[Federal Register Volume 85, Number 25 (Thursday, February 6, 2020)]
[Proposed Rules]
[Pages 7162-7189]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2020-01459]



[[Page 7161]]

Vol. 85

Thursday,

No. 25

February 6, 2020

Part IV





Department of Transportation





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Pipeline and Hazardous Materials Safety Administration





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49 CFR Parts 192 and 195





Pipeline Safety: Valve Installation and Minimum Rupture Detection 
Standards; Proposed Rule

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

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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.

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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

[[Page 7163]]

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.
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    \1\ For brevity, reference to ``hazardous liquid pipelines'' 
through the remainder of this NPRM will include carbon dioxide 
pipelines as well, unless otherwise stipulated.
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    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.
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    \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 Sec.  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.
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    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; 5 6 comments received 
on related topics through advance notices of proposed rulemaking 
(ANPRM); and information gathered at public meetings and workshops.
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    \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.
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    PHMSA believes this approach, as detailed in this NPRM, will help 
reduce the consequences of ruptures through

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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.
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    \7\ ``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.
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    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.
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    \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.
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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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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.
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    \11\ 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.
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    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.\12\ 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

[[Page 7166]]

pipelines in urban and environmentally sensitive areas to provide for 
rapid shutdown of failed pipeline systems (P-95-1).
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    \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.
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    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\
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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.
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    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.
---------------------------------------------------------------------------

    \15\ See www.regulations.gov, dockets PHMSA-2010-0229 and PHMSA-
2011-0023, respectively, for both the ANPRMs and NPRMs.
---------------------------------------------------------------------------

    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\
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    \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).
---------------------------------------------------------------------------

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

[[Page 7167]]

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\
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    \18\ For natural gas and hazardous liquid pipelines, Sec. Sec.  
192.615(a)(3) and 195.402(e)(2), respectively.
    \19\ Requirements for ASV and RCV installation are at Sec.  
192.935(c), and requirements for EFRD installation are at Sec.  
195.452(i)(4).
---------------------------------------------------------------------------

    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 Sec. Sec.  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.
---------------------------------------------------------------------------

    \20\ A break in the pipeline that involves the opening of the 
pipe in either the circumferential or longitudinal direction.
---------------------------------------------------------------------------

    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

[[Page 7168]]

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\
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    \21\ 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)
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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 Sec.  192.13(b) states ``no person may operate a segment of 
pipeline [. . .] that is replaced, relocated, or otherwise

[[Page 7169]]

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 
Sec.  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 Sec.  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.
---------------------------------------------------------------------------

    \24\ In the Matter of Viking Gas Transmission, Final Order, 
C.P.F. No. 32102 (May 1, 1998).
---------------------------------------------------------------------------

    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

[[Page 7170]]

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.
---------------------------------------------------------------------------

    \25\ 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.
---------------------------------------------------------------------------

    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 Sec.  
192.3 for onshore gas transmission pipelines and in Sec.  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\
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    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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 Partnership Act of 1996); September 1999; 
https://rosap.ntl.bts.gov/view/dot/16918/dot_16918_DS1.pdf?.

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[[Page 7171]]

    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.
---------------------------------------------------------------------------

    \32\ As defined in this NPRM, rupture identification occurs when 
a rupture is observed by or reported to pipeline operating personnel 
or a controller.
---------------------------------------------------------------------------

    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'' (Sec. Sec.  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

[[Page 7172]]

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.
---------------------------------------------------------------------------

    \33\ 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.
---------------------------------------------------------------------------

    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

[[Page 7173]]

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.
---------------------------------------------------------------------------

    \35\ ``Pipeline Safety: Standards for Increasing the Maximum 
Allowable Operating Pressure for Gas Transmission Pipelines; Final 
Rule;'' October 17, 2008; 73 FR 62148.
---------------------------------------------------------------------------

    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.

[[Page 7174]]

    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 Sec.  192.745 for onshore gas transmission pipelines and Sec.  
195.420 for onshore hazardous liquid pipelines.

D. Maximum Valve Spacing Distance

i. Gas Transmission Pipelines
    Existing regulations for gas transmission pipelines at Sec.  
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 Sec. Sec.  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 Sec.  192.611(a) for a ``one class 
change bump.'' This allows operators to use the valve spacing required 
in Sec.  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 Sec.  192.179. The Gas Piping Technology 
Committee (GPTC), AGA, INGAA, and several of INGAA's members 
(MidAmerican, Paiute, and Southwest Gas) opposed applying Sec.  192.179 
requirements retroactively to class location changes. Commenters also

[[Page 7175]]

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 Sec.  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 Sec.  
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 Sec.  
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 Sec.  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.
---------------------------------------------------------------------------

    \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 Sec.  
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.
---------------------------------------------------------------------------

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 Sec.  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 (Sec.  
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

[[Page 7176]]

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 Sec. Sec.  
192.179, 192.610 and 192.634 for gas transmission pipelines and 
Sec. Sec.  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 Sec.  
192.935(c) for gas transmission pipelines and Sec.  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\
---------------------------------------------------------------------------

    \38\ Method 1 is defined in Sec.  192.903 HCA definition, 
paragraph (1) as a Class 3 or Class 4 location as those terms are 
defined under Sec.  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 Sec.  
192.903.
---------------------------------------------------------------------------

    PHMSA notes that although Sec.  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

[[Page 7177]]

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 Sec.  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 (Sec.  192.617 for gas 
transmission pipelines and Sec.  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 Sec. Sec.  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

[[Page 7178]]

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 Sec.  192.634 and 
isolate a ruptured pipeline segment within 40 minutes of rupture 
identification. Rupture identification would be defined in Sec.  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 Sec.  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 Sec. Sec.  192.611, 
192.619(a), and 192.620, then the rupture-mitigation valve installation 
requirement in Sec.  192.179 applies for the new class location, which 
may require the operator to install new valves, and the rupture-
mitigation requirements of Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  192.615(a)(6) and meet 
the standard specified in the proposed Sec.  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

[[Page 7179]]

or RCVs installed under this section can comply with the proposed valve 
maintenance requirements at Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec. Sec.  195.418 and 195.452(i)(4).
    PHMSA is also revising Sec.  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 Sec.  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 Sec.  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

[[Page 7180]]

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 Sec.  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 Sec.  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 Sec.  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 Sec.  
195.402 and meet the standard specified in the proposed Sec.  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 Sec. Sec.  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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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:

             Table 1--Annualized Costs of the Proposed Rule
                            [Millions 2015$]
------------------------------------------------------------------------
                                                        7%         3%
                    System type                      Discount   Discount
                                                       rate       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.

[[Page 7181]]

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.

[[Page 7182]]

    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

0
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.

0
2. In Sec.  192.3, the definition of ``rupture'' is added in 
alphabetical order to read as follows:


Sec.  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.
* * * * *
0
3. In Sec.  192.179, paragraph (e) is added to read as follows:


Sec.  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-

[[Page 7183]]

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 Sec.  192.634(h). All valves and technology 
installed under this paragraph must meet the requirements of Sec.  
192.634(c), (d), (f), and (g).
0
4. Section 192.610 is added to read as follows:


Sec.  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 Sec. Sec.  
192.611, 192.619, or 192.620, then the requirements in Sec. Sec.  
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 Sec.  192.611(d).
0
5. In Sec.  192.615, paragraphs (a)(2), (6), (8), and (11), and 
paragraph (c) introductory text are revised to read as follows:


Sec.  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 Sec.  192.179(e) or subject to the 
requirements in Sec.  192.634 must also evaluate and identify a rupture 
as defined in Sec.  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 
Sec. Sec.  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:
* * * * *
0
6. Section 192.617 is revised to read as follows:


Sec.  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 Sec.  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 Sec.  192.3 or the closure of a rupture-mitigation valve as 
defined in Sec.  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 Sec.  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 Sec.  192.3 or the closure of a 
rupture-mitigation valve as defined in Sec.  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.
0
7. Section 192.634 is added to read as follows:


Sec.  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-

[[Page 7184]]

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 Sec.  192.179 when 
mainline valve spacing does not meet Sec.  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 Sec.  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

[[Page 7185]]

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 
Sec.  192.179(e), the operator must notify PHMSA at least 90 days in 
advance of installation or use in accordance with Sec.  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.
0
8. In Sec.  192.745 paragraphs (c), (d), and (e) are added to read as 
follows:


Sec.  192.745   Valve maintenance: Transmission lines.

* * * * *
    (c) For each valve installed under Sec.  192.179(e) and each 
rupture-mitigation valve under Sec.  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 Sec.  192.631(c) and 
(e).
    (d) For each rupture-mitigation valve under Sec.  192.634 that is 
manually or locally operated:
    (1) Operators must establish the 40-minute total response time as 
required by Sec.  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 Sec.  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 Sec.  192.179(e) or any rupture-mitigation valve 
identified in Sec.  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.
0
9. In Sec.  192.935, paragraph (c) is revised to read as follows:


Sec.  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 Sec. Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  192.634.
    (3) Periodic evaluations. Risk analyses and assessments conducted 
under

[[Page 7186]]

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 Sec. Sec.  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

0
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.

0
11. In Sec.  195.2, the definition for ``rupture'' is added in 
alphabetical order to read as follows:


Sec.  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.

* * * * *
0
12. In Sec.  195.258, paragraph (c) is added to read as follows:


Sec.  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 
Sec.  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 Sec.  195.418(h). 
Valves and technology installed under this section must meet the 
requirements of Sec.  195.418(c), (d), (f), and (g).
0
13. In Sec.  195.260, paragraphs (c) and (e) are revised and paragraphs 
(g) and (h) are added to read as follows:


Sec.  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 Sec.  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 Sec.  
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 
Sec.  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 
[email protected]; 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.
0
14. In Sec.  195.402, paragraphs (c)(4), (5), and (12), and (e)(1), 
(4), (7), and (10) are revised to read as follows:

[[Page 7187]]

Sec.  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 Sec. Sec.  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 Sec.  195.2 or a rupture-mitigation valve closure as defined 
in Sec.  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 Sec.  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 Sec.  195.2 or the closure of a 
rupture-mitigation valve as defined in Sec.  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 Sec.  
195.258(c) or subject to the requirements in Sec.  195.418 must also 
evaluate and identify a rupture as defined in Sec.  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 
Sec. Sec.  195.418 and 195.446.
* * * * *
0
15. Section 195.418 is added to read as follows:


Sec.  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 Sec.  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

[[Page 7188]]

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 Sec.  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 Sec.  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 Sec.  195.258(c), the 
operator must notify PHMSA at least 90 days in advance of installation 
or use in accordance with Sec.  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 Sec.  195.420, paragraph (b) is revised and paragraphs (d), 
(e), and (f) are added to read as follows:


Sec.  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 
Sec.  195.258(c) or rupture-mitigation valve, as defined under Sec.  
195.418, must also be partially operated as part of the inspection.
* * * * *

[[Page 7189]]

    (d) For each valve installed under Sec.  195.258(c) or onshore 
rupture-mitigation valve identified under Sec.  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 Sec.  195.446(c) and 
(e), or perform an equivalent verification.
    (e) For each onshore rupture-mitigation valve identified under 
Sec.  195.418 that is to be manually or locally operated:
    (1) Operators must establish the 40-minute total response time as 
required by Sec.  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 Sec.  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 Sec.  195.258(c) or rupture-mitigation 
valve identified under Sec.  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.
0
17. In Sec.  195.452, paragraph (i)(4) is revised to read as follows:


Sec.  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 Sec. Sec.  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 Sec.  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