NATIONAL COUNCIL FOR AIR AND STREAM IMPROVEMENT

NOX CONTROL IN

FOREST PRODUCTS INDUSTRY

BOILERS: A REVIEW OF

TECHNOLOGIES, COSTS,

AND INDUSTRY EXPERIENCE

SPECIAL REPORT NO. 03-04

AUGUST 2003

by

Arun V. Someshwar, Ph.D.

Ashok K. Jain

NCASI Southern Regional Center

Gainesville, Florida

ASHDOWN-Q8-000763
Acknowledgments

This report was prepared by Dr. Arun V. Someshwar, Principal Research Engineer at the NCASI Southern

Regional Center. Dr. John E. Pinkerton, Vice President, Air Quality, provided valuable review of the report

contents. Susan Kirkland was responsible for report preparation.

For more information about this research, contact:

Arun V. Someshwar, Ph.D.

Principal Research Engineer

NCASI Southern Regional Center

402 SW 140th Terrace

Newberry, FL 32669-3000

(352) 331-1745, ext. 226

asomeshwar@ncasi.org

John Pinkerton, Ph.D.

Vice President, Air Quality

NCASI

P.O. Box 13318

Research Triangle Park, NC 27709-3318

(919) 941-6406

jpinkerton@ncasi.org

For information about NCASI publications, contact:

Publications Coordinator

NCASI

P.O. Box 13318

Research Triangle Park, NC 27709-3318

(919) 941-6400

publications@ncasi.org

National Council for Air and Stream Improvement, Inc. (NCASI). 2003. NOx control in forest products industry

boilers: A review of technologies, costs and industry experience. Special Report No. 03-04. Research Triangle

Park, N.C.: National Council for Air and Stream Improvement, Inc.

© 2003 by the National Council for Air and Stream Improvement, Inc.

ASHDOWN-Q8-000764
National Council for Air and Stream Improvement

serving the environmental research needs of the forest products industry since 1943

PRESIDENT’S NOTE

The United States Environmental Protection Agency and many state agencies are attempting to lower

ambient ozone concentrations by reducing emissions of precursor compounds, including NOx. The

contribution of NOx to secondary fine particulate matter and regional haze is actively being studied by

EPA as it develops strategies to reduce ambient PM2.5 levels. As a result of these regulatory initiatives,

it is not surprising to find an escalating interest in the investigation of NOx emissions and options for

reduction. Although forest products manufacturing facilities represent only about 1% of the total U.S.

NOx emissions, many regulatory agencies have been scrutinizing mill NOx emission sources for

potential reductions.

Therefore, NCASI has devoted considerable efforts in recent years to studying NOx emissions from mill

combustion sources, including kraft recovery furnaces, lime kilns, thermal oxidizers, and power boilers,

particularly those burning wood residues. At most mills, boilers are the largest NOx emission source

and are thus the most frequent target for reductions. To assist mills in responding to regulatory agency

pressures for NOx reductions, NCASI issued a special report in 1999 (A Review of NOx Emission

Control Strategies for Industrial Boilers, Kraft Recovery Furnaces, and Lime Kilns). Since there

have been significant developments over the past five years in combustion modifications and add-on

control technologies for boiler NOx reductions, NCASI reviewed the more recent information to

update the 1999 report.

This special report is meant to serve as a background document to assist member companies in

responding to NOx limitations that might be proposed by regulatory agencies as a result of uniform

State Implementation Plan (SIP) requirements for industrial boilers or in permitting decisions for

individual units. It reviews NOx control technologies that are available for direct application to

forest products industry boilers, or that may be transferable from current utility boiler applications. 

Limitations identified by vendors and boiler operators that could preclude successful installation and

operation of certain control technologies on particular boilers have been reviewed and summarized,

especially with respect to technical feasibility. NOx control costs and removal cost-effectiveness

estimates from a number of sources are provided.

NCASI appreciates the engineering, cost, and other information on boiler NOx reductions anonymously

shared by several member companies for use in this report.

Ronald A. Yeske

August 2003

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National Council for Air and Stream Improvement

au service de la recherche environnemental e pour l’industrie forestière depuis 1943

MOT DU PRESIDENT

L’EPA et plusieurs agences d’état tentent de diminuer les concentrations d’ozone dans l’air ambiant par la

réduction des émissions de composés précurseurs, tels que les NOx. La contribution des NOx aux particules

secondaires et à la brume sèche en régions (regional haze) est actuellement à l’étude par l’EPA. L’EPA est

en cours de développement de stratégies pour réduire les niveaux ambiants de PM2.5. Il n’est pas surprenant

de voir apparaître, suite à ces initiatives réglementaires, un intérêt grandissant pour la recherche sur les

émissions de NOx de même que sur les options de réduction de ces polluants. Malgré le fait que l’industrie

des produits forestiers ne représente qu’environ 1% des émissions totales de NOx aux États-Unis, plusieurs

agences de réglementation se sont penchées sur les sources d’émissions de NOx des fabriques afin de déceler

des réductions potentielles.

Par conséquent, NCASI a déployé des efforts considérables depuis les dernières années afin d’étudier les

émissions de NOx des sources de combustion des fabriques, incluant les fournaises de récupération kraft,

les fours à chaux, les oxydateurs thermiques et les chaudières, plus particulièrement celles qui sont alimentées

par de la biomasse. Dans la plupart des fabriques, les chaudières demeurent les principales sources

d’émissions de NOx et elles représentent une cible de choix pour ce qui est des réductions potentielles. Afin

de soutenir les fabriques qui doivent répondre aux pressions des agences de réglementation pour ce qui est

des réductions d’émissions de NOx, NCASI a publié un rapport spécial en 1999 (Une revue des stratégies de

contrôle des émissions de NOx pour les chaudières, les fournaises de récupération kraft ainsi que les fours

à chaux). Depuis les cinq dernières années, d’importants développements ont vu le jour en matière de

modifications de la combustion et de technologies de contrôle pour la réduction des émissions de NOx

des chaudières. NCASI a brossé un tableau des informations les plus récentes afin de mettre à jour son

rapport de 1999.

Ce rapport spécial se veut un document de référence afin d’aider les compagnies membres à répondre aux

exigences de réductions des émissions de NOx qui peuvent être proposées par les agences de réglementation

dans le cadre du Plan d’implantation de l’état (State Implementation Plan) pour les chaudières ou encore suite

aux décisions reliées aux autorisations et permis pour les unités individuelles. Le rapport fait la revue des

technologies de contrôle des NOx qui sont disponibles pour une application directe dans les chaudières de

l’industrie forestière ou encore qui peuvent être transférées des expériences acquises sur les chaudières de

centrales thermiques. Les limites identifiées par les fournisseurs et les opérateurs de chaudières et qui sont

susceptibles de nuire au succès de l’installation et de l’opération de certaines technologies de contrôle des

NOx sur des chaudières spécifiques ont fait l’objet d’une revue et d’une synthèse, principalement en ce qui

concerne la faisabilité technique. On trouve également dans ce rapport les coûts de contrôle des NOx et les

estimés d’efficacité d’enlèvement pour plusieurs sources.

NCASI tient à remercier les nombreuses compagnies membres qui ont bien voulu partager, dans l’anonymat,

des données sur les travaux d’ingénierie, les coûts et d’autres informations en matière de réduction des NOx

émis par les chaudières. Ces données ont été utilisées dans ce rapport.

Ronald A. Yeske

Août 2003

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National Council for Air and Stream Improvement

NOX CONTROL IN FOREST PRODUCTS INDUSTRY BOILERS:

A REVIEW OF TECHNOLOGIES, COSTS AND INDUSTRY EXPERIENCE

SPECIAL REPORT NO. 03-04

AUGUST 2003

ABSTRACT

Recent information on techniques for reducing NOx emissions from boilers burning fossil fuels

and biomass fuels is reviewed. The applicability of both combustion modifications and flue

gas treatment to industrial-sized boilers at forest products manufacturing facilities is discussed. 

Difficulties inherent in applying various technologies to boilers burning coal, gas, oil, wood, or

combinations thereof are highlighted. Combustion modifications such as the use of low-NOx burners

and overfire air appear suitable for most coal, oil and gas-fired boilers, although cost considerations

in each individual instance should be evaluated. Selective non-catalytic reduction (SNCR) by urea

injection appears to be a viable NOx reduction technology for base-loaded boilers. However, its

applicability to boilers with swinging loads needs further research and development. Problems with

ammonia slip and curtailed NOx removal efficiencies are key concerns. Installation and operation of

selective catalytic reduction (SCR) on industrial boilers firing coal, oil, and gas is the most expensive

add-on control option. There are numerous issues with using SCR on wood and combination woodfired boilers, including catalyst plugging and soluble alkali poisoning as well as increased energy

consumption. Emerging technologies such as gas reburning and low temperature oxidation followed

by scrubbing, hold much promise as technologies that can fill the gap in NOx control efficiencies

between the 30 to 50% expected from SNCR and 80 to 90% expected from the more expensive SCR.

With regard to NOx removal costs, available mill-generated estimates of cost-effectiveness fall in the

$2,000 to $6,000 per ton removed range. These estimates exceed EPA’s benchmark figure of $2,000

per ton removed, a figure EPA believes is a reasonable cost for retrofit industrial boiler NOx controls

in ozone nonattainment areas.

KEYWORDS

biomass, combustion modification, cost-effectiveness, costs, fuel NOx, LNB, OFA, SCR, SNCR,

thermal NOx, staged combustion, wood residue

RELATED NCASI PUBLICATIONS

Technical Bulletin No. 802 (March 2000). Effect of stripper off-gas burning on NOx emissions.

Special Report No. 99-01 (April 1999). A review of NOx emission control strategies for industrial

boilers, kraft recovery furnaces, and lime kilns.

Technical Bulletin No. 646 (February 1993). Emission factors for NOx, SO2 and volatile organic

compounds for boilers, kraft pulp mills, and bleach plants.

Technical Bulletin No. 636 (July 1992). An analysis of kraft recovery furnace NOx emissions and

related parameters. 

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National Council for Air and Stream Improvement

Technical Bulletin No. 455 (April 1985). Volatile organic carbon emissions from wood residue fired

power boilers in the Southeast.

Atmospheric Quality Improvement Technical Bulletin No. 111 (January 1981). A study of nitrogen

oxides emissions from large kraft recovery furnaces.

Atmospheric Quality Improvement Technical Bulletin No. 109 (September 1980). A study of woodresidue fired power boiler total gaseous non-methane organic emissions in the Pacific Northwest.

Atmospheric Quality Improvement Technical Bulletin No. 107 (April 1980). A study of nitrogen

oxides emissions from lime kilns. 

Atmospheric Quality Improvement Technical Bulletin No. 105 (December 1979). A study of

nitrogen oxides emissions from kraft recovery furnaces.

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National Council for Air and Stream Improvement

CONTROLE DES NOX EMIS PAR LES CHAUDIERES DE L’INDUSTRIE DES

PRODUITS DU BOIS - UNE REVUE DES TECHNOLOGIES, DES COUTS ET DE

L’EXPERIENCE DE L’INDUSTRIE

RAPPORT SPECIAL NO. 03-04

AOUT 2003

RESUME

Les informations récentes portant sur les techniques de réduction des émissions de NOx générées par

la combustion de combustibles fossiles et de biomasse dans les chaudières font l’objet d’une revue.

On discute des modifications de combustion et du traitement des gaz de combustion appliqué aux

chaudières utilisées dans les fabriques de l’industrie des produits du bois. On trouve également des

informations sur les difficultés inhérentes à l’application de différentes technologies de contrôle sur

des chaudières utilisant du charbon, du gaz, de l’huile, de la biomasse ou une combinaison de ces

combustibles. Les modifications de combustion telles que l’utilisation de brûleurs à bas niveau de

NOx (low-NOx) et l’optimisation de l’air de combustion secondaire et tertiaire (overfire air) semblent

applicable pour la plupart des chaudières utilisant du charbon, de l’huile et du gaz, mais les

considérations économiques doivent être évaluées au cas par cas. La réduction sélective noncatalytique (SNCR) à l’aide d’injection d’urée semble être une technologie de réduction des NOx

viable pour les chaudières alimentées par la base; toutefois on se doit de poursuivre les efforts de

recherche et développement en ce qui concerne l’application de cette technologie sur des chaudières

dont les charges varient. Les problèmes reliés aux pertes d’ammoniac et à la diminution de

l’efficacité d’enlèvement de NOx qui en découle demeurent des préoccupations majeures.

L’installation et l’opération de la réduction catalytique sélective (SCR) sur des chaudières utilisant

du charbon, de l’huile et du gaz représente l’option de contrôle la plus coûteuse. Il existe plusieurs

enjeux associés à l’utilisation de la SCR dans les chaudières à biomasse et les chaudières à

biomasse/combustibles multiples : obstruction du catalyseur, empoisonnement par des alcali

solubles et augmentation de la consommation d’énergie. On mise beaucoup sur les nouvelles

technologies telles que la combustion répétée des gaz et l’oxydation à basse température suivie de

l’épuration pour combler l’écart existant en ce qui concerne l’efficacité de contrôle des NOx, entre

30 à 50% pour la SNCR et entre 80 à 90% pour la SCR, plus coûteuse. En ce qui concerne les coûts

d’enlèvement des NOx, les estimés de rentabilité obtenus dans les fabriques varient de 2 000 $

à 6 000 $ par tonne enlevée. Ces estimés dépassent l’évaluation de référence de l’EPA de 2 000 $

par tonne enlevée. L’EPA estime que ce montant représente un coût raisonnable pour modifier ou

ajouter le contrôle des NOx émis par des unités situées dans les zones de non atteinte de la norme

sur l’ozone.

MOTS CLÉS

NOx combustible, NOx thermique, biomasse, combustion étagée, résidus de bois, SCR, SNCR,

modification de combustion, NOx bas niveau, LNB, OFA, coûts, rentabilité

AUTRES PUBLICATIONS DE NCASI DANS CE DOMAINE

Bulletin technique no. 802 (mars 2000). Effect of stripper off-gas burning on NOx emissions.

Rapport spécial no. 99-01 (avril 1999). A review of NOx emission control strategies for industrial

boilers, kraft recovery furnaces, and lime kilns.

ASHDOWN-Q8-000771
National Council for Air and Stream Improvement

Bulletin technique no. 646 (février 1993). Emission factors for NOx, SO2 and volatile organic

compounds for boilers, kraft pulp mills, and bleach plants.

Bulletin technique no. 636 (juillet 1992). An analysis of kraft recovery furnace NOx emissions and

related parameters.

Bulletin technique no. 455 (avril 1985). Volatile organic carbon emissions from wood residue fired

power boilers in the Southeast.

Bulletin technique sur l’amélioration de la qualité de l’atmosphère no. 111 (janvier 1981). A study of

nitrogen oxides emissions from large kraft recovery furnaces.

Bulletin technique sur l’amélioration de la qualité de l’atmosphère no. 109 (septembre 1980). A

study of wood-residue fired power boiler total gaseous non-methane organic emissions in the Pacific

Northwest.

Bulletin technique sur l’amélioration de la qualité de l’atmosphère no. 107 (avril 1980). A study of

nitrogen oxides emissions from lime kilns.

Bulletin technique sur l’amélioration de la qualité de l’atmosphère no. 105 (décembre 1979). A study

of nitrogen oxides emissions from kraft recovery furnaces.

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National Council for Air and Stream Improvement

CONTENTS

1.0 INTRODUCTION ........................................................................................................................ 1

2.0 NOX LEVELS, CONTROL REQUIREMENTS, AND TYPES OF BOILERS........................... 2

2.1 NOx Levels and Control Requirements for Boilers ............................................................ 2

2.2 Description of Boiler Types ............................................................................................... 3

3.0 REVIEW OF NOX CONTROL TECHNIQUES FOR INDUSTRIAL BOILERS ....................... 4

3.1 Combustion Modifications ................................................................................................. 4

3.2 Flue Gas Treatment............................................................................................................. 8

4.0 NOX CONTROL TECHNIQUES TYPICALLY APPLICABLE TO FPI BOILERS ................ 11

4.1 Conventional Boilers Firing Fossil Fuels, Wood, or Both ............................................... 12

4.2 Gas Turbines..................................................................................................................... 18

4.3 Fluidized Bed Combustors ............................................................................................... 18

5.0 TECHNOLOGICAL ADVANCES IN NOX CONTROL FOR BOILERS ................................ 19

5.1 Swanekamp (2002a) ......................................................................................................... 20

5.2 Swanekamp (2002b) ......................................................................................................... 20

5.3 Swanekamp and Ellison (2001) ........................................................................................ 21

5.4 NESCAUM (2001) ........................................................................................................... 21

5.5 NESCAUM (2000) ........................................................................................................... 22

6.0 EMERGING TECHNOLOGIES FOR INDUSTRIAL BOILER NOX CONTROL................... 22

6.1 Methane de-NOX Reburn Technology............................................................................. 23

6.2 Low Temperature Oxidation............................................................................................. 23

6.3 Induced Flue Gas Recirculation Technology ................................................................... 24

6.4 The Pahlman Process........................................................................................................ 24

6.5 Other Emerging Technologies.......................................................................................... 25

7.0 TECHNICAL LIMITATIONS OF APPLYING AVAILABLE NOX CONTROL

TECHNOLOGIES TO FPI BOILERS ....................................................................................... 26

7.1 Applicability of Combustion Modifications..................................................................... 27

7.2 Applicability of SNCR NOx Control Technology ............................................................ 28

7.3 Applicability of SCR NOx Control Technology............................................................... 29

8.0 PERMITTING INFORMATION ............................................................................................... 29

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National Council for Air and Stream Improvement

9.0 NOX EMISSIONS CONTROL COST ESTIMATES FOR INDUSTRIAL BOILERS ..............29

9.1 EPA Estimates for New Industrial Fossil Fuel-Fired Boilers ...........................................30

9.2 NESCAUM .......................................................................................................................33

9.3 FPI Cost Estimates for Industrial Boiler NOx Control......................................................33

9.4 Comparison of Cost Estimates ..........................................................................................33

10.0 SUMMARY ................................................................................................................................37

REFERENCES .....................................................................................................................................38

APPENDICES

A THE 0.2 lb NOx/106

 Btu EMISSION STANDARD FOR INDUSTRIAL

BOILERS – AF&PA PETITION CHALLENGING AND EPA LEGAL

BRIEF DEFENDING THIS STANDARD AND NCASI COMMENTS

ON EPA’S LEGAL BRIEF..............................................................................................A1

B NEW SOURCE PERFORMANCE STANDARDS, SUBPARTS Da AND Db -

SUMMARY OF PUBLIC COMMENTS AND EPA RESPONSES ...............................B1

C RACT/BACT/LAER NOX CONTROL OPTIONS FOR BOILERS –

INFORMATION SUBMITTED BY FOREST PRODUCTS COMPANIES ..................C1

D PERMITTING DESIGNS AND NOX EMISSION LIMITS IN EPA’S RACT/

BACT/LAER CLEARINGHOUSE DATABASE FOR FPI BOILERS ..........................D1

E DETAILED COST ANALYSIS FOR MILL H COAL-FIRED BOILER ....................... E1

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National Council for Air and Stream Improvement

TABLES

Table 2.1 AP-42 NOx Emission Factors (boilers with >100 x 106 Btu/hr heat input) and

NSPS for Industrial Boilers (>100 x 106

 Btu/hr heat input)............................................... 3

Table 4.1 NOx Emissions Results with Wood Waste Co-Firing with Coal (Hughes 1998)............. 18

Table 9.1 Summary of Annualized Costs for Model Boilers (USEPA 1997) .................................. 31

Table 9.2 Model Boiler Incremental Cost-Effectiveness Ranges (USEPA 1997)............................ 32

Table 9.3 Cost Estimates of NOx Control for Industrial Boilers (NESCAUM 2000) ...................... 33

Table 9.4 Cost Estimates of NOx Control in Forest Products Industry Boilers................................ 34

Table 9.5 Summary of Estimated Costs and NOx Control Options for Mill H

Pulverized Coal-fired Boiler............................................................................................. 36

FIGURES

Figure 3.1 Primary SNCR Reaction Sequences................................................................................... 8

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NOX CONTROL IN FOREST PRODUCTS INDUSTRY BOILERS:

A REVIEW OF TECHNOLOGIES, COSTS, AND INDUSTRY EXPERIENCE

1.0 INTRODUCTION

As part of its strategy to reduce ground-level ozone concentrations, USEPA has become more

focused on NOx emission reductions, especially in the eastern Unites States. In 1998, EPA issued

the NOx SIP Call Rule. This rule, NOx Trading Program for State Implementation Plans (40 CFR

Part 96), required 22 eastern states and the District of Columbia to submit State Implementation Plan

(SIP) revisions to reduce emissions of NOx, one of the key precursors in the formation of groundlevel ozone. Each of these states was assigned an NOx budget for the summer ozone season (May 1

through September 30). The statewide budget amounts were determined by photochemical modeling.

NOx reductions could come from any type of NOx-emitting sources, but EPA felt the most costeffective reductions would come from utility and large industrial boilers burning coal and residual

oil. However, states could target additional sources such as smaller boilers, mobile sources, and

industrial processes for NOx reductions.

States initially subject to the NOx reduction requirements were Alabama, Connecticut, Delaware,

Georgia, Illinois, Indiana, Kentucky, Maryland, Massachusetts, Michigan, Missouri, New Jersey,

New York, North Carolina, Ohio, Pennsylvania, Rhode Island, South Carolina, Tennessee, Virginia,

West Virginia and Wisconsin. For each of these states, EPA set a target reduction total amount of

NOx (in tons) which would have to be achieved by May 31, 2004. NOx emission reductions are

based on the May 1 through September 30 ozone season. In 2002, Wisconsin was removed from the

list of states subject to the SIP Call, and the first compliance period for Georgia and Missouri was

moved to May 1, 2005. Southern portions of Georgia and Alabama, northern portions of Michigan

and western portions of Missouri were also excluded from geographic coverage of the NOx SIP call. 

Emission reductions required by the states (except Georgia and Missouri) must be implemented by

May 31, 2004. EPA suggested that a cost criterion of $2,000 per ton of NOx reduction be used by

the states to determine which types of stationary sources should be subject to control requirements. 

EPA concluded that electric utilities and fossil fuel-fired industrial boilers (>250 x 106

 Btu/hr heat

input capacity) should be the primary candidates for lowered NOx emissions, with average costs

under $2,000 per ton of NOx removed for units burning coal or residual oil. Other types of sources,

including smaller industrial boilers, pulp mill recovery furnaces, and lime kilns, were determined to

likely have NOx control costs exceeding $2,000/ton. However, individual states must decide on the

specific control requirements for each stationary NOx emission source.

In the 21 states, there are a large number of forest products manufacturing facilities, many of which

operate combustion units, that are potential candidates for NOx controls. These facilities will need

to ensure the technical feasibility and cost-reasonableness of any proposed new NOx emission

restrictions. Mills with large coal and oil burning boilers have begun examining the costs and

technical feasibility of various NOx control measures such as fuel switching, boiler combustion

modifications, and add-on controls. In addition to coal and residual oil, pulp mills also use distillate

oil, natural gas, and wood residues as boiler fuels. Most of these fuels are burned in conventional

steam generating boilers. In addition to conventional boilers, fluidized bed combustors and gas

turbines are being used for steam and power generation at an increasing number of mills. In 2000,

natural gas and wood residues each accounted for 33% of the fuel use in paper mill steam generating

units, followed by coal (26%), and residual oil (8%) (NCASI 2002a). Distillate oil and miscellaneous

fuels accounted for the remainder. Miscellaneous fuels include tire chips, petroleum coke, anthracite

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National Council for Air and Stream Improvement

culm, fiber and paper-based fuels, wastewater treatment plant (WTP) residuals, rejects from old

corrugated container processing, used oil, and refuse-derived fuel.

An earlier report (NCASI 1999) provided an overview of the mechanisms of NOx formation and

explained how an understanding of these mechanisms was important in the context of applying

NOx control technologies to many forest products industry (FPI) combustion units that are unique

in their use of biomass fuels such as wood and black liquor. This report provides a review of the

NOx control techniques that could be considered applicable to industrial boilers and highlights those

technologies currently available for controlling industrial boiler NOx emissions. It also summarizes

the various technological concerns raised in the literature or by individual companies and mills in

their evaluations of potential NOx control technologies to particular boilers in the context of RACT

(Reasonably Available Control Technology), BACT (Best Available Control Technology), LAER

(Lowest Achievable Emission Rate), or other regulatory permitting requirements. Finally, cost

estimates generated by individual FPI companies for implementing such technologies are provided

and compared with those developed by EPA.

2.0 NOX LEVELS, CONTROL REQUIREMENTS, AND TYPES OF BOILERS

The level of NOx control required for a boiler, along with the boiler design and operating conditions,

will generally determine the technologies that are capable of achieving the requisite reduction. Some

boilers are incapable of significant NOx control by combustion modifications because of the nature of

their design and operation. Most boiler designs do not, however, directly influence post-combustion

NOx control via flue gas treatment, such control being limited only by boiler operating considerations

such as load swings and flue gas composition and other considerations such as space and geometry

limitations, cost of control, etc. Gas and oil-fired boilers that need to achieve NOx removal

efficiencies in excess of about 75% and solid fuel-fired boilers needing NOx removal efficiencies in

excess of about 30% are generally forced to look at post-combustion NOx control. Boilers subject to

lesser NOx removal requirements can resort to various combinations of combustion modifications.

2.1 NOx Levels and Control Requirements for Boilers

Table 2.1 presents the uncontrolled NOx emission factors for typical industrial boilers with heat

inputs >100 x 106

 Btu/hr as given in EPA’s AP-42 documents for bituminous coal, oil, gas (USEPA

1998a, 1998b, 1998c), and wood-fired boilers (USEPA 2001). In September 1998, EPA revised

NOx emission limits contained in the Subpart Db NSPS (new source performance standards) which

apply to new industrial boilers with heat input capacities of 100 x 106

 Btu/hr or greater. Table 2.1

also shows the revised Subpart Db emission limits for various types of boilers. The Db limits are

30-day rolling averages and apply to all boilers for which construction started after July 9, 1997. 

Limits for natural gas and distillate oil-fired boilers were left essentially unchanged from the earlier

NSPS Subpart Db standards promulgated on June 19, 1984, while limits for coal and residual oil

were lowered significantly. The basis for the revised standards for coal- and residual oil-fired boilers

is the application of combustion modifications and selective catalytic reduction (SCR) flue gas

treatment, although EPA claims selective non-catalytic treatment (SNCR) may be sufficient for

residual oil-fired units. While no specific limits were promulgated for boilers firing wood residues

under Subpart Db, any boiler firing more than 10% of any fossil fuel on an annual basis is subject to

the NOx emission limit for the fossil fuel. Thus, boilers firing coal or oil with wood would have a

limit of 0.2 lb/106 Btu.

Also shown in Table 2.1 are the corresponding percentage reductions in NOx emissions expected

from the uncontrolled or baseline levels for boilers (as indicated by the AP-42 factors) that become

subject to the revised NSPS. It should be noted that for large electric generating units (EGUs) in

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National Council for Air and Stream Improvement

states subject to the NOx SIP call, EPA has recommended that they be assigned NOx limits of about

0.15 lb NOx /106

 Btu heat input, representing an average cost-effectiveness of $1,720 per ozone

season ton NOx removed in 1997 dollars. Very few, if any, boilers in the FPI are classified as EGUs.

 Large non-EGUs, i.e., industrial boilers with coal or residual oil heat input capacities over 250 x 106

Btu/hr, are recommended by EPA for a 60% reduction in NOx emissions from baseline levels.

Table 2.1 AP-42 NOx Emission Factors (boilers with >100 x 106

 Btu/hr heat input)

and NSPS for Industrial Boilers (>100 x 106 Btu/hr heat input)a

Fuel Type

AP-42b

Uncontrolled

Emission Factors 

lb/106

 Btu

Subpart Db

Boilers Built After

July 9, 1997 lb/106

Btu

Reduction

Requiredc

 to meet

Subpart Db Limits

Percent

Natural Gas 0.17 - 0.27d 0.10 - 0.20e 26 to 41

Residual Oil 0.21 - 0.31d 0.20 5 to 35

Distillate Oil 0.16 0.10 - 0.20e 0 to 38

Coal

 Pulverized

 Stoker

 Fluidized Bed

0.39 to 1.24d

0.30 to 0.44f

0.20 to 0.61 g

0.20

0.20

0.20

49 to 84

33 to 55

0 to 67

Woodh

 Bark/Wet Wood

 Dry Wood

0.22

0.49

none

none

NA

NA

a

 60% reduction from baseline expected for non-EGU boilers subject to SIP Call; b uncontrolled emission factors,

converted using 1,020 Btu/ft3

 gas, 150,000 Btu/gal residual oil, 12,500 Btu/lb coal and 4,500 Btu/lb as-fired

wood; c

 from uncontrolled AP-42 factor; d lower for tangential and higher for wall-fired boilers; e lower factor for

low and higher factor for high heat release rates; f

 spreader, overfeed, and underfeed stokers; g circulating bed and

bubbling bed; h note that wood-fired boilers firing >10% fossil fuel are subject to limits for fossil fuel

Besides boilers firing wood residues or fossil fuels, NOx emissions from kraft pulp mill boilers can

also result from the burning of stripper off-gases (SOGs) containing ammonia. The burning of SOGs

in five power boilers resulted in NH3-to-NOx conversion rates ranging from -11 to 34% with changes

in baseline NOx levels ranging from -0.05 to 0.14 lb/106

 Btu (NCASI 2002b).

2.2 Description of Boiler Types

Steam can be generated in many different types of combustion devices. The vast majority of pulp

and paper mills and wood products plants use conventional boiler technology, where the fuel is

combusted in a furnace chamber and the resulting heat is used to generate steam inside water tubes.

The water tubes are located near the furnace walls and above the furnace. Water tube boilers are

generally used in industrial applications to generate steam at rates of 20,000 lb/hr and greater. There

are approximately 1,300 boilers at U.S. pulp and paper mills (about 2.5 boilers per mill), and most of

these have steam generating capacities of 20,000 lb/hr and greater. Conventional boilers are often

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characterized according to whether they are factory assembled (package) or assembled at the mill

(field-erected). In addition, boilers can be categorized by their fuel burning capability (gas, liquid,

solid), fuel firing mechanism (pulverized coal, cyclone, stoker, mass feed), grate type (vibrating,

stationary, chain) and burner arrangement (tangential, wall-fired). These latter characteristics

influence emission rates of NOx.

Most paper mill boilers are equipped to burn more than one fuel to ensure steam availability and to

provide it at the lowest possible cost. Package boilers frequently are equipped to burn either natural

gas or oil. Boilers built primarily for coal firing often have the capability to burn either gas or oil,

or both. Most of the boilers that burn wood have the capability to co-fire one or more fossil fuels. 

In fact, very few boilers at pulp and paper mills run exclusively on wood residues.

Besides conventional boilers, a few mills use fluidized bed combustors for steam generation.

Fluidized bed units typically burn mixtures of solid fuels (coal, wood, wastewater treatment plant

residuals), although gas or oil may serve as a back-up. The fuels are combusted in a moving bed of

sand or other solid heat transfer media. Water tubes for steam generation are located in the moving

bed and above the bed. These units are increasingly used for solid fuel combustion because of

efficiency and environmental control considerations.

Gas turbines are used at about 25 mills for steam and electricity cogeneration. In these units,

combustion air is compressed before introduction into a combustion chamber with the fuel, which is

almost always natural gas (distillate oil is normally used only as a back-up fuel). Combustion takes

place at very high temperatures, and the energy from the expanding combustion gases is converted to

mechanical energy. About one-half of the energy is used to drive the compressor, and the remainder

is used in the turbine to generate electricity. The hot gases are then passed into a heat recovery steam

generator. The heat content of these gases can be increased to generate additional steam by burning

fuel in duct burners prior to the steam generator.

3.0 REVIEW OF NOX CONTROL TECHNIQUES FOR INDUSTRIAL BOILERS

There are two principal methods of industrial boiler NOx emissions control: combustion modification

and flue gas treatment. Combustion modifications are often associated with improving boiler

performance. Flue gas treatment can occur both within the boiler and at several points along the

path of the flue gas from the boiler to the stack. Other pre-combustion techniques such as fuel

denitrogenation to reduce “fuel NOx” have shown little promise. Biomass fuel gasification could

lead to lower NOx emissions, but this technology is still in the early stages of development.

3.1 Combustion Modifications

Combustion modifications are the most common, commercially available means of controlling NOx

emissions from fossil fuel-fired boilers. These can be brought about either by effecting relatively

simple modifications of operating conditions or by incorporating more elaborate modifications of the

combustion facility. Retrofit applications of NOx controls by combustion modification usually proceed

in several stages. First, fine tuning of combustion conditions by lowering excess air and adjusting

burner settings and air distribution may be attempted. Next, minor modifications such as biased burner

firing or taking burners out of service may be implemented. Finally, if further reductions are desired,

other retrofits such as installation of overfire air ports, flue gas recirculation systems, and/or low-NOx

burners may be employed (USEPA 1992).

Combustion modifications can be divided into five categories: a) low excess air (LEA), b) staged

combustion, c) temperature reduction technologies, d) low NOx burners (LNB), and e) in-furnace

destruction.

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National Council for Air and Stream Improvement

3.1.1 Low Excess Air in the Flame Zone (LEA)

By reducing the amount of excess air, and therefore excess oxygen, in the local flame zone, moderate

reductions in NOx emissions may be possible. Operating the burners with low excess air (<5% for

oil and gas-fired boilers) results in lower NOx emissions (both fuel and thermal NOx) and higher

boiler efficiencies. Unfortunately, low excess air operation has proven to yield only moderate NOx

reductions, if any (Wood 1994). Ten to 20% NOx reduction is believed feasible by LEA for every 1%

reduction in furnace O2 levels (Makanski 1988). However, this technique is limited by the production

of smoke, high CO emissions and possibly other problems within the boiler itself such as increased

fouling and corrosion due to the reducing atmosphere (Jones 1994). LEA is not in widespread use as

an NOx control technique for industrial boilers, but it is used for energy conservation (Jones 1994).

3.1.2 Staged Combustion or Off-Stoichiometric Combustion

Staged combustion or off-stoichiometric combustion is one of the oldest modification techniques

for NOx control. Diverting a portion of the total amount of air required through separate ports,

generally located above the burners, creates a “fuel-rich” zone (also known as air staging). The

fuel-rich conditions result in lower peak temperatures and thus, lower thermal as well as fuel nitrogengenerated NOx. Staged combustion can be accomplished by various in-furnace techniques such as

a) overfire air (OFA), b) burners out of service (BOOS) and c) biased burner firing (BBF) or air/fuel

mixing, each of which is described briefly below. These techniques are generally applicable to larger,

multiple burner combustion devices (Wood 1994).

Overfire Air (OFA)

In OFA, about 10 to 20% of the combustion air flow is directed to separate air ports located

downstream of the burners. OFA works by reducing the excess air in the burner zone, thereby

enhancing the combustion staging effect and reducing NOx emissions. Residual unburned material,

such as CO and unburned carbon, which inevitably escapes the main burner zone, is oxidized as

the overfire air is admixed later. This modification is more attractive in original designs than in

retrofit applications because of cost considerations, including cost of additional ductwork, furnace

penetrations, extra fan capacity, and physical obstructions that make retrofit difficult in some

installations (USEPA 1992). When implemented, 15 to 30% NOx reductions with OFA alone are

expected (Makanski 1988). OFA is a very effective technique for NOx reduction, especially for

tangentially-fired boilers (USEPA 1992), and may be used with all fuels and most combustion

systems, including stoker/grate units (Jones 1994). Operational problems resulting from OFA

can include decreased combustion efficiency and deterioration of final steam conditions.

Burners Out of Service (BOOS)

BOOS is a relatively simple technique used mostly in retrofit situations (suspension-fired coal and

oil/gas-fired boilers) wherein multiple burners exist and fuel flow is blocked to an upper level of

burners, allowing only air to pass through these. To avoid flame stability and vibration problems, the

number of burners taken out of service should not exceed 25% (USEPA 1991). Operational problems

resulting from BOOS can include corrosion and soot/slag formation (USEPA 1991).

Biased Burner Firing

In biased burner firing (BBF), also known as air/fuel mixing or fuel biasing, the furnace is divided

into a lower, fuel-rich zone and an upper fuel-lean zone to complete the burnout. This technique has

been proven only for oil/gas-fired utility boilers (Makanski 1988). A 20% reduction in NOx can be

expected.

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3.1.3 Temperature Reduction Technologies

Several NOx reduction technologies employ some method of reducing peak flame temperatures to

minimize thermal NOx formation. These include a) flue gas recirculation (FGR), b) reduced air

preheat, c) steam and water injection, and d) decreased load.

Flue Gas Recirculation (FGR)

In FGR, a portion of the combustion flue gas is brought into the combustion zone (up to 20% of the

flue gas). This has typically been accomplished using a recirculation fan, but if there is already a

forced-draft (FD) fan installed, some recirculation can be educted in the discharge or the suction of

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

oxygen concentration. Both these effects result in lower thermal NOx. Reported flame temperatures

(gas/oil) are 3,500°F with no recirculation and 2,900°F at 20% FGR. It should be noted that the

onset of thermal NOx occurs around 2,800°F, and NOx generation increases exponentially with

temperatures beyond 2,800°F.

High capital expenditures are necessary to install new ductwork, recirculation fans, devices to mix flue

gas with combustion air, etc. Flue gas is typically taken from a stack breaching at about 300 to 400°F

and mixed with the secondary combustion air (wind box). As only thermal NOx can be controlled by

this technique, it is especially effective only in oil and gas-fired units. In fact, FGR is probably the

most effective and least troublesome system for NOx reduction for gas-fired combustors (Wood 1994).

A 20 to 30% reduction in NOx is expected (Makanski 1988). FGR is most effective when used in

conjunction with air and/or fuel staging (Jones 1994). Once the favored method of industrial-boiler

NOx control, today it has lost some of its favor due to a better understanding of the high capital costs

and FGR fan and operation and maintenance costs involved, in addition to loss of boiler efficiency

(Jones 1994). FGR is more adaptable to new designs than as a retrofit application (USEPA 1992).

Reduced Air Preheat (RAP)

Lowering the amount of combustion air preheat results in a lower primary combustion zone peak

temperature, and thus lower thermal NOx emissions. The energy penalty usually makes this option

unfavorable (Yaverbaum 1979). A rule of thumb is a 1% efficiency loss for each 40°F reduction in

preheat (Wood 1994). As in FGR, RAP only lowers thermal NOx, and thus is economically attractive

for only natural gas and distillate fuel oil combustion (USEPA 1992).

Steam and Water Injection

Flame quenching by the addition of steam or water in the combustion zone is an effective control

technology for oil/gas-fired burners, although a significant energy penalty could ensue. Oil/water

emulsions can realize a similar response as steam/water injection (Jones 1994). Up to 70%

suppression of NOx formation in gas turbines is believed feasible (Makanski 1988).

Decreased Load

A reduction in the percentage of rated capacity leads to lower “volumetric heat release rates” in the

boiler, and correspondingly lower flame temperatures and NOx formation. Wasted load capacity is a

definite disadvantage. Reduced mass flow can also cause improper fuel-air mixing during combustion,

creating carbon monoxide and soot emissions (USEPA 1992).

3.1.4 Low NOx and Ultra Low NOx Burners (LNB & ULNB)

Low NOx burners (LNBs) are designed to mix fuel and air in a controlled pattern that sustains local

fuel-rich regions, keeps the temperatures down, and dissipates heat quickly. By controlling the

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National Council for Air and Stream Improvement

mixing of the fuel and air, the combustion process can be initiated at the burner throat and the zone

of complete combustion can be varied in the furnace chamber, resulting in elongated flames as

compared to short, intense flames. Virtually all of the boiler and burner vendors have developed

LNBs for retrofit (Makanski 1988). Both staged air and staged fuel combustion principles are

employed in LNBs. Combustion modification with LNBs is used in both gas/oil-fired and coal-fired

units. A full LNB retrofit can be expected to reduce NOx levels by about 50% (Makanski 1988). 

Flame containment, specifically sidewall and/or rear-wall flame impingement, is a challenge in the

smaller boilers, particularly in a high-space-heat-release-rate package boiler. While LNBs use staged

fuel to reduce NOx, by contrast, ultra low NOx burners or ULNBs reduce NOx by inducing the

internal circulation of fuel gas within the heater. ULNBs also tend to have large diameters, but

shorter flame lengths and may be easier to retrofit.

Considered a modification of the low NOx burner, slagging combustors involve high temperature

combustion of coal in an air-deficient chamber. Ash is removed as a liquid slag and NOx formation

is suppressed. The gasified coal is then combusted in the existing furnace cavity. Because their

combustion characteristics are similar to those of cyclone-fired coal boilers (coal ash removed as

liquid slag), slagging combustors are thought to be particularly good for retrofitting the latter

(Makanski 1988).

3.1.5 In-Furnace Destruction

Also known as “reburning,” “off-stoichiometric combustion” or “fuel staging”, in this technique from

15 to 25% of the total fuel input is diverted to a second combustion zone downstream of the primary

zone (Makanski 1988). The fuel in the fuel-rich secondary zone acts as a reducing agent, reducing

NO formed in the primary zone to N2. Low nitrogen-containing fuels such as natural gas and distillate

oil are typically used for reburning to minimize further NOx formation. For example, the METHANE

de-NOX reburning process utilizes the injection of natural gas together with recirculated flue gases

(for enhanced mixing) to create an oxygen-rich zone above the combustion grate. Overfire air is then

injected at a higher furnace elevation to burn out the combustibles (Loviska et al. 1998). This process

is claimed to yield between 50 and 70% NOx reduction and be suitable for all solid fuel-fired stoker

boilers (coal, biomass, municipal solid waste, RDF, etc.). However, it has only been demonstrated on

one pulp mill boiler (Rabovitser et al. 2000), one municipal waste combustor (Abbasi et al. 1998) and

one 60 MWe stoker coal-fired unit (Loviska et al. 1998) in the U.S. The Gas Research Institute (GRI),

which developed this process, has plans to apply METHANE de-NOX to several pulp and paper mill

wood-fired stoker units (Schrecengost et al. 2002).

Fuel Lean Gas Reburn (FLGR) is GRI’s technology that offers operators of electric utility boilers a

low cost approach for moderate levels of NOx reduction (about 30% to 50%). Natural gas is injected

into the upper furnace region in small quantities (under 10% of heat input, typically 5-7% of total

heat input). Unlike conventional gas reburning technology, which requires overfire air (OFA) and

15% to 25% of the heat input from natural gas, with FLGR the furnace stays fuel-lean overall and

does not require OFA. Therefore, furnaces that could not utilize conventional reburning due to the

need for OFA and do not require the higher NOx reductions of conventional reburning (over 60% in

some cases), may be able to use FLGR.

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3.2 Flue Gas Treatment

Selective non-catalytic reduction (SNCR) and selective catalytic reduction (SCR), and to a lesser

extent catalytic or non-catalytic oxidation with scrubbing, are among the only proven, viable, fullscale post-combustion flue gas treatment techniques for industrial boilers at the current time. Other

advanced post-combustion treatment options are currently being developed, some awaiting results

of pilot stage results, and others awaiting the enactment of more stringent NOx control requirements

before their full-scale use can be put to test.

3.2.1 Selective Non-Catalytic Reduction (SNCR)

SNCR involves the injection of urea, ammonium hydroxide, anhydrous ammonia, or aqueous

ammonia into the furnace exit region where the flue gas is in the range of 1,600 to 1,900°F

(USEPA 1997). NOx is reduced to N2 and H2O. The primary reaction sequences for SNCR are

shown in Figure 3.1 (ABB 1997). This figure does not show any of the potential side reactions

and undesirable competing reactions which contribute to the complexity of the overall SNCR

reaction mechanism.

Figure 3.1 Primary SNCR Reaction Sequences

One concern about this process is its ability to perform adequately under changing load and fuel

conditions (Jones 1994), although the use of computational fluid dynamics (CFD) modeling and

the design of multiple level injections in the boiler is reported to alleviate some of this concern

(Sun 2002). The Exxon Thermal DeNOx process relies on the injection of ammonia, while Fuel

Tech’s NOxOUT process relies on the injection of urea into the boiler. Both ammonia and urea

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National Council for Air and Stream Improvement

bring about gas phase reduction of NOx to nitrogen. A portion of the NO reduction by SNCR systems,

usually around 5%, is due to transformation of NO to N2O, which is a greenhouse gas (USEPA 1998d).

Thermal DeNOx

The thermal DeNOx process, developed and marketed by Exxon Research and Engineering Company

(Hurst 1983), selectively reduces NOx to molecular nitrogen and water by using ammonia injection

into the air-rich flue gas in the temperature range of 1600 to 2200°F, temperatures typically found in

the upper portions of the furnace (superheater section or before air preheater). The actual chemical

mechanism of the process is quite complex, involving 31 significant chemical reactions (Hurst 1983). 

NOx reductions as high as 60 to 70% have been achieved in some industrial applications. The

reduction efficiency is affected by the NH3 feed rate relative to NOx concentrations, by the degree

of flue gas thermal stratification in the ammonia injection section, and by the flue gas residence time

within the appropriate temperature window.

The reaction predominates around a temperature of 1740°F (USEPA 1981). For temperatures above

2000°F, the injected ammonia is oxidized to NOx, and for temperatures below about 1560°F the

reaction proceeds slowly and the NO reduction falls off drastically, resulting in significant ammonia

slippage (USEPA 1981). The oxidation of ammonia to NO, unreacted ammonia or ammonia slippage

and reduction of NO in NH3-NO mixtures, is discussed further in NCASI Technical Bulletin No. 802

(NCASI 2000).

The ammonia injected must be diluted with air or steam to allow for good mixing. The injection is

usually accomplished by using a multiport injection grid to allow for varying flue gas temperatures due

to boiler load swings. Problems with NH3 injection include ammonia slippage, fouling of air preheater

surface by ammonium sulfate/bisulfate formation, and maintaining optimum reaction temperatures for

the NH3-NO reaction (USEPA 1981).

NOxOUT

Research into the injection of urea (solid or aqueous solution) in a manner similar to ammonia was

first carried out by the Electric Power Research Institute (DePriest, Jarvis, and Cichanowicz 1989). 

Known as the NOxOUT process, it has received increased attention on account of both the reduced

cost and reduced danger of handling urea as compared with ammonia (Sun 2002). Also, it is believed

that urea/water injection parameters can be more easily matched to furnace temperature, providing

better load-following capability and resulting in reduced hardware requirements such as injection grids

(Makanski 1988). The NOxOUT process is based upon the following chemical reaction that ideally

occurs in the temperature range of 1700 to 2000°F (Muzio and Anand 1976), but could be operated at

temperatures from as low as 1,600°F to as high as 2,200°F (Sun 2002). 

2 NO + NH2CONH2 + 1/2 O2  2 N2 + CO2 + 2 H2O 

The problems of ammonia slippage and heat transfer surface fouling with byproduct formation also

exist with the NOxOUT process. 

Six factors directly affect the performance of urea- or NH3-based SNCR systems (USEPA 1997). 

These are a) inlet NOx level, b) temperature, c) mixing, d) residence time, e) reagent-to-NOx ratio,

and f) fuel sulfur content. Lower inlet NOx concentrations reduce the reaction kinetics and hence the

achievable NOx emissions reductions. As mentioned above, temperatures below the desired window

result in ammonia emissions (slip), and temperatures above the desired window result in NH3 being

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oxidized to NOx. Mixing becomes an important consideration in regions distant from an injection

nozzle where the level of turbulence is reduced and stratification of the reagent and flue gas will

probably be a greater problem, especially at low boiler loads (USEPA 1997). Residence time becomes

important to allow the desired reactions to go to completion. Small, packaged, water tube boilers and

boilers with varying steam loads are therefore difficult applications for SNCR (USEPA 1997). As

higher than the theoretical NH3 to NOx ratios are generally required to achieve desired NOx emission

reductions, a trade-off exists between NOx control and the presence of NH3 in the flue gas. The main

disadvantage of SNCR is the low NOx reduction that is experienced when the allowable ammonia slip

is low (as in the Houston area, Southern California and Europe). Finally, in the case of high sulfur

fuels, excess NH3 can react with sulfur trioxide to form ammonium sulfate salt compounds that deposit

on downstream equipment leading to plugging and reduced heat transfer efficiencies.

3.2.2 Selective Catalytic Reduction (SCR)

The SCR process also uses ammonia injection, but the reduction reactions are carried out on the

surface of a catalyst operating at temperatures between 450°F and 750°F. The following overall

reactions are known to occur on the catalytic surface:

 catalyst

4 NH3 + 4 NO + O2  4 N2 + 6 H2O

 catalyst

 8 NH3 + 6 NO2  7 N2 + 12 H2O

The active compound which promotes the NH3-NOx reaction may be composed of a precious metal

(e.g., Pt, Pd), a base metal oxide, or a zeolite (USEPA 1997). Precious metal catalysts are used in

clean fuel applications and at lower temperatures than the base metal oxide or zeolite catalyst. The

most common base metal oxide catalysts are vanadium/titanium based, with V2O5 as the active

material and TiO2 as the support material. The zeolite catalysts are stable over a wider temperature

window than other types of catalysts. Optimum NOx reduction occurs at catalyst bed temperatures

between 600 and 750°F for conventional (vanadium or titanium-based) catalyst types, and between

470 and 510°F for platinum-based catalysts (USEPA 1991). An ammonia to NO ratio of 1:1 has

typically reduced NOx by 80 to 90%, with a leak rate of less than 20 ppm (USEPA 1981). The reactor

is usually located between the boiler and air preheater. NOx control efficiencies are typically in the

range of 70 to 90%, depending on the type of catalyst, amount of NH3 injected, the initial NO level,

and the age of the catalyst.

The performance of an SCR system is also affected by six factors (USEPA 1997). These are a) NOx

level at SCR inlet, b) flue gas temperature, c) NH3-to-NOx ratio, d) fuel sulfur content, e) gas flow rate,

and f) catalyst condition. For SCR, when inlet NOx concentrations fall below 150 ppm, the reduction

efficiencies decrease with decreasing NOx concentrations (USEPA 1997). Each type of catalyst has

an optimum operating temperature range. Temperatures below this range result in ammonia emissions

(slip), and temperatures above the desired range result in NH3 being oxidized to NOx. For up to about

80% NOx reduction efficiencies, a 1:1 NH3:NOx ratio is sufficient. For higher efficiencies, higher

reagent to NOx ratios are required which may result in higher NH3 slip. In the case of high sulfur fuels,

excess NH3 can react with sulfur trioxide to form ammonium sulfate salt compounds that deposit and

foul downstream equipment. SCR application experience in the case of medium-to-high sulfur fuels

is limited. For a given flue gas flow rate, the catalyst structural design should be chosen so that the

residence time needed for the reduction reactions to take place on the catalyst surface is achievable. 

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Catalysts degrade over time due to poisoning, fouling, thermal stress, erosion by particulate, etc. 

NOx removal decreases as the catalyst gets deactivated. Catalysts are a major component of the

cost of SCR.

SCR is considered a high-efficiency removal device. Today, SCR has become a common feature of

new gas-turbine cogeneration and combined cycle systems in the U.S. (Jones 1994). Several utility

boilers have also been equipped with the SCR NOx control technology. By the year 2004, in excess

of 100 GW of coal-fired capacity in the U.S. may be equipped with this technology in order to mitigate

“seasonal” ozone production. As a result, in the 25 years since the first commercial installations in

Japan, SCR technology has evolved in response to changing application conditions, with present day

catalysts featuring thinner walls, improved mass transfer and activity, and better poison resistance

than earlier generation catalysts (Cichanowicz and Muzio 2001).

Major problems with SCR processes include corrosion due to higher flue gas acid dew points, and

formation of solid ammonium sulfate and ammonium bisulfate, particularly in high sulfur oil-fired or

coal-fired boilers. These could deposit on the air preheater surface to reduce heat transfer efficiencies.

Ammonia slippage is also a potential problem. Arsenic poisoning has been demonstrated as a major

contributor to catalyst deactivation, requiring a minimum quantity of available calcium in the fly ash

(which could be obtained by injecting or adding limestone or lime to coals) (Cichanowicz and Muzio

2001). Because of poisoning by trace metals or erosion by fly ash, catalysts lose activity over time. 

Although a proven technology for larger units (>20 MW), it is not in widespread use for smaller

industrial boilers, primarily due to cost considerations. Catalyst regeneration rather than replacement,

better reactor design and layout to promote contacting of reagent and flue gas, etc. may eventually

improve performance at lower cost for industrial boilers.

3.2.3 Scrubbing After Catalytic Oxidation or Ozone Injection

Unlike NO, which is neutral, NO2 can be scrubbed with caustic solutions. Several vendors have

proprietary technologies for the catalytic oxidation of NO in scrubbing systems. Catalytic scrubbing

is generally considered economical only if a caustic scrubber already exists. A scrubber with a long

residence time and multiple scrubbing stages, such as a packed bed, is the main consideration in

increasing efficiencies in most catalytic scrubbing processes (Bradford, Grover, and Paul 2002).

An alternative approach to catalytic scrubbing is the injection of ozone into the flue gas upstream of

the scrubber. Ozone injection is said to achieve up to a 95% NO reduction, because ozone reportedly

converts both the NO and NO2 to N2O5, which is more soluble in caustic solution than NO or NO2.

Important design considerations for ozone injection include a) a large oxygen requirement since a

10% ozone stream is generated from oxygen using an electric arc, b) a low temperature (below

300°F) to prevent the ozone from decomposing, and c) a long enough residence time to allow the

reaction to go to completion (Bradford, Grover, and Paul 2002). Cost considerations for the ozone

generating equipment have been a major hindrance in the past. 

4.0 NOX CONTROL TECHNOLOGIES TYPICALLY APPLICABLE TO FPI BOILERS

This section discusses the various types of conventional fossil fuel and wood-fired boilers, turbines

and fluidized bed combustion units operating in the FPI, the fuels fired in these units, and the type of

NOx control technologies generally considered applicable.

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4.1 Conventional Boilers Firing Fossil Fuels, Wood, or Both

4.1.1 Natural Gas

Natural gas contains a high percentage (generally >85%) of methane and varying amounts of ethane,

propane, butane, and inerts (typically N2, CO2, and helium). Natural gas is burned in package boilers

(these units generally have heat input capacities under 100 x 106

 Btu/hr) or in field-erected boilers

(mainly over 100 x 106

 Btu/hr). Field-erected boilers may be wall-fired (multiple burners on a wall)

or tangential-fired (rows of fuel and air nozzles in each of the four corners).

The principal mechanism of NOx formation in natural gas combustion is by the “thermal” NOx

mechanism (thermal fixation of atmospheric nitrogen). NOx emissions are dependent on the

combustion temperature and the rate of cooling of the combustion products.

Several combustion modification techniques are available to reduce the amount of NOx formed in

natural gas-fired boilers and turbines. The two most prevalent ones are flue gas recirculation (FGR)

and low-NOx burners (LNB). FGR reduces formation of thermal NOx by reducing peak temperatures

and limiting availability of oxygen. LNB reduces formation of thermal NOx by delayed combustion

(staging), resulting in a cooler flame. In conjunction with FGR, the burners can achieve NOx

emission reductions of 60-90%. Other techniques include staged combustion and gas reburning.

In general, these techniques have been incorporated in newer boilers; thus their NOx emissions are

lower than those of older units. There are also many add-on control technologies to reduce NOx

emissions such as selective non-catalytic reduction (SNCR) and selective catalytic reduction (SCR),

although these are not commonly used because of cost considerations. The addition of NOx control

systems such as low-NOx burners and flue gas recirculation may reduce combustion efficiencies and

result in higher CO emissions (USEPA 1998c).

4.1.2 Fuel Oil

Two major types of oil are burned by combustion sources in the FPI: distillate and residual. 

Distillate oil is a relatively clean burning fuel that has negligible nitrogen. The heavier residual

oils contain significantly higher levels of nitrogen. As for natural gas, distillate or residual oils

are burned in either package boilers (generally having heat inputs less than 100 x 106

 Btu/hr) or in

field-erected boilers (heat inputs over 100 x 106

 Btu/hr). Field-erected boilers may be normal-fired

(wall) or tangential-fired.

NOx emissions from fuel-oil combustion depend on the grade and composition of the fuel oil, the

type and size of the boiler, and the firing practices used. NOx emissions from burning distillate

oil are similar to those from natural gas. Many paper mill boilers that mainly burn natural gas

can also burn distillate oil during cold weather gas supply curtailments.

NOx emissions are formed from the nitrogen in the residual oil (“fuel” NOx) and from high

temperature oxidation of nitrogen in the combustion air (“thermal” NOx). “Fuel” NOx can account

for 60 to 80% of the total NOx formation, although the nitrogen levels in residual oil can vary from

0.1 to almost 1% and the percent conversion of fuel N to NOx can range from 20 to 90%. NOx

emissions from tangentially-fired units are, on average, lower than those from horizontally opposed

wall-fired units.

For fuel oil-fired boilers, NOx emissions can be controlled by fuel substitution/alteration, combustion

modification, and post-combustion control. Fuel substitution reduces NOx by burning an oil with

lower N content. For boilers burning residual oil, fuel NOx is the dominant mechanism for NOx

formation, and thus the most common combustion modification technique is to suppress combustion

air levels below the theoretical amount required for complete combustion. Several combustion

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National Council for Air and Stream Improvement

modification techniques are available to reduce the amount of NOx formed in fuel oil-fired boilers,

including low excess air, burners out of service, biased-burner firing, flue gas recirculation, overfire

air, and low-NOx burners. NOx reductions from 5-60% may be expected from these techniques. 

Post-combustion controls include SNCR and SCR. NOx reductions from 25-40% and from 75-85%

may be expected from use of SNCR and SCR systems on oil-fired boilers, respectively (Pakrasi

2000), although as shown later, the cost-effectiveness for these add-on controls could well exceed

the threshold of $2,000/ton NOx removed advocated by EPA.

4.1.3 Coal

Bituminous and subbituminous coals are the main types of coal burned in paper industry boilers. 

No use of lignite or anthracite coal is known at the present time. Boiler types include pulverized

coal, stoker, cyclone, fluidized bed, and mass feed units. The 2000 NCASI survey of pulp and paper

industry boilers showed there were 105 pulverized coal, 67 spreader stoker, eight cyclone, eight

fluidized bed, and 11 underfeed stoker coal-fired boilers operating during that year. Over half of

these units were also capable of burning wood fuels and/or wastewater treatment plant residuals

(NCASI 2002a).

Pulverized coal-fired boilers can be wall-fired (single or multiple burners on one or opposing walls)

or tangential-fired (burners and air nozzles mounted in the corners of the furnace). In cyclone

boilers, the coal is fed tangentially, with primary air, into a horizontal cylindrical furnace. There are

two main types of stokers. The underfeed stoker is either a horizontal-feed, side ash-discharge type

or a gravity-feed, rear ash-discharge type. The spreader stoker uses mechanical or pneumatic feeders

to distribute coal uniformly over the surface of a moving grate. Fluidized bed combustors (FBCs)

can be atmospheric or pressurized. The atmospheric FBC can be of the bubbling bed design or the

circulating bed design (USEPA 1998a).

NOx emissions from coal combustion are considerably higher than those from gas or oil. NOx

formation results from thermal and fuel mechanisms. Fuel nitrogen can account for up to 80% of

the total NOx formed. Coal nitrogen contents range from 0.5 to 2% (USEPA 1998a). Emissions

of NOx are highest for cyclone boilers, followed by pulverized coal, stokers, and mass feed units.

Just as in fuel oil combustion, NOx emissions can be controlled by fuel substitution/alteration,

combustion modification and post-combustion control. NOx reductions can be achieved by burning a

coal with lower N content. NOx emissions from coal-fired boilers can be controlled by combustion

controls and post-combustion controls. Combustion controls involve a) reducing peak temperatures

in the combustion zone, b) reducing gas residence time in the high-temperature zone, and c) air or

fuel staging by operating at an off-stoichiometric ratio by using a rich fuel-air ratio in the primary

flame zone and lower overall excess air conditions (Pakrasi 2000). The use of combustion controls

depends on the type of boiler and the method of coal firing. Low-NOx burners and overfire air

(OFA) have been successfully applied to tangential- and wall-fired units, whereas reburning is the

only current option for cyclone boilers. For large coal-fired boilers, the most developed and widely

applied post-combustion NOx control technology is SCR. Catalyst deactivation and residual NH3

slip are the two key operating considerations in an SCR system (Pakrasi 2000). The use of SNCR

systems on coal-fired boilers is still in the development stage. NOx reductions from 30-70%

and from 60-90% may be expected from use of SNCR and SCR systems on coal-fired boilers,

respectively (Pakrasi 2000). The shortcomings of installing SCR systems on industrial coal-fired

boilers are discussed later.

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National Council for Air and Stream Improvement

4.1.4 Wood Residues

A majority of chemical wood pulp mills that debark logs on site burn the bark and other wood

residues in boilers to generate steam and power. Although smaller boiler types such as the Dutch

oven and fuel cell oven are sometimes utilized, the majority of boilers with steam generation rates

exceeding 100,000 lb/hr are of the spreader stoker type. At pulp and paper mills in 2000, there were

9 Dutch ovens, 13 fluidized bed boilers, 38 pulverized coal-fired boilers, 1 gasifier and 141 spreader

stokers that burned wood fuels (NCASI 2002a). Of the 202 boilers firing wood residues, 72 could

co-fire coal, 93 could co-fire residual oil, 25 could co-fire distillate oil, 111 boilers co-fired natural

gas, 76 burned waste treatment system residuals, and 25 burned tire-derived fuel. The wood products

industry burns several types of wood residues including bark, sawdust, planer shavings, sander dust,

and trim from lumber cutting and plywood manufacture in a variety of boilers including stokers, fuel

cells, Dutch ovens, and suspension burners.

Using a 65 kW refractory-walled reactor to study biomass combustion under conditions typical

of the suspension burning phase in a spreader-stoker-fired boiler, Winter et al. (1989) showed that

wood-fired boiler NOx emissions were strongly dependent on combustion zone oxygen concentration

and the nitrogen content of the biomass fuel. However, these emissions were relatively insensitive

to both temperature and moisture content. In other words, NOx emissions from wood residue

combustion are mainly the result of “fuel NOx.” This is consistent with the observation that “thermal

NOx,” or NOx generated by the thermal fixation of atmospheric nitrogen, usually sets in only at

temperatures exceeding about 2,800°F, and wood combustion in boilers seldom reaches such high

temperatures. The dependence of NOx emissions on excess air levels was confirmed by Philo,

Chapman, and Mirolli (1989) who conducted parametric tests on a 550,000 lb steam/hr wood-fired

stoker unit varying the level of excess air. They found that the NOx emissions increased from

85 to 170 ppm when the flue gas O2 content rose from 1.9 to 6.4%.

No systematic study has been conducted to examine the relationship between wood nitrogen content

and emissions of NOx, although NCASI has begun a study to look at this relationship (NCASI 2003).

Wood and bark nitrogen contents typically range from 0.1 to 0.2% (dry basis), lower than most coals

and residual fuel oils. Thus, average NOx emissions from wood combustion in typical pulp mill

boilers would be expected to be lower than those from coal or residual oil combustion, but slightly

higher than those from natural gas combustion. However, if the wood fuel burned contains nitrogen

from other sources (e.g., sander dust from wood products operations using urea formaldehyde resins),

higher NOx emissions can be expected. Also, certain types of wood residues (e.g., juvenile woods)

are known to contain somewhat higher levels of nitrogen (0.2 to 0.4% range).

Common combustion modification techniques used to control fuel NOx by suppressing combustion

air levels to below the theoretical amount required for complete combustion have not been

demonstrated in full-scale wood-fired boilers. Overfire air ports are claimed to lower NOx emissions

from wood-fired stoker and fluidized bed combustion units (USEPA 2001), although evidence that

such installations exist is lacking. Tests conducted by Philo, Chapman, and Mirolli (1989) on a

tangential wood-fired boiler (550 KPPH) with 0 and 20% OFA at a constant 30-35% excess air

and over boiler loads ranging from 55 to 100% of rated capacity, showed NOx emissions actually

increased (from 20 to 30%) with the 20% OFA operation at all three boiler loads evaluated. The

authors stated, however, that this phenomenon was likely unit-specific, and that increasing OFA

mass flow should typically lead to reduced NOx emissions as in situations with fossil fuel firing.

Certain biomass fuels such as sander dust from operations using urea formaldehyde (UF) resins or

agricultural waste such as rice husks and wheat straw can contain high nitrogen levels ranging from

0.5 to 2.5% by weight. When combusted, these can lead to high levels of NOx. Webster and

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National Council for Air and Stream Improvement

Drennan (2003) discuss their experience with using air staging in reducing NOx emissions by over

50% when burning sander dust fuels in two boilers, one a “packaged” boiler at a medium density

fiberboard plant, and the second a bark grate boiler with sander dust suspension-fired over the grate. 

A Dual Air Zone (DAZ) gas burner with an annular scroll to introduce the sander dust with substoichiometric air flow through the burner was used in both cases. In the packaged boiler, a separate

system of adjustable direction air ports in the boiler front wall was used to introduce the secondary

combustion air, and NOx emissions were reduced by 43 to 51%. Tests in the bark grate boiler were

reportedly under way. This boiler was to be equipped with overfire air ports above the suspensionfired sander dust burners, and computational fluid dynamics modeling techniques were to be used

to bring about an NOx reduction of over 70% compared to unstaged combustion of the sander dust.

Gas reburning techniques have been demonstrated for a short duration in one wood-fired stoker

boiler that also burned small amounts of waste treatment plant residuals, with NOx reductions of

40 to 50% from baseline (untuned boiler) reported (Schrecengost et al. 2002). However, this reburn

technology would require a 5 to 25% natural gas input. Other combustion modification techniques

such as FGR would not be effective in wood combustion since FGR reduces formation of thermal

NOx by reducing peak temperatures, and most of the NOx generated during wood combustion is

from the “fuel NOx” pathway. FGR may also reduce the availability of O2 in the combustion zone,

but the impact of this on NOx generation during wood combustion has not been demonstrated.

As for fossil fuels, post-combustion control options for wood-fired boilers include SNCR and SCR. 

Other emerging technologies (see Section 6.0) such as catalytic or low temperature oxidation

followed by scrubbing have not been applied on a full scale to FPI boilers at the present time.

SNCR has been applied to several base-loaded wood and combination wood-fired boilers

(www.fueltechnv.com). However, its efficacy on stoker wood-fired boilers, especially with changing

loads, has not been adequately demonstrated, except when used as a polishing step. Early use of

ammonia injection in the case of one pulp mill wood-fired boiler met with significant problems and

had to be abandoned (Abrams 1998). While the manufacturer had guaranteed an NOx emission rate

of 0.042 lb/106

 Btu, the boiler was unable to meet this guarantee unless operated at less than half

load. Even then, reducing NOx to near permitted limits consumed considerably more ammonia than

anticipated, leading to the formation of a visible ammonium chloride plume. A similar problem was

encountered at a second FPI mill. The fluidized bed combustor at the mill fired various fuels (bark,

gas, recycled paperboard, and sawdust, ≈300 x 106

 Btu/hr), and was equipped with a urea injection

system (SNCR), which reduced NOx emissions under varying loads from about 250 lb/hr (uncontrolled)

to between 25 and 40 lb/hr (84 to 90% removal) (NCASI File Information). However, a single

measurement in the stack showed nearly 75 lb/hr of ammonia were being emitted, suggesting that

nearly half the urea (on a molar basis) injected was being emitted as ammonia in order to bring

about this level of NOx reduction. 

The use of SNCR technology on most base-loaded wood-fired boilers could be considered a proven

technology, although the suitability of the unique fuel mix, boiler design, and boiler operation

(including ductwork, flue gas temperature profiles and desired residence times, flue gas chemistry,

etc.) inherent in each boiler should be evaluated on a case-by-case basis. Typical maximum levels

of NOx emissions control achievable are in the range of 30 to 60%. The use of SNCR on stoker type

wood-fired boilers that have significant load swings has not been demonstrated. Excessive ammonia

slip (ammonia is an air toxic in many states) is a primary concern when adequate dispersion of the

SNCR chemical is not achieved in the boiler ductwork within the range of residence times available

and temperatures needed for the NOx reduction reactions to go to completion. Also, when dry

particulate matter (PM) emission control is utilized (such as an ESP), problems with plume opacity

from ammonium chloride in the stack gases could arise, especially for combination boilers. For

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16 Special Report No. 03-04

National Council for Air and Stream Improvement

boilers which produce high levels of SO2/SO3 (combination wood-fired boilers), problems associated

with ammonium sulfate/bisulfate deposition on heat transfer surfaces could also arise.

The impact of interference from higher CO levels present in many wood-fired boilers (compared

to fossil fuel-fired boilers) with the SNCR chemical is currently unknown. Also, the possibility

of appreciable SNCR chemical being absorbed on to the ash matrix in a wood-fired boiler should

be examined. The extent and fate of ammonia in precipitated ash from boilers with dry PM control

or scrubber purge streams for boilers with wet PM control also need to be adequately investigated.

The use of SCR on wood-fired boilers in the forest products industry has not been demonstrated. 

The use of SCR technology on wood- or combination wood-fired boilers would be considered

technically infeasible based upon the fact that post-particulate removal flue gas temperatures are

typically significantly lower than those desired for this application (450 to 750°F). Many woodand combination wood-fired boilers are equipped with wet scrubbers for particulate emission (PM)

control. Reheating the scrubbed flue gases from these boilers (typical temperatures from 150 to

220°F) to bring them within the desired temperature window would involve a significant energy

penalty. For pre-particulate removal flue gas application, catalyst deactivation from high particulate

loading would be a serious concern, in addition to the impact of fluctuating loads on flue gas

temperatures. Deactivation and/or poisoning could result from the size and density of fly ash

particulate, and from their unique chemical and physical nature. Water soluble alkali (such as

Mg, Na) in particulate-laden gas streams have been known to poison SCR catalysts (USEPA 1999). 

Space considerations for installing a catalyst section in an existing boiler’s ductwork are also

important.

In response to a request for information from a consultant and one of their FPI clients, Fuel Tech

N. V. (www.fueltechnv.com) reviewed the possibility of applying SCR to a certain circulating

fluidized bed combination wood-fired boiler (T. Brown, personal communication, June 26, 2002). 

They found that the only “wood-fired” boiler SCR application in service in the U.S. was located at a

woodworking facility in Archbold, Ohio. Fuel Tech contacted this facility (Sauder Corporation) to

learn more about their process and the design of the SCR system. Although specific discussions on

the fuel makeup were not held, it was assumed the wood fuel was sawdust and relatively high quality

wood scraps from the furniture-making process. It was learned this SCR was located downstream of

a mechanical collector and electrostatic precipitator, operating in flue gas temperatures ranging from

550°F to 650°F. The only problem reported at this installation was minor catalyst blinding due to the

deposition of fine particulate that escaped the PM collection devices. It was learned the operating

temperature for this SCR system allowed the use of conventional catalysts designed to accommodate

high dust applications. For these catalysts, the catalyst openings through which the flue gas flows

are sized to provide proper surface area contact and sufficient flue gas velocity to minimize fouling. 

Low temperature catalyst designs are considerably different and would not be recommended for use

on any high dust application.

Based on this description of the air pollution control system configuration and the operating

conditions for this particular wood-fired boiler, it is important to identify several specific differences

between this installation and those that operate in the FPI. First, due to the requirement to provide

hot air to burn all but the driest of wood fuels, wood-fired boilers are usually equipped with air

preheaters (Stultz and Kitto 1992). Thus, even when dry particulate control devices like an ESP

are utilized, the flue gas exits such control devices at temperatures in the 350°F to 450°F range. 

Consequently, the installation of an SCR catalyst section after an ESP to treat gases in the range

of 550°F and 650°F is not amenable for adaptation to such boilers without, of course, incurring a

severe energy penalty. Second, a significant portion of the FPI’s wood-fired boilers are controlled

for PM emissions by multiclones and wet scrubbers. The PM emissions from these would therefore

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National Council for Air and Stream Improvement

be higher than the Sauder situation. Third, it is unclear how the Sauder SCR system would have

worked under a fluctuating boiler load characteristic of many FPI boilers. Finally, sawdust fired in

the Sauder boiler is a low moisture fuel, and the particulate matter present in the flue gases from

its combustion is likely to be of different composition than when bark or hog fuel (typically much

higher moisture) is burned.

In conclusion, the use of SCR technology has clearly not been demonstrated for industrial wood,

biomass or combination fuel-fired boilers in the forest products industry, and the issues pertaining

to severe energy penalties and space and logistical limitations, and potential catalyst poisoning

from soluble alkali metals need to be addressed. The feasibility of achieving high levels of NOx

removal (such as >60%) using SNCR technologies on wood-fired boilers is uncertain due to several

limitations, including the key one of installing optimally placed injection points for the SNCR

chemical in swinging load situations and dealing with potentially excessive NH3 slip and plume

opacity problems. Combustion modifications (with perhaps the exception of gas reburning where

gas is available) are generally not effective for biomass-fired boilers since most of the NOx is

generated by the fuel NOx pathway. Emerging post-combustion technologies and in-furnace

technologies such as gas reburning are in the early stages of demonstration.

4.1.5 Combination Wood-Fossil Fuel

As previously mentioned, nearly 40% of the wood-fired boilers in the pulp and paper industry

are capable of firing coal. The Electric Power Research Institute (EPRI), with co-funding from

the Department of Energy (DOE), and with utility cooperation and cost sharing, tested co-firing

of biomass in ten coal-fired utility boilers (Hughes 1998). NOx emissions recorded at three of these

boilers are summarized in Table 4.1. The biofuels fired included sawdust, dry shavings, and wood

chips. Typically, the trend observed was lower NOx emissions with increased levels of biomass

co-firing, at least up to the point where about 10% of the heat was supplied by the biomass. The

recorded range of NOx reductions was typically between 0 and 15-20%. The authors conclude

NOx reductions can be the result of several factors, including reduced total fuel nitrogen, lower firing

temperatures because of increased fuel moisture, and increased staging of the combustion process

due to early volatiles burnout in the biomass fraction. Preliminary results show that the co-firing

of up to 7% biomass, on a heat-input basis, with crushed or pulverized coal can lower NOx emissions

by as much as 15% depending on the firing configuration. These tests did not explore optimizing

the firing configuration for biomass to maximize the NOx control potential for this renewable fuel. 

Some tests did not show any NOx reduction at all.

In an attempt to explain the outcomes of co-firing biomass in pulverized coal boilers, particularly

the potential for simultaneous reduction of NOx, Tillman (2003) looked into the differences in

combustion characteristics between various biomass fuels and coals using a drop tube reactor (DTR).

An analysis of the NOx reduction data obtained from several EPRI demonstrations of the co-firing

of biomass with coal showed that one could expect slightly above 1% NOx reduction from baseline

levels for every 1% co-firing percentage of biomass (Btu basis). The DTR laboratory results with

sawdust, urban wood waste, fresh switchgrass, and weathered switchgrass for biomass fuels and two

reference coals led to the following conclusions: a) fuel reactivity is a key to NOx control using

staged combustion; b) biomass fuels, in general, are highly reactive, although weathering reduces

nitrogen reactivity in switchgrass; c) the relative reactivity of biomass and various coals can be used

as a technique to evaluate potential in NOx management; and d) the DTR technique for analyzing

fuels has significant benefits in evaluating initial combustion processes applied to NOx management.

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Table 4.1 NOx Emissions Results with Wood Waste Co-Firing with Coal (Hughes 1998)

Site Biofuel

Baseline NOx

lb/MMBtu

Percent Co-Fire

(mass basis)

Percent Co-Fire

(heat basis)

NOx

Reductions

(percent)

GPU Seward Wood

(FGS, DSS

and OS)a

0.87 to 0.95 3.4 to 6.4

8.2 to 9.4

11.9 to 13.8

16.1 to 17.9

1.5 to 2.8

3.1 to 4.3

4.3 to 8.1

7.6 to 10.3

0 to 11

2.3 to 13

3.4 to 14

5.7 to 18

TVA Allen Wood

(sawdust)

2.0

with E. Coal

8.5 to 10

20

4.5

9.0

0 to 11.6

25

TVA Allen Wood

(sawdust &

woodchips)

1.5

with W. Coal

4.3

10

15

1.9

4.7

6.9

-1.3 to 7.3

-8.7 to 14

-2.7

NIPSCO

Mich. City

Wood 1.05 to 1.28

(1.17 avg)

10 6.5 0 to 20

(9.5 avg)

a

 FGS = Fresh Green Sawdust; DSS = Dry Shavings and Sawdust; OS = Old Sawdust

4.2 Gas Turbines

There are a variety of combustion modification techniques and add-on control technologies to

reduce NOx emissions from combustion turbines (CT). These include a) wet controls, b) dry low

NOx (DLN) combustion controls, c) catalytic combustors, and d) selective catalytic reduction (SCR).

Wet controls involve injecting water or steam into the flame of a CT to provide a sink that limits

thermal NOx. Suppression of NOx formation from 70 to 90% is believed feasible (USEPA 1996). 

Combustion controls consist of either the Lean Combustion or Lean Premixed System, which have

been deployed on new CT units in recent years (USEPA 1996). These systems are generally used as

alternatives to wet systems. One of the difficulties with lean premixed systems is maintaining flame

stability in the narrow flame temperature range between high NOx production and lean flame

extinction (Peltier 2003). Catalytic combustion promises to be an alternative for DLN technologies. 

Catalytic combustors burn lean fuel-air mixtures to achieve sub-5 ppm NOx. The maximum

combustor exit temperature is 2,460°F or lower, which is well below the NOx formation temperature

(Peltier 2003). SCR can be applied to CTs in a manner similar to that for steam boilers. Distillate

oil is occasionally used in place of natural gas in gas turbines.

4.3 Fluidized Bed Combustors

Pulp mill boilers capable of firing coal or wood often have the option to burn other solid fuels such

as tire chips, wastewater treatment plant residuals (sludge), rejected material from processing of

old corrugated containers (OCC rejects), non-recyclable paper pellets, etc. The amount of these

materials that can be burned in traditional spreader-stoker type boilers is relatively small, and

co-firing them with wood and/or coal has only minimal effects on the emissions. Fluidized bed

boilers, on the other hand, can accommodate much larger percentages of alternative solid fuels. In

general, coal-fired fluidized bed combustors (FBCs) are capable of achieving relatively low levels

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National Council for Air and Stream Improvement

of NOx, SO2, CO, and particulates (Makanski 1991). The combustor operating temperatures are very

low, in the 1500° to 1600°F range, thus limiting the formation of NOx. Nearly all circulating fluid

bed (CFB) designs employ staging to minimize NOx emissions. Post-combustion NOx control using

the SCR or SNCR technologies is feasible, but SCR in particular has only been demonstrated on

large utility FBCs. 

One southeastern kraft pulp mill operates a bubbling fluidized bed boiler (BFB) equipped with an

SNCR system. This 820 MMBtu/hr BFB burns various combinations of wood, waste treatment

plant residuals, and tire-derived fuel and uses the NOxOUT process to reduce NOx levels by about

40% from a baseline level of about 0.35 lb/106

 Btu (NCASI file information). The NOxOUT process

was originally designed to reduce NOx emissions by about 62%. A second southeastern mill operates

a CFB boiler that burns coal, wood residue, non-recyclable and pulper rejects, and some synfuel gas

(175 MMBtu/hr) in varying blends and has been equipped with a urea-based SNCR system since

1996. The SNCR system is designed to achieve a 50% NOx reduction. However, the boiler is able

to achieve its permit limit of 0.3 lb/MMBtu without the use of SNCR. The removal efficiency has

never been guaranteed since the fuel blend varies all the time. A third (northwestern) pulp mill also

operates a CFB boiler (165 MMBtu/hr) that burns wood residues, waste treatment plant (WTP)

residuals and some gas, and since 1996 has also been equipped with an SNCR system designed to

reduce NOx by up to 60%. The WTP residuals at this mill contain high levels of nitrogen, resulting

in higher levels of NOx (uncontrolled) compared to wood alone.

Leckner and Karlsson (1993) studied emissions of NO, N2O, SO2 and CO from fluidized bed

combustion of mixtures of wood and coal in a 12 MW research circulating fluidized bed (CFB)

boiler. Bituminous coal (1.5% N) was co-fired with sawdust (0.10% N) or fir chips (0.15% N) in

amounts ranging from 0 to 100% coal. In spite of the much lower N content, 100% wood firing

led to higher NO emissions than did 100% coal firing. Reduction of NO by char in the bed and ten

times higher char concentrations in the bed during 100% coal burning compared to 100% wood

burning were believed to explain this difference. Small additions of coal to wood initially yielded

a higher NO emission than even 100% wood. The authors explained that at low coal contents,

since the amount of char in the bed was small, the reduction of NO formed during coal burning by

char was small and higher fractions of the coal N were converting to NO. NO reduction by char from

coal burning increased with higher levels of coal burning, leading ultimately to lower NO emissions

from 100% coal burning than from 100% wood burning. Emissions of N2O were primarily from coal

burning (negligible from wood burning).

One emission from circulating and bubbling bed combustors burning coal that could potentially be

of concern is the greenhouse gas nitrous oxide (N2O). In CFB combustors, the N2O levels could be

as much as 70% of the corresponding NOx (NO+NO2) levels (IPCC 1997). The formation of N2O

depends on the combustion temperature, with the highest N2O emissions occurring at a temperature

of about 1,000°K (1,340°F). For combustion temperatures below 800°K or above 1,200°K, the N2O

emissions are negligible (IPCC 1997). In pulverized coal and stoker-fired boilers, higher flame and

post-flame temperatures in the presence of gas phase radicals preclude the formation of N2O

(Makanski 1991).

5.0 TECHNOLOGICAL ADVANCES IN NOX CONTROL FOR BOILERS

This section provides brief summaries of recent reports and reviews published in the literature

on the current state of the art for NOx emissions control, especially as applied to industrial boilers. 

Although much of the information pertains to utility boilers, some of it can be useful in understanding

NOx emissions control from industrial boilers.

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5.1 Swanekamp (2002a)

In a special report titled Emissions-Control Technologies Continue to Clear the Air, Swanekamp

described advances in combustion and post-combustion technologies that reduced stack emissions

from utility boilers and gas turbines. He made the following observations relevant to NOx emissions

control:

• Combustion modification is generally the lowest-cost option for NOx control.

 At one utility, the John Zink Co. applied its COOLflow modeling technology to

design baffles and turning vanes in the windbox and ductwork systems to correct

air flow distribution problems; this in turn optimized combustion and also enabled

existing (unused) OFA ports to be returned to service, resulting in a 22% reduction

in NOx emissions.

 The Rotating Opposed Fire Air (ROFA) system by Mobotec USA improved

combustion by creating upper-boiler turbulence with high-velocity air injection

through asymmetrically located nozzles in the boiler walls. The system was

expected to reduce NOx emissions at two utilities by 50 to 75% using no

chemicals or catalysts.

• LNB with OFA is the most popular combustion modification and is capable of achieving

NOx reductions of up to 70% with gas and oil fuels.

• Sophisticated software known as a “process-optimization package” uses techniques like

neural networks, Bayesian analysis, and internal heuristics to monitor critical process

parameters, determine optimum setpoints and communicate them to control devices, and

continuously reconfigure the control system based upon the software models. The software

is used by many fossil-fueled utilities to limit NOx emissions. The use resulted in a 20%

reduction in NOx at one utility.

• There are limitations to combustion modifications such as LNBs and optimization software.

 LNBs are best applied to wall-fired units, not cyclones.

 LNBs can cause performance problems, such as carbon loss and tube-wall wastage.

 Most importantly, even in “layered” applications, they cannot meet levels dictated

by the NOx SIP Call.

• SCR is the only commercially viable alternative for high levels of NOx reduction.

• Ammonia slip requirements are getting stricter in many states – typically 5 ppm in

California; 2 ppm in Massachusetts; some NE states are pushing for “zero” slip.

5.2 Swanekamp (2002b)

In a brief excerpt titled “Connectiv plant cuts NOx emissions without SCR,” Swanekamp described

RJM Corporation’s “layered approach” to achieve 90% NOx emissions reduction without an SCR at

60% of the cost of an SCR retrofit as applied to a 480 MW coal/oil-fired boiler in Beesley’s Point,

New Jersey. The first four layers included:

• burner modifications

• installation of overfire air ports

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National Council for Air and Stream Improvement

• NOx tempering, which injects micronized water droplets into high-NOx production zones,

and

• SNCR, which injects a urea-based reagent into the lean-fuel zone above the furnace.

The fifth layer, dubbed “absolute compliance” or “RJM-AC,” involved injection of an amine

reagent in the primary combustion zone. RJM Corporation also described a “combustion tempering”

technique applied to a natural gas-fired cyclone boiler, “burner optimizations” applied to three

coal-fired front-fired utility boilers rated at 50MW each, and a rich reagent (amine-based) injection

system followed by OFA applied to a 138 MW cyclone coal-fired boiler, all three in conjunction

with SNCR systems, to achieve nearly 60%, over 70% and nearly 80% NOx reduction, respectively

(http://www.rjm.com/html/techinfo.htm).

5.3 Swanekamp and Ellison (2001)

The use of ammonia- or urea-based additive treatments in de-NOx processes, either upstream or

downstream of the boiler economizer, presented substantial problems. Technological advances

to address these problems, including supplemental additive treatment techniques, were discussed

in two conferences and summarized by Swanekamp and Ellison.

• Lime addition in a furnace can negate high SO3 concentrations and lead to sludge

buildup in the air preheater.

• Lime addition can also tie up catalyst poisoning arsenic in coal.

• Additives can counteract high lime content in some PRB coals, which can foul SCR

catalysts.

• Replacing tubular air heaters with Ljungstrom-type helps catalyst plugging problems.

• Replacing soot blowers by on-line acoustic horns produces favorable results.

Additionally, the authors reported other technological advances including the following:

• a Fuel Lean Gas Reburn (FLGR) system (that used natural gas injection to replace

3-10% of heat input from coal) which can be integrated with SNCR

• a conversion system of urea, a stable non-volatile material that is safer to transport, store, and

handle, to a gaseous mixture of ammonia on-site as and when needed for use in SCR systems.

5.4 NESCAUM (2001)

In a 2001 report entitled Power Companies’ Efforts to Comply with the NOx SIP Call and Section

126, Progress Report” the Northeast States for Coordinated Air Use Management (NESCAUM)

made the following key points relative to NOx control:

• The NOx SIP Call region’s total SCR commitment was at least 115 units, representing

over 66,000 MWs of capacity.

• 0.15 lb/MMBtu represented an 85% reduction from uncontrolled NOx for most large

coal-fired power plants; hence, SCR was the most suitable candidate for NOx control.

• Other emerging technologies in the mix included:

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National Council for Air and Stream Improvement

 a combustion technology called ThermaloNOx that had been applied at American

Electric Power’s 375 MW Conesville facility (expected to achieve 80 to 90%

NOx reduction)

 a combustion improvement technology called Rotating Overfire Air used at

Carolina Power & Light’s Cape Fear facility, and

 a reburn technology supplied by General Electric to the Southern Company’s

Scherer plant (50 to 70% reduction expected).

5.5 NESCAUM (2000)

In a 2000 report entitled Status Report on NOx Control for Gas Turbines, Cement Kilns, Industrial

Boilers, Internal Combustion Engines – Technologies & Cost Effectiveness - Executive Summary,

NESCAUM evaluated various control technologies that had been commercially applied to four

major source categories, including industrial boilers in the northeastern states and also their costeffectiveness in reducing emissions of oxides of nitrogen. Case studies were taken up for actual

installations of NOx reduction technologies on many sources, and detailed write-ups prepared in

cooperation with the users of the technologies. The users provided all the information and approved

the written descriptions of the case studies. Thus, the case studies represented the user’s view of the

performance, reliability, and cost of technologies (NESCAUM 2000). Relative to industrial boilers,

the report noted the following significant findings:

• LNB, OFA, SCR, SNCR, and reburn technology have been used for NOx reduction.

• Decisions to use OFA should be made on a case-by-case basis.

• In year 2000, for pulverized coal boilers, a 30% NOx reduction could be achieved

with LNB at a cost of <$2,000/ton.

• LNBs were capable of controlling a majority of gas-fired industrial boilers to NOx

levels below 0.15 lb/MMBtu.

• LNBs on boilers firing No. 6 oil achieved median NOx levels of 0.35 lb/MMBtu.

• SIP Call-dictated annual NOx reductions with LNB for oil & gas-fired industrial boilers

can be achieved at <$2,000/ton for moderate to high capacity factor (65 to 85%) units.

• SNCR was well suited for industrial boilers, achieving on average over 50% NOx reduction.

• SCR had seen only limited use in the U.S. on boilers firing solid fuel, but there was no

technical reason to prevent its use on such boilers.

• Gas reburn technologies operating on some industrial boilers in the U.S. were providing

NOx reductions of about 50%.

6.0 EMERGING TECHNOLOGIES FOR INDUSTRIAL BOILER NOX CONTROL

This section reviews some of the emerging NOx control technologies presented in the literature that

may be applicable to industrial boilers. However, it should be emphasized that most (if not all) of

these technologies are currently under development or in the “full-scale” evaluation stage. They

involve both combustion modifications and post-combustion flue gas NOx emissions control.

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National Council for Air and Stream Improvement

6.1 Methane de-NOX Reburn Technology

Reburning involves the staged addition of fuel into two combustion zones: a) the primary combustion

zone where the primary fuel is fired; and b) the reburn zone where additional fuel (the reburn fuel) is

added to create a reducing (oxygen deficient) condition to convert the NOx produced in the primary

zone to molecular nitrogen (N2) and water. In the reducing zone, the reburn fuel molecules break

down to hydrocarbon fragments (CH, CH2, etc.) that react with NOx. Above the reburn zone is a

burnout zone where OFA is added to complete the combustion.

Schrecengost et al. (2002) provided an overview of a gas reburn technology (Methane de-NOX )

using 5 to 25% natural gas heat input for combustion improvement and 50 to 70% NOx reduction in

coal-, biomass-, and MSW-fired stoker boilers. The process features injection of gas near the grate

with recirculated flue gas and injection of overfire air at a higher furnace elevation to burn out the

combustibles. The oxygen-deficient atmosphere above the grate is expected to retard NOx formation. 

More recently, the Methane de-NOX technology (MdN) is being applied to kraft pulp mill stoker

boilers by utilizing the VOC content of non-condensible gases (NCGs) to partially replace the natural

gas (by up to 25%). This technology has been tested for over a year at one pulp mill boiler, and is

being tested at several boilers within one FPI company. The MdN technology has also been applied to

two MSW plants and a coal-fired utility. The authors claimed the following energy and environmental

benefits when applying this technology to pulp and paper industry boilers:

• reduced operating costs and air emissions through advanced combustion with strategic

use of natural gas

 increased utilization of wood residues

 improved boiler operability, reliability, and efficiency

 improved boiler environmental performance

• increased effective, efficient, and reliable self-generated power capacity

• cost-effective and efficient destruction/utilization of NCGs.

6.2 Low Temperature Oxidation

Low temperature oxidation (LTO) is an NOx removal system that uses ozone, injected into the flue

gas stream, to oxidize insoluble NOx to soluble oxidized compounds. Ozone is produced on site and

on demand by passing oxygen through a conventional industrial ozone generator.

The BOC Group commercialized this technology under the trade name LoTOx. Barasso and Donovan

(2002a, 2002b) presented the following key points relevant to the LTO technology for NOx control.

• NO and NO2 in a gas stream were oxidized to highly soluble N2O5 and HNO3 by injecting

ozone.

• A particulate and/or SO2 scrubber was used to scrub out the oxidized compounds.

• Ozone was produced in response to the amount of NOx present in the flue gas.

• At the design retention time, ozone reacted selectively with NOx and not with SOx and CO.

• LTO operated optimally below 300°F.

• Performance was unaffected by “dirty” streams.

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Tests conducted in 2002 on a slip stream from a pulp and paper industry bubbling fluidized bed boiler

burning deink sludge, bark and TDF were reported to be successful in reducing NOx emissions by over

90% (http://www.boc.com/news/article_detail.cfm?ID=334&bSegment=0). A 25 MW coal-fired

power plant at the Medical College of Ohio (MCO) is the only full-scale installation of LTO

technology to date. It has been operating since October 2001. The MCO system involves a semi-dry

rapid absorption process for SOx scrubbing (using lime slurry) and a bag house particulate control

technology, followed by the LTO system for NOx removal. The LTO system consists of a reactor

(72-inch diameter, one pass with 1.5 sec residence time), followed by a wet absorber and a wet stack,

associated oxygen supply, an ozone generator, and a cooling water system. A six-month testing phase

was planned in late 2001 to determine performance of the LTO system at a 45,000 lb/hr boiler steam

load. Early operating results indicated 85 to 90% NOx removal from 50 to 70 ppm baseline levels. A

1,000 acfm slip stream at a 500 MW coal-fired boiler and a slip stream at a 400 MM Btu/hr bubbling

fluidized boiler burning wood residues, deink residuals, tire-derived fuel, and natural gas at a deinking

facility have also been reported to be tested successfully with over 90% NOx removal. Cost estimates

are not available for comparison, although a cost analysis carried out using this technology on a 200

MW coal-fired power plant with an existing FGD scrubber showed that fixed costs were 50 to 55%

of total annual cost, and operating costs (largely the power for ozone generation and oxygen) were

45 to 50%, with a cost-effectiveness estimated at about $1,696 per ton of NOx removed from the

baseline (0.4 lb/MM Btu).

6.3 Induced Flue Gas Recirculation Technology

For modified flue gas recirculation technology (Broske 1998), a duct is added between the economizer

outlet (or air preheater outlet) duct and the FD fan, thus eliminating the need for a separate FGR fan,

where the boiler flue gas is recirculated to the combustion zone by induced flow through the FD fan(s)

and a flue gas flow rate of 0 to 20% is controlled (manually or automatically) over the load range.

The following advantages were claimed for this technology.

• 40 to 50% NOx reduction at a low cost ($0.25 to $1.00/kW installed cost, about 30% of

cost of LNB or FGR)

• easy to retrofit

• applicable to various boiler firing systems

The following disadvantages were also noted.

• may limit the boiler load (without modifications)

• involved a heat penalty (0.3 to 0.5%)

• reduced the rate of load change during transitions

• affected steam temperature (spray capacity)

6.4 The Pahlman Process

Enviroscrub Technologies Corporation, a Minneapolis, Minnesota company, provided

some information about a unique (but secretive) NOx scrubbing process at their website

(www.enviroscrub.com) that included the following:

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National Council for Air and Stream Improvement

• a one step, dry scrubbing process using a fine black powder dubbed Pahlmanite

• slip streams tested using this technology at the Huntsville Power station, Huntsville,

Illinois, the Boswell Energy Center (Minnesota Power), Cohasset, Minnesota and

Potlatch Corporation’s Brainerd, Minnesota coal-fired boiler (mill since shut down)

• claimed between 75 and 96% NOx removal

• compounds of sulfur (sulfates) and nitrogen (nitrates) formed when Pahlmanite

is regenerated for reuse could be resold for chemical or as fertilizer

6.5 Other Emerging Technologies

One emerging technology involves the injection of elemental phosphorus as an oxidant to convert

NO to NO2 which is then removed in a wet scrubber. The first full-scale application of Thermal

Energy’s THERMALONOx technology on a power plant has been undergoing a commercial

demonstration on a high sulfur coal-fired utility boiler in Ohio. Initial results of this demonstration

at American Electric Power’s (AEP) Conesville plant suggest a need for additional research. AEP

stated that despite the promising nature of the technology, the data from the demonstration indicate

the system did not appreciably reduce nitrogen oxide emission levels from the plant’s 375-megawatt

generating unit (http://www.aep.com/environmental/performance). The system was expected to

remove as much as 75% of the NOx emissions from the exhaust gases of utility power plants and

industrial boilers when used in combination with a flue-gas desulfurization system.

The Electric Power Research Institute (EPRI) stated in December 2002 it was involved with several

emerging post-combustion NOx control technologies that were principally designed for utility coalfired boilers (http://www.epri.com/corporate/ productsservices/project_opps/gen/1007605.pdf). 

Some of these technologies may have application to industrial boilers. The projects included:

• boosted overfire air + SNCR (urea reagent)

• ecotube high pressure OFA system + ammonia injection

• Mobotec ROTAMIXTM (ammonia injection)

• SNCR Trim (single level of injectors)

• Selective Auto-Catalytic Reduction (SACR)

• rich reagent injection

Durr Environmental (http://www.durrenvironmental.com/NOXCS.asp) offered a Zero Ammonia

Technology (ZAT) that did not require the injection of ammonia or urea. ZAT is a catalytic-based

system that converts all of the NOx into NO2 (i.e., it oxidizes the NO) and adsorbs the NO2 onto

the catalyst. Portions of the catalyst are isolated from the exhaust stream, and the adsorbed NO2

is reduced to N2 using diluted hydrogen, or some sort of hydrogen reagent gas, and desorbed from

the catalyst.

The National Energy Technology Laboratory (NETL) stated that it was managing several

NOx control technology R&D projects ranging from laboratory studies to modeling to full-scale

demonstration. The technologies being addressed included ultra low NOx burners, advanced

reburning, selective non-catalytic reduction (SNCR), selective catalytic reduction (SCR),

METHANE de-NOx, and oxygen-enhanced combustion. The project summaries may be found

at http://www.netl.doe.gov/ publications/proceedings/02/ubc/lanisummary.pdf.

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6.5.1 Ultra Low NOx Integrated Systems for NOx Emission Control

Alstom Power reported developing an ultra low NOx integrated system for coal-fired power plants

that will achieve furnace outlet emission levels at or below 0.15 lb/MMBtu. The reduced NOx

emissions will be obtained without increasing the level of unburned carbon (UBC) in the fly ash

through advances in control systems, combustion process modifications, and postcombustion

carbon burnout technology. The target market would be tangentially fired (T-fired) coal boilers,

which represent about 40% of the boilers currently listed in the State Implementation Plan (SIP)

Call region.

6.5.2 NOx Control Options and Integration for U.S. Coal-Fired Boilers

Reaction Engineering International has reported optimizing the performance of the combined

application of low NOx firing systems (LNFS) and post-combustion controls. The project will

assess real-time monitoring equipment to evaluate waterwall wastage, soot formation, and burner

stoichiometry. In addition, the impact of various coals on SCR catalyst activity will be investigated

along with novel UBC/fly ash separation processes. The primary target of the research would be

cyclone boilers, which represent about 20% of the U.S. generating capacity.

6.5.3 Cost-Effective Control of NOx with Integrated Ultra Low NOx-PC Burners and SNCR

In another advanced low NOx burner project, McDermott Technology and Fuel Tech have reported

teaming up to develop an integrated system comprised of ultra LNBs, coupled with SNCR. The

overall goal of this project is to develop a cost-effective control system capable of achieving NOx

levels below 0.15 lb/MMBtu for a wide range of coals. The primary market for the ultra LNB/SNCR

technology would be front- and opposed-wall-fired boilers within the NOx SIP Call region, with

cell-fired, roof-fired, and arch-fired boilers also among the candidates.

6.5.4 METHANE de-NOx for Utility Boilers

The Gas Technology Institute (GTI; formerly the Institute of Gas Technology and Gas Research

Institute) has reported developing a pulverized-coal combustion reburn system. The technology

integrates natural gas-fired coal preheating, LNBs with internal combustion staging, and additional

natural gas injection with overfire air. Preheating the coal promotes the conversion of fuel-bound

nitrogen to molecular nitrogen rather than to NOx. GTI estimates the market for the technology

would include more than 21,000 burners (over 260,600 MW) in the 37 eastern states encompassing

wall-fired (wet- and dry-bottom), T-fired, roof-fired, and cell burners.

6.5.5 Oxygen-Enhanced Combustion for NOx Control

Praxair has reported developing oxygen-enhanced combustion and oxygen-enhanced reburning

technologies for controlling NOx. Oxygen-enhanced combustion can be used to control both

thermal and fuel NOx. The key to this project is the use of controlled conditions to take advantage

of the combustion benefits of oxy-fuel firing to reduce NOx emissions below 0.15 lb/MMBtu.

7.0 TECHNICAL LIMITATIONS OF APPLYING AVAILABLE NOX CONTROL

TECHNOLOGIES TO FPI BOILERS

Much of the operating experience gained on fossil fuel-fired boiler NOx emissions control

has involved utility boilers. A few gas and/or oil-fired FPI boilers have employed combustion

modification NOx reduction techniques such as LNB, OFA and FGR. A few have even installed

SNCR for post-combustion NOx emissions control. The SNCRs have typically been installed

on base-loaded boilers or for marginal NOx removal purposes. None has SCR in place.

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In November of 1998, the American Forest and Paper Association (AF&PA), along with several

other organizations including the Council of Industrial Boilers (CIBO), submitted a petition to the

DC Circuit Court challenging the revised Subpart Db standards of performance for NOx applicable

to fossil-fuel fired steam-generating units (“boilers”) promulgated by EPA on September 16, 1998. 

The petition claimed EPA did not consider adequately the feasibility of installing SCR on coal-fired

industrial boilers (or coal/wood and coal/oil boilers) which have different characteristics than utility

boilers such as swinging loads. It highlighted several characteristics pertinent to pulp and paper

industry boilers that differentiate them from utility boilers, thereby calling the applicability of a

uniform technology-based NOx standard into question. EPA responded to this petition in a July 30,

1999 legal brief, arguing that it should be denied (USEPA 1999). Highlights of the AF&PA petition,

EPA’s response, and an evaluation of EPA’s response can be found in Appendix A.

Appendix B summarizes the public comments relative to FPI boilers that were submitted to EPA in

response to the July 9, 1997 proposal to revise the NOx emission limits in subparts Da and Db of 40

CFR Part 60. EPA’s responses to these comments (USEPA 1998d) are also included in Appendix B.

The following sections summarize the technical limitations identified in selected industry and nonindustry publications on the application of various NOx control technologies to FPI boilers.

7.1 Applicability of Combustion Modifications

Industrial boilers typically operate with widely varying steam loads, with an estimated mean capacity

utilization factor of 45 to 55% (CIBO 1993). Even recently installed cogeneration and independentpower facilities with higher utilization factors operate on dispatch schedules dictated by the utility

purchasing the power (Jones 1994). NOx reduction measures are particularly difficult to implement

in small, low capacity facilities because a) residence time is limited and often inadequate for applying

overfire air (OFA) without excessive loss of thermal efficiency or induced smoking; b) relatively small

furnace dimensions limit combustion modifications that increase flame length and tend to cause the

flame to impinge on tube walls’ c) peak boiler efficiency and minimized NOx emissions occur close to

minimum flue-gas O2 content, which is at the threshold of smoke or combustible-emissions formation;

d) steam is used far more effectively in industrial applications than in conventional electric utility

plants and, consequently, emission limits based on boiler heat input or volume of flue gas do not

recognize such efficiency (Jones 1994).

The Council of Industrial Boiler Owners prepared an NOx RACT (Reasonably Available Control

Technologies) guidance document (CIBO 1993) which identified numerous reasons why uniform

RACT rules for industrial boilers would be inappropriate.

• The industrial boiler population is diverse – no specific type is prevalent.

• There are very little hard NOx emissions data for existing industrial systems.

• The variability of emissions from a unit, type system, or class of units, can be extreme.

• Projection of system trends is impractical; therefore, emissions may have to be considered

on a unit-by-unit basis.

• Most industrial stoker fired units installed prior to 1987 were equipped with only one

or two rows of overfire ports, and a maximum of 10 to 20% total air, an arrangement

designed to optimize combustion efficiency, not to control NOx emissions.

• Bottom-supported stoker units are virtually impossible to retrofit with a new

overfire air arrangement.

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• Inherent system variability required that a 30-day rolling average be the standard

for industrial boilers.

In written comments to the Maine Department of Environmental Protection, Sonnichsen (1994)

of CARNOT listed several reservations about applying utility NOx control experience to industrial

boilers.

• The greatest difference in utility and power boiler operations is the fluctuating steam demand

characteristic of pulp and paper mill operations which requires that power boilers continuously

adjust fuel firing rates and excess air levels. Even with the most sophisticated combustion

controls, it is not practical or safe to maintain excess air continuously at minimum levels. 

Consequently, power boilers have characteristically and inherently higher NOx emissions. 

• Fuel biasing on an industrial boiler subject to rapid and excessive load swings could result in

too rich or lean firing conditions, which can lead to flame stability problems and explosive

conditions.

• Windbox flue gas recirculation (FGR) could be considered for use on oil-fired boilers. 

Its application, however, can be limited by (1) the windbox and boiler fans’ capacities,

(2) increased boiler bank tube wall erosion, and (3) the potential for severe damage from

changes in convection heat transfer and boiler water circulation patterns.

• The application of low NOx burners (LNB) is often limited by the longer flames produced

as a consequence of improved air distribution control. While there is generally ample room

for LNB flames in utility furnaces, their use on the smaller power boilers can result in flame

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

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

and CO emissions.

• Unlike utilities which can specify the nitrogen content of their large oil purchases,

most mills cannot do this.

Even within the family of industrial boilers there are considerable differences in the design of various

types of boilers and therefore the applicability of certain NOx control technologies. For example,

considerable differences exist in the heat removal rates between a grate-fired boiler for wood residue

or coal combustion and a packaged boiler for oil or gas combustion. The grate boiler is designed for

staged combustion since a large amount of the combustion air is introduced above the grate fire. Also,

the size of the grate furnace is two to three times greater than a similar packaged boiler. The net result

is that there is more heat absorption in a grate-fired boiler resulting in lower thermal NOx formation. 

Both air staging and flue gas recirculation, recommended NOx control techniques for oil and gas

combustion, when applied to packaged boilers will increase the burner flame length and require

added furnace length to avoid flame impingement on the furnace walls.

7.2 Applicability of SNCR NOx Control Technology

As previously mentioned, the use of the SNCR process in a packaged boiler would require access

to a temperature window between about 1700 and 2000°F in which to inject the ammonia or urea. 

Controlling flue gas temperatures in the convective section of a package or even grate boiler over the

entire range of operating loads the boiler is expected to experience will be very difficult to achieve. 

Boilers in the pulp and paper industry rarely operate under base loaded conditions. Consequently, the

location of the desired temperature window is expected to change constantly. Accurate, instantaneous

temperature measurement, as well as the ability to accurately adjust the location of the injection

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nozzle, would be necessary. Ammonia slip would be a recurring problem associated with the

application of the SNCR process to industrial boilers with fluctuating loads.

7.3 Applicability of SCR NOx Control Technology

An important factor restricting the use of the SCR process on most industrial boilers is the loss in

energy efficiency that would result from the need to reheat the exhaust gases. Exhaust gases exiting

the economizer sections of most FPI boilers are typically in the range of 250 to 400°F, while the

desired temperature range for the SCR process is between 450 and 750°F. At part load, a boiler

economizer bypass will probably be required, especially in high sulfur applications, as most boilers

feature flue gas temperature at the economizer exit that is below the ammonium sulfate/bisulfate dew

point (Cichanowicz 1999). Air heater surfaces must withstand corrosion from ammonium sulfates

and bisulfates, be easily cleaned with conventional soot blowing, and survive corrosion-inducing

water washing. SO3 produced by the catalyst may condense on cooler surfaces, depending on the

temperature, during both steady-state and non-steady-state operation. Higher levels of SO2 to SO3

conversion could cause accelerated corrosion or higher SO3-induced plume opacity. Minimizing

ammonia levels in the stack (typically <2 to 3 ppm) is required to avoid problems with disposing

or marketing fly ash or scrubber byproduct contaminated by ammonia. The use of a particular

catalyst puts restrictions on the fuel flexibility for a boiler. For example, purchasing coal with

fly ash containing calcium oxide and arsenic outside the defined range absolves the catalyst

supplier from responsibility for arsenic poisoning (Cichanowicz 1999).

8.0 PERMITTING INFORMATION

NOx emission limits for boilers are often set on a case-by-case basis as part of an air quality

permitting process. For new boilers, or existing boilers undergoing a major modification, obtaining

a construction permit generally involves a determination of Best Available Control Technology (BACT)

or Lowest Achievable Emission Rate (LAER). For existing boilers located in or near ozone nonattainment areas, NOx emission limits may be based on facility-specific determinations of Reasonably

Available Control Technology (RACT). EPA guidance indicates LAER limits should be the most

stringent, followed by BACT and RACT limits. 

Permitting decisions are usually made by states and reviewed by EPA regional offices. Information

submitted by the permit applicant is considered in the decision-making process. Factors such as

technical feasibility, cost-effectiveness, ambient air quality impact, and non-air quality impacts

are evaluated on a facility-specific basis.

Appendix C contains information submitted to permitting agencies by forest products companies as

part of their evaluation of alternative RACT, BACT, and/or LAER NOx control options for boilers. 

Appendix D tabulates permitting decisions and NOx emission limits in EPA’s RACT/BACT/LAER

Clearinghouse database for boilers at forest products industry manufacturing facilities for the period

between 1992 and 2001.

9.0 NOX EMISSIONS CONTROL COST ESTIMATES FOR INDUSTRIAL BOILERS

This section deals with costs for implementing NOx emissions control on industrial boilers. Cost

plays a critical role in making permitting decisions and in development of nationwide emission

regulations such as the NSPS. First, EPA’s summary analysis on NOx control costs for fossil fuelfired boilers presented during the promulgation of the revised Subpart Db NOx emission standards

for boilers is discussed. Cost estimates published by NESCAUM are then briefly summarized. 

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Finally, cost estimates and comments provided in permitting analyses of boiler NOx control options

performed by individual forest products industry companies are summarized.

9.1 EPA Estimates for New Industrial Fossil Fuel-Fired Boilers

In the background technical document for the revised Subpart Db NOx emissions standards,

EPA estimated control technology costs for installing various types of NOx emissions control

on new fossil fuel-fired industrial boilers (USEPA 1997). Annualized costs and incremental

cost-effectiveness ranges from this document are reproduced for various model boilers in Tables 9.1

and 9.2, respectively. Table 9.1 shows the cost of installing combustion controls for NOx emissions

on industrial fossil fuel-fired boilers ranges from 0 to 2% of the net cost of generating steam in the

boiler. It should be noted that the requisite combustion controls for fluidized bed combustors and

spreader stokers burning coal and field-erected water tube boilers burning distillate oil or natural

gas are already assumed to exist and thus represent the baseline for these boilers. When combustion

controls are augmented by SNCR, the total cost rises to between 4% and 16% of the steam cost. 

Finally, when SCR is used along with combustion controls, the total cost increases appreciably

to between 10% and 48% of the steam cost. Table 9.2 gives estimates for incremental costeffectiveness in $/ton NOx removed. When applying SCR to industrial boilers after combustion

controls have been implemented, the incremental cost-effectiveness estimates range from $5,900 to

$49,800 per ton of NOx removed. Incremental cost-effectiveness estimates for applying SNCR to

boilers after combustion control implementation are also high, ranging from $1,720 to $32,140 per

ton of NOx removed. In the July 1997 Federal Register proposal ([FR 62 (131) 36948-36963]),

EPA explained the wide range in the cost and cost-effectiveness estimates as follows: “The main

differences between industrial steam generating units and utility steam generating units are that

industrial steam generating units tend to be smaller and tend to operate at lower capacity factors. 

The differences between industrial and utility steam generating units would be reflected in the cost

impacts of the various NOx control technologies. Smaller sized and lower capacity factor units

tend to have a higher cost on a per unit output basis.”

ASHDOWN-Q8-000806
Table 9.1 Summary of Annualized Costs for Model Boilersa (USEPA 1997)

Size CCc CC + SNCRc CC + SCRc

Fuel Type Furnace Typeb (MM Btu/hr) $/yr % $/yr % $/yr %

Coal PC 250 40,040 1 286,530 9 997,740 33

500 59,020 1 384,460 6 1,605,070 27

1,000 87,010 1 538,850 4 2,756,820 23

FBC 100 0 0 173,170 14 NA NA

250 0 0 227,480 8 NA NA500 0 0 287,410 5 NA NA

1,000 0 0 375,780 3 NA NA

Spreader Stoker 100 0 0 184,580 15 583,440 48

250 0 0 256,000 8 960,920 32500 0 0 344,540 6 1,551,210 26

Residual Oil Field-Erected 100 23,970 2 197,060 16 461,860 38

Water Tube 250 40,040 1 265,600 9 668,940 22

500 59,020 1 341,770 6 972,550 16

1,000 87,010 1 453,320 4 1,522,790 13

Packaged 100 23,970 2 197,060 16 461,860 38

Water Tube 250 40,040 1 265,600 9 668,940 22

Distillate Oil/ Field-Erected 100 0 0 168,910 14 418,880 35

Natural Gas Water Tube 250 0 0 215,110 7 581,250 19

500 0 0 261,830 4 818,200 14

1,000 0 0 324,470 3 1,245,120 10

Packaged 100 23,970 2 194,400 16 443,210 37

Water Tube 250 40,040 1 258,940 9 622,310 21

a Annualized costs are for a capacity factor of 0.30. Annualized cost expressed as a percentage of steam cost; steam cost based on $6 per 1000 lb steam;

and 1,300 Btu of heat input per lb of steam generated

b PC = Pulverized Coal; FBC = Fluidized Bed Combustion;c CC = Combustion Control; SCR = Selective Catalytic Reduction; SNCR = Selective Non-Catalytic Reduction

Special Report No. 03-04 31

National Council for Air and Stream Improvement

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32 Special Report No. 03-04

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Table 9.2 Model Boiler Incremental Cost-Effectiveness Rangesa (USEPA 1997)

Control Technology Incremental Cost

Fuel Type Furnace Typeb Comparisonsc Effectiveness ($/ton)

Coal PC CC vs. Baseline 240 - 440

CC + SNCR vs. CC 1,720 - 3,375

CC + SCR vs. CC

CC + SCR vs. CC + SNCR

6,350 - 9,110

14,070 - 18,040

FBC CC vs. Baseline 0

CC + SNCR vs. CC 2,860 - 13,180

CC + SCR vs. CC

CC + SCR vs. CC + SNCR

NAd

NA

Spreader Stoker CC vs. Baseline 0

CC + SNCR vs. CC 2,100 - 5,620

CC + SCR vs. CC

CC + SCR vs. CC + SNCR

5,900 - 11,100

12,250 - 20,240

Residual Oil Field-Erected CC vs. Baseline 740 - 2,030

Water Tube CC + SNCR vs. CC 2,930 - 13,870

CC + SCR vs. CC

CC + SCR vs. CC + SNCR

7,190 - 21,920

14,280 - 35,350

Packaged Water Tube CC vs. Baseline 640 - 960

CC + SNCR vs. CC 7,230 - 13,870

CC + SCR vs. CC

CC + SCR vs. CC + SNCR

12,600 - 21,920

21,540 - 35,350

Distillate Oil/ Field-Erected CC vs. Baseline 0

Natural Gas Water Tube CC + SNCR vs. CC 6,170 - 32,140

CC + SCR vs. CC

CC + SCR vs. CC + SNCR

14,180 - 49,800

29,190 - 79,250

CC vs. Baseline 2,030 - 3,040

Packaged Water Tube CC + SNCR vs. CC 11,110 - 21,620

CC + SCR vs. CC

CC + SCR vs. CC + SNCR

18,460 - 33,240

30,730 - 52,600 a Incremental cost-effectiveness at a capacity factor of 0.30 for the range of boiler sizes 250, 500 and 1,000 MMBtu/hr

for PC boilers; 100, 250, 500 and 1,000 MMBtu/hr for FBC and field-erected boilers; 100, 250 and 500 MMBtu/hr for

spreader stoker boilers; and 100 and 250 MMBtu/hr for packaged boilers

b PC = Pulverized Coal; FBC = Fluidized Bed Combustion

c CC = Combustion Control; SNCR = Selective Noncatalytic Reduction; SCR = Selective Catalytic Reduction

d NA = Not Applicable

ASHDOWN-Q8-000808
Special Report No. 03-04 33

National Council for Air and Stream Improvement

9.2 NESCAUM

The NESCAUM report (2000) also evaluated cost-effectiveness of reducing NOx emissions from

existing industrial boilers. Table 9.3 summarizes the type of NOx control, percent NOx removal

expected, and cost-effectiveness for oil, gas- and coal-fired industrial boilers in the NESCAUM

area (retrofit situations).

Table9.3 Cost Estimates of NOx Control for Industrial Boilers (NESCAUM 2000)

Boiler Type, Size

& Fuel Fired Type of NOx Control

Percent NOx

Control

Cost-Effectiveness,

$/ton NOx removed

LNB <$2,000

Gas Reburn >50 <$2,000

Oil- & Gas-Fired

Industrial Boilers

Gas Reburn + SNCR >60 <$2,000

LNB 30 <$2,000

SNCR 35 $1,300 to $1,800

Coal-Fired Industrial Boiler

SCR 90 $2,000

9.3 FPI Cost Estimates for Industrial Boiler NOx Control

Table 9.4 was compiled from studies done by pulp and paper companies, and lists the type of NOx

control, percent NOx removal expected, and cost-effectiveness for various boilers at several mills. 

The date for each analysis is shown in the first column. All the situations except that for Mill F

(greenfield mill) correspond to retrofit applications.

9.3.1 Detailed NOx Estimates for Mill H Pulverized Coal-Fired Boiler

In October of 2001, Mill H developed detailed cost estimates for various NOx reduction technologies

potentially applicable to its 360 MM Btu/hr pulverized coal-fired boiler. Table 10.1 provides a

summary of costs for this pulverized coal-fired boiler for four different NOx control options

considered [Option 1: Low NOx Burners + Overfire Air + NOx Monitor; Option 2: Low NOx

Burners + Overfire Air + Urea System (SNCR) + NOx Monitor; Option 3: Ammonia Addition +

SCR Catalyst + NOx Monitor; and Option 4: Low NOx Burners + Overfire Air + Ammonia Addition

+ SCR Catalyst + NOx Monitor]. The summary costs include the annualized capital cost, annual

operating and maintenance cost, and total annualized cost. The details of the cost analysis for each

NOx control option are included in Appendix E.

9.4 Comparison of Cost Estimates

It is clear from comparing the mill-generated and EPA-generated cost estimates that the actual costs

for installing and operating most NOx control technologies on FPI boilers will be boiler-specific. 

The costs can easily exceed the cost-effectiveness threshold of $2,000/ton NOx removed, a figure

EPA believes is reasonable for retrofit NOx controls in ozone nonattainment areas. In addition to

the typical costs associated with the nature of the boiler whose emissions are to be controlled,

other factors would also appear to cause the cost-effectiveness estimates to become significantly

higher than $2,000/ton NOx removed, principal among them being the extent of NOx control

desired from the baseline level and the cost of installation of each boiler.

ASHDOWN-Q8-000809
34 Special Report No. 03-04

National Council for Air and Stream Improvement

Table 9.4 Cost Estimates of NOx Control in Forest Products Industry Boilers

Boiler Type, Size

& Fuel Fired Type of NOx Control

Percent NOx

Control

Cost-Effectiveness,

$/ton NOx removed

FBC (new) 62.5 $11,244

SNCR 30.0 $1,041

OFA 10.0 $2,300

Mill A (July 1994)

Baseline = 0.4 lb/MMBtu;

coal-fired, traveling grate, 225

KPPH FGR 5.0 $4,600

Fuel Switching 45.0 $20,158

FGR 5.0 $5,840

LNB 5.0 $3,239

LNB + OFA 25.0 $2,023

Mill B (Oct. 1994)

Baseline = 0.37 lb/MMBtu;

oil-fired, 855 MM Btu/hr

LNB + OFA + FGR 32.0 $2,476

Mill C1 (Feb. 1996) LNB 30.0 $3,286

Coal, PC - 500 MM Btu/hr SNCR 50.0 $4,826

SCR 80.0 $6,755

Mill C2 (Feb. 1996) LNB 40.0 $3,422

Gas – 150 MM Btu/hr LNB + FGR 60.0 $3,666

SNCR 50.0 $6,766

SCR 90.0 $5,563

Mill D (Jan. 1996)

Sludge, FBC, 90 MMBtu/hr

SNCR -- $3,400

Mill E (Dec. 1996)

Baseline – 0.25 lb/MMBtu;

wood-fired boiler, stoker

SNCR 40.0 $3,400

O/Rb 90.0 $8,580

SCR 75.0 $6,276

Mill F1 (March 1997)a

Oil/Gas, Package Boiler, 365

MM Btu/hr, baseline = 0.10

lb/MMBtu

(Continued on next page. See notes at end of table.)

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Special Report No. 03-04 35

National Council for Air and Stream Improvement

Table 9.4 Continued

Boiler Type, Size

& Fuel Fired Type of NOx Control

Percent NOx

Control

Cost-Effectiveness,

$/ton NOx removed

O/Rb Mill F2 (March 1997) 90.0 $7,142 a

Oil/Gas, Power Boiler, 781

MM Btu/hr, baseline = 0.10

lb/MMBtu

SCR 75.0 $5,816

Mill G1 (June 1998)

Solid Fuelsc

Staged

Comb/LNB/GRd

5 to 30 $1,000 to $2,500

Mill G2 (June 1998)

Oil/Gas/low fuel bound N

FGR/LNB 30 to 80 $1,000 to $3,000

SNCR 33 to 50 >$1,700

SNCR/Hybride 50 to 85 $3,000

SCR 90.0 $6,000 to $7,500

Mill G3 (June 1998)

All Fuels (solid, liquid, gas)

O/R2 90.0 $7,500 to $9,000

LNB + OFAg 30.0 $1,989 ($4,746h

)

LNB + OFA + SNCRg 60.0 $1,645 ($3,925h

)

NH3 Addition + SCRg 60.0 $2,440 ($5,821h

)

Mill H (Oct. 2001)f

Baseline – 0.83 lb/MMBtu –

Coal, PC – 360 MMBtu/hr

LNB/OFA/NH3 SCRg 85.0 $2,342 ($5,588h

)

a

 greenfield mill, never built; bO/R=Oxidation/Reduction Scrubbing; cstokers: wood, coal, TDF; burners: oil;

pulverized coal; fuels w/high fuel-bound N; d

GR=gas reburn; eurea injection followed by small catalyst; fdetails

provided in Appendix E; g

including NOx monitor (LNB & OFA total capital cost=$2,910,934; NOx monitor &

flow monitor total capital cost=$628,878; SNCR total capital cost=$1,468,719; SCR total capital

cost=$5,348,505); h

if based on ozone season only, May 1–Sept. 30

ASHDOWN-Q8-000811
Table 9.5 Summary of Estimated Costs and NOx Control Options for Mill H Pulverized Coal-Fired Boiler

Capital

Amount

Total

Investeda

Annualized

Capital

Costb

Annual

Operating &

Maintenance

Costc

Total

Annualized

Cost

Estimated

Percent NOx

Removal

Annual NOx

Reduction

(tons)

Annualized

Cost ($)/ Ton

of NOx

Reduction

Annualized

Cost ($)/ Ton

of NOx

Reductiond

Capital Cost

($)/Ton for

NOx

Reductiond

Option 1:

3,500,000 569,450 215,000 784,450 30% 395 1,989 4,746d 21,174d

Option 2:

4,900,000 797,230 500,300 1,297,530 60% 789 1,645 3,925d 14,822d

Option 3:

5,977,000 972,458 954,350 1,926,808 60% 789 2,440 5,821d 18,057d

Option 4:

8,900,000 1,448,030 1,169,175 2,617,205 85% 1,118 2,342 5,588d 19,003d

Boiler NOx Control Options (see details in Appendix C)

Option 1: Low NOx Burners + Overfire Air + NOx Monitor; Option 2: Low NOx Burners + Overfire Air + Urea System (SNCR) + NOx Monitor

Option 3: Ammonia Addition + SCR Catalyst + NOx Monitor; Option 4: Low NOx Burners + Overfire Air + Ammonia Addition + SCR Catalyst + NOx

MonitoraIncorporates $600,000 of capital for NOx monitor as boiler is not subject to Subpart D (see Tables 8 to 11 for detailed cost summary)bAnnualized Capital Recovery Factor of 0.1627 (at 10% interest) calculated using EPA-OAQPS Costing Manual EPA-453/R95cUsing the following estimated annual operating cost factors:

 Monitor: $40,000/ year for consultants, certification, testing, cal gas (does not include maintenance) Services: $50,000/year for service based on a southeastern mill’s NALCO SNCR system Maintenance: 5% of capital investment (Includes operating, maintenance, and supervisory labor, and power, materials, taxes, and misc.)

 Urea: $500/ton NOx removed ($250/ton of 50% urea delivered and used) Catalyst: $800,000 replacement cost every 2 years

dAssuming control applied during ozone season only (153 days/year; May 1 - September 30);

Operating Assumptions

(1) Riley Boiler operates at 360 MMBtu/hr burning pulverized coal only; (2) 2000 Coal shipments averaged 13,191 Btu/lb; (3) Average tons of coal burned perhour = 13.65; (4) 2000 MAERS emission factor for NOx equaled 22 lbs NOx/ton coal (0.8339 lbs NOx/MMBtu); (5) Average NOx generation by Riley Boiler =

300.3 lbs./hr; (6) Current emissions of NOx from the Riley are about 300.3 lbs./hr, 3.6 Tons/day, and 1,315.3 tons/yr

36 Special Report No. 03-04

National Council for Air and Stream Improvement

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National Council for Air and Stream Improvement

10.0 SUMMARY

There is growing regulatory pressure for NOx emission reductions, particularly in and near ozone

nonattainment areas. Although utility boilers have been the major target for these reductions,

industrial boilers are under increasing scrutiny. As a result, NOx control measures are being

installed at a rapid pace on both utility and industrial boilers.

NOx control measures can be categorized as either combustion modification or flue gas treatment. 

The applicability of a particular control measure to a given boiler will depend upon the boiler type,

design parameters, fuel type, and operating conditions.

In this report, currently available NOx control measures are described and their applicability to

boilers operated by the forest products industry is discussed. Emerging technologies with potential

applicability are also reviewed. Differences between utility and industrial boilers that influence

the applicability or effectiveness of certain NOx control measures are enumerated. Estimates of

the capital and operating costs for NOx control measures developed by EPA, NESCAUM, and

individual companies are presented. 

Relative to combustion modifications, the following observations may be made.

• Combustion modifications such as low-NOx burners with overfire air and

flue gas recirculation work well with oil- and gas-fired boilers.

• For coal-fired boilers, low-NOx burners and overfire air have been successfully applied to

tangential- and wall-fired units, whereas reburning is the only current option for cyclone

boilers. Among emerging technologies worth consideration are the gas reburn technology

(when gas is available), the low temperature oxidation technique using ozone injection,

and layered technologies such as LNB with OFA combined with SNCR.

Relative to flue gas treatment, the following observations may be made.

• Considering reasonably available and proven NOx control technologies applicable

to solid fuel-fired industrial boilers, only SNCR and SCR would be deemed applicable

when control efficiencies exceeding about 40% are desired.

• Outstanding issues for applying SNCR and SCR technologies to boilers with swinging

loads remain, especially with respect to ammonia slip, and reliable removal efficiencies.

• Base-loaded oil-, coal- and gas-fired boilers can perhaps be controlled by SNCR

or SCR technologies, but site-specific factors must be considered.

• The use of SCR for biomass boilers or combination boilers firing biomass of all

configurations, even when base-loaded, needs further investigation since the ash

concentrations in the uncontrolled flue gas are quite high and the wood ash is

known to be rich in alkali metals that could potential act as catalyst poisons.

• SNCR for stoker-type biomass boilers or combination boilers firing biomass, even when

base-loaded, also needs to be further investigated since insufficient dispersion of the

ammonia or urea injected could lead to significant ammonia slip or low control efficiencies.

• The performance of SNCR and SCR on swing-loaded industrial boilers has not been

demonstrated to deliver consistently high levels of NOx reduction efficiencies.

ASHDOWN-Q8-000813
38 Special Report No. 03-04

National Council for Air and Stream Improvement

The most cost-effective strategy for installing NOx control on an industrial boiler could involve the

following steps (in succession) for higher levels of NOx control.

• Step 1 – Fine-tune the boiler (e.g., burner modification or replacement, process

modification and/or energy efficiency improvements).

• Step 2 – Improve or replace the convective section to preheat process fluid,

improve heater’s efficiency and decrease firing rate.

• Step 3 – Install low NOx and/or ultra low NOx burners.

• Step 4 – Investigate other combustion modifications such as OFA, FGR

and NOx tempering.

• Step 5 – Investigate use of SNCR.

• Step 6 – Investigate use of one of the emerging NOx control technologies

such as gas reburn and catalytic or ozone oxidation/scrubbing.

• Step 7 – For boilers with relatively clean flue gases (gas-, oil-, or coal-fired)

that also have access to the required temperature windows without severe

energy penalty, investigate installing SCR.

Relative to NOx control costs, the following observations may be made.

• Cost-effectiveness estimates vary considerably from one application to another,

depending on factors such as baseline and final NOx emission levels, specific site

installation costs, age and condition of the boiler, type of boiler, fuel types, and

capacity utilization.

• Estimates developed by individual mills showed NOx control cost-effectiveness

for mill boilers ranged from $2,000 to over $6,000 per ton NOx removed. The

estimates generally exceeded generic estimates prepared by EPA and NESCAUM

for similar control measures.

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ASHDOWN-Q8-000818
A1

APPENDIX A

THE 0.2 lb NOX/106 Btu EMISSION STANDARD FOR INDUSTRIAL

BOILERS – AF&PA PETITION CHALLENGING AND EPA

LEGAL BRIEF DEFENDING THIS STANDARD AND

NCASI COMMENTS ON EPA’S LEGAL BRIEF

In November of 1998, AF&PA, along with several other organizations, including the Council of

Industrial Boilers (CIBO), submitted a petition to the DC Circuit Court challenging the revised Subpart

Db standards of performance for NOx applicable to fossil-fuel fired steam-generating units (“boilers”)

promulgated by EPA on September 16, 1998. The petition claimed EPA did not consider adequately

the feasibility of installing SCR on coal-fired industrial boilers (or coal/wood and coal/oil boilers)

which have different characteristics than utility boilers, such as swinging loads. This petition

highlighted the following characteristics pertinent to pulp and paper industry boilers that differentiate

them from utility boilers, thereby calling the applicability of a uniform technology-based NOx standard

into question:

• Load Swings - Pulp mill combination and power boilers frequently exhibit wide and rapid

load swings that are not consistent with the steady conditions required for effective use of

either SNCR or SCR NOx control technologies. The load swings produce variable

temperature conditions in the boiler, causing the temperature zone for NOx reduction to

fluctuate, making it more difficult to know where to inject the reactants.

• Temperature Incompatibility - Combination and power boilers are affected by temperature

profile incompatibility. To obtain the required temperature window for SCR (550 to 750°F),

the only location to install this technology is upstream of the particulate matter control

device, yet this is where flue gases are dirty and can foul the catalyst rapidly. Downstream

of the PM control device, the temperature is too low for the catalyst to be effective.

• Burning of Sulfur-Containing Gases - Many kraft mills use their boilers to combust pulp

mill gases containing reduced sulfur compounds. This process may constrain combustion

patterns in that it requires high temperatures to be maintained to ensure complete oxidation.

• Adverse Trade-Offs -There are very few NOx reduction options available for most large

non-utility combustion sources, but even these options (e.g., low NOx burners, overfire air,

and flue gas recirculation systems) often have adverse trade-offs. 

• Unproven Technologies for High Levels of NOx Control - Even these options likely would

not achieve the levels of NOx reduction outlined in any of EPA’s ozone transport rule

makings, including the Subpart Db revisions. The 60% reductions proposed as part of the

Section 126 rulemaking likely would require the use of SCR or SNCR controls, technologies

which, for the most part, are untested and infeasible for pulp and paper mill boilers. These

technologies must be operated on a continuous basis within a specified temperature range in

order to be effective. The type of fuel burned influences the design of the technology, and

FPI facilities’ frequent fuel changes and co-firing of multiple fuels would result in design

and operational problems.

• SCRs Unproven for Biomass Applications – Many of the FPI boilers are fired to a large

degree by biomass. SCRs are not a proven NOx reduction technology for biomass

applications. There is test evidence of catalyst poisoning in sludge-burning applications and

ASHDOWN-Q8-000819
A2

accelerated deterioration in bark-burning applications. Furthermore, carryover of burning

embers from the furnace to the desired temperature zone for SCRs is expected in varying

degrees unless the catalyst is installed after a “hot” dust collector.

• Space Limitations For Installing SCRs - SCRs and the associated reagent systems require

considerable space, which would present problems for many pulp and paper mill

applications.

• Lack of Guarantee for SCRs on FPI Boilers – Boiler owners are finding that vendors of

SCR and SNCR technologies are unwilling to provide performance guarantees that the

controls will meet the level of reduction called for in the EPA proposal.

• EPA Claims of Transferability of SCR Experience on One Boiler Type to Other Boiler

Types – Industry experience conflicts with this, both on a technical basis and on a cost basis.

On July 30, 1999 EPA submitted a legal brief to the DC court outlining its arguments why certain

consolidated petitions challenging the revised Subpart Db standards of performance for NOx

applicable to fossil-fuel fired steam-generating units (“boilers”) promulgated by EPA on September

16, 1998 (viz., 0.2 lb NOx /106

 Btu for utility and industrial boilers firing more than 10% gas, coal, or

oil on an annual basis) should be denied (USEPA 1999). According to EPA, the petitions addressed

three main issues:

1. whether in revising the standards of performance for NOx emissions applicable to new

boilers, EPA properly chose selective catalytic reduction in combination with combustion

controls as the best system of emission reduction, taking into account environmental impacts,

costs and energy requirements

2. whether EPA reasonably established uniform emission standards for newly constructed

boilers based on the record before it

3. whether EPA properly assigned a 50% credit for the steam exported from cogeneration units

for purposes of determining compliance with the revised output-based standard for new

utility boilers

In its brief, EPA mentioned it chose “selective catalytic reduction in combination with combustion

control technologies as the best system of emission reduction because those technologies could

obtain significant NOx reductions at reasonable costs with minimal energy requirements.” The

revised limit for coal-fired industrial boilers was 0.20 lb/MMBtu heat input, 30-day rolling average. 

The brief contained the following points relevant to NOx emissions control.

• For industrial boilers, data on SCR were available for gas-fired units only.

• Results of SCR coal-fired utility boiler data analyses were used to assess appropriateness of

SCR for industrial boilers.

• EPA considered similarities and differences between utility and industrial boilers.

• EPA obtained cost data from utility questionnaires, vendor information, and published

literature and combined these with performance data and theoretical constructs of 38 utility

and 22 industrial boilers to arrive at control costs.

• For a boiler operating at 65% capacity, average cost-effectiveness for SCR was about $1,500

and $2,000 per ton NOx removed for utility and industrial boilers, respectively, over the cost

required to meet the regulatory baseline.

ASHDOWN-Q8-000820
A3

• Since combustion controls prevent NOx formation during combustion, their effectiveness

depends, in part, on the fuel used (e.g., the nitrogen content of the fuel) and the boiler design.

• The effectiveness of flue gas technologies, like SCR, however, does not depend on these

factors - they are applied after the combustion phase and destroy NOx regardless of how it

was formed.

• To avoid plugging and corrosion of catalyst during use of SCR on high S coal applications,

vendors have modified catalyst composition, including pore size; also, they have reduced the

temperature range for the NOx chemical reduction in new catalysts.

• Poisoning of SCR catalysts by alkaline metals—poisoning caused by alkalis in water soluble

form—most alkaline metals in coal-fired flue gas are not water soluble.

• Alkaline metals in oil-fired boiler emissions are water soluble—thus greater poisoning

potential—Mg (fuel oil additive) and Na (sea water contamination).

• EPA recognized differences between industrial and utility boilers and focused extensively on

the one main difference viz., more fluctuating loads.

• EPA evaluated CEM data on two utility boilers with cycling loads—32 to 100% and 28 to

84%—0.15 lb/MMBtu met on a 30-day rolling average.

• Issue of overcoming effect of flue gas temperatures while operating at low loads can be

addressed by including an economizer bypass duct.

• Other issues arising from operating at low loads such as lower gas flow rates and catalyst

poisoning were discounted by EPA.

• EPA claimed “Because SCR responds to NOx levels in the flue gas, adding wood should not

affect results, particularly given that coal represents the worst case scenario in terms of NO

emissions.”

• Wood-fired boilers using SNCR, which operates similarly to SCR, can achieve limits of 0.06

to 0.07 lb/MMBtu, far below the revised NSPS limits, at reasonable costs.

• EPA’s regulations do not require use of specific fuels or technologies—not favoring natural

gas—fluidized bed units using combustion controls alone, industrial boilers using SNCR, or

gas reburn alone can achieve the limit.

NCASI performed a technical review for AF&PA of the July 30, 1999 legal brief submitted by EPA

to the DC court in which it included the following comments.

• EPA cites two domestic gas-fired boilers with SCR with <0.01 lb NOx /106 Btu. If these

were base-loaded, gas-fired boilers equipped with SCR, it is easy to understand how the flue

gases could be controlled for NOx to such low levels; however, it is unclear whether these

levels could be achieved for swing-loaded boilers. Also, since no emissions data were

available for the two foreign coal-fired boilers, it is not clear why these were identified.

• EPA’s assertion that utility and industrial forest products industry boilers burn the same fuels

is untrue. Also, EPA states “boiler type is irrelevant for SCR because the technology is

applied downstream of the combustion process.” This is correct except, as shown later, the

type of boiler fuels could impact the particulate and/or SO2 loading in the gases entering the

SCR system, which may have an impact.

ASHDOWN-Q8-000821
A4

• EPA cites data from “two utility boilers with cycling loads analogous to industrial boilers.” 

How was this determination of analogous made? For example, were these cycling on a dayto-day basis or more slowly over a 30-day period?

• While operating at low loads, the lowered flue gas temperature that results is no doubt the

most important factor that could affect SCR performance. EPA recommends “adding an

economizer bypass duct.” First, this recommendation is not a “catalyst design” as

mentioned, but rather a design change of the ductwork. SCR requires a certain fixed

temperature window before the flue gases enter the catalyst section. Bypassing the

economizer section will no doubt raise the gas temperature, but this rise will depend on the

boiler load at any given time. Does EPA have data to show that achieving the desired

temperature range before the catalyst section can be met at various boiler loads by just

bypassing the economizer section?

• On page 45, EPA states “Because SCR responds to NOx levels in the flue gas, 63 Fed. Reg.

49, 444/3, adding wood, as Petitioners suggest, should not affect the results, particularly

given that coal represents the worst case scenario in terms of NOx emissions.” There is,

however, a major difference between wood- and coal-fired boilers. EPA’s AP-42 document

gives an uncontrolled particulate matter emission factor for pulverized, bituminous coal, dry

bottom boiler operations of 10 lb/ton or about 0.38 lb/106

 Btu. The same AP-42 document

gives an uncontrolled PM emission factor for bark firing in a spreader-stoker of 48 lb/ton or

about 5.33 lb/106

 Btu, i.e., about a 14 times higher particulate loading on a heat input basis is

expected from wood residue-firing than coal-firing. It is not clear EPA has considered the

impact upon SCR performance from increased PM loading in combination bark/coal boilers.

Note that the use of SNCR is likely not affected by PM loading.

• It is not clear whether the 0.06 to 0.07 lb NOx /106

 Btu quoted as having been achieved by

wood-fired boilers with SNCR are for base-loaded or swing-loaded wood-fired units.

ASHDOWN-Q8-000822
B1

APPENDIX B

NEW SOURCE PERFORMANCE STANDARDS, SUBPARTS Da AND Db –

SUMMARY OF PUBLIC COMMENTS AND EPA RESPONSES

EPA summarized the public comments it received with respect to its proposed amendments on July

9, 1997 to subparts Da and Db of 40 CFR Part 60 and the responses to such comments in September

of 1998 (USEPA 1998d). Several comments pertinent to FPI boilers and EPA responses to such

comments are summarized below.

a) Selective Catalytic Reduction as Best Demonstrated Technology

Comments on coal-fired industrial boilers

• SCR is not the best demonstrated technology for coal-fired industrial boilers.

• EPA should consider the potential problems associated with SCR, including costs, catalyst

poisoning, and oil ash coating catalyst.

• Deactivation of catalyst from alkali sulfates and excess SO3 in the flue gas.

Comments on appropriateness at pulp and paper mills

• SCR not appropriate for combination boilers at pulp and paper mills

• Boilers subject to wide, sudden changes in load that complicate use of SCR

• Other problems – high particulate loadings, sulfur poisoning, difficulty in maintaining

temperatures to minimize NOx and HAP generation

Comments on oil-fired boilers

• SCR is not the best demonstrated technology for oil-fired industrial boilers.

• Annual averaging period preferred if 0.20 lb/106

 Btu is set as standard.

EPA Response

• Additional U.S. experience - EPA obtained new data from three U.S. utility boilers with

SCRs that suggested all three could meet the input-based NOx standard of 0.15 lb/MM Btu

and output-based standard of 1.6 lb/MWh on a 30-day rolling average (one if facility

“improves” SCR performance).

• 30-day averaging period accommodates fluctuations in performance due to changing loads -

Data from two U.S. utilities showed that SCR can meet the proposed standard over a 30-day

averaging period under cycling conditions (one cycled from 32 to 100% load, the second

from 28 to 84%).

• Expected temperature range at economizer exit is factored into selection of SCR catalyst

formulation.

• In cases of low load with low gas velocity to keep ash in suspension, an ash hopper can be

added to divert the ash from reactor and catalyst surface.

ASHDOWN-Q8-000823
B2

• An economizer bypass can be added to avoid low boiler exit temperatures at low loads.

• Developments in catalyst technology minimize the impact of poisoning.

• A 1997 study identified 212 worldwide SCR installations on coal-fired units covering

different types of boilers subject to varying operating conditions and firing a variety of coals.

• Issues such as burning high sulfur coals, catalyst poisoning, SCR use in high dust vs. low

dust environments, etc. are more cost-based issues dealing with catalyst life.

b) Selective Non-Catalytic Reduction

Comments on Fluidized Bed Combustion Boilers (FBCs)

• SNCR not demonstrated on circulating FBCs which have inherently low combustion

temperatures - three of five CFBCs that use SNCR stated SNCR did not work when units

were operated at less than maximum capacity.

EPA Response

• Subpart Db background information document (BID) states that flue gas temperatures exiting

the furnace range from 2,200 ± 200°F at full load to 1,900 ± 125°F at half load.

• Addition of hydrogen or other hydrocarbon reducing agent while injecting NH3 or urea

lowers effective NOx reduction temperature range.

c) Control Technology Costs

Comments on Estimated Costs Being Too Low

• EPA cost estimates for SCR are much too low since they were extrapolated from an earlier

study that focused on retrofit costs for existing plants, and did not consider site layout, with

boiler conditions not typical of new units. EPA estimates are only 65% of values estimated

in a recent EPA/DOE/EPRI technical conference.

• SCR systems require more energy to operate due to a pressure drop across the catalyst bed.

• Costs associated with fouling of air heater surfaces by ammonium salts, and waste disposal

costs for the spent catalyst need to be considered.

• Additional costs associated with (a) lower catalyst life than 5 years due to catalyst poisoning,

(b) disposal of ash with higher nitrogen content, (c) plugging of air heaters by ammonium

bisulfate and fouling of catalyst by calcium and ammonium salts, (d) storing large quantities

of ammonia, (e) requiring open space for the catalyst bed, and (f) handling and disposal of

spent ammonia catalyst were not considered.

• Unplanned shutdown due to control device malfunction for utility boilers can be managed

differently than for industrial boilers that need the steam for the manufacturing operation. A

considerable economic penalty follows a shutdown in the case of the latter.

• Cost-effectiveness values for coal units using SCR are calculated using a baseline NOx

emission rate of 0.45 lb/MM Btu when low NOx burners can easily meet a 0.30 lb/MM Btu

emission rate.

ASHDOWN-Q8-000824
B3

EPA Response

• Cost estimates were made using actual baseline emissions from planned, new units in the

country and using more recent information obtained by the Acid Rain Division.

• Energy impact of SCR amounts to only about 0.4% of boiler output, which is justified.

• EPA used a three-year catalyst life for coal-fired units; the agency did account for different

types of coals, with varying ash contents in the costing analysis; indirect costs from

downstream effects from SCR have been included; additional storage costs for ammonia

were considered in indirect costs for SCR and SNCR; retrofit costs were included in EPA’s

analysis; spent catalyst costs were also included in indirect costs of SCR.

• In the case of a malfunction, the NSPS provisions do not apply for the period of the

malfunction, assuming the source acted to repair the malfunction soon thereafter.

• Model plants used a higher emission rate (0.45 lb/MM Btu), but the impacts analysis used

emission rates based on projected permit limits, which are lower.

Comments on Fuel Switching Costs

• Natural gas can cost more than twice as much as coal (Btu basis) when purchased on a

“curtailment basis.”

EPA Response

• The proposed standards are written in a “fuel-neutral” format that would allow use of natural

gas but would not require it when fuel costs exceed the costs of meeting the standard using

alternative means such as the use of SCR.

ASHDOWN-Q8-000825
ASHDOWN-Q8-000826
C1

APPENDIX C

RACT/BACT/LAER NOX CONTROL OPTIONS FOR BOILERS –

INFORMATION SUBMITTED BY FOREST PRODUCTS COMPANIES

Mill A - RACT Proposal – July 1994

Two coal-fired spreader stokers – Alternatives for NOx Control

• Conversion to Fluidized Bed Combustion – technically feasible, but economically infeasible

– estimated cost-effectiveness was about $11,200/ton NOx removed

• SNCR – economically feasible, but unproven technology for the type of boilers –

specifically, not proven for stokers over a wide range of load levels on a potentially rapidly

varying basis – rejected based on technical grounds

• Modification of Grate and Overfire Air System – small reductions in NOx – technically

infeasible – control of temperature to ensure effectiveness was found to be beyond the

capability of existing technology – costs were too high - $2,300/ton NOx reduction

• FGR – small reduction feasible – technically infeasible – flue gas temperature cannot be

controlled for proper combustion at all loads - $4,600/ton NOx reduction

Mill B, RACT Proposal – Aug. 1994

Two pulverized coal-fired boilers - separated OFA was considered not technically feasible due to the

following reasons:

• insufficient space in the furnace zone to accommodate installation of system

• unknown if boiler wall tubes could be relocated to accommodate the OFA ports

• boiler materials inadequate to accommodate corrosive conditions created in the reduction

zone

• risk of flame stability problems and, potentially, the creation of explosive conditions

• adverse effect on boiler energy efficiency from improperly functioning OFA system

• no prior installation of OFA system as retrofit on similar PC boilers

One wood-coal combination boiler (spreader stoker) - FGR was considered not technically feasible

due to:

• feasibility and effectiveness of FGR was questionable because of uncontrollable effects

associated with the temperature of the flue gas – if gas is too hot, the grate may overheat – if

too cold, this may lead to higher PM, CO, and VOC emissions

• PM entrained in recirculated flue gas could cause localized pluggage of grate

• no prior installation of FGR as retrofit on a similar mixed fuel stoker boiler

ASHDOWN-Q8-000827
C2

Mill C – BACT Analysis – October 1994

Power boiler, 855 MMBtu/hr (85% from No. 6 fuel oil, rest wood), oil burned through burners, wood

burned on grate - NOx control technologies considered – LNB, FGR, LNB w/OFA, LNB with OFA

and FGR, and fuel switching

LNB - technologically feasible

FGR - technologically feasible, especially in combination with LNB and OFA

OFA - technologically feasible

Staged Combustion – considered technologically infeasible for this boiler

BOOS – not applicable to this boiler since only 6 burners available

Gas Reburning – not applicable, since gas not available

Mill D – BACT Proposal – January 1997

Bark Boiler – 622 MMBtu/hr

• FGR - not applied to wood-fired boilers

• Low excess air - generally not applicable to low N, high-moisture fuels that require more

excess air to assure flame stability and effective combustion to control formation of CO,

VOC, and PM emissions

• SCR

 Not demonstrated on wood solid fuel boilers

 Use of solid fuels can result in catalyst contamination even with efficient PM control

system

 High moisture levels in exhaust air would result in inefficient SCR operation

 Exhaust gases need to be reheated by at least 150°F, representing about 40

MMBtu/hr or about 6.5% of the boiler heat rate

• SNCR

 technically feasible

 economic analysis results in a cost-effectiveness of $3,400/ton NOx removed -

considered cost-prohibitive

 adverse environmental impacts due to ammonia slip of 10 to 25 ppmv

 storage of ammonia or urea poses potential for accidental releases

• Enhanced staged combustion with OFA – proposed as BACT – 0.25 lb/MMBtu

ASHDOWN-Q8-000828
C3

Mill E – Greenfield Mill - BACT Analysis - March 1997

Combination Boiler (wood, sludge, OCC rejects, oil, gas) – 500 MMBtu/hr

• FGR – technically infeasible – would have to withstand high temperature and particulate

matter (PM) loading in the flue gas stream – does not affect fuel NOx from wood combustion

– not demonstrated on wood waste-fired boilers in pulp and paper industry

• SCR – technically infeasible – catalyst would be poisoned by sulfur compounds present - PM

would plug catalyst – reheat necessary if installed downstream of ESP – not demonstrated on

wood waste-fired boilers in pulp and paper industry

• SNCR – technically infeasible – temperature would be above the required temperature

window, and residence time would be less than the 1 second required

• Oxidation/Reduction Scrubbing – technically infeasible – high moisture content would result

in dew point exceeding max temperature required for effective scrubbing

• LNB – applies to fuel oil and gas – selected as BACT – 0.30 lb/MMBtu

Package Boiler (oil, gas) – 365 MMBtu/hr

• SNCR – technically infeasible – temperature would be above the required window and

residence time would be less than the 1 second required

• Oxidation/Reduction Scrubbing – economically infeasible – $8,580/ton NOx removed

• SCR – economically infeasible – $6,276/ton NOx removed

• LNB & FGR – selected as BACT – 0.10 lb/MMBtu

Power Boiler (oil, gas) – 781 MMBtu/hr

• SNCR – technically infeasible – temperature would be above the required window and

residence time would be less than the 1 second required

• Oxidation/Reduction Scrubbing – economically infeasible – $7,142/ton NOx removed

• SCR – economically infeasible – $5,816/ton NOx removed

• LNB & FGR – selected as BACT – 0.10 lb/MMBtu

BACT/LAER Study of NOx Reduction Technologies Study, June 1998

A consulting company carried out a comprehensive study evaluating several NOx reduction

technologies for various boilers within a company. The following summarizes their major findings:

• Load Reduction, Excess Air Reduction, Fuel Switching, Fuel Biasing, Air Staging, BOOS,

Water Injection - all these techniques are limited to applications where they can be

effectively implemented without sacrificing steam load - percent reductions in NOx of

between 5 and 10% feasible where applicable - cost-effectiveness = < $500/ton NOx reduced

• Staged Combustion/Low NOx Burners – feasible on the stoker-fired boilers – cost per ton

NOx removed = $1,000 to $2,500 - percent reduction in NOx 5 to 30 (maximum)

• Flue Gas Recirculation/LNB – LNB extends the flame and FGR limits flame temperature

more than OFA – up to 30% of flue gases recirculated to dilute amount of O2 present in

ASHDOWN-Q8-000829
C4

combustion air, thereby delaying combustion process – also stages air within the burner itself

to reduce thermal NOx – only thermal NOx reduced – good for gas and low fuel-bound N oils

only - cost per ton NOx removed = $1,000 to $3,000 - percent reduction in NOx 30 to 80

(maximum)

• SNCR – due to the narrow temperature window, applicable to base-loaded boilers only - cost

per ton NOx removed = >$1,700 - percent reduction in NOx 33 to 50

• SNCR Hybrid Systems – rely on SNCR followed by a small catalyst grid in a lower

temperature zone – allows for increasing the temperature window between 1500°F and

1900°F and possibly allows for some variations on boiler load – problems with particulate

plugging unless hot-side ESP used – cost per ton NOx removed = $3,000 – percent reduction

in NOx 50 to 85 (maximum)

• SCR – large catalyst bed – prone to plugging from PM – not suitable for PC units or other

solid fuel-firing methods like stokers – equipment size often quite large leading to space

limitations for retrofitting – cost per ton NOx removed = $6,000 to $7,500 – percent

reduction in NOx up to 90 (maximum)

• Oxidation/Reduction Scrubbing – 2-stage process involves oxidation of NO to NO2, using

ozone or sodium hypochlorite – 2nd stage uses caustic to remove NO2 – capital intensive,

with two scrubbing towers, recirculation tank, pre-mix tank, blowers, heat exchanger, and a

waste handling system – limited to maximum temperature of 200°F which makes it very

prone to corrosion – cost per ton NOx removed = $7,500 to $9,000 – percent reduction in

NOx up to 90 (maximum)

ASHDOWN-Q8-000830
D1

APPENDIX D

PERMITTING DECISIONS AND NOX EMISSION LIMITS IN EPA’S

RACT/BACT/LAER CLEARINGHOUSE DATABASE FOR FPI BOILERS

RACT/BACT/LAER Clearinghouse

Table D1 provides a summary of relevant information on FPI boiler NOx control extracted from

reports in the RACT-BACT-LAER Clearinghouse for the period between 1992 and 2001. This

information provides a look at the type of NOx limits and pollution prevention/add-on descriptions

outlined in these reports. It is clear from the information presented here that during the past decade,

LNBs with FGR and LNB were the most commonly recommended NOx control technologies for

oil/gas and coal-fired boilers, respectively, while good combustion control was typically the only

recommendation for wood waste-fired boilers.

ASHDOWN-Q8-000831
ASHDOWN-Q8-000832
Table D1 Summary of RACT-BACT-LAER Clearinghouse (RBLC) Information on NOx for FPI Boilers - 1992 to 2001

Permit

Date

Boiler

Description

Primary

Fuel

MM

Btu/hr1

NOx Limit,

lb/106 Btu Basis

P2/Add-on

Description Process Notes Company

7/7/93 Coal-fired Coal 174.7 0.20 BACT

-PSD

Good Combustion

Control

Not built Seminole Kraft,

Jacksonville, FL

12/21/94 Coal-fired Coal 214 0.51 RACT LNB, 30% eff.;

some nat. gas

Pulverized

Coal

IP, Erie. PA

9/10/96 Power Boiler Wood/Coal 1600 0.50 BACT

-PSD

Contd. Efficient

Operation w/LNB

other fuels4 Weyerhaeuser,

Columbus, MS

1/25/96 Fluidized

Bed

Sludge 90 100 ppm Other SNCR Fort James,

Green Bay, WI

3/10/97 Combination Wood/

Sludge

494 0.30 BACT LNB (applies to oil

& gas)

Not built Mid-South Project

12/17/98 Oil-fired No. 6 Oil 212 0.425 BACT

-PSD

LNB w/FGR -

20% control

Stack Tests Rayonier,

Fernandina Bch, FL

3/10/97 Package No. 2 Oil/

Gas

365 0.10 BACT LNB w/FGR Not built Mid-South Project

3/10/97 Power Boiler No. 2 Oil/

Gas

781 0.10 BACT LNB w/FGR Not built Mid-South Project

8/15/94 Oil-fired No. 6 Oil 223 0.30 BACT

-PSD

Mead, Stevenson, AL

7/1/93 Oil-fired No. 2 Oil 240 0.10 BACT

-PSD

LNB w/FGR 75%

efficiency

Appleton Papers,

Combined Lock, WI

ASHDOWN-Q8-000833
Table D1 (Cont’d). Summary of RACT-BACT-LAER Clearinghouse (RBLC) Information on NOx for FPI Boilers, etc. – 1992 to 2001

Permit

Date

Boiler

Description Primary Fuel

MM

Btu/hr1

NOx

Limit,

lb/106 Btu Basis

P2/Add-on

Description

Process

Notes Company

7/1/93 Wood-fired Wood Waste 718 150 ppm1 BACTOther Good Combustion Control SNCR rejected3 Scott Paper Co., Everett, WA

10/28/94 Wood-fired Wood Waste 91 0.23 BACTPSD Weyerhaeuser, Millport, AL

12/19/94 Wood-fired Wood Waste 275 0.23 BACTOther No Controls Kes Chateaugay Project, NY

12/21/94 Wood-fired Bark/Wood 326 0.54 RACT None IP, Erie. PA

4/11/95 Wood-fired Wood Waste 244 0.30 BACTPSD None Georgia Pacific, Gloster, MS4/17/96 Wood-fired Bark/Wood 470 0.30 BACT Good Combustion also natural

gas

Willamette,Bennettsville, SC

1/15/97 Wood-fired Bark/Wood 622 0.25 BACTPSD Combustion Control other fuels5 Mead, Stevenson, AL

12/9/97 Wood-fired Wood Waste 710 0.25 BACTPSD Addition of tertiary air system; 30% η other fuels6 Champion Interntl, Courtland, AL

12/10/97 Wood-fired Bark 775 0.3 BACTPSD LNB for gas/oil burners; 50% eff. includes sludge Gulf States, Demopolis, AL

5/13/98 Wood-fired Wood 245.3 115 ppm2 GACT SNCR Stack Tests Sierra Pacific Ind.,

Redding, CA

10/14/98 Wood-fired Wood 98 0.3 BACTPSD None Gulf States, Moundville, AL

1@ 7%O2 or about 0.25 lb/MM Btu; 2@12%CO2 or about 0.23 lb/MM Btu; 3NH3 injection led to visible plume; 4sludge/gas/ oil/NCG;5NRP/rejects/sludge/NCG; 6sludge/NRP/TDF/gas/NCG

ASHDOWN-Q8-000834
E1

APPENDIX E

DETAILED COST ANALYSIS FOR MILL H COAL-FIRED BOILER

Table E1 Low NOx Burners and Overfire Air Installation Costs at Mill H

Quantity Price Cost

Direct Costs

Purchased Equipment Costs*

Low NOx Burner Assemblies 4 $75,000 $300,000

Replace Burner Management System 1 $150,000 $150,000

Replace Forced Draft Fan 1 $125,000 $125,000

Replace Forced Draft Fan Motor 1 $40,000 $40,000

Lot Windbox Modification Materials 1 $75,000 $75,000

Lot OFA Nozzles & Pressure Part Openings 1 $180,000 $180,000

Lot New Instrumentation & PLC Controller 1 $316,000 $316,000

Lot Misc. Boiler Repairs/Modifications** 1 $250,000 $250,000

Sales and Construction Taxes (10%) $118,600

Freight (7.5%) $88,950

Purchased Equipment Costs, Subtotal $1,554,600

Installation Costs

Lot Foundation/Demolition 1 $10,000 $10,000

Structural, tons 2 $5,000 $10,000

Lot Equipment (Incl. port installation) 1 $500,000 $500,000

Lot Instrumentation/Electrical 1 $200,000 $200,000

Installation Costs, Subtotal $720,000

Total Direct Costs $2,274,600

Indirect Costs

Engineering, @ 7% of Direct Cost $159,222

Construction & Field Expenses --

Contractor --

Owner’s Cost, @ 5% of Direct Cost $113,730

Consultant Services/Testing (Boiler Model) 120,000

Contingency, @ 10% of Direct Cost and Engineering $243,382

Total Indirect Costs $636,334

Total Capital Costs $2,910,934

*operating and maintenance (OM) equipment estimates from Alstom Power

**One of the vendors indicated there may be a problem with flame impingement due to the extended flame

from the burner and the small width of the furnace (19'). The cost to install shields or additional refractory

can be quantified only after selection of vendor and burner.

Notes:

1. Principal vendors are Alstom Power and ABB-Ahlstrom

2. Guarantees:

(a) All willing to guarantee greater than 30% reduction (Alstom insistent on 50%–but no bond)

(b) Alstom willing to guarantee 50% for base-loaded boiler at 100% MCR

(c) All unwilling to guarantee any reduction when boiler operates below 70% MCR

ASHDOWN-Q8-000835
E2

Table E2 NOx Monitor and Flow Monitor Installation Costs at Mill H

Quantity Price Cost

Direct Costs

Purchased Equipment Costs*

NOx Monitor 1 $175,000 $175,000

Flow Monitor 1 $25,000 $25,000

Lot Stack Platform Materials 1 $55,000 $55,000

Sales and Construction Taxes (10%) $25,500

Freight (7.5%)** $19,125

Purchased Equipment Costs, Subtotal $280,500

Installation Costs

Lot Foundation/Demolition 0 $0 $0

Structural, tons 4 $5,000 $20,000

Lot Equipment (Includes Stack Platform) 1 $55,000 $55,000

Lot Instrumentation/Electrical* 1 $120,000 $120,000

Installation Costs, Subtotal $195,000

Total Direct Costs $475,500

Indirect Costs

Engineering, @ 7% of Direct Cost $33,285

Construction & Field Expenses***

Contractor

Owner’s Cost, @ 5% of Direct Cost 23,775

Testing**** 20,000

Contingency, @ 15% of Direct Cost and

Engineering

$76,318

Total Indirect Costs $153,378

Total Capital Costs $628,878

*includes programming for NOx Monitor ($50,000) and Flow Monitor ($15,000) from Thermo

Environmental Instruments (formerly STI)

**not included in purchased equipment cost

***crane rental included in Stack Platform installation costs

****includes RATA, Compliance test, QA/QC Manual, and cal-gas

Notes:

1. Principal vendors are Automated Control Systems and Thermo Environmental.

2. Guarantees: all willing to guarantee satisfactory RATA and 95% uptime

3. Cost for Compliance test and RATA is $12,000 per Weston - assume 3.5 /year ($40,000).

ASHDOWN-Q8-000836
E3

Table E3 SNCR NOx Control Installation Costs at Mill H

Quantity Price Cost

Direct Costs

Purchased Equipment Costs

One Lot - (Urea) SNCR System 1 $515,000 $515,000

Structural Materials (Building) 1 $65,000 $65,000

Misc. Materials 1 $25,000 $25,000

Sales and Construction Taxes (10%) $60,500

Freight* $23,000

Purchased Equipment Costs, Subtotal $665,500

Installation Costs

Lot Foundation/Demolition 1 $105,000 $105,000

Structural, tons 0 $5,000 $0

Lot Equipment Installation 1 $240,000 $240,000

Lot Instrumentation/Electrical 1 $105,000 $105,000

Installation Costs, Subtotal $450,000

Total Direct Costs $1,115,500

Indirect Costs

Engineering, @ 7% of Direct Cost $78,085

Construction & Field Expenses --

Contractor --

Owner;s Cost, @ 5% of Direct Cost $55,775

Consultant, Boiler Model $100,000

Contingency, @ 10% of Direct Cost and

Engineering

$119,359

Total Indirect Costs $353,219

Total Capital Costs $1,468,719

*Not included in purchased equipment cost

Notes:

1. Principal vendors are Nalco and Wheelabrator Fuel Tech

2. Guarantees:

(a) all willing to guarantee greater than 30% reduction in addition to LNB & OFA

(b) all willing to guarantee >50% for base loaded boiler at 100% MCR

(c) all unwilling to guarantee any reduction when boiler operates below 70% MCR

(d) none willing to guarantee ammonia slip

ASHDOWN-Q8-000837
E4

Table E4 SCR NOx Control Installation Costs for Mill H

Quantity Price Cost

Direct Costs

Purchased Equipment Costs*

One Lot - SCR System 1 $2,000,000 $2,000,000

Misc. Materials (Includes CRI-Shell catalyst) 1 $900,000 $900,000

Sales and Construction Taxes (10%) $290,000

Freight** $88,000

Purchased Equipment Costs, Subtotal $3,190,000

Installation Costs***

Lot Foundation/Demolition 1 $205,000 $205,000

Structural, tons 55 $5,000 $275,000

Lot Equipment Installation 1 $440,000 $440,000

Lot Instrumentation/Electrical 1 $205,000 $205,000

Installation Costs, Subtotal $1,125,000

Total Direct Costs $4,315,000

Indirect Costs

Engineering, @ 7% of Direct Cost $302,050

Construction & Field Expenses 54,000

Contractor --

Owner’s Cost, @ 5% of Direct Cost $215,750

Contingency, @ 10% of Direct Cost and

Engineering

$461,705

Total Indirect Costs $1,033,505

Total Capital Costs $5,348,505

*not included in purchased equipment cost

**Assume that cost for ammonia feed system will be same as estimated for urea feed and complete

assembly supplied except building for liquid ammonia feed.

***Assume that it is possible to install modular SNR system and duct from ESP and from SCR back

to use the existing stack. This project could require stack replacement, and the location could be

affected by Boiler MACT which is not included in cost estimate.

Notes:

1. Principal vendors are Durr' and Pearless - Both offer fabricated modular systems that include

ammonia feed, fan, ducting, SCR, and complete control systems.

2. Guarantees:

(a) All are willing to guarantee greater than 60% reduction, regardless of boiler load, but both

recommend LNB and OFA installation for dependable benefit.

(b) Both will guarantee <3 ppm ammonia slip with additional (20%) catalyst.

ASHDOWN-Q8-000838