Response to Request for Information 

Reasonable Progress 

For 

Montana Sulphur & Chemical Co 

Pursuant to: 

Section 114(A) of the Federal Clean Air Act 

[42 USC 7414(A)] 

Prepared for: 

Montana Sulphur & Chemical Co 

PO Box 31118 

Billings, MT 59107 

Prepared by: 

Montana Sulphur & Chemical Co. 

and 

Bison Engineering, Inc. 

1400 11th Avenue 

Helena, MT 59601 

406-442-5768 

www.bison-eng.com 

February 6, 2012
Montana Sulphur & Chemical Company Regional Haze Rule Section 114 Response 

Page ii 

TABLE OF CONTENTS 

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

1.1 Introduction ............................................................................................. 1-1

1.2 Regulatory Summary .............................................................................. 1-4

1.3 Selection of Reasonable Progress .......................................................... 1-5

1.4 Historical Perspective of Emission Reductions at MSCC ........................ 1-7

1.5 Selection of Emitting Units .................................................................... 1-11

1.6 Selection of Pollutants .......................................................................... 1-13

2.0 COSTS OF COMPLIANCE................................................................................ 2-1

2.1 MSCC Facility Description ...................................................................... 2-1

2.2 Emitting Unit and Control Information ..................................................... 2-2

2.3 Particulate Matter .................................................................................... 2-3

2.4 Sulfur Dioxide ......................................................................................... 2-4

2.4.1 Control Technologies Considered ........................................................... 2-4

2.4.2 Eliminating Technically Infeasible Options .............................................. 2-9

2.4.3 Technically Feasible Options ................................................................ 2-10

2.4.4 Cost-Effectiveness ................................................................................ 2-12

2.5 Nitrogen Oxides .................................................................................... 2-13

3.0 TIME NECESSARY FOR COMPLIANCE .......................................................... 3-1

3.1 Time Necessary for Compliance ............................................................. 3-1

3.1.1 Installation of SO2 Controls ..................................................................... 3-1

4.0 ENERGY AND NON-AIR QUALITY IMPACTS .................................................. 4-1

4.1 Energy Impacts: SO2 Controls ............................................................... 4-1

4.2 Non-Air Quality Impacts: SO2 Controls .................................................. 4-2

5.0 REMAINING USEFUL LIFE OF THE AFFECTED SOURCE ............................ 5-1

6.0 VISIBILITY MODELING RESULTS ................................................................... 6-1

6.1 Visibility Modeling Results ...................................................................... 6-1

7.0 ECONOMIC RESULTS AND IMPACTS TO VISIBILITY ................................... 7-1

8.0 SUMMARY ........................................................................................................ 8-1
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1.0 INTRODUCTION 

1.1 Introduction 

On January 6, 2012, Montana Sulphur & Chemical Company (MSCC) received a letter 

from the U.S. Environmental Protection Agency (EPA) requesting an analysis of control 

options for the Lockwood, Montana facility. The January letter invokes Section 114(a) of 

the Federal Clean Air Act.1

 The letter notes that in 2006, the Montana Department of 

Environmental Quality (MDEQ) withdrew its development of a state implementation plan 

(SIP) for regional haze under the Regional Haze Rule (RHR).2

 EPA also stated in the 

January letter that: “we believe that . . . emissions from . . . (MSCC) . . . warrant further 

analysis to determine whether additional controls should be considered.”3

 To that end, 

EPA requested that MSCC submit an analysis of control options for the plant.4 

More specifically, the January letter asks that the analysis “address the four factors 

included in 40 CFR §51.308(d)(1)(i)(A).” These factors are summarized in the January 6 

letter as: 

(1) The costs of compliance, 

(2) The time necessary for compliance, 

(3) The energy and non-air quality impacts of compliance, and 

(4) The remaining useful life of the potentially affected sources. 

This report and attached cover letter serve as MSCC’s response to EPA’s information 

request. 

The time allotted to conduct the requested analyses is extremely short. A few weeks are 

insufficient time to thoughtfully analyze equipment issues and control possibilities, much 

less for conducting an accurate analysis of costs or construction schedules. We believe 

we have done our best to be responsive to EPA’s request, but caution the agency that 

much of the work is based on (optimistic) generic review reports or data. It represents 

our best effort at approximating a cost, impact or timeline given the extremely short 

period provided for response. We have sought data from manufacturers or designers of 

 

1

 The letter was dated December 30, 2011, by EPA. The letter itself was mailed on or after January 3 and 

not received by MSCC until January 6, 2012. For purposes of consistency, this letter will be referenced as 

the January 6, 2012, letter since that is the date on which MSCC first became aware of EPA’s request. 

2

 The RHR is a reference to the visibility protection program outlined in 40 CFR 51.308. The entire 

visibility program, including RHR, is found in 40 CFR 51, Subpart P. 

3

 We note that while EPA states they believe an analysis is warranted, there was no justification provided 

to reach that conclusion. Regardless, MSCC is providing this response in good faith. We note that the 

results of the investigations in this document provide substantial evidence that no additional emission 

reductions from MSCC are necessary to carry out the purposes of the RHR. 

4

 The January letter was not specific as to which emitting units were to be addressed in the analysis. 

Based on later discussions with EPA staff, we have presumed that the analysis is to be directed toward

the emissions from the MSCC sulfur recovery plant (at the main stack EU3) since it represents the largest 

level of emissions (of those pollutants which could affect visibility) from the facility. 
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possible equipment, but the timeline does not allow consideration of all processes or 

site-specific cost or reliability estimates. No vendor or other source of information was 

able or willing to produce a quotation or performance guarantee, of course, in the short 

period allowed for response. 

MSCC and Bison, until January 6, 2012, were reasonably under the belief that the RHR 

program did not consider MSCC’s emissions as appropriate candidates for additional 

control under the reasonable progress (or any other) criteria. First, MSCC’s emissions 

(historical and current actuals) have been addressed and controlled by separate 

implementation plans, voluntary emission limitations, voluntary actions undertaken by 

MSCC, and by subsequent federal implementation plan actions. The majority of these 

emission controlling items occurred between 1998 and 2008. 

Second, as a whole, Montana emission inventory data clearly shows substantial and 

adequate reductions in potential and actual sulfur dioxide and nitrogen oxide emissions 

in the period since 1980. These reductions have resulted from voluntary source actions, 

implementation plans, major smelter and plant closures, new plant constructions, and 

numerous consent decrees. As an example, annual SO2 ambient concentrations in 

Billings have fallen over 95% since 1990. More notably, an 86% reduction in SO2

concentrations has been realized since 2002 alone (See Figure 1.1-1.). 

Similarly, emissions in Billings have been reduced by approximately 75% since the early 

1990s (See Figure 1.1-2). Emissions from MSCC have also dropped significantly during 

this same general period. MSCC emissions are found in Section 1.4 below. 

Figure 1.1-1: Billings Historical Ambient SO2 Concentrations 
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Figure 1.1-2: Historical SO2 Emissions 

Third, discussions with the agency as late as the fourth quarter of 2011 did not indicate 

a need for further information beyond that informally provided in those brief telephone 

discussions. 

The Billings area reductions clearly exceed those attained nationally. For example, 

Figure 1.1-3 shows EPA-sourced data for SO2 emissions since 1983, which show a 

decline of about 25% through 2002.5

 

5

Issues in Political Economy, Vol. 13, August 2004, Ludwig, citing EPA data.
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Figure 1.1-3: National Historical SO2 Emissions 

The above graphic also shows that the reduction in emissions nationally have not kept 

pace with the reductions by MSCC and the Billings area in general. For Montana as a 

whole, major losses of industries in the state (e.g. smelters) have drastically reduced 

emissions since the creation of the national goals on visibility. Montana has clearly 

reduced industrial emissions disproportionately, and any Montana plan should take this 

fact into account. 

Despite the emissions discussion above, we understand, based from agency staff that 

EPA is pressed by a consent decree deadline of its own,6 and believes it must act as 

quickly as possible. However, such constraint should not justify any hasty or unsuitable 

conclusions. 

1.2 Regulatory Summary 

As this request for information arises from the RHR we find it useful and prudent to 

review our understanding of the nature and purpose of the visibility protection program 

in order to ascertain important criteria that will lead to the selection of specific 

Reasonable Progress requirements. 

A visibility program aimed at attaining national visibility goals in mandatory Class I areas 

was authorized in Section 169A of the Clean Air Act. The national goals are to be 

attained by the year 2064, approximately 52 years from now. The rules which are to 

 

6

 Originally set for January, 2012, and then extended to March, 2012, as described by discussions with 

the agency. 
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implement this goal of protecting visibility are found at 40 CFR 51, Subpart P 

(subsections 300 through 309). A review of Subpart P indicates the purpose and goals 

of the program. The purposes of the program are outlined as follows: 

“The primary purposes of this subpart are . . .to assure reasonable 

progress toward meeting the national goal of preventing any future, and 

remedying any existing, impairment of visibility in mandatory Class I 

Federal areas which impairment results from manmade air pollution;. . .” 

[40 CFR 51.300(a)].

The visibility program may then be thought of as the implementation of two subprograms. One regards new source review (NSR, PSD, etc.) and the other addresses 

“regional haze.” Regional haze may further be broken down into the best available 

retrofit technology (BART) program7

 and the Reasonable Progress program. The 

underlying reason stated for EPA’s January 6 letter to MSCC is to address the 

Reasonable Progress portion of visibility protection. 

In that regard, the RHR [§308(d)] outlines what it refers to as: “the core requirements” 

for the implementation of the regional haze goals. More specifically, §308(d)(1) states: 

“For each mandatory Class I Federal area . . ., the State must establish 

goals . . . that provide for reasonable progress towards achieving natural 

visibility conditions. The reasonable progress goals must provide for 

an improvement in visibility for the most impaired days. .” [40 CFR 

51.308(d)(1)]. 

The rules go on to provide the states (EPA in this case) with a list of what must be 

considered in developing reasonable progress. Among these details are the “four 

factors” analysis that is outlined above in Section 1.1 and in the January 6 letter. 

1.3 Selection of Reasonable Progress 

For Montana, EPA is tasked to establish (a plan for) Reasonable Progress in carrying 

out the visibility protection. Section 1.2 outlines the purpose of the program along with 

core elements. To that end, EPA states it has asked for “an analysis of control options”

which will, we assume, be evaluated by EPA for applicability in establishing a set of 

specific reasonable Montana control strategies that create “reasonable progress” toward 

the 2064 goals. 

The January 6 request for a review of “control options” notwithstanding, it seems to us 

that the visibility program itself and the reasonable progress portion of that program is 

clear as to intent. That is, the purpose of the program is to protect visibility (by, over 

time, remedying, and preventing man-made impairments) in mandatory Class I areas as 

to the effects of human activities. Reasonable Progress expresses the notion that states 

must have implementation plans to approach the national goal by 2064 along a ‘glide-

 

7

 Applicable to certain sources built between 1962 and 1976. 
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path’ of improvements to visibility, with certain exceptions. Based on the language 

contained in the rule,8

 it is also clear that any activity, remedy or control (proposed or 

otherwise) that does not reasonably “improve visibility” in a mandatory Class I area is 

not a reasonable candidate for those “reasonable progress” goals.9

 

As a result, we believe an analysis that only considers one or more emission control 

options is not sufficient for inclusion into reasonable progress mandates unless those 

emission controls are expected to improve actual visibility in a Class I area in a 

discernible manner. It is neither necessary nor appropriate to include an emission 

control as part of a reasonable progress goal or plan without reasonable expectation of 

a resulting improvement in regional haze arising from the application of the control (i.e., 

a discernible improvement in deciviews in a Class I area). (The deciview metric is briefly 

explained below.)10

 

To that end, we have chosen to not only analyze various control “options” using the four 

factor test outlined in the January 6 letter, we have also conducted a brief analysis of 

any modeled impacts this facility may have on the nearest mandatory Class I areas. 

This was accomplished to determine if either the current configuration or future control 

options would fulfill the underlying need of the program to “provide for an 

improvement in visibility”

11 at a mandatory Class I area. 

We note that we have seen no measured evidence of any impact by MSCC’s operations 

on the visibility in any mandatory Class I airshed. We are peripherally aware that some 

efforts in the past decade have attempted to delineate, via computer modeling 

assumptions, potential visibility impacts of selected human emission sources at nearby 

mandatory Class I areas. For example, relative to the BART program, analyses have 

been conducted for the PPL-Montana J.E. Corette coal-fired plant that is a few miles 

from MSCC. (For reference, this coal-fired facility typically has higher emissions of SO2

and NOx than MSCC). The results of that modeling indicate a visibility impact of only 

about 0.7 deciviews (dv). This 0.7dv impact is less than that deemed as discernible. 

The above notwithstanding, the visibility impact of MSCC as traditionally operated or as 

to any of the control options, via dispersion modeling presumptions, has been analyzed 

by Bison Engineering for inclusion in this reply. The modeling and analysis results are 

 

8

 The language in 40 CFR 51.300(d)(1), among other examples, make it clear that these “reasonable 

progress” goals must indeed result in an actual improvement in visibility; not just a reduction in emissions. 

The language states: “The reasonable progress goals must provide for an improvement in visibility. . .” 

[§300(d)(1)]. 

9

 Ibid. 

10 The definition of a deciview is as follows: Deciview haze index=10 lne(bext/10 Mm-1). This is taken from 

the definitions found in 40 CFR 51.301. There are, of course, numerous articles and explanations for the 

deciview metric. One article may be found in the publication “IMPROVE,” Volume 2, No. 1, April 1993 

which was written by Pitchford and Malm, 1993. From a non-mathematical point of view, the change in 

deciview of “1” is intended to represent a “just noticeable change” (or sometimes referred to as ‘just

discernible’) in visibility regardless of the baseline visibility. 

11 40 CFR 51.308(d)(1). 
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presented in subsequent sections of this document. The reader is referred to those 

sections for details on the analysis method and the results of those investigations. 

1.4 Historical Perspective of Emission Reductions at MSCC 

This response to EPA’s request would not be complete without consideration of current 

and past emission reductions and controls that have occurred at MSCC. In the period 

since the authorizing legislation for the program was passed (1977),12 numerous 

changes have occurred (not only at MSCC, but many other nearby facilities as well). 

MSCC reasonably believes that it has made substantial emission reductions from its 

facility, both as to “actual” and “potential” emissions. Any suggestion or conclusion that 

further reductions or controls are necessary and appropriate for improvement to 

regional haze is not warranted. A short summary is in order. 

MSCC was established in 1955 as a facility to capture sulfur from fuel gases and acid 

gases. This sulfur was previously and traditionally burned as fuel without recovery 

resulting in tens of thousands of tons of sulfur dioxide emissions annually in the area. 

As a pioneer facility, MSCC’s plant operations also immediately reduced area emissions 

by tens of thousands of tons annually. MSCC’s facility also produces sulfur products, 

including fertilizer and soil-amending materials, with its sulfur recovery processes and 

clean fuel gases in its fuel gas scrubbing plant. 

Fuel gases are scrubbed of hydrogen sulfide in an amine unit. Cleaned fuel gases are 

returned to their owner for combustion or sale. The concentrated sulfur gases recovered 

are designated “acid gases.” Other acid gases are also received for processing and 

mingled with those recovered in the fuel gas scrubber operation. The acid gases feed 

into the sulfur recovery equipment where they are reacted with oxygen from the air in a 

thermal/catalytic system consisting of multiple reaction furnaces/boilers and multiple 

catalytic reaction stages. The result of these processes is to produce elemental sulfur 

and water vapor, along with some side-reaction products. Elemental sulfur is separated 

from the gas stream by condensation in multiple stages. The use of such multiple 

stages allows the reversible “Claus” reaction to be driven toward completion. About 92% 

to 95% of the incoming sulfur in these particular gases is recoverable in this manner. 

This is known as the modified “Claus/Chance” process.13 14 Unrecovered sulfur and 

compounds from the plant were, in the 1950s and 1960s, typically vented through the 

 

12 The Visibility Protection program was originally contained in the Clean Air Act Amendments of 1977 in

Section 169A. 

13 MSCC also historically has processed acid gases to produce other products such as liquefied hydrogen 

sulfide. These materials were stored and shipped in large tonnages and used in numerous industries, 

including the nuclear power industry and the production of “heavy water” for the US nuclear weapons 

industry. However, the national goal of reducing or eliminating domestic inventory of highly hazardous

substances such as H2S has led to the cessation of sale of these materials by MSCC, which withdrew 

completely from supplying that market earlier in this past decade.

14 AP-42 contains a description of this process. This information may be found at: 

http://www.epa.gov/ttn/chief/ap42/ch08/final/c08s13.pdf 
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smoke stack,15 as a semi-opaque plume consisting of sulfur aerosol particulate, SO2, 

H2S, water vapor, carbon oxides and nitrogen, as was normal for the time period. 

In anticipation of state regulation related to opacity and visibility, these “tail gas” 

materials were next subjected to tail-gas oxidation or incineration. This tail-gas 

treatment process became established in its present form in about 1967 at MSCC. 

MSCC uses a selective oxidation catalyst in the presence of excess air and elevated 

temperature to convert particulate sulfur and reduced sulfur compounds in the tail-gas 

to sulfur dioxide gas which is both transparent and also (relatively) odorless. 

In 1990, EPA contracted with E.H. Pechan and Associates to inventory both ‘actual’ and 

‘potential-to-emit’ (PTE) SO2 emissions in the Billings, Montana, area. This governmentinitiated, -directed, and -funded study included emissions from MSCC as well as several 

other local industries. MSCC cooperated with Pechan in developing this inventory. 

Pechan concluded that as of 1989 for MSCC’s SRU, sulfur dioxide emissions were: 

1989 Actuals: 3,450 tons/year 

Potential to Emit: 12,200 tons/year16

By comparison, MSCC’s SRU actual emissions were 1,376 tons in 2010. Thus, actual 

emissions have dropped from the 1989 study period by over 60%. Historical annual 

emissions are also shown as a graph later in this section. 

In 1998, MSCC became subject to an annual emission limitation of SO2 at its main 

stack of 4,544 tons per year.17 Thus, “potential to emit” dropped by 73% from 1989

potential to emit values. In December of that same year, MSCC voluntarily installed a 

SuperClausTM unit at the facility to assist in meeting shorter-term emission limitations, 

also established in 1998. This unit processes tail gas from the Claus plant and 

significantly reduced actual emissions. The unit, in effect, is an additional emissions 

control device for the facility. 

It is interesting to note that while MSCC’s allowable emissions were 4,544 tons per year 

in1998, its actual emissions the prior year were 4,058.18 In 1999, the first full year of 

SuperClausTM operation, MSCC’s actual emissions were reduced to 1,137 tons/year, a 

72% reduction. A graphical representation of annual emissions is found later in this 

section. 

 

15 These emissions were routinely emitted through the 100-foot stack (EU4) during this period. 

16 These values represent the SRU unit only. Actual and PTE emissions from the boilers and flares were 

(and continue to be) much less than the SRU. As an example, PTE emissions from the boilers were, at 

the time of the Pechan report, 18 tons/year while the flares were 271 tons/year. 

17 This was the “Stipulation” limit adopted by the Montana Board of Environmental Review in 1998. EPA 

eventually adopted the same limit in their FIP which is found in 40 CFR 52.1392(g). 

18 The emissions for 1998 were 3,626 tons per year. However, 1986 includes partial operation of the new 

SuperClausTM unit. The first full year of operation of the SuperClausTM yielded in a 69% reduction in 

emissions from the 1998 year. 
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In May 2002, EPA found the 1998 SIP revision limitations “inadequate” to protect 

NAAQS under modeling criteria.19 EPA then empowered itself to impose additional 

restrictions on MSCC. Those restrictions became ‘final’ on April 21, 2008 (73 FR 21418) 

in 40 CFR 52.1392.20

 

Like all processes, SuperClausTM processing must occasionally be interrupted, for 

example, for repairs and catalyst work. In such cases MSCC’s emissions would again 

necessarily return to pre-1998 levels, if processing normal loads. In 2007 MSCC 

undertook to increase the on-line reliability of SuperClausTM processing by installing a 

second SuperClausTM unit in parallel with the 1998 unit.21 This provides a great level of 

redundancy for enhanced SuperClausTM processing, so that sulfur and fuel gas 

processing can continue during periods of repair and maintenance on either (but not 

both) of the SuperClausTM process trains. 

Shortly thereafter, MSCC also ramped up the reliability of incinerator processing for 

opacity control, with a second selective oxidation incinerator operating in parallel with 

the 1967 unit.22 This provides a great level of redundancy for this processing, so that 

sulfur and fuel gas processing can continue, with incineration, even during periods of 

repair and maintenance on either (but not both) incineration trains. 

In 2008, as part of the FIP,23 MSCC’s flare emissions during startup, shutdown, and 

malfunction (SSM) events also became regulated and limited to 150 pounds per 3-hour 

period (this is equivalent to 219 tons/year). This enforceable limitation represented a 

substantial reduction from the prior emissions presented in the EPA PECHAN study.24

 

Actual emissions since the FIP was promulgated, including SSM emissions, were: 

2009: 0.2 tons/year 

2010: 6.5 tons/year 

To aid the reader in understanding the depth of the changes in emissions from the 

Billings area and MSCC in particular, the following figure shows historical emissions 

from the industrial facilities. 

 

19 May 2, 2002, at 67 FR 22168. 

20 This became EPA’s final action regarding the Montana FIP for Billings-Laurel area SO2. 

21 Montana DEQ approved the installation of the second SuperClausTM unit (and a redundant selective 

oxidizer incinerator) on March 1, 2007. 

22 Ibid. 

23 40 CFR 52.1392(g). 

24 “Development of a Sulfur Dioxide Emissions Inventory for Billings and Laurel, Montana – Volume 6 – 

Montana Sulphur & Chemical Company Sulfur Recovery Plant,” EPA Contract 68-02-4400, EPA Region 

VIII. 
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Figure 1.4-1: MSCC Historical Emissions 

If, solely for purposes of argument, MSCC’s relatively small past emissions of 3,500+ 

tons per year are deemed to have created a significant (discernible) visibility impact on 

a mandatory Class I area, the plant changes and control options outlined above clearly 

have led to a large reduction in those emissions. By inference, if the prior emissions are 

deemed significant to visibility, then those same emission reductions might necessarily 

be deemed to represent reasonable progress toward a goal for the year 2064 

established by 40 CFR 51.308(d)(1)(i)(B). That would be so if these prior MSCC 

emissions were known to be creating a significant impact on visibility. If, on the other 

hand, there is no data and no finding that MSCC’s past emissions were creating 

significant visibility impact, then the reductions made since 1998 [SIP and second 

SuperClausTM (2006)] could not have amounted to reasonable progress toward the 

national visibility goal and, of course, any further future reductions, control options, or 

changes also could not amount to reasonable progress toward natural visibility in a 

Class I area. 

A modeling study, summarized in Appendix B, addresses this question more directly. 

The modeling supports a conclusion that MSCC’s present emissions, and even MSCC’s 

past emissions rates which were significantly higher, were and are not significantly 

impacting regional haze visibility in Class I areas. Accordingly, any further “control 

option” considered herein also cannot significantly impact visibility improvements or be 

justified as reasonable progress. 
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1.5 Selection of Emitting Units 

On January 13, 2012, Hal Robbins of Bison Engineering, Inc. (Bison) called Vanessa 

Hinkle, EPA Region 8, at the request of MSCC management, to discuss and clarify 

various requirements in the January 6 letter. During the discussion, it was clarified that 

the sulfur recovery process, which vents through the main 100m stack (EU3), would be 

the emitting unit subject to analysis. This process and its related stack is the 

preponderant source of SO2 from the facility. All other emitting units at MSCC constitute 

a tiny fraction of potential visibility-related pollutants (see discussion below for the 

selection of pollutants for further analysis) relating to SO2, NOx and particulate matter. 

In order to lend some specifics to the justification of only selecting the SRU, the 

following discussion is offered. 

MSCC’s operating permit (OP211-04) lists 25 emitting units. A cursory review indicates 

that most of the units do not warrant further attention. Those units include: 
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Unit Name Comment 

EU1 Monaca – Sulfur Vaporization 

Heater 

This is a small natural gas-fired unit. 

It has not operated for many years. 

It is rated at less than 5 mmBtu/hr. 

EU2 Monaca – Steam Methane 

Superheater Same comment as above. 

EU3 100 Meter SRU Stack 

This is the primary stack through 

which the SRU equipment 

(including the incinerators) vents. 

The SRU itself will be the subject of 

this Reasonable Progress analysis. 

EU4 30 Meter Stack This is a stack and is not, by itself, 

the subject of an analysis. 

EU5 Railroad Boiler 

This is an older primarily gas-fired 

boiler. It has a small capacity and 

has not operated for many years. 

The function of the unit was 

effectively replaced by the 17 

MMBTU/hr boiler (EU10). 

EU6 through EU9 H-1 through H1-2 Boilers 

These multipurpose boilers are 

almost exclusively used as an 

integral part of the Claus plant 

(SRU). These emissions will be 

analyzed as part of the SRU 

analysis to follow. They 

occasionally may vent separately as 

a small capacity gas-fired boiler, but 

this is not a common event, and 

emissions from such gas-firing are 

de minimis in any event. 

EU10 17 MMBTU/hr Boiler 

This is a gas-fired boiler. It 

combusts natural gas or sweetened 

refinery fuel gas. Its SO2 emissions 

are minimal. 

EU11 through EU14 Flares 

These flares are operated 

intermittently. In addition they have 

been the subject of extensive 

federal and state regulation since 

1998. 

EU15 Hydrogen Plant 

This is a natural gas or sweetened 

refinery fuel gas-fired device of 

small potential emissions. It is not in 

use. 

EU16 through EU25 

These sources include H2S 

compression, molten sulfur 

storage and load-out, sulfur 

handling, valves and pumps, 

and fugitive emissions 

(access roads). 

These units do not emit significant 

quantities of SO2 and/or do not or 

have not operated for some time. 
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As a result of a review of the table above, the emissions information for these units, and 

the January 13 discussion with EPA staff, only the SRU equipment is a candidate for a 

Reasonable Progress analysis. The other units are not considered since they emit only 

minimal quantities of SO2 and NOx (primarily as a result of the combustion of natural 

gas or sweetened refinery fuel gas). Absent evidence to the contrary, it is reasonable to 

conclude that small emissions units cannot reasonably impact regional haze at distant 

areas, and control options, if any, for such sources cannot reasonably contribute to 

“reasonable progress” toward any mandatory Class I visibility goal. 

1.6 Selection of Pollutants 

During the January 13, 2012, phone call with EPA, it was also clarified that only sulfur 

dioxide (as to this source) would likely bear any potential relationship as to Reasonable 

Progress. The other potential visibility-affecting pollutants are small in volume at MSCC 

and in general those pollutants do not relate to the SRU. However, it was agreed to 

provide some justification to that conclusion for the record. 

To begin, one must first identify which pollutants typically are believed by EPA to 

participate in the degradation of visibility (regional haze) when arising from sources far 

removed from the mandatory Class I area of interest. 

The January 6 letter suggests that we (MSCC) refer to the Best Available Retrofit 

Technology (BART) Guidelines which are found in 40 CFR 51, Appendix Y. A review of 

the Guideline yields the following comment. 

What pollutants should I address? 

Visibility-impairing pollutants include the following: 

(1) Sulfur dioxide (SO2), 

(2) Nitrogen oxides (NOX), and 

(3) Particulate matter.25

Using this guideline, then the pollutants of interest will be SO2, NOx and particulate 

matter (PM). From this we must now deduce which of these visibility pollutants should 

be the subject of further investigation in Section 2 below. 

To make the analysis more complete, a table has been prepared which compares 

(recent) emissions from not only the SRU stack, but some of the other (smaller) emitting 

units of the three pollutants above. The emissions are presented based on the actual 

emissions from calendar year 2010. This year was chosen since it is the most recent 

year with complete inventory data. Calendar years before 2010 are similar in nature. 

Those prior year values would not lead to a different conclusion regarding which units or 

pollutants to select for analysis. 

 

25 This language is taken from Page 598 of the July 1, 2010 version of the CFR found in: 

http://edocket.access.gpo.gov/cfr_2010/julqtr/pdf/40cfr51AppY.pdf 
Montana Sulphur & Chemical Company Regional Haze Rule Section 114 Response 

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Figure 1.6-1: 2010 Actual Emissions (Tons/year) 

Emitting Unit Description SO2 NOx PM10

EU1 Monaca – Sulfur Vaporization Heater 0 0 0 

EU2 Monaca – Steam Methane 

Superheater 0 0 0 

EU3 100 Meter SRU Stack 1,376 3 1 

EU4 30 Meter Stack 0 0 0 

EU5 Railroad Boiler 0 0 0 

EU10 17 MMBTU/hr Boiler < 1 1 < 1 

EU12 – 14 Flares (all) 6 < 1 < 1 

EU15 Hydrogen Plant 0 0 

The results shown above indicate that the amount of NOx and PM10 emitted from the 

facility is small, that it is small relative to SO2, and that SO2 is “major” only as to the 

SRU main stack EU3. As a result, no control technology analyses will be made for these 

pollutants, or for emission units other than EU3. The remainder of this document will 

address SO2 from the SRU. 

 
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2.0 COSTS OF COMPLIANCE 

This section of the RHR Section 114 response will describe some estimated “costs of 

compliance,” presumably to meet the reasonable progress goals and strategies of the 

RHR. EPA has requested that MSCC provide the “costs of compliance.”26 The term 

“costs of compliance” is vague in the regulation since it is not clear what standard of 

compliance is to be met in which a particular cost must be incurred. 

For example, a hypothetical facility may need to meet an applicable NSPS emission 

limit.27 From such a limit, one may begin to determine and then analyze what equipment 

and operating parameters may be necessary to meet the limit for the hypothetical plant. 

As a result, the “cost of compliance” may ultimately be ascertained. Since there is no 

particular numerical emission value to be met under this program, or under the 

reasonable progress criteria, the “costs of compliance” are undefined and such costs 

cannot be determined by MSCC or any other person. 

Nonetheless, we have interpreted this request for control option analysis to be a review 

of some “available” (additional) controls known to MSCC that could further reduce SO2

emissions. As noted elsewhere in this document, it is assumed that such reduction has 

a cause/effect relationship to regional haze at mandatory Class 1 areas. Based on the 

January 13 conversation with EPA, we have surmised that SCOT-type processing in 

particular was to be considered. 

2.1 MSCC Facility Description 

Before discussing control options, it is appropriate to provide the reader with a brief 

description of MSCC’s facility and the current emission control system. 

As discussed above, the MSCC facility has been in existence at its Billings-area location 

since 1955. The facility processes various hydrogen sulfide-laden streams from a 

nearby refinery. The facility is able to take raw (sour) refinery fuel gas and clean the gas 

of most of the sulfur compounds creating a ‘sweetened’ fuel gas for the refinery. In 

addition to the fuel gas, MSCC processes other sulfur-bearing streams (sour water 

stripper overhead, acid gases, and recovered flare gases, for example) from the 

refinery. 

MSCC then takes these (recovered) sulfur compounds and/or streams and creates 

primarily elemental sulfur. The small fraction of unrecoverable sulfur is vented to the 

100 meter stack (in almost all cases) as SO2. As discussed above, these emissions of 

SO2 are presently limited under the FIP to 2,983 pounds per three-hours which, after 

2008, results in an effective annual limitation of no more than 4,355 tons per year. Prior 

permit limits (post-1998) were set at 4,544 tons per year. As indicated in the E.H. 

 

26 This term is found in 40 CFR 51.308(d)(i)(A). 

27 This discussion is purely hypothetical for purposes of making a point. There is no NSPS limit that is

applicable to this facility for a number of reasons. In addition, the sulfur recovery operation at MSCC predates the NSR regulations as well as BART. 
Montana Sulphur & Chemical Company Regional Haze Rule Section 114 Response 

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Pechan (1989) study, permissible emissions (not actual) at 1989-1990 were about 

12,200 tons per year. Significant progress has therefore been made in reducing 

permissible emissions since 1990. 

The basic form of the sulfur dioxide control system at the sulfur recovery plant may be 

thought of as three components: 

a) Claus, 

b) SuperClausTM, and 

c) Tailgas oxidizer. 

The Claus process is the first step and is responsible for the vast majority of sulfur 

recovery and collection. The SuperClausTM is an additional device28 that further 

removes primarily H2S and sulfur mist from the stream. Finally, the tailgas oxidizer 

converts the few remaining sulfur compounds (such as H2S and other reduced 

compounds) and remaining sulfur vapors to SO2 prior to being exited from the stack. 

Section 1.4 provides more complete description and history of the facility. The reader is 

referred to that section for further discussion. 

2.2 Emitting Unit and Control Information 

Emissions from the sulfur recovery process and other sources are vented to 

atmosphere using the 100-meter stack. The stack handles emissions from the sulfur 

recovery plant (including the Claus plant, SuperClausTM and incinerator units) and may 

also handle minor gas combustion emissions from several small gas-fired boilers such 

as the 17-mmBtu/hour boiler (EU10) and the H-boilers. 

The sulfur recovery process is a combination of equipment including but not limited to 

four “H” boiler units,29 five Claus Sulfur Reactor systems including their associated 

multi-fuel process re-heaters, process gas coolers, barometric seal legs, which normally 

vent ultimately to the associated tail gas oxidation heaters and oxidation reactor 

equipment with optional waste heat recovery. Both the original and the newer redundant 

tail gas oxidizer (incinerator) permissibly may operate either catalytically or noncatalytically. The five Claus reactors are generally configured in a three-stage operation, 

but were designed for and may be configured in two-stage operation; for example, 

during reactor maintenance, and are designed to operate as a combined single train or 

as dual parallel trains by means of by-pass ducting and alternative ducting to allow 

maintenance and operational flexibility over a wide range of operating loads. At reduced 

loads, the unit has also been configured as a four-stage Claus plant. Individual reactors 

and the associated stage equipment may be taken on or off line to allow 

repairs/maintenance on each stage while operations of the Claus process then resume 

while the equipment is isolated. This is normally accomplished by brief shutdowns to 

 

28 There are two redundant (parallel) SuperClausTM units. 

29 The H-Boiler units are small reaction boilers that are, in most circumstances, an integral part of the 

“Claus” operation, but which may also be used as fuel gas-fired steam generators. 
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swing blinds on alternative duct routes. Feed gas is flared as necessary during these 

brief and infrequent shutdowns. 

Claus process reheaters are dual-fueled, meaning that the re-heat energy is provided 

by either low sulfur fuel gas or process acid gas. Normally these are fired by process 

acid gases; the reheater gases join the main Claus process gases at each stage for 

further processing. 

The Claus process is capable of converting hydrogen sulfide-rich gases into elemental 

sulfur by means of partial oxidation and catalytic oxidation-reduction of sulfur dioxide 

and hydrogen sulfide. The process also is capable of converting other sulfur-containing 

materials (e.g., carbonyl sulfide, carbon disulfide, mercaptans, sulfuric acid, and others) 

to elemental sulfur in conjunction with hydrogen sulfide-rich feed gases. It is capable of 

handling small concentrations of volatile ammonia compounds in the acid gas feed. 

The Claus process is enclosed and pressurized to minimize fugitive emissions and 

vents presently to the 100-meter stack. Historically, it vented to a 30-meter stack along 

with the above-mentioned H units. The Claus process is rated at 252 long tons (2240 

pounds = 1 long ton) per day of elemental sulfur production.30

2.3 Particulate Matter 

Particulate matter generated by the Sulphur Recover Equipment and emitted from the 

100m stack is minimal. Below is a summary of MSCC’s PM and PM10 emissions 

inventory31 from 2009 and 2010: 

Table 2.2-1: 2008–2009 PM and PM10 Emission Rates 

Year PM

(tpy) 

PM10

(tpy) 

2009 1.15 1.15 

2010 1.07 0.83 

Based on experience, conducting a cost analysis for additional controls to an emitting 

unit with such low emissions would show that adding particulate control would be 

prohibitively expensive with no discernible improvement to visibility impacts. Therefore, 

we conclude that PM is being controlled to a level that satisfies the RP goals of the RHR 

and no further cost analysis is warranted. Please see the Visibility Modeling Results in 

Section 6.0 of this report which support this conclusion. 

 

30 “Development of a Sulfur Dioxide Emissions Inventory for Billings and Laurel, Montana – Volume 6 – 

Montana Sulphur & Chemical Company Sulfur Recovery Plant,” EPA Contract 68-02-4400, EPA Region 

VIII. 

31 Emissions estimates from Montana Department of Environmental Quality annual emission inventories. 
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2.4 Sulfur Dioxide 

Several techniques can, in theory, be used to generally reduce SO2 emissions from 

SRUs. SO2 control options typically can include traditional post-combustion controls 

(e.g., wet scrubbers, dry scrubbers, etc.), tail gas treating units (TGTU) such as the 

Shell Claus Off-gas Treating Process (SCOTTM) which rely on reduction, or TGTUs 

such as SuperClausTM or Wellman Lord relying on oxidation, and/or extending the Claus 

reaction into a lower temperature liquid phase (discussed below). 

MSCC currently controls SO2 emissions using the Claus and SuperClausTM processes 

(see Section 1), and controls odors and opacity via incineration. 

2.4.1 Control Technologies Considered 

AP-42 Chapter 8.13 Sulfur Recovery identifies two general types of control technologies 

to reduce SO2 emissions from Claus Plants32: 

1. Extend the Claus reaction into a lower temperature liquid phase 

2. Tail Gas “Scrubbing” 

The third listed technology at AP-42, incineration, is not discussed further because it is 

used to reduce H2S emissions and visible emissions in the tail gas by converting these 

to SO2. Hence, this technology does not reduce SO2 emissions as part of this analysis. 

SuperClausTM technology does not extend the Claus reaction at lower temperature, 

instead reaching a similar product result by means of “selective catalytic oxidation of 

H2S.” The net result is production of sulfur and water vapor from H2S, just as with the 

forward direction of the Claus reaction. The selective oxidation reaction is relatively 

irreversible compared to the Claus reaction, which is highly reversible at process 

temperatures. SuperClausTM technology is reported to result in up to to ~99% overall 

recovery when used after a typical three-stage or four-stage Claus system,33 with 

somewhat lesser recoveries expected following shorter or atypical Claus configurations. 

SuperClausTM technology was selected by MSCC in 1997 as the most appropriate 

retrofit technology for this pioneer34 facility. As seen from Figure 1.4-1, the results were 

a substantial reduction in annual facility SO2 emissions following application of 

SuperClausTM processing. SuperClausTM is is widely used, and well recognized 

technology, worldwide. 

Extend the Claus Reaction into a Lower Temperature Liquid Phase 

This technique reduces sulfur dioxide emissions by lowering the temperature in 

downstream Claus catalytic stages and extending the Claus reaction. Five common 

 

32 AP-42 Chapter 8.13 Sulfur Recovery also identified incineration as an H2S control technology. 

http://www.epa.gov/ttn/chief/ap42/ch08/final/c08s13.pdf 

33 Jacobs Comprimo Sulfur Solutions. Link: http://www.jacobs.com/products.aspx?id=6292 

34 MSCC believes this facility to be the longest continuously running sulfur recovery plant in North 

America, if not the world, at this time. 
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processes that extend the Claus reaction include Sulfreen®, BSR/selectox, Cold Bed 

Absorption, Maxisulf, and the IFP-1 process. These processes are variously reported 

(but not guaranteed) to result in 9835 to 99.536 percent sulfur recovery when used after a 

typical two- or three-stage Claus SRU. AP-42 Chapter 8.13 Sulfur Recovery reports, “All 

of these processes give overall sulfur recoveries of 98 to 99 percent when installed 

downstream of a typical two- or three-stage Claus sulfur recovery unit, and therefore 

emit lower sulfur emissions [than normal Claus].”37 As such, we conclude they have 

potential recoveries similar to those being attained or attainable, on similar typical 

plants, using SuperClausTM technology. As noted, SuperClausTM is employed as a 

retrofit technology at MSCC since 1998. 

Tail Gas Scrubbing 

Two types of tail gas scrubber technologies are predominant at Claus SRUs: oxidation 

and reduction tail gas scrubbers. 

Oxidation tail gas scrubbers remove SO2 from the post-incinerator flue gas. SO2 is 

concentrated and recycled back into the Claus SRU where it is converted to elemental 

sulfur. The Wellman-Lord scrubber system is the typically cited oxidation tail gas 

scrubber on Claus SRUs.38 These systems, however, appear to be rarely, if ever, in use 

on SRUs in the United States. 

The Wellman-Lord (W-L) scrubber uses sodium sulfite (Na2SO3) and sodium bisulfite 

(NaHSO3) to react with SO2 gas from the Claus incinerator to from bisulfite. The 

incinerator gases must be cooled and quenched before scrubbing, subjected to misting 

after scrubbing, and reheated afterwards. The bisulfite solution is regenerated to sodium 

sulfite in a steam-energized evaporator. The concentrated wet SO2 gas stream from the 

evaporator is partially condensed and some of the liquid water is used to dissolve sulfite 

crystals. The remaining enriched SO2 gas stream is recycled back to the Claus plant 

and used to recover additional sulfur by reaction with the incoming hydrogen sulfide. 

Claimed advantages of the W-L process include that it does not typically result in 

scaling or plugging and that it produces sulfur for incremental sales. Disadvantages 

include higher operating costs, sensitivity to components in the gas (particulates, HCl, 

and SO3), metals attrition, and the requirement of a purge system to remove solids and 

chlorides.39 Excess acid water must also be disposed of. W-L scrubber systems are 

 

35 AP-42 Chapter 8.13 Sulfur Recovery also identified incineration as an H2S control technology. 

http://www.epa.gov/ttn/chief/ap42/ch08/final/c08s13.pdf 

36 Concawe Cost and Cost-Effectiveness Assessment of Abatement Technology/Techniques For 

Refineries. http://www.citepa.org/forums/egtei/5-White-refineries.pdf 

37 AP-42 Chapter 8.13 Sulfur Recovery also identified incineration as an H2S control technology. 

http://www.epa.gov/ttn/chief/ap42/ch08/final/c08s13.pdf 

38 Another might be “ClausMasterTM” which is based on different chemistry. 

39 Estimating Costs of Air Pollution Control, 1990, William M. Vatavuk, p 197. 
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complex and can also require significant area to construct, especially in retrofit 

applications.40

 

The reduction scrubber processes first require a hydrogenation step to convert sulfur, 

SO2, and reduced compounds in the tailgas to H2S. The tail gas must be pre-heated to 

reaction temperature, which varies with the catalyst employed. Preheat consumes fuel 

or steam energy. All sulfur compounds in the SRU tailgas besides H2S (e.g., SO2, COS, 

CS2, and elemental sulfur) are reduced to H2S in this step by using a catalyst and a 

reducing gas, such as hydrogen or water-gas. 

The hot reduced tailgas is then cooled and quenched, removing a sour water waste, 

and gaseous moist H2S is then sent to the scrubber for contact with a selective amine. 

The amine must reject carbon dioxide effectively. H2S is removed from the gas by 

amine equipment for regeneration in a separate regeneration stage, where the H2S gas 

is then cooled and processed (again) in the Claus process. The produced sour water 

(which necessarily arises from cooling the Claus tail-gas below its dew point for wet 

scrubbing) must also be processed in separate units, requiring substantial energy and 

capital. The cooled, scrubbed tail gas is typically reheated again and incinerated before 

discharge. Variants on this processing scheme are believed to be the most typically 

used in U.S. refinery sulfur plants built since 1976. 

Other traditional flue gas desulfurization (FGD) technologies were considered as part of 

this analysis. For a variety of reasons, these do not appear to be applied to sulfur 

recovery plants. These technologies include: 

• Wet lime scrubbers, 

• Wet limestone scrubbers, 

• Dual alkali wet scrubbers, 

• Spray dry absorbers, 

• Dry sorbent injection, 

• Circulating dry scrubber. 

Wet Lime Scrubber 

The wet lime scrubbing process uses alkaline slurry made by adding lime (CaO) to 

water. The lime must be produced in a fired kiln either on or off site, from limestone. The 

alkaline slurry is sprayed into the exhaust stream and reacts with the SO2 in the flue 

gas. Insoluble calcium sulfite (CaSO3) and calcium sulfate (CaSO4) salts are formed in 

 

40 Summary Report, Sulfur Oxides Control Technology Series: Flue Gas Desulfurization; Wellman-Lord 

Process. EPA National Service Center for Environmental Publications, 

http://nepis.epa.gov/Exe/ZyNET.exe/30004EB1.TXT?ZyActionD=ZyDocument&Client=EPA&Index=1976

+Thru+1980&Docs=&Query=&Time=&EndTime=&SearchMethod=1&TocRestrict=n&Toc=&TocEntry=&Q

Field=&QFieldYear=&QFieldMonth=&QFieldDay=&IntQFieldOp=0&ExtQFieldOp=0&XmlQuery=&File=D

%3A\zyfiles\Index%20Data\76thru80\Txt\00000001\30004EB1.txt&User=ANONYMOUS&Password=anon

ymous&SortMethod=h|-

&MaximumDocuments=1&FuzzyDegree=0&ImageQuality=r75g8/r75g8/x150y150g16/i425&Display=p|f&

DefSeekPage=x&SearchBack=ZyActionL&Back=ZyActionS&BackDesc=Results%20page&MaximumPag

es=1&ZyEntry=1&SeekPage=x&ZyPURL 
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the chemical reaction that occurs in the scrubber. The salts are removed as a solid 

waste by-product. The waste by-product is mainly CaSO3, which is difficult to dewater. 

Solid waste by-products from wet lime scrubbing are typically managed in dewatering 

ponds and landfills. A review of the RBLC database has found wet lime scrubbers are 

commonly used in large industrial and utility boiler applications and not on SRUs. 

Wet Limestone Scrubber 

Wet limestone scrubbers are very similar to wet lime scrubbers. However, the use of 

limestone (CaCO3) instead of prepared lime requires different feed preparation 

equipment and a higher liquid-to-gas ratio. The higher liquid-to-gas ratio typically 

requires a larger absorbing unit. The limestone slurry process also requires a ball mill to 

crush the limestone feed. 

Wet lime/limestone scrubbers can achieve SO2 control efficiencies of approximately 

95% or greater. The actual control efficiency of a wet lime/limestone FGD system 

depends on several factors, including the uncontrolled SO2 concentration entering the 

scrubber: The higher the uncontrolled concentration, the higher the efficiency. Similar to 

wet lime scrubbers, wet limestone scrubbers generate sludge that creates material 

handling and disposal issues. A review of the RBLC database has found wet limestone 

scrubbers are commonly used in large industrial and utility boiler applications and not 

on SRUs. 

Dual Alkali Wet Scrubber 

Dual-alkali scrubbers use a sodium-based alkali solution to remove SO2 from the 

combustion exhaust gas. The process uses both sodium-based and calcium-based 

compounds. The sodium-based reagents absorb SO2 from the exhaust gas, and the 

calcium-based solution (lime or limestone) regenerates the spent liquor. Calcium sulfites 

and sulfates are precipitated and discarded as sludge, and the regenerated alkaline 

sodium solution is returned to the absorber loop. 

The dual-alkali process requires lower liquid-to-gas ratios than scrubbing with lime or 

limestone. The reduced liquid-to-gas ratios generally mean smaller scrubber units; 

however, additional regeneration and sludge processing equipment is necessary. 

A sodium-based scrubbing solution, typically consisting of a mixture of sodium 

hydroxide, sodium carbonate, and sodium sulfite, is an efficient SO2 control reagent. 

However, the process generates sludge that creates material handling and disposal 

issues. The control efficiency is similar to the wet lime/limestone scrubbers at 

approximately 95% or greater. Once again, control efficiencies are highly dependent 

upon the uncontrolled SO2 concentration entering the scrubber. A review of the RBLC 

database has found dual-alkali scrubbers are commonly used in large industrial and 

utility boiler applications and not on SRUs. 
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Spray Dry Absorber 

The typical spray dry absorber (SDA) uses lime slurry and water injected into a tower to 

remove SO2 from the combustion gases. The towers must be designed to provide 

adequate contact and residence time between the exhaust gas and the slurry in order to 

produce a relatively dry by-product. The process equipment associated with an SDA 

typically includes an alkaline storage tank, mixing and feed tanks, atomizer, spray 

chamber, particulate control device, and recycle system. The recycle system collects 

solid reaction products and recycles them back to the spray dryer feed system to reduce 

alkaline sorbent use. 

SDAs are the commonly used dry scrubbing method in large industrial and utility boiler 

applications and not on SRUs. SDAs have demonstrated the ability to achieve greater 

than 95% SO2 reduction. Once again, control efficiencies are highly dependent upon the 

uncontrolled SO2 concentration entering the scrubber, and fall off as the incoming 

concentration falls off. 

Dry Sorbent Injection 

Dry sorbent injection involves the injection of powdered or hydrated sorbent (typically 

alkaline) directly into the flue gas exhaust stream. Dry sorbent injection systems are 

simple systems, and generally require a sorbent storage tank, feeding mechanism, 

transfer line and blower, and injection device. The dry sorbent is typically injected 

countercurrent to the gas flow through a venturi orifice. An expansion chamber is often 

located downstream of the injection point to increase residence time and contact 

efficiency. Particulates generated in the reaction are controlled in a downstream 

particulate control device. 

SO2 control efficiencies for dry sorbent injection systems are approximately 50%, but if 

the sorbent is hydrated lime, then 80% or greater removal can be achieved. These 

systems are commonly called lime spray dryers. Once again, control efficiencies are 

highly dependent upon the uncontrolled SO2 concentration entering the scrubber.

Circulating Dry Scrubber 

A third type of dry scrubbing system, the circulating dry scrubber (CDS), uses a 

circulating fluidized bed of dry hydrated lime reagent to remove SO2. Flue gas passes 

through a venturi at the base of a vertical reactor tower and is humidified by a water 

mist. The humidified flue gas then enters a fluidized bed of powdered hydrated lime 

where SO2 is removed. The dry by-product produced by this system is routed with the 

flue gas to a particulate removal system. 

Material must be purged from the system continuously and replaced. The solid waste 

must be landfilled in accordance with regulations and with the consent of the landfill 

owners. Approximately 2.5 pounds of waste are generated for each pound of SO2

removed.41

 

41 Based on lime to sulfur stoichiometric ratio of 1.4:1 and 80% removal efficiency. 
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2.4.2 Eliminating Technically Infeasible Options 

CDS systems result in high particulate loading to a unit’s downstream particulate control 

device. Because of the high particulate loading, the pressure drop across a fabric filter 

would be unacceptable; therefore, electrostatic precipitators (ESP) are generally used 

for particulate control in power plant applications. Based on limited technical data from 

non-comparable applications and engineering judgment, it has been determined that 

CDS is not technically feasible. Therefore, CDS will not be evaluated further. 

SDA and DSI are not typically used at Claus SRUs. The EPA factsheet for these 

technologies also indicates that they cannot be used for waste gas SO2 concentrations 

greater than 2,000 ppm.42 Due to these reasons, these technologies were not evaluated 

further. 

The MSCC facility has a very limited area to install additional SO2 controls or to manage 

waste materials (see Figure 2.3-1). The wet FGD scrubber systems with the higher 

water requirements (Wet Lime Scrubber, Wet Limestone Scrubber, Dual Alkali Wet 

Scrubber) would require an on-site dewatering pond and landfill to process and dispose 

of scrubber sludge. Similarly, the Wellman-Lord scrubber also has significant space 

requirements, especially in a retrofit situation43 as well as a “purge stream” requiring 

disposal. Due to MSCC’s limited space, its proximity to the Yellowstone River and a 

shallow aquifer, and due to limited water availability and lack of disposal infrastructure 

for these controls, these technologies are considered technically infeasible and will not 

be evaluated further.

 

 

42 Air Pollution Control Technology Fact Sheet, Flue Gas Desulfurization (FGD) – Wet, Spray Dry, and 

Dry Scrubbers, http://www.epa.gov/ttncatc1/dir1/ffdg.pdf 

43 Summary Report, Sulfur Oxides Control Technology Series: Flue Gas Desulfurization; Wellman-Lord 

Process. EPA National Service Center for Environmental Publications, 

http://nepis.epa.gov/Exe/ZyNET.exe/30004EB1.TXT?ZyActionD=ZyDocument&Client=EPA&Index=1976

+Thru+1980&Docs=&Query=&Time=&EndTime=&SearchMethod=1&TocRestrict=n&Toc=&TocEntry=&Q

Field=&QFieldYear=&QFieldMonth=&QFieldDay=&IntQFieldOp=0&ExtQFieldOp=0&XmlQuery=&File=D

%3A\zyfiles\Index%20Data\76thru80\Txt\00000001\30004EB1.txt&User=ANONYMOUS&Password=anon

ymous&SortMethod=h|-

&MaximumDocuments=1&FuzzyDegree=0&ImageQuality=r75g8/r75g8/x150y150g16/i425&Display=p|f&

DefSeekPage=x&SearchBack=ZyActionL&Back=ZyActionS&BackDesc=Results%20page&MaximumPag

es=1&ZyEntry=1&SeekPage=x&ZyPURL 
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Figure 2.3-1: Approximate MSCC Leased Property Boundary and 

Yellowstone River 

2.4.3 Technically Feasible Options 

Technologies proven effective at Claus plants and which require low amounts of water 

and installation space were evaluated. The two technically feasible alternative control 

approaches for the MSCC facility were determined to be: 
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• Extending the Claus reaction into a lower temperature liquid phase (ECLT) (or 

equivalent) 

• Reduction Tail Gas Scrubbing (RTGS) 

ECLT44 and RTGS45 include several potentially feasible technologies. Due to the 

extremely limited timeframe to adequately respond, Sulfreen® and SCOT were chosen 

as representative average cases of ECLT and RTGS, respectively. These technologies 

were selected due to the availability of some cost information provided by contacted 

vendors, information available on the web, and their commercial availability. 

2.4.3.1 Sulfreen® 

In the Sulfreen® process, the Claus reaction is extended at low temperatures (260 to 

300oF) to recover SO2 and H2S in the tail gas. Tail gas passes through one of three 

reactors on line at a given time. Two reactors are on either heating or cooling cycles 

while the third is on the gas stream. Gas flow is switched from the reactors and is 

determined by the sulfur-holding capacity of each catalyst bed in the reactors. Sulfur is 

vaporized by using inert gas from a blower, resulting in the regeneration of the catalyst 

bed. The inert gas is then cooled in a condenser, where the liquid sulfur is removed. 

The hot regenerated catalyst bed must be cooled before going back on the gas stream. 

Sulfreen® systems reportedly can achieve 98%46 to 99.5%47 sulfur recovery efficiency. 

AP-42 Chapter 8.13 Sulfur Recovery suggests the upper range is about 99%. Bison 

and MSCC believe the higher end of this recovery percentage to be theoretically 

possible, but unlikely achievable at the MSCC facility. These are substantially similar 

efficiencies as those reported for SuperClausTM systems. The MSCC facility operates 

SuperClausTM systems at this time, as already noted. Review of the available 

information does not suggest that application of these costly “low-temperature Claus” 

alternative technologies would result in significant additional reduction as compared to 

SuperClausTM systems. We also do not expect a vendor to guarantee the higher end of 

this sulfur recovery percentage range due to atypical conditions necessarily existing in 

the upstream Claus system at MSCC. 

The recovery percentage ranges also represent the amount of sulfur removed from the 

untreated gas stream(s) entering a sulfur recovery facility and not the amount of SO2 

reduction from the existing tail gas stream. The effective reduction to existing controlled 

 

44ECLT includes at least five technologies, BSR/Selectox, Sulfreen®, Cold Bed Absorption, Maxisulf, and

IFP-1 processes as identified AP-42 Chapter 8.13 Sulfur Recovery, 

http://www.epa.gov/ttn/chief/ap42/ch08/final/c08s13.pdf 

45 Beavon, Beavon MDEA, SCOT, and ARCO are identified in AP-42 Chapter 8.13. 

46 Sulfreen® description adapted from “Encyclopedia of chemical processing and design, Volume 1.” 

http://books.google.com/books?id=JoZbcFQvHJ8C&pg=PA210&lpg=PA210&dq=Sulfreen+Process+Desc

ription&source=bl&ots=yWr1jJ6Aq3&sig=3yS-ffTUZ7lcwISqSy3BbopfH7g&hl=en&sa=X&ei=_awoTeQGImyiQKXs721Cg&ved=0CDsQ6AEwAw#v=onepage&q=Sulfreen%20Process%20Description&f=fals

e 

47 Sulfreen® Recovery of up to 99.5% per “Concawe Cost and Cost-Effectiveness, Assessment of 

Abatement Technology/Techniques for Refineries”. Link: http://www.citepa.org/forums/egtei/5-Whiterefineries.pdf 
Montana Sulphur & Chemical Company Regional Haze Rule Section 114 Response 

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SO2 emissions would be substantially lower than the theoretically possible overall sulfur 

recovery rates. 

2.4.3.2 Shell Claus Off-Gas Treatment (SCOT) 

In the SCOT process, and numerous variants, tail gas from the SRU is re-heated and 

mixed with a hydrogen-rich reducing gas stream. Heated tail gas is treated using a 

catalytic reactor where the free sulfur, sulfur dioxide, and reduced sulfur compounds are 

substantially reconverted to H2S. The H2S-rich gas stream is then routed to a 

cooling/quench system where the gases are cooled. Excess condensed water from the 

quench system is routed to a separate sour water system for treatment and disposal. 

The cooled quench system gas effluent is then fed to an absorber section where the 

acidic gas comes in contact with a selective amine solution and is absorbed into 

solution; the amine must selectively reject carbon dioxide gas to avoid problems in the 

following steps, and must not be exposed to unreduced gases or oxygen (e.g., 

unconverted SO2 or sulfur) that may arise during malfunctions. The rich solution is 

separately regenerated using steam, cooled and returned to the scrubber/absorber. The 

H2S-rich gas released at the regenerator is reprocessed by the SRU. 

In certain applications, particularly newly designed plants designed for use with Tail Gas 

Treatment, SCOT can reportedly achieve sulfur recovery as high as 99.8%-99.9%.48

Bison and MSCC believe this recovery percentage to be theoretically possible, but 

unlikely achievable at the MSCC facility which dates to the 1950s. Similar to the 

Sulfreen® discussion above, this sulfur recovery percentage represents the amount of 

sulfur removed from the untreated acid gas stream entering the upstream SRU and not 

the amount of further SO2 reduction from the tail gas stream. The effective reduction to 

existing controlled SO2 emissions would be substantially lower than these overall sulfur 

recovery rates. 

2.4.4 Cost-Effectiveness 

The cost-effectiveness of the potentially feasible SO2 control technologies was 

estimated, to the extent time allowed, based on the methodologies developed by 

William M. Vatavuk in the book Estimating Costs of Air Pollution Control and the 

methodologies provided in EPA’s Office of Air Quality Planning and Standards 

(OAQPS) Pollution Cost Control Manual, 6th Edition. 

The emission rate for this analysis was based on (approximately) the average emission 

rate of 2009 and 2010, the most recent reporting years as of the January 6 letter. The 

results of the analysis are presented in the Results section of this report. Detailed 

estimates and supporting information are provided in Appendix A – Costs of 

Compliance Analysis. 

 

48 From: http://www.gec.jp/JSIM_DATA/AIR/AIR_6/html/Doc_142.html 
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2.5 Nitrogen Oxides 

Nitrogen oxides generated by the SRU and emitted from the 100m stack are minimal. 

Below is a summary of MSCC’s NOx emissions from 2009 and 2010 annual emission 

inventories49: 

Table 2.2-1: 2008–2009 Annual NOx Emissions 

Year NOx (tpy) 

2009 3.95 

2010 4.10 

Based on experience, conducting a cost analysis for additional controls to an emitting 

unit with such low emissions would show that adding NOx control would be prohibitively 

expensive with no discernible improvement to visibility impacts. Therefore, we conclude 

that NOx is being controlled to a level that is irrelevant to or which satisfies the RP goals 

of the RHR and no further cost analysis is warranted. Please see the Visibility Modeling 

Results in Section 6.0 of this report which support this conclusion. 

 

49 Emissions estimates from Montana Department of Environmental Quality prescribed emission factors in 

annual emission inventories. 
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3.0 TIME NECESSARY FOR COMPLIANCE 

3.1 Time Necessary for Compliance 

Based on the modeling results presented in Section 6 of this report, MSCC and Bison 

consider the facility already in compliance with the RHR. However, this section of the 

report will discuss the estimated amount of time to install the SO2 technologies identified 

previously in this report, as this is requested in the January 6 letter. 

3.1.1 Installation of SO2 Controls 

The addition of either ECLT (Sulfreen®) or RTGS (SCOT) would require careful 

planning in order to ensure that sulfur-rich gas streams from the client refinery are 

treated as required by law. The installation of new SOx controls would need to be 

carefully coordinated to allow a parallel treatment path using the existing equipment and 

to allow processes to remain in operation while the retrofits are applied to another 

parallel path. When MSCC elected to apply the far simpler SuperClausTM technology in 

1998, the time for design and installation, from “go-date” to on-line was approximately 

15 months, with some processing interruptions. When the second system was installed 

in 2008, the time required was approximately 30 months without process interruptions. 

Installation of a more complex process can be expected to take longer periods. Further, 

in order for any reduction to be fully effective, a level of redundancy is required to allow 

for operation during periods of tail-gas treatment downtime and repair. This could 

require multiple units and consecutive phases. Bison estimates the time necessary to 

complete the modifications to the SRU to be 18 to 36 months, per unit installed. 

Installation of these processes would also require the dismantling of the existing 

SuperClausTM units without a discernible improvement to visibility (see Section 6). 
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4.0 ENERGY AND NON-AIR QUALITY IMPACTS 

4.1 Energy Impacts: SO2 Controls 

The example SCOT and Sulfreen® systems require substantial additional energy to 

operate. Both systems require natural gas or fuel gas50 to heat the Claus tail gas prior to 

entering a reducing reactor and/or for heating recycle gas for regeneration 

requirements. Sulfreen® systems require electric power for operation of large 

regeneration blowers. Low-temperature based systems (either SCOT or Sulfreen®) 

also typically require additional fuel for reheat of the final tail gas for incineration prior to 

discharge.51 SCOT systems also require substantial electricity to operate numerous 

pumps, coolers, and a condenser. Additional power is required to provide relatively 

large amounts (compared to current) of cooling water. Additional fuel and power energy 

(and equipment) is required for processing of the new sour water waste continuously 

produced in the quench processes necessary for scrubbing. 

The limited time to evaluate these options has not allowed a detailed energy evaluation 

for SCOT, and none for Sulfreen®. However, we are advised that energy requirements 

for SCOT are (at least) as follows: 

 

50 Natural gas must be burned either directly in a re-heater or fuel gas/natural gas fired in new boiler

equipment to produce high pressure steam in a new boiler. MSCC does not presently own or operate 

any boilers of the 600 pound pressure class necessary for use of steam re-heat. 

51 MSCC currently reheats gases for incineration, but this is reheated from a higher temperature than 

SCOT effluent, and thus has lower fuel requirements. 
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Table 4.1-1: SCOT Utility Estimates 

Equipment Normal 

Consumption

Maximum 

Consumption 

Required Heat 

Input (MMBtu/hr) 

Low Pressure Steam 

Service (50 psig) 

19,654 

lb/hr 

22,046 

lb/hr 27.5 to 30.9 

Superheated MidPressure Steam 

Service (150 psig) 

331 

lb/hr 

661 

lb/hr 0.5 to 1 

High Pressure Steam 

Service (600 psig) 

3,382 

lb/hr 

4,526 

lb/hr 4.7 to 6.4 

Total Steam: 19,654 22,046 32.7 to 38.1 

Power Service 220 kW/h 222 kW/hr ~0.8 

Nitrogen Service 5 Nm3

/h 1404 Nm3/h NA 

These also necessarily represent increases in greenhouse gas emissions and other 

pollutants either at MSCC or at provider facilities. 

4.2 Non-Air Quality Impacts: SO2 Controls 

The quench system in the SCOT system produces a sour water waste effluent that 

requires treatment prior to disposal. This effluent would contain hydrogen sulfide, and 

may contain sulfur and other troublesome species as well, particularly during upsets. 

MSCC currently does not have sour water treatment facilities nor access to a public 

sewer system to accommodate such a waste stream. A permissible solution to this 

problem would have to be engineered if this system is installed at the facility. 

SCOT would also require a few non-fuel consumables of significant cost: 

1. Catalyst for the reduction stage, 

2. MDEA or proprietary blends of amines, 

3. Corrosion inhibitors, 

4. Water treatment chemicals. 

Other processes evaluated would produce substantially greater solid or liquid waste 

streams requiring treatment and disposal off site. All processes evaluated represent an 
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increase in solid/liquid waste and energy consumption as compared with the current 

control option (SuperClaus). 
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5.0 REMAINING USEFUL LIFE OF THE AFFECTED SOURCE 

A brief history of MSCC operation was given in Section 2.1. As a summary, the facility 

began operation in 1955, and has operated continuously since then. It is a privatelyheld, family business, now operated by second-generation management. Estimates 

vary on the typical useful life of SRU equipment, but in Bison’s view, it would be typical 

to expect plants to last about 40 years or more. Thanks to careful operation, quality 

maintenance and continual improvements in reliability, this facility has exceeded that 

typical expectation. No specific additional life of the sulfur recovery plant can be 

offered. The facility has operated under a succession of essential contracts relating to 

raw material supply and gas processing. There is no way to assuredly predict if such 

contracts will continue or will cease. However, for purposes of planning, it would 

reasonable to assume that the facility, which remains serviceable, effective and reliable 

today, would continue to operate at least 15 years into the future. 
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6.0 VISIBILITY MODELING RESULTS 

6.1 Visibility Modeling Results 

As noted in Section 1 and elsewhere, no analysis which purports to address or 

implement a plan for “reasonable progress” in visibility improvement would be complete 

without ascertaining “visibility improvement.” An analysis of cost-effectiveness of 

alternatives, useful life and other factors could certainly play into a decision of what 

alternatives could be important, but only if such alternatives yield human-perceptible 

changes in visibility at a nearby mandatory Class I area. After all, visibility improvement 

in such areas is the sole purpose of the RHR program; and visibility is an aesthetic 

resource at its core, as perceived by the human eye and mind. Any proposal to reduce 

emissions must first, and foremost, yield visibility improvement that could indeed be 

observed as a result of such proposed emission reductions. 

No monitoring data was found suitable to determine “visibility” impacts, if any, arising at 

MSCC in any nearby mandatory Class I area. In order to assess potential impacts to 

visibility, Bison conducted dispersion modeling for MSCC.52 The modeling followed the 

general procedures outlined in the BART program. In the interest of brevity, a complete 

discussion of the model (Calpuff) and its multiple inputs are not presented in this report. 

The methods used, data inputs, output and so forth are all available upon request. The 

model effort conforms to the general procedures used in previous BART and 

Reasonable Progress modeling conducted in Montana. 

The emissions data used in the model were a measure of “actual” emissions. For this 

modeling effort, the base case model used the SO2 rate that was derived from the 

calendar years 2008 – 2010. Table 6.1-1 summarizes the emission rates used in the 

baseline visibility modeling analysis. 

Table 6.1-1: Modeled Emission Rates 

Pollutant lb/hour tons/year 

SO2 331.553 1,452 

NOx 0.93 4.06 

PM10 0.106 0.465 

A number of mandatory Class I areas were chosen for analysis. These included the 

following: 

 

52 Bison Engineering, Inc. is a recognized expert in the field of dispersion modeling. Bison has conducted 

numerous PSD permit applications, SIP analyses and visibility impacts for various facilities and purposes. 

Bison conducted several BART analyses and is familiar with the CALPUFF modeling system. 

53 This SO2 rate represents about 1/3 of the allowable emission rate at this stack per the FIP related to the 

NAAQS for SO2 [40 CFR 52.1392(g)(3)(i)(A)]. 
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Yellowstone National Park, 

UL Bend Wilderness Area, 

North Absaroka Wilderness Area, 

Gates of the Mountains Wilderness Area. 

These areas include all of the nearby areas covering the major quadrant directions. 

Figure 6.1-1: Location Class I Areas 

As specified in the RHR and BART analysis guidelines, the visibility impacts were 

calculated and presented using the 98th percentile modeled visibility impacts from 

MSCC’s 2008-2010 emission rate on these mandatory Class I Areas. Table 6.1-2 below 

provides the results of the modeling using the emission rates in the table above. This 

represents the impacts “base case” emissions from the facility assuming no additional 

controls are added to the current operation. 
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Table 6.1-2: Base Case Visibility Impacts 

Mandatory Class I Area 

Visibility Impact

(∆DV) 

24-Hour Maximum 

Yellowstone National Park 0.08 

UL Bend 0.14 

North Absaroka Wilderness Area 0.10 

Gates of the Mountains Wilderness Area 0.08 

From the data in the table, one observes that the highest modeled impact was 0.14 

deciview at the UL Bend Wilderness located approximately 140 km NNE of the facility. 

As an explanation, the deciview metric was developed (and adopted by EPA) to more 

easily understand a measure of visibility change and at the same time provide a more 

uniform (linear) representation of observed or modeled visibility impairment. More 

specifically, a “1.0” deciview impact is usually described as a “just noticeable change”

(JNC) in a visibility scene.54 

Therefore, it should be clearly understood that a 0.14 deciview modeled impact is not

discernible. As a result, MSCC does not contribute to regional haze at any mandatory 

Class I areas. That would be the case at current (2008-2010) emissions or at Potential 

to Emit emission rates which are substantially higher. That alone reasonably exempts 

MSCC from consideration of any additional control options that would otherwise be 

considered as candidates for visibility improvement or reasonable progress toward the 

2064 goals. 

The above discussion notwithstanding, it is worth noting EPA’s position on what would 

be an acceptable impact from a new facility. EPA generally considers an impact, by the 

facility alone, of less than 0.5 deciviews to be acceptable. Therefore, if MSCC were a 

new source of sulfur dioxide in the Billings area, its 2008-2010 emission impact on the 

 

54 There are numerous articles and explanations for the deciview metric. This discussion is taken from the 

publication “IMPROVE,” Volume 2, No. 1, April 1993. The information itself is taken from a publication by 

Pitchford and Malm, 1993. The article contains the following quote: 

“Ideally, a just noticeable change (JNC) in scene visibility should be approximately a 

one or two dv change in the deciview scale (i.e., a 10% to 20% fractional change in 

extinction coefficient) regardless of the baseline visibility.” 

The idea that a “1” deciview change represents ‘just discernible’ to the human eye is also found in many 

other publications and web sites such as the Arizona Department of Environmental Quality and the 

“Group Against Smog and Pollution” (GASP) which may be found at: 

http://gasp-pgh.org/publications/hotline/spr02-2/ 

http://www.phoenixvis.net/education.html 

 
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mandatory Class I areas would be considered quite acceptable, and definitely negligible 

at 0.14 deciviews, and also acceptable at levels essentially three times as high.55

The data in the table shows that MSCC, by itself as currently configured and controlled, 

has no perceptible change in visibility at any mandatory Class I area. It is reasonable to 

conclude that the addition of any additional emission controls cannot change that 

conclusion. Since the statutory purpose and authorization of the program is to improve 

regional haze in Class I areas, toward a national goal in the year 2064, and given 

MSCC does not now impact regional haze discernibly, no additional controls are 

warranted. Thus, the addition of controls or further limitations at MSCC would not serve 

the program’s purpose of creating “reasonable progress” toward the national goal, since 

no measurable progress would be created. 

 

55 See Appendix A for linear equation that predicts deciview impact based on SO2 emission rate. 
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7.0 ECONOMIC RESULTS AND IMPACTS TO VISIBILITY 

The installation of any SOx controls would ultimately require two parallel systems at the 

MSCC facility. Parallel systems are required because MSCC must operate the facility 

8,760 hours a year to treat fuel and acid gases supplied by the adjacent refinery. 

Redundant systems enable the current, and evaluated, systems to undergo 

maintenance and outages while still meeting the enforceable short-term and long-term 

emission limits. Therefore, two systems (126 long tons per day each) with a nominal 

capacity of half of MSCCs capacity (252 long tons per day) were evaluated as part of 

this analysis. 

As discussed in Section 2.4, sulfur recovery of these technologies is based on sulfur 

removed from the feed gas streams and does not represent the percentage of SO2

removed from the flue gas as emitted from the presently controlled stack. In this section, 

these removal percentages will be referred to as sulfur recovery percentage and 

effective incremental SO2 removal percentage. 

The baseline SO2 emission rate used for this analysis was 1,452 tons/year. This 

emission rate was achieved with the current SuperClausTM units in place, as measured 

by CEMS. To identify the comparable incoming rates we have assumed the overall 

facility achieves 98.5% sulfur recovery from the feed gases, consistent with original 

vendor expectations for this retrofit. The quantity of sulfur dioxide equivalent in the feed 

gas can then be back-calculated to be 96,800 tpy during this period56. The theoretically 

achievable sulfur recovery percentages of each technology can then be applied to 

determine the effective SO2 removal percentage. This is summarized in the table below: 

Table 7.0-1: Theoretical Sulfur Recovery and Effective SO2 Removal 

Technology 

Theoretical 

Sulfur 

Recovery % 

Representative 

SO2 Emission 

Rate (tpy) 

Calculated 

Sulfur 

Dioxide in 

Feed Gas 

Based on 

98.5% 

SuperClausTM

Recovery 

Resultant 

SO2

Emission 

Rate 

(tpy) 

Effective, 

Incremental 

SO2

Removal 

(%) 

Sulfreen® 99.0% 1452 96,800 tpy 968 tpy 33.3% 

SCOT 99.4% 1452 96,800 tpy 580.8 60.0% 

MSCC and Bison worked to obtain capital and operating costs for these technologies. 

We contacted Jacobs Comprimo, one of the foremost companies in the world with 

SCOT experience, to provide us approximate capital and operating costs for a SCOT-

 

56 Actual recoveries will vary, and actual feed rates also will vary over time. These were used for purposes of 

comparison. 
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type system at least theoretically feasible at the MSCC facility. Jacobs Comprimo 

estimated that the capital cost for two (redundant) 126 tpd systems would be in the 

range of $55,000,000 to $60,000,000 USD,57 assuming the existence of adequate 

nearby plot space and adequacy of existing utilities and existence of a viable “sink” for 

sour water waste. This level of capacity would provide a level of redundancy, necessary 

to the normal operation of the facility 24/7/365. Time allowed for estimation does not 

allow for customization or refinement of the estimate, which may be low by as much as 

50%, and does not allow for assessment of availability of sufficient plot space, or 

account for the cost of necessary support utilities, such as steam, power backup, and 

sour water handling. 

Sulfreen® capital and operating costs were estimated using information available on the 

web. The following presentation based on refineries in Europe using this technology 

was used to estimate capital and operating costs for this analysis: 

Concawe Cost and Cost-Effectiveness Assessment of Abatement 

Technology/Techniques for Refineries, Contributing to the Update of the EGTEI 

Synopsis Sheets for the Petroleum Sector.

58

 

The cost data located in this resource yielded a capital cost estimate of $76,500,000 for 

two 126 tpd Sulfreen units. 

Using these resources of information, we were able to roughly estimate the theoretical 

cost-effectiveness of these two types of technologies. Table 7.0-2 summarizes the 

results of the potential addition of SOx controls and their emission reductions. 

 

57 Estimates provided by Jacobs Comprimo were caveated with an accuracy of -25% to +50%. The 

median of the capital cost estimate range, $57,500,000 and a retrofit factor of 1.3 were used for this

analysis. 

58 Please see Appendix A for more details. The presentation is available at 

http://www.citepa.org/forums/egtei/5-White-refineries.pdf. 
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Table 7.0-2: Cost-Effectiveness of Alternate SOx Controls 

Technology Capital 

Investment59

Annual 

Operating 

Cost60

Sulfur 

Recovery 

Efficiency 

(%) 

Tons SOx 

Emitted 

after 

Control 

Tons SOx 

Reduced 

(2010 

baseline) 

Effective 

SO2

Removal 

Efficiency 

CostEffectiveness 

($/ton) 

Sulfreen® - 

Two 126 tpd 

Units 

$76,500,000 $18,980,254 99.0% 968 484 33.3% $39,215

Shell Claus 

Off-Gas 

Treatment 

(SCOT) – 

Two 126 tpd 

Units 

$74,750,000 $18,824,971 99.4% 580.8 871.2 60.0% $21,608 

The potential visibility impacts of installing the more cost-effective of these two classes 

of controls, SCOT, were determined by predicting the resultant effective ~60% control of 

SO2 emissions from the SRU.61 The highest predicted impact to the most impacted 

Class I Area (UL Bend) following control was compared to the highest 98th percentile 

impact from the baseline modeling. Table 7.0-3 summarizes what the potential effects to 

visibility would be if this control was installed and the cost-effectiveness of this option in 

$/deciview. Note that “dollars/deciview” in this case is a misnomer. Since the maximum 

estimated “improvement” is imperceptible, at less than 1 deciview, no amount of cost at 

MSCC can improve visibility by even one deciview. 

 

59 Capital investment costs include retrofit multiplier of 1.3. 

60 Annual Operating Cost includes maintenance, materials, electrical costs, loan interest, and other costs. 

Please see Appendix A for more details. 

61 Deciview impact was determined by a linear equation developed by modeling 50% and 99.9% control 

of the baseline emission rate. See Appendix A for more information. 
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Table 7.0-3: Cost-Effectiveness of SO2 Control in $/Deciview 

Control 

Option 

Emission 

Rate (tpy) 

Max 

Prediction 

(∆DV) 

Class I 

Area 

Impacted 

Incremental 

Deciview 

Change 

Annual 

Operating 

Cost 

CostEffectiveness 

($/deciview) 

Base 

Case, 

current 

redundant 

controls 

1452 0.136 UL Bend --- --- --- 

SCOT, 

Two 126 

tpd Units 

580.8 0.053 UL Bend 0.08 $18,824,971 $226,730,391 
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8.0 SUMMARY 

As requested by EPA, MSCC, via Bison Engineering, has analyzed its Sulfur Recovery 

Unit (SRU) at the facility for the purposes of meeting the Reasonable Progress goals of 

the Regional Haze Rule (RHR). MSCC retained Bison Engineering, Inc. to assist MSCC 

in evaluating possible control alternatives, in the extremely limited time frame provided 

for response. 

The analysis concluded that the particulate matter and NOx emissions from the SRU 

facility are minimal (approximately 0.5 tpy particulate and 4 tpy of NOx). As a result, 

these small emissions would not reasonably be expected to impact regional haze at any 

nearby mandatory Class I area. (The nearest area is approximately 120 km from the 

plant site.) 

The analysis, given the severely limited time, was able to identify two potentially 

technically feasible alternate controls approaches for SO2: ECLT and RTGS. Sulfreen® 

and SCOT were selected and evaluated as being representative of ECLT and RTGS, 

respectively. It should be noted that the technology presently employed at MSCC 

(Claus+SuperClausTM) is already roughly equivalent in published control effectiveness 

as ECLT. In addition, it is essential for the reader to understand that combining these 

technologies does not result in cumulative benefits or reductions. Similarly, 

SuperClausTM technology cannot be applied upstream of SCOT technology as the 

oxidative chemistry of SuperClausTM is incompatible with the reduction technology 

invoked by SCOT. 

As the intent of the RHR is to protect visibility in mandatory Class I Areas, Bison also 

conducted visibility modeling. The modeling was conducted to assess the predicted 

impacts from MSCC’s current facility emissions and from emissions that could result 

from the addition of alternative SO2 controls. The modeling analysis has shown that 

current (and allowable) emission rates result in impacts well below 1.0 deciview. EPA 

employs 1.0 deciview as a level to indicate a discernible visible impact. Also, EPA 

routinely considers an impact below 0.5 deciviews (for new or modified facilities) as a 

permissible contribution to modeled visibility impact. Effectively, an impact less than 0.5 

deciviews would be considered de minimis. 

The alternative controls reviewed in this report all result in modeled predictions much 

less than 0.5 deciviews. This conclusion is also valid for current emissions as well as 

allowable emissions [40 CFR 52.1392(g)(3)]. 

The short time allowed for response (essentially four weeks) did not allow sufficient 

review of other potential technologies that may have been considered given adequate 

time. However, even with the most effective proven technology typically applied to new 

Claus plants, irrespective of cost, no discernible visibility benefits accrue. 

As part of the analysis, EPA requested that MSCC analyze the costs of compliance 

related to the installation and operation of alternative control technologies. These values 

have been analyzed as required despite a limited time and limited data. Regardless, the 
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costs identified are very high both on both a ‘cost per ton of pollutant removed’ as well 

as a ‘cost per deciview improvement’ basis. EPA’s document Guidance for Setting 

Reasonable Progress Goals under the Regional Haze Program62 states: 

“...the cost of compliance factor can be interpreted to encompass the cost of 

compliance for individual sources or source categories, and more broadly the 

implication of compliance to the health and vitality of industries within a state.” 

The two technically “feasible” identified additional SO2 control options identified would 

have major adverse impacts on the facility and its ability to remain in operation, and 

thus on its employees and owners. 

As a result of all of the analyses conducted in this document, we conclude that no 

additional controls at the MSCC facility are consistent with the Reasonable Progress 

national goals since: 

(a) The cost of additional controls are excessive; 

(b) The existing controls and operation MSCC facility does not demonstrate any 

discernible impact on any nearby mandatory Class I area; 

(c) The addition of emission controls at MSCC would not improve discernible 

visibility attributes in any nearby mandatory Class I area. 

 

62 Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program, U.S. 

Environmental Protection Agency Office of Air Quality Planning and Standards Air Quality: 

http://www.epa.gov/ttncaaa1/t1/memoranda/reasonable_progress_guid071307.pdf. 
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APPENDIX A –COSTS OF COMPLIANCE ANALYSIS 
MSCC

SOx Cost Summary

Sulfreen® with two, 126 t/d units 99.0% 96,800 $76,500,000 $18,980,254 1,452 968.0 

Shell Claus Off-Gas Treatment (SCOT) 

with two, 126 tpd Units 99.4% 96,800 $74,500,000 $18,824,971 1,452 580.8 

SO2 Control Option 

Sulfur % 

Recovery

Total Capital 

Investment

Total Annual 

Cost

Annual 

Emissions 

After Contr

Reduction 

(tpy)

Sulfur in 

Feedgas 

(tpy)

Baseline SO2 

Emissions (tpy)
Typical SuperClaus Sulfur Recovery: 98.5% Per MSCC, 3 Stages %

Representative SO2 Emissions out Stack: 1452 tpyBack Calculating SO2 in Feed Stock: 96800 tpy

Add On Technology

SCOT - two, 126 

tpd Units

Sulfreen - two, 126 tpd Units

Assumed Recovery %: 99.4% 99.0%

Resultant SO2 Emissions (tpy) 580.8 968.0

Baseline Deciview Impact (No Control): 0.136 0.136

Predicted Deciview Impact of Controla: 0.053 0.09

Deiview Improvement: 0.083 0.048

Calculated $/Deciview Improvementb: $ $393,944,655.64 226,730,391.18

Notes:

a Predictive equation derived based on highest modeled impact at the UL Bend Wilderness.

Y = 0.00009x+.0007 SO2 Emission Rate (tpy) Deciview Impact Using Predicti

Where: 1000 0.0907 

Y = Deciview Impact 1452 0.13138 

X =

SO2 Emission Rate (tpy) 2000 0.1807 

3000 0.2707 4000 0.3607 4355 0.39265 5000 0.4507 5548 0.5 

Emission Calculations and Deciview Impact Summary

Predictive Equation:

$/Deciview improvement calculated by dividing the annual operating costs for each technology by the 

b predicted deciview improvement.

1000

1452

2000

3000

0

0.10.20.30.40.50.6

0 1000 2000 3000 400

Deciview Impact vs. SO2 Emis

Predictive Equati
MSCC

SO2 Control AnalysisCosts for TGTU (SCOT)

Estimated using OAQPS example for Acid Gas RemovalBased on methodology described inEPA Pollution Cost Control Manual, 6th EditionJanuary 2002Section 5.2, Chapter 1 Wet Scrubbers for Acid Gas Removal

Cost Item Factor Cost Cost Item 

DIRECT COSTS Fixed Operating Cost Purchased equipment costs

Number of systems required: 2

Size of System (Long Tons/Sulphur per Day); 126

Cost of system(s) + auxiliary equipmenta: $ 25,648,107 Fixed Operating Cost (4%/y Capital Cost): Reference: http://www.citepa.org/forums/e

Total system+ auxiliary equipment A 25,648,106.60 $ 

Instrumentation 0.10 A $2,564,811Sales taxes 0.03 A $769,443.20Freight 0.05 A $1,282,405 Variable Operating Cost

Purchased equipment cost, PEC B = 1.18 A $30,264,766 $8.05/ton S Processed Reference: http://www.citepa.org/forums/e

 Direct installation costs

Foundations & supports 0.12 B $3,631,772Handling & erection 0.40 B $12,105,906 INDIRECT ANNUAL COSTS, IC

Electrical 0.01 B $302,648Piping 0.30 B $9,079,430 Administrative Charges 

Insulation for ductwork 0.01 B $302,648 Property Taxes 

Painting 0.01 B $302,648 Insurance 

 Direct installation cost 0.85 B $25,725,051 Capital Recovery Factor (Annualized Capital Cost, 10 yrs at 10%) 

Retrofit Factor: 1.3 TOTAL ANNUAL COST (SCOT): 

Direct Installation cost Including Retrofit Factor: $33,442,566

Site preparation As required, estimate $100,000 Buildings As required, Estimate. $100,000 Total Direct Cost, DC 1.30 B + SP + Bldg. $63,907,332 Baseline Emiss

Sulfur Recove

INDIRECT COSTS (Installation) Effective SO2 

Engineering 0.10 B $3,026,477 Tons SO2 Emi

Construction and field expenses 0.10 B $3,026,477 Tons Removed Contractor fees 0.10 B $3,026,477Start-up 0.01 B $302,648 Cost-EffectivePerformance test 0.01 B $302,648Contingencies 0.03 B $907,943 Total Indirect Cost, IC 0.35 B $10,592,668

TOTAL CAPITAL INVESTMENT (TCI) = DC + IC 2.20 B + SP + Bldg. $74,500,000

Notes:

b Tons SO2 removed calculated by comparing the base case emissions to the tons emitted following add on control.

a

Based on vendor estimate of $55 - $60M for two, 126 tpd capacity units. The capital investment was back calculated based on a total capital investment of the median of this range ($57.5M). A retrofit factor of 1.3 was used, resulting in the total capital investment of $74,750,000.

Typical Supe

Represent

Back C
MSCC

SO2 Control AnalysisCosts for Lower Temperature Liquid Phase (Sulfreen ®)

Estimated using OAQPS example for Acid Gas RemovalBased on methodology described inEPA Pollution Cost Control Manual, 6th EditionJanuary 2002Section 5.2, Chapter 1 Wet Scrubbers for Acid Gas Removal

Cost Item Factor Cost Cost Item 

DIRECT COSTS Fixed Operating Cost Purchased equipment costs

Number of systems required: 2Capacity of Each Unit (tpd) 126Cost of system(s) + auxiliary equipmenta: $26,338,500 Fixed Operating Cost (4%/y Capital Cost): Reference: http://www.citepa.orgTotal system+ auxiliary equipment A $26,338,500Instrumentation 0.10 A $2,633,850Sales taxes 0.03 A $790,154.99Freight 0.05 A $1,316,925 Variable Operating Cost

Purchased equipment cost, PEC B = 1.18 A $31,079,430 $4.46/ton S Processed Reference: http://www.citepa.org

 Direct installation costs

Foundations & supports 0.12 B $3,729,532Handling & erection 0.40 B $12,431,772 INDIRECT ANNUAL COSTS, ICElectrical 0.01 B $310,794Piping 0.30 B $9,323,829 Administrative Charges Insulation for ductwork 0.01 B $310,794 Property Taxes Painting 0.01 B $310,794 Insurance  Direct installation cost 0.85 B $26,417,515 Capital Recovery Factor (Annualized Capital Cost, 10 yrs at 10%) Retrofit Factor: 1.3 TOTAL ANNUAL COST (SCOT): Direct Installation cost Including Retrofit Factor: $34,342,770Site preparation As required, estimate $100,000 Buildings As required, Estimate. $100,000 Total Direct Cost, DC 1.30 B + SP + Bldg. $65,622,200 Baselin

Sulfur 

INDIRECT COSTS (Installation) Effective 

Engineering 0.10 B $3,107,943 Tons SConstruction and field expenses 0.10 B $3,107,943 Tons RContractor fees 0.10 B $3,107,943Start-up 0.01 B $310,794 Cost-EPerformance test 0.01 B $310,794Contingencies 0.03 B $932,383 Total Indirect Cost, IC 0.35 B $10,877,800

TOTAL CAPITAL INVESTMENT (TCI) = DC + ICa 2.20 B + SP + Bldg. $76,500,000

Notes:

b Tons SO2 removed calculated by comparing the base case emissions to the tons emitted following add on control.

Typical 

Repr

Ba

a

Estimate based on "Concawe Cost and Cost-Effectiveness Assessment of Abatement Technology/Techniques For Refineries Contributing to 

the Update of the EGTEI Synopsis Sheets For the Petroleum Sector" L. White, Special Advisor, May 6th , 2011, 

http://www.citepa.org/forums/egtei/5-White-refineries.pdf
Sulfreen Capital and Operating Cost References

Based on: Concawe Cost and Cost-Effectiveness Assessment of Abatement Technology/Techniques For Refineries Contributing to the Update of the EGTEI Synopsis Sheets For the Petroleum SectorL. White, Special Advisor, May 6th , 2011Link: http://www.citepa.org/forums/egtei/5-White-refineries.pdfReference Size of Plant Used for Estimate: 33,333 tS/yearReference Size of Plant Used for Estimate: 91 tS/dayNominal Size of Plant at MSCC (tS/day) 252 tS/dayNominal Size of Plant at MSCC (tS/year) 91,980 tS/yearConversion from Euros to USD (January 2012): 1.3213

http://www.google.com/search?q=%E2%82%AC+to+dollars&ie=utf-8&oe=utf8&aq=t&rls=org.mozilla:enUS:official&client=firefox-a

Year of Cost Data 2006Chemical Engineering Plant Cost Index 2006 499.6Chemical Engineering Plant Cost Index 2011 596

Sulfreen (252 t/d) Sulfreen (Single 126t/d Unit) Sulfreen (2nd,126 t/d unit)

Capital Cost Low (Euro) 15,000,000 € 15,000,000 € ---Capital Cost High (Euro) 25,000,000 € 25,000,000 € ---Capital Cost Median (Euro) 20,000,000 € 20,000,000 € ---Cost vs. Unit Size (Cost Ref *(Feed Rate/Feed Rate Reference)^.6 36,772,351 € 24,260,704 € 48,521,408 €Convert Capital Cost to 2011 USD: $ 57,962,440 $ 76,48 38,240,949 $ 1,898.65

Fixed Operating Cost (4%/y Capital Cost): 2,318,497. $ 62 $ 3,059,27 1,529,637.97 $ 5.95

Sulfreen Variable Operating Cost Factor (Euro/tS) 2.83 € 2.83 € 2.83 €Variable Operating Cost Factor (2006 USD/tS) 3.74 $ $ 3.74 3.74 $ 

Variable Operating Cost Factor (2011 USD/tS) 4.46 $ $ 4.46 4.46 $ 

Variable Operating Cost (USD): 410,303.39 $ $ 410,3 205,151.70 $ 03.39

SCOT Variable Operating Cost Factor (Euro/tS): 5.11 €Variable Operating Cost Factor (2006 USD/tS) 6.75 $ Variable Operating Cost Factor (2011 USD/tS) 8.05 $ Annual Variable Operating Cost (USD): 740,865.84 $ 
Montana Sulphur & Chemical Company Regional Haze Rule Section 114 Response 

2/6/12 

APPENDIX B - MODELING 
Appendix B

Dispersion Modeling Report 

Assessment of Visibility Impacts: 

Mandatory Class I Areas 
Appendix B MSCC 2/6/2012 Section114 Request 

Visibility Modeling Report Page B-1 

1.0 INTRODUCTION 

This appendix provides a summary of the dispersion modeling conducted in support of 

MSCC’s response to EPA’s December 30, 2011, letter (received by MSCC on January 

6, 2012).1

 Dispersion modeling was not specifically required in response to the request; 

therefore, this appendix is only a brief summary of the model and various options used. 

More details of model options along with all modeling input and output files are available 

upon request. Summary information is provided herein. 

The January 6, 2012, letter from EPA asked MSCC to “Please submit an analysis of 

control options” for the MSCC facility located near Billings, Montana. The request 

relates to EPA’s effort to “address requirements under the RHR for reasonable progress 

(RP) goals and strategies (see 40 CFR 51.308(d)(l) and 51.308(d)(3)).” 

Although the request did not specifically seek or address MSCC’s visibility impacts on 

any nearby mandatory Class I areas, we believe that such an analysis is required and 

appropriate in order to address the underlying requirements of the RHR program. 

We note that the entire program of protecting visibility is found at 40 CFR 51, Subpart P 

(subsections 300 through 309). A review of Subpart P indicates the purpose and goals 

of the program. To begin, the overall purpose of the program is outlined as follows: 

“The primary purposes of this subpart are . . .to assure reasonable 

progress toward meeting the national goal of preventing any future, and 

remedying any existing, impairment of visibility in mandatory Class I 

Federal areas . . . .” [40 CFR 51.300(a)]. 

Insofar as regional haze is concerned, the following is noted when describing the “core 

requirements”2 for an implementation plan for regional haze. 

“For each mandatory Class I Federal area . . ., the State must establish 

goals . . . that provide for reasonable progress towards achieving natural 

visibility conditions. The reasonable progress goals must provide for 

an improvement in visibility for the most impaired days . . .” [40 CFR 

51.308(d)(1)]. 

The rules go on to provide states (EPA in this case) with what must be considered in 

developing reasonable progress. These details were outlined in the January 6, 2012, 

letter, which sought information relating to reasonable progress goals. 

 

1

 The letter was dated December 30, 2011, by EPA. The letter itself was mailed on or after January 3 and 

not received by MSCC until January 6, 2012. For purposes of consistency, this letter will be referenced as 

the January 6, 2012, letter since that is the date on which MSCC first became aware of EPA’s request. 

2

 40 CFR 51.308(d). 
Appendix B MSCC 2/6/2012 Section114 Request 

Visibility Modeling Report Page B-2 

The review of control options notwithstanding, it seems the visibility program is clear as 

to its intent. That is, the purpose of the program is to protect visibility (remedy, prevent 

impairment) as perceived in mandatory Class I areas. Based on the 51.308(d)(1) 

language above, it is also quite clear that any activity or goal (proposed or otherwise) 

that does not “improve visibility” is not, therefore, a candidate for those “reasonable 

progress” plans or goals. 

As a result, we believe an analysis that only addresses emission control options is not 

sufficient for inclusion into reasonable progress elements unless those emission 

controls actually improve visibility. It would be at odds with the program to include an 

emission control scenario that did not improve visibility (i.e., did not predictably produce 

a discernible change in deciviews). 

To that end, we have chosen to conduct an analysis of modeled impacts this facility has 

on the nearest mandatory Class I areas, and also to relate these numeric values to 

discernible visibility improvements. In order to conduct the analysis we have chosen, as 

a matter of convenience and consistency, to follow the general elements of the BART 

dispersion modeling effort relating to visibility impacts. The modeling effort used by 

BART, including this submittal, is found in 40 CFR 51, Appendix Y. 
Appendix B MSCC 2/6/2012 Section114 Request 

Visibility Modeling Report Page B-3 

2.0 MODEL SELECTION 

For this analysis, and as generally required by EPA for assessing visibility impacts, we 

used the CALPUFF dispersion model system. This is the same system that was applied 

for the BART analyses carried out under 40 CFR 51.308(e). BART is, itself, an element 

of the regional haze program and an element in the overall protection of visibility found 

in 40 CFR 51, Subpart P. 

CALPUFF is a non-steady-state Lagrangian dispersion model that simulates pollutant 

releases as a continuous series of “puffs.” It is supported by two primary sub-programs, 

CALMET and CALPOST. CALMET is used in refined analyses to simulate threedimensional wind fields based on multiple sources of geophysical and meteorological 

data. The output of the CALPUFF model consists of binary data files with information on 

pollutant concentrations, wet and dry flux rates, and visibility parameters. CALPOST 

processes these data based on specified input parameters or assumptions, and reports 

calculated impact values. 

The CALPUFF analyses utilized for this project are noted below and were obtained from 

the CALPUFF developer, Atmospheric Studies Group (ASG) at: 

http://www.src.com/calpuff/calpuff1.htm. 

Geophysical Data Processors

• TERREL (Version 3.311, Level 030709) 

• CTGCOMP 

• CTGPROC (Version 2.42, Level 030709) 

• MAKEGEO (Version 2.22, Level 030709) 

Meteorological Preprocessors 

• SMERGE (Version 5.31a, Level 040706) 

• PXTRACT 

• PMERGE (Version 5.31, Level 030528) 

• READ62 (Version 5.52, Level 040716) 

Main Models 

• CALMET (Version 6.211, Level 060414) 

• CALPUFF (Version 6.112, Level 060412) 

Postprocessors 

• CALPOST (Version 6.131, Level 060410) 

• PRTMET 

The version and level identifiers for the major modules used for this project are 

identified above. Electronic executable files for the primary modules and the primary 
Appendix B MSCC 2/6/2012 Section114 Request 

Visibility Modeling Report Page B-4 

electronic input and output files associated with this analysis are available upon request 

from Bison Engineering, Inc. 
Appendix B MSCC 2/6/2012 Section114 Request 

Visibility Modeling Report Page B-5 

3.0 CALMET 

CALMET, the meteorological preprocessor for CALPUFF, was used to compile and 

process land use data, terrain data, and meteorological data for use in the CALPUFF 

model. The CALMET output files define gridded fields of wind speed, wind direction, 

mixing heights, stabilities, micrometeorological parameters, and precipitation – all 

parameters required for input to the CALPUFF dispersion model. The following sections 

provide a brief description of each of these data sets. The CALMET input files are 

provided on the portable hard drives that accompany this dispersion modeling report. 

3.1 Land Use Data 

CALMET uses specific land use data developed by the U.S. Geological Survey (USGS) 

[available for download from the USGS Earth Resources Observation and Science 

(EROS) web site]. The data files used by this project are 1:250,000-scale files. Each 

land use cell, typically 200 meters square, is assigned a land use code by USGS. 

3.2 Terrain Data 

CALMET uses USGS 1:250k Digital Elevation Models (DEMs) to determine the terrain 

elevation in the model domain. The terrain data are preprocessed into a data set 

recognizable by CALMET and used to help create the CALMET output file. 

3.3 Meteorological Data 

CALMET output files representing meteorological data for the 2001, 2002, and 2003 

calendar years were prepared for this analysis. The input surface and upper air 

meteorological data and the Mesoscale Model version 5 (MM5) data (processed with 

the CALMM5 processor) are those data sets used for the Montana Best Available 

Retrofit Technology (BART) modeling conducted by EPA. 

3.3.1 Mesoscale Model Data 

The MM5 meteorological data for the 2001, 2002, and 2003 calendar years were 

obtained from the Western Regional Air Partnership (WRAP) web site at 

http://pah.cert.ucr.edu/aqm/308/bart.shtml. These data are generated by the CALMM5 

processor from MM5 mesoscale meteorological model output files. The CALMM5 data 

have a spatial resolution of 36 kilometers. The mesoscale models are limited-area, 

nonhydrostatic or hydrostatic, terrain-following sigma-coordinate models designed to 

simulate or predict mesoscale and regional-scale atmospheric circulation. The data are 

used as a basis for generating an “initial guess field” of multilayer meteorological 

parameters in CALMET. 
Appendix B MSCC 2/6/2012 Section114 Request 

Visibility Modeling Report Page B-6 

3.3.2 Surface Data 

Hourly surface meteorological data for 2001, 2002, and 2003 also were obtained from 

the WRAP internet site. This data set includes data from 39 locations for 2001 and 36 

locations for 2002 and 2003. The WRAP data are in the SMERGE format and are ready 

for input into CALMET Version 6. The data have been manually converted for use with 

CALMET Version 5.8 (involving only minor changes to the header records in the data 

files). 

Surface data from the following locations were used in the CALMET analysis: 

• Badger Peak, MT (2001 only) 

• Billings, MT 

• Bismarck, ND 

• Boise, ID 

• Bozeman, MT 

• Butte, MT 

• Casper, WY 

• Coeur d’Alene, ID 

• Cut Bank, MT 

• Dickinson, ND 

• Dillon, MT 

• Estevan, SK 

• Havre, MT 

• Kalispell, MT 

• Garfield Peak, MT (2001 only) 

• Glacier National Park, MT 

• Glasgow, MT 

• Great Falls, MT 

• Helena, MT 

• Havre, MT 

• Lander, WY 

• Lewistown, MT 

• Livingston, MT 

• Medicine Hat, AB 

• Miles City, MT 

• Minot, ND 

• Missoula, MT 

• Morningstar, MT (2001 only) 

• Peabody Coal, MT 

• Pocatello, ID 

• Rapid City, SD 

• Rexburg, ID 

• Riverton, WY 

• Salmon, ID 

• Sheridan, WY 

• Spokane, WA 

• Spring Creek Coal, MT 

• Theodore Roosevelt National 

Park, ND 

• Williston, ND 

• Yellowstone National Park, WY 
Appendix B MSCC 2/6/2012 Section114 Request 

Visibility Modeling Report Page B-7 

3.3.3 Upper Air Data 

Upper air rawinsonde data collected at seven National Weather Service (NWS) stations 

were obtained from the rawinsonde data repository maintained by the National Oceanic 

and Atmospheric Administration (NOAA) at http://esrl.noaa.gov/raobs/. The data were 

provided in the standard FSL data format for use in the CALMET system. The seven 

NWS upper air rawinsonde locations used for this project are: 

• Bismarck, ND 

• Boise, ID 

• Glasgow, MT 

• Great Falls, MT 

• Rapid City, SD 

• Riverton, WY 

• Spokane, WA 

3.3.4 Precipitation Data 

Hourly precipitation data in the National Climatic Data Center (NCDC) TD-3240 format 

were obtained from the data set developed by the Montana Department of 

Environmental Quality (MDEQ) for their BART modeling analysis effort. All precipitation 

stations located within the CALMET modeling domain were extracted from the data set 

and used in the CALMET analysis. A total of 286 stations were selected for each of the 

three modeled years. A complete list of precipitation stations is included in the CALMET 

input files. 

3.4 CALMET Technical Options 

The CALMET meteorological processor was executed using the technical options 

recommended in the EPA/IWAQM guidance, the EPA Model Clearinghouse 

memorandum of May 15, 2009, and the EPA-Federal Land Managers (FLM) Model 

Clearinghouse clarification memorandum of August 31, 2009. A table of the values used 

is available upon request. 
Appendix B MSCC 2/6/2012 Section114 Request 

Visibility Modeling Report Page B-8 

4.0 CALPUFF 

4.1 CALPUFF Technical Options 

CALPUFF applies mathematical algorithms to calculate pollutant concentrations at 

specified receptor locations. CALPUFF’s output files contain concentration values for 

every receptor and every hour modeled. These output files must be processed through 

CALPOST to evaluate model results against regulatory limits or guideline thresholds. 

CALPUFF requires inputs of CALMET data files, source characteristics and emission 

rates, and receptor grids to model impacts. 

For brevity, a complete list of the technical options chosen for this modeling exercise is 

not presented. As noted earlier, the same options used for the Montana BART analyses 

were used here as well. A copy of the technical options along with all other input and 

output files are available on request. 

4.2 Receptors 

The receptors chosen for this modeling were those of the nearby mandatory Class I 

areas. The mandatory Class I areas chosen were: 

• Gates of the Mountain Wilderness 

• UL Bend Wildlife Wilderness Area 

• North Absaroka Wilderness 

• Yellowstone National Park 

These four areas represent the closest areas to the facility and also display a relatively 

wide range in direction from the plant. The nearest of these areas is approximately 120 

kilometers from MSCC’s location at Lockwood, Montana. Figure B-1 below shows the 

relative distance from the MSCC facility. 

The specific receptors used for the runs are the same as those generated by the federal 

land managers and used in the prior BART analyses. The exact receptor locations are 

not presented here to keep this report brief. 
Appendix B MSCC 2/6/2012 Section114 Request 

Visibility Modeling Report Page B-9 

Figure B-1: Class I Locations and Distances 3

MSCC

UL Bend

Yellowstone National Park

North Absaroka

Gates of the Mountain

120 Kilometers

4.3 Modeled Sources and Emission Rates 

The modeled source for this analysis was the MSCC facility in Billings, Montana. 

Emissions from the Sulphur Recovery Unit (SRU) vent to a 100-meter stack. In very 

rare cases, emissions from the SRU will be routed to a 30-meter stack, but this is 

uncommon. Certain low sulfur emissions are permitted from the 30-meter stack, 

although such emissions are rare and have not occurred since before 1998. 

 

3

 Map obtained from: 

http://wrapfets.org/map.cfm?StartDate=02%2F04%2F2012&EndDate=02%2F04%2F2012&SumSelector=

V2MapXMLEvents.cfm&view=Lower48&vMapZoom=7&vMapCenterLat=45.85176&vMapCenterLon=-

109.127197265625&StartDateObj=&EndDateObj=&vMapType=Terrain&clust=&full_submit=Submit&tribe

=on&class1=on 
Appendix B MSCC 2/6/2012 Section114 Request 

Visibility Modeling Report Page B-10 

The emission rate for this analysis was based on (approximately) the average emission 

rate of 2008 through 2010, the most recent reporting years.4

 Additional modeling was 

conducted using arbitrarily lower emission rates (50% and 99.9% reduction to SO2) that 

were based on control option analyses contained in this report so that an estimate could 

be made of the impact a specific option could have on the nearest mandatory Class I 

areas.5

 

The baseline emission rates6 used in the model are shown in the table below. 

Table B-1: Modeled Emission Rates 

SO2

(tpy) 

NOx 

(tpy) 

PM10 

(tpy) 

1,452 4.1 0.47 

 

4

 The BART analysis (40 CFR 51, Appendix Y) used emission years from early 2000. It was decided to 

use the two most recent years of data as a better representation of impacts. 

5

 For reference, the nearest mandatory Class I area is about 120 kilometers from the plant. 

6

 Baseline means the emission rate (as discussed in footnote 4 above) and does not include the effect of 

the control options discussed elsewhere in this document. 
Appendix B MSCC 2/6/2012 Section114 Request 

Visibility Modeling Report Page B-11 

5.0 CALPOST CLASS I VISIBILITY ASSESSMENT 

Visibility impacts (expressed in terms of percentage change in 24-hour average 

background extinction relative to natural background visibility) were calculated using 

the CALPUFF modeling system and data. The analysis was conducted using 

concentration files produced by CALPUFF and CALSUM. The visibility assessment is 

based solely on the MSCC facility. 

 

The methods recommended in the BART program were followed in the visibility 

analyses. CALPOST Version 6.131, Level 060410 was used in these analyses. The 

technical options employed in the CALPOST analyses are not presented here for the 

sake of brevity. It is noted, however, that some visibility options are specific to the 

mandatory Class I area being evaluated. Those area-specific data were applied as 

appropriate. 
Appendix B MSCC 2/6/2012 Section114 Request 

Visibility Modeling Report Page B-12 

6.0 RESULTS 

6.1 Visibility Analysis 

The methodology for the visibility analysis portion of this project is the same as the 

methods used for the BART program discussed elsewhere in this appendix. The 

analysis is conducted by calculating concentrations of particulate, sulfate, nitrate and 

other compounds in the atmosphere from the modeled facility in question. The 

concentration of those compounds in the atmosphere is used to estimate changes to 

visibility that could occur. 

Impacts to natural background visibility, expressed in terms of percentage change in 

24-hour average background extinction (∆Bex) were calculated by CALPOST 

processor (an integral part of the CALPUFF modeling system). The BART guidelines 

also reference 40 CFR §51.301(a) in asserting that determinations must be made on 

a “...case-by-case basis taking into account the geographic extent, intensity, duration, 

frequency and time of visibility impairments....” In accordance with 40 CFR 51, 

Appendix Y, the 24-hour average 98th percentile impact results are summarized in 

the following table. 

To serve as a baseline, the table below shows the results of the CALPUFF modeling 

results. The data uses a baseline emission rate that approximates the 2008-2010 

average rate and assumes no additional controls as discussed in the main document. 

The emission rates were shown in Section 4.3 above.

Table B-2: Visibility Impacts: Baseline 2008-2010 Case

Class I Area Visibility 

(∆DV) 

% of a Discernible 

Change in Visibility 

% 

of a ‘de minimis’ 

Change in Visibility 

Yellowstone National Park 0.08 8% 16% 

UL Bend 0.14 14% 27% 

North Absaroka 0.10 10% 20% 

Gates of the Mountains 0.08 8% 16% 

The results of this analysis are revealing. The deciview values themselves represent 

the change in modeled visibility (∆DV) that could occur as a result of the facility as

currently operating. The values in the table are all below 0.5 deciview (see 

comparison in the last column). EPA has used this ‘threshold” value for some time as 

a measure and demonstration of a non-measurable or nil impact, for example in new 

source permitting. The modeling analysis has shown that current emission rates also 

result in impacts well below the 1.0 deciview level (see column 3) EPA also employs 

as a level to indicate that a source causes a visibility impact, and are also below the 
Appendix B MSCC 2/6/2012 Section114 Request 

Visibility Modeling Report Page B-13 

0.5 deciview level that EPA has proposed as the level at which even a new source 

may contribute to a visibility impact. According to general guidance, if a facility’s 

impact, by itself, is less than 0.5 dv, then the facility’s impact is de minimis. 

Since the impact predicted from this facility, without the consideration of additional 

reduction or controls, is de minimis, then clearly the addition of additional controls 

contributes nothing toward the national goal or toward reasonable progress. Since the 

addition of controls does not create any “progress” toward the national goal, no 

additional controls at MSCC constitute “reasonable progress.” 

As a matter of interest, it was decided to provide an estimate of the improvement to 

visibility, regardless how small, that would be expected to occur, based on the model, 

as a result of reducing emissions beyond their current baseline level. Since a 

particular strategy is not up for discussion, it was decided to execute the model using 

a 50% and 99.9% reduction of SO2. These two values, coupled with the base case, 

made it possible to estimate visibility impacts from any number of possible emissions 

scenarios.7 These reductions are consistent with the lower end and highest 

reductions from SO2 controls (e.g., Flue Gas Desulfurization and Shell Claus Off-Gas 

Treatment). 

The results of the modeling are shown in the tables below. 

Table B-3: Visibility Impacts: 50% Reduction SO2

Class I Area 

Visibility (∆DV) 

Baseline 

After 

50% 

Reduction 

“Improvement” 

to Visibility 

“Improvement” 

Discernible or 

Greater than 

De Minimis? 

Yellowstone National Park 0.08 0.04 0.04 No 

UL Bend 0.14 0.07 0.07 No 

North Absaroka 0.10 0.05 0.05 No 

Gates of the Mountains 0.08 0.04 0.04 No 

 

7

 It is known, a priori, that the model provides a linear relationship between emissions and ambient 

(visibility) impact; provided that there is only one source, stack parameters remain constant, and other 

visibility pollutants (NOx and particulate) are zero or near zero. All of the above conditions are met for 

this analysis. The modeling that was done here provides empirical evidence that such is the case. The 

results, presented below, showed a straight-line (linear) impact. These results were then used to 

determine visibility impacts from a particular scenario (specific equipment such as Scot). 
Appendix B MSCC 2/6/2012 Section114 Request 

Visibility Modeling Report Page B-14 

Table B-4: Visibility Impacts: 99.9% Reduction SO2

Class I Area 

Visibility (∆DV) 

Baseline 99.9% 

Reduction8

“Improvement” 

to Visibility 

Improvement” 

Discernible or 

Greater than 

De Minimis? 

Yellowstone National Park 0.080 0.000 0.080 No 

UL Bend 0.14 0.001 0.14 No 

North Absaroka 0.10 0.001 0.10 No 

Gates of the Mountains 0.08 0.000 0.08 No 

The results of these model runs (which do not relate to any particular equipment 

under consideration in the body of this report) show a linear relationship between the 

SO2 emission rate and visibility impacts. Appendix A contains a graphic showing the 

relationship between SO2 and visibility. 

The above analysis makes three conclusions clear: 

(i) The emissions from the MSCC facility, as configured, lead to no predicted 

(or otherwise observed) visibility impacts at any nearby Mandatory Class I 

areas. 

(ii) The addition of emission controls at MSCC would lead to no humanly 

perceptible improvement in visibility (regional haze) at any of the nearby 

Mandatory Class I areas. 

(iii) The modeling and graphic illustrate the expected linearity of the 

subliminal (imperceptible) modeled effects. 

To complete the discussion, the table below has been created to compare the 

modeled visibility impact of the MSCC facility in a range of emission scenarios 

including allowable, actual and with additional controls. The table shows that the 

MSCC facility in any configuration does not yield a discernible impact on the 

mandatory Class I areas. In addition, all of the scenarios show an impact below ‘de 

minimis.’ 

 

8

 The 98th percentile value for Yellowstone National Park and the Gates of the Mountains was below 

the reporting algorithms of the model. This means that the predicted visibility impact at the Park would 

be less than 0.0005 deciviews. 
Appendix B MSCC 2/6/2012 Section114 Request 

Visibility Modeling Report Page B-15 

Table B-5: Visibility Impacts: Multiple Scenarios

Class I Area 

Emission Scenarios 

Allowable 

(FIP & Permit) 

Actual 

(2008 – 2010) 

50% 

Reduction in 

Actuals 

90% 

Reduction in 

Actuals 

Yellowstone National Park 0.25 0.08 0.04 0.01 

UL Bend 0.43 0.14 0.07 0.01 

North Absaroka 0.31 0.10 0.05 0.01 

Gates of the Mountains 0,24 0.08 0.04 0.01 

Units: Deciviews (∆DV) – reported to 2 decimals 

Note: All values are less than discernible visibility impacts and all values are 

less than 0.5, the de facto ‘de minimis’ value for an impact on a mandatory 

Class I area. 

Therefore, the only logical and reasonable conclusion for this report is that existing 

controls and emission limitations are sufficient, and no additional emission controls or 

restrictions at this facility are justified based on reasonable progress or the national 

goal of improved visibility at Class I areas.