Freeport-McMoRan Miami Inc. 

BART Analysis 

Miami, Arizona 

March 2014 

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TABLE OF CONTENTS 

1.0 INTRODUCTION ............................................................................................................ 1-1

2.0 BASELINE DATA .......................................................................................................... 2-1

2.1 Emission Units That Constitute the FMMI BART-Eligible Source ........................ 2-1

2.1.1 Electric Furnace ................................................................................... 2-1

2.1.2 Converters ........................................................................................... 2-2

2.2 Existing Control Measures ................................................................................... 2-3

2.2.1 Double-Contact Acid Plant ................................................................... 2-3

2.2.2 Vent Fume Scrubber ............................................................................ 2-4

2.2.3 Converter Mouth Covers ...................................................................... 2-4

2.2.4 Pollution Prevention ............................................................................. 2-5

2.3 BART-Eligible Baseline Emissions ...................................................................... 2-5

2.3.1 Acid Plant Tail Gas Stack .................................................................... 2-5

2.3.2 Vent Fume Stack ................................................................................. 2-7

2.3.3 Smelter Fugitives ................................................................................. 2-8

2.3.4 Summary of BART-eligible Baseline Emissions .................................. 2-8

3.0 BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS ...................................... 3-1

3.1 Identification of Available Retrofit Control Technologies ...................................... 3-1

3.1.1 Sulfur Dioxide ...................................................................................... 3-2

3.1.2 Nitrogen Oxides ................................................................................... 3-6

3.2 Elimination of Technically Infeasible Options ....................................................... 3-7

3.2.1 Sulfur Dioxide ...................................................................................... 3-8

3.2.2 Nitrogen Oxides ................................................................................... 3-8

3.3 Evaluation of Control Effectiveness of Remaining Control Technologies .......... 3-11

3.3.1 Sulfur Dioxide .................................................................................... 3-11

3.3.2 Nitrogen Oxides ................................................................................. 3-14

3.4 Evaluation of Impacts ......................................................................................... 3-15

3.4.1 Sulfur Dioxide .................................................................................... 3-15

3.4.2 Nitrogen Oxides ................................................................................. 3-21

3.4.3 Summary of Impacts Evaluation and Determination of Control Level 

Representing BART ........................................................................... 3-23

3.5 BART Determination .......................................................................................... 3-26

3.5.1 SO2 Emissions, Acid Plant Tail Gas Stack ........................................ 3-26

3.5.2 SO2 Emissions, Vent Fume Stack ..................................................... 3-26

3.5.3 NOX Emissions .................................................................................. 3-26

4.0 References .................................................................................................................... 4-1
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Appendices

Appendix A Baseline Emissions Calculation 

Appendix B Emission Reduction and Cost Effectiveness Calculations 

Appendix C Eric Partelpoeg, PhD, Analysis of SO2 Emissions Allocations 
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1.0 INTRODUCTION 

Freeport-McMoRan Miami Inc. (FMMI) requested that AMEC conduct a Best Available Retrofit 

Technology (BART) analysis for the sulfur dioxide (SO2) and nitrogen oxide (NOX) units that 

constitute the BART eligible source at FMMI’s copper smelting facility in Claypool, Arizona 

(Miami Smelter). AMEC’s BART analysis was conducted in accordance with the procedures 

contained in the U.S. Environmental Protection Agency’s (USEPA) “Guidelines for BART 

Determinations under the Regional Haze Rule” (BART Guidelines) under Title 40 of the Code of 

Federal Regulations (CFR) Part 51, Appendix Y. According to USEPA’s BART Guidelines, a 

case-by-case BART analysis consists of the following five basic steps: 

1. Identify All Available Retrofit Control Technologies, 

2. Eliminate Technically Infeasible Options, 

3. Evaluate Control Effectiveness of Remaining Control Technologies, 

4. Evaluate Impacts and Document the Results, and 

5. Evaluate Visibility Impacts. 

This report documents AMEC’s five-step BART analysis for the SO2 and NOX units that 

constitute FMMI’s BART-eligible source. Section 2 provides baseline data, including an 

overview of the SO2 and NOX units, current emission control practices, and baseline emissions. 

Section 3 identifies available retrofit control technologies; evaluates their technical feasibility, 

control effectiveness, and impacts; and concludes the analysis with recommendations for 

BART. References are listed in Section 4. 
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2.0 BASELINE DATA 

2.1 Emission Units That Constitute the FMMI BART-Eligible Source 

The emission units that constitute the FMMI BART-eligible source have previously been 

identified as FMMI’s Electric Furnace, Converters No. 2 through No. 5, and Double-Contact Acid 

Plant (78 FR 46142). As explained by USEPA’s BART Guidelines, “BART eligible sources” are 

those sources which have the potential to emit 250 tons or more of a visibility-impairing air 

pollutant, were put in place between August 7, 1962 and August 7, 1977, and whose operations 

fall within one or more of 26 specifically listed source categories. USEPA’s BART Guidelines 

set forth the following step-by-step process for identifying the emission units that constitute the 

BART-eligible source: 

1. Identify the emission units in the BART categories. 

2. Identify the start-up dates of those emission units. 

3. Compare the potential emissions from units identified in Steps 1 and 2 to the 250 

ton/year cutoff. 

4. Identify the emission units and pollutants that constitute the BART eligible source. 

Because FMMI’s Double-Contact Acid Plant is a control device for the reduction of SO2

emissions, it should not be identified as an emission unit in the “primary copper smelter” BART 

category in Step 1. As USEPA’s BART Guidelines explain: 

Sources are not BART-eligible if the only change at the plant during the relevant time 

period was the addition of pollution controls. For example, if the only change at a copper 

smelter during the 1962 through 1977 time period was the addition of acid plants for the 

reduction of SO2 emissions, these emission controls would not by themselves trigger a 

BART review. 

Accordingly, the emission units that constitute the FMMI BART-eligible source include only the 

Electric Furnace and Converters No. 2 through No. 5. FMMI’s Double-Contact Acid Plant will be 

addressed in this BART analysis as an existing control for the reduction of SO2 emissions. 

2.1.1 Electric Furnace 

The Electric Furnace is used as a slag (residual ferrosilicates and other compounds) separation 

device. It can potentially be used as a primary smelting vessel in the event that the Isa furnace 

goes down, but at a greatly reduced concentrate feed rate by comparison. The Electric Furnace 

receives a matte/slag mixture by launders (a refractory-lined channel used to convey molten 

metallurgical material by gravity) from the IsaSmelt® (Isa) furnace and slag returned from the 

converters by ladle. There are two separate launder systems. The purpose of the Electric 

Furnace is to separate the matte/slag mixture through retention time and density differences. 
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After the copper matte settles to the bottom of the Electric Furnace, the slag on the top of the 

bath is removed from the process by launder into slag pots and transferred by a Kress Hauler (a 

specialized truck) to the slag storage area. Matte is tapped from the Electric Furnace by 

launder into ladles and transported by crane to the converters. Six electrodes in the furnace 

maintain the bath temperature through resistive heating by passing a current through the slag 

layer. Electrode seals are installed on the furnace arch around each electrode to reduce air 

infiltration. A furnace off-take is located at the matte end of the furnace. Sonic water sprays 

cool the gas exiting the furnace via the off-take. The flue gases in the off-take are subsequently 

passed to the Double-Contact Acid Plant. 

The Electric Furnace normally uses electricity to keep the molten materials hot by resistive heat 

(passing electricity through the molten slag layer). Natural gas must periodically be used in 

certain situations (e.g., electrical outages, electrode breakage, cold furnace startup after the 

bath has been lowered to a level below the travel limit of the electrodes). Maximum natural gas 

usage during these scenarios is estimated at 15,000 standard cubic feet per hour 

(approximately 15 MMBtu/hr). Natural gas has not been used in the Electric Furnace since 

2008. 

Process off-gas from the Electric Furnace is captured in an off-take duct, cooled with water 

sprays, and then combined with Isa furnace and converter process off-gases that are routed to 

the Double-Contact Acid Plant, which serves as a control device for SO2 emissions. Captured 

process fugitive emissions from the Electric Furnace matte tapping launders/ladles, and Electric 

Furnace slag tapping launders/ladles are collected by the vent fume system. These gases pass 

through a scrubber for SO2 emissions control and then through wet electrostatic precipitators 

(WESP) prior to venting through the Vent Fume Stack. Emissions that are not captured by the 

process off-gas or vent fume capture systems exit through a roofline vent located above the 

furnace. 

2.1.2 Converters 

Converting of matte to blister copper occurs in four Hoboken Converters (No. 2 through No. 5). 

The Inspiration Converter (No. 1) is no longer operable. The conversion of matte to blister 

copper is performed by blowing air into the molten matte through tuyeres. Oxygen in the air 

reacts with iron and sulfur, producing slag and SO2 gas. The blast air rate can vary per copper 

charge. Silica is added to the bath to complete the slag formation process (converts the iron 

compounds to iron silicate). 

Converting is accomplished in a two-step process: a slag blow to remove iron and part of the 

sulfur, and a copper blow to remove the remaining sulfur to produce blister copper. The 

oxidation reactions are exothermic (heat producing) and “cold dope” can be added during the 

process to control the bath temperature. “Cold dope” consists of secondary or intermediate 

copper-containing solid materials (e.g., reverts, buttons, copper scrap, etc.). The normal 
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converter operations require three hot converters (two blowing and one in standby). Slag from 

the converters is returned to the Electric Furnace by ladle. Blister copper is transferred by ladle 

to one of the two anode furnaces (in batches) and on occasion to the mold vessel for temporary 

storage. 

Each Hoboken converter is equipped with an integral side flue at one end of the furnace for 

withdrawal of the off-gas. Shaped like an inverted "U", this flue, or siphon, rotates with the 

converter, as does the cylindrical duct to which it is connected. The cylindrical duct is 

connected by an airtight rotating joint to a fixed vertical duct that leads to the gas cleaning 

system. The Hoboken thus provides a direct link at all times between the converter and the gas 

off-take, regardless of its operating position. Hoboken converters generate only minimal fugitive 

emissions because the converter is operated under zero or slightly negative draft. At slight 

negative draft, air from outside of the converter is sucked into the mouth and exits through the 

converter siphon with the gas stream containing the SO2 generated during blowing. Slight 

negative or zero draft prevents fugitive emissions from the mouth of the converter. 

The converters do not require supplemental heat as the exothermic reaction in the vessel 

provides the necessary heat for the process. Natural gas must periodically be used in certain 

situations (e.g., to maintain heat when the converters are on standby, vessel pre-heat during 

cold startups, and burn-out of accretions in the dome section). Maximum natural gas usage 

during these scenarios is estimated at 20,000 standard cubic feet per hour (approximately 20 

MMBtu/hr) per converter based on data from 2007 through 2012. Normal natural gas use 

during the period is estimated at 11,400 standard cubic feet per hour (approximately 11 

MMBtu/hr) per converter. Natural gas is never used when the converter is processing matte. 

Process off-gas from the converters is collected and conveyed through the side-flue intake on 

each converter vessel. The process off-gas is cooled by water sprays, and then combined with 

Isa and Electric Furnace process off-gases before being routed to the Double-Contact Acid 

Plant for control of SO2 emissions. Uncaptured emissions exit through roofline vents located 

above the converters. 

2.2 Existing Control Measures 

2.2.1 Double-Contact Acid Plant 

The process off-gases from the Isa, Electric Furnace, and converters are combined and passed 

to radial flow scrubbers and a packed gas cooling tower. The gases are then passed through a 

set of primary and secondary WESPs and then vented to the Double-Contact Acid Plant. The 

Double-Contact Acid Plant utilizes the following unit operations to remove SO2 from the flue gas 

and produce sulfuric acid: 

 Drying tower; 
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 Four catalyst beds containing potassium-promoted vanadium pentoxide (V2O5) catalyst 

which converts SO2 to SO3; 

 Cesium-promoted V2O5 catalyst in the first and fourth catalyst beds to improve 

conversion of SO2 to SO3 when the bed temperatures are less than the activation 

temperature for the potassium-promoted catalyst. Catalyst volumes are based on 

vendor specification for the pressure drop and temperature of the beds; 

 Two SO3 absorption towers for sulfuric acid production; 

 Heat exchangers, strong acid coolers, and cooling water towers (evaporative & air-to-air) 

to dissipate heat from the Acid Plant; and 

 A natural gas-fired preheater to heat the converter beds during startup, or when catalyst 

bed temperatures fall below desired values (the Acid Plant Preheater is not BARTeligible). 

The gases from the Double-Contact Acid Plant are routed to the Tail Gas Stack. The Tail Gas 

Stack is equipped with a scrubber that is used as necessary to reduce SO2 concentrations in the 

tail stack to help ensure compliance with the SO2 limit imposed by New Source Performance 

Standards (NSPS) at 40 CFR 60 Subpart P. The scrubber currently uses magnesium oxide 

and/or magnesium hydroxide as a scrubbing agent, but also has the capability to use soda ash 

and caustic, with modifications. The scrubber typically operates approximately 440 hours per 

year. The Double-Contact Acid Plant is expected to achieve an overall SO2 removal efficiency 

of better than 99 percent. 

2.2.2 Vent Fume Scrubber 

A scrubber similar in design to the Tail Gas Stack Scrubber is used to remove SO2 from the flue 

gas captured by the Vent Fume Collection System. The scrubber is operated continuously and 

currently uses magnesium oxide and/or magnesium hydroxide as a scrubbing agent, but also 

has the capabilities to use soda ash and caustic, with modifications. The Vent Fume Scrubber 

is expected to achieve a removal efficiency of better than 60 percent. 

2.2.3 Converter Mouth Covers 

Actuated mouth covers are in the process of being installed on all four Hoboken Converters 

(Nos. 2 through 5). The covers are anticipated to improve the efficiency of the side flue intake 

capture system and reduce potential process off-gas leakage during blowing operations into the 

Converter Aisle. The mouth covers are also anticipated to reduce heat loss from the vessel by 

reducing infiltration in the converter mouth during blowing operations or in a ‘hot’ standby mode. 

The additional off-gas captured as a result of the mouth covers installation will be routed to the 

Double-Contact Acid Plant, reducing process fugitive SO2 emitted from the converters and 

through the roofline by 80 percent. The project will also result in more efficient operation of the 

converters, which in turn will result in a reduction of natural gas use required for burnout of 
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accretions and heating during standby. Therefore, a reduction in anticipated actual NOX

emissions is also expected although no attempt is made to quantify the NOX reduction in this 

analysis. 

2.2.4 Pollution Prevention 

The Electric Furnace typically uses electricity to provide needed heat. Use of the electrodes 

reduces the need for fossil fuels and is therefore considered to be a pollution prevention 

measure because it minimizes SO2 and NOX emissions from the Electric Furnace. Similarly, the 

converters do not require supplemental heat as the exothermic reaction in the vessel provides 

the necessary heat for the process. 

As noted previously, natural gas must be used in these vessels in certain situations. Natural 

gas is an inherently low-sulfur fuel compared to other available alternatives such as coal and oil. 

Combustion of natural gas also results in reduced NOX emissions compared to coal and oil. 

2.3 BART-Eligible Baseline Emissions 

Figure 1 presents a schematic of emissions from the various emission units located at FMMI. 

The figure illustrates that emissions from the units that constitute the BART-eligible source are 

vented through the Tail Gas Stack, the Vent Fume Stack, and roofline vents.1

 However, 

emissions from other units are also vented through the same release points. Because 

emissions testing has historically been performed at the release points for compliance 

demonstration purposes, potential emissions from the facility have traditionally been quantified 

by release point rather than by specific emission unit venting to the release point. Accordingly, 

for purposes of establishing baseline emissions for the units that constitute the BART-eligible 

source, the emissions from the release points must be speciated or allocated by emission unit. 

2.3.1 Acid Plant Tail Gas Stack 

BART-eligible baseline emissions for the Tail Gas Stack are based on actual emissions reported 

to the Arizona Department of Environmental Quality (ADEQ) for 2011 and 2012. The total SO2

emissions reported to ADEQ were measured by the Continuous Emissions Monitoring System 

(CEMS) installed on the Tail Gas Stack. The total NOX emissions were estimated based on the 

results of semi-annual stack tests performed on the Tail Gas Stack (i.e., a total of four stack 

tests). 

 

 

1

 Because USEPA’s BART Guidelines do not generally recommend that emissions reflecting periods of 

start-up, shutdown, and malfunction be used for visibility impact modeling, the Acid Plant Bypass Stack 

has not been included in the baseline emissions analysis. 

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The allocation of Tail Gas Stack SO2 emissions to the emission units is based on a sulfur 

balance of the material in the Isa, Electric Furnace, and converters. Data available for March 

and April 2013 were evaluated and determined to be representative of normal smelter 

operations (Partelpoeg, 2014). The analysis concluded that SO2 emissions are allocated as 

follows: 

 Isa = 67 percent, 

 Converters = 31 percent, and 

 Electric Furnace = 2 percent. 

The allocation of Tail Gas Stack NOX emissions to the emission units is based on analysis of 

natural gas consumption in the Isa, Electric Furnace, and converters. Natural gas consumption 

data available for 2007 to 2012 were evaluated and determined to be representative of normal 

smelter operations. The analysis concluded that NOX emissions are allocated as follows: 

 Isa = 99 percent, 

 Converters = 0.9 percent, and 

 Electric Furnace = 0.04 percent. 

These figures were applied to the reported Tail Gas Stack emissions of SO2 and NOX. The 

resulting emissions are presented in Table 2-1. 

2.3.2 Vent Fume Stack 

BART-eligible baseline emissions for the Vent Fume Stack are based on actual emissions 

reported to ADEQ for 2011 and 2012. The total SO2 emissions reported to ADEQ were 

measured by the CEMS installed on the Vent Fume Stack. The Vent Fume System does not 

collect process fugitive emissions from areas that would produce NOX emissions. 

Consequently, there are no baseline NOX emissions for the Vent Fume Stack. 

The allocation of Vent Fume Stack SO2 emissions to the emission units is based on an analysis 

of the open surface area of molten metal-bearing materials associated with the Isa and Electric 

Furnace (Partelpoeg, 2014). The analysis concluded that SO2 emissions are allocated as 

follows: 

 Isa = 39 percent, and 

 Electric Furnace = 61 percent. 

These figures were applied to the reported Vent Fume Stack emissions of SO2. The resulting 

emissions are presented in Table 2-1. 
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2.3.3 Smelter Fugitives 

BART-eligible baseline SO2 emissions were estimated based on average hourly emission rates 

(lb/hr) measured in 2012 from the roof monitors (Trinity, 2013). Direct measurements are 

preferred over the historic use of a mass balance approach and represent the best data 

available for estimating baseline emissions. BART-eligible baseline NOX emissions are derived 

from actual emissions reported to ADEQ for 2011 and 2012 and based on natural gas 

consumption in the smelter building and AP-42 emission factors for natural gas combustion. 

The roofline study of SO2 emissions showed that SO2 emissions are allocated as follows 

(Trinity, 2013): 

 Isa = 24 percent, 

 Converters = 53 percent, 

 Electric Furnace = 4 percent, and 

 Anode Furnaces = 19 percent. 

The allocation of fugitive NOX emissions to the emission units is based on analysis of natural 

gas consumption in the smelter. Natural gas consumption data available for 2007 to 2012 were 

evaluated and determined to be representative of normal smelter operations. The analysis 

concluded that NOX emissions are allocated as follows: 

 Isa = 4.1 percent, 

 Converters = 40.2 percent, 

 Electric Furnace = 1.6 percent, and 

 Anode Furnaces = 54.1 percent. 

These figures were applied to the reported fugitive emissions of SO2 and NOX. The resulting 

emissions are presented in Table 2-1. 

2.3.4 Summary of BART-eligible Baseline Emissions 

In accordance with USEPA BART Guidelines, baseline emissions should reflect a realistic 

depiction of anticipated annual emissions for the units that constitute the BART-eligible source. 

As quantified per the discussion above, the annual BART-eligible baseline emissions are 

summarized in Table 2-1. A more detailed calculation table is provided in Appendix A. 
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Table 2-1. Calculated Baseline Emissions for the FMMI BART-Eligible Source 

 SO2 (tpy) NOX (tpy) 

Emission Point 

Electric 

Furnace Converters Total 

Electric 

Furnace Converters Total 

Acid Plant Tail Gas Stack 10.9 344 355 0.1 1.7 1.8 

Vent Fume Stack 316 - 316 - - - 

Smelter Process Fugitives 41.3 109 151 0.8 19.1 19.9 

Total 369 453 822 0.9 20.8 21.7 
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3.0 BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS 

USEPA’s visibility regulations at 40 CFR 51 Subpart P define “BART” as follows: 

Best Available Retrofit Technology (BART) means an emission limitation based on the 

degree of reduction achievable through the application of the best system of continuous 

emission reduction for each pollutant which is emitted by . . . [a BART-eligible source]. 

The emission limitation must be established, on a case-by-case basis, taking into 

consideration the technology available, the costs of compliance, the energy and non-air 

quality environmental impacts of compliance, any pollution control equipment in use or in 

existence at the source, the remaining useful life of the source, and the degree of 

improvement in visibility which may reasonably be anticipated to result from the use of 

such technology. 

According to USEPA’s BART Guidelines at 40 CFR 51 Appendix Y, design, equipment, work 

practice, operation standard, or combination of these types of standards can be established as 

BART when technical or economic limitations in the application of measurement methodologies 

make conventional emission limits infeasible. 

The five basic steps of a case-by-case BART analysis as set forth in USEPA’s BART Guidelines 

are: 

Step 1: Identify all available retrofit control technologies; 

Step 2: Eliminate technically infeasible options; 

Step 3: Evaluate control effectiveness of remaining control technologies; 

Step 4: Evaluate impacts and document the results; and 

Step 5: Evaluate visibility impacts. 

3.1 Identification of Available Retrofit Control Technologies 

It is important to recognize that FMMI’s smelting process is unique in the United States. No 

other actively operating or decommissioned primary copper smelter in the US uses or used the 

IsaSmelt® process. As a result, neither the USEPA’s RACT/BACT/LAER Clearinghouse (RBLC) 

nor air permits issued to other primary copper smelters provide information specific to the 

technology employed at FMMI. Nevertheless, the production processes used at other primary 

copper smelters are analogous and emission control determinations for these processes may 

be transferable. Similarly, emission controls used at other industry sources such as coal-fired 

power plants and sulfuric acid production facilities may be transferable. 

To identify potential BART options, AMEC relied on USEPA’s RBLC, air permits for facilities 

likely to have analogous processes, and technical journals such as that published by the Air & 
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Waste Management Association (AWMA). As such, the analysis is a reasonably 

comprehensive compilation of potentially available retrofit control technologies. 

3.1.1 Sulfur Dioxide 

The following identifies both available retrofit control technologies and other retrofit control 

measures that could possibly reduce SO2 emissions from the emission units that constitute the 

FMMI BART-eligible source. A retrofit control measure could include, for example, the improved 

capture of SO2 emissions that can then be routed to an existing control device such as the Vent 

Fume Scrubber or the Acid Plant. 

3.1.1.1 Absorption 

Absorption methods for SO2 control include wet scrubbers (such as those used at FMMI), dry 

scrubbers (spray dryer absorbers or SDA), and dry sorbent injection (DSI). All of these 

technologies rely on control of sulfur dioxide through an acid-base reaction that occurs in the 

flue gas. SO2 is acidic in nature. Absorption techniques utilize bases as the reagent (typically 

alkaline minerals such as lime or caustic soda) in a neutralization reaction that produces a salt. 

This salt is precipitated and removed from the combustion gases for off-site disposal. 

Wet Scrubbers

The advantage of a wet scrubber system is that it is capable of higher SO2 removal rates 

(attaining higher levels of SO2 removal when there is heavy loading) than alternative absorption 

technologies. The disadvantages are that the construction materials are more costly and the 

waste products result in environmental impacts (the need for wastewater handling and 

treatment) and often require special handling. Wet scrubber systems are more complex (and 

thus more expensive) to operate. 

Wet scrubbers can use a variety of alkaline minerals for the neutralization reaction. The most 

common uses slaked lime or limestone as the reagent. Another uses a sodium-based reagent 

such as sodium hydroxide. The advantage of the lime scrubber is the lower cost of the reagent; 

however, large amounts of liquid and solid waste are generated. The sodium-based scrubber 

generates less waste; however, this waste is more difficult to treat. Magnesium-based 

reagents, such as those presently used at FMMI, are another option. 

In these systems, the flue gas is passed through a reaction vessel and passed through the 

reagent which neutralizes the acid gases. The reaction kinetics favor neutralization of sulfurbased acid gases and mists over any neutralization of halogenated and organic acids. Some 

reagent is constantly purged from the reaction vessel (blowdown) and replenished with fresh 

reagent (makeup) to maintain the acid gas neutralizing capabilities. The treatment and disposal 

of this liquid waste stream must be considered in the design and costing of the system. 
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Due to the increased pressure drop across the wet scrubber, a new induced draft fan (ID fan) is 

usually required in retrofit situations. The increased draft losses caused by the pressure drop 

across the wet scrubber must be considered in selecting the ID fan and any increases in 

backpressure at the precipitator must be evaluated. In many instances a new stack must also 

be considered. 

All materials of construction downstream of a wet scrubber must be constructed of very 

corrosion-resistant material, such as stainless steel. Moreover, the addition of moisture to the 

flue gas can drastically reduce flue gas temperatures, and may require a reheating process 

before the gas leaves the stack to avoid excess condensation inside the stack. 

Dry Scrubbers (Spray Dry Absorbers)

Dry scrubbers rely on reagents sprayed into the scrubber reaction vessel with minimal water so 

that the byproduct is dry and can be handled using conventional ash handling equipment. The 

scrubber, commonly referred to as a Spray Dryer Absorber (SDA), removes SO2 from the flue 

gas by injecting atomized lime slurry into the scrubber vessel via very fine nozzles. The waste 

product from the scrubber is dry lime because most of the liquid is evaporated in the vessel. It 

is a common misconception to consider a dry scrubber as having no water in the process, when 

in fact this technology requires water to produce the lime slurry. The evaporated water can 

cause a prominent water vapor plume from the stack under most weather conditions. 

Like wet scrubbers, dry scrubbers rely on the use of alkaline minerals (reagent) to neutralize 

acid gases such as SO2. In these systems, a small amount of water is mixed with the reagent to 

form a slurry which is atomized and sprayed into the flue gas. The acid gases react with the 

alkaline material in the slurry and are neutralized. The sensible heat of flue gas vaporizes the 

water and the neutralized material, now a solid, is removed by a downstream PM control device. 

Factors affecting this neutralization process include quality of the slurry, droplet size of the 

atomized slurry, flue gas temperature, and contact time of the flue gas with the atomized slurry. 

To a substantial degree, the size of the reaction vessel determines the retention time. Due to 

increase in the volumetric capacity of the flue gas from vaporization of water in the slurry, a 

larger reaction vessel is required for a dry scrubber than a wet scrubber to effect the same 

contact time of the flue gas. 

In normal operation a dry scrubber increases the particulate matter (PM) load of the flue gas, 

thereby requiring a location upstream of a PM control device. This, along with the need for a 

larger reaction vessel, makes retrofitting a dry scrubber at an existing facility generally more 

difficult than a wet scrubber. In the specific case of FMMI, there are no attractive retrofit 

applications for a dry scrubber. The primary off-gas control includes the acid plant and its 

associated existing wet scrubber, both of which are located downstream of PM control 

equipment. The vent fume system includes a wet scrubber located upstream of PM control 

equipment, and as such a dry scrubber would effectively serve as a replacement technology for 
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the wet scrubber rather than a retrofit technology. In the case of vent fume wet scrubber 

replacement, the additional PM loading would also require an upgrade of the PM control device. 

Generally, dry scrubbers are not as efficient as wet scrubbers for the removal of sulfur-based 

acid gases, although they typically achieve at least 80 percent removal rates in traditional 

applications with high levels of SO2 in the flue gas. Dry scrubbers can achieve 80-90% 

reductions with the addition of a baghouse for typical applications with significant sulfur loading. 

A cake of unreacted reagent accumulates on the bags, offering additional removal or requiring 

less reagent than a dry scrubber/ESP combination. 

Dry Sorbent Injection

Dry sorbent injection (DSI) has been used in mostly research-type applications as a lesser cost 

option to retrofitting existing coal fired boilers with flue gas desulfurization (FGD) requirements. 

Like scrubber technologies, DSI neutralizes the acid gases through the use of alkaline reagents. 

DSI injects the reagent directly into the furnace or flue gas path. However, even distribution of 

the reagent can be difficult to achieve and contact time with the reagent is reduced compared to 

wet and dry scrubbing techniques. Reagent injection into the furnace allows for more residence 

time for the reagent. Potential side effects may include slagging, and corrosion or erosion of 

boiler internals. Injection of reagent just prior to the PM control device is the most common 

option employed. However, significantly reduced contact time can result in lower acid gas 

removal efficiencies and overloading of existing PM control devices. 

In this type of system, dry reagent is conveyed from a storage silo through a blower/metering 

system. A short contact time is expected and the PM loading into the PM control device is 

increased considerably. The increased PM loading often requires further control of PM. In the 

specific case of FMMI, there are no attractive retrofit applications for DSI. The primary off-gas 

control includes the acid plant and its associated existing wet scrubber, both of which are 

located downstream of PM control equipment. The vent fume system includes a wet scrubber 

located upstream of PM control equipment, and as such a dry scrubber would effectively serve 

as a replacement technology for the wet scrubber. In the case of a replacement of the vent 

fume wet scrubber, the additional PM loading would also require an upgrade of the PM control 

device. 

Amine Systems

A regenerable aqueous dimethylaniline (DMA) reagent was used to control SO2 emissions from 

the reverberatory furnace located at the former Ajo Smelter in Ajo, Arizona. The absorbed gas 

was dried by sulfuric acid, compressed, and condensed to a liquid form. Liquid SO2 was stored 

under pressure and then vaporized to supplement the acid plant operation whenever necessary. 

CANSOLV® is a similar patented technology that uses an aqueous amine reagent to achieve 

selective absorption of SO2 from a variety of gas streams. The technology has been used to 
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reduce SO2 emissions from acid plant tail gas at a lead smelter in India. An amine scrubber 

system is incompatible with the existing scrubber systems in use at FMMI and would therefore 

constitute a replacement technology for the Acid Plant Tail Gas Stack and for the Vent Fume 

Stack. 

Hydrogen Peroxide Systems

Hydrogen peroxide reagent can be used in scrubbers to convert SO2 directly to sulfuric acid, 

which is recycled to the acid plant. Outotec’s Peracidox® process is an example that has been 

applied to sulfuric acid plants. Tail gas is washed in a two-stage scrubber with dilute sulfuric 

acid in which the hydrogen peroxide is dissolved. The hydrogen peroxide is introduced into the 

acid circuit of the first scrubbing stage at a stoichiometric rate proportional to the SO2 to be 

removed. The scrubber overflow consists of dilute sulfuric acid with an optimum concentration 

50 percent sulfuric acid by weight. The sulfuric acid is introduced into the final or intermediate 

absorber of the main acid plant in place of process water. A hydrogen peroxide scrubber 

system is incompatible with the existing scrubber systems in use at FMMI and would therefore 

constitute a replacement technology for the Acid Plant Tail Gas Stack and for the Vent Fume 

Stack. 

3.1.1.2 Sulfuric Acid Plant 

A sulfuric acid plant is an available control technology that is commonly used to reduce SO2

emissions from smelters, as is the case at FMMI which specifically uses a double-contact 

process. Process off-gases must first be cleaned to remove impurities such as PM and water 

vapor. Because dust can fill the voids in the catalyst material and reduce its activity, cyclones, 

scrubbers, or electrostatic precipitators are used to remove the material before the process offgas enters the acid plant’s drying tower. 

Available retrofit control technologies for SO2 emissions include improvements in the efficiency 

of the existing Acid Plant’s conversion of SO2 to SO3. In most cases, the improvements would 

be most readily addressed by equipment replacement rather than retrofits, such as converter 

beds, heat exchangers, and SO3 coolers. Cesium-promoted catalyst can also be charged to the 

converter beds, although FMMI is already using cesium-promoted catalyst in the vendorrecommended first and fourth beds. The volume of cesium-promoted catalyst currently used by 

FMMI is based on vendor specifications for the current pressure drop and temperature of the 

catalyst beds. Greater volumes of cesium-promoted catalyst can only be achieved with 

additional upgrades of the acid plant, such as increased fan capacity to address increased 

pressure drop and increased cooling capacity to ensure the bed temperatures are in the 

activation range of the cesium catalyst. 
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3.1.1.3 Enhanced Capture 

Enhanced capture of process fugitive emissions is a control measure that can reduce pollutant 

emissions. For example, the roofline above the Converter Aisle and above the Electric Furnace 

can be reconfigured to capture process fugitive emissions and route the captured emissions to 

an existing control device or a new control device. 

Additional capture of Electric Furnace fumes at the matte tapping hood could also be used. 

Select leakages in the existing vent fume system inlet ductwork would be eliminated and active 

control used to increase ventilation from the existing active matte tapping hoods by 20 percent. 

The captured SO2 would be passed to the existing vent fume scrubber resulting in reduced SO2

emissions. 

3.1.1.4 Pollution Prevention 

As noted earlier in this report, SO2 emissions can be reduced by employing a low-sulfur fuel 

such as natural gas and FMMI is actively utilizing this SO2 control measure. Reduction in sulfur 

content of smelter raw materials would also be a means of reducing SO2 emissions. The raw 

materials are received from a number of different locations and the sulfur content of the metalbearing minerals received cannot be readily reduced. Furthermore, the process at FMMI is 

configured in part based on the sulfur content of raw materials (i.e., smelting is used to extract 

copper from sulfide ores). For example, the converters are configured to rely on the exothermic 

reaction of sulfur in the vessels. 

3.1.2 Nitrogen Oxides 

The following identifies both available retrofit control technologies and other retrofit control 

measures that would reduce NOX emissions from the FMMI BART-eligible source. Because no 

NOX controls have been implemented at primary copper smelters, candidate NOX controls were 

selected as those which are technically demonstrated and commercially available for 

combustion sources. 

3.1.2.1 Combustion Modifications 

Combustion modifications for NOX control consist of various techniques to limit NOX formation at 

the combustion source. Such modifications are arranged to carefully control combustion 

temperature, available oxygen, and flame turbulence and residence time at peak temperatures. 

Common combustion controls include low NOX burners, staged combustion, low-excess-air, 

burners out-of-service, and flue gas recirculation. These are common technologies employed in 

boilers, but are impractical and infeasible for use in the Electric Furnace and Converters. The 

burners used at FMMI are long pole-style burners where natural gas and oxygen are added at 

the head, blended down the length of the shaft, and combusted at the tip. The burners must be 

of retractable design to be quickly inserted and removed from the vessels. The burners are 
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designed to meet the temperature specifications required for proper operation of the Converters 

and Electric Furnace. 

3.1.2.2 Selective Non-Catalytic Reduction 

SNCR uses injection of a NOX reducing reagent, either anhydrous ammonia (NH3), aqueous 

ammonium (NH4

+

), or urea (NH2C(O)H2), into hot flue gas. The reducing reagent is injected into 

the flue gas where the flue gas temperature is between 1600°F and 2100°F. The high gas 

temperatures support high chemical reaction rates so that a catalyst is not required. The 

reagent reduces NOX to nitrogen and water. In traditional boiler installations, SNCR systems 

often have multiple injection levels to account for shifting of the optimal reaction temperature 

window (1600°F - 2100°F) as the boiler load changes. This arrangement ensures maximum 

NOX reduction over varying boiler loads and as the furnace heat exchange characteristics vary. 

With SNCR, placement of the reagent injection probes is important. If reagent is injected at a 

point where the flue gas temperature is greater than 2100°F, ammonia or urea will react with 

oxygen to form additional NOX. At flue gas temperatures less than 1600°F, excessive/ 

unreacted ammonia passes through the ductwork and is discharged out the stack as ammonia 

slip. 

3.1.2.3 Selective Catalytic Reduction 

SCR uses a combination of reducing reagent and a catalyst placed in the flue gas stream to 

promote the NOX reduction reaction. In a full-scale SCR system, the flue gas is ducted through 

a separate reactor that contains a catalyst. Traditional SCR using vanadium-titanium catalysts 

requires flue gas temperatures of 550°F to 750°F for efficient NOX reduction. Zeolite catalysts 

are available which can operate at temperatures up to 1130°F. With SCR, either aqueous 

ammonia (after vaporization) or anhydrous ammonia is injected upstream of a catalyst reactor 

that is placed in a location where the gas temperature is in the optimal range. The ammonia 

reacts with NOX on the catalyst to form nitrogen gas and water. The catalyst is installed in the 

reactor in layers. Catalysts can be installed with a specified number of catalyst layers with 

provisions for adding future layers if necessary. While SCR systems have the potential for high 

NOX removal, there are inherent operating concerns associated with their use such as plugging 

or poisoning of the catalyst, high dependence on proper flue gas temperature for NOX reduction, 

and some emissions of unreacted ammonia (“ammonia slip”). SCR is capable of NOX reduction 

efficiencies as high as 80 percent with low corresponding ammonia slip concentrations. 

3.2 Elimination of Technically Infeasible Options 

Most of the identified SO2 and NOX control measures are technically feasible, although not in all 

possible configurations. For example, absorption techniques are not technically feasible 

upstream of the Acid Plant. The reduction in SO2 to the Acid Plant would render the Acid Plant 

ineffective and would additionally require upgrades to the PM control devices upstream of the 
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Acid Plant. In contrast, a dry scrubber would be technically feasible for the control of captured 

emissions from a reconfigured converter aisle roofline. 

3.2.1 Sulfur Dioxide 

3.2.1.1 Concentrate Sulfur Content 

The pollution prevention measure of reducing the sulfur content of smelter raw materials is not 

technically feasible for FMMI. The concentrated ores available to FMMI are sulfide 

concentrates, and the smelting process is used to separate copper from the ferrous and sulfide 

components. While smelting sulfide concentrates, most of the energy needed to heat and melt 

the feed materials is derived from the reaction of oxygen with the sulfur and iron in the 

concentrate. Because the smelter is specifically designed to process sulfide concentrates, a 

reduction in the sulfur content is not technically feasible. 

3.2.1.2 Absorption 

Absorption techniques would not be technically feasible in a position upstream of the Acid Plant. 

Such placement of absorbers, regardless of technology, would render the Acid Plant to be 

ineffective. Furthermore, dry scrubbers and dry sorbent injection would require a 

reconfiguration of PM control devices upstream of the Acid Plant. Dry absorption, amine 

absorption, and hydrogen peroxide absorption techniques located downstream of the acid plant 

would constitute a replacement of the existing Tail Gas Scrubber. While these techniques are 

feasible downstream of the acid plant, they provide less effective control than the existing Tail 

Gas Scrubber and consequently the existing wet scrubber is a better control option. Therefore, 

dry absorption, amine absorption, and hydrogen peroxide absorption techniques located before 

and after the acid plant are not considered further. 

Similarly, the use of dry absorption techniques in the Vent Fume System would require a 

reconfiguration of PM control devices. Such a retrofit, while not technically infeasible, is 

impractical in comparison to retrofits that focus on the existing wet scrubber. Furthermore, dry 

absorption, amine absorption, and hydrogen peroxide absorption techniques provide less 

effective control than the existing Vent Fume Scrubber and consequently the existing wet 

scrubber is a better control option. Therefore, dry absorption techniques located in the Vent 

Fume System are not considered further. 

3.2.2 Nitrogen Oxides 

3.2.2.1 Combustion Modifications 

The use of low-NOX combustion techniques is not technically feasible for FMMI. Because the 

Electric Furnace is a metallurgical reactor that utilizes a unique combustion method, none of the 

conventional NOX combustion controls are feasible. The efficiency of the slag separation 
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process in the Electric Furnace is highly dependent upon carefully controlled conditions which 

cannot be altered without severely affecting the process. Furthermore, the Electric Furnace is 

predominantly operated using electrical resistance. Natural gas has not been used in the 

Electric Furnace since 2008. Similarly, the converter requirements for heating and burnout are 

such that conventional NOX combustion controls are not feasible. 

Low NOX burners work by reducing the oxygen level in the primary combustion zone to limit fuel 

NOX formation, reducing the flame temperature to limit thermal NOX formation, and the 

residence time at peak temperature to reduce thermal NOX formation. In the case of natural 

gas, which has a very low fuel nitrogen content, strategies focus on reducing thermal NOX

formation. The thermal NOX reduction strategies, particularly flame temperature reduction, is 

infeasible for the units to operate at specification. In the case of the Electric Furnace, the slag 

separation requirements are such that the use of low NOX burners is not feasible. Similarly, the 

burnout requirements in the converters are such that the use of low NOX burners is not feasible. 

Likewise, other NOX reduction strategies that involve the mixing and dilution of combustion 

gases with air and flue gas to reduce thermal NOX formation (such as staged combustion and 

flue gas recirculation) are not feasible technologies. 

3.2.2.2 Selective Non-Catalytic Reduction 

SNCR has been successfully applied to a number of traditional (boiler/furnace) combustion 

systems; however, it is not technically feasible upstream of the Acid Plant. The extremely high 

flue gas sulfur content and the layout of the flue gas train from the radial flow scrubbers through 

the Acid Plant are the principal reasons. SO3/H2SO4 present at 5,000 to 8,000 ppm in the offgas ahead of the Acid Plant will react with ammonia slip to form condensed ammonium 

sulfate/ammonium bisulfate (AS/ABS) as the flue gas cools. Equipment fouling, pluggage, and 

corrosion from AS/ABS formation has plagued high sulfur applications of SCR and SNCR where 

ammonia slip is not strictly limited to less than 1-2 ppm (Radian, 1991). 

Based on 5 ppm ammonia slip and 5,000 ppm SO3 in the flue gas, thermodynamic calculations 

show that the upper temperature threshold for AS/ABS formation is approximately 585°F (TRC, 

1995). As the gas is cooled below this threshold, rapid reaction of ammonia with SO3 occurs to 

form condensed AS/ABS. Condensation would occur within the long run of ductwork leading to 

the radial flow scrubbers, resulting in rapid plugging of the ductwork with solid/liquid AS/ABS. In 

addition, rapid corrosion and destruction of the existing carbon steel ductwork would be 

expected because ammonium bisulfate is highly acidic. 

There are a number of additional technical reasons for eliminating SNCR from consideration, 

including adverse effects of ammonia slip on the gas cleaning and sulfuric acid processes. For 

these reasons, and because of the unavoidable downstream AS/ABS fouling from this 

application, SNCR is not technically feasible as a NOX control upstream of the Acid Plant. 
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A tail-end SNCR system would avoid most of the identified concerns; however, the energy 

required for flue gas reheat to achieve temperatures in the range of 1600°F to 2100°F would be 

excessive by comparison to a tail-end SCR system. A review of RBLC controls on nitric acid 

and sulfuric acid plants reveals that no plants are equipped with SNCR systems. Rather, SCR 

systems are instead used and because SCR systems achieve greater NOX removal than SNCR 

systems, SNCR systems are not further evaluated for the Acid Plant Tail Gas Stack. 

Similarly, the ideal temperature window of 1600°F to 2100°F would not exist in the ductwork of a 

reconfigured roofline used to enhance capture of process fugitive emissions. The flue gas 

would need to be reheated for the SNCR reaction to proceed. The need to reheat flue gas does 

not alone render SNCR as technically infeasible. However, the energy required would be 

excessive by comparison to a SCR system and because SCR systems achieve greater NOX

removal than SNCR systems, SNCR systems are not evaluated further. 

3.2.2.3 Selective Catalytic Reduction 

SCR could theoretically be retrofitted in several locations ahead of the Acid Plant where the flue 

gas is at the optimal SCR operating temperature. The optimum location would fall between the 

waste heat recovery boiler and the ESP. However, the SCR catalysts will not withstand the high 

SO2 levels in these areas. The maximum SO2 content for which SCR could be applied is in the 

range of 2,000 ppm. The flue gas SO2 concentration ahead of the Acid Plant is typically much 

greater than 2,000 ppm. Furthermore and as noted for SNCR, ammonia slip concentrations 

would need to be well maintained at levels less than 2 ppm to prevent AS/ABS fouling problems 

ahead of the Acid Plant. 

SCR is technically feasible downstream of the existing Acid Plant Tail Gas Scrubber, just 

upstream of the stack. In this area, a “tail-end” SCR configuration would be required. This 

configuration would require a heater to reheat the flue gas temperature in the range of 120°F to 

160°F up to a minimum of 600°F before treatment with SCR. To lessen the overall cost of the 

system, a recuperative heat exchanger is usually applied to recover heat from the SCR exit flue 

gas while simultaneously heating the SCR inlet flue gas. The RBLC does indicate the 

installation of an SCR unit on a sulfuric acid plant, and therefore a tail-end SCR configuration is 

retained as a technically feasible option. 

SCR is not feasible for a reconfigured roofline vent system because of the particulate matter 

loading in the flue gas. The particulate loading damages the SCR catalyst through erosion, 

thermal sintering and particulate deposition. High levels of alkali aerosols, calcium and 

potassium in particular, have been shown to irreversibly poison SCR catalyst and dramatically 

reduce its performance. Therefore, SCR is not a feasible technology for reducing NOX emitted 

to the roofline vent. 
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3.3 Evaluation of Control Effectiveness of Remaining Control Technologies 

The remaining control measures and technologies identified as technically feasible could 

potentially be implemented in a variety of ways at FMMI. AMEC identified feasible scenarios for 

control measures and provides an analysis of control effectiveness (in terms of achievable 

emissions reductions) for each scenario. 

3.3.1 Sulfur Dioxide 

Retrofits to the existing wet scrubbers, the existing acid plant, and control measures that include 

the capture of additional emissions and control of those emissions at existing or new control 

devices are evaluated below. 

The following control measures are considered in the following sections, ranked by the 

calculated emission reduction from BART-eligible baseline emissions: 

 Upgrade Acid Plant Tail Gas Scrubber to caustic reagent (348 tpy), 

 Upgrade Vent Fume Scrubber to caustic reagent (299 tpy), 

 Continuously operate existing Acid Plant Tail Gas Scrubber (281 tpy), 

 Upgrade Acid Plant (266 tpy), 

 Capture process fugitive emissions at Converter Aisle Roofline and install New Wet 

Scrubber (56.2 tpy), 

 Capture process fugitive emissions at Electric Furnace Roofline and install New Wet 

Scrubber (34.8 tpy), 

 Increase Acid Plant Tail Gas Scrubber operation (<31 tpy), 

 Improve capture of process fugitive emissions from Electric Furnace Matte Tapping 

Hood and use existing Vent Fume Scrubber (1.0 tpy). 

Detailed calculations of emission reductions are provided in Appendix B. 

3.3.1.1 Upgrade Acid Plant Tail Gas Scrubber to Caustic Reagent 

As shown in Table 2-1, BART-eligible baseline SO2 emissions through the Tail Gas Scrubber 

are estimated to be 355 tpy. Reconfiguring the scrubber to use a caustic reagent is expected to 

improve the control efficiency to better than 98 percent. The calculation of SO2 reduction from 

baseline requires a calculation of the SO2 loading to the scrubber inlet. A performance test of 

the scrubber showed a control efficiency of 71 percent as currently operated. As noted 

previously, the scrubber is used as necessary to meet SO2 limits imposed by the NSPS at 40 

CFR 60 Subpart P, operating 440 hours per year on average. Thus, BART-eligible baseline 

SO2 loading to the scrubber amounts to 368 tpy. SO2 emissions from the upgraded scrubber 
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would be 7 tpy, assuming a control efficiency of 98 percent can be achieved. BART-eligible 

baseline SO2 emissions would be reduced from 355 tpy to 7 tpy, resulting in a reduction of 

BART-eligible baseline SO2 emissions by 348 tpy (see Table B-1 for the detailed calculation). 

3.3.1.2 Upgrade Vent Fume Scrubber to Caustic Reagent 

The existing scrubber with magnesium hydroxide slurry reagent has an estimated control 

efficiency in the range of 60 to 65 percent, with BART-eligible baseline SO2 emissions through 

the vent fume system estimated to be 316 tpy as shown in Table 2-1. Reconfiguring the 

scrubber to use a caustic reagent is expected to improve the control efficiency to better than 98 

percent. 

The calculation of SO2 reduction from baseline requires a calculation of the SO2 loading to the 

scrubber inlet. A performance test of the scrubber showed a control efficiency of 62 percent as 

currently operated. Thus, BART-eligible baseline SO2 loading to the scrubber amounts to 832 

tpy. SO2 emissions from the upgraded scrubber would be 17 tpy, assuming a control efficiency 

of 98 percent can be achieved. This, BART-eligible baseline SO2 emissions would be reduced 

from 316 tpy to 17 tpy, resulting in a reduction of BART-eligible baseline SO2 emissions by 299 

tpy (see Table B-2 for the detailed calculation). 

3.3.1.3 Continuously Operate Acid Plant Tail Gas Scrubber 

The existing scrubber with magnesium hydroxide slurry reagent has an estimated control 

efficiency in the range of 70 to 75 percent. As noted previously, the scrubber is used as needed 

to help ensure compliance with the NSPS Subpart P limit and is operated 440 hours per year on 

average. Baseline SO2 emissions through the Tail Gas Stack are estimated to be 355 tpy 

based on intermittent operation of the Tail Gas Scrubber. Operating the Tail Gas Scrubber 

continuously would require capital expenditure for upgrades to the magnesium hydroxide 

handling system and construction of a new stack made of materials that would be compatible 

with the continuous use of the existing scrubber. Continuous operation would also increase 

operating and maintenance expenditures with the purchase of additional reagent and the 

handling of additional sludge. 

The calculation of SO2 reduction from baseline requires a calculation of the SO2 loading to the 

scrubber inlet. A performance test of the scrubber showed a control efficiency of 71 percent as 

currently operated. Thus, baseline SO2 loading to the scrubber amounts to 368 tpy. SO2

emissions from continuous operation of the scrubber would be 74 tpy. Baseline SO2 emissions 

would be reduced from 355 tpy to 74 tpy, resulting in a reduction of baseline SO2 emissions by 

281 tpy (see Table B-3 for the detailed calculation). 
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3.3.1.4 Upgrade Acid Plant 

The existing acid plant would be upgraded for additional capacity, including additional catalyst 

loading, and gas and acid cooling. Additional cooling facilitates reduced SO2 emissions through 

improved plant operation and allows for increased use of cesium-promoted catalyst. The 

amount of cesium catalyst added to the first pass would be increased to 35 percent of the 

catalyst load, while the amount of cesium catalyst added to the fourth pass would be increased 

to 100 percent of the catalyst load for improved conversion. A new maintenance shop would be 

required for layout reasons as the existing shop would need to be demolished to accommodate 

the new acid plant equipment. 

As shown in Table 2-1, BART-eligible baseline SO2 emissions through the Tail Gas Scrubber 

are estimated to be 355 tpy. This control measure, as addressed in this section, would not 

include an upgrade of the Tail Gas Scrubber. The Acid Plant upgrade would reduce the SO2

loading to the Tail Gas Scrubber by 70 to 80 percent. Assuming a 75 percent reduction of SO2

loading to the Tail Gas Scrubber, the Acid Plant upgrade would reduce BART-eligible baseline 

SO2 emissions by approximately 266 tpy (see Table B-4 for the detailed calculation). 

3.3.1.5 Capture Process Fugitive Emissions at Converter Aisle Roofline, Install New Wet 

Scrubber 

As shown in Table 2-1, BART-eligible baseline SO2 emissions through the Converter Aisle 

Roofline are estimated to be 109 tpy. The reconfigured roofline would capture an expected 84.7 

percent of SO2 emissions. The Acid Plant does not have the capacity to handle the additional 

captured volume of air, and even if it had the capacity, the additional air would dilute the SO2

concentration entering the Acid Plant, rendering it less effective. Similarly, the Vent Fume 

Scrubber would not have the capacity to handle the additional volume. Therefore, a new wet 

scrubber would be constructed to treat the captured emissions. The new wet scrubber would 

reduce these captured SO2 emissions to a concentration of 1 ppm or less, equivalent to a 

controlled emission rate of 53 tpy. BART-eligible baseline SO2 emissions would be reduced by 

56 tpy (see Tables B-5 and B-6 for the detailed calculation). 

3.3.1.6 Capture Process Fugitive Emissions at Electric Furnace Roofline, Install New Wet 

Scrubber 

As shown in Table 2-1, BART-eligible baseline SO2 emissions through the Electric Furnace 

Roofline are estimated to be 41 tpy. The reconfigured roofline would capture an expected 84.7 

percent of SO2 emissions. The Acid Plant does not have the capacity to handle the additional 

captured volume of air, and even if it had the capacity, the additional air would dilute the SO2

concentration entering the Acid Plant, rendering it less effective. Similarly, the Vent Fume 

Scrubber would not have the capacity to handle the additional volume. Therefore, a new wet 

scrubber would be constructed to treat the captured emissions. The new wet scrubber would 
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reduce these captured SO2 emissions to a concentration of 1 ppm or less, equivalent to a 

controlled emission rate of 6 tpy. BART-eligible baseline SO2 emissions would be reduced by 

35 tpy (see Tables B-5 and B-7 for the detailed calculation). 

3.3.1.7 Increase Acid Plant Tail Gas Scrubber Operation 

An alternative to continuously operating the Acid Plant Tail Gas Scrubber would be to increase 

its frequency of use. The scrubber could be run additional hours per year (up to 1,300 hours) 

without capital expenditure such that cost would be associated with increased purchase of 

reagent and handling of additional sludge. 

The calculation of SO2 reduction from baseline requires a calculation of the SO2 loading to the 

scrubber inlet. A performance test of the scrubber showed a control efficiency of 71 percent as 

currently operated. Thus, baseline SO2 loading to the scrubber amounts to 368 tpy. Baseline 

SO2 emissions would be reduced by 31 tpy or less, depending on the number of additional 

operating hours (see Table B-8 for the detailed calculation). 

3.3.1.8 Improve Capture of Process Fugitive Emissions at Electric Furnace Matte Tapping 

Hood 

Select leakages in the existing vent fume system ductwork would be eliminated and active 

control would be used to increase ventilation from the existing active matte tapping hoods by 20 

percent, reducing SO2 emissions to the roofline by 4 percent. The additional captured SO2

would be passed to the existing Vent Fume Scrubber resulting in reduced SO2 emissions. 

BART-eligible baseline SO2 emissions through the Electric Furnace Roofline are estimated to be 

41.3 tpy. These BART-eligible baseline SO2 emissions would be reduced by 1 tpy using the 

existing Vent Fume Scrubber (see Table B-9 for the detailed calculation). 

3.3.2 Nitrogen Oxides 

As was noted in the evaluation of technical feasibility, combustion modifications and SNCR will 

not be evaluated further. SCR is the only NOX control measure to be evaluated further and is 

determined to be technically feasible only at the Acid Plant Tail Gas Stack. 

3.3.2.1 Selective Catalytic Reduction at Acid Plant Tail Gas Stack 

A tail-end SCR system would be installed between the Tail Gas Scrubber and the Tail Gas 

Stack. A tail-end SCR system has an estimated control efficiency of 75 to 85 percent. BARTeligible baseline NOX emissions through the Tail Gas Stack are 1.8 tpy without SCR control per 

Table 2-1. Based on a control efficiency of 80 percent, the tail-end SCR system would reduce 

BART-eligible NOX emissions to 0.4 tpy, resulting in an emissions reduction of 1.4 tpy (see 

Tables B-10 through B-12 for the detailed calculation). 
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3.4 Evaluation of Impacts 

The evaluation of impacts includes analysis of cost of compliance, energy impact, and 

environmental impact. The control measures listed in Section 3.3 are evaluated further. 

3.4.1 Sulfur Dioxide 

Cost estimates for the SO2 control measures were supplied by Hatch except where indicated in 

the following discussion. Equipment and other direct costs were based on a combination of 

Hatch engineering experience and consultation with vendors. Other direct costs included 

distributed control system upgrades (various additional new systems in the facility) and 

construction distributables (items such as contractor supervision and management, on-site 

facilities and scaffolding). 

Indirect costs were factored as a percentage (38.1 percent) of the total direct cost. These 

include items essential for implementing the scope: engineering, procurement and construction 

management (EPCM), pre-operational testing, travel and relocation, temporary construction 

facilities and services, first fills, capital and commissioning spares, vendor representatives, 

freight and third party services. 

Contingency was factored as a percentage of the total direct plus indirect cost. A value of 15 

percent was applied for this analysis. Contingency is a provision for project costs which will 

occur, but which cannot be defined in sufficient detail for estimating purposes due to the lack of 

complete, accurate and detailed information, as well as limited engineering which has been 

performed. Project contingency does not cover cost escalation, scope changes or project 

exclusions. 

Owner’s costs were likewise factored as a percentage of the total direct plus indirect cost. A 

value of 6.7 percent was applied for this analysis. The Owner’s costs include salaries and 

expenses associated with the Owner’s team, environmental modeling, permitting fees, legal 

expenses, abatement costs and other miscellaneous expenses expected to be incurred at the 

site. 

Hatch used a simplified approach for estimating annual operating costs. Annual scrubbing 

reagent costs were calculated from total estimated SO2 design reductions (i.e., inclusive of 

emission units that are not BART-eligible) while all other operating costs were factored as 7.4 

percent of partial direct capital cost. 

3.4.1.1 Upgrade Acid Plant Tail Gas Scrubber to Caustic Reagent 

Costs of Compliance. The Acid Plant Tail Gas Scrubber upgrade requires a new reagent 

receiving and distribution system and modification of the existing scrubber. Table B-1 shows 

the calculations, assumptions, and results. The total capital investment is estimated at 
Freeport-McMoRan Miami Inc. 

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Miami, Arizona 

March 2014 

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approximately $11.63 million. The resulting capital recovery, based on a 15-year equipment life 

and an interest rate of 7 percent per the USEPA’s OAQPS Control Cost Manual, is estimated to 

be $1.28 million per year. Annual operating and maintenance costs are estimated to be $1.10 

million, resulting in a total estimated annualized cost of $2.38 million per year. 

For the BART-eligible baseline SO2 emission rate of 355 tpy and the estimated control efficiency 

of 98%, the amount of BART-eligible SO2 emissions removed would be 348 tpy. The resulting 

cost-effectiveness is estimated as $6,800 per ton of BART-eligible SO2 emissions removed. 

Consequently, the Acid Plant Tail Gas Scrubber upgrade is not considered cost effective for 

BART purposes. 

Energy Impacts. Continuous operation of the scrubber will result in increased energy use 

compared to existing energy use. The existing scrubber typically operates 440 hours per year. 

Energy use will increase more-or-less in proportion to the increased hours in operation. 

Environmental Impacts. Wet scrubbers create large amounts of scrubber blowdown and solids 

that must be handled. FMMI reuses all of the generated material, with solids sent back to the 

smelter and liquids sent to the mine for use in the respective processes. While the upgrade 

would generate more blowdown than the existing operation, the upgrade is not expected to 

have environmental impacts that are significantly different from the existing environmental 

impacts because of the reuse of the generated materials. 

Conclusion. Given the significant economic impact associated with the upgrade of the Acid 

Plant Tail Gas Scrubber, the scenario was eliminated from further consideration as BART. 

3.4.1.2 Upgrade Vent Fume Scrubber to Caustic Reagent 

Costs of Compliance. The Vent Fume Scrubber upgrade requires a new reagent receiving and 

distribution system and modification of the existing scrubber. Table B-2 shows the calculations, 

assumptions, and results. The total capital investment is estimated at approximately $8.55 

million. The resulting capital recovery, based on a 15-year equipment life and an interest rate of 

7 percent per the USEPA’s OAQPS Control Cost Manual, is estimated to be $0.94 million per 

year. Annual operating and maintenance costs are estimated to be $0.99 million, resulting in a 

total estimated annualized cost of $1.93 million per year. 

Cost-effectiveness is based on the annualized cost of the control ($/year) divided by the amount 

of SO2 that can be controlled (tpy). The result is a measure of control cost in units of dollars per 

ton. For the BART-eligible baseline SO2 emission rate of 316 tpy and the estimated control 

efficiency of 98%, the amount of BART-eligible SO2 emissions removed would be 299 tpy. The 

resulting cost-effectiveness is estimated as $6,500 per ton of BART-eligible SO2 emissions 

removed. Consequently, the Vent Fume Scrubber upgrade is not considered cost effective for 

BART purposes. 
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Energy Impacts. The scrubber upgrade is not expected to have energy impacts that are 

significantly different from the existing energy impacts. 

Environmental Impacts. Wet scrubbers create large amounts of scrubber blowdown and solids 

that must be handled. FMMI reuses all of the generated material, with solids sent back to the 

smelter and liquids sent to the mine for use in the respective processes. While the upgrade 

would generate more blowdown than the existing operation, the upgrade is not expected to 

have environmental impacts that are significantly different from the existing environmental 

impacts because of the reuse of the generated materials. 

Conclusion. Given the significant economic impact associated with the upgrade of the Vent 

Fume Scrubber, the scenario was eliminated from further consideration as BART. 

3.4.1.3 Continuously Operate Acid Plant Tail Gas Scrubber 

Costs of Compliance. Continuous operation of the scrubber would require capital investment to 

install a new wet stack, isolation damper, and ductwork. Table B-3 shows the calculations, 

assumptions, and results for modifying the scrubber for continuous operation. The total capital 

investment is estimated at approximately $7.23 million. The resulting capital recovery, based on 

a 15-year equipment life and an interest rate of 7 percent per the USEPA’s OAQPS Control 

Cost Manual, is estimated to be $0.79 million per year. Annual operating and maintenance 

costs are estimated to be $1.55 million, largely due to the continuous use of high-cost 

magnesium-based reagents, resulting in a total estimated annualized cost of $2.35 million per 

year. 

For the baseline SO2 emission rate of 355 tpy and the estimated control efficiency of 80%, the 

amount of BART-eligible SO2 emissions removed would be 281 tpy. The resulting costeffectiveness is estimated as $8,300 per ton of BART-eligible SO2 emissions removed. 

Consequently, the continuous operation of the Acid Plant Tail Gas Scrubber is not considered 

cost effective. 

Energy Impacts. Continuous operation of the scrubber will result in increased energy use 

compared to existing energy use. 

Environmental Impacts. Wet scrubbers create large amounts of scrubber blowdown and solids 

that must be handled. FMMI reuses all of the generated material, with solids sent back to the 

smelter and liquids sent to the mine for use in the respective processes. While the continuous 

operation would generate more blowdown than the existing operation, the continuous operation 

is not expected to have environmental impacts that are significantly different from the existing 

environmental impacts because of the reuse of the generated materials. 
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Conclusion. Given the significant economic impact associated with the continuous operation of 

the Acid Plant Tail Gas Scrubber, the option was eliminated from further consideration as 

BART. 

3.4.1.4 Upgrade Acid Plant 

Costs of Compliance. The existing acid plant would be upgraded for additional capacity, 

including additional catalyst loading, gas and acid cooling, and an additional blower. Additional 

cooling facilitates reduced SO2 emissions through improved plant operation. The amount of 

cesium-promoted catalyst added to the first pass would be increased to 35 percent of the 

catalyst load, while the amount of cesium-promoted catalyst added to the fourth pass would be 

increased to 100 percent of the catalyst load for improved conversion. A new maintenance 

shop would be required for layout reasons as the existing shop would need to be demolished to 

accommodate the new acid plant equipment. 

Table B-4 shows the calculations, assumptions, and results. The total capital investment is 

estimated at approximately $114.84 million. The resulting capital recovery, based on a 20-year 

equipment life and an interest rate of 7 percent per the USEPA’s OAQPS Control Cost Manual, 

is estimated to be $10.84 million per year. Annual operating and maintenance costs are 

estimated to be $3.05 million, resulting in a total estimated annualized cost of $13.89 million per 

year. 

For the BART-eligible baseline SO2 emission rate of 355 tpy, the amount of BART-eligible SO2

emissions removed would be 266 tpy. The resulting cost-effectiveness is estimated as $52,200 

per ton of BART-eligible SO2 emissions removed. Consequently, the Acid Plant Tail Gas 

Scrubber upgrade is not considered cost effective for BART purposes. 

Energy Impacts. Energy use will increase as a consequence of adding cooling capacity and the 

additional blower. 

Environmental Impacts. The Acid Plant upgrade would require additional disposal of catalyst 

compared to existing operations. 

Conclusion. Given the significant economic impact associated with the upgrade of the Acid 

Plant, the scenario was eliminated from further consideration as BART. 

3.4.1.5 Capture Process Fugitive Emissions at Converter Aisle Roofline, Install New Wet 

Scrubber 

Costs of Compliance. The Converter Aisle roofline would be reconfigured to capture process 

fugitive emissions and ductwork would be added to pass the captured emissions to a new wet 

scrubber. Additional caustic receiving and distribution system capacity would be installed. A 

new maintenance shop would be required and existing buildings would be demolished to 
Freeport-McMoRan Miami Inc. 

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Miami, Arizona 

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accommodate new equipment. Tables B-5 and B-6 show the calculations, assumptions, and 

results. The total capital investment is estimated at approximately $102.85 million. The 

resulting capital recovery, based on a 15-year equipment life for the wet scrubber and an 

interest rate of 7 percent per the USEPA’s OAQPS Control Cost Manual, is estimated to be 

$11.29 million per year. Annual operating and maintenance costs are estimated to be $4.23 

million, resulting in a total estimated annualized cost of $15.52 million per year. 

For the BART-eligible baseline SO2 emission rate of 109 tpy, the amount of BART-eligible SO2

emissions removed would be 56 tpy. The resulting cost-effectiveness is estimated as $276,300 

per ton of BART-eligible SO2 emissions removed. Consequently, the Converter Aisle roofline 

reconfiguration and associated new wet scrubber are not considered cost effective for BART 

purposes. 

Energy Impacts. The system would require a significant increase in energy consumption, 

requiring fans to move 1.4 million acfm of captured air and to operate the new wet scrubber. 

Environmental Impacts. Wet scrubbers create large amounts of scrubber blowdown and solids 

that must be handled. FMMI would reuse all of the generated material, with solids sent back to 

the smelter and liquids sent to the mine for use in the respective processes. While the new wet 

scrubber would generate considerably more blowdown than the existing operation, the smelter 

and mine have capacity to reuse the generated liquids and solids. Therefore, the project is not 

expected to have significant environmental impacts. 

Conclusion. Given the significant economic impact associated with the project, the scenario 

was eliminated from further consideration as BART. 

3.4.1.6 Capture Process Fugitive Emissions at Electric Furnace Roofline, Install New Wet 

Scrubber 

Costs of Compliance. The Electric Furnace roofline would be reconfigured to capture process 

fugitive emissions and ductwork would be added to pass the captured emissions to a new wet 

scrubber. Additional scrubber and caustic receiving and distribution system capacity would be 

installed to accommodate the additional emissions captured at the Electric Furnace roofline. 

The costs associated with reconfiguration of the Electric Furnace Roofline was scaled from the 

costs associated with reconfiguration of the Converter Aisle Roofline. The engineering “sixtenths” rule of economies of scale (Peters et al., 2002) was used based on the exhaust flows: 

Electric Furnace Cost = Converter Aisle Cost × (Electric Furnace Flow / Converter Aisle Flow)0.6

Tables B-5 and B-7 show the calculations, assumptions, and results. The total capital 

investment is estimated at approximately $28.56 million. The resulting capital recovery, based 

on a 15-year equipment life for the wet scrubber and an interest rate of 7 percent per the 

USEPA’s OAQPS Control Cost Manual, is estimated to be $3.14 million per year. Annual 
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operating and maintenance costs are estimated to be $1.17 million, resulting in a total estimated 

annualized cost of $4.31 million per year. 

For the BART-eligible baseline SO2 emission rate of 41 tpy, the amount of BART-eligible SO2

emissions removed would be 35 tpy. The resulting cost-effectiveness is estimated as $124,000 

per ton of BART-eligible SO2 emissions removed. Consequently, the Electric Furnace roofline 

reconfiguration and associated new wet scrubber are not considered cost effective for BART 

purposes. 

Energy Impacts. The system would require a significant increase in energy consumption, 

requiring a fan to move 165,000 acfm of captured air and to operate the new wet scrubber. 

Environmental Impacts. Wet scrubbers create large amounts of scrubber blowdown and solids 

that must be handled. FMMI would reuse all of the generated material, with solids sent back to 

the smelter and liquids sent to the mine for use in the respective processes. While the new wet 

scrubber would generate considerably more blowdown than the existing operation, the smelter 

and mine have capacity to reuse the generated liquids and solids. Therefore, the project is not 

expected to have significant environmental impacts. 

Conclusion. Given the significant economic impact associated with the project, the scenario 

was eliminated from further consideration as BART. 

3.4.1.7 Increase Acid Plant Tail Gas Scrubber Operation 

Costs of Compliance. Increased operation of the scrubber would not require capital investment 

but would require increased expenditure for additional reagent, reagent handling, and sludge 

handling. The scale of the increase is limited by the existing infrastructure as new storage 

capacity for reagent and sludge would need to be added at some point (this was addressed in 

Section 3.4.1.4). Annual direct operating and maintenance costs are estimated to increase 

linearly with increasing SO2 reduction. Because of this linear relationship, the cost effectiveness 

is fixed at an estimated $5,500 per ton of BART-eligible SO2 emissions removed regardless of 

the scale of increased operation. Consequently, the increased operation of the Acid Plant Tail 

Gas Scrubber is not considered cost effective. 

Table B-8 shows the calculations, assumptions, and results for increasing scrubber operation. 

The table shows operating hours increased from 440 hours per year to 1,300 hours per year for 

illustration purposes. 

Energy Impacts. Increased operation of the scrubber will result in increased energy use 

compared to existing energy use. 

Environmental Impacts. Wet scrubbers create large amounts of scrubber blowdown and solids 

that must be handled. FMMI reuses all of the generated material, with solids sent back to the 
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smelter and liquids sent to the mine for use in the respective processes. While the increased 

operation would generate more blowdown than the existing operation, the increased operation 

is not expected to have environmental impacts that are significantly different from the existing 

environmental impacts because of the reuse of the generated materials. 

Conclusion. Given the significant economic impact associated with the increased operation of 

the Acid Plant Tail Gas Scrubber, the option was eliminated from further consideration as 

BART. 

3.4.1.8 Improve Capture of Process Fugitive Emissions at Electric Furnace Matte Tapping 

Hood 

Costs of Compliance. Select leakages in the existing vent fume system ductwork would be 

eliminated and active control would be used to increase ventilation from the existing active 

matte tapping hoods by 20 percent, reducing SO2 emissions to the roofline by 4 percent. The 

captured SO2 would be passed to the existing Vent Fume Scrubber resulting in reduced SO2

emissions. Table B-9 shows the calculations, assumptions, and results. The total capital 

investment is estimated at approximately $0.52 million. The resulting capital recovery, based on 

a 20-year equipment life and an interest rate of 7 percent per the USEPA’s OAQPS Control 

Cost Manual, is estimated to be $49,000 per year. Annual operating and maintenance costs are 

estimated to be $20,900, resulting in a total estimated annualized cost of $69,900 per year. 

For the BART-eligible baseline SO2 emission rate of 41.3 tpy, the amount of BART-eligible SO2

emissions removed would be 1 tpy. The resulting cost-effectiveness is estimated as $68,700 

per ton of BART-eligible SO2 emissions removed. Consequently, the improved Electric Furnace 

Matte Tapping Hood capture is not considered cost effective for BART purposes. 

Energy Impacts. The improvement would not result in significant additional energy use. 

Environmental Impacts. The improvement would not result in significant additional 

environmental impacts. 

Conclusion. Given the significant economic impact associated with the project, the scenario 

was eliminated from further consideration as BART. 

3.4.2 Nitrogen Oxides 

The evaluation of impacts includes analysis of cost of compliance, energy impact, and 

environmental impact. SCR is the only NOX control measure to be evaluated further and is 

determined to be technically feasible only at the Acid Plant Tail Gas Stack. 
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3.4.2.1 Selective Catalytic Reduction at Acid Plant Tail Gas Stack 

Costs of Compliance. A cost estimate for a tail-end SCR system was assembled for purposes 

of determining SCR cost-effectiveness. Vendor costs were obtained for the primary system 

components, including: 

1. the SCR system itself, including reactor, catalyst, ammonia injection system, and 

controls, 

2. a NOX analyzer which will be required for the ammonia injection control system, 

3. a direct-fired heater to reheat the flue gas, 

4. a recuperative heat exchanger with a heat recovery of 95 percent to minimize capital 

and operating costs, and 

5. a new induced-draft fan which will be required to overcome the added flue gas pressure 

drop resulting from the SCR system. 

The cost is based in part on a BACT analysis performed previously for the facility (TRC, 1995). 

The vendor-quoted equipment cost of $2.23 million was escalated to be representative of 

current costs by applying cost escalation indices from the Chemical Engineering Plant Cost 

Index (Chemical Engineering, October 1996 and December 2013), resulting in an adjusted 

equipment cost of $3.57 million. 

Cost factors and methods are otherwise based on guidance from USEPA (USEPA, 2002). 

Tables B-10 through B-12 show the calculations, assumptions, and results. The total capital 

investment is estimated at approximately $7.07 million. The resulting capital recovery, based on 

a 20-year equipment life and an interest rate of 7 percent, is estimated to be $0.67 million per 

year. Annual operating and maintenance costs are estimated to be $1.31 million, resulting in a 

total estimated annualized cost of $1.98 million per year. The capital and operating costs 

include the necessary heater/heat exchanger equipment to reheat the exhaust gas to the SCR 

system. 

SCR cost-effectiveness is based on the annualized cost of the control ($/year) divided by the 

amount of NOX that can be controlled (tpy). The result is a measure of control cost in units of 

dollars per ton. For the BART-eligible baseline NOX emission rate from the Acid Plant of 1.8 tpy 

and the estimated control efficiency of 80%, the amount of BART-eligible NOX emissions 

removed would be 1.4 tpy. The resulting cost-effectiveness is estimated as $1.38 million per 

ton of BART-eligible NOX emissions removed. Installation of SCR is therefore not considered 

cost effective for BART purposes. 

Energy Impacts. The annual energy impacts resulting from using an SCR system would be the 

use of approximately 36.7 million scf additional cubic feet per year of natural gas to reheat the 

flue gas and 3.27 million kWh per year of electricity to overcome the increased pressure drop 
Freeport-McMoRan Miami Inc. 

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across the catalyst reactor. The energy impact from natural gas consumption would be 25.5 

million cubic feet of natural gas per ton of BART-eligible NOX controlled. The impact associated 

with electricity consumption would be 2.27 million kWh per ton of BART-eligible NOX controlled. 

These values represent significant energy impacts and are excessive given the level of NOX

emissions controlled. 

Environmental Impacts. The environmental impacts associated with using SCR are primarily 

from the required combustion of additional fossil fuel to reheat the flue gas. Firing natural gas in 

a duct burner would not only increase NOX emissions, the pollutant intended to be controlled by 

the SCR system, but would also increase CO, VOC, SO2, and PM emissions. In addition, a 

significant amount of greenhouse gas emissions (CO2) would be generated. Estimated 

emissions from firing the required amount of natural gas were calculated using natural gas 

combustion emission factors from Section 1.4 of USEPA’s AP-42 (USEPA, 1998) as follows: 

 NOX 0.92 tpy; 

 CO 1.54 tpy; 

 VOC 0.10 tpy; 

 SO2 0.01 tpy; 

 PM 0.14 tpy; and 

 CO2 2,200 tpy. 

Also, SCR catalysts will oxidize some of the inlet SO2 to SO3, possibly creating stack opacity 

problems from acid mist and condensed ammonium compounds which pass through the heat 

exchanger. Additionally, an SCR system would generate a solid waste stream in the form of 

spent catalyst that would also have a negative environmental impact. 

Conclusion. Given the significant economic, energy, and environmental impacts associated 

with application of SCR, it was eliminated from further consideration as BART. 

3.4.3 Summary of Impacts Evaluation and Determination of Control Level Representing 

BART 

Based on the foregoing impacts evaluation, the use of existing control measures is the only 

remaining BART alternative. Because this constitutes the most stringent control available, an 

air quality modeling analysis for the purpose of determining visibility impacts is not required 

according to USEPA’s BART Guidelines. Therefore, the control level representing BART is the 

use of existing control measures, including the Acid Plant, Acid Plant Tail Gas Scrubber, Vent 

Fume Scrubber, Converter Mouth Covers, and Pollution Prevention. A summary of the findings 

are presented in Table 3-1. 
Freeport-McMoRan Miami Inc. 

BART Analysis Miami, Arizona March 2014 

Page 3-24 

Table 3-1. Summary of Best Available Retrofit Technology Evaluations 

Control Technology 

BART-Eligible 

Emission Units 

Emission 

Reduction 

(tpy) 

Cost 

Effectiveness 

($/ton) Comments 

SO2

Upgrade Acid Plant Tail Gas Scrubber to Caustic 

Converters and 

Electric Furnace 

348 $6,800 Existing scrubber system 

caustic reagent: caustic redistribution capacity instalcapacity installed, new stachanged chemistry. 

Upgrade Vent Fume Scrubber to Caustic 

Electric Furnace 299 $6,500 Existing scrubber system 

caustic reagent: caustic redistribution capacity instaladdress changed chemist

Continuously Operate Existing Acid Plant Tail Gas Scrubber 

Converters and 

Electric Furnace 

281 $8,300 Existing scrubber system 

reagent receiving capacity capacity installed, new staaddress changed chemist

Upgrade Acid Plant Converters and 

Electric Furnace 

266 $52,200 Existing acid plant upgrad

capacity: additional catalyacid cooling, additional blo

Capture Process Fugitive Emissions at Converter Aisle Roofline, Install New Scrubber 

Converters 56 $276,300 Converter Aisle roofline re

capture process fugitive eadded to pass the capturenew wet scrubber, additioand distribution system ca
Freeport-McMoRan Miami Inc. 

BART Analysis Miami, Arizona March 2014 

Page 3-25 

Table 3-1. Summary of Best Available Retrofit Technology Evaluations (continued) 

Control Technology 

BART-Eligible 

Emission Units 

Emission 

Reduction 

(tpy) 

Cost 

Effectiveness 

($/ton) Comments 

SO2

Capture Process Fugitive Emissions at Electric Furnace Roofline, Install New Scrubber 

Electric Furnace 35 $124,000 Electric Furnace roofline r

capture process fugitive eadded to pass the capturenew wet scrubber, additioand distribution system ca

Increased Operation of Existing Acid Plant Tail Gas Scrubber 

Converters and 

Electric Furnace 

< 31 $5,500 No capital investment; inc

purchase and blowdown hare linear with amount of 

Limited to capacity of exisblowdown handling system

Improve Capture of Process Fugitive Emissions from Electric Furnace Matte Tapping Hood 

Electric Furnace 1 $68,700 Select leakages in the exi

system ductwork would be active control would be usventilation from the existintapping hoods; additional controlled by existing Ven

NO2

SCR at Acid Plant Tail Gas Stack 

Converters and 

Electric Furnace 

0.4 $1,375,600 SCR installed downstream 

Gas Scrubber. Aqueous and handling system instaexhaust required which inenergy and environmenta
Freeport-McMoRan Miami Inc. 

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3.5 BART Determination 

After identifying the level of control representing BART, an emission limit representing BART 

should be established for each BART-eligible emission unit and for each pollutant subject to 

review. However, a design, equipment, work practice, operational standard, or combination of 

such standards can be established in cases where technical or economic limitations exist in the 

application of measurement methods that make a conventional emission limit infeasible. 

As noted previously, emissions from the Acid Plant Tail Gas Stack and Vent Fume Stack 

include commingled emissions from units subject to BART (i.e., the Electric Furnace and the 

Converters) and units not subject to BART (i.e., the Isa Furnace). Because a continuous 

emissions monitoring system (CEMS) cannot continuously differentiate BART-eligible emissions 

from those that are not, a conventional emission limit is not technically feasible. Accordingly, 

the following work practice and operational standards are proposed as representing BART: 

3.5.1 SO2 Emissions, Acid Plant Tail Gas Stack 

The recommended BART SO2 emission limit is a work practice standard that requires the 

existing use of the Acid Plant, Acid Plant Tail Gas Scrubber, and Converter Mouth Covers to 

reduce SO2 emissions. This equipment shall be maintained and operated in a manner 

consistent with good air pollution control practices for minimizing emissions. 

3.5.2 SO2 Emissions, Vent Fume Stack 

The recommended BART SO2 emission limit is a work practice standard that requires the 

existing use of the Vent Fume Scrubber to reduce SO2 emissions. This equipment shall be 

maintained and operated in a manner consistent with good air pollution control practices for 

minimizing emissions. 

3.5.3 NOX Emissions 

The recommended BART NOX emission limit is a work practice standard that requires the use of 

natural gas or propane to reduce NOX emissions. The burners associated with the Converters 

and Electric Furnace shall be operated in accordance with good combustion practices. 
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Page 4-1 

4.0 REFERENCES 

Chemical Engineering, 1996. Chemical Engineering Plant Cost Index, Chemical Engineering, 

October 1996. 

Chemical Engineering, 2013. Chemical Engineering Plant Cost Index, Chemical Engineering, 

December 2013. 

Partelpoeg, E.H., 2014. Miami Smelter Calculation Summary. January 23, 2014. 

Peters, M.S., K. Timmerhaus, and R.E. West. 2002. Plant Design and Economics for Chemical 

Engineers, 5th Edition, McGraw-Hill Professional, 2002, pp. 242-243. 

Radian, 1991. Ammonium Sulfate and Bisulfate Formation in Air Preheaters, prepared for the 

USEPA Industrial Environmental Research Laboratory by Radian Corporation, 1991. 

TRC, 1995. Class I Air Quality Permit Application for IsaSmelt® Modification Cyprus Miami 

Mining Corporation. October 26, 1995. 

Trinity Consultants, 2013. Roofline Study. November 2013. 

USEPA, 1998. Compilation of Air Pollutant Emission Factors, Volume I: Stationary Point and 

Area Sources; Section 1.4, Natural Gas Combustion, AP-42. U.S. Environmental Protection 

Agency, Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina. 

July 1998. 

USEPA, 2002. Air Pollution Control Cost Manual, 6th Ed., EPA/452/B-02-001. U.S. 

Environmental Protection Agency, Office of Air Quality Planning and Standards, Research 

Triangle Park, North Carolina. January 2002. 

USEPA, 2013. RACT/BACT/LAER Clearinghouse (RBLC). U.S. Environmental Protection 

Agency, Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina. 

November 2013. 
Freeport-McMoRan Miami Inc. 

BART Analysis 

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March 2014 

APPENDIX A 

BART-Eligible Baseline Emissions Calculations 
Table A‐1. BART Baseline Emissions

Capture

2011 2012 Average 2011 2012 Average ELF Converters ELF Converters ELF Converters Total (tpy

Acid	Plant	Tail	Stack 1,204 985 1,095 198 172 185 1% 31% 0.036% 0.92% 10.9 339 350 

Vent	Fume	Stack 394 510 452 70% 316 316 Smelter	Process	Fugitives 1,036 1,030 1,033 4% 53% 41.3 547 589 43Smelter	Combustion	Fugitives 46.6 48.5 47.6 1.6% 40.2% 

TOTALS 2,634 2,525 2,579 245 221 233 369 887 1,255 

Notes:		1.		Emission	unit	allocations	for	SO2	emissions	from	the	Acid	Plant	Tail	Gas	Stack	are	from	calculations	performed	by	Dr.	Eric	Partelpoeg	(Partelpoeg,	2014).

		2.		Emission	unit	allocations	for	SO2	emissions	from	the	Vent	Fume	Stack	are	from	calculations	performed	by	Dr.	Eric	Partelpoeg	(Partelpoeg,	2014).

		3.		Emission	unit	allocations	for	SO2	emissions	from	smelter	fugitives	based	on	emissions	testing	performed	in	2012	(Trinity,	2013).		4.		The	Converter	Mouth	Covers	are	expected	to	capture	80	percent	of	the	SO2	process	fugitive	emissions	during	blowing	operations.

		5.		Emission	unit	allocations	for	NOx	emissions	from	the	Acid	Plant	Tail	Gas	Stack	assume	720	hours	per	year	of	Electric	Furnace	venting	of	natural	gas	combustion	emissions	and	100	hours	per	year	of	Converters	venting	of	nat

		6.		Emission	unit	allocations	for	NOx	emissions	from	smelter	fugitives	are	based	on	natural	gas	usage	in	the	smelter	building.

		7.		The	normal	configuration	of	the	ELF	is	to	operate	with	electrodes.		Natural	gas	is	used	only	when	electrodes	break,	or	during	excessively	cold	weather.		The	ELF	had	no	actual	NOx	emissions	in	2011	or	2012.		The	last	year	in

												natural	gas	was	2007,	and	the	NOx	emissions	presented	above	for	the	ELF	are	representative	of	that	year.

Emission Points

SO2 (tpy) NOx (tpy) SO2 NOX 

Annual Actual Emissions Emission Unit Allocations Conver

Mouth Cover Project (tpy)

SO2 Emissions Before Converter

Freeport‐McMoRan	Miami	Inc. Page	1	of	1 
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BART Analysis 

Miami, Arizona 

March 2014 

APPENDIX B 

Emission Reduction and Cost Effectiveness Calculations 

Confidential Business Information 
UPGRADE OF ACID PLANT TAIL GAS SCRUBBER

Capital and Annual Costs

Source Parameters

Baseline SO2 emission rate (tpy) 355

Baseline SO2 control efficiency Stack Test Result 71%

Baseline scrubber operating hours 440

Baseline scrubber inlet SO2 loading (tpy) 368

SO2 control efficiency Control Efficiency per Hatch (1) 98%

SO2 controlled (tpy) 361

SO2 emitted (tpy) 7.4

Baseline SO2 removed (tpy) 348

Operating schedule (hr/yr) 8,760

Item Factor Cost

Capital Costs

 Total Equipment Cost Cost Estimate per Hatch (1) $6,134,000

 Direct & Indirect Installation Costs Cost Estimate per Hatch (1) $5,496,000

Total Capital Investment (TCI) $11,630,000

Annual Costs

 Reagent Costs Cost Estimate per Hatch (1) $653,000

 General Costs Cost Estimate per Hatch (1) $451,000

 Equipment Life (2) 15 years

 Interest Rate (2) 7%

 Capital Recovery Factor 0.110

 Capital Recovery $1,277,000

Total Annual Cost $2,381,000

SO2 Reduction (tpy) 348

Cost Effectiveness ($/ton controlled) $6,849

Reference Sources:

(1) Control efficiency and cost estimates per Hatch 2014. Direct and indirect installation costs include construction

 distributables, indirects (EPCM cost,temporary construction facilities, etc.), owners cost and contingency.

(2) Section 5, Table 1.3. U.S. EPA 2002. EPA Air Pollution Control Cost Manual, 6th Ed., Office of Air Quality Planning and 

 Standards, Research Triangle Park, North Carolina, EPA/452/B-02-001, January, 2002

Table B-1

Freeport‐McMoRan Miami Inc.

Confidential Business Information Page 1 of 9 3/26/2014
UPGRADE OF VENT FUME SCRUBBER

Capital and Annual Costs

Source Parameters

Baseline SO2 emission rate (tpy) 316

Baseline SO2 control efficiency Stack Test Result 62%

Baseline Scrubber inlet SO2 loading (tpy) 832

SO2 control efficiency Control Efficiency per Hatch (1) 98%

SO2 controlled (tpy) 815

SO2 emitted (tpy) 16.6

Baseline SO2 removed (tpy) 299

Operating schedule (hr/yr) 8,760

Item Factor Cost

Capital Costs

 Total Equipment Cost Cost Estimate per Hatch (1) $4,512,000

 Direct & Indirect Installation Costs Cost Estimate per Hatch (1) $4,042,000

Total Capital Investment (TCI) $8,554,000

Annual Costs

 Reagent Costs Cost Estimate per Hatch (1) $663,000

 General Costs Cost Estimate per Hatch (1) $332,000

 Equipment Life (2) 15 years

 Interest Rate (2) 7%

 Capital Recovery Factor 0.110

 Capital Recovery $939,000

Total Annual Cost $1,934,000

SO2 Reduction (tpy) 299

Cost Effectiveness ($/ton controlled) $6,460

Reference Sources:

(1) Control efficiency and cost estimates per Hatch 2014. Direct and indirect installation costs include construction

 distributables, indirects (EPCM cost,temporary construction facilities, etc.), owners cost and contingency.

(2) Section 5, Table 1.3. U.S. EPA 2002. EPA Air Pollution Control Cost Manual, 6th Ed., Office of Air Quality Planning and 

 Standards, Research Triangle Park, North Carolina, EPA/452/B-02-001, January, 2002

Table B-2

Freeport‐McMoRan Miami Inc.

Confidential Business Information Page 2 of 9 3/26/2014
CONTINUOUS OPERATION OF ACID PLANT TAIL GAS SCRUBBER

Capital and Annual Costs

Source Parameters

Baseline SO2 emission rate (tpy) 355

Baseline SO2 control efficiency 71%

Baseline scrubber operating hours 440

Baseline Scrubber inlet SO2 loading (tpy) 368

SO2 control efficiency Control Efficiency per Hatch (1) 80%

SO2 controlled (tpy) 295

SO2 emitted (tpy) 74

Baseline SO2 removed (tpy) 281

Operating schedule (hr/yr) 8,760

Item Factor Cost

Capital Costs

 Total Equipment Cost Cost Estimate per Hatch (1) $3,811,000

 Direct & Indirect Installation Costs Cost Estimate per Hatch (1) $3,415,000

Total Capital Investment (TCI) $7,226,000

Annual Costs

 Reagent Costs Cost Estimate per Hatch (1) $1,272,000

 General Costs Cost Estimate per Hatch (1) $280,000

 Equipment Life (to be replaced in 2 years) 15 years

 Interest Rate (2) 7%

 Capital Recovery Factor 0.110

 Capital Recovery $793,000

Total Annual Cost $2,345,000

SO2 Reduction (tpy) 281

Cost Effectiveness ($/ton controlled) $8,334

Reference Sources:

(1) Control efficiency and cost estimates per Hatch 2014. Direct and indirect installation costs include construction

 distributables, indirects (EPCM cost,temporary construction facilities, etc.), owners cost and contingency.

(2) Section 5, Table 1.3. U.S. EPA 2002. EPA Air Pollution Control Cost Manual, 6th Ed., Office of Air Quality Planning and 

 Standards, Research Triangle Park, North Carolina, EPA/452/B-02-001, January, 2002

Table B-3

Freeport‐McMoRan Miami Inc.

Confidential Business Information Page 3 of 9 3/26/2014
UPGRADE OF ACID PLANT

Capital and Annual Costs

Source Parameters

Upgrade of Acid Plant

 Baseline SO2 emission rate (tpy) 355

 Baseline SO2 control efficiency Stack Test Result 71%

 Baseline scrubber operating hours 440

 Baseline scrubber inlet SO2 loading (tpy) 368

 SO2 Loading Reduction due to Acid Plant Upgrade Control Efficiency per Hatch (1) 75%

 Future SO2 loading to scrubber (tpy) 92

 Operating schedule (hr/yr) 8,760

Existing Acid Plant Tail Gas Scrubber

 SO2 control efficiency Control Efficiency per Hatch (1) 71%

 Baseline scrubber operating hours 440

 SO2 emitted (tpy) 88.8

 Operating schedule (hr/yr) 8,760

Item Factor Cost

Capital Costs

 Total Equipment Cost Cost Estimate per Hatch (1) $60,573,000

 Direct & Indirect Installation Costs Cost Estimate per Hatch (1) $54,265,000

Total Capital Investment (TCI) $114,838,000

Annual Costs

 Reagent Costs (negative; reduced scrubber loading) Cost Estimate per Hatch (1) -$1,404,000

 General Costs Cost Estimate per Hatch (1) $4,455,000

 Equipment Life 20 years

 Interest Rate (2) 7%

 Capital Recovery Factor 0.094

 Capital Recovery $10,840,000

Total Annual Cost $13,891,000

SO2 Reduction (tpy) 266

Cost Effectiveness ($/ton controlled) $52,173

Reference Sources:

(1) Control efficiency and cost estimates per Hatch 2014. Direct and indirect installation costs include construction

 distributables, indirects (EPCM cost,temporary construction facilities, etc.), owners cost and contingency.

(2) Section 5, Table 1.3. U.S. EPA 2002. EPA Air Pollution Control Cost Manual, 6th Ed., Office of Air Quality Planning and 

 Standards, Research Triangle Park, North Carolina, EPA/452/B-02-001, January, 2002

Table B-4

Freeport‐McMoRan Miami Inc.

Confidential Business Information Page 4 of 9 3/26/2014
Table B-5. Aisle Scrubber Calculations

Scrubber Outlet Conditions, Converter Aisle

SO2 concentration at scrubber outlet 1 ppmv

Exhaust Flow Rate 1,392,718 acfm

Exhaust Temperature 70 °F

Standard Temperature 68 °F

Atmospheric Pressure 26.082 in Hg at 3500 feet elevation

Standard Pressure 29.921 in Hg

Exhaust Flow Rate 1,209,442 scfm

SO2 emission rate 1.52 g/s

SO2 emission rate 12.1 lb/hr

SO2 emission rate 52.8 tpy

Scrubber Outlet Conditions, Electric Furnace

SO2 concentration at scrubber outlet 1 ppmv

Exhaust Flow Rate 164,619 acfm

Exhaust Temperature 70 °F

Standard Temperature 68 °F

Atmospheric Pressure 26.082 in Hg at 3500 feet elevation

Standard Pressure 29.921 in Hg

Exhaust Flow Rate 142,956 scfm

SO2 emission rate 0.18 g/s

SO2 emission rate 1.4 lb/hr

SO2 emission rate 6.2 tpy

Constants

SO2 Molecular Weight 64.06 g/mol

Molar Volume 24.055 l/mol at 20C (68F)

Mass Conversion 453.5924 g/lb

Mass Conversion 2,000 lb/ton

Volume Conversion 28.317 l/ft3

Operating Hours 8,760 hr/yr

Freeport‐McMoRan Miami Inc.

Confidential Business Information Page 5 of 9 3/26/2014
CAPTURE PROCESS FUGITIVE EMISSIONS AT CONVERTER AISLE ROOFLINE WITH NEW SCRUBBER

Capital and Annual Costs

Source Parameters

Baseline SO2 emission rate (tpy) 109

Capture efficiency 85%

Inlet SO2 loading (tpy) 92.7

Outlet SO2 concentration (ppm) Outlet concentration per Hatch (1) 1.0

Outlet SO2 emission rate (tpy) 52.8

SO2 control efficiency based on 1 ppm outlet and inlet loading 43.0%

Operating schedule (hr/yr) 8,760

Item Factor Cost

Capital Costs

 Total Equipment Cost Cost Estimate per Hatch (1) $54,247,000

 Direct & Indirect Installation Costs Cost Estimate per Hatch (1) $48,598,000

Total Capital Investment (TCI) $102,845,000

Annual Costs

 Reagent Costs Cost Estimate per Hatch (1) $236,000

 General Costs Cost Estimate per Hatch (1) $3,990,000

 Equipment Life (2) 15 years

 Interest Rate (2) 7%

 Capital Recovery Factor 0.110

 Capital Recovery $11,292,000

Total Annual Cost $15,518,000

SO2 Reduction (tpy) 56.2

Cost Effectiveness ($/ton controlled) $276,300

Reference Sources:

(1) Control efficiency and cost estimates per Hatch 2014. Direct and indirect installation costs include construction

 distributables, indirects (EPCM cost,temporary construction facilities, etc.), owners cost and contingency.

(2) Section 5, Table 1.3. U.S. EPA 2002. EPA Air Pollution Control Cost Manual, 6th Ed., Office of Air Quality Planning and 

 Standards, Research Triangle Park, North Carolina, EPA/452/B-02-001, January, 2002

Table B-6

Freeport‐McMoRan Miami Inc.

Confidential Business Information Page 6 of 9 3/26/2014
CAPTURE PROCESS FUGITIVE EMISSIONS AT ELECTRIC FURNACE ROOFLINE WITH NEW SCRUBBER

Capital and Annual Costs

Source Parameters

Baseline SO2 emission rate (tpy) 41

Capture efficiency 85%

Inlet SO2 loading (tpy) 34.9

Outlet SO2 concentration (ppm) Outlet concentration per Hatch (1) 1.0

Outlet SO2 emission rate (tpy) 6.2

SO2 control efficiency based on 1 ppm outlet and inlet loading 82.1%

Operating schedule (hr/yr) 8,760

Item Factor Cost

Capital Costs

 Total Equipment Cost Cost Estimate per Hatch (1) and Peters et al (2) $15,064,205

 Direct & Indirect Installation Costs Cost Estimate per Hatch (1) and Peters et al (2) $13,495,497

Total Capital Investment (TCI) $28,559,702

Annual Costs

 Reagent Costs Cost Estimate per Hatch (1) and Peters et al (2) $65,536

 General Costs Cost Estimate per Hatch (1) and Peters et al (2) $1,108,009

 Equipment Life (3) 15 years

 Interest Rate (3) 7%

 Capital Recovery Factor 0.110

 Capital Recovery $3,136,000

Total Annual Cost $4,309,546

SO2 Reduction (tpy) 34.8

Cost Effectiveness ($/ton controlled) $124,000

Reference Sources:

(1) Control efficiency and cost estimates per Hatch 2014. Direct and indirect installation costs include construction

 distributables, indirects (EPCM cost,temporary construction facilities, etc.), owners cost and contingency.

(2) Peters, M.S., K. Timmerhaus, and R.E. West. 2002. “Plant Design and Economics for Chemical Engineers, 5th Edition,” McGraw-Hill

 Professional, 2002, pp. 242-243.

(3) Section 5, Table 1.3. U.S. EPA 2002. EPA Air Pollution Control Cost Manual, 6th Ed., Office of Air Quality Planning and 

 Standards, Research Triangle Park, North Carolina, EPA/452/B-02-001, January, 2002

Table B-7

Freeport‐McMoRan Miami Inc.

Confidential Business Information Page 7 of 9 3/26/2014
INCREASED OPERATION OF ACID PLANT TAIL GAS SCRUBBER

Capital and Annual Costs

Source Parameters

Baseline SO2 emission rate (tpy) 355

Baseline SO2 control efficiency 71%

Baseline scrubber operating hours 440

Baseline Scrubber inlet SO2 loading (tpy) 368

SO2 control efficiency Control Efficiency per Hatch (1) 80%

SO2 controlled (tpy) 44

SO2 emitted (tpy) 324

Baseline SO2 removed (tpy) 31

Operating schedule (hr/yr) 1,300

Item Factor Cost

Capital Costs

 Total Equipment Cost $0

 Direct & Indirect Installation Costs $0

Total Capital Investment (TCI) $0

Annual Costs

 Reagent Costs Cost Estimate scaled from Hatch (1) $139,049

 General Costs Cost Estimate scaled from Hatch (1) $30,608

 Equipment Life (to be replaced in 2 years) 15 years

 Interest Rate (2) 7%

 Capital Recovery Factor 0.110

 Capital Recovery $0

Total Annual Cost $169,657

SO2 Reduction (tpy) 31

Cost Effectiveness ($/ton controlled) $5,549

Reference Sources:

(1) Control efficiency and cost estimates per Hatch 2014. Direct and indirect installation costs include construction

 distributables, indirects (EPCM cost,temporary construction facilities, etc.), owners cost and contingency.

(2) Section 5, Table 1.3. U.S. EPA 2002. EPA Air Pollution Control Cost Manual, 6th Ed., Office of Air Quality Planning and 

 Standards, Research Triangle Park, North Carolina, EPA/452/B-02-001, January, 2002

Table B-8

Freeport‐McMoRan Miami Inc.

Confidential Business Information Page 8 of 9 3/26/2014
IMPROVE CAPTURE OF PROCESS FUGITIVE EMISSIONS FROM ELECTRIC FURNACE MATTE TAPPING HOOD

WITH EXISTING VENT FUME SCRUBBER

Capital and Annual Costs

Source Parameters

Additional Capture of Electric Furnace Emissions

 Baseline SO2 emission rate (tpy) 41

 SO2 captured Capture per Hatch (1) 4%

 SO2 captured (tpy) 1.6

 SO2 emitted (tpy) 39

 Operating schedule (hr/yr) 8,760

Existing Vent Fume Scrubber

 Additional inlet SO2 emission rate (tpy) 1.6

 SO2 control efficiency 62%

 Additional SO2 controlled (tpy) 1.0

 Additional SO2 emitted (tpy) 0.6

 Operating schedule (hr/yr) 8,760

Item Factor Cost

Capital Costs

 Total Equipment Cost Cost Estimate per Hatch (1) $272,000

 Direct & Indirect Installation Costs Cost Estimate per Hatch (1) $244,000

Total Capital Investment (TCI) $516,000

Annual Costs

 Reagent Costs Cost Estimate per Hatch (1) $900

 General Costs Cost Estimate per Hatch (1) $20,000

 Equipment Life (2) 20 years

 Interest Rate (2) 7%

 Capital Recovery Factor 0.094

 Capital Recovery $49,000

Total Annual Cost $69,900

SO2 Reduction (tpy) 1.0

Cost Effectiveness ($/ton controlled) $68,700

Reference Sources:

(1) Control efficiency and cost estimates per Hatch 2014. Direct and indirect installation costs include construction

 distributables, indirects (EPCM cost,temporary construction facilities, etc.), owners cost and contingency.

(2) Section 5, Table 1.3. U.S. EPA 2002. EPA Air Pollution Control Cost Manual, 6th Ed., Office of Air Quality Planning and 

 Standards, Research Triangle Park, North Carolina, EPA/452/B-02-001, January, 2002

Table B-9

Freeport‐McMoRan Miami Inc.

Confidential Business Information Page 9 of 9 3/26/2014
Table B-10. SCR Calculations

Exhaust Flow Calculations - Standard Conditions TGS Apr

Exhaust Flow Rate 134,491 dscfm Average of 4 stack test measurements, 2011-2012 139

Exhaust Moisture Content 2.90% Average of 4 stack test measurements, 2011-2012, used VFS results to capture appropriate moisture content 

Exhaust Flow Rate 138,390 wscfm Calculated 139Exhaust Molecular Weight 28.52 g/mol Average of 4 stack test measurements, 2011-2012, used VFS results to capture appropriate moisture content 28

ConstantsNOx Molecular Weight 46.01 g/mol as NO2NH3 Molecular Weight 17.09 g/molMolar Volume 24.055 l/mol at 20C (68F)Mass Conversion 453.5924 g/lb

Mass Conversion 2,000 lb/tonVolume Conversion 28.317 l/ft3Time Conversion 60 min/hr

Operating Hours 8,760 hr/yrNOx Control CalculationsUncontrolled NOx Emission Rate 0.41 lb/hr Calculated BART-eligible emission rate (anticipated actual)Uncontrolled NOx Emission Rate 1.8 tpy BART-eligible emission rate (anticipated actual)

Uncontrolled NOx Emission Rate 42.2 lb/hr Calculated total emission rate (anticipated actual)Uncontrolled NOx Emission Rate 185 tpy Total emission rate (anticipated actual)

Uncontrolled NOx Concentration 0.427 ppmdv Calculated, BART-eligible fraction onlyNOx Control Efficiency 80% Specified

Controlled NOx Concentration 0.085 ppmdv Calculated, BART-eligible fraction onlyControlled NOx Emission Rate 0.082 lb/hr Calculated, BART-eligible fraction onlyControlled NOx Emission Rate 0.36 tpy Calculated, BART-eligible fraction onlyNOx Removed 1.4 tpy Calculated, BART-eligible fraction onlyReheat CalculationsSCR Inlet Flow 10,244 lb/min CalculatedSCR Inlet Density 0.074 lb/wscfm CalculatedInlet Temperature 71 °F Average of 4 stack test measurements, 2011-2012, used VFS results to capture appropriate moisture content 15

SCR Temperature 650 °F Estimated

Exhaust Flow Rate Prior to Reheat 139,124 acfm CalculatedSCR Exhaust Flow Rate 290,997 acfm CalculatedSCR Exhaust Density 0.035 lb/acfm CalculatedAir Heat Capacity 0.24 Btu/lb·°F

SCR Heat Exchanger Recovery 95% SpecifiedReheat Requirement 4.27 MMBtu/hr CalculatedReheat Requirement 37,406 MMBtu/yr CalculatedNatural Gas Heat Content 1,020 Btu/scf AP-42Natural Gas Density 0.047 lb/scfNatural Gas Mass Required 1,723,592 lb/yr CalculatedNatural Gas Mass Required 3.28 lb/min CalculatedNatural Gas Volume Required 36,672,173 scf/yr CalculatedNatural Gas Volume Required 25,466,786 scf/ton NOx removed CalculatedTotal Exhaust Rate to SCR 10,247 lb/min CalculatedElectricity Consumption Calculations

nNOx 0.8 Specified

∆Pduct 3 inches water OAQPS Control Cost Manual

nTotal 6 catalyst layers Calculated per OAQPS Control Cost Manual, Section 4, Equation 2.28

∆Ptotal 1 inches water per layer OAQPS Control Cost Manual

Natural Gas F-Factor 10,610 wscf/MMBtu EPA Method 19

Equivalent Gas-Fired Boiler Size 783 MMBtu/hr CalculatedEquivalent Inlet NOx 0.05397 lb/MMBtu Calculated, total NOxPower Required 373.3 kW Calculated per OAQPS Control Cost Manual, Section 4, Equation 2.48Electricity Consumption 3,270,343 kW·hr/yr CalculatedElectricity Consumption 2,271,071 kW·hr/ton NOx removed Calculated

Freeport‐McMoRan Miami Inc.Confidential Business Information Page 1 of 4 
SCR SYSTEM

Capital Costs

Source Parameters

SCR location Tail-end after scrubber

Uncontrolled NOx emission rate (tpy) 1.80

SCR NOx control efficiency 80%

SCR heat recovery 95%

Operating schedule (hr/yr) 8,760

Actual flow rate (acfm) 290,997

Standard flow rate (scfm) 138,390

Inlet temperature (°F) 71

SCR temperature (°F) 650

Exhaust moisture content (% by volume) 2.90%

Standard flow rate, dry (dscfm) 134,491

Ammonia Slip (assumed) (ppm) 10

Cost escalation factor (Aug. 2013 / Jun. 1996) 1.60

Item Factor Cost

Equipment Costs

 Complete System SCR Equipment Cost Cost Quote per TRC (1) $2,234,500

 Auxiliary Equipment All included $0

 Cost Escalation to 2013 Dollars Reference (2) $1,337,800

Purchased Equipment Cost $3,572,300

 Sales Taxes 0.03 x Purchased Equipment Cost (3) $107,200

 Freight 0.05 x Purchased Equipment Cost (3) $178,600

Total Equipment Cost $3,858,100

Direct Installation Costs 

 Foundation 0.08 x Total Equipment Cost (3) $308,600

 Erection and Handling 0.14 x Total Equipment Cost (3) $540,100

 Electrical 0.04 x Total Equipment Cost (3) $154,300

 Piping 0.02 x Total Equipment Cost (3) $77,200

 Insulation 0.01 x Total Equipment Cost (3) $38,600

 Painting 0.01 x Total Equipment Cost (3) $38,600

Total Direct Installation Costs $1,157,400

Direct Capital Cost Total Equipment Cost + Direct Installation Costs $5,015,500

Indirect Installation Costs

 General Facilities 0.05 x Direct Capital Cost (3) $250,800

 Engineering and Home Office Fees 0.1 x Direct Capital Cost (3) $501,600

 Process Contingency 0.05 x Direct Capital Cost (3) $250,800

Total Indirect Installation Costs $1,003,200

Total Direct Capital and Indirect Installed Costs $6,018,700

 Project Contingencies 0.15 of Total Direct and Indirect (3) $902,800

Total Plant Costs $6,921,500

 Preproduction Costs 0.02 of Total Plant Costs (3) $138,400

 Inventory Capital Initial ammonia charge (assumes 2 week supply) (3) $5,100

Total Capital Investment (TCI) $7,065,000

Reference Sources:

(1) Cost quote of $2,234,500 per TRC 1996. 

(2) Chemical Engineering Plant Cost Index, Equipment: June 1996 = 427.1; August 2013 = 682.8; ratio = 682.8/427.1 = 1.60

(3) Section 4, Table 2.5. U.S. EPA 2002. EPA Air Pollution Control Cost Manual, 6th Ed., Office of Air Quality Planning and 

 Standards, Research Triangle Park, North Carolina, EPA/452/B-02-001, January, 2002

Table B-11

Freeport‐McMoRan Miami Inc.

Confidential Business Information Page 2 of 4 3/26/2014
SCR SYSTEM

Annual Costs

Source Parameters

SCR location Tail-end after scrubber

Uncontrolled NOx emission rate (tpy) 1.8

SCR NOx control efficiency 80%

SCR heat recovery 95%

Operating schedule (hr/yr) 8,760

Actual flow rate (acfm) 290,997

Standard flow rate (scfm) 138,390

Inlet temperature (°F) 71

SCR temperature (°F) 650

Exhaust moisture content (% by volume) 2.90%

Flow rate (dscfm) 134,491

Ammonia Slip (assumed) (ppm) 10

Cost escalation factor (Aug. 2013 / Jun. 1996) 1.60

Cost Item Cost Factor Unit Cost Total Cost

Direct Annual Costs

 Maintenance OAQPS Section 4, Equation 2.46 (1) 0.015 of TCI $106,000

 Replacement Parts

 Catalyst Volume OAQPS Section 4, Equation 2.28 (1) 5638 cu. ft.

 Estimated Catalyst Area OAQPS Section 4, Equation 2.25 (1) 303 sq. ft.

 Estimated Number of Catalyst Layers Estimate based on TRC (2) 6

 Catalyst Life From TRC (2) 2 yrs

 Catalyst Cost Reference (3) $142 /cu. ft.

 Catalyst Replacement Cost $399,100

 Reagent Comsumption (19.2% aqueous ammonia) OAQPS Section 4, Equation 2.32 and 2.33 (1) 85.6 lb/hr 

 Aqueous ammonia costs 19.2% aqueous ammonia delivered (4) $355 /ton $133,000

 Utilities

 Net BTU Reheat Requirement 37,406 MMBtu/yr

 Natural Gas Fuel Requirement 1020 Btu/scf (AP-42) 36,672,173 scf/yr

 Natural Gas Fuel Cost 2013 cost of natural gas to facility (5) $0.0050 /scf $182,900

 Electricity Requirement OAQPS Section 4, Equation 2.48 (1) 3,270,343 kWhr/yr

 Electricity Cost 2013 cost of electricity to facility (5) $0.0643 /kWhr $210,300

Indirect Annual Cost

 Administrative Charges 2% TCI (1) $141,300

 Property Taxes 1% TCI (1) $70,700

 Insurance 1% TCI (1) $70,700

 Equipment Life 20 yrs

 Interest Rate 7%

 Capital Recovery Factor 0.094

 Capital Recovery CRF x TCI (1) $666,900

Total Annual Cost $1,980,900

Uncontrolled NOx Emission Rate (tpy) 1.8

NOx Controlled (tpy) 1.4

NOx Emitted (tpy) 0.36

Cost Effectiveness ($/ton controlled) $1,375,600

Reference Sources:

(1) U.S. EPA 2002. EPA Air Pollution Control Cost Manual, 6th Ed., Office of Air Quality Planning and Standards, Research Triangle Park, 

 North Carolina, EPA/452/B-02-001, January, 2002

(2) Vendor quote presented in TRC (1996) showed a pressure drop of 6"; OAPQS indicates 1" pressure drop per layer. 

(3) UARG 2010.

(4) November 2009 benchmark ammonia cost from http://www.icis.com

(5) December 2013 site costs.

Table B-12

Freeport‐McMoRan Miami Inc.

Confidential Business Information Page 3 of 4 3/26/2014
Emission Annual

Factor Emission

Pollutant lb/MMscf tpy

SO2 0.6 0.011

NOx 50 0.92

CO 84 1.54

PM 7.6 0.14 filterable + condensable

VOC 5.5 0.101

CO2 120000 2200

Reheat Emissions Calculation

Table B-13

Freeport‐McMoRan Miami Inc.

Confidential Business Information Page 4 of 4 3/26/2014
Freeport-McMoRan Miami Inc. 

BART Analysis 

Miami, Arizona 

March 2014 

APPENDIX C 

Eric Partelpoeg, PhD, Analysis of SO2 Emissions Allocations 
 

Miami Smelter Calculation Summary 

January 23, 2014 

Prepared by: 

Eric Partelpoeg, EHP Consulting Inc. 

6038 N Camino Miraval 

Tucson AZ 85718 

(520)615-4030 

 eric@ehp-consulting.com
Miami Smelter Calculations

 January 23, 2014 

 

1 EHP

Consulting, Inc.

1.0 PROJECT BACKGROUND ........................................................................................................................................... 2

2.0 EHP CONSULTING INC. RELEVANT EXPERIENCE ............................................................................................... 3

3.0 SMELTER PROCESS GAS DISTRIBUTION .............................................................................................................. 4

4.0 ISA / ELF FUGITIVE GAS DISTRIBUTION ............................................................................................................... 6

4.1 RELATIVE CONCENTRATION OF SO2 IN MOLTEN STREAMS ......................................................................................... 6

4.2 EXPOSED AREAS OF LAUNDER SYSTEMS ..................................................................................................................... 7

4.3 LAUNDER SYSTEM ACTIVITY ...................................................................................................................................... 7

4.4 ESTIMATION OF SOURCES OF ISA/ELF FUGITIVE EMISSIONS ..................................................................................... 7

 
Miami Smelter Calculations

 January 23, 2014 

 

2 EHP

Consulting, Inc.

1.0 PROJECT BACKGROUND 

Freeport McMoRan’s Miami Smelter is located 90 miles east of Phoenix. Its major unit operations 

include: 

1. An ISASMELT concentrate smelting vessel (referred to as ISA in this report). 

2. An Electric furnace (referred as the ELF in this report) that receives the smelted 

product of the ISA. The smelted product separates into two phases in the ELF—a 

copper rich matte phase and an iron oxide rich slag phase. 

3. Copper converters that process ELF matte to produce blister copper (that is further 

processed in anode furnaces to produce the smelter’s final product of anode copper). 

The converting process produces additional slag that is returned to the ELF to recover 

copper values which settle into ELF matte. 

4. An acid plant that is an emissions control plant that produces sulfuric acid from sulfur 

dioxide (SO2) generated in the ISA, the ELF, and the converters. 

The Miami Smelter has contracted with EHP Consulting, Inc. to estimate: 

1. The distribution of SO2 sent to the acid plant from the ISA, ELF, and the converters. 

2. The distribution of captured fugitive gases that is attributable to the ISA and the ELF. 

This report documents these calculations. 
Miami Smelter Calculations

 January 23, 2014 

 

3 EHP

Consulting, Inc.

2.0 EHP CONSULTING INC. RELEVANT EXPERIENCE 

EHP Consulting, Inc. (referred to as EHP in this report) is an Arizona based corporation that provides 

consulting services to the world wide mining industry. Its principal, Eric Partelpoeg, earned his 

doctorate in Metallurgical Engineering in 1985 from the University of Arizona. Dr. Partelpoeg’s 

experience and expertise that is relevant to the tasks presented in this report include: 

1. Expertise in smelter mass and heat balances (subject of Ph.D. dissertation) 

2. Experience and expertise in acid plant operations. 

3. Experience and expertise with the operation of copper smelters and the emission control 

equipment associated with smelters. 
Miami Smelter Calculations

 January 23, 2014 

 

4 EHP

Consulting, Inc.

3.0 SMELTER PROCESS GAS DISTRIBUTION 

EHP reviewed Miami Smelter operating data from the period March 10, 2013 to April 9, 2013 to 

estimate the distribution of process gases within the Miami Smelter. This period was selected because 

it represented typical operating conditions for the smelter and its acid plant (the data was provided to 

EHP as part of an effort to evaluate the performance of the Miami acid plant—this evaluation is not 

included in this report). 

The data evaluated to estimate the smelter process gas distribution are: 

1. ISA feed rate (which averaged 87 tph during this period). 

2. ISA feed analysis (33.25% sulfur, 26.9% copper, and 28.8% iron). 

3. ISA product (matte and slag) analyses (copper, iron, and sulfur) 

4. ELF product (matte and slag) analyses (copper, iron and sulfur) 

This data was used to: 

1. Estimate SO2 in ISA off-gas by subtracting the sulfur content of ISA matte and slag from the 

inlet sulfur content of ISA feed. 

2. Estimate SO2 in ELF off-gas by subtracting the sulfur content of ELF matte and slag from the 

ELF inputs (ISA matte and slag). While the ELF is primarily a settling furnace, there is some 

generation of SO2 in the ELF, primarily from reactions that occur between sulfur in matte and 

magnetite in slag (both the ISA slag and magnetite that is contained in the converter slag that is 

returned to the ELF. This reaction is shown below: 

 FeS(a component of matte) + 3 Fe3O4 (a component of slag) = 10 FeO(a component of slag) + SO2(evolved from bath)

This reaction lowers the iron and sulfur content in matte which results in a higher copper 

concentration of ELF matte compared to the ISA matte that enters the ELF. For the data 

evaluated in this report; inlet (ISA) matte grade was 56.8% copper and outlet (ELF) matte 

grade was 58.8% copper. Note that this reaction does not likely occur at a continuous and even 

rate in the ELF—the reaction is promoted by mixing of matte and slag which occurs primarily 

during periods when ISA products are transferred to the ELF or converter slag is returned to 

the ELF. During periods of quiescent settling of matte and slag, the rate of this reaction is 

lower. 

3. Estimate overall sulfur and sulfur dioxide distribution from the results of Items 1 and 2 above. 

Table 3-1 and Table 3-2 summarize the results of these calculations. The first table shows overall 

sulfur distribution that includes the sulfur locked up with ELF slag (that is stock-piled on the smelter 

property) and in the converters’ blister copper product. The second table shows the sources of SO2

reporting to the acid plant. Note that this distribution will vary to some extent based on feed sulfur 

concentration and the extent of reactions that occur in the ELF. In broad terms, the ISA contribution 

of SO2 to the acid plant is likely to be in the range of 60-70%; converter contribution is likely in the 

range of 25-35% and ELF contribution is likely to be less 2%. 
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 Table 3-1 Estimate of Total Sulfur Distribution 

Estimated Range of

Distribution

Sulfur Output % of Input Low range High range

ISA off‐gas 66.0% 60% 70%

ELF off‐gas 0.8% 0.1% 1.50%

Converter off‐gas   30.4% 26% 32%

ELF slag 2.7% 2.00% 3%

Blister Copper 0.1% 0.05% 0.15%

100%

Table 3-2 Estimate of Sulfur Dioxide Sources to Acid Plant 

Percentage to

Acid Plant   

ISA 68%   

Converters 31%   

ELF off‐gas 1%   

100%   
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4.0 ISA / ELF FUGITIVE GAS DISTRIBUTION 

ISA smelting vessel fugitive gases and ELF fugitive gases are collected in a common ducting system 

and scrubbed. These fugitive gases are captured from the following sources: 

1. From the launders from which molten ISA vessel products flow to the ELF. 

2. From the launders from which ELF matte flows to the matte ladle (this includes emissions 

captured from the ladle area). 

3. From the launders from which ELF slag flows to the slag ladle (this includes emissions 

captured from the ladle area). 

The amount of sulfur dioxide (SO2) released from these sources depends on: 

1. The concentration of SO2 in the molten flow stream. The SO2 dissolved in the molten stream 

is largely dependent on the SO2 concentration in the furnace from which the stream originates. 

2. The exposed area in the launders from which SO2 can evolve from the molten stream to the 

atmosphere. 

3. The amount of time that the molten stream flows through the launders (tapping the furnaces is 

not a continuous process). 

These three factors were used to estimate the source of SO2 scrubbed from the ISA vessel and ELF. 

4.1 RELATIVE CONCENTRATION OF SO2 IN MOLTEN STREAMS 

The ISA smelting vessel operates with oxygen enrichment and is the major source of SO2 that is 

processed in the acid plant. The SO2 concentration in the ISA vessel is in the order of twenty volume 

per cent (20%). This contrasts significantly with the conditions of the ELF. This furnace’s primary 

duty is to separate the matte and slag solutions that enter it from the ISA vessel. The ELF also 

receives slag from the converters. This converter slag contains copper values that are recovered in the 

ELF (the copper values settle to the matte phase). The ELF off-gases have been measured in the past. 

The SO2 concentration has always been lower than 1% (typically less than 0.25%). 

Due to the significant difference between the SO2 concentrations in these furnaces, the amount of SO2

dissolved in these gases (and subject to release as fugitive gases upon leaving the furnaces) is expected 

to be different. The solubility of SO2 in molten metals (in particular copper) was studied in the first 

half of the 20th century. Both Scaff and Schumaher (“Some Theoretical and Practical Aspects of 

Gases in Metals”, Metals and Alloys, January 1933) and Floe and Chipman (“Solubility of Sulphur 

Dioxide in Molten Copper, February 1941 AIME meeting) conclude that the solubility of SO2 is 

proportional to the (1/2.5) root of the furnace SO2 pressure (i.e. between a square root and cube root 

relationship). 

Based on this relationship, the dissolved level of SO2 in the ISA molten bath can be expected to be 

approximately four times higher than the molten bath in the ELF (see Table 4-1). 
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Table 4-1 Relative Concentration of Dissolved SO2 in ISA and ELF Molten Solutions 

Volume %

SO2

Root of

(1/2.5)

ISA 20% 0.53

ELF 0.65% 0.13

4.2 EXPOSED AREAS OF LAUNDER SYSTEMS 

The exposed area of furnace tapping systems is summarized below. 

1. ISA tapping launder: The portion of this launder system that are subject to fugitive emissions 

(and their subsequent capture and treatment) is limited to a length of 16 feet with a width of 

approximately 15 inches (for a total of 20 square feet). 

2. The ELF matte launder length is 17 feet long and approximately 15 inches wide. In addition to 

this area, the freefall stream of matte to the launder is a source of fugitive emissions as well as 

the surface area of matte that collects in the launder. EHP has estimated the total area to be 

approximately 106 square feet. 

3. The ELF slag launder system is very similar to the matte system. Total area is also slightly 

more than 100 square feet. 

4.3 LAUNDER SYSTEM ACTIVITY 

The Miami Smelter provided EHP and estimate for the duration that tapping and skimming systems 

are active (i.e. molten material is flowing through the system). Based on the Miami data (which was 

provided as minutes per ladle), EHP has estimated that the ISA tapping system was active for 1500 

hours in 2013. The ELF matte tapping system was estimated to be active for approximately 1900 

hours and the ELF slag tapping system was estimated to be active for approximately 1100 hours in 

2013. 

4.4 ESTIMATION OF SOURCES OF ISA/ELF FUGITIVE EMISSIONS 

The estimates for relative SO2 concentration, exposed areas for emissions, and the active time that 

each tapping system was active results in the following estimate of the source of captured ISA and 

ELF fugitive emissions: 

 Fugitive emissions associated with ISA activities are estimated to account for 30% of the SO2 

entering the fugitive emission scrubbing system. 

 The balance (70%) of fugitive emissions is linked to ELF matte and slag tapping activities. 

Note that there are other variables that could be incorporated into a study of this subject (i.e. the 

temperature effect on SO2 solubility, the effect of turbulence of the ladles when matte and slag is 
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pouring into them, etc.). EHP believes that the calculated distribution cited above reasonably 

represents the split of the sources of SO2 to the fugitive gas scrubber system.