.17 lb/mmBtu for each boiler.
Other Taconite Sources
For PM, requirements compelled by the upcoming MACT standard constitute BART. The
corresponding emissions limit would be equivalent to the MACT limit.
The schedule for implementation of these limits is within the 5-year time-frame required for BART
implementation.
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 1: Cost Summary
NOx Control Cost Summary
Control TechnologyControl
Eff %
Controlled
Emissions T/y
Emission
Reduction T/yr
Installed Capital
Cost $
Total Annual Cost
$/yr
Pollution Control
Cost $/ton
Furnace 11 Hood Exhaust 80% 5.7 106.7 $46,019,283 $11,628,024 $108,969
Furnace 11 Waste Gas 80% 17.8 255.9 $43,197,692 $8,239,261 $32,199
Furnace 12 Hood Exhaust 80% 5.6 104.4 $46,284,809 $11,688,411 $112,008
Furnace 12 Waste Gas 80% 17.4 250.3 $43,455,895 $10,383,373 $41,488
SO2 Control Cost Summary
Control TechnologyControl
Eff %
Controlled
Emissions T/y
Emission
Reduction T/yr
Installed Capital
Cost $
Total Annual Cost
$/yr
Pollution Control
Cost $/ton
Wet Walled Electrostatic Precipitator (WWESP)
Furnace 11 Hood Exhaust 80% 5.7 22.9 $23,617,556 $4,188,875 $182,993
Furnace 11 Waste Gas 80% 1.9 7.6 $21,846,389 $3,799,211 $496,949
Furnace 12 Hood Exhaust 80% 5.3 21.0 $23,617,556 $4,294,171 $204,058
Furnace 12 Waste Gas 80% 1.8 7.0 $21,846,389 $3,764,113 $535,575
Wet Scrubber
Furnace 11 Hood Exhaust 60% 11.4 17.2 $16,952,864 $2,401,349 $139,872
Furnace 11 Waste Gas 60% 3.8 5.7 $15,859,420 $2,201,975 $384,034
Furnace 12 Hood Exhaust 60% 10.5 15.8 $16,952,864 $2,401,349 $152,149
Furnace 12 Waste Gas 60% 3.5 5.3 $15,859,420 $2,201,975 $417,742
Selective Catalytic Reduction with Reheat
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Cost Summary 9/6/2006 Page 1 of 56
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 2: - Summary of Utility, Chemical and Supply Costs
Operating Unit: Furnace 11 Hood Exhaust Study Year 2006
Emission Unit Number EU 100
Stack/Vent Number SV 101, 102, & 103
Operating Unit: Furnace 11 Waste Gas
Emission Unit Number EU 104
Stack/Vent Number SV 104 & 105
Operating Unit: Furnace 12 Hood Exhaust
Emission Unit Number EU 110
Stack/Vent Number SV 111, 112, & 113
Operating Unit: Furnace 12 Waste Gas
Emission Unit Number EU 114
Stack/Vent Number SV 114 & 115
Reference
Item Unit Cost Units Cost Year Data Source NotesOperating Labor 50 $/hr 2006 Site Specific - Northshore Mining .
Maintenance Labor 60 $/hr 2006 Site Specific - Northshore Mining . Construction Labor Rate.
Electricity 0.060 $/kwh 2006 Site Specific - Northshore Mining. Purchased.
Natural Gas 10.0204 $/mscf 2006 Site Specific - Northshore Mining . $9.40/MMBtu @ 1066 Btu/scf.
Water 0.28 $/mgal 0.20 1995
EPA Air Pollution Control Cost Manual, 6th
Ed 2002, Section 5 Ch 1, page 1-40.
Annual Costs for Packed Tower Absorber Example Problem. '95 cost
adjusted for 3% inflation.
Cooling Water 0.28 $/mgal 0.23 1999
EPA Air Pollution Control Cost Manual, 6th
ed. Section 3.1 Ch 1.
Ch 1 Carbon Absorbers, 1999 $0.15 - $0.30 Avg of 22.5 and 7 yrs and
3% inflation.
Compressed Air 0.32 $/mscf 0.25 1998
EPA Air Pollution Control Cost Manual 6th Ed
2002, Section 6 Chapter 1 .
Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3%
inflation.
Wastewater Disposal Neutralization 1.69 $/mgal 1.50 2002
EPA Air Pollution Control Cost Manual 6th Ed
2002, Section 2 Chapter 2.5.5.5.
Section 2 lists $1- $2/1000 gal. Cost adjusted for 3% inflation Sec 6 Ch
3 lists $1.30 - $2.15/1,000 gal.
Chemicals & Supplies
Lime 88.98 $/ton 88.98 2006 Estimate from Cutler-Magney Company.
Oxygen 40.00 $/ton 2006 BOC estimate.
Ammonia (29% aqua.) 0.12 $/lb 0.101 2000
EPA Air Pollution Control Cost Manual 6th Ed
2002, Section 5 Chapter 2, page 2-50.
Annual costs for a retrofit SCR system example problem. '00 costs
adjusted for 3% inflation.
Caustic 305.96 $/ton 280 2003 Hawkins Chemical 50% solution (50 Deg Be); includes delivery. '03 cost adjusted for inflation
Other
Sales Tax 6.5% %
Interest Rate 7.00% %
EPA Air Pollution Control Cost Manual
Introduction, Chapter 2, section 2.4.2. Social (discount) rate used as a default.
Operating Information
Annual Op. Hrs 8339.1 Hours 2006 Site Specific - Northshore Mining . Maximum hours of operation 2004-2005 with a 10% safety factor.
Utilization Rate 93%
Equipment Life 20 yrs Engineering Estimate.
Standardized Flow Rate
SV 101, 102, & 103 181,762 scfm @ 32º F Calculated.
SV 104 & 105 152,520 scfm @ 32º F Calculated.
SV 111, 112, & 113 181,762 scfm @ 32º F Calculated.
SV 114 & 115 152,520 scfm @ 32º F Calculated.
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Utility Chem$ Data 9/6/2006 Page 2 of 56
Reference
Item Unit Cost Units Cost Year Data Source Notes
Temperature
SV 101, 102, & 103 142 Deg F BART spreadsheet.
SV 104 & 105 140 Deg F BART spreadsheet.
SV 111, 112, & 113 142 Deg F BART spreadsheet.
SV 114 & 115 140 Deg F BART spreadsheet.
Moisture Content
SV 101, 102, & 103 11.3% 2006
Y:\23\38\126 NSM 2006 Stack Testing\WK4
Fce 11+\Data. Average from test results in:Test 1-3 Fce 11 HE 1101-1103 - 6-13-06.
SV 104 & 105 18.3% 2006
Y:\23\38\126 NSM 2006 Stack Testing\WK4
Fce 11+\Data. Average from test results in: Test 4-5 Fce 11 WG 1104-1105 - 6-14-06.
SV 111, 112, & 113 9.5% 2006
Y:\23\38\126 NSM 2006 Stack Testing\WK2
Fce 12\Data. Average from test results in: Fce 12 HE 1201-1203 4-18-06.
SV 114 & 115 16.4% 2006
Y:\23\38\126 NSM 2006 Stack Testing\WK2
Fce 12\Data. Average from test results in: Fce 12 WG 1204-1205 4-19-06.
Actual Flow Rate
SV 101, 102, & 103 222,400 acfm BART spreadsheet.
SV 104 & 105 186,000 acfm BART spreadsheet.
SV 111, 112, & 113 222,400 acfm BART spreadsheet.
SV 114 & 115 186,000 acfm BART spreadsheet.
Standardized Flow Rate
SV 101, 102, & 103 195,062 scfm @ 68º F Calculated.
SV 104 & 105 163,680 scfm @ 68º F Calculated.
SV 111, 112, & 113 195,062 scfm @ 68º F Calculated.
SV 114 & 115 163,680 scfm @ 68º F Calculated.
Dry Std Flow Rate
SV 101, 102, & 103 172,951 dscfm @ 68º F Calculated.
SV 104 & 105 133,792 dscfm @ 68º F Calculated.
SV 111, 112, & 113 176,529 dscfm @ 68º F Calculated.
SV 114 & 115 136,902 dscfm @ 68º F Calculated.
Max Emis Actual Emissions lb/hr ton/year
Pollutant Lb/Hr Ton/year ('04&'05 Max) ppmv ppmv
Nitrous Oxides (NOx)
SV 101, 102, & 103 51.3 112.4 41 20.7 2005 plus 10%
SV 104 & 105 124.8 273.7 130 65.1 2004 plus 10%
SV 111, 112, & 113 51.3 109.9 40 19.8 2004 plus 10%
SV 114 & 115 124.8 267.7 127 62.3 2004 plus 10%
Sulfur Dioxides (SO2)
SV 101, 102, & 103 35.5 28.6 21 3.8 2004 plus 10%
SV 104 & 105 11.8 9.6 9 1.6 2004 plus 10%
SV 111, 112, & 113 35.5 26.3 20 3.4 2004 plus 10%
SV 114 & 115 11.8 8.8 9 1.5 2004 plus 10%
guess
calculated value
known or assumed data
required data
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Utility Chem$ Data 9/6/2006 Page 3 of 56
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 3: SOx Control - Wet Scrubber
Operating Unit: Furnace 11 Hood Exhaust
Emission Unit Number EU 100 Stack/Vent Number SV 101, 102, & 103
Standardized Flow Rate 181,762 scfm @ 32º F
Expected Utilization Rate 93% Temperature 142 Deg F
Expected Annual Hours of Operation 8,339 Hours Moisture Content 11.3%
Annual Interest Rate 7.0% Actual Flow Rate 222,400 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 195,062 scfm @ 68º F
Dry Std Flow Rate 172,951 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs (1)
Purchased Equipment (A) 2,765,654
Purchased Equipment Total (B) 22% of control device cost (A) 3,360,270
Installation - Standard Costs 85% of purchased equip cost (B) 2,856,229
Installation - Site Specific Costs 6,200,000
Installation Total 2,856,229
Total Direct Capital Cost, DC 6,216,499
Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 504,040
Total Capital Investment (TCI) = DC + IC 16,952,864
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 476,790
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,924,559
Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,401,349
Actual
Emission Control Cost Calculation Emis Emissions
Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 51.3 112.4 0% 112.4 - NA
Sulfur Dioxide (SO2) 35.5 28.6 60% 11.4 17.2 139,872
Notes & Assumptions
1 Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm.
2 Liquid/Gas ratio = 38 L/G = Gal/1,000 acf.
3 Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate.
4 Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition.
5 CUECost Workbook Version 1.0, USEPA Document Page 2.
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EU100 Wet Scrubber 9/6/2006 Page 4 of 56
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 3: SOx Control - Wet Scrubber
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1)
Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 2,765,654
Instrumentation 10% of control device cost (A) 276,565
MN Sales Taxes 7% of control device cost (A) 179,768
Freight 5% of control device cost (A) 138,283
Purchased Equipment Total (B) 22% 3,360,270
Installation
Foundations & supports 12% of purchased equip cost (B) 403,232
Handling & erection 40% of purchased equip cost (B) 1,344,108
Electrical 1% of purchased equip cost (B) 33,603
Piping 30% of purchased equip cost (B) 1,008,081
Insulation 1% of purchased equip cost (B) 33,603
Painting 1% of purchased equip cost (B) 33,603
Installation Subtotal Standard Expenses 85% 2,856,229
Total Direct Capital Cost, DC 6,216,499
Indirect Capital Costs
Engineering, supervision 5% of purchased equip cost (B) 168,013
Construction & field expenses 0% of purchased equip cost (B) 0
Contractor fees 5% of purchased equip cost (B) 168,013Start-up 1% of purchased equip cost (B) 33,603Performance test 1% of purchased equip cost (B) 33,603
Model Studies NA of purchased equip cost (B) NA
Contingencies 3% of purchased equip cost (B) 100,808
Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 504,040
Total Capital Investment (TCI) = DC + IC 6,720,540
Retrofit multiplier5
60% of TCI 4,032,324
Sitework and foundations Site Specific 1,400,000
Structural steel Site Specific 4,800,000
Site Specific - Other Site Specific 0
Total Site Specific Costs 6,200,000
Total Capital Investment (TCI) Retrofit Installed 16,952,864
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 37.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 26,060
Supervisor 15% 15% of Operator Costs 3,909
Maintenance
Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 31,272
Maintenance Materials 100% of maintenance labor costs 31,272
Utilities, Supplies, Replacements & Waste Management
Electricity 0.06 $/kwh, 457 kW-hr, Annual Operating Hours, 93% utilization 212,823
Water 0.28 $/kgal, 209 gpm, Annual Operating Hours, 93% utilization 26,883
WW Treat Neutralization 1.69 $/kgal, 169 gpm, Annual Operating Hours, 93% utilization 132,783
Lime 88.98 $/ton, 34 lb/hr, Annual Operating Hours, 93% utilization 11,789Total Annual Direct Operating Costs 476,790
Indirect Operating Costs
Overhead 60% of total labor and material costs 55,507
Administration (2% total capital costs) 2% of total capital costs (TCI) 134,411
Property tax (1% total capital costs) 1% of total capital costs (TCI) 67,205
Insurance (1% total capital costs) 1% of total capital costs (TCI) 67,205
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,600,230
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,924,559
Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,401,349
See Summary page for notes and assumptions
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EU100 Wet Scrubber 9/6/2006 Page 5 of 56
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 3: SOx Control - Wet Scrubber
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalyst:
Equipment Life 20 years
CRF 0.0000
Rep part cost per unit 0 $/ft3
Amount Required 0 ft3
Packing Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit 0.00 $ each
Amount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kW
Blower, Scrubber 222,400 8.55 0.7 - 317.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48
Flow Liquid SPGR ∆ P ft H2O Efficiency Hp kWCirc Pump 8,451 gpm 1 60 0.7 - 136.2 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
H2O WW Disch 209 gpm 1 60 0.7 - 3.4 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
Other
Total 457.4
Reagent Use & Other Operating Costs
Caustic Use 35.50 lb/hr SO2 2.50 lb NaOH/lb SO2 88.75 lb/hr Caustic
Lime Use 35.50 lb/hr SO2 0.96 lb Lime/lb SO2 34.17 lb/hr lime, lime addition at 1.1 times the stoichiometric ratio
Liquid/Gas ratio 38.0 * L/G = Gal/1,000 acf
Circulating Water Rate2
8,451 gpm
Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 209 gpm
Evaporation Loss4 = 39.66 gpm
Operating Cost Calculations Annual hours of operation: 8,339
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 521 26,060 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours,
Supervisor 15% of Op. NA 3,909 15% of Operator Costs
Maintenance
Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 521 31,272 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours,
Maint Mtls 100 % of Maintenance Labor NA 31,272 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.060 $/kwh 457.4 kW-hr 3,547,050 212,823 $/kwh, 457 kW-hr, Annual Operating Hours, 93% utilization
Water 0.28 $/kgal 208.7 gpm 97,104 26,883 $/kgal, 209 gpm, Annual Operating Hours, 93% utilization
WW Treat Neutralization 1.69 $/kgal 169.0 gpm 78,651 132,783 $/kgal, 169 gpm, Annual Operating Hours, 93% utilization
Lime 89.0 $/ton 34.2 lb/hr 132 11,789 $/ton, 34 lb/hr, Annual Operating Hours, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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EU100 Wet Scrubber 9/6/2006 Page 6 of 56
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 4: SOx Control - Wet Scrubber
Operating Unit: Furnace 11 Waste Gas
Emission Unit Number EU 104 Stack/Vent Number SV 104 & 105
Standardized Flow Rate 152,520 scfm @ 32º F
Expected Utilization Rate 93% Temperature 140 Deg F
Expected Annual Hours of Operation 8,339 Hours Moisture Content 18.3%
Annual Interest Rate 7.0% Actual Flow Rate 186,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 163,680 scfm @ 68º F
Dry Std Flow Rate 133,792 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs (1)
Purchased Equipment (A) 2,484,419
Purchased Equipment Total (B) 22% of control device cost (A) 3,018,569
Installation - Standard Costs 85% of purchased equip cost (B) 2,565,783
Installation - Site Specific Costs 6,200,000
Installation Total 2,565,783
Total Direct Capital Cost, DC 5,584,352
Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 452,785
Total Capital Investment (TCI) = DC + IC 15,859,420
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 407,966
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,794,010
Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,201,975
Actual
Emission Control Cost Calculation Emis Emissions
Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 124.8 273.7 0% 273.7 - NA
Sulfur Dioxide (SO2) 11.8 9.6 60% 3.8 5.7 384,034
Notes & Assumptions
1 Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm.
2 Liquid/Gas ratio = 38 L/G = Gal/1,000 acf.
3 Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate.
4 Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition.
5 CUECost Workbook Version 1.0, USEPA Document Page 2.
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EU104 Wet Scrubber 9/6/2006 Page 7 of 56
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 4: SOx Control - Wet Scrubber
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1)
Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 2,484,419
Instrumentation 10% of control device cost (A) 248,442
MN Sales Taxes 7% of control device cost (A) 161,487
Freight 5% of control device cost (A) 124,221
Purchased Equipment Total (B) 22% 3,018,569
Installation
Foundations & supports 12% of purchased equip cost (B) 362,228
Handling & erection 40% of purchased equip cost (B) 1,207,427
Electrical 1% of purchased equip cost (B) 30,186
Piping 30% of purchased equip cost (B) 905,571
Insulation 1% of purchased equip cost (B) 30,186
Painting 1% of purchased equip cost (B) 30,186
Installation Subtotal Standard Expenses 85% 2,565,783
Total Direct Capital Cost, DC 5,584,352
Indirect Capital Costs
Engineering, supervision 5% of purchased equip cost (B) 150,928
Construction & field expenses 0% of purchased equip cost (B) 0
Contractor fees 5% of purchased equip cost (B) 150,928Start-up 1% of purchased equip cost (B) 30,186Performance test 1% of purchased equip cost (B) 30,186
Model Studies NA of purchased equip cost (B) NA
Contingencies 3% of purchased equip cost (B) 90,557
Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 452,785
Total Capital Investment (TCI) = DC + IC 6,037,137
Retrofit multiplier5
60% of TCI 3,622,282
Sitework and foundations Site Specific 1,400,000
Structural steel Site Specific 4,800,000
Site Specific - Other Site Specific 0
Total Site Specific Costs 6,200,000
Total Capital Investment (TCI) Retrofit Installed 15,859,420
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 37.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 26,060
Supervisor 15% 15% of Operator Costs 3,909
Maintenance
Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 31,272
Maintenance Materials 100% of maintenance labor costs 31,272
Utilities, Supplies, Replacements & Waste Management
Electricity 0.06 $/kwh, 383 kW-hr, Annual Operating Hours, 93% utilization 177,990
Water 0.28 $/kgal, 175 gpm, Annual Operating Hours, 93% utilization 22,483
WW Treat Neutralization 1.69 $/kgal, 141 gpm, Annual Operating Hours, 93% utilization 111,050
Lime 88.98 $/ton, 11 lb/hr, Annual Operating Hours, 93% utilization 3,930Total Annual Direct Operating Costs 407,966
Indirect Operating Costs
Overhead 60% of total labor and material costs 55,507
Administration (2% total capital costs) 2% of total capital costs (TCI) 120,743
Property tax (1% total capital costs) 1% of total capital costs (TCI) 60,371
Insurance (1% total capital costs) 1% of total capital costs (TCI) 60,371
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,497,017
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,794,010
Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,201,975
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
EU104 Wet Scrubber 9/6/2006 Page 8 of 56
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 4: SOx Control - Wet Scrubber
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalyst:
Equipment Life 20 years
CRF 0.0000
Rep part cost per unit 0 $/ft3
Amount Required 0 ft3
Packing Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit 0.00 $ each
Amount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kW
Blower, Scrubber 186,000 8.55 0.7 - 265.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48
Flow Liquid SPGR ∆ P ft H2O Efficiency Hp kWCirc Pump 7,068 gpm 1 60 0.7 - 113.9 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
H2O WW Disch 175 gpm 1 60 0.7 - 2.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
Other
Total 382.5
Reagent Use & Other Operating Costs
Caustic Use 11.83 lb/hr SO2 2.50 lb NaOH/lb SO2 29.58 lb/hr Caustic
Lime Use 11.83 lb/hr SO2 0.96 lb Lime/lb SO2 11.39 lb/hr lime, lime addition at 1.1 times the stoichiometric ratio
Liquid/Gas ratio 38.0 * L/G = Gal/1,000 acf
Circulating Water Rate2
7,068 gpm
Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 175 gpm
Evaporation Loss4 = 33.17 gpm
Operating Cost Calculations Annual hours of operation: 8,339
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 521 26,060 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours,
Supervisor 15% of Op. NA 3,909 15% of Operator Costs
Maintenance
Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 521 31,272 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours,
Maint Mtls 100 % of Maintenance Labor NA 31,272 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.060 $/kwh 382.5 kW-hr 2,966,507 177,990 $/kwh, 383 kW-hr, Annual Operating Hours, 93% utilization
Water 0.28 $/kgal 174.5 gpm 81,211 22,483 $/kgal, 175 gpm, Annual Operating Hours, 93% utilization
WW Treat Neutralization 1.69 $/kgal 141.4 gpm 65,778 111,050 $/kgal, 141 gpm, Annual Operating Hours, 93% utilization
Lime 89.0 $/ton 11.4 lb/hr 44 3,930 $/ton, 11 lb/hr, Annual Operating Hours, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
EU104 Wet Scrubber 9/6/2006 Page 9 of 56
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 5 SOx Control - Wet Scrubber
Operating Unit: Furnace 12 Hood Exhaust
Emission Unit Number EU 110 Stack/Vent Number SV 111, 112, & 113
Standardized Flow Rate 181,762 scfm @ 32º F
Expected Utilization Rate 93% Temperature 142 Deg F
Expected Annual Hours of Operation 8,339 Hours Moisture Content 9.5%
Annual Interest Rate 7.0% Actual Flow Rate 222,400 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 195,062 scfm @ 68º F
Dry Std Flow Rate 176,529 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs (1)
Purchased Equipment (A) 2,765,654
Purchased Equipment Total (B) 22% of control device cost (A) 3,360,270
Installation - Standard Costs 85% of purchased equip cost (B) 2,856,229
Installation - Site Specific Costs 6,200,000
Installation Total 2,856,229
Total Direct Capital Cost, DC 6,216,499
Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 504,040
Total Capital Investment (TCI) = DC + IC 16,952,864
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 476,790
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,924,559
Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,401,349
Actual
Emission Control Cost Calculation Emis Emissions
Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 51.3 109.9 0% 109.9 - NA
Sulfur Dioxide (SO2) 35.5 26.3 60% 10.5 15.8 152,149
Notes & Assumptions
1 Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm.
2 Liquid/Gas ratio = 38 L/G = Gal/1,000 acf.
3 Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate.
4 Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition.
5 CUECost Workbook Version 1.0, USEPA Document Page 2.
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
EU110 Wet Scrubber 9/6/2006 Page 10 of 56
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 5 SOx Control - Wet Scrubber
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1)
Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 2,765,654
Instrumentation 10% of control device cost (A) 276,565
MN Sales Taxes 7% of control device cost (A) 179,768
Freight 5% of control device cost (A) 138,283
Purchased Equipment Total (B) 22% 3,360,270
Installation
Foundations & supports 12% of purchased equip cost (B) 403,232
Handling & erection 40% of purchased equip cost (B) 1,344,108
Electrical 1% of purchased equip cost (B) 33,603
Piping 30% of purchased equip cost (B) 1,008,081
Insulation 1% of purchased equip cost (B) 33,603
Painting 1% of purchased equip cost (B) 33,603
Installation Subtotal Standard Expenses 85% 2,856,229
Total Direct Capital Cost, DC 6,216,499
Indirect Capital Costs
Engineering, supervision 5% of purchased equip cost (B) 168,013
Construction & field expenses 0% of purchased equip cost (B) 0
Contractor fees 5% of purchased equip cost (B) 168,013Start-up 1% of purchased equip cost (B) 33,603Performance test 1% of purchased equip cost (B) 33,603
Model Studies NA of purchased equip cost (B) NA
Contingencies 3% of purchased equip cost (B) 100,808
Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 504,040
Total Capital Investment (TCI) = DC + IC 6,720,540
Retrofit multiplier5
60% of TCI 4,032,324
Sitework and foundations Site Specific 1,400,000
Structural steel Site Specific 4,800,000
Site Specific - Other Site Specific 0
Total Site Specific Costs 6,200,000
Total Capital Investment (TCI) Retrofit Installed 16,952,864
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 37.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 26,060
Supervisor 15% 15% of Operator Costs 3,909
Maintenance
Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 31,272
Maintenance Materials 100% of maintenance labor costs 31,272
Utilities, Supplies, Replacements & Waste Management
Electricity 0.06 $/kwh, 457 kW-hr, Annual Operating Hours, 93% utilization 212,823
Water 0.28 $/kgal, 209 gpm, Annual Operating Hours, 93% utilization 26,883
WW Treat Neutralization 1.69 $/kgal, 169 gpm, Annual Operating Hours, 93% utilization 132,783
Lime 88.98 $/ton, 34 lb/hr, Annual Operating Hours, 93% utilization 11,789Total Annual Direct Operating Costs 476,790
Indirect Operating Costs
Overhead 60% of total labor and material costs 55,507
Administration (2% total capital costs) 2% of total capital costs (TCI) 134,411
Property tax (1% total capital costs) 1% of total capital costs (TCI) 67,205
Insurance (1% total capital costs) 1% of total capital costs (TCI) 67,205
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,600,230
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,924,559
Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,401,349
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
EU110 Wet Scrubber 9/6/2006 Page 11 of 56
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 5 SOx Control - Wet Scrubber
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalyst:
Equipment Life 20 years
CRF 0.0000
Rep part cost per unit 0 $/ft3
Amount Required 0 ft3
Packing Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit 0.00 $ each
Amount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kW
Blower, Scrubber 222,400 8.55 0.7 - 317.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48
Flow Liquid SPGR ∆ P ft H2O Efficiency Hp kWCirc Pump 8,451 gpm 1 60 0.7 - 136.2 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
H2O WW Disch 209 gpm 1 60 0.7 - 3.4 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
Other
Total 457.4
Reagent Use & Other Operating Costs
Caustic Use 35.50 lb/hr SO2 2.50 lb NaOH/lb SO2 88.75 lb/hr Caustic
Lime Use 35.50 lb/hr SO2 0.96 lb Lime/lb SO2 34.17 lb/hr lime, lime addition at 1.1 times the stoichiometric ratio
Liquid/Gas ratio 38.0 * L/G = Gal/1,000 acf
Circulating Water Rate2
8,451 gpm
Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 209 gpm
Evaporation Loss4 = 39.66 gpm
Operating Cost Calculations Annual hours of operation: 8,339
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 521 26,060 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours,
Supervisor 15% of Op. NA 3,909 15% of Operator Costs
Maintenance
Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 521 31,272 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours,
Maint Mtls 100 % of Maintenance Labor NA 31,272 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.060 $/kwh 457.4 kW-hr 3,547,050 212,823 $/kwh, 457 kW-hr, Annual Operating Hours, 93% utilization
Water 0.28 $/kgal 208.7 gpm 97,104 26,883 $/kgal, 209 gpm, Annual Operating Hours, 93% utilization
WW Treat Neutralization 1.69 $/kgal 169.0 gpm 78,651 132,783 $/kgal, 169 gpm, Annual Operating Hours, 93% utilization
Lime 89.0 $/ton 34.2 lb/hr 132 11,789 $/ton, 34 lb/hr, Annual Operating Hours, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
EU110 Wet Scrubber 9/6/2006 Page 12 of 56
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 6: SOx Control - Wet Scrubber
Operating Unit: Furnace 12 Waste Gas
Emission Unit Number EU 114 Stack/Vent Number SV 114 & 115
Standardized Flow Rate 152,520 scfm @ 32º F
Expected Utilization Rate 93% Temperature 140 Deg F
Expected Annual Hours of Operation 8,339 Hours Moisture Content 16.4%
Annual Interest Rate 7.0% Actual Flow Rate 186,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 163,680 scfm @ 68º F
Dry Std Flow Rate 136,902 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs (1)
Purchased Equipment (A) 2,484,419
Purchased Equipment Total (B) 22% of control device cost (A) 3,018,569
Installation - Standard Costs 85% of purchased equip cost (B) 2,565,783
Installation - Site Specific Costs 6,200,000
Installation Total 2,565,783
Total Direct Capital Cost, DC 5,584,352
Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 452,785
Total Capital Investment (TCI) = DC + IC 15,859,420
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 407,966
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,794,010
Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,201,975
Actual
Emission Control Cost Calculation Emis Emissions
Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 124.8 267.7 0% 267.7 - NA
Sulfur Dioxide (SO2) 11.8 8.8 60% 3.5 5.3 417,742
Notes & Assumptions
1 Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm.
2 Liquid/Gas ratio = 38 L/G = Gal/1,000 acf.
3 Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate.
4 Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition.
5 CUECost Workbook Version 1.0, USEPA Document Page 2.
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
EU114 Wet Scrubber 9/6/2006 Page 13 of 56
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 6: SOx Control - Wet Scrubber
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1)
Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 2,484,419
Instrumentation 10% of control device cost (A) 248,442
MN Sales Taxes 7% of control device cost (A) 161,487
Freight 5% of control device cost (A) 124,221
Purchased Equipment Total (B) 22% 3,018,569
Installation
Foundations & supports 12% of purchased equip cost (B) 362,228
Handling & erection 40% of purchased equip cost (B) 1,207,427
Electrical 1% of purchased equip cost (B) 30,186
Piping 30% of purchased equip cost (B) 905,571
Insulation 1% of purchased equip cost (B) 30,186
Painting 1% of purchased equip cost (B) 30,186
Installation Subtotal Standard Expenses 85% 2,565,783
Total Direct Capital Cost, DC 5,584,352
Indirect Capital Costs
Engineering, supervision 5% of purchased equip cost (B) 150,928
Construction & field expenses 0% of purchased equip cost (B) 0
Contractor fees 5% of purchased equip cost (B) 150,928Start-up 1% of purchased equip cost (B) 30,186Performance test 1% of purchased equip cost (B) 30,186
Model Studies NA of purchased equip cost (B) NA
Contingencies 3% of purchased equip cost (B) 90,557
Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 452,785
Total Capital Investment (TCI) = DC + IC 6,037,137
Retrofit multiplier5
60% of TCI 3,622,282
Sitework and foundations Site Specific 1,400,000
Structural steel Site Specific 4,800,000
Site Specific - Other Site Specific 0
Total Site Specific Costs 6,200,000
Total Capital Investment (TCI) Retrofit Installed 15,859,420
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 37.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 26,060
Supervisor 15% 15% of Operator Costs 3,909
Maintenance
Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 31,272
Maintenance Materials 100% of maintenance labor costs 31,272
Utilities, Supplies, Replacements & Waste Management
Electricity 0.06 $/kwh, 383 kW-hr, Annual Operating Hours, 93% utilization 177,990
Water 0.28 $/kgal, 175 gpm, Annual Operating Hours, 93% utilization 22,483
WW Treat Neutralization 1.69 $/kgal, 141 gpm, Annual Operating Hours, 93% utilization 111,050
Lime 88.98 $/ton, 11 lb/hr, Annual Operating Hours, 93% utilization 3,930Total Annual Direct Operating Costs 407,966
Indirect Operating Costs
Overhead 60% of total labor and material costs 55,507
Administration (2% total capital costs) 2% of total capital costs (TCI) 120,743
Property tax (1% total capital costs) 1% of total capital costs (TCI) 60,371
Insurance (1% total capital costs) 1% of total capital costs (TCI) 60,371
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,497,017
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,794,010
Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,201,975
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
EU114 Wet Scrubber 9/6/2006 Page 14 of 56
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 6: SOx Control - Wet Scrubber
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalyst:
Equipment Life 20 years
CRF 0.0000
Rep part cost per unit 0 $/ft3
Amount Required 0 ft3
Packing Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit 0.00 $ each
Amount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kW
Blower, Scrubber 186,000 8.55 0.7 - 265.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48
Flow Liquid SPGR ∆ P ft H2O Efficiency Hp kWCirc Pump 7,068 gpm 1 60 0.7 - 113.9 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
H2O WW Disch 175 gpm 1 60 0.7 - 2.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
Other
Total 382.5
Reagent Use & Other Operating Costs
Caustic Use 11.83 lb/hr SO2 2.50 lb NaOH/lb SO2 29.58 lb/hr Caustic
Lime Use 11.83 lb/hr SO2 0.96 lb Lime/lb SO2 11.39 lb/hr lime, lime addition at 1.1 times the stoichiometric ratio
Liquid/Gas ratio 38.0 * L/G = Gal/1,000 acf
Circulating Water Rate2
7,068 gpm
Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 175 gpm
Evaporation Loss4 = 33.17 gpm
Operating Cost Calculations Annual hours of operation: 8,339
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 521 26,060 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours,
Supervisor 15% of Op. NA 3,909 15% of Operator Costs
Maintenance
Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 521 31,272 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours,
Maint Mtls 100 % of Maintenance Labor NA 31,272 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.060 $/kwh 382.5 kW-hr 2,966,507 177,990 $/kwh, 383 kW-hr, Annual Operating Hours, 93% utilization
Water 0.28 $/kgal 174.5 gpm 81,211 22,483 $/kgal, 175 gpm, Annual Operating Hours, 93% utilization
WW Treat Neutralization 1.69 $/kgal 141.4 gpm 65,778 111,050 $/kgal, 141 gpm, Annual Operating Hours, 93% utilization
Lime 89.0 $/ton 11.4 lb/hr 44 3,930 $/ton, 11 lb/hr, Annual Operating Hours, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
EU114 Wet Scrubber 9/6/2006 Page 15 of 56
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 7: SO2 Control - Wet Walled Electrostatic Precipitator
Operating Unit: Furnace 11 Hood Exhaust
Emission Unit Number EU 100 Stack/Vent Number SV 101, 102, & 103
Standardized Flow Rate 181,762 scfm @ 32º F
Expected Utilization Rate 93% Temperature 142 Deg F
Expected Annual Hours of Operation 8,339 Hours Moisture Content 11.3%
Annual Interest Rate 7.0% Actual Flow Rate 222,400 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 195,062 scfm @ 68º F
Dry Std Flow Rate 172,951 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 3,999,843
Purchased Equipment Total (B) 22% of control device cost (A) 4,859,809
Installation - Standard Costs 67% of purchased equip cost (B) 3,256,072
Installation - Site Specific Costs 6,200,000
Installation Total 3,256,072
Total Direct Capital Cost, DC 8,115,881
Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,770,091
Total Capital Investment (TCI) = DC + IC 23,617,556
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,425,578
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,763,297
Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,188,875
Actual
Emission Control Cost Calculation Emissions
Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 51.3 112.4 0% 112.4 - NA
Sulfur Dioxide (SO2) 35.5 28.6 80% 5.7 22.9 182,993
Notes & Assumptions
1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3.
2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm.
3 CUECost Workbook Version 1.0, USEPA Document Page 2.
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
EU100 WWESP 9/6/2006 Page 16 of 56
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 7: SO2 Control - Wet Walled Electrostatic Precipitator
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A)1
Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 3,999,843
Instrumentation 10% of control device cost (A) 399,984
MN Sales Taxes 6.5% of control device cost (A) 259,990
Freight 5% of control device cost (A) 199,992
Purchased Equipment Total (B) 22% 4,859,809
Installation
Foundations & supports 4% of purchased equip cost (B) 194,392
Handling & erection 50% of purchased equip cost (B) 2,429,905
Electrical 8% of purchased equip cost (B) 388,785
Piping 1% of purchased equip cost (B) 48,598
Insulation 2% of purchased equip cost (B) 97,196
Painting 2% of purchased equip cost (B) 97,196
Installation Subtotal Standard Expenses 67% 3,256,072
Total Direct Capital Cost, DC 8,115,881
Indirect Capital Costs
Engineering, supervision 20% of purchased equip cost (B) 971,962
Construction & field expenses 20% of purchased equip cost (B) 971,962
Contractor fees 10% of purchased equip cost (B) 485,981
Start-up 1% of purchased equip cost (B) 48,598
Performance test 1% of purchased equip cost (B) 48,598Model Studies 2% of purchased equip cost (B) 97,196
Contingencies 3% of purchased equip cost (B) 145,794
Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,770,091
Total Capital Investment (TCI) = DC + IC 10,885,972
Retrofit multiplier3
60% of TCI 6,531,583
Sitework and foundations Site Specific 1,400,000
Structural steel Site Specific 4,800,000
Site Specific - Other Site Specific NA
Total Site Specific Costs 6,200,000
Total Capital Investment (TCI) Retrofit Installed 23,617,556
OPERATING COSTSDirect Annual Operating Costs, DC
Operating Labor
Operator 50.00 $/Hr, 2 hr/8 hr shift, Annual Operating Hours, 0% utilization 104,239
Supervisor 15% of Op., 0 , Annual Operating Hours, 0% utilization 15,636
Maintenance
Maintenance Labor 60.00 $/Hr, 15 hr/wk, Annual Operating Hours, 0% utilization 4,340
Maintenance Materials 1.00 % of Maintenance Labor 39,998
Utilities, Supplies, Replacements & Waste Management
Electricity 0.06 $/kwh, 526 kW-hr, Annual Operating Hours, 93% utilization 244,544
Water 0.28 $/mgal, 1,112 gpm, Annual Operating Hours, 93% utilization 143,251
WW Treat Neutralization 1.69 $/mgal, 1,112 gpm, Annual Operating Hours, 93% utilization 873,571
Caustic 305.96 $/ton, 89 lb/hr, 8339.1 hr/yr, 93% utilization 105,296Total Annual Direct Operating Costs 1,425,578
Indirect Operating Costs
Overhead 60% of total labor and material costs 98,528
Administration (2% total capital costs) 2% of total capital costs (TCI) 217,719
Property tax (1% total capital costs) 1% of total capital costs (TCI) 108,860
Insurance (1% total capital costs) 1% of total capital costs (TCI) 108,860
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,229,330
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,763,297
Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,188,875
See summary page for notes and assumptions
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BART Report - Appendix A Emission Control Cost Analysis
Table 7: SO2 Control - Wet Walled Electrostatic Precipitator
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit
Amount Required 0
Total Rep Parts Cost 0
Installation Labor 0
Total Installed Cost 0
Annualized Cost 0
Electrical Use
Flow acfm D P in H2O kW
Fan Power 222,400 10 402.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46
Fluid Head (ft) Pump Eff.
Pump Power 60 60% 20.9 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47
Plate Area
ESP Power 52,600 102.0 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48
Total 525.5
Reagent Use & Other Operating Costs
gpm
Water 5.00 gal/min-kacfm 1112.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6
lb/hr
Reagent Use 2.50 lb NaOH/lb SO2 88.75 lb/hr caustic
Operating Cost Calculations Annual hours of operation: 8,339
Utilization Rate: 93.0%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor , 0 , Annual Operating Hours, 0% utilization
Op Labor 50 $/Hr 2.0 hr/8 hr shift 2,085 104,239 $/Hr, 2 hr/8 hr shift, Annual Operating Hours, 0% utilization
Supervisor 15% of Op. NA 15,636 of Op., 0 , Annual Operating Hours, 0% utilization
Maintenance , 0 , Annual Operating Hours, 0% utilization
Maint Labor 60.00 $/Hr 15.0 hr/wk 660 4,340 $/Hr, 15 hr/wk, Annual Operating Hours, 0% utilization
Maint Mtls 1 % of Purchase Cost NA 39,998 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1
Utilities, Supplies, Replacements & Waste ManagementElectricity 0.060 $/kwh 525.5 kW-hr 4,075,729 244,544 $/kwh, 526 kW-hr, Annual Operating Hours, 93% utilization
Water 0.28 $/mgal 1,112.0 gpm 517,438 143,251 $/mgal, 1,112 gpm, Annual Operating Hours, 93% utilization
WW Treat Neutralization 1.69 $/mgal 1,112.0 gpm 517,438 873,571 $/mgal, 1,112 gpm, Annual Operating Hours, 93% utilization
Caustic 305.96 $/ton 88.8 lb/hr 344 105,296 $/ton, 89 lb/hr, 8339.1 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See summary page for notes and assumptions
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BART Report - Appendix A Emission Control Cost Analysis
Table 8: SO2 Control - Wet Walled Electrostatic Precipitator
Operating Unit: Furnace 11 Waste Gas
Emission Unit Number EU 104 Stack/Vent Number SV 104 & 105
Standardized Flow Rate 152,520 scfm @ 32º F
Expected Utilization Rate 93% Temperature 140 Deg F
Expected Annual Hours of Operation 8,339 Hours Moisture Content 18.3%
Annual Interest Rate 7.0% Actual Flow Rate 186,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 163,680 scfm @ 68º F
Dry Std Flow Rate 133,792 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 3,593,104
Purchased Equipment Total (B) 22% of control device cost (A) 4,365,622
Installation - Standard Costs 67% of purchased equip cost (B) 2,924,967
Installation - Site Specific Costs 6,200,000
Installation Total 2,924,967
Total Direct Capital Cost, DC 7,290,588
Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,488,404
Total Capital Investment (TCI) = DC + IC 21,846,389
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,249,949
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,549,263
Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,799,211
Actual
Emission Control Cost Calculation Emissions
Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 124.8 273.7 0% 273.7 - NA
Sulfur Dioxide (SO2) 11.8 9.6 80% 1.9 7.6 496,949
Notes & Assumptions
1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3.
2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm.
3 CUECost Workbook Version 1.0, USEPA Document Page 2.
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Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 8: SO2 Control - Wet Walled Electrostatic Precipitator
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A)1
Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 3,593,104
Instrumentation 10% of control device cost (A) 359,310
MN Sales Taxes 6.5% of control device cost (A) 233,552
Freight 5% of control device cost (A) 179,655
Purchased Equipment Total (B) 22% 4,365,622
Installation
Foundations & supports 4% of purchased equip cost (B) 174,625
Handling & erection 50% of purchased equip cost (B) 2,182,811
Electrical 8% of purchased equip cost (B) 349,250
Piping 1% of purchased equip cost (B) 43,656
Insulation 2% of purchased equip cost (B) 87,312
Painting 2% of purchased equip cost (B) 87,312
Installation Subtotal Standard Expenses 67% 2,924,967
Total Direct Capital Cost, DC 7,290,588
Indirect Capital Costs
Engineering, supervision 20% of purchased equip cost (B) 873,124
Construction & field expenses 20% of purchased equip cost (B) 873,124
Contractor fees 10% of purchased equip cost (B) 436,562
Start-up 1% of purchased equip cost (B) 43,656
Performance test 1% of purchased equip cost (B) 43,656Model Studies 2% of purchased equip cost (B) 87,312
Contingencies 3% of purchased equip cost (B) 130,969
Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,488,404
Total Capital Investment (TCI) = DC + IC 9,778,993
Retrofit multiplier3
60% of TCI 5,867,396
Sitework and foundations Site Specific 1,400,000
Structural steel Site Specific 4,800,000
Site Specific - Other Site Specific NA
Total Site Specific Costs 6,200,000
Total Capital Investment (TCI) Retrofit Installed 21,846,389
OPERATING COSTSDirect Annual Operating Costs, DC
Operating Labor
Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr 104,239
Supervisor 15% 15% of Operator Costs 15,636
Maintenance
Maintenance Labor 60.00 $/Hr, 15.0 hr/wk, 8339.1 hr/yr 4,125
Maintenance Materials 1.00 % of Maintenance Labor 35,931
Utilities, Supplies, Replacements & Waste Management
Electricity 0.06 $/kwh, 440 kW-hr, Annual Operating Hours, 93% utilization 204,519
Water 0.28 $/mgal, 930 gpm, Annual Operating Hours, 93% utilization 119,805
WW Treat Neutralization 1.69 $/mgal, 930 gpm, Annual Operating Hours, 93% utilization 730,595
Caustic 305.96 $/ton, 30 lb/hr, 8339.1 hr/yr, 93% utilization 35,099Total Annual Direct Operating Costs 1,249,949
Indirect Operating Costs
Overhead 60% of total labor and material costs 95,958Administration (2% total capital costs) 2% of total capital costs (TCI) 195,580
Property tax (1% total capital costs) 1% of total capital costs (TCI) 97,790
Insurance (1% total capital costs) 1% of total capital costs (TCI) 97,790
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,062,145
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,549,263
Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,799,211
See summary page for notes and assumptions
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BART Report - Appendix A Emission Control Cost Analysis
Table 8: SO2 Control - Wet Walled Electrostatic Precipitator
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit
Amount Required 0
Total Rep Parts Cost 0
Installation Labor 0
Total Installed Cost 0
Annualized Cost 0
Electrical Use
Flow acfm D P in H2O kW
Fan Power 186,000 10 336.7 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46
Fluid Head (ft) Pump Eff.
Pump Power 60 60% 17.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47
Plate Area
ESP Power 43,991 85.3 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48
Total 439.5
Reagent Use & Other Operating Costs
gpm
Water 5.00 gal/min-kacfm 930.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6
lb/hr
Reagent Use 2.50 lb NaOH/lb SO2 29.58 lb/hr caustic
Operating Cost Calculations Annual hours of operation: 8,339
Utilization Rate: 93.0%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 50 $/Hr 2.0 hr/8 hr shift 2,085 104,239 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr
Supervisor 15% of Op. NA 15,636 15% of Operator Costs
Maintenance
Maint Labor 60.00 $/Hr 15.0 hr/wk 660 4,125 $/Hr, 15.0 hr/wk, 8339.1 hr/yr
Maint Mtls 1 % of Purchase Cost NA 35,931 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1
Utilities, Supplies, Replacements & Waste ManagementElectricity 0.060 $/kwh 439.5 kW-hr 3,408,658 204,519 $/kwh, 440 kW-hr, Annual Operating Hours, 93% utilization
Water 0.28 $/mgal 930.0 gpm 432,749 119,805 $/mgal, 930 gpm, Annual Operating Hours, 93% utilization
WW Treat Neutralization 1.69 $/mgal 930.0 gpm 432,749 730,595 $/mgal, 930 gpm, Annual Operating Hours, 93% utilization
Caustic 305.96 $/ton 29.6 lb/hr 115 35,099 $/ton, 30 lb/hr, 8339.1 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See summary page for notes and assumptions
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BART Report - Appendix A Emission Control Cost Analysis
Table 9: SO2 Control - Wet Walled Electrostatic Precipitator
Operating Unit: Furnace 12 Hood Exhaust
Emission Unit Number EU 110 Stack/Vent Number SV 111, 112, & 113
Standardized Flow Rate 181,762 scfm @ 32º F
Expected Utilization Rate 93% Temperature 142 Deg F
Expected Annual Hours of Operation 8,339 Hours Moisture Content 9.5%
Annual Interest Rate 7.0% Actual Flow Rate 222,400 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 195,062 scfm @ 68º F
Dry Std Flow Rate 176,529 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 3,999,843
Purchased Equipment Total (B) 22% of control device cost (A) 4,859,809
Installation - Standard Costs 67% of purchased equip cost (B) 3,256,072
Installation - Site Specific Costs 6,200,000
Installation Total 3,256,072
Total Direct Capital Cost, DC 8,115,881
Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,770,091
Total Capital Investment (TCI) = DC + IC 23,617,556
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,530,874
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,763,297
Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,294,171
Actual
Emission Control Cost Calculation Emissions
Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 51.3 109.9 0% 109.9 - NA
Sulfur Dioxide (SO2) 35.5 26.3 80% 5.3 21.0 204,058
Notes & Assumptions
1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3.
2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm.
3 CUECost Workbook Version 1.0, USEPA Document Page 2.
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Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 9: SO2 Control - Wet Walled Electrostatic Precipitator
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A)1
Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 3,999,843
Instrumentation 10% of control device cost (A) 399,984
MN Sales Taxes 6.5% of control device cost (A) 259,990
Freight 5% of control device cost (A) 199,992
Purchased Equipment Total (B) 22% 4,859,809
Installation
Foundations & supports 4% of purchased equip cost (B) 194,392
Handling & erection 50% of purchased equip cost (B) 2,429,905
Electrical 8% of purchased equip cost (B) 388,785
Piping 1% of purchased equip cost (B) 48,598
Insulation 2% of purchased equip cost (B) 97,196
Painting 2% of purchased equip cost (B) 97,196
Installation Subtotal Standard Expenses 67% 3,256,072
Total Direct Capital Cost, DC 8,115,881
Indirect Capital Costs
Engineering, supervision 20% of purchased equip cost (B) 971,962
Construction & field expenses 20% of purchased equip cost (B) 971,962
Contractor fees 10% of purchased equip cost (B) 485,981
Start-up 1% of purchased equip cost (B) 48,598
Performance test 1% of purchased equip cost (B) 48,598Model Studies 2% of purchased equip cost (B) 97,196
Contingencies 3% of purchased equip cost (B) 145,794
Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,770,091
Total Capital Investment (TCI) = DC + IC 10,885,972
Retrofit multiplier3
60% of TCI 6,531,583
Sitework and foundations Site Specific 1,400,000
Structural steel Site Specific 4,800,000
Site Specific - Other Site Specific NA
Total Site Specific Costs 6,200,000
Total Capital Investment (TCI) Retrofit Installed 23,617,556
OPERATING COSTSDirect Annual Operating Costs, DC
Operating Labor
Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr 104,239
Supervisor 15% 15% of Operator Costs 15,636
Maintenance
Maintenance Labor 60.00 $/Hr, 15.0 hr/wk, 8339.1 hr/yr 4,340
Maintenance Materials 1.00 % of Maintenance Labor 39,998
Utilities, Supplies, Replacements & Waste Management
Electricity 0.06 $/kwh, 526 kW-hr, Annual Operating Hours, 93% utilization 244,544
Water 0.28 $/mgal, 1,112 gpm, Annual Operating Hours, 93% utilization 143,251
WW Treat Neutralization 1.69 $/mgal, 1,112 gpm, Annual Operating Hours, 93% utilization 873,571
Caustic 305.96 $/ton, 89 lb/hr, 8339.1 hr/yr, 93% utilization 105,296Total Annual Direct Operating Costs 1,530,874
Indirect Operating Costs
Overhead 60% of total labor and material costs 98,528
Administration (2% total capital costs) 2% of total capital costs (TCI) 217,719
Property tax (1% total capital costs) 1% of total capital costs (TCI) 108,860
Insurance (1% total capital costs) 1% of total capital costs (TCI) 108,860
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,229,330
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,763,297
Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,294,171
See summary page for notes and assumptions
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BART Report - Appendix A Emission Control Cost Analysis
Table 9: SO2 Control - Wet Walled Electrostatic Precipitator
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit
Amount Required 0
Total Rep Parts Cost 0
Installation Labor 0
Total Installed Cost 0
Annualized Cost 0
Electrical Use
Flow acfm D P in H2O kW
Fan Power 222,400 10 402.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46
Fluid Head (ft) Pump Eff.
Pump Power 60 60% 20.9 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47
Plate Area
ESP Power 52,600 102.0 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48
Total 525.5
Reagent Use & Other Operating Costs
gpm
Water 5.00 gal/min-kacfm 1112.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6
lb/hr
Reagent Use 2.50 lb NaOH/lb SO2 88.75 lb/hr caustic
Operating Cost Calculations Annual hours of operation: 8,339
Utilization Rate: 93.0%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 50 $/Hr 2.0 hr/8 hr shift 2,085 104,239 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr
Supervisor 15% of Op. NA 15,636 15% of Operator Costs
Maintenance
Maint Labor 60.00 $/Hr 15.0 hr/wk 660 4,340 $/Hr, 15.0 hr/wk, 8339.1 hr/yr
Maint Mtls 1 % of Purchase Cost NA 39,998 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1
Utilities, Supplies, Replacements & Waste ManagementElectricity 0.060 $/kwh 525.5 kW-hr 4,075,729 244,544 $/kwh, 526 kW-hr, Annual Operating Hours, 93% utilization
Water 0.28 $/mgal 1,112.0 gpm 517,438 143,251 $/mgal, 1,112 gpm, Annual Operating Hours, 93% utilization
WW Treat Neutralization 1.69 $/mgal 1,112.0 gpm 517,438 873,571 $/mgal, 1,112 gpm, Annual Operating Hours, 93% utilization
Caustic 305.96 $/ton 88.8 lb/hr 344 105,296 $/ton, 89 lb/hr, 8339.1 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See summary page for notes and assumptions
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BART Report - Appendix A Emission Control Cost Analysis
Table 10: SO2 Control - Wet Walled Electrostatic Precipitator
Operating Unit: Furnace 12 Waste Gas
Emission Unit Number EU 114 Stack/Vent Number SV 114 & 115
Standardized Flow Rate 152,520 scfm @ 32º F
Expected Utilization Rate 93% Temperature 140 Deg F
Expected Annual Hours of Operation 8,339 Hours Moisture Content 16.4%
Annual Interest Rate 7.0% Actual Flow Rate 186,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 163,680 scfm @ 68º F
Dry Std Flow Rate 136,902 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 3,593,104
Purchased Equipment Total (B) 22% of control device cost (A) 4,365,622
Installation - Standard Costs 67% of purchased equip cost (B) 2,924,967
Installation - Site Specific Costs 6,200,000
Installation Total 2,924,967
Total Direct Capital Cost, DC 7,290,588
Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,488,404
Total Capital Investment (TCI) = DC + IC 21,846,389
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,214,850
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,549,263
Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,764,113
Actual
Emission Control Cost Calculation Emissions
Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 124.8 267.7 0% 267.7 - NA
Sulfur Dioxide (SO2) 11.8 8.8 80% 1.8 7.0 535,575
Notes & Assumptions
1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3.
2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm.
3 CUECost Workbook Version 1.0, USEPA Document Page 2.
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BART Report - Appendix A Emission Control Cost Analysis
Table 10: SO2 Control - Wet Walled Electrostatic Precipitator
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A)1
Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 3,593,104
Instrumentation 10% of control device cost (A) 359,310
MN Sales Taxes 6.5% of control device cost (A) 233,552
Freight 5% of control device cost (A) 179,655
Purchased Equipment Total (B) 22% 4,365,622
Installation
Foundations & supports 4% of purchased equip cost (B) 174,625
Handling & erection 50% of purchased equip cost (B) 2,182,811
Electrical 8% of purchased equip cost (B) 349,250
Piping 1% of purchased equip cost (B) 43,656
Insulation 2% of purchased equip cost (B) 87,312
Painting 2% of purchased equip cost (B) 87,312
Installation Subtotal Standard Expenses 67% 2,924,967
Total Direct Capital Cost, DC 7,290,588
Indirect Capital Costs
Engineering, supervision 20% of purchased equip cost (B) 873,124
Construction & field expenses 20% of purchased equip cost (B) 873,124
Contractor fees 10% of purchased equip cost (B) 436,562
Start-up 1% of purchased equip cost (B) 43,656
Performance test 1% of purchased equip cost (B) 43,656Model Studies 2% of purchased equip cost (B) 87,312
Contingencies 3% of purchased equip cost (B) 130,969
Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,488,404
Total Capital Investment (TCI) = DC + IC 9,778,993
Retrofit multiplier3
60% of TCI 5,867,396
Sitework and foundations Site Specific 1,400,000
Structural steel Site Specific 4,800,000
Site Specific - Other Site Specific NA
Total Site Specific Costs 6,200,000
Total Capital Investment (TCI) Retrofit Installed 21,846,389
OPERATING COSTSDirect Annual Operating Costs, DC
Operating Labor
Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr 104,239
Supervisor 15% 15% of Operator Costs 15,636
Maintenance
Maintenance Labor 60.00 $/Hr, 15.0 hr/wk, 8339.1 hr/yr 4,125
Maintenance Materials 1.00 % of Maintenance Labor 35,931
Utilities, Supplies, Replacements & Waste Management
Electricity 0.06 $/kwh, 440 kW-hr, Annual Operating Hours, 93% utilization 204,519
Water 0.28 $/mgal, 930 gpm, Annual Operating Hours, 93% utilization 119,805
WW Treat Neutralization 1.69 $/mgal, 930 gpm, Annual Operating Hours, 93% utilization 730,595
Total Annual Direct Operating Costs 1,214,850
Indirect Operating Costs
Overhead 60% of total labor and material costs 95,958
Administration (2% total capital costs) 2% of total capital costs (TCI) 195,580
Property tax (1% total capital costs) 1% of total capital costs (TCI) 97,790
Insurance (1% total capital costs) 1% of total capital costs (TCI) 97,790
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,062,145
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,549,263
Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,764,113
See summary page for notes and assumptions
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BART Report - Appendix A Emission Control Cost Analysis
Table 10: SO2 Control - Wet Walled Electrostatic Precipitator
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit
Amount Required 0
Total Rep Parts Cost 0
Installation Labor 0
Total Installed Cost 0
Annualized Cost 0
Electrical Use
Flow acfm D P in H2O kW
Fan Power 186,000 10 336.7 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46
Fluid Head (ft) Pump Eff.
Pump Power 60 60% 17.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47
Plate Area
ESP Power 43,991 85.3 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48
Total 439.5
Reagent Use & Other Operating Costs
gpm
Water 5.00 gal/min-kacfm 930.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6
lb/hr
Reagent Use 2.50 lb NaOH/lb SO2 29.58 lb/hr caustic
Operating Cost Calculations Annual hours of operation: 8,339
Utilization Rate: 93.0%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 50 $/Hr 2.0 hr/8 hr shift 2,085 104,239 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr
Supervisor 15% of Op. NA 15,636 15% of Operator Costs
Maintenance
Maint Labor 60.00 $/Hr 15.0 hr/wk 660 4,125 $/Hr, 15.0 hr/wk, 8339.1 hr/yr
Maint Mtls 1 % of Purchase Cost NA 35,931 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1
Utilities, Supplies, Replacements & Waste Management
Electricity 0.060 $/kwh 439.5 kW-hr 3,408,658 204,519 $/kwh, 440 kW-hr, Annual Operating Hours, 93% utilization
Water 0.28 $/mgal 930.0 gpm 432,749 119,805 $/mgal, 930 gpm, Annual Operating Hours, 93% utilization
WW Treat Neutralization 1.69 $/mgal 930.0 gpm 432,749 730,595 $/mgal, 930 gpm, Annual Operating Hours, 93% utilization
Caustic 305.96 $/ton 29.6 lb/hr 115 35,099 $/ton, 30 lb/hr, 8339.1 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See summary page for notes and assumptions
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EU114 WWESP 9/6/2006 Page 27 of 56
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 11: - SCR + Reheat (100)
Operating Unit: Furnace 11 Hood Exhaust
Emission Unit Number EU 100 Stack/Vent Number SV 101, 102, & 103 Chemical Engineering
Desgin Capacity 150 MMBtu/hr Standardized Flow Rate 181,762 scfm @ 32º F Chemical Plant Cost Index
Expected Utiliztion Rate 93% Temperature 142 Deg F 1998/1999 390
Expected Annual Hours of Operation 8,339 Hours Moisture Content 11.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 222,400 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 195,062 scfm @ 68º F
Dry Std Flow Rate 172,951 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs EPRI Correlation
Purchased Equipment (A) 10,191,798
Purchased Equipment Total (B) SCR Only 10,854,265
Installation - Standard Costs 15% of purchased equip cost (B) SCR Only 2,024,725
Installation - Site Specific Costs 0
Installation Total 0
Total Direct Capital Cost, DC 0
Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0
Total Capital Investment (TCI) = DC + IC SCR + Reheat 46,019,283
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 7,301,482
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 4,326,542
Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 11,628,024
Emission Control Cost Calculation
Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost
Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 112.4 1.5 0.01 5.7 106.7 108,969
Notes & Assumptions
1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2.
2 For Calculation purposes, duty reflects increased flow rate, not actual duty.
3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2
4 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43
5 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35
6 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24
7 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31
8 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53
9 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48
10 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46
11 Control Efficiency = 90% reduction which is typically the upper range of normal SCR control efficiency
12 $35/MW-hr, 140 MW
13 Catalyst replacement every 8000 hours. This requires an additional 2 week outage per 3 year outage cycle, annualized to 4.7 days.
Notes to User
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
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Table 11: - SCR + Reheat (100)
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1)
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 10,191,798
Instrumentation 10% of control device cost (A) NA
MN Sales Taxes 6.5% of control device cost (A) 662,467
Freight 5% of control device cost (A) NA
Purchased Equipment Total (A) 10,854,265
Indirect Installation
General Facilities 0% of purchased equip cost (A) 0
Engineering & Home Office 0% of purchased equip cost (A) 0
Process Contingency 0% of purchased equip cost (A) 0
Site Specific-Other 24% Replacement Power, two weeks 2,643,899
Total Indirect Installation Costs (B) 24% of purchased equip cost (A) 2,643,899
Project Contingeny ( C) 15% of (A + B) 2,024,725
Total Plant Cost D A + B + C 15,522,888
Allowance for Funds During Construction (E) Additional 10 week outage for installation 8,232,000
Pre Production Costs (G) 2% of (D+E)) 475,098
Inventory Capital Reagent Vol * $/gal 2,331
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 24,232,317
Retrofit multiplier3
60% of TCI 14,539,390
Total Retorfit Capital Investment 38,771,707
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr 104,239
Supervisor 15% 15% of Operator Costs 15,636
Maintenance
Maintenance Total 1.50 % of Total Capital Investment 363,485
Maintenance Materials NA % of Maintenance Labor -
Utilities, Supplies, Replacements & Waste Management
Electricity 0.06 $/kwh, 1,444 kW-hr, 8339.1 hr/yr, 93% utilization 672,157
NA NA -
NA NA -
NA NA -
NA NA -
NA NA -
NA NA -
NA NA -
NA NA -
NA NA -
Cat. Replacement [14] 35.00 Catalyst Replacement 423,178
NA NA -
Ammonia 0.12 $/lb, 69 lb/hr, 8339.1 hr/yr, 93% utilization 64,238
NA NA -
NA NA -
NA NA -
Total Annual Direct Operating Costs 1,642,933
Indirect Operating Costs
Overhead 60% of total labor and material costs 40,360
Administration (2% total capital costs) 2% of total capital costs (TCI) 484,646
Property tax (1% total capital costs) 1% of total capital costs (TCI) 242,323
Insurance (1% total capital costs) 1% of total capital costs (TCI) 242,323
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,287,359
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,297,011
Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,939,944
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
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Table 11: - SCR + Reheat (100)
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Equivalent Duty 1,052 Plant Cap kW A 107,954
Est power platn eff 35% Unc Nox lb/mmBtu B 0.05 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35
Watt per Btu/hr 0.29307 Nox Red. Eff. C 80% E=D*A*0.0066
Equivalent power plant kW 107,954 Capital Cost $/kW D $94.41 $10,191,798.18 Total SCR Equipment
Uncontrolled Nox t/y 112.4 Fixed O&M E $67,265.87
Annual Operating Hrs 8000 Variable O&M F $205,606.98
Uncontrolled Nox lb/mmBtu 0.049 Ann Cap Factor G 0.82
Heat Input mmBtu/hrH 6,000
SCR Capital Cost
Duty 1,052 MMBtu/hr Catalyst Area 508 ft2
614 f (h SCR)
Q flue gas 487,426 acfm Rx Area 584 83 f (h NH3)
NOx Cont Eff 80% (as faction) Rx Height 24.2 ft 0 f (h New) new= -728, Retrofit = 0
NOx in 0.05 lb/MMBtu n layer 22 layers Y Bypass? Y or N
Ammonia Slip 2 ppm h layer 23.5 ft 127 f (h Bypass)
Fuel Sulfur 0.67 wt % (as %) n total 23 layers 8,220,568 f (vol catalyst)
Temperature 142 Deg F h SCR 131 ft f (h SCR)
Catalyst Volume 34,252 ft3
New/Retrofit R N or R
Electrical Use
Duty 1,052 MMBtu/hr kW
NOx Cont Eff 80% (as faction) Power 1,444.5
NOx in 0.05 lb/MMBtu
n catalyst layers 23 layers
Press drop catalyst 1 in H2O per layer
Press drop duct 3 in H2O
Total 1444.5
Reagent Use & Other Operating Costs
Ammonia Use 56.0 lb/ft3 Density
20 lb/hr Neat 9.2 gal/hr
29% solution Volume 14 day inventory 3,083 gal $2,331 Inventory Cost
69 lb/hr
Design Basis Baseline Emis.Baseline Emis.Max Emis. (Model) Control Eff (%) Cont. Emis (lb/MMBtu)
T/yr lb/MMBtu lb/hr 80% 0.01
Nitrous Oxides (NOx) 112.4 0.05 51.25
Actual 69,180 dscf/MMBtu
Method 19 Factor 9,860 dscf/MMBtu
Adjusted Duty 1,052 MMBtu/hr
Operating Cost Calculations Annual hours of operation: 8,339
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 50.00 $/Hr 2.0 hr/8 hr shift 2,085 104,239 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr
Supervisor 15% of Op. NA 15,636 15% of Operator Costs
Maintenance
Maintenance Total 1.5 % of Total Capital Investment 363,485 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.060 $/kwh 1444.5 kW-hr 11,202,612 672,157 $/kwh, 1,444 kW-hr, 8339.1 hr/yr, 93% utilization
Cat. Replacement [14] 35 $/MW-hr 108.0 mw 112 423,178 Catalyst Replacement
7 Ammonia 0.12 $/lb 69 lb/hr 532,660 64,238 $/lb, 69 lb/hr, 8339.1 hr/yr, 93% utilization
** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
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BART Report - Appendix A Emission Control Cost Analysis
Table 12: Reheat (100)
Operating Unit: Furnace 11 Hood Exhaust
Emission Unit Number EU 100 Stack/Vent Number SV 101, 102, & 103 Chemical Engineering
Desgin Capacity 150 MMBtu/hr Standardized Flow Rate 181,762 scfm @ 32º F Chemical Plant Cost Index
Expected Utiliztion Rate 93% Temperature 142 Deg F 1998/1999 390
Expected Annual Hours of Operation 8,339 Hours Moisture Content 11.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 222,400 acfm Inflation Adj 1.19Expected Equipment Life 20 yrs Standardized Flow Rate 195,062 scfm @ 68º F
Dry Std Flow Rate 172,951 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 535,530
Purchased Equipment Total (B) 22% of control device cost (A) 650,668
Installation - Standard Costs 30% of purchased equip cost (B) 195,201
Installation - Site Specific Costs 6,200,000
Installation Total 6,395,201
Total Direct Capital Cost, DC 7,045,869
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 201,707
Total Capital Investment (TCI) = DC + IC 7,247,576
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 5,658,549
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,029,530Total Annual Cost (Annualized Capital Cost + Operating Cost) 6,688,079
Notes & Assumptions
1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
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BART Report - Appendix A Emission Control Cost Analysis
Table 12: Reheat (100)
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 535,530
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC
Instrumentation 10% of control device cost (A) 53,553
MN Sales Taxes 6.5% of control device cost (A) 34,809
Freight 5% of control device cost (A) 26,776Purchased Equipment Total (B) 22% 650,668
Installation
Foundations & supports 8% of purchased equip cost (B) 52,053
Handling & erection 14% of purchased equip cost (B) 91,094
Electrical 4% of purchased equip cost (B) 26,027
Piping 2% of purchased equip cost (B) 13,013
Insulation 1% of purchased equip cost (B) 6,507
Painting 1% of purchased equip cost (B) 6,507
Installation Subtotal Standard Expenses 30% 195,201
Sitework and foundations Site Specific 1,400,000
Structural steel Site Specific 4,800,000
Site Specific - Other Site Specific 0
Total Site Specific Costs 6,200,000Installation Total 6,395,201
Total Direct Capital Cost, DC 7,045,869
Indirect Capital Costs
Engineering, supervision 10% of purchased equip cost (B) 65,067Construction & field expenses 5% of purchased equip cost (B) 32,533Contractor fees 10% of purchased equip cost (B) 65,067
Start-up 2% of purchased equip cost (B) 13,013Performance test 1% of purchased equip cost (B) 6,507Model Studies of purchased equip cost (B) 0Contingencies 3% of purchased equip cost (B) 19,520
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 201,707
Total Capital Investment (TCI) = DC + IC 7,247,576
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 7,247,576
OPERATING COSTSDirect Annual Operating Costs, DC
Operating Labor
Operator 50.00 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr 26,060
Supervisor 15% 15% of Operator Costs 3,909
Maintenance
Maintenance Labor 60.00 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr 31,272
Maintenance Materials 100% of maintenance labor costs 31,272Utilities, Supplies, Replacements & Waste Management
Electricity 0.06 $/kwh, 824 kW-hr, 8339.1 hr/yr, 93% utilization 383,421
Natural Gas 10.02 $/mscf, 1,112 scfm, 8339.1 hr/yr, 93% utilization 5,182,616
Total Annual Direct Operating Costs 5,658,549
Indirect Operating Costs
Overhead 60% of total labor and material costs 55,507
Administration (2% total capital costs) 2% of total capital costs (TCI) 144,952
Property tax (1% total capital costs) 1% of total capital costs (TCI) 72,476
Insurance (1% total capital costs) 1% of total capital costs (TCI) 72,476
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 684,120 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,029,530
Total Annual Cost (Annualized Capital Cost + Operating Cost) 6,688,079
See Summary page for notes and assumptions
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Table 12: Reheat (100)
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalyst: Catalyst
Equipment Life 2 years
CRF 0.5531
Rep part cost per unit 0 $/ft3
Amount Required 39 ft3
Catalyst Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit 0 $ each
Amount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales taxInstallation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kWBlower, Thermal 222,400 19 0.6 824.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Blower, Catalytic 222,400 23 0.6 997.5 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Oxidizer Type thermal (catalytic or thermal) 824.0
Reagent Use & Other Operating Costs Oxidizers - NA
Operating Cost Calculations Annual hours of operation: 8,339
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 521 26,060 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr
Supervisor 15% of Op. NA 3,909 15% of Operator Costs
Maintenance
Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 521 31,272 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 31,272 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.060 $/kwh 824.0 kW-hr 6,390,357 383,421 $/kwh, 824 kW-hr, 8339.1 hr/yr, 93% utilization
Natural Gas 10.02 $/mscf 1,112 scfm 517,206 5,182,616 $/mscf, 1,112 scfm, 8339.1 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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BART Report - Appendix A Emission Control Cost Analysis
Table 12: Reheat (100)
Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery
Auxiliary Fuel Use Equation 3.19
Twi 142 Deg F - Temperature of waste gas into heat recovery
Tfi 750 Deg F - Temperature of Flue gas into of heat recovery
Tref 77 Deg F - Reference temperature for fuel combustion calculations
FER 70% Factional Heat Recovery % Heat recovery section efficiency
Two 568 Deg F - Temperature of waste gas out of heat recovery
Tfo 324 Deg F - Temperature of flue gas into of heat recovery
-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)
-hwg 0 Btu/lb Heat of combustion waste gas
Cp wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air)
p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F
p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Qwg 195,062 scfm - Flow of waste gas
Qaf 1,112 scfm - Flow of auxiliary fuel
Year 2005 Inflation Rate 3.0%Cost Calculations 196,173 scfm Flue Gas Cost in 1989 $'s $449,154
Current Cost Using CHE Plant Cost Index $535,530
Heat Rec % A B
0 10,294 0.2355 Exponents per equation 3.24
0.3 13,149 0.2609 Exponents per equation 3.25
0.5 17,056 0.2502 Exponents per equation 3.260.7 21,342 0.2500 Exponents per equation 3.27
Indurator Flue Gas Heat Capacity - Basis Typical Composition
100 scfm 359 scf/lbmole
Gas Composition lb/hr f wt % Cp Gas Cp Flue28 mw CO 0 v % 0
44 mw CO2 15 v % 184 22.0% 0.24 0.052818 mw H2O 10 v % 50 6.0% 0.46 0.0276
28 mw N2 60 v % 468 56.0% 0.27 0.1512
32 mw O2 15 v % 134 16.0% 0.23 0.0368
Cp Flue Gas 100 v % 836 100.0% 0.2684
Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators
(EPA 453/B-96-001)
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Table 13: - SCR + Reheat (104)
Operating Unit: Furnace 11 Waste Gas
Emission Unit Number EU 104 Stack/Vent Number SV 104 & 105 Chemical Engineering
Desgin Capacity 150 MMBtu/hr Standardized Flow Rate 152,520 scfm @ 32º F Chemical Plant Cost Index
Expected Utiliztion Rate 93% Temperature 140 Deg F 1998/1999 390
Expected Annual Hours of Operation 8,339 Hours Moisture Content 18.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 186,000 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 163,680 scfm @ 68º F
Dry Std Flow Rate 133,792 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs Year
Direct Capital Costs EPRI Correlation 1998
Purchased Equipment (A) 2005 0
Purchased Equipment Total (B) 0% of control device cost (A) SCR Only 9,372,318
Installation - Standard Costs 15% of purchased equip cost (B) SCR Only 1,802,433
Installation - Site Specific Costs 0
Installation Total 0
Total Direct Capital Cost, DC 0
Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0
Total Capital Investment (TCI) = DC + IC SCR + Reheat 43,197,692
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 4,157,530
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 4,081,731
Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 8,239,261
Emission Control Cost Calculation
Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost
Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 273.7 4.6 0.03 17.8 255.9 32,199
Notes & Assumptions
1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2.
2 For Calculation purposes, duty reflects increased flow rate, not actual duty.
3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2
4 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43
5 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35
6 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24
7 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31
8 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53
9 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48
10 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46
11 Control Efficiency = 90% reduction which is typically the upper range of normal SCR control efficiency
12 $35/MW-hr, 140 MW
13 Catalyst replacement every 8000 hours. This requires an additional 2 week outage per 3 year outage cycle, annualized to 4.7 days.
Notes to User
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
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Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 13: - SCR + Reheat (104)
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1)
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 8,800,299
Instrumentation 10% of control device cost (A) NA
MN Sales Taxes 6.5% of control device cost (A) 572,019
Freight 5% of control device cost (A) NA
Purchased Equipment Total (A) 9,372,318
Indirect Installation
General Facilities 0% of purchased equip cost (A) 0
Engineering & Home Office 0% of purchased equip cost (A) 0
Process Contingency 0% of purchased equip cost (A) 0
Site Specific-Other 28% Replacement Power, two weeks 2,643,899
Total Indirect Installation Costs (B) 28% of purchased equip cost (A) 2,643,899
Project Contingeny ( C) 15% of (A + B) 1,802,433
Total Plant Cost D A + B + C 13,818,649
Allowance for Funds During Construction (E) Additional 10 week outage for installation 8,232,000
Pre Production Costs (G) 2% of (D+E)) 441,013
Inventory Capital Reagent Vol * $/gal 5,677
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 22,497,340
Retrofit multiplier3
60% of TCI 13,498,404
Total Retorfit Capital Investment 35,995,743
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr 104,239
Supervisor 15% 15% of Operator Costs 15,636
Maintenance
Maintenance Total 1.50 % of Total Capital Investment 337,460
Maintenance Materials NA % of Maintenance Labor -
Utilities, Supplies, Replacements & Waste Management
Electricity 0.06 $/kwh, 1,167 kW-hr, 8339.1 hr/yr, 93% utilization 543,246
NA NA -
NA NA -
NA NA -
NA NA -
NA NA -
NA NA -
NA NA -
NA NA -
NA NA -
Cat. Replacement [14] 35.00 Catalyst Replacement 327,363
NA NA -
Ammonia 0.12 $/lb, 167 lb/hr, 8339.1 hr/yr, 93% utilization 156,470
NA NA -
NA NA -
NA NA -
Total Annual Direct Operating Costs 1,484,414
Indirect Operating Costs
Overhead 60% of total labor and material costs 34,849
Administration (2% total capital costs) 2% of total capital costs (TCI) 449,947
Property tax (1% total capital costs) 1% of total capital costs (TCI) 224,973
Insurance (1% total capital costs) 1% of total capital costs (TCI) 224,973
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,123,590
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,058,332
Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,542,746
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
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Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 13: - SCR + Reheat (104)
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Equivalent Duty 814 Plant Cap kW A 83,511
Est power platn eff 35% Unc Nox lb/mmBtu B 0.15 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35
Watt per Btu/hr 0.29307 Nox Red. Eff. C 80% E=D*A*0.0066
Equivalent power plant kW 83,511 Capital Cost $/kW D $105.38 $8,800,298.76 Total SCR Equipment
Uncontrolled Nox t/y 273.7 Fixed O&M E $58,081.97
Annual Operating Hrs 8000 Variable O&M F $171,504.18
Uncontrolled Nox lb/mmBtu 0.153 Ann Cap Factor G 0.82
Heat Input mmBtu/hrH 6,000
SCR Capital Cost
Duty 814 MMBtu/hr Catalyst Area 393 ft2
638 f (h SCR)
Q flue gas 377,064 acfm Rx Area 452 121 f (h NH3)
NOx Cont Eff 80% (as faction) Rx Height 21.3 ft 0 f (h New) new= -728, Retrofit = 0
NOx in 0.15 lb/MMBtu n layer 23 layers Y Bypass? Y or N
Ammonia Slip 2 ppm h layer 24.5 ft 127 f (h Bypass)
Fuel Sulfur 0.67 wt % (as %) n total 24 layers 6,646,500 f (vol catalyst)
Temperature 140 Deg F h SCR 135 ft f (h SCR)
Catalyst Volume 27,694 ft3
New/Retrofit R N or R
Electrical Use
Duty 814 MMBtu/hr kW
NOx Cont Eff 80% (as faction) Power 1,167.5
NOx in 0.15 lb/MMBtu
n catalyst layers 24 layers
Press drop catalyst 1 in H2O per layer
Press drop duct 3 in H2O
Total 1167.5
Reagent Use & Other Operating Costs
Ammonia Use 56.0 lb/ft3 Density
49 lb/hr Neat 22.3 gal/hr
29% solution Volume 14 day inventory 7,509 gal $5,677 Inventory Cost
167 lb/hr
Design Basis Baseline Emis.Baseline Emis.Max Emis. (Model) Control Eff (%) Cont. Emis (lb/MMBtu)
T/yr lb/MMBtu lb/hr 80% 0.03
Nitrous Oxides (NOx) 273.7 0.15 124.83
Actual 53,517 dscf/MMBtu
Method 19 Factor 9,860 dscf/MMBtu
Adjusted Duty 814 MMBtu/hr
Operating Cost Calculations Annual hours of operation: 8,339
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 50.00 $/Hr 2.0 hr/8 hr shift 2,085 104,239 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr
Supervisor 15% of Op. NA 15,636 15% of Operator Costs
Maintenance
Maintenance Total 1.5 % of Total Capital Investment 337,460 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.060 $/kwh 1167.5 kW-hr 9,054,097 543,246 $/kwh, 1,167 kW-hr, 8339.1 hr/yr, 93% utilization
Cat. Replacement [14] 35 $/MW-hr 83.5 mw 112 327,363 Catalyst Replacement
7 Ammonia 0.12 $/lb 167 lb/hr 1,297,437 156,470 $/lb, 167 lb/hr, 8339.1 hr/yr, 93% utilization
** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
NOx SCR+ Reheat 90% Eff (104) NOx SCR+ Reheat 90% Eff (104) 37 of 56
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 14: - Reheat (104)
Operating Unit: Furnace 11 Waste Gas
Emission Unit Number EU 104 Stack/Vent Number SV 104 & 105 Chemical Engineering
Desgin Capacity 150 MMBtu/hr Standardized Flow Rate 152,520 scfm @ 32º F Chemical Plant Cost Index
Expected Utiliztion Rate 93% Temperature 140 Deg F 1998/1999 390
Expected Annual Hours of Operation 8,339 Hours Moisture Content 18.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 186,000 acfm Inflation Adj 1.19Expected Equipment Life 20 yrs Standardized Flow Rate 163,680 scfm @ 68º F
Dry Std Flow Rate 133,792 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 512,205
Purchased Equipment Total (B) 22% of control device cost (A) 622,328
Installation - Standard Costs 30% of purchased equip cost (B) 186,699
Installation - Site Specific Costs 6,200,000
Installation Total 6,386,699
Total Direct Capital Cost, DC 7,009,027
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 192,922
Total Capital Investment (TCI) = DC + IC 7,201,949
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 2,673,116
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,023,398Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,696,515
Notes & Assumptions
1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
Reheat (104) Reheat (104) 38 of 56
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 14: - Reheat (104)
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 512,205
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC
Instrumentation 10% of control device cost (A) 51,220
MN Sales Taxes 6.5% of control device cost (A) 33,293
Freight 5% of control device cost (A) 25,610Purchased Equipment Total (B) 22% 622,328
Installation
Foundations & supports 8% of purchased equip cost (B) 49,786
Handling & erection 14% of purchased equip cost (B) 87,126
Electrical 4% of purchased equip cost (B) 24,893
Piping 2% of purchased equip cost (B) 12,447
Insulation 1% of purchased equip cost (B) 6,223
Painting 1% of purchased equip cost (B) 6,223
Installation Subtotal Standard Expenses 30% 186,699
Sitework and foundations Site Specific 1,400,000
Structural steel Site Specific 4,800,000
Site Specific - Other Site Specific 0
Total Site Specific Costs 6,200,000Installation Total 6,386,699
Total Direct Capital Cost, DC 7,009,027
Indirect Capital Costs
Engineering, supervision 10% of purchased equip cost (B) 62,233Construction & field expenses 5% of purchased equip cost (B) 31,116Contractor fees 10% of purchased equip cost (B) 62,233
Start-up 2% of purchased equip cost (B) 12,447Performance test 1% of purchased equip cost (B) 6,223Model Studies of purchased equip cost (B) 0Contingencies 3% of purchased equip cost (B) 18,670
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 192,922
Total Capital Investment (TCI) = DC + IC 7,201,949
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 7,201,949
OPERATING COSTSDirect Annual Operating Costs, DC
Operating Labor
Operator 50.00 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr 26,060
Supervisor 15% 15% of Operator Costs 3,909
Maintenance
Maintenance Labor 60.00 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr 31,272
Maintenance Materials 100% of maintenance labor costs 31,272Utilities, Supplies, Replacements & Waste Management
Electricity 0.06 $/kwh, 689 kW-hr, 8339.1 hr/yr, 93% utilization 320,667
Natural Gas 10.02 $/mscf, 485 scfm, 8339.1 hr/yr, 93% utilization 2,259,937
Total Annual Direct Operating Costs 2,673,116
Indirect Operating Costs
Overhead 60% of total labor and material costs 55,507
Administration (2% total capital costs) 2% of total capital costs (TCI) 144,039
Property tax (1% total capital costs) 1% of total capital costs (TCI) 72,019
Insurance (1% total capital costs) 1% of total capital costs (TCI) 72,019
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 679,813 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,023,398
Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,696,515
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
Reheat (104) Reheat (104) 39 of 56
Cleveland Cliffs Incorporated: United Taconite
BART Report - <Insert attachment name> Emission Control Cost Analysis
Table 14: - Reheat (104)
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalyst: Catalyst
Equipment Life 2 years
CRF 0.5531
Rep part cost per unit 0 $/ft3
Amount Required 39 ft3
Catalyst Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit 0 $ each
Amount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales taxInstallation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kWBlower, Thermal 186,000 19 0.6 689.1 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Blower, Catalytic 186,000 23 0.6 834.2 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Oxidizer Type thermal (catalytic or thermal) 689.1
Reagent Use & Other Operating Costs Oxidizers - NA
Operating Cost Calculations Annual hours of operation: 8,339
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 521 26,060 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr
Supervisor 15% of Op. NA 3,909 15% of Operator Costs
Maintenance
Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 521 31,272 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 31,272 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.060 $/kwh 689.1 kW-hr 5,344,453 320,667 $/kwh, 689 kW-hr, 8339.1 hr/yr, 93% utilization
Natural Gas 10.02 $/mscf 485 scfm 225,534 2,259,937 $/mscf, 485 scfm, 8339.1 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
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Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 14: - Reheat (104)
Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery
Auxiliary Fuel Use Equation 3.19
Twi 140 Deg F - Temperature of waste gas into heat recovery
Tfi 450 Deg F - Temperature of Flue gas into of heat recovery
Tref 77 Deg F - Reference temperature for fuel combustion calculations
FER 70% Factional Heat Recovery % Heat recovery section efficiency
Two 357 Deg F - Temperature of waste gas out of heat recovery
Tfo 233 Deg F - Temperature of flue gas into of heat recovery
-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)
-hwg 0 Btu/lb Heat of combustion waste gas
Cp wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air)
p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F
p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Qwg 163,680 scfm - Flow of waste gas
Qaf 485 scfm - Flow of auxiliary fuel
Year 2005 Inflation Rate 3.0%Cost Calculations 164,165 scfm Flue Gas Cost in 1989 $'s $429,591
Current Cost Using CHE Plant Cost Index $512,205
Heat Rec % A B
0 10,294 0.2355 Exponents per equation 3.24
0.3 13,149 0.2609 Exponents per equation 3.25
0.5 17,056 0.2502 Exponents per equation 3.260.7 21,342 0.2500 Exponents per equation 3.27
Indurator Flue Gas Heat Capacity - Basis Typical Composition
100 scfm 359 scf/lbmole
Gas Composition lb/hr f wt % Cp Gas Cp Flue28 mw CO 0 v % 0
44 mw CO2 15 v % 184 22.0% 0.24 0.052818 mw H2O 10 v % 50 6.0% 0.46 0.0276
28 mw N2 60 v % 468 56.0% 0.27 0.1512
32 mw O2 15 v % 134 16.0% 0.23 0.0368
Cp Flue Gas 100 v % 836 100.0% 0.2684
Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators
(EPA 453/B-96-001)
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
Reheat (104) Reheat (104) 41 of 56
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 15: - SCR + Reheat (110)
Operating Unit: Furnace 12 Hood Exhaust
Emission Unit Number EU 110 Stack/Vent Number SV 111, 112, & 113 Chemical Engineering
Desgin Capacity 150 MMBtu/hr Standardized Flow Rate 181,762 scfm @ 32º F Chemical Plant Cost Index
Expected Utiliztion Rate 93% Temperature 142 Deg F 1998/1999 390
Expected Annual Hours of Operation 8,339 Hours Moisture Content 9.5% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 222,400 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 195,062 scfm @ 68º F
Dry Std Flow Rate 176,529 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs Year
Direct Capital Costs EPRI Correlation 1998
Purchased Equipment (A) 2005 10,324,640
Purchased Equipment Total (B) 0% of control device cost (A) SCR Only 10,995,741
Installation - Standard Costs 15% of purchased equip cost (B) SCR Only 2,045,946
Installation - Site Specific Costs 0
Installation Total 0
Total Direct Capital Cost, DC 0
Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0
Total Capital Investment (TCI) = DC + IC SCR + Reheat 46,284,809
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 7,339,040
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 4,349,371
Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 11,688,411
Emission Control Cost Calculation
Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost
Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 109.9 1.4 0.01 5.6 104.4 112,008
Notes & Assumptions
1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2.
2 For Calculation purposes, duty reflects increased flow rate, not actual duty.
3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2
4 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43
5 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35
6 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24
7 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31
8 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53
9 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48
10 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46
11 Control Efficiency = 90% reduction which is typically the upper range of normal SCR control efficiency
12 $35/MW-hr, 140 MW
13 Catalyst replacement every 8000 hours. This requires an additional 2 week outage per 3 year outage cycle, annualized to 4.7 days.
Notes to User
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
NOx SCR+ Reheat 90% Eff (110) NOx SCR+ Reheat 90% Eff (110) 42 of 56
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 15: - SCR + Reheat (110)
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1)
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 10,324,640
Instrumentation 10% of control device cost (A) NA
MN Sales Taxes 6.5% of control device cost (A) 671,102
Freight 5% of control device cost (A) NA
Purchased Equipment Total (A) 10,995,741
Indirect Installation
General Facilities 0% of purchased equip cost (A) 0
Engineering & Home Office 0% of purchased equip cost (A) 0
Process Contingency 0% of purchased equip cost (A) 0
Site Specific-Other 24% Replacement Power, two weeks 2,643,899
Total Indirect Installation Costs (B) 24% of purchased equip cost (A) 2,643,899
Project Contingeny ( C) 15% of (A + B) 2,045,946
Total Plant Cost D A + B + C 15,685,586
Allowance for Funds During Construction (E) Additional 10 week outage for installation 8,232,000
Pre Production Costs (G) 2% of (D+E)) 478,352
Inventory Capital Reagent Vol * $/gal 2,331
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 24,398,268
Retrofit multiplier3
60% of TCI 14,638,961
Total Retorfit Capital Investment 39,037,230
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr 104,239
Supervisor 15% 15% of Operator Costs 15,636
Maintenance
Maintenance Total 1.50 % of Total Capital Investment 365,974
Maintenance Materials NA % of Maintenance Labor -
Utilities, Supplies, Replacements & Waste Management
Electricity 0.06 $/kwh, 1,474 kW-hr, 8339.1 hr/yr, 93% utilization 686,019
NA NA -
NA NA -
NA NA -
NA NA -
NA NA -
NA NA -
NA NA -
NA NA -
NA NA -
Cat. Replacement [14] 35.00 Catalyst Replacement 431,932
NA NA -
Ammonia 0.12 $/lb, 69 lb/hr, 8339.1 hr/yr, 93% utilization 64,238
NA NA -
NA NA -
NA NA -
Total Annual Direct Operating Costs 1,668,038
Indirect Operating Costs
Overhead 60% of total labor and material costs 40,886
Administration (2% total capital costs) 2% of total capital costs (TCI) 487,965
Property tax (1% total capital costs) 1% of total capital costs (TCI) 243,983
Insurance (1% total capital costs) 1% of total capital costs (TCI) 243,983
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,303,024
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,319,840
Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,987,878
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
NOx SCR+ Reheat 90% Eff (110) NOx SCR+ Reheat 90% Eff (110) 43 of 56
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 15: - SCR + Reheat (110)
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Equivalent Duty 1,074 Plant Cap kW A 110,187
Est power platn eff 35% Unc Nox lb/mmBtu B 0.05 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35
Watt per Btu/hr 0.29307 Nox Red. Eff. C 80% E=D*A*0.0066
Equivalent power plant kW 110,187 Capital Cost $/kW D $93.70 $10,324,639.77 Total SCR Equipment
Uncontrolled Nox t/y 109.9 Fixed O&M E $68,142.62
Annual Operating Hrs 8000 Variable O&M F $209,166.23
Uncontrolled Nox lb/mmBtu 0.048 Ann Cap Factor G 0.82
Heat Input mmBtu/hrH 6,000
SCR Capital Cost
Duty 1,074 MMBtu/hr Catalyst Area 518 ft2
613 f (h SCR)
Q flue gas 497,508 acfm Rx Area 596 80 f (h NH3)
NOx Cont Eff 80% (as faction) Rx Height 24.4 ft 0 f (h New) new= -728, Retrofit = 0
NOx in 0.05 lb/MMBtu n layer 22 layers Y Bypass? Y or N
Ammonia Slip 2 ppm h layer 23.5 ft 127 f (h Bypass)
Fuel Sulfur 0.67 wt % (as %) n total 23 layers 8,387,553 f (vol catalyst)
Temperature 142 Deg F h SCR 131 ft f (h SCR)
Catalyst Volume 34,948 ft3
New/Retrofit R N or R
Electrical Use
Duty 1,074 MMBtu/hr kW
NOx Cont Eff 80% (as faction) Power 1,474.3
NOx in 0.05 lb/MMBtu
n catalyst layers 23 layers
Press drop catalyst 1 in H2O per layer
Press drop duct 3 in H2O
Total 1474.3
Reagent Use & Other Operating Costs
Ammonia Use 56.0 lb/ft3 Density
20 lb/hr Neat 9.2 gal/hr
29% solution Volume 14 day inventory 3,083 gal $2,331 Inventory Cost
69 lb/hr
Design Basis Baseline Emis.Baseline Emis.Max Emis. (Model) Control Eff (%) Cont. Emis (lb/MMBtu)
T/yr lb/MMBtu lb/hr 80% 0.01
Nitrous Oxides (NOx) 109.9 0.05 51.25
Actual 70,611 dscf/MMBtu
Method 19 Factor 9,860 dscf/MMBtu
Adjusted Duty 1,074 MMBtu/hr
Operating Cost Calculations Annual hours of operation: 8,339
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 50.00 $/Hr 2.0 hr/8 hr shift 2,085 104,239 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr
Supervisor 15% of Op. NA 15,636 15% of Operator Costs
Maintenance
Maintenance Total 1.5 % of Total Capital Investment 365,974 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.060 $/kwh 1474.3 kW-hr 11,433,649 686,019 $/kwh, 1,474 kW-hr, 8339.1 hr/yr, 93% utilization
Cat. Replacement [14] 35 $/MW-hr 110.2 mw 112 431,932 Catalyst Replacement
7 Ammonia 0.12 $/lb 69 lb/hr 532,660 64,238 $/lb, 69 lb/hr, 8339.1 hr/yr, 93% utilization
** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
NOx SCR+ Reheat 90% Eff (110) NOx SCR+ Reheat 90% Eff (110) 44 of 56
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 16: - Reheat (110)
Operating Unit: Furnace 12 Hood Exhaust
Emission Unit Number EU 110 Stack/Vent Number SV 111, 112, & 113 Chemical Engineering
Desgin Capacity 150 MMBtu/hr Standardized Flow Rate 181,762 scfm @ 32º F Chemical Plant Cost Index
Expected Utiliztion Rate 93% Temperature 142 Deg F 1998/1999 390
Expected Annual Hours of Operation 8,339 Hours Moisture Content 9.5% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 222,400 acfm Inflation Adj 1.19Expected Equipment Life 20 yrs Standardized Flow Rate 195,062 scfm @ 68º F
Dry Std Flow Rate 176,529 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 535,531
Purchased Equipment Total (B) 22% of control device cost (A) 650,671
Installation - Standard Costs 30% of purchased equip cost (B) 195,201
Installation - Site Specific Costs 6,200,000
Installation Total 6,395,201
Total Direct Capital Cost, DC 7,045,872
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 201,708
Total Capital Investment (TCI) = DC + IC 7,247,580
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 5,671,002
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,029,531Total Annual Cost (Annualized Capital Cost + Operating Cost) 6,700,533
Notes & Assumptions
1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
Reheat (110) Reheat (110) 45 of 56
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 16: - Reheat (110)
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 535,531
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC
Instrumentation 10% of control device cost (A) 53,553
MN Sales Taxes 6.5% of control device cost (A) 34,810
Freight 5% of control device cost (A) 26,777Purchased Equipment Total (B) 22% 650,671
Installation
Foundations & supports 8% of purchased equip cost (B) 52,054
Handling & erection 14% of purchased equip cost (B) 91,094
Electrical 4% of purchased equip cost (B) 26,027
Piping 2% of purchased equip cost (B) 13,013
Insulation 1% of purchased equip cost (B) 6,507
Painting 1% of purchased equip cost (B) 6,507
Installation Subtotal Standard Expenses 30% 195,201
Sitework and foundations Site Specific 1,400,000
Structural steel Site Specific 4,800,000
Site Specific - Other Site Specific 0
Total Site Specific Costs 6,200,000Installation Total 6,395,201
Total Direct Capital Cost, DC 7,045,872
Indirect Capital Costs
Engineering, supervision 10% of purchased equip cost (B) 65,067Construction & field expenses 5% of purchased equip cost (B) 32,534Contractor fees 10% of purchased equip cost (B) 65,067
Start-up 2% of purchased equip cost (B) 13,013Performance test 1% of purchased equip cost (B) 6,507Model Studies of purchased equip cost (B) 0Contingencies 3% of purchased equip cost (B) 19,520
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 201,708
Total Capital Investment (TCI) = DC + IC 7,247,580
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 7,247,580
OPERATING COSTSDirect Annual Operating Costs, DC
Operating Labor
Operator 50.00 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr 26,060
Supervisor 15% 15% of Operator Costs 3,909
Maintenance
Maintenance Labor 60.00 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr 31,272
Maintenance Materials 100% of maintenance labor costs 31,272Utilities, Supplies, Replacements & Waste Management
Electricity 0.06 $/kwh, 824 kW-hr, 8339.1 hr/yr, 93% utilization 383,421
Natural Gas 10.02 $/mscf, 1,114 scfm, 8339.1 hr/yr, 93% utilization 5,195,069
Total Annual Direct Operating Costs 5,671,002
Indirect Operating Costs
Overhead 60% of total labor and material costs 55,507
Administration (2% total capital costs) 2% of total capital costs (TCI) 144,952
Property tax (1% total capital costs) 1% of total capital costs (TCI) 72,476
Insurance (1% total capital costs) 1% of total capital costs (TCI) 72,476
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 684,120 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,029,531
Total Annual Cost (Annualized Capital Cost + Operating Cost) 6,700,533
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
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BART Report - <Insert attachment name> Emission Control Cost Analysis
Table 16: - Reheat (110)
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalyst: Catalyst
Equipment Life 2 years
CRF 0.5531
Rep part cost per unit 0 $/ft3
Amount Required 39 ft3
Catalyst Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit 0 $ each
Amount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales taxInstallation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kWBlower, Thermal 222,400 19 0.6 824.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Blower, Catalytic 222,400 23 0.6 997.5 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Oxidizer Type thermal (catalytic or thermal) 824.0
Reagent Use & Other Operating Costs Oxidizers - NA
Operating Cost Calculations Annual hours of operation: 8,339
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 521 26,060 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr
Supervisor 15% of Op. NA 3,909 15% of Operator Costs
Maintenance
Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 521 31,272 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 31,272 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.060 $/kwh 824.0 kW-hr 6,390,357 383,421 $/kwh, 824 kW-hr, 8339.1 hr/yr, 93% utilization
Natural Gas 10.02 $/mscf 1,114 scfm 518,449 5,195,069 $/mscf, 1,114 scfm, 8339.1 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
Reheat (110) Reheat (110) 47 of 56
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BART Report - Appendix A Emission Control Cost Analysis
Table 16: - Reheat (110)
Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery
Auxiliary Fuel Use Equation 3.19
Twi 140 Deg F - Temperature of waste gas into heat recovery
Tfi 750 Deg F - Temperature of Flue gas into of heat recovery
Tref 77 Deg F - Reference temperature for fuel combustion calculations
FER 70% Factional Heat Recovery % Heat recovery section efficiency
Two 567 Deg F - Temperature of waste gas out of heat recovery
Tfo 323 Deg F - Temperature of flue gas into of heat recovery
-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)
-hwg 0 Btu/lb Heat of combustion waste gas
Cp wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air)
p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F
p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Qwg 195,062 scfm - Flow of waste gas
Qaf 1,114 scfm - Flow of auxiliary fuel
Year 2005 Inflation Rate 3.0%Cost Calculations 196,176 scfm Flue Gas Cost in 1989 $'s $449,155
Current Cost Using CHE Plant Cost Index $535,531
Heat Rec % A B
0 10,294 0.2355 Exponents per equation 3.24
0.3 13,149 0.2609 Exponents per equation 3.25
0.5 17,056 0.2502 Exponents per equation 3.260.7 21,342 0.2500 Exponents per equation 3.27
Indurator Flue Gas Heat Capacity - Basis Typical Composition
100 scfm 359 scf/lbmole
Gas Composition lb/hr f wt % Cp Gas Cp Flue28 mw CO 0 v % 0
44 mw CO2 15 v % 184 22.0% 0.24 0.052818 mw H2O 10 v % 50 6.0% 0.46 0.0276
28 mw N2 60 v % 468 56.0% 0.27 0.1512
32 mw O2 15 v % 134 16.0% 0.23 0.0368
Cp Flue Gas 100 v % 836 100.0% 0.2684
Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators
(EPA 453/B-96-001)
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
Reheat (110) Reheat (110) 48 of 56
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BART Report - Appendix A Emission Control Cost Analysis
Table 17: - SCR + Reheat (114)
Operating Unit: Furnace 12 Waste Gas
Emission Unit Number EU 114 Stack/Vent Number SV 114 & 115
Desgin Capacity 150 MMBtu/hr Standardized Flow Rate 152,520 scfm @ 32º F
Expected Utiliztion Rate 93% Temperature 140 Deg F
Expected Annual Hours of Operation 8,339 Hours Moisture Content 16.4%
Annual Interest Rate 7.0% Actual Flow Rate 186,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 163,680 scfm @ 68º F
Dry Std Flow Rate 136,902 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs EPRI Correlation
Purchased Equipment (A) 8,929,135
Purchased Equipment Total (B) SCR Only 9,509,529
Installation - Standard Costs 15% of purchased equip cost (B) SCR Only 1,823,014
Installation - Site Specific Costs 0
Installation Total 0
Total Direct Capital Cost, DC 0
Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0
Total Capital Investment (TCI) = DC + IC SCR + Reheat 43,455,895
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 6,279,410
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 4,103,963
Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 10,383,373
Emission Control Cost Calculation
Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost
Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 267.7 4.5 0.03 17.4 250.3 41,488
Notes & Assumptions
1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2.
2 For Calculation purposes, duty reflects increased flow rate, not actual duty.
3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2
4 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43
5 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35
6 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24
7 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31
8 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53
9 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48
10 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46
11 Control Efficiency = 90% reduction which is typically the upper range of normal SCR control efficiency
12 $35/MW-hr, 140 MW
13 Catalyst replacement every 8000 hours. This requires an additional 2 week outage per 3 year outage cycle, annualized to 4.7 days.
Notes to User
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
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BART Report - Appendix A Emission Control Cost Analysis
Table 17: - SCR + Reheat (114)
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1)
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 8,929,135
Instrumentation 10% of control device cost (A) NA
MN Sales Taxes 6.5% of control device cost (A) 580,394
Freight 5% of control device cost (A) NA
Purchased Equipment Total (A) 9,509,529
Indirect Installation
General Facilities 0% of purchased equip cost (A) 0
Engineering & Home Office 0% of purchased equip cost (A) 0
Process Contingency 0% of purchased equip cost (A) 0
Site Specific-Other 28% Replacement Power, two weeks 2,643,899
Total Indirect Installation Costs (B) 28% of purchased equip cost (A) 2,643,899
Project Contingeny ( C) 15% of (A + B) 1,823,014
Total Plant Cost D A + B + C 13,976,441
Allowance for Funds During Construction (E) Additional 10 week outage for installation 8,232,000
Pre Production Costs (G) 2% of (D+E)) 444,169
Inventory Capital Reagent Vol * $/gal 5,677
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 22,658,287
Retrofit multiplier3
60% of TCI 13,594,972
Total Retorfit Capital Investment 36,253,260
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr 104,239
Supervisor 15% 15% of Operator Costs 15,636
Maintenance
Maintenance Total 1.50 % of Total Capital Investment 339,874
Maintenance Materials NA % of Maintenance Labor -
Utilities, Supplies, Replacements & Waste Management
Electricity 0.06 $/kwh, 1,194 kW-hr, 8339.1 hr/yr, 93% utilization 555,760
NA NA -
NA NA -
NA NA -
NA NA -
NA NA -
NA NA -
NA NA -
NA NA -
NA NA -
Cat. Replacement [14] 35.00 Catalyst Replacement 334,973
NA NA -
Ammonia 0.12 $/lb, 167 lb/hr, 8339.1 hr/yr, 93% utilization 156,470
NA NA -
NA NA -
NA NA -
Total Annual Direct Operating Costs 1,506,951
Indirect Operating Costs
Overhead 60% of total labor and material costs 35,359
Administration (2% total capital costs) 2% of total capital costs (TCI) 453,166
Property tax (1% total capital costs) 1% of total capital costs (TCI) 226,583
Insurance (1% total capital costs) 1% of total capital costs (TCI) 226,583
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,138,782
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,080,473
Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,587,424
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
NOx SCR+ Reheat 90% Eff (114) NOx SCR+ Reheat 90% Eff (114) 50 of 56
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BART Report - Appendix A Emission Control Cost Analysis
Table 17: - SCR + Reheat (114)
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Equivalent Duty 833 Plant Cap kW A 85,452
Est power platn eff 35% Unc Nox lb/mmBtu B 0.15 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35
Watt per Btu/hr 0.29307 Nox Red. Eff. C 80% E=D*A*0.0066
Equivalent power plant kW 85,452 Capital Cost $/kW D $104.49 $8,929,134.83 Total SCR Equipment
Uncontrolled Nox t/y 267.7 Fixed O&M E $58,932.29
Annual Operating Hrs 8000 Variable O&M F $174,705.21
Uncontrolled Nox lb/mmBtu 0.150 Ann Cap Factor G 0.82
Heat Input mmBtu/hrH 6,000
SCR Capital Cost
Duty 833 MMBtu/hr Catalyst Area 402 ft2
638 f (h SCR)
Q flue gas 385,829 acfm Rx Area 462 117 f (h NH3)
NOx Cont Eff 80% (as faction) Rx Height 21.5 ft 0 f (h New) new= -728, Retrofit = 0
NOx in 0.15 lb/MMBtu n layer 23 layers Y Bypass? Y or N
Ammonia Slip 2 ppm h layer 24.5 ft 127 f (h Bypass)
Fuel Sulfur 0.67 wt % (as %) n total 24 layers 6,792,565 f (vol catalyst)
Temperature 140 Deg F h SCR 135 ft f (h SCR)
Catalyst Volume 28,302 ft3
New/Retrofit R N or R
Electrical Use
Duty 833 MMBtu/hr kW
NOx Cont Eff 80% (as faction) Power 1,194.4
NOx in 0.15 lb/MMBtu
n catalyst layers 24 layers
Press drop catalyst 1 in H2O per layer
Press drop duct 3 in H2O
Total 1194.4
Reagent Use & Other Operating Costs
Ammonia Use 56.0 lb/ft3 Density
49 lb/hr Neat 22.3 gal/hr
29% solution Volume 14 day inventory 7,509 gal $5,677 Inventory Cost
167 lb/hr
Design Basis Baseline Emis.Baseline Emis.Max Emis. (Model) Control Eff (%) Cont. Emis (lb/MMBtu)
T/yr lb/MMBtu lb/hr 80% 0.03
Nitrous Oxides (NOx) 267.7 0.15 124.83
Actual 54,761 dscf/MMBtu
Method 19 Factor 9,860 dscf/MMBtu
Adjusted Duty 833 MMBtu/hr
Operating Cost Calculations Annual hours of operation: 8,339
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 50.00 $/Hr 2.0 hr/8 hr shift 2,085 104,239 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr
Supervisor 15% of Op. NA 15,636 15% of Operator Costs
Maintenance
Maintenance Total 1.5 % of Total Capital Investment 339,874 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.060 $/kwh 1194.4 kW-hr 9,262,659 555,760 $/kwh, 1,194 kW-hr, 8339.1 hr/yr, 93% utilization
Cat. Replacement [14] 35 $/MW-hr 85.5 mw 112 334,973 Catalyst Replacement
7 Ammonia 0.12 $/lb 167 lb/hr 1,297,437 156,470 $/lb, 167 lb/hr, 8339.1 hr/yr, 93% utilization
** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
NOx SCR+ Reheat 90% Eff (114) NOx SCR+ Reheat 90% Eff (114) 51 of 56
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BART Report - Appendix A Emission Control Cost Analysis
Table 18: - Reheat (114)
Operating Unit: Furnace 12 Waste Gas
Emission Unit Number EU 114 Stack/Vent Number SV 104 & 105 Chemical Engineering
Desgin Capacity 150 MMBtu/hr Standardized Flow Rate 152,520 scfm @ 32º F Chemical Plant Cost Index
Expected Utiliztion Rate 93% Temperature 140 Deg F 1998/1999 390
Expected Annual Hours of Operation 8,339 Hours Moisture Content 18.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 186,000 acfm Inflation Adj 1.19Expected Equipment Life 20 yrs Standardized Flow Rate 163,680 scfm @ 68º F
Dry Std Flow Rate 133,792 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 512,555
Purchased Equipment Total (B) 22% of control device cost (A) 622,755
Installation - Standard Costs 30% of purchased equip cost (B) 186,826
Installation - Site Specific Costs 6,200,000
Installation Total 6,386,826 Total Direct Capital Cost, DC 7,009,581
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 193,054
Total Capital Investment (TCI) = DC + IC 7,202,635
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 4,772,459
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,023,490Total Annual Cost (Annualized Capital Cost + Operating Cost) 5,795,949
Notes & Assumptions
1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
Reheat (114) Reheat (114) 52 of 56
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 18: - Reheat (114)
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 512,555
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC
Instrumentation 10% of control device cost (A) 51,256
MN Sales Taxes 6.5% of control device cost (A) 33,316
Freight 5% of control device cost (A) 25,628Purchased Equipment Total (B) 22% 622,755
Installation
Foundations & supports 8% of purchased equip cost (B) 49,820
Handling & erection 14% of purchased equip cost (B) 87,186
Electrical 4% of purchased equip cost (B) 24,910
Piping 2% of purchased equip cost (B) 12,455
Insulation 1% of purchased equip cost (B) 6,228
Painting 1% of purchased equip cost (B) 6,228
Installation Subtotal Standard Expenses 30% 186,826
Sitework and foundations Site Specific 1,400,000
Structural steel Site Specific 4,800,000
Site Specific - Other Site Specific 0Total Site Specific Costs 6,200,000
Installation Total 6,386,826
Total Direct Capital Cost, DC 7,009,581
Indirect Capital Costs
Engineering, supervision 10% of purchased equip cost (B) 62,275Construction & field expenses 5% of purchased equip cost (B) 31,138Contractor fees 10% of purchased equip cost (B) 62,275
Start-up 2% of purchased equip cost (B) 12,455Performance test 1% of purchased equip cost (B) 6,228Model Studies of purchased equip cost (B) 0Contingencies 3% of purchased equip cost (B) 18,683
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 193,054
Total Capital Investment (TCI) = DC + IC 7,202,635
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 7,202,635
OPERATING COSTSDirect Annual Operating Costs, DC
Operating Labor
Operator 50.00 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr 26,060
Supervisor 15% 15% of Operator Costs 3,909
Maintenance
Maintenance Labor 60.00 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr 31,272
Maintenance Materials 100% of maintenance labor costs 31,272Utilities, Supplies, Replacements & Waste Management
Electricity 0.06 $/kwh, 689 kW-hr, 8339.1 hr/yr, 93% utilization 320,667
Natural Gas 10.02 $/mscf, 935 scfm, 8339.1 hr/yr, 93% utilization 4,359,280
Total Annual Direct Operating Costs 4,772,459
Indirect Operating Costs
Overhead 60% of total labor and material costs 55,507
Administration (2% total capital costs) 2% of total capital costs (TCI) 144,053
Property tax (1% total capital costs) 1% of total capital costs (TCI) 72,026
Insurance (1% total capital costs) 1% of total capital costs (TCI) 72,026
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 679,878 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,023,490
Total Annual Cost (Annualized Capital Cost + Operating Cost) 5,795,949
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls
Reheat (114) Reheat (114) 53 of 56
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BART Report - <Insert attachment name> Emission Control Cost Analysis
Table 18: - Reheat (114)
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalyst: Catalyst
Equipment Life 2 years
CRF 0.5531
Rep part cost per unit 0 $/ft3
Amount Required 39 ft3
Catalyst Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit 0 $ each
Amount Required 0 NumberTotal Rep Parts Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kWBlower, Thermal 186,000 19 0.6 689.1 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Blower, Catalytic 186,000 23 0.6 834.2 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Oxidizer Type thermal (catalytic or thermal) 689.1
Reagent Use & Other Operating Costs Oxidizers - NA
Operating Cost Calculations Annual hours of operation: 8,339
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 521 26,060 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr
Supervisor 15% of Op. NA 3,909 15% of Operator Costs
Maintenance
Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 521 31,272 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 31,272 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.060 $/kwh 689.1 kW-hr 5,344,453 320,667 $/kwh, 689 kW-hr, 8339.1 hr/yr, 93% utilization
Natural Gas 10.02 $/mscf 935 scfm 435,040 4,359,280 $/mscf, 935 scfm, 8339.1 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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Reheat (114) Reheat (114) 54 of 56
Cleveland Cliffs Incorporated: Northshore Mining
BART Report - Appendix A Emission Control Cost Analysis
Table 18: - Reheat (114)
Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery
Auxiliary Fuel Use Equation 3.19
Twi 140 Deg F - Temperature of waste gas into heat recovery
Tfi 750 Deg F - Temperature of Flue gas into of heat recovery
Tref 77 Deg F - Reference temperature for fuel combustion calculations
FER 70% Factional Heat Recovery % Heat recovery section efficiency
Two 567 Deg F - Temperature of waste gas out of heat recovery
Tfo 323 Deg F - Temperature of flue gas into of heat recovery
-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)
-hwg 0 Btu/lb Heat of combustion waste gas
Cp wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air)
p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F
p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Qwg 163,680 scfm - Flow of waste gas
Qaf 935 scfm - Flow of auxiliary fuel
Year 2005 Inflation Rate 3.0%
Cost Calculations 164,615 scfm Flue Gas Cost in 1989 $'s $429,885
Current Cost Using CHE Plant Cost Index $512,555
Heat Rec % A B
0 10,294 0.2355 Exponents per equation 3.24
0.3 13,149 0.2609 Exponents per equation 3.25
0.5 17,056 0.2502 Exponents per equation 3.260.7 21,342 0.2500 Exponents per equation 3.27
Indurator Flue Gas Heat Capacity - Basis Typical Composition
100 scfm 359 scf/lbmole
Gas Composition lb/hr f wt % Cp Gas Cp Flue28 mw CO 0 v % 0
44 mw CO2 15 v % 184 22.0% 0.24 0.052818 mw H2O 10 v % 50 6.0% 0.46 0.0276
28 mw N2 60 v % 468 56.0% 0.27 0.1512
32 mw O2 15 v % 134 16.0% 0.23 0.0368
Cp Flue Gas 100 v % 836 100.0% 0.2684
Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators
(EPA 453/B-96-001)
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Reheat (114) Reheat (114) 55 of 56
InputsCalculated or scaled valuesEstimated value
1 2 3 4 5 6 7 8 9
Stack No Facility Name
SO2 Max. 24-
hr Actual
Emissions
Flow Rate
at Exit
Specific
Collection Area
(SCA)1
Surface Collection
Area2
Pressure
Drop3 Cost
4
lb/hr acfm ft2/kacfm ft
2 in. H20 $
BASE N/A 291,000 198 68,825 5 4,700,000
SV 101, 102, & 103 Northshore Furnace 11 Hood Exhaust 35.50 222,400 198 52,600 10 3,999,843SV 104 & 105 Northshore Furnace 11 Waste Gas 11.83 186,000 198 43,991 10 3,593,104
SV 111, 112, & 113 Northshore Furnace 12 Hood Exhaust 35.50 222,400 198 52,600 10 3,999,843SV 114 & 115 Northshore Furnace 12 Waste Gas 11.83 186,000 198 43,991 10 3,593,104
SV021M-SV024M Hibbtac Pellet Indurating Furnace Line No 1 30.00 772,000 198 182,587 10 8,439,806SV025M-SV028M Hibbtac Pellet Indurating Furnace Line No 2 38.00 795,000 198 188,027 10 8,589,786SV029M-SV032M Hibbtac Pellet Indurating Furnace Line No 3 43.00 827,000 198 195,595 10 8,795,598
SV 014 Ispat Indurating Furnace 125.00 205,478 198 48,598 10 3,814,356SV 015 Ispat Indurating Furnace 125.00 205,478 198 48,598 10 3,814,356SV 016 Ispat Indurating Furnace 125.00 205,478 198 48,598 10 3,814,356SV 017 Ispat Indurating Furnace 125.00 205,478 198 48,598 10 3,814,356
SV 046 UTAC Line 1 Pellet Induration 4.25 369,137 198 87,305 10 5,420,940SV 049 UTAC Line 2 Pellet Induration 286.67 380,000 198 89,875 10 5,516,101SV 048 UTAC Line 2 Pellet Induration 345.50 346,000 198 81,833 10 5,214,441
SV051M Keetac Grate Kiln - Indurator Waste Gas, Phase II 217.2 848,000 198 200,562 10 8,928,933
SV 151 Minntac Line 7 waste gas 75.0 600,000 198 141,907 10 7,255,257SV 127 Minntac Line 5 waste gas 93.7 650,000 198 153,733 10 7,612,198SV 144 Minntac Line 6 waste gas 113.5 555,650 198 131,418 10 6,928,558SV 118 Minntac Line 4 waste gas 133.1 650,000 198 153,733 10 7,612,198SV 103 Minntac Line 3 waste gas 128.9 322,000 198 76,157 10 4,994,311
NSM Power 365.0 300,000 141,907 9,573,369
1) Estimated value from Durr. Value indpendent of stack flow.2) Original estimate from Durr. Scaled linearly using stack flow rates.
3) Pressure drop is not a design driving factor, but must be maintained at an acceptably low value. 10" H2O is used as a maximum value.
4) Capital price back calculated using reverse of EPA control cost manual factors from installed price estimate provided from DURR. Used 0.6 power law factor to adjust price to each stack's acfm from bid basis of 291,000 acfm.
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Northshore Process Boiler
BART Report - Appendix A Emission Control Cost Analysis
Table 19: Cost Summary - Natural gas boiler
NOx Control Cost Summary baseline: 0.17 lb/mmBtu 11.625 lb/hr
Control TechnologyControl
Eff %
Controlled
Emissions T/y
Emission
Reduction T/yr
Installed Capital
Cost $
Total Annual Cost
$/yr
Pollution Control
Cost $/ton
Incremental
Cost $/ton
Selective Catalytic Reduction
(SCR)90% 4.1 37.1 $5,563,529 $1,119,307 $30,139
Low NOx Burner / Flue Gas
Recirculation75% 10.3 30.9 $547,722 $77,510 $2,505 $30,626
Low Nox Burner/Over Fire Air 68% 13.4 27.9 $1,091,532 $387,372 $13,908
Low NOx Burner 50% 20.6 20.6 $95,851 $16,766 $813
Selective Non-Catalytic
Reduction (SNCR) 50% 20.6 20.6 $925,876 $250,181 $12,126
SO2 Control Cost Summary baseline 0.24 lb/mmBtu 16.75 lb/hr
Control TechnologyControl
Eff %
Controlled
Emissions T/y
Emission
Reduction T/yr
Installed Capital
Cost $
Total Annual Cost
$/yr
Pollution Control
Cost $/ton
Wet ESP
Process Boiler 1 & 2 80% 11.9 61.5 $11,808,857 $2,247,725 $36,558
SO2 Absorber
Process Boiler 1 & 2 80% 11.9 61.5 $3,935,118 $1,118,879 $18,198Spray Dryer and Baghouse
Process Boiler 1 & 2 90 11.9 61.5 $16,134,577 $2,754,704 $44,804
DSI Baghouse
Process Boiler 1 & 2 55 11.9 61.5 $4,890,063 $1,412,189 $22,969
Wet Scrubber
Process Boiler 1 & 2 80% 14.68 58.72 $13,618,522 $1,869,933 $31,845
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Cost Summary 9/6/2006 Page 1 of 42
Northshore Process Boiler
BART Report - Appendix A Emission Control Cost Analysis
Table 20: - Summary of Utility, Chemical and Supply Costs
Operating Unit: Process Boiler 1 & 2 Study Year 2006
Emission Unit Number 003 & 004
Stack/Vent Number 003
Reference
Item Unit Cost Units Cost Year Data Source Notes
Operating Labor 50.00 $/hr Estimated industry average
Maintenance Labor 60.00 $/hr Estimated industry average
Electricity 0.052 $/kwh 0.049 2004
DOE Average Retail Price of Industrial
Electricity, 2004 http://www.eia.doe.gov/emeu/aer/txt/ptb0810.html
Natural Gas 2.31 $/mscf 2005
Average natural gas spot price July 04 - June
05, Henry La Hub., WTRG Economics, WWW.wtrg.com/daily/small/ngspot.gig
Water 0.40 $/mgal 0.76 2004 Estimated industrial cost cost adjusted for 3% inflation
Cooling Water 0.28 $/mgal 0.23 1999
EPA Air Pollution Control Cost Manual, 6th
ed. Section 3.1 Ch 1
Ch 1 Carbon Absorbers, 1999 $0.15 - $0.30 Avg of 22.5 and 7 yrs and
3% inflation
Compressed Air 0.32 $/mscf 0.25 1998
EPA Air Pollution Control Cost Manual 6th Ed
2002, Section 6 Chapter 1
Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3%
inflation
Wastewater Disposal Neutralization 3.80 $/mgal 1.50 2002
EPA Air Pollution Control Cost Manual 6th Ed
2002, Section 2 Chapter 2.5.5.5
Section 2 lists $1- $2/1000 gal. Cost adjusted for 3% inflation Sec 6 Ch
3 lists $1.30 - $2.15/1,000 gal
Wastewater Disposal Bio-Treat 4.28 $/mgal 3.80 2002
EPA Air Pollution Control Cost Manual 6th Ed
2002, Section 5.2 Chapter 1
Ch 1lists $1.00 - $6.00 for municipal treatment, $3.80 is average. Cost
adjusted for 3% inflation
Solid Waste Disposal 11.48 $/ton 25.00 2002
EPA Air Pollution Control Cost Manual 6th Ed
2002, Section 2 Chapter 2.5.5.5
Section 2 lists $20 - $30/ton Used $25/ton. Cost adjusted for 3%
inflation
Hazardous Waste Disposal 281.38 $/ton 250.00 2002
EPA Air Pollution Control Cost Manual 6th Ed
2002, Section 2 Chapter 2.5.5.5
Section 2 lists $200 - $300/ton Used $250/ton. Cost adjusted for 3%
inflation
Waste Transport 0.56 $/ton-mi 0.50 2002
EPA Air Pollution Control Cost Manual 6th Ed
2002, Section 6 Chapter 3 Example problem. Cost adjusted for 3% inflation
Internal Waste Recycle 1 $/ton 1.00 2000 Estimated waste cost Used $1/ton to cover cost of materials movement
Chemicals & Supplies
Lime 90.00 $/ton Info provided by Sonnek Engineeing
Caustic 305.21 $/ton 2005 Hawkins Chemical 50% solution (50 Deg Be) includes delivery
Urea 405 $/ton 2005 Hawkins Chemical 50% solution of urea in water, includes delivery
Soda Ash $/ton
Oxygen 1.49 Mscf 1.40 2004 Industry estimate cost adjusted for 3% inflation
EPA Urea 179.1 $/ton
Ammonia 0.92 $/lb
Reagent #8 0.00 $/ton
Catalyst & Replacement Parts
SCR Catalyst 500 $/ft3
Cormetech, Inc., 1/2006 bid
CO Catalyst 650 $/ft3
Vendor quote if needed
Catalyst #3
Catalyst #4
Catalyst #5
Filter Bags 37.94 $/bag 33.71 2002
EPA Air Pollution Control Cost Manual 6th Ed
2002, Section 6, Chapter 1 Example problem cost for 10 ft bags. Cost adjusted for 3% inflation
Tower Packing 100 $/ft3
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Utility Chem$ Data 9/6/2006 Page 2 of 42
Replacement Parts
Replacement Parts
Replacement Parts
Other
Sales Tax 6.5% %
Interest Rate 7.00% %
EPA Air Pollution Control Cost Manual
Introduction, Chapter 2, section 2.4.2. Social (discount) rate used as a default.
Operating Information
Annual Op. Hrs 7,650 Hours Engineering Estimate
Utilization Rate 93%
Equipment Life 20 yrs Engineering Estimate
Design Capacity 70 MMBtu/hr
Standardized Flow Rate 64,771 scfm @ 32º F
Temperature 450 Deg F
Moisture Content 13.3%
Actual Flow Rate 119,800 acfm
Standardized Flow Rate 69,510 scfm @ 68º F Based on Table 19.2 of 40 CFR 60, Appendix A, Method 19 F factor for n
Dry Std Flow Rate 60,265 dscfm @ 68º F
Max Emis
Pollutant Lb/Hr
PM10 1.90
Total Particulates 1.90
Nitrous Oxides (NOx) 11.60
Sulfur Dioxide (SO2) 16.800
Sulfuric Acid Mist
Fluorides
Volatile Organic Compounds (VOC) 0.99
Carbon Monoxide (CO) 0.00
Lead (Pb)
Enter this data for each emission unit
Enter data for this study (applies to all units)
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Utility Chem$ Data 9/6/2006 Page 3 of 42
Northshore Process BoilerBART Report - Appendix A Emission Control Cost AnalysisTable 21: NOx Control - Low NOx Burner
Operating Unit: Process Boiler 1 & 2
Emission Unit Number 003 & 004 Stack/Vent Number 003 Chemical EngineeringDesign Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32º F Chemical Plant Cost IndexExpected Utilization Rate 93% Temperature 450 Deg F 1998/1999 390
Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Inflation Adj 1.19Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68º F
Dry Std Flow Rate 60,265 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs Direct Capital Costs
Purchased Equipment (A) 49,000
Purchased Equipment Total (B) 22% of control device cost (A) 59,535
Installation - Standard Costs 30% of purchased equip cost (B) 17,861 Installation - Site Specific Costs NA Installation Total 17,861
Total Direct Capital Cost, DC 77,396
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 18,456
Total Capital Investment (TCI) = DC + IC 95,851
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 2,866 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 13,900Total Annual Cost (Annualized Capital Cost + Operating Cost) 16,766
Emission Control Cost Calculation
Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont CostPollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 1.9 6.8 6.8 - NATotal Particulates 1.9 6.8 6.8 - NA
Nitrous Oxides (NOx) 11.6 41.3 50% 20.6 20.6 813
Sulfur Dioxide (SO2) 16.8 59.8 59.8 - NA
Sulfuric Acid Mist - - 0.0 - NAFluorides - - 0.0 - NAVolatile Organic Compounds (VOC) 1.0 3.5 3.5 - NACarbon Monoxide (CO) - - 0.0 - NALead (Pb) - - 0.0 - NA
Notes & Assumptions1 Burner cost scaled from MacTec Burner Estimate, March 2005 cost estimate
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost
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Northshore Process BoilerBART Report - Appendix A Emission Control Cost AnalysisTable 21: NOx Control - Low NOx Burner
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 49,000Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 4,900
Mn Sales Taxes 6.5% of control device cost (A) 3,185
Freight 5% of control device cost (A) 2,450Purchased Equipment Total (B) 22% 59,535
Installation
Foundations & supports 8% of purchased equip cost (B) 4,763Handling & erection 14% of purchased equip cost (B) 8,335Electrical 4% of purchased equip cost (B) 2,381
Piping 2% of purchased equip cost (B) 1,191Insulation 1% of purchased equip cost (B) 595
Painting 1% of purchased equip cost (B) 595
Installation Subtotal Standard Expenses 30% 17,861
Site Preparation, as required Site Specific NABuildings, as required Site Specific NASite Specific - Other Site Specific NA
Total Site Specific Costs NAInstallation Total 17,861
Total Direct Capital Cost, DC 77,396
Indirect Capital Costs
Engineering, supervision 10% of purchased equip cost (B) 5,954Construction & field expenses 5% of purchased equip cost (B) 2,977Contractor fees 10% of purchased equip cost (B) 5,954
Start-up 2% of purchased equip cost (B) 1,191Performance test 1% of purchased equip cost (B) 595Model Studies of purchased equip cost (B) 0Contingencies 3% of purchased equip cost (B) 1,786
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 18,456
Total Capital Investment (TCI) = DC + IC 95,851
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 95,851
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating LaborOperator 50.00 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr 478Supervisor 15% 15% of Operator Costs 72
MaintenanceMaintenance Labor 60.00 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr 574Maintenance Materials 100% of maintenance labor costs 574
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 3 kW-hr, 7650 hr/yr, 93% utilization 1,168
NA NA - NA NA - NA NA - NA NA - NA NA -
NA NA - NA NA - NA NA - NA NA - NA NA - NA NA -
NA NA -
NA NA -
NA NA -
NA NA - Total Annual Direct Operating Costs 2,866
Indirect Operating Costs
Overhead 60% of total labor and material costs 1,018
Administration (2% total capital costs) 2% of total capital costs (TCI) 1,917
Property tax (1% total capital costs) 1% of total capital costs (TCI) 959
Insurance (1% total capital costs) 1% of total capital costs (TCI) 959
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 9,048 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 13,900
Total Annual Cost (Annualized Capital Cost + Operating Cost) 16,766
See Summary page for notes and assumptions
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Northshore Process BoilerBART Report - Appendix A Emission Control Cost AnalysisTable 21: NOx Control - Low NOx Burner
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%Equipment Life 20 yearsCRF 0.0944
Replacement Catalyst: CatalystEquipment Life 2 years
CRF 0.5531
Rep part cost per unit 650 $/ft3
Amount Required 39 ft3
Catalyst Cost 28,265 Cost adjusted for freight & sales taxInstallation Labor 4,240 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts neededAnnualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3CRF 0.3811Rep part cost per unit 37.940902 $ eachAmount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales taxInstallation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical UseFlow acfm D P in H2O Efficiency Hp kW
Blower, Thermal 3,239 5 0.6 3.2 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1
Blower, Catalytic 0 23 0.6 0.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1
Oxidizer Type thermal (catalytic or thermal) 3.2
Reagent Use & Other Operating Costs Oxidizers - NA
Operating Cost Calculations Annual hours of operation: 7,650Utilization Rate: 93.0%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating LaborOp Labor 50 $/Hr 0.01 hr/8 hr shift 10 478 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yrSupervisor 15% of Op. NA 72 15% of Operator CostsMaintenanceMaint Labor 60.00 $/Hr 0.01 hr/8 hr shift 10 574 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yrMaint Mtls 100 % of Maintenance Labor NA 574 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.052 $/kwh 3.2 kW-hr 22,465 1,168 $/kwh, 3 kW-hr, 7650 hr/yr, 93% utilization
Natural Gas 2.31 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7650 hr/yr, 93% utilization
Water 0.40 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilizationCooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
Comp Air 0.32 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7650 hr/yr, 93% utilization
WW Treat Neutralization 3.80 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
SW Disposal 11.48 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization
Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization
Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7650 hr/yr, 93% utilization
Waste Recycle 1.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization1 Lime 90 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization
2 Caustic 305.21 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization
5 Oxygen 1.49 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7650 hr/yr, 93% utilization2 CO Catalyst 650 $/ft3 0 ft3 0 0 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization
1 Filter Bags 37.94 $/bag 0 bags 0 0 $/bag, 0 bags, 7650 hr/yr, 93% utilization*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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Northshore Process BoilerBART Report - Appendix A Emission Control Cost AnalysisTable 22: NOx Control - Low NOx Burner with Flue Gas Recirculation/Advanced Controls
Operating Unit: Process Boiler 1 & 2
Emission Unit Number 003 & 004 Stack/Vent Number 003 Chemical EngineeringDesign Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32º F Chemical Plant Cost IndexExpected Utilization Rate 93% Temperature 450 Deg F 1998/1999 390
Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Inflation Adj 1.19Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68º F
Dry Std Flow Rate 60,265 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs Direct Capital Costs
Purchased Equipment (A) 280,000
Purchased Equipment Total (B) 22% of control device cost (A) 340,200
Installation - Standard Costs 30% of purchased equip cost (B) 102,060 Installation - Site Specific Costs NA Installation Total 102,060
Total Direct Capital Cost, DC 442,260
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 105,462
Total Capital Investment (TCI) = DC + IC 547,722
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 2,881 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 74,628Total Annual Cost (Annualized Capital Cost + Operating Cost) 77,510
Emission Control Cost Calculation
Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont CostPollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 1.9 6.8 6.8 - NATotal Particulates 1.9 6.8 6.8 - NA
Nitrous Oxides (NOx) 11.6 41.3 75% 10.3 30.9 2,505
Sulfur Dioxide (SO2) 16.8 59.8 59.8 - NA
Sulfuric Acid Mist - - 0.0 - NAFluorides - - 0.0 - NAVolatile Organic Compounds (VOC) 1.0 3.5 3.5 - NACarbon Monoxide (CO) - - 0.0 - NALead (Pb) - - 0.0 - NA
Notes & Assumptions
1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
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Northshore Process BoilerBART Report - Appendix A Emission Control Cost AnalysisTable 22: NOx Control - Low NOx Burner with Flue Gas Recirculation/Advanced Controls
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 280,000Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 28,000
MN Sales Taxes 6.5% of control device cost (A) 18,200
Freight 5% of control device cost (A) 14,000Purchased Equipment Total (B) 22% 340,200
Installation
Foundations & supports 8% of purchased equip cost (B) 27,216Handling & erection 14% of purchased equip cost (B) 47,628Electrical 4% of purchased equip cost (B) 13,608
Piping 2% of purchased equip cost (B) 6,804Insulation 1% of purchased equip cost (B) 3,402
Painting 1% of purchased equip cost (B) 3,402
Installation Subtotal Standard Expenses 30% 102,060
Site Preparation, as required Site Specific NABuildings, as required Site Specific NASite Specific - Other Site Specific NA
Total Site Specific Costs NAInstallation Total 102,060
Total Direct Capital Cost, DC 442,260
Indirect Capital Costs
Engineering, supervision 10% of purchased equip cost (B) 34,020Construction & field expenses 5% of purchased equip cost (B) 17,010Contractor fees 10% of purchased equip cost (B) 34,020
Start-up 2% of purchased equip cost (B) 6,804Performance test 1% of purchased equip cost (B) 3,402Model Studies of purchased equip cost (B) 0Contingencies 3% of purchased equip cost (B) 10,206
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 105,462
Total Capital Investment (TCI) = DC + IC 547,722
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 547,722
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating LaborOperator 50.00 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr 478Supervisor 15% 15% of Operator Costs 72
MaintenanceMaintenance Labor 60.00 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr 574Maintenance Materials 100% of maintenance labor costs 574
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 3 kW-hr, 7650 hr/yr, 93% utilization 1,184
NA NA - NA NA - NA NA - NA NA - NA NA -
NA NA - NA NA - NA NA - NA NA - NA NA - NA NA -
NA NA -
NA NA -
NA NA -
NA NA - Total Annual Direct Operating Costs 2,881
Indirect Operating Costs
Overhead 60% of total labor and material costs 1,018
Administration (2% total capital costs) 2% of total capital costs (TCI) 10,954
Property tax (1% total capital costs) 1% of total capital costs (TCI) 5,477
Insurance (1% total capital costs) 1% of total capital costs (TCI) 5,477
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 51,701 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 74,628
Total Annual Cost (Annualized Capital Cost + Operating Cost) 77,510
See Summary page for notes and assumptions
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Northshore Process BoilerBART Report - Appendix A Emission Control Cost AnalysisTable 22: NOx Control - Low NOx Burner with Flue Gas Recirculation/Advanced Controls
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%Equipment Life 20 yearsCRF 0.0944
Replacement Catalyst: CatalystEquipment Life 2 years
CRF 0.5531
Rep part cost per unit 650 $/ft3
Amount Required 39 ft3
Catalyst Cost 28,265 Cost adjusted for freight & sales taxInstallation Labor 4,240 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts neededAnnualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3CRF 0.3811Rep part cost per unit 37.940902 $ eachAmount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales taxInstallation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical UseFlow acfm D P in H2O Efficiency Hp kW
Blower, Thermal 3,239 5 0.6 3.2 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1
Blower, Catalytic 0 23 0.6 0.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1
Oxidizer Type thermal (catalytic or thermal) 3.2
Reagent Use & Other Operating Costs Oxidizers - NA
Operating Cost Calculations Annual hours of operation: 7,650Utilization Rate: 93.0%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating LaborOp Labor 50 $/Hr 0.01 hr/8 hr shift 10 478 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yrSupervisor 15% of Op. NA 72 15% of Operator CostsMaintenanceMaint Labor 60.00 $/Hr 0.01 hr/8 hr shift 10 574 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yrMaint Mtls 100 % of Maintenance Labor NA 574 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.052 $/kwh 3.2 kW-hr 22,766 1,184 $/kwh, 3 kW-hr, 7650 hr/yr, 93% utilization
Natural Gas 2.31 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7650 hr/yr, 93% utilization
Water 0.40 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilizationCooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
Comp Air 0.32 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7650 hr/yr, 93% utilization
WW Treat Neutralization 3.80 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
SW Disposal 11.48 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization
Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization
Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7650 hr/yr, 93% utilization
Waste Recycle 1.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization1 Lime 90 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization
2 Caustic 305.21 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization
5 Oxygen 1.48526 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7650 hr/yr, 93% utilization2 CO Catalyst 650 $/ft3 0 ft3 0 0 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization
1 Filter Bags 37.940902 $/bag 0 bags 0 0 $/bag, 0 bags, 7650 hr/yr, 93% utilization*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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Northshore Process BoilerBART Report - Appendix A Emission Control Cost AnalysisTable 23: NOx Control - Low NOx Burner with Overfire Air
Operating Unit: Process Boiler 1 & 2
Emission Unit Number 003 & 004 Stack/Vent Number 003 Chemical EngineeringDesign Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32º F Chemical Plant Cost IndexExpected Utilization Rate 93% Temperature 450 Deg F 1998/1999 390
Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Inflation Adj 1.19Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68º F
Dry Std Flow Rate 60,265 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs [2] Direct Capital Costs 468000
Purchased Equipment (A) 558,000
Purchased Equipment Total (B) 22% of control device cost (A) 677,970
Installation - Standard Costs 30% of purchased equip cost (B) 203,391 Installation - Site Specific Costs NA Installation Total 203,391
Total Direct Capital Cost, DC 881,361
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 210,171
Total Capital Investment (TCI) = DC + IC 1,091,532
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 174,008 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 213,364Total Annual Cost (Annualized Capital Cost + Operating Cost) 387,372
Emission Control Cost Calculation
Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont CostPollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 1.9 6.8 6.8 - NATotal Particulates 1.9 6.8 6.8 - NA
Nitrous Oxides (NOx) 11.6 41.3 68% 13.4 27.9 13,908
Sulfur Dioxide (SO2) 16.8 59.8 59.8 - NA
Sulfuric Acid Mist - - 0.0 - NAFluorides - - 0.0 - NAVolatile Organic Compounds (VOC) 1.0 3.5 3.5 - NACarbon Monoxide (CO) - - 0.0 - NALead (Pb) - - 0.0 - NA
Notes & Assumptions
1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
2 Cost based upon Analyzing Electric Power Gneration Under the CAAA.
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Northshore Process BoilerBART Report - Appendix A Emission Control Cost AnalysisTable 23: NOx Control - Low NOx Burner with Overfire Air
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 558,000Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 55,800
MN Sales Taxes 6.5% of control device cost (A) 36,270
Freight 5% of control device cost (A) 27,900Purchased Equipment Total (B) 22% 677,970
Installation
Foundations & supports 8% of purchased equip cost (B) 54,238Handling & erection 14% of purchased equip cost (B) 94,916Electrical 4% of purchased equip cost (B) 27,119
Piping 2% of purchased equip cost (B) 13,559Insulation 1% of purchased equip cost (B) 6,780
Painting 1% of purchased equip cost (B) 6,780
Installation Subtotal Standard Expenses 30% 203,391
Site Preparation, as required Site Specific NABuildings, as required Site Specific NASite Specific - Other Site Specific NA
Total Site Specific Costs NAInstallation Total 203,391
Total Direct Capital Cost, DC 881,361
Indirect Capital Costs
Engineering, supervision 10% of purchased equip cost (B) 67,797Construction & field expenses 5% of purchased equip cost (B) 33,899Contractor fees 10% of purchased equip cost (B) 67,797
Start-up 2% of purchased equip cost (B) 13,559Performance test 1% of purchased equip cost (B) 6,780Model Studies of purchased equip cost (B) 0Contingencies 3% of purchased equip cost (B) 20,339
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 210,171
Total Capital Investment (TCI) = DC + IC 1,091,532
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,091,532
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating LaborOperator 50.00 $/Hr, 2.0 hr/8 hr shift, 7650 hr/yr 95,625Supervisor 15% 15% of Operator Costs 14,344
MaintenanceMaintenance Labor 60.00 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr 574Maintenance Materials 100% of maintenance labor costs 574
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 170 kW-hr, 7650 hr/yr, 93% utilization 62,892
NA NA - NA NA - NA NA - NA NA - NA NA -
NA NA - NA NA - NA NA - NA NA - NA NA - NA NA -
NA NA -
NA NA -
NA NA -
NA NA - Total Annual Direct Operating Costs 174,008
Indirect Operating Costs
Overhead 60% of total labor and material costs 66,670
Administration (2% total capital costs) 2% of total capital costs (TCI) 21,831
Property tax (1% total capital costs) 1% of total capital costs (TCI) 10,915
Insurance (1% total capital costs) 1% of total capital costs (TCI) 10,915
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 103,033 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 213,364
Total Annual Cost (Annualized Capital Cost + Operating Cost) 387,372
See Summary page for notes and assumptions
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Northshore Process BoilerBART Report - Appendix A Emission Control Cost AnalysisTable 23: NOx Control - Low NOx Burner with Overfire Air
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%Equipment Life 20 yearsCRF 0.0944
Replacement Catalyst: CatalystEquipment Life 2 years
CRF 0.5531
Rep part cost per unit 650 $/ft3
Amount Required 39 ft3
Catalyst Cost 28,265 Cost adjusted for freight & sales taxInstallation Labor 4,240 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts neededAnnualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3CRF 0.3811Rep part cost per unit 37.940902 $ eachAmount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales taxInstallation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical UseFlow acfm D P in H2O Efficiency Hp kW
Blower, Thermal 0 19 0.6 0.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1
Blower, Catalytic 0 23 0.6 0.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1
Oxidizer Type thermal (catalytic or thermal) 0.0
Reagent Use & Other Operating Costs Oxidizers - NA
Operating Cost Calculations Annual hours of operation: 7,650Utilization Rate: 93.0%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating LaborOp Labor 50 $/Hr 2.00 hr/8 hr shift 1,913 95,625 $/Hr, 2.0 hr/8 hr shift, 7650 hr/yrSupervisor 15% of Op. NA 14,344 15% of Operator CostsMaintenanceMaint Labor 60.00 $/Hr 0.01 hr/8 hr shift 10 574 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yrMaint Mtls 100 % of Maintenance Labor NA 574 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.052 $/kwh 170.0 kW-hr 1,209,465 62,892 $/kwh, 170 kW-hr, 7650 hr/yr, 93% utilization
Natural Gas 2.31 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7650 hr/yr, 93% utilization
Water 0.40 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilizationCooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
Comp Air 0.32 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7650 hr/yr, 93% utilization
WW Treat Neutralization 3.80 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
SW Disposal 11.48 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization
Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization
Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7650 hr/yr, 93% utilization
Waste Recycle 1.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization1 Lime 90 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization
2 Caustic 305.21 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization
5 Oxygen 1.48526 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7650 hr/yr, 93% utilization2 CO Catalyst 650 $/ft3 0 ft3 0 0 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization
1 Filter Bags 37.940902 $/bag 0 bags 0 0 $/bag, 0 bags, 7650 hr/yr, 93% utilization*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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Northshore Process BoilerBART Report - Appendix A Emission Control Cost AnalysisTable 23: Selective Catalytic Reduction - Basis Power Plant Installed Cost
Operating Unit: Process Boiler 1 & 2
Emission Unit Number 003 & 004 Stack/Vent Number 003Design Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32º FExpected Utilization Rate 93% Temperature 450 Deg F
Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3%
Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfmExpected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68º F
Dry Std Flow Rate 60,265 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs Direct Capital Costs
Purchased Equipment (A) NA
Purchased Equipment Total (B) 22% of control device cost (A) NA
Installation - Standard Costs 30% of purchased equip cost (B) NA Installation - Site Specific Costs NA Installation Total NA
Total Direct Capital Cost, DC NA
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) NA
Total Capital Investment (TCI) = DC + IC 5,563,529
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 362,636 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 756,672Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,119,307
Emission Control Cost Calculation
Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont CostPollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 1.9 6.8 6.8 - NATotal Particulates 1.9 6.8 6.8 - NA
Nitrous Oxides (NOx) 11.6 41.3 90% 4.1 37.1 30,139
Sulfur Dioxide (SO2) 16.8 59.8 59.8 - NA
Sulfuric Acid Mist - - 0.0 - NAFluorides - - 0.0 - NAVolatile Organic Compounds (VOC) 1.0 3.5 3.5 - NACarbon Monoxide (CO) - - 0.0 - NALead (Pb) - - 0.0 - NA
Notes & AssumptionsBasis for SCR control cost:
1 The SCR capital investment is from vendor estimates (Babcok Power Inc, 2005).
2 SCR catalyst quote based on information obtained from Cormetech, Inc. It is used for catalyst replacement costs.3 The total direct and indirect operating costs are based on operation and maintenance costs in the
"Pwr Plt SCR $" tab per EPA correlation of SCR costs for power plants.
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Northshore Process BoilerBART Report - Appendix A Emission Control Cost AnalysisTable 23: Selective Catalytic Reduction - Basis Power Plant Installed Cost
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) NAPurchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) NA
MN Sales Taxes 6.5% of control device cost (A) NA
Freight 5% of control device cost (A) NAPurchased Equipment Total (B) 22% NA
Installation
Foundations & supports 8% of purchased equip cost (B) NAHandling & erection 14% of purchased equip cost (B) NAElectrical 4% of purchased equip cost (B) NA
Piping 2% of purchased equip cost (B) NAInsulation 1% of purchased equip cost (B) NA
Painting 1% of purchased equip cost (B) NA
Installation Subtotal Standard Expenses 30% NA
Site Preparation, as required Site Specific NABuildings, as required Site Specific NASite Specific - Other Site Specific NA
Total Site Specific Costs NA
Installation Total NA
Total Direct Capital Cost, DC NA
Indirect Capital Costs
Engineering, supervision 10% of purchased equip cost (B) NAConstruction & field expenses 5% of purchased equip cost (B) NAContractor fees 10% of purchased equip cost (B) NA
Start-up 2% of purchased equip cost (B) NAPerformance test 1% of purchased equip cost (B) NAModel Studies of purchased equip cost (B) NAContingencies 3% of purchased equip cost (B) NA
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) NA
Total Capital Investment (TCI) = DC + IC 5,563,529
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 5,425,183
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating LaborOperator NA - Supervisor NA -
MaintenanceMaintenance Labor NA - Maintenance Materials 100% of maintenance labor costs -
Utilities, Supplies, Replacements & Waste Management
NA NA -
NA NA - NA NA - NA NA - NA NA - NA NA -
NA NA - NA NA - NA NA - NA NA - NA NA - NA NA -
NA NA -
NA NA -
CO Catalyst 650.00 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization 52,717
NA NA - Total Annual Direct Operating Costs 362,636
Indirect Operating Costs
Overhead 60% of total labor and material costs 22,032
Administration (2% total capital costs) 2% of total capital costs (TCI) 111,271
Property tax (1% total capital costs) 1% of total capital costs (TCI) 55,635
Insurance (1% total capital costs) 1% of total capital costs (TCI) 55,635
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 512,099 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 756,672
Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,119,307
See Summary page for notes and assumptions
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Northshore Process BoilerBART Report - Appendix A Emission Control Cost AnalysisTable 23: Selective Catalytic Reduction - Basis Power Plant Installed Cost
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%Equipment Life 20 yearsCRF 0.0944
Replacement Catalyst: Catalyst Estimate amount of catalyst required Equipment Life 3 years Vol. #1 5000 ft3CRF 0.3811 Flow #1 359,256 acfm Basis SCR Bids for proposed 2001 Taconite Plant
Rep part cost per unit 65 $/ft3 Flow #2 119,800 acfm
Amount Required 1667.3 ft3 Vol #2 1667.3 ft3Catalyst Cost 120,301 Cost adjusted for freight & sales taxInstallation Labor 18,045 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 138,346 Zero out if no replacement parts neededAnnualized Cost 52,717
Replacement Parts & Equipment:Equipment Life 3CRF 0.3811Rep part cost per unit 37.940902 $ eachAmount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts neededAnnualized Cost 0
Electrical UseFlow acfm D P in H2O Efficiency Hp kW
Blower, Thermal 119,800 19 0.6 443.9 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1
Blower, Catalytic 119,800 23 0.6 537.3 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1
Oxidizer Type Catalytic (catalytic or thermal) 537.3
Reagent Use & Other Operating Costs Oxidizers - NA
Operating Cost Calculations Annual hours of operation: 7,650Utilization Rate: 93.0%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating LaborOp Labor 50 $/Hr 0.5 hr/8 hr shift 0 0 $/Hr, 0.5 hr/8 hr shift, 7650 hr/yrSupervisor 15% of Op. NA - 15% of Operator CostsMaintenanceMaint Labor 60.00 $/Hr 0.5 hr/8 hr shift 0 0 $/Hr, 0.5 hr/8 hr shift, 7650 hr/yrMaint Mtls 100 % of Maintenance Labor NA 0 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.052 $/kwh 537.3 kW-hr 0 0 $/kwh, 537 kW-hr, 7650 hr/yr, 93% utilization
Natural Gas 2.31 $/mscf 14676 scfm 0 0 $/mscf, 14,676 scfm, 7650 hr/yr, 93% utilization
Water 0.40 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilizationCooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
Comp Air 0.32 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7650 hr/yr, 93% utilization
WW Treat Neutralization 3.80 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
SW Disposal 11.48 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization
Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization
Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7650 hr/yr, 93% utilization
Waste Recycle 1.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization1 Lime 90 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization
2 Caustic 305.21 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization
5 Oxygen 1.48526 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7650 hr/yr, 93% utilization2 CO Catalyst 650 $/ft3 0 ft3 0 52,717 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization
1 Filter Bags 37.940902 $/bag 0 bags 0 0 $/bag, 0 bags, 7650 hr/yr, 93% utilization*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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Northshore Process BoilerBART Report - Appendix A Emission Control Cost AnalysisTable 23: Selective Catalytic Reduction - Basis Power Plant Installed Cost
EPA SCR Cost Worksheet for Coal Fired Power Plants
Determine Comparable Boiler Size Based on Flue Gas Exhaust Ratestack exhaust flow scfm 69,510Moisture Content 10%
Stack exhaust flow dcfm 60,265
Coal F Factor dscf/MMBtu 10,000Equivalent Duty MMBtu/hr 362Est. Power Plant Efficiency 35%
Watt per Btu/hr 0.29307
Equivalent Power Plant kW 37,090Uncontrolled NOx t/yr 41Annual Operating Hours 8,000
Uncontrolled NOx lb/MMBtu 0.029
Plant Capacity kW A 37,090
Uncontrolled NOx lb/MMBtu B 0.029NOx Reduction Efficiency C 90Capital Cost $/kW D $150.00 Total Capital Cost $5,563,529
D= 75*(300,000((B/1.5)^0.05*(C/100)^0.04/A)^0.35
Plant Capacity kW A 37,090
Capital Cost $/kW D $150.00Fixed O&M Cost, $/yr E $36,719
E = D*A*0.0066
Plant Capacity kW A 37,090
Uncontrolled NOx lb/MMBtu B 0.03NOx Reduction Efficiency C 90Capital Cost $/kW D $150.00Annual Capacity Factor G 0.82
Heat Input MMBtu/hr H 6000
Variable O&M Cost $/yr F $362,636
F = G*(225(0.37*B*H*C/100*8760/2000)*1.005+0.075*D*A*((B/1.5)^0.05*(c/100) .̂4)+1.45*A)Note: used worst case factor for catalyst replacement
Note: Capital Cost kW is estimate from Tom Robinson @ Babcock Power Inc.
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Northshore Process Boiler
BART Report - Appendix A Emission Control Cost Analysis
Table 25: Selective Non-Catalytic Reduction SNCR
Operating Unit: Process Boiler 1 & 2
Emission Unit Number 003 & 004 Stack/Vent Number 003 Chemical Engineering
Design Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32º F Chemical Plant Cost IndexExpected Utilization Rate 93% Temperature 450 Deg F 1998/1999 390
Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Inflation Adj 1.19Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68º F
Dry Std Flow Rate 60,265 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs Control Eff NOx in lb/MMBtu Year Direct Capital Costs EPRI Correlation, 1998 $'s 50% 0.17 1998 551,300
Purchased Equipment (A) 2005 657,319
Purchased Equipment Total (B) 0% of control device cost (A) 657,319
Installation - Standard Costs 15% of purchased equip cost (B) 118,317
Installation - Site Specific Costs 0
Installation Total 0
Total Direct Capital Cost, DC 0
Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0
Total Capital Investment (TCI) = DC + IC 925,876
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 153,526
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 96,655Total Annual Cost (Annualized Capital Cost + Operating Cost) 250,181
Emission Control Cost Calculation
Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont CostPollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem
PM10 1.9 6.8 6.8 - NATotal Particulates 1.9 6.8 6.8 - NA
Nitrous Oxides (NOx) 11.6 41.3 50% 20.6 20.6 12,126
Sulfur Dioxide (SO2) 16.8 59.8 59.8 - NA
Sulfuric Acid Mist - - 0.0 - NA
Fluorides - - 0.0 - NA
Volatile Organic Compounds (VOC) 1.0 3.5 3.5 - NA
Carbon Monoxide (CO) - - 0.0 - NALead (Pb) - - 0.0 - NA
Notes & Assumptions
1 Cost Estimate from EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1
3 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.19
4 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.22
5 Water use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.25
6 Additional Fuel Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.29
7 SNCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.238 SNCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.21
9 No coal ash disposal cost; fuel is natural gas
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Northshore Process Boiler
BART Report - Appendix A Emission Control Cost Analysis
Table 25: Selective Non-Catalytic Reduction SNCR
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1)
Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 657,319Instrumentation 10% of control device cost (A) NA
MN Sales Taxes 6.5% of control device cost (A) NA
Freight 5% of control device cost (A) NAPurchased Equipment Total (A) 657,319
Indirect Installation
General Facilities 5% of purchased equip cost (A) 32,866
Engineering & Home Office 10% of purchased equip cost (A) 65,732Process Contingency 5% of purchased equip cost (A) 32,866
Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 131,464
Project Contingency ( C) 15% of (A + B) 118,317
Total Plant Cost D A + B + C 907,100
Allowance for Funds During Construction (E) 0 for SNCR 0
Royalty Allowance (F) 0 for SNCR 0
Pre Production Costs (G) 2% of (D+E)) 18,142
Inventory Capital Reagent Vol * $/gal 634
Initial Catalyst and Chemicals 0 for SNCR 0
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 925,876
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 925,876
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating LaborOperator NA -
Supervisor NA -
Maintenance
Maintenance Total 15.00 % of Total Capital Investment 138,881
Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management
NA NA -
Natural Gas 2.31 $/mscf, 0 scfh, 7650 hr/yr, 93% utilization 1,215
Water 0.40 $/mgal, 4 gph, 7650 hr/yr, 93% utilization 13
NA NA -
NA NA - NA NA -
NA NA -
NA NA -
NA NA -
NA NA -
NA NA -
NA NA -
Urea 405.00 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization 13,416
NA NA -
NA NA -
NA NA - Total Annual Direct Operating Costs 153,526
Indirect Operating Costs
Overhead NA of total labor and material costs NA
Administration (2% total capital costs) NA of total capital costs (TCI) NA
Property tax (1% total capital costs) NA of total capital costs (TCI) NA
Insurance (1% total capital costs) 0 of total capital costs (TCI) 9,259
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 87,396 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 96,655
Total Annual Cost (Annualized Capital Cost + Operating Cost) 250,181
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Northshore Process Boiler
BART Report - Appendix A Emission Control Cost Analysis
Table 25: Selective Non-Catalytic Reduction SNCR
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 yearsCRF 0.0944
Replacement Catalyst <- Enter Equipment Name to Get CostEquipment Life 5 years
CRF 0.2439
Rep part cost per unit 500 $/ft3
Amount Required 12 ft3
Packing Cost 6,690 Cost adjusted for freight & sales taxInstallation Labor 1,004 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts neededAnnualized Cost 0
Replacement Parts & Equipment: <- Enter Equipment Name to Get Cost
Equipment Life 2 years
CRF 0.0000
Rep part cost per unit 38 $/ft3
Amount Required 0 Cages
Total Rep Parts Cost 0 Cost adjusted for freight & sales tax See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs
Installation Labor 0 10 min per bag, Labor + Overhead (68% = $29.65/hr)
Total Installed Cost 0 Zero out if no replacement parts needed EPA CCM list replacement times from 5 - 20 min per bag.Annualized Cost 0
Electrical Use
NOx in 0.17 lb/MMBtu kWNSR 1.12
Power 0.0
Total 0.0
Reagent Use & Other Operating Costs Urea Use
NOx in 0.17 lb/MMBtu 5 lb/hr Neat
Efficiency 50% 50% solution 71.0 lb/ft3 Density 50% Solution
Duty 70 MMBtu/hr 9 lb/hr 1.0 gal/hr
Volume 14 day inventory 330 gal $634 Inventory Cost
Water Use 4 gal/hr Inject at 10% solution
Fuel Use 0.1 MMBtu/hr 0.1 mscfh natural gas
Ash Generation 0.6 lb/hr
Operating Cost Calculations Annual hours of operation: 7,650
Utilization Rate: 93.0%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 50 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr
Supervisor 15% of Op. NA - 15% of Operator Costs
Maintenance
Maintenance Total 15 % of Total Capital Investment 138,881 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.052 $/kwh 0.0 kW-hr 0 0 $/kwh, 0 kW-hr, 7650 hr/yr, 93% utilization
Natural Gas 2.31 $/mscf 0.1 scfh 526 1,215 $/mscf, 0 scfh, 7650 hr/yr, 93% utilization
Water 0.40 $/mgal 4.5 gph 32 13 $/mgal, 4 gph, 7650 hr/yr, 93% utilizationCooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
Comp Air 0.32 $/mscf 0.0 scfm/kacfm** 0 0 $/mscf, 0 scfm/kacfm**, 7650 hr/yr, 93% utilization
WW Treat Neutralization 3.80 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
SW Disposal 11.48 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization
Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization
Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7650 hr/yr, 93% utilization
Waste Recycle 1.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization1 Lime 90 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization
3 Urea 405 $/ton 0.0047 ton/hr 33 13,416 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization
5 Oxygen 1.48526 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7650 hr/yr, 93% utilization1 SCR Catalyst 500 $/ft3 0 ft
30 0 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization
1 Filter Bags 37.940902 $/bag 0 bags 0 0 $/bag, 0 bags, 7650 hr/yr, 93% utilization** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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Northshore Process Boiler
BART Report - Appendix A Emission Control Cost Analysis
Table 26: SO2 Control - Wet ESP
Operating Unit: Process Boiler 1 & 2
Emission Unit Number 003 & 004 Stack/Vent Number 003 Chemical Engineering
Design Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32º F Chemical Plant Cost Index
Expected Utilization Rate 93% Temperature 450 Deg F 1998/1999 390
Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68º F
Dry Std Flow Rate 60,265 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs Year
Direct Capital Costs (1)
Purchased Equipment (A) 2005 5,519,073 2,687,838
Purchased Equipment Total (B) 22% of control device cost (A) 3,265,724
Installation - Standard Costs 69% of purchased equip cost (B) 2,253,349
Installation - Site Specific Costs 0
Installation Total 2,253,349
Total Direct Capital Cost, DC 5,519,073
Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 1,861,462
Total Capital Investment (TCI) = DC + IC 11,808,857
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 742,986
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,504,739
Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,247,725
Emission Control Cost Calculation
Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost (5)
Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem
PM10 8.3 1.5 0.021 5.3 3.0 758,310
Total Particulates 8.3 1.5 0.021 5.3 3.0 758,310
Nitrous Oxides (NOx) 50.9 - 50.9 - NA
Sulfur Dioxide (SO2) 73.4 3.4 0.048 11.9 61.5 36,558
Notes & Assumptions
1 Total Direct Capital Cost Cost Estimated, 19% as compared to dry ESP cost.
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3
3 ESP Maintenance costs Eq 3.45 EPA Cont Cost Manual Section 6 Chapter 3
4 ESP Maintenance Materials Eq 3.45 EPA Cont Cost Manual Section 6 Chapter 3
5 High control cost is due to the small additional decrease in emissions as compared to existing controls.
6 CUECost Workbook Version 1.0, USEPA Document Page 2.
Notes to User
1) Enter Data in Blue Highlighted Cells Throughout Worksheet
2) Control cost basis calculated by % control efficiency or concentration. Enter valued in appropriate yellow highlighted cell
2a) If using % control efficiency, enter data only in coluND F, do not enter concentration units in coluND H
2b) If using concentration, enter concentration data in coluND Fand units in coluND H
3) If not data entered in colums F and G; control cost will show NA. This was done to prevent divide by zero errors
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SO2 WESP 9/6/2006 Page 20 of 42
4) See comments in cell V88 regarding selection of reagents, catalysts and supplies
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Northshore Process Boiler
BART Report - Appendix A Emission Control Cost Analysis
Table 26: SO2 Control - Wet ESP
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 2,687,838
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC
Instrumentation 10% of control device cost (A) 268,784
MN Sales Taxes 6.5% of control device cost (A) 174,709
Freight 5% of control device cost (A) 134,392
Purchased Equipment Total (B) 22% 3,265,724
Installation
Foundations & supports 4% of purchased equip cost (B) 130,629
Handling & erection 50% of purchased equip cost (B) 1,632,862
Electrical 8% of purchased equip cost (B) 261,258
Piping 3% of purchased equip cost (B) 97,972
Insulation 2% of purchased equip cost (B) 65,314
Painting 2% of purchased equip cost (B) 65,314
Installation Subtotal Standard Expenses 69% 2,253,349
Installation Total 2,253,349
Total Direct Capital Cost, DC 5,519,073
Indirect Capital Costs
Engineering, supervision 20% of purchased equip cost (B) 653,145Construction & field expenses 20% of purchased equip cost (B) 653,145
Contractor fees 10% of purchased equip cost (B) 326,572
Start-up 1% of purchased equip cost (B) 32,657
Performance test 1% of purchased equip cost (B) 32,657Model Studies 2% of purchased equip cost (B) 65,314
Contingencies 3% of purchased equip cost (B) 97,972
Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 1,861,462
7,380,535
Retrofit TCI (TCI*1.6) (6) 11,808,857
Total Capital Investment (TCI) = DC + ICSite Preparation, as required site preparation and foundations 0
Buildings, as required structural steel 0
Site Specific - Other Replacement Power - One 14 day outage [8] 0
Total Site Specific Costs 0
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 11,808,857
OPERATING COSTSDirect Annual Operating Costs, DC
Operating Labor
Operator 50.00 $/Hr, 1.0 hr/8 hr shift, 7650 hr/yr 47,813
Supervisor 48% % of Operator Costs. 22,950
Maintenance
Maintenance Labor (3) 66,249 ft2 grid area, 0.8 $/ft2 of grid area 54,656
Maintenance Materials (4) 1 1% of purchased equipment cost 32,657
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 228 kW-hr, 7650 hr/yr, 93% utilization 84,287
NA NA -
Water 0.40 $/mgal, 24 gpm, 7650 hr/yr, 93% utilization 4,091
NA NA -
NA NA -
NA NA -
NA NA -
SW Disposal 11.48 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization 77
NA NA -
NA NA -
NA NA -
NA NA -
Caustic 305.21 $/ton, 227 lb/hr, 7650 hr/yr, 93% utilization 246,456
NA NA -
Lost Revenue - Fly Ash NA 250,000
NA NA -
Total Annual Direct Operating Costs 742,986
Indirect Operating Costs
Overhead 60% of total labor and material costs 94,845
Administration (2% total capital costs) 2% of total capital costs (TCI) 147,611
Property tax (1% total capital costs) 1% of total capital costs (TCI) 73,805 1
Insurance (1% total capital costs) 1% of total capital costs (TCI) 73,805 2
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,114,673 5
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,504,739 1
1
Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,247,725
See Summary page for notes and assumptions
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SO2 WESP 9/6/2006 Page 22 of 42
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Northshore Process Boiler
BART Report - Appendix A Emission Control Cost Analysis
Table 26: SO2 Control - Wet ESP
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalyst:
Equipment Life 5 years
CRF 0.0000
Rep part cost per unit 500 $/ft3
Amount Required 0 ft3
Packing Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit 37.94090199 $ each
Amount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kW
Blower Baghouse & ESP 119,800 4.48 97.1 EPA Cost Cont Manual 6th ed Section 6 Chapter 3 Eq 3.46
Liq flow Liquid SPGR ∆ P ft H2O Efficiency Hp kW
WESP Pump 120 gpm 1.000 40 0.5 1.8 EPA Cost Cont Manual 6th ed Section 6 Chapter 3 Eq 3.47
WESP H2O WW Disch 24 gpm 1.000 40 0.5 0.4 EPA Cost Cont Manual 6th ed Section 6 Chapter 3 Eq 3.47
SCA Factor 553 ft2/1000 acfm
ESP Grid 66,249 ft2 1.94E-03 kW/ft2 128.5 EPA Cost Cont Manual 6th ed Section 6 Chapter 3 Eq 3.48
Total 227.8
Reagent Use & Other Operating Costs
WESP Pump 23,960 acfm 5 gpm/kacfm 120 gpm EPA Cost Cont Manual 6th ed Section 6 Chapter 3.4.1.9
WESP Water Makeup Rate/WW Disch 20% of circulating water rate = 24 gpm
Operating Cost Calculations Annual hours of operation: 7,650
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 50.00 $/Hr 1.0 hr/8 hr shift 956 47,813 $/Hr, 1.0 hr/8 hr shift, 7650 hr/yr
Supervisor 48% of Operator Costs. NA 22,950 % of Operator Costs.
Maintenance
Maint Labor 66,249 ft2 grid area 0.825 $/ft2 of grid area 54,656 ft2 grid area, 0.8 $/ft2 of grid area
Maint Mtls 1 % of purchased equipment cost NA 32,657 1% of purchased equipment cost
Utilities, Supplies, Replacements & Waste Management
Electricity 0.052 $/kwh 227.8 kW-hr 1,620,903 84,287 $/kwh, 228 kW-hr, 7650 hr/yr, 93% utilization
Natural Gas 2.31 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7650 hr/yr, 93% utilization
Water 0.40 $/mgal 24.0 gpm 10,228 4,091 $/mgal, 24 gpm, 7650 hr/yr, 93% utilization
Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
Comp Air 0.32 $/mscf 0 kscfm 0 0 $/mscf, 0 kscfm, 7650 hr/yr, 93% utilization
WW Treat Neutralization 3.80 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
SW Disposal 11.48 $/ton 0.0 ton/hr 7 77 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization
Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization
Waste Transport 0.56 $/ton-mi 0.0 Mi 0 0 $/ton-mi, 0 Mi, 7650 hr/yr, 93% utilization
PRB Coal 1 $/ton 0.0 ton/hr 0 0 $/ton, $5.1MM/yr extra for PRB - $1MM/yr Lower O&M Cost
Lime 90.0 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization
Caustic 305.21 $/ton 227.0 lb/hr 807 246,456 $/ton, 227 lb/hr, 7650 hr/yr, 93% utilization
Oxygen 1.48526 Mscf 0.0 kscf/hr 0 0 Mscf, 0 kscf/hr, 7650 hr/yr, 93% utilization
SCR Catalyst 500 $/ft3 0 ft3 0 0 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization
Filter Bags 37.94 $/bag 0 bags 0 0 $/bag, 0 bags, 7650 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Note: Select reagent, catayst and repacement parts by entering number in coluND U. Unhide Col U to enter choice.
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Northshore Process Boiler
BART Report - Appendix A Emission Control Cost Analysis
Table 27: SO2 Absorber
Operating Unit: Process Boiler 1 & 2
Emission Unit Number 003 & 004 Stack/Vent Number 003 Chemical Engineering
Design Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32º F Chemical Plant Cost Index
Expected Utilization Rate 93% Temperature 450 Deg F 1998/1999 390
Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68º F
Dry Std Flow Rate 60,265 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs Year
Direct Capital Costs (1) 2002 [1] 1,908,056
Purchased Equipment (A) 2005 2,274,990 1,012,119
Purchased Equipment Total (B) 22% of control device cost (A) 1,229,724
Installation - Standard Costs 85% of purchased equip cost (B) 1,045,266
Installation - Site Specific Costs 0
Installation Total 1,045,266
Total Direct Capital Cost, DC 2,274,990
Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 184,459
Total Capital Investment (TCI) = DC + IC 3,935,118
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 598,134
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 520,746
Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,118,879
Emission Control Cost Calculation
Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost
Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem
PM10 8.3 - 8.3 - NA
Total Particulates 8.3 - 8.3 - NA
Nitrous Oxides (NOx) 50.9 - 50.9 - NA
Sulfur Dioxide (SO2) 73.4 3.4 0.05 11.9 61.5 18,198
Notes & Assumptions
1 Original estimate was from Durr. Use 0.6 Powerlaw factor to adjust price to stack flow rate from bid basis of 500,000 acfm.
2 Liquid/Gas ratio = 38 L/G = Gal/1,000 acf.
3 Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate.
4 Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition.
5 CUECost Workbook Version 1.0, USEPA Document Page 2.
Notes to User
1) Enter Data in Blue Highlighted Cells Throughout Worksheet
2) Control cost basis calculated by % control efficiency or concentration. Enter valued in appropriate yellow highlighted cell
2a) If using % control efficiency, enter data only in coluND F, do not enter concentration units in coluND H
2b) If using concentration, enter concentration data in coluND Fand units in coluND H
3) If not data entered in colums F and G; control cost will show NA. This was done to prevent divide by zero errors
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SO2 Absorber 9/6/2006 Page 25 of 42
4) See comments in cell V88 regarding selection of reagents, catalysts and supplies
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Northshore Process Boiler
BART Report - Appendix A Emission Control Cost Analysis
Table 27: SO2 Absorber
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 1,012,119
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC
Instrumentation 10% of control device cost (A) 101,212
MN Sales Taxes 6.5% of control device cost (A) 65,788
Freight 5% of control device cost (A) 50,606
Purchased Equipment Total (B) 22% 1,229,724
Installation
Foundations & supports 12% of purchased equip cost (B) 147,567
Handling & erection 40% of purchased equip cost (B) 491,890
Electrical 1% of purchased equip cost (B) 12,297
Piping 30% of purchased equip cost (B) 368,917
Insulation 1% of purchased equip cost (B) 12,297
Painting 1% of purchased equip cost (B) 12,297
Installation Subtotal Standard Expenses 85% 1,045,266
Installation Total 1,045,266
Total Direct Capital Cost, DC 2,274,990
Indirect Capital Costs
Engineering, supervision 5% of purchased equip cost (B) 61,486Construction & field expenses 0% of purchased equip cost (B) 0
Contractor fees 5% of purchased equip cost (B) 61,486
Start-up 1% of purchased equip cost (B) 12,297
Performance test 1% of purchased equip cost (B) 12,297Model Studies NA of purchased equip cost (B) NA
Contingencies 3% of purchased equip cost (B) 36,892
Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 184,459
Total Capital Investment (TCI) = DC + IC 2,459,448
Retrofit TCI (TCI*1.6) (5) 3,935,118
Site Preparation, as required site preparation and foundations 0
Buildings, as required structural steel 0
Site Specific - Other Replacement Power - One 14 day outage [8] 0
Total Site Specific Costs 0
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 3,935,118
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 50.00 $/Hr, 0.5 hr/8 hr shift, 7650 hr/yr 23,906
Supervisor 15% 15% of Operator Costs 3,586
Maintenance
Maintenance Labor 60.00 $/Hr, 0.5 hr/8 hr shift, 7650 hr/yr 28,688
Maintenance Materials 100% of maintenance labor costs 28,688
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 246 kW-hr, 7650 hr/yr, 93% utilization 91,145
NA NA -
Water 0.40 $/mgal, 112 gpm, 7650 hr/yr, 93% utilization 19,194
NA NA -
NA NA -
WW Treat Neutralization 3.80 $/mgal, 91 gpm, 7650 hr/yr, 93% utilization 147,690
NA NA -
SW Disposal 11.48 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization 77
NA NA -
NA NA -
NA NA -
Lime 90.00 $/ton, 16 lb/hr, 7650 hr/yr, 93% utilization 5,161
NA NA -
NA NA -
Lost Revenue - Fly Ash NA 250,000
NA NA -
Total Annual Direct Operating Costs 598,134
Indirect Operating Costs
Overhead 60% of total labor and material costs 50,920
Administration (2% total capital costs) 2% of total capital costs (TCI) 49,189
Property tax (1% total capital costs) 1% of total capital costs (TCI) 24,594 1
Insurance (1% total capital costs) 1% of total capital costs (TCI) 24,594 2
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 371,447 5
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 520,746 1
1
Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,118,879
See Summary page for notes and assumptions
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SO2 Absorber 9/6/2006 Page 27 of 42
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SO2 Absorber 9/6/2006 Page 28 of 42
Northshore Process Boiler
BART Report - Appendix A Emission Control Cost Analysis
Table 27: SO2 Absorber
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalyst:
Equipment Life 5 years
CRF 0.0000
Rep part cost per unit 500 $/ft3
Amount Required 0 ft3
Packing Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit 37.94 $ each
Amount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kW
Blower, Scrubber 119,800 8.55 0.7 - 171.2 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48
Flow Liquid SPGR ∆ P ft H2O Efficiency Hp kW
Circ Pump 4,552 gpm 1 60 0.7 - 73.4 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
H2O WW Disch 112 gpm 1 60 0.7 - 1.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
Other
Total 246.4
Reagent Use & Other Operating Costs
Caustic Use 16.75 lb/hr SO2 2.50 lb NaOH/lb SO2 41.88 lb/hr Caustic
Lime Use 16.75 lb/hr SO2 0.96 lb Lime/lb SO2 16.12 lb/hr lime, lime addition at 1.1 times the stoichiometric ratio
Liquid/Gas ratio (2) 38.0 * L/G = Gal/1,000 acf
Circulating Water Rate 4,552 gpm
Water Makeup Rate/WW Disch = (3) 2.0% of circulating water rate + evap. loss = 112 gpm
Evaopration Loss = (4) 21.36 gpm
Pollutant BART Baseline Emissions Control Eff (%) Cont. Emis (lb/MMBtu)
T/yr lb/MMBtu lb/hr 80% 0.05
NOx 50.90 0.166071429 11.625
SO2 73.40 0.239285714 16.75
Operating Cost Calculations Annual hours of operation: 7,650
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 478 23,906 $/Hr, 0.5 hr/8 hr shift, 7650 hr/yr
Supervisor 15% of Op. NA 3,586 15% of Operator Costs
Maintenance
Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 478 28,688 $/Hr, 0.5 hr/8 hr shift, 7650 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 28,688 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.052 $/kwh 246.4 kW-hr 1,752,797 91,145 $/kwh, 246 kW-hr, 7650 hr/yr, 93% utilization
Natural Gas 2.31 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7650 hr/yr, 93% utilization
Water 0.40 $/mgal 112.4 gpm 47,984 19,194 $/mgal, 112 gpm, 7650 hr/yr, 93% utilization
Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
Comp Air 0.32 $/mscf 0 kscfm 0 0 $/mscf, 0 kscfm, 7650 hr/yr, 93% utilization
WW Treat Neutralization 3.80 $/mgal 91.0 gpm 38,866 147,690 $/mgal, 91 gpm, 7650 hr/yr, 93% utilization
WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
SW Disposal 11.48 $/ton 0.0 ton/hr 7 77 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization
Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization
Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7650 hr/yr, 93% utilization
PRB Coal 1 $/ton 0.0 ton/hr 0 0 $/ton, $5.1MM/yr extra for PRB - $1MM/yr Lower O&M Cost
Lime 90.0 $/ton 16.1 lb/hr 57 5,161 $/ton, 16 lb/hr, 7650 hr/yr, 93% utilization
Caustic 305.21 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization
Oxygen 1.48526 Mscf 0.0 kscf/hr 0 0 Mscf, 0 kscf/hr, 7650 hr/yr, 93% utilization
SCR Catalyst 500 $/ft3 0 ft3 0 0 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization
Filter Bags 37.94 $/bag 0 bags 0 0 $/bag, 0 bags, 7650 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Note: Select reagent, catayst and repacement parts by entering number in coluND U. Unhide Col U to enter choice.
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls
SO2 Absorber 9/6/2006 Page 29 of 42
Northshore Process Boiler
BART Report - Appendix A Emission Control Cost Analysis
Table 28: SO2 Control - Spray Dryer and Baghouse
Operating Unit: Process Boiler 1 & 2
Emission Unit Number 003 & 004 Stack/Vent Number 003 Chemical Engineering
Design Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32º F Chemical Plant Cost Index
Expected Utilization Rate 93% Temperature 450 Deg F 1998/1999 390
Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68º F
Dry Std Flow Rate 60,265 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs Year
Direct Capital Costs (1) 2002 [1] 7,786,400
Purchased Equipment (A) 2005 9,283,785 4,391,365
Purchased Equipment Total (B) 22% of control device cost (A) 5,335,508
Installation - Standard Costs 74% of purchased equip cost (B) 3,948,276
Installation - Site Specific Costs 0
Installation Total 3,948,276
Total Direct Capital Cost, DC 9,283,785
Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 800,326
Total Capital Investment (TCI) = DC + IC (5) 16,134,577
Operating Costs (2)
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 693,518
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,061,186
Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,754,704
Emission Control Cost Calculation
Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost
Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem
PM10 8.3 - 8.3 - NA
Total Particulates 8.3 - 8.3 - NA
Nitrous Oxides (NOx) 50.9 - 50.9 - NA
Sulfur Dioxide (SO2) 73.4 3.4 0.05 11.9 61.5 44,804
Notes & Assumptions
1 Stone and Webster 2002 total direct installed cost estimate adjusted for inflation
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1
3 Compressed air for baghouse assumed to be 2 scfm / 1000 acfm EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1.5.1.8
4 Bag replacement at 10 min/bag EPA Cost Cont Manual 6th ed Section 6 Chapter 1.5.1.4 lists replacement times from 5 - 20 min per bag.
5 Bag replacement costs for baghouse need to be updated. Bag costs from EPA example calculations were used.
6 Dry scrubbing SO2 costs include addition of a baghouse. Assumed that the existing baghouse could not handle additional loading.
7 CUECost Workbook Version 1.0, USEPA Document Page 2.
Notes to User
1) Enter Data in Blue Highlighted Cells Throughout Worksheet
2) Control cost basis calculated by % control efficiency or concentration. Enter valued in appropriate yellow highlighted cell
2a) If using % control efficiency, enter data only in coluND F, do not enter concentration units in coluND H
2b) If using concentration, enter concentration data in coluND Fand units in coluND H
3) If not data entered in colums F and G; control cost will show NA. This was done to prevent divide by zero errors
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Spray Dry Baghouse 9/6/2006 Page 30 of 42
4) See comments in cell V88 regarding selection of reagents, catalysts and supplies
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Spray Dry Baghouse 9/6/2006 Page 31 of 42
Northshore Process Boiler
BART Report - Appendix A Emission Control Cost Analysis
Table 28: SO2 Control - Spray Dryer and Baghouse
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 4,391,365
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC
Instrumentation 10% of control device cost (A) 439,136
MN Sales Taxes 6.5% of control device cost (A) 285,439
Freight 5% of control device cost (A) 219,568
Purchased Equipment Total (B) 22% 5,335,508
Installation
Foundations & supports 4% of purchased equip cost (B) 213,420
Handling & erection 50% of purchased equip cost (B) 2,667,754
Electrical 8% of purchased equip cost (B) 426,841
Piping 1% of purchased equip cost (B) 53,355
Insulation 7% of purchased equip cost (B) 373,486
Painting 4% of purchased equip cost (B) 213,420
Installation Subtotal Standard Expenses 74% 3,948,276
Installation Total 3,948,276
Total Direct Capital Cost, DC 9,283,785
Indirect Capital Costs
Engineering, supervision 5% of purchased equip cost (B) 266,775
Construction & field expenses 0% of purchased equip cost (B) 0Contractor fees 5% of purchased equip cost (B) 266,775
Start-up 1% of purchased equip cost (B) 53,355
Performance test 1% of purchased equip cost (B) 53,355
Model Studies NA of purchased equip cost (B) NA
Contingencies 3% of purchased equip cost (B) 160,065
Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 800,326
Total Capital Investment (TCI) = DC + IC 10,084,111
Retrofit TCI (TCI*1.6) (7) 16,134,577
Site Preparation, as required site preparation and foundations 0
Buildings, as required structural steel 0
Site Specific - Other Replacement Power - One 14 day outage [8] 0
Total Site Specific Costs 0
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 16,134,577
OPERATING COSTSDirect Annual Operating Costs, DC
Operating Labor
Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 7650 hr/yr 95,625
Supervisor 15% 15% of Operator Costs 14,344
Maintenance
Maintenance Labor 60.00 $/Hr, 1.0 hr/8 hr shift, 7650 hr/yr 57,375
Maintenance Materials 100% of maintenance labor costs 57,375
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 217 kW-hr, 7650 hr/yr, 93% utilization 80,220
NA NA -
Water 0.40 $/mgal, 141 gpm, 7650 hr/yr, 93% utilization 24,000
NA NA -
Comp Air 0.32 $/mscf, 2 scfm/kacfm, 7650 hr/yr, 93% utilization 32,391
NA NA -
NA NA -
SW Disposal 11.48 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization 77
NA NA -
NA NA -
NA NA -
Lime 90.00 $/ton, 16 lb/hr, 7650 hr/yr, 93% utilization 5,161
NA NA -
Lost Revenue - Fly Ash NA 250,000
NA NA -
Filter Bags 37.94 $/bag, 0 bags, 7650 hr/yr, 93% utilization 76,951
Total Annual Direct Operating Costs 693,518
Indirect Operating Costs
Overhead 60% of total labor and material costs 134,831
Administration (2% total capital costs) 2% of total capital costs (TCI) 201,682
Property tax (1% total capital costs) 1% of total capital costs (TCI) 100,841
Insurance (1% total capital costs) 1% of total capital costs (TCI) 100,841
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,522,990
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,061,186
Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,754,704
See Summary page for notes and assumptions
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Spray Dry Baghouse 9/6/2006 Page 32 of 42
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Spray Dry Baghouse 9/6/2006 Page 33 of 42
Northshore Process Boiler
BART Report - Appendix A Emission Control Cost Analysis
Table 28: SO2 Control - Spray Dryer and Baghouse
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalsyt:
Equipment Life 5 years
CRF 0.0000
Rep part cost per unit 500 $/ft3
Amount Required 0 ft3
Total Rep Parts Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment: Filter bags & cages (4)
Equipment Life 4 years
CRF 0.2952
Rep part cost per unit 38 $/bag
Amount Required 4410
Total Rep Parts Cost 186,561 Cost adjusted for freight & sales tax
Installation Labor 74,088 10 min per bag, Labor + Overhead (68% = $29.65/hr) EPA Cost Cont Manual 6th ed Section 6 Chapter 1.5.1.4
Total Installed Cost 260,649 Zero out if no replacement parts needed lists replacement times from 5 - 20 min per bag.
Annualized Cost 76,951
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kW
Blower, Baghouse 119,800 10 216.8
Baghouse Shaker 0.0 Gross fabric area ft2 0 EPA Cost Cont Manual 6th ed Section 6 Chapter 1 Eq 1.14
Other
Other
Other
Other
Other
Total 216.8
Baghouse Filter Cost See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs
Gross BH Filter Area 0 ft2
Cages 0 ft long 0 in dia 0.00 area/cage ft2 0.000 $/cage
Bags 0 $/ft2 of fabric 0.00 $/bag
H2O Use (1) 140.56 gpm 0.000 Total
Lime Use 16.75 lb/hr SO2 0.96 lb Lime/lb SO2 16.12 lb/hr lime, lime addition at 1.1 times the stoichiometric ratio
Pollutant BART Baseline Emissions Control Eff (%) Cont. Emis (lb/MMBtu)
T/yr lb/MMBtu lb/hr 80% 0.05
NOx 50.90 0.166071429 11.625
SO2 73.40 0.239285714 16.75
Operating Cost Calculations Annual hours of operation: 7,650
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 50.00 $/Hr 2.0 hr/8 hr shift 1,913 95,625 $/Hr, 2.0 hr/8 hr shift, 7650 hr/yr
Supervisor 15% of Op. NA 14,344 15% of Operator Costs
Maintenance
Maint Labor 60.00 $/Hr 1.0 hr/8 hr shift 956 57,375 $/Hr, 1.0 hr/8 hr shift, 7650 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 57,375 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.052 $/kwh 216.8 kW-hr 1,542,694 80,220 $/kwh, 217 kW-hr, 7650 hr/yr, 93% utilization
Natural Gas 2.31 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7650 hr/yr, 93% utilization
Water 0.40 $/mgal 140.6 gpm 60,000 24,000 $/mgal, 141 gpm, 7650 hr/yr, 93% utilization
Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
(3) Comp Air 0.32 $/mscf 2 scfm/kacfm 102,278 32,391 $/mscf, 2 scfm/kacfm, 7650 hr/yr, 93% utilization
WW Treat Neutralization 3.80 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
SW Disposal 11.48 $/ton 0.0 ton/hr 7 77 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization
Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization
Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7650 hr/yr, 93% utilization
PRB Coal 1 $/ton 0.0 ton/hr 0 0 $/ton, $5.1MM/yr extra for PRB - $1MM/yr Lower O&M Cost
1 Lime 90.0 $/ton 16.1 lb/hr 57 5,161 $/ton, 16 lb/hr, 7650 hr/yr, 93% utilization
2 Caustic 305.21 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization
5 Oxygen 1.48526 Mscf 0.0 kscf/hr 0 0 Mscf, 0 kscf/hr, 7650 hr/yr, 93% utilization
1 SCR Catalyst 500 $/ft3 0 ft3 0 0 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization
1 Filter Bags 37.940902 $/bag 0 bags NA 76,951 $/bag, 0 bags, 7650 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Note: Select reagent, catayst and repacement parts by entering number in coluND U. Unhide Col U to enter choice.
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls
Spray Dry Baghouse 9/6/2006 Page 34 of 42
Northshore Process Boiler
BART Report - Appendix A Emission Control Cost Analysis
Table 29: SO2 Control - Dry Sorbent Injection and Baghouse
Operating Unit: Process Boiler 1 & 2
Emission Unit Number 003 & 004 Stack/Vent Number 003 Chemical Engineering
Design Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32º F Chemical Plant Cost Index
Expected Utilization Rate 93% Temperature 450 Deg F 1998/1999 390
Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68º F
Dry Std Flow Rate 60,265 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs Year
Direct Capital Costs (1) 1997 2,359,900
Purchased Equipment (A) 2005 [6] 2,813,727 1,330,934
Purchased Equipment Total (B) 22% of control device cost (A) 1,617,084
Installation - Standard Costs 74% of purchased equip cost (B) 1,196,642
Installation - Site Specific Costs 0
Installation Total 1,196,642
Total Direct Capital Cost, DC 2,813,727
Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 242,563
Total Capital Investment (TCI) = DC + IC (5) 4,890,063
Operating Costs (2)
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 693,518
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 718,670
Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,412,189
Emission Control Cost Calculation
Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost
Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem
PM10 8.3 - 8.3 - NA
Total Particulates 8.3 - 8.3 - NA
Nitrous Oxides (NOx) 50.9 - 50.9 - NA
Sulfur Dioxide (SO2) 73.4 3.4 0.05 11.9 61.5 22,969
Notes & Assumptions
1 Total Direct Capital Cost Cost Estimated using the Integrated Air Pollution Control Sytem Program Version 5a, EPA May 1999
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1
3 Compressed air for baghouse assumed to be 2 scfm / 1000 acfm EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1.5.1.8
4 Bag replacement at 10 min/bag EPA Cost Cont Manual 6th ed Section 6 Chapter 1.5.1.4 lists replacement times from 5 - 20 min per bag.
5 Dry scrubbing SO2 costs include addition of a baghouse. Assumed that the existing Ebaghouse could not handle additional loading.
6 Stone and Webster 2002 total direct installed cost estimate adjusted for inflation adjusted for costs already included
7 CUECost Workbook Version 1.0, USEPA Document Page 2.
Notes to User
1) Enter Data in Blue Highlighted Cells Throughout Worksheet
2) Control cost basis calculated by % control efficiency or concentration. Enter valued in appropriate yellow highlighted cell
2a) If using % control efficiency, enter data only in coluND F, do not enter concentration units in coluND H
2b) If using concentration, enter concentration data in coluND Fand units in coluND H
3) If not data entered in colums F and G; control cost will show NA. This was done to prevent divide by zero errors
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls
DSI Baghouse 9/6/2006 Page 35 of 42
4) See comments in cell V88 regarding selection of reagents, catalysts and supplies
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DSI Baghouse 9/6/2006 Page 36 of 42
Northshore Process Boiler
BART Report - Appendix A Emission Control Cost Analysis
Table 29: SO2 Control - Dry Sorbent Injection and Baghouse
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 1,330,934
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC
Instrumentation 10% of control device cost (A) 133,093
MN Sales Taxes 6.5% of control device cost (A) 86,511
Freight 5% of control device cost (A) 66,547
Purchased Equipment Total (B) 22% 1,617,084
Installation
Foundations & supports 4% of purchased equip cost (B) 64,683
Handling & erection 50% of purchased equip cost (B) 808,542
Electrical 8% of purchased equip cost (B) 129,367
Piping 1% of purchased equip cost (B) 16,171
Insulation 7% of purchased equip cost (B) 113,196
Painting 4% of purchased equip cost (B) 64,683
Installation Subtotal Standard Expenses 74% 1,196,642
Installation Total 1,196,642
Total Direct Capital Cost, DC (6) 2,813,727
Indirect Capital Costs
Engineering, supervision [6] 5% of purchased equip cost (B) 80,854
Construction & field expenses [6] 0% of purchased equip cost (B) 0Contractor fees [6] 5% of purchased equip cost (B) 80,854
Start-up 1% of purchased equip cost (B) 16,171
Performance test 1% of purchased equip cost (B) 16,171
Model Studies NA of purchased equip cost (B) NA
Contingencies 3% of purchased equip cost (B) 48,513
Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 242,563
Total Capital Investment (TCI) = DC + IC 3,056,290
Retrofit TCI (TCI*1.6) (7) 4,890,063
Site Preparation, as required site preparation and foundations 0
Buildings, as required structural steel 0
Site Specific - Other Replacement Power - One 14 day outage [8] 0
Total Site Specific Costs 0
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 4,890,063
OPERATING COSTSDirect Annual Operating Costs, DC
Operating Labor
Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 7650 hr/yr 95,625
Supervisor 15% 15% of Operator Costs 14,344
Maintenance
Maintenance Labor 60.00 $/Hr, 1.0 hr/8 hr shift, 7650 hr/yr 57,375
Maintenance Materials 100% of maintenance labor costs 57,375
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 217 kW-hr, 7650 hr/yr, 93% utilization 80,220
NA NA -
Water 0.40 $/mgal, 141 gpm, 7650 hr/yr, 93% utilization 24,000
NA NA -
Comp Air 0.32 $/mscf, 2 scfm/kacfm, 7650 hr/yr, 93% utilization 32,391
NA NA -
NA NA -
SW Disposal 11.48 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization 77
NA NA -
NA NA -
NA NA -
Lime 90.00 $/ton, 16 lb/hr, 7650 hr/yr, 93% utilization 5,161 (3)
NA NA -
Lost Revenue - Fly Ash NA 250,000
NA NA -
Filter Bags 37.94 $/bag, 0 bags, 7650 hr/yr, 93% utilization 76,951
Total Annual Direct Operating Costs 693,518
Indirect Operating Costs 1
Overhead 60% of total labor and material costs 134,831 2
Administration (2% total capital costs) 2% of total capital costs (TCI) 61,126 5
Property tax (1% total capital costs) 1% of total capital costs (TCI) 30,563 1
Insurance (1% total capital costs) 1% of total capital costs (TCI) 30,563 1
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 461,587
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 718,670
Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,412,189
See Summary page for notes and assumptions
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DSI Baghouse 9/6/2006 Page 37 of 42
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DSI Baghouse 9/6/2006 Page 38 of 42
Northshore Process Boiler
BART Report - Appendix A Emission Control Cost Analysis
Table 29: SO2 Control - Dry Sorbent Injection and Baghouse
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalsyt:
Equipment Life 5 years
CRF 0.0000
Rep part cost per unit 500 $/ft3
Amount Required 0 ft3
Total Rep Parts Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment: Filter bags & cages (4)
Equipment Life 4 years
CRF 0.2952
Rep part cost per unit 38 $/bag
Amount Required 4410
Total Rep Parts Cost 186,561 Cost adjusted for freight & sales tax
Installation Labor 74,088 10 min per bag, Labor + Overhead (68% = $29.65/hr) EPA Cost Cont Manual 6th ed Section 6 Chapter 1.5.1.4
Total Installed Cost 260,649 Zero out if no replacement parts needed lists replacement times from 5 - 20 min per bag.
Annualized Cost 76,951
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kW
Blower, Baghouse 119,800 10 216.8
Baghouse Shaker 0.0 Gross fabric area ft2 0 EPA Cost Cont Manual 6th ed Section 6 Chapter 1 Eq 1.14
Other
Other
Other
Other
Other
Total 216.8
Baghouse Filter Cost See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs
Gross BH Filter Area 0 ft2
Cages 0 ft long 5 in dia 0.00 area/cage ft2 0.000 $/cage
Bags 0 $/ft2 of fabric 0.00 $/bag
H2O Use (6) 140.56 gpm 0.000 Total
Lime Use 16.75 lb/hr SO2 0.96 lb Lime/lb SO2 16.12 lb/hr lime, lime addition at 1.1 times the stoichiometric ratio
Pollutant BART Baseline Emissions Control Eff (%) Cont. Emis (lb/MMBtu)
T/yr lb/MMBtu lb/hr 80% 0.05
NOx 50.90 0.166071429 11.625
SO2 73.40 0.239285714 16.75
Operating Cost Calculations Annual hours of operation: 7,650
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 50.00 $/Hr 2.0 hr/8 hr shift 1,913 95,625 $/Hr, 2.0 hr/8 hr shift, 7650 hr/yr
Supervisor 15% of Op. NA 14,344 15% of Operator Costs
Maintenance
Maint Labor 60.00 $/Hr 1.0 hr/8 hr shift 956 57,375 $/Hr, 1.0 hr/8 hr shift, 7650 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 57,375 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.052 $/kwh 216.8 kW-hr 1,542,694 80,220 $/kwh, 217 kW-hr, 7650 hr/yr, 93% utilization
Natural Gas 2.31 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7650 hr/yr, 93% utilization
Water 0.40 $/mgal 140.6 gpm 60,000 24,000 $/mgal, 141 gpm, 7650 hr/yr, 93% utilization
Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
Comp Air 0.32 $/mscf 2 scfm/kacfm 102,278 32,391 $/mscf, 2 scfm/kacfm, 7650 hr/yr, 93% utilization
WW Treat Neutralization 3.80 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization
SW Disposal 11.48 $/ton 0.0 ton/hr 7 77 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization
Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization
Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7650 hr/yr, 93% utilization
PRB Coal 1 $/ton 0.0 ton/hr 0 0 $/ton, $5.1MM/yr extra for PRB - $1MM/yr Lower O&M Cost
Lime 90.0 $/ton 16.1 lb/hr 57 5,161 $/ton, 16 lb/hr, 7650 hr/yr, 93% utilization
Caustic 305.21 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization
Oxygen 1.49 Mscf 0.0 kscf/hr 0 0 Mscf, 0 kscf/hr, 7650 hr/yr, 93% utilization
SCR Catalyst 500 $/ft3 0 ft3 0 0 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization
Filter Bags 37.94 $/bag 0 bags NA 76,951 $/bag, 0 bags, 7650 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Note: Select reagent, catayst and repacement parts by entering number in coluND U. Unhide Col U to enter choice.
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls
DSI Baghouse 9/6/2006 Page 39 of 42
Northshore Process Boiler
BART Report - Appendix A Emission Control Cost Analysis
Table 30: SOx Control - Wet Scrubber
Operating Unit: Process Boiler 1 & 2
Emission Unit Number 003 & 004 Stack/Vent Number 003
Standardized Flow Rate 64,771 scfm @ 32º F
Expected Utilization Rate 93% Temperature 450 Deg F
Expected Annual Hours of Operation 7,650 0 Moisture Content 13% 0
Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm
Expected Equipment Life 20 0 Standardized Flow Rate 69,510 scfm @ 68º F
Dry Std Flow Rate 60,265 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs (1)
Purchased Equipment (A) 1,908,056
Purchased Equipment Total (B) 22% of control device cost (A) 2,318,288
Installation - Standard Costs 85% of purchased equip cost (B) 1,970,545
Installation - Site Specific Costs 6,200,000
Installation Total 1,970,545
Total Direct Capital Cost, DC 4,288,833
Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 347,743
Total Capital Investment (TCI) = DC + IC 13,618,522
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 348,057
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,521,875
Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,869,933
Actual
Emission Control Cost Calculation Emis Emissions
Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 11.6 50.9 0% 50.9 - NA
Sulfur Dioxide (SO2) 16.8 73.4 80% 14.7 58.7 31,845
Notes & Assumptions
1 Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm.
2 Liquid/Gas ratio = 38 L/G = Gal/1,000 acf.
3 Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate.
4 Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition.
5 CUECost Workbook Version 1.0, USEPA Document Page 2.
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls
Wet Scrubber 9/6/2006 Page 40 of 42
Northshore Process Boiler
BART Report - Appendix A Emission Control Cost Analysis
Table 30: SOx Control - Wet Scrubber
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1)
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 1,908,056
Instrumentation 10% of control device cost (A) 190,806
MN Sales Taxes 6.5% of control device cost (A) 124,024
Freight 5% of control device cost (A) 95,403
Purchased Equipment Total (B) 22% 2,318,288
Installation
Foundations & supports 12% of purchased equip cost (B) 278,195
Handling & erection 40% of purchased equip cost (B) 927,315
Electrical 1% of purchased equip cost (B) 23,183
Piping 30% of purchased equip cost (B) 695,486
Insulation 1% of purchased equip cost (B) 23,183
Painting 1% of purchased equip cost (B) 23,183
Installation Subtotal Standard Expenses 85% 1,970,545
Total Direct Capital Cost, DC 4,288,833
Indirect Capital Costs
Engineering, supervision 5% of purchased equip cost (B) 115,914
Construction & field expenses 0% of purchased equip cost (B) 0
Contractor fees 5% of purchased equip cost (B) 115,914Start-up 1% of purchased equip cost (B) 23,183Performance test 1% of purchased equip cost (B) 23,183
Model Studies NA of purchased equip cost (B) NA
Contingencies 3% of purchased equip cost (B) 69,549
Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 347,743
Total Capital Investment (TCI) = DC + IC 4,636,576
Retrofit multiplier5 60% of TCI 2,781,946
Sitework and foundations Site Specific 1,400,000
Structural steel Site Specific 4,800,000
Site Specific - Other Site Specific 0
Total Site Specific Costs 6,200,000
Total Capital Investment (TCI) Retrofit Installed 13,618,522
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 37.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 23,906
Supervisor 15% 15% of Operator Costs 3,586
Maintenance
Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 28,688
Maintenance Materials 100% of maintenance labor costs 28,688
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 246 kW-hr, Annual Operating Hours, 93% utilization 91,145
Water 0.40 $/kgal, 112 gpm, Annual Operating Hours, 93% utilization 19,194
WW Treat Neutralization 3.80 $/kgal, 91 gpm, Annual Operating Hours, 93% utilization 147,690
Lime 90.00 $/ton, 16 lb/hr, Annual Operating Hours, 93% utilization 5,161Total Annual Direct Operating Costs 348,057
Indirect Operating Costs
Overhead 60% of total labor and material costs 50,920
Administration (2% total capital costs) 2% of total capital costs (TCI) 92,732
Property tax (1% total capital costs) 1% of total capital costs (TCI) 46,366
Insurance (1% total capital costs) 1% of total capital costs (TCI) 46,366
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,285,492
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,521,875
Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,869,933
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls
Wet Scrubber 9/6/2006 Page 41 of 42
Northshore Process Boiler
BART Report - Appendix A Emission Control Cost Analysis
Table 30: SOx Control - Wet Scrubber
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalyst:
Equipment Life 20 years
CRF 0.0000
Rep part cost per unit 0 $/ft3
Amount Required 0 ft3
Packing Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit 0.00 $ each
Amount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kW
Blower, Scrubber 119,800 8.55 0.7 - 171.2 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48
Flow Liquid SPGR ∆ P ft H2O Efficiency Hp kWCirc Pump 4,552 gpm 1 60 0.7 - 73.4 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
H2O WW Disch 112 gpm 1 60 0.7 - 1.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
Other
Total 246.4
Reagent Use & Other Operating Costs
Caustic Use 16.75 lb/hr SO2 2.50 lb NaOH/lb SO2 41.88 lb/hr Caustic
Lime Use 16.75 lb/hr SO2 0.96 lb Lime/lb SO2 16.12 lb/hr lime, lime addition at 1.1 times the stoichiometric ratio
Liquid/Gas ratio 38.0 * L/G = Gal/1,000 acf
Circulating Water Rate24,552 gpm
Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 112 gpm
Evaopration Loss4 = 21.36 gpm
Operating Cost Calculations Annual hours of operation: 7,650
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 478 23,906 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours,
Supervisor 15% of Op. NA 3,586 15% of Operator Costs
Maintenance
Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 478 28,688 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours,
Maint Mtls 100 % of Maintenance Labor NA 28,688 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.052 $/kwh 246.4 kW-hr 1,752,797 91,145 $/kwh, 246 kW-hr, Annual Operating Hours, 93% utilization
Water 0.40 $/kgal 112.4 gpm 47,984 19,194 $/kgal, 112 gpm, Annual Operating Hours, 93% utilization
WW Treat Neutralization 3.80 $/kgal 91.0 gpm 38,866 147,690 $/kgal, 91 gpm, Annual Operating Hours, 93% utilization
Lime 90.0 $/ton 16.1 lb/hr 57 5,161 $/ton, 16 lb/hr, Annual Operating Hours, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls
Wet Scrubber 9/6/2006 Page 42 of 42
Memorandum
To: Margaret McCourtney
From: Andrew Skoglund
Subject: Revisions per your comments
Date: May 16, 2006
Project: Taconite Industry BART Clients
c: Mary Jean Fenske, Barr Taconite BART Project Team, Taconite BART Industry Reps.
Attached is a revised version of our proposed changes to the BART-analysis modeling protocol. They are
set up in the format described in Appendix G to the modeling protocol. The proposed OZONE.DAT files
and a figure depicting the proposed modeling domain are also included, as requested.
The PSD modeling protocols referenced for the CALMET parameters are based on PSD modeling
protocols submitted for Mesabi Nugget LLC, Northshore Mining Line 5 Restart, and Minnesota Steel
Industries LLC. Each of these facilities has submitted a modeling protocol using MM4/MM5 data with
observations for review. The values noted are representative of those that were used after receiving
comment from the FLMs. The Minnesota Steel Industries modeling protocol was submitted in May 2005,
with FLM response on June 14, 2005. FLMs approved of the submitted values.
The comments section regarding receptors has been revised to indicate that we will be using a subset of the
original MPCA receptor group, using only BWCA and Voyageurs receptors.
Thank you,
Andrew J. Skoglund
Barr Engineering Co.
(952) 832 - 2685
Barr Engineering Company Appendix B
4700 West 77th Street • Minneapolis, MN 55435-4803 Phone: 952-832-2600 • Fax: 952-832-2601 • www.barr.com An EEO Employer Minneapolis, MN • Hibbing, MN • Duluth, MN • Ann Arbor, MI • Jefferson City, MO
!;N
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2004
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0 100Kilometers
MODELING DOMAINTaconite BART ModelingTaconite Industry Group
Minnesota
0 100Miles
LegendModeling Domain
Class I AreaBWCAVoyageurs
TERREL
Variable Description Value Default Comments
GTOPO30 GTOPO 30-sec data - n/a 1 degree DEM files will be used
XREFKM Reference point coordinates for grid 168 n/a
YREFKM Reference point coordinates for grid 720 n/a
NX Number of X grid cells 40 n/aNY Number of Y grid cells 30 n/a
CTGPROC
Variable Description Value Default Comments
XREFKM Reference point coordinates for grid 168 n/a
YREFKM Reference point coordinates for grid 720 n/a
NX Number of X grid cells 40 n/aNY Number of Y grid cells 30 n/a
CALMET
Variable Description Value Default Comments
NUSTA Number of upper air stations 4 14898, 14918, 94983, 4837
NX Number of X grid cells 40 n/a
NY Number of Y grid cells 30 n/a
XORIGKM Reference point coordinates for grid 168 n/a
YORIGKM Reference point coordinates for grid 720 n/a
NOOBS No Observation Mode 0 Y Include Surface, Upper Air and Precipitation Observations
NSSTA Number of Surface Stations 74 n/a 74 surface weather stations
NPSTA Number of Precipitation Stations 68 n/a 68 precipitation stations
RMAX2 Maximum radius of influence over land aloft 50 n/a Similar to PSD with Observations
RMAX3 Maximum radius of influence over water 500 n/a Similar to PSD with Observations
R1 Relative weighting of the first guess field and observations in the surface layer (km) 10 n/a Similar to PSD with Observations
R2 Relative weighting of the first guess field and observations in the layers aloft (km) 20 n/a Similar to PSD with Observations
ISURFT Surface met. Stations to use for the surface temperature - n/a Hibbing Met station
IUPT Upper air station to use for the domain scale lapse rate - n/a International Falls Upper Air station
ITPROG 3D temperature from observations or from prognostic data? 0 Y Inclusion of Surface and Upper Air
TRADKM Radius of influence for temperature interpolation 500 Y Similar to PSD with Observations
JWAT1 Beginning land use category for temperature interpolation over water 99 n/a CALMET may fail when using 55 with no overwater data
JWAT2 Ending land use category for temperature interpolation over water 99 n/a CALMET may fail when using 55 with no overwater dataSIGMAP Radius of influence (km) 100 Y Precipitation Observations are included
Input Group 0b
Input Group 2
Input Group 2
Input Group 2
Input Group 4
Input Group 5
Input Group 6
CALPUFF
Variable Description Value Default Comments
NX Number of X grid cells in met grid 40 n/a
NY Number of Y grid cells in met grid 30 n/a
XORIGKM Reference point coordinates for met grid 168 n/a
YORIGKM Reference point coordinates for met grid 720 n/a
IBCOMP X index of LL corner 1 n/a
JBCOMP Y index of LL corner 1 n/a
IECOMP X index of UR corner 40 n/a
JECOMP Y index of UR corner 30 n/a
MOZ Ozone data input option 1 N OZONE.DAT from MN, WI, and MI observation stations
NREC Number of non-gridded receptors 1222 n/a Using only BWCA and Voyageurs from MPCA protocol
Input Group 11
Input Group 17
Input Group 4
Appendix C
1. CALPUFF Modeling System
The CALPUFF Modeling System is the required model for determining visual impacts at long distances
from sources. This model was used in accordance with the guidelines found in the Best Available
Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject-to-BART in the State of
Minnesota, Final1, with the modifications found in Appendix B.
The CALPUFF system consists of three main components (CALMET, CALPUFF and CALPOST) and a
number of pre-processing programs. These pre-processing programs are designed to prepare available
meteorological and geophysical data for input into CALMET. Each of these modeling components are
described below:
• CALMET is a meteorological model that develops hourly wind and temperature fields on a three-
dimensional gridded modeling domain. Associated two-dimensional fields such as mixing
heights, terrain elevations, land use categories and dispersion properties are also included in the
file produced by CALMET.
• CALPUFF is a transport and dispersion model that follows the “puffs” of material emitted from
one or more sources as they travel downwind. CALPUFF simulates dispersion and chemical
transformations as each puff moves away from the source, using the multi-dimensional grids
generated by CALMET.
• CALPUFF produces an output file containing hourly concentrations of pollutants which are
processed by CALPOST to yield estimates of ambient air extinction coefficients and related
measures of visibility impairment at selected averaging times and locations.
Lambert conformal coordinates (LCC) were used in the modeling. To accommodate this coordinate
system, it was necessary to use CALPUFF version 5.711a. To allow the use of larger meteorological sets
and overcome other size limitations, CALPUFF was recompiled with several size parameters increased.
1 MPCA, Final March 2006. Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources
Subject to BART in the State of Minnesota.
CALMET
Three years (2002-2004) of MM5 prognostic mesoscale meteorological data, surface weather data,
precipitation data, and upper air data were used to generate the CALMET data set for use in the
CALPUFF model. The CALMET computational grid was 175 grid cells (east-west) by 120 grid cells
(north-south) with a grid spacing of 12 km. This grid encompasses Northshore Mining Company (NMC)
sources, the BWCAW and Voyageurs National Park. USGS digital elevation maps (DEMs) and land use
land cover (LULC) files required by CALMET were obtained from the MPCA.
CALPUFF
CALPUFF model input files were set up for each year of CALMET data. Model parameters were set to
the values specified in the revised modeling protocol (Appendix B).
The CALPUFF modeling considered the emission of SO2, NOx, PM10 (coarse particulate matter, 2.5µ to
10µ), and PM2.5 (fine particulate matter, under 2.5µ).
The CALPUFF modeling also tracked SO4, NO3, and HNO3, which are generated by the chemical
transformation of the emitted SO2 and NOx. The default MESOPUFF II algorithms described the rates
of transformation. The MESOPUFF-generated transformation rates are a function of the background
ozone and ammonia concentrations, the former set by observations, the latter using monthly average
values provided by MPCA.
The CALPUFF modeling used the receptors for the Boundary Water Canoe Area Wilderness and
Voyageurs National Park provided by the MPCA in the original subject-to-BART modeling files.
CALPOST
CALPOST converted the hourly concentration and monthly average relative humidity files generated by
CALPUFF into 24-hour time-averaged extinction coefficients. These emissions-based extinction
coefficients were compared to the 20% best days background extinction coefficients designated in the
modeling protocol.
2. Visibility Impacts Analysis
As indicated in EPA’s final BART guidance2, states are required to consider the degree of visibility
improvement resulting from the retrofit technology in combination with other factors, such as economics
and technical feasibility, when determining BART for an individual source.
The CALPUFF program models how a pollutant contributes to visibility impairment with consideration
for the background atmospheric ammonia, ozone and meteorological data. Additionally, the interactions
between the visibility impairing pollutants NOx, SO2 and PM10 can play a large part in predicting
impairment. It is therefore important to take a multi-pollutant approach when assessing visibility impacts.
Assessing Visibility Impairment
The visibility impairment contribution for different emission rate scenarios can be determined using the
CALMET, CALPUFF, and CALPOST modeling templates provided by the Minnesota Pollution Control
Agency (MPCA). The Minnesota BART modeling protocol3 describes the CALPUFF model inputs
including the meteorological data set and background atmospheric ammonia and ozone concentrations
along with the functions of the CALPOST post processing. There are two criteria with which to assess the
expected post-BART visibility improvement: the 98th percentile delta deciview and the number of days
on which a source exceeds an impairment threshold.
As defined by federal guidance4 a source "contributes to visibility impairment” if the 98th percentile of
any year’s modeling results meets or exceeds the threshold of five-tenths of a deciview (dV) at a federally
protected Class I area receptor. The pre-BART evaluation of this criterion conducted by the Minnesota
Pollution Control Agency identified this facility as having BART eligible source(s)5 that could cause or
contribute to visibility impairment at Minnesota Class I areas. In addition to establishing whether or not a
source contributes to impairment on the 98th percentile, the severity of the visibility impairment
contribution or reasonably attributed visibility impairment can be gauged by assessing the number of days
on which a source exceeds 0.5 dV.
2 40 CFR 51, Appendix Y. 3 MPCA, March 2006, Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources
Subject-to-Bart in the State of Minnesota. 4 40 CFR 51, Appendix Y. 5 MPCA, March 2006, Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources
Subject-to-Bart in the State of Minnesota.
Predicting 24-Hour Maximum Emission Rates
Pursuant to guidance from MPCA and to be consistent with use of the highest daily emissions for pre-
BART visibility impacts, the post-BART emissions to be used for the visibility impacts analysis should
reflect a maximum 24-hour average basis. There were no post-BART scenarios to be modeled.
Table 4-1 describes the pre-BART model input parameters. There were no post-BART scenarios to be
modeled.
Modeled Results
Visibility impairment was modeled using the meteorological data for the years 2002, 2003 and 2004 for
the pre-BART emission scenario. Results for the 98th percentile and number of days above 0.5 dV at
Boundary Waters Canoe Area Wilderness (BWCA) and Voyageurs National Park (VNP) are included in
Table 4-2.
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Northshore A
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Taconite BART Analysis
NOx Control
Available and Applicable ReviewRevised: August 23, 2006
Step 1 Step 2
This table is part of the Taconite BART Report and should not be distributed without the full text of the report so that the information is not taken out of context.
Refe
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NOx Pollution Control
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Comments Basic Principle
Combustion Controls
1 Overfire Air (OFA) Y N --- ---NOx formation front is not stationary in an indurating furnace
Combustion air is separated into primary and secondary flow sections to achieve complete burnout and to encourage the formation of N2 rather
than NOx
2External Flue Gas
Recirculation (EFGR)Y Y N ---
Mixes flue gas with combustion air which reduces oxygen content and therefore reduces flame temperature
3 Low-NOx Burners Y YY
(preheat burners)
Y (preheat burners)
Higher control efficiency at the burner, but the listed control efficiency is for the entire furnace.
Burners are designed to reduce NOx formation through restriction of oxygen, flame temperature, and/or residence time
4Induced Flue Gas
Recirculation BurnersY Y N ---
Need to be upfired. Need convective loop to get gas recirculated
Draws flue gas to dilute the fuel in order to reduce the flame temperature
5 Low Excess Air Y N --- ---Need high O2 for process requirements
and product qualityReduces oxygen content in flue gas and reduces flame temperature
6Burners out of Service
(BOOS)Y N --- ---
Need capacity of all burners for worst case scenario
Shut off the fuel flow from one burner or more to create fuel rich and fuel lean zones
7 Fuel Biasing Y N --- --- Power plant technologyCombustion is staged by diverting fuel from the upper level burners to the lower ones or from the center to the side burners to create fuel-rich and fuel-lean zones
8 Reburning Y N --- ---Kiln configuration not correct for this technology.
Part of the total fuel heat input is injected into the furnace in a region above the primary (main burners) flames to create a reducing atmosphere (re-burn zone), where hydrocarbon radicals react with NOx to produce elemental nitrogen
9 Load Reduction N --- --- ---Power plant technology -product demand side solution
This is a strategy to reduce load on a power plant by reducing the electrical demand throught efficiency projects.
10 Energy Efficiency Projects Y Y
Y (for large
projects like heat-recoup)
Y (for large
projects like heat-recoup)
decrease amount of fuel required to make an acceptable product
11 Coal Drying Y N --- --- Applies only to facilities that burn coalDry coal will increase the as-burned BTU value, and therefore less fuel is required to be burned. Specific energy efficiency project
12Coal Addition to Pellets with
Low Excess Air in the Induration Furnace
N --- --- --- Check on status of research Reduce flame temperature and energy requirements
Taconite BART Analysis
NOx Control
Available and Applicable ReviewRevised: August 23, 2006
Step 1 Step 2
This table is part of the Taconite BART Report and should not be distributed without the full text of the report so that the information is not taken out of context.
Refe
ren
ce N
o.1
NOx Pollution Control
Technology Is t
his
a g
en
era
lly a
vailab
le
co
ntr
ol te
ch
no
log
y?
Is t
he c
on
tro
l te
ch
no
log
y
availab
le t
o in
du
rati
ng
furn
aces?
Is t
he c
on
tro
l te
ch
no
log
y
ap
plicab
le t
o t
his
sp
ecif
ic
so
urc
e?
Is it
tech
nic
ally f
easib
le f
or
this
so
urc
e?
Comments Basic Principle
13 Ported Kilns Y YY
(grate-kilns only)
N(Metso says
no NOx improvement)
Applicable to grate kilns. Provides additional oxygen for pellet oxidation which reduces the overall energy use of the kiln
14 Combustion Zone Cooling Y N --- --- Boiler technologyCooling of the primary flame zone by heat transfer to surrounding surfaces
15 Alternate Fuels Y Y
Y(for furnaces capable of
multiple fuels)
Y(not required
by BART)
Requires case by case analysis. Typically, facilities experience lower NOx when burning solid fuels.
Lower combustion temps with solid fuels vs gas. May also reduce fuel NOx by using a fuel with less nitrogen.
16Oxygen Enhanced
CombustionN --- --- --- Research level A small fraction of the combustion air is replaced with oxygen.
17 Preheat Combustion N --- --- --- Research level
Pulverized coal preheated and volatiles and fuel-bound nitrogen compounds are released in a controlled reducing atmosphere where the nitrogen compounds are reduced to N2.
18 ROFA-ROTAMIX Y N --- ---Can't achieve correct temperature window (1400-1800F). Too hot in kiln too cold in reheat
Combination of OFA and SCR. Wall-fired or tangentially-fired furnace that utilizes high velocity overfire air. Additional NOx reductions are achieved with ammonia injection (Rotamix)
19 NOx CEMS Y N --- --- Optimization of combustion
20 Parametric Monitoring Y N --- --- Optimization of combustion
38Catalyst Injection
(EPS Technologies)N --- --- --- Research Level
A combustion catalyst is directly injected into the air intake stream and delivered to the combustion site, initiating chemical reactions that change the dynamics of the flame.
Post Combustion Controls
21Non-Selective Catalytic
Reduction (NSCR)Y N --- ---
For clean services. Too much stuff in flue gas would poison catalyst
Under near stoichiometric conditions, in the presence of a catalyst, NOx is reduced by CO, resulting in nitrogen (N2) and carbon dioxide (CO2).
22Low Temperature Oxidation
(LTO) - Tri-NOx® Y N --- --- Used for higher flue gas concentrations
Utilizes an oxidizing agent such as ozone to oxidize various pollutants including NOx
Taconite BART Analysis
NOx Control
Available and Applicable ReviewRevised: August 23, 2006
Step 1 Step 2
This table is part of the Taconite BART Report and should not be distributed without the full text of the report so that the information is not taken out of context.
Refe
ren
ce N
o.1
NOx Pollution Control
Technology Is t
his
a g
en
era
lly a
vailab
le
co
ntr
ol te
ch
no
log
y?
Is t
he c
on
tro
l te
ch
no
log
y
availab
le t
o in
du
rati
ng
furn
aces?
Is t
he c
on
tro
l te
ch
no
log
y
ap
plicab
le t
o t
his
sp
ecif
ic
so
urc
e?
Is it
tech
nic
ally f
easib
le f
or
this
so
urc
e?
Comments Basic Principle
23Low Temperature Oxidation
(LTO) - LoTOxY N --- ---
Has been included as an "applicable and available" technology in recent BACT analyses from multiple facilities.
Utilizes an oxidizing agent such as ozone to oxidize various pollutants including NOx
24Selective Catalytic Reduction (SCR)
Y Y Y Y
Need to inject at appropriate temperature (reheat will be required). Applicable on clean side only.
Although this hasn't been demonstrated on an indurating furnace, the stream characteristics appear to make this technology feasible.
Ammonia (NH3) is injected into the flue gas stream in the presence of a
catalyst to convert NOx into N2 and water
25 Regenerative SCR Y N --- --- Clean side only
26Selective Non-Catalytic
Reduction (SNCR)Y N --- ---
Can't achieve correct temperature window (1400-1800F). Too hot in kiln too cold in reheat
Urea or ammonia-based chemicals are injected into the flue gas stream to convert NO to molecular nitrogen, N2, and water
27 Adsorption N --- --- --- Still in research stages. Use of char (activated carbon) to adsorb oxides of nitrogen
28 Absorption Y N --- --- Similar to TriNOxUse of water, hydroxide and carbonate solutions, sulfuric acid, organic solutions, molten alkali carbonates, or hydroxides to absorb oxides of nitrogen.
29 Oxidizer Y N --- --- Redundant to regenerative SCRGas stream is sent through the regenerative, recuperative, catalytic or direct fired oxidizer where pollutants are heated to a combustion point and destroyed.
30 SNOX N --- --- --- Early commercial development stage
Catalytic reduction of NOx in the presence of ammonia (NH3), followed by
catalytic oxidation of SO2 to SO3. The exit gas from the SO3 converter
passes through a novel glass-tube condenser in which the SO3 is
hydrated to H2SO4 vapor and then condensed to a concentrated liquid
sulfuric acid (H2SO4).
31 SOx-NOx-Rox-Box N --- --- ---Technology has not been demonstrated
Dry sorbent injection upstream of the baghouse for removal of SOx and ammonia injection upstream of a zeolitic selective catalytic reduction (SCR) catalyst incorporated in the baghouse to reduce NOx emissions.
Taconite BART Analysis
NOx Control
Available and Applicable ReviewRevised: August 23, 2006
Step 1 Step 2
This table is part of the Taconite BART Report and should not be distributed without the full text of the report so that the information is not taken out of context.
Refe
ren
ce N
o.1
NOx Pollution Control
Technology Is t
his
a g
en
era
lly a
vailab
le
co
ntr
ol te
ch
no
log
y?
Is t
he c
on
tro
l te
ch
no
log
y
availab
le t
o in
du
rati
ng
furn
aces?
Is t
he c
on
tro
l te
ch
no
log
y
ap
plicab
le t
o t
his
sp
ecif
ic
so
urc
e?
Is it
tech
nic
ally f
easib
le f
or
this
so
urc
e?
Comments Basic Principle
32 Electron (E-Beam) Process N --- --- ---No operating commercial applications on coal
Electron beam irradiation in the presence of ammonia to initiate chemical conversion of sulfur and nitrogen oxides into components which can be easily collected by conventional methods such as an ESP or baghouse.
33 Electrocatalytic Oxidation N --- --- ---Similar to cold plasma. Will keep watch for availability of this technology
Utilizes a reactor in which SO2, NOx, and mercury are oxidized to nitrogen
dioxide (NO2), sulfuric acid, and mercuric oxide respectively using non-
thermal plasma.
On recent project, the vender was doing final trials on full-scale applications.
34 NOXSO N --- --- ---Commercial version of adsorption. Limited experience (proof-of-concept tests).
Uses a regenerable sorbent to simultaneously adsorb SO2 and NOx from
flue gas from coal-fired utility and industrial boilers. In the process, the SO2 is converted to a saleable sulfur by-product (liquid SO2, elemental
sulfur, or sulfuric acid) and the NOx is converted to nitrogen and oxygen.
35 Copper-Oxide N --- --- ---Absorption and SCR. Experience limited to pilot scale.
SO2 in the flue gas reacts with copper oxide, supported on small spheres
of alumina, to form copper sulfate. Ammonia is injected into the flue gas before the absorption reactor and a selective catalytic reduction-type reaction occurs that reduces the nitric oxides in the flue gas. In the regeneration step, the copper sulfate is reduced in a regenerator with a reducing agent, such as natural gas, producing a concentrated stream of SO2.
36 Cold Plasma N --- --- --- Research Level
37 Biofilters Y N --- --- Not applicable to furnaces.Gas stream is passed through a filter medium of soil and microbes. Pollutants are adsorbed and degraded by microbial metabolism forming the products carbon dioxide and water.
38 Pahlman Process N --- --- --- Research LevelGas stream is passed through a filter baghouse in which specially-developed, small-particle, high-surface area metal oxide sorbent have been deployed. Pollutants are removed from the gases by adsorption.
1) This number is for reference only. It does not in any way rank the control technologies.
2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.
2) b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm
Taconite BART Analysis
NOx Control
Available and Applicable ReviewRevised: August 23, 2006
Step 1 Step 2
This table is part of the Taconite BART Report and should not be distributed without the full text of the report so that the information is not taken out of context.
Refe
ren
ce N
o.1
NOx Pollution Control
Technology Is t
his
a g
en
era
lly a
vailab
le
co
ntr
ol te
ch
no
log
y?
Is t
he c
on
tro
l te
ch
no
log
y
availab
le t
o in
du
rati
ng
furn
aces?
Is t
he c
on
tro
l te
ch
no
log
y
ap
plicab
le t
o t
his
sp
ecif
ic
so
urc
e?
Is it
tech
nic
ally f
easib
le f
or
this
so
urc
e?
Comments Basic Principle
2) c) New and Emerging Environmental Technologies, http://neet.rti.org/
2) d) ND BART Reports
Taconite BART Analysis
SO2 Control
Available and Applicable Review
Revised: August 23, 2006
Step 1 Step 2
This table is part of the Taconite BART Report and should not be distributed without the full text of the report so that the information is not taken out of context.
Ref
eren
ce N
o.1
SO2 Pollution Control
Technology
Is t
his
a g
en
era
lly a
vail
ab
le
co
ntr
ol
tech
no
log
y?
Is t
he c
on
tro
l te
ch
no
log
y
avail
ab
le t
o i
nd
ura
tin
g
furn
aces?
Is t
he c
on
tro
l te
ch
no
log
y
ap
pli
cab
le t
o t
his
sp
ecif
ic
so
urc
e?
Is i
t te
ch
nic
all
y f
easib
le f
or
this
so
urc
e?
Comments Basic Principle
1Wet Scrubbing (High
Efficiency)Y Y Y Y Absorption and reaction using an alkaline reagent to produce a solid compound
2Wet Scrubbing (Low
Efficiency)Y Y Y Y Absorption and reaction using an alkaline reagent to produce a solid compound
3Wet Walled Electrostatic
Precipitator (WWESP)Y Y Y Y
Suspended particles are separated from the flue gas stream, attracted to plates, and
collected in hoppers
4 Dry sorbent injection Y Y Y N
Pulverized lime or limestone is directly injected into the duct upstream of the fabric
filter. Dry sorption of SO2 onto the lime or limestone particle occurs and the solid
particles are collected with a fabric filter
5 Spray Dryer Absorption (SDA) Y Y Y NLime slurry is sprayed into an absorption tower where SO2 is absorbed by the
slurry, forming CaSO3/CaSO4
6 Alternative Fuels Y Y
Y(for furnaces capable of
multiple fuels)
Y(not required
by BART)
Natural gas is base case Use a fuel with lower sulfur content.
7 Load Reduction N --- --- --- Power plant technologyThis is a strategy to reduce load on a power plant by reducing the electrical demand
throught efficiency projects.
8 Energy Efficiency Projects Y Y
Y (for large
projects like heat-recoup)
Y (for large
projects like heat-recoup)
decrease amount of fuel required to make an acceptable product
9 Coal Drying Y N --- --- Applies only to facilities that burn coalDry coal will increase the as-burned BTU value, and therefore less fuel is required
to be burned. Specific energy efficiency project
10 Bio Filters N --- --- --- Research level
Gas stream passes through a packed bed of specially engineered biomedia which
supports the growth of active bacterial species. The pollutants in the gas stream are
biodegraded or biotransformed into innocuous products, such as carbon dioxide,
water, chloride ion in water, sulfate or nitrate ions in water.
11 CANSOLV Regenerable SO2 N --- --- --- Research level
An aqueous solution of proprietary diamine captures SO2 from the feed gas in a
countercurrent absorption tower. The rich solvent is regenerated by steam stripping,
giving a byproduct of pure, water saturated SO2 gas and lean solvent for recycling
to the absorber.
12 Pahlman Process N --- --- --- Research level
Gas stream is passed through a filter baghouse in which specially-developed, small-
particle, high-surface area metal oxide sorbent have been deployed. Pollutants are
removed from the gases by adsorption.
Taconite BART Analysis
SO2 Control
Available and Applicable Review
Revised: August 23, 2006
Step 1 Step 2
This table is part of the Taconite BART Report and should not be distributed without the full text of the report so that the information is not taken out of context.
Ref
eren
ce N
o.1
SO2 Pollution Control
Technology
Is t
his
a g
en
era
lly a
vail
ab
le
co
ntr
ol
tech
no
log
y?
Is t
he c
on
tro
l te
ch
no
log
y
avail
ab
le t
o i
nd
ura
tin
g
furn
aces?
Is t
he c
on
tro
l te
ch
no
log
y
ap
pli
cab
le t
o t
his
sp
ecif
ic
so
urc
e?
Is i
t te
ch
nic
all
y f
easib
le f
or
this
so
urc
e?
Comments Basic Principle
13 SOx-NOx-Rox-Box N --- --- --- Technology has not been demonstrated
Dry sorbent injection upstream of the baghouse for removal of SOx and ammonia
injection upstream of a zeolitic selective catalytic reduction (SCR) catalyst
incorporated in the baghouse to reduce NOx emissions.
14 Electron (E-Beam) Process N --- --- ---No operating commercial applications on
coal
Electron beam irradiation in the presence of ammonia to initiate chemical
conversion of sulfur and nitrogen oxides into components which can be easily
collected by conventional methods such as an ESP or baghouse.
15 Electrocatalytic Oxidation N --- --- ---Similar to cold plasma. Will keep watch for
availability of this technology
Utilizes a reactor in which SO2, NOx, and mercury are oxidized to nitrogen dioxide
(NO2), sulfuric acid, and mercuric oxide respectively using non-thermal plasma.
On recent project, the vender was doing final trials on full-scale applications.
16 NOXSO N --- --- ---Commercial version of adsorption. Limited
experience (proof-of-concept tests).
Uses a regenerable sorbent to simultaneously adsorb SO2 and NOx from flue gas
from coal-fired utility and industrial boilers. In the process, the SO2 is converted to
a saleable sulfur by-product (liquid SO2, elemental sulfur, or sulfuric acid) and the
NOx is converted to nitrogen and oxygen.
17 Copper-Oxide N --- --- ---Absorption and SCR. Experience limited to
pilot scale.
SO2 in the flue gas reacts with copper oxide, supported on small spheres of
alumina, to form copper sulfate. Ammonia is injected into the flue gas before the
absorption reactor and a selective catalytic reduction-type reaction occurs that
reduces the nitric oxides in the flue gas. In the regeneration step, the copper sulfate
is reduced in a regenerator with a reducing agent, such as natural gas, producing a
concentrated stream of SO2.
18 SNOX N --- --- --- Early commercial development stage
Catalytic reduction of NOx in the presence of ammonia (NH3), followed by
catalytic oxidation of SO2 to SO3. The exit gas from the SO3 converter passes
through a novel glass-tube condenser in which the SO3 is hydrated to H2SO4 vapor
and then condensed to a concentrated liquid sulfuric acid (H2SO4).
19 Cold Plasma N --- --- --- Research level
1) This number is for reference only. It does not in any way rank the control technologies.
2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.
2) b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm
2) c) New and Emerging Environmental Technologies, http://neet.rti.org/
2) d) ND BART Reports
Appendix E Clean Air Interstate Rule (CAIR)
Cost-Effective air pollution Controls
9/1/2006
Comments
Reference Regulatory Body/Rule SO2 NOx SO2 NOx
BART 100 to 1000 100 to 1000 70 FR 39135
BART 281 to 1296 70 FR 39135 Table 3
BART 919 70 FR 39133
BARTGuidelines disparagingly reference "thousands of
dollars per ton" in commenting on the need to
exceed MACT and its general unreasonableness.
70_FR_25210_CAIR.pdf CAIR 1300 Estimated Marginal cost 2009
BART(proposed rule) 200-1000
BART proposed lists this as values for 90-95%
SO2 control, which is still assumed, or .1 to .15
lb/MMBtu. Dropped from final to give states
flexibility to require more. Says for scrubbers,
bypasses aren't BART, only 100% scrubbing is
BART.
BART(proposed rule)
0.2 lb/MMBtu for NOx is assumed reasonble.
Recognizes that some sources may need SCR to
get this level. For those, state discretion of the the
cost vs. visibility value is necessary.
CAIR(using IPM) 1000 1500
CAIR ( 2009 in 1999$) 900 2400
CAIR ( 2015 in 1999$) 1800 3000
CAIR (depending on Nat'l
emissions)1200 - 3000 1400- 2100
This was modeled with TRUM (Technologly
Retrofitting Updating Model) to develop the
marginal values.
Kammer_EPA_Decision.doc Kammer Decision over 1000 over 1000
LADCO_MidwestRPO_Boiler Analysis.pdf LADCO/Midwest RPO 1240 to 3822 607 to 4493
MANE-VU_BART_Control_Assessment.pdf MANE-VU 200-500 200-1500
Bowers_vs_SWAPCA.txt Bowers vs SWAPCA 300 300 1000 1000
954-1134 was ruled too much, in favor of 256-310
for SO2. This did consider incremental value.
Sections XVII to XIX
WRAP 3000
EPA - Referenced by Wrap
References EPA-600S\7-90-018. Low is
<$500/ton, Moderate is $500-3000/ton, High is
over $3000/ton
WRAP_Trading_program_methodology.pdf
Avg. Expected Values ($/ton) Limiting/Marginal values ($/ton)
MidwestRPO_rept_referencing_CAIR.pdf
FR_Notice_5MAY04_Proposed_Rule.pdf
FR_Notice_6JULY05_Final_Rule.pdf
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\HTC\Appendix E - Table of Costs_per_ton.xls
Appendix F
Northshore Process Boilers BART Analysis
NOx Control
Available and Applicable Review
Reference(s) Revised: June 8, 2006
Ref
eren
ce N
o.1
NOx Pollution Control
TechnologyAvailable? Applicable?
MP
CA
Ta
con
ite
BA
RT
Rep
ort
AW
MA
Jo
urn
al
9/0
5
Oth
er2
Comments Basic Principle
Combustion Controls
1 Overfire Air (OFA) Yes Yes x xCombustion air is separated into primary and secondary flow sections to achieve
complete burnout and to encourage the formation of N2 rather than NOx
2External Flue Gas
Recirculation (EFGR)Yes Yes x x
Mixes flue gas with combustion air which reduces oxygen content and therefore
reduces flame temperature
3 Low-NOx Burners Yes Yes x x xBurners are designed to reduce NOx formation through restriction of oxygen,
flame temperature, and/or residence time
4Induced Flue Gas
Recirculation BurnersYes Yes x x x
Need to be upfired. Need
convective loop to get gas
recirculated
Draws flue gas to dilute the fuel in order to reduce the flame temperature
5 Low Excess Air Yes Yes x Reduces production Reduces oxygen content in flue gas and reduces flame temperature
6Burners out of Service
(BOOS)Yes No x
Need capacity of all
burners for worst case
scenario
Shut off the fuel flow from one burner or more to create fuel rich and fuel lean
zones
7 Fuel Biasing Yes No xCombustion is staged by diverting fuel from the upper level burners to the lower
ones or from the center to the side burners to create fuel-rich and fuel-lean zones
8 Reburning Yes Yes x x
Part of the total fuel heat input is injected into the furnace in a region above the
primary (main burners) flames to create a reducing atmosphere (re-burn zone),
where hydrocarbon radicals react with NOx to produce elemental nitrogen
9 Load Reduction Yes Yes xThis is a strategy to reduce load on a power plant by reducing the electrical
demand throught efficiency projects.
10 Energy Efficiency Projects Yes Yes x decrease amount of fuel required to make an acceptable product
11 Coal Drying Yes Yes xRequires available excess
heat.
Dry coal will increase the as-burned BTU value, and therefore less fuel is required
to be burned. Specific energy efficiency project
14 Combustion Zone Cooling Yes Yes x xCould reduce load
capabilitiesCooling of the primary flame zone by heat transfer to surrounding surfaces
Y:\23\38\131\NMC Process Boilers List of Control Technologies 2006-07-11.xls 1 of 4
Appendix F
Reference(s) Revised: June 8, 2006R
efer
ence
No
.1
NOx Pollution Control
TechnologyAvailable? Applicable?
MP
CA
Ta
con
ite
BA
RT
Rep
ort
AW
MA
Jo
urn
al
9/0
5
Oth
er2
Comments Basic Principle
15 Alternate Fuels Yes Yes x x
Requires case by case
analysis. Typically,
facilities experience lower
NOx when burning solid
fuels.
Lower combustion temps with solid fuels vs gas. May also reduce fuel NOx by
using a fuel with less nitrogen.
16Oxygen Enhanced
CombustionNo No x x Research level A small fraction of the combustion air is replaced with oxygen.
17 Preheat Combustion No No x x Research level
Pulverized coal preheated and volatiles and fuel-bound nitrogen compounds are
released in a controlled reducing atmosphere where the nitrogen compounds are
reduced to N2.
18 ROFA-ROTAMIX Yes Yes x x
Combination of OFA and SCR. Wall-fired or tangentially-fired furnace that
utilizes high velocity overfire air. Additional NOx reductions are achieved with
ammonia injection (Rotamix)
19 NOx CEMS Yes Yes x Optimization of combustion
20 Parametric Monitoring Yes Yes x Optimization of combustion
38Catalyst Injection
(EPS Technologies)No No x Research Level
A combustion catalyst is directly injected into the air intake stream and delivered
to the combustion site, initiating chemical reactions that change the dynamics of
the flame.
Post Combustion Controls
21Non-Selective Catalytic
Reduction (NSCR)Yes No x x
For clean services. Too
much stuff in flue gas
would poison catalyst
Under near stoichiometric conditions, in the presence of a catalyst, NOx is
reduced by CO, resulting in nitrogen (N2) and carbon dioxide (CO2).
22Low Temperature Oxidation
(LTO) - Tri-NOx® Yes Yes x x Requires ozone generation
Utilizes an oxidizing agent such as ozone to oxidize various pollutants including
NOx
23Low Temperature Oxidation
(LTO) - LoTOxYes Yes x x x
Has been included as an
"applicable and available"
technology in recent BACT
analyses from multiple
facilities.
Utilizes an oxidizing agent such as ozone to oxidize various pollutants including
NOx
Y:\23\38\131\NMC Process Boilers List of Control Technologies 2006-07-11.xls 2 of 4
Appendix F
Reference(s) Revised: June 8, 2006R
efer
ence
No
.1
NOx Pollution Control
TechnologyAvailable? Applicable?
MP
CA
Ta
con
ite
BA
RT
Rep
ort
AW
MA
Jo
urn
al
9/0
5
Oth
er2
Comments Basic Principle
24Selective Catalytic Reduction
(SCR)Yes Yes x x x
Need to inject at
appropriate temperature.
Applicable on clean side
only.
Ammonia (NH3) is injected into the flue gas stream in the presence of a catalyst
to convert NOx into N2 and water
25 Regenerative SCR Yes Yes x Clean side only
26Selective Non-Catalytic
Reduction (SNCR)Yes Yes x x x
Urea or ammonia-based chemicals are injected into the flue gas stream to convert
NO to molecular nitrogen, N2, and water
27 Adsorption No No x Still in research stages. Use of char (activated carbon) to adsorb oxides of nitrogen
28 Absorption Yes Yes x Similar to TriNOxUse of water, hydroxide and carbonate solutions, sulfuric acid, organic solutions,
molten alkali carbonates, or hydroxides to absorb oxides of nitrogen.
29 Oxidizer Yes Yes xRedundant to regenerative
SCR
Gas stream is sent through the regenerative, recuperative, catalytic or direct fired
oxidizer where pollutants are heated to a combustion point and destroyed.
30 SNOX No No x xEarly commercial
development stage
Catalytic reduction of NOx in the presence of ammonia (NH3), followed by
catalytic oxidation of SO2 to SO3. The exit gas from the SO3 converter passes
through a novel glass-tube condenser in which the SO3 is hydrated to H2SO4
vapor and then condensed to a concentrated liquid sulfuric acid (H2SO4).
31 SOx-NOx-Rox-Box No No xTechnology has not been
demonstrated
Dry sorbent injection upstream of the baghouse for removal of SOx and ammonia
injection upstream of a zeolitic selective catalytic reduction (SCR) catalyst
incorporated in the baghouse to reduce NOx emissions.
32 Electron (E-Beam) Process No No x xNo operating commercial
applications on coal
Electron beam irradiation in the presence of ammonia to initiate chemical
conversion of sulfur and nitrogen oxides into components which can be easily
collected by conventional methods such as an ESP or baghouse.
33 Electrocatalytic Oxidation No No x
Similar to cold plasma.
Will keep watch for
availability of this
technology
Utilizes a reactor in which SO2, NOx, and mercury are oxidized to nitrogen
dioxide (NO2), sulfuric acid, and mercuric oxide respectively using non-thermal
plasma.
On recent project, the vender was doing final trials on full-scale applications.
Y:\23\38\131\NMC Process Boilers List of Control Technologies 2006-07-11.xls 3 of 4
Appendix F
Reference(s) Revised: June 8, 2006R
efer
ence
No
.1
NOx Pollution Control
TechnologyAvailable? Applicable?
MP
CA
Ta
con
ite
BA
RT
Rep
ort
AW
MA
Jo
urn
al
9/0
5
Oth
er2
Comments Basic Principle
34 NOXSO No No x
Commercial version of
adsorption. Limited
experience (proof-of-
concept tests).
Uses a regenerable sorbent to simultaneously adsorb SO2 and NOx from flue gas
from coal-fired utility and industrial boilers. In the process, the SO2 is converted
to a saleable sulfur by-product (liquid SO2, elemental sulfur, or sulfuric acid) and
the NOx is converted to nitrogen and oxygen.
35 Copper-Oxide No No x x
Absorption and SCR.
Experience limited to pilot
scale.
SO2 in the flue gas reacts with copper oxide, supported on small spheres of
alumina, to form copper sulfate. Ammonia is injected into the flue gas before the
absorption reactor and a selective catalytic reduction-type reaction occurs that
reduces the nitric oxides in the flue gas. In the regeneration step, the copper
sulfate is reduced in a regenerator with a reducing agent, such as natural gas,
producing a concentrated stream of SO2.
36 Cold Plasma No No x Research Level
37 Biofilters Yes No x Research level
Gas stream is passed through a filter medium of soil and microbes. Pollutants are
adsorbed and degraded by microbial metabolism forming the products carbon
dioxide and water.
38 Pahlman Process No No x Research Level
Gas stream is passed through a filter baghouse in which specially-developed,
small-particle, high-surface area metal oxide sorbent have been deployed.
Pollutants are removed from the gases by adsorption.
1) This number is for reference only. It does not in any way rank the control technologies.
2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.
b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm
c) New and Emerging Environmental Technologies, http://neet.rti.org/
d) ND BART Reports
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Appendix F
Taconite BART Analysis
SOx Control
Available and Applicable Review
Reference(s) Revised: June 8, 2006
Ref
eren
ce N
o.1
SO2 Pollution Control Technology Available? Applicable?
MP
CA
Taco
nit
e
BA
RT
Rep
ort
MP
CA
BA
RT
Gu
idan
ce
(Att
ach
men
t 2)
Oth
er2
Comments Basic Principle
1 Wet Scrubbing (High Efficiency) Yes Yes x x x Absorption and reaction using an alkaline reagent to produce a solid compound
2 Wet Scrubbing (Low Efficiency) Yes Yes x x x Absorption and reaction using an alkaline reagent to produce a solid compound
3 Wet Walled Electrostatic Precipitator (WWESP) Yes Yes x xExisting fabric filter
control
Suspended particles are separated from the flue gas stream, attracted to plates, and collected in
hoppers
4 Dry sorbent injection Yes Yes x x x
Pulverized lime or limestone is directly injected into the duct upstream of the fabric filter. Dry
sorption of SO2 onto the lime or limestone particle occurs and the solid particles are collected
with a fabric filter
5 Spray Dryer Absorption (SDA) Yes Yes x xLime slurry is sprayed into an absorption tower where SO2 is absorbed by the slurry, forming
CaSO3/CaSO4
6 Alternative Fuels Yes Yes x xNot permitted for
other fuels.Use a fuel with lower sulfur content.
7 Load Reduction Yes No xCould reduce
production
This is a strategy to reduce load on a power plant by reducing the electrical demand throught
efficiency projects.
8 Energy Efficiency Projects Yes Yes x decrease amount of fuel required to make an acceptable product
9 Coal Drying Yes Yes xRequires available
excess heat source
Dry coal will increase the as-burned BTU value, and therefore less fuel is required to be
burned. Specific energy efficiency project
10 Bio Filters No No x Research level
Gas stream passes through a packed bed of specially engineered biomedia which supports the
growth of active bacterial species. The pollutants in the gas stream are biodegraded or
biotransformed into innocuous products, such as carbon dioxide, water, chloride ion in water,
sulfate or nitrate ions in water.
11 CANSOLV Regenerable SO2 No No x Research level
An aqueous solution of proprietary diamine captures SO2 from the feed gas in a countercurrent
absorption tower. The rich solvent is regenerated by steam stripping, giving a byproduct of
pure, water saturated SO2 gas and lean solvent for recycling to the absorber.
12 Pahlman Process No No x Research level
Gas stream is passed through a filter baghouse in which specially-developed, small-particle,
high-surface area metal oxide sorbent have been deployed. Pollutants are removed from the
gases by adsorption.
13 SOx-NOx-Rox-Box No No xTechnology has not
been demonstrated
Dry sorbent injection upstream of the baghouse for removal of SOx and ammonia injection
upstream of a zeolitic selective catalytic reduction (SCR) catalyst incorporated in the baghouse
to reduce NOx emissions.
14 Electron (E-Beam) Process No No x
No operating
commercial
applications on coal
Electron beam irradiation in the presence of ammonia to initiate chemical conversion of sulfur
and nitrogen oxides into components which can be easily collected by conventional methods
such as an ESP or baghouse.
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Appendix F
Reference(s) Revised: June 8, 2006
Ref
eren
ce N
o.1
SO2 Pollution Control Technology Available? Applicable?
MP
CA
Taco
nit
e
BA
RT
Rep
ort
MP
CA
BA
RT
Gu
idan
ce
(Att
ach
men
t 2)
Oth
er2
Comments Basic Principle
15 Electrocatalytic Oxidation No No x
Similar to cold
plasma. Will keep
watch for availability
of this technology
Utilizes a reactor in which SO2, NOx, and mercury are oxidized to nitrogen dioxide (NO2),
sulfuric acid, and mercuric oxide respectively using non-thermal plasma.
On recent project, the vender was doing final trials on full-scale applications.
16 NOXSO No No
Commercial version
of adsorption.
Limited experience
(proof-of-concept
tests).
Uses a regenerable sorbent to simultaneously adsorb SO2 and NOx from flue gas from coal-
fired utility and industrial boilers. In the process, the SO2 is converted to a saleable sulfur by-
product (liquid SO2, elemental sulfur, or sulfuric acid) and the NOx is converted to nitrogen
and oxygen.
17 Copper-Oxide No No x
Absorption and
SCR. Experience
limited to pilot scale.
SO2 in the flue gas reacts with copper oxide, supported on small spheres of alumina, to form
copper sulfate. Ammonia is injected into the flue gas before the absorption reactor and a
selective catalytic reduction-type reaction occurs that reduces the nitric oxides in the flue gas.
In the regeneration step, the copper sulfate is reduced in a regenerator with a reducing agent,
such as natural gas, producing a concentrated stream of SO2.
18 SNOX No No xEarly commercial
development stage
Catalytic reduction of NOx in the presence of ammonia (NH3), followed by catalytic oxidation
of SO2 to SO3. The exit gas from the SO3 converter passes through a novel glass-tube
condenser in which the SO3 is hydrated to H2SO4 vapor and then condensed to a concentrated
liquid sulfuric acid (H2SO4).
19 Cold Plasma No No x Research level
1) This number is for reference only. It does not in any way rank the control technologies.
2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.
b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm
c) New and Emerging Environmental Technologies, http://neet.rti.org/
d) ND BART Reports
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