Page 1 of 13 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY WASHINGTON, D.C. 20460

OFFICE OF
AIR AND RADIATION

Petroleum and Natural Gas Systems (Subpart W) of the Greenhouse Gas Reporting Rule Docket: EPA-HQ-OAR-2009-0923

Title: Understanding the Substan ce of DOT Regulations and Comp aring Them to the Subpart W Requirements

Summary: This memorandum discusses the substance of certain regulations of the Department of Transportation (DOT), which involve natural gas pi pelines and may have ha d applicability to the goals of Subpart W, and compares the content and practices of these regulations with the requirements laid out in the re quirements of Subpart W.Page 2 of 13 Understanding the Substance of the DOT Re gulations and Comparing Them to the Subpart W Requirements

This memorandum discusses the substance of certain regulations of the Department of Transportation (DOT), which involve natural gas pi pelines and may have ha d applicability to the goals of Subpart W, and compares the content and practices of these regulations with the requirements laid out in the re quirements of Subpart W.

EPA embarked on this detailed review of th e DOT regulations based on industry comments received in response to the Subpart W proposed re gulation. These comments stated that overlap already existed in DOT requirements pertaining to local distribution companies (LDCs) that would meet the proposed requirements for leak detection and greenhouse gas emissions reporting requirements outlined in subpart W. EPA reviewed DOT regulations in an attempt to minimize burden and to avoid duplicating existing requiremen ts, if indeed DOT regulations were sufficient to EPA’s purposes under Subpart W.Page 3 of 13 Background

In response to the EPA proposed rule addressi ng GHG emissions from petroleum and natural gas systems (subpart W), industry has filed comments requesting that EPA not duplicate and where possible align with regulatory requirements already in place unde r DOT federal leak detection regulations with respect to LDCs

. 1 Although both EPA and DOT re gulations apply to natural gas metering and regulating stations, fundame ntally, EPA is concerned with GHG emissions detection, measurement and reporting and DOT is focused on safety requirements. 2

Leak detection for LDCs comes under the reporti ng requirements of the Pipeline and Hazardous Materials Safety Administrati on (PHMSA). These leak detection requirements focus on the concentration (as opposed to the total cumulative volume) of leak age that may be expected over the reporting period of one calendar year. Henc e the emissions reporting from LDCs for the purpose of PHMSA reporting would be expected to be different from that for current Greenhouse Gas Mandatory Reporting Rule (MRR) purposes. Nonetheless, there is a potential for overlap,

which EPA has considered.

In considering the request, and comparing the su bstance of the DOT regulations to the Subpart W requirements, EPA has examined four criteria:

1.) What Releases or Leaks are Detected? 2.) For What Portion of the System is Leak Detection and Quantification Required? 3.) How Often are Leak Detection and Quantification Conducted? 4.) How are Leaks Quantified When Detected?

1. What Releases or Leaks Are Detected?

In order to determine how the Subpart W regul ation overlaps with the DOT leak detection regulations, the most important cr iteria to consider was what each requires the regulated party to detect, and whether there is sufficie nt overlap. The DOT ’s Guidance Manual for Operators of Small Natural Gas Systems

, Chapter IV

– Leak Detection (June 2002) ( Guidance Manual, Chapter IV ) provides examples of three grad es of releases, classified in to categories of leaks; the quantifiable example provided is any reading greater than 80% lower explosion limit (LEL) in

1 DOT’s safety regulations for the transportation of gases by pipeline are published in Title 49 of the Code of Federal Regulations (CFR), Part s 190, 191, 192, and 199 and enforced by the Office of Pipeline Safety (OPS) of DOT’s Research and Special Programs Administration (RSPA).

2 DOT’s pipeline safety regulati ons apply to natural gas systems and operators of natural gas master meter systems. The regulations require oper ators of natural gas systems to (1) deliver gas safely and reliably to customers, (2) provide tr aining and written instruction for employees, (3) establish written procedures to minimize the hazards resulting from natural gas pipeline emergencies, and (4) keep reco rds of inspection and testing

.Page 4 of 13 small gas associated substructures or greater than 20% LEL in a confined space. 3 This addresses atmospheric concentrations of gas from a general area of the station rather than equipment leak emissions from a specific valve or connector . Additionally, gas is odorized under certain

conditions. 4 Odorization may aid in leak detection from the perspective of a safety concern, but may not be sufficient to detect all equipment leak emissions. 5 Beyond “leak detector equipment” the DOT regulations do not specif y instrumentation; however, the Guidance Manual, Chapter IV does indicate that the commonly used leak detector equipment includes the combustible gas indictor (CGI) and the flame ionization gas detector (FI).

Subpart W requires that affected parties det ect, calculate, and re port equipment leak GHG emissions, defined as “those emissions wh ich could not reasonabl y pass through a stack, chimney, vent, or other functiona lly equivalent opening.” Speci fically, Subpart W is concerned with above ground meters and regulators at city gate stations at cu stody transfer, and the equipment leak emissions from connectors, block valves, control valves, pressure relief valves, orifice meters, regulators, a nd open ended lines. Further, S ubpart W allows the use of several leak detection methods including the optical gas imaging instrument; Method 21 (including OVA/TVA); or infrared laser beam illuminated inst rument. The optical gas imaging instrument (also known as an IR camera) and detection me thods are defined in the Alternative Work Practice for monitoring equipment leaks (AWP)( 40 CFR part 60 subpart A §60.18(i)(1) and (2)), which is part of the Leak Detection and Repair (LDAR) program. IR cameras are able to scan hundreds of source components quickly, including co mponents out of reach for an organic vapor analyzer or toxic vapor analyz er (OVA/TVA). The use of OVA/ TVA and infrared laser beam illuminated leak detection was added to provide fl exibility to affected facilities already using such instruments. Equipment leak emissions are quantified by applying specific leaker factors to the components found leaking with the IR camera, OVA/TVA, or infrared laser beam

illuminated leak detection.

3 See Guidance Manual, Chapter IV, Table 3a-3c. DOT defines th ree classes of leaks based on LEL readings in a confined space or small st ructure. Grade 1 (80% LEL and greater) is a leak that represents an existing or probable h azard to persons or property and requires immediate repair or continuous action until the conditions are no longer hazardous. Grade 2 (between 20% and 80% LEL) is a leak that was non-hazardous at time of detection, but justifies scheduled repairs based on probable future hazard. Grad e 3 (under 20% LEL) is a leak that is nonhazardous at the time of detection and is re asonably expected to remain non-hazardous.

4 See 49 CFR 192.625(a) (“A combustible gas in a di stribution line must contain a natural

odorant or be odorized so that at concentration in air of one-fifth of the lower explosive limit, the gas is readily datable by a person with a normal sense of smell.”).

5 In addition to odor, the Guidance Manual, Chapter IV recognizes other methods of detecting a leak: (1) improved or deteriorat ed vegetation in the area; (2) insect activity; (3) fungus-like growth in valve boxes and manholes; (3) sound; (4) uncounted for gas determined by meter reading; (5) soap solutions; and (6) leak detection equipment. See also 49 CFR § 192.721 (requiring LDCs to patrol na tural gas lines regularly); id . § 192.723 (requiring LDCs to conduct leakage surveys with leak detecti on equipment at regular intervals).Page 5 of 13 Finding :

• DOT regulations prescribe dete ction of releases or leaks from pipeline facilities to meet minimum safety requirements.

• DOT regulations indicate that leaks can be detected, but not nece ssarily measured or emissions reported to DOT, using a variet y of methods, including “leak detector equipment,” which is not a defined term
, but includes CGI and FI.

• Subpart W requires for LDCs above ground gate stations at custody transfer to detect equipment leak GHG emissions from connector s, valves, meters, regulators, and open ended lines with an optical gas imaging instrument, OVA/TVA, or infrared laser

beam illuminated leak detection.

2. For What Portion of the System Is Leak Detection and Quantification Required?

The second criterion for comparison between DOT regulations and Subpart W was to determine which portions of the distribution system are subj ect to the requirements of each rule. The DOT regulations concerning natural gas transportation apply in scope to pipeline facilities, which includes “all facilities through which gas moves in transportation. This includes pipes, valves, and other items attached to the pipe, compressor units, meter stations, regu lator stations, delivery stations, holders, and fabricated assemblies.” 6 Subpart W requirements for GHG equipment leak emission detection and reporting ap ply to connectors, valves, meters, regulators, and open ended lines at above ground metering and regulati ng at custody transfer gate stations.

Finding :

• DOT leak survey regulations pertain to pipeline facilities, including existing pipelines, rights-of-way, and any equipment, facility, or buildings.

• Subpart W leak detection and quantificati on for LDCs pertains to valves, meters, regulators, and open ended lines at above ground metering and regul ating stations at custody transfer. In the final rule, EPA has cl arified that meters a nd regulators in the natural gas distribution industry segm ent do not include customer meters.

3. How Often Is the Leak Detection and Quantification Conducted?

The third criterion for comparis on between DOT regulations and s ubpart W is the frequency with which leak detection and quantif ication is conducted. The DOT re gulations require leak surveys to be conducted at least once per calendar year in business districts and at least once in every five calendar years outside of busine ss districts. Per 49 CFR 192:

§ 192.723 (b) The type and scope of the leakage c ontrol program must be determined by the nature of the operations and the local c onditions, but it must meet the following minimum requirements:

(1) A leakage survey with leak detector equipment mu st be conducted in business districts, including tests of the atmosphere in gas, electric, telephone, sewer, and

6 See 49 CFR 192.3 (definition of “pipeline”).Page 6 of 13 water system manholes, at cracks in pavement and sidewalks, and at other locations providing an opportunity for finding gas leaks, at intervals not exceeding 15 months, but at least once each calendar year. (2) A leakage survey with leak detector equipment must be conducted outside business districts as frequently as ne cessary, but at least once every 5 calendar years at intervals not exceeding 63 months. However, for cathodically unprotected distribution lines subject to §192.465(e) on which electrical surveys for corrosion are impractical, a leakage su rvey must be conducted at least once every 3 calendar years at intervals not exceeding 39 months.

DOT does provide that states may adopt more stringent requirements, and some state regulations require annual surveys for all sources. 7

All affected EPA Subpart W sources are required to detect, calculate, and report GHG equipment leak emissions annually, with no provision for less frequent detection in more remote locations

outside of business districts.

Finding :

• DOT leak surveys of distribution systems are required to be conducted every calendar year (at intervals not to exceed 15 calendar months) in business districts and every five calendar years (at intervals not to exceed 63 months) outside of business districts.

• Subpart W requires for LDCs above ground ga te stations at custody transfer to conduct an annual equipment leak detect ion survey and subsequent emissions quantification.

4. How Are Releases or Leak s Quantified When Detected?

The fourth criterion for comparison between DOT regulations and Subpart W is methodology for quantifying releases or leaks when detected. The DOT regulations do no t require quantification except in the occurrence of an “inc ident,” as defined in § 191.3:

Incident means any of the following events:

(1) An event that involves a release of gas from a pipeline or of liquefied natural gas or gas from an LNG facility and (i) A death, or personal injury necessitating in-patient hospitalization; or (ii) Estimated property damage, including cost of gas lost, of the operator or others, or both, of $50,000 or more. (2) An event that results in an emer gency shutdown of an LNG facility. (3) An event that is significant, in the j udgment of the operator, even though it did not meet the criteria of paragraphs (1) or (2).

7 See, e.g., Guidance Manual, Chapter I at I-1.Page 7 of 13 Note that the DOT regulations provide an exemp tion for reporting releases from an LNG facility per §191.9 and §191.11:

§ 191.9 Distribution system: Incident report. (c) The incident report required by this se ction need not be submitted with respect to master meter systems or LNG facilities. § 191.11 Distribution syst em: Annual report. (b) The annual report required by this section need not be submitted with respect to: (3) LNG facilities.

Subpart W requires that all equipment leak emissions for LDCs above ground gate stations at custody transfer are quantified by applying spec ific leaker factors to the components found leaking during the annual l eak detection survey.

Finding :

• DOT regulations require quantif ication of a release of gas from a pipeline that results in death, personal injury necessitating hospita lization, estimated property damage (including cost of gas lost) exceeding $50,000, or is “signi ficant” in the judgment of the operator.

• Subpart W requires quantifica tion of equipment leak emissions by applying specific leaker factors to the connectors, valves , meters, regulators, and open ended lines at metering and regulating stations found l eaking during the annual leak detection

survey.

Summary of Findings:

• DOT regulations prescribe detection of re leases, including leaks from gas pipeline facilities, pipeline rights-of-way, and a ny equipment (including compressors and odorization equipment), facility or build ings (including mete ring and regulating stations), used in the transportation or treatment of gas to meet minimum safety requirements under 49 CFR 192.

• Subpart W requires for LDCs above ground gate stations at custody transfer to detect and quantify equipment leak GHG emissions from connectors, valves, meters, regulators, and open ended lines.

• DOT regulations indicate that leaks from gas pipeline facili ties are to be detected using “leak detector equipment,” which is not a defined term within 49 CFR 192. The Guidance Manual provides multiple examples of leak detection methods, including odor, changes in vegetation, insect activ ity, fungus growth, sound, unaccounted for gas, soap solutions, and leak detection instruments, such as a combustible gas indicator (CGI) or flame ionization detector (FI). These instruments do not measure

actual mass emissions rates of the detected leaks.

• Subpart W requires that equipment leak GHG emissions from LDCs metering and regulating gate stations a bove ground at custody transfer , detect equipment leak GHG emissions using an optical gas imaging in struments, organic va por analyzers (OVA), toxic vapor analyzers (TVA) or infrared laser beam illuminated leak detectors.Page 8 of 13 • DOT leak surveys of gas distribution systems including metering and regulating stations are required to be conducted every calendar year (at intervals not to exceed 15 calendar months) in busine ss districts and every five calendar years (at intervals not to exceed 63 months) outsi de of business districts.

• Subpart W requires for LDCs above ground ga te stations at custody transfer to conduct an annual equipment leak detect ion survey and subsequent emissions quantification.

• DOT regulations require quantif ication of releases resu lting from a release of gas from a pipeline that results in death, personal injury necessitating hospitalization, estimated property damage (including cost of gas lost) exceeding $50,000, or that is “significant” in the judg ment of the operator.

• Subpart W requires quantific ation of equipment leak GHG emissions with an OVA/TVA instrument reading equal to or greater than 10,000 ppm, or any emission detected by the o ptical gas imaging instrument or infrared laser beam illuminated instrument. Quantification is done by applying specific leaker factors from the subpart W rule to the co mponents found leaking.

Table 1: Terms Defined Under DOT and Subpart W

Term DOT Regulations Subpart W

Leak Detection

Method Leaks are to be detected using unspecified “leak detector equipment.” The leak detection options are: optical gas imaging instrument; Method 21 (including OVA/TVA); or

infrared laser beam illuminated

instrument.

Release or

Emissions A release is categorized into Category 1, 2, or 3 leak. The quantifiable description of leak per PHMSA is an atmospheric

gas concentrati on reading of

more than 80% LEL in small gas

associated substructures or

more than 20% LEL in a

confined

space. 8 Method 21 instrument reading equal to or greater than 10,000 ppm. Any emission detected

by the o ptical gas imaging

instrument or infrared laser

beam illuminated instrument.

8 See Guidance Manual, Chapter IV, Table 3a-3c. DOT defines th ree classes of leaks based on LEL readings in a confined space or small struct ure. Grade 1 (80% LEL and greater) is a leak that represents an existing or probable hazard to persons or propert y and requires immediate repair or continuous action until the conditions are no longer hazardous. Grade 2 (between 20% and 80% LEL) is a leak that was non- hazardous at time of detection, but justifies scheduledPage 9 of 13 Leak Detection Frequency Survey interval may range from one to five years Annually

Leak Detection

Location Gas distribution systems

within business districts and

outside of business districts Above ground gate stations at custody transfer at all locations

Leak Quantification Incidents involving releases are quantified if they result in death, personal injury requiring hospitalization,

property damage in the equivalent of $50,000 including cost of gas lost, or a release deemed “significant” by the operator Leaks are quantified by applying specific leaker factors

to components found leaking during the annual survey

Equipment Leak

Emissions Not defined Equipment leak means those

emissions which could not reasonably pass through a stack, chimney, vent, or other functionally equivalent opening

repairs based on probable future hazard. Grad e 3 (under 20% LEL) is a leak that is nonhazardous at the time of detection and is reasonably expected to remain non-hazardous.Page 10 of 13 Table 2: Federal Regulations and Federal Guidance Documents Reviewed in

Comparison of DOT and Subpart W Loca l Distribution Leak Detection of Quantification

Federal Regulations and

Federal Guidance AGA

Referenced Reviewed by EPA

49 CFR 191 9

49 CFR 192 9 9

49 CFR 192.3 9 9

49 CFR 192.481 9 9

49 CFR 192.613 9 9

49 CFR 192.705 9 9

49 CFR 192.706 9 9

49 CFR 192.721 9 9

49 CFR 192.723 9 9

49 CFR 192.905 9 9

49 CFR 192.921 9 9

49 CFR 192.941 9 9

49 CFR 192.1007 9 9
PHMSA F 7100.1-1 (12- 05) Form Approved OMB No. 2137-0522 (Annual Reporting Form 9 9

PHMSA Distribution Incident Reporting Form

F 7100.1 9 9

PHMSA Transmission and Gathering Annual Reporting Form F7100.2-

1 9

PHMSA Transmission and Gathering Incident Reporting Form F 7100.2 9

PHMSA Form-02 Standard Inspection Report of a Gas Distribution Operator 9

PHMSA Gas Integrity Management Protocol Results Form (Jan 2008) 9Page 11 of 13 Attachment A 49 CFR 192 Transportation Of Natural And Othe r Gas By Pipeline: Minimum Federal Safety Standards: Excerpts Related to Le ak Surveys in Distribution Systems

§ 192.1 What is the scope of this part? (a) This part prescribes minimum safety requirements for pipeline facilities and the transportation of gas, including pipeline facilities and the transportation of gas within the lim its of the outer continental shelf as that term is defined in the Outer Continental Shelf Lands Act (43 U.S.C. 1331).

§ 192.3 Definitions.

Distribution line means a pipeline other than a gathering or transmission line.

Pipeline means all parts of those physical facilities through which gas moves in transportation, including pipe, valves, and other appurtenance attached to pipe, compress or units, metering stations, regulator stations, delivery stations, holders, and fabricated assemblies.

Pipeline facility means new and existing pipelines, rights-of-way, and any equipment, facility, or building used in the transportation of gas or in the treatment of gas during the course of transportation.

Service line means a distribution line that transports gas from a common source of supply to an individual customer, to two adjacent or adjoining residential or sma ll commercial customers, or to multiple residential or small commercial customers served through a meter header or manifold. A service line ends at the outlet of the customer meter or at the connection to a customer's pipi ng, whichever is further downstream, or at the connection to customer piping if there is no meter.

§ 192.625 Odorization of gas. (a) A combustible gas in a distribution line must contain a natural odorant or be odorized so that at a concentration in air of one-fifth of the lower explosive limit, the gas is re adily detectable by a person with a normal sense of smell. (b) After December 31, 1976 , a combustible gas in a transm ission line in a Class 3 or Class 4 location must comply with the requirements of paragraph (a) of this section unless: (1) At least 50 percent of the length of the line downstream from that location is in a Class 1 or Class 2 location; (2) The line transports gas to any of the following fa cilities which received gas without an odorant from that line before May 5, 1975; (i) An underground storage field; (ii) A gas processing plant; (iii) A gas dehydration plant; or (iv) An industrial plant using gas in a process where the presence of an odorant: (A) Makes the end product unfit for the purpose for which it is intended; (B) Reduces the activity of a catalyst; or (C) Reduces the percentage completion of a chemical reaction; (3) In the case of a lateral line which transports gas to a distribution center, at least 50 percent of the length of that line is in a Class 1 or Class 2 location; or (4) The combustible gas is hydrogen intended for use as a feedstock in a manufacturing process. (c) In the concentrations in which it is used, the odorant in combustible gases must comply with the following: (1) The odorant may not be deleterious to persons, materials, or pipe. (2) The products of combustion from the odorant may not be toxic when breathed nor may they be corrosive or harmful to those materials to which the products of combustion will be exposed. (d) The odorant may not be soluble in water to an extent greater than 2.5 parts to 100 parts by weight. (e) Equipment for odorizatio n must introduce the odorant without wide variations in the level of odorant. (f) To assure the proper concentration of odorant in accordance with this section, each operator must conduct periodic sampling of combustible gases using an instrument capable of determining the percentage of gas in air at which the odor becomes readily detectable. Operators of master meter systems may comply with this requirement by—Page 12 of 13 (1) Receiving written verification from th eir gas source that th e gas has the proper c oncentration of odorant;

and (2) Conducting periodic “sniff” tests at the extremities of the system to confirm that the gas contains odorant. [35 FR 13257, Aug. 19, 1970]

§ 192.721 Distribution systems: Patrolling. (a) The frequency of patro lling mains must be de termined by the severity of the conditions which could cause failure or leakage, and the consequent hazards to public safety. (b) Mains in places or on structures where anticipated physical movement or external loading could cause failure or leakage must be patrolled— (1) In business districts, at intervals not exceeding 41/2months, but at least four times each calendar year; and (2) Outside business districts, at in tervals not exceeding 71/2months, but at least twice each calendar year.

§ 192.723 Distribution systems: Leakage surveys. (a) Each operator of a distribution syst em shall conduct periodic leakage surveys in accordance w ith this section. (b) The type and scope of the leakage control program must be determined by the nature of the operations and the local conditions, but it must meet the following minimum requirements: (1) A leakage survey with leak detector equipment must be conducted in business distri cts, including tests of the atmosphere in gas, electric, telephone, sewer, and water system manholes, at cracks in pavement and sidewalks, and at other locations providing an opportunity for finding gas leaks, at intervals not exceeding 15 months, but at least once each calendar year. (2) A leakage survey with leak detector equipment must be conducted outside business districts as frequently as necessary, but at least once every 5 calendar years at intervals not exceeding 63 months. However, for cathodically unprotected distribution lines s ubject to §192.465(e) on which elect rical surveys for corrosion are impractical, a leakage survey must be conducted at le ast once every 3 calendar years at intervals not exceeding

39 months.

§ 192.703 General. (c) Hazardous leaks must be repaired promptly.

§ 192.1001 Hazardous Leak means a leak that represents an existing or probable hazard to persons or property and requires immediate repair or continuous action until the conditions are no longer hazardous.Page 13 of 13 Attachment B 49 CFR 191 Transportation Of Natural And Othe r Gas By Pipeline: Annual Reports, Incident Reports, and Safety Related Condition Reports : Excerpts Related to Leak Surveys in Distribution Systems

§ 191.3 Definitions. As used in this part and the PHMSA Forms referenced in this part— Gas means natural gas, flammable gas, or gas which is toxic or corrosive;

Incident means any of the following events: (1) An event that involves a release of gas from a pi peline or of liquefied natural gas or gas from an LNG facility and (i) A death, or personal injury necessitating in-patient hospitalization; or (ii) Estimated property damage, including cost of gas lost, of the operator or others, or both, of $50,000 or

more. (2) An event that results in an emergency shutdo wn of an LNG facility. (3) An event that is significant, in th e judgment of the oper ator, even though it did no t meet the criteria of paragraphs (1) or (2).

§ 191.9 Distribution syst em: Incident report. (c) The incident report required by this section need not be submitted with respect to master meter systems or LNG facilities.

§ 191.11 Distribution system: Annual report. (b) The annual report required by this section need not be submitted with respect to: (3) LNG facilities.