IN THE MATTER OF A PERMIT APPLICATION (AP-6046) FROM GENERAL CHEMICAL

SODA ASH PARTNERS FOR A BEST AVAILABLE RETROFIT TECHNOLOGY (BART)

PERMIT FOR THE GREEN RIVER WORKS

DECISION

I. Introduction:

The Air Quality Division received a BART permit application from General Chemical Soda Ash Partners

(General Chemical) for the two coal-fired boilers that operate at their Green River Works in Sweetwater

County, Wyoming. Regulations governing the BART program have been established by the U.S. EPA in

40 CFR Part 51 - Appendix Y. As stated in the regulations, a source is eligible for BART if it belongs

within a particular group of stationary source categories, was not in operation prior to August 7, 1962,

was in existence on August 7, 1977, and has the potential to emit 250 tons per year (tpy) or more of any

visibility impairing air pollutant. Fossil fuel boilers with more than 250 million Btu (MMBtu) per hour

heat input are listed as an eligible source type. Boiler C, with a heat input of 534 million MMBtu, was

installed at the Green River Works in 1973. Boiler D, with a heat input of 880 MMBtu, was installed in

1975. Potential emissions from both boilers for two visibility impairing air pollutants, nitrogen oxides

(NOx) and sulfur dioxide (S02), exceed 250 tpy and therefore the units are eligible for BART.

The Division conducted an analysis of the BART permit application and on August 12, 2008, published

in the Rock Springs Daily Rocket-Miner a public notice and notice of public hearing of the proposed

intent to issue BART determinations. Copies ofthe BART applications and the Division's analysis were

placed in the Sweetwater County Clerk's office in Green River, Wyoming, in accordance with

regulations. A 30-day public notice period ran from August 12, 2008, to September 11, 2008, and a

public hearing was held on Thursday, September 11,2008, at 6 p.m. in Room 1302 at Western Wyoming

Community College, located at 2500 College Drive in Rock Springs, Wyoming.

To allow adequate opportunity for comment as specified under the Regional Haze Rule 40 CFR

51.308(i)(2), the public comment period was extended to October 20, 2008.

The Division received five (5) comment letters on the proposed permit during the public comment period:

1) a September 4,2008 letter from General Chemical; 2) a September 10,2008 letter from the Wyoming

Outdoor Council; 3) a September 15,2008 letter co-signed by the U.S. Fish and Wildlife Service (FWS)

and the National Park Service (NPS); 4) an October 17, 2008 letter with supplemental comments from the

Wyoming Outdoor Council; and 5) an October 17, 2008 letter from EPA Region 8. The Division

received one (1) comment letter on the proposed permit after the public comment period on November 7,

2008 from the USDA Forest Service. The USDA Forest Service comments were received after the close

ofthe 69-day public notice period that ran from August 12,2008 through October 20,2008. As such, the

Division cannot consider or respond to the comments in the final BART determination on this

application. The comments and the Division's responses are presented on the following pages.
General Chemical Soda Ash Partners

Decision Document, BART Permit Application, AP-6046

Page 2 of 15

ll. Analysis of Comments from General Chemical:

ILl Existing Overfire Air Can Achieve NOLLimits - General Chemical commented that the

-----~installation-of_low-NGxbumers-EbNB)-and-the-operation-ofexisting-overfire-air-(GFA)-equipmentc----

can achieve the proposed BART limit for NOx (0.49 lb/MMBtu). General Chemical states that

the installation ofseparated overfire air (SOFA) would not clearly improve the operation of either

boiler, and they request that the permit language be changed to read that a design "equivalent" to

SOFA is available as an option.

Response - After the close ofthe public comment period for General Chemical's BART

application, the Division requested that the company address NOx emission levels below the

proposed emission rate of0.49Ib/MMBtu. On December 15,2008, General Chemical submitted

a response to the Division's request. General Chemical analyzed emission levels of 0.32

Ib/MMBtu from the application of new LNB with existing OFA and 0.28Ib/MMBtu from the

application ofnew LNB with separated OFA. Updated cost information for the installation of

each technology and revised CALPUFF visibility modeling were also provided. The Division

revised the August 4, 2008 BART analysis to specifically address the lower NOx emission rates

analyzed by General Chemical, and the revised analysis is included as Appendix A to this

document.

Based on the additional information provided by General Chemical on the capabilities ofLNB

and the operation of existing OFA equipment, the Division will set the BART emission limit for

NOxfor both boilers at the facility to 0.32Ib/MMBtu (30-day rolling). The installation ofLNB

and the use ofthe existing overfrre air systems will be required to achieve and maintain this

emission level. The Division agrees that separated overfire air (SOFA) is not warranted as BART

due to the minimal improvement in visibility that was modeled for LNB/OFA vs. LNB/SOFA. A

comparison ofthe 3-year average 98th percentile modeling results shows that modeled visibility

improvement with the option ofnew LNB with existing OFA, as compared to baseline, is 0.27

~dv at Bridger WA. The addition of SOFA would only provide a modeled improvement of an

additional 0.03 ~dv at Bridger WA.

The Division will require that General Chemical install low NOx burners to accompany the

existing overfrre air on boilers C and D no later than December 31, 2011 for Boiler C and

December 31, 2012 for Boiler D.

IL2 Responsible Official - General Chemical requested that the responsible official be changed to

Randy T. Pitts, Plant Manager.

Response - The Division has changed the responsible official.

ID. Analysis of Comments from the Wyoming Outdoor Council:

IlL1 SCR Should Be Required as BART in Addition to LNB - The Wyoming Outdoor Council

commented that selective catalytic reduction (SCR) should be required as BART for the coalfired boilers to increase visibility improvement and because the Division did not impose specific

emission limits for particulate matter (PM) and S02.

Response - The Division's BART limits for NOx emissions from the coal-fired boilers were

based on several factors, including the modeled impact on visibility. The individual 98th
General Chemical Soda Ash Partners

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Page 3 of 15

percentile modeling result for each boiler with the proposed BART controls was less than a 0.5

delta deciview (~dv) 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-O~5-~dv-threshold-that-is-used-in-sereening-analyses-to-determine-if-sourees-eontribute~·~- ~~~

to visibility impairment.

Control Option A (LNB and existing OFA) was chosen as BART rather than Control Option 3

(SCR) not only because ofthe added costs associated with Option 3, but also because LNB/OFA

does not require non-air quality environmental mitigation for the use of chemical reagents and

because of the low level of modeled visibility improvement for Option 3. Option 3 provided a

predicted improvement in visibility at Bridger WA of only 0.04 dv, as compared to LNB/OFA

based on the modeled 98th percentile results.

BART limits for S02 will not be set because Wyoming is a §309 state participating in the

Regional S02 Milestone and Backstop Trading Program. §308(e)(2) provides States with the

option to implement or require participation in an emissions trading program or other alternative

measure rather than to require sources subject to BART to install, operate, and maintain

additional control technology to meet an established emission limit on a continuous basis.

However, the alternate program must achieve greater reasonable progress than would be

accomplished by installing BART. A demonstration that the alternate program can achieve

greater reasonable progress is prescribed by §308(e)(2)(i). Since the pollutant of concern is S02,

this demonstration has been performed under §309 as part of the state implementation plan.

§309(d)(4)(i) requires that the S02 milestones established under the plan " ..:must be shown to

provide for greater reasonable progress than would be achieved by application ofBART pursuant

to §51.308(e)(2)."

Emissions ofPM will continue to be controlled with the existing electrostatic precipitators (ESPs)

on each boiler, and PM emission limits will be set in the BART permit at a level of 0.09

Ib/MMBtu for each boiler.

III.2 Impacts Analysis in the Proposed Permit is too Limited - The Wyoming Outdoor Council

commented that the Division's analysis of the BART options for the Green River Works did not

fully consider all factors for a BART analysis, and that cost was the only driver in the BART

determination for NOx•

Response - The Division's BART determination for the Green River Works was not driven by a

single factor. After considering: (1) the costs of compliance, (2) the energy and non-air quality

environmental impacts of compliance, (3) any pollution equipment in use or in existence at the

source, (4) the remaining useful life ofthe source, and (5) the degree of improvement in visibility

(all five statutory factors) from each proposed control technology, the Division determined BART

for the Green River Works. The Division revised the August 4, 2008 BART analysis to address

lower NOx emission rates that were analyzed by General Chemical at the request ofthe Division

(See response to General Chemical comment II. 1 and Appendix A).

Control Option A (LNB/existing OFA) was chosen as BART rather than Control Option 2

(selective non-catalytic reduction [SNCRJ) or Control Option 3 (SCR) not only because of the

added costs associated with Options 2 and 3, but also because LNB/OFA does not require non-air

quality environmental mitigation for the use of chemical reagents and because ofthe low level of

modeled visibility improvement for Options 2 or 3.
General Chemical Soda Ash Partners

Decision Document, BART Permit Application, AP-6046

Page 4 of15

Based on the initial modeling submitted by the applicant and reviewed by the Division, Option 2

(SNCR) provided a predicted improvement in visibility at Bridger WA of only 0.08 dv for both

units combined compared to the modeled impact for the scenario that was modeled as Option 1

~~~tbNB/-S8FA)~ -8ption-3-E-SGR)-provided-a-predieted-improvement-in-visibility-at-Bridger-WA-of~~~~~

only 0.19 dv for both units combined as compared to LNB/SOFA. The NOx emission rate for

LNB/SOFA for that initial modeling was 0.49 lblMMBtu. After reviewing the comments

received on the proposed BART limits for the Green River Works, the Division requested that

General Chemical evaluate additional state-of-the-art control levels achievable through the

application of low NOx burners with the existing OFA. In a report submitted to the Division in

December of 2008, General Chemical stated that engineering reviews ofthe proposed LNB/OFA

system showed that NOx emissions could be reduced to 0.32 lblMMBtu. This lower emission

limit will be set as the BART limit for each ofthe two coal-fired boilers, as reflected in the [mal

section ofthis document.

III.3 Receptors Are Not Adequately Identified - The Wyoming Outdoor COlillcil commented that

the Division's analysis did not adequately identify the receptors that were used to model visibility

impacts at Class I areas.

Response - Latitude and longitude coordinates for Class I area receptors were taken from the

NPS Class I Receptors database and converted to the appropriate Lambert Conformal Conic

coordinates for input to the CALPUFF model. The Class I receptors contained in the NPS

database are recommended by the Federal Land Managers (FLM) for use in long-range transport

(e.g., CALPUFF) modeling of Class I areas. Receptor spacing for the modeled areas is

approximately 1.3 km in the east-west direction and approximately 1.8 km in the north-south

direction. The receptor configurations that were used for Bridger Wilderness Area (WA) and

Fitzpatrick WA are shown in the figures below. .
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Page 5 of15

Figure 1

tors for Brid er W A

BridgerWilderness

684 Receptors

USFS Boundary Source:

FS Nalional Coverage file: NRIS - AlP group

COlVallis,OR

August 27.2003

Source: http://www.nature.nps.gov/air/Maps/Receptors

I~-----------~----
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Page 6 of 15

Figure 2

Receptors for Fitzpatrick WA

• • • • • • • • • • •

+ • + • •

• • • • • + • • • • •

• • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • + • • • • • • • •

• • • • + • • • •

• • • • • • • + •

• • • • • • • • • • • • • • • • • + •

• •

• •

• •

• •

• •

• •

• •

• •

• •

• •

• •

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~~_. ~---~-~~-

FlzpalrickWiderness

316 Receptors

USFS Boundary Source:

FS National Coverage file: NRIS· ALP group

Corvallis. OR

.August 27. 2003

Source: http://www.nature.nps.gov/air/Maps/Receptors/index.cfm
General Chemical Soda Ash Partners

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lIlA Impacts Less Than 0.5 dv Should Not Be Deemed A Per Se Does Not Contribute SituationThe Wyoming Outdoor Council commented that a modeled level of 0.5 dv should not be used as

a threshold below which visibility impacts are deemed to be insignificant.

Response - The Division is comfortable using 0.5 dv as the threshold level to exempt a source

from BART or to deem modeled impacts as insignificant. EPA's Regional Haze Regulations and

Guidelines for Best Available Retrofit Technology (BART) Determinations (Appendix Y to 40

CFR part 51), suggest that 0.5 dv can represent the level at which a source "contributes" to

visibility impairment. This is also consistent with the rules which are being applied by most

states in the WRAP region. Further, the Division believes that the 0.5 deciview threshold is a

conservative value given that language in the Regional Haze Rule suggests that 1.0 dv is an

appropriate perceptibility threshold and recent literature suggests that the perceptibility threshold

is greater than 1.0 dv (from page 39120 ofAppendix Y to 40 CFR part 51).

IlLS Scaling Factors Used for Background Aerosol Concentrations Should be Explained And

Justified The Wyoming Outdoor Council commented that the process of determining

background aerosol concentrations for the 20% best visibility days was not explained in adequate

detail.

Response - Individual species concentrations corresponding to the 20% best days natural

background were calculated for each Class I area by scaling back the annual average natural

background concentrations given in Table 2-1 of the EPA doCiiment~Guidance for Estimating

Natural Visibility Conditions Under the Regional Haze Rule. The EPA guidance document

provides annual average values of natural background for individual species, and total deciview

values for the 20% best days for particular areas, but does not provide values for individual

species for the 20% best days. Therefore, the Division developed separate scaling factors for

each Class I area such that, when multiplied by the guidance table annual concentrations for each

species, the 20% best days concentrations for each species for that particular Class I area could be

calculated.

The scaling procedure is illustrated here for Bridger WA. From Appendix B in the EPA natural

visibility guidance document, the total deCiview value for the 20% best days at Bridger WA is

1.96 dv. To obtain the speciated background concentrations representative ofthe 20% best days,

the deciview value (1.96 dv) was first converted to light extinction. The relationship between

deciviews and light extinction is expressed as follows:

dv = lOin (bex!10) or bext = 10 exp (dv/1 0)

where: bext = light extinction expressed in inverse megameters (Mm-1

).

Using this relationship with the known deciview value of 1.96, one obtains an equivalent light

extinction value of 12.17 Mm-1

. Next, the annual average natural visibility concentrations were

set equal to a total extinction value of 12.17 Mm-1. The relationship between total light extinction

and the individual components ofthe light extinction is as follows:
General Chemical Soda Ash Partners

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Page 80f15

bexl = (3)f(RH)[ammonium sulfate] + (3)f(RH)[ammonium nitrate] + (0.6)[coarse mass] +

(4)[organic carbon] +(1)[soil] + (1 0)[elemental carbon] + bray

---------where:

• bracketed quantities represent background concentrations in J.lg/m3

• values in parenthesis represent scattering efficiencies

• f(RH) is the relative humidity adjustment factor (applied to hygroscopic species only)

• bray is light extinction due to Rayleigh scattering (10 Mm-I used for all Class I areas)

Substituting the total light extinction for the 20% best days, the annual average natural

background concentrations, the average f(RH) for Bridger WA, and including a coefficient for

scaling, one obtains:

12.17 = (3)(2.1)[0.12]X + (3)(2.1)[0.1]X + (0.6)[3.0]X + (4)[0.47]X + (1)[0.5]X + (10)[0.02]X +

10

In the equation above, X represents a scaling factor needed to convert the annual average natural

background concentrations to values representative of the 20% best days natural background.

Solving for X provides a value of 0.376. Table 1 presents the annual average natural background

concentrations, the calculated scaling factor, and the calculated background concentrations for the

20% best days natural background for Bridger WA.

Ta e hI 1 C I : a cultda e B k ac .!!roundComnonents or B"drI l!!er WA

Annual Average 20% Best Days

Natural Natural

Background for Calculated Background for

the West Region Scaling BridgerWA

Comnonent (11!!/m3

) Factor (l1IDm3

)

Ammonium Sulfate 0.12 0.376 0.045

Ammonium Nitrate 0.10 0.376 0.038

Organic Carbon 0.47 0.376 0.176

Elemental Carbon 0.02 0.376 0.008

Soil 0.50 0.376 0.188

Coarse Mass 3.00 0.376 1.127

Because of the geographical proximity and similar annual background visibility for the Bridger

WA and Fitzpatrick WA, the scaled aerosol concentrations for the two areas were averaged. The

20% best days natural background aerosol concentrations that were used for the two Class I areas

in question for this analysis are listed in Table 2 below.
General Chemical Soda Ash Partners

Decision Document, BART Permit Application, AP-6046

Page 9 of 15

I C centrations (J.1g1m3 ays Naura t IBack(l!roundAeroso on )

Fitzpatrick

Aerosol WA&

Component BrideerWA

Ammonium Sulfate 0.045

Ammonium Nitrate 0.038

Organic Carbon 0.178

Elemental Carbon 0.008

Soil 0.189

Coarse Mass 1.136

Table 2: 20% Best D

III.6 Combined Impacts from Three Trona Plants in Southwestern Wyoming - The Wyoming

Outdoor Council commented that the modeled impacts from three trona plants in southwestern

Wyoming should be considered in combination rather than individually. Modeled results for

individual facilities were summed in a table in their October 17,2008 letter.

Response - Summing the 98th percentile modeled visibility impacts for separate facilities is not

an accurate portrayal of combined impacts because the individual impacts may occur at different

locations (receptors) and during different 24-hour time periods. Moreover, the visibility impacts

from BART-eligible sources are to be determined separately. As stated in the EPA's Appendix Y

to part 40 CFR 51 - Guidelinesfor BART Determinations Under the Regional Haze Rule, relative

to the use of the CALPUFF model for BART determinations, "We believe that CALPUFF is an

appropriate application for States to use for the particular purposes ofthis rule, to determine if

an individual source is reasonably anticipated to cause or contribute to impairment of visibility

in Class I areas, and to predict the degree of visibility improvement which could reasonably be

anticipated to result from the use ofretrofit technology at an individual source. We encourage

States to use itfor these purposes."

IV. Analysis of Comments from the FWS (and NPS):

IV.1 New Stack for SNCR - The FWS commented that General Chemical's cost estimate for SNCR

included the cost for a new stack, and the FWS questioned the need for a new stack. .

Response - As described in General Chemical's BART application, space for emissions control

equipment is limited at the Green River Works. Flue gas exiting the boiler house passes through

ESPs for each boiler and then is routed to the stacks. There is very limited vertical distance

between the existing air heater and the intake to each electrostatic precipitator (ESP), prohibiting

the construction of ductwork/equipment between the air heater and the ESP. fustallation of

SNCR would therefore require the construction of new stacks.

IV.2 SOl-Scrubber Costs - The FWS commented that General Chemical inflated scrubber costs by

underestimating the effectiveness of the S02 scrubbing options and by overestimating operating

costs.

Response - Wyoming is a §309 state participating in the Regional S02 Milestone and Backstop

Trading Program, and therefore visibility impacts from S02 emissions will be reduced through an

emissions trading program rather than through requirements that BART sources install, operate,
General Chemical Soda Ash Partners

Decision Document, BART Permit Application, AP-6046

Page 10 of 15

and maintain additional control technology. The scrubber control effectiveness that was

evaluated by the applicant was reasonable because it was based on an assumption of continuous

compliance when the control equipment is well maintained and operated in a manner consistent

~-- ~~~-~~---with~good~airpoHution~control~practices~for-minimizing- emissions-.-In~order~to demonstrate~-- ~-- ~~

continuous compliance with a permit limit it is important to consider that even well maintained

and operated equipment will have some emissions variability. Complex emission control

equipment, such as wet scrubbers, generally has inherent variability that must be considered.

The Division is satisfied that the costs for S02 controls presented in the BART application are

adequate for the purposes ofthis analysis.

N.3 Combined Control Costs and Dollar per Deciview Metric - The FWS commented that

General Chemical combined the costs associated with controls for multiple pollutants when

drawing cost effectiveness determinations. The FWS offered some conclusions on the costeffectiveness ofNOx and S02 controls based on dollars per deciview ($/dv).

Response - The Division's cost effectiveness determinations were based on the costs associated

with the control of each visibility-reducing pollutant separately. Cost effectiveness was not

determined by the Division using a hybrid metric such as dollars per deciview. Several different

metrics can be considered when evaluating the cost-benefit relationships of different emission

control technologies. In 40 CFR part 51 Appendix Y, two metrics are specifically mentioned:

cost effectiveness and incremental cost effectiveness. Through the application of BACT, the

Division has extensive experience using cost effectiveness (i.e., dollars per ton of pollutant

removed) to evaluate different control technologies. Incremental cost effectiveness is also used

extensively by the Division when comparing emission controls under the BACT process. While

the BART and the BACT processes are not necessarily equivalent, control determinations from

either process are based on cost effectiveness and incremental cost effectiveness and are

indicative of the economic costs to control emissions. The $/dv metric can illustrate the control

cost and visibility improvement differences between control options, but it is not commonly used

to assess the overall effectiveness of pollution control equipment. When performing the

presumptive BART limits analyses for NOx and S02, EPA addressed cost effectiveness and

incremental cost effectiveness separately from visibility improvement. EPA did not use the $/dv

metric to compare control options. Visibility improvements from the application ofthe analyzed

control measures used to establish presumptive levels were addressed in a separate visibility

analysis.

The Division evaluated the amount of anticipated visibility improvement gained by the

application of additional emission control technology. The Division considered capital cost,

annual cost, cost effectiveness, and incremental cost effectiveness in the evaluation of each

proposed emission control.

NA Modeled Class I Areas - The FWS commented that the Division modeled visibility impacts at

the two closest Class I areas only (Bridger WA and Fitzpatrick WA). The FWS stated that the

FLM typically ask for modeling at all Class I areas within 300 kilometers (km) of a source.

Response - The distance for Class I area modeling is based largely on the size of a given source

and the source's potential to impact a given Class I area. While 300 km is generally recognized

as the maximum effective distance for the CALPUFF model, this does not dictate that all

CALPUFF analyses include each Class I area within 300 km. Only those Class I areas most

likely to be impacted by the Green River facility sources were modeled, as determined 1Jy
General Chemical Soda Ash Partners

Decision Document, BART Permit Application, AP-6046

Page 11 of 15

source/Class I area locations, distances to each Class I area, and professional judgment

considering meteorological and terrain factors. The Division recognizes that more distant Class I

areas may yield modeled impacts ofsome magnitude, but the Division is also satisfied that Class

~--~----- I-areas-at-a-greater-distance-and-in-directions-of-Iess-frequent-plume-transport-would-not--yield--~---­

modeled impacts greater than those yielded by the two Class I areas chosen for BART modeling.

The modeling results for the two chosen Class I areas allowed the Division to make an informed

decision on the effect on visibility from the various control options.

IV.5 Control Strategies Should Not be Dismissed Because ofPerceptibility - The FWS commented

that a threshold of perceptibility should not be used to interpret visibility modeling or to exclude a

given control strategy from consideration as BART. The FWS stated that the Division's

misinterpretation of the 0.5 dv threshold led to the Division proposing only combustion controls

rather than SNCR.

Response - The Division does recognize that the chosen control option for BART (LNB/overfrreair) brought the modeled impacts for each boiler to less than the 0.5 dv threshold at which a

source is considered to "contribute" to visibility impairment, but incremental differences between

control options were also considered (see response to Wyoming Outdoor Council comment III.2)

IV.6 S02 Controls - The FWS commented that the Bridger WA is not one of the Class I areas under

the Western Backstop Trading Program, and therefore "S02 controls of Section 309 sources

should be evaluated and documented as to the effects on the Section 308 areas."

Response - Wyoming, along with other 309 States in the WRAP region, evaluated the impact of

the 309 program on all Class I areas in the west, even though the requirement by rule was to

demonstrate improvement in Class I areas on the Colorado Plateau. The following table

summarizes WRAP modeling for sulfates, and shows that all Class I areas in and around

Wyoming sources are benefiting from the sulfur dioxide emission reductions instituted in the 309

program. Sulfate extinction levels show improvement on the 20% worst days and improvement

or at least no degradation on the 20% best days. Furthermore, the Regional Haze rule allows the

state to take full credit for strategies implemented under 309 when addressing Class I Areas away

from the Colorado Plateau (51.309(g)(4)(i».
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T bl 3 WRAP M d r f, S If E·

Represents 2018 Base Case WIthout S02 control strategIes

2Represents 2018 Preliminary Reasonable Progress with Regional S02 Strategies

a e : o e m2 or u ate xtmctlOn

Visibility - Sulfate Extinction Onh (Mm-1

)

20% Worst Visibility Days 20% Best Visibility Days

(Monthly Avera2e) . (Monthly Avera2e)

20181 20182 20182

Base Preliminary Preliminary

Case Reasonable 20181 Reasonable

(Base Progress Case Base Case Progress Case

Class I Area 18b) (PRP18) (Base 18b) (PRP18)

Bridger, WY 5.2 4.3 1.6 1.3 (Bridger W. and Fitzpatrick W.)

North Absaroka, WY

(North Absaroka W. and 4.8 4.5 1.1 1.1

Washakie W.)

Yellowstone, WY

(Yellowstone NP, Grand Teton 4.3 3.9 1.6 1.4

NP, and Teton W.)

Badlands, SD 17.8 16.0 3.5 3.1

Wind Cave, SD 13.0 12.1 2.7 2.5

Mount Zirkel, CO 4.6 4.1 1.4 1.3 (Mt. Zirkel W. and Rawah W.)

Rocky Mountain, CO 6.8 6.2 1.3 1.1

Gates ofthe Mountains, MT 5.3 5.1 1.0 1.0

ULBend,MT 9.7 9.6 1.8 1.7

Craters ofthe Moon, ill 5.8 5.5 1.5 1.5

Sawtooth, ill 3.0 2.8 1.2 1.1

Canyonlands, UT

(Canyonlands NP and Arches 5.4 4.8 2.1 1.9

NP)

Capitol Reef, UT 5.7 5.4 1.9 1.8 I
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N.? SNCR as BART in Addition to LNB/overfire air - The FWS commented that SNCR and Dry

FGD should be considered as BART because costs are reasonable.

-- -----~----~Response~See-responseto-WyomingOutdoor·-Council-comments-IU:-l-and-ill-;-2.

V. Analysis of Comments from EPA Region 8:

V.1 NO!..BART Control Option Selection - EPA Region 8 objected to the Division's use ofthe 0.5

dv threshold to deem a given control strategy as acceptable, and commented that regional haze

impacts should be considered cumulatively and not per individual source.

Response - See response to Wyoming Outdoor Council comments lIlA and 1II.6.

V.2 SOLControl - EPA Region 8 commented that the Division's Regional Haze SIP under the

Western Backstop Sulfur Dioxide Trading Program must demonstrate greater reasonable progress

than source~specific BART at all Class I areas, including Bridger WA and Fitzpatrick WA.

Suggestions for S02 control at the Green River Works in the event reasonable progress cannot be

demonstrated were provided.

Response - See response to FWS Comment N.6.

V.3 PM Analysis - EPA Region 8 commented that costs and impacts associated with PM controls

should be evaluated separately.

Response - The Division is satisfied that the existing PM controls (ESPs) at the Green River

Works represent BART, and PM emission limits will be set in the BART permit at a level of 0.09

IblMMBtu for each boiler. It is the experience ofthe Division that a potential upgrade from ESPs

would not be cost effective, and that modeled visibility impacts would not be affected to a

significant degree by reductions in PM emissions that would result from an upgrade from ESPs.
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Decision Document, BART Permit Application, AP-6046

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VI. Decision:

On the basis of comments received during the public comment period, an analysis ofthose comments, and

._.__.~ Tepresentations-madeby6eneral-8hemical;-the Bepartment-of-Environmental ~uality-has-determined-that-~--- ._-

the permit application filed by General Chemical complies with all applicable Wyoming Air Quality

Standards and Regulations and that a BART permit will be issued for the General Chemical Green River

Works. All ofthe conditions proposed in the Division's analysis will be included in the permit with the

following changes and additions (in bold):

6. Each time low NOx burners with seflamted overfire air is installed, the owner or operator shall

furnish the Administrator written notification of: (i) the anticipated date ofinitial 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) ofthe WAQSR.

7. [replace previous] PMlPMlO performance tests shall be conducted on boilers C and D no later

than 90 days after permit issuance. NOx performance tests shall be conducted on boilers C

and D within 30 days of achieving maximum design rate after installation of the low NOx

burners to accompany existing overfire air, but not later than 90 days following initial startup in accordance with Chapter 6, Section 2(j) of the WAQSR. 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. For each test, a

written report ofthe results shall be submitted and the operator shall provide 15 days prior

notice ofthe test date.

8. [replace previous] Effective upon startup of the unit with low NOx burners with overfire air

and completion of the initial performance tests required by Condition 7 of this permit, NOx

emissions shall not exceed the levels below. The PMlPMlO levels shall apply upon permit

issuance. The NOx and PMlPMlO limits shall apply during all operating periods.

Boiler C:

Filterable portIOn only

Pollutant IblMMBtu lb/hr tpy

NOx 0.32 (30-day rolling) 170.9 (30-day rolling) 748.5

PMlPM1O(1) 0.09 50 219.0 (I) •

Boiler D:

Filterable portIOn only

Pollutant IblMMBtu lb/hr tpy

NOx 0.32 (30-day rolling) 281.6 (30-day rolling) 1233.4

PMlPM1O(1) 0.09 80 350.4 (I) •

9. Performance tests, required by Condition 7 ofthis permit, shall consist ofthe following:

Boilers C and D:

Emissions - Compliance with the NOx 30-day rolling average shall be determined

using a continuous emissions monitoring system (CEMS) certified in accordance with 40
General Chemical Soda Ash Partners

Decision Document, BART Permit Application, AP-6046

Page 15 of 15

CFR part 60. Testing is required for boilers C and D after installation of low NOx burners

with separated overfire air.

-~~--~~. ~_·_--·--PMJPMfOEmissions-~-Testing-shall-follow-40-€FR-60046-and-EPA-Reference-'I'est~ ._~- ._-

Methods 1-4 and 5.

Testing required by the Chapter 6, Section 3, Operating Permit may be submitted to satisfy

the testing required by this condition.

10. Prior to any pel'formanee testing required by this permit, a test protocol shall be submitted to the

Division for approval, at least 30 days prior to testing. Notification should be provided to the

Division at least 15 days prior to any testing. Results of the tests shall be submitted to this

office within 45 days of completing the tests.

11. [replace previous] General Chemical shall comply with all requirements of the Regional S02

Milestone and Backstop Trading Program in accordance with Chapter 14, Sections 2 and 3,

ofthe WAQSR.

12. [add to previous] Testing for PM shall be conducted annually, or more frequently as

specified by the Administrator, following 40 CFR 60.46 and EPA Reference Test Methods

1-4 and 5. Testing required by the Chapter 6, Section 3, Operating Permit may be

submitted to satisfy the testing required by this condition.

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 December 31, 2011 for Boiler C and December 31, 2012

for Boiler D.

Dated this i h day ofAugust, 2009. r// v?~/;;V John V. Corra

Director

Wyoming Department ofEnvironmental Quality
APPENDIX A

Revised NOx BART Analysis
DEPARTMffiNTOFE~ONMENTALQUALITY

AIR QUALITY DIVISION

Revised NOx BART Analysis

AP-6046

August 7, 2009

- ----~-PURPOSE-OF~VISION-:~_._-.__.. ..- --_.----

After the close ofthe public comment period for General Chemical (Soda Ash) Partners' BART

application, AP-6046, the company was requested by the Division to address NOx emission levels

below the company-proposed emission rate of 0.49 Ib/MMBtu from both boilers. On December

15,2008, General Chemical submitted a response to the Air Quality Division's request. General

Chemical analyzed emission levels of 0.32 Ib/MMBtu from the application ofnew low NOx

burners (LNB) with existing overfire air (OFA) on the two boilers and 0.28 Ib/MMBtu from the

application ofnew LNB with separated OFA (SOFA) on the same units. Updated cost

information for the installation of each technology and revised CALPUFF visibility modeling

were also provided. The Division is revising the August 4,2008 BART analysis to specifically

address lower NOx emission rates analyzed by General Chemical.

DESCRIPTION OF BART ELIGffiLE SOURCES:

General Chemical Green River Works' two existing coal-fired boilers, Boilers C and D, are colocated 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. S02 emissions are controlled without the use of add-on

controls by burning low-sulfur coal.

(a) T bl 1 C I fi d B 'I C d D B r 0 f

Same baseline operatIOns as presented In the DlVlslOn Songmal BART analySIS

a e : oa - Ire OJ ers an ase me 'pera Ions

Operating Permit 3-1-123 Emission Limits

Firing Rate Existing NOx S02 PMlPMlO

Source (MMBtu/hour) Controls (lb/MMBtu) (lb/MMBtu) (lb/hr)

Boiler C 534 Overfire air, dry 0.7 1.2 50.0 ESP (3-hour rolling) (2-hour fixed)

Boiler D 880 Overfire air, dry 0.7 1.2 80.0 ESP (3-hour rolling) (2-hour fixed)

(aJ . . . , ..

CHAPTER 6, SECTION 9 - BEST AVAILABLE RETROFIT TECHNOLOGY (BART)

A BART determination is an emission limit based on the application of a continuous emission

reduction technology for a visibility impairing pollutant emitted by a source. It is " ... established,

on a case-by-case basis, taking into consideration the technology available, [1] the costs of

compliance, [2] the energy and non-air quality environmental impacts of compliance, [3] any

pollution equipment in use or in existence at the source, [4] the remaining useful life ofthe

source, and [5] the degree ofimprovement in visibility which may reasonably be anticipated to
General Chemical Green River Works

AP-6046 Revised NOx BART Analysis

Page 2

result from the use ofsuch technology."! A BART analysis is a comprehensive evaluation of

potential retrofit technologies with respect to the five criteria above. At the conclusion ofthe

BART analysis, a technology and corresponding emission limit is chosen for each pollutant for

-~~~-----each-unitsubject-t0-BAR-I'. ----~---- ------

Visibility control options presented in the application for each source were reviewed using the

methodology prescribed in 40 CFR 51 Appendix Y, as required in WAQSR Chapter 6 Section

9(c)(i). This methodology is comprised offive basic steps:

Step 1: Identify ale available retrofit control technologies

Step 2: Eliminate technically infeasible options

Step 3: Evaluate control effectiveness ofremaining control technologies

Step 4: Evaluate impacts and document the results

Step 5: Evaluate visibility impacts

The Division acknowledges that BART is intended to identify retrofit technology for existing

sources and is not the same as a top down analysis required for new sources under the Prevention

of Significant Deterioration (PSD) rules known as Best Available Control Technology (BACT).

Although BART is not the same as BACT, it is possible that BART may be equivalent to BACT

on a case-by-case basis.

In the original BART analysis for Boilers C and D at General Chemical's Green River Works, the

Division applied all five steps to each ofthe three identified visibility impairing pollutants

emitted from each coal-fired boiler thereby conducting a comprehensive BART analysis for NOx,

S02 and PM/PMIO• Based on the additional information submitted by General Chemical, a

revised comprehensive NOx BART analysis is provided.

NO!: IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

General Chemical identified four control technologies to control NOx emissions: (1) LNB with

existing OFA, (2) LNB with SOFA, (3) selective non-catalytic reduction (SNCR), and (4)

selective catalytic reduction (SCR). LNB with existing OFA and LNB with SOFA are two

combustion control technologies that reduce NOx emissions by controlling the combustion

process within the boiler. These two technologies effectively control NOx emissions by reducing

the amount of oxygen directly accessible to the fuel during combustion and by enhancing air-fuel

mixing above the main combustion zone located near the burners. SNCR and SCR are add-on

controls that provide a chemical conversion mechanism for NOx to form molecular nitrogen (N2)

in the flue gas after combustion occurs. These four technologies are proven emissions controls

commonly used on coal-fired boilers.

1 40 CFR Part 51 Appendix Y: Guidelines for BART Detenninations under the Regional Haze Rule (70 Federal Register

39163).

2 Footnote 12 of40 CFR 51 Appendix 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

AP-6046 Revised NOx BART Analysis

Page 3

1. Low NOx Burners with Existing Overfire Air - LNB technologies rely on a combination

offuel staging and combustion air control to suppress the formation ofthermal NOx'

Fuel staging occurs in the very beginning of combustion, where the pulverized coal is

~--~~----~-~injected-through the-burner-into-thefurnace.-CarefuLcontroLof-the-fuel..air-mixture-- --~~- --~

leaving the burner can limit the amount of oxygen available to the fuel during combustion

creating a fuel-rich zone that reduces the nitrogen to molecular nitrogen (N2) rather than

using oxygen in the combustion air to oxidize the nitrogen to NOx'

2. Low NOx Burners with Separated Overfire Air - SOFA can be used with LNB

technology to further control the combustion process inside the boiler. The addition of

separated overfire air provides additional NOx control by injecting air into the lower

temperature combustion zone, above the LNB, where thermal NOx is less likely to form.

This allows complete combustion ofthe fuel, or burnout, under more controlled

conditions.

3. 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 ofthe reagent and flue gas, and

prolonged retention time in place ofthe catalyst. SNCR operates at higher temperatures

than SCR. The effective temperature range for SNCR is 1,600 to 2,100°F. SNCR

systems are very sensitive to temperature changes and typically have lower NOx

emissions reduction (up to fifty or sixty percent) and may emit ammonia out ofthe

exhaust stack when too much ammonia is added to the system.

4. 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 1,1OO°F,

depending on the application and type of catalyst used. When catalyst temperatures are

not in the optimal range for the reduction 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. A well controlled SCR system

typically emits less ammonia than a comparable SNCR control system.

In addition to applying these control technologies separately, they can be combined to increase

overall NOx reduction. For example, the application of SCR on power plant boilers often

includes installing LNB with some form of advanced overfire air to reduce NOx emissions by

90% or more. General Chemical addressed the application of each control technology separately.

Proposed control efficiencies are based on feasible reductions reported in literature for each

technology.

NO!: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

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

infeasible. All four technologies are proven emission reduction technologies with several

examples of each in operation.
General Chemical Green River Works

AP-6046 Revised NOx BART Analysis

Page 4

NO!: EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES

The Division considers the control effectiveness of a proposed control technology to be

-- --- --equivalent-to-the BAR'I'-determined-permitlimit.--The-limit-is--based-on-continuous-compliance- -- - -

when the control equipment is well maintained and operated in a manner consistent with good air

pollution control practices for minimizing emissions. In order to demonstrate continuous

compliance with the permit limit it is important to consider that even well maintained and

operated equipment will have some emissions variability. Complex emission control equipment,

such as LNB with existing OFA, generally have inherent variability that must be considered when

establishing the limit. Otherwise, the source will be out of compliance even though the

equipment is operated and maintained as well as possible.

General Chemical noted in the original analysis that, while all four technologies are technically

feasible, space for emission control equipment is extremely limited. Post combustion add-on

controls, SNCR and SCR, require significant changes to the facility to accommodate the foot

print ofthe control, any ancillary equipment, and a new stack. Equipment costing for these

options include demolition costs and installing a new stack.

General Chemical noted in their December 15,2008, response that "[t]he level ofboiler work

required to install each ofthese systems varies significantly [LNB with existing OFA vs. LNB

with SOFA]. Installation ofLNB is a matter of changing the existing burners and replacing them

with burners with a different configuration in the same space. Installation ofLNB+SOFA

requires extensive modification ofthe boiler windbox where new air ports are installed, air supply

provided, and operator interface control provided." (Response to Commentfor the BART

Analysis-General Chemical Green River Works, pg. 3-1). Boiler modifications significantly

increase the time necessary to install LNB with SOFA and increase the amount oftime the unit is

shutdown.

General Chemical reviewed literature for each ofthe four emission control technologies and

determined achievable emission rates for each. General Chemical's December 15,2008 submittal

included revised emission reductions for LNB with existing OFA and LNB with SOFA. General

Chemical anticipates LNB with existing OFA can achieve a new emission rate of0.32lblMMBtu

on each boiler and the installation ofLNB with SOFA is anticipated to achieve a new emission

rate of 0.28 IblMMBtu. General Chemical was not requested to provide additional information

regarding the application of SNCR or SCR. The proposed emission reductions from the original

BART analysis are included in this analysis. Installing SNCR was determined to reduce NOx

emissions by 50%. Based on the permitted baseline value of 0.70 Ib/MMBtu, the resulting NOx

emission rate is 0.35 Ib/MMBtu for each boiler. Applying SCR to each ofthe boilers is

anticipated to reduced NOx emissions by 80%. Based on the permitted baseline value of 0.70

IblMMBtu, the resulting NOx emission rate is 0.14 IblMMBtu. Revised achievable emission rates

from the four proposed control technologies are shown in Table 2.
General Chemical Green River Works

AP-6046 Revised NOx BART Analysis

PageS

Table 2: Revised NOx Emission Rates Per Boiler

40 CFR part 60, subpart D lImit

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

Boiler C Boiler D

Resulting NOx Resulting NOx

-----_.._------------Emission-Rate--~-Emission-Rate--- -

Control Technology (lblMMBtu) / (lb/hr) (lblMMBtu) / (lb/hr)

Good Combustion Practices 0.70 (a) / 374.0 0.70 (a) / 616.0

LNB with existing OFA 0.32 (b) / 170.9 0.32 (b) / 281.6

LNB with SOFA 0.28 (b) / 149.5 0.28 (b) / 246.4

SNCR 0.35 (b) / 188.0 0.35 (b) / 308.0

SCR 0.14 (b) / 75.0 0.14 (b) /123.0

(a) ..

The above emission rates were used in the comprehensive visibility analysis, but not in the cost

analysis. Instead, a 3-year average of actual emissions from the BART baseline period, 2001-

2003, was used as the baseline emission rate. Reduction efficiencies for SNCR and SCR were

applied to the 3-year averaged baseline emission rate to calculate emission reductions. Emission

reductions for LNB with existing OFA and LNB with SOFA were calculated based on the

difference between the baseline emission rate and the achievable emission rate of either 0.32

lb/MMBtu or 0.28lblMMBtu, respectively.

NO!: EVALUATE IMPACTS AND DOCUMENT RESULTS

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

the four proposed control options for Boilers C and D. General Chemical contacted vendors for

information, but did not provide vendor quotes in the original application for equipment costs

associated with each proposed control option. A vendor quote was provided in the December 15,

2008 response for the capital costs ofinstalling LNB with existing OFA. Costs associated with

proposed 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 to site preparation and auxiliary

energy costs associated with generating additional steam to supplement lost steam production

when each ofthe 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 included in the revised application, as well as in the original application for the

installation of SNCR and SCR, to account for lost steam production as each ofthe units is

shutdown for modification. Makeup steam can be generated by Boiler E, a 490 MMBtu/hr

natural-gas fired boiler. However due to the size ofthe boiler, the plant will operate on reduced

steam demand when firing Boiler E. General Chemical included auxiliary energy costs, reported

as lost revenue in the costing analysis, for installing LNB with existing OFA and LNB with

SOFA in their December 15,2008 response. The same differential energy cost basis that was
General Chemical Green River Works

AP-6046 Revised NOx BART Analysis

Page 6

originally proposed for installation of SNCR and SCR, $8/MMBtu, was used to calculate energy

costs associated with the revised LNB options. However, the replacement energy cost included in

the economic costs for installing LNB with existing OFA was based on firing Boiler E for one

week($658,OOO~,~while-energy-cosLfoLtheinstallation-ofLNB~withSOEA-was-based-on_fI"V'e_~~ ~~---

weeks ($3,290,000). The Division notes that five weeks appears somewhat excessive when

compared to the reported two-week downtime and necessary firing ofBoiler E required for

installing SCR.

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 existing OFA and 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 the options including LNB.

Several different metrics can be considered when evaluating the cost-benefit relationships of

different emission control technologies. In 40 CFR part 51 Appendix Y two metrics are

specifically mentioned: cost effectiveness and incremental cost effectiveness. Through the

application ofBACT, the Division has extensive experience using cost effectiveness (i.e., dollars

per ton of pollutant removed) to evaluate different control technologies. Incremental cost

effectiveness is also used extensively by the Division when comparing emission controls under

the BACT process. While the BART and the BACT processes are not necessarily equivalent,

control determinations from either process are based on cost effectiveness and incremental cost

effectiveness and are indicative ofthe economic costs to control emissions. In addition to

providing cost effectiveness and incremental cost effectiveness results, General Chemical

provided cost information in terms of cost of applying emission controls and the level of visibility

improvement achieved (i.e., dollars per deciviews). While this metric can illustrate the control

cost and visibility improvement differences between control options, it is not commonly used to

assess the overall effectiveness of pollution control equipment. When performing the

presumptive BART limits analyses for NOx and S02, EPA addressed cost effectiveness and

incremental cost effectiveness separate from visibility improvement. EPA did not use the dollars

per deciview metric to compare control options. Visibility improvements from the application of

the analyzed control measures used to establish presumptive levels were addressed in a separate

visibility analysis. As discussed in the comprehensive visibility analysis presented later in this

analysis as Step 5: Evaluate visibility impacts, the Division evaluated the amount of anticipated

visibility improvement gained by the application of additional emission control technology. The

Division considered capital cost, annual cost, cost effectiveness, and incremental cost

effectiveness in the evaluation of each proposed NOx emission control. Economic and

environmental costs for additional NOx controls on Boilers C and D are summarized in Tables 3-

6.
General Chemical Green River Works

AP-6046 Revised NOx BART Analysis

Page 7

Table 3· Boiler C Economic Costs

CRF IS based on 7 Yo mterest over 20 years

(b) CRF is based on 7% interest over 30 years

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

.

Option 1: Option 2: Option 3: Option 4:

Cost Baseline LNBw/OFA LNBw/SOFA SNCR SCR

eontrol~Equipment-~-~- --- ~----_.~~--

-------- ~--_._--~-

-----------

Capital Cost $0 $1,121,750 $5,837,180 $7,541,800 $14,097,600

Capital Recovery Factor N/A 0.0944 (a) 0.0944 (a) 0.0806 (b) 0.0806 (b)

Annual Capital Recovery

Costs $0 $105,893 $551,030 $607,870 $1,136,267

Annual O&M Costs $0 $96,341 (0) $287,234 (0) $825,850 $1,298,542

Annual Cost ofControl $0 $202,234 $838,264 $1,433,720 $2,434,809

ta) o .

Table 4· Boiler C Environmental Costs

Annual baselme emiSSIOns based on 3 year average of actual NOx emiSSIOns from the boiler for calendar years 2001 2003

Option 1: Option 2: Option 3: Option 4:

Baseline LNBw/OFA LNBw/SOFA SNCR SCR

Annual NOx Emission (tpy) 1,167 (a) 748 655 584 233

Percent Control from Baseline 0 36% 44% 50% 80%

Annual NOx Reduction from Baseline (tpy) 0 419 512 584 934

Annual Cost of Control $0 $202,234 $838,264 $1,433,720 $2,434,809

Cost per ton ofReduction N/A $483 $1,637 $2,457 $2,608

Incremental Cost per ton ofReduction N/A $483 $6,839 $8,270 $2,860

ta) . . .. - -

Table 5· Boiler D Economic Costs

CRF IS based on 7 Yo mterest over 20 years

(h) CRF is based on 7% interest over 30 years

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

.

Option 1: Option 2: Option 3: Option 4:

Cost Baseline LNBw/OFA LNBw/SOFA SNCR SCR

Control Equipment

Capital Cost $0 $1,188,000 $7,487,600 $8,391,400 $19,194,500

Capital Recovery Factor N/A 0.0944 (a) 0.0944 (a) 0.0806 (b) 0.0806 (b)

Annual Capital Recovery

Costs $0 $112,147 $706,829 $676,347 $1,547,077

Annual O&M Costs $0 $98,461 (0) $340,048 (0) $810,234 $1,852,189

Annual Cost ofControl $0 $210,608 $1,046,877 $1,486,581 $3,399,266

(al o .
General Chemical Green River Works

AP-6046 Revised NO. BART Analysis

Page 8

Table 6· Boiler D Environmental Costs

Annual baselme emlSSlOns based on 3 year average of actual NOx emlSSlOns from the bOiler for calendar years 2001 2003

. Option 1: Option 2: Option 3: Option 4:

Baseline LNBw/OFA LNBw/SOFA SNCR SCR ~--- ~~-~---- ---- --- ----- ----~._--

Annual NOx Emission (tpy) 1,816 (a) 1,234 1,079 908 363

Percent Control from Baseline 0 32% 41% 50% 80%

Annual NOx Reduction from Baseline (tpy) 0 582 737 908 1,453

Annual Cost ofControl $0 $210,608 $1,046,877 $1,486,581 $3,399,266

Cost per ton ofReduction N/A $362 $1,420 $1,637 $2,340

Incremental Cost per ton ofReduction N/A $362 $5,395 $2,571 $3,510

ta) .. . . -

The Division considers the cost effectiveness and incremental cost effectiveness of all four

proposed NOx BART technologies are reasonable.

The final step in the NOx BART determination process for Boilers C and D, Step 5: Evaluate

visibility impacts, is addressed in a comprehensive visibility analysis covering all three visibility

impairing pollutants. The visibility analysis follows below. Tables on pages 9 and 10 list the

modeled control scenarios and associated emission rates.

VISIBILITY IMPROVEMENT DETERMINATION:

The fifth offive factors that must be considered for a BART determination analysis, as required

by 40 CFR part 51 - Appendix Y, is the degree ofClass 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. A detailed description ofthe

modeling setup and results for the initial BART submittal from General Chemical can be found in

the Division's August 4, 2008 BART analysis.

In response to comments received on the initial BART determinations for the facility, the

Division requested that General Chemical evaluate additional state-of-the-art control levels that

could be achieved for NOx emissions. General Chemical submitted additional modeling that

included evaluations of: 1) new LNB along with the existing OFA systems at a NOx emission rate

based on 0.32 Ib/MMBtu for each boiler, and 2) new LNB along with separated OFA with a NOx

emission rate based on 0.28 Ib/MMBtu for each boiler. The Division reviewed the modeling,

which consisted ofyear 2001 modeling for each ofthe two control options, and expanded the

modeling to include all three years of available meteorological data.

Table 7 presents the model inputs that were used to represent the baseline scenario for Boilers C

and D, and Table 8 presents the inputs that were used to model the additional control scenarios.
General Chemical Green River Works

AP-6046 Revised NOx BART Analysis

Page 9

Table 7: Source Parameters and Emissions for the Baseline Scenario

Baseline

Coal-Fired Boiler C Coal-Fired Boiler D ~~-----------~-

~(GR;;2;;-L) (GR;;-3;;-W)~--

NOx Control- overfire air, low excess air

Parameter PM Control- "hot-side" ESP

S02 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

S02 Emissions (lb/MMBtu) 1.2 1.2

S02 Emissions (lb/hr) 640.8 1056.0

H2S04 Emissions (lb/hr) 5.87 9.39

NOxEmissions (lb/MMBtu) 0.7 0.7

NOxEmissions (lb/hr) 374.0 616.0

PM Coarse Emissions (lb/hr) 27.77 44.44

PM Fine Emissions (lb/hr) 21.39 34.24

Elemental Carbon Emissions 0.82 1.32

(lb/hr)

Organic Carbon Emissions (lb/hr) 1.47 2.35

ESP = electrostatIc precipitator

H2S04 = sulfuric acid

K=Kelvin

lb/hr = pounds per hour

lb/MMBtu = pounds per million British thermal units

m/s = meters per second

MMBtu/hr = million British thermal units per hour

NOx = nitrogen oxides

PM = particulate matter

S02 = sulfur dioxide
General Chemical Green River Works

AP-6046 Revised NOx BART Analysis

Page 10

dE Add"f I M drS narios .. : ource p arameters an mISSIons or I JOna o e mg ce

---~ -----~--~ --~_..._----_..- -

Control Scenario A: Control Scenario B:

LNB wI Existing OFA LNBw/SOFA

Coal- Coal- Coal- CoalFired Fired Fired Fired

Boiler C Boiler D Boiler C Boiler D

Parameter (GR-2-L) (GR-3-W) (GR-2-L) (GR-3-W)

Base Elevation (m) 1928 1928 1928 1928

Stack Height (m) 47.55 47.55 47.55 47.55

Stack Diameter (m) 3.05 3.05 3.05 3.05

Stack Temperature (K) 452.6 460.9 452.6 460.9

Exit Velocity (mls) 15.98 25.12 15.98 25.12

S02 Emissions (Ib/hr) 641.0 1056.0 641.0 1056.0

H2S04 Emissions (lb/hr) 5.87 9.39 5.87 9.39

NOxEmissions (lb/hr) 171.0 282.0 149.5 246.4

PM Coarse Emissions

(lb/hr) 27.77 44.44 27.77 44.44

PM Fine Emissions

(lb/hr) 21.39 34.24 21.39 34.24

Elemental Carbon (lb/hr) 0.82 1.32 0.82 1.32

I Organic Emissions (lb/hr) 1.47 2.35 1.47 2.35

Table 8 S

H2S04 = sulfuric acid

K=Kelvin

lb/hr = pounds per hour

LNB =low NOxburners

m=meters

mls = meters per second

NOx= nitrogen oxides

OFA = overfire air

SOFA = separated overfire air

PM = particulate matter

S02=sulfur dioxide

Visibility Post-Processing Results

The results ofthe baseline 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 ~dv at Bridger WA.

For Fitzpatrick WA, the 98th percentile results equals or exceeds 0.5 ~dv for two ofthe three

years ofmeteorology.

Particulate (PM) emissions contributed very little to the modeled results. For example, the

percentage contribution from PM on days above 0.5 ~dv at Bridger WA was at most 3.5% and on

average 1.6% (2001 meteorology). Therefore, subsequent modeling ofthe various control

options did not consider any additional PM controls.

Table 10 presents a summary ofthe modeling results for the additional control scenarios.
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AP-6046 Revised NOx BART Analysis

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Adv = delta declVlew

WA = wilderness area

Table 9: CALPUFF Visibility Modeline Results - Baseline Conditions

2001 2002 2003

-~~~~-~-

98th Total 98th Total 98th Total ---------~ ----~~-~~~- -~--~--~--_.--~-_._--_.. ..

Percentile No. of Percentile No. of Percentile No. of

Value Days> Value Days> Value Days>

Class I Area (Adv) 0.5 Adv (Adv) 0.5 Adv (Adv) 0.5 Adv

BridgerWA 0.84 21 0.72 16 0.97 16

Fitzpatrick WA 0.50 8 0.47 7 0.59 10 ..

Table 10: CALPUFF Results for Baseline and Added Control Options

3-Year Averal!e

98th Total

Percentile No. of

Value Days>

Class I Area (Adv) 0.5 Adv

Baseline

BridgerWA 0.84 18

Fitzpatrick WA 0.52 8

Control Scenario A: New LNB and Existing OFA

BridgerWA 0.57 10

Fitzpatrick WA 0.32 3

Control Scenario B: New LNB/SOFA

BridgerWA 0.54 8

Fitzpatrick WA 0.31 3

LNB = low NOx burners

OFA = overfire air

SOFA =separated overfire air

A comparison ofthe3-year average 98th percentile modeling results for baseline, LNB/OFA, and

LNB/SOFA is shown in Figure 1 below. Modeled visibility improvement with the option of new

LNB with existing OFA, as compared to baseline, is 0.27 ~dv at Bridger WA. The addition of

SOFA would only provide a modeled improvement of an additional 0.03 ~dv at Bridger WA.
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Figure 1

CALPUFF Results for Baseline, LNB/OFA, and LNB/SOFA

• BridgerWA

• Fitzpatrick WA

Baseline lNB/OFA lNB/SOFA

0.000

0.200

v

t

a 0.400

d

__1_.00~l--___ I~_~_~~ ~~__

I

d 0.800 +-

e

0.600 1

3-Year Average 98th Percentile

BART CONCLUSION FOR NOx:

After reviewing the original information submitted by General Chemical and the December 15,

2008 response, and considering: (1) the costs of compliance, (2) the energy and non-air quality

environmental impacts of compliance, (3) any pollution equipment in use or in existence at the

source, (4) the remaining useful life ofthe source, and (5) the degree ofimprovement in visibility

(all five statutory factors) from each proposed control technology, the Division determined BART

for NOx emitted from the two boilers subject to BART at General Chemical's Green River

Works.

LNB with existing OFA is determined to be BART for Boilers C and D for NOx based, in part, on

the following conclusions:

1. LNB with existing OFA on Boiler C was cost effective with a capital cost of$I,121,750

and a $483 per ton ofNOx removed average cost effectiveness over a twenty year

operational life. LNB with existing OFA on Boiler D was cost effective with a capital

cost of$I,188,000 and a $362 per ton ofNOx removed average cost effectiveness over a

twenty year operational life.

2. Combustion control using LNB with existing OFA does not require non-air quality

environmental mitigation for the use of chemical reagents (i.e., ammonia or urea) and

there is a minimal energy impact.
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3. Visibility impacts were addressed in a comprehensive visibility analysis covering all

three visibility impairing pollutants and associated control options. Cumulative 3-year

averaged visibility improvement from the baseline summed across the two Class I areas

-------~~~-achieved-by- installing-LNB-with-existing-OFA-on-both-Boilers-C-and-D,-is-O.41-~d:v.~- ---~~ ---

4. Annual NOx emission reduction from installing LNB with existing OFA on the boilers

was 419 tons from Boiler C and 582 tons from Boiler D. Applying LNB with SOFA to

the boilers further reduced emissions by 93 tons from Boiler C and 155 tons from Boiler

D, which yield minimal visibility improvement across the two Class I areas.

LNB with separated OFA, SNCR, and SCR were not determined to be BART for Boilers C and D

for NOx based, in part, on the following conclusions:

I. The cost of compliance for installing LNB with SOFA on Boilers C and D is significantly

higher than LNB with existing OFA. Capital costs for installing LNB with SOFA on

Boiler C is $5,837,180 and $7,487,600 on Boiler D. Annual operating costs associated

with operating LNB with SOFA on Boiler C are $190,893 higher than the operating costs

for LNB with existing OFA. Annual operating costs for LNB with SOFA on Boiler D

are $241,587 higher than the operating costs for LNB with existing OFA.

2. Additional cumulative 3-year averaged visibility improvement across the two Class I

areas gained by installing LNB with SOFA instead ofLNB with existing OFA on both

Boilers C and D is just 0.04 ~dv.

3. The cost of compliance for installing SNCR on each boiler is higher than LNB with

existing OFA. Capital costs for SNCR on Boiler Cis $7,541,800 and $8,391,400 for

Boiler D. Annual operating cost for SNCR is $825,850 for Boiler C and $810,234 for

BoilerD.

4. The cost of compliance for installing SCR on each boiler is higher than LNB with

existing OFA. Capital costs for SCR on Boiler C is $14,097,600 and $19,194,500 for

Boiler D. Annual operating cost for SCR is $1,298,542 for Boiler C and $1,852,189 for

BoilerD.

5. Additional non-air quality environmental mitigation is required for the use of chemical

reagents when either SNCR or SCR is used to reduced NOx emissions from the boilers.

6. Operation of SNCR requires an estimated 50 kW of additional power to operate. SCR on

Boiler C requires 200 kW of additional power and Boiler D requires 300 kW.
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AP-6046 Revised NOx BART Analysis

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7. Visibility impacts from General Chemical's additional scenarios for LNB with existing

OFA and LNB with SOFA, which were proposed in the December 15, 2008 response,

were determined using the average ofthree modeled years, 2001-2003. Visibility

impactsforSNCR-and-SCR-weredeterminedusing the.2001modeled-year,-which

yielded the highest modeled impacts. Result indicate the application ofLNB with

existing OFA and LNB with SOFA yield lower visibility impacts than applying SNCR to

each ofthe boilers. Installing SCR on each ofthe boilers reduces visibility impacts

below the visibility impacts ofLNB with existing OFA in the Bridger Wilderness Area

by 0.04 ~dv.

The Division considers the installation and operation ofthe BART-determined NOx controls,

LNB with existing OFA, on Boilers C and D to meet the corresponding emission limits on a

continuous basis, to meet the statutory requirements ofBART. BART controls will be installed

on Boiler C by December 31,2011 and on Boiler D by December 31,2012.

Unit-by-unit NOx BART determinations:

Boiler C:

BoilerD:

LNB with existing OFA and meeting NOx emission limits of 0.32 Ib/MMBtu

(30-day rolling average), 170.9 lb/hr (30-day rolling average) and 748.5 tpyas

BART for NOx'

LNB with existing OFA and meeting NOx emission limits of 0.32 Ib/MMBtu

(30-day rolling average), 281.6Ib/hr (30-day rolling average) and 1,233.4 tpy as

BART for NOx'