DEPARTMENT OF ENVIRONMENTAL QUALITY

AIR QUALITY DIVISION

BART Application Analysis

AP-6046

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

TELEPHONE NUMBER: (307) 875-3350

REVIEWING ENGINEERS: 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 Technology (BART) to reduce emissions of 

three (3) visibility impairing pollutants, nitrogen oxides (NOx), particulate matter (PM), and sulfur 

dioxide (SO2). EPA published Appendix Y to part 51 - Guidelines for BART Determinations Under the 

Regional Haze Rule 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 NOx and PM10 for each source subject to BART and include each determination in 

the §308 Wyoming Regional Haze State 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 Visibility Transport Commission (i.e., Arizona, California, Colorado, Idaho, 
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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 special provisions for 

addressing SO2 emissions, which include a Market Trading program and a provision for a 2018 SO2

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 SO2 emissions as part of the BART analysis.

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

Available Retrofit Technology (BART) analysis 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 Works‟ location is attached as Appendix A.

On May 6, 2008 General Chemical submitted additional documentation committing to install BARTdetermined 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 Wyoming 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 sources 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, 1962 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 visibility. 

Three pollutants are identified by 40 CFR part 51, Appendix Y as visibility impairing pollutants. They 

are sulfur dioxide (SO2), nitrogen oxides (NOx), and particulate matter (PM). Particulate matter with an 

aerodynamic diameter of 10 microns or less (PM10) 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 SO2 or NOx or 15 tons of PM10 were included in the screening analysis. Using 

three years of meteorological data, the screening analysis calculated visibility impacts from sources at 

nearby Class I areas. Sources whose modeled 98th percentile 24-hour impact or 8th 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.
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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. Overfire air and 

low excess air are currently used to reduce NOx emissions from the boilers. SO2 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 3-1-123 Emission Limits

Source

Firing Rate 

(MMBtu/hour)

Existing 

Controls

NOx

(lb/MMBtu)

SO2

(lb/MMBtu)

PM/PM10

(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 fixed) 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 on 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 control 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 emissions 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, subpart Y, as required in 

WAQSR Chapter 6 Section 9(c)(i). This methodology is comprised of five basic steps:

Step 1: Identify all1available retrofit control technologies

Step 2: Eliminate technically infeasible options

Step 3: Evaluate control effectiveness of remaining control technologies

Step 4: Evaluate impacts and document the results

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 NOx, PM, and SO2.

 

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.”
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NOx: INDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

General Chemical identified three well-established control technologies, including the most stringent 

option, for reducing NOx emissions from existing process boilers: selective catalytic reduction (SCR), 

selective non-catalytic reduction (SNCR), and combustion modifications including low NOx burners 

(LNB). SNCR and SCR are add-on, post combustion controls that can reduce NOx emissions by 50% and 

90%, respectively. The third control, combustion modifications including LNB, involves modifying the 

existing coal injection and the combustion air to reduce NOx emissions. In addition to using these three 

controls individually, they can be combined to increase the overall NOx emissions reduction. LNB are

often used with SCR to control NOx 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. NOx entrained in the flue gas 

is reduced to molecular nitrogen (N2) 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 much 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 injection 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, and 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 2,200 F. SNCR systems are very sensitive to temperature changes and 

typically have lower NOx emissions reduction and higher ammonia slip than SCR systems.

3. Low NOx 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 

NOx. Lean premix combustion occurs when excess air and fuel are well controlled by burner 

injection prior to entering the combustion zone to effectively operate at or near the limit of 

flammability. This operation minimizes the amount of thermal NOx 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 NOx formation.

NOx: ELIMINATE 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 operation.

NOx: 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 determined to reduce NOx

emissions from each boiler by approximately 12%. LNB with separated overfire air (SOFA) could reduce 
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emissions by an additional 18% for a total NOx reduction from each boiler of 30%. The application of 

SNCR was determined to reduce NOx emissions by 50%. Installing SCR reduced emissions the most. 

Each boiler could reduce NOx emissions by 80% if SCR was installed. Resulting emission rates are 

shown in Table 2.

Table 2: NOx Emission Rates Per Boiler

Control Technology

Boiler C

Resulting NOx

Emission Rate 

(lb/MMBtu) / (lb/hr)

Boiler D

Resulting NOx

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 SOFA 0.49 (b) / 263 0.49 (b) / 431

SNCR 0.35 (b) / 188 0.35 (b) / 308

SCR 0.14

(b) / 75 0.14 (b) / 123

(a) 40 CFR part 60, subpart D limit

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

NOx: 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 and D. Costs associated with proposed 

and modeled NOx control options are presented 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 steam 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 

account 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 reduced 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. The replacement energy cost is equal to $1,316,000 for each boiler.
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The environmental cost for each control option was based on a three year average of actual NOx

emissions from each of the boilers. NOx emissions from calendar years 2001-2003 were used to calculate 

an average yearly emission rate. 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 annualized 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 boilers are summarized in the following tables.

Table 3: Boiler C Economic Costs

Cost Baseline

Option 1: LNB, 

separated OFA

Option 2: SNCR 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 Costs

Baseline

Option 1: LNB, 

separated OFA

Option 2: SNCR Option 3: SCR

Annual NOx Emission (tpy) (a)

1,057.4 740.2 528.7 211.5

Percent Control from Baseline 0 30% 50% 80%

Annual NOx 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 emissions based on 3 year average of actual NOx emissions from the boiler for calendar years 2001-2003
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Table 5: Boiler D Economic Costs

Cost Baseline

Option 1: LNB, 

separated OFA

Option 2: SNCR Option 3: SCR

Control Equipment Capital Cost $0 $4,197,600 $8,391,400 $19,194,500

Capital Recover Factor N/A 0.0944 (a)

0.0806 0.0806

Annual Capital Recovery Costs $0 $396,253 $676,347 $1,547,077

Annual O&M Costs $0 $234,768 (b)

$810,234 $1,852,189

Annual Cost of Control $0 $631,021 $1,486,581 $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 Costs

Baseline

Option 1: LNB, 

separated OFA

Option 2: SNCR Option 3: SCR

Annual NOx Emission (tpy) (a)

1,468.4 1,027.9 734.2 293.7

Percent Control from Baseline 0 30% 50% 80%

Annual NOx Reduction from Baseline (tpy) 0 440.5 734.2 1,174.7

Annual Cost of Control $0 $631,021 $1,486,581 $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 emissions based on 3 year average of actual NOx emissions from the boiler for calendar years 2001-2003

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

addressed in a comprehensive visibility analysis covering all three visibility impairing pollutants and 

associate control options. The visibility analysis follows the PM evaluation in this analysis.

SO2: INDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

General Chemical identified three technologies for controlling SO2 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 DFGD, 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. 
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There are two primary mechanisms to reduce SO2 from coal-fired boiler flue gas: adsorption and 

absorption. Adsorption control systems are designed to capture SO2 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. SO2 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 and when the sorbent has a high affinity for SO2.

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-products can be 

more expensive. SO2 control technologies identified by General Chemical are discussed below.

1. Wet flue gas desulfurization – WFGD removes SO2 through absorption by mass transfer as 

soluble SO2 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. SO2 diffuses from the flue gas into the scrubber water when the liquid contains less than 

the equilibrium concentration of the gaseous SO2. The rate of SO2 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 between the gas and the liquid solvent to 

allow diffusion of SO2. Once the SO2 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 chemical reaction prevents the SO2 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. SO2 removal efficiencies for wet scrubbers can be as high 

as 98%.

2. Lime 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 particulate control system. Water in the slurry evaporates, 

hydrolizing the SO2 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 exhaust 

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 dryers 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 SO2 because it requires less makeup water than 

WFGD is nearly as efficient. Removal efficiencies for spray dryer absorbers are in the range of 

70% to 95%.
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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. The dry 

powdered material is injected into the flue gas where SO2 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 usually requires less capital cost as the existing 

duct work can be used without significant modifications. However 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.

SO2: ELIMINATE 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 SO2 emissions would 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 installing 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 baghouse, General Chemical did not 

further evaluate DSI for the existing boilers.

Reduced sulfur alternative 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 existing fuel is low, ranging from 

0.42 to 0.51 percent sulfur. While coal blending is technically feasible, the reduction in SO2 emissions 

would be very minor. The cost per ton of SO2 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.

SO2: EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES

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

achievable emission rates for each one. Retrofitting the existing boilers with either SO2 control is 

difficult. Both technologies require sufficient space for the SO2 in the flue gas to react with injected

alkaline compounds. 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 retrofit 

limitations for each control technology. SDA was estimated to reduce SO2 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 particulates. A new stack is also included in the design of the SDA system. 

The lowest SO2 emission rate is achieved by installing WFGD. General Chemical estimates that 

installing WFGD could reduce SO2 emissions by 90%. Space limitations require a separate building and 

a new stack for the WFGD system. Emission rates for each of the SO2 control technologies discussed are 

shown in Table 7.
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Table 7: SO2 Emission Rates Per Boiler

Control Technology

Boiler C

Resulting SO2

Emission Rate 

(lb/MMBtu) / (lb/hr)

Boiler D

Resulting SO2

Emission Rate 

(lb/MMBtu) / (lb/hr)

Low Sulfur Coal 1.20

(a) / 641 1.20 (a) / 1056

SDA 0.24 (b) / 128 0.24

(b) / 211

WFGD 0.12 (b) / 64 0.12 (b) / 106

(a) Current 40 CFR part 60, subpart D limit

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

SO2: EVALUATE IMPACTS AND DOCUMENT RESULTS

General Chemical evaluated the economic, environmental, and energy impacts associated with the two

proposed SO2 control options for boilers C and D. Vendors‟ information was used to estimate the capital 

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 supplemental 

energy costs associated with the extended downtime for the boilers when the SO2 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 Economic Costs

Cost Baseline Option 1: SDA Option 2: WFGD

Control Equipment Capital Cost $0 $16,411,800 $32,122,500

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 $3,811,240 $4,439,310

Annual Cost of Control $0 $5,134,031 $7,028,384
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Table 9: Boiler C Environmental Costs

Baseline Option 1: SDA Option 2: WFGD

Annual SO2 Emission (tpy) (a)

1,991.1 398.2 199.1

Percent Control from Baseline 0 80% 90%

Annual SO2 Reduction from Baseline (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 $3,223 $9,515

(a) Annual baseline emissions based on 3 year average of actual SO2 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 $16,411,800 $32,122,500

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 Costs

Baseline Option 1: SDA Option 2: WFGD

Annual SO2 Emission (tpy) (a)

2,894.7 578.9 289.5

Percent Control from Baseline 0 80% 90%

Annual SO2 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 $2,224 $2,704

Incremental Cost per ton of Reduction N/A $2,224 $6,547

(a) Annual baseline emissions based on 3 year average of actual SO2 emissions from the boiler for calendar years 2001-2003

Step 5: Evaluate visibility impacts, for SO2 is addressed in a comprehensive visibility analysis covering 

all three visibility impairing pollutants and associate control options. The visibility analysis follows the 

PM evaluation in this analysis.
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PM10: STEPS 1-4 COMBINED

General Chemical addressed PM emissions through an abbreviated analysis. While there are several PM 

control technologies available 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 analysis. Previous visibility modeling analyses, including the BART analysis for FMC 

Wyoming Corporation‟s Westvaco 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 NOx and SO2. 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. The Division did not require General Chemical to perform additional 

visibility analyses for PM control options beyond the existing dry ESPs. Boilers C and D will continue to 

meet PM/PM10 emission limits in Operating Permit 3-1-123 of 50.0 lb/hr and 80.0 lb/hr, respectively.

VISIBILITY IMPROVEMENT DETERMINATION:

The fifth of five factors 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 conducted using 

current (baseline) emissions from the facility. The screening modeling, as well as more 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 Figure 1 below. Bridger WA is located approximately 120

kilometers (km) northeast of General Chemical and Fitzpatrick WA is located approximately 154 km 

northeast of the facility. 

Only those 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. Areas 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 application. 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

AP-6046 BART Application Analysis

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 Figure 1

-400 -300 -200 -100 0 100 200

LCC East (km)

General Chemical Green River Works and Class I Areas

-300

-200

-100

0

100

200

300

400

LCC North (km)

Billings

Casper

Lander

Pocatello

RockSpr

Sheridan

SLC

GenChem

Bridger WA

Fitzpatrick WA

 

SCREENING MODELING

To determine if the General Chemical Green 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 upper-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. Sources input to the 

modeling included the potential emissions (current operation) from two emission units at the Green River

facility, the coal-fired boilers GR-2-L (“Boiler C”) and GR-3-W (“Boiler D”). 
General Chemical Green River Works

AP-6046 BART Application Analysis

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Results of the modeling showed that the 98th percentile value for the change in visibility (delta deciview 

[Δdv]) was above 0.5 Δdv for Bridger WA for all three years of meteorology. As defined in EPA‟s final 

BART rule, a 98th percentile 0.5 Δdv 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)

98th

Percentile 

Value (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 results of the Division‟s screening modeling, General Chemical 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 modeling 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 distances 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 

dispersion 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 transport, transformation, and 

removal. 
General Chemical Green River Works

AP-6046 BART Application Analysis

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CALMET is a diagnostic wind model that develops hourly wind and temperature fields in a threedimensional, gridded modeling domain. Meteorological inputs to CALMET can include surface and 

upper-air observations from 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-dimensional 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 radius of influence for surface and upper-air stations. 

CALPUFF is a multi-layer, Lagrangian puff dispersion model. CALPUFF can be driven by the threedimensional wind fields developed by the CALMET model (refined mode), or by data from a single 

surface and upper-air station in a format consistent with the meteorological files 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-processing 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. CALPOST is a post-processing program that 

can read the CALPUFF (or POSTUTIL or CALSUM) 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 modeling 

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 required 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 the 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 spanned 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 meteorological 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

AP-6046 BART Application Analysis

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Key User-Defined CALMET Settings

Variable Description 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, 3400 

RMIN2 Minimum distance for extrapolation -1 

IPROG Use gridded 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) 25 
General Chemical Green River Works

AP-6046 BART Application Analysis

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-400 -300 -200 -100 0 100 200 300

LCC East (km)

CALMET Surface, Upper-Air, and Precipitation Stations

-300

-200

-100

0

100

200

300

400

LCC North (km)

BIL

CPR

CYS

LND

PIH

RKS

SHR

SLC

GenChem

Precipitation Station

Surface Station

Upper-Air Station
General 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 and 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 the 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) 

operations 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, particulate 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 NOx burners (LNB) and separated overfire air (SOFA): 30% reduction in NOx

Selective catalytic reduction (SCR): 80% reduction in NOx

Selective non-catalytic reduction (SNCR): 50% reduction in NOx

Wet flue gas desulfurization (WFGD): 90% reduction in SO2

Dry flue gas desulfurization (DFGD): 80% reduction in SO2
General Chemical Green River Works

AP-6046 BART Application Analysis

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Source Parameters and Emissions for the Baseline Scenario

Parameter

Baseline

Coal-Fired Boiler C 

(GR-2-L)

Coal-Fired Boiler D

(GR-3-W)

NOx Control – overfire air, low excess air

PM Control – “hot-side” ESP 

SO2 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

SO2 Emissions (lb/MMBtu) 1.2 1.2

SO2 Emissions (lb/hr) 640.8 1056.0

H2SO4 Emissions (lb/hr) 5.87 9.39

NOx Emissions (lb/MMBtu) 0.7 0.7

NOx 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

H2SO4 = 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

NOx = nitrogen oxides

PM = particulate matter

SO2 = sulfur dioxide
General Chemical Green River Works

AP-6046 BART Application Analysis

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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

CoalFired 

Boiler C 

(GR-2-L)

CoalFired 

Boiler D 

(GR-3-W)

CoalFired 

Boiler C 

(GR-2-L)

CoalFired 

Boiler D 

(GR-3-W)

CoalFired 

Boiler C 

(GR-2-L)

CoalFired 

Boiler D 

(GR-3-W)

CoalFired 

Boiler C 

(GR-2-L)

CoalFired 

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

SO2 Emissions (lb/hr) 641.0 1056.0 641.0 1056.0 641.0 1056.0 128.0 211.0

HS2O4 Emissions (lb/hr) 5.87 9.39 5.87 9.39 5.87 9.39 5.87 9.39

NOx 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

H2SO4 = sulfuric acid 

K = Kelvin

lb/hr = pounds per hour

LNB = low NOx burners

m = meters

m/s = meters per second

NOx = nitrogen oxides

PM = particulate matter

SNCR = selective non-catalytic reduction

SO2 = sulfur dioxide

SOFA = separated overfire air
General Chemical Green River Works

AP-6046 BART Application Analysis

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

Parameter

Control Option 5 Control Option 6 Control Option 7 Control Option 8

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

CoalFired 

Boiler C 

(GR-2-L)

CoalFired 

Boiler D 

(GR-3-W)

CoalFired 

Boiler C 

(GR-2-L)

CoalFired 

Boiler D 

(GR-3-W)

CoalFired 

Boiler C 

(GR-2-L)

CoalFired 

Boiler D 

(GR-3-W)

CoalFired 

Boiler C 

(GR-2-L)

CoalFired 

Boiler D 

(GR-3-W)

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

Stack Height (m) 79.24 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

SO2 Emissions (lb/hr) 64.0 106.0 64.0 106.0 128.0 211.0 128.0 211.0

HS2O4 Emissions (lb/hr) 5.87 9.39 5.87 9.39 5.87 9.39 5.87 9.39

NOx 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 44.44 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

H2SO4 = sulfuric acid 

K = Kelvin

lb/hr = pounds per hour

LNB = low NOx burners

m = meters

m/s = meters per second

NOx = nitrogen oxides

PM = particulate matter

SNCR = selective non-catalytic reduction

SO2 = sulfur dioxide

SOFA = separated overfire air

WFGD = wet flue gas desulfurization
General Chemical Green River Works

AP-6046 BART Application Analysis

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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

CoalFired 

Boiler C 

(GR-2-L)

CoalFired 

Boiler D 

(GR-3-W)

CoalFired 

Boiler C 

(GR-2-L)

CoalFired 

Boiler D 

(GR-3-W)

CoalFired 

Boiler C 

(GR-2-L)

CoalFired 

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

SO2 Emissions (lb/hr) 64.0 106.0 128.0 211.0 64.0 106.0

HS2O4 Emissions (lb/hr) 5.87 9.39 5.87 9.39 5.87 9.39

NOx 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

H2SO4 = sulfuric acid 

K = Kelvin

lb/hr = pounds per hour

LNB = low NOx burners

m = meters

m/s = meters per second

NOx = nitrogen oxides

PM = particulate matter

SNCR = selective non-catalytic reduction

SO2 = sulfur dioxide

WFGD = wet flue gas desulfurization
General Chemical Green River Works

AP-6046 BART Application Analysis

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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, natural 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 deciview values for each Class I area on 

an annual basis, but does not provide species concentration data for the 20% best background 

conditions. 

Species 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 guidance 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

AP-6046 BART Application Analysis

Page 24

Natural Background Aerosol Concentrations (μg/m3)

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-Processing Results

Baseline Conditions:

The results of the visibility modeling for both units combined are shown in the table below. For 

each year modeled, the 98th percentile result is greater than 0.5 Δdv at Bridger WA. For 

Fitzpatrick WA, the 98th percentile 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 most 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 

Percentile 

Value 

(Δdv)

Total

No. of 

Days > 

0.5 Δdv

98th

Percentile 

Value 

(Δdv)

Total

No. of 

Days > 

0.5 Δdv

98th

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

WA = 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 (Bridger WA), the impacts for that year were used for evaluating the control 

options.
General Chemical Green River Works

AP-6046 BART Application Analysis

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CALPUFF Visibility Modeling Results: BART Control Options

Class I Area

2001

98th Percentile 

Value (Δdv)

Total

No. of Days > 

0.5 Δdv

Control Option 1

Bridger WA 0.72 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

Fitzpatrick 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

Control 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 area
General Chemical Green River Works

AP-6046 BART Application Analysis

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BART DETERMINATION:

General Chemical‟s proposed BART control option, the installation of LNB with SOFA (Option 

1) results in a reduction of 0.12 Δdv in the 98th percentile result at Bridger WA as compared to 

the baseline condition for both units, and a reduction of 0.06 Δdv in the 98th percentile result at 

Fitzpatrick WA as compared to the baseline condition for both units. The individual 98th

percentile values for both boilers, 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 boilers 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 NOx burners with separated 

overfire air meeting a NOx 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 boilers. No additional controls are required by BART for 

PM/PM10 emissions from the two boilers and they will continue to meet a PM/PM10 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 DIOXIDE 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 SO2 emission rates from the 

application of SDA and WFGD of 0.24 lb/MMBtu and 0.12 lb/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 Chapter 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. Under 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 SOFA 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

AP-6046 BART Application Analysis

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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, Section 3 of the 

Wyoming Air Quality Standards and Regulations. Operating Permit 3-1-123 was issued for the 

facility on June 10, 2008. In accordance with Chapter 6, Section 3 of the Wyoming Air Quality 

Standards and Regulations (WAQSR), General Chemical will 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 Quality 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 the 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 descriptions 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 modify 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 Manager, 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.
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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 construction 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 low NOx burners with separated overfire air is installed, the owner or operator 

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 Chapter 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 maximum rate is achieved.

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

Boiler C

Upon installation of control equipment:

NOx: 0.49 lb/MMBtu and 263.0 lb/hr; 30-day rolling average

1,152.0 tpy

a. Limits shall apply during all operating periods.

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

low NOx 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.

Boiler D

Upon installation of control equipment:

NOx: 0.49 lb/MMBtu and 431.0 lb/hr; 30-day rolling average

1,887.8 tpy

a. Limits shall apply during all operating periods.

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

low NOx 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.
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9. Performance tests, required by Condition 7 of this permit, shall consist of the following:

Boilers C and D:

NOx Emissions – Compliance with the NOx 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 NOx 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 prior to testing. Results of the 

tests shall be submitted to this office within 45 days of completing the tests.

11. If the Western Backstop Sulfur Dioxide Trading Program 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).

12. 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 existing continuous monitoring systems as follows:

a. Exceedances of the NOx limits shall be defined as follows:

i. Any 30-day rolling average of NOx 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 NOx limit established in this 

permit. Valid data shall meet the requirements of WAQSR, Chapter 5, 

Section 2(j) and follow the compliance provisions and monitoring 

requirements of §60.48Da and §60.49Da. The 30-day average emission 

rate shall be calculated as the arithmetic average of 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, Chapter 5, Section 2(g) and 40 CFR part 

60, subpart D. All excess emissions shall be reported using the procedures and 

reporting format specified in WAQSR, Chapter 5, Section 2(g).

13. 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.
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14. General Chemical shall install low NOx burners with separated overfire air on boilers C 

and D, in accordance with the Division‟s BART determination, and conduct the initial 

performance tests required in Condition 9 no later than January 1, 2014.
Appendix A

Facility Location