General Monitoring Requirements and Options

Louis Nichols

US EPA, Clean Air Markets Division (CAMD)

December 2007

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

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

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

Monitoring Requirements

SO2 Mass Emissions (lb/hr)

Heat Input (mmBtu/hr)

NOx Mass Emissions (lb/hr) – Subpart H (§§75.70-75.75)

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

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

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

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

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

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

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

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

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

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

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

NOx Correlation Curve Segments

0.000

0.050

0.100

0.150

0.200

0.250

0.300

0 200 400 600 800 1000 1200 1400

Heat Input Rate (mmBtu/hr)

NO

x E

mis

sio

n R

ate

(lb

/mm

Btu

)

Operating Level 1

Operating Level 2

Operating Level 3

Operating Level 4

Segment 1

Segment 2

Segment 3

Segment 4

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

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

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

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

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

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)

LME Monitoring Option

Low Mass Emissions Units

§75.19

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

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

Initial Certification Timeline

Submit Monitoring

Plan & Certification

Test Notification

Start of the Certification Test Period

Certification Testing

Deadline

Certification Application Submitted

(Electronic and Hardcopy)

Deadline for Certification

Approval

No later than 120 Days after receipt

of completed Certification Application

Package

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)

First certification test performed

Date of Provisional Certification

All Certification Testing Completed

Required Certification Testsfor NOx and SO2 Concentration Systems

7-day Calibration Error Test Linearity Check RATA Bias Test Cycle Time Test DAHS Verification

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

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