1 

Performance of the Boswell Energy Center Unit 3 

Environmental Improvement Project 

Paper #57 

Karen E. Burchardt, P.E. 

Burns & McDonnell, 9400 Ward Parkway, Kansas City, MO 64114 

Tom Coughlin, P.E. 

Minnesota Power, 30 W. Superior Street, Duluth, MN 55803 

ABSTRACT 

Minnesota Power’s Boswell Energy Center Unit 3 is the site of a recently-completed, full-scale, 

multi-pollutant control project in northeastern Minnesota. The goal of the project was to 

simultaneously implement air pollution controls to reduce emissions of sulfur dioxide (SO2), 

nitrogen oxides (NOx), and mercury from the 355-MW unit. This paper will describe the design 

and performance of the project, which includes the installation of a new Selective Catalytic 

Reduction (SCR) system, low NOx burners, overfire air, fabric filter baghouse, activated carbon 

injection, wet limestone Flue Gas Desulfurization (FGD) system, and induced draft (ID) fans. 

The installation of the new ash handling system and limestone handling system will also be 

discussed. Performance tests were performed in January and February 2010. The results of this 

testing will be discussed. 

INTRODUCTION 

Minnesota Power developed and undertook an air pollution control retrofit project at Unit 3 of 

the Boswell Energy Center in response to several air quality regulations and legislation that were 

being developed and implemented. Planning for the project began in 2004 with a study that 

evaluated current and developing regulations and legislation and their impact on Boswell Unit 3. 

The outcome of the study was a preliminary plan for complying with future regulations and 

legislation and an estimate of the cost of compliance. 

As the regulatory landscape of the 2004 timeframe became clearer, Minnesota Power decided to 

implement an air pollution control retrofit project at Boswell Unit 3. This project, called the 

Boswell Unit 3 Environmental Improvement Project, included the addition of the following 

equipment: 

• Low NOx burners and an overfire air system for NOx control 

• Selective Catalytic Reduction (SCR) system for NOx control 

• Wet Flue Gas Desulfurization (FGD) system for SO2 control 

• Fabric filter baghouse for particulate matter and mercury control 

• Activated carbon injection system for mercury control 

• Induced Draft (ID) fans, motors, and drives 
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This paper will describe the Boswell Unit 3 Environmental Improvement Project and some of the 

challenges that were overcome to complete the project. The results of the performance testing 

completed in January and February 2010 will also be discussed. 

DESCRIPTION OF UNIT 

Minnesota Power operates the Boswell Energy Center located in Cohasset in northeastern 

Minnesota. Boswell Unit 3 is a pulverized coal-fired, Combustion Engineering, TangentiallyFired Steam Generator put in service in 1973. Boswell Unit 3 is rated at 335 MW (net) and 355 

MW (gross) and fires a blend of coals from the Powder River Basin (PRB). 

Before undertaking the Environmental Improvement Project, Boswell Unit 3 employed Burner 

Out Of Service (BOOS) to simulate overfire air for NOx control and a single-stage wet 

particulate scrubber for particulate control. The wet particulate scrubber also achieved a small 

degree of SO2 control (approximately 25%). Boswell Unit 3 shares a chimney with Boswell 

Units 1 and 2. 

REGULATORY DRIVERS 

The main regulatory drivers for this project included the Clean Air Interstate Rule (CAIR), the 

Clean Air Mercury Rule (CAMR), the Regional Haze Rule, and the Minnesota Mercury 

Emissions Reduction Act (MMERA). Even though Boswell Unit 3 will no longer be impacted 

by the CAIR or CAMR, the unit may be subject to the rules that are being developed to replace 

the CAIR and CAMR. Minnesota Power anticipates that the air pollution control equipment 

installed as part of the Environmental Improvement Project will be needed to comply with the 

CAIR and CAMR replacement rules. 

Under the MMERA, Minnesota's largest coal-fired power plants are required to seek a goal of 

90% mercury emissions reduction by 2015. Under the timeline set by the MMERA, Boswell 

Unit 3 is required to retrofit mercury reduction technology by December 31, 2010. 

Boswell Unit 3 is also considered to be “BART-eligible” under the Regional Haze Rule. The 

state of Minnesota has not yet submitted a State Implementation Plan (SIP) for the Regional 

Haze Rule. However, if Boswell Unit 3 is found to impact visibility in a Federal Class I area, the 

unit may be required to install Best Available Retrofit Technology (BART) to reduce its 

emissions of visibility-impairing pollutants (SO2, NOx or PM10). 

The CAIR was designed to address interstate transport of SO2 and NOx, which are precursors to 

ozone (O3) and PM2.5. The CAIR sets state-wide budgets for annual SO2 and NOx emissions, as 

well as ozone-season NOx emissions in 28 eastern states and the District of Columbia. The state 

of Minnesota was only subject to the annual SO2 and NOx emission budgets. The CAMR 

established a nationwide cap-and-trade program for mercury emissions. The CAMR set statewide annual mercury emission budgets for each state and the District of Columbia. Electric 

Generating Units (EGUs) that are over 25 megawatts (MW) and fire coal or oil were required to 

hold mercury allowances to cover their emissions. 
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Both the CAIR and CAMR were promulgated in May 2005, about nine months before the 

engineering kickoff of the Boswell Unit 3 Environmental Improvement Project. However, both 

of these regulations were vacated by the courts in 2008, in the middle of the project construction 

period. The CAIR was subsequently remanded back to the Environmental Protection Agency 

(EPA) without vacatur. The CAIR is still in effect until EPA finalizes a new interstate transport 

rule to address the court’s issues. However, on November 3, 2009, the EPA issued a final 

administrative stay of the CAIR and CAIR Federal Implementation Plan (FIP) for Minnesota. 

Therefore, the remanded CAIR does not apply to the state of Minnesota. 

Even though the CAMR has been vacated and the remanded CAIR does not apply to sources in 

the state of Minnesota, the EPA is currently working on replacements for these rules. On July 6, 

2010, the EPA proposed a Clean Air Transport Rule (CATR) to replace the CAIR. The proposed 

rule establishes a state-wide annual SO2 and NOx budget for the state of Minnesota. The CATR 

is expected to be finalized by June 2011. 

Because the CAMR was rescinded, the EPA is now required to develop a Maximum Achievable 

Control Technology (MACT) standard for EGUs under Section 112 of the Clean Air Act (CAA). 

Per consent decree, the EPA must propose the MACT standard by March 16, 2011 and finalize 

the standard by November 16, 2011. Compliance for existing units will be required within 3 

years after the MACT is finalized. 

DESCRIPTION OF PROJECT 

The objective of the Boswell Unit 3 Environmental Improvement Project was to install air 

pollution control equipment to significantly reduce SO2, NOx, mercury emissions and comply 

with future regulations by 2010. The Boswell Unit 3 Environmental Improvement Project 

included the addition of the following equipment: 

• Low NOx burners and an overfire air system for NOx control 

• Selective Catalytic Reduction (SCR) system for NOx control 

• Wet Flue Gas Desulfurization (FGD) system for SO2 control 

• Fabric filter baghouse for particulate matter and mercury control 

• Activated carbon injection system for mercury control 

• ID fans, motors, and drives 

The low NOx burners and overfire air system were provided by Alstom Power, Inc. Hitachi 

Power Systems America provided the SCR system, FGD system, and all ductwork from the 

economizer outlet to the chimney inlet. The wet FGD system provided uses the limestone, 

forced-oxidation process. The fabric filter baghouse was provided by Hamon Research-Cottrell. 

The activated carbon injection system was also provided by Hamon Research-Cottrell through a 

subcontractor, ADA-ES. New ID fans were provided by Flakt-Woods. The new ID fan motors 

and Variable Frequency Drives (VFDs) were provided by ABB, Inc. 

Additional equipment was also added to support the main air pollution control equipment, 

including: 

• Aqueous ammonia storage system 
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• Limestone handling and preparation system 

• Fly ash handling and storage system 

Boswell Unit 4 currently operates a venturi scrubber for particulate control and spray tower 

absorber for SO2 control. The Boswell Unit 4 scrubber was originally designed to use lime as a 

reagent. However, the target SO2 removal can be met using just the fly ash collected in the 

venturi scrubber as a reagent in the spray tower absorber. The Boswell Unit 4 lime storage, 

handling, and preparation system was commissioned, but has not been used since the original 

performance tests were completed. As part of the Boswell Unit 3 Environmental Improvement 

Project, the existing lime storage, handling, and preparation system was modified for the 

limestone to be used in the Boswell Unit 3 FGD system. 

The Boswell Unit 3 FGD system uses powdered limestone sized at 95% passing a 325 mesh 

screen that is delivered to the site by truck. Truck-mounted blowers are used to pneumatically 

convey the limestone from the trucks to a large existing lime storage silo. Modifications were 

made to the existing lime storage silo, including new fluidizing air blowers, a new aeration 

system, a new rotary feeder on the outlet of the silo, and a new bin vent filter. The limestone is 

then transferred pneumatically by a new pressure blower system into existing day silos. Existing 

transfer lines also allow trucks to unload directly to the existing day silos. Modifications were 

made to two existing day bin storage silos, including new bin vent filters, new fluidizing air 

blowers, a new aeration system, new air cone hoppers, and new surge (lock) hoppers. The day 

silos discharge the powdered limestone to a new Vacucam Ejector Mixer where the powdered 

limestone is mixed with water to achieve a slurry of approximately 30% solids by weight. The 

limestone slurry is then discharged to a new limestone slurry storage tank. The limestone slurry 

is then pumped to the Boswell Unit 3 FGD reaction tank. 

The Boswell Unit 3 Environmental Improvement Project also included the addition of many new 

equipment enclosures. The cold climate of northern Minnesota required that much of the new 

equipment be enclosed to allow for maintenance activities and reliable operation. New FGD and 

ID fan buildings were constructed as part of the Boswell Unit 3 project. The fabric filter hoppers 

and penthouse were enclosed. A new enclosure was also installed for the SCR system ammonia 

flow control unit (AFCU). 

Performance Targets 

The Boswell Energy Center air permit was updated to reflect the air pollution control equipment 

to be installed as part of the Boswell Unit 3 Environmental Improvement Project. In the updated 

air permit, emissions from Boswell Unit 3 are limited to the following: 

• NOx: 0.07 lb/mmBtu at the stack (30-day rolling average) 

• SO2: 0.09 lb/mmBtu (30-day rolling average) 

• PM10 (filterable): 0.014 lb/mmBtu 

• PM10 (filterable plus condensible): 0.035 lb/mmBtu 

• Opacity: 20% (6-minute average) 

• HF: 0.0018 lb/mmBtu 

• CO: 0.15 lb/mmBtu (24-hour rolling average) 
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In order to meet the emission limits in the air permit, as well as future air pollution control 

regulations, the air pollution equipment installed at Boswell Unit 3 has the following design 

emission rates: 

• NOx: 0.18 lb/mmBtu at 100% load at the economizer outlet (design ranges from 0.18 to 0.25 

lb/mmBtu, depending on load) 

• CO: 200 ppm corrected to 3% O2 at the economizer outlet 

• NOx: 0.05 lb/mmBtu at the outlet of the SCR reactor 

• Ammonia (NH3) slip: 2 ppmvd corrected to 3% O2 at the outlet of the SCR reactor 

• SO2 to SO3 oxidation across the SCR reactor: 3.1% 

• SO2: 98% removal across the FGD absorber 

• HF: 90% removal across the FGD absorber 

• HCl: 95% removal across the FGD absorber 

• H2SO4: 25% removal across the FGD absorber 

• PM10: 0.012 lb/mmBtu (filterable), at the outlet of the fabric filter baghouse 

• PM10: 0.08 lb/mmBtu (filterable plus condensible) at the outlet of the FGD absorber 

• Opacity: 5.0% at the outlet of the fabric filter baghouse 

• Mercury (total): 90% removal across the entire air pollution control system (measured in the 

stack compared to inlet coal data) 

• Mercury (oxidized): 70% removal across the FGD absorber 

Schedule 

The Boswell Unit 3 Environmental Improvement Project was executed on a very tight schedule. 

Multiple systems and pieces of equipment had to be specified, purchased, and installed in a fouryear timeframe. The schedule for the Boswell Unit 3 project is listed in Table 1. 

Table 1. Boswell Unit 3 Project Schedule. 

Activity Timeframe 

Engineering kickoff February 2006 

Main equipment contracts in place: 

 SCR, FGD, ductwork December 2006 

 Baghouse, SI system December 2006 

 ID fans March 2007 

Construction: 

 SCR October 2007 – October 2008 

 FGD March 2008 – July 2009 

 Baghouse April 2008 – April 2009 

Unit outage (equipment tie-in) August – November 2009 

Start-up November – December 2009 

Performance testing January – February 2010 

 
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PROJECT CHALLENGES 

There were several challenges associated with the Boswell Unit 3 Environmental Improvement 

Project. The main project challenges that will be discussed further in this paper include the 

limited site space, the installation of the SCR reactor and support truss, the tight project schedule, 

the need to construct a new utility bridge, the upgrade of the existing auxiliary power system, 

and the design of the waste slurry disposal system. 

Limited Site Space 

The Boswell Energy Center is adjacent to the Blackwater Lake. The plant is oriented from south 

to north, with Boswell Unit 1 being the southernmost unit and Boswell Unit 4 being the 

northernmost unit. Blackwater Lake bounds the plant on the west, and the plant switchyard 

bounds the plant to the east. The existing wet particulate scrubber on Boswell Unit 3 lies to the 

west of the boiler, towards Blackwater Lake. 

The new air pollution control equipment to be added to Boswell Unit 3 was constructed to the 

west of the existing boiler. The existing particulate scrubber needed to remain in operation until 

the new air pollution control equipment was commissioned. Because of the large footprint of the 

new equipment, and because the existing particulate scrubber could not be demolished, some of 

the Blackwater Lake needed to be reclaimed in order to make space for the new equipment. The 

total area reclaimed was limited to three (3) acres, and the total area of wetlands impacted was 

limited to one (1) acre due to regulatory and permitting constraints. The amount of lake to be 

reclaimed was minimized by installing a sheet pile wall. Some of the Blackwater Lake was 

filled in, and then the sheet piling was installed. Backfilling behind the sheet piling was then 

done, and the new air pollution control equipment was constructed on the reclaimed land. 

Due to the site constraints, the foundation for the fabric filter baghouse was installed early in the 

project. This foundation then served to support the crane used to erect the SCR reactor and 

support structural steel. The installation of the fabric filter baghouse was delayed until the 

installation of the SCR reactor and support structural steel was complete and the crane was 

moved. The fabric filter baghouse compartments were pre-assembled in the construction 

laydown area while the SCR reactor and support structural steel were being erected. The fabric 

filter baghouse compartments were then transported to the fabric filter baghouse foundation to 

complete the fabric filter baghouse erection. 

Another challenge associated with the limited space available for the new equipment was that the 

new FGD absorber building footprint had to be minimized. The absorber building had to be 

arranged and sized even before detailed drawings of all miscellaneous skids were available. This 

made designing for maintenance access difficult. 

Installation of SCR Reactor and Support Truss 

The installation of the SCR reactor and support steel posed a particular challenge in the Boswell 

Unit 3 Environmental Improvement Project. Due to site constraints discussed previously, the 

SCR reactor was located above the existing particulate scrubber building instead of at-grade. 

The existing particulate scrubber building was not designed to handle the additional weight of 
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the SCR reactor. Therefore, the SCR reactor is supported by a 160-foot long structural steel truss 

that spans the existing particulate scrubber building. 

The SCR support truss is supported by new foundations on either side of the existing particulate 

scrubber building. The soil near the existing building was found to be highly compressive, so 

large foundations were needed. This also required that existing underground utilities be rerouted. Early investigations found settling near existing structures from the installation of other 

foundations. In order to avoid exacerbating this settling, pressure-grouted augercast piles were 

used instead of conventional displacement piles. Pile installation was limited to seven (7) 

months of the year due to the cold climate in northern Minnesota. 

As discussed above, a single large crane was used to erect the SCR reactor and support steel. In 

order to maintain access to the existing particulate scrubber, which remained in operation during 

construction of the new equipment, the crane could only be placed to the north of the job site. 

As the crane could only be located on one side of existing particulate scrubber building, a larger 

crane was needed to lift material over to the other side of the building. This crane was placed on 

the fabric filter baghouse foundation as discussed previously, as a deep foundation was needed 

for such a large crane. The design of the fabric filter baghouse foundation took into account the 

loads from the crane. 

Tight Schedule 

Another challenge faced in the Boswell Unit 3 Environmental Improvement Project was the tight 

project schedule. In a timeframe of four (4) years, many pieces of equipment and air pollution 

control systems were engineered, procured, delivered, installed, and tested in a relatively small 

space. Because of the limited space available, all construction activities had to be highly 

coordinated. There were multiple teams of contractors on site at any given time during the 

construction period, making this coordination even more challenging and important. Winter 

construction in northern Minnesota was another factor to consider in the schedule. 

In order to support the tight project schedule, the design of the foundations was performed early 

in the project. All of the construction work was organized into “work packages.” Once 

engineering and design was complete on a certain part of the project, a work package was issued 

to expedite construction. In other words, the construction phase of the project was not delayed 

until all engineering was complete. Minnesota Power established relationships with several key 

contractors who worked on a time-and-material basis to construct work packages as they were 

released. 

Construction of New Utility Bridge 

In order to support the new air pollution control equipment being installed, a new utility bridge 

was needed. The utility bridge was designed to hold piping for fly ash, FGD waste slurry, pond 

reclaim water, and service water. The new utility bridge runs from the main plant site out to the 

fly ash storage pond. 

Fly ash collected by the fabric filter baghouse is transported by a new pressure system to a new 

fly ash storage silo near the existing Unit 3 fly ash pond. The fly ash is then conditioned with 
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service water or cooling tower blowdown in pug mill mixers located below the ash silo. The 

conditioned fly ash is then loaded into open haul trucks for disposal near the existing ash ponds. 

The new utility bridge was designed to support the fly ash piping from the fabric filter baghouse 

to the new storage silo as well as the piping for service water and cooling tower blowdown 

needed in the pugmill. 

The FGD waste slurry stream is transferred to hydrocyclones for primary dewatering. The 

hydroclone underflow is transferred to the existing Boswell Unit 3 fly ash pond for disposal. 

Reclaim water from the Boswell Unit 3 fly ash pond is used as a source of blend water for the 

waste slurry stream to maintain the required velocity in the waste slurry pipeline and mitigate 

solid settling issues. The new utility bridge was designed to support the waste slurry piping and 

reclaim water line. 

In order to construct the new utility bridge across the lake, temporary fill was placed in the lake. 

The temporary fill provided construction access for installing pile foundations and constructing 

the new utility bridge. Construction on the new utility bridge started in August 2008. However, 

the temporary fill had to be removed by December 2008 due to permitting requirements. The 

size of the utility bridge had to be minimized. However, future expanded use for additional 

utilities had to be considered in the design. 

Upgrade of the Auxiliary Power System 

In order to handle the electrical loads of the new air pollution control equipment, the existing 

Boswell Unit 3 auxiliary power system required additional capacity. This required the existing 

auxiliary transformer to be replaced by not one, but two larger transformers. Other electrical 

equipment was also required for this upgrade including a generator circuit breaker, medium 

voltage switchgear, additional lengths of isolated-phase bus (isophase bus) and new medium 

voltage non-segregated bus. 

Several challenges were presented to the design and construction teams. These included a tight 

schedule as this work was critical path, work below the existing high-voltage lines (sometimes 

energized), accommodating support structures and foundations for the equipment in very tight 

spaces, and replacement of the existing medium-voltage switchgear with new switchgear. All of 

this work had to be performed during either very short outages or while the plant was in 

operation. 

Waste Slurry Handling 

Early in the development of the Boswell Unit 3 Environmental Improvement Project, Minnesota 

Power decided that the waste slurry from the FGD system would be sent to the Boswell Unit 3 

fly ash pond for disposal. Minnesota Power decided that the waste slurry would not go through 

secondary dewatering due to the cost and footprint required for a secondary dewatering facility 

and the lack of a local market for the resulting gypsum byproduct. 

The updated National Pollutant Discharge Elimination System (NPDES) permit for the Boswell 

plant eliminated the outfall from the Boswell Unit 3 fly ash pond. This caused concerns about 

the life of the pond. In order to preserve as much pond life as possible, the Boswell Unit 3 
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Environmental Improvement Project incorporated water reclaimed from the pond. Also, the 

amount of water sent out to the Boswell Unit 3 fly ash pond was minimized. 

New slurry transfer pumps transfer the waste slurry in an above grade line from the waste slurry 

tank to the fly ash pond, a distance over a mile long. During the winter months the slurry line 

may be susceptible to freezing. Two different methods were evaluated to prevent the slurry line 

from freezing. The first method evaluated was a batch process in which waste slurry is stored in 

the waste slurry tank. When the level in the waste slurry tank reaches a predetermined level, the 

transfer pumps would pump the slurry to the Boswell Unit 3 fly ash pond. Once the waste slurry 

tank reaches the tank low level, the transfer pumps would be stopped and the piping system 

would be flushed with clean water to prevent the slurry from settling in the pipe. The pipeline 

would be required to have heat tracing and insulation to prevent the flush water left in the line 

between batches from freezing. Failure of the heat tracing system during freezing conditions 

could lead to a forced unit outage. Because of this, the batch process was eliminated from 

further consideration. 

The second method evaluated (and ultimately implemented) was to maintain a constant flow of 

waste slurry to the Boswell Unit 3 fly ash pond. The constant flow of slurry is designed to keep 

the line from freezing even at the lowest design temperature of -51 °F. However, the rate of 

hydroclone underflow generation varies with the unit operation and coal characteristics. No 

single size of pipe could be selected and still maintain the required slurry velocities of 7 ft/s to 10 

ft/s to prevent freezing in the line. It was determined that a flow of 80 gallons/minute in a two 

(2) inch pipeline would transfer the slurry at an adequate velocity and also meet the water 

balance requirements of the system. Blend water from the cooling tower blowdown and/or 

reclaim water from the Boswell Unit 3 fly ash pond is needed to achieve an adequate velocity in 

the pipeline. 

Reclaimed water from the Unit 3 fly ash pond is used as a source of blend water for the waste 

slurry transfer system. The pond reclaim is pumped back to the waste slurry tank only during the 

summer months, since the line could possibly freeze during the winter without heat tracing and 

insulation. The cooling tower blowdown will be used during the winter months for the waste 

slurry tank make-up water since the line is underground and there is no concern that the line will 

freeze. 

PERFORMANCE RESULTS 

Emissions testing was performed in January and February 2010 to determine if the FGD system, 

SCR system, fabric filter baghouse, and activated carbon injection systems were meeting their 

design performance. The following discussion summarizes the emissions tests that were 

performed, as well as the results of the performance tests. 

FGD Performance Testing 

Emissions of the following pollutants were measured at the inlet and outlet of the new FGD 

absorber: SO2, PM10 (filterable and filterable plus condensible), oxidized mercury, HCl, HF, and 

H2SO4. Emission measurements at the FGD inlet and outlet were used to determine removal 

efficiency across the FGD absorber. 
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SO2 emissions were measured at the inlet and outlet of the FGD absorber using EPA Method 6C. 

Three test runs were conducted. In each test run, SO2 emissions at the inlet and outlet of the 

FGD absorber were measured simultaneously. During each test run, over 99% SO2 removal was 

achieved, which is above the design SO2 removal efficiency of 98%. 

Filterable PM10 emissions were measured at the inlet and outlet of the FGD absorber using EPA 

Method 5B. Condensible PM10 emissions were measured at the inlet and outlet of the FGD 

absorber using EPA Method 202. In each test run, both filterable and condensable PM10

measurements were made inlet and outlet of the FGD absorber simultaneously. The average 

filterable PM10 emission rate was 0.0010 lb/mmBtu at the FGD absorber outlet. This is lower 

than the design emission rate of 0.012 lb/mmBtu. The average condensible PM10 emission rate 

was 0.0033 lb/mmBtu at the FGD absorber outlet, and the average total PM10 emission rate 

(filterable plus condensable) was 0.0044 lb/mmBtu. This is lower than the design PM10 emission 

rate (filterable plus condensable) of 0.08 lb/mmBtu. 

Oxidized mercury was measured at the inlet and outlet of the FGD absorber using the Ontario 

Hydro Method. Three test runs were conducted. In each test run, oxidized mercury emissions at 

the inlet and outlet of the FGD absorber were measured simultaneously. The design removal for 

oxidized mercury was 70%. However, during the three test runs, oxidized mercury measured at 

the inlet and outlet of the FGD absorber was below the detection limit of the laboratory 

equipment. Therefore, no useful information is available regarding oxidized mercury removal 

across the FGD absorber. However, oxidized mercury emissions at the outlet of the FGD 

absorber are undetectable. 

HCl and HF emissions were measured at the inlet and outlet of the FGD absorber using EPA 

Method 26A. Three test runs were conducted. In each test run, HCl and HF emissions at the 

inlet and outlet of the FGD absorber were measured simultaneously. During the three test runs, 

an average of 82.6% HCl removal and an average of 71.2% HF removal was achieved. Both of 

these results are below design removals of 95% for HCl and 90% for HF. The results of this 

testing are being evaluated to determine if the HCl and HF design removal efficiencies have been 

met. 

Emissions of H2SO4 were measured simultaneously at the inlet and outlet of the FGD absorber 

using the Controlled Condensate Method (CCM). Three test runs were performed over three 

days at four inlet ports and four outlet ports. During each test run, H2SO4 emissions were 

measured at each of the four sets of inlet and outlet ports sequentially. The design removal for 

H2SO4 was 25%. However, during the three test runs, H2SO4 measured at the inlet and outlet of 

the FGD absorber was below the detection limit of the laboratory equipment. Therefore, no 

useful information is available regarding H2SO4 removal across the FGD absorber. However, 

H2SO4 emissions at the outlet of the FGD absorber are undetectable. 

 
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SCR Performance Testing 

NOx emissions were measured during three test runs at the inlet and outlet of the SCR reactor 

using EPA Method 7E. All three test runs were completed in one day. Each test simultaneously 

measured NOx emissions at the inlet and outlet of the SCR reactor. Average NOx emissions at 

the inlet to the SCR reactor were 0.15 lb/mmBtu, which is below the design emission rate for the 

low NOx burners and overfire air systems (0.18 to 0.25 lb/mmBtu, depending on load). Average 

NOx emissions at the outlet of the SCR reactor were 0.029 lb/mmBtu, which is below the design 

emission rate for the SCR system (0.05 lb/mmBtu). 

Ammonia (NH3) slip was measured at the outlet of the SCR reactor using test Conditional Test 

Method 27 (CTM-027). Three test runs were performed on each of six ports during one day of 

testing. Ammonia slip at the outlet of the SCR averaged 0.04 ppm at 3% O2. This is lower than 

the design level of 2.0 ppm at 3% O2. 

Emissions of SO3 were measured at the inlet and outlet of the SCR reactor using the Controlled 

Condensate Method (CCM). SO2 emissions were measured at the inlet of the SCR reactor using 

EPA Method 6C in order to determine the SO2-to-SO3 oxidation rate across the catalyst. The 

SO2-to-SO3 oxidation rate was calculated as the difference between the outlet and inlet SO3

emissions, divided by the inlet SO2 emissions. Three tests were conducted for SO3 over two 

days. On the first day of SO3 testing, one SO3 test run was performed on only two ports at the 

SCR inlet and four ports at the SCR outlet due to inclement weather. On the second day of SO3

testing, two SO3 test runs were performed on three ports at the SCR inlet and three ports at the 

SCR outlet. The average SO2-to-SO3 oxidation rate across the catalyst was measured to be 

1.33%, which is below the 3.1% design oxidation rate.

It is common for an SCR system to achieve NOx emissions, ammonia slip levels, and an SO2-toSO3 oxidation rate below the design points when the catalyst is new. Over time, the NOx

reduction performance of the SCR system will decrease and ammonia slip and SO2-to-SO3

oxidation will increase to levels closer to their design points. Once NOx, ammonia slip, and SO3

emissions increase to a certain level (still below any permit limits), a layer of catalyst is changed 

out to maintain performance. 

Fabric Filter Baghouse Performance Testing 

Filterable PM10 emissions were measured at the outlet of the fabric filter baghouse using EPA 

Method 5B. Three (3) 180-minute tests were conducted on one day. Filterable PM10 measured 

during the test runs ranged from 0.0031 to 0.0042 lb/mmBtu, with an average of 0.0038 

lb/mmBtu. This is lower than the design emission rate of 0.012 lb/mmBtu. 

Mercury removal across the entire air pollution control system was estimated based on coal data 

and data collected from the mercury Continuous Emissions Monitoring System (CEMS) in the 

stack. Mercury emissions at the inlet of the fabric filter baghouse were estimated based on coal 

usage and mercury content information. Mercury emissions in the stack were measured with the 

CEMS. An average of 92% mercury removal was achieved across the entire air pollution control 

system with the activated carbon injection system in use. This is higher than the design mercury 

removal efficiency of 90%. 
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SUMMARY 

Minnesota Power developed and undertook an air pollution control retrofit project at Unit 3 of 

the Boswell Energy Center in response to several air quality regulations and legislation that were 

being developed and implemented. This project, called the Boswell Unit 3 Environmental 

Improvement Project, included the addition of the following equipment: 

• Low NOx burners and an overfire air system for NOx control 

• SCR system for NOx control 

• FGD system for SO2 control 

• Fabric filter baghouse for particulate matter and mercury control 

• Activated carbon injection system for mercury control 

• ID fans, motors, and drives 

Additional equipment and structures were also added to support the main air pollution control 

equipment, including: 

• Aqueous ammonia storage system 

• Limestone handling and preparation system 

• Fly ash handling and storage system 

• Enclosures for the new FGD system, ID fans, fabric filter hoppers and penthouse, and AFCU 

There were several challenges associated with the Boswell Unit 3 Environmental Improvement 

Project. The main project challenges included the limited site space, the installation of the SCR 

reactor and support truss, the tight project schedule, the need to construct a new utility bridge, 

the upgrade of the existing auxiliary power system, and the design of the new waste slurry 

disposal system. 

In order to meet the requirements of future air pollution control regulations, design criteria were 

set for SO2, HF, HCl, H2SO4, PM10 (filterable and filterable plus condensible), mercury (total 

and oxidized), and NOx emissions. Design criteria for ammonia (NH3) slip and SO2-to-SO3

oxidation across the SCR reactor were also set. Emissions testing was performed in January and 

February 2010 to determine if the FGD system, SCR system, fabric filter baghouse, and 

activated carbon injection systems were meeting their design performance. The following 

emission measurements were made during the performance testing: 

• FGD system 

– Emissions of SO2, PM10 (filterable and filterable plus condensible), oxidized mercury, 

HCl, HF, and H2SO4 were measured at the inlet and outlet of the new FGD absorber 

– Emission measurements at the FGD inlet and outlet were used to determine removal 

efficiency across the FGD absorber 

• SCR system 

– NOx emissions were measured at the inlet and outlet of the SCR reactor 

– Ammonia (NH3) slip was measured at the outlet of the SCR reactor 

– Emissions of SO3 were measured at the inlet and outlet of the SCR reactor 
13 

– SO2 emissions were measured at the inlet of the SCR reactor to determine the SO2-to-SO3

oxidation rate across the catalyst 

• Fabric filter baghouse 

– Filterable PM10 emissions were measured at the outlet of the fabric filter baghouse 

– Mercury removal across the entire air pollution control system was estimated based on 

coal data and data collected from the mercury Continuous Emissions Monitoring System 

(CEMS) in the stack 

All of the performance design criteria were met except for the HCl, HF, H2SO4, and oxidized 

mercury removal rates across the FGD absorber. During the performance testing, H2SO4 and 

oxidized mercury measured at the inlet and outlet of the FGD absorber were below the detection 

limits of the laboratory equipment. Therefore, no useful information is available regarding 

H2SO4 and oxidized mercury removal across the FGD absorber. However, H2SO4 and oxidized 

mercury emissions at the outlet of the FGD absorber are undetectable. The results of the HCl 

and HF emissions testing are being evaluated to determine if the HCl and HF design removal 

efficiencies have been met. 

The performance of the SCR system during the performance testing exceeded the design 

performance criteria. It is common for an SCR system to achieve NOx emissions, ammonia slip 

levels, and an SO2-to-SO3 oxidation rate below the design points when the catalyst is new. Over 

time, the NOx reduction performance of the SCR system will decrease and ammonia slip and 

SO2-to-SO3 oxidation will increase to levels closer to their design points. Once NOx, ammonia 

slip, and SO3 emissions increase to a certain level (still below any permit limits), a layer of 

catalyst is changed out to maintain performance. 

KEY WORDS 

Baghouse 

Boswell 

Emissions testing 

Fabric filter 

FGD 

Minnesota Power 

Retrofit 

SCR