DEPARTMENT OF ENVIRONMENTAL QUALITY AIR QUALITY DIVISION

BART Application Analysis

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- 604 6

August 4 , 2008

NAME OF FIRM: General Chemical ( Soda Ash ) Partners

NAME OF FACILITY: Green River Works

FACILITY LOCATION: Sections 29

- 33, T19N, R109W and

Sections 4

- 6, T18N, R109W Sweetwater County, Wyoming

TYPE OF OPERATION: Trona Mine and Sodium Products Plant

RESPONSIBLE OFFICIAL: Peter J. Kalivas , Vice President of Manufacturing

MAILING ADDRESS: PO Box 551 Green River, WY 82935

- 0551

TELE PHONE NUMBER: (307) 87 5

- 3350

REVIEWING ENGINEER S : Cole Anderson , Air Quality Engineer Josh Nall, Air Quality Modeler

PURPOSE OF APPLICATION:

Sections 169A and 169B of the 1990 Clean Air Act Amendments require states to improve visibility at

Class I areas. On July 1, 1999, EPA first published the Regional Haze Rule, which provided specific details regarding the overall program requirements to improve visibility. The goal of the regional haze program is to achieve natural conditions by 2064.

Section 308 of the Regional Haze Rule (40 CFR 51) includes discussion on control strategies for improving visibility impairment. One of these strategies is the requirement under 40 CFR 51.308(e) for certain stationary sources to install Best Available Retrofit T echnology (BART) to reduce emissions of three (3) visibility impairing pollutants, nitrogen oxides (NO

x ), particulate matter (PM), and sulfur dioxide (SO 2 ). EPA published Appendix Y to part 51

- Guidelines for BART Determinations Under the Regional Haze R ule in the July 6, 2005 Federal Register to provide guidance to regulatory authorities for making BART determinations. Chapter 6, Section 9, Best Available Retrofit Technology was adopted into the Wyoming Air Quality Standards and Regulations (WAQSR) and became effective on December 5, 2006. The Wyoming Department of Environmental Quality, Air Quality Division (Division) will

determine BART for NO

x and PM 10 for each source subject to BART and include each determination in the §308 Wyoming Regional Haze St ate Implementation Plan (SIP).

Section 309 of the Regional Haze Rule (40 CFR 51), Requirements related to the Grand Canyon Visibility Transport Commission , provides states that are included within the Transport Region addressed by the Grand Canyon Visibil ity Transport Commission (i.e., Arizona, California, Colorado, Idaho,General Chemical Green River Works

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Nevada, New Mexico, Oregon, Utah, and Wyoming) an alternative to the requirements established in 40 CFR 51.308. This alternative control strategy for improving visibility contains speci al provisions for addressing SO 2 emissions, which include a Market Trading program and a provision for a 2018 SO 2 Milestone. Wyoming submitted a 309 Regional Haze SIP to EPA on December 29, 2003. As of the date of this analysis, EPA has not taken action on the SIP. Sources that are subject to BART are required to

address SO 2 emissions as part of the BART analysis.

On March 26, 2007 General Chemical (Soda Ash) Partners (General Chemical) submitted a B est

A vailable R etrofit T echnology (BART) an alysis for two existing coal

- fired boilers at the Green River

Works facility in accordance with the requirements of WAQSR Chapter 6 Section 9(e)(i). A map of

General Chemical Green River Work s ‟ location is attached as Appendix A.

On May 6 , 2008 General Chemical sub mitted additional documentation committing to install BART

determined controls by January 1, 2014 and to propose a 30

- day rolling average for emission limits established through the BART process.

BART ELIGIBILITY DETERMINATION:

In August of 2005 the Wyom ing Air Quality Division began an internal review of sources that could be subject to BART. This initial effort followed the methods prescribed in 40 CFR part 51, Appendix Y: Guidelines for BART Determinations Under the Regional Haze Rule to identify sour ces and facilities. The rule requires that States identify and list BART

- eligible sources, which are sources that fall within the 26 source categories, have emission units which were in existence on August 7, 1977 but not in operation before August 7, 196 2 and have the potential to emit more than 250 tons per year (tpy) of any visibility impairing pollutant when emissions are aggregated from all eligible emission units at a stationary source. One hundred two (102) sources at fourteen (14) facilities were identified that could be subject to BART in Wyoming.

The next step for the Air Quality Division was to identify BART

- eligible sources that may emit any air pollutant which may reasonably be anticipated to cause or contribute to any impairment of visibilit y. Three pollutants are identified by 40 CFR part 51, Appendix Y as visibility impairing pollutants. They are sulfur dioxide (SO 2 )

, nitrogen oxides (NO

x ), and particulate matter (PM). Particulate matter with an aerodynamic diameter of 10 microns or less (PM 10 ) was used as an indicator of PM. In order to determine visibility impairment of each source, a screening analysis was performed using CALPUFF. Sources that

emitted over 40 tons of SO 2 or NO

x or 15 tons of PM 10 were included in the screening analys is. Using three years of meteorological data, the screening analysis calculated visibility impacts from sources at nearby Class I areas. Sources whose modeled 98 th percentile 24

- hour impact or 8 th highest modeled impact, by year, was equal to or greater than 0.5 deciviews (dv) above natural background conditions were determined to be subject to BART. For additional information on the Division‟s screening analysis see the Visibility Improvement Determination: Screening Modeling section of this analysis. General

Chemical ‟s two existing coal

- fired boilers were determined to be subject to BART. General Chemical was notified in a letter dated June 14, 2006 of the Division‟s finding.General Chemical Green River Works

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DESCRIPTION OF BART ELIGIBLE SOURCES:

General Chemical Green River Works ‟ two existing coal

- fired boilers , units C and D

, are co

- located at the facility power plant building

. Burning low sulfur bituminous coal, they supply power and process steam to the mining and ore processing operations. Both boilers are tangentially fired using in

- line coal pulverizers. Boiler C was installed in 1973 and boiler D was installed in 1975. Each boiler is currently equipped with a hot

- side electrostatic precipitator (ESP) to control particulate emissions. O verfire air and

low excess air are currently used to reduce NO

x emissions from the boilers. SO 2 emissions are controlled

without the use of add

- on controls by burning low sulfur coal.

Table 1: Coal

- fired Boilers Units C and D Baseline Operations

Operating Permit 3

- 1

- 1 23 Emission Limit s

Source Firing Rate

(MMBtu/hour) Existing

Controls NO

x

(lb/MMBtu) SO 2

(lb/MMBtu) PM/PM 10

(lb/ hr )

Boiler C 534 Overfire air , dry

ESP 0.7

(3

- hour rolling) 1.2

(2

- hour fixed) 50.0

Boiler D 880 Overfire air, dry

ESP 0.7

(3

- hour rolling) 1.2

(2

- hour fi xed) 80.0

CHAPTER 6, SECTION 9

– BEST AVAILABLE RETROFIT TECHNOLOGY (BART)

BART is an emission limit based on the application of a continuous emission reduction technology for each visibility impairing pollutant emitted by a source. It is established o n a case

- by

- case basis taking into consideration six factors for each proposed BART control. The six factors are: (1) The available retrofit control options, (2) Any pollution control equipment in use at the source, (3) The costs of compliance with contro l options, (4) The remaining useful life of the facility, (5) The energy and non

- air quality environmental impacts of control options, and (6) The visibility impacts analysis. A BART determination must address air pollution control measures for each emiss ions unit or pollutant emitting activity subject to review. Visibility control options presented in the application for each of the emissions units were reviewed using the methodology prescribed in 40 CFR part 51

, s ubpart Y, as required in WAQSR Chapter 6 Section 9(c)(i). This methodology is comprised of five basic steps:

Step 1: Identify all 1 available retrofit control technologies Step 2: Eliminate technically infeasible options Step 3: Evaluate control effectiveness of remaining control technologie s Step 4: Evaluate impacts and document the results Step 5: Evaluate visibility impacts

The five steps were applied to each coal

- fired boiler , units C and D, to determine a pollutant

- specific

BART control measure for NO

x , PM, and SO 2

.

1 Footnote 12 of 40 CFR 51 Subpart Y defines the intended use of „all‟ by stating “...you must identify the most stringent option and a reasonable set of options for analysis that reflects a comprehensive list of available technologies.”General Chemical Green River Works

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NO

x : INDENTIFY A VAILABLE RETROFIT CONTROL TECHNOLOGIES

General Chemical identified three well

- established control technologies , including the most stringent option, for reducing NO

x emissions from existing process boilers : selective catalytic reduction (SCR),

selective n on

- catalytic reduction (SNCR), and combustion modifications including low NO

x burners (LNB). S N CR and SCR are add

- on, post combustion controls that can reduce NO

x emissions by 5 0% and

9 0%, respectively. The third control, combustion modifications includi ng LNB, involves modifying the existing coal injection and the combustion air to reduce NO

x emissions. In addition to using these three controls individually

, they can be combined to i ncrease the overall NO

x emissions reduction. LNB are often used with S CR to control NO

x emissions above 90%.

1. Selective Catalytic Reduction

– SCR is a post combustion control technique in which vaporized ammonia or urea is injected into the flue gas upstream of a catalyst. NO

x entrained in the flue gas

is reduced to molecu lar nitrogen (N 2 ) and water. The use of a catalyst facilitates the reaction at an exhaust temperature range of 300 to 1

, 100 F, depending on the type of catalyst used. When catalyst temperatures are not in the optimal range for the reaction or when too mu ch ammonia is injected into the process, unreacted ammonia can be released to the atmosphere through the stack. This release is commonly referred to as ammonia slip.

2. Selective Non

- Catalytic Reduction

– SNCR is similar to SCR in that it involves the injec tion of a reducing agent such as ammonia or urea into the flue gas stream. The reduction chemistry, however, takes place without the aid of a catalyst. SNCR systems rely on appropriate injection temperatures, proper mixing of the reagent and flue gas, an d prolonged retention time in place of the catalyst. SNCR operates at higher temperatures than SCR. The effective temperature range

for SNCR is 1

, 500 to 2

, 2 00 F. SNCR systems are very sensitive to temperature changes and typically have lower NO

x emissio ns reduction and higher ammonia slip than SCR systems.

3. Low NO

x Burners

– LNB technologies can rely on a combination of lean premix combustion , fuel staging

, and internal, or forced external flue gas recirculation to suppress the formation of thermal

NO

x . Lean premix combustion occurs when excess air and fuel are well controlled by burner injection prior to entering the combustion zone to effectively o perat e at or near the limit of flammability

. This operation minimize s the amount of thermal NO

x formation by reducing the combustion temperature in the boiler and preventing high temperature combustion zones from forming. Fuel staging can also be using to limit the amount of oxygen available to the fuel during combustion to prevent NO

x formation.

NO

x : ELIMI NATE TECHNICALLY INFEASIBLE OPTIONS

General Chemical did not eliminate any of the three individual control technologies as technically

infeasible. All three technologies are proven emission reduction technologies with several examples of each in operatio n.

NO

x : EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES

General Chemical reviewed literature for each of the three emission control technologies and determined achievable emission rates for each. LNB without separated overfire air was determine d to reduce NO

x emissions from each boiler by approximately 12%. LNB with separated overfire air (SOFA) could reduceGeneral Chemical Green River Works

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emissions by an additional 18% for a total NO

x reduction from each boiler of 30%. T he application of

SNCR was determined to reduce NO

x em issions by 50 %. Installing SCR reduced emissions the most.

Each boiler could reduce NO

x emissions by 80% if SCR was installed. Resulting emission rates are

shown in Table 2.

Table 2: NO

x Emission Rates Per Boiler

Control Technology Boiler C Resulting NO

x Emission Rate (lb/MMBtu) / (lb/hr) Boiler D Resulting NO

x Emission Rate (lb/MMBtu) / (lb/hr)

Good Combustion Practices 0.70 (a) / 374 0.70 (a) / 616

LNB 0. 62 (b) / 331 0. 62 (b) / 546

LNB with S OFA 0. 49 (b) / 263 0. 49 (b) / 431

S N CR 0. 35 (b) / 188 0

. 35 (b) / 308

SCR 0.1 4 (b) / 75 0. 14 (b) / 123

(a) 40 CFR part 60, s ubpart D limit

(b) Calculated by dividing the proposed lb/hr emission rate by the boiler‟s maximum heat input

NO

x : EVALUATE IMPACTS AND DOCUMENT RESULTS

General Chemical evaluated the economic, environmental, and energy impacts associated with the four proposed control options for both boilers C and D

. General Chemical contacted vendors for information, but did not provide vendor quotes for equipment costs associated with each proposed control option. After reviewing costs of the LNB with SOFA and without, General Chemical did not proceed with modeling the effect of installing LNB without SOFA on boilers C a nd D. Costs associated with proposed

and modeled NO

x control options are prese nted below.

In addition to the typical purchase, installation, and operational costs associated with installing emission controls, General Chemical included costs related site preparation and auxiliary energy costs associated with generating additional st eam to supplement lost steam production when each of the existing boilers is shutdown to install the emission controls. Site preparation costs are included in the capital costs for each control option and account for additional structural modification and demolition work required to retrofit the existing boilers , since the installation of the emission control equipment was not accounted for in the original plant design. Auxiliary energy costs were also included for the installation of SNCR and SCR to

acco unt for lost steam production as each of the units is shutdown for modification, one at a time

. Makeup steam can be generated by boiler E, a 490 MMBtu/hr natural

- gas fired boiler. However due to the size of the boiler, the plant will have to operate on r educed steam demand. Energy costs associated

with a two week shutdown of either boiler C or boiler D were calculated by subtracting the fuel cost of coal from the fuel cost of natural gas ($10/MMBtu minus $2/MMBtu) and multiplying the differential

cost ($ 8/MMBtu) by continual operation of the 490 MMBtu/hr natural

- gas boiler at maximum design heat input for two weeks. Th e replacement energy cost is equal to $1,316,000 for each boiler.General Chemical Green River Works

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The environmental cost for each control option was based on a three y ear average of actual NO

x emissions from each of the boilers. NO

x e mission s from calendar years 2001

- 2003 were used to calculate an average yearly emission ra te. The environmental benefit was determined by multiplying the proposed reduction efficiency of the control technology times the average annual actual emission rate.

General Chemical based the capital recovery factor (CRF) and annual cost of control of SNCR and SCR

on a 7% interest rate and a control life of 30 years. LNB with SOFA costs were annu alized using a 7% interest rate and a control life of 20 years. Labor and service costs associated with SNCR and SCR were estimated at $37 per hour, while only $30 per hour was used to calculate them for LNB. Economic and

environmental costs for both boi lers are summarized in the following tables.

Table 3: Boiler C Economic Costs

Cost Baseline Option 1: LNB, separated OFA Option 2 : S N CR Option 3 : SCR

Control Equipment Capital Cost $0 $ 2,547,180 $ 7,541,800 $ 14

, 097

, 600

Capital Recover Factor N/A 0. 0944 ( a ) 0.0806 0. 0806

Annual Capital Recovery Costs $0 $ 240

, 454 $607,870 $1,136,267

Annual O&M Costs $0 $ 181

, 954 ( b ) $ 825

, 850 $ 1,298,542

Annual Cost of Control $0 $ 422

, 408 $ 1,433,720 $ 2

, 434

, 809

( a ) For LNB the CRF is based on 7% interest over 20 years

( b ) Labor rate of $30/hour was used for LNB instead of $37/hour which was used for SCR and SNCR

Table 4: Boiler C Environmental Cost s

Baseline Option 1: LNB,

separated OFA Option 2 : S N CR Option 3 : SCR

Annual NO

x Emission (tpy) ( a ) 1

, 057.4 740.2 528.7 211.5

Percent Control from Baseline 0 30% 50% 80%

Annual NO

x Reduction from Baseline (tpy) 0 317.2 528.7 845.9

Annual Cost of Control $0 $ 422

, 408 $ 1

, 433

, 720 $ 2

, 434

, 809

Cost per ton of Reduction N/A $ 1,332 $ 2,712 $ 2,878

Incremental Cost per ton of Reduction N/A $ 1,332 $ 4,782 $ 3,156

(a) Annual baseline emission s based on 3 year average of actual NO

x emissions from the boiler for calendar years 2001

- 2003General Chemical Green River Works

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Table 5 : Boiler D Economic Costs

Cost Baseline Option 1: LNB, separated OFA Option 2 : S N CR Option 3 : SC R

Control Equipment Capital Cost $0 $ 4

, 197

, 600 $ 8

, 391

, 4 00 $ 19

, 194

, 5 00

Capital Recover Factor N/A 0. 0944 ( a ) 0.0806 0. 0806

Annual Capital Recovery Costs $0 $ 396

, 253 $67 6

, 347 $1, 547

, 0 7 7

Annual O&M Costs $0 $ 234

, 768 ( b ) $ 810

, 234 $ 1, 852

, 189

Annual Cost of Control $0 $ 631

, 021 $ 1,4 86

, 581 $ 3

, 399

, 266

( a ) For LNB the CRF is based on 7% interest over 20 years

( b ) Labor rate of $30/hour was used for LNB instead of the $37/hour which was used for SCR and SNCR

Table 6 : Boiler D Environmental Cost s

Baseline Opti on 1: LNB,

separated OFA Option 2 : S N CR Option 3 : SCR

Annual NO

x Emission (tpy) ( a ) 1

, 468.4 1

, 027.9 734.2 293.7

Percent Control from Baseline 0 30% 50% 80%

Annual NO

x Reduction from Baseline (tpy) 0 440.5 734.2 1

, 174.7

Annual Cost of Control $0 $ 631

, 02 1 $ 1

, 4 86

, 581 $ 3

, 399

, 266

Cost per ton of Reduction N/A $1,433 $2,025 $2,894

Incremental Cost per ton of Reduction N/A $1,433 $2,913 $4,342

( a) Annual baseline emission s based on 3 year average of actual NO

x emissions from the boiler for calendar ye ars 2001

- 2003

The final step in the BART determination process, Step 5: Evaluate visibility impacts

, for NO

x is addressed in a comprehensive visibility analysis covering all three visibility impairing pollutants and associate control options. The visibil ity analysis follows the PM evaluation in this analysis.

SO 2 : INDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

General Chemical identified three technologies for controlling SO 2 emissions from the two coal

- fired

boilers : lime or limestone based wet flue gas desulfurization (WFGD)

, lime spray dryer absorber (SDA), and dry sorbent injection (DSI). In the comprehensive visibility analysis SDA is referred to as dry flue gas desulfurization (DFGD). For the purposes of this analysis the two terms

, SDA and DF GD, will be used interchangeably. A fourth option, reduced sulfur alternative fuel supplies, was identified. However, Wyoming coal typically has lower sulfur content than coal produced in most other states, which makes it

difficult to further reduce the sulfur content of the fuel fed to the boiler . Coal blending can be used to

reduce the overall amount of sulfur combusted in a boiler, but it is most effective when high sulfur coal is

blended with low sulfur Wyoming coal.General Chemical Green River Works

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There are two primary mechanis ms to reduce SO 2 from coal

- fired boiler flue gas: adsorption and absorption. Adsorption control systems are designed to capture SO 2 as either a sulfate or sulfite at the

surface of a sorbent . Dry alkaline powder, often lime, is injected into the exhaust gas upstream of a particulate control device such as a fabric filter. SO 2 in the gas binds to the surface of the alkaline powder and is captured by the particulate control device for disposal. This control method works best in low moisture gas streams an d when the sorbent has a high affinity for SO 2

.

The absorption process can be categorized as physical or chemical. Physical absorption occurs when the absorbed compound dissolves in the solvent. Chemical absorption occurs when the absorbed compound

and the solvent chemically react to form a sulfite or sulfate in the solvent phase

. Costs for absorption control processes can be higher than adsorption technologies because disposing of the by

- product s can be more expensive. SO 2 control technologies identif ied by General Chemical are discussed below.

1. W et flue gas desulfurization

– W FGD remove s SO 2 through absorption by mass transfer as

soluble SO 2 in the exhaust gas mixture is dissolved in an alkaline water solvent that has low volatility under the process conditions. Limestone, lime, or caustic may be used as alkali. When the flue gas enters the scrubbing vessel, the temperature drops as it becomes saturated with the

solvent. SO 2 diffuses from the flue gas into the scrubber water when the liquid contains less than the equilibrium concentration of the gaseous SO 2 . The rate of SO 2 mass transfer between the two phases is largely dependent on the surface area exposed and the time of contact. A properly designed wet scrubber will provide sufficient contact b etween the gas and the liquid solvent to

allow diffusion of SO 2 . Once the SO 2 enters the alkaline water phase, it will form a weak acid and react with the alkaline component dissolved in the scrubber water to form a sulfite or sulfite.

The acid/alkali ch emical reaction prevents the SO 2 from diffusing back into the flue gas stream. When the alkaline scrubber water is saturated with sulfur compounds, it can be converted to a wet gypsum by

- product that may be sold. SO 2 removal efficiencies for wet scrubber s can be as high

as 9 8 %.

2. L ime spray dryer absorber

– SDA is similar to DSI systems, however the spray dryer provides greater contact area and enhances chemical reactivity. A spray dryer sprays an atomized alkaline slurry into the flue gas upstream of par ticulate control system. Water in the slurry evaporates, hydrolizing the SO 2 into a weak acid, which reacts with the alkali to form a sulfate or sulfite. The resulting dry product is captured in the particulate control and physically moved from the exhau st gas into a storage bin. The dry by

- product may be dissolved back into the lime slurry or dried and sold as a gypsum product. Spray dryer s typically require lower capital cost than a wet scrubber. They also require less flue gas after

- treatment. When exhaust gas leaves the wet scrubber, it is at or near saturation. In locations where water supply is an issue, the spray dryer absorber is a better candidate for removing SO 2 because it requires less makeup water than WFGD is nearly as efficient. Remova l efficiencies for spray dryer absorbers are in the range of

70% to 95%.General Chemical Green River Works

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3. Dry sorbent injection

– Similar to SDA, DSI involves injecting a fine alkaline compound into the flue gas. Unlike SDA, the sorbent, or injected material, does not contain water. T he dry powdered material is injected into the flue gas where SO 2 impacts the surface of the sorbent and chemically binds to it. Injection occurs upstream of a particulate matter control device, which removes the material for disposal. A DSI system usuall y requires less capital cost as the existing duct work can be used without significant modifications . H owever the operating cost can be higher because injecting more sorbent is necessary to make up for the lower reactivity of the dry powder as compared to the wet slurry used in SDA.

SO 2 : E LIMINATE TECHNICALLY INFEASIBLE OPTIONS

General Chemical did not eliminate any of the four individual control technologies as technically

infeasible , by themselves

. However, installing DSI to control SO 2 emissions woul d dramatically increase the particulate loading on the existing ESP

, beyond its current design. General Chemical notes that DSI systems perform well when particulate matter in the flue gas is controlled with a baghouse. General Chemical did not propose i nstalling a baghouse to control particulate emissions because the existing ESP

is an effective control device for particulate matter . Therefore, given the high costs associated with redesigning the existing ESP or retro

- fitting each boiler with a new bagh ouse, General Chemical did not further evaluate DSI for the existing boilers

.

R educed sulfur alternati ve fuel supplies were not addressed further in the analysis. As discussed in Section 2.3 of General Chemical‟s analysis, the sulfur content of the exist ing fuel is low, ranging from 0.42 to 0.51 percent sulfur. While coal blending is technically feasible, the reduction in SO 2 emissions would be very minor. The cost per ton of SO 2 reduction using this control option would likely be quite high, given the small environmental benefit. The Division did not require further consideration of

reduced sulfur alternative fuels.

SO 2 : EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES

General Chemical reviewed each of the two remaining emission control techn ologies and determined

achievable emission rates for each one

. Retrofitting the existing boilers with either SO 2 control is

difficult

. Both technologies require sufficient space for the SO 2 in the flue gas to react with injected alkaline compound s

. The existing plant layout does not accommodate these space requirements and would require significant modification to incorporate either WFGD or SDA control technologies. General Chemical proposed conservative emission reduction rates that take into account r etrofit

limi t at ions for each control technology. SDA was estimated to reduce SO 2 emissions from each boiler by

80 %. This estimate is based on installing a stand

- alone SDA unit with a baghouse in addition to using the existing dry ESP to control particula tes . A new stack is also included in the design of the SDA system.

The lowest SO 2 emission rate is achieved by i nstalling WFGD

. General Chemical estimates that installing WFGD could reduce SO 2 emissions by 9 0%. Space limitations require a separate buil ding and a new stack for the WFGD system. E mission rates for each of the SO 2 control technologies discussed are shown in Table 7

.General Chemical Green River Works

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Table 7 : SO 2 Emission Rates Per Boiler

Control Technology Boiler C Resulting SO 2 Emission Rate (lb/MMBtu) / (lb/hr) Boile r D Resulting SO 2 Emission Rate (lb/MMBtu) / (lb/hr)

Low Sulfur Coal 1.2 0 (a) / 641 1.20 (a) / 1056

S DA 0.24 (b) / 128 0. 2 4 (b) / 211

WFGD 0. 12 (b) / 64 0. 12 (b) / 106

(a) Current 4 0 CFR part 60

, s ubpart D limit

(b) Calculated by dividing the proposed lb/hr emission rate by the boiler‟s maximum heat input

SO 2 : EVALUATE IMPACTS AND DOCUMENT RESULTS

General Chemical evaluated the economic, environmental, and energy impacts associated with the two proposed SO 2 control options for b oilers C and D . Vendor s‟ information w as used to estimate the c apital costs for each of the proposed options. The capital recovery factor used to estimate the annual cost of

control was based on a 7% interest rate and a control life of 30 years. Demolition costs and supplemen tal

energy costs associated with the extended downtime for the boilers when the SO 2 emission control equipment is installed were included . Economic and environmental costs for both boilers are summarized in the following two tables.

Table 8 : Boiler C Eco nomic Costs

Cost Baseline Option 1: SDA Option 2 : WFGD

Control Equipment Capital Cost $0 $ 16

, 411 ,8 0 0 $ 32

, 122

, 5 00

Capital Recover Factor N/A 0. 0 806 0.0806

Annual Capital Recovery Costs $0 $ 1,322,791 $ 2,589,074

Annual O&M Costs $0 $ 3,811,240 $ 4

, 439

, 310

Annual Cost of Control $0 $ 5,134

, 031 $ 7

, 028

, 384General Chemical Green River Works

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Table 9 : Boiler C Environmental Cost s

Baseline Option 1: SDA Option 2 : WFGD

Annual SO 2 Emission (tpy) ( a) 1,991.1 398.2 199.1

Percent Control from Baseline 0 80% 90%

Annual SO 2 Reduction from Baseli ne (tpy) 0 1,592.9 1,792.0

Annual Cost of Control $0 $ 5,134

, 031 $ 7

, 028

, 384

Cost per ton of Reduction N/A $ 3,223 $ 3

, 922

Incremental Cost per ton of Reduction N/A $ 3 ,2 23 $ 9,515

(a) Annual baseline emission s based on 3 year average of actual SO 2 emissions from the boiler for calendar years 2001

- 2003

Table 10 : Boiler D Economic Costs

Cost Baseline Option 1: SDA Option 2 : WFGD

Control Equipment Capital Cost $0 $ 16

, 411 ,8 0 0 $ 32

, 122

, 5 00

Capital Recover Factor N/A 0.0806 0.0806

Annual Capital Recovery Costs $0 $ 1,322,791 $ 2,589,074

Annual O&M Costs $0 $ 3,826,610 $ 4,455

, 040

Annual Cost of Control $0 $ 5,149,401 $ 7,044,114

Table 11 : Boiler D Environmental Cost s

Baseline Option 1: SDA Option 2 : WFGD

Annual SO 2 Emission (tpy) ( a) 2

, 894.7 578.9 289.5

Perce nt Control from Baseline 0 80% 90%

Annual SO 2 Reduction from Baseline (tpy) 0 2,315.8 2,605.2

Annual Cost of Control $0 $ 5,149,401 $ 7,044,114

Cost per ton of Reduction N/A $ 2 ,2 24 $ 2,704

Incremental Cost per ton of Reduction N/A $ 2 ,2 24 $ 6,547

(a) Annua l baseline emission s based on 3 year average of actual SO 2 emissions from the boiler for calendar years 2001

- 2003

Step 5: Evaluate visibility impacts, for SO 2 is addressed in a comprehensive visibility analysis covering all three visibility impairing poll utants and associate control options. The visibility analysis follows the PM evaluation in this analysis.General Chemical Green River Works

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PM 10 : STEPS 1

- 4 COMBINED

General Chemical addressed PM emissions through an abbreviated analysis. While there are several PM control technologies a vailable for coal

- fired boilers, two dominant technologies are electrostatic precipitators and baghouses. Both technologies are technically feasible for boilers. The existing ESP on each boiler is effective at controlling PM emissions . However, upgrade and installation costs associated with retrofitting the boilers with additional PM controls can be high, as demonstrated in the FMC

Westvaco BART a nalysis. P revious visibility modeling analyses , including the BART analysis for FMC Wyoming Corporation‟s We stvaco Facilty, AP

- 6045, indicate that the contribution in visibility degradation from PM for a source comparable to the two coal

- fired boilers located a similar distance from a Class I area is minor when compared to the contributing effects of NO

x and SO 2

. Additionally, costs for controlling PM from similar coal

- fired boilers are high. The average costs to control PM emissions from

NS

- 1A and NS

- 1B, two (2) 887 MMBtu/hr coal

- fired boilers, at the Westvaco Facility are between $29, 654 and $42,958 and the incremental costs are between $39,253 and $42,958, based on installing an additional ESP or a new baghouse. T he Division did not require General Chemical to perform additional visibility analyses for PM control options beyond the existing dry ESP s

. Boile rs C and D will continue to

meet PM/PM 10 emission limit s in Operating Permit 3

- 1

- 123 of 50 .0 lb/hr and 80 .0 lb/ hr, respectively.

VISIBILITY IMPROVEMENT DETERMINATION :

The fifth of five factor s that must be considered for a BART determination analysis, as required by 40 CFR part 51

- Appendix Y, is the degree of Class I area visibility improvement that results from the possible options for control technology. This factor was evaluated for the General Chemical Green River facility by using an EPA

- approved dispersion modeling system (CALPUFF) to predict the change in Class I area visibility. The Division had previously determined that the General Chemical Green River facility was subject to BART based on the results of initial screening modeling that was co nducted using current (baseline) emissions from the facility. The screening modeling, as well as m ore refined modeling conducted by the applicant

, is described in detail below.

Bridger Wilderness Area (WA) and Fitzpatrick WA are the two closest Class I areas to the General

Chemical Green River facility, as shown in F igure 1 below. Bridger W A is located approximately 1 20 kilometers (km) northeast of G eneral Chemical and Fitzpatrick WA is located approximately 15 4 km northeast of the facility.

Only th ose Class I areas most likely to be impacted by the Green River facility sources were modeled, as determined by source/Class I area locations, distances to each Class I area, and professional judgment considering meteorological and terrain factors. A reas greater than 300 km from Green River were excluded from consideration . All source

- Class I area distances from Green River to Bridger WA and Fitzpatrick WA exceed 50 km and are less than 300 km, thus falling within the range of recommended CALPUFF applicat ion. If impacts are less than the BART threshold for the Class I areas modeled, it can be reasonably assumed that areas at a greater distance and in directions of less frequent plume transport will not experience significant impacts.General Chemical Green River Works

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- 6046 BART Application Analysis Page 13

Figure 1

SCREENING MODELING

To determine if the G eneral Chemical G reen River facility would be subject to BART, the Division conducted CALPUFF modeling using three years of meteorological data. These data, from 1995

- 1996 and 2001, consisted of surface and u pper

- air observations and gridded output from the Mesoscale Model ( MM5 ) . Resolution of the MM5 data was 36

- km for all three of the modeled years. S ources input to the modeling included the potential emissions (current operation) from two emission units a t the Green River facility, the coal

- fired boilers GR

- 2

- L (“Boiler C”) and GR

- 3

- W (“Boiler D”)

.General Chemical Green River Works

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Results of the modeling showed that the 98 th percentile value for the change in visibility (delta deciview [Δdv]) was above 0.5 Δ dv for Bridger W A for all three years of meteorolog y

. As defined in EPA‟s final
BART rule, a 98 th percentile 0.5 Δ dv impact or more from a given source indicates that the source contributes to visibility impairment, and therefore is subject to BART. The results of the screening modeling are shown in the table below.

Results of the Class I Area Screening Modeling

Class I Area Maximum

Modeled Value (Δdv) 98 th

Percentile

V alue (Δdv)

1995 Bridger WA 1.47 0.75 Fitzpatrick WA 0.70 0.30

1996 Bridger WA 2.37 0.98 Fitzpatrick WA 1.66 0.37

2001 Bridger WA 1.76 1.36 Fitzpatrick WA 1.08 0.49

Δdv = delta deciview

WA = wilderness area

REFINED MODELING

Because of the re sults of the Division‟s screening modeling, G eneral C hemical was required to conduct a refined BART analysis that included CALPUFF visibility modeling for the facility. The modeling approach followed the requirements described in the Division‟s BART model ing protocol, BART Air Modeling Protocol

- Individual Source Visibility Assessments for BART Control Analyses (WDEQ

- AQD, September 2006)

.

CALPUFF System

Predicted visibility impacts from the General Chemical Green River sources were determined with the EPA CALPUFF modeling system, which is the EPA

- preferred modeling system for long

- range transport. As described in the EPA Guideline on Air Quality Models (Appendix W of 40 CFR Part 51), long

- range transport is defined as modeling with source

- receptor dist ances greater than 50 km . Because all modeled areas are located more than 50 km from the sources in question, the CALPUFF system was appropriate

for use.

The CALPUFF modeling system consists of a meteorological data pre

- processor (CALMET), an air dispers ion model (CALPUFF), and post

- processor programs (POSTUTIL, CALSUM, CALPOST). The CALPUFF model was developed as a non

- steady

- state air quality modeling system for assessing the

effects of time

- and space

- varying meteorological conditions on pollutant tra nsport, transformation, and

removal.General Chemical Green River Works

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CALMET is a diagnostic wind model that develops hourly wind and temperature fields in a three

dimensional, gridded modeling domain. Meteorological inputs to CALMET can include surface and

upper

- air observations fro m multiple meteorological monitoring stations. Additionally, the CALMET model can utilize gridded analysis fields from various mesoscale models such as MM5 to better represent regional wind flows and complex terrain circulations. Associated two

- dimension al fields such as mixing height, land use, and surface roughness are included in the input to the CALMET model. The CALMET model allows the user to “weight” various terrain influence parameters in the vertical and horizontal directions by defining the rad ius of influence for surface and upper

- air stations.

CALPUFF is a multi

- layer, Lagrangian puff dispersion model. CALPUFF can be driven by the three

dimensional wind fields developed by the CALMET model (refined mode), or by data from a single

surface a nd upper

- air station in a format consistent with the meteorological file s used to drive steady

- state dispersion models. All far

- field modeling assessments described here were completed using the

CALPUFF model in a refined mode.

CALSUM is a post

- processin g program that can operate on multiple CALPUFF output files to combine the results for further post

- processing. POSTUTIL is a post

- processing program that processes

CALPUFF concentrations and wet/dry flux files . The POSTUTIL model operates on one or more output data files from CALPUFF to sum, scale, and/or compute species derived from those that are modeled , and outputs selected species to a file for further post

- processing . C ALPOST is a post

- processing program that can read the CALPUFF (or POSTUTIL or C ALSUM) output files, and calculate the impacts to visibility.

All of the refined CALPUFF modeling was conducted with the version of the CALPUFF system that was recognized as the EPA

- approved release at the time of the development of the Division‟s model ing protocol. Version designations of the key programs are listed in the table below.

Key Programs in CALPUFF System
Program Version Level

CALMET 5.53a 040716

CALPUFF 5.711a 040716

CALPOST 5.51 030709

Meteorological Data Processing (CALMET)

As requ ired by the Division‟s modeling protocol, the CALMET model was used to construct the initial

three

- dimensional windfield using data from the MM5 model . Surface and upper

- air data were also input

to CALMET to adjust the initial windfield, but because of th e relative scarcity of observations in the modeling domain, the influence of the observations was limited. Because the MM5 data were afforded a high degree of influence on the CALMET windfields, the Division obtained MM5 data at 12

- km resolution that spann ed the years 2001

- 2003. Surface, upper

- air, and precipitation data for the domain was incorporated into the CALMET windfield. Locations of the various observations are shown in the figure below. The Division provided the BART applicants all raw meteorolo gical inputs for the CALMET

model.

Default settings were used in the CALMET input files for most of the technical options. The following table lists the key user

- defined CALMET settings that were selected.General Chemical Green River Works

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Key User

- Defined CALMET Settings

Variable D escription Value

PMAP Map projection LCC

DGRIDKM Grid spacing (km) 4

NZ Number of layers 10

ZFACE Cell face heights (m) 0, 20, 40, 100, 140, 320, 580, 1020, 1480, 2220, 3 4 00

RMIN2 Minimum distance for extrapolation

- 1

IPROG Use grid ded prognostic model output 14

RMAX 1 Maximum radius of influence (surface

layer, km) 30

RMAX 2 Maximum radius of influence (layers

aloft, km) 50

TERRAD Radius of influence for terrain (km) 15

R1 Relative weighting of first guess wind

field and observations (km) 5

R2 Relative weighting aloft (km) 25General Chemical Green River Works

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CALPUFF Modeling Setup

To allow chemical transformations within CALPUFF using the recommended chemistry mechanism (MESOPUFF II), the model required input of background ozone a nd ammonia. For ozone, hourly data collected from the following stations were used:

Rocky Mountain National Park, Colorado (NP)
Craters of the Moon National Monument, Idaho Highland, Utah Thunder Basin, Wyoming Yellowstone NP, Wyoming Centennial, Wyoming Pinedale, Wyoming

For any hour that was missing ozone data from all stations, a default value of 44 parts per billion (ppb) was used by the model as a substitute. For ammonia, a domain

- wide background value of 2 ppb was

used.

Discrete receptors for t he Class I areas that were modeled (Bridger WA and Fitzpatrick WA) were provided by the Division.

CALPUFF Inputs

– Baseline and Control Options

The first step in the refined modeling analysis was to perform visibility modeling for current (baseline)

ope rations at the facility

. Baseline source release parameters and emissions are shown in the table below, followed by a table with data for the various control options.

For all cases, p articulate emissions were divided between fine particulate (PMF) and coarse particulate (PMC) and modeled accordingly within CALPUFF and CALPOST.

The percentage reductions from the baseline emissions for the various control options are shown below:

Low NO

x burners (LNB) and separated overfire air (SOFA): 30% reduction in NO

x Selective catalytic reduction (SCR): 80% reduction in NO

x S elective non

- catalytic reduction (SNCR): 50% reduction in NO

x Wet flue gas desulfurization (WFGD): 90% reduction in SO 2 Dry flue gas desulfurization (DFGD): 80% reduction in SO 2General Chemical Green River Works

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So urce Parameters and Emissions for the Baseline Scenario

Parameter Baseline

Coal

- Fired Boiler C (GR

- 2

- L) Coal

- Fired Boiler D

(GR

- 3

- W)

NO

x Control

– o verfire a ir , low excess air

PM Control

– “hot

- side” ESP

SO 2 Control

– no add

- on controls

Heat Input (MMBtu/hr) 534 880

Base Elevation (m) 1928 1928

Stack Height (m) 47.55 47.55

Stack Diameter (m) 3.05 3.05

Stack Temperature (K) 452.6 460.9

Exit Velocity (m/s) 15.98 25.12

SO 2 Emissions (lb/MMBtu) 1.2 1.2

SO 2 Emissions (lb/hr) 640.8 1056.0

H 2 SO 4 Emissions (lb/hr) 5.87 9.39

NO

x Emissions (lb/MMBtu) 0.7 0.7

NO

x Emissions (lb/hr) 376.0 616.0

PM Coarse Emissions (lb/hr) 27.77 44.44

PM Fine Emissions (lb/hr) 21.39 34.24

Elemental Carbon Emissions (lb/hr) 0.82 1.32

Organic Carbon Emissions (lb /hr) 1.47 2.35

ESP = electrostatic precipitator

H 2 SO 4 = sulfuric acid

K = Kelvin lb/hr = pounds per hour lb/MMBtu = pounds per million British thermal units

m = meters m/s = meters per second MMBtu/hr = million British thermal units per hour

NO

x = nitro gen oxides PM = particulate matter

SO 2 = sulfur dioxideGeneral Chemical Green River Works

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Source Parameters and Emissions for BART Control Options

Parameter Control Option 1 Control Option 2 Control Option 3 Control Option 4

LNB + SOFA SNCR SCR DFGD

Coal

Fired

Boiler C (GR

- 2

- L) Coal

Fired

Boiler D (GR

- 3

- W) Coal

Fired

Boiler C (GR

- 2

- L) Coal

Fired

Boiler D (GR

- 3

- W) Coal

Fired

Boiler C (GR

- 2

- L) Coal

Fired

Boiler D (GR

- 3

- W) Coal

Fired

Boiler C (GR

- 2

- L) Coal

Fired

Boiler D (GR

- 3

- W)

Base Elevation (m) 1928 1928 1928 1928 1928 1928 1928 1928

Stack Height (m) 47.55 47.55 47.55 47.55 47.55 47.55 79.24 79.24

Stack Diameter (m) 3.05 3.05 3.05 3.05 3.05 3.05 3.05 3.05

Stack Temperature (K) 452 .6 460.9 452.6 460.9 452.6 460.9 322.0 322.0

Exit Velocity (m/s) 15.98 25.12 15.98 25.12 15.98 25.12 15.98 25.12

SO 2 Emissions (lb/hr) 641.0 1056.0 641.0 1056.0 641.0 1056.0 128.0 211.0

HS 2 O 4 Emissions (lb/hr) 5.87 9.39 5.87 9.39 5.87 9.39 5.87 9.39

NO

x Emissions (lb/hr) 263.0 431.0 188.0 308.0 75.0 123.0 376.0 616.0

PM Coarse Emissions (lb/hr) 27.77 44.44 27.77 44.44 27.77 44.44 27.77 44.44

PM Fine Emissions (lb/hr) 21.39 34.24 21.39 34.24 21.39 34.24 21.39 34.24

Elemental Carbon (lb/hr) 0.82 1.32 0 .82 1.32 0.82 1.32 0.82 1.32

Organic Emissions (lb/hr) 1.47 2.35 1.47 2.35 1.47 2.35 1.47 2.35
DFGD = dry flue gas desulfurization

H 2 SO 4 = sulfuric acid

K = Kelvin lb/hr = pounds per hour

LNB = low NO

x burners

m = meters m/s = meters per s econd

NO

x = nitrogen oxides PM = particulate matter

SNCR = selective non

- catalytic reduction

SO 2 = sulfur dioxide SOFA = separated overfire airGeneral Chemical Green River Works

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Source Parameters and Emissions for BART Control Options (cont.)

Parameter Control Option 5 Contro l Option 6 Control Option 7 Control Option 8

WFGD LNB /SOFA + DFGD LNB /SOFA + WFGD SNCR + DFGD

Coal

Fired

Boiler C (GR

- 2

- L) Coal

Fired

Boiler D (GR

- 3

- W) Coal

Fired

Boiler C (GR

- 2

- L) Coal

Fired

Boiler D ( GR

- 3

- W) Coal

Fired

Boiler C (GR

- 2

- L) Coal

Fired

Boiler D (GR

- 3

- W) Coal

Fired

Boiler C (GR

- 2

- L) Coal

Fired

Boiler D (GR

- 3

- W)

Base Elevation (m) 1928 1928 1928 1928 1928 1928 1928 1928

Stack Height (m) 79.2 4 79.24 79.24 79.24 79.24 79.24 79.24 79.24

Stack Diameter (m) 3.05 3.05 3.05 3.05 3.05 3.05 3.05 3.05

Stack Temperature (K) 322.0 322.0 322.0 322.0 322.0 322.0 322.0 322.0

Exit Velocity (m/s) 15.98 25.12 15.98 25.12 15.98 25.12 15.98 25.12

SO 2 Emissio ns (lb/hr) 64.0 106.0 64.0 106.0 128.0 211.0 128.0 211.0

HS 2 O 4 Emissions (lb/hr) 5.87 9.39 5.87 9.39 5.87 9.39 5.87 9.39

NO

x Emissions (lb/hr) 376.0 616.0 263.0 431.0 188.0 308.0 263.0 431.0

PM Coarse Emissions (lb/hr) 27.77 44.44 27.77 44.44 27.77 44.4 4 27.77 44.44

PM Fine Emissions (lb/hr) 21.39 34.24 21.39 34.24 21.39 34.24 21.39 34.24

Elemental Carbon (lb/hr) 0.82 1.32 0.82 1.32 0.82 1.32 0.82 1.32

Organic Emissions (lb/hr) 1.47 2.35 1.47 2.35 1.47 2.35 1.47 2.35
DFGD = dry flue gas desulfuriza tion

H 2 SO 4 = sulfuric acid

K = Kelvin lb/hr = pounds per hour

LNB = low NO

x burners

m = meters m/s = meters per second

NO

x = nitrogen oxides PM = particulate matter

SNCR = selective non

- catalytic reduction

SO 2 = sulfur dioxide

SOFA = separated overfire air WFGD = wet flue gas desulfurizationGeneral Chemical Green River Works

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Source Parameters and Emissions for BART Control Options (cont.)

Parameter Control Option 9 Control Option 10 Control Option 11

SNCR + WFGD SCR + DFGD SCR + WFGD

Coal

Fired

Boiler C ( GR

- 2

- L) Coal

Fired

Boiler D (GR

- 3

- W) Coal

Fired

Boiler C (GR

- 2

- L) Coal

Fired

Boiler D (GR

- 3

- W) Coal

Fired

Boiler C (GR

- 2

- L) Coal

Fired

Boiler D (GR

- 3

- W)

Base Elevation (m) 1928 1928 1928 1928 1928 1928

Stack Height (m) 79.24 79.24 79.24 79.24 79.24 79.24

Stack Diameter (m) 3.05 3.05 3.05 3.05 3.05 3.05

Stack Temperature (K) 322.0 322.0 322.0 322.0 322.0 322.0

Exit Velocity (m/s) 15.98 25.12 15.98 25.12 15.98 25.12

SO 2 Emissions (lb/h r) 64.0 106.0 128.0 211.0 64.0 106.0

HS 2 O 4 Emissions (lb/hr) 5.87 9.39 5.87 9.39 5.87 9.39

NO

x Emissions (lb/hr) 188.0 308.0 75.0 123.0 75.0 123.0

PM Coarse Emissions (lb/hr) 27.77 44.44 27.77 44.44 27.77 44.44

PM Fine Emissions (lb/hr) 21.39 34.24 21. 39 34.24 21.39 34.24

Elemental Carbon (lb/hr) 0.82 1.32 0.82 1.32 0.82 1.32

Organic Emissions (lb/hr) 1.47 2.35 1.47 2.35 1.47 2.35
DFGD = dry flue gas desulfurization

H 2 SO 4 = sulfuric acid

K = Kelvin lb/hr = pounds per hour

LNB = low NO

x burners

m = meters m/s = meters per second

NO

x = nitrogen oxides PM = particulate matter

SNCR = selective non

- catalytic reduction

SO 2 = sulfur dioxide WFGD = wet flue gas desulfurizationGeneral Chemical Green River Works

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Visibility Post

- Processing (CALPOST) Setup

The changes in visibility were calculated using Method 6 within the CALPOST post

- processor. Method 6 requires input of monthly relative humidity factors [f(RH)] for each Class I area. Monthly f(RH) factors that were used for Bridger WA and Fitzpatrick WA are shown in the table

below.

Relative Humidity Factors for CALPOST

Month Bridger WA

Fitzpatrick WA

January 2.50

February 2.30

March 2.30

April 2.10

May 2.10

June 1.80

July 1.50

August 1.50

September 1.80

October 2.00

November 2.50

December 2.40

According to the final BART rule, n atural background conditions as a reference for determination of the Δdv change within CALPOST should be representative of the 20% best natural visibility days. EPA BART guidance provides the 20% best days decivie w values for each Class I area on an annual basis, but does not provide species concentration data for the 20% best background

conditions.

S pecies concentrations corresponding to the 20% best days were calculated for each Class I area by scaling back the annual average concentrations given in Table 2

- 1 of the EPA document Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule. A separate scaling factor was derived for each Class I area such that, when multiplied by the g uidance table annual concentrations, the 20% best days dv value for that particular Class I area would be calculated. The scaled aerosol concentrations were averaged for the Bridger WA and Fitzpatrick WA because of their geographical proximity and similar annual background visibility. The 20% best days aerosol concentrations that were used for each month are listed in the table below.General Chemical Green River Works

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Natural Background Aerosol Concentrations (μg/m 3 )

Aerosol Component Fitzpatrick WA

Bridger WA

Ammonium Sulfate 0 .045

Ammonium Nitrate 0 .038

Organic Carbon 0 .178

Elemental Carbon 0 .008

Soil 0 .189

Coarse Mass 1.136

Visibility Post

- Pro cessing Results

Baseline Conditions:

The results of the visibility modeling for both units combined are shown in the table below. For each year modeled, the 98 th percentile result is greater than 0.5 Δdv at Bridger WA . For Fitzpatrick WA , the 98 th perc entile results equals or exceeds 0.5 Δdv for two of the three years of meteorology

.

Particulate (PM) emissions contributed very little to the modeled results. For example, the percentage contribution from PM on days above 0.5 Δdv at Bridger WA was at m ost 3.5% and on average 1.6% (2001 meteorology). Therefore, subsequent modeling of the various control options did not consider any additional PM controls.

CALPUFF Visibility Modeling Results: Baseline Conditions

Class I Area 2001 2002 2003

98th

Perc entile

Value (Δdv) Total

No. of Days >

0.5 Δdv 98 th

Percentile

Value (Δdv) Total

No. of Days >

0.5 Δdv 98 th

Percentile

Value (Δdv) Total

No. of Days >

0.5 Δdv
Bridger WA 0.84 21 0.72 16 0.97 16
Fitzpatrick WA 0.50 8 0.47 7 0.59 10

Δdv = delta deciview

W A = wilderness area

Control Options:

The results of the visibility modeling for the control options are summarized in the table below. Because the baseline results for 2001 yielded the highest number of days above 0.5 Δdv at the nearest Class I area (Br idger WA), the impacts for that year were used for evaluating the control options.General Chemical Green River Works

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CALPUFF Visibility Modeling Results: BART Control Option s

Class I Area 2001

98th Percentile Value (Δdv) Total

No. of Days >

0.5 Δdv
Control Option 1
Bridger WA 0.7 2 14
Fitzpatrick WA 0.44 7
Control Option 2
Bridger WA 0.64 11
Fitzpatrick WA 0.39 6
Control Option 3
Bridger WA 0.53 8
Fitzpatrick WA 0.33 4
Control Option 4
Bridger WA 0.59 9
Fitzpatrick WA 0.30 5
Control Option 5
Bridger WA 0.53 9
Fitzpatri ck WA 0.28 4
Control Option 6
Bridger WA 0.45 7
Fitzpatrick WA 0.23 2
Control Option 7
Bridger WA 0.40 7
Fitzpatrick WA 0.21 2
Control Option 8
Bridger WA 0.36 5
Fitzpatrick WA 0.18 2
Control Option 9
Bridger WA 0.31 3
Fitzpatrick WA 0.16 2

Co ntrol Option 10
Bridger WA 0.22 2
Fitzpatrick WA 0.12 0
Control Option 11
Bridger WA 0.17 1
Fitzpatrick WA 0.09 0

Δdv = delta deciview

WA = wilderness areaGeneral Chemical Green River Works

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BART DETERMINATION:

General Chemical ‟s proposed BART control option , the installation o f LNB with SOFA (Option 1) results in a reduction of 0. 12 Δdv in the 98 th percentile result at Bridger WA as compared to

the baseline condition for both units , and a reduction of 0. 06 Δdv in the 98 th percentile result at Fitzpatrick WA as compared to the b aseline condition for both units . The individual 98 th
percentile values for both boiler s, C and D , were below a 0. 5 Δdv increase from background conditions for all three years of meteorology. Therefore, the proposed BART controls for both

coal

- fired boil ers reduce visibility impacts below the 0.5 Δdv threshold used in the screening analysis to determine if sources contribute to visibility impairment. Based on the results of this analysis, the Division has determined that the installation of low NO

x burne rs with separated

overfire air meeting a NO

x emission limit of 0. 49 lb/MMBtu (30

- day rolling average) , which

equates to 263

. 0 lb/hr (30

- day rolling) for boiler C and 431.0 lb/hr (30

- day rolling) for boiler D represents BART for each of the boiler s . No ad ditional controls are required by BART for

PM/PM 10 emissions from the two boilers and they will continue to meet a PM/PM 10 emission

limit of 0. 10 lb/MMBtu, which equates to 50.0 lb/hr for boiler C and 80.0 lb/hr for boiler D

.

WESTERN BACKSTOP SULFUR DIOXI DE TRADING PROGRAM:

Wyoming is a §309 state and will participate in the Western Backstop Sulfur Dioxide Trading Program should it be triggered. General Chemical evaluated SO 2 emission rate s from the application of SDA and WFGD of 0. 24 lb/MMBtu and 0.12 l b/MMBtu, respectively . In accordance with Wyoming‟s §309 Regional Haze SIP and WAQSR Chapter 6, Section 9, General

Chemical will not be required to meet either proposed emission limit under BART. Instead,

General Chemical will be required to participate in the emission trading program authorized under Chapter 14 of the WAQSR should the program be triggered.

CHAPTER 6, SECTION 4

– PREVENTION OF SIGNIFICANT DETERIORATION (PSD):

General Chemical‟s Green River Works is a “major emitting facility” under Chap ter 6, Section 4 of the Wyoming Air Quality Standards and Regulations (WAQSR) because emissions of a criteria pollutant are greater than 250 tpy. Installation of the LNB with SOFA, as required by

BART

, may result in a CO emission increase above 40 tpy. U nder Chapter 6 , Section 4, General

Chemical will be required to submit a permit application addressing the increase in CO emissions and Prevention of Significant Deterioration (PSD) applicability . If required, a permit must be

obtained prior to commencing construction to install the LNB with S OFA controls.

CHAPTER 5, SECTION 2

– NEW SOURCE PERFORMANCE STANDARDS (NSPS):

The installation of the LNB with SOFA will not change New Source Performance Standard applicability for the two coal

- fired boilers C and D at the Green River Works

.General Chemical Green River Works

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CHAPTER 5, SECTION 3

– NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS (NESHAPs) AND CHAPTER 6, SECTION 6

– HAZARDOUS AIR POLLUTANT (HAP) EMISSIONS AND MAXIMUM AVAILABLE CONTROL TECHNOLOGY (MACT):

The installation of the LNB with SOFA will not change 40 CFR part 63 applicability for the two existing coal

- fired boilers C and D at the Green River Works.

CHAPTER 6, SECTION 3

– OPERATING PERMIT:

General Chemical ‟s Green River Works is a major source under Chapter 6, Sec tion 3 of the Wyoming Air Quality Standards and Regulations. Operating Permit 3

- 1

- 12 3 was issued for the facility on June 10 , 200 8 . In accordance with Chapter 6, Section 3 of the Wyoming Air Quality Standards and Regulations (WAQSR), General Chemical wil l need to modify their operating permit to include the changes authorized in this permitting action.

CONCLUSION:

The Division is satisfied that the General Chemical (Soda Ash) Partners‟ Green River Works will comply with all applicable Wyoming Air Qualit y Standards and Regulations. The Division proposes to issue a BART Air Quality Permit for the Green River Works ‟ modification.

PROPOSED PERMIT CONDITIONS:

The Division proposes to issue an Air Quality Permit to General Chemical (Soda Ash) Partners

for t he modification of the Green River Works with the following conditions:

1. Authorized representatives of the Division of Air Quality be given permission to enter and inspect any property, premise or place on or at which an air pollution source is

located or is being constructed or installed for the purpose of investigating actual or potential sources of air pollution, and for determining compliance or non

- compliance with any rules, standards, permits or orders.

2. All substantive commitments and descripti ons set forth in the application for this permit, unless superseded by a specific condition of this permit, are incorporated herein by this reference and are enforceable as conditions of this permit.

3. That General Chemical (Soda Ash) Partners shall modi fy their Operating Permit in accordance with Chapter 6, Section 9(e)(iv) and Chapter 6, Section 3 of the WAQSR.

4. All notifications, reports and correspondence associated with this permit shall be submitted to the Stationary Source Compliance Program Man ager, Air Quality Division, 122 West 25th Street, Cheyenne, WY 82002 and a copy shall be submitted to the District Engineer, Air Quality Division, 510 Meadowview Drive, Lander, WY 82520.General Chemical Green River Works

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5. That the date of commencement of construction shall be reported to the Administrator within 30 days of commencement. In accordance with Chapter 6, Section 2(h) of the WAQSR, approval to construct or modify shall become invalid if construction is not commenced within 24 months after receipt of such approval or if const ruction is discontinued for a period of 24 months or more. The Administrator may extend the period based on satisfactory justification of the requested extension.

6

. Each time l ow NO

x b urners with separated overfire air is installed, the owner or operato r shall furnish the Administrator written notification of: (i) the anticipated date of initial startup not more than 60 days or less than 30 days prior to such date, and; (ii) the actual

date of initial start

- up within 15 days after such date in accordance with Chapter 6, Section 2(i) of the WAQSR.

7

. Performance tests shall be conducted and a written report of the results submitted within 30 days of achieving maximum design rate but not later than 90 days following initial

start

- up in accordance with Chap ter 6, Section 2(j) of the WAQSR. The operator shall provide 15 days prior notice of the test date. If maximum design production rate is not achieved within 90 days of start

- up, the Administrator may require testing at the rate achieved and again when ma ximum rate is achieved.

8. Emissions from each unit shall not exceed the levels below.

Boiler C Upon installation of control equipment:

NO

x : 0. 49 lb/MMBtu and 26 3

. 0 lb/hr ; 30

- day rolling average
1,1 52.0 tpy

a. Limits shall apply during all operating period s. b. Limits shall become effective upon startup of the unit with

l ow NO

x burners with separated overfire air and completion of the initial performance tests required by Condition 7 of this permit. Actual date of startup shall be submitted as required by Con dition 6 of this permit.

Boiler D Upon installation of control equipment:

NO

x : 0.49 lb/MMBtu and 431

. 0 lb/hr; 30

- day rolling average
1, 88 7

. 8 tpy

a. Limits shall apply during all operating periods.

b. Limits shall become effective upon startup of the unit with

l ow NO

x burners with separated overfire air and completion of the initial performance tests required by Condition 7 of this permit. Actual date of startup shall be submitted as required by Condition 6 of this permit.General Chemical Green River Works

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- 6046 BART Application Analysis Page 29

9

. P erformance tests, required by Con dition 7 of this permit, shall consist of the following:

Boilers C and D :

NO

x Emissions

– Compliance with the NO

x 30

- day rolling average shall be determined using a continuous emissions monitoring system (CEMS) certified in accordance with 40 CFR part 60

. Testing is required for boilers C and D after

installation of low NO

x burners with separated overfire air.

10

. Prior to any performance testing required by this permit, a test protocol shall be submitted to the Division for approval, at least 30 days p rior to testing. Results of the tests shall be submitted to this office within 45 days of completing the tests.

1 1

. If the Western B ackstop S ulfur D ioxide T rading P rogram is triggered in accordance with Chapter 14 then General Chemical shall participate in the trading program as required by Chapter 14, Section 2(c)(i).

1 2

. Following the performance tests required by Condition 7 , compliance with the limits set forth in this permit for the C and D coal

- fired boilers shall be determined with data from

the e xisting continuous monitoring systems as follows:

a. Exceedances of the NO

x limits shall be defined as follows:

i. Any 30

- day rolling average of NO

x emissions which exceeds the

lb/MMBtu limits calculated in accordance with 40 CFR part 60, subpart

D.

ii. Any 30

- day rolling average calculated using valid data (output concentration and average hourly volumetric flowrate) from the existing CEM equipment which exceeds the lb/hr NO

x limit established in this permit. Valid data shall meet the requirem ents of WAQSR, C hapter 5,

Section 2(j) and follow the compliance provisions and monitoring requirements of §60.4 8Da and §60.4 9Da

. The 30

- day average emission

rate shall be calculated as the arithmetic average o f hourly emissions with valid data during the previous 30

- day period.

b. General Chemical shall comply with all reporting and record keeping requirements as specified in WAQSR

, Chap ter 5, Section 2(g) and 40 CFR p art 60, s ubpart D. All excess emissions shall be reported using the procedures and reporting format sp ecified in WAQSR

, Chapter 5, Section 2(g).

1 3

. Records required by any applicable regulation or permit condition shall be maintained for a minimum period of five (5) years and shall be readily accessible to Division representatives.General Chemical Green River Works

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1 4

. General Chemical shall install l ow NO

x burners with separated overfire air on boiler s C

and D , in accordance with the Division‟s BART determination, and conduct the initial performance test s required in Condition 9 no later than January 1, 2014.

# Appendix A

Fa cility Location