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 (SO 2 ), nitrogen oxides (NO x ), 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 NO x 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 NO x burners and an overfire air system for NO x control

• Selective Catalytic Reduction (SCR) system for NO x control

• Wet Flue Gas Desulfurization (FGD) system for SO 2 control

• Fabric filter baghouse for particulate matter and mercury control

• Activated carbon injection system for mercury control

• Induced Draft (ID) fans, motors, and drives2 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 northeasternMinnesota. 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 NO x control and a single-stage wet particulate scrubber for particulate control. The wet particulate scrubber also achieved a small degree of SO 2 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 (SO 2 , NO x or PM 10 ).

The CAIR was designed to address interstate transport of SO 2 and NO x , which are precursors to ozone (O 3 ) and PM 2.5 . The CAIR sets state-wide budgets for annual SO 2 and NO x emissions, as well as ozone-season NO x emissions in 28 eastern states and the District of Columbia. The state of Minnesota was only subject to the annual SO 2 and NO x emission budgets. The CAMRestablished 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.3 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 SO 2 and NO x 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 SO 2 , NO x , mercury emissions and comply with future regulations by 2010. The Boswell Unit 3 Environmental Improvement Project included the addition of the following equipment:

• Low NO x burners and an overfire air system for NO x control

• Selective Catalytic Reduction (SCR) system for NO x control

• Wet Flue Gas Desulfurization (FGD) system for SO 2 control

• Fabric filter baghouse for particulate matter and mercury control

• Activated carbon injection system for mercury control

• ID fans, motors, and drives

The low NO x 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 system4 • 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 SO 2 control. The Boswell Unit 4 scrubber was originally designed to use lime as a reagent. However, the target SO 2 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:

• NO x : 0.07 lb/mmBtu at the stack (30-day rolling average)

• SO 2 : 0.09 lb/mmBtu (30-day rolling average)

• PM 10 (filterable): 0.014 lb/mmBtu

• PM 10 (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)5 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:

• NO x : 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% O 2 at the economizer outlet

• NO x : 0.05 lb/mmBtu at the outlet of the SCR reactor

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

• SO 2 to SO 3 oxidation across the SCR reactor: 3.1%

• SO 2 : 98% removal across the FGD absorber

• HF: 90% removal across the FGD absorber

• HCl: 95% removal across the FGD absorber

• H 2 SO 4 : 25% removal across the FGD absorber

• PM 10 : 0.012 lb/mmBtu (filterable), at the outlet of the fabric filter baghouse

• PM 10 : 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 20106 

### 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 of7 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, solarge 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 with8 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 39 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: SO 2 , PM 10 (filterable and filterable plus condensible), oxidized mercury, HCl, HF, and H 2 SO 4 . Emission measurements at the FGD inlet and outlet were used to determine removal efficiency across the FGD absorber.10 SO 2 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, SO 2 emissions at the inlet and outlet of the FGD absorber were measured simultaneously. During each test run, over 99% SO 2 removal was achieved, which is above the design SO 2 removal efficiency of 98%.

Filterable PM 10 emissions were measured at the inlet and outlet of the FGD absorber using EPA Method 5B. Condensible PM 10 emissions were measured at the inlet and outlet of the FGD absorber using EPA Method 202. In each test run, both filterable and condensable PM 10 measurements were made inlet and outlet of the FGD absorber simultaneously. The average filterable PM 10 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 PM 10 emission rate was 0.0033 lb/mmBtu at the FGD absorber outlet, and the average total PM 10 emission rate (filterable plus condensable) was 0.0044 lb/mmBtu. This is lower than the design PM 10 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 H 2 SO 4 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, H 2 SO 4 emissions were measured at each of the four sets of inlet and outlet ports sequentially. The design removal for H 2 SO 4 was 25%. However, during the three test runs, H 2 SO 4 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 H 2 SO 4 removal across the FGD absorber. However, H 2 SO 4 emissions at the outlet of the FGD absorber are undetectable.11 

### SCR Performance Testing

NO x 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 NO x emissions at the inlet and outlet of the SCR reactor. Average NO x emissions at the inlet to the SCR reactor were 0.15 lb/mmBtu, which is below the design emission rate for the low NO x burners and overfire air systems (0.18 to 0.25 lb/mmBtu, depending on load). Average NO x 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 (NH 3 ) 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% O 2 . This is lower than the design level of 2.0 ppm at 3% O 2
.

Emissions of SO 3 were measured at the inlet and outlet of the SCR reactor using the Controlled Condensate Method (CCM). SO 2 emissions were measured at the inlet of the SCR reactor using EPA Method 6C in order to determine the SO 2 -to-SO 3 oxidation rate across the catalyst. The SO 2 -to-SO 3 oxidation rate was calculated as the difference between the outlet and inlet SO 3 emissions, divided by the inlet SO 2 emissions. Three tests were conducted for SO 3 over two days. On the first day of SO 3 testing, one SO 3 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 SO 3 testing, two SO 3 test runs were performed on three ports at the SCR inlet and three ports at the SCR outlet. The average SO 2 -to-SO 3 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 NO x emissions, ammonia slip levels, and an SO 2 -toSO 3 oxidation rate below the design points when the catalyst is new. Over time, the NO x reduction performance of the SCR system will decrease and ammonia slip and SO 2 -to-SO 3 oxidation will increase to levels closer to their design points. Once NO x , ammonia slip, and SO 3 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 PM 10 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 PM 10 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%.12 

### 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 NO x burners and an overfire air system for NO x control

• SCR system for NO x control

• FGD system for SO 2 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 SO 2 , HF, HCl, H 2 SO 4 , PM 10 (filterable and filterable plus condensible), mercury (total and oxidized), and NO x emissions. Design criteria for ammonia (NH 3 ) slip and SO 2 -to-SO 3 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 SO 2 , PM 10 (filterable and filterable plus condensible), oxidized mercury, HCl, HF, and H 2 SO 4 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

– NO x emissions were measured at the inlet and outlet of the SCR reactor

– Ammonia (NH 3 ) slip was measured at the outlet of the SCR reactor

– Emissions of SO 3 were measured at the inlet and outlet of the SCR reactor13 – SO 2 emissions were measured at the inlet of the SCR reactor to determine the SO 2 -to-SO 3 oxidation rate across the catalyst

• Fabric filter baghouse

– Filterable PM 10 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, H 2 SO 4 , and oxidized mercury removal rates across the FGD absorber. During the performance testing, H 2 SO 4 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 H 2 SO 4 and oxidized mercury removal across the FGD absorber. However, H 2 SO 4 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 NO x emissions, ammonia slip levels, and an SO 2 -to-SO 3 oxidation rate below the design points when the catalyst is new. Over time, the NO x reduction performance of the SCR system will decrease and ammonia slip and SO 2 -to-SO 3 oxidation will increase to levels closer to their design points. Once NO x , ammonia slip, and SO 3 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