northshore mining company analysis of best available ... · y:\23\00 mn taconite bart...

$: Northshore Mining Company Analysis of Best Available ... · Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc$
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\NMC Furnace BART Report_9-6-2006.doc

i

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


ii

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


iii

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


iv

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.


v

• 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


1

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.


2

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


3

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.


4

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


5

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


6

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.


7

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.


8

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.


9

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


10

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.


11

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


12

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.


13

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.


14

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.


15

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


NA NA NA NA 8 SV018 631328.6 5238905.9 69 767 2.7 15,000 77

EU 019


NA NA NA NA 8 SV019 631334.4 5238915.1 69 767 2.7 15,000 77

EU 020


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


102

NA NA NA NA 18 SV045 631486.7 5238828.7 93 716 3.3 29200 77


16

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


103

NA NA NA NA 18 SV046 631501.3 5238849.0 93 716 3.3 29200 77

EU 047


104

NA NA NA NA 18 SV047 631514.8 5238870.3 93 716 3.3 29200 77

EU 048


105

NA NA NA NA 18 SV048 631529.4 5238890.7 93 716 3.3 29200 77

EU 049


106

NA NA NA NA 18 SV049 631544.0 5238911.0 93 716 3.3 29200 77

EU 050


107

NA NA NA NA 18 SV050 631557.6 5238932.3 93 716 3.3 29200 77

EU 051


108

NA NA NA NA 18 SV051 631572.1 5238952.6 93 716 3.3 29200 77

EU 052


109

NA NA NA NA 18 SV276 631590.6 5238980.0 93 716 3.3 29200 77

EU 053


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


17

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


284 410 272 SV102 631344.3 5238338.3 121 636 6.0 74300 142

EU 100


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


284 410 272 SV111 631361.5 5238372.7 121 636 6.0 70700 142


18

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


284 410 272 SV112 631365.6 5238369.7 121 636 6.0 74300 142

EU 110


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


19

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.


20

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


21

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


22

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.


23

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:


24

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%.


25

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.


26

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


27

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


28

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.


29

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


$16,952,864 $2,401,349 $139,872 NA

Furnace 11 Waste Gas

$15,859,420 $2,201,975 $384,034 NA


$16,952,864 $2,401,349 $152,149 NA


$15,859,420 $2,201,975 $417,742 NA

Secondary Wet Walled Electrostatic Precipitator (WWESP)


$23,617,556 $4,188,875 $182,993 NA


$21,846,389 $3,799,211 $496,949 NA


$23,617,556 $4,294,171 $204,058 NA


$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


30

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.


31

• 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


32

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


33

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


34

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 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.







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.


35

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.



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.


31 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 4.


36

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.


37

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.


38

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;


39

• 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


40

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


41

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


42

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.




Consequently, the technical feasibility of LTO on an indurating furnace is technically infeasible for

this application and will not be evaluated further.


43

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?


Yes Yes No

Low- NOx Burners Yes Yes No


Yes Yes No


Ported Kilns Yes No No

Alternative Fuels Yes Yes No

Process Optimization using NOx CEMS

Yes No No


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


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%


44

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


(MM$)

Total Annual Cost

(MM$/yr)



Incremental Control Cost

($/ton) Selective Catalytic Reduction (SCR)

With Reheat


$25,735,488 $11,314,358 $155,784 NA


$23,344,084 $8,274,322 $46,771 NA


$25,912,320 $11,387,084 $162,309 NA


$24,026,527 $10,442,659 $61,107 NA







45















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.


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





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.



46

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,


47

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.


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.


48

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.


49

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 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.


50

Alternate Fuels



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.



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.



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.



51

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


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


52

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


($)

Total Annual Cost

($/yr)



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










34 U.S. EPA, January 2002, EPA Air Pollution Control Cost Manual, Sixth Edition.


53











technology as compared to the next most effective alternative. Since none of the technologies are

cost effective, the incremental control cost is not applicable.


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





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.



54

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) 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


55

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, 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%.


56


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.







Alternate Fuels



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.



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





57


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.


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:


58

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,


59

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.




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.


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®.


60

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.


61

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


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%


62

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


($) Operating Cost

($/yr)



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








63













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.


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.



64

5.B.ii.e STEP 5 – Evaluate Visibility Impacts





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


65

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


66

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)


0.5 deciview

Modeled 98th

Percentile

Value (deciview)


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



0.5 deciview

Improved Modeled 98

th



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


67

6. Visibility Impacts



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


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.


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


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



SV114 Furnace 12 Waste Gas --- 5.9 --- 62.4 10.6


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



SV104 Furnace 11 Waste Gas 5.9 --- 62.4 10.6


SV111 Furnace 12 Hood Exh 11.8 --- 17.1 11.3



SV114 Furnace 12 Waste Gas 5.9 --- 62.4 10.6


SV003 Process Boilers 1 & 2 33.5 50.0% 11.6 1.9


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)


0.5 deciview

Modeled 98th

Percentile

Value (deciview)

No. of days exceeding 0.5

deciview

Modeled 98th

Percentile

Value (deciview)


deciview

Modeled 98th

Percentile

Value (deciview)


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


Decreased No. of Days exceeding

0.5 dV

Improved Modeled 98th


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


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



SO2 Control Cost Summary


Eff %

Controlled

Emissions T/y

Emission

Reduction T/yr

Installed Capital

Cost $

Total Annual Cost

$/yr

Pollution Control

Cost $/ton






Wet Scrubber





Selective Catalytic Reduction with Reheat

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

Cost Summary 9/6/2006 Page 1 of 56



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


Stack/Vent Number SV 104 & 105

Operating Unit: Furnace 12 Hood Exhaust


Stack/Vent Number SV 111, 112, & 113



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


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


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


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.




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


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


Fce 12\Data. Average from test results in: Fce 12 HE 1201-1203 4-18-06.

SV 114 & 115 16.4% 2006


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





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





Table 3: SOx Control - Wet Scrubber


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.


EU100 Wet Scrubber 9/6/2006 Page 4 of 56




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


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



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



See Summary page for notes and assumptions






Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst:


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.


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


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








Emission Unit Number EU 104 Stack/Vent Number SV 104 & 105








Capital Costs










Operating Costs




Actual






Notes & Assumptions











CAPITAL COSTS








Installation




Piping 30% of purchased equip cost (B) 905,571














60% of TCI 3,622,282






OPERATING COSTS


Operating Labor



Maintenance
























Interest Rate 7.00%


CRF 0.0944



CRF 0.0000






Annualized Cost 0


Equipment Life 3

CRF 0.3811






Annualized Cost 0

Electrical Use





Other

Total 382.5






7,068 gpm






Operating Labor



Maintenance














Table 5 SOx Control - Wet Scrubber










Capital Costs










Operating Costs




Actual






Notes & Assumptions











CAPITAL COSTS








Installation




Piping 30% of purchased equip cost (B) 1,008,081














60% of TCI 4,032,324






OPERATING COSTS


Operating Labor



Maintenance
























Interest Rate 7.00%


CRF 0.0944



CRF 0.0000






Annualized Cost 0


Equipment Life 3

CRF 0.3811






Annualized Cost 0

Electrical Use





Other

Total 457.4






8,451 gpm






Operating Labor



Maintenance
























Capital Costs










Operating Costs




Actual






Notes & Assumptions











CAPITAL COSTS








Installation


















60% of TCI 3,622,282






OPERATING COSTS


Operating Labor



Maintenance
























Interest Rate 7.00%


CRF 0.0944



CRF 0.0000






Annualized Cost 0


Equipment Life 3

CRF 0.3811






Annualized Cost 0

Electrical Use





Other

Total 382.5






7,068 gpm






Operating Labor



Maintenance














Table 7: SO2 Control - Wet Walled Electrostatic Precipitator










Capital Costs








Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,770,091


Operating Costs

Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,425,578



Actual

Emission Control Cost Calculation Emissions





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.



EU100 WWESP 9/6/2006 Page 16 of 56




CAPITAL COSTS


Purchased Equipment (A)1

Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 3,999,843


MN Sales Taxes 6.5% of control device cost (A) 259,990



Installation











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





60% of TCI 6,531,583



Site Specific - Other Site Specific NA



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



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









See summary page for notes and assumptions


EU100 WWESP 9/6/2006 Page 17 of 56






Interest Rate 7.00%


CRF 0.0944


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


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


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




EU100 WWESP 9/6/2006 Page 18 of 56













Capital Costs










Operating Costs




Actual






Notes & Assumptions





EU104 WWESP 9/6/2006 Page 19 of 56




CAPITAL COSTS








Installation



















60% of TCI 5,867,396







Operating Labor

Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr 104,239


Maintenance

Maintenance Labor 60.00 $/Hr, 15.0 hr/wk, 8339.1 hr/yr 4,125




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



Overhead 60% of total labor and material costs 95,958Administration (2% total capital costs) 2% of total capital costs (TCI) 195,580








EU104 WWESP 9/6/2006 Page 20 of 56






Interest Rate 7.00%


CRF 0.0944


Equipment Life 3

CRF 0.3811


Amount Required 0




Annualized Cost 0

Electrical Use





Plate Area


Total 439.5


gpm


lb/hr






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


Maintenance

Maint Labor 60.00 $/Hr 15.0 hr/wk 660 4,125 $/Hr, 15.0 hr/wk, 8339.1 hr/yr



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





EU104 WWESP 9/6/2006 Page 21 of 56













Capital Costs










Operating Costs




Actual






Notes & Assumptions





EU110 WWESP 9/6/2006 Page 22 of 56




CAPITAL COSTS








Installation



















60% of TCI 6,531,583







Operating Labor



Maintenance





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












EU110 WWESP 9/6/2006 Page 23 of 56






Interest Rate 7.00%


CRF 0.0944


Equipment Life 3

CRF 0.3811


Amount Required 0




Annualized Cost 0

Electrical Use





Plate Area


Total 525.5


gpm


lb/hr






Operating Labor



Maintenance




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





EU110 WWESP 9/6/2006 Page 24 of 56













Capital Costs










Operating Costs




Actual






Notes & Assumptions





EU114 WWESP 9/6/2006 Page 25 of 56




CAPITAL COSTS








Installation



















60% of TCI 5,867,396







Operating Labor



Maintenance





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











EU114 WWESP 9/6/2006 Page 26 of 56






Interest Rate 7.00%


CRF 0.0944


Equipment Life 3

CRF 0.3811


Amount Required 0




Annualized Cost 0

Electrical Use





Plate Area


Total 439.5


gpm


lb/hr






Operating Labor



Maintenance





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





EU114 WWESP 9/6/2006 Page 27 of 56



Table 11: - SCR + Reheat (100)


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




Capital Costs

Direct Capital Costs EPRI Correlation


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


NOx SCR+ Reheat 90% Eff (100) NOx SCR+ Reheat 90% Eff (100) 28 of 56




CAPITAL COSTS



Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 10,191,798

Instrumentation 10% of control device cost (A) NA


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


60% of TCI 14,539,390

Total Retorfit Capital Investment 38,771,707

OPERATING COSTS


Operating Labor



Maintenance

Maintenance Total 1.50 % of Total Capital Investment 363,485

Maintenance Materials NA % of Maintenance Labor -


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 -

















Interest Rate 7.00%


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


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 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


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


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






Table 12: Reheat (100)






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



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






Operating Costs


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



Reheat (100) Reheat (100) 31 of 56




CAPITAL COSTS


Purchased Equipment (A) (1) 535,530

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC



Freight 5% of control device cost (A) 26,776Purchased Equipment Total (B) 22% 650,668

Installation


Handling & erection 14% of purchased equip cost (B) 91,094





Installation Subtotal Standard Expenses 30% 195,201




Total Site Specific Costs 6,200,000Installation Total 6,395,201



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



Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 7,247,576


Operating Labor



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







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





Cleveland Cliffs Incorporated: United Taconite

BART Report - <Insert attachment name> Emission Control Cost Analysis




Interest Rate 7.00%


CRF 0.0944

Replacement Catalyst: Catalyst


CRF 0.5531



Catalyst Cost 0 Cost adjusted for freight & sales tax



Annualized Cost 0


Equipment Life 3

CRF 0.3811

Rep part cost per unit 0 $ each


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.


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 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


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



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








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)







Emission Unit Number EU 104 Stack/Vent Number SV 104 & 105 Chemical Engineering








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







Operating Costs








Notes & Assumptions












12 $35/MW-hr, 140 MW


Notes to User






CAPITAL COSTS





















60% of TCI 13,498,404


OPERATING COSTS


Operating Labor



Maintenance





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 -

















Interest Rate 7.00%


CRF 0.0944

Equivalent Duty 814 Plant Cap kW A 83,511








SCR Capital Cost

Duty 814 MMBtu/hr Catalyst Area 393 ft2

638 f (h SCR)









Electrical Use

Duty 814 MMBtu/hr kW






Total 1167.5





167 lb/hr






Adjusted Duty 814 MMBtu/hr





Operating Labor



Maintenance






7 Ammonia 0.12 $/lb 167 lb/hr 1,297,437 156,470 $/lb, 167 lb/hr, 8339.1 hr/yr, 93% utilization







Table 14: - Reheat (104)









Capital Costs










Operating Costs



Notes & Assumptions








CAPITAL COSTS







Installation




















Operating Labor



Maintenance




Natural Gas 10.02 $/mscf, 485 scfm, 8339.1 hr/yr, 93% utilization 2,259,937

















Interest Rate 7.00%


CRF 0.0944



CRF 0.5531






Annualized Cost 0


Equipment Life 3

CRF 0.3811





Annualized Cost 0

Electrical Use








Operating Labor



Maintenance





Natural Gas 10.02 $/mscf 485 scfm 225,534 2,259,937 $/mscf, 485 scfm, 8339.1 hr/yr, 93% utilization






















Qaf 485 scfm - Flow of auxiliary fuel



Heat Rec % A B







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


(EPA 453/B-96-001)















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







Operating Costs








Notes & Assumptions












12 $35/MW-hr, 140 MW


Notes to User






CAPITAL COSTS





















60% of TCI 14,638,961


OPERATING COSTS


Operating Labor



Maintenance





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 -

















Interest Rate 7.00%


CRF 0.0944

Equivalent Duty 1,074 Plant Cap kW A 110,187








SCR Capital Cost

Duty 1,074 MMBtu/hr Catalyst Area 518 ft2

613 f (h SCR)









Electrical Use

Duty 1,074 MMBtu/hr kW






Total 1474.3





69 lb/hr






Adjusted Duty 1,074 MMBtu/hr





Operating Labor



Maintenance






7 Ammonia 0.12 $/lb 69 lb/hr 532,660 64,238 $/lb, 69 lb/hr, 8339.1 hr/yr, 93% utilization
















Capital Costs










Operating Costs



Notes & Assumptions








CAPITAL COSTS







Installation




















Operating Labor



Maintenance




Natural Gas 10.02 $/mscf, 1,114 scfm, 8339.1 hr/yr, 93% utilization 5,195,069

















Interest Rate 7.00%


CRF 0.0944



CRF 0.5531






Annualized Cost 0


Equipment Life 3

CRF 0.3811





Annualized Cost 0

Electrical Use








Operating Labor



Maintenance





Natural Gas 10.02 $/mscf 1,114 scfm 518,449 5,195,069 $/mscf, 1,114 scfm, 8339.1 hr/yr, 93% utilization






















Qaf 1,114 scfm - Flow of auxiliary fuel



Heat Rec % A B







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


(EPA 453/B-96-001)








Desgin Capacity 150 MMBtu/hr Standardized Flow Rate 152,520 scfm @ 32º F

Expected Utiliztion Rate 93% Temperature 140 Deg F






Capital Costs

Direct Capital Costs EPRI Correlation


Purchased Equipment Total (B) SCR Only 9,509,529







Operating Costs








Notes & Assumptions












12 $35/MW-hr, 140 MW


Notes to User






CAPITAL COSTS





















60% of TCI 13,594,972


OPERATING COSTS


Operating Labor



Maintenance





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 -

















Interest Rate 7.00%


CRF 0.0944

Equivalent Duty 833 Plant Cap kW A 85,452








SCR Capital Cost

Duty 833 MMBtu/hr Catalyst Area 402 ft2

638 f (h SCR)









Electrical Use

Duty 833 MMBtu/hr kW






Total 1194.4





167 lb/hr






Adjusted Duty 833 MMBtu/hr





Operating Labor



Maintenance






7 Ammonia 0.12 $/lb 167 lb/hr 1,297,437 156,470 $/lb, 167 lb/hr, 8339.1 hr/yr, 93% utilization
















Capital Costs






Installation Total 6,386,826 Total Direct Capital Cost, DC 7,009,581



Operating Costs



Notes & Assumptions








CAPITAL COSTS







Installation










Site Specific - Other Site Specific 0Total Site Specific Costs 6,200,000










Operating Labor



Maintenance




Natural Gas 10.02 $/mscf, 935 scfm, 8339.1 hr/yr, 93% utilization 4,359,280

















Interest Rate 7.00%


CRF 0.0944



CRF 0.5531






Annualized Cost 0


Equipment Life 3

CRF 0.3811


Amount Required 0 NumberTotal Rep Parts Cost 0 Cost adjusted for freight & sales tax



Annualized Cost 0

Electrical Use








Operating Labor



Maintenance





Natural Gas 10.02 $/mscf 935 scfm 435,040 4,359,280 $/mscf, 935 scfm, 8339.1 hr/yr, 93% utilization






















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


Heat Rec % A B







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


(EPA 453/B-96-001)



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.

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xlsWWESP Scale 9/6/2006 Page 56 of 56

Northshore Process Boiler


Table 19: Cost Summary - Natural gas boiler

NOx Control Cost Summary baseline: 0.17 lb/mmBtu 11.625 lb/hr


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


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

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls

Cost Summary 9/6/2006 Page 1 of 42



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


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


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


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


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



Section 2 lists $20 - $30/ton Used $25/ton. Cost adjusted for 3%

inflation

Hazardous Waste Disposal 281.38 $/ton 250.00 2002



Section 2 lists $200 - $300/ton Used $250/ton. Cost adjusted for 3%

inflation

Waste Transport 0.56 $/ton-mi 0.50 2002


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


2002, Section 6, Chapter 1 Example problem cost for 10 ft bags. Cost adjusted for 3% inflation

Tower Packing 100 $/ft3



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


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


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)



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





Capital Costs Direct Capital Costs



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 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


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


Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xlsLow NOx 9/6/2006 Page 4 of 42


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


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


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




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



Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 95,851

OPERATING COSTS


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


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




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






Interest Rate 7.00%Equipment Life 20 yearsCRF 0.0944

Replacement Catalyst: CatalystEquipment Life 2 years

CRF 0.5531



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


Equipment Life 3CRF 0.3811Rep part cost per unit 37.940902 $ eachAmount Required 0 Number



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



Operating Cost Calculations Annual hours of operation: 7,650Utilization Rate: 93.0%


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


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



Northshore Process BoilerBART Report - Appendix A Emission Control Cost AnalysisTable 22: NOx Control - Low NOx Burner with Flue Gas Recirculation/Advanced Controls














Operating Costs





Nitrous Oxides (NOx) 11.6 41.3 75% 10.3 30.9 2,505



Notes & Assumptions


Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xlsLow NOx FGR 9/6/2006 Page 7 of 42


CAPITAL COSTS





Installation


Piping 2% of purchased equip cost (B) 6,804Insulation 1% of purchased equip cost (B) 3,402












OPERATING COSTS


Operating LaborOperator 50.00 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr 478Supervisor 15% 15% of Operator Costs 72






NA NA -

NA NA -

NA NA -
















CRF 0.5531









Annualized Cost 0








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


Electricity 0.052 $/kwh 3.2 kW-hr 22,766 1,184 $/kwh, 3 kW-hr, 7650 hr/yr, 93% utilization















Northshore Process BoilerBART Report - Appendix A Emission Control Cost AnalysisTable 23: NOx Control - Low NOx Burner with Overfire Air







Capital Costs [2] Direct Capital Costs 468000







Operating Costs








Notes & Assumptions


2 Cost based upon Analyzing Electric Power Gneration Under the CAAA.

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xlsLow NOx OFA 9/6/2006 Page 10 of 42


CAPITAL COSTS





Installation


Piping 2% of purchased equip cost (B) 13,559Insulation 1% of purchased equip cost (B) 6,780












OPERATING COSTS


Operating LaborOperator 50.00 $/Hr, 2.0 hr/8 hr shift, 7650 hr/yr 95,625Supervisor 15% 15% of Operator Costs 14,344






NA NA -

NA NA -

NA NA -
















CRF 0.5531









Annualized Cost 0


Blower, Thermal 0 19 0.6 0.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1






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


Electricity 0.052 $/kwh 170.0 kW-hr 1,209,465 62,892 $/kwh, 170 kW-hr, 7650 hr/yr, 93% utilization















Northshore Process BoilerBART Report - Appendix A Emission Control Cost AnalysisTable 23: Selective Catalytic Reduction - Basis Power Plant Installed Cost


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


Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfmExpected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68º F




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


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







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.

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xlsNOx SCR PwrPlt 9/6/2006 Page 13 of 42


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


Total Site Specific Costs NA

Installation Total NA

Total Direct Capital Cost, DC NA


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



OPERATING COSTS


Operating LaborOperator NA - Supervisor NA -

MaintenanceMaintenance Labor NA - Maintenance Materials 100% of maintenance labor costs -


NA NA -



NA NA -

NA NA -

CO Catalyst 650.00 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization 52,717















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






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




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


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










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





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


Capital Cost $/kW D $150.00Fixed O&M Cost, $/yr E $36,719

E = D*A*0.0066


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.




Table 25: Selective Non-Catalytic Reduction SNCR


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





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








Operating Costs


Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 96,655Total Annual Cost (Annualized Capital Cost + Operating Cost) 250,181






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


NOx SNCR 9/6/2006 Page 17 of 42




CAPITAL COSTS



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


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


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


OPERATING COSTS


Operating LaborOperator NA -

Supervisor NA -

Maintenance


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 -



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










Interest Rate 7.00%

Equipment Life 20 yearsCRF 0.0944

Replacement Catalyst <- Enter Equipment Name to Get CostEquipment Life 5 years

CRF 0.2439



Packing Cost 6,690 Cost adjusted for freight & sales taxInstallation Labor 1,004 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)


Replacement Parts & Equipment: <- Enter Equipment Name to Get Cost


CRF 0.0000


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 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



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







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






Table 26: SO2 Control - Wet ESP



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






Capital Costs Year


Purchased Equipment (A) 2005 5,519,073 2,687,838








Operating Costs





Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost (5)


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.


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


SO2 WESP 9/6/2006 Page 20 of 42

4) See comments in cell V88 regarding selection of reagents, catalysts and supplies


SO2 WESP 9/6/2006 Page 21 of 42




CAPITAL COSTS


Purchased Equipment (A) (1) 2,687,838






Installation











Engineering, supervision 20% of purchased equip cost (B) 653,145Construction & field expenses 20% of purchased equip cost (B) 653,145






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



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



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




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




SO2 WESP 9/6/2006 Page 22 of 42


SO2 WESP 9/6/2006 Page 23 of 42






Interest Rate 7.00%


CRF 0.0944



CRF 0.0000






Annualized Cost 0


Equipment Life 3

CRF 0.3811






Annualized Cost 0

Electrical Use


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


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 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




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





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



Note: Select reagent, catayst and repacement parts by entering number in coluND U. Unhide Col U to enter choice.


SO2 WESP 9/6/2006 Page 24 of 42



Table 27: SO2 Absorber










Capital Costs Year

Direct Capital Costs (1) 2002 [1] 1,908,056









Operating Costs


Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 520,746





PM10 8.3 - 8.3 - NA

Total Particulates 8.3 - 8.3 - NA



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.





Notes to User







SO2 Absorber 9/6/2006 Page 25 of 42




CAPITAL COSTS








Installation











Engineering, supervision 5% of purchased equip cost (B) 61,486Construction & field expenses 0% of purchased equip cost (B) 0



Performance test 1% of purchased equip cost (B) 12,297Model Studies NA of purchased equip cost (B) NA




Retrofit TCI (TCI*1.6) (5) 3,935,118

Site Preparation, as required site preparation and foundations 0





OPERATING COSTS


Operating Labor



Maintenance

Maintenance Labor 60.00 $/Hr, 0.5 hr/8 hr shift, 7650 hr/yr 28,688




NA NA -


NA NA -

NA NA -

WW Treat Neutralization 3.80 $/mgal, 91 gpm, 7650 hr/yr, 93% utilization 147,690

NA NA -


NA NA -

NA NA -

NA NA -

Lime 90.00 $/ton, 16 lb/hr, 7650 hr/yr, 93% utilization 5,161

NA NA -

NA NA -


NA NA -







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










Interest Rate 7.00%


CRF 0.0944



CRF 0.0000






Annualized Cost 0


Equipment Life 3

CRF 0.3811






Annualized Cost 0

Electrical Use



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


Other

Total 246.4




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)


NOx 50.90 0.166071429 11.625

SO2 73.40 0.239285714 16.75





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


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







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






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



Filter Bags 37.94 $/bag 0 bags 0 0 $/bag, 0 bags, 7650 hr/yr, 93% utilization








Table 28: SO2 Control - Spray Dryer and Baghouse










Capital Costs Year

Direct Capital Costs (1) 2002 [1] 7,786,400








Total Capital Investment (TCI) = DC + IC (5) 16,134,577

Operating Costs (2)







PM10 8.3 - 8.3 - NA




Notes & Assumptions

1 Stone and Webster 2002 total direct installed cost estimate adjusted for inflation


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.


Notes to User







Spray Dry Baghouse 9/6/2006 Page 30 of 42




CAPITAL COSTS








Installation












Construction & field expenses 0% of purchased equip cost (B) 0Contractor fees 5% of purchased equip cost (B) 266,775


Performance test 1% of purchased equip cost (B) 53,355





Retrofit TCI (TCI*1.6) (7) 16,134,577







Operating Labor



Maintenance





NA NA -


NA NA -

Comp Air 0.32 $/mscf, 2 scfm/kacfm, 7650 hr/yr, 93% utilization 32,391

NA NA -

NA NA -


NA NA -

NA NA -

NA NA -

Lime 90.00 $/ton, 16 lb/hr, 7650 hr/yr, 93% utilization 5,161

NA NA -


NA NA -

Filter Bags 37.94 $/bag, 0 bags, 7650 hr/yr, 93% utilization 76,951


















Interest Rate 7.00%


CRF 0.0944

Replacement Catalsyt:


CRF 0.0000






Annualized Cost 0

Replacement Parts & Equipment: Filter bags & cages (4)


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


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




NOx 50.90 0.166071429 11.625

SO2 73.40 0.239285714 16.75





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


Maintenance








(3) Comp Air 0.32 $/mscf 2 scfm/kacfm 102,278 32,391 $/mscf, 2 scfm/kacfm, 7650 hr/yr, 93% utilization







1 Lime 90.0 $/ton 16.1 lb/hr 57 5,161 $/ton, 16 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








Table 29: SO2 Control - Dry Sorbent Injection and Baghouse










Capital Costs Year

Direct Capital Costs (1) 1997 2,359,900

Purchased Equipment (A) 2005 [6] 2,813,727 1,330,934







Total Capital Investment (TCI) = DC + IC (5) 4,890,063

Operating Costs (2)







PM10 8.3 - 8.3 - NA




Notes & Assumptions

1 Total Direct Capital Cost Cost Estimated using the Integrated Air Pollution Control Sytem Program Version 5a, EPA May 1999


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


Notes to User







DSI Baghouse 9/6/2006 Page 35 of 42




CAPITAL COSTS








Installation









Total Direct Capital Cost, DC (6) 2,813,727


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


Performance test 1% of purchased equip cost (B) 16,171





Retrofit TCI (TCI*1.6) (7) 4,890,063







Operating Labor



Maintenance





NA NA -


NA NA -

Comp Air 0.32 $/mscf, 2 scfm/kacfm, 7650 hr/yr, 93% utilization 32,391

NA NA -

NA NA -


NA NA -

NA NA -

NA NA -

Lime 90.00 $/ton, 16 lb/hr, 7650 hr/yr, 93% utilization 5,161 (3)

NA NA -


NA NA -

Filter Bags 37.94 $/bag, 0 bags, 7650 hr/yr, 93% utilization 76,951


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



Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 461,587











Interest Rate 7.00%


CRF 0.0944

Replacement Catalsyt:


CRF 0.0000






Annualized Cost 0

Replacement Parts & Equipment: Filter bags & cages (4)


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


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




NOx 50.90 0.166071429 11.625

SO2 73.40 0.239285714 16.75





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


Maintenance








Comp Air 0.32 $/mscf 2 scfm/kacfm 102,278 32,391 $/mscf, 2 scfm/kacfm, 7650 hr/yr, 93% utilization







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



Filter Bags 37.94 $/bag 0 bags NA 76,951 $/bag, 0 bags, 7650 hr/yr, 93% utilization










Emission Unit Number 003 & 004 Stack/Vent Number 003



Expected Annual Hours of Operation 7,650 0 Moisture Content 13% 0


Expected Equipment Life 20 0 Standardized Flow Rate 69,510 scfm @ 68º F



Capital Costs










Operating Costs




Actual






Notes & Assumptions







Wet Scrubber 9/6/2006 Page 40 of 42




CAPITAL COSTS








Installation

















Retrofit multiplier5 60% of TCI 2,781,946






OPERATING COSTS


Operating Labor



Maintenance
























Interest Rate 7.00%


CRF 0.0944



CRF 0.0000






Annualized Cost 0


Equipment Life 3

CRF 0.3811






Annualized Cost 0

Electrical Use





Other

Total 246.4





Circulating Water Rate24,552 gpm


Evaopration Loss4 = 21.36 gpm




Operating Labor



Maintenance












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

[email protected]

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

Barr F

ooter

: Date

: 6/3/

2004

4:10

:56 PM

File

: C:\T

emp\T

est.m

xd U

ser:

bal

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


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


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


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.

� �N

Barr Footer: Date: 7/5/2006 2:27:05 PM File: I:\projects\23\00\Minntac.mxd User: ams

1000

Meters

Northshore A

erial Photo

BTH

Pencil

BTH

Pencil

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

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


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


NOx Control


Step 1 Step 2


Refe

ren

ce N

o.1


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?


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.


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


NOx Control


Step 1 Step 2


Refe

ren

ce N

o.1


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?



(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.


NOx Control


Step 1 Step 2


Refe

ren

ce N

o.1


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?


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


NOx Control


Step 1 Step 2


Refe

ren

ce N

o.1


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?


2) c) New and Emerging Environmental Technologies, http://neet.rti.org/

2) d) ND BART Reports


SO2 Control

Available and Applicable Review

Revised: August 23, 2006

Step 1 Step 2


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?


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


Y (for large


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.


SO2 Control


Revised: August 23, 2006

Step 1 Step 2


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?


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.


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 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



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


Reference(s) Revised: June 8, 2006

Ref

eren

ce N

o.1


TechnologyAvailable? Applicable?

MP

CA

Ta

con

ite

BA

RT

Rep

ort

AW

MA

Jo

urn

al

9/0

5

Oth

er2


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



MP

CA

Ta

con

ite

BA

RT

Rep

ort

AW

MA

Jo

urn

al

9/0

5

Oth

er2


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.


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).


(LTO) - Tri-NOx® Yes Yes x x Requires ozone generation

Utilizes an oxidizing agent such as ozone to oxidize various pollutants including

NOx


(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


Appendix F


efer

ence

No

.1



MP

CA

Ta

con

ite

BA

RT

Rep

ort

AW

MA

Jo

urn

al

9/0

5

Oth

er2


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 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.



Appendix F


efer

ence

No

.1



MP

CA

Ta

con

ite

BA

RT

Rep

ort

AW

MA

Jo

urn

al

9/0

5

Oth

er2


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.



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


Appendix F


SOx Control



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


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.


Appendix F


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


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.


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



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


northshore mining company analysis of best available ... · y:\23\00 mn taconite bart...

Documents