Pipeline Safety: Overpressure Protection on Low-Pressure Natural Gas Distribution Systems, 61097-61101 [2020-21508]
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Federal Register / Vol. 85, No. 189 / Tuesday, September 29, 2020 / Notices
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electronic submission of responses.
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Chou-Lin Chou,
Associate Administrator, National Center for
Statistics and Analysis.
[FR Doc. 2020–21417 Filed 9–28–20; 8:45 am]
BILLING CODE 4910–59–P
DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials
Safety Administration
[Docket No. PHMSA–2020–0025]
Pipeline Safety: Overpressure
Protection on Low-Pressure Natural
Gas Distribution Systems
Pipeline and Hazardous
Materials Safety Administration
(PHMSA), DOT.
ACTION: Notice; Issuance of advisory
bulletin.
AGENCY:
The Pipeline and Hazardous
Materials Safety Administration
(PHMSA) is issuing this advisory
bulletin to remind owners and operators
of natural gas distribution pipelines of
the possibility of failure due to an
overpressurization on low-pressure
distribution systems. PHMSA is also
reminding such owners and operators of
existing federal integrity management
regulations for gas distribution systems.
ADDRESSES: PHMSA guidance,
including the advisory bulletin, can be
found on PHMSA’s website at https://
www.phmsa.dot.gov/guidance.
FOR FURTHER INFORMATION CONTACT:
Technical Questions: Michael
Thompson, Transportation Specialist,
by phone at 503–883–3495 or by email
at michael.thompson@dot.gov.
General Questions: Ashlin Bollacker,
Technical Writer, by phone at 202–366–
4203 or by email at ashlin.bollacker@
dot.gov.
SUPPLEMENTARY INFORMATION:
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SUMMARY:
I. Natural Gas Distribution Systems
Natural gas distribution systems
deliver natural gas to customers for
heating, cooking, and other domestic
and industrial uses. A basic natural gas
distribution system has four elements:
(1) Mains that transport gas
underground; (2) service lines that
deliver natural gas from the main to the
customer; (3) regulators that control the
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pressure of gas to a designated value;
and (4) meters that measure the quantity
of natural gas used by each customer.
Customer piping takes natural gas from
the meter to the customer’s heating
equipment and other appliances.
There are two types of natural gas
distribution systems used to supply
natural gas to the customer: Highpressure distribution systems and lowpressure distribution systems. In a highpressure distribution system, the gas
pressure in the main is higher than the
pressure provided to the customer. A
pressure regulator installed at each
meter reduces the pressure from the
main to a pressure that can be used by
the customer’s equipment and
appliances. These regulators incorporate
an overpressure protection device to
prevent overpressurization of the
customer’s piping and appliances
should the regulator fail. Additionally,
as of April 14, 2017, all new or replaced
service lines connected to a highpressure distribution system must have
excess flow valves. (§ 192.383).1 Excess
flow valves can reduce the risk of
overpressurization in natural gas
distribution pipelines by shutting off
unplanned, excessive gas flows. Because
each customer’s service line in a highpressure distribution system is
protected by an excess flow valve and
a pressure regulator, it is highly unlikely
that an overpressurization condition in
the main would impact customers.
In a low-pressure natural gas
distribution system, however, the
natural gas in a distribution pipeline
flows predominantly at the same
pressure as the pressure contained
within the customer’s service line
piping. Natural gas is typically supplied
to distribution pipeline mains from a
high-pressure source that connects to,
and flows through, a regulator station.
The regulator station functions to
reduce the pressure to a level that
allows the gas to flow continuously at
a low pressure all the way to premises
of the customers where the gas is
ultimately consumed. Since there are no
regulators at the customer meter set in
a low-pressure system, an overpressure
condition occurring on the distribution
system can affect all customers served
by the system in the event that the
regulator(s) that controls the pressure
for the system fails. This scenario is
1 PHMSA published the final rule, ‘‘Pipeline
Safety: Expanding the Use of Excess Flow Valves
in Gas Distribution Systems to Applications Other
Than Single-Family Residences,’’ on October 14,
2016, but delayed the effective date by six months
to give operators time to comply with the new
provisions. (81 FR 70987). A copy of this final rule
is available in the docket PHMSA–2011–0009 at
https://www.regulations.gov.
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what happened in the September 13,
2018, accident in Merrimack Valley that
prompted the subsequent National
Transportation Safety Board (NTSB)
report and recommendations.
II. CMA’s Accident in Merrimack
Valley
A. Accident Synopsis
On September 13, 2018, a series of
structure fires and explosions occurred
after high-pressure natural gas entered a
low-pressure natural gas distribution
system operated by Columbia Gas of
Massachusetts (CMA), a subsidiary of
NiSource, Inc.2 CMA delivers natural
gas to about 325,000 customers in
Massachusetts. According to an
investigation of the accident conducted
by the National Transportation Safety
Board,3 the fires and explosions
damaged 131 structures, including at
least 5 homes that were destroyed in the
city of Lawrence and the towns of
Andover and North Andover. CMA shut
down the low-pressure natural gas
distribution system serving 10,894
customers, including some outside the
affected area who had their service shut
off as a precaution. An 18-year-old male
was killed when a home exploded, and
the house’s chimney fell onto the
vehicle where he was sitting. Another
person in the vehicle at the time of the
explosion was seriously injured, as was
someone on the second floor of the
house. In total, 22 people, including 3
firefighters, were transported to
hospitals for treatment of their injuries.
B. Background on CMA’s Natural Gas
Main Replacement Project
The low-pressure natural gas
distribution system in the Merrimack
Valley was installed in the early 1900s
and was constructed with cast iron
mains. The system was designed with
14 regulator stations to control the
pressure of natural gas entering the
downstream distribution pipeline
mains. Each regulator station contained
two regulators in series—a ‘‘worker
regulator’’ and a ‘‘monitor regulator’’—
each with a sensing line connected to a
downstream section of main for the
purpose of providing a pressure
measurement back to the regulator
station so that the system could be
maintained at a specified pressure level
of 0.5 pounds per square inch. The
2 CMA is expected to be officially transferred by
NiSource, Inc., to Eversource Energy in November
2020.
3 ‘‘Pipeline Accident Report: Overpressurization
of Natural Gas Distribution System, Explosions, and
Fires in Merrimack Valley, Massachusetts;
September 13, 2018.’’ The National Transportation
Safety Board. Accident Report: NTSB/PAR–19/02.
Adopted September 24, 2019.
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‘‘worker’’ regulator is the primary
regulator that maintains the natural gas
pressure, and the ‘‘monitor’’ regulator
provides a redundant backup to the
‘‘worker’’ regulator. Each of the
regulator stations reduced the natural
gas pressure from about 75 pounds per
square inch gauge (psig) to 12 inches of
water column (w.c.), or about 0.5 psig,
for distribution through the mains and
delivery to customers.4
Beginning in 2016, CMA initiated an
effort to replace 7,595 feet of lowpressure cast iron and bare steel mains
with 4,845 feet of low-pressure and
high-pressure polyethylene (plastic)
mains. CMA contracted with Feeney
Brothers, a pipeline services firm, to
complete the replacement project. A
work package, which included materials
such as isometric drawings and
procedural details for disconnecting and
connecting pipes, was prepared for each
of the planned construction activities.
However, no package was prepared for
the relocation of the Winthrop Avenue
sensing lines serving the Winthrop
Avenue regulator station.
The first stage of the project involved
the installation of the plastic main,
which was completed in late 2016. The
regulator sensing lines at the Winthrop
Avenue regulator station remained
attached to the cast iron main that
would ultimately be decommissioned.
CMA connected the plastic pipe to the
distribution system, which allowed it to
be monitored for pressure changes. The
second stage of the project began in
2018 and involved the installation of
tie-ins to the new plastic main, after
which the legacy cast iron mains would
be decommissioned and abandoned in
their existing location. On the day of the
accident, the sensing lines were still
connected to the abandoned cast iron
main.
At the Winthrop Avenue regulator
station, about 0.5 mile south of the work
area, the sensing lines connected to the
abandoned cast iron mains continued
providing data input to the two pressure
regulators used to control the system
pressure.5 Once the contractor crew
isolated the cast iron main, the natural
gas pressure began to drop in the cast
iron main and the sensing lines
continued to provide those readings to
the regulator station. As the pressure
dropped, the pressure regulators
responded by opening further to inject
more gas to into the downstream system
to the newly installed plastic system.
4 In
the pipeline industry, it is customary to
measure anything less than 1 psig in inches of water
column. A measurement of 1 inch w.c. equals
0.0361 psig.
5 Sensing lines are also called control lines or
static lines.
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Because there were no sensing lines
connecting the regulator station to the
newly installed plastic mains, the legacy
sensing lines continued to provide
‘‘zero’’ pressure readings to Winthrop
Avenue regulators, thereby causing
them to fully open and provide a
continuous flow of gas into the new
low-pressure plastic system, resulting in
an extreme overpressurization of the
distribution system. This immediately
resulted in multiple fires, explosions,
and injuries.
C. National Transportation Safety Board
(NTSB) Accident Investigation and
Recommendations
Since the accident, the National
Transportation Safety Board (NTSB)
issued several safety recommendations.
On November 14, 2018, NTSB
recommended that the operator,
NiSource Inc.:
• Revise the engineering plan and
constructability review process across
all of its subsidiaries to ensure that all
applicable departments review
construction documents for accuracy,
completeness, and correctness, and that
the documents or plans be sealed by a
professional engineer prior to
commencing work (P–18–6);
• Review and ensure that all records
and documentation of its natural gas
systems are traceable, reliable, and
complete (P–18–7);
• Apply management of change
process to all changes to adequately
identify system threats that could result
in a common mode failure (P–18–8);
and
• Develop and implement control
procedures during modifications to gas
mains to mitigate the risks identified
during management of change
operations. Gas main pressures should
be continually monitored during these
modifications and assets should be
placed at critical locations to
immediately shut down the system if
abnormal operations are detected (P–
18–9).
In response, NiSource Inc. has taken
actions that satisfied the NTSB’s
recommendations, which are now
classified as ‘‘Closed.’’
On September 24, 2019, the National
Transportation Safety Board (NTSB)
issued its accident report and identified
the probable cause of, and contributing
factors to, CMA’s accident in Merrimack
Valley. NTSB found that the probable
cause of the accident was CMA’s weak
engineering management that failed to
adequately plan, review, sequence, and
oversee the construction project that
abandoned the cast iron main without
first relocating the regulator sensing
lines to the new plastic main. NTSB also
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found that a contributing cause of the
accident was a low-pressure natural gas
distribution system that was designed
and operated without adequate
overpressure protection. As a result of
its investigation, NTSB made several
recommendations to NiSource, Inc., the
Commonwealth of Massachusetts and
several other States, and PHMSA. NTSB
made two recommendations to PHMSA.
The first (P–19–14) called for PHMSA to
‘‘revise Title 49 Code of Federal
Regulations Part 192 to require
overpressure protection for low-pressure
natural gas distribution systems that
cannot be defeated by a single operator
error or equipment failure.’’ Having
investigated multiple overpressurization
accidents over the past 50 years, NTSB
concluded that low-pressure natural gas
distribution systems that use only
sensing lines and regulators to detect
and prevent overpressurization are not
optimal to prevent overpressurization
accidents.
NTSB’s second recommendation (P–
19–15) called for PHMSA to ‘‘issue an
alert to all low-pressure natural gas
distribution system operators of the
possibility of a failure of overpressure
protection, and the alert should
recommend that operators use a failure
modes and effects analysis (FMEA) or
equivalent structured and systematic
method to identify potential failures and
take action to mitigate those identified
failures.’’ NTSB found that CMA’s
constructability review 6 process was
not sufficiently robust to detect the
omission of a work order to relocate the
sensing lines; and that CMA’s
engineering risk management processes
were deficient. NTSB explained that for
regulator sensing lines, CMA only
considered excavation damage as a risk
to be mitigated. NTSB concluded that a
comprehensive and formal risk
assessment, such as FMEA, would have
identified the human error that caused
the redundant regulators to open and
over pressurize the low-pressure system.
In response to NTSB’s
recommendation P–19–15, PHMSA is
issuing this advisory bulletin to remind
owners and operators of low-pressure
natural gas distribution systems of the
possibility of a failure of overpressure
protection devices. Currently, there are
Federal regulations in place that specify
several minimum safety standards
requiring operators to account for the
possibility of overpressure events in the
6 ‘‘Constructability reviews’’ are a recognized and
generally accepted good engineering practice
commonly used for the execution of professional
design services and are intended to provide an
independent and structured review of construction
plans and specifications to ensure there are no
conflicts, errors, or omissions.
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design and operation of their systems.
Specifically, the Distribution Integrity
Management Program (DIMP)
regulations at 49 CFR 192.1005 require
operators of natural gas distribution
systems to develop and implement an
integrity management program for
pipelines they own, operate, or
maintain. Under DIMP, operators must
identify existing and potential threats to
the integrity of their systems, and to
rank the risks so that known issues can
be evaluated by the risks they pose.
PHMSA agrees with the NTSB that lowpressure distribution system operators
need to be reminded of their obligation
to identify all threats to their systems
and take mitigative measures in
accordance with the risks to their
systems. The diversity of designs and
operating conditions of those systems
mean that the risks associated with
overpressure conditions may be best
managed by a combination of design
elements and engineering practices
tailored to the unique attributes and
conditions of their specific systems that
pipeline operators are best positioned to
identify and implement. Therefore,
PHMSA is reminding operators of lowpressure distribution systems of their
existing obligations under the DIMP
regulations to consider and implement
such tailored approaches to mitigate or
eliminate the risk of an
overpressurization event.
D. Distribution Integrity Management
Program Regulatory Provisions
PHMSA first adopted integrity
management regulations for hazardous
liquid pipelines in 2000, then for gas
transmission pipelines in 2003.
Subsequently, the Pipeline Integrity,
Protection, Enforcement, and Safety Act
of 2006 (PIPES Act of 2006; Pub. L. 109–
468) mandated that PHMSA prescribe
minimum safety standards to extend
integrity management to gas distribution
pipeline systems. The 2006 legislation
directed PHMSA to require operators of
distribution pipelines to identify and
assess risks on their distribution lines,
to remediate conditions that present a
potential threat to pipeline integrity,
and to monitor program effectiveness. In
response to that mandate, PHMSA
implemented new requirements in 49
CFR part 192, subpart P, that rely on
operator-specific programs to improve
the overall integrity of pipeline systems
and reduce risk (74 FR 63905; December
4, 2009). PHMSA concluded that this
performance-based approach was a
more effective method for improving
pipeline system safety—given the
diversity of distribution systems and the
particular threats to which different
systems may each be exposed—than
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imposing a ‘‘one-size-fits-all’’
prescriptive requirement.
The DIMP regulations require
operators of natural gas distribution
systems to develop, write, and
implement an integrity management
program for pipelines they own,
operate, or maintain. An integrity
management plan is a written set of
policies and procedures that each
operator must develop and implement
to ensure compliance. Pursuant to
§ 192.1007,7 an integrity management
plan must include procedures for
implementing the following elements:
• Periodically assess and improve the
integrity management program; and
• Report performance results to
PHMSA and, where applicable, also to
state public utility commissions.
a. Knowledge (192.1007(a)). This
section requires an operator to develop
an understanding of its distribution
pipeline. An operator must identify the
characteristics of its pipeline’s design
and operations, and of the environment
in which it operates, which are
necessary to assess applicable threats
and risks. This must include
considering information gained from
past design, operations, and
maintenance. This section further
requires that operators develop their
understanding from reasonably
available information. Operators have
considerable knowledge of their
pipeline to support routine operations
and maintenance, but this information
may be distributed throughout the
company, in possession of groups
responsible for individual functions.
Operators must assemble this
information to the extent necessary to
support the development and
implementation of their IM program.
PHMSA recognizes that there may be
gaps in the knowledge an operator
possesses when it develops its initial IM
plan. Operators must identify these gaps
and the additional information needed
to improve their understanding.
Operators are required to provide a plan
for gaining that information over time
through the normal activities of
operating and maintaining pipeline
systems (e.g., collecting information
about underlying components when
portions of the pipeline must be
excavated for other reasons). Operators
must also develop a process by which
the program will be periodically
reviewed and refined, as needed.
7 ‘‘Pipeline Safety: Integrity Management Program
for Gas Distribution Pipelines.’’ Final Rule. (74 FR
63905; Dec. 4, 2009). https://
www.federalregister.gov/documents/2009/12/04/E928467/pipeline-safety-integrity-managementprogram-for-gas-distribution-pipelines#h-22
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b. Identify threats ((§ 192.1007(b)).
Identification of the threats that affect,
or could potentially affect, a distribution
pipeline remains critical to ensuring
integrity. Knowledge of applicable
threats allows operators to evaluate the
safety risks they pose and to rank those
risks, allowing safety resources to be
applied where they will be most
effective. This section requires that
operators consider the general categories
of threats that must be reported on
annual reports. Operators are required
to consider reasonably available
information to identify threats that
affect their pipeline or that could
potentially affect it (e.g., landslides in a
hilly area with loose soils even if no
landslide has been experienced). The
section specifies that operators should
minimally consider data sources
resulting from normal operation and
maintenance in evaluating threats.
c. Evaluate and rank risk
(192.1007(c)). This section requires that
an operator evaluate the identified
threats to determine their relative
importance and rank the risks
associated with its pipeline. Operators
must consider the likelihood of threats
and the consequences of a failure that
might result from each threat.
Consideration of consequences is
important to help ensure that risks are
properly ranked. A potential accident of
relatively low probability but that
would produce significant
consequences should be considered to
be of higher risk than an accident with
somewhat greater likelihood, but one
that is not expected to produce major
consequences.
d. Identify and implement measures
to address risks (§ 192.1007(d)). This
section requires operators to determine
and implement measures designed to
reduce the risk of failure of gas
distribution pipeline systems.
e. Measure performance, monitor
results, and evaluate effectiveness
(§ 192.1007(e)). This section requires
operators to develop performance
measures, including some that are
specified for use by all operators.
Measuring performance periodically
enables operators to determine whether
actions being taken to address threats
are effective, or whether different or
additional actions are needed. An
operator must also periodically reevaluate the threats and risks to its gas
distribution pipeline.
f. Periodic evaluation and
improvement (§ 192.1007(f)). This
section requires operators to re-evaluate
risks across the entire pipeline system
periodically and to consider the
relevance of threats in one specific
location as compared to other locations.
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Operators must consider the results of
their performance monitoring in these
evaluations, which must be performed
at least once every five years. An
operator must determine an appropriate
period for conducting a complete
program evaluation based on the
complexity of its system. An operator
should conduct a program evaluation
any time there are changes in factors
that would increase the risk associated
with a failure.
While DIMP regulations have been in
place since 2009, some operators may
not be sufficiently aware of their
pipeline attributes, nor adequately or
consistently assessing threats as part of
their DIMP programs. Early in the
investigation, NTSB determined that
several of NiSource’s engineering
processes were deficient. For example,
the NTSB found that CMA’s inadequate
planning, documentation, and
recordkeeping processes led to the
omission of the relocation of sensing
lines during a construction project.
Further, NTSB found that CMA’s
constructability review process was not
sufficiently robust to detect the
omission of a work order to relocate
sensing lines. It was the abandonment of
the cast iron main without first
relocating the sensing lines that led
directly to the accident. Thus, it is
necessary to identify and evaluate the
physical and operational characteristics
of each pipeline system to evaluate risks
adequately. It is also important that an
operator focus its DIMP on identifying
the conditions that can cause failures
and address them before a failure
occurs. Therefore, PHMSA is reminding
owners and operators of their
continuing obligation to comply with
DIMP regulations and is alerting
operators that PHMSA considers the
possibility of an overpressure protection
failure to be a high-risk threat. PHMSA
reminds operators of low-pressure
systems that they must consider
reasonably available information about
possible threats to their gas distribution
system, including such sources as the
NTSB report, industry publications, and
this advisory bulletin.
As part of the DIMP plans, PHMSA
recommends that operators enhance
their processes and procedures by
including a failure modes and effects
analysis, or equivalent structured and
systematic method of risk analysis.
Including a failure mode and effect
analysis or equivalent methodology can
help identify and mitigate the
possibility of an overpressure failure
event. PHMSA also urges operators to
develop and implement procedures for
construction-related work that are
specific to low-pressure distribution
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systems, such as repairs, uprates in
pressure, or replacement of pipeline or
pressure regulation facilities.
II. Advisory Bulletin (ADB–2020–02)
To: Owners and Operators of Natural
Gas Distribution Systems
Subject: Overpressure Protection on
Low-pressure Natural Gas Distribution
Systems.
Advisory: PHMSA is reminding all
owners and operators of low-pressure
natural gas distribution systems of the
risk of failure of overpressure protection
systems. This advisory bulletin is
intended to clarify for the public
existing pipeline safety standards and
highlight the importance of evaluating
and implementing overpressure
protection design elements and
operational practices within their
compliance programs. The contents of
this advisory bulletin do not have the
force and effect of law. They are not
meant to bind the public in any way,
even as pipeline owners and operators
must comply with the underlying safety
standards.
PHMSA encourages operators to
review the NTSB’s Pipeline Accident
Report concerning Columbia Gas of
Massachusetts’ (CMA)
overpressurization event in the
Merrimack Valley on September 13,
2018. It may be instructive regarding a
host of potential safety problems that
operators of low-pressure natural gas
distribution systems may need to
address. A copy of NTSB’s accident
report is contained within Docket No.
PHMSA–2020–0025 for this advisory
bulletin.
PHMSA also reminds pipeline
operators of their obligations to comply
with the gas DIMP regulations at 49 CFR
part 192, subpart P. Under DIMP, gas
distribution operators must have
knowledge of their pipeline systems;
identify threats to their systems;
evaluate and rank risks; and identify,
evaluate, and implement measures to
address those risks. CMA’s accident in
Massachusetts highlights the need for
operators of low-pressure systems to
review thoroughly their current DIMP
for the threat of overpressurization and
to make any necessary changes or
modifications to become fully compliant
with the Federal Pipeline Safety
Regulations (§ 192.1007(f)).
Written Procedures (§ 192.1005)
Developing and implementing
comprehensive written procedures with
sufficient specificity is one of the most
effective ways to prevent
overpressurization of a low-pressure gas
system. Therefore, PHMSA reminds
operators of low-pressure systems to
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review their written integrity
management plans to help ensure that
they comply with § 192.1005 and to
ensure that they specifically address the
risk of an overpressurization event.
PHMSA further recommends, in
addition to having procedures for
operations, maintenance, and
emergencies (§ 192.605), that operators
develop written procedures for all
activities involving new construction or
pipe replacement projects for lowpressure distribution systems. PHMSA
recommends that these procedures
account for the additional precautions
needed to protect those systems from an
overpressurization event. These
procedures should include:
• Clear roles and responsibilities
across all departments involved in the
planning and execution of construction
or pipe replacement projects;
• Description and delineated scope of
work to be conducted, with a materials
list, necessary schematics, and maps of
the location of the work;
• Requirements to review and ensure
that all records and documentation of
the affected gas system(s) are traceable,
reliable, and complete;
• The sequential process of how the
work is to be carried out and who or
what group is responsible for each step;
• Application of a ‘‘management of
change’’ process to identify all changes
that could threaten system integrity,
particularly where there is a risk
emanating from a common mode of
failure, including a list of individuals
and groups necessary for review along
with their comment and approval before
work commences; and
• Implement a review process
sufficiently robust to detect the
omission of critical process and
procedural steps that could prevent
possible overpressurization events.
Knowledge of Distribution System
(§ 192.1007(a))
PHMSA reminds operators that they
are required to develop procedures in
their DIMP that demonstrate an
understanding of their gas distribution
systems (§ 192.1007(a)). An operator
must identify the characteristics of its
pipeline design and operations, and of
the environment in which it operates, in
the process of assessing applicable
threats and risks. Section 192.1007(a)
requires that operators develop their
understanding from reasonably
available information. This must
include information gained from past
design, operations, and maintenance. If
an operator acquires a pipeline and the
historical records were not obtained or
are not reasonably available, the records
do not need to be re-created. However,
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operators must assemble this
information to the extent necessary to
support the development and
implementation of their integrity
management programs. Underlying
procedures must also identify additional
information necessary to improve their
understanding and provide a plan for
gaining that information over time
through the normal activities of
operating and maintaining pipeline
systems (e.g., collecting information
about buried components when portions
of the pipeline must be excavated for
other reasons). Operators must also
develop a process by which the program
will be periodically reviewed and
refined, as needed. The outcome of the
process should be that all affected
departments of an operator’s
organization are aware of any planned
construction work, have had the
opportunity to review and provide
comments on potential failure modes
and to adopt a process for providing
final approval of construction
procedures.
Identifying Threats and Ranking Risk
(§ 192.1007(b)–(c))
PHMSA reminds operators of their
obligation under DIMP regulations (part
192, subpart P) to consider available
information when identifying all
potential and existing threats to the
integrity of their systems
(§ 192.1007(b)). In accordance with
§ 192.1007(b), operators are required to
consider seven specific threats,
including equipment failure and
incorrect operation. Further, PHMSA
reminds operators to evaluate the risks
associated with their distribution
pipelines, determine the relative
importance of each threat, and rank the
risks posed to their pipeline systems
(§ 192.1007(c)). PHMSA reminds
operators that consideration of
consequences is important to help
ensure that risks are properly ranked. A
potential accident of relatively low
likelihood but one that would produce
significant consequences may be a
higher risk than an accident with
somewhat greater likelihood, but one
that is not expected to produce major
consequences.
Given the catastrophic consequences
of the Merrimack Valley accident,
PHMSA considers the possibility of an
overpressure protection system failure
to be a high-risk threat for low-pressure
distribution systems where there are not
adequate provisions to protect such
systems. Therefore, PHMSA
recommends that operators consider the
single point of failure that could lead to
an overpressurization of a low-pressure
system as a high-risk threat and to
VerDate Sep<11>2014
18:14 Sep 28, 2020
Jkt 250001
review and adjust their DIMP plans
accordingly. NTSB’s Pipeline Accident
Report sufficiently documents the
occurrence of overpressurization of lowpressure distribution systems such that
the threat of overpressurization should
be considered a real and present threat.
If the threat of overpressurization of
low-pressure distribution systems is not
considered an existing threat by an
operator, justification for the
elimination of this threat from
consideration should be documented.
In performing a risk analysis required
by DIMP (§ 192.1007), PHMSA
recommends operators use a failure
modes and effectiveness analysis
(FMEA) model or an equivalent
structured and systematic method to
identify and mitigate risks. Failure
modes and effects analysis (FMEA) is a
generally accepted and recognized
engineering practice used to identify
and assess potential failures, including
common mode failures. As NTSB
concluded, a comprehensive and formal
risk assessment, such as FMEA, would
have identified the human error that
caused the redundant regulators to open
and over-pressurize the low-pressure
system. Operators may already be
leveraging FMEA or other similarly
robust methodologies to perform the
risk analysis and should continue to do
so. PHMSA recommends that operators
consider adopting FMEA or another
qualitative tool that may help to identify
possible failures or consequences of
those failures that would not be
identified otherwise.
Identify and Implement Measures To
Address Risk (§ 192.1007(d))
PHMSA reminds operators that they
must determine and implement
measures designed to reduce the risk of
failure on their pipeline systems
(§ 192.1007(d)). If additional actions
have not been taken to reduce risks,
justification should be documented
(e.g., current overpressure protection
design was determined to be sufficient;
risks were deemed to be low).
There are several ways that operators
can protect low-pressure distribution
systems from overpressure events. Some
notable examples include:
• Installing a full-capacity relief valve
downstream of the low-pressure
regulator station, including in
applications where there is only workermonitor pressure control;
• Installing a ‘‘slam shut’’ device;
• Using telemetered pressure
recordings at district regulator stations
to signal failures immediately to
operators at control centers; and
PO 00000
Frm 00147
Fmt 4703
Sfmt 4703
61101
• Completely and accurately
documenting the location for all control
(i.e., sensing) lines on the system.
Measure Performance, Monitor Results,
and Evaluate Effectiveness
(§ 192.1007(e))
PHMSA reminds operators that they
must monitor performance measures
from an established baseline to evaluate
the effectiveness of DIMP
(§ 192.1007(e)). Section 192.1007(e)(vi)
requires that these performance
measures include any additional
measures determined necessary to
control identified threats. PHMSA
reminds operators to modify their DIMP
as appropriate, considering the potential
failure of overpressure protection
systems as a high-risk threat.
Issued in Washington, DC, on September
24, 2020, under authority delegated in 49
CFR 1.97.
Alan K. Mayberry,
Associate Administrator for Pipeline Safety.
[FR Doc. 2020–21508 Filed 9–28–20; 8:45 am]
BILLING CODE 4910–60–P
DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials
Safety Administration
[Docket No. PHMSA–2020–0115]
Pipeline Safety: Inside Meters and
Regulators
Pipeline and Hazardous
Materials Safety Administration
(PHMSA); DOT.
ACTION: Notice; issuance of advisory
bulletin.
AGENCY:
PHMSA is issuing this
advisory bulletin to alert owners and
operators of natural gas distribution
pipelines to the consequences of failures
of inside meters and regulators. PHMSA
is also reminding operators of existing
Federal regulations covering the
installation and maintenance of inside
meter and regulators, including the
integrity management regulations for
distribution systems to reduce the risks
associated with failures of inside meter
and regulator installations.
ADDRESSES: PHMSA guidance,
including this advisory bulletin, can be
found on PHMSA’s website at https://
www.phmsa.dot.gov/guidance. You may
also view this advisory bulletin and
related documents at https://
www.regulations.gov.
SUMMARY:
FOR FURTHER INFORMATION CONTACT:
Technical Questions: Michael
Thompson, Transportation Specialist,
by phone at 503–883–3495.
E:\FR\FM\29SEN1.SGM
29SEN1
Agencies
[Federal Register Volume 85, Number 189 (Tuesday, September 29, 2020)]
[Notices]
[Pages 61097-61101]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2020-21508]
-----------------------------------------------------------------------
DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials Safety Administration
[Docket No. PHMSA-2020-0025]
Pipeline Safety: Overpressure Protection on Low-Pressure Natural
Gas Distribution Systems
AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA),
DOT.
ACTION: Notice; Issuance of advisory bulletin.
-----------------------------------------------------------------------
SUMMARY: The Pipeline and Hazardous Materials Safety Administration
(PHMSA) is issuing this advisory bulletin to remind owners and
operators of natural gas distribution pipelines of the possibility of
failure due to an overpressurization on low-pressure distribution
systems. PHMSA is also reminding such owners and operators of existing
federal integrity management regulations for gas distribution systems.
ADDRESSES: PHMSA guidance, including the advisory bulletin, can be
found on PHMSA's website at https://www.phmsa.dot.gov/guidance.
FOR FURTHER INFORMATION CONTACT:
Technical Questions: Michael Thompson, Transportation Specialist,
by phone at 503-883-3495 or by email at [email protected].
General Questions: Ashlin Bollacker, Technical Writer, by phone at
202-366-4203 or by email at [email protected].
SUPPLEMENTARY INFORMATION:
I. Natural Gas Distribution Systems
Natural gas distribution systems deliver natural gas to customers
for heating, cooking, and other domestic and industrial uses. A basic
natural gas distribution system has four elements: (1) Mains that
transport gas underground; (2) service lines that deliver natural gas
from the main to the customer; (3) regulators that control the pressure
of gas to a designated value; and (4) meters that measure the quantity
of natural gas used by each customer. Customer piping takes natural gas
from the meter to the customer's heating equipment and other
appliances.
There are two types of natural gas distribution systems used to
supply natural gas to the customer: High-pressure distribution systems
and low-pressure distribution systems. In a high-pressure distribution
system, the gas pressure in the main is higher than the pressure
provided to the customer. A pressure regulator installed at each meter
reduces the pressure from the main to a pressure that can be used by
the customer's equipment and appliances. These regulators incorporate
an overpressure protection device to prevent overpressurization of the
customer's piping and appliances should the regulator fail.
Additionally, as of April 14, 2017, all new or replaced service lines
connected to a high-pressure distribution system must have excess flow
valves. (Sec. 192.383).\1\ Excess flow valves can reduce the risk of
overpressurization in natural gas distribution pipelines by shutting
off unplanned, excessive gas flows. Because each customer's service
line in a high-pressure distribution system is protected by an excess
flow valve and a pressure regulator, it is highly unlikely that an
overpressurization condition in the main would impact customers.
---------------------------------------------------------------------------
\1\ PHMSA published the final rule, ``Pipeline Safety: Expanding
the Use of Excess Flow Valves in Gas Distribution Systems to
Applications Other Than Single-Family Residences,'' on October 14,
2016, but delayed the effective date by six months to give operators
time to comply with the new provisions. (81 FR 70987). A copy of
this final rule is available in the docket PHMSA-2011-0009 at
https://www.regulations.gov.
---------------------------------------------------------------------------
In a low-pressure natural gas distribution system, however, the
natural gas in a distribution pipeline flows predominantly at the same
pressure as the pressure contained within the customer's service line
piping. Natural gas is typically supplied to distribution pipeline
mains from a high-pressure source that connects to, and flows through,
a regulator station. The regulator station functions to reduce the
pressure to a level that allows the gas to flow continuously at a low
pressure all the way to premises of the customers where the gas is
ultimately consumed. Since there are no regulators at the customer
meter set in a low-pressure system, an overpressure condition occurring
on the distribution system can affect all customers served by the
system in the event that the regulator(s) that controls the pressure
for the system fails. This scenario is what happened in the September
13, 2018, accident in Merrimack Valley that prompted the subsequent
National Transportation Safety Board (NTSB) report and recommendations.
II. CMA's Accident in Merrimack Valley
A. Accident Synopsis
On September 13, 2018, a series of structure fires and explosions
occurred after high-pressure natural gas entered a low-pressure natural
gas distribution system operated by Columbia Gas of Massachusetts
(CMA), a subsidiary of NiSource, Inc.\2\ CMA delivers natural gas to
about 325,000 customers in Massachusetts. According to an investigation
of the accident conducted by the National Transportation Safety
Board,\3\ the fires and explosions damaged 131 structures, including at
least 5 homes that were destroyed in the city of Lawrence and the towns
of Andover and North Andover. CMA shut down the low-pressure natural
gas distribution system serving 10,894 customers, including some
outside the affected area who had their service shut off as a
precaution. An 18-year-old male was killed when a home exploded, and
the house's chimney fell onto the vehicle where he was sitting. Another
person in the vehicle at the time of the explosion was seriously
injured, as was someone on the second floor of the house. In total, 22
people, including 3 firefighters, were transported to hospitals for
treatment of their injuries.
---------------------------------------------------------------------------
\2\ CMA is expected to be officially transferred by NiSource,
Inc., to Eversource Energy in November 2020.
\3\ ``Pipeline Accident Report: Overpressurization of Natural
Gas Distribution System, Explosions, and Fires in Merrimack Valley,
Massachusetts; September 13, 2018.'' The National Transportation
Safety Board. Accident Report: NTSB/PAR-19/02. Adopted September 24,
2019.
---------------------------------------------------------------------------
B. Background on CMA's Natural Gas Main Replacement Project
The low-pressure natural gas distribution system in the Merrimack
Valley was installed in the early 1900s and was constructed with cast
iron mains. The system was designed with 14 regulator stations to
control the pressure of natural gas entering the downstream
distribution pipeline mains. Each regulator station contained two
regulators in series--a ``worker regulator'' and a ``monitor
regulator''--each with a sensing line connected to a downstream section
of main for the purpose of providing a pressure measurement back to the
regulator station so that the system could be maintained at a specified
pressure level of 0.5 pounds per square inch. The
[[Page 61098]]
``worker'' regulator is the primary regulator that maintains the
natural gas pressure, and the ``monitor'' regulator provides a
redundant backup to the ``worker'' regulator. Each of the regulator
stations reduced the natural gas pressure from about 75 pounds per
square inch gauge (psig) to 12 inches of water column (w.c.), or about
0.5 psig, for distribution through the mains and delivery to
customers.\4\
---------------------------------------------------------------------------
\4\ In the pipeline industry, it is customary to measure
anything less than 1 psig in inches of water column. A measurement
of 1 inch w.c. equals 0.0361 psig.
---------------------------------------------------------------------------
Beginning in 2016, CMA initiated an effort to replace 7,595 feet of
low-pressure cast iron and bare steel mains with 4,845 feet of low-
pressure and high-pressure polyethylene (plastic) mains. CMA contracted
with Feeney Brothers, a pipeline services firm, to complete the
replacement project. A work package, which included materials such as
isometric drawings and procedural details for disconnecting and
connecting pipes, was prepared for each of the planned construction
activities. However, no package was prepared for the relocation of the
Winthrop Avenue sensing lines serving the Winthrop Avenue regulator
station.
The first stage of the project involved the installation of the
plastic main, which was completed in late 2016. The regulator sensing
lines at the Winthrop Avenue regulator station remained attached to the
cast iron main that would ultimately be decommissioned.
CMA connected the plastic pipe to the distribution system, which
allowed it to be monitored for pressure changes. The second stage of
the project began in 2018 and involved the installation of tie-ins to
the new plastic main, after which the legacy cast iron mains would be
decommissioned and abandoned in their existing location. On the day of
the accident, the sensing lines were still connected to the abandoned
cast iron main.
At the Winthrop Avenue regulator station, about 0.5 mile south of
the work area, the sensing lines connected to the abandoned cast iron
mains continued providing data input to the two pressure regulators
used to control the system pressure.\5\ Once the contractor crew
isolated the cast iron main, the natural gas pressure began to drop in
the cast iron main and the sensing lines continued to provide those
readings to the regulator station. As the pressure dropped, the
pressure regulators responded by opening further to inject more gas to
into the downstream system to the newly installed plastic system.
Because there were no sensing lines connecting the regulator station to
the newly installed plastic mains, the legacy sensing lines continued
to provide ``zero'' pressure readings to Winthrop Avenue regulators,
thereby causing them to fully open and provide a continuous flow of gas
into the new low-pressure plastic system, resulting in an extreme
overpressurization of the distribution system. This immediately
resulted in multiple fires, explosions, and injuries.
---------------------------------------------------------------------------
\5\ Sensing lines are also called control lines or static lines.
---------------------------------------------------------------------------
C. National Transportation Safety Board (NTSB) Accident Investigation
and Recommendations
Since the accident, the National Transportation Safety Board (NTSB)
issued several safety recommendations. On November 14, 2018, NTSB
recommended that the operator, NiSource Inc.:
Revise the engineering plan and constructability review
process across all of its subsidiaries to ensure that all applicable
departments review construction documents for accuracy, completeness,
and correctness, and that the documents or plans be sealed by a
professional engineer prior to commencing work (P-18-6);
Review and ensure that all records and documentation of
its natural gas systems are traceable, reliable, and complete (P-18-7);
Apply management of change process to all changes to
adequately identify system threats that could result in a common mode
failure (P-18-8); and
Develop and implement control procedures during
modifications to gas mains to mitigate the risks identified during
management of change operations. Gas main pressures should be
continually monitored during these modifications and assets should be
placed at critical locations to immediately shut down the system if
abnormal operations are detected (P-18-9).
In response, NiSource Inc. has taken actions that satisfied the
NTSB's recommendations, which are now classified as ``Closed.''
On September 24, 2019, the National Transportation Safety Board
(NTSB) issued its accident report and identified the probable cause of,
and contributing factors to, CMA's accident in Merrimack Valley. NTSB
found that the probable cause of the accident was CMA's weak
engineering management that failed to adequately plan, review,
sequence, and oversee the construction project that abandoned the cast
iron main without first relocating the regulator sensing lines to the
new plastic main. NTSB also found that a contributing cause of the
accident was a low-pressure natural gas distribution system that was
designed and operated without adequate overpressure protection. As a
result of its investigation, NTSB made several recommendations to
NiSource, Inc., the Commonwealth of Massachusetts and several other
States, and PHMSA. NTSB made two recommendations to PHMSA. The first
(P-19-14) called for PHMSA to ``revise Title 49 Code of Federal
Regulations Part 192 to require overpressure protection for low-
pressure natural gas distribution systems that cannot be defeated by a
single operator error or equipment failure.'' Having investigated
multiple overpressurization accidents over the past 50 years, NTSB
concluded that low-pressure natural gas distribution systems that use
only sensing lines and regulators to detect and prevent
overpressurization are not optimal to prevent overpressurization
accidents.
NTSB's second recommendation (P-19-15) called for PHMSA to ``issue
an alert to all low-pressure natural gas distribution system operators
of the possibility of a failure of overpressure protection, and the
alert should recommend that operators use a failure modes and effects
analysis (FMEA) or equivalent structured and systematic method to
identify potential failures and take action to mitigate those
identified failures.'' NTSB found that CMA's constructability review
\6\ process was not sufficiently robust to detect the omission of a
work order to relocate the sensing lines; and that CMA's engineering
risk management processes were deficient. NTSB explained that for
regulator sensing lines, CMA only considered excavation damage as a
risk to be mitigated. NTSB concluded that a comprehensive and formal
risk assessment, such as FMEA, would have identified the human error
that caused the redundant regulators to open and over pressurize the
low-pressure system.
---------------------------------------------------------------------------
\6\ ``Constructability reviews'' are a recognized and generally
accepted good engineering practice commonly used for the execution
of professional design services and are intended to provide an
independent and structured review of construction plans and
specifications to ensure there are no conflicts, errors, or
omissions.
---------------------------------------------------------------------------
In response to NTSB's recommendation P-19-15, PHMSA is issuing this
advisory bulletin to remind owners and operators of low-pressure
natural gas distribution systems of the possibility of a failure of
overpressure protection devices. Currently, there are Federal
regulations in place that specify several minimum safety standards
requiring operators to account for the possibility of overpressure
events in the
[[Page 61099]]
design and operation of their systems. Specifically, the Distribution
Integrity Management Program (DIMP) regulations at 49 CFR 192.1005
require operators of natural gas distribution systems to develop and
implement an integrity management program for pipelines they own,
operate, or maintain. Under DIMP, operators must identify existing and
potential threats to the integrity of their systems, and to rank the
risks so that known issues can be evaluated by the risks they pose.
PHMSA agrees with the NTSB that low-pressure distribution system
operators need to be reminded of their obligation to identify all
threats to their systems and take mitigative measures in accordance
with the risks to their systems. The diversity of designs and operating
conditions of those systems mean that the risks associated with
overpressure conditions may be best managed by a combination of design
elements and engineering practices tailored to the unique attributes
and conditions of their specific systems that pipeline operators are
best positioned to identify and implement. Therefore, PHMSA is
reminding operators of low-pressure distribution systems of their
existing obligations under the DIMP regulations to consider and
implement such tailored approaches to mitigate or eliminate the risk of
an overpressurization event.
D. Distribution Integrity Management Program Regulatory Provisions
PHMSA first adopted integrity management regulations for hazardous
liquid pipelines in 2000, then for gas transmission pipelines in 2003.
Subsequently, the Pipeline Integrity, Protection, Enforcement, and
Safety Act of 2006 (PIPES Act of 2006; Pub. L. 109-468) mandated that
PHMSA prescribe minimum safety standards to extend integrity management
to gas distribution pipeline systems. The 2006 legislation directed
PHMSA to require operators of distribution pipelines to identify and
assess risks on their distribution lines, to remediate conditions that
present a potential threat to pipeline integrity, and to monitor
program effectiveness. In response to that mandate, PHMSA implemented
new requirements in 49 CFR part 192, subpart P, that rely on operator-
specific programs to improve the overall integrity of pipeline systems
and reduce risk (74 FR 63905; December 4, 2009). PHMSA concluded that
this performance-based approach was a more effective method for
improving pipeline system safety--given the diversity of distribution
systems and the particular threats to which different systems may each
be exposed--than imposing a ``one-size-fits-all'' prescriptive
requirement.
The DIMP regulations require operators of natural gas distribution
systems to develop, write, and implement an integrity management
program for pipelines they own, operate, or maintain. An integrity
management plan is a written set of policies and procedures that each
operator must develop and implement to ensure compliance. Pursuant to
Sec. 192.1007,\7\ an integrity management plan must include procedures
for implementing the following elements:
---------------------------------------------------------------------------
\7\ ``Pipeline Safety: Integrity Management Program for Gas
Distribution Pipelines.'' Final Rule. (74 FR 63905; Dec. 4, 2009).
https://www.federalregister.gov/documents/2009/12/04/E9-28467/pipeline-safety-integrity-management-program-for-gas-distribution-pipelines#h-22
---------------------------------------------------------------------------
Periodically assess and improve the integrity management
program; and
Report performance results to PHMSA and, where applicable,
also to state public utility commissions.
a. Knowledge (192.1007(a)). This section requires an operator to
develop an understanding of its distribution pipeline. An operator must
identify the characteristics of its pipeline's design and operations,
and of the environment in which it operates, which are necessary to
assess applicable threats and risks. This must include considering
information gained from past design, operations, and maintenance. This
section further requires that operators develop their understanding
from reasonably available information. Operators have considerable
knowledge of their pipeline to support routine operations and
maintenance, but this information may be distributed throughout the
company, in possession of groups responsible for individual functions.
Operators must assemble this information to the extent necessary to
support the development and implementation of their IM program.
PHMSA recognizes that there may be gaps in the knowledge an
operator possesses when it develops its initial IM plan. Operators must
identify these gaps and the additional information needed to improve
their understanding. Operators are required to provide a plan for
gaining that information over time through the normal activities of
operating and maintaining pipeline systems (e.g., collecting
information about underlying components when portions of the pipeline
must be excavated for other reasons). Operators must also develop a
process by which the program will be periodically reviewed and refined,
as needed.
b. Identify threats ((Sec. 192.1007(b)). Identification of the
threats that affect, or could potentially affect, a distribution
pipeline remains critical to ensuring integrity. Knowledge of
applicable threats allows operators to evaluate the safety risks they
pose and to rank those risks, allowing safety resources to be applied
where they will be most effective. This section requires that operators
consider the general categories of threats that must be reported on
annual reports. Operators are required to consider reasonably available
information to identify threats that affect their pipeline or that
could potentially affect it (e.g., landslides in a hilly area with
loose soils even if no landslide has been experienced). The section
specifies that operators should minimally consider data sources
resulting from normal operation and maintenance in evaluating threats.
c. Evaluate and rank risk (192.1007(c)). This section requires that
an operator evaluate the identified threats to determine their relative
importance and rank the risks associated with its pipeline. Operators
must consider the likelihood of threats and the consequences of a
failure that might result from each threat. Consideration of
consequences is important to help ensure that risks are properly
ranked. A potential accident of relatively low probability but that
would produce significant consequences should be considered to be of
higher risk than an accident with somewhat greater likelihood, but one
that is not expected to produce major consequences.
d. Identify and implement measures to address risks (Sec.
192.1007(d)). This section requires operators to determine and
implement measures designed to reduce the risk of failure of gas
distribution pipeline systems.
e. Measure performance, monitor results, and evaluate effectiveness
(Sec. 192.1007(e)). This section requires operators to develop
performance measures, including some that are specified for use by all
operators. Measuring performance periodically enables operators to
determine whether actions being taken to address threats are effective,
or whether different or additional actions are needed. An operator must
also periodically re-evaluate the threats and risks to its gas
distribution pipeline.
f. Periodic evaluation and improvement (Sec. 192.1007(f)). This
section requires operators to re-evaluate risks across the entire
pipeline system periodically and to consider the relevance of threats
in one specific location as compared to other locations.
[[Page 61100]]
Operators must consider the results of their performance monitoring in
these evaluations, which must be performed at least once every five
years. An operator must determine an appropriate period for conducting
a complete program evaluation based on the complexity of its system. An
operator should conduct a program evaluation any time there are changes
in factors that would increase the risk associated with a failure.
While DIMP regulations have been in place since 2009, some
operators may not be sufficiently aware of their pipeline attributes,
nor adequately or consistently assessing threats as part of their DIMP
programs. Early in the investigation, NTSB determined that several of
NiSource's engineering processes were deficient. For example, the NTSB
found that CMA's inadequate planning, documentation, and recordkeeping
processes led to the omission of the relocation of sensing lines during
a construction project. Further, NTSB found that CMA's constructability
review process was not sufficiently robust to detect the omission of a
work order to relocate sensing lines. It was the abandonment of the
cast iron main without first relocating the sensing lines that led
directly to the accident. Thus, it is necessary to identify and
evaluate the physical and operational characteristics of each pipeline
system to evaluate risks adequately. It is also important that an
operator focus its DIMP on identifying the conditions that can cause
failures and address them before a failure occurs. Therefore, PHMSA is
reminding owners and operators of their continuing obligation to comply
with DIMP regulations and is alerting operators that PHMSA considers
the possibility of an overpressure protection failure to be a high-risk
threat. PHMSA reminds operators of low-pressure systems that they must
consider reasonably available information about possible threats to
their gas distribution system, including such sources as the NTSB
report, industry publications, and this advisory bulletin.
As part of the DIMP plans, PHMSA recommends that operators enhance
their processes and procedures by including a failure modes and effects
analysis, or equivalent structured and systematic method of risk
analysis. Including a failure mode and effect analysis or equivalent
methodology can help identify and mitigate the possibility of an
overpressure failure event. PHMSA also urges operators to develop and
implement procedures for construction-related work that are specific to
low-pressure distribution systems, such as repairs, uprates in
pressure, or replacement of pipeline or pressure regulation facilities.
II. Advisory Bulletin (ADB-2020-02)
To: Owners and Operators of Natural Gas Distribution Systems
Subject: Overpressure Protection on Low-pressure Natural Gas
Distribution Systems.
Advisory: PHMSA is reminding all owners and operators of low-
pressure natural gas distribution systems of the risk of failure of
overpressure protection systems. This advisory bulletin is intended to
clarify for the public existing pipeline safety standards and highlight
the importance of evaluating and implementing overpressure protection
design elements and operational practices within their compliance
programs. The contents of this advisory bulletin do not have the force
and effect of law. They are not meant to bind the public in any way,
even as pipeline owners and operators must comply with the underlying
safety standards.
PHMSA encourages operators to review the NTSB's Pipeline Accident
Report concerning Columbia Gas of Massachusetts' (CMA)
overpressurization event in the Merrimack Valley on September 13, 2018.
It may be instructive regarding a host of potential safety problems
that operators of low-pressure natural gas distribution systems may
need to address. A copy of NTSB's accident report is contained within
Docket No. PHMSA-2020-0025 for this advisory bulletin.
PHMSA also reminds pipeline operators of their obligations to
comply with the gas DIMP regulations at 49 CFR part 192, subpart P.
Under DIMP, gas distribution operators must have knowledge of their
pipeline systems; identify threats to their systems; evaluate and rank
risks; and identify, evaluate, and implement measures to address those
risks. CMA's accident in Massachusetts highlights the need for
operators of low-pressure systems to review thoroughly their current
DIMP for the threat of overpressurization and to make any necessary
changes or modifications to become fully compliant with the Federal
Pipeline Safety Regulations (Sec. 192.1007(f)).
Written Procedures (Sec. 192.1005)
Developing and implementing comprehensive written procedures with
sufficient specificity is one of the most effective ways to prevent
overpressurization of a low-pressure gas system. Therefore, PHMSA
reminds operators of low-pressure systems to review their written
integrity management plans to help ensure that they comply with Sec.
192.1005 and to ensure that they specifically address the risk of an
overpressurization event. PHMSA further recommends, in addition to
having procedures for operations, maintenance, and emergencies (Sec.
192.605), that operators develop written procedures for all activities
involving new construction or pipe replacement projects for low-
pressure distribution systems. PHMSA recommends that these procedures
account for the additional precautions needed to protect those systems
from an overpressurization event. These procedures should include:
Clear roles and responsibilities across all departments
involved in the planning and execution of construction or pipe
replacement projects;
Description and delineated scope of work to be conducted,
with a materials list, necessary schematics, and maps of the location
of the work;
Requirements to review and ensure that all records and
documentation of the affected gas system(s) are traceable, reliable,
and complete;
The sequential process of how the work is to be carried
out and who or what group is responsible for each step;
Application of a ``management of change'' process to
identify all changes that could threaten system integrity, particularly
where there is a risk emanating from a common mode of failure,
including a list of individuals and groups necessary for review along
with their comment and approval before work commences; and
Implement a review process sufficiently robust to detect
the omission of critical process and procedural steps that could
prevent possible overpressurization events.
Knowledge of Distribution System (Sec. 192.1007(a))
PHMSA reminds operators that they are required to develop
procedures in their DIMP that demonstrate an understanding of their gas
distribution systems (Sec. 192.1007(a)). An operator must identify the
characteristics of its pipeline design and operations, and of the
environment in which it operates, in the process of assessing
applicable threats and risks. Section 192.1007(a) requires that
operators develop their understanding from reasonably available
information. This must include information gained from past design,
operations, and maintenance. If an operator acquires a pipeline and the
historical records were not obtained or are not reasonably available,
the records do not need to be re-created. However,
[[Page 61101]]
operators must assemble this information to the extent necessary to
support the development and implementation of their integrity
management programs. Underlying procedures must also identify
additional information necessary to improve their understanding and
provide a plan for gaining that information over time through the
normal activities of operating and maintaining pipeline systems (e.g.,
collecting information about buried components when portions of the
pipeline must be excavated for other reasons). Operators must also
develop a process by which the program will be periodically reviewed
and refined, as needed. The outcome of the process should be that all
affected departments of an operator's organization are aware of any
planned construction work, have had the opportunity to review and
provide comments on potential failure modes and to adopt a process for
providing final approval of construction procedures.
Identifying Threats and Ranking Risk (Sec. 192.1007(b)-(c))
PHMSA reminds operators of their obligation under DIMP regulations
(part 192, subpart P) to consider available information when
identifying all potential and existing threats to the integrity of
their systems (Sec. 192.1007(b)). In accordance with Sec.
192.1007(b), operators are required to consider seven specific threats,
including equipment failure and incorrect operation. Further, PHMSA
reminds operators to evaluate the risks associated with their
distribution pipelines, determine the relative importance of each
threat, and rank the risks posed to their pipeline systems (Sec.
192.1007(c)). PHMSA reminds operators that consideration of
consequences is important to help ensure that risks are properly
ranked. A potential accident of relatively low likelihood but one that
would produce significant consequences may be a higher risk than an
accident with somewhat greater likelihood, but one that is not expected
to produce major consequences.
Given the catastrophic consequences of the Merrimack Valley
accident, PHMSA considers the possibility of an overpressure protection
system failure to be a high-risk threat for low-pressure distribution
systems where there are not adequate provisions to protect such
systems. Therefore, PHMSA recommends that operators consider the single
point of failure that could lead to an overpressurization of a low-
pressure system as a high-risk threat and to review and adjust their
DIMP plans accordingly. NTSB's Pipeline Accident Report sufficiently
documents the occurrence of overpressurization of low-pressure
distribution systems such that the threat of overpressurization should
be considered a real and present threat. If the threat of
overpressurization of low-pressure distribution systems is not
considered an existing threat by an operator, justification for the
elimination of this threat from consideration should be documented.
In performing a risk analysis required by DIMP (Sec. 192.1007),
PHMSA recommends operators use a failure modes and effectiveness
analysis (FMEA) model or an equivalent structured and systematic method
to identify and mitigate risks. Failure modes and effects analysis
(FMEA) is a generally accepted and recognized engineering practice used
to identify and assess potential failures, including common mode
failures. As NTSB concluded, a comprehensive and formal risk
assessment, such as FMEA, would have identified the human error that
caused the redundant regulators to open and over-pressurize the low-
pressure system. Operators may already be leveraging FMEA or other
similarly robust methodologies to perform the risk analysis and should
continue to do so. PHMSA recommends that operators consider adopting
FMEA or another qualitative tool that may help to identify possible
failures or consequences of those failures that would not be identified
otherwise.
Identify and Implement Measures To Address Risk (Sec. 192.1007(d))
PHMSA reminds operators that they must determine and implement
measures designed to reduce the risk of failure on their pipeline
systems (Sec. 192.1007(d)). If additional actions have not been taken
to reduce risks, justification should be documented (e.g., current
overpressure protection design was determined to be sufficient; risks
were deemed to be low).
There are several ways that operators can protect low-pressure
distribution systems from overpressure events. Some notable examples
include:
Installing a full-capacity relief valve downstream of the
low-pressure regulator station, including in applications where there
is only worker-monitor pressure control;
Installing a ``slam shut'' device;
Using telemetered pressure recordings at district
regulator stations to signal failures immediately to operators at
control centers; and
Completely and accurately documenting the location for all
control (i.e., sensing) lines on the system.
Measure Performance, Monitor Results, and Evaluate Effectiveness (Sec.
192.1007(e))
PHMSA reminds operators that they must monitor performance measures
from an established baseline to evaluate the effectiveness of DIMP
(Sec. 192.1007(e)). Section 192.1007(e)(vi) requires that these
performance measures include any additional measures determined
necessary to control identified threats. PHMSA reminds operators to
modify their DIMP as appropriate, considering the potential failure of
overpressure protection systems as a high-risk threat.
Issued in Washington, DC, on September 24, 2020, under authority
delegated in 49 CFR 1.97.
Alan K. Mayberry,
Associate Administrator for Pipeline Safety.
[FR Doc. 2020-21508 Filed 9-28-20; 8:45 am]
BILLING CODE 4910-60-P