We Energies Biomass Energy Project 

Revised Control Technology Review for 

Carbon Monoxide Emissions for the 

Biomass-Fired Boiler. 

September, 2010 
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50 MW Biomass Fuels-Fired Cogeneration Facility RTP Environmental Associates, Inc.

Appendix A: Control Technology Review for the Biomass-Fired Boiler. Revised September, 2010

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Chapter 3. Carbon Monoxide (CO) 

Control Technology Review. 

Carbon monoxide (CO) is emitted from biomass-fired boilers as a result of incomplete combustion. 

Incomplete combustion can also result in reduced boiler efficiency and emissions of particulate matter, 

volatile organic compounds, and organic hazardous air pollutants. CO and VOC emissions from the 

combustion of biomass fuels are normally expected to be somewhat elevated as compared to the 

combustion of natural gas, fuel oil, and coal because of the high moisture content and relatively low 

heating value of most biomass fuels. Because fuel costs represent the highest single operating cost for this 

boiler, this biomass-fired boiler is designed to achieve the highest combustion efficiencies practicable. 

CO emissions can be reduced by operating the boiler with higher furnace temperatures, higher excess 

oxygen levels, and longer furnace residence times. Unfortunately, techniques for reducing CO emissions 

can increase NOx emissions. Achieving low CO and low NOx emissions is therefore a balancing act in 

boiler design and operation. 

3.1 BACT Baseline. 

There are no specific Wisconsin state implementation plan (SIP) requirements or new source performance 

standards for CO emissions from biomass or fossil fuel-fired boilers. Therefore, baseline emissions are 

the uncontrolled emissions from the boiler. 

3.2 STEP 1. Identify All Available Control Technologies. 

Table 3-1 is a summary of carbon monoxide (CO) BACT emission limits for new biomass-fired boilers 

contained in the U.S. EPA’s RACT/BACT/LAER Clearinghouse, and in other permits issued in the 

United States. Emission limits range from 0.10 to 1.15 pounds per million Btu. Except for one facility, 

the only technology selected for all permitted biomass-fired boilers is good combustion practices. For the 

South Point Biomass Generation facility (Ohio, 2006), the facility was required to install an oxidation 

catalyst. However, this facility has not been constructed and therefore has not demonstrated compliance 

with a BACT emission limit. Note that from Table 3-1, of the top 6 ranked facilities, i.e., the Public 

Service of NH - Schiller Station, South Point Biomass Generation, Yellow Pine Energy Company, 

Nacogdoches Power, LLC, Mancelona Renewable, and Northern Michigan University, only the South 

Point Biomass boiler is a stoker boiler. The other boilers are fluidized bed boilers. 
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TABLE 3-1. Carbon monoxide (CO) BACT emission limits for biomass fuel-fired boilers. 

Facility State Permit

Date

Capacity, 

mmBtu/hr Primary Fuel Limit,lb/mmBtu

Pub. Service of NH - Schiller Station NH Oct-04 720 Wood 0.10 

South Point Biomass Generation OH Apr-06 318 Wood 0.10 

Yellow Pine Energy Company GA May-09 1,529 Wood 0.15 

Nacogdoches Power, LLC TX Mar-07 1,374 Wood 0.15 

Mancelona Renewable MI Nov-09 565 Wood/Biomass 0.17 

Northern Michigan University MI Nov-09 210 Wood/Biomass 0.17 

Fibrominn Biomass Power MN Feb-05 792 Poultry Litter 0.24 

Virginia PWC - Laurention Energy MN Aug-05 230 Wood 0.30 

District Energy St. Paul, Inc. MN Nov-01 550 Wood 0.30 

Sierra Pacific Aberdeen facility WA Oct-02 310 Waste Wood 0.35 

S.D. Warren Company ME Nov-01 1,300 Wood 0.40 

Stoneman Power Plant WI Jan-09 340 Wood 0.40 

Koda Energy MN Aug-07 308 Wood / Nat. Gas 0.43 

Martinsville Thermal LLC VA Sep-03 120 Wood 0.44 

Wheelabrator Sherman Energy ME Apr-99 315 Wood 0.45 

Northern Sun ND May-06 100 Wood / Hulls 0.63 

Skagit County Lumber Mill WA Jan-06 430 Wood 0.93 

Sierra Pacific Industries CA Dec-02 245 Wood 1.15 

3.3 STEP 2. Identify Technically Feasible Control Technologies. 

Available control technologies for the control of CO emissions include good combustion practices, 

oxidation catalysts, and thermal oxidation. 

3.3.1 Oxidation Catalysts. 

Oxidation catalysts are used to reduce CO emissions from natural gas or oil-fired combustion turbines, 

with typical CO reductions of 50 – 90%. However, oxidation catalysts have limited demonstration on 

biomass-fired boilers, and we are not aware of any demonstration or commercial operation of oxidation 

catalysts on a fluidized bed boiler. Boilers have several characteristics that make the use of oxidation 

catalysts technically infeasible, including catalyst fouling and poisoning by the wood fly ash, and low 

excess oxygen levels in the flue gas. 

CO oxidation catalysts are generally noble metal catalysts which are susceptible to poisoning from sulfur 

and calcium bearing compounds. These catalysts may experience rapid deactivation and fouling in 

biomass-fired boiler flue gas streams with high particulate loading. To be effective, the oxidation catalyst 

must be placed in a location with gas temperatures of at least 600 o

F. This location would be near the 

boiler economizer outlets, a location with high ash loading and low excess oxygen levels. 
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A research effort to assess catalyst deactivation mechanisms was presented at the 2008 Advanced 

Combustion Engineering Research Center conference1

 reported that SCR catalyst poisoning is the 

predominant deactivation mechanism resulting from biomass combustion. Note that oxidation catalysts 

and SCR catalysts have similar poisoning mechanisms. The study ranks the order of poisoning of the 

alkali-metals and alkaline-earth metals from having the most effect to lesser effect as potassium, followed 

by sodium, followed by calcium, and states that the “effects are proportional to basicity of the exhaust 

gas.” The study includes Figure 3-2 showing the difference in of coal versus biomass ash composition. 

Figure 3-2 shows that the relative proportion of potassium is much greater in the biomass ash than in the 

coal ash. Because of the presence of these base compounds and the low acid gas constituents such as 

sulfur dioxide (SO2), biomass flue gas tends to be basic while especially high sulfur coal combustion flue 

gas tends to be acidic. This exacerbates the catalyst deactivation and is the primary reason that oxidation 

catalyst and SCR systems located in a high dust environment are not applicable to biomass combustors. 

This problem is worsened by the CFB boiler design which has an extremely high dust loading. Erosion, 

plugging, and blinding are major potential problems in fluidized bed boiler applications due to the very 

high particulate loading in the boiler. 

To reduce the fouling and catalyst poisoning problems, the oxidation catalyst can be located downstream 

of the particulate matter control device. However, this “tail gas” oxidation catalyst control configuration 

does not eliminate fouling and deactivation, since the exhaust gas stream remains highly alkaline. 

In addition to this severe poisoning problem, the use of oxidation catalysts in this boiler application have 

another problem; the lack of sufficient excess oxygen to effectively reduce CO emissions. Oxidation 

catalysts operate according to the following general reaction: 

 2CO + O2 2CO2 

Typical excess oxygen (O2) levels in combustion turbines is 12 – 15%, compared to 3 – 6% in biomassfired boilers. These low excess O2 levels will limit the effectiveness of the oxidation catalyst. 

Tailgas oxidation catalyst has never been used on a similar biomass-fired circulating fluidized bed (CFB) 

boiler. Please refer to the attached letter in Figure 3-3 from the CFB boiler manufacturer regarding the 

lack of industry experience with the use of tailgas oxidation catalyst systems on fluidized bed boilers. 

Other concerns include severe catalyst deactivation due to the highly alkaline flue gases, and the low 

excess oxygen levels of CFB boilers which further reduce the effectiveness of this system. CFB boilers 

also have lower excess oxygen levels in the flue gas leaving the boiler than stoker-fired boilers. Because 

there is limited experience in utilizing CO catalyst technology on biomass fueled boilers including 

experience on similar CFB boilers similar to the proposed Rothschild biomass boiler, there is insufficient 

operating experience and information to support a determination that this technology can effectively 

control CO emissions from a CFB boiler. 

 

1

 Guo, X., et. al. Poisoning/Deactivation Study of V2O5/TiO2 SCR Catalysts, ACERC Annual Conference, 

February 2008. 
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Because of these serious technical problems and the fact that oxidation catalysts have not been 

demonstrated on similar circulating fluidized bed biomass boilers, we have concluded that oxidation 

catalysts are not a technically feasible CO control technology for these biomass-fired boilers. 

FIGURE 3-2. Coal and biomass ash composition showing the high levels of potassium and 

sodium in biomass ash relative to coal ash.

 (Source: Guo, X., et. al. Poisoning / Deactivation Study of V2O5/TiO2 SCR Catalysts, ACERC Annual 

Conference, February 2008.) 

3.3.2 Thermal Oxidation 

Thermal oxidation has never been required nor used on a biomass-fired boiler, and its theoretical ability 

to reduce CO emissions from these boilers has not been demonstrated in practice and is questionable. 

Thermal oxidation would involve injecting additional air into the flue gas and heating the oxygen 

enriched mixture to approximately 1,500 o

F to oxidize CO to carbon dioxide. However, since the 

combustion of the reheat fuel would itself result in CO emissions, there is no evidence that thermal 

oxidation would result in any CO emission reductions. Since thermal oxidation has never been 

demonstrated on a biomass-fired boiler, and because there is no evidence that it could reduce CO 

emissions, thermal oxidation is not a technically feasible CO control technology for these boilers. 
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Appendix A: Control Technology Review for the Biomass-Fired Boiler. Revised September, 2010

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FIGURE 3-3. Letter from the boiler vendor regarding the use of oxidation catalysts on CFB boilers.
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Appendix A: Control Technology Review for the Biomass-Fired Boiler. Revised September, 2010

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3.3.3 Good Combustion Practices 

Good combustion practices or combustion controls generally include the following components: 

1. Good air/fuel mixing in the combustion zone. 

2. High temperatures and low oxygen levels in the primary combustion zone. 

3. Overall excess oxygen levels high enough to complete combustion while maximizing 

boiler thermal efficiency. 

4. Sufficient residence time to complete combustion. 

In biomass-fired boilers, good combustion practices is the only technically feasible CO control 

technology. Combustion efficiency is related to the three “T’s” of combustion: Time, Temperature, and 

Turbulence. These components of combustion efficiency are designed into utility boilers to maximize 

fuel efficiency and reduce the highest single operating cost of a utility boiler: FUEL. A fourth critical 

parameter is the level of oxygen in the boiler, referred to as the excess air or excess oxygen level. 

Therefore, combustion control is accomplished primarily through boiler design as it relates to time, 

temperature, and turbulence, and through boiler operation as it relates to excess oxygen levels. 

Combustion design for modern boilers is intended to simultaneously minimize formation of CO and NOx

emissions. This is a difficult task, since emissions of NOx and emissions of CO are inversely related. 

That is, measures used to reduce NOx emissions often lead to increases in CO emissions. Therefore, the 

boiler design to minimize CO emissions is interrelated with the boiler design to minimize NOx formation. 

3.4 STEP 3. Rank the Technically Feasible Control Technologies. 

Based on the above analysis, the only technically feasible CO control technology for this biomass-fired 

boiler is good combustion practices. From Table 3-1, recent BACT determinations have CO limits 

ranging from 0.10 to 1.15 lb/mmBtu. The proposed CFB boiler is an advanced boiler which is expected 

to achieve low CO emission rates. However, boiler startup, shutdown, and load changes can causes CO 

emissions to increase because of unstable combustion conditions. CO emissions are also sensitive to 

boiler operating conditions. Changes in operating conditions, such as rapid changes in load, can have a 

significant, though temporary, impact on emissions. This condition is further exasperated during boiler 

startup because the boiler itself is relatively cool, and the low air flow rates make it difficult to obtain 

good air/fuel mixing. For these reasons, CO emissions can “spike” when transient conditions occur 

during boiler startup and shut down. 

Based on the analysis of this boiler, we have concluded that this boiler can achieve CO emission rates of 

0.0.12 lb/mmBtu, excluding periods of startup and shutdown, averaged over any 30-day period. In 

addition, we have concluded that this boiler can achieve an emission rate of 0.12 lb/mmBtu including all 

periods, averaged over any consecutive 12-month period. 

CO emissions may increase for brief periods due to boiler startup and shutdown conditions, boiler load 

swings which may occur to address steam load requirements, and boiler upset conditions. These 

conditions occur for even the best controlled boilers during startup, shutdown, and load changing 
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conditions. During these periods, CO emissions can increase above the normal rates during steady-state 

operation. Although a CFB boiler is a highly efficient boiler with low steady-state CO emissions, 

because of these operating conditions which are inherent to the fluidized bed boiler design, the maximum 

CO emission rate for the biomass-fired boiler is expected to be 800 pounds per hour. 

The CFB boiler is operating at normal combustion conditions when the temperature of the flue gas 

entering the cyclone separator exceeds 1,450 o

F. At this temperature, the entire CFB bed is at or near its 

normal operating temperature, and combustion conditions are essentially stable at the boiler design 

conditions. Therefore, for purposes of defining periods of boiler startup and shutdown, startup begins 

with the firing of fuel and ends when the temperature of the flue gas entering the cyclone separator 

exceeds 1,450 degrees F. Similarly, shutdown begins when the temperature of the flue gas entering the 

cyclone separator drops below 1,450 degrees F and ends with the cessation of fuel firing. 

3.5 STEP 4. Evaluate the Most Effective Controls. 

Because the only technically feasible control technology for the control of CO emissions from this boiler 

is good combustion practices, further evaluation is unnecessary. 

Although we have concluded that the use of an oxidation catalyst is not technically feasible, we can also 

evaluate the economic feasibility of the use of an oxidation catalyst for the control of CO emissions. A 

tailgas oxidation catalyst system requires an oxidation catalyst reactor, a flue gas heat exchanger, a flue 

gas reheating system, and ductwork from the baghouse or induced draft fan to the stack. Table 3-2 

summarizes the cost effectiveness of a CO oxidation catalyst for the biomass-fired boiler. If the oxidation 

catalyst could reduce CO emissions by 40%, from 0.12 lb/mmBtu to 0.072 lb/mmBtu, the cost 

effectiveness of a tailgas oxidation catalyst system, based on 8,760 hours per year of operation, would be 

$13,200 per ton of CO controlled. This is a very high cost of control, especially for a system which has 

never been demonstrated in practice on a similar, biomass-fired CFB boiler. 

TABLE 3-1. Cost effectiveness of a CO oxidation catalyst for the biomass-fired boiler. 

Parameter CO Catalyst CFB Boiler Only 

Control Efficiency 40% 0% 

Controlled Emission Rate, lb/mmBtu 0.072 0.12 

Total Boiler Heat Input, mmBtu 800 800 

Actual CO Emissions, tons per year 252 420 

Total Capital Requirement, $ $10,810,000 $0 

Capital Recovery Factor (CRF) 0.1098 0.1098 

Annual Capital Cost, $/yr $1,186,900 n/a 

Annual O&M Cost, $/yr $1,034,000 n/a 

Total Annual Cost, $/yr $2,220,900 $0 

Average Annual Cost, $/yr $2,220,900 

Average CO Reduction, tons per year 168 

Average Cost per Ton Reduced, $ per ton $13,200 
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3.6 STEP 5. Proposed Carbon Monoxide BACT Determination. 

Based on this analysis, We Energies has concluded that the use of good combustion practices is the best 

available control technology (BACT) for CO emissions from the biomass-fired boiler B01. Based on this 

analysis, We Energies proposes the following limits as BACT for the control of CO emissions from the 

biomass-fired, fluidized bed boiler B01. 

(1) Carbon monoxide (CO) emissions from the biomass-fired boiler B01 

shall be controlled using good combustion practices as the best 

available control technology. 

(2) Carbon monoxide (CO) emissions may not exceed 0.12 pounds per 

million Btu of heat input, excluding periods of boiler startup and shut 

down, averaged over any consecutive 30-day period. 

(3) Carbon monoxide (CO) emissions may not exceed 0.12 pounds per 

million Btu of heat input, for all periods, including periods of boiler 

startup and shut down, averaged over any consecutive 12-month period 

(4) Carbon monoxide (CO) emissions may not exceed 800 pounds per 

hour.

(5) Carbon monoxide (CO) emissions from the biomass-fired boiler B01 

shall be continuously monitored and recorded using a continuous 

emissions monitoring system meeting the requirements of 40 CFR Part 

60 Appendix B, and NR 439.06(4), Wis. Adm. Code.