Info

3-hour average

1300 ^g/m3

0.50 ppm

Primary

and

secondary

Emission standards can be categorized into the following general types of standards [4]:

• Visible emissions standards—The opacity of the plume from a stack or a point of fugitive emissions is not to equal to or does not exceed a specified opacity;

• Particulate concentration standards—The maximum allowable emission rate is specified in mass/volume (grams per dry standard cubic meter [g/dscm] or grains per dry standard cubic foot [gr/dscf]), and for combustion processes it is common to specify the concentration at a fixed oxygen (O2) or carbon dioxide (CO2) level so as to prevent dilution, thereby lowering the concentration;

• Particulate process weight (or mass) standards—The maximum allowable particulate emissions are tied to the actual mass of material being processed or used, and in combustion systems the standards are commonly reported in pounds of particulate matter per million Btu of fuel burned (lb/106 Btu or lb/MM Btu);

• Gas concentration standards—Gas standards are typically reported in mass per volume or volume per volume (g/dscm or ppm);

• Prohibition of emissions—Processes are banned outright;

• Fuel regulations—Fuel standards may be specified for various fuel-burning equipment such as limiting sulfur concentration in a fuel;

• Zoning restrictions—Emissions may be limited by passing zoning ordinances that dictate facilities that can be constructed;

• Dispersion-based standards—These standards limit the allowable emission of pollutants based on their contribution to the ambient air quality.

National emission or performance standards have been set for a number of industries, including fossil fuel-fired electric utility steam-generating units. National standards are necessary for industries that are spread geographically across the country and provide a basic commodity essential for the development of the country. Unfair economic advantages might be gained if the standards were set by individual states, thus allowing a state to relax the standards to attract industries. These national emissions standards are referred to as New Source Performance Standards (NSPSs) and apply to construction of new sources as well as sources that undergo operational and physical changes, which either increase emission rates or initiate new emissions from the plant [4].

40 CFR, Part 60, Subpart D On December 23, 1971, the first five final standards were published. Since December 23, 1971, the EPA administrator has promulgated nearly 75 standards. The complete text for each NSPS is available in the Code of Federal Register at Title 40 (Protection of the Environment), Part 60 (Standards of Performance for New Stationary Sources), with steam electric plants found in Subpart D [8]. The 1971 regulations addressed coal usage in utility and industrial steam generation units, and the regulations were amended for lignite on March 7, 1978. The maximum SO2 emissions allowable from electric utility steam-generating units of more than 73 MW (megawatts) or 250 million (MM) Btu/hr of heat input and under construction or modification after August 17, 1971, was 1.2 lb SO2 per MM Btu for solid fuels. Particulate matter was limited to 0.10 lb/MM Btu heat input, and opacity was not to exceed 20% for one 6-minute period per hour. NOZ standards were 0.70 lb NOZ per MM Btu heat input for solid fossil fuel or solid fossil fuel and wood residue (except for lignite); 0.60 lb NOx per MM Btu heat input for lignite or lignite and wood residue; and 0.80 lb NOx per MM Btu for lignite mined in North Dakota, South Dakota, or Montana and burned in a cyclone-fired unit (various combustion technologies are discussed in Chapter 5, Technologies for Coal Utilization).

40 CFR, Part 60, Subpart D(a) The original regulations were significantly revised as of February 6, 1980. The EPA promulgated new regulations for the control of SO2, NOZ, and particulate matter from steam-generating units of more than 73 MW or 250 MM Btu/hr of heat input (40 CFR, Part 60, Subpart

D(a)) and under construction after September 18, 1978. For a coal-fired unit, the 1980 standard requires at least a 90% reduction of potential SO2 emissions and limits the rate to 1.2 lb SO2 per MM Btu heat input, or requires at least a 70% reduction and limits the emission rate to 0.6 lb SO2 per MM Btu heat input. In addition, the standard specifies a unique maximum allowable emission rate and unique minimum reduction of potential emission based on the sulfur content and heating value of the coal [9]. If the uncontrolled emission rate (UER) is determined, then the required efficiency is as follows:

UER of SO2

Required efficiency or maximum allowable efficiency rate

6-12 lb SO2 per MM Btu >12 lb SO2 per MM Btu

1.2 lb SO2 per MM Btu; efficiency (%) = [(UER - 1.2)/UER] x 100%

The NOz standard varies according to fuel type and, with respect to coal, is 0.50 lb NOZ per MM Btu heat input from subbituminous coal, shale oil, or any solid, liquid, or gaseous fuel derived from coal; 0.80 lb NOZ per MM Btu heat input from the combustion in a slag tap furnace of any fuel containing more than 25%, by weight, lignite, which has been mined in North Dakota, South Dakota, or Montana; and 0.60 lb NOZ per MM Btu heat input from anthracite or bituminous coal. The NOZ standard is based on a 30-day rolling average.

Particulate emissions are limited to 0.03 lb/MM Btu heat input. In addition, opacity is limited to 20% for a 6-minute average. The NOZ standards for Subparts D(a) and D(b) (see below for Subpart D(b)) were revised on September 16, 1998 [10]. Only those electric utility steam generating units for which construction, modification, or reconstruction is commenced after July 9, 1997, would be affected by these revisions. The revisions changed the existing standards for NOZ emission limits to reflect the performance of best-demonstrated technology. The revisions also changed the format of the revised NOx emission limit for new electric utility steam-generating units to an output-based format to promote energy efficiency and pollution prevention. The NOx emission limit in Subpart D(a) is 1.6 lb NOx per megawatt-hour (MWh) gross energy output regardless of fuel type for new utility boilers. For existing utility boilers that would become subject to the standards due to a modification or reconstruction, the EPA revised the NOx limit to be consistent with the requirements for new units but expressed the emission limits in an equivalent input-based format: 0.15 lb NOZ per MM Btu. This provision was withdrawn by the EPA on August 7, 2001, however, after industry groups filed petitions for review and a motion to vacate the standards as applied to modified boilers in the U.S. Court of

Appeals [11]. On September 21, 1999, the court issued an order granting the petitioner's motion and, as a result, owners and operators of electric utility boilers on which modification is commenced after July 9, 1997, are required to comply with the applicable nitrogen oxides emission limits specified in the pre-existing NSPS, which is 0.50 lb NOZ per MM Btu.

40 CFR, Part 60, Subparts D(b) and D(c) Although the acid rain provisions of the 1990 Clean Air Act Amendments (discussed further below) place additional requirements on the electric utility industry, the NSPS, as revised in 1980, is still applicable for new sources. Smaller sources have been addressed over time, including industrial/commercial/institutional steam generators constructed after June 19, 1984, with heat inputs of 29 to 73 MW (40 CFR, Part 60, Subpart D(b)) and small industrial/commercial/institutional steam-generating units with 2.9 to 29 MW of heat input constructed after June 9, 1989 (40 CFR, Part 60, Subpart D(c)). On November 25, 1986, standards of performance for industrial/commercial/institutional steam-generation units were promulgated [12]. Coal-fired facilities having heat input capacity between 29 and 73 MW (100 and 250 million Btu/hr) are subject to the particulate matter and NOZ standards under 40 CFR, Part 60, Subpart D(b). Particulate matter (PM) standards for coal are more complicated than previous regulations:

• 0.05 lb PM/MM Btu heat input if the facility combusts only coal or combusts coal and other fuels and has an annual capacity factor for the other fuels of 10% or less;

• 0.10 lb PM/MM Btu heat input if the facility combusts coal and other fuels and has an annual capacity factor for the other fuels greater than 10% and is subject to a federally-enforceable requirement limiting operation of the affected facility to an annual capacity factor greater than 10% for fuels other than coal;

• 0.20 lb PM/MM Btu heat input if the affected facility combusts coal or coal and other fuels and has an annual capacity factor for coal or coal and other fuels of 30% or less, has a maximum heat input capacity of 73 MW (250 million Btu/hr) or less, had a federally-enforceable requirement limiting operation of the affected facility to an annual capacity factor of 30% or less for coal or coal and other solid fuels, and construction of the facility commenced after June 19, 1984, and before November 25, 1986.

The NOZ standards for coal-fired facilities identified in 1986 in Subpart D(b) are:

• 0.50 lb NOZ (expressed as NO2) per MM Btu for mass-feed stokers;

• 0.60 lb NOZ per MM Btu for spreader stoker and fluidized-bed combustors;

• 0.70 lb NOz per MM Btu for pulverized coal-fired units;

• 0.60 lb NOz per MM Btu for lignite units except for lignite mined in North Dakota, South Dakota, or Montana and combusted in a slag tap furnace for which the emissions limits are 0.8 lb NOz per MM Btu;

• 0.50 lb NOz per MM Btu for coal-derived synthetic fuels.

As previously mentioned, the NOZ standard for Subpart D(b) was revised on September 16, 1998 [10]. Only those industrial steam-generating units for which construction, modification, or reconstruction is commenced after July 9, 1997, would be affected by these revisions. For coal-fired Subpart D(b) units, the NOZ emission limit promulgated was 0.20 lb/MM Btu heat input; however, this provision was withdrawn on August 7, 2001, and owners and operators of industrial/commercial/institutional boilers on which modification is commenced after July 9, 1997, are required to comply with the applicable nitrogen oxides emission limits specified in the pre-existing NSPS (i.e., 0.50 to 0.80 lb NOZ per MM Btu, depending on fuel type and boiler configuration as listed above) [11].

On September 12, 1990, standards of performance for small industrial/commercial/institutional steam-generation units were promulgated (40 CFR, Part 60, Subpart D(c)) [13]. Under Subpart D(c), coal-fired facilities having heat input capacity between 2.9 and 29 MW (10 and 100 million Btu/hr) are not subject to NOZ standards nor are they subject to SO2 or particulate matter emissions limits during periods of combustion research. For nonresearch operations, SO2 standards include the following:

• When firing only coal, SO2 emissions are limited to no more than 10% of the potential SO2 emissions rate (i.e., 90% reduction) and less than 1.2 lb SO2 per MM Btu heat input;

• If coal is combusted with other fuels, the affected facility is subject to the 90% SO2 reduction requirement, and the emission limit is determined by the equation:

where:

Eso2 is the SO2 emission limit, expressed in lb/million Btu heat input;

Ka is 1.2 lb/million Btu; Kb is 0.60 lb/million Btu; Kc is 0.50 lb/million Btu;

Ha is the heat input from the combustion of coal, except coal combusted in a facility that uses an emerging technology for SO2 control, in million Btu;

Hb is the heat input from the combustion of coal in a facility that uses an emerging technology for SO2 control, in million Btu;

Hc is the heat input from the combustion of oil in million Btu.

• When firing only coal in a facility that uses an emerging technology for SO2 control, SO2 emissions are limited to no more than 50% of the potential SO2 emissions rate (i.e., 50% reduction) and less than 0.60 lb SO2 per MM Btu heat input;

• If coal is combusted with other fuels, a 50% SO2 reduction is required, and the emission limit is determined using Equation (4-1);

• Percent reduction requirements are not applicable for affected facilities that have input capacity of 22 MW (75 million Btu/hr) or less; affected facilities that have an annual capacity for coal of 55% or less; affected facilities located in a noncontinental area; and affected facilities that combust coal in a duct burner as part of a combined cycle system where 30% or less of the heat entering the steam-generating unit is from combustion of coal in the duct burner and 70% or more of the heat entering the steam generating unit is from exhaust gases entering the duct burner;

• Reduction of the potential SO2 emission rate through fuel pre-treatment is not credited toward the percent reduction requirement unless fuel pretreatment results in a 50% or greater reduction in the potential SO2 emission rate and emissions from the pretreated fuel (without either combustion or post-combustion SO2 control) are equal or less than 0.60 lb/MM Btu.

The particulate matter standards in Subpart D(c) state that a facility that combusts coal or mixtures of coal with other fuels and has a heat input capacity of 8.7 MW (30 million Btu/hr) or greater is subject to the following emission limits:

• 0.05 lb PM per MM Btu heat input if the facility combusts only coal, or combusts coal with other fuels and has an annual capacity factor for the other fuels of 10% or less;

• 0.10 lb PM per MM Btu heat input if the facility combusts coal with other fuels, has an annual capacity factor for the other fuels greater than 10%, and is subject to a federally enforceable requirement limiting operation of the facility to an annual capacity factor greater than 10% for fuels other than coal.

Emission Factors Once an NSPS has been established, it is necessary for new sources constructed after a defined date to meet the standards. It is not possible to sample new sources to determine required collection or removal efficiencies. In these cases, knowledge of the emission factors for the specific regulated pollutant from these sources is used to estimate the approximate level of control required to meet the NSPS. The EPA has published a document, Compilation of Air Pollutant Emission Factors (referred to as AP-42) since 1972. Supplements to AP-42 have been routinely published to add new emissions source categories and to update existing emission factors. This document is also provided on the EPA website at their CHIEF (Clearinghouse for Inventories and Emissions Factors; www.epa.gov/ttn/chief/ap42) bulletin board.

The EPA routinely updates AP-42 in order to respond to new emission factor needs of state and local air pollution control programs, industry, and the agency itself. The current emission factors for bituminous and sub-bituminous coal, lignite, and anthracite firing are provided in Appendix A and are from Sections 1.1 (Bituminous and Subbituminous Coal Combustion), 1.2 (Anthracite Coal Combustion), and 1.7 (Lignite Combustion) of AP-42, fifth ed., vol. I, suppls. A through G. The emission factors have been developed for (not inclusive):

• Various fuel firing configurations;

• Uncontrolled and controlled emissions;

• Criteria gaseous pollutants (SOZ, NOZ, CO);

• Filterable particulate matter and condensable particulate matter;

• Various types of polynuclear organic matter (POM), polynuclear aromatic hydrocarbons (PAHs), and organic compounds;

• Other gaseous pollutants such as CO2, N2O, and CH4;

• Cumulative ash particle size distribution and size-specific emissions.

Emissions factors and emissions inventories have long been fundamental tools for air quality management. Emission estimates are important for developing emission control strategies, determining applicability of permitting and control programs, and ascertaining the effects of sources and appropriate mitigation strategies. Users include federal, state, and local agencies; consultants; and industry. Data from source-specific emission tests or continuous emission monitors are usually preferred for estimating a source's emissions because those data provide the best representation of the tested source's emissions; however, test data from individual sources are not always available and they may not reflect the variability of actual emissions over time. Consequently, emission factors are often the best or only method available for estimating emissions.

The passage of the Clean Air Act Amendments of 1990 and the Emergency Planning and Community Right-To-Know Act of 1986 has increased the need for both criteria and hazardous air pollutant emission factors and inventories. The Emission Factor and Inventory Group (EFIG) of the EPA's Office of Air Quality Planning and Standards develops and maintains emission-estimating tools. The AP-42 series is the principal means by which the EFIG can document its emission factors.

Emission factors may be appropriate to use in a number of situations such as source-specific emission estimates for area-wide inventories. These inventories have many purposes, including ambient dispersion modeling and analysis, control strategy development, as screening sources for compliance investigations, and in some permitting applications. Emission factors in AP-42 are neither EPA-recommended emission limits—for example, best available control technology (BACT) or lowest achievable emission rate (LAER)—nor standards (e.g., NSPSs or NESHAPs).

Figure 4-1 depicts various approaches to emission estimation in a hierarchy of requirements and levels of sophistication that need to be considered when analyzing the tradeoffs between cost of the estimates and the quality of the resulting estimates. More sophisticated and more costly emission determination methods may be necessary where risks of either adverse environmental effects or adverse regulatory outcomes are high. Less expensive estimation techniques such as emission factors and emission models may be appropriate and satisfactory where risks of using a poor estimate are low. Note that the reliability of the AP-42 emission factors are rated from A through E, which is a general indication of the robustness of that factor. This rating is assigned based on the estimated reliability of the tests used to develop the factor. In general, factors based on many observations, or on

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