# Appendix 9H

Tilden Mining Company BART

Technical Analysis

# West (Tilden) Analysis of Best Available Retrofit Technology (BART)

Table of Contents

1. Executive Summary

, v

2. Introduction 1

2.A BART Eligibility 2

2.B BART Determinations :

.. 3

3. Streamlined BART Analysis :

.. 

# 8

3.A Indurating Furnaces 8

3.B PM-Only Taconite MACT EmissionUnits 9

3.C Other Combustion Units 9

4. Baseline Conditions andVisibility Impacts for BART Eligible Units 12

4.A MDEQ Subject-to-BART Modeling 12

4.B Facility Baseline Modeling 13

4.C Facility Baseline Modeling Results 15

5. BART Analysis for Indurating Furnaces :16

5.A Line 1 Indurating Furnace 16

5.A.i Sulfur Dioxide Controls 17

5.A.i.a STEP 1- Identify All Available Retrofit Control Technologies 17

5.A.i.b STEP 2 - Eliminate Teclmically Infeasible Options 17

5.A.i.c STEP 3 - Evaluate Control Effectiveness of Remaining Control

Technologies 23

5.A.i.d STEP 4 - Evaluate Impacts and Document the Results 23

5.A.i.e STEP 5 - Evaluate Visibility Impacts 26

5.A.ii Nitrogen Oxide Controls : 33

5.A.ii.a STEP 1- Identify All Available Retrofit Control Technologies 33

5.A.ii.b STEP i-Eliminate Technically Infeasible Options ·33

5.A.ii.c STEP 3 - Evaluate Control Effectiveness of Remaining Control

Technologies 46

5.A.ii.d STEP 4 - Evaluate Impacts and Document the Results .46

5.A.ii.e STEP 5 - Evaluate Visibility Impacts 49

5.B Process Boilers 1 and 2 .55

5.B.i Sulfur Dioxide Controls : 55

5.B.i.a STEP 1 - Identify All Available Retrofit Control Technologies 55

5.B.i.b STEP 2 - Eliminate Technically Infeasible Options 55

5.B.i.c STEP 3- Evaluate Control Effectiveness of Remaining Control

Technologies 59

5.B.i.d STEP 4 - Evaluate Impacts and Document the Results 59

5.B.i.e STEP 5 - Evaluate Visibility Impacts 61

5.B.ii Nitrogen Oxide Controls 62

5.B.ii.a STEP 1 - Identify All Available Retrofit Control Technologies 62

Y:\22152\080 Tilden BARTIBART reportlTIIden BART Report (2006-12-28).doc

# 5.B.ii.b STEP 2 Eliminate TeclmicallyInfeasible Options

.. ; 62

5.B.ii.c STEP 3 - Evaluate Control Effectiveness of Remaining Control

Teclmologies 70

5.B.ii.d STEP 4 - Evaluate Impacts and Document the Results 71

5.B.ii.e STEP 5 - Evaluate Visibility Impacts 73

5.C Line I Dryer 81

5.C.i Sulfur Dioxide Controls 81

5.C.i.a STEP 1- IdentifY All Available Retrofit ControI.Teclmologies 81

5.C.i.b STEP 2 - Eliminate Teclmically Infeasible Options 81

5.C.i.,,- STEP3

- Evaluate Control Effectiveness of Remaining Control

Teclmologies 87

5.C.i.d STEP 4- Evaluate Impacts and Document the Results 87

5.A.ii.f STEP 5 - Evaluate Visibility Impacts 89

5.C.ii Nitrogen Oxide Controls 90

5.C.ii.a STEP 1 - IdentifY All Available Retrofit Control Teclmologies 90

5.C.ii.b STEP 2 - Eliminate Teclmically Infeasible Options 90

5.C.ii.c STEP 3 - Evaluate Control Effectiveness of Remaining Control

Teclmologies 98

5.C.ii.d STEP 4 - Evaluate Impacts and Document the Results 99

5.C.ii.e STEP 5 - Evaluate Visibility Impacts 101

6. Visibility Impacts 111

6.A Post-Control Modeling Scenarios 111

6.B Post-Control Modeling Results 111

7. Select BART 128

List of Tables

Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis 11

Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions Data 14

Table 4-2

Table 5-1

Table 5-2

Table 5-3

Table 5-4

Table 5-5

Table 5-6

Table 5-7

Table 5-8

Table 5-9 Baseline Visibility Modeling Results :: 15

Indurating Furnace S02 Control Teclmology

- Availability, Applicability, and

Teclmical Feasibility 22

Indurating Furnace S02 Control Teclmology Effectiveness

, 23

Indurating Furnace S02 Control Cost Summary 24

S02 Control Teclmology Impacts Assessment.. 25

Post-Control Modeling Scenarios 27

Post-Control S02 Modeling Scenarios

- Modeling Input Data 29

Post-Control S02 Modeling Scenarios

- Visibility Modeling Results 31

Post-Control S02 Modeling Scenarios

- Visibility Improvements

, 32

Indurating Furnace NO

x 

# Control Technology

- Availability, Applicability, and

Teclmical Feasibility 45

11



# Y:\22\52\080 Tilden BARnBART report\Tilden BART Report (2006-12-28).doc

# Table 5-30

Table 5-31

Table 5-32 . Table 5-18

Table 5-219

Table 5-20

Table 6-1

Table 6-2

Table 6-3

Table 6-4

Table 6-5 Table 5-21

Table 5-22

Table 5-23

Table 5-27

Table 5-28

Table 5-29

Table 5-30 Table 5- I0 Indurating Furnace NO

x 

# Control Technology Effectiveness --46

Table 5- I I Indurating Furnace NO

x 

# Control Cost Summary .....................................................•.. .47

Table 5-12 NO

x 

# Control Technology Impacts Assessment.. .48

Table 5-13 Post-Control NO

x 

# Modeling Scenarios ...................................................................•... 50

Control Scenario 50

Table 5-14 Post-Control NO x Modeling Scenarios

- Modeling Input Data 52

Table 5-15 Post-Control NO x Modeling Scenarios

- Visibility Modeling Results 53

Table 5-16 Post-Control NO x Modeling Scenarios

- Visibility Improvements 54

Table 5-17 Process Boiler S02 Control Technology-Availability, Applicability, and Technical

Feasibility 59

Process Boiler S02 Control Technology Effectiveness .59

Process Boilers 1 and 

# 2 S02 Control Cost Summary 60

Process Boilers 1 and 2 NO, Control Technology

- Availability, Applicability and

Technical Feasibility 70

Backup Process Boiler NOx Control Technology Effectiveness 71

Process Boiler NO

x 

# Control Cost Summary

, 72

Process Boiler NO, Control Technology

- Other Impacts Assessment 73

Process Boiler Post-BART Modeling Scenarios 75

Process Boiler Post-BART NO, Modeling Scenarios

- Modeling Input Data 78

Process Boiler Post-BART NO, Modeling Scenarios

- Visibility Modeling Results 79

Process Boiler Post-BART NO, Modeling Scenarios

- Comparison of Visibility

Modeling Results to Baseline Modeling Results

, 80

Table 5-29 Line 1 Dryer S02 Control Technology

- Availability, Applicability, and Technical

Feasibility 87

Line I Dryer S02 Control Technology Effectiveness 87

Line I Dryer SO, Control Cost Summary 88

Line 1 Dryer NO

x 

# Control Technology

- Availability, Applicability and Technical

Feasibility .......................................................................................................•.......... 98

Line 1 Dryer NOx Control Technology Effectiveness 99

Backup Process Boiler NO, Control Cost Summary 1 00

Line 1 Dryer NO, Control Technology

- Other Impacts Assessment.. 101

Process Boiler Post-BART Modeling Scenarios 103

Process Boiler Post-BART NO, Modeling Scenarios

- Modeling Input Data I08

Process Boiler Post-BART NO, Modeling Scenarios

- Visibility Modeling Results

.. 109

Process Boiler Post-BART NO, Modeling Scenarios

- Comparison of Visibility

Modeling Results to Baseline Modeling Results 1 10

Post-Control Modeling Scenarios I 13

Post-Control NO x Modeling Scenarios

- Modeling Input Data I 18

Post-Control Modeling Scenarios

- Visibility Modeling Results I 19

Post-Control Modeling Scenarios

- Visibility Modeling Results 120

Post-Control Modeling Results

- Dollars per Deciview Improvement.. 121 Table 5-33

Table 5-34

Table 5-35

Table 5-36

Table 5-37

Table 5-38

Table 5-39

111



# Y:\221521080 Tilden BARTIBART reportlTilden BART Report (2006·12·28).doc

# Appendix A

AppendixB

Appendix C

AppendixD

AppendixE

AppendixF List of Appendices

Control Cost Analysis Spreadsheets

Changes to MDEQ BART Modeling Protocol

Visibility Impacts Modeling Report

Applicable and Available Retrofit Teclrnologies

Clean Air 

# Interstate Rule (CAIR), Cost-Effective Air Pollution Controls

BART Analysis Procedure and Streamlined BART Approach

IV



# Y:\22\52\OBO Tilden BART\BART reportlTiiden BART Report 

# (2006-12-2B).doc

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# v 

# 1. Executive Summary

DRAFT LANGUAGE

Tilden Mining Company LC (Tilden) owns and operates an iron mining facility near Ishpeming,

Michigan in Marquette County. This report describes the background and methods for the selection

of the Best Available Retrofit Technology (BART) as proposed by Tilden for its taconite processing

plant located near Ishpeming, MI.

Michigan Department of Environmental Quality (MDEQ) identified the six pieces of equipment that

were installed within the time window (1962-1977) that makes them subject to BART. The

equipment includes Line 1 Kiln, Dryer, Cooler, Primary Crusher, and Process Boilers 1 and 2. Line

1 Kiln is permitted for natural gas, coal and fuel oil and Line 1 Dryer, Process Boilers 1 and 2 are

permitted for natural gas and fuel oil. Preliminary visibility modeling conducted by the MDEQ

found that air emissions from Tilden’s facility “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 were used to propose BART for the subject units.

The existing pollution control equipment includes wet scrubbers on the dryer, cooler, and primary

crusher, which are designed to control particulate matter (PM). The wet scrubber on the dryer will,

however, experience some collateral control of sulfur dioxide (SO 2 

# ). The kiln PM is controlled with

a n electrostatic precipitator (dry). 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, Tilden proposes the following as BART:

Line 1 Kiln

• SO 2 

# emissions of 28,000 lb per day for Line 1 when coal is burned

• NOx limit as specified in Appendix 2 Schedule of Compliance in the Renewable Operating

Permit 199600379 and with Rule 336.1801.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# vi • P M emissions will be controlled as prescribed by the taconite maximum achievable control

technology (MACT) standard 1



# .

L ine 1 Cooler

• PM emissions will be controlled as prescribed by the taconite maximum achievable control

technology (MACT) standard 2



# .

B oilers 1 and 2

• SO 2 

# emissions limit is regulated by limiting the sulfur content to 1.2% by weight, calculated

on the basis on 18,000 BTU per pound when used oil is burned.

• NO

x 

# is good combustion practices

• P M emissions will be controlled as prescribed by the taconite maximum achievable control

technology (MACT) standard 3



# .

L ine 1 Dryer

• SO 2 

# emissions limit is regulated by limiting the sulfur content to 1.5% by weight, calculated

on the basis on 18,000 BTU per pound when used oil is burned NO

x 

# emissions will be

c ontrolled

• NO

x 

# is good combustion practices

• P M emissions will be controlled as prescribed by the taconite maximum achievable control

technology (MACT) standard 4



# .

P rimary Crusher

1 

# 40 CFR Subpart 63 RRRRR-NESHAPS: Taconite Iron Ore Processing

2 

# 40 CFR Subpart 63 RRRRR-NESHAPS: Taconite Iron Ore Processing

3 

# 40 CFR Subpart 63 RRRRR-NESHAPS: Taconite Iron Ore Processing

4 

# 40 CFR Subpart 63 RRRRR-NESHAPS: Taconite Iron Ore Processing

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# vii • P M emissions will be controlled as prescribed by the taconite maximum achievable control

technology (MACT) standard 5



# .

C ALPUFF model is conservative, resulting in an over prediction of impacts. This modeled high

impact from the BART eligible sources is 0.72 dV, which is below perceptible levels of one to two

dV. Real impacts to the Class I areas from Tilden are expected to be even less than these modeled

impacts.

5 

# 40 CFR Subpart 63 RRRRR-NESHAPS: Taconite Iron Ore Processing

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 1 

# 2. Introduction

Tilden Mining Company LC (Tilden) owns and operates an iron mining facility near Ishpeming,

Michigan in Marquette County. This report describes the background and methods for the selection

of the Best Available Retrofit Technology (BART) as proposed by Tilden for its taconite processing

plant also located near Ishpeming, MI.

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 51.300 through 51.309.

Within its boundary, Michigan has two Class I areas – the Isle Royale National Park (IRNP) and

Seney Wilderness Area. By December 2007, MDEQ 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. 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.

By U.S. EPA’s definition, reasonable progress means that there is no degradation of the 20 bestvisibility days, and the 20 worst-visibility days must have no more visibility impairment than the 20

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 2 worst days under natural conditions by 2064. 6 

# Assuming a uniform rate of progress, the default gl ide

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.

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 states may rely upon in making “reasonable progress” towards regional haze

improvement goals.



# 2.A BART Eligibility

BART eligibility is established on the basis on thre e 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 visibilityimpairing 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, PM 10 

# , PM 2.5 

# , SO 2 

# , NO

x 

# , and possibly Volatile Organic

C ompounds (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

6 

# 70 FR No. 178 pp. 39104 to 39172.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 3 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.



# 2.B BART Determinations

Each source that is subject to BART must determine B ART 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. 7 

# The five steps of a BART analysis are:

S tep 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

7 

# 40 CFR 51 Appendix Y

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 4 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. 8



# S tep 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:

a. 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. 9 

# ”

H owever, 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. 10 

# ”

b

. 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. 11 

# ” 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. 12 

# ”

c

. Are there source-specific issues/conditions that would make the control technology

not technically feasible?

8 

# Federal Register 70, No. 128 (July 6, 2005): 39164

9 

# Federal Register 70, No. 128 (July 6, 2005): 39165

10 

# IBID

11 

# IBID

12 

# IBID

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 5 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

technology 13 

# .” This also involves the identification of “irreso lvable 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 analysis 14



# .

I t 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 the absence of a vendor guarantee to be a “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 guarantees 15



# .

S tep 3 - Evaluate Control Effectiveness

In step three, the remaining controls are ranked based on the control efficiency at the

expected emission rate (post-control) 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

13 

# IBID

14 

# IBID

15 

# IBID

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 6 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 protocol 16 

# , including receptor grid, meteorological

d ata, and other factors used for this part of the analysis were provided by the Michigan

Department of Environmental Quality (MDEQ). 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 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

16 

# Single Source Modeling to Support Regional Haze BART Modeling Protocol, March 21, 2006, Lake Michigan Air Directors

Consortium.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 7 plants in the same industry have been required to install BART controls if this

information is available. 17



# T o complete the BART process, the analysis must “establish enforceable emission limits that reflect

the BART requirements and requires compliance within a reasonable period of time 18 

# .” Those limits

m ust 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 basis 19 

# .” which could include the incorporation of

o ther regulatory requirements for the source, including Compliance Assurance Monitoring (40 CFR

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 standards 20 

# .”

C ompliance with the BART emission limits will be required within 5 years of U.S. EPA approval of

the Michigan SIP.

17 

# 40 CFR 51 Appendix Y. Page 361.

18 

# 40 CFR 51 Appendix Y. Page 368.

19 

# 40 CFR 51 Appendix Y. Page 369.

20 

# 40 CFR 51 Appendix Y. Page 368.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 8 

# 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 analyses 21 

# . The streamlined approach will allow both states an d the

facilities to focus their resources on the main contributors to visibility impairment. This section of

the report follows the MDEQ-approved streamlined BART analysis for taconite facilities and

presents the results of the streamlined approach in Table 3-1.



# 3.A Indurating Furnaces

The indurating furnaces are sources of three visibil ity impairing pollutants: NO

x 

# , SO 2 

# , and PM.

R elative to NO

x 

# and SO 2 

# , PM is not a major visibility impairing pollutant. Further, the indurating

furnaces are subject to the taconite MACT standard 22 

# for the PM emissions. MDEQ requested that

T ilden submit a BART analysis approach August 31, 2006. Tilden submitted both the BART

Analysis Procedures and Streamlined BART Approach on August 29, 2006. Tilden has performed the

BART analysis as outlined in the August 29, 2006 submittals. The BART Analysis Procedures and

Streamlined BART Approach dated August 29, 2006 is included in Appendix F for reference.

The approach, as outlined in the August 29, 2006 Streamlined BART Approach, relies 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. Specifically in 40 CFR Part 51

Appendix Y paragraph IV.C., it states:

For VOC and PM sources subject to MACT standards, States may streamline the analysis by

including a discussion of the MACT controls and whether any major new technologies have

been developed subsequent to the MACT standards. We believe that there are many VOC and

PM sources that are well controlled because they are regulated by the MACT standards,

which EPA developed under CAA section 112. For a few MACT standards, this may also be

true for SO 2 

# . Any source subject to MACT standards must meet a l evel that is as stringent as

the best-controlled 12 percent of sources in the industry. Examples of these hazardous air

pollutant sources which effectively control VOC and PM emissions include (among others)

secondary lead facilities, organic chemical plants subject to the hazardous organic NESHAP

21 

# Federal Register 70, no. 128 (July 6, 2005): 39107 and 39116

22 

# 40 CFR Subpart 63 RRRRR-NESHAPS: Taconite Iron Ore Processing

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 9 (HON), pharmaceutical production facilities, and equipment leaks and wastewater

operations at petroleum refineries. We believe that, in many cases, it will be unlikely that

States will identify emission controls more stringent than the MACT standards without

identifying control options that would cost many thousands of dollars per ton. Unless there

are new technologies subsequent to the MACT standards which would lead to cost effective

increases in the level of control, you may rely on the MACT standards for purposes of

BART . (emphasis added)

It is clear from EPA’s guidance that they are encour aging states to develop a streamlined BART

analysis approach for sources regulated under a MACT. Since the Taconite 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.

A full BART analysis will be conducted for NO

x 

# and SO 2 

# 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 Pellet Cooler operations. These sources operate near ambient temperature, only

emit PM, and do not emit NO

x 

# or SO 2 

# . The Ore Crushing source operates with control equ ipment 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.

Since the MACT standard was established recently and became effective in October 31, 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 Streamlined BART Procedures submitted to

MDEQ August 29, 2006.

No further analysis will be required to establish BART for these sources.



# 3.C Other Combustion Units

The combustion units are sources of three visibility impairing pollutants: NO

x 

# , SO 2 

# , and PM.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 10 Tilden facility has two process boilers that are subject to the boiler MACT 23 

# . Since the boiler MACT

s tandards were established recently and become effective in 2007, the technology analysis is up-todate. For the units subject to the boiler MACT standard, BART will be presumed to be equivalent to

MACT for PM according to Streamlined BART Procedures submitted to MDEQ August 29, 2006

Similar to the induration furnaces, the dryer is also subject to the Taconite MACT for PM. As a

result, BART will be presumed to be equivalent to MACT for PM.

A full BART analysis will be conducted for NO

x 

# and SO 2 

# where applicable for the process boilers

a nd dryer.

23 

# 40 CFR 63 Subpart DDDDD-NESHAPS: ICI Boilers and Pr ocess HeatersY:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc11Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART AnalysisEmissionUnit #Emission UnitDescriptionNOxMax 24-hrActualEmissions(lbs/day)SO2Max 24-hrActualEmissions(lbs/day)PM10Max 24-hrActualEmissions(lbs/day)MACTPM EmissionLimit(gr/dscf)StackNumberActionsRequired3.AIndurating FurnaceEUKILN1Line 1 InduratingFurnace26208.0 6552.0 4948.50.01 magnetite0.03 hematiteSVP0051711(South) andSVP0051981(North)Full BARTAnalysis for SO2and NOx3.BPM-Only Taconite MACT Emission UnitsEUPRIMARYCRUSHERPrimary Crusher 1 -- --25.70.008 SVA0011570NoneEUCOOLER1Line 1 Pellet CoolerExhaust-- --5.90.008 SVP0025490None3.COther Combustion UnitsEUDRYER1 Line 1 Dryer88.3 199.2 529.00.61SVP0082951Full BARTAnalysis for SO2and NOxEUBOILER1 Process Boiler #1463.3 1.5 300.00.61SVBLR.STK.T1Full BARTAnalysis for SO2and NOxEUBOILER2 Process Boiler #2463.3 1.5 300.00.61SVBLR.STK.T1Full BARTAnalysis for SO2and NOx1PM – Filterable PM only as measured by U.S. EPA Method 5 including the applicable averaging and grouping provisions, as presented in the MACTregulation, effective 10/30/2006.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 12 

# 4. Baseline Conditions and Visibility Impacts for

BART Eligible Units

As indicated in U.S. EPA’s final BART guidance 24 

# , one of the factors to consider when determining

B ART 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

alternatives. 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 NO

x 

# , SO 2, 

# PM 2.5, 

# PM 10 

# , and

b ackground ammonia 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 estimate the visibility improvement resulting from the retrofit technology, the source must

first be modeled at baseline conditions. Per U.S. EPA 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 emissions 25



# .



# 4.A MDEQ Subject-to-BART Modeling

In order to determine which sources are “Subject-to- BART” in the state of Michigan, the MDEQ

completed modeling of the BART-eligible emission units at various facilities in Michigan in

accordance with the Regional Haze Rule. The modeling by MDEQ was conducted using CALPUFF,

as detailed in the “Single Source Modeling to Support Regional Haze BART Modeling Protocol”,

March 21, 2006, Lake Michigan Air Directors Consortium. The modeling by MDEQ was conducted

using emission rate information submitted by the facility in the annual emissions reporting. The

emissions were reported in units of pounds per year and divided by the annual hours per year of

operation to calculate a pound per hour (lb/hr) emission rate. The lb/hr emission rate was then

multiplied by 24 hours to calculate the pounds per day (lb/day) emission rate. The lb/day is to reflect

24 

# Federal Register 70, no. 128 (July 6, 2005): 39106.

25 

# 40 CFR Part 51 Appendix Y

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 13 the maximum actual emissions during a 24-hour period under steady-state operating conditions

during periods of high capacity utilization. The modeling conducted by MDEQ demonstrated that

this facility is subject-to-BART as stated in the letter from MDEQ on March 17, 2006



# 4.B Facility Baseline Modeling

Prior to re-creating the MDEQ visibility impairment model, the modeling method was re-revaluated.

On behalf of Tilden and Empire, Barr Engineering proposed changes to the modeling. In discussions

with MDEQ, it was indicated that most aspects of the modeling were flexible, so long as the changes

were documented and appropriate files were included for their review with submittal of results.

Details of the modifications to the model are included in Appendix B.

In addition, the maximum 24-hour emission rates were re-evaluated internally within Tilden to verify

that the emission rates represent the maximum steady-state operating conditions during periods of

high capacity utilization. The maximum 24-hour emission rates were adjusted to reflect combustion

of permitted fuels.

The original baseline emissions were modeled for comparison to MDEQ results. This data is

summarized in Table 4-1. The full modeling analysis is presented in Appendix C.Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc14Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions DataEmissionUnitIDEmissionUnitDescriptionSO2Max.24-hrActualEmissions(lb/day)Basisfor SO224-hrActualEmissionsNOx Max.24-hrActualEmissions(lb/day)Basis forNOx 24-hrActualEmissionsPM2.5Max. 24-hr ActualEmissions (lb/day)BasisforPM2.524-hrActualEmissionsPM10Max. 24-hr ActualEmissions (lb/day)BasisforPM1024-hrActualEmissionsStackNo.LatitudeLongitudeHeightofopeningfromground(ft)BaseElevationofGround(ft)Stack length,width orDiameter (ft)Flow Rateat Exit(acfm)ExitGasTemperature(F)3.AIndurating FurnacesEUKILN1Line 1PelletInduration6552.0 COAL 26,208.0Natgas3,610.1 MACTSVP005198146.44084994-87.65340738240 1474 19.3 842,000 3001,338.4 MACTSVP005171146.44075383-87.65132336160 1474 13.5 306,000 3003.BPM-Only Taconite MACT Emission UnitsEUPRIMARYCRUSHERPRIMARYCRUSHER25.7 MACTSVA001157046.43933071-87.6515277015 1474 2.5 15,400 60EUCOOLERLine 1Cooler5.9 MACTSVP002549046.43979916-87.64827887151 1474 14.0 786,000 3333.CPM-Only Other Combustion MACT EmissionUnitsEUDRYER1Line 1Dryer199.2 COAL 88.3NAT.GAS529.0 MACTSVP008295146.44075383-87.65132336119 1474 6.3 57,135 150EUBOILER1ProcessBoiler #11.5FUELOIL463.3NAT.GAS300.0 MACTSVBLR.STK.T146.44091784-87.65412418130 1474 7.5 192,000 350EUBOILER2ProcessBoiler #21.5FUELOIL463.3NAT.GAS300.0 MACTSVBLR.STK.T146.44091784-87.65412418130 1474 7.5 192,000 350

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 15 

# 4.C Facility Baseline Modeling Results

The Michigan BART modeling protocol 26 

# describes the CALPUFF model inputs, including the

m eteorological data set and background atmospheric ammonia and ozone concentrations, along with

the functions of the CALPOST post processing. The CALPOST output files provide the following

two methods to assess the expected post-control visibility improvement:

• 98 th 

# Percentile: As defined by federal guidance, a sour ce "contributes to visibility

impairment” if the 98 th 

# percentile of any year’s modeling results (i.e. 7 th 

# highest day) meets

o r 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

98 th 

# percentile of the baseline conditions exceeds the t hreshold of 0.5 dV. The results of this

modeling are also utilized in the post-control modeling analysis in section 6 of this document. The

full modeling analysis is presented in Appendix C.

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



# IRNP 0.714 19 0.722 11 0.599 11 0.674 41

26 

# Single Source Modeling to Support Regional Haze BART Modeling Protocol, March 21, 2006, Lake Michigan Air Directors

Consortium. 

# Page 3.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 16 

# 5. BART Analysis for Indurating Furnaces

As presented in section 3 and Table 3-1, the following sources at Tilden require a full BART analysis

for SO 2 

# and NO

x 

# :

 L ine 1 Indurating Furnace;

 Process Boilers 1 and 2; and

 Line 1 Dryer.

The BART analyses for these sources are presented in sections 5.A, 5.B, and 5.C, respectively.



# 5.A Line 1 Indurating Furnace

The primary function of taconite indurating furnaces is to convert magnetic or hematite 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.

The Line 1 Indurating Furnace is a grate/kiln furnace, in which the pellets are dried on a grate and

then transferred to a rotary kiln for hardening and oxidation. The pellet hardening and oxidation

section of the induration furnace is designed to operate at 2,400 oF and higher. 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 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

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 17 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.

Tilden has two grate/kiln furnaces, Line 1 and Line 2. Line 1 is subject-to-BART and Line 2 is not

subject to BART because Line 2 was installed outside the BART applicability time window. Line 1 is

permitted to burn natural gas, coal and fuel oil. Line 1 is controlled by an electrostatic precipitator

(ESP). The ESP is designed to remove PM and would be considered a high efficiency PM ESP Kiln

1 has a PM limit of 0.065 per 1000 pounds of exhaust gas and 200 pounds per hour. NO

x 

# is

c ontrolled through furnace design and type of fuel usage. During high ozone alert days, coal is

burned to reduce the amount of NO

x 

# generation. The SO 2 

# is controlled through furnace design and

t ype of fuel usage. Kiln 1 has a SO 2 

# limit of 28,000 lbs per day.



# 5.A.i Sulfur Dioxide Controls

There are two sources of SO 2 

# emissions from the Line 1 Indurating Furnace:

1

. SO 2 

# emissions from the trace amounts of sulfur in the i ron concentrate and binding agents

present in the green balls; and

2. SO 2 

# emission from the sulfur in distillate fuel oil and coal, which are the permitted fuels.

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 MDEQ on October 6, 2006 with the

status of the technology as it was understood at that time. Appendix D presents the current status of

the general availability of each technology.

5.A.i.b STEP 2 – Eliminate Technically Infeasible Options

Step 1 identified the available and applicable technologies for SO 2 

# emission reduction. Within

S tep 1, the technical feasibility of the control option was also discussed and determined. The

following describes retrofit SO 2 

# control technologies that were identified as availa ble 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.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 18 Wet Walled Electrostatic Precipitator (WWESP)

An 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 SO 2 

# removal,

c austic is added to the water spray system, allowing the WWESP spray system to function as an SO 2



# a bsorber.

The SO 2 

# control efficiency for a WWESP is dependent upon va rious process specific variables, such

as SO 2 

# flue gas concentration, fuel used, and ore compositi on. Tilden currently employs an ESP

designed for removal of particulate matter. The existing ESP does not have the capacity to handle

the additional loading of sulfate particulates. To add a WWESP to the process, it would be necessary

to install it in series with the existing ESP. A control efficiency of a WWESP ranges from 30-80%

dependent upon the process specific operating parameters.

Based on the information contained within this report, a WWESP is considered a technically feasible

technology for SO 2 

# reduction for this BART analysis.

W et Scrubbing (High and Low Efficiency)

Wet scrubbing, when applied to remove SO 2 

# , 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 SO 2 

# in the waste gas. Crushed limestone, lime, or caust ic 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 SO 2 

# wet scrubber, the scrubber would require

d esigns for removal efficiency up to 95% SO 2 

# . Typical high efficiency SO 2 

# wet scrubbers are packedb ed spray towers using a caustic scrubbing solution. Whereas, a low efficiency SO 2 

# wet scrubber

c ould have a control efficiency of 30% or lower. A low efficiency SO 2 

# scrubber could be a venturi

r od 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 SO 2 

# from the flue gas as

c ollateral emission reduction.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 19 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:

CaCO 3 

# + SO 2 

# → CaSO 3 

# • 1/2 H2O + CO 2



# C aSO 3 

# •1/2 H 2 

# O + 3H 2 

# O + O 2 

# → 2 CaSO 4 

# •2 H 2 

# O

L ime 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 

# +SO 2 

# → CaSO 3 

# • 1/2 H 2 

# O + 1/2 H 2 

# O

C a(OH) 2 

# + SO 2 

# + 1/2 O 2 

# + H 2 

# O → CaSO 4 

# •2 H 2 

# O

W hen caustic (sodium hydroxide solution) is the scrubbing agent, the SO 2 

# removal reactions are as

f ollows:

Na+ + OH- + SO 2 

# + → Na 2 

# SO 3



# 2 Na+ + 2OH- + SO 2 

# + → Na 2 

# SO 3 

# + H 2 

# O

C austic 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 SO 2 

# removal, additional

e quipment 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 SO 2 

# control efficiency range for SO 2 

# scrubbers on coal-fired utility boilers with oxygen

concentrations 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 SO 2 

# concentrations are

t he highest. The indurating furnace SO 2 

# concentration would be considered low due to the hi gh air

flow rates required to assure product quality. Unlike coal-fired boilers, indurating furnaces operate

with maximum excess air to enable proper oxidation of the pellet. The excess air dilutes the SO 2



# c oncentration as well as creates higher flow rates to control. Additionally, the varying sulfur

concentration within the pellet causes fluctuations of the SO 2 

# concentrations in the exhaust gas

s tream. This could also impact the SO 2 

# control efficiency of the wet scrubber.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 20 Based on the information contained within this report, a wet scrubber is considered a technically

feasible technology for SO 2 

# reduction for this BART analysis.

D ry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection)

Dry sorbent injection (DSI) of lime/limestone is a post-combustion SO 2 

# control technology in which

p ulverized lime or limestone is directly injected into the duct upstream of the fabric filter. Dry

sorption of SO 2 

# onto the lime or limestone particle occurs and the solid particles are collected with a

fabric filter. Further SO 2 

# removal occurs as the flue gas flows through the fi lter cake on the bags. The

normal SO 2 

# control efficiency range for dry SO 2 

# scrubbers is 70% to 90 % for coal fired utility

b oilers. Depending on the residence time and gas stream temperature, DSI control efficiency for an

indurating furnace is estimated at 55%.

Based on the information contained within this report, DSI is considered a technically feasible

technology for SO 2 

# reduction for this BART analysis.

S pray Dryer Absorption (SDA)

Spray dryer absorption (SDA) systems spray lime slurry into an absorption tower where SO 2 

# is

a bsorbed by the slurry, forming CaSO 3 

# /CaSO 4 

# . The liquid-to-gas ratio is such that the water

e vaporates 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 SO 2 

# , the term flue-gas

d esulfurization (FGD) may also be used.

Based on the information contain with this report, SDA is considered a technically feasible

technology for SO 2 

# reduction for this BART analysis.

E nergy Efficiency Projects

Energy efficiency projects provide opportunities for a company to reduce their fuel consumption,

which results in lower operating costs. Typically, reduced fuel usage translates into reduced

pollution emissions. Due to the increased price of fuel, Tilden has already implemented energy

efficiency projects. Each project carries its own fuel usage reductions and potentially emission

reductions. Due to the uncertainty and generalization of this category, this will not be further

evaluated in this report. However, it should be noted that Tilden will continue to evaluate and

implement energy efficiency projects as they arise.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 21 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 physical forms – solid, liquid and

gas. To achieve reduction of SO 2 

# emissions through alternative fuel usage, the sourc e must be

capable of burning fuels with lower sulfur content than the existing fuels. Switching fuels trades one

visibility impairment pollutant (SO 2 

# ) for another (NO

x 

# ), as induration furnaces emit significantly less

N O

x 

# when burning solid fuels. Therefore, if this option is pursued, the impact on emissions of all

visibility pollutants must be quantified and the cumulative visibility impact modeled to determine the

net benefit of a particular alternative fuel.

It is also important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as an

option, not to direct the fuel choice. 27



# T herefore, due to the uncertainty of alternative fuel costs, the potential of replacing one visibility

impairment pollutant for another, and the fact that BART is not intended to mandate a fuel switch,

alternative fuels as an SO 2 

# air pollution control technology will not be furthe r evaluated in this

report. However, similar to energy efficiency, Tilden will continue to evaluate and implement

alternate fuel usage as the feasibility arises.

Coal Processing

Pre-combustion coal processing techniques have been proposed as one strategy to reduce

uncontrolled SO 2 

# emissions. Coal processing technologies are being developed to remove moisture

and potential contaminants from the coal prior to use.

These processes typically employ both mechanical and thermal means to increase the quality of coal

by removing moisture, sulfur, mercury, and heavy metals. In one process, raw coal from the mine

enters a first stage separator where it is crushed and screened to remove large rock and rock

material. 28 

# The processed coal is then passed on to an interme diate storage facility prior to being sent

to the next stage in the process, the thermal process. In this stage, coal passes through pressure locks

into the thermal processors where steam is injected. Moisture in the coal is released under these

conditions. Mineral inclusions are also fractured under thermal stress, removing both included rock

27 

# Federal Register 70, no. 128 (July 6, 2005): 39164

28 

# The coal processing description provided herein is based on the K-Fuel ® 

# process under development by KFx, Inc.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 22 and sulfur-forming pyrites. After treatment, the coal is discharged into a second pressurized lock.

The second pressurized lock is vented into a water condenser to return the processor to atmospheric

pressure and to flash cool the coal. Water, removed from the process at various points, and

condensed process steam are reused within the process or treated prior to being discharged.

To date, the use of processed fuels has only been demonstrated with test burns in a pulverized coalfired boiler. Using processed fuels at a taconite plant would require research, test burns, and

extended trials to identify potential impacts on plant systems, including the furnaces, material

handling, and emission control systems. Therefore, processed fuels are not considered commercially

available, and will not be analyzed further in this BART analysis.

Coal crushing and drying is currently employed by Tilden as an incidental option for SO 2 

# reduction.

I n the process, raw coal is crushed and screened to remove rocks and other impurities. The crushed

coal is then thermally processed to remove excess moisture. Coal crushing and drying is already in

use, so further reductions from this control option are not possible. Therefore, it will not be further

evaluated in this report.

Step 2 Conclusion

Based upon the determination within Step 2, the remaining SO 2 

# control technologies that are

a vailable and applicable as secondary controls to the existing indurating furnace wet scrubbers 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 SO 2 

# Control Technology – Availability, Applicability, a nd

Technical Feasibility



# SO 2 

# Pollution Control Technology Available? Applicable? Technically

Feasible?

Wet Walled Electrostatic Precipitator

(WWESP) Yes Yes Yes

Wet Scrubbing Yes Yes Yes

Dry sorbent injection (DSI) Yes Yes Yes

Spray Dryer Absorption (SDA) Yes Yes Yes

Energy Efficiency Projects Yes Yes Project Dependent

Alternative Fuels Yes Yes Yes – Not

Required by BART

Coal Processing No No No

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 23 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.

Table 5-2 Indurating Furnace SO 2 

# Control Technology Effectiveness

SO 2 

# Pollution Control Technology Approximate Control Efficiency

SDA 90%

Wet Scrubber 80%

WWESP 80%

DSI 55%



# 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 the above alternatives 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 six-tenths-factor rule as shown in the following equation:

Cost of equipment A = Cost of equipment B * (capacity of A/capacity of B) 0.6



# D irect 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 100% utilization and annual operating hours

of 7680 hours. Operating costs of consumable materials, such as electricity, water, and chemicals

were established based on the U.S. EPA control cost manual 29 

# and engineering experience, and were

a djusted for the specific flow rates and pollutant concentrations.

Due to space considerations, 60% 30 

# 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

29 

# U.S. EPA, January 2002, E PA Air Pollution Control Cost Manual, Sixth Edition

. 30 

# U.S. EPA, C UE Cost Workbook Version 1.0 . Page 2.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 24 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 retrofit projects. See Appendix C

for an aerial photo of the facility. The detailed cost analysis is provided in Appendix A.

Table 5-3 Indurating Furnace SO 2 

# Control Cost Summary

Control Technology Installed

Capital Cost

(MM$) Total Annual Cost

(MM$/yr) Annualized

Pollution

Control Cost

($/ton)

SDA $167,260,397 $23,254,882 $22,407

Wet Scrubber $34,869,327 $6,048,540 $6,557

WWESP $52,638,755 $13,922,184 $15,091

DSI $42,082,032 $9,975,786 $15,729



# 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 rulemaking process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost

effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not

afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the

electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater

business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for

proposing BART in lieu of developing industry and site specific data.

The annualized pollution control cost value was used to determine whether or not additional impacts

analyses would be conducted for the technology. If the control cost was less than a screening

threshold established by MDEQ, then visibility modeling impacts, and energy and other impacts are

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 25 evaluated. MDEQ set the screening level to eliminate technologies from requiring the additional

impact analyses at an annualized cost of $12,000 per ton of controlled pollutant 31 

# . Therefore, all air

p ollution controls with annualized costs less than this screening threshold will be evaluated for

visibility improvement, energy and other impacts. Based on the information presented in table 5-3,

the wet scrubber is the only technology that requires analysis for visibility improvement, energy and

other impacts.

The BART guidance documents also present a calculation method for incremental control cost which

is intended to present the incremental value of each technology as compared to the next most

effective alternative. Since only one of the technologies is cost effective, the incremental control

cost is not applicable and is not presented in this analysis.

Energy and Environmental Impacts

The energy and non-air quality impacts for wet scrubbers are presented in Table 5-4.

Table 5-4 SO 2 

# Control Technology Impacts Assessment

Control

Technology Energy Impacts Other Impacts

Wet Scrubber Significant pressure drop results

in higher electrical requirements • Additional water

consumption and

wastewater generation

• Increased facility water

balance and water quality

issues

• Ponding for scrubber

discharge will be limited

because of site space

constraints

• Additional solid

waste/sludge generation

• Process downtime/lost

production during

installation



# Table 5-4 notes that wet scrubbers would require additional water consumption. Michigan’s Upper

Peninsula has experienced a drought in the past several years. Use of wet scrubbers would create

additional demand for water, a resource that is already stressed due to the recent drought conditions.

Because the cost of the remaining SO 2 

# control technologies for Tilden Line 1 furnace is s o high and

31 

# Michigan Department of Environmental Quality May 12 , 2006 meeting.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 26 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. This section of the report evaluates the visibility impacts of BART SO 2 

# control for the

L ine 1 Indurating Furnace 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-control emissions to be used for the visibility impacts analysis should also reflect a

maximum 24-hour average project emission rate. In the visibility impacts analysis for SO 2 

# , the

e missions from the sources undergoing a full BART SO 2 

# analysis were adjusted to reflect the

p rojected 24-hour maximum SO 2 

# emission rate when applying the control technologie s that met the

threshold requirements of steps 1 – 4. The emissions from all other Subject-to-BART sources were

not changed. Table 5-5 provides a summary of the modeled 24-hour maximum emission rates and

their computational basis for the evaluated SO 2 

# control technologies. Table 5-6 provides a summary

of the modeling input data.Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc27Table 5-5 Post-Control Modeling ScenariosScenario Control TechnologySO2NOxControlScenarioSV #Emission UnitSO2NOx% ReductionMax24-hour lbs/hr% ReductionMax24-hour lbs/hrBaseSVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1Base SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7Base SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.32SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.33SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.36SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.37SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.310SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.811SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.814SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc28Scenario Control TechnologySO2NOxControlScenarioSV #Emission UnitSO2NOx% ReductionMax24-hour lbs/hr% ReductionMax24-hour lbs/hrSVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.815SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.818SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.419SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.422SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.423SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.426SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.727SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.7Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc29Scenario Control TechnologySO2NOxControlScenarioSV #Emission UnitSO2NOx% ReductionMax24-hour lbs/hr% ReductionMax24-hour lbs/hr30SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.731SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.7Table 5-6 Post-Control SO2Modeling Scenarios - Modeling Input DataControl ScenarioSV #Emission UnitStack LatitudeStack LongitudeHeight ofOpening fromGround(ft)Base Elevationof Ground(ft)Stack length,width, orDiameter(ft)Flow Rate at exit(acfm)Exit Temp(oF)All ScenariosSVP0051981SVP0051711EUKILN146.4408499446.44075383-87.65340738-87.65132336240160147419.313.5842,000306,000300300SVP0082951 EUDRYER1 46.44075383-87.6513233611914746.357,135 150SVBLR.STK.T1EUBOILER1EUBOILER246.44091784-87.6541241813014747.5 192,000 350

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 30 Post-Control Visibility Impacts Modeling Results

Results of the post-control visibility impacts modeling for SO 2 

# are presented in Table 5-7. The

r esults summarize the 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 postcontrol modeling scenarios to the baseline conditions is presented in Table 5-8.

As illustrated in Tables 5-7 and 5-8, the highest facility baseline visibility contribution is 0.72 dV. A

wet scrubber (Scenario 2) would potentially reduce the visibility contribution by 0.1 dV at a cost of

over $34 million in installed capital cost and a total annual cost of over $6.0 million per year. This

would result in a cost per deciview reduction of over $60 million per deciview.

Visibility impacts with NO

x 

# controls are presented in Section 6.Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc31Table 5-7 Post-Control SO2Modeling Scenarios - Visibility Modeling Results2002200320042002 – 2004CombinedScenario #Class IArea withGreatestImpactModeled98thPercentileValue(deciview)No. of daysexceeding0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewBase IRNP 0.714 19.0 0.722 11.000 0.599 11.000 0.674 412 IRNP 0.610 15.0 0.620 10.000 0.535 8.000 0.600 333 IRNP 0.183 0.0 0.177 0.000 0.154 0.000 0.17306 IRNP 0.619 15.0 0.623 10.000 0.528 8.000 0.598 337 IRNP 0.182 0.0 0.177 0.000 0.155 0.000 0.169010 IRNP 0.618 15.0 0.607 10.000 0.527 8.000 0.590 3311 IRNP 0.176 0.0 0.168 0.000 0.150 0.000 0.161014 IRNP 0.627 15.0 0.608 9.000 0.544 8.000 0.585 3215 IRNP 0.176 0.0 0.171 0.000 0.150 0.000 0.160018 IRNP 0.626 15.0 0.605 9.000 0.542 8.000 0.596 3219 IRNP 0.175 0.0 0.173 0.000 0.151 0.000 0.163022 IRNP 0.625 15.0 0.602 9.000 0.291 3.000 0.588 2723 IRNP 0.175 0.0 0.170 0.000 0.150 0.000 0.165026 IRNP 0.623 15.0 0.605 9.000 0.550 8.000 0.597 3227 IRNP 0.176 0.0 0.172 0.000 0.151 0.000 0.165030 IRNP 0.613 14.0 0.614 9.000 0.542 8.000 0.588 3131 IRNP 0.173 0.0 0.172 0.000 0.151 0.000 0.1640Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc32Table 5-8 Post-Control SO2Modeling Scenarios - Visibility ImprovementsModeling Results02002200320042002-2004ScenarioLimitingClass IAreaImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. of Daysexceeding0.5 dVImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. of Daysexceeding0.5 dVImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. of Daysexceeding0.5 dVImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. of Daysexceeding0.5 dVBaseIRNP0.714 19.0 0.722 11.000 0.599 11.000 0.674 412 IRNP 0.104 4 0.102 1 0.064 3 0.074 83 IRNP 0.531 19 0.545 11 0.445 11 0.501 416 IRNP 0.095 4 0.099 1 0.071 3 0.076 87 IRNP 0.532 19 0.545 11 0.444 11 0.505 4110 IRNP 0.096 4 0.115 1 0.072 3 0.084 811 IRNP 0.538 19 0.554 11 0.449 11 0.513 4114 IRNP 0.087 4 0.114 2 0.055 3 0.089 915 IRNP 0.538 19 0.551 11 0.449 11 0.514 4118 IRNP 0.088 4 0.117 2 0.057 3 0.078 919 IRNP 0.539 19 0.549 11 0.448 11 0.511 4122 IRNP 0.089 4 0.12 2 0.308 8 0.086 1423 IRNP 0.539 19 0.552 11 0.449 11 0.509 4126 IRNP 0.091 4 0.117 2 0.049 3 0.077 927 IRNP 0.538 19 0.55 11 0.448 11 0.509 4130 IRNP 0.101 5 0.108 2 0.057 3 0.086 1031 IRNP 0.541 19 0.55 11 0.448 11 0.51 41.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 33 

# 5.A.ii Nitrogen Oxide Controls

To be able to control NO

x 

# it is important to understand how NO

x 

# is formed. There are three

m echanisms by which NO

x 

# production occurs: thermal, fuel and prompt NO

x 

# .

• F uel bound NO

x 

# is formed from fuel combustion as nitrogen compound s in the fuel are

oxidized.

• Thermal NO

x 

# 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 NO

x 

# production is a function of the residence time, fre e oxygen,

and temperature, primarily in the flame area of the furnace.

• Prompt NO

x 

# is a form of thermal NO

x 

# which is generated at the flame boundary. It is th e

result of reactions between nitrogen and carbon radicals generated during combustion. Only

minor amounts of NO

x 

# are emitted as prompt NO

x 

# .

T he majority of NO

x 

# is emitted as NO. Minor amounts of NO 2 

# are formed in the furnaces.

5 .A.ii.a STEP 1 – Identify All Available Retrofit Control Technologies

With the understanding of how NO

x 

# is formed, available and applicable control technol ogies were

evaluated. See Appendix D for a comprehensive list of all potential retrofit control technologies that

were evaluated.

5.A.ii.b STEP 2 – Eliminate Technically Infeasible Options

Step 1 identified the available and applicable technologies for NO

x 

# emission reduction. Within

S tep 1, the technical feasibility of the control option was also discussed and determined. The

following describes retrofit NO

x 

# control technologies that were identified as availa ble 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 NO

x 

# formation. In an external flue gas recirculation sy stem, 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

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 34 level in the combustion zone reduces flame temperatures; which in turn reduces NO

x 

# emissions. For

t his technology to be effective, the combustion conditions must have the ability to be controlled at

the burner tip.

The normal NO

x 

# control efficiency range for EFGR is 30% to 50%.

A pplication of EFGR technology in taconite induration is problematic for three reasons:

1. The exhaust gas in an induration furnace typically has an oxygen content that is close to

ambient, or 18% oxygen, vs. a boiler which has 2% - 3% oxygen. In a boiler, the flue gas

is relatively inert and oxygen starved 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 2,400 o 

# F in order to meet

p roduct 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-NO

x 

# Burners

L ow-NO

x 

# burner (LNB) technology utilizes advanced burner de sign to reduce NO

x 

# formation through

t he 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.

In the primary combustion zone of a staged fuel burner, NO

x 

# formation is limited by a rich (high

f uel) condition. Oxygen levels and flame temperatures are low; this results in less NO

x 

# formation. In

t he secondary combustion zone, incomplete combustion products formed in the primary zone act as

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 35 reducing agents. In a reducing atmosphere, nitrogen compounds are preferentially converted to

molecular nitrogen (N 2 

# ) over nitric oxide (NO). The estimated NO

x 

# control efficiency for LNB in

h igh temperature applications is 10%. Low NO

x 

# burners have been installed in the preheating secti on

of a straight-grate furnace at another taconite plant; however, the Line 1 Indurating Furnace does not

contain a pre-heat burner section. If LNB were to be applied in the indurating zone of the furnace,

the reduced flame temperatures associated with LNB would adversely affect taconite pellet product

quality. LNB has not been applied to the indurating or preheat zones of any grate-kiln taconite

furnace. Therefore, this option is not technically feasible.

It is also important to note that there are other methods being developed for LNB which are not yet

commercially available. Some incorporate various fuel dilution techniques to reduce flame

temperatures; such as mixing an inert gas like CO 2 

# with natural gas. Water injection to cool the

b urner peak flame temperature is also being investigated. This technique has already been

successfully used for reducing NO

x 

# emissions from gas turbines and a straight-grate ta conite

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 and is not yet commercially available.

Induced Flue Gas Recirculation Burners

Induced flue gas recirculation burners, also called ultra low-NO

x 

# burners, combine the benefits of

f lue gas recirculation and low-NO

x 

# 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 NO

x 

# control efficiency for IFGR

b urners in high temperature applications is 25-50%.

As noted above, taconite furnaces are designed to operate with oxygen levels near 18%. At these

oxygen levels, flue gas recirculation is ineffective at NO

x 

# reduction, and it would adversely affect

c ombustion because excessive amounts of oxygen would be injected into the flame pattern. In

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.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 36 Energy Efficiency Projects

Energy efficiency projects provide opportunities for a company to reduce their fuel consumption,

which results in lower operating costs. Typically, reduced fuel usage translates into reduced

pollution emissions. Due to the increased price of fuel, Tilden has already implemented energy

efficiency projects. Each project carries its own fuel usage reductions and potentially emission

reductions. Due to the uncertainty and generalization for this category, this will not be further

evaluated in this report. However, it should be noted that Tilden will continue to evaluate and

implement energy efficiency projects as they arise.

Ported Kilns

Ported kilns are rotary kilns that have air ports installed at specified points along the length of the

kiln for process improvement. The purpose of the ports is to allow air injection into the pellet bed as

it travels down the kiln bed. Ports are installed about the circumference of the kiln. Each port is

equipped with a closure device that opens when it is at the bottom position to inject air in the pellet

bed, and closed when it rotates out of position.

The purpose of air injection is to provide additional oxygen for pellet oxidation. The oxidation

reaction produces 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 reduces the carry over of the oxidation reaction into the pellet coolers.

Ported kilns are potentially applicable to grate-kilns. In the past, the technology was believed to

reduce NO

x 

# formation. However, the technology vendor will not guarantee that ported kilns will

reduce NO

x 

# emissions because controlling the oxygen in the fir ing zone is not possible due to the

flow of air from the pellet cooler 32 

# . Any reduction in NO

x 

# would be minor and incidental to the

p rocess improvement and specific to the individual furnace. Therefore, although this may be an

available and applicable technology, its NO

x 

# reduction potential is small and may be unsuccessfu l

because of the design of the pellet cooler area. Ported kilns will not be further evaluated in this

report.

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 physical forms – solid, liquid and

32 

# Telephone conversation with Metso, July 18, 2006.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 37 gas. Reduction of NO

x 

# emissions through alternative fuel usage has been a chieved at taconite gratekilns through the use of solid fuel. In these cases the reduction resulted due to changes from

pulverized solid fuel dispersal in the kiln that resulted 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 (NO

x 

# ) for another (SO 2 

# ). Therefore, if this option is pursued, the

i mpact on emissions of all visibility pollutants must be quantified and the cumulative visibility

impact modeled to determine the net benefit of a particular alternative fuel.

It is also important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as an

option, not to direct the fuel choice. 33



# H owever, similar to energy efficiency, Tilden will continue to evaluate and implement alternate fuel

usage as the feasibility arises.

Coal Processing

Pre-combustion coal processing techniques have been proposed as one strategy to reduce

uncontrolled NO

x 

# emissions. Coal processing technologies are being developed to remove moisture

and potential contaminants from the coal prior to use.

These processes typically employ both mechanical and thermal means to increase the quality of coal

by removing moisture, sulfur, mercury, and heavy metals. In one process, raw coal from the mine

enters a first stage separator where it is crushed and screened to remove large rock and rock

material. 34 

# The processed coal is then passed on to an interme diate storage facility prior to being sent

to the next stage in the process, the thermal process. In this stage, coal passes through pressure locks

into the thermal processors where steam is injected. Moisture in the coal is released under these

conditions. Mineral inclusions are also fractured under thermal stress, removing both included rock

and sulfur-forming pyrites. After treatment, the coal is discharged into a second pressurized lock.

The second pressurized lock is vented into a water condenser to return the processor to atmospheric

pressure and to flash cool the coal. Water, removed from the process at various points, and

condensed process steam are reused within the process or treated prior to being discharged.

33 

# Federal Register 70, no. 128 (July 6, 2005): 39164

34 

# The coal processing description provided herein is based on the K-Fuel ® 

# process under development by KFx, Inc.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 38To date, the use of processed fuels has only been demonstrated with test burns in a pulverized coalfired boiler. Using processed fuels at a taconite plant would require research, test burns, and

extended trials to identify potential impacts on plant systems, including the furnaces, material

handling, and emission control systems. Therefore, processed fuels are not considered commercially

available, and will not be analyzed further in this BART analysis.

Coal crushing and drying is currently employed by Tilden as an incidental option for NO

x 

# reduction.

I n the process, raw coal is crushed and screened to remove rocks and other impurities. The crushed

coal is then thermally processed to remove excess moisture. Coal crushing and drying is already in

use, so further reductions from this control option are not possible. Therefore, it will not be further

evaluated in this report.

Process Optimization with Parametric Monitoring

There are several concerns with utilizing process optimization as an available, applicable and

technically feasible control option for the taconite industry:

• Typical 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 NO

x 

# formation.

• A t some operations, the operating parameters which generally influence the rate of NO

x



# g eneration 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 NO

x



# f ormation may not be dependent upon controllable operating parameters. In the absence of

controllable parameters, process optimization would not be effective at controlling NO

x



# e missions.

Based upon this information, there is no indication that further emission reductions would be

achieved through process optimization using parametric monitoring as a control technology.

Therefore, process optimization as a control option will not be evaluated further in this report.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 39 Post Combustion Controls

NO

x 

# can be controlled using add-on systems located down stream 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 NO

x 

# downstream of the combustion chamber. Examples of these alternatives

are nonselective catalytic reduction (NSCR) and Low Temperature Oxidation (LTO). Each of these

alternatives is described below.

Non-Selective Catalytic Reduction (NSCR)

A non-selective catalytic reduction (NSCR) system is a post combustion add-on exhaust gas

treatment system. NSCR catalyst is very sensitive to poisoning; so; NSCR is usually applied

primarily in natural gas combustion applications.

NSCR is often referred to as “three-way conversion” catalyst because it simultaneously reduces NO

x 

# ,

u nburdened hydrocarbons (UBH), and carbon monoxide (CO). Typically, NSCR can achieve NO

x



# e mission 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, NO

x 

# is reduced by CO,

r esulting in nitrogen (N 2 

# ) and carbon dioxide (CO 2 

# ). The most important reactions for NO

x 

# removal

a re:

2CO + 2NO → 2CO 2 

# + N 2 

# (1)

[ UBH] + NO → N 2 

# + CO 2 

# + H 2 

# O (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 is not considered to be

available and applicable, and therefore will not be further evaluated in this report.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 40 Selective Catalytic Reduction (SCR) and Regenerative Selective Catalytic Reduction

(R-SCR)

SCR is a post-combustion NO

x 

# control technology in which ammonia (NH 3 

# ) is injected into the flue

g as stream in the presence of a catalyst. NO

x 

# is removed through the following chemical reaction:

4 NO + 4 NH 3 

# + O 2 

# → 4 N 2 

# + 6 H 2 

# O ( 1)

2 NO 2 

# + 4 NH 3 

# + O 2 

# → 3 N 2 

# + 6 H 2 

# O (2 )

A catalyst bed containing metals in the platinum family is used to lower the activation energy

required for NO

x 

# 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 (R-SCR) applies the Selective Catalytic Reduction (SCR)

control process as described above 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 R-SCR

and then transfers that heat to gas entering the R-SCR. The duct burner is used to complete the

preheating process. R-SCR 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 R-SCR are:

• Its high energy efficiency allows it to be used after SO 2 

# and particulate controls.

• R -SCR has a thermal efficiency of 70% vs. standard heat exchangers which have a thermal

efficiency of 60% to 70%.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 41 • Application of R-SCR after SO 2 

# and PM controls significantly reduces the potential for

problems associated with plugging and catalyst poisoning and deactivation.

There are several concerns about the technical feasibility and applicability of R-SCR 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 R-SCR;

• The taconite dust is highly erosive and can cause significantly equipment damage. R-SCR

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;

• R-SCR 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;

• R-SCR 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, R-SCR 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 R-SCR 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.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 42 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, R-SCR 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

NO

x 

# . In the system, the NO

x 

# in the flue gas is oxidized to form nitrogen pentox ide (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-NO

x 

# ® and LoTOx®.

N O + O 3 

# → N O 2 

# + O 2 

# (1)

N O 2 

# + O 3 

# → N O 3 

# + O 2 

# (2)

N O 3 

# + NO 2 

# → N 2 

# O 5 

# (3)

N 2 

# O 5 

# + H 2 

# O → 2 HNO 3 

# (4)

H NO 3 

# + NaOH → N aNO 3 

# + H 2 

# O (5)

L ow Temperature Oxidation (Tri-NO

x ® 

# )

T his technology uses an oxidizing agent such as ozone or sodium chlorite to oxidize NO to NO 2 

# in a

p rimary scrubbing stage. Then NO 2 

# is removed through caustic scrubbing in a secondary stage. The

reactions are as follows:

O 3 

# + NO → O 2 

# + NO 2 

# ( 1)

2NaOH + 2NO 2 

# + 1⁄2 O 2 

# → 2NaNO 3 

# + H2O ( 2)

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 43 Tri-NO

x ® 

# is a multi-staged wet scrubbing process in industri al 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 NO 2 

# . Subsequent

s tages reduce NO 2 

# to nitrogen gas, while the oxygen becomes part of a soluble salt. Tri-NO

x ® 

# is

t ypically applied at small to medium sized sources with high NO

x 

# concentration in the exhaust gas

( 1,000 ppm NO

x 

# ). NO

x 

# concentrations in the exhaust at Tilden are typical ly less than 200 ppm.

Therefore, Tri-NO

x ® 

# is not applicable to taconite processing and will n ot be analyzed further in this

BART analysis.

Low Temperature Oxidation (LoTOx ® 

# )

B OC Gases’ Lo-TOx ® 

# is an example of a version of an LTO system. LoTOx ® 

# technology uses ozone

t o oxidize NO to NO 2 

# and NO 2 

# to N 2 

# O 5 

# in a wet scrubber (absorber). This can be done in t he same

scrubber used for particulate or sulfur dioxide removal, The N 2 

# O 5 

# is converted to HNO 3 

# in a

s crubber, and is removed with lime or caustic. Ozone for LoTOx ® 

# is generated on site with an

e lectrically powered ozone generator. The ozone generation rate is controlled to match the amount

needed for NO

x 

# control. Ozone is generated from pure oxygen. In order for LoTOx ® 

# to be

e conomically 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 or any process beyond coal or gas fired boilers. 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 –

3 5,000 acfm, which is quite small, compared to the indurating furnace flue gas flow rates of over one

million acfm. Therefore, the application of LTO would be more than two orders of magnitude larger

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 44 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 a pplications.

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 from 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 (Fe 3 

# O 4 

# ) which would react with the

o zone to form hematite (Fe 2 

# O 3 

# ); since the ozone injection point would be before t he scrubber,

there can be more than 185 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

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 SO 2 

# , converting the

m aterial to SO 3 

# which could result in the generation of sulfuric ac id 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 tried on taconite induration furnaces, on airflows of the

magnitude of taconite furnace exhausts, nor on 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

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 45 performance would be forthcoming in advance of a demonstration project. The timeline required to

perform such a demonstration project would likely be two years to develop and agree on the test

plan, obtain permits for the trial, commission the equipment for the test runs, perform the test runs

for a reasonable study period, and evaluate and report on the results. The results would not be

available within the time window for establishing emission limits to be incorporated in the state

implementation plan (SIP) by December 2007.

Recalling U.S. EPA’s intention regarding “available” technologies to be considered for BART, as

mentioned in Section 2.B, facility owners are not expected to undergo extended trials in order to

learn how to apply a control technology to a completely new and significantly different source type.

Consequently, LTO is technically infeasible on an indurating furnace and will not be evaluated

further.

Step 2 Conclusion

Based upon the determination within Step 2, the remaining NO

x 

# control technologies that are

a vailable and applicable to the indurating furnace process are identified in Table 5-9. The technical

feasibility as determined in Step 2 is also included in Table 5-9.

Table 5-9 Indurating Furnace NO

x 

# Control Technology – Availability, Applicability, a nd

Technical Feasibility



# NO

x 

# Pollution Control

Technology Available? Applicable? Technically

Feasible?

External Flue Gas

Recirculation (EFGR) Yes No No

Low NO

x 

# Burners (LNB) Y es Yes No

Induced Flue Gas

Recirculation Burners (IFGR) Yes Yes No

Energy Efficiency Projects Yes Yes Project

Dependent

Ported Kilns

(Applies to Grate-Kilns Only) Yes Yes No

Alternative Fuels Yes Yes Yes

- Not Required

by BART

Process Optimization Yes No No

Non-Selective Catalytic

Reduction (NSCR) Yes No No

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 46 NO

x 

# Pollution Control

Technology Available? Applicable? Technically

Feasible?

Selective Catalytic

Reduction (SCR) with

conventional reheat Yes Yes Yes

Regenerative SCR Yes No No

Selective Non-Catalytic

Reduction (SNCR) Yes No No

Low Temperature Oxidation

(LTO) Yes No No



# 5.A.ii.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies

Table 5-10 describes the expected control efficiency from each of the remaining technically feasible

control options as identified in Step 2.

Table 5-10 Indurating Furnace NO

x 

# Control Technology Effectiveness



# NO

x 

# Pollution Control

Technology Approximate Control

Efficiency

SCR

With conventional reheat 80%



# 5.A.ii.d STEP 4 – Evaluate Impacts and Document the Results

Table 5-11 summarizes the expected costs associated with installation of low NO

x 

# burners and SCR

w ith conventional reheat. 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 six-tenths-factor rule to account for the

economy of scale. Operating costs were based on 93% utilization and annual operating hours of

7680 hours for Line 1. 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 recent actual

retrofit costs. See Appendix C for a site plan of the facility. Additionally, the structural design of the

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 47 existing building would not support additional equipment on the roof. The detailed cost analysis is

provided in Appendix A.

Table 5-11 Indurating Furnace NO

x 

# Control Cost Summary

Control Technology Installed

Capital Cost

(MM$) Total Annual

Cost

(MM$/yr) Annualized

Pollution

Control Cost

($/ton)

SCR

With conventional reheat $65,492,092 $31,055,581 $8,416



# 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 rulemaking process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost

effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not

afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the

electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater

business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for

proposing BART in lieu of developing industry and site specific data.

The annualized pollution control cost value was used to determine whether or not additional impacts

analyses would be conducted for the technology. If the control cost was less than a screening

threshold established by MDEQ, then visibility modeling impacts, and energy and other impacts are

evaluated. MDEQ set the screening level to eliminate technologies from requiring the additional

impact analyses at an annualized cost of $12,000 per ton of controlled pollutant 35 

# . Therefore, all air

p ollution controls with annualized costs less than this screening threshold will be evaluated for

visibility improvement, energy and other impacts. Based on the information presented in table 5-11,

SCR with conventional reheat is the only technology that requires analysis for visibility

improvement, energy and other impacts.

35 

# Michigan Department of Environmental Quality May 12 , 2006 meeting.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 48 The BART guidance documents also present a calculation method for incremental control cost which

is intended to present the incremental value of each technology as compared to the next most

effective alternative. Since only one of the technologies is cost effective, the incremental control

cost is not applicable and is not presented in this analysis.

The incremental control cost column in Table 5-11 is intended to present the incremental value of

each technology as compared to the technology with the next most effective alternative. Since none

of the NO

x 

# reduction technologies are cost effective, the incr emental cost is not applicable.

Energy and Environmental Impact

The energy and non-air quality impacts for the remaining alternatives are presented in Table 5-12.

Table 5-12 NO

x 

# Control Technology Impacts Assessment

Control Technology Energy Impacts Other Impacts

SCR with Reheat Reheat would require

additional natural gas

use. • Ammonia slip, which

contributes to regional

haze. Ammonia reacts

with NO

x 

# to form

a mmonium nitrate and

SO 2 

# to form ammonium

s ulfate particles.

Ammonium sulfate is

hygroscopic and bonds

with water in the air to

grow large particles. The

large particles formed by

ammonium sulfate

disproportionately

contribute to visibility

impairment.

• Ammonia emissions will

increase condensable PM

emissions that will have

possible PSD permitting

implications.

• Ammonia deposition onto

nearby lakes and waters

of the state and contribute

nutrients and undesirable

biological growth.

• Additional safety and

regulatory concerns

associated with ammonia

storage on site.

• Possible oxidation of

elemental mercury.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 49 5.A.ii.e STEP 5 – Evaluate Visibility Impacts

As previously stated in Section 4 of this document, states are required to consider the degree of

visibility improvement resulting from the retrofit technology, in combination with other factors such

as economic, energy and other non-air quality impacts, when determining BART for an individual

source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this

document. This section of the report evaluates the visibility impacts of BART NO

x 

# control and the

r esulting 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-control emissions to be used for the visibility impacts analysis should also reflect a

maximum 24-hour average project emission rate. In the visibility impacts analysis for NO

x 

# , the

e missions from the sources undergoing a full BART NO

x 

# analysis were adjusted to reflect the

p rojected 24-hour maximum NO

x 

# emission rate when applying the control technologie s that met the

threshold requirements of steps 1 – 4. The emissions from all other Subject-to-BART sources were

not changed. Table 5-13 provides a summary of the modeled 24-hour maximum emission rates and

their computational basis for the evaluated NO

x 

# control technologies. Table 5-14 provides a

s ummary of the modeling input data.Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc50Table 5-13 Post-Control NOxModeling ScenariosScenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrBaseSVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood CombustionPractice0.0%200.272.80.0%800.9291.1Base SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7Base SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 0.1 0.0% 19.31SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat 0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 0.1 0.0% 19.33SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 0.1 0.0% 19.35SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 0.1 0.0% 19.37SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 0.1 0.0% 19.39SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat 0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.811SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc51Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrSVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.813SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat 0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.815SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.817SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat 0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.419SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.421SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat 0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.423SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.425SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.727SVP0051981 EUKILN1 Wet ScrubberSCR w/reheat80% 40.0 80% 160.2Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc52Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrSVP005171180% 14.6 80% 58.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.729SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat 0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.731SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.7Table 5-14 Post-Control NOXModeling Scenarios - Modeling Input DataControl ScenarioSV #Emission UnitStack Easting(utm)Stack Northing(utm)Height ofOpening fromGround(ft)Base Elevationof Ground(ft)Stack length,width, orDiameter(ft)Flow Rate at exit(acfm)Exit Temp(oF)All ScenariosSVP0051981SVP0051711EUKILN146.4408499446.44075383-87.65340738-87.65132336240160147419.313.5842,000306,000300300SVP0082951 EUDRYER1 46.44075383-87.6513233611914746.357,135 150SVBLR.STK.T1EUBOILER1EUBOILER246.44091784-87.6541241813014747.5 192,000 350

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 53 Post-Control Visibility Impacts Modeling Results

Results of the post-control visibility impacts modeling for NO X 

# are presented in Table 5-15. The

r esults 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-control

modeling scenarios to the baseline conditions is presented in Table 5-16.

As illustrated in tables 5-15 and 5-16, the facility baseline visibility contribution is 0.72 dV.

Installing SCR with conventional reheat on Line 1 when natural gas is burned could potentially

reduce the visibility contribution by 0.45 from Scenario 1..

Visibility impacts with SO 2 

# controls are presented in section 6.

Table 5-15 Post-Control NO X 

# Modeling Scenarios - Visibility Modeling Results

Modeling Results

2002 2003 2004

2002-2004

Scenario Limiting

Class I

Area Modeled

98%ile

∆ dV # days

over

0.5 ∆ dV Modeled

98%ile

∆ dV # days

over

0.5 ∆ dV Modeled

98%ile

∆ dV # days

over

0.5 ∆ dV Modeled

98%ile

∆ dV # days

over

0.5 ∆ dV



# Base IRNP 0.714 19.0 0.722 11.000 0.599 11.000 0.674 41

1 IRNP 0.323 2.0 0.275 1.000 0.228 1.000 0.248 2

3 IRNP 0.183 0.0 0.177 0.000 0.154 0.000 0.173 0

5 IRNP 0.322 2.0 0.256 0.000 0.219 1.000 0.254 2

7 IRNP 0.182 0.0 0.177 0.000 0.155 0.000 0.169 0

9 IRNP 0.314 2.0 0.252 0.000 0.213 1.000 0.248 2

11 IRNP 0.176 0.0 0.168 0.000 0.150 0.000 0.161 0

13 IRNP 0.315 2.0 0.246 0.000 0.218 1.000 0.243 2

15 IRNP 0.176 0.0 0.171 0.000 0.150 0.000 0.160 0

17 IRNP 0.326 2.0 0.243 0.000 0.218 1.000 0.243 2

19 IRNP 0.175 0.0 0.173 0.000 0.151 0.000 0.163 0

21 IRNP 0.324 2.0 0.241 0.000 0.215 1.000 0.241 2

23 IRNP 0.175 0.0 0.170 0.000 0.150 0.000 0.165 0

25 IRNP 0.326 2.0 0.245 0.000 0.207 1.000 0.241 2

27 IRNP 0.176 0.0 0.172 0.000 0.151 0.000 0.165 0

29 IRNP 0.325 2.0 0.239 0.000 0.198 1.000 0.240 2

31 IRNP 0.173 0.0 0.172 0.000 0.151 0.000 0.164 0

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 54 Table 5-16 Post-Control NO X 

# Modeling Scenarios - Visibility Improvements

Modeling Results

2002 2003 2004 2002-2004

Scenario Limiting

Class I

Area Improved

Modeled

98 th



# Percentile

Value

( ∆ -dV) Decreased

No. of

Days

exceeding

0.5 dV Improved

Modeled

98 th



# Percentile

Value

( ∆ -dV) Decreased

No. of

Days

exceeding

0.5 dV Improved

Modeled

98 th



# Percentile

Value

( ∆ -dV) Decreased

No. of

Days

exceeding

0.5 dV Improved

Modeled

98 th



# Percentile

Value

( ∆ -dV) Decreased

No. of

Days

exceeding

0.5 dV



# 1 IRNP 0.391 17 0.447 10 0.371 10 0.426 39

3 IRNP 0.531 19 0.545 11 0.445 11 0.501 41

5 IRNP 0.392 17 0.466 11 0.38 10 0.42 39

7 IRNP 0.532 19 0.545 11 0.444 11 0.505 41

9 IRNP 0.4 17 0.47 11 0.386 10 0.426 39

11 IRNP 0.538 19 0.554 11 0.449 11 0.513 41

13 IRNP 0.399 17 0.476 11 0.381 10 0.431 39

15 IRNP 0.538 19 0.551 11 0.449 11 0.514 41

17 IRNP 0.388 17 0.479 11 0.381 10 0.431 39

19 IRNP 0.539 19 0.549 11 0.448 11 0.511 41

21 IRNP 0.39 17 0.481 11 0.384 10 0.433 39

23 IRNP 0.539 19 0.552 11 0.449 11 0.509 41

25 IRNP 0.388 17 0.477 11 0.392 10 0.433 39

27 IRNP 0.538 19 0.55 11 0.448 11 0.509 41

29 IRNP 0.389 17 0.483 11 0.401 10 0.434 39

31 IRNP 0.541 19 0.55 11 0.448 11 0.51 41

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 55 

# 5.B Process Boilers 1 and 2

Two natural gas and fuel oil fired process boilers r equire BART analysis. These boilers provide

steam required to operate the taconite plant, as needed. The boilers are only permitted to burn

natural gas and used oil.



# 5.B.i Sulfur Dioxide Controls

Sulfur in the fuel is the only source of SO 2 

# emissions from these boilers. The boilers have low

emissions of SO 2 

# due to the low sulfur content of the permitted fuel s.

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. Many emerging technologies have been identified that are not currently commercially

available. A preliminary list of technologies was submitted to MDEQ on October 6, 2006 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 F presents the current status of the general availability of each technology.

5.B.i.b STEP 2 – Eliminate Technically Infeasible Options

Step 1 identified the available and applicable technologies for SO 2 

# emission reduction. Within

S tep 1, the technical feasibility of the control option was also discussed and determined. The

following describes retrofit SO 2 

# control technologies that were identified as availa ble 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.

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 SO 2 

# removal,

c austic is added to the water spray system, allowing the WWESP spray system to function as an SO 2



# a bsorber.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 56 The SO 2 

# control efficiency for a WWESP is dependent upon va rious process specific variables, such

as SO 2 

# flue gas concentration and fuel used. Based on the i nformation contained within this report, a

WWESP is considered a technically feasible technology for SO 2 

# reduction for this BART analysis.

W et Scrubbing (High and Low Efficiency)

Wet scrubbing, when applied to remove SO 2 

# , 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 SO 2 

# in the waste gas. Crushed limestone, lime or Causti c 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:

CaCO 3 

# + SO 2 

# → CaSO 3 

# • 1/2 H2O + CO 2



# C aSO 3 

# •1/2 H 2 

# O + 3H 2 

# O + O 2 

# → 2 CaSO 4 

# •2 H 2 

# O

L ime 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 

# +SO 2 

# → CaSO 3 

# • 1/2 H 2 

# O + 1/2 H 2 

# O

C a(OH) 2 

# + SO 2 

# + 1/2 O 2 

# + H 2 

# O → CaSO 4 

# •2 H 2 

# O

W hen that caustic (sodium hydroxide solution) is the scrubbing agent, the SO 2 

# removal reactions are

a s follows:

Na+ + OH- + SO 2 

# + → Na 2 

# SO 3



# 2 Na+ + 2OH- + SO 2 

# + → Na 2 

# SO 3 

# + H 2 

# O

C austic 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 SO 2 

# removal, additional

e quipment 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.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 57 The normal SO 2 

# control efficiency range for SO 2 

# scrubbers on coal fired utility boilers is 80% to 9 0%

for low efficiency scrubbers and 90% and more for high efficiency scrubbers. The highest control

efficiencies can be achieved when SO 2 

# concentrations are the highest. The process boiler ’s exhaust

would not have a high SO 2 

# concentration, so the low end of the efficiency ran ge would be expected.

Based on the information contained within this report, a wet scrubber is considered a technically

feasible technology for SO 2 

# reduction for this BART analysis.

D ry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection)

Dry sorbent injection (DSI) of lime/limestone is a post-combustion SO 2 

# control technology in which

p ulverized lime or limestone is directly injected into the duct upstream of the fabric filter. Dry

sorption of SO 2 

# onto the lime or limestone particle occurs and the solid particles are collected with a

fabric filter. Further SO 2 

# removal occurs as the flue gas flows through the fi lter cake on the bags. The

normal SO 2 

# control efficiency range for dry SO 2 

# scrubbers is 70% to 90 % for coal fired utility

b oilers.

Based on the information contained within this report, DSI is considered a technically feasible

technology for SO 2 

# reduction for this BART analysis.

S pray Dryer Absorption (SDA)

Spray dryer absorption (SDA) systems spray lime slurry into an absorption tower where SO 2 

# is

a bsorbed by the slurry, forming CaSO 3 

# /CaSO 4 

# . The liquid-to-gas ratio is such that the water

e vaporates 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 a technically feasible

technology for SO 2 

# reduction for this BART analysis.

E nergy Efficiency Projects

Energy efficiency projects provide opportunities for a company to reduce their fuel consumption,

which results in lower operating costs. Typically, reduced fuel usage translates into reduced

pollution emissions. Due to the increased price of fuel, Tilden has already implemented energy

efficiency projects. Each project carries its own fuel usage reductions and potentially emission

reductions. Due to the uncertainty and generalization of this category, this will not be further

evaluated in this report. However, it should be noted that Tilden will continue to evaluate and

implement energy efficiency projects as they arise.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 58 Alternate Fuels

As described within the energy efficiency description, increased price of fuel has also pushed

companies to evaluate alternate fuel sources. These fuel sources come in all forms – solid, liquid and

gas. To achieve reduction of SO 2 

# emissions through alternative fuel usage, the sourc e must be

capable of burning fuels with lower sulfur content than the existing fuels. The process boilers are

only permitted to burn natural gas and used oil, which are both low in sulfur content. Therefore SO 2



# e mission reductions through the use of alternate fuels are not an option and are not applicable to the

process boilers.

It is also important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as their

option, not to direct the fuel choice. 36



# T herefore, due to the limited fuel burning capabilities of the boilers and the fact that BART is not

intended to mandate a fuel switch, alternative fuels as an air pollution control technology will not be

further evaluated in this report.

However, similar to energy efficiency, Tilden will continue to evaluate and implement alternate fuel

usage as the feasibility arises.

Coal Processing

Since the process boilers are not capable of burning solid fuel, this option is not applicable for SO 2



# r eductions.

STEP 2 Conclusion

Based upon the determination within Step 2, the remaining SO 2 

# control technologies that are

a vailable and applicable to the process boilers are identified in Table 5-17. The technical feasibility

as determined in Step 2 is also included in Table 5-17.

36 

# Federal Register 70, no. 128 (July 6, 2005): 39164

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 59 Table 5-17 Process Boiler SO 2 

# Control Technology – Availability, Applicability, a nd Technical

Feasibility

SO 2 

# Pollution Control

Technology Available? Applicable? Technically Feasible?

WWESP Yes Yes Yes

Wet Scrubber Yes Yes Yes

Spray Dry Absorption (SDA) Yes Yes Yes

Dry Sorbent Injection (DSI) Yes Yes Yes

Energy Efficiency Projects Yes Yes Project Dependent

Alternative Fuels Yes Yes Yes - Not Required by

BART



# 5.B.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies

Table 5-18 describes the expected control efficiency from each of the remaining feasible control

options when burning liquid fuels.

Table 5-18 Process Boiler SO 2 

# Control Technology Effectiveness

SO 2 

# Pollution Control Technology Approximate Control Efficiency

SDA 90%

Wet Scrubbing (High Efficiency) 80%

WWESP 80%

DSI 55%



# 5.B.i.d STEP 4 – Evaluate Impacts and Document the Results

As illustrated in Table 5-18 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 5-19 details the expected costs associated with installation of the above alternatives on each

stack. Equipment design was based on the maximum 24-hour emissions, vendor estimates, and U.S.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 60 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 six-tenths-factor rule 37 

# as shown in the following equation:

Cost of equipment A = Cost of equipment B * (capacity of A/capacity of B) 0.6



# D irect 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 manual 38 

# and engineering experience, and were adjusted for t he specific flow rates

and pollutant concentrations.

The detailed cost analysis is provided in Appendix A.

Table 5-19 Process Boilers 1 and 2 SO 2 

# Control Cost Summary

Control Technology Installed

Capital Cost

($) Total

Annual Cost

($/yr) Annualized

Pollution

Control Cost

($/ton)

SDA $56,323,180 $8,640,697 $38,403,097

Wet Scrubber $9,309,297 $1,489,576 $7,447,882

WWESP $17,123,526 $3,146,592 $15,732,959

DSI $32,010,048 $4,892,432 $35,581,325



# 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 rulemaking process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost

effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not

afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the

electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater

37 

# M.S. Peters and K.D. Timmerhaus, December, 2002 P lant Design and Economics for Chemical Engineers, Fifth

Edition.

38 

# U.S. EPA, January 2002, E PA Air Pollution Control Cost Manual, Sixth Edition

.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 61 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 MDEQ, then visibility modeling impacts, and energy and other impacts are

evaluated. MDEQ set the screening level to eliminate technologies from requiring the additional

impact analyses at an annualized cost of $12,000 per ton of controlled pollutant 39 

# . Therefore, all air

p ollution controls with annualized costs less than this screening threshold will be evaluated for

visibility improvement, energy and other impacts. Based on the information presented in table 5-19,

the annualized pollution control costs for all of the technologies are above the $12,000 threshold.

Therefore, no additional analysis for visibility improvement, energy and other impacts is required.

The BART guidance documents also present a calculation method for incremental control cost which

is intended to present the incremental value of each technology as compared to the next most

effective alternative. Since none of the technologies are cost effective, the incremental control cost

is not applicable and is not presented in this analysis.

Energy and Environmental Impacts

Since none of the SO 2 

# technologies are cost effective for the process boi lers, the energy and non-air

quality impacts were not assessed for the SO 2 

# control equipment technologies for the process boil ers.

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

As previously stated in section 4 of this document, states are required to consider the degree of

visibility improvement resulting from the retrofit technology, in combination with other factors such

as economic, energy and other non-air quality impacts, when determining BART for an individual

source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this

document. Since none of the SO 2 

# technologies are cost effective for the process boi lers, the visibility

impacts were not evaluated.

39 

# Michigan Department of Environmental Quality May 12 , 2006 meeting.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 62 

# 5.B.ii Nitrogen Oxide Controls

To be able to control NO

x 

# it is important to understand how NO

x 

# is formed. There are three

m echanisms by which NO

x 

# production occurs: thermal, fuel and prompt NO

x 

# .

• F uel bound NO

x 

# is formed as nitrogen compounds in the fuel is oxid ized in the combustion

process.

• Thermal NO

x 

# 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 NO

x 

# production is a function of the residence time, fre e oxygen, and temperature.

• Prompt NO

x 

# is a form of thermal NO

x 

# which is generated at the flame boundary. It is th e

result of reactions between nitrogen and carbon radicals generated during combustion. Only

minor amounts of NO

x 

# are emitted as prompt NO

x 

# .

T he majority of NO

x 

# is emitted as NO. Minor amounts of NO 2 

# are formed in the boiler.

5 .B.ii.a STEP 1 – Identify All Available Retrofit Control Technologies

With the understanding of how NO

x 

# is formed, available and applicable control technol ogies were

evaluated. See Appendix F for the current status of the availability and applicability of retrofit

control technologies. Many emerging technologies have been identified that are not currently

commercially available. A preliminary list of technologies was submitted to MDEQ on October 6,

2006 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 F presents the current status of the general availability of each

technology.

5.B.ii.b STEP 2 – Eliminate Technically Infeasible Options

Step 1 identified the available and applicable technologies for NO

x 

# emission reduction. Within

S tep 1, the technical feasibility of the control option was also discussed and determined. The

following describes retrofit NO

x 

# control technologies that were identified as availa ble and applicable

in the original submittal and discusses aspects of those technologies that determine whether or not

the technology is technically feasible for process boilers.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 63 External Flue Gas Recirculation (EFGR)

External flue gas recirculation (EFGR) uses flue gas as an inert material to reduce flame temperatures

thereby reducing thermal NO

x 

# formation. In an external flue gas recirculation sy stem, 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 NO

x 

# emissions. For

t his technology to be effective, the combustion conditions must have the ability to be controlled at

the burner tip. Due to the current configuration of the burners, 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-NO

x 

# burner (LNB) technology utilizes advanced burner de sign to reduce NO

x 

# formation through

t he 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 NO

x 

# formation. In the secondary zone, combustion produc ts formed in

the primary zone act to lower the local oxygen concentration, resulting in a decrease in NO

x



# f ormation. Low NO

x 

# burners typically achieve NO

x 

# emission reductions of 25% - 50% for process

b oilers.

Based on the information contained within this report, LNB is considered a technically feasible

technology for NO

x 

# reduction for this BART analysis.

O verfire Air (OFA)

Overfire air (OFA) 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 NO

x 

# control technology typically

u sed in boilers and is primarily geared to reduce thermal NO

x 

# . Staging of the combustion air creates

a n initial fuel-rich combustion zone for a cooler fuel-rich combustion zone. This reduces the

production of thermal NO

x 

# by lowering peak combustion temperature and limitin g the availability of

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 64 oxygen in the combustion zone where NO

x 

# is most likely to be formed. OFA is considered

c ompatible with the LNB. The estimated NO

x 

# control efficiency for LNB with OFA is 50-67%.

B ased on the information contained within this report, OFA with LNB is considered a technically

feasible technology for NO

x 

# reduction for this BART analysis.

I nduced Flue Gas Recirculation (IFGR)

Induced flue gas recirculation burners, also called ultra low-NO

x 

# burners, combine the benefits of

f lue gas recirculation and low-NO

x 

# 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 NO

x 

# control efficiency for IFGR

b urners in high temperature applications is 50-75%.

Based on the information contained within this report, IFGR is considered a technically feasible

technology for NO

x 

# reduction for this BART analysis.

E nergy Efficiency Projects

Energy efficiency projects provide opportunities for a company to reduce their fuel consumption.

Typically reduced fuel usage translates into reduced pollution emissions. An energy efficiency

project could be preheat incoming make-up air or pellet feed. Each project is very dependent upon

the fuel usage, process equipment, type of product and so many other variables.

Due to the increased price of fuel, Tilden has already implemented energy efficiency projects. Each

project carries its own fuel usage reductions and potential emission reductions. Due to the

uncertainty and generalization of this category, this will not be further evaluated in this report.

However, it should be noted that Tilden 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 also pushed

companies to evaluate alternate fuel sources. These fuel sources come in all forms – solid, liquid and

gas. To achieve reduction of NO

x 

# emissions through alternative fuel usage, the sourc e must be

currently burning a high NO

x 

# 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.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 65 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. 40



# T herefore, due to the limited boiler fuel capabilities and the fact that BART is not intended to

mandate a fuel switch, alternative fuels as an air pollution control technology will not be further

evaluated in this report

However, similar to energy efficiency, Tilden will continue to evaluate and implement alternate fuel

usage as the feasibility arises.

Low Excess Air

Operating a boiler with low excess air is a method to minimize peak flame temperature and excess

oxygen which therefore minimizes the production of NO

x 

# . Operating a boiler with low excess air

a lso optimizes the fuel efficiency as less air is heated up in the combustion chamber.

As previously stated, the increased price of fuel has pushed companies to evaluate fuel usage.

Therefore, the boilers at Tilden are operated with low excess air within the constraints of the boilers.

Therefore, low excess air will not be further evaluated in this report. However, similar to energy

efficiency and alternate fuels, the facility will continue to evaluate boiler optimization including

operating at low excess air.

Reburning

Reburning is a technology used with solid fuels. Process boilers are not cable of burning solid fuel,

therefore this technology will not be further evaluated.

Post Combustion Controls

NO

x 

# can be controlled using add-on systems located down stream 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,

40 

# Federal Register 70, no. 128 (July 6, 2005): 39164

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 66 absorbing, or adsorbing NO

x 

# downstream of the combustion chamber. Examples of these alternatives

are nonselective catalytic reduction (NSCR) and Low Temperature Oxidation (LTO). Each of these

alternatives is described below.

Non-Selective Catalytic Reduction (NSCR)

A non-selective catalytic reduction (NSCR) system is a post combustion add-on exhaust gas

treatment system. NSCR catalyst is very sensitive to poisoning; therefore, NSCR is applied primarily

in natural gas combustion applications.

NSCR is often referred to as “three-way conversion” catalyst because it simultaneously reduces NO

x 

# ,

u nburdened hydrocarbons (UBH), and carbon monoxide (CO). Typically, NSCR can achieve NO

x



# e mission 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, NO

x 

# is reduced by CO,

r esulting in nitrogen (N 2 

# ) and carbon dioxide (CO 2 

# ). The most important reactions for NO

x 

# removal

a re:

2CO + 2NO → 2CO 2 

# + N 2 

# (1)

[ UBH] + NO → N 2 

# + CO 2 

# + H 2 

# O (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 (SCR) and Regenerative Selective Catalytic Reduction

(R-SCR)

SCR is a post-combustion NO

x 

# control technology in which ammonia (NH 3 

# ) is injected into the flue

g as stream in the presence of a catalyst. NO

x 

# is removed through the following chemical reaction:

4 NO + 4 NH 3 

# + O 2 

# → 4 N 2 

# + 6 H 2 

# O ( 1)

2 NO 2 

# + 4 NH 3 

# + O 2 

# → 3 N 2 

# + 6 H 2 

# O (2 )

A catalyst bed containing metals in the platinum family is used to lower the activation energy

required for NO

x 

# 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.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 67 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 (R-SCR) 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 R-SCR

and then transfers that heat to gas entering the R-SCR. The duct burner is used to complete the

preheating process. R-SCR 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 R-SCR are:

• Its high energy efficiency allows it to be used after SO 2 

# and particulate controls.

• R -SCR has a thermal efficiency of 90% - 95% vs. standard heat exchangers which have a

thermal efficiency of 60% to 70%.

• Application of R-SCR after SO 2 

# and PM controls significantly reduces the potential for

problems associated with plugging and catalyst poisoning and deactivation.

To date, R-SCR 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, 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.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 68 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, R-SCR 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.

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, N 2 

# , 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 + NH 3 

# + 1⁄4O 2 

# → N 2 

# + 3/2 

# H 2 

# O (1)

N H 3 

# + 1⁄4O 2 

# → N O + 3/2H 2 

# O (2)

At temperature ranges of 1470 to 1830 ° F reaction (1) dominates. At temperatures above 2000 ° F,

reaction (2) will dominate.

Based on the information contained within this report, a SNCR is considered a technically feasible

technology for NO

x 

# reduction for this BART analysis.

L ow Temperature Oxidation (LTO)

The LTO system utilizes an oxidizing agent such as ozone to oxidize various pollutants including

NO

x 

# . In the system, the NO

x 

# in the flue gas is oxidized to form nitrogen pentox ide (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-NO

x 

# ® and LoTOx®.

N O + O 3 

# → N O 2 

# + O 2 

# (1)

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 69 NO 2 

# + O 3 

# → N O 3 

# + O 2 

# (2)

N O 3 

# + NO 2 

# → N 2 

# O 5 

# (3)

N 2 

# O 5 

# + H 2 

# O → 2 HNO 3 

# (4)

H NO 3 

# + NaOH → N aNO 3 

# + H 2 

# O (5)

L ow Temperature Oxidation (Tri-NO

x ® 

# )

T his technology uses an oxidizing agent such as ozone or sodium chlorite to oxidize NO to NO 2 

# in a

p rimary scrubbing stage. Then NO 2 

# is removed through caustic scrubbing in a secondary stage. The

reactions are as follows:

O 3 

# + NO → O 2 

# + NO 2 

# ( 1)

2NaOH + 2NO 2 

# + 1⁄2 O 2 

# → 2NaNO 3 

# + H2O ( 2)

Tri-NO

x ® 

# is a multi-staged wet scrubbing process in industri al 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 NO 2 

# . Subsequent

s tages reduce NO 2 

# to nitrogen gas, while the oxygen becomes part of a soluble salt. Tri-NO

x ® 

# is

t ypically applied at small to medium sized sources with high NO

x 

# concentration in the exhaust gas

( 1,000 ppm NO

x 

# ).

L ow Temperature Oxidation (LoTOx ® 

# )

B OC Gases’ Lo-TOx ® 

# is an example of a version of an LTO system. LoTOx ® 

# technology uses ozone

t o oxidize NO to NO 2 

# and NO 2 

# to N 2 

# O 5 

# in a wet scrubber (absorber). This can be done in t he same

scrubber used for particulate or sulfur dioxide removal, The N 2 

# O 5 

# is converted to HNO 3 

# in a

s crubber, and is removed with lime or caustic. Ozone for LoTOx ® 

# is generated on site with an

e lectrically powered ozone generator. The ozone generation rate is controlled to match the amount

needed for NO

x 

# control. Ozone is generated from pure oxygen. In order for LoTOx ® 

# to be

e conomically feasible, a source of low cost oxygen must be available from a pipeline or on site

generation.

In addition, only two of BOC’s LoTOx ® 

# installations are fully installed and operational a pplications.

Therefore, although this is an emerging technology, the limited application means that it has not been

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 70 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 NO

x 

# control technologies that are

a vailable and applicable to the process boilers are identified in Table 5-20. The technical feasibility

as determined in Step 2 is also included in Table 5-20.

Table 5-20 Process Boilers 1 and 2 NO

x 

# Control Technology – Availability, Applicability an d

Technical Feasibility

NOx Pollution Control Technology Available? Applicable? Technically

Feasible?

External Flue Gas Recirculation (EFGR) Yes Yes No

Low-NOx Burners (LNB) Yes Yes Yes

Low NOx Burners with Overfired Air

(LNB/OFA) Yes Yes Yes

Induced Flue Gas Recirculation (IFGR) Yes Yes Yes

Low Excess Air Yes Yes Yes

(already

implemented)

Reburning Yes Yes No

Energy Efficiency Projects Yes Yes Project

Dependent

Alternative Fuels Yes Yes Yes

- Not Required

by BART

Non-Selective Catalytic Reduction (NSCR) Yes Yes Yes

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 5-21 describes the expected control efficiency from the remaining technically feasible control

option as identified in Step 2.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 71 Table 5-21 Process Boiler NOx Control Technology Effectiveness

NOx Pollution Control Technology Approximate Control

Efficiency

Selective Catalytic Reduction (SCR) with

Reheat 80%

Low NOX Burner / Flue Gas Recirculation

(LNB/FGR) 75%

Regenerative Selective Catalytic Reduction

(R-SCR) 70%

Low NOX Burner / Overfire Air (LNB/OFA) 67%

Low NOX Burner (LNB) 50%

Selective Non-Catalytic Reduction (SNCR) 50%



# 5.B.ii.d STEP 4 – Evaluate Impacts and Document the Results

Table 5-22 details the expected costs associated with installation of NO

x 

# controls. Capital costs were

c alculated 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.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 72 Table 5-22 Process Boiler NO

x 

# Control Cost Summary

Control

Technology Installed

Capital Cost

($) Total Annual

Cost

($/yr) Annualized

Pollution

Control Cost

($/ton) Incremental

Control Cost

($/ton)

SCR with Reheat** $6,317,686 $2,528,225 $39,888 NA

LNB/FGR $2,190,300 $270,904 $4,559 Lowest

R-SCR** $16,117,290 $3,303,391 $59,563 NA

LNB/OFA $3,031,714 $390,751 $7,361 NA

LNB $1,320,909 $286,968 $7,244 NA

SNCR $1,501,420 $426,135 $10,760 NA*

* Control efficiency is equal to the option with the lowest cost per ton, LNB at 50%.

** SCR and R-SCR were eliminated from further consideration due to high cost per ton.



# B ased 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 rulemaking process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost

effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not

afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the

electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater

business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for

proposing BART in lieu of developing industry and site specific data.

The annualized pollution control cost value was used to determine whether or not additional impacts

analyses would be conducted for the technology. If the control cost was less than a screening

threshold established by MDEQ, then visibility modeling impacts, and energy and other impacts are

evaluated. MDEQ set the screening level to eliminate technologies from requiring the additional

impact analyses at an annualized cost of $12,000 per ton of controlled pollutant 41 

# . Therefore, all air

p ollution controls with annualized costs less than this screening threshold will be evaluated for

visibility improvement, energy and other impacts.

41 

# Michigan Department of Environmental Quality May 12 , 2006 meeting.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 73 The incremental control cost listed in Table 5-22 represents the incremental value of each technology

as compared to the technology with the next highest level of control. The cost of control and

incremental cost of SCR with reheat, R-SCR and SNCR are not reasonable. The magnitude of the

capital and operating costs of remaining alternatives is also significant and may impact the viability

of continued operation.

Energy and Environmental Impacts

The energy and non-air quality impacts for LNB and LNB with IFGR are presented in Table 5-23.

Because the cost of the remaining NO

x 

# control technologies for the 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 5-23 Process Boiler NO

x 

# 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

LNB/OFA - Minimal energy impacts - Increase in CO emissions

- Potential for steam tube wastage due to

longer combustion flame

LNB/FGR - Minimal energy impacts. - Increase in CO emissions

- Potential for steam tube wastage due to

longer combustion flame.

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

As previously stated in section 4 of this document, states are required to consider the degree of

visibility improvement resulting from the retrofit technology, in combination with other factors such

as economic, energy and other non-air quality impacts, when determining BART for an individual

source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this

document. This section of the report evaluates the visibility impacts of BART NO X 

# control and the

r esulting 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

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 74 maximum 24-hour average project emission rate. In the visibility impacts NO X 

# modeling analysis,

t he emissions from the sources undergoing a full BART NO

x 

# analysis were adjusted to reflect the

p rojected 24-hour maximum NO

x 

# emission rate when applying the control technologie s that met the

threshold requirements of steps 1 – 4. The emissions from all other Subject-to-BART sources were

not changed. Table 5-24 provides a summary of the modeled 24-hour maximum emission rates and

their computational basis for the evaluated NO

x 

# control technologies. Table 5-25 provides a

s ummary of the modeling input data.

Post-BART Visibility Impacts Modeling Results

Results of the post-BART visibility impacts modeling for NO X 

# for the process boilers are presented

i n Table 5-26. 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 5-27.

Visibility impacts with SO 2 

# controls are presented in section 6.Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc75Table 5-27 Process Boiler Post-BART Modeling ScenariosScenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrBaseSVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood CombustionPractice0.0%200.272.80.0%800.9291.1Base SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7Base SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 0.1 0.0% 19.38SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood CombustionPractice0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.89SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat 0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.810SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.811SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.812SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood CombustionPractice0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.813SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat 0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.814SVP0051981 EUKILN1 Wet Scrubber Good Combustion 80% 40.0 0.0% 800.9Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc76Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrSVP0051711Practice80% 14.6291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.815SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.816SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood CombustionPractice0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.417SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat 0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.418SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.419SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.420SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood CombustionPractice0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.421SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat 0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc77Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrSVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.422SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.423SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.424SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood CombustionPractice0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.725SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.726SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.727SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasGood CombustionPractice0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.728SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood CombustionPractice0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.729SVP0051981 EUKILN1 Low Sulfur Coal SCR w/reheat 0.0% 200.2 80% 160.2Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc78Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrSVP0051711Natural Gas72.8 80% 58.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.730SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.731SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur Fuel OilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur Fuel OilNatural GasLNB0.0% 0.1 50.0% 9.7Table 5-28 Process Boiler Post-BART NOxModeling Scenarios - Modeling Input DataControl ScenarioSV #Emission UnitStack Easting(utm)Stack Northing(utm)Height ofOpening fromGround(ft)Base Elevationof Ground(ft)Stack length,width, orDiameter(ft)Flow Rate at exit(acfm)Exit Temp(oF)All ScenariosSVP0051981SVP0051711EUKILN146.4408499446.44075383-87.65340738-87.65132336240160147419.313.5842,000306,000300300SVP0082951 EUDRYER1 46.44075383-87.6513233611914746.357,135 150SVBLR.STK.T1EUBOILER1EUBOILER246.44091784-87.6541241813014747.5 192,000 350Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc79Table 5-29 Process Boiler Post-BART NOxModeling Scenarios - Visibility Modeling ResultsModeling Results2002200320042002-2004ScenarioLimitingClass IAreaModeled98%ile∆dV# daysover0.5∆dVModeled98%ile∆dV# daysover0.5∆dVModeled98%ile∆dV# daysover0.5∆dVModeled98%ile∆dV# daysover0.5∆dVBaseIRNP0.714 19.0 0.722 11.000 0.599 11.000 0.674 418 IRNP0.714 19.0 0.711 11.000 0.583 11.000 0.653 419 IRNP0.314 2.0 0.252 0.000 0.213 1.000 0.248 210 IRNP 0.618 15.0 0.607 10.000 0.527 8.000 0.590 3311 IRNP 0.176 0.0 0.168 0.000 0.150 0.000 0.161 012 IRNP0.719 19.0 0.693 10.000 0.592 9.000 0.654 3813 IRNP0.315 2.0 0.246 0.000 0.218 1.000 0.243 214 IRNP 0.627 15.0 0.608 9.000 0.544 8.000 0.585 3215 IRNP 0.176 0.0 0.171 0.000 0.150 0.000 0.160 016 IRNP0.722 19.0 0.673 10.000 0.605 9.000 0.656 3817 IRNP0.326 2.0 0.243 0.000 0.218 1.000 0.243 218 IRNP 0.626 15.0 0.605 9.000 0.542 8.000 0.596 3219 IRNP 0.175 0.0 0.173 0.000 0.151 0.000 0.163 020 IRNP0.734 19.0 0.692 10.000 0.605 10.000 0.654 3921 IRNP0.324 2.0 0.241 0.000 0.215 1.000 0.241 222 IRNP 0.625 15.0 0.602 9.000 0.291 3.000 0.588 2723 IRNP 0.175 0.0 0.170 0.000 0.150 0.000 0.165 024 IRNP0.727 19.0 0.689 10.000 0.603 10.000 0.656 3925 IRNP0.326 2.0 0.245 0.000 0.207 1.000 0.241 226 IRNP 0.623 15.0 0.605 9.000 0.550 8.000 0.597 3227 IRNP 0.176 0.0 0.172 0.000 0.151 0.000 0.165 028 IRNP0.704 19.0 0.672 10.000 0.606 9.000 0.657 3829 IRNP0.325 2.0 0.239 0.000 0.198 1.000 0.240 230 IRNP 0.613 14.0 0.614 9.000 0.542 8.000 0.588 3131 IRNP 0.173 0.0 0.172 0.000 0.151 0.000 0.164 0Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc80Table 5-30 Process Boiler Post-BART NOxModeling Scenarios – Comparison of Visibility Modeling Results to Baseline ModelingResultsModeling Results2002200320042002-2004ScenarioLimitingClass IAreaImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. ofDaysexceeding0.5 dVImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. ofDaysexceeding0.5 dVImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. ofDaysexceeding0.5 dVImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. ofDaysexceeding0.5 dV8 IRNP 0 0 0.011 0 0.016 0 0.021 09 IRNP 0.4 17 0.47 11 0.386 10 0.426 3910 IRNP 0.096 4 0.115 1 0.072 3 0.084 811 IRNP 0.538 19 0.554 11 0.449 11 0.513 4112 IRNP -0.005 0 0.029 1 0.007 2 0.02 313 IRNP 0.399 17 0.476 11 0.381 10 0.431 3914 IRNP 0.087 4 0.114 2 0.055 3 0.089 915 IRNP 0.538 19 0.551 11 0.449 11 0.514 4116 IRNP -0.008 0 0.049 1 -0.006 2 0.018 317 IRNP 0.388 17 0.479 11 0.381 10 0.431 3918 IRNP 0.088 4 0.117 2 0.057 3 0.078 919 IRNP 0.539 19 0.549 11 0.448 11 0.511 4120 IRNP -0.02 0 0.03 1 -0.006 1 0.02 221 IRNP 0.39 17 0.481 11 0.384 10 0.433 3922 IRNP 0.089 4 0.12 2 0.308 8 0.086 1423 IRNP 0.539 19 0.552 11 0.449 11 0.509 4124 IRNP -0.013 0 0.033 1 -0.004 1 0.018 225 IRNP 0.388 17 0.477 11 0.392 10 0.433 3926 IRNP 0.091 4 0.117 2 0.049 3 0.077 927 IRNP 0.538 19 0.55 11 0.448 11 0.509 4128 IRNP 0.01 0 0.05 1 -0.007 2 0.017 329 IRNP 0.389 17 0.483 11 0.401 10 0.434 3930 IRNP 0.101 5 0.108 2 0.057 3 0.086 1031 IRNP 0.541 19 0.55 11 0.448 11 0.51 41

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 81 

# 5.C Line 1 Dryer

The Line 1 Dryer requires a BART analysis. This Lin e 1 Dryer includes a combustion box in which

natural gas and used oil is burned as fuel. The flue gas from the combustion box flows into a rotary

dryer that repeatedly tumbles wet taconite ore concentrate through the flue gas stream to reduce the

amount of entrained moisture in the taconite ore concentrated. The particulate emissions from the

dryer are controlled by cyclones and impingement scrubbers in series. The dryer is only permitted to

use natural gas and used oil for fuel.



# 5.C.i Sulfur Dioxide Controls

Sulfur in the fuel is the only source of SO 2 

# emissions from the dryer. The Line 1 Dryer has low

emissions of SO 2 

# due to the low sulfur content of the permitted fuel s. In addition, collateral SO 2



# r eductions occur within the existing impingment scrubbers, and therefore the existing scrubber is

considered a low-efficiency SO 2 

# scrubber.

5 .C.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. Many emerging technologies have been identified that are not currently commercially

available. A preliminary list of technologies was submitted to MDEQ on October 6, 2006 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 F presents the current status of the general availability of each technology.

5.C.i.b STEP 2 – Eliminate Technically Infeasible Options

Step 1 identified the available and applicable technologies for SO 2 

# emission reduction. Within

S tep 1, the technical feasibility of the control option was also discussed and determined. The

following describes retrofit SO 2 

# control technologies that were identified as availa ble 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.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 82 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 SO 2 

# removal,

c austic is added to the water spray system, allowing the WWESP spray system to function as an SO 2



# a bsorber.

The SO 2 

# control efficiency for a WWESP is dependent upon va rious process specific variables, such

as SO 2 

# flue gas concentration and fuel used. Since Line 1 D ryer currently employs a wet scrubber

designed for removal of particulate matter, the scrubber also performs as a low efficiency SO 2 

# wet

s crubber. The addition of a WWESP would act as a polishing SO 2 

# control device and would

e xperience reduced control efficiency due to lower SO 2 

# inlet concentrations.

B ased on the information contained within this report, a WWESP is considered a technically feasible

technology for SO 2 

# reduction for this BART analysis.

W et Scrubbing (High and Low Efficiency)

Wet scrubbing, when applied to remove SO 2 

# , 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 SO 2 

# in the waste gas. Crushed limestone, lime or Causti c 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:

CaCO 3 

# + SO 2 

# → CaSO 3 

# • 1/2 H2O + CO 2



# C aSO 3 

# •1/2 H 2 

# O + 3H 2 

# O + O 2 

# → 2 CaSO 4 

# •2 H 2 

# O

L ime 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 

# +SO 2 

# → CaSO 3 

# • 1/2 H 2 

# O + 1/2 H 2 

# O

C a(OH) 2 

# + SO 2 

# + 1/2 O 2 

# + H 2 

# O → CaSO 4 

# •2 H 2 

# O

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 83 When that caustic (sodium hydroxide solution) is the scrubbing agent, the SO 2 

# removal reactions are

a s follows:

Na+ + OH- + SO 2 

# + → Na 2 

# SO 3



# 2 Na+ + 2OH- + SO 2 

# + → Na 2 

# SO 3 

# + H 2 

# O

C austic 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 SO 2 

# removal, additional

e quipment 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 SO 2 

# control efficiency range for SO 2 

# scrubbers on coal fired utility boilers is 80% to 9 0%

for low efficiency scrubbers and 90% and more for high efficiency scrubbers. The highest control

efficiencies can be achieved when SO 2 

# concentrations are the highest. The dryer and proc ess boiler’s

exhaust would not have a high SO 2 

# concentration, so the low end of the efficiency ran ge would be

expected.

As stated in the beginning of this section, a wet scrubber is currently in place on the Line 1 Dryer and

is believed to remove approximately 30% of the SO 2 

# in the exhaust. The addition of an additional

S O 2 

# scrubber would act as a polishing SO 2 

# control device and would experience reduced control

efficiency due to lower SO 2 

# inlet concentrations.

A Minnesota taconite facility has evaluated modifying the exiting scrubber on the kiln exhaust,

which is similar to the dryer exhaust stream, to determine if improvements to SO 2 

# removal could be

a ccomplished. The concentration of caustic in the scrubbing water was increased to a pH of 8 for

several hours and stack sampling was performed to evaluate the change in SO 2 

# emissions. The SO 2



# e missions were not reduced. The materials of construction of the existing scrubbers would not

withstand a higher pH than 7 or 8. An engineering study would be required to evaluate more

extensive redesign of the existing scrubbers, such as modifying the spray, increasing the contact

time, recirculating the scrubber water, and retrofitting to allow use of a much higher pH.

Quantifying the likelihood and magnitude of potential improvements to SO 2 

# control would not be

p ossible without a study, so this option could not be selected as BART.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 84 Based on the information contained within this report, a wet scrubber is considered a technically

feasible technology for SO 2 

# reduction for this BART analysis.

D ry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection)

Dry sorbent injection (DSI) of lime/limestone is a post-combustion SO 2 

# control technology in which

p ulverized lime or limestone is directly injected into the duct upstream of the fabric filter. Dry

sorption of SO 2 

# onto the lime or limestone particle occurs and the solid particles are collected with a

fabric filter. Further SO 2 

# removal occurs as the flue gas flows through the fi lter cake on the bags. The

normal SO 2 

# control efficiency range for dry SO 2 

# scrubbers is 70% to 90 % for coal fired utility

b oilers.

The Line 1 Dryer flue gas stream is high in water content and is exhausted at or near their dew

points. Exhaust gases leaving the Line 1 Dryer is currently treated for removal of particulate matter

using a wet scrubber. Due to the high water content in the dryer flue gas, 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 for the Line 1 Dryer.

Spray Dryer Absorption (SDA)

Spray dryer absorption (SDA) systems spray lime slurry into an absorption tower where SO 2 

# is

a bsorbed by the slurry, forming CaSO 3 

# /CaSO 4 

# . The liquid-to-gas ratio is such that the water

e vaporates 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%.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 85 The Line 1 Dryer flue gas stream is high in water content and is exhausted at or near their dew

points. Gases leaving the dryer are currently treated for removal of particulate matter using a wet

scrubber. The exhaust temperature is typically in the range of 100 o 

# F to 150 o 

# F and is saturated with

w ater. For comparison, a utility boiler exhaust operates at 350 o 

# F or higher and is not saturated with

w ater. Under dryer 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.

Energy Efficiency Projects

Energy efficiency projects provide opportunities for a company to reduce their fuel consumption,

which results in lower operating costs. Typically, reduced fuel usage translates into reduced

pollution emissions. Due to the increased price of fuel, Tilden has already implemented energy

efficiency projects. Each project carries its own fuel usage reductions and potentially emission

reductions. Due to the uncertainty and generalization of this category, this will not be further

evaluated in this report. However, it should be noted that Tilden 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 also pushed

companies to evaluate alternate fuel sources. These fuel sources come in all forms – solid, liquid and

gas. To achieve reduction of SO 2 

# emissions through alternative fuel usage, the sourc e must be

capable of burning fuels with lower sulfur content than the existing fuels. The Line 1 Dryer is only

permitted to burn natural gas and used oil, which are both low in sulfur content. Therefore SO 2



# e mission reductions through the use of alternate fuels are not an option and are not applicable to the

Line 1 Dryer.

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. 42

42 

# Federal Register 70, no. 128 (July 6, 2005): 39164

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 86 Therefore, due to the limited fuel burning capabilities of the Line 1 Dryer and the fact that BART is

not intended to mandate a fuel switch, alternative fuels as an air pollution control technology will not

be further evaluated in this report.

However, similar to energy efficiency, Tilden will continue to evaluate and implement alternate fuel

usage as the feasibility arises.

Coal Processing

Since the Line 1 Dryer is not permitted to burn solid fuel, this option is not applicable for SO 2



# r eductions.

STEP 2 Conclusion

Based upon the determination within Step 2, the remaining SO 2 

# control technologies that are

a vailable and applicable to the Line 1 Dryer are identified in Table 5-29. The technical feasibility as

determined in Step 2 is also included in Table 5-29.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 87 Table 5-29 Line 1 Dryer SO 2 

# Control Technology – Availability, Applicability, a nd Technical

Feasibility

SO 2 

# Pollution Control

Technology Available? Applicable? Technically Feasible?

WWESP Yes Yes Yes

Wet Scrubber Yes Yes Yes

Spray Dry Absorption (SDA) Yes Yes No

Dry Sorbent Injection (DSI) Yes Yes No

Energy Efficiency Projects Yes Yes Project Dependent

Alternative Fuels Yes Yes Yes – Not required by

BART



# 5.C.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies

Table 5-30 describes the expected control efficiency from each of the remaining feasible control

options for the Line 1 Dryer.

Table 5-30 Line 1 Dryer SO 2 

# Control Technology Effectiveness

SO 2 

# Pollution Control Technology Approximate Control Efficiency

Wet Scrubbing (High Efficiency) 80%

Wet Walled Electrostatic Precipitator (WWESP) 80%



# 5.C.i.d STEP 4 – Evaluate Impacts and Document the Results

As illustrated in Table 5-30 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 5-31 details the expected costs associated with installation of a WWESP and wet scrubber.

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 six-tenths-factor rule as shown in the following equation:

Cost of equipment A = Cost of equipment B * (capacity of A/capacity of B) 0.6

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 88 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 100% utilization and 7650 operating hours

per year, which is very conservative based on historic operating data. Operating costs of consumable

materials, such as electricity, water, and chemicals were established based on the U.S. EPA control

cost manual 43 

# and engineering experience, and were adjusted for t he 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 5-31 Line 1 Dryer SO 2 

# Control Cost Summary

Control Technology Installed

Capital Cost

($) Total

Annual Cost

($/yr) Annualized

Pollution

Control Cost

($/ton)

Wet Scrubber $3,898,490 $684,207 $25,103

Wet ESP (WWESP) $7,674,618 $1,429,065 $52,432



# 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 rulemaking process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost

effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not

afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the

electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater

business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for

proposing BART in lieu of developing industry and site specific data.

The annualized pollution control cost value was used to determine whether or not additional impacts

analyses would be conducted for the technology. If the control cost was less than a screening

threshold established by MDEQ, then visibility modeling impacts, and energy and other impacts are

evaluated. MDEQ set the screening level to eliminate technologies from requiring the additional

43 

# U.S. EPA, January 2002, E PA Air Pollution Control Cost Manual, Sixth Edition

.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 89 impact analyses at an annualized cost of $12,000 per ton of controlled pollutant 44 

# . Therefore, all air

p ollution controls with annualized costs less than this screening threshold will be evaluated for

visibility improvement, energy and other impacts. However, as presented in table 5-31, all of the

available and applicable technologies for SO 2 

# control for the Line 1 Dryer have annualized contro l

costs greater than $12,000 per ton of controlled pollutant. Therefore, no additional impacts analysis

is required.

The BART guidance documents also present a calculation method for incremental control cost which

is intended to present the incremental value of each technology as compared to the next most

effective alternative. Since none of the technologies are cost effective, the incremental control cost

is not applicable and is not presented in this analysis.

Energy and Environmental Impacts

As presented in table 5-31, all of the available and applicable technologies for SO 2 

# control for the

L ine 1 Dryer have annualized control costs greater than $12,000 per ton of controlled pollutant.

Therefore, no energy and environmental impacts analysis was required.

5.C.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. Since none of the SO 2 

# technologies are cost effective for the process boi lers, the visibility

impacts were not evaluated.

44 

# Michigan Department of Environmental Quality May 12 , 2006 meeting.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 90 

# 5.C.ii Nitrogen Oxide Controls

To be able to control NO

x 

# it is important to understand how NO

x 

# is formed. There are three

m echanisms by which NO

x 

# production occurs: thermal, fuel and prompt NO

x 

# .

• F uel bound NO

x 

# is formed as nitrogen compounds in the fuel is oxid ized in the combustion

process.

• Thermal NO

x 

# 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 NO

x 

# production is a function of the residence time, fre e oxygen, and temperature.

• Prompt NO

x 

# is a form of thermal NO

x 

# which is generated at the flame boundary. It is th e

result of reactions between nitrogen and carbon radicals generated during combustion. Only

minor amounts of NO

x 

# are emitted as prompt NO

x 

# .

T he majority of NO

x 

# is emitted as NO. Minor amounts of NO 2 

# are formed in the dryer.

5 .C.ii.a STEP 1 – Identify All Available Retrofit Control Technologies

With the understanding of how NO

x 

# is formed, available and applicable control technol ogies were

evaluated. See Appendix F for the current status of the availability and applicability of retrofit

control technologies. Many emerging technologies have been identified that are not currently

commercially available. A preliminary list of technologies was submitted to MDEQ on October 6,

2006 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 F presents the current status of the general availability of each

technology.

5.C.ii.b STEP 2 – Eliminate Technically Infeasible Options

Step 1 identified the available and applicable technologies for NO

x 

# emission reduction. Within

S tep 1, the technical feasibility of the control option was also discussed and determined. The

following describes retrofit NO

x 

# control technologies that were identified as availa ble and applicable

in the original submittal and discusses aspects of those technologies that determine whether or not

the technology is technically feasible for the Line 1 Dryer.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 91 External Flue Gas Recirculation (EFGR)

External flue gas recirculation (EFGR) uses flue gas as an inert material to reduce flame temperatures

thereby reducing thermal NO

x 

# formation. In an external flue gas recirculation sy stem, 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 NO

x 

# emissions. For

t his technology to be effective, the combustion conditions must have the ability to be controlled at

the burner tip. Due to the current configuration of the burners, the Line 1 Dryer does 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-NO

x 

# burner (LNB) technology utilizes advanced burner de sign to reduce NO

x 

# formation through

t he 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 NO

x 

# formation. In the secondary zone, combustion produc ts formed in

the primary zone act to lower the local oxygen concentration, resulting in a decrease in NO

x



# f ormation. Low NO

x 

# burners typically achieve NO

x 

# emission reductions of 25% - 50% for process

b oilers.

Based on the information contained within this report, LNB is considered a technically feasible

technology for NO

x 

# reduction for this BART analysis.

O verfire Air (OFA)

Overfire air (OFA) 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 NO

x 

# control technology typically

u sed in boilers and is primarily geared to reduce thermal NO

x 

# . Staging of the combustion air creates

a n initial fuel-rich combustion zone for a cooler fuel-rich combustion zone. This reduces the

production of thermal NO

x 

# by lowering peak combustion temperature and limitin g the availability of

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 92 oxygen in the combustion zone where NO

x 

# is most likely to be formed. OFA is considered

c ompatible with the LNB. The estimated NO

x 

# control efficiency for LNB with OFA is 50-67%.

B ased on the information contained within this report, OFA with LNB is considered a technically

feasible technology for NO

x 

# reduction for this BART analysis.

I nduced Flue Gas Recirculation (IFGR)

Induced flue gas recirculation burners, also called ultra low-NO

x 

# burners, combine the benefits of

f lue gas recirculation and low-NO

x 

# 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 NO

x 

# control efficiency for IFGR

b urners in high temperature applications is 50-75%.

Based on the information contained within this report, IFGR is considered a technically feasible

technology for NO

x 

# reduction for this BART analysis.

E nergy Efficiency Projects

Energy efficiency projects provide opportunities for a company to reduce their fuel consumption.

Typically reduced fuel usage translates into reduced pollution emissions. An energy efficiency

project could be preheat incoming make-up air or pellet feed. Each project is very dependent upon

the fuel usage, process equipment, type of product and so many other variables.

Due to the increased price of fuel, Tilden has already implemented energy efficiency projects. Each

project carries its own fuel usage reductions and potential emission reductions. Due to the

uncertainty and generalization of this category, this will not be further evaluated in this report.

However, it should be noted that Tilden 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 also pushed

companies to evaluate alternate fuel sources. These fuel sources come in all forms – solid, liquid and

gas. To achieve reduction of NO

x 

# emissions through alternative fuel usage, the sourc e must be

currently burning a high NO

x 

# emitting fuel relative to other fuels. The Line 1 Dryer is only capable

of burning natural gas and distillate oil. Therefore the use of alternate fuels is not a viable option for

the Line 1 Dryer and will not be considered further in this analysis.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 93 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. 45



# T herefore, due to the limited Line 1 Dryer fuel capabilities and the fact that BART is not intended to

mandate a fuel switch, alternative fuels as an air pollution control technology will not be further

evaluated in this report.

However, similar to energy efficiency, Tilden will continue to evaluate and implement alternate fuel

usage as the feasibility arises.

Low Excess Air

Operating a burner with low excess air is a method to minimize peak flame temperature and excess

oxygen which therefore minimizes the production of NO

x 

# . Operating a burner with low excess air

a lso optimizes the fuel efficiency as less air is heated up in the combustion chamber.

As previously stated, the increased price of fuel has pushed companies to evaluate fuel usage.

Therefore, the Line 1 Dryer at Tilden is operated with low excess air within the constraints of the

combustion chamber. Therefore, low excess air will not be further evaluated in this report.

However, similar to energy efficiency and alternate fuels, the facility will continue to evaluate boiler

optimization including operating at low excess air.

Reburning

Reburning is a technology used with solid fuels. The Line 1 Dryer is not cable of burning solid fuel;

therefore this technology will not be further evaluated.

Post Combustion Controls

NO

x 

# can be controlled using add-on systems located down stream 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,

45 

# Federal Register 70, no. 128 (July 6, 2005): 39164

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 94 absorbing, or adsorbing NO

x 

# downstream of the combustion chamber. Examples of these alternatives

are nonselective catalytic reduction (NSCR) and Low Temperature Oxidation (LTO). Each of these

alternatives is described below.

Non-Selective Catalytic Reduction (NSCR)

A non-selective catalytic reduction (NSCR) system is a post combustion add-on exhaust gas

treatment system. NSCR catalyst is very sensitive to poisoning; therefore, NSCR is applied primarily

in natural gas combustion applications.

NSCR is often referred to as “three-way conversion” catalyst because it simultaneously reduces NO

x 

# ,

u nburdened hydrocarbons (UBH), and carbon monoxide (CO). Typically, NSCR can achieve NO

x



# e mission 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, NO

x 

# is reduced by CO,

r esulting in nitrogen (N 2 

# ) and carbon dioxide (CO 2 

# ). The most important reactions for NO

x 

# removal

a re:

2CO + 2NO → 2CO 2 

# + N 2 

# (1)

[ UBH] + NO → N 2 

# + CO 2 

# + H 2 

# O (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 (SCR) and Regenerative Selective Catalytic Reduction

(R-SCR)

SCR is a post-combustion NO

x 

# control technology in which ammonia (NH 3 

# ) is injected into the flue

g as stream in the presence of a catalyst. NO

x 

# is removed through the following chemical reaction:

4 NO + 4 NH 3 

# + O 2 

# → 4 N 2 

# + 6 H 2 

# O ( 1)

2 NO 2 

# + 4 NH 3 

# + O 2 

# → 3 N 2 

# + 6 H 2 

# O (2 )

A catalyst bed containing metals in the platinum family is used to lower the activation energy

required for NO

x 

# 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.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 95 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 (R-SCR) 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 R-SCR

and then transfers that heat to gas entering the R-SCR. The duct burner is used to complete the

preheating process. R-SCR 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 R-SCR are:

• Its high energy efficiency allows it to be used after SO 2 

# and particulate controls.

• R -SCR has a thermal efficiency of 90% - 95% vs. standard heat exchangers which have a

thermal efficiency of 60% to 70%.

• Application of R-SCR after SO 2 

# and PM controls significantly reduces the potential for

problems associated with plugging and catalyst poisoning and deactivation.

To date, R-SCR has been applied to wood-fired utility boilers. Application of this technology has

not been applied to liquid and natural gas fired taconite dryers. Using R-SCR would require research,

test runs, 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.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 96 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, R-SCR 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.

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, N 2 

# , 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 + NH 3 

# + 1⁄4O 2 

# → N 2 

# + 3/2 

# H 2 

# O (1)

N H 3 

# + 1⁄4O 2 

# → N O + 3/2H 2 

# O (2)

At temperature ranges of 1470 to 1830 ° F reaction (1) dominates. At temperatures above 2000 ° F,

reaction (2) will dominate.

Based on the information contained within this report, a SNCR is considered a technically feasible

technology for NO

x 

# reduction for this BART analysis.

L ow Temperature Oxidation (LTO)

The LTO system utilizes an oxidizing agent such as ozone to oxidize various pollutants including

NO

x 

# . In the system, the NO

x 

# in the flue gas is oxidized to form nitrogen pentox ide (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-NO

x 

# ® and LoTOx®.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 97 NO + O 3 

# → N O 2 

# + O 2 

# (1)

N O 2 

# + O 3 

# → N O 3 

# + O 2 

# (2)

N O 3 

# + NO 2 

# → N 2 

# O 5 

# (3)

N 2 

# O 5 

# + H 2 

# O → 2 HNO 3 

# (4)

H NO 3 

# + NaOH → N aNO 3 

# + H 2 

# O (5)

L ow Temperature Oxidation (Tri-NO

x ® 

# )

T his technology uses an oxidizing agent such as ozone or sodium chlorite to oxidize NO to NO 2 

# in a

p rimary scrubbing stage. Then NO 2 

# is removed through caustic scrubbing in a secondary stage. The

reactions are as follows:

O 3 

# + NO → O 2 

# + NO 2 

# ( 1)

2NaOH + 2NO 2 

# + 1⁄2 O 2 

# → 2NaNO 3 

# + H2O ( 2)

Tri-NO

x ® 

# is a multi-staged wet scrubbing process in industri al 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 NO 2 

# . Subsequent

s tages reduce NO 2 

# to nitrogen gas, while the oxygen becomes part of a soluble salt. Tri-NO

x ® 

# is

t ypically applied at small to medium sized sources with high NO

x 

# concentration in the exhaust gas

( 1,000 ppm NO

x 

# ).

L ow Temperature Oxidation (LoTOx ® 

# )

B OC Gases’ Lo-TOx ® 

# is an example of a version of an LTO system. LoTOx ® 

# technology uses ozone

t o oxidize NO to NO 2 

# and NO 2 

# to N 2 

# O 5 

# in a wet scrubber (absorber). This can be done in t he same

scrubber used for particulate or sulfur dioxide removal, The N 2 

# O 5 

# is converted to HNO 3 

# in a

s crubber, and is removed with lime or caustic. Ozone for LoTOx ® 

# is generated on site with an

e lectrically powered ozone generator. The ozone generation rate is controlled to match the amount

needed for NO

x 

# control. Ozone is generated from pure oxygen. In order for LoTOx ® 

# to be

e conomically feasible, a source of low cost oxygen must be available from a pipeline or on site

generation.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 98 In addition, only two of BOC’s LoTOx ® 

# installations are fully installed and operational a pplications.

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. In addition, LoTOx has not

been applied on a taconite dryer or similar process. 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 NO

x 

# control technologies that are

a vailable and applicable to the process boilers are identified in Table 5-32. The technical feasibility

as determined in Step 2 is also included in Table 5-32.

Table 5-32 Line 1 Dryer NO

x 

# Control Technology – Availability, Applicability an d Technical

Feasibility

NOx Pollution Control Technology Available? Applicable? Technically

Feasible?

External Flue Gas Recirculation (EFGR) Yes Yes No

Low-NOx Burners Yes Yes Yes

Overfired Air Yes Yes No

Induced Flue Gas Recirculation (IFGR) Yes Yes Yes

Energy Efficiency Projects Yes Yes Project

Dependent

Alternative Fuels Yes Yes Yes – Not

required by

BART

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.C.ii.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies

Table 5-33 describes the expected control efficiency from each of the remaining technically feasible

control options as identified in Step 2.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 99 Table 5-33 Line 1 Dryer NOx Control Technology Effectiveness

NOx Pollution Control Technology Approximate Control

Efficiency

Selective Catalytic Reduction (SCR) with

Reheat 80%

Low NOX Burner / Flue Gas Recirculation

(LNB/FGR) 75%

Regenerative Selective Catalytic Reduction

(R-SCR) 70%

Low NOX Burner / Overfire Air (LNB/OFA) 67%

Low NOX Burner (LNB) 50%

Selective Non-Catalytic Reduction (SNCR) 50%



# 5.C.ii.d STEP 4 – Evaluate Impacts and Document the Results

Table 5-34 details the expected costs associated with installation of NO

x 

# controls. Capital costs were

c alculated 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 six-tenths-factor rule to account for the economy of scale. Operating costs were based on

100% utilization and 7650 operating hours per year, which is extremely conservative. 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.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 100 Table 5-34 Line 1 Dryer NO

x 

# Control Cost Summary

Control

Technology Installed

Capital Cost

($) Total Annual

Cost

($/yr) Annualized

Pollution

Control Cost

($/ton) Incremental

Control Cost

($/ton)

SCR with Reheat $6,439,029 $1,008,211 $83,472 NA

LNB/FGR $1,087,058 $134,645 $11,891 $19,493

R-SCR $5,445,064 $1,024,459 $96,934 NA

LNB/OFA $888,317 $116,686 $11,535 $21,669

LNB $432,579 $61,070 $8,090 Lowest

SNCR $915,968 $278,929 $36,949 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 rulemaking process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost

effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not

afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the

electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater

business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for

proposing BART in lieu of developing industry and site specific data.

The annualized pollution control cost value was used to determine whether or not additional impacts

analyses would be conducted for the technology. If the control cost was less than a screening

threshold established by MDEQ, then visibility modeling impacts, and energy and other impacts are

evaluated. MDEQ set the screening level to eliminate technologies from requiring the additional

impact analyses at an annualized cost of $12,000 per ton of controlled pollutant 46 

# . Therefore, all air

p ollution controls with annualized costs less than this screening threshold will be evaluated for

visibility improvement, energy and other impacts.

The incremental control cost listed in Table 5-34 represents the incremental value of each technology

as compared to the technology with the next highest level of control. The cost of control and

46 

# Michigan Department of Environmental Quality May 12 , 2006 meeting.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 101 incremental cost of SCR with reheat, R-SCR and SNCR are not reasonable. The magnitude of the

capital and operating costs of remaining alternatives is also significant and may impact the viability

of continued operation.

Energy and Environmental Impacts

The energy and non-air quality impacts for LNB and LNB with IFGR are presented in Table 5-35.

Because the cost of the remaining NO

x 

# control technologies for the Line 1 Dryer is so hig h and does

not meet a reasonable definition of cost effective technology, these technologies are removed from

further consideration in this analysis.

Table 5-35 Line 1 Dryer NO

x 

# 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

LNB/FGR - Minimal energy impacts. - Increase in CO emissions

- Potential for steam tube wastage due to

longer combustion flame.

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

As previously stated in section 4 of this document, states are required to consider the degree of

visibility improvement resulting from the retrofit technology, in combination with other factors such

as economic, energy and other non-air quality impacts, when determining BART for an individual

source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this

document. This section of the report evaluates the visibility impacts of BART NO X 

# control and the

r esulting 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 NO X 

# modeling analysis,

t he emissions from the sources undergoing a full BART NO

x 

# analysis were adjusted to reflect the

p rojected 24-hour maximum NO

x 

# emission rate when applying the control technologie s that met the

threshold requirements of steps 1 – 4. The emissions from all other Subject-to-BART sources were

not changed. Table 5-36 provides a summary of the modeled 24-hour maximum emission rates and

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 102 their computational basis for the evaluated NO

x 

# control technologies. Table 5-37 provides a

s ummary of the modeling input data.

Post-BART Visibility Impacts Modeling Results

Results of the post-BART visibility impacts modeling for NO X 

# for the process boilers are presented

i n Table 5-38. 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 5-39.

Visibility impacts with SO 2 

# controls are presented in section 6.Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc103Table 5-36 Line 1 Dryer Post-BART Modeling ScenariosScenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrBaseSVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1Base SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7Base SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.31SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.33SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.34SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.35SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.36SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilLNB0.0% 8.3 50.0% 1.8Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc104Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrNatural GasSVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.37SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.38SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.89SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.810SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.811SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.8Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc105Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hr12SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.813SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.814SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.815SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.816SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.417SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1 EUBOILER1 Low Sulfur FuelLNB w/OFA0.0% 0.1 67.0% 6.4Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc106Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrEUBOILER2OilNatural Gas18SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.419SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.420SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.421SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.422SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.423SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilLNB0.0% 8.3 50.0% 1.8Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc107Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrNatural GasSVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.424SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.725SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.726SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.727SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.728SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.729SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat0.0%200.272.880%80%160.258.2Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc108Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrSVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.730SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.731SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.7Table 5-37 Line 1 Dryer Post-BART NOxModeling Scenarios - Modeling Input DataControl ScenarioSV #Emission UnitStack Easting(utm)Stack Northing(utm)Height ofOpening fromGround(ft)Base Elevationof Ground(ft)Stack length,width, orDiameter(ft)Flow Rate at exit(acfm)Exit Temp(oF)All ScenariosSVP0051981SVP0051711EUKILN146.4408499446.44075383-87.65340738-87.65132336240160147419.313.5842,000306,000300300SVP0082951 EUDRYER1 46.44075383-87.6513233611914746.357,135 150SVBLR.STK.T1EUBOILER1EUBOILER246.44091784-87.6541241813014747.5 192,000 350

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 109 Table 5-38 Line 1 Dryer Post-BART NO

x 

# Modeling Scenarios - Visibility Modeling Results

Modeling Results

2002 2003 2004

2002-2004

Scenario Limiting

Class I

Area Modeled

98%ile

∆ dV # days

over

0.5 ∆ dV Modeled

98%ile

∆ dV # days

over

0.5 ∆ dV Modeled

98%ile

∆ dV # days

over

0.5 ∆ dV Modeled

98%ile

∆ dV # days

over

0.5 ∆ dV



# Base IRNP 0.714 19.0 0.722 11.000 0.599 11.000 0.674 41

1 IRNP 

# 0.323 2.0 0.275 1.000 0.228 1.000 0.248 2



# 2 IRNP 0.610 15.0 0.620 10.000 0.535 8.000 0.600 33

3 IRNP 0.183 0.0 0.177 0.000 0.154 0.000 0.173 0

4 IRNP 

# 0.717 19.0 0.717 11.000 0.589 12.000 0.668 42

5 IRNP 

# 0.322 2.0 0.256 0.000 0.219 1.000 0.254 2



# 6 IRNP 0.619 15.0 0.623 10.000 0.528 8.000 0.598 33

7 IRNP 0.182 0.0 0.177 0.000 0.155 0.000 0.169 0

8 IRNP 

# 0.714 19.0 0.711 11.000 0.583 11.000 0.653 41



# 9 IRNP 

# 0.314 2.0 0.252 0.000 0.213 1.000 0.248 2



# 10 IRNP 0.618 15.0 0.607 10.000 0.527 8.000 0.590 33

11 IRNP 0.176 0.0 0.168 0.000 0.150 0.000 0.161 0

12 IRNP 

# 0.719 19.0 0.693 10.000 0.592 9.000 0.654 38



# 13 IRNP 

# 0.315 2.0 0.246 0.000 0.218 1.000 0.243 2



# 14 IRNP 0.627 15.0 0.608 9.000 0.544 8.000 0.585 32

15 IRNP 0.176 0.0 0.171 0.000 0.150 0.000 0.160 0

16 IRNP 

# 0.722 19.0 0.673 10.000 0.605 9.000 0.656 38



# 17 IRNP 

# 0.326 2.0 0.243 0.000 0.218 1.000 0.243 2



# 18 IRNP 0.626 15.0 0.605 9.000 0.542 8.000 0.596 32

19 IRNP 0.175 0.0 0.173 0.000 0.151 0.000 0.163 0

20 IRNP 

# 0.734 19.0 0.692 10.000 0.605 10.000 0.654 39



# 21 IRNP 

# 0.324 2.0 0.241 0.000 0.215 1.000 0.241 2



# 22 IRNP 0.625 15.0 0.602 9.000 0.291 3.000 0.588 27

23 IRNP 0.175 0.0 0.170 0.000 0.150 0.000 0.165 0

24 IRNP 

# 0.727 19.0 0.689 10.000 0.603 10.000 0.656 39



# 25 IRNP 

# 0.326 2.0 0.245 0.000 0.207 1.000 0.241 2



# 26 IRNP 0.623 15.0 0.605 9.000 0.550 8.000 0.597 32

27 IRNP 0.176 0.0 0.172 0.000 0.151 0.000 0.165 0

28 IRNP 

# 0.704 19.0 0.672 10.000 0.606 9.000 0.657 38



# 29 IRNP 

# 0.325 2.0 0.239 0.000 0.198 1.000 0.240 2



# 30 IRNP 0.613 14.0 0.614 9.000 0.542 8.000 0.588 31

31 IRNP 0.173 0.0 0.172 0.000 0.151 0.000 0.164 0

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 110 Table 5-39 Line 1 Dryer Post-BART NO

x 

# Modeling Scenarios – Comparison of Visibility

M odeling Results to Baseline Modeling Results

Modeling Results

2002 2003 2004 2002-2004

Scenario Limiting

Class I

Area Improved

Modeled

98 th



# Percentile

Value

( ∆ -dV) Decreased

No. of

Days

exceeding

0.5 dV Improved

Modeled

98 th



# Percentile

Value

( ∆ -dV) Decreased

No. of

Days

exceeding

0.5 dV Improved

Modeled

98 th



# Percentile

Value

( ∆ -dV) Decreased

No. of

Days

exceeding

0.5 dV Improved

Modeled

98 th



# Percentile

Value

( ∆ -dV) Decreased

No. of

Days

exceeding

0.5 dV



# 1 IRNP 0.391 17 0.447 10 0.371 10 0.426 39

2 IRNP 0.104 4 0.102 1 0.064 3 0.074 8

3 IRNP 0.531 19 0.545 11 0.445 11 0.501 41

4 IRNP -0.003 0 0.005 0 0.01 -1 0.006 -1

5 IRNP 0.392 17 0.466 11 0.38 10 0.42 39

6 IRNP 0.095 4 0.099 1 0.071 3 0.076 8

7 IRNP 0.532 19 0.545 11 0.444 11 0.505 41

8 IRNP 0 0 0.011 0 0.016 0 0.021 0

9 IRNP 0.4 17 0.47 11 0.386 10 0.426 39

10 IRNP 0.096 4 0.115 1 0.072 3 0.084 8

11 IRNP 0.538 19 0.554 11 0.449 11 0.513 41

12 IRNP -0.005 0 0.029 1 0.007 2 0.02 3

13 IRNP 0.399 17 0.476 11 0.381 10 0.431 39

14 IRNP 0.087 4 0.114 2 0.055 3 0.089 9

15 IRNP 0.538 19 0.551 11 0.449 11 0.514 41

16 IRNP -0.008 0 0.049 1 -0.006 2 0.018 3

17 IRNP 0.388 17 0.479 11 0.381 10 0.431 39

18 IRNP 0.088 4 0.117 2 0.057 3 0.078 9

19 IRNP 0.539 19 0.549 11 0.448 11 0.511 41

20 IRNP -0.02 0 0.03 1 -0.006 1 0.02 2

21 IRNP 0.39 17 0.481 11 0.384 10 0.433 39

22 IRNP 0.089 4 0.12 2 0.308 8 0.086 14

23 IRNP 0.539 19 0.552 11 0.449 11 0.509 41

24 IRNP -0.013 0 0.033 1 -0.004 1 0.018 2

25 IRNP 0.388 17 0.477 11 0.392 10 0.433 39

26 IRNP 0.091 4 0.117 2 0.049 3 0.077 9

27 IRNP 0.538 19 0.55 11 0.448 11 0.509 41

28 IRNP 0.01 0 0.05 1 -0.007 2 0.017 3

29 IRNP 0.389 17 0.483 11 0.401 10 0.434 39

30 IRNP 0.101 5 0.108 2 0.057 3 0.086 10

31 IRNP 0.541 19 0.55 11 0.448 11 0.51 41

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 111 

# 6. Visibility Impacts

As previously stated in section 4 of this document, states are required to consider the degree of

visibility improvement resulting from the retrofit technology, in combination with other factors such

as economic, energy and other non-air quality, when determining BART for an individual source.

The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this document.

The visibility impacts of individual control technologies were presented in Step 5 of section 5 of this

document. This section of the report evaluates the various BART control scenarios utilizing both

SO 2 

# and NO

x 

# controls, and estimates the resulting degree of vis ibility improvement.



# 6.A Post-Control Modeling Scenarios

Steps 1-4 of the BART analysis identified the contro l 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.

The interactions between the visibility impairing pollutants NO

x 

# , SO 2 

# and PM 10 

# can play a large part

i n 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 NO

x 

# controls. In addition,

t wo site-specific scenarios were developed so that the evaluation includes other operating scenarios

and conditions that would improve visibility impairment. The post-control modeling scenarios,

including those presented in Step 5 of section 5, are presented in Table 6-1. The modeling scenario

stack parameters are presented in Table 6-2.



# 6.B Post-Control Modeling Results

Results of the post-control modeling scenarios are p resented in Table 6-3. 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-control modeling

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 112 scenarios to the baseline conditions is presented in Table 6-4. Notably, none of the post-control

scenarios produces a visibility improvement that exceeds the perceptible threshold of 1-2 dV.

Additionally, Table 6-5 illustrates the scenarios on a $/dV basis. The dollar per deciview ranges

from $6.1 million to more than $79 million per dV of improvement.Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc113Table 6-1 Post-Control Modeling ScenariosScenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrBaseSVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1Base SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7Base SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.31SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.32SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.33SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.34SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.35SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilLNB0.0% 8.3 50.0% 1.8Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc114Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrNatural GasSVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.36SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.37SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 0.1 0.0% 19.38SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.89SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.810SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.811SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc115Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrSVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.812SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.813SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.814SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.815SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/FGR0.0% 0.1 75.0% 4.816SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.4Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc116Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hr17SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.418SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.419SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.420SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.421SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.422SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1 EUBOILER1 Low Sulfur FuelLNB w/OFA0.0% 0.1 67.0% 6.4Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc117Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrEUBOILER2OilNatural Gas23SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB w/OFA0.0% 0.1 67.0% 6.424SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.725SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.726SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.727SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasGood Combustion Practice 0.0% 8.3 0.0% 3.7SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.728SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasGood Combustion Practice 0.0%200.272.80.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilLNB0.0% 8.3 50.0% 1.8Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc118Scenario Control TechnologySO2NOxControl ScenarioSV #Emission UnitSO2NOx% ReductionMax24-hourlbs/hr% ReductionMax24-hour lbs/hrNatural GasSVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.729SVP0051981SVP0051711EUKILN1Low Sulfur CoalNatural GasSCR w/reheat0.0%200.272.880%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.730SVP0051981SVP0051711EUKILN1 Wet Scrubber Good Combustion Practice80%80%40.014.60.0%800.9291.1SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.731SVP0051981SVP0051711EUKILN1 Wet ScrubberSCR w/reheat80%80%40.014.680%80%160.258.2SVP0082951 EUDRYER1Low Sulfur FuelOilNatural GasLNB0.0% 8.3 50.0% 1.8SVBLR.STK.T1EUBOILER1EUBOILER2Low Sulfur FuelOilNatural GasLNB0.0% 0.1 50.0% 9.7Table 6-2 Post-Control NOXModeling Scenarios - Modeling Input DataControl ScenarioSV #Emission UnitStack Easting(utm)Stack Northing(utm)Height ofOpening fromGround(ft)Base Elevationof Ground(ft)Stack length,width, orDiameter(ft)Flow Rate at exit(acfm)Exit Temp(oF)All ScenariosSVP0051981SVP0051711EUKILN146.4408499446.44075383-87.65340738-87.65132336240160147419.313.5842,000306,000300300SVP0082951 EUDRYER1 46.44075383-87.6513233611914746.357,135 150SVBLR.STK.T1EUBOILER1EUBOILER246.44091784-87.6541241813014747.5 192,000 350

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 119 Table 6-3 Post-Control Modeling Scenarios - Visibility Modeling Results

Modeling Results

2002 2003 2004

2002-2004

Scenario Limiting

Class I

Area Modeled

98%ile

∆ dV # days

over

0.5 ∆ dV Modeled

98%ile

∆ dV # days

over

0.5 ∆ dV Modeled

98%ile

∆ dV # days

over

0.5 ∆ dV Modeled

98%ile

∆ dV # days

over

0.5 ∆ dV



# Base IRNP 0.714 19.0 0.722 11.000 0.599 11.000 0.674 41

1 IRNP 0.323 2.0 0.275 1.000 0.228 1.000 0.248 2

2 IRNP 0.610 15.0 0.620 10.000 0.535 8.000 0.600 33

3 IRNP 0.183 0.0 0.177 0.000 0.154 0.000 0.173 0

4 IRNP 0.717 19.0 0.717 11.000 0.589 12.000 0.668 42

5 IRNP 0.322 2.0 0.256 0.000 0.219 1.000 0.254 2

6 IRNP 0.619 15.0 0.623 10.000 0.528 8.000 0.598 33

7 IRNP 0.182 0.0 0.177 0.000 0.155 0.000 0.169 0

8 IRNP 0.714 19.0 0.711 11.000 0.583 11.000 0.653 41

9 IRNP 0.314 2.0 0.252 0.000 0.213 1.000 0.248 2

10 IRNP 0.618 15.0 0.607 10.000 0.527 8.000 0.590 33

11 IRNP 0.176 0.0 0.168 0.000 0.150 0.000 0.161 0

12 IRNP 0.719 19.0 0.693 10.000 0.592 9.000 0.654 38

13 IRNP 0.315 2.0 0.246 0.000 0.218 1.000 0.243 2

14 IRNP 0.627 15.0 0.608 9.000 0.544 8.000 0.585 32

15 IRNP 0.176 0.0 0.171 0.000 0.150 0.000 0.160 0

16 IRNP 0.722 19.0 0.673 10.000 0.605 9.000 0.656 38

17 IRNP 0.326 2.0 0.243 0.000 0.218 1.000 0.243 2

18 IRNP 0.626 15.0 0.605 9.000 0.542 8.000 0.596 32

19 IRNP 0.175 0.0 0.173 0.000 0.151 0.000 0.163 0

20 IRNP 0.734 19.0 0.692 10.000 0.605 10.000 0.654 39

21 IRNP 0.324 2.0 0.241 0.000 0.215 1.000 0.241 2

22 IRNP 0.625 15.0 0.602 9.000 0.291 3.000 0.588 27

23 IRNP 0.175 0.0 0.170 0.000 0.150 0.000 0.165 0

24 IRNP 0.727 19.0 0.689 10.000 0.603 10.000 0.656 39

25 IRNP 0.326 2.0 0.245 0.000 0.207 1.000 0.241 2

26 IRNP 0.623 15.0 0.605 9.000 0.550 8.000 0.597 32

27 IRNP 0.176 0.0 0.172 0.000 0.151 0.000 0.165 0

28 IRNP 0.704 19.0 0.672 10.000 0.606 9.000 0.657 38

29 IRNP 0.325 2.0 0.239 0.000 0.198 1.000 0.240 2

30 IRNP 0.613 14.0 0.614 9.000 0.542 8.000 0.588 31

31 IRNP 0.173 0.0 0.172 0.000 0.151 0.000 0.164 0

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 120 Table 6-4 Post-Control Modeling Scenarios – Improved Visibility Modeling Results

Modeling Results

2002 2003 2004 2002-2004

Scenario Limiting

Class I

Area Improved

Modeled

98 th



# Percentile

Value

( ∆ -dV) Decreased

No. of

Days

exceeding

0.5 dV Improved

Modeled

98 th



# Percentile

Value

( ∆ -dV) Decreased

No. of

Days

exceeding

0.5 dV Improved

Modeled

98 th



# Percentile

Value

( ∆ -dV) Decreased

No. of

Days

exceeding

0.5 dV Improved

Modeled

98 th



# Percentile

Value

( ∆ -dV) Decreased

No. of

Days

exceeding

0.5 dV



# 1 IRNP 0.391 17 0.447 10 0.371 10 0.426 39

2 IRNP 0.104 4 0.102 1 0.064 3 0.074 8

3 IRNP 0.531 19 0.545 11 0.445 11 0.501 41

4 IRNP -0.003 0 0.005 0 0.01 -1 0.006 -1

5 IRNP 0.392 17 0.466 11 0.38 10 0.42 39

6 IRNP 0.095 4 0.099 1 0.071 3 0.076 8

7 IRNP 0.532 19 0.545 11 0.444 11 0.505 41

8 IRNP 0 0 0.011 0 0.016 0 0.021 0

9 IRNP 0.4 17 0.47 11 0.386 10 0.426 39

10 IRNP 0.096 4 0.115 1 0.072 3 0.084 8

11 IRNP 0.538 19 0.554 11 0.449 11 0.513 41

12 IRNP -0.005 0 0.029 1 0.007 2 0.02 3

13 IRNP 0.399 17 0.476 11 0.381 10 0.431 39

14 IRNP 0.087 4 0.114 2 0.055 3 0.089 9

15 IRNP 0.538 19 0.551 11 0.449 11 0.514 41

16 IRNP -0.008 0 0.049 1 -0.006 2 0.018 3

17 IRNP 0.388 17 0.479 11 0.381 10 0.431 39

18 IRNP 0.088 4 0.117 2 0.057 3 0.078 9

19 IRNP 0.539 19 0.549 11 0.448 11 0.511 41

20 IRNP -0.02 0 0.03 1 -0.006 1 0.02 2

21 IRNP 0.39 17 0.481 11 0.384 10 0.433 39

22 IRNP 0.089 4 0.12 2 0.308 8 0.086 14

23 IRNP 0.539 19 0.552 11 0.449 11 0.509 41

24 IRNP -0.013 0 0.033 1 -0.004 1 0.018 2

25 IRNP 0.388 17 0.477 11 0.392 10 0.433 39

26 IRNP 0.091 4 0.117 2 0.049 3 0.077 9

27 IRNP 0.538 19 0.55 11 0.448 11 0.509 41

28 IRNP 0.01 0 0.05 1 -0.007 2 0.017 3

29 IRNP 0.389 17 0.483 11 0.401 10 0.434 39

30 IRNP 0.101 5 0.108 2 0.057 3 0.086 10

31 IRNP 0.541 19 0.55 11 0.448 11 0.51 41Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc121Table 6-5 Post-Control Modeling Results – Dollars per Deciview ImprovementScenario Control TechnologyControl ScenarioSV #Emission UnitSO2NOxAnnualized Cost($/yr)ImprovedModeled 98thPercentileValue (∆-dV)$/dVBaseSVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasGood CombustionPracticeBase SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeBase SVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasGood CombustionPractice1SVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasSCR w/reheat$31,055,5810.447$69,475,573SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasGood CombustionPractice2SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice$6,048,5400.104$58,159,038SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasGood CombustionPractice3SVP0051981SVP0051711EUKILN1 Wet Scrubber SCR w/reheat$37,104,1220.545$68,080,958SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasGood CombustionPractice4SVP0051981SVP0051711EUKILN1Low SulfurCoalGood CombustionPractice$61,0700.01$6,107,000Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc122Scenario Control TechnologyControl ScenarioSV #Emission UnitSO2NOxAnnualized Cost($/yr)ImprovedModeled 98thPercentileValue (∆-dV)$/dVNatural GasSVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasGood CombustionPractice5SVP0051981SVP0051711EUKILN1 Wet Scrubber SCR w/reheat$37,165,1920.466$79,753,630SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasGood CombustionPractice6SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice$6,048,5400.099$61,493,020SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasGood CombustionPractice7SVP0051981SVP0051711EUKILN1 Wet Scrubber SCR w/reheat$37,104,1210.545$68,153,011SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasGood CombustionPractice8SVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasGood CombustionPractice$303,7580.016$18,984,875SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/FGR9SVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasSCR w/reheat$31,055,5810.47$66,652,096SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeY:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc123Scenario Control TechnologyControl ScenarioSV #Emission UnitSO2NOxAnnualized Cost($/yr)ImprovedModeled 98thPercentileValue (∆-dV)$/dVSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/FGR10SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice$6,352,2980.115$55,237,373SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/FGR11SVP0051981SVP0051711EUKILN1 Wet Scrubber SCR w/reheat$37,407,8800.554$67,523,250SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/FGR12SVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasGood CombustionPractice$364,8280.029$12,580,275SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/FGR13SVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasSCR w/reheat$31,420,4090.476$66,009,262SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/FGR14SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice$6,413,3680.114$56,257,614SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/FGR15 SVP0051981 EUKILN1 Wet Scrubber SCR w/reheat$37,165,1920.551$67,450,439Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc124Scenario Control TechnologyControl ScenarioSV #Emission UnitSO2NOxAnnualized Cost($/yr)ImprovedModeled 98thPercentileValue (∆-dV)$/dVSVP0051711SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/FGR16SVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasGood CombustionPractice$390,7510.049$7,974,510SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/OFA17SVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasSCR w/reheat$31,446,3330.479$65,649,965SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/OFA18SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice$6,439,2910.117$55,036,675SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/OFA19SVP0051981SVP0051711EUKILN1 Wet Scrubber SCR w/reheat$37,494,8730.549$68,296,672SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/OFA20SVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasGood CombustionPractice$451,8210.03$15,060,700SVP0082951 EUDRYER1Low SulfurFuel OilLNBY:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc125Scenario Control TechnologyControl ScenarioSV #Emission UnitSO2NOxAnnualized Cost($/yr)ImprovedModeled 98thPercentileValue (∆-dV)$/dVNatural GasSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/OFA21SVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasSCR w/reheat$31,507,4030.481$65,503,956SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/OFA22SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice$6,500,3620.12$54,169,683SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/OFA23SVP0051981SVP0051711EUKILN1 Wet Scrubber SCR w/reheat$37,555,9420.552$68,036,127SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB w/OFA24SVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasGood CombustionPractice$286,9680.033$8,696,000SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB25SVP0051981SVP0051711EUKILN1 Wet Scrubber SCR w/reheat$37,391,0890.477$78,388,027SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNBY:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc126Scenario Control TechnologyControl ScenarioSV #Emission UnitSO2NOxAnnualized Cost($/yr)ImprovedModeled 98thPercentileValue (∆-dV)$/dV26SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice$6,335,5080.117$54,149,641SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB27SVP0051981SVP0051711EUKILN1 Wet Scrubber SCR w/reheat$37,391,0890.55$67,983,798SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasGood CombustionPracticeSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB28SVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasGood CombustionPractice$348,0380.05$6,960,760SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB29SVP0051981SVP0051711EUKILN1Low SulfurCoalNatural GasSCR w/reheat$31,403,6190.483$65,017,845SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB30SVP0051981SVP0051711EUKILN1 Wet ScrubberGood CombustionPractice$6,396,5780.108$59,227,574SVP0082951 EUDRYER1Low SulfurFuel OilNatural GasLNBSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB31SVP0051981SVP0051711EUKILN1 Wet Scrubber SCR w/reheat$37,452,1590.55$68,094,834SVP0082951 EUDRYER1Low SulfurFuel OilLNBY:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc127Scenario Control TechnologyControl ScenarioSV #Emission UnitSO2NOxAnnualized Cost($/yr)ImprovedModeled 98thPercentileValue (∆-dV)$/dVNatural GasSVBLR.STK.T1EUBOILER1EUBOILER2Low SulfurFuel OilNatural GasLNB

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 128 

# 7. Select BART

DRAFT LANGUAGE

BART for Tilden is determined to be as described below.

Line 1 Indurating Furnace

For SO 2 

# , add-on controls are not cost effective. Therefore , BART is determined to be existing

controls. The corresponding SO 2 

# emissions limit is 28,000 lb per day for Line 1 whe n coal is burned.

For NO

x 

# , the reduction due to good combustion practices on Line 1 is selected as BART. Other addon controls for NO

x 

# are not cost effective. The corresponding NOx limit is specified in Appendix 2

Schedule of Compliance in the Renewable Operating Permit 199600379 and with Rule 336.1801.

For PM, requirements compelled by the October 30, 2006 MACT standard constitute BART. The

corresponding emissions limits are equivalent to the limits identified in Table 3-1.

Process Boilers 1 and 2

For SO 2 

# , add-on controls are not cost effective. Therefore , BART is determined to be existing

controls. The corresponding SO 2 

# emissions limit is regulated by limiting the sulfur content to 1.2%

by weight, calculated on the basis on 18,000 BTU per pound when used oil is burned.

For NO

x 

# , the reduction due to good combustion practices is selected as BART. Other add-on controls

for NO

x 

# are not cost effective.

F or PM, requirements compelled by the September 13, 2007 MACT standard constitute BART. The

corresponding emissions limits are equivalent to the limits identified in Table 3-1.

Line 1 Dryer

For SO 2 

# , add-on controls are not cost effective. Therefore , BART is determined to be existing

controls. The corresponding SO 2 

# emissions limit is regulated by limiting the sulfur content to 1.5%

by weight, calculated on the basis on 18,000 BTU per pound when used oil is burned.

For NO

x 

# , the reduction due to good combustion practices is selected as BART. Other add-on controls

for NO

x 

# are not cost effective.

# Y:\22\52\080 Tilden BART\BART report\Tilden BART Rep ort (2006-12-28).doc 

# 129 For PM, requirements compelled by the October 30, 2006 MACT standard constitute BART. The

corresponding emissions limits are equivalent to the limits identified in Table 3-1.

The schedule for implementation of controls is by October 30, 2006, well in advance of the 5-year

time-frame required for BART implementation.Michigan Operations - West (Tilden)12/28/2006BART Report - Attachment A: Emission Control Cost AnalysisTable A.1: Grate Kiln Cost SummaryNOxControl Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled Capital Cost$Annualized Cost$/yrPollution ControlCost $/tonIncrementalControl Cost$/tonSelective CatalyticReduction with Reheat80% 9233690$65,492,092$31,055,581$8,416n/aSO2Control Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled Capital Cost$Annualized Cost$/yrPollution ControlCost $/tonIncrementalControl Cost$/tonSpray Dry Baghouse 90% 115.3 1037.8 $167,260,397 $23,254,882$22,407n/aWet Scrubber (Absorber)(after existing ESP)80% 230.6922.5$34,869,327$6,048,540$6,557n/aSecondary Wet WalledElectrostatic Precipitator(WWESP)(after existing ESP)80% 230.6922.5$52,638,755$13,922,184$15,091n/aDSI Baghouse55% 518.9634.2$42,082,032$9,975,786$15,729n/aY:\22\52\080 Tilden BART\BART report\Appendix\Appendix A Tilden Furnace Control Costs.xlsCost SummaryPage 1 of 112/28/2006Michigan Operations - West (Tilden)12/27/2006BART Report - Attachment A: Emission Control Cost AnalysisTable A.1: Process Boilers 1 and 2 and Line 1 Dryer Cost SummaryNOxControl Cost SummaryControl TechnologyControl Eff%ControlledEmissionsT/yEmissionReductionT/yrInstalledCapital Cost $AnnualizedCost$/yrPollutionControlCost $/tonIncrementalCostSelective Catalytic Reduction (SCR) with ReheatProcess Boilers #1 and #280%15.8563.38$6,317,686$2,528,225$39,888n/aLine 1 Dryer80% 3.02 12.08 $6,439,029 $1,008,211 $83,472n/aLow NOXBurner / Flue Gas RecirculationProcess Boilers #1 and #275%19.8159.42$2,190,300$303,758$5,112n/aLine 1 Dryer75% 3.77 11.32 $1,087,058 $134,645 $11,891$19,493Regenerative Selective Catalytic Reduction (R-SCR)Process Boilers #1 and #270%23.7755.46$16,117,290$3,303,391$59,563n/aLine 1 Dryer70% 4.53 10.57 $5,445,064 $1,024,459 $96,934n/aLow NOXBurner / Overfire Air (OFA)Process Boilers #1 and #267%26.1553.08$3,031,714$390,751$7,361naLine 1 Dryer67% 4.98 10.12 $888,317 $116,686 $11,535$21,669Low NOXBurnerProcess Boilers #1 and #250%39.6139.61$1,320,909$286,968$7,244n/aLine 1 Dryer50% 7.55 7.55 $432,579 $61,070 $8,090n/aSelective Non-Catalytic Reduction (SNCR)Process Boilers #1 and #250%39.6139.61$1,501,420$468,772$11,833n/aLine 1 Dryer50% 7.55 7.55 $915,968 $278,929 $36,949n/aSO2Control Cost SummaryControl TechnologyControl Eff%ControlledEmissionsT/yEmissionReductionT/yrInstalledCapital Cost $AnnualizedCost$/yrPollutionControlCost $/tonIncrementalCostSpray Dry BaghouseProcess Boilers #1 and #290%0.030.23$56,323,180$8,640,697$38,403,097n/aLine 1 Dryer90% 0.03 0.23 $26,617,360 $4,025,029 $17,889,019n/aWet ScrubberProcess Boilers #1 and #280%0.050.20$9,309,297$1,489,576$7,447,882n/aLine 1 Dryer80% 6.81 27.26 $3,898,490 $684,207 $25,103n/aWet ESP (WWESP)Process Boilers #1 and #280%0.050.20$17,123,526$3,146,592$15,732,959n/aLine 1 Dryer80% 6.81 27.26 $7,674,618 $1,429,065 $52,432n/aDSI BaghouseProcess Boilers #1 and #255%0.110.14$32,010,048$4,892,432$35,581,325n/aLine 1 Dryer55% 0.04 0.14 $26,023,184 $4,079,117 $29,666,302n/aY:\22\52\080 Tilden BART\BART report\Appendix\Appendix A Tilden Process Boilers Control Costs.xlsCost Summary1 of 112/28/2006Michigan Operations - West (Tilden)BART Report - Changes to MDEQ BART Modeling ProtocolAppendix BCALMETVariableDescriptionValueDefaultCommentsNX Number of X grid cells66 n/aNY Number of Y grid cells39 n/aXORIGKM Reference point coordinates for grid180 n/aYORIGKM Reference point coordinates for grid612 n/aNOOBS No Observation Mode0 Y Include Surface, Upper Air and Precipitation ObservationsNSSTA Number of Surface Stations88 n/a 88 surface weather stationsNPSTA Number of Precipitation Stations99 n/a 99 precipitation stationsInput Group 5BIAS Surface/upper-air weighting factors-1, 11*0 12*0 Surface Layer is set to -1 since IEXTRP=-1ITPROG 3D temperature from observations or from prognostic data?0 Y Inclusion of Surface and Upper AirCALPUFFVariableDescriptionValueDefaultCommentsNX Number of X grid cells in met grid66 n/aNY Number of Y grid cells in met grid39 n/aXORIGKM Reference point coordinates for met grid180 n/aYORIGKM Reference point coordinates for met grid612 n/aIBCOMP X index of LL corner1 n/aJBCOMP Y index of LL corner1 n/aIECOMP X index of UR corner66 n/aJECOMPY index of UR corner39n/aInput Group 2Input Group 4Input Group 6Input Group 4Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix B Changes to MDEQ BART Modeling Protocol (WEST).xlsSheet11 of 112/28/2006Cleveland Cliffs Michigan Operations - Taconite BART AnalysisSO2 ControlIndurating FurnacesAvailable and Applicable ReviewRevised: December 1, 2006Step 1Step 2This table is part of the CCMO Taconite BART Report and shouldnot be distributed without the full text of the report so that theinformation is not taken out of context.

Reference No.

1SO2Pollution ControlTechnology2 Is this a generally available control technology? Is the control technology available to indurating furnaces? Is the control technology applicable to this specific source? Is it technically feasible for this source?ApproximateControlEfficiencyCommentsBasic Principle1Wet Scrubbing (HighEfficiency)YYYY 90-95%Absorption and reaction using an alkaline reagent to produce a solid compound2Wet Scrubbing (LowEfficiency)YYYY<50%Absorption and reaction using an alkaline reagent to produce a solid compound3Wet Walled ElectrostaticPrecipitator (WWESP)YYYY80%Suspended particles are separated from the flue gas stream, attracted to plates, andcollected in hoppers4 Dry sorbent injectionY Y Y Y<55%Pulverized lime or limestone is directly injected into the duct upstream of thefabric filter. Dry sorption of SO2onto the lime or limestone particle occurs and thesolid particles are collected with a fabric filter5 Spray Dryer Absorption (SDA)Y Y Y Y<90%Lime slurry is sprayed into an absorption tower where SO2is absorbed by theslurry, forming CaSO3/CaSO46 Alternative FuelsYYY(for furnacescapable ofmultiple fuels)Y(not requiredby BART)Site-specificNatural gas is base caseUse a fuel with lower sulfur content.7 Load ReductionN------------Power plant technologyThis is a strategy to reduce load on a power plant by reducing the electricaldemand throught efficiency projects.8 Energy Efficiency ProjectsYYY(for largeprojects likeheat-recoup)Y(for largeprojects likeheat-recoup)Site-specificdecrease amount of fuel required to make an acceptable product9 Coal ProcessingYN---------Applies only to facilities that burn coalDry coal will increase the as-burned BTU value, and therefore less fuel is requiredto be burned. Specific energy efficiency project10 Bio FiltersN ------------Research levelGas stream passes through a packed bed of specially engineered biomedia whichsupports the growth of active bacterial species. The pollutants in the gas streamare biodegraded or biotransformed into innocuous products, such as carbondioxide, water, chlor11CANSOLV Regenerable SO2N------------Research levelAn aqueous solution of proprietary diamine captures SO2from the feed gas in acountercurrent absorption tower. The rich solvent is regenerated by steamstripping, giving a byproduct of pure, water saturated SO2gas and lean solvent forrecycling to the a12 Pahlman ProcessN------------Research levelGas stream is passed through a filter baghouse in which specially-developed, smallparticle, high-surface area metal oxide sorbent have been deployed. Pollutants areremoved from the gases by adsorption.Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix D - Michigan Operations Control Technologies - Furnaces.xls1 of 212/28/2006Cleveland Cliffs Michigan Operations - Taconite BART AnalysisSO2 ControlIndurating FurnacesAvailable and Applicable ReviewRevised: December 1, 2006Step 1Step 2This table is part of the CCMO Taconite BART Report and shouldnot be distributed without the full text of the report so that theinformation is not taken out of context.

Reference No.

1SO2Pollution ControlTechnology2 Is this a generally available control technology? Is the control technology available to indurating furnaces? Is the control technology applicable to this specific source? Is it technically feasible for this source?ApproximateControlEfficiencyCommentsBasic Principle13 SOx-NOx-Rox-BoxN ------------Technology has not been demonstratedDry sorbent injection upstream of the baghouse for removal of SOx and ammoniainjection upstream of a zeolitic selective catalytic reduction (SCR) catalystincorporated in the baghouse to reduce NOx emissions.14 Electron (E-Beam) ProcessN------------No operating commercial applications oncoalElectron beam irradiation in the presence of ammonia to initiate chemicalconversion of sulfur and nitrogen oxides into components which can be easilycollected by conventional methods such as an ESP or baghouse.15 Electrocatalytic OxidationN------------Similar to cold plasma. Will keep watchfor availability of this technologyUtilizes a reactor in which SO2, NOx, and mercury are oxidized to nitrogendioxide (NO2), sulfuric acid, and mercuric oxide respectively using non-thermalplasma.On recent project, the vender was doing final trials on full-scale applications.16NOXSON------------Commercial version of adsorption. Limitedexperience (proof-of-concept tests).Uses a regenerable sorbent to simultaneously adsorb SO2and NOx from flue gasfrom coal-fired utility and industrial boilers. In the process, the SO2is convertedto a saleable sulfur by-product (liquid SO2, elemental sulfur, or sulfuric acid) andthe NOx17 Copper-OxideN------------Absorption and SCR. Experience limited topilot scale.SO2in the flue gas reacts with copper oxide, supported on small spheres ofalumina, to form copper sulfate. Ammonia is injected into the flue gas before theabsorption reactor and a selective catalytic reduction-type reaction occurs thatreduces the nitr18SNOXN------------Early commercial development stageCatalytic reduction of NOx in the presence of ammonia (NH3), followed bycatalytic oxidation of SO2to SO3. The exit gas from the SO3converter passesthrough a novel glass-tube condenser in which the SO3is hydrated to H2SO4vaporand then condensed to a19 Cold PlasmaN ------------Research level1) 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.htm2) c) New and Emerging Environmental Technologies, http://neet.rti.org/2) d) ND BART ReportsY:\22\52\080 Tilden BART\BART report\Appendix\Appendix D - Michigan Operations Control Technologies - Furnaces.xls2 of 212/28/2006Cleveland Cliffs Michigan Operations BART AnalysisSO2 ControlProcess BoilersAvailable and Applicable ReviewDRAFTRevised: December 1, 2006Step 1Step 2This table is part of the CCMO Process Boiler BART Report and should not be distributedwithout the full text of the report so that the information is not taken out of context.

Reference No.

1SO2Pollution ControlTechnology2Is this agenerallyavailablecontroltechnology?Is the controltechnologyavailable topower boilers?Is the controltechnologyapplicable tothis specificsource?Is it technicallyfeasible for thissource?CommentsBasic Principle1Wet Scrubbing (HighEfficiency)YesYesYesYesAbsorption and reaction using an alkaline reagent to produce a solid compound2Wet Scrubbing (LowEfficiency)YesYesYesYesAbsorption and reaction using an alkaline reagent to produce a solid compound3Wet Walled ElectrostaticPrecipitator (WWESP)YesYesYesYesExisting fabric filtercontrolSuspended particles are separated from the flue gas stream, attracted to plates, and collected inhoppers4 Dry sorbent injection YesYesYesYesPulverized lime or limestone is directly injected into the duct upstream of the fabric filter. Drysorption of SO2onto the lime or limestone particle occurs and thesolid particles are collected witha fabric filter5Spray Dryer Absorption(SDA)YesYesYesYesLime slurry is sprayed into an absorption tower where SO2is absorbed by the slurry, formingCaSO3/CaSO46 Alternative FuelsYesYesYesYes (notrequired byBART)Not permitted forother fuels.Use a fuel with lower sulfur content.7 Load ReductionYesYesNo---Could reduceproductionThis is a strategy to reduce load on a power plant by reducing the electrical demand throughefficiency projects.8 Energy Efficiency Projects YesYesYesYesDecrease amount of fuel required to make an acceptable product9 Coal DryingYesYesNo---Requires availableexcess heat sourceDry coal will increase the as-burned BTU value, and therefore less fuel is required to be burned.Specific energy efficiency project10Bio FiltersNo--------- Research levelGas stream passes through a packed bed of specially engineered biomedia which supports thegrowth of active bacterial species. The pollutants in the gas stream are biodegraded orbiotransformed into innocuous products, such as carbon dioxide, water, chloride ion in water,sulfate or nitrate ions in water.11CANSOLV Regenerable SO2No--------- Research levelAn aqueous solution of proprietary diamine captures SO2from the feed gas in a countercurrentabsorption tower. The rich solvent is regenerated by steam stripping, giving a byproduct of pure,water saturated SO2gas and lean solvent for recycling to the absorber.12 Pahlman ProcessNo--------- Research levelGas stream is passed through a filter baghouse in which specially-developed, small-particle, highsurface area metal oxide sorbent have been deployed. Pollutants are removed from the gases byadsorption.Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix D - Michigan Operations Control Technologies - Process Boilers.xlsSOx Process Boilers1 of 312/28/2006Cleveland Cliffs Michigan Operations BART AnalysisSO2 ControlProcess BoilersAvailable and Applicable ReviewDRAFTRevised: December 1, 2006Step 1Step 2This table is part of the CCMO Process Boiler BART Report and should not be distributedwithout the full text of the report so that the information is not taken out of context.

Reference No.

1SO2Pollution ControlTechnology2Is this agenerallyavailablecontroltechnology?Is the controltechnologyavailable topower boilers?Is the controltechnologyapplicable tothis specificsource?Is it technicallyfeasible for thissource?CommentsBasic Principle13 SOx-NOx-Rox-BoxNo---------Technology has notbeen demonstratedDry sorbent injection upstream of the baghouse for removal of SOx and ammonia injectionupstream of a zeolitic selective catalytic reduction (SCR) catalyst incorporated in the baghouse toreduce NOx emissions.14 Electron (E-Beam) Process No---------No operatingcommercialapplications on coalElectron beam irradiation in the presence of ammonia to initiate chemical conversion of sulfur andnitrogen oxides into components which can be easily collected by conventional methods such asan ESP or baghouse.15 Electrocatalytic Oxidation No---------Similar to coldplasma. Will keepwatch for availabilityof this technologyUtilizes a reactor in which SO2, NOx, and mercury are oxidized to nitrogen dioxide(NO2), sulfuricacid, and mercuric oxide respectively using non-thermal plasma.On recent project, the vender was doing final trials on full-scale applications.16NOXSONo---------Commercial versionof adsorption.Limited experience(proof-of-concepttests).Uses a regenerable sorbent to simultaneously adsorb SO2and NOx from flue gas from coal-firedutility and industrial boilers. In the process, the SO2is converted to a saleable sulfur by-product(liquid SO2, elemental sulfur, or sulfuric acid) and the NOx isconverted to nitrogen and oxygen.17 Copper-OxideNo---------Absorption and SCR.Experience limited topilot scale.SO2in the flue gas reacts with copper oxide, supportedon small spheres of alumina, to formcopper sulfate. Ammonia is injected into the flue gas before the absorption reactor and a selectivecatalytic reduction-type reaction occurs that reduces the nitric oxides in the flue gas. In theregeneration step, the copper sulfate is reduced in a regenerator with a reducing agent, such asnatural gas, producing a concentrated stream of SO2.18SNOXNo---------Early commercialdevelopment stageCatalytic reduction of NOx in the presence of ammonia (NH3), followed by catalytic oxidation ofSO2to SO3. The exit gas from the SO3converter passes through a novel glass-tube condenser inwhich the SO3is hydrated to H2SO4vapor and then condensed to a concentrated liquid sulfuricacid (H2SO4).19 Cold PlasmaNo--------- Research level1) This number is for reference only. It does not in any way rank the control technologies.Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix D - Michigan Operations Control Technologies - Process Boilers.xlsSOx Process Boilers2 of 312/28/2006Cleveland Cliffs Michigan Operations BART AnalysisSO2 ControlProcess BoilersAvailable and Applicable ReviewDRAFTRevised: December 1, 2006Step 1Step 2This table is part of the CCMO Process Boiler BART Report and should not be distributedwithout the full text of the report so that the information is not taken out of context.

Reference No.

1SO2Pollution ControlTechnology2Is this agenerallyavailablecontroltechnology?Is the controltechnologyavailable topower boilers?Is the controltechnologyapplicable tothis specificsource?Is it technicallyfeasible for thissource?CommentsBasic Principle2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htmc) New and Emerging Environmental Technologies, http://neet.rti.org/d) ND BART ReportsY:\22\52\080 Tilden BART\BART report\Appendix\Appendix D - Michigan Operations Control Technologies - Process Boilers.xlsSOx Process Boilers3 of 312/28/2006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlDryerAvailableandApplicableReviewRevised:December1,2006OverfircAir(OFA)YesYesYesYesCombustionairisseparatedintoprimaryandsecondaryflowsectionstoachievecompleteburnoutandtoencouragetheformationofN2ratherthanNOx2ExternalFlueGasYesYesYesNoMixesfluegaswithcombustionairwhichreducesoxygencontentandthereforeRecirculation(EFGR)reducesflametemperature3Low-NOxBurnersYesYesYesYesBurnersaredesignedtoreduceNOxformationthroughrestrictionofoxygen,flametemperature,and/orresidencetimeInducedFlueGasNeedtobeupfired.Need4RecirculationBurnersYesYesYesYesconvectivelooptogetgasDrawsfluegastodilutethefuelinordertoreducetheflametemperaturerecirculated5LowExcessAirYesYesYesYesReducesroductionReducesoxencontentinflueasandreducesflameterneratureBurnersoutofServiceNeedcapacityofallShutoffthefuelflowfi·omoneburnerormoretocreatefuelrichandfuellean6YesYesYesNoburnersforworstcase(BOOS)scenariozones7FuelBiasingYesYesYesNoCombustionisstagedbydivertingfuelfromtheupperlevelburnerstotheloweronesorfromthecentertothesideburnerstocreateandfucl·lcanzonesPartofthetotalfuelheatinputisinjectedintothefurnaceinaregionabovethe8RebumingYesYesYesNoprimary(mainburners)flamestocreateareducingatmospherezone),wherehydrocarbonradicalsrcactwithNOxtoproduccclementalnitrogen9LoadReductionYesYesNoThisisastrategytoreduceloadonapowerplantbyreducingtheelcctricaldemandthroughefficiencyrojects,10EnerEfficiencPro'ectsYesYesYesYesDecreaseamountoffuelreuircdtomakeanaccetableroduct11CoalDryingYesYesNoRequiresavailableexcessDrycoalwillincreasetheas-burnedBTUvalue,andthereforelessfuelisrequiredheat.tobeburned,Specificenergyefficiencyproject14CombustionZoneCoolingYesYesNoCouldreduceloadCoolingoftheprimaryflamezonebyheattransfertosurroundingsurfacescapabilitiesY:\22\52\OBOTildenBART\BARTreport\Appendix\Appendix0MichiganOperationsControlTechnologiesDryer.xlsNOxDryer1of412/21/2006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlOryerAvailableandApplicableReviewRevised:December1,2006RequirescasebycaseYes(notanalysis.Typically,Lowercombustiontempswithsolidfuelsvsgas.MayalsoreducefuelNOxby15AlternateFuelsYesYesYesrequiredbyfacilitiesexperiencelowerBART)NOxwhenburningsolidusingafuelwithlessnitrogen.fuels.16OxygenEnhancedNoResearchlevelAsmallfractionofthecombustionairisreplacedwithoxygen.CombustionPulverizedcoalpreheatedandvolatilesandnitrogencompoundsare17PreheatCombustionNoResearchlevelreleasedinacontrolledreducingatmospherewherethenitrogencompoundsarereducedtoNz.ThisisaddressedthroughCombinationnfGFAandSCR.Wall-firedorfurnacethat18ROFA-ROTAMIXYesYesYes'Yesthescenariothatcombinesutilizeshighvelocityoverflreair.AdditionalNOxreductionsareachievedwithOFAandSCRanunoniainjection(Rotamix)Currentequipmentcannot19NOxCEMSYesYesYes"'-'-No---""---·'"betunedto'impactNOxOptimizationofcombustionemissionsCUrrente,quipmentcannot20ParametricMonitoringYesYesYesNobetunedtoimpactNOxOptimizationofcombustionemissionsCatalystInjectionAcombustioncatalystisdirectlyinjectedintotheairintakestreamanddelivered38NoResearchLeveltothecombustionsite,initiatingchemicalreactionsthatchangethedynamicsof(EPSTechnologies)theflame.21Non-SelectiveCatalyticYesYesYesYesNot,efficientasotherUndernear stoichiometricconditions,inthepresenceofacatalyst,NOxisReduction(NSCR)reducedbyCO,resultinginnitrogen(N2)andcarbondioxide(CO2),22LowTemperatureOxidationYesYesNoRequiresozonegenerationUtilizesanoxidizingagentsuchasozonetooxidizevariouspollutantsincluding(LTD)Tri-NOx®NOxY:\22\52\OBOTildenBART\BARTreport\Appendix\Appendix0MichiganOperationsControlTechnologiesMDryer.xlsNOxDryer20f412/21/2006ClevelandCliffsMichiganOperationsBARTAnalysisNOxCOl")trolDryer.AvailableandApplicableReviewRevised:December1,200623LowTemperatureOxidationYes(LTO)-LoTOx24SelectiveCatalyticReductionYes(SCR)NoYesYesYesHasbeenincludedasan"innovative"technologyinrecentBACTanalysesfrommultiplefacilities.Needtoinjectatappropriatetemperature.Applicabletocleanservices.UtilizesanoxidizingagentsuchasozonetooxidizevariouspollutantsincludingNOxAmmonia(NH))isinjectedintothefluegasstreaminthepresenceofacatalysttoconvertNOxintoNzandwater25RegenerativeSCR26SelectiveNon-CatalyticReduction(SNCR)27AdsOition28Absorption29OxidizerYesYesNoYesYesNoYesYesYesYesYesYesYesYesYes•..j.",Forcleanservices.ToomuchdebrisinfluegaswouldpoisoncatalystStillinresearchstaes.SimilartoTriNOxRedundanttoregenerative....,r;Ureaorammonia·basedchemicalsareinjectedintothefluegasstreamtoCOnvertNOtomolecularnitrogen,N2,andwaterUseofcharactivatedcarbontoadsorboxidesofnitroenUseofwater,hydroxideandcarbonatesolutions,sulfuricacid,organicsolutions,moltenalkalicarbonates,orhydroxidestoabsorboxidesofnitrogen.Gasstreamissentthroughtheregenerative, recuperative,catalyticordirectfiredoxidizerwherepollutantsareheatedtoacombustionpointanddestroyed.3031SNOXSOx-NOx-Rox-BoxNoNoEarly'col1li:nercialdevelopmentstageTechnologyhasnotbeendemonstratedCatalyticreductionofNOxinthepresenceofammonia(NH]),followedbycatalyticoxidationofS02toSO].TheexitgasfromtheSO)converterpassesthroughanovelglass-tubecondenserinwhichtheSO]ishydratedtoH2S04vaporandthencondensedtoaconcentratedliquidsulfuricacid(H2S04),DrysorbentinjectionupstreamofthebaghouseforremovalofSOxandammoniainjectionupstreamofazeoliticselectivecatalyticreduction(SCR)catalystincorporatedinthebaghousetoreduceNOxemissions.Y:\22\52\080TildenBARnBARTreport\Appendix\AppendixDMichiganOperationsControlTechnologies7Dl)Ier.xlsNOxDryer.30f41212112006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlDryerAvailableandApplicableReviewRevised:December1,2006NooperatingcommercialElectronbeamirradiationinthepresenceofammoniatoinitiatechemical32Electron(E-Beam)ProcessNoapplicationsoncoalconversionofsulfurandnitrogenoxidesintocomponentswhichcanbeeasilycollectedbyconventionalmethodssuchasanESPorbaghouse.Similartocoldplasma.UtilizesareactorinwhichS02'NOx,andmercuryareoxidizedtonitrogenWillkeepwatchfordioxide(N02),sulfuricacid,andmercuricoxiderespectivelyusingnon-thermal33ElectrocatalyticOxidationNoavailabilityofthisplasma.technologyOnrecentproject,thevenderwasdoingfinaltrialsonapplications.CommercialversionofUsesaregenerablesorbenttosimultaneouslyadsorb502andNOxfromfluegas34NOXSONoadsorption.Limitedfromutilityandindustrialboilers.Intheprocess,theS02isconvertedexperiencetoasaleablesulfurby-product(liquidSOz,elementalsulfur,orsulfuricacid)andconcepttests).theNOxisconvertedtonitrogenandoxygen.S02inthefluegasreactswithcopperoxide,supportedonsmallspheresofAbsorptionandSCR.alumina,tofonncoppersulfate.Ammoniaisinjectedintothefluegasbeforetheabsorptionreactorandaselectivecatalyticreactionoccursthat35Noe,·.ExperitmceJimitedtopilotreducesthenitricoxidesinthefluegas.Intheregenerationstep,thecopperscale.sulfateisreducedinaregeneratorwithareducingagent,suchasnaturalgas,producingaconcentratedstreamofS02.36ColdPlasmaNoResearchLevelGasstreamispassedthroughafiltermediumofsoilandmicrobes.Pollutantsare37BiofiltersNoResearchleveladsorbedanddegradedbymicrobialmetabolismfonningtheproductscarbondioxideandwater.Gasstreamispassedthroughafilterbaghouseinwhich38PahlmanProcessNoResearchLevelareametaloxidesorbenthavebeendeployed.Pollutantsareremovedfromthegasesbyadsortion.I)Thisnumberisforreferenceonly.Itdoesnotinanywayrankthecontroltechnologies.2)a)AirPollution:ItsOriginAndControl.Wark,Kenneth;Warner,CecilF.;andDavis,WayneT.1998.AddisonWesleyLongman,Inc.b)USEPABasicConceptsinEnvironmentalScience,Module6,http://www.epa.gov/eogaptil/inodule6/index.htmc)NewandEmergingEnvironmentalTechnologies,http://neet.rti.orgld)NDBARTReportsY:\22\52\080TildenBART\8ARTreport\Appendix\Appendix0MichiganOperationsControlTechnologies,.Dryer,xisNOxDryer4of412/21/2006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlProcessBoilersAvailableandApplicableReviewDRAFTRevised:December1,2006OverfireAir(OFA)YesYesYesYesCombustionairisseparatedintoprimaryandsecondaryflowsectionstoachievecompleteburnoutandtoencouragethefonnationofN1ratherthanNOx2ExtemalFlueGasYesYesYesNoMixesfluegaswithcombustionairwhichreducesoxygencontentandthereforeRecirculation(EFGR)reducesflametemperatureJLow·NOxBurnersYesYesYesYesBurnersaredesignedtoreduceNOxfonnationthroughrestrictionofoxygen,flametemperature,and/orresidencetimeInducedFlueGasNeedtobeupfired.Need4RecirculationBurnersYesYesYesYesconvectivelooptogetgasDrawsfluegastodilutethefuelinordertoreducetheflametemperaturerecirculated5LowExcessAirYesYesYesYesReducesroductionReducesoxencontentinflueasandreducesflametemeratureBU111el'SoutofServiceNeedcapacityofallShutoffthefuelflowfromoneburnerormoretocreatefuelrichandfuellean6YesYesYesNobU111ersforworstcase(BOOS)scenariozones7FuelBiasingYesYesYesNoCombustionisstagedbydivertingfuelfromtheupperlevelburnerstotheloweronesorfromthecentertothesideburnerstocreatefuel-richandfuel-leal).zonesPaltofthetotalfuelheatinputisinjectedintothefurnaceinaregionabovethe8ReburningYesYesYesYesprimary(mainburners)flamestocreateareducingatmosphere(re-bumzone),wherehydrocarbonradicalsreactwithNOxtoproduceelementalnitrogen9LoadReductionYesYesNoThisisastrategytoreduceloadonapowerplantbyreducingtheelectricaldemandthroughefficiencyprojects,toEnergEfficienePro'ectsYesYesYesYesDecreaseamountoffuelreuiredtomakeanaccetableroduetIICoalDryingYesYesNoRequiresavailableexcessDrycoalwillincreasetheas-burnedBTUvalue,andthereforelessfuelisrequiredheat.tobeburned.Specificenergyefficiencyproject14CombustionZoneCoolingYesYesNoCouldreduceloadCoolingoftheprimaryflamezonebyheattransfertosurroundingsurfacescapabilitiesY:\22\52\OBOTildenBARnBARTreport\Appendix\Appendix0-MichiganOperationsControlTechnologies-ProcessBoilers.xlsNOxProcessBoilers1of512/20/2006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlProcessBoilersAvailableandApplicableReviewDRAFTRevised:December1,2006RequirescasebycaseYes(notanalysis.Typically,Lowercombustiontempswithsolidfuelsvsgas.MayalsoreducefuelNOxby15AltemateFuelsYesYesYesrequiredbyfacilitiesexperiencelowerusingafuelwithlessnitrogen.BART)NOxwhenburningsolidfuels.16OxygenEnhancedNoResearchlevelAsmallfractionofthecombustionairisreplacedwithoxygen.CombustionPulverizedcoalpreheatedandvolatilesandfuel-boundnitrogencompoundsare17PreheatCombustionNoResearchlevelreleasedinacontrolledreducingatmospherewherethenitrogencompoundsarereducedtoNz.ThisisaddressedthroughCombinationafCFAandSCR.Wall-firedortangentially-firedfurnacethat18ROFA-ROTAMIXYesYesYesYesthescenariothatcombinesutilizeshighvelocityoverfireair.AdditionalNOxreductionsareachievedwithOFAandSCRammoniainjection(Rotamix)Currentequipmentcannot19NOxCEMSYesYesYesNobetunedtoimpactNOxOptimizationofcombustionemissionsCurrentequipmentcannot20ParametricMonitoringYesYesYesNohetunedtoimpactNOxOptimizationofcombustionemissionsCatalystInjectionAcombustioncatalystisdirectlyinjectedintotheairintakestreamanddelivered38NoResearchLeveltothecombustionsite,initiatingchemicalreactionsthatchangethedynamicsof(EPSTechnologies)theflame.CatalyticForcleanservices.TooUndernearstoichiometricconditions,inthepresenceofacatalyst,NOxis21Reduction(NSCR)YesYesYesYesmuchdebrisinfluegasreducedbyCO,resultinginnitrogen(N2)andcarbondioxide(CO2),wouldpoisoncatalystY:\22\52\080TildenBART\BARTreport\Appendix\Appendix0 -MichiganOperationsConlrolTechnologiesProcessBoilers.xlsNOxProcessBoilers20f51212012006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlProcessBoilersAvailableandApplicableReviewDRAFTRevised:December1,200622LowTemperatureOxidationYesYesNoRequiresozonegenerationUtilizesanoxidizingagentsuchasozonetooxidizevariouspollutantsincluding(LTD)Tri·NOx®NOxHasbeenincludedasan23LowTemperatureOxidationYesNo"innovative"technologyinUtilizesanoxidizingagentsuchasozonetooxidizevariouspollutantsincluding(LTO)-LoTOxrecentBACTanalysesNOxfrommultiplefacilities.Needtoinjectat24SelectiveCatalyticReductionYesYesYesYesappropriatetemperature.Ammonia(NH3)isinjectedintothefluegasstreaminthepresenceofacatalystto(SCR)ApplicabletocleanconvertNOxintoN2andwaterservices.Forcleanservices.Too25RegenerativeSCRYesNomuchdebrisinfluegaswouldpoisoncatalyst26SelectiveNon-CatalyticYesYesYesYesUreaorammonia-basedchemicalsareinjectedintothefluegasstreamtoconvertReduction(SNCR)NOtomolecularnitrogen,N2,andwater27AdsoHonNoStillinresearchstages.Uscofcharactivatedcarbontoadsorboxidesofnitroen28AbsorptionYesYesNoSimilartoTriNOxUseofwater,hydroxideandcarbonatesolutions,sulfuricacid,organicsolutions,moltenalkalicarbonates,orhydroxidestoabsorboxidesofnitrogen.29OxidizerYesYesYesYesRedundanttoregenerativeGasstreamissentthroughtheregenerative,recuperative,catalyticordirectfiredSCRoxidizerwherepollutantsareheatedtoacombustionpointanddestroyed.Y:\22\52\080TildenBARnBARTreport\Appendix\Appendix0 -MichiganOperationsControlTechnologiesProcessBoilers.xlsNOxProcessBoilers30f512/20/2006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlProcessBoilersAvailableandApplicableReviewDRAFTRevised:December1,200630313233343S36SNOXSOx-NOx-Rox-BoxElectron(E-Beam)ProcessElectrocatalyticOxidationNOXSOCopper-OxideColdPlasmaNoNoNoNoNoNoNoEarlycommercialstageTechnologyhasnotbeendemonstratedNooperatingcommercialapplicationsoncoalSimilartocoldplasma.Willkeepwatchforavailabilityofthi5Commercialversionofadsorption.Limitedexperienceconcepttests).AbsorptionandSCR.Experiencelimitedtopilotscale.ResearchLevelCatalyticreductionofNOxinthepresenceofammonia(NH3),followed,bycatalyticoxidationofS02toS03'TheexitgasfromtheSOJconvelierpassesthroughanovelglass-tubecondenserinwhichtheS03ishydratedtoH2S04vaporandthencondensedtoaconcentratedliquidsulfuricacid(H2S04).DrysorbentinjectionupstreamofthebaghouseforremovalofSOxandammoniainjectionupstreamofazeoliticselectivecatalyticreduction(SCR)catalystincorporatedinthebaghousetoreduceNOxemissions.ElectronbeamirradiationinthepresenceofammoniatoinitiatechemicalconversionofsulfurandnitrogenoxidesintocomponentswhichcanbeeasilycollectedbyconventionalmethodssuchasanESPorbaghouse.UtilizesareactorinwhichS02'NOx,andmercuryareoxidizedtonitrogendioxide(N0z),sulfuricacid,andmercuricoxiderespectivelyusingplasma.Onrecentproject,thevenderwasdoingfinaltrialsonapplications.UsesaregenerablesorbenttosimultaneouslyadsorbSOzandNOxfromfluegasfi'omutilityandindustrialboilers.Intheprocess,theSOzisconvertedtoasaleablesulfurby-product(liquidS02,elementalsulfur,orsulfuricacid)andtheNOxisconvertedtonitrogenandoxygen.S02inthefluegasreactswithcopperoxide,supportedonsmallspheresofalumina,tofonncoppersulfate.Ammoniaisinjectedintothefluegasbeforetheabsorptionreactorandaselectivecatalyticreduction-typereactionoccursthatreducesthenitricoxidesinthefluegas.Intheregenerationstep,thecoppersulfateisreducedinaregeneratorwithareducingagent,suchasnaturalgas,producingaconcentratedstreamofS02'Y:\22\52\OBOTildenBART\BARTreport:\Appendlx\Appendix0MichiganOperationsControlTechnologiesProcessBoilers.xisNOxProcessBoilers4of512/20/2006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlProcessBoilersAvailableandApplicableReviewDRAFTRevised:December1,20063738BiofiltersPahlmanProcessNoNoResearchlevelResearchLevelGasstreamispassedthroughafiltermediumofsoilandmicrobes.Pollutantsareadsorbedanddegradedbymicrobialmetabolismformingtheproductscarbondioxideandwater.Gasstreamispassedthroughafilterbaghouseinwhichspecially-developed,small-particle,high-surfaceareametaloxidesorbenthavebeendeployed.Pollutantsareremovedfromthegasesbadsortion.1)Thisnumberisforreferenceonly.Itdoesnotinanywayrankthecontroltechnologies.2)a)AirPollution:ItsOriginAndControl.Wark,Kenneth;Wamer,CecilF.;andDavis,WayneT.1998.AddisonWesleyLongman,Inc.b)USEPABasicConceptsinEnvironmentalScience,Module6,http://www.epa.gov/eogaptillmodule6/index.htmc)NewandEmergingEnvironmentalTechnologies,http://neet.rti.org!d)NDBARTReportsY:\22\52\080TildenBART\BARTreport\Appendix\Appendix0 -MichiganOperationsControlTechnologiesProcessBoilers.xlsNOxProcessBoilers50f512120/2006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlProcessBoilersAvailableandApplicableReviewDRAFTRevised:December1,2006OverfireAir(OFA)YesYesYesYesCombustionairisseparatedintoprimaryandsecondaryflowsectionstoachievecompleteburnoutandtoencouragethefonnationofN1ratherthanNOx2ExtemalFlueGasYesYesYesNoMixesfluegaswithcombustionairwhichreducesoxygencontentandthereforeRecirculation(EFGR)reducesflametemperatureJLow·NOxBurnersYesYesYesYesBurnersaredesignedtoreduceNOxfonnationthroughrestrictionofoxygen,flametemperature,and/orresidencetimeInducedFlueGasNeedtobeupfired.Need4RecirculationBurnersYesYesYesYesconvectivelooptogetgasDrawsfluegastodilutethefuelinordertoreducetheflametemperaturerecirculated5LowExcessAirYesYesYesYesReducesroductionReducesoxencontentinflueasandreducesflametemeratureBU111el'SoutofServiceNeedcapacityofallShutoffthefuelflowfromoneburnerormoretocreatefuelrichandfuellean6YesYesYesNobU111ersforworstcase(BOOS)scenariozones7FuelBiasingYesYesYesNoCombustionisstagedbydivertingfuelfromtheupperlevelburnerstotheloweronesorfromthecentertothesideburnerstocreatefuel-richandfuel-leal).zonesPaltofthetotalfuelheatinputisinjectedintothefurnaceinaregionabovethe8ReburningYesYesYesYesprimary(mainburners)flamestocreateareducingatmosphere(re-bumzone),wherehydrocarbonradicalsreactwithNOxtoproduceelementalnitrogen9LoadReductionYesYesNoThisisastrategytoreduceloadonapowerplantbyreducingtheelectricaldemandthroughefficiencyprojects,toEnergEfficienePro'ectsYesYesYesYesDecreaseamountoffuelreuiredtomakeanaccetableroduetIICoalDryingYesYesNoRequiresavailableexcessDrycoalwillincreasetheas-burnedBTUvalue,andthereforelessfuelisrequiredheat.tobeburned.Specificenergyefficiencyproject14CombustionZoneCoolingYesYesNoCouldreduceloadCoolingoftheprimaryflamezonebyheattransfertosurroundingsurfacescapabilitiesY:\22\52\OBOTildenBARnBARTreport\Appendix\Appendix0-MichiganOperationsControlTechnologies-ProcessBoilers.xlsNOxProcessBoilers1of512/20/2006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlProcessBoilersAvailableandApplicableReviewDRAFTRevised:December1,2006RequirescasebycaseYes(notanalysis.Typically,Lowercombustiontempswithsolidfuelsvsgas.MayalsoreducefuelNOxby15AltemateFuelsYesYesYesrequiredbyfacilitiesexperiencelowerusingafuelwithlessnitrogen.BART)NOxwhenburningsolidfuels.16OxygenEnhancedNoResearchlevelAsmallfractionofthecombustionairisreplacedwithoxygen.CombustionPulverizedcoalpreheatedandvolatilesandfuel-boundnitrogencompoundsare17PreheatCombustionNoResearchlevelreleasedinacontrolledreducingatmospherewherethenitrogencompoundsarereducedtoNz.ThisisaddressedthroughCombinationafCFAandSCR.Wall-firedortangentially-firedfurnacethat18ROFA-ROTAMIXYesYesYesYesthescenariothatcombinesutilizeshighvelocityoverfireair.AdditionalNOxreductionsareachievedwithOFAandSCRammoniainjection(Rotamix)Currentequipmentcannot19NOxCEMSYesYesYesNobetunedtoimpactNOxOptimizationofcombustionemissionsCurrentequipmentcannot20ParametricMonitoringYesYesYesNohetunedtoimpactNOxOptimizationofcombustionemissionsCatalystInjectionAcombustioncatalystisdirectlyinjectedintotheairintakestreamanddelivered38NoResearchLeveltothecombustionsite,initiatingchemicalreactionsthatchangethedynamicsof(EPSTechnologies)theflame.CatalyticForcleanservices.TooUndernearstoichiometricconditions,inthepresenceofacatalyst,NOxis21Reduction(NSCR)YesYesYesYesmuchdebrisinfluegasreducedbyCO,resultinginnitrogen(N2)andcarbondioxide(CO2),wouldpoisoncatalystY:\22\52\080TildenBART\BARTreport\Appendix\Appendix0 -MichiganOperationsConlrolTechnologiesProcessBoilers.xlsNOxProcessBoilers20f51212012006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlProcessBoilersAvailableandApplicableReviewDRAFTRevised:December1,200622LowTemperatureOxidationYesYesNoRequiresozonegenerationUtilizesanoxidizingagentsuchasozonetooxidizevariouspollutantsincluding(LTD)Tri·NOx®NOxHasbeenincludedasan23LowTemperatureOxidationYesNo"innovative"technologyinUtilizesanoxidizingagentsuchasozonetooxidizevariouspollutantsincluding(LTO)-LoTOxrecentBACTanalysesNOxfrommultiplefacilities.Needtoinjectat24SelectiveCatalyticReductionYesYesYesYesappropriatetemperature.Ammonia(NH3)isinjectedintothefluegasstreaminthepresenceofacatalystto(SCR)ApplicabletocleanconvertNOxintoN2andwaterservices.Forcleanservices.Too25RegenerativeSCRYesNomuchdebrisinfluegaswouldpoisoncatalyst26SelectiveNon-CatalyticYesYesYesYesUreaorammonia-basedchemicalsareinjectedintothefluegasstreamtoconvertReduction(SNCR)NOtomolecularnitrogen,N2,andwater27AdsoHonNoStillinresearchstages.Uscofcharactivatedcarbontoadsorboxidesofnitroen28AbsorptionYesYesNoSimilartoTriNOxUseofwater,hydroxideandcarbonatesolutions,sulfuricacid,organicsolutions,moltenalkalicarbonates,orhydroxidestoabsorboxidesofnitrogen.29OxidizerYesYesYesYesRedundanttoregenerativeGasstreamissentthroughtheregenerative,recuperative,catalyticordirectfiredSCRoxidizerwherepollutantsareheatedtoacombustionpointanddestroyed.Y:\22\52\080TildenBARnBARTreport\Appendix\Appendix0 -MichiganOperationsControlTechnologiesProcessBoilers.xlsNOxProcessBoilers30f512/20/2006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlProcessBoilersAvailableandApplicableReviewDRAFTRevised:December1,200630313233343S36SNOXSOx-NOx-Rox-BoxElectron(E-Beam)ProcessElectrocatalyticOxidationNOXSOCopper-OxideColdPlasmaNoNoNoNoNoNoNoEarlycommercialstageTechnologyhasnotbeendemonstratedNooperatingcommercialapplicationsoncoalSimilartocoldplasma.Willkeepwatchforavailabilityofthi5Commercialversionofadsorption.Limitedexperienceconcepttests).AbsorptionandSCR.Experiencelimitedtopilotscale.ResearchLevelCatalyticreductionofNOxinthepresenceofammonia(NH3),followed,bycatalyticoxidationofS02toS03'TheexitgasfromtheSOJconvelierpassesthroughanovelglass-tubecondenserinwhichtheS03ishydratedtoH2S04vaporandthencondensedtoaconcentratedliquidsulfuricacid(H2S04).DrysorbentinjectionupstreamofthebaghouseforremovalofSOxandammoniainjectionupstreamofazeoliticselectivecatalyticreduction(SCR)catalystincorporatedinthebaghousetoreduceNOxemissions.ElectronbeamirradiationinthepresenceofammoniatoinitiatechemicalconversionofsulfurandnitrogenoxidesintocomponentswhichcanbeeasilycollectedbyconventionalmethodssuchasanESPorbaghouse.UtilizesareactorinwhichS02'NOx,andmercuryareoxidizedtonitrogendioxide(N0z),sulfuricacid,andmercuricoxiderespectivelyusingplasma.Onrecentproject,thevenderwasdoingfinaltrialsonapplications.UsesaregenerablesorbenttosimultaneouslyadsorbSOzandNOxfromfluegasfi'omutilityandindustrialboilers.Intheprocess,theSOzisconvertedtoasaleablesulfurby-product(liquidS02,elementalsulfur,orsulfuricacid)andtheNOxisconvertedtonitrogenandoxygen.S02inthefluegasreactswithcopperoxide,supportedonsmallspheresofalumina,tofonncoppersulfate.Ammoniaisinjectedintothefluegasbeforetheabsorptionreactorandaselectivecatalyticreduction-typereactionoccursthatreducesthenitricoxidesinthefluegas.Intheregenerationstep,thecoppersulfateisreducedinaregeneratorwithareducingagent,suchasnaturalgas,producingaconcentratedstreamofS02'Y:\22\52\OBOTildenBART\BARTreport:\Appendlx\Appendix0MichiganOperationsControlTechnologiesProcessBoilers.xisNOxProcessBoilers4of512/20/2006ClevelandCliffsMichiganOperationsBARTAnalysisNOxControlProcessBoilersAvailableandApplicableReviewDRAFTRevised:December1,20063738BiofiltersPahlmanProcessNoNoResearchlevelResearchLevelGasstreamispassedthroughafiltermediumofsoilandmicrobes.Pollutantsareadsorbedanddegradedbymicrobialmetabolismformingtheproductscarbondioxideandwater.Gasstreamispassedthroughafilterbaghouseinwhichspecially-developed,small-particle,high-surfaceareametaloxidesorbenthavebeendeployed.Pollutantsareremovedfromthegasesbadsortion.1)Thisnumberisforreferenceonly.Itdoesnotinanywayrankthecontroltechnologies.2)a)AirPollution:ItsOriginAndControl.Wark,Kenneth;Wamer,CecilF.;andDavis,WayneT.1998.AddisonWesleyLongman,Inc.b)USEPABasicConceptsinEnvironmentalScience,Module6,http://www.epa.gov/eogaptillmodule6/index.htmc)NewandEmergingEnvironmentalTechnologies,http://neet.rti.org!d)NDBARTReportsY:\22\52\080TildenBART\BARTreport\Appendix\Appendix0 -MichiganOperationsControlTechnologiesProcessBoilers.xlsNOxProcessBoilers50f512120/2006ClevelandCliffsMichiganOperations·TaconiteBARTAnalysis502ControlInduratingFurnacesAvailableandApplicableReviewRevised:December1.2006Absorptionaudreactionusingallalkalinereagenttoproduceasolidcompound<50%yyyy2WetScrubbing(High__-1f+-/-If-__---11---------------f----------------------------11co;WetScrubbing(LowEfficiency)WetWalledElectrostaticPreciitator(WWESP)yyyy80%Suspcndedparticlesarescparatedfromlhefluegasstrealil,attractedtoplates,andcollectedinhoers4Drysorbentinjectionyyyy<55%Pulverizedlimeorlimestoneisdirectly injectedintotheductlIpstreamoftllefabricfilter,DrysorptionofS02ontothelimeorlimestoneparticleoccursandthesolid particlesarccollectedwitltafabricfilter5SprayDryerAbsorption6AllemativeFuels7LoadReduction8EnergyEfficiencyProjects9CoalProcessing10BioFiltersyyNyyNyyyNyy(forfurnacescapableofmultiplefLlels)y(forlargeprojectsheat-recouyy(notrequiredbyBART)y(forlargeprqjects.llke<90%Site-specificNaturalgasisbasecasePowcrplanttechnologySite-specificAppliesonlytofacilitiestllatburncoallevelUseafuelwithlowersulfurcontent.Tbisisastrategytorcduceloadallapowerplantbyreducingtheelectricaldemandthrallhtcfficiencro·ccts.decreaseamountoffuelrequiredtomakeallacceptableproductDrycoalwillincreasetheas-buntedBTUvalue,alidthereforelessfuelisrequiredtobebunted,8ecificenerefficiencro'ectGasstreampassesthroughapackedbedofspeciallyenginceredbiomediawhicltsupportstltegrowthofactivebacterialspecies,Tltepollutantsillthegasstreamarebiodegradedorbiotransfonnedintoinnocuousproducts,suchascarbOlldioxide,water,clilorIICANSOLVRegenerableS02NResearchlevelAllaqueoussolutionofproprietarydiaminecaptures802fromthefeedgasillacountercurreutabsorptiontower.Therichsolventisregeneratedbysteamstripping,givingabyproductofpure,watersaturated802gasandleansolventforrecyclingtothea12PahlmanProcessNRcsearchlevelGasstreamispassedthroughafilterbaghollseinwltichspecially.developed,smallparticlc,high·surfaceareametaloxidesorbellthavebeendeployed.Pollutantsareremovedfromthegascsbyadsotion.13SOx-NOx-Rox-BoxNTeclmologyhasnotbeendemonstratedDrysorbcnt injectionnpstreamoftbebaghouseforremovalofSOxandammoniainjectionupstreamofazeoliticselectivecatalyticreduction(SCR)catalystincorporatedintltebagltousetoreduceNOxemissions.Y:\22\52\080TildenBART\BARTrepor1\Appendix\AppendixD·MichiganOperationsControlTechnologies_Furnaces.xls502Tables-Furnace10f212120{2006ClevelandCliffsMichiganOperations·TaconiteBARTAnalysis502ControlInduratingFurnacesAvailableandApplicableReviewRevised:December1,20061415161718Electron(E-Scam)ProcessElectrocatalyticOxidationNOXSOCopper-OxideSNOXNNNNNNooperatingcommercialapplicationsallcoalSimilartocoldplasma.WillkeepwatchfaavailabilityOfl11istechnologyCommercialversionofadsorption.Limitedexperience(proof-of-concepttests).AbsorptionandSCR.Experiencelimitedtopilotscale.arlycommercialdevelopmentstageElectronbeamirradiationinthepresenceofammoniatoinitiatechemicalconversionofsulfurandnitrogenoxidesintocomponentswl\ic1\canbeeasilycollectedbyconventionalmethodssuchasanESPorbaghouse.Utilizesareactorinwhic1\S02'NOll,andmercuryareoxidizedtonitrogendioxide(N02),sulfuricacid,andmercuricoxiderespectivelyusinglloll-thenllalplasma.Onrecentproject,thevenderwasdoingfInaltrialsallfull-scaleapplications.UsesaregenerablesorbenttosimultaneouslyadsorbS02andNOxfromfluegasfromcoal-firedutilityandindustrialboilers.Intheprocess,dieS02isconvertedtasaleablesulfilrby-product(liquidS02,elementalsulfur,orsulfuricacid)andtheNO,S02inthefluegasreactswitllcopperoxide,supportedonsmallspheresofalumina,tofonncoppersnlfate.Ammoniaisinjectedintothefluegasbeforetheabsorptionreactorandaselectivecatalyticreduction-typereactionoccursthatreducesthenitrCatalyticreductionofNOxinthepresenceofammonia(NHl),followedbycatalyticoxidationofS02toSOl'TheexitgasfromtheS03converterpassesthroughanovelglass-tubecondenserinwhichtheS03ishydratedtoH2S04vaporandthencondensedtoa19ColdPlasmaNhlevel1)Thisnumberisforreferenceonly.Itdoesnotinany wayrankthecontroltcclmologies.2)a)AirPollntion:itsOriginAndControl.Wark,Kennetll;Warner,CecilF.;andDavis,WayneT.1998.AddisonWesleyLongman,Tuc.2)b)USEPABasicConceptsinEnvironmentalScience,Module6,http://www.epa.gov/eogaptillmodllle6/index.1Jtm2)c)NewandEmergingEnvironmentalTechnologies,llttp:llncet..rti.orgl2)d)NDBARTReportsY:\22\52\080TildenBARnBARTreportlAppendixlAppendixo·MichiganOperationsControlTechnologies-Furnaces.xls502Tables-Furnace20f212/20/2006Cleveland Cliffs Michigan Operations BART AnalysisNOx ControlDryerAvailable and Applicable ReviewRevised: December 1, 2006Step 1Step 2This table is part of the CCMO Process Boiler BART Report and should notbe distributed without the full text of the report so that the information isnot taken out of context.

Reference No.

1NOxPollution ControlTechnology2Is this agenerallyavailablecontroltechnology?Is the controltechnologyavailable topower boilers?Is the controltechnologyapplicable tothis specificsource?Is it technicallyfeasible for thissource?CommentsBasic PrincipleCombustion Controls1 Overfire Air (OFA) YesYesYesYesCombustion air is separated into primary and secondary flow sections to achievecomplete burnout and to encourage the formation of N2rather than NOx2External Flue GasRecirculation (EFGR)YesYesYesNoMixes flue gas with combustion air which reduces oxygen content and thereforereduces flame temperature3 Low-NOx BurnersYesYesYesYesBurners are designed to reduce NOx formation through restriction of oxygen,flame temperature, and/or residence time4Induced Flue GasRecirculation BurnersYesYesYesYesNeed to be upfired. Needconvective loop to get gasrecirculatedDraws flue gas to dilute the fuel in order to reduce the flame temperature5 Low Excess AirYesYesYesYes Reduces production Reduces oxygen content in flue gas and reduces flame temperature6Burners out of Service(BOOS)YesYesYesNoNeed capacity of allburners for worst casescenarioShut off the fuel flow from one burner or more to create fuel rich and fuel leanzones7 Fuel Biasing YesYesYesNoCombustion is staged by diverting fuel from the upper level burners to the lowerones or from the center to the side burners to create fuel-rich and fuel-lean zones8 ReburningYesYesYesNoPart of the total fuel heat input is injected into the furnace in a region above theprimary (main burners) flames to create a reducing atmosphere (re-burn zone),where hydrocarbon radicals react with NOx to produce elemental nitrogen9 Load Reduction YesYesNo---This is a strategy to reduce load on a power plant by reducing the electricaldemand through efficiency projects.10 Energy Efficiency Projects YesYesYesYesDecrease amount of fuel required to make an acceptable product11 Coal DryingYesYesNo---Requires available excessheat.Dry coal will increase the as-burned BTU value, and therefore less fuel isrequired to be burned. Specific energy efficiency project14 Combustion Zone Cooling Yes Yes No ---Could reduce loadcapabilitiesCooling of the primary flame zone by heat transfer to surrounding surfacesY:\22\52\080 Tilden BART\BART report\Appendix\Appendix D Michigan Operations Control Technologies - Dryer.xlsNOx Dryer1 of 512/28/2006Cleveland Cliffs Michigan Operations BART AnalysisNOx ControlDryerAvailable and Applicable ReviewRevised: December 1, 2006Step 1Step 2This table is part of the CCMO Process Boiler BART Report and should notbe distributed without the full text of the report so that the information isnot taken out of context.

Reference No.

1NOxPollution ControlTechnology2Is this agenerallyavailablecontroltechnology?Is the controltechnologyavailable topower boilers?Is the controltechnologyapplicable tothis specificsource?Is it technicallyfeasible for thissource?CommentsBasic Principle15 Alternate FuelsYesYesYesYes (notrequired byBART)Requires case by caseanalysis. Typically,facilities experience lowerNOx when burning solidfuels.Lower combustion temps with solid fuels vs gas. May also reduce fuel NOx byusing a fuel with less nitrogen.16Oxygen EnhancedCombustionNo --- ------ Research levelA small fraction of the combustion air is replaced with oxygen.17 Preheat CombustionNo--------- Research levelPulverized coal preheated and volatiles and fuel-bound nitrogen compounds arereleased in a controlled reducing atmosphere where the nitrogen compounds arereduced to N2.18 ROFA-ROTAMIXYesYesYesYesThis is addressed throughthe scenario that combinesOFA and SCRCombination of OFA and SCR. Wall-fired or tangentially-fired furnace thatutilizes high velocity overfire air. Additional NOx reductions are achieved withammonia injection (Rotamix)19 NOx CEMSYesYesYesNoCurrent equipment cannotbe tuned to impact NOxemissionsOptimization of combustion20 Parametric Monitoring Yes YesYesNoCurrent equipment cannotbe tuned to impact NOxemissionsOptimization of combustion38Catalyst Injection(EPS Technologies)No --- ------ Research LevelA combustion catalyst is directly injected into the air intake stream and deliveredto the combustion site, initiating chemical reactions that change the dynamics ofthe flame.Post Combustion Controls21Non-Selective CatalyticReduction (NSCR)YesYesYesYesNot as efficient as othercontrol technologiesUnder near stoichiometric conditions, in the presence of a catalyst, NOx isreduced by CO, resulting in nitrogen (N2) and carbon dioxide (CO2).22Low Temperature Oxidation(LTO) - Tri-NOx®YesYesNo--- Requires ozone generationUtilizes an oxidizing agent such as ozone to oxidize various pollutants includingNOxY:\22\52\080 Tilden BART\BART report\Appendix\Appendix D Michigan Operations Control Technologies - Dryer.xlsNOx Dryer2 of 512/28/2006Cleveland Cliffs Michigan Operations BART AnalysisNOx ControlDryerAvailable and Applicable ReviewRevised: December 1, 2006Step 1Step 2This table is part of the CCMO Process Boiler BART Report and should notbe distributed without the full text of the report so that the information isnot taken out of context.

Reference No.

1NOxPollution ControlTechnology2Is this agenerallyavailablecontroltechnology?Is the controltechnologyavailable topower boilers?Is the controltechnologyapplicable tothis specificsource?Is it technicallyfeasible for thissource?CommentsBasic Principle23Low Temperature Oxidation(LTO) - LoTOxYesNo------Has been included as an"innovative" technology inrecent BACT analysesfrom multiple facilities.Utilizes an oxidizing agent such as ozone to oxidize various pollutants includingNOx24Selective Catalytic Reduction(SCR)YesYesYesYesNeed to inject atappropriate temperature.Applicable to cleanservices.Ammonia (NH3) is injected into the flue gas stream in the presence of a catalystto convert NOx into N2and water25 Regenerative SCRYesNo------For clean services. Toomuch debris in flue gaswould poison catalyst26Selective Non-CatalyticReduction (SNCR)YesYesYesYesUrea or ammonia-based chemicals are injected into the flue gas stream to convertNO to molecular nitrogen, N2, and water27 Adsorption No --- ------ Still in research stages. Use of char (activated carbon) to adsorb oxides of nitrogen28 AbsorptionYesYesYesYes Similar to TriNOxUse of water, hydroxide and carbonate solutions, sulfuric acid, organic solutions,molten alkali carbonates, or hydroxides to absorb oxides of nitrogen.29 OxidizerYesYesYesYesRedundant to regenerativeSCRGas stream is sent through the regenerative, recuperative, catalytic or direct firedoxidizer where pollutants are heated to a combustion point and destroyed.30SNOXNo---------Early commercialdevelopment stageCatalytic reduction of NOx in the presence of ammonia (NH3), followed bycatalytic oxidation of SO2to SO3. The exit gas from the SO3converter passesthrough a novel glass-tube condenser in which the SO3is hydrated to H2SO4vapor and then condensed to a concentrated liquid sulfuric acid (H2SO4).31 SOx-NOx-Rox-BoxNo---------Technology has not beendemonstratedDry sorbent injection upstream of the baghouse for removal of SOx and ammoniainjection upstream of a zeolitic selective catalytic reduction (SCR) catalystincorporated in the baghouse to reduce NOx emissions.Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix D Michigan Operations Control Technologies - Dryer.xlsNOx Dryer3 of 512/28/2006Cleveland Cliffs Michigan Operations BART AnalysisNOx ControlDryerAvailable and Applicable ReviewRevised: December 1, 2006Step 1Step 2This table is part of the CCMO Process Boiler BART Report and should notbe distributed without the full text of the report so that the information isnot taken out of context.

Reference No.

1NOxPollution ControlTechnology2Is this agenerallyavailablecontroltechnology?Is the controltechnologyavailable topower boilers?Is the controltechnologyapplicable tothis specificsource?Is it technicallyfeasible for thissource?CommentsBasic Principle2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htmc) New and Emerging Environmental Technologies, http://neet.rti.org/d) ND BART ReportsY:\22\52\080 Tilden BART\BART report\Appendix\Appendix D Michigan Operations Control Technologies - Dryer.xlsNOx Dryer5 of 512/28/2006Appendix ESummary of Relevant Economic Feasility ($/ton) Control Costs12/28/2006Appendix E Clean Air Interstate Rule (CAIR), Cost-Effective Air Pollution ControlsCommentsReferenceRegulatory Body/RuleSO2NOxSO2NOxBART100 to 1000100 to 100070 FR 39135BART281 to 129670 FR 39135 Table 3BART91970 FR 39133BARTGuidelines disparagingly reference "thousands ofdollars per ton" in commenting on the need toexceed MACT and its general unreasonableness.70_FR_25210_CAIR.pdfCAIR1300Estimated Marginal cost 2009BART(proposed rule) 200-1000BART proposed lists this as values for 90-95%SO2 control, which is still assumed, or .1 to .15lb/MMBtu. Dropped from final to give statesflexibility to require more. Says for scrubbers,bypasses aren't BART, only 100% scrubbing isBART.BART(proposed rule)0.2 lb/MMBtu for NOx is assumed reasonble.Recognizes that some sources may need SCR toget this level. For those, state discretion of the thecost vs. visibility value is necessary.CAIR(using IPM)10001500CAIR ( 2009 in 1999$) 9002400CAIR ( 2015 in 1999$) 18003000CAIR (depending on Nat'lemissions)1200 - 3000 1400- 2100This was modeled with TRUM (TechnologlyRetrofitting Updating Model) to develop themarginal values.Kammer_EPA_Decision.docKammer Decisionover 1000 over 1000LADCO_MidwestRPO_Boiler Analysis.pdf LADCO/Midwest RPO 1240 to 3822 607 to 4493MANE-VU_BART_Control_Assessment.pdf MANE-VU200-500 200-1500Bowers_vs_SWAPCA.txtBowers vs SWAPCA30030010001000954-1134 was ruled too much, in favor of 256-310for SO2. This did consider incremental value.Sections XVII to XIXWRAP3000EPA - Referenced by WrapReferences EPA-600S\7-90-018. Low is<$500/ton, Moderate is $500-3000/ton, High isover $3000/tonWRAP_Trading_program_methodology.pdfAvg. Expected Values ($/ton) Limiting/Marginal values ($/ton)MidwestRPO_rept_referencing_CAIR.pdfFR_Notice_5MAY04_Proposed_Rule.pdfFR_Notice_6JULY05_Final_Rule.pdfY:\22\52\080 Tilden BART\BART report\Appendix\Appendix E - Table of Costs_per_ton.xls

# DRAFT – BART Analysis Procedures 8/29/2006

P :\22-52\CCMO BART\BART General Documents\BART Analysis Procedures.doc 

# 1 

# 1. BART Eligibility

BART eligibility is established on the basis on thre e 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 particulate matter (PM), PM 10 

# ,

P M 2.5 

# , sulfur dioxide (SO 2 

# ), nitrous oxide (NO

x 

# ), 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. EPAapproved 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.



# 2. BART Determinations

Each source that is subject to BART must determine B ART 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

# DRAFT – BART Analysis Procedures 8/29/2006

P :\22-52\CCMO BART\BART General Documents\BART Analysis Procedures.doc 

# 2 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. 1 

# The five steps of a BART analysis are:

S tep 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. 2



# S tep 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:

1 

# 40 CFR 51 Appendix Y

2 

# Federal Register 70, No. 128 (July 6, 2005): 39164

# DRAFT – BART Analysis Procedures 8/29/2006

P :\22-52\CCMO BART\BART General Documents\BART Analysis Procedures.doc 

# 3 a. 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. 3 

# ” However, the U.S. EPA further states that they “d o not

expect a source owner to conduct extended trials to learn how to apply a

technology on a totally new and dissimilar source type. 4 

# ”

b

. 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. 5 

# ” 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 pollutantbearing stream and comparing them to the gas stream characteristics of the

source types to which the technology has been applied previously. 6 

# ”

c

. 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 technology 7 

# .” This also involves the

i dentification of “un-resolvable technical difficulties.” However, when the

technical difficulties are merely a matter of increased cost, the technology

3 

# Federal Register 70, No. 128 (July 6, 2005): 39165

4 

# IBID

5 

# IBID

6 

# IBID

7 

# IBID

# DRAFT – BART Analysis Procedures 8/29/2006

P :\22-52\CCMO BART\BART General Documents\BART Analysis Procedures.doc 

# 4 should be considered technically feasible and the technological difficulty

evaluated as part of the economic analysis 8



# .

I t 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 guarantees 9



# .

S tep 3 - Evaluate Control Effectiveness

In step three, the remaining controls are ranked based on the control efficiency

at the expected emission rate (post-control) 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.

Step 5 - Evaluate Visibility Impacts

The fifth step requires a modeling analysis conducted with U.S. EPA-approved

models such as CALPUFF. The modeling protocol 10 

# , including receptor grid,

m eteorological data, and other factors used for this part of the analysis were

provided by the MDEQ. The model outputs, including the 98th percentile

deciview (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, are used to establish

the degree of improvement that can be reasonably attributed to each technology.

8 

# IBID

9 

# IBID

10 

# LADCO. March 21, 2006. Single Source Modeling to Support Regional Haze BART Modeling Protocol

.

# DRAFT – BART Analysis Procedures 8/29/2006

P :\22-52\CCMO BART\BART General Documents\BART Analysis Procedures.doc 

# 5 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 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. 11



# T o complete the BART process, the analysis must “establish enforceable emission limits that

reflect the BART requirements and requires compliance within a reasonable period of

time 12 

# .” Those limits must be developed for inclusion in t he 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

basis 13 

# ;” which could include the incorporation of other re gulatory requirements for the

source, including Compliance Assurance Monitoring (40 CFR 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

11 

# Federal Register 70, No. 128 (July 6, 2005): 39171.

12 

# Federal Register 70, No. 128 (July 6, 2005): 39172.

13 

# IBID.

# DRAFT – BART Analysis Procedures 8/29/2006

P :\22-52\CCMO BART\BART General Documents\BART Analysis Procedures.doc 

# 6 BART limit can “instead prescribe a design, equipment, work practice, operation standard, or

combination of these types of standards 14 

# .”

C ompliance with the BART emission limits will be required within 5 years of U.S. EPA

approval of the Michigan SIP.

14 

# IBID.

# 8/29/2006

P:\22-52\CCMO BART\BART General Documents\Streamline d BART Approach.doc Page 1 of 3 

# DRAFT BART Eligible Emission Units Subject to a Streamlined BART Analysis

1.0 Indurating Furnaces (PM Only)

The indurating furnaces are sources of three visibility impairing pollutants: NO

x 

# , SO 2 

# , and PM.

R elative to NO

x 

# and SO 2 

# , PM is not a major visibility impairing pollutant. Further, the

indurating furnaces are subject to the taconite Maximum Achievable Control Technologies

(MACT) standard [40 CFR Subpart RRRRR-NESHAPS: Taconite Iron Ore Processing] for the

PM emissions. In 40 CFR Part 51 Appendix Y paragraph IV.C., it states:

For VOC and PM sources subject to MACT standards, States may streamline the analysis

by including a discussion of the MACT controls and whether any major new technologies

have been developed subsequent to the MACT standards. We believe that there are many

VOC and PM sources that are well controlled because they are regulated by the MACT

standards, which EPA developed under CAA section 112. For a few MACT standards,

this may also be true for SO 2 

# . Any source subject to MACT standards must meet a l evel

that is as stringent as the best-controlled 12 percent of sources in the industry. Examples

of these hazardous air pollutant sources which effectively control VOC and PM emissions

include (among others) secondary lead facilities, organic chemical plants subject to the

hazardous organic NESHAP (HON), pharmaceutical production facilities, and

equipment leaks and wastewater operations at petroleum refineries. We believe that, in

many cases, it will be unlikely that States will identify emission controls more stringent

than the MACT standards without identifying control options that would cost many

thousands of dollars per ton. Unless there are new technologies subsequent to the

MACT standards which would lead to cost effective increases in the level of control,

you may rely on the MACT standards for purposes of BART .(emphasis added)

I t is clear from EPA’s guidance that they are encouraging states to develop a streamlined BART

analysis approach for sources regulated under a MACT. Since the Taconite 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.

A full BART analysis will be conducted for NO

x 

# and SO 2 

# where applicable.

2 .0 Taconite MACT Emission Units (PM-Only)

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 NO

x



# o r SO 2 

# . The Ore Crushing and Handling sources and the Fin ished 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].

# 8/29/2006

P:\22-52\CCMO BART\BART General Documents\Streamline d BART Approach.doc Page 2 of 3 

# 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 U.S. EPA guidance.

No further analysis will be required to establish BART for these sources.

3.0 Process Boiler MACT Emission Units (PM-Only)

Similarly to sources subject to the Taconite MACT, a taconite processing facility has many

process boilers subject to the Boiler MACT. Since the MACT standard was established recently

and will become effective in 2007, 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

U.S. EPA guidance.

No further analysis will be required to establish BART for these sources.

4.0 Process Boiler Emission Units (NO

x 

# and SO 2 

# )

I t is important to note that the emissions from the indurating furnaces represent the vast majority

of emissions of all visibility impairing pollutants, with the process boiler emission units typically

contributing less than 1% of the total emissions of each pollutant from sources that are subject to

BART. The emissions from all the remaining sources are small relative to the total 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. Each facility will conduct an

analysis for the remaining sources to demonstrate that the impact on visibility is negligible. The

procedure for the analysis is detailed in section 5 of this document. Assuming that the modeling

demonstrates that the sources have a negligible impact on visibility in Class I areas, no further

analysis will be required to establish BART for these sources.

5.0 Visibility Impact Modeling for Negligible Impacts

As described in sections 3 and 4 of this document, e ach facility contains several process boilers

that are assumed to have a negligible impact on visibility in Class I areas. In order to confirm

this assumption, each facility will conduct a modeling analysis to determine the impact of the

emissions from these sources on visibility in Class I areas. The analysis will consist of the

following:

A. Conduct air dispersion modeling for uncontrolled BART-eligible emission unit, as

described in sections 3 and 4 above. The modeling will be conducted based on the

guidance document Single Source Modeling to Support Regional Haze BART

Modeling Protocol dated March 21, 2006 as prepared by Lake Michigan Air

# 8/29/2006

P:\22-52\CCMO BART\BART General Documents\Streamline d BART Approach.doc Page 3 of 3



# Directors Consortium (LADCO). One modeling analysis will be conducted for each

facility.

B. Count the days with a 98 th 

# percentile (21 over 3-yrs, 7 each year) change in v isibility

greater than or equal to 0.05 deciviews (based on 10% of the facility threshold of 0.5

deciviews) at the modeled receptors with in the boundaries of each Class I area

assessed over the 3-year period 2002-2004.

C. If the modeled emission sources result in a 98 th 

# percentile change in visibility less

t han or equal to 0.05 deciviews, the point sources will be considered to not cause or

contribute to visibility impairment in Class I areas. Therefore, the existing operations

will be considered BART. No further analysis will be required to establish BART for

these sources.

D. If the modeled emissions result in a 98 th 

# percentile change in visibility greater than or

e qual to 0.05 deciviews, a full BART analysis will be conducted on the emission

sources.