Mercury Rules For Coal-Fired Power Plants
Utility Mercury Rule
General Provisions
340-228-0600
Purpose
This rule establishes the mandatory reduction levels and monitoring provisions for the Utility Mercury Rule, as a means of reducing mercury (Hg) emissions in Oregon. Stat. Auth.: ORS 468.020 & 468A.310
Stats. Implemented: ORS 468A.025
Hist.: DEQ 13-2006, f. & cert. ef. 12-22-06
340-228-0601
Applicability
(1) Except as provided in section (2) of this rule:
(a) The following units in the State shall be coal-fired electric generating units subject to the requirements of OAR 340-228-0600 through 0678: Any stationary, coal-fired boiler or stationary, coal-fired combustion turbine serving at any time, since the later of November 15, 1990 or the start-up of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe producing electricity for sale.
(b) If a stationary boiler or stationary combustion turbine that, under subsection (1)(a) of this rule, is not a coal-fired electric generating unit begins to combust coal or coal-derived fuel or to serve a generator with nameplate capacity of more than 25 MWe producing electricity for sale, the unit shall become a coal-fired electric generating unit as provided in subsection (1)(a) of this rule on the first date on which it both combusts coal or coal-derived fuel and serves such generator.
(2) The units in the State that meet the requirements set forth in paragraph (2)(a)(A) or subsection (2)(b) of this rule are not coal-fired electric generating units:
(a)(A) Any unit that is a coal-fired electric generating unit under subsection (1)(a) or (b) of this rule:
(i) Qualifying as a cogeneration unit during the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a cogeneration unit; and
(ii) Not serving at any time, since the later of November 15, 1990 or the start-up of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe supplying in any calendar year more than one-third of the unit's potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.
(B) If a unit qualifies as a cogeneration unit during the 12-month period starting on the date the unit first produces electricity and meets the requirements of paragraph (2)(a)(A) of this rule for at least one calendar year, but subsequently no longer meets all such requirements, the unit shall become a coal-fired electric generating unit starting on the earlier of January 1 after the first calendar year during which the unit first no longer qualifies as a cogeneration unit or January 1 after the first calendar year during which the unit no longer meets the requirements of subparagraph (2)(a)(A)(ii) of this rule.
(b) Any unit that is a coal-fired electric generating unit under subsection (1)(a) or (b) of this rule, is a solid waste incineration unit combusting municipal waste, and is subject to the requirements of:
(A) A State Plan approved by the Administrator of the EPA in accordance with 40 CFR part 60 subpart Cb (emissions guidelines and compliance times for certain large municipal waste combustors);
(B) 40 CFR part 60 subpart Eb (standards of performance for certain large municipal waste combustors);
(C) 40 CFR part 60 subpart AAAA (standards of performance for certain small municipal waste combustors);
(D) A State Plan approved by the Administrator of the EPA in accordance with 40 CFR part 60 subpart BBBB (emission guidelines and compliance times for certain small municipal waste combustion units);
(E) 40 CFR part 62 subpart FFF (Federal Plan requirements for certain large municipal waste combustors); or
(F) 40 CFR part 62 subpart JJJ (Federal Plan requirements for certain small municipal waste combustion units).
340-228-0602
Definitions
(1) "Acid rain emissions limitation" means a limitation on emissions of sulfur dioxide or nitrogen oxides under the Acid Rain Program.
(2) "Acid Rain Program" means a multi-state sulfur dioxide and nitrogen oxides air pollution control and emission reduction program established by the Administrator under title IV of the CAA and 40 CFR parts 72 through 78.
(3) "Automated data acquisition and handling system or DAHS" means that component of the continuous emission monitoring system (CEMS), or other emissions monitoring system approved for use under OAR 340-228-0658 though 0670, designed to interpret and convert individual output signals from pollutant concentration monitors, flow monitors, diluent gas monitors, and other component parts of the monitoring system to produce a continuous record of the measured parameters in the measurement units required OAR 340-228-0658 through 0670.
(4) (4) "Biomass" means:
(a) Any organic material grown for the purpose of being converted to energy;
(b) Any organic byproduct of agriculture that can be converted into energy; or
(c) Any material that can be converted into energy and is nonmerchantable for other purposes, that is segregated from other nonmerchantable material, and that is;
(A) A forest-related organic resource, including mill residues, precommercial thinnings, slash, brush, or byproduct from conversion of trees to merchantable material; or
(B) A wood material, including pallets, crates, dunnage, manufacturing and construction materials (other than pressure-treated, chemically-treated, or painted wood products), and landscape or right-of-way tree trimmings.
(5) "Boiler" means an enclosed fossil-or other fuel-fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other medium.
(6) "Bottoming-cycle cogeneration unit" means a cogeneration unit in which the energy input to the unit is first used to produce useful thermal energy and at least some of the reject heat from the useful thermal energy application or process is then used for electricity production.
(7) "Coal" means any solid fuel classified as anthracite, bituminous, subbituminous, or lignite by the American Society of Testing and Materials (ASTM) Standard Specification for Classification of Coals by Rank D388-77, 90, 91, 95, 98a, or 99 (Reapproved 2004) & epsiv; (incorporated by reference, see 40 CFR 60.17).
(8) "Coal-derived fuel" means any fuel (whether in a solid, liquid, or gaseous state) produced by the mechanical, thermal, or chemical processing of coal.
(9) "Coal-fired" means combusting any amount of coal or coal-derived fuel, alone or in combination with any amount of any other fuel, during any year.
(10) "Cogeneration unit" means a stationary, coal-fired boiler or stationary, coal-fired combustion turbine:
(a) Having equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy; and
(b) 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:
(A) For a topping-cycle cogeneration unit,
(i) Useful thermal energy not less than 5 percent of total energy output; and
(ii) Useful power that, when added to one-half of useful thermal energy produced, is not less then 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.
(B) For a bottoming-cycle cogeneration unit, useful power not less than 45 percent of total energy input.
(c) Provided that the total energy input under paragraphs (b)(A)(ii) and (b)(B) of this definition equals the unit's total energy input from all fuel except biomass if the unit is a boiler.
(11) "Combustion turbine" means:
(a) An enclosed device comprising a compressor, a combustor, and a turbine and in which the flue gas resulting from the combustion of fuel in the combustor passes through the turbine, rotating the turbine; and
(b) If the enclosed device under paragraph (a) of this definition is combined cycle, any associated heat recovery steam generator and steam turbine.
(12) "Commence commercial operation" means, with regard to a unit serving a generator:
(a) To have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation.
(A) For a unit that is a coal-fired electric generating unit under OAR 340-228-0601 on the date the unit commences commercial operation as defined in paragraph (a) of this definition and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source), such date shall remain the unit's date of commencement of commercial operation.
(B) For a unit that is a coal-fired electric generating unit under OAR 340-228-0601 on the date the unit commences commercial operation as defined in paragraph (a) of this definition and that is subsequently replaced by a unit at the same source (e.g., repowered), the replacement unit shall be treated as a separate unit with a separate date for commencement of commercial operation as defined in paragraph (a) or (b) of this definition as appropriate.
(b) Notwithstanding paragraph (a) of this definition, for a unit that is not a coal-fired electric generating unit under OAR 340-228-0601 on the date the unit commences commercial operation as defined in paragraph (a) of this definition, the unit's date for commencement of commercial operation shall be the date on which the unit becomes a coal-fired electric generating unit under OAR 340-228-0601.
(A) For a unit with a date for commencement of commercial operation as defined in paragraph (b) of this definition and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source), such date remains the unit's date of commencement of commercial operation.
(B) For a unit with a date for commencement of commercial operation as defined in paragraph (b) of this definition and that is subsequently replaced by a unit at the same source (e.g., repowered), the replacement unit shall be treated as a separate unit with a separate date for commencement of commercial operation as defined in paragraph (a) or (b) of this definition as appropriate.
(13) "Commence operation" means:
(a) To have begun any mechanical, chemical, or electronic process, including, with regard to a unit, start-up of a unit's combustion chamber.
(A) For a unit that is a coal-fired electric generating unit under OAR 340-228-0601 on the date the unit commences operation as defined in paragraph (a) of this definition and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source), such date shall remain the unit's date of commencement of operation.
(B) For a unit that is a coal-fired electric generating unit under OAR 340-228-0601 on the date the unit commences operation as defined in paragraph (a) of this definition and that is subsequently replaced by a unit at the same source (e.g., repowered), the replacement unit shall be treated as a separate unit with a separate date for commencement of operation as defined in paragraph (a) or (b) of this definition as appropriate.
(b) Notwithstanding paragraph (a) of this definition, for a unit that is not a coal-fired electric generating unit under OAR 340-228-0601 on the date the unit commences operation as defined in paragraph (a) of this definition, the unit's date for commencement of operation shall be the date on which the unit becomes a coal-fired electric generating unit under OAR 340-228-0601.
(A) For a unit with a date for commencement of operation as defined in paragraph (b) of this definition and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source), such date shall remain the unit's date of commencement of operation.
(B) For a unit with a date for commencement of operation as defined in paragraph (b) of this definition and that is subsequently replaced by a unit at the same source (e.g., repowered), the replacement unit shall be treated as a separate unit with a separate date for commencement of operation as defined in paragraph (a) or (b) of this definition as appropriate.
(14) "Common stack" means a single flue through which emissions from 2 or more units are exhausted.
(15) "Continuous emission monitoring system" or "CEMS" means the equipment required under OAR 340-228-0658 through 0670 to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes (using an automated data acquisition and handling system (DAHS)), a permanent record of Hg emissions, stack gas volumetric flow rate, stack gas moisture content, and oxygen or carbon dioxide concentration (as applicable), in a manner consistent with 40 CFR part 75. The following systems are the principal types of CEMS required under OAR 340-228-0658 through 0670:
(a) A flow monitoring system, consisting of a stack flow rate monitor and an automated data acquisition and handling system and providing a permanent, continuous record of stack gas volumetric flow rate, in units of standard cubic feet per hour (scfh);
(b) A Hg concentration monitoring system, consisting of a Hg pollutant concentration monitor and an automated data acquisition and handling system and providing a permanent, continuous record of Hg emissions in units of micrograms per dry standard cubic meter (μg/dscm);
(c) A moisture monitoring system, as defined in 40 CFR 75.11(b)(2) and providing a permanent, continuous record of the stack gas moisture content, in percent H2O.
(d) A carbon dioxide monitoring system, consisting of a CO2 concentration monitor (or an oxygen monitor plus suitable mathematical equations from which the CO2 concentration is derived) and an automated data acquisition and handling system and providing a permanent, continuous record of CO2 emissions, in percent CO2; and
(e) An oxygen monitoring system, consisting of an O2 concentration monitor and an automated data acquisition and handling system and providing a permanent, continuous record of O2, in percent O2.
(16) "Emissions" means air pollutants exhausted from a unit or source into the atmosphere, as measured, recorded, and reported to the Department by the owner or operator and as determined by the Department in accordance with OAR 340-228-0658 through 0670.
(17) "Generator" means a device that produces electricity.
(18) "Heat input" means, with regard to a specified period of time, the product (in MMBtu/time) of the gross calorific value of the fuel (in Btu/lb) divided by 1,000,000 Btu/MMBtu and multiplied by the fuel feed rate into a combustion device (in lb of fuel/time), as measured, recorded, and reported to the Department by the owner or operator and determined by the Department in accordance with OAR 340-228-0658 through 0670 and excluding the heat derived from preheated combustion air, recirculated flue gases, or exhaust from other sources.
(19) "Heat input rate" means the amount of heat input (in MMBtu) divided by unit operating time (in hr) or, with regard to a specific fuel, the amount of heat input attributed to the fuel (in MMBtu) divided by the unit operating time (in hr) during which the unit combusts the fuel.
(20) “Hg CEMS” means a Hg pollutant concentration monitor and an automated DAHS. A Hg CEMS provides a permanent, continuous record of Hg emissions in units of micrograms per standard cubic meter (μg/scm).
(21) "Life-of-the-unit, firm power contractual arrangement" means a unit participation power sales agreement under which a utility or industrial customer reserves, or is entitled to receive, a specified amount or percentage of nameplate capacity and associated energy generated by any specified unit and pays its proportional amount of such unit's total costs, pursuant to a contract:
(a) For the life of the unit;
(b) For a cumulative term of no less than 30 years, including contracts that permit an election for early termination; or
(c) For a period no less than 25 years or 70 percent of the economic useful life of the unit determined as of the time the unit is built, with option rights to purchase or release some portion of the nameplate capacity and associated energy generated by the unit at the end of the period.
(22) "Lignite" means coal that is classified as lignite A or B according to the American Society of Testing and Materials (ASTM) Standard Specification for Classification of Coals by Rank D338-77, 90, 91, 95, 98a, or 99 (Reapproved 2004) & epsiv; (incorporated by reference, see 40 CFR 60.17).
(23) "Maximum design heat input" means, starting from the initial installation of a unit, the maximum amount of fuel per hour (in Btu/hr) that a unit is capable of combusting on a steady-state basis as specified by the manufacturer of the unit, or, starting from the completion of any subsequent physical change in the unit resulting in a decrease in the maximum amount of fuel per hour (in Btu/hr) that a unit is capable of combusting on a steady-state basis, such decreased maximum amount as specified by the person conducting the physical change.
(24) “Maximum expected Hg concentration (MEC)” means, for units with FGD systems that significantly reduce Hg emissions (including fluidized bed units that use limestone injection) and for units equipped with add-on Hg emission controls (e.g., carbon injection), the maximum expected Hg concentration (MEC) during normal, stable operation of the unit and emission controls. To calculate the MEC, substitute the MPC value from section (25) of this rule into Equation A–2 in section 2.1.1.2 of appendix A to 40 CFR part 75. For units with add-on Hg emission controls, base the percent removal efficiency on design engineering calculations. For units with FGD systems, use the best available estimate of the Hg removal efficiency of the FGD system.
(25) “Maximum potential Hg concentration (MPC)” means the following:
(a) The maximum potential concentration depends upon the type of coal combusted. For the initial MPC determination, the MPC is one of the following:
(A) The MPC is one of the following default values: 9 μg/scm for bituminous coal; 10 μg/scm for sub-bituminous coal; 16 μg/scm for lignite, and 1 μg/scm for waste coal. If different coals are blended, the MPC is the highest MPC for any fuel in the blend; or
(B) The MPC may be based on the results of site-specific emission testing using one of the Hg reference methods in section 32 of this rule or in 40 CFR 75.22, if the unit does not have add-on Hg emission controls or a flue gas desulfurization system, or if testing upstream of these control devices. A minimum of 3 test runs are required, at the normal operating load. The highest total Hg concentration obtained in any of the tests may be used as the MPC; or
(C) The MPC is based on the maximum potential Hg concentration on 720 or more hours of historical CEMS data or data from a sorbent trap monitoring system, if the unit does not have add-on Hg emission controls or a flue gas desulfurization system (or if the CEMS or sorbent trap system is located upstream of these control devices) and if the Hg CEMS or sorbent trap system has been tested for relative accuracy against one of the Hg reference methods in section 32 of this rule or in 40 CFR 75.22 and has met a relative accuracy specification of 20.0% or less.
(b) For the purposes of missing data substitution, the fuel-specific or site-specific MPC values defined in subsection (25)(a) of this rule apply to units using sorbent trap monitoring systems.
(26) "Monitoring system" means any monitoring system that meets the requirements of OAR 340-228-0658 through 0670, including a continuous emissions monitoring system, an alternative monitoring system, or an excepted monitoring system under 40 CFR part 75.
(27) "Nameplate capacity" means, starting from the initial installation of a generator, the maximum electrical generating output (in MWe) that the generator is capable of producing on a steady-state basis and during continuous operation (when not restricted by seasonal or other deratings) as specified by the manufacturer of the generator or, starting from the completion of any subsequent physical change in the generator resulting in an increase in the maximum electrical generating output (in MWe) that the generator is capable of producing on a steady-state basis and during continuous operation (when not restricted by seasonal or other deratings), such increased maximum amount as specified by the person conducting the physical change.
(28) "Operator" means any person who operates, controls, or supervises a coal-fired electric generating unit and shall include, but not be limited to, any holding company, utility system, or plant manager of such a unit or source.
(29) "Owner" means any of the following persons:
(a) Any holder of any portion of the legal or equitable title in a coal-fired electric generating unit;
(b) Any holder of a leasehold interest in a coal-fired electric generating unit; or
(c) Any purchaser of power from a coal-fired electric generating unit under a life-of-the-unit, firm power contractual arrangement; provided that, unless expressly provided for in a leasehold agreement, owner shall not include a passive lessor, or a person who has an equitable interest through such lessor, whose rental payments are not based (either directly or indirectly) on the revenues or income from such coal-fired electric generating unit.
(30) "Potential electrical output capacity" means 33 percent of a unit's maximum design heat input, divided by 3,413 Btu/kWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr.
(31) "Reference method" means any direct test method of sampling and analyzing for an air pollutant as follows or as specified in 40 CFR 75.22.
(a) ASTM D6784–02, ‘‘Standard Test Method for Elemental, Oxidized, Particle-Bound, and Total Mercury in Flue Gas Generated from Coal-Fired Stationary Sources’’ is the reference method for determining Hg concentration. When this method is used, paired sampling trains are required, and to validate a RATA run, the relative deviation (RD), calculated according to OAR 340-228-0627(12)(g), must not exceed 10 percent. If the RD criterion is met, use the average Hg concentration measured by the two trains (vapor phase Hg, only) in the relative accuracy calculations. Alternatively, an instrumental reference method capable of measuring total vapor phase Hg may be used, subject to the approval of the Department.
(32) "Repowered" means, with regard to a unit, replacement of a coal-fired boiler with one of the following coal-fired technologies at the same source as the coal-fired boiler:
(a) Atmospheric or pressurized fluidized bed combustion;
(b) Integrated gasification combined cycle;
(c) Magnetohydrodynamics;
(d) Direct and indirect coal-fired turbines;
(e) Integrated gasification fuel cells; or
(f) As determined by the Department in consultation with the Secretary of Energy, a derivative of one or more of the technologies under paragraphs (a) through (e) of this definition and any other coal-fired technology capable of controlling multiple combustion emissions simultaneously with improved boiler or generation efficiency and with significantly greater waste reduction relative to the performance of technology in widespread commercial use as of January 1, 2005.
(33) "Sequential use of energy" means:
(a) For a topping-cycle cogeneration unit, the use of reject heat from electricity production in a useful thermal energy application or process; or
(b) For a bottoming-cycle cogeneration unit, the use of reject heat from useful thermal energy application or process in electricity production.
(34) “Sorbent trap monitoring system” means the equipment required for the continuous monitoring of Hg emissions, using paired sorbent traps containing iodinized charcoal (IC) or other suitable reagent(s). This excepted monitoring system consists of a probe, the paired sorbent traps, a heated umbilical line, moisture removal components, an airtight sample pump, a dry gas meter, and an automated data acquisition and handling system. The monitoring system samples the stack gas at a rate proportional to the stack gas volumetric flow rate. The sampling is a batch process. Using the sample volume measured by the dry gas meter and the results of the analyses of the sorbent traps, the average Hg concentration in the stack gas for the sampling period is determined, in units of micrograms per dry standard cubic meter (μg/dscm). Mercury mass emissions for each hour in the sampling period are calculated using the average Hg concentration for that period, in conjunction with contemporaneous hourly measurements of the stack gas flow rate, corrected for the stack gas moisture content.
(35) "Subbituminous" means coal that is classified as subbituminous A, B, or C, according to the American Society of Testing and Materials (ASTM) Standard Specification for Classification of Coals by Rank D388-77, 90, 91, 95, 98a, or 99 (Reapproved 2004) & epsiv; (incorporated by reference, see 40 CFR 60.17).
(36) "Submit or serve" means to send or transmit a document, information, or correspondence to the person specified in accordance with the applicable regulation:
(a) In person;
(b) By United States Postal Service; or
(c) By other means of dispatch or transmission and delivery. Compliance with any ''submission'' or ''service'' deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.
(37) "Title V operating permit" means a permit issued under title V of the CAA and 40 CFR part 70 or 71.
(38) "Title V operating permit regulations" means the regulations that the Administrator has approved or issued as meeting the requirements of title V of the CAA and 40 CFR part 70 or 71.
(39) "Topping-cycle cogeneration unit" means a cogeneration unit in which the energy input to the unit is first used to produce useful power, including electricity, and at least some of the reject heat from the electricity production is then used to provide useful thermal energy.
(40) "Total energy input" means, with regard to a cogeneration unit, total energy of all forms supplied to the cogeneration unit, excluding energy produced by the cogeneration unit itself. Each form of energy supplied shall be measured by the lower heating value of that form of energy calculated as follows:
LHV = HHV − 10.55(W + 9H)
Where:
LHV = lower heating value of fuel in Btu/lb,
HHV = higher heating value of fuel in Btu/lb,
W = Weight % of moisture in fuel, and
H = Weight % of hydrogen in fuel.
(41) "Total energy output" means, with regard to a cogeneration unit, the sum of useful power and useful thermal energy produced by the cogeneration unit.
(42) "Unit" means a stationary coal-fired boiler or a stationary coal-fired combustion turbine.
(43) "Unit operating day" means a calendar day in which a unit combusts any fuel.
(44) "Unit operating hour" or "hour of unit operation" means an hour in which a unit combusts any fuel.
(45) "Useful power" means, with regard to a cogeneration unit, electricity or mechanical energy made available for use, excluding any such energy 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).
(46) "Useful thermal energy" means, with regard to a cogeneration unit, thermal energy that is:
(a) Made available to an industrial or commercial process (not a power production process), excluding any heat contained in condensate return or makeup water;
(b) Used in a heat application (e.g., space heating or domestic hot water heating); or
(c) Used in a space cooling application (i.e., thermal energy used by an absorption chiller).
(47) "Utility power distribution system" means the portion of an electricity grid owned or operated by a utility and dedicated to delivering electricity to customers.
Stat. Auth.: ORS 468.020 & 468A.310
Stats. Implemented: ORS 468A.025
Hist.: DEQ 13-2006, f. & cert. ef. 12-22-06
340-228-0603
Measurements, Abbreviations, and Acronyms
Measurements, abbreviations, and acronyms used in this part are defined as follows:
(1) Btu-British thermal unit.
(2) CO2-carbon dioxide.
(3) H2O-water.
(4) Hg-mercury.
(5) hr-hour.
(6) kW-kilowatt electrical.
(7) kWh-kilowatt hour.
(8) lb-pound.
(9) MMBtu-million Btu.
(10) MWe-megawatt electrical.
(11) MWh-megawatt hour.
(12) NOX-nitrogen oxides.
(13) O2-oxygen.
(14) ppm-parts per million.
(15) scf-standard cubic foot.
(16) scfh-standard cubic feet per hour.
(17) scm-standard cubic meter.
(18) SO2-sulfur dioxide.
(19) µg-micrograms.
(20) yr-year.
Stat. Auth.: ORS 468.020 & 468A.310
Stats. Implemented: ORS 468A.025
Hist.: DEQ 13-2006, f. & cert. ef. 12-22-06
340-228-0606
Hg Emission Standards
(1) Mercury reduction plan. By July 1, 2009 or 1-year prior to commencement of commercial operation, whichever is later, the owner or operator of each coal-fired electric generating unit must develop and submit for Department approval a mercury reduction plan for each coal-fired electric generating unit. The plan must propose a control strategy for mercury that is most likely to result in the capture of at least 90 percent of the mercury emitted from the unit or that will limit mercury emissions to 0.60 pounds per trillion BTU of heat input. The owner or operator must demonstrate that the plan reflects technology that could reasonably be expected to meet the limits in this section if the technology operates as anticipated by the manufacturer. The plan must provide a timeframe for implementation of the selected control strategy including major milestones, installation and operation requirements, and work practice standards for the selected technology. The owner and operator of the coal-fired electric generating unit may proceed with the plan within 60 days of submittal unless, within the 60 day period, the Department notifies the owner or operator of the coal-fired electric generating unit that the plan must be revised.
(2) Mercury emission standards. On and after July 1, 2012 or at commencement of commercial startup, whichever is later, except as allowed under section (3) of this rule, each coal-fired electric generating unit must have implemented the approved control strategy projected to achieve at least 90 percent mercury capture or that will limit mercury emissions to 0.60 pounds per trillion BTU of heat input.
(3) Compliance extension. Up to a 1-year extension of the requirement to implement the approved control strategy may be granted by the Department if the owner or operator of a coal-fired electric generating unit demonstrates that it is not practical to install mercury control equipment by July 1, 2012 due to supply limitations or other extenuating circumstances that are beyond the control of the owner or operator.
(4) Compliance demonstration. Commencing in July 2013 or 12 months after commercial startup or 12 months after expiration of the extension granted under section (3) of this rule, whichever is later, each coal-fired electric generating unit must thereafter demonstrate compliance with one of the standards in subsections (4)(a) or (4)(b) of this rule for each compliance period, except as allowed under sections (5) and (6) of this rule. A compliance period consists of twelve months. Each month commencing with June 2013 or the twelfth month after commencement of commercial operation or twelfth month after expiration of the extension granted under section (3) of this rule, whichever is later, is the end of a compliance period consisting of that month and the previous 11 months.
(a) A mercury emission standard of 0.60 pounds per trillion BTU of heat input calculated by dividing the Hg mass emissions determined using a mercury CEMS or sorbent trap monitoring system by heat input as determined according to 40 CFR part 75, appendix F (procedure 5); or
(b) A minimum 90-percent capture of inlet mercury determined as follows:
(A) Inlet mercury must be determined as specified in subparagraph (4)(b)(A)(i) or (4)(b)(A)(ii) of this rule:
(i) Coal sampling and analysis. To demonstrate compliance by coal sampling and analysis, the owner or operator of a coal-fired electric generating unit must test its coal for mercury consistent with a coal sampling and analysis plan. The coal sampling and analysis plan must be consistent with the requirements of 40 CFR 63.7521.
(ii) Hg mass emissions prior to any control device(s). To demonstrate compliance by measuring Hg mass emissions, the owner or operator of a coal-fired electric generating unit must measure mercury emissions prior to any control device(s) using a Hg CEMS or sorbent trap.
(B) The mercury capture efficiency must be calculated using the Hg emissions determined using a mercury CEMS or sorbent trap monitoring system and the inlet mercury determined using the coal mercury content data obtained in accordance with subparagraph (4)(b)(A)(i) of this rule or the measured inlet mercury data obtained in accordance with subparagraph (4)(b)(A)(ii) of this rule and a calculation methodology approved by the Department.
(5) Temporary compliance alternative. If the owner or operator of a Coal-fired electric generating unit properly implements the approved control strategy and the strategy fails to achieve at least 90 percent mercury capture or limit mercury emissions to 0.60 pounds per trillion BTU of heat input:
(a) The owner or operator must notify the Department of the failure within 30 days of the end of the initial compliance period; and
(b) The owner or operator must file an application with the Department for a permit or permit modification in accordance with OAR 340 division 216 to establish a temporary alternative mercury emission limit. The application must be filed within 60 days of the end of the initial compliance period, and must include a continual program of mercury control progression able to achieve at least 90 percent mercury capture or to limit mercury emissions to 0.60 pounds per trillion BTU of heat input and all monitoring and operating data for the Coal-fired electric generating unit.
(c) The Department may establish a temporary alternative mercury emission limit only if the owner or operator applies for a permit or permit modification, that includes a control strategy that the Department determines constitutes a continual program of mercury control progression able to achieve at least 90 percent mercury capture or to limit mercury emissions to 0.60 pounds per trillion BTU of heat input.
(d) Establishment of a temporary alternative mercury emission limit requires public notice in accordance with OAR 340 division 209 for Category III permit actions
(e) If the owner or operator files an application under subsection (5)(b) of this rule, the Coal-fired electric generating unit must operate according to the temporary alternative mercury emission limit proposed in the permit or permit modification application until the Department either denies the application or issues the permit or permit modification. Compliance with the proposed temporary alternative mercury emission limit prior to final Department action on the application shall constitute compliance with the limits in section (2) of this rule.
(f) A temporary alternative mercury emission limit established in a permit expires July 1, 2015 or within 2 years of commencement of commercial operation, whichever is later.
(6) Permanent compliance alternative. If the owner or operator of a Coal-fired electric generating unit is unable to achieve at least 90 percent mercury capture or an emission level of 0.60 pounds per trillion BTU of heat input by July 1, 2015 or within 2 years of commencement of commercial operation, whichever is later, despite properly implementing the continual program of mercury progression required in section (5) of this rule:
(a) The owner or operator of the Coal-fired electric generating unit may file an application with the Department for a permit modification in accordance with OAR 340 division 216 to establish a permanent alternative mercury emission limit that comes as near as technically possible to achieving 90 percent mercury capture or an emission level of 0.60 pounds per trillion BTU of heat input.
(b) The Department may establish a permanent alternative mercury emission limit only if the owner or operator applies for a permit modification, that proposes an alternative mercury emission limit that the Department determines comes as near as technically possible to achieving 90 percent mercury capture or an emission level of 0.60 pounds per trillion BTU of heat input.
(c) Establishment of a permanent alternative mercury emission limit requires public notice in accordance with OAR 340 division 209 for Category IV permit actions.
(d) If the owner or operator files an application under subsection (6)(a) of this rule, the Coal-fired electric generating unit must operate according to the permanent alternative mercury emission limit proposed in the permit modification application until the Department either denies the application or modifies the permit. Compliance with the proposed permanent alternative mercury emission limit prior to final Department action on the application shall constitute compliance with the limits in section (4) of this rule.
(7) Emission Caps. Beginning in calendar year 2018, the following coal-fired electric generating unit specific emission caps shall apply.
(a) Existing Boardman coal-fired electric generating unit cap. The existing coal-fired electric generating unit in Boardman shall emit no more than:
(A) 60 pounds of mercury in any calendar year in which there are no new coal-fired electric generating units operated in Oregon.
(B) 35 pounds of mercury in any calendar year in which there are new coal-fired electric generating units operated in Oregon.
(b) New coal-fired electric generating unit cap:
(A) New coal-fired electric generating units, in aggregate, shall emit no more than:
(i) 25 pounds of mercury in any calendar year in which the existing coal-fired electric generating unit in Boardman is operated.
(ii) 60 pounds of mercury in any calendar year in which the existing coal-fired electric generating unit in Boardman is not operated.
(B) The owner or operator of each new coal-fired electric generating unit must submit to the Department a request, in a format specified by the Department, to receive a portion of the new coal-fired electric generating unit cap. The request may not be submitted until the new coal-fired electric generating unit has received its Site Certification from the Facility Siting Council, or if the new coal-fired electric generating unit is not required to obtain a Site Certificate, all governmental approvals necessary to commence construction.
(C) The Department will allocate the new coal-fired electric generating unit cap in order of receipt of requests and, once allocated, the new coal-fired electric generating unit shall be entitled to receive and equal allocation in future years unless the new coal-fired electric generating unit permanently ceases operations.
(D) Each individual new coal-fired electric generating unit shall emit no more than the lesser of:
(i) An amount of mercury determined by multiplying the design heat input in TBtu of such coal-fired electric generating unit by 0.60 pounds per TBtu rounded to the nearest pound as appropriate, or
(ii) The amount of the emission cap under (7)(b) less the amount of the emission cap under (7)(b) that has been allocated to other new coal-fired electric generating units.
(c) Compliance demonstration. Each coal-fired electric generating unit must demonstrate compliance with the applicable calendar year emission cap in subsection (7)(a) or (7)(b) of this rule using a mercury CEMS or sorbent trap monitoring system.
Stat. Auth.: ORS 468.020 & 468A.310
Stats. Implemented: ORS 468A.025
Hist.: DEQ 13-2006, f. & cert. ef. 12-22-06
Monitoring Requirements
340-228-0609
General Requirements
The owners and operators of a coal-fired electric generating unit must comply with the monitoring, recordkeeping, and reporting requirements as provided in this rule and OAR 340-228-0611 through 0637. For purposes of complying with such requirements, the definitions in OAR 340-228-0602 and in 40 CFR 72.2 shall apply, and the terms "affected unit" and "designated representative" in 40 CFR part 75 shall be deemed to refer to the terms "coal-fired electric generating unit" and "owner or operator" respectively, as defined in OAR 340-228-0602. The owner or operator of a unit that is not a coal-fired electric generating unit but that is monitored under OAR 340-228-0615(2)(a) must comply with the same monitoring, recordkeeping, and reporting requirements as a coal-fired electric generating unit.
(1) Requirements for installation, certification, and data accounting. The owner or operator of each coal-fired electric generating unit must:
(a) Install all applicable monitoring systems required under this rule and OAR 340-228-0611 through 0637 for monitoring Hg mass emissions, inlet Hg, and individual unit heat input (including all systems required to monitor Hg concentration, stack gas moisture content, stack gas flow rate, and CO2 or O2 concentration, as applicable).
(b) Successfully complete all certification tests required under OAR 340-228-0621 and meet all other requirements of this rule and OAR 340-228-0611 through 0637 applicable to the monitoring systems under subsection (1)(a) of this rule.
(c) The owner or operator must reduce all volumetric flow, CO2 concentration, O2 concentration, CO2 mass emissions (if applicable), and Hg concentration data collected by the monitors to hourly averages.
(d) Record, report, and quality-assure the data from the monitoring systems under subsection (1)(a) of this rule.
(e) Failure of a CO2, or O2 emissions concentration monitor, Hg concentration monitor, flow monitor, or moisture monitor to acquire the minimum number of data points for calculation of an hourly average shall result in the failure to obtain a valid hour of data and the loss of such component data for the entire hour.
(2) Compliance deadlines. The owner or operator must meet the monitoring system certification and other requirements of sections (1) of this rule on or before the following dates. The owner or operator must record, report, and quality-assure the data from the monitoring systems under subsection (1)(a) of this rule on and after the following dates.
(a) Outlet Hg.
(A) For the owner or operator of a coal-fired electric generating unit that commences commercial operation before July 1, 2008, by January 1, 2009.
(B) For the owner or operator of a coal-fired electric generating unit that commences commercial operation on or after July 1, 2008, by the later of the following dates:
(i) January 1, 2009; or
(ii) 90 unit operating days or 180 calendar days, whichever occurs first, after the date on which the unit commences commercial operation.
(C) For the owner or operator of a coal-fired electric generating unit for which construction of a new stack or flue or installation of add-on Hg emission controls, a flue gas desulfurization system, a selective catalytic reduction system, or a compact hybrid particulate collector system is completed after the applicable deadline under paragraph (2)(a)(A) or (B) of this rule, by 90 unit operating days or 180 calendar days, whichever occurs first, after the date on which emissions first exit to the atmosphere through the new stack or flue, add-on Hg emissions controls, flue gas desulfurization system, selective catalytic reduction system, or compact hybrid particulate collector system.
(b) Heat input. For monitoring systems used to monitor heat input in accordance with OAR 340-228-0606(4)(a), if applicable, by the later of the following dates:
(A) July 1, 2012 or the date established under OAR 340-228-0606(3); or
(B) The date on which the unit commences commercial operation.
(c) Inlet Hg. If required to perform coal sampling and analysis in accordance with OAR 340-228-0606(4)(b)(A)(i) or measure Hg emission prior to any control device(s) in accordance with OAR 340-228-0606(4)(b)(A)(ii), if applicable, by the later of the following dates:
(A) July 1, 2012 or the date established under OAR 340-228-0606(3); or
(B) The date on which the unit commences commercial operation.
(3) Reporting data.
(a) Except as provided in subsection (3)(b) of this rule, the owner or operator of a coal-fired electric generating unit that does not meet the applicable compliance date set forth in section (2) of this rule for any monitoring system under subsection (1)(a) of this rule must, for each monitoring system, determine, record, and report maximum potential (or, as appropriate, minimum potential) values for Hg concentration, stack gas flow rate, stack gas moisture content, and any other parameters required to determine Hg mass emissions and heat input in accordance with OAR 340-228-0637(5).
(b) The owner or operator of a coal-fired electric generating unit that does not meet the applicable compliance date set forth in paragraph (2)(a)(C) of this rule for any monitoring system under subsection (1)(a) must, for each such monitoring system, determine, record, and report substitute data using the applicable missing data procedures in 40 CFR part 75 subpart D, OAR 340-228-0631, and OAR 340-228-0633, in lieu of the maximum potential (or, as appropriate, minimum potential) values, for a parameter if the owner or operator demonstrates that there is continuity between the data streams for that parameter before and after the construction or installation under subsection (2)(a)(C) of this rule.
(4) Prohibitions.
(a) No owner or operator of a coal-fired electric generating unit shall use any alternative monitoring system, alternative reference method, or any other alternative to any requirement of this rule and OAR 340-228-0611 through 0637 without having obtained prior written approval.
(b) No owner or operator of a coal-fired electric generating unit shall operate the unit so as to discharge, or allow to be discharged, Hg emissions to the atmosphere without accounting for all such emissions in accordance with the applicable provisions of this rule and OAR 340-228-0611 through 0637.
(c) No owner or operator of a coal-fired electric generating unit shall disrupt the continuous emission monitoring system, any portion thereof, or any other approved emission monitoring method, and thereby avoid monitoring and recording Hg mass emissions discharged into the atmosphere, except for periods of recertification or periods when calibration, quality assurance testing, or maintenance is performed in accordance with the applicable provisions of this rule and OAR 340-228-0611 through 0637.
(d) No owner or operator of a coal-fired electric generating unit shall retire or permanently discontinue use of the continuous emission monitoring system, any component thereof, or any other approved emission monitoring system under this rule, except under any one of the following circumstances:
(A) The owner or operator is monitoring Hg mass emissions from the coal-fired electric generating unit with another certified monitoring system approved, in accordance with the applicable provisions of this rule and OAR 340-228-0611 through 0637, by the Department for use at that unit that provides emission data for the same pollutant or parameter as the retired or discontinued monitoring system; or
(B) The owner or operator submits notification of the date of certification testing of a replacement monitoring system for the retired or discontinued monitoring system in accordance with OAR 340-228-0621(3)(c)(A).
340-228-0611
Additional Requirements to Provide Heat Input Data
The owner or operator of a coal-fired electric generating unit that monitors and reports Hg mass emissions using a Hg concentration monitoring system and a flow monitoring system must also monitor and report heat input rate at the unit level using the procedures set forth in 40 CFR part 75.
340-228-0613
Monitoring of Hg Mass Emissions and Heat Input at the Unit Level
The owner or operator of the affected coal-fired electric generating unit must meet the general operating requirements in 40 CFR 75.10 for the following continuous emission monitors (except as provided in accordance with 40 CFR part 75 subpart E):
(1) A Hg concentration monitoring system (as defined in OAR 340-228-0602) or a sorbent trap monitoring system (as defined in OAR 340-228-0602) to measure Hg concentration; and
(2) A flow monitoring system; and
(3) A continuous moisture monitoring system (if correction of Hg concentration for moisture is required), as described in 40 CFR 75.11(b) or 75.12(b). Alternatively, the owner or operator may use the appropriate fuel-specific default moisture value provided in 40 CFR 75.11 or 75.12, or a site-specific moisture value approved by petition under 40 CFR 75.66; and
(4) If heat input is required to be reported, the owner or operator also must meet the general operating requirements for a flow monitoring system and an O2 or CO2 monitor to measure heat input rate; or
340-228-0615
Monitoring of Hg Mass Emissions and Heat Input at Common and Multiple Stacks
(1) Unit utilizing common stack with other coal-fired electric generating unit(s). When a coal-fired electric generating unit utilizes a common stack with one or more coal-fired electric generating unit, but no non coal-fired electric generating units, the owner or operator must either:
(a) Install, certify, operate, and maintain the monitoring systems described in OAR 340-228-0613 at the common stack, record the combined Hg mass emissions for the units exhausting to the common stack. If reporting of the unit heat input rate is required, determine the hourly unit heat input rates either by:
(A) Apportioning the common stack heat input rate to the individual units according to the procedures in 40 CFR 75.16(e)(3); or
(B) Installing, certifying, operating, and maintaining a flow monitoring system and diluent monitor in the duct to the common stack from each unit; or
(b) Install, certify, operate, and maintain the monitoring systems and (if applicable) perform the Hg emission testing described in OAR 340-228-0613 in the duct to the common stack from each unit.
(2) Unit utilizing common stack with non coal-fired electric generating unit(s). When one or more coal-fired electric generating units utilize a common stack with one or more non coal-fired electric generating units, the owner or operator must either:
(a) Install, certify, operate, and maintain the monitoring systems and (if applicable) perform the Hg emission testing described in OAR 340-228-0613 in the duct to the common stack from each coal-fired electric generating unit; or
(b) Install, certify, operate, and maintain the monitoring systems described in OAR 340-228-0613 in the common stack; and
(A) Install, certify, operate, and maintain the monitoring systems and (if applicable) perform the Hg emission testing described in OAR 340-228-0613 in the duct to the common stack from each non coal-fired electric generating unit. The designated representative must submit a petition to the Department to allow a method of calculating and reporting the Hg mass emissions from the coal-fired electric generating units as the difference between Hg mass emissions measured in the common stack and Hg mass emissions measured in the ducts of the non coal-fired electric generating units, not to be reported as an hourly value less than zero. The Department may approve such a method whenever the owner or operator demonstrates, to the satisfaction of the Department, that the method ensures that the Hg mass emissions from the coal-fired electric generating units are not underestimated; or
(B) Count the combined emissions measured at the common stack as the Hg mass emissions for the coal-fired electric generating units, for recordkeeping and compliance purposes, in accordance with section (1) of this rule; or
(C) Submit a petition to the Department to allow use of a method for apportioning Hg mass emissions measured in the common stack to each of the units using the common stack and for reporting the Hg mass emissions. The Department may approve such a method whenever the owner or operator demonstrates, to the satisfaction of the Department, that the method ensures that the Hg mass emissions from the coal-fired electric generating units are not underestimated.
(3) Unit with a main stack and a bypass stack. Whenever any portion of the flue gases from a coal-fired electric generating unit can be routed through a bypass stack to avoid the Hg monitoring system(s) installed on the main stack, the owner and operator must either:
(a) Install, certify, operate, and maintain the monitoring systems described in OAR 340-228-0613 on both the main stack and the bypass stack and calculate Hg mass emissions for the unit as the sum of the Hg mass emissions measured at the two stacks;
(b) Install, certify, operate, and maintain the monitoring systems described in OAR 340-228-0613 at the main stack and measure Hg mass emissions at the bypass stack using the appropriate reference methods in OAR 340-228-0602(31) or in 40 CFR 75.22. Calculate Hg mass emissions for the unit as the sum of the emissions recorded by the installed monitoring systems on the main stack and the emissions measured by the reference method monitoring systems; or
(c) Install, certify, operate, and maintain the monitoring systems and (if applicable) perform the Hg emission testing described in OAR 340-228-0613 only on the main stack. If this option is chosen, it is not necessary to designate the exhaust configuration as a multiple stack configuration in the monitoring plan required under 40 CFR 75.53 and OAR 340-228-0637(2), since only the main stack is monitored. For each unit operating hour in which the bypass stack is used, report, as applicable, the maximum potential Hg concentration (as defined in OAR 340-228-0602(25)), and the appropriate substitute data values for flow rate, CO2 concentration, O2 concentration, and moisture (as applicable), in accordance with the missing data procedures of 40 CFR 75.31 through 75.37.
(4) Unit with multiple stack or duct configuration. When the flue gases from a coal-fired electric generating unit discharge to the atmosphere through more than one stack, or when the flue gases from a coal-fired electric generating unit utilize two or more ducts feeding into a single stack and the owner or operator chooses to monitor in the ducts rather than in the stack, the owner or operator must either:
(a) Install, certify, operate, and maintain the monitoring systems and (if applicable) perform the Hg emission testing described in OAR 340-228-0613 in each of the multiple stacks and determine Hg mass emissions from the coal-fired electric generating unit as the sum of the Hg mass emissions recorded for each stack. If another unit also exhausts flue gases into one of the monitored stacks, the owner or operator must comply with the applicable requirements of sections (1) and (2) of this rule, in order to properly determine the Hg mass emissions from the units using that stack; or
(b) Install, certify, operate, and maintain the monitoring systems and (if applicable) perform the Hg emission testing described in OAR 340-228-0613 in each of the ducts that feed into the stack, and determine Hg mass emissions from the coal-fired electric generating unit using the sum of the Hg mass emissions measured at each duct, except that where another unit also exhausts flue gases to one or more of the stacks, the owner or operator must also comply with the applicable requirements of sections (1) and (2) of this rule to determine and record Hg mass emissions from the units using that stack. The owner or operator must calculate Hg mass emissions and heat input rate in accordance with approved procedures.
340-228-0617
Special Provisions for Measuring Hg Mass Emissions using the Excepted Sorbent Trap Monitoring Methodology
For an affected coal-fired electric generating unit, if the owner or operator elects to use sorbent trap monitoring systems to quantify Hg mass emissions, the guidelines in sections (1) through (10) of this rule must be followed for this excepted monitoring methodology:
(1) For each sorbent trap monitoring system (whether primary or redundant backup), the use of paired sorbent traps, as described in OAR 340-228-0627, is required.
(2) Each sorbent trap must have both a main section, a backup section, and a third section to allow spiking with a calibration gas of known Hg concentration, as described in OAR 340-228-0627.
(3) A certified flow monitoring system is required.
(4) Correction for stack gas moisture content is required, and in some cases, a certified O2 or CO2 monitoring system is required.
(5) Each sorbent trap monitoring system must be installed and operated in accordance with OAR 340-228-0627. The automated data acquisition and handling system must ensure that the sampling rate is proportional to the stack gas volumetric flow rate.
(6) At the beginning and end of each sample collection period, and at least once in each unit operating hour during the collection period, the dry gas meter reading must be recorded.
(7) After each sample collection period, the mass of Hg adsorbed in each sorbent trap (in all three sections) must be determined according to the applicable procedures in OAR 340-228-0627.
(8) The hourly Hg mass emissions for each collection period are determined using the results of the analyses in conjunction with contemporaneous hourly data recorded by a certified stack flow monitor, corrected for the stack gas moisture content. For each pair of sorbent traps analyzed, the average of the two Hg concentrations must be used for reporting purposes under OAR 340-228-0637(4). Notwithstanding this requirement, if, due to circumstances beyond the control of the owner or operator, one of the paired traps is accidentally lost, damaged, or broken and cannot be analyzed, the results of the analysis of the other trap, if valid, may be used for reporting purposes.
(9) All unit operating hours for which valid Hg concentration data are obtained with the primary sorbent trap monitoring system (as verified using the quality assurance procedures in OAR 340-228-0627) must be reported in the electronic quarterly report under OAR 340-228-0637(4). For hours in which data from the primary monitoring system are invalid, the owner or operator may report valid Hg concentration data from a certified redundant backup CEMS or sorbent trap monitoring system or from an applicable reference method under OAR 340-228-0602(31) or 40 CFR 75.22. If no quality-assured Hg concentration are available for a particular hour, the owner or operator must report the appropriate substitute data value in accordance with OAR 340-228-0633.
(10) Initial certification requirements and additional quality-assurance requirements for the sorbent trap monitoring systems are found in OAR 340-228-0627.
340-228-0619
Procedures for Hg Mass Emissions
(1) Use the procedures in this rule to calculate the hourly Hg mass emissions (in pounds) at each monitored location, for the affected unit or group of units that discharge through a common stack.
(a) To determine the hourly Hg mass emissions when using a Hg concentration monitoring system that measures on a wet basis and a flow monitor, use the following equation:
Mh = K x Ch x Qh x th
Where:
Mh = Hg mass emissions for the hour, rounded off to three decimal places, (pounds).
K = Units conversion constant, 6.236 x 10-11 lb-scm/μg-scf
Ch = Hourly Hg concentration, wet basis, adjusted for bias if the bias-test procedures show that a bias-adjustment factor is necessary, (μg/wscm).
Qh = Hourly stack gas volumetric flow rate, adjusted for bias, where the bias-test procedures show a bias-adjustment factor is necessary, (scfh)
th = Unit or stack operating time, as defined in 40 CFR 72.2, (hr)
(b) To determine the hourly Hg mass emissions when using a Hg concentration monitoring system that measures on a dry basis or a sorbent trap monitoring system and a flow monitor, use the following equation:
Mh =K x Ch x Qh x th x (1−Bws)
Where:
Mh = Hg mass emissions for the hour, rounded off to three decimal places, (pounds).
K = Units conversion constant, 6.236 x 10-11 lb-scm/μg-scf
Ch = Hourly Hg concentration, dry basis, adjusted for bias if the bias-test procedures show that a bias-adjustment factor is necessary, (μg/dscm). For sorbent trap systems, a single value of Ch (i.e., a flow proportional average concentration for the data collection period), is applied to each hour in the data collection period, for a particular pair of traps.
Qh = Hourly stack gas volumetric flow rate, adjusted for bias, where the bias-test procedures show a bias-adjustment factor is necessary, (scfh)
Bws = Moisture fraction of the stack gas, expressed as a decimal (equal to % H2O 100)
th = Unit or stack operating time, as defined in 40 CFR 72.2, (hr)
(2) Use equation 5 to this division to calculate quarterly, year-to-date, and 12-month total Hg mass emissions in pounds.
(3) If heat input rate monitoring is required, follow the applicable procedures for heat input apportionment and summation in sections 5.3, 5.6 and 5.7 of appendix F to 40 CFR part 75.
Monitoring Certification
340-228-0621
Initial Certification and Recertification Procedures
(1) The owner or operator of a coal-fired electric generating unit shall be exempt from the initial certification requirements of this rule for a monitoring system under OAR 340-228-0609(1)(a) if the following conditions are met:
(a) The monitoring system has been previously certified; and
(b) The applicable quality-assurance and quality-control requirements are fully met for the certified monitoring system described in subsection (1)(a) of this rule.
(2) The recertification provisions of this rule shall apply to a monitoring system under OAR 340-228-0609(1)(a) exempt from initial certification requirements under section (1) of this rule.
(3) Initial certification and recertification procedures. Except as provided section (1) of this rule, the owner or operator of a coal-fired electric generating unit must comply with the following initial certification and recertification procedures for a continuous monitoring system (e.g., a continuous emission monitoring system and an excepted monitoring system (sorbent trap monitoring system) under OAR 340-228-0617) under OAR 340-228-0609(1)(a). The owner or operator must meet any additional requirements for Hg concentration monitoring systems, sorbent trap monitoring systems (as defined in OAR 340-228-0602(34)), flow monitors, CO2 monitors, O2 monitors, or moisture monitors, as set forth under OAR 340-228-0613, under the common stack provisions in OAR 340-228-0615. The owner or operator of a unit that qualifies to use an alternative monitoring system must comply with the procedures in section (4) of this rule respectively.
(a) Requirements for initial certification. The owner or operator must ensure that each monitoring system under OAR 340-228-0609(1)(a) (including the automated data acquisition and handling system) successfully completes all of the initial certification testing by the applicable deadline in OAR 340-228-0609(2). In addition, whenever the owner or operator installs a monitoring system to meet the requirements of this rule in a location where no such monitoring system was previously installed, initial certification is required.
(b) Requirements for recertification. Whenever the owner or operator makes a replacement, modification, or change in any certified continuous emission monitoring system, or an excepted monitoring system (sorbent trap monitoring system) under OAR 340-228-0617, under OAR 340-228-0609(1)(a) that may significantly affect the ability of the system to accurately measure or record the CO2 concentration, stack gas volumetric flow rate, Hg concentration, Hg mass emissions, percent moisture, or heat input rate or to meet the quality-assurance and quality-control requirements of 40 CFR 75.21, OAR 340-228-0623, or appendix B to 40 CFR part 75, the owner or operator must recertify the monitoring system in accordance with 40 CFR 75.20(b). Furthermore, whenever the owner or operator makes a replacement, modification, or change to the flue gas handling system or the unit's operation that may significantly change the stack flow or concentration profile, the owner or operator must recertify each continuous emission monitoring system, and each excepted monitoring system (sorbent trap monitoring system) under OAR 340-228-0617, whose accuracy is potentially affected by the change, in accordance with 40 CFR 75.20(b). Examples of changes to a continuous emission monitoring system that require recertification include replacement of the analyzer, complete replacement of an existing continuous emission monitoring system, or change in location or orientation of the sampling probe or site.
(c) Approval process for initial certification and recertification. Paragraphs (3)(c)(A) through (D) of this rule apply to both initial certification and recertification of a continuous monitoring system under OAR 340-228-0609(1)(a). For recertifications, apply the word "recertification" instead of the words "certification" and "initial certification" and apply the word "recertified" instead of the word "certified," and follow the procedures in 40 CFR 75.20(b)(5) in lieu of the procedures in paragraph (3)(c)(E) of this rule.
(A) Notification of certification. The owner or operator must submit to the Department written notice of the dates of certification testing, in accordance with 40 CFR 75.61.
(B) Certification application. The owner or operator must submit to the Department a certification application for each monitoring system. A complete certification application must include the information specified in 40 CFR 75.63.
(C) Provisional certification date. The provisional certification date for a monitoring system must be determined in accordance with 40 CFR 75.20(a)(3). A provisionally certified monitoring system may be used for a period not to exceed 120 days after receipt by the Department of the complete certification application for the monitoring system under paragraph (3)(c)(B) of this rule. Data measured and recorded by the provisionally certified monitoring system will be considered valid quality-assured data (retroactive to the date and time of provisional certification), provided that the Department does not invalidate the provisional certification by issuing a notice of disapproval within 120 days of the date of receipt of the complete certification application by the Department.
(D) Certification application approval process. The Department will issue a written notice of approval or disapproval of the certification application to the owner or operator within 120 days of receipt of the complete certification application under paragraph (3)(c)(B) of this rule. In the event the Department does not issue such a notice within such 120-day period, each monitoring system that meets the applicable performance requirements and is included in the certification application will be deemed certified for use.
(i) Approval notice. If the certification application is complete and shows that each monitoring system meets the applicable performance requirements, then the Department will issue a written notice of approval of the certification application within 120 days of receipt.
(ii) Incomplete application notice. If the certification application is not complete, then the Department will issue a written notice of incompleteness that sets a reasonable date by which the owner or operator must submit the additional information required to complete the certification application. If the owner or operator does not comply with the notice of incompleteness by the specified date, then the Department may issue a notice of disapproval under subparagraph (3)(c)(D)(iii) of this rule. The 120-day review period must not begin before receipt of a complete certification application.
(iii) Disapproval notice. If the certification application shows that any monitoring system does not meet the performance requirements or if the certification application is incomplete and the requirement for disapproval under subparagraph (3)(c)(D)(ii) of this rule is met, then the Department will issue a written notice of disapproval of the certification application. Upon issuance of such notice of disapproval, the provisional certification is invalidated by the Department and the data measured and recorded by each uncertified monitoring system must not be considered valid quality-assured data beginning with the date and hour of provisional certification (as defined under 40 CFR 75.20(a)(3)). The owner or operator must follow the procedures for loss of certification in paragraph (3)(c)(E) of this rule for each monitoring system that is disapproved for initial certification.
(iv) Audit decertification. The Department may issue a notice of disapproval of the certification status of a monitor in accordance with OAR 340-228-0629(2).
(E) Procedures for loss of certification. If the Department issues a notice of disapproval of a certification application under subparagraph (3)(c)(D)(iii) of this rule or a notice of disapproval of certification status under subparagraph (3)(c)(D)(iv) of this rule, then:
(i) The owner or operator must substitute the following values, as applicable, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under 40 CFR 75.20(a)(4)(iii), 40 CFR 75.21(e) and continuing until such time, date, and hour as the continuous emission monitoring system can be adjusted, repaired, or replaced and certification tests successfully completed (or, if the conditional data validation procedures in 40 CFR 75.20(b)(3)(ii) through (ix) are used, until a probationary calibration error test is passed following corrective actions in accordance with 40 CFR 75.20(b)(3)(ii)):
(I) For a disapproved Hg pollutant concentration monitor and disapproved flow monitor, respectively, the maximum potential Hg concentration, as defined in OAR 340-228-0602(25), and the maximum potential flow rate, as defined in section 2.1.4.1 of appendix A to 40 CFR part 75; and
(II) For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO2 concentration or the minimum potential O2 concentration (as applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of appendix A to 40 CFR part 75.
(III) For a disapproved excepted monitoring system (sorbent trap monitoring system) and disapproved flow monitor, respectively, the maximum potential Hg concentration, as defined in OAR 340-228-0602(25), and maximum potential flow rate, as defined in section 2.1.4.1 of appendix A to 40 CFR part 75.
(ii) The owner or operator must submit a notification of certification retest dates as specified in 40 CFR 75.61(a)(1)(ii) and a new certification application in accordance with paragraphs (3)(c)(A) and (B) of this rule.
(iii) The owner or operator must repeat all certification tests or other requirements that were failed by the monitoring system, as indicated in the Department's notice of disapproval, no later than 30 unit operating days after the date of issuance of the notice of disapproval.
(d) For each Hg concentration monitoring system, the owner or operator must perform the following tests for initial certification or recertification of a Hg continuous emission system:
(A) A 7-day calibration error test in accordance with section 6.3 of appendix A to 40 CFR part 75. The owner or operator may perform this test using either elemental Hg standards or a NIST-traceable source of oxidized Hg. The calibration error of a Hg concentration monitor must not deviate from the reference value of either the zero or upscale calibration gas by more than 5.0 percent of the span value, as calculated using Equation A–5 of appendix A to 40 CFR part 75. Alternatively, if the span value is 10 μg/scm, the calibration error test results are also acceptable if the absolute value of the difference between the monitor response value and the reference value, |R–A| in Equation A–5 of appendix A to 40 CFR part 75, is ≤ 1.0 μg/scm.
(B) A linearity check in accordance with section 6.2 of appendix A to 40 CFR part 75. Design and equip each mercury monitor to permit the introduction of known concentrations of elemental Hg and HgCl2 separately, at a point immediately preceding the sample extraction filtration system, such that the entire measurement system can be checked. If the Hg monitor does not have a converter, the HgCl2 injection capability is not required. Follow the applicable procedures in section 6.2 of appendix A to 40 CFR part 75 when performing the 3-level system integrity checks described in paragraph (3)(d)(F) of this rule. Perform this check with elemental Hg standards.
(C) A relative accuracy test audit (RATA) in accordance with section 6.5 of appendix A to 40 CFR part 75 and as follows:
(i) The RATA must be performed on a µg/scm basis and while the unit is combusting coal.
(ii) Calculate the relative accuracy, in accordance with section 7.3 or 7.4 of appendix A to 40 CFR part 75, as applicable.
(iii) The relative accuracy shall not exceed 20.0 percent. Alternatively, for affected units where the average of the reference method measurements of Hg concentration during the relative accuracy test audit is less than 5.0 μg/scm, the test results are acceptable if the difference between the mean value of the monitor measurements and the reference method mean value does not exceed 1.0 μg/scm, in cases where the relative accuracy specification of 20.0 percent is not achieved.
(iv) For the RATA of a Hg CEMS using the Ontario Hydro Method, or for the RATA of a sorbent trap system (irrespective of the reference method used), the time per run must be long enough to collect a sufficient mass of Hg to analyze. For the RATA of a sorbent trap monitoring system, use the same-size trap that is used for daily operation of the monitoring system. Spike the third section of each sorbent trap with elemental Hg, as described in OAR 340-228-0627(7)(a)(B). Install a new pair of sorbent traps prior to each test run. For each run, the sorbent trap data must be validated according to the quality assurance criteria in OAR 340-228-0627(8).
(v) Use the same traverse points that are used for the gas monitor RATAs.
(D) A bias test in accordance with section 7.6 of appendix A to 40 CFR part 75 and as follows:
(i) For multiple-load flow RATAs, perform a bias test at each load level designated as normal under section 6.5.2.1 of appendix A to 40 CFR part 75.
(ii) Mercury concentration monitoring systems and sorbent trap monitoring systems shall not be biased low.
(iii) For Hg concentration and sorbent trap monitoring systems, where the average Hg concentration during the RATA is < 5.0 μg/dscm, if the monitoring system meets the normal or the alternative relative accuracy specification in subparagraph (3)(d)(C)(iii) of this rule but fails the bias test, the owner or operator may either use the bias adjustment factor (BAF) calculated from Equation A–12 appendix A to 40 CFR part 75 and in accordance with sections 7.6.4 and 7.6.5 of appendix A to 40 CFR part 75, using the data from the relative accuracy test audits, or may use a default BAF of 1.250 for reporting purposes.
(E) A cycle time test in accordance to section 6.4 of appendix A to 40 CFR part 75.
(F) A 3-level system integrity check, using a NIST traceable source of oxidized Hg. This test is not required for an Hg monitor that does not have a converter. The system measurement error shall not exceed 5.0 percent of the span value at any of the three gas levels.
(4) Certification/recertification procedures for alternative monitoring systems. The owner or operator of each unit for which the owner or operator intends to use an alternative monitoring system approved by the Department must comply with the applicable notification and application procedures of 40 CFR 75.20(f).
Monitoring Quality Assurance/Quality Control
340-228-0623
Quality Assurance and Quality Control Requirements
(1) For units that use continuous emission monitoring systems to account for Hg mass emissions, the owner or operator must meet the applicable quality assurance and quality control requirements in 40 CFR 75.21, appendix B to 40 CFR part 75, and as follows, for the flow monitoring systems, Hg concentration monitoring systems, moisture monitoring systems, and diluent monitors required under OAR 340-228-0613. Units using sorbent trap monitoring systems must meet the applicable quality assurance requirements in OAR 340-228-0617, 340-228-0627, and as follows.
(a) Calibration Error Test. Except as provided in section 2.1.1.2 of appendix B to 40 CFR part 75, perform the daily calibration error test of each Hg monitoring system according to the procedures in OAR 340-228-0621(3)(d)(A). For Hg monitors, the daily assessments may be made using either elemental Hg standards or a NIST-traceable source of oxidized Hg.
(b) Data Validation. For a Hg monitor, an out-of-control period occurs when the calibration error exceeds 5.0% of the span value. Notwithstanding, the Hg monitor shall not be considered out-of-control if |R–A| in Equation A–6 of appendix A to 40 CFR part 75 does not exceed 1.0 μg/scm.
(c) Linearity Check. Unless a particular monitor (or monitoring range) is exempted under this subsection or under section 6.2 of appendix A to 40 CFR part 75, perform a linearity check, in accordance with the procedures in section 6.2 of appendix A to 40 CFR part 75, for each primary and redundant backup Hg at least once during each QA operating quarter, as defined in 40 CFR 72.2. For Hg monitors, perform the linearity checks using elemental Hg standards. Alternatively, you may perform 3-level system integrity checks at the same three calibration gas levels (i.e., low, mid, and high), using a NIST-traceable source of oxidized Hg. If choosing this option, the performance specification in paragraph (1)(i)(B) of this rule must be met at each gas level. For units using both a low and high span value, a linearity check is required only on the range(s) used to record and report emission data during the QA operating quarter. Conduct the linearity checks no less than 30 days apart, to the extent practicable.
(d) Standard RATA Frequencies. For each primary and redundant backup Hg concentration monitoring system and each sorbent trap monitoring system, RATAs must be performed annually, i.e., once every four successive QA operating quarters (as defined in 40 CFR 72.2).
(e) RATA Load (or Operating) Levels and Additional RATA Requirements. For Hg concentration monitoring systems and sorbent trap monitoring systems, the required semiannual or annual RATA tests must be done at the load level (or operating level) designated as normal under section 6.5.2.1(d) of appendix A to 40 CFR part 75. If two load levels (or operating levels) are designated as normal, the required RATA(s) may be done at either load level (or operating level).
(f) Data Validation. Each time that a hands-off RATA of a Hg concentration monitoring system or a sorbent trap monitoring system is passed, perform a bias test in accordance with section 7.6.4 of appendix A to 40 CFR part 75. Apply the appropriate bias adjustment factor to the reported Hg data, in accordance with subsection (1)(g) of this rule.
(g) Bias Adjustment Factor. Except as otherwise specified in section 7.6.5 of appendix A to 40 CFR part 75, if an Hg concentration monitoring system or sorbent trap monitoring system fails the bias test, use the bias adjustment factor given in Equations A–11 and A–12 of appendix A to 40 CFR part 75, or a default bias adjustment factor of 1.250, to adjust the monitored data.
(h) Bias Adjusted Values. Use the bias-adjusted values in computing substitution values in the missing data procedure and in reporting the concentration of Hg during the quarter and calendar year. In addition, when using a Hg concentration or sorbent trap monitoring system and a flow monitor to calculate Hg mass emissions, use bias-adjusted values for Hg concentration and flow rate in the mass emission calculations and use bias-adjusted Hg concentrations to compute the appropriate substitution values for Hg concentration in the missing data routines.
(i) System Integrity Checks for Hg Monitors. For each Hg concentration monitoring system (except for a Hg monitor that does not have a converter), perform a single-point system integrity check weekly, i.e., at least once every 168 unit or stack operating hours, using a NIST-traceable source of oxidized Hg. Perform this check as follows using a mid- or high-level gas concentration, as defined in section 5.2 of appendix A to 40 CFR part 75.
(A) The performance specification in paragraph (1)(i)(B) must be met, otherwise the monitoring system is considered out-of-control until a subsequent system integrity check is passed. This weekly check is not required if the daily calibration assessments in subsection (1)(a) of this rule are performed using a NIST-traceable source of oxidized Hg.
(B) The error in linearity for each calibration gas concentration (low-, mid-, and high-levels) must not exceed or deviate from the reference value by more than 10.0 percent as calculated using equation A–4 of appendix A to 40 CFR part 75; or, the absolute value of the difference between the average of the monitor response values and the average of the reference values, |R–A| in equation A–4 of appendix A to 40 CFR part 75, must be less than or equal to 1.0 μg/scm, whichever is less restrictive.
(2) Missing data procedures. Except as provided in OAR 340-228-0617(11) and 340-228-0631(2), the owner or operator must provide substitute data from monitoring systems required under OAR 340-228-0613 for each affected unit as follows:
(a) For an owner or operator using an Hg concentration monitoring system, substitute for missing data in accordance with the applicable missing data procedures in 40 CFR 75.31 through 75.37 and OAR 340-228-0631 and 0633 whenever the unit combusts fuel and:
(A) A valid, quality-assured hour of Hg concentration data (in μg/scm) has not been measured and recorded, either by a certified Hg concentration monitoring system, by an appropriate reference method under OAR 340-228-0602(31) or 40 CFR 75.22, or by an approved alternative monitoring method under 40 CFR part 75 subpart E; or
(B) A valid, quality-assured hour of flow rate data (in scfh) has not been measured and recorded for a unit either by a certified flow monitor, by an appropriate EPA reference method under 40 CFR 75.22, or by an approved alternative monitoring system under 40 CFR part 75 subpart E; or
(C) A valid, quality-assured hour of moisture data (in percent H2O) has not been measured or recorded for an affected unit, either by a certified moisture monitoring system, by an appropriate EPA reference method under 40 CFR 75.22, or an approved alternative monitoring method under 40 CFR part 75 subpart E. This requirement does not apply when a default percent moisture value, as provided in 40 CFR 75.11(b) or 75.12(b), is used to account for the hourly moisture content of the stack gas, or when correction of the Hg concentration for moisture is not necessary; or
(D) A valid, quality-assured hour of heat input rate data (in MMBtu/hr) has not been measured and recorded for a unit, either by certified flow rate and diluent (CO2 or O2) monitors, by appropriate EPA reference methods under 40 CFR 75.22, or by approved alternative monitoring systems under 40 CFR part 75 subpart E.
(b) For an owner or operator using a sorbent trap monitoring system to quantify Hg mass emissions, substitute for missing data in accordance with the missing data procedures in OAR 340-228-0633.
CEMS Performance Specifications
340-228-0625
Specifications and Test Procedures for Total Vapor Phase Mercury CEMS
(1) Analyte. Mercury (Hg), CAS No. 7439-97-6.
(2) Applicability.
(a) This specification is for evaluating the acceptability of total vapor phase Hg CEMS installed on the exit gases from fossil fuel fired boilers at the time of or soon after installation and whenever specified in the regulations. The Hg CEMS must be capable of measuring the total concentration in μg/m3 (regardless of speciation) of vapor phase Hg, and recording that concentration on a wet or dry basis.
(b) Particle bound Hg is not included in the measurements.
(c) This specification is not designed to evaluate an installed CEMS’s performance over an extended period of time nor does it identify specific calibration techniques and auxiliary procedures to assess the CEMS’s performance. The source owner or operator, however, is responsible to calibrate, maintain, and operate the CEMS properly.
(d) The Department may require the operator to conduct CEMS performance evaluations at other times besides the initial test to evaluate the CEMS performance.
(e) The owner or operator may conduct the performance evaluation of the Hg CEMS according to OAR 340-228-0621(3)(d), in lieu of following the procedures in this rule.
(3) Summary of Performance Specification. Procedures for measuring CEMS relative accuracy, measurement error and drift are outlined. CEMS installation and measurement location specifications, and data reduction procedures are included. Conformance of the CEMS with the Performance Specification is determined.
(4) Definitions.
(a) “Continuous Emission Monitoring System (CEMS)” means the total equipment required for the determination of a pollutant concentration. The system consists of the following major subsystems:
(A) “Sample Interface” means that portion of the CEMS used for one or more of the following: sample acquisition, sample transport, sample conditioning, and protection of the monitor from the effects of
the stack effluent.
(B) “Hg Analyzer” means that portion of the Hg CEMS that measures the total vapor phase Hg mass concentration and generates a proportional output.
(C) “Data Recorder” means that portion of the CEMS that provides a permanent electronic record of the analyzer output. The data recorder may provide automatic data reduction and CEMS control capabilities.
(b) “Span Value” means the upper limit of the intended Hg concentration measurement range. The span value is a value equal to two times the emission standard. Alternatively, the Hg span value(s) may be determined as follows:
(A) For each Hg monitor, determine a high span value, by rounding the maximum potential Hg concentration value from OAR 340-228-0602(25) upward to the next highest multiple of 10 μg/scm.
(B) For an affected unit equipped with an FGD system or a unit with add-on Hg emission controls, if the maximum expected Hg concentration value from OAR 340-228-0602(25) is less than 20 percent of the high span value from paragraph (4)(b)(A) of this rule, and if the high span value is 20 μg/scm or greater, define a second, low span value of 10 μg/scm.
(C) If only a high span value is required, set the full-scale range of the Hg analyzer to be greater than or equal to the span value.
(D) If two span values are required, the owner or operator may either:
(i) Use two separate (high and low) measurement scales, setting the range of each scale to be greater than or equal to the high or low span value, as appropriate; or
(ii) Quality-assure two segments of a single measurement scale.
(c) “Measurement Error (ME)” means the absolute value of the difference between the concentration indicated by the Hg analyzer and the known concentration generated by a reference gas, expressed as a percentage of the span value, when the entire CEMS, including the sampling interface, is challenged. An ME test procedure is performed to document the accuracy and linearity of the Hg CEMS at several points over the measurement range.
(d) “Upscale Drift (UD)” means the absolute value of the difference between the CEMS output response and an upscale Hg reference gas, expressed as a percentage of the span value, when the entire CEMS, including the sampling interface, is challenged after a stated period of operation during which no unscheduled maintenance, repair, or adjustment took place.
(e) “Zero Drift (ZD)” means the absolute value of the difference between the CEMS output response and a zero-level Hg reference gas, expressed as a percentage of the span value, when the entire CEMS, including the sampling interface, is challenged after a stated period of operation during which no unscheduled maintenance, repair, or adjustment took place.
(f) “Relative Accuracy (RA)” means the absolute mean difference between the pollutant concentration(s) determined by the CEMS and the value determined by the reference method (RM) plus the 2.5 percent error confidence coefficient of a series of tests divided by the mean of the RM tests. Alternatively, for low concentration sources, the RA may be expressed as the absolute value of the difference between the mean CEMS and RM values.
(5) Safety. The procedures required under this performance specification may involve hazardous materials, operations, and equipment. This performance specification may not address all of the safety problems associated with these procedures. It is the responsibility of the user to establish appropriate safety and health practices and determine the applicable regulatory limitations prior to performing these procedures. The CEMS user’s manual and materials recommended by the RM should be consulted for specific precautions to be taken.
(6) Equipment and Supplies.
(a) CEMS Equipment Specifications.
(A) Data Recorder Scale. The Hg CEMS data recorder output range must include zero and a high level value. The high level value must be approximately two times the Hg concentration corresponding to the emission standard level for the stack gas under the circumstances existing as the stack gas is sampled. A lower high level value may be used, provided that the measured values do not exceed 95 percent of the high level value. Alternatively, the owner or operator may set the full-scale range(s) of the Hg analyzer according to subsection (4)(b) of this rule.
(B) The CEMS design should also provide for the determination of calibration drift at a zero value (zero to 20 percent of the span value) and at an upscale value (between 50 and 100 percent of the high-level value).
(b) Reference Gas Delivery System. The reference gas delivery system must be designed so that the flowrate of reference gas introduced to the CEMS is the same at all three challenge levels specified in subsection (7)(a) of this rule and at all times exceeds the flow requirements of the CEMS.
(c) Other equipment and supplies, as needed by the applicable reference method used. See paragraph (8)(f)(B) of this rule.
(7) Reagents and Standards.
(a) Reference Gases. Reference gas standards are required for both elemental and oxidized Hg (Hg and mercuric chloride, HgCl2). The use of National Institute of Standards and Technology (NIST)-certified or NIST-traceable standards and reagents is required. The following gas concentrations are required.
(A) Zero-level. 0 to 20 percent of the span value.
(B) Mid-level. 50 to 60 percent of the span value.
(C) High-level. 80 to 100 percent of the span value.
(b) Reference gas standards may also be required for the reference methods. See paragraph (8)(f)(B) of this rule.
(8) Performance Specification (PS) Test Procedure.
(a) Installation and Measurement Location Specifications.
(A) CEMS Installation. Install the CEMS at an accessible location downstream of all pollution control equipment. Since the Hg CEMS sample system normally extracts gas from a single point in the stack, use a location that has been shown to be free of stratification for SO2 and NOX through concentration measurement traverses for those gases. If the cause of failure to meet the RA test requirement is determined to be the measurement location and a satisfactory correction technique cannot be established, the Administrator may require the CEMS to be relocated. Measurement locations and points or paths that are most likely to provide data that will meet the RA requirements are listed below.
(B) Measurement Location. The measurement location should be (1) at least two equivalent diameters downstream of the nearest control device, point of pollutant generation or other point at which a change of pollutant concentration may occur, and (2) at least half an equivalent diameter upstream from the effluent exhaust. The equivalent duct diameter is calculated as per appendix A to 40 CFR part 60, Method 1.
(C) Hg CEMS Sample Extraction Point. Use a sample extraction point (1) no less than 1.0 meter from the stack or duct wall, or (2) within the centroidal velocity traverse area of the stack or duct cross section.
(b) RM Measurement Location and Traverse Points. Refer to PS 2 of appendix B to 40 CFR part 60. The RM and CEMS locations need not be immediately adjacent.
(c) ME Test Procedure. The Hg CEMS must be constructed to permit the introduction of known concentrations of Hg and HgCl2 separately into the sampling system of the CEMS immediately preceding the sample extraction filtration system such that the entire CEMS can be challenged.
Sequentially inject each of the three reference gases (zero, mid-level, and high level) for each Hg species. Record the CEMS response and subtract the reference value from the CEMS value, and express the absolute value of the difference as a percentage of the span value. For each reference gas, the absolute value of the difference between the CEMS response and the reference value must not exceed 5 percent of the span value. If this specification is not met, identify and correct the problem before proceeding.
(d) UD Test Procedure.
(A) UD Test Period. While the affected facility is operating at more than 50 percent of normal load, or as specified in an applicable subpart, determine the magnitude of the UD once each day (at 24-hour intervals, to the extent practicable) for 7 consecutive unit operating days according to the procedure given in paragraphs (8)(d)(B) through (C) of this rule. The 7 consecutive unit operating days need not be 7 consecutive calendar days. Use either Hg0 or HgCl2 standards for this test.
(B) The purpose of the UD measurement is to verify the ability of the CEMS to conform to the established CEMS response used for determining emission concentrations or emission rates. Therefore, if periodic automatic or manual adjustments are made to the CEMS zero and response settings, conduct the UD test immediately before these adjustments, or conduct it in such a way that the UD can be determined.
(C) Conduct the UD test at either the mid-level or high-level point specified in subsection (7)(a) of this rule. Introduce the reference gas to the CEMS. Record the CEMS response and subtract the reference value from the CEMS value, and express the absolute value of the difference as a percentage of the span value. For the reference gas, the absolute value of the difference between the CEMS response and the reference value must not exceed 5 percent of the span value. If this specification is not met, identify and correct the problem before proceeding.
(e) ZD Test Procedure.
(A) ZD Test Period. While the affected facility is operating at more than 50 percent of normal load, or as specified in an applicable subpart, determine the magnitude of the ZD once each day (at 24-hour intervals, to the extent practicable) for 7 consecutive unit operating days according to the procedure given in paragraphs (8)(e)(B) through (C) of this rule. The 7 consecutive unit operating days need not be 7 consecutive calendar days. Use either nitrogen, air, Hg0, or HgCl2 standards for this test.
(B) The purpose of the ZD measurement is to verify the ability of the CEMS to conform to the established CEMS response used for determining emission concentrations or emission rates. Therefore, if periodic automatic or manual adjustments are made to the CEMS zero and response settings, conduct the ZD test immediately before these adjustments, or conduct it in such a way that the ZD can be determined.
(C) Conduct the ZD test at the zero level specified in subsection (7)(a) of this rule. Introduce the zero gas to the CEMS. Record the CEMS response and subtract the zero value from the CEMS value and express the absolute value of the difference as a percentage of the span value. For the zero gas, the absolute value of the difference between the CEMS response and the reference value must not exceed 5 percent of the span value. If this specification is not met, identify and correct the problem before proceeding.
(f) RA Test Procedure.
(A) RA Test Period. Conduct the RA test according to the procedure given in paragraphs (8)(f)(B) through (F) of this rule while the affected facility is operating at normal full load, or as specified in an applicable subpart. The RA test may be conducted during the ZD and UD test period.
(B) RM. Use one of the reference methods specified in OAR 340-228-0602(31). Do not include the filterable portion of the sample when making comparisons to the CEMS results. When Method 29 or ASTM D6784–02 is used, conduct the RM test runs with paired or duplicate sampling systems. When an approved instrumental method is used, paired sampling systems are not required. If the RM and CEMS measure on a different moisture basis, data derived with Method 4 in appendix A to 40 CFR part 60 must also be obtained during the RA test.
(C) Sampling Strategy for RM Tests. Conduct the RM tests in such a way that they will yield results representative of the emissions from the source and can be compared to the CEMS data. It is preferable
to conduct moisture measurements (if needed) and Hg measurements simultaneously, although moisture measurements that are taken within an hour of the Hg measurements may be used to adjust the Hg concentrations to a consistent moisture basis. In order to correlate the CEMS and RM data properly, note the beginning and end of each RM test period for each paired RM run (including the exact time of day) on the CEMS chart recordings or other permanent record of output.
(D) Number and length of RM Tests. Conduct a minimum of nine RM test runs. When Method 29 or ASTM D6784–02 is used, only test runs for which the data from the paired RM trains meet the relative deviation (RD) criteria of this PS must be used in the RA calculations. In addition, for Method 29 and ASTM D 6784–02, use a minimum sample run time of 2 hours. Note: More than nine sets of RM tests may be performed. If this option is chosen, paired RM test results may be excluded so long as the total number of paired RM test results used to determine the CEMS RA is greater than or equal to nine. However, all data must be reported, including the excluded data.
(E) Correlation of RM and CEMS Data. Correlate the CEMS and the RM test data as to the time and duration by first determining from the CEMS final output (the one used for reporting) the integrated average pollutant concentration for each RM test period. Consider system response time, if important, and confirm that the results are on a consistent moisture basis with the RM test. Then, compare each integrated CEMS value against the corresponding RM value. When Method 29 or ASTM D6784–02 is used, compare each CEMS value against the corresponding average of the paired RM values.
(F) Paired RM Outliers.
(i) When Method 29 or ASTM D6784–02 is used, outliers are identified through the determination of relative deviation (RD) of the paired RM tests. Data that do not meet this criteria should be flagged as a data quality problem. The primary reason for performing paired RM sampling is to ensure the quality of the RM data. The percent RD of paired data is the parameter used to quantify data quality. Determine RD for two paired data points as follows:
RD=100 x |(Ca−Cb)|/(Ca+ Cb)
where Ca and Cb are concentration values determined from each of the two samples respectively.
(ii) A minimum performance criteria for RM Hg data is that RD for any data pair must be ≤10 percent as long as the mean Hg concentration is greater than 1.0 μg/m3. If the mean Hg concentration is less than or equal to 1.0 μg/m3, the RD must be ≤20 percent. Pairs of RM data exceeding these RD criteria should be eliminated from the data set used to develop a Hg CEMS correlation or to assess CEMS RA.
(G) Calculate the mean difference between the RM and CEMS values in the units of micrograms per cubic meter (μg/m3), the standard deviation, the confidence coefficient, and the RA according to the procedures in section (10) of this rule.
(f) Reporting. At a minimum (check with the Department for additional requirements, if any), summarize in tabular form the results of the RD tests and the RA tests or alternative RA procedure, as appropriate. Include all data sheets, calculations, charts (records of CEMS responses), reference gas concentration certifications, and any other information necessary to confirm that the performance of the CEMS meets the performance criteria.
(9) Analytical Procedure. Sample collection and analysis are concurrent for this PS (see section (8) of this rule). Refer to the RM employed for specific analytical procedures.
(10) Calculations and Data Analysis. Summarize the results on a data sheet similar to that shown in Figure 2–2 for PS 2.
(a) Consistent Basis. All data from the RM and CEMS must be compared in units of μg/m3, on a consistent and identified moisture and volumetric basis (STP = 20oC, 760 millimeters (mm) Hg).
(b) Moisture Correction (as applicable). If the RM and CEMS measure Hg on a different moisture basis, using the following equation to make the appropriate corrections to the Hg concentrations.
Concentration(dry) = Concentration(wet)/(1−Bws)
In the above equation, Bws is the moisture content of the flue gas from Method 4, expressed as a decimal fraction (e.g., for 8.0 percent H2O, Bws = 0.08).
(c) Arithmetic Mean. Calculate the arithmetic mean of the difference, d, of a data set using equation 1 to this division.
(d) Standard Deviation. Calculate the standard deviation, Sd, using equation 2 to this division.
(e) Confidence Coefficient (CC). Calculate the 2.5 percent error confidence coefficient (one-tailed), CC, using equation 3 to this division:
(f) RA. Calculate the RA of a set of data using equation 4 to this division:
(11) Performance Specifications.
(a) ME. ME is assessed at zero-level, mid-level and high-level values as given below using standards for both Hg0 and HgCl2. The mean difference between the indicated CEMS concentration and the reference concentration value for each standard must be no greater than 5 percent of the span value.
(b) UD. The UD must not exceed 5 percent of the span value on any of the 7 days of the UD test.
(c)ZD. The ZD must not exceed 5 percent of the span value on any of the 7 days of the ZD test.
(d) RA. The RA of the CEMS must be no greater than 20 percent of the mean value of the RM test data in terms of units of μg/m3. Alternatively, if the mean RM is less than 5.0 μg/m3, the results are acceptable if the absolute value of the difference between the mean RM and CEMS values does not exceed 1.0 μg/m3.
(12) Bibliography.
(a) 40 CFR part 60, appendix B, ‘‘Performance Specification 2—Specifications and Test Procedures for SO2 and NOX Continuous Emission Monitoring Systems in Stationary Sources.’’
(b) 40 CFR part 60, appendix A, ‘‘Method 29—Determination of Metals Emissions from Stationary Sources.’’
(c) ASTM Method D6784–02, ‘‘Standard Test Method for Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro Method).’’
(13) The following values are already corrected for n–1 degrees of freedom. Use n equal to the number of individual values.
(a) For n = 2, t0.975 = 12.706.
(b) For n = 3, t0.975 = 4.303.
(c) For n = 4, t0.975 = 3.182.
(d) For n = 5, t0.975 = 2.776.
(e) For n = 6, t0.975 = 2.571.
(f) For n = 7, t0.975 = 2.447.
(g) For n = 8, t0.975 = 2.365.
(h) For n = 9, t0.975 = 2.306.
(i) For n = 10, t0.975 = 2.262.
(j) For n = 11, t0.975 = 2.228.
(k) For n = 12, t0.975 = 2.201.
(l) For n = 13, t0.975 = 2.179.
(m) For n = 14, t0.975 = 2.160.
(n) For n = 15, t0.975 = 2.145.
(o) For n = 16, t0.975 = 2.131.
Sorbent Trap Sampling Procedures
340-228-0627
Quality Assurance and Operating Procedures for Sorbent Trap Monitoring Systems
(1) Scope and Application. This rule specifies sampling, and analytical, and quality-assurance criteria and procedures for the performance-based monitoring of vapor-phase mercury (Hg) emissions in combustion flue gas streams, using a sorbent trap monitoring system (as defined in OAR 340-228-0602). The principle employed is continuous sampling using in-stack sorbent media coupled with analysis of the integrated samples. The performance-based approach of this rule allows for use of various suitable sampling and analytical technologies while maintaining a specified and documented level of data quality through performance criteria. Persons using this rule should have a thorough working knowledge of Methods 1, 2, 3, 4 and 5 in appendices A–1 through A–3 to 40 CFR part 60, as well as the determinative technique selected for analysis.
(a) Analytes. 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, in mass concentration units of micrograms per dry standard cubic meter (μg/dscm).
(b) Applicability. These performance criteria and procedures are applicable to monitoring of vapor-phase Hg emissions under relatively low-dust conditions (i.e., sampling in the stack after all pollution control devices), from coal-fired electric utility steam generators. Individual sample collection times can range from 30 minutes to several days in duration, depending on the Hg concentration in the stack. The monitoring system must achieve the performance criteria specified in section (8) of this rule and the sorbent media capture ability must not be exceeded. The sampling rate must be maintained at a constant proportion to the total stack flowrate to ensure representativeness of the sample collected. Failure to achieve certain performance criteria will result in invalid Hg emissions monitoring data.
(2) Principle. Known volumes of flue gas are extracted from a stack or duct through paired, in-stack, pre-spiked sorbent media traps at an appropriate nominal flow rate. Collection of Hg on the sorbent media in the stack mitigates potential loss of Hg during transport through a probe/sample line. Paired train sampling is required to determine measurement precision and verify acceptability of the measured emissions data. The sorbent traps are recovered from the sampling system, prepared for analysis, as needed, and analyzed by any suitable determinative technique that can meet the performance criteria. A section of each sorbent trap is spiked with Hg0 prior to sampling. This section is analyzed separately and the recovery value is used to correct the individual Hg sample for measurement bias.
(3) Clean Handling and Contamination. To avoid Hg contamination of the samples, special attention should be paid to cleanliness during transport, field handling, sampling, recovery, and laboratory analysis, as well as during preparation of the sorbent cartridges. Collection and analysis of blank samples (field, trip, lab) is useful in verifying the absence of contaminant Hg.
(4) Safety.
(a) Site hazards. Site hazards must be thoroughly considered in advance of applying these procedures/specifications in the field; advance coordination with the site is critical to understand the conditions and applicable safety policies. At a minimum, portions of the sampling system will be hot, requiring appropriate gloves, long sleeves, and caution in handling this equipment.
(b) Laboratory safety policies. Laboratory safety policies should be in place to minimize risk of chemical exposure and to properly handle waste disposal. Personnel must wear appropriate laboratory attire according to a Chemical Hygiene Plan established by the laboratory.
(c) Toxicity or carcinogenicity. The toxicity or carcinogenicity of any reagents used must be considered. Depending upon the sampling and analytical technologies selected, this measurement may involve hazardous materials, operations, and equipment and this rule does not address all of the safety problems associated with implementing this approach. It is the responsibility of the user to establish appropriate safety and health practices and determine the applicable regulatory limitations prior to performance. Any chemical should be regarded as a potential health hazard and exposure to these compounds should be minimized. Chemists should refer to the Material Safety Data Sheet (MSDS) for each chemical used.
(d) Wastes. Any wastes generated by this procedure must be disposed of according to a hazardous materials management plan that details and tracks various waste streams and disposal procedures.
(5) Equipment and Supplies. The following list is presented as an example of key equipment and supplies likely required to perform vapor-phase Hg monitoring using a sorbent trap monitoring system. It is recognized that additional equipment and supplies may be needed. Collection of paired samples is required. Also required are a certified stack gas volumetric flow monitor that meets the requirements of 40 CFR 75.10 and an acceptable means of correcting for the stack gas moisture content, i.e., either by using data from a certified continuous moisture monitoring system or by using an approved default moisture value (see 40 CFR 75.11(b) and 75.12(b)).
(a) Sorbent Trap Monitoring System. The monitoring system must include the following components:
(A) Sorbent Traps. The sorbent media used to collect Hg must be configured in a trap with three distinct and identical segments or sections, connected in series, that are amenable to separate analyses. Section 1 is designated for primary capture of gaseous Hg. Section 2 is designated as a backup section for determination of vapor-phase Hg breakthrough. Section 3 is designated for QA/QC purposes where this section must be spiked with a known amount of gaseous Hg0 prior to sampling and later analyzed to determine recovery efficiency. The sorbent media may be any collection material (e.g., carbon, chemically-treated filter, etc.) capable of quantitatively capturing and recovering for subsequent analysis, all gaseous forms of Hg for the intended application. Selection of the sorbent media must be based on the material’s ability to achieve the performance criteria contained in section (8) of this rule as well as the sorbent’s vapor phase Hg capture efficiency for the emissions matrix and the expected sampling duration at the test site. The sorbent media must be obtained from a source that can demonstrate the quality assurance and control necessary to ensure consistent reliability. The paired sorbent traps are supported on a probe (or probes) and inserted directly into the flue gas stream.
(B) Sampling Probe Assembly. Each probe assembly must have a leak-free attachment to the sorbent trap(s). Each sorbent trap must be mounted at the entrance of or within the probe such that the gas sampled enters the trap directly. Each probe/sorbent trap assembly must be heated to a temperature sufficient to prevent liquid condensation in the sorbent trap(s). Auxiliary heating is required only where the stack temperature is too low to prevent condensation. Use a calibrated thermocouple to monitor the stack temperature. A single probe capable of operating the paired sorbent traps may be used. Alternatively, individual probe/sorbent trap assemblies may be used, provided that the individual sorbent traps are co-located to ensure representative Hg monitoring and are sufficiently separated to prevent aerodynamic interference.
(C) Moisture Removal Device. A robust moisture removal device or system, suitable for continuous duty (such as a Peltier cooler), must be used to remove water vapor from the gas stream prior to entering the dry gas meter.
(D) Vacuum Pump. Use a leak-tight, vacuum pump capable of operating within the candidate system’s flow range.
(E) Dry Gas Meter. A dry gas meter must be used to determine total sample volume. The meter must be sufficiently accurate to measure the total sample volume within 2 percent, must be calibrated at the selected flow rate and conditions actually encountered during sampling, and must be equipped with a temperature sensor capable of measuring typical meter temperatures accurately to within 3oC for correcting final sample volume.
(F) Sample Flow Rate Meter and Controller. Use a flow rate indicator and controller for maintaining necessary sampling flow rates.
(G) Temperature Sensor. Same as Section 6.1.1.7 of Method 5 in appendix A–3 to 40 CFR part 60.
(H) Barometer. Same as Section 6.1.2 of Method 5 in appendix A–3 to 40 CFR part 60.
(I) Data Logger (Optional). Device for recording associated and necessary ancillary information (e.g., temperatures, pressures, flow, time, etc.).
(b) Gaseous Hg0 Sorbent Trap Spiking System. A known mass of gaseous Hg0 must be spiked onto section 3 of each sorbent trap prior to sampling. Any approach capable of quantitatively delivering known masses of Hg0 onto sorbent traps is acceptable. Several technologies or devices are available to meet this objective. Their practicality is a function of Hg mass spike levels. For low levels, NIST-certified or NIST-traceable gas generators or tanks may be suitable, but will likely require long preparation times. A more practical, alternative system, capable of delivering almost any mass required, makes use of NIST-certified or NIST-traceable Hg salt solutions (e.g., Hg(NO3)2). With this system, an aliquot of known volume and concentration is added to a reaction vessel containing a reducing agent (e.g., stannous chloride); the Hg salt solution is reduced to Hg0 and purged onto section 3 of the sorbent trap using an impinger sparging system.
(c) Sample Analysis Equipment. Any analytical system capable of quantitatively recovering and quantifying total gaseous Hg from sorbent media is acceptable provided that the analysis can meet the performance criteria in section (8) of this rule. Candidate recovery techniques include leaching, digestion, and thermal desorption. Candidate analytical techniques include ultraviolet atomic fluorescence (UV AF); ultraviolet atomic absorption (UV AA), with and without gold trapping; and in situ X-ray fluorescence (XRF) analysis.
(6) Reagents and Standards. Only NIST-certified or NIST-traceable calibration gas standards and reagents must be used for the tests and procedures required under this rule.
(7) Sample Collection and Transport.
(a) Pre-Test Procedures.
(A) Selection of Sampling Site. Sampling site information should be obtained in accordance with Method 1 in appendix A–1 to 40 CFR part 60. Identify a monitoring location representative of source Hg emissions. Locations shown to be free of stratification through measurement traverses for gases such as SO2 and NOX may be one such approach. An estimation of the expected stack Hg concentration is required to establish a target sample flow rate, total gas sample volume, and the mass of Hg0 to be spiked onto section 3 of each sorbent trap.
(B) Pre-Sampling Spiking of Sorbent Traps. Based on the estimated Hg concentration in the stack, the target sample rate and the target sampling duration, calculate the expected mass loading for section 1 of each sorbent trap (for an example calculation, see subsection (12)(a) of this rule). The pre-sampling spike to be added to section 3 of each sorbent trap must be within + 50 percent of the expected section 1 mass loading. Spike section 3 of each sorbent trap at this level, as described in subsection (5)(b) of this rule. For each sorbent trap, keep an official record of the mass of Hg0 added to section 3. This record must include, at a minimum, the ID number of the trap, the date and time of the spike, the name of the analyst performing the procedure, the mass of Hg0 added to section 3 of the trap (μg), and the supporting calculations. This record must be maintained in a format suitable for inspection and audit and must be made available to the regulatory agencies upon request.
(C) Pre-test Leak Check. Perform a leak check with the sorbent traps in place. Draw a vacuum in each sample train. Adjust the vacuum in the sample train to +15″ Hg. Using the dry gas meter, determine leak rate. The leakage rate must not exceed 4 percent of the target sampling rate. Once the leak check passes this criterion, carefully release the vacuum in the sample train then seal the sorbent trap inlet until the probe is ready for insertion into the stack or duct.
(D) Determination of Flue Gas Characteristics. Determine or measure the flue gas measurement environment characteristics (gas temperature, static pressure, gas velocity, stack moisture, etc.) in order to determine ancillary requirements such as probe heating requirements (if any), initial sample rate, proportional sampling conditions, moisture management, etc.
(b) Sample Collection.
(A) Remove the plug from the end of each sorbent trap and store each plug in a clean sorbent trap storage container. Remove the stack or duct port cap and insert the probe(s). Secure the probe(s) and ensure that no leakage occurs between the duct and environment.
(B) Record initial data including the sorbent trap ID, start time, starting dry gas meter readings, initial temperatures, setpoints, and any other appropriate information.
(C) Flow Rate Control. Set the initial sample flow rate at the target value from paragraph (7)(a)(A) of this rule. Record the initial dry gas meter reading, stack temperature, meter temperatures, etc. Then, for every operating hour during the sampling period, record the date and time, the sample flow rate, the gas meter reading, the stack temperature, the flow meter temperatures, temperatures of heated equipment such as the vacuum lines and the probes (if heated), and the sampling system vacuum readings. Also record the stack gas flow rate, as measured by the certified flow monitor, and the ratio of the stack gas flow rate to the sample flow rate. Adjust the sampling flow rate to maintain proportional sampling, i.e., keep the ratio of the stack gas flow rate to sample flow rate constant, to within + 25 percent of the reference ratio from the first hour of the data collection period (see section (11) of this rule).
(D) Stack Gas Moisture Determination. Determine stack gas moisture using a continuous moisture monitoring system, as described in 40 CFR 75.11(b) or 75.12(b). Alternatively, the owner or operator may use the appropriate fuel-specific moisture default value provided in 40 CFR 75.11 or 75.12, or a site specific moisture default value approved by petition under 40 CFR 75.66.
(E) Essential Operating Data. Obtain and record any essential operating data for the facility during the test period, e.g., the barometric pressure must be obtained for correcting sample volume to standard conditions. At the end of the data collection period, record the final dry gas meter reading and the final values of all other essential parameters.
(F) Post Test Leak Check. When sampling is completed, turn off the sample pump, remove the probe/sorbent trap from the port and carefully re-plug the end of each sorbent trap. Perform a leak check with the sorbent traps in place, at the maximum vacuum reached during the sampling period. Use the same general approach described in paragraph (7)(a)(C) of this rule. Record the leakage rate and vacuum. The leakage rate must not exceed 4 percent of the average sampling rate for the data collection period. Following the leak check, carefully release the vacuum in the sample train.
(G) Sample Recovery. Recover each sampled sorbent trap by removing it from the probe, sealing both ends. Wipe any deposited material from the outside of the sorbent trap. Place the sorbent trap into an appropriate sample storage container and store/preserve in appropriate manner.
(H) Sample Preservation, Storage, and Transport. While the performance criteria of this approach provide for verification of appropriate sample handling, it is still important that the user consider, determine, and plan for suitable sample preservation, storage, transport, and holding times for these measurements. Therefore, procedures in ASTM D6911–03 ‘‘Standard Guide for Packaging and Shipping Environmental Samples for Laboratory Analysis’’ must be followed for all samples.
(I) Sample Custody. Proper procedures and documentation for sample chain of custody are critical to ensuring data integrity. The chain of custody procedures in ASTM D4840–99 (reapproved 2004) ‘‘Standard Guide for Sample Chain-of-Custody Procedures’’ must be followed for all samples (including field samples and blanks).
(8) Quality Assurance and Quality Control. The owner and operator using a sorbent trap monitoring system must develop and implement a quality assurance/quality control (QA/QC) program. At a minimum, include in each QA/QC program a written plan that describes in detail (or that refers to separate documents containing) complete, step-by-step procedures and operations. Upon request from the Department, the owner or operator must make all procedures, maintenance records, and ancillary supporting documentation from the manufacturer (e.g., software coefficients and troubleshooting diagrams) available for review during an audit. Electronic storage of the information in the QA/QC plan is permissible, provided that the information can be made available in hardcopy upon request during an audit. Table 2 to this division summarizes the QA/QC performance criteria that are used to validate the Hg emissions data from sorbent trap monitoring systems, including the relative accuracy test audit (RATA) requirement (see section 6.5.7 of appendix A to 40 CFR part 75 and section 2.3 of appendix B to 40 CFR part 75, except that for sorbent trap monitoring systems, RATAs must be performed annually, i.e., once every four successive QA operating quarters). The RATA must meet the requirements in OAR 340-228-0621(3)(d)(C)(iii). Except as provided in OAR 340-228-0617(8) and as otherwise indicated in Table 2 to this division, failure to achieve these performance criteria will result in invalidation of Hg emissions data.
(9) Quality Assurance and Quality Control Plan Content. In addition to section 1 of Appendix B to 40 CFR part 75, the QA/QC plan must contain the following:
(a) Sorbent Trap Identification and Tracking. Include procedures for inscribing or otherwise permanently marking a unique identification number on each sorbent trap, for tracking 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.
(b) Monitoring System Integrity and Data Quality. Explain the procedures used to perform the leak checks when a sorbent trap is placed in service and removed from service. Also explain the other QA procedures used to ensure system integrity and data quality, including, but not limited to, dry gas 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 section (8) of this rule.
(c) Hg Analysis. Explain the chain of custody employed in packing, transporting, and analyzing the sorbent traps (see paragraphs (7)(b)(H) and (I) of this rule). Keep records of all Hg analyses. The analyses must be performed in accordance with the procedures described in section (11) of this rule.
(d) Laboratory Certification. The QA Plan must include documentation that the laboratory performing the analyses on the carbon sorbent traps is certified by the International Organization for Standardization (ISO) to have a proficiency that meets the requirements of ISO 17025. Alternatively, if the laboratory performs the spike recovery study described in subsection (11)(c) of this rule and repeats that procedure annually, ISO certification is not required.
(10) Calibration and Standardization.
(a) Only NIST-certified and NIST-traceable calibration standards (i.e., calibration gases, solutions, etc.) must be used for the spiking and analytical procedures in this rule.
(b) Dry Gas Meter Calibration. Prior to its initial use, perform a full calibration of the metering system at three orifice settings to determine the average dry gas meter coefficient (Y), as described in section 10.3.1 of Method 5 in appendix A–3 to 40 CFR part 60. Thereafter, recalibrate the metering system quarterly at one intermediate orifice setting, as described in section 10.3.2 of Method 5 in appendix A–3 to 40 CFR part 60. If a quarterly recalibration shows that the value of Y has changed by more than 5 percent, repeat the full calibration of the metering system to determine a new value of Y.
(c) Thermocouples and Other Temperature Sensors. Use the procedures and criteria in section 10.3 of Method 2 in appendix A–1 to 40 CFR part 60 to calibrate in-stack temperature sensors and thermocouples. Dial thermometers must be calibrated against mercury-in-glass thermometers. Calibrations must be performed prior to initial use and at least quarterly thereafter. At each calibration point, the absolute temperature measured by the temperature sensor must agree to within + 1.5 percent of the temperature measured with the reference sensor, otherwise the sensor may not continue to be used.
(d) Barometer. Calibrate against a mercury barometer. Calibration must be performed prior to initial use and at least quarterly thereafter. At each calibration point, the absolute pressure measured by the barometer must agree to within + 10 mm Hg of the pressure measured by the mercury barometer, otherwise the barometer may not continue to be used.
(e) Other Sensors and Gauges. Calibrate all other sensors and gauges according to the procedures specified by the instrument manufacturer(s).
(f) Analytical System Calibration. See subsection (10)(a) of this rule.
(11) Analytical Procedures. The analysis of the Hg samples may be conducted using any instrument or technology capable of quantifying total Hg from the sorbent media and meeting the performance criteria in section (8) of this rule.
(a) Analyzer System Calibration. Perform a multipoint calibration of the analyzer at three or more upscale points over the desired quantitative range (multiple calibration ranges must be calibrated, if necessary). The field samples analyzed must fall within a calibrated, quantitative range and meet the necessary performance criteria. For samples that are suitable for aliquotting, a series of dilutions may be needed to ensure that the samples fall within a calibrated range. However, for sorbent media samples that are consumed during analysis (e.g., thermal desorption techniques), extra care must be taken to ensure that the analytical system is appropriately calibrated prior to sample analysis. The calibration curve range(s) should be determined based on the anticipated level of Hg mass on the sorbent media. Knowledge of estimated stack Hg concentrations and total sample volume may be required prior to analysis. The calibration curve for use with the various analytical techniques (e.g., UV AA, UV AF, and XRF) can be generated by directly introducing standard solutions into the analyzer or by spiking the standards onto the sorbent media and then introducing into the analyzer after preparing the sorbent/standard according to the particular analytical technique. For each calibration curve, the value of the square of the linear correlation coefficient, i.e., r2, must be ≥ 0.99, and the analyzer response must be within + 10 percent of reference value at each upscale calibration point. Calibrations must be performed on the day of the analysis, before analyzing any of the samples. Following calibration, an independently prepared standard (not from same calibration stock solution) must be analyzed. The measured value of the independently prepared standard must be within + 10 percent of the expected value.
(b) Sample Preparation. Carefully separate the three sections of each sorbent trap. Combine for analysis all materials associated with each section, i.e., any supporting substrate that the sample gas passes through prior to entering a media section (e.g., glass wool, polyurethane foam, etc.) must be analyzed with that segment.
(c) Spike Recovery Study. Before analyzing any field samples, the laboratory must demonstrate the ability to recover and quantify Hg from the sorbent media by performing the following spike recovery study for sorbent media traps spiked with elemental mercury. Using the procedures described in subsections (5)(b) and (11)(a) of this rule, spike the third section of nine sorbent traps with gaseous Hg0, i.e., three traps at each of three different mass loadings, representing the range of masses anticipated in the field samples. This will yield a 3 x 3 sample matrix. Prepare and analyze the third section of each spiked trap, using the techniques that will be used to prepare and analyze the field samples. The average recovery for each spike concentration must be between 85 and 115 percent. If multiple types of sorbent media are to be analyzed, a separate spike recovery study is required for each sorbent material. If multiple ranges are calibrated, a separate spike recovery study is required for each range.
(d) Field Sample Analyses. Analyze the sorbent trap samples following the same procedures that were used for conducting the spike recovery study. The three sections of the sorbent trap must be analyzed separately (i.e., section 1, then section 2, then section 3). Quantify the mass of total Hg for each section based on analytical system response and the calibration curve from subsection (10)(a) of this rule. Determine the spike recovery from sorbent trap section 3. Pre-sampling spike recoveries must be between 75 and 125 percent. To report final Hg mass, normalize the data for sections 1 and 2 based on the sample-specific spike recovery, and add the normalized masses together.
(12) Calculations and Data Analysis.
(a) Calculation of Pre-Sampling Spiking Level. Determine sorbent trap section 3 spiking level using estimates of the stack Hg concentration, the target sample flow rate, and the expected sample duration. First, calculate the expected Hg mass that will be collected in section 1 of the trap. The presampling spike must be within + 50 percent of this mass. Example calculation: For an estimated stack Hg concentration of 5 μg/m3, a target sample rate of 0.30 L/min, and a sample duration of 5 days:
(0.30 L/min) (1440 min/day) (5 days) (10-3 m3/liter) (5μg/m3) = 10.8 μg
A pre-sampling spike of 10.8 μg + 50 percent is, therefore, appropriate.
(b) Calculations for Flow-Proportional Sampling. For the first hour of the data collection period, determine the reference ratio of the stack gas volumetric flow rate to the sample flow rate, as follows:
Rref = K x Qref / Fref
Where:
Rref = Reference ratio of hourly stack gas flow rate to hourly sample flow rate
Qref = Average stack gas volumetric flow rate for first hour of collection period, adjusted for bias, if necessary according to section 7.6.5 of appendix A to 40 CFR part 75, (scfh)
Fref = Average sample flow rate for first hour of the collection period, in appropriate units (e.g., liters/min, cc/min, dscm/min)
K = Power of ten multiplier, to keep the value of Rref between 1 and 100. The appropriate K value will depend on the selected units of measure for the sample flow rate. Then, for each subsequent hour of the data collection period, calculate ratio of the stack gas flow rate to the sample flow rate using the following equation:
Rh = K x Qh / Fh
Where:
Rh = Ratio of hourly stack gas flow rate to hourly sample flow rate
Qh = Average stack gas volumetric flow rate for the hour, adjusted for bias, if necessary, according to section 7.6.5 of appendix A to 40 CFR part 75, (scfh)
Fh = Average sample flow rate for the hour, in appropriate units (e.g., liters/min, cc/min, dscm/min)
K = Power of ten multiplier, to keep the value of Rh between 1 and 100. The appropriate K value will depend on the selected units of measure for the sample flow rate and the range of expected stack gas flow rates.
Maintain the value of Rh within + 25 percent of Rref throughout the data collection period.
(c) Calculation of Spike Recovery. Calculate the percent recovery of each section 3 spike, as follows:
%R = (M3/Ms) x 100
Where:
%R = Percentage recovery of the presampling spike
M3 = Mass of Hg recovered from section 3 of the sorbent trap, (μg)
Ms = Calculated Hg mass of the pre-sampling spike, from paragraph (7)(a)(B) of this rule, (μg)
(d) Calculation of Breakthrough. Calculate the percent breakthrough to the second section of the sorbent trap, as follows:
%B = (M2/M1) x 100
Where:
%B = Percent breakthrough
M2 = Mass of Hg recovered from section 2 of the sorbent trap, (μg)
M1 = Mass of Hg recovered from section 1 of the sorbent trap, (μg)
(e) Normalizing Measured Hg Mass for Section 3 Spike Recoveries. Based on the results of the spike recovery in subsection (12)(c) of this rule, normalize the Hg mass collected in sections 1 and 2 of the sorbent trap, as follows:
M* = ((M1+M2) x Ms) / M3
Where:
M* = Normalized total mass of Hg recovered from sections 1 and of the sorbent trap, (μg)
M1 = Mass of Hg recovered from section 1 of the sorbent trap, unadjusted, (μg)
M2 = Mass of Hg recovered from section 2 of the sorbent trap, unadjusted, (μg)
Ms = Calculated Hg mass of the pre-sampling spike, from paragraph (7)(a)(B) of this rule, (μg)
M3 = Mass of Hg recovered from section 3 of the sorbent trap, (μg)
(f) Calculation of Hg Concentration. Calculate the Hg concentration for each sorbent trap, using the following equation:
C = M* / Vt
Where:
C = Concentration of Hg for the collection period, (μg/dscm)
M* = Normalized total mass of Hg recovered from sections 1 and 2 of the sorbent trap, (μg)
Vt = Total volume of dry gas metered during the collection period, (dscm). For the purposes of this rule, standard temperature and pressure are defined as 20oC and 760 mm Hg, respectively.
(g) Calculation of Paired Trap Agreement. Calculate the relative deviation (RD) between the Hg concentrations measured with the paired sorbent traps as follows:
RD = (|Ca – Cb| / (Ca + Cb)) x 100
Where:
RD = Relative deviation between the Hg concentrations from traps ‘‘a’’ and ‘‘b’’ (percent)
Ca = Concentration of Hg for the collection period, for sorbent trap ‘‘a’’ (μg/dscm)
Cb = Concentration of Hg for the collection period, for sorbent trap ‘‘b’’ (μg/dscm)
(h) Calculation of Hg Mass Emissions. To calculate Hg mass emissions, follow the procedures in OAR 340-228-0619(1)(b). Use the average of the two Hg concentrations from the paired traps in the calculations, except as provided in OAR 340-228-0617(8).
(13) Method Performance. These monitoring criteria and procedures have been applied to coal-fired utility boilers (including units with post-combustion emission controls), having vapor-phase Hg concentrations ranging from 0.03 μg/dscm to 100 μg/dscm.
Out of Control Periods
340-228-0629
Out of Control Periods and Adjustment for System Bias
(1) Whenever any monitoring system fails to meet the quality-assurance and quality-control requirements or data validation requirements of OAR 340-228-0623, data must be substituted using the applicable missing data procedures.
(2) Audit decertification. Whenever both an audit of a monitoring system and a review of the initial certification or recertification application reveal that any monitoring system should not have been certified or recertified because it did not meet a particular performance specification or other requirement under OAR 340-228-0621 or the applicable provisions of 40 CFR part 75, both at the time of the initial certification or recertification application submission and at the time of the audit, the Department will issue a notice of disapproval of the certification status of such monitoring system. For the purposes of this section, an audit must be either a field audit or an audit of any information submitted to the Department. By issuing the notice of disapproval, the Department revokes prospectively the certification status of the monitoring system. The data measured and recorded by the monitoring system must not be considered valid quality-assured data from the date of issuance of the notification of the revoked certification status until the date and time that the owner or operator completes subsequently approved initial certification or recertification tests for the monitoring system. The owner or operator must follow the applicable initial certification or recertification procedures in OAR 340-228-0621 for each disapproved monitoring system.
(3) When the bias test indicates that a flow monitor, a Hg concentration monitoring system or a sorbent trap monitoring system is biased low (i.e., the arithmetic mean of the differences between the reference method value and the monitor or monitoring system measurements in a relative accuracy test audit exceed the bias statistic), the owner or operator must adjust the monitor or continuous emission monitoring system to eliminate the cause of bias such that it passes the bias test or calculate and use the bias adjustment factor given in Equations A-11 and A-12 of appendix A to 40 CFR part 75, to adjust the monitored data.
Missing Data Procedure
340-228-0631
Standard Missing Data Procedures for Hg CEMS
(1) Once 720 quality assured monitor operating hours of Hg concentration data have been obtained following initial certification, the owner or operator must provide substitute data for Hg concentration in accordance with the procedures in 40 CFR 75.33(b)(1) through (b)(4) and Table 1 to this division, except that the term ‘‘Hg concentration’’ shall apply rather than ‘‘SO2 concentration,’’ the term ‘‘Hg concentration monitoring system’’ shall apply rather than ‘‘SO2 pollutant concentration monitor,’’ and the term ‘‘maximum potential Hg concentration, as defined in 340-228-0602(25)’’ shall apply, rather than ‘‘maximum potential SO2 concentration.’’
(2) For a unit equipped with a flue gas desulfurization (FGD) system that significantly reduces the concentration of Hg emitted to the atmosphere (including circulating fluidized bed units that use limestone injection), or for a unit equipped with add-on Hg emission controls (e.g., carbon injection), the standard missing data procedures in section (1) of this rule may only be used for hours in which the SO2 or Hg emission controls are documented to be operating properly, as described in OAR 340-228-0635(6). For any hour(s) in the missing data period for which this documentation is unavailable, the owner or operator must report, as applicable, the maximum potential Hg concentration, as defined in OAR 340-228-0602(25). In addition, under 40 CFR 75.64(c), the owner or operator must submit as part of each electronic quarterly report, a certification statement, verifying the proper operation of the SO2 or Hg emission controls for each missing data period in which the procedures in section (1) of this rule are applied.
(3) For units with FGD systems or add-on Hg controls, when the percent monitor data availability is less than 80.0 percent, and a missing data period occurs, the owner or operator may petition to report the maximum controlled Hg concentration in the previous 720 quality-assured monitor operating hours, consistent with 40 CFR 75.34(a)(3).
340-228-0633
Missing Data Procedures for Sorbent Trap Monitoring Systems
(1) If a sorbent trap monitoring system has not been certified by the applicable compliance date specified under OAR 340-228-0609(2), the owner or operator must report the maximum potential Hg concentration, as defined in OAR 340-228-0602(25), until the system is certified.
(2) For a certified sorbent trap system, a missing data period will occur whenever:
(a) A gas sample is not extracted from the stack (e.g. during a monitoring system malfunction or when the system undergoes maintenance); or
(b) The results of the Hg analysis for the paired sorbent traps are missing or invalid (as determined using the quality assurance procedures in OAR 340-228-0627). The missing data period begins with the hour in which the paired sorbent traps for which the Hg analysis is missing or invalid were put into service. The missing data period ends at the first hour in which valid Hg concentration data are obtained with another pair of sorbent traps (i.e., the hour at which this pair of traps was placed in service).
(3) Initial missing data procedures. Use these missing data procedures until 720 hours of quality-assured data have been collected with the sorbent trap monitoring system(s), following initial certification. For each hour of the missing data period, the substitute data value for Hg concentration shall be the average Hg concentration from all valid sorbent trap analyses to date, including data from the initial certification test runs.
(4) Standard missing data procedures. Once 720 quality-assured hours of data have been obtained with the sorbent trap system(s), begin reporting the percent monitor data availability in accordance with 40 CFR 75.32 and switch from the initial missing data procedures in section (3) of this rule to the following standard missing data procedures:
(a) If the percent monitor data availability (PMA) is ≥ 90.0 percent, report the average Hg concentration for all valid sorbent trap analyses in the previous 12 months.
(b) If the PMA is ≥ 80.0 percent, but < 90.0 percent, report the 95th percentile Hg concentration obtained from all of the valid sorbent trap analyses in the previous 12 months.
(c) If the PMA is ≥ 70.0 percent, but < 80.0 percent, report the maximum Hg concentration obtained from all of the valid sorbent trap analyses in the previous 12 months.
(d) If the PMA is < 70.0 percent, report the maximum potential Hg concentration, as defined in OAR 340-228-0602(25).
(e) For the purposes of subsections (4)(a), (b), and (c) of this rule, if fewer than 12 months have elapsed since initial certification, use whatever valid sorbent trap analyses are available to determine the appropriate substitute data values.
(5) Notwithstanding the requirements of sections (3) and (4) of this rule, if the unit has add-on Hg emission controls or is equipped with a flue gas desulfurization system that significantly reduces Hg emissions, the owner or operator must report the maximum potential Hg concentration, as defined in 340-228-0602(25), for any hour(s) in the missing data period for which proper operation of the Hg emission controls or FGD system is not documented according to OAR 340-228-0635(6).
Recordkeeping and Reporting
340-228-0635
Recordkeeping
(1) General recordkeeping provisions. The owner or operator of any coal-fired electric generating unit must maintain for each coal-fired electric generating unit and each non-affected unit under OAR 340-228-0615(2)(b)(B) a file of all measurements, data, reports, and other required information at the source in a form suitable for inspection for at least 5 years from the date of each record. Except for the certification data required in 40 CFR 75.57(a)(4) and the initial submission of the monitoring plan required in 40 CFR 75.57(a)(5), the data must be collected beginning with the earlier of the date of provisional certification or the compliance deadline in OAR 340-228-0609(2). The certification data required in 40 CFR 75.57(a)(4) must be collected beginning with the date of the first certification test performed. The file must contain the following information:
(a) The information required in 40 CFR 75.57(a)(2), (a)(4), (a)(5), (a)(6), (b), (c)(2), (g) (if applicable), (h), and sections (4) or (5) of this rule (as applicable).
(b) For coal-fired electric generating units using Hg CEMS or sorbent trap monitoring systems, for each hour when the unit is operating, record the Hg mass emissions, calculated in accordance with OAR 340-228-0619.
(c) Heat input and Hg methodologies for the hour.
(d) Formulas from monitoring plan for total Hg mass emissions and heat input rate (if applicable); and
(e) Laboratory calibrations of the source sampling equipment. For sorbent trap monitoring systems, the laboratory analyses of all sorbent traps, and information documenting the results of all leak checks and other applicable quality control procedures.
(f) Unless otherwise provided, the owners and operators of the coal-fired electric generating unit must keep on site at the source each of the following documents for a period of 5 years from the date the document is created. This period may be extended for cause, at any time before the end of 5 years, in writing by the Department.
(A) All emissions monitoring information, in accordance with OAR 340-228-0609 through 0637.
(B) Copies of all reports, compliance certifications, and other submissions.
(2) Certification, quality assurance, and quality control record provisions. The owner or operator of a coal-fired electric generating unit must maintain the information required in 40 CFR 75.59, including the following:
(a) For each Hg monitor, the owner or operator must record the information in 40 CFR 75.59(a)(1)(i) through (xi) for all daily and 7-day calibration error tests, all daily system integrity checks (Hg monitors, only), and all off-line calibration demonstrations, including any follow-up tests after corrective action.
(b) For each Hg concentration monitor, the owner or operator must record the information in 40 CFR 75.59(a)(3)(i) through (x) for the initial and all subsequent linearity check(s) and 3-level system integrity checks (Hg monitors with converters, only), including any follow-up tests after corrective action.
(c) For each Hg concentration monitoring system or sorbent trap monitoring system, the owner or operator must record the information in 40 CFR 75.59(a)(5)(i) and (iii) through (vii) for the initial and all subsequent relative accuracy test audits. The owner or operator must also record individual test run data from the relative accuracy test audit for the Hg concentration monitoring system or sorbent trap monitoring system, including the information in 40 CFR 75.59(a)(5)(ii)(A) through (M).
(d) For each Hg emissions concentration monitor, the owner or operator must record the information in 40 CFR 75.59(a)(6)(i) through (xi) for the cycle time test.
(e) The owner or operator must record, for each relative accuracy test audit run using the Ontario Hydro Method to determine Hg concentration:
(A) Percent CO2 and O2 in the stack gas, dry basis;
(B) Moisture content of the stack gas (percent H2O);
(C) Average stack temperature (oF);
(D)) Dry gas volume metered (dscm);
(E) Percent isokinetic;
(F) Particle-bound Hg collected by the filter, blank, and probe rinse (µg);
(G) Oxidized Hg collected by the KCl impingers (µg);
(H) Elemental Hg collected in the HNO3/H2O2 impinger and in the KMnO4/H2SO4 impingers (µg);
(I) Total Hg, including particle-bound Hg (µg); and
(J) Total Hg, excluding particle-bound Hg (µg).
(f) When hardcopy relative accuracy test reports, certification reports, recertification reports, or semiannual or annual reports for Hg CEMS or sorbent trap monitoring systems are required or requested under 40 CFR 75.60(b)(6) or 75.63, the reports must include, at a minimum, the elements in 40 CFR 75.59(a)(9)(i) through (ix) (as applicable to the type(s) of test(s) performed). For sorbent trap monitoring systems, the report must include laboratory analyses of all sorbent traps, and information documenting the results of all leak checks and other applicable quality control procedures.
(g) Except as otherwise provided in subsection (6)(a) of this rule, units with add-on Hg emission controls, the owner or operator must keep the records in 40 CFR 75.59(c)(1) through (2) on-site in the quality assurance/quality control plan.
(3) Monitoring plan recordkeeping provisions.
(a) General provisions. The owner or operator of a coal-fired electric generating unit must prepare and maintain a monitoring plan for each affected unit or group of units monitored at a common stack and each non coal-fired electric generating unit under OAR 340-228-0615(2)(b)(B). The monitoring plan must contain sufficient information on the continuous monitoring systems and the use of data derived from these systems to demonstrate that all the unit’s Hg emissions are monitored and reported.
(b) Updates. Whenever the owner or operator makes a replacement, modification, or change in a certified continuous monitoring system or alternative monitoring system under 40 CFR part 75 subpart E, including a change in the automated data acquisition and handling system or in the flue gas handling system, that affects information reported in the monitoring plan (e.g., a change to a serial number for a component of a monitoring system), then the owner or operator must update the monitoring plan.
(c) Contents of the monitoring plan. Each monitoring plan must contain the information in 40 CFR 75.53(e)(1) in electronic format and the information in 40 CFR 75.53(e)(2) in hardcopy format.
(4) Hg emission record provisions (CEMS). The owner or operator must record for each hour the information required by this section for each affected unit using Hg CEMS in combination with flow rate, and (in certain cases) moisture, and diluent gas monitors, to determine Hg mass emissions and (if applicable) unit heat input.
(a) For Hg concentration during unit operation, as measured and reported from each certified primary monitor, certified back-up monitor, or other approved method of emissions determination:
(A) Component-system identification code, as provided in 40 CFR 75.53;
(B) Date and hour;
(C) Hourly Hg concentration (μg/scm, rounded to the nearest tenth). For a particular pair of sorbent traps, this will be the flow-proportional average concentration for the data collection period;
(D) The bias-adjusted hourly average Hg concentration (μg/scm, rounded to the nearest hundredth) if a bias adjustment factor is required, as provided in OAR 340-228-0629(3);
(E) Method of determination for hourly Hg concentration using Codes 1–55 in Table 4a of 40 CFR 75.57; and
(F) The percent monitor data availability (to the nearest tenth of a percent), calculated pursuant to 40 CFR 75.32.
(b) For flue gas moisture content during unit operation (if required), as measured and reported from each certified primary monitor, certified back-up monitor, or other approved method of emissions determination (except where a default moisture value is used in accordance with 40 CFR 75.11(b), 40 CFR 75.12(b), or approved under 40 CFR 75.66):
(A) Component-system identification code, as provided in 40 CFR 75.53;
(B) Date and hour;
(C) Hourly average moisture content of flue gas (percent, rounded to the nearest tenth). If the continuous moisture monitoring system consists of wet- and dry-basis oxygen analyzers, also record both the wet- and dry-basis oxygen hourly averages (in percent O2, rounded to the nearest tenth);
(D) Percent monitor data availability (recorded to the nearest tenth of a percent) for the moisture monitoring system, calculated pursuant to 40 CFR 75.32; and
(E) Method of determination for hourly average moisture percentage, using Codes 1–55 in Table 4a of 40 CFR 75.57.
(c) For diluent gas (O2 or CO2) concentration during unit operation (if required), as measured and reported from each certified primary monitor, certified back-up monitor, or other approved method of emissions determination:
(A) Component-system identification code, as provided in 40 CFR 75.53;
(B) Date and hour;
(C) Hourly average diluent gas (O2 or CO2) concentration (in percent, rounded to the nearest tenth);
(D) Method of determination code for diluent gas (O2 or CO2) concentration data using Codes 1–55, in Table 4a of 40 CFR 75.57; and
(E) The percent monitor data availability (to the nearest tenth of a percent) for the O2 or CO2 monitoring system (if a separate O2 or CO2 monitoring system is used for heat input determination), calculated pursuant to 40 CFR 75.32.
(d) For stack gas volumetric flow rate during unit operation, as measured and reported from each certified primary monitor, certified back-up monitor, or other approved method of emissions determination, record the information required under paragraphs 40 CFR 75.57(c)(2)(i) through (c)(2)(vi).
(e) For Hg mass emissions during unit operation, as measured and reported from the certified primary monitoring system(s), certified redundant or nonredundant back-up monitoring system(s), or other approved method(s) of emissions determination:
(A) Date and hour;
(B) Hourly Hg mass emissions (pounds, rounded to three decimal places);
(C) Hourly Hg mass emissions (pounds, rounded to three decimal places), adjusted for bias if a bias adjustment factor is required, as provided in OAR 340-228-0629(3); and
(D) Identification code for emissions formula used to derive hourly Hg mass emissions from Hg concentration, flow rate and moisture data, as provided in 40 CFR 75.53.
(5) Hg emission record provisions (sorbent trap systems). For the sorbent traps used in sorbent trap monitoring systems to quantify Hg concentration (including sorbent traps used for relative accuracy testing), the owner or operator must record for each hour the information required by this section.
(a) For Hg concentration during unit operation, as measured and reported from each certified primary monitor, certified back-up monitor, or other approved method of emissions determination:
(A) Component-system identification code, as provided in 40 CFR 75.53;
(B) The ID number of the monitoring system in which each sorbent trap was used to collect Hg;
(C) The unique identification number of each sorbent trap;
(D) The beginning and ending dates and hours of the data collection period for each sorbent trap;
(E) Hourly Hg concentration (μg/dscm, rounded to the nearest tenth). For a particular pair of sorbent traps, this will be the flow-proportional average concentration for the data collection period;
(F) The bias-adjusted hourly average Hg concentration (μg/dscm, rounded to the nearest tenth) if a bias adjustment factor is required, as provided in OAR 340-228-0629(3);
(G) Method of determination for hourly average Hg concentration using Codes 1–55 in Table 4a of 40 CFR 75.57; and
(H) Percent monitor data availability (recorded to the nearest tenth of a percent), calculated pursuant to 40 CFR 75.32.
(b) For flue gas moisture content during unit operation, as measured and reported from each certified primary monitor, certified back-up monitor, or other approved method of emissions determination (except where a default moisture value is used in accordance with 40 CFR 75.11(b), 40 CFR 75.12(b), or approved under 40 CFR 75.66), record the information required under paragraphs (4)(b)(A) through (E) of this rule.
(c) For diluent gas (O2 or CO2) concentration during unit operation (if required for heat input determination), record the information required under paragraphs (4)(c)(A) through (E) of this rule.
(d) For stack gas volumetric flow rate during unit operation, as measured and reported from each certified primary monitor, certified back-up monitor, or other approved method of emissions determination, record the information required under 40 CFR 75.57(c)(2)(i) through (c)(2)(vi).
(e) For Hg mass emissions during unit operation, as measured and reported from the certified primary monitoring system(s), certified redundant or nonredundant back-up monitoring system(s), or other approved method(s) of emissions determination, record the information required under subsection (4)(e) of this rule.
(f) Record the average flow rate of stack gas through each sorbent trap (in appropriate units, e.g., liters/min, cc/min, dscm/min).
(g) Record the dry gas 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.
(h) Calculate and record the ratio of the bias-adjusted stack gas flow rate to the sample flow rate, as described in OAR 340-228-0627(11)(b).
(i) Information documenting the results of the required leak checks;
(j) The analysis of the Hg collected by each sorbent trap; and
(k) Information documenting the results of the other applicable quality control procedures in OAR 340-228-0617, 0623, and 0627.
(6) General recordkeeping provisions for specific situations. Except as otherwise provided in 40 CFR 75.34(d), the owner or operator must record:
(a) Parametric data which demonstrate, for each hour of missing Hg emission data, the proper operation of the add-on emission controls, as described in the quality assurance/quality control program for the unit. The parametric data must be maintained on site and must be submitted, upon request, to the Department. Alternatively, for units equipped with flue gas desulfurization (FGD) systems, the owner or operator may use quality assured data from a certified SO2 monitor to demonstrate proper operation of the emission controls during periods of missing Hg data;
(b) A flag indicating, for each hour of missing Hg emission data, either that the add-on emission controls are operating properly, as evidenced by all parameters being within the ranges specified in the quality assurance/quality control program, or that the add-on emission controls are not operating properly.
340-228-0637
Reporting
(1) General reporting provisions.
(a) The owner or operator of an affected unit must comply with all reporting requirements in this section.
(b) The owner or operator of an affected unit must submit the following for each affected unit or group of units monitored at a common stack and each non-affected unit under OAR 340-228-0615(2)(b)(B):
(A) Initial certification and recertification applications in accordance with OAR 340-228-0621;
(B) Monitoring plans in accordance with section (2) of this rule; and
(C) Quarterly reports in accordance with section (4) of this rule.
(c) Quality assurance RATA reports. If requested by the Department, the owner or operator of an affected unit must submit the quality assurance RATA report for each affected unit or group of units monitored at a common stack and each non-affected unit under OAR 340-228-0615(2)(b)(B) by the later of 45 days after completing a quality assurance RATA or 15 days of receiving the request. The owner or operator must report the hardcopy information required by 40 CFR 75.59(a)(9) and OAR 340-228-0635(2)(f) to the Department.
(d) Notifications. The owner or operator of an affected unit must submit written notice to the Department according to the provisions in 40 CFR 75.61 for each affected unit or group of units monitored at a common stack and each non-affected unit under OAR 340-228-0615(2)(b)(B).
(2) Monitoring plans. The owner or operator of a coal-fired electric generating unit must comply with the applicable requirements of subsections (2)(a) and (b) of this rule and 40 CFR 63.7521(b).
(a) The owner or operator of an affected unit must submit to the Department a complete, up-to-date monitoring plan file for each affected unit or group of units monitored at a common stack and each non-affected unit under OAR 340-228-0615(2)(b)(B), as follows: No later than 45 days prior to the commencement of initial certification testing; at the time of a certification or recertification application submission; and whenever an update of the monitoring plan is required, under 40 CFR 75.53. In addition the information in 40 CFR 75.53(e)(1), the plan must include the type(s) of emission controls for Hg installed or to be installed, including specifications of whether such controls are pre-combustion, post-combustion, or integral to the combustion process; control equipment code, installation date, and optimization date; control equipment retirement date (if applicable); primary/secondary controls indicator; and an indicator for whether the controls are an original installation.
(b) The owner or operator of an affected unit must submit all of the information required under 40 CFR 75.53, for each affected unit or group of units monitored at a common stack and each non-affected unit under OAR 340-228-0615(2)(b)(B), to the Department prior to initial certification. Thereafter, the owner or operator must submit information only if that portion of the monitoring plan is revised. The owner or operator must submit the required information as follows: no later than 45 days prior to the commencement of initial certification testing; with any certification or recertification application, if a monitoring plan change is associated with the recertification event; and within 30 days of any other event with which a monitoring plan change is associated, pursuant to 40 CFR 75.53(b).
(3) Certification applications. The owner or operator must submit an application to the Department within 45 days after completing all initial certification or recertification tests required under OAR 340-228-0621, including the information required under 40 CFR 75.63.
(4) Quarterly reports. The owner or operator must submit quarterly reports, as follows:
(a) Electronic submission. Electronic quarterly reports must be submitted, beginning with the calendar quarter containing the compliance date in OAR 340-228-0609(2). The owner or operator must report the data and information in this subsection and the applicable compliance certification information in subsection (4)(b) of this rule to the Department quarterly. Each electronic report must be submitted to the Department within 30 days following the end of each calendar quarter. Each electronic report must include the date of report generation and the following information for each affected unit or group of units monitored at a common stack.
(A) The facility information in 40 CFR 75.64(a)(1); and
(B) The information and hourly data required in OAR 340-228-0635(1), except for:
(i) Descriptions of adjustments, corrective action, and maintenance;
(ii) Information which is incompatible with electronic reporting (e.g., field data sheets, lab analyses, quality control plan);
(iii) For units with flue gas desulfurization systems or with add-on Hg emission controls, the parametric information in OAR 340-228-0635(6);
(iv) Information required by 40 CFR 75.57(h) concerning the causes of any missing data periods and the actions taken to cure such causes;
(v) Hardcopy monitoring plan information required by 40 CFR 75.53, OAR 340-228-0637(2), and hardcopy test data and results required by 40 CFR 75.59 and OAR 340-228-0635(2);
(vi) Records of flow polynomial equations and numerical values required by 40 CFR 75.59(a)(5)(vi);
(vii) Stratification test results required as part of RATAs;
(viii) Data and results of RATAs that are aborted or invalidated due to problems with the reference method or operational problems with the unit and data and results of linearity checks that are aborted or invalidated due to operational problems with the unit;
(ix) Supplementary RATA information, except that the data under 40 CFR 75.59(a)(7)(ii)(A) through (T) and the data under 40 CFR 75.59(a)(7)(iii)(A) through (M) must, as applicable, be reported for flow RATAs in which angular compensation (measurement of pitch and/or yaw angles) is used and for flow RATAs in which a site-specific wall effects adjustment factor is determined by direct measurement; and the data under 40 CFR 75.59(a)(7)(ii)(T) must be reported for all flow RATAs in which a default wall effects adjustment factor is applied; and
(x) For units using sorbent trap monitoring systems, the hourly dry gas meter readings taken between the initial and final meter readings for the data collection period;
(C) Pounds of Hg emitted during quarter and cumulative pounds of Hg emitted in the year-to-date (rounded to the nearest thousandth);
(D) Reporting data.
(i) The owner or operator of a coal-fired electric generating unit that does not meet the applicable compliance date set forth in OAR 340-228-0609(2) for any monitoring system under OAR 340-228-0609(1)(a) must, for each monitoring system, determine, record, and report maximum potential (or, as appropriate, minimum potential) values for heat input, inlet Hg, and any other parameters required to determine heat input and Hg inlet.
(ii) On and after January 1, 2018, the owner or operator of a coal-fired electric generating unit must submit monthly and 12-month rolling average mercury emissions per trillion Btu of energy input and/or mercury capture efficiency, for each month in the calendar quarter.
(E) Unit or stack operating hours for quarter, cumulative unit or stack operating hours for year-to-date; and
(F) Reporting period heat input (if applicable) and cumulative, year-to-date heat input.
(b) Compliance certification.
(A) The owner or operator must certify that the monitoring plan information in each quarterly electronic report (i.e., component and system identification codes, formulas, etc.) represent current operating conditions for the affected unit(s)
(B) The owner or operator must submit and sign a compliance certification in support of each quarterly emissions monitoring report based on reasonable inquiry of those persons with primary responsibility for ensuring that all of the unit’s emissions are correctly and fully monitored. The certification must state that:
(i) The monitoring data submitted were recorded in accordance with the applicable requirements of OAR 340-228-0609 through 0637 and 40 CFR part 75, including the quality assurance procedures and specifications; and
(ii) With regard to a unit with an FGD system or add-on Hg emission controls, that for all hours where data are substituted in accordance with OAR 340-228-0631(2), the add-on emission controls were operating within the range of parameters listed in the quality assurance plan for the unit (or that quality-assured SO2 CEMS data were available to document proper operation of the emission controls), and that the substitute values do not systematically underestimate Hg emissions.
(5) Reporting data prior to initial certification. If, by the applicable compliance date under OAR 340-228-0609(2), the owner or operator of a coal-fired electric generating unit has not successfully completed all required certification tests for any monitoring system(s), he or she must determine, record and report hourly data prior to initial certification using one of the following procedures, for the monitoring system(s) that are uncertified:
(a) For Hg concentration and flow monitoring systems, report the maximum potential Hg concentration of Hg as defined in OAR 340-228-0602(25) and the maximum potential flow rate, as defined in section 2.1.4.1 of appendix A to 40 CFR part 75; or
(b) For any unit, report data from the reference methods in OAR 340-228-0602(31) or in 40 CFR 75.22; or
(c) For any unit that is required to report heat input, report (as applicable) the maximum potential flow rate, as defined in section 2.1.4.1 of appendix A to 40 CFR part 75, the maximum potential CO2 concentration, as defined in section 2.1.3.1 of appendix A to 40 CFR part 75, the minimum potential O2 concentration, as defined in section 2.1.3.2 of appendix A to 40 CFR part 75, and the minimum potential percent moisture, as defined in section 2.1.5 of appendix A to 40 CFR part 75.