February 28, 2011 

U.S. Environmental Protection Agency Region VIII 

1595 Wynkoop Street 

Denver, CO 80202-1129 

Attention: Vanessa Hinkle, 8P-AR 

Dear Ms. Hinkle: 

This letter serves as a response to the Clean Air Act Section 114(a) request issued by the U.S. 

Environmental Protection Agency (EPA) Region 8 towards the fulfillment of the Reasonable 

Progress (RP) goals and strategies under EPA’s Regional Haze Rule, per Title 40 of the Code of 

Federal Regulations (40 CFR) 51.308(d)(1) and 40 CFR 51.308(d)(3) (herein referred to as “114 

request letter”).1 This response contains further analysis of control technologies for the Plum 

Creek Manufacturing (Plum Creek) Columbia Falls Operations’ Riley Stoker Boiler and 

medium density fiberboard (MDF) Fiber Dryers and the Plum Creek Evergreen Division’s Riley 

Stoker Boiler, per EPA’s November 5, 2010 request. 

The 114 request letter issued by the EPA is included as Attachment A to this response. In the 

letter, EPA requests a control technology analysis for the emission units listed above in order to 

develop strategies towards achieving RP goals for Montana. In the letter, EPA specifies that the 

analysis must address the factors included in 40 CFR 51.308(d)(i)(A): the costs of compliance, 

time necessary for compliance, the energy and non-air quality environmental impacts of 

compliance, and the remaining useful life of the affected sources. The 114 request letter states 

that further analysis is warranted for the emission units listed above, based on the information 

submitted by Plum Creek in March 2009 in response to a previously issued Section 114(a) 

request regarding a more expansive list of emission units at the facilities.2 

The Regional Haze Rule covers emissions of particulate matter (PM), sulfur dioxide (SO2), and 

nitrogen oxides (NOx). However, detailed control evaluations for emissions of PM and SO2 are 

not included in this response for the following reasons: 

3⁄4 PM emissions are already well-controlled from all the emission units identified in the 114 

request letter. 

• The Riley Stoker Boilers at the Columbia Falls Operations and at the Evergreen 

Division are equipped with dry Electrostatic Precipitators (ESPs).

• The Columbia Falls Operations Line 1 MDF Fiber Dryers exhaust through a Wet 

ESP.

 1 Letter dated November 5, 2010 from Mr. Stephen S. Tuber, EPA Region 8, to Mr. Thomas Ray, Plum 

Creek Manufacturing, received November 29, 2010, included as Attachment A. 

2 The first 114 request regarding RP was issued by EPA Region 8 on January 29, 2009. 
Plum Creek Manufacturing - Page 2 

February 28, 2011 

• The Columbia Falls Operations Line 2 MDF Fiber Dryers are equipped with a 

Venturi Scrubber.

3⁄4 SO2 emissions are minimal from all emission units identified in the 114 request letter. 

• The SO2 emissions from the boilers and dryers are expected to be minimal as the 

units combust wood residue with only trace amounts of sulfur. 

• Any residual sulfur in the fuel will be oxidized during the combustion process and 

would be expected to be captured by the alkaline wood ash, with minimal amounts 

of SOx exhausting.3 

• Commercial-grade natural gas is used in the Columbia Falls Operations boiler 

during startup. The natural gas also contains only trace amounts of sulfur. 

The control technology evaluation presented in this letter report follows the guidelines for a Best 

Achievable Retrofit Technology (BART) analysis, per 40 CFR 51, Appendix Y. The report is 

organized as follows: 

3⁄4 Section 1: BART Determination Methodology 

3⁄4 Section 2: NOx Control Technology Descriptions 

3⁄4 Section 3: Control Technology Analysis for NOx from the Riley Stoker Boilers 

3⁄4 Section 4: Control Technology Analysis for NOx from the Line 2 MDF Fiber Dryers 

3⁄4 Section 5: Control Technology Analysis for NOx from the Line 1 MDF Fiber Dryers 

3⁄4 Section 6: Conclusion 

3⁄4 Attachment A: Copy of 114 request letter 

3⁄4 Attachment B: Supplemental material for the control technology evaluations 

SECTION 1. BART DETERMINATION METHODOLOGY

In the July 6, 2005, final BART Regulations and Guidelines, the EPA established guidelines for 

performing a BART Determination.4 Essentially, the goal of the BART analysis is to determine 

the BART for each unit identified as a BART-eligible source. In this analysis, there are no 

BART-eligible sources. However, the BART determination approach is followed to conduct a 

control technology evaluation for the fulfillment of reasonable progress goals under 40 CFR 

51.308(d) (1) and (3). This analysis must take into account several factors: 

3⁄4 The availability and feasibility of retrofit control options 

3⁄4 Pollution control equipment currently utilized 

 3 NCASI Technical Bulletin No. 884, Compilation of Criteria Air Pollutant Emissions Data for Sources at 

Pulp and Paper Mills Including Boilers, August 2004. Section 9.5.1 states: “...a significant amount of the fuel sulfur 

can be captured within the boiler itself by the alkaline wood ash.” 

4 40 CFR Part 51, Appendix Y, Section IV.A 
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February 28, 2011 

3⁄4 Costs of compliance for each control option 

3⁄4 Remaining useful life of the facility 

3⁄4 Energy and environmental impacts of the control options 

Note that a visibility impacts analysis was not requested by EPA Region 8, and, thus, it is not 

included in this report 

To guide selection of appropriate case-by-case BART limits, EPA noted that the BART 

Determination evaluation must include the following specific steps (excluding the visibility 

impacts analysis): 

1. Identify all available retrofit control options 

2. Eliminate technically infeasible options 

3. Evaluate control effectiveness of remaining control technologies 

4. Evaluate impacts and document results 

Each of these steps is described in the following sections. 

STEP 1: IDENTIFY ALL AVAILABLE RETROFIT CONTROL OPTIONS

The first step in the BART Determination is the identification of all retrofit control options, 

which:5 

...are those air pollution control technologies with a practical potential for application 

to the emissions unit and the regulated pollutant under evaluation...Technologies 

required as [Best Available Control Technology] BACT or [Lowest Achievable 

Emission Rate] LAER are available for BART purposes and must be included as control 

alternatives...We do not expect the source owner to purchase or construct a process or 

control device that has not already been demonstrated in practice. 

The guidelines also note that New Source Performance Standards (NSPS) level controls should 

be considered, as should pollution prevention options and usage (or improvement to existing 

units) of add-on controls. 

STEP 2: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

After the identification of control options, the next step in the analysis is to eliminate technically 

infeasible options. A control option is considered technically infeasible if technical difficulties 

(based on physical, chemical, or engineering principles) would not allow the option to be 

utilized successfully. A control is eliminated from consideration if there are process-specific 

 5 40 CFR Part 51, Appendix Y, Section IV.D.1 
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February 28, 2011 

conditions that prohibit the implementation of control or if the highest control efficiency for that 

option would result in an emission level that is higher than any applicable regulatory limits. 

Specifically, an option is considered technically feasible if it “has been installed and operated 

successfully for the type of source under review under similar conditions, or the technology 

could be applied to the source under review.”6 According to EPA’s Guidelines for BART 

Determinations under the Regional Haze Rules, technologies which have not yet been applied to 

(or permitted for) full scale operations need not be considered as available. Therefore, control 

options that have not been successfully demonstrated for a particular emission unit are 

considered technically infeasible and removed from further consideration in this step.7

To demonstrate that an option is not technically feasible, the source must evaluate and document 

that either (1) the characteristics of the exhaust stream and/or the capabilities of the technology 

that would not allow the option to be used, or (2) the option is not commercially available. 

STEP 3: EVALUATE CONTROL EFFECTIVENESS OF REMAINING CONTROL 

TECHNOLOGIES

The third step in the BART Determination is the evaluation of control effectiveness of any 

control options considered technically feasible. The control effectiveness should include 

comparing options on the same basis (e.g., lb/MMBtu). Varying control effectiveness levels for 

the same control option can be considered (e.g., 50% control versus 75% control). The 

effectiveness evaluation should also consider ways to improve the control associated with any 

existing control options already employed, especially when existing control devices are not 

achieving as great of reduction as the same control device on a similar source.8

STEP 4: EVALUATE IMPACTS AND DOCUMENT RESULTS

The fourth step in the BART Determination is to analyze the costs of compliance using the 

control option, the energy impacts of the control option, the non-air quality environmental 

impacts of the control option, and the remaining useful life of the equipment. 

The first factor evaluated is the cost of compliance. Evaluation of this factor includes 

development of cost calculations necessary to determine the average cost effectiveness, which is 

defined as “the total annualized costs of control divided by the annual emissions reductions.”9 

The incremental cost effectiveness can also be evaluated in situations where a number of control 

options are being evaluated in order to compare those options to one another. Costs of 

compliance can be determined using EPA’s OAQPS Control Cost Manual as guidance.10 Note 

that the emissions reductions included in the cost of compliance calculations should “represent a 

 6 40 CFR Part 51, Appendix Y, Section IV.D.2 

7 40 CFR Part 51, Appendix Y 

8 40 CFR Part 51, Appendix Y, Section IV.D.3 

9 40 CFR Part 51, Appendix Y, Section IV.D.4.b 

10 EPA, OAQPS Control Cost Manual, Sixth Edition, January 2002. EPA-452/B-02-001. 
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February 28, 2011 

realistic depiction of anticipated annual emissions for the source...based upon actual emissions 

from a baseline period.”11 Therefore, emission units with limited operation during the baseline 

period can consider similar limited operation (and limited emissions) in the cost effectiveness 

calculations. 

The second factor evaluated is the energy impact. Energy impacts will result in additional costs 

or income to a source. Typically, these impacts are determined as part of the cost impact 

calculations, considering only the direct energy consumption. 

The third factor evaluated is the non-air quality environmental impact. Environmental impacts 

include generation of additional solid or liquid waste and the disposal of such waste. 

The fourth factor evaluated is the remaining useful life of the source. If the remaining useful life 

of the equipment is less than the time period recommended by EPA’s OAQPS Control Cost 

Manual, the shortened life should be utilized in the cost evaluations for the purposes of 

amortizing costs of the retrofit. 

SECTION 2. NOX CONTROL TECHNOLOGY DESCRIPTIONS

This section contains a detailed description of each NOx control technology discussed in later 

sections of the report. While the working mechanism of these technologies in NOx removal is 

highlighted, the unit-specific applications of these options are discussed in Sections 3 through 5. 

The control technologies are classified based on whether they are post-combustion controls or 

combustion modifications that are pollution-preventive by design. 

POST-COMBUSTION CONTROLS

The post-combustion control technologies described in detail below include Selective Catalytic 

Reduction (SCR) and Selective Non-Catalytic Reduction (SNCR), which both reduce NOx in the 

flue gas by converting the NOx to N2 and H2O. 

Selective Catalytic Reduction (SCR) 

The SCR technique involves injecting ammonia or urea into a flue gas with a temperature of 

about 480 to 800°F, then passing the gas through a catalyst bed where NOx is converted to N2

and H2O. The function of the catalyst is to lower the activation energy of the NO decomposition 

reaction, therefore, lowering the temperature necessary to carry out the reaction. Depending on 

the location of the SCR system in the combustion flue gas path, SCR technologies can be Tailend (Cold-side) or High-dust (Hot-side). A High-dust SCR system is placed between the 

economizer and air heater, while the Tail-end SCR is located downstream of the particulate 

control and air heater. 

 11 40 CFR Part 51, Appendix Y, Section IV.D.4.d 
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February 28, 2011 

Babcock Power’s patented Regenerative SCR (RSCR) systems are “Tail-end” SCR systems on 

the cold side, after the particulate control device. In the RSCR configuration, the reagent is first 

introduced upstream of the RSCR unit. The flue gas/reagent mixture (previously cleaned of 

particulate matter) then enters one end of the system, where the flue gas mixture travels up 

through the (hot) ceramic heat retention canister to be reheated. The flue gas mixture then flows 

through the catalyst section, where the ammonia reacts with the NOx to form nitrogen and water. 

After the catalyst, the flue gas flows through a “retention” chamber, where a burner reheats the 

flue gas slightly. From this chamber, the flue gas then flows through the (cold) second canister 

and is used to heat this canister’s ceramic heat retention block. Once this cycle is complete, the 

air flow is diverted, so that the second canister is the inlet for the “cold” flue gas, and the first 

canister is the outlet for the cleaned flue gas.12 The RSCR approach minimizes the supplemental 

fuel required to reheat the cold exhaust gas. 

Selective Non-Catalytic Reduction (SNCR) 

SNCR is an exhaust gas treatment process in which urea or ammonia is injected into the exhaust 

gas. High temperatures, normally between 1,600 and 2,100°F, promote the reaction between 

urea or ammonia and NOx to form N2 and water.13 The effectiveness of SNCR systems depends 

on the inlet NOx concentration, temperature, mixing, residence time, reagent-to-NOx ratio, and 

fuel sulfur content. The temperature of the system must fall within the appropriate range to 

avoid excess ammonia slip or the oxidation of NH3 to NOx. Proper mixing of the reagent and 

the flue gas is necessary to ensure reduction of NOx. The residence time must be of an 

appropriate duration to allow completion of the reaction. If the reagent-to-NOx ratio is too high, 

excess NH3 will become present in the exhaust. 

Outside of the design temperature window, the emissions are adversely affected. If the 

temperatures are too high, then the reagent may be oxidized, causing additional NOx emissions. 

If the temperatures are too low, then the reaction between the reagent and NOx is slowed, and 

emissions of the reagent will be present. 

COMBUSTION MODIFICATION CONTROLS

The combustion modification control technologies described below decrease NOx emissions by 

preventing the formation of NOx during the combustion process, rather than by reducing NOx

concentrations in the exhaust. 

Flue Gas Recirculation (FGR) 

Flue gas recirculation (FGR) involves recycling a portion of the flue gas back into the 

combustion zone where inert combustion products in the recycled gas stream adsorb some of the 

heat generated by the combustion process, thus lowering peak flame temperature. The reduction 

 12 Abrams, Richard F. (Babcock Power Environmental, Inc.) and Kevin Toupin (Riley Power, Inc.). 

Efficient and Low Emission Stoker Fired Biomass Boiler Technology in Today’s Marketplace. Worcester, MA: 

Babcock Power Environmental, Inc. March 2007. http://www.babcockpower.com/pdf/t-200.pdf

13 EPA, Air Pollution Control Technology Fact Sheet, EPA-452/F-03-031, Selective Non-Catalytic 

Reduction (SNCR), dated July 15, 2003. 
Plum Creek Manufacturing - Page 7 

February 28, 2011 

of the peak flame temperature reduces the formation of thermal NOx (conversion of N2 in the 

combustion air to NOx due to high temperatures and the presence of oxygen). 

Fuel Staging 

Also known as “reburning” or “off-stoichiometric combustion,” fuel staging is a technique 

where 10 to 20 percent of the total fuel input is diverted to a second combustion zone 

downstream of the primary zone. The fuel in the secondary zone serves as a reducing agent, and 

NO formed in the primary combustion zone is reduced to N2. This technique usually employs 

natural gas or distillate oil as the fuel in the secondary combustion zone. 

Low NOx Burners (LNB) 

Traditional burner design introduces both the fuel and air into one combustion zone. To obtain 

optimal flames, large amounts of excess air must be combined with the fuel. This relatively 

“uncontrolled” combustion creates high flame temperatures and therefore higher NOx emissions. 

To control the generation of thermal NOx, LNB technology stages combustion in the high 

temperature zone of the flame. The first stage is a fuel-rich, oxygen-lean atmosphere where 

little oxygen is available for NOx formation, which reduces peak flame temperatures by delaying 

the completion of the combustion process. Combustion is then completed downstream in the 

second stage where excess air is available but temperatures are lower than the hottest portion of 

the primary flame core. LNB technology is most suitable for oil and gas combustion. 

Low Excess Air (LEA) 

LEA involves reducing the amount of excess combustion air to near-stoichiometric levels, 

reducing flame temperature, and decreasing thermal NOx formation.

Staged Combustion 

Staged combustion technologies such as Overfire Air (OFA) reduce NOx emissions by creating a 

“fuel-rich” zone via air staging (i.e., diverting a portion of the total amount of air required 

through separate ports so that partial combustion is carried out initially in the first stage with a 

lower air to fuel ratio than that of normal combustion, while secondary air is supplied to 

complete the combustion reaction in a subsequent combustion stage). Fuel-rich conditions in 

the first stage reduce fuel NOx formation by limiting the amount of oxygen available to react 

with the fuel bound nitrogen. Conditions in the secondary combustion zone result in lower peak 

temperatures and thus, lower NOx emissions. 

SECTION 3. CONTROL TECHNOLOGY ANALYSIS FOR NOX FROM THE 

RILEY STOKER BOILERS (COLUMBIA FALLS AND EVERGREEN)

The Riley Stoker Boilers at the Columbia Falls Operations and Evergreen Division facility are 

similar in design. Both spreader-stoker boilers combust wood residue, primarily as bark from 

each facility’s log debarking process, and both are load-following boilers used to meet the steam 
Plum Creek Manufacturing - Page 8 

February 28, 2011 

demand of various process operations. Sanderdust burners supplement the hog fuel firing 

downstream of the spreader-stoker grate in both boilers. The sanderdust burners are also 

capable of firing natural gas, with a design capacity of approximately 10 percent of the total 

boiler capacity. Natural gas firing only occurs during startup and rare events of sanderdust 

shortage. For reasons of similarity in design and operation, the control technology evaluations 

for both units are addressed in this section. 

The firing rate varies for the Riley Stoker Boilers at the Columbia Falls Operations and at the 

Evergreen Division facility in order to meet the steam demand at the respective facilities. The 

load of the Columbia Falls Operations Riley Stoker Boiler fluctuates between 50,000 pph steam 

and 150,000 pph steam, and the Evergreen Division Riley Stoker Boiler’s load varies between 

30,000 pph steam and 70,000 pph steam. These wide load changes often occur rapidly, 

sometimes swinging from the minimum load to the maximum load within thirty minutes. 

The Riley Stoker Boiler at Columbia Falls Operations was installed in 1973. It supplies steam to 

the dry kilns, plywood press, log vats, and MDF platen press. The boiler is rated at 

292 MMBtu/hr and 170,000 pounds per hour (pph) steam. 

The Riley Stoker Boiler at the Evergreen Division facility was installed in 1971. The boiler is 

rated at 196 MMBtu/hr and 140,000 pph steam. It supplies steam for process operations such as 

the dry kilns, the veneer dryers, plywood presses, and the medium density overlay (MDO) press. 

BACKGROUND ON POLLUTANT FORMATION

In industrial boiler and furnace combustion processes, NOx is formed by two fundamentally 

different mechanisms: fuel NOx and thermal NOx. Technical literature suggests that NOx

formation from wood combustion is primarily fuel NOx.

14 

 

“Fuel NOx” forms when the fuel bound nitrogen compounds are converted into nitrogen oxides. 

The amount of fuel bound nitrogen converted to fuel NOx depends largely upon the fuel type, 

nitrogen content of the fuel, air supply, and boiler design (including combustion temperature). 

The reaction between elemental nitrogen and oxygen to form nitrogen oxides happens very 

rapidly. Therefore, the primary mechanisms for reducing fuel NOx involve creating a minimum 

amount of excess oxygen available to react with the fuel bound nitrogen throughout the 

combustion process.15

NOx formed in the high-temperature, post-flame region of the combustion equipment is “thermal 

NOx.” Temperature is the most important factor, and at flame temperatures above 2,200°F, 

thermal NOx formation increases exponentially.16 

 14 Webster, T.S. and S. Drennan. Low NOX Combustion of Biomass Fuels. Coen Company, Inc. 

http://www.coen.com/i_html/white_lownoxbiom.html. 

15 Kraft, D.L. Bubbling Fluid Bed Boiler Emissions Firing Bark & Sludge. Barberton, OH: Babcock & 

Wilcox. September 1998. http://www.babcock.com/library/pdf/BR-1661.pdf. 

16 Kraft, D.L. Bubbling Fluid Bed Boiler Emissions Firing Bark & Sludge. Barberton, OH: Babcock & 

Wilcox. September 1998. http://www.babcock.com/library/pdf/BR-1661.pdf. 
Plum Creek Manufacturing - Page 9 

February 28, 2011 

NO formation is inherent in all high temperature combustion processes. Nitrogen dioxide (NO2) 

can then be formed in a reaction between the NO and oxygen in the combustion gases. In 

stationary source combustion, little of the NO is converted to NO2 before being emitted. 

However, the NO continues to oxidize in the atmosphere. For this reason, all NOx emissions 

from boilers are usually reported as NO2. 

STEP 1: IDENTIFY ALL AVAILABLE RETROFIT CONTROL OPTIONS

Potentially applicable NOx control technologies are identified based on a review of relevant 

information published in literature, determinations for similar units identified from the a search 

of the EPA RACT/BACT/LAER Clearinghouse (RBLC) and from a review of recently issued 

permits for similar biomass boilers (a summary of relevant RBLC and permit search results is 

presented in Attachment B), and experience in conducting control technology reviews for 

similar types of equipment. After accounting for the physical and operational characteristics of 

the Riley Stoker Boilers, the post-combustion and combustion modification control technologies 

and strategies considered in this analysis for controlling NOx emissions include the following: 

Post-Combustion Controls 

3⁄4 Selective Catalytic Reduction (SCR) 

3⁄4 Selective Non-Catalytic Reduction (SNCR) 

Combustion Modification Controls 

3⁄4 Flue Gas Recirculation (FGR) 

3⁄4 Fuel Staging 

3⁄4 Low NOx Burners (LNB) 

3⁄4 Low Excess Air (LEA) 

3⁄4 Staged Combustion 

3⁄4 Good Operating Practices (base case) 

Each of the technologies listed above are described in Section 2 of this letter report, with the 

exception of good operating practices for the Riley Stoker Boilers. 

The formation of NOx can be controlled using good combustion and boiler operation practices. 

Plum Creek adheres to a robust maintenance program to maintain the boilers’ burners, hog fuel 

feed system, fans, and other equipment in optimal condition. The boilers are also equipped with 

a computer control system used to maintain optimum air to fuel ratios and fuel feed rates. These 

good operating practices allow the facilities to meet the NOx permit limits for the Riley Stoker 

Boilers at the Columbia Falls Operations (134.50 lb/hr) and Evergreen Division facility 

(104 lb/hr). 

Additionally, the Riley Stoker Boilers inherently use a process similar to fuel staging by design. 

The sanderdust burners, which typically supply approximately 10 percent of the heat to the 

boiler, are located downstream of the primary wood-fired flame.
Plum Creek Manufacturing - Page 10 

February 28, 2011 

STEP 2: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

The technical feasibility of each identified technology for control of NOx emissions from the 

Riley Stoker Boilers is discussed in the following sections. 

Selective Catalytic Reduction (SCR) 

Implementing SCR on industrial hog fuel boilers poses several technical challenges. Size 

constraints often make retrofitting an SCR system near the boiler impossible. Further, most hog 

fuel boilers’ temperature profiles are not appropriate for SCR, and the SCR system pressure drop 

requirements result in sizing concerns related to existing boiler fans. The National Council for 

Air and Stream Improvement (NCASI) notes that the high PM concentrations upstream of the 

PM control equipment (Hot-side/High-dust) would impede catalyst effectiveness and could 

result in deactivation or poisoning of the catalyst (requiring downtime to clean and/or replace 

the catalyst), while the installation of SCR downstream of the PM control equipment (Coldside/Tail-end SCR) would render the gas stream too cold for effective reaction with the catalyst 

to reduce NOx.

17 In biomass boilers, plugging and fouling of the catalyst can occur due to large 

amounts of fly ash generated by the biomass. 

The desired temperature range for SCR application is 480 to 800°F, while the maximum exhaust 

temperature of the Riley Stoker Boiler at Columbia Falls Operations is 500 °F and the exhaust 

temperature for the boiler at the Evergreen Division facility is 430°F. While the exhaust 

temperatures of the two boilers are close to the range of operation of the SCR system, higher 

temperatures would likely be needed for optimum control efficiency for Tail-end SCR 

application. In an RCSR system, the regenerative heating reduces the required heat input; 

however, this reheating of the flue gas still represents a significant amount of auxiliary fuel that 

would be necessary for successful operation. Moreover, it is not considered available as RSCR 

has not been previously demonstrated on load-following industrial boilers.18 As noted above, 

locating the SCR in a higher temperature region (Hot-side/High-Dust SCR) to avoid the issue 

use of auxiliary fuel would result in exposure to high particulate emissions from hog fuel 

combustion that could significantly damage the catalyst. 

The technical difficulties described above apply generally to biomass boilers, and recent 

applications indicate that these difficulties may be overcome by advanced technologies and 

auxiliary heating of the Tail-end flue gas. However, the wide swings experienced by the Plum 

Creek boilers result in unstable exhaust temperatures and would make it particularly difficult to 

control the reagent injection rate needed to ensure appropriate NOx reductions while avoiding 

excessive ammonia slip. For these reasons, SCR technology has never been successfully 

demonstrated for a load-following spreader-stoker boiler with load swings comparable to the 

 17 NCASI Special Report 03-04, NOxControl in Forest Products Industry Boilers: A Review of 

Technologies, Costs, and Industry Experience, August 2003. 

18 A review of the RBLC database indicates that RSCR technology has previously been used only on a 

base-loaded utility boiler. 
Plum Creek Manufacturing - Page 11 

February 28, 2011 

Riley Stoker Boilers at the Columbia Falls Operations and Evergreen Division Facility.19,

20 

BART guidelines state that technologies which have not yet been applied to (or permitted for) 

full scale operations need not be considered available; thus, technologies that have not been 

successfully implemented on a comparable emission unit are eliminated in the technical 

infeasibility section of this evaluation. Therefore, this technology is considered technically 

infeasible and is not considered further.

Selective Non-Catalytic Reduction (SNCR) 

Implementing SNCR on industrial load-following hog fuel boilers also poses several technical 

challenges for many of the same reasons that SCR technology is considered technically 

infeasible. In an SNCR system, the injection of the reagent must be applied in a narrow 

temperature window in order for the reduction reaction to successfully complete. In a loadfollowing boiler, the region of the boiler where this temperature occurs varies depending on the 

firing rate, making it nearly impossible to control the SNCR reaction temperature. Another 

factor preventing proper implementation of SNCR technology in load-following biomass boilers 

is inadequate reagent dispersion in the injection region, which can lead to significant amounts of 

unreacted ammonia exhausted to the atmosphere (i.e., large ammonia slip). At least one pulp 

mill wood-fired boiler had to abandon their SNCR system due to problems caused by poor 

dispersion of the reagent within the boiler.21 

While there have been recent advancements in SNCR technology that may aide in overcoming 

these technical hurdles, such as setting up multiple injection grids and the addition of 

sophisticated Continuous Emissions Monitoring Systems (CEMS)-based feedback loops, SNCR 

has yet to be successfully demonstrated for a hog fuel boiler with swing loads comparable to the 

Riley Stoker Boilers at the Columbia Falls Operations and Evergreen Division facility.22,

23 

Therefore, this technology is considered technically infeasible and is not considered further. 

Flue Gas Recirculation (FGR) 

In FGR, a portion of the flue gas is routed to the combustion zone (up to 20% of the flue gas). 

The flue gas acts as a heat sink, thus lowering the flame temperature. It also reduces the oxygen 

concentration. Both of these effects result in lower thermal NOx. Thus, FGR does not 

 19 NCASI Corporate Correspondent Memorandum No. 06-014, Information on Retrofit Control Measures 

for Kraft Pulp Mill Sources and Boilers for NOx, SO2 and PM Emissions, June 2006. 

20 A review of the RBLC database and of recently issued biomass boiler permits, performed in 2011, 

indicates that SCR technology has not been previously demonstrated on similar load-following boilers. 

21 NCASI Corporate Correspondent Memorandum No. 06-014, Information on Retrofit Control Measures 

for Kraft Pulp Mill Sources and Boilers for NOx, SO2 and PM Emissions, June 2006. 

22 NCASI Corporate Correspondent Memorandum No. 06-014, Information on Retrofit Control Measures 

for Kraft Pulp Mill Sources and Boilers for NOx, SO2 and PM Emissions, June 2006. 

23 A review of the RBLC database and of recently issued biomass boiler permits, performed in 

February 2011, indicates that SNCR technology has not been previously demonstrated on similar load-following 

boilers. SNCR installations were identified for several industrial biomass boilers. However, each of the boilers with 

SNCR does not operate under load-following conditions comparable to the Plum Creek Riley Stoker Boilers. Further 

detail for each SNCR application is provided in Attachment B. 
Plum Creek Manufacturing - Page 12 

February 28, 2011 

significantly reduce NOx emissions for a biomass spreader stoker boiler since the majority of 

NOx emissions arise from fuel nitrogen. 

FGR also requires considerable equipment for carrying the recirculated flue gas. For 

recirculation rates greater than 15 percent, an additional fan is needed. The recirculation fan is a 

specialty fan that must be able to withstand the high temperature and high particulate loading in 

the flue gas stream. High particulate loading in the flue gas stream is of particular concern since 

the boilers’ fuel is wood. The increased flue gas volume would also increase gas velocity in the 

superheaters and boiler bank, which can cause additional pluggage and lost capacity. 

FGR is not anticipated to provide a significant reduction in the NOx emissions from the Riley 

Stoker Boilers. Applying FGR as a means of controlling NOx is considered ineffective for the 

Riley Stoker Boilers and is not considered further. 

Fuel Staging (Reburning) 

Fuel staging involves sending the fuel into a secondary inlet combustion zone for breaking the 

combustion event into several stages. It is usually facilitated by diverting natural gas or 

distillate oil in a secondary combustion zone downstream of the primary zone. The Riley Stoker 

Boilers are primarily fired by hog fuel and only use natural gas during start-ups; therefore, they 

are unable to utilize this technique. Further, fuel staging often employs FGR, which is 

considered infeasible for the hog fuel boilers due to its inability to minimize fuel NOx, the 

primary component of NOx from wood-waste combustion.24 For these reasons, this technology 

has not been successfully demonstrated on wood-fired boilers and is not considered further. 

Low NOx Burners (LNB) 

LNB are designed to mix fuel and air at optimum ratios in order to keep the temperature low and 

maintain fuel-rich zones within the burner. This results in the reduction of thermal NOx

formation. An LNB retrofit is usually done for oil/gas or coal-fired units. It is not possible to 

retrofit a wood-fired spreader stoker boiler with LNB, because the hog fuel is not fed into the 

boiler using a traditional burner. Sanderdust is fired using burners in the Riley Stoker Boilers; 

however, sanderdust burners also work differently than traditional burners and only supply a 

maximum of 10 percent of the boiler heat input.25 Therefore, applying LNB as a means of 

controlling NOx is considered technically infeasible for the Riley Stoker Boilers and is not 

considered further. 

 24 NCASI Special Report 03-04, NOx Control in Forest Products Industry Boilers: A Review of 

Technologies, Costs, and Industry Experience, August 2003. 

25 The burners installed on the Line 2 MDF dryers that are referred to as “Low NOx Burners” in the 

Columbia Falls Operations permit, reduce NOx by applying staged combustion technology. The Line 2 MDF Dryers 

burners limit the combustion air (creating a fuel-rich zone), and air is added downstream to complete combustion. 

Refer to the staged combustion discussion for the Boilers for further discussion regarding why staged combustion is 

considered technically infeasible for the Riley Stoker Boilers. 
Plum Creek Manufacturing - Page 13 

February 28, 2011 

Low Excess Air (LEA) 

LEA is difficult to employ in spreader stoker boilers because high excess air levels are needed 

for proper fuel burning.26 LEA can result in the production of smoke, increased carbon 

monoxide (CO) emissions, and other problems associated with the boiler operation, including 

increased corrosion and fouling.27 Thus, LEA is considered technically infeasible and is not 

considered further. 

Staged Combustion 

Implementing staged combustion technology would require installation of OFA injection ports, 

which poses several site-specific technical obstacles for Plum Creek’s Riley Stoker Boilers. The 

ports would need to be installed at the exact location where the current sanderdust burners are 

located, and installing OFA in the boilers’ small combustion chambers could result in flame 

impingement on boiler walls, leading to tube wall overheating and mechanical failure. Flame 

impingement can also result in premature flame quenching and increased soot and CO 

emissions.28 Staged combustion generally lengthens the flame configuration so the applicability 

is limited to installations large enough to avoid flame impingement on internal surfaces.29 Other 

issues related to general OFA retrofit installations include penetration of the boiler walls, which 

may affect the structural integrity of the unit, and which would require re-routing of the steam 

tubes. The reducing atmosphere created in the fuel-rich primary combustion zone may also 

result in accelerated corrosion of the furnace. Additionally, grate corrosion and overheating may 

occur in stokers as primary air flow is diverted to overfire air ports.30 

Retrofitting the Riley Stoker Boilers with OFA injection ports is not technically feasible due to 

the numerous technical issues described above. Therefore, OFA technology is considered to be 

technically infeasible and is not considered further in the analysis. 

STEP 3: EVALUATE CONTROL EFFECTIVENESS OF REMAINING CONTROL 

TECHNOLOGIES

Good operating practices are the only available NOx control technology for the Riley Stoker 

Boilers. Therefore, there are no other technically feasible control options for evaluation. 

 26 Washington State Department of Ecology Publication No. 03-02-009, Hog Fuel Boiler RACT 

Determination, April 2003, http://www.ecy.wa.gov/biblio/0302009.html. 

27 NCASI Special Report 03-04, NOX Control in Forest Products Industry Boilers: A Review of 

Technologies, Costs, and Industry Experience, August 2003. 

28 NCASI Special Report 03-04, NOx Control in Forest Products Industry Boilers: A Review of 

Technologies, Costs, and Industry Experience, August 2003. 

29 Sloss, Leslie L. Nitrogen oxides technology fact book. 1992. 

30 Controlling Nitrogen Dioxides under the Clean Air Act, A Menu of Options: Industrial and Commercial 

Boilers, http://www.p2pays.org/ref/02/01245/3017103.pdf
Plum Creek Manufacturing - Page 14 

February 28, 2011 

STEP 4: EVALUATE IMPACTS

Good combustion and boiler operation practices constitute the most suitable control option for 

the Riley Stoker Boilers. 

The remaining useful life of the boilers is used for evaluating the economic feasibility of control 

options. Because all control technology options are considered technically infeasible, an 

economic analysis is not necessary for the control technology evaluation conducted for these 

boilers. However, the remaining useful life of the equipment may need to be considered in 

establishing RP goals for the region. The remaining useful life of each Riley Stoker Boiler is 10 

years.31

SECTION 4. CONTROL TECHNOLOGY ANALYSIS FOR NOX FROM THE 

LINE 2 MDF FIBER DRYERS (COLUMBIA FALLS) 

The Line 2 MDF Dryers at Columbia Falls Operations are direct-contact dryers. The flue gas 

from the combustion chamber, rated at 85 MMBtu/hr, feeds two dryer lines (the first stage dryer 

and the second stage dryer). The combustion stage for the Line 2 MDF Fiber Dryers employs a 

staged combustion design.32 First, the burners fire sanderdust at less than stoichiometric oxygen 

to fuel ratio. The primary combustion stage is "fuel rich," thereby limiting formation of fuel 

NOx. As the flame progresses in the firebox, additional air is added to complete the combustion 

process. Due to the lower temperature needed in the secondary combustion zone, formation of 

thermal NOx is also reduced. 

 31 Engineering estimate by Plum Creek, emailed to Trinity Consultants by Mitchell Leu, January 11, 2011. 

32 It should be noted that the Columbia Falls Operations air permit specifies that the Line 2 Dryers employ 

LNB/FGR; however, the technology employed in practice is staged combustion. The burners contribute to lower NOx

formation by firing the sanderdust at sub-stoichiometric conditions; however, the burners themselves do not support 

the secondary combustion stage needed to complete the combustion process. The unit does not employ any form of 

FGR. 
Plum Creek Manufacturing - Page 15 

February 28, 2011 

STEP 1: IDENTIFY ALL AVAILABLE RETROFIT CONTROL OPTIONS

Potentially applicable NOx control technologies are identified based on a review of 

determinations for similar units identified from the RBLC search (Attachment B presents a 

summary of the RBLC search results for the NOx control technologies for MDF dryers). After 

accounting for the physical and operational characteristics of the Line 2 MDF Fiber Dryers, the 

control technologies and strategies considered in this analysis for controlling NOx emissions 

include the following: 

3⁄4 Selective Catalytic Reduction (SCR) 

3⁄4 Selective Non-Catalytic Reduction (SNCR) 

3⁄4 Flue Gas Recirculation (FGR) 

3⁄4 Fuel Staging 

3⁄4 Low Excess Air (LEA) 

3⁄4 Low NOx Burner (LNB)/ Staged Combustion (base case) 

The Line 2 MDF Fiber Dryers are currently equipped with staged combustion, and hence this 

control is treated as a baseline scenario against which additional control options are considered. 

Please refer to Section 2 of this report for a description of the control technologies listed above. 

STEP 2: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

The technical feasibility of each identified technology for the control of NOx from the Line 2 

MDF Fiber Dryers is discussed in the following sections. 

Selective Catalytic Reduction (SCR) 

SCR technology has not been previously demonstrated on a wood product dryer. This control 

option does not appear in the RBLC search results for similar units. SCR technology is not 

feasible for wood products dryers because of the direct contact of the combustion air with the 

wood product material. If the reagent were to be injected in the optimal temperature range 

directly after the burner, the ammonia in the flue gas would deposit on the wood fibers (due to 

the direct-fired nature of the burners where the combustion gases come in contact with the 

material being dried), causing product damage. 

For these reasons, SCR has not been successfully demonstrated on wood products dryers. 

Hence, it is considered technically infeasible and is not considered further. 

Selective Non-Catalytic Reduction (SNCR) 

As previously discussed, SNCR systems are installed where the temperature in the combustion 

zone of the unit reaches the optimum range for operation of the SNCR of 1600 to 2100 °F. The 

combustion zone for the Line 2 Dryers reaches a maximum temperature of approximately 

1500 °F, lower than the minimum temperature needed for SNCR. Moreover, as for SCR, if the 

reagent were to be injected near the optimal temperature range within the combustion chamber, 

the reagent in the flue gas would deposit on the wood fibers, causing product damage. Due to 
Plum Creek Manufacturing - Page 16 

February 28, 2011 

these reasons, SNCR has not been successfully demonstrated on wood products dryers. 

Therefore, SNCR is considered technically infeasible and is not considered further.

Flue Gas Recirculation (FGR) 

FGR reduces thermal NOx by routing a portion of the flue gas to the burner to reduce thermal 

NOx. Most of the NOx emissions from wood-fired units arise from the fuel nitrogen, and the 

Line 2 Dryers are already designed with LNB and staged combustion technology. Since the 

minimal thermal NOx emissions that may form would already be controlled using the staged 

combustion technology, the addition of FGR would be ineffective. For these reasons, FGR has 

not been implemented on wood products dryers and is considered technically infeasible.33

Fuel Staging 

As previously discussed, fuel staging is a technique where 10 – 20 percent of the total fuel input 

is diverted to a second combustion zone downstream of the primary zone, and natural gas or 

distillate oil are used in the secondary combustion zone, resulting in lower thermal NOx

formation. This control option is not suitable for the Line 2 Dryers, because they are fired by 

wood residue in a small combustion chamber with no available footprint for a secondary 

combustion zone. Further, this technique reduces thermal NOx, not fuel NOx (the primary 

component of the dryers’ exhaust). Hence, fuel staging is considered technically infeasible and 

is not considered further.

Low Excess Air (LEA) 

In an MDF dryer, there is limited thermal decomposition (partial combustion) of wood furnish 

components during the drying process.34 As such, LEA would not be effective when employed 

in such dryers as high excess air levels are needed for proper fuel burning. Moreover, as seen in 

the case of the Boilers, LEA in the dryers too can result in the production of smoke, increased 

CO emissions, and other problems associated with the dryer operation including increased 

corrosion and fouling.35 Thus, LEA is considered technically infeasible and is not considered 

further. 

STEP 3: EVALUATE CONTROL EFFECTIVENESS OF REMAINING CONTROL 

TECHNOLOGIES

Staged combustion technology, presently installed and operational, is an available NOx control 

for the Line 2 Dryers. There are no other remaining control options which are technically 

feasible. 

 33 NCASI Special Report 03-04, NOx Control in Forest Products Industry Boilers: A Review of 

Technologies, Costs, and Industry Experience, August 2003. 

34 Prevention of Significant Air Quality Deterioration Review of Georgia-Pacific Wood Products LLC - 

Monticello MDF, http://www.gaepd.org/air/airpermit/downloads/permits/15900012/tv16820/1590012pd.pdf

35 NCASI Special Report 03-04, NOx Control in Forest Products Industry Boilers: A Review of 

Technologies, Costs, and Industry Experience, August 2003. 
Plum Creek Manufacturing - Page 17 

February 28, 2011 

STEP 4: EVALUATE IMPACTS

Staged combustion constitutes the most suitable control option for the Line 2 MDF Fiber Dryers. 

Plum Creek employs a robust maintenance program that keeps this technology effective at 

reducing NOx emissions. The burner itself is also strictly controlled using computer controls 

that monitor and control fuel feed and combustion air, monitor combustion zone temperatures as 

well as monitor fire brick temperatures. 

The remaining useful life of the dryers is used for evaluating the economic feasibility of control 

options. Because all add-on control technology options are considered technically infeasible, an 

economic analysis is not necessary for the control technology evaluation conducted for this unit. 

However, the remaining useful life of the equipment may need to be considered in establishing 

Reasonable Progress goals for the region. The remaining useful life of the Line 2 MDF Fiber 

Dryers is 10 years.36

SECTION 5. CONTROL TECHNOLOGY ANALYSIS FOR NOX FROM THE 

LINE 1 MDF FIBER DRYERS (COLUMBIA FALLS OPERATIONS) 

The Line 1 MDF Fiber Dryers at the Columbia Falls Operations include a core dryer and a face 

dryer, each installed with a sanderdust burner with a capacity of 50 MMBtu/hr. The dryers can 

process up to 57 tons/hr of bone dry fiber. The size of the combustion chambers in the Line 1 

Dryers is approximately one-fourth that of the combustion chamber for the Line 2 Dryers. This 

size difference is a direct result of the Line 2 Dryers including a staged combustion design 

requirement from the permitting process of the second line. The staged combustion technology 

implemented when the Line 2 Dryers were constructed requires four times the space to complete 

the combustion process. 

STEP 1: IDENTIFY ALL AVAILABLE RETROFIT CONTROL OPTIONS

Potentially applicable NOx control technologies are identified based on a review of 

determinations for similar units identified from the RBLC search (a summary of relevant RBLC 

search results are presented in Attachment B). After accounting for the physical and operational 

characteristics of the Line 1 MDF Fiber Dryers, the control technologies and strategies 

considered in this analysis for controlling NOx emissions include the following: 

3⁄4 Selective Catalytic Reduction (SCR) 

3⁄4 Selective Non-Catalytic Reduction (SNCR) 

3⁄4 Flue Gas Recirculation (FGR) 

3⁄4 Fuel Staging 

3⁄4 Low Excess Air (LEA) 

3⁄4 Staged Combustion / Low NOx Burners (LNB) 

3⁄4 Good Operating Practices (baseline) 

 36 Engineering estimate by Plum Creek, emailed to Trinity Consultants by Mitchell Leu, January 11, 2011. 
Plum Creek Manufacturing - Page 18 

February 28, 2011 

Each of the technologies listed above are described in Section 2 of this letter report, with the 

exception of good operating practices for the Line 1 MDF Fiber Dryers. 

The formation of NOx can be controlled using good operation practices. Plum Creek adheres to 

a robust maintenance program for the Line 1 MDF Fiber Dryers. Maintaining the burners and 

other dryer equipment in good condition promotes proper combustion and supports good 

operating practices, including computer controlled optimization of air to fuel ratios and firing 

rates. The burners are also computer monitored for combustion zone temperatures. 

STEP 2: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

SCR, SNCR, FGR, fuel staging, and LEA are considered technically infeasible for the Line 1 

Dryers for the same reasons outlined previously under Section 3, Step 2 for the Line 2 MDF 

Fiber Dryers. The technical feasibility for applying staged combustion for the control of NOx

from the Line 1 MDF Fiber Dryers is discussed in the following section. 

Staged Combustion / Low NOx Burners (LNB) 

The available technique for application of staged combustion / LNB technology for the 

combustion of sanderdust involves the same staged combustion process described for the Line 2 

MDF Fiber Dryers. This technique involves firing the sanderdust at sub-stoichiometric levels at 

the burners, and adding air through separate air ports to complete the combustion process. The 

type of LNB technology that can be applied for natural gas or fuel oil combustion is not 

applicable for the combustion of sanderdust. 

The application of staged combustion is limited by the longer and cooler flames produced as a 

consequence of improved air distribution control. The Line 1 MDF Fiber Dryers have a 

combustion chamber that is size-restricted. The firebox is one-fourth the size of that of the 

Line 2 MDF Fiber Dryers combustion chamber. The small size of the combustion chamber 

makes it impossible to retrofit the Line 1 MDF Fiber Dryers with a staged combustion 

technology without requiring replacement of the unit for the larger sized chamber. Where the 

current burners are located is footprint restricted for size so the larger combustion chambers 

would need to be relocated further away from the dryer also. This would add in sizable 

additional costs for ducting the combustion gases into the dryer. Therefore, staged combustion 

technology is considered technically infeasible for the retrofit of the Line 1 MDF Fiber Dryers. 

STEP 3: EVALUATE CONTROL EFFECTIVENESS OF REMAINING CONTROL 

TECHNOLOGIES

Good operating practices are the only available NOx control technology for the Line 1 MDF 

Fiber Dryers. Therefore, there are no other technically feasible control options for evaluation. 
Plum Creek Manufacturing - Page 19 

February 28, 2011 

STEP 4: EVALUATE IMPACTS

Good combustion practices constitute the most suitable control option for the Line 1 MDF Fiber 

Dryers. 

The remaining useful life of the unit is used for evaluating the economic feasibility of control 

options. Because all add-on control technology options are considered technically infeasible, an 

economic analysis is not necessary for the control technology evaluation conducted for these 

dryers. However, the remaining useful life of the equipment may need to be considered in 

establishing Reasonable Progress goals for the region. The remaining useful life of the Line 1 

MDF Fiber Dryers is 10 years. 37

SECTION 6. CONCLUSION

Plum Creek conducted a control technology evaluation to address requirements under the 

Regional Haze Rule for Reasonable Progress goals and strategies. Based on the evaluation 

presented in this letter, the existing control measures are the most suitable for PM, SO2, and NOx

emissions from the Riley Stoker Boilers at the Columbia Falls Operations and at the Evergreen 

Division facility and the Line 1 and Line 2 MDF Fiber Dryers at the Columbia Falls Operations. 

PM emissions are well controlled for all four emission units, using a Venturi scrubber for the 

Line 2 MDF Fiber Dryers and ESP technology for the remaining units. Emissions of SO2 are 

minimal, since all four units combust fuels with negligible amounts of sulfur (hog fuel, 

sanderdust, and natural gas). NOx emissions from the Riley Stoker Boilers are controlled using 

good operating practices, including employing a computerized control system to optimize the air 

and fuel feed rates. Additionally, the firing of hog fuel with supplemental downstream 

sanderdust burners results in low thermal NOx formation. NOx emissions from the Line 1 MDF 

Fiber Dryers are controlled using good operating practices, and the Line 2 MDF Fiber Dryers 

employ staged combustion technology to reduce NOx formation. 

 37 Engineering estimate by Plum Creek, emailed to Trinity Consultants by Mitchell Leu, January 11, 2011. 
Plum Creek Manufacturing - Page 20 

February 28, 2011 

Should EPA Region 8 have any questions or require further information regarding the emission 

units or control technologies addressed in this letter, Plum Creek looks forward to working with 

EPA Region 8 to provide additional information to assist in establishing the Reasonable 

Progress goals and strategies for Montana. 

Sincerely, 

PLUM CREEK MANUFACTURING 

Thomas Ray 

Vice President Montana Operations 

Attachments 

cc: Mr. Mitchell Leu, Plum Creek 

Ms. Anna Henolson, Trinity Consultants 

Ms. Anupama Krishnan, Trinity Consultants 
ATTACHMENT A 

EPA 114 Request Letter 



ATTACHMENT B 

RBLC and Biomass Boiler Permit Search Results 
Table B-1. RBLC Search Results for NOx control devices on Hog Fuel Boilers 1

FACILITY STATE

PERMIT 

ISSUANCE DATE EQUIPMENT PRIMARY FUEL THROUGHPUT UNIT CONTROL METHOD DESCRIP

MEADWESTVACO KENTUCKY, INC/WICKLIFFE KY 2/27/2002 BOILER, BARK BARK 631 MMBTU/H 

BOGALUSA MILL LA 11/23/2004

NO. 12 HOGGED FUEL 

BOILER BARK 787.5 MMBTU/H

EXISTING OVERFIRE AIR SYSTEM 

NOX BURNERS IN THE UNDER G

HEATER SYSTEM, PLUS GOOD CO

PRACTICES 

S.D. WARREN CO. - SKOWHEGAN, ME ME 11/27/2001 BOILER, #2 WOOD WASTE 1300 MMBTU/H SCNR 

DISTRICT ENERGY ST. PAUL, INC MN 11/15/2001 BOILER WOOD 550 MMBTU/H

SELECTIVE, NON-CATALYTIC RE

SNCR 

KODA ENERGY MN 8/23/2007 BIOMASS BOILER 3 SNCR KODA ENERGY MN 8/23/2007 BIOMASS BOILER 4 SNCR 

NORTHERN SUN ND 5/1/2006 WOOD/HULL FIRED BOILER BIOMASS COMBUSTION CONTROL

SCHILLER STATION NH 10/25/2004

BOILER, WOOD FIRED CFB, 

UNIT #5 BIOMASS 720 MMBTU/h SELECTIVE NON-CATALYTIC RE

CONCORD STEAM CORPORATION NH 2/27/2009 BOILER #1 BIOMASS 32.62 T/H

SELECTIVE CATALYTIC REDUCT

SYSTEM 

CLEAN POWER BERLIN LLC NH 9/25/2009 BOILER 1 WOOD CHIPS 40.75 T/H WOOD

SELECTIVE CATALYTIC REDUCT

WITH STAGED COMBUSTI

BERLIN BIOPOWER NH 7/26/2010 EU01 BOILER #1 WOOD 1013 MMBTU/H

SCR (COLD SIDE OF BAGHOUSE

AMMONIA INJECTION 

BERLIN BIOPOWER NH 7/26/2010 EU01 BOILER #1 WOOD 1013 MMBTU/H

SCR (COLD SIDE OF BAGHOUSE

AMMONIA INJECTION 

SOUTH POINT BIOMASS GENERATION OH 4/4/2006 WOOD FIRED BOILERS (7) WOOD 318 MMBTU/H SELECTIVE CATALYTIC REDU

Plum Creek ManufacturingRBLC Search Boiler_v2.0.xlsx - 11.120
LINDALE RENEWABLE ENERGY TX 1/8/2010 Wood fired boiler biomass 73 T/H Selective Non-catalytic Reduc

LUFKIN GENERATING PLANT TX 10/26/2009 Wood-fired Boiler wood 693 MMBtu/hr Selective Catalytic Reductio

INTERNATIONAL BIOFUELS, INC VA 12/13/2005

WOOD THERMAL OXIDERS 

FOR WOOD PELLENT 

PROCESS WOOD/WOOD PASTE 43 MMBTU/H THERMAL OXIDIZERS AND CEM 

ABERDEEN DIVISION WA 10/17/2002 HOG FUEL BOILER WASTE WOOD 310 MMBTU/H SNCR, BOILER DESIGN 

SKAGIT COUNTY LUMBER MILL WA 1/25/2006

WOOD-FIRED 

COGENERATION UNIT BARK & WASTE WOOD 430 mmBtu/H

SELECTIVE NONCATALYTIC RED

(SNCR) 

DARRINGTON ENERGY COGENERATION POWER 

PLANT WA 2/11/2005

WOOD WASTE-FIRED 

BOILER WOOD WASTE 403 MMBtTU/H SNCR 

CLEWISTON SUGAR MILL AND REFINERY FL 2004 BOILER 8 BAGASSE 1030 MMBTU/H SNCR 

DEL-TIN FIBER L.L.C AR 2/28/2003 HEAT ENERGY SYSTEM BIOMASS 291 MMBTU/H SNCR 

INLAND PAPERBOARD TX 10/5/2004 BOILER BARK 856 MMBTU/H SNCR 

WEYERHAEUSER RED RIVER MILL LA 5/24/2006 NO. 2 HOGGED FUEL BOILER WOOD 940 MMBTU/H SNCR 

1. Search Criteria for RBLC: Date range from January 1, 2000 through January, 2011; Process Information included Boilers fired by all fuel types. Boilers with all other fuel types other than hog fuel are removed from the search results. W

list also includes a search of facilities with recently permitted industrial biomass boilers having SNCR systems installed.

Plum Creek ManufacturingRBLC Search Boiler_v2.0.xlsx - 11.120
Table B-2. RBLC Search Results for NOx control devices on Wood Products Dryers

FACILITY STATE

PERMIT ISSUANCE 

DATE PROCESS NAME PRIMARY FUEL THROUGHPUT UN

PARAGON PANELS OF ALABAMA, L.L.C. AL 4/12/2006 WOOD FIBER PREP/DRYING 151 mm

LOUISIANA PACIFIC CORPORATION AL 6/14/2006 BOARD PRESS BARK 85000 LBLOUISIANA PACIFIC CORPORATION AL 6/14/2006 BARK BURNER/DRYER BARK 85000 lb

GEORGIA-PACIFIC ORIENTED STRANDBOARD FACILITY AR 1/7/2003 ROTARY CHIP DRYER, (5) WOOD WASTES 600 MMS

NORBORD GEORGIA GA 6/3/2005 WOOD FLAKE DRYERS WOOD 52 OD

OAKDALE OSB PLANT LA 6/13/2005 ROTARY DRYER NOS. 1-3 WOOD 300000

MSF/Y

inch 

WEYERHAEUSER MI 6/11/2002 DRYERS AND BURNERS, WOOD CHIP WOOD 108000 LB

SAGOLA MILL MI 1/31/2008 FLAKE DRYERS

DIBOLL PARTICLEBOARD OPERATION TX 9/28/2001 PARTICLE BOARD PRESS, PB-53 DIBOLL PARTICLEBOARD OPERATION TX 9/28/2001 (2) DRYERS NO 1 & 2, PB-47 DIBOLL PARTICLEBOARD OPERATION TX 9/28/2001 DRYER NO 3, PB-49 DIBOLL PARTICLEBOARD OPERATION TX 9/28/2001 DRYER NO 4, PB-50 DIBOLL PARTICLEBOARD OPERATION TX 9/28/2001 SANDER DUST BOILER, PB-44 WOOD 40 MMB

JASPER ORIENTED STRANDBOARD MILL TX 2/9/2004 DRYERS 1-5 BYPASS 

CARHAGE ORIENTED STRANDBOARD MILL TX 3/16/2004 DRYER BYPASS (2) 

LOUISIANA-PACIFIC HAYWARD WI 6/17/2004 DRYER SYSTEM, LINE I, LINE II WOOD

1. Search Criteria for RBLC: Date range from January 1, 2000 through January, 2011; Process Information included Dryers fired by all fuel types. Dryers with all other fuel types other than hog fuel fuel type is not provided in RBLC entries, assumptions regarding possible fuel types are made based on industry.

Plum Creek ManufacturingRBLC Search MFD Dryer_v2.0.xlsx - 30.530