# Appendix H.5 Four Factor Analysis Source Reports

### BOWATER- CALHOUN SUBMITTED REPORT

. .................................................................3

INVISTA – HIXON/CHATTANOOGA SUBMITTED REPORT

. .. ...................................... 11 (FORMERLY DUPONT)

## F OUR 

## F ACTOR 

## A NALYSIS 

## INVISTA  C HATTANOOGA 

## , TN

F OUR 

### F ACTOR 

### A NALYSIS
OF 

### C ANDIDATE 

### SO 2 

### C ONTROL 

### M EASURES
FOR 

### R EASONABLE 

### P ROGRESS 

### U NDER THE 

### R EGIONAL 

### H AZE 

### R ULE

Prepared by:

T RINITY C ONSULTANTS 1100 Johnson Ferry Rd. NE Suite 685 Atlanta, GA 30342 (404) 256-1919

October 2007

Project 071101.0077INVISTA Chattanooga i Trinity Consultants Four-Factor Analysis 

## T ABLE OF 

## C ONTENTS



### 1. I NTRODUCTION 

### .................................................................................................... 1-1 1.1 B ACKGROUND 

### ....................................................................................................... 1-1

2. E MISSIONS 

### ........................................................................................................... 2-1 2.1 E MISSION 

### U NITS 

### S UBJECT TO THE 

### F OUR 

### -F ACTOR 

### A NALYSIS 

### ................................ 2-1 2.2 B ASELINE 

### E MISSIONS 

### ............................................................................................ 2-1

3. SO 2 

### C ONTROL 

### T ECHNOLOGY 

### F EASIBILITY 

### A SSESSMENT 

### ................................. 3-1 3.1 L OW 

### S ULFUR 

### C OAL 

### .............................................................................................. 3-1 3.2 W ET 

### FGD SYSTEMS 

### .............................................................................................. 3-2 3.3 S PRAY 

### D RYER 

### A BSORBER 

### ..................................................................................... 3-3 3.4 F LUIDIZED 

### B ED 

### C OMBUSTION WITH 

### L IMESTONE 

### .................................................. 3-3 3.5 D RY 

### S ORBENT 

### I NJECTION 

### ..................................................................................... 3-3

4. C OSTS OF 

### C OMPLIANCE 

### ...................................................................................... 4-1 4.1 L OW 

### S ULFUR 

### C OAL 

### .............................................................................................. 4-1 4.2 W ET 

### FGD S YSTEM 

### ............................................................................................... 4-3 4.3 S PRAY 

### D RYER 

### A BSORBER 

### S YSTEM 

### ....................................................................... 4-6 4.4 D RY 

### S ORBENT 

### I NJECTION 

### S YSTEM 

### ........................................................................ 4-7 4.5 C OSTS OF 

### O THER 

### CAA P ROGRAMS 

### .................................................................... 4-11 4.6 A NOTHER 

### C OST



### - EFFECTIVE 

### M ETRIC 

### ................................................................... 4-11 4.7 L OCAL 

### E CONOMIC 

### I MPACT 

### ................................................................................. 4-12

5. T IME 

### N ECESSARY FOR 

### C OMPLIANCE 

### ................................................................. 5-1

6. E NERGY AND NON


### - AIR QUALITY ENVIRONMENTAL IMPACTS 

### ............................ 6-1

7. R EMAINING USEFUL LIFE OF EXISTING SOURCES IN 

### EU-002 ............................. 7-1

8. V ISIBILITY 

### I MPROVEMENT 

### ................................................................................. 8-1 8.1 P OTENTIAL 

### INVISTA SO 2 

### I MPACT ON 

### V ISIBILITY 

### ............................................... 8-2 8.2 I MPACT OF 

### O THER 

### CAA P ROGRAMS 

### ..................................................................... 8-2

9. A NALYSIS AND 

### C ONCLUSION 

### .............................................................................. 9-1

A PPENDIX 

### A

A PPENDIX 

### BINVISTA Chattanooga ii Trinity Consultants Four-Factor Analysis 

## L IST OF 

## T ABLES

T ABLE 2-1. B OILER S PECIFICATIONS FOR EU-002

T ABLE 2-2. P AST A CTUAL SO2 E MISSIONS

T ABLE 4-1. T OTAL C APITAL I NVESTMENT E STIMATE

– W ET FGD O PTION

T ABLE 4-2. T OTAL A NNUAL COST ESTIMATE

– W ET FGD O PTION

T ABLE 4-3. E XTRACT FROM EPA T ABLE 1A (EPA-F/452-03-34)

T ABLE 4-4. T OTAL C APITAL I NVESTMENT E STIMATE

– D RY S ORBENT I NJECTION O PTION

T ABLE 4-5. T OTAL A NNUAL C OST E STIMATE

– D RY S ORBENT I NJECTION O PTION

T ABLE 5-1. T IME N ECESSARY FOR C OMPLIANCE

T ABLE 6-1. E NERGY AND N ON -A IR Q UALITY E NVIRONMENTAL I MPACTSINVISTA Chattanooga iii Trinity Consultants Four-Factor Analysis 

## L IST OF 

## F IGURES

F IGURE 4-1. U TILITY GRADE COAL COST AS A FUNCTION OF SULFUR CONTENT (2006)INVISTA Chattanooga 1-1 Trinity Consultants Four-Factor Analysis 

## 1. I NTRODUCTION

The purpose of this document is to present the f our-factor analysis for the INVISTA S.à r.l. (INVISTA) nylon fiber and flake manufacturing fac ility 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 B ACKGROUND

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 th e 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 pollution 1

.
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 pr ogress, the Act requires the following factors to be taken into consideration: (1) the costs of complia nce, (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 requirement s 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 Stat es 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 dete rmining reasonable progress has become known as the “Four-Factor Analysis.” More recently, EPA h as 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 avai lable retrofit technology (BART) determinations, but made no substantive changes with respect to other reasonable progress re quirements. 70 Fed. Reg. 39104 (July 6, 2005). Visibility improvement achieved by BART is a specific compone nt 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 G oals Under the Regional Haze Program (June 1, 2007).INVISTA Chattanooga 1-2 Trinity Consultants Four-Factor Analysis The Regional Haze Rule specifies a planning peri od 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 Tr ibal Association of the Southeast (VISTAS) -- a collaborative effort of state governments, tribal go vernments, and various fe deral agencies established to initiate and coordinate activities associated with the management of regional haze, visibility and other air quality issues in the Southeastern Unite d States. After extensive analysis, VISTAS has concluded that sulfate is the primary cause of vi sibility 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 (SO 2 ) from utility and industrial boilers. In pa rticular, VISTAS’ analysis found that SO 2 emissions from INVISTA’s Chattanooga facility c ontributed 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 ju risdiction, the Georgia Environmental Protection Division (EPD) has asked the Tennessee Department of Environment and Conservation (TDEC) to evaluate whether a future SO 2 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 SO 2 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. Th e VISTAS analysis considered total visi bility impairment, frequency of air masses from source areas entering the Class I area of interest, and SO 2 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 VIST AS analysis assigned a 1.5% c ontribution to INVISTA, that value cannot be directly correlated to 1.5% of th e visibility impact on the Cohutta Wilderness Area.INVISTA Chattanooga 2-1 Trinity Consultants Four-Factor Analysis 

## 2. E MISSIONS



## 2.1 E MISSION 

## U NITS 

## S UBJECT TO THE 

## F OUR 

## -F ACTOR 

## A NALYSIS

The only source that TDEC has requested that I NVISTA examine with a four-factor analysis is Emission Unit 002 (EU-002), which consists of coal-f ired boilers No. 3, 4, and 5. The general specifications of the boilers comprising EU-002 are listed in Table 2-1.

T ABLE 2-1. B OILER S PECIFICATIONS 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 an d 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 th at 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 w ith 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 co mbined with bottom ash. Ash is periodically dredged from the pond and sent to a nearby cement kiln for beneficial reuse.



## 2.2 B ASELINE 

## E MISSIONS

The annual baseline SO 2 emission rate for this four-factor anal ysis was calculated to be 944 tons. This is an annual average of the actual SO 2 emissions from EU-002 that were reported by INVISTA to APCB for the three most recent calendar years (2 004, 2005 and 2006). Th e data used and methodINVISTA Chattanooga 2-2 Trinity Consultants Four-Factor Analysis of calculation are presented below. The emission f actor is derived from Table 1.1-3 of AP-42 (Sept. 1998), as specified in the Facility’s operating permit.

T ABLE 2-2. P AST A CTUAL SO 2 E MISSIONS

Year Coal Combusted (tons) Avg. Sulfur Content

(%) SO 2 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:



### tons 133

, 1 / 000

, 2 612

, 63 93

. 0 38

. 38

2 

### = × ×

= ton lb ton E SO

where: 38.38 is the SO 2 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 co al sulfur content has averaged nearly 1% over the last three years.INVISTA Chattanooga 3-1 Trinity Consultants Four-Factor Analysis 

## 3. SO 2 

## C ONTROL 

## T ECHNOLOGY 

## F EASIBILITY 

## A SSESSMENT

According to the EPA data for coal-fired electric generating units 2

, 96.8 percent of the 1,140 coalfired utility boilers operating in the U.S. in 1999 used one of the following SO 2 control technologies:

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

2. Wet flue gas desulfurization (FGD) – passage of fl ue gas through a contactor where it comes into intimate contact with a scrubbing solution that reacts with SO 2 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 SO 2 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 SO 2 emissions from EU-002.



## 3.1 L OW 

## S ULFUR 

## C OAL

The emission of SO 2 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 SO 2 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 SO 2 reduction by this method may be feasible).

Reducing SO 2 emissions from EU-002 by switching to a lower-s ulfur coal is deemed to be technically feasible for certain coals. In particular, the altern ative coal must meet certain minimum specifications (e.g., ash fusion temperature) in order to be compa tible with the design of the boilers and material handling systems of EU-002.

Although sub-bituminous coals from particular regi ons in the western United States, such as the Powder River Basin, have low-sulfur concentrati ons, those coals have other properties that are notINVISTA Chattanooga 3-2 Trinity Consultants Four-Factor Analysis compatible with the design of the boilers and ma terial 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 averag e sulfur level in acceptable bituminous coals that could consistently be purchased without risking fu ture increases in sulfur content due to limited availability of an alternative coal.



## 3.2 W ET 

## FGD SYSTEMS

Wet FGD technology relies upon the relatively high solubility of SO 2 in water to remove SO 2 from the flue gas. Since water ceases to remove SO 2 effectively when it reaches an equilibrium concentration with SO 2 in the gas phase, calcium-, sodium- or ammonium-based chemicals are added to the scrubber liquor to react with the dissolved SO 2 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-bear ing 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 SO 2 removal efficiencies in the range of approximately 90 percent where the particulate matter (PM) concentration of the flue gas has already been significantly reduced. Howe ver, packed tower absorbers and other designs containing any significant amount of internal structure are suscep tible 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.

SO 2 removal efficiency of wet FGD systems is a function of the inlet SO 2 concentration. Higher removal efficiencies are possible when inlet SO 2 concentrations are high. Conversely, removal efficiency decreases as inlet SO 2 concentration decreases, leading many vendors to guarantee a minimum outlet SO 2 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 wate r. 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 downs tream of a wet scrubber, corrosion resistant materials must generally be used in those downstr eam components. Furthermore, saturated flue gases from wet scrubbers often create highly opaque plum es of condensed water upon discharge of those flue gases to the atmosphere.INVISTA Chattanooga 3-3 Trinity Consultants Four-Factor Analysis Wet FGD technology is determined to be technically feasible for control of SO 2 emissions from EU-002. Because wet scrubbers are typically more reli able if the majority of PM is removed from the flue gas upstream of the scrubber, applying this co ntrol option to EU-002 assumes the installation of a scrubber downstream of each of the two existing baghouses.



## 3.3 S PRAY 

## D RYER 

## A BSORBER

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 g as is contacted with a fine mist of slurry instead of a bulk liquid (as in wet scrubbing). The combustion gases containing SO 2 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 ar e in the range of 250 to 350 °F. The SO 2 is absorbed in the slurry and reacts with the hydrat ed lime reagent to form solid ca lcium sulfite and calcium sulfate, as in a wet lime scrubber. The slurry water is eva porated by the hot flue gas, leaving dry particles containing the captured sulfur. These particles are en trained in the flue gas, along with fly ash, and are collected in a PM collection device. Most of the SO 2 removal occurs in the spray dryer vessel itself, although some additional SO 2 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 SO 2 emissions from EU-002.



## 3.4 F LUIDIZED 

## B ED 

## C OMBUSTION WITH 

## L IMESTONE

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 SO 2 from the coal. Spent reactant and ash are continuously remove d from the bed and from the flue gas exiting the boiler.

FBC with limestone is not considered technically feasible for control of SO 2 emissions from EU-002 because that technology requires an entirely different t ype 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 D RY 

## S ORBENT 

## I NJECTION

For the dry sorbent injection pro cess, dry powdered hydrated lime (o r 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 SO 2 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 SO 2 removal efficiencies are lower than for wet scrubbing or SDA and are approximately 40-50 percent. This dry pro cess eliminates the slurry production and handling equipment required for wet scrubbers and spray dr yers, and produces a dry waste product for easier disposal.INVISTA Chattanooga 3-4 Trinity Consultants Four-Factor Analysis Dry sorbent injection is determined to be technically feasible for controlling SO 2 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 si gnificant change to the ex isting fly ash disposal system. Currently, fly ash from the baghouses is hy draulically 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 bene ficial reuse. Due to the collected particulates from a DSI system (fly ash/slaked lime/calcium sulfat e) being incompatible with water, it would be necessary to switch to a dry fly ash collection and conveyance system.INVISTA Chattanooga 4-1 Trinity Consultants Four-Factor Analysis 

## 4. C OSTS OF 

## C OMPLIANCE

The control technology cost analyses in this four-f actor assessment have been generally prepared in accordance with the EPA Air Pollution Control Cost Manual , 6 th ed., EPA/452/B-02-001 (Jan. 2002).

Estimates of total capital investment (TCI) and to tal annual cost (TAC) were made for each of the four, technically feasible control technology optio ns identified in the previous section using the techniques described in the Manual, quotes obtai ned directly from equipment vendors and service contractors, and data developed by INVISTA pr ocurement and engineering personnel. Because these estimates are not based on firm equipment and c onstruction 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 co sts), are those directly related to the operation of the option. These include costs of operator labor, utili ties, replacement parts, etc. Indirect costs are those costs that are fixed, and do not generally va ry with the extent of u se of the option. These include administrative charges, ta xes, insurance premiums, and the capital recovery cost. The capital recovery cost is a means of annualizing the TCI ove r 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 per cent, for a capital recovery factor (CRF) of 0.149..



## 4.1 L OW 

## S ULFUR 

## C OAL

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 I NVISTA believed it could cons istently purchase was 0.75 percent. Figure 4-1 provides an example of the depe ndence 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 u sed at the site. It is apparent from the figure that the cost of coal increases very rapidly as th e sulfur content drops below one percent.INVISTA Chattanooga 4-2 Trinity Consultants Four-Factor Analysis F IGURE 4-1. U TILITY G RADE C OAL COST AS A FUNCTIO N OF SULFUR CONTENT (2006)

Using the trend line curve in Figure 1, the 2006 aver age cost of utility coal at 1.25% sulfur (the specification for coal received in 2004, 2005, and 20 06) 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 fro m 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: 

## ( ) ton ton yr ton yr Cost Additional / 13

. 44 $ / 30

. 49 $ / 719

, 50 ) / ($

− × =

To calculate cost-effectiveness, th e 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-r eceived 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 SO 2 emitted from the baseline was calculated to be approximately 214 tons per y ear using the following equation:INVISTA Chattanooga 4-3 Trinity Consultants Four-Factor Analysis 

### tons/yr 214 97

. 0 75

. 0 1 / 944 ) / ( 2 

### = ⎟ ⎠ ⎞ ⎜ ⎝ ⎛

− × = yr ton yr ton SO Decrease Emissions

The cost-effectiveness (cost per ton of SO 2 emission reduction) was calculated to be approximately $1,225 per ton of SO 2 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 dema nds. 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 in crease as will costs. These potential cost increases are not quantified in this analysis.



## 4.2 W ET 

## FGD S YSTEM

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 i nduced draft fan in each of the two existing air pollution control trains in EU-002.

Each scrubber, as quoted, has the cap acity to accept the maximum flow rate capacity of the baghouse with which it would be associated. The manufact urer has guaranteed that each will achieve a minimum of 92 percent SO 2 removal when EU-002 fires coal containing 1.25 percent by weight sulfur, with potentially lower c ontrol efficiency at reduced SO 2 inlet loading to the scrubber. The scrubbers are designed to use hydrated lime as the SO 2 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 manufact urer. 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 approxim ately 2.5 wt. %, this waste water is expected to require pretreatment prior to discharge, and the es timated 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 $3,0 46,633. This cost was estimated assuming that EU-002 would be operated under the same average c onditions 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 SO 2 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 SO 2 emitted under this option was est imated to be 76 tons per year. The estimated cost effec tiveness of the wet FGD system when EU-002 is operated under the baseline conditions was estimated to be $3,508 per ton of SO 2 removed.INVISTA Chattanooga 4-4 Trinity Consultants Four-Factor Analysis T ABLE 4-1. T OTAL C APITAL I NVESTMENT E STIMATE

– W ET FGD O PTION

Factor Estimate 1

Direct Costs
Purchased equipment costs Wet scrubbers (including standard options ) Vendor quote 2 $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 Estimate 3 $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.INVISTA Chattanooga 4-5 Trinity Consultants Four-Factor Analysis T ABLE 4-2. T OTAL A NNUAL COST ESTIMATE

– W ET FGD O PTION

Cost Item Calculation Cost 1

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 & maintenance 2 $100,000 Reagent for SO 2 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 wee k $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 wee k $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 presen ce 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” pl umes. The addition of stacks and reheaters would also increase both the capital and operating cost of th is candidate control technology, making it even less cost-effective.INVISTA Chattanooga 4-6 Trinity Consultants Four-Factor Analysis 

## 4.3 S PRAY 

## D RYER 

## A BSORBER 

## S YSTEM

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 SO 2 removal efficiency of this contro l 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. INVI STA 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 curre ntly is hydraulically conveyed to an ash pond where it is mixed with bottom ash from EU-002. Th e combined ash is periodically dredged from the pond and trucked to a nearby cement kiln for benefi cial 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 fu sion 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 chem ical 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 accepta ble 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) S DA vendors have been unresponsive to Company requests for budgetary quotes.

According to Table 1A of the referenced EPA contro l technology fact sheet, the range of costs for an SDA system for boilers having firing rates of less th an 2,000 MMBtu per hour is listed in Table 4-3.INVISTA Chattanooga 4-7 Trinity Consultants Four-Factor Analysis T ABLE 4-3. E XTRACT FROM EPA T ABLE 1A (EPA-F/452-03-34) B OILERS < 2,000 MMB TU / HR

Capital Cost ($/MMBtu/hr) O & M Cost ($/MMBtu/hr) Annual Cost ($/MMBtu/hr) Cost of SO 2 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 sh eet indicates that both capital and operating costs for SDA increase substantially as boiler capacity decreas es. Under this control technology option, the maximum heat input rate for which each SDA syst em would be designed would be approximately eight percent of the maximum firing rate (2,000 MMB tu/hr) for which Table 1A contains cost data (as shown above in Table 4-3). Given the inver se relationship between boiler capacity and SDA equipment costs, and given the comparatively sma ll 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 maximu m costs for applying SDA to a “small” coalfired utility boiler, the cost-effectiveness of appl ying SDA to EU-002 is estimated to be at least $4,000 per ton

.



## 4.4 D RY 

## S ORBENT 

## I NJECTION 

## S YSTEM

After EPA promulgated the “Boiler MACT,” INVIST A 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 ha ndling 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 hand ling system would have to be upgraded and converted to a dry system.

Using hydrated lime as the reactant, the DS I system was assumed to achieve an SO 2 control efficiency of 50 percent. At the aforementioned baseline SO 2 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 fu sion 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 chem ical 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 accepta ble 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.INVISTA Chattanooga 4-8 Trinity Consultants 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 tota l 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. Th is latter cost was estimated assuming that EU-002 would be operated under the same average cond itions as occurred during the period of 2004, 2005 and 2006. The capital recovery factor utilized in th e estimated TAC is based on an interest rate of 8.0% and an economic lifetime of 10 years.

The estimated SO 2 removed by the DSI option is 472 tons pe r year, based on a 50% control efficiency and the 944 tpy historical emissions. The remaining SO 2 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 w as estimated to be $4,037 per ton of SO 2 removed.INVISTA Chattanooga 4-9 Trinity Consultants Four-Factor Analysis T ABLE 4-4. T OTAL C APITAL I NVESTMENT E STIMATE

– D RY S ORBENT I NJECTION O PTION

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 ItemINVISTA Chattanooga 4-10 Trinity Consultants Four-Factor Analysis T ABLE 4-5. T OTAL A NNUAL C OST E STIMATE

– D RY S ORBENT I NJECTION O PTION

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 5 2 $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) $1,905,890INVISTA Chattanooga 4-11 Trinity Consultants Four-Factor Analysis 

## 4.5 C OSTS OF 

## O THER 

## CAA P ROGRAMS

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 so lely to reductions from other CAA programs will exceed, by a significant margin, the visibility impr ovement 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 acknowle dged that visibility improvements from other CAA requirements essentially had no costs attributable to the regional haze program 7 . In other words, while those other CAA requirements redu ce 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 co mply with the Clean Air Act’s acid rain program. The costs for those controls, although substantial, ar e 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 SO 2 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, wh en evaluated with the “cost of compliance” statutory factor, visibility improvements from other CAA pr ograms 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 SO 2 control option considered in this analysis could not be representative of reasonable progress.



## 4.6 A NOTHER 

## C OST


## - EFFECTIVE 

## M ETRIC

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 SO 2 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 a ssessing additional emission reduction strategies for

7 EPA, Regulatory Impact Analysis for the Final Regional Haze Rule, Apr. 22, 1999INVISTA Chattanooga 4-12 Trinity Consultants Four-Factor Analysis source categories or individual, large scale sour ces, simple cost-effectiveness estimates based on dollar-per-ton calculation may not be as mean ingful as a dollar-per-deciview calculation.” 8 In this particular analysis, the Comp any has determined that the four SO 2 control options will cost at least $1,225 and extend to more than >$4,000 per ton of SO 2 removed. The Company has also shown in a latter section of this analysis that none of th e control options is expect ed to improve visibility perceptibly in the Cohutta Class I area. Conse quently, 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 w ould not be appropriate to find the de minimis improvement in visibility achieved by each candidate control option to cons titute reasonable progress.



## 4.7 L OCAL 

## E CONOMIC 

## I MPACT

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 state 9 .” The Agency’s position reinforces its well-settled view that each Stat e has considerable discretion as to how it weighs the statutory factors in any reasonable pr ogress 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’ discretion 10

.
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 reduc tions to later planning periods in order to maintain a consistent g lidepath 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 SO 2 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 Regula tions for Visibility Protection for Federal Class I Areas, 172 (Oct. 1980).INVISTA Chattanooga 4-13 Trinity Consultants Four-Factor Analysis facility. INVISTA clearly recognizes the ever-presen t tension between envir onmental protection and economic growth and stability. In this instan ce, however, the Company believes that significant visibility improvement from other CAA programs weighs heavily against imposing additional SO 2 control costs on the Chattanooga Plant with the St ate’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.INVISTA Chattanooga 5-1 Trinity Consultants Four-Factor Analysis 

## 5. T IME 

## N ECESSARY FOR 

## C OMPLIANCE

The estimated minimum time periods necessary for INVISTA to implement each of the four SO 2 control options in this analysis are listed in the table below.

T ABLE 5-1. T IME N ECESSARY FOR C OMPLIANCE

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 th e low sulfur coal option include the following:

♦ Obtain quotations from vendors

♦ Negotiate a procurement contract

♦ Complete the existing coal contract a nd 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 SO 2 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 opt ions in this analysis could theoretically be accomplished within 1-3 years, current market demands for SO 2 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.INVISTA Chattanooga 6-1 Trinity Consultants Four-Factor Analysis 

## 6. E NERGY AND NON


## - AIR QUALITY ENVIRONMENTAL IMPACTS

The anticipated energy and non-air qua lity environmental impacts of the SO 2 emission control options in this analysis are listed below in Table 6-1.

T ABLE 6-1. E NERGY AND N ON -A IR Q UALITY E NVIRONMENTAL I MPACTS

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.INVISTA Chattanooga 7-1 Trinity Consultants Four-Factor Analysis 

## 7. R EMAINING 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 con tinue 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 co sts and on the reasonable progress determination 11 .” 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 legislativ e 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, ol der sources. During the 1977 Amendments, Congress adopted the PSD program, requiring best availabl e control technology on new and modified major sources. In doing so, Congress deliberately “grandfat hered” existing major sources, concluding that the imposition of substantial costs for new contro l equipment on existing units did not constitute sound public policy.

Nevertheless, when adopting the visibility prot ection provisions of the 1977 Amendments, Congress did carve out a subset of existing major sources fo r which best available retrofit technology (BART) was required. The legislative history of those vi sibility provisions confirms that potentially BARTeligible sources were restricted to those which began operation be tween 1962 and 1977 because Congress did not want to require those expensive retr ofits on units that were more than 15-years-old. In other words, INVISTA believes that “remaining u seful life” is a distinct statutory factor because Congress expected that any requirement for retrof it controls on sources greater than 15-years-old would be disfavored.

11 EPA, Reasonable Progress Guidance, 5-3.INVISTA Chattanooga 7-2 Trinity Consultants Four-Factor Analysis To be sure, any application of th e 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 contro ls on any unit of a certain age or older, INVISTA believes that the legislative histories and struct ures of those provisions and the PSD program evince congressional sentiment not to require control measur es 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 SO 2 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 lim ited subset which Congress explicitly approved for retrofits of control technologies 12

.

12 In response to those who would re ply that older sources should be re quired 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 ex clusion for routine maintenance, repair and replacement. In most cases, the source undergoing such changes becomes a “m ajor modification” subject to the retrofit application of BACT.INVISTA Chattanooga 8-1 Trinity Consultants Four-Factor Analysis 

## 8. V ISIBILITY 

## I MPROVEMENT

It is unfortunate that this methodology under th e Regional Haze Rule has been dubbed the “fourfactor analysis,” because that misleading terminol ogy 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 congressi onal 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 comp liance, [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 recogni zed 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 eval uated 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 onl y statutory interpretation which gives effect to all of the above words in th at provision for determining reasonable progress. Moreover, consideration of the related visibility improvement during any “four-factor analysis” is simply intuitive, common-sense 14

.

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).INVISTA Chattanooga 8-2 Trinity Consultants Four-Factor Analysis 

## 8.1 P OTENTIAL 

## INVISTA SO 2 

## I MPACT ON 

## V ISIBILITY

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 SO 2 emissions but also due to those estimated SO 2 emissions resulting from application of each of the four control technology options in this analysis. With such modeling results, th e Company could estimate the extent of visibility improvement resulting from each candidate control, wh ich could then be weighed with the four listed statutory factors. However, INVISTA simply di d 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 maximu m visibility improvement which could be achieved at Cohutta by retrofitting EU-002 with SO 2 control technology. Modeling projections by VISTAS have suggested that EU-002’s baseline SO 2 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 dv 15

. Therefore, applying an overly simplistic assumption for the purpose of this analysis only that EU-002’s visibility impact without any SO 2 control option is 0.34 dv (23 dv × 0.015), then a maximum achievable SO 2 reduction of 92% with an FGD system conceivably would result in re ducing EU-002’s visibility impact in Cohutta by 0.31 dv.

In its BART modeling protocol, VISTAS defined a c ontribution to visibility impairment as equal to or greater than a threshold level of 0.5 dv 16 . This metric obviously suggests that EU-002’s SO 2 emissions without any added SO 2 control measure do not, by definition, “contribute” to regional haze in the Cohutta Wilderness Area. Furthermor e, a maximum reduction in those existing SO 2 emissions from EU-002 would result in a decrease in visibility im pairment 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 SO 2 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 benef it. 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 I MPACT OF 

## O THER 

## CAA P ROGRAMS

The Clean Air Act has already established a number of control programs, such as Acid Rain, NO x SIP Call, and CAIR that require reductions in air pollutants that also happen to cause visibility impairment. Consequently, those existing CAA progr ams create a collateral benefit, the improvement of visibility in Class I areas. EPA has acknowledge d that a State’s planning for reasonable progress “should reflect at least the rate of visibility impr ovement expected from the implementation of ‘other’

15 VISTAS, “Uniform Rate of Progress Glide Path (B ase G2a projections),” Cohutta - 20% Worst Days, New IMPROVE equation. 16 VISTAS, Protocol for the Application of the CALPUFF M odel for Analyses of Best Available Retrofit Technology (BART), 5 (Dec. 22, 2005).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 r each 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 me asures implementing the CAA requirements will provide the visibility improvement and emissions [reductions] needed for reasonable progress during the first regional haze implementation plan 19 .” With respect to specifi cs of the Cohutta Wilderness Area, VISTAS has estimated that visibility improv ement at a uniform rate of progress will result in a haziness index during the area’s 20% worst days e qual to 25.51 dv by 2018, the end of the first planning period for regional haze SIPs 20 . In addition, VISTAS has projected that visibility improvement attributable to “other” (non-regiona l-haze) CAA requirements will result in a haziness index in Cohutta of 22.02 dv by 2018. In other wo rds, 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 ear lier prediction that the initial reasonable progress goal of a Class I area such as Cohutta would be realiz ed without the need to require control measures under the regional haze program. Given the substa ntial 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 stat utory factors could not logically be found to be “reasonable.”

17 64 Fed. Reg. 35733 (July 1, 1999). 18 Id. at 35731 19 Id. at 35733 20 VISTAS, “Uniform Rate of Progress Glide Path (B ase G2a projections),” Cohutta - 20% Worst Days, New IMPROVE equationINVISTA Chattanooga 9-1 Trinity Consultants Four-Factor Analysis 

## 9. A NALYSIS AND 

## C ONCLUSION

In response to a request from TDEC, INVISTA h as examined whether reasonable progress could be achieved in the Cohutta Wilderness Area by retr ofitting the coal-fired boile rs’ exhausts at the Company’s Chattanooga facility with an SO 2 emission control technology. The Company first identified the following four SO 2 control options as technically feasibl e: (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 fro m 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 opti ons 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 cont rol 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 eval uating the control options is $/dv. While quantitative $/dv values could not be determin ed, 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 SO 2 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 provisi ons 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.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-e ffective, and (3) without any control options at INVISTA, visibility improvement in Cohutta by 20 18 will nevertheless exceed that required from the uniform rate of progress glidepath.

Therefore, consistent with EPA’s original projec tions 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 re ductions from other CAA programs, and that no SO 2 control option on the boilers at Chattanooga w ould achieve reasonable progress during that same period.Four-Factor Analysis A - 1 Trinity Consultants 

## A PPENDIX 

## A

C ONTROL 

### D EVICE 

### I NFORMATION 

### Sizing Calculations Vendor Supplied DataINVISTA Chattanooga Four Factor Analysis Wet FGD Sizing Calculations

Variable Value C max Maximum permitted coal consumption 112,000 ton/yr S max Maximum permitted coal sulfur content 1.25% EF SO2 SO 2 emission factor 38.38 C avg Average coal consumed in 2004, 2005, 2006 50,719 ton/yr S avg Average sulfur content of coal consumed in 2004, 20 05, 2006 0.97% R gmax Gas flow rate per scrubber at maximum design condit ions 74,000 acfm Pd max Pressure drop per scrubber at maximum design condit ions 4.0 inch wg E ctl SO 2 removal efficiency of scrubbers at maximum design conditions 92% L max Ca(OH) 2 usage per scrubber at maximum permitted coal sulfu r and consumption 423 lb/hr R wmax Fresh water makeup rate per scrubber at maximum des ign conditions 78 gal/min R bmax Blowdown rate per scrubber at maximum design condit ions 54 gal/min R r Liquor recirculation rate per scrubber at maximum d esign conditions 3,300 gal/min P r Scrubber liquor recirculation pressure 20 psig R i Design inlet SO 2 mass flow rate per scrubber at maximum design cond itions 327 lb/hr

Assumed operating duty cycle of EU-002 per 365 day period 8,760 hr HV coal Average coal heating value 13,591 Btu/lb R flyash Flyash generation rate for EU-002 0.00366 ton/MMBtu

Maximum Potential Uncontrolled SO 2 Emissions from EU-002

EU max = C max x S max x EF SO2 / 2,000 lb/ton = 112,000 ton/yr x 1.25% x 38.38 / 2,000 lb/ton 2,687 ton/yr

Baseline Uncontrolled SO 2 Emissions from EU-002

EU base = C avg x S avg x EF SO2 / 2,000 lb/ton = 50,719 ton/yr x 0.97% x 38.38 / 2,000 lb/ton 944 ton/yr

Baseline Controlled SO 2 Emissions from EU-002

EC base = EU base x (1 - CE) = 944 ton/yr x (1 - 0.92) 76 ton/yr

SO 2 Removed from EU-002 Under Baseline Operating Condi tions

ER FGDbase = EU base - EC base = 944 ton/yr - 76 ton/yr 869 ton/yr

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

L base = 2 x L max x (C avg /C max ) x (S avg /S max )

= 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 Ope rating Conditions

R wbase = 2 x R wmax x (C avg /C max ) x (S avg /S max )

= 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 Operatin g Conditions

R bbase = 2 x R bmax x (C avg /C max ) x (S avg /S max )

= 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 Reci rculation 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).x ls Wet FGD calcsINVISTA Chattanooga Four Factor Analysis Wet FGD Sizing Calculations

EP recircmax = 2 x 0.746 x 2.52x10 -4 x R r x P r / 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 Require d for I.D. Fan at Maximum Design Conditions

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

EP idfanmax = 2 x 1.17x10 -4 x R gmax x Pd max / 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 Basel ine Conditions

C eff = TAC FGD / ER FGDbase = $3,046,633 / 869 ton $3,508/ton

Estimated Cost of Recirculation Pumps (for TCI esti mate)

From the OAQPS Control Cost Manual:

Cost = 2 x R r x $16/gpm = 2 x 3,300 gal/min x $16/gpm $105,600
Estimated Average Heat Input for EU-002 Operating a t Baseline Consitions

HI base = C avg x 2,000 x HV coal / (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).x ls Wet FGD calcsINVISTA Chattanooga Four Factor Analysis Wet FGD Sizing Calculations

Estimated Total Flyash/Spent Reactant Generation at Baseline Operating Conditions

R wbase = HI base x R flyash + L base / 2,000 + E ctl x EU base / 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).x ls Wet FGD calcs

### INVISTA Chattanooga Four Factor Analysis Dry Sorbent Injection Sizing Calculations

V ariable V alue C avg A verage coa l consume d i n 2004

, 2005

, 2006 50,719 ton/y r HV coal A verage coa l h ea ti ng va l ue 13,591 Btu/lb EF SO2 SO 2 emission factor 38.38 S avg A verage su lf ur con t en t o f coa l consume d i n 2004

, 2005

, 2006 0.97% R gmax G as fl ow ra t e per scru bb er a t max i mum d es i gn con diti ons 74,000 acfm

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

E ctl SO 2 removal efficiency of DSI system at maximum design conditions 50% NSR Normalized stoichiometric ratio 3.48 R flyash Fl yas h genera ti on ra t e f or EU

- 002 0.00366 ton/MMBtu P r S cru bb er li quor rec i rcu l a ti on pressure 20 psig D op A ssume d opera ti ng d u t y cyc l e o f EU

- 002 per 365 d ay per i o d 8,760 hr

Baseline Uncontrolled SO 2 Emissions from EU-002

EU base = C avg x S avg x EF SO2 / 2,000 lb/ton = 50,719 ton/yr x 0.97% x 38.38 / 2,000 lb/to n 944 ton/y r

Baseline Controlled SO 2 Emissions from EU-002

EC base = EU base x (1 - CE) = 944 ton/yr x (1 - 0.50 ) 472 ton/y r

SO 2 Removed from EU-002 Under Baseline Operating Conditions

ER DSIbase = EU base - EC base = 944 ton/yr - 472 ton/y r 472 ton/y r
Estimated Total Ca(OH) 2 Usage at Baseline Operating Conditions

L base = NSR x EU base x 2,000 / D op = 3.48 x 944 ton/yr x 2,000 lb/ton / 8,760 hr/y r 750 lb/hr

Estimated Average Heat Input for EU-002 Operating at Baseline Consition s

HI base = C avg x 2,000 x H V coal / (1,000,000 x 8,760)

= 50

, 719 t on / yr x 2

, 000 lb/t on x 13

, 591 Bt u /lb / (1

, 000

, 000 Bt u /MMBt u x 8,760 hr/yr) 157 MMBtu/hr

Estimated Total Flyash/Spent Reactant Generation at Baseline Operating Conditions

R wbase = HI base x R flyash + L base / 2

, 000 + E ctl x EU base / 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/ y r / 8

, 760 hr/ y r x ( 136.142 - 74.093 ) / 64.05 4 1.00 ton/hr

Trinity Consultants INVISTA Chttg 4 Factor Control Costs (2007-10-12).xls DSI Calcs

### 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):

EP idfanmax = 2 x 1.17x10 - 4 x R gmax x Pd max / ε Where ε is the combined fan/motor efficiency 0.70 = 2 x 0.000117 x 74,000 acfm x 4 inches wg / 0.7 0 99 kW

Estimated Cost Effectiveness of FGD Option at Baseline Conditions

C eff = TAC DSI / E R DSIbase
= $ 1,905,890 / 472 ton $4,037/ton

Trinity Consultants INVISTA Chttg 4 Factor Control Costs (2007-10-12).xls DSI Calcs

## 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 A ddressee only and must not be copied or distributed without prior writt en consent of TurboSonic. Upon completion of evaluation this ma terial shall be returned or destroyed

.

## 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 SO 2 

### 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 sp ray zones, which provide the necessary contact surface for absorption of the acid gases. The Spray Headers are provided with large orifice spray nozzles, which ar e 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 ca rry-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 t he 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 SO 2 

### hydrated lime Ca(OH) 2 

### is added to the top Spray Header, so that t he 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 bl eed 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.

## 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) c an be located on top of the Absorber. That yields a compact assembly with sma ll 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 lowe r velocities the condensate drains back into the Absorber.

## TurboSonic Page 4 of 10 TRINITY CONSULTANTS 25 September, 2007 Wet Scrubber for Coal Fired Boiler Proposal Q08-1269



## D ESIGN 

## D ATA

P LANT 

### D ATA 

### :

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



### I NLET 

### C ONDITIONS 

### : ( PER 

### A BSORBER 

### )

Gas Flow ACFM 74,000 Normal Gas Flow ACFM 70,000 Gas Temperature o F 400 Gas Composition (assumed) O 2 % by volume 5 CO 2 % by volume 12
H 2 O % by volume 5
N 2 % by volume 78 Dry Gas Volume SCFMD 42,568 Gas Pressure at Absorber Inlet Inch WG 4 Positive Gas Density lbs/ft 3 0.0465 SO 2 Loading lbs/hr 327
PPM DV 771 HCl Loading lbs/hr 13
PPM DV 54


### O UTLET 

### C ONDITIONS 

### : ( PER 

### A BSORBER 

### )

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 SO 2 Loading lbs/hr 26
PPM DV 61 HCl Loading lbs/hr 2.4
PPM DV 10

## TurboSonic Page 5 of 10 TRINITY CONSULTANTS 25 September, 2007 Wet Scrubber for Coal Fired Boiler Proposal Q08-1269



## O PERATING 

## D ATA 

## : ( PER 

### A BSORBER 

### )

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% CaCl 2 ) 54 Salt Concentration % by weight 2.6 CaCl 2 % 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

## TurboSonic Page 6 of 10 TRINITY CONSULTANTS 25 September, 2007 Wet Scrubber for Coal Fired Boiler Proposal Q08-1269



## E QUIPMENT 

## S UPPLY 

## : ( PER 

### A BSORBER 

### )

One (1) SPRAY TOWER ABSORBERThe 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 durat ion 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

## TurboSonic Page 7 of 10 TRINITY CONSULTANTS 25 September, 2007 Wet Scrubber for Coal Fired Boiler Proposal Q08-1269



## S ERVICES

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 Dr awing 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

## TurboSonic Page 8 of 10 TRINITY CONSULTANTS 25 September, 2007 Wet Scrubber for Coal Fired Boiler Proposal Q08-1269



## P ERFORMANCE 

## G UARANTEE

TurboSonic guarantees that the equipm ent supplied, when operated in accordance with the Design Data and O perating Data specified in this document, and TurboSonic Operating and Maintenance Manual, will meet the following performance:

SO 2 Emission shall not exceed 26 lbs/hr For 

### SO 2 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.

## TurboSonic Page 9 of 10 TRINITY CONSULTANTS 25 September, 2007 Wet Scrubber for Coal Fired Boiler Proposal Q08-1269



## P RICE 

## :

PRICE FOR THE DESIGN , ENGINEERING AND SUPPLY OF EQUIPMENT , DRAWINGS AND FLOW SHEETS AS SPECIFIED IN THIS P ROPOSAL :

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 'T erms 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

T HE P RICE LISTED ABOVE IS BASED ON THE COST OF THE RAW MATERIAL AT THE DATE OF THIS P ROPOSAL

. I N VIEW OF THE PRESENT SHORTAGE OF S TAINLESS S TEEL WE RESERVE THE RIGHT TO REVIEW AND ADJUST THE P RICE IN ACCORDANCE WITH THE RAW MATERIAL COST AT THE TIME OF THE ORDER

.



### D ELIVERY 

### S CHEDULE
GA Drawings for Approval 4 weeks Supply of Equipment after Approval 12 – 14 weeks Certified Drawing after Approval 4 weeks



### T ERMS OF 

### P AYMENT
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

## TurboSonic Page 10 of 10 TRINITY CONSULTANTS 25 September, 2007 Wet Scrubber for Coal Fired Boiler Proposal Q08-1269



### S TANDARDS 

### All equipment will be manufactured to TurboSonic standard specifications unless otherwise noted.

T ERMS AND 

### C ONDITIONS 

### This Proposal is subject to TurboSonic ‘Terms and Conditions of Sale’ attached to this proposal.

TurboSonic Technologies Inc. Jorgen G. Hedenhag Sales ManagerFour-Factor Analysis B - 1 Trinity Consultants 

## A PPENDIX 

## B

A IR 

### P OLLUTION 

### C ONTROL 

### T ECHNOLOGY 

### F ACT 

### S HEET


### - F LUE 

### G AS 

### D ESULFURIZATIONEPA-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 (SO 2 )

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 combus tion 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 H 2 SO 4 manufacturing facilities. Approximately 85% of t he 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: SO 2 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 t he adiabatic saturation temperature. Optimal temperatures for SO 2 removal for dry sorbent injection systems range from 150°C to 180°C (300°F to 350°F). Optimal temperatures for SO 2 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: SO 2 scrubbers are limited to dilute SO 2 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 c ontent improves the SO 2 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.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 SO 2 scrubbers have decreased by over 30% si nce the beginning of the 1990's. Current costs for SO 2 scrubbers applied to electric utilities are r eported to be approximately $100/kW (Smith, 2001). Retrofit of scrubbers on existing units can increase the capi tal cost up to 30%. Retrofit costs vary significantly between sites and depend on space limitations, major modi fications to existing equipment (e.g., ductwork and stack) and the operating condition of t he units (e.g., temperature, flowrate).

O&M costs increase with increasing su lfur 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 si gnificantly increase the O&M cost. Limestone is generally available for 10 to 20 $/ton and lime is ava ilable 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 t he reaction. New scrubber designs result in an energy penalty of less than 1% of the tota l 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%EPA-CICA Fact Sheet Flue Gas Desulfurization 3 Theory of Operation:

The FDG or SO 2 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 SO 2 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 di spose 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-th rough processes; however, regenerable processes might be chosen if space or disposal options are lim ited 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-thr ough 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 contac t between the waste gas and sorbent, the nozzles and injection locations are designed to optimize the size and density of slurry droplet s formed by the system. A portion of the water in the slurry is evaporat ed and the waste gas stream becomes saturated with water vapor. Sulfur dioxide dissolves into the sl urry droplets where it reacts with the alkaline particulates. The slurry falls to the bottom of t he absorber where it is collected. Treated flue gas passes through a mist eliminator before ex iting the absorber which removes any entrained slurry droplets. The absorber effluent is sent to a reaction tank where the SO 2 -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 di sposal or use as a by-product.

Typical sorbent material is limestone, or lime. Li mestone is very inexpensive but control efficiencies for limestone systems are limited to appr oximately 90%. Lime is easier to manage on-site and has control efficiencies up to 95% but is significantly more cost ly (Cooper 2002). Proprietary sorbents with reactivityenhancing additives provide control efficiencies greater t han 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 re ferred to as the liquid to gas ratio (L/G). The L/G ratio determines the amount of reagent available for reaction with SO 2 . Higher L/G ratios result in higher control efficiencies. Higher L/G al so increases oxidation of the SO 2 , 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 appr oximately 1:1 for wet scrubbers and are expressed as gallons of slurry per 1000 ft 3 of flue gas (liters of slurry/1000Nm 3 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 wh ich 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 wa ste product (Srivastava, 2001). In addition to scale control, the larger si ze gypsum crystals formed in LSFO settle and dewaterEPA-CICA Fact Sheet Flue Gas Desulfurization 4 more efficiently, reducing the size of the by product handling equipment (EPA, 2002). However, LSFO requires additional blowers which increase t he capital and annual costs of the system.

Wet limestone scrubbing has high capital and operati ng cost due to the handling of liquid reagent and waste. Nonetheless, it is the pr eferred process for coal-fired elec tric utility power plants burning coal due to the low cost of limestone and SO 2 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 t he 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 SO 2 . 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 wa ste product can be disposed, sold as a byproduct or recycled to the slurry.

Various calcium and sodium based reagents can be ut ilized as sorbent. Spray dry scrubbers typically inject lime since it is more reactive than limes tone and less expensive than s odium based reagents. The reagent slurry is injected through ro tary atomizers or dual-fluid nozzles to create a finer droplet spray than wet scrubber system s (Srivastava, 2000).

The performance of a lime spray dry scrubber is mo re sensitive to operating conditions. A “close approach” to adiabatic saturation temperature is required to maximize the removal of SO 2 . 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 SO 2 concentrations or temperatures reduce the performance of the scrubber (Schnelle, 2002).

SO 2 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. App lication 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 fl ue gas is less humid. Typically applications include electric utility units burning low- to medium- su lfur coal, industrial boilers, and municipal waste incinerators that require 80% SO 2 control efficiency (Schnelle, 2002).

Dry systems

Dry sorbent injection syst ems, 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 precipit ator (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 SO 2 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 sp ray into the flue gas downstream of the air preheater. The injection must occur at flue gas temperat ures between 150°C to 180°C (300°F to 350°F) (Joseph, 1998).EPA-CICA Fact Sheet Flue Gas Desulfurization 5 Dry sorbent systems typically use calcium and sodi um based alkaline reagents. A number of proprietary reagents are also available. A typica l injection system uses several in jection lances protruding from the furnace or duct walls. Injection of water dow nstream of the sorbent injection increases SO 2 removal by the sorbent.

An even distribution of sorbent across the reactor and adequate residence time at the proper temperature are critical for high SO 2 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 sy stems 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. SO 2 removal efficiencies are significantly lower than wet syst ems, between 50% and 60% for calciu m 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 SO 2 control technology for medium to small industrial boiler applications. Newer applications of dry sorbent in jection on small coal-fired industrial boilers have achieved greater than 90% SO 2 control efficiencies.

Advantages:

• High SO 2 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 produc t and may result in a visible plume • Cannot be used for waste gas SO 2 concentrations greater than 2,000 ppm • Disposal of waste products signi ficantly 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 SO 2 Emissions: A Review of Technologies. US Environmental Protection Agency, Office of Research and De velopment. EPA/600/R-00/093. Washington, D.C. 2002. http://www.epa.gov/ordntrnt/O RD/WebPubs/so2/index.html

FETC, 1996. Electric Utility Engineer’s FGD Manual, Volume 1: FGD Process Design . Department of Energy, Federal Energy Technol ogy Center. Morgantown, WV, 1996.

IEA, 2001. “ Coal Research, Sorbent Injection Systems for SO 2 Control”, Clean Coal Technologies Database. http://ww.iea-coal.org.u k/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.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. “SO 2 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-Elect ric Plant Operation and Design Data, 2001. Energy Information Administration, Departm ent of Energy. November 26, 2002. http://www.eia.doe.gov/cneaf/e lectricity/page/eia767.html