wv-wv-18467: 45-02 — Control of Particulate Matter Air Pollution from the Combustion of Fuel in Indirect Heat Exchangers

6/4/2026 4:04:56 PM Office of West Virginia Secretary Of State NOTICE OF PUBLIC COMMENT PERIOD AGENCY: Air Quality TITLE-SERIES: 45-02 RULE TYPE: Legislative Amendment to Existing Rule: Yes Repeal of existing rule:No RULE NAME: Control of Particulate Matter Air Pollution from the Combustion of Fuel in Indirect Heat Exchangers CITE STATUTORY AUTHORITY: W. Va. Code § 22-5-4 COMMENTS LIMITED TO: Oral and Written DATE OF PUBLIC HEARING: 07/07/2026 6:00 PM LOCATION OF PUBLIC HEARING: Virtual DATE WRITTEN COMMENT PERIOD ENDS: 07/07/2026 11:59 PM COMMENTS MAY BE MAILED OR EMAILED TO: NAME: Laura Jennings ADDRESS: Department of Environmental Protection; Division of Air Quality; 601 57th Street SE Charleston, WV 25304 EMAIL: laura.m.jennings@wv.gov PLEASE INDICATE IF THIS FILING INCLUDES: RELEVANT FEDERAL STATUTES OR REGULATIONS: No (IF YES, PLEASE UPLOAD IN THE SUPPORTING DOCUMENTS FIELD) INCORPORATED BY REFERENCE: No (IF YES, PLEASE UPLOAD IN THE SUPPORTING DOCUMENTS FIELD) PROVIDE A BRIEF SUMMARY OF THE CONTENT OF THE RULE: This rule establishes emission limitations for smoke and particulate matter which are discharged from fuel burning units and sets forth the registration, permitting, testing, monitoring, recordkeeping, reporting, and exemption requirements. SUMMARIZE IN A CLEAR AND CONCISE MANNER CONTENTS OF CHANGES IN THE RULE AND A STATEMENT OF CIRCUMSTANCES REQUIRING THE RULE: Summary of changes in the rule: The rule is being revised primarily to address SIP approvability concerns with the severability language in section 13 by removing this language. Additional revisions include: (1) allowing alternative monitoring methods to demonstrate compliance with visible emissions limits in section 3; (2) reorganizing paragraph 8.1.1 for clarity; (3) establishing monitoring requirements for use of certified particulate matter continuous emissions monitoring systems in section 8.2; and (4) miscellaneous typographical updates. Statement of circumstances requiring the rule: Rule 2 remains subject to the U.S. EPA finding of failure to submit action [88 Fed. Reg. 23353, April 17, 2023] to address deficiencies identified in the U.S. EPA 2015 findings of substantial inadequacy and SIP Call for provisions related to excess emissions during periods of startup, shutdown, and malfunction (SSM) (SSM SIP Call). The rule was revised in 2024; however, it is not approvable as a SIP revision by EPA due to the severability language. The rule is exempt from the Regulatory Moratorium of Executive Order 21-21 under condition 2(f), implementing a federal mandate and no waiver is permitted. Determination of Stringency: A federal counterpart to the proposed rule does not exist; therefore, no determination of stringency is required. Consultation with the Environmental Protection Advisory Council: The Environmental Protection Advisory Council received a copy of the draft rule in advance of the scheduled June 3, 2026, meeting. SUMMARIZE IN A CLEAR AND CONCISE MANNER THE OVERALL ECONOMIC IMPACT OF THE PROPOSED RULE: A. ECONOMIC IMPACT ON REVENUES OF STATE GOVERNMENT: The proposed revisions to this rule should not impact revenues of state government. B. ECONOMIC IMPACT ON SPECIAL REVENUE ACCOUNTS: The proposed revisions to this rule should not impact special revenue accounts. C. ECONOMIC IMPACT OF THE RULE ON THE STATE OR ITS RESIDENTS: The proposed revisions to this rule should not impact costs of state government beyond that resulting from currently applicable federal requirements, nor should it have an economic impact on the state or its residents. D. FISCAL NOTE DETAIL: Effect of Proposal Fiscal Year 2026 2027 Fiscal Year (Upon Increase/Decrease Increase/Decrease Full (use "-") (use "-") Implementation) 1. Estimated Total Cost 0 0 0 Personal Services 0 0 0 Current Expenses 0 0 0 Repairs and Alterations 0 0 0 Assets 0 0 0 Other 0 0 0 2. Estimated Total 0 0 0 Revenues E EXPLANATION OF ABOVE ESTIMATES (INCLUDING LONG-RANGE EFFECT): The proposed revisions to this rule should have minimal effect on the costs to the Division of Air Quality. Revisions to the rule may require review of alternative emission limits in subsequent permit applications; however, any potential permitting activity resulting from the proposed revision is not expected to be significant. In accordance with W. Va. Code §22-1A 3(c), the Secretary has determined that this rule will not result in a taking of private property within the meaning of the Constitutions of West Virginia and the United States of America. BY CHOOSING 'YES', I ATTEST THAT THE PREVIOUS STATEMENT IS TRUE AND CORRECT. Yes Isaac Lewis Tincher By my signature, I certify that I am the person authorized to file legislative rules, in accordance with West Virginia Code §29A-3-11 and §39A-3-2. 45CSR2 TITLE 45 LEGISLATIVE RULE DEPARTMENT OF ENVIRONMENTAL PROTECTION AIR QUALITY SERIES 2 CONTROL OF PARTICULATE MATTER AIR POLLUTION FROM THE COMBUSTION OF FUEL IN INDIRECT HEAT EXCHANGERS §45-2-1. General. 1.1. Scope. -- This rule establishes emission limitations for smoke and particulate matter which are discharged from fuel burning units and sets forth the registration, permitting, testing, monitoring, recordkeeping, reporting, and exemption requirements. Appendix 45-2 to this rule sets forth compliance determination methods and procedures. 1.2. Authority. -- W. Va. Code §22-5-4. 1.3. Filing Date. -- May 2, 2024. 1.4. Effective Date. -- June 1, 2024. 1.5. Sunset provision. -- Does not apply. §45-2-2. Definitions. 2.1. “ASTM” means American Society for Testing and Materials. 2.2. “Air Pollutants” means solids, liquids or gases which, if discharged into the air, may result in a statutory air pollution. 2.3. “Air Pollution” or “statutory air pollution” shall have the meaning ascribed to it in W. Va. Code §22-5-2. 2.4. “Air Pollution Control Equipment” means any equipment used for collecting or confining particulate matter for the purpose of preventing or reducing the emission of this air pollutant into the open air. 2.5. “Alternative Emission Limitation” means an emission limitation that applies to a source during some but not all periods of normal operation (e.g., applies only during a specifically defined mode of operation such as startup or shutdown). An alternative emission limitation is a component of a continuously applicable emission limitation, and it may take the form of a control measure such as a design, equipment, work practice or operational standard (whether or not numerical). 2.6. “Control Equipment” means any equipment used for collecting or confining particulate matter for the purpose of preventing or reducing the emission of this air pollutant into the open air. 2.7. “Discharge Point” means the point at which particulate matter is released from a stack into open air. 1 45CSR2 2.8. “Distillate Oil” means fuel oil that complies with the specifications for fuel oil numbers 1 or 2, as defined by the American Society for Testing and Materials in ASTM D396-98, “Standard Specification for Fuel Oils”. 2.9. “Fuel” means any form of combustible matter (solid, liquid, vapor or gas) that is used as a source of heat. 2.10. “Fuel Burning Unit” means and includes any furnace, boiler apparatus, device, mechanism, stack or structure used in the process of burning fuel or other combustible material for the primary purpose of producing heat or power by indirect heat transfer. For the purposes of this rule, all fuel burning units are classified in the following categories: 2.10.1. Type ‘a’ means any fuel burning unit which has as its primary purpose the generation of steam or other vapor to produce electric power for sale. 2.10.2. Type ‘b’ means any fuel burning unit not classified as a Type ‘a’ or Type ‘c’ unit such as industrial pulverized-fuel-fired furnaces, cyclone furnaces, gas-fired and liquid-fuel-fired units. 2.10.3. Type ‘c’ means any hand-fired or stoker-fired fuel burning unit not classified as a Type ‘a’ unit. 2.11. “Fugitive Particulate Matter” means any and all particulate matter generated by any operation involving or associated with the combustion of fuel in fuel burning units which, if not confined, would be emitted directly into the open air from points other than a stack outlet. 2.12. “Fugitive Particulate Matter Control System” means any equipment or method used to confine, collect or dispose of fugitive particulate matter, including, but not limited to, hoods, bins, duct work, fans and air pollution control equipment. 2.13. “Heat Input” means the rate of heat release from all fuels fired in all similar units vented by the test stack during the test run period. 2.13.1. “Design Heat Input (DHI)” means the heat input level (in MM Btu/hr) for which an individual fuel burning unit has been designed to be operated during continuous operation. 2.13.2. “Total Design Heat Input (TDHI)” means the sum of the design heat inputs for all similar units located at one1 plant. 2.13.3. “Normal Maximum Operating Load (NMOL)” means the sum of the Design Heat Input levels (in MM Btu/hr) of the similar unit(s) vented by the test stack, unless the owner/operator has elected to operate one1 or more of the similar units vented by the test stack at or below a specified percentage of its Design Heat Input level as part of a compliance program, permit or consent order officially accepted by the Secretary. In such event, the NMOL is the sum of the Design Heat Input levels or fractions thereof as appropriate (i.e., NMOL = 0.75 DHI + D1I ). 2 2.14. “Indirect Heat Exchanger” means a device that combusts any fuel and produces steam or heats water or any other heat transfer medium. This term includes any duct burner that combusts fuel and is part of a combined cycle system. This term does not include process heaters as defined in subsection 2.26. 2.15. “Laboratory Official” means the person, qualified by experience or education, who is charged with overseeing or conducting the laboratory analysis of the collected samples. This person is responsible 2 45CSR2 for ensuring the accuracy and validity of the laboratory results. 2.16. “Malfunction” means a sudden and unavoidable breakdown of process or control equipment. 2.17. “Natural Gas” means (1) a naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in geologic formations beneath the earth’s surface, of which the principal constituent is methane, or (2) liquefied petroleum (LP) gas, as defined by the American Society for Testing and Materials in ASTM D1835-97, “Standard Specification for Liquefied Petroleum Gases”. 2.18. “Normal Operation” when used in the context of fuel quality and combinations fired, means the type, quality and combination of fuel(s) fired which is representative of the fuel or fuel combination fired, in the unit(s) tested, over a reasonable period prior to the test, and the fuel or fuel combination which might reasonably be expected to continue to be fired in this unit after the test. If the type of fuel, quality or combination used in the unit is variable, use the type, quality and/or combination fired in day-to-day operation which can reasonably be expected to produce the greatest particulate matter loading to the control equipment (e.g., if coal is fired eight8 months out of the year and gas is fired four4 months out of the year, coal is to be burned during the test). 2.19. “Opacity” means the degree to which emissions reduce the transmission of light and obscure the view of an object in the background. 2.20. “Owner or Operator” means the person responsible for the compliance of the fuel burning units subject to the provisions of 45CSR2. 2.21. “Particulate Matter” means any material, except uncombined water, that exists in a finely divided form as a liquid or solid. 2.22. “Person” means any and all persons, natural or artificial, including the state of West Virginia or any other state, the United States of America, any municipal, statutory, public or private corporation organized or existing under the laws of this or any other state or country, and any firm, partnership or association of whatever nature. 2.23. “Plant” means and includes all fuel burning units, source operations, equipment and grounds utilized in an integral complex. 2.24. “Prefilter” means a filter used in the sampling train prior to the primary filter for the purpose of reducing the particulate matter build-up on the primary filter. 2.25. “Primary Filter” means the last filter used in the sampling train to separate the particulate matter sample from the sampled stack gas. 2.26. “Process Heater” means a device that is primarily used to heat a material to initiate or promote a chemical reaction in which the material participates as a reactant or catalyst. 2.27. “Probe” means the part of the pitot tube assembly (nozzle, sample tube, pitot tube, filter holder(s), sensor(s)), which precedes the last filter in the sampling train and conveys the sample gas and particulate matter from the nozzle inlet to the last filter disc used for collecting stack particulate matter. 2.28. “Residual Oil” means crude oil, fuel oil that does not comply with the specifications under the definition ofdistillate oil,and all fuel oil numbers 4, 5 and6,as defined by the American Society for Testing and Materials in ASTM D396-98, “Standard Specification for Fuel Oils”. 3 45CSR2 2.29. “Sampling Plane” means the imaginary plane located perpendicular to the gas flow in the duct or stack at the place selected for the extraction of the required samples. 2.30. “Secretary” means the Secretary of the Department of Environmental Protection or such other person to whom the Secretary has delegated authority or duties pursuant to W.Va. Code §§22-1-6 or 22-1- 8. 2.31. “Shipment” means any discrete, identifiable quantity of fuel for which a quality report is available. For example, a fuel shipment may be all fuel delivered from a specific lot, identified by the lot number, or fuel delivered under a specific purchase order number. 2.32. “Shutdown” means the cessation of operation of a fuel burning unit(s) subject to this rule for any purpose, unless otherwise defined in a permit creating an alternative emission limitation. 2.33. “Similar Unit(s)” means all Type ‘a’, or all Type ‘b’ or all Type ‘c’ fuel burning units located at one1 plant. 2.34. “Smoke” means small gas borne and airborne particulate matter arising from a process of combustion in sufficient number to be visible. 2.35. “Stack”, for the purposes of this rule, means, but is not limited to, any duct, control equipment exhaust or similar apparatus, which vents gases and/or particulate matter into the open air. 2.36. “Startup”meansthesettinginoperationofafuelburningunitsubjecttothisruleforanypurpose, unless otherwise defined in a permit creating an alternative emission limitation. 2.37. “Test Team Supervisor” means the person, qualified by experience or education, who is charged with supervising the stack test. This person is responsible for ensuring the validity and correctness of the submitted test results. 2.38. “Wet Scrubber System” means any emission control device that mixes an aqueous stream or slurry with the exhaust gases from an indirect heat exchanger to control emissions of particulate matter (PM) or SO .2 2.39. “Wood” means wood, wood residue, bark, or any derivative fuel or residue thereof, in any form, including, but not limited to, sawdust, sander dust, wood chips, scraps, slabs, millings, shavings and processed pellets made from wood or other forest residues. 2.40. Other words and phrases used in this rule, unless otherwise indicated, shall have the meaning ascribed to them in W.Va. §22-5-1 et seq. §45-2-3. Visible Emissions of Smoke and/or Particulate Matter Prohibited and Standards of Measurement. 3.1. No person shall cause, suffer, allow or permit emission of smoke and/or particulate matter into the open air from any fuel burning unit which is greater than 10 percent opacity based on a six6-minute block average. 3.2. Compliance with the visible emission requirements of subsection 3.1 shall be determined in accordance with 40 CFR Part 60, Appendix A, Method 9 and 45CSR16 or by using measurements from 4 45CSR2 continuous opacity monitoring systems approved by the Secretary. the methods described in subdivision 3.2.1, 3.2.2, or 3.2.3. 3.2.1. Using measurements from continuous opacity monitoring systems approved by the Secretary. The Secretary may require the installation, calibration, maintenance and operation of continuous opacity monitoring systems and may establish policies for the evaluation of continuous opacity monitoring results and the determination of compliance with the visible emission requirements of subsection 3.1. Continuous opacity monitors shall not be required on fuel burning units which employ wet scrubbing systems for emission control. 3.2.2. Using measurements from continuous particulate matter monitoring systems approved by the Secretary. The Secretary may require the installation, calibration, maintenance and operation of continuous particulate matter monitoring systems and may establish policies for the evaluation of continuous particulate matter monitoring results and the determination of compliance with the visible emission requirements of subsection 3.1. 3.2.3. Using an equivalent EPA approved method as approved by the Secretary. 3.3. If the owner or operator of a fuel burning unit can demonstrate to the satisfaction of the Secretary that compliance with subsection 3.1 cannot practically be achieved with respect to soot blowing operations or during the cleaning of a fire box, the Secretary may formally approve an alternative visible emission standard applicable to the fuel burning unit for soot blowing periods; provided that the exception period shall not exceed a total of 6 six-minute time periods in a calendar day with visible emissions limited to 30% opacity, as determined in accordance with 40 CFR Part 60, Appendix A, Method 9 and 45CSR16, or by using measurements from a certified continuous opacity monitoring system or by using an equivalent EPA approved method as approved by the Secretary. 3.4. The Secretary may approve an alternative visible emission standard to that required under subsection 3.1, not to exceed 20 percent opacity, upon the filing of a written petition by the owner or operator, which petition shall include a demonstration satisfactory to the Secretary: 3.4.1. That it is technologically or economically infeasible to comply with subsection 3.1; 3.4.2. That emissions from the fuel burning unit for which an alternative visible emission standard is proposed impact no area in which the National Ambient Air Quality Standards for particulate matter are being exceeded nor will any such emissions cause or contribute to a violation of the National Ambient Air Quality Standards for particulate matter in an area which currently meets such standards; 3.4.3. That the particulate weight emission standards under section 4 of this rule are being met, as determined in accordance with the Appendix45-2 to this rule – “Compliance Test Procedures for 45CSR2”; 3.4.4. That the fuel burning unit for which an alternative visible emission standard is proposed is at all times operated and maintained in accordance with the provisions of subsection 9.2; 3.4.5. That the fuel burning unit for which an alternative visible emission standard is proposed and its associated air pollution control equipment are incapable of being adjusted or operated at normal operating loads to meet the applicable visible emission standard; 3.4.6. That the owner or operator will install, calibrate, maintain and operate a continuous opacity monitoring system approved by the Secretary, for the fuel burning unit for which an alternative visible emission standard is proposed, and will submit the results of such monitoring system to the Secretary on a 5 45CSR2 calendar monthly basis in a format approved by the Secretary, provided that this provision shall not apply to fuel burning units which employ wet scrubbing systems for emission control; and 3.4.7. That all other requirements of law and rules enforced by the Secretary will be met. §45-2-4. Weight Emission Standards. 4.1. No person shall cause, suffer, allow or permit the discharge of particulate matter into the open air from all fuel burning units located at one1 plant, measured in terms of pounds per hour in excess of the amount determined as follows: 4.1.1. For Type ‘a’ fuel burning units, the product of 0.05 and the total design heat inputs for such units in million British Thermal Units (B.T.U.’s) per hour, provided however that no more than 1200 pounds per hour of particulate matter shall be discharged into the open air from all such units; 4.1.2. For Type ‘b’ fuel burning units, the product of 0.09 and the total design heat inputs for such units in million B.T.U.’s per hour, provided however that no more than 600 pounds per hour of particulate matter shall be discharged into the open air from all such units; and 4.1.3. For Type ‘c’ fuel burning units, in excess of the values listed in Table 45-2, provided however that no more than 300 pounds per hour of particulate matter shall be discharged into the open air from all such units. 4.1.3.a. For values between any two2 corresponding consecutive values listed in Table 45-2, linear interpolation is to be used for both columns. 4.2. Subject to the provisions of this rule, allowable emission rates for individual stacks shall be determined by the owner and/or operator and registered with the Secretary at the request of, and on forms provided by, the Secretary. Such rates shall be subject to review and approval by the Secretary. 4.2.1. The approved set of individual stack allowable emission rates shall become an official part of the compliance schedule and/or any permits concerning such source(s) and shall not be changed without the prior written approval of the Secretary. 4.3. If the number of similar fuel burning units located at one1 plant, each of which is meeting the requirements of this rule, is expanded by the addition of a new unit(s), the total allowable emission rate for the new unit(s) shall be determined by the following formula. However, the maximum allowable emission rates given in subsection 4.1 are not to be exceeded: R e ( 1 - ( Het H )e) R et H et Where: R es the total allowable emission rate in pounds per hour for the new fuel burning unit(s); H etis the total design heat input in million B.T.U.’s per hour of the existing and new similar units; R et the total allowable emission rate in pounds per hour corresponding to H ; anet H es the total design heat input in million B.T.U.’s per hour for the new fuel burning unit(s). 4.4. The addition of sulfur oxides to a combustion unit exit gas stream for the purpose of improving emissions control equipment efficiency shall be reviewed by the Secretary. No person shall cause, suffer, allow or permit the addition of sulfur oxides as described above unless written approval for such addition 6 45CSR2 is provided by the Secretary. 4.5. The provisions of subsection 4.4 shall not apply to combustion units in operation on or before September 1, 1974. §45-2-5. Control of Fugitive Particulate Matter. 5.1. No person shall cause, suffer, allow or permit any source of fugitive particulate matter to operate that is not equipped with a fugitive particulate matter control system. This system shall be operated and maintained in such a manner as to minimize the emission of fugitiveparticulate matter. Sources of fugitive particulate matter associated with fuel burning units shall include, but not be limited to, the following: 5.1.1. Stockpiling of ash or fuel either in the open or in enclosures such as silos; 5.1.2. Transport of ash in vehicles or on conveying systems, to include spillage, tracking or blowing of particulate matter from or by such vehicles or equipment; and 5.1.3. Ash or fuel handling systems and ash disposal areas. §45-2-6. Registration. 6.1. All persons owning or operating fuel burning units in existence on September 1, 1974 not previously registered shall have registered such units with the Secretary. The information required for registration shall be determined and provided in the manner specified by the Secretary. Registration forms should be requested from the Secretary by the owner and/or operator of fuel burning unit(s) subject to the provisions of this section. 6.2. The owner or operator of fuel burning units that were under construction or on which construction was initiated as of October 1, 1974, not previously registered shall have registered such fuel burning units with the Secretary. §45-2-7. Permits. 7.1. Nopersonshallconstruct,modifyorrelocateanyfuelburningunitwithoutfirstobtainingapermit in accordance with the provisions of W. Va. Code §22-5-1 et seq., and Series 13, 14, 19 and 30 of Title 45. §45-2-8. Testing, Monitoring, Recordkeeping and Reporting. 8.1. Testing. 8.1.1. The owner or operator of a fuel burning unit(s) shall demonstrate compliance with section 3 in accordance with 8.1.1.a and with section 4 in accordance with 8.1.1.b. with section 3 byperiodic testing in accordance with 40 CFR Part 60, Appendix A, Method 9 and 45CSR16, or a certified continuous opacity monitoring system, as approved by the Secretary, and section 4 by periodic particulate matter stack testing, conducted in accordance with the appropriate test method set forth in the Appendix 45-2 to this rule or other equivalent EPA approved method approved by the Secretary. The owner or operator shall conduct such testing at a frequency to be established by the Secretary. 8.1.1.a. Conduct periodic testing in accordance with 40 CFR Part 60, Appendix A, Method 9 and 45CSR16, a certified continuous opacity monitoring system as approved by the Secretary, a certified continuous particulate matter monitoring system as approved by the Secretary, or by using an equivalent 7 45CSR2 EPA approved method as approved by the Secretary. 8.1.1.b. Conduct periodic particulate matter stack testing, conducted in accordance with the appropriate test method set forth in the Appendix 45-2 to this rule or by using an equivalent EPA approved method as approved by the Secretary. 8.1.2. At such reasonable times as the Secretary may designate, the owner or operator of any fuel burning unit(s) may be required to conduct or have conducted tests to determine the compliance of such unit(s) with the emission limitations of section 4. Such tests shall be conducted in accordance with the appropriate method set forth in Appendix 45-2 to this rule or other equivalent EPA approved method approved by the Secretary. The Secretary may at his option witness or conduct such tests. Should the Secretary exercise his option to conduct such tests, the operator will provide all necessary sampling connections and sampling ports located in such manner as the Secretary may require, power for test equipment, and the required safety equipment such as scaffolding, railings and ladders to comply with generally accepted good safety practices. 8.1.2.a. Sufficient information on temperatures, velocities, pressures, weights and dimensional values shall be reported to the Secretary, with such necessary commentary as he may require to allow an accurate evaluation of the reported test results and the conditions under which they were obtained. 8.1.3. The Secretary may conduct such other tests as he may deem necessary to evaluate air pollution emissions other than those noted in subsection 4.1. 8.2. Monitoring. 8.2.1. The owner or operator of a fuel burning unit(s) shall monitor compliance with section 3 and 4assetforthinanapprovedmonitoringplanforeachemissionunit. Suchmonitoringplan(s)shallinclude, but not be limited to, one1 or more of the following: continuous measurement of emissions, monitoring of emission control equipment, periodic parametric monitoring, or such other monitoring as approved by the Secretary. 8.2.1.a. Direct measurement with a certified continuous opacity monitoring system (COMS) shall be deemed to satisfy the requirements for a monitoring plan. Such COMS shall be installed, calibrated, operated and maintained as specified in 40CFR Part60,Appendix B,Performance Specification 1 (PS1) and 45CSR16. COMS meeting the requirements of 40 CFR Part 75 (Acid Rain) and 45CSR33 will be deemed to have satisfied the requirements of PS1. 8.2.1.b. Reserved. Direct measurement with a certified continuous particulate matter monitoring system (CEMS) shall be deemed to satisfy the requirements for a monitoring plan. Such CEMS shall be installed, calibrated, operated and maintained as specified in 40 CFR Part 60, Appendix B, Performance Specification 1 (PS11) and 45CSR16. 8.2.1.c. Excursions outside the range of operating parameters associated with control or process equipment which are established in an approved monitoring plan will not necessarily constitute a violation of this rule. 8.3. Recordkeeping and Reporting. 8.3.1. The owner or operator of a fuel burning unit(s) shall maintain on-site all records of monitored data established in the monitoring plan pursuant to subdivision 8.2.1. Such records shall be 8 45CSR2 made available to the Secretary upon request. Such records shall be retained on-site for a minimum of five5 years. 8.3.2. The owner or operator shall submit a periodic exception report to the Secretary, in a manner and at a frequency to be established by the Secretary. Such exception report shall provide details of all excursions outside the range of measured emissions or monitored parameters established in an approved monitoring plan, and shall include, but not be limited to, the time of the excursion, the magnitude of the excursion, the duration of the excursion, the cause of the excursion and the corrective action taken. 8.3.3. The owner or operator shall maintain records of the operating schedule and the quantity and quality of fuel consumed in each fuel burning unit in a manner to be established by the Secretary. Such records are to be maintained on-site and made available to the Secretary upon request. 8.3.4. Where appropriate, the owner or operator of a fuel burning unit(s) may maintain such records in electronic form. 8.4. Exceptions. 8.4.1. The owner or operator of a fuel burning unit(s) may petition for alternatives to testing, monitoring and reporting requirements prescribed pursuant to this rule for conditions, including, but not limited to, the following: 8.4.1.a. Infrequent use of a fuel burning unit(s). 8.4.1.b. Continuous emission measurement equipment that does not meet the design requirements of 40 CFR Part 60, Appendix B, Performance Specification 1 (PS1) and 45CSR16 or 40 CFR 75(AcidRain)and45CSR33,whereitcanbeadequatelydemonstratedthatthereisadefiniteandconsistent relationship between its measurement and the measurements of opacity by a system complying with PS1. The Secretary may require that such demonstration be performed for each fuel burning unit. 8.4.1.c. Where a single fuel burning unit may have more than one1 emission point. 8.4.1.d. Where the desired location of the continuous monitoring system does not meet the requirements of the applicable performance standard, when the owner or operator can demonstrate that installation at alternative locations will enable accurate and representative measurements. 8.4.2. The owner or operator of a fuel burning unit(s) which combusts only natural gas shall be exempt from the requirements of subdivision 8.1.1 and subsection 8.2. 8.4.3. The owner or operator of a fuel burning unit(s) with a Design Heat Input of less than 100 mmBtu/hr shall be exempt from the periodic testing requirements of subdivision 8.1.1 and the monitoring requirements of subsection 8.2. The Secretary reserves the right to require testing pursuant to subdivisions 8.1.2 and 8.1.3. 8.5. Requests for Information. 8.5.1. The Secretary shall respond within five5 working days to requests for information generated or required under this rule. Requests for information not in the Secretary’s custody shall be promptly forwarded to the appropriate federal or state agency known to have such information. 8.5.2. Data relating to electric utilities and fuel quality and costs of fuels are available from the 9 45CSR2 Federal Energy Regulatory Commission (FERC) and the West Virginia Public Service Commission (PSC). §45-2-9. Start-ups, Shutdowns and Malfunctions. 9.1. Reserved. 9.2. At all times, including periods of start-ups, shutdowns and malfunctions, owners and operators shall, to the extent practicable, maintain and operate any fuel burning unit(s) including associated air pollution control equipment in a manner consistent with good air pollution control practice for minimizing emissions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Secretary which may include, but is not limited to, monitoring results, visible emission observations, review of operating and maintenance procedures and inspection of the source. 9.3. The owner or operator of a fuel burning unit(s) subject to this rule shall report to the Secretary any malfunction of such unit or its air pollution control equipment which results in any excess particulate matter emission rate or excess opacity (i.e., emissions exceeding the standards in sections 3 and 4 as provided in one1 of the following subdivisions: 9.3.1. Excess opacity periods meeting the following conditions may be reported on a quarterly basis unless otherwise required by the Secretary: 9.3.1.a. The excess opacity period does not exceed 30 minutes within any 24-hour period; and 9.3.1.b. Excess opacity does not exceed 40%. 9.3.2. The owner or operator shall report to the Secretary any malfunction resulting in excess particulate matter or excess opacity, not meeting the criteria set forth in subdivision 9.3.1, by telephone or e-mail by the end of the next business day after becoming aware of such condition. The owner or operator shall file a certified written report concerning the malfunction with the Secretary within 30 days providing the following information: 9.3.2.a. A detailed explanation of the factors involved or causes of the malfunction; 9.3.2.b. The date and time of duration (with starting and ending times) of the period of excess emissions; 9.3.2.c. An estimate of the mass of excess emissions discharged during the malfunction period; 9.3.2.d. The maximum opacity measured or observed during the malfunction; 9.3.2.e. Immediate remedial actions taken at the time of the malfunction to correct or mitigate the effects of the malfunction; and 9.3.2.f. A detailed explanation of the corrective measures or program that will be implemented to prevent a recurrence of the malfunction and a schedule for such implementation. 9.4. Reserved. 9.5. Reserved. 10 45CSR2 9.6. Any owner or operator that cannot comply with the emission limitations required by sections 3 or 4 during startup or shutdown shall request an alternative emission limitation pursuant to 45CSR1. §45-2-10. Reserved. §45-2-11. Exemptions. 11.1. Any fuel burning unit(s) having a heat input under 10 million B.T.U.’s per hour will be exempt from sections 4, 5, 6, 8 and 9. However, failure to attain acceptable air quality in parts of some urban areas may require the mandatory control of these sources at a later date. §45-2-12. Inconsistency Between Rules. 12.1. In the event of any inconsistency between this rule and Appendix 45-2 and any other rule of the Division of Air Quality, such inconsistency shall be resolved by the determination of the Secretary and such determination shall be based upon the application of the more stringent provision, term, condition, method or rule. §45-2-13. Disposition of Rule; Severability. Reserved. 13.1. In the event the U.S. EPA’s June 12, 2015 “State Implementation Plans: Response to Petition for Rulemaking; Restatement and Update of EPA’s SSM Policy Applicable to SIPs; Finding of Substantial Inadequacy; and SIP Calls to Amend Provisions Applying to Excess Emissions During Periods of Startup, Shutdown and Malfunction,” at 80 Fed. Reg. 33840 (2015 SSM SIP Call) is withdrawn by the U.S. EPA, is invalidated by a court of competent jurisdiction, and/or is invalidated by an act of the West Virginia Legislature or United States Congress, the Secretary may terminate any permit or section of an existing permit issued pursuant to this rule. 13.2. In the event the U.S. EPA’s April 17, 2023 “Air Plan Disapproval; West Virginia; Revision to the West Virginia State Implementation Plan To Add the Startup, Shutdown, Maintenance Rule 45CSR1— Alternative Emission Limitations DuringStartup, Shutdown, and Maintenance Operations,” at 88 Fed. Reg. 23356 (45CSR1 2023 Disapproval) is withdrawn by the U.S. EPA, is invalidated by a court of competent jurisdiction, and/or is invalidated by an act of the West Virginia Legislature or United States Congress, the Secretary may terminate any permit or section of an existing permit issued pursuant to this rule. 13.3. In the event the U.S. EPA’s April 17, 2023 “West Virginia; Finding of Failure To Submit State Implementation Plan Revision in Response to the 2015 Findings of Substantial Inadequacy and SIP Calls To Amend Provisions Applying to Excess Emissions During Periods of Startup, Shutdown, and Malfunction,” at 88 Fed. Reg. 23353 (2023 FFS) is withdrawn by the U.S. EPA, is invalidated by a court of competent jurisdiction, and/or is invalidated by an act of the West Virginia Legislature or United States Congress, the Secretary may terminate any permit or section of an existing permit issued pursuant to this rule. 13.4. In the event the 2015 SSM SIP Call, 45CSR1 2023 Disapproval, and/or the 2023 FFS is withdrawn by the U.S. EPA, is invalidated by a court of competent jurisdiction, and/or is invalidated by an act of the West Virginia Legislature or United States Congress, the Secretary may sever requirement § 45- 2-9.6 and revert to the August 31, 2000 requirements found at §§ 45-2-9.1, -9.4, -9.5, -10.1, and -10.2. 11 45CSR2 TABLE 45-2 Total Design Heat Input for All Total Allowable Particulate Type ‘c’ Fuel Burning Units Matter Emission Rate for Located at One1 Plant in Units Located at One1 Plant Millions of B.T.U.’s Per Hour in Pounds Per Hour 10 3.4 20 5.6 40 9.0 60 11.7 80 14.4 100 16.6 200 26.4 400 42.2 600 54.0 3,333 300.0 12 Appendix 45-2 APPENDIX 45-2 COMPLIANCE TEST PROCEDURES FOR 45CSR2 Section 1. General. 1.1. Scope. -- Appendix 45-2 establishes stack testing procedures for determination of compliance with the weight emission standards set forth in 45CSR2. The test methods in subsection 4.1 of Appendix 45-2 contain acceptable stack testing, calibration, and laboratory procedures including appropriate apparatus with provisions for certain minor exceptions as provided in section 6 of Appendix 45-2. Section 2. Reserved. Section 3. Symbols. 3.1. Ab = (Sd) x (Va), Ab is the estimate of the weight of residue, prior to use, in the acetone wash volume used (grams) 3.2. An = cross-sectional area of the sample nozzle (ft ) 3.3. As = cross-sectional area of the sample plane (ft ) 3.4. ASTM = American Society for Testing and Materials 3.5. B = percent moisture in the sampled gas, by volume, on a wet basis, divided by 100 3.6. BE = the boiler thermal efficiency (percent) 3.7. C = 453.592 grams/pound 3.8. oC = degrees Centrigrade 3.9. cfm = cubic feet per minute 3.10. CEM = continuous emission monitoring equipment 3.11. CO = carbon monoxide 3.12. CO = 2arbon dioxide 3.13. d = diameter of nozzle (inches) 3.14. DGR = dry gas meter reading: the sample gas volume meter reading at meter conditions (cubic feet) 3.15. ΔDGR = difference between two2 consecutive DGR’s, the volume sampled at each sampling point (cubic feet) 13 Appendix 45-2 3.16. EA = excess air fraction 3.17. F-factor = a factor representing a ratio of the dry flue gases generated to the calorific value of the fuel combusted (dscf/10 Btu) 3.18. Fi = quantity of each fuel fired in a fuel burning unit during the total test run period (in appropriate units) 3.19. ○F = degrees Fahrenheit 3.20. Fp = combined correction factor for units and pitot tube deviation 3.21. ft = cubic feet 3.22. ft/min = feet per minute 3.23. gm = grams 3.24. hbd = average enthalpy of steam/water leaving boiler as blowdown (Btu/lbm) 3.25. hi = average enthalpy of steam or other working fluid entering the boiler of the fuel burning unit (Btu/lbm) 3.26. ho = average enthalpy of steam or other working fluid leaving the boiler of the fuel burning unit (Btu/lbm) 3.27. ΔH = pitot tube differential reading (inches H O)2 3.28. ΔHp = indicated differential pressure when the test pitot tube is used at the calibration point 3.29. ΔHs = indicated differential pressure when the standard pitot tube is used at the calibration point 3.30. Hg = mercury 6 3.31. HI = heat input per fuel burning unit(s) (10 Btu per hour) 3.32. H S2= hydrogen sulfide 3.33. HVf = higher heating value of the fuel on an as fired basis (in Btu/lbm) 3.34. HVi = average Btu value of each fuel used on an as fired basis, in appropriate units (Btu/lbm, Btu/gal, etc.) 3.35. in. Hg = inches of mercury, pressure 3.36. ISKo = overall isokinetic factor, ratio of total actual sample volume (Qm) to the total isokinetic sample volume (Qo), both volumes adjusted to standard conditions 14 Appendix 45-2 3.37. ISKp= point isokinetic factor, ratio of the actual sample volume to the isokinetic sample volume 3.38. %ISK = 100 (ISKo - 1) 3.39. Kp = coefficient of deviation of the Type S pitot tube used in sampling, determined by calibration 3.40. Ks = coefficient of deviation for a standard pitot tube 3.41. ibf = pounds force 3.42. lbm = pounds mass 3.43. Ma = particulate matter obtained from the evaporation of the acetone washings (grams) 3.44. Mbd = average mass flow rate of blowdown (lbm/hr) 3.45. Mf = particulate matter collected by filter(s) (grams) 3.46. Mg = molecular weight of gas sample on wet basis 3.47. mf = average mass flow rate of steam through the boiler (lbm/hr) 3.48. mg = milligram 3.49. ml = milliliter 3.50. Mn = Mf + Ma - Ab (grams), indicated weight of particulate matter collected by the sampling train 3.51. n = number of items in a set of related items 3.52. N =2nitrogen 3.53. O =2oxygen 3.54. Θ = sum of all extraction times at all points sampled per run (min.) 3.55. Pb = atmospheric pressure (in. Hg) 3.56. Pf = ash fraction of the non-metered fuel on an as fired basis 3.57. Pm = absolute pressure of gas at meter (in. Hg) 3.58. Pm = average absolute pressure of the sampled gas at meter conditions for the test run (in. Hg) 3.59. Ps = absolute pressure of gas in stack at sampling plane 15 Appendix 45-2 3.60. qm = actual sample volume for each sample point adjusted to 68 F and 29.92 in. Hg (ft ) 3 3 3.61. Qm = sum of all qm for each test run (ft ) 3.62. qo = volume of sampled gas for each point if isokinetic conditions were maintained, adjusted to 68 F and 29.92 in. Hg (ft )3 3.63. Qo = sum of all qo for each test run (ft ) 3.64. Sd = residue found in acetone blank (gm/ml) 3.65. π = pi, 3.1416 3.66. Δt = elapsed time at each sampling point (minutes) 3.67. Tf = temperature of the primary out-of-stack filter holder, when used ( F)○ ○ 3.68. Tm = temperature of gas sample at volume meter for each point ( F) 3.69. Tm = average temperature of gas sample at volume meter for test run ( F) ○ ○ 3.70. Ts = stack gas temperature ( F) 3.71. Va = volume of acetone wash (ml) 3.72. Vac = vacuum (inches of mercury) 3 3.73. Vm = sum of all ΔDGR for the test run (ft ) 3.74. Vmstd = Vm corrected to standard conditions 3.75. w = 1/(1 - B), ratio of wet gas volume to dry gas volume 3.76. W = Wc + Wd (grams), amount of H O remov2d from the sampled gas 3.77. Wc = amount of water collected in the condenser or impingers (grams) 3.78. Wd = amount of water collected by the drying agent in the absorber (grams) 3.79. % = percent Section 4. Adoption of Test Methods. 4.1. The owner or operator of a fuel burning unit shall determine compliance with the weight emission standards contained in 45CSR2 by using Reference Method 5, 5B, or 17 set forth in 40 CFR Part 60, Appendix A (incorporated by reference into state law in 45CSR16), as amended by subdivisions 4.1.1. through 4.1.4. 16 Appendix 45-2 4.1.1. Primary filter media shall be maintained at, or about, stack temperature. The temperature of the primary filter media shall not exceed that of the stack except that in cases where sampling follows a wet scrubbing device the temperature of the primary○filter, initial filter tare, and oven temperature may be adjusted to a maintained temperature of up to 250 F. 4.1.2. The result of each compliance test is to be the arithmetic average of 3 complete sampling runs conducted within a 7 day period. 4.1.3. A complete sampling run shall be one1 complete determination of the total particulate matter emission rate through the test stack for which: 4.13.a. the minimum total sampling time is 2 hours; and 4.1.3.b. the minimum total sample volume is 60 cubic feet adjusted to 68 F and 29.92 inches of Hg. Smaller sampling volumes and shorter sampling times may be approved by the Secretary on a case- by-case basis when necessitated by process variables or other factors. 4.1.4. Any and all references in 40 CFR, Part 60, Appendix A and 45CSR16 to the “Administrator” is amended to be the “Secretary”. 4.2. In carrying out these methods for the purpose of determining mass emission rates, it is understood that other Reference Methods contained in 40 CFR, Part 60, Appendix A are integral parts of Methods 5, 5B, and 17 in particular, but not inclusive, Methods 1, 2, 3, and 4. Section 5. Unit Load and Fuel Quality Requirements. 5.1. All compliance test runs, which are to be included in the test result for a unit or a specified number of units, shall be conducted while the unit or group of units is operated at or above the normal maximum operating load for the specified unit or group of units; while fuel or combinations of fuel representative of normal operation are being burned; and under such other relevant conditions as the Secretary may specify based on representative performance of the specified units. Section 6. Minor Exceptions. 6.1. In the interest of practicality, the Secretary or his designee may allow minor exceptions, not related to test site safety, to the specifications of these methods, if the Secretary or his designee concludes that in a particular case, the granting of such exception would not invalidate the test results. If such exceptions are granted, alternate specifications may be prescribed. 6.2. If an exception as described above is granted, the scope of the exception and any alternative specification prescribed shall be recorded in a letter of exception signed by the authorizing official. A copy of such letter of exception shall be attached to the test report. Section 7. Pretest and Post Test General Requirements. 7.1. The owner or operator required to conduct tests and his test consultants shall become familiar with the requirements of 45CSR2 Reference Methods as contained in 40 CFR, Part 60, Appendix A and 45CSR16, and the requirements as delineated in Appendix 45-2, including all forms, equations, and 17 Appendix 45-2 definitions. Questions of interpretation, applicability, or exception shall be resolved with the Secretary prior to conducting the test. 7.2. When a compliance test conducted in accordance with Appendix 45-2 is required, the owner or operator of the affected unit(s) shall be notified in writing by the Secretary. The notice shall prescribe the following: 7.2.1. the unit(s) to be tested; 7.2.2. the identification number to be assigned to the test; 7.2.3. the date by which the test is to be completed and the test report submitted; and 7.2.4. the person, if other than the Secretary, to whom the test report is to be submitted, and with whom questions concerning the test procedure may be resolved. Test report forms for filing the results of the compliance test are available from the Secretary on request. 7.3. At least 30 days prior to each compliance test, or within such other time period as requested and approved by the Secretary, a test protocol shall be furnished to the Secretary for review and approval and shall include as a minimum, the following information: 7.3.1. Identification and description of the unit(s) that are to be tested. 7.3.2. A discussion of the manner in which the unit(s) shall be operated during the test periods with respect to operating loads, representativeness of fuel(s) fired, operating temperatures, and other factors which may affect emissions. 7.3.3. A description or listing of unit and control equipment data that shall be monitored and recorded during the test runs. 7.3.4. A description of test methods and equipment that shall be employed with requests for approval of any variances to test method procedures or sampling equipment designs set forth under Appendix 45-2. 7.3.5. A drawing of the stack or duct sections where samples shall be taken showing distances to upstream and downstream gas flow disturbances or bends and changes in duct or stack cross sections. 7.3.6. A drawing of the test plane(s) showing dimensions and number and location of sampling (traverse) points. 7.3.7. The sampling time at each traverse point and total sampling time for each test run. If the sampling time per traverse point is to be less than 5 minutes, comments shall be included concerning the variability of gas flow and temperatures during the shorter sampling time and how the sampling rate shall be monitored and adjusted to maintain isokinetic conditions. 7.3.8. The minimum volume (SCF) of gas that shall be sampled per test run. 7.3.9. The name of the person to contact concerning the scheduled tests and affiliation of 18 Appendix 45-2 personnel who shall conduct the tests. 7.3.10. A copy of the last individual stack registration approved by the Secretary in accordance with subsection subdivision 4.1.2 of 45CSR2. 7.3.11. A statement concerning where the laboratory analyses are to be conducted and a description of the chain of custody for collected samples. 7.3.12. The anticipated date that subject testing is to be performed. 7.4. Notification of the actual dates upon which compliance testing will be conducted shall be provided to the Secretary, in writing, no later than 15 days prior to the date of the first test run, or within such other time period as requested and approved by the Secretary, so that he may, at his option, have an observer present during the test runs and sample analyses. Such notification may be submitted with the test protocol, however, the actual date of initial testing shall not be less than 30 days from date of protocol submittal. Within constraints imposed by available facilities, copies of test field data sheets, laboratory sheets, unit operating logs and similar relevant data collected during the test runs shall be provided to the Secretary’s observer upon request at the conclusion of the tests. Any such data or other information so made available shall be treated as confidential upon request by the operator and shall not be made available to the public. The owner or operator shall place the word “confidential” upon all such information which is gathered and retained by the Secretary. If facilities and circumstances allow, the Secretary’s test observer shall, at his or her option, observe the laboratory analyses. 7.5. A compliance test report providing the information summarized below and any additional information that the Secretary may require shall be submitted to the Secretary within 60 days, or within such other time period as requested and approved by the Secretary, of the completion of the compliance testing. 7.5.1. General Information 7.5.1.a. Plant name and location 7.5.1.b. Units/stacks tested 7.5.1.c. Name and address of company performing the tests 7.5.1.d. Test dates and times 7.5.2. Report Certification. The following persons shall certify that the test report contains true and accurate information: 7.5.2.a. Test team supervisor 7.5.2.b. Reviewer of test report (if applicable) 7.5.2.c. If test is performed by source owner, the report shall also be certified by facility owner/operator 19 Appendix 45-2 7.5.3. Test Summary 7.5.3.a. Description of emissions sources/stacks tested 7.5.3.b. Purpose of test 7.5.3.c. Pollutants measured 7.5.3.d. Operating data 7.5.3.d.1. Unit(s) configuration and air pollution control equipment flow diagrams. 7.5.3.d.2. Summaryofoperatingparametersincludingsteamorelectricalproductionrates and other relevant parameters measured and recorded and/or calculated for test periods shall be attached to the report. 7.5.3.d.3. Pertinent control equipment and operating data recorded and/or calculated for the test period should be attached to the report. As each boiler operation and associated control equipment normally presents a unique case, pertinent data shall be determined on a case-by-case basis. 7.5.3.d.4. Description of any unusual or non-typical operating mode, fuels, soot blowing, blowdown, etc. occurring or used during the tests. 7.5.4. Test Results. 7.5.4.a. Mass emission test results with emissions reported in units of the applicable standard and in pounds per hour. 7.5.4.b. Visible emissions test results, if applicable, as measured by observer or transmissometer. Ifobservedbypersonnelfromtestcompanyorplant,evidenceofobserver’scertification shall be attached to the report. 7.5.4.c. Description of collected samples (if such information is deemed to be useful). 7.5.4.d. Description and discussion of real or apparent errors involved in test or process measurements, analysis, etc. 7.5.5. Test Procedures 7.5.5.a. Description of test equipment including drawing of sampling train. 7.5.5.b. Description of test procedures employed with detailed documentation of any deviations from methods required by Appendix 45-2. 7.5.5.c. Description of analytical procedures employed with detailed documentation of any deviations from methods required by Appendix 45-2. 7.5.5.d. Dimensioned drawing of sampling port location showing distances to upstream and 20 Appendix 45-2 downstream gas flow disturbances. 7.5.5.e. Cross-sectional drawing of sampling plane showing location and numbers or other designations of sampling points. 7.5.6. Appendix. 7.5.6.a. Copies of original field data sheets from test runs. 7.5.6.b. Copies of original log sheets, strip charts and other process or control equipment data recorded during tests. These attachments shall be certified by a responsible plant official. As each boiler operation and associated control equipment normally presents a unique case, pertinent data shall be determined on a case-by-case basis. 7.5.6.c. Laboratory report including chain of custody. 7.5.6.d. Description of test equipment calibration procedures and calibration results for test equipment used. 7.5.6.e. Description of calibration performed on devices recording important operating data during the tests. 7.5.6.f. Copies of strip charts or other original outputs from continuous emission monitoring (CEM) equipment on the tested source and description of CEM system calibration and operation prior to and/or during tests. 7.5.6.g. Originals of any visible emission readings taken during test period. 7.5.6.h. Copies of relevant correspondence such as West Virginia Department of Environmental Protection letters approving test method variances. 7.5.6.i. Names and titles of persons involved in the test including sampling team members, company personnel, and outside observers. 7.6. Subject to the provisions of section 6 of Appendix 45-2, Minor Exceptions, a complete sampling run is one1 complete determination of the total particulate matter emission rate through the test stack for which: 7.6.1. The composite particulate matter sample is extracted from the duct or stack at a location and from the number of sampling points prescribed in Method 1 of 40 CFR, Part 60, Appendix A and 45CSR16; 7.6.2. The sampling equipment and its method of operation for collection of particulate sample meets the criteria and requirements prescribed in Method 5, 5B or Method 17 of 40 CFR, part 60, Appendix A and 45CSR16; 7.6.3. The overall sampling rate is within ± 10% of the overall isokinetic sampling rate, as calculated in Method 5, 5B or Method 17 of 40 CFR, Part 60, Appendix A and 45CSR16; whichever is 21 Appendix 45-2 applicable; 7.6.4. The stack gas components data is determined as prescribed by Methods 3 and 4 of 40 CFR, Part 60, Appendix A and 45CSR16; 7.6.5. The other provisions of Appendix 45-2 are met and sufficient heat input and fuel quality data is provided to verify that the requirements of section 8 are met; and 7.6.6. Sufficient data and commentary is provided with the submitted test report forms to allow the Secretary or his designee to evaluate the reported test results and the conditions under which they were obtained. Section 8. Heat Input Data Measurements. 8.1. General. 8.1.1. The data measurements required to determine the total heat input to the fuel burning unit(s) vented by the test stack during the test run period depends on the computational method applicable. Appendix 45-2 prescribes 3 computational methods: Method 1H - Fuel Use Basis, Method 2H - Steam Balance Basis and Method 3H - Flue Gas Analysis Basis. 8.1.1.a. The test supervisor is to submit data on the heat input(s) based on the Fuel Use Basis (Method 1H) whenever coal scales or other fuel meters, as appropriate, are available. 8.1.1.b. If the appropriate fuel metering device(s) are not available, Method 2H - Steam Balance Basis is to be used. 8.1.1.c. For all test runs also submit data on the heat input(s) based on Method 3H - Flue Gas Analysis Basis, in addition to the data required by Method 1H or 2H, whichever is applicable. 8.1.2. The following subsections detail the specific data required for each method and the means of obtaining these data. 8.2. Fuel Use Method (1H). 8.2.1. This computational method requires: 8.2.1.a. The measured amount of all fuel(s) fired in the fuel burning units during each test run period, as determined by continuous coal scales or equivalent and/or oil flow and/or gas meter(s). When gas is fired, the temperature and pressure of the gas meter(s) are needed. 8.2.1.b. The average moisture, ash, sulfur, volatile matter, and Btu value(s) of fuels fired in the fuel burning units during the test run period is to be determined and reported as follows: 8.2.1.b.1. For coal: 8.2.1.b.1.A. Obtain a representative sample of the coal fired in each fuel burning unit during the test run period. This sample is to be obtained in accordance with the Commercial Sampling 22 Appendix 45-2 Procedure of ASTM Method D 2234-76 or its latest revision. Consult this ASTM standard for details of the required procedures. Sampling and analysis of coal entering bunkers or silos feeding the fuel burning unit to be tested is also acceptable provided that ASTM requirements are met and that such sampling/analysis properly represents the quality of the coal burned during the test periods. 8.2.1.b.1.B. Prepare the reduced gross sample, obtained above, for laboratory analysis in accordance with ASTM Method D 2013-72, “Preparing Coal Samples for Analysis” or its later revision. Consult this ASTM standard for details of the required procedure. In this ASTM method, further amplification is given to the methods of reducing the gross sample to a laboratory sample and preparing the laboratory analysis. The laboratory sample is so prepared that 100% of the coal sample shall pass through a No. 60 (250 micron) sieve. The final product is thoroughly mixed prior to extracting analytical samples. 8.2.1.b.1.C. Extract an analytical sample from the laboratory sample and determine the moisture, ash, and volatile matter content of this sample in accordance with ASTM Method D 3173-73 or ASTM Method D 2961-87 (Moisture), ASTM D 3174-82 (Ash), and ASTM D 3175-82 (Volatile Matter) or their latest revisions. Consult these ASTM standards for details of the required procedures. In these ASTM methods, procedures are prescribed for determining the moisture, ash, and volatile content of the sample. 8.2.1.b.1.D. Extract another analytical sample from the laboratory sample and determine the Btu content of the sample in accordance with ASTM Method D 2015-77 “Gross Calorific Value of Solid Fuel by the Adiabatic Bomb Calorimeter” or its latest revision. Consult this ASTM standard for details of the required procedure. 8.2.1.b.1.E. Extract another analytical sample from the laboratory sample and determine total sulfur content of the sample in accordance with ASTM Method D 3177-75 “Test for Total Sulfur in the Analysis Sample of Coal and Coke” or ASTM Method D 4239-85 or their latest revisions. Consult these ASTM standards for details of the required procedures. 8.2.1.b.1.F. Send a sealed and marked one1 pint sample of the laboratory sample representative of the gross sample, to the Secretary with the test report. If drying was used in reducing the gross sample to the laboratory sample, indicate the percent loss of moisture during this process. For each container provide the test identification number assigned by the West Virginia Department of Environmental Protection in accordance with subdivision 7.2.2 of Appendix 45-2 and the test run number. 8.2.1.b.2. For fuel oils: Determine the supplier’s name and address, and the specifications for the oil supplied. Use the supplier’s specifications when available for the ash content and Btu value of the oil. When such specifications are not available, determine the grade of oil fired, by referring to any Standard Engineering Handbook. As such the Handbook and appropriate edition should be properly identified, for inclusion as part of any results submitted to the agency for the ash, sulfur and Btuvalues. Sendaneight8ounce,sealedandmarked,sampleoftheoilfiredduringthetesttotheSecretary with the test report. 8.2.1.b.3. For natural gas: Determine the supplier’s name and address, and the specification of the natural gas supplied. Use the supplier’s specification for the Btu value of the fuel. Ash may be considered negligible. 23 Appendix 45-2 8.2.1.b.4. For other fuels: Determine the name and address of the supplier(s) or producer(s) of any other materials fired during the test run period. Determine the source(s) of the fuel(s). Use the supplier(s)’/producer(s)’ specifications for the ash, sulfur, and Btu value. When such specifications are not available, resolve with the Secretary or his designee, the method which shall be used to determine these values, prior to conducting the test. Submit an appropriate small sample of the fuel fired, if other than a gas, to the Secretary in a sealed and marked sample container. 8.3. Steam Balance Method (2H). This method requires a materials balance and inlet and outlet water/steam or other media pressure and temperature data during the test run period, for the boiler(s) of the fuel burning unit(s) vented by the test stack. 8.3.1. Measure the mass flow rate of all water/steam or other media flowing through each boiler, including blowdown. 8.3.2. Measure the inlet and outlet pressure and temperatureof each water/steam circuit, including blowdown. 8.3.3. Construct a flow diagram of the water/steam or other media flow circuit(s) on Form THI-II (2H). Record the measured data on this form, indicating the data points on the diagram. 8.3.4. Determine the boiler manufacturer’s name and address, and the boiler type and model number. From the manufacturer’s specification, determine the boiler(s) thermal efficiencies. If such specifications are not available, describe in detail the basis and method of selecting the value used. 8.4. Flue Gas Analysis Method (3H). 8.4.1. This method involves determining the heat input for the boiler(s) of the fuel burning unit(s) vented by the test stack utilizing: 8.4.1.a. Appropriate F-factors as contained in 40 CFR, Part 60, Subpart D and 45CSR16; and 8.4.1.b. Total volume of stack gas discharged through the stack during the test run; and 8.4.1.c. The average excess air discharged [O % 2r CO %] t2rough the test stack during the test run period. 8.4.2. Appropriate F-factors are to be obtained from 40 CFR, Part 60, Subpart D and 45CSR16, unless carbon content of fly ash or bottom ash exceeds 5 percent on a per weight basis. In these cases, consult the Secretary or his designee prior to conducting the test to determine and resolve a suitable F-factor adjustment. 8.4.3. Total Volume of Stack Gas. The total volume of stack gas is determined from: 8.4.3.a. Volume meter readings obtained during subject test run and recorded on Form TD: Test Run Data Sheet for each test run. 8.4.4. Stack Excess Air. 24 Appendix 45-2 8.4.4.a. For low nitrogen content fuel(s) (coal, fuel oil, natural gas), the stack excess air can be computed from the data obtained from the Orsat analysis and recorded on Form TOA - Laboratory Data Sheet (Orsat) for each test run. If blast furnace gas, producer gas, or other fuel(s) of high nitrogen content areused,consulttheSecretaryorhisdesigneepriortoconductingthetesttodetermineandresolveasuitable method of determining the excess air when such fuel(s) is burned. Section 9. Computations and Data Analysis. This section prescribes the computational method to be used in computing the particulate matter stack emission rate for the test and evaluating the supporting test data. Perform the computations and analysis prescribed in this section for the data obtained from each test run which is to be part of the submitted test results. Record the measured data and the appropriate computations on the designated test report forms, which may be obtained from the Secretary upon request. Submit sufficient commentary with the test report data to fully describe the conditions under which the data was obtained and any factors which might affect the evaluation of the test results. 9.1. Particulate Matter Sample Weight Determination. (Form TLP - Laboratory Data Sheet (Particulate)). 9.1.1. Mf = particulate matter (grams) collected by the primary filter, including any prefilter if used 9.1.2. Ma = particulate matter (grams) obtained from the evaporation of the acetone washings of the internal sampling train surfaces exposed to the particulate sample prior to the primary filter 9.1.3. Ab = particulate matter residue (grams) in the volume (Va) of acetone wash used for Ma above, as determined by the acetone blank analysis [i.e., Ab = (Sd) (Va); where Sd equals the residue found in the acetone blank analysis in gm/ml, and Va equals the volume of acetone used in the acetone wash for Ma above] 9.1.4. Mn = Mf + Ma - Ab = the indicated weight of particulate matter collected, in grams 9.2. Moisture Determination. (Form TLH : Laboratory Data Sheet - Moisture; Forms TD; Test Run Data Sheet). 9.2.1. Record all measured and calculated data on the appropriate forms. 9.2.2. Compute and record the following: 9.2.2.a. Vm = (ft ) the sum of all ΔDGR for the run, where ΔDGR is equal to the n idicated amount of gas sampled at each point during the extraction interval ○ 9.2.2.b. Tm = ( F ) average temperature of the dry gas meter during the test run. Tm = average dry gas meter temperatures ( F ) at each sampling point. 9.2.2.c. Pm = (in. Hg) average absolute pressure at the dry gas meter during the test run. Pm = the average absolute pressure at the dry gas meter for each sample point, where Pm = Pb - Vac; Pb = barometric pressure, Vac = meter vacuum. 9.2.2.d. Wc = amount of water collected in condenser or impingers (grams) 25 Appendix 45-2 9.2.2.e. Wd = amount of water collected by the drying agent used after the condenser or impingers (grams) 9.2.2.f. W = Wc + Wd (grams) 9.2.2.g. B = percent moisture in the sampled gas by volume on a wet basis, divided by 100 B= W/(((374* Pm * Vm)/Tm + 460)) + W) 9.2.2.h. w = moisture correction factor ratio of the volume of wet sample gas to the volume of dry sample gas W = 1/(1-B) 9.3. Sample Gas Density and Excess Air Determination. (Form TOA - Laboratory Data Sheet (Orsat)). 9.3.1. Gas Density. 9.3.1.a. Record the Orsat analysis for all three 3 runs on Form TOA (Laboratory Data Sheet) on lines 1 through 9. Compute and record the average value of CO , O ,2CO 2nd N for ea2h run on line 10 or the value of these components of the composite sample, if obtained (optional), on line 11. 9.3.1.b. Transcribe the values of w (moisture correction factor) from Form TLH to Form TOA in blocks 12 for each run. Transcribe the values of B, the percent water (wet basis) from Form TLH to Form TOA in column 13, line 14, for each run. 9.3.1.c. Correct the average component volumetric percentages, dry basis (line 10), to volumetric fractions (wet basis), by dividing by 100w and enter these values on line 14 for each test run. 9.3.1.d. Multiply each of these volumetric fractions (wet basis - line 14) by the corresponding molecular weights on line 15 and enter the values on line 16. 9.3.1.e. Enter the sum of the values on line 16 for each run in the appropriate box on line 17, the apparent molecular weight of the wet gas (Mg). 9.3.1.f. Determine the wet gas density for each run by dividing the molecular weight for the run (on line 17) by the number 29 and enter this quotient in the appropriate box on line 18. 9.3.2. Excess Air. Compute and record the excess air fraction for each run using the average dry gas analysis from line 10 and the formula shown on line 20. Record excess air fraction (EA) in the appropriate box on line 19. Note: The excess air fraction equation present on line 20 of Form TOA is not applicable when producer gas, blast furnace gas or other fuels high in nitrogen content are used. 9.4. Actual Sample Gas Volume Determination. (Form TD : Test Run Data Sheet). 9.4.1. For each point sampled during the run compute the actual volume drawn through the 26 Appendix 45-2 ○ sampling nozzle adjusted to standard conditions of 68 F and 29.92 inches of Hg as indicated below: qm = Actual sample volume (in cubic feet) drawn through the sampling nozzle for each sampled point adjusted to 68 F and 29.92 inches of Hg. qm = (ΔDGR)(w) * ((528/(Tm + 460)) * (Pm/29.92) Where: ΔDGR, w, Tm, and Pm are defined in subsection 9.2 and are recorded on Form TD. 9.4.2. Record the computed values of qm for each sampled point on the appropriate line of the column labeled qm on Form TD. Sum the values of qm for all points included in the run and enter this value (Qm) in the block so labeled. 9.5. Isokinetic Sample Volume Determination. (Form TD: Test Run Data Sheet). 9.5.1. For each point samples during the run, compute the volume of sample gas (adjusted to 68 F ○ and 29.92 inches of Hg) that would have been drawn through the sampling nozzle if isokinetic conditions were maintained, as indicated below: qo = Isokinetic sample volume, the volume of sampled gas (in cubic feet) for each sampled point, if ○ isokinetic conditions were maintained, adjusted to standard conditions of 68 F and 29.92 inches of Hg. For conditions where static pressure in the duct or stack being tested is more than 20 in. H 2, consult with Secretary or his designee. qo = 60 * (528)(Fp)(An) * ((ΔH/ (Ts + 460)) 0.5* Δt Where: Fp = combined correction factor for units and Pitot tube deviation: Standard tube = 2.90 (units) x 1.00 (deviation) = 2.90 Type S tube = 2.90 (units) x 0.83*(deviation) = 2.41 *Note: The deviation for the Type S tube may vary for different sampling configurations and should be determined by calibration against a standard pitot tube for each Pitobe arrangement per Method 2 of 40 CFR, Part 60, Appendix A and 45CSR16. An = the cross-sectional area of the sampling nozzle in (ft ) ΔH = Pitot tube differential reading** in inches of H 2 **Note: If the particular pitot tube differential indicator used is calibrated to give a reading of the square root of ΔH (√ΔH), change the heading of the “ΔH” column on Form TD to √ΔH and modify your computations for qo as appropriate. ○ Ts = Average stack gas temperature (in F) at each sampled point during the extraction time at that point. Δt = elapsed time at each sampling point (minutes) 9.5.2. Record the computed values of qo for each sampled point on the appropriate line of the column labeled qo on Form TD. Sum the values of qo for all points included in the run and enter this value 27 Appendix 45-2 (Qo) in the block so designated. 9.6. Fractional Isokinetic Rate Determination. (Form TD: Test Run Data Sheet). 9.6.1. For each point sampled during the run, compute the point isokinetic factor (ISKp), which indicates the average degree of deviation from isokinetic conditions during the sampling (extraction) time at that point. ISKp is computed as follows: ISKp = the point isokinetic factor, the ratio of the○actual sample volume to the isokinetic sample volume, both volumes adjusted to standard conditions of 68 F and 29.92 inches of Hg ISKp = (qm/qo) Where: qm is defined in subsection 9.4 and qo is defined in subsection 9.5 of Appendix 45-2, both values are recorded for each point on Form TD. 9.6.2. Record the computed value of ISKp for each sampled point on the appropriate line of the column labeled ISKp on Form TD. The value of ISKp for each sampled point should not vary greatly from the overall isokinetic factor (ISKo). 9.6.3. For each run, compute the overall isokinetic factor (ISKo), which indicates the overall degree of deviation from isokinetic conditions during the run, and which is used in the weight emission rate computations of the next section. ISKo is computed as follows: ISKo = the overall isokinetic factor, the ratio of the total actual sample volume to the total isokinetic sample volume, both volumes adjusted to standard conditions of 68 F and 29.92 inches of Hg. ISKo = (Qm/Qo) Where: Qm is defined in subsection 9.4 and Qo is defined in subsection 9.5 of Appendix 45-2, both values are recorded for each run on Form TD. 9.6.4. Record the computed value of ISKo for each run in the block so designated on Form TD. If the value of ISKo is outside the range of 0.9 to 1.10, reject the run result. 9.6.5. Compute the value %ISK as follows: retain the sign and record on Form TR-II: Summary of Test Run Results. %ISK = 100(ISKo – 1) 9.7. Particulate Matter Emission Rate Determination. (Form TD: Test Run Data Sheet, Form TR- II: Summary of Test Run Results). The particulate matter emission rate for each run is computed from the following equation: M(P)n = (Mn/C) * (As/An) * (60/ Θ) * (1/ISKo) 28 Appendix 45-2 Where: M(P)n = the particulate matter emission rate (in pounds per hour) for the test run Mn = Mf + Ma - Ab indicated weight of particulate matter (in grams) collected by the sampling train. C = 453.592 grams/pound As = the cross-sectional area of the sampling plane (ft ) An = the cross-sectional area of the sampling nozzle (ft ) 60 = 60 minutes per hour Θ = the sum of all extraction times at all points sampled per run (the sum of Δt’s). The total sampling time, not including movement time from port to port. ISKo = Qm/Qo = the overall isokinetic factor for the run. The ratio of total actual volume sampled to the total isokinetic volume, both values adjusted to 68 F and 29.92 inches of Hg on a wet basis. The values of Mn, As, An, Θ and ISKo for each run are recorded on Form TD: Test Run Data Sheet. Record the value of M(P)n for each test run on Form TR-II: Summary of Test Run Results. 9.8. If more than one1 sampling plane was required to evaluate the total stack emission rate, perform the computation specified in subsection 9.7 of Appendix 45-2 for each sampling plane, then sum the values of M(P)n for all sampling planes used. Record the total emission rate for each run (all sampling planes) on Form TR-II as above, then compute the average stack emission rate for the test. Note the number and designations of the sampling planes used under comments. If more than one1 sampling train was used simultaneously to sample the required number of sampling points at one1 sampling plane, the values of Mn, Qm, and Qo are the sum total values for all the sampling trains used for the one1 sampling plane. 9.9. Heat Input Determinations. (Forms THI-II: Heat Input Data Sheets: Form TOA; Laboratory Data Sheet (Orsat); Form TR-II: Summary of Test Run Results). 9.9.1. This subsection prescribes 3 methods of computing the total heat input to the (similar) fuel burning unit(s) vented by the test stack: Method 1H, Fuel Use Basis, Method 2H, Steam Balance Basis, and Method 3H, Flue Gas Analysis Basis. Submit data and computations on the appropriate forms. 9.9.2. Summarize the results of the selected computational methods on Form TR-II: Summary of Test Run Results for each run. Record the type units tested (see definitions for type), the total number of similar units associated with the test run results, the two2 values of the total heat input for all the units associated with the test run results, as computed by the two2 selected methods, the total design heat input and the total maximum normal operating load for the units associated with the test result (see definitions for the heat input terms). 9.10. Method 1H - Fuel Use Basis. 9.10.1. From the data obtained in accordance with subsection 8.2, Heat Input Data Measurements, compute the heat input for each fuel burning unit for which this method is to be used, as follows: n 6 HI = (60/ Θ) * ∑ ((Fi * HVi)/10 i=1 29 Appendix 45-2 Where: 6 HI = Heat input per fuel burning unit(s) in 10 Btu per hour Fi=Thequantityofeachfuelfiredinthisfuelburningunitduringthetotaltestrunperiod(Θ)in appropriate dimension units (e.g., pounds, gallons, SMCF) HVi = The average Btu value of each fuel used, in appropriate dimensional units related to the Fi units (e.g., Btu/lb, Btu/gal, Btu/SMCF), on an as fired basis Θ = The total test run period in minutes. The sum of all extraction intervals (Δt) n = The number of different fuels fired in the fuel burning unit during the test run period Note: When more than one1 fuel burning unit is vented by the test stack, sum the individual heat input values for all units of the same type vented by the test stack to obtain the total heat input for the test. 9.10.2. Record the values used in the computations, and the results on Form THI-II (1H) 9.11. Method 2H - Steam Balance Basis. 9.11.1. From the data obtained in accordance with subsection 8.3 of Appendix 45-2, compute the heat input for each fuel burning unit for which this method is to be used, as follows: 4 HI = ((((mf * (ho – hi)) + (Mbd * hbd)))/(10 * BE)) Where: HI = Heat input per fuel burning unit in 10 6Btu per hour ho = Average enthalpy of steam/water or other media leaving the boiler of the fuel burning unit in Btu/lbm hi = Average enthalpy of steam/water or other media entering the boiler of the fuel burning unit in Btu/lb mf = Average mass flow rate of steam/water or other media through the boiler in lbm/hour Mbd = Average mass flow rate of blowdown in lbm/hour hbd = Average enthalpy of steam/water or other media leaving the boiler as blowdown in Btu/lbm BE = The boiler thermal efficiency (percent) Note: The enthalpy values for the above equation can be determined from the inlet and outlet temperatures and pressures of the steam/water or other media flowing through the boiler using appropriate steam tables. 9.11.2. Record the steam flow, temperatures, pressures, and enthalpy values on the steam/water or other media circuit flow diagram required on Form THI-II (2H). Also record the necessary calculations and results on Form THI-II (2H) or attached sheet(s). Sum the heat input values of all fuel burning units of the same type vented by the test stack. 9.12. Method 3H - Flue Gas Analysis Basis: 9.12.1. From data obtained in accordance with subsection 8.4 of Appendix 45-2, compute the heat input for each fuel burning unit for which this method is to be used, as follows: HI = ((mf * (ho – hi) + (Mbd * hbd))/(10 * BE) Where: 6 HI = Heat input per fuel burning unit in 10 Btu per hour Vmstd = Volume of gas sample measured by the dry gas meter during run corrected to standard conditions 30 Appendix 45-2 of 68 F and 29.92 inches Hg. As = Cross-sectional area of the sampling plane (ft ) 2 2 An = Cross-sectional area of the sampling nozzle (ft ) %O =2Percent oxygen content by volume as taken from Orsat analysis on Form TOA F-factor = a factor representing a ration of the dry flue gases generated to the calorific value of the fuel combusted (dscf/10 Btu), See 40 CFR, Part 60, Subpart D and 45CSR16 Θ = Sum of all extraction time at all points sampled per run (minutes) 9.12.2. Record Vmstd, %O , F-f2ctor, and Θ on Form THI-II (3H). Record calculations. 31