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Guia de Emisiones | Ley de Aire Limpio (Estados Unidos) | Contaminación del aire
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US Department of Justice Official Release - 02011-06 enrd 278
Air Pollution and the Clean Air- PPA Envi. Managment Seminar (Aug. 14, 2013)
HOUSE HEARING, 110TH CONGRESS - STRENGTHS AND WEAKNESSES OF REGULATING GREENHOUSE GAS EMISSIONS USING EXISTING CLEAN AIR ACT AUTHORITIES
Clean Air Act - EPPMagbanua.pptx
Proposed Rule: Air programs; approval and promulgation; State plans for designated facilities and pollutants: Indiana
Notice: Meetings: Clean Air Act Advisory Committee; correction
BOILER EMISSION GUIDE 3 Edition
Boiler Emissions Reference Guide Table of Contents
Regulations.................................................................................................................................................2 Federal Actions..........................................................................................................................................2 The Clean Air Act ..............................................................................................................................2 Clean Air Act Amendment of 1990....................................................................................................2 Title I - National Ambient Air Quality Standards........................................................................2 Attainment and Nonattainment..................................................................................................3 State Implementation Plans.......................................................................................................5 New Source Performance Standards................................................................................................5 State Actions.............................................................................................................................................6 Nonattainment Areas.........................................................................................................................6 Emission Inventories..........................................................................................................................6 State Activities...................................................................................................................................8 An Emission Alphabet................................................................................................................................9 BACT (Best Available Control Technology).......................................................................................9 RACT (Reasonably Available Control Technology)..........................................................................10 LAER (Lowest Achievable Emission Rate)......................................................................................10 Permits.....................................................................................................................................................10 Pollutants and Control Techniques Nitrogen Compounds..............................................................................................................................11 Thermal NOx....................................................................................................................................12 Fuel NOx...........................................................................................................................................12 NOx Control Technologies.......................................................................................................................12 Post Combustion Control Methods.........................................................................................................12 Selective Non-catalytic Reduction..................................................................................................12 Selective Catalytic Reduction..........................................................................................................12 Combustion Control Techniques.............................................................................................................12 Low Excess Air Firing......................................................................................................................13 Low Nitrogen Fuel Oil......................................................................................................................13 Burner Modifications.......................................................................................................................13 Water/Steam Injection.....................................................................................................................14 Flue Gas Recirculation.....................................................................................................................14 External Flue Gas Recirculation...............................................................................................14 Induced Flue Gas Recirculation...............................................................................................14 Side Bar - Choosing the Best NOx Technology for the Job............................................................14 Sulfur Compounds (SOx).........................................................................................................................16 Carbon Monoxide....................................................................................................................................16 Particulate Matter.....................................................................................................................................17 Ozone.......................................................................................................................................................17 Lead.........................................................................................................................................................18 Appendices Appendix A: Nonattainment Areas (Listing).............................................................................................20 Appendix B: Regional EPA Offices..........................................................................................................25 Appendix C: Acronyms............................................................................................................................26 Appendix D: Conversion Curves.............................................................................................................27 Appendix E: Annual NOx Emission Calculations...................................................................... 30
Since the beginning of time, mankind, flora, and fauna have been sustained by sunlight, fresh water, and clean air. But fly over many regions of the country today, and one will see our cities and mountains shrouded in a dull haze of pollutants. Look upon the horizon and see the suns rays reflect a kaleidoscope of colors grey for lead, yellow for sulphur, brown for nitrogen oxides. From the Appalachian Mountains, where brown tree tops are brittle and burnt from acid rain, to the Great Lakes, where shorelines all too often appear rimmed by murky mist, to the San Gabriel Mountains, where a natural inversion of the atmosphere presses a blanket of smog upon Southern California, we cant escape the damage. Carbon Monoxide, lead, nitrogen oxides, ozone, particulate matter, and sulfur, are now cited as the most insidious of pollutants. They are proven to contribute to respiratory illnesses in humans, damage to the environment and buildings and, ultimately, lead to higher costs for health care and environmental cleanup. Over the past several decades, the culprit pollutants spewed into our environment at increasing rates. Thus, in the 1980s, alarmed environmental activists and coalitions began to pressure Congress for stiffer air pollution control regulations. The result: in 1990, Congress passed its most comprehensive piece of environmental legislation, the Clean Air Act Amendments (CAAA). The Boiler Emissions Reference Guide is a multipurpose tool, which is intended to give you a clearer understanding of how industrial boilers fit into the clean air equation. In the first part, the guide discusses how federal and state actions are driving the air cleanup. It discusses air quality standards and areas of attainment and nonattainment for the pollutants. It describes how the government has set up emission limits for industrial boilers and other 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 six major pollutants in detail and discusses various control techniques. Emphasis is placed on combustion control for industrial boilers and how to choose the best technology. The guide concludes with special appendices, which provide fingertip information a must when dealing with a problem as complex as air pollution. 1
A word of caution... The information conveyed in the appendix and figures 2, 3, 4 & 5 are dynamic and may change based on the latest requirements issued by the EPA. Visiting an EPA site such as <epa.gov> will assist you in keeping abreast of the latest requirements.
Air pollution regulations are enacted at the federal level or at the state and local level. Federal regulations, which primarily establish outdoor, or ambient, air quality standards, are the primary drivers behind state and local air pollution regulations. However, with a few exceptions, the New Source Performance Standards (see page 5 for more information), federal regulations only set the ambient air quality standards. They do not detail how to accomplish them. The necessary actions to accomplish the federal standards must be developed and implemented by state and local air quality agencies. It is the state and local actions, along with the Federal New Source Performance Standards, that directly impact industrial boilers.
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, its interpretations and associated implications, are very complex. It would be impractical to list the details of the amendment and the requirements for future activity that the federal government dictates for state governments. For this reason, this section provides basic insight into the implications the act poses for fossil-fuel fired packaged boilers. As mentioned earlier, the 1990 Clean Air Act Amendment is comprised of 11 titles (see Figure 1). The provisions contained in the titles have the potential to affect nearly every source of air pollution. Although several titles affect industrial boilers, the title having the most impact is Title I, Attainment and Maintenance of the National Ambient Air Quality Standards.
FEDERAL ACTIONS The Clean Air Act
Nearly all air pollution regulations originate from the Clean Air Act, which was enacted in 1963. The act improved and strengthened pollution prevention programs and was the first major step toward more federal control of air pollution. The first major amendments to the Clean Air Act occurred in 1970. The 1970 amendments set national air quality standards and established performance standards for new sources of pollution. As a result of the 1970 amendments, standards were set for sulfur oxides and nitrogen oxides for several sources, including boilers. The next significant amendment to the Clean Air Act occurred in 1977. The 1977 amendment enhanced many aspects of the Clean Air Act by implementing a more comprehensive permit program, establishing emission limitations on existing sources, and imposing stricter emission standards on new sources. But most importantly, the 1977 amendment extended compliance deadlines because many geographical areas had not achieved compliance with the ambient air quality standards. After regulating air pollution for almost 15 years, nationwide compliance still had not been achieved. The most recent amendment to the Clean Air Act occurred in 1990. The 1990 Clean Air Act Amendment has been labelled the most complex, comprehensive, and far-reaching environmental law Congress has ever enacted. The 1990 amendments consist of 11 titles. Some of the titles are revisions of existing titles and others are new titles. As a result, the Clean Air Act now encompasses most aspects of air pollution. 2
EPA recently reviewed the current air quality standards for ground-level ozone (commonly known as smog) and particulate matter (or PM). Based on new scientific evidence, revisions have been made to both standards. At the same time, EPA is developing new programs to control regional haze, which is largely caused by particulate matter and mercury.
The National Ambient Air Quality Standards (NAAQS) are pollution standards set by the federal Environmental Protection Agency (EPA) through the Clean Air Act. The NAAQS set ambient pollutant standards to address seven criteria pollutants (see Figure 2):
less than 10 microns) Lead
Ozone (O ) Carbon Monoxide (CO) Nitrogen Dioxide (NO ) Sulfur Dioxide (SO ) PM10 (particulate matter with a diameter of
1990 CAAA Titles
Title I - Attainment and Maintenance of the National Ambient Air Quality Standards: Deals with attaining and maintaining the National Ambient Air Quality Standard (NAAQS) for six criteria pollutants. Title II - Mobile Sources: Establishes stricter emission standards for motor vehicles. Title III - Hazardous Air Pollutants: Identifies and calls for reductions in 189 toxic pollutants. Title IV - Acid Deposition Control: Addresses NOx and SO2 reduction in large utility boilers (major sources). Regulations for industrial units will be developed shortly. Title V - Permits: Establishes a comprehensive operating permit program for air emissions. Title VI - Stratospheric Ozone Protection: Requires a complete phase-out of chlorofluorocarbons (CFCs) and halons. Title VII - Enforcement: Gives the EPA more administrative enforcement penalties. It is now a felony to knowingly violate the Clean Air Act. Title VIII - Miscellaneous: Addresses oil drilling and visibility provisions. Title IX - Clean Air Research: Addresses air pollution research in the areas of monitoring and modeling, health effects, ecological effects, pollution prevention, emission control, and acid rain. Title X - Disadvantaged Business Concerns: Requires that a portion of federal funds for air research go to disadvantaged firms. Title XI - Clean Air Employment Transition Assistance: Provides additional unemployment benefits to workers for retraining who are laid off because of compliance with the Clean Air Act.
NationalAmbientAirQualityStandards
Primary Standards	Averaging Times	Secondary Standards
9 ppm (10 mg/m3)	8-hour1	None 35 ppm (40 mg/m3)	1-hour1	None 1.5 g/m3	0.053 ppm (100 g/m3)	50 g/m3	150 Quarterly Average	Annual (Arithmetic Mean)	Annual2 (Arithmetic Mean)	Same as Primary Same as Primary Same as Primary
Carbon Monoxide	Lead	Nitrogen Dioxide	Particulate Matter (PM10)	Particulate Matter (PM2.5)	Ozone	Sulfur Oxides
g/m3	24-hour1 Annual3 (Arithmetic Mean)	Same as Primary
65 g/m3	24-hour4 0.08 ppm	0.03 ppm	0.14 ppm	8-hour5	Annual (Arithmetic Mean)	3-hour1	Same as Primary 0.5 ppm (1300ug/m3)
24-hour1	_
Not to be exceeded more than once per year. To attain this standard, the 3-year average of the weighted annual mean PM10 concentration at each monitor within an area must not exceed 50ug/m3. To attain this standard, the 3-year average of the weighted annual mean PM2.5 concentration from single or multiple community-oriented monitors must not exceed 15.0ug/m3. 4 To attain this standard, the 3-year average of the 98th percentile of 24-hour concentrations at each population-oriented monitor within an area must not exceed 65 ug/m3. 5 To attain this standard, the 3-year average of the fourth-highest daily maximum 8-hor average ozone concentrations measured at each monitor within an area over each year must not exceed 0.08 ppm.
figure 2 The NAAQS are designed to protect humans and the environment from the adverse effects of air pollutants. Unlike emission limitations, which specify allowable pollutant releases from air pollution sources, ambient standards set forth maximum allowable concentrations of pollutants in the outdoor, or ambient, air. The Clean Air Act sets 3 specific deadlines for every area in the country not in compliance with the NAAQS to enact regulations for achieving these standards.
Attainment and Nonattainment
Extreme & Severe Serious Moderate Marginal Transitional & Incomplete Data Areas Not Included
figure 3 Through the NAAQS, areas of the United States are designated as attainment and nonattainment. Simply put, areas with ambient pollutant levels below the NAAQS are in attainment. Areas with pollutant levels above the NAAQS are in nonattainment.
Note: Attainment/Nonattainment designation is made on a pollutant-by-pollutant basis for all pollutants included in the NAAQS. Therefore, an area can be designated as attainment and nonattainment because it may be in compliance with the NAAQS for one pollutant but not another.
The most common pollutant for which the NAAQS are exceeded is ozone. Ozone is not emitted directly from smokestacks, tailpipes, or other pollution sources. Instead, it is formed by the reaction of volatile organic compounds (VOCs) and nitrogen oxides (NOx) in the presence of sunlight. NOx and VOCs are released into the air by
automobiles, factories, and several other sources, including industrial boilers. As of January, 1994, there are 101 cities and towns violating the NAAQS for ozone (see Figure 3). Ozone nonattainment areas are classified into one of five categories, based on the amount by 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 nonattainment pollutant is carbon monoxide. As of January, 1994, 52 metropolitan areas exceed the NAAQS for carbon monoxide (see Figure 4). Carbon monoxide nonattainment areas are classified as serious and moderate, depending on the amount local CO levels exceed the NAAQS for CO. Although the number of nonattainment areas are not as great as they are for ozone and carbon monoxide, there are several areas violating the NAAQS for PM10, NOx, SOx, and lead. Areas violating the NAAQS for PM10 are subclassified as serious or moderate. There are no subclassifications for NOx, SOx, and lead. A listing of the ozone, CO, PM10, and SO2 nonattainment areas as of January, 1994 is included in Appendix A. The classifications of areas are constantly changing as air pollution levels are continuously under review for attainment/ nonattainment designation. For the most current attainment/nonattainment classification, contact your local air pollution control agency.
Through the NAAQS, the EPA has established pollution standards for six criteria pollutants. However, the NAAQS are only an interim step in the regulation of these pollutants. The ambient standards do not tell an individual polluter what must be done to control their emissions. Rather, Title I of the 1990 Clean Air Act Amendments delegates the responsibility to the states by requiring local nonattainment areas to develop a plan to reduce ambient pollution levels below the NAAQS. Nonattainment characteristics vary by area and pollutant. A nonattainment area can be affected by weather, geography, demographics, and other forces. Therefore, regulations established for one area may not be effective in another area. This is why the Federal EPA does not establish general, source-specific regulations for all nonattainment areas. The responsibility is assigned to the states. The states are required to develop State Implementation Plans, or SIPs. SIPs include regulations addressing individual pollution sources in order to achieve the pollutant reductions necessary to comply with the NAAQS. SIPs must address several elements of air pollution control as required by the EPA. The elements include: Attainment of the NAAQS within specified deadlines Emission limitations for individual sources Monitoring provisions Permit programs Several miscellaneous provisions A SIP is developed as follows. State regulation developers draft the SIP. Then it undergoes public comment. Next, it is submitted to the EPA for review. The EPA has established submittal dates for the SIPs, which vary depending on the nonattainment status of the local area. Many states have missed the deadlines and are still developing their SIPs. Once the EPA reviews the SIP, it is either approved or, if it fails to fulfill all requirements, the plan could be returned to the state for revision, or the EPA could draft a plan or portions of the plan for the state.
Note: You can obtain a copy of the sections of any SIP applying to industrial boilers by contacting your state air quality agency. It is important to become familiar with the SIP in your state, as the provisions within the SIP may directly impact industrial boilers.
If an owner or operator of a major source wants to release more of a criteria air pollutant, an offset (a reduction of the criteria air pollutant by an amount somewhat greater than the planned increase) must be obtained somewhere else, so that permit requirements are met and the nonattainment area keeps moving toward attainment. The company must also install tight pollution controls. An increase in a criteria air pollutant can be offset with a reduction of the pollutant from some other stack at the same plant or at another plant owned by the same or some other company in the nonattainment area. Since total polllution will continue to go down, trading offsets among companies is allowed. This is one of the market approaches to cleaning up air pollution in the Clean Air Act.
One situation where the Federal EPA has established nationally uniform source-specific regulations is through the New Source Performance Standards, or NSPS. The standards, which set minimal requirements for individual sources, address approximately 65 categories of new or modified stationary sources, including industrial boilers. However, because the NSPS are not based on the nonattainment status of the local area, they may result in over control in some locations and under control in others. The NSPS for industrial boilers regulate levels for NOx, SOx, and particulate matter. The regulated pollutants and requirements vary for different fuels and boiler sizes. There are currently three categories for the NSPS: Boilers with inputs greater than 250 MMBtu/hr Boilers with inputs between 100-250 MMBtu/hr Boilers with inputs between 10-100 MMBtu/hr The current Small Boiler NSPS apply to all new, modified, or reconstructed boilers with inputs between 10-100 MMBTU/hr where construction, modification, or reconstruction commenced after June 9, 1989. They set emission standards for SOx and particulate matter for boilers firing coal, distillate and residual oil, and wood. The NSPS also dictate record keeping requirements regarding fuel usage for all fuels, including natural gas. Record keeping requirements and compliance standards for the different emissions depends on the type of fuel fired and on the boiler size. For a summary of the Small Boiler NSPS, see Figure 5. Expect to hear more about the NSPS. The 1990 Clean Air Act Amendments require the EPA to review the current NSPS and modify the requirements to incorporate new technologies for several source categories addressed through the NSPS.
States must determine the boundaries of nonattainment areas through the use of the data collected. The boundaries of nonattainment and attainment areas can be difficult to define. For example, because of the high population in the northeastern United States and the close proximity of major cities, an ozone nonattainment area may enact regulations to bring the area into compliance. But because of the influence of the surrounding cities, attainment may not be achieved. Ozone nonattainment areas in the northeast are forming alliances to develop regulations because of the influence of pollution from a broad area. For example, uniform regulations are being developed for eleven states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Pennsylvania, Rhode Island, and Vermont) in what is designated by the Federal EPA as the Northeast Ozone Transport Region.
All of the activities mentioned earlier eventually will result in some form of regulation for areas classified as nonattainment. While it is impossible to predict what any given state will do, it appears that many are following the lead of Southern California. Southern California has the worst air quality in the United States. Their efforts toward cleaner air are usually considered to be the basis for establishing regulations in other areas of the country in high degrees of ozone nonattainment. Regulations will change as new technologies allow for lower emission levels. Also, adjustments will be made based on the improvements in air quality. It is necessary to stay involved with air quality regulations to keep appraised of any regulation changes. The application of regulations can take several different forms and is often based on the degree of nonattainment. Required controls are based on the size of equipment, total emissions from a facility, type of fuels used, or a combination of factors. For example, in ozone nonattainment areas, the required measures depend on the nonattainment degree and total emissions from the facility. Levels set by the EPA help identify major sources of VOCs and NOx emissions. If the total NOx or VOC emissions for a facility located in an ozone nonattainment area exceed the preestablished major source trigger levels, extensive computer modeling and stringent regulations may be necessary. The major source trigger levels are indicated in tons per year and apply to the total 6
STATE ACTIONS Nonattainment Areas
Air quality monitoring stations operate throughout the United States to assess local air quality. Readings are continuously taken from the stations to monitor the six criteria pollutants regulated through the NAAQS. The levels of the pollutants are continuously evaluated. If levels exceed the NAAQS, the area is classified as nonattainment.
Summary of Federal EPA Rules
New 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. CEMSrequired 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 are not 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 and corrective action taken. - For fuel supplies certificate, information on supplies and details of sampling and testing for coal and residual oil. - Records must be maintained for two years.
NOx or VOC emissions for all sources located at the facility. The major source trigger levels for the different ozone nonattainment classifications are shown in Figure 6. To put this in perspective, a facility with three 800 horsepower boilers firing natural gas 24 hours per day, 365 days per year, would result in an uncontrolled NOx level of 57 tons per year (based on a NOx level of 0.13 lb/MMBtu). Referring to major source trigger levels specified in Figure 6, consider the following. If the facility is located in a moderate or marginal ozone nonattainment area, it is not a major source. But, if it is located in a serious, severe, or extreme ozone nonattainment area, it is a major source and would have specific air quality NOx control requirements. These requirements may include: An extensive permit application Dispersion modeling Procurement of emission offsets Stringent emission limitations
An Emission Alphabet
If a facility is classified as a major source, regulations may require technology equivalent to: Maximum Achievable Control Technology (MACT) Lowest Achievable Emission Rate (LAER) Reasonably Available Control Technology (RACT) All three regulations are based on technology and do not directly specify an emission level requirement. Instead, they require an evaluation of each affected facility in order to determine the applicable emission and technology requirements. As new technologies are developed, which may result in greater emission reductions than currently available, they must be included in the evaluation. Technology-based regulations have been utilized for years and proven effective.
Maximum Achievable Control Technology (MACT) is a regulation requiring an evaluation of all current technologies to determine the emission limitation for a new source. It is established on a case-by-case basis for sources and takes into account energy, environmental, and economic impacts. MACT evaluates the optimum effectiveness of a control technology against the
Continuous emission monitoring equipment Extensive emission controls Detailed fuel usage recording
0 Attainment Marginal Moderate Serious Severe Extreme
extremity of the environmental condition. In establishing MACT for a source, cost is not the only the driving factor. When cost is a consideration, the equipment (cost) is compared to the annual emission reductions in order to determine a figure in dollars per ton of pollutant removed (see Figure 7). The comparison is called the cost effectiveness of the technology. The regulations requiring MACT set a maximum cost figure that the polluter can spend in order to meet local emission requirements. If the cost effectiveness of the technology is above the figure, the technology is not required and the next lower cost technology MACT is evaluated. The process of reviewing each technology in decreasing order of cost is called Top Down BACT. The Top Down BACT process assures that the source achieves the lowest emission level within the required cost effectiveness. Typical regulations in areas of moderate and serious nonattainment for ozone require boiler owners to utilize NOx control technologies that result in a cost effectiveness figure between $3,000$10,000 per ton of NOx removed. In severe and extreme ozone nonattainment areas, the required cost effectiveness can be as high as $24,500 per ton of NOx controlled.
Reasonably Available Control Technology (RACT) is similar to BACT in that cost effectiveness is associated with the boiler owners emission requirements. The difference is that RACT is utilized on existing sources while MACT is used on new or modified sources. The cost requirements for RACT are less and are intended to be available at a reasonable cost. Many states with ozone nonattainment areas have submitted proposed RACT regulations to the EPA for approval as part of the SIP requirements. Many of the regulations set emission limitations from industrial boilers that can be achieved through burning cleaner fuels (i.e., natural gas), utilizing low NOx technologies, or a combination of both. Owners of industrial boilers located in ozone nonattainment areas should be familiar with the RACT requirements in their states.
Lowest Achievable Emission Rates
Some regulations require technology equivalent to the Lowest Achievable Emission Rate (LAER) be utilized in new major sources located in nonattainment areas. LAER is different from BACT in that it has no economic justification associated with its requirements. When required, technology equivalent to LAER must be installed regardless
MACT/RACT Cost Effectiveness
Annualized Costs of Control Equipment* Uncontrolled Emission Controlled Emission Rate	Rate Example: Uncontrolled Emission Rate	Controlled Emission Rate	Annualized Cost of Emission Control Method	$70,000 18 tpy - 4 tpy =	$70,000/year =	18 tons/year =	4 tons/year
= $5,000/ton of NOx removed
* considering hardware, installation, operating and maintenance costs figure 7 9
of costs impacts. It is the most stringent of all technology-based regulations.
The permit program established under Title V of the 1990 Clean Air Act Amendments will undoubtedly affect the way each state conducts its permitting process. Title V requires a review (and most likely a revision) of each states permitting program in order to ensure that the states permit program meets all Federal EPA requirements. Elements of state permit programs that 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 to submit proposed permitting programs to the EPA. By November of 1994, the EPA must approve or disapprove the proposed permit programs. The new permit programs will go into effect when approved by the EPA or the EPA promulgates a program for states failing to submit a satisfactory program. Currently, several states have implemented a two-stage permitting process. In the first stage, a permit to construct must be obtained. The permit usually requires a detailed description of the installation, including information such as the type and size of equipment and associated emissions. The second stage of the permit process consists of obtaining an operating permit. In some states, emission testing may be part of the requirement for obtaining an operating permit. Although many states may have the same basic permitting structure, the details and requirements of the permitting process are different for each state. It is important to be aware of not only the state permitting requirements, but also any federal requirements (i.e., Small Boiler New Source Performance Standards) that may be applicable. It is particularly important to be familiar with the permitting process as the new federal and state programs are implemented. Nearly every source of air pollution will be affected. Any violators may face stiff penalties.
POLLUTANTS AND CONTROLTECHNIQUES
A pollutant can be defined as matter that contaminates air, soil, or water. Air pollutants are airborne contaminants that produce unwanted effects on humans and the environment. They occur as solids, liquid droplets, gases, or combinations of these forms. Generally, air pollutants are classified into two major categories: Primary Pollutants pollutants emitted directly from identifiable sources Secondary Pollutants pollutants formed by interaction between two or more primary pollutants To protect humans and the environment from the adverse effects of air pollutants, the EPA has established the National Ambient Air Quality Standards (see Figure 2, page 3). The Clean Air Act Amendments of 1990 require areas in noncompliance for one or more of the NAAQS pollutants to implement regulations to reduce ambient levels. All six pollutants addressed in the National Ambient Air Quality Standards are directly or indirectly related to the combustion process. The following sections describe the formation and control of the pollutants in industrial boilers, discuss their impact on humans and the environment, and describe the current emission control technologies.
sources to the total NOx level ranges from 60 to 80 percent: For stationary sources, it ranges between 20 and 40 percent. A significant portion of the NOx from stationary sources can be attributed to residential, commercial, and industrial sources, including industrial boilers. In industrial boilers, NOx is primarily formed in two ways; thermal NOx and fuel NOx. Thermal NOx Thermal NOx is formed when nitrogen and oxygen in the combustion air combine with one another at the high temperatures in a flame. Thermal NOx makes up the majority of NOx formed during the combustion of gases and light oils. Fuel NOx uel NOx is formed by the reaction of nitrogen F in the fuel with oxygen in the combustion air. It is rarely a problem with gaseous fuels. But in oils containing significant amounts of fuel-bound nitrogen, fuel NOx can account for up to 50% of the total NOx emissions. NOx emissions from boilers are influenced by many factors. The most significant factors are flame temperature and the amount of nitrogen in the fuel. Other factors affecting NOx formation are excess air level and combustion air temperature. While flame temperature primarily affects thermal NOx formation, the amount of nitrogen in the fuel determines the level of fuel NOx emissions. Fuel containing more nitrogen results in higher levels of NOx emissions (see Figure 9). Most NOx control technologies for industrial boilers, with inputs less than 100 MMBtu/hr, reduce thermal NOx and have little affect on fuel NOx. Fuel NOx is most economically reduced in commercial and industrial boilers by switching to cleaner fuels, if available.
Although there is evidence proving NOx, in itself, is harmful to humans, the main reason NOx is considered an environmental problem is because it initiates reactions that result in the production of ozone and acid rain. Ozone and acid rain can damage fabric, cause rubber to crack, reduce visibility, damage buildings, harm forests and lakes, and cause health problems. By controlling NOx levels, along with other contributing primary pollutants, the levels of acid rain and ozone can be reduced. The principal nitrogen pollutants generated by boilers are nitric oxide (NO) and nitrogen dioxide (NO2), collectively referred to as NOx. The majority of NOx produced during combustion is NO (95%). Once emitted into the atmosphere, NO reacts to form NO2. It is NO2 that reacts with other pollutants to form ozone. The contribution from different NOx sources to the total NOx levels varies among metropolitan areas. In general, the contribution of mobile 11
NOx controls can be classified into two types; post combustion methods and combustion control techniques. Post combustion methods address NOx emissions after formation while combustion control techniques prevent the formation of NOx during the combustion process. Post combustion methods tend to be more expensive than combustion control techniques and generally are not used on boilers with inputs of less than 100 MMBtu/hr. Following is a list of different NOx control methods.
Pollutnats and Control Techniques
figure 8 Post Combustion Control Methods Selective Non-Catalytic Reduction Selective Catalytic Reduction Low Excess Air Firing Low Nitrogen Fuel Oil Burner Modifications Water/Steam Injection Flue Gas Recirculation flue gas temperature. And in industrial boilers that modulate frequently, the location of the exhaust gases at the specified temperature is constantly changing. Thus, it is not feasible to apply selective non-catalytic reduction to industrial boilers that have high turndown capabilities and modulate frequently. Selective Catalytic Reduction Selective catalytic reduction involves the injection of ammonia in the boiler exhaust gases in the presence of a catalyst (see Figure 11). The catalyst allows the ammonia to reduce NOx levels at lower exhaust temperatures than selective noncatalytic reduction. Unlike selective non-catalytic reduction, where the exhaust gases must be approximately 1400-1600F, selective catalytic reduction can be utilized where exhaust gases are between 500 and 1200F, depending on the catalyst used. Selective catalytic reduction can result in NOx reductions up to 90%. However, it is costly to use and rarely can be cost justified on boilers with inputs less than 100 MMBtu/hr.
Each method results in a different degree of NOx control. For example, when firing natural gas, low excess air firing typically reduces NOx by 10%, flue gas recirculation by 75%, and selective catalytic reduction by 90%. Post Combustion Control Methods Selective Non-catalytic Reduction Selective non-catalytic reduction involves the injection of a NOx reducing agent, such as ammonia or urea, in the boiler exhaust gases at a temperature of approximately 1400-1600F (see Figure 10). The ammonia or urea breaks down the NOx in the exhaust gases into water and atmospheric nitrogen. Selective non-catalytic reduction reduces NOx up to 50%. However, the technology is extremely difficult to apply to industrial boilers that modulate frequently. This is because the ammonia (or urea) must be injected in the flue gases at a specific 12
figure 10 Low Excess Air (LEA) Firing As a safety factor to assure complete combustion, boilers are fired with excess air. One of the factors influencing NOx formation in a boiler is the excess air levels. High excess air levels (>45%) may result in increased NOx formation because the excess nitrogen and oxygen in the combustion air entering the flame will combine to form thermal NOx. Low excess air firing involves limiting the amount of excess air that is entering the combustion process in order to limit the amount of extra nitrogen and oxygen that enters the flame. Limiting the amount of excess air entering a flame is usually accomplished through burner design and can be optimized through the use of oxygen trim controls. Low excess air firing can be used on most boilers and generally results in overall NOx reductions of 5-10% when firing natural gas. 13 Low Nitrogen Fuel Oil When firing fuel oils, NOx formed by fuelbound nitrogen can account for 20-50% of the total NOx level. Utilizing fuel oils with lower nitrogen contents results in lower NOx levels. One method to reduce NOx levels from boilers firing distillate oils is through the use of low nitrogen fuel oil. Low nitrogen oils can contain up to 15-20 times less fuel-bound nitrogen than standard No. 2 oil (less than 0.001% fuel-bound nitrogen). When low NOx oil is fired in firetube boilers utilizing flue gas recirculation, NOx reductions of 60%-70% over NOx emissions from standard No. 2 oils have been achieved. Low nitrogen oil is currently used most frequently in Southern California.
Burner Modifications Burner modifications for NOx control involve changing the design of a standard burner in order to create a larger flame. Enlarging the flame results in lower flame temperatures and lower thermal NOx formation which, in turn, results in lower overall NOx emissions. The technology can be applied to most boiler types and sizes. It is most effective when firing natural gas and distillate fuel oil and has little affect on boilers firing heavy oil. To comply with the more stringent regulations, burner modifications must be used in conjunction with other NOx reduction methods, such as flue gas recirculation. If burner modifications are utilized exclusively to achieve low NOx levels (30 ppm), adverse affects on boiler operating parameters such as turndown, capacity, CO levels, and efficiency may result. It is important to address all aspects of NOx control when selecting NOx control technologies (see Side Bar, this page). Water/Steam Injection Water or steam injection can be utilized to reduce NOx levels. By introducing water or steam into the flame, flame temperatures are reduced, thereby lowering thermal NOx formation and overall NOx levels. Water or steam injection can reduce NOx up to 80% (when firing natural gas) and can result in lower reductions when firing oils. There is a practical limit to the amount of water or steam that can be injected into the flame before condensation problems are experienced. Additionally, under normal operating conditions, water/steam injection can result in a 3-10% efficiency loss. Many times water or steam injection is used in conjunction with other NOx control methods such as burner modifications or flue gas recirculation. Flue Gas Recirculation Flue gas recirculation, or FGR, is the most effective method of reducing NOx emission from industrial boilers with inputs below 100 MMBtu/hr. FGR entails recirculating a portion of relatively cool exhaust gases back into the combustion zone in order to lower the flame temperature and reduce NOx formation. It is currently the most effective and popular low NOx technology for firetube and watertube boilers. And, in many applications, it does not require any additional reduction equipment to comply with the most stringent regulations in the United States. Flue gas recirculation technology can be classified into two types; external or induced. External flue gas recirculation utilizes an external fan to recirculate the flue gases back into the 14
combustion zone. External piping routes the exhaust gases from the stack to the burner. A valve controls the recirculation rate, based on boiler input. Induced flue gas recirculation utilizes the combustion air fan to recirculate the flue gases back into the combustion zone. A portion of the flue gases are routed by duct work or internally to the combustion air fan, where they are premixed with the combustion air and introduced into the flame through the burner. New designs of induced FGR that utilize an integral FGR design are becoming popular among boiler owners and operators because of their uncomplicated design and reliability. Theoretically, there is no limit to the amount of NOx reduction with FGR; practically, there is a physical, feasible limit. The limit of NOx reduction varies for different fuels - 90% for natural gas and 25-30% for standard fuel oils. The current trends with low NOx technologies are to design the boiler and low NOx equipment as a package. Designing as a true package allows the NOx control technology to be specifically tailored to match the boilers furnace design features, such as shape, volume, and heat release. By designing the low NOx technology as a package with the boiler, the effects of the low NOx technology on boiler operating parameters (turndown, capacity, efficiency, and CO levels) can be addressed and minimized.
What effect does NOx control technology ultimately have on a boilers performance? Certain NOx controls can worsen boiler performance while other controls can appreciably improve performance. Aspects of the boiler performance that could be affected include turndown, capacity, efficiency, excess air, and CO emissions. Failure to take into account all of the boiler operating parameters can lead to increased operating and maintenance costs, loss of efficiency, elevated CO levels, and shortening of the boilers life. The following section discusses each of the operating parameters of a boiler and how they relate to NOx control technology.
TURNDOWN Choosing a low NOx technology that sacrifices turndown can have many adverse effects on the boiler. When selecting NOx control, the boiler should have a turndown capability of at least 4:1 or more, in order to reduce operating costs and the number of on/off cycles. A boiler utilizing a standard burner with a 4:1 turndown can cycle as frequently as 12 times per hour or 288 times a day because the boiler must begin to cycle at inputs below 25% capacity. With each cycle, pre- and post-purge air flow removes heat from the boiler and sends it out the stack. The energy loss can be reduced by using a high turndown burner (10:1), which keeps the boiler on at low firing rates. Every time the boiler cycles off, it must go through a specific start-up sequence for safety assurance. It takes about one to two minutes to get the boiler back on line. If there is a sudden load demand, the response cannot be accelerated. Keeping the boiler on line assures a quick response to load changes. Frequent cycling also deteriorates the boiler components. Maintenance increases, the chance of component failure increases, and boiler downtime increases. So, when selecting NOx control, always consider the burners turndown capability. CAPACITY When selecting the best NOx control, capacity and turndown should be considered together because some NOx control technologies require boiler derating in order to achieve guaranteed NOx reductions. For example, flame shaping (primarily enlarging the flame to produce a lower flame temperature - thus lower NOx levels) can require boiler derating, because the shaped flame could impinge on the furnace walls at higher firing rates. However, the boilers capacity requirement is typically determined by the maximum load in the steam/hot water system. Therefore, the boiler may be oversized for the typical load conditions occurring. If the boiler is oversized, its ability to handle minimum loads without cycling is limited. Therefore, when selecting the most appropriate NOx control, capacity and turndown should be considered together for proper boiler selection and to meet overall system load requirements.
EFFICIENCY Some low NOx controls reduce emissions by lowering flame temperature, particularly in boilers with inputs less than 100 MMBtu/hr. Reducing the flame temperature decreases the radiative heat transfer from the flame and could lower boiler efficiency. The efficiency loss due to the lower flame temperatures can be partially offset by utilizing external components, such as an economizer. Or, the loss can be greatly reduced or eliminated by the boiler/burner design. One technology that offsets the efficiency loss due to lower flame temperatures in a firetube boiler is flue gas recirculation. Although the radiant heat transfer could result in an efficiency loss, the recirculated flue gases increase the mass flow through the boiler - thus the convective heat transfer in the tube passes increases. The increase in convective heat transfer compensates for losses in radiative heat transfer, with no net efficiency loss. When considering NOx control technology, remember, it is not necessary to sacrifice efficiency for NOx reductions. EXCESS AIR A boilers excess air supply provides for safe operation above stoichiometric conditions. A typical burner is usually set up with 10-20% excess air (2-4% O2). NOx controls that require higher excess air levels can result in fuel being used to heat the air rather than transferring it to usable energy. Thus, increased stack losses and reduced boiler efficiency occur. NOx controls that require reduced excess air levels can result in an oxygen deficient flame and increased levels of carbon monoxide or unburned hydrocarbons. It is best to select a NOx control technology that has little effect on excess air. CO EMISSIONS High flame temperatures and intimate air/fuel mixing are essential for low CO emissions. Some NOx control technologies used on industrial and commercial boilers reduce NOx levels by lowering flame temperatures by modifying air/fuel mixing patterns. The lower flame temperature and decreased mixing intensity can result in higher CO levels. An induced flue gas recirculation package can lower NOx levels by reducing flame temperature without increasing CO levels. CO levels remain constant or are lowered because the flue gas is introduced into the flame in the early stages of 15
combustion and the air fuel mixing is intensified. Intensified mixing offsets the decrease in flame temperature and results in CO levels that are lower than achieved without FGR. Induced FGR lowers CO levels as well as NOx levels. But, the level of CO depends on the burner design. Not all flue gas recirculation applications result in lower CO levels.
alone is not enough to meet more stringent SOx emission requirements; reduction methods must also be employed. Methods of SOx reduction include switching to low sulfur fuel, desulfurizing the fuel, and utilizing a flue gas desulfurization (FGD) system. Fuel desulfurization, which primarily applies to coal, involves removing sulfur from the fuel prior to burning. Flue gas desulfurization involves the utilization of scrubbers to remove SOx emissions from the flue gases. Flue gas desulfurization systems are classified as either nonregenerable or regenerable. Nonregenerable FGD systems, the most common type, result in a waste product that requires proper disposal. Regenerable FGD converts the waste byproduct into a marketable product, such as sulfur or sulfuric acid. SOx emission reductions of 90-95% can be achieved through FGD. Fuel desulfurization and FGD are primarily used for reducing SOx emissions for large utility boilers. Generally the technology cannot be cost justified on industrial boilers. For users of industrial boilers, utilizing low sulfur fuels is the most cost effective method of SOx reduction. Because SOx emissions primarily
TOTAL PERFORMANCE Selecting the best low NOx control package should be made with total boiler performance in mind. Consider the application. Investigate all of the characteristics of the control technology and the effects of the technology on the boilers performance. A NOx control technology that results in the greatest NOx reduction is not necessarily the best for the application or the best for high turndown, adequate capacity, high efficiency, sufficient excess air, or lower CO. The newer low NOx technologies provide NOx reductions without affecting total boiler performance.
The primary reason sulfur compounds, or SOx, are classified as a pollutant is because they react with water vapor (in the flue gas and atmosphere) to form sulfuric acid mist. Airborne sulfuric acid has been found in fog, smog, acid rain, and snow. Sulfuric acid has also been found in lakes, rivers, and soil. The acid is extremely corrosive and harmful to the environment. The combustion of fuels containing sulfur (primarily oils and coals) results in pollutants occurring in the form of SO2 (sulfur dioxide) and SO3 ( sulfur trioxide), together referred to as SOx (sulfur oxides). The level of SOx emitted depends directly on the sulfur content of the fuel (see Figure 11). The level of SOx emissions is not dependent on boiler size or burner design. Typically, about 95% of the sulfur in the fuel will be emitted as SO2, 1-5% as SO3, and 1-3% as sulfate particulate. Sulfate particulate is not considered part of the total SOx emissions. Historically, SOx pollution has been controlled by either dispersion or reduction. Dispersion involves the utilization of a tall stack, which enables the release of pollutants high above the ground and over any surrounding buildings, mountains, or hills, in order to limit ground level SOx emissions. Today, dispersion 16
figure 11 depend on the sulfur content of the fuel, burning fuels containing a minimal amount of sulfur (distillate oil) can achieve SOx reductions, without the need to install and maintain expensive equipment.
Carbon monoxide is a pollutant that is readily absorbed in the body and can impair the oxygencarrying capacity of the hemoglobin. Impairment of
the bodys hemoglobin results in less oxygen to the brain, heart, and tissues. Short-term over exposure to carbon monoxide can be critical, even fatal, to people with heart and lung diseases. It also may cause headaches and dizziness in healthy people. During combustion, carbon in the fuel oxidizes through a series of reactions to form carbon dioxide (CO2). However, 100 percent conversion of carbon to CO2 is rarely achieved in practice and some carbon only oxidizes to the intermediate step, carbon monoxide. Older boilers generally have higher levels of CO than new equipment because CO has only recently become a concern and older burners were not designed to achieve low CO levels. In todays equipment, high levels of carbon monoxide emissions primarily result from incomplete combustion due to poor burner design or firing conditions (for example, an improper air-to-fuel ratio) or possibly a compromised furnace seal. Through proper burner maintenance, inspections, operation, or by upgrading equipment or utilizing an oxygen control package, the formation of carbon monoxide can be controlled at an acceptable level.
Ozone is a highly reactive form of oxygen. Ground level ozone is a secondary pollutant formed by the reaction of volatile organic compounds (VOCs) with nitrogen oxides (NOx) in the presence of sunlight. Ozone formed at the ground level is the main component of smog. It is known to irritate the eyes, nose, throat, and lungs, and also cause damage to crops. Ground level ozone should not be confused with ozone in the upper atmosphere. Since ozone is formed by the reaction of VOCs and NOx, methods of ozone reduction focus on the control of these two pollutants. Recent studies show that reducing NOx emissions in several ozone nonattainment areas would be beneficial in meeting federal ozone standards. Sources of VOCs are automobiles, solvents, paints, domestic products and, in nature, decomposition of organic materials such as wood and grass. Although a major source of VOCs is automobiles, the ozone standards also address stationary sources; including boilers. Regulations limiting VOC emissions from stationary combustion sources are relatively new. The regulations originally applied only to large utility boilers, but now are beginning to address industrial boilers. These regulations are primarily at the state level and vary among states. VOCs are compounds containing combinations of carbon, hydrogen and sometimes oxygen. They can be vaporized easily at low temperatures. They often are referred to as hydrocarbons and generally are divided into two categories methane and non-methane hydrocarbons. VOCs can result from poor combustion but, more commonly, result from vaporization of fuels and paints. Leaks in oil or gas piping, and even the few drops of gasoline spilled when filling an automobile, are sources of VOCs. 17
Emissions of particulate matter (PM) from combustion sources consist of many different types of compounds, including nitrates, sulfates, carbons, oxides, and any uncombusted elements in the fuel. Particulate pollutants can be corrosive, toxic to plants and animals, and harmful to humans. Particulate matter emissions generally are classified into two categories, PM and PM10. PM10 is a particulate matter with a diameter less than 10 microns. All particulate matter can pose a health problem. However, the greatest concern is with PM10, because of its ability to bypass the bodys natural filtering system. PM emissions primarily depend on the grade of fuel fired in the boiler. Generally, PM levels from natural gas are significantly lower than those of oils. Distillate oils result in much lower particulate emissions than residual oils. When burning heavy oils, particulate levels mainly depend on four fuel constituents: sulfur, ash, carbon residue, and asphaltines. The constituents exist in fuel oils, particularly residual oils, and have a major effect on particulate emissions. By knowing the content of the components, the particulate emissions for the oil can be estimated.
Control of VOC emissions is best accomplished by maintaining proper combustion conditions. The use of controls to maintain proper air-to-fuel ratios and periodic burner maintenance checks should result in reducing VOC emissions below imposed limits.
Note: If a boiler is operated improperly or is poorly maintained (incorrect air/fuel ratio, inadequate atomizing pressure for oil burners, and improper air and fuel pressures), the concentration of VOCs may increase by several orders of magnitude.
We hope you have a better grasp of how federal, state, and local governments are regulating air pollution. We also hope you have a better understanding of NOx and CO emissions and industrial boiler control technologies. When you need to specify or purchase an industrial boiler with emission control technology, your local Cleaver-Brooks authorized representative is available to discuss control technology options and how you can achieve the lowest possible emissions. If at any time you need more information, please dont hesitate to contact your local Cleaver-Brooks representative.
Lead poisoning can lead to diminished physical fitness, fatigue, sleep disturbance, headache, aching bones and muscles, and digestive upset, including anorexia. Lead poisoning primarily involves the gastrointestinal tract and the peripheral and central nervous systems. Lead emissions are primarily a result of gasoline combustion in automobile engines and depend highly on the lead content of the fuel. Efforts to reduce lead emissions have focused on the use of lead-free fuels, particularly in automobiles. New blends of gasoline containing lower levels of lead additives continue to be introduced. The impact of lead emission regulations in industrial boilers that burn standard fuels has been minimal because the fuels generally contain little or no lead. Boilers that fire alternate fuels containing lead are subject to stringent federal, state, and local regulations. For example, under the Federal Resource Conservation Recovery Act (RCRA), waste oil to be burned as fuel in an industrial boiler must contain less than 50 ppm lead. As a result of such strict regulations, the use of fuel containing lead in industrial boilers is limited.
CLASSIFIED OZONE NONATTAINMENT AREAS (January 1994)
ALABAMA(Region IV) Birmingham, AL (Subpart 1)
Jefferson Co Shelby Co [m*] [m*]
San Francisco Bay Area, CA (Marginal)
Alameda Co Contra Costa Co Marin Co Napa Co	San Francisco Co	San Mateo Co	Santa Clara Co	Solano Co (P)	Sonoma Co (P)	[n*] [n*] [n*] [n*] [n*] [n*] [n*] [n*] [n*]
ARIZONA(Region IX) Phoenix-Mesa, AZ (Subpart 1)
Maricopa Co (P)	Pinal Co (P)	[n*] [*]
ARKANSAS(Region VI) Memphis, TN-AR
Fresno Co	Kern Co (P)	Kings Co	Madera Co	Merced Co	San Joaquin Co	Stanislaus Co	Tulare Co
[n*] [n*] [n*] [n*] [n*] [n*] [n*] [n*]
CALIFORNIA(Region IX)
Amador and Calaveras Cos (Central Mtn), CA (Subpart 1)
Amador Co Calaveras Co
Sutter Co (Sutter Buttes), CA (Subpart 1)
Sutter Co (P)	[n*]
Chico, CA (Subpart 1)
Butte Co [n*]
Imperial Co Kern Co (P)
[n*] [m*]
Kern Co (Eastern Kern), CA (Subpart 1) Los Angeles South Coast Air Basin, CA
Los Angeles Co (P) Orange Co Riverside Co (P) San Bernardino Co (P)
COLORADO(Region VIII) Denver-Boulder-Greeley-Ft Collins-Love., CO (Subpart 1 EAC)
Adams Co	Arapahoe Co	Boulder Co	Broomfield Co	Denver Co	Douglas Co	Jefferson Co	Larimer Co (P)	Weld Co (P)	[m*] [m*] [m*] [m*] [m*] [m*] [m*] [*] [*]
(Severe 17)
[n*] [n*] [n*] [n*]
Los Angeles-San Bernardino Cos (W Mojave),CA (Moderate)
Los Angeles Co (P) San Bernardino Co (P) [n*] [n*]
Mariposa and Tuolumne Cos (Southern Mtn),CA (Subpart 1)
Mariposa Co Tuolumne Co
CONNECTICUT(Region I) Greater Connecticut, CT
Hartford Co	Litchfield Co	New London Co	Tolland Co	Windham Co
[n*] [n*] [n*] [n*] [n*]
Nevada Co. (Western Part), CA (Subpart 1)
Nevada Co (P)
Riverside Co (P)
New York-N. New JerseyLong Island,NY-NJ-CT
Fairfield Co	Middlesex Co	New Haven Co
[n*] [n*] [n*]
El Dorado Co (P) Placer Co (P) Sacramento Co Solano Co (P) Sutter Co (P) Yolo Co
[n*] [n*] [n*] [n*] [n*] [n*] [m*]
DELAWARE(Region III) Philadelphia-Wilmin-Atlantic Ci,PA-NJ-MD-DE
Kent Co	New Castle Co	Sussex Co
San Diego, CA (Subpart 1)
San Diego Co (P)
Imperial Co, CA
Ventura Co (P)	[n*] That part of Ventura County excluding the Channel Islands of Anacapa and San Nicolas Islands.
CLASSIFIED OZONE NONATTAINMENT AREAS (DATE ???)
DISTRICT OF COLUMBIA (Region III) Washington, DC-MD-VA (Moderate)
Entire District	[n*]
Cincinnati-Hamilton, OH-KY-IN (Subpart 1)
Dearborn Co (P) Lawrenceburg Township
GEORGIA(Region IV) Atlanta, GA
Barrow Co Bartow Co Carroll Co Cherokee Co	Clayton Co	Cobb Co	Coweta Co	De Kalb Co	Douglas Co	Fayette Co	Forsyth Co	Fulton Co	Gwinnett Co	Hall Co Henry Co	Newton Co Paulding Co	Rockdale Co	Spalding Co Walton Co Catoosa Co
Evansville, IN (Subpart 1)
Vanderburgh Co	Warrick Co [m*]
Fort Wayne, IN (Subpart 1)
Allen Co [n*] [n*] [n*] [n*] [n*] [n*] [n*] [n*] [n*] [n*] [n*] [n*] [n*]
Greene Co, IN (Subpart 1)
Indianapolis, IN (Subpart 1)
Boone Co Hancock Co Hendricks Co Johnson Co Madison Co Marion Co Morgan Co Shelby Co
Jackson Co, IN (Subpart 1)
La Porte Co
Chattanooga, TN-GA (Subpart 1 EAC) Macon, GA (Subpart 1)
Bibb Co Monroe Co (P)
Louisville, KY-IN (Subpart 1)
Clark Co	Floyd Co	[m*] [m*]
Muncie, IN (Subpart 1)
Murray Co (Chattahoochee Nat Forest), GA (Subpart 1)
Murray Co (P)
South Bend-Elkhart, IN (Subpart 1)
Elkhart Co	St Joseph Co	[m*] [m*]
ILLINOIS(Region V) Chicago-Gary-Lake County, IL-IN	(Moderate)
Cook Co	Du Page Co	Grundy Co (P)	Aux Sable Township, Goose Lake Township Kane Co	Kendall Co (P)	Oswego Township Lake Co	Mc Henry Co	Will Co	[n*] [n*] [n*] [n*] [n*] [n*] [n*] [n*]
Terre Haute, IN (Subpart 1)
KENTUCKY(Region IV) Cincinnati-Hamilton, OH-KY-IN (Subpart 1)
Boone Co	Campbell Co	Kenton Co	[m*] [m*] [m*]
Clarksville-Hopkinsville, TN-KY (Subpart 1)
Jersey Co	Madison Co	Monroe Co	St Clair Co
[m*] [m*] [m*] [m*]
Huntington-Ashland, WV-KY (Subpart 1)
Boyd Co	[m*] [m*] [m*] [m*]
Bullitt Co	Jefferson Co	Oldham Co
INDIANA(Region V) Chicago-Gary-Lake County, IL-IN
Lake Co	Porter Co
LOUISIANA(Region VI) (Moderate)
[n*] [n*]
East Baton Rouge Par	Iberville Par	Livingston Par	West Baton Rouge Par
Springfield (Western MA), MA (Moderate)
Berkshire Co	Franklin Co	Hampden Co	Hampshire Co	[n*] [n*] [n*] [n*]
MAINE(Region I) Hancock, Knox, Lincoln & Waldo Cos, ME (Subpart 1)
Hancock Co (P)	Knox Co (P)	Lincoln Co (P)	Waldo Co (P)	[m*] [n*] [n*] [m*]
MICHIGAN(Region V) Allegan Co, MI (Subpart 1)
Allegan Co	[m*]
Benton Harbor, MI (Subpart 1)
Androscoggin Co (P)	Cumberland Co (P)	Sagadahoc Co	York Co (P)
Benzie Co, MI (Subpart 1)
MARYLAND(Region III) Baltimore, MD
Anne Arundel Co	Baltimore (City)	Baltimore Co	Carroll Co	Harford Co	Howard Co
Detroit-Ann Arbor, MI (Marginal) (Moderate)
[n*] [n*] [n*] [n*] [n*] [n*] Lenawee Co Livingston Co	Macomb Co	Monroe Co	Oakland Co	St Clair Co	Washtenaw Co	Wayne Co	[m*] [m*] [m*] [m*] [m*] [m*] [m*] [m*]
Kent and Queen Annes Cos, MD
Kent Co	Queen Annes Co
[m*] [m*]
Flint, MI (Subpart 1)
Genesee Co	Lapeer Co
Philadelphia-Wilmin-Atlantic Ci,PA-NJ-MD-DE
Grand Rapids, MI (Subpart 1)
Kent Co	Ottawa Co	[m*] [m*]
Washington Co (Hagerstown), MD (Subpart 1 EAC)
Huron Co, MI (Subpart 1)
Kalamazoo-Battle Creek, MI (Subpart 1)
Calhoun Co Kalamazoo Co Van Buren Co
Washington, DC-MD-VA (Moderate)
Calvert Co	Charles Co	Frederick Co	Montgomery Co	Prince Georges Co	[n*] [n*] [n*] [n*] [n*]
Lansing-East Lansing, MI (Subpart 1)
Clinton Co Eaton Co Ingham Co
MASSACHUSETTS(Region I) Boston-Lawrence-Worcester (E. MA), MA
Barnstable Co	Bristol Co	Dukes Co	Essex Co	Middlesex Co	Nantucket Co	Norfolk Co	Plymouth Co	Suffolk Co	Worcester Co
Mason Co, MI (Subpart 1) (Moderate)
[n*] [n*] [n*] [n*] [n*] [n*] [n*] [n*] [n*] [n*] Mason Co
Muskegon, MI (Marginal)
Muskegon Co [m*]
MISSOURI(Region VII) St Louis, MO-IL (Moderate)
Franklin Co Jefferson Co St Charles Co	St Louis	St Louis Co [m*] [m*] [m*] [m*] [m*]
NEVADA(Region IX) Las Vegas, NV (Subpart 1)
Clark Co (P) [*]
Bronx Co	Kings Co	Nassau Co	New York Co	Queens Co	Richmond Co	Rockland Co	Suffolk Co	Westchester Co
[n*] [n*] [n*] [n*] [n*] [n*] [n*] [n*] [n*]
NEW HAMPSHIRE(Region I) Boston-ManchesterPortsmouth(SE),NH
Hillsborough Co (P)	Merrimack Co (P)	Rockingham Co (P)	Strafford Co (P)
Dutchess Co	Orange Co	Putnam Co
NEW JERSEY(Region II) New York-N. New JerseyLong Island,NY-NJ-CT
Bergen Co	Essex Co	Hudson Co	Hunterdon Co	Middlesex Co	Monmouth Co	Morris Co	Passaic Co	Somerset Co	Sussex Co	Union Co	Warren Co
[n*] [n*] [n*] [n*] [n*] [n*] [n*] [n*] [n*] [n*] [n*] [n*]
Rochester, NY (Subpart 1)
Genesee Co Livingston Co Monroe Co Ontario Co Orleans Co Wayne Co
NORTH CAROLINA(Region IV) Charlotte-GastoniaRock Hill, NC-SC
Cabarrus Co Gaston Co	Iredell Co (P) Davidson Township Coddle Creek Township Lincoln Co Mecklenburg Co	Rowan Co Union Co Cumberland Co
Philadelphia-WilminAtlantic Ci,PA-NJ-MD-DE
Atlantic Co	Burlington Co	Camden Co	Cape May Co	Cumberland Co	Gloucester Co	Mercer Co	Ocean Co	Salem Co
Fayetteville, NC (Subpart 1 EAC) Greensboro-Winston SalemHigh Point, NC (Marginal EAC)
Alamance Co Caswell Co Davidson Co	Davie Co	Forsyth Co	Guilford Co	Randolph Co Rockingham Co [m*] [m*] [m*] [m*]
NEW YORK(Region II) Albany-Schenectady-Troy, NY (Subpart 1)
Albany Co	Greene Co	Montgomery Co	Rensselaer Co	Saratoga Co	Schenectady Co	Schoharie Co Erie Co	Niagara Co	[n*] [n*] [n*] [n*] [n*] [n*]
Buffalo-Niagara Falls, NY (Subpart 1)
Haywood and Swain Cos (Great Smoky NP), NC (Subpart 1)
Haywood Co (P) Great Smoky Mountain National Park Swain Co (P) Great Smoky Mountain National Park
Essex Co (Whiteface Mtn), NY (Subpart 1)
Essex Co (P)	[n*]
Jamestown, NY (Subpart 1)
Hickory-Morganton-Lenoir, NC (Subpart 1 EAC)
Alexander Co Burke Co (P) Unifour Metropolitan Planning Organization Boundary Caldwell Co (P) Unifour Metropolitan Planning Organization Boundary Catawba Co
Parkersburg-Marietta, WV-OH (Subpart 1) Washington Co Steubenville-Weirton, OH-WV (Subpart 1)
Jefferson Co	[m*] [m*] [m*]
Toledo, OH (Subpart 1)
Lucas Co Wood Co
Raleigh-Durham-Chapel Hill, NC (Subpart 1)
Chatham Co (P) Baldwin Township, Center Township, New Hope Township, Williams Township Durham Co	[m*] Franklin Co Granville Co	[m*] Johnston Co Orange Co Person Co Wake Co	[m*]
Wheeling, WV-OH (Subpart 1)
Youngstown-Warren-Sharon, OH-PA (Subpart 1)
Columbiana Co	Mahoning Co	Trumbull Co	[m*] [m*] [m*]
Rocky Mount, NC (Subpart 1)
Edgecombe Co Nash Co
PENNSYLVANIA(Region III) Allentown-BethlehemEaston, PA (Subpart 1)
Carbon Co	Lehigh Co	Northampton Co	[n*] [n*] [n*] [n*]
OHIO(Region V) Canton-Massillon, OH (Subpart 1)
Stark Co	[m*]
Altoona, PA (Subpart 1)
Butler Co	Clermont Co	Clinton Co	Hamilton Co	Warren Co	Ashtabula Co	Cuyahoga Co	Geauga Co	Lake Co	Lorain Co	Medina Co	Portage Co	Summit Co	[n*] [n*] [m*] [n*] [n*] [m*] [m*] [m*] [m*] [m*] [m*] [m*] [m*] [m*] [m*] [m*]
Clearfield and Indiana Cos, PA (Subpart 1)
Clearfield Co Indiana Co
Erie, PA (Subpart 1)
Erie Co	[n*] [n*] [n*]
Cleveland-Akron-Lorain, OH (Moderate)
Franklin Co, PA (Subpart 1)
Greene Co, PA (Subpart 1)
Harrisburg-LebanonCarlisle, PA (Subpart 1)
Cumberland Co	Dauphin Co	Lebanon Co	Perry Co	[n*] [n*] [n*] [n*] [n*]
Columbus, OH (Subpart 1)
Delaware Co	Fairfield Co Franklin Co	Knox Co Licking Co	Madison Co Clark Co	Greene Co	Miami Co	Montgomery Co
Johnstown, PA (Subpart 1)
Dayton-Springfield, OH (Subpart 1)
Lima, OH (Subpart 1)
Bucks Co	Chester Co	Delaware Co	Montgomery Co	Philadelphia Co
TENNESSEE(Region IV) Chattanooga, TN-GA (Subpart 1 EAC)
Hamilton Co Meigs Co
Pittsburgh-Beaver Valley, PA (Subpart 1)
Allegheny Co	Armstrong Co	Beaver Co	Butler Co	Fayette Co	Washington Co	Westmoreland Co	[m*] [m*] [m*] [m*] [m*] [m*] [m*] [m*] [n*] [n*] [n*] [n*]
Johnson City-Kingsport-Bristol, TN (Subpart 1 EAC)
Hawkins Co Sullivan Co
Knoxville, TN (Subpart 1)
Anderson Co Blount Co Cocke Co (P) (Great Smoky Mtn Park) Jefferson Co Knox Co	Loudon Co Sevier Co
Reading, PA (Subpart 1)
Berks Co	Lackawanna Co	Luzerne Co Monroe Co	Wyoming Co
Scranton-Wilkes-Barre, PA (Subpart 1)
[m*] [m*] [m*] [m*] [m*] [m*]
State College, PA (Subpart 1)
Nashville, TN (Subpart 1 EAC)
Davidson Co	Rutherford Co	Sumner Co	Williamson Co	Wilson Co	[n*] [n*]
Tioga Co, PA (Subpart 1)
York, PA (Subpart 1)
Adams Co	York Co
TEXAS(Region VI) Beaumont-Port Arthur, TX
Hardin Co	Jefferson Co	Orange Co
Mercer Co	[n*]
RHODE ISLAND(Region I) Providence (All RI), RI
Bristol Co	Kent Co	Newport Co	Providence Co	Washington Co
Dallas-Fort Worth, TX (Moderate)
[n*] [n*] [n*] [n*] [n*] Collin Co	Dallas Co	Denton Co	Ellis Co Johnson Co Parker Co Rockwall Co Tarrant Co
SOUTH CAROLINA(Region IV) Charlotte-GastoniaRock Hill, NC-SC
York Co (P) Portion along MPO lines
Houston-GalvestonBrazoria, TX
Brazoria Co	Chambers Co	Fort Bend Co	Galveston Co	Harris Co	Liberty Co	Montgomery Co	Waller Co	Bexar Co Comal Co Guadalupe Co
Columbia, SC (Subpart 1 EAC)
Lexington Co (P) Richland Co (P)
Greenville-SpartanburgAnderson, SC (Subpart 1 EAC)
Anderson Co Greenville Co Spartanburg Co
San Antonio, TX (Subpart 1 EAC)
VIRGINIA(Region III) Frederick Co, VA (Subpart 1 EAC)
Frederick Co Winchester
Charleston, WV (Subpart 1)
Kanawha Co	Putnam Co	Cabell Co	Wayne Co	[m*] [m*] [m*] [m*]
Huntington-Ashland, WV-KY (Subpart 1) (Moderate)
Fredericksburg Spotsylvania Co Stafford
Parkersburg-Marietta, WV-OH (Subpart 1)
Wood Co	[m*]
Madison and Page Cos (Shenandoah NP), VA (Subpart 1
Madison Co (P) Page Co (P)
Steubenville-Weirton, OH-WV (Subpart 1)
Brooke Co	Hancock Co	[*] [*]
Norfolk-Virginia BeachNewport News (HR),VA
Chesapeake	[m*] Gloucester Co Hampton	[m*] Isle Of Wight Co James City Co	[m*] Newport News	[m*] Norfolk	[m*] Poquoson	[m*] Portsmouth	[m*] Suffolk	[m*] Virginia Beach	[m*] Williamsburg	[m*] York Co	[m*]
Marshall Co Ohio Co
WISCONSIN(Region V) Door Co, WI (Subpart 1)
Door Co	[m*] [m*] [m*]
Kewaunee Co, WI (Subpart 1)
Manitowoc Co, WI (Subpart 1)
Charles City Co	[m*] Chesterfield Co	[m*] Colonial Heights	[m*] Hanover Co	[m*] Henrico Co	[m*] Hopewell	[m*] Petersburg Prince George Co Richmond	[m*]
Kenosha Co	Milwaukee Co	Ozaukee Co Racine Co	Washington Co	Waukesha Co
[n*] [n*] [n*] [n*] [n*] [n*]
Roanoke, VA (Subpart 1 EAC)
Botetourt Co Roanoke Roanoke Co Salem
Key (Moderate) n = county in current 1-hr Ozone Nonattainment area m = county in current 1-hr Ozone Maintenance area P = a portion of the county is located within the area * = county in 1-Hr Ozone, CO or PM-10 non-attainment or maintenance area
Alexandria	[n*] Arlington Co	[n*] Fairfax	[n*] Fairfax Co	[n*] Falls Church	[n*] Loudoun Co	[n*] Manassas	[n*] Manassas Park	[n*] Prince William Co	[n*]
WEST VIRGINIA(Region III) Berkeley and Jefferson Counties, WV (Subpart 1 EAC)
Berkeley Co Jefferson Co
Classified CARBONMONOXIDE NONATTAINMENT AREAS (January 1994)
Alaska Anchorage	Fairbanks	Arizona Phoenix	California Chico	Fresno	Lake Tahoe South Shore	Los Angeles South Coast Air Basin	Modesto	Sacramento	San Diego	San Francisco Oakland San Jose	Stockton	Colorado Colorado Springs	Denver Boulder	Fort Collins	Longmont	Moderate>12.7 ppm Moderate12.7 ppm Moderate12.7 ppm Moderate12.7 ppm Moderate>12.7 ppm Moderate12.7 ppm Serious Moderate12.7 ppm Moderate12.7 ppm Moderate12.7 ppm Moderate12.7 ppm Moderate12.7 ppm Moderate12.7 ppm Moderate>12.7 ppm Moderate12.7 ppm Moderate12.7 ppm Camden County Philadelphia New Mexico Albuquerque	New York New York N. New Jersey Long Island	Syracuse	North Carolina Raleigh Durham	Winston Salem Ohio Cleveland	Oregon Grants Pass	Klamath Falls	Medford	Portland Vancouver	Pennsylvania Philadelphia Camden County	Tennessee Memphis	Texas El Paso	Utah Ogden	Provo	Virginia Washington D.C.	Alexandria City, Arlington County	Washington Vancouver Portland	Seattle Tacoma	Spokane	Moderate12.7 ppm Moderate12.7 ppm Moderate12.7 ppm Moderate>12.7 ppm Moderate12.7 ppm Moderate12.7 ppm
Moderate>12.7 ppm Moderate12.7 ppm Moderate12.7 ppm Moderate12.7 ppm Moderate12.7 ppm Moderate12.7 ppm Moderate12.7 ppm Moderate12.7 ppm Moderate12.7 ppm
Connecticut Hartford New Britain Middletown	Moderate12.7 ppm New York N. New Jersey Long Island	Moderate>12.7 ppm Parts of Fairfield and Litchfield Counties District of Columbia	Entire District	Maryland Baltimore	Washington D.C.	Montgomery and Prince Georges Counties Massachusetts Boston	Moderate12.7 ppm Moderate12.7 ppm Moderate12.7 ppm
Moderate12.7 ppm
Moderate12.7 ppm Moderate12.7 ppm Moderate>12.7 ppm	Moderate>12.7 ppm
Minnesota Duluth	Moderate12.7 ppm Minneapolis St. Paul	Moderate12.7 ppm Montana Missoula	Nevada Las Vegas	Reno	Moderate12.7 ppm Moderate>12.7 ppm Moderate12.7 ppm
NOTE: If there is no listing for a state, there are no classified carbon monoxide nonattainment areas located in the state.
New Jersey N. New Jersey New York Long Island	Moderate>12.7 ppm 26
Classified PM10 nonattainment areas (January 1994)
Arizona	Montana Ajo Butte Douglas Columbia Hayden/Miami Kalispell Nogalas Lame Deer Paul Spur Libby Phoenix Missoula Rillito	Polson Yuma Ronan Arkansas	Eagle River	Nevada Juneau	Las Vegas Reno California	Coachella Valley	New Mexico Imperial Valley	Anthony Mammoth Lake	Owens Valley	Ohio San Joaquin Valley Cuyahoga County Searles Valley Mingo Junction South Coast Basin	Oregon Colorado Grant Pass Aspen	Klamath Falls Canon City La Grand Denver Metro Medford Lamar	Springfield/Eugene Pagosa Springs Telluride Pennsylvania Clairton Connecticut	New Haven Texas El Paso Idaho	Boise	Utah Bonner County Salt Lake County Pinehurst	Utah County Pocatello	Washington	Illinois Kent	Granite City Olympia/Tumwater/Lacey Lyons Township, McCook	Seattle Spokane	Oglesby Tacoma	Southeast Chicago	Wallula Yakima Indiana Lake County West Virginia Vermillion County Follansbee Maine Presque Isle Michigan Detroit Minnesota Rochester St. Paul Wyoming Sheridan
NOTE: If there is no listing for a state, there are no classified PM-10 nonattainment areas located in the state.
Classified SULFUR DIOXIDE nonattainment areas (January 1994)
Alabama Colbert Co. Lauderdale Co. Arizona	Cochise Co. (Douglas) Gila Co. (Miami/Globe) Greenlee Co. (Morenci)	Pima Co. (Ajo) Pinal Co. (Hayden) Pinal Co. (San Manual) Illinois Peoria Co. Tazwell Co. Indiana	Lake Co. Laporte Co. Marion Co. Vigo Co.	Wayne Co. Pennsylvaina Allegheny Co. Armstrong Co. Warren Co. Tennessee Benton Co. Humphreys Co. Polk Co. Utah Salt Lake Co. Tooele Co. (part) Wisconsin Brown Co. (Green Bay) Dane Co. (Madison) Marathon Co. (Rothschild) Milwaukee Co. (Milwaukee) Oneida Co. (Rhinelander) West Virginia Hancock Co. (part)
NOTE: If there is no listing for a state, there are no classified SO2 nonattainment areas located in the state.
Kentucky Boyd Co.	Muhlenberg Co.	Maine	Penobscot Co. Millinocket
Minnesota Minneapolis-St. Paul. Olmsted Co. (Rochester)	Montana	Lewis and Clark Co.	Yellowstone Co. (Laurel) New Jersey Warren Co. New Mexico Grant Co. Nevada White Pine Co. Ohio Coshocton 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.
EPA REGIONAL AIR QUALITY DIVISIONS
Boston, MA 617/565-3800 Maine, Vermont, New Hampshire, Connecticut, Massachusetts, Rhode Island New York, NY 212/264-2301 New York, New Jersey, Puerto Rico, U.S. Virgin Islands Philadelphia, PA 215/597-9390 Pennsylvania, Delaware, Virginia, West Virginia, Maryland, District of Columbia Atlanta, GA 404/347-3043 Georgia, Florida, Alabama, North Carolina, South Carolina, Kentucky Tennessee, Mississippi Chicago, IL 312/353-2212 Illinois, Indiana, Michigan, Minnesota, Ohio, Wisconsin Dallas, TX 214/655-7200 Texas, Arkansas, Oklahoma, Louisiana, New Mexico Kansas City, MO 913/551-7020 Nebraska, Iowa, Kansas, Missouri Denver, CO 303/293-1438 Colorado, Utah, Wyoming, Montana, North Dakota, South Dakota San Francisco, CA 414/744-1219 California, Arizona, Nevada, Hawaii, American Samoa, Guam, Trust Territories of the Pacific Seattle, WA 206/422-4152 Washington, Oregon, Idaho, Alaska
ABMA American Boiler Manufacturers Association A group of manufacturers representing the boiler industry of which Cleaver-Brooks is a member APCD Air Pollution Control District Usually refers to a local air quality agency controlling pollution in a given district AQCR Air Quality Control Region Generally refers to one of the ten EPA regional offices throughout the U.S. AQMD Air Quality Management District Refers to an area or region where air quality is regulated by a local agency ARAC Acid Rain Advisory Committee A committee established by the EPA to focus efforts on the various aspects of Title IV (Acid Deposition Control) of the Clean Air Act ARB Air Resource Board An air quality agency usually responsible for pollution control at the state level LAER Lowest Achievable Emission Rate The most stringent emission limitation contained in any SIP or achieved in practice for a given class of equipment MACT Maximum Available Control Technology Emission standard requiring the maximum degree of emission reduction that has been demonstrated achievable NAAQS National Ambient Air Quality Standards EPA established air quality standards for ambient outdoor emission levels NESHAP National Emission Standards for Hazardous Air Pollutants Standards established by the EPA for regulation of air toxins NSPS New Source Performance Standards Regulations established by the EPA for emissions from equipment, including boilers. Many state regulations are more stringent than the NSPS NSR New Source Review A review performed during the permitting process for a new major installation in a nonattainment area PSD Prevention of Significant Deterioration A review performed during the permitting process for a new major installation in an attainment area RACT Reasonably Available Control Technology A set of recommended levels of emission controls applicable to specific sources or categories located in nonattainment areas SCAQMD South Coast Air Quality Management District The air pollution control agency for the Los Angeles, CA area - emission regulations enacted in this district generally set the trends for other local regulations throughout the U.S. SCR Selective Catalytic Reduction A NOx control method in which ammonia or urea is injected into the exhaust gases in the presence of a catalyst SIP State Implementation Plan An EPA approved emission control plan to attain or maintain NAAQS SNCR Selective Non-Catalytic Reduction A NOx control method where ammonia or urea is injected into the stack and where the exhaust gases are approximately 1600 degrees Fahrenheit 32
BACT Best Available Control Technology An emission limitation based on the maximum degree of reduction, which the permitting authority has determined is achievable and cost effective BARCT Best Available Retrofit Control Technology A retrofit equipment emission limitation based on the BACT principles - but developed for retrofitting existing equipment CEM Continuous Emission Monitoring An emission monitoring system used for measuring emission levels without interruption - required in many local districts and NSPS for certain applications CFR Code of Federal Regulations A codification of the rules published in the Federal Register by the departments and agencies of the Federal Government EPA Environmental Protection Agency A federal agency responsible for pollution control at the national level ESP Electrostatic Precipitators Emission control equipment used to control particulate matter on large utility boilers FGD Flue Gas Desulfurization Emission control method used to control sulfur dioxide emissions FGR Flue Gas Recirculation NOx emission control technique - involves returning a portion of the flue gases to the combustion zone
Many provisions of the 1990 Clean Air Act Amendments assess the impact of pollution sources based on the potential annual emissions (usually expressed as tons per year, or tpy). When addressing industrial boilers, the potential annual emissions of NOx are of concern and frequently must be calculated. Following is an example of how to calculate the potential annual NOx emissions for industrial 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	Input	x Emission	Factor	x Annual Hours	of Operation	= Total Annual Emissions
For example, the calculation of the total annual NOx emissions for an 800 hp boiler operating 24 hours/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) 0.13 lb NOx	MMBtu	33.5 MMBtu	hr	8760 hrs	year	1 ton	2000lb = 19.1 tpy NOx
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 firing natural gas at maximum input operating 24 hours/day, 365 days/year. There are for NOx emission levels of 110, 60, 30, 25, and 20 ppm.
221 Law Street Thomasville, GA 31792 414-359-0600 800-250-5883 info@cleaverbrooks.com cleaverbrooks.com
Printed in the USA 2010 Cleaver-Brooks, Inc CB-7435 11/10
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