[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
[[Page 7162]]
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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
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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.
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\15\ See www.regulations.gov, dockets PHMSA-2010-0229 and PHMSA-
2011-0023, respectively, for both the ANPRMs and NPRMs.
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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).
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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.
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\20\ A break in the pipeline that involves the opening of the
pipe in either the circumferential or longitudinal direction.
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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.
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\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.
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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.
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\24\ In the Matter of Viking Gas Transmission, Final Order,
C.P.F. No. 32102 (May 1, 1998).
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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.
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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\
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\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.
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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\
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\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.
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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.
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\39\ PHMSA notes that HVL releases may have similar incident
profiles to natural gas transmission pipelines, as escaping product
can be ignited and cause similar damage via a rupture.
---------------------------------------------------------------------------
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