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General Monitoring Requirements and Options

General Monitoring Requirements and Options. Matt Boze US EPA, Clean Air Markets Division (CAMD) August 2007. Monitoring Deadlines. Deadlines for Initial Certification for existing units: Annual NOx Trading Program - January 1, 2008 SO2 Trading Program – January 1, 2009

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General Monitoring Requirements and Options

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  1. General Monitoring Requirements and Options Matt Boze US EPA, Clean Air Markets Division (CAMD) August 2007

  2. Monitoring Deadlines • Deadlines for Initial Certification for existing units: • Annual NOx Trading Program - January 1, 2008 • SO2 Trading Program – January 1, 2009 • Ozone Season NOx Trading Program – May 1, 2008

  3. Monitoring Regulations • 40 CFR Part 72.2 • Basic Definitions referred to throughout Part 75 • 40 CFR Part 75 - Continuous Emissions Monitoring • Monitoring Provisions • Operation and Maintenance Requirements • Missing Data Substitution Procedures • Record Keeping and Reporting Requirements

  4. Monitoring Regulations • 40 CFR Part 75 - Appendices • App A, Specifications and Test Procedures • App B, Quality Assurance and Quality Control Procedures • App F, Equations, F-factor

  5. Monitoring Requirements • SO2 Mass Emissions (lb/hr) • Heat Input (mmBtu/hr) • NOx Mass Emissions (lb/hr) – Subpart H (§§75.70-75.75)

  6. Reporting Requirements -Subpart H NOx Monitoring • Annual Reporting • Submit quarterly Electronic Data Reports (EDR or ECMPS) • Only the NOx mass data from the Ozone Season is used for emissions trading for ozone season trading program • Follow standard Part 75 QA/QC timelines and data validation procedures • A must for Acid Rain units • May be required by the State rule (check with state) • Ozone Season Only Reporting • Only submit 2nd and 3rd quarterly electronic reports • Follow special QA/QC timelines and data validation procedures described in §75.74(c) • This option is a choice not a requirement • Do not get same grace period as annual reporters

  7. Monitoring Options for DeterminingNOx Mass Emissions • NOx Concentration (ppm) & Stack Flow Rate (scfh) • NOx Emission Rate (lb/mmBtu) & Heat Input Rate (mmBtu/hr) • http://www.epa.gov/airmarkets/progsregs/cair/docs/ CAIR_NOx_Monitoring_Final_04-23-07.pdf

  8. SO2 Mass Monitoring Options • SO2 Mass • SO2 and Stack flow monitor, or • Part 75, Appendix D (for gas or oil fired peaking units) • LME Method §75.19

  9. NOx Emission Rate Monitoring Options • NOx Emission Rate • NOx-Diluent CEMS, or • Part 75, Appendix E (for gas or oil fired peaking units) • LME Default NOx Emission Rate

  10. NOx-Diluent CEMS • Two components • NOx Concentration Analyzer & • CO2 or O2 Concentration Analyzer as the Diluent • Part 75, Appendix F, section 3, provides the equations that are used to compute NOx emission rate (lb/mmBtu) given: • NOx concentration • CO2 or O2 concentration • F-factor for the fuel combusted

  11. Part 75, Appendix E • May be used in lieu of a NOx-diluent CEMS for determining hourly NOx emission rate (lb/mmBtu) • Applicable only to Gas and Oil-Fired Peaking Units

  12. Part 75, Appendix E • Peaking unit (§ 72.2 - Definitions) • An average capacity factor of no more than 10.0% during the previous three calendar years and • A capacity factor of no more than 20.0% in each of those three calendar years • Ozone season only reporters can qualify on an ozone season only basis §75.74(c)(11) • Initial qualification for peaking status by • Three years (or ozone season) of historical capacity factor data, or • For newer or new units, a combination of all historical capacity factor data available and projected capacity factor information

  13. Part 75, Appendix E • For units that make a change in capacity factor may qualify by: • Collecting three calendar years of data following the change to meet the historical capacity factor specification, or • Collect one calendar year of data following the change showing a capacity factor of less than 10.0% and provide a statement that the change is considered permanent

  14. Part 75, Appendix E • Units that hold peaking status must continue to meet both the 10% three year and 20% single year (or ozone season) criteria to retain peaking status • If a unit fails to meet the criteria it must install & certify a NOx CEM by January 1 of the year after the year for which the criteria are not met • A unit may then re-qualify only by providing three new years (or ozone seasons) of qualifying capacity factor data

  15. Part 75, Appendix E • The average NOx emission rate (lb/mmBtu) is determined from • Periodic fuel specific NOx emission rate testing at four, equally spaced load levels • Boilers • Method 7E for NOx • Method 3A for the diluent • Stationary gas turbines • Method 7E for NOx • Method 3A for the diluent

  16. Part 75, Appendix E • Plot the NOx Emission Rate vs. Heat Input Rate • Use the graph of the baseline correlation results to determine the NOx emission rate corresponding to the heat input rate for the hour • Linearly interpolate between reference points to the nearest 0.001 lb/mmBtu using heat input values rounded to the nearest 0.1 mmBtu/hr

  17. Segment 4 Segment 3 Operating Level 4 Operating Level 1 Segment 2 Operating Level 3 Segment 1 Operating Level 2

  18. Heat Input Rate Monitoring Options • Heat Input Rate • Stack Flow & *Diluent (%CO2 or O2) CEMS, or • Fuel flow monitoring via Part 75, Appendix D, or • LME Long term fuel flow or Max Rated HI *Note: If the diluent is on dry basis must correct for moisture

  19. Heat Input Rate from Stack Flow and Diluent System • Components for a Stack Flow-Diluent Heat Input System • Stack Flow Monitor & • CO2 or O2 Concentration Analyzer as the Diluent • Moisture monitor if necessary • Part 75, Appendix F § 5, provides the equations that are used to compute the heat input rate (mmBtu/hr) given: • Volumetric Stack flow • CO2 or O2 concentration • F-factor for the fuel combusted • Moisture correction

  20. Part 75, Appendix D Fuel Flow Monitoring • Applicability • May be used in lieu of flow monitoring systems for the purpose of determining the hourly heat input rate and SO2 mass emissions • Gas and Oil fired units only • Heat input rate (mmBtu/hr) is determined from the: • Fuel Flow Rate (fuel flowmeter), and • Gross Calorific Value (GCV) of the fuel • Sulfur content of fuel

  21. Part 75, Appendix D • Fuel Flowmeters • Must meet the fuel flowmeter accuracy specification for initial certification (App D § 2.1.5) • Visual inspection of orifice, nozzle, and venturi meters every 3 years • Must pass a fuel flowmeter accuracy test at least once every four QA operating quarters (App D § 2.1.6) • Fuel flowmeter accuracy < 2% of the flowmeter’s upper range value

  22. Part 75, Appendix D • Fuel Flowmeters Certified by Design • Orifice Plate • Nozzle • Venturi • Fuel Flowmeters Certified by Accuracy testing • Coriolis • Annubars • Vortex • Turbine meters • others

  23. Appendix D Basic Fuel Sampling Options • Oil Sampling • Flow proportional/weekly composite • Daily manual sampling • Storage tank sampling (after each addition) • As delivered (sample from delivery vessel) • Gas Sampling • Monthly Samples (pipeline natural gas, or natural gas, or any gaseous fuel having demonstrated a “low GCV or sulfur variability”) • Daily or Hourly Samples (any gaseous fuel not having a “low GCV or sulfur variability”) • Lot sampling (upon receipt of each lot or shipment)

  24. LME Monitoring Option Low Mass Emissions Units §75.19

  25. Overview of the Certification Process • Submit an initial monitoring plan and notification of initial certification testing 45 days prior to starting certification testing (§75.61 & §75.62) • Conduct all required testing for the system(s) to be certified • DAHS Verification • 7-day Calibration Error • Cycle Time • Linearity • RATA & Bias Test

  26. Overview of the Certification Process (cont.) • Upon successful completion of all certification tests, the system(s) are provisionally certified • The completed certification application is submitted within 45 days after completing all initial certification tests • Permitting Authority has 120 days after receipt of a complete certification application to review the application and approve or disapprove certification

  27. Initial Certification Timeline Submit Monitoring Plan & Certification Test Notification Certification Application Submitted (Electronic and Hardcopy) Start of the Certification Test Period Deadline for Certification Approval Date of Provisional Certification Certification Testing Deadline All Certification Testing Completed No later than 120 Days after receipt of completed Certification Application Package First certification test performed 45 Days Prior to the first day of Initial Certification Testing No later than 45 days after completion of Certification Testing Monitoring Deadline in SIP (January 1, 2008 Annual NOx May 1, 2008 Ozone Season NOx January 1, 2009 SO2)

  28. Required Certification Testsfor NOx and SO2 Concentration Systems • 7-day Calibration Error Test • Linearity Check • RATA • Bias Test • Cycle Time Test • DAHS Verification

  29. Required Certification Tests for NOx-Diluent Systems • 7-day Calibration Error Test performed on both the NOx Concentration and Diluent components • Linearity Check performed on both the NOx Concentration and Diluent components • RATA and Bias Test • Cycle Time Test performed on both the NOx Concentration and Diluent components; cycle time for the system is the highest of the components • DAHS Verification

  30. Types of Electronic Reports • Initial Monitoring Plans • Certification Application • Quarterly Electronic Data Report* • Includes: • Most up-to-date version of the Monitoring Plan • Latest Certification and/or QA Tests information * ECMPS is different

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