Appendix H.5

Four Factor Analysis Source Reports

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BOWATER- CALHOUN SUBMITTED REPORT..................................................................3

INVISTA – HIXON/CHATTANOOGA SUBMITTED REPORT.........................................11

(FORMERLY DUPONT)

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FOUR FACTOR ANALYSIS

INVISTA  CHATTANOOGA, TN 

FOUR FACTOR ANALYSIS

OF CANDIDATE SO2 CONTROL MEASURES

FOR REASONABLE PROGRESS

UNDER THE REGIONAL HAZE RULE

Prepared by: 

TRINITY CONSULTANTS

1100 Johnson Ferry Rd. NE 

Suite 685 

Atlanta, GA 30342 

(404) 256-1919 

October 2007 

Project 071101.0077 

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Four-Factor Analysis 

TABLE OF CONTENTS

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

1.1 BACKGROUND....................................................................................................... 1-1 

2. EMISSIONS ........................................................................................................... 2-1

2.1 EMISSION UNITS SUBJECT TO THE FOUR-FACTOR ANALYSIS................................ 2-1 

2.2 BASELINE EMISSIONS............................................................................................ 2-1 

3. SO2 CONTROL TECHNOLOGY FEASIBILITY ASSESSMENT................................. 3-1

3.1 LOW SULFUR COAL .............................................................................................. 3-1 

3.2 WET FGD SYSTEMS .............................................................................................. 3-2 

3.3 SPRAY DRYER ABSORBER..................................................................................... 3-3 

3.4 FLUIDIZED BED COMBUSTION WITH LIMESTONE .................................................. 3-3 

3.5 DRY SORBENT INJECTION ..................................................................................... 3-3 

4. COSTS OF COMPLIANCE...................................................................................... 4-1

4.1 LOW SULFUR COAL .............................................................................................. 4-1 

4.2 WET FGD SYSTEM ............................................................................................... 4-3 

4.3 SPRAY DRYER ABSORBER SYSTEM....................................................................... 4-6 

4.4 DRY SORBENT INJECTION SYSTEM........................................................................ 4-7 

4.5 COSTS OF OTHER CAA PROGRAMS .................................................................... 4-11 

4.6 ANOTHER COST-EFFECTIVE METRIC................................................................... 4-11 

4.7 LOCAL ECONOMIC IMPACT ................................................................................. 4-12 

5. TIME NECESSARY FOR COMPLIANCE ................................................................. 5-1

6. ENERGY AND NON-AIR QUALITY ENVIRONMENTAL IMPACTS ............................ 6-1

7. REMAINING USEFUL LIFE OF EXISTING SOURCES IN EU-002 ............................. 7-1

8. VISIBILITY IMPROVEMENT ................................................................................. 8-1

8.1 POTENTIAL INVISTA SO2 IMPACT ON VISIBILITY ............................................... 8-2 

8.2 IMPACT OF OTHER CAA PROGRAMS..................................................................... 8-2 

9. ANALYSIS AND CONCLUSION .............................................................................. 9-1

APPENDIX A

APPENDIX B

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Four-Factor Analysis 

LIST OF TABLES

TABLE 2-1. BOILER SPECIFICATIONS FOR EU-002 

TABLE 2-2. PAST ACTUAL SO2 EMISSIONS

TABLE 4-1. TOTAL CAPITAL INVESTMENT ESTIMATE – WET FGD OPTION

TABLE 4-2. TOTAL ANNUAL COST ESTIMATE – WET FGD OPTION

TABLE 4-3. EXTRACT FROM EPA TABLE 1A (EPA-F/452-03-34) 

TABLE 4-4. TOTAL CAPITAL INVESTMENT ESTIMATE – DRY SORBENT INJECTION OPTION

TABLE 4-5. TOTAL ANNUAL COST ESTIMATE – DRY SORBENT INJECTION OPTION

TABLE 5-1. TIME NECESSARY FOR COMPLIANCE

TABLE 6-1. ENERGY AND NON-AIR QUALITY ENVIRONMENTAL IMPACTS

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Four-Factor Analysis 

LIST OF FIGURES

FIGURE 4-1. UTILITY GRADE COAL COST AS A FUNCTION OF SULFUR CONTENT (2006) 

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Four-Factor Analysis 

1. INTRODUCTION

The purpose of this document is to present the four-factor analysis for the INVISTA S.à r.l. 

(INVISTA) nylon fiber and flake manufacturing facility in Chattanooga, Hamilton County, Tennessee 

(the “Facility”). The Facility operates under a Part 70 Permit No. 47-065-2730, effective February 

12, 2004, by the Chattanooga-Hamilton County Air Pollution Control Bureau (APCB). The 

expiration date of this permit is February 11, 2009. 

1.1 BACKGROUND

Section 169A of the 1977 Amendments to the Clean Air Act set the following goal for visibility 

protection in specific Class I areas throughout the United States: 

Congress hereby declares as a national goal the prevention of any future, and the remedying 

of any existing, impairment of visibility in mandatory class I Federal areas which impairment 

results from manmade air pollution1. 

Congress directed each State implementation plan (SIP) to contain emission limits, compliance 

schedules and other measures as may be necessary to make “reasonable progress” toward meeting 

that national goal. In determining reasonable progress, the Act requires the following factors to be 

taken into consideration: (1) the costs of compliance, (2) the time necessary for compliance, (3) the 

energy and nonair quality environmental impacts of compliance and (4) the remaining useful life of 

any existing source subject to such requirements.2 

In response to the visibility-protection requirements of the Act, the U.S. Environmental Protection 

Agency (EPA) promulgated regulations in 1999 to guide States’ development of plans to reduce 

visibility impairment in Class I areas attributable to regional haze.3 That Regional Haze Rule (RHR) 

included an analytical methodology for how States were to establish reasonable progress goals for 

each Class I area.4 Because that methodology has been based on application of the specific statutory 

factors identified above, that approach to determining reasonable progress has become known as the 

“Four-Factor Analysis.” More recently, EPA has issued a guidance document which provides the 

Agency’s current thinking on how to establish reasonable progress goals by applying the four 

statutory factors to candidate emission control measures.5

 1 42 U.S.C. § 7491(a)(1). 

2 42 U.S.C. § 7491(g)(1). 

3 64 Fed. Reg. 35714 (July 1, 1989) (codified within 40 C.F.R. Part 51, Subpart P). Revisions to the Regional 

Haze Rule in 2005 primarily addressed guidelines for best available retrofit technology (BART) determinations, but made 

no substantive changes with respect to other reasonable progress requirements. 70 Fed. Reg. 39104 (July 6, 2005). 

Visibility improvement achieved by BART is a specific component of reasonable progress which is separately determined 

by a methodology similar to the Four-Factor Analysis. 

4 Id.

5 U.S. EPA, Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program (June 1, 2007). 

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Four-Factor Analysis 

The Regional Haze Rule specifies a planning period of 2004-2018 for States’ initial regional haze 

SIPs. Those SIPs must be submitted to EPA by December 17, 2007. The State of Tennessee is a 

member of the Visibility Improvement State and Tribal Association of the Southeast (VISTAS) -- a 

collaborative effort of state governments, tribal governments, and various federal agencies established 

to initiate and coordinate activities associated with the management of regional haze, visibility and 

other air quality issues in the Southeastern United States. After extensive analysis, VISTAS has 

concluded that sulfate is the primary cause of visibility impairment in Class I areas throughout the 

Southeast. 

VISTAS has further demonstrated that the principal cause of that atmospheric sulfate is the emission 

of sulfur dioxide (SO2) from utility and industrial boilers. In particular, VISTAS’ analysis found that 

SO2 emissions from INVISTA’s Chattanooga facility contributed roughly 1.5% of the total visibility 

impairment in the Cohutta Wilderness Area, a Class I area located southeast of Chattanooga in 

northwest Georgia.6 Because Cohutta is under Georgia’s jurisdiction, the Georgia Environmental 

Protection Division (EPD) has asked the Tennessee Department of Environment and Conservation 

(TDEC) to evaluate whether a future SO2 control measure at INVISTA-Chattanooga could achieve 

any reasonable progress in the Cohutta Class I area. Accordingly, INVISTA has performed this FourFactor Analysis of candidate SO2 control measures to assist TDEC’s evaluation of the issue. 

 6 The contribution analysis included several simplifying assumptions that reduce the accuracy in assigning 

contribution to any individual source. The VISTAS analysis considered total visibility impairment, frequency of air masses 

from source areas entering the Class I area of interest, and SO2 mass emissions. No attempt was made to consider the 

specific atmospheric dispersion parameters of individual sources or the differences in atmospheric chemistry that can occur 

during differing lengths of transport. Thus, while the VISTAS analysis assigned a 1.5% contribution to INVISTA, that 

value cannot be directly correlated to 1.5% of the visibility impact on the Cohutta Wilderness Area. 

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Four-Factor Analysis 

2. EMISSIONS

2.1 EMISSION UNITS SUBJECT TO THE FOUR-FACTOR ANALYSIS

The only source that TDEC has requested that INVISTA examine with a four-factor analysis is 

Emission Unit 002 (EU-002), which consists of coal-fired boilers No. 3, 4, and 5. The general 

specifications of the boilers comprising EU-002 are listed in Table 2-1. 

TABLE 2-1. BOILER SPECIFICATIONS FOR EU-002 

Boiler 

No. Fuel Type 

Maximum 

Firing Rate 

(MMBtu/hr)

Existing Air 

Pollution 

Control Device 

3 Bituminous Coal 65 Baghouse 

4 Bituminous Coal 150 Baghouse 

5 Bituminous Coal 150 Baghouse 

The number of boilers operating at any given time and the total heat input to EU-002 is dependent 

upon the Facility’s variable demand for process steam. Because of the Facility’s continuous need for 

a reliable steam supply, INVISTA normally maintains a boiler in a state of readiness to be brought 

on-line with short notice. The boilers are permitted to combust a combined total of 112,000 tons of 

coal during any consecutive 365 day period. 

The three boilers in EU-002 share a common flue gas handling and particulate matter (PM) air 

pollution control system consisting of two trains that contain manifolds and valving leading to two 

independently operated baghouses. Each baghouse is ducted to a dedicated stack. The capacity of 

each baghouse is approximately 110 percent of the flue gas flow rate from one of the larger boilers. 

The flue gas handling system is often operated with flue gas being ducted to both baghouses and 

emitted from both stacks, irrespective of the number of boilers in operation. 

INVISTA does not have a railcar dumper and associated material handling system that would be 

necessary to receive coal directly by railcar. Therefore, all coal is delivered via truck. 

Fly ash is removed from the baghouse hoppers by a hydrovac system, which conveys the ash through 

a pipeline to the Facility’s ash pond, where it is combined with bottom ash. Ash is periodically 

dredged from the pond and sent to a nearby cement kiln for beneficial reuse. 

2.2 BASELINE EMISSIONS

The annual baseline SO2 emission rate for this four-factor analysis was calculated to be 944 tons. 

This is an annual average of the actual SO2 emissions from EU-002 that were reported by INVISTA 

to APCB for the three most recent calendar years (2004, 2005 and 2006). The data used and method 

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Four-Factor Analysis 

of calculation are presented below. The emission factor is derived from Table 1.1-3 of AP-42 

(Sept. 1998), as specified in the Facility’s operating permit. 

TABLE 2-2. PAST ACTUAL SO2 EMISSIONS

Year 

Coal 

Combusted 

(tons) 

Avg. 

Sulfur 

Content 

(%) 

SO2

Emitted 

(tons) 

2004 63,612 0.93 1,133 

2005 43,264 1.000 829 

2006 45,282 0.97 842 

Average: 50,719 0.97 944 

An example calculation for 2004 emissions is: 

1,133 tons

2,000 /

38.38 0.93 63,612

2 = × × = lb ton

ton ESO

where: 38.38 is the SO2 emission factor for Bituminous Coal 

 (obtained from AP-42 Table 1.1-3) 

 0.93 % is the 2004 average sulfur content 

 63,612 tons is the total coal combusted in 2004 

 2,000 lb/ton is a unit conversion factor 

Note that the permit limits coal sulfur content to 1.25 percent, and weekly testing of fuel sulfur levels 

is required. As shown in Table 2-2, the actual coal sulfur content has averaged nearly 1% over the 

last three years. 

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Four-Factor Analysis 

3. SO2 CONTROL TECHNOLOGY FEASIBILITY ASSESSMENT

According to the EPA data for coal-fired electric generating units2, 96.8 percent of the 1,140 coalfired utility boilers operating in the U.S. in 1999 used one of the following SO2 control technologies: 

1. Low-sulfur coal - switching to a coal with a sulfur content lower than that of the coal being 

combusted 

2. Wet flue gas desulfurization (FGD) – passage of flue gas through a contactor where it comes into 

intimate contact with a scrubbing solution that reacts with SO2 in the flue gas 

3. Spray dryer absorber (SDA) - injection of a liquid slurry of sorbent material into the flue gas 

downstream of the boiler and upstream of a contact chamber and the fabric filter 

4. Fluidized-bed combustion (FBC) with limestone – coal is combusted in a fluidized bed with 

limestone added to react with the SO2 formed 

5. Dry sorbent injection (DSI) - injection of finely divided dry sorbent material into the flue gas 

immediately upstream of the fabric filter 

These technologies were chosen for inclusion in this four-factor analysis because they have been 

demonstrated (at least for coal-fired utility boilers) and are commercially available. The following 

presents an assessment of the technical feasibility of applying each of these technologies to control 

SO2 emissions from EU-002. 

3.1 LOW SULFUR COAL

The emission of SO2 from combustion of coal occurs due to the oxidation of a significant fraction of 

the naturally-occurring sulfur contained in the coal. As with the other characteristics of coal, the 

sulfur content of coal can vary considerably (e.g., from several percent to under one percent by 

weight). It may be technically possible to reduce SO2 emissions from EU-002 by purchasing coal 

with lower sulfur content than what has been burned in the past by that source. Limiting factors for 

this approach include the compatibility of numerous other coal characteristics (e.g., heating value, ash 

fusion temperature, capability to be stoked) with the specific design parameters of the combustion 

source and associated coal and ash handling equipment. Another limiting factor is the extent of coal 

reserves having the desired characteristics (which can impact the length of time over which SO2

reduction by this method may be feasible). 

Reducing SO2 emissions from EU-002 by switching to a lower-sulfur coal is deemed to be technically 

feasible for certain coals. In particular, the alternative coal must meet certain minimum specifications 

(e.g., ash fusion temperature) in order to be compatible with the design of the boilers and material 

handling systems of EU-002. 

Although sub-bituminous coals from particular regions in the western United States, such as the 

Powder River Basin, have low-sulfur concentrations, those coals have other properties that are not 

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compatible with the design of the boilers and material handling systems in EU-002. Consequently, 

low-sulfur sub-bituminous coals are not considered to be technically feasible for combustion at the 

Facility. 

INVISTA procurement personnel have researched the availability of lower-sulfur coals with 

properties that meet the specifications for combustion in EU-002. Based on INVISTA’s past 

procurements of coal from various mines, and its regular review of market reports, the Company has 

concluded that 0.75 percent is the minimum average sulfur level in acceptable bituminous coals that 

could consistently be purchased without risking future increases in sulfur content due to limited 

availability of an alternative coal. 

3.2 WET FGD SYSTEMS

Wet FGD technology relies upon the relatively high solubility of SO2 in water to remove SO2 from 

the flue gas. Since water ceases to remove SO2 effectively when it reaches an equilibrium 

concentration with SO2 in the gas phase, calcium-, sodium- or ammonium-based chemicals are added 

to the scrubber liquor to react with the dissolved SO2 and form sulfite and sulfate compounds. Some 

percentage of the scrubber liquor must be bled off and fresh water added during operation in order to 

limit the build up of both suspended and dissolved solids. Sodium-based reactants (e.g., sodium 

hydroxide) form water-soluble sulfate salts, minimizing the generation of solids that require disposal. 

However, it may be difficult to treat the salt-bearing wastewater to achieve low dissolved solid 

discharge limits. Calcium-based reactants typically form insoluble reaction products that must be 

landfilled but are easier to separate from wastewater. 

Wet FGD systems are commercially available in many variations and proprietary designs. For 

example, spray tower or packed tower absorbers can attain SO2 removal efficiencies in the range of 

approximately 90 percent where the particulate matter (PM) concentration of the flue gas has already 

been significantly reduced. However, packed tower absorbers and other designs containing any 

significant amount of internal structure are susceptible to plugging and fouling if there is any 

appreciable quantity of PM in the flue gas. In such applications, these types of scrubbers must follow 

a separate PM control device. 

SO2 removal efficiency of wet FGD systems is a function of the inlet SO2 concentration. Higher 

removal efficiencies are possible when inlet SO2 concentrations are high. Conversely, removal 

efficiency decreases as inlet SO2 concentration decreases, leading many vendors to guarantee a 

minimum outlet SO2 concentration rather than a removal efficiency. 

Wet scrubbers require significant amounts of energy (to overcome the pressure drop and circulate the 

scrubbing fluid) and significant amounts of clean water. Wet scrubbers also generate wastewater 

and/or sludge that must be treated and/or disposed of. Due to the likelihood that sulfuric acid will 

condense from the flue gas in components downstream of a wet scrubber, corrosion resistant 

materials must generally be used in those downstream components. Furthermore, saturated flue gases 

from wet scrubbers often create highly opaque plumes of condensed water upon discharge of those 

flue gases to the atmosphere. 

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Four-Factor Analysis 

Wet FGD technology is determined to be technically feasible for control of SO2 emissions from 

EU-002. Because wet scrubbers are typically more reliable if the majority of PM is removed from the 

flue gas upstream of the scrubber, applying this control option to EU-002 assumes the installation of a 

scrubber downstream of each of the two existing baghouses. 

3.3 SPRAY DRYER ABSORBER

A spray dryer absorber (sometimes referred to as a wet-dry or semi-dry scrubber) operates by the 

same principle as wet scrubbing, except that the flue gas is contacted with a fine mist of slurry instead 

of a bulk liquid (as in wet scrubbing). The combustion gases containing SO2 are contacted with fine 

spray droplets of hydrated lime slurry in a spray dryer vessel. This vessel is located downstream of 

the air heater outlet where gas temperatures are in the range of 250 to 350 °F. The SO2 is absorbed in 

the slurry and reacts with the hydrated lime reagent to form solid calcium sulfite and calcium sulfate, 

as in a wet lime scrubber. The slurry water is evaporated by the hot flue gas, leaving dry particles 

containing the captured sulfur. These particles are entrained in the flue gas, along with fly ash, and 

are collected in a PM collection device. Most of the SO2 removal occurs in the spray dryer vessel 

itself, although some additional SO2 removal may occur in downstream particulate collection devices, 

especially fabric filters. This control technology produces a dry, solid waste for easy disposal. 

An SDA system is determined to be technically feasible for the control of SO2 emissions from 

EU-002. 

3.4 FLUIDIZED BED COMBUSTION WITH LIMESTONE

Fluidized-bed combustion (FBC) involves the burning of coal particles suspended by a stream of 

combustion air and flue gas. Limestone may be added to the bed to react with the SO2 from the coal. 

Spent reactant and ash are continuously removed from the bed and from the flue gas exiting the 

boiler. 

FBC with limestone is not considered technically feasible for control of SO2 emissions from EU-002 

because that technology requires an entirely different type of combustor design than that of the boilers 

in EU-002. The statutory four-factor analysis involves the evaluation of candidate control measures 

for a given source and not a complete replacement of the source itself. 

3.5 DRY SORBENT INJECTION

For the dry sorbent injection process, dry powdered hydrated lime (or another suitable reactant) is 

directly injected into the ductwork upstream of a PM control device. Some systems use spray 

humidification followed by dry injection. The SO2 is adsorbed and reacts with the powdered sorbent. 

The dry solids remain entrained in the combustion gases, along with fly ash, and are collected by the 

PM control device. The SO2 removal efficiencies are lower than for wet scrubbing or SDA and are 

approximately 40-50 percent. This dry process eliminates the slurry production and handling 

equipment required for wet scrubbers and spray dryers, and produces a dry waste product for easier 

disposal. 

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Four-Factor Analysis 

Dry sorbent injection is determined to be technically feasible for controlling SO2 emissions from 

EU-002. Under this option, the existing baghouses would be used to collect spent reactant and fly 

ash. 

The installation of a DSI system could require significant change to the existing fly ash disposal 

system. Currently, fly ash from the baghouses is hydraulically conveyed to an ash pond where the 

ash slurry is mixed with bottom ash from EU-002. The combined ash is periodically dredged from 

the pond and trucked to a nearby cement kiln for beneficial reuse. Due to the collected particulates 

from a DSI system (fly ash/slaked lime/calcium sulfate) being incompatible with water, it would be 

necessary to switch to a dry fly ash collection and conveyance system. 

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Four-Factor Analysis 

4. COSTS OF COMPLIANCE

The control technology cost analyses in this four-factor assessment have been generally prepared in 

accordance with the EPA Air Pollution Control Cost Manual, 6th ed., EPA/452/B-02-001 (Jan. 2002). 

Estimates of total capital investment (TCI) and total annual cost (TAC) were made for each of the 

four, technically feasible control technology options identified in the previous section using the 

techniques described in the Manual, quotes obtained directly from equipment vendors and service 

contractors, and data developed by INVISTA procurement and engineering personnel. Because these 

estimates are not based on firm equipment and construction quotes and were prepared prior to 

detailed engineering evaluations, the accuracy of these estimates is generally accepted to be 

approximately ±30 percent. Supporting documents are included in Appendix A. 

The TCI estimate includes one-time costs associated with each option, including purchase of capital 

equipment, electrical, mechanical and structural construction costs, engineering, permitting, and 

testing fees. 

The TAC estimate includes recurring direct and indirect costs anticipated to be incurred in each year 

of operation. Direct costs (also known as variable costs), are those directly related to the operation of 

the option. These include costs of operator labor, utilities, replacement parts, etc. Indirect costs are 

those costs that are fixed, and do not generally vary with the extent of use of the option. These 

include administrative charges, taxes, insurance premiums, and the capital recovery cost. The capital 

recovery cost is a means of annualizing the TCI over a certain period of time. In the case of this 

analysis, the equipment lifetime was assumed to be 10 years for the purposes of calculating the capital 

recovery costs with an interest rate of eight percent, for a capital recovery factor (CRF) of 0.149.. 

4.1 LOW SULFUR COAL

In 2006 INVISTA undertook a study comparing the current average cost of coal (meeting the 

necessary technical specifications for EU-002) from different coal suppliers. The study concluded 

that the lowest average sulfur content that INVISTA believed it could consistently purchase was 0.75 

percent. Figure 4-1 provides an example of the dependence of coal cost on sulfur content. While the 

dollars per ton indicated in the figure are specifically for utility grade coal (which is not suitable for 

the stoker-fired units at INVISTA), the relationship between coal cost and sulfur content (i.e., the 

sulfur premium) is applicable for the stoker coal used at the site. It is apparent from the figure that 

the cost of coal increases very rapidly as the sulfur content drops below one percent. 

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Four-Factor Analysis 

FIGURE 4-1. UTILITY GRADE COAL COST AS A FUNCTION OF SULFUR CONTENT (2006) 

Using the trend line curve in Figure 1, the 2006 average cost of utility coal at 1.25% sulfur (the 

specification for coal received in 2004, 2005, and 2006) was approximately $44.13 per ton. Using the 

same trend line, the cost of utility coal specified at 0.75 percent sulfur was approximately $49.30 per 

ton. As mentioned, this approximately $5 per ton sulfur premium also holds for the bituminous 

stoker coal used by INVISTA. 

The additional cost, in 2006 dollars, of switching from coal specified at 1.25 percent sulfur to that 

specified at 0.75 percent sulfur, was estimated to be $262,217 using the following equation: 

Additional Cost($ / yr) = 50,719ton / yr × ($49.30 / ton − $44.13/ ton)

To calculate cost-effectiveness, the change in emissions must be determined. For 2004-2006, while 

the coal sulfur level was specified at 1.25%, the as-received coal average value was 0.97%, and this 

value is used to calculate the historical emissions. For coal-specified at 0.75%, it is likely that the asreceived value would also be slightly lower, though the exact content cannot be quantified. In the 

absence of as-received data to verify a realistic as-received sulfur value for coal specified at 0.75%, 

the potential future emissions were calculated assuming the as-received and specified value are 

identical. Using these assumptions, the decrease in SO2 emitted from the baseline was calculated to 

be approximately 214 tons per year using the following equation: 

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Four-Factor Analysis 

214 tons/yr 0.97

0.75

2 ( / ) 944 / 1 ⎟ =

⎠

⎞ ⎜

⎝

⎛ Emissions Decrease SO ton yr = ton yr × −

The cost-effectiveness (cost per ton of SO2 emission reduction) was calculated to be approximately 

$1,225 per ton of SO2 removed. 

Although there is no capital cost associated with the low-sulfur coal option, low sulfur coal is a 

commodity that is experiencing increasing market demands. Therefore, there is no way to accurately 

estimate how the cost-effectiveness of the low-sulfur coal option will change in the coming years. 

General expectations are that the demand will increase as will costs. These potential cost increases 

are not quantified in this analysis. 

4.2 WET FGD SYSTEM

A budgetary quotation was obtained for a wet FGD system from Turbosonic Technologies, a 

manufacturer of emission control equipment. The quoted FGD system consists of two cyclonic 

scrubbers, to be installed after each baghouse and induced draft fan in each of the two existing air 

pollution control trains in EU-002. 

Each scrubber, as quoted, has the capacity to accept the maximum flow rate capacity of the baghouse 

with which it would be associated. The manufacturer has guaranteed that each will achieve a 

minimum of 92 percent SO2 removal when EU-002 fires coal containing 1.25 percent by weight 

sulfur, with potentially lower control efficiency at reduced SO2 inlet loading to the scrubber. The 

scrubbers are designed to use hydrated lime as the SO2 reactant at a maximum rate of approximately 

423 pounds per hour per scrubber. A storage silo for the hydrated lime was included in the equipment 

to be installed. 

It was assumed that the stacks for each air pollution control system train would be mounted directly 

on top of each scrubber, as recommended by the manufacturer. This would help reduce the extent of 

water droplet carryover in the flue gas exiting the stacks. Because the scrubber blowdown will 

contain dissolved salts at a concentration of approximately 2.5 wt. %, this waste water is expected to 

require pretreatment prior to discharge, and the estimated cost of a wastewater system has been 

included.. 

The TCI for the wet FGD system, presented in Table 4-1, is $11,445,390. The estimated TAC for the 

wet FGD system, presented in Table 4-2, is $3,046,633. This cost was estimated assuming that 

EU-002 would be operated under the same average conditions as occurred during the period of 2004, 

2005 and 2006. The capital recovery factor utilized in the estimated TAC is based on an interest rate 

of 8.0% and an economic lifetime of 10 years. 

The estimated quantity of SO2 removed by the wet FGD option from the flue gas under the baseline 

operating conditions is 869 tons per year, based on a 92% control efficiency and the 944 tpy historical 

emissions. The estimated quantity of SO2 emitted under this option was estimated to be 76 tons per 

year. The estimated cost effectiveness of the wet FGD system when EU-002 is operated under the 

baseline conditions was estimated to be $3,508 per ton of SO2 removed.

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Appendix H.5 - 27

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INVISTA Chattanooga 4-4 Trinity Consultants 

Four-Factor Analysis 

TABLE 4-1. TOTAL CAPITAL INVESTMENT ESTIMATE – WET FGD OPTION

Factor Estimate1

Direct Costs

Purchased equipment costs

Wet scrubbers (including standard options)Vendor quote2 $1,228,000

Pumps Estimate $100,000

Stacks Estimate $50,000

Lime silo Estimate $200,000

Other equipment Estimate $50,000

A= $1,628,000

Contengencies 0.2 x A $325,600

Instrumentation 0.10 x A $162,800

Sales tax 0.03 x A $48,840

Freight 0.05 x A $81,400

Total Purchased Equipment Costs B= $2,246,640

Direct installation costs

Labor 0.49 x B $1,100,854

Field material 0.25 x B $561,660

Foundations and supports 0.12 x B $269,597

Handling and erection 0.40 x B $898,656

Electrical 0.01 x B $22,466

Piping 0.03 x B $67,399

Insulation for ductwork 0.01 x B $22,466

Contingencies 0.20 x B $449,328

Total Direct installation costs $3,392,426

Waste water treatment plant Estimate3 $5,000,000

Total Direct Costs (DC) $10,639,066

Indirect Costs (installation)

Engineering 0.10 x B $224,664

Construction and field expenses 0.10 x B $224,664

Contractor fees 0.10 x B $224,664

Start-up 0.01 x B $22,466

Permits, licenses, fees Estimate $20,000

Performance test 0.01 x B $22,466

Contingencies 0.03 x B $67,399

Total Indirect Cost (IC) $806,324

Total Capital Investment (TCI) = DC + IC $11,445,390

Cost Item

1. Estimation methodology is from section 5 of EPA/452/B-02-001

2. Vendor estimate includes one absorber for $620,000 and a second identical absorber for $608,000.

3. INVISTA estimate.

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Appendix H.5 - 28

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Four-Factor Analysis 

TABLE 4-2. TOTAL ANNUAL COST ESTIMATE – WET FGD OPTION

Cost Item Calculation Cost1

Direct Annual Costs (DC)

Operating labor

Operator $22.90/hr x 8 man-hr/day x 7 day/week x 52 week/yr $66,685

Supervisor 15% of operator labor = 0.15 x $66,685 $10,003

Maintenance

Labor $22.70/hr x 4 man-hr/day x 7 day/week x 52 week/yr $33,051

Materials 100 percent of maintenance labor $33,051

Wastewater treatment plant operation & maintenance2 $100,000

Reagent for SO2 Control

297 lb/hr x $0.050/lb x 24 hr/day x 7 day/week x 52 week/yr $129,858

Residue Disposal

Flyash 0.82 ton/hr x 24 hr/day x 7 day/week x 52 week/yr x $45.00/ton $322,635

Utilities

Electricity = (Added fan kW + pump kW) x annual operating hours x electricity rate

= (99 kW + 82 kW) x $0.0500 /kW-hr x 24 hr/day x 7 day/week x 52 week $78,944

Water week/yr $21,551

Wastewater $0.0020/gal x 38 gpm x 60 min/hr x 24.0 hr/day x 7.0 day/week x 52 week $38,792

 Total DC $834,568

Indirect Annual Costs (IC)

 Overhead 34% of sum of operating, supv., maint. labor & materials $48,549

= 0.34 x ($66,685 + $10,003 + $33,051 + $33,051)

 Administrative charges 2% of Total Capital Investment = 0.02 x $11,445,390 $228,908

 Property taxes 1% of Total Capital Investment = 0.01 x $11,445,390 $114,454

 Insurance 1% of Total Capital Investment = 0.01 x $11,445,390 $114,454

 Capital recovery CRF x TCI = 0.1490 x $11,445,390 $1,705,701

 Total IC $2,212,065

Total Annual Cost (rounded) $3,046,633

1. Estimation methodology is from section 5 of EPA/452/B-02-001 and INVISTA.

2. INVISTA estimate.

It is also not known at this time whether the presence of a persistent, highly opaque steam plume from 

the scrubbers’ stacks will be an issue. It could be necessary to install a separate, free-standing stack 

with reheat for each scrubber to avoid the “wet” plumes. The addition of stacks and reheaters would 

also increase both the capital and operating cost of this candidate control technology, making it even 

less cost-effective. 

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Appendix H.5 - 29

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INVISTA Chattanooga 4-6 Trinity Consultants 

Four-Factor Analysis 

4.3 SPRAY DRYER ABSORBER SYSTEM

An SDA system would include separate reactant atomization and injection sub-systems and an 

absorption vessel located upstream of the baghouse in each existing air pollution control train. The 

existing baghouses would be used to collect fly ash as well as spent reactant. Hydrated lime would be 

the reactant. The SO2 removal efficiency of this control technology option was assumed to be 85 

percent. 

Installation of an SDA system would likely cause significant changes to the existing methods for 

collecting, handling and disposing of fly ash. INVISTA engineering has determined that the type of 

bags in each baghouse would need to be upgraded. In addition, due to the substantial increase in the 

quantity of material that would be collected by the baghouses, the existing fly ash handling system 

would have to be upgraded. 

Furthermore, fly ash gathered from the baghouses currently is hydraulically conveyed to an ash pond 

where it is mixed with bottom ash from EU-002. The combined ash is periodically dredged from the 

pond and trucked to a nearby cement kiln for beneficial reuse. The reuse of the fly ash currently 

helps to offset the potentially significant cost of ash handling and disposal. 

Physical properties (pH, moisture content, ash fusion temperature, etc.) of the fly ash and spent 

reactant collected by the baghouses under the SDA option would be different from those physical 

properties of the current fly ash. Similarly, the chemical properties of the particulate matter collected 

under the SDA option would be different from those chemical properties of fly ash that is now 

collected. Consequently, the SDA option could result in an overall ash with properties so different 

from the current ash that it would no longer be acceptable for use in the cement kiln. If that becomes 

the case, the ash and spent reactant mixture would have to be trucked offsite for disposal in a landfill 

at a substantial increase in cost relative to the current disposal. 

The estimated cost of the SDA option was based on general cost data for SDA systems provided in 

Table 1A of the Air Pollution Control Technology Fact Sheet – Flue Gas Desulfurization 

(EPA-F/452-03-34) included in Appendix B. This EPA reference was used because (1) there is no 

cost information in the EPA Control Cost Manual pertaining to SDA systems, (2) the heat input 

capacity of EU-002 is below the size range of coal-fired utility boilers for which the EPA 

CUECOST3 spreadsheet was intended, and (3) SDA vendors have been unresponsive to Company 

requests for budgetary quotes. 

According to Table 1A of the referenced EPA control technology fact sheet, the range of costs for an 

SDA system for boilers having firing rates of less than 2,000 MMBtu per hour is listed in Table 4-3. 

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Appendix H.5 - 30

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INVISTA Chattanooga 4-7 Trinity Consultants 

Four-Factor Analysis 

TABLE 4-3. EXTRACT FROM EPA TABLE 1A (EPA-F/452-03-34) 

BOILERS < 2,000 MMBTU/HR

Capital Cost 

($/MMBtu/hr) 

O & M Cost 

($/MMBtu/hr) 

Annual Cost 

($/MMBtu/hr) 

Cost of SO2

Removed 

($/ton) 

30,000 – 150,000 1,000 – 30,000 10,000 – 50,000 500 – 4,000 

Overall, EPA’s Table 1A in the Agency’s fact sheet indicates that both capital and operating costs for 

SDA increase substantially as boiler capacity decreases. Under this control technology option, the 

maximum heat input rate for which each SDA system would be designed would be approximately 

eight percent of the maximum firing rate (2,000 MMBtu/hr) for which Table 1A contains cost data (as 

shown above in Table 4-3). Given the inverse relationship between boiler capacity and SDA 

equipment costs, and given the comparatively small size of the boilers in EU-002, INVISTA believes 

it is reasonable to conclude that a specific cost of the SDA alternative for EU-002 will be no less than 

the maximum value for each of cost parameters shown above. 

Based on the above EPA information for the maximum costs for applying SDA to a “small” coalfired utility boiler, the cost-effectiveness of applying SDA to EU-002 is estimated to be at least 

$4,000 per ton. 

4.4 DRY SORBENT INJECTION SYSTEM

After EPA promulgated the “Boiler MACT,” INVISTA engineering prepared an analysis of the 

process and equipment requirements associated with retrofitting a DSI system on EU-002. That 

system design consisted of a separate lime injection system in the ductwork upstream of each 

baghouse. A new lime storage silo and handling equipment were also included. 

INVISTA determined that the type of bags in each baghouse would need to be upgraded. Due to the 

substantial increase in the quantity and properties of material to be collected by each baghouse, the 

Company concluded that the existing fly ash handling system would have to be upgraded and 

converted to a dry system. 

Using hydrated lime as the reactant, the DSI system was assumed to achieve an SO2 control 

efficiency of 50 percent. At the aforementioned baseline SO2 emission rate for EU-002, the required 

injection rate of hydrated lime was estimated to be 750 pounds per hour. 

Physical properties (pH, moisture content, ash fusion temperature, etc.) of the fly ash and spent 

reactant collected by the baghouses under the DSI option would be different from those physical 

properties of the current fly ash. Similarly, the chemical properties of the particulate matter collected 

under the DSI option would be different from those chemical properties of fly ash that is now 

collected. Consequently, the DSI option could result in an overall ash with properties so different 

from the current ash that it would no longer be acceptable for use in the cement kiln. If that becomes 

the case, the ash and spent reactant mixture would have to be trucked offsite for disposal in a landfill 

at a substantial increase in cost relative to the current disposal. 

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Appendix H.5 - 31

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Four-Factor Analysis 

A budgetary quotation was obtained by INVISTA engineering from Bundy Environmental 

Technology for the injection components of a DSI system. The quotation was used along with other 

equipment cost data in a factored estimate of total capital cost and total annual cost for installation 

and operation of the DSI system. 

The TCI for the DSI system, presented in Table 4-4, is $4,700,000. The estimated TAC for the DSI 

system, presented in Table 4-5, is $1,905,890. This latter cost was estimated assuming that EU-002 

would be operated under the same average conditions as occurred during the period of 2004, 2005 

and 2006. The capital recovery factor utilized in the estimated TAC is based on an interest rate of 

8.0% and an economic lifetime of 10 years. 

The estimated SO2 removed by the DSI option is 472 tons per year, based on a 50% control efficiency 

and the 944 tpy historical emissions. The remaining SO2 emitted under this option was likewise 

estimated to be 472 tons per year. The estimated cost-effectiveness of the DSI option when EU-002 

is operated under the baseline conditions was estimated to be $4,037 per ton of SO2 removed.

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Appendix H.5 - 32

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Four-Factor Analysis 

TABLE 4-4. TOTAL CAPITAL INVESTMENT ESTIMATE – DRY SORBENT INJECTION OPTION

Factor Estimate

Direct Costs

Purchased equipment costs

Lime injection equipment Quotation $475,000

Dry fly ash system Quotation $830,000

New filter bags Quotation $116,000

Lime storage silo Estimate $8,000

Other equipment Estimate $42,000

A= $1,471,000

Instrumentation 0.10 x A $147,100

Sales Tax 0.03 x A $44,130

Freight 0.05 x A $73,550

Total Purchased equipment cost (PEC) B= $1,735,780

Direct installation costs

Labor Estimate $328,786

Field materials Estimate $142,700

Dismantlement & removal Estimate $80,000

Foundations & supports 0.04 x B $69,431

Handling & erection 0.50 x B $867,890

Electrical 0.08 x B $138,862

Piping 0.01 x B $17,358

Insulation for duct work 0.07 x B $121,505

Painting 0.04 x B $69,431

Contengencies 0.20 x B $347,156

Total Direct installation cost $2,183,119

Total Direct Cost (DC) $3,918,899

Indirect Costs (installation)

Engineering 0.10 x B $173,578

Construction and field expenses 0.20 x B $347,156

Contractor fees 0.10 x B $173,578

Start-up 0.01 x B $17,358

Performance test 0.01 x B $17,358

Contingencies 0.03 x B $52,073

Total Indirect Cost (IC) $781,101

Total Capital Investment (TCI) = DC + IC $4,700,000

Cost Item

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Appendix H.5 - 33

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INVISTA Chattanooga 4-10 Trinity Consultants 

Four-Factor Analysis 

TABLE 4-5. TOTAL ANNUAL COST ESTIMATE – DRY SORBENT INJECTION OPTION

Cost Item Calculation Cost

Direct Annual Costs (DC)

Operating labor

Operator $22.90/hr x 8 man-hr/day x 7.0 day/week x 52 week/yr $66,685

Supervisor 15% of operator labor = 0.15 x $66,685 $10,003

Consummables

Lime 750 lb/hr x 1 ton/2,000 lb x $100/ton x 24 hr/day x 7 day/week x 52 $327,646

Maintenance

Labor $22.70/hr x 4.0 hr/day x 7.0 day/week x 52 week/yr $33,051

Material 100 percent of maintenance labor $33,051

Replacement parts

Bags (materials and labor) CRF for bags x bag replacement cost: 0.388 x $156,800 $60,844

Residue Disposal

Flyash 1.00 ton/hr x 24 hr/day x 7 day/week x 52 week/yr x $45.00/ton $394,402

Utilities

Electricity $0.0500 /kW-hr x 99 kW x 24 hr/day x 7 day/week x 52 week/yr $43,221

 Total DC $968,903

Indirect Annual Costs (IC)

 Overhead 34% of sum of operating, supv., maint. labor & materials

= 0.34 x ($66,685 + $10,003 + $33,051 + $33,051) $48,549

 Administrative charges 2% of Total Capital Investment = 0.02 x $4,700,000 $94,000

 Property taxes 1% of Total Capital Investment = 0.01 x $4,700,000 $47,000

 Insurance 1% of Total Capital Investment = 0.01 x $4,700,000 $47,000

 Capital recovery CRF x TCI = 0.1490 x $4,700,000 $700,439

 Total IC $936,987

Total Annual Cost (TAC) $1,905,890

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Appendix H.5 - 34

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INVISTA Chattanooga 4-11 Trinity Consultants 

Four-Factor Analysis 

4.5 COSTS OF OTHER CAA PROGRAMS

In a subsequent section of this analysis, INVISTA demonstrates that emission reductions required by 

other CAA programs will be highly successful in improving visibility in many Class I areas 

throughout the Southeast. Indeed, VISTAS’ modeling predicts that visibility improvement in Cohutta 

over the first regional haze planning period due solely to reductions from other CAA programs will 

exceed, by a significant margin, the visibility improvement defined by the area’s uniform rate of 

progress. 

The economic impact of that collateral benefit to the regional haze program cannot be ignored. 

During its regional haze rulemaking, EPA acknowledged that visibility improvements from other 

CAA requirements essentially had no costs attributable to the regional haze program7. In other 

words, while those other CAA requirements reduce emissions and improve visibility, the “costeffectiveness” of those reductions with respect to the regional haze program are zero dollars per ton. 

For example, consider a FGD system installed to comply with the Clean Air Act’s acid rain program. 

The costs for those controls, although substantial, are not attributable to the regional haze program. 

Thus, with respect to a four-factor analysis for reasonable progress, the “cost of compliance” for that 

control measure would be $0 per ton SO2 removed. 

That “cost of compliance” contrasts sharply with the $3,508 per ton “cost-effectiveness” of the FGD 

option in this analysis for EU-002. In short, when evaluated with the “cost of compliance” statutory 

factor, visibility improvements from other CAA programs will always constitute reasonable progress 

compared to those visibility improvements required solely by the regional haze program. Especially 

in cases such as this one, where reasonable progress beyond Cohutta’s glide path will occur due to 

other CAA programs, any small or de minimis improvement in visibility considered in a regional 

haze “four-factor analysis” cannot be deemed cost-effective. Therefore, relative to visibility 

improvements by other CAA programs, the cost of compliance for each SO2 control option 

considered in this analysis could not be representative of reasonable progress. 

4.6 ANOTHER COST-EFFECTIVE METRIC

In a subsequent section of this analysis, INVISTA also demonstrates why consideration of visibility 

improvement is an integral component of a so-called “four-factor analysis.” While the costeffectiveness of a given control option may look acceptable when expressed in terms of $/ton of SO2

removed, that particular metric says virtually nothing about how effective the control option would 

actually be (i.e., the amount of any resulting visibility improvement). 

EPA has acknowledged States may want to consider a more representative metric, the “cost of 

compliance.” As the Agency has stated, “[I]n assessing additional emission reduction strategies for 

 7 EPA, Regulatory Impact Analysis for the Final Regional Haze Rule, Apr. 22, 1999 

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Four-Factor Analysis 

source categories or individual, large scale sources, simple cost-effectiveness estimates based on 

dollar-per-ton calculation may not be as meaningful as a dollar-per-deciview calculation.”8 

In this particular analysis, the Company has determined that the four SO2 control options will cost at 

least $1,225 and extend to more than >$4,000 per ton of SO2 removed. The Company has also shown 

in a latter section of this analysis that none of the control options is expected to improve visibility 

perceptibly in the Cohutta Class I area. Consequently, those control options’ cost-effectiveness 

values from a visibility improvement perspective will be large (approaching hundreds of thousands of 

dollars) divided by a de minimis improvement in visibility, resulting in a huge $/dv cost-effectiveness 

value. On the cost-effectiveness basis alone, it would not be appropriate to find the de minimis 

improvement in visibility achieved by each candidate control option to constitute reasonable progress. 

4.7 LOCAL ECONOMIC IMPACT

In EPA’s opinion, an assessment of the “cost of compliance” statutory factor can encompass “the 

implication of compliance costs to the health and vitality of industries within a state9.” The Agency’s 

position reinforces its well-settled view that each State has considerable discretion as to how it weighs 

the statutory factors in any reasonable progress analysis. As EPA has explained: 

 [T]he visibility regulations give the States a great deal of flexibility in 

determining the measures they choose to assure reasonable progress toward 

the national visibility goal. As the Act requires, EPA has provided measures 

for the States to consider, but left the actual ‘mix’ of measures adopted to the 

States’ discretion10. 

At page 1-4 of its Reasonable Progress Guidance, EPA also acknowledges the flexibility which States 

have in their reasonable progress planning, as follows: 

 In deciding what amount of emissions reduction is appropriate in 

setting the RPG, you should take into account the fact that the long-term 

goal of no manmade impairment encompasses several planning periods. 

It is reasonable for you to defer reductions to later planning periods in 

order to maintain a consistent glidepath toward the long-term goal. 

In other words, the States should not feel compelled to weigh the statutory factors in such a manner as 

to require substantial emission reductions in order to maximize visibility improvement achieved by 

2018. 

In light of this philosophy of planning for the “long run,” INVISTA respectfully requests TDEC to 

consider the economic “health and vitality” of the Company’s Chattanooga facility when weighing 

the statutory factors and the related visibility improvement from applying SO2 control options at that 

 8 EPA, Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program, 5-2 (June 1, 2007) 

(hereinafter “Reasonable Progress Guidance”). 

9 Id. at 5-1. 

10 EPA, Summary of Comments and Responses on the May 22, 1980 Proposed Regulations for Visibility 

Protection for Federal Class I Areas, 172 (Oct. 1980). 

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Four-Factor Analysis 

facility. INVISTA clearly recognizes the ever-present tension between environmental protection and 

economic growth and stability. In this instance, however, the Company believes that significant 

visibility improvement from other CAA programs weighs heavily against imposing additional SO2

control costs on the Chattanooga Plant with the State’s initial regional haze SIP. As EPA guidance 

allows, TDEC’s ultimate reasonable progress decision is encouraged to qualitatively account for the 

economic impacts of that decision not only upon the facility’s continued vitality but also upon the 

economic well-being of its employees and the surrounding community. 

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Four-Factor Analysis 

5. TIME NECESSARY FOR COMPLIANCE

The estimated minimum time periods necessary for INVISTA to implement each of the four SO2

control options in this analysis are listed in the table below. 

TABLE 5-1. TIME NECESSARY FOR COMPLIANCE

Option No. Description Time to Implement 

1 Low sulfur coal 1 year 

2 Wet FGD system 3 years 

3 Spray dryer absorber system 3 years 

4 Dry sorbent injection system 3 years 

The major activities required for implementation of the low sulfur coal option include the following: 

♦ Obtain quotations from vendors 

♦ Negotiate a procurement contract 

♦ Complete the existing coal contract and depletion of the existing coal stock 

♦ Receive sufficient quantities of the lower sulfur coal 

The major activities required for implementation of any of the post-combustion SO2 emission control 

systems are anticipated to include the following: 

♦ Complete a full engineering estimate of capital and O&M costs 

♦ Obtain approval for the project and allocate funds 

♦ Initiate detailed design project 

♦ Order long-lead items 

♦ Obtain necessary permits 

♦ Solicit bids and award construction project 

♦ Construct the system 

♦ Start up system and debug 

♦ Commence normal operations. 

While implementation of the four control options in this analysis could theoretically be accomplished 

within 1-3 years, current market demands for SO2 controls by utilities seeking to comply with the 

Clean Air Interstate Rule (CAIR) and Clean Air Mercury Rule (CAMR) could realistically delay 

implementation of such options at INVISTA by up to five years. 

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Appendix H.5 - 38

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Four-Factor Analysis 

6. ENERGY AND NON-AIR QUALITY ENVIRONMENTAL IMPACTS

The anticipated energy and non-air quality environmental impacts of the SO2 emission control options 

in this analysis are listed below in Table 6-1. 

TABLE 6-1. ENERGY AND NON-AIR QUALITY ENVIRONMENTAL IMPACTS

Option 

No. Description Energy Impacts 

Non-Air Quality 

Environmental Impacts 

1 Low sulfur 

coal 

May have to be shipped from greater 

distances, resulting in additional fuel 

usage. 

None identified 

2 Wet FGD 

system 

Additional fuel usage to transport lime 

to Facility, increased electricity usage 

for lime handling, recirculation 

pumps, and to overcome increased 

pressure drop across scrubbers. 

Potential for increased fuel use if stack 

reheaters are needed to reduce steam 

plumes. 

Use of substantial quantities 

of fresh water. Generation of 

substantial quantities of 

industrial wastewater 

containing suspended and 

dissolved solids requiring 

disposal. 

3 Spray dryer 

absorber 

Additional fuel usage to transport lime 

to Facility, increased electricity usage 

for lime injector and due to increased 

pressure drop in absorption chamber 

and baghouse. Potentially increased 

fuel and electricity usage if fly ash 

must be disposed of at the landfill. 

Potential for increased fuel use if stack 

reheaters are needed to reduce steam 

plumes. 

Use of substantial quantities 

of fresh water. Potential for 

degradation in quality of 

water discharged from ash 

pond outfall due to lime and 

dissolved salts. Potentially 

substantial increase in solid 

waste generation and disposal 

if fly ash cannot be recycled. 

4 Dry Sorbent 

Injection 

System 

Additional fuel usage to transport lime 

to Facility, increased electricity usage 

for lime injector and due to increased 

pressure drop in baghouse. Increased 

fuel and electricity usage due to 

disposal of fly ash at the landfill 

Substantial increase in solid 

waste generation and disposal 

associated with fly ash and 

spent reactant. 

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Appendix H.5 - 39

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Four-Factor Analysis 

7. REMAINING USEFUL LIFE OF EXISTING SOURCES IN EU-002 

In keeping with EPA’s Reasonable Progress Guidance, INVISTA has estimated the remaining useful 

lives of Boilers 3, 4 and 5 in EU-002 to be between 20 and 30 years. Boilers 3, 4, and 5 were 

installed in 1953, 1966 and 1969, respectively, and thus currently range in age from 38 years to 54 

years. 

It is difficult to predict the remaining useful life of a boiler because that projection is necessarily done 

on a case-by-case basis and typically is influenced by numerous design and construction parameters 

as well as the detailed operational and maintenance histories of the individual unit. At this time the 

Company expects each of the three boilers to continue operating beyond the end of the initial regional 

haze planning period (2018). 

EPA considers this particular statutory factor to be little more than one element of the cost-ofcompliance analysis. Accordingly, EPA suggests that “[i]f the remaining useful life of the source will 

clearly exceed this time period [for amortizing the cost of a control device], the remaining useful life 

factor has essentially no effect on control costs and on the reasonable progress determination11.” 

INVISTA respectfully disagrees with EPA’s limited view of this statutory factor. 

It is highly unlikely that Congress intended the “useful life” factor to be nothing more than part of the 

“cost-of-compliance” factor. If that were the only intended purpose of the “useful life” factor, it is 

reasonable to expect that Congress would never have expressly and separately identified that 

parameter. 

Furthermore, INVISTA believes that the legislative history of section 169A of the 1977 Amendments 

to the Act supports its view that Congress was extremely reluctant to require the widespread 

retrofitting of control equipment on existing, older sources. During the 1977 Amendments, Congress 

adopted the PSD program, requiring best available control technology on new and modified major 

sources. In doing so, Congress deliberately “grandfathered” existing major sources, concluding that 

the imposition of substantial costs for new control equipment on existing units did not constitute 

sound public policy. 

Nevertheless, when adopting the visibility protection provisions of the 1977 Amendments, Congress 

did carve out a subset of existing major sources for which best available retrofit technology (BART) 

was required. The legislative history of those visibility provisions confirms that potentially BARTeligible sources were restricted to those which began operation between 1962 and 1977 because 

Congress did not want to require those expensive retrofits on units that were more than 15-years-old. 

In other words, INVISTA believes that “remaining useful life” is a distinct statutory factor because 

Congress expected that any requirement for retrofit controls on sources greater than 15-years-old 

would be disfavored. 

 11 EPA, Reasonable Progress Guidance, 5-3. 

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INVISTA Chattanooga 7-2 Trinity Consultants 

Four-Factor Analysis 

To be sure, any application of the statutory factors does not lend itself to a completely objective and 

quantitative analysis. The “useful life” factor is a case in point. While the visibility provisions of the 

Act do not prohibit the requirement of retrofit controls on any unit of a certain age or older, INVISTA 

believes that the legislative histories and structures of those provisions and the PSD program evince 

congressional sentiment not to require control measures on existing major sources, in general, and on 

existing major sources over 15-years-old, in particular. Yet, at this time INVISTA is confronted with 

the possibility of retrofitting SO2 controls on its units which range in age from 38 to 54 years. As 

explained, that prospect goes against the general grain of the Act’s visibility and PSD provisions, and 

the Company encourages TDEC’s ultimate decision to qualitatively weigh the fact that INVISTA’s 

units are considerably older than those of a limited subset which Congress explicitly approved for 

retrofits of control technologies12. 

 12 In response to those who would reply that older sources should be required to retrofit control equipment 

because companies will simply continue rebuilding and refurbishing sources so their remaining useful lives are extended 

indefinitely without retrofit controls, one need only look to EPA’s success with its NSR Enforcement Initiative over the past 

decade in which the Agency has narrowly interpreted any PSD exclusion for routine maintenance, repair and replacement. 

In most cases, the source undergoing such changes becomes a “major modification” subject to the retrofit application of 

BACT. 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix H.5 - 41

January 18, 2008
INVISTA Chattanooga 8-1 Trinity Consultants 

Four-Factor Analysis 

8. VISIBILITY IMPROVEMENT

It is unfortunate that this methodology under the Regional Haze Rule has been dubbed the “fourfactor analysis,” because that misleading terminology creates an impression that only four specific 

factors or parameters should be evaluated. An analysis based solely on evaluating four statutory 

factors would be completely meaningless in the context of the congressional goal (i.e., visibility 

improvement to natural background levels in Class I areas). 

The plain language of the statute expresses the legislative intent as follows: 

 [I]n determining reasonable progress there shall be taken into 

consideration [1] the costs of compliance, [2] the time necessary for 

compliance, and [3] the energy and nonair quality environmental impacts of 

compliance, and [4] the remaining useful life of any existing source subject 

to such requirements (emphasis added)13. 

Congress had no expectation that its four listed factors would be evaluated in isolation. Rather, as the 

statutory language indicates, those four factors should be considered “in determining reasonable 

progress.” In that context, the word “progress” is nothing more than a synonym for “visibility 

improvement.” Thus, the Act mandates that the four listed factors be evaluated with respect to their 

influence upon a fifth factor, visibility improvement. 

 

Section 169A of the Act clearly contemplates States requiring “such emission limits, schedules of 

compliance and other measures as may be necessary to make reasonable progress toward the national 

goal.” In other words, Congress obviously recognized that emission reductions from new control 

measures might be necessary to achieve reasonable progress. But the language above confirms that 

Congress intended that visibility improvement resulting from any such control measure being 

considered under section 169A should be evaluated relative to four specific factors. 

In other words, there appears to be a widespread misconception that the four statutory factors are 

evaluated to determine “reasonable” control measures. However, the statute clearly requires 

consideration of four specific factors to determine whether the visibility improvement associated with 

a candidate control measure will be reasonable. Weighing the visibility improvement from a potential 

control measure in terms of the four factors listed in the statute is the only statutory interpretation 

which gives effect to all of the above words in that provision for determining reasonable progress. 

Moreover, consideration of the related visibility improvement during any “four-factor analysis” is 

simply intuitive, common-sense14. 

 13 42 U.S.C. § 7491(g)(1) 

14 “[I]t is self evident that visibility improvement must be considered in determining what progress is reasonable 

in remedying visibility impairment.” EPA, Draft Guidance for Setting Reasonable Progress Goals Under the Regional 

Haze Program, § 5.0, p. 1 (Nov. 28, 2005). 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix H.5 - 42

January 18, 2008
INVISTA Chattanooga 8-2 Trinity Consultants 

Four-Factor Analysis 

8.1 POTENTIAL INVISTA SO2 IMPACT ON VISIBILITY

For this four-factor analysis, INVISTA ideally would have performed CALPUFF modeling of the 

visibility impacts at Cohutta not only due to EU-002’s baseline SO2 emissions but also due to those 

estimated SO2 emissions resulting from application of each of the four control technology options in 

this analysis. With such modeling results, the Company could estimate the extent of visibility 

improvement resulting from each candidate control, which could then be weighed with the four listed 

statutory factors. However, INVISTA simply did not have the resources available in the required 

timeframe to perform such comprehensive modeling for this four-factor analysis. 

Nevertheless, it is possible to estimate the maximum visibility improvement which could be achieved 

at Cohutta by retrofitting EU-002 with SO2 control technology. Modeling projections by VISTAS 

have suggested that EU-002’s baseline SO2 emissions would contribute up to 1.5% of the total 

visibility impairment in the Cohutta Wilderness Area in 2018. VISTAS’ modeling has also predicted 

that by 2018 the haziness index in Cohutta will be about 23 dv15. Therefore, applying an overly 

simplistic assumption for the purpose of this analysis only that EU-002’s visibility impact without 

any SO2 control option is 0.34 dv (23 dv × 0.015), then a maximum achievable SO2 reduction of 92% 

with an FGD system conceivably would result in reducing EU-002’s visibility impact in Cohutta by 

0.31 dv. 

In its BART modeling protocol, VISTAS defined a contribution to visibility impairment as equal to 

or greater than a threshold level of 0.5 dv16. This metric obviously suggests that EU-002’s SO2

emissions without any added SO2 control measure do not, by definition, “contribute” to regional haze 

in the Cohutta Wilderness Area. Furthermore, a maximum reduction in those existing SO2 emissions 

from EU-002 would result in a decrease in visibility impairment of no more than 0.3 dv, a change in 

visibility which is less than the minimum value perceptible to the human observer. 

In short, it appears that in 2018 EU-002’s baseline SO2 emissions will not contribute to visibility 

impairment in the Cohutta Wilderness Area. Consequently, the use of any control option on those 

emissions seems highly unlikely to produce any tangible visibility benefit. That is, by any measure, 

the de minimis visibility improvement achievable by any of the candidate control; measures for 

INVISTA’s boilers could not be considered reasonable progress. 

8.2 IMPACT OF OTHER CAA PROGRAMS

The Clean Air Act has already established a number of control programs, such as Acid Rain, NOx SIP 

Call, and CAIR that require reductions in air pollutants that also happen to cause visibility 

impairment. Consequently, those existing CAA programs create a collateral benefit, the improvement 

of visibility in Class I areas. EPA has acknowledged that a State’s planning for reasonable progress 

“should reflect at least the rate of visibility improvement expected from the implementation of ‘other’ 

 15 VISTAS, “Uniform Rate of Progress Glide Path (Base G2a projections),” Cohutta - 20% Worst Days, New 

IMPROVE equation. 

16 VISTAS, Protocol for the Application of the CALPUFF Model for Analyses of Best Available Retrofit 

Technology (BART), 5 (Dec. 22, 2005). 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix H.5 - 43

January 18, 2008
INVISTA Chattanooga 8-3 Trinity Consultants 

Four-Factor Analysis 

applicable requirements under the CAA.”17 In its Regional Haze Rule, EPA established an analytical 

methodology which requires States to consider “setting an ambitious reasonable progress goal, one 

that is aimed at reaching natural background conditions in 60 years (emphasis added)18.” By 

establishing a 60-year period for each Class I area to reach its natural background levels of visibility, 

EPA’s “ambitious reasonable progress goal” effectively establishes a presumptively acceptable goal 

defined by a uniform rate of visibility improvement (the glide path). 

Given the visibility improvement from “other” CAA requirements and its ambitious reasonable 

progress goal defined by a uniform rate of progress, EPA has acknowledged its expectation for “the 

eastern United States that the reductions from measures implementing the CAA requirements will 

provide the visibility improvement and emissions [reductions] needed for reasonable progress during 

the first regional haze implementation plan19.” With respect to specifics of the Cohutta Wilderness 

Area, VISTAS has estimated that visibility improvement at a uniform rate of progress will result in a 

haziness index during the area’s 20% worst days equal to 25.51 dv by 2018, the end of the first 

planning period for regional haze SIPs20. In addition, VISTAS has projected that visibility 

improvement attributable to “other” (non-regional-haze) CAA requirements will result in a haziness 

index in Cohutta of 22.02 dv by 2018. In other words, if Cohutta’s visibility of 25.81 dv in 2018 

constitutes the “ambitious reasonable progress goal” described by EPA, then existing CAA programs 

will exceed that goal by almost 3 dv. 

In short, VISTAS’ modeling confirms EPA’s earlier prediction that the initial reasonable progress 

goal of a Class I area such as Cohutta would be realized without the need to require control measures 

under the regional haze program. Given the substantial visibility improvement in Cohutta to be 

achieved from other CAA programs by 2018, any de minimis visibility improvement from a control 

option on EU-002 when considered with the four statutory factors could not logically be found to be 

“reasonable.” 

 17 64 Fed. Reg. 35733 (July 1, 1999). 

18Id. at 35731 

19 Id. at 35733 

20 VISTAS, “Uniform Rate of Progress Glide Path (Base G2a projections),” Cohutta - 20% Worst Days, New 

IMPROVE equation 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix H.5 - 44

January 18, 2008
INVISTA Chattanooga 9-1 Trinity Consultants 

Four-Factor Analysis 

9. ANALYSIS AND CONCLUSION

In response to a request from TDEC, INVISTA has examined whether reasonable progress could be 

achieved in the Cohutta Wilderness Area by retrofitting the coal-fired boilers’ exhausts at the 

Company’s Chattanooga facility with an SO2 emission control technology. The Company first 

identified the following four SO2 control options as technically feasible: (1) low-sulfur coal; (2) flue 

gas desulfurization (FGD); (3) Spray Dryer Absorber (SDA); and (4) Dry Sorbent Injection (DSI). 

The predicted visibility improvement resulting from each of these candidate control measures was 

then evaluated with the four listed statutory factors. 

The results of this four-factor analysis were heavily influenced by the following findings: 

1. Installation of each of the four control options would result in a de minimis improvement 

in visibility at Cohutta which would not be detectable to the human observer; 

2. By 2018, visibility improvement in Cohutta resulting from emission reductions required 

by other CAA programs will be more than the visibility improvement which would be 

obtained in 2018 with the Area’s uniform rate of progress; 

3. The “cost-effectiveness” values of the control options ranged from $1,225 per ton to 

more than $4,000 per ton, but those values are misleading because of the de minimis 

visibility improvement resulting from each option; 

4. A more telling cost-effectiveness metric for evaluating the control options is $/dv. While 

quantitative $/dv values could not be determined, their values would be extraordinarily 

high due to the de minimis visibility improvement with each option. 

In addition, this four-factor analysis determined the following: 

1. The cost of any visibility improvement from each reasonable progress control option 

would be extremely excessive in comparison to the incremental zero cost of visibility 

improvements achieved by other CAA programs through 2018. 

2. Implementation of each control option could theoretically require from 1 to 3 years in the 

absence of any constraints. However, ongoing electric utility compliance plans for 

applicable CAIR and the CAMR requirements will severely constrain the availabilities of 

FGD, SDA and DSI systems as well as the skilled construction personnel that must install 

such retrofits. As a result, the time for INVISTA to comply with any of the four control 

options herein could be delayed by up to five years. 

3. Each of the three SO2 control devices would use significant amounts of energy. The 

FGD and the SDA would use significant amounts of water. The FGD, the SDA and the 

DSI would each create substantial quantities of either liquid or solid wastes. 

4. In crafting the visibility and PSD provisions of the 1977 Amendments, Congress was 

reluctant to require the retrofitting of control technologies on existing major sources, the 

one exception being BART for certain large sources no more than 15-years-old. 

Although INVISTA’s three boilers are expected at this time to operate beyond 2018, their 

current ages range from 38 to 54 years. 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix H.5 - 45

January 18, 2008
INVISTA Chattanooga 9-2 Trinity Consultants 

Four-Factor Analysis 

In this four-factor analysis, INVISTA believes that compelling weight must be given to the findings 

that (1) each of the control options will result in only de minimis visibility improvement, (2) none of 

the cost options therefore will actually be cost-effective, and (3) without any control options at 

INVISTA, visibility improvement in Cohutta by 2018 will nevertheless exceed that required from the 

uniform rate of progress glidepath. 

Therefore, consistent with EPA’s original projections for visibility improvement in the Eastern 

Class I areas, INVISTA concludes that the reasonable progress goal for Cohutta during the initial 

planning period will be achieved by emission reductions from other CAA programs, and that no SO2

control option on the boilers at Chattanooga would achieve reasonable progress during that same 

period. 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix H.5 - 46

January 18, 2008
Four-Factor Analysis A - 1 Trinity Consultants 

APPENDIX A 

CONTROL DEVICE INFORMATION

Sizing Calculations 

Vendor Supplied Data 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix H.5 - 47

January 18, 2008
INVISTA Chattanooga Four Factor Analysis

Wet FGD Sizing Calculations

Variable Value

Cmax Maximum permitted coal consumption 112,000 ton/yr

Smax Maximum permitted coal sulfur content 1.25%

EFSO2 SO2 emission factor 38.38

Cavg Average coal consumed in 2004, 2005, 2006 50,719 ton/yr

Savg Average sulfur content of coal consumed in 2004, 2005, 2006 0.97%

Rgmax Gas flow rate per scrubber at maximum design conditions 74,000 acfm

Pdmax Pressure drop per scrubber at maximum design conditions 4.0 inch wg

Ectl SO2 removal efficiency of scrubbers at maximum design conditions 92%

Lmax Ca(OH)2 usage per scrubber at maximum permitted coal sulfur and consumption 423 lb/hr

Rwmax Fresh water makeup rate per scrubber at maximum design conditions 78 gal/min

Rbmax Blowdown rate per scrubber at maximum design conditions 54 gal/min

Rr Liquor recirculation rate per scrubber at maximum design conditions 3,300 gal/min

Pr Scrubber liquor recirculation pressure 20 psig

Ri Design inlet SO2 mass flow rate per scrubber at maximum design conditions 327 lb/hr

Assumed operating duty cycle of EU-002 per 365 day period 8,760 hr

HVcoal Average coal heating value 13,591 Btu/lb

Rflyash Flyash generation rate for EU-002 0.00366 ton/MMBtu

Maximum Potential Uncontrolled SO2 Emissions from EU-002

EUmax = Cmax x Smax x EFSO2 / 2,000 lb/ton

= 112,000 ton/yr x 1.25% x 38.38 / 2,000 lb/ton 2,687 ton/yr

Baseline Uncontrolled SO2 Emissions from EU-002

EUbase = Cavg x Savg x EFSO2 / 2,000 lb/ton

= 50,719 ton/yr x 0.97% x 38.38 / 2,000 lb/ton 944 ton/yr

Baseline Controlled SO2 Emissions from EU-002

ECbase = EUbase x (1 - CE)

= 944 ton/yr x (1 - 0.92) 76 ton/yr

SO2 Removed from EU-002 Under Baseline Operating Conditions

ERFGDbase = EUbase - ECbase

= 944 ton/yr - 76 ton/yr 869 ton/yr

Estimated Total Ca(OH)2 Usage at Baseline Operating Conditions

Lbase = 2 x Lmax x (Cavg/Cmax) x (Savg/Smax)

= 2 x 423 lb/hr x (50,719 ton/yr / 112,000 ton/yr) x (0.97% /1.25%) 297 lb/hr

Estimated Total Make-Up Water Usage at Baseline Operating Conditions

Rwbase = 2 x Rwmax x (Cavg/Cmax) x (Savg/Smax)

= 2 x 78 gal/min x (50,719 ton/yr / 112,000 ton/yr) x (0.97% /1.25%) 55 gal/min

Estimated Total Blow Down Flow at Baseline Operating Conditions

Rbbase = 2 x Rbmax x (Cavg/Cmax) x (Savg/Smax)

= 2 x 54 gal/min x (50,719 ton/yr / 112,000 ton/yr) x (0.97% /1.25%) 38 gal/min

Estimated Total Electrical Power Required for Recirculation Pumps at Maximum Design Conditions

From Section 5 of the EPA OAQPS Control Cost Manual (EPA/452/B-02-001):

Trinity Consultants

INVISTA Chttg 4 Factor Control Costs (2007-10-12).xls

Wet FGD calcs

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix H.5 - 48

January 18, 2008
INVISTA Chattanooga Four Factor Analysis

Wet FGD Sizing Calculations

EPrecircmax = 2 x 0.746 x 2.52x10-4 x Rr x Pr / ε

 Where ε is the combined pump/motor efficiency 0.70

= 2 x 0.746 x 0.000252 x 3,300 gal/min x 20 psig x 2.307 ft water/psig / 0.70 82 kW

Estimated Total Additional Electrical Power Required for I.D. Fan at Maximum Design Conditions

From Section 5 of the EPA OAQPS Control Cost Manual (EPA/452/B-02-001):

EPidfanmax = 2 x 1.17x10-4 x Rgmax x Pdmax / ε

 Where ε is the combined fan/motor efficiency 0.70

= 2 x 0.000117 x 74,000 acfm x 4 inches wg / 0.70 99 kW

Estimated Cost Effectiveness of FGD Option at Baseline Conditions

Ceff = TACFGD / ERFGDbase

= $3,046,633 / 869 ton $3,508/ton

Estimated Cost of Recirculation Pumps (for TCI estimate)

From the OAQPS Control Cost Manual:

Cost = 2 x Rr

 x $16/gpm 

= 2 x 3,300 gal/min x $16/gpm $105,600

Estimated Average Heat Input for EU-002 Operating at Baseline Consitions

HIbase = Cavg x 2,000 x HVcoal / (1,000,000 x 8,760) 157

= 50,719 ton/yr x 2,000 lb/ton x 13,591 Btu/lb / (1,000,000 Btu/MMBtu x 8,760 hr/yr)

Trinity Consultants

INVISTA Chttg 4 Factor Control Costs (2007-10-12).xls

Wet FGD calcs

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix H.5 - 49

January 18, 2008
INVISTA Chattanooga Four Factor Analysis

Wet FGD Sizing Calculations

Estimated Total Flyash/Spent Reactant Generation at Baseline Operating Conditions

Rwbase = HIbase x Rflyash + Lbase / 2,000 + Ectl x EUbase / 8,760 x (136.142 - 74.093) / 64.054 0.82

= 157 MMBtu/hr x 0.00366 ton/MMBtu + 297 lb/hr / 2,000 lb/ton + 0.92 x 944 ton/yr 

/ 8,760 hr/yr x (136.142 - 74.093) / 64.054

Trinity Consultants

INVISTA Chttg 4 Factor Control Costs (2007-10-12).xls

Wet FGD calcs

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix H.5 - 50

January 18, 2008
INVISTA Chattanooga Four Factor Analysis

Dry Sorbent Injection Sizing Calculations

Variable Value

Cavg Average coal consumed in 2004, 2005, 2006 50,719 ton/yr

HVcoal Average coal heating value 13,591 Btu/lb

EFSO2 SO2 emission factor 38.38

Savg Average sulfur content of coal consumed in 2004, 2005, 2006 0.97%

Rgmax Gas flow rate per scrubber at maximum design conditions 74,000 acfm

Pdmax Additional pressure drop per baghouse at maximum design conditions 4.0 inch wg

Ectl SO2 removal efficiency of DSI system at maximum design conditions 50%

NSR Normalized stoichiometric ratio 3.48

Rflyash Flyash generation rate for EU-002 0.00366 ton/MMBtu

Pr Scrubber liquor recirculation pressure 20 psig

Dop Assumed operating duty cycle of EU-002 per 365 day period 8,760 hr

Baseline Uncontrolled SO2 Emissions from EU-002

EUbase = Cavg x Savg x EFSO2 / 2,000 lb/ton

= 50,719 ton/yr x 0.97% x 38.38 / 2,000 lb/ton 944 ton/yr

Baseline Controlled SO2 Emissions from EU-002

ECbase = EUbase x (1 - CE)

= 944 ton/yr x (1 - 0.50) 472 ton/yr

SO2 Removed from EU-002 Under Baseline Operating Conditions

ERDSIbase = EUbase - ECbase

= 944 ton/yr - 472 ton/yr 472 ton/yr

Estimated Total Ca(OH)2 Usage at Baseline Operating Conditions

Lbase = NSR x EUbase x 2,000 / Dop

= 3.48 x 944 ton/yr x 2,000 lb/ton / 8,760 hr/yr 750 lb/hr

Estimated Average Heat Input for EU-002 Operating at Baseline Consitions

HIbase = Cavg x 2,000 x HVcoal / (1,000,000 x 8,760)

= 50,719 ton/yr x 2,000 lb/ton x 13,591 Btu/lb / (1,000,000 Btu/MMBtu x 

8,760 hr/yr) 157 MMBtu/hr

Estimated Total Flyash/Spent Reactant Generation 

at Baseline Operating Conditions

Rwbase = 

HIbase x Rflyash + Lbase / 2,000 + Ectl x EUbase / 8,760 x (136.142 - 74.093) /

64.054

= 157 MMBtu/hr x 0.00366 ton/MMBtu + 750 lb/hr / 2,000 lb/ton + 0.50 x 944

ton/yr / 8,760 hr/yr x (136.142 - 74.093) / 64.054 1.00 ton/hr

Trinity Consultants

INVISTA Chttg 4 Factor Control Costs (2007-10-12).xls

DSI Calcs

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix H.5 - 51

January 18, 2008
INVISTA Chattanooga Four Factor Analysis

Dry Sorbent Injection Sizing Calculations

Estimated Total Additional Electrical Power Required for I.D. Fan 

at Maximum Design Conditions

From Section 5 of the EPA OAQPS Control Cost Manual (EPA/452/B-02-001):

EPidfanmax = 2 x 1.17x10-4 x Rgmax x Pdmax / ε

 Where ε is the combined fan/motor efficiency 0.70

= 2 x 0.000117 x 74,000 acfm x 4 inches wg / 0.70 99 kW

Estimated Cost Effectiveness of FGD Option at Baseline Conditions

Ceff = TACDSI / ERDSIbase

= $1,905,890 / 472 ton $4,037/ton

Trinity Consultants

INVISTA Chttg 4 Factor Control Costs (2007-10-12).xls

DSI Calcs

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix H.5 - 52

January 18, 2008
 Proposal to 

TRINITY CONSULTANTS

 Atlanta, Georgia 

 

 

Wet Scrubber for 

Coal Fired Boiler 

Proposal No: Q08-1269 

September 25, 2007

 Prepared by 

 TurboSonic Technologies, Inc. 

 239 New Road 

 Building “B”, Suite 205 

 Parsippany, NJ, 07054 

 Phone: (973) 244-9544 

 Fax: (973) 244-9545 

 Contact: Jorgen G. Hedenhag

 TurboSonic Inc. 

 550 Parkside Drive, Suite A-14 

 Waterloo, Ontario, N2L 5V4 

 Phone: (519) 885-5513 

 Fax: (519) 885-6992

This proposal is and remains the property of TurboSonic. It contains proprietary 

and confidential information and is issued for the purpose of bid evaluation and 

purchase only. It is intended for the Addressee only and must not be copied or 

distributed without prior written consent of TurboSonic. 

 Upon completion of evaluation this material shall be returned or destroyed. 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix H.5 - 53

January 18, 2008
TurboSonic Page 2 of 10 

TRINITY CONSULTANTS 25 September, 2007 

Wet Scrubber for Coal Fired Boiler Proposal Q08-1269 

GENERAL DESCRIPTION

The purpose of the proposed Equipment is to remove SO2 and HCl in the exhaust 

gases from three coal fired Boilers in southern Tennessee. This proposal is based 

on information from Trinity Consultants received via e-mail, September 19, 2007.

GENERAL 

The ID Fan will draw the gases from the two existing baghouses blow them into 

two Scrubbers, one for each baghouse. The Scrubbers consist of Spray Tower 

Absorbers for acid gas absorption. 

SPRAY TOWER ABSORBER 

Each Spray Tower is a vertical vessel with radial inlet, where the gas continues 

vertically upwards through a number of spray zones, which provide the necessary 

contact surface for absorption of the acid gases. The Spray Headers are provided 

with large orifice spray nozzles, which are located so that the Absorber cross 

sectional area is completely covered and that no gas can escape without coming in 

intimate contact with the liquid. 

 

After passing through the Spray Zones the gas enters two Mist Eliminators of 

chevron type, which will eliminate droplet carry-over to the Tower outlet. In order 

to remove possible build up of reaction salts, the bottom Mist Eliminator is provided 

with wash sprays, one above and one below the unit. The upper Mist Eliminator 

has a wash spray from below. The wash will expose the units to a powerful spray 

of clean water. The wash is triggered by the plant DCS and is intermittent and 

covers only part of the Mist Eliminator at the same time. A few minutes per day 

are sufficient to maintain the Mist Eliminators clean. 

In order to attain required absorption of HCl and SO2 hydrated lime Ca(OH)2 is 

added to the top Spray Header, so that the gas leaving the Scrubber sees the 

highest pH. 

LIQUID LOOP 

The salt concentration in the recycle loop is maintained at 10% by a bleed (blow 

down) connected to the discharge side of the recycle pump(s). We propose one 

Pump for each Spray Zone, which yields a flexible Scrubber and makes it possible 

to shut down any Zone, if the acid gas conditions would so require. 

Evaporation takes place in the Scrubber and in order to compensate for the liquid 

removed from the Scrubber in the bleed and by evaporation, a liquid level 

controller in the bottom of the Absorber adds water via a control valve to maintain 

the pre-determined level. 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix H.5 - 54

January 18, 2008
TurboSonic Page 3 of 10 

TRINITY CONSULTANTS 25 September, 2007 

Wet Scrubber for Coal Fired Boiler Proposal Q08-1269 

GENERAL DESCRIPTION (Cont’d)

STACK 

The Exhaust Stack (supplied by Others) can be located on top of the Absorber. 

That yields a compact assembly with small footprint. We recommend that the gas 

velocity in the Stack shall not exceed 33 FPS. The gas entering the Stack is 100% 

saturated and condensation will take place on the inside stack walls. At higher gas 

velocities than 33 FPS the condensate will be thrown out of the Stack and cause 

“raining” around the stack area. At lower velocities the condensate drains back 

into the Absorber. 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix H.5 - 55

January 18, 2008
TurboSonic Page 4 of 10 

TRINITY CONSULTANTS 25 September, 2007 

Wet Scrubber for Coal Fired Boiler Proposal Q08-1269 

DESIGN DATA

PLANT DATA: 

Plant Elevation feet ASL 680 

Design Wind Load: MPH 90 

Seismic Zone: UBC #2 

Fuel Coal 

Boiler Rating (2 Boilers) MMBTU/hr 160 

Boiler Rating (1 Boiler) MMBTU/hr 65 

INLET CONDITIONS: (PER ABSORBER) 

Gas Flow ACFM 74,000 

Normal Gas Flow ACFM 70,000 

Gas Temperature oF 400 

Gas Composition (assumed) 

 O2 % by volume 5 

 CO2 % by volume 12 

 H2O % by volume 5 

 N2 % by volume 78 

Dry Gas Volume SCFMD 42,568 

Gas Pressure at Absorber Inlet Inch WG 4 Positive 

Gas Density lbs/ft3 0.0465 

SO2 Loading lbs/hr 327 

PPMDV 771 

HCl Loading lbs/hr 13 

PPMDV 54 

OUTLET CONDITIONS: (PER ABSORBER) 

Gas Volume (saturated) ACFM 55,069 

Gas Temperature (saturated) °F 124.7 

Dry Gas Volume SCFMD 42,568 

Moisture Content % by Volume 13.24 

Gas Pressure at Outlet Inch WG 0 

SO2 Loading lbs/hr 26 

PPMDV 61 

HCl Loading lbs/hr 2.4 

PPMDV 10 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix H.5 - 56

January 18, 2008
TurboSonic Page 5 of 10 

TRINITY CONSULTANTS 25 September, 2007 

Wet Scrubber for Coal Fired Boiler Proposal Q08-1269 

OPERATING DATA: (PER ABSORBER) 

Pressure Drop 

Pressure at Absorber Inlet inch WG 4 Positive 

Pressure Drop in Absorber inch WG 4 

Pressure at Absorber Outl. inch WG 0 

Liquid Rates 

Scrubbing Liquid Recycled Water 

Absorber Recycle Flow GPM 3,300 

 Flow per Spray Zone GPM 825 

 Liquid Pressure PSIG 20 

Ca (OH)2 Consumption 

 100% lbs/hr 423 

 20% slurry GPM 4.25 

System Bleed

 Absorber Bleed Flow GPM (to maintain 0.06% CaCl2) 54 

 Salt Concentration % by weight 2.6 

 CaCl2 % by weight 0.06 

 Evaporative Loss GPM 24 

Water Make-up Rate GPM 78 

Mist Eliminator Wash Fresh Water 

 Flow Rate GPM (Intermittent) 62 

 Per each of (3) levels 5 minutes per (3) zones every 24 hours 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix H.5 - 57

January 18, 2008
TurboSonic Page 6 of 10 

TRINITY CONSULTANTS 25 September, 2007 

Wet Scrubber for Coal Fired Boiler Proposal Q08-1269 

EQUIPMENT SUPPLY: (PER ABSORBER)

 

One (1) SPRAY TOWER ABSORBER 

The Spray Tower is a cylindrical vessel with vertical gas upflow. It is provided with four (4) spray zones. Each spray 

zone consists of a main header with branch pipes equipped 

with large orifice pigtail nozzles. 

Above the upper spray zone are two (2) Mist Eliminators of 

chevron type. Each Mist Eliminator has a wash spray to 

remove possible reaction salt build-up. The wash is 

intermittent with frequency and duration controlled by the plant 

DCS. 

 Material of Construction: 

 Entire Absorber 316 L Stainless Steel 

 Plate Thickness 1/4 inch 

 Spray Headers (4) 316 Stainless Steel 

 Spray Nozzles 316 Stainless Steel 

 Mist Eliminators (2) 316 Stainless Steel 

 Wash Headers (3) 316 Stainless Steel 

 Wash Nozzles 316 Stainless Steel 

One (1) SET of FIELD INSTRUMENTATION (type Honeywell), 

 consisting of 

(1) Differential Gas Pressure Sensor & Transmitter 

(1) Liquid Level Sensor & Transmitter for Venturi 

(4) Liquid Flow Meter of Mag-type for Venturi 

(1) pH Sensor & Transmitter 

(1) Density Sensor & Transmitter of El. Conductivity type 

(8) Liquid Pressure Gauges 

(4) Liquid Pressure Switches with alarm 

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TurboSonic Page 7 of 10 

TRINITY CONSULTANTS 25 September, 2007 

Wet Scrubber for Coal Fired Boiler Proposal Q08-1269 

SERVICES

Technical Services 

TurboSonic will provide the following services with drawings and flow 

sheets in ‘Solid Works’ format: 

1. Design and Engineering of the Equipment specified under 

‘Equipment Supply’ 

 2. General Arrangement Drawing of ‘Equipment Supply’ 

 3. Four (4) Operating and Maintenance Manuals 

 

 Services Provided by Others 

The following services are not included as part of TurboSonic services 

unless otherwise specified: 

1. Foundations, Anchor Bolts and Grouting 

2. Ductwork and Stack 

3. Fan & Motor 

4. Pumps, Piping and Valves 

5. Design of Pipe Hangers and Supports 

6. Motor Starters & MCC 

7. Electric Wiring and Conduits 

8. Structural Support Steel and Access Platforms 

9. Field Installation and Erection Materials 

10. Performance Guarantee Testing 

11. All Permits 

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Appendix H.5 - 59

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TurboSonic Page 8 of 10 

TRINITY CONSULTANTS 25 September, 2007 

Wet Scrubber for Coal Fired Boiler Proposal Q08-1269 

PERFORMANCE GUARANTEE

TurboSonic guarantees that the equipment supplied, when operated in 

accordance with the Design Data and Operating Data specified in this 

document, and TurboSonic Operating and Maintenance Manual, will meet 

the following performance: 

SO2 Emission shall not exceed 26 lbs/hr 

For SO2 Inlet loadings above the 

values specified in Design Data, the 

Removal Efficiency shall not be less 

than 92% 

HCl Emission shall not exceed 2.4 lbs/hr 

For HCl Inlet loadings above the 

values specified in Design Data, the 

Removal Efficiency shall not be less 

than 82% 

 

 

 

The above performance is subject to the TurboSonic ‘Conditions of 

Performance Guarantee’ attached to this proposal. The guarantee is valid 

for the specific items listed above and does not extend to other items listed 

under ‘Operating Data. 

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TurboSonic Page 9 of 10 

TRINITY CONSULTANTS 25 September, 2007 

Wet Scrubber for Coal Fired Boiler Proposal Q08-1269 

PRICE: 

PRICE FOR THE DESIGN, ENGINEERING AND SUPPLY OF EQUIPMENT, DRAWINGS 

AND FLOW SHEETS AS SPECIFIED IN THIS PROPOSAL: 

One (1) Absorber as described in this Proposal $620,000 

One (1) Second Identical Absorber $608,000 

 

Currency U.S. Dollars 

FOB Point Point of Manufacture 

Freight Not Included, will be billed separately at cost 

Proposal Validity November 25, 2007 

Price Escalation See attached 'Terms and Conditions of Sale' 

Taxes Not Included 

Duties Not Applicable 

Erection Advice: Per diem at $850 /calendar day plus travel expenses 

Startup Service: Per diem at $850 /calendar day plus travel expenses 

 THE PRICE LISTED ABOVE IS BASED ON THE COST OF THE RAW MATERIAL AT THE 

DATE OF THIS PROPOSAL. IN VIEW OF THE PRESENT SHORTAGE OF STAINLESS 

STEEL WE RESERVE THE RIGHT TO REVIEW AND ADJUST THE PRICE IN 

ACCORDANCE WITH THE RAW MATERIAL COST AT THE TIME OF THE ORDER.

DELIVERY SCHEDULE

GA Drawings for Approval 4 weeks 

Supply of Equipment after Approval 12 – 14 weeks 

Certified Drawing after Approval 4 weeks 

TERMS OF PAYMENT

All payments are due net 30 days unless otherwise indicated. 

10% with Purchase Order 

20% on submittal of Approval Drawings 

70% upon delivery of the Equipment 

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Appendix H.5 - 61

January 18, 2008
TurboSonic Page 10 of 10 

TRINITY CONSULTANTS 25 September, 2007 

Wet Scrubber for Coal Fired Boiler Proposal Q08-1269 

STANDARDS

All equipment will be manufactured to TurboSonic standard specifications 

unless otherwise noted. 

TERMS AND CONDITIONS

This Proposal is subject to TurboSonic ‘Terms and Conditions of Sale’ 

attached to this proposal. 

 TurboSonic Technologies Inc. 

 Jorgen G. Hedenhag 

 Sales Manager 

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Appendix H.5 - 62

January 18, 2008
Four-Factor Analysis B - 1 Trinity Consultants 

APPENDIX B 

AIR POLLUTION CONTROL TECHNOLOGY FACT SHEET- FLUE GAS DESULFURIZATION

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Appendix H.5 - 63

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EPA-452/F-03-034

 Air Pollution Control Technology 

Fact Sheet

EPA-CICA Fact Sheet Flue Gas Desulfurization 1

Name of Technology: Flue Gas Desulfurization (FGD) - Wet, Spray Dry, and Dry Scrubbers

Type of Technology: Control Device - absorption and reaction using an alkaline reagent to produce a solid

compound.

Applicable Pollutants: Sulfur dioxide (SO2)

Achievable Emission Limits/Reductions: Scrubbers are capable of reduction efficiencies in the range of

50% to 98%. The highest removal efficiencies are achieved by wet scrubbers, greater than 90% and the

lowest by dry scrubbers, typically less than 80%. Newer dry scrubber designs are capable of higher control

efficiencies, on the order of 90%. 

Applicable Source Type: Point

Typical Industrial Applications: Stationary coal- and oil-fired combustion units such as utility and industrial

boilers, as well as other industrial combustion units such as municipal and medical waste incinerators,

cement and lime kilns, metal smelters, petroleum refineries, glass furnaces, and H2SO4 manufacturing

facilities. Approximately 85% of the FGD systems installed in the US are wet systems, 12% are spray dry

and 3% are dry systems.

Emission Stream Characteristics:

a. Combustion Unit Size: SO2 scrubbers have been applied combustion units firing coal and oil

ranging in size from 5 MW to over 1,500 MW (50 MMBtu/hr to 15,000 MMBut/hr). Dry and spray

scrubbers are generally applied to units less than 3,000 MMBtu/hr (300 MW) (EPA, 2000).

b. Temperature: For wet scrubbers, typical inlet gas temperatures are 150°C to 370°C (300°F to

700°F) (FETC, 1996). For spray dry systems, the temperature of the flue gas exiting the absorber

must be 10°C to 15°C (20°F to 30°F) above the adiabatic saturation temperature. Optimal

temperatures for SO2 removal for dry sorbent injection systems range from 150°C to 180°C (300°F

to 350°F). Optimal temperatures for SO2 removal when applying dry sorbent injection systems

vary between 150°C to 1000°C (300°F to 1830°F) depending on the sorbent properties (Joseph,

1998)

c. Pollutant Loading: SO2 scrubbers are limited to dilute SO2 waste gas streams of approximately

2000 ppm.(Cooper, 2002). 

d. Other Considerations: The amount of chlorine in the flue gas affects the amount of water

evaporated by the system due to the formation of salts. Chlorine content improves the SO2

removal but also results in salt deposition on the absorber and downstream equipment (Schnelle,

2002). 

An additional or upgraded induced draft (ID) fan may be required to compensate for flue gas

pressure drop across the absorber. 

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EPA-CICA Fact Sheet Flue Gas Desulfurization 2

Many wet systems reheat the flue gas downstream of the absorber to prevent corrosion caused

by condensation inside the ducts and stack and reduce plume visibility.

Emission Stream Pretreatment Requirements: In spray dry and dry injection systems, the flue gas must

be cooled to a temperature range of 10°C to 15°C (20°F to 30°F) above adiabatic saturation. This

temperature range avoids wet solids deposition on downstream equipment and plugging of the baghouse.

 A heat recovery boiler, an evaporative cooler or a heat exchanger is typically used to cool the gas.

Cost Information:

Capital costs for SO2 scrubbers have decreased by over 30% since the beginning of the 1990's. Current

costs for SO2 scrubbers applied to electric utilities are reported to be approximately $100/kW (Smith, 2001).

Retrofit of scrubbers on existing units can increase the capital cost up to 30%. Retrofit costs vary significantly

between sites and depend on space limitations, major modifications to existing equipment (e.g., ductwork

and stack) and the operating condition of the units (e.g., temperature, flowrate).

O&M costs increase with increasing sulfur content since more reagent is required to treat the same volume

of gas. Typical reagents such as lime and limestone are inexpensive; however, the use of proprietary

reagents or reagent enhancers or additives that can significantly increase the O&M cost. Limestone is

generally available for 10 to 20 $/ton and lime is available for 60 to 80 $/ton (Smith, 2001). Waste product

disposal costs vary from $10/ton to $30/ton and byproduct saleable prices vary from 0 to 15 $/ton (Smith,

2001). The addition of a scrubbers causes a loss of energy available for generating steam due to

evaporation of water and the energy required to drive the reaction. New scrubber designs result in an energy

penalty of less than 1% of the total plant energy (Srivastava, 2001).

Table 1a: Summary of Cost Information in $/MMBtu/hr (2001 Dollars) a

Scrubber Type Unit Size Capital Cost O&M Cost b Annual Cost Cost per Ton of

Pollutant Removed 

(MMBtu/hr) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($/ton)

Wet > 4,000 10,000 -25,000 200 - 800 25 - 40 200 - 500

 < 4,000 25,000 -

150,000 800 - 1,800 60 - 600 500 - 5,000

Spray Dry > 2,000 4,000 - 15,000 600 - 1,000 150 - 300

< 2,000 30,000 -

150,000 1,000 - 30,000 10,000 - 50,000 500 - 4,000

Table 1b: Summary of Cost Information in $/MW (2001 Dollars) a

Scrubber

Type

Unit Size Capital Cost O&M Cost b Annual Cost Cost per Ton of

Pollutant Removed 

(MW) ($/kW) ($/kW) ($/kW) ($/ton)

Wet > 400 100 - 250 2 - 8 20 - 50 200 - 500

 < 400 250 - 1,500 8 - 20 50 - 200 500 - 5,000

Spray Dry > 200 40 - 150 4 - 10 20 -50 150 - 300

 < 200 150 - 1,500 10 - 300 50 - 500 500 - 4,000 a ( EIA, 2002; EPA, 2000; Srivastava, 2001)

b

 Assumes capacity factor > 80% 

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EPA-CICA Fact Sheet Flue Gas Desulfurization 3

Theory of Operation:

The FDG or SO2 scrubbing process typically uses a calcium or sodium based alkaline reagent. The reagent

is injected in the flue gas in a spray tower or directly into the duct. The SO2 is absorbed, neutralized and/or

oxidized by the alkaline reagent into a solid compound, either calcium or sodium sulfate. The solid is

removed from the waste gas stream using downstream equipment. 

Scrubbers are classified as “once-through” or “regenerable”, based on how the solids generated by the

process are handled . Once-through systems either dispose of the spent sorbent as a waste or utilize it as

a byproduct. Regenerable systems recycle the sorbent back into the system. At the present time,

regenerable processes have higher costs than once-through processes; however, regenerable processes

might be chosen if space or disposal options are limited and markets for byproducts (gypsum) are available

(Cooper, 2002). In 1998, approximately 3% of FDG systems installed in the US were regenerable.

Both types of systems, once-through and regenerable, can be further categorized as wet, dry, or semi-dry.

Each of these processes is described in the following sections.

Wet Systems

In a wet scrubber system, flue gas is ducted to a spray tower where an aqueous slurry of sorbent is

injected into the flue gas. To provide good contact between the waste gas and sorbent, the nozzles and

injection locations are designed to optimize the size and density of slurry droplets formed by the system.

A portion of the water in the slurry is evaporated and the waste gas stream becomes saturated with

water vapor. Sulfur dioxide dissolves into the slurry droplets where it reacts with the alkaline

particulates. The slurry falls to the bottom of the absorber where it is collected. Treated flue gas passes

through a mist eliminator before exiting the absorber which removes any entrained slurry droplets. The

absorber effluent is sent to a reaction tank where the SO2-alkali reaction is completed forming a neutral

salt. In a regenerable system, the spent slurry is recycled back to the absorber. Once through systems

dewater the spent slurry for disposal or use as a by-product. 

Typical sorbent material is limestone, or lime. Limestone is very inexpensive but control efficiencies for

limestone systems are limited to approximately 90%. Lime is easier to manage on-site and has control

efficiencies up to 95% but is significantly more costly (Cooper 2002). Proprietary sorbents with reactivityenhancing additives provide control efficiencies greater than 95% but are very costly. Electrical utilities

store large volumes of limestone or lime on site and prepare the sorbent for injection, but this is

generally not cost effective for smaller industrial applications.

The volume ratio of reagent slurry to waste gas is referred to as the liquid to gas ratio (L/G). The L/G

ratio determines the amount of reagent available for reaction with SO2. Higher L/G ratios result in higher

control efficiencies. Higher L/G also increases oxidation of the SO2, which results in a decrease of the

formation of scale in the absorber. O&M costs are a direct function of reagent usage, so increasing the

L/G increases annual costs. L/G ratios are approximately 1:1 for wet scrubbers and are expressed as

gallons of slurry per 1000 ft3

 of flue gas (liters of slurry/1000Nm3 of flue gas).

Oxidation of the slurry sorbent causes gypsum (calcium sulfate) scale to form in the absorber.

Limestone forced oxidation (LSFO) is a newer process based on wet limestone scrubbing which reduces

scale. In LSFO, air is added to the reaction tank which oxidizes the spent slurry to gypsum. The

gypsum is removed from the reaction tank prior to the slurry being recycled to the absorber. The recycle

slurry has a lower concentration of gypsum and scale formation in the absorber is significantly reduced.

Gypsum can be commercially sold, eliminating the need for landfilling of the waste product (Srivastava,

2001). In addition to scale control, the larger size gypsum crystals formed in LSFO settle and dewater

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EPA-CICA Fact Sheet Flue Gas Desulfurization 4

more efficiently, reducing the size of the byproduct handling equipment (EPA, 2002). However, LSFO

requires additional blowers which increase the capital and annual costs of the system.

Wet limestone scrubbing has high capital and operating cost due to the handling of liquid reagent and

waste. Nonetheless, it is the preferred process for coal-fired electric utility power plants burning coal

due to the low cost of limestone and SO2 control efficiencies from 90% up to 98% (Schnelle, 2002). 

Semi-Dry Systems

Semi-dry systems, or spray dryers, inject an aqueous sorbent slurry similar to a wet system, however,

the slurry has a higher sorbent concentration. As the hot flue gas mixes with the slurry solution, water

from the slurry is evaporated. The water that remains on the solid sorbent enhances the reaction with

SO2. The process forms a dry waste product which is collected with a standard particulate matter (PM)

collection device such as a baghouse or ESP. The waste product can be disposed, sold as a byproduct

or recycled to the slurry. 

Various calcium and sodium based reagents can be utilized as sorbent. Spray dry scrubbers typically

inject lime since it is more reactive than limestone and less expensive than sodium based reagents. The

reagent slurry is injected through rotary atomizers or dual-fluid nozzles to create a finer droplet spray

than wet scrubber systems (Srivastava, 2000). 

The performance of a lime spray dry scrubber is more sensitive to operating conditions. A “close

approach” to adiabatic saturation temperature is required to maximize the removal of SO2. However,

excess moisture causes the wet solids to deposit on the absorber and downstream equipment. The

optimum temperature is 10°C to 15°C (20°F to 50°F) below saturation temperature (Srivastava, 2000).

Lower L/G ratios, approximately 1:3, must be utilized do to the limitation on flue gas moisture (Schnelle,

2002). Flue gas with high SO2 concentrations or temperatures reduce the performance of the scrubber

(Schnelle, 2002).

SO2 control efficiencies for spray dry scrubbers are slightly lower than wet systems, between 80% and

90% due to its lower reactivity and L/G ratios. Application of a single spray dry absorber is limited to

combustion units less than 200 MW (2,000 MMBtu/hr) (IEA, 2001). Larger combustion units require

multiple absorber systems. The capital and operating cost for spray dry scrubbers are lower than for wet

scrubbing because equipment for handling wet waste products is not required. In addition, carbon steel

can be used to manufacture the absorber since the flue gas is less humid. Typically applications include

electric utility units burning low- to medium- sulfur coal, industrial boilers, and municipal waste

incinerators that require 80% SO2 control efficiency (Schnelle, 2002). 

Dry systems

Dry sorbent injection systems, pneumatically inject powdered sorbent directly into the furnace, the

economizer, or downstream ductwork. The dry waste product is removed using particulate control

equipment such as a baghouse or electrostatic precipitator (ESP). The flue gas is generally cooled prior

to the entering the PM control device. Water can be injected upstream of the absorber to enhance SO2

removal (Srivastava, 2001).

Furnace injection requires flue gas temperatures between 950°C to 1000°C (1740°F to 1830°F) in order

to decompose the sorbent into porous solids with high surface area (Srivastava 2001). Injection into the

economizer requires temperatures of 500°C to 570°C (930°F to 1060°F) (Srivastava 2001). Duct

injection requires the dispersion of a fine sorbent spray into the flue gas downstream of the air preheater.

The injection must occur at flue gas temperatures between 150°C to 180°C (300°F to 350°F) (Joseph,

1998). 

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EPA-CICA Fact Sheet Flue Gas Desulfurization 5

Dry sorbent systems typically use calcium and sodium based alkaline reagents. A number of proprietary

reagents are also available. A typical injection system uses several injection lances protruding from the

furnace or duct walls. Injection of water downstream of the sorbent injection increases SO2 removal by

the sorbent. 

An even distribution of sorbent across the reactor and adequate residence time at the proper

temperature are critical for high SO2 removal rates (Srivastava 2001). Flue gas must be kept 10°C to

15°C (20°F to 50°F) below saturation temperature to minimize deposits on the absorber and

downstream equipment. 

Dry scrubbers have significantly lower capital and annual costs than wet systems because they are

simpler, demand less water and waste disposal is less complex. Dry injection systems install easily and

use less space, therefore, they are good candidates retrofit applications. SO2 removal efficiencies are

significantly lower than wet systems, between 50% and 60% for calcium based sorbents. Sodium based

dry sorbent injection into the duct can achieve up to 80% control efficiencies (Srivastava 2001). Dry

sorbent injection is viewed as an emerging SO2 control technology for medium to small industrial boiler

applications. Newer applications of dry sorbent injection on small coal-fired industrial boilers have

achieved greater than 90% SO2 control efficiencies.

Advantages:

• High SO2 removal efficiencies, from 50% up to 98%.

• Products of reaction may be reusable

• Difficulty of retrofit is moderate to low

• Inexpensive and readily available reagents

Disadvantages:

• High capital and O&M costs

• Scaling and deposit of wet solids on absorber and downstream equipment

• Wet systems generate a wet waste product and may result in a visible plume

• Cannot be used for waste gas SO2 concentrations greater than 2,000 ppm

• Disposal of waste products significantly increases O&M costs

References:

Cooper, 2002. Cooper, C.D. and Alley, F.C. Air Pollution Control : A Design Approach. Waveland Press,

Inc. Prospect Heights, IL, 2002.

EPA, 2000. Srivastava Ravi K. Controlling SO2 Emissions: A Review of Technologies. US Environmental

Protection Agency, Office of Research and Development. EPA/600/R-00/093. Washington, D.C. 2002.

http://www.epa.gov/ordntrnt/ORD/WebPubs/so2/index.html

FETC, 1996. Electric Utility Engineer’s FGD Manual, Volume 1: FGD Process Design. Department of

Energy, Federal Energy Technology Center. Morgantown, WV, 1996.

IEA, 2001. “ Coal Research, Sorbent Injection Systems for SO2 Control”, Clean Coal Technologies

Database. http://ww.iea-coal.org.uk/CCTdatabase/sorbing.htm.

Joseph, 1998. Joseph, G. T. and Beachler, D.S. “Scrubber Systems Operation Review APTI Course”.

Developed by North Carolina State University under EPA Cooperative Assistance Agreement. Raleigh,

N.C 1998.

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EPA-CICA Fact Sheet Flue Gas Desulfurization 6

Schenelle, 2002. Schenelle, K.B. Jr and Brown, C.A. Air Pollution Control Technology Handbook. CRC

Press LLC. Boca Raton, FL. 2002.

Smith 2001. Smith, Douglas. “SO2 Controls: Cost of Scrubbers down to $100/kW”. Power Engineering,

September, 2001.

Srivastava, 2001. Srivastava R. K., and W. Josewicz.. “Flue Gas Desulfurization: The State of the Art”.

Air and Waste Management Assoc., 51:1676-1688, 2001.

EIA, 2002. EIA-767 Database; Annual Steam-Electric Plant Operation and Design Data, 2001. Energy

Information Administration, Department of Energy. November 26, 2002. 

http://www.eia.doe.gov/cneaf/electricity/page/eia767.html

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