Terms used in this subpart are defined in the Clean Air Act (CAA), in Sec. 63.2 (the General Provisions), and in this section as follows:
Affirmative defense means, in the context of an enforcement proceeding, a response or defense put forward by a defendant, regarding which the defendant has the burden of proof, and the merits of which are independently and objectively evaluated in a judicial or administrative proceeding.
Anthracite coal means solid fossil fuel classified as anthracite coal by American Society of Testing and Materials (ASTM) Method D388-05, ``Standard Classification of Coals by Rank'' (incorporated by reference, see Sec. 63.14).
Bituminous coal means coal that is classified as bituminous according to ASTM Method D388-05, ``Standard Classification of Coals by Rank'' (incorporated by reference, see Sec. 63.14).
Boiler operating day means a 24-hour period that begins at midnight and ends the following midnight during which any fuel is combusted at any time in the EGU, excluding startup periods or shutdown periods. It is not necessary for the fuel to be combusted the entire 24-hour period.
Capacity factor for a liquid oil-fired EGU means the total annual heat input from oil divided by the product of maximum hourly heat input for the EGU, regardless of fuel, multiplied by 8,760 hours.
Clean fuel means natural gas, synthetic natural gas that meets the specification necessary for that gas to be transported on a Federal Energy Regulatory Commission (FERC) regulated pipeline, propane, distillate oil, synthesis gas that has been processed through a gas clean-up train such that it could be used in a system's combustion turbine, or ultra-low-sulfur diesel (ULSD) oil, including those fuels meeting the requirements of 40 CFR part 80, subpart I (``Subpart I--Motor Vehicle Diesel Fuel; Nonroad, Locomotive, and Marine Diesel Fuel; and ECA Marine Fuel'').
Coal means all solid fuels classifiable as anthracite, bituminous, sub-bituminous, or lignite by ASTM Method D388-05, ``Standard Classification of Coals by Rank'' (incorporated by reference, see Sec. 63.14), and coal refuse. Synthetic fuels derived from coal for the purpose of creating useful heat including but not limited to, coal derived gases (not meeting the definition of natural gas), solvent-refined coal, coal-oil mixtures, and coal-water mixtures, are considered ``coal'' for the purposes of this subpart.
Coal-fired electric utility steam generating unit means an electric utility steam generating unit meeting the definition of ``fossil fuel-fired'' that burns coal for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year.
Coal refuse means any by-product of coal mining, physical coal cleaning, and coal preparation operations (e.g., culm, gob, etc.) containing coal, matrix material, clay, and other organic and inorganic material with an ash content greater than 50 percent (by weight) and a heating value less than 13,900 kilojoules per kilogram (6,000 Btu per pound) on a dry basis.
Cogeneration means a steam-generating unit that simultaneously produces both electrical and useful thermal (or mechanical) energy from the same primary energy source.
Cogeneration unit means a stationary, fossil fuel-fired EGU meeting the definition of ``fossil fuel-fired'' or stationary, integrated gasification combined cycle:
(1) Having equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy; and
(2) Producing during the 12-month period starting on the date the unit first produces electricity and during any calendar year after which the unit first produces electricity:
(i) For a topping-cycle cogeneration unit,
(A) Useful thermal energy not less than 5 percent of total energy output; and
(B) Useful power that, when added to one-half of useful thermal energy produced, is not less than 42.5 percent of total energy input, if useful thermal energy produced is 15 percent or more of total energy output, or not less than 45 percent of total energy input, if useful thermal energy produced is less than 15 percent of total energy output.
(ii) For a bottoming-cycle cogeneration unit, useful power not less than 45 percent of total energy input.
(3) Provided that the total energy input under paragraphs (2)(i)(B) and (2)(ii) of this definition shall equal the unit's total energy input from all fuel except biomass if the unit is a boiler.
Combined-cycle gas stationary combustion turbine means a stationary combustion turbine system where heat from the turbine exhaust gases is recovered by a waste heat boiler.
Common stack means the exhaust of emissions from two or more affected units through a single flue.
Continental liquid oil-fired subcategory means any oil-fired electric utility steam generating unit that burns liquid oil and is located in the continental United States.
Default electrical load means an electrical load equal to 5 percent of the maximum sustainable electrical output (megawatts), as defined in section 6.5.2.1(a)(1) of Appendix A to part 75 of this chapter, of an affected EGU that is in startup or shutdown mode. For monitored common stack configurations, the default electrical load is 5 percent of the combined maximum sustainable electrical load of the EGUs that are in startup or shutdown mode during an hour in which the electrical load for all operating EGUs is zero. The default electrical load is used to calculate the electrical output-based emission rate (lb/MWh or lb/GWh, as applicable) for any startup or shutdown hour in which the actual electrical load is zero. The default electrical load is not used for EGUs required to make heat input-based emission rate (lb/MMBtu or lb/TBtu, as applicable) calculations. For the purposes of this subpart, the default electrical load is not considered to be a substitute data value.
(1) Deviation means any instance in which an affected source subject to this subpart, or an owner or operator of such a source:
(i) Fails to meet any requirement or obligation established by this subpart including, but not limited to, any emission limit, operating limit, work practice standard, or monitoring requirement; or
(ii) Fails to meet any term or condition that is adopted to implement an applicable requirement in this subpart and that is included in the operating permit for any affected source required to obtain such a permit.
(2) A deviation is not always a violation. The determination of whether a deviation constitutes a violation of the standard is up to the discretion of the entity responsible for enforcement of the standards.
Diluent cap means a default CO2 or O2 concentration that may be used to calculate the Hg, HCl, HF, or SO2 emission rate (lb/MMBtu or lb/TBtu, as applicable) during a startup or shutdown hour in which the measured CO2 concentration is below the cap value or the measured O2 concentration is above the cap value. The appropriate diluent cap values for EGUs are presented in Sec. 63.10007(f) and in section 6.2.1.2 of Appendix A to this subpart. For the purposes of this subpart, the diluent cap is not considered to be a substitute data value.
Distillate oil means fuel oils, including recycled oils, that comply with the specifications for fuel oil numbers 1 and 2, as defined by ASTM Method D396-10, ``Standard Specification for Fuel Oils'' (incorporated by reference, see Sec. 63.14).
Dry flue gas desulfurization technology, or dry FGD, or spray dryer absorber (SDA), or spray dryer, or dry scrubber means an add-on air pollution control system located downstream of the steam generating unit that injects a dry alkaline sorbent (dry sorbent injection) or sprays an alkaline sorbent slurry (spray dryer) to react with and neutralize acid gases such as SO2 and HCl in the exhaust stream forming a dry powder material. Alkaline sorbent injection systems in fluidized bed combustors (FBC) or circulating fluidized bed (CFB) boilers are included in this definition.
Dry sorbent injection (DSI) means an add-on air pollution control system in which sorbent (e.g., conventional activated carbon, brominated activated carbon, Trona, hydrated lime, sodium carbonate, etc.) is injected into the flue gas steam upstream of a PM control device to react with and neutralize acid gases (such as SO2 and HCl) or Hg in the exhaust stream forming a dry powder material that may be removed in a primary or secondary PM control device.
Electric Steam generating unit means any furnace, boiler, or other device used for combusting fuel for the purpose of producing steam (including fossil-fuel-fired steam generators associated with integrated gasification combined cycle gas turbines; nuclear steam generators are not included) for the purpose of powering a generator to produce electricity or electricity and other thermal energy.
Electric utility steam generating unit (EGU) means a fossil fuel-fired combustion unit of more than 25 megawatts electric (MWe) that serves a generator that produces electricity for sale. A fossil fuel-fired unit that cogenerates steam and electricity and supplies more than one-third of its potential electric output capacity and more than 25 MWe output to any utility power distribution system for sale is considered an electric utility steam generating unit.
Emission limitation means any emissions limit, work practice standard, or operating limit.
Excess emissions means, with respect to this subpart, results of any required measurements outside the applicable range (e.g., emissions limitations, parametric operating limits) that is permitted by this subpart. The values of measurements will be in the same units and averaging time as the values specified in this subpart for the limitations.
Federally enforceable means all limitations and conditions that are enforceable by the Administrator, including the requirements of 40 CFR parts 60, 61, and 63; requirements within any applicable state implementation plan; and any permit requirements established under 40 CFR 52.21 or under 40 CFR 51.18 and 40 CFR 51.24.
Flue gas desulfurization system means any add-on air pollution control system located downstream of the steam generating unit whose purpose or effect is to remove at least 50 percent of the SO2 in the exhaust gas stream.
Fossil fuel means natural gas, oil, coal, and any form of solid, liquid, or gaseous fuel derived from such material.
Fossil fuel-fired means an electric utility steam generating unit (EGU) that is capable of combusting more than 25 MW of fossil fuels. To be ``capable of combusting'' fossil fuels, an EGU would need to have these fuels allowed in its operating permit and have the appropriate fuel handling facilities on-site or otherwise available (e.g., coal handling equipment, including coal storage area, belts and conveyers, pulverizers, etc.; oil storage facilities). In addition, fossil fuel-fired means any EGU that fired fossil fuels for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year after the applicable compliance date.
Fuel type means each category of fuels that share a common name or classification. Examples include, but are not limited to, bituminous coal, subbituminous coal, lignite, anthracite, biomass, and residual oil. Individual fuel types received from different suppliers are not considered new fuel types.
Fluidized bed boiler, or fluidized bed combustor, or circulating fluidized boiler, or CFB means a boiler utilizing a fluidized bed combustion process.
Fluidized bed combustion means a process where a fuel is burned in a bed of granulated particles which are maintained in a mobile suspension by the upward flow of air and combustion products.
Gaseous fuel includes, but is not limited to, natural gas, process gas, landfill gas, coal derived gas, solid oil-derived gas, refinery gas, and biogas.
Generator means a device that produces electricity.
Gross output means the gross useful work performed by the steam generated and, for an IGCC electric utility steam generating unit, the work performed by the stationary combustion turbines. For a unit generating only electricity, the gross useful work performed is the gross electrical output from the unit's turbine/generator sets. For a cogeneration unit, the gross useful work performed is the gross electrical output, including any such electricity used in the power production process (which process includes, but is not limited to, any on-site processing or treatment of fuel combusted at the unit and any on-site emission controls), or mechanical output plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit (i.e., steam delivered to an industrial process).
Heat input means heat derived from combustion of fuel in an EGU (synthetic gas for an IGCC) and does not include the heat input from preheated combustion air, recirculated flue gases, or exhaust gases from other sources such as gas turbines, internal combustion engines, etc.
Integrated gasification combined cycle electric utility steam generating unit or IGCC means an electric utility steam generating unit meeting the definition of ``fossil fuel-fired'' that burns a synthetic gas derived from coal and/or solid oil-derived fuel for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year in a combined-cycle gas turbine. No solid coal or solid oil-derived fuel is directly burned in the unit during operation.
ISO conditions means a temperature of 288 Kelvin, a relative humidity of 60 percent, and a pressure of 101.3 kilopascals.
Lignite coal means coal that is classified as lignite A or B according to ASTM Method D388-05, ``Standard Classification of Coals by Rank'' (incorporated by reference, see Sec. 63.14).
Limited-use liquid oil-fired subcategory means an oil-fired electric utility steam generating unit with an annual capacity factor of less than 8 percent of its maximum or nameplate heat input, whichever is greater, averaged over a 24-month block contiguous period commencing April 16, 2015.
Liquid fuel includes, but is not limited to, distillate oil and residual oil.
Monitoring system malfunction or out of control period means any sudden, infrequent, not reasonably preventable failure of the monitoring system to provide valid data. Monitoring system failures that are caused in part by poor maintenance or careless operation are not malfunctions.
Natural gas means a naturally occurring fluid mixture of hydrocarbons (e.g., methane, ethane, or propane) produced in geological formations beneath the Earth's surface that maintains a gaseous state at standard atmospheric temperature and pressure under ordinary conditions. Natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. Additionally, natural gas must either be composed of at least 70 percent methane by volume or have a gross calorific value between 950 and 1,100 Btu per standard cubic foot. Natural gas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable sulfur content or heating value.
Natural gas-fired electric utility steam generating unit means an electric utility steam generating unit meeting the definition of ``fossil fuel-fired'' that is not a coal-fired, oil-fired, or IGCC electric utility steam generating unit and that burns natural gas for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year.
Net-electric output means the gross electric sales to the utility power distribution system minus purchased power on a calendar year basis.
Non-continental area means the State of Hawaii, the Virgin Islands, Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern Mariana Islands.
Non-continental liquid oil-fired subcategory means any oil-fired electric utility steam generating unit that burns liquid oil and is located outside the continental United States.
Non-mercury (Hg) HAP metals means Antimony (Sb), Arsenic (As), Beryllium (Be), Cadmium (Cd), Chromium (Cr), Cobalt (Co), Lead (Pb), Manganese (Mn), Nickel (Ni), and Selenium (Se).
Oil means crude oil or petroleum or a fuel derived from crude oil or petroleum, including distillate and residual oil, solid oil-derived fuel (e.g., petroleum coke) and gases derived from solid oil-derived fuels (not meeting the definition of natural gas).
Oil-fired electric utility steam generating unit means an electric utility steam generating unit meeting the definition of ``fossil fuel-fired'' that is not a coal-fired electric utility steam generating unit and that burns oil for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year.
Particulate matter or PM means any finely divided solid material as measured by the test methods specified under this subpart, or an alternative method.
Pulverized coal (PC) boiler means an EGU in which pulverized coal is introduced into an air stream that carries the coal to the combustion chamber of the EGU where it is fired in suspension.
Residual oil means crude oil, and all fuel oil numbers 4, 5 and 6, as defined by ASTM Method D396-10, ``Standard Specification for Fuel Oils'' (incorporated by reference, see Sec. 63.14).
Responsible official means responsible official as defined in 40 CFR 70.2.
Shutdown means the period in which cessation of operation of an EGU is initiated for any purpose. Shutdown begins when the EGU no longer generates electricity or makes useful thermal energy (such as heat or steam) for industrial, commercial, heating, or cooling purposes or when no coal, liquid oil, syngas, or solid oil-derived fuel is being fired in the EGU, whichever is earlier. Shutdown ends when the EGU no longer generates electricity or makes useful thermal energy (such as steam or heat) for industrial, commercial, heating, or cooling purposes, and no fuel is being fired in the EGU. Any fraction of an hour in which shutdown occurs constitutes a full hour of shutdown.
Startup means:
(1) Either the first-ever firing of fuel in a boiler for the purpose of producing electricity, or the firing of fuel in a boiler after a shutdown event for any purpose. Startup ends when any of the steam from the boiler is used to generate electricity for sale over the grid or for any other purpose (including on-site use). Any fraction of an hour in which startup occurs constitutes a full hour of startup; or
(2) The period in which operation of an EGU is initiated for any purpose. Startup begins with either the firing of any fuel in an EGU for the purpose of producing electricity or useful thermal energy (such as heat or steam) for industrial, commercial, heating, or cooling purposes (other than the first-ever firing of fuel in a boiler following construction of the boiler) or for any other purpose after a shutdown event. Startup ends 4 hours after the EGU generates electricity that is sold or used for any other purpose (including on site use), or 4 hours after the EGU makes useful thermal energy (such as heat or steam) for industrial, commercial, heating, or cooling purposes (16 U.S.C. 796(18)(A) and 18 CFR 292.202(c)), whichever is earlier. Any fraction of an hour in which startup occurs constitutes a full hour of startup.
Stationary combustion turbine means all equipment, including but not limited to the turbine, the fuel, air, lubrication and exhaust gas systems, control systems (except emissions control equipment), and any ancillary components and sub-components comprising any simple cycle stationary combustion turbine, any regenerative/recuperative cycle stationary combustion turbine, the combustion turbine portion of any stationary cogeneration cycle combustion system, or the combustion turbine portion of any stationary combined cycle steam/electric generating system. Stationary means that the combustion turbine is not self propelled or intended to be propelled while performing its function. Stationary combustion turbines do not include turbines located at a research or laboratory facility, if research is conducted on the turbine itself and the turbine is not being used to power other applications at the research or laboratory facility.
Steam generating unit means any furnace, boiler, or other device used for combusting fuel for the purpose of producing steam (including fossil-fuel-fired steam generators associated with integrated gasification combined cycle gas turbines; nuclear steam generators are not included).
Stoker means a unit consisting of a mechanically operated fuel feeding mechanism, a stationary or moving grate to support the burning of fuel and admit undergrate air to the fuel, an overfire air system to complete combustion, and an ash discharge system. There are two general types of stokers: underfeed and overfeed. Overfeed stokers include mass feed and spreader stokers.
Subbituminous coal means coal that is classified as subbituminous A, B, or C according to ASTM Method D388-05, ``Standard Classification of Coals by Rank'' (incorporated by reference, see Sec. 63.14).
Unit designed for coal "8,300 Btu/lb subcategory means any coal-fired EGU that is not a coal-fired EGU in the ``unit designed for low rank virgin coal'' subcategory.
Unit designed for low rank virgin coal subcategory means any coal-fired EGU that is designed to burn and that is burning nonagglomerating virgin coal having a calorific value (moist, mineral matter-free basis) of less than 19,305 kJ/kg (8,300 Btu/lb) that is constructed and operates at or near the mine that produces such coal.
Unit designed to burn solid oil-derived fuel subcategory means any oil-fired EGU that burns solid oil-derived fuel.
Voluntary consensus standards or VCS mean technical standards (e.g., materials specifications, test methods, sampling procedures, business practices) developed or adopted by one or more voluntary consensus bodies. The EPA/OAQPS has by precedent only used VCS that are written in English. Examples of VCS bodies are: American Society of Testing and Materials (ASTM), American Society of Mechanical Engineers (ASME), International Standards Organization (ISO), Standards Australia (AS), British Standards (BS), Canadian Standards (CSA), European Standard (EN or CEN) and German Engineering Standards (VDI). The types of standards that are not considered VCS are standards developed by: the U.S. states, e.g., California (CARB) and Texas (TCEQ); industry groups, such as American Petroleum Institute (API), Gas Processors Association (GPA), and Gas Research Institute (GRI); and other branches of the U.S. government, e.g., Department of Defense (DOD) and Department of Transportation (DOT). This does not preclude EPA from using standards developed by groups that are not VCS bodies within an EPA rule. When this occurs, EPA has done searches and reviews for VCS equivalent to these non-VCS methods.
Wet flue gas desulfurization technology, or wet FGD, or wet scrubber means any add-on air pollution control device that is located downstream of the steam generating unit that mixes an aqueous stream or slurry with the exhaust gases from an EGU to control emissions of PM and/or to absorb and neutralize acid gases, such as SO2 and HCl.
Work practice standard means any design, equipment, work practice, or operational standard, or combination thereof, which is promulgated pursuant to CAA section 112(h). [77 FR 9464, Feb. 16, 2012, as amended at 77 FR 23405, Apr. 19, 2012; 78 FR 24087, Apr. 24, 2013; 79 FR 68792, Nov. 19, 2014]
Sec. Table 1 to Subpart UUUUU of Part 63--Emission Limits for New or
Reconstructed EGUs
As stated in Sec. 63.9991, you must comply with the following applicable emission limits: ----------------------------------------------------------------------------------------------------------------
Using these
requirements, as
You must meet the appropriate (e.g.,
For the following following emission specified sampling
If your EGU is in this subcategory pollutants limits and work volume or test run
practice standards duration) and
limitations with the
test methods in Table 5----------------------------------------------------------------------------------------------------------------1. Coal-fired unit not low rank a. Filterable 9.0E-2 lb/MWh \1\...... Collect a minimum of 4
virgin coal. particulate matter dscm per run.
(PM).
OR OR
Total non-Hg HAP metals 6.0E-2 lb/GWh.......... Collect a minimum of 4
dscm per run.
OR OR
Individual HAP metals:. ....................... Collect a minimum of 3
dscm per run.
Antimony (Sb).......... 8.0E-3 lb/GWh..........
Arsenic (As)........... 3.0E-3 lb/GWh..........
Beryllium (Be)......... 6.0E-4 lb/GWh..........
Cadmium (Cd)........... 4.0E-4 lb/GWh..........
Chromium (Cr).......... 7.0E-3 lb/GWh..........
Cobalt (Co)............ 2.0E-3 lb/GWh..........
Lead (Pb).............. 2.0E-2 lb/GWh..........
Manganese (Mn)......... 4.0E-3 lb/GWh..........
Nickel (Ni)............ 4.0E-2 lb/GWh..........
Selenium (Se).......... 5.0E-2 lb/GWh..........
b. Hydrogen chloride 1.0E-2 lb/MWh.......... For Method 26A, collect
(HCl). a minimum of 3 dscm
per run.
For ASTM D6348-03 \2\
or Method 320, sample
for a minimum of 1
hour.
OR .......................
Sulfur dioxide (SO2) 1.0 lb/MWh............. SO2 CEMS.
\3\.
c. Mercury (Hg)........ 3.0E-3 lb/GWh.......... Hg CEMS or sorbent trap
monitoring system
only.2. Coal-fired units low rank virgin a. Filterable 9.0E-2 lb/MWh \1\...... Collect a minimum of 4
coal. particulate matter dscm per run.
(PM).
OR OR
Total non-Hg HAP metals 6.0E-2 lb/GWh.......... Collect a minimum of 4
dscm per run.
OR OR
Individual HAP metals:. ....................... Collect a minimum of 3
dscm per run.
Antimony (Sb).......... 8.0E-3 lb/GWh..........
Arsenic (As)........... 3.0E-3 lb/GWh..........
Beryllium (Be)......... 6.0E-4 lb/GWh..........
Cadmium (Cd)........... 4.0E-4 lb/GWh..........
Chromium (Cr).......... 7.0E-3 lb/GWh..........
Cobalt (Co)............ 2.0E-3 lb/GWh..........
Lead (Pb).............. 2.0E-2 lb/GWh..........
Manganese (Mn)......... 4.0E-3 lb/GWh..........
Nickel (Ni)............ 4.0E-2 lb/GWh..........
Selenium (Se).......... 5.0E-2 lb/GWh..........
b. Hydrogen chloride 1.0E-2 lb/MWh.......... For Method 26A, collect
(HCl). a minimum of 3 dscm
per run.
For ASTM D6348-03 \2\
or Method 320, sample
for a minimum of 1
hour.
OR
Sulfur dioxide (SO2) 1.0 lb/MWh............. SO2 CEMS.
\3\.
c. Mercury (Hg)........ 4.0E-2 lb/GWh.......... Hg CEMS or sorbent trap
monitoring system
only.3. IGCC unit......................... a. Filterable 7.0E-2 lb/MWh \4\...... Collect a minimum of 1
particulate matter 9.0E-2 lb/MWh \5\...... dscm per run.
(PM).
OR OR
Total non-Hg HAP metals 4.0E-1 lb/GWh.......... Collect a minimum of 1
dscm per run.
OR OR
Individual HAP metals:. ....................... Collect a minimum of 2
dscm per run.
Antimony (Sb).......... 2.0E-2 lb/GWh..........
Arsenic (As)........... 2.0E-2 lb/GWh..........
Beryllium (Be)......... 1.0E-3 lb/GWh..........
Cadmium (Cd)........... 2.0E-3 lb/GWh..........
Chromium (Cr).......... 4.0E-2 lb/GWh..........
Cobalt (Co)............ 4.0E-3 lb/GWh..........
Lead (Pb).............. 9.0E-3 lb/GWh..........
Manganese (Mn)......... 2.0E-2 lb/GWh..........
Nickel (Ni)............ 7.0E-2 lb/GWh..........
Selenium (Se).......... 3.0E-1 lb/GWh..........
b. Hydrogen chloride 2.0E-3 lb/MWh.......... For Method 26A, collect
(HCl). a minimum of 1 dscm
per run; for Method
26, collect a minimum
of 120 liters per run.
For ASTM D6348-03 \2\
or Method 320, sample
for a minimum of 1
hour.
OR .......................
Sulfur dioxide (SO2) 4.0E-1 lb/MWh.......... SO2 CEMS.
\3\.
c. Mercury (Hg)........ 3.0E-3 lb/GWh.......... Hg CEMS or sorbent trap
monitoring system
only.4. Liquid oil-fired unit--continental a. Filterable 3.0E-1 lb/MWh \1\...... Collect a minimum of 1
(excluding limited-use liquid oil- particulate matter dscm per run.
fired subcategory units). (PM).
OR OR
Total HAP metals....... 2.0E-4 lb/MWh.......... Collect a minimum of 2
dscm per run.
OR OR
Individual HAP metals:. ....................... Collect a minimum of 2
dscm per run.
Antimony (Sb).......... 1.0E-2 lb/GWh..........
Arsenic (As)........... 3.0E-3 lb/GWh..........
Beryllium (Be)......... 5.0E-4 lb/GWh..........
Cadmium (Cd)........... 2.0E-4 lb/GWh..........
Chromium (Cr).......... 2.0E-2 lb/GWh..........
Cobalt (Co)............ 3.0E-2 lb/GWh..........
Lead (Pb).............. 8.0E-3 lb/GWh..........
Manganese (Mn)......... 2.0E-2 lb/GWh..........
Nickel (Ni)............ 9.0E-2 lb/GWh..........
Selenium (Se).......... 2.0E-2 lb/GWh..........
Mercury (Hg)........... 1.0E-4 lb/GWh.......... For Method 30B sample
volume determination
(Section 8.2.4), the
estimated Hg
concentration should
nominally be <\1/2\
the standard.
b. Hydrogen chloride 4.0E-4 lb/MWh.......... For Method 26A, collect
(HCl). a minimum of 3 dscm
per run.
For ASTM D6348-03 \2\
or Method 320, sample
for a minimum of 1
hour.
c. Hydrogen fluoride 4.0E-4 lb/MWh.......... For Method 26A, collect
(HF). a minimum of 3 dscm
per run.
For ASTM D6348-03 \2\
or Method 320, sample
for a minimum of 1
hour.5. Liquid oil-fired unit--non- a. Filterable 2.0E-1 lb/MWh \1\...... Collect a minimum of 1
continental (excluding limited-use particulate matter dscm per run.
liquid oil-fired subcategory units). (PM).
OR OR
Total HAP metals....... 7.0E-3 lb/MWh.......... Collect a minimum of 1
dscm per run.
OR OR
Individual HAP metals:. ....................... Collect a minimum of 3
dscm per run.
Antimony (Sb).......... 8.0E-3 lb/GWh..........
Arsenic (As)........... 6.0E-2 lb/GWh..........
Beryllium (Be)......... 2.0E-3 lb/GWh..........
Cadmium (Cd)........... 2.0E-3 lb/GWh..........
Chromium (Cr).......... 2.0E-2 lb/GWh..........
Cobalt (Co)............ 3.0E-1 lb/GWh..........
Lead (Pb).............. 3.0E-2 lb/GWh..........
Manganese (Mn)......... 1.0E-1 lb/GWh..........
Nickel (Ni)............ 4.1E0 lb/GWh...........
Selenium (Se).......... 2.0E-2 lb/GWh..........
Mercury (Hg)........... 4.0E-4 lb/GWh.......... For Method 30B sample
volume determination
(Section 8.2.4), the
estimated Hg
concentration should
nominally be <\1/2\
the standard.
b. Hydrogen chloride 2.0E-3 lb/MWh.......... For Method 26A, collect
(HCl). a minimum of 1 dscm
per run; for Method
26, collect a minimum
of 120 liters per run.
For ASTM D6348-03 \2\
or Method 320, sample
for a minimum of 1
hour.
c. Hydrogen fluoride 5.0E-4 lb/MWh.......... For Method 26A, collect
(HF). a minimum of 3 dscm
per run.
For ASTM D6348-03 \2\
or Method 320, sample
for a minimum of 1
hour.6. Solid oil-derived fuel-fired unit. a. Filterable 3.0E-2 lb/MWh \1\...... Collect a minimum of 1
particulate matter dscm per run.
(PM).
OR OR .......................
Total non-Hg HAP metals 6.0E-1 lb/GWh.......... Collect a minimum of 1
dscm per run.
OR OR .......................
Individual HAP metals:. ....................... Collect a minimum of 3
dscm per run.
Antimony (Sb).......... 8.0E-3 lb/GWh..........
Arsenic (As)........... 3.0E-3 lb/GWh..........
Beryllium (Be)......... 6.0E-4 lb/GWh..........
Cadmium (Cd)........... 7.0E-4 lb/GWh..........
Chromium (Cr).......... 6.0E-3 lb/GWh..........
Cobalt (Co)............ 2.0E-3 lb/GWh..........
Lead (Pb).............. 2.0E-2 lb/GWh..........
Manganese (Mn)......... 7.0E-3 lb/GWh..........
Nickel (Ni)............ 4.0E-2 lb/GWh..........
Selenium (Se).......... 6.0E-3 lb/GWh..........
b. Hydrogen chloride 4.0E-4 lb/MWh.......... For Method 26A, collect
(HCl). a minimum of 3 dscm
per run.
For ASTM D6348-03 \2\
or Method 320, sample
for a minimum of 1
hour.
OR ....................... .......................
Sulfur dioxide (SO2) 1.0 lb/MWh............. SO2 CEMS.
\3\.
c. Mercury (Hg)........ 2.0E-3 lb/GWh.......... Hg CEMS or Sorbent trap
monitoring system
only.----------------------------------------------------------------------------------------------------------------\1\ Gross electric output.\2\ Incorporated by reference, see Sec. 63.14.\3\ You may not use the alternate SO2 limit if your EGU does not have some form of FGD system (or, in the case
of IGCC EGUs, some other acid gas removal system either upstream or downstream of the combined cycle block)
and SO2 CEMS installed.\4\ Duct burners on syngas; gross electric output.\5\ Duct burners on natural gas; gross electric output. [78 FR 24087, Apr. 24, 2013]
Sec. Table 2 to Subpart UUUUU of Part 63--Emission Limits for Existing
EGUs
As stated in Sec. 63.9991, you must comply with the following applicable emission limits: \1\ ----------------------------------------------------------------------------------------------------------------
Using these
requirements, as
appropriate (e.g.,
You must meet the specified sampling
If your EGU is in this subcategory. For the following following emission volume or test run
. . pollutants. . . limits and work practice duration) and
standards. . . limitations with the
test methods in Table
5. . .----------------------------------------------------------------------------------------------------------------1. Coal-fired unit not low rank a. Filterable 3.0E-2 lb/MMBtu or 3.0E- Collect a minimum of 1
virgin coal. particulate matter 1 lb/MWh.\2\ dscm per run.
(PM).
OR OR
Total non-Hg HAP metals 5.0E-5 lb/MMBtu or 5.0E- Collect a minimum of 1
1 lb/GWh. dscm per run.
OR OR
Individual HAP metals: ........................ Collect a minimum of 3
dscm per run.
Antimony (Sb).......... 8.0E-1 lb/TBtu or 8.0E-3
lb/GWh.
Arsenic (As)........... 1.1E0 lb/TBtu or 2.0E-2
lb/GWh.
Beryllium (Be)......... 2.0E-1 lb/TBtu or 2.0E-3
lb/GWh.
Cadmium (Cd)........... 3.0E-1 lb/TBtu or 3.0E-3
lb/GWh.
Chromium (Cr).......... 2.8E0 lb/TBtu or 3.0E-2
lb/GWh.
Cobalt (Co)............ 8.0E-1 lb/TBtu or 8.0E-3
lb/GWh.
Lead (Pb).............. 1.2E0 lb/TBtu or 2.0E-2
lb/GWh.
Manganese (Mn)......... 4.0E0 lb/TBtu or 5.0E-2
lb/GWh.
Nickel (Ni)............ 3.5E0 lb/TBtu or 4.0E-2
lb/GWh.
Selenium (Se).......... 5.0E0 lb/TBtu or 6.0E-2
lb/GWh.
b. Hydrogen chloride 2.0E-3 lb/MMBtu or 2.0E- For Method 26A, collect
(HCl). 2 lb/MWh. a minimum of 0.75 dscm
per run; for Method
26, collect a minimum
of 120 liters per run.
For ASTM D6348-03 \3\
or Method 320, sample
for a minimum of 1
hour.
OR ........................
Sulfur dioxide (SO2) 2.0E-1 lb/MMBtu or 1.5E0 SO2 CEMS.
\4\. lb/MWh.
c. Mercury (Hg)........ 1.2E0 lb/TBtu or 1.3E-2 LEE Testing for 30 days
lb/GWh with 10 days maximum
per Method 30B run or
Hg CEMS or sorbent
trap monitoring system
only.2. Coal-fired unit low rank virgin a. Filterable 3.0E-2 lb/MMBtu or 3.0E- Collect a minimum of 1
coal. particulate matter 1 lb/MWh.\2\ dscm per run.
(PM).
OR OR
Total non-Hg HAP metals 5.0E-5 lb/MMBtu or 5.0E- Collect a minimum of 1
1 lb/GWh. dscm per run.
OR OR
Individual HAP metals: ........................ Collect a minimum of 3
dscm per run.
Antimony (Sb).......... 8.0E-1 lb/TBtu or 8.0E-3
lb/GWh.
Arsenic (As)........... 1.1E0 lb/TBtu or 2.0E-2
lb/GWh.
Beryllium (Be)......... 2.0E-1 lb/TBtu or 2.0E-3
lb/GWh.
Cadmium (Cd)........... 3.0E-1 lb/TBtu or 3.0E-3
lb/GWh.
Chromium (Cr).......... 2.8E0 lb/TBtu or 3.0E-2
lb/GWh.
Cobalt (Co)............ 8.0E-1 lb/TBtu or 8.0E-3
lb/GWh.
Lead (Pb).............. 1.2E0 lb/TBtu or 2.0E-2
lb/GWh.
Manganese (Mn)......... 4.0E0 lb/TBtu or 5.0E-2
lb/GWh.
Nickel (Ni)............ 3.5E0 lb/TBtu or 4.0E-2
lb/GWh.
Selenium (Se).......... 5.0E0 lb/TBtu or 6.0E-2
lb/GWh.
b. Hydrogen chloride 2.0E-3 lb/MMBtu or 2.0E- For Method 26A, collect
(HCl). 2 lb/MWh. a minimum of 0.75 dscm
per run; for Method
26, collect a minimum
of 120 liters per run.
For ASTM D6348-03 \3\
or Method 320, sample
for a minimum of 1
hour.
OR
Sulfur dioxide (SO2) 2.0E-1 lb/MMBtu or 1.5E0 SO2 CEMS.
\4\. lb/MWh.
c. Mercury (Hg)........ 4.0E0 lb/TBtu or 4.0E-2 LEE Testing for 30 days
lb/GWh with 10 days maximum
per Method 30B run or
Hg CEMS or sorbent
trap monitoring system
only.3. IGCC unit........................ a. Filterable 4.0E-2 lb/MMBtu or 4.0E- Collect a minimum of 1
particulate matter 1 lb/MWh.\2\ dscm per run.
(PM).
OR OR
Total non-Hg HAP metals 6.0E-5 lb/MMBtu or 5.0E- Collect a minimum of 1
1 lb/GWh. dscm per run.
OR OR
Individual HAP metals: ........................ Collect a minimum of 2
dscm per run.
Antimony (Sb).......... 1.4E0 lb/TBtu or 2.0E-2
lb/GWh.
Arsenic (As)........... 1.5E0 lb/TBtu or 2.0E-2
lb/GWh.
Beryllium (Be)......... 1.0E-1 lb/TBtu or 1.0E-3
lb/GWh.
Cadmium (Cd)........... 1.5E-1 lb/TBtu or 2.0E-3
lb/GWh.
Chromium (Cr).......... 2.9E0 lb/TBtu or 3.0E-2
lb/GWh.
Cobalt (Co)............ 1.2E0 lb/TBtu or 2.0E-2
lb/GWh.
Lead (Pb).............. 1.9E+2 lb/TBtu or 1.8E0
lb/GWh.
Manganese (Mn)......... 2.5E0 lb/TBtu or 3.0E-2
lb/GWh.
Nickel (Ni)............ 6.5E0 lb/TBtu or 7.0E-2
lb/GWh.
Selenium (Se).......... 2.2E+1 lb/TBtu or 3.0E-1
lb/GWh.
b. Hydrogen chloride 5.0E-4 lb/MMBtu or 5.0E- For Method 26A, collect
(HCl). 3 lb/MWh. a minimum of 1 dscm
per run; for Method
26, collect a minimum
of 120 liters per run.
For ASTM D6348-03 \3\
or Method 320, sample
for a minimum of 1
hour.
c. Mercury (Hg)........ 2.5E0 lb/TBtu or 3.0E-2 LEE Testing for 30 days
lb/GWh with 10 days maximum
per Method 30B run or
Hg CEMS or sorbent
trap monitoring system
only.4. Liquid oil-fired unit-- a. Filterable 3.0E-2 lb/MMBtu or 3.0E- Collect a minimum of 1
continental (excluding limited-use particulate matter 1 lb/MWh.\2\ dscm per run.
liquid oil-fired subcategory units). (PM).
OR OR
Total HAP metals....... 8.0E-4 lb/MMBtu or 8.0E- Collect a minimum of 1
3 lb/MWh. dscm per run.
OR OR
Individual HAP metals: ........................ Collect a minimum of 1
dscm per run.
Antimony (Sb).......... 1.3E+1 lb/TBtu or 2.0E-1
lb/GWh.
Arsenic (As)........... 2.8E0 lb/TBtu or 3.0E-2
lb/GWh.
Beryllium (Be)......... 2.0E-1 lb/TBtu or 2.0E-3
lb/GWh.
Cadmium (Cd)........... 3.0E-1 lb/TBtu or 2.0E-3
lb/GWh.
Chromium (Cr).......... 5.5E0 lb/TBtu or 6.0E-2
lb/GWh.
Cobalt (Co)............ 2.1E+1 lb/TBtu or 3.0E-1
lb/GWh.
Lead (Pb).............. 8.1E0 lb/TBtu or 8.0E-2
lb/GWh.
Manganese (Mn)......... 2.2E+1 lb/TBtu or 3.0E-1
lb/GWh.
Nickel (Ni)............ 1.1E+2 lb/TBtu or 1.1E0
lb/GWh.
Selenium (Se).......... 3.3E0 lb/TBtu or 4.0E-2
lb/GWh.
Mercury (Hg)........... 2.0E-1 lb/TBtu or 2.0E-3 For Method 30B sample
lb/GWh. volume determination
(Section 8.2.4), the
estimated Hg
concentration should
nominally be <\1/2\;
the standard.
b. Hydrogen chloride 2.0E-3 lb/MMBtu or 1.0E- For Method 26A, collect
(HCl). 2 lb/MWh. a minimum of 1 dscm
per Run; for Method
26, collect a minimum
of 120 liters per run.
For ASTM D6348-03 \3\
or Method 320, sample
for a minimum of 1
hour.
c. Hydrogen fluoride 4.0E-4 lb/MMBtu or 4.0E- For Method 26A, collect
(HF). 3 lb/MWh. a minimum of 1 dscm
per run; for Method
26, collect a minimum
of 120 liters per run.
For ASTM D6348-03 \3\
or Method 320, sample
for a minimum of 1
hour.5. Liquid oil-fired unit--non- a. Filterable 3.0E-2 lb/MMBtu or 3.0E- Collect a minimum of 1
continental (excluding limited-use particulate matter 1 lb/MWh.\2\ dscm per run.
liquid oil-fired subcategory units). (PM).
OR OR
Total HAP metals 6.0E-4 lb/MMBtu or 7.0E- Collect a minimum of 1
3 lb/MWh. dscm per run.
OR OR
Individual HAP metals: ........................ Collect a minimum of 2
dscm per run.
Antimony (Sb).......... 2.2E0 lb/TBtu or 2.0E-2
lb/GWh.
Arsenic (As)........... 4.3E0 lb/TBtu or 8.0E-2
lb/GWh.
Beryllium (Be)......... 6.0E-1 lb/TBtu or 3.0E-3
lb/GWh.
Cadmium (Cd)........... 3.0E-1 lb/TBtu or 3.0E-3
lb/GWh.
Chromium (Cr).......... 3.1E+1 lb/TBtu or 3.0E-1
lb/GWh.
Cobalt (Co)............ 1.1E+2 lb/TBtu or 1.4E0
lb/GWh.
Lead (Pb).............. 4.9E0 lb/TBtu or 8.0E-2
lb/GWh.
Manganese (Mn)......... 2.0E+1 lb/TBtu or 3.0E-1
lb/GWh.
Nickel (Ni)............ 4.7E+2 lb/TBtu or 4.1E0
lb/GWh.
Selenium (Se).......... 9.8E0 lb/TBtu or 2.0E-1
lb/GWh.
Mercury (Hg)........... 4.0E-2 lb/TBtu or 4.0E-4 For Method 30B sample
lb/GWh. volume determination
(Section 8.2.4), the
estimated Hg
concentration should
nominally be <\1/2\;
the standard.
b. Hydrogen chloride 2.0E-4 lb/MMBtu or 2.0E- For Method 26A, collect
(HCl). 3 lb/MWh. a minimum of 1 dscm
per run; for Method
26, collect a minimum
of 120 liters per run.
For ASTM D6348-03 \3\
or Method 320, sample
for a minimum of 2
hours.
c. Hydrogen fluoride 6.0E-5 lb/MMBtu or 5.0E- For Method 26A, collect
(HF). 4 lb/MWh. a minimum of 3 dscm
per run.
For ASTM D6348-03 \3\
or Method 320, sample
for a minimum of 2
hours.6. Solid oil-derived fuel-fired unit a. Filterable 8.0E-3 lb/MMBtu or 9.0E- Collect a minimum of 1
particulate matter 2 lb/MWh.\2\ dscm per run.
(PM).
OR OR
Total non-Hg HAP metals 4.0E-5 lb/MMBtu or 6.0E- Collect a minimum of 1
1 lb/GWh. dscm per run.
OR OR
Individual HAP metals.. Collect a minimum of 3
dscm per run.
Antimony (Sb).......... 8.0E-1 lb/TBtu or 7.0E-3
lb/GWh.
Arsenic (As)........... 3.0E-1 lb/TBtu or 5.0E-3
lb/GWh.
Beryllium (Be)......... 6.0E-2 lb/TBtu or 5.0E-4
lb/GWh.
Cadmium (Cd)........... 3.0E-1 lb/TBtu or 4.0E-3
lb/GWh.
Chromium (Cr).......... 8.0E-1 lb/TBtu or 2.0E-2
lb/GWh.
Cobalt (Co)............ 1.1E0 lb/TBtu or 2.0E-2
lb/GWh.
Lead (Pb).............. 8.0E-1 lb/TBtu or 2.0E-2
lb/GWh.
Manganese (Mn)......... 2.3E0 lb/TBtu or 4.0E-2
lb/GWh.
Nickel (Ni)............ 9.0E0 lb/TBtu or 2.0E-1
lb/GWh.
Selenium (Se).......... 1.2E0 lb/TBtu or 2.0E-2
lb/GWh.
b. Hydrogen chloride 5.0E-3 lb/MMBtu or 8.0E- For Method 26A, collect
(HCl). 2 lb/MWh. a minimum of 0.75 dscm
per run; for Method
26, collect a minimum
of 120 liters per run.
For ASTM D6348-03 \3\
or Method 320, sample
for a minimum of 1
hour.
OR
Sulfur dioxide (SO2) 3.0E-1 lb/MMBtu or 2.0E0 SO2 CEMS.
\4\. lb/MWh.
c. Mercury (Hg)........ 2.0E-1 lb/TBtu or 2.0E-3 LEE Testing for 30 days
lb/GWh. with 10 days maximum
per Method 30B run or
Hg CEMS or Sorbent
trap monitoring system
only.----------------------------------------------------------------------------------------------------------------\1\ For LEE emissions testing for total PM, total HAP metals, individual HAP metals, HCl, and HF, the required
minimum sampling volume must be increased nominally by a factor of two.\2\ Gross electric output.\3\ Incorporated by reference, see Sec. 63.14.\4\ You may not use the alternate SO2 limit if your EGU does not have some form of FGD system and SO2 CEMS
installed. [77 FR 23405, Apr. 19, 2012]
Sec. Table 3 to Subpart UUUUU of Part 63--Work Practice Standards
As stated in Secs. 63.9991, you must comply with the following applicable work practice standards: ------------------------------------------------------------------------
If your EGU is. . . You must meet the following. . .------------------------------------------------------------------------1. An existing EGU........... Conduct a tune-up of the EGU burner and
combustion controls at least each 36
calendar months, or each 48 calendar
months if neural network combustion
optimization software is employed, as
specified in Sec. 63.10021(e).2. A new or reconstructed EGU Conduct a tune-up of the EGU burner and
combustion controls at least each 36
calendar months, or each 48 calendar
months if neural network combustion
optimization software is employed, as
specified in Sec. 63.10021(e).3. A coal-fired, liquid oil- You have the option of complying using
fired (excluding limited-use either of the following work practice
liquid oil-fired subcategory standards.
units), or solid oil-derived (1) If you choose to comply using
fuel-fired EGU during paragraph (1) of the definition of
startup. ``startup'' in Sec. 63.10042, you must
operate all CMS during startup. Startup
means either the first-ever firing of
fuel in a boiler for the purpose of
producing electricity, or the firing of
fuel in a boiler after a shutdown event
for any purpose. Startup ends when any
of the steam from the boiler is used to
generate electricity for sale over the
grid or for any other purpose (including
on site use). For startup of a unit, you
must use clean fuels as defined in Sec.
63.10042 for ignition. Once you convert
to firing coal, residual oil, or solid
oil-derived fuel, you must engage all of
the applicable control technologies
except dry scrubber and SCR. You must
start your dry scrubber and SCR systems,
if present, appropriately to comply with
relevant standards applicable during
normal operation. You must comply with
all applicable emissions limits at all
times except for periods that meet the
applicable definitions of startup and
shutdown in this subpart. You must keep
records during startup periods. You must
provide reports concerning activities
and startup periods, as specified in
Sec. 63.10011(g) and Sec. 63.10021(h)
and (i).
(2) If you choose to comply using
paragraph (2) of the definition of
``startup'' in Sec. 63.10042, you must
operate all CMS during startup. You must
also collect appropriate data, and you
must calculate the pollutant emission
rate for each hour of startup.
For startup of an EGU, you must use one
or a combination of the clean fuels
defined in Sec. 63.10042 to the maximum
extent possible throughout the startup
period. You must have sufficient clean
fuel capacity to engage and operate your
PM control device within one hour of
adding coal, residual oil, or solid oil-
derived fuel to the unit. You must meet
the startup period work practice
requirements as identified in Sec.
63.10020(e).
Once you start firing coal, residual oil,
or solid oil-derived fuel, you must vent
emissions to the main stack(s). You must
comply with the applicable emission
limits within 4 hours of start of
electricity generation. You must engage
and operate your particulate matter
control(s) within 1 hour of first firing
of coal, residual oil, or solid oil-
derived fuel.
You must start all other applicable
control devices as expeditiously as
possible, considering safety and
manufacturer/supplier recommendations,
but, in any case, when necessary to
comply with other standards made
applicable to the EGU by a permit limit
or a rule other than this Subpart that
require operation of the control
devices.
Relative to the syngas not fired in the
combustion turbine of an IGCC EGU during
startup, you must either: (1) flare the
syngas, or (2) route the syngas to duct
burners, which may need to be installed,
and route the flue gas from the duct
burners to the heat recovery steam
generator.
If you choose to use just one set of
sorbent traps to demonstrate compliance
with Hg emission limits, you must comply
with all applicable Hg emission limits
at all times; otherwise, you must comply
with all applicable emission limits at
all times except for startup or shutdown
periods conforming to this practice. You
must collect monitoring data during
startup periods, as specified in Sec.
63.10020(a) and (e). You must keep
records during startup periods, as
provided in Secs. 63.10032 and
63.10021(h). Any fraction of an hour in
which startup occurs constitutes a full
hour of startup. You must provide
reports concerning activities and
startup periods, as specified in Secs.
63.10011(g), 63.10021(i), and 63.10031.
4. A coal-fired, liquid oil- You must operate all CMS during shutdown.
fired (excluding limited-use You must also collect appropriate data,
liquid oil-fired subcategory and you must calculate the pollutant
units), or solid oil-derived emission rate for each hour of shutdown.
fuel-fired EGU during While firing coal, residual oil, or solid
shutdown. oil-derived fuel during shutdown, you
must vent emissions to the main stack(s)
and operate all applicable control
devices and continue to operate those
control devices after the cessation of
coal, residual oil, or solid oil-derived
fuel being fed into the EGU and for as
long as possible thereafter considering
operational and safety concerns. In any
case, you must operate your controls
when necessary to comply with other
standards made applicable to the EGU by
a permit limit or a rule other than this
Subpart and that require operation of
the control devices.
If, in addition to the fuel used prior to
initiation of shutdown, another fuel
must be used to support the shutdown
process, that additional fuel must be
one or a combination of the clean fuels
defined in Sec. 63.10042 and must be
used to the maximum extent possible.
Relative to the syngas not fired in the
combustion turbine of an IGCC EGU during
shutdown, you must either: (1) flare the
syngas, or (2) route the syngas to duct
burners, which may need to be installed,
and route the flue gas from the duct
burners to the heat recovery steam
generator.
You must comply with all applicable
emission limits at all times except
during startup periods and shutdown
periods at which time you must meet this
work practice. You must collect
monitoring data during shutdown periods,
as specified in Sec. 63.10020(a). You
must keep records during shutdown
periods, as provided in Secs. 63.10032
and 63.10021(h). Any fraction of an hour
in which shutdown occurs constitutes a
full hour of shutdown. You must provide
reports concerning activities and
shutdown periods, as specified in Secs.
63.10011(g), 63.10021(i), and 63.10031.------------------------------------------------------------------------ [79 FR 68792, Nov. 19, 2014]
Sec. Table 4 to Subpart UUUUU of Part 63--Operating Limits for EGUs
As stated in Sec. 63.9991, you must comply with the applicable operating limits: ------------------------------------------------------------------------
If you demonstrate compliance You must meet these operating
using. . . limits. . .------------------------------------------------------------------------1. PM CPMS for an existing EGU.... Maintain the 30-boiler operating day
rolling average PM CPMS output at
or below the highest 1-hour average
measured during the most recent
performance test demonstrating
compliance with the filterable PM,
total non-mercury HAP metals (total
HAP metals, for liquid oil-fired
units), or individual non-mercury
HAP metals (individual HAP metals
including Hg, for liquid oil-fired
units) emissions limitation(s).2. PM CPMS for a new EGU.......... Maintain the 30-boiler operating day
rolling average PM CPMS output
determined in accordance with the
requirements of Sec.
63.10023(b)(2) and obtained during
the most recent performance test
run demonstrating compliance with
the filterable PM, total non-
mercury HAP metals (total HAP
metals, for liquid oil-fired
units), or individual non-mercury
HAP metals (individual HAP metals
including Hg, for liquid oil-fired
units) emissions limitation(s).------------------------------------------------------------------------ [78 FR 24090, Apr. 24, 2013]
Sec. Table 5 to Subpart UUUUU of Part 63--Performance Testing
Requirements
As stated in Sec. 63.10007, you must comply with the following requirements for performance testing for existing, new or reconstructed affected sources: \1\ ----------------------------------------------------------------------------------------------------------------
You must perform the
following activities, as
To conduct a performance test for Using. . . applicable to your input- Using \2\. . .
the following pollutant. . . or output-based emission
limit. . .----------------------------------------------------------------------------------------------------------------1. Filterable Particulate matter Emissions Testing.... a. Select sampling ports Method 1 at Appendix A-1
(PM). location and the number to part 60 of this
of traverse points. chapter.
b. Determine velocity and Method 2, 2A, 2C, 2F, 2G
volumetric flow-rate of or 2H at Appendix A-1 or
the stack gas. A-2 to part 60 of this
chapter.
c. Determine oxygen and Method 3A or 3B at
carbon dioxide Appendix A-2 to part 60
concentrations of the of this chapter, or ANSI/
stack gas. ASME PTC 19.10-1981.\3\
d. Measure the moisture Method 4 at Appendix A-3
content of the stack gas. to part 60 of this
chapter.
e. Measure the filterable Method 5 at Appendix A-3
PM concentration. to part 60 of this
chapter.
For positive pressure
fabric filters, Method
5D at Appendix A-3 to
part 60 of this chapter
for filterable PM
emissions.
Note that the Method 5
front half temperature
shall be 160 [14 C (320
[25 F).
f. Convert emissions Method 19 F-factor
concentration to lb/MMBtu methodology at Appendix
or lb/MWh emissions rates. A-7 to part 60 of this
chapter, or calculate
using mass emissions
rate and electrical
output data (see Sec.
63.10007(e)).
OR OR
PM CEMS a. Install, certify, Performance Specification
operate, and maintain the 11 at Appendix B to part
PM CEMS. 60 of this chapter and
Procedure 2 at Appendix
F to Part 60 of this
chapter.
b. Install, certify, Part 75 of this chapter
operate, and maintain the and Secs. 63.10010(a),
diluent gas, flow rate, (b), (c), and (d).
and/or moisture
monitoring systems.
c. Convert hourly Method 19 F-factor
emissions concentrations methodology at Appendix
to 30 boiler operating A-7 to part 60 of this
day rolling average lb/ chapter, or calculate
MMBtu or lb/MWh emissions using mass emissions
rates. rate and electrical
output data (see Sec.
63.10007(e)).----------------------------------------------------------------------------------------------------------------2. Total or individual non-Hg HAP Emissions Testing.... a. Select sampling ports Method 1 at Appendix A-1
metals. location and the number to part 60 of this
of traverse points. chapter.
b. Determine velocity and Method 2, 2A, 2C, 2F, 2G
volumetric flow-rate of or 2H at Appendix A-1 or
the stack gas. A-2 to part 60 of this
chapter.
c. Determine oxygen and Method 3A or 3B at
carbon dioxide Appendix A-2 to part 60
concentrations of the of this chapter, or ANSI/
stack gas. ASME PTC 19.10-1981.\3\
d. Measure the moisture Method 4 at Appendix A-3
content of the stack gas. to part 60 of this
chapter.
e. Measure the HAP metals Method 29 at Appendix A-8
emissions concentrations to part 60 of this
and determine each chapter. For liquid oil-
individual HAP metals fired units, Hg is
emissions concentration, included in HAP metals
as well as the total and you may use Method
filterable HAP metals 29, Method 30B at
emissions concentration Appendix A-8 to part 60
and total HAP metals of this chapter; for
emissions concentration. Method 29, you must
report the front half
and back half results
separately.
f. Convert emissions Method 19 F-factor
concentrations methodology at Appendix
(individual HAP metals, A-7 to part 60 of this
total filterable HAP chapter, or calculate
metals, and total HAP using mass emissions
metals) to lb/MMBtu or lb/ rate and electrical
MWh emissions rates. output data (see Sec.
63.10007(e)).----------------------------------------------------------------------------------------------------------------3. Hydrogen chloride (HCl) and Emissions Testing.... a. Select sampling ports Method 1 at Appendix A-1
hydrogen fluoride (HF). location and the number to part 60 of this
of traverse points. chapter.
b. Determine velocity and Method 2, 2A, 2C, 2F, 2G
volumetric flow-rate of or 2H at Appendix A-1 or
the stack gas. A-2 to part 60 of this
chapter.
c. Determine oxygen and Method 3A or 3B at
carbon dioxide Appendix A-2 to part 60
concentrations of the of this chapter, or ANSI/
stack gas. ASME PTC 19.10-1981.\3\
d. Measure the moisture Method 4 at Appendix A-3
content of the stack gas. to part 60 of this
chapter.
e. Measure the HCl and HF Method 26 or Method 26A
emissions concentrations. at Appendix A-8 to part
60 of this chapter or
Method 320 at Appendix A
to part 63 of this
chapter or ASTM 6348-03
\3\ with (1) additional
quality assurance
measures in footnote \4\
and (2) spiking levels
nominally no greater
than two times the level
corresponding to the
applicable emission
limit. Method 26A must
be used if there are
entrained water droplets
in the exhaust stream.
f. Convert emissions Method 19 F-factor
concentration to lb/MMBtu methodology at Appendix
or lb/MWh emissions rates. A-7 to part 60 of this
chapter, or calculate
using mass emissions
rate and electrical
output data (see Sec.
63.10007(e)).
OR OR
HCl and/or HF CEMS... a. Install, certify, Appendix B of this
operate, and maintain the subpart.
HCl or HF CEMS.
b. Install, certify, Part 75 of this chapter
operate, and maintain the and Secs. 63.10010(a),
diluent gas, flow rate, (b), (c), and (d).
and/or moisture
monitoring systems.
c. Convert hourly Method 19 F-factor
emissions concentrations methodology at Appendix
to 30 boiler operating A-7 to part 60 of this
day rolling average lb/ chapter, or calculate
MMBtu or lb/MWh emissions using mass emissions
rates. rate and electrical
output data (see Sec.
63.10007(e)).----------------------------------------------------------------------------------------------------------------4. Mercury (Hg)................... Emissions Testing.... a. Select sampling ports Method 1 at Appendix A-1
location and the number to part 60 of this
of traverse points. chapter or Method 30B at
Appendix A-8 for Method
30B point selection.
b. Determine velocity and Method 2, 2A, 2C, 2F, 2G
volumetric flow-rate of or 2H at Appendix A-1 or
the stack gas. A-2 to part 60 of this
chapter.
c. Determine oxygen and Method 3A or 3B at
carbon dioxide Appendix A-1 to part 60
concentrations of the of this chapter, or ANSI/
stack gas. ASME PTC 19.10-1981.\3\
d. Measure the moisture Method 4 at Appendix A-3
content of the stack gas. to part 60 of this
chapter.
e. Measure the Hg emission Method 30B at Appendix A-
concentration. 8 to part 60 of this
chapter, ASTM D6784 \3\,
or Method 29 at Appendix
A-8 to part 60 of this
chapter; for Method 29,
you must report the
front half and back half
results separately.
f. Convert emissions Method 19 F-factor
concentration to lb/TBtu methodology at Appendix
or lb/GWh emission rates. A-7 to part 60 of this
chapter, or calculate
using mass emissions
rate and electrical
output data (see Sec.
63.10007(e)).
OR OR
Hg CEMS................... Sections 3.2.1 and 5.1 of
a. Install, certify, Appendix A of this
operate, and maintain the subpart.
CEMS.
b. Install, certify, Part 75 of this chapter
operate, and maintain the and Secs. 63.10010(a),
diluent gas, flow rate, (b), (c), and (d).
and/or moisture
monitoring systems.
c. Convert hourly Section 6 of Appendix A
emissions concentrations to this subpart.
to 30 boiler operating
day rolling average lb/
TBtu or lb/GWh emissions
rates.
OR OR
Sorbent trap a. Install, certify, Sections 3.2.2 and 5.2 of
monitoring system. operate, and maintain the Appendix A to this
sorbent trap monitoring subpart.
system.
b. Install, operate, and Part 75 of this chapter
maintain the diluent gas, and Secs. 63.10010(a),
flow rate, and/or (b), (c), and (d).
moisture monitoring
systems.
c. Convert emissions Section 6 of Appendix A
concentrations to 30 to this subpart.
boiler operating day
rolling average lb/TBtu
or lb/GWh emissions rates.
OR OR
LEE testing.......... a. Select sampling ports Single point located at
location and the number the 10% centroidal area
of traverse points. of the duct at a port
location per Method 1 at
Appendix A-1 to part 60
of this chapter or
Method 30B at Appendix A-
8 for Method 30B point
selection.
b. Determine velocity and Method 2, 2A, 2C, 2F, 2G,
volumetric flow-rate of or 2H at Appendix A-1 or
the stack gas. A-2 to part 60 of this
chapter or flow
monitoring system
certified per Appendix A
of this subpart.
c. Determine oxygen and Method 3A or 3B at
carbon dioxide Appendix A-1 to part 60
concentrations of the of this chapter, or ANSI/
stack gas. ASME PTC 19.10-1981,\3\
or diluent gas
monitoring systems
certified according to
Part 75 of this chapter.
d. Measure the moisture Method 4 at Appendix A-3
content of the stack gas. to part 60 of this
chapter, or moisture
monitoring systems
certified according to
part 75 of this chapter.
e. Measure the Hg emission Method 30B at Appendix A-
concentration. 8 to part 60 of this
chapter; perform a 30
operating day test, with
a maximum of 10
operating days per run
(i.e., per pair of
sorbent traps) or
sorbent trap monitoring
system or Hg CEMS
certified per Appendix A
of this subpart.
f. Convert emissions Method 19 F-factor
concentrations from the methodology at Appendix
LEE test to lb/TBtu or lb/ A-7 to part 60 of this
GWh emissions rates. chapter, or calculate
using mass emissions
rate and electrical
output data (see Sec.
63.10007(e)).
g. Convert average lb/TBtu Potential maximum annual
or lb/GWh Hg emission heat input in TBtu or
rate to lb/year, if you potential maximum
are attempting to meet electricity generated in
the 22.0 lb/year GWh.
threshold.----------------------------------------------------------------------------------------------------------------5. Sulfur dioxide (SO2)........... SO2 CEMS............. a. Install, certify, Part 75 of this chapter
operate, and maintain the and Secs. 63.10010(a)
CEMS. and (f).
b. Install, operate, and Part 75 of this chapter
maintain the diluent gas, and Secs. 63.10010(a),
flow rate, and/or (b), (c), and (d).
moisture monitoring
systems.
c. Convert hourly Method 19 F-factor
emissions concentrations methodology at Appendix
to 30 boiler operating A-7 to part 60 of this
day rolling average lb/ chapter, or calculate
MMBtu or lb/MWh emissions using mass emissions
rates. rate and electrical
output data (see Sec.
63.10007(e)).----------------------------------------------------------------------------------------------------------------\1\ Regarding emissions data collected during periods of startup or shutdown, see Secs. 63.10020(b) and (c) and
Sec. 63.10021(h).\2\ See Tables 1 and 2 to this subpart for required sample volumes and/or sampling run times.\3\ Incorporated by reference, see Sec. 63.14.\4\ When using ASTM D6348-03, the following conditions must be met: (1) The test plan preparation and
implementation in the Annexes to ASTM D6348-03, Sections A1 through A8 are mandatory; (2) For ASTM D6348-03
Annex A5 (Analyte Spiking Technique), the percent (%)R must be determined for each target analyte (see
Equation A5.5); (3) For the ASTM D6348-03 test data to be acceptable for a target analyte, %R must be 70% 4R
4130%; and (4) The %R value for each compound must be reported in the test report and all field measurements
corrected with the calculated %R value for that compound using the following equation:
[GRAPHIC] [TIFF OMITTED] TR16FE12.011
[77 FR 9464, Feb. 16, 2012, as amended at 78 FR 24091, Apr. 24, 2013] Sec. Table 6 to Subpart UUUUU of Part 63--Establishing PM CPMS Operating
Limits
As stated in Sec. 63.10007, you must comply with the following requirements for establishing operating limits: ----------------------------------------------------------------------------------------------------------------
And you choose to
If you have an applicable establish PM CPMS According to the
emission limit for. . . operating limits, And. . . Using. . . following
you must. . . procedures. . .----------------------------------------------------------------------------------------------------------------1. Filterable Particulate matter Install, certify, Establish a site- Data from the PM 1. Collect PM CPMS
(PM), total non-mercury HAP maintain, and specific CPMS and the PM output data
metals, individual non-mercury operate a PM CPMS operating limit or HAP metals during the entire
HAP metals, total HAP metals, for monitoring in units of PM performance tests. period of the
or individual HAP metals for an emissions CPMS output performance
existing EGU. discharged to the signal (e.g., tests.
atmosphere milliamps, mg/ 2. Record the
according to Sec. acm, or other raw average hourly PM
63.10010(h)(1). signal). CPMS output for
each test run in
the three run
performance test.
3. Determine the
highest 1-hour
average PM CPMS
measured during
the performance
test
demonstrating
compliance with
the filterable PM
or HAP metals
emissions
limitations.2. Filterable Particulate matter Install, certify, Establish a site- Data from the PM 1. Collect PM CPMS
(PM), total non-mercury HAP maintain, and specific CPMS and the PM output data
metals, individual non-mercury operate a PM CPMS operating limit or HAP metals during the entire
HAP metals, total HAP metals, for monitoring in units of PM performance tests. period of the
or individual HAP metals for a emissions CPMS output performance
new EGU. discharged to the signal (e.g., tests.
atmosphere milliamps, mg/ 2. Record the
according to Sec. acm, or other raw average hourly PM
63.10010(h)(1). signal). CPMS output for
each test run in
the performance
test.
3. Determine the
PM CPMS operating
limit in
accordance with
the requirements
of Sec.
63.10023(b)(2)
from data
obtained during
the performance
test
demonstrating
compliance with
the filterable PM
or HAP metals
emissions
limitations.---------------------------------------------------------------------------------------------------------------- [78 FR 24091, Apr. 24, 2013]
Sec. Table 7 to Subpart UUUUU of Part 63--Demonstrating Continuous
Compliance
As stated in Sec. 63.10021, you must show continuous compliance with the emission limitations for affected sources according to the following: ------------------------------------------------------------------------If you use one of the following to
meet applicable emissions limits, You demonstrate continuousoperating limits, or work practice compliance by. . .
standards. . .------------------------------------------------------------------------1. CEMS to measure filterable PM, Calculating the 30- (or 90-) boiler
SO2, HCl, HF, or Hg emissions, or operating day rolling arithmetic
using a sorbent trap monitoring average emissions rate in units of
system to measure Hg. the applicable emissions standard
basis at the end of each boiler
operating day using all of the
quality assured hourly average CEMS
or sorbent trap data for the
previous 30- (or 90-) boiler
operating days, excluding data
recorded during periods of startup
or shutdown.2. PM CPMS to measure compliance Calculating the 30- (or 90-) boiler
with a parametric operating limit. operating day rolling arithmetic
average of all of the quality
assured hourly average PM CPMS
output data (e.g., milliamps, PM
concentration, raw data signal)
collected for all operating hours
for the previous 30- (or 90-)
boiler operating days, excluding
data recorded during periods of
startup or shutdown.3. Site-specific monitoring using If applicable, by conducting the
CMS for liquid oil-fired EGUs for monitoring in accordance with an
HCl and HF emission limit approved site-specific monitoring
monitoring. plan.
4. Quarterly performance testing Calculating the results of the
for coal-fired, solid oil derived testing in units of the applicable
fired, or liquid oil-fired EGUs emissions standard.
to measure compliance with one or
more non-PM (or its alternative
emission limits) applicable
emissions limit in Table 1 or 2,
or PM (or its alternative
emission limits) applicable
emissions limit in Table 2.5. Conducting periodic performance Conducting periodic performance tune-
tune-ups of your EGU(s). ups of your EGU(s), as specified in
Sec. 63.10021(e).6. Work practice standards for Operating in accordance with Table
coal-fired, liquid oil-fired, or 3.
solid oil-derived fuel-fired EGUs
during startup.7. Work practice standards for Operating in accordance with Table
coal-fired, liquid oil-fired, or 3.
solid oil-derived fuel-fired EGUs
during shutdown.------------------------------------------------------------------------ [78 FR 24092, Apr. 24, 2013]
Sec. Table 8 to Subpart UUUUU of Part 63--Reporting Requirements
As stated in Sec. 63.10031, you must comply with the following requirements for reports: ----------------------------------------------------------------------------------------------------------------
You must submit the
You must submit a. . . The report must contain. . . report. . .----------------------------------------------------------------------------------------------------------------1. Compliance report.................... a. Information required in Sec. Semiannually according to
63.10031(c)(1) through (4); and the requirements in Sec.
b. If there are no deviations from any 63.10031(b).
emission limitation (emission limit and
operating limit) that applies to you and
there are no deviations from the
requirements for work practice standards
in Table 3 to this subpart that apply to
you, a statement that there were no
deviations from the emission limitations
and work practice standards during the
reporting period. If there were no
periods during which the CMSs, including
continuous emissions monitoring system,
and operating parameter monitoring
systems, were out-of-control as specified
in Sec. 63.8(c)(7), a statement that
there were no periods during which the
CMSs were out-of-control during the
reporting period; and.
c. If you have a deviation from any ..........................
emission limitation (emission limit and
operating limit) or work practice
standard during the reporting period, the
report must contain the information in
Sec. 63.10031(d). If there were periods
during which the CMSs, including
continuous emissions monitoring systems
and continuous parameter monitoring
systems, were out-of-control, as
specified in Sec. 63.8(c)(7), the report
must contain the information in Sec.
63.10031(e).----------------------------------------------------------------------------------------------------------------
Sec. Table 9 to Subpart UUUUU of Part 63--Applicability of General
Provisions to Subpart UUUUU
As stated in Sec. 63.10040, you must comply with the applicable General Provisions according to the following:
[As stated in Sec. 63.10040, you must comply with the applicable
General Provisions according to the following]------------------------------------------------------------------------
Applies to subpart
Citation Subject UUUUU------------------------------------------------------------------------Sec. 63.1.................... Applicability.... Yes.Sec. 63.2.................... Definitions...... Yes. Additional terms
defined in Sec.
63.10042.Sec. 63.3.................... Units and Yes.
Abbreviations.Sec. 63.4.................... Prohibited Yes.
Activities and
Circumvention.Sec. 63.5.................... Preconstruction Yes.
Review and
Notification
Requirements.
Sec. 63.6(a), (b)(1)-(5), Compliance with Yes.
(b)(7), (c), (f)(2)-(3), Standards and
(7), (c), (f)(2)-(3), Standards and
(h)(2)-(9), (i), (j). Maintenance
(2)-(9), (i), (j). Maintenance
Requirements.Sec. 63.6(e)(1)(i)........... General Duty to No. See Sec.
minimize 63.10000(b) for
emissions. general duty
requirement.Sec. 63.6(e)(1)(ii).......... Requirement to No.
correct
malfunctions
ASAP.Sec. 63.6(e)(3).............. SSM Plan No.
requirements.Sec. 63.6(f)(1).............. SSM exemption.... No.Sec. 63.6(h)(1).............. SSM exemption.... No.Sec. 63.6(g)................. Compliance with Yes. See Secs.
Standards and 63.10011(g)(4) and
Maintenance 63.10021(h)(4) for
Requirements, additional
Use of an requirements.
alternative non-
opacity emission
standard.Sec. 63.7(e)(1).............. Performance No. See Sec.
testing. 63.10007.Sec. 63.8.................... Monitoring Yes.
Requirements.Sec. 63.8(c)(1)(i)........... General duty to No. See Sec.
minimize 63.10000(b) for
emissions and general duty
CMS operation. requirement.Sec. 63.8(c)(1)(iii)......... Requirement to No.
develop SSM Plan
for CMS.Sec. 63.8(d)(3).............. Written Yes, except for last
procedures for sentence, which
CMS. refers to an SSM
plan. SSM plans are
not required.Sec. 63.9.................... Notification Yes.
Requirements.Sec. 63.10(a), (b)(1), (c), Recordkeeping and Yes, except for the
(d)(1)-(2), (e), and (f). Reporting requirements to
(1)-(2), (e), and (f). Reporting requirements to
Requirements. submit written
reports under Sec.
63.10(e)(3)(v).Sec. 63.10(b)(2)(i).......... Recordkeeping of No.
occurrence and
duration of
startups and
shutdowns.Sec. 63.10(b)(2)(ii)......... Recordkeeping of No. See Sec.
malfunctions. 63.10001 for
recordkeeping of (1)
occurrence and
duration and (2)
actions taken during
malfunction.Sec. 63.10(b)(2)(iii)........ Maintenance Yes.
records.Sec. 63.10(b)(2)(iv)......... Actions taken to No.
minimize
emissions during
SSM.Sec. 63.10(b)(2)(v).......... Actions taken to No.
minimize
emissions during
SSM.Sec. 63.10(b)(2)(vi)......... Recordkeeping for Yes.
CMS malfunctions.Sec. 63.10(b)(2)(vii)-(ix)... Other CMS Yes.
requirements.Sec. 63.10(b)(3), and (d)(3)- ................. No.
(5).Sec. 63.10(c)(7)............. Additional Yes.
recordkeeping
requirements for
CMS--identifying
exceedances and
excess emissions.Sec. 63.10(c)(8)............. Additional Yes.
recordkeeping
requirements for
CMS--identifying
exceedances and
excess emissions.Sec. 63.10(c)(10)............ Recording nature No. See Sec.
and cause of 63.10032(g) and (h)
malfunctions. for malfunctions
recordkeeping
requirements.Sec. 63.10(c)(11)............ Recording No. See Sec.
corrective 63.10032(g) and (h)
actions. for malfunctions
recordkeeping
requirements.Sec. 63.10(c)(15)............ Use of SSM Plan.. No.Sec. 63.10(d)(5)............. SSM reports...... No. See Sec.
63.10021(h) and (i)
for malfunction
reporting
requirements.Sec. 63.11................... Control Device No.
Requirements.Sec. 63.12................... State Authority Yes.
and Delegation.Secs. 63.13-63.16............ Addresses, Yes.
Incorporation by
Reference,
Availability of
Information,
Performance
Track Provisions.Secs. 63.1(a)(5), (a)(7)-(9), Reserved......... No.
(b)(2), (c)(3)-(4), (d),
(2), (c)(3)-(4), (d),
63.6(b)(6), (c)(3), (c)(4),
(d), (e)(2), (e)(3)(ii),
(h)(3), (h)(5)(iv),
(3), (h)(5)(iv),
63.8(a)(3), 63.9(b)(3),
(h)(4), 63.10(c)(2)-(4),
(4), 63.10(c)(2)-(4),
(c)(9).------------------------------------------------------------------------ [79 FR 68793, Nov. 19, 2014]
(9).------------------------------------------------------------------------ [79 FR 68793, Nov. 19, 2014]
Sec. Appendix A to Subpart UUUUU of Part 63--Hg Monitoring Provisions
1. General Provisions
1.1 Applicability. These monitoring provisions apply to the measurement of total vapor phase mercury (Hg) in emissions from electric utility steam generating units, using either a mercury continuous emission monitoring system (Hg CEMS) or a sorbent trap monitoring system. The Hg CEMS or sorbent trap monitoring system must be capable of measuring the total vapor phase mercury in units of the applicable emissions standard (e.g., lb/TBtu or lb/GWh), regardless of speciation.
1.2 Initial Certification and Recertification Procedures. The owner or operator of an affected unit that uses a Hg CEMS or a sorbent trap monitoring system together with other necessary monitoring components to account for Hg emissions in units of the applicable emissions standard shall comply with the initial certification and recertification procedures in section 4 of this appendix.
1.3 Quality Assurance and Quality Control Requirements. The owner or operator of an affected unit that uses a Hg CEMS or a sorbent trap monitoring system together with other necessary monitoring components to account for Hg emissions in units of the applicable emissions standard shall meet the applicable quality assurance requirements in section 5 of this appendix.
1.4 Missing Data Procedures. The owner or operator of an affected unit is not required to substitute for missing data from Hg CEMS or sorbent trap monitoring systems. Any process operating hour for which quality-assured Hg concentration data are not obtained is counted as an hour of monitoring system downtime.
2. Monitoring of Hg Emissions
2.1 Monitoring System Installation Requirements. Flue gases from the affected units under this subpart vent to the atmosphere through a variety of exhaust configurations including single stacks, common stack configurations, and multiple stack configurations. For each of these configurations, Sec. 63.10010(a) specifies the appropriate location(s) at which to install continuous monitoring systems (CMS). These CMS installation provisions apply to the Hg CEMS, sorbent trap monitoring systems, and other continuous monitoring systems that provide data for the Hg emissions calculations in section 6.2 of this appendix.
2.2 Primary and Backup Monitoring Systems. In the electronic monitoring plan described in section 7.1.1.2.1 of this appendix, you must designate a primary Hg CEMS or sorbent trap monitoring system. The primary system must be used to report hourly Hg concentration values when the system is able to provide quality-assured data, i.e., when the system is ``in control''. However, to increase data availability in the event of a primary monitoring system outage, you may install, operate, maintain, and calibrate backup monitoring systems, as follows:
2.2.1 Redundant Backup Systems. A redundant backup monitoring system may be either a separate Hg CEMS with its own probe, sample interface, and analyzer, or a separate sorbent trap monitoring system. A redundant backup system is one that is permanently installed at the unit or stack location, and is kept on ``hot standby'' in case the primary monitoring system is unable to provide quality-assured data. A redundant backup system must be represented as a unique monitoring system in the electronic monitoring plan. Each redundant backup monitoring system must be certified according to the applicable provisions in section 4 of this appendix and must meet the applicable on-going QA requirements in section 5 of this appendix.
2.2.2 Non-redundant Backup Monitoring Systems. A non-redundant backup monitoring system is a separate Hg CEMS or sorbent trap system that has been certified at a particular unit or stack location, but is not permanently installed at that location. Rather, the system is kept on ``cold standby'' and may be reinstalled in the event of a primary monitoring system outage. A non-redundant backup monitoring system must be represented as a unique monitoring system in the electronic monitoring plan. Non-redundant backup Hg CEMS must complete the same certification tests as the primary monitoring system, with one exception. The 7-day calibration error test is not required for a non-redundant backup Hg CEMS. Except as otherwise provided in section 2.2.4.5 of this appendix, a non-redundant backup monitoring system may only be used for 720 hours per year at a particular unit or stack location.
2.2.3 Temporary Like-kind Replacement Analyzers. When a primary Hg analyzer needs repair or maintenance, you may temporarily install a like-kind replacement analyzer, to minimize data loss. Except as otherwise provided in section 2.2.4.5 of this appendix, a temporary like-kind replacement analyzer may only be used for 720 hours per year at a particular unit or stack location. The analyzer must be represented as a component of the primary Hg CEMS, and must be assigned a 3-character component ID number, beginning with the prefix ``LK''.
2.2.4 Quality Assurance Requirements for Non-redundant Backup Monitoring Systems and Temporary Like-kind Replacement Analyzers. To quality-assure the data from non-redundant backup Hg monitoring systems and temporary like-kind replacement Hg analyzers, the following provisions apply:
2.2.4.1 When a certified non-redundant backup sorbent trap monitoring system is brought into service, you must follow the procedures for routine day-to-day operation of the system, in accordance with Performance Specification (PS) 12B in appendix B to part 60 of this chapter.
2.2.4.2 When a certified non-redundant backup Hg CEMS or a temporary like-kind replacement Hg analyzer is brought into service, a calibration error test and a linearity check must be performed and passed. A single point system integrity check is also required, unless a NIST-traceable source of oxidized Hg was used for the calibration error test.
2.2.4.3 Each non-redundant backup Hg CEMS or temporary like-kind replacement Hg analyzer shall comply with all required daily, weekly, and quarterly quality-assurance test requirements in section 5 of this appendix, for as long as the system or analyzer remains in service.
2.2.4.4 For the routine, on-going quality-assurance of a non-redundant backup Hg monitoring system, a relative accuracy test audit (RATA) must be performed and passed at least once every 8 calendar quarters at the unit or stack location(s) where the system will be used.
2.2.4.5 To use a non-redundant backup Hg monitoring system or a temporary like-kind replacement analyzer for more than 720 hours per year at a particular unit or stack location, a RATA must first be performed and passed at that location.
3. Mercury Emissions Measurement Methods
The following definitions, equipment specifications, procedures, and performance criteria are applicable to the measurement of vapor-phase Hg emissions from electric utility steam generating units, under relatively low-dust conditions (i.e., sampling in the stack or duct after all pollution control devices). The analyte measured by these procedures and specifications is total vapor-phase Hg in the flue gas, which represents the sum of elemental Hg (Hg0, CAS Number 7439-97-6) and oxidized forms of Hg.
3.1 Definitions.
3.1.1 Mercury Continuous Emission Monitoring System or Hg CEMS means all of the equipment used to continuously determine the total vapor phase Hg concentration. The measurement system may include the following major subsystems: sample acquisition, Hg+2 to Hg0 converter, sample transport, sample conditioning, flow control/gas manifold, gas analyzer, and data acquisition and handling system (DAHS). Hg CEMS may be nominally real-time or time-integrated, batch sampling systems that sample the gas on an intermittent basis and concentrate on a collection medium before intermittent analysis and reporting.
3.1.2 Sorbent Trap Monitoring System means the equipment required to monitor Hg emissions continuously by using paired sorbent traps containing iodated charcoal (IC) or other suitable sorbent medium. The monitoring system consists of a probe, paired sorbent traps, an umbilical line, moisture removal components, an airtight sample pump, a gas flow meter, and an automated data acquisition and handling system. The system samples the stack gas at a constant proportional rate relative to the stack gas volumetric flow rate. The sampling is a batch process. The average Hg concentration in the stack gas for the sampling period is determined, in units of micrograms per dry standard cubic meter (g/dscm), based on the sample volume measured by the gas flow meter and the mass of Hg collected in the sorbent traps.
3.1.3 NIST means the National Institute of Standards and Technology, located in Gaithersburg, Maryland.
3.1.4 NIST-Traceable Elemental Hg Standards means either: compressed gas cylinders having known concentrations of elemental Hg, which have been prepared according to the ``EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards''; or calibration gases having known concentrations of elemental Hg, produced by a generator that meets the performance requirements of the ``EPA Traceability Protocol for Qualification and Certification of Elemental Mercury Gas Generators'' or an interim version of that protocol.
3.1.5 NIST-Traceable Source of Oxidized Hg means a generator that is capable of providing known concentrations of vapor phase mercuric chloride (HgCl2), and that meets the performance requirements of the ``EPA Traceability Protocol for Qualification and Certification of Mercuric Chloride Gas Generators'' or an interim version of that protocol.
3.1.6 Calibration Gas means a NIST-traceable gas standard containing a known concentration of elemental or oxidized Hg that is produced and certified in accordance with an EPA traceability protocol.
3.1.7 Span Value means a conservatively high estimate of the Hg concentrations to be measured by a CEMS. The span value of a Hg CEMS should be set to approximately twice the concentration corresponding to the emission standard, rounded off as appropriate (see section 3.2.1.4.2 of this appendix).
3.1.8 Zero-Level Gas means calibration gas containing a Hg concentration that is below the level detectable by the Hg gas analyzer in use.
3.1.9 Low-Level Gas means calibration gas with a concentration that is 20 to 30 percent of the span value.
3.1.10 Mid-Level Gas means calibration gas with a concentration that is 50 to 60 percent of the span value.
3.1.11 High-Level Gas means calibration gas with a concentration that is 80 to 100 percent of the span value.
3.1.12 Calibration Error Test means a test designed to assess the ability of a Hg CEMS to measure the concentrations of calibration gases accurately. A zero-level gas and an upscale gas are required for this test. For the upscale gas, either a mid-level gas or a high-level gas may be used, and the gas may either be an elemental or oxidized Hg standard.
3.1.13 Linearity Check means a test designed to determine whether the response of a Hg analyzer is linear across its measurement range. Three elemental Hg calibration gas standards (i.e., low, mid, and high-level gases) are required for this test.
3.1.14 System Integrity Check means a test designed to assess the transport and measurement of oxidized Hg by a Hg CEMS. Oxidized Hg standards are used for this test. For a three-level system integrity check, low, mid, and high-level calibration gases are required. For a single-level check, either a mid-level gas or a high-level gas may be used.
3.1.15 Cycle Time Test means a test designed to measure the amount of time it takes for a Hg CEMS, while operating normally, to respond to a known step change in gas concentration. For this test, a zero gas and a high-level gas are required. The high-level gas may be either an elemental or an oxidized Hg standard.
3.1.16 Relative Accuracy Test Audit or RATA means a series of nine or more test runs, directly comparing readings from a Hg CEMS or sorbent trap monitoring system to measurements made with a reference stack test method. The relative accuracy (RA) of the monitoring system is expressed as the absolute mean difference between the monitoring system and reference method measurements plus the absolute value of the 2.5 percent error confidence coefficient, divided by the mean value of the reference method measurements.
3.1.17 Unit Operating Hour means a clock hour in which a unit combusts any fuel, either for part of the hour or for the entire hour.
3.1.18 Stack Operating Hour means a clock hour in which gases flow through a particular monitored stack or duct (either for part of the hour or for the entire hour), while the associated unit(s) are combusting fuel.
3.1.19 Operating Day means a calendar day in which a source combusts any fuel.
3.1.20 Quality Assurance (QA) Operating Quarter means a calendar quarter in which there are at least 168 unit or stack operating hours (as defined in this section).
3.1.21 Grace Period means a specified number of unit or stack operating hours after the deadline for a required quality-assurance test of a continuous monitor has passed, in which the test may be performed and passed without loss of data.
3.2 Continuous Monitoring Methods.
3.2.1 Hg CEMS. A typical Hg CEMS is shown in Figure A-1. The CEMS in Figure A-1 is a dilution extractive system, which measures Hg concentration on a wet basis, and is the most commonly-used type of Hg CEMS. Other system designs may be used, provided that the CEMS meets the performance specifications in section 4.1.1 of this appendix. [GRAPHIC] [TIFF OMITTED] TR16FE12.012
3.2.1.1 Equipment Specifications.
3.2.1.1.1 Materials of Construction. All wetted sampling system components, including probe components prior to the point at which the calibration gas is introduced, must be chemically inert to all Hg species. Materials such as perfluoroalkoxy (PFA) Teflon\TM\, quartz, and treated stainless steel (SS) are examples of such materials.
3.2.1.1.2 Temperature Considerations. All system components prior to the Hg+2 to Hg\0\ converter must be maintained at a sample temperature above the acid gas dew point.
3.2.1.1.3 Measurement System Components.
3.2.1.1.3.1 Sample Probe. The probe must be made of the appropriate materials as noted in paragraph 3.2.1.1.1 of this section, heated when necessary, as described in paragraph 3.2.1.1.3.4 of this section, and configured with ports for introduction of calibration gases.
3.2.1.1.3.2 Filter or Other Particulate Removal Device. The filter or other particulate removal device is part of the measurement system, must be made of appropriate materials, as noted in paragraph 3.2.1.1.1 of this section, and must be included in all system tests.
3.2.1.1.3.3 Sample Line. The sample line that connects the probe to the converter, conditioning system, and analyzer must be made of appropriate materials, as noted in paragraph 3.2.1.1.1 of this section.
3.2.1.1.3.4 Conditioning Equipment. For wet basis systems, such as the one shown in Figure A-1, the sample must be kept above its dew point either by: heating the sample line and all sample transport components up to the inlet of the analyzer (and, for hot-wet extractive systems, also heating the analyzer); or diluting the sample prior to analysis using a dilution probe system. The components required for these operations are considered to be conditioning equipment. For dry basis measurements, a condenser, dryer or other suitable device is required to remove moisture continuously from the sample gas, and any equipment needed to heat the probe or sample line to avoid condensation prior to the moisture removal component is also required.
3.2.1.1.3.5 Sampling Pump. A pump is needed to push or pull the sample gas through the system at a flow rate sufficient to minimize the response time of the measurement system. If a mechanical sample pump is used and its surfaces are in contact with the sample gas prior to detection, the pump must be leak free and must be constructed of a material that is non-reactive to the gas being sampled (see paragraph 3.2.1.1.1 of this section). For dilution-type measurement systems, such as the system shown in Figure A-1, an ejector pump (eductor) may be used to create a sufficient vacuum that sample gas will be drawn through a critical orifice at a constant rate. The ejector pump must be constructed of any material that is non-reactive to the gas being sampled.
3.2.1.1.3.6 Calibration Gas System(s). Design and equip each Hg CEMS to permit the introduction of known concentrations of elemental Hg and HgCl2 separately, at a point preceding the sample extraction filtration system, such that the entire measurement system can be checked. The calibration gas system(s) must be designed so that the flow rate exceeds the sampling system flow requirements and that the gas is delivered to the CEMS at atmospheric pressure.
3.2.1.1.3.7 Sample Gas Delivery. The sample line may feed directly to either a converter, a by-pass valve (for Hg speciating systems), or a sample manifold. All valve and/or manifold components must be made of material that is non-reactive to the gas sampled and the calibration gas, and must be configured to safely discharge any excess gas.
3.2.1.1.3.8 Hg Analyzer. An instrument is required that continuously measures the total vapor phase Hg concentration in the gas stream. The analyzer may also be capable of measuring elemental and oxidized Hg separately.
3.2.1.1.3.9 Data Recorder. A recorder, such as a computerized data acquisition and handling system (DAHS), digital recorder, or data logger, is required for recording measurement data.
3.2.1.2 Reagents and Standards.
3.2.1.2.1 NIST Traceability. Only NIST-certified or NIST-traceable calibration gas standards and reagents (as defined in paragraphs 3.1.4 and 3.1.5 of this section) shall be used for the tests and procedures required under this subpart. Calibration gases with known concentrations of Hg0 and HgCl2 are required. Special reagents and equipment may be needed to prepare the Hg0 and HgCl2 gas standards (e.g., NIST-traceable solutions of HgCl2 and gas generators equipped with mass flow controllers).
3.2.1.2.2 Required Calibration Gas Concentrations.
3.2.1.2.2.1 Zero-Level Gas. A zero-level calibration gas with a Hg concentration below the level detectable by the Hg analyzer is required for calibration error tests and cycle time tests of the CEMS.
3.2.1.2.2.2 Low-Level Gas. A low-level calibration gas with a Hg concentration of 20 to 30 percent of the span value is required for linearity checks and 3-level system integrity checks of the CEMS. Elemental Hg standards are required for the linearity checks and oxidized Hg standards are required for the system integrity checks.
3.2.1.2.2.3 Mid-Level Gas. A mid-level calibration gas with a Hg concentration of 50 to 60 percent of the span value is required for linearity checks and for 3-level system integrity checks of the CEMS, and is optional for calibration error tests and single-level system integrity checks. Elemental Hg standards are required for the linearity checks, oxidized Hg standards are required for the system integrity checks, and either elemental or oxidized Hg standards may be used for the calibration error tests.
3.2.1.2.2.4 High-Level Gas. A high-level calibration gas with a Hg concentration of 80 to 100 percent of the span value is required for linearity checks, 3-level system integrity checks, and cycle time tests of the CEMS, and is optional for calibration error tests and single-level system integrity checks. Elemental Hg standards are required for the linearity checks, oxidized Hg standards are required for the system integrity checks, and either elemental or oxidized Hg standards may be used for the calibration error and cycle time tests.
3.2.1.3 Installation and Measurement Location. For the Hg CEMS and any additional monitoring system(s) needed to convert Hg concentrations to the desired units of measure (i.e., a flow monitor, CO2 or O2 monitor, and/or moisture monitor, as applicable), install each monitoring system at a location: that is consistent with 63.10010(a); that represents the emissions exiting to the atmosphere; and where it is likely that the CEMS can pass the relative accuracy test.
3.2.1.4 Monitor Span and Range Requirements. Determine the appropriate span and range value(s) for the Hg CEMS as described in paragraphs 3.2.1.4.1 through 3.2.1.4.3 of this section.
3.2.1.4.1 Maximum Potential Concentration. There are three options for determining the maximum potential Hg concentration (MPC). Option 1 applies to coal combustion. You may use a default value of 10 g/scm for all coal ranks (including coal refuse) except for lignite; for lignite, use 16 g/scm. If different coals are blended as part of normal operation, use the highest MPC for any fuel in the blend. Option 2 is to base the MPC on the results of site-specific Hg emission testing. This option may be used only if the unit does not have add-on Hg emission controls or a flue gas desulfurization system, or if testing is performed upstream of all emission control devices. If Option 2 is selected, perform at least three test runs at the normal operating load, and the highest Hg concentration obtained in any of the tests shall be the MPC. Option 3 is to use fuel sampling and analysis to estimate the MPC. To make this estimate, use the average Hg content (i.e., the weight percentage) from at least three representative fuel samples, together with other available information, including, but not limited to the maximum fuel feed rate, the heating value of the fuel, and an appropriate F-factor. Assume that all of the Hg in the fuel is emitted to the atmosphere as vapor-phase Hg.
3.2.1.4.2 Span Value. To determine the span value of the Hg CEMS, multiply the Hg concentration corresponding to the applicable emissions standard by two. If the result of this calculation is an exact multiple of 10 g/scm, use the result as the span value. Otherwise, round off the result to either: the next highest integer; the next highest multiple of 5 g/scm; or the next highest multiple of 10 g/scm.
3.2.1.4.3 Analyzer Range. The Hg analyzer must be capable of reading Hg concentration as high as the MPC.
3.2.2 Sorbent Trap Monitoring System. A sorbent trap monitoring system (as defined in paragraph 3.1.2 of this section) may be used as an alternative to a Hg CEMS. If this option is selected, the monitoring system shall be installed, maintained, and operated in accordance with Performance Specification (PS) 12B in Appendix B to part 60 of this chapter. The system shall be certified in accordance with the provisions of section 4.1.2 of this appendix.
3.2.3 Other Necessary Data Collection. To convert measured hourly Hg concentrations to the units of the applicable emissions standard (i.e., lb/TBtu or lb/GWh), additional data must be collected, as described in paragraphs 3.2.3.1 through 3.2.3.3 of this section. Any additional monitoring systems needed for this purpose must be certified, operated, maintained, and quality-assured according to the applicable provisions of part 75 of this chapter (see Secs. 63.10010(b) through (d)). The calculation methods for the types of emission limits described in paragraphs 3.2.3.1 and 3.2.3.2 of this section are presented in section 6.2 of this appendix.
3.2.3.1 Heat Input-Based Emission Limits. For a heat input-based Hg emission limit (i.e., in lb/TBtu), data from a certified CO2 or O2 monitor are needed, along with a fuel-specific F-factor and a conversion constant to convert measured Hg concentration values to the units of the standard. In some cases, the stack gas moisture content must also be considered in making these conversions.
3.2.3.2 Electrical Output-Based Emission Rates. If the applicable Hg limit is electrical output-based (i.e., lb/GWh), hourly electrical load data and unit operating times are required in addition to hourly data from a certified stack gas flow rate monitor and (if applicable) moisture data.
3.2.3.3 Sorbent Trap Monitoring System Operation. Routine operation of a sorbent trap monitoring system requires the use of a certified stack gas flow rate monitor, to maintain an established ratio of stack gas flow rate to sample flow rate.
4. Certification and Recertification Requirements
4.1 Certification Requirements. All Hg CEMS and sorbent trap monitoring systems and the additional monitoring systems used to continuously measure Hg emissions in units of the applicable emissions standard in accordance with this appendix must be certified in a timely manner, such that the initial compliance demonstration is completed no later than the applicable date in Sec. 63.9984(f).
4.1.1 Hg CEMS. Table A-1, below, summarizes the certification test requirements and performance specifications for a Hg CEMS. The CEMS may not be used to report quality-assured data until these performance criteria are met. Paragraphs 4.1.1.1 through 4.1.1.5 of this section provide specific instructions for the required tests. All tests must be performed with the affected unit(s) operating (i.e., combusting fuel). Except for the RATA, which must be performed at normal load, no particular load level is required for the certification tests.
4.1.1.1 7-Day Calibration Error Test. Perform the 7-day calibration error test on 7 consecutive source operating days, using a zero-level gas and either a high-level or a mid-level calibration gas standard (as defined in sections 3.1.8, 3.1.10, and 3.1.11 of this appendix). Either elemental or oxidized NIST-traceable Hg standards (as defined in sections 3.1.4 and 3.1.5 of this appendix) may be used for the test. If moisture and/or chlorine is added to the calibration gas, the dilution effect of the moisture and/or chlorine addition on the calibration gas concentration must be accounted for in an appropriate manner. Operate the Hg CEMS in its normal sampling mode during the test. The calibrations should be approximately 24 hours apart, unless the 7-day test is performed over nonconsecutive calendar days. On each day of the test, inject the zero-level and upscale gases in sequence and record the analyzer responses. Pass the calibration gas through all filters, scrubbers, conditioners, and other monitor components used during normal sampling, and through as much of the sampling probe as is practical. Do not make any manual adjustments to the monitor (i.e., resetting the calibration) until after taking measurements at both the zero and upscale concentration levels. If automatic adjustments are made following both injections, conduct the calibration error test such that the magnitude of the adjustments can be determined, and use only the unadjusted analyzer responses in the calculations. Calculate the calibration error (CE) on each day of the test, as described in Table A-1. The CE on each day of the test must either meet the main performance specification or the alternative specification in Table A-1.
4.1.1.2 Linearity Check. Perform the linearity check using low, mid, and high-level concentrations of NIST-traceable elemental Hg standards. Three gas injections at each concentration level are required, with no two successive injections at the same concentration level. Introduce the calibration gas at the gas injection port, as specified in section 3.2.1.1.3.6 of this appendix. Operate the CEMS at its normal operating temperature and conditions. Pass the calibration gas through all filters, scrubbers, conditioners, and other components used during normal sampling, and through as much of the sampling probe as is practical. If moisture and/or chlorine is added to the calibration gas, the dilution effect of the moisture and/or chlorine addition on the calibration gas concentration must be accounted for in an appropriate manner. Record the monitor response from the data acquisition and handling system for each gas injection. At each concentration level, use the average analyzer response to calculate the linearity error (LE), as described in Table A-1. The LE must either meet the main performance specification or the alternative specification in Table A-1.
4.1.1.3 Three-Level System Integrity Check. Perform the 3-level system integrity check using low, mid, and high-level calibration gas concentrations generated by a NIST-traceable source of oxidized Hg. Follow the same basic procedure as for the linearity check. If moisture and/or chlorine is added to the calibration gas, the dilution effect of the moisture and/or chlorine addition on the calibration gas concentration must be accounted for in an appropriate manner. Calculate the system integrity error (SIE), as described in Table A-1. The SIE must either meet the main performance specification or the alternative specification in Table A-1. (Note: This test is not required if the CEMS does not have a converter).
Table A-1--Required Certification Tests and Performance Specifications for Hg CEMS----------------------------------------------------------------------------------------------------------------
The alternate
For this required certification The main performance performance And the conditions of
test. . . specification \1\ is . . specification \1\ is. . the alternate
. . specification are. . .----------------------------------------------------------------------------------------------------------------7-day calibration error test \2\.... R - A 45.0% of span R - A 41.0 g/scm. specification may be
zero and upscale gases, used on any day of
on each of the 7 days. the test.Linearity check \3\................. R - Aavg 410.0% of R - Aavg 40.8 g/scm. specification may be
concentration at each used at any gas
calibration gas level level.
(low, mid, or high).3-level system integrity check \4\.. R - Aavg 410.0% of R - Aavg 40.8 g/scm. specification may be
concentration at each used at any gas
calibration gas level. level.RATA................................ 20.0% RA................ RMavg - Cavg 41.0 RMavg <5.0 g/
g/scm**. scm.Cycle time test \2\................. 15 minutes.\5\----------------------------------------------------------------------------------------------------------------\1\ Note that R - A is the absolute value of the difference between the reference gas value and the analyzer
reading. R - Aavg, is the absolute value of the difference between the reference gas concentration and the
average of the analyzer responses, at a particular gas level.\2\ Use either elemental or oxidized Hg standards; a mid-level or high-level upscale gas may be used. This test
is not required for Hg CEMS that use integrated batch sampling; however, those monitors must be capable of
recording at least one Hg concentration reading every 15 minutes.\3\ Use elemental Hg standards.\4\ Use oxidized Hg standards. Not required if the CEMS does not have a converter.\5\ Stability criteria--Readings change by <2.0% of span or by 40.5 g/scm, for 2 minutes.** Note that RMavg-Cavg is the absolute difference between the mean reference method value and the mean CEMS
value from the RATA. The arithmetic difference between RMavg and Cavg can be either + or -.
4.1.1.4 Cycle Time Test. Perform the cycle time test, using a zero-level gas and a high-level calibration gas.
Either an elemental or oxidized NIST-traceable Hg standard may be used as the high-level gas. Perform the test in two stages--upscale and downscale. The slower of the upscale and downscale response times is the cycle time for the CEMS. Begin each stage of the test by injecting calibration gas after achieving a stable reading of the stack emissions. The cycle time is the amount of time it takes for the analyzer to register a reading that is 95 percent of the way between the stable stack emissions reading and the final, stable reading of the calibration gas concentration. Use the following criterion to determine when a stable reading of stack emissions or calibration gas has been attained--the reading is stable if it changes by no more than 2.0 percent of the span value or 0.5 g/scm (whichever is less restrictive) for two minutes, or a reading with a change of less than 6.0 percent from the measured average concentration over 6 minutes. Integrated batch sampling type Hg CEMS are exempted from this test; however, these systems must be capable of delivering a measured Hg concentration reading at least once every 15 minutes. If necessary to increase measurement sensitivity of a batch sampling type Hg CEMS for a specific application, you may petition the Administrator for approval of a time longer than 15 minutes between readings.
4.1.1.5 Relative Accuracy Test Audit (RATA). Perform the RATA of the Hg CEMS at normal load. Acceptable Hg reference methods for the RATA include ASTM D6784-02 (Reapproved 2008), ``Standard Test Method for Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro Method)'' (incorporated by reference, see Sec. 63.14) and Methods 29, 30A, and 30B in appendix A-8 to part 60. When Method 29 or ASTM D6784-02 is used, paired sampling trains are required. To validate a Method 29 or ASTM D6784-02 test run, calculate the relative deviation (RD) using Equation A-1 of this section, and assess the results as follows to validate the run. The RD must not exceed 10 percent, when the average Hg concentration is greater than 1.0 g/dscm. If the average concentration is 41.0 g/dscm, the RD must not exceed 20 percent. The RD results are also acceptable if the absolute difference between the two Hg concentrations does not exceed 0.2 g/dscm. If the RD specification is met, the results of the two samples shall be averaged arithmetically.[GRAPHIC] [TIFF OMITTED] TR16FE12.013 Where: RD = Relative deviation between the Hg concentrations of samples ``a''
and ``b'' (percent)Ca = Hg concentration of Hg sample ``a'' (g/dscm)Cb = Hg concentration of Hg sample ``b'' (g/dscm)
4.1.1.5.1 Special Considerations. A minimum of nine valid test runs must be performed, directly comparing the CEMS measurements to the reference method. More than nine test runs may be performed. If this option is chosen, the results from a maximum of three test runs may be rejected so long as the total number of test results used to determine the relative accuracy is greater than or equal to nine; however, all data must be reported including the rejected data. The minimum time per run is 21 minutes if Method 30A is used. If Method 29, Method 30B, or ASTM D6784-02 (Reapproved 2008), ``Standard Test Method for Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro Method)'' (incorporated by reference, see Sec. 63.14) is used, the time per run must be long enough to collect a sufficient mass of Hg to analyze. Complete the RATA within 168 unit operating hours, except when Method 29 or ASTM D6784-02 is used, in which case up to 336 operating hours may be taken to finish the test.
4.1.1.5.2 Calculation of RATA Results. Calculate the relative accuracy (RA) of the monitoring system, on a g/scm basis, as described in section 12 of Performance Specification (PS) 2 in Appendix B to part 60 of this chapter (see Equations 2-3 through 2-6 of PS2). For purposes of calculating the relative accuracy, ensure that the reference method and monitoring system data are on a consistent moisture basis, either wet or dry. The CEMS must either meet the main performance specification or the alternative specification in Table A-1.
4.1.1.5.3 Bias Adjustment. Measurement or adjustment of Hg CEMS data for bias is not required.
4.1.2 Sorbent Trap Monitoring Systems. For the initial certification of a sorbent trap monitoring system, only a RATA is required.
4.1.2.1 Reference Methods. The acceptable reference methods for the RATA of a sorbent trap monitoring system are the same as those listed in paragraph 4.1.1.5 of this section.
4.1.2.2 ``The special considerations specified in paragraph 4.1.1.5.1 of this section apply to the RATA of a sorbent trap monitoring system. During the RATA, the monitoring system must be operated and quality-assured in accordance with Performance Specification (PS) 12B in Appendix B to part 60 of this chapter with the following exceptions for sorbent trap section 2 breakthrough:
4.1.2.2.1 For stack Hg concentrations >1 g/dscm, 410% of section 1 Hg mass;
4.1.2.2.2 For stack Hg concentrations 41 g/dscm and >0.5 g/dscm, 420% of section 1 Hg mass;
4.1.2.2.3 For stack Hg concentrations 40.5 g/dscm and >0.1 g/dscm, 450% of section 1 Hg mass; and
4.1.2.2.4 For stack Hg concentrations 40.1g/dscm, no breakthrough criterion assuming all other QA/QC specifications are met.
4.1.2.3 The type of sorbent material used by the traps during the RATA must be the same as for daily operation of the monitoring system; however, the size of the traps used for the RATA may be smaller than the traps used for daily operation of the system.
4.1.2.4 Calculation of RATA Results. Calculate the relative accuracy (RA) of the sorbent trap monitoring system, on a g/scm basis, as described in section 12 of Performance Specification (PS) 2 in appendix B to part 60 of this chapter (see Equations 2-3 through 2-6 of PS2). For purposes of calculating the relative accuracy, ensure that the reference method and monitoring system data are on a consistent moisture basis, either wet or dry.The main and alternative RATA performance specifications in Table A-1 for Hg CEMS also apply to the sorbent trap monitoring system.
4.1.2.5 Bias Adjustment. Measurement or adjustment of sorbent trap monitoring system data for bias is not required.
4.1.3 Diluent Gas, Flow Rate, and/or Moisture Monitoring Systems. Monitoring systems that are used to measure stack gas volumetric flow rate, diluent gas concentration, or stack gas moisture content, either for routine operation of a sorbent trap monitoring system or to convert Hg concentration data to units of the applicable emission limit, must be certified in accordance with the applicable provisions of part 75 of this chapter.
4.2 Recertification. Whenever the owner or operator makes a replacement, modification, or change to a certified CEMS or sorbent trap monitoring system that may significantly affect the ability of the system to accurately measure or record pollutant or diluent gas concentrations, stack gas flow rates, or stack gas moisture content, the owner or operator shall recertify the monitoring system. Furthermore, whenever the owner or operator makes a replacement, modification, or change to the flue gas handling system or the unit operation that may significantly change the concentration or flow profile, the owner or operator shall recertify the monitoring system. The same tests performed for the initial certification of the monitoring system shall be repeated for recertification, unless otherwise specified by the Administrator. Examples of changes that require recertification include: replacement of a gas analyzer; complete monitoring system replacement, and changing the location or orientation of the sampling probe.
5. Ongoing Quality Assurance (QA) and Data Validation
5.1 Hg CEMS.
5.1.1 Required QA Tests. Periodic QA testing of each Hg CEMS is required following initial certification. The required QA tests, the test frequencies, and the performance specifications that must be met are summarized in Table A-2, below. All tests must be performed with the affected unit(s) operating (i.e., combusting fuel). Except for the RATA, which must be performed at normal load, no particular load level is required for the tests. For each test, follow the same basic procedures in section 4.1.1 of this appendix that were used for initial certification.
5.1.2 Test Frequency. The frequency for the required QA tests of the Hg CEMS shall be as follows:
5.1.2.1 Calibration error tests of the Hg CEMS are required daily, except during unit outages. Use either NIST-traceable elemental Hg standards or NIST-traceable oxidized Hg standards for these calibrations. Both a zero-level gas and either a mid-level or high-level gas are required for these calibrations.
5.1.2.2 Perform a linearity check of the Hg CEMS in each QA operating quarter, using low-level, mid-level, and high-level NIST-traceable elemental Hg standards. For units that operate infrequently, limited exemptions from this test are allowed for ``non-QA operating quarters''. A maximum of three consecutive exemptions for this reason are permitted, following the quarter of the last test. After the third consecutive exemption, a linearity check must be performed in the next calendar quarter or within a grace period of 168 unit or stack operating hours after the end of that quarter. The test frequency for 3-level system integrity checks (if performed in lieu of linearity checks) is the same as for the linearity checks. Use low-level, mid-level, and high-level NIST-traceable oxidized Hg standards for the system integrity checks.
5.1.2.3 If required, perform a single-level system integrity check weekly, i.e., once every 7 operating days (see the third column in Table A-2).
5.1.2.4 The test frequency for the RATAs of the Hg CEMS shall be annual, i.e., once every four QA operating quarters. For units that operate infrequently, extensions of RATA deadlines are allowed for non-QA operating quarters. Following a RATA, if there is a subsequent non-QA quarter, it extends the deadline for the next test by one calendar quarter. However, there is a limit to these extensions; the deadline may not be extended beyond the end of the eighth calendar quarter after the quarter of the last test. At that point, a RATA must either be performed within the eighth calendar quarter or in a 720 hour unit or stack operating hour grace period following that quarter. When a required annual RATA is done within a grace period, the deadline for the next RATA is three QA operating quarters after the quarter in which the grace period test is performed.
5.1.3 Grace Periods.
5.1.3.1 A 168 unit or stack operating hour grace period is available for quarterly linearity checks and 3-level system integrity checks of the Hg CEMS.
5.1.3.2 A 720 unit or stack operating hour grace period is available for RATAs of the Hg CEMS.
5.1.3.3 There is no grace period for weekly system integrity checks. The test must be completed once every 7 operating days.
5.1.4 Data Validation. The Hg CEMS is considered to be out-of-control, and data from the CEMS may not be reported as quality-assured, when any one of the acceptance criteria for the required QA tests in Table A-2 is not met. The CEMS is also considered to be out-of-control when a required QA test is not performed on schedule or within an allotted grace period. To end an out-of-control period, the QA test that was either failed or not done on time must be performed and passed. Out-of-control periods are counted as hours of monitoring system downtime.
5.1.5 Conditional Data Validation. For certification, recertification, and diagnostic testing of Hg monitoring systems, and for the required QA tests when non-redundant backup Hg monitoring systems or temporary like-kind Hg analyzers are brought into service, the conditional data validation provisions in Secs. 75.20(b)(3)(ii) through (b)(3)(ix) of this chapter may be used to avoid or minimize data loss. The allotted window of time to complete 7-day calibration error tests, linearity checks, cycle time tests, and RATAs shall be as specified in Sec. 75.20(b)(3)(iv) of this chapter. Required system integrity checks must be completed within 168 unit or stack operating hours after the probationary calibration error test.
Table A-2--On-Going QA Test Requirements for Hg CEMS----------------------------------------------------------------------------------------------------------------
With these
Perform this type of QA test. . . At this frequency. . . qualifications and Acceptance criteria. .
exceptions. . . .----------------------------------------------------------------------------------------------------------------Calibration error test............... Daily.................. Use either a mid- or R-A 45.0% of span
high-level gas. value.
or
R-A 41.0 g/
scm.
Use either elemental
or oxidized Hg.
Calibrations are not
required when the unit
is not in operation.Single-level system integrity check.. Weekly \1\............. Required only for R-Aavg 410.0% of the
systems with reference gas value.
converters. or
R-Aavg 40.8 g/scm.
Use oxidized Hg--
either mid- or high-
level.
Not required if daily
calibrations are done
with a NIST-traceable
source of oxidized Hg.Linearity check Quarterly \3\.......... Required in each ``QA R-Aavg 410.0% of theor................................... operating quarter'' reference gas value,3-level system integrity check....... \2\--and no less than at each calibration
once every 4 calendar gas level.
quarters. or
R-Aavg 40.8 g/scm.
168 operating hour
grace period available.
Use elemental Hg for
linearity check.
Use oxidized Hg for
system integrity check.
For system integrity
check, CEMS must have
a converter.RATA................................. Annual \4\............. Test deadline may be 20.0% RA.
extended for ``non-QA or
operating quarters'', RMavg-Cavg 41.0
up to a maximum of 8 g/scm,
quarters from the if
quarter of the RMavg <5.0 g/
previous test. scm.
720 operating hour
grace period available.----------------------------------------------------------------------------------------------------------------\1\ ``Weekly'' means once every 7 operating days.\2\ A ``QA operating quarter'' is a calendar quarter with at least 168 unit or stack operating hours.\3\ ``Quarterly'' means once every QA operating quarter.\4\ ``Annual'' means once every four QA operating quarters.
5.1.6 Adjustment of Span. If you discover that a span adjustment is needed (e.g., if the Hg concentration readings exceed the span value for a significant percentage of the unit operating hours in a calendar quarter), you must implement the span adjustment within 90 days after the end of the calendar quarter in which you identify the need for the adjustment. A diagnostic linearity check is required within 168 unit or stack operating hours after changing the span value.
5.2 Sorbent Trap Monitoring Systems.
5.2.1 Each sorbent trap monitoring system shall be continuously operated and maintained in accordance with Performance Specification (PS) 12B in appendix B to part 60 of this chapter. The QA/QC criteria for routine operation of the system are summarized in Table 12B-1 of PS 12B. Each pair of sorbent traps may be used to sample the stack gas for up to 14 operating days.
5.2.2 For ongoing QA, periodic RATAs of the system are required.
5.2.2.1 The RATA frequency shall be annual, i.e., once every four QA operating quarters. The provisions in section 5.1.2.4 of this appendix pertaining to RATA deadline extensions also apply to sorbent trap monitoring systems.
5.2.2.2 The same RATA performance criteria specified in Table A-2 for Hg CEMS also apply to the annual RATAs of the sorbent trap monitoring system.
5.2.2.3 A 720 unit or stack operating hour grace period is available for RATAs of the monitoring system.
5.2.3 Data validation for sorbent trap monitoring systems shall be done in accordance with Table 12B-1 in Performance Specification (PS) 12B in appendix B to part 60 of this chapter. All periods of invalid data shall be counted as hours of monitoring system downtime.
5.3 Flow Rate, Diluent Gas, and Moisture Monitoring Systems. The on-going QA test requirements for these monitoring systems are specified in part 75 of this chapter (see Secs. 63.10010(b) through (d)).
5.4 QA/QC Program Requirements. The owner or operator shall develop and implement a quality assurance/quality control (QA/QC) program for the Hg CEMS and/or sorbent trap monitoring systems that are used to provide data under this subpart. At a minimum, the program shall include a written plan that describes in detail (or that refers to separate documents containing) complete, step-by-step procedures and operations for the most important QA/QC activities. Electronic storage of the QA/QC plan is permissible, provided that the information can be made available in hard copy to auditors and inspectors. The QA/QC program requirements for the diluent gas, flow rate, and moisture monitoring systems described in section 3.2.1.3 of this appendix are specified in section 1 of appendix B to part 75 of this chapter.
5.4.1 General Requirements.
5.4.1.1 Preventive Maintenance. Keep a written record of procedures needed to maintain the Hg CEMS and/or sorbent trap monitoring system(s) in proper operating condition and a schedule for those procedures. Include, at a minimum, all procedures specified by the manufacturers of the equipment and, if applicable, additional or alternate procedures developed for the equipment.
5.4.1.2 Recordkeeping and Reporting. Keep a written record describing procedures that will be used to implement the recordkeeping and reporting requirements of this appendix.
5.4.1.3 Maintenance Records. Keep a record of all testing, maintenance, or repair activities performed on any Hg CEMS or sorbent trap monitoring system in a location and format suitable for inspection. A maintenance log may be used for this purpose. The following records should be maintained: date, time, and description of any testing, adjustment, repair, replacement, or preventive maintenance action performed on any monitoring system and records of any corrective actions associated with a monitor outage period. Additionally, any adjustment that may significantly affect a system's ability to accurately measure emissions data must be recorded (e.g., changing the dilution ratio of a CEMS), and a written explanation of the procedures used to make the adjustment(s) shall be kept.
5.4.2 Specific Requirements for Hg CEMS.
5.4.2.1 Daily Calibrations, Linearity Checks and System Integrity Checks. Keep a written record of the procedures used for daily calibrations of the Hg CEMS. If moisture and/or chlorine is added to the Hg calibration gas, document how the dilution effect of the moisture and/or chlorine addition on the calibration gas concentration is accounted for in an appropriate manner. Also keep records of the procedures used to perform linearity checks of the Hg CEMS and the procedures for system integrity checks of the Hg CEMS. Document how the test results are calculated and evaluated.
5.4.2.2 Monitoring System Adjustments. Document how each component of the Hg CEMS will be adjusted to provide correct responses to calibration gases after routine maintenance, repairs, or corrective actions.
5.4.2.3 Relative Accuracy Test Audits. Keep a written record of procedures used for RATAs of the Hg CEMS. Indicate the reference methods used and document how the test results are calculated and evaluated.
5.4.3 Specific Requirements for Sorbent Trap Monitoring Systems.
5.4.3.1 Sorbent Trap Identification and Tracking. Include procedures for inscribing or otherwise permanently marking a unique identification number on each sorbent trap, for chain of custody purposes. Keep records of the ID of the monitoring system in which each sorbent trap is used, and the dates and hours of each Hg collection period.
5.4.3.2 Monitoring System Integrity and Data Quality. Document the procedures used to perform the leak checks when a sorbent trap is placed in service and removed from service. Also Document the other QA procedures used to ensure system integrity and data quality, including, but not limited to, gas flow meter calibrations, verification of moisture removal, and ensuring air-tight pump operation. In addition, the QA plan must include the data acceptance and quality control criteria in Table 12B-1 in section 9.0 of Performance Specification (PS) 12B in Appendix B to part 60 of this chapter. All reference meters used to calibrate the gas flow meters (e.g., wet test meters) shall be periodically recalibrated. Annual, or more frequent, recalibration is recommended. If a NIST-traceable calibration device is used as a reference flow meter, the QA plan must include a protocol for ongoing maintenance and periodic recalibration to maintain the accuracy and NIST-traceability of the calibrator.
5.4.3.3 Hg Analysis. Explain the chain of custody employed in packing, transporting, and analyzing the sorbent traps. Keep records of all Hg analyses. The analyses shall be performed in accordance with the procedures described in section 11.0 of Performance Specification (PS) 12B in Appendix B to part 60 of this chapter.
5.4.3.4 Data Collection Period. State, and provide the rationale for, the minimum acceptable data collection period (e.g., one day, one week, etc.) for the size of sorbent trap selected for the monitoring. Address such factors as the Hg concentration in the stack gas, the capacity of the sorbent trap, and the minimum mass of Hg required for the analysis. Each pair of sorbent traps may be used to sample the stack gas for up to 14 operating days.
5.4.3.5 Relative Accuracy Test Audit Procedures. Keep records of the procedures and details peculiar to the sorbent trap monitoring systems that are to be followed for relative accuracy test audits, such as sampling and analysis methods.
6. Data Reduction and Calculations
6.1 Data Reduction.
6.1.1 Reduce the data from Hg CEMS to hourly averages, in accordance with Sec. 60.13(h)(2) of this chapter.
6.1.2 For sorbent trap monitoring systems, determine the Hg concentration for each data collection period and assign this concentration value to each operating hour in the data collection period.
6.1.3 For any operating hour in which valid data are not obtained, either for Hg concentration or for a parameter used in the emissions calculations (i.e., flow rate, diluent gas concentration, or moisture, as applicable), do not calculate the Hg emission rate for that hour. For the purposes of this appendix, part 75 substitute data values are not considered to be valid data.
6.1.4 Operating hours in which valid data are not obtained for Hg concentration are considered to be hours of monitor downtime. The use of substitute data for Hg concentration is not required.
6.2 Calculation of Hg Emission Rates. Use the applicable calculation methods in paragraphs 6.2.1 and 6.2.2 of this section to convert Hg concentration values to the appropriate units of the emission standard.
6.2.1 Heat Input-Based Hg Emission Rates. Calculate hourly heat input-based Hg emission rates, in units of lb/TBtu, according to sections 6.2.1.1 through 6.2.1.4 of this appendix.
6.2.1.1 Select an appropriate emission rate equation from among Equations 19-1 through 19-9 in EPA Method 19 in appendix A-7 to part 60 of this chapter.
6.2.1.2 Calculate the Hg emission rate in lb/MMBtu, using the equation selected from Method 19. Multiply the Hg concentration value by 6.24 x 10-11 to convert it from g/scm to lb/scf. In cases where an appropriate F-factor is not listed in Table 19-2 of Method 19, you may use F-factors from Table 1 in section 3.3.5 of appendix F to part 75 of this chapter, or F-factors derived using the procedures in section 3.3.6 of appendix to part 75 of this chapter. Also, for startup and shutdown hours, you may calculate the Hg emission rate using the applicable diluent cap value specified in section 3.3.4.1 of appendix F to part 75 of this chapter, provided that the diluent gas monitor is not out-of-control and the hourly average O2 concentration is above 14.0% O2 (19.0% for an IGCC) or the hourly average CO2 concentration is below 5.0% CO2 (1.0% for an IGCC), as applicable.
6.2.1.3 Multiply the lb/MMBtu value obtained in section 6.2.1.2 of this appendix by 10\6\ to convert it to lb/TBtu.
6.2.1.4 The heat input-based Hg emission rate limit in Table 2 to this subpart must be met on a 30 boiler operating day rolling average basis, except as otherwise provided in Sec. 63.10009(a)(2). Use Equation 19-19 in EPA Method 19 to calculate the Hg emission rate for each averaging period. The term Ehj in Equation 19-19 must be in the units of the applicable emission limit. Do not include non-operating hours with zero emissions in the average.
6.2.2 Electrical Output-Based Hg Emission Rates. Calculate electrical output-based Hg emission limits in units of lb/GWh, according to sections 6.2.2.1 through 6.2.2.3 of this appendix.
6.2.2.1 Calculate the Hg mass emissions for each operating hour in which valid data are obtained for all parameters, using Equation A-2 of this section (for wet-basis measurements of Hg concentration) or Equation A-3 of this section (for dry-basis measurements), as applicable:[GRAPHIC] [TIFF OMITTED] TR16FE12.014 Where: Mh = Hg mass emission rate for the hour (lb/h)K = Units conversion constant, 6.24 x 10-11 lb-scm/
g-scf,Ch = Hourly average Hg concentration, wet basis (g/
scm)Qh = Stack gas volumetric flow rate for the hour (scfh).
(Note: Use unadjusted flow rate values; bias adjustment is not required)[GRAPHIC] [TIFF OMITTED] TR16FE12.015 Where: Mh = Hg mass emission rate for the hour (lb/h)K = Units conversion constant, 6.24 x 10-11 lb-scm/
g-scf.Ch = Hourly average Hg concentration, dry basis (g/
dscm).Qh = Stack gas volumetric flow rate for the hour (scfh)(Note: Use unadjusted flow rate values; bias adjustment is not
required).Bws = Moisture fraction of the stack gas, expressed as a
decimal (equal to % H2O/100)
6.2.2.2 Use Equation A-4 of this section to calculate the emission rate for each unit or stack operating hour in which valid data are obtained for all parameters.[GRAPHIC] [TIFF OMITTED] TR16FE12.016 Where: Eho = Electrical output-based Hg emission rate (lb/GWh).Mh = Hg mass emission rate for the hour, from Equation A-2 or
A-3 of this section, as applicable (lb/h).(MW)h = Gross electrical load for the hour, in megawatts
(MW).10 \3\ = Conversion factor from megawatts to gigawatts.
6.2.2.3 The applicable electrical output-based Hg emission rate limit in Table 1 or 2 to this subpart must be met on a 30-boiler operating day rolling average basis, except as otherwise provided in Sec. 63.10009(a)(2). Use Equation A-5 of this section to calculate the Hg emission rate for each averaging period.[GRAPHIC] [TIFF OMITTED] TR19AP12.003 Where: Eo = Hg emission rate for the averaging period (lb/GWh).Echo = Electrical output-based hourly Hg emission rate for
unit or stack operating hour ``h'' in the averaging period,
from Equation A-4 of this section (lb/GWh).n = Number of unit or stack operating hours in the averaging period in
which valid data were obtained for all parameters.(Note: Do not include non-operating hours with zero emission rates in the average).
7. Recordkeeping and Reporting
7.1 Recordkeeping Provisions. For the Hg CEMS and/or sorbent trap monitoring systems and any other necessary monitoring systems installed at each affected unit, the owner or operator must maintain a file of all measurements, data, reports, and other information required by this appendix in a form suitable for inspection, for 5 years from the date of each record, in accordance with Sec. 63.10033. The file shall contain the information in paragraphs 7.1.1 through 7.1.10 of this section.
7.1.1 Monitoring Plan Records. For each affected unit or group of units monitored at a common stack, the owner or operator shall prepare and maintain a monitoring plan for the Hg CEMS and/or sorbent trap monitoring system(s) and any other monitoring system(s) (i.e., flow rate, diluent gas, or moisture systems) needed for routine operation of a sorbent trap monitoring system or to convert Hg concentrations to units of the applicable emission standard. The monitoring plan shall contain essential information on the continuous monitoring systems and shall Document how the data derived from these systems ensure that all Hg emissions from the unit or stack are monitored and reported.
7.1.1.1 Updates. Whenever the owner or operator makes a replacement, modification, or change in a certified continuous monitoring system that is used to provide data under this subpart (including a change in the automated data acquisition and handling system or the flue gas handling system) which affects information reported in the monitoring plan (e.g., a change to a serial number for a component of a monitoring system), the owner or operator shall update the monitoring plan.
7.1.1.2 Contents of the Monitoring Plan. For Hg CEMS and sorbent trap monitoring systems, the monitoring plan shall contain the information in sections 7.1.1.2.1 and 7.1.1.2.2 of this appendix, as applicable. For stack gas flow rate, diluent gas, and moisture monitoring systems, the monitoring plan shall include the information required for those systems under Sec. 75.53 (g) of this chapter.
7.1.1.2.1 Electronic. The electronic monitoring plan records must include the following: unit or stack ID number(s); monitoring location(s); the Hg monitoring methodologies used; Hg monitoring system information, including, but not limited to: Unique system and component ID numbers; the make, model, and serial number of the monitoring equipment; the sample acquisition method; formulas used to calculate Hg emissions; Hg monitor span and range information The electronic monitoring plan shall be evaluated and submitted using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by the Clean Air Markets Division in the Office of Atmospheric Programs of the EPA.
7.1.1.2.2 Hard Copy. Keep records of the following: schematics and/or blueprints showing the location of the Hg monitoring system(s) and test ports; data flow diagrams; test protocols; monitor span and range calculations; miscellaneous technical justifications.
7.1.2 Operating Parameter Records. The owner or operator shall record the following information for each operating hour of each affected unit and also for each group of units utilizing a common stack, to the extent that these data are needed to convert Hg concentration data to the units of the emission standard. For non-operating hours, record only the items in paragraphs 7.1.2.1 and 7.1.2.2 of this section. If there is heat input to the unit(s), but no electrical load, record only the items in paragraphs 7.1.2.1, 7.1.2.2, and (if applicable) 7.1.2.4 of this section.
7.1.2.1 The date and hour;
7.1.2.2 The unit or stack operating time (rounded up to the nearest fraction of an hour (in equal increments that can range from one hundredth to one quarter of an hour, at the option of the owner or operator);
7.1.2.3 The hourly gross unit load (rounded to nearest MWe); and
7.1.2.4 If applicable, the F-factor used to calculate the heat input-based Hg emission rate.
7.1.2.5 If applicable, a flag to indicate that the hour is a startup or shutdown hour (as defined in Sec. 63.10042).
7.1.3 Hg Emissions Records (Hg CEMS). For each affected unit or common stack using a Hg CEMS, the owner or operator shall record the following information for each unit or stack operating hour:
7.1.3.1 The date and hour;
7.1.3.2 Monitoring system and component identification codes, as provided in the monitoring plan, if the CEMS provides a quality-assured value of Hg concentration for the hour;
7.1.3.3 The hourly Hg concentration, if a quality-assured value is obtained for the hour (g/scm, rounded to three significant figures);
7.1.3.4 A special code, indicating whether or not a quality-assured Hg concentration is obtained for the hour. This code may be entered manually when a temporary like-kind replacement Hg analyzer is used for reporting; and
7.1.3.5 Monitor data availability, as a percentage of unit or stack operating hours, calculated according to Sec. 75.32 of this chapter.
7.1.4 Hg Emissions Records (Sorbent Trap Monitoring Systems). For each affected unit or common stack using a sorbent trap monitoring system, each owner or operator shall record the following information for the unit or stack operating hour in each data collection period:
7.1.4.1 The date and hour;
7.1.4.2 Monitoring system and component identification codes, as provided in the monitoring plan, if the sorbent trap system provides a quality-assured value of Hg concentration for the hour;
7.1.4.3 The hourly Hg concentration, if a quality-assured value is obtained for the hour (g/scm, rounded to three significant figures). Note that when a quality-assured Hg concentration value is obtained for a particular data collection period, that single concentration value is applied to each operating hour of the data collection period.
7.1.4.4 A special code, indicating whether or not a quality-assured Hg concentration is obtained for the hour;
7.1.4.5 The average flow rate of stack gas through each sorbent trap (in appropriate units, e.g., liters/min, cc/min, dscm/min);
7.1.4.6 The gas flow meter reading (in dscm, rounded to the nearest hundredth), at the beginning and end of the collection period and at least once in each unit operating hour during the collection period;
7.1.4.7 The ratio of the stack gas flow rate to the sample flow rate, as described in section 12.2 of Performance Specification (PS) 12B in Appendix B to part 60 of this chapter; and
7.1.4.8 Monitor data availability, as a percentage of unit or stack operating hours, calculated according to Sec. 75.32 of this chapter.
7.1.5 Stack Gas Volumetric Flow Rate Records.
7.1.5.1 Hourly measurements of stack gas volumetric flow rate during unit operation are required for routine operation of sorbent trap monitoring systems, to maintain the required ratio of stack gas flow rate to sample flow rate (see section 8.2.2 of Performance Specification (PS) 12B in Appendix B to part 60 of this chapter). Hourly stack gas flow rate data are also needed in order to demonstrate compliance with electrical output-based Hg emissions limits, as provided in section 6.2.2 of this appendix.
7.1.5.2 For each affected unit or common stack, if hourly measurements of stack gas flow rate are needed for sorbent trap monitoring system operation or to convert Hg concentrations to the units of the emission standard, use a flow rate monitor that meets the requirements of part 75 of this chapter to record the required data. You must keep hourly flow rate records, as specified in Sec. 75.57(c)(2) of this chapter.
7.1.6 Records of Stack Gas Moisture Content.
7.1.6.1 Correction of hourly Hg concentration data for moisture is sometimes required when converting Hg concentrations to the units of the applicable Hg emissions limit. In particular, these corrections are required:
7.1.6.1.1 For sorbent trap monitoring systems;
7.1.6.1.2 For Hg CEMS that measure Hg concentration on a dry basis, when you must calculate electrical output-based Hg emission rates; and
7.1.6.1.3 When using certain equations from EPA Method 19 in appendix A-7 to part 60 of this chapter to calculate heat input-based Hg emission rates.
7.1.6.2 If hourly moisture corrections are required, either use a fuel-specific default moisture percentage from Sec. 75.11(b)(1) of this chapter or a certified moisture monitoring system that meets the requirements of part 75 of this chapter, to record the required data. If you use a moisture monitoring system, you must keep hourly records of the stack gas moisture content, as specified in Sec. 75.57(c)(3) of this chapter.
7.1.7 Records of Diluent Gas (CO2 or O2) Concentration.
7.1.7.1 When a heat input-based Hg mass emissions limit must be met, in units of lb/TBtu, hourly measurements of CO2 or O2 concentration are required to convert Hg concentrations to units of the standard.
7.1.7.2 If hourly measurements of diluent gas concentration are needed, use a certified CO2 or O2 monitor that meets the requirements of part 75 of this chapter to record the required data. You must keep hourly CO2 or O2 concentration records, as specified in Sec. 75.57(g) of this chapter.
7.1.8 Hg Emission Rate Records. For applicable Hg emission limits in units of lb/TBtu or lb/GWh, record the following information for each affected unit or common stack:
7.1.8.1 The date and hour;
7.1.8.2 The hourly Hg emissions rate (lb/TBtu or lb/GWh, as applicable, calculated according to section 6.2.1 or 6.2.2 of this appendix, rounded to three significant figures), if valid values of Hg concentration and all other required parameters (stack gas volumetric flow rate, diluent gas concentration, electrical load, and moisture data, as applicable) are obtained for the hour;
7.1.8.3 An identification code for the formula (either the selected equation from Method 19 in section 6.2.1 of this appendix or Equation A-4 in section 6.2.2 of this appendix) used to derive the hourly Hg emission rate from Hg concentration, flow rate, electrical load, diluent gas concentration, and moisture data (as applicable); and
7.1.8.4 A code indicating that the Hg emission rate was not calculated for the hour, if valid data for Hg concentration and/or any of the other necessary parameters are not obtained for the hour. For the purposes of this appendix, the substitute data values required under part 75 of this chapter for diluent gas concentration, stack gas flow rate and moisture content are not considered to be valid data.
7.1.8.5 If applicable, a code to indicate that the default electrical load (as defined in Sec. 63.10042) was used to calculate the Hg emission rate.
7.1.8.6 If applicable, a code to indicate that the diluent cap (as defined in Sec. 63.10042) was used to calculate the Hg emission rate.
7.1.9 Certification and Quality Assurance Test Records. For any Hg CEMS and sorbent trap monitoring systems used to provide data under this subpart, record the following certification and quality-assurance information:
7.1.9.1 The reference values, monitor responses, and calculated calibration error (CE) values, and a flag to indicate whether the test was done using elemental or oxidized Hg, for all required 7-day calibration error tests and daily calibration error tests of the Hg CEMS;
7.1.9.2 The reference values, monitor responses, and calculated linearity error (LE) or system integrity error (SIE) values for all linearity checks of the Hg CEMS, and for all single-level and 3-level system integrity checks of the Hg CEMS;
7.1.9.3 The CEMS and reference method readings for each test run and the calculated relative accuracy results for all RATAs of the Hg CEMS and/or sorbent trap monitoring systems;
7.1.9.4 The stable stack gas and calibration gas readings and the calculated results for the upscale and downscale stages of all required cycle time tests of the Hg CEMS or, for a batch sampling Hg CEMS, the interval between measured Hg concentration readings;
7.1.9.5 Supporting information for all required RATAs of the Hg monitoring systems, including records of the test dates, the raw reference method and monitoring system data, the results of sample analyses to substantiate the reported test results, and records of sampling equipment calibrations;
7.1.9.6 For sorbent trap monitoring systems, also keep records of the results of all analyses of the sorbent traps used for routine daily operation of the system, and information documenting the results of all leak checks and the other applicable quality control procedures described in Table 12B-1 of Performance Specification (PS) 12B in appendix B to part 60 of this chapter.
7.1.9.7 For stack gas flow rate, diluent gas, and (if applicable) moisture monitoring systems, you must keep records of all certification, recertification, diagnostic, and on-going quality-assurance tests of these systems, as specified in Sec. 75.59 of this chapter.
7.2 Reporting Requirements.
7.2.1 General Reporting Provisions. The owner or operator shall comply with the following requirements for reporting Hg emissions from each affected unit (or group of units monitored at a common stack) under this subpart:
7.2.1.1 Notifications, in accordance with paragraph 7.2.2 of this section;
7.2.1.2 Monitoring plan reporting, in accordance with paragraph 7.2.3 of this section;
7.2.1.3 Certification, recertification, and QA test submittals, in accordance with paragraph 7.2.4 of this section; and
7.2.1.4 Electronic quarterly report submittals, in accordance with paragraph 7.2.5 of this section.
7.2.2 Notifications. The owner or operator shall provide notifications for each affected unit (or group of units monitored at a common stack) under this subpart in accordance with Sec. 63.10030.
7.2.3 Monitoring Plan Reporting. For each affected unit (or group of units monitored at a common stack) under this subpart using Hg CEMS or sorbent trap monitoring system to measure Hg emissions, the owner or operator shall make electronic and hard copy monitoring plan submittals as follows:
7.2.3.1 Submit the electronic and hard copy information in section 7.1.1.2 of this appendix pertaining to the Hg monitoring systems at least 21 days prior to the applicable date in Sec. 63.9984. Also submit the monitoring plan information in Sec. 75.53.(g) pertaining to the flow rate, diluent gas, and moisture monitoring systems within that same time frame, if the required records are not already in place.
7.2.3.2 Whenever an update of the monitoring plan is required, as provided in paragraph 7.1.1.1 of this section. An electronic monitoring plan information update must be submitted either prior to or concurrent with the quarterly report for the calendar quarter in which the update is required.
7.2.3.3 All electronic monitoring plan submittals and updates shall be made to the Administrator using the ECMPS Client Tool. Hard copy portions of the monitoring plan shall be kept on record according to section 7.1 of this appendix.
7.2.4 Certification, Recertification, and Quality-Assurance Test Reporting. Except for daily QA tests of the required monitoring systems (i.e., calibration error tests and flow monitor interference checks), the results of all required certification, recertification, and quality-assurance tests described in paragraphs 7.1.9.1 through 7.1.9.7 of this section (except for test results previously submitted, e.g., under the ARP) shall be submitted electronically, using the ECMPS Client Tool, either prior to or concurrent with the relevant quarterly electronic emissions report.
7.2.5 Quarterly Reports.
7.2.5.1 Beginning with the report for the calendar quarter in which the initial compliance demonstration is completed or the calendar quarter containing the applicable date in Sec. 63.9984, the owner or operator of any affected unit shall use the ECMPS Client Tool to submit electronic quarterly reports to the Administrator, in an XML format specified by the Administrator, for each affected unit (or group of units monitored at a common stack) under this subpart.
7.2.5.2 The electronic reports must be submitted within 30 days following the end of each calendar quarter, except for units that have been placed in long-term cold storage.
7.2.5.3 Each electronic quarterly report shall include the following information:
7.2.5.3.1 The date of report generation;
7.2.5.3.2 Facility identification information;
7.2.5.3.3 The information in paragraphs 7.1.2 through 7.1.8 of this section, as applicable to the Hg emission measurement methodology (or methodologies) used and the units of the Hg emission standard(s); and
7.2.5.3.4 The results of all daily calibration error tests of the Hg CEMS, as described in paragraph 7.1.9.1 of this section and (if applicable) the results of all daily flow monitor interference checks.
7.2.5.4 Compliance Certification. Based on reasonable inquiry of those persons with primary responsibility for ensuring that all Hg emissions from the affected unit(s) under this subpart have been correctly and fully monitored, the owner or operator shall submit a compliance certification in support of each electronic quarterly emissions monitoring report. The compliance certification shall include a statement by a responsible official with that official's name, title, and signature, certifying that, to the best of his or her knowledge, the report is true, accurate, and complete. [77 FR 9464, Feb. 16, 2012, as amended at 77 FR 23408, Apr. 19, 2012; 78 FR 24093, Apr. 24, 2013; 79 FR 68795, Nov. 19, 2014]
Sec. Appendix B to Subpart UUUUU of Part 63---HCl and HF Monitoring
Provisions
1. Applicability
These monitoring provisions apply to the measurement of HCl and/or HF emissions from electric utility steam generating units, using CEMS. The CEMS must be capable of measuring HCl and/or HF in the appropriate units of the applicable emissions standard (e.g., lb/MMBtu, lb/MWh, or lb/GWh).
2. Monitoring of HCl and/or HF Emissions
2.1 Monitoring System Installation Requirements. Install HCl and/or HF CEMS and any additional monitoring systems needed to convert pollutant concentrations to units of the applicable emissions limit in accordance with Performance Specification 15 for extractive Fourier Transform Infrared Spectroscopy (FTIR) continuous emissions monitoring systems in appendix B to part 60 of this chapter and Sec. 63.10010(a).
2.2 Primary and Backup Monitoring Systems. The provisions pertaining to primary and redundant backup monitoring systems in section 2.2 of appendix A to this subpart apply to HCl and HF CEMS and any additional monitoring systems needed to convert pollutant concentrations to units of the applicable emissions limit.
2.3 FTIR Monitoring System Equipment, Supplies, Definitions, and General Operation. The provisions of Performance Specification 15 Sections 2.0, 3.0, 4.0, 5.0, 6.0, and 10.0 apply.
3. Initial Certification Procedures
The initial certification procedures for the HCl or HF CEMS used to provide data under this subpart are as follows:
3.1 The HCl and/or HF CEMS must be certified according to Performance Specification 15 using the procedures for gas auditing and comparison to a reference method (RM) as specified in sections 3.1.1 and 3.1.2 below. (Please Note: EPA plans to publish a technology neutral performance specification and appropriate on-going quality-assurance requirements for HCl CEMS in the near future along with amendments to this appendix to accommodate their use.)
3.1.1 You must conduct a gas audit of the HCl and/or HF CEMS as described in section 9.1 of Performance Specification 15, with the exceptions listed in sections 3.1.2.1 and 3.1.2.2 below.
3.1.1.1 The audit sample gas does not have to be obtained from the Administrator; however, it must be (1) from a secondary source of certified gases (i.e., independent of any calibration gas used for the daily calibration assessments) and (2) directly traceable to National Institute of Standards and Technology (NIST) or VSL Dutch Metrology Institute (VSL) reference materials through an unbroken chain of comparisons. If audit gas traceable to NIST or VSL reference materials is not available, you may use a gas with a concentration certified to a specified uncertainty by the gas manufacturer.
3.1.1.2 Analyze the results of the gas audit using the calculations in section 12.1 of Performance Specification 15. The calculated correction factor (CF) from Eq. 6 of Performance Specification 15 must be between 0.85 and 1.15. You do not have to test the bias for statistical significance.
3.1.2 You must perform a relative accuracy test audit or RATA according to section 11.1.1.4 of Performance Specification 15 and the requirements below. Perform the RATA of the HCl or HF CEMS at normal load. Acceptable HCl/HF reference methods (RM) are Methods 26 and 26A in appendix A-8 to part 60 of this chapter, Method 320 in Appendix A to this part, or ASTM D6348-03 (Reapproved 2010) ``Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy'' (incorporated by reference, see Sec. 63.14), each applied based on the criteria set forth in Table 5 of this subpart.
3.1.2.1 When ASTM D6348-03 is used as the RM, the following conditions must be met:
3.1.2.1.1 The test plan preparation and implementation in the Annexes to ASTM D6348-03, Sections A1 through A8 are mandatory;
3.1.2.1.2 In ASTM D6348-03 Annex A5 (Analyte Spiking Technique), the percent (%) R must be determined for each target analyte (see Equation A5.5);
3.1.2.1.3 For the ASTM D6348-03 test data to be acceptable for a target analyte, %R must be 70% 4R 4130%; and
3.1.2.1.4 The %R value for each compound must be reported in the test report and all field measurements corrected with the calculated %R value for that compound using the following equation: [GRAPHIC] [TIFF OMITTED] TR16FE12.018
3.1.2.2 The relative accuracy (RA) of the HCl or HF CEMS must be no greater than 20 percent of the mean value of the RM test data in units of ppm on the same moisture basis. Alternatively, if the mean RM value is less than 1.0 ppm, the RA results are acceptable if the absolute value of the difference between the mean RM and CEMS values does not exceed 0.20 ppm.
3.2 Any additional stack gas flow rate, diluent gas, and moisture monitoring system(s) needed to express pollutant concentrations in units of the applicable emissions limit must be certified according to part 75 of this chapter.
4. Recertification Procedures
Whenever the owner or operator makes a replacement, modification, or change to a certified CEMS that may significantly affect the ability of the system to accurately measure or record pollutant or diluent gas concentrations, stack gas flow rates, or stack gas moisture content, the owner or operator shall recertify the monitoring system. Furthermore, whenever the owner or operator makes a replacement, modification, or change to the flue gas handling system or the unit operation that may significantly change the concentration or flow profile, the owner or operator shall recertify the monitoring system. The same tests performed for the initial certification of the monitoring system shall be repeated for recertification, unless otherwise specified by the Administrator. Examples of changes that require recertification include: Replacement of a gas analyzer; complete monitoring system replacement, and changing the location or orientation of the sampling probe.
5. On-Going Quality Assurance Requirements
5.1 For on-going QA test requirements for HCl and HF CEMS, implement the quality assurance/quality control procedures of Performance Specification 15 of appendix B to part 60 of this chapter as set forth in sections 5.1.1 through 5.1.3 and 5.3.2 of this appendix.
5.1.1 On a daily basis, you must assess the calibration error of the HCl or HF CEMS using either a calibration transfer standard as specified in Performance Specification 15 Section 10.1 which references Section 4.5 of the FTIR Protocol or a HCl and/or HF calibration gas at a concentration no greater than two times the level corresponding to the applicable emission limit. A calibration transfer standard is a substitute calibration compound chosen to ensure that the FTIR is performing well at the wavelength regions used for analysis of the target analytes. The measured concentration of the calibration transfer standard or HCl and/or HF calibration gas results must agree within [5 percent of the reference gas value after correction for differences in pressure.
5.1.2 On a quarterly basis, you must conduct a gas audit of the HCl and/or HF CEMS as described in section 3.1.1 of this appendix. For the purposes of this appendix, ``quarterly'' means once every ``QA operating quarter'' (as defined in section 3.1.20 of appendix A to this subpart). You have the option to use HCl gas in lieu of HF gas for conducting this audit on an HF CEMS. To the extent practicable, perform consecutive quarterly gas audits at least 30 days apart. The initial quarterly audit is due in the first QA operating quarter following the calendar quarter in which certification testing of the CEMS is successfully completed. Up to three consecutive exemptions from the quarterly audit requirement are allowed for ``non-QA operating quarters'' (i.e., calendar quarters in which there are less than 168 unit or stack operating hours). However, no more than four consecutive calendar quarters may elapse without performing a gas audit, except as otherwise provided in section 5.3.3.2.1 of this appendix.
5.1.3 You must perform an annual relative accuracy test audit or RATA of the HCl or HF CEMS as described in section 3.1.2 of this appendix. Perform the RATA at normal load. For the purposes of this appendix, ``annual'' means once every four ``QA operating quarters'' (as defined in section 3.1.20 of appendix A to this subpart). The first annual RATA is due within four QA operating quarters following the calendar quarter in which the initial certification testing of the HCl or HF CEMS is successfully completed. The provisions in section 5.1.2.4 of appendix A to this subpart pertaining to RATA deadline extensions also apply.
5.2 Stack gas flow rate, diluent gas, and moisture monitoring systems must meet the applicable on-going QA test requirements of part 75 of this chapter.
5.3 Data Validation.
5.3.1 Out-of-Control Periods. A HCl or HF CEMS that is used to provide data under this appendix is considered to be out-of-control, and data from the CEMS may not be reported as quality-assured, when any acceptance criteria for a required QA test is not met. The HCl or HF CEMS is also considered to be out-of-control when a required QA test is not performed on schedule or within an allotted grace period. To end an out-of-control period, the QA test that was either failed or not done on time must be performed and passed. Out-of-control periods are counted as hours of monitoring system downtime.
5.3.2 Grace Periods. For the purposes of this appendix, a ``grace period'' is defined as a specified number of unit or stack operating hours after the deadline for a required quality-assurance test of a continuous monitor has passed, in which the test may be performed and passed without loss of data.
5.3.2.1 For the flow rate, diluent gas, and moisture monitoring systems described in section 5.2 of this appendix, a 168 unit or stack operating hour grace period is available for quarterly linearity checks, and a 720 unit or stack operating hour grace period is available for RATAs, as provided, respectively, in sections 2.2.4 and 2.3.3 of appendix B to part 75 of this chapter.
5.3.2.2 For the purposes of this appendix, if the deadline for a required gas audit or RATA of a HCl or HF CEMS cannot be met due to circumstances beyond the control of the owner or operator:
5.3.2.2.1 A 168 unit or stack operating hour grace period is available in which to perform the gas audit; or
5.3.2.2.2 A 720 unit or stack operating hour grace period is available in which to perform the RATA.
5.3.2.3 If a required QA test is performed during a grace period, the deadline for the next test shall be determined as follows:
5.3.2.3.1 For a gas audit or RATA of the monitoring systems described in section 5.1 of this appendix, determine the deadline for the next gas audit or RATA (as applicable) in accordance with section 2.2.4(b) or 2.3.3(d) of appendix B to part 75 of this chapter; treat a gas audit in the same manner as a linearity check.
5.3.2.3.2 For the gas audit of a HCl or HF CEMS, the grace period test only satisfies the audit requirement for the calendar quarter in which the test was originally due. If the calendar quarter in which the grace period audit is performed is a QA operating quarter, an additional gas audit is required for that quarter.
5.3.2.3.3 For the RATA of a HCl or HF CEMS, the next RATA is due within three QA operating quarters after the calendar quarter in which the grace period test is performed.
5.3.3 Conditional Data Validation For recertification and diagnostic testing of the monitoring systems that are used to provide data under this appendix, and for the required QA tests when non-redundant backup monitoring systems or temporary like-kind replacement analyzers are brought into service, the conditional data validation provisions in Secs. 75.20(b)(3)(ii) through (b)(3)(ix) of this chapter may be used to avoid or minimize data loss. The allotted window of time to complete calibration tests and RATAs shall be as specified in Sec. 75.20(b)(3)(iv) of this chapter; the allotted window of time to complete a gas audit shall be the same as for a linearity check (i.e., 168 unit or stack operating hours).
6. Missing Data Requirements
For the purposes of this appendix, the owner or operator of an affected unit shall not substitute for missing data from HCl or HF CEMS. Any process operating hour for which quality-assured HCl or HF concentration data are not obtained is counted as an hour of monitoring system downtime.
7. Bias Adjustment
Bias adjustment of hourly emissions data from a HCl or HF CEMS is not required.
8. QA/QC Program Requirements
The owner or operator shall develop and implement a quality assurance/quality control (QA/QC) program for the HCl and/or HF CEMS that are used to provide data under this subpart. At a minimum, the program shall include a written plan that describes in detail (or that refers to separate documents containing) complete, step-by-step procedures and operations for the most important QA/QC activities. Electronic storage of the QA/QC plan is permissible, provided that the information can be made available in hard copy to auditors and inspectors. The QA/QC program requirements for the other monitoring systems described in section 5.2 of this appendix are specified in section 1 of appendix B to part 75 of this chapter.
8.1 General Requirements for HCl and HF CEMS.
8.1.1 Preventive Maintenance. Keep a written record of procedures needed to maintain the HCl and/or HF CEMS in proper operating condition and a schedule for those procedures. This shall, at a minimum, include procedures specified by the manufacturers of the equipment and, if applicable, additional or alternate procedures developed for the equipment.
8.1.2 Recordkeeping and Reporting. Keep a written record describing procedures that will be used to implement the recordkeeping and reporting requirements of this appendix.
8.1.3 Maintenance Records. Keep a record of all testing, maintenance, or repair activities performed on any HCl or HF CEMS in a location and format suitable for inspection. A maintenance log may be used for this purpose. The following records should be maintained: Date, time, and description of any testing, adjustment, repair, replacement, or preventive maintenance action performed on any monitoring system and records of any corrective actions associated with a monitor outage period. Additionally, any adjustment that may significantly affect a system's ability to accurately measure emissions data must be recorded and a written explanation of the procedures used to make the adjustment(s) shall be kept.
8.2 Specific Requirements for HCl and HF CEMS. The following requirements are specific to HCl and HF CEMS:
8.2.1 Keep a written record of the procedures used for each type of QA test required for each HCl and HF CEMS. Explain how the results of each type of QA test are calculated and evaluated.
8.2.2 Explain how each component of the HCl and/or HF CEMS will be adjusted to provide correct responses to calibration gases after routine maintenance, repairs, or corrective actions.
9. Data Reduction and Calculations
9.1 Design and operate the HCl and/or HF CEMS to complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15-minute period.
9.2 Reduce the HCl and/or HF concentration data to hourly averages in accordance with Sec. 60.13(h)(2) of this chapter.
9.3 Convert each hourly average HCl or HF concentration to an HCl or HF emission rate expressed in units of the applicable emissions limit.
9.3.1 For heat input-based emission rates, select an appropriate emission rate equation from among Equations 19-1 through 19-9 in EPA Method 19 in Appendix A-7 to part 60 of this chapter, to calculate the HCl or HF emission rate in lb/MMBtu. Multiply the HCl concentration value (ppm) by 9.43 x 10-8 to convert it to lb/scf, for use in the applicable Method 19 equation. For HF, the conversion constant from ppm to lb/scf is 5.18 x 10-8. The appropriate diluent cap value from section 6.2.1.2 of Appendix A to this subpart may be used to calculate the HCl or HF emission rate (lb/MMBtu) during startup or shutdown hours.
9.3.2 For electrical output-based emission rates, first calculate the HCl or HF mass emission rate (lb/h), using an equation that has the general form of Equation A-2 or A-3 in appendix A to this subpart (as applicable), replacing the value of K with 9.43 x 10-8 lb/scf-ppm (for HCl) or 5.18 x 10-8 (for HF) and defining Ch as the hourly average HCl or HF concentration in ppm. Then, use Equation A-4 in appendix A to this subpart to calculate the HCl or HF emission rate in lb/GWh. If the applicable HCl or HF limit is expressed in lb/MWh, divide the result from Equation A-4 by 10\3\.
9.4 Use Equation A-5 in appendix A of this subpart to calculate the required 30 operating day rolling average HCl or HF emission rates. Round off each 30 operating day average to two significant figures. The term Eho in Equation A-5 must be in the units of the applicable emissions limit.
10. Recordkeeping Requirements
10.1 For each HCl or HF CEMS installed at an affected source, and for any other monitoring system(s) needed to convert pollutant concentrations to units of the applicable emissions limit, the owner or operator must maintain a file of all measurements, data, reports, and other information required by this appendix in a form suitable for inspection, for 5 years from the date of each record, in accordance with Sec. 63.10033. The file shall contain the information in paragraphs 10.1.1 through 10.1.8 of this section.
10.1.1 Monitoring Plan Records. For each affected unit or group of units monitored at a common stack, the owner or operator shall prepare and maintain a monitoring plan for the HCl and/or HF CEMS and any other monitoring system(s) (i.e, flow rate, diluent gas, or moisture systems) needed to convert pollutant concentrations to units of the applicable emission standard. The monitoring plan shall contain essential information on the continuous monitoring systems and shall explain how the data derived from these systems ensure that all HCl or HF emissions from the unit or stack are monitored and reported.
10.1.1.1 Updates. Whenever the owner or operator makes a replacement, modification, or change in a certified continuous HCl or HF monitoring system that is used to provide data under this subpart (including a change in the automated data acquisition and handling system or the flue gas handling system) which affects information reported in the monitoring plan (e.g., a change to a serial number for a component of a monitoring system), the owner or operator shall update the monitoring plan.
10.1.1.2 Contents of the Monitoring Plan. For HCl and/or HF CEMS, the monitoring plan shall contain the applicable electronic and hard copy information in sections 10.1.1.2.1 and 10.1.1.2.2 of this appendix. For stack gas flow rate, diluent gas, and moisture monitoring systems, the monitoring plan shall include the electronic and hard copy information required for those systems under Sec. 75.53 (g) of this chapter. The electronic monitoring plan shall be evaluated using the ECMPS Client Tool.
10.1.1.2.1 Electronic. Record the unit or stack ID number(s); monitoring location(s); the HCl or HF monitoring methodology used (i.e., CEMS); HCl or HF monitoring system information, including, but not limited to: unique system and component ID numbers; the make, model, and serial number of the monitoring equipment; the sample acquisition method; formulas used to calculate emissions; monitor span and range information (if applicable).
10.1.1.2.2 Hard Copy. Keep records of the following: schematics and/or blueprints showing the location of the monitoring system(s) and test ports; data flow diagrams; test protocols; monitor span and range calculations (if applicable); miscellaneous technical justifications.
10.1.2 Operating Parameter Records. For the purposes of this appendix, the owner or operator shall record the following information for each operating hour of each affected unit or group of units utilizing a common stack, to the extent that these data are needed to convert pollutant concentration data to the units of the emission standard. For non-operating hours, record only the items in paragraphs 10.1.2.1 and 10.1.2.2 of this section. If there is heat input to the unit(s), but no electrical load, record only the items in paragraphs 10.1.2.1, 10.1.2.2, and (if applicable) 10.1.2.4 of this section.
10.1.2.1 The date and hour;
10.1.2.2 The unit or stack operating time (rounded up to the nearest fraction of an hour (in equal increments that can range from one hundredth to one quarter of an hour, at the option of the owner or operator);
10.1.2.3 The hourly gross unit load (rounded to nearest MWge); and
10.1.2.4 If applicable, the F-factor used to calculate the heat input-based pollutant emission rate.
10.1.2.5 If applicable, a flag to indicate that the hour is a startup or shutdown hour (as defined in Sec. 63.10042).
10.1.3 HCl and/or HF Emissions Records. For HCl and/or HF CEMS, the owner or operator must record the following information for each unit or stack operating hour:
10.1.3.1 The date and hour;
10.1.3.2 Monitoring system and component identification codes, as provided in the electronic monitoring plan, for each hour in which the CEMS provides a quality-assured value of HCl or HF concentration (as applicable);
10.1.3.3 The pollutant concentration, for each hour in which a quality-assured value is obtained. For HCl and HF, record the data in parts per million (ppm), rounded to three significant figures.
10.1.3.4 A special code, indicating whether or not a quality-assured HCl or HF concentration value is obtained for the hour. This code may be entered manually when a temporary like-kind replacement HCl or HF analyzer is used for reporting; and
10.1.3.5 Monitor data availability, as a percentage of unit or stack operating hours, calculated according to Sec. 75.32 of this chapter.
10.1.4 Stack Gas Volumetric Flow Rate Records.
10.1.4.1 Hourly measurements of stack gas volumetric flow rate during unit operation are required to demonstrate compliance with electrical output-based HCl or HF emissions limits (i.e., lb/MWh or lb/GWh).
10.1.4.2 Use a flow rate monitor that meets the requirements of part 75 of this chapter to record the required data. You must keep hourly flow rate records, as specified in Sec. 75.57(c)(2) of this chapter.
10.1.5 Records of Stack Gas Moisture Content.
10.1.5.1 Correction of hourly pollutant concentration data for moisture is sometimes required when converting concentrations to the units of the applicable Hg emissions limit. In particular, these corrections are required:
10.1.5.1.1 To calculate electrical output-based pollutant emission rates, when using a CEMS that measures pollutant concentrations on a dry basis; and
10.1.5.1.2 To calculate heat input-based pollutant emission rates, when using certain equations from EPA Method 19 in appendix A-7 to part 60 of this chapter.
10.1.5.2 If hourly moisture corrections are required, either use a fuel-specific default moisture percentage for coal-fired units from Sec. 75.11(b)(1) of this chapter, an Administrator approved default moisture value for non-coal-fired units (as per paragraph 63.10010(d) of this subpart), or a certified moisture monitoring system that meets the requirements of part 75 of this chapter, to record the required data. If you elect to use a moisture monitoring system, you must keep hourly records of the stack gas moisture content, as specified in Sec. 75.57(c)(3) of this chapter.
10.1.6 Records of Diluent Gas (CO2 or O2) Concentration.
10.1.6.1 To assess compliance with a heat input-based HCl or HF emission rate limit in units of lb/MMBtu, hourly measurements of CO2 or O2 concentration are required to convert pollutant concentrations to units of the standard.
10.1.6.2 If hourly measurements of diluent gas concentration are needed, you must use a certified CO2 or O2 monitor that meets the requirements of part 75 of this chapter to record the required data. For all diluent gas monitors, you must keep hourly CO2 or O2 concentration records, as specified in Sec. 75.57(g) of this chapter.
10.1.7 HCl and HF Emission Rate Records. For applicable HCl and HF emission limits in units of lb/MMBtu, lb/MWh, or lb/GWh, record the following information for each affected unit or common stack:
10.1.7.1 The date and hour;
10.1.7.2 The hourly HCl and/or HF emissions rate (lb/MMBtu, lb/MWh, or lb/GWh, as applicable, rounded to three significant figures), for each hour in which valid values of HCl or HF concentration and all other required parameters (stack gas volumetric flow rate, diluent gas concentration, electrical load, and moisture data, as applicable) are obtained for the hour;
10.1.7.3 An identification code for the formula used to derive the hourly HCl or HF emission rate from HCl or HF concentration, flow rate, electrical load, diluent gas concentration, and moisture data (as applicable); and
10.1.7.4 A code indicating that the HCl or HF emission rate was not calculated for the hour, if valid data for HCl or HF concentration and/or any of the other necessary parameters are not obtained for the hour. For the purposes of this appendix, the substitute data values required under part 75 of this chapter for diluent gas concentration, stack gas flow rate and moisture content are not considered to be valid data.
10.1.7.5 If applicable, a code to indicate that the default electrical load (as defined in Sec. 63.10042) was used to calculate the HCl or HF emission rate.
10.1.7.6 If applicable, a code to indicate that the diluent cap (as defined in Sec. 63.10042) was used to calculate the HCl or HF emission rate.
10.1.8 Certification and Quality Assurance Test Records. For the HCl and/or HF CEMS used to provide data under this subpart at each affected unit (or group of units monitored at a common stack), record the following information for all required certification, recertification, diagnostic, and quality-assurance tests:
10.1.8.1 HCl and HF CEMS.
10.1.8.1.1 For all required daily calibrations (including calibration transfer standard tests) of the HCl or HF CEMS, record the test dates and times, reference values, monitor responses, and calculated calibration error values;
10.1.8.1.2 For gas audits of HCl or HF CEMS, record the date and time of each spiked and unspiked sample, the audit gas reference values and uncertainties. Keep records of all calculations and data analyses required under sections 9.1 and 12.1 of Performance Specification 15, and the results of those calculations and analyses.
10.1.8.1.3 For each RATA of a HCl or HF CEMS, record the date and time of each test run, the reference method(s) used, and the reference method and HCl or HF CEMS values. Keep records of the data analyses and calculations used to determine the relative accuracy.
10.1.8.2 Additional Monitoring Systems. For the stack gas flow rate, diluent gas, and moisture monitoring systems described in section 3.2 of this appendix, you must keep records of all certification, recertification, diagnostic, and on-going quality-assurance tests of these systems, as specified in Sec. 75.59(a) of this chapter.
11. Reporting Requirements
11.1 General Reporting Provisions. The owner or operator shall comply with the following requirements for reporting HCl and/or HF emissions from each affected unit (or group of units monitored at a common stack):
11.1.1 Notifications, in accordance with paragraph 11.2 of this section;
11.1.2 Monitoring plan reporting, in accordance with paragraph 11.3 of this section;
11.1.3 Certification, recertification, and QA test submittals, in accordance with paragraph 11.4 of this section; and
11.1.4 Electronic quarterly report submittals, in accordance with paragraph 11.5 of this section.
11.2 Notifications. The owner or operator shall provide notifications for each affected unit (or group of units monitored at a common stack) in accordance with Sec. 63.10030.
11.3 Monitoring Plan Reporting. For each affected unit (or group of units monitored at a common stack) using HCl and/or HF CEMS, the owner or operator shall make electronic and hard copy monitoring plan submittals as follows:
11.3.1 Submit the electronic and hard copy information in section 10.1.1.2 of this appendix pertaining to the HCl and/or HF monitoring systems at least 21 days prior to the applicable date in Sec. 63.9984. Also, if applicable, submit monitoring plan information pertaining to any required flow rate, diluent gas, and/or moisture monitoring systems within that same time frame, if the required records are not already in place.
11.3.2 Update the monitoring plan when required, as provided in paragraph 10.1.1.1 of this appendix. An electronic monitoring plan information update must be submitted either prior to or concurrent with the quarterly report for the calendar quarter in which the update is required.
11.3.3 All electronic monitoring plan submittals and updates shall be made to the Administrator using the ECMPS Client Tool. Hard copy portions of the monitoring plan shall be kept on record according to section 10.1 of this appendix.
11.4 Certification, Recertification, and Quality-Assurance Test Reporting Requirements. Except for daily QA tests (i.e., calibrations and flow monitor interference checks), which are included in each electronic quarterly emissions report, use the ECMPS Client Tool to submit the results of all required certification, recertification, quality-assurance, and diagnostic tests of the monitoring systems required under this appendix electronically, either prior to or concurrent with the relevant quarterly electronic emissions report.
11.4.1 For daily calibrations (including calibration transfer standard tests), report the information in Sec. 75.59(a)(1) of this chapter, excluding paragraphs (a)(1)(ix) through (a)(1)(xi).
11.4.2 For each quarterly gas audit of a HCl or HF CEMS, report:
11.4.2.1 Facility ID information;
11.4.2.2 Monitoring system ID number;
11.4.2.3 Type of test (e.g., quarterly gas audit);
11.4.2.4 Reason for test;
11.4.2.5 Certified audit (spike) gas concentration value (ppm);
11.4.2.6 Measured value of audit (spike) gas, including date and time of injection;
11.4.2.7 Calculated dilution ratio for audit (spike) gas;
11.4.2.8 Date and time of each spiked flue gas sample;
11.4.2.9 Date and time of each unspiked flue gas sample;
11.4.2.10 The measured values for each spiked gas and unspiked flue gas sample (ppm);
11.4.2.11 The mean values of the spiked and unspiked sample concentrations and the expected value of the spiked concentration as specified in section 12.1 of Performance Specification 15 (ppm);
11.4.2.12 Bias at the spike level as calculated using equation 3 in section 12.1 of Performance Specification 15; and
11.4.2.13 The correction factor (CF), calculated using equation 6 in section 12.1 of Performance Specification 15.
11.4.3 For each RATA of a HCl or HF CEMS, report:
11.4.3.1 Facility ID information;
11.4.3.2 Monitoring system ID number;
11.4.3.3 Type of test (i.e., initial or annual RATA);
11.4.3.4 Reason for test;
11.4.3.5 The reference method used;
11.4.3.6 Starting and ending date and time for each test run;
11.4.3.7 Units of measure;
11.4.3.8 The measured reference method and CEMS values for each test run, on a consistent moisture basis, in appropriate units of measure;
11.4.3.9 Flags to indicate which test runs were used in the calculations;
11.4.3.10 Arithmetic mean of the CEMS values, of the reference method values, and of their differences;
11.4.3.11 Standard deviation, as specified in Equation 2-4 of Performance Specification 2 in appendix B to part 60 of this chapter;
11.4.3.12 Confidence coefficient, as specified in Equation 2-5 of Performance Specification 2 in appendix B to part 60 of this chapter; and
11.4.3.13 Relative accuracy calculated using Equation 2-6 of Performance Specification 2 in appendix B to part 60 of this chapter or, if applicable, according to the alternative procedure for low emitters described in section 3.1.2.2 of this appendix. If applicable use a flag to indicate that the alternative RA specification for low emitters has been applied.
11.4.4 Reporting Requirements for Diluent Gas, Flow Rate, and Moisture Monitoring Systems. For the certification, recertification, diagnostic, and QA tests of stack gas flow rate, moisture, and diluent gas monitoring systems that are certified and quality-assured according to part 75 of this chapter, report the information in section 10.1.9.3 of this appendix.
11.5 Quarterly Reports.
11.5.1 Beginning with the report for the calendar quarter in which the initial compliance demonstration is completed or the calendar quarter containing the applicable date in Sec. 63.10005(g), (h), or (j) (whichever is earlier), the owner or operator of any affected unit shall use the ECMPS Client Tool to submit electronic quarterly reports to the Administrator, in an XML format specified by the Administrator, for each affected unit (or group of units monitored at a common stack).
11.5.2 The electronic reports must be submitted within 30 days following the end of each calendar quarter, except for units that have been placed in long-term cold storage.
11.5.3 Each electronic quarterly report shall include the following information:
11.5.3.1 The date of report generation;
11.5.3.2 Facility identification information;
11.5.3.3 The information in sections 10.1.2 through 10.1.7 of this appendix, as applicable to the type(s) of monitoring system(s) used to measure the pollutant concentrations and other necessary parameters.
11.5.3.4 The results of all daily calibrations (including calibration transfer standard tests) of the HCl or HF monitor as described in section 10.1.8.1.1 of this appendix; and
11.5.3.5 If applicable, the results of all daily flow monitor interference checks, in accordance with section 10.1.8.2 of this appendix.
11.5.4 Compliance Certification. Based on reasonable inquiry of those persons with primary responsibility for ensuring that all HCl and/or HF emissions from the affected unit(s) have been correctly and fully monitored, the owner or operator shall submit a compliance certification in support of each electronic quarterly emissions monitoring report. The compliance certification shall include a statement by a responsible official with that official's name, title, and signature, certifying that, to the best of his or her knowledge, the report is true, accurate, and complete. [77 FR 9464, Feb. 16, 2012, as amended at 78 FR 24094, Apr. 24, 2013; 79 FR 68795, Nov. 19, 2014] Subpart VVVVV [Reserved]
Subpart WWWWW_National Emission Standards for Hospital Ethylene Oxide
Sterilizers
Source: 72 FR 73623, Dec. 28, 2007, unless otherwise noted.
Applicability and Compliance Dates