1 Reasonable Progress (RP) Four-Factor Analysis of Co ntrol Options For Colstrip Energy Limited Partnership, Rosebud Po wer Plant, in Colstrip, Montana

U.S. EPA Region 8 Air Program March 20, 2012

Executive Summary

This four-factor analysis documents the basis for d etermination of Reasonable Progress (RP) control options for control of sulfur dioxide (SO 2 ) and nitrogen oxide (NO

x ) emissions at Colstrip Energy Limited Partnership (CELP), Rosebud Power Plant, an electric utility power plant in Colstrip, Montana, operated by Rosebud Ope rating Services. The four-factor analysis consists of the following steps:

Step 1 – Identify All Available Technologies Step 2 – Eliminate Technically Infeasible Options Step 3 – Evaluate Control Effectiveness of Remainin g Control Technology Step 4 – Evaluate Impacts and Document Results: Factor 1: Cost of compliance Factor 2: Time necessary for compliance Factor 3: Energy and non-air quality environmenta l impacts of compliance Factor 4: Remaining useful life Step 5 – Select Reasonable Progress Controls

This analysis is based on the following submittals from CELP:

→ Response to Request for Information for the Colstr ip Energy Limited Partnership Facility Pursuant to Section 114(a) of the Clean Air Act (42 U.S.C. Section 7414(A) (“CELP Initial Response”), Rosebud Energy Corp. (Mar. 11, 2009)

→ Response to Additional Reasonable Progress Informa tion for the Colstrip Energy Limited Partnership Facility Pursuant to Section 114(a) of the Clean Air Act (42 U.S.C. Section 7414(A)) (“CELP Additional Response”), Rosebud Ener gy Corp., Prepared by Bison Engineering Inc (Feb. 24, 2011)

The Rosebud Power Plant is rated at 43 megawatts gr oss output (30 megawatts net). The primary source of emissions consists of a single ci rculating fluidized bed (CFB) boiler, fired on waste coal, with average heating value of 8,073 Btu /lb, sulfur content of 1.5% to 1.7% by weight, and ash content of 14% to 15.6% by weight. This Reasonable Progress analysis focuses

on the CFB boiler.

The boiler and emission controls were installed in 1989-90. Expected life of the boiler and its emission control equipment is 40 years from date of installation. The boiler was manufactured by Tampela-Keeler and utilizes a twin-cyclone desig n. Heat input capacity is 516 MMBtu per

hour. Emission controls consist of a fabric filter baghouse for particulate control and limestone injection into the boiler for sulfur dioxide (SO 2 ) control. There are no nitrogen oxide (NO

x ) add-2

on controls. The limestone injection system is rat ed at no less than 79% control efficiency. Limestone injection rate is 5.5 tons/hr, or about 9 1 tons/day. The limestone is injected with the waste coal prior to combustion in the boiler. 1

CELP states that average hourly controlled emission s during 2007, as determined from CEMS data, were 310 lbs/hr for SO 2 and 250 lbs/hr for NO

x . This is equivalent to about 1,358 tons/yr

for SO 2 and 1,095 tons/yr for NO

x , assuming the boiler operates at capacity for 8,76 0 hrs/yr. Actual annual tonnages would be somewhat less; none were listed by CELP in its March 13,

2009 submittal. 2 Emissions during 2002, listed in EPA’s National E missions Inventory, were 705 tons/yr for SO 2 and 537 tons/yr for NO

x . In its cost analyses, CELP used 1,141 tons/yr fo r SO 2 and 768 tons/yr for NO

x . 3

Particulate matter (PM) emissions are controlled by a fabric filter baghouse that is designed to achieve greater than 99% control of particulates. 4 As discussed in Section V.D.6.b. of EPA’s Federal Register

notice on the proposed Montana regional haze Feder al Implementation Plan, the contribution from point sources to primary organic aerosols, elemental carbon, and PM 2.5 at Montana Class I areas is very small, and modeling t ends to confirm that PM emissions from point sources do not have a very large impact. The refore, EPA is proposing that additional controls for PM are not necessary for this planning period.

Reasonable Progress Evaluation of SO 2 Emissions

As stated above, current SO 2 control consists of a limestone injection system r ated at no less than 79% control efficiency. Limestone injection rate i s 5.5 tons/hr, or about 91 tons/day. The limestone is injected with the waste coal prior to combustion in the boiler.

Step 1: Identify All Available Technologies

EPA has identified the following technologies as be ing available for SO 2 emission reductions, beyond those achieved by the current control config uration at Rosebud Power Plant:

1. Limestone injection process upgrade

2. Dry scrubbing (a) Spray dry absorber (b) Dry sorbent injection (c) Circulating dry scrubber (d) Hydrated ash reinjection

3. Wet scrubbing (a) Wet lime scrubber (b) Wet limestone scrubber (c) Dual alkali scrubber

1 CELP Initial Response, p. 3; CELP Additional Respo nse, p. 2-2.

2 CELP Initial Response, p. 3.

3 CELP Additional Response, pp. 7-2, 7-3 and Appendi x A.

4 CELP Additional Response, p. 2-1.3

Below is a description of each available control te chnology.

Limestone Injection Process Upgrade

CELP currently controls SO 2 emissions using limestone injection. Crushed lime stone is injected with the waste coal prior to its combustion in the boiler, becoming the solid medium in which coal combustion takes place. When limestone is hea ted to 1550 o F, it releases carbon dioxide (CO 2 ) and forms lime (CaO), which subsequently reacts w ith acid gases released from the burning coal, to form calcium sulfates and calcium sulfites. The calcium compounds are removed as PM by the baghouse. Depending on the fu el fired in the boiler and the total heat input, this process currently removes 70% to 90% of SO2 emissions, on average about 80%. Increasing the limestone injection rate beyond curr ent levels could theoretically result in a

modest increase in SO 2 control. 5

Spray Dry Absorber (SDA)

SDAs use lime slurry and water injected into a towe r to remove SO 2 from the combustion gases. The towers must be designed to provide adequate con tact and residence time between the exhaust gas and the slurry in order to product a re latively dry by-product. The process equipment associated with an SDA typically includes an alkaline storage tank, mixing and feed tanks, atomizer, spray chamber, particulate control device, and recycle system. The recycle system collects solid reaction product and recycles it back to the spray dryer feed system to reduce alkaline sorbent use. SDAs are the commonly used dry scrubbing method in large industrial and utility boiler applications. SDAs h ave demonstrated the ability to achieve 90% to

94% SO 2 reduction. 6

Dry Sorbent Injection (DSI)

Dry sorbent injection (DSI) involves the injection of powdered or hydrated sorbent (typically alkaline) directly into the flue gas exhaust stream . Dry sorbent injection systems are simple systems, and generally require a sorbent storage ta nk, feeding mechanism, transfer line and blower, and injection device. The dry sorbent is t ypically injected countercurrent to the gas flow through a venturi orifice. An expansion chamber is often located downstream of the injection point to increase residence time and contact effici ency. Particulates generated in the reaction are controlled in the system’s particulate control devi ce.

SO 2 control efficiencies for dry sorbent injection sys tems by themselves (not downstream of limestone injection systems) are approximately 50%, but if the sorbent is hydrated lime, then 80% or greater removal can be achieved. These sys tems are commonly called lime spray dryers.

5 CELP Additional Response, p. 2-2.

6 US EPA Region 8, Final Statement of Basis, PSD Per mit to Construct, Deseret Power Elec. Coop., Bonanz a Power Plant (“Deseret Bonanza SOB”), p. 92 (Aug. 30, 2007 ), available at http://www.epa.gov/region8/air/pdf/FinalStatementOf Basis.pdf4

Circulating Dry Scrubber (CDS)

A CDS uses a fluidized bed of dry hydrated lime rea gent to remove SO 2 . Flue gas passes through a venturi at the base of a vertical reactor tower and is humidified by a water mist. The humidified flue gas then enters a fluidized bed of powdered hydrated lime where SO 2 is removed. The dry by-product produced by this syste m is routed with the flue gas to the particulate removal system. A CDS can achieve remo val efficiency similar to that achieved by

SDA on CFB boilers. 7

Hydrated Ash Reinjection (HAR)

The HAR process is a modified dry FGD process devel oped to increase the use of unreacted lime in the CFB ash and any free lime left from the furn ace burning process. HAR will further reduce

the SO 2 concentration in the flue gas. The actual design of an HAR system is vendor-specific, but in general, a portion of the collected ash and lime is hydrated and re-introduced into a

reaction vessel located ahead of the fabric filter inlet. In conventional boiler applications, additional lime may be added to the ash to increase the mixture’s alkalinity. For CFB applications, sufficient residual lime is available in the ash and additional lime is not required.

HAR downstream of a CFB boiler that utilizes limest one injection can reduce the remaining SO 2 by about 80%. 8

Wet Lime Scrubber

The wet lime scrubbing process uses alkaline slurry made by adding lime to water. The alkaline slurry is sprayed into the exhaust stream and react s with the SO 2 in the flue gas. Insoluble calcium sulfite (CaSO 3 ) and calcium sulfate (CaSO 4 ) salts are formed in the chemical reaction

that occurs in the scrubber. The salts are removed as a solid waste by-product. The waste byproduct is mainly CaSO 3 , which is difficult to dewater. Solid waste by-pr oducts from wet lime scrubbing are typically managed in dewatering ponds and landfills.

Wet Limestone Scrubber

Wet limestone scrubbers are very similar to wet lim e scrubbers. Again, alkaline slurry is sprayed

into the exhaust stream and reacts with the SO 2 in the flue gas. The use of limestone (CaCO 3 ) instead of lime requires different feed preparation equipment and a higher liquid-to-gas ratio. The higher liquid-to-gas ratio typically requires a larger absorbing unit. The limestone slurry process also requires a ball mill to crush the lime stone feed. Similar to wet lime scrubbers, wet limestone scrubbers generate sludge that can create material handling and disposal issues.

Wet lime and limestone scrubbers have been demonstr ated to achieve greater than 99% control efficiency. 9

7 Id.

8 Id., p. 93.

9 Id., p. 94 (for proposed CFB boiler, indicating th at a wet FGD scrubber plus limestone injection can achieve 99.1% control efficiency).5

Dual Alkali Wet Scrubber

Dual-alkali scrubbers use a sodium-based alkali sol ution to remove SO 2 from the combustion exhaust gas. The process uses both sodium-based an d calcium-based compounds. The sodiumbased reagents absorb SO 2 from the exhaust gas, and the calcium–based soluti on (lime or limestone) regenerates the spent liquor. Calcium s ulfites and sulfates are precipitated and discarded as sludge, and the regenerated sodium sol ution is returned to the absorber loop. The dual-alkali process requires lower liquid-to-ga s ratios than scrubbing with lime or limestone. The reduced liquid-to-gas ratios generally mean sma ller reaction units; however, additional regeneration and sludge processing equipment is nec essary.

A sodium-based scrubbing solution, typically consis ting of a mixture of sodium hydroxide, sodium carbonates, and sodium sulfite, is an effici ent SO 2 control reagent. However, the process generates a sludge that can create material handlin g and disposal issues. The control efficiency

is similar to the wet lime/limestone scrubbers at a pproximately 95% or greater.

Step 2: Eliminate Technically Infeasible Options

Limestone Injection Process Upgrade

The current limestone injection system is operating at or near its maximum capacity. The boiler feed rates are approximately 770 tons/day of waste coal and 91 tons/day of limestone. Increasing limestone injection beyond the current levels would result in plugging of the injection lines, increased bed ash production, which can reduce comb ustion efficiency, and increased particulate loading to the baghouses. Therefore, increasing li mestone injection beyond its current level would require major upgrades to the limestone feedi ng system and the baghouses. 10 Only

modest increases in SO 2 removal efficiency, if any, would be expected with this scenario, compared to add-on SO 2 control systems discussed below. Therefore, a lim estone injection process upgrade is eliminated from further consider ation.

Circulating Dry Scrubber

CDS systems result in high particulate loading to t he unit’s particulate control device. Because of the high particulate loading, the pressure drop across a fabric filter would be unacceptable; therefore, electrostatic precipitators are generall y used for particulate control. CELP has a high efficiency fabric filter (baghouse) in place. Base d on limited technical data from noncomparable applications and engineering judgment, E PA is determining that CDS is not technically feasible for this baghouse-equipped fac ility. 11 Therefore, CDS is eliminated from

further consideration.

Dry Sorbent Injection (DSI)

A DSI system is not practical for use in a CFB boil er such as CELP, where limestone injection is already being used upstream in the boiler for SO 2 control. With limestone injection, the CFB

10 CELP Additional Response, p. 2-2.

11 Deseret Bonanza SOB, p. 92 (indicating that CDS sy stems have thus far not been used on CFB boilers).6

boiler flue gas already contains excess unreacted l ime. Fly ash containing this unreacted lime is reinjected back into the CFB boiler combustion bed, as part of the boiler operating design. A DSI system would simply add additional unreacted li me to the flue gas and would probably achieve little, if any, additional SO 2 control. 12 If used instead of limestone injection, rather th an in addition to limestone injection (the only practi cal way it might be used), DSI would achieve less control efficiency (50%) than the limestone in jection system already being used (70% to 90%). Therefore, DSI is eliminated from further co nsideration.

Note: CELP did not eliminate DSI as technically in feasible at Step 2, but calculated the cost of installing and using DSI at Step 4. CELP calculate d the average cost effectiveness using a control efficiency of 50%. 13 For reasons explained above, EPA believes this co ntrol efficiency figure is too high, where DSI is used downstream of limestone injection. Actual control efficiency for DSI in such a scenario would probabl y be very low, such that average cost effectiveness would be very high, eliminating DSI a s too expensive, even if it was to be considered technically feasible.

Wet Scrubbing

There is limited area at Rosebud Power Plant to ins tall additional SO 2 controls. A wet scrubber would require high quantities of water and dewateri ng ponds. The wet FGD scrubber systems with the higher water requirements (wet lime scrubb er, wet limestone scrubber, dual alkali wet scrubber) would require an on-site dewatering pond or an additional landfill to dispose of scrubber sludge. Due to the limited available spac e, its proximity to the East Armels Creek to the east of the plant, an unnamed creek to the sout h of the plant, and limited water availability for these controls, 14 EPA considers these technologies technically infea sible and does not evaluate

them further.

The remaining technically feasible SO 2 control options for CELP are SDA and HAR.

Step 3: Evaluate Control Effectiveness of Remaining Control Technology

Baseline SO 2 emissions from CELP are 1,141 tons per year. A su mmary of emissions projections for the various control options is prov ided in Table 1 below. Since limestone injection is already in use at the CELP facility, t he control efficiencies and emissions reductions show below are those that might be achieved beyond the control already being achieved by the existing limestone injection system.

12 Id., p. 93.

13 CELP Additional Response, Appendix A, DSI control cost spreadsheet.

14 CELP Additional Response, p. 2-5.7 Table 1 Summary of CELP SO 2 Reasonable Progress Analysis Control Technologies

Control Option Control

Effectiveness (%) Emissions

Reduction (tpy) Remaining

Emissions (tpy)

SDA 80 913 228

HAR 50 571 570

Step 4: Evaluate Impacts and Document Results

Factor 1: Cost of Compliance

Table 2 provides a summary of estimated annual cost s for the various control options. EPA has relied on the control costs provided by CEL P, 15 with two exceptions. First, EPA calculated the annual cost of capital using a 7% an nual interest rate and a 20-year equipment life (which yields a capital CRF of 0.0944), as specifie d in the Office of Management and Budget’s Circular A-4, Regulatory Analysis. 16 Second, EPA calculated the cost of SDA and HAR in two ways: (1) with baghouse replacement, and (2) witho ut baghouse replacement. The calculated costs by CELP for both SDA and HAR included replace ment of the existing baghouse. CELP cited one equipment vendor as saying that the bagho use design must be matched with the add-on control system and its particulate loading; however , CELP did not explain why the baghouse would need to be replaced to accommodate either SDA or HAR. 17

Table 2
Summary of CELP SO 2 Reasonable Progress Cost Analysis

Control Option Control

Effectiveness (%) Tons

SO2

Reduced

from

Baseline Capital Cost

($) Annual Cost

of Capital ($) (CRF=.0944) Annual

O&M Cost ($) Total

Annual Cost ($) Average Cost

Effectiveness ($/ton reduced)

SDA w/o replacing baghouse 80 913 18,760,005 1,770,944 1,367,506 3,138,450 3,4 37

HAR w/o replacing baghouse 50 571 13,362,115 1,261,383 842,160 2,103,543 3,684

SDA with baghouse replaced 80 913 18,760,005 + 5,768,033 = 24,528,038 2,315,446 1,367,506 + 736,520 = 2,104,206 4,419,472 4,840

HAR with baghouse replaced 50 571 13,362,115 + 5,768,033 = 19,130,148 1,805,885 842,160 + 736,520 = 1,578,680 3,384,565 5,927

15 CELP Additional Response, Appendix A, pp. 17-24.

16 Available at: http://www.whitehouse.gov/omb/circulars_a004_a-4/

. 17 CELP Additional Response, p. 3-1.8

Factor 2: Time necessary for compliance

EPA has relied on CELP’s estimates that the time ne cessary to complete the modifications to the boiler to accommodate SDA or HAR, without baghouse replacement, would be approximately four to six months and that a boiler outage of appr oximate two to three months would be necessary to perform the installation of either sys tem. As noted previously, CELP states that complete replacement or major modifications to the existing baghouse would be necessary; however, the company does not explain why the exist ing baghouse would need to be replaced or

modified to accommodate SDA or HAR. 18

Factor 3: Energy and non-air quality environmental impacts of compliance

Wet FGD systems are estimated to consume 1% to 2.5% of the total electric generation of the plant and can consume approximately 40% more than d ry FGD systems (SDA). Electricity requirements for a HAR system are less than FGD sys tems. DSI systems are estimated to consume 0.1% to 0.5% of the total plant generation. 19 For reasons explained above, wet FGD systems and DSI systems have already been eliminate d as technically infeasible.

SO 2 controls would result in increased ash production at the CELP facility. Boiler ash is currently either sent to a landfill or sold for ben eficial use, such as oil well reclamation. Changes in ash properties due to increased calcium sulfates and calcium sulfites could result in the ash being no longer suitable to be sold for beneficial uses. If the ash properties were to change such that the ash could no longer be sold for beneficial use, the loss of this market would cost approximately $1,020,000 per year at the current as h value and production rates (approximately 100,000 tons of ash per year). The loss of this ma rket could also result in the company having to dispose of the ash at its current landfill, which i s adjacent to the plant. The cost to dispose of th e ash would be approximately $62,000 per year. The t otal cost from the loss of the beneficial use market and the increase in ash disposal costs would be a total of $1,082,000 per year. 20 This potential cost has not been included in the cost de scribed above, as it is only speculative, being based on an undetermined potential future change in ash properties.

As described above, wet FGD scrubber systems with t he higher water requirements (wet lime scrubber, wet limestone scrubber, dual alkali wet s crubber) would require an on-site dewatering pond or an additional landfill to dispose of scrubb er sludge.

Factor 4: Remaining useful life

EPA has determined that the default 20-year amortiz ation period is most appropriate to use as the remaining useful life of the facility. Without com mitments for an early shut down, EPA cannot consider a shorter amortization period in its analy sis.

18 Id.

19 Id., p. 4-1.

20 Id.9

Step 5: Select Reasonable Progress Controls

EPA has considered the following four factors: the cost of compliance; the time necessary for compliance; the energy and non-air quality environm ental impacts of compliance; and the remaining useful life of the source. EPA is also t aking into account the size of the facility, the baseline Q/D of the facility, and the potential red uction in Q/D from the controls. Given the cost of $3,437 per ton of SO 2 (at a minimum) for the most cost-effective option (SDA), the relatively small size of CELP, and the small baseline Q/D of 1 1, EPA finds it reasonable to not impose any

of the SO 2 control options. EPA therefore proposes to not re quire additional SO 2 controls for this planning period. 21

Reasonable Progress Evaluation of NOx Emissions

Currently there are no NO

x controls at the CELP facility.

Step 1: Identify All Available Technologies

EPA has identified the following technologies as be ing available for NO

x emission reductions at

the Rosebud Power Plant:

1. Selective Catalytic Reduction (SCR)

2. Selective Non-Catalytic Reduction (SNCR)

3. Low Excess Air (LEA)

4. Flue Gas Recirculation (FGR)

5. Overfire Air (OFA)

6. Low NO

x Burners (LNB)

7. Non-thermal Plasma Reactor

8. Carbon Injection into Combustion Chamber

Selective Catalytic Reduction (SCR)

SCR is a post-combustion gas treatment technique th at uses either ammonia (NH 3 ) or urea in the presence of a metal-based catalyst to selectively r educe NO and NO 2 to molecular nitrogen, water, and oxygen. The catalyst lowers the tempera ture required for the chemical reaction

between NO

x and the reducing agent. Technical factors that im pact the effectiveness of this technology include the catalyst reactor design, ope rating temperature, type of fuel fired, sulfur content of the fuel, design of the ammonia injectio n system, and the potential for catalyst poisoning.

21 As explained in Section V.D.6.b of EPA’s Federal R egister notice on the proposed Montana regional haze Feder al Implementation Plan, Q/D means the quantity of a so urce’s combined SO 2 and NO

x emissions, in tons per year, divided by the distance in kilometers from the sour ce to the nearest Federal Class I area.10

SCR has been demonstrated to achieve high levels of NO

x reduction in the range of 80% to 90% control, for a wide range of industrial combustion sources, including PC and stoker coal-fired boilers and natural gas-fired boilers and turbines. EPA used 80% for its analysis.

Typically, installation of the SCR is upstream of the particulate control device (e.g., baghouse). However, calcium oxide (from a dry scrubber) in the exhaust stream can cause the SCR catalyst to plug and foul, which would lead to an ineffectiv e catalyst.

SCRs are classified as a low dust SCR (LDSCR) or hi gh dust SCR (HDSCR). LDSCR is usually applied to natural gas combustion units or after a particulate control device. HDSCR units can

be installed on solid fuel combustion units before the particulate control device, but they have

their limitations. Installation of SCR in a low du st flue gas stream is often not practical, especially on an existing boiler. The reason is t hat the low dust portion of a flue gas stream is located after a baghouse or precipitator. The temp erature of the flue gas stream is too low in these areas for proper operation of an SCR. The te mperature range for proper operation of an

SCR is between 480 o F and 800 o F. Many of the CFBs in the United States have bagh ouses for particulate control. The normal maximum allowable temperature for a baghouse is 400 o F.

Therefore, on some installations, regenerative SCR (RSCR) is installed. RSCRs are expensive to install and expensive to operate, because an RSCR r equires the use of burners to heat up the flue gas stream in order for the NO

x capture to occur. This is often an efficiency dec rease for the boiler, significant increase in operating cost, and often not a practical solution. For this reason, RSCR was not evaluated as a control option for CELP . Instead, HDSCR was evaluated.

Selective Non-Catalytic Reduction (SNCR)

SNCR involves the non-catalytic decomposition of NO

x to nitrogen and water. An NO

x reducing agent, typically ammonia or urea, is injected into the upper reaches of the furnace, through injection nozzles at the cyclone inlets. Because c atalyst is not used to drive the reaction, temperatures of 1600 o F to 2100 o F are required.

Typical NO

x control efficiencies range from 40% to 60%, depend ing on inlet NO

x concentrations, fluctuating flue gas temperatures, residence time, amount and type of nitrogenous reducing agent, mixing effectiveness, acceptable le vels of ammonia slip, and presence of interfering chemical substances in the gas stream. Guaranteed NO

x reduction rates are in the 50% range to limit ammonia slip to 10 ppm. EPA use d 50% for its analysis.

Low Excess Air (LEA)

LEA operation involves lowering the amount of combu stion air to the minimum level compatible with efficient and complete combustion. Limiting t he amount of air fed to the furnace reduces the availability of oxygen for the formation of fue l NO

x and lowers the peak flame temperature,

which inhibits thermal NO

x formation.

Emissions reductions achieved by LEA are limited by the need to have sufficient oxygen present for flame stability and to ensure complete combusti on. As excess air levels decrease, emissions11

of carbon monoxide (CO), hydrocarbons (HC) and unbu rned carbon increase, resulting in lower boiler efficiency. Other impediments to LEA operat ion are the possibility of increased corrosion and slagging in the upper boiler because of the red ucing atmosphere created at low oxygen

levels.

Flue Gas Recirculation (FGR)

FGR is a flame-quenching technique that involves re circulating a portion of the flue gas from the economizers or the air heater outlet and returning it to the furnace through the burner or windbox. The primary effect of FGR is to reduce th e peak flame temperature through absorption of the combustion heat by relatively cooler flue ga s. FGR also serves to reduce the oxygen

concentration in the combustion zone.

Overfire Air (OFA)

OFA allows staged combustion by supplying less than the stoichiometric amount of air theoretically required for complete combustion thro ugh the burners. The remaining necessary combustion air is injected into the furnace through overfire air ports. Having an oxygendeficient primary combustion zone in the furnace lo wers the formation of fuel NO

x . In this atmosphere, most of the fuel nitrogen compounds are driven into the gas phase. Having combustion occur over a larger portion of the furna ce lowers peak flame temperatures. Use of a cooler, less intense flame limits thermal NO

x formation.

Poorly controlled OFA may result in increased CO an d HC emissions, as well as unburned carbon in the fly ash. These products of incomplet e combustion result from a decrease in boiler efficiency. OFA may also lead to reducing conditio ns in the lower furnace that in turn may lead

to corrosion of the boiler.

Low NO

x Burners (LNB)

LNBs integrate staged combustion into the burner, c reating a fuel-rich primary combustion zone.

Fuel NO

x formation is decreased by the reducing conditions in the primary combustion zone.

Thermal NO

x is limited due to the lower flame temperature caus ed by the lower oxygen concentration. The secondary combustion zone is a fuel-lean zone where combustion is completed. LNB may result in increased CO and HC e missions, decreased boiler efficiency, and

increased fuel costs.

Non-thermal Plasma Reactor

This control technique involves using methane and h exane as reducing agents. Non-thermal plasma has been shown to remove NO

x in a laboratory setting with a reactor duct only t wo feet long. The reducing agents were ionized by a transi ent high voltage that created a non-thermal plasma. The ionized reducing agents reacted with N O

x and achieved a 94% destruction efficiency. There are indications that even higher destruction efficiency can be achieved. A

successful commercial vendor uses ammonia as a redu cing agent to react with NO

x in an electron beam generated plasma. Such a short reactor can me et available space requirements for virtually12

any plant. The non-thermal plasma reactor could al so be used without a reducing agent to generate ozone and use that ozone to raise the vale nce of nitrogen for subsequent absorption as nitric acid. This control technology may have prac tical potential for application to coal-fired CFB boilers as a technology transfer option. 22

Carbon Injection into Combustion Chamber

A version of sorbent injection uses carbon injected into the air flow to finish the capture of NO

x . The carbon is captured in either the baghouse or th e ESP just like other sorbents. 23

Step 2: Eliminate Technically Infeasible Options

LEA, FGR, and OFA are typically used on Pulverized Coal (PC) units and cannot be used on

CFB boilers due to air needed to fluidize the bed. 24 While LEA may have substantial effect on

NO

x emissions at PC boilers, it has much less effect o n NO

x emissions at combustion sources such as CFBs that operate at low combustion tempera tures. FGR reduces NO

x formation by reducing peak flame temperature and is ineffective on combustion sources such as CFBs that already operate at low combustion temperatures. Fo r these reasons, LEA, FGR and OFA are

eliminated from further consideration.

LNBs are typically used on PC units and cannot be u sed on CFB boilers because the combustion

occurs within the fluidized bed. 25 CFB boilers do not use burners during normal oper ation. Therefore, LNBs are eliminated from further conside ration.

While a non-thermal plasma reactor may have practic al potential for application to coal-fired CFB boilers as a technology transfer option at Step 1 of the analysis, it is not known to be commercially available for CFB boilers. 26 Therefore, a non-thermal plasma reactor is eliminat ed

from further consideration.

Although carbon injection is an emerging technology used to reduce mercury emissions, it has not been used anywhere to control NO

x . Therefore, it is eliminated from further conside ration.

The remaining technically feasible NO

x control options for CELP are HDSCR and SNCR.

Step 3: Evaluate Control Effectiveness of Remaining Control Technology

Baseline NO

x emissions from CELP are 768 tpy. A summary of emi ssions projections for the various control options is provided in Table 3.

22 Deseret Bonanza SOB, p. 46.

23 US EPA, Office of Air Quality Planning and Standar ds, Technical Bulletin: Nitrogen Oxides (NO

x ), Why and How They are Controlled, EPA-456/F-99-006R, p. 19 ( Nov. 1999), available at http://www.epa.gov/ttn/catc/dir1/fnoxdoc.pdf .

24 CELP Additional Response, pp. 2-7, 2-8.

25 CELP Additional Response, p. 2-8.

26 Deseret Bonanza SOB, pp. 46, 48.13 Table 3
Summary of CELP NO

x Reasonable Progress Analysis Control Technologies

Control Option Control

Effectiveness (%) Emissions

Reduction (tpy) Remaining

Emissions (tpy)

HDSCR 80 614 154

SNCR 50 384 384

Step 4: Evaluate Impacts and Document Results

Factor 1: Cost of Compliance

Table 4 provides a summary of the estimated costs f or the various NO

x control options.

Table 4 Summary of CELP NO

x Reasonable Progress Cost Analysis

Control Option Control

Effectiveness (%) Tons

NOx

Reduced

from

Baseline Capital

Cost ($) Annual Cost

of Capital ($) (CRF=.0944) Annual

O&M Cost ($) Total

Annual Cost ($) Average Cost

Effectiveness ($/ton reduced)

SCR 80 614 13,500,000 $1,274,400 827,789 2,102,189 3,423

SNCR 50 384 800,000 $75,520 509,197 584,717 1,523

EPA has relied on all the NO

x control costs provided by CELP 27 , with one exception. EPA calculated the annual cost of capital using a 7% an nual interest rate and 20-year equipment life (which yields a capital CRF of 0.0944), as specifie d in the Office of Management and Budget’s Circular A-4, Regulatory Analysis. 28 (CELP used 10% interest rate and 10-year equipmen t
life. 29 )

Factor 2: Time necessary for compliance

EPA has relied on CELP’s estimates that SCR would t ake approximately 26 months to install

and that SNCR would take 16 to 24 weeks to install. 30

27 CELP Additional Response.

28 Available at: http://www.whitehouse.gov/omb/circu lars_a004_a-4/.

29 CELP Additional Response.

30 CELP Additional Response, p. 3-1.14

Factor 3: Energy and non-air quality environmental impacts of compliance

The energy impacts from SNCR are expected to be min imal. SNCR is not expected to cause a loss of power output from the facility. SCR, howev er, could cause significant backpressure on the boiler, leading to lost boiler efficiency and, thus, a loss of power production. If LDSCR was to be installed instead of HDSCR, CELP would be sub ject to the additional cost of reheating the exhaust gas.

Regarding other non-air quality environmental impac ts of compliance, SCRs can contribute to airheater fouling from the formation of ammonium su lfate. Airheater fouling could reduce unit efficiency, increase flue gas velocities in the air heater, cause corrosion, and erosion. Catalyst replacement can lengthen boiler outages, especially in retrofit installations, where space and

access is limited. This is a retrofit installation in a high dust environment, thus fouling is likely

, which could lead to unplanned outages or less time between planned outages. On some installations, catalyst life is short and SCRs have fouled in high dust environments. For both SCR and SNCR, the storage of on-site NH 3 could pose a risk from potential releases to the

environment. An additional concern is the loss of NH 3 , or “slip” into the emissions stream from the facility. This “slip” contributes another poll utant to the environment, which has been implicated as a precursor to PM2.5 formation.

Factor 4: Remaining useful life

EPA has determined that the default 20-year amortiz ation period is most appropriate to use as the remaining useful life of the facility. Without com mitments for an early shut down, EPA cannot consider a shorter amortization period in its analy sis.

Step 5: Select Reasonable Progress Controls

EPA has considered the following four factors: the cost of compliance; the time necessary for compliance; the energy and non-air quality environm ental impacts of compliance; and the remaining useful life of the sources. EPA is also taking into account the size of the facility, the baseline Q/D of the facility, and the potential red uction in Q/D from the controls. Based on costs of compliance, the relatively small size of CELP, a nd the relatively small baseline Q/D, EPA proposes to eliminate the more expensive control op tion (SCR). The more cost-effective control option (SNCR) would result in a fairly small total reduction in emissions (384 tpy). This would constitute an approximately 20% reduction in overal l emissions of SO 2 + NO

x for the facility and a reduction of the facility’s Q/D from 11 to 9. Ba sed on the cost of compliance, the relatively small size of CELP, and the reduction in Q/D for SN CR, EPA finds it reasonable to not require SNCR. EPA therefore proposes to not require additi onal NO

x controls for this planning period.