Pipeline Safety: Valve Installation and Minimum Rupture Detection Standards

• Citation: 85 FR 7162
• Record Number: 2020-01459
• Published date: 06 February 2020
• Court: Pipeline And Hazardous Materials Safety Administration

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Federal Register / Vol. 85, No. 25 / Thursday, February 6, 2020 / Proposed Rules

DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials

Safety Administration

49 CFR Parts 192 and 195

[Docket No. PHMSA–2013–0255]

RIN 2137–AF06

Pipeline Safety: Valve Installation and

Minimum Rupture Detection Standards

AGENCY

: Pipeline and Hazardous

Materials Safety Administration

(PHMSA), DOT.

ACTION

: Notice of proposed rulemaking.

SUMMARY

: PHMSA is proposing to revise

the Pipeline Safety Regulations

applicable to newly constructed and

entirely replaced onshore natural gas

transmission and hazardous liquid

pipelines to mitigate ruptures.

Additionally, PHMSA is revising the

regulations regarding rupture detection

to shorten pipeline segment isolation

times. These proposals address

congressional mandates, incorporate

recommendations from the National

Transportation Safety Board, and are

necessary to reduce the consequences of

large-volume, uncontrolled releases of

natural gas and hazardous liquid

pipeline ruptures.

DATES

: Persons interested in submitting

written comments on this NPRM must

do so by April 6, 2020.

ADDRESSES

: You may submit comments

identified by the docket number

PHMSA–2013–0255 by any of the

following methods:

Comments should reference Docket

No. PHMSA–2013–0255 and may be

submitted in the following ways:

•Federal eRulemaking Portal: http://

www.regulations.gov. This site allows

the public to enter comments on any

Federal Register notice issued by any

agency. Follow the online instructions

for submitting comments.

•Fax: 1–202–493–2251.

•Mail: U.S. DOT Docket Operations

Facility (M–30), West Building, 1200

New Jersey Avenue SE, Washington, DC

20590.

•Hand Delivery: DOT Docket

Operations Facility, West Building,

Room W12–140, 1200 New Jersey

Avenue SE, Washington, DC 20590

between 9:00 a.m. and 5:00 p.m.,

Monday through Friday, except Federal

holidays.

Instructions: Identify the docket

number, PHMSA–2013–0255, at the

beginning of your comments. If you mail

your comments, submit two copies. To

confirm receipt of your comments,

include a self-addressed, stamped

postcard.

Note: All comments are posted

electronically in their original form,

without changes or edits, including any

personal information.

Privacy Act Statement

In accordance with 5 U.S.C. 553(c),

DOT solicits comments from the public

to better inform its rulemaking process.

DOT posts these comments, without

edit, including any personal information

the commenter provides, to

www.regulations.gov, as described in

the system of records notice (DOT/ALL–

14 FDMS), which can be reviewed at

www.dot.gov/privacy.

Confidential Business Information

Confidential Business Information

(CBI) is commercial or financial

information that is both customarily and

actually treated as private by its owner.

Under the Freedom of Information Act

(FOIA) (5 U.S.C. 552), CBI is exempt

from public disclosure. If your

comments responsive to this notice

contain commercial or financial

information that is customarily treated

as private, that you actually treat as

private, and that is relevant or

responsive to this notice, it is important

that you clearly designate the submitted

comments as CBI. Pursuant to 49 CFR

190.343, you may ask PHMSA to give

confidential treatment to information

you give to the agency by taking the

following steps: (1) Mark each page of

the original document submission

containing CBI as ‘‘Confidential’’; (2)

send PHMSA, along with the original

document, a second copy of the original

document with the CBI deleted; and (3)

explain why the information you are

submitting is CBI. Unless you are

notified otherwise, PHMSA will treat

such marked submissions as

confidential under the Freedom of

Information Act, and they will not be

placed in the public docket of this

notice. Submissions containing CBI

should be sent to Robert Jagger at U.S.

DOT, PHMSA, PHP–30, 1200 New

Jersey Avenue SE, PHP–30, Washington,

DC 20590–0001. Any commentary

PHMSA receives that is not specifically

designated as CBI will be placed in the

public docket for this matter.

FOR FURTHER INFORMATION CONTACT

:

Technical questions: Steve Nanney,

Project Manager, by telephone at 713–

272–2855. General information: Robert

Jagger, Senior Transportation Specialist,

by telephone at 202–366–4361.

SUPPLEMENTARY INFORMATION

:

I. Executive Summary

A. Purpose of Regulatory Action

B. Summary of the Major Provisions of the

Regulatory Action

C. Costs and Benefits

II. Background

A. General Authority

B. Major Pipeline Accidents

C. National Transportation Safety Board

Recommendations

D. Advance Notices of Proposed

Rulemaking (ANPRM)

E. Pipeline Safety, Regulatory Certainty,

and Job Creation Act of 2011 and Related

Studies

i. Section 4—Automatic and Remote-

Controlled Shut-Off Valves

a. GAO Report GAO–13–168

b. ORNL Report ORNL/TM–2012/411

ii. Section 8—Leak Detection

F. PHMSA 2012 R&D Forum, ‘‘Leak

Detection and Mitigation’’

III. Proposed Rupture Detection and

Mitigation Actions and Analysis of

ANPRM Comments

A. Definition of Rupture

B. Accident Response and Mitigation

Measures

i. Installing Remote Control Valves (RCVs)

and Automatic Shutoff Valves (ASVs)

ii. Standards for Rupture Identification and

Response Times

iii. Using RCVs and ASVs in All Cases

C. Drills to Validate Valve Closure

Capability

D. Maximum Valve Spacing Distance

i. Gas Transmission Pipelines

ii. Valve Spacing in Response to Class

Location Changes

iii. Hazardous Liquid Pipelines

E. Protection of High Consequence Areas

(HCAs)

i. Gas Transmission Pipelines

ii. Hazardous Liquid Pipelines

F. Failure Investigations

IV. Section-by-Section Analysis of Changes to

49 CFR Part 192 for Gas Transmission

Pipelines

V. Section-by-Section Analysis of Changes to

49 CFR Part 195 for Hazardous Liquid

Pipelines

VI. Regulatory Analyses and Notices

I. Executive Summary

A. Purpose of the Regulatory Action

PHMSA seeks notice and comment on

proposed revisions to the Pipeline

Safety Regulations for both gas

transmission and hazardous liquid

pipelines. PHMSA is proposing

regulations to meet a congressional

mandate calling for the installation of

remote-control valves (RCV), automatic

shutoff valves (ASV), or equivalent

technology, on all newly constructed

and fully replaced gas transmission and

hazardous liquid lines. However,

consistent with the mandate, PHMSA

recognizes that there may be locations

where it is not economically,

technically, or operationally feasible to

install RCVs, ASVs, or equivalent

technology. Therefore, PHMSA is

proposing to allow operators to install

manual valves at these locations,

provided operators have a sufficient

justification for using a manual valve

instead of an RCV, an ASV, or

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For brevity, reference to ‘‘hazardous liquid

pipelines’’ through the remainder of this NPRM will

include carbon dioxide pipelines as well, unless

otherwise stipulated.

2

A gas pipeline’s class location broadly indicates

the level of potential consequences for a pipeline

release based upon population density along the

pipeline. Class locations are determined as

specified at §192.5(a) by using a ‘‘sliding mile’’ that

extends 220 yards on both sides of the centerline

of a pipeline. The number of buildings within this

sliding mile at any point during the mile’s

movement determines the class location for the

entire mile of pipeline contained within the sliding

mile. Class 1 locations contain 10 or fewer

buildings intended for human occupancy, Class 2

locations contain 11 to 45 buildings, Class 3

locations contain 46 or more buildings, and Class

4 locations have a prevalence of 4-or-more-story

buildings.

3

‘‘Pacific Gas and Electric Company; Natural Gas

Transmission Pipeline Rupture and Fire; San

Bruno, CA; September 9, 2010; NTSB Accident

Report PAR–11/01; Adopted August 30, 2011.

https://www.ntsb.gov/investigations/

AccidentReports/Reports/PAR1101.pdf.

4

‘‘Pipeline Safety: Better Data and Guidance

Needed to Improve Pipeline Operator Incident

Response,’’ Government Accountability Office

Report to Congressional Committees, January 2013.

https://www.gao.gov/assets/660/651408.pdf.

5

‘‘Studies for the Requirements of Automatic and

Remotely Controlled Shutoff Valves and Hazardous

Liquids and Natural Gas Pipelines with Respect to

Public and Environmental Safety;’’ Oak Ridge

National Laboratory; ORNL/TM–2012/411; October

31, 2012. https://www.phmsa.dot.gov/sites/

phmsa.dot.gov/files/docs/technical-resources/

pipeline/16701/finalvalvestudy.pdf.

6

‘‘Leak Detection Study—DTPH56–11–D–

000001;’’ Kiefner and Associates, Inc.; Final Report

No. 12–173; December 10, 2012. https://

www.phmsa.dot.gov/sites/phmsa.dot.gov/files/

docs/technical-resources/pipeline/16691/leak-

detection-study.pdf.

equivalent technology, and provided

that operators appropriately station

personnel to ensure that a manual valve

can be closed within the same 40-

minute timeframe PHMSA is proposing

in this rulemaking for RCVs, ASVs, and

equivalent technology. This will help to

ensure that a consistent level of safety

is provided whether operators use

manual valves, RCVs, ASVs, or

equivalent technology.

This rulemaking (NPRM) is proposing

to apply this installation requirement to

those newly constructed or fully

replaced pipelines that are greater-than-

or-equal-to 6 inches in nominal

diameter. PHMSA is also proposing

regulations to improve pipeline

operators’ responses to large-volume,

uncontrolled release events that may

occur during the operation of certain

onshore gas transmission, hazardous

liquid, and carbon dioxide pipelines of

particular diameters and in specific

locations.

1

This NPRM would define a

‘‘rupture’’ event through certain metrics

or observations, require operators of

applicable lines to meet new regulatory

standards to identify ruptures more

quickly, respond to them more

effectively, and mitigate their impacts.

PHMSA’s existing regulations require

that operators take several steps to

reduce the risk of potential leaks and

failures, including testing and

assessments, continuous monitoring of

operations, and physical surveys and

patrols of their pipelines’ right-of-ways.

Based on congressional direction,

National Transportation Safety Board

(NTSB) safety recommendations from

accident investigations,

recommendations from the Government

Accountability Office (GAO), and

PHMSA’s analysis of incidents and

evolving technology, this rule proposes

to define large-volume, uncontrolled

releases of both natural gas and

hazardous liquids as pipeline

‘‘ruptures’’ and proposes standards to

mitigate those ruptures.

One such rupture occurred on July 25,

2010, in Marshall, Michigan, resulting

in the spill of approximately 800,000

gallons of crude oil into the Kalamazoo

River and approximately $1 billion in

damages. The operator took 18 hours to

confirm the pipeline rupture. Following

confirmation of the rupture, the failed

segment of the pipeline was

immediately isolated using remote-

controlled valves.

Another incident occurred on

September 9, 2010, in San Bruno,

California, when a gas pipeline

ruptured, causing a fire. This incident

involved the uncontrolled release of

natural gas for 95 minutes, severely

hampering firefighting efforts, before the

operator closed the mainline valves. The

incident resulted in 8 deaths, 51 injuries

requiring hospitalization, the

destruction of 38 homes, damage to 70

other homes, and the evacuation of

approximately 300 houses.

These two incidents are examples of

release events where consequences can

be significantly aggravated by some

combination of missed opportunities by

operators, including: (1) Identifying that

a rupture has occurred; (2) failing to

take appropriate and prompt action(s)

once a rupture has been identified,

including calling 911 following the

rupture, activating emergency response

protocols, and notifying first responders

and public officials; and (3) failing to

promptly access and close available

segment isolation valves that would be

most beneficial for mitigating the impact

of the rupture.

Following those incidents, Congress

issued the Pipeline Safety, Regulatory

Certainty, and Job Creation Act of 2011

(2011 Pipeline Safety Act), which

contained several mandates to improve

pipeline safety. Section 4 of the 2011

Pipeline Safety Act requires PHMSA to

issue regulations, if appropriate,

requiring the use of automatic or

remote-controlled shut-off valves, or

equivalent technology, on newly

constructed or replaced natural gas or

hazardous liquid pipeline facilities.

PHMSA is proposing these

regulations to improve operational

practices related to rupture mitigation

and to shorten rupture-segment

isolation times by requiring operators of

applicable lines to identify a rupture

quickly, implement response

procedures, and fully close pipeline

mainline valves to terminate the

uncontrolled release of commodity as

soon as practicable. PHMSA is also

requiring operators to install automatic

shutoff, remote-controlled, or equivalent

valves on newly constructed and

entirely replaced pipelines to meet the

section 4 mandate. PHMSA seeks

comment from the public on these

proposals.

Enbridge, the pipeline operator

responsible for the incident near

Marshall, MI, had remote-control

technology installed on the ruptured

pipeline. However, a failure to identify

the rupture within a short amount of

time rendered the technology essentially

useless. Therefore, PHMSA believes a

regulation requiring the installation of

rupture-mitigating valves should be

paired with a standard delineating when

an operator must identify a rupture and

actuate those valves. PHMSA also

believes that this standard will be most

cost-effective when applied to onshore

hazardous liquid and natural gas

transmission pipelines of certain

diameters in high-consequence areas

(HCA), areas that could affect HCAs (for

hazardous liquid pipelines), and Class 3

and 4 locations (for natural gas

transmission pipelines),

2

where a

release could have the most significant

adverse consequences on public safety

or the environment.

In developing these proposed

regulations, PHMSA considered other

mandates in the 2011 Pipeline Safety

Act, as well as NTSB safety

recommendations that followed the San

Bruno incident;

3

GAO

recommendations on the ability of

operators to respond to commodity

releases in HCAs;

4

technical reports

commissioned by PHMSA on valves and

leak detection from Oak Ridge National

Laboratory (ORNL) and Kiefner and

Associates, respectively;

56

comments

received on related topics through

advance notices of proposed rulemaking

(ANPRM); and information gathered at

public meetings and workshops.

PHMSA believes this approach, as

detailed in this NPRM, will help reduce

the consequences of ruptures through

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‘‘Nominal’’ pipe size is the standard size used

to refer to pipe in non-specific terms and identifies

the approximate inner diameter of the pipe with a

non-dimensional number.

8

https://www.regulations.gov/docket?D=PHMSA-

2010-0229.

9

Details on all of PHMSA’s leak detection

research and development projects can be found at:

https://primis.phmsa.dot.gov/matrix/

PrjQuery.rdm?text1=leak&btn=Modern+Search.

10

Computational Pipeline Monitoring for Liquids

and Pipeline Leak Detection Program Management,

respectively.

improving both rupture identification

and rupture mitigation, including more

rapid and effective isolation of failed

pipeline segments.

B. Summary of the Major Provisions of

the Proposed Regulatory Action

This NPRM will require the

installation of automatic shutoff valves,

remote-control valves, or equivalent

technology, on all newly constructed or

entirely replaced natural gas

transmission and hazardous liquid

pipelines that have nominal diameters

of 6 inches or greater.

7

For the purposes

of this NPRM, PHMSA considers

pipelines to be ‘‘entirely replaced’’

when 2 or more contiguous miles are

being replaced with new pipe. PHMSA

requests comments on this definition of

‘‘entirely replaced’’ in the context of the

Section 4 valve installation mandate

and whether it is reasonable or should

be modified in the future. Additionally,

for gas transmission pipelines, when a

pipeline’s class location changes and

results in pipe replacement to meet the

maximum allowable operating pressure

(MAOP) requirements of the new class

location, an operator would be required

to install or otherwise modify valves as

necessary to comply with valve spacing

requirements and the proposed rupture

identification and mitigation

requirements.

The NPRM also would establish

Federal minimum standards for the

identification of ruptures and the

initiation of pipeline shutdowns,

segment isolation, and other mitigative

actions, which are designed to reduce

the volume of commodity released due

to a pipeline rupture and thereby

minimize potential adverse safety and

environmental consequences. This

NPRM also would establish standards

for improving the effectiveness of

emergency response. Specifically, the

proposed rupture identification and

mitigation regulations include: (1)

Defining the term ‘‘rupture’’ as an event

that results in an uncontrolled release of

a large volume of commodity that can be

determined according to specific criteria

or that has been observed and reported

to the operator; (2) a requirement to

establish procedures for responding to a

rupture; (3) a requirement to declare a

rupture as soon as practicable but no

longer than 10 minutes after initial

notification or indication; (4) a

requirement to immediately and directly

notify the appropriate public safety

answering point (9–1–1 emergency call

centers) for the jurisdiction in which the

rupture is located; and (5) a requirement

to respond to a rupture as soon as

practicable by closing rupture-

mitigation valves, with complete valve

shut-off and segment isolation within 40

minutes after rupture identification.

The term ‘‘rupture-mitigation valve,’’

as it pertains to this proposal, means the

specific valve(s) that the operator would

use to isolate a pipeline segment that

experiences a rupture—the applicable

‘‘shut-off segment’’ as those are

specified in this rulemaking. These

valves can be any combination of

automatic shutoff valves (ASVs),

remote-control valves (RCVs), or

equivalent technology. A ‘‘shut-off

segment,’’ for the purposes of this

NPRM, is the segment of applicable pipe

between the rupture-mitigation valves

closest to the upstream and downstream

endpoints of a high-consequence area, a

Class 3 location, or a Class 4 location so

that the entirety of these areas is

between rupture-mitigation valves.

Multiple high-consequence areas, Class

3 locations, or Class 4 locations can be

contained in a single shut-off segment,

and all valves installed on a shut-off

segment are rupture-mitigation valves.

Additionally, operators would be

required to perform post-accident

reviews of any ruptures or other release

events involving the closure of rupture-

mitigation valves to ensure these

proposed performance objectives are

met and to apply any lessons learned

system-wide. The new rupture

mitigation requirements in this NPRM

would take effect 12 months after the

final rule is published.

In this NPRM, PHMSA is only

allowing operators to install or use

manual valves if they can demonstrate

to PHMSA that it would be

economically, technically, or

operationally infeasible to install or use

an ASV, RCV, or equivalent technology.

Examples of where an ASV, RCV, or

equivalent technology might be

infeasible include locations that may

have issues with communication

signals, power sources, space for

actuators, or physical security.

PHMSA is not proposing additional

valve requirements for smaller diameter

pipelines or leaks that don’t meet the

proposed definition of rupture in this

rulemaking. PHMSA is also not

requiring leak detection equipment on

gas transmission and distribution

pipelines as specifically recommended

by NTSB Recommendation P–11–10.

Pursuant to the findings in the Kiefner

Leak Detection study that is referenced

later in this rulemaking, it is typically

more challenging to detect smaller leaks

in an operationally, technically, and

economically feasible manner. However,

this proposed rule, for both hazardous

liquid and gas transmission pipelines,

requires the installation of pressure

monitoring equipment at all rupture

mitigation valves on both the upstream

and downstream locations of the valve,

which will help operators better detect

ruptures and which can be used for leak

detection.

PHMSA continues to address the

effectiveness of leak detection systems

for other non-rupture type leaks through

its rulemaking on the safety of

hazardous liquid pipelines;

8

research

and development projects, including

work on external-based leak detection

sensors and acoustic pipeline leak

detection systems;

9

and engagement in

new or updated standards being

developed by standard developing

organizations, including API

recommended practices 1130 and

1175.

10

The requirements in this NPRM

of adding pressure detection and

communication equipment at rupture

mitigation valves are expected to drive

further development and installation of

leak detection technology and may help

drive operators to make decisions to

improve the capabilities of their leak

detection systems to detect non-rupture-

type events.

C. Costs and Benefits

Consistent with Executive Order

12866, PHMSA has prepared an

assessment of the benefits and costs of

the NPRM, as well as reasonable

alternatives. Per the Preliminary

Regulatory Impact Analysis (PRIA),

PHMSA estimates the annual costs of

the rule to be approximately $3.1

million, calculated using a 7 percent

discount rate. The costs reflect the

installation of valves on newly

constructed and entirely replaced gas

transmission and hazardous liquid

pipelines, as well as incremental

programmatic changes that operators

will need to make to incorporate the

proposed rupture detection and

response procedures. PHMSA elected

not to quantify the benefits of this

rulemaking and instead discusses them

qualitatively in the PRIA.

PHMSA is posting the PRIA for this

proposed rule in the public docket. In

the PRIA, costs are aggregated by

compliance method to estimate total

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Energy products being shipped through the

nation’s 2.7 million miles of pipelines reach their

destinations without incident 99.997 percent of the

time. https://www.phmsa.dot.gov/sites/

phmsa.dot.gov/files/docs/news/69671/aopl-api-

speech.pdf.

12

National Transportation Safety Board Pipeline

Accident Report; Texas Eastern Transmission

Corporation Natural Gas Pipeline Explosion and

Fire; Edison, New Jersey; March 23, 1994. https://

www.ntsb.gov/investigations/AccidentReports/

Reports/PAR9501.pdf.

costs, by year, for the baseline and

NPRM. The incremental effect of this

rulemaking is estimated by taking the

difference in total costs relative to the

baseline. Costs are then aggregated

across all years in the analysis period

and annualized.

II. Background

A. General Authority

Congress has authorized Federal

regulation of the transportation of gas

and hazardous liquids by pipeline in the

Pipeline Safety Laws (49 U.S.C. 60101 et

seq.), a series of statutes that are

administered by PHMSA. Congress

established the current framework for

regulating pipelines transporting gas in

the Natural Gas Pipeline Safety Act of

1968 (Pub. L. 90–481) and the safety of

hazardous liquid pipelines in the

Hazardous Liquid Pipeline Safety Act of

1979 (Pub. L. 96–129). These laws give

PHMSA the authority and responsibility

to develop, prescribe, and enforce

minimum Federal safety standards for

the transportation of gas and hazardous

liquids by pipeline. PHMSA prescribes

and enforces comprehensive minimum

safety standards for the transportation of

gas and hazardous liquids by pipeline in

49 Code of Federal Regulations (CFR)

parts 190–199. Among those standards,

PHMSA has codified safety standards

for the design, construction, testing,

operation, and maintenance of gas and

hazardous liquid pipelines in 49 CFR

part 192, Transportation of Natural and

Other Gas by Pipeline, and 49 CFR part

195, Transportation of Hazardous

Liquids by Pipeline.

Part 192 prescribes minimum safety

requirements for the transportation of

gas by pipeline, including ancillary

facilities and within the limits of the

outer continental shelf as defined in the

Outer Continental Shelf Lands Act (43

U.S.C. 1331). Part 195 prescribes

minimum safety requirements for

pipeline facilities used in the

transportation of hazardous liquids or

carbon dioxide, including pipelines on

the Outer Continental Shelf.

B. Major Pipeline Accidents

Although transmission pipelines are

generally considered to be a very safe

means of transporting natural gas and

hazardous liquids,

11

they can

experience large-volume, uncontrolled

releases that can have severe

consequences. For example, and

according to PHMSA hazardous liquid

pipeline accident reports from 2006 to

2016, there were 91 reported incidents

on pipelines within HCAs that would

have been reported as ‘‘ruptures’’ per

this proposed rulemaking and would

have triggered this NPRM’s rupture-

mitigation response provisions. Such

accidents can be aggravated by some

combination of: Missed opportunities by

the operator to identify that a rupture

has occurred; failure of operating

personnel to take appropriate action(s)

once a rupture is identified; delays in

accessing and closing available segment

isolation valves; and an inability to

quickly close isolation valves that

would have the most significant impact

in mitigating the consequences of a

rupture. Typically, these types of

incidents (i.e., failure events that result

in rapidly occurring, large-volume

releases) have been the most serious in

terms of monetary and environmental

damages and safety consequences—the

aforementioned 91 hazardous liquid

‘‘ruptures’’ resulted in $1.21 billion

dollars in damage and 88,506 bbls

spilled. The Marshall, MI, and San

Bruno, CA, accidents are examples of

failure events that resulted in rapidly

occurring, large-volume releases on

high-pressure, large-diameter pipelines.

The intent of this NPRM is to improve

operational practices that in turn will

improve rupture mitigation and shorten

rupture isolation times for certain

onshore gas transmission and hazardous

liquid pipelines. ‘‘Rupture isolation

time,’’ as it is discussed in this NPRM,

is the time it takes an operator to

identify a rupture, implement response

procedures, and fully close the

appropriate mainline valves to

terminate the uncontrolled flow of

commodity from the ruptured pipeline

segment.

In accident investigations, PHMSA

and the NTSB have identified issues

relating to the timeliness of rupture

identification and the appropriateness

and timeliness of operators’ responses to

ruptures. Typically, no single aspect

contributes to the deficiencies in

rupture identification and response.

Instead, there were multiple

contributing factors associated with the

technology, equipment, procedures, and

human elements that resulted in

inadequate rupture identification and

response efforts. In some incidents,

certain aspects of an operator’s rupture

identification or response efforts

appeared adequate, but other issues,

such as delayed access to isolation

valves, resulted in an inadequate

response overall. For instance, in the

incident near Marshall, MI, the pipeline

operator had in place leak detection

systems (LDS) and supervisory control

and data acquisition (SCADA) systems

that notified the controller of a potential

rupture within minutes of the actual

event, but issues related to the

operator’s procedures, training, and

personnel response resulted in an

excessive amount of time—18 hours—

before the operator confirmed the

rupture and initiated mitigative actions.

In the incident in San Bruno, CA, the

operator effectively identified there was

a leak through LDS or SCADA systems

but took 95 minutes to isolate the gas

pipeline rupture, which caused the fire

to continue to burn unabated. The NTSB

noted that the operator, Pacific Gas &

Electric (PG&E), lacked a detailed and

comprehensive procedure for

responding to large-scale emergencies

such as a transmission pipeline break,

and that the use of ASVs or RCVs would

have reduced the amount of time taken

to stop the flow of gas.

Prior to these incidents, the NTSB

noted similar issues related to rupture

response in its report on an incident

occurring on March 23, 1994, in Edison

Township, New Jersey.

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In the Edison

incident, the operator took nearly 2

1

⁄

2

hours to stop the flow of gas. The fire

that followed the rupture destroyed 8

buildings, caused the evacuation of

approximately 1,500 apartment

residents, and caused more than $25

million worth of property damage. The

director of the operator’s Gas Control

division stated in the NTSB accident

report that the operator could typically

notify employees to close valves within

5 to 10 minutes after identifying a

rupture and that the time it took to close

a valve depended on the employee’s

travel time to the valve site. In his

experience, he found that employees

could usually arrive at a valve site

within 15 to 20 minutes, but in some

instances it took more than 1 hour for

employees to arrive at certain valves

after being dispatched. In its accident

report, the NTSB concluded that the

lack of automatic- or remote-operated

valves on the ruptured line prevented

the company from promptly stopping

the flow of gas to the failed pipeline

segment, which exacerbated damage to

nearby property. Subsequently, the

NTSB recommended to PHMSA’s

predecessor, the Research and Special

Programs Administration (RSPA), that it

expedite establishing requirements for

installing automatic- or remote-operated

mainline valves on high-pressure

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13

NTSB/PAR–11/01, PB2011–916501, Pacific Gas

and Electric Company Natural Gas Transmission

Pipeline Rupture and Fire.

14

NTSB Safety Recommendation addressed to

PHMSA; September 26, 2011; https://www.ntsb.gov/

safety/safety-recs/recletters/P-11-008-020.pdf.

15

See www.regulations.gov, dockets PHMSA–

2010–0229 and PHMSA–2011–0023, respectively,

for both the ANPRMs and NPRMs.

16

Published January 2013; www.regulations.gov

(Docket ID PHMSA–2013–0255–0002).

17

Published October 31, 2012;

www.regulations.gov (Docket ID PHMSA–2013–

0255–0004).

pipelines in urban and environmentally

sensitive areas to provide for rapid

shutdown of failed pipeline systems (P–

95–1).

As recognized by Congress and

several other stakeholders, these high-

consequence rupture events deserve

special consideration and regulatory

treatment. Accordingly, PHMSA is

proposing a combination of standards

that focus on achieving the

congressional objective of more timely

rupture detection and mitigation in

important areas while also requiring a

broader installation of rupture-

mitigating valves on newly constructed

and entirely replaced pipeline

infrastructure.

C. National Transportation Safety Board

Recommendations

On August 30, 2011, the NTSB issued

its report on the gas transmission

pipeline accident that occurred in San

Bruno, CA, on September 9, 2010.

13

In

its report, the NTSB issued safety

recommendations P–11–8 through P–

11–20 to PHMSA; safety

recommendations P–11–24 through P–

11–31 to PG&E, the operator of the

failed line; and several

recommendations to other entities,

including the Governor of the State of

California, the California Public Utilities

Commission (CPUC), the American Gas

Association (AGA), and the Interstate

Natural Gas Association of America

(INGAA). NTSB safety

recommendations P–11–9, P–11–10, and

P–11–11 recommended that PHMSA

require operators to immediately and

directly notify the appropriate public

safety answering point (9–1–1

emergency call centers) in the

communities and jurisdictions where a

pipeline rupture is indicated; equip

their SCADA systems with tools,

including leak detection systems and

appropriately spaced flow and pressure

transmitters along covered transmission

lines, to identify leaks (and ruptures);

and require automatic shut-off valves

(ASV) or remote-control valves (RCV) be

installed in HCAs and Class 3 and 4

locations with the valves spaced

considering risk analysis factors,

respectively.

14

PHMSA determined that, although the

NTSB directed these recommendations

to onshore gas transmission pipelines in

response to a natural gas transmission

accident, certain aspects of these

recommendations are also applicable to

hazardous liquid pipelines, particularly

as they relate to ruptures.

D. Advance Notices of Proposed

Rulemaking

PHMSA published two ANPRMs

seeking comments regarding the

revision of several topic areas in the

Pipeline Safety Regulations that are

applicable to the safety of hazardous

liquid pipelines (October 18, 2010; 75

FR 63774) and gas transmission

pipelines (August 25, 2011; 76 FR

53086).

15

This NPRM addresses issues

that were raised in the ANPRMs related

to rupture detection and mitigation,

including leak detection, valve spacing,

valve installation, and method of valve

actuation.

In response to the questions in the

ANPRMs, a variety of parties

representing interests from the natural

gas and hazardous liquid industries,

citizen groups, regulators, and local

governments, provided comments.

PHMSA considered these comments as

discussed in Section III of this NPRM.

Separately, PHMSA is addressing

several other topics considered in the

hazardous liquid and gas transmission

ANPRMs, specifically in NPRMs titled

‘‘Safety of Hazardous Liquid Pipelines’’

(October 13, 2015; 80 FR 61610) and

‘‘Safety of Gas Transmission and

Gathering Pipelines’’ (April 8, 2016; 81

FR 20722).

E. Pipeline Safety, Regulatory Certainty,

and Job Creation Act of 2011 and

Related Studies

Public Law 112–9, known as the

‘‘Pipeline Safety, Regulatory Certainty,

and Job Creation Act of 2011’’ (2011

Pipeline Safety Act), was enacted on

January 3, 2012. Several of the 2011

Pipeline Safety Act’s statutory

requirements relate directly to the topics

addressed in the ANPRMs, which have

an impact on this proposed rulemaking.

This NPRM is, in part, a response to the

mandates of section 4 and section 8 of

the 2011 Pipeline Safety Act.

i. Section 4—Automatic and Remote-

Controlled Shut-Off Valves

Section 4 of the 2011 Pipeline Safety

Act directs the Secretary of

Transportation (Secretary), if

appropriate, to require by regulation the

use of ASVs or RCVs, or equivalent

technology, where it is economically,

technically, and operationally feasible,

on hazardous liquid and natural gas

transmission pipeline facilities that are

constructed or entirely replaced after

the date on which the Secretary issues

the final rule containing such

requirements. PHMSA is proposing to

address this mandate by establishing the

minimum standards described in this

NPRM. These standards were also

developed in consideration of NTSB

Recommendations P–11–10 and P–11–

11, the GAO Report GAO–13–168,

‘‘Better Data and Guidance Needed to

Improve Pipeline Operator Incident

Response,’’

16

and ORNL Report/TM–

2012/411, ‘‘Studies for the

Requirements of Automatic and

Remotely Controlled Shutoff Valves on

Hazardous Liquids and Natural Gas

Pipelines With Respect to Public and

Environmental Safety,’’ which was

performed in response to the 2011

Pipeline Safety Act.

17

a. GAO Report GAO–13–168

Section 4 of the 2011 Pipeline Safety

Act also required the development of a

study by the Comptroller General on the

ability of pipeline operators to respond

to a hazardous liquid or gas release from

a pipeline segment located in an HCA.

This study was published by the GAO

in January 2013 and recommended

PHMSA take the following two actions:

1. Improve the reliability of incident

response data to improve operators’

incident response times, and use this

data to evaluate whether to implement

a performance-based framework for

incident response times, and

2. Assist operators in determining

whether to install automated valves by

using PHMSA’s existing information

sharing mechanisms to alert all pipeline

operators of inspection and enforcement

guidance that provides additional

information on how to interpret

regulations on automated valves, and

share approaches used by operators for

making decisions on whether to install

automated valves.

The GAO report noted that defined

performance-based goals, established

with reliable data and sound agency

assessments, could result in improved

operator response to incidents, with

ASV and RCV installation and use being

one of the determining factors. The GAO

further noted that, although the current

PHMSA regulations for incident

response and the installation and use of

ASVs and RCVs are performance-based,

they are very general, currently

requiring operators to respond to

incidents in a ‘‘prompt and effective

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For natural gas and hazardous liquid pipelines,

§§192.615(a)(3) and 195.402(e)(2), respectively.

19

Requirements for ASV and RCV installation are

at §192.935(c), and requirements for EFRD

installation are at §195.452(i)(4).

20

A break in the pipeline that involves the

opening of the pipe in either the circumferential or

longitudinal direction.

manner,’’

18

and requiring operators to

install ASVs, RCVs, or emergency flow

restricting devices (EFRD) if an operator

determines, through risk analysis, such

valves are necessary to protect HCAs.

19

More clearly defined goals can help

operators identify actions that could

improve their ability to respond to

certain types of incidents consistently

and promptly, though identical incident

response actions are not appropriate for

all circumstances due to pipelines

having variable locations, equipment

needs, configurations, and operating

conditions. PHMSA agrees with the

GAO’s conclusions that a more specific

standard, in conjunction with carefully

selected requirements, could be more

effective in improving incident response

times, particularly when ruptures are

involved.

The GAO report also concluded that

the primary advantage of installing and

using automated valves is that operators

can respond more quickly to isolate the

affected pipeline segment and reduce

the amount of commodity released.

Although the report suggested that using

automated valves can have certain

disadvantages, including the potential

for accidental closures, which makes it

appropriate for operators to decide

whether to install automated valves on

a case-by-case basis, the report

recognized that a faster incident

response time could reduce the amount

of property damage from secondary fires

(after an initial pipeline rupture) by

allowing fire departments to extinguish

the fires sooner. In addition, for

hazardous liquid pipelines, a faster

incident response time could result in

lower costs for environmental

remediation efforts and less commodity

loss.

PHMSA applied these principles and

the GAO’s findings and

recommendations in developing the

standards proposed in this NPRM. The

proposed amendments in this NPRM

would also include new, specific, post-

accident review requirements in

§§ 192.617(a) and 195.402(c)(5)(i) and

(ii). Operators would make those post-

accident reviews available for PHMSA

to inspect, and PHMSA could use those

reviews in disseminating lessons

learned to other operators and to better

inform future rulemakings. The GAO

report may be reviewed at http://

www.regulations.gov by searching for

Docket No. PHMSA–2013–0023.

b. ORNL Report ORNL/TM–2012/411

In March 2012, PHMSA requested

assistance from ORNL to perform a

study to address the issues outlined in

Section 4 of the 2011 Pipeline Safety

Act and those raised by the NTSB in its

accident report for the September 9,

2010, San Bruno natural gas pipeline

incident. The ORNL study assessed the

effectiveness of valve-closure swiftness

in mitigating the consequences of

natural gas and hazardous liquid

pipeline releases on public and

environmental safety. It also evaluated

the technical, operational, and

economic feasibility and potential

benefits of installing ASVs and RCVs in

newly constructed and fully replaced

pipelines. The study concluded that:

1. In general, installing ASVs and

RCVs on newly constructed and fully

replaced natural gas transmission and

hazardous liquid pipelines is

technically feasible, provided sufficient

space is available for the valve body,

actuators, power source, sensors and

related electronic equipment, and

personnel required to install and

maintain the valve; and is operationally

feasible, provided the communication

links between the RCV site and the

control room are continuous and

reliable.

2. There is evidence that it is

economically feasible to install ASVs

and RCVs on newly constructed and

fully replaced natural gas transmission

and hazardous liquid pipelines and the

benefits would exceed the costs for the

release scenarios considered in the

study. However, it is necessary to

consider site-specific variables in

determining whether installing ASVs or

RCVs on newly constructed or fully

replaced pipelines is economically

feasible in a particular situation.

3. Installing ASVs and RCVs on newly

constructed and fully replaced natural

gas and hazardous liquid pipelines can

be an effective strategy for mitigating

potential fire consequences resulting

from a release and subsequent ignition.

Adding automatic closure capability to

valves on newly constructed or fully

replaced hazardous liquid pipelines can

also be an effective strategy for

mitigating potential socioeconomic and

environmental damage resulting from a

release that does not ignite.

4. For hazardous liquid pipelines,

installing ASVs and RCVs can be an

effective strategy for mitigating potential

fire damage resulting from a pipe

opening-type breaks

20

and subsequent

ignition, provided the leak is detected

and the appropriate ASVs and RCVs

close completely so that the damaged

pipeline segment is isolated within 15

minutes after the break.

PHMSA used the conclusions of the

ORNL Report in developing this NPRM

and as a basis for proposing to

implement standards for valve

installation per Section 4 of the 2011

Pipeline Safety Act. The report may be

reviewed at http://www.regulations.gov

by searching for Docket No. PHMSA–

2013–0255–0004.

ii. Section 8—Leak Detection

Section 8 of the 2011 Pipeline Safety

Act required the Secretary to submit to

Congress a report on leak detection

systems (LDS) utilized by operators of

hazardous liquid pipeline facilities,

including transportation-related flow

lines, and to establish technically,

operationally, and economically feasible

standards for the capability of leak

detection systems to detect leaks.

PHMSA responded to the 2011

Pipeline Safety Act’s Section 8 mandate

by contracting with Kiefner and

Associates, Inc. to prepare a leak

detection study. The Kiefner study

examined LDS used by operators of

hazardous liquid and natural gas

transmission pipelines and included an

analysis of the technical limitations of

current LDS, the ability of the systems

to detect ruptures and small leaks that

are ongoing or intermittent, and what

can be done to foster development of

better technologies. It also reviewed the

practicality of establishing technically,

operationally, and economically feasible

standards for LDS capabilities. The

study addressed five tasks defined by

PHMSA:

•Assess past incidents to determine

if additional LDS may have helped to

reduce the consequences of the

incident;

•Review installed and currently

available LDS technologies, along with

their benefits, drawbacks, and their

retrofit applicability to existing

pipelines;

•Study current LDS operational

practices used by the pipeline industry;

•Perform a cost-benefit analysis of

deploying LDS on existing and new

pipelines; and

•Study existing LDS standards to

determine what gaps exist and if

additional standards are needed to cover

LDS over a larger range of pipeline

categories.

The authors of the Kiefner study were

tasked only to report data and technical

and cost aspects of LDS. Although the

Kiefner study did not provide any

specific conclusions or

recommendations related to leak

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Pipeline Safety: Safety of Hazardous Liquid

Pipelines; 80 FR 61609; October 13, 2015.

22

Improving Leak Detection System Design

Redundancy and Accuracy, DTPH56–14–H–00007

(End: April 2017); Emissions Quantification

Verification Process, DTPH5615T00012L (End:

December 2017); Framework for Verifying and

Validating the Performance and Viability of

External Leak Detection Systems for Liquid and

Natural Gas Pipelines, DTPH5615T00004L (End:

March 2018)

23

https://primis.phmsa.dot.gov/meetings/

MtgHome.mtg?mtg=77. For details on the meeting,

please see the summary report at https://

primis.phmsa.dot.gov/rd/mtgs/071812/2012_RD_

ForumSummaryReport.pdf.

24

In the Matter of Viking Gas Transmission, Final

Order, C.P.F. No. 32102 (May 1, 1998).

detection system standards, its content

did inform this NRPM, acknowledging

that pressure/flow monitoring (leak

detection techniques) will consistently

and reliably catch large volume,

uncontrolled release events such as

ruptures. Therefore, PHMSA has

proposed that valves designated as

rupture-mitigation valves for this

rulemaking be outfitted with equipment

or other means to monitor valve status,

commodity pressures, and flow rates.

Also, the report noted that operator

procedures may have allowed ignoring

alarms, restarting pumps, or opening

valves during large releases.

The standard PHMSA is proposing in

this rulemaking intends to reduce the

frequency of these errors by requiring an

operator to determine a rupture is

occurring within 10 minutes following

the first notification to the operator or

following specific criteria involving

throughput. PHMSA is considering

alternate timeframes for rupture

confirmation for this rulemaking.

PHMSA notes that a 10-minute

confirmation standard would be

consistent with certain industry

practices. For example, in its report

following the incident near Marshall,

MI, the NTSB noted that the operator

had procedures in its operations manual

that restricted the operation of a

pipeline for longer than 10 minutes

when the pipeline was operating under

unknown circumstances. This

procedure was adopted following a 1991

rupture and release by the same

operator. PHMSA welcomes comments

from stakeholders on the feasibility,

reasonableness, and adequacy of the

proposed 10-minute rupture

confirmation standard.

The proposed accident review

following these ruptures can also help

drive operators to implement lessons

learned system-wide and assist PHMSA

in providing industry-wide guidance

regarding overarching performance

issues. The report may be reviewed at

http://www.regulations.gov by searching

for Docket No. PHMSA–2013–0018.

PHMSA is not proposing specific

metrics to address smaller, non-rupture-

type leaks in this rulemaking. PHMSA

is also not proposing to require leak

detection equipment on gas

transmission and distribution pipelines

as expansively as recommended by

NTSB recommendation P–11–10, which

recommended that all operators of

natural gas transmission and

distribution pipelines equip their

supervisory control and data acquisition

systems with tools to assist in

recognizing and pinpointing the

location of leaks, including line breaks.

Pursuant to the findings in the Kiefner

Leak Detection study, it is typically

more challenging to detect smaller leaks

in an operationally, technically, and

economically feasible manner. Further,

the report notes that LDS with the same

technology, when applied to two

different operating pipeline systems,

can have very different results. In short,

one size does not fit all, and

determining a reasonable, minimum

Federal standard for safety comes with

several challenges. However, this

NPRM, for both onshore hazardous

liquid and gas transmission pipelines,

would require the installation of

pressure monitoring equipment at all

rupture mitigation valves on both the

upstream and downstream locations of

the valve. This requirement incorporates

an aspect of NTSB Recommendation P–

11–10 that will help operators to better

detect ruptures, which should drive

further development and installation of

leak detection technology, and may help

drive operators to make decisions to

improve the capabilities of their current

leak detection systems to detect non-

rupture type events. PHMSA continues

to address the effectiveness of LDS for

other non-rupture type leaks through a

rulemaking,

21

engagement in new or

updated standards being developed by

standard developing organizations, and

through the development of research

and development projects.

22

F. PHMSA 2012 R&D Forum, ‘‘Leak

Detection and Mitigation’’

PHMSA sponsored a workshop on

leak detection and expanded EFRD use,

in Rockville, MD, on March 27–28,

2012. Additionally, a Government and

Industry Pipeline Research and

Development (R&D) Forum was held in

Arlington, VA, on July 18–19, 2012.

23

PHMSA periodically holds 2-day R&D

forums to generate a national research

agenda that fosters solutions for the

many challenges facing pipeline safety

and environmental protection. The R&D

forum allowed public, government, and

industry pipeline stakeholders to

develop a consensus on the technical

gaps and challenges for future research.

It also enabled stakeholders to discuss

ways to reduce duplication of programs,

consider ongoing research efforts, and

leverage resources to achieve common

objectives. Participants discussed the

development of leak detection

technology for all pipeline types (from

any deployment platform) and the

capabilities and limitations of current

leak-detection technologies. A working

group convened for the meeting for the

topic of leak detection identified four

gaps for future research, which were: (1)

To reduce false alarms of leak detection

systems; (2) leak detection technology,

standards, and knowledge for new and

existing systems; (3) smart system

development; and (4) mobile-based leak

detection system testing.

III. Proposed Rupture Identification

and Mitigation Actions and Analysis of

ANPRM Comments

In response to the congressional

mandates contained in the 2011

Pipeline Safety Act, recommendations

from the NTSB and GAO, comments

received to both ANPRMs, discussions

at PHMSA’s public workshops, and the

results of the studies and analyses

described above, PHMSA is proposing

standards for valve installation, rupture

recognition and timely mitigation, and

valve shut-off and location requirements

for segment isolation. These actions are

intended to minimize consequences

from ruptured pipeline segments and

improve the effectiveness of emergency

response.

The proposed valve installation

requirement applies to all newly

constructed and entirely replaced gas

transmission and hazardous liquid

pipelines with nominal diameters of 6

inches or greater. For the purposes of

this rulemaking, PHMSA proposes to

define ‘‘entirely replaced’’ pipelines as

those pipelines where 2 or more

contiguous miles are being replaced

with new pipe. Operators of these lines

would be required to install automatic

shutoff valves, remote-control valves, or

equivalent technology at the valve

spacing intervals or locations already

specified in the current regulations. In

the case of ‘‘entirely replaced’’

pipelines, valves that are directly

associated with or are otherwise

impacted by the replacement project

would need to be upgraded to automatic

shutoff, remote control, or equivalent

valve technology. In the May 1, 1998,

final order to Viking Gas

Transmission,

24

PHMSA notes that

§ 192.13(b) states ‘‘no person may

operate a segment of pipeline [. . .] that

is replaced, relocated, or otherwise

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changed [. . .], unless the replacement,

relocation, or change has been made

according to the requirements in [part

192].’’ In that final order, PHMSA stated

it expected the operator to ensure that

any future pipeline replacements

comply with the valve spacing

requirements at § 192.179. Therefore,

even if a replaced segment does not

have a valve, operators would need to

ensure that the replaced segment meets

the spacing requirements at § 192.179

and would need to ensure, per this

rulemaking, that any valves installed for

compliance also meet the standard of

being automatic shut-off, remote-

control, or equivalent technology. In the

case of hazardous liquid pipelines,

maximum valve spacing mileages are

not specified under the current

regulations, and PHMSA has proposed

valve spacing for those pipelines

constructed following the issuance of

the final rule. The valves installed per

the NPRM’s provisions for both gas

transmission and hazardous liquid

pipelines would also be subject to the

40-minute rupture-mitigation closure

requirement and the monitoring

requirements of the rulemaking.

These proposed rupture identification

and mitigation regulations include: (1)

Defining the term ‘‘rupture’’ as a

significant breach of a pipeline that

results in a large-volume, uncontrolled

release of commodity that can be

determined according to specific criteria

or that has been observed and reported

to the operator; (2) a requirement to

establish procedures specifically for

responding to a rupture based on the

definition; (3) a requirement to declare

a rupture as soon as practicable but no

longer than 10 minutes after initial

notification or indication; (4) a

requirement to immediately and directly

notify the appropriate public safety

answering point (9–1–1 emergency call

centers) for the jurisdiction in which the

rupture is located; and 5) a requirement

to respond to a rupture as soon as

practicable by closing rupture-

mitigation valves, with complete valve

shut-off and segment isolation within 40

minutes after rupture identification.

Rupture identification occurs when a

rupture is reported to, or observed by,

pipeline operating personnel or a

controller.

The term ‘‘rupture-mitigation valve,’’

as it pertains to this proposal, means the

specific valve(s) that the operator would

use to isolate a pipeline segment that

experiences a rupture—the applicable

‘‘shut-off segment’’ as specified in this

NPRM. These valves can be any

combination of ASVs, RCVs, or

equivalent technology upon review by

PHMSA, and they would be required to

comply with the proposed new rupture

mitigation timing, testing,

communication, maintenance, and

inspection requirements of this NPRM.

PHMSA is also proposing operators

periodically verify, through drills, that

their rupture-mitigation valves can

reliably meet the standard outlined

above and that any communications

equipment necessary for valve actuation

functions as needed. Additionally,

operators would be required to perform

post-accident reviews of any ruptures or

other release events involving the

closure of rupture-mitigation valves to

ensure these proposed performance

objectives are met and that any lessons

learned can be applied system-wide.

Regarding the proposal for

immediately and directly notifying the

appropriate public safety answering

point (PSAP) for the jurisdiction in

which the rupture is located, per

PHMSA’s Advisory Bulletin published

on October 11, 2012 (77 FR 61826),

PHMSA believes that immediate

communication should be established

between pipeline facility operators and

PSAP staff when there is any indication

of a pipeline rupture or other emergency

condition that may have a potential

adverse impact on public safety or the

environment. PHMSA recommends that

pipeline facility operators ask their

applicable PSAP(s) if there are any other

reported indicators of possible pipeline

emergencies such as odors, unexplained

noises, product releases, explosions,

fires, etc., as these reports may not have

been linked to a possible pipeline

incident by the callers contacting the

9–1–1 emergency call center. This early

coordination will facilitate the timely

and effective implementation of the

pipeline facility operator’s emergency

response plan and coordinated response

with local public safety officials.

PHMSA is not proposing specific

metrics to address smaller, non-rupture-

type leaks in this NPRM. PHMSA is also

not proposing to require leak detection

equipment on gas transmission and

distribution pipelines as specifically

recommended by NTSB

recommendation P–11–10. Pursuant to

the findings in the Kiefner Leak

Detection study, it is typically more

challenging to detect smaller leaks on

pipelines in an operationally,

technically, and economically feasible

manner. However, this NPRM, for both

hazardous liquid and gas transmission

pipelines, requires the installation of

pressure monitoring equipment at all

rupture mitigation valves on both the

upstream and downstream locations of

the valve, which will help operators to

better detect ruptures and which can be

used for leak detection when leak

detection technology becomes further

developed. PHMSA continues to

address the effectiveness of leak

detection systems for other non-rupture

type leaks through other rulemakings,

R&D projects, and engagement in new or

updated standards being developed by

standard developing organizations.

The rupture-mitigation provisions of

this NPRM, and the related comments to

the major topic areas of this NPRM, are

discussed below:

A. Definition of Rupture

Section 4 of the 2011 Pipeline Safety

Act requires PHMSA to, if appropriate,

issue regulations requiring the use of

ASVs or RCVs, or equivalent

technology, where economically,

technically, and operationally feasible,

on newly constructed or entirely

replaced transmission pipeline

facilities. PHMSA notes, though, that

there may be little benefit to the

installation of these valves if there is not

a threshold requiring their use to

mitigate the consequence of large

releases.

While some individual operators have

installed ASVs and RCVs in response to

recent high-profile incidents, and

existing regulations require operators to

consider these types of valves as

additional mitigative measures in HCAs,

the continued occurrence of incidents

with unnecessarily slow response times

suggests that operators may not be fully

accounting for the social costs of

unmitigated large-scale release events in

their risk analysis, emergency planning,

and valve automation decisions.

PHMSA is proposing a new definition

for the term ‘‘rupture’’ for both natural

gas and hazardous liquid pipelines in

parts 192 and 195, respectively, that

operators must properly identify and

subsequently take mitigative action

against as proposed in this NPRM.

The term ‘‘rupture,’’ as defined and

applied in these proposed regulations, is

meant to encompass any type of large-

volume, rapidly occurring, and

uncontrolled release or failure event.

Ruptures would include events that

have rupture-like characteristics in

terms of pressure and flow profiles,

including but not limited to failures due

to mechanical punctures, line breaks

and other large-scale failures, seam

splits, large through-wall cracks,

sheared lines due to natural or other

outside force damage, and valves

inadvertently left open.

A rupture, as defined in this NPRM,

would include any of the following

events that involve an uncontrolled

release of a large volume of product over

a short period of time: An unanticipated

or unplanned pressure loss of 10

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Oak Ridge National Laboratory; ‘‘Studies for

the Requirements of Automatic and Remotely

Controlled Shutoff Valves on Hazardous Liquids

and Natural Gas Pipelines with Respect to Public

and Environmental Safety;’’ ORNL/TM–2012/411;

October 31, 2012; Section 5, pgs. 175–186.

26

Carey and Rogers. 2011. PG&E officials grilled

about automatic shut off valves. Silicon Valley

MercuryNews.com, http://www.mercurynews.com/

san-bruno-fire/ci_17510209?nclick_check=1, posted

3/1/11.

27

California Public Utilities Commission. 2012.

‘‘CPUC Approves Pipeline Safety Plan for PG&E;

Increases Whistleblower Protections.’’ http://

docs.cpuc.ca.gov/PublishedDocs/Published/G000/

M040/K531/40531580.PDF

28

Carey and Rogers. 2011. PG&E officials grilled

about automatic shut off valves. Silicon Valley

MercuryNews.com, http://www.mercurynews.com/

san-bruno-fire/ci_17510209?nclick_check=1, posted

3/1/11.

29

NTSB Accident Report; NTSB/PAR–11/01;

PG&E Natural Gas Transmission Rupture and Fire;

San Bruno, California; September 9, 2010; Pgs. 56–

57.

30

M. Stephens, ‘‘A Model for Sizing High

Consequence Areas Associated with Natural Gas

Pipelines,’’ GRI–00/0189, Gas Research Institute,

October 2000; and C.R. Sparks, ‘‘Remote and

Automatic Main Line Valve Technology

Assessment,’’ Gas Research Institute, July 1995.

31

Remotely Controlled Valves on Interstate

Natural Gas Pipelines (Feasibility Determination

Mandated by the Accountable Pipeline Safety and

percent or more, occurring within a time

interval of 15 minutes or less (with

certain specific exceptions relevant to

gas and liquid pipelines); an

unexplained flow-rate change, pressure

change, instrumentation indication, or

equipment function; and an apparent

large-volume, uncontrolled release of

gas or a failure observed by operator

personnel, the public, or public

authorities. The term ‘‘rupture’’ as

defined in this NPRM is only applicable

as it would pertain to the proposed

regulations in parts 192 and 195 and

should not be confused with the term

‘‘rupture’’ as it is utilized in other

PHMSA applications, such as in

incident and accident reporting forms

and other general PHMSA documents

and records. For the purposes of those

other applications, operators should

consult the instructions for those forms

to find the definition of ‘‘rupture,’’ as it

will be distinct from the term’s

proposed use in parts 192 or 195 per

this rulemaking. PHMSA welcomes

comment on this proposed definition of

rupture and the usages of the term as

they are proposed.

Although there are key differences in

the behavior of gas pipeline ruptures

and hazardous liquid pipeline ruptures,

prompt identification, rapid system

shutdown, and segment isolation are

objectives common to both. Both types

of ruptures have increased risks of

adverse consequences as the time

lengthens for both system shutdown and

segment isolation. In the case of

hazardous liquid pipelines, the volume

of product released increases and

spreads further over the surrounding

terrain or in water as response and

isolation times are prolonged, which

significantly increases the potential for

adverse consequences. As it can take an

area affected by a hazardous liquid spill

months or even years to be restored to

a pre-accident state, limiting the amount

of product released and the size of the

affected area are of great importance.

For gas pipelines, a rupture results in

a sudden release of energy that is

sustained for longer periods of time

even after the system is shut down, as

the pressurized gas expands into the

atmosphere and remains in relative

proximity to the failure site in most

cases. When gas ruptures ignite, the

length of time that the gas pipeline is

not shut down and isolated leads to

consequences, such as fires, that may

otherwise be containable but spread

outward and cause significant

additional damage beyond the

immediate impact zone.

In both cases, the quick isolation of a

ruptured segment does not significantly

alter the immediate impact of the

rupture even though the extended

consequences can be significantly

reduced.

25

Therefore, this rulemaking is

expected to drive improvement in

rupture response and isolation times to

reduce a rupture’s extended

consequences.

The rupture-mitigation requirements

of any final rule that are based on the

new rupture definition would take effect

12 months after the rulemaking becomes

effective, and the definition itself would

be incorporated with the other

definitions for parts 192 and 195 in

§ 192.3 for onshore gas transmission

pipelines and in § 195.2 for onshore

hazardous liquid pipelines,

respectively.

B. Accident Response and Mitigation

Measures

i. Installing RCVs and ASVs

Several operators and industry trade

groups, including INGAA, AGA,

American Public Gas Association

(APGA), Atmos, MidAmerican,

Dominion East Ohio, and TransCanada,

noted in the ANPRM that installing

RCVs and ASVs will not prevent

incidents and that existing requirements

allow for safe and reliable service.

Chevron commented that operators

should have the flexibility to select the

most effective measures based on

specific locations, risks, and conditions

of the pipeline segment. PHMSA notes

that, following the San Bruno incident,

PG&E rapidly installed ASVs where

possible and stated there was sufficient

basis to deploy such valves; according

to a CPUC press release, the workplan

it approved for PG&E would install 228

automated shut-off valves from 2012–

2014.

26 27

In comparison, in 2006, PG&E

concluded that most of the damage from

a rupture would take place in the first

30 seconds before shut-off valves could

stop the flow of gas.

28

Gas transmission

operators have previously cited a Gas

Research Institute study from 1998 as

the basis for concluding that the

installation of RCVs is not cost-effective

since, in most cases, injury or death

occurs so near to the time of pipeline

rupture that RCVs may not respond

quickly enough. A PG&E internal

memorandum from 2006 (subsequently

released to the public) documenting its

consideration of installing ASVs and

RCVs on lines pointed to this study

when concluding that the use of an ASV

or RCV as a prevention and mitigation

measure in an HCA would have ‘‘little

or no effect on increasing human safety

or protecting properties,’’ and did not

recommend using either as a general

mitigation measure.

29

However, the NTSB investigation of

the San Bruno incident and research by

ORNL suggests there are real benefits to

more rapid valve closure due to faster

emergency response. As the NTSB

stated, the total heat and radiant energy

released by the burning gas was directly

proportional to the time gas flowed

freely from the ruptured pipeline.

Because the operator took 95 minutes to

stop the flow of gas and isolate the

rupture, the natural gas-fed fire

continued to ignite homes and

vegetation, contributing to the extent

and severity of property damage and

increasing the life-threatening risks to

residents and emergency responders. It

wasn’t until 95 minutes after the rupture

that firefighters could safely approach

the rupture site and begin containment

efforts due to the intensity of the fire.

Firefighting continued for 2 days after

the flow of gas stopped, and over 900

emergency responders were deployed.

The use of ASVs or RCVs would have

reduced the amount of time taken to

stop the flow of gas and would have

shortened the time the site was

inaccessible to emergency responders.

Additionally, studies have indicated

that a prolonged gas-fed fire leads to

increased property damage, including

two separate studies from the Gas

Research Institute,

30

as well as a 1999

study from RSPA stating that RCV use

could reduce property damage, reduce

public disruption of product supply,

reduce damage to other utilities, and

allow emergency responders faster

access to the accident site.

31

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Partnership Act of 1996); September 1999; https://

rosap.ntl.bts.gov/view/dot/16918/dot_16918_

DS1.pdf?.

32

As defined in this NPRM, rupture identification

occurs when a rupture is observed by or reported

to pipeline operating personnel or a controller.

PHMSA is proposing to implement

the section 4 mandate from the 2011

Pipeline Safety Act by requiring newly

constructed and entirely replaced

natural gas transmission and hazardous

liquid pipelines with nominal diameters

of 6 inches and greater be equipped

with remote-control valves, automatic

shutoff valves, or equivalent technology,

at distances specified under the valve

spacing requirements per the current

regulations.

For newly constructed pipelines of

certain diameters and replaced

pipelines of certain diameters and

specific lengths, this NPRM would

require rupture-mitigation valves

located on both sides of a ‘‘shut-off

segment,’’ which is defined in this

NPRM as the applicable segment of pipe

between the valves closest to the

endpoints of a high consequence area or

Class 3 or 4 location. For hazardous

liquid pipelines, any mainline valve

located within a shut-off segment would

be a rupture-mitigation valve. For gas

transmission pipelines, maximum valve

spacing for shut-off segments would

apply based on class location factors.

Comments from pipeline operators

and industry organizations point to a

wide disparity in the percentage of

sectionalizing valves that are RCVs or

ASVs. This may reflect the use of very

different decision criteria by different

operators for determining when RCVs or

ASVs should be installed. PHMSA

determined a need for clarity in the

criteria for rupture mitigation and

segment isolation to ensure that valve

configurations are capable of adequately

mitigating the potential consequences of

rupture releases, as discussed below.

ii. Standards for Rupture Identification

and Response Times

In this NPRM, PHMSA proposes

requirements for rupture response and

mitigation that would require operators

of certain pipeline segments to: (1)

Determine the existence of a rupture

within 10 minutes of initial

identification; (2) make immediate and

direct notification to the appropriate

public safety answering point (9–1–1

emergency call centers); (3) initiate

rupture-mitigation valve closure as soon

as practicable after identifying a

rupture; and 4) complete rupture-

mitigation valve shut-off (closure and

rupture segment isolation) as soon as

practicable but within a maximum time

interval of 40 minutes after rupture

identification.

32

Operators may meet

this standard using ASVs, RCVs, or

equivalent technologies upon review by

PHMSA. This NPRM also proposes that

operators conduct regular emergency

drills and inspections to confirm the

performance of operator systems,

processes, procedures, and personnel to

achieve this standard.

In the hazardous liquid ANPRM, the

American Petroleum Institute (API),

Association of Oil Pipelines (AOPL), the

Texas Oil and Gas Association

(TxOGA), Louisiana Midcontinent Oil &

Gas Association (LMOGA), and

TransCanada Keystone Pipeline

commented that there is no current

industry standard setting a maximum

spill volume or valve activation timing

due to the widespread variation in

pipeline dynamics, and it therefore

would be difficult to establish a one-

size-fits-all requirement for these items.

API and AOPL suggested PHMSA

should focus on prevention and

response rather than reducing spill size.

PHMSA agrees with the commenters

that spill prevention and response are

important to ensuring the safety of

hazardous liquid pipelines and that

establishing a one-size-fits-all maximum

spill volume would be extremely

challenging due to a variety of factors,

including different pipeline diameters,

terrain surrounding pipelines,

commodity type, operating conditions,

sensitivity of the surrounding areas, and

types and nature of flow paths.

However, based on previous incident

history, PHMSA has determined that it

is necessary to define standards to

ensure operators identify ruptures when

they occur and promptly shut off

mainline valves and isolate the ruptured

pipeline segment. As a result, PHMSA

is proposing to require operators to base

their decisions upon documented

procedures that take into account

unexplained flow rate changes, pressure

changes, instrumentation indications,

and equipment functions. Factoring this

information into the decision-making

processes, when paired with additional

pressure sensors located along the

pipeline and valves that can be closed

quickly after rupture detection, should

help mitigate the effects of pipeline

ruptures. For instance, such

requirements would have helped

mitigate the PG&E incident at San

Bruno, CA, and the Enbridge incident

near Marshall, MI, because the operators

would have been in a better position to

identify the ruptures if they were

monitoring for the required information.

The GAO report referenced in Section

II of this NPRM noted that performance-

based goals established with reliable

data and sound agency assessments

could result in improved operator

response with ASV and RCV use. The

report also states that although existing

PHMSA regulations for operator

response and ASV and RCV use are

performance-based, they are ‘‘not well-

defined.’’ Specifically, parts 192 and

195 currently require operators to

respond to incidents and accidents in a

‘‘prompt and effective manner’’

(§§ 192.615(a)(3) and 195.402(e)(2)). As

mentioned earlier, however, identical

response actions are not appropriate for

all circumstances due to the specific

and highly variable location, equipment,

and operating conditions involved on

individual pipeline systems. The GAO

noted some organizations in the

pipeline industry believe that some

form of performance-based goals can

allow operators to identify actions that

could improve their ability to respond

to accidents, including ruptures, more

consistently and in a timelier manner,

and those organizations are taking steps

to implement this approach. PHMSA

agrees that a more precise regulation

specific to ruptures would be effective

in improving operator response times

and mitigative actions because ruptures

have recognizable operational signatures

and, hence, more clearly defined

triggers and actions that operators can

take in response.

iii. Using RCVs or ASVs in All Cases

In the hazardous liquid and gas

transmission ANPRMs, PHMSA asked

stakeholders to comment on whether

the Pipeline Safety Regulations should

include a requirement mandating the

use of RCVs in all cases. The NTSB

reinforced, via a submitted comment,

that PHMSA should adopt requirements

consistent with its recommendations

P–11–10 and P–11–11. The NTSB noted

in its analysis of the San Bruno incident

that if PG&E could have shut off the gas

flow of its ruptured segment sooner than

95 minutes, it would have likely

resulted in a smaller fire of shorter

duration as well as less risk to residents,

their property, and first responders. The

ORNL report and the GAO report

referenced in this rulemaking reached

conclusions similar to the NTSB’s for

both gas transmission and hazardous

liquid pipelines. In other comments,

Metro Area Water Utility Commission

(MAWUC) indicated that PHMSA

should consider requiring all valves to

be remotely controlled but that its

decision should be based on an analysis

of benefits and risks. North Slope

Borough (NSB) supported the use of

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FERC, 2015. Southeast Market Pipelines

Project, Final EIS, Office of Energy Projects. Volume

1, Section 2.6.1. https://www.ferc.gov/industries/

gas/enviro/eis/2015/12-18-15-eis.asp

34

FERC, 2016. Rover Pipeline, Panhandle

Backhaul, and Trunkline Backhaul Projects, Final

EIS. Volume 1, Section 2.2.2. https://www.ferc.gov/

industries/gas/enviro/eis/2016/07-29-16-rover-

pipeline.asp.

RCVs in all instances. A private citizen

commented that PHMSA should issue

regulatory language requiring RCVs for

poison inhalation hazard pipelines.

Conversely, comments from industry

groups and pipeline operators stated

that the benefits of requiring all valves

to be remotely controlled would be

dependent on local factors, and such

additional requirements would add to

pipeline system complexity and

increase the probability of failure.

In consideration of the comments

received, PHMSA has determined that a

requirement for all valves to be

automatically or remotely controlled

would not be feasible due to several

technical concerns, including a lack of

space for actuator and communication

equipment in urban areas, no

communications signal in certain areas,

and the potential for vandalism. The

ORNL report came to a similar

conclusion in that it was technically

feasible to install ASVs and RCVs

provided there was sufficient space for

the valve body, actuators, power source,

sensors, related electronic equipment,

and the appropriate personnel required

to install and maintain the valves.

Further, PHMSA determined that it

would be most reasonable for newly

constructed or entirely replaced natural

gas transmission and hazardous liquid

pipelines with diameters of 6 inches or

greater to be subject to the valve

installation requirement per the Section

4 mandate in the 2011 Pipeline Safety

Act. While it is technically possible for

lines as small as 2 or 4 inches to have

automatic shutoff or remote-control

valves, the potential impact radii and

release volumes would be smaller under

those scenarios, and PHMSA would not

expect there to be benefits

commensurate with the costs of

installing the valves. However, PHMSA

would like comment on whether these

assumptions are reasonable.

Therefore, PHMSA is addressing the

mandate in the 2011 Pipeline Safety Act

by proposing a valve installation

requirement on newly constructed and

entirely replaced gas transmission and

hazardous liquid pipelines, as well as

proposing a standard for rupture

identification and mitigation in areas of

higher consequence. Alternatives

considered by PHMSA are documented

in the PRIA filed under Docket No.

PHMSA–2013–0255 at http://

www.regulations.gov.

Several commenters on the gas

transmission and hazardous liquid

ANPRMs, including industry trade

groups and pipeline operators, opposed

a requirement that all sectionalizing

valves be capable of being controlled

remotely. As some commenters pointed

out, RCVs or ASVs may not be

warranted in many situations because of

specific local conditions that could limit

the safety benefits of such a

requirement. The ORNL report also

concluded that site-specific parameters

can influence risk analyses and

feasibility evaluations, and they can

often vary significantly from one

pipeline segment to another.

Recent high-profile pipeline

construction projects show a wide use

of ASVs and RCVs, which demonstrates

the feasibility and prevalence of these

technologies. The interstate

transportation of energy products,

including natural gas, is subject to

economic regulation by the Federal

Energy Regulatory Commission (FERC).

New gas transmission pipeline

construction projects and significant

changes to existing pipelines are

therefore subject to FERC review and

environmental analysis requirements

under the National Environmental

Policy Act. Final Environmental Impact

Statements (EIS) published or approved

after the 2011 Pipeline Safety Act have

included some commitment to use

ASVs or RCVs on new or upgraded gas

transmission pipelines subject to FERC

approval. The wide use of this

technology demonstrates the feasibility

and prevalence of the use of powered

actuators or otherwise remote-controlled

valves.

For instance, the Southeast Market

Pipelines Project

33

intended to equip all

63 mainline block valves with ASVs or

RCVs within three connected natural

gas transmission pipeline projects in

Florida, Alabama, and Georgia.

Similarly, per the Rover Pipeline final

EIS,

34

all 78 mainline block valves for

the Rover Pipeline and related projects

would be equipped for remote operation

from the control center. The PRIA for

this NPRM contains further information

on this topic under Section 4.4—Valve

Automation.

Further, recent high-profile hazardous

liquid pipeline construction projects

also show use of RCVs. The final EIS for

TransCanada’s proposed Keystone XL

Pipeline project indicated that 71 out of

112 intermediate mainline valves along

the route would be remotely operated

block valves, while an additional 24

valves would be designated as check

valves (U.S. Department of State, 2011).

The North Dakota Public Service

Commission reported that the Dakota

Access Pipeline design includes remote

actuators on all mainline valves in the

State of North Dakota (North Dakota

Public Service Commission, 2016).

However, as stated before, PHMSA

understands there may be technical

challenges to requiring the use of

automation in certain cases.

Specifically, PHMSA is aware that there

might not be the space necessary for

operators to install equipment needed

for an ASV or an RCV, and PHMSA also

realizes that in certain areas, operators

might not be able to get the necessary

communications signal to ASVs or RCVs

so they work as intended. Therefore, a

one-size-fits-all valve-type installation

requirement may not be feasible. As

such, PHMSA is proposing a rupture-

mitigation valve standard that provides

operators flexibility to install RCVs,

ASVs, or an equivalent technology.

Alternatively, operators may use manual

valves where it is not economically,

technically, and operationally feasible

to use RCVs, ASVs, or an equivalent

technology. This flexibility will allow

operators to choose the most

appropriate valve based on the unique

circumstances at each location, while

still ensuring that such valves will close

as soon as practicable but no later than

40 minutes after a rupture is identified.

PHMSA welcomes any comments that

stakeholders might have regarding the

reasonability of the proposed 40-minute

valve closure time based on current

technologies and capabilities. When

considering an appropriate valve

closure time for this rulemaking,

PHMSA noted that many natural gas

transmission and hazardous liquid

systems can have several junctions

where product arrives and departs or

where multiple pipelines are connected

with each other in a series of looped

lines. On these more complicated

pipeline systems, operators

implementing shutoff procedures may

need to consider factors including the

potential effects on pipeline systems

flowing into a pipeline needing to be

isolated, the restriction of downstream

deliveries to vital customers, and the

impacts of the complete isolation of

looped common-use systems. Therefore,

establishing a one-size-fits-all

requirement for valve closure times on

all natural gas transmission and

hazardous liquid pipeline systems can

be challenging.

When developing the proposed valve-

closure time in this NPRM, PHMSA

considered its work on the ‘‘Alternative

MAOP’’ rulemaking and the

requirements in that rule for operators

to install RCVs and close valves within

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‘‘Pipeline Safety: Standards for Increasing the

Maximum Allowable Operating Pressure for Gas

Transmission Pipelines; Final Rule;’’ October 17,

2008; 73 FR 62148.

60 minutes on applicable pipeline

segments.

35

PHMSA also considered its

work on recent special permits and

conditions in those permits for single,

non-looped pipelines to have valves that

can close within 30 minutes. Further,

PHMSA notes that in the ANPRM stages

of the Safety of Hazardous Liquid

Pipelines and the Safety of Gas

Transmission Pipelines rulemakings,

PHMSA considered valve closure times

of 30 minutes for both natural gas

transmission and hazardous liquid

pipelines, and certain industry

commenters representing gas pipeline

operators proposed times of 60 minutes.

In this NPRM, PHMSA is proposing to

require operators to close the necessary

valves ‘‘as soon as practicable’’

following rupture identification with a

40-minute-maximum closure time

because 40 minutes represents a

reasonable outer limit to provide time,

if needed, for operators to get personnel

on-site to close any necessary valves.

However, PHMSA expects RCVs or

ASVs in most instances to be shut off in

a much shorter timeframe.

PHMSA determined the 40-minute

closure time as follows:

Locating the rupture: Once an

operator confirms a rupture is occurring,

an operator needs to determine the

location of the rupture. As a part of this

process, control personnel would

identify the location of the mainline

valves needing to be shut as well as any

crossover valves and other pipeline

systems that flow into or out of the

impacted pipeline system. Control

personnel would then identify the

systems needing to be isolated, if any,

and the locations of the valves necessary

to do so. If any of these systems are

operated by a different operator, those

operators must be notified so that

deliveries can be re-routed and so that

deliveries are not restricted to critical

customers such as hospitals or power

plants. Following the rupture being

located, control personnel would

dispatch operating personnel to the

rupture site, mainline valve locations,

and any other critical pipeline locations.

Those operating personnel would

communicate and collaborate with local

emergency responders to minimize the

impact to the public and environment

and identify safety needs. Further,

operators must notify other parties,

including local distribution companies,

operators of directly connected

pipelines, power plants, and direct-feed

manufacturing facilities to ensure that

rapid valve closures do not cause

emergency cascading events due to

increased pressures, surges, or the lack

of energy product. PHMSA has

estimated these actions will be

completed anywhere between 5 and 15

minutes of rupture identification.

Isolating the ruptured segment: An

operator will begin closing the

appropriate valves once a rupture is

identified and located. This might

include mainline valves, any crossover

valves, and valves to other pipeline

systems that flow into or out of the

ruptured pipeline system. Operating

personnel would continue to work with

emergency responders to minimize the

impact to the public and identify safety

needs. If a valve fails to close, the local

pipeline operating personnel would

close it. PHMSA notes that RCV

shutdown times will vary based on size,

whether it is a ball or gate valve, the

actuator type, and the operating

pressure at the time of closure, which

will depend on how close it is located

to the rupture site. ASV shutdown times

will vary based on the preceding factors

as well as the minimum pressure or the

rate of pressure change at the mainline

valve. All pipeline system valve

shutdown times require the

consideration of the valve closure

timing and its impact on maximum

operating pressures and surge pressures

from the speed of valve closure on the

pipeline system and any laterals or

other pipeline systems connected to the

ruptured pipeline. Under emergency

conditions and given operating

pressures, PHMSA estimates an RCV

can be closed within 5 to 15 minutes

after rupture identification and location,

an ASV can be closed within 10 to 25

minutes after rupture identification, and

a valve needing some type of manual

actuation could be closed within 15 to

25 minutes after rupture identification.

Based on this analysis, PHMSA is

proposing a maximum 40-minute valve

closure period; however, PHMSA

welcomes comments regarding whether

this timeframe could be reasonably

lowered so that segments are isolated

more quickly and ruptures are mitigated

faster, or whether there are other

reasons that would preclude an operator

from confirming a rupture and closing

an ASV, RCV, or equivalent valve

within 40 minutes after the

identification of a rupture. Similarly,

PHMSA welcomes comment on the 40-

minute closure limit as it applies to any

manual valves that operators might need

to install because installing ASVs,

RCVs, or equivalent technology is not

feasible.

PHMSA also notes that the

‘‘Alternative MAOP’’ final rule

published on October 17, 2008, which

affects gas transmission pipelines,

finalized a requirement to provide

remote valve control through a SCADA

system, other leak detection system, or

an alternative method of control. This

requirement applies if personnel

response time to mainline valves on

either side of an HCA exceeds 1 hour

(under normal driving conditions and

posted speed limits) from the time an

emergency event is identified in the

operator’s control room. PHMSA

welcomes comment on whether it

should revise the Alternative MAOP

rule’s requirements to match this

rulemaking’s proposed 40-minute

response time, or whether this

rulemaking should be made consistent

with the Alternative MAOP rule and

establish a 60-minute response time

following rupture identification.

C. Drills To Validate Valve Closure

Capability

In response to the hazardous liquid

ANPRM, Texas Pipeline Association

(TPA) and others commented that

requiring additional valve automation

could result in an increased probability

of valve or system failure. PHMSA

agrees that the addition of any type of

engineered equipment is accompanied

by a potential for mechanical or

operational failure. This rule proposes

inspection and maintenance provisions

to minimize this possibility. These

inspection and maintenance provisions

would apply to procedures and

equipment that should be in use to

isolate pipeline segments in the event of

potential incidents. More specifically,

PHMSA proposes to require that

operators conduct initial and periodic

validation drills to ensure that valves

designated for rupture mitigation will

close to ensure that the response and

shut-off times of this proposal can be

reliably and consistently achieved.

PHMSA is also proposing

demonstration and verification

requirements, including point-to-point

verification tests for RCVs, to ensure

that communications equipment works.

New provisions proposed in this NPRM

would also require that any deficiencies

be identified and corrected within a

fixed period, and that any lessons

learned during these drills be applied

system-wide to ensure adequate

performance in future emergencies.

PHMSA has proposed these

requirements because any newly

installed valve systems will require

regular maintenance activities and

emergency drills to ensure they operate

as intended per the proposals in this

rulemaking.

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The ORNL report discussed in Section

II of this NPRM documented the reliable

operation of ASVs and the importance

of operating procedures in ensuring the

reliability of RCVs. The report noted

that, in areas that are susceptible to

electrical power outages, reliability is a

potential concern, and redundant,

alternative, or backup power sources

may be required to ensure continuous

availability of electricity for motors,

solenoids, and electronic components.

Proper valve maintenance involving seat

and valve-body cleaning, packing and

gasket replacement, and valve closure

testing to ensure that ASVs actuate on

command and close completely, are

issues that influence operational

feasibility. As PHMSA notes throughout

this NPRM, rupture-mitigation valves

must function properly when needed

following an identified rupture to

quickly mitigate the consequences of

pipeline ruptures, including property

and environmental damage. The drill

requirements are proposed in § 192.745

for onshore gas transmission pipelines

and § 195.420 for onshore hazardous

liquid pipelines.

D. Maximum Valve Spacing Distance

i. Gas Transmission Pipelines

Existing regulations for gas

transmission pipelines at § 192.179

already contain provisions for

maximum valve spacing based on class

location. This NPRM proposes

supplementary requirements for

rupture-mitigation valve spacing in

newly defined ‘‘shut-off segments’’ on

newly constructed or replaced onshore

gas transmission pipelines.

These ‘‘shut-off segments’’ are

segments of pipe between the upstream

mainline valves closest to the upstream

endpoints of the HCAs or Class 3 or 4

locations and the downstream mainline

valves closest to the downstream

endpoints of the HCAs or Class 3 or 4

locations so that the entirety of the

applicable HCA or Class 3 or 4 location

is contained between a set of rupture-

mitigation valves. A shut-off segment

can contain multiple HCAs or Class 3 or

4 locations—an operator of such a

segment would need to ensure that the

entirety of the contiguous class

locations and HCAs are within a set of

rupture-mitigation valves. Shut-off

segments also extend to the nearest

mainline valves of any crossover and

lateral pipe that connects to the shut-off

segment between the furthest upstream

and downstream mainline valves. All

valves on shut-off segments would be

identified as ‘‘rupture-mitigation

valves’’ for the purposes of this

rulemaking and its proposed provisions

so that, when closed, there is no flow

path for gas to be transported to the

rupture site (except for any residual gas

already in the ruptured shut-off

segment).

In this NPRM, PHMSA proposes that

the distance between rupture-mitigation

valves for each shut-off segment must

not exceed 8 miles for shut-off segments

containing a Class 4 location (with or

without an HCA), 15 miles for a shut-

off segment containing a Class 3

location (with or without an HCA), and

20 miles for a shut-off segment

containing HCAs in Class 1 or 2

locations. These proposed rupture-

mitigation valve spacing requirements

for shut-off segments are in accordance

with §§ 192.179 and 192.611 for

pipeline class location segments that

have had a one-class class location

change (a Class 1 to a Class 2, a Class

2 to a Class 3, or a Class 3 to a Class

4 change) and meet the criteria under

§ 192.611(a) for a ‘‘one class change

bump.’’ This allows operators to use the

valve spacing required in § 192.179 for

the previous class location when

creating shut-off segments where the

class location has recently changed.

Shut-off segments containing different

class locations or HCAs must have valve

spacing equivalent to the spacing, as

provided above, for the most stringent

class location in the shut-off segment.

In response to questions in the gas

transmission ANPRM related to valve

spacing, INGAA contended that while

valve spacing and selection are

important factors in incident response,

public safety requires integrated

planning and implementation for

detecting ruptures and closing valves,

which INGAA called an ‘‘Incident

Mitigation Management’’ (IMM) plan in

its comments. INGAA described IMM as

a holistic performance-based means of

detecting and responding to pipeline

failures with some similarities to the

proposals in this NPRM. INGAA

contends that IMM plans should cover

various aspects of response, including

how operators detect failures, how they

place and operate valves, how they

evacuate gas from pipeline segments,

and how they prioritize coordination

efforts with emergency responders.

Conversely, Accufacts contended that

existing spacing requirements are

inadequate and suggested that further

regulation is required concerning the

placement, selection, and choice of

RCVs, ASVs, or equivalent technology.

They stated that valve spacing and

closure play a significant role in

depressurizing a gas pipeline segment

after a rupture, thereby limiting the total

volume of gas released in an incident.

The Pipeline Safety Trust also

supported the installation of additional

valves on gas transmission pipelines to

reduce consequences following large-

scale incidents. A private citizen

suggested that valves be required at 1-

mile intervals in densely populated

urban areas and that they close

automatically in the event of an

incident.

PHMSA agrees with certain

commenters that the mere installation of

additional valves, including RCVs or

ASVs, will not reduce the frequency of

gas transmission pipeline releases. The

mere presence of a valve will not

prevent an incident from occurring.

However, PHMSA disagrees with the

same commenters who assert that

additional valves do not reduce the

consequences after such releases, as

prompt rupture identification, response,

and segment isolation through valve

shut-off are key factors in limiting and

reducing incident consequences. As

discussed throughout this NPRM,

PHMSA has determined that prompt

operator rupture identification and

mitigation, which includes the isolation

of the rupture or failed segment as soon

as practicable, are important factors that

can contribute to reduced consequences.

ii. Valve Spacing in Response to Class

Location Changes

In addition to the valve spacing

requirements listed above related to

shut-off segments, PHMSA is also

proposing that operators be required to

add valves if necessary to meet the

applicable valve spacing requirements

when changes to class location occur

that require pipe replacement. PHMSA

notes that a gas pipeline’s class location

broadly indicates the level of potential

consequences for a pipeline release.

Section 192.179 currently requires

closer valve spacing for higher class

locations. Areas of potentially higher

consequences (i.e., HCAs) can be in

lower class locations as well. HCAs in

Class 1 or Class 2 locations include

pipeline segments where a release could

have severe consequences similar to a

release in Class 3 and Class 4 areas. In

HCAs, operators are required to provide

additional protection in accordance

with the integrity management

requirements of part 192, subpart O.

There were several comments related

to new valve installations in the event

of a class location change so that those

valves meet the spacing requirements of

§ 192.179. The Gas Piping Technology

Committee (GPTC), AGA, INGAA, and

several of INGAA’s members

(MidAmerican, Paiute, and Southwest

Gas) opposed applying § 192.179

requirements retroactively to class

location changes. Commenters also

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36

In the Matter of Viking Gas Transmission, Final

Order, C.P.F. No. 32102 (May 1, 1998).

37

Valve spacing requirements are in the design

and construction sections of the regulations. If a

pipeline segment changes class location but can be

successfully pressure tested to the MAOP standards

of the next highest class location per §192.611,

PHMSA cannot retroactively impose new valve

spacing on an existing segment. However, if the

segment is replaced by virtue of a higher class

location, the more stringent valve spacing

requirements would apply.

expressed opinions that the existing

regulations are adequate. However, the

Commissioners of Wyoming County,

Pennsylvania and CPUC commented

that regulations should require

additional valves when population

increases and class locations change.

Additionally, Accufacts suggested that

new mainline valves should be installed

when a site becomes an HCA regardless

of class location, but a reasonable time

should be allowed for such valves to be

installed and become operational.

Valve spacing requirements in

§ 192.179 are based upon the class

location. When a pipeline class location

changes because of additional

development near a pipeline, this

increases both the potential

consequences of a release and the

potential benefits of closer valve spacing

for consequence mitigation. PHMSA

proposes to only require that valve

spacing be made to match the

requirements in § 192.179 for a new

class location when pipe replacement is

necessary in response to a class location

change, such as a Class 1 to Class 3, or

a Class 2 to Class 4. Note that this

requirement would be consistent with

the 1998 Final Order for Viking

Pipeline,

36

which required class

location changes to meet the mainline

valve spacing as defined in § 192.179

and the installation of a sectionalizing

valve based upon the class location in

a ‘‘replaced pipeline segment.’’ Under

this approach, when a class location

change is implemented using only a

pressure test in accordance with

§ 192.611 but without pipe replacement,

then additional valve installation would

not be required.

37

This approach will

better balance the potential benefits

from mitigating consequences of

releases because of closer valve spacing

with the costs of installing new valves,

costs that will be lower if operators

install additional valves in the context

of installing new pipe for a class

location change.

iii. Hazardous Liquid Pipelines

For onshore hazardous liquid

pipelines, existing regulations establish

valve location requirements for certain

pipeline facilities and locations, such as

at pump stations, breakout storage

tanks, lateral takeoffs, certain water

crossings, public water reservoirs, and

for other locations as appropriate, based

on terrain, location of populated areas,

and other factors. However, a maximum

distance for valve spacing for new

pipelines is not currently specified. In

response to the hazardous liquid

ANPRM, several industry groups and

individual operators noted that ASME

B31.4, a consensus industry standard

published by the American Society of

Mechanical Engineers (ASME), includes

a maximum valve spacing requirement

of 7

1

⁄

2

miles for liquefied petroleum gas

and anhydrous ammonia pipelines in

populated areas. Specifically, these

commenters stated that valve spacing

varies, that most mainline valves are

manually operated, that check valves

are used in certain cases, and that some

remotely controlled valves had been

added because of the integrity

management requirements.

PHMSA also asked for public

comment on how the agency should

apply any new valve location

requirements developed for hazardous

liquid pipelines. API and AOPL,

supported by TransCanada Keystone

Pipeline, LMOGA, and TxOGA,

indicated that valve spacing

requirements should not be changed,

and that specifying valve location

requirements retroactively would be

difficult and confusing. Further, these

commenters indicated that requiring the

retrofitting of existing lines to meet any

type of new requirement would be

expensive for industry, create

environmental impacts, lead to potential

construction accidents, and may cause

possible interruptions of service.

MAWUC and NSB commented that any

new valve locations or remote actuation

regulations should be applied to new

pipelines or existing pipelines that are

repaired.

In this NPRM, PHMSA is proposing

that newly constructed and entirely

replaced hazardous liquid pipelines

with nominal diameters of 6 inches or

greater have automatic shutoff valves,

remote-control valves, or equivalent

technology spaced in accordance with

the existing hazardous liquid valve

location provisions and the valve

spacing requirements proposed in this

rulemaking, as there are no current

valve spacing requirements in the

regulations for hazardous liquid

pipelines.

For newly constructed onshore

hazardous liquid pipelines that could

affect HCAs or for hazardous liquid

pipelines in areas that could affect

HCAs and where 2 or more contiguous

miles have been replaced, PHMSA is

proposing a maximum valve spacing of

every 15 miles. PHMSA based this

spacing mileage, in part, off of Class 2

requirements for natural gas pipelines.

Additionally, PHMSA believes that,

given the current guidelines operators

must consider regarding local terrain

and drain-down volumes, a maximum

spacing of 15 miles for valves in HCAs

would be reasonable.

For newly constructed onshore highly

volatile liquid (HVL) pipelines in high

population areas or other populated

areas, as those terms are defined in

§ 195.450, or for HVL pipelines in those

areas where 2 or more contiguous miles

have been replaced, PHMSA is

proposing a maximum valve spacing of

every 7

1

⁄

2

miles. PHMSA notes that the

current ASME B31.4 code provides for

a 7

1

⁄

2

mile maximum valve spacing

requirement on piping systems

transporting liquefied petroleum gas or

liquid anhydrous ammonia in

industrial, commercial, and residential

areas.

In an attempt to be more consistent

with similar aspects of the natural gas

pipeline regulations and taking into

account the valve spacing requirements

for Class 1 locations, PHMSA is

proposing a 20-mile maximum valve

spacing requirement for newly

constructed and replaced hazardous

liquid pipelines that could not affect

HCAs.

Part 195 currently does not prescribe

whether manual or remote control

valves must be installed at particular

locations, but it does require the

consideration of check valves and

remote control valves under the EFRD

requirements for pipelines that could

affect an HCA. Section 4 of the Act

includes a new mandate for PHMSA to

evaluate and issue additional

regulations for the use of valves (such as

remote control, automatic shut-off, or

equivalent technology) for rupture

mitigation. The current proposal seeks

to establish a reasonable maximum

distance that would apply to any type

of terrain and in any area, regardless of

population or environmental sensitivity.

PHMSA expects that operators, in their

pursuit of compliance with other valve

location requirements, will locate,

install, and equip valves for remote or

automatic operation as needed and in

accordance with the requirements of the

integrity management regulations

(§ 195.452(i)(4), including Appendix C).

This will result in valve location

profiles that meet their operational

needs and are reflective of the risks and

potential consequences unique to their

individual pipelines, including the

consideration of factors such as

maximum spill volumes, terrain, and

population and environmental

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Method 1 is defined in §192.903 HCA

definition, paragraph (1) as a Class 3 or Class 4

location as those terms are defined under §192.5;

or any area within a Class 1 or Class 2 location

where the potential impact radius is greater than

660 feet, and the area within a potential impact

circle contains 20 or more buildings intended for

human occupancy; or any area in a Class 1 or Class

2 location where the potential impact circle

contains an identified site. Definitions for

‘‘potential impact radius,’’ ‘‘potential impact

circle,’’ and ‘‘identified site’’ are at §192.903.

receptors. The maximum spacing

requirements would not supplant or

supersede any other valve location

requirement and would only apply to

newly constructed and replaced

pipelines of certain diameters. These

proposed requirements address Section

4 of the 2011 Act and are consistent

with PHMSA’s efforts to address NTSB

Recommendation P–11–11 for gas

transmission pipelines as well.

For newly constructed and replaced

segments that could affect an HCA or

that are within an HCA, valves would be

required at a minimum of every 15

miles. For new and replaced segments

transporting highly volatile liquids

(HVL) in HCAs established due to

populated areas, the maximum distance

between valves would be 7

1

⁄

2

miles.

This requirement mirrors the

requirements that currently exist under

ASME B31.4 for HVL mainline valve

spacing and is necessary due to the

unique safety risks these pipelines pose

to populated areas. In addition, valves

located on each side of a water crossing

greater than or equal to 100 feet (30

meters) wide would be required to be

installed outside the flood plain. The

requirements of this proposed rule,

specifically applying to segments of new

or replaced pipelines that could

potentially impact HCAs, would result

in the placement of valves on each side

of these HCA segments. This

requirement acknowledges the sensitive

nature of these specifically defined

areas and requires their protection with

mainline valves comparable to other

sensitive locations.

The new requirements for valve

spacing are proposed in §§ 192.179,

192.610 and 192.634 for gas

transmission pipelines and §§ 195.260

and 195.418 for hazardous liquid

pipelines.

E. Integrity Management and the

Protection of HCAs

This NPRM would also strengthen

integrity management requirements for

both onshore gas transmission and

hazardous liquid pipelines by

addressing the use of ASVs or RCVs

(including EFRDs) in HCAs as they

apply to rupture mitigation. These

existing requirements are at § 192.935(c)

for gas transmission pipelines and

§ 195.452(i)(4) for hazardous liquid

pipelines, and they specify that

operators must conduct a risk analysis

and add additional ASVs, RCVs, and

EFRDs, as needed, to provide additional

protections for HCAs. As gas

transmission pipeline segments in HCAs

are, by definition, near higher-

population areas and developments and

include areas where people assemble or

have difficult-to-evacuate facilities such

as schools or hospitals, releases from

these segments have a higher potential

for adverse consequences than releases

from other segments.

i. Gas Transmission Pipelines

In the gas transmission ANPRM,

commenters addressed PHMSA’s

consideration of additional decision

criteria for operator evaluation of

additional valves, remote closure, and

valve automation. INGAA, AGA, GPTC,

Ameren, and MidAmerican were not in

support of additional decision criteria,

whereas Accufacts, CPUC, and an

anonymous commenter were in support

of additional decision criteria. Accufacts

argued that valve regulations should be

required for larger-diameter gas

transmission pipelines in HCAs,

especially in areas where manual

closure times could be long. CPUC

expressed its conclusion that decision

criteria may need to be added for all

Method 1 HCA locations.

38

PHMSA notes that although § 192.935

currently requires operators to consider

installing additional RCVs and ASVs to

mitigate potential consequences to

HCAs, the regulation does not establish

criteria based on consequence reduction

to guide operator decisions. In

developing this rulemaking, PHMSA

has noted the challenges of requiring

certain types of valves at specific

locations. Therefore, PHMSA has

determined that the most beneficial

criteria for rupture mitigation are

standards for rupture identification and

response times paired with maximum

valve spacing requirements, because

limiting the consequences of a release is

primarily dependent upon how quickly

an operator identifies, acknowledges,

and isolates a rupture. In this NPRM,

the required time thresholds for

operator response following rupture

identification serve as the decision

criteria. Because the rupture response

and mitigation requirements of this

rulemaking will apply to newly

constructed systems and entirely

replaced pipeline systems of 2

contiguous miles or greater, operators

can design their valve configurations as

needed to address site-specific issues

while meeting the proposed rupture-

mitigation requirements. Operators can

determine what kinds of response and

communication procedures need to be

established, if arrangements need to be

made for valve access by local operating

personnel, if valves need to be equipped

for remote or automatic operation and

whether some other alternative

equivalent technology can be employed

to meet the standard.

ii. Hazardous Liquid Pipelines

The hazardous liquid integrity

management regulations issued in 2002

require operators to assess and adjust

their existing EFRD configurations to

better protect HCAs. GAO’s findings in

GAO–13–168 support PHMSA’s

experience that large discrepancies still

exist in how individual operators use

existing valves as EFRDs, due largely to

the lack of prescription in both the

regulations and industry standards

relating to EFRD installation. The lack

of rapid closure capability has been

found to have significantly exacerbated

both the volume released and the

adverse consequences in past accidents,

even when emergency situations were

quickly recognized by the operator. The

ORNL report (ORNL/TM–2012/411)

confirmed that ‘‘swiftness of valve

closure has a significant effect on

mitigating potential socioeconomic and

environmental damage to the human

and natural environments.’’ Similarly,

the GAO study also found that ‘‘quickly

isolating the pipeline segment through

automated valves can significantly

reduce subsequent damage by reducing

the amount of hazardous liquid

released.’’

PHMSA determined that there is a

need to establish additional

requirements related to EFRD actuation

for newly constructed and replaced

pipelines of 2 contiguous miles or

greater in HCAs, as pairing standards for

valve actuation with considerations for

valve placement will help to achieve

fuller safety benefits when considering

rupture mitigation. This NPRM would

also include annual inspection and

maintenance requirements to assure that

any valves installed under this

rulemaking would reliably operate on-

demand during emergency situations.

In response to the hazardous liquid

ANPRM of October 18, 2010, PHMSA

received comments on location and

performance standards for EFRDs from

industry and trade associations. API,

AOPL, TxOGA, LMOGA, and

TransCanada Keystone Pipeline

reported that no industry standards

currently address EFRD use. PHMSA

also received several comments

regarding location requirements for

EFRDs, indicating that PHMSA should

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not specify the location of EFRDs. More

specifically, API, AOPL, TransCanada

Keystone Pipeline, LMOGA, and

TxOGA indicated that a requirement to

place EFRDs at predetermined locations

or fixed intervals in lieu of a

comprehensive engineering risk analysis

would be arbitrary, costly, and

potentially counter-productive to

pipeline safety. They noted that

§ 195.452 already requires EFRDs to be

installed to protect an HCA if the

operator determines, through a risk

assessment, that an EFRD is needed, and

TPA suggested that no general criteria

beyond those in the existing regulations

are appropriate because decisions on

EFRD placement are driven by local

factors. Conversely, NSB and MAWUC

stated EFRDs should be required on all

pipelines PHMSA regulates, with

specific instruction or criteria on when

and where EFRDs need to be used,

especially if they can limit a spill.

As discussed above, PHMSA

determined that the lack of more

comprehensive and specific guidance

regarding the location and performance

requirements for EFRDs perpetuates the

inconsistencies and large variances in

operators’ response times in isolating

pipeline segments when failures occur,

particularly when a rupture or other

fast-acting, large-volume release occurs.

Valves, even when located properly, are

more effective in failure scenarios when

they can be closed quickly to isolate the

failed segment. PHMSA also notes that

ASME B31.4, ‘‘Pipeline Transportation

Systems for Liquid Hydrocarbons and

Other Liquids’’ (2009), addresses

mainline valves and specifies operators

install RCVs and/or check valves in

certain instances.

Furthermore, PHMSA determined

that, although the EFRD evaluation

requirement already exists for HCA

segments, additional measures are

needed to specifically address rupture

mitigation for new and replaced

pipelines. In accident reports submitted

to PHMSA by operators from 2010 to

2017, just over one-half of all HCA

incidents where valve type was

recorded occurred at a location where

either the upstream or downstream

valve was an automatic, remotely

controlled, or check valve. In

approximately one-third of incidents

occurring in an HCA, both the upstream

and down valves were actuated by some

manner of automation. It is difficult to

envision a case where some type of

rupture-mitigation valve (which in some

cases can be an EFRD) on either side of

(or within) an HCA segment would not

provide additional protection. In all

cases where a valve cannot be quickly

accessed and manually closed, remote

or automatic actuation is the only way

to ensure prompt and effective closure.

In the hazardous liquid pipeline

regulations, EFRDs are defined as check

valves or remote-control valves.

Although check valves can be

considered as either an ASV or an EFRD

in some applications, this NPRM only

considers them to be a rupture-

mitigation valve if an operator can

demonstrate the valve’s operational and

protective equivalence when the valve

is used for segment shut-off and

isolation in response to a rupture. The

NPRM proposes that operators must

annually verify check valves or EFRDs

are operational if they serve as rupture-

mitigation valves. Considerations for the

use of check valves as alternative

equivalent technology for rupture

mitigation should include all of the

factors identified in this proposal and

all existing regulations, including those

contained in part 195, appendix C, such

as the nature and characteristics of the

transported commodity, the physical

and operating characteristics of the

pipeline, the hydraulic gradient of the

pipeline, the terrain surrounding the

pipeline, and all other factors pertinent

to rupture mitigation including valve

closure sealing performance and closure

times.

F. Failure Investigations

Current pipeline safety regulations

(§ 192.617 for gas transmission pipelines

and § 195.402(c)(5) for hazardous liquid

pipelines) require operators to report all

incidents (gas) and accidents (hazardous

liquid) over certain reporting

thresholds, and to investigate incidents

and accidents involving failed pipe,

failed components or other pipeline

system equipment, and incorrect

operations. The terms incident and

accident are used interchangeably in

this NPRM.

In addition to the proposed rupture

response and mitigation requirements,

PHMSA is proposing new specific

requirements for post-accident analysis

(i.e., an accident investigation) of any

rupture or other event involving the

activation of rupture-mitigation valves.

These post-accident reviews would

focus on ways to ensure that the

proposed performance objectives in this

NPRM are met in the future and that

lessons learned can be applied by the

operator system-wide. PHMSA has

determined this will improve the safety

performance of individual operators,

while also improving the industry’s

overall safety performance through

information sharing forums.

The NTSB noted in its accident report

of the PG&E incident at San Bruno, CA,

that many of the organizational

deficiencies causing the incident were

previously known to the operator as a

result of previous accidents. The NTSB

further noted that, as a lesson from

those accidents, PG&E should have

critically examined all components of

its pipeline system to identify and

analyze risks as well as update

emergency response procedures. Had

this recommended approach been taken

by PG&E following earlier incidents, the

NTSB argued, the San Bruno accident

may have been prevented. Similar

organizational failures were found

following the Enbridge incident near

Marshall, MI, and the NTSB noted that

Enbridge failed to adapt lessons learned

into its IM program.

Consistent with the findings in the

GAO Report (GAO–13–168) and

recommendations as described in this

section, the proposed amendments in

this NPRM would include new post-

accident review and implementation

requirements in §§ 192.617 and

195.402(c)(5). As provided in the

regulatory text, PHMSA would expect

operators would analyze data points

including, but not limited to, the time

taken to detect a rupture, the time taken

to initiate mitigative actions, emergency

response communications, personnel

response time, valve closure time,

SCADA performance, and valve

location. Operators would then use

these data points to enact improvements

to the operator’s suite of procedures,

including its training and qualification

programs, pipeline system design, risk

management, operations and

maintenance activities, and emergency

response procedures.

IV. Section-by-Section Analysis of

Changes to 49 CFR Part 192 for Gas

Transmission Pipelines

Sec. 192.3 Definitions

Most of the requirements of this

NPRM would be triggered by the

identification of a ‘‘rupture.’’ Section

192.3 would be amended to define

‘‘rupture’’ as any of the following events

that involve an uncontrolled release of

a large volume of gas over a short period

of time: (1) An unanticipated or

unplanned pressure loss of 10 percent

or more, occurring within a time

interval of 15 minutes or less, unless the

operator has documented in advance of

the pressure loss a need for a higher

pressure change; (2) an unexplained

flow-rate change, pressure change,

instrumentation indication, or

equipment function that may be

representative of an event described

above; or (3) an apparent large-volume,

uncontrolled release of gas or a failure

observed by operator personnel, the

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public, or public authorities, that is

reported to the operator and that may be

representative of an unintentional and

uncontrolled release event that is

defined in the items above.

Sec. 192.179 Transmission Line Valves

PHMSA proposes adding paragraph

(e) to require that all valves on newly

constructed or entirely replaced onshore

gas transmission pipelines that have

nominal diameters greater than or equal

to 6 inches be automatic shut-off valves,

remote-control valves, or an equivalent

technology, unless such valves are not

economically, technologically, or

operationally feasible. PHMSA proposes

to permit the installation of manual

valves as rupture-mitigation valves only

when there are feasibility issues

precluding the installation of automatic

or remote-control valves. All valves

installed per this requirement would

have to meet the new rupture-mitigation

standards proposed in § 192.634 and

isolate a ruptured pipeline segment

within 40 minutes of rupture

identification. Rupture identification

would be defined in § 192.3 to occur

when a rupture is reported to or

observed by pipeline operating

personnel or a controller.

Sec. 192.610 Change in Class Location:

Change in Valve Spacing

A new § 192.610 is proposed to

specify rupture-mitigation valve

requirements when a class location

changes. In cases where pipe is replaced

to meet the maximum allowable

operating pressure in accordance with

requirements for class location changes

under §§ 192.611, 192.619(a), and

192.620, then the rupture-mitigation

valve installation requirement in

§ 192.179 applies for the new class

location, which may require the

operator to install new valves, and the

rupture-mitigation requirements of

§ 192.634 would apply as well. Such

additional valves must be installed

within 24 months of the class location

change.

Sec. 192.615 Emergency Plans

PHMSA proposes to revise paragraphs

(a)(2), (a)(6), (a)(8), (a)(11), and (c) of

§ 192.615 to require that emergency

procedures provide for rupture

mitigation in response to a rupture

event, including specific timing

provisions relating to the identification

of ruptures. Specifically, operators must

have procedures in place allowing them

to identify a rupture event within 10

minutes of the initial notification to the

operator. PHMSA also proposes to

require that operators maintain liaison

with and contact the appropriate public

safety answering point (9–1–1

emergency call center) in the event an

operator’s pipeline ruptures.

Sec. 192.617 Investigation of Failures

and Incidents

PHMSA proposes to revise § 192.617

to define the elements that an operator

must incorporate when conducting a

post-incident analysis of certain

specifically defined incidents, namely

ruptures, and other release and failure

events involving the activation of

rupture-mitigation valves.

The proposed revision would require

the operator to identify potential

preventive and mitigative measures that

could be taken to reduce or limit the

release volume and damage from similar

events in the future. The post-incident

review would address factors associated

with this rulemaking, including but not

limited to detection and mitigation

actions, response time, valve location,

valve actuation, and SCADA

performance. Upon completing the post-

accident analysis, the operator must

develop and implement the lessons

learned throughout its suite of

procedures, including in pertinent

operator personnel training and

qualification programs, and in design,

construction, testing, maintenance,

operations, and emergency procedure

manuals and specifications.

Sec. 192.634 Transmission Lines:

Onshore Valve Shut-Off for Rupture

Mitigation

Proposed new § 192.634 would

establish an emergency operations

standard requiring operators to isolate

certain ruptured pipeline segments as

soon as practicable via rupture-

mitigation valves with complete

segment isolation as soon as practicable

but within 40 minutes of identifying a

rupture. This would apply to newly

constructed and entirely replaced

onshore gas transmission pipeline

segments in HCAs and Class 3 and Class

4 locations with nominal diameters

greater than or equal to 6 inches, and it

would also apply to any gas

transmission pipelines where 2 or more

contiguous miles of pipeline with

nominal diameters greater than or equal

to 6 inches are replaced in HCAs and

Class 3 and Class 4 locations. This

NPRM would require that operators

designate shut-off segments in these

areas and designate mainline valves

used to isolate ruptures on those shutoff

segments as rupture-mitigation valves.

This rulemaking would establish

maximum distances between rupture-

mitigation valves from 8 to 20 miles

depending on the pipeline’s class

location. Compliance with the standard

could be achieved using ASVs, RCVs, or

an equivalent technology. Operators

may install manually or locally operated

valves to act as rupture-mitigation

valves only if the installation of ASVs,

RCVs, or equivalent technology is not

feasible at the location, provided the

operator demonstrates that the 40-

minute closure standard can be

achieved under emergency conditions.

Operators using manual valves or other

equivalent technology must notify

PHMSA in accordance with the

procedure outlined in § 192.634(h). The

NPRM would also require that operators

monitor the position and operational

status of all rupture-mitigation valves.

Operators will be required to meet these

provisions within 12 months after the

effective date of the final rule.

Sec. 192.745 Valve Maintenance:

Transmission Lines

PHMSA proposes to revise § 192.745

by adding paragraphs (c), (d), and (e) to

incorporate the maintenance,

inspection, and operator drills required

to ensure operators can close a rupture-

mitigation valve as soon as practicable,

but within 40 minutes of rupture

identification. Demonstration and

verification requirements are proposed,

including point-to-point verification

tests for rupture-mitigation valves that

are ASVs or RCVs and initial validation

drills and periodic confirmation drills

for any manually or locally operated

valve identified as a rupture-mitigation

valve. The operator would be required

to identify corrective actions and

lessons learned resulting from its

validation and confirmation drills and

share and implement them across its

entire network of pipeline systems.

Sec. 192.935 What additional

preventive and mitigative measure must

an operator take?

PHMSA proposes to revise

§ 192.935(c) to clarify the requirements

for conducting ASV and RCV

evaluations for HCAs, particularly when

RCVs and ASVs are installed as

preventive and mitigative measures

associated with improved response

times for pipeline ruptures. The

amendments would require that

operators be able to evaluate and

demonstrate that they could identify a

rupture within 10 minutes in

accordance with the proposed

§ 192.615(a)(6) and meet the standard

specified in the proposed § 192.634 to

isolate shut-off segments in HCAs

during rupture events as soon as

practicable but within 40 minutes.

Operators would also be required to

demonstrate, through the risk analysis

required by this section, that any ASVs

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or RCVs installed under this section can

comply with the proposed valve

maintenance requirements at § 192.745.

V. Section-by-Section Analysis for

Changes to 49 CFR Part 195 for

Hazardous Liquid Pipelines

Sec. 195.2 Definitions

Most of the requirements of the NPRM

would be triggered by the identification

of a ‘‘rupture.’’ Section 195.2 would be

amended to define ‘‘rupture’’ for

hazardous liquid pipelines as any of the

following events that involve an

uncontrolled release of a large volume

of hazardous liquid over a short period

of time: (1) An unanticipated or

unplanned flow rate change of 10

percent or greater or a pressure loss of

10 percent or greater, occurring within

a time interval of 15 minutes or less,

unless the operator has documented in

advance of the flow rate change or

pressure loss the need for a higher flow

rate change or higher pressure-change

threshold due to pipeline flow

dynamics and terrain elevation changes

that cause fluctuations in hazardous

liquid flow that are typically higher

than a flow rate change or pressure loss

of 10 percent or greater in a time

interval of 15 minutes or less; (2) An

unexpected flow rate change, pressure

change, instrumentation indication, or

equipment function that may be

representative of an event defined

above; or (3) An apparent large-volume,

uncontrolled release of hazardous liquid

or a failure observed by operator

personnel, the public, or public

authorities, that is reported to the

operator and that may be representative

of an unintentional and uncontrolled

release event that is defined above.

Sec. 195.258 Valves: General

PHMSA proposes to require that all

valves on newly constructed and

entirely replaced hazardous liquid lines

that have nominal diameters greater

than or equal to 6 inches be RCVs,

ASVs, or an equivalent technology,

unless such valves are not

economically, technologically, or

operationally feasible. PHMSA proposes

to permit operators install manually or

locally operated valves only when there

are feasibility issues precluding the

installation of ASVs, RCVs, or

equivalent technology. All valves

installed under this requirement would

have to meet the new rupture-mitigation

standards proposed in § 195.418 and

isolate a ruptured pipeline segment as

soon as practicable, but within 40

minutes of rupture identification.

Rupture identification would be defined

in § 195.2 to occur when a rupture is

reported to or observed by pipeline

operating personnel or a controller.

Sec. 195.260 Valves: Location

Section 195.260 proposes the

requirements for the location of valves

on newly constructed hazardous liquid

pipelines, entirely replaced hazardous

liquid pipelines, and hazardous liquid

pipelines where 2 or more contiguous

miles have been replaced. PHMSA

proposes to revise § 195.260 to

incorporate new maximum valve

spacing requirements for the general

placement of valves, including a 20-mile

maximum spacing requirement for

valves on pipelines that could not affect

high consequence areas, with more

stringent maximum spacing

requirements of 15 miles and 7.5 miles

for pipelines that could affect HCAs and

HVL pipelines in populated areas,

respectively. These valve spacing

requirements carry over to the rupture-

mitigation valve spacing requirements at

§ 195.418 as well, where operators

would be required to install rupture-

mitigation valves at a maximum of every

15 miles but no further than 7

1

⁄

2

miles

from the HCA segment endpoints and at

a maximum of every 7

1

⁄

2

miles for HVL

lines in highly populated areas.

Revisions to § 195.260 would also

include two miscellaneous

clarifications: (1) To explicitly include

carbon dioxide as a transported

commodity whose consequences are to

be considered, and (2) to include new

requirements pertaining to valves at

water crossings to ensure these valves

will not be impacted by flood

conditions and to allow multiple water

crossings to be protected by a single pair

of valves.

Sec. 195.402 Procedural Manual for

Operations, Maintenance, and

Emergencies

PHMSA proposes to revise § 195.402

to identify the areas requiring an

immediate response by the operator to

prevent hazards to the public, property,

or the environment if the facilities failed

or malfunctioned, including segments

that could affect HCAs and segments

with valves that are specified in

§§ 195.418 and 195.452(i)(4).

PHMSA is also revising § 195.402 to

define the elements that an operator

must incorporate when conducting a

post-accident analysis of ruptures and

other release and failure events

involving the activation of rupture-

mitigation valves. The proposed

revision would require the operator to

identify potential preventative and

mitigative measures that could be taken

to reduce or limit the release volume

and damage from similar events in the

future. The post-accident review would

address factors associated with this

rulemaking, including but not limited to

detection and mitigation actions,

response time, valve location, valve

actuation, and SCADA performance.

Upon completion of this post-accident

analysis, the operator would be required

to develop and implement the lessons

learned throughout its suite of

procedures, including in pertinent

operator personnel training and

qualification programs, and in design,

construction, testing, maintenance,

operations, and emergency procedure

manuals and specifications.

Further, PHMSA is revising § 195.402

to clarify that requirements to establish

liaison with emergency officials must

include public safety answering points

(9–1–1 emergency call centers) and that

requirements for notifying emergency

officials when events occur must

include notifications to those local

public safety answering points.

Section 195.402 also require that

emergency procedures provide for

rupture detection and valve closure in

response to a leakage or failure event,

including specific timing provisions

relating to ruptures. Specifically,

operators must have procedures in place

so that they can identify a rupture event

within 10 minutes of the initial

notification to the operator. This section

would also be revised as a matter of

minor clarification to incorporate valve

shut-off as an example of an emergency

action to minimize the hazards of

released hazardous liquid or carbon

dioxide to life, property, or the

environment.

Sec. 195.418 Valves: Onshore Valve

Shut-Off for Rupture Mitigation

Proposed new § 195.418 would

establish an emergency operations

standard requiring operators to isolate

certain ruptured pipeline segments as

soon as practicable via rupture-

mitigation valves with complete

segment isolation within 40 minutes of

identifying a rupture. This standard

would apply to newly constructed and

entirely replaced onshore hazardous

liquid pipelines in HCAs and that could

affect HCAs with nominal diameters

greater than or equal to 6 inches, and it

would also apply to any hazardous

liquid pipelines where 2 or more

contiguous miles of pipeline with

nominal diameters greater than or equal

to 6 inches are replaced in HCAs or

where they could affect HCAs. This

NPRM would require that operators

designate shut-off segments in these

areas and designate mainline valves

used to isolate ruptures on those shut-

off segments as rupture-mitigation

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39

PHMSA notes that HVL releases may have

similar incident profiles to natural gas transmission

pipelines, as escaping product can be ignited and

cause similar damage via a rupture.

valves. This NPRM would establish

maximum distances of 15 miles between

rupture-mitigation valves and 7

1

⁄

2

miles

between rupture-mitigation valves on

HVL lines, which are consistent with

the proposed spacing requirements of

§ 195.260. Operators could use ASVs,

RCVs, an equivalent technology, or

manually operated valves (if the

operator demonstrates infeasibility of

ASVs, RCVs and equivalent technology,

that the standard can be achieved under

emergency conditions, and provides

notification to PHMSA). Operators

would also be required to monitor the

position and operational status of all

rupture-mitigation valves. Operators

will be required to meet these

provisions within 12 months after the

effective date of the final rule.

Sec. 195.420 Valve Maintenance

PHMSA proposes to revise § 195.420

to incorporate the maintenance,

inspection, and operator drills required

to ensure operators can close a rupture-

mitigation valve as soon as practicable

but within 40 minutes. Demonstration

and verification requirements are

proposed, including point-to-point

verification tests for rupture-mitigation

valves that are ASVs or RCVs and initial

validation drills and periodic

confirmation drills for any manually or

locally operated valves identified as

rupture-mitigation valves. This section

would also require an operator to

identify corrective actions and lessons

learned resulting from its validation or

confirmation drills and share and

implement those lessons learned across

its entire network of pipeline systems.

Sec. 195.452 Pipeline Integrity

Management in High Consequence

Areas

PHMSA proposes to revise

§ 195.452(i)(4) to clarify the existing

requirements for the conduct of EFRD

evaluations for HCAs, particularly when

operators use EFRDs as rupture-

mitigation valves on applicable lines.

Further, the amendments would also

require that operators be able to evaluate

and demonstrate that they could

identify a rupture within 10 minutes in

accordance with the proposed § 195.402

and meet the standard specified in the

proposed § 195.418 to isolate shut-off

segments that could affect HCAs during

rupture events, and the amendments

would require that any EFRDs installed

on shut-off segments also comply with

the design, operation, testing, and

maintenance requirements of

§§ 195.258, 195.260, 195.402, and

195.420.

VI. Regulatory Analyses and Notices

A. Statutory/Legal Authority for This

Rulemaking

This NPRM is published under the

authority of the Federal Pipeline Safety

Law (49 U.S.C. 60101 et seq.). Section

60102 authorizes the Secretary of

Transportation to issue regulations

governing the design, installation,

inspection, emergency procedures,

testing, construction, extension,

operation, replacement, and

maintenance of pipeline facilities. The

Secretary delegated this authority to

PHMSA at 49 CFR 1.97(a).

B. Executive Orders 12866 and 13771,

and DOT Regulatory Policies and

Procedures

Executive Order 12866 requires

agencies to regulate in the ‘‘most cost-

effective manner,’’ to make a ‘‘reasoned

determination that the benefits of the

intended regulation justify its costs,’’

and to develop regulations that ‘‘impose

the least burden on society.’’ This

NPRM has been determined to be

significant under Executive Order 12866

and the Department of Transportation’s

Regulatory Policies and Procedures.

This NPRM has been reviewed by the

Office of Management and Budget in

accordance with Executive Order 12866

(Regulatory Planning and Review) and

is consistent with the Executive Order

12866 requirements and 49 U.S.C.

60102(b)(5)–(6).

Consistent with Executive Order

12866, PHMSA has prepared a

preliminary assessment of the benefits

and costs of the proposed rule as well

as reasonable alternatives. PHMSA

anticipates that, if promulgated, this

NPRM will provide benefits to the

public through more rapid valve closure

resulting in better consequence

mitigation.

For hazardous liquid pipelines, most

damages are calculated by the cost of

cleanup and long-term environmental

remediation.

39

Therefore, a reduction in

the amount of product released from a

hazardous liquid pipeline can directly

correlate to a reduction in damages. As

discussed earlier in this NPRM, in the

Enbridge incident near Marshall, MI, the

pipeline continued to pump oil for 18

hours before valves were closed,

resulting in approximately 20,000

barrels of oil being released. With faster

rupture detection, pump shutdowns,

and valve closures in line with this

NPRM, the pipeline would have been

isolated 17 hours and 20 minutes

earlier, which would have resulted in a

substantially lower spill size,

environmental impact, and remedial

costs.

Natural gas transmission pipeline

incidents result predominately in

fatalities, injuries, or property damages

that are not linearly related to the

quantity of natural gas released. For

small incidents and for those incidents

in remote locations, damages may be

limited to pipeline repair and gas loss

costs. Larger incidents, on the other

hand, likely involve the ignition of gas

and extensive property damage and

personal injury, depending on the

location of the release and its proximity

to buildings, homes, or other areas. A

reduction in the cumulative product

release over these types of incidents

would not necessarily imply avoided

damages in the way that it would apply

to hazardous liquid pipelines as

discussed above. For example, in the

PG&E incident, the homes destroyed by

the initial rupture would not have been

saved through a more prompt valve

closure. However, as discussed earlier

in this document, during the 95 minutes

it took PG&E to isolate the ruptured

segment, the fire resulting from the

rupture was being fed by the

transmission line, and firefighters could

not start firefighting and containment

activities until the line was isolated.

Earlier valve closure, in that

circumstance, could have limited the

spread of fire and additional damage

beyond the immediate rupture area.

PHMSA estimates that the NPRM will

result in annualized costs of

approximately $3.1 million per year,

calculated at a 7 percent discount rate.

The table below presents the annualized

costs for the baseline and this NPRM, at

a 3 percent and a 7 percent discount

rate:

T

ABLE

1—A

NNUALIZED

C

OSTS OF THE

P

ROPOSED

R

ULE

[Millions 2015$]

System type 7%

Discount

rate

3%

Discount

rate

Gas transmission ...... $1.2 $1.0

Hazardous liquid ....... 1.9 1.5

Total .......................... 3.1 2.5

The NPRM is expected to be an E.O.

13771 regulatory action. Details on the

estimated costs of this NPRM can be

found in the rule’s economic analysis.

For more information, please see the

PRIA in the docket for this rulemaking.

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C. Executive Order 13132: Federalism

PHMSA has analyzed this rulemaking

action according to Executive Order

13132 (‘‘Federalism’’). While this NPRM

may preempt some State requirements,

it does not impose any regulation that

has substantial direct effects on the

States, the relationship between the

national government and the States, or

the distribution of power and

responsibilities among the various

levels of government. Therefore, the

consultation and funding requirements

of Executive Order 13132 do not apply.

The pipeline safety laws, specifically 49

U.S.C. 60104(c), prohibit State safety

regulation of interstate pipelines. Under

the pipeline safety laws, States have the

ability to augment pipeline safety

requirements for intrastate pipelines,

but may not approve safety

requirements less stringent than those

required by Federal law. A State may

also regulate an intrastate pipeline

facility PHMSA does not regulate.

D. Regulatory Flexibility Act

The Regulatory Flexibility Act, as

amended by the Small Business

Regulatory Flexibility Fairness Act of

1996, requires Federal regulatory

agencies to prepare an Initial Regulatory

Flexibility Analysis (IRFA) for any

proposed rule subject to notice-and-

comment rulemaking under the

Administrative Procedure Act unless

the agency head certifies that the

rulemaking will not have a significant

economic impact on a substantial

number of small entities.

PHMSA prepared an IRFA of the

potential economic impact on small

entities, which is available in the docket

for this NPRM. For a worst-case

scenario, PHMSA compared compliance

costs to estimated sales for businesses.

Average annualized costs could exceed

1 percent of sales for 34 (8 percent) of

the estimated small gas transmission

entities and 12 (19 percent) of the

estimated small hazardous liquid

operators for a total of 46 (10 percent)

entities combined across both sectors.

Average annualized costs could exceed

3% of sales for 3 (1 percent) gas

transmission operators and 4 (6 percent)

hazardous liquid operators, which

represent 7 (1 percent) of the total

estimated small business entities.

Due to various uncertainties in the

screening analysis (see Table 7 in the

IRFA), PHMSA seeks comments

regarding the impacts of the NPRM on

small entities. PHMSA will

subsequently modify the IRFA and

make a determination as to whether this

NPRM will have a significant economic

impact on a number of small entities at

the final rule stage.

E. National Environmental Policy Act

PHMSA analyzed this NPRM in

accordance with section 102(2)(c) of the

National Environmental Policy Act (42

U.S.C. 4332), the Council on

Environmental Quality regulations (40

CFR parts 1500–1508), and DOT Order

5610.1C, and has preliminarily

determined this action will not

significantly affect the quality of the

human environment. The

Environmental Assessment for this

NPRM is in the docket.

F. Executive Order 13175: Consultation

and Coordination With Indian Tribal

Governments

PHMSA has analyzed this NPRM in

accordance with the principles and

criteria contained in Executive Order

13175 (‘‘Consultation and Coordination

with Indian Tribal Governments’’).

Because this NPRM is not expected to

have Tribal implications and is not

expected to impose substantial direct

compliance costs on Indian Tribal

governments, PHMSA does not

anticipate that the funding and

consultation requirements of Executive

Order 13175 will apply. PHMSA seeks

comment on the applicability of the

executive order to this NPRM.

G. Executive Order 13211

This NPRM is not anticipated to be a

‘‘significant energy action’’ under

Executive Order 13211 (Actions

Concerning Regulations That

Significantly Affect Energy Supply,

Distribution, or Use). It is not likely to

have a significant adverse effect on

supply, distribution, or energy use.

Further, the Office of Information and

Regulatory Affairs has not designated

this proposed rule as a significant

energy action.

H. Paperwork Reduction Act

Pursuant to 5 CFR 1320.8(d), PHMSA

is required to provide interested

members of the public and affected

agencies with an opportunity to

comment on information collection and

recordkeeping requests. PHMSA

estimates that the proposals in this

NPRM will create the following

Paperwork Reduction Act impacts:

PHMSA proposes to create a new

information collection to cover the

recordkeeping requirement for post-

incident recordkeeping called:

‘‘Rupture/Shut-off Valve: Post-Incident

Records for Pipeline Operators.’’

PHMSA also proposes to create a new

information collection called

‘‘Alternative Technology for Onshore

Rupture Mitigation Notifications’’ to

cover this specific notification

requirement.

PHMSA will submit information

collection requests to the Office of

Management and Budget (OMB) for

approval based on the requirements that

trigger components of the Paperwork

Reduction Act in this NPRM. PHMSA

will also request two new OMB Control

Numbers for these collections. These

information collections are contained in

the pipeline safety regulations, 49 CFR

parts 190–199. The following

information is provided for each of

these information collections: (1) Title

of the information collection; (2) OMB

control number; (3) Current expiration

date; (4) Type of request; (5) Abstract of

the information collection activity; (6)

Description of affected public; (7)

Estimate of total annual reporting and

recordkeeping burden; and (8)

Frequency of collection. The

information collection burdens are

estimated as follows:

1. Title: ‘‘Rupture/Valve Shut-off:

Post-Incident Records for Pipeline

Operators.’’

OMB Control Number: Will request

one from OMB.

Current Expiration Date: New

Collection—To be determined.

Abstract: This NPRM proposes to

amend 49 CFR 192.617 and 195.402 to

require operators who have experienced

a rupture or rupture-mitigation valve

shut-off to complete a post-incident

summary. The post-incident summary,

all investigation and analysis

documents used to prepare it, and

records of lessons learned must be kept

for the life of the pipeline. PHMSA

estimates this recordkeeping

requirement will result in 50 responses

annually and has allotted each

respondent 8 hours per response to

make and maintain the required records.

PHMSA does not currently have an

information collection that covers this

requirement and will request the

approval of this new collection, along

with a new OMB Control Number, from

the Office of Management and Budget.

Affected Public: Operators of PHMSA-

regulated pipelines.

Annual Reporting and Recordkeeping

Burden:

Total Annual Responses: 50.

Total Annual Burden Hours: 400.

Frequency of Collection: On occasion.

2. Title: ‘‘Alternative Equivalent

Technology for Onshore Rupture

Mitigation Notifications.’’

OMB Control Number: Will request

one from OMB.

Current Expiration Date: New

Collection—To be determined.

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Abstract: This NPRM proposes a new

paragraph (d) in both 49 CFR 192.634

and 195.418 requiring operators who

elect to use alternative equivalent

technology to notify, in accordance with

192.949, the Office of Pipeline Safety at

least 90 days in advance of use. An

operator choosing this option must

include a technical and safety

evaluation, including design,

construction, and operating procedures

for the alternative equivalent technology

to the Associate Administrator of

Pipeline Safety with the notification.

PHMSA would then have 90 days to

object to the alternative equivalent

technology via letter from the Associate

Administrator of Pipeline Safety;

otherwise, the alternative equivalent

technology would be acceptable for use.

PHMSA estimates this notification

requirement will result in 2 responses

annually and has allotted each

respondent 40 hours per response to

conduct this task. PHMSA does not

currently have an information collection

that covers this requirement and will

request the approval of this new

collection, along with a new OMB

Control Number, from the Office of

Management and Budget.

Affected Public: Operators of PHMSA-

regulated pipelines.

Annual Reporting and Recordkeeping

Burden:

Total Annual Responses: 2.

Total Annual Burden Hours: 80.

Frequency of Collection: On occasion.

Requests for copies of these

information collections should be

directed to Angela Hill, Office of

Pipeline Safety (PHP–30), Pipeline and

Hazardous Materials Safety

Administration, 2nd Floor, 1200 New

Jersey Avenue SE, Washington, DC

20590–0001, Telephone: 202–366–1246.

Comments are invited on:

(a) The need for the proposed

collection of information for the proper

performance of the functions of the

agency, including whether the

information will have practical utility;

(b) The accuracy of the agency’s

estimate of the burden of the revised

collection of information, including the

validity of the methodology and

assumptions used;

(c) Ways to enhance the quality,

utility, and clarity of the information to

be collected; and

(d) Ways to minimize the burden of

the collection of information on those

who are to respond, including the use

of appropriate automated, electronic,

mechanical, or other technological

collection techniques.

(e) Ways the collection of this

information is beneficial or not

beneficial to public safety.

Send comments directly to the Office

of Management and Budget, Office of

Information and Regulatory Affairs,

Attn: Desk Officer for the Department of

Transportation, 725 17th Street NW,

Washington, DC 20503. Comments

should be submitted on or prior to April

6, 2020.

I. Unfunded Mandates Reform Act of

1995

The analysis PHMSA performed in

accordance with preparing the

Preliminary Regulatory Impact

Assessment does not expect this NPRM

to impose unfunded mandates per the

Unfunded Mandates Reform Act of

1995. It is not expected to result in costs

of $100 million, adjusted for inflation,

or more in any one (1) year to either

State, local, or tribal governments, in the

aggregate, or to the private sector, and

is the least burdensome alternative that

achieves the objective of the proposed

rulemaking. A copy of the Preliminary

Regulatory Impact Assessment is

available for review in the docket.

J. Privacy Act Statement

Anyone may search the electronic

form of all comments received for any

of our dockets. You may review DOT’s

complete Privacy Act Statement,

published on April 11, 2000 (65 FR

19476), in the Federal Register at:

https://www.govinfo.gov/content/FR-

2000-04-11/pdf/00-8505.pdf.

K. Regulation Identifier Number

A regulation identifier number (RIN)

is assigned to each regulatory action

listed in the Unified Agenda of Federal

Regulations. The Regulatory Information

Service Center publishes the Unified

Agenda in April and October of each

year. The RIN contained in the heading

of this document may be used to cross-

reference this action with the Unified

Agenda.

List of Subjects

49 CFR Part 192

Gas, Incorporation by reference,

Natural gas, Pipeline safety, Reporting

and recordkeeping requirements.

49 CFR Part 195

Anhydrous ammonia, Carbon dioxide,

Incorporation by reference, Petroleum,

Pipeline safety, Reporting and

recordkeeping requirements.

In consideration of the foregoing,

PHMSA proposes to amend 49 CFR

parts 192 and 195 as follows:

PART 192—TRANSPORTATION OF

NATURAL GAS AND OTHER GAS BY

PIPELINE: MINIMUM FEDERAL

SAFETY STANDARDS

■1. The authority citation for part 192

continues to read as follows:

Authority: 30 U.S.C. 185(w)(3), 49 U.S.C.

5103, 60101 et. seq., and 49 CFR 1.97.

■2. In § 192.3, the definition of

‘‘rupture’’ is added in alphabetical order

to read as follows:

§ 192.3 Definitions.

* * * * *

Rupture means any of the following

events that involve an uncontrolled

release of a large volume of gas:

(1) A release of gas observed or

reported to the operator by its field

personnel, nearby pipeline or utility

personnel, the public, local responders,

or public authorities, and that may be

representative of an unintentional and

uncontrolled release event defined in

paragraphs (2) or (3) of this definition;

(2) An unanticipated or unplanned

pressure loss of 10 percent or greater,

occurring within a time interval of 15

minutes or less, unless the operator has

documented in advance of the pressure

loss the need for a higher pressure-

change threshold due to pipeline flow

dynamics that cause fluctuations in gas

demand that are typically higher than a

pressure loss of 10 percent in a time

interval of 15 minutes or less; or

(3) An unexplained flow rate change,

pressure change, instrumentation

indication, or equipment function that

may be representative of an event

defined in paragraph (2) of this

definition.

Note: Rupture identification occurs

when a rupture, as defined in this

section, is first observed by or reported

to pipeline operating personnel or a

controller.

* * * * *

■3. In § 192.179, paragraph (e) is added

to read as follows:

§ 192.179 Transmission line valves.

* * * * *

(e) All onshore transmission line

segments with diameters greater than or

equal to 6 inches that are constructed or

entirely replaced after [DATE 12

MONTHS AFTER EFFECTIVE DATE OF

FINAL RULE] must have automatic

shutoff valves, remote-control valves, or

equivalent technology installed at

intervals meeting the appropriate valve

spacing requirements of this section. An

operator may only install a manual

valve under this paragraph if it can

demonstrate to PHMSA that installing

an automatic shutoff valve, remote-

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control valve, or equivalent technology

would be economically, technically, or

operationally infeasible. An operator

using alternative equivalent technology

or manual valve must notify PHMSA in

accordance with the procedure in

§ 192.634(h). All valves and technology

installed under this paragraph must

meet the requirements of § 192.634(c),

(d), (f), and (g).

■4. Section 192.610 is added to read as

follows:

§ 192.610 Change in class location:

Change in valve spacing.

If a class location change on a

transmission line occurs after

[EFFECTIVE DATE OF FINAL RULE]

and results in pipe replacement to meet

the maximum allowable operating

pressure requirements in §§ 192.611,

192.619, or 192.620, then the

requirements in §§ 192.179 and 192.634

apply to the new class location, and the

operator must install valves as necessary

to comply with those sections. Such

valves must be installed within 24

months of the class location change in

accordance with § 192.611(d).

■5. In § 192.615, paragraphs (a)(2), (6),

(8), and (11), and paragraph (c)

introductory text are revised to read as

follows:

§ 192.615 Emergency plans.

(a) * * *

(2) Establishing and maintaining

adequate means of communication with

the appropriate public safety answering

point (9–1–1 emergency call center), as

well as fire, police, and other public

officials, to learn the responsibility,

resources, jurisdictional area, and

emergency contact telephone numbers

for both local and out-of-area calls of

each government organization that may

respond to a pipeline emergency, and to

inform the officials about the operator’s

ability to respond to the pipeline

emergency and means of

communication.

* * * * *

(6) Taking necessary actions,

including but not limited to, emergency

shutdown, valve shut-off, and pressure

reduction, in any section of the

operator’s pipeline system to minimize

hazards of released gas to life, property,

or the environment. Each operator

installing valves in accordance with

§ 192.179(e) or subject to the

requirements in § 192.634 must also

evaluate and identify a rupture as

defined in § 192.3 as being an actual

rupture event or non-rupture event in

accordance with operating procedures

as soon as practicable but within 10

minutes of the initial notification to or

by the operator, regardless of how the

rupture is initially detected or observed.

* * * * *

(8) Notifying the appropriate public

safety answering point (9–1–1

emergency call center), as well as fire,

police, and other public officials, of gas

pipeline emergencies to coordinate and

share information to determine the

location of the release, including both

planned responses and actual responses

during an emergency. The operator

(pipeline controller or the appropriate

operator emergency response

coordinator) must immediately and

directly notify the appropriate public

safety answering point (9–1–1

emergency call center) or other

coordinating agency for the

communities and jurisdictions in which

the pipeline is located after the operator

determines a rupture has occurred when

a release is indicated and rupture-

mitigation valve closure is

implemented.

* * * * *

(11) Actions required to be taken by

a controller during an emergency in

accordance with the operator’s

emergency plans and §§ 192.631 and

192.634.

* * * * *

(c) Each operator must establish and

maintain liaison with the appropriate

public safety answering point (9–1–1

emergency call center), as well as fire,

police, and other public officials to:

* * * * *

■6. Section 192.617 is revised to read

as follows:

§ 192.617 Investigation of failures and

incidents.

(a) Post-incident procedures. Each

operator must establish and follow post-

incident procedures for investigating

and analyzing failures and incidents as

defined in § 191.3, including sending

the failed pipe, component, or

equipment for laboratory testing or

examination, where appropriate, to

determine the causes and contributing

factors of the failure or incident and

minimize the possibility of a recurrence.

(b) Post-incident lessons learned.

Each operator must develop, implement,

and incorporate lessons learned from a

post-incident review into its procedures,

including in pertinent operator

personnel training and qualification

programs, and in design, construction,

testing, maintenance, operations, and

emergency procedure manuals and

specifications.

(c) Analysis of rupture and valve shut-

offs; preventive and mitigative

measures. If a failure or incident

involves a rupture as defined in § 192.3

or the closure of a rupture-mitigation

valve as defined in § 192.634, the

operator must also conduct a post-

incident analysis of all factors impacting

the release volume and the

consequences of the release, and

identify and implement preventive and

mitigative measures to reduce or limit

the release volume and damage in a

future failure or incident. The analysis

must include all relevant factors

impacting the release volume and

consequences, including, but not

limited to, the following:

(1) Detection, identification,

operational response, system shut-off,

and emergency response

communications, based on the type and

volume of the release or failure event;

(2) Appropriateness and effectiveness

of procedures and pipeline systems,

including SCADA, communications,

valve shut-off, and operator personnel;

(3) Actual response time from rupture

detection to initiation of mitigative

actions, and the appropriateness and

effectiveness of the mitigative actions

taken;

(4) Location and the timeliness of

actuation of rupture-mitigation valves

identified under § 192.634; and

(5) All other factors the operator

deems appropriate.

(d) Rupture post-incident summary. If

a failure or incident involves a rupture

as defined in § 192.3 or the closure of

a rupture-mitigation valve as defined in

§ 192.634, the operator must complete a

summary of the post-incident review

required by paragraph (c) of this section

within 90 days of the failure or incident,

and while the investigation is pending,

conduct quarterly status reviews until

completed. The post-incident summary

and all other reviews and analyses

produced under the requirements of this

section must be reviewed, dated, and

signed by the appropriate senior

executive officer. The post-incident

summary, all investigation and analysis

documents used to prepare it, and

records of lessons learned must be kept

for the useful life of the pipeline.

■7. Section 192.634 is added to read as

follows:

§ 192.634 Transmission lines: Onshore

valve shut-off for rupture mitigation.

(a) Applicability. For onshore

transmission pipeline segments with

nominal diameters of 6 inches or greater

in high consequence areas or Class 3 or

Class 4 locations that are constructed or

where 2 or more contiguous miles have

been replaced after [DATE 12 MONTHS

AFTER EFFECTIVE DATE OF FINAL

RULE], an operator must install rupture-

mitigation valves according to the

requirements of this section. Rupture-

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mitigation valves must be operational

within 7 days of placing the new or

replaced pipeline segment in service.

(b) Maximum spacing between valves.

Rupture-mitigation valves must be

installed in accordance with the

following requirements:

(1) High Consequence Areas. For

purposes of this paragraph (b)(1), ‘‘shut-

off segment’’ means the segment of pipe

located between the upstream mainline

valve closest to the upstream high

consequence area segment endpoint and

the downstream mainline valve closest

to the downstream high consequence

area segment endpoint so that the

entirety of the high consequence area

segment is between at least two rupture-

mitigation valves. If any crossover or

lateral pipe for gas receipts or deliveries

connects to the shut-off segment

between the upstream and downstream

mainline valves, then the segment also

extends to the nearest valve on the

crossover connection(s) or lateral(s),

such that, when all valves are closed,

there is no flow path for gas to be

transported to the rupture site (except

for residual gas already in the shut-off

segment). All such valves on a shut-off

segment are ‘‘rupture-mitigation

valves.’’ Multiple high consequence

areas may be contained within a single

shut-off segment. The distance between

rupture-mitigation valves for each shut-

off segment must not exceed:

(i) 8 miles if one or more high

consequence areas in the shutoff

segment is in a Class 4 location;

(ii) 15 miles if one or more high

consequence areas in the shutoff

segment is in a Class 3 location, and

(iii) 20 miles if all high consequence

areas in the shutoff segment are located

in Class 1 or 2 locations, or

(iv) The mainline valve spacing

requirements of § 192.179 when

mainline valve spacing does not meet

§ 192.634(b)(1)(i), (ii), or (iii).

(2) Class 3 locations. For purposes of

this paragraph, ‘‘shut-off segment’’

means the segment of pipe located

between the upstream mainline valve

closest to the upstream endpoint of the

Class 3 location and the downstream

mainline valve closest to the

downstream endpoint of the Class 3

location so that the entirety of the Class

3 location is between at least two

rupture-mitigation valves. If any

crossover or lateral pipe for gas receipts

or deliveries connects to the shut-off

segment between the upstream and

downstream mainline valves, the shut-

off segment also extends to the nearest

valve on the crossover connection(s) or

lateral(s), such that, when all valves are

closed, there is no flow path for gas to

be transported to the rupture site

(except for residual gas already in the

shut-off segment). All such valves on a

shut-off segment are ‘‘rupture-mitigation

valves.’’ Multiple Class 3 locations may

be contained within a single shut-off

segment. The distance between

mainline valves serving as rupture-

mitigation valves for each shut-off

segment must not exceed 15 miles.

(3) Class 4 locations. For purposes of

this paragraph, ‘‘shut-off segment’’

means the segment of pipe between the

upstream mainline valve closest to the

upstream endpoint of the Class 4

location and the downstream mainline

valve closest to the downstream

endpoint of the Class 4 location so that

the entirety of the Class 4 location is

between at least two rupture-mitigation

valves. If any crossover or lateral pipe

for gas receipts or deliveries connects to

the shut-off segment between the

upstream and downstream mainline

valves, the shut-off segment also

extends to the nearest valve on the

crossover connection(s) or lateral(s),

such that, when all valves are closed,

there is no flow path for gas to be

transported to the rupture site (except

for residual gas already in the shut-off

segment). All such valves on a shut-off

segment are ‘‘rupture-mitigation

valves.’’ Multiple Class 4 locations may

be contained within a single shut-off

segment. The distance between

mainline valves serving as rupture-

mitigation valves for each shut-off

segment must not exceed 8 miles.

(4) Laterals. Laterals extending from

shut-off segments that contribute less

than 5 percent of the total shut-off

segment volume may have rupture-

mitigation valves that meet the

actuation requirements of this section at

locations other than mainline receipt/

delivery points, as long as all of these

laterals contributing gas volumes to the

shut-off segment do not contribute more

than 5 percent of the total shut-off

segment gas volume, based upon

maximum flow volume at the operating

pressure.

(c) Valve shut-off time for rupture

mitigation. Upon identifying a rupture,

the operator must, as soon as

practicable:

(1) Commence shut-off of the rupture-

mitigation valve or valves which would

have the greatest effect on minimizing

the release volume and other potential

safety and environmental consequences

of the discharge to achieve full rupture-

mitigation valve shut-off within 40

minutes of rupture identification; and

(2) Initiate other mitigative actions

appropriate for the situation to

minimize the release volume and

potential adverse consequences.

(d) Valve shut-off capability. Onshore

transmission line rupture-mitigation

valves must have actuation capability

(i.e., remote-control shut-off, automatic

shut-off, equivalent technology, or

manual shut-off where personnel are in

proximity) to ensure pipeline ruptures

are promptly mitigated based upon

maximum valve shut-off times, location,

and spacing specified in paragraphs (b)

and (c) of this section to mitigate the

volume and consequence of gas

released.

(e) Valve shut-off methods. All

onshore transmission line rupture-

mitigation valves must be actuated by

one of the following methods to mitigate

a rupture as soon as practicable but

within 40 minutes of rupture

identification:

(1) Remote control from a location

that is continuously staffed with

personnel trained in rupture response to

provide immediate shut-off following

identification of a rupture or other

decision to close the valve;

(2) Automatic shut-off following

identification of a rupture; or

(3) Alternative equivalent technology

that is capable of mitigating a rupture in

accordance with this section.

(4) Manual operation upon

identification of a rupture. Operators

using a manual valve in accordance

with § 192.179(e), must appropriately

station personnel to ensure valve shut-

off in accordance with paragraph (c) of

this section. Manual operation of valves

must include time for the assembly of

necessary operating personnel, the

acquisition of necessary tools and

equipment, driving time under heavy

traffic conditions and at the posted

speed limit, walking time to access the

valve, and time to manually shut off all

valves, not to exceed the 40-minute total

response time in paragraph (c)(1) of this

section.

(f) Valve monitoring and operation

capabilities. Onshore transmission line

rupture-mitigation valves actuated by

methods in paragraph (e) of this section

must be capable of being:

(1) Monitored or controlled by either

remote or onsite personnel;

(2) Operated during normal,

abnormal, and emergency operating

conditions;

(3) Monitored for valve status (i.e.,

open, closed, or partial closed/open),

upstream pressure, and downstream

pressure. Pipeline segments that use

manual valve operation must have the

capability to monitor pressures and gas

flow rates on the pipeline to be able to

identify and locate a rupture;

(4) Initiated to close as soon as

practicable after identifying a rupture

and with complete valve shut-off within

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40 minutes of rupture identification as

specified in paragraph (c) of this

section; and

(5) Monitored and controlled by

remote personnel or must have a back-

up power source to maintain SCADA or

other remote communications for

remote control shut-off valve or

automatic shut-off valve operational

status.

(g) Monitoring of valve shut-off

response status. Operating control

personnel must continually monitor

rupture-mitigation valve position and

operational status of all rupture-

mitigation valves for the affected shut-

off segment during and after a rupture

event until the pipeline segment is

isolated. Such monitoring must be

maintained through continual electronic

communications with remote

instrumentation or through continual

verbal communication with onsite

personnel stationed at each rupture-

mitigation valve, via telephone, radio, or

equivalent means.

(h) Alternative equivalent technology

or manual valves for onshore

transmission rupture mitigation. If an

operator elects to use alternative

equivalent technology or manual valves

in accordance with § 192.179(e), the

operator must notify PHMSA at least 90

days in advance of installation or use in

accordance with § 192.949. The operator

must include a technical and safety

evaluation in its notice to PHMSA,

including design, construction, and

operating procedures for the alternative

equivalent technology or manual valve.

Operators installing manual valves must

also demonstrate that installing an

automatic shutoff valve, a remote-

control valve, or equivalent technology

would be economically, technically, or

operationally infeasible. An operator

may proceed to use the alternative

equivalent technology or manual valves

91 days after submitting the notification

unless it receives a letter from the

Associate Administrator of Pipeline

Safety informing the operator that

PHMSA objects to the proposed use of

the alternative equivalent technology or

manual valves or that PHMSA requires

additional time to conduct its review.

■8. In § 192.745 paragraphs (c), (d), and

(e) are added to read as follows:

§ 192.745 Valve maintenance:

Transmission lines.

* * * * *

(c) For each valve installed under

§ 192.179(e) and each rupture-mitigation

valve under § 192.634 that is a remote

control shut-off or automatic shut-off

valve, or that is based on alternative

equivalent technology, the operator

must conduct a point-to-point

verification between SCADA displays

and the mainline valve, sensors, and

communications equipment in

accordance with § 192.631(c) and (e).

(d) For each rupture-mitigation valve

under § 192.634 that is manually or

locally operated:

(1) Operators must establish the 40-

minute total response time as required

by § 192.634 through an initial drill and

through periodic validation as required

in paragraph (d)(2) of this section. Each

phase of the drill response must be

reviewed and the results documented to

validate the total response time,

including valve shut-off, as being less

than or equal to 40 minutes following

rupture identification.

(2) A mainline valve serving as a

rupture-mitigation valve within each

pipeline system and within each

operating or maintenance field work

unit must be randomly selected for an

annual 40-minute total response time

validation drill that simulates worst-

case conditions for that location to

ensure compliance. The response drill

must occur at least once each calendar

year, with intervals not to exceed 15

months.

(3) If the 40-minute maximum

response time cannot be validated or

achieved in the drill, the operator must

revise response efforts to achieve

compliance with § 192.634 no later than

6 months after the drill. Alternative

valve shut-off measures must be in place

in accordance with paragraph (e) of this

section within 7 days of a failed drill.

(4) Based on the results of response-

time drills, the operator must include

lessons learned in:

(i) Training and qualifications

programs; and

(ii) Design, construction, testing,

maintenance, operating, and emergency

procedures manuals; and

(iii) Any other areas identified by the

operator as needing improvement.

(e) Each operator must take remedial

measures to correct any valve installed

under § 192.179(e) or any rupture-

mitigation valve identified in § 192.634

that is found to be inoperable or unable

to maintain shut-off, as follows:

(1) Repair or replace the valve as soon

as practicable but no later than 6

months after finding that the valve is

inoperable or unable to maintain shut-

off; and

(2) Designate an alternative compliant

valve within 7 calendar days of the

finding while repairs are being made.

■9. In § 192.935, paragraph (c) is

revised to read as follows:

§ 192.935 What additional preventive and

mitigative measures must an operator take?

* * * * *

(c) Risk analysis for gas releases and

protection against ruptures. If an

operator determines, based on a risk

analysis, that an automatic shut-off

valve (ASV) or remote-control valve

(RCV) would be an efficient means of

adding protection to a high consequence

area in the event of a gas release, an

operator must install the ASV or RCV.

In making that determination, an

operator must, at least, consider the

following factors—swiftness of leak

detection and pipe shutdown

capabilities, the type of gas being

transported, operating pressure, the rate

of potential release, pipeline profile, the

potential for ignition, and location of

nearest response personnel.

(1) Protection of onshore transmission

high consequence areas from ruptures.

An operator of an onshore transmission

pipeline segment that is constructed, or

that has 2 or more contiguous miles

replaced, after [DATE 12 MONTHS

AFTER EFFECTIVE DATE OF FINAL

RULE] and is greater than or equal to 6

inches in nominal diameter and is

located in a high consequence area must

provide for the additional protection of

those pipeline segments to assure the

timely termination and mitigation of

rupture events by complying with

§§ 192.615(a)(6), 192.634, and 192.745.

At a minimum, the analysis specified in

paragraph (c) of this section must

demonstrate that the operator can

achieve the following standards for

termination of rupture events:

(i) Operators must identify a rupture

event as soon as practicable but within

10 minutes of the initial notification to

or by the operator, in accordance with

§ 192.615(a)(6), regardless of how the

rupture is initially detected or observed;

(ii) Operators must begin closing shut-

off segment rupture-mitigation valves as

soon as practicable after identifying a

rupture in accordance with § 192.634;

and

(iii) Operators must achieve complete

segment shut-off and isolation as soon

as practicable after rupture detection but

within 40 minutes of rupture

identification in accordance with

§ 192.634.

(2) Compliance deadlines. The risk

analysis and assessments specified in

paragraph (c) of this section must be

completed prior to placing into service

onshore transmission pipelines

constructed or where 2 or more

contiguous miles have been replaced

after [DATE 12 MONTHS AFTER

EFFECTIVE DATE OF FINAL RULE].

Implementation of risk analysis and

assessment findings for rupture-

mitigation valves must meet § 192.634.

(3) Periodic evaluations. Risk analyses

and assessments conducted under

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paragraph (c) of this section must be

reviewed by the operator for new or

existing operational and integrity

matters that would affect rupture

mitigation on an annual basis, not to

exceed a period of 15 months, or within

3 months of an incident or safety-related

condition, as those terms are defined at

§§ 191.3 and 191.23, respectively, and

certified by the signature of a senior

executive of the company.

* * * * *

PART 195—TRANSPORTATION OF

HAZARDOUS LIQUIDS BY PIPELINE

■10. The authority citation for part 195

continues to read as follows:

Authority: 30 U.S.C. 185(w)(3), 49 U.S.C.

5103, 60101 et seq., and 49 CFR 1.97.

■11. In § 195.2, the definition for

‘‘rupture’’ is added in alphabetical order

to read as follows:

§ 195.2 Definitions.

* * * * *

Rupture means any of the following

events that involve an uncontrolled

release of a large volume of hazardous

liquid or carbon dioxide:

(1) A release of hazardous liquid or

carbon dioxide observed and reported to

the operator by its field personnel,

nearby pipeline or utility personnel, the

public, local responders, or public

authorities, and that may be

representative of an unintentional and

uncontrolled release event defined in

paragraphs (2) or (3) of this definition;

(2) An unanticipated or unplanned

flow rate change of 10 percent or greater

or a pressure loss of 10 percent or

greater, occurring within a time interval

of 15 minutes or less, unless the

operator has documented in advance of

the flow rate change or pressure loss the

need for a higher flow rate change or

higher pressure-change threshold due to

pipeline flow dynamics and terrain

elevation changes that cause

fluctuations in hazardous liquid or

carbon dioxide flow that are typically

higher than a flow rate change or

pressure loss of 10 percent in a time

interval of 15 minutes or less; or

(3) An unexplained flow rate change,

pressure change, instrumentation

indication or equipment function that

may be representative of an event

defined in paragraph (2) of this

definition.

Note: Rupture identification occurs when a

rupture, as defined in this section, is first

observed by or reported to pipeline operating

personnel or a controller.

* * * * *

■12. In § 195.258, paragraph (c) is

added to read as follows:

§ 195.258 Valves: General.

* * * * *

(c) All onshore hazardous liquid or

carbon dioxide pipeline segments with

diameters greater than or equal to 6

inches that are constructed or entirely

replaced after [DATE 12 MONTHS

AFTER EFFECTIVE DATE OF FINAL

RULE] must have automatic shutoff

valves, remote-control valves, or

equivalent technology installed at

intervals meeting the appropriate valve

location and spacing requirements of

this section and § 195.260. An operator

may only install a manual valve under

this paragraph if it can demonstrate to

PHMSA that installing an automatic

shutoff valve, remote-control valve, or

equivalent technology would be

economically, technically, or

operationally infeasible. An operator

installing alternative equivalent

technology or manual valves must

notify PHMSA in accordance with the

procedure at § 195.418(h). Valves and

technology installed under this section

must meet the requirements of

§ 195.418(c), (d), (f), and (g).

■13. In § 195.260, paragraphs (c) and (e)

are revised and paragraphs (g) and (h)

are added to read as follows:

§ 195.260 Valves: Location.

* * * * *

(c) On each mainline at locations

along the pipeline system that will

minimize or prevent safety risks,

property damage, or environmental

harm from accidental hazardous liquid

or carbon dioxide discharges, as

appropriate for onshore areas, offshore

areas, or high consequence areas. For

onshore pipelines constructed or that

have had 2 or more contiguous miles

replaced after [DATE 12 MONTHS

AFTER EFFECTIVE DATE OF FINAL

RULE], mainline valve spacing must not

exceed 15 miles for pipeline segments

that could affect high consequence areas

(as defined in § 195.450) and 20 miles

for pipeline segments that could not

affect high consequence areas. Valves

protecting high consequence areas must

be located as determined by the

operator’s process for identifying

preventive and mitigative measures

established in § 195.452(i) and by using

a process, such as is set forth in Section

I.B of Appendix C of part 195, but with

a maximum distance from the high

consequence area segment endpoints

that does not exceed 7

1

⁄

2

miles.

* * * * *

(e) On each side of a water crossing

that is more than 100 feet (30 meters)

wide from high-water mark to high-

water mark as follows, unless the

Associate Administrator finds under

paragraph (e)(3) of this section that

valves or valve spacing is not necessary

in a particular case to achieve an

equivalent level of safety:

(1) Valves must either be located

outside of the flood plain or have valve

actuators and other control equipment

installed to not be impacted by flood

conditions; and

(2) For multiple water crossings,

valves must be located on the pipeline

upstream and downstream of the first

and last water crossings so that the total

distance between the first upstream

valve and last downstream valve does

not exceed 1 mile.

(3) An operator may notify PHMSA in

accordance with paragraph (h) of this

section if in a particular case the valves

or valve spacing required by this

paragraph is not necessary to achieve an

equivalent level of safety. Unless the

Associate Administrator finds in that

particular case the valves or valve

spacing required by this paragraph are

not necessary to achieve an equivalent

level of safety, the operator must

comply with the valve and valve

spacing requirements of this paragraph.

* * * * *

(g) On each mainline highly volatile

liquid (HVL) pipeline that is located in

a high population area or other

populated area as defined in § 195.450

and that is constructed or that has 2 or

more contiguous miles replaced after

[DATE 12 MONTHS AFTER EFFECTIVE

DATE OF FINAL RULE], with a

maximum valve spacing of 7

1

⁄

2

miles,

unless the Associate Administrator

finds in a particular case that this valve

spacing is not necessary to achieve an

equivalent level of safety. An operator

may notify PHMSA in accordance with

paragraph (h) of this section if in a

particular case the valve spacing

required by this paragraph is not

necessary to achieve an equivalent level

of safety. If the Associate Administrator

informs an operator that PHMSA

objects, the operator must comply with

the valve spacing requirements of this

paragraph.

(h) An operator must provide any

notification required by this section by:

(1) Sending the notification by

electronic mail to

InformationResourcesManager@dot.gov;

or

(2) Sending the notification by mail to

ATTN: Information Resources Manager,

DOT/PHMSA/OPS, East Building, 2nd

Floor, E22–321, 1200 New Jersey Ave.

SE, Washington, DC 20590.

■14. In § 195.402, paragraphs (c)(4), (5),

and (12), and (e)(1), (4), (7), and (10) are

revised to read as follows:

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§ 195.40 2 Procedural manual for

operations, maintenance, and emergencies.

* * * * *

(c) * * *

(4) Determining which pipeline

facilities are in areas that would require

an immediate response by the operator

to prevent hazards to the public,

property, or the environment if the

facilities failed or malfunctioned,

including segments that could affect

high consequence areas and valves

specified in either §§ 195.418 or

195.452(i)(4).

(5) Investigating and analyzing

pipeline accidents and failures,

including sending the failed pipe,

component, or equipment for laboratory

testing or examination where

appropriate, to determine the causes

and contributing factors of the failure

and minimize the possibility of a

recurrence.

(i) Post-incident lessons learned. Each

operator must develop, implement, and

incorporate lessons learned from a post-

accident review into its procedures,

including in pertinent operator

personnel training and qualifications

programs and in design, construction,

testing, maintenance, operations, and

emergency procedure manuals and

specifications.

(ii) Analysis of rupture and valve

shut-offs; preventive and mitigative

measures. If a failure or accident

involves a rupture as defined in § 195.2

or a rupture-mitigation valve closure as

defined in § 195.418, the operator must

also conduct a post-accident analysis of

all factors impacting the release volume

and the consequences of the release, and

identify and implement preventive and

mitigative measures to reduce or limit

the release volume and damage in a

future failure or incident. The analysis

must include all relevant factors

impacting the release volume and

consequences, including, but not

limited to, the following:

(A) Detection, identification,

operational response, system shut-off,

and emergency-response

communications, based on the type and

volume of the release or failure event;

(B) Appropriateness and effectiveness

of procedures and pipeline systems,

including SCADA, communications,

valve shut-off, and operator personnel;

(C) Actual response time from rupture

identification to initiation of mitigative

actions, and the appropriateness and

effectiveness of the mitigative actions

taken;

(D) Location and the timeliness of

actuation of all rupture-mitigation

valves identified under § 195.418; and

(E) All other factors the operator

deems appropriate.

(iii) Rupture post-incident summary.

If a failure or incident involves a

rupture as defined in § 195.2 or the

closure of a rupture-mitigation valve as

defined in § 195.418, the operator must

complete a summary of the post-

accident review required by paragraph

(c)(5)(ii) of this section within 90 days

of the failure or incident, and while the

investigation is pending, conduct

quarterly status reviews until

completed. The post-incident summary

and all other reviews and analyses

produced under the requirements of this

section must be reviewed, dated, and

signed by the appropriate senior

executive officer. The post-incident

summary, all investigation and analysis

documents used to prepare it, and

records of lessons learned must be kept

for the useful life of the pipeline.

* * * * *

(12) Establishing and maintaining

adequate means of communication with

the appropriate public safety answering

point (9–1–1 emergency call center), as

well as fire, police, and other public

officials, to learn the responsibility,

resources, jurisdictional area, and

emergency contact telephone numbers

for both local and out-of-area calls of

each government organization that may

respond to a pipeline emergency, and to

inform the officials about the operator’s

ability to respond to the pipeline

emergency and means of

communication.

* * * * *

(e) * * *

(1) Receiving, identifying, and

classifying notices of events that need

immediate response by the operator or

notice to the appropriate public safety

answering point (9–1–1 emergency call

center), as well as fire, police, and other

appropriate public officials, and

communicating this information to

appropriate operator personnel for

corrective action.

* * * * *

(4) Taking necessary actions,

including but not limited to, emergency

shutdown, valve shut-off, and pressure

reduction, in any section of the

operator’s pipeline system to minimize

hazards of released hazardous liquid or

carbon dioxide to life, property, or the

environment. Each operator installing

valves in accordance with § 195.258(c)

or subject to the requirements in

§ 195.418 must also evaluate and

identify a rupture as defined in § 195.2

as being an actual rupture event or non-

rupture event in accordance with

operating procedures as soon as

practicable but within 10 minutes of the

initial notification to or by the operator,

regardless of how the rupture is initially

detected or observed.

* * * * *

(7) Notifying the appropriate public

safety answering point (9–1–1

emergency call center), as well as fire,

police, and other public officials, of

hazardous liquid or carbon dioxide

pipeline emergencies to coordinate and

share information to determine the

location of the release, including both

planned responses and actual responses

during an emergency, and any

additional precautions necessary for an

emergency involving a pipeline

transporting a highly volatile liquid.

The operator (pipeline controller or the

appropriate operator emergency

response coordinator) must immediately

and directly notify the appropriate

public safety answering point (9–1–1

emergency call center) or other

coordinating agency for the

communities and jurisdictions in which

the pipeline is located after the operator

determines a rupture has occurred when

a release is indicated and valve closure

is implemented.

* * * * *

(10) Actions required to be taken by

a controller during an emergency, in

accordance with the operator’s

emergency plans and §§ 195.418 and

195.446.

* * * * *

■15. Section 195.418 is added to read

as follows:

§ 195.418 Valves: Onshore valve shut-off

for rupture mitigation.

(a) Applicability. For onshore pipeline

segments that could affect high

consequence areas with nominal

diameters of 6 inches or greater, that are

constructed or where 2 or more

contiguous miles are replaced after

[DATE 12 MONTHS AFTER THE

EFFECTIVE DATE OF THE RULE], an

operator must install rupture-mitigation

valves according to the requirements of

this section and § 195.260. Rupture-

mitigation valves must be operational

within 7 days of placing the new or

replaced pipeline segment in service.

(b) Maximum spacing between valves.

Rupture-mitigation valves must be

installed in accordance with the

following requirements:

(1) For purposes of this section, a

‘‘shut-off segment’’ means the segment

of pipe located between the upstream

mainline valve closest to the upstream

high consequence area segment

endpoint and the downstream mainline

valve closest to the downstream high

consequence area segment endpoint so

that the entirety of the segment that

could affect the high consequence area

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is between at least two rupture-

mitigation valves. If any crossover or

lateral pipe for commodity receipts or

deliveries connects to the shut-off

segment between the upstream and

downstream mainline valves, the

segment also extends to the nearest

valve on the crossover connection(s) or

lateral(s), such that, when all valves are

closed, there is no flow path for

commodity to be transported to the

rupture site (except for residual liquids

already in the shut-off segment). All

such valves on a shut-off segment are

‘‘rupture-mitigation valves.’’ Multiple

high consequence areas may be

contained within a single shut-off

segment. All replacement pipeline

segments that are over 2 continuous

miles in length and could affect a high

consequence area must include a

minimum of one mainline valve that

meets the requirements of this section.

The distance between rupture-

mitigation valves in high consequence

areas for each shut-off segment must not

exceed 15 miles, with a maximum

distance not to exceed 7

1

⁄

2

miles from

the endpoints of a shut-off segment.

Valves on lines carrying highly volatile

liquids in high population areas and

other populated areas, as those terms are

defined in § 195.450, must have rupture-

mitigation valves spaced at a maximum

distance not exceeding 7

1

⁄

2

miles.

(2) Lateral lines to shut-off segments

that contribute less than 5 percent of the

total shut-off segment commodity

volume may have lateral rupture-

mitigation valves that meet the

actuation requirements of this section at

locations other than mainline receipt/

delivery points, as long as all of these

laterals contributing hazardous liquid or

carbon dioxide volumes to the shut-off

segment do not contribute more than 5

percent of the total shut-off segment

commodity volume based upon

maximum flow gradients and terrain.

(c) Valve shut-off time for rupture

mitigation. Upon identifying a rupture,

the operator must, as soon as

practicable:

(1) Commence shut-off of the rupture-

mitigation valve or valves that would

have the greatest effect on minimizing

the release volume and other potential

safety and environmental consequences

of the discharge to achieve full rupture-

mitigation valve shut-off within 40

minutes of rupture identification; and

(2) Initiate other mitigative actions

appropriate for the situation to

minimize the release volume and

potential adverse consequences.

(d) Valve shut-off capability. Onshore

rupture-mitigation valves must have

actuation capability (i.e., remote control

shut-off, automatic shut-off, equivalent

technology, or manual shut-off where

personnel are in proximity) to ensure

pipeline ruptures are promptly

mitigated based upon maximum valve

shut-off times, location, and spacing

specified in paragraphs (b) and (c) of

this section to mitigate the volume and

consequence of hazardous liquid or

carbon dioxide released.

(e) Valve shut-off methods. All

onshore rupture-mitigation valves must

be actuated by one of the following

methods to mitigate a rupture as soon as

practicable but within 40 minutes of

rupture identification:

(1) Remote control from a location

that is continuously staffed with

personnel trained in rupture response to

provide immediate shut-off following

identification of a rupture or other

decision to close the valve;

(2) Automatic shut-off following an

identification of a rupture; or

(3) Alternative equivalent technology

that is capable of mitigating a rupture in

accordance with this section.

(4) Manual operation upon

identification of a rupture. Operators

using a manual valve in accordance

with § 195.258 must appropriately

station personnel to ensure valve shut-

off in accordance with paragraph (c) of

this section. Manual operation of valves

must include time for the assembly of

necessary operating personnel,

acquisition of necessary tools and

equipment, driving time under heavy

traffic conditions and at the posted

speed limit, walking time to access the

valve, and time to manually shut off all

valves, not to exceed a 40-minute total

response time in paragraph (c)(1) of this

section.

(f) Valve monitoring and operation

capabilities. Onshore rupture-mitigation

valves actuated by methods in

paragraph (e) of this section must be

capable of being:

(1) Monitored or controlled by either

remote or onsite personnel;

(2) Operated during normal,

abnormal, and emergency operating

conditions;

(3) Monitored for valve status (i.e.,

open, closed, or partial closed/open),

upstream pressure, and downstream

pressure. Pipeline segments that use

manual valve operation must have the

capability to monitor pressures and gas

flow rates on the pipeline to be able to

identify and locate a rupture;

(4) Initiated to close as soon as

practicable after identifying a rupture

and with complete valve shut-off within

40 minutes of rupture identification as

specified in paragraph (c)(1) of this

section; and

(5) Monitored and controlled by

remote personnel or must have a back-

up power source to maintain SCADA or

other remote communications for

remote control shut-off valve or

automatic shut-off valve operational

status.

(g) Monitoring of valve shut-off

response status. Operating control

personnel must continually monitor

rupture-mitigation valve position and

operational status of all rupture-

mitigation valves for the affected shut-

off segment during and after a rupture

event until the pipeline segment is

isolated. Such monitoring must be

maintained through continual electronic

communications with remote

instrumentation or through continual

verbal communication with onsite

personnel stationed at each rupture-

mitigation valve, via telephone, radio, or

equivalent means.

(h) Alternative equivalent technology

or manual valves for onshore rupture

mitigation. If an operator elects to use

alternative equivalent technology or

manual valves in accordance with

§ 195.258(c), the operator must notify

PHMSA at least 90 days in advance of

installation or use in accordance with

§ 195.452(m). The operator must include

a technical and safety evaluation in its

notice to PHMSA, including design,

construction, and operating procedures

for the alternative equivalent technology

or manual valve. Operators installing

manual valves must also demonstrate

that installing an automatic shutoff

valve, a remote-control valve, or

equivalent technology in lieu of a

manual valve would be economically,

technically, or operationally infeasible.

An operator may proceed to use the

alternative equivalent technology or

manual valves 91 days after submitting

the notification unless it receives a letter

from the Associate Administrator of

Pipeline Safety informing the operator

that PHMSA objects to the proposed use

of the alternative equivalent technology

or manual valves or that PHMSA

requires additional time to conduct its

review.

16. In § 195.420, paragraph (b) is

revised and paragraphs (d), (e), and (f)

are added to read as follows:

§ 195.420 Valve maintenance.

* * * * *

(b) Each operator must, at intervals

not exceeding 7

1

⁄

2

months but at least

twice each calendar year, inspect each

mainline valve to determine that it is

functioning properly. Each valve

installed under § 195.258(c) or rupture-

mitigation valve, as defined under

§ 195.418, must also be partially

operated as part of the inspection.

* * * * *

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(d) For each valve installed under

§ 195.258(c) or onshore rupture-

mitigation valve identified under

§ 195.418 that is remote-control shut-off,

automatic shut-off, or that is based on

alternative equivalent technology, the

operator must conduct a point-to-point

verification between SCADA displays

and the mainline valve, sensors, and

communications equipment in

accordance with § 195.446(c) and (e), or

perform an equivalent verification.

(e) For each onshore rupture-

mitigation valve identified under

§ 195.418 that is to be manually or

locally operated:

(1) Operators must establish the 40-

minute total response time as required

by § 195.418 through an initial drill and

through periodic validation as required

by paragraph (e)(2) of this section. Each

phase of the drill response must be

reviewed and the results documented to

validate the total response time,

including valve shut-off, as being less

than or equal to 40 minutes.

(2) A rupture-mitigation valve within

each pipeline system and within each

operating or maintenance field work

unit must be randomly selected for an

annual 40-minute total response time

validation drill simulating worst-case

conditions for that location to ensure

compliance. The response drill must

occur at least once each calendar year,

with intervals not to exceed 15 months.

(3) If the 40-minute maximum

response time cannot be validated or

achieved in the drill, the operator must

revise response efforts to achieve

compliance with § 195.418 no later than

6 months after the drill. Alternative

valve shut-off measures must be in

accordance with paragraph (f) of this

section within 7 days of the drill.

(4) Based on the results of response-

time drills, the operator must include

lessons learned in:

(i) Training and qualifications

programs; and

(ii) Design, construction, testing,

maintenance, operating, and emergency

procedures manuals.

(iii) Any other areas identified by the

operator as needing improvement.

(f) Each operator must take remedial

measures to correct any onshore valve

installed under § 195.258(c) or rupture-

mitigation valve identified under

§ 195.418 that is found inoperable or

unable to maintain shut-off as follows:

(1) Repair or replace the valve as soon

as practicable but no later than 6

months after the finding; and

(2) Designate an alternative compliant

valve within 7 calendar days of the

finding while repairs are being made.

Repairs must be completed within 6

months.

■17. In § 195.452, paragraph (i)(4) is

revised to read as follows:

§ 195.452 Pipeline integrity management in

high consequence areas.

* * * * *

(i) * * *

(4) Emergency Flow Restricting

Devices (EFRD). If an operator

determines that an EFRD is needed on

a pipeline segment to protect a high

consequence area in the event of a

hazardous liquid pipeline release, an

operator must install the EFRD. In

making this determination, an operator

must, at least, consider the following

factors—the swiftness of leak detection

and pipeline shutdown capabilities, the

type of commodity carried, the rate of

potential leakage, the volume that can

be released, topography or pipeline

profile, the potential for ignition,

proximity to power sources, location of

nearest response personnel, specific

terrain between the pipeline segment

and the high consequence area, and

benefits expected by reducing the spill

size.

(i) Where EFRDs are installed to

protect HCAs on all onshore pipelines

with diameters of 6 inches or greater

and that are placed into service or that

have had 2 or more contiguous miles of

pipe replaced after [insert date 12

months after effective date of this rule],

the location, installation, actuation,

operation, and maintenance of such

EFRDs (including valve actuators,

personnel response, operational control

centers, SCADA, communications, and

procedures) must meet the design,

operation, testing, maintenance, and

rupture mitigation requirements of

§§ 195.258, 195.260, 195.402, 195.418,

and 195.420.

(ii) The EFRD analysis and

assessments specified in paragraph (i)(4)

of this section must be completed prior

to placing into service all onshore

pipelines with diameters of 6 inches or

greater and that are constructed or that

have had 2 or more contiguous miles of

pipe replaced after [insert date 12

months after effective date of this rule].

Implementation of EFRD findings for

rupture-mitigation valves must meet

§ 195.418.

* * * * *

Issued in Washington, DC on January 23,

2020, under authority delegated in 49 CFR

part 1.97.

Alan K. Mayberry,

Associate Administrator for Pipeline Safety.

[FR Doc. 2020–01459 Filed 2–5–20; 8:45 am]

BILLING CODE 4910–60–P

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