1 Reasonable Progress (RP) Four-Factor Analysis of Co ntrol Options

For Montana Sulphur & Chemical Company in Billings, Mon tana

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 Sul fur Equivalent

2 Super Claus Installed: 1998, 2008 Maximum Unit Capacity: 170 Long Tons of Sul fur Equivalent (each unit)

MSCC receives sulfur-containing fuel gases from Exx on 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 t he refinery, serves to reduce sulfur oxide emissions that might otherwise be emitted to the at mosphere from the disposal of this material at the oil refinery site.

At MSCC, acid gases are processed in a multistage C laus 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 tailg ases by selective partial oxidation and controls emissions of sulfur dioxide (SO2) to assis t 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, marketa ble 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 sulfat es.

Current sulfur removal efficiency is approximately 98.5%

Reasonable Progress Evaluation of SO2 Emissions

Step 1: Identify All Available Technologies2

Several techniques can be used to reduce SO 2 emissions from tail gases. The following technologies are available control technologies for SO 2 tailgas treatment:

a. Tail Gas Scrubbing

b. Extending the Claus reaction into a lower temperatu re 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 w here 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 eve r, 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 incin erator 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 rege nerated to sodium sulfite in a steam-energized evaporator. The concentrated wet SO2 gas stream fro m the evaporator is partially condensed and some of the liquid water is used to dissolve sulfit e 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 o f 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, sensi tivity to components in the gas (particulates, HCl, and SO3), metals attrition, and the requiremen t 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, esp ecially in retrofit applications.

The reduction scrubber processes first require a hydrogenation step to convert sulfu r, SO2, and reduced compounds in the tailgas to H2S. T he tail gas must be pre-heated to reaction temperature, which varies with the catalys t employed. Preheating consumes fuel or steam energy. All sulfur compounds in the SRU ta ilgas except H2S (e.g., SO2, COS, CS2, and elemental sulfur) are reduced to H2S in th is step by using a catalyst and a reducing gas, such as hydrogen or water-gas. The ho t- 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, wher e the H2S gas is then cooled and processed (again) in the Claus process. The produced sour wat er (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) te chnologies were considered as part of this analysis. For a variety of reasons, these do not ap pear 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 forme d 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 b y-products from wet lime scrubbing are typically managed in dewatering ponds and landfills

Wet Limestone Scrubber

Wet limestone scrubbers are very similar to wet lim e 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 a pproximately 95% or greater. The actual control efficiency of a wet lime/limestone FGD syst em depends on several factors, including the uncontrolled SO2 concentration entering the scrubbe r: The higher the uncontrolled concentration, the higher the efficiency. Similar t o 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 sol ution 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 su lfites and sulfates are precipitated and discarded as sludge, and the regenerated alkaline s odium 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 general ly mean smaller scrubber units; however, additional regeneration and sludge processing equip ment is necessary. A sodium-based scrubbing solution, typically consisting of a mixtu re 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 gr eater. Once again, control efficiencies are highly dependent upon the uncontrolled SO2 concentr ation entering the scrubber.

Spray Dry Absorber4

The typical spray dry absorber (SDA) uses lime slur ry and water injected into a tower to remove SO2 from the combustion gases. The towers must be d esigned to provide adequate contact and residence time between the exhaust gas and the slur ry in order to produce a relatively dry byproduct. The process equipment associated with an S DA typically includes an alkaline storage tank, mixing and feed tanks, atomizer, spray chambe r, 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. S DAs are the commonly used dry scrubbing method in large industrial and utility boilerapplic ations and not on SRUs. SDAs have demonstrated the ability to achieve greaterthan 95% SO2 reduction. Once again, control efficiencies are highly dependent upon the uncontro lled SO2 concentration entering the scrubber, and fall off as the incoming concentration falls of f.

Dry Sorbent Injection

Dry sorbent injection involves the injection of pow dered or hydrated sorbent (typically alkaline) directly into the flue gas exhaust stream. Dry sorb ent injection systems are simple systems, and generally require a sorbent storage tank, feeding m echanism, transfer line and blower, and injection device. The dry sorbent is typically inje cted countercurrent to the gas flow through a venturi orifice. An expansion chamber is often loca ted downstream of the injection point to increase residence time and contact efficiency. Par ticulates generated in the reaction are controlled in a downstream particulate control devi ce.

SO2 control efficiencies for dry sorbent injection systems are approximately 50%, but if the sorbent is hydrated lime, then 80% or greater remov al can be achieved. These systems are commonly called lime spray dryers.

Circulating Dry Scrubber

The circulating dry scrubber (CDS), uses a circulat ing 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-prod uct produced by this system is routed with the flue gas to a particulate removal system. Mater ial 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. Approximat ely 2.5 pounds of waste are generated for each pound of SO2 removed.

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

Sulfreen® In the Sulfreen® process, the Claus reaction is ext ended at low temperatures (260 to 300oF) to recover SO2 and H2S in the tail gas. Tail gas passe s through one of three reactors on line at a given time. Two reactors are on either heating or c ooling 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 vap orized 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 regener ated catalyst bed must be cooled before going back on the gas stream. Sulfreen® systems reportedl y 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 ga s from the SRU is re-heated and mixed with a hydrogen-rich reducing gas stream. Heated tail ga s is treated using a catalytic reactor where the free sulfur, sulfur dioxide, and reduced sulfur com pounds 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 ro uted to a separate sour water system for treatment and disposal. The cooled quench system ga s effluent is then fed to an absorber section where the acidic gas comes in contact with a select ive 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 o r oxygen (e.g., unconverted SO2 or sulfur) that may arise during malfunctions. The rich soluti on is separately regenerated using steam,

cooled and returned to the scrubber/absorber. The H 2S-rich gas released at the regenerator is reprocessed by the SRU.

In certain applications, particularly newly designe d plants designed for use with Tail Gas Treatment, SCOT can reportedly achieve sulfur recov ery 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 gener ally used for particulate control. The EPA factsheet for SDA and DSI technologies also indicat es that they cannot be used for waste gas SO2 concentrations greater than 2,000 ppm 3 . Annual data provided by MSCC for 1998 -2011 show the average ppm of the tailgas ranges from app roximately 2,100 – 6,000 ppm. Due to this reasons, these technologies were not evaluated furt her.

The MSCC facility has a very limited area to instal l 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 Al kali Wet Scrubber) would require an onsite dewatering pond and landfill to process and di spose of scrubber sludge. Similarly, the Wellman-Lord scrubber also has significant space re quirements, 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 Cos t and Cost-Effectiveness, Assessment of Abatement Technology/Techniques for Refineries”. Li nk: http://www.citepa.org/forums/egtei/5-Whiterefin eries. pdf

2 From: http://www.gec.jp/JSIM_DATA/AIR/AIR_6/html/D oc_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/ffd g.pdf6

accept the assertion by MSCC that these technologie s are infeasible based on space limitations. These technologies are considered technically infea sible 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 gener ally used for particulate control. Because an additional PM control device is required, and becau se 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 temperatu re liquid phase (ECLT)

• Reduction Tail Gas Scrubbing (RTGS)

Step 3: Evaluate Control Effectiveness of Each Rema ining Technology

Sulfreen® can increase theoretical overall sulfur r emoval 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 dev eloped 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 (a pproximately) the average emission rate of 2009 and 2010, the most recent reporting years as o f the January 6 letter. The results of the analysis are presented in the Results section of th is report. Detailed estimates and supporting

information are attached.

Estimates by MSCC found the following Cost Effectiv eness: 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 efficienc y 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 y ears used by MSCC, with the resulting Cost

Effectiveness:

Control Option Total Annual Cost Cost Effectiveness7

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 (SC OT) would require careful planning in order to ensure that sulfur-rich gas streams from t he 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 i nterruptions. When the second system was installed in 2008, the time required was approximat ely 30 months without process interruptions. Installation of a more complex process can be expec ted 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 r epair. This could require multiple units and consecutive phases. Bison estimates the time necess ary to complete the modifications to the SRU to be 18 to 36 months, per unit installed. Installa tion 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 subs tantial additional energy to operate. Both systems require natural gas or fuel gas50 to heat t he Claus tail gas prior to entering a reducing reactor and/or for heating recycle gas for regenera tion requirements. Sulfreen® systems require electric power for operation of large regeneration blowers. Low-temperature based systems (either SCOT or Sulfreen®) also typically require a dditional fuel for reheat of the final tail gas for incineration prior to discharge. SCOT systems a lso require substantial electricity to operate numerous pumps, coolers, and a condenser. Additiona l power is required to provide relatively large amounts (compared to current) of cooling wate r. Additional fuel and power energy (and equipment) is required for processing of the n ew sour water waste continuously produced in the quench processes necessary for scrubbing. The l imited 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 l east) 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 38.18

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 sou r water waste effluent that requires treatment prior to disposal. This effluent would co ntain 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 pub lic sewer system to accommodate such a waste stream. A permissible solution to this problem woul d 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 substantial ly greater solid or liquid waste streams requiring treatment and disposal off site. All proc esses evaluated represent an increase in solid/liquid waste and energy consumption as compar ed with the current control option (SuperClaus).

Factor 4: Remaining Useful Life

The facility began operation in 1955, and has opera ted continuously since then. It is a privately held, family business, now operated by second-gener ation 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 oper ation, quality maintenance and continual improvements in reliability, this facility has exce eded 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 m aterial supply and gas processing. There is no way to assuredly predict if such contracts will con tinue or will cease. However, for purposes of planning, it would reasonable to assume that the fa cility, which remains serviceable, effective and reliable today, would continue to operate at le ast 15 years into the future.