Technical Document

This version of the Technical Document was developed for the Methane Challenge program’s “Information Collection Request” renewal in 2021. It includes the following updates from the previously published version:

Following their development through the program’s “Continuous Improvement Process”, addition of commitment details for:
- Equipment Leaks/Fugitive Emissions – Compressor Isolation and Blowdown Valves (pg 10)
- Renewable Natural Gas (pg 33)
Refinement of reporting requirements for the following emission sources to ensure the program can track partner commitment progress accurately and is not collecting unnecessary data. Changes have been indicated with yellow highlighting throughout the document.
- Pneumatic Controllers (pg 6)
- Fixed Roof, Atmospheric Pressure Hydrocarbon Liquid Storage Tanks (pg 8)
- Reciprocating Compressors – Rod Packing Vent – Gathering & Processing Segment (pg 14)
- Mains – Cast Iron and Unprotected Steel (pg 24)
- Services – Cast Iron and Unprotected Steel (pg 27)
- Adding ‘alternate calculation methods’ for certain emission sources for below threshold (i.e., non-Subpart W reporting facilities ONLY) for consistency with ONE Future reporting methodologies
  - Reciprocating Compressors (Processing and Transmission & Storage) (pg 15)
  - Centrifugal Compressors (Processing and Transmission & Storage) (pg 19)
  - Transmission Pipeline Blowdowns Between Compressor Stations (pg 21)
Addition of optional data elements to report on innovative technologies and practices not covered by existing Methane Challenge commitments (pg 37)

Introduction

This document provides additional details to augment the Natural Gas STAR Methane Challenge Program (“Methane Challenge”) Best Management Practices (BMP) Commitment Framework and Partnership Agreement documents released January 21, 2016.^¹ This document provides additional information for each of the emission sources, including source descriptions, detail on voluntary mitigation options, and Greenhouse Gas Reporting Program (GHGRP) and voluntary reporting data elements that partners should report annually to EPA to track commitment progress. Where multiple mitigation options are listed, Partners can choose to implement any combination of these throughout their operations to meet their commitments.

Methane Challenge Program Reporting

To provide context for participation in the Program and facilitate annual tracking of progress, EPA collects the following information from partner companies during facility registration and management in the Methane Challenge reporting module of the electronic Greenhouse Gas Reporting Tool (e-GGRT):

List of included facilities that report to Subpart W (GHGRP facility ID)
List of included facilities not reporting to Subpart W (Methane Challenge facility ID²)
List of facilities acquired/divested during the reporting year

In the following sections of this document, for each emission source, the “Reporting” table summarizes the Data Elements the Methane Challenge Program utilizes to track partner company progress towards their commitments, including the following information:

Emission Source: For each Emission Source that a company has committed to address^³, the company will provide information on all occurrences of that source across company/unit operations. Data collection will include both unmitigated sources and sources that have implemented mitigation options (including supplementary information for those sources that have eliminated emissions completely).
Quantification Method: For most Emission Sources, there is a corresponding method or methods to quantify methane emissions.
Data Elements Collected via Facility-Level Reporting: This column lists all data elements to be reported by Partners and indicates those already collected through GHGRP Subpart W reporting. For facilities that report to Subpart W, the applicable Subpart W data for the reporting year will be automatically pre-populated in their Methane Challenge reporting forms by the reporting system.⁴ These facilities will only need to fill out the supplementary Methane Challenge data elements. Facilities that do not report to Subpart W will fill out all relevant data elements on their Methane Challenge reporting forms.

Annual reports also provide partners an opportunity to report optional, qualitative information to give context for their progress each year.

For reporting purposes, the Methane Challenge Program uses the same segment and facility definitions as Subpart W (see Appendix A). Methane Challenge data are reported at the facility level. Annually, EPA compiles the data collected and publicly releases (i.e., on the Program website) all non-confidential data submitted to the Methane Challenge Program^⁵ to track the progress of individual Partner companies in meeting their Program commitments.

EPA reserves the right to update the contents of this document at any time to maintain alignment with GHGRP or Greenhouse Gas Inventory (GHGI) definitions and methodologies. Beginning in the second full year of reporting for the program, EPA will send the Technical Document and Reporting Form for the upcoming reporting year to all Methane Challenge Implementation Managers annually and highlight any changes made.

Cost Recovery

Distribution companies charge rates that are typically approved by the utility’s governing body (state public utility commission (PUC), city council, utility board, etc.). EPA recognizes that Methane Challenge Program partner commitments may be dependent on obtaining additional approval from regulators, including cost recovery for steps taken to reduce methane emissions and meeting their Program commitments. EPA encourages company efforts, including efforts to seek cost recovery if appropriate, to make and fulfill Methane Challenge commitments.

Description of Emission Sources

Pneumatic Controllers

Applicable Segments: Production, Gathering and Boosting, Transmission and Storage

Source Description: Natural gas pneumatic controllers are automated instruments actuated by pressurized natural gas used for maintaining a process condition such as liquid level, pressure, delta-pressure and temperature. Continuous bleed means a continuous flow of pneumatic supply natural gas to the process control device (e.g. level control, temperature control, pressure control) where the supply gas pressure is modulated by the process condition, and then flows to the valve controller where the signal is compared with the process set-point to adjust gas pressure in the valve actuator. Pneumatic controllers in this document are equivalent to pneumatic devices as defined in the GHGRP.

This source focuses on continuous high-bleed controllers (those with natural gas bleed rate greater than 6 standard cubic feet per hour). This source does not cover operational situations in which pneumatic controllers with a bleed rate greater than 6 standard cubic feet (scf) per hour are required based on functional needs, including but not limited to response time, safety and positive actuation. Partner companies would track and report pneumatic controllers operating under these exceptions. Intermittent bleed pneumatic controllers are not included in this source category, however Partners may provide information on voluntary actions taken to mitigate methane emission from intermittent bleed pneumatic controllers.

Mitigation Options:

Utilize natural gas-actuated pneumatic controllers with a continuous bleed rate less than or equal to 6 scf of gas per hour, or
Utilize zero emitting controllers (e.g. instrument air, solar, electric, or mechanical controllers), or
Remove natural gas pneumatics controllers from service with no replacement.

Commitment Timeframe: Partners commit to implement the specified mitigation options for all sources included in their commitment (except those specifically exempted) by their designated commitment achievement date, not to exceed five (5) years from the commitment start date.

Reporting:

Emission Source	Quantification Method	Data Elements Collected via Facility-Level Reporting^⁶	GHGRP
Natural gas-actuated controllers with a bleed rate greater than 6 scf per hour	Subpart W Emission Factor(EF)^⁷	Actual count of high-bleed pneumatic controllers^⁸	X
		Average operating hours per high-bleed controller (hr/yr)	X
		Total CH₄ emissions from high-bleed controllers (mt CH₄)	X
		Number of high-bleed controllers claiming operational exemptions
		Rationale for operational exemption
Natural gas-actuated controllers with a bleed rate less than or equal to 6 scf per hour	Subpart W EF^⁹	Actual count of low-bleed pneumatic controllers^¹⁰	X
		Average operating hours per low-bleed controller (hr/yr)	X
		Total CH₄ emissions from low-bleed controllers (mt CH₄)	X
Voluntary action to reduce methane emissions during the reporting year	Difference in emissions before and after mitigation^¹¹	Number of high-bleed controllers converted to low-bleed
		Number of high-bleed controllers converted to zero emitting or removed from service
		Number of intermittent-bleed controllers converted to zero emitting or removed from service
		If converting or removing intermittent-bleed controllers, mitigation technology(ies) used
		Number of low bleed controllers converted to zero emitting or removed from service
		Emission reductions from voluntary action (mt CH₄)

Fixed Roof, Atmospheric Pressure Hydrocarbon Liquid Storage Tanks

Applicable Segments: Production, Gathering and Boosting

Source Description: Atmospheric pressure fixed roof storage tanks receiving hydrocarbon produced liquids from onshore petroleum and natural gas production and gathering and boosting facilities.

Mitigation Options:

Route gas to a capture system (e.g. a vapor recovery unit or VRU) for beneficial use^¹² to achieve at least a 95% reduction in methane emissions^¹³, or
Route gas to a flare or control device^¹⁴ to achieve at least a 95% reduction in methane emissions.

Commitment Timeframe: Partners commit to implement the specified mitigation options for all sources included in their commitment by their designated commitment achievement date, not to exceed five (5) years from the commitment start date.

Reporting:

Emission Source	Quantification Method	Data Elements Collected via Facility-Level Reporting^¹⁵	GHGRP
Fixed Roof, Atmospheric Pressure Hydrocarbon Liquid Storage Tanks	N/A	Basin ID	X
For gas-liquid separators or gathering and boosting non-separator equipment (e.g., stabilizers, slug catchers) with annual average daily throughput of oil greater than or equal to 10 barrels per day, and for wells flowing directly to atmospheric storage tanks without passing through a separator with throughput greater than or equal to 10 barrels per day: Tanks venting to atmosphere Tanks routing gas to a flare Tanks routing gas to capture system for beneficial use	Subpart W calculation methods 1 or 2, adjusted as needed for vents routed to VRU (beneficial use) or flare^¹⁶	Sub-Basin ID or county ID, as applicable depending on the industry segment	X
		Calculation method used	X
		Count of atmospheric tanks that vent directly to the atmosphere	X
		Count of atmospheric tanks with vapor recovery system emission control measures	X
		Count of atmospheric tanks with flaring emission control measures	X
		Annual CH₄ emissions from flashing in atmospheric tanks venting directly to the atmosphere (mt CH₄)	X
		Annual CH₄ emissions from flashing in atmospheric tanks equipped with vapor recovery systems (mt CH₄)	X
		Annual CH₄ emissions from flashing in atmospheric tanks that control emissions with flaring (mt CH₄)	X
For hydrocarbon liquids flowing to gas-liquid separators or non-separator equipment or directly to atmospheric storage tanks with throughput of oil less than 10 barrels/day: Tanks venting to the atmosphere Tanks with gas routed to a flare Tanks with gas routed to a capture system for beneficial use	Subpart W calculation method 3, adjusted as needed for vents routed to VRU (beneficial use) or flare^¹⁷	Sub-Basin ID or county ID, as applicable depending on the industry segment	X
		Count of tanks that vent directly to atmosphere
		Count of tanks equipped with vapor recovery system emission control measures
		Count of tanks with flaring emission control measures	X
		Annual CH₄ emissions from venting direct to atmosphere (mt CH₄)
		Annual CH4 emissions from flashing in tanks equipped with vapor recovery systems (mt CH4)
		Annual CH4 emissions from flashing in tanks that control emissions with flaring (mt CH₄)	X
Voluntary action to reduce methane emissions during the reporting year	Difference in emissions before and after mitigation^¹⁸	Total number of tanks in the basin	X
		Number of tanks routed to VRU or beneficial use
		Number of tanks routed to flare or controls device
		Emission reductions from voluntary action (mt CH₄)

Equipment Leaks/Fugitive Emissions – Compressor Isolation and Blowdown Valves

Applicable Segments: Transmission & Storage

Source Description: This commitment option addresses methane emissions at compressor stations from leakage through compressor blowdown and isolation valves. For additional information on the emission source and mitigation options, please review the Methane Challenge “Continuous Improvement” document for this commitment: https://www.epa.gov/natural-gas-star-program/continuous-improvement-document-equipment-leaks-compressor-valves.

Mitigation Options:

Develop a compressor valve inspection, maintenance, and repair/replacement program
- Implement an annual isolation and blowdown valve-focused leak survey at all compressor stations. Partners can measure the compressors as-found but are encouraged to work up to a biannual survey, timing the surveys so both the isolation and blowdown valve can be surveyed on each unit, each year
- Develop an isolation and blowdown valve enhanced maintenance plan
- Mitigate emissions from found leaks by any combination of the following:
  - Implementing activities identified in the enhanced maintenance plan that lead to emissions reductions, or
  - Repairing or replacing valves where practical (e.g., considering budgetary constraints, operating requirements and maintenance schedules). Repair/replacement should be targeted as soon as practical, but in no more than three years after identifying the leaking component, or
  - Routing isolation and blowdown valve leakage to a capture system for beneficial use to achieve at least a 95% reduction in methane emissions, or
  - Routing isolation and blowdown valve leakage to flare or control device^¹⁹ to achieve at least a 95% reduction in methane emissions

Facility-level Annual Reporting:

Emission Source	Quantification Method	Data Elements Collected via Facility-Level Reporting	GHGRP
Individual compressor	NA	Unique name or ID for the compressor	X
		Compressor type (Reciprocating or Centrifugal)	X
		Hours in operating-mode	X
		Hours in standby-pressurized-mode	X
		Hours in not-operating-depressurized-mode	X
		Is compressor part of a manifolded group of compressor sources? (Y/N)	X
		Indicate all of the following that apply to blowdown valve and isolation valve emissions from the compressor during the year:
		Emissions are vented to the atmosphere	X
		Emissions are routed to vapor recovery	X
		Emissions are routed to flare	X
		Emissions are captured for fuel use or routed to a thermal oxidizer	X
		Compressor in not-operating-depressurized-mode all year (Y/N)	X
Individual components on each compressor	NA	Unique name or ID for the compressor	X
		Unique name or ID for the individual vent to the atmosphere	X
		Type of component [Isolation valve; Blowdown valve]²⁰	X
		Did you repair or replace this component during the calendar year? [Repair; Replace; N/A]
		If yes, date of repair or replacement
		Did you implement an enhanced²¹ maintenance program on the valve this year?
		If yes, provide pertinent details on the maintenance activity(ies)
		Emissions Calculation Method (As Found Measurement; Continuous Measurement; Reporter Emission Factor)
	As found measurement^²²or continuous measurement^²³ of individual compressor²⁴	Mode in which the compressor was operating when measured (Operating; Standby-pressurized; Not-operating depressurized)
		The measurement method used	X
		Measurement date	X
		Was this measurement taken before or after a mitigation action was implemented during the calendar year (if applicable) [Before; After; N/A]
		Flow rate based on measurement type:
		As found: Measured volumetric flow at standard conditions (scfh)	X
		Continuous: Measured volumetric flow at standard conditions (MMscf)	X
		Annual CH₄ emissions (mt CH₄)	X
	Site-specific EF by compressor mode-source combination^²⁵,²⁶^,²⁷	Reporter EF (scfh)	X
		Number of measured compressors (during the current year and 2 previous years) from which the reporter EF was developed	X
Leak inspection and repair / replacement program details	NA	Number of surveys at this facility during the calendar year
		How many compressors at this facility were surveyed this year?
		How many vents indicated valve leakage this year?
		How many leaking isolation valves were repaired or replaced this year?
		How many leaking blowdown valves were repaired or replaced this year?
		How many leaking isolation valves were routed to a capture system for beneficial use?
		How many leaking blowdown valves were routed to a capture system for beneficial use?
		How many leaking isolation valves were routed to flare or control device?
		How many leaking blowdown valves were routed to flare or control device?
		If valves were repaired or replaced, use this space to provide any pertinent details on the replacement/repaired valve’s performance, installation, and design considerations
Voluntary action to reduce methane emissions during the reporting year	Difference in emissions before and after mitigation²⁸	Has the inspection and maintenance program been rolled-out to this facility? (Y/N)
	Difference in emissions before and after mitigation²⁸	Annual emissions reductions from voluntary action (mt CH₄)

End-of-Commitment Report:

This emission source will have a special “end-of-commitment” report in which partners will submit an analysis of their leak detection, maintenance, and repair/replacement program to inform future commitments. Partners making this commitment should ensure they are tracking these data each year, so they are able to prepare this report at the end of their commitment.

Summary of “lessons learned”
Analysis of leak counts and distribution
Year-over-year leak changes, repair methods, and practices, including a discussion of the effects of implementing the enhanced maintenance plan
Equipment / valve-specific recommendations
Maintenance plan results and costs

Reciprocating Compressors – Rod Packing Vent

Applicable Segments: Gathering and Boosting, Processing, Transmission and Storage

Source Description: Reciprocating compressor means a piece of equipment that increases the pressure of a process natural gas by positive displacement, employing linear movement of a shaft driving a piston in a cylinder. Reciprocating compressor rod packing means a series of flexible rings in machined metal cups that fit around the reciprocating compressor piston rod to create a seal limiting the amount of compressed natural gas that escapes to the atmosphere. Rod packing emissions typically occur around the rings from slight movement of the rings in the cups as the rod moves, but can also occur through the “nose gasket” around the packing case, between the packing cups, and between the rings and shaft. As the rings wear, or if the fit between the rod packing rings and rod is too loose, more compressed natural gas can escape.

Mitigation Options:

Replace the reciprocating compressor rod packing every 26,000 hours of operation, or
Replace the reciprocating compressor rod packing prior to every 36 months, or
Route rod packing vent to a capture system for beneficial use to achieve at least a 95% reduction in methane emissions, or
Route rod packing vent to flare or control device^²⁹ to achieve at least a 95% reduction in methane emissions.

Reporting – Gathering and Boosting:

Emission Source	Quantification Method	Data Elements Collected via Facility-Level Reporting	GHGRP
Reciprocating compressors	Reciprocating compressor venting EF^³⁰	Number of reciprocating compressors	X
Reciprocating compressors	Reciprocating compressor venting EF^³⁰	Annual CH4 emissions (mt CH₄)	X
Each reciprocating compressor	NA	Is rod packing replacement occurring every 26,000 hours or 36 months (Y/N)
		Date of last rod packing replacement
		Number of operating hours since rod packing replacement
		Indicate all of the following that apply to rod packing venting emissions from the compressor during the year:
		Emissions are vented to the atmosphere
		Emissions are routed to vapor recovery
		Emissions are routed to flare
		Emissions are captured for fuel use or routed to a thermal oxidizer
		Is compressor part of a manifolded group of compressor sources? (Y/N)
Voluntary action to reduce methane emissions during the reporting year	Difference in emissions before and after mitigation^³¹	Number of reciprocating compressors with rod packing vents routed to VRU or beneficial use during reporting year
		Number of reciprocating compressors with rod packing vents routed to flare or control device during reporting year
		Number of reciprocating compressors for which rod packing was replaced during reporting year
		Methodology used to quantify reductions
		Emission reductions from voluntary action (mt CH₄)

Reporting – Processing and Transmission and Storage:

Emission Source	Quantification Method	Data Elements Collected via Facility-Level Reporting^³²	GHGRP
Each reciprocating compressor	NA	Unique name or ID for the reciprocating compressor	X
		Hours in operating-mode	X
		Hours in standby-pressurized-mode	X
		Hours in not-operating-depressurized-mode	X
		Is rod packing replacement occurring every 26,000 hours or 36 months (Y/N)
		Date of last rod packing replacement
		Number of operating hours since rod packing replacement
		Which, if any, compressor sources are part of a manifolded group of compressor sources	X
		Indicate all of the following that apply to rod packing venting emissions from the compressor during the year:
		Emissions are vented to the atmosphere	X
		Emissions are routed to vapor recovery	X
		Emissions are routed to flare	X
		Emissions are captured for fuel use or routed to a thermal oxidizer	X
		Emissions are part of a manifolded group of compressor sources	X
		Compressor in not-operating-depressurized-mode all year (Y/N)	X
Reciprocating compressor rod packing individual atmospheric vents	As found measurement or continuous measurement in operating mode of individual compressor^³³^,^³⁴	Unique name or ID for the compressor	X
		Unique name or ID for the individual vent to the atmosphere	X
		Flow rate based on measurement type:
		As found: Measured volumetric flow at standard conditions from the rod packing vent (scfh)	X
		Continuous: Measured volumetric flow at standard conditions from the rod packing vent (MMscf)	X
		Annual CH₄ emissions (mt CH₄)	X
	Site-specific EF^³⁵	Unique name or ID for the compressor	X
		Unique name or ID for the individual vent to the atmosphere	X
		Reporter EF (scfh)	X
		Number of measured compressors (during the current year and 2 previous years) from which the reporter EF was developed	X
		Annual CH₄ emissions (mt CH₄)	X
Reciprocating compressors	Alternate calculation method for facilities not reporting to Subpart W only³⁶	Actual count of compressors not reported to Subpart W (i.e., those utilizing the alternate calculation method)
Reciprocating compressors		Annual CH4 emissions using the alternate calculation method (mt CH₄)
Voluntary action to reduce methane emissions during the reporting year	Difference in emissions before and after mitigation^³⁷	Number of reciprocating compressors with rod packing vents routed to VRU or beneficial use during reporting year
		Number of reciprocating compressors with rod packing vents routed to flare or control device during reporting year
		Number of reciprocating compressors for which rod packing was replaced during reporting year
		Emission reductions from voluntary action (mt CH₄)

Centrifugal Compressors – Venting

Applicable Segments: Gathering and Boosting, Processing, Transmission and Storage

Source Description: Centrifugal compressor means any equipment that increases the pressure of a process natural gas by centrifugal action, employing rotating movement of the driven shaft. In wet seal centrifugal compressors, high-pressure oil is used as a barrier against escaping gas in centrifugal compressor shafts. Very little gas escapes through the oil barrier, but under high pressure, considerably more gas is absorbed by the oil. The seal oil is purged of the absorbed gas (using heaters, flash tanks, and degassing techniques) and recirculated; the centrifugal compressor wet seal degassing vent releases emissions when the high-pressure oil barriers for centrifugal compressors are depressurized to release absorbed natural gas. This source is focused on centrifugal compressors with wet seals.

Mitigation Options:

Route wet seal degassing to a capture system for beneficial use to achieve at least a 95% reduction in methane emissions, or
Route wet seal degassing to flare or control device^³⁸ to achieve at least a 95% reduction in methane emissions, or
Convert wet seals to dry seals or use centrifugal compressors with dry seals.

Reporting – Gathering and Boosting:

Emission Source	Quantification Method	Data Elements Collected via Facility-Level Reporting	GHGRP
Centrifugal compressors	Wet Seal Oil Degassing Vent EF³⁹	Number of centrifugal compressors with wet seal oil degassing vents	X
Centrifugal compressors	Wet Seal Oil Degassing Vent EF³⁹	Annual CH4 emissions (mt CH₄)	X
Centrifugal compressors with dry seals	NA	Number of centrifugal compressors with dry seals
Voluntary action to reduce methane emissions during the reporting year	Difference in emissions before and after mitigation^⁴⁰	Number of wet seal compressor de-gassing vents routed to VRU or beneficial use during reporting year
		Number of wet seal compressor de-gassing vents routed to flare or control device during reporting year
		Number of wet seal compressors converted to dry seal⁴¹
		Methodology used to quantify reductions
		Emission reductions from voluntary action (mt CH₄)

Reporting – Processing and Transmission & Storage:

Emission Source	Quantification Method	Data Elements Collected via Facility-Level Reporting^⁴²	GHGRP
Each centrifugal compressor with wet seals	NA	Unique name or ID for the compressor	X
		Number of wet seals	X
		Hours in operating mode	X
		Which, if any, compressor sources are part of a manifolded group of compressor sources	X
		Indicate all of the following that apply to wet seal degassing emissions from the compressor during the year:
		Emissions are vented to the atmosphere
		Emissions are routed to flare	X
		Emissions are captured for fuel use or routed to a thermal oxidizer	X
		Emissions are routed to vapor recovery for beneficial use other than as fuel	X
		Compressor in not-operating-depressurized-mode all year (Y/N)	X
Centrifugal compressors with dry seals	NA	Number of centrifugal compressors with dry seals	X
Centrifugal compressor with wet seal degassing vented to the atmosphere	As found or continuous measurement in operating mode of individual compressor wet seal degassing vent^⁴³,⁴⁴	Unique name or ID for the compressor	X
		Unique name or ID for the individual vent to the atmosphere	X
		Flow rate based on measurement type:
		As found: Measured flow rate (scfh)	X
		Continuous: Measured volume of flow during the reporting year (MMscf)	X
		Annual CH₄ emissions (mt CH₄)	X
	Site-specific EF^⁴⁵	Unique name or ID for the compressor	X
		Unique name or ID for the individual vent to the atmosphere	X
		Reporter EF (scfh)	X
		Number of measured compressors (during the current year and the 2 previous years) from which the reporter EF was developed	X
		Annual CH₄ emissions (mt CH₄)	X
	Alternate calculation method for facilities not reporting to Subpart W only⁴⁶	Number of compressors not reported to Subpart W (i.e., those utilizing the alternate calculation method)
		Annual CH₄ emissions using the alternate calculation method (mt CH₄)
Voluntary action to reduce methane emissions during the reporting year	Difference in emissions before and after mitigation^⁴⁷	Number of wet seal compressor de-gassing vents routed to VRU or beneficial use during reporting year
		Number of wet seal compressor de-gassing vents routed to flare or control device during reporting year
		Number of wet seal compressors converted to dry seal
		Emission reductions from voluntary action (mt CH₄)

Transmission Pipeline Blowdowns between Compressor Stations

Applicable Segments: Transmission and Storage

Source Description: Blowdown means the release of gas from a pipeline or section of pipeline that causes a reduction in system pressure or a complete depressurization.

Mitigation Options:

Route gas to a compressor or capture system for beneficial use, or
Route gas to a flare, or
Route gas to a low-pressure system by taking advantage of existing piping connections between high- and low-pressure systems, temporarily resetting or bypassing pressure regulators to reduce system pressure prior to maintenance, or installing temporary connections between high and low-pressure systems, or
Utilize hot tapping, a procedure that makes a new pipeline connection while the pipeline remains in service, flowing natural gas under pressure, to avoid the need to blow down gas.

Partners commit to maximize blowdown gas recovery and/or emission reductions through utilization of one or more of these options to reduce methane emissions from non-emergency blowdowns by at least 50%⁴⁸ from total potential emissions each year. Total potential emissions equals calculated emissions from all planned maintenance activities in a calendar year^⁴⁹, assuming the pipeline is mechanically evacuated or mechanically displaced using non-hazardous means down to atmospheric pressure and no mitigation is used.^⁵⁰

Commitment Timeframe: Partners commit to achieve the specified annual reduction rate by their designated commitment achievement date, not to exceed five (5) years from the commitment start date, and maintain at least that rate moving forward.

Reporting:

Emission Source	Quantification Method	Data Elements Collected via Facility-Level GHGRP Reporting^⁵¹	GHGRP
Pipeline blowdowns between compressor stations^⁵²	Subpart W Method 1, based on volume, temperature, and pressure^⁵³	Total number of blowdowns per equipment or event type^⁵⁴	X
		Total CH₄ emissions (mt CH₄) per equipment or event type	X
	Subpart W Method 2, based on measurement^⁵⁵	Total number of blowdowns	X
	Subpart W Method 2, based on measurement^⁵⁵	Total CH₄ emissions (mt CH₄)	X
	Alternate calculation method for facilities not reporting to Subpart W only⁵⁶	Actual count of blowdowns
		Annual CH₄ Emissions (mt CH₄)
Voluntary action to reduce methane emissions during the reporting year	Difference in potential and actual emissions^⁵⁷	Total number of blowdowns to which a BMP was applied
		Number of blowdowns that routed gas to a:
		Compressor or capture system for beneficial use
		Flare^⁵⁸
		Low-pressure system
		Number of hot taps utilized that avoided the need to blowdown gas to the atmosphere
		Total potential emissions (mt CH₄)
		Emission reductions from voluntary action (mt CH₄)

Mains – Cast Iron and Unprotected Steel

Applicable Segments: Distribution

Source Description: Distribution mains are natural gas distribution pipelines that serve as a common source of supply for more than one service line.^⁵⁹ This source covers cast iron and unprotected steel mains (steel mains without cathodic protection).

Mitigation Options:

Replace cast iron mains with plastic or cathodically protected steel and replace or cathodically protect unprotected steel mains, or
Rehabilitate cast iron and unprotected steel pipes with plastic pipe inserts, also referred to as slip-lining or u-liners, or cured-in-place liners:
- Slip-lining is a technique that involves the insertion of a plastic pipe into an existing pipe. The new pipe is pushed or pulled into the host pipe.^⁶⁰ U-liners are high-density polyethylene (HDPE) plastic piping and are manufactured in a “U” shape with diameter sizing specific to the host pipe in need of repair. The liner is pulled through the host pipe and then reformed to a circular shape after insertion using steam. This process is carried out without the need to trench and results in a structurally sound HDPE plastic pipe fitted tightly within the pipe needing repair.^⁶¹ PHMSA provides guidance related to inserting plastic pipe into a metal pipe.
- Cured-in place liners are pipe liners comprised of flexible tubing, jackets, elastomer skin, and adhesive systems. These liners are installed into an existing metallic natural gas pipe in need of rehabilitation. Cured-in place liners provide resistance to gas permeation and provide resistance against damage caused by ground movement, internal corrosion, leaking joints, pinholes, and chemical attacks.^⁶²

Partners commit to replace or rehabilitate cast iron and unprotected steel mains at the following minimum annual rates (based on a partner’s total inventory of cast iron and unprotected steel mains) per the mitigation options listed above. Partners may choose to commit to higher rates than those designated.

Tier	Inventory of Cast Iron⁶³ and Unprotected Steel Mains⁶⁴	% Minimum Annual Replacement/Repair
Tier 1	<500 miles	6.50%
Tier 2	500-1,000 miles	5%
Tier 3	1,001 – 1,500 miles	3%
Tier 4	1,501 miles – 3000 miles	2%
Tier 5	>3000 miles	1.5%

Commitment Timeframe: Partners commit to achieve the specified annual replacement/rehabilitation rate by their designated commitment achievement date, not to exceed five years from the commitment start date, and maintain at least that rate moving forward. Commitments will be based on the Partner’s inventory of cast iron and unprotected steel mains as of January 1 of the year of their commitment⁶⁵. After achieving their specified rate, Partners can maintain that rate for a period of five years (e.g. if replacement/rehabilitation actions result in a Partner’s moving to a different mileage tier, they will not automatically have to adopt that new rate). After five years, Partners will be requested to evaluate their ability to commit to a higher rate. Partners can raise their committed rate at any time.

Reporting:

Emission Source	Quantification Method^⁶⁶	Data Elements Collected via Facility-Level Reporting	GHGRP
Distribution mains - cast iron - gas service	NA	Initial inventory of cast iron distribution mains as of January 1 of the first year of current commitment (miles)⁶⁷
	Subpart W Cast iron mains EF	Total miles of cast iron distribution mains	X
	Subpart W Cast iron mains EF	Annual CH₄ emissions (mt CH₄)	X
Distribution mains - plastic - gas service	Subpart W Plastic mains EF	Total miles of plastic distribution mains	X
Distribution mains - plastic - gas service	Subpart W Plastic mains EF	Annual CH₄ emissions (mt CH₄)	X
Distribution mains - protected steel - gas service	Subpart W Protected steel mains EF	Total miles of protected steel distribution mains	X
Distribution mains - protected steel - gas service	Subpart W Protected steel mains EF	Annual CH₄ emissions (mt CH₄)	X
Distribution mains - unprotected steel - gas service	Subpart W Unprotected steel mains EF	Initial inventory of unprotected steel distribution mains as of January 1 of the first year of current commitment (miles)⁶⁸
		Total miles of unprotected steel distribution mains	X
		Annual CH₄ emissions (mt CH₄)	X
Distribution mains - cast iron or unprotected steel with plastic liners or inserts - gas service	Subpart W Plastic mains EF	Total miles of cast iron or unprotected steel distribution mains with Plastic Liners or Inserts
	Subpart W Plastic mains EF	~~Annual CH~~₄ ~~emissions (mt CH~~₄)
Voluntary action to reduce methane emissions during the reporting year	Difference in emissions before and after mitigation⁶⁹	Miles of cast iron mains:
		Replaced with plastic
		Replaced with protected steel
		Rehabilitated with plastic pipe inserts or cured-in-place liners
		Retired without replacement
		Miles of unprotected steel mains:
		Cathodically protected or replaced with protected steel
		Rehabilitated with pipe inserts or cured-in-place liners
		Replaced with plastic
		Retired without replacement
		Emission reductions from voluntary action (mt CH₄)

Services – Cast Iron and Unprotected Steel

Applicable Segments: Distribution

Source Description: A service line is a distribution line that transports gas from a common source of supply to (1) a customer meter or the connection to a customer's piping, whichever is farther downstream, or (2) the connection to a customer's piping if there is no customer meter. (A customer meter is the meter that measures the transfer of gas from an operator to a consumer.)^⁷⁰ This source covers cast iron and unprotected steel services.⁷¹

Mitigation Options:

Replace unprotected steel and cast iron services with copper, plastic, or protected steel that meet the manufacturing requirements and qualifications provided in 49 CFR Part 192, Subpart B^⁷², or
Rehabilitate cast iron and unprotected steel services with plastic pipe inserts or liners.

At a minimum, partners commit to replace or rehabilitate cast iron and unprotected steel services when the main is replaced or rehabilitated. Partners would be encouraged to specify any additional targeted replacement efforts beyond this practice. Due to the linkage with mains, this source is not eligible for a stand-alone commitment, but can be selected as an optional addition for Partners that select the “Mains – Cast Iron and Unprotected Steel” source category.

Commitment Timeframe: Partners commit to adopt the specified replacement or rehabilitation practice by their designated commitment achievement date, not to exceed five (5) years from the commitment start date, and maintain that practice moving forward.

Reporting:

Emission Source	Quantification Method ^⁷³	Data Elements Collected via Facility-Level Reporting	GHGRP
Distribution services - cast iron - gas service	NA	Initial number of cast iron services as of January 1 of the first year of current commitment⁷⁴
	Subpart W Unprotected steel services EF⁷⁵	Total number of cast iron services
	Subpart W Unprotected steel services EF⁷⁵	Annual CH₄ emissions (mt CH₄)
Distribution services - copper - gas service	Subpart W Copper services EF	Total number of copper services	X
Distribution services - copper - gas service	Subpart W Copper services EF	Annual CH₄ emissions (mt CH₄)	X
Distribution services - plastic - gas service	Subpart W Plastic services EF	Total number of plastic services	X
Distribution services - plastic - gas service	Subpart W Plastic services EF	Annual CH₄ emissions (mt CH₄)	X
Distribution services - protected steel - gas service	Subpart W Protected steel services EF	Total number of protected steel services	X
Distribution services - protected steel - gas service	Subpart W Protected steel services EF	Annual CH₄ emissions (mt CH₄)	X
Distribution services - unprotected steel - gas service	Subpart W Unprotected steel services EF	Initial number of unprotected steel services as of January 1 of the first year of current commitment⁷⁶
		Total number of unprotected steel services	X
		Annual CH₄ emissions (mt CH₄)	X
Distribution services - cast Iron or unprotected steel with plastic liners or inserts - gas service	Subpart W Plastic services EF	Total number of cast iron or unprotected steel services with plastic liners or inserts
	Subpart W Plastic services EF	~~Annual CH~~₄ ~~emissions (mt CH~~₄)
Voluntary action to reduce methane emissions during the reporting year	Difference in emissions before and after mitigation⁷⁷	Number of cast iron services:
		Replaced with plastic
		Replaced with protected steel
		Replaced with copper
		Rehabilitated with plastic pipe inserts
		Retired without replacement
		Number of unprotected steel services:
		Cathodically protected or replaced with protected steel
		Replaced with plastic
		Replaced with copper
		Rehabilitated with plastic pipe inserts
		Retired without replacement
		Emission reductions from voluntary action (mt CH₄)

Distribution Pipeline Blowdowns

Applicable Segments: Distribution

Source Description: Blowdown means the release of gas from a pipeline or section of pipeline that causes a reduction in system pressure or a complete depressurization.

Mitigation Options:

Route gas to a compressor or capture system for beneficial use, or
Route gas to a flare, or
Route gas to a low-pressure system by taking advantage of existing piping connections between high- and low-pressure systems, temporarily resetting or bypassing pressure regulators to reduce system pressure prior to maintenance, or installing temporary connections between high and low-pressure systems, or
Utilize hot tapping, a procedure that makes a new pipeline connection while the pipeline remains in service, flowing natural gas under pressure, to avoid the need to blow down gas, or
Use stopoff/stopple equipment and fittings to reduce the length of pipe and the associated volume of gas being blown down.

Partners commit to maximize blowdown gas recovery and/or emission reductions through utilization of one or more of these options to reduce methane emissions from non-emergency blowdowns of pipelines operating greater than 60 psi by at least 50%⁷⁸ from total potential emissions each year. Total potential emissions equal calculated emissions from all planned maintenance activities in a calendar year^⁷⁹, assuming the pipeline is mechanically evacuated or mechanically displaced using non-hazardous means down to atmospheric pressure and no mitigation is used.⁸⁰

Reporting:

Emission Source	Quantification Method	Data Elements Collected via Facility-Level Reporting	GHGRP
Distribution Pipeline Blowdowns⁸¹	Subpart W calculation method 1 or 2 ^⁸²,⁸³	Number of blowdowns
Distribution Pipeline Blowdowns⁸¹	Subpart W calculation method 1 or 2 ^⁸²,⁸³	Total CH₄ emissions (mt CH₄)
Voluntary action to reduce methane emissions during the reporting year	Difference in potential and actual emissions^⁸⁴	Number of blowdowns that routed gas to a:
		Compressor or capture system for beneficial use
		Flare⁸⁵
		Low-pressure system
		Number of hot taps utilized that avoided the need to blowdown gas to the atmosphere
		Total potential emissions (mt CH₄)
		Emission reductions from voluntary action (mt CH₄)

Excavation Damages

Applicable Segments: Distribution

Source Description: Excavation damage may include damage to the external coating of the pipe, or dents, scrapes, cuts, or punctures directly into the pipeline itself. Excavation damage often occurs when required One-Call notifications are not made prior to beginning excavation, digging, or plowing activities, or when calls are made but pipe is still damaged. When the location of underground facilities is not properly determined, the excavator may inadvertently – and sometimes unknowingly – damage the pipeline and its protective coating.^⁸⁶ This source covers both distribution mains and services.

Mitigation Options:

Conduct incident analyses (e.g. by identifying whether excavation, locating, or One-Call practices were not sufficient) to inform process improvements and reduce excavation damages, or
Undertake targeted programs to reduce excavation damages and/or shorten time to shut-in when damages do occur, including patrolling systems when construction activity is higher, excavator education programs (811, call before you dig), identifying and implementing steps to minimize repeat offenders, and stand-by efforts.

Partner companies’ collection and reporting of data on all excavation damages is a significant part of this commitment.⁸⁷ Partners will use the collected data to set a company-specific goal for reducing excavation damages and/or methane emissions from excavation damages.

Commitment Timeframe: Partners commit to report as many data elements as possible annually and to be reporting all data elements by the designated commitment achievement date, not to exceed five (5) years from the commitment start date.

Reporting:

Emission Source	Quantification Method	Data Elements Collected via Facility-Level Reporting	GHGRP
Excavation damages – natural gas distribution network	NA	Total number of excavation damages
		Total number of excavation damages per thousand locate calls
		Total number of excavation damages per class location (optional)
		Total number of excavation damages by pipe material (steel, cast iron, copper, plastic etc.) and part of system involved (main, service, inside meter/regulator set, etc.)
		Total number of excavation damages which resulted in a release of natural gas
		Total number of excavation damages which resulted in the pipeline being shut down
		Total number of excavation damages where the operator was given prior notification of excavation activity
		Total number of excavation damages by type that caused excavation damage incidents^⁸⁸
		Total number of excavation damages by apparent root cause^⁸⁹
Voluntary action to reduce methane emissions during the reporting year	NA	Actions taken to minimize excavation damages/reduce methane emissions from excavation damages
		Company-specific goal for reducing excavation damages and/or methane emissions from excavation damages (when available)
		Progress in meeting company-specific goal (when available)

Renewable Natural Gas

Applicable Segments: Transmission & Storage; Distribution

Source Description: This commitment addresses the supply of renewable natural gas (RNG) through natural gas transmission and distribution systems. For the purposes of this commitment, “biogas” is gas produced by the anaerobic digestion of organic matter at one or more of the following sources: municipal solid waste (MSW) landfills, anaerobic digestion (AD) at municipal water resource recovery facilities (WRRFs), AD at livestock farms and AD at stand-alone organic waste management operations. For the purposes of this commitment, “renewable natural gas”⁹⁰ encompasses biogas that has been upgraded for use in place of fossil natural gas. In the reporting form for this commitment, partners will also have the opportunity to provide general information about their companies’ strategies for supplying other “low carbon” fuels.

Raw biogas typically has a methane content between 45 and 65 percent, depending on the source of the feedstock, and must go through a series of steps to be converted into RNG. The treatments used will depend on the source of the raw biogas and the constituents found in the raw biogas. These may include removing moisture, carbon dioxide (CO₂) and trace level contaminants (which, depending on the biogas source, can include siloxanes, volatile organic compounds-- VOCs, and hydrogen sulfide), as well as reducing the nitrogen and oxygen content. Once upgraded, the gas has a methane content of 90 percent or greater.

As a substitute for natural gas, RNG has many end-uses, including in thermal applications, to generate electricity, for vehicle fuel, or as a bio-product feedstock. For the purpose of this commitment option, the end-use is a requested, but not required, data element. To develop a greater understanding of the RNG market and the role of natural gas transmission and distribution systems in advancing use of RNG, the end use is a valuable piece of information. However, EPA recognizes that transmission and distribution companies may not be privy to the information about the end use of the RNG projects for RNG in their systems.

RNG can be used locally at the site where the gas is produced and upgraded, or it can be injected into natural gas transmission or distribution pipelines. This commitment option is focused on natural gas injected into transmission or distribution pipelines. This commitment does not encompass RNG attributes that are purchased, unless the RNG is directly injected into the Partner’s system or another system that is physically connected to the Partner’s system.

Additional information on renewable natural gas can be found in a discussion paper published by EPA’s voluntary methane programs in 2020: https://www.epa.gov/lmop/overview-renewable-natural-gas-biogas

Partners Commit To:

Annually report RNG data elements to the Program;
Research the nature and extent of RNG in its system (i.e., information about the biogas project that generated the gas and how the gas is being used by end users) so that the Partner can report as complete a representation of the RNG it has acquired, transported, and delivered as possible by the end of its commitment.

Commitment Timeframe: Partners commit to report as many data elements as possible annually and to research the nature and extent of RNG in their systems by the designated commitment achievement date, not to exceed five (5) years from the commitment start date. If the project(s) from which a Partner receives its RNG permanently go(es) offline during its commitment, the Partner should report this to the Methane Challenge Program as soon as possible. If the Partner does not plan to source RNG from another project, it can change its ‘Commitment Achievement Year’ to the year the project went offline and would not be required to report when not sourcing RNG.

Facility-level Annual Reporting:

Data will be reported at the facility-level through e-GGRT as for other BMP commitments. The RNG reporting form tab will allow Partners to report the requested data elements for each biogas project (if more than one). Partners can also use multiple lines per category to indicate multiple interconnects, designated end uses, etc. Data should only be reported on RNG that is received directly from an interconnect with a biogas project or a virtual pipeline or that is received from another system that is physically connected to the Partner’s system and that is then delivered and/or supplied to customers by the partner.

All data elements for this commitment option are OPTIONAL and to be provided if feasible. If data are considered confidential (e.g., by the biogas project developer) and the partner cannot report them, the partner should not report these data and can indicate that the requested data are confidential and cannot be shared in the applicable free-text field. It is not expected that all partners will report all data elements and companies that cannot report all requested data will not be penalized.

Data Category	Data Elements Collected via Facility-Level Reporting
General Information	What role(s) does your company play in the RNG process? (please check all that apply) [Investing in biogas projects; Directly interconnecting with biogas project; Delivering RNG to end users; Supplying RNG to end users; Purchasing environmental attributes for RNG that is physically connected to the company’s system; Purchasing environmental attributes for RNG that is not physically connected to the company’s system]
	For Distribution Partners⁹¹ – Does your company offer a ‘green gas’ option to residential customers? Is your company in the process of offering a ‘green gas’ option?
	Any additional information on the role(s) your company plays in the RNG process, or about ‘green gas’ offerings?
Information about the biogas source	Biogas Project ID⁹²
	What is the feedstock for the biogas? (Anaerobic digester – livestock farm; Anaerobic digester – co-digestion; Anaerobic digester – food production facility; Anaerobic digester – organic waste management; Anaerobic digester – wastewater treatment plan; Landfill; Other (Specify)⁹³)
	Name the specific municipal solid waste landfill or digester (i.e., at water resource recovery facilities (wastewater treatment plants), livestock farms, food production facilities or organic waste management operations) from which the RNG was generated
	What upgrading technology was used? [to be selected from a list]
	Any additional information on the biogas project/upgrading process you wish to share?
Information about the pipeline interconnect(s)	Type of interconnect [Direct interconnect with biogas project; Interconnect with natural gas transmission company delivering/transporting RNG; Interconnect with natural gas distribution company delivering/transporting RNG; Interconnect with natural gas distribution company delivering and supplying RNG]
	If interconnect with natural gas transmission company or distribution company, name of interconnecting company
	If interconnect with biogas project:
	Biogas Project ID⁹⁴
	Location of the interconnect (latitude/longitude)
	Volume of gas received this year (scf gas)
	Reference to the company’s gas quality standards that are applicable to this project (e.g., pipeline tariff)
	How far is the interconnect from the feedstock source (km)?
	Is there a virtual pipeline?
	If yes, details about the virtual pipeline
	Any additional information on the interconnect process you wish to share?
Information about the end use(s) and environmental attributes	Biogas Project ID [if known]⁹⁵
	What is the destinated market for the RNG (region/city/state/facility) [if known]?
	What is the designated end use [if known]? (Thermal applications; Electricity generation; Vehicle fuel; Bio-product feedstock; Interconnect with other natural gas company (specify company); Not designated; Other (specify end use); Unknown)
	Volume of RNG going to this end use, this year (scf gas) [if known]
	Any additional information on the end use you wish to share?
	Does your company currently own the environmental attributes for the RNG? [Yes; No; Unknown]
	If your company does not own the environmental attributes now, who does? [If known]
	If, your company does, or at one point did, own the attributes for RNG, does your supply contract for “renewable” natural gas include conveyance of environmental attributes to your company (e.g., by way of a contract clause, attestation)? [Yes; No; Unknown]
	If your company is selling “renewable” natural gas supply to another downstream entity (e.g., distributor, end consumer etc.), have you contractually conveyed the RNG environmental attributes to the downstream buyer? [Yes; No; Unknown]
	Is your company using a third party provider to certify or track attributes? If so, which one(s)?
	Any additional information about environmental attributes that you wish to share?
Information about the Company’s strategy for supply of “low carbon fuels”	Company-specific goals or strategies for supply of “low carbon fuels” (such as upgraded biogas, hydrogen, etc.) (e.g., percent of natural gas supply to be RNG by a certain year; convert vehicle fleet to run on natural gas and use RNG for fuel), if applicable.
	Is your company blending hydrogen into its natural gas supply? [Yes; Planning to; Researching; No; Unknown]
	If yes, or planning to:
	At what rate will you be blending (% hydrogen by volume)
	What is the source and/or feedstock of the hydrogen? (e.g., renewable/nuclear/etc.)
	Is any upgrading/cleaning of the hydrogen required before injection?
	What pipeline types does your company inject hydrogen into (material and pressure)?
	Have you done any related customer engagement?
	Has anything been done to customer appliances (if yes, what)?

Innovative Technologies, Practices, and Approaches

Applicable Segments: All

The Methane Challenge program encourages partners to share information on innovative technologies, practices, and approaches they are using to measure, track, and/or mitigate their emissions that are not covered by the other BMP data elements. Partners may provide information on technologies/practices/approaches to mitigate emissions from existing emission sources in the program, or for emission sources not currently included in the program.

Under this Innovation Reporting mechanism, partners can share this information by providing the following details:

Applicable emission source(s)
Applicable industry segments
Name of technology/practice(s) to mitigate emissions from that source
Scope of implementation
Confirmation the technology/practice is covered by regulation (federal, state, local)
For each technology/practice
- A description of the technology/practice(s)
- Description of how widely available technology is
- Description of any technical infeasibilities/issues that need to be addressed
- Estimated range of emission reductions achievable and methodology used to develop the estimate
- Assessment of cost-effectiveness
- Data elements needed to monitor progress in reducing methane emissions
Any other information needed to fully understand the technology/practice/approach

Methane Challenge will publish these data and may use them to inform future commitment options and its library of technical information.

Before reporting under this mechanism, Partners should email the program managers at [email protected] to get approval for each topic they wish to submit data on. On approval, Partners will receive instructions how to submit this information.

Non-Finalized Emission Sources

At this time, EPA is not finalizing BMP commitment details for these sources. Details will be released as soon as they are available.

Equipment Leaks⁹⁶

Liquids Unloading

Pneumatic Pumps

Metering and Regulating (M&R) Stations/City Gates

Appendix A: Segment and Facility Definitions

Onshore Production

For purposes of the Methane Challenge Program, onshore petroleum and natural gas production means all equipment on a single well-pad or associated with a single well-pad (including but not limited to compressors, generators, dehydrators, storage vessels, engines, boilers, heaters, flares, separation and processing equipment, and portable non-self-propelled equipment, which includes well drilling and completion equipment, workover equipment, and leased, rented or contracted equipment) used in the production, extraction, recovery, lifting, stabilization, separation or treating of petroleum and/or natural gas (including condensate). This equipment also includes associated storage or measurement vessels, all petroleum and natural gas production equipment located on islands, artificial islands, or structures connected by a causeway to land, an island, or an artificial island. Onshore petroleum and natural gas production also means all equipment on or associated with a single enhanced oil recovery (EOR) well pad using CO₂or natural gas injection.

A facility means all natural gas equipment on a single well-pad or associated with a single well-pad and CO₂ EOR operations that are under common ownership or common control including leased, rented, or contracted activities by an onshore natural gas production owner or operator and that are located in a single hydrocarbon basin as defined in 40 CFR 98.238. Where a person or entity owns or operates more than one well in a basin, then all onshore natural gas production equipment associated with all wells that the person or entity owns or operates in the basin would be considered one facility.

Gathering and Boosting

For purposes of the Methane Challenge Program, onshore petroleum and natural gas gathering and boosting means gathering pipelines and other equipment used to collect petroleum and/or natural gas from onshore production gas or oil wells and used to compress, dehydrate, sweeten, or transport the petroleum and/or natural gas to a natural gas processing facility, a natural gas transmission pipeline, or a natural gas distribution pipeline. Gathering and boosting equipment includes, but is not limited to, gathering pipelines, separators, compressors, acid gas removal units, dehydrators, pneumatic devices/pumps, storage vessels, engines, boilers, heaters, and flares. Gathering and boosting equipment does not include equipment reported under any other industry segment defined in subpart W. Gathering pipelines operating on a vacuum and gathering pipelines with a gas to oil ratio (GOR) less than 300 standard cubic feet per stock tank barrel (scf/STB) are not included in this industry segment (oil here refers to hydrocarbon liquids of all API gravities).

A gathering and boosting facility for purposes of reporting under Methane Challenge means all gathering pipelines and other equipment located along those pipelines that are under common ownership or common control by a gathering and boosting system owner or operator and that are located in a single hydrocarbon basin as defined in 40 CFR 98.238. Where a person owns or operates more than one gathering and boosting system in a basin (for example, separate gathering lines that are not connected), then all gathering and boosting equipment that the person owns or operates in the basin would be considered one facility. Any gathering and boosting equipment that is associated with a single gathering and boosting system, including leased, rented, or contracted activities, is considered to be under common control of the owner or operator of the gathering and boosting system that contains the pipeline. The facility does not include equipment and pipelines that are part of any other industry segment defined in subpart W.

Natural Gas Processing

For purposes of the Methane Challenge Program, natural gas processing means the separation of natural gas liquids (NGLs) or non-methane gases from produced natural gas, or the separation of NGLs into one or more component mixtures. Separation includes one or more of the following: forced extraction of natural gas liquids, sulfur and carbon dioxide removal, fractionation of NGLs, or the capture of CO2 separated from natural gas streams. This segment also includes all residue gas compression equipment owned or operated by the natural gas processing plant. This industry segment includes processing plants that fractionate gas liquids, and processing plants that do not fractionate gas liquids but have an annual average throughput of 25 MMscf per day or greater.

A natural gas processing facility for the purposes of reporting under the Methane Challenge is any physical property, plant, building, structure, source, or stationary equipment in the natural gas processing industry segment located on one or more contiguous or adjacent properties in actual physical contact or separated solely by a public roadway or other public right-of-way and under common ownership or common control, that emits or may emit any greenhouse gas. Operators of military installations may classify such installations as more than a single facility based on distinct and independent functional groupings within contiguous military properties.

Natural Gas Transmission & Underground Storage

For purposes of the Methane Challenge Program, BMP option, natural gas transmission compression and natural gas transmission pipelines are both included in the ‘Natural Gas Transmission & Underground Natural Gas Storage’ segment.

Onshore natural gas transmission compression means any stationary combination of compressors that move natural gas from production fields, natural gas processing plants, or other transmission compressors through transmission pipelines to natural gas distribution pipelines, LNG storage facilities, or into underground storage. In addition, a transmission compressor station includes equipment for liquids separation, and tanks for the storage of water and hydrocarbon liquids. Residue (sales) gas compression that is part of onshore natural gas processing plants are included in the onshore natural gas processing segment and are excluded from this segment.

Onshore natural gas transmission pipeline means all natural gas pipelines that are a Federal Energy Regulatory Commission rate-regulated Interstate pipeline, a state rate-regulated Intrastate pipeline, or a pipeline that falls under the “Hinshaw Exemption” as referenced in section 1(c) of the Natural Gas Act, 15 I.S.C. 717-717(w)(1994).

Underground natural gas storage means subsurface storage, including depleted gas or oil reservoirs and salt dome caverns that store natural gas that has been transferred from its original location for the primary purpose of load balancing (the process of equalizing the receipt and delivery of natural gas); natural gas underground storage processes and operations (including compression, dehydration and flow measurement, and excluding transmission pipelines); and all the wellheads connected to the compression units located at the facility that inject and recover natural gas into and from the underground reservoirs

A natural gas transmission compression facility or underground natural gas storage facility for the purposes of reporting under the Methane Challenge is any physical property, plant, building, structure, source, or stationary equipment in the natural gas transmission compression industry segment or underground natural gas storage industry segment located on one or more contiguous or adjacent properties in actual physical contact or separated solely by a public roadway or other public right-of-way and under common ownership or common control, that emits or may emit any greenhouse gas. Operators of military installations may classify such installations as more than a single facility based on distinct and independent functional groupings within contiguous military properties.

An onshore natural gas transmission pipeline facility for the purpose of reporting under the Methane Challenge is the total U.S. mileage of natural gas transmission pipelines owned or operated by an onshore natural gas transmission pipeline owner or operator. If an owner or operator has multiple pipelines in the United States, the facility is considered the aggregate of those pipelines, even if they are not interconnected.

Natural Gas Distribution

For purposes of the Methane Challenge Program, natural gas distribution means the distribution pipelines and metering and regulating equipment at metering-regulating stations that are operated by a Local Distribution Company (LDC) within a single state that is regulated as a separate operating company by a public utility commission or that is operated as an independent municipally-owned distribution system. This segment excludes customer meters and regulators, infrastructure, and pipelines (both interstate and intrastate) delivering natural gas directly to major industrial users and farm taps upstream of the local distribution company inlet.

A natural gas distribution facility for the purposes of reporting under the Methane Challenge is the collection of all distribution pipelines and metering-regulating stations that are operated by an LDC within a single state that is regulated as a separate operating company by a public utility commission or that are operated as an independent municipally-owned distribution system.

1 The Methane Challenge Program: Best Management Practices (BMP) Framework document can be found on the Natural Gas STAR website at https://www.epa.gov/natural-gas-star-program/methane-challenge-program-best-management-practice-bmp-commitment-framework.

2 In the Methane Challenge module in e-GGRT, the system will auto-generate IDs for all non-GHGRP facilities created by the partner’s Implementation Manager (IM) or the IM’s Delegates.

3 Partners will only provide supplemental data for sources for which they have made commitments.

4 This creates a copy of the Subpart W data in the Methane Challenge reporting module. Methane Challenge reports cannot edit/update data reported to the GHGRP.

5 The program only uses non-confidential data from Subpart W; additionally, all Methane Challenge supplemental data must be non-confidential.

6 Pneumatic device data for onshore production and gathering and boosting facilities are aggregated at the basin level for reporting under Subpart W, which is equivalent to reporting at the facility level. Data for the transmission compression and underground storage industry segments are aggregated at the facility level.

7 40 CFR 98.233(a)

8 This source is equivalent to GHGRP “pneumatic devices”

9 40 CFR 98.233(a)

10 This source is equivalent to GHGRP “pneumatic devices”

11 As calculated per the specified emission quantification methodologies for each source.

12 Beneficial use means routing natural gas for use such that the gas is not vented to the atmosphere or flared. This includes natural gas reinjection, electricity generation, natural gas liquefaction, and natural gas sales.

13 May be used in conjunction with a vapor recovery tower.

14 Control device means any equipment used for oxidizing methane vapors. Such equipment includes, but is not limited to, enclosed combustion devices, flares, boilers, and process heaters.

15 For reporting under Subpart W, atmospheric tank counts and emissions data are aggregated at the sub-basin level for onshore production facilities, and at the county level for onshore gathering and boosting facilities.

16 40 CFR 98.233(j)(1); 40 CFR 98.233(j)(2)

17 40 CFR 98.233(j)(3)

18 As calculated per the specified emission quantification methodologies for each source.

19 Control device means any equipment used for oxidizing methane vapors. Such equipment includes, but is not limited to, enclosed combustion devices, flares, boilers, and process heaters.

20 Wet seals on centrifugal compressors and rod packing on reciprocating compressors are outside of the scope of this commitment and will not be included in the reporting requirements for this commitment.

21 “Enhanced” maintenance refers to a data-driven approach that uses measurement to target certain valves for maintenance and will likely go beyond “recommended” maintenance.

22 Reciprocating: 40 CFR 98.233(p)(1)(i),(p)(1)(iii), (p)(2),(p)(4),(p)(6),(p)(8),(p)(11);

Centrifugal: 40 CFR 98.233(o)(1)(i)(1)(iii),(o)(2),(o)(4),(o)(6),(o)(8),(o)(11)

23 Reciprocating: 40 CFR 98.233(p)(1)(ii),(p)(1)(iv),(p)(3),(p)(5),(p)(7),(p)(9),(p)(11);

Centrifugal: 40 CFR 98.233(o)(1)(ii),(o)(1)(iv),(o)(3),(o)(5),(o)(7),(o)(9),(o)(11)

24 Under this Methane Challenge commitment, partners should report measurements from all surveys conducted during the calendar year. The reporting form will be set up to accommodate this.

25 For reciprocating compressors, the site-specific emissions factor approach is used for blowdown valves when an as found measurement is not conducted in operating mode or stand-by pressurized mode and for isolation valves when an as found measurement is not conducted in not-operating depressurized mode. The site-specific emissions factor is developed from applicable measurements from other compressors during the same year and the 2 previous years. 40 CFR 98.233(p)(6)(iii) and (iv).

26 For centrifugal compressors, the site-specific emissions factor approach is used for blowdown valves when an as found measurement is not conducted in operating mode and for isolation valves when an as found measurement is not conducted in not-operating mode. The site-specific emissions factor is developed from applicable measurements from other compressors during the same year and the 2 previous years. 40 CFR 98.233(o)(6)(iii) and (iv).

27 As detailed in the continuous improvement document for this source, partners are encouraged to work up to a biannual (or more frequent) survey, timing the surveys so both the isolation and blowdown valve can be surveyed on each unit, each year. https://www.epa.gov/sites/production/files/2020-07/documents/mc_ci_equipleaks-compvalves_techdoc_final.pdf

28 This should be calculated on a compressor-by-compressor basis, subtracting emissions after mitigation from emissions before mitigation. Emissions after mitigation should be measured within 90 days of implementing the mitigation action.

29 Control device means any equipment used for oxidizing methane vapors. Such equipment includes, but is not limited to, enclosed combustion devices, flares, boilers, and process heaters.

30 40 CFR 98.233(p)(10)

31 Partners can use a methodology of their choosing to calculate voluntary methane emission reductions from this source and must specify what that methodology is.

32 Subpart W requires facilities to report certain information per compressor and other information per vent. Information reported per individual compressor vent is also specific to that one compressor.

33 40 CFR 98.233(p)(1)(i)(A), (p)(2)(ii), (p)(6)(i), and (p)(11)

34 40 CFR 98.233(p)(1)(ii), (p)(3), (p)(7), and (p)(11)

35 The site-specific emissions factor approach is used when an as found measurement for the compressor is conducted in standby-pressurized-mode or in not-operating-depressurized-mode during the year (and an as found measurement is not conducted in operating mode). The site-specific emissions factor is developed from as found measurements of individual rod packing vent emissions from other compressors during the same year and the 2 previous years. 40 CFR 98.233(p)(1)(i)(A), (p)(2)(ii), (p)(6), and (p)(11).

36 Alternate calculation method using average company EF based on all company-specific Subpart W reciprocating compressor measurements (for Processing and Transmission & Storage facilities not reporting to Subpart W only)

37 As calculated per the specified emission quantification methodologies for each source.

38 Control device means any equipment used for oxidizing methane vapors. Such equipment includes, but is not limited to, enclosed combustion devices, flares, boilers, and process heaters.

39 40 CFR 98.233(o)(10)

40 Partners can use a methodology of their choosing to calculate voluntary methane emission reductions from this source and must specify what that methodology is.

41 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2016, Annex 3.6 (Table 3.6-2), Gas Processing, https://www.epa.gov/sites/production/files/2018-04/2018_ghgi_natural_gas_systems_annex_tables.xlsx

42 Subpart W requires facilities to report certain information per compressor and other information per vent. Information reported per individual compressor vent is also specific to that one compressor.

43 40 CFR 98.233(o)(1)(i)(A), (o)(2)(ii), (o)(6)(i), and (o)(11)

44 40 CFR 98.233(o)(1)(ii), (o)(3), (o)(7), and (o)(11)

45 The site-specific emissions factor approach is used when an as found measurement for the compressor is conducted in not-operating-depressurized-mode during the year (and an as found measurement is not conducted in operating mode). The site-specific emissions factor is developed from as found measurements of individual seal oil degassing vent emissions from other compressors during the same year and the 2 previous years. 40 CFR 98.233(o)(1)(i)(A), (o)(2)(ii), (o)(6), and (o)(11)

46 Alternate calculation method using average company EF based on all company-specific Subpart W measurements (for Processing and Transmission & Storage facilities not reporting to Subpart W only)

47 As calculated per the specified emission quantification methodologies for each source.

48 Partners are encouraged to designate a higher reduction rate.

49 Total potential emissions amounts will likely be different each year.

50 The reference to atmospheric pressure is intended to assist in defining total potential emissions, not an indication that companies must reduce pressure to atmospheric pressure for every blowdown.

51 Under Calculation Method 1, Subpart W requires aggregated reporting of blowdown counts and emissions per equipment or event type at the facility level. Under Calculation Method 2, Subpart W requires aggregated reporting of the emissions per facility, but the number of blowdown events or number of stacks monitored is not reported. For transmission pipeline facilities, Subpart W also requires reporting the total number of blowdown events and total emissions aggregated over both methods at the state level.

52 Emergency blowdown events are not included in this source for the BMP Option.

53 98.233(i)(2), based on the volume of pipeline segment between isolation valves and the pressure and temperature of the gas within the pipeline

54 Event types are as follows: pipeline integrity work (e.g., the preparation work of modifying facilities, ongoing assessments, maintenance or mitigation), traditional operations or pipeline maintenance, equipment replacement or repair (e.g., valves), pipe abandonment, new construction or modification of pipelines including commissioning and change of service, operational precaution during activities (e.g. excavation near pipelines), and all other pipeline segments with a physical volume greater than or equal to 50 ft³.

55 98.233(i)(3), based on the measurement of emissions using a flow meter.

56 Alternate calculation method using actual event counts multiplied by the average emission factor as calculated from all company-specific Subpart W facility events (for Transmission Pipeline facilities not reporting to Subpart W only).

57 As calculated per the specified emission quantification methodologies for each source.

58 98.233 (n) provides flaring quantification guidance.

59 http://primis.phmsa.dot.gov/comm/glossary/index.htm?nocache=1606#Main

60 https://www.istt.com/main/task.guidelinedetail/id.113

61 http://www.astm.org/Standards/F1504.htm

62 http://www.astm.org/Standards/F2207.htm

63 Includes wrought iron.

64 Excluding cast iron and unprotected steel mains that have been rehabilitated using specified mitigation methods.

65 Excluding cast iron and unprotected steel mains that have been rehabilitated using specified mitigation methods.

66 40 CFR 98.233(r) ; based on comments received on the Continuous Improvement proposal published August 13, 2018, the Methane Challenge Program will continue to use the Subpart W emission factors (40 CFR 98.233(r) and Table W-7) for the Distribution Mains source. EPA will continue to evaluate the Methane Challenge reporting methodology for this source for future reporting years.

67 For example, if a partner made a Mains commitment in March 2020 and submits a report for this commitment for the first time in 2022, in this report they will include their inventory as of January 1, 2020. In subsequent years, the reporting system will prepopulate this cell with the value reported in the previous year. It should not be changed year-over-year unless there was an error in the value initially reported; this inventory should not be adjusted each year as replacements are made.

68 Ibid.

69 As calculated per the specified emission quantification methodologies for each source.

70 http://primis.phmsa.dot.gov/comm/glossary/index.htm?nocache=1606#ServiceLine

71 “Service Ts” are included in this source category.

72 http://www.ecfr.gov/cgi-bin/text-idx?SID=06dfe10fe465d0ee1b352dad32b2c248&mc=true&node=sp49.3.192.b&rgn=div6

73 Based on comments received on the Continuous Improvement proposal published August 13, 2018, the Methane Challenge Program will continue to use the Subpart W emission factors (40 CFR 98.233(r) and Table W-7) for the Distribution Services source. EPA will continue to evaluate the Methane Challenge reporting methodology for this source for future reporting years.

74 For example, if a partner made a Services commitment in March 2020 and submits a report for this commitment for the first time in 2022, in this report they will include their inventory as of January 1, 2020. In subsequent years, the reporting system will prepopulate this cell with the value reported in the previous year. It should not be changed year-over-year unless there was an error in the value initially reported; this inventory should not be adjusted each year as replacements are made.

75 EPA is using the unprotected steel EF as a proxy quantification method for this source.

76 For example, if a partner made a Services commitment in March 2020 and submits a report for this commitment for the first time in 2022, in this report they will include their inventory as of January 1, 2020. In subsequent years, the reporting system will prepopulate this cell with the value reported in the previous year. It should not be changed year-over-year unless there was an error in the value initially reported; this inventory should not be adjusted each year as replacements are made.

77 As calculated per the specified emission quantification methodologies for each source.

78 Partners are encouraged to designate a higher reduction rate.

79 Total potential emissions amounts will likely be different each year.

80 The reference to atmospheric pressure is intended to assist in defining total potential emissions, not an indication that companies must reduce pressure to atmospheric pressure for every blowdown.

81 Emergency blowdown events and blowdowns of pipelines operating at 60 psi or less are not included in this source for the BMP Option.

82 40 CFR 98.233(i)(2), based on the volume of pipeline segment between isolation valves and the pressure and temperature of the gas within the pipeline.

83 40 CFR 98.233(i)(3), based on the measurement of emissions using a flow meter.

84 As calculated per the specified emission quantification methodologies for each source.

85 40 CFR 98.233 (n) provides flaring quantification guidance.

86 http://primis.phmsa.dot.gov/comm/FactSheets/FSExcavationDamage.htm

87 The program is not requesting quantification of emissions/reductions due to lack of a quantification methodology that would result in consistent, comparable emissions calculations. EPA will evaluate adding quantification to this source in the future should an acceptable methodology become available.

88 Contractor, Railroad, County, State, Developer, Utility, Farmer, Municipality, Occupant, Unknown/Other

89 One-Call Notification Practices, Locating Practices, or Excavation Practices Not Sufficient; One-Call Notification Center Error; Abandoned Facility; Deteriorated Facility; Previous Damage; Other/Miscellaneous. Note – for a damage root cause of “No Locate Call”, please use the “One-Call Notification Practices Not Sufficient” category.

90 There are many different definitions of renewable natural gas currently used; these definitions are specifically tailored to each context. For example, the American Gas Association has developed this consensus definition: “Renewable natural gas (RNG) is any pipeline compatible gaseous fuel derived from biogenic or other renewable sources that has lower lifecycle CO2e emissions than geological natural gas”. Further information on AGA’s definition can be found at this URL: https://www.aga.org/natural-gas/renewable/

91 If your company operates in multiple states and is in different phases of offering ‘green gas’ to customers in the different states, you can provide additional details in the ‘additional information’ free text field.

92 This ID is to be generated by the reporting partner and can be of any alphanumeric format desired. The same ID should be used for any given project across the different tables on the reporting form.

93 If project feedstock is a combined waste stream, please select “Other” and specify the waste streams using the nomenclature from the drop-down list

94 This ID is to be generated by the reporting partner and can be of any alphanumeric format desired. The same ID should be used for any given project across the different tables on the reporting form.

95 This ID is to be generated by the reporting partner and can be of any alphanumeric format desired. The same ID should be used for any given project across the different tables on the reporting form.

96 Generally; a commitment specifically for isolation and blowdown valves at compressor stations was finalized in 2020.

Document last updated 31 March 2021

File Type	application/vnd.openxmlformats-officedocument.wordprocessingml.document
File Title	Methane Challenge Best Management Practice Technical Document
Author	Natural Gas STAR Methane Challenge Program
File Modified	0000-00-00
File Created	2021-07-05