PSC REF#:100388

PSC REF#:100388Public Service Commission of Wisconsin

RECEIVED: 09/12/08, 12:59:42 PM

CFB BACT

Wisconsin Power and Light 2-30 Control Technology Analysis

2.2 NED 3 EGU: Sulfur Dioxide

Sulfur dioxide (SO2) emissions result from the oxidation of sulfur in the fuel. During combustion, the

majority of the fuel sulfur is emitted as SO2. A small portion of the fuel sulfur is further oxidized to

sulfur trioxide (SO3), as described further in Section 2.6. At normal flue gas temperatures SO3 combines

with water to form sulfuric acid (H2SO4). A portion of the sulfur may also remain in bottom and fly ash

generated during the combustion process. In this control technology review for SO2 emissions, all sulfur

present in the fuel is assumed to be converted to SO2. This uncontrolled emission rate, called the

potential combustion concentration, has been used to compare the effectiveness of emission control

techniques.

Sulfur dioxide emissions from CFB boilers may be controlled through the inherent control of a CFB

boiler using limestone injection into the boiler, post combustion controls, such as flue gas desulfurization

(FGD), the use of low sulfur fuels and fuel cleaning, or a combination of these controls. CFB boilers

have been designed with the inherent ability to control SO2 emissions in the combustion process. This is

a critical component of the facility design which allows for a wide range of fuel characteristics. The

NED 3 project is proposed to utilize low sulfur solid fuels including subbituminous and bituminous coals,

renewable resource fuels, fly ash from the existing NED 1 and NED 2 boilers, as well as medium and

high sulfur solid fuels including bituminous coals and petroleum coke.

The selection of SO2 control technology impacts the control of numerous pollutants beyond SO2

emissions. The selection of SO2 control technology can impact emissions of H2SO4, HAPS including

hydrogen chloride (HCl), hydrogen fluoride (HF) and metals, such as mercury. Therefore, it is important

to consider the multi-pollutant control impacts of each technology given the pollutant source and control

synergies.

2.2.1 BACT Baseline

The definition of BACT under NR 405.02(7) states:

In no event shall application of BACT result in emissions of any pollutant which would exceed the emissions allowed by any applicable standard under 40 CFR Parts 60 and 61… In addition, these units must meet each applicable emission limitation under chs. NR 400 – 499, Wis. Adm. Code.

Therefore, units subject to BACT must meet applicable emission limitations under Wis. Admin. Code

chs. NR 400-499. As a result, the new source performance standards (NSPS) under 40 CFR Part 60 and

NR 440 Wis. Adm. Code establish the maximum allowable emission limitations or the control technology

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“baseline”. The performance and costs of more stringent control technologies are evaluated against these

baselines.

The EPA published final rules revising the NSPS for new fossil fuel-fired electric utility steam generating

units on February 27, 2006. These standards include emission limits for nitrogen oxides (NOx), sulfur

dioxide (SO2), and particulate matter (PM). The NSPS standards in 40 CFR § 60.43Da(i)(1) require that

affected facilities for which construction commenced after February 28, 2005 limit SO2 emissions to:

(i) 1.4 lb/MW-hr gross energy output on a 30-day rolling average basis, or

(ii) 5 percent of the potential combustion concentration (95 percent reduction) on a 30-

day rolling average basis.

NED 3 has a design heat rate of 9,300 Btu/kWh. However, because of the inherent CEMS versus coal

flow heat input bias, the CEMS measured heat rate is expected to be about 10% higher, or approximately

10,000 Btu/kWh. Based on a heat rate of 10,000 Btu/kWh or 10.0 MMBtu/MW-hr, an NSPS SO2 limit of

1.4 lb/MW-hr gross is equal to an emission rate of 0.14 lb/MMBtu.

The NSPS SO2 emission limit is shown in Figure 2-1 as a function of the potential combustion

concentration for the proposed NED 3 fuel blends. Note that when the potential combustion

concentration is less than or equal to 2.8 lb/MMBtu, the required SO2 reduction is less than 95% and the

limit of 0.14 lb/MMBtu is less stringent than 95 percent reduction. The design of the NSPS limit is based

on the general engineering principle that as the absolute value of the uncontrolled emission rate goes

down, the ability to reduce emissions on a percent reduction basis becomes more difficult.

2.2.2 STEP 1. Identify All Potential Control Strategies

The first step in a top-down BACT analysis, according to EPA’s October 1990, Draft New Source Review

Workshop Manual and the WDNR’s November 7, 2005 memorandum titled “Procedures for PSD

BACT/NSR LAER and Netting”, is to identify all available control options. Available control options are

those air pollution control technologies or techniques with practical potential for application to the

emission unit and the pollutant that is being evaluated. This analysis considers the range of control

technologies that are demonstrated and potentially applicable to this project.

Sulfur dioxide emissions may be controlled through the use of the CFB boiler itself, post combustion

controls, fuel selection, and fuel cleaning. These technologies may be used separately, or they may be

used in combination for more effective SO2 control. It is important to note that the atmospheric pressure

CFB boiler technology was specifically developed to minimize SO2 and NOx emissions from the

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combustion of coal and high sulfur fuels such as petroleum coke. The CFB boiler operates at lower

combustion temperatures than a PC boiler which minimizes NOx formation and the injected limestone

reacts with the ensuing flue gas to remove significant sulfur compounds, such as H2SO4, and SO2 in the

boiler before said gas is directed through post combustion air pollution control systems. For this reason,

the CFB boiler technology is considered a "Clean Coal Technology" by the U.S. DOE, U.S. EPA and the

WDNR.

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Figure 2-1 Sulfur Dioxide emission limit required under the revised New Source Performance Standards in 40 CFR Part 60, Subpart Da based on 95% reduction or 0.14 lb/MMBtu

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.0 2.0 4.0 6.0 8.0 10.0

Potential Combustion Concentration, lb SO2/MMBtu

NSP

S A

llow

able

Em

issi

on R

ate,

lb/m

mB

tu

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The U.S. EPA’s RACT/BACT/LAER Clearinghouse (RBLC) and recently issued PSD permits in

Wisconsin and other states identify the following technologies for controlling SO2 emissions from solid

fuel-fired electric generating units, which can be classified according to the following generic categories:

Combustion Controls

Post Combustion Controls or Flue Gas Desulfurization

Low Sulfur Fuels

Fuel Cleaning

From a review of the U.S. EPA’s RBLC database, the U.S. EPA’s National Coal-Fired Utility Projects

Spreadsheet, Updated July 2008, and numerous permits issued in the past 10 years, the only SO2 control

technologies for CFB boilers include boiler limestone injection alone or in combination with dry FGD

systems and the use of low sulfur fuels. Tables 2-7 (low sulfur fuel) and 2-8 (high sulfur fuel) summarize

emission limits for projects similar to NED 3 obtained from the National Coal-Fired Utility Datasheet, the

RBLC, and a review of issued permits. Note that while wet FGD systems potentially have practical

applicability to CFB boiler technology, the RBLC database and EPA’s National Coal-Fired Utility

Projects, Updated July 2008 do not show any CFB boiler that has been permitted or constructed using wet

FGD systems. Review of available records for international CFB projects also did not identify any

projects utilizing wet FGD systems.

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Table 2-7

Summary of Recent Sulfur Dioxide BACT Emission Limits for CFB Boilers with Low Sulfur Fuels

Facility Capacity, MW

Permit or Application Date State Fuel

Uncontrol-led Rate, lb/MMBtu

Post Comb. Control EquipmentA

Emission LimitB

lb/MMBtu

Equivalent Control

Efficiency

AES Puerto Rico 494 Operating Sep-98 PR Columbia Coal 1.6 Dry FGD 0.022C 98.6% NEVCO Energy - Sevier Power Co. 270 Permit Oct-04 UT Subbituminous Coal 0.7 Dry FGD 0.022 96.9% Southern Montana Electric-Highwood 250 Permit May-07 MT Subbituminous Coal 1.4 Ash Reinj 0.038 97.3%

Rio Bravo Poso 38 Operating Oct-86 CA Bit. Coal / Pet. Coke / TDFD 1.02 Dry FGD 0.038E 96.0%

Mount Poso Cogeneration Project 62 Operating Jan-07 CA Bit. Coal / Pet. Coke / TDFD 1.02 Dry FGD 0.039 96.2%

Deseret Power Coop - Bonanza 110 Permit Aug-07 UT Bituminous Coal 2.2 Dry FGD 0.040 98.2% Lamar L & P - Repowering Project 44 Permit Aug-07 CO West Bit/Sub Coal 1.48 - 0.103F 93.1%

Footnotes A All of the units use limestone injection as the primary SO2 control method; the stated technology is in addition to limestone injection. FGD means flue gas desulfurization. B The stated emission limit is based on a 30-day rolling average, unless otherwise specified. C The limit for the AES Puerto Rico facility is based on a 3-hour average excluding start-up, shutdown and malfunction. The permit also limits coal sulfur content to 1.0% sulfur. The

‘worst-case’ coal fired at AES Puerto Rico is approximately 1.6 lb/MMBtu. D TDF = Tire-derived fuel. E The SO2 emission limit for the Rio Bravo Poso facility is 20.2 ppm corrected to 3% O2, equal to 0.038 lb/MMBtu. F The SO2 emission limit for the Lamar L & P - Repowering Project is a daily average.

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Table 2-8 Summary of Recent Sulfur Dioxide BACT Emission Limits for CFB Boilers with Higher Sulfur Fuel

Facility Capacity, MW

Permit or Application Date State Fuel

Uncontrol-led Rate, lb/MMBtu

Post Comb. Control EquipmentA

Emission LimitB

lb/MMBtu

Equivalent Control

Efficiency

Virginia City Hybrid Energy Center C 585 Permit Jun-08 VA Waste Coal, Wood 3.00 Dry FGD 0.022 99.3% D Montana-Dakota Utilities-Gascoyne 175 Permit Jun-05 ND Lignite 3.48 Dry FGD 0.038 98.9% Deseret Power Coop - Bonanza 110 Permit Aug-07 UT Waste Coal 4.73 Dry FGD 0.055 98.8% ACE Cogeneration Company 108 Operating Sep-87 CA Bit. Coal/Pet. Coke 4.00E Ash Reinj 0.079F 98.0% Kentucky Mountain Power 500 Permit May-01 KY Waste Coal 6.00 Dry FGD 0.13 97.8% Western Green Brier, LLC 85 Permit Apr-06 WV Waste Coal 7.00 Dry FGD 0.14 98.0%G JEA Northside Units 298 Operating Jul-99 FL Bit. Coal/Pet. Coke 8.42 Dry FGD 0.15 98.2% Entergy Louisiana, LLC - Little Gypsy 265 Permit Feb- 07 LA Pet Coke/Coal/Wood 5.00E Dry FGD 0.15 97.0% Cleco Power - Rodemacher 3-1 & 3-2 600 Permit Feb- 06 LA Bit. Coal/Pet. Coke 5.00E Dry FGD 0.15 97.0% Indeck-Elwood LLC 330 Permit Oct-03 IL Bit. Coal/Pet. Coke 7.50 - 0.15 98.0% East Kentucky Coop Spurlock 4 240 Permit Jul-06 KY Pittsburg #8 Coal 4.00E Dry FGD 0.15 96.3% Greene Energy 525 Permit Jun-05 PA Waste Coal 8.17 Dry FGD 0.156 98.1% Calhoun County E.S. Joslin Station 300 Permit Aug-07 TX Petroleum Coke 11.9 - 0.178 98.5% East Kentucky Coop Spurlock 3 270 Operating Jul-02 KY Pittsburg #8 Coal 4.00E Dry FGD 0.20 95.0% River Hill Power Facility 290 Permit Jul-05 PA Waste Coal 8.00 Dry FGD 0.20 97.5% Energy Services of Manitowoc 100 Permit Jun-01 WI Petroleum Coke 7.00 Dry FGD 0.20 97.1% Beech Hollow Project 250 Permit Apr-05 PA Waste Coal 8.17 Dry FGD 0.245 97.0%G Enviro Power - Benton 500 Permit Jul-01 IL Waste Coal 10.0 - 0.25 97.5% Red Hills 440 Operating Jun-97 MS Lignite 3.50E - 0.25 92.3%

Footnotes A All of the units use limestone injection as the primary SO2 control method; the stated technology is in addition to limestone injection. FGD means flue gas desulfurization. B The stated emission limit is based on a 30-day rolling average, unless otherwise specified. C The permit includes an annual fuel sulfur content of 1.5% equal to approximately 3 lb/MMBtu. Note that in the final draft permit, the DNR staff recommended a limit of 0.09 lb/MMBtu. The

Virginia State Air Pollution Control Board directed the Virginia DEQ to revise the SO2 limit to a value of 0.022 lb/MMBtu to reflect the AES Puerto Rico facility. D Removal rate selected based on AES Puerto Rico initial performance test. E The potential combustion concentration of the fuel was not identified; the stated level is an estimate based on the type of coal fired. F The Determination for the Argus Expansion Project was finalized on September 23, 1987, which specifies dry limestone injection and baghouse. The operating permit for Ace Cogeneration

limits SO2 emissions to 83 lb/hr on a 3-hour avg. For a boiler rating of 1,052 MMBtu/hr, this is equal to 0.079 lb/MMBtu. G The reduction efficiency for the Western Green brier, LLC and Beech Hollow Project are required by the permit.

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2.2.3 STEP 2. Identify Technically Feasible Control Technologies

Step 2 of the BACT analysis involves the evaluation of all of the identified available control technologies

from Step 1 to determine their technical feasibility. A control technology is technically feasible if it has

been previously installed and operated successfully at a similar emission source of comparable size, or

there is technical agreement that the technology can be applied to the emission source. Technical

infeasibility is demonstrated through clear physical, chemical, or other engineering principles that

demonstrate that technical difficulties preclude the successful use of the control option. In addition, the

technology must be commercially available for it to be considered technically feasible. EPA’s New

Source Review Workshop Manual, page B.12 states, “Technologies which have not yet been applied to

(or permitted for) full scale operations need not be considered available; an applicant should be able to

purchase or construct a process or control device that has already been demonstrated in practice.”

In general, if a control technology has been "demonstrated" successfully for the type of emission source

under review, then it would normally be considered technically feasible. For an undemonstrated

technology, “availability” and “applicability” determine technical feasibility. Page B.17 of the New

Source Review Workshop Manual states:

Two key concepts are important in determining whether an undemonstrated technology is feasible: "availability" and "applicability." As explained in more detail below, a technology is considered "available" if it can be obtained by the applicant through commercial channels or is otherwise available within the common sense meaning of the term. An available technology is "applicable" if it can reasonably be installed and operated on the source type under consideration. A technology that is available and applicable is technically feasible. Availability in this context is further explained using the following process commonly used for bringing a control technology concept to reality as a commercial product:

• concept stage; • research and patenting; • bench scale or laboratory testing; • pilot scale testing; • licensing and commercial demonstration; and • commercial sales.

Applicability involves not only commercial availability (as evidenced by past or expected near-term

deployment on the same or similar type of emission source), but also involves consideration of the

physical and chemical characteristics of the gas stream to be controlled. A control method applicable to

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one emission source may not be applicable to a similar source depending on differences in physical and

chemical gas stream characteristics.

2.2.3.1 Low Sulfur Fuels Sulfur dioxide emissions may be controlled by the use of a CFB boiler, and through post-combustion

FGD systems designed to remove SO2 from the flue gas. Because SO2 emissions occur from the

oxidation of sulfur contained in the fuel, the sulfur content of a given fuel can influence the amount of

SO2 emissions.

2.2.3.1.1 Project Design Pursuant to Wis. Stat. § 196.491(3), WPL submitted an Application for a Certificate of Public

Convenience and Necessity to the Public Service Commission of Wisconsin for approval of NED 3. The

purpose of constructing a baseload generating facility is to maximize the delivery of electric energy and

capacity to the State in the most reliable, cost-effective and technically feasible manner with the greatest

fuel supply reliability achievable (the “Project Purpose”). A major attribute favoring the NED 3 site as

the location for WPL’s proposed baseload unit is NED 3’s unique location on the transmission system.

Together with American Transmission Company LLC’s (“ATC”) Paddock to Rockdale transmission line,

NED 3 will increase transmission import capability to Wisconsin by approximately 900 MW, which is

additional to NED 3’s 300 MW nominal in-state generation output.

NED also offers greater fuel supply flexibility and reliability than any other alternative WPL considered.

The unique location of NED 3 on the Mississippi River and adjacent to existing rail service will allow

100 percent coal and pet coke delivery through either train, barge or a combination of the two. The

location also offers limited truck transportation. This flexibility for fuel transportation creates the

opportunity to utilize different coal supply regions for sourcing the fuel, which can create negotiating

leverage with the coal and transportation suppliers to achieve the lowest delivered cost. In addition,

petroleum (pet) coke is an opportunity fuel that can provide a low cost alternative in the upper Midwest,

and barge delivery to NED represents a low cost mode for delivery of pet coke from the refinery sources.

NED is also located in a prime location for a sustainable supply of renewable resource fuels.

In evaluating the feasibility of low sulfur fuels for the NED 3 project, it is important to note that a

fundamental design element of the NED 3 project is to develop a unit capable of utilizing a wide range of

solid fuels. Fuel flexibility was the key decision factor for the technology selection for NED 3. WPL

selected a CFB boiler for NED 3 to maximize the reliability, fuel flexibility, and potential cost savings

offered by the NED location. The ability of this unit to use a wide array of solid fuels, including

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renewable sources to help WPL meet Wisconsin’s Renewable Portfolio Standard will directly impact the

reliability and operating cost of this unit. CFB technology satisfies these decision factors as follows:

(1) Flexibility - The attributes of CFB technology provide the flexibility to burn a wide range of

fuel types. These attributes include the differences in fuel preparation that are required, lower

combustion temperature resulting in lower NOx emissions, high level of mixing of the fuel and

the recycling of the bed material/fuel and the inherent reduction of SO2 when limestone is used as

the bed material. These attributes allow a CFB unit to burn fuels with a wide range of

characteristics while maintaining reliable operations. The flexibility of a CFB unit also extends to

co-burning renewable resource fuels, making a CFB unit a hybrid fuel-fired unit, as opposed to a

100% coal unit. The design fuels for the NED 3 project include subbituminous coals, bituminous

coals, petroleum coke, and renewable resource fuels.

(2) Reliability – Fuel flexibility is also important for the reliability of this unit. Fuel flexibility is

becoming an increasingly important consideration as the demand for PRB coal increases. For

example, a train derailment on a rail line used to bring PRB coal east from Wyoming in 2005

forced many eastern utilities to curtail generation at units firing PRB coals and coal prices were

driven upward by the decreased supply. This incident continued to affect utility operations for

over a year. The problems of fuel price volatility and problems with fuel delivery are expected to

worsen in the future. The NED 3 CFB boiler technology designed for a wide range of potential

fuels will allow the use of other design fuels and reduce the risk of interruptions and outages due

to fuel curtailments. Most importantly, the opportunity to utilize different coal supply regions and

sources significantly increases the reliability of the NED fuel supply.

Furthermore, fuels such as pet coke, eastern bituminous coals, and foreign bituminous coals,

when blended with PRB coal, enhance the heat value of the fuel, which in turn improves the

operating efficiency. These other fuels also have certain environmental advantages over PRB

coal. While these fuels are higher in sulfur content, they have characteristics that have been

shown to result in more effective capture of fuel-bound mercury emitted during combustion.

(3) Cost savings - Fuel costs are the single highest operating cost for any fossil fuel-fired power

generating plant, including most plants that also fire renewable resource fuels. The use of a CFB

boiler designed for a wide range of fuels will allow operating costs to be managed by changing to

a different fuel when the availability or price of a fuel changes. The ability to utilize other fuels

also provides the opportunity to negotiate lower prices for the primary fuels. CFB boilers were

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developed to burn a wide range of fuels, especially high sulfur fuels such as bituminous coal and

petroleum coke, because the combustion process itself controls SO2 emissions. These high sulfur

fuels are often available at relatively low costs because their high sulfur content limits their use in

utility and industrial boilers that do not have SO2 control systems.

U.S. EPA recognizes the availability, reliability and fuel characteristic considerations utilities face when

choosing which fuels to utilize and how those considerations factor into plant design. Restricting the fuels

choices available to a utility would force a redesign of the unit. U.S. EPA recognized the importance of

fuel selection on plant design as they discussed in their proposed Electric Utility Steam Generating Unit

MACT:

The rank of coal to be burned has a significant impact on overall plant design. The goal of the

plant engineer is to arrange boiler components (furnace, superheater, reheater, boiler bank,

economizer, and air heater) to provide the rated steam flow, maximize thermal efficiency, and

minimize cost. Engineering calculations are used to determine the optimum positioning and

sizing of these components, which cool the flue gas and generate the superheated steam. The

accuracy of the parameters specified by the owner/operators is critical to designing and building

an optimally efficient plant. The rank of coal to be burned greatly impacts the entire design

process. The rank of coal burned also has significant impact on the design and operation of the

emission control equipment (e.g. ash resistivity impacts ESP performance).

For the above reasons, one of the most important factors in modern electric utility boiler design

involves the differences in the ranks and range of coals to be fired and their impact on the details

and overall arrangement of boiler components. Coal rank is so important that plant designers and

manufacturers expect to be provided with a complete list of all coal ranks presently available or

planned for future use, along with their complete chemical and ash analyses, so that the engineers

can properly design and specify plant equipment. The various coal characteristics (e.g., how hard

the coal is to pulverize; how high its ash content; the chemical content of the ash; how the ash

"slags" (fused deposits or resolidified molten material that forms primarily on furnace walls or

other surfaces exposed predominantly to radiant heat or high temperature); how big the boiler has

to be to adequately utilize the heat content; etc.), therefore, affect design from the pulverizer

through the boiler to the final steam tubes. For a boiler to operate efficiently it is critical to

recognize the differences in coals and make the necessary modifications in boiler components

during design to provide optimum conditions for efficient combustion.

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Coal-fired units are designed and constructed with different process configurations partially

because of the constraints, including the properties of the fuel to be used, placed on the initial

design of the unit. Accordingly, these site-specific constraints dictate the process equipment

selected, the component order, the materials of construction, and the operating conditions.

69 Fed. Reg. 4652, 4665 (January 30, 2004)

Based on this information, EPA then analyzed the available data to determine which coal ranks

were burned, and why, to ascertain if changing coal rank would be a conceivable control strategy.

The EPA found that the characteristics of the coal rank to be burned was the driving factor in how

a coal-fired unit was designed. Further, the choice of coal ranks to be burned for a given unit is

based upon economic issues, including availability of the coal within the region or locale.

69 Fed. Reg. at 4666.

The EPA also found that substitution of coal rank, in most cases, would require significant

modification or retooling of the unit, which would indicate a pertinent difference in the

design/operation of the units.

Id.

Furthermore, the U.S. EPA recognizes the importance of high sulfur fuels as a national resource in the

development of the NSPS. The EPA responded to comments regarding the need to allow utilities the

option to use high sulfur fuel indicating:

“High sulfur coals are an important part of the United States energy resources, and spray dryers

for SO2 control are important in locations with limited water resources. EPA has concluded that

it is vital that the amended NSPS preserve the use of both high sulfur coals and spray dryers.”

(emphasis added)11

The CFB system is expected to achieve very high SO2 control efficiencies of 98.6% to 99.1%, while

pulverized coal-fired units, equipped with FGD, are expected to achieve SO2 control efficiencies of 95%

to 98%. Based on these SO2 control efficiency ranges, the CFB boiler/FGD technology combination will

reduce SO2 emission by an additional 70% as compared to a PC boiler with FGD. Therefore, the design

11 Federal Register Rule Vol. 71, No. 38 February 27, 2006 pp.9866-9886

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of the NED 3 unit to use a CFB boiler is intended to maximize fuel flexibility and allow the use of high

sulfur fuels that will improve reliability and reduce operating costs while still minimizing SO2 emissions.

As a result, NED 3’s project design for purposes of BACT comprises both the CFB boiler and the types

of fuels intended to be burned.

2.2.3.1.2 Design Fuels. To maximize the benefits of CFB boiler technology, fuel flexibility is essential because flexibility in fuel

source, type, and delivery method lowers the risk of interruption of service due to fuel delivery

curtailments and volatile fuel prices. Fuel flexibility also lowers the risk of elevated power generation

costs which is significant because fuel costs are the most influential operating and maintenance (O&M)

cost component of any new electric generating facility. Fuel flexibility can be affected by several

important factors, including availability, chemical and physical properties, impacts on material handling

systems, the ability to feed the fuel to the boiler, and the delivered cost of the fuel. These factors must be

considered when determining the “performance fuel” “design fuels” and “fuel blends”. These terms are

defined as follows:

Performance Fuel – A fuel or fuel blend from a specific commercially available region, mine,

refinery or other source which is anticipated to be the primary fuel fired in the boiler.

Design Fuel – A fuel or fuel blend from an available region, mine, refinery, or other source,

which is used in the design of the boiler and auxiliary equipment to establish ranges (e.g.,

maximum chlorine content for project).

Fuel Blend – A fuel mixture consisting of a nominal percentage of two or more different design

fuels, which has prudent technical or commercial advantages. For example, the Performance Fuel

chosen for the project is an example of a fuel blend. It is comprised of 20% renewable resource

fuel, 64% subbituminous PRB coal and 16% petroleum coke, by heat input and can provide

improved combustion characteristics at a low cost. A fuel blend that includes a renewable

resource fuel such as wood or wood wastes provides renewable generation to help WPL meet

Wisconsin’s Renewable Portfolio Standard.

For the NED 3 project, the “Performance Fuel” will be a blend of 20% renewable resource fuel, 64%

subbituminous PRB coal & 16% petroleum coke by heat input five years after the date the unit begins

commercial operation. There are many potential fuel blends possible with the “primary design” fuels of

subbituminous coal, bituminous coal, petroleum coke, and renewable resource fuels. Other fuel and fuel

blend options include, but are not limited to:

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• 100% subbituminous coal

• 100% bituminous coal

• 100% petroleum coke

• 50 to 90% subbituminous coal blended with 10 to 50% petroleum coke or

bituminous coal

• 70 to 90% bituminous coal, 10 to 30% petroleum coke or subbituminous coal

• Any of the above fuels blended with renewable resource fuels12 including wood,

wood wastes, switch grass, and other agricultural residues at 20% blends, by heat

input, five years after NED 3 reaches commercial operation.

While there are many fuel properties that affect the ability to utilize a solid fuel or fuel blend in the

proposed CFB boiler, the general fuel properties of the feasible fuels are summarized in Table 2-9.

Table 2-9 Summary of the Properties of Fuels and Fuel Blends Reviewed for Nelson Dewey Unit 3

Permit. Property Minimum Maximum

Heat Value, Btu/lb 8,300 14,420@@@

Ash Content, % 0.69% 15%

Sulfur Content, lb SO2/MMBtu 0.25 9.5

2.2.3.1.3 Fuel Properties and Sulfur Content. The properties of the proposed fuels and fuel blends are summarized in Table 2-10 and Figure 2-2. The

coal quality data in Table 2-10 is from the U.S. Geological Survey’s National Coal Resources Data

System, US Coal Quality Database. This data is available at

http://energy.er.usgs.gov/products/databases/CoalQual/index.htm. Note that the coal data in Table 2-10

represents the USGS data of coal as it exists in the ground. This data may vary substantially from the

coal that is currently utilized by existing sources.

12 It is unknown at this time the maximum percentages of pet coke and renewable resource fuel that can comprise the total heat content of the fuels that will feed the NED 3 boiler; however, for purposes of this air permit application, including the BACT analysis, a maximum (worst-case) of 100 percent pet coke, 100 percent bituminous, and/or 100 percent subittuminous and these fuels, in blends with 20 percent renewable resource fuel by heat input, was used for purposes of modeling and emission calculations.

CFB BACT


From Table 2-10, the potential fuels and fuel blends have a wide range of potential SO2 combustion

concentrations, ranging from 0.5 to 9.0 lb SO2/MMBtu. The maximum anticipated fuel sulfur combustion

concentration for NED 3 is 9.5 lb SO2/mmBtu. It is typical for a CFB boiler to utilize a higher range of

sulfur content fuels than a PC boiler because of the CFB boiler’s inherent design for high sulfur fuels, fuel

flexibility, and the CFB boiler’s greater potential to reduce SO2 emissions. For example, the Deseret

Power Electric Cooperative is constructing a new CFB boiler at the Bonanza Power Plant, Uintah &

Ouray Reservation, Utah, which would fire both waste coal and “run of mine” coal from a nearby mine.

The waste coal had a ‘worst case’ potential SO2 combustion concentration of 4.73 lb/MMBtu, while the

‘average’ waste coal has a much lower potential combustion concentration of 1.71 lb/MMBtu. To resolve

the issue about which fuel is appropriate as a basis for BACT, the U.S. EPA Region 8 required a two tier

SO2 BACT limit13. This two tier approach addressed the difference in the uncontrolled SO2 emission rate

between the worst-case coal and the average coal. The first limit is applicable when the fuel has an

uncontrolled SO2 emission rate of 2.2 lb/MMBtu or less; the second limit is applicable when the potential

combustion concentration exceeds 2.2 lb/MMBtu. The “cutpoint” of 2.2 lb/MMBtu was selected by the

U.S. EPA to ensure that the emission limit required that the SO2 control efficiency at the “cutpoint” was

at least 97.5%; this rate was selected because it is the equivalent control efficiency that the AES Puerto

Rico facility must achieve to meet its SO2 emission limit of 0.022 lb/MMBtu when burning its “average”

coal.

Because of the range of potential combustion concentrations for the NED 3 project, these fuels may also

be evaluated based on a multi-tier approach similar to that used by the U.S. EPA Region 8 for the Deseret

Power Electric Cooperative project. In this analysis, two “cutpoints” have been selected. Because the as

fired sulfur content of some of the fuels or fuel blends are within the same sulfur content range as fuels

fired at the AES Puerto Rico facility, the first cutpoint is the maximum potential combustion

concentration of the fuel fired for the AES Puerto Rico facility, or 1.6 lb/MMBtu. The second cutpoint

has been set at 2.8/MMBtu as it is near the upper range of sulfur content for PRB coals (based on USGS

data) and it maintains a minimum removal rate of 98.0% when the fuel is just above the 2.8 lb/MMBtu

cut point. This removal rate is greater than the minimum removal rate required on the Deserete Power

Electric Cooperative permit. A higher minimum rate is appropriate in this application because the cut

point is slightly higher in this application. This cut point also happens to be equivalent to the minimum

13 The U.S. EPA Region 8 permit decision is available at http://www.epa.gov/Region8/air/permitting/deseret.html.

CFB BACT


NSPS level which requires 95% control, or 2.8 lb/MMBtu. Figure 2-3 indicates the minimum removal

rate required with in each fuel Teir to maintain the proposed BACT emission rates discussed in Step 3.

Table 2-10 Summary of the Fuel and Fuel Blend Characteristics for the Nelsen Dewey Unit 3. (The coal data is taken from the U.S. Geologic Service Coal Quality Database.A)

HEAT VALUE, Btu/lb UNCONTROLLED SO2,

lb/MMBtu

FUEL OR FUEL BLENDA 10th

Percentile Average 90th

Percentile 10th

Percentile Average 90th

Percentile Renewable Resource Fuels (RRF), including Wood, Wood Wastes, Corn Stover, etc.B

6,017 6,244 6,478 0.17 1.74 7.11

Petroleum Coke 13,500 14,134 14,810 6.66 7.83 9.00 Subbituminous Coals 6,989 8,605 10,298 0.58 1.83 3.66 Powder River Basin Subbituminous Coals 6,906 8,088 9,550 0.53 1.89 3.52

Illinois Bituminous CoalsC 10,799 11,605 12,362 2.77 4.85 5.61 North Appalachian Bituminous CoalsC 11,049 12,430 13,641 1.01 3.68 5.52

80% Subbit Coal / 20% Petroleum Coke 8,291 9,711 11,200 2.56 3.58 5.08

40% Subbituminous Coal / 60% Petroleum Coke 10,862 11,716 12,706 5.12 6.21 7.48

50% Subbituminous Coal / 50% IL Bituminous CoalC 8,894 10,105 11,330 1.91 3.56 4.73

64% Subbituminous Coal / 16% Petroleum Coke / 20% RRF 7,836 9,018 10,256 1.47 2.85 5.37

A The USGS coal quality data is available at http://energy.er.usgs.gov/products/databases/CoalQual/index.htm. B Renewable Resrouce Fuel quality data is based on information collected by WPL. C Bituminous coal analysis assumes 20% sulfur removal due to coal washing at the mine.

CFB BACT


Figure 2-2 Summary of the Typical Range of Potential Sulfur Dioxide (SO2) Combustion Concentrations for the Proposed Fuels and

Fuel Blends for Nelson Dewey Unit 3

0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0

Uncontrolled SO2 Emission Rate, lb/MBtu

Biomass Fuels

Petroleum Coke

Subbituminous Coals

Powder River Basin Coals

Illinois Bituminous Coals

North Appalachian Bituminous Coals

80% Subbituminous Coal/20% Pet. Coke

40% Subbituminous Coal/60% Pet. Coke

50% Subbituminous Coal/50% ILBituminous Coal

Perf. Fuel: 64% Subbituminous Coal/ 16% Petroleum Coke/20% Biomass

The coal sulfur content data range represents the 10th percentile and 90th percentile coal sulfur contents from the USGS Coal Quality Database, available at http://energy.er.usgs.gov/products/databases/CoalQual/index.htm.

Tier 0 Fuels

Tier II Fuels

Tier I Fuels

CFB BACT


Figure 2-3 Coal to Stack Minimum Remoaval Rate Required in Different Fuel Tiers

97.0%

97.5%

98.0%

98.5%

99.0%

99.5%

100.0%

00.511.522.533.544.555.566.577.588.599.5

lb SO2/MMBtu in Fuel

% R

emov

al

Minimum Dry Removal Minimum Wet Removal AES Puerto Rico Minimum Removal

Tier II/I Break Tier I/0 Break

Tier II Tier 0Teir I

CFB BACT

Wisconsin Power & Light 2-48 Control Technology Analysis

2.2.3.1.4 Low Sulfur Petroleum Coke Petroleum coke is a byproduct of the coker refinery process which upgrades crude oil by heating it and

cracking it to higher valued gasoline, jet and diesel fuels. When compared to coal, petroleum coke is

generally lower in ash (<0.5%), and lower in moisture (8-10%), resulting in a higher heating value, on the

order of 14,000 Btu/lb. Typically, petroleum coke also has a higher sulfur content, ranging from about

4% to 7% sulfur. The sulfur content of petroleum coke is largely controlled by the crude oil sulfur

content and the refining process. While the sulfur content does vary from refinery to refinery, refineries

do not separate fuel grade petroleum coke into “low sulfur” fractions. Basically, whatever is produced at

the refinery is shipped without segregation.

Petroleum coke, as it is removed from the coking process, is called “green coke.” Green petroleum coke

contains approximately 15-20% residual hydrocarbon materials. These hydrocarbons are those

compounds that do not polymerize in the coking process and cannot be removed from the coke substrate.

Petroleum coke is either sold in green form, or further processed such as through calcination. Calcined

petroleum coke is manufactured by heating green coke to approximately 2,400 – 2,600 F in a rotary kiln.

This removes virtually all residual hydrocarbons and moisture. The final calcined product contains only a

trace of volatile matter, and 0.3% - 6% sulfur. The primary use of calcined petroleum coke, which

demands a higher price, is in making carbon anodes for the aluminum industry and is not typically fired

in a power generating plant.

Production costs associated with pet coke are minimal because it is a byproduct of the refining process.

Because coke is a byproduct and the refinery gets much more from the light products produced from the

coker, refineries are sometimes willing to run the coker even if they had to pay to dispose of the pet coke.

Therefore, refineries do not attempt to produce low sulfur petroleum coke. With this said, petroleum

coke pricing is generally discounted to compensate for the higher sulfur content which limits its use in

many coal-fired boilers.

Data from the US Department of Energy’s FERC – 423 Database (http://www.ferc.gov/docs-

filing/eforms/form-423/data-annual.asp#skipnavsub) indicates that between 1999 and 2006, sulfur levels

in pet coke used by electric utilities in the United States have ranged from less than 3.2 pounds of SO2

per million Btu to over 12.8 pounds of SO2 per million Btu. The median SO2 value has increased from

4.9 pounds of SO2 per million Btu in 1999 to 7.5 pounds per million Btu or more since 2003. This source

also indicates that the quantity has risen from less than 2 million tons per year in 2000 to well over 3

million tons per year since 2003.While low sulfur petroleum coke is available, low sulfur petroleum coke

is a high value specialty product used as a raw material for many carbon and graphite products, including

CFB BACT


furnace electrodes and liners, and the anodes used in the production of aluminum. The amounts of low

sulfur petroleum coke are so small that the use of low sulfur petroleum cokes as a fuel for electric power

production is technically infeasible. Therefore, low sulfur petroleum coke will not be considered further

in this analysis.

2.2.3.1.5 Feasibility Due to NED 3’s design emphasizing fuel flexibility, it would be contrary to the project design for WPL

to propose BACT for SO2 based upon any restrictions of its proposed fuels. While clean fuels may be

considered to meet BACT requirements, clean fuels may be considered if the permit applicant proposes

to meet BACT using clean fuels. See Pub. Law No. 101-549, § 403(d), 104 Stat. at 2631 (1990) (U.S.

Senate Report of the Committee on Environment and Public Works to Accompany S. 1630 (Dec. 20,

1989) discussing the addition of “clean fuels” to the definition of BACT in the 1990 Clean Air Act

Amendments). A CFB was chosen at the NED location specifically because of fuel flexibility

requirements in order to meet the Project Purpose. Any limit on sulfur content or type of fuel burned

within the design fuels identified for this unit (subbituminous and bituminous coals, pet coke and

renewable resource fuels) is beyond the scope of the project and would redesign the source. It is well-

established that it is up to the applicant to define the source and that BACT does not include redesigning

the project proposed by the applicant. WPL is proposing to meet BACT for SO2 based upon the inherent

reductions in SO2 control within the CFB boiler and add-on FGD control, not through limiting the sulfur

content of its fuels.

Due to the large range of sulfur contents in the fuels proposed for this Project, the variability of sulfur

content within the proposed fuels, and the fact that BACT limits may be established with the sulfur

content of fuels as part of the limit (e.g. lower-sulfur fuels will be capable of achieving lower SO2

emission rates than higher sulfur fuels when using the same SO2 control technology), WPL believes that

it is appropriate to subdivide the proposed fuels into three tiers to ensure that high removal rates are

achieved at all times. In other words, WPL will evaluate BACT for 3 separate fuel tiers – one for each

fuel tier based on the sulfur content of the fuel.

For purposes of evaluating BACT, WPL has divided its proposed fuels into 3 tiers: Tier 0 (maximum

sulfur content of 1.6 lb/MMBtu), Tier I (maximum sulfur content up to 2.8 lb/MMBtu) and Tier 2 (any

fuel with a sulfur content exceeding 2.8 lb/MMBtu). See section 2.2.3.1.3 for the technical basis for the

divisions between fuel tiers. Using the sulfur content of the fuel itself as the basis for the BACT tiers,

rather than proposing BACT for a given fuel (e.g. PRB), recognizes that each fuel WPL is proposing to

use contains inherent variability with respect to its sulfur content. (Please refer to Figure 2-2 which

CFB BACT


illustrates the range of sulfur content within various fuel Tiers). Thus, WPL has divided the proposed

fuels into tiers based upon sulfur content, since this approach is directly related to actual SO2 emissions.

This three-tiered BACT is essential to maintaining a high level of SO2 reduction and is essential to

WPL’s project design. Without it, WPL could only establish one BACT limit. Traditionally this BACT

limit would be established based upon the worst case sulfur fuel. A BACT limit based upon the worst-

case sulfur fuel would not, however, reflect the lower sulfur emissions that could be achieved with use of

lower-sulfur fuels. If, however, the limit was established based on low sulfur fuel, then, as a practical

matter, higher sulfur fuels would be eliminated from WPL’s design. These higher sulfur fuels would be

eliminated because the technically feasible controls could not achieve the stringent emission limit based

on low sulfur fuel when combusting higher sulfur fuels. Establishing the BACT limit based upon low

sulfur fuel would eliminate WPL’s performance fuel (PRB, renewable resource fuels and pet coke) and

all higher sulfur fuels changing the design of the project. Thus, multiple limits are proposed to ensure

that high removal efficiences are maintained at all times. The limits and associated fuel tiers are based on

site specific conditions such as the need for fuel flexibility and the range of fuels available as well as non-

site specific conditions such as achievable emission reduction rates and the need to maintain a minimum

removal rate, that corresponds with BACT levels, at all times.

While WPL asserts that limiting the sulfur content of its fuel would redesign the source, the preceding

analysis discussed in detail why restricting sulfur content at NED 3 solely to Tier 0 and/or Tier I fuels

would negatively impact the reliability and costs associated with NED 3 and could not be the basis for

establishing BACT. To summarize this analysis, concerns regarding fuel availability, reliability and costs

have lead to the choice of CFB technology for NED 3 for which fuel flexibility is an inherent design

factor. Based on the above discussion, the exclusive use of low sulfur Teir 0 and Tier I fuels for NED 3

is not a feasible control option and not within the scope of NED 3 project and therefore will not be

evaluated further.

2.2.3.2 Combustion Controls. The atmospheric pressure, fluidized bed boiler technology was developed to minimize SO2 and NOx

emissions from the combustion of high sulfur fuels such as coal and petroleum coke. The fluidized bed

boiler combustion process minimizes NOx formation, by avoiding significant “thermal NOx” contribution

by utilizing a low combustion temperature, and the injected limestone removes SO2 in the boiler before

flue gas discharge to post combustion air pollution control systems. For this reason, the fluidized bed

boiler technology is designated as a "Clean Coal Technology" by the U.S. DOE, U.S. EPA, and the

WDNR.

CFB BACT


2.2.3.2.1 Fluidized Bed Boiler Types. There are two major fluidized bed boiler types: the bubbling fluidized bed (BFB) boiler, and the

circulating fluidized bed (CFB) boiler. In the BFB boiler, the bed of materials including the limestone,

fuel, and ash is suspended by the combustion air flowing upward through an air distribution plate at

relatively low velocities of 1 to 5 ft/sec. The fluidized bed is typically about 4 feet deep, and is

characterized by a sharp density profile at the top of the bed. The sharp drop off in density indicates the

end of the fluidized bed. In a BFB boiler, the bed level is easy to see, and there is a distinct transition

between the bed and the space above. Solid material is drained from the bed to maintain the desired bed

depth. Some solid material is also entrained in the flue gas and is carried out of the furnace with the flue

gas. Approximately 10 to 90 percent of this fly ash is collected in a cyclone at the furnace outlet and is

re-injected into the bed. Re-injection of ash from cyclones located at the furnace outlet back to the

furnace is an important efficiency improvement in all fluidized bed boilers, improving combustion

efficiency and maximizing limestone utilization.

The CFB boiler is a more advanced fluidized bed boiler technology. CFB boilers may be contrasted with

the BFB boiler by higher fluidizing air velocities ranging from 10 to 20 ft/sec, the lack of a distinct

transition from the dense bed at the bottom of the furnace to the dilute zone above, and a very high flow

rate of re-circulated solids. The high fluidizing air velocity results in a turbulent fluidized bed and a high

rate of entrained solids carried out of the boiler. These solids are separated from the combustion gases by

cyclones located at the outlet of the boiler furnace and are returned to the furnace to improve combustion

efficiency and limestone utilization.

In the furnace section of the CFB boiler, limestone is injected with solid fuel to create a fuel and

limestone “bed”. The injection of limestone is necessary to create an abrasive bed of particles which

assists in eroding fuel particles and completing the combustion process. Combustion air introduced at the

bottom of the furnace keeps the mixture of fuel, limestone, char, and ash “fluidized” in a constantly

upward flowing stream. Although the fuel and limestone are solids, the combination of fuel, limestone,

ash, and combustion air exhibit fluid-like properties. The highly turbulent, erosive conditions of the

fluidized bed results in very high combustion efficiencies even though combustion takes place at

relatively low temperatures of 1,500 to 1,650°F. At the outlet of the CFB boiler furnace, large cyclones

separate relatively large particles from the smaller ash particles and flue gas and are returned to the

furnace to complete combustion of the fuel and to utilize unreacted lime or limestone.

The BFB boiler has limited application in the large utility boiler size range. The majority of the

applications for bubbling fluidized beds have been at installations of less than 200,000 pounds per hour

CFB BACT


of steam. Almost all of the new, large capacity, coal-fired fluidized-bed boilers have been of the

circulating type14. Furthermore, CFB boilers have higher SO2 control efficiencies than BFB boilers.

While the boiler proposed for the NED 3 Project is a fluidized bed boiler, since CFB boilers have higher

removal rates than BFB boilers, BFB boilers will not be further evaluated in this analysis.

2.2.3.2.2 Fluidized Bed Boiler SO2 Control. The limestone injected into the CFB boiler to facilitate the combustion process is also an inherent sulfur

dioxide control system. The limestone (dolomite or calcite, containing mostly calsium carbonate or

CaCO3) is first “calcined” to calcium oxide or lime (CaO). This reaction is endothermic, requiring about

766 Btu/lb of limestone. Calcium oxide then reacts with SO2 to form calcium sulfate (CaSO4). This

reaction is exothermic, liberating about 6,733 Btu per pound of sulfur. The SO2 removal reactions

include the following:

Calcination: CaCO3 (s) + 766 Btu/lb (of CaCO3) → CaO (s) + CO2 (g)

Adsorption: SO2 (g) + ½O2 (g) + CaO (s) → CaSO4 (s) + 6,733 Btu/lb (of S)

Net Reaction: CaCO3 (s) + SO2 (g) + ½O2 (g) → CaSO4 (s) + CO2 (g) + 4,342 Btu/lb (of S)

Calcium sulfate is removed from the CFB bed (bottom ash blowdown) and in the fabric filter baghouse as

a solid in concert with ash remaining from fuel combustion. In the presence of water, calcium sulfate

absorbs water to form calcium sulfate dihydrate (CaSO4•2H2O), or gypsum.

When fluidized bed boilers were first developed, the boiler itself with limestone injection was the only

SO2 control technology required as BACT. As other control technologies have evolved, CFB boilers

have been equipped with post combustion dry FGD systems to further reduce SO2 emissions.

As the desired SO2 removal increases, the required ratio of limestone (or calcium) to sulfur increases.

Typical calcium to sulfur molar ratios in CFB boilers for 90% SO2 removal range from 3.0 to 3.5 for

BFB boilers, and from 2.0 to 2.5 for CFB boilers. In CFB boilers, calcium to sulfur ratios of 1.8 to 2.5

may be necessary to achieve 95% removal on high sulfur fuels15. However, calcium to sulfur ratios

(Ca/S) versus percent removal will vary based on fuel type, fuel sulfur content and actual operating

conditions. For example, in the DOE demonstration project at the JEA Northside Plant, increases in the

14 STEAM, its generation and use, 41st Edition, the Babcock & Wilcox Company, Barberton, Ohio.

CFB BACT


fuel sulfur content required lower Ca/S ratios in the boiler to achieve 95% or greater removal efficiencies

(refer to Table 2-11).

Table 2-11 Calcium to Sulfur Ratio vs. CFB SO2 Removal for Various Uncontrolled SO2 Rates at

JEA Northside

Uncontrolled SO2, lb/MMBtu

Calcium to Sulfur Ratio in Boiler, mole Ca/mole S

CFB SO2 Removal Efficiency (%)

7.52 1.67 96.8% 7.03 1.70 95.9% 7.95 1.87 97.5%

8.845 1.76 96.9% 5.44 2.68 94.9% 5.69 2.93 94.9% 5.25 2.30 97.8%

5.312 2.24 96.9%

2.2.3.2.3 Technical Feasibility. Based on the above analysis, the CFB boiler combustion technology is a well demonstrated technology

and is a technically feasible SO2 control technology for the NED3 project.

2.2.3.3 Flue Gas Desulfurization. When the fluidized bed boiler technology was first developed, the use of a fluidized bed boiler was, by

itself, considered the BACT for SO2 control. More recently, BACT has required the addition of dry FGD

systems on some, but not all CFB boilers to further reduce SO2 emissions.

FGD technologies used for coal-fired utility boilers may be broadly classified as “wet” and “dry”

systems. Wet FGD (WFGD) systems are characterized by saturated or wet flue gas conditions, and a wet

sludge reaction product which is dewatered before reuse or disposal. For most coals and boiler types, the

flue gas saturation temperature is about 130 oF. In WFGD applications, the primary particulate matter

control system is typically located upstream of the wet FGD system so that the fly ash and FGD system

reaction products are collected separately. This is necessary to avoid saturated conditions in the PM

15 From STEAM, its generation and use, 41st Edition, the Babcock & Wilcox Company, Barberton, Ohio, Chapter 17, Fluidized Bed Combustion, page 17-13, available at www.babcock.com; and Combustion and Gasification in Fluidized Beds, 2006, Prabir Basu, CRC Press, ISBN 0849333962, page 154.

CFB BACT


control system which would plug a fabric filter baghouse or render a dry ESP ineffective. Finally,

WFGD systems are also characterized by relatively high water use as compared to dry FGD systems.

Conversely, dry FGD (DFGD) systems are characterized by non-saturated or dry flue gas conditions and

a dry reaction product. Flue gas temperatures exiting a dry FGD system are typically about 20 to 50 °F

above the saturation point, or about 150 oF to 180 oF. In DFGD applications, the particulate matter

control system is located downstream of the DFGD system so that the fly ash and the FGD reaction

product are commingled into a single byproduct or waste stream. Finally, DFGD systems are

characterized by reduced water use as compared to wet FGD systems.

2.2.3.3.1 Dry Flue Gas Desulfurization DFGD is a well demonstrated technology for the control of SO2 emissions from coal-fired electric

generating units. For CFB boilers, DFGD systems are the only post combustion SO2 control systems

currently in use or required by permit in the U.S. Like wet FGD systems, DFGD can be subdivided into

several types. Dry FGD systems involve injecting a dry sorbent into the furnace or flue gas duct; the by-

product solids are collected with the boiler fly ash. In semi-dry FGD systems, the sorbent is introduced

as an aqueous slurry or a humidified dry powder to improve SO2 control efficiency. The water content is

controlled so that the reaction by-products are dry solids. While the flue gas temperature in both types

remains above the adiabatic saturation temperature, the semi-dry systems have lower temperatures and a

closer approach to the saturation temperature. The primary particulate matter control system for dry FGD

applications is normally a fabric filter baghouse. The filter cake on the bags acts like a fixed-bed reactor;

reagent captured on the filter and the subsequent filtration of the flue gas enhances reagent utilization and

improves the overall SO2 removal efficiency.

DFGD systems do not have a saturated plume and therefore do not require the same design elements

related to a saturated and corrosive plume as wet FGD systems. Since the dry FGD reaction products are

also dry, there is no need for dewatering equipment or wastewater discharge. The reaction product in the

DFGD process is primarily calcium sulfite, with smaller amounts of calcium sulfate. Because of the

calcium sulfite content, the DFGD byproduct will undergo pozzolanic (cementitious) reactions when

wetted. When wetted and compacted, dry FGD byproducts make a fill material with low permeability

and high bearing strength. However, this material has limited commercial value and is typically disposed

of as waste material or mine fill.

Lime Spray Dryer Absorber

CFB BACT


One of the most widely used DFGD technologies for utility boilers is lime spray dryer absorber (LSDA)

technology. LSDA is a “semi-dry” FGD technology that is often used in low sulfur pulverized coal-fired

boilers. The LSDA process employs a Spray Dryer Absorber (SDA) and a downstream particulate matter

control device. In a CFB boiler application, the SDA utilizes a reagent of slurry of limited water mixed

with recycled fly ash, remaining CaO from the boiler and FGD solids (supplemental lime) to absorb and

neutralize SO2. The SDA introduces the lime slurry and flue gas at the top of an absorber vessel. Rotary

atomizers or dual fluid nozzles are used to create a spray of atomized slurry droplets which are dispersed

in the flue gas stream. The water in the slurry droplets evaporates as the flue gas passes through the

absorber, cooling and humidifying the flue gas stream and rapidly drying the slurry to a powder. In

practice, water is also added to control the SDA outlet temperature to approximately 155oF, or an

approach temperature approximately 25oF above the saturation temperature. SO2 is absorbed into the

droplet and neutralized by the lime. Fly ash, reaction products, and unreacted lime are captured

downstream in the particulate matter control system. A portion of the collected material is recycled back

to the SDA to improve reagent utilization.

Advanced Dry and Semi-Dry FGD Systems

Advanced dry and “semi-dry” FGD systems include circulating fluidized bed (CFB or CDS) scrubber

systems, hydrated lime injection systems, flash dryer absorbers (FDA) systems also known as novel

integrated desulphurization system (NIDS). These systems also utilize excess lime (CaO) produced in

the CFB boiler as the FGD reagent, which is hydrated and mixed with supplemental lime which is either

reinjected into the flue gas ductwork or scrubber vessel (reactor) upstream of the baghouse. With the

CDS and FDA systems, remaining SO2 in the flue gas reacts with calcium hydroxide in the reactor or on

the fabric filter bags to form solid calcium sulfite (CaSO3) and calcium sulfate (CaSO4):

2Ca(OH)2 (s) + 2SO2 (g) + 2H2O (g) → 2(CaSO3 • 2H2O) 2Ca(OH)2 (s) + 2SO2 (g) + 2H2O (g) +O2 → 2(CaSO4 • 2H2O)

These advanced semi-dry systems may be contrasted with conventional SDA systems in that the ash is

humidified but remains a dry free-flowing solid, rather than being mixed into a slurry as in the SDA

process. This lower water content eliminates the need for slurry handling, atomization, and a large

reactor. Reinjecting a dry solid also allows the reagent to disperse rapidly in the flue gas. These systems

may also be contrasted with conventional SDA systems in that the solids recirculation rate is 30 to 100

times, compared to 3 – 5 times in a conventional SDA system, improving lime utilization.

CFB BACT


The CFB semi-dry FGD process uses lime, water and recycled solids from the CFB boiler and fabric

filter baghouse in a fluidized bed reactor to form calcium sulfite and calcium sulfate as described above.

In a CFB FGD system, flue gas is introduced into the bottom of a vessel at high velocity through a

venturi nozzle and is mixed with water, hydrated lime, recycled fly ash and FGD reaction byproducts.

The mixture of flue gas, water, and solids traverses the reactor in a highly turbulent fluidized bed. SO2 in

the flue gas reacts with calcium hydroxide in the reactor or on the fabric filter bags to form solid calcium

sulfite and calcium sulfate. The injected water humidifies and cools the flue gas. By the time the

particles leave the reactor, they are dry particulate matter which is captured in the primary particulate

matter control system.

Advanced dry FGD processes, such as hydrated lime injection into flue gas ductwork upstream of a

particulate control device such as a baghouse are not considered viable for SO2 control for a larger 300

MW unit based on reduced control effectiveness compared to semi-dry FGD processes. However, both

dry and semit-dry FGD process are effective sulfuric acid mist and hazardous air pollutant (HAP) control

systems. SO3 formed during combustion will react with moisture in the flue gas to form sulfuric acid

(H2SO4) mist. Unlike a wet FGD system, the temperature in the dry or semi-dry FGD system is

maintained above the sulfuric acid dew point so that SO3 does not become an acid mist. The moisture

coated calcium hydroxide particles in the absorber preferentially react with SO3 before reacting with SO2.

In the vapor phase, SO3 is readily contacted with the moisture coated calcium hydroxide particles and a

significant fraction is removed from the flue gas. Furthermore, the very alkaline ash that collects on the

fabric filters down stream of the FGD system further reduce the SO3 from the flue gas by reacting with

the remaining SO3 in the flue gas at reduced temperatures. Therefore, a dry or semi-dry FGD and fabric

filter system combination is very effective at controlling SO3 emissions.

Similar concepts can be applied to the ability of the dry FGD systems to control other HAPs including

hydrogen chloride (HCl), hydrogen fluoride (HF) and metals, including mercury. The flue gas

temperature in the baghouse is below the temperature where many of these HAPs change from a gaseous

state to a solid state16 which facilitates condensation of certain HAPS which can then be collected in the

baghouse.

Technical Feasibility

CFB BACT


Semi-dry FGD systems, including lime spray dryer absorbers, circulating fluidized bed semi-dry systems,

and flash dryer absorbers are all demonstrated technologies for the control of SO2 emissions from larger

CFB boilers. Therefore, these semi-dry FGD systems are technically feasible control options for CFB

boilers. Because of the general similarities in all of these semi-dry FGD systems, and because the CFB

semi-dry FGD system has demonstrated the ability to achieve SO2 emission reductions equivalent to or

greater than that achieved by conventional dry FGD systems, an advanced semi-dry FGD system is used

to represent all dry and semi-dry FGD systems in this control technology review.

2.2.3.3.2 Wet Flue Gas Desulfurization Wet flue gas desulfurization (WFGD) is also a well demonstrated technology for the control of SO2

emissions from coal-fired electric generating units utilizing pulverized coal or cyclone-fired boilers.

However, the RBLC and EPA’s National Coal-Fired Utility Projects Spreadsheet, Updated July 2008,

do not show that a WFGD system has ever been installed on a commercial utility CFB boiler.

In a WFGD system, the flue gas is exposed to an alkaline reagent which absorbs SO2 and reacts with it to

form a solid. There are several alkaline reagents used in WFGD systems, including water-based slurries

with lime, magnesium enhanced lime, limestone, liquors containing dissolved sodium or magnesium

salts, or amine based liquors including ammonia. Most WFGD systems use lime or limestone as the

alkaline reagent and produce a mixture of calcium sulfite and calcium sulfate as a potentially salable by-

product.

Regardless of the wet FGD design, the flue gas leaving the absorber will be saturated with water, and the

stack will have a visible condensed moisture plume. The conditions downstream of the absorber are

highly corrosive, requiring corrosion-resistant materials for the downstream ductwork and stack.

Equipment is also needed to manage the condensation that occurs on the downstream ductwork and in the

stack. The WFGD reaction products also require dewatering, usually by a combination of hydroclones

and vacuum filters, though some systems have significantly more complex drying systems to produce

more valuable byproducts. Large areas are needed to manage the dewatering and byproduct storage

operations. All of these factors contribute to the high capital and operating costs of WFGD systems.

State-of-the-Art Wet FGD Designs

16 Control of Mercury Emissions from Coal-Fired Electric Utility Boilers: Interim Report Including Errata Dated 3-21-02, EPA-600/R-01-109, April 2002, Page 5-4, and Figure 5-2. Predicted distribution of Hg species at equilibrium, as a function of temperature.

CFB BACT


The first FGD systems in the U.S. were installed in response to the 1970 Clean Air Act. Most of these

original FGD systems were calcium based wet FGD systems. About half of the early systems were lime

and the other half limestone. Many of the original FGD systems were plagued with operational issues that

included scaling, plugging, and low SO2 removal efficiency - generally less than 90%. These first wet

FGD systems utilized spray tower absorbers, with and without a perforated plate tray, as the method for

contacting the flue gas with the alkaline reagent.

FGD systems installed in the 1990’s were 2nd and 3rd generation FGD systems which generally achieved

greater than 90% SO2 removal with improved reliability. The limestone systems installed during this time

were mostly limestone forced oxidation systems (LSFO), which demonstrated the ability to achieve

similar performance and reliability as lime systems. The SO2 removal efficiencies of the 2nd and 3rd

generation systems were improved by improving gas-liquid contact. These improvements include

absorption trays and multiple levels of interspatial reagent spray nozzles. Pollution control system

suppliers have introduced several new designs in an attempt to improve the flue gas to FGD liquid

reagent contact and minimize operating costs. Designs such as the Jet Bubbling Reactor developed by

Chiyoda and Alstom’s Flowpac systems were developed to improve the gas-to-liquid contact by forcing

the flue gas to bubble through the liquid reagent using a gas sparger design rather than spraying the

alkaline slurry into the gas stream. Mitsubishi developed the Double Contact Flow Scrubber (DCFS)

which uses ‘fountains’ of slurry to contact the flue gas. Babcock Power Environmental Inc. utilizes

bidirectional sprays and wall rings to maximize contact between the flue gas and liquid reagent. All of

these different types of wet FGD systems typically use what is characterized as a limestone forced

oxidation (LSFO) process.

All of the WFGD designs described above will generally meet similar emission rate objectives and will

have similar operating characteristics. Therefore, this control technology review will be based on the wet

limestone forced oxidation (LSFO) process as representative of the abilities and cost of all WFGD

systems regardless of specific reagent or absorber design.

Wet Limestone with Forced Oxidation

In recent years, the WFGD market has turned almost completely to the use of wet lime or limestone with

forced oxidation on pulverized coal-fired boilers because it improves SO2 control, reduces chemical scale

formation, and produces gypsum; a stable and potentially valuable byproduct. Wet limestone with forced

oxidation (LSFO) is a modification of a conventional wet limestone FGD process. A conventional wet

limestone system forms a scrubber product composed mostly of calcium sulfite (CaSO3). The LSFO

process further oxidizes calcium sulfite to calcium sulfate dihydrate (gypsum, or CaSO4·2H2O). The

CFB BACT


gypsum content of the scrubber sludge can be in excess of 95% on a dry basis, making the sludge easier

to dewater, and much more valuable.

In a typical LSFO process, flue gas exits the primary particulate matter pollution control system such as a

baghouse or electrostatic precipitator at approximately 300 oF and enters a spray tower where an alkaline

slurry consisting of limestone (calcium carbonate), calcium sulfite, and calcium sulfate is contacted with

the flue gas. Through a series of reactions, SO2 in the flue gas reacts with calcium carbonate in the

limestone to form CaSO3. The flue gas exits the absorption tower through a mist eliminator to remove

entrained moisture droplets. The calcium sulfite remains in the slurry which drains into a recirculation

tank located at the bottom of the spray tower. By injecting air into the slurry using fans or blowers, the

calcium sulfite is oxidized to CaSO4·2H2O. A portion of the slurry in the recirculation tank is pumped

back into the spray tower, and a portion is removed. The removed slurry is dewatered and stockpiled for

transport offsite. The overall FGD reaction is:

CaCO3(s) + SO2(g) + ½O2(g) + 2H2O → CaSO4·2H2O(s) + CO2(g)

The LSFO process can achieve high levels of control on pulverized coal-fired boilers. Recent BACT

determinations put the level of control in the 95-98% range. However, the same performance principle

for any SO2 control system is also true for the LSFO process – as the boiler outlet SO2 concentration

decreases, the ability to achieve high control efficiencies also decreases. As a result, the higher level of

performance for LSFO systems stated as a percentage reduction can only be achieved when the boiler is

firing higher sulfur content fuels.

The design of the typical LSFO system and the arrangement of the other pollution control systems may

be less efficient at controlling hazardous air pollutants (HAPs) and sulfuric acid mist than advanced semi-

dry FGD systems. In wet FGD applications, the primary particulate matter control equipment must be

located upstream of the wet FGD system to prevent heavy ash loading to the absorber. Because the

primary PM control system in this arrangement operates at higher temperatures, metals and other

substances that may condense out at lower flue gas temperatures such as mercury and selenium may not

be controlled to the same level as in advanced semi-dry FGD pollution control system arrangements.

Technical Feasibility

As noted above, WFGD is a well demonstrated technology for the control of SO2 emissions from

pulverized coal or cyclone-fired boilers. While WFGD systems should be technically feasible for CFB

boilers, the RBLC and EPA’s National Coal-Fired Utility Spreadsheet do not show WFGD systems ever

actually being installed on a CFB boiler and no evidence of use was found in review of international CFB

CFB BACT


boiler literature reviews. Therefore, there is no known demonstrated control efficiency for a WFGD

system on a utility baseload CFB boiler. WFGD systems have been installed primarily on PC boilers

combusting higher sulfur coals, while dry FGD systems have typically been installed on PC boilers firing

lower sulfur coals and CFB boilers.

2.2.3.3.3 Emerging Flue Gas Desulfurization Technologies Emerging SO2 control technologies include Enviroscrub (also known as the Pahlman process), ECO

scrubber, REACT, and the Airborne process. These emerging technologies are not yet demonstrated

through installation and successful operation on a CFB boiler or are not available or applicable. Of these

advanced processes, the ECO system process and Airborne process are closest to commercial operation.

The ECO process has been installed as a slip stream unit on a bituminous coal-fired boiler. The ECO

system being offered is a redesigned version of the slip stream scrubber taking into account the “lessons

learned.” The ECO system design has not yet been installed or demonstrated on a full scale on any

boiler.

The REACT technology from Japan consists of three major process steps: absorption, regeneration, and

byproduct recovery. The absorption process utilizes pelletized activated coke (ATC) and ammonia for

removal of SO2 and sulfuric acid from the flue gas. The absorption and regeneration processes of the

REACT technology are dry, and require secondary particulate removal to collect the salable reaction

product. No known REACT system has been proposed or installed on a U.S. Utility boiler. Therefore

this technology will not be considered further.

Airborne ProcessTM

On October 14, 2004, the U.S. Department of Energy announced that Peabody Energy’s Mustang Energy

project will be awarded a $19.7 million Clean Coal Power Initiative grant for demonstrating technology

to achieve ultra-low emissions at a proposed 300 MW facility near Grants, New Mexico. This project

was selected in the second round of the DOE’s Clean Coal Power Initiative (CCPI). The Mustang Clean

Coal Project teamed Peabody Energy and Airborne Clean Energy to demonstrate Airborne’s emission

control process. There were four objectives for this demonstration:

1. 99.5% removal of SO2

2. 98% removal of SO3

3. 98% percent removal of NOx, and

4. 90% removal of mercury.

CFB BACT


The Airborne process was intended to achieve these emission reduction goals while producing a

potentially valuable granular fertilizer byproduct. The technology would combine a dry sodium

bicarbonate injection system with enhanced wet sodium bicarbonate scrubbing. Because the sodium

bicarbonate reagent is expensive and the reaction product has limited value, the Airborne Process™ was

configured to regenerate the scrubber reagent. The regeneration process was intended to recover the

reagent for reuse and convert SO2 and NOx into ammonium sulfate and ammonium nitrate based

fertilizers.

To develop this process, Airborne Clean Energy constructed a series of bench and small scale combustor

tests, followed by a 5-MW test facility in Ghent, Kentucky. At the Ghent facility, the above SO2 removal

goals were achieved, but the NOx and mercury reductions were not. Subsequent studies using oxidant

additives found that NOx and mercury removals could be substantially enhanced.

Technical Feasibility.

While several advanced FGD technologies show promise in achieving very low SO2 emission rates, these

processes are not commercial, nor are they demonstrated in practice. EPA’s New Source Review

Manual, page B.11 summarizes the technical feasibility criteria as follows:

Technologies which have not yet been applied to (or permitted for) full scale operations

need not be considered available; an applicant should be able to purchase or construct a

process or control device that has already been demonstrated in practice.

With respect to the Airborne project, because the Mustang project received U.S. DOE funding to

demonstrate the technology’s feasibility, it is, by definition, not demonstrated in practice. As a result,

WPL has concluded that the Airborne ProcessTM is not technically feasible because it is not commercially

available, nor is it demonstrated in practice on a full scale utility boiler similar to NED 3.

With respect to other advanced technologies, due to the lack of demonstrated and proven performance of

these emerging technologies, these technologies are not considered technically feasible SO2 control

options for the NED 3 project.

2.2.3.4 Fuel Cleaning Coal is a mineral consisting of a heterogeneous mixture of organic and inorganic matter. The impurities

associated with coal may be classified as inherent or extraneous. Inherent impurities cannot be physically

separated from coal. However, extraneous impurities such as rocks, scrap iron, and pyrite (iron disulfide,

FeS2) can be physically separated to varying degrees through coal cleaning. Sulfur is generally present in

coal in three forms: pyritic, sulfate, or organic. The pyritic portion of sulfur in coal may vary from 10%

CFB BACT


to 80% of the total sulfur content, depending on the coal. Large pyrite particles can be removed by

physical cleaning. Sulfate forms of sulfur are usually calcium or iron sulfates, and generally account for

less than 0.1% of the coal sulfur content. Organic sulfur is chemically bound to the coal and cannot be

separated by coal cleaning. Therefore, fuel cleaning is only effective for coals containing high

percentages of sulfur as pyrite.

In the coal cleaning process, “run-of-mine” coal is first cleaned of trash, crushed, and screened. The coal

is then cleaned by gravity separation. In the gravity separation process, the desirable coal organic

fraction floats in a separating fluid (usually an aqueous suspension of magnetite in water), while pyrite,

soil, rock, and shale debris sink. The floating organic fraction is transferred to a dewatering system.

Dewatering is a key cleaning step, since the reduction of water reduces shipping costs and improves the

coal heating value. Nearly all of the bituminous coals from Illinois and Appalachia are washed before

being shipped from the mine. Thus, the sulfur reduction from coal cleaning is included in the evaluation

for eastern bituminous coals and is part of the NED3 project design. To account for coal cleaning in this

control technology review, the average and 90th percentile USGS coal data for Illinois and Appalachia

coals was reduced by 20%.

While coal cleaning can achieve substantial sulfur reductions on some coals (20 to 30% for Illinois

bituminous coals), not all coals and solid fuels can be effectively washed. Subbituminous coals have low

sulfur, low ash and small particle sizes. Washing of subbituminous coals is not technically feasible

because of the minimal improvement in sulfur content and the high energy requirements and fresh water

needed to effectively dewater the coal, in mine area where these commodities are in short supply.

Therefore washing of PRB coal is not considered further.

Other means of reducing the sulfur content per unit of heat value (pounds of sulfur per million Btu) can

be achieved through enhancing the heat value of western subbituminous coals. One example is the K-

Fuel technology (Evergreen Energy Inc. formerly known as KFx Inc.). As reported on July 31, 2007, the

capacity to produce K-Fuel nationally in the U.S. is only 700 tons per day, which represents only about

20% of the fuel needed for NED 3. No commercially available means of reducing the sulfur content on a

pounds per million Btu basis of low sulfur subbituminous coal with sufficient capacity to provide

enhanced coal has been identified, and therefore, this enhancement technology is not considered further

herein.

Cleaning is not technically feasible for petroleum coke or renewable resource fuels. The sulfur in

petroleum coke and renewable resource fuels is primarily organic; there is no known commercial

CFB BACT


technology for removing organic sulfur from petroleum coke or renewable resource fuels. Therefore,

cleaning for petroleum coke and renewable fuels is not considered further in this analysis.

2.2.3.4.1 Technical Feasibility Fuel cleaning is a technically feasible control option to reduce the sulfur content of Illinois and

Appalachia bituminous coals with relatively high percentages of sulfur as pyrite. To account for coal

cleaning in this control technology review, the average and 90th percentile USGS coal data for Illinois

and Appalachia coals was reduced by 20%. Fuel cleaning is not technically feasible for subbituminous

coals, petroleum coke, or renewable resource fuels.

2.2.4 STEP 3. Rank the Technically Feasible Control Technologies.

2.2.4.1 Achievable Emission Reductions. When evaluating the achievable emission reductions for the available SO2 control technologies,

regulatory agencies generally evaluate the maximum expected control efficiency of the control or

combination of controls based on the worse-case fuel. In addition, agencies have also considered the

long term expected reduction based on the typical or average fuel. Because the range of fuels for NED3

varies significantly in sulfur content and the sulfur content within each tier varies as well, the maximum

expected control efficiency is not expected to be constant through out the full range of inlet sulfur content

this analysis shall be split into three sections to address the range of inlet sulfur content.

2.2.4.1.1 Fuel Tiers WPL is proposing to fire a wide range of fuels and fuel blends in the CFB boiler with potential

combustion concentrations ranging from 0.5 lb SO2/MMBtu to more than 9.0 lb SO2/MMBtu. Because

the range of potential combustion concentrations is large, this analysis uses a three tier approach based on

the potential combustion concentration of the fuels to evaluate SO2 control options. A similar technique

was used in the Deseret Generation permit recently approved by the U.S. EPA Region 8. The EPA has a

website with the permit decision at http://www.epa.gov/Region8/air/permitting/deseret.html. The tiers

used in this SO2 BACT analysis are:

• Tier 0 – Up to 1.6 lb of SO2/MMBtu in fuel or fuel blend

• Tier I – Greater than 1.6 to 2.8 lb of SO2/MMBtu in fuel or fuel blend

• Tier II – Greater than 2.8 lb SO2/MMBtu in fuel or fuel blend

CFB BACT


Tier 0 has been selected based on the performance of AES Puerto Rico CFB unit on low sulfur foreign

bituminous coal. The Tier I cutpoint of 2.8 lb/MMBtu is selected to maintain a minimum removal

performance within Tier II, as well, it also represents the cutpoint of the NSPS SO2 control requirements.

2.2.4.2 Step 3a- Rank the Technically Feasible Control Technologies - Tier 0.

2.2.4.2.1 Combustion Controls. Operating CFB boilers, including Manitowoc Public Utilities Boiler 9 (Wisconsin) and Southern Illinois

Cooperative (Illinois), have demonstrated the ability to maintain SO2 removal rates in excess of the new

source performance standards based only on the inherent control of limestone injection in the CFB boiler.

In addition, the Indeck-Elwood LLC plant (Illinois) and Calhoun County E.S. Joslin Station (Texas) are

both recently permitted facilities which are required to meet the NSPS Subpart Da limits, and neither of

these facilities must have post combustion controls. Therefore, the SO2 removal inherent in the CFB

boiler combustion technology with limestone injection can be equivalent to the NSPS Subpart Da

standard of 95% reduction of the potential SO2 combustion concentration, or 0.14 lb/MMBtu.

2.2.4.2.2 Dry Flue Gas Desulfurization. Boiler and air pollution control manufacturers have guaranteed the overall, combined control efficiency

of the CFB boiler, fabric filter baghouse, and dry or semi-dry FGD systems at 98% to >99%, depending

on the fuel sulfur content. As with other FGD systems, the control efficiency of the CFB boiler, fabric

filter baghouse and semi-dry FGD system is expected to improve as the uncontrolled sulfur content of the

fuel increases. This level of control reflects the long-term, combined performance of the CFB boiler,

fabric filter baghouse, and dry FGD system.

Regulatory Decisions

There are numerous regulatory decisions regarding the overall control capability of a CFB boiler in

combination with semi-dry FGD systems which represents BACT. The reduction requirements in recent

BACT decisions are included in Table 2-7 & 2-8, with the highest levels of control summarized in Table

2-12. The highest overall reduction required, based on a worse-case potential combustion concentration

of 3.00 lb SO2/MMBtu, was 99.3% for the Virginia City Hybrid Energy Center. The highest overall

reduction required for a coal with a worse-case potential sulfur concentration of less than 2.80 lb

SO2/MMBtu was 98.6% for the AES Puerto Rico facility.

CFB BACT


Table 2-12 Regulatory Decisions Regarding the Overall SO2 Removal Rates for CFB Boilers

Equipped with Dry FGD Systems.

Unit Name Status Worst Case Fuel,

lb SO2/MMBtu (Fuel Type)

Percent SO2 Removal From Worst Case

FuelA

Virginia City Hybrid Energy Center Permit 8/2008. 3.0

(Waste Coal) 99.3%B

Montana – Dakota Utilities Gascoyne Station Permit issued 6/2005. 3.48

(Lignite Coal) 98.9%

Deseret Power Cooperative - Bonanza Permit issued 8/2007. 4.73

(Waste Coal) 98.8%

AES Puerto Rico Cogeneration Project Operating 1.60

(Columbian Coal) 98.6%

Calhoun County E.S. Joslin Station Permit issued 8/2007. 11.9

(Petroleum Coke) 98.5%


(Bituminous Coal) 98.2%

JEA Northside U 1&2 Operating 8.42

(Bituminous Coal/ Petroleum Coke)

98.2%

Western Greenbrier Permit issued 4/2006. 7.0 (Waste Coal) 98.0% C

Southern Montana Electric Highwood Station Permit issued 5/2007. 1.4

(Subbituminous) 97.3%

Green Energy Permit issued 6/2005 8.17

(Waste Coal) 98.1% A Note that the removal percentage in these instances is calculated by comparing fuel type and emission limitation and not required by permit condition unless otherwise noted. B Removal rate selected based on AES Puerto Rico initial performance test. C The reduction efficiency for the Western Greenbrier facility is required by the permit.

Performance of Operating Units

The AES Puerto Rico, L.P. facility is a 454 megawatt (net) coal-fired steam electric cogeneration facility

in Guayama, Puerto Rico. The AES Puerto Rico facility generates electricity for sale to the Puerto Rico

Electric Power Authority, and steam for industries near the site. This facility consists of two bituminous

coal-fired CFB boilers, each rated at 2,461 MMBtu/hr. These boilers fire low sulfur Columbian coal with

a typical sulfur content of 0.88 lb SO2/MMBtu, and a maximum design value of 1.6 lb SO2/MMBtu. The

CFB boilers are equipped with a circulating dry scrubber (CFB Semi-Dry FGD systems), designed to

achieve an outlet SO2 concentration of 9 ppm at 7% O2, equal to 0.022 lb/MMBtu. Note that these dry

FGD systems are similar to that proposed for NED 3.

The U.S. EPA Region 2 issued a final PSD permit for the AES Puerto Rico facility in September, 1998.

The permit limits SO2 emissions to 0.022 lb/MMBtu on a 3-hour average basis, not including periods of

CFB BACT


startup and shutdown. Based on the design coal sulfur content fired of 1.6 lb/MMBtu, this limit requires

an SO2 control efficiency of 98.6%. Based on the typical coal sulfur content of 0.88 lb/MMBtu, this limit

requires an SO2 control efficiency of 97.5%.

The AES Puerto Rico facility commenced commercial operation in 2002. According to information

obtained from the U.S. EPA Region 2, this facility has generally maintained compliance with the

emission limit of 0.022 lb/MMBtu on a 3-hour average, but every quarterly report reviewed for this

analysis had noted exceedances of the 3-hour limit due to periods of startup and shutdown or process

malfunctions. Continuous emissions monitoring system (CEMS) data obtained from the U.S. EPA

Region 2 indicates typical SO2 emission rates of 0.01 – 0.02 lb/MMBtu. The initial emission compliance

test indicates stack SO2 concentrations of less than 1.0 ppm at 7% O2, emission rates below 0.01

lb/MMBtu and removal rates of greater than 99%.

However, the initial compliance test conditions are akin to ideal operating conditions. These conditions

are not considered representative of long term operating conditions that can be continuously maintained

and as such, do not represent normal operations. Initial compliance test conditions are different from

typical conditions in that the equipment is new, the fuel conditions are specificly set, testing periods are

limited in time frame and before/during the testing period the vendor is typically on-site ensuring

everything is working as well as possible. These types of results are considered to be reflective of the

best short term performance rates of the equipment and are not considered reflective of long term rates

that should be evaluated for a BACT analysis.

The compliance emissions test data and CEMS data for the AES Puerto Rico units indicate SO2

concentrations below the levels typically achieved using wet FGD systems on pulverized coal-fired units,

even when firing low sulfur coals. In fact, the typical performance of the AES Puerto Rico CFB boilers

in combination with the semi-dry CFB FGD systems is better than the performance of any other FGD

systems – wet or dry – reviewed in this control technology review.

The Jacksonville Electric Authority Northside Units 1 & 2 are also two operating CFB units. The

emission limit for these units is 0.15 lb SO2/MMBtu. Monthly as-fired fuel data and as-received fuel data

CFB BACT


were collected for these units for the years 2002-200517. Based on this analysis, the highest and lowest

monthly SO2 content of the fuel is 8.42 lb/MMBtu and 3.63 lb/MMBtu respectively. The actual control

efficiencies necessary to comply with the permit limit of 0.15 lb/MMBtu for the highest and lowest

monthly SO2 content are 98.2% and 95.9%, respectively.

Achievable Level of Control.

Based on the above regulatory analyses, operating experience and vendor information, when the potential

combustion concentration of the fuel is less than 1.6 lb/MMBtu, the combined control efficiency of the

CFB boiler, fabric filter baghouse, and dry FGD systems is expected to be 98.6% or less and maintain an

emission rate of 0.022 lb/MMBtu.

2.2.4.2.3 Wet Flue Gas Desulfurization. Air pollution control manufacturers have guaranteed the control efficiency of wet FGD systems at 98%

removal. However, the expected long-term performance of wet FGD systems has generally been 95 –

97% depending on the wet FGD inlet SO2 concentration. Some wet FGD systems have claimed

potential SO2 reduction efficiencies of up to 99%. However, this very high reduction efficiency has been

specified at very high SO2 inlet concentrations.

Regulatory Decisions

With the preface that we are not aware of any CFB boilers actually operating with a wet FGD system,

there are several regulatory decisions regarding the overall, theoretical control capability of a CFB boiler

in combination with a wet FGD system. Regulatory agency estimates of the overall SO2 reduction

capabilities of a wet FGD system in combination with a CFB boiler in recent decisions are summarized in

Table 2-13. The highest overall reduction used by a regulatory agency in review of the performance of

wet FGD systems was the U.S. EPA Region 8 analysis of the Deseret Power Cooperative’s Bonanza

Plant (August 2007), with an estimated SO2 control efficiency of 99.1%. Several permitting authorities

concluded that there was no difference in the performance of a CFB boiler equipped with a dry FGD

system, as compared to a CFB boiler equipped with a wet FGD system. The review agencies did not

provide further insight into their decision. Because there are no known operating facilities utilizing a

17 Data available in Energy Information Administration Form 767 at www.eia.doe.gov. The as-fired data included monthly quantities and average heat content for the fuels. The sulfur content of the coal was included in this data set, but petroleum coke sulfur content was not. To estimate the sulfur content of the petroleum coke, it was assumed the average pound of SO2/MBtu in the most recently received petroleum coke shipment was fired in each month.

CFB BACT


CFB with wet FGB upon which to base the expected control efficiency, there is no data to support or

refute these conclusions.

Table 2-13 Regulatory Reviews on the Potential SO2 Removal for CFB Boilers Evaluated for the Use

of Wet FGD Systems.

Unit Name Status Worst Case Fuel, lb SO2/MMBtu

% SO2 Removal From Worst Case Fuel


(Waste Coal) 99.1%

Virginia City Hybrid Energy Center Draft Permit 12/2007

6.0 (Waste Coal) 99.0%

Montana – Dakota Utilities Gascoyne Station Permit issued 6/2005. 3.48

(Lignite Coal) 98.9%A

Entergy – Louisiana Little Gypsy Station Permit issued 2/2007. 11.9

(Petroleum Coke) Not Technically

Feasible Southern Montana Electric

Highwood Station Permit issued 5/2007. 1.4 (Subbituminous) 97.3%A

NEVCO Energy - Sevier Power Company

Permit issued 11/2004.

0.7 (Subbituminous) 96.9%A

A This is the same overall control as the selected BACT option, which was dry FGD.

Performance of Operating Units on PC Boilers

We Energies recently commenced operation of wet FGD systems on the subbituminous coal, pulverized

coal-fired units at the Pleasant Prairie Power Plant. The initial performance test data for the Unit 1

indicated a wet FGD inlet SO2 concentration of 272 ppm, an outlet concentration of 8.9 ppm (0.022

lb/MMBtu), and a reduction of 96.6%. However, these units have only been in operation for a limited

period of time and these performance levels may not reflect the long term performance of these wet FGD

systems. However, this level of removal is comparable to the removal rates of other existing high-

removal wet FGD systems on low sulfur fuel such as Navajo and Clover stations.

The Navajo Generating Station in Page, Arizona is described as having one of the lowest SO2 emission

rates in the nation. Recent CEM data and coal quality reports for the Navajo Generating Station from

January, 2003 through July, 2005 indicate that during this period, the Navajo Units fired approximately

1.0 lb SO2/MMBtu coal and averaged 0.045 lb/MMBtu emissions, equal to 95.7% control. Another plant

cited by EPA as one of the lowest emitting power plants in the nation is the Clover Power Station in

Virginia. Recent CEM data and coal quality reports for the Clover Station show that the plant achieved

an average of 95.8% removal between January, 2003 and July, 2005. During this time, the fuel had an

CFB BACT


average sulfur content of approximately 1.52 lb SO2/MMBtu, and the average emission rate was 0.06 lb

SO2/MMBtu. Table 2-14 summarizes the inlet and outlet SO2 emission levels and removal efficiencies

for Navajo and Clover Stations. This information was collected from the EIA 767 data and CEM

reporting data from the EPA website (www.epa.gov). Appendix E includes plots of this information for

the individual units on a monthly basis for the time period covered by the Table 2-14.

Table 2-14 Demonstrated Long Term SO2 Control Efficiencies for Wet FGDA

Plant Scrubber Inlet

Loading, lb/MMBtu Scrubber Outlet

Loading, lb/MMBtu SO2 Removal Efficiency, %

Navajo (AZ) 0.90 0.04 95.7% Clover (VA) 1.52 0.06 95.8% A Information presented in this table is averaged over the period Jan., 2003 to July, 2005.


Based on the above regulatory analyses, the highest estimated combined control efficiency of the CFB

boiler, fabric filter baghouse, and wet FGD systems for regulatory review purposes was 99.1%.

Furthermore, based on the limited data indicating that wet FGD systems can achieve emission rates

below 0.04 lb/MMBtu on a long term basis the performance of a wet FGD is considered to be limited to

achieving a floor emission rate of 0.025 lb/MMBtu. On Tier 0 fuels the SO2 inlet rate to the wet FGD is

expected to be sufficiently low such that this floor emission rate shall be maintained. However, while

wet FGD systems are considered a technically feasible control option based on an engineering review

of the technology, based upon the RBLC and EPA’s National Coal-fired Utility Database, Updated

July 2008, no wet FGD systems are in operation on a CFB boiler, and there is no known commercial

operating history upon which to base expected SO2 emission rates.

2.2.4.2.4 Ranking of the Technically Feasible Control Options on Tier 0 Fuel. Table 2-15 is a summary of the ranking of the technically feasible SO2 control technologies and

combination of controls based on the above analysis of available technologies and Tier 0 fuel. As noted

above, while wet FGD systems are considered a technically feasible control option based on an

engineering review of the technology, there are no wet FGD systems in operation on a CFB boiler, and

there is no commercial operating history upon which to base the expected SO2 emission rate.

CFB BACT


Table 2-15 Ranking of the Technically Feasible Control Technologies for

SO2 Emissions on Tier 0 Fuel

Control Systems Expected Emission RateA, B

Basis of Expected Emission Rate

Is Technology Permitted?

Is Technology Operating in

Practice?

1. Tier 0 Fuel with CFB Boiler and semi-dry FGD.

0.022 lb/MMBtu and

309 tons/yr

Overall control of 98.6% based on a maximum fuel sulfur content of 1.6 lb/MMBtu.

YES YES

2. Tier 0 Fuel with CFB Boiler and wet FGD.

0.025 lb/MMBtu and

353 tons/yr


NO NO

3. Tier 0 Fuel with CFB Boiler.

0.14 lb/MMBtu and

1,962 tons/yr

1. Maximum 1.6 lb/MMBtu. 2. Overall control 91.3%.

YES YES

Footnotes AEmission rate is based on a 30-day rolling average. B Annual emissions are based on the maximum continuous rating and 8,760 hours per year of operation.

2.2.4.3 Step 3b- Rank the Technically Feasible Control Technologies for Tier I.

2.2.4.3.1 Combustion Controls. As indicnated in Step 3a, the SO2 removal inherent in the CFB boiler combustion technology with

limestone injection can be equivalent to the NSPS Subpart Da standard of 95% reduction of the potential

SO2 combustion concentration, or 0.14 lb/MMBtu.

2.2.4.3.2 Dry Flue Gas Desulfurization.



combustion concentration of the fuel is between 1.6 lb/MMBtu and 2.8 lb/MMBtu the combined control

efficiency of the CFB boiler, fabric filter baghouse, and dry FGD systems is expected to maintain 0.038

lb/MMBtu (98.6% removal from 2.8 lb/MMBtu). The emission rate of 0.038 lb/mmBtu results in a

minimum removal rate of 97.7% when the inlet rate is just above 1.6 lb/MMBtu. This lower end removal

rate is greater than the AES Puerto Rico removal effiency necessary to achieve the limit of 0.022

lb/mmBtu when firing the average sulfur content fuel.

2.2.4.3.3 Wet Flue Gas Desulfurization.


CFB BACT



boiler, fabric filter baghouse, and wet FGD systems for regulatory review purposes was 99.1%.

Furthremore, based on the limited data indicating that wet FGD systems can achieve emission rates

below 0.04 lb/MMBtu on a long term basis the performance of a wet FGD is considered to be limited to

achieving a floor emission rate of 0.025 lb/MMBtu. On Tier I fuels the SO2 inlet rate to the wet FGD is

expected to be sufficiently low such that this floor emission rate shall be maintained. However, while

wet FGD systems are considered a technically feasible control option based on an engineering review

of the technology, based upon the RBLC and EPA’s National Coal-fired Utility Database, Updated

July 2008, no wet FGD systems are in operation on a CFB boiler, and there is no known commercial

operating history upon which to base expected SO2 emission rates.

2.2.4.3.4 Ranking of the Technically Feasible Control Options on Tier I Fuel. Table 2-16 is a summary of the ranking of the technically feasible SO2 control technologies and

combination of controls based on the above analysis of available technologies and Tier I fuel. As noted





SO2 Emissions on Tier I Fuel





Practice?

1. Tier I Fuel with CFB Boiler and wet FGD.

0.025 lb/MMBtu and

353 tons/yr


NO NO

2. Tier I Fuel with CFB Boiler and semi-dry FGD.

0.038 lb/MMBtu and

534 tons/yr


YES YES

3. Tier I Fuel with CFB Boiler.

0.14 lb/MMBtu and

1,962 tons/yr

1. Maximum 2.8 lb/MMBtu. 2. Overall control 95%.

YES YES

Footnotes AEmission rate is based on a 30-day rolling average. B Annual emissions are based on the maximum continuous rating and 8,760 hours per year of operation.

CFB BACT


2.2.4.4 Step 3c- Rank the Technically Feasible Control Technologies for Tier II.

2.2.4.4.1 Combustion Controls. As indicnated in Step 3a, the SO2 removal inherent in the CFB boiler combustion technology with

limestone injection can be equivalent to the NSPS Subpart Da standard of 95% reduction of the potential

SO2 combustion concentration.

2.2.4.4.2 Dry Flue Gas Desulfurization.



combustion concentration exceeds 2.8 lb/MMBtu, the combined control efficiency of the CFB boiler,

fabric filter baghouse, and dry or semi-dry FGD systems is expected to maintain an emission rate of

0.057 lb/MMBtu. This emission rate is equal to an SO2 removal range of 98.0% to 99.4%. This

maximum removal rate is in excess of the maximum removal rate evaluated at Virginia City Hybrid

Energy Center. While the Virginia City Hybrid Energy Center rate is not considered representative of

BACT for lower Tier fuels, as discussed above, with a maximum sulfur content of 9.5 lb/MMBtu

exceeding this control rate is considered feasible as a BACT control rate. This is based on vendor

information and taking into consideration the high potential combustion concentration of the maximum

sulfur content fuel should result in easier attainment of higher removal rates than have been deonstarated

on lower sulfur fuels.

2.2.4.4.3 Wet Flue Gas Desulfurization.



boiler, fabric filter baghouse, and wet FGD systems for regulatory review purposes was 99.1%. Based on

the potential inlet rate and the evaluation of previous BACT reviews, the performance of a wet FGD

system with a CFB boiler on Tier II fuels is assumed to be equal to the performance of a CFB boiler with

a dry FGD on Tier II fuels. The combination of a wet FGD and CFB boiler is expected to maintain an

emission rate of 0.057 lb/MMBtu which is equal to SO2 removal range of 98.0% to 99.4%. This

maximum removal rate is in excess of the maximum removal rate evaluated at Virginia City Hybrid

Energy Center. However, while wet FGD systems are considered a technically feasible control option

based on an engineering review of the technology, based upon the RBLC and EPA’s National Coal-

fired Utility Database, Updated July 2008, no wet FGD systems are in operation on a CFB boiler, and

there is no known commercial operating history upon which to base expected SO2 emission rates.

CFB BACT


2.2.4.4.4 Ranking of the Technically Feasible Control Options on Tier II Fuel. Table 2-17 is a summary of the ranking of the technically feasible SO2 control technologies and

combination of controls based on the above analysis of available technologies and Tier II fuel. As noted





SO2 Emissions on Tier II Fuel





Practice?

1. Tier II Fuel with CFB Boiler and semi-dry FGD.

0.057 lb/MMBtu and

795 tons/yr

Overall control of 99.4% based on a fuel sulfur content of 9.5 lb/MMBtu.

YES YES

2. Tier II Fuel with CFB Boiler and wet FGD.C

0.057 lb/MMBtu and

795 tons/yr

Overall control of 99.4% based on a fuel sulfur content of 9.5 lb/MMBtu.

NO NO

3. Tier II Fuel with CFB Boiler.

0.48 lb/MMBtu and

4,415 tons/yr

1. Fuel sulfur content 9.5 lb/MMBtu.

2. Overall control 95%. YES YES

Footnotes AEmission rate is based on a 30-day rolling average. B Annual emissions are based on the maximum continuous rating and 8,760 hours per year of operation. C Because control options 1 & 2 are achieving the same level of reduction the lower cost technology is considered the higher

ranked control option.

Figure 2-4 displays the equivalent removal rates required to maintain the above BACT limits for the wet

and dry FGD options. The minimum removal rate required for AES Puerto Rico to achieve its emission

limit while firing its average fuel is also indicated for reference.

CFB BACT


Figure 2-4 Coal to Stack Removal Rate Required to Achieve BACT Emission Rates in Different Fuel Tiers

97.0%

97.5%

98.0%

98.5%

99.0%

99.5%

100.0%

00.511.522.533.544.555.566.577.588.599.5

lb SO2/MMBtu in Fuel

% R

emov

al

Dry Removal Wet Removal AES Puerto Rico Minimum Removal Tier II/I Break Tier I/0 Break

Tier IILimit: 0.057 lb/MMBtuWet & Dry

Tier 0Dry Limit: 0.022 lb/MMBtu

Wet Limit:0.025 lb/MMBtu

Teir IDry Limit: 0.038 lb/MMBtu

Wet Limit:0.025 lb/MMBtu

CFB BACT


2.2.5 STEP 4. Evaluate the Most Effective Controls.

2.2.5.1 Achievable Emission Reductions. When evaluating the achievable emission reductions for the available SO2 control technologies,

regulatory agencies generally evaluate the maximum expected control efficiency of the control or

combination of controls based on the worse-case fuel. In addition, agencies have also considered the

long term expected reduction based on the typical or average fuel. Because the range of fuels for NED3

varies significantly in sulfur content and the maximum expected control efficiency is not expected to be

constant through out the full range of inlet sulfur content, WPL is proposing to split this anaysis into

three sections, one for each fuel tier that is part of the project design.

2.2.5.2 STEP 4a. Evaluate the Most Effective Controls for Tier 0. 2.2.5.2.1 Rank No. 1: CFB Boiler with Dry FGD. The most effective SO2 control option is the use of a CFB boiler in combination with a semi-dry FGD

system. Based on the above analysis, this combination of controls has the potential to reduce SO2

emissions to 0.022 lb/MMBtu, and 309 tons per year. This technology represents BACT while firing

Tier 0 fuels and no further analysis is necessary for Tier 0 fuels.

2.2.5.3 STEP 4b. Evaluate the Most Effective Controls for Tier I. 2.2.5.3.1 Rank No. 1: CFB Boiler with Wet FGD. The most effective SO2 control option is the use of a CFB Boiler in combination with a wet FGD system.

Based on the above analysis, this combination of controls has the potential to reduce SO2 emissions to

0.025 lb/MMBtu, and 353 tons per year. However, as described in Tables 2-7 and 2-8, no wet FGD

systems are in operation on a CFB boiler, nor is there any known commercial operating history upon

which to base or confirm the expected SO2 emission rate.

2.2.5.3.2 Environmental Impacts The use of a wet FGD system may reduce the control of hazardous air pollutants as compared to a dry

FGD system. In a wet FGD pollution control system arrangement, the baghouse would be located

upstream of the wet FGD system, and the baghouse operating temperature would be substantially higher

than in a dry FGD arrangement. The lower baghouse operating temperature in the dry FGD system

arrangement increases the condensation and control of hazardous air pollutants such as beryllium and

selenium. The use of a wet FGD system will also consume greater amounts of water and result in a waste

water discharge stream. Because a dry FGD system would not have a wastewater discharge, the cost of a

zero liquid discharge system has been included in the wet FGD evaluation to eliminate the wastewater

CFB BACT


discharge stream, bring the comparison to an equitable basis and to eliminate scrubber blowdown as an

unacceptable source of mercury emissions. In addition, an advanced semi-dry FGD system will produce

a less visible plume than a wet FGD.

2.2.5.3.3 Energy Impacts A wet FGD system would require more auxiliary electric power than dry FGD systems. In a wet FGD

system, auxiliary electric power is required to operate slurry pumps, sludge dewatering, and for the

induced draft fan requirements to overcome the wet FGD system pressure drop. The pressure drop and

the additional induced draft fan power requirements would increase further in wet FGD systems using

more extensive gas distribution or gas sparging systems. For the NED 3 boiler, the power consumption

of a wet FGD system would be approximately 2 percent of the unit’s generating capacity, versus about 1

percent for the dry FGD system, or approximately 6 MW and 3 MW, respectively. An auxiliary power

requirement of 6 MW would be an energy penalty of approximately 50,000 MW-hr per year; enough

electric energy for the annual power requirements of about 4,000 homes. The auxiliary load to operate

the FGD system and the additional fan power due to the pressure drop across the FGD system is included

in the economic evaluation.

2.2.5.3.4 Economic Impacts Economic feasibility is normally evaluated according to the average and incremental cost effectiveness of

the control option. From the EPA’s guidance document the New Source Review Workshop Manual,

average cost effectiveness is expressed as the cost per ton of pollutant reduced. The incremental cost

effectiveness is the cost per additional ton reduced from the technology being evaluated as compared to

the next technology.

Table 2-18 is a summary of the average and incremental control costs for a wet FGD system as compared

to a dry FGD system. The average cost effectiveness for the use of the wet FGD system is $10,796 per

ton of SO2 controlled. The incremental annual cost for the use of a wet FGD system as compared to a dry

FGD system would be $8,900,000 per year. For an incremental reduction of 182 tons per year for the use

of the wet FGD system, the incremental cost effectiveness of the wet FGD system would be $48,845 per

ton of SO2 controlled.

CFB BACT


Table 2-18 Tier 1 Fuel Summary of the Average and Incremental Control Costs for a Wet FGD

System as Compared to a Dry FGD System. Parameter Wet FGD Dry FGD Controlled Emission Rate, lb/MMBtu 0.025 0.038 Potential SO2 Emissions, tons per year 350 533 Total Capital Requirement, $ $78,613,000 $38,005,000 Total Capital Requirement, $/kW $262 $127 Capital Recovery Factor (CRF) 0.0973 0.0973 Annual Capital Cost, $/yr $7,652,000 $3,699,000 Annual FGD O&M Cost, $/yr $9,749,000 $4,802,000 Additional Fuel Costs, $/yr $0 $0 Change in Boiler Limestone $/yr $0 $0 Total Annual Cost, $/yr $17,401,000 $8,501,000 Total SO2 Reduction, tons/yr 1,612 1,430 Average Control Cost, $ per ton $10,796 $5,946 Incremental Reduction, tons per year 182 Incremental Annual Cost, $/yr $8,900,000 Incremental Cost per Ton, $ per ton $48,845

Footnotes

1. The annual cost of the total capital requirement is given by the capital recovery factor (CRF):

where:

i = annual interest rate = 9.0% n = project life, years = 30

2. The average SO2 emission reduction for each option is based on the CFB boiler emission rate of 0.14 lb/MMBtu.

Regulatory Decisions Regarding Economic Feasibility.

Numerous permitting authorities have made decisions regarding the economic feasibility of air pollution

controls for coal-fired electric utility boilers which represent BACT. Table 2-19 is a summary of recent

BACT economic analyses by various review agencies in which a control technology was rejected as not

cost effective for BACT. The determinations summarized in Table 2-19 include decisions for SO2

emissions for both pulverized coal-fired boilers and CFB boilers. While cost effectiveness is determined

on a case-by-case basis, the following information on comparative economic costs of BACT options

gives some perspective on the costs that similar sources have not been expected to bear as BACT.

[ ]1)1()1(−+

+= n

n

iiiCRF

CFB BACT


Table 2-19 Summary of Recent BACT Economic Analyses by Various Review Agencies in which the

Control Technology was Rejected as not Cost Effective for BACT. Cost Effectiveness, $ per ton controlled Facility State Unit Type

Control Technology Rejected Average Incremental

1 Longleaf Energy Associates GA PC Wet FGD - $8,964

2 Rocky Mountain Power Hardin MT PC Wet FGD $1,395 $23,855

3 Virginia City Hybrid Energy Center VA CFB Wet FGD - $8,100

4 Basin Electric - Dry Fork Station WY PC Wet FGD $1,595 $15,299

5 Deseret Power Cooperative - Bonanza UT CFB Wet FGD $418 $10,540

Wet FGD - $27,3656 Southern Montana

Electric Coop- Highwood MT CFB Dry FGD - $7,939

7 Red Trail Energy Ethanol Plant ND CFB Wet FGD $1,041 $10,252

8 River Hill Power Company PA CFB Wet FGD - >$5,000

9 Highwood Generating Station MT CFB Wet FGD $27,370

10 Highwood Generating Station MT CFB Dry FGD $7,940

11 Energy Services of Manitowoc WI CFB Wet FGD $7,550

12 Wellington Development Greene Energy Project PA CFB Wet FGD - $5,764

13 Cargill - Blair Ethanol Plant NE CFB Dry FGD - $5,900

2.2.5.3.5 Conclusion From Table 2-19, the average SO2 control costs that similar sources have not been expected to bear as

BACT range between $418 and $27,370 dollars per ton of SO2 controlled, with a narrower range of

approximately $1,000 to $8,000 per ton if the two extreme values are eliminated. The average cost

effectiveness for the use of the wet FGD system is $10,796 per ton of SO2 controlled and the incremental

cost effectiveness is $48,845 per ton. Based upon the above determinations, both the average and

incremental costs of installing a wet FGD on NED 3’s CFB exceed the costs rejected in the

determinations above associated with installing a wet FGD on a PC. In addition, both the average and

CFB BACT


incremental costs associated with installing a wet FGD on NED 3 are within the average and incremental

costs rejected by other permitting authorities when evaluating installation of wet FGD on other CFBs. As

the above analysis has determined, the use of a wet FGD system in combination with a CFB boiler is at

the high end of the range of control options that have been found to be economically infeasible options in

other BACT analyses.

There are several technological and economic risks associated with the application of the unproven

combination of a wet FGD system downstream of a CFB boiler. The use of a wet FGD system would

have significant adverse economic impacts and would also have significant operating and economic risks,

since a wet FGD system has never been integrated with a CFB boiler. Based on these findings, the use of

a wet FGD system does not represent BACT for the control of SO2 emissions from NED 3 while firing

Tier I fuels. This conclusion is consistent with every other BACT analysis reviewed herein for the use of

wet FGD systems for the control of SO2 emissions from CFB boilers.

2.2.5.3.6 Rank No. 2: CFB Boiler with Dry FGD. The next ranked option for the control of SO2 emissions from NED 3 is the use of a CFB boiler in

combination with a dry FGD system. Based on the above analysis, this combination of controls has the

potential to reduce SO2 emissions to 0.038 lb/MMBtu and which is equivalent to 533 tons per year. This

technology represents BACT when firing Tier I fuels and no further analysis is necessary for Tier I fuels.

2.2.5.4 STEP 4c. Evaluate the Most Effective Controls for Tier II. The removal rates of a CFB boiler with a dry FGD system or a wet FGD system are considered equal

while firing Tier II fuels. Since no significant environmental or energy impact precludes the use of either

technology over the other, a dry FGD system is considered the top ranked technology due to the lower

cost.

2.2.5.4.1 Rank No. 1: CFB Boiler with Dry FGD. The top ranked option for the control of SO2 emissions is the use of a CFB boiler in combination with a

dry FGD system and high sulfur Tier II fuels. Based on the above analysis, this combination of controls

has the potential to reduce SO2 emissions to 0.057 lb/MMBtu, and 799 tons per year. This technology

represents BACT when firing Tier II fuels and no further analysis is necessary for Tier II fuels.

2.2.6 STEP 5. Proposed Sulfur Dioxide BACT Determination

Based upon this analysis, WPL has concluded that the use of a CFB boiler in combination with an

advanced semi-dry FGD system represents the best available control technology for SO2 emissions from

CFB BACT


the NED 3 boiler. In the above analysis, the use of a dry FGD system was accepted as the #1 ranked

technology for two out of the three fuel tiers while the use of a wet FGD systems was eliminated from the

remaining fuel tier based, partially, on an economically infeasible average control cost of $10,796 per ton

of SO2 controlled. Further supporting the rejection of the wet FGD system are the adverse environmental

and energy impacts summarized in section 2.2.5.3.2 and the unproven combination of a CFB boiler and

wet FGD would introduce operational risk for NED3. The performance of a wet FGD/CFB boiler

combination has been estimated, there are no operating CFB boilers with wet FGD control systems.

WPL proposes the following sulfur dioxide emission limits at three different fuel tiers to ensure high

levels of SO2 control for all fuel types. Figure 2-5 shows the proposed three-tier emission limit compared

to the NSPS Subpart Da emission limit for new fossil fuel-fired electric utility steam generating units

adopted on February 27, 2006.

WPL proposes that a three-tier SO2 emission limit approach go into effect 12 months after completion of

initial performance testing, to provide a sufficient ‘break-in’ period to fine-tune and balance the emission

control equipment for optimum efficiency. Prior to that point in time, WPL’s requested interim BACT

emission limit of 0.057 lb/MMBtu would be in effect for any fuel burned. The explanation for a need for

a break-in period may be found in NOx BACT. WPL considers the inter-relationship between NOx and

SO2 control (explained in the NOx BACT discussion) to call for a break-in period applicable to both

pollutants. The higher Tier limit is selected to allow WPL to test a significant portion of the range of

proposed fuel blends during the break in period to optimize SNCR performance for both lower sulfur and

higher sulfur blends.

Proposed Sulfur Dioxide BACT Emission Limits

1. SO2 emissions shall be controlled by the use of a circulating fluidized bed boiler in

combination with an advanced semi-dry flue gas desulfurization system.

2. Prior to the date (which ever occurs first) which is 12 months after completion of initial

performance testing or 15 months from the first firing of coal or petroleum coke, emissions

from the unit shall be limited to 0.057 lb/MMBtu heat input on a 30 day rolling average.

3. On and after the date (which ever occurs first) which is 12 months after completion of initial

performance testing or 15 months from the first firing of coal or petroleum coke, the unit SO2

emissions shall be limited as follows:

CFB BACT


a. When the potential SO2 combustion concentration of the fuel is less than or equal to 1.60

lb/MMBtu, SO2 emissions may not exceed 0.022 lb/MMBtu, based on a 30-day rolling

average.

b. When the potential SO2 combustion concentration of the fuel is greater than 1.6

lb/MMBtu and less than or equal to 2.8 lb/MMBtu, SO2 emissions may not exceed 0.038

lb/MMBtu, based on a 30-day rolling average.

c. When the potential SO2 combustion concentration of the fuel is greater than 2.8

lb/MMBtu, SO2 emissions may not exceed 0.057 lb/MMBtu, based on a 30-day rolling

average.

d. During any 30-day period when the fuels fired have potential SO2 combustion

concentration which meet the conditions in any combination of a, b or c above, SO2

emissions may not exceed the following:

Limit = 0.022A + 0.038B + 0.057C lb/MMBtu 30

Where the limit is based on a 30-day rolling average, and:

A = the number of boiler operating days when the potential SO2 combustion

concentration of the combusted fuel is less than or equal to 1.6 lb/MMBtu.

B = the number of boiler operating days when the potential SO2 combustion

concentration of the combusted fuel is less or equal to 2.8 lb/MMBtu but

greater than 1.6 lb/MMBtu.

C = the number of boiler operating days when the potential SO2 combustion

concentration of the combusted fuel is greater than 2.8 lb/MMBtu.

Compliance is demonstrated by summing the previous 30 days pounds of SO2

emissions and dividing by the sum of the previous 30 days heat input.

2.2.6.1 Startup and Shutdown BACT Conditions. WPL proposes that the above emission limits apply to all periods, including startup and shutdown.

Furthermore, the following limitations will be placed on the unit for startup and shut down:

1. Start up for the CFB boiler will be accomplished using low sulfur fuel oil with a sulfur

concentration less than 0.0015%. This will ensure that startup SO2 emissions are minimized.

CFB BACT


a. If WDNR agrees that ultra low fuel oil is not available to WPL with a sulfur content of

0.0015 percent or less then WPL shall utilize low sulfur fuel oil with a sulfur content of

0.05 percent or less.

b. “Available” shall mean readily available for purchase by any member of the public in the

quantities that WPL requires, and does not require a refinery to produce a specialty

product.

2. Startup begins with fuel oil firing via special combustor at the base of the boiler, as

recognized by flame scanners and recorded by the CEMs.

a. Fuel oil firing rate continues to increase until furnace temperatures are sufficient to allow

solid fuel to be gradually added. At approximately 30% unit output, fuel oil firing starts

to decrease and solid fuel firing initiates and continues to increase.

b. At approximately 40% output, minimum steady-state operating load is established when

the fuel and limestone reagent bed have reached a reliable, sustainable temperature

(approximately 1,550 to 1,600 degrees F) and the fuel oil supply is terminated. For

normal dispatch above the 40% minimum, no additional fuel oil firing is necessary.

3. The unit shut down begins when the startup process is reversed and fuel oil is reintroduced to

maintain a stable solid fuel and reagent bed.

a. Solid fuel firing is gradually decreased to a point at about 30% output where solid fuel

firing stops completely and only fuel oil is used to continue to reduce output to

approximately 10%.

b. At this point, fuel oil firing ends and the unit is brought off line.

c. This point is recorded by the CEMs.

CFB BACT


Figure 2-5 Comparison of the Proposed 2-Tier Sulfur Dioxide Emission Limits of 0.022, 0.038 and 0.057 lb/MMBtu to the New Source Performance Standard Subpart Da Emission Limit

0.00

0.05

0.10

0.15

0.20

0.25

0.30

0.35

0.40

0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0Uncontrolled SO2 Emission Rate, lb/mmBtu

Emis

sion

Lim

it, lb

/mm

Btu

Proposed BACT Emission Limit

NSPS Subpart Da Emission Limit

Documents

PSC REF#:100388