BOILEREMISSIONS

REFERENCE GUIDE

Cleaver Brooks®

Division of Aqua-Chem, Inc.

2nd Edition

BOILER EMISSIONS REFERENCE GUIDETABLE OF CONTENTS

REGULATIONS.................................................................................................................................................2Federal Actions..........................................................................................................................................2

The Clean Air Act ..............................................................................................................................2Clean Air Act Amendment of 1990....................................................................................................2

Title I - National Ambient Air Quality Standards........................................................................2Attainment and Nonattainment..................................................................................................3State Implementation Plans.......................................................................................................5

New Source Performance Standards ...............................................................................................5State Actions ............................................................................................................................................6

Nonattainment Areas.........................................................................................................................6Emission Inventories..........................................................................................................................6State Activities ...................................................................................................................................8

An Emission Alphabet ...............................................................................................................................9BACT (Best Available Control Technology) ......................................................................................9RACT (Reasonably Available Control Technology).........................................................................10LAER (Lowest Achievable Emission Rate) ......................................................................................10

Permits.....................................................................................................................................................10

POLLUTANTS AND CONTROL TECHNIQUESNitrogen Compounds..............................................................................................................................11

Thermal NOx ....................................................................................................................................12Fuel NOx...........................................................................................................................................12

NOx Control Technologies.......................................................................................................................12Post Combustion Control Methods ........................................................................................................12

Selective Non-catalytic Reduction..................................................................................................12Selective Catalytic Reduction .........................................................................................................12

Combustion Control Techniques ............................................................................................................12Low Excess Air Firing ......................................................................................................................13Low Nitrogen Fuel Oil ......................................................................................................................13Burner Modifications .......................................................................................................................13Water/Steam Injection.....................................................................................................................14Flue Gas Recirculation ....................................................................................................................14

External Flue Gas Recirculation...............................................................................................14Induced Flue Gas Recirculation ..............................................................................................14

Side Bar - Choosing the Best NOx Technology for the Job...........................................................14Sulfur Compounds (SOx) .........................................................................................................................16Carbon Monoxide....................................................................................................................................16Particulate Matter ....................................................................................................................................17Ozone.......................................................................................................................................................17Lead .........................................................................................................................................................18

APPENDICESAppendix A: Nonattainment Areas (Listing) ............................................................................................20Appendix B: AP-42 Emission Factors.....................................................................................................25Appendix C: Regional EPA Offices .........................................................................................................27Appendix D: Acronyms............................................................................................................................28Appendix E: Conversion Curves .............................................................................................................29Appendix F: Annual NOx Emission Calculations ......................................................................32

1

IntroductionSince the beginning of time, mankind, flora,

and fauna have been sustained by sunlight, freshwater, and clean air. But fly over many regions ofthe country today, and one will see our cities andmountains shrouded in a dull haze of pollutants.Look upon the horizon and see the sun’s raysreflect a kaleidoscope of colors — grey for lead,yellow for sulphur, brown for nitrogen oxides.

From the Appalachian Mountains, wherebrown tree tops are brittle and burnt from acidrain, to the Great Lakes, where shorelines all toooften appear rimmed by murky mist, to the SanGabriel Mountains, where a natural inversion ofthe atmosphere presses a blanket of smog uponSouthern California, we can’t escape the damage.

Carbon Monoxide, lead, nitrogen oxides,ozone, particulate matter, and sulfur, are nowcited as the most insidious of pollutants. They areproven to contribute to respiratory illnesses inhumans, damage to the environment andbuildings and, ultimately, lead to higher costs forhealth care and environmental cleanup.

Over the past several decades, the culpritpollutants spewed into our environment atincreasing rates. Thus, in the 1980s, alarmedenvironmental activists and coalitions began topressure Congress for stiffer air pollution controlregulations. The result: in 1990, Congress passedits most comprehensive piece of environmentallegislation, the Clean Air Act Amendments (CAAA).

The Boiler Emissions Reference Guide is amulti-purpose tool, which is intended to give youa clearer understanding of how industrial boilersfit into the clean air equation.

In the first part, the guide discusses howfederal and state actions are driving the aircleanup. It discusses air quality standards andareas of attainment and nonattainment for thepollutants. It describes how the government hasset up emission limits for industrial boilers andother equipment. And, it looks at permitting,emission limitations, and BACT, RACT, LAER —the alphabet of control techniques.

The second part of the guide examines the sixmajor pollutants in detail and discusses variouscontrol techniques. Emphasis is placed oncombustion control for industrial boilers and howto choose the best technology.

The guide concludes with special appendices,which provide fingertip information — a mustwhen dealing with a problem as complex as airpollution.

Reg

ulat

ions

REGULATIONSAir pollution regulations are enacted at the

federal level or at the state and local level.Federal regulations, which primarily establishoutdoor, or ambient, air quality standards, are theprimary drivers behind state and local air pollutionregulations. However, with a few exceptions, theNew Source Performance Standards (see page 5for more information), federal regulations only setthe ambient air quality standards. They do notdetail how to accomplish them. The necessaryactions to accomplish the federal standards mustbe developed and implemented by state andlocal air quality agencies. It is the state and localactions, along with the Federal New SourcePerformance Standards, that directly impactindustrial boilers.

FEDERAL ACTIONSThe Clean Air Act

Nearly all air pollution regulations originatefrom the Clean Air Act, which was enacted in1963. The act improved and strengthenedpollution prevention programs and was the firstmajor step toward more federal control of airpollution. The first major amendments to theClean Air Act occurred in 1970. The 1970amendments set national air quality standardsand established performance standards for newsources of pollution. As a result of the 1970amendments, standards were set for sulfuroxides and nitrogen oxides for several sources,including boilers.

The next significant amendment to the CleanAir Act occurred in 1977. The 1977 amendmentenhanced many aspects of the Clean Air Act byimplementing a more comprehensive permitprogram, establishing emission limitations onexisting sources, and imposing stricter emissionstandards on new sources. But most importantly,the 1977 amendment extended compliancedeadlines because many geographical areas hadnot achieved compliance with the ambient airquality standards. After regulating air pollutionfor almost 15 years, nationwide compliance stillhad not been achieved.

The most recent amendment to the Clean AirAct occurred in 1990. The 1990 Clean Air ActAmendment has been labelled the most complex,comprehensive, and far-reaching environmentallaw Congress has ever enacted. The 1990amendments consist of 11 titles. Some of thetitles are revisions of existing titles and others arenew titles. As a result, the Clean Air Act nowencompasses most aspects of air pollution.

The act:

• Controls air pollution from stationary and mobile sources

• Controls the release of air toxins

• Controls acid rain pollutants (NOx and SOx)

• Establishes a massive permit program

• Sets-up enforcement provisions

• Establishes many miscellaneous programs

The Clean Air Act Amendment of 1990The Clean Air Act, its interpretations and

associated implications, are very complex. Itwould be impractical to list the details of theamendment and the requirements for futureactivity that the federal government dictates forstate governments. For this reason, this sectionprovides basic insight into the implications theact poses for fossil-fuel fired packaged boilers.

As mentioned earlier, the 1990 Clean Air ActAmendment is comprised of 11 titles (see Figure1). The provisions contained in the titles have thepotential to affect nearly every source of airpollution. Although several titles affect industrialboilers, the title having the most impact is Title I,Attainment and Maintenance of the NationalAmbient Air Quality Standards.

Title I - National Ambient Air QualityStandards

The National Ambient Air Quality Standards(NAAQS) are pollution standards set by the federalEnvironmental Protection Agency (EPA) through theClean Air Act. The NAAQS set ambient pollutantstandards to address six ‘criteria’ pollutants(see Figure 2):

• Ozone (O3)

• Carbon Monoxide (CO)

• Nitrogen Dioxide (NO2)

• Sulfur Dioxide (SO2)

• PM10 (particulate matter with a diameter of less than 10 microns)

• Lead

The NAAQS are designed to protect humans andthe environment from the adverse effects of airpollutants. Unlike emission limitations, whichspecify allowable pollutant releases from airpollution sources, ambient standards set forthmaximum allowable concentrations of pollutantsin the outdoor, or ambient, air. The Clean Air Actsets specific deadlines for every area in thecountry not in compliance with the NAAQS toenact regulations for achieving these standards.

2

Attainment and Nonattainment

Through the NAAQS, areas of the United Statesare designated as attainment and nonattainment.Simply put, areas with ambient pollutant levelsbelow the NAAQS are in attainment. Areas withpollutant levels above the NAAQS are innonattainment.

Note: Attainment/Nonattainment designation ismade on a pollutant-by-pollutant basis for allpollutants included in the NAAQS. Therefore, anarea can be designated as attainment andnonattainment because it may be in compliancewith the NAAQS for one pollutant but not another.

The most common pollutant for which theNAAQS are exceeded is ozone. Ozone is notemitted directly from smokestacks, tailpipes, orother pollution sources. Instead, it is formed bythe reaction of volatile organic compounds(VOCs) and nitrogen oxides (NOx) in the presenceof sunlight. NOx and VOCs are released into theair by automobiles, factories, and several othersources, including industrial boilers. As ofJanuary, 1994, there are 101 cities and townsviolating the NAAQS for ozone (see Figure 3).Ozone nonattainment areas are classified intoone of five categories, based on the amount by

3

Title I - Attainment and Maintenance of theNational Ambient Air Quality Standards: Deals withattaining and maintaining the National Ambient AirQuality Standard (NAAQS) for six criteria pollutants.

Title II - Mobile Sources: Establishes stricter emissionstandards for motor vehicles.

Title III - Hazardous Air Pollutants: Identifies andcalls for reductions in 189 toxic pollutants.

Title IV - Acid Deposition Control: Addresses NOxand SO2 reduction in large utility boilers (major sources).Regulations for industrial units will be developed shortly.

Title V - Permits: Establishes a comprehensiveoperating permit program for air emissions.

Title VI - Stratospheric Ozone Protection: Requiresa complete phase-out of chlorofluorocarbons (CFCs)and halons.

Title VII - Enforcement: Gives the EPA moreadministrative enforcement penalties. It is now a felonyto knowingly violate the Clean Air Act.

Title VIII - Miscellaneous: Addresses oil drilling andvisibility provisions.

Title IX - Clean Air Research: Addresses air pollutionresearch in the areas of monitoring and modeling, healtheffects, ecological effects, pollution prevention, emissioncontrol, and acid rain.

Title X - Disadvantaged Business Concerns:Requires that a portion of federal funds for air researchgo to disadvantaged firms.

Title XI - Clean Air Employment TransitionAssistance: Provides additional unemployment benefitsto workers for retraining who are laid off because ofcompliance with the Clean Air Act.

■ 1990 CAAA Titles

figure 1

figure 2

■ National Ambient Air Quality Standards (NAAQS)

Averaging Time

Pollutant 1 hour 8 hour 24 hour Annual Calendar Quarter

Ozone 0.12 ppm

Carbon Monoxide 35 ppm 9 ppm

Nitrogen Dioxide 0.053 ppm

Sulfur Dioxide 0.14 ppm 0.03 ppm

PM10 0.000066 grains/ft3

Lead 0.00000066 grains/ft3

The National Ambient Air Quality Standards are ambient emission standards set by the Federal EPA for six criteria pollutants. Theambient levels are measured on a time average basis by air pollution monitoring stations located throughout the country. Forexample, the ambient level of ozone must not exceed 0.12 ppm for any one hour period in order for the local area to beincompliance with the NAAQS for ozone.

Reg

ulat

ions

which the local ozone levels exceed the NAAQS.From highest to lowest degree of nonattainment,the categories are: extreme; severe; serious;moderate; and marginal.

The second most common nonattainmentpollutant is carbon monoxide. As of January,1994, 52 metropolitan areas exceed the NAAQSfor carbon monoxide (see Figure 4). Carbonmonoxide nonattainment areas are classified as

serious and moderate, depending on the amountlocal CO levels exceed the NAAQS for CO.

Although the number of nonattainment areasare not as great as they are for ozone and carbonmonoxide, there are several areas violating theNAAQS for PM10, NOx, SOx, and lead. Areasviolating the NAAQS for PM10 are subclassified asserious or moderate. There are no subclassificationsfor NOx, SOx, and lead.

4

Extreme & Severe

Serious

Moderate

Marginal

Classified Ozone Nonattainment Areas

New York

Raleigh

San Diego El PasoBatonRouge

BirminghamDallas

Houston

St. Louis

Indianapolis

Salt Lake City

Kansas CitySan Francisco

Milwaukee

Seattle

Portland

Reno

Los Angeles(Serious)

Atlanta

Miami

Nashville

Louisville Charleston

Washington

Boston

Buffalo

Detroit

Cincinnati

Phoenix

Transitional & IncompleteData Areas Not Included

Youngstown

figure 3

figure 4

Serious & Moderate > 12.7 ppm

Moderate < = 12.7 ppm

Classified Carbon Monoxide Nonattainment Areas

Seattle

Spokane

Portland

Medford

Fresno

Phoenix

AlbuquerqueMemphis

Minneapolis

Duluth

ClevelandBaltimore

Ogden

El Paso

New York

BostonSyracuse

Raleigh

Denver

Colorado SpringsProvo

LasVegas

RenoLake

Tahoe

San Diego

Fairbanks

San Francisco

Los Angeles(Serious)

Not Classified Areas Excluded

A listing of the ozone, CO, PM10, and SO2

nonattainment areas as of January, 1994 isincluded in Appendix A. The classifications ofareas are constantly changing as air pollutionlevels are continuously under review forattainment/nonattainment designation. For themost current attainment/nonattainment classification, contact your localair pollution control agency.

State Implementation PlansThrough the NAAQS, the EPA has established

pollution standards for six criteria pollutants.However, the NAAQS are only an interim step inthe regulation of these pollutants. The ambientstandards do not tell an individual polluter whatmust be done to control their emissions. Rather,Title I of the 1990 Clean Air Act Amendmentsdelegates the responsibility to the states byrequiring local nonattainment areas to develop aplan to reduce ambient pollution levels below theNAAQS.

Nonattainment characteristics vary by areaand pollutant. A nonattainment area can beaffected by weather, geography, demographics,and other forces. Therefore, regulationsestablished for one area may not be effective inanother area. This is why the Federal EPA doesnot establish general, source-specific regulationsfor all nonattainment areas. The responsibility isassigned to the states. The states are required todevelop State Implementation Plans, or SIPs.SIPs include regulations addressing individualpollution sources in order to achieve the pollutantreductions necessary to comply with the NAAQS.

SIPs must address several elements of airpollution control as required by the EPA. Theelements include:

• Attainment of the NAAQS withinspecified deadlines

• Emission limitations for individual sources

• Monitoring provisions

• Permit programs

• Several miscellaneous provisions

A SIP is developed as follows. Stateregulation developers draft the SIP. Then itundergoes public comment. Next, it is submittedto the EPA for review. The EPA has establishedsubmittal dates for the SIPs, which varydepending on the nonattainment status of thelocal area. Many states have missed thedeadlines and are still developing their SIPs.Figure 5 shows the EPA SIP submittal dates.

Once the EPA reviews the SIP, it is eitherapproved or, if it fails to fulfill all requirements, theplan could be returned to the state for revision, orthe EPA could draft a plan or portions of the planfor the state.

Note: You can obtain a copy of the sections of anySIP applying to industrial boilers by contactingyour state air quality agency. It is important tobecome familiar with the SIP in your state, as theprovisions within the SIP may directly impactindustrial boilers.

New Source Performance StandardsOne situation where the Federal EPA has

established nationally uniform source-specificregulations is through the New SourcePerformance Standards, or NSPS. The standards,which set minimal requirements for individualsources, address approximately 65 categories ofnew or modified stationary sources, includingindustrial boilers. However, because the NSPSare not based on the nonattainment status of thelocal area, they may result in over control in somelocations and under control in others.

5

figure 5

Lead

Nitrogen Oxides

Sulfur Dioxide

Serious

Moderate

Serious

Moderate

Ozo

neC

arbo

nM

onox

ide

PM

10

Extreme

Severe II

Severe I

Serious

Moderate

Marginal(11/15/93)

(11/15/93)

(11/15/96)

(11/15/94)

(11/15/94)(11/15/05)

(11/15/94)

(11/15/94)

(11/15/07)

(11/15/10)

(11/15/92)(12/31/95)

(12/31/00)(11/15/92)

(11/15/91)

(11/15/91)(12/31/01)

(12/31/94)

(5/15/92)

(5/15/92)

(11/15/95)

(11/15/95)

(6/6/93)(11/15/95)

(11/15/99)

Year

State Implementation Plan (SIP)Submittal Dates

SIP Submittal PeriodAttainment Compliance Period

Reg

ulat

ions

The NSPS for industrial boilers regulate levelsfor NOx, SOx, and particulate matter. Theregulated pollutants and requirements vary fordifferent fuels and boiler sizes. There arecurrently three categories for the NSPS:

• Boilers with inputs greater than250 MMBtu/hr

• Boilers with inputs between100-250 MMBtu/hr

• Boilers with inputs between10-100 MMBtu/hr

The current Small Boiler NSPS apply to allnew, modified, or reconstructed boilers withinputs between 10-100 MMBTU/hr whereconstruction, modification, or reconstructioncommenced after June 9, 1989. They setemission standards for SOx and particulatematter for boilers firing coal, distillate andresidual oil, and wood. The NSPS also dictaterecord keeping requirements regarding fuelusage for all fuels, including natural gas. Recordkeeping requirements and compliance standardsfor the different emissions depends on the typeof fuel fired and on the boiler size. For a summaryof the Small Boiler NSPS, see Figure 6.

Expect to hear more about the NSPS. The1990 Clean Air Act Amendments require the EPA toreview the current NSPS and modify the requirementsto incorporate new technologies for several sourcecategories addressed through the NSPS.

STATE ACTIONS Nonattainment Areas

Air quality monitoring stations operatethroughout the United States to assess local airquality. Readings are continuously taken fromthe stations to monitor the six criteria pollutantsregulated through the NAAQS. The levels of thepollutants are continuously evaluated. If levelsexceed the NAAQS, the area is classified asnonattainment.

States must determine the boundaries ofnonattainment areas through the use of the datacollected. The boundaries of nonattainment andattainment areas can be difficult to define. Forexample, because of the high population in thenortheastern United States and the closeproximity of major cities, an ozone nonattainmentarea may enact regulations to bring the area intocompliance. But because of the influence of thesurrounding cities, attainment may not beachieved. Ozone nonattainment areas in thenortheast are forming alliances to develop

regulations because of the influence of pollutionfrom a broad area. For example, uniformregulations are being developed for eleven states(Connecticut, Delaware, Maine, Maryland,Massachusetts, New Hampshire, New Jersey,New York, Pennsylvania, Rhode Island, andVermont) in what is designated by the FederalEPA as the Northeast Ozone Transport Region.

Emission InventoriesOnce a nonattainment area is defined, the

pollution sources are identified and the quantityof emissions from the sources are evaluated. Tohelp states determine the types and levels ofemissions for the various sources, the EPA hasestablished the AP-42 Compilation of AirPollutant Emission Factors. The documentindicates average emission levels emitted byvarious equipment and industries. Once theindividual sources in a nonattainment area havebeen identified, the AP-42 can be used todetermine the type and level of emissions. Theemission inventory is a valuable tool, which canbe used to evaluate different regulatory actionsand to calculate the reduction of emissions andthe impact on the total emissions.

The average emission levels in AP-42 havesometimes been used as a standard forequipment performance by regulators who areunfamiliar with the equipment. Using the AP-42levels as pollution standards is not the intent ofthe AP-42. The AP-42 was developed to providea “rule-of-thumb” to estimate emissions for abroad category of equipment. Specific emissionlevels for sites need to be evaluated on a site-specific basis, as the AP-42 states. And becausethe AP-42 is based on averages, half of the sitesreviewed and half of the applications exceed thepollutant levels in the AP-42. In fact, fewapplications are below all the pollutant averageslisted in the AP-42.

Note: Because few applications are belowall the pollutant levels listed the AP-42, the AP-42emission levels should not be used to permitboilers. The boiler/burner manufacturer should becontacted to obtain the emissions levels thatshould be used to permit the boiler.

Appendix B shows the AP-42 emission levelsfor industrial boilers firing natural gas, distillateand residual oils, and propane.

6

7

Summary of Federal EPA RulesNEW SOURCE PERFORMANCE STANDARDS

For Boilers 10-100 MMBtu/hr,built or modified after 6-9-1989

RULES FOR SULFUR DIOXIDE (SO2) EMISSIONS

1. Coal Firing• 1.2 lb SO2/MMBtu Limit all 10-100 MMBtu.• 90% SO2 reduction required if > 75 MMBtu and > 55% annual coal capacity.• Initial performance testing required within 180 days of start-up.• 30 day rolling average used in calculations.• Continuous Emission Monitoring System (CEMS) required except:

- Fuel analysis may be used (before cleanup equipment).- Units < 30 MMBtu may use supplier certificate for compliance.

2. Residual Oil Firing• Limit of 0.5 lb SO2/MMBtu or 0.5% sulfur in fuel.• CEMS required to meet SO2 limit except fuel analysis can be used as fired condition before cleanup

equipment.• Fuel sulfur limit compliance can be:

- Daily as fired fuel analysis.- As delivered (before used) fuel analysis.- Fuel supplier certificate for units < 30 MMBtu.

• Initial performance testing and 30 day rolling average required except for supplier certificate.

3. Distillate Oil Firing (ASTM grades 1 and 2)• Limit 0.5% sulfur in fuel (required in ASTM standard).• Compliance by fuel supplier certificate.• No monitoring or initial testing required.

RULES FOR PARTICULATE MATTER (PM) EMISSIONS

1. General• Limits established only for units between 30-100 MMBtu.• All coal, wood and residual oil fired units > 30 MMBtu must meet opacity limit of 20%, except

one 6 minute/hour opacity of 27%. CEMS required to monitor opacity.

2. Coal Firing• 0.05 lb/MMBtu limit if > 30 MMBtu and > 90% annual coal capacity.• 0.10 lb/MMBtu limit if > 30 MMBtu and < 90% annual coal capacity.• 20% opacity (CEMS) and initial performance tests on both PM limit and opacity.

3. Wood Firing• 0.10 lb/MMBtu limit if > 30 MMBtu and > 30% annual wood capacity.• 0.30 lb/MMBtu limit if > 30 MMBtu and < 30% annual wood capacity.• Opacity limits and initial testing per above.

4. Oil Firing• All units > 30 MMBtu subject to opacity limit, only residual oil firing must use CEMS.• Initial performance testing required.

REPORTING REQUIREMENTS

• Owners or operators of all affected units must submit information to the administrator, even if they arenot subject to any emission limits or testing. Required reports include:- Information on unit size, fuels, start-up dates and other equipment information.- Initial performance test results, CEMS performance evaluation.- Quarterly reports on SO2 and/or PM emission results, including variations from limits andcorrective action taken.

- For fuel supplies certificate, information on supplies and details of sampling and testing forcoal and residual oil.

- Records must be maintained for two years.

figure 6

Reg

ulat

ions

State ActivitiesAll of the activities mentioned earlier

eventually will result in some form of regulationfor areas classified as nonattainment. While it isimpossible to predict what any given state willdo, it appears that many are following the lead ofSouthern California. Southern California has theworst air quality in the United States. Their effortstoward cleaner air are usually considered to bethe basis for establishing regulations in otherareas of the country in high degrees of ozonenonattainment.

Regulations will change as new technologiesallow for lower emission levels. Also, adjustmentswill be made based on the improvements in airquality. It is necessary to stay involved with airquality regulations to keep appraised of anyregulation changes.

The application of regulations can takeseveral different forms and is often based on thedegree of nonattainment. Required controls arebased on the size of equipment, total emissionsfrom a facility, type of fuels used, or acombination of factors. For example, in ozonenonattainment areas, the required measuresdepend on the nonattainment degree and totalemissions from the facility. Levels set by the EPAhelp identify ‘major’ sources of VOCs and NOx

emissions. If the total NOx or VOC emissions for afacility located in an ozone nonattainment areaexceed the pre-established major source trigger

levels, extensive computer modeling and stringentregulations may be necessary. The major sourcetrigger levels are indicated in tons per year andapply to the total NOx or VOC emissions for allsources located at the facility. The major sourcetrigger levels for the different ozone nonattainmentclassifications are shown in Figure 7.

To put this in perspective, a facility with three800 horsepower boilers firing natural gas 24hours per day, 365 days per year, would result inan uncontrolled NOx level of 57 tons per year(based on a NOx level of 0.13 lb/MMBtu).Referring to major source trigger levels specifiedin Figure 7, consider the following. If the facility islocated in a moderate or marginal ozonenonattainment area, it is not a major source. But,if it is located in a serious, severe, or extremeozone nonattainment area, it is a major sourceand would have specific air quality NOx controlrequirements. These requirements may include:

• An extensive permit application

• Dispersion modeling

• Procurement of emission offsets

• Stringent emission limitations

• Continuous emission monitoring equipment

• Extensive emission controls

• Detailed fuel usage recording

8

figure 7

0

50

100

150

200

250

ExtremeSevereSeriousModerateMarginalAttainment

Ozone Nonattainment AreasMajor Source Levels

Ozone Nonattainment Status

Ann

ual N

Ox

Em

issi

ons

(tpy)

BACT/RACT Cost Effectiveness

Annualized Costs of Control Equipment*

Uncontrolled Emission — Controlled EmissionRate Rate

Example:

Uncontrolled Emission Rate = 18 tons/year

Controlled Emission Rate = 4 tons/year

Annualized Cost of Emission

Control Method = $50,000/year

$50,000

18 tpy - 4 tpy

* considering hardware, installation, operating and maintenance costs

An Emission AlphabetIf a facility is classified as a major source,regulations may require technology equivalent to:

• Best Available Control Technology (BACT)

• Lowest Achievable Emission Rate (LAER)

• Reasonably Available Control Technology (RACT)

All three regulations are based on technology anddo not directly specify an emission levelrequirement. Instead, they require an evaluationof each affected facility in order to determine theapplicable emission and technology requirements.As new technologies are developed, which mayresult in greater emission reductions thancurrently available, they must be included in theevaluation. Technology-based regulations havebeen utilized for years and proven effective.

Best Available Control TechnologyBest Available Control Technology (BACT) is

a regulation requiring an evaluation of all currenttechnologies to determine the emission limitationfor a new source. It is established on a case-by-case basis for sources and takes into accountenergy, environmental, and economic impacts.BACT evaluates the effectiveness of a controltechnology against the cost of the technology.

In establishing BACT for a source, cost is usuallythe driving factor. The cost of the equipment iscompared to the annual emission reductions inorder to determine a figure in dollars per ton ofpollutant removed (see Figure 8). The comparisonis called the cost effectiveness of the technology.

The regulations requiring BACT set a maximumcost figure that the polluter can spend in order tomeet local emission requirements. If the costeffectiveness of the technology is above thefigure, the technology is not required and thenext lower cost technology is evaluated. Theprocess of reviewing each technology indecreasing order of cost is called Top DownBACT. The Top Down BACT process assures thatthe source achieves the lowest emission levelwithin the required cost effectiveness.

Typical regulations in areas of moderate andserious nonattainment for ozone require boilerowners to utilize NOx control technologies thatresult in a cost effectiveness figure between$3,000-$10,000 per ton of NOx removed. Insevere and extreme ozone nonattainment areas,the required cost effectiveness can be as high as$24,500 per ton of NOx controlled.

9

figure 8

= $3,571/ton of NOx removed

Reg

ulat

ions

Reasonably Available Control TechnologyReasonably Available Control Technology

(RACT) is similar to BACT in that costeffectiveness is associated with the boiler owners'emission requirements. The difference is thatRACT is utilized on existing sources while BACTis used on new or modified sources. The costrequirements for RACT are less than BACT; RACTis intended to be available at a ‘reasonable’ cost.

Many states with ozone nonattainment areashave submitted proposed RACT regulations tothe EPA for approval as part of the SIPrequirements. Many of the regulations setemission limitations from industrial boilers thatcan be achieved through burning cleaner fuels(i.e., natural gas), utilizing low NOx technologies,or a combination of both. Owners of industrialboilers located in ozone nonattainment areasshould be familiar with the RACT requirements intheir states.

Lowest Achievable Emission Rates Some regulations require technology

equivalent to the Lowest Achievable EmissionRate (LAER) be utilized in new major sourceslocated in nonattainment areas. LAER is differentfrom BACT in that it has no economic justificationassociated with its requirements. When required,technology equivalent to LAER must be installedregardless of costs impacts. It is the moststringent of all technology-based regulations.

PermitsThe permit program established under Title V

of the 1990 Clean Air Act Amendments willundoubtedly affect the way each state conductsits permitting process. Title V requires a review(and most likely a revision) of each state’spermitting program in order to ensure that thestate’s permit program meets all Federal EPArequirements. Elements of state permit programsthat could be affected include:

• The permit application process

• Monitoring and reporting requirements

• Permit renewal process

• Several other permitting issues

By November of 1993, states were required tosubmit proposed permitting programs to theEPA. By November of 1994, the EPA mustapprove or disapprove the proposed permitprograms. The new permit programs will go intoeffect when approved by the EPA or the EPA

promulgates a program for states failing tosubmit a satisfactory program.

Currently, several states have implemented atwo-stage permitting process. In the first stage, apermit to construct must be obtained. The permitusually requires a detailed description of theinstallation, including information such as thetype and size of equipment and associatedemissions. The second stage of the permitprocess consists of obtaining an operating permit.In some states, emission testing may be part ofthe requirement for obtaining an operating permit.

Although many states may have the samebasic permitting structure, the details andrequirements of the permitting process aredifferent for each state. It is important to beaware of not only the state permittingrequirements, but also any federal requirements(i.e., Small Boiler New Source PerformanceStandards) that may be applicable. It isparticularly important to be familiar with thepermitting process as the new federal and stateprograms are implemented. Nearly every sourceof air pollution will be affected. Any violators mayface stiff penalties.

10

POLLUTANTS ANDCONTROL TECHNIQUES

A pollutant can be defined as matter thatcontaminates air, soil, or water. Air pollutants areairborne contaminants that produce unwantedeffects on humans and the environment. Theyoccur as solids, liquid droplets, gases, orcombinations of these forms. Generally, airpollutants are classified into two major categories:

• Primary Pollutants -pollutants emitted directly fromidentifiable sources

• Secondary Pollutants -pollutants formed by interaction betweentwo or more primary pollutants

To protect humans and the environment fromthe adverse effects of air pollutants, the EPA hasestablished the National Ambient Air QualityStandards (see Figure 2, page 3). The Clean AirAct Amendments of 1990 require areas innoncompliance for one or more of the NAAQSpollutants to implement regulations to reduceambient levels. All six pollutants addressed inthe National Ambient Air Quality Standards aredirectly or indirectly related to the combustionprocess. The following sections describe theformation and control of the pollutants inindustrial boilers, discuss their impact on humansand the environment, and describe the currentemission control technologies.

Nitrogen Compounds

Although there is evidence proving NOx, initself, is harmful to humans, the main reason NOx

is considered an environmental problem isbecause it initiates reactions that result in theproduction of ozone and acid rain. Ozone andacid rain can damage fabric, cause rubber tocrack, reduce visibility, damage buildings, harmforests and lakes, and cause health problems. Bycontrolling NOx levels, along with other contributingprimary pollutants, the levels of acid rain andozone can be reduced.

The principal nitrogen pollutants generatedby boilers are nitric oxide (NO) and nitrogendioxide (NO2), collectively referred to as NOx. Themajority of NOx produced during combustion isNO (95%). Once emitted into the atmosphere, NOreacts to form NO2. It is NO2 that reacts withother pollutants to form ozone.

The contribution from different NOx sourcesto the total NOx levels varies among metropolitanareas. In general, the contribution of mobile

sources to the total NOx level ranges from 60 to80 percent: For stationary sources, it rangesbetween 20 and 40 percent. A significant portionof the NOx from stationary sources can beattributed to residential, commercial, andindustrial sources, including industrial boilers. Inindustrial boilers, NOx is primarily formed in twoways; thermal NOx and fuel NOx.

Thermal NOx

Thermal NOx is formed when nitrogen andoxygen in the combustion air combine withone another at the high temperatures in aflame. Thermal NOx makes up the majority ofNOx formed during the combustion of gasesand light oils.

Fuel NOx

Fuel NOx is formed by the reaction ofnitrogen in the fuel with oxygen in thecombustion air. It is rarely a problem withgaseous fuels. But in oils containingsignificant amounts of fuel-bound nitrogen,fuel NOx can account for up to 50% of thetotal NOx emissions.

NOx emissions from boilers are influenced bymany factors. The most significant factors areflame temperature and the amount of nitrogen inthe fuel. Other factors affecting NOx formation areexcess air level and combustion air temperature.

While flame temperature primarily affectsthermal NOx formation, the amount of nitrogen inthe fuel determines the level of fuel NOx

emissions. Fuel containing more nitrogen resultsin higher levels of NOx emissions (see Figure 9).Most NOx control technologies for industrialboilers, with inputs less than 100 MMBtu/hr,reduce thermal NOx and have little affect on fuelNOx. Fuel NOx is most economically reduced incommercial and industrial boilers by switching tocleaner fuels, if available.

NOx Control TechnologiesNOx controls can be classified into two types;

post combustion methods and combustioncontrol techniques. Post combustion methodsaddress NOx emissions after formation whilecombustion control techniques prevent theformation of NOx during the combustion process.Post combustion methods tend to be moreexpensive than combustion control techniquesand generally are not used on boilers with inputsof less than 100 MMBtu/hr. Following is a list ofdifferent NOx control methods.

11

Pollu

tant

s and

Con

trol

Tec

hniq

ues

Pollu

tant

s and

Con

trol

Tec

hniq

ues

Post Combustion Control Methods

Selective Non-Catalytic Reduction

Selective Catalytic Reduction

Combustion Control Techniques

Low Excess Air Firing

Low Nitrogen Fuel Oil

Burner Modifications

Water/Steam Injection

Flue Gas Recirculation

Each method results in a different degree ofNOx control. For example, when firing natural gas,low excess air firing typically reduces NOx by10%, flue gas recirculation by 75%, and selectivecatalytic reduction by 90%.

Post Combustion Control MethodsSelective Non-catalytic Reduction

Selective non-catalytic reduction involves theinjection of a NOx reducing agent, such asammonia or urea, in the boiler exhaust gases at atemperature of approximately 1400-1600°F (seeFigure 10). The ammonia or urea breaks down theNOx in the exhaust gases into water andatmospheric nitrogen. Selective non-catalyticreduction reduces NOx up to 50%. However, thetechnology is extremely difficult to apply toindustrial boilers that modulate frequently. This isbecause the ammonia (or urea) must be injectedin the flue gases at a specific flue gastemperature. And in industrial boilers that

modulate frequently, the location of the exhaustgases at the specified temperature is constantlychanging. Thus, it is not feasible to applyselective non-catalytic reduction to industrialboilers that have high turndown capabilities andmodulate frequently.

Selective Catalytic Reduction

Selective catalytic reduction involves theinjection of ammonia in the boiler exhaust gasesin the presence of a catalyst (see Figure 11). Thecatalyst allows the ammonia to reduce NOx levelsat lower exhaust temperatures than selectivenon-catalytic reduction. Unlike selective non-catalytic reduction, where the exhaust gasesmust be approximately 1400-1600°F, selectivecatalytic reduction can be utilized where exhaustgases are between 500° and 1200°F, dependingon the catalyst used. Selective catalytic reductioncan result in NOx reductions up to 90%. However,it is costly to use and rarely can be cost justifiedon boilers with inputs less than 100 MMBtu/hr.

Combustion Control TechniquesCombustion control techniques reduce the

amount of NOx emission by limiting the amount ofNOx formation during the combustion process.This is typically accomplished by lowering flametemperatures. Combustion control techniques aremore economical than post combustion methodsand are frequently utilized on industrial boilersrequiring NOx controls.

12

Fuel-Bound Nitrogen (% weight)

NO

x E

mis

sio

ns

(pp

m a

t 3%

O2)

Effects of Fuel-Bound Nitrogen on NOx Emissions for Fuel Oils

Incr

easi

ng

Increasing

0

0

figure 9

Low Excess Air (LEA) Firing

As a safety factor to assure completecombustion, boilers are fired with excess air. Oneof the factors influencing NOx formation in aboiler is the excess air levels. High excess airlevels (>45%) may result in increased NOx

formation because the excess nitrogen andoxygen in the combustion air entering the flamewill combine to form thermal NOx. Low excess airfiring involves limiting the amount of excess airthat is entering the combustion process in orderto limit the amount of extra nitrogen and oxygenthat enters the flame. Limiting the amount ofexcess air entering a flame is usually accomplishedthrough burner design and can be optimizedthrough the use of oxygen trim controls. Lowexcess air firing can be used on most boilers andgenerally results in overall NOx reductions of 5-10%when firing natural gas.

Low Nitrogen Fuel Oil

When firing fuel oils, NOx formed by fuel-bound nitrogen can account for 20-50% of thetotal NOx level. Utilizing fuel oils with lowernitrogen contents results in lower NOx levels.One method to reduce NOx levels from boilersfiring distillate oils is through the use of lownitrogen fuel oil. Low nitrogen oils can contain upto 15-20 times less fuel-bound nitrogen thanstandard No. 2 oil (less than 0.001% fuel-boundnitrogen). When low NOx oil is fired in firetubeboilers utilizing flue gas recirculation, NOx

reductions of 60%-70% over NOx emissions fromstandard No. 2 oils have been achieved. Lownitrogen oil is currently used most frequently inSouthern California.

Burner Modifications

Burner modifications for NOx control involvechanging the design of a standard burner in order

13

figure 10

Selective Non-Catalytic Reduction (SNCR)Flue Gas Temperature

1400 - 1600°FAmmonia

FlueGas

CleanGas

NOx N2

N2NOx

NOxNH3

NH3 H2O

H2O

H2ONH3

NOx

✖

✖

✖

figure 11

Selective Catalytic Reduction (SCR)CatalystAmmonia

FlueGas

CleanGas

NOx N2

N2NOx

NOxNH3

NH3 H2O

H2O

H2ONH3

NOx

✖

✖

✖

Pollu

tant

s and

Con

trol

Tec

hniq

ues

to create a larger flame. Enlarging the flame resultsin lower flame temperatures and lower thermalNOx formation which, in turn, results in loweroverall NOx emissions. The technology can beapplied to most boiler types and sizes. It is mosteffective when firing natural gas and distillate fueloil and has little affect on boilers firing heavy oil.To comply with the more stringent regulations,burner modifications must be used in conjunctionwith other NOx reduction methods, such as fluegas recirculation. If burner modifications areutilized exclusively to achieve low NOx levels(30 ppm), adverse affects on boiler operatingparameters such as turndown, capacity, CO levels,and efficiency may result. It is important toaddress all aspects of NOx control when selectingNOx control technologies (see Side Bar, this page).

Water/Steam Injection

Water or steam injection can be utilized toreduce NOx levels. By introducing water or steaminto the flame, flame temperatures are reduced,thereby lowering thermal NOx formation andoverall NOx levels. Water or steam injection canreduce NOx up to 80% (when firing natural gas)and can result in lower reductions when firingoils. There is a practical limit to the amount ofwater or steam that can be injected into the flamebefore condensation problems are experienced.Additionally, under normal operating conditions,water/steam injection can result in a 3-10%efficiency loss. Many times water or steaminjection is used in conjunction with other NOx

control methods such as burner modifications orflue gas recirculation.

Flue Gas Recirculation

Flue gas recirculation, or FGR, is the mosteffective method of reducing NOx emission fromindustrial boilers with inputs below 100 MMBtu/hr.FGR entails recirculating a portion of relativelycool exhaust gases back into the combustionzone in order to lower the flame temperature andreduce NOx formation. It is currently the mosteffective and popular low NOx technology forfiretube and watertube boilers. And, in manyapplications, it does not require any additionalreduction equipment to comply with the moststringent regulations in the United States.

Flue gas recirculation technology can beclassified into two types; external or induced.

External flue gas recirculation utilizes anexternal fan to recirculate the flue gases backinto the combustion zone. External pipingroutes the exhaust gases from the stack to

the burner. A valve controls the recirculationrate, based on boiler input.

Induced flue gas recirculation utilizes thecombustion air fan to recirculate the flue gasesback into the combustion zone. A portion ofthe flue gases are routed by duct work orinternally to the combustion air fan, where theyare premixed with the combustion air andintroduced into the flame through the burner.New designs of induced FGR that utilize anintegral FGR design are becoming popularamong boiler owners and operators becauseof their uncomplicated design and reliability.

Theoretically, there is no limit to the amountof NOx reduction with FGR; practically, there is aphysical, feasible limit. The limit of NOx reductionvaries for different fuels - 80% for natural gas and20-25% for standard fuel oils. When firing naturalgas, typical NOx reductions are 45% with 10%recirculation and 75% with 20% recirculation.

The current trends with low NOx technologiesare to design the boiler and low NOx equipmentas a package. Designing as a true packageallows the NOx control technology to bespecifically tailored to match the boiler’s furnacedesign features, such as shape, volume, and heatrelease. By designing the low NOx technology asa package with the boiler, the effects of the lowNOx technology on boiler operating parameters(turndown, capacity, efficiency, and CO levels)can be addressed and minimized.

SIDE BAR:CHOOSING THE BEST NOXTECHNOLOGY FOR THE JOBWhat effect does NOx control technologyultimately have on a boiler’s performance? CertainNOx controls can worsen boiler performance whileother controls can appreciably improve performance.Aspects of the boiler performance that could beaffected include turndown, capacity, efficiency,excess air, and CO emissions.

Failure to take into account all of the boileroperating parameters can lead to increasedoperating and maintenance costs, loss ofefficiency, elevated CO levels, and shortening ofthe boiler’s life.

The following section discusses each of theoperating parameters of a boiler and how theyrelate to NOx control technology.

14

15

TURNDOWN

Choosing a low NOx technology that sacrificesturndown can have many adverse effects on theboiler. When selecting NOx control, the boilershould have a turndown capability of at least 4:1or more, in order to reduce operating costs andthe number of on/off cycles. A boiler utilizing astandard burner with a 4:1 turndown can cycle asfrequently as 12 times per hour or 288 times aday because the boiler must begin to cycle atinputs below 25% capacity.

With each cycle, pre- and post-purge air flowremoves heat from the boiler and sends it out thestack. The energy loss can be reduced by using ahigh turndown burner (10:1), which keeps theboiler on at low firing rates.

Every time the boiler cycles off, it must gothrough a specific start-up sequence for safetyassurance. It takes about one to two minutes toget the boiler back on line. If there is a suddenload demand, the response cannot be accelerated.Keeping the boiler on line assures a quickresponse to load changes.

Frequent cycling also deteriorates the boilercomponents. Maintenance increases, the chanceof component failure increases, and boilerdowntime increases. So, when selecting NOx

control, always consider the burner’s turndowncapability.

CAPACITY

When selecting the best NOx control, capacity andturndown should be considered together becausesome NOx control technologies require boilerderating in order to achieve guaranteed NOx

reductions. For example, flame shaping (primarilyenlarging the flame to produce a lower flametemperature - thus lower NOx levels) can requireboiler derating, because the shaped flame couldimpinge on the furnace walls at higher firing rates.

However, the boiler’s capacity requirement istypically determined by the maximum load in thesteam/hot water system. Therefore, the boilermay be oversized for the typical load conditionsoccurring.

If the boiler is oversized, its ability to handleminimum loads without cycling is limited.Therefore, when selecting the most appropriateNOx control, capacity and turndown should beconsidered together for proper boiler selectionand to meet overall system load requirements.

EFFICIENCY

Some low NOx controls reduce emissions bylowering flame temperature, particularly in boilerswith inputs less than 100 MMBtu/hr. Reducingthe flame temperature decreases the radiativeheat transfer from the flame and could lowerboiler efficiency. The efficiency loss due to thelower flame temperatures can be partially offsetby utilizing external components, such as aneconomizer. Or, the technique can be inherent inthe NOx design.

One technology that offsets the efficiency lossdue to lower flame temperatures in a firetubeboiler is flue gas recirculation. Although theradiant heat transfer could result in an efficiencyloss, the recirculated flue gases increase themass flow through the boiler - thus theconvective heat transfer in the tube passesincreases. The increase in convective heattransfer compensates for losses in radiative heattransfer, with no net efficiency loss. Whenconsidering NOx control technology, remember, itis not necessary to sacrifice efficiency for NOx

reductions.

EXCESS AIR

A boiler’s excess air supply provides for safeoperation above stoichiometric conditions. Atypical burner is usually set up with 10-20%excess air (2-4% O2). NOx controls that requirehigher excess air levels can result in fuel beingused to heat the air rather than transferring it tousable energy. Thus, increased stack losses andreduced boiler efficiency occur. NOx controls thatrequire reduced excess air levels can result in anoxygen deficient flame and increased levels ofcarbon monoxide or unburned hydrocarbons. It isbest to select a NOx control technology that haslittle effect on excess air.

CO EMISSIONS

High flame temperatures and intimate air/fuelmixing are essential for low CO emissions. SomeNOx control technologies used on industrial andcommercial boilers reduce NOx levels by loweringflame temperatures by modifying air/fuel mixingpatterns. The lower flame temperature anddecreased mixing intensity can result in higherCO levels.

An induced flue gas recirculation package canlower NOx levels by reducing flame temperaturewithout increasing CO levels. CO levels remainconstant or are lowered because the flue gas isintroduced into the flame in the early stages of

combustion and the air fuel mixing is intensified.Intensified mixing offsets the decrease in flametemperature and results in CO levels that arelower than achieved without FGR. Induced FGRlowers CO levels as well as NOx levels. But, thelevel of CO depends on the burner design. Not allflue gas recirculation applications result in lowerCO levels.

TOTAL PERFORMANCE

Selecting the best low NOx control packageshould be made with total boiler performance inmind. Consider the application. Investigate all ofthe characteristics of the control technology andthe effects of the technology on the boiler’sperformance. A NOx control technology thatresults in the greatest NOx reduction is notnecessarily the best for the application or thebest for high turndown, adequate capacity, highefficiency, sufficient excess air, or lower CO. Thenewer low NOx technologies provide NOx

reductions without affecting total boilerperformance.

Sulfur Compounds (SOx)The primary reason sulfur compounds, or

SOx, are classified as a pollutant is because theyreact with water vapor (in the flue gas andatmosphere) to form sulfuric acid mist. Airbornesulfuric acid has been found in fog, smog, acidrain, and snow. Sulfuric acid has also been foundin lakes, rivers, and soil. The acid is extremelycorrosive and harmful to the environment.

The combustion of fuels containing sulfur(primarily oils and coals) results in pollutantsoccurring in the form of SO2 (sulfur dioxide) andSO3 ( sulfur trioxide), together referred to as SOx

(sulfur oxides). The level of SOx emitted dependsdirectly on the sulfur content of the fuel (seeFigure 12). The level of SOx emissions is notdependent on boiler size or burner design.Typically, about 95% of the sulfur in the fuel willbe emitted as SO2, 1-5% as SO3, and 1-3% assulfate particulate. Sulfate particulate is notconsidered part of the total SOx emissions.

Historically, SOx pollution has beencontrolled by either dispersion or reduction.Dispersion involves the utilization of a tall stack,which enables the release of pollutants highabove the ground and over any surroundingbuildings, mountains, or hills, in order to limitground level SOx emissions. Today, dispersionalone is not enough to meet more stringent SOx

emission requirements; reduction methods mustalso be employed.

Methods of SOx reduction include switchingto low sulfur fuel, desulfurizing the fuel, andutilizing a flue gas desulfurization (FGD) system.Fuel desulfurization, which primarily applies tocoal, involves removing sulfur from the fuel priorto burning. Flue gas desulfurization involves theutilization of scrubbers to remove SOx emissionsfrom the flue gases.

Flue gas desulfurization systems are classifiedas either nonregenerable or regenerable. Non-regenerable FGD systems, the most commontype, result in a waste product that requiresproper disposal. Regenerable FGD converts thewaste byproduct into a marketable product, suchas sulfur or sulfuric acid. SOx emission reductionsof 90-95% can be achieved through FGD. Fueldesulfurization and FGD are primarily used forreducing SOx emissions for large utility boilers.Generally the technology cannot be cost justifiedon industrial boilers.

For users of industrial boilers, utilizing lowsulfur fuels is the most cost effective method ofSOx reduction. Because SOx emissions primarily

depend on the sulfur content of the fuel, burningfuels containing a minimal amount of sulfur(distillate oil) can achieve SOx reductions, withoutthe need to install and maintain expensiveequipment.

Carbon MonoxideCarbon monoxide is a pollutant that is readily

absorbed in the body and can impair the oxygen-carrying capacity of the hemoglobin. Impairmentof the body’s hemoglobin results in less oxygen

Pollu

tant

s and

Con

trol

Tec

hniq

ues

16

figure 12

0

200

400

600

800

1000

1200

Effects of Fuel Sulfur Contenton SOx Emissions for Fuel Oils

Sulfur in Fuel (% weight)

SO

x E

mis

sio

n L

evel

*(P

PM

at

3% O

2)

*Based on EPA AP-42 Estimates

0 .2 .4 .6 .8 1 1.2 1.4 1.6 1.8 2.0

to the brain, heart, and tissues. Short-term overexposure to carbon monoxide can be critical,even fatal, to people with heart and lungdiseases. It also may cause headaches anddizziness in healthy people.

During combustion, carbon in the fueloxidizes through a series of reactions to formcarbon dioxide (CO2). However, 100 percentconversion of carbon to CO2 is rarely achieved inpractice and some carbon only oxidizes to theintermediate step, carbon monoxide.

Older boilers generally have higher levels ofCO than new equipment because CO has onlyrecently become a concern and older burnerswere not designed to achieve low CO levels. Intoday’s equipment, high levels of carbonmonoxide emissions primarily result fromincomplete combustion due to poor burnerdesign or firing conditions (for example, animproper air-to-fuel ratio) or possibly a leakyfurnace. Through proper burner maintenance,inspections, operation, or by upgradingequipment or utilizing an oxygen controlpackage, the formation of carbon monoxide canbe controlled at an acceptable level.

Particulate MatterEmissions of particulate matter (PM) from

combustion sources consist of many differenttypes of compounds, including nitrates, sulfates,carbons, oxides, and any uncombusted elementsin the fuel. Particulate pollutants can becorrosive, toxic to plants and animals, andharmful to humans.

Particulate matter emissions generally areclassified into two categories, PM and PM10.PM10 is a particulate matter with a diameter lessthan 10 microns. All particulate matter can pose ahealth problem. However, the greatest concern iswith PM10, because of its ability to bypass thebody’s natural filtering system.

PM emissions primarily depend on the gradeof fuel fired in the boiler. Generally, PM levelsfrom natural gas are significantly lower than thoseof oils. Distillate oils result in much lower particulateemissions than residual oils.

When burning heavy oils, particulate levelsmainly depend on four fuel constituents: sulfur,ash, carbon residue, and asphaltines. Theconstituents exist in fuel oils, particularly residualoils, and have a major effect on particulateemissions. By knowing the content of thecomponents, the particulate emissions for the oil

can be estimated.

Methods of particulate control vary fordifferent types and sizes of boilers. For utilityboilers, electrostatic precipitators, scrubbers, andbaghouses are commonly utilized. For industrialand commercial boilers, the most effectivemethod is to utilize clean fuels. The emissionlevels of particulate matter can be lowered byswitching from a residual to a distillate oil or byswitching from a distillate oil to a natural gas.Additionally, through proper burner set-up,adjustment and maintenance, particulateemissions can be minimized, but not to the extentaccomplished by switching fuels.

OzoneOzone is a highly reactive form of oxygen.

Ground level ozone is a secondary pollutantformed by the reaction of volatile organiccompounds (VOCs) with nitrogen oxides (NOx) inthe presence of sunlight. Ozone formed at theground level is the main component of smog. It isknown to irritate the eyes, nose, throat, andlungs, and also cause damage to crops. Groundlevel ozone should not be confused with ozone inthe upper atmosphere.

Since ozone is formed by the reaction ofVOCs and NOx, methods of ozone reductionfocus on the control of these two pollutants.Recent studies show that reducing NOx emissionsin several ozone nonattainment areas would bebeneficial in meeting federal ozone standards.

Sources of VOCs are automobiles, solvents,paints, domestic products and, in nature,decomposition of organic materials such aswood and grass. Although a major source ofVOCs is automobiles, the ozone standards alsoaddress stationary sources; including boilers.Regulations limiting VOC emissions fromstationary combustion sources are relatively new.The regulations originally applied only to largeutility boilers, but now are beginning to addressindustrial boilers. These regulations are primarilyat the state level and vary among states.

VOCs are compounds containingcombinations of carbon, hydrogen andsometimes oxygen. They can be vaporized easilyat low temperatures. They often are referred to ashydrocarbons and generally are divided into twocategories — methane and non-methanehydrocarbons.

VOCs can result from poor combustion but,more commonly, result from vaporization of fuels

17

Pollu

tant

s and

Con

trol

Tec

hniq

ues

18

and paints. Leaks in oil or gas piping, and eventhe few drops of gasoline spilled when filling anautomobile, are sources of VOCs.

Control of VOC emissions is bestaccomplished by maintaining proper combustionconditions. The use of controls to maintainproper air-to-fuel ratios and periodic burnermaintenance checks should result in reducingVOC emissions below imposed limits.

Note: If a boiler is operated improperly or is poorlymaintained (incorrect air/fuel ratio, inadequateatomizing pressure for oil burners, and improperair and fuel pressures), the concentration of VOCsmay increase by several orders of magnitude.

LeadLead poisoning can lead to diminished

physical fitness, fatigue, sleep disturbance,headache, aching bones and muscles, anddigestive upset, including anorexia. Leadpoisoning primarily involves the gastrointestinaltract and the peripheral and central nervoussystems.

Lead emissions are primarily a result ofgasoline combustion in automobile engines anddepend highly on the lead content of the fuel.Efforts to reduce lead emissions have focused onthe use of lead-free fuels, particularly inautomobiles. New blends of gasoline containinglower levels of lead additives continue to beintroduced.

The impact of lead emission regulations inindustrial boilers that burn standard fuels hasbeen minimal because the fuels generally containlittle or no lead. Boilers that fire alternate fuelscontaining lead are subject to stringent federal,state, and local regulations. For example, underthe Federal Resource Conservation Recovery Act(RCRA), waste oil to be burned as fuel in anindustrial boiler must contain less than 50 ppmlead. As a result of such strict regulations, the useof fuel containing lead in industrial boilers is limited.

19

CONCLUSION

We hope you have a better grasp of how federal,state, and local governments are regulating airpollution. We also hope you have a betterunderstanding of NOx and CO emissions andindustrial boiler control technologies.

When you need to specify or purchase an industrialboiler with emission control technology, your localCleaver-Brooks authorized representative is availableto discuss control technology options and howyou can achieve the lowest possible emissions.

If at any time you need more information, pleasedon’t hesitate to contact your local Cleaver-Brooksrepresentative.

App

endi

x A

20

AlabamaBirmingham Marginal

ArizonaPhoenix Moderate

CaliforniaLos Angeles – South Coast ExtremeAir Basin

Monterey Bay ModerateSacramento Metro SeriousSan Diego Severe-15San Francisco – Bay Area ModerateSan Joaquin Valley SeriousSanta Barbara – Santa Maria -Lompoc Moderate

Southeast DesertModified AQMA Severe-17

Ventura County Severe-15

ConnecticutGreater Connecticut SeriousFairfield, Hartford, Litchfield,Middlesex, New Haven,New London, Tolland, and Windham Counties

New York – N. New Jersey -Long Island Severe-17Parts of Fairfield andLitchfield Counties

DelawareWilmington – Philadelphia -Trenton Severe-15

Sussex County Marginal

District of ColumbiaEntire District Serious

FloridaMiami – Fort Lauderdale –W. Palm Beach Moderate

Tampa – St. Petersburg –Clearwater Marginal

GeorgiaAtlanta Serious

IllinoisChicago – Gary – Lake County Severe-17Jersey County MarginalSt. Louis ModerateMadison, Monroe, and

St. Clair Counties

IndianaGary – Chicago – Lake County Severe-17Evansville MarginalIndianapolis MarginalLouisville ModerateClark and Floyd Counties

South Bend – Elkhart Marginal

KansasKansas City Sub Marginal

KentuckyCincinnati – Hamilton ModerateBoone, Campbell, andKenton Counties

Edmonson County MarginalAshland – Huntington ModerateLexington – Fayette MarginalLouisville ModerateOwensboro MarginalPudacah Marginal

LouisianaBaton Rouge SeriousLake Charles Marginal

MaineHancock and Waldo Counties MarginalKnox and Lincoln Counties ModerateLewiston – Auburn ModeratePortland Moderate

MarylandBaltimore Severe-15Kent and Queen Anne’sCounties Marginal

Philadelphia – Wilmington -Trenton Severe-15Cecil County

Wasington D.C. SeriousCalvert, Charles, Frederick,Montgomery, andPrince George’s Counties

MassachusettsBoston – Lawrence –Worcester Serious

Springfield Serious

MichiganDetroit – Ann Arbor ModerateGrand Rapids ModerateMuskegon Serious

MissouriKansas City Sub-MarginalSt. Louis Moderate

NevadaReno Marginal

New HampshireBoston – Lawrence –Worcester SeriousParts of Hillsborough andRockingham Counties

Manchester MarginalPortsmouth - Dover -Rochester Serious

CLASSIFIED OZONENONATTAINMENT AREAS (January 1994)

21

New JerseyAllentown – Bethlehem -Easton – Warren County Marginal

Atlantic City ModerateN. New Jersey – New York -Long Island Severe-17

Trenton – Philadelphia -Wilmington Severe-15

New YorkAlbany – Schenectady – Troy MarginalBuffalo – Niagara Falls MarginalEssex County MarginalJefferson County MarginalNew York – N. New Jersey –Long Island Severe-17

Poughkeepsie Marginal

North CarolinaCharlotte – Gastonia ModerateGreensboro – Winston – Salem –High Point Moderate

Raleigh – Durham Moderate

OhioCanton MarginalCincinnati – Hamilton ModerateCleveland – Akron – Lorain ModerateColumbus MarginalDayton – Springfield ModerateToledo ModerateYoungstown – Warren – Sharon Marginal

OregonPortland – Vancouver AQMA Marginal

PennsylvaniaAllentown – Bethlehem – Easton MarginalAltoona MarginalErie MarginalHarrisburg – Lebanon – Carlisle MarginalJohnstown MarginalLancaster MarginalPhiladelphia – Wilmington – Trenton Severe-15

Pittsburgh – Beaver Valley ModerateReading ModerateScranton – Wilkes – Barre MarginalYork MarginalSharon – Youngstown – Warren Marginal

Rhode IslandEntire State Serious

South CarolinaCherokee County Marginal

TennesseeKnoxville MarginalMemphis MarginalNashville Moderate

TexasBeaumont – Port Arthur SeriousDallas – Ft. Worth ModerateEl Paso SeriousHouston – Galveston – Brazoria Severe-17

UtahSalt Lake City Moderate

VirginiaNorfolk – Virginia Beach -Newport News Marginal

Richmond – Petersburg ModerateSmyth County MarginalWashington D.C. SeriousArlington, Fairfax, Loudoun,Prince William, and StaffordCounties; Alexandria, Fairfax,Falls Church, Manassas, andManassas Park

WashingtonVancouver AQMA – Portland MarginalSeattle – Tacoma Marginal

West VirginiaCharleston ModerateGreenbrier County MarginalHuntington – Ashland ModerateParkersburgh Moderate

WisconsinDoor County MarginalKewaunee County ModerateManitowoc County ModerateMilwaukee – Racine Severe-17Sheboygan SeriousWalworth County Marginal

NOTE: If there is no listing for a state, there are noclassified ozone nonattainment areas located in thestate.

App

endi

x A

22

AlaskaAnchorage Moderate>12.7 ppmFairbanks Moderate≤12.7 ppm

ArizonaPhoenix Moderate≤12.7 ppm

CaliforniaChico Moderate≤12.7 ppmFresno Moderate>12.7 ppmLake Tahoe South Shore Moderate≤12.7 ppmLos Angeles SouthCoast Air Basin Serious

Modesto Moderate≤12.7 ppmSacramento Moderate≤12.7 ppmSan Diego Moderate≤12.7 ppmSan Francisco –Oakland – San Jose Moderate≤12.7 ppm

Stockton Moderate≤12.7 ppm

ColoradoColorado Springs Moderate≤12.7 ppmDenver – Boulder Moderate>12.7 ppmFort Collins Moderate≤12.7 ppmLongmont Moderate≤12.7 ppm

ConnecticutHartford – New Britain -Middletown Moderate≤12.7 ppm

New York –N. New Jersey –Long Island Moderate>12.7 ppmParts of Fairfieldand Litchfield Counties

District of ColumbiaEntire District Moderate≤12.7 ppm

MarylandBaltimore Moderate≤12.7 ppmWashington D.C. Moderate≤12.7 ppmMontgomery andPrince George’sCounties

MassachusettsBoston Moderate≤12.7 ppm

MinnesotaDuluth Moderate≤12.7 ppmMinneapolis – St. Paul Moderate≤12.7 ppm

MontanaMissoula Moderate≤12.7 ppm

NevadaLas Vegas Moderate>12.7 ppmReno Moderate≤12.7 ppm

New JerseyN. New Jersey –

New York – Long Island Moderate>12.7 ppmCamden County –Philadelphia Moderate≤12.7 ppm

New MexicoAlbuquerque Moderate≤12.7 ppm

New YorkNew York –N. New Jersey –Long Island Moderate>12.7 ppm

Syracuse Moderate≤12.7 ppm

North CarolinaRaleigh – Durham Moderate≤12.7 ppmWinston – Salem Moderate≤12.7 ppm

OhioCleveland Moderate≤12.7 ppm

OregonGrants Pass Moderate≤12.7 ppmKlamath Falls Moderate≤12.7 ppmMedford Moderate≤12.7 ppmPortland – Vancouver Moderate≤12.7 ppm

PennsylvaniaPhiladelphia –Camden County Moderate≤12.7 ppm

TennesseeMemphis Moderate≤12.7 ppm

TexasEl Paso Moderate≤12.7 ppm

UtahOgden Moderate≤12.7 ppmProvo Moderate>12.7 ppm

VirginiaWashington D.C.Alexandria City, Arlington County Moderate≤12.7 ppm

WashingtonVancouver – Portland Moderate≤12.7 ppmSeattle – Tacoma Moderate>12.7 ppmSpokane Moderate>12.7 ppm

NOTE: If there is no listing for a state, there are noclassified carbon monoxide nonattainment areaslocated in the state.

CLASSIFIED CARBON MONOXIDENONATTAINMENT AREAS (January 1994)

23

ArizonaAjoDouglasHayden/MiamiNogalas Paul SpurPhoenixRillitoYuma

ArkansasEagle RiverJuneau

CaliforniaCoachella ValleyImperial ValleyMammoth LakeOwens ValleySan Joaquin ValleySearles ValleySouth Coast Basin

ColoradoAspenCanon CityDenver MetroLamarPagosa SpringsTelluride

ConnecticutNew Haven

IdahoBoiseBonner CountyPinehurstPocatello

IllinoisGranite CityLyons Township, McCookOglesbySoutheast Chicago

IndianaLake CountyVermillion County

MainePresque Isle

MichiganDetroit

MinnesotaRochesterSt. Paul

MontanaButteColumbia

KalispellLame DeerLibbyMissoulaPolsonRonan

NevadaLas VegasReno

New MexicoAnthony

OhioCuyahoga CountyMingo Junction

OregonGrant PassKlamath FallsLa GrandMedfordSpringfield/Eugene

PennsylvaniaClairton

TexasEl Paso

UtahSalt Lake CountyUtah County

WashingtonKentOlympia/Tumwater/LaceySeattle SpokaneTacomaWallulaYakima

West VirginiaFollansbee

WyomingSheridan

NOTE: If there is no listing for a state, there are noclassified PM-10 nonattainment areas located inthe state.

CLASSIFIED PM10NONATTAINMENT AREAS (January 1994)

App

endi

x A

24

AlabamaColbert Co.Lauderdale Co.

ArizonaCochise Co. (Douglas)Gila Co. (Miami/Globe)Greenlee Co. (Morenci)Pima Co. (Ajo)Pinal Co. (Hayden)Pinal Co. (San Manual)

IllinoisPeoria Co.Tazwell Co.

IndianaLake Co.Laporte Co.Marion Co.Vigo Co.Wayne Co.

Kentucky Boyd Co.Muhlenberg Co.

MainePenobscot Co.Millinocket

MinnesotaMinneapolis-St. Paul.Olmsted Co. (Rochester)

MontanaLewis and Clark Co.Yellowstone Co. (Laurel)

New JerseyWarren Co.

New MexicoGrant Co.

NevadaWhite Pine Co.

OhioCoshocton Co.Cuyahoga Co. (part)Gallia Co. (Addison Twnshp.)Jefferson Co. (part)Lake Co. (part)Lorrain Co. (part)Lucas Co. (part)Morgan Co. (Center Twnshp.)Washington Co.

PennsylvainaAllegheny Co.Armstrong Co.Warren Co.

TennesseeBenton Co.Humphreys Co.Polk Co.

UtahSalt Lake Co.Tooele Co. (part)

WisconsinBrown Co. (Green Bay)Dane Co. (Madison)Marathon Co. (Rothschild)Milwaukee Co. (Milwaukee)Oneida Co. (Rhinelander)

West VirginiaHancock Co. (part)

NOTE: If there is no listing for a state, there are noclassified SO2 nonattainment areas located in the state.

CLASSIFIED SULFUR DIOXIDENONATTAINMENT AREAS (January 1994)

lb/MMBtuVolatile Organic Compounds

Boiler Particulate Matter Sulfur Dioxide Carbon Monoxide Nitrogen Oxides Nonmethane MethaneType (lb/MMBtu) (lb/MMBtu) (lb/MMBtu) (lb/MMBtu) (lb/MMBtu) (lb/MMBtu)

Industrial 0.00095-0.0048 0.00057 0.033 0.133 0.0027 0.0029

Commercial 0.00095-0.0048 0.00057 0.019 0.095 0.005 0.0023

ppmVolatile Organic Compounds

Boiler Particulate Matter Sulfur Dioxide Carbon Monoxide Nitrogen Oxides Nonmethane MethaneType (ppm) (ppm) (ppm) (ppm) (ppm) (ppm)

Industrial N/A 0.34 46 112 6.8 7.3

Commercial N/A 0.34 26 80 13 5.8

Notes: Industrial Boilers: 10-100 MMBtu/hrEstimated HHV of Natural Gas: 1050 Btu/FT3 Commercial Boilers: 0.5-10 MMBtu/hr

lb/MMBtuVolatile Organic Compounds

Boiler Particulate Matter Sulfur Dioxide Carbon Monoxide Nitrogen Oxides Nonmethane MethaneType (lb/MMBtu) (lb/MMBtu) (lb/MMBtu) (lb/MMBtu) (lb/MMBtu) (lb/MMBtu)

Industrial 0.00098-0.0048 0.812 (%S) 0.034 0.136 0.0027 0.003

Commercial 0.00098-0.0048 0.812 (%S) 0.02 0.096 0.005 0.0026

ppmVolatile Organic Compounds

Boiler Particulate Matter Sulfur Dioxide Carbon Monoxide Nitrogen Oxides Nonmethane MethaneType (ppm) (ppm) (ppm) (ppm) (ppm) (ppm)

Industrial N/A 475 (%S) 45 111 6.8 7.5

Commercial N/A 475 (%S) 27 78 12.5 6.5

Notes: Industrial Boilers: 10-100 MMBtu/hrEstimated HHV of Propane: 91,500 Btu/gal Commercial Boilers: 0.5-10 MMBtu/hr

App

endi

x B

25

AP-42Uncontrolled Emission Factors for Propane Combustion

AP-42Uncontrolled Emission Factors for Natural Gas Combustion

App

endi

x B

26

lb/MMBtuVolatile Organic Compounds

Boiler Particulate Matter Sulfur Dioxide Sulfur Trioxide Carbon Monoxide Nitrogen Oxides Nonmethane MethaneType (lb/MMBtu) (lb/MMBtu) (lb/MMBtu) (lb/MMBtu) (lb/MMBtu) (lb/MMBtu) (lb/MMBtu)

Industrial:Residual 0.0649(%S) + 0.0195 1.02(%S) 0.013(%S) 0.0325 0.357* 0.0018 0.0065Distillate 0.0143 1.01(%S) 0.013(%S) 0.0325 0.143 0.0014 0.0004

Commercial:Residual 0.0649(%S) + 0.0195 1.02(%S) 0.013(%S) 0.0325 0.357* 0.0073 0.0031

Distillate 0.0143 1.01(%S) 0.013(%S) 0.0325 0.143 0.00124 0.0015

*Nitrogen oxide emissions from residual oil combustion in industrial and commercial boilers are strongly related to fuel nitrogen content.

The emissions can be more accurately predicted by the empirical relationship:

2.6(%N) ^ 2+0.143 lb/MMBtu (%N in fuel <0.5%)

For residual oils having nitrogen content (>0.5%) use 0.779 lb/MMBtu as an emission factor.

Notes:

Estimated HHV of #2 Oil: 140,000 Btu/gal Industrial Boilers: 10 - 100 MMBtu/hr

Estimated HHV of #6 Oil: 154,000 Btu/gal Commercial Boilers: 0.5 - 10 MMBtu/hr

AP-42Uncontrolled Emission Factors for Fuel Oil Combustion

ppmVolatile Organic Compounds

Boiler Particulate Matter Sulfur Dioxide Sulfur Trioxide Carbon Monoxide Nitrogen Oxide Nonmethane MethaneType (ppm) (ppm) (ppm) (ppm) (ppm) (ppm) (ppm)

Industrial:Residual N/A 549(%S) 7(%S) 42 273* 3.6 13Distillate N/A 544(%S) 7(%S) 42 107 2.8 0.8

Commercial:Residual N/A 549(%S) 7(%S) 42 273* 14.6 6.2

Distillate N/A 544(%S) 7(%S) 42 107 4.8 3

*Nitrogen oxide emissions from residual oil combustion in industrial and commercial boilers are strongly related to fuel nitrogen content.

The emissions can be more accurately predicted by the empirical relationship:

1,940(%N) ^ 2+107 ppm (%N in fuel <0.5%)

For residual oils having nitrogen content (>0.5%) use 595 ppm as an emission factor.

Notes:

Estimated HHV of #2 Oil: 140,000 Btu/gal Industrial Boilers: 10 - 100 MMBtu/hr

Estimated HHV of #6 Oil: 154,000 Btu/gal Commercial Boilers: 0.5 - 10 MMBtu/hr

AP-42Uncontrolled Emission Factors for Fuel Oil Combustion

27

App

endi

x C

EPA REGIONAL AIR QUALITY DIVISIONS

Region 1

Boston, MA 617/565-3800Maine, Vermont, New Hampshire,Connecticut, Massachusetts, Rhode Island

Region 2

New York, NY 212/264-2301New York, New Jersey, Puerto Rico, U.S.Virgin Islands

Region 3

Philadelphia, PA 215/597-9390Pennsylvania, Delaware, Virginia, WestVirginia, Maryland, District of Columbia

Region 4

Atlanta, GA 404/347-3043Georgia, Florida, Alabama, North Carolina,South Carolina, Kentucky Tennessee,Mississippi

Region 5

Chicago, IL 312/353-2212Illinois, Indiana, Michigan, Minnesota, Ohio,Wisconsin

Region 6

Dallas, TX 214/655-7200Texas, Arkansas, Oklahoma, Louisiana, NewMexico

Region 7

Kansas City, MO 913/551-7020Nebraska, Iowa, Kansas, Missouri

Region 8

Denver, CO 303/293-1438Colorado, Utah, Wyoming, Montana, NorthDakota, South Dakota

Region 9

San Francisco, CA 414/744-1219California, Arizona, Nevada, Hawaii,American Samoa, Guam, Trust Territories ofthe Pacific

Region 10

Seattle, WA 206/422-4152Washington, Oregon, Idaho, Alaska

App

endi

x D

28

ABMA American Boiler Manufacturer's AssociationA group of manufacturer's representing theboiler industry of which Cleaver-Brooks is amember

APCD Air Pollution Control DistrictUsually refers to a local air quality agencycontrolling pollution in a given district

AQCR Air Quality Control RegionGenerally refers to one of the ten EPA regionaloffices throughout the U.S.

AQMD Air Quality Management DistrictRefers to an area or region where air quality isregulated by a local agency

ARAC Acid Rain Advisory CommitteeA committee established by the EPA to focusefforts on the various aspects of Title IV (AcidDeposition Control) of the Clean Air Act

ARB Air Resource BoardAn air quality agency usually responsible forpollution control at the state level

BACT Best Available Control TechnologyAn emission limitation based on the maximumdegree of reduction, which the permittingauthority has determined is achievable andcost effective

BARCT Best Available Retrofit Control TechnologyA retrofit equipment emission limitation basedon the BACT principles - but developed forretrofitting existing equipment

CEM Continuous Emission MonitoringAn emission monitoring system used formeasuring emission levels withoutinterruption - required in many local districtsand NSPS for certain applications

CFR Code of Federal RegulationsA codification of the rules published in theFederal Register by the departments andagencies of the Federal Government

EPA Environmental Protection AgencyA federal agency responsible for pollutioncontrol at the national level

ESP Electrostatic PrecipitatorsEmission control equipment used to controlparticulate matter on large utility boilers

FGD Flue Gas DesulfurizationEmission control method used to controlsulfur dioxide emissions

FGR Flue Gas RecirculationNOx emission control technique - involvesreturning a portion of the flue gases to thecombustion zone

LAER Lowest Achievable Emission RateThe most stringent emission limitationcontained in any SIP or achieved in practicefor a given class of equipment

MACT Maximum Available Control TechnologyEmission standard requiring the maximumdegree of emission reduction that has beendemonstrated achievable

NAAQS National Ambient Air Quality StandardsEPA established air quality standards forambient outdoor emission levels

NESHAP National Emission Standards forHazardous Air Pollutants

Standards established by the EPA forregulation of air toxins

NSPS New Source Performance StandardsRegulations established by the EPA foremissions from equipment, including boilers.Many state regulations are more stringentthan the NSPS

NSR New Source ReviewA review performed during the permittingprocess for a new major installation in anonattainment area

PSD Prevention of Significant DeteriorationA review performed during the permittingprocess for a new major installation in anattainment area

RACT Reasonably Available Control TechnologyA set of recommended levels of emissioncontrols applicable to specific sources orcategories located in nonattainment areas

SCAQMD South Coast Air Quality Management DistrictThe air pollution control agency for the LosAngeles, CA area - emission regulationsenacted in this district generally set the trendsfor other local regulations throughout the U.S.

SCR Selective Catalytic ReductionA NOx control method in which ammonia orurea is injected into the exhaust gases in thepresence of a catalyst

SIP State Implementation PlanAn EPA approved emission control plan toattain or maintain NAAQS

SNCR Selective Non-Catalytic ReductionA NOx control method where ammonia or ureais injected into the stack and where theexhaust gases are approximately 1600degrees Fahrenheit

ACRONYMS/DEFINITIONS

App

endi

x E

29

0.0 100 200 300 400 500 600 700 800 900 1,000 1,100 1,2000

0.4

0.8

1.2

1.6

2.0

0.2

0.6

1.0

1.4

1.8

2.4

2.2

SOx Emissions Conversion Curves15% Excess Air

SOx Emissions (ppm)

SO

x E

mis

sio

ns

(lb

/MM

Btu

)

Dry Analysis

#2 and #6 Oil

#2 and #6 Oil:ppm = (lb/MMBtu)*540lb/MMBtu = (ppm)/540

Conversion Equations

0.000 10 20 30 40 50 60 70 80 90 1000

0.010

0.020

0.030

0.040

0.050

0.005

0.015

0.025

0.035

0.045

0.060

0.055

Volatile Organic CompoundConversion Curves

15% Excess Air

VOC Emissions (ppm)

VO

C E

mis

sio

ns

(lb

/MM

Btu

)

Dry Analysis

#2 and #6 Oil:ppm = (lb/MMBtu)*2000lb/MMBtu = (ppm)/2000

Conversion Equations

#2 and #6 Oil

Natural Gas and Propane

Natural Gas and Propane:ppm = (lb/MMBtu)*2500lb/MMBtu = (ppm)/2500

App

endi

x E

30

0.00 20 40 60 80 100 120 140 160 180 2000

0.04

0.08

0.12

0.16

0.20

0.02

0.06

0.10

0.14

0.18

0.24

0.26

0.28

0.22

NOx Emissions Conversion Curves15% Excess Air

NOx Emissions (ppm)

NO

x E

mis

sio

ns

(lb

/MM

Btu

)

Dry Analysis

#2 and #6 Oil:ppm = (lb/MMBtu)*750lb/MMBtu = (ppm)/750

Propane:ppm = (lb/MMBtu)*810lb/MMBtu = (ppm)/810

Conversion EquationsNatural Gas:

ppm = (lb/MMBtu)*850lb/MMBtu = (ppm)/850

#2 and #6 Oil

Natural Gas and Propane

Propane

31

Natural Gas

#2 Oil

0.00 20 40 60 80 100 120 140 160 180 2000

0.02

0.04

0.08

0.10

0.12

0.14

0.16

0.18

CO Emissions Conversion Curves15% Excess Air

CO Emissions (ppm)

CO

Em

issi

on

s (l

b/M

MB

tu)

Dry Analysis

#2 Oil:ppm = (lb/MMBtu)*1290lb/MMBtu = (ppm)/1290

#6 Oil:ppm = (lb/MMBtu)*1260lb/MMBtu = (ppm)/1260

Propane:ppm = (lb/MMBtu)*1340lb/MMBtu = (ppm)/1340

Conversion EquationsNatural Gas:

ppm = (lb/MMBtu)*1370lb/MMBtu = (ppm)/1370

Propane

#6 Oil

Correcting Emission Readingsto 3% Oxygen

Example: What is the NO level corrected to 3% oxygen for a measured level of 12 ppm at 7.1% oxygen?

ppm (@3%) =21 - 3

21 - O (actual) x ppm (actual)

ppm (@3%) =21 - 3

21 - 7.1 x 12 = 15.5 ppm NO

2

x

x

App

endi

x F

32

1000 2000 3000 4000 5000 6000 7000 8000 90000

5

10

15

20

Annual NOx Emissions for 250-800 Horsepower Boilers

NOx = 110 ppm*

Annual Hours of Operation

An

nu

al N

Ox

Em

issi

on

s (t

py)

Efficiency = 80% *ppm corrected to 3% oxygen

500 HP

800 HP700 HP600 HP*400 HPx350 HP✦

▲ 300 HP

250 HP

▲

▲▲

▲

▲▲

▲

▲

▲

✦✦

✦

✦✦

✦

✦

✦✦

xx

xx

xx

xx

x

**

*

**

**

*

CALCULATION OF ANNUAL EMISSIONS FOR INDUSTRIAL BOILERS

Many provisions of the 1990 Clean Air Act Amendments assess the impact of pollution sources basedon the potential annual emissions (usually expressed as tons per year, or tpy). When addressingindustrial boilers, the potential annual emissions of NOx are of concern and frequently must becalculated. Following is an example of how to calculate the potential annual NOx emissions forindustrial boilers.

To determine the annual NOx emissions for an industrial boiler, three items must be known:

1. The NOx emission factor for the boiler.2. The maximum rated input for the boiler.3. The maximum allowable hours of operation for the boiler.

Once the information above is obtained, the following equation can be used to determine annual emissions.

Boiler Emission Annual Hours Total Annual Input Factor of Operation Emissions

For example, the calculation of the total annual NOx emissions for an 800 hp boiler operating 24hours/day, 365 days/year and having a NOx level of 110 ppm would be as follows.

Boiler Input = 33.5 MMBtu/hr (Based on 80% Efficiency)Emission Factor = 0.13 lb/MMBtu (110 ppm = 0.13 lb/MMBtu)Annual Hours of Operation = 8760 hours/year (24 hours/day x 365 days/year)

Substituting this data into the equation above yields:

The annual NOx emissions for this specific boiler is 19.1 tpy.

The following graphs indicate the annual NOx emissions for boiler sizes 250-800 horsepower firingnatural gas at maximum input operating 24 hours/day, 365 days/year. There are for NOx emissionlevels of 110, 60, 30, 25, and 20 ppm.

0.13 lb NOx 33.5 MMBtu 8760 hrs 1 ton

MMBtu hr year 2000lbx x x

x x =

= 19.1 tpy NOx

33

1000 2000 3000 4000 5000 6000 7000 8000 9000

0

2

4

Annual NOx Emissions for 250-800 Horsepower Boilers

NOx = 20 ppm*

Annual Hours of Operation

An

nu

al N

Ox

Em

issi

on

s (t

py)

Efficiency = 80% *ppm corrected to 3% oxygen

500 HP

800 HP700 HP600 HP*400 HPx350 HP✦

▲ 300 HP

3

1▲

▲

✦✦▲

▲

▲

▲

▲

▲▲

✦

✦

✦

✦✦

✦✦

x

xx

xx

x

xx

x*

****

250 HP

****

1000 2000 3000 4000 5000 6000 7000 8000 90000

2

4

5

Annual NOx Emissions for 250-800 Horsepower Boilers

NOx = 25 ppm*

Annual Hours of Operation

An

nu

al N

Ox

Em

issi

on

s (t

py)

Efficiency = 80% *ppm corrected to 3% oxygen

3

1

▲

▲✦

✦▲

▲▲

▲▲

▲▲

✦✦

✦✦

✦✦

✦

x

x

xx

xx

xx

x

***

*

******

500 HP

800 HP700 HP600 HP*400 HPx350 HP✦

▲ 300 HP

250 HP

App

endi

x F

34

1000 2000 3000 4000 5000 6000 7000 8000 90000

2

4

5

6

Annual NOx Emissions for 250-800 Horsepower Boilers

NOx = 30 ppm*

Annual Hours of Operation

An

nu

al N

Ox

Em

issi

on

s (t

py)

Efficiency = 80% *ppm corrected to 3% oxygen

500 HP

800 HP700 HP600 HP*400 HPx350 HP✦

▲ 300 HP

250 HP*

* *3

1▲

▲

▲

▲

▲▲

▲▲

✦

✦✦

✦

✦

✦✦

✦

x

x

xx

xx

x

▲

xx✦ ✦

*****

*

1000 2000 3000 4000 5000 6000 7000 8000 90000

4

8

10

12

Annual NOx Emissions for 250-800 Horsepower Boilers

NOx = 60 ppm*

Annual Hours of Operation

An

nu

al N

Ox

Em

issi

on

s (t

py)

Efficiency = 80% *ppm corrected to 3% oxygen

500 HP

800 HP700 HP600 HP*400 HPx350 HP✦

▲ 300 HP

250 HP

***

*

** *6

2

▲

▲▲

▲▲

▲▲

▲▲

✦

✦

✦✦

✦✦

✦✦

✦

x

x

xx

xx

xx

x

* *

NOTES

Cleaver Brooks®

Cleaver-Brooks is pleased to present the Boiler Emissions Reference Guide.Cleaner air and cleaner fuels must be a goal for all of us.

For more information on emissions,please contact your local Cleaver-Brooks authorized Representative.

Milwaukee, WI • Greenville, MS • Stratford, Ontario, Canada • Mexico City, Mexico • Thomasville, GA

CB-7435R25M 1/94

Printed in U.S.A.

P.O. Box 421, Milwaukee, WI 53201(414) 359-0600