Oil and Gas LDAR Requirements in EPA GHG Reporting Rule
January 4, 2019

EPA Mandatory GHG Reporting Regulations – 40 CFR Part 98

The EPA’s greenhouse gas (GHG) reporting rules in 40 CFR 98 Subpart W – Petroleum and Natural Gas Systems are contained in 40 CFR 98 – Mandatory Greenhouse Gas Reporting. The rule requires a facility that has actual emissions of 25,000 metric tons or more of CO2e per year to submit an annual report of GHGs to the EPA. Below is a summary of the requirements regarding leak detection and repair (LDAR) requirements. Review the rule for specific detailed requirements.

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Equipment types Included

The rule requires the monitoring of leaks from various equipment types. This includes:  

  • Transmission storage tanks
  • Centrifugal compressor venting
  • Reciprocating compressor venting
  • Fugitive equipment leaks

Facility Types Included

Facility types required to monitor for fugitive equipment leaks include:

  • Onshore natural gas transmission compression
  • Underground natural gas storage
  • LNG storage
  • LNG import and export equipment
  • Oil and gas well site and compressor stations (with exceptions)

Components Requiring Fugitive Equipment Leak Monitoring

If mandated for the facility type, equipment leaks from the following require annual monitoring:

  • Valves
  • Connectors
  • Open ended lines
  • Pressure relief valves
  • Pumps
    Flanges
  • Components (such as instruments, loading arms, stuffing boxes, compressor seals, dump lever arms, and breather caps.

Equipment leak components do not include reciprocating and centrifugal compressor venting and do not include thief hatches or other openings on a storage vessel.

LDAR Approved Methods

  1. Optical gas imaging (OGI) instrument
  2. Method 21 using an organic volatile analyzer meter
  3. Infrared laser beam illuminated instrument
  4. Acoustic leak detection device

Definition of an Equipment Leak

  1. Optical gas imaging (OGI) instrument: a leak is detected if any emissions are detected, unless screened with Method 21 (40 CFR part 60, appendix A-7) monitoring, in which case 10,000 ppm or greater is designated a leak.
  2. Method 21 monitoring: a leak is detected if an instrument reading of 10,000 ppm or greater is measured by the meter.
  3. Infrared laser beam illuminated instrument is a leak unless screened with Method 21 monitoring, in which case 10,000 ppm or greater is designated a leak.
  4. Acoustic leak detection device to detect through-valve leakage. When using the acoustic leak detection device to quantify the through-valve leakage, you must use the instrument manufacturer's calculation methods to quantify the through-valve leak. When using the acoustic leak detection device, if a leak of 3.1 scf per hour or greater is calculated, a leak is detected.

Frequency of LDAR Monitoring

Subpart W requires a minimum one LDAR survey per calendar year using regulation specified approved methods.

More frequent monitoring can be used to obtain credit (and lower calculated emissions) for leaking components repaired during the same calendar year.

Exemptions from LDAR Monitoring

  • Onshore natural gas processing facilities are not required to monitor for leaks under Subpart W. These facilities are already required to do periodic leak detection under 40 CFR Subpart KKK, 40 CFR 60 Subpart OOOOa and State regulatory agency rules. The leaker count data gathered by these programs must be used in calculating emissions.
  • Onshore petroleum and natural gas production facilities that are not required to monitor for leaks under 40 CFR 60 Subpart OOOOa are exempt from leak monitoring under Subpart W.
  • For equipment leaks, tubing systems equal to or less than one half inch diameter are exempt from LDAR monitoring under Subpart W.

Calculating Emissions with LDAR Data

For facilities using leaking component calculations, the following data are used for calculations:

  1. Count of leakers by component type
  2. Duration of leak during the year
  3. Equations and leaker emission factors specified in Subpart W
  4. If only one LDAR survey is completed in a calendar year, then the facility must assume that the component was leaking for entire year operating (e.g., 8760 hours). If multiple LDAR surveys completed, then assume a component leaking for the number of hours between surveys within that calendar year. Review the rule for specific guidance for the calculations.
  5. Engineering estimates can be used to account for the duration (hours) a component was not operational (i.e., not operating under pressure)

Relationship to NSPS OOOOa

According to 40 CFR 98, oil and gas and compressor stations that are required to perform LDAR surveys under 40 CFR 60 Subpart OOOOa must use the NSPS OOOOa generated leaker count of components, leak duration and the corresponding leaker emission factor in calculating GHG emissions. Only the count of leaking components is included in the calculations.

Oil and gas and compressor stations that are exempt from 40 CFR 60 Subpart OOOOa are also exempt from LDAR monitoring under 40 CFR 98 Subpart W.

Onshore natural gas processing facilities required to monitor for leaks according to 40 CFR 60 Subpart KKK and 40 CFR 60 Subpart OOOOa must use the LDAR survey generated leaker count of components, leak duration and the corresponding leaker emission factor in calculating GHG emissions. Only the count of leaking components is included in the calculations.

Voluntary LDAR Monitoring

For oil and gas well and compressor facilities exempt from NSPS OOOOa, a company can voluntarily monitor for leaks using Subpart W prescribed methods and use the corresponding emission factors to calculate annual GHG emissions.

HY-BON/EDI IQR Emissions Services (LDAR) Services

HY-BON/EDI can assist your company with your required Subpart W and NSPS OOOOa LDAR leak monitoring. Our qualified specialists currently conduct LDAR monitoring for hundreds of nationwide facilities from the well head through the gas processing and transmission facilities.

Our IQR/LDAR direct measurement services can quantify the amount of gas from storage tanks to determine if a vapor recovery unit (VRU) is feasible and to size a needed combustion device.

Contact us at G3kHI=d51pQB]#[VExPZRvAB}eO or G3kHI=d51pQB8'lD]#[7oX*9UM/9SA-Ef\. for more information.