1 

Reasonable Progress (RP) Four-Factor Analysis of Control Options 

For 

Montana Sulphur & Chemical Company in Billings, Montana 

I. Source Description 

 Owner/Operator: Montana Sulphur & Chemical Company

 Source Type: Sulfur Recovery Plant 

 RP Emission Sources: Claus 

 Installed: 1963 

 Maximum Unit Capacity: 252 Long Tons of Sulfur 

Equivalent 

 2 Super Claus 

 Installed: 1998, 2008 

 Maximum Unit Capacity: 170 Long Tons of Sulfur 

Equivalent (each unit) 

 

MSCC receives sulfur-containing fuel gases from Exxon and desulfurizes these gases in its 

amine unit and returns low-sulfur fuels back to the refinery. This action, along with the 

processing of directly delivering acid gases from the refinery, serves to reduce sulfur oxide 

emissions that might otherwise be emitted to the atmosphere from the disposal of this material at 

the oil refinery site. 

At MSCC, acid gases are processed in a multistage Claus Process and tail gas incinerator. In 

1998, MSCC installed a SuperClaus Process pursuant to provisions in the 1996 and 1998 

Stipulations with the Department regarding Emission Limiting Equipment (ELE). This 

SuperClaus process further desulfurizes Claus tailgases by selective partial oxidation and 

controls emissions of sulfur dioxide (SO2) to assist in compliance with emission limitations, with 

a redundant system added in 2008 . 

The main purpose of the facility is to convert the raw sulfur compound from fuel gases, acid 

gases and other materials to create useful, marketable products. MSCC has the capability to 

create many products including: low sulfur fuel gas, elemental sulfur, dry fertilizers, hydrogen 

gas, hydrogen sulfide, and carbon and sodium sulfates. 

Current sulfur removal efficiency is approximately 98.5% 

Reasonable Progress Evaluation of SO2 Emissions

Step 1: Identify All Available Technologies 
2 

Several techniques can be used to reduce SO2 emissions from tail gases. The following 

technologies are available control technologies for SO2 tailgas treatment: 

a. Tail Gas Scrubbing 

b. Extending the Claus reaction into a lower temperature liquid phase (ECLT) 

c. Reduction Tail Gas Scrubbing (RTGS) 

 

Tail Gas Scrubbing

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. 

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. Excess acid water must also be disposed of. W-L scrubber systems are complex and 

can also require significant area to construct, especially in retrofit applications. 

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. Preheating consumes fuel 

or steam energy. All sulfur compounds in the SRU tailgas except 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. 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. 

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: 
3 

• 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 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

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. 

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 sodiumbased 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. 

Spray Dry Absorber 
4 

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 byproduct. 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 boilerapplications and not on SRUs. SDAs have 

demonstrated the ability to achieve greaterthan 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. 

Circulating Dry Scrubber 

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. 

Extending the Claus reaction into a lower temperature liquid phase (ECLT) 

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, 
5 

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%1 sulfur 

recovery efficiency. 

Reduction Tail Gas Scrubbing (RTGS)

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%2

Step 2: Eliminate Technically Infeasible Options

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

device. Electrostatic precipitators (ESP) are generally used for particulate control. The EPA 

factsheet for SDA and DSI technologies also indicates that they cannot be used for waste gas 

SO2 concentrations greater than 2,000 ppm3. Annual data provided by MSCC for 1998 -2011 

show the average ppm of the tailgas ranges from approximately 2,100 – 6,000 ppm. Due to this 

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 onsite 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 situation, 

as well as a “purge stream” requiring disposal. EPA believes that this issue may be overcome in 

the future if unused or mothballed equipment at the facility is removed. However, EPA believes 

that requiring removal of this equipment is outside the scope of this determination and will 

 

1

 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 

2

 From: http://www.gec.jp/JSIM_DATA/AIR/AIR_6/html/Doc_142.html 

3

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

Dry Scrubbers, http://www.epa.gov/ttncatc1/dir1/ffdg.pdf 
6 

accept the assertion by MSCC that these technologies are infeasible based on space limitations. 

These technologies are considered technically infeasible and will not be evaluated further. 

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

device. Electrostatic precipitators (ESP) are generally used for particulate control. Because an 

additional PM control device is required, and because the CDS system is provides a lower level 

of control than currently in place, this technology will not be evaluated further. 

Remaining Technically Feasible Options

• Extending the Claus reaction into a lower temperature liquid phase (ECLT) 

• Reduction Tail Gas Scrubbing (RTGS) 

Step 3: Evaluate Control Effectiveness of Each Remaining Technology

Sulfreen® can increase theoretical overall sulfur removal efficiency to 99.5%. 

SCOT System can increase theoretical overall sulfur removal efficiency to 99.9% 

Step 4: Evaluate Factors and Present Determination 

Factor 1: Cost of Compliance

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 attached. 

Estimates by MSCC found the following Cost Effectiveness: 

Control Option Total Annual Cost Cost Effectiveness

Sulfreen $18,980,254 $39,215 

SCOT $18,824,971 $21,608 

EPA reran the numbers at a higher control efficiency closer to the theoretical removal efficiency 

(99.9% for the SCOT unit rather than 99.4% expected by MSCC) and at a Capital Recovery 

Factor using 7% at 20 years, instead of 10% at 10 years used by MSCC, with the resulting Cost 

Effectiveness: 

Control Option Total Annual Cost Cost Effectiveness
7 

SCOT $7,705,000 $5441 

EPA did not rerun Sulfreen as it is more expensive and less effective, so it will have a higher 

Cost Effectiveness than the SCOT unit. 

Factor 2: Time Necessary for Compliance

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 

Factor 3: Energy and Non-Air Quality Impacts

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. 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: 

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 
8 

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

Nitrogen Service 5 Nm3/h 1404 Nm3/h NA

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 increase in 

solid/liquid waste and energy consumption as compared with the current control option 

(SuperClaus). 

Factor 4: Remaining Useful Life

The facility began operation in 1955, and has operated continuously since then. It is a privately 

held, 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.