Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines, 20721-20856 [2016-06382]
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Vol. 81
Friday,
No. 68
April 8, 2016
Part II
Department of Transportation
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Pipeline and Hazardous Materials Safety Administration
49 CFR Parts 191 and 192
Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines;
Proposed Rule
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DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials
Safety Administration
49 CFR Parts 191 and 192
[Docket No. PHMSA–2011–0023]
RIN 2137–AE72
Pipeline Safety: Safety of Gas
Transmission and Gathering Pipelines
Pipeline and Hazardous
Materials Safety Administration
(PHMSA), Department of Transportation
(DOT).
ACTION: Notice of proposed rulemaking.
AGENCY:
This Notice of Proposed
Rulemaking (NPRM) proposes to revise
the Pipeline Safety Regulations
applicable to the safety of onshore gas
transmission and gathering pipelines.
PHMSA proposes changes to the
integrity management (IM) requirements
and proposes changes to address issues
related to non-IM requirements. This
NPRM also proposes modifying the
regulation of onshore gas gathering
lines.
DATES: Persons interested in submitting
written comments on this NPRM must
do so by June 7, 2016.
ADDRESSES: You may submit comments
identified by the docket number
PHMSA–2011–0023 by any of the
following methods:
• Federal eRulemaking Portal: https://
www.regulations.gov. Follow the online
instructions for submitting comments.
• Fax: 1–202–493–2251.
• Mail: Hand Delivery: U.S. DOT
Docket Management System, West
Building Ground Floor, Room W12–140,
1200 New Jersey Avenue SE.,
Washington, DC 20590–0001 between 9
a.m. and 5 p.m., Monday through
Friday, except Federal holidays.
Instructions: If you submit your
comments by mail, submit two copies.
To receive confirmation that PHMSA
received your comments, include a selfaddressed stamped postcard.
Note: Comments are posted without
changes or edits to https://
www.regulations.gov, including any
personal information provided. There is
a privacy statement published on https://
www.regulations.gov.
FOR FURTHER INFORMATION CONTACT:
Mike Israni, by telephone at 202–366–
4571, or by mail at U.S. DOT, PHMSA,
1200 New Jersey Avenue SE., PHP–30,
Washington, DC 20590–0001.
SUPPLEMENTARY INFORMATION:
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SUMMARY:
Outline of This Document
I. Executive Summary
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A. Purpose of the Regulatory Action
B. Summary of the Major Provisions of the
Regulatory Action in Question
C. Costs and Benefits
II. Background
A. Detailed Overview
B. Advance Notice of Proposed
Rulemaking
C. National Transportation Safety Board
Recommendations
D. Pipeline Safety, Regulatory Certainty,
and Job Creation Act of 2011
E. Summary of Each Topic Under
Consideration
F. Integrity Verification Process Workshop
III. Analysis of Comments on the Advance
Notice of Proposed Rulemaking
A. Modifying the Definition of HCA
B. Strengthening Requirements To
Implement Preventive and Mitigative
Measures for Pipeline Segments in HCAs
C. Modifying Repair Criteria
D. Improving Requirements for Collecting,
Validating, and Integrating Pipeline Data
E. Making Requirements Related to the
Nature and Application of Risk Models
More Prescriptive
F. Strengthening Requirements for
Applying Knowledge Gained Through
the IM Program
G. Strengthening Requirements on the
Selection and Use of Assessment
Methods
H. Valve Spacing and the Need for
Remotely or Automatically Controlled
Valves
I. Corrosion Control
J. Pipe Manufactured Using Longitudinal
Weld Seams
K. Establishing Requirements Applicable to
Underground Gas Storage
L. Management of Change
M. Quality Management Systems (QMS)
N. Exemption of Facilities Installed Prior to
the Regulations
O. Modifying the Regulation of Gas
Gathering Lines
IV. Other Proposals
V. Section-by-Section Analysis
VI. Availability of Standards Incorporated by
Reference
VII. Regulatory Analysis and Notices
I. Executive Summary
A. Purpose of the Regulatory Action
PHMSA believes that the current
regulatory requirements applicable to
gas pipeline systems have increased the
level of safety associated with the
transportation of gas. Still, incidents
with significant consequences and
various causes continue to occur on gas
pipeline systems. PHMSA has also
identified concerns during inspections
of gas pipeline operator programs that
indicate a potential need to clarify and
enhance some requirements. Based on
this experience, this NPRM proposes
additional safety measures to increase
the level of safety for those pipelines
that are not in HCAs as well as
clarifications and selected
enhancements to integrity management
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requirements to improve safety in
HCAs.
On August 25, 2011, PHMSA
published an Advance Notice of
Proposed Rulemaking (ANPRM) to seek
feedback and comments regarding the
revision of the Pipeline Safety
Regulations applicable to the safety of
gas transmission and gas gathering
pipelines. In particular, PHMSA
requested comments regarding whether
integrity management (IM) requirements
should be changed and whether other
issues related to system integrity should
be addressed by strengthening or
expanding non-IM requirements.
Subsequent to issuance of the
ANPRM, the National Transportation
Safety Board (NTSB) adopted its report
on the San Bruno accident on August
30, 2011. The NTSB issued safety
recommendations P–11–1 and P–11–2
and P–11–8 through -20 to PHMSA, and
issued safety recommendations P–10–2
through -4 to Pacific Gas & Electric
(PG&E), among others. Several of these
NTSB recommendations related directly
to the topics addressed in the August
25, 2011 ANPRM and have an impact on
the proposed approach to rulemaking.
Also subsequent to issuance of the
ANPRM, the Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011
(the Act) was enacted on January 3,
2012. Several of the Act’s statutory
requirements related directly to the
topics addressed in the August 25, 2011
ANPRM and have an impact on the
proposed approach to rulemaking.
Congress has authorized Federal
regulation of the transportation of gas by
pipeline in the Pipeline Safety Laws (49
U.S.C. 60101 et seq.), a series of statutes
that are administered by the DOT,
PHMSA. PHMSA has used that
authority to promulgate comprehensive
minimum safety standards for the
transportation of gas by pipeline.
Congress established the current
framework for regulating pipelines
transporting gas in the Natural Gas
Pipeline Safety Act of 1968, Public Law
90–481. That law delegated to DOT the
authority to develop, prescribe, and
enforce minimum Federal safety
standards for the transportation of gas,
including natural gas, flammable gas, or
toxic or corrosive gas, by pipeline.
Congress has since enacted additional
legislation that is currently codified in
the Pipeline Safety Laws, including:
In 1992, Congress required regulations be
issued to define the term ‘‘gathering line’’
and establish safety standards for certain
‘‘regulated gathering lines,’’ Public Law 102–
508. In 1996, Congress directed that DOT
conduct demonstration projects evaluating
the application of risk management
principles to pipeline safety regulation, and
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mandated that regulations be issued for the
qualification and testing of certain pipeline
personnel, Public Law 104–304. In 2002,
Congress required that DOT issue regulations
requiring operators of gas transmission
pipelines to conduct risk analyses and to
implement IM programs under which
pipeline segments in high consequence areas
(HCA) would be subject to a baseline
assessment within 10 years and reassessments at least every seven years, and
required that standards be issued for
assessment of pipelines using direct
assessment, Public Law 107–355.
PHMSA plans to address several of
the topics in the ANPRM in separate
rulemakings because of the diverse
scope and nature of several NTSB
recommendations and the statutory
requirements of the Act that were
covered in the ANPRM. This proposed
rule addresses several IM topics,
including: Revision of IM repair criteria
for pipeline segments in HCAs to
address cracking defects, nonimmediate corrosion metal loss
anomalies, and other defects; explicitly
including functional requirements
related to the nature and application of
risk models currently invoked by
reference to industry standards;
explicitly specifying requirements for
collecting, validating, and integrating
pipeline data models currently invoked
by reference to industry standards;
strengthening requirements for applying
knowledge gained through the IM
Program models currently invoked by
reference to industry standards;
strengthening requirements on the
selection and use of direct assessment
methods models by incorporating
recently issued industry standards by
reference; adding requirements for
monitoring gas quality and mitigating
internal corrosion, and adding
requirements for external corrosion
management programs including above
ground surveys, close interval surveys,
and electrical interference surveys; and
explicitly including requirements for
management of change currently
invoked by reference to industry
standards. With respect to non-IM
requirements, this NPRM proposes: A
new ‘‘moderate consequence areas’’
definition; adding requirements for
monitoring gas quality and mitigating
internal corrosion; adding requirements
for external corrosion management
programs including above ground
surveys, close interval surveys, and
electrical interference surveys;
additional requirements for
management of change, including
invoking the requirements of ASME/
ANSI B31.8S, Section 11; establishing
repair criteria for pipeline segments
located in areas not in an HCA; and
requirements for verification of
maximum allowable operating pressure
(MAOP) in accordance with new
§ 192.624 and for verification of
pipeline material in accordance with
new section § 192.607 for certain
onshore, steel, gas transmission
pipelines. This includes establishing
and documenting MAOP if the pipeline
MAOP was established in accordance
with § 192.619(c) or the pipeline meets
other criteria indicating a need for
establishing MAOP.
In addition, this NPRM proposes
modifying the regulation of onshore gas
gathering lines. The proposed
rulemaking would repeal the exemption
for reporting requirements for gas
gathering line operators and repeal the
use of API RP 80 for determining
regulated onshore gathering lines and
add a new definition for ‘‘onshore
production facility/operation’’ and a
revised definition for ‘‘gathering lines.’’
The proposed rulemaking would also
extend certain part 192 regulatory
requirements to Type A lines in Class 1
locations for lines 8 inches or greater.
Requirements that would apply to
previously unregulated pipelines
meeting these criteria would be limited
to damage prevention, corrosion control
(for metallic pipe), public education
program, maximum allowable operating
pressure limits, line markers, and
emergency planning.
This NPRM also proposes
requirements for additional topics that
have arisen since issuance of the
ANPRM. These include: (1) Requiring
inspections by onshore pipeline
operators of areas affected by an extreme
weather event such as a hurricane or
flood, landslide, an earthquake, a
natural disaster, or other similar event;
(2) revising the regulations to allow
extension of the IM 7-year reassessment
interval upon written notice per Section
5 of the Act; (3) adding a requirement
to report each exceedance of the MAOP
that exceeds the margin (build-up)
allowed for operation of pressurelimiting or control devices per Section
23 of the Act; (4) adding requirements
to ensure consideration of seismicity of
the area in identifying and evaluating all
potential threats per Section 29 of the
1 PHMSA plans to initiative separate rulemaking
to address other topics included in the ANPRM and
that would implement other requirements of the
Act and NTSB recommendations.
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B. Summary of the Major Provisions of
the Regulatory Action in Question
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Act; (5) adding regulations to require
safety features on launchers and
receivers for in-line inspection, scraper,
and sphere facilities; and (6)
incorporating consensus standards into
the regulations for assessing the
physical condition of in-service
pipelines using in-line inspection,
internal corrosion direct assessment,
and stress corrosion cracking direct
assessment.
The overall goal of this proposed rule
is to increase the level of safety
associated with the transportation of gas
by proposing requirements to address
the causes of recent incidents with
significant consequences, clarify and
enhance some existing requirements,
and address certain statutory mandates
of the Act and NTSB
recommendations.1
C. Costs and Benefits
Consistent with Executive Orders
12866 and 13563, PHMSA has prepared
an assessment of the benefits and costs
of the proposed rule as well as
reasonable alternatives. PHMSA is
publishing the Preliminary Regulatory
Impact Analysis (PRIA) for this
proposed rule simultaneously with this
document, and it is available in the
docket.
PHMSA estimates the total (15-year)
present value of benefits from the
proposed rule to be approximately
$3,234 to $3,738 million 2 using a 7%
discount rate ($4,050 to $4,663 million
using a 3% discount rate) and the
present value of costs to be
approximately $597 million using a 7%
discount rate ($711 million using a 3%
discount rate). The table below
summarizes the average annual present
value benefits and costs by topic area.
The majority of benefits reflect cost
savings from material verification
(processes to determine maximum
allowable operating pressure for
segments for which records are
inadequate) under the proposed rule
compared to existing regulations; the
range in these benefits reflects different
effectiveness assumptions for estimating
safety benefits. Costs reflect primarily
integrity verification and assessment
costs (pressure tests, inline inspection,
and direct assessments). The proposed
gas gathering regulations account for the
next largest portion of benefits and costs
and primarily reflect safety provisions
and associated risk reductions on
previously unregulated lines.
2 Range reflects uncertainty in defect failure rates
for Topic Area 1.
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SUMMARY OF AVERAGE ANNUAL PRESENT VALUE BENEFITS AND COSTS 1
[Millions; 2015$]
7% discount rate
3% discount rate
Topic area
Benefits
Costs
Benefits
Costs
Re-establish MAOP, verify material properties, and integrity assessments outside
HCAs ............................................................................................................................
Integrity management process clarifications ...................................................................
Management of change process improvement ...............................................................
Corrosion control .............................................................................................................
Pipeline inspection following extreme events ..................................................................
MAOP exceedance reports and records verification .......................................................
Launcher/receiver pressure relief ....................................................................................
Gas gathering regulations ...............................................................................................
$196.9–$230.5
n.e.
1.1
5.5
0.3
n.e.
0.4
11.3
$17.8
2.2
0.7
6.3
0.1
0.2
0.0
12.6
$247.8–$288.6
n.e.
1.2
5.9
0.3
n.e.
0.6
14.2
$22.0
1.3
0.8
7.9
0.1
0.2
0.0
15.1
Total ..........................................................................................................................
215.6–249.2
39.8
270–310.8
47.4
HCA = high consequence area.
MAOP = maximum allowable operating pressure.
n.e. = not estimated.
1 Total over 15-year study period divided by 15. Additional costs to states estimated not to exceed $1.5 million per year. Range of benefits reflects range in estimated defect failure rates.
2 Break even value of benefits, based on the average consequences for incidents in high consequence areas, would equate to less than one
incident averted over the 15-year study period.
For the seven percent discount rate
scenario, approximately 13 percent of
benefits are due to safety benefits from
incidents averted, 82 percent represent
cost savings from MAOP verification in
Topic Area 1, and four percent are
attributable to reductions in greenhouse
gas emissions. (For the three percent
discount rate scenario, these
percentages are approximately 13, 83,
and 3 percent, respectively.)
II. Background
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A. Detailed Overview
Introduction
The significant and expected growth
in the nation’s production and use of
natural gas is placing unprecedented
demands on the nation’s pipeline
system, underscoring the importance of
moving this energy product safely and
efficiently. With changing spatial
patterns of natural gas production and
use and an aging pipeline network,
improved documentation and data
collection are increasingly necessary for
the industry to make reasoned safety
choices and for preserving public
confidence in its ability to do so.
Congress recognized these needs when
passing the Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011,
calling for an examination of a broad
range of issues pertaining to the safety
of the nation’s pipeline network,
including a thorough application of the
risk-based integrity assessment, repair,
and validation system known as
‘‘integrity management’’ (IM).
This proposed rulemaking advances
the goals established by Congress in the
2011 Act, which are consistent with the
emerging needs of the natural gas
pipeline system. This proposed rule also
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advances an important discussion about
the need to adapt and expand risk-based
safety practices in light of changing
markets and a growing national
population whose location choices
increasingly encroach on existing
pipelines. As some severe pipeline
accidents have occurred in areas outside
of high consequence areas (HCA) where
the application of IM principles is not
required, and as gas pipelines continue
to experience failures from causes that
IM was intended to address, this
conversation is increasingly important.
This proposed rule strengthens
protocols for IM, including protocols for
inspections and repairs, and improves
and streamlines information collection
to help drive risk-based identification of
the areas with the greatest safety
deficiencies. Further, this proposed rule
establishes requirements to periodically
assess and extend aspects of IM to
pipeline segments in locations where
the surrounding population is expected
to potentially be at risk from an
incident. Even though these segments
are not within currently defined HCAs,
they could be located in areas with
significant populations where incidents
could have serious consequences. This
change would facilitate prompt
identification and remediation of
potentially hazardous defects and
anomalies while still allowing operators
to make risk-based decisions on where
to allocate their maintenance and repair
resources.
Natural Gas Infrastructure Overview
The U.S. natural gas pipeline network
is designed to transport natural gas to
and from most locations in the lower 48
States. Approximately two-thirds of the
lower 48 States depend almost entirely
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on the interstate transmission pipeline
system for their supplies of natural gas.3
To envision the scope of the nation’s
natural gas pipeline infrastructure, it is
best to consider it in three
interconnected parts that together
transport natural gas from the
production field, where gas is extracted
from underground, to its end users,
where the gas is used as an energy fuel
or chemical feedstock. These three parts
are referred to as gathering,
transmission, and distribution systems.
Because this proposed rule applies only
to gas gathering and transmission lines,
this document will not discuss natural
gas distribution infrastructure and its
associated issues. Currently, there are
over 11,000 miles of onshore gas
gathering pipelines and 297,814 miles of
onshore gas transmission pipelines
throughout the U.S.4
Gas gathering lines are pipelines used
to transport natural gas from production
sites to central collection points, which
are often gas treatment plants where
pipeline-quality gas is separated from
petroleum liquids and various
impurities. Historically, these lines were
of smaller diameters than gas
transmission lines and operated at lower
pressures. However, due to changing
demand factors, some gathering lines
are being constructed with diameters
equal to or larger than typical
transmission lines and are being
operated at much higher pressures.
Transmission pipelines primarily
transport natural gas from gas treatment
3 U.S. Department of Energy, ‘‘Appendix B:
Natural Gas,’’ Quadrennial Energy Review Report:
Energy Transmission, Storage, and Distribution
Infrastructure, p. NG–28, April 2015.
4 US DOT Pipeline and Hazardous Materials
Safety Administration Data as of 9/25/2015.
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plants and gathering systems to bulk
customers, local distribution networks,
and storage facilities. Transmission
pipelines are typically made of steel and
can range in size from several inches to
several feet in diameter. They can
operate over a wide range of pressures,
from relatively low (200 pounds per
square inch) to over 1,500 pounds per
square inch gage (psig). They can
operate within the geographic
boundaries of a single State, or span
hundreds of miles, crossing one or more
State lines.
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Regulatory History
PHMSA and its State partners regulate
pipeline safety for jurisdictional 5 gas
gathering, transmission, and
distribution systems under minimum
Federal safety standards authorized by
statute 6 and codified in the Pipeline
Safety Regulations at 49 CFR parts 190–
199.
Federal regulation of gas pipeline
safety began in 1968 with the creation
of the Office of Pipeline Safety and their
subsequent issuance of interim
minimum Federal safety standards for
gas pipeline facilities and the
transportation of natural and other gas
in accordance with the Natural Gas
Pipeline Safety Act of 1968 (Pub. L. 90–
481). These Federal safety standards
were upgraded several times over the
following decades to address different
aspects of natural gas transportation by
pipeline, including construction
standards, pipeline materials, design
standards, class locations, corrosion
control, and maximum allowable
operating pressure (MAOP).
These original Pipeline Safety
Regulations were not designed with
risk-based regulations in mind. In the
mid-1990s, following models from other
industries such as nuclear power,
PHMSA started to explore whether a
risk-based approach to regulation could
improve safety of the public and the
environment. During this time, PHMSA
found that many operators were
performing forms of IM that varied in
scope and sophistication but that there
were no minimum standards or
requirements.
In response to a hazardous liquid
incident in Bellingham, WA, in 1999
that killed 3 people and a gas
transmission incident in Carlsbad, NM,
in 2000 that killed 12, IM regulations for
gas transmission pipelines were
5 Typically, onshore pipelines involved in the
‘‘transportation of gas’’—see 49 CFR 192.1 and
192.3 for detailed applicability.
6 Title 49, United States Code, Subtitle VIII,
Pipelines, Sections 60101, et. seq.
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finalized in 2004.7 The primary goal of
the 2004 IM regulations was to provide
a structure to operators for focusing
their resources on improving pipeline
integrity in the areas where a failure
would have the greatest impact on
public safety. Further objectives
included accelerating the integrity
assessment of pipelines in HCAs,
improving IM systems within
companies, improving the government’s
ability to review the adequacy of
integrity programs and plans, thus
providing increased public assurance in
pipeline safety.
The IM regulations specify how
pipeline operators must conduct
comprehensive analyses to identify,
prioritize, assess, evaluate, repair, and
validate the integrity of gas transmission
pipelines in HCAs, which are typically
areas where population is highly
concentrated. Currently, approximately
7 percent of onshore gas transmission
pipeline mileage is located in HCAs.
PHMSA and state inspectors review
operators’ written IM programs and
associated records to verify that the
operators have used all available
information about their pipelines to
assess risks and take appropriate actions
to mitigate those risks.
Since the implementation of the IM
regulations more than 10 years ago,
many factors have changed. Most
importantly, sweeping changes in the
natural gas industry have caused
significant shifts in supply and demand,
and the nation’s relatively safe but aging
pipeline network faces increased
pressures from these changes as well as
from the increased exposure caused by
a growing and geographically dispersing
population. Long-identified pipeline
safety issues, some of which IM set out
to address, remain problems. Infrequent
but severe accidents indicate that some
pipelines continue to be vulnerable to
failures stemming from outdated
construction methods or materials.
Some severe pipeline accidents have
occurred in areas outside HCAs where
the application of IM principles is not
required. Gas pipelines continue to
experience failures from causes that IM
was intended to address, such as
corrosion, and the measures currently in
use have not always been effective in
identifying and preventing these causes
of pipeline damage.
There is a pressing need for an
improved strategy to protect the safety
and integrity of the nation’s pipeline
system. Following a significant pipeline
7 [68 FR 69778, Dec. 15, 2003] 49 CFR part 192
[Docket No. RSPA–00–7666; Amendment 192–95]
Pipeline Safety: Pipeline Integrity Management in
High Consequence Areas (Gas Transmission
Pipelines).
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incident in 2010 at San Bruno, CA, in
which 8 people died and more than 50
people were injured, Congress, the
National Transportation Safety Board
(NTSB), and the Government
Accountability Office (GAO) charged
PHMSA with improving IM. Comments
from a 2011 advanced notice of
proposed rulemaking (ANPRM)
suggested there were many commonsense improvements that could be made
to IM, as well as a clear need to extend
certain IM provisions to pipelines not
now covered by the IM regulations. A
large portion of the transmission
pipeline industry has voluntarily
committed to extending certain IM
provisions to non-HCA pipe, which
clearly underscores the common
understanding of the need for this
strategy.
Through this proposed rule, PHMSA
is taking action to deliver a
comprehensive strategy to improve gas
transmission pipeline safety and
reliability, through both immediate
improvements to IM and a long-range
review of risk management and
information needs, while also
accounting for a changing landscape
and a changing population.
Supply Changes
The U.S. natural gas industry has
undergone changes of unprecedented
magnitude and pace, increasing
production by 33 percent between 2005
and 2013, from 19.5 trillion cubic feet
per year to 25.7 trillion cubic feet per
year.8 Driving these changes has been a
shift towards the production of
‘‘unconventional’’ natural gas supplies
using improved technology to extract
gas from low permeability shales. The
increased use of directional drilling and
improvements to a long-existing
industrial technique—hydraulic
fracturing, which began as an
experiment in 1947—made the recovery
of unconventional natural gas easier and
economically viable. This shift in
production has decreased prices and
spurred tremendous increases in the use
of natural gas.
While conventional natural gas
production in the U.S. has fallen over
the past decade by about 14 billion
cubic feet per day, overall natural gas
production has grown due to increased
unconventional shale gas production. In
2004, unconventional shale gas
accounted for about 5 percent of the
total natural gas production in the U.S.
Since then, unconventional shale gas
8 U.S. Department of Energy, ‘‘Appendix B:
Natural Gas,’’ Quadrennial Energy Review Report:
Energy Transmission, Storage, and Distribution
Infrastructure, p. NG–2, April 2015.
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liquefied natural gas exporting terminals
in the U.S. and British Columbia,
Canada, are projected to demand
between 5.1 Bcf/d and 8.3 Bcf/d of gas
by 2030.21
nation’s growing population while
helping reduce greenhouse gas
emissions, and American industries are
taking advantage of cheap energy by
investing in onshore production
capacity, while also exploring economic
opportunities for international energy
export.
Plentiful domestic natural gas supply
and comparatively low natural gas
prices have changed the economics of
electric power markets.17 Further, new
environmental standards at the local,
state, regional, and Federal levels have
encouraged switching to fuels with
lower emissions profiles, including
natural gas and renewables. U.S. natural
gas consumption for power generation
grew from 15.8 billion cubic feet per day
(Bcf/d) in 2005 to 22.2 Bcf/d in 2013,
and demand is projected to increase by
another 8.9 Bcf/d by 2030.18 Net gasfired electricity generation increased 73
percent nationally from 2003 to 2013,
and natural gas-fired power plants
accounted for more than 50 percent of
new utility-scale generating capacity
Demand Changes
added in 2013. To accommodate
The recent increase in domestic
continued future growth in natural gasnatural gas production has led to
fueled power, changes in pipeline
decreased gas price volatility and lower infrastructure will be needed, including
average prices.13 In 2004, the outlook for reversals of existing pipelines;
natural gas production and demand
additional lines to gas-fired generators;
growth was weak. Monthly average spot looping of the existing network, where
prices at Henry Hub 14 were high,
pipelines are laid parallel to one another
fluctuating between $4 per million
along a single right-of-way to increase
British thermal units (Btu) and $7 per
capacity; and potentially new pipelines
million Btu. Prices rose above $11 per
as well.
Further, the increased availability of
million Btu for several months in both
low-cost natural gas has brought jobs
2005 and 2008.15 Since 2008, after
back to American soil, and increasing
production shifted to onshore
investment in projects designed to take
unconventional shale resources, and
advantage of the significant increase in
price volatility fell away following the
supplies of low-cost gas available in the
Great Recession, natural gas has traded
U.S. suggests this trend will continue.19
between about $2 per million Btu and
Moreover, low domestic prices and high
$5 per million Btu.16
international prices have made natural
These historically low prices for this
gas export increasingly attractive to
commodity are fueling tremendous
American businesses. The Federal
consumption growth and changes in
Energy Regulatory Commission, as of
markets and spatial patterns of
September 2015, estimated U.S. LNG
consumption. A shift towards natural
prices at $2.25–$2.41 per million Btu,
gas-fueled electric power generation is
while prices in areas of Asia, Europe,
helping to serve the needs of the
and South America ranged from $6.30 to
9 Id., at NG–7.
$7.62 per million Btu.20 Due to high
10 Id.
capital investment barriers and
11 Id., at NG–6.
coordination difficulties between
12 Id.
pipeline shippers, the maritime
13 Id., at NG–11.
shipping industry, and pipeline
14 Henry Hub is a Louisiana natural gas
distribution hub where conventional Gulf of Mexico operators, there are not enough ships
natural gas can be directed to gas transmission lines and processing facilities to transport
running to different parts of the country. Gas bought enough LNG to equalize prices. Taking
and sold at the Henry hub serves as the national
advantage of these price differentials,
benchmark for U.S. natural gas prices. (Id., at NG–
Increasing Pressures on the Existing
Pipeline System Due to Supply and
Demand Changes
Despite the significant increase in
domestic gas production, the
widespread distribution of domestic gas
demand, combined with significant
flexibility and capacity in the existing
transmission system, mitigates the level
of pipeline expansion and investment
required to accommodate growing and
shifting demand. Some of the new gas
production is located near existing or
emerging sources of demand, which
reduces the need for additional natural
gas pipeline infrastructure. In many
instances where new natural gas
pipelines are needed, the network is
being expanded by participants
pursuing lowest-cost options to move
product to market—often making
investments to enhance network
capacity on existing lines rather than
increasing coverage through new
infrastructure. Where this capacity is
not increasing via additional mileage, it
is increasing through larger pipeline
diameters or higher operating pressures.
In short, the nation’s existing, and in
many cases, aging, pipeline system is
facing the full brunt of this dramatic
increase in natural gas supply and the
shifting energy needs of the country.
The U.S. Energy Information
Administration estimates that between
2004 and 2013, the natural gas industry
spent about $56 billion expanding the
natural gas pipeline network. Between
2008 and 2013, pipeline capacity
additions totaled more than 110 Bcf/d.22
Despite this increase in capacity, gas
transmission mileage decreased from
299,358 miles in 2010 to 298,287 miles
in 2013.
Building new infrastructure, or
replacing and modernizing old
infrastructure, is expensive and requires
a long lead-time for planning.
Frequently, the most inexpensive way to
move new production to demand
centers is by using available existing
infrastructure. For several reasons, the
U.S.’s extensive pre-existing gas
network is currently underutilized: (1)
Pipelines are long-lived assets that
reflect historic supply and demand
trends; (2) pipelines often are sized to
meet high initial production levels and
29, NG–30).
15 Energy Information Administration, Natural
Gas Spot and Futures Prices, https://www.eia.gov/
dnav/ng/ng_pri_fut_s1_m.htm, retrieved 14 October
2015.
16 Id., at NG–11.
21 U.S. Department of Energy, ‘‘Appendix B:
Natural Gas,’’ Quadrennial Energy Review Report:
Energy Transmission, Storage, and Distribution
Infrastructure, p. NG–11, April 2015.
22 Id., at NG–31.
production has increased more than
tenfold from 2.7 Bcf/d to about 35.0 Bcf/
d in 2014 9 and now accounts for about
half of overall gas production in the
U.S.10
This increase in unconventional
natural gas production shifted
production away from traditional gasrich regions towards onshore shale gas
regions. In 2004, the Gulf of Mexico
produced about 20 percent of the
nation’s natural gas supply, but by2013,
that number had fallen to 5 percent.
During that same time, Pennsylvania’s
share of production grew from 1 percent
to 13 percent. An analysis conducted by
the Department of Energy’s (DOE) Office
of Energy Policy and Systems Analysis
projects that the most significant
increases in production through 2030
will occur in the Marcellus and Utica
Basins in the Appalachian Basin,11
which will continue to fuel growth in
natural gas production from current
levels of 66.5 Bcf/d to more than 93.5
Bcf/d.12
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17 Id.,
at NG–9.
18 Id.
19 Id.,
at NG–10.
20 https://www.ferc.gov/market-oversight/mkt-
gas/overview/ngas-ovr-lng-wld-pr-est.pdf.
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have excess long-term capacity due to
changing economics; and (3) pipelines
that were built specifically to provide
gas to residential and commercial
consumers in cold-weather regions but
not for power generation are often
under-utilized during off-peak seasons.
In cases where utilization of the
existing pipeline network is high, the
next most cost-effective solution is to
add capacity to existing lines via
compression. While this is technically a
form of infrastructure investment, it is
less costly, faster, and simpler for
market participants in comparison to
building a new pipeline. Adding
compression, however, may raise
average pipeline operating pressures,
exposing previously hidden defects.
Developers also recognize that
building new pipelines is challenging
due to societal fears and cost, so new
pipelines are typically designed in such
a way that they can handle additional
capacity if needed. In New England,
new pipeline projects have been
proposed to address pending supply
constraints and higher prices. However,
public acceptance presents a substantial
challenge to natural gas pipeline
development. Investments and
proposals to pay for new natural gas
transmission pipeline capacity and
services often face significant challenges
in determining feasible rights of way
and developing community support for
the projects.
Data Challenges
Because there is so much emphasis on
using the existing pipeline system to
meet the country’s energy needs, it is
increasingly important for that system to
be safe and efficient. In order to keep
the public safe and to assure the
nation’s energy security, operators and
regulators must have an intimate
understanding of the threats to and
operations of the entire pipeline system.
Data gathering and integration are
important elements of good IM
practices, and while many strides have
been made over the years to collect
more and better data, several data gaps
still exist. Ironically, the comparatively
positive safety record of the nation’s
pipeline system to date makes it harder
to quantify some of these gaps. Over the
20-year period of 1995–2014,
transmission facilities accounted for 42
fatalities and 174 injuries, or about oneseventh of the total fatalities and
injuries on the nation’s natural gas
pipeline system.23 Over the 4-year
period of 2011–2014, there was only 1
23 PHMSA, Pipeline Incident 20-Year Trends,
https://www.phmsa.dot.gov/pipeline/library/datastats/pipelineincidenttrends.
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transmission-related fatality.
Fortunately, there have been only
limited ‘‘worst-case scenarios’’ to
evaluate for cost/benefit analysis of
measures to improve safety, so there are
limited bases for projecting the possible
impacts of low-probability, highconsequence events.
On September 9, 2010, a 30-inchdiameter segment of an intrastate
natural gas transmission pipeline owned
and operated by the Pacific Gas and
Electric Company ruptured in a
residential area of San Bruno,
California. The rupture produced a
crater about 72 feet long by 26 feet wide.
The section of pipe that ruptured, which
was about 28 feet long and weighed
about 3,000 pounds, was found 100 feet
south of the crater. The natural gas that
was released subsequently ignited,
resulting in a fire that destroyed 38
homes and damaged 70. Eight people
were killed, many were injured, and
many more were evacuated from the
area.
The San Bruno incident exposed
several problems in the way data on
pipeline conditions is collected and
managed, showing that many operators
have inadequate records regarding the
physical and operational characteristics
of their pipelines. Many of these records
are necessary for the correct setting and
validation of MAOP, which is critically
important for providing an appropriate
margin of safety to the public.
Much of operator and PHMSA’s data
is obtained through testing and
inspection under IM requirements.
However, this testing can be expensive,
and the approaches to obtaining data
that are most efficient over the long term
may require significant upfront costs to
modernize pipes and make them
suitable for automated inspection. As a
result, there continue to be data gaps
that make it hard to fully understand the
risks to and the integrity of the nation’s
pipeline system.
To assess a pipeline’s integrity,
operators generally choose between
three methods of testing a pipeline:
Inline inspection (ILI), pressure testing,
and direct assessment (DA). There is a
marked difference in the distribution of
assessment methods between interstate
and intrastate pipelines. In 2013, we
estimate that about two-thirds of
interstate pipeline mileage was suitable
for in-line inspection, compared to only
about half of intrastate pipeline mileage.
Because a larger percentage of intrastate
pipelines are unable to accommodate ILI
tools, intrastate operators use more
pressure testing and DA than interstate
operators.
ILIs are performed by using special
tools, sometimes referred to as ‘‘smart
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pigs,’’ which are usually pushed
through a pipeline by the pressure of the
product being transported. As the tool
travels through the pipeline, it identifies
and records potential pipe defects or
anomalies. Because these tests can be
performed with product in the pipeline,
the pipeline does not have to be taken
out of service for testing to occur, which
can prevent excessive cost to the
operator and possible service
disruptions to consumers. Further, ILI is
a non-destructive testing technique, and
it can be less costly on a per-unit basis
to perform than other assessment
methods.
Pressure tests are typically used by
pipeline operators as a means to
determine the integrity (or strength) of
the pipeline immediately after
construction and before placing the
pipeline in service, as well as
periodically during a pipeline’s
operating life. In a pressure test, a test
medium inside the pipeline is
pressurized to a level greater than the
normal operating pressure of the
pipeline. This test pressure is held for
a number of hours to ensure there are
no leaks in the pipeline.
Direct assessment (DA) is the
evaluation of various locations on a
pipeline for corrosion threats. Operators
will review records, indirectly inspect
the pipeline, or use mathematical
models and environmental surveys to
find likely locations on a pipeline where
corrosion might be occurring. Areas that
are likely to have suffered from
corrosion are subsequently excavated
and examined. DA can be prohibitively
expensive to use unless targeting
specific locations, which may not give
an accurate representation of the
condition of lengths of entire pipeline
segments.
Ongoing research and industry
response to the ANPRM 24 appear to
indicate that ILI and spike hydrostatic
pressure testing is more effective than
DA for identifying pipe conditions that
are related to stress corrosion cracking
defects. Both regulators and operators
have expressed interest in improving ILI
methods as an alternative to hydrostatic
testing for better risk evaluation and
management of pipeline safety.
Hydrostatic pressure testing can result
in substantial costs, occasional
disruptions in service, and substantial
methane emissions due to the routine
evacuation of natural gas from pipelines
prior to tests. Further, many operators
prefer not to use hydrostatic pressure
tests because it can potentially be a
24 ‘‘Pipeline Safety: Safety of Gas Transmission
Pipelines—Advanced Notice of Proposed
Rulemaking,’’ 76 FR 5308; August 25, 2011.
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destructive method of testing.25 ILI
testing can obtain data along a pipeline
not otherwise obtainable via other
assessment methods, although this
method also has certain limitations.
In this proposed rulemaking, PHMSA
would expand the range of permissible
assessment methods while imposing
new requirements to guide operators’
selection of appropriate methods.
Allowing alternatives to hydrostatic
testing (including ILI technologies),
combined with further research and
development to make ILI testing more
accurate, could help to drive innovation
in pipeline integrity testing
technologies. This could eventually lead
to improved safety and system
reliability through better data collection
and assessment.
Increased and Changing Use, Coupled
With Age, Exposure to Weather, and
Other Factors Can Increase the Risk of
Pipeline Incidents
While the existing pipeline network’s
capacity is expected to bear the brunt of
the increasing demand for natural gas in
this country, due in part due to the
location of new gas resources, new
production patterns are causing unique
concerns for some pipeline operators.
The significant growth of production
outside the Gulf Coast region—
especially in Pennsylvania and Ohio—
is causing a reorientation of the nation’s
transmission pipeline network. The
most significant of these changes will
require reversing flows on pipelines to
move Marcellus and Utica gas to the
southeastern Atlantic region and the
Midwest.
Reversing a pipeline’s flow can cause
added stresses on the system due to
changes in pressure gradients, flow
rates, and product velocity, which can
create new risks of internal corrosion.
Occasional failures on natural gas
transmission pipelines have occurred
after operational changes that include
flow reversals and product changes.
PHMSA has noticed a large number of
recent or proposed flow reversals and
product changes on a number of gas
transmission lines. In response to this
phenomenon, PHMSA issued an
Advisory Bulletin notifying operators of
the potentially significant impacts such
changes may have on the integrity of a
pipeline.26
25 National Transportation Safety Board, ‘‘Pacific
Gas and Electric Company; Natural Gas
Transmission Pipeline Rupture and Fire; San
Bruno, California; September 9, 2010,’’ Pipeline
Accident Report NTSB/PAR–11–01, Page 96, 2011.
26 ‘‘Pipeline Safety: Guidance for Pipeline Flow
Reversals, Product Changes, and Conversion to
Service,’’ ADB PHMSA–2014–0040, 79 FR 56121;
September 18, 2014.
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Further, the rise of shale gas
production is altering not just the
extent, but also the characteristics of the
nation’s gas gathering systems. Gas
fields are being developed in new
geographic areas, thus requiring entirely
new gathering systems and expanded
networks of gathering lines. Producers
are employing gathering lines with
diameters as large as 36 inches and
maximum operating pressures up to
1480 psig, far exceeding historical
design and operating pressure of typical
gathering lines and making them similar
to large transmission lines. Most of
these new gas gathering lines are
unregulated, and PHMSA does not
collect incident data or report annual
data on these unregulated lines.
However, PHMSA is aware of
incidents that show gathering lines are
subject to the same sorts of failures
common to other pipelines that the
agency does regulate. For example, on
November 14, 2008, three homes were
destroyed and one person was injured
when a gas gathering line ruptured in
Grady County, OK. On June 8, 2010, two
workers died when a bulldozer struck a
gas gathering line in Darrouzett, TX, and
on June 29, 2010, three men working on
a gas gathering line in Grady County,
OK, were injured when it ruptured. The
dramatic expansion in natural gas
production and changes in typical
gathering line characteristics require
PHMSA to review its regulatory
approach to gas gathering pipelines to
address new safety and environmental
risks.
In addition to demands placed on the
nation’s pipeline system due to
increased and changing use, there are
many other factors—including recurring
issues that IM was initially developed to
address—that affect the integrity of the
nation’s pipelines.
Data indicate that some pipelines
continue to be vulnerable to issues
stemming from outdated construction
methods or materials. Much of the older
line pipe in the nation’s gas
transmission infrastructure was made
before the 1970s using techniques that
have proven to contain latent defects
due to the manufacturing process. For
example, line pipe manufactured using
low frequency electric resistance
welding is susceptible to seam failure.
Because these manufacturing techniques
were used during the time before the
Federal gas regulations were issued,
many of those pipes are subsequently
exempt from certain regulations, most
notably the requirement to pressure test
the pipeline or otherwise verify its
integrity to establish MAOP. A
substantial amount of this type of pipe
is still in service. The IM regulations
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include specific requirements for
evaluating such pipe if located in HCAs,
but infrequent-yet-severe failures that
are attributed to longitudinal seam
defects continue to occur. The NTSB’s
investigation of the San Bruno incident
determined that the pipe failed due to
a similar defect. Additionally, between
2010 and 2014, fifteen other reportable
incidents were attributed to seam
failures, resulting in over $8 million of
property damage.
The nation’s pipeline system also
faces a greater risk from failure due to
extreme weather events such as
hurricanes, floods, mudslides,
tornadoes, and earthquakes. A 2011
crude oil spill into the Yellowstone
River near Laurel, MT, was caused by
channel migration and river bottom
scour, leaving a large span of the
pipeline exposed to prolonged current
forces and debris washing downstream
in the river. Those external forces
damaged the exposed pipeline. In
October 1994, flooding along the San
Jacinto River led to the failure of eight
hazardous liquid pipelines and also
undermined a number of other
pipelines. The escaping products were
ignited, leading to smoke inhalation and
burn injuries of 547 people. From 2003
to 2013, there were 85 reportable
incidents in which storms or other
severe natural force conditions damaged
pipelines and resulted in their failure.
Operators reported total damages of over
$104M from these incidents. PHMSA
has issued several Advisory Bulletins to
operators warning about extreme
weather events and the consequences of
flooding events, including river scour
and river channel migration.
Considering recent incidents and
many of the factors outlined above,
PHMSA believes IM has led to several
improvements in managing pipeline
safety, yet the agency believes there is
still more to do to improve the safety of
natural gas transmission pipelines and
ensure public confidence.
Challenges to Modernization and
Historical Problems Underscore the
Need for a Clear Strategy To Protect the
Safety and Integrity of the Nation’s
Pipeline System
The current IM program is both a set
of regulations and an overall regulatory
approach to improve pipeline operators’
ability to identify and mitigate the risks
to their pipeline systems. The objectives
of IM are to accelerate and improve the
quality of integrity assessments,
promote more rigorous and systematic
management of integrity, strengthen
oversight, and increase public
confidence. On the operator level, an IM
program consists of multiple
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components, including adopting
procedures and processes to identify
HCAs, determining likely threats to the
pipeline within the HCA, evaluating the
physical integrity of the pipe within the
HCA, and repairing or remediating any
pipeline defects found. Because these
procedures and processes are complex
and interconnected, effective
implementation of an IM program relies
on continual evaluation and data
integration.
The initial definition for HCAs was
finalized on August 6, 2002,27 providing
concentrations of populations with
corridors of protection spanning 300,
660, or 1,000 feet, depending on the
diameter and MAOP of the particular
pipeline.28 In a later NPRM,29 PHMSA
proposed changes to the definition of a
HCA by introducing the concept of a
covered segment, which PHMSA
defined as the length of gas transmission
pipeline that could potentially impact
an HCA.30 Previously, only distances
from the pipeline centerline related to
HCA definitions. PHMSA also proposed
using Potential Impact Circles, Potential
Impact Zones, and Potential Impact
Radii (PIR) to identify covered segments
instead of a fixed corridor width. The
final Gas Transmission Pipeline
Integrity Management Rule,
incorporating the new HCA definition,
was issued on December 15, 2003.31
The incident at San Bruno in 2010
motivated a comprehensive
reexamination of gas transmission
pipeline safety. Congress responded to
concerns in light of the San Bruno
incident by passing the Pipeline Safety,
Regulatory Certainty, and Job Creation
Act of 2011, which directed the DOT to
reexamine many of its safety
requirements, including the expansion
of IM regulations for transmission
pipelines.
Further, both the NTSB and the GAO
issued several recommendations to
27 ‘‘Pipeline Safety: High Consequence Areas for
Gas Transmission Pipelines,’’ Final rule, 67 FR
50824; August 6, 2002.
28 The influence of the existing class location
concept on the early definition of HCAs is evident
from the use of class locations themselves in the
definition, and the use of fixed 660 ft. distances,
which corresponds to the corridor width used in
the class location definition. This concept was later
significantly revised, as discussed later, in favor of
a variable corridor width (referred to as the
Potential Impact Radius) based on case-specific
pipe size and operating pressure.
29 ‘‘Pipeline Safety: Pipeline Integrity
Management in High Consequence Areas (Gas
Transmission Pipelines),’’ Notice of Proposed
Rulemaking, 68 FR 4278; January 28, 2003.
30 HCA and PIR definitions are in 49 CFR
192.903.
31 ‘‘Pipeline Safety: Pipeline Integrity
Management in High Consequence Areas (Gas
Transmission Pipelines),’’ Final rule, 68 FR 69778;
December 15, 2003.
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PHMSA to improve its IM program and
pipeline safety. The NTSB noted, in a
2015 study,32 that IM requirements have
reduced the rate of failures due to
deterioration of pipe welds, corrosion,
and material failures. However, pipeline
incidents in high-consequence areas due
to other factors increased between 2010
and 2013, and the overall occurrence of
gas transmission pipeline incidents in
high-consequence areas has remained
stable. The NTSB also found many types
of basic data necessary to support
comprehensive probabilistic modeling
of pipeline risks are not currently
available.
Many of these mandates and
recommendations caused PHMSA to
evaluate whether IM system
requirements, or elements thereof,
should be expanded beyond HCAs to
afford protection to a larger percentage
of the nation’s population. Additionally,
several of these mandates and
recommendations asked PHMSA to
enhance the existing IM regulations by
addressing MAOP verification,
inadequate operator records, legacy pipe
issues, and inadequate integrity
assessments. Further, PHMSA was
charged with reducing data gaps and
improving data integration, considering
the regulatory framework for gas
gathering systems, and deleting the
‘‘grandfather clause’’ to require all gas
transmission pipelines constructed
before 1970 be subjected to a hydrostatic
spike pressure test. This proposed rule
addresses several of the
recommendations from the 2015 study
including P–15–18 (IM–ILI capability),
P–15–20 (IM–ILI tools), P–15–21 (IM–
Direct Assessments), and P–21 (IM–Data
Integration).
PHMSA Is Delivering a Comprehensive
Strategy To Protect the Nation’s Pipeline
System While Accounting for a
Changing Landscape and a Changing
Population
To address these statutory mandates,
the post-San Bruno NTSB and GAO
recommendations, and other pipeline
safety mandates, PHMSA posed a series
of questions to the public in the context
of an August 2011 ANPRM titled
‘‘Pipeline Safety: Safety of Gas
Transmission Pipelines’’ (PHMSA–
2011–0023). In that document, PHMSA
asked whether the regulations governing
the safety of gas transmission pipelines
needed changing. In particular, PHMSA
asked whether IM requirements should
be changed, including through adding
32 National Transportation Safety Board, ‘‘Safety
Study: Integrity Management of Gas Transmission
Pipelines in High Consequence Areas,’’ NTSB SS–
15/01, January 27, 2015.
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more prescriptive language in some
areas, and whether other issues related
to system integrity should be addressed
by strengthening or expanding non-IM
requirements. Among the specific issues
PHMSA considered concerning IM
requirements were whether the
definition of an HCA should be revised,
and whether additional restrictions
should be placed on the use of specific
pipeline assessment methods. In the
ANPRM, PHMSA also considered
changes to non-IM requirements,
including valve spacing and
installation, corrosion control, and
whether regulations for gathering lines
needed to be modified.
PHMSA received 103 comments in
response to the ANPRM, which are
summarized in more detail later in this
document. Feedback from the ANPRM
helped to identify a series of commonsense improvements to IM, including
improvements to assessment goals such
as integrity verification, MAOP
verification, and material
documentation; clarified repair criteria;
clarified protocol for identifying threats,
risk assessments and management, and
prevention and mitigation measures;
expanded and enhanced corrosion
control; requirements for inspecting
pipelines after incidents of extreme
weather; and new guidance on how to
calculate MAOP in order to set
operating parameters more accurately
and predict the risks of an incident.
Many of these aspects of IM have been
an integral part of PHMSA’s
expectations since the inception of the
IM program. As specified in the first IM
rule, PHMSA expects operators to start
with an IM framework, evolve a more
detailed and comprehensive IM
program, and continually improve their
IM programs as they learn more about
the IM process and the material
condition of their pipelines through
integrity assessments. This NPRM’s
proposals regarding operators’ processes
for implementing IM reflect PHMSA’s
expectations regarding the degree of
progress operators should be making, or
should have made, during the first 10
years of IM program implementation.
To address issues involving the
increased risk posed by larger-diameter,
higher-pressure gathering lines, PHMSA
is proposing to issue requirements for
certain currently unregulated gas
gathering pipelines that are intended to
prevent the most frequent causes of
failure—corrosion and excavation
damage—and to improve emergency
response preparedness. Minimum
Federal safety standards would also
bring an appropriate level of
consistency to the current mix of
regulations that differ from state to state.
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PHMSA believes these proposed
changes will improve the safety and
protection of pipeline workers, the
public, property, and the environment
by improving the detection and
remediation of unsafe conditions,
ensuring that certain currently
unregulated pipelines are subject to
appropriate regulatory oversight, and
speeding mitigation of adverse effects of
pipeline failures. In addition to safety
benefits, the rule is expected to improve
the performance and extend the
economic life of critical pipeline
infrastructure that transports
domestically produced natural gas
energy, thus supporting national
economic and security energy
objectives.
Looking at Risk Beyond HCAs
In addition to the common sense
improvements to IM, responses to the
ANPRM reinforced the importance of
carefully reconsidering the scope of
areas covered by IM. While PHMSA’s
IM program manages risks primarily by
focusing oversight on areas with the
greatest population density, responses
to the ANPRM highlight the imperative
of protecting the safety of communities
throughout the country in light of a
changing landscape of production,
consumption, and product movement
that merits a refreshed look at the
current scope of IM coverage.
In the 2011 Act, Congress required
PHMSA to have pipeline operators
conduct a records verification to ensure
that their records accurately reflect the
physical and operational characteristics
of pipelines in certain HCAs and class
locations, and to confirm the established
MAOP of the pipelines. The results of
that action indicate that problems
similar to the contributing factors of the
San Bruno incident are more
widespread than previously believed,
affecting both HCA and non-HCA
segments. This indicates that a rupture
on the scale of San Bruno, with the
potential to affect populations, the
environment, or commerce, could occur
elsewhere on the nation’s pipeline
system.
In fact, devastating incidents have
occurred outside of HCAs in rural areas
where populations are sparse but
present. On August 19, 2000, a 30-inchdiameter gas transmission pipeline
ruptured adjacent to the Pecos River
near Carlsbad, NM. The released gas
ignited and burned for 55 minutes.
Twelve persons who were camping
under a concrete-decked steel bridge
that supported the pipeline across the
river were killed, and their vehicles
were destroyed. Two nearby steel
suspension bridges for gas pipelines
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crossing the river were damaged
extensively.
On December 14, 2007, two men were
driving in a pickup truck on Interstate
20 near Delhi, LA, when a 30-inch gas
transmission pipeline ruptured. One of
the men was killed, and the other was
injured.
On December 11, 2012, a 20-inchdiameter gas transmission line ruptured
in a sparsely populated area about 106
feet west of Interstate 77 (I–77) in
Sissonville, WV. An area of fire damage
about 820 feet wide extended nearly
1,100 feet along the pipeline right-ofway. Three houses were destroyed by
the fire, and several other houses were
damaged. Reported losses, repairs, and
upgrades from this incident totaled over
$8.5 million, and major transportation
delays occurred. I–77 was closed in both
directions because of the fire and
resulting damage to the road surface.
The northbound lanes were closed for
about 14 hours, and the southbound
lanes were closed for about 19 hours
while the road was resurfaced, causing
delays to both travelers and commercial
shipping.
Because the nation’s population is
growing, moving, and dispersing,
population density is a changing
measure, and we need to be prepared for
further shifts in the coming decades.
The current definition of an HCA uses
building density as a proxy for
approximating the presence of
communities and surrounding
infrastructure. This can be a meaningful
metric for prioritizing implementation
of safety and risk management protocols
for areas where an accident would have
the greatest likelihood of putting human
life in danger, but it is not necessarily
an accurate reflection of whether an
incident will have a significant impact
on people. Requiring assessment and
repair criteria for pipelines that, if
ruptured, could pose a threat to areas
where any people live, work, or
congregate would improve public safety
and would improve public confidence
in the nation’s natural gas pipeline
system.
Feedback from industry indicated that
some pipeline operators are already
moving towards expanding the
protections of IM beyond HCAs. In
2012, the Interstate Natural Gas
Association of America (INGAA) issued
a ‘‘Commitment to Pipeline Safety,’’ 33
33 Letter from Terry D. Boss, Senior Vice
President of Environment, Safety and Operations to
Mike Israni, Pipeline and Hazardous Materials
Safety Administration, U.S. Department of
Transportation, dated January 20, 2012, ‘‘Safety of
Gas Transmission Pipelines, Docket No. PHMSA–
2011–0023.’’ INGAA represents companies that
operate approximately 65 percent of the gas
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underscoring its efforts towards a goal of
zero incidents, a committed safety
culture, a pursuit of constant
improvement, and applying IM
principles on a system-wide basis.
INGAA divides the commitment into
four stages:
• Stage 1—INGAA members will
complete an initial assessment using
some degree of IM on their pipelines,
covering 90% of the population living,
working, or congregating along INGAA
member pipelines, by the end of 2012.
This represents roughly 64% of INGAA
member pipeline mileage, including the
4% of pipelines that are in HCAs.
• Stage 2—By 2020, INGAA members
will consistently and comprehensively
apply IM principles to those pipelines.
• Stage 3—By 2030, INGAA members
will apply IM principles to pipelines,
extending IM protection to 100% of the
population living along INGAA member
pipelines. This stage would cover
roughly 16% of pipeline mileage,
bringing the total coverage by 2030 to
approximately 80% of INGAA’s
pipeline mileage.
• Stage 4—Beyond 2030, INGAA
members will apply IM principles to the
remaining 20% of pipeline mileage
where no population resides.
To accomplish this commitment,
INGAA’s members are performing
actions that include applying risk
management beyond HCAs; raising the
standards for corrosion management;
demonstrating ‘‘fitness for service’’ on
pre-regulation pipelines; and evaluating,
refining, and improving operators’
ability to assess and mitigate safety
threats. Ultimately, these actions aim to
extend protection to people who live
near pipelines but not within defined
HCAs.
INGAA’s commitment and other
stakeholder feedback on this issue have
triggered an important exchange about
measuring the risks that exist in lessdensely populated areas and the
impacts of expanding greater
protections to those areas. If constant
improvement and zero incidents are
goals for pipeline operators, INGAA’s
plan to extend and prioritize IM
assessments and principles to all parts
of their pipeline networks that are
located near any concentrations of
population is an effective way to
achieve those goals. Such an approach
is needed to help clarify vulnerabilities
and prioritize improvements, and this
proposed rulemaking takes important
steps forward towards developing such
an approach.
transmission pipelines, but INGAA does not
represent all pipeline operators subject to 49 CFR
part 192.
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The question then, is how to
implement risk management standards
that most accurately target the safety of
communities, while also providing
sufficient ability to prioritize areas of
greatest possible risk and/or impact.
Addressing that question has been, and
remains, an important part of this
proposed rule, recognizing that the
answer will remain fluid based on
factors that continue to change.
Given INGAA’s commitment,
feedback from the ANPRM, the results
of incident investigations, and IM
considerations, PHMSA has determined
it is appropriate to improve aspects of
the current IM program and codify
requirements for additional gas
transmission pipelines to receive
integrity assessments on a periodic basis
to monitor for, detect, and remediate
pipeline defects and anomalies. In
addition, in order to achieve the desired
outcome of performing assessments in
areas where people live, work, or
congregate, while minimizing the cost of
identifying such locations, PHMSA
proposes to base the requirements for
identifying those locations on processes
already being implemented by pipeline
operators and that protect people on a
risk-prioritized basis.
Establishing integrity assessment
requirements and associated repair
conditions for non-HCA pipe segments
is important for providing safety to the
public. Although those segments are not
within defined HCAs, they will usually
be located in populated areas, and
pipeline accidents in these areas may
cause fatalities, significant property
damage, or disrupt livelihoods. This
rulemaking proposes a newly defined
moderate consequence area (MCA) to
identify additional non-HCA pipeline
segments that would require integrity
assessments, thus assuring timely
discovery and repair of pipeline defects
in MCA segments. These changes would
ensure prompt remediation of
anomalous conditions that could
potentially impact people, property, or
the environment, and commensurate
with the severity of the defects, while at
the same time allowing operators to
allocate their resources to HCAs on a
higher-priority basis. INGAA’s
commitment and PHMSA’s MCA
definition are comparable, which shows
a common understanding of the
importance of this issue and a path
towards a solution.
B. Advance Notice of Proposed
Rulemaking
On August 25, 2011, PHMSA
published an Advance Notice of
Proposed Rulemaking (ANPRM) to seek
public comments regarding the revision
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of the Pipeline Safety Regulations
applicable to the safety of gas
transmission pipelines. In particular,
PHMSA requested comments regarding
whether integrity management (IM)
requirements should be changed and
whether other issues related to system
integrity should be addressed by
strengthening or expanding non-IM
requirements. The ANPRM may be
viewed at https://www.regulations.gov by
searching for Docket ID PHMSA–2011–
0023. As mentioned above, pursuant to
the related issues raised by the NTSB
recommendations and statutory
requirements of the Act, PHMSA is
issuing separate rulemaking for several
of the topics in the ANPRM. These
topics are so designated in the following
list. Specifically, the ANPRM sought
comments on the following topics:
A. Modifying the Definition of HCA
(to be addressed in separate
rulemaking),
B. Strengthening Requirements to
Implement Preventive and Mitigative
Measures for Pipeline Segments in
HCAs (partially addressed in separate
rulemaking—aspects related to Remote
Control Valves and Leak Detection will
be addressed in separate rulemaking,
other aspects are being addressed in this
NPRM),
C. Modifying Repair Criteria,
D. Improving Requirements for
Collecting, Validating, and Integrating
Pipeline Data,
E. Making Requirements Related to
the Nature and Application of Risk
Models More Prescriptive,
F. Strengthening Requirements for
Applying Knowledge Gained Through
the IM Program,
G. Strengthening Requirements on the
Selection and Use of Assessment
Methods,
H. Valve Spacing and the Need for
Remotely or Automatically Controlled
Valves (to be addressed in separate
rulemaking),
I. Corrosion Control,
J. Pipe Manufactured Using
Longitudinal Weld Seams,
K. Establishing Requirements
Applicable to Underground Gas Storage
(to be considered for separate
rulemaking),
L. Management of Change,
M. Quality Management Systems
(QMS) (to be considered for separate
rulemaking),
N. Exemption of Facilities Installed
Prior to the Regulations,
O. Modifying the Regulation of Gas
Gathering Lines.
A summary of comments and
responses to those comments are
provided later in the document.
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C. National Transportation Safety Board
Recommendations
On August 30, 2011, following the
issuance of the ANPRM, the NTSB
adopted its report on the gas pipeline
accident that occurred on September 9,
2010, in San Bruno, California. On
September 26, 2011, the NTSB issued
safety recommendations P–11–8
through –20 to PHMSA, and issued
safety recommendations P–10–2
through –4 to Pacific Gas & Electric
(PG&E), among others. The NTSB made
these recommendations following its
investigation of the tragic September 9,
2010 natural gas pipeline rupture in the
city of San Bruno, California. Several of
the NTSB recommendations related
directly to the topics addressed in the
August 25, 2011 ANPRM and impacted
the proposed approach to rulemaking.
The potentially impacted topics and the
related NTSB recommendations
include, but are not limited to:
• Topic B—Strengthening
Requirements to Implement Preventive
and Mitigative Measures for Pipeline
Segments in HCAs. NTSB
Recommendation P–11–10: ‘‘Require
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;
such tools could include a real-time
leak detection system and appropriately
spaced flow and pressure transmitters
along covered transmission lines.’’
• Topic D—Improving Requirements
for Collecting, Validating, and
Integrating Pipeline Data. NTSB
Recommendation P–11–19: ‘‘(1) Develop
and implement standards for integrity
management and other performancebased safety programs that require
operators of all types of pipeline
systems to regularly assess the
effectiveness of their programs using
clear and meaningful metrics, and to
identify and then correct deficiencies;
and (2) make those metrics available in
a centralized database.’’
• Topic G—Strengthening
Requirements on the Selection and Use
of Assessment Methods. NTSB
Recommendation P–11–17: ‘‘Require
that all natural gas transmission
pipelines be configured so as to
accommodate in-line inspection tools,
with priority given to older pipelines.’’
• Topic H—Valve Spacing and the
Need for Remotely or Automatically
Controlled Valves. NTSB
Recommendation P–11–11: ‘‘Amend
Title 49 Code of Federal Regulations
Section 192.935(c) to directly require
that automatic shutoff valves or remote
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control valves in high consequence
areas and in class 3 and 4 locations be
installed and spaced at intervals that
consider the population factors listed in
the regulations.’’
• Topic J—Pipe Manufactured Using
Longitudinal Weld Seams. NTSB
Recommendation P–11–15: ‘‘Amend
Title 49 Code of Federal Regulations
Part 192 of the Federal pipeline safety
regulations so that manufacturing- and
construction-related defects can only be
considered stable if a gas pipeline has
been subjected to a post-construction
hydrostatic pressure test of at least 1.25
times the maximum allowable operating
pressure.’’
• Topic N—Exemption of Facilities
Installed Prior to the Regulations. NTSB
Recommendation P–11–14: Amend title
49 Code of Federal Regulations 192.619
to repeal exemptions from pressure test
requirements and require that all gas
transmission pipelines constructed
before 1970 be subjected to a
hydrostatic pressure test that
incorporates a spike test.’’
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D. Pipeline Safety, Regulatory Certainty,
and Job Creation Act of 2011
Also subsequent to issuance of the
ANPRM, the Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011
(the Act) was enacted on January 3,
2012. Several of the Act’s statutory
requirements relate directly to the topics
addressed in the August 25, 2011
ANPRM. The related topics and
statutory citations include, but are not
limited to:
Æ Section 5(e)—Allow periodic
reassessments to be extended for an
additional 6 months if the operator
submits sufficient justification.
Æ Section 5(f)—Requires regulations
issued by the Secretary, if any, to
expand integrity management system
requirements, or elements thereof,
beyond high-consequence areas.
Æ Section 21—Regulation of Gas (and
Hazardous Liquid) Gathering Lines
Æ Section 23—Testing regulations to
confirm the material strength of
previously untested natural gas
transmission pipelines.
Æ Section 29—Consider seismicity
when evaluating pipeline threats.
E. Summary of Each Topic Under
Consideration
This NPRM proposes new
requirements and revisions to existing
requirements to address topics
discussed in the ANPRM, including
some topics from the Act and the NTSB
recommendations. Each topic area
discussed in the ANPRM, as well as
additional topics that have arisen since
issuance of the ANPRM, is summarized
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below. Details of the changes proposed
in this rule are discussed below in
section V. Section-by-Section Analysis.
• Topic A—Modifying the Definition
of HCA. The ANPRM requested
comments regarding expanding the
definition of an HCA so that more miles
of pipe would be subject to IM
requirements and so that all Class 3 and
4 locations would be subject to the IM
requirements. The Act, Section 5,
requires that the Secretary of
Transportation complete an evaluation
and issue a report on whether integrity
management requirements should be
expanded beyond HCAs and whether
such expansion would mitigate the need
for class location requirements. PHMSA
has prepared the class location report
and a copy is available in the docket
(www.regulations.gov) for this proposed
rulemaking. PHMSA invites
commenters to review the class location
report when formulating their
comments.
Although PHMSA is not proposing to
expand the definition of an HCA,
PHMSA is proposing to expand certain
IM requirements beyond HCAs by
creating a new ‘‘moderate consequence
areas (MCA).’’ MCAs would be used to
define the subset of non-HCA pipeline
locations where periodic integrity
assessments are required (§ 192.710),
where material documentation
verification is required (§ 192.607), and
where MAOP verification is required
(§§ 192.619(e) and 192.624). The
proposed criteria for determining MCA
locations would use the same process
and the same definitions as currently
used to identify HCAs, except that the
threshold for buildings intended for
human occupancy and the threshold for
persons that occupy other defined sites,
that are located within the potential
impact radius, would both be lowered
from 20 to 5. The intention is that any
pipeline location at which persons are
normally expected to be located would
be afforded extra safety protections
described above. In addition, as a result
of the Sissonville, West Virginia
incident, NTSB issued recommendation
P–14–01, to revise the gas regulations to
add principal arterial roadways
including interstates, other freeways
and expressways, and other principal
arterial roadways as defined in the
Federal Highway Administration’s
Highway Functional Classification
Concepts, Criteria and Procedures to the
list of ‘‘identified sites’’ that establish a
high consequence area. PHMSA
proposes to meet the intent of NTSB’s
recommendation by incorporating
designated interstates, freeways,
expressways, and other principal 4-lane
arterial roadways (as opposed to NTSB’s
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all ‘‘other principal arterial roadways’’)
within the new definition of MCAs.
PHMSA believes this approach would
be cost-beneficial. The Sissonville, WV,
incident location would not meet the
current definition of an HCA, but
would, however, meet the proposed
definition of an MCA. PHMSA
considered expanding the scope of
HCAs instead of creating Moderate
Consequence Areas. Such an approach
was contemplated in the 2011 ANPRM
and PHMSA received a number of
comments on this approach. PHMSA
concluded that this approach would be
counter to a graded approach based on
risk (i.e., risk based gradation of
requirements to apply progressively
more protection for progressively greater
consequence locations). By simply
expanding HCAs, PHMSA would be
simply lowering the threshold for what
is considered ‘‘high consequence.’’
Expanding HCAs would require that all
integrity management program elements
(specified in subpart O) be applied to
pipe located in a newly designated
HCA. The proposed rule would only
apply three IM program elements
(assessment, periodic reassessment, and
remediation of discovered defects) to
the category of pipe that has lesser
consequences than HCAs (i.e., MCAs),
but not to segments without any
structure or site within the PIR
(arguably ‘‘low consequence areas’’).
There would be additional significant
costs to apply all other integrity
management program elements (most
notably the risk analysis and
preventive/mitigative measures program
elements) to additional segments
currently not designated as HCA. Also,
if HCAs were expanded, long term
reassessment costs would
approximately triple (compared to the
proposed MCA requirements) based on
an almost 3:1 ratio of reassessment
interval. For the above reasons, PHMSA
is not proposing to expand HCAs.
Instead, PHMSA is proposing to create
and apply selected integrity
management requirements to a category
of lesser consequence areas defined as
MCAs. With regard to the criteria for
defining HCAs, PHMSA also considered
several alternatives, including more
relaxed population density and
excluding small pipe diameters.
In addition, a major constituency of
the pipeline industry (INGAA) has
committed to apply IM principles to all
segments where any persons are located.
This is comparable to PHMSA’s
proposed MCA definition. PHMSA
seeks comment on the relative merits of
expanding High Consequence Areas
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versus creating a new category of
‘‘Moderate Consequence Areas.’’
Another alternative PHMSA
considered was a shorter a compliance
deadline (10 years) and a shorter
reassessment interval (15 years) for
MCA assessments. The assessment
timeframes in the proposed rule were
selected based on a graded approach
which would apply relaxed timeframes
to MCAs, as compared to HCAs. The
industry was originally required to
perform baseline assessments for
approximately 20,000 miles of HCA
pipe within approximately 8 years from
the effective date of the integrity
management rule. PHMSA estimates
that approximately 41,000 miles of pipe
would require an assessment within 15
years under this proposed rule, thus
constituting a comparable level of effort
on the part of industry. The maximum
HCA reassessment interval is 20 years
for low stress pipe. The 20 year interval
was selected to align with the longest
interval allowed for any HCA pipe,
which is 20 years for pipe operating less
than 30% SMYS. A reassessment
interval of 15 years for MCAs would be
shorter than the reassessment interval
for some HCAs. PHMSA also considered
that compliance with the proposed rule
would be performed in parallel with
ongoing HCA reassessments at the same
time, thus resulting in greater demand
for ILI tools and industry resources than
during the original IM baseline
assessment period. In addition, the
proposed rule incorporates other
assessment goals, including integrity
verification, maximum allowable
operating pressure (MAOP) verification,
and material documentation, thus
constituting a larger/more costly
assessment effort than originally
required under IM rules. For the above
reasons, PHMSA believes that this
proposed rule would require full
utilization or expansion of industry
resources devoted to assessments.
Therefore, PHMSA believes that
compressing the timeframes would
place unreasonably high demands on
the industry’s assessment capabilities.
PHMSA also considered the possibility
that placing burdensome demands on
the industry’s assessment capability
might drive assessment costs higher.
PHMSA seeks comments on the
potential safety benefits, avoided lost
gas, economic costs, and operational
considerations involved in longer or
shorter compliance periods for initial
MCA assessment periods and reassessment intervals.
More generally, PHMSA seeks
comment on the approach and scope of
the proposed rule with respect to
applying integrity management program
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elements to additional pipe segments
not currently designated as HCA,
including, inter alia, alternative
definitions of ‘‘Moderate Consequence
Area’’ and limits on the categories of
pipeline to be regulated within this new
area.
• Topic B—Strengthening
Requirements to Implement Preventive
and Mitigative Measures for Pipeline
Segments in HCAs. The ANPRM
requested comments regarding whether
the requirements of Section 49 CFR
192.935 for pipelines in HCAs should be
more prescriptive and whether these
requirements, or other requirements for
additional preventive and mitigative
measures, should apply to pipelines
outside of HCAs. Section 5 of the Act
requires the Secretary of Transportation
to evaluate and report to Congress on
expanding IM requirements to non-HCA
pipelines. PHMSA will further evaluate
applying P&M measures to non-HCA
areas after this evaluation is complete.
This NPRM proposes rulemaking for
amending the integrity management rule
to add requirements for selected
preventive and mitigative measures
(internal and external corrosion
control).
Two special topics associated with
preventive and mitigative measures,
leak detection and automatic valve
upgrades, were addressed by the NTSB
and Congress. The NTSB 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;
such tools could include a real-time leak
detection system and appropriately
spaced flow and pressure transmitters
along covered transmission lines
(recommendation P–11–10). In addition,
Section 8 of the Act requires issuance of
a report on leak detection systems used
by operators of hazardous liquid
pipelines which was completed and
submitted to Congress in December
2012. Although that study is specific to
hazardous liquid pipelines, its analysis
and conclusions could influence
PHMSA’s approach to leak detection for
gas pipelines. In response to the NTSB
recommendations, PHMSA conducted
as part of a larger study on pipeline leak
detection technology a public workshop
in 2012. This study, among other things,
examined how enhancements to SCADA
systems can improve recognition of
pipeline leak locations. Additionally, in
2012 PHMSA held a pipeline research
forum to identify technological gaps,
potentially including the advancement
of leak detection methodologies.
PHMSA is developing a rulemaking
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with respect to leak detection in
consideration of these studies and
ongoing research. In addition, PHMSA
is focusing this rulemaking on
regulations oriented toward preventing
incidents. Leak detection (in the context
of mitigating pipe breaks as described in
NTSB P–11–10) 34 and automatic valve
upgrades are features that serve to
mitigate the consequences of incidents
after they occur but do not prevent
them. In order to not delay the
important requirements proposed in this
NPRM, PHMSA will address the topic of
incident mitigation later in a separate
rulemaking. It is anticipated that
advancing rulemaking to address the
NTSB recommendations will follow
assessment of the results of these
actions.
PHMSA completed and submitted the
valve study to congress in December
2012. PHMSA is developing a separate
rulemaking related to the need for
remotely or automatically controlled
valves to addresses the NTSB
recommendations and statutory
requirements related to this topic as
discussed under Topic H.
• Topic C—Modifying Repair Criteria.
The ANPRM requested comments
regarding amending the integrity
management regulations by revising the
repair criteria for pipelines in HCAs to
provide greater assurance that injurious
anomalies and defects are repaired
before the defect can grow to a size that
leads to a leak or rupture. PHMSA is
proposing in this rule to revise the
repair criteria for pipelines in HCAs.
Revisions include repair criteria for
cracks and crack-like defects, corrosion
metal loss for defects less severe than an
immediate condition (already included),
and mechanical damage defects.
In addition, the ANPRM requested
comments regarding establishing repair
criteria for pipeline segments located in
areas that are not in HCAs. PHMSA is
proposing rulemaking for establishing
repair criteria for pipelines that are not
in HCAs. Such repair criteria would be
similar to the repair criteria for HCAs,
with more relaxed deadlines for nonimmediate conditions. It is
acknowledged that applying repair
criteria to pipelines that are not in HCAs
is one of the factors to be considered in
the integrity management evaluation
required in the Act, as discussed in
Topic A above.
• Topic D—Improving Requirements
for Collecting, Validating, and
Integrating Pipeline Data. The ANPRM
34 Leak detection in the context of detecting
small, latent leaks such as leaks at fittings typical
of gas distribution systems, and is outside the scope
of the ANPRM, Topic B.
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requested comments regarding whether
more prescriptive requirements for
collecting, validating, integrating, and
reporting pipeline data are necessary.
PHMSA also discussed this topic in a
2012 pipeline safety data workshop.
PHMSA issued Advisory Bulletin 12–
06 to remind operators of gas pipeline
facilities to verify their records relating
to operating specifications for maximum
allowable operating pressure (MAOP)
required by 49 CFR 192.517. On January
10, 2011, PHMSA also issued Advisory
Bulletin 11–01, which reminded
operators that if they are relying on the
review of design, construction,
inspection, testing and other related
data to establish MAOP, they must
ensure that the records used are reliable,
traceable, verifiable, and complete.
PHMSA is proposing in this rule to add
specificity to the data integration
language in the IM rule to establish a
number of pipeline attributes that must
be included in these analyses, by
explicitly requiring that operators
integrate analyzed information, and by
requiring that data be verified and
validated. In addition, PHMSA has
determined that additional rules are
needed to ensure that records used to
establish MAOP are reliable, traceable,
verifiable, and complete. The proposed
rule would add a new paragraph (e) to
section 192.619 to codify this
requirement and to require that such
records be retained for the life of the
pipeline.
• Topic E—Making Requirements
Related to the Nature and Application of
Risk Models More Detailed. The
ANPRM requested comments regarding
making requirements related to the
nature and application of risk models
more specific to improve the usefulness
of these analyses in informing decisions
to control risks from pipelines. This
NPRM contains proposed requirements
that address this topic.
• Topic F—Strengthening
Requirements for Applying Knowledge
Gained Through the IM Program. The
ANPRM requested comments regarding
strengthening requirements related to
operators’ use of insights gained from
implementation of its IM program. In
this NPRM, PHMSA proposes detailed
requirements for strengthening integrity
management requirements for applying
knowledge gained through the IM
Program. These requirements include
provisions for analyzing interacting
threats, potential failures, and worstcase incident scenarios from initial
failure to incident termination. Though
not proposed, PHMSA seeks comment
on whether a time period for updating
aerial photography and patrol
information should be established.
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• Topic G—Strengthening
Requirements on the Selection and Use
of Assessment Methods for pipelines
requiring assessment. The ANPRM
requested comments regarding the
applicability, selection, and use of
assessment methods, including the
application of existing consensus
standards. NTSB recommendation P–
11–17 related to this topic, recommends
that all gas pipelines be upgraded to
accommodate ILI tools. PHMSA will
consider separate rulemaking for
upgrading pipelines pending further
evaluation of the issue from new data
being collected in the annual reports.
This NPRM proposes to strengthen
requirements for the selection and use
of assessment methods. The proposed
rule would provide more detailed
guidance for the selection of assessment
methods, including the requirements in
new § 192.493 when performing an
assessment using an in-line inspection
tool. This NPRM also proposes to add
more specific requirements for use of
internal inspection tools to require that
an operator using this method must
explicitly consider uncertainties in
reported results when identifying
anomalies. In addition, the proposed
rulemaking would add a ‘‘spike’’
hydrostatic pressure test, which is
particularly well suited to address SCC
and other cracking or crack-like defects,
guided wave ultrasonic testing (GWUT),
which is particularly appropriate in
cases where short segments, such as
roads or railroad crossings, are difficult
to assess, and excavation and in situ
direct examination, which is well suited
to address crossovers and other short,
easily accessible segments that are
impractical to assess by remote
technology, as allowed assessment
methods and would revise the
requirements for direct assessment to
allow its use only if a line is not capable
of inspection by internal inspection
tools.
The issue of selection and use of
assessment methods is related to the
statutory mandate in the Act for the
Comptroller General of the United
States to evaluate whether risk-based
reassessment intervals are a more
effective alternative. The Act requires an
evaluation of reassessment intervals and
the anomalies found in reassessments.
While not directly addressing selection
of assessment methods, the results of
the evaluation will have an influence on
the general approach for conducting
future integrity assessments. PHMSA
will consider the Comptroller General’s
evaluation when it becomes available.
Additional rulemaking may be
considered after PHMSA considers the
results of the evaluation.
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• Topic H—Valve Spacing and the
Need for Remotely or Automatically
Controlled Valves. The ANPRM
requested comments regarding proposed
changes to the requirements for
sectionalizing block valves. In response
to the NTSB recommendations, PHMSA
held a public workshop in 2012 on
pipeline valve issues, which included
the need for additional valve
installation on both natural gas and
hazardous liquid transmission
pipelines. PHMSA also included this
topic in the 2012 Pipeline Research
Forum. In addition, Section 4 of the Act
requires issuance of regulations on the
use of automatic or remote-controlled
shut-off valves, or equivalent
technology, where economically,
technically, and operationally feasible
on transmission pipeline facilities
constructed or entirely replaced after
the date of the final rule. The Act also
requires completion of a study by the
Comptroller General of the United
States on the ability of transmission
pipeline facility operators to respond to
a hazardous liquid or gas release from
a pipeline segment located in an HCA.
Separate rulemaking on this topic will
be considered based on the results of the
study.
• Topic I—Corrosion Control. The
ANPRM requested comments regarding
proposed revisions to subpart I to
improve the specificity of existing
requirements. This NPRM proposes to
revise subpart I, including a general
update to the technical requirements in
appendix D to part 192 for cathodic
protection.
• Topic J—Pipe Manufactured Using
Longitudinal Weld Seams. In
recommendation P–11–15, the NTSB
recommended that PHMSA amend its
regulations to require that any
longitudinal seam in an HCA be
pressure tested in order to consider the
seam to be ‘‘stable.’’ This issue is
addressed in Topic N. PHMSA proposes
to address this issue by revising the
integrity management requirements in
§ 192.917(e)(3) to specify that
longitudinal seams may not be treated
as stable defects unless the segment has
been pressure tested (and therefore
would require an integrity assessment
for seam threats). Also, PHMSA
proposes to add new requirements for
verification of maximum allowable
operating pressure (MAOP) in new
§ 192.624.
• Topic K—Establishing
Requirements Applicable to
Underground Gas Storage. The ANPRM
requested comments regarding
establishing requirements within part
192 applicable to underground gas
storage in order to help assure safety of
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underground storage and to provide a
firm basis for safety regulation. PHMSA
will consider proposing a separate
rulemaking that specifically focuses on
improving the safety of underground
natural gas storage facilities will allow
PHMSA to fully consider the impacts of
incidents that have occurred since the
close of the initial comment period. It
will also allow the Agency to consider
voluntary consensus standards that
were developed after the close of the
comment period for this ANPRM, and to
solicit feedback from additional
stakeholders and members of the public
to inform the development of potential
regulations.
• Topic L—Management of Change.
The ANPRM requested comments
regarding adding requirements for
management of change to provide a
greater degree of control over this
element of pipeline risk. This NPRM
contains proposed requirements that
address this topic. Specifically, PHMSA
proposes to revise the general
applicability requirements in § 192.13 to
require each operator of an onshore gas
transmission pipeline to develop and
follow a management of change process,
as outlined in ASME/ANSI B31.8S,
section 11, that addresses technical,
design, physical, environmental,
procedural, operational, maintenance,
and organizational changes to the
pipeline or processes, whether
permanent or temporary.
• Topic M—Quality Management
Systems (QMS). The ANPRM requested
comments regarding whether and how
to impose requirements related to
quality management systems. PHMSA
will consider separate rulemaking for
this topic.
• Topic N—Exemption of Facilities
Installed Prior to the Regulations. The
ANPRM requested comments regarding
proposed changes to part 192
regulations that would repeal
exemptions to pressure test
requirements. The NTSB recommended
that PHMSA repeal 49 CFR 192.619(c)
and require that all gas transmission
pipelines be pressure tested to establish
MAOP (recommendation P–11–14). In
addition, section 23 of the Act requires
issuance of regulations requiring tests to
confirm the material strength of
previously untested natural gas
transmission lines. In response to the
NTSB recommendation and the Act, this
NPRM proposes requirements for
verification of maximum allowable
operating pressure (MAOP) in
accordance with new § 192.624 for
certain onshore, steel, gas transmission
pipelines, including establishing and
documenting MAOP if the pipeline
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MAOP was established in accordance
with § 192.619(c).
The Act also requires verification of
records to ensure they accurately reflect
the physical and operational
characteristics of the pipelines and to
confirm the established maximum
allowable operating pressure of the
pipelines. PHMSA issued Advisory
Bulletin 12–06 on May 7, 2012 to notify
operators of this required action.
PHMSA has initiated an information
collection effort to gather data needed to
accurately characterize the quantity and
location of pre-1970 gas transmission
pipeline operating under an MAOP
established by 49 CFR 192.619(c). This
NPRM proposes requirements in new
§ 192.607 for certain onshore, steel, gas
transmission pipelines to confirm and
record the physical and operational
characteristics of pipelines for which
adequate records are not available.
• Topic O—Modifying the Regulation
of Gas Gathering Lines. The ANPRM
requested comments regarding
modifying the regulations relative to gas
gathering lines. The Act required several
actions related to this topic, including:
review existing regulations for gathering
lines; provide a report to Congress; and
make recommendations on: (1) The
sufficiency of existing regulations, (2)
the economic impacts, technical
practicability, and challenges of
applying existing federal regulations to
gathering lines, and (3) subject to a riskbased assessment, the need to modify or
revoke existing exemptions from
Federal regulation for gas and hazardous
liquid gathering lines. PHMSA proposes
to address aspects of this topic
identified before enactment of the Act in
this NPRM. The report submitted to
Congress will be evaluated to determine
the need for any future rulemaking,
specifically the need to apply integrity
management concepts to gas gathering
lines.
In addition, on August 20, 2014, the
Government Accountability Office
(GAO) released a report (GAO Report
14–667) to address the increased risk
posed by new gathering pipeline
construction in shale development
areas. The GAO recommended that
rulemaking be pursued for gathering
pipeline safety that addresses the risks
of larger-diameter, higher-pressure
gathering pipelines, including
subjecting such pipelines to emergency
response planning requirements that
currently do not apply. PHMSA
proposes to address this
recommendation as described below in
the ‘‘Section-by-Section Analysis’’
under § 192.9.
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Additional Topics
• Inspection of Pipelines Following a
Severe Weather Event. Existing pipeline
regulations prescribe requirements for
surveillance periodically patrolling of
pipeline to observe surface conditions
on and adjacent to the transmission line
right-of-way for indications of leaks,
construction activity, and other factors
affecting safety and operation, including
unusual operating and maintenance
conditions. The cause of the 2011
hazardous liquid pipeline accident
resulting in a crude oil spill into the
Yellowstone River near Laurel, Montana
was scouring at the river crossing due to
flooding. In this case, annual heavy
flooding occurred in the Spring of the
2011. In late May, the operator shut
down the pipeline for several hours to
assess the state of the pipeline.
Following the assessment, the operator
restarted the pipeline and agreed to
monitor the river area on a daily basis.
On July 1, 2011 the pipeline ruptured
which resulted in the release of 1,500
barrels of crude oil into the Yellowstone
River. A second break, due to exposure
to flood conditions, occurred several
years later on the same pipeline led to
an additional spill in the Yellowstone
River. Other examples include
Hurricane Katrina (2005) which resulted
in significant damage to the oil and gas
production structures and the San
Jacinto flood (1994) which resulted in 8
ruptures and undermining of 29 other
pipelines. In the context of the San
Jacinto flood, ‘‘undermining’’ occurred
when support material for the pipelines
was removed due to erosion driven by
the floodwaters. As a result, the
unsupported pipelines were subjected
to stress from the floodwaters that
resulted in fatigue cracks in the pipe
walls. Based on these examples of
extreme weather events that did result,
or could have resulted, in pipeline
incidents, PHMSA has determined that
additional regulations are needed to
require, and establish standards for,
inspection of the pipeline and right-ofway for ‘‘other factors affecting safety
and operation’’ following an extreme
weather event, such as a hurricane or
flood, an earthquake, a natural disaster,
or other similar event that has the
likelihood of damage to infrastructure.
The proposed rule would require such
inspections, specify the timeframe in
which such inspections should
commence, and specify the appropriate
remedial actions that must be taken to
ensure safe pipeline operations. The
new regulation would apply to onshore
transmission pipelines and their rightsof-way.
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• Notification for 7-Year
Reassessment Interval Extension.
Subsection 5(e) of the Act identifies a
technical correction amending section
60109(c)(3)(B) of title 49 of the United
States Code to allow the Secretary of
Transportation to extend the 7- calendar
year reassessment interval for an
additional 6 months if the operator
submits written notice to the Secretary
with sufficient justification of the need
for the extension. PHMSA would expect
that any justification, at a minimum,
would need to demonstrate that the
extension does not pose a safety risk.
PHMSA proposes to codify this
statutory requirement.
• Reporting Exceedances of
Maximum Allowable Operating
Pressure. Section 23 of the Act requires
operators to report to PHMSA each
exceedance of the maximum allowable
operating pressure (MAOP) that exceeds
the margin (build-up) allowed for
operation of pressure-limiting or control
devices. Implicit in § 192.605 is the
intent for operators to establish
operational and maintenance controls
and procedures to effectively preclude
operation at pressures that exceed
MAOP. PHMSA expects that operators’
procedures should already address this
aspect of operations and maintenance,
as it is a long-standing, critical aspect of
safe pipeline operations. PHMSA issued
ADB 12–11 to address exceedances of
MAOP. However, PHMSA proposes to
codify this statutory requirement in
§ 192.605.
• Consideration of Seismicity.
Section 29 of the Act states that in
identifying and evaluating all potential
threats to each pipeline segment, an
operator of a pipeline facility must
consider the seismicity of the area.
PHMSA proposes to codify this
statutory requirement by adding
requirements to explicitly reference
seismicity for data gathering and
integration, threat identification, and
implementation of preventive and
mitigative measures.
• Safety Regulations for In-line
Inspection (ILI), Scraper, and Sphere
Facilities. PHMSA is proposing to add
explicit requirements for safety features
on launchers and receivers associated
with ILI, scraper and sphere facilities.
• Consensus Standards for Pipeline
Assessments. The proposed rule would
incorporate by reference industry
standards for assessing the physical
condition of in-service pipelines using
in-line inspection, internal corrosion
direct assessment, and stress corrosion
cracking direct assessment. Periodic
assessment of the condition of gas
transmission pipelines in HCAs is
required by 49 CFR 192.921 and
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192.937. The regulations provide
minimal requirements for the use of
these assessment techniques since at the
time these regulations were established,
industry standards did not exist
addressing how these techniques should
be applied. Incorporation of standards
subsequently published by the
American Petroleum Institute (API), the
National Association of Corrosion
Engineers (NACE), and the American
Society of Nondestructive Testing
(ASNT) would assure better
consistency, accuracy and quality in
pipeline assessments conducted using
these techniques.
F. Integrity Verification Process
Workshop
An Integrity Verification Process (IVP)
workshop was held on August 7, 2013.
At the workshop, PHMSA, the National
Association of State Pipeline Safety
Representatives and various other
stakeholders presented information and
comments were sought on a proposed
IVP that will help address mandates set
forth in Section 23, Maximum
Allowable Operating Pressure, of the
Act and the NTSB Recommendations P–
11–14 (repeal pressure test exemptions)
and P–11–15 (stability of manufacturing
and construction defects). Key aspects
of the proposed IVP process include
criteria for establishing which pipe
segments would be subject to the IVP,
technical requirements for verifying
material properties where adequate
records are not available, and technical
requirements for re-establishing MAOP
where adequate records are not
available or the existing MAOP was
established under § 192.619(c).
Comments were received from the
American Gas Association, the Interstate
Natural Gas Association of America, and
other stakeholders addressing the draft
IVP flow chart, technical concerns for
implementing the proposed IVP, and
other issues. The detailed comments are
available under Docket No. PHMSA–
2013–0119. PHMSA considered and
incorporated the stakeholder input, as
appropriate, into this NPRM, which
proposes requirements to address the
current exemptions to pressure test
requirements, manufacturing and
construction defect stability, verification
of MAOP where records to establish
MAOP are not available or inadequate
(new §§ 192.619(e) and 192.624), and
verification and documentation of
pipeline material for certain onshore,
steel, gas transmission pipelines (new
§ 192.607).
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III. Analysis of Comments on the
ANPRM
In Section II of the ANPRM, PHMSA
sought comments concerning the
significance of the proposed issues to
pipeline safety; whether new/revised
regulations are needed and, if so,
suggestions as to what changes are
needed; and likely costs that would be
associated with implementing any new/
revised requirements. PHMSA posed
specific questions to solicit stakeholder
input. These included questions related
to 15 specific topic areas in two broad
categories:
1. Should IM requirements be revised
and strengthened to bring more pipeline
mileage under IM requirements and to
better assure safety of pipeline segments
in HCAs? Specific topics included:
A. Modifying the Definition of HCA,
B. Strengthening Requirements to
Implement Preventive and Mitigative
Measures for Pipeline Segments in
HCAs,
C. Modifying Repair Criteria,
D. Improving Requirements for
Collecting, Validating, and Integrating
Pipeline Data,
E. Making Requirements Related to
the Nature and Application of Risk
Models More Prescriptive,
F. Strengthening Requirements for
Applying Knowledge Gained Through
the IM Program,
G. Strengthening Requirements on the
Selection and Use of Assessment
Methods.
2. Should non-IM requirements be
strengthened or expanded to address
other issues associated with pipeline
system integrity. Specific topics
included:
H. Valve Spacing and the Need for
Remotely or Automatically Controlled
Valves,
I. Corrosion Control,
J. Pipe Manufactured Using
Longitudinal Weld Seams,
K. Establishing Requirements
Applicable to Underground Gas Storage,
L. Management of Change,
M. Quality Management Systems
(QMS),
N. Exemption of Facilities Installed
Prior to the Regulations,
O. Modifying the Regulation of Gas
Gathering Lines.
PHMSA received a total of 1,463
comments; 1,080 from industry sources
(Trade Associations/Unions, Pipeline
Operators and Consultants); 316
comments from the public
(Environmental Groups, Government
Agencies/Municipalities, NAPSR and
individual members of the general
public); and 67 general comments not
directly related to the ANPRM questions
or categories. Commenters included:
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• Citizen Groups
Æ Environmental Defense Fund (EDF)
Æ League of Women Voters of
Pennsylvania (LWV)
Æ Pipeline Safety Trust (PST)
Æ State of Washington Citizens
Advisory Committee on Pipeline
Safety (CCOPS)
• Consultants
Æ Accufacts Inc.
Æ Oleksa and Associates, Inc.
Æ Thomas M. Lael
Æ WKM Consultancy, LLC
• Government Agencies
Æ California Public Utilities
Commission (CPUC)
Æ City and County of San Francisco
(CCSF)
Æ Federal Energy Regulatory
Commission (FERC)
Æ Harris County Fire Marshal’s Office
(HCFM)
Æ Interstate Oil and Gas Compact
Commission (IOGCC)
Æ Iowa Utilities Board
Æ Kansas Corporation Commission
(KCC)
Æ Kansas Department of Health and
Environment (KDHE)
Æ National Association of Pipeline
Safety Representatives (NAPSR)
Æ National Transportation Safety
Board (NTSB)
Æ Railroad Commission of Texas
(TRRC)
Æ State of Alaska—AK Natural Gas
Development Authority (AKN)
Æ State of Alaska Dept. of Natural
Resources (AKDNR)
Æ Wyoming County Commissioners of
Pennsylvania (WYCTY)
• Pipeline Industry
Æ Air Products and Chemicals, Inc.
Æ Alliance Pipeline
Æ Ameren Illinois (AmerenIL)
Æ Atmos Energy
Æ Avista Corporation
Æ CenterPoint Energy
Æ CenterPoint Energy Resources Corp.
Æ Chevron
Æ Dominion East Ohio Gas (DEOG)
Æ El Paso (EPPG)
Æ ITT Exelis Geospatial Systems
Æ Kern River Gas Transmission
Company
Æ MidAmerican Energy Company
Æ National Fuel Gas Supply
Corporation
Æ National Grid
Æ Nicor Gas
Æ NiSource Gas Transmission &
Storage
Æ Northern Natural Gas
Æ Paiute Pipeline Company
Æ Panhandle Energy
Æ Questar Gas Company
Æ Questar Pipeline Company
Æ SCGC and SDG&E (Sempra)
Æ Southern Star Central Gas Pipeline,
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Inc.
Æ Southwest Gas Corporation
Æ Spectra Energy
Æ TransCanada
Æ TransCanada Corporation
Æ Waste Management, Inc
Æ Williams Gas Pipeline
• Municipalities
Æ Delaware Solid Waste Authority
(DSWA)
Æ Iowa Association of Municipal
Utilities (IAMU)
• Trade Associations
Æ American Gas Association (AGA)
Æ American Public Gas Association
(APGA)
Æ Gas Processors Association (GPA)
Æ Gas Piping Technology Committee
(GPTC)
Æ Independent Petroleum Association
of America, its Cooperating
Associations, and the American
Petroleum Institute (IPAA/API)
Æ Interstate Natural Gas Association
of America (INGAA)
Æ NACE International
Æ National Solid Waste Management
Association (NSWMA)
Æ National Utility Locating
Contractors Association (Locators)
Æ Oklahoma Independent Petroleum
Association (OKIPA)
Æ Texas Oil and Gas Association
(TXOGA)
Æ Texas Pipeline Association (TPA)
• Trade Unions
Æ Professional Engineers in California
Government (PECG)
• 31 Private Citizens
Commenters responded to ANPRM
questions, but also submitted comments
on subjects generally related to gas
pipeline safety regulation (but not
related to an ANPRM topic) and general
comments related to a topic but not in
response to any specific question. This
NPRM presents a summary of the
comments received (similar or duplicate
comments are consolidated). The
general (no-topic) comments are
presented first under the heading
‘‘General Comments.’’ Comments on
each topic follow under the heading
‘‘Comments on ANPRM Section II
Topics on Which PHMSA Sought
Comment,’’ beginning with general
comments related to the topic and then
proceeding to each individual question.
General Comments
General Industry Comments
1. A number of commenters
associated with the pipeline industry
suggested that PHMSA should defer
action on the changes discussed in the
ANPRM until the studies required by
the Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011
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20737
are completed. They contended the Act
presents critical issues that require
priority attention. They believe the
questions raised by Congress, and to
which the studies are addressed, could
lead to fundamental changes in how
pipeline safety is regulated and these
changes need to be understood before
new rules are written. Several
commenters also suggested PHMSA
lacks the resources to pursue
simultaneously the required studies and
complicated rulemakings. The Railroad
Commission of Texas also suggested no
new requirements be proposed until the
effects of the new Act are understood,
since they believe that the Act will
change the scope of regulatory authority
and impose additional costs on industry
and regulators.
Response
PHMSA has placed studies and
evaluations that relate to the topics in
this proposed rulemaking on the docket.
PHMSA seeks public comment on those
reports and will consider comments
before finalizing this rule. Other topics
not addressed in this rulemaking that
require additional study or evaluation
will be addressed separately. Areas for
safety improvement that have
previously been identified and that are
not dependent on the outcome of the
required studies are also the subject of
the proposals in this Notice.
2. INGAA, AGA, and several pipeline
operators and consultants commented
that the ANPRM suggested that PHMSA
intends to pursue prescriptive
regulation in a number of areas. They
objected to this approach. They prefer
performance-based regulation, under
which operators have greater flexibility
in deciding how the required safety goal
can be met, considering the specific
circumstances of their pipeline systems.
They noted that integrity management,
a performance-based approach, has
greatly improved pipeline safety, and
suggested PHMSA consider expanding
the elements to be covered in an IM
plan and providing more well-defined
guidelines on how these expanded
plans should evolve over time. They
noted that implementing pipeline safety
regulations is a complex process and
implementing prescriptive requirements
is usually inefficient. They also noted
that prescriptive requirements tend to
discourage technological advancements
which can lead to improved means to
assure safety.
Response
PHMSA believes performance-based
regulations are central to improving
pipeline performance. In some
instances, however, prescriptive
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requirements may be necessary to
provide the requisite improvement to
pipeline safety performance; for
example, requirements for corrosion
control, repair conditions, and repair
criteria to more specifically address
significant corrosion issues. In these
cases, the unsafe condition can be
clearly specified, and steps necessary to
remediate the risk are well-understood
engineering practice. PHMSA is
committed to an efficient and effective
approach to pipeline safety, and using
prescriptive regulatory requirements
only where necessary.
3. AGA, Texas Pipeline Association,
Texas Oil and Gas Association, and a
number of pipeline operators objected to
the scope and pace of change in
pipeline safety regulation. These
commenters noted that the ANPRM
covered a number of complex issues. In
addition, they noted that pipeline
operators are still implementing a
number of large new initiatives
including control room management,
public awareness, distribution integrity
management, and damage prevention.
They commented that the industry
needs time to complete implementing
these other new regulations and PHMSA
and the industry need time to evaluate
the effect they have on pipeline safety.
AGA specifically expressed concern that
the pace of change could result in
unintended adverse consequences. The
Texas Associations suggested that any
expansion of non-HCA regulations
should address highest risks first and be
structured to tailor requirements to
different pipeline conditions because
other approaches are likely to result in
increased costs with little safety benefit.
MidAmerican commented that the
ANPRM appeared to be based on an
incorrect assumption that there are no
current requirements applicable to nonHCA pipe; they noted that part 192
includes many requirements applicable
to non-HCA segments and that they
assure safety. Atmos suggested PHMSA
avoid the ‘‘one size fits all’’ approach to
pipeline safety regulations.
Response
PHMSA understands that assimilation
of change is an important consideration
and agrees that the ANPRM covers a
number of complex issues. Many of the
more complex issues contemplated in
the ANPRM, such as leak detection and
automatic valves, will be addressed by
separate rulemaking so that more careful
and detailed analysis can be completed.
However, PHMSA is proposing
rulemaking in a number of areas to
assure that the regulations continue to
provide an adequate level of safety for
both HCAs and non-HCAs. Additional
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discussion of the basis for the proposed
rulemaking is presented in the response
to comments received for each ANPRM
topic and in Section V below (Sectionby-Section Analysis).
4. A number of industry commenters
suggested that PHMSA exercise care in
developing broad requirements that may
be inappropriate for some types of
pipelines. In particular, APGA noted
that ‘‘transmission’’ pipeline operated
by local distribution companies is very
different from long-distance
transmission lines. They are typically
smaller diameter, operate at lower
pressures, and are often made of plastic.
AGA and distribution pipeline operators
noted that leaks are a routine
management issue for distribution
pipelines and those requirements
appropriate to leak response for
transmission pipelines would not be
appropriate in a distribution context.
The Texas Oil & Gas Association
requested that any changes be examined
for possible unexpected impact on
gathering lines, which also differ from
transmission pipelines.
Response
PHMSA is aware of the varying nature
of pipeline systems. One aspect of
performance-based requirements is the
ability of operators to customize the
integrity management program so that it
is appropriate to its circumstances.
5. AGA and some pipeline operators
noted that the ANPRM suggested that
PHMSA intends to extrapolate
hazardous liquid pipeline experience to
gas pipelines. In particular, they
expressed concern regarding the
discussion of leak detection. They noted
pin-point leak detection may be
practical for non-compressible liquids
but is not for gas.
Response
PHMSA appreciates the significant
differences between hazardous liquid
pipelines and gas pipelines with respect
to leak detection. PHMSA is sponsoring
studies and research to address leak
detection in a responsible way, while
still being responsive to related NTSB
recommendations. PHMSA is
considering separate rulemaking for leak
detection that will address these studies
and research.
6. Pipeline industry trade associations
reported that their members plan to
implement voluntary approaches to
improve pipeline safety. INGAA
reported it has implemented a strategy
to achieve a goal of zero pipeline
incidents. This strategy includes
voluntary application of IM principles
to non-HCA pipeline segments where
people live. Their goal is to apply
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ASME/ANSI B31.8S, Managing System
Integrity of Gas Pipelines, principles to
90 percent of people who live or work
in close proximity to pipelines by 2020,
and 100 percent by 2030. INGAA’s
strategy also includes assuring the
fitness for service of pipelines installed
before federal safety regulations were
promulgated, improving incident
response time (to less than one hour in
populated areas), and implementing the
Pipelines and Informed Planning
Alliance (PIPA) guidelines. AGA
similarly reported their intentions to
address improvements to safety
proactively by applying Operator
Qualification to new construction,
continuing to advance IM principles
(including developing industry
guidelines for data management and
data quality), and working with a
coalition of PIPA stakeholders to adopt
PIPA-recommended best practices,
among other initiatives.
Response
PHMSA commends the pipeline
industry for these initiatives and is
committed to working with the industry
to improve performance toward the goal
of zero pipeline incidents.
7. A number of comments addressed
the cost-benefit analyses that will be
required in support of rulemaking that
results from this ANPRM. AGA noted
that a detailed estimate has not been
completed but that preliminary
evaluations suggest that the cost of
implementing the initiatives included in
the ANPRM could well exceed the cost
of implementing the 2003 gas
transmission IM rule. APGA agreed that
some of the concepts discussed in the
ANPRM are potentially very costly and
must be considered carefully. Accufacts
cautioned PHMSA to be wary of efforts
to distort the cost-benefit analyses by
hyper inflating costs. As an example,
Accufacts pointed to estimates of costs
to perform hydrostatic tests ranging
from $500,000 to $1,000,000 per mile
compared to costs of $29,400 to $40,000
per mile cited in the NTSB report on the
San Bruno accident.
Response
PHMSA acknowledges that estimates
of hydrostatic test costs can vary and
that there is risk in using overstated
estimates in the analysis of benefits and
costs since regulatory decisions
regarding public safety can be based on
these results. For the Preliminary
Regulatory Impact Assessment (PRIA)
for this proposed rule PHMSA used
vendor pricing data to develop unit
costs for pressure testing. These costs
represent the contractor’s costs to
complete an eight hour pressure test for
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various segment diameters and lengths.
PHMSA applied a multiplier to account
for other operator costs, such as
manifold installation and operational
oversight, and also added estimated
costs to provide temporary gas supplies
and the market value of lost gas. Based
on these data and assumptions, PHMSA
estimated per mile pressure test costs
range from approximately $60,000 per
mile (12″ diameter, 10 mile segment) to
630,000 (36″ diameter, one mile
segment). Detailed explanations of these
unit costs are available in the PRIA,
provided in the regulatory docket.
8. AGA and several pipeline operators
suggested PHMSA should establish
jointly with industry a committee to
evaluate pipeline data and to determine
whether more data is needed. They
commented industry has repeatedly
made this request and PHMSA has, to
date, not responded. They contended
PHMSA’s current analysis of pipeline
safety performance data is inadequate.
Similarly, Panhandle Energy noted a
number of the questions in the ANPRM
requested data on various subjects;
Panhandle expressed its belief that
PHMSA collects and has access to at
least some of data requested, and this
data, collected pursuant to regulatory
requirements, should be more complete,
and consistently collected and reported,
than piecemeal collections of data in
response to this ANPRM. Expressing a
somewhat contrary view, El Paso
suggested more data should be collected
and analyzed before notices of proposed
rulemakings are prepared; PHMSA
needs to collect and analyze data to
determine the proper path for future
requirements, if any.
Response
In response to NTSB recommendation
P–11–19, PHMSA held a pipeline safety
data workshop in January 2013. The
workshop: (1) Summarized the data OPS
collects, who it is collected from, and
why it is collected; (2) addressed how
stakeholders, including OPS, industry,
and the public use the data; (3)
addressed data quality improvement
efforts and performance measures; and
(4) discussed the best method(s) for
collecting, analyzing, and ensuring
transparency of additional data needed
to improve performance measures.
PHMSA considered the results of the
workshop as well as the comments to
the ANPRM related to pipeline safety
performance data.
9. APGA suggested PHMSA revise the
definitions of transmission and
distribution pipelines to be more riskbased. APGA contended that the current
definitions are not risk-based and lead
to inappropriate outcomes. In particular,
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classification of some pipelines as
‘‘transmission’’ based on functional
aspects of the current definition leads to
inappropriate application of
requirements. In a similar vein, Oleksa
and Associates suggested it may be time
to reduce IM requirements on low-stress
transmission pipelines, which pose
lower risk than high-stress lines. Texas
Pipeline Association and Texas Oil &
Gas Association commented PHMSA
should not extrapolate experience with
interstate pipelines to intrastate lines,
which differ in design and operation.
Response
The definition of transmission vs.
distribution pipelines and the
applicability requirements for integrity
management in High Consequence
Areas is not within the scope of this
proposed rule. The general topic of the
scope and applicability of integrity
management is addressed in the class
location report which available in the
docket.
10. Northern Natural Gas
recommended all exemptions from onecall requirements be eliminated. They
noted excavation damage remains, by
far, the single greatest threat to pipeline
safety and management of excavation
damage, through one-call programs, has
been demonstrated to be an effective
means of countering that threat.
Response
This comment is not within the scope
of the ANPRM topics. However, PHMSA
has revised the pipeline safety
regulations related to pipeline damage
prevention programs, which includes
one-call programs, in an final rule
issued July 23, 2015 (80 FR 43836).
11. The Gas Processors Association,
Texas Pipeline Association, and Texas
Oil & Gas Association commented
regarding current efforts to clarify the
applicability of part 192 requirements,
particularly requirements for
distribution integrity management, to
farm taps. They suggested PHMSA is
engaged in an expansion of
requirements in this area without notice
or a demonstrated safety need. They
suggested PHMSA initiate a rulemaking
specifically to clarify requirements
applicable to farm taps.
Response
Treatment of farm taps is not within
the scope of the ANPRM topics.
However, PHMSA has engaged in
dialogue with industry on this topic and
will continue to consider options to
address this issue in a separate action.
12. Northern Natural Gas suggested
PHMSA reduce the time allowed for
conducting a baseline assessment in
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20739
cases where a new HCA is found,
tailored to the circumstances of the
particular segment. Northern expressed
its belief this would address threats to
integrity in areas affecting population
more quickly than current requirements.
Response
Currently, § 192.905(c) requires that
newly identified HCAs be incorporated
into the baseline assessment plan within
one year. PHMSA does not currently
have plans to address this requirement.
However, periodically DOT or PHMSA
seeks public input on retrospective
review of existing regulations under
Executive Order 13563. PHMSA
encourages the commenter to raise this
issue the next time DOT or PHMSA
solicits comments on retrospective
review of existing regulations.
13. Alliance Pipeline suggested many
pipeline safety questions can be
answered by applying INGAA’s five
guiding principles of pipeline safety.
They noted INGAA has developed the
Integrity Management-Continuous
Improvement (IMCI) Initiative to
implement these principles and
suggested PHMSA actively engage with
INGAA in developing workable
solutions to pipeline safety issues.
Response
PHMSA appreciates the industry
efforts to improve pipeline safety and is
committed to working with all
stakeholders toward this end.
14. Paiute Pipeline and Southwest
Gas commented integrity management
requirements have not been in effect
long enough to gauge their effectiveness
and decide whether additional changes
are needed. The companies noted the
first, baseline assessments of pipeline
segments subject to those requirements
are only now being completed. AGA
and other pipeline operators agreed,
noting IM is still new, operators are still
refining their processes, and PHMSA
should approach change with caution.
Response
While the first round of baseline
assessments are only now being
completed, the gas IM rule has been in
place approximately 10 years. PHMSA
expects that operator IM programs
should have significantly matured in
this timeframe.
15. Panhandle Energy suggested that
PHMSA evaluate rule changes that
could have prevented incidents which
occurred in recent years. Any initiatives
that would not have contributed to
improved safety, they suggest, should be
postponed or treated as lower priority
activities. Panhandle suggested
rulemaking without a sound basis is not
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only ineffective but counterproductive
in that it diverts resources that could
have been used to improve safety.
Questar Gas similarly commented
PHMSA needs to minimize unnecessary
activities that inappropriately divert
safety resources. Questar also
recommended that PHMSA explicitly
consider the diversity within the
regulated community.
Response
One of the major motivations for
PHMSA’s issuance of the ANPRM was
to solicit information useful to ensuring
that pipeline safety reforms have a
sound basis. PHMSA is also required by
Executive Orders 12866 and 13563 to
ensure that the benefits of its rules
justify the costs, to the extent permitted
by law. PHMSA has prepared an initial
regulatory impact analysis for this
proposed rule, which is available in the
docket for this rule. PHMSA encourages
the commenter as well as other
members of the public to review the
analysis and provide input for
improving the final rule.
16. AGA and several pipeline
operators commented that, while
enhancements can be made, IM
requirements need not be subjected to
wholesale change. They cited GAO and
NTSB reports on the efficacy of
transmission pipeline integrity
management and the lack of pipeline
safety issues among the NTSB’s ‘‘Most
Wanted’’ issues.
Response
While PHMSA believes that IM has
led to improvements in managing
pipeline integrity, recent incidents and
accidents demonstrate that much work
remains to improve pipeline safety.
17. AGA and pipeline operators noted
that transmission and distribution
integrity management are not distinct
activities for most intrastate pipeline
operators. They contended that the
ANPRM seemed to be based on a
presumption that operators manage
their transmission and distribution
pipeline safety differently, and that this
assumption is without basis.
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Response
PHMSA has promulgated specific IM
rules for both transmission and
distribution systems with a view toward
allowing operators to customize their
performance based programs as
appropriate to their specific systems.
18. AGA and several pipeline
operators suggested that any changes to
public awareness requirements should
be made at the state level. They noted
that federal requirements in this area are
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new and that effectiveness reviews are
still in progress.
Response
This issue is not within the scope of
the ANPRM. However, PHMSA has
revised the pipeline safety regulations
related to pipeline damage prevention
programs in a final rule issued July 23,
2015 (80 FR 43836).
19. NACE International suggested that
adopting its standards for corrosion
control would be the best means to
accomplish the goal of maintaining
pipelines safe and functional for long
periods of time.
Response
This NPRM proposes to incorporate
industry consensus standards into the
regulations for assessing the physical
condition of in-service pipelines using
in-line inspection, internal corrosion
direct assessment, and stress corrosion
cracking direct assessment. In addition,
this NPRM proposes to enhance subpart
I requirements for corrosion control and
to revise Appendix D to improve
requirements for cathodic protection.
20. The NTSB commented that
regulations for gas transmission
pipelines can and should be improved
and expressed its support for the overall
intent of the ANPRM. The NTSB noted
publication of the ANPRM prior to its
recommendations resulting from the
San Bruno incident investigation
precluded any mention in the ANPRM
of these NTSB safety recommendations.
The NTSB suggested PHMSA should
seek comment on its recommendations.
Response
PHMSA has reviewed the NTSB
recommendations that were issued on
September 26, 2011 and found that
several recommendations related
directly to the topics addressed in the
ANPRM and that may impact the
proposed approach to rulemaking. The
topics impacted are discussed above in
the Background section above, in
sections II.C and II.E, and include NTSB
Recommendations P–11–10, P–11–11,
P–11–14, P–11–15, P–11–17, and P–11–
19. The NTSB’s other recommendations
will be addressed in separate
proceedings.
21. El Paso suggested that the proper
approach to attain the highest pipeline
safety levels is through a structured,
deliberate rulemaking that closely
examines all issue aspects prior to
making informed decisions.
Response
PHMSA agrees and is taking a careful,
structured, and phased approach to
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enhancing pipeline safety regulations
and IM performance standards.
22. Thomas M. Lael, a pipeline
industry consultant, suggested any new
regulations be concise and clear. He
contended past lack of clarity has
created the need for many reinterpretations and enforcement
problems.
Response
PHMSA concurs but also notes that
performance-based regulations, by their
nature, are not as specific, nor as easily
measurable, as prescriptive regulations,
but are more likely to improve safety
and the cost-effectiveness of regulations.
PHMSA provides guidance to help
stakeholders understand the intent and
scope of performance-based regulations.
General Public Comments
1. A member of the public stated that
the ANPRM did not provide specific
options for consideration. As written,
only those with direct involvement in
the industry could understand it well
enough to comment. Presenting the
options more specifically would allow
for better informed public comment.
The discussion should also include a
regional component, since issues
affecting different states/regions are not
the same.
Response
By its nature, the ANPRM did not
propose specific alternatives or rules,
but solicited input to help inform future
proposals. This NPRM provides specific
proposed rules for public comment.
2. The Alaska Natural Gas
Development Authority stated that the
regulations should require consideration
of earthquakes, as recent history shows
they can be very important to safety of
high-pressure gas lines.
Response
Section 29 of the Act states that in
identifying and evaluating all potential
threats to each pipeline segment, an
operator of a pipeline facility shall
consider the seismicity of the area.
Rulemaking for this issue is addressed
in this NPRM and would add
requirements to explicitly reference
seismicity for data gathering and
integration, threat identification and
implementation of preventive and
mitigative measures.
3. The Environmental Defense Fund
pointed out that methane is a very
potent greenhouse gas. They
commented that PHMSA should
consider and minimize the potential
environmental effects of any future
rulemaking. They suggested EPA’s
Natural Gas Star program as a model.
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Response
The proposals in this rulemaking are
designed to minimize the risk of
pipeline failures, which will result in
environmental benefits. The draft
environmental assessment addresses the
environmental effects of this
rulemaking.
In addition, the RIA provides
estimates of the environmental benefits
of this proposed rule. Natural gas
transported in transmission pipelines
contains heat-trapping gases that
contribute to global climate change and
its attendant societal costs. Of these
gases, of primary importance for
evaluation are methane—by far, the
largest constituent of natural gas—and
carbon dioxide. Other natural gas
components (ethane, propane, etc.)
contribute as well, but they account for
a much smaller percentage of the
natural gas mixture and, as a result, are
much less significant than methane in
terms of their environmental impact.
The proposed rule is expected to
prevent incidents, leaks, and other types
of failures that might occur, thereby
preventing future releases of greenhouse
gases (GHG) to the atmosphere, thus
avoiding additional contributions to
global climate change. PHMSA
estimated net GHG emissions abatement
over 15 years of 69,000 to 122,000
metric tons of methane and 14,000 to
22,000 metric tons of carbon dioxide,
based on the estimated number of
incidents averted and emissions from
pressure tests and ILI upgrades.
4. A member of the public questioned
the openness and clarity of PHMSA’s
enforcement of pipeline safety
regulations, and the use of civil penalty
revenues.
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Response
This comment is not within the scope
of the ANPRM topics, however, it
should be noted that PHMSA embraces
transparency in its regulatory oversight
program and has established a Pipeline
Safety Stakeholder Communications
Web site, https://primis.phmsa.dot.gov/
comm/, which presents a variety of
reports detailing enforcement activity.
These reports are offered on both
nationwide and operator-specific bases.
5. One member of the public
suggested that DOT define ‘‘safe
corridors’’ for above-ground
construction of pipelines. The
commenter suggested this would be
similar, in principle, to the interstate
highway system. It would help to keep
pipelines separated from residences,
avoid corrosive environments, and make
pipelines available for routine direct
examination. At a minimum, this
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commenter suggested the regulations
should specify a minimum separation
between new pipelines and residences,
as does the New Jersey state code, or
homebuyers be informed when a home
is within the potential impact radius of
a gas transmission pipeline so they may
make an informed buying decision.
Response
This comment addresses pipeline
siting and routing, which is outside the
scope of PHMSA’s statutory authority.
As specified in 49 U.S.C. 60104,
Requirements and Limitations of the
Act, PHMSA is prohibited from
regulating activities associated with
locating and routing pipelines.
Paragraph (e) of the statute states
‘‘Location and routing of facilities.—
This chapter does not authorize the
Secretary of Transportation to prescribe
the location or routing of a pipeline
facility.’’ However, PHMSA is an active
participant in the Pipeline and Informed
Planning Alliance (PIPA) and
encourages all stakeholders to learn
about, and become involved with, PIPA.
More information can be obtained
online at: https://primis.phmsa.dot.gov/
comm/pipa/landuseplanning.htm.
6. One member of the public noted
there is an increasing trend in
significant incidents and suggested that
this trend may be related to undue
influence of the pipeline industry on the
regulations under which it operates. The
commenter recommended regulations
should not be weakened in favor of
industry. The League of Women Voters
of Pennsylvania also recommended that
regulatory agencies be insulated from
political and other influences of natural
gas pipeline companies to avoid the
appearance of a conflict of interest.
Response
PHMSA appreciates these comments.
PHMSA is committed to improving
pipeline safety, and that is the goal of
this endeavor. Significant incidents on
Gas Transmission (GT) pipelines have
averaged between 70 and 80 incidents
per year over the past 9 years. The
existing integrity management
regulations in 49 CFR part 192, subpart
O, addresses pipeline integrity in HCAs,
which is only about 7 percent of the GT
pipeline mileage. This proposed NPRM
is focused on strengthening
requirements in HCAs and applying
integrity management principles to
areas outside HCAs to better address
safety issues. In addition, the proposed
rule seeks to address significant issues
that caused or contributed to the San
Bruno accident, which include lack of
pressure test, inadequate records, poor
materials, and inadequate integrity
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20741
assessment. The operator reports
submitted to PHMSA as mandated by
the Act confirm that these issues are
widespread for both HCA and non-HCA
pipe segments.
7. The Harris County Fire Marshall’s
Office (HCFM) suggested stiffer
regulations are needed for gas
transmission pipeline safety, because of
the large potential for negative impact
and catastrophic consequences. HCFM
expressed concern about corrosion
control and current inspection practices
for aging transmission infrastructure.
Response
This NPRM proposes enhanced
corrosion control requirements,
including periodic close interval
surveys, post construction surveys for
coating damage, and interference
current surveys. This NPRM also
proposes enhanced requirements for
internal corrosion and external
corrosion management programs.
8. The Pipeline Safety Trust (PST)
commented that the ANPRM, itself, may
heighten and fuel existing public
concerns about pipeline safety. PST
noted that many of the questions asked
the industry to provide information they
believe the public would believe
PHMSA should already have. PST
expressed its view that the number and
types of questions asked in the ANPRM
reflect gaps in PHMSA’s knowledge of
gas transmission pipeline systems and
operator practices.
Response
PHMSA appreciates these comments.
PHMSA is committed to improving
pipeline safety and stakeholder input is
valuable to the regulatory process.
9. Professional Engineers in California
Government (PECG) commented that
private companies should not be solely
responsible for the safety of their
pipelines. PECG contended that this
approach has not worked. PECG also
suggested PHMSA examine options for
increasing the number of inspectors at
state pipeline regulatory agencies and
require public inspectors be on site for
pipeline construction and testing. They
contended such inspection is necessary
to assure that older pipelines are tested
adequately and replaced when needed.
Response
PHMSA appreciates these comments.
PHMSA is committed to ensuring that
operators maintain and operate their
pipelines safely. This rulemaking
contains a number of measures aimed at
enhancing oversight.
10. The City and County of San
Francisco (CCSF) noted the scope of
potential rulemaking discussed in the
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ANPRM did not include consideration
of PHMSA’s coordination with and
oversight of state certified agencies. In
order to ensure the proper oversight
over natural gas transmission operators
and the safe operation of natural gas
transmission lines, CCSF believes
PHMSA must address its state
certification program and its oversight
of state enforcement of pipeline safety
standards. CCSF recommended PHMSA
publish regulations for certification of
state programs. They cited NTSB
recommendation P–11–20 and asserted
PHMSA has not corrected inadequate
practices of the California Public
Utilities Commission.
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Response
This comment is outside the scope of
this rulemaking. PHMSA is addressing
NTSB recommendation P–11–20
separately.
11. Two members of the public
suggested the processes of the Federal
Energy Regulatory Commission (FERC)
for siting pipelines should be revised.
One suggested a Commission on Public
Accountability and Safety Standards be
established, consisting of a majority of
local public officials, first responder
experts, and independent qualified
engineers, to make recommendations for
FERC’s pre-application process and
standards. The purpose would be to
assure standards require public
accountability for review and vetting of
pipeline safety issues with local
authorities when pipelines are
proposed. The other commenter
suggested the relationship between
FERC and DOT should be clarified, that
a company’s enforcement history be
taken into account in siting decisions,
and PHMSA be a full party to all FERC
proceedings. The commenter believes
this is necessary because FERC does not
have a public safety mandate.
Response
PHMSA is a separate agency from
FERC and has no statutory authority
with respect to pipeline siting or
approval. As specified in 49 U.S.C.
60104, Requirements and Limitations of
the Act, PHMSA is prohibited from
regulating activities associated with
locating and routing pipelines.
Paragraph (e) of the statute states
‘‘Location and routing of facilities.—
This chapter does not authorize the
Secretary of Transportation to prescribe
the location or routing of a pipeline
facility.’’ However, PHMSA is an active
participant in the Pipeline and Informed
Planning Alliance (PIPA) and
encourages all stakeholders to learn
about, and become involved with, PIPA.
More information can be obtained
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online at: https://primis.phmsa.dot.gov/
comm/pipa/landuseplanning.htm.
12. Two members of the public
commented federal regulations should
not override local ordinances. They
noted the concern of local authorities is
safety, while others are concerned about
industry costs. They believe federal
regulations that allow operators
significant discretion are a poor basis to
supersede specific local requirements.
Response
PHMSA appreciates these comments.
Federal regulations provide for a
uniform body of standards and
requirements related to pipeline safety.
PHMSA is receptive to input from state
and local authorities on pipeline safety
issues. States and local authorities may
adopt requirements that are more
stringent than and consistent with the
federal regulations for their intrastate
pipelines if they have a 49 U.S.C. 60105
certification.
13. One member of the public
suggested regulations require periodic
safety audits by an auditor not selected
by the pipeline operator. The
commenter further suggested that local
authorities should have approval
authority in the choice of the auditor.
The commenter contended this
approach would strengthen public
confidence in pipeline safety.
Response
PHMSA appreciates this comment.
Highly trained federal and state pipeline
inspectors conduct inspections of
pipeline operators, their facilities, and
their compliance programs on a regular
basis.
Comments on ANPRM Section II Topics
on Which PHMSA Sought Comment
In section II of the ANPRM,
commenters were urged to consider
whether additional safety measures are
necessary to increase the level of safety
for those pipelines that are in non-HCA
areas as well as whether the current IM
requirements need to be clarified and in
some cases enhanced to assure that they
continue to provide an adequate level of
safety in HCAs. PHMSA posed specific
questions to solicit stakeholder input.
These included questions related to the
following topics:
A. Modifying the Definition of HCA,
B. Strengthening Requirements to
Implement Preventive and Mitigative
Measures for Pipeline Segments in
HCAs,
C. Modifying Repair Criteria,
D. Improving Requirements for
Collecting, Validating, and Integrating
Pipeline Data,
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E. Making requirements Related to the
Nature and Application of Risk Models
More Prescriptive,
F. Strengthening Requirements for
Applying Knowledge Gained Through
the IM Program
G. Strengthening Requirements on the
Selection and Use of Assessment
Methods,
H. Valve Spacing and the Need for
Remotely or Automatically Controlled
Valves,
I. Corrosion Control,
J. Pipe Manufactured Using
Longitudinal Weld Seams,
K. Establishing Requirements
Applicable to Underground Gas Storage,
L. Management of Change,
M. Quality Management Systems
(QMS),
N. Exemption of Facilities Installed
Prior to the Regulations,
O. Modifying the Regulation of Gas
Gathering Lines.
Each topic is summarized as
presented in the ANPRM, then general
comments related to the topic are
presented, followed by each individual
question and comments received for the
question.
A. Modifying the Definition of HCA
The ANPRM stated that ‘‘IM
requirements in subpart O of part 192
specify how pipeline operators must
identify, prioritize, assess, evaluate,
repair and validate; [sic] through
comprehensive analyses, the integrity of
gas transmission pipelines in HCAs.
Although operators may voluntarily
apply IM practices to pipeline segments
that are not in HCAs, the regulations do
not require operators to do so. A gas
transmission pipeline ruptured in San
Bruno, California on September 9, 2010,
resulting in eight deaths and
considerable property damage. As a
result of this event, public concern has
been raised regarding whether safety
requirements applicable to pipe in
populated areas can be improved.
PHMSA is thus considering expanding
the definition of an HCA so that more
miles of pipe are subject to IM
requirements.’’ The ANPRM then listed
questions for consideration and
comment. The following are general
comments received related to the topic
as well as comments related to the
specific questions:
General Comments for Topic A
1. INGAA and a number of pipeline
operators noted this is an opportune
time for considering the next steps in
integrity management, since baseline
assessments under the current IM rules
are now being completed. INGAA noted
its policy goal is to apply IM principles
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(as described in ASME/ANSI B31.8S)
beyond HCAs, covering 90 percent of
people living near transmission
pipelines by 2020 and 100 percent by
2030. TransCanada submitted
information in support of INGAA’s
proposal, noting that by the end of 2012
the company will have assessed more
than 85 percent of its US pipeline
mileage covering more than 95 percent
of people living near their pipelines.
Thus, the current IM rules are having a
significant positive impact on pipeline
safety. TransCanada believes significant
technological challenges would be
encountered if IM regulations were
extended to all pipelines.
2. MidAmerican commented it would
be reasonable to differentiate between
transmission pipelines operating above
and below 30 percent specified
minimum yield strength (SMYS) in
terms of IM requirements. They
estimated that less than 3 percent of
local distribution company (LDC)
transmission lines operate at greater
than 30 percent SMYS.
3. MidAmerican and a member of the
public suggested PHMSA eliminate
class locations in favor of better-defined
HCAs. They contend such a change
would result in administrative savings
for pipeline operators.
4. Southwest Gas and Paiute
commented no new regulations should
be promulgated in this area until the
study required by the Pipeline Safety,
Regulatory Certainty, and Job Creation
Act of 2011 is completed.
Response to General Comments for
Topic A
PHMSA appreciates the information
provided by the commenters. Section 5
of the Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011
(the Act) (Pub. L. 112–90) requires the
Secretary of Transportation to ‘‘evaluate
(1) whether integrity management
system requirements, or elements
thereof, should be expanded beyond
high-consequence areas; and (2) with
respect to gas transmission pipeline
facilities, whether applying integrity
management program requirements, or
elements thereof, to additional areas
would mitigate the need for class
location requirements.’’ PHMSA has
completed the report mandated by the
Act that documents that evaluation and
addresses whether integrity
management (IM) program requirements
should be expanded beyond high
consequence areas (HCAs) and,
specifically for gas transmission
pipelines regulated under 49 Code of
Federal Regulations (CFR) part 192,
whether such expansion would mitigate
the need for class location designations
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and corresponding requirements. The
class location report is available for
review in the docket.
In October 2010 and August 2011, the
Pipeline and Hazardous Materials Safety
Administration (PHMSA) published
notices in the Federal Register to solicit
comments on revising the pipeline
safety regulations applicable to
hazardous liquid and natural gas
transmission pipelines including
expansion of IM program requirements
beyond HCAs. In general, industry
representatives and pipeline operators
were opposed to any expansion of HCAs
and in favor of eliminating class
locations on newly constructed
pipelines, whereas public interest
groups were in favor of expanding HCA
but against curtailing class location
requirements.
PHMSA has carefully considered the
input and comments. At this time
PHMSA plans to propose an approach
that balances the need to provide
additional protections for persons
within the potential impact radius (PIR)
of a pipeline rupture (outside of a
defined HCA), and the need to
prudently apply IM resources in a
fashion that continues to emphasize the
risk priority of HCAs. PHMSA,
therefore, is considering an approach
that would require selected aspects of
IM programs (namely, integrity
assessments and repair criteria) to be
applicable for non-HCA segments. For
hazardous liquid pipelines, PHMSA
would propose to apply these
requirements to non-HCA pipeline
segments. For gas transmission
pipelines, PHMSA would propose to
apply these requirements where persons
live and work and could reasonably be
expected to be located within a pipeline
PIR. Under this approach, PHMSA
would propose requirements that
integrity assessments be conducted, and
that injurious anomalies and defects be
repaired in a timely manner, using
similar standards in place for HCAs.
However, the other program elements of
a full IM program contained in 49 CFR
part 192, subpart O, or 49 CFR 195.452
(as applicable) would not be required
for non-HCA segments.
The Act also required the Secretary of
Transportation to evaluate if expanding
IM outside of HCAs, as discussed above,
would mitigate the need for class
location requirements. In August 2013,
PHMSA published a notice in the
Federal Register (78 FR 53086)
soliciting comments on expanding IM
program requirements and mitigating
class location requirements. In addition,
PHMSA held a Class Location
Workshop on April 16, 2014, to discuss
the notice and comments were received
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20743
from stakeholders, including industry
representatives, pipeline operators, state
regulatory agencies, and the public.
Overall, the majority of stakeholder
responses suggested that PHMSA not
change the current class location
approach for class locations and class
location changes as population
increases used for establishing MAOP
and operation and maintenance (O&M)
surveys for existing pipelines. For new
transmission pipelines, some industry
groups and operators supported some
type of bifurcated approach for existing
and new pipelines as described above.
Based upon stakeholder input and
findings from lessons learned, incident
investigations, assessments, IM, and
operating, maintenance, design and
construction considerations, PHMSA
believes the application of integrity
management assessment and
remediation requirements to MCAs does
not warrant elimination of class
locations. Class locations affect all gas
pipelines, including transmission
(interstate and intrastate), gathering, and
distribution pipelines, whether they are
constructed of steel pipe or plastic pipe.
Class location is integral to determining
MAOPs, design pressures, pipeline
repairs, high consequence areas (HCAs),
and operating and maintenance
inspections and surveillance intervals.
Class locations affect 12 subparts and 28
sections of 49 CFR part 192 for gas
pipelines. The subparts and sections are
listed and discussed in Sections 3.1.2.4
and 3.7.2.2. While assessment and
remediation of defects on gas
transmission pipelines is an important
risk mitigation program, it does not
adequately compensate for other aspects
of class location as it relates to other
types of gas pipelines and as it relates
(for all gas pipelines) to the original
pipeline design and construction such
as the design factor, initial pressure
testing, establishment of MAOP, O&M
activities, and other aspects of pipeline
safety, that are based on class location.
Thus, PHMSA has determined not to
eliminate class location requirements.
With respect to the application of gas
transmission IM requirements to
pipeline operating at less than 30%
SMYS, as part of its consideration of the
issues discussed in Topics J and N,
PHMSA considered but rejected the
suggestion that pipelines operating less
than 30% SMYS be differentiated from
those operating at higher stress levels.
Comments submitted for questions in
Topic A.
A.1—Should PHMSA revise the
existing criteria for identifying HCAs to
expand the miles of pipeline included in
HCAs? If so, what amendments to the
criteria should PHMSA consider (e.g.,
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increasing the number of buildings
intended for human occupancy in
Method 2?) Have improvements in
assessment technology during the past
few years led to changes in the cost of
assessing pipelines? Given that most
non-HCA mileage is already subjected
to in-line inspection (ILI), does the
contemplated expansion of HCAs
represent any additional cost for
conducting integrity assessments? If so,
what are those costs? How would
amendments to the current criteria
impact state and local governments and
other entities?
1. INGAA, industry consultant
Thomas Lael, and a number of pipeline
operators commented that modification
of the HCA definition is unnecessary.
They contended that the current
definition is already risk-based and
provides an effective basis for IM
requirements along with a reasonable
point from which to expand the
application of IM principles by
voluntary action. Accufacts commented
that PHMSA should focus on closing
gaps and loopholes rather than
increasing HCA mileage, and that
increasing covered mileage would only
create the illusion of more safety.
2. AGA, APGA, and a number of gas
distribution pipeline operators also
opposed changes to the definition. They
commented that other requirements of
part 192 already address the primary
threats for pipe outside HCA. They
noted that much effort went into
establishing the current definition, there
is no safety rationale to abandon it, and
change would be inconsistent with riskbased principles and would dilute
safety efforts. AGA further noted that
imprudent expansion would be contrary
to Congressional intent, in that it would
dilute the focus on densely populated
and environmentally sensitive areas.
AGA commented that PHMSA should
make no change in this area before
completing the related studies required
by the Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011.
3. Taking a contrary position, a
number of commenters not affiliated
with the pipeline industry supported
increasing the pipeline mileage
classified as HCA. One private citizen
suggested that all pipelines in cities
with population greater than 100,000
should be classified as HCA. This
commenter believes that existing
regulations result in insufficient
requirements for urban pipelines.
Another citizen suggested that all highstress lines with a ‘‘receptor,’’ which he
defines as ‘‘something which needs to
be protected,’’ should be assessed. If
changes to the HCA definition are
needed to accomplish this, then he
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contended those changes should be
made. The Pipeline Safety Trust would
strengthen IM requirements and expand
them to all transmission pipelines,
although they allow that the details
could be different for pipelines not
currently classified as HCA. PST
believes this would be an effective way
to identify and eliminate threats.
4. The Oklahoma Independent
Petroleum Association (OKIPA)
commented that any changes to the
HCA definition must be supported by a
scientifically-valid assessment of risks
and a complete cost-benefit analysis.
5. The Iowa Association of Municipal
Utilities commented that PHMSA
should not revise the HCA definition
without taking into account the
differences between high-pressure
transmission pipelines and lowpressure, low-risk lines that are also
classified as transmission. IAMU
reported ‘‘transmission lines’’ operated
by Iowa Municipal Utilities are typically
2 to 4 inches in diameter and have
potential impact radii less than 90 feet.
6. The Texas Pipeline Association and
Texas Oil & Gas Association contended
that expanding HCA pipeline mileage
would increase assessment costs,
particularly if the arbitrary requirement
for reassessments every 7 years is not
changed. These associations also believe
that additional assessments will result
in significant service interruptions.
They suggested that assessment
requirements be expanded to other
pipelines, if needed, rather than
changing the definition of HCA,
contending that this would allow a more
reasoned approach not burdened by the
requirement for 7-year reassessments.
7. The Texas Pipeline Association,
Texas Oil & Gas Association and several
pipeline operators disagreed with the
ANPRM assertion that most non-HCA
transmission pipeline has been subject
to ILI inspections. They noted much
non-HCA pipeline has been pigged (i.e.,
assessed using an in-line inspection
tool) but that intrastate transmission
pipelines are typically not piggable.
8. MidAmerican suggested that there
is no reason to believe that changes to
the HCA definition would improve
safety. They also noted that the effects
of other recent regulatory changes have
not yet been realized and could mask
any effect of changes in HCA. At the
same time, the company noted that
revising the definition of an HCA to
encompass potential impact circles with
15 structures intended for human
occupancy, vs. the current 20, would
increase the amount of HCA mileage on
its pipeline system by about 10 percent,
contending that the safety benefit of
such a change would be questionable.
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They suggested it would be better to
focus on pipe in HCAs rather than
adding lower-risk pipe, since part 192
already provides a good level of safety
for all pipelines.
9. INGAA and a number of pipeline
operators commented that increasing
the amount of HCA mileage would add
or increase costs for hundreds of state
and local government agencies. The
increases would result from increased
demands for identification, certification,
and compliance auditing.
10. Northern Natural Gas suggested
that PHMSA consider expanding HCA
coverage by modifying the specifics of
Method 2 for defining HCAs over time.
Changes could include reducing the
number of structures in potential impact
circles that define an HCA, reducing the
number of people that defines an
identified site, etc. The company
believes this kind of change would have
the benefit of continued use of the
‘‘science’’ represented by the C–FER
Technologies circle for determining
HCAs (see part 192, appendix E, figure
E.I.A). Northern also suggested PHMSA
define a time period for occupation of
an identified site which, they
contended, would eliminate the need to
address locations where a gathering of
people is truly transient.
11. TransCanada reported its belief
that the current HCA criteria provide an
appropriate risk focus. In support of this
belief, they noted that only 3 percent of
their US transmission pipeline mileage
is in HCAs but this includes 45 percent
of the population within a potential
impact radius of their pipelines.
12. The Iowa Utilities Board opposed
changes to the HCA criteria to
encompass more mileage. IUB
commented that such changes would
divert resources from application to
higher-risk pipeline segments and there
has been no demonstration that nonHCA pipeline segments pose as much
risk as those currently defined as HCA.
13. Two private citizens and the
Commissioners of Wyoming County,
Pennsylvania, suggested the existence of
one structure intended for human
occupancy within a potential impact
circle should be sufficient to define an
HCA. These commenters noted that
catastrophic consequences (i.e., loss of
life) are still possible in such sparsely
populated areas. The Commissioners
noted homes in their jurisdiction
generally did not encroach on the
pipelines; the homes were there first
and the pipeline encroached on what
should have been a safe zone around the
home. They implied pipeline operators
should expect a higher burden to assure
safety in such circumstances.
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14. The Pipeline Safety Trust
commented that there should be a single
set of criteria defining HCAs and that
these criteria should be known to the
public. They contended the public
currently has no information on the
criteria defining HCAs.
15. The California Public Utilities
Commission commented that HCA
criteria should be revised to include
more pipeline mileage and that method
2 (use of potential impact circles)
should be eliminated.
16. The Alaska Natural Gas
Development Authority suggested that
the definition of an HCA should
accommodate the phenomenon of rapid
growth in previously rural areas. They
noted that such growth has occurred
within Alaska due, in part, to disposal
of state lands.
17. NAPSR suggested that PHMSA
require all transmission pipelines to
meet Class 3 and 4 requirements and
eliminate HCAs. NAPSR contended that
focusing resources on higher-risk
pipelines is bad public policy, since an
accident anywhere poses a risk to public
safety and reduces public confidence.
18. The Texas Pipeline Association,
Texas Oil & Gas Association and several
pipeline operators objected to the
implication in the ANPRM that
assessment costs have decreased. They
contended that costs have actually
increased due to such factors as
operational cost escalation and
increased costs to address cased
pipeline segments.
19. INGAA and a number of pipeline
operators contended that costs cannot
be estimated accurately absent a specific
regulatory proposal. They suggested that
additional costs would be minimal if
expanding HCA mileage results in
actions similar to INGAA’s Integrity
Management—Continuous Improvement
(IMCI) action plan, but that costs could
be high if different requirements are
imposed.
20. INGAA reported that a recent
survey showed that its members’
identified baseline IM assessments will
cover 64 percent of members’ pipeline
mileage, only 4 percent of which is in
HCAs. INGAA stated that these
assessments will have covered 90
percent of the population within a
potential impact radius of the pipelines.
21. Southwest Gas and Paiute
provided cost estimates for conducting
IM assessments on their pipeline
systems: $45,000 per mile for direct
assessment, up to $125,000 per mile for
in-line inspection, and from $200,000 to
$2 million per instance where changes
need to be made to a pipeline to
accommodate instrumented pigs.
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22. The California Public Utilities
Commission and MidAmerican
commented that costs would increase if
the changes suggested in the ANPRM
were made, but they provided no
specific estimates.
23. APGA noted that costs incurred by
or passed on to municipal utilities are
costs to local governments, since the
utilities are, themselves, government
agencies.
24. Paiute and Southwest Gas noted
that costs to local governments,
including preparation of permits, paving
repairs, etc., can be high.
25. An anonymous commenter
suggested that costs are not likely to
increase much, since most operators
already assess more than HCAs and IM
has fostered growth in ILI vendors.
26. Kern River noted that its costs
would not increase much, since the
company is already under similar
restrictive requirements via special
permit.
27. Accufacts noted that safety is not
free. They suggested that relative
ranking of assessment methods, by cost,
is not likely to have changed. They
cautioned that costs used in cost-benefit
analyses supporting any rules must be
credible and should have an auditable
trail available to the public. They
suggested that serious accidents can be
a ‘‘cost’’ of associated deregulation and
lack of proper, effective, and efficient
safety regulatory oversight for this
critical infrastructure.
Response to Question A.1 Comments
PHMSA appreciates the information
provided by the commenters. PHMSA
agrees that the definition of HCAs is
adequate, and does not propose to
modify the definition of scope of HCAs
in this proposed rulemaking. However,
to afford additional protections to other
segments along the pipeline, PHMSA is
proposing to apply selected IM program
elements (namely assessment and
remediation of defects) to areas outside
HCAs that are newly defined as MCAs.
PHMSA believe this approach applies
appropriate risk-based levels of safety.
A.2. Should the HCA definition be
revised so that all Class 3 and 4
locations are subject to the IM
requirements? What has experience
shown concerning the HCA mileage
identified through present methods (e.g.,
number of HCA miles relative to system
mileage or mileage in Class 3 and 4
locations)? Should the width used for
determining class location for pipelines
over 24 inches in diameter that operate
above 1000 psig be increased? How
many miles of HCA covered segments
are Class 1, 2, 3, and 4? How many
miles of Class 2, 3, and 4 pipe do
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20745
operators have that are not within
HCAs?
A.3. Of the 19,004 miles of pipe that
are identified as being within an HCA,
how many miles are in Class 1 or 2
locations?
1. Industry trade associations,
pipeline operators, and the Iowa
Utilities Board objected to the
suggestion all Class 3 and 4 locations
should be treated as HCA. They noted
class location does not have a direct
relationship to risk. Small, low-pressure
pipelines with no structures intended
for human occupancy within the PIR (or
for which the PIR is contained entirely
within the right of way) could be Class
3 or 4 under current definitions. INGAA
noted approximately 90 percent of Class
3 and 4 mileage not in HCA is presently
assessed through over testing during IM
assessments. Kern River commented
that class location is an outmoded
system that is confusing and unduly
complex. Many of these commenters
noted there is no demonstration of need
for including all Class 3 and 4 areas,
since existing HCA criteria adequately
identify areas posing higher risks.
2. Public commenters took a contrary
position, suggesting class locations are a
reasonable basis for increasing HCA
mileage. Pipeline Safety Trust and
California Public Utilities Commission
commented all Class 3 and 4 locations
should be HCA. They noted these are all
highly populated areas putting more
people at risk from pipeline accidents.
CPUC noted the location of the
significant 2010 pipeline accident in
San Bruno, CA, could have avoided
HCA classification if method 2 of the
current definition had been used. An
anonymous commenter supported this
position, suggesting all Class 3 and 4
locations be treated as HCA and use of
method 2 be restricted to Class 1 and 2
locations; this commenter contended
use of method 2 to exclude some
portions of Class 3 and 4 locations from
HCA classification is inappropriate.
This commenter further suggested the
definition of Class 4 locations be
revised, contending that the criterion of
4-story buildings being ‘‘prevalent’’ is
not specific enough. Thomas Lael, an
industry consultant, suggested all Class
4 locations should be HCA. Lael
contended that this would be an easy
change and would assure that the
highest risk pipe is included.
3. NAPSR also suggested all Class 3
and 4 locations should be classified as
HCA. NAPSR noted this is an
alternative to their preferred solution of
eliminating HCA and requiring that all
transmission pipelines meet Class 3 and
4 requirements.
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4. One public commenter went
further. He suggested a new
classification, Class 5, be established
encompassing all pipeline in cities with
populations of more than 100,000. He
further suggested pipe in this new class
should meet enhanced construction
requirements, including required
installation of automatic valves to
isolate the pipeline in the event of an
incident. He contended the existing
regulations impose inadequate safety
requirements on urban pipelines.
5. Accufacts suggested PHMSA focus
first on closing loopholes and gaps
rather than increasing HCA mileage.
They commented increasing covered
mileage without closing gaps would
produce only the illusion of safety.
6. Northern Natural Gas suggested
PHMSA consider an option of
eliminating method 2 of the current
HCA definition. They contended such a
change would be easy to accomplish. At
the same time, they questioned its
efficacy, suggesting that it would result
in limited or no increase in safety while
imposing large costs.
7. INGAA and many pipeline
operators objected to the suggested
increase in the width of a class location
unit for larger, high-pressure pipelines.
They noted such a change would
contravene the goals of IM and divert
resources to pipe of lower risk, and pipe
of this type posing high risks to
population concentrations is already
included as HCA based on its potential
impact radius (which could be larger
than 220 yards).
8. Here, again, public commenters
generally took a contrary position.
Pipeline Safety Trust suggested class
location width should be at least as
much as the potential impact radius.
PST noted the PIR is intended to focus
on areas requiring more protection
while the existing class location width
is arbitrary. Two private citizens agreed,
one noting that large-diameter, highpressure gathering pipelines in the
Marcellus shale area are located slightly
more than 220 yards from pre-existing
houses and the other suggesting the
class location width in higher-class
areas should be 220 yards or the PIR,
whichever is larger. Accufacts would go
further, suggesting class location width
be increased for large-diameter pipe
regardless of pressure. Accufacts
contended diameter is a more
significant factor in determining the
potential extent of post-accident damage
than is pressure, noting the devastation
resulting from the San Bruno accident
extended to a much greater distance
than the PIR. The Texas Pipeline
Association and Texas Oil & Gas
Association commented no change
should be made until the studies
required by the Pipeline Safety,
Regulatory Certainty, and Job Creation
Act of 2011 are completed.
9. INGAA and a number of pipeline
companies submitted data concerning
the amount of pipeline mileage
currently in HCAs. INGAA’s data is
based on a survey of its members.
INGAA
Class 1 ..........
Class 2 ..........
Class 3 ..........
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Class 4 ..........
Paiute
SWGas
MidAmerican
Northern Natural
475 miles HCA,
103,286 not.
535 miles HCA, 11,318
not.
4,100 miles HCA, 4,
646 not.
24 miles HCA, 5 not ....
1 mile HCA, 632 not ....
<1 of 382 miles are
HCA.
<1 of 20 miles are HCA
0.63 miles HCA,
493.11 not.
0.98 miles HCA,
101.92 not.
44.96 miles HCA,
128.38 not.
no HCA mileage ..........
0.1% of all mileage is
HCA.
2% of mileage is HCA.
0 miles HCA, 55 not ....
26 miles HCA, 142 not
None of less than 1
mile is HCA.
10. Iowa Association of Municipal
Utilities reported its members have zero
HCA miles in any class. Most member
transmission pipelines are in Class 1
locations. Members have 1.46 miles of
Class 2 pipe and one mile in Class 3.
11. Ameren Illinois reported 3.5 of its
82 HCA miles are in Class 1 or 2.
12. Kern River reported it has 18.51
HCA miles in Class 1 and 3.14 miles in
Class 2, of a total of 95.96 miles of HCA.
13. On March 15, 2012, PHMSA
received a petition for rulemaking from
the Jersey City Mayor’s office
contending that the current Class
Location system ‘‘does not sufficiently
reflect high density urban areas, as the
regulation fails to contemplate either (1)
the dramatic differences in population
densities between highly congested
areas and other less dense Class 4
Locations, or (2) the full continuum of
population densities found in urban
areas themselves.’’ Based on this, Jersey
City petitioned PHMSA to add three (3)
new Class Locations, which would be
defined as follows:
• A Class 5 location is any class
location unit that includes one or more
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185 miles HCA, 242
not.
6 miles HCA, 5 not ......
building(s) with between four (4) and
eight (8) stories;
• A Class 6 location is any class
location unit that includes one or more
building(s) with between nine (9) and
forty (40) stories;
• A Class 7 location is any class
location unit that includes at least one
building with at least forty-one (41)
stories.
Response to Questions A.2 and A.3
Comments
PHMSA appreciates the information
provided by the commenters. PHMSA
agrees that HCAs should not be based
exclusively on class location. Similarly,
PHMSA does not propose to define
MCAs based on class location. PHMSA
proposes that moderate consequence
area means an onshore area that is
within a potential impact circle, as
defined in § 192.903, containing five (5)
or more buildings intended for human
occupancy, an occupied site, or a rightof-way for a designated interstate,
freeway, expressway, and other
principal 4-lane arterial roadway as
defined in the Federal Highway
Administration’s Highway Functional
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27% of mileage is
HCA.
no data reported.
Classification Concepts, Criteria and
Procedures, and does not meet the
definition of high consequence area, as
defined in § 192.903. This assures a
comparable level of safety for all
pipelines, regardless of class location.
As a result, PHMSA is not proposing to
expand class locations in this proposed
rule. The issue of expanding class
locations is addressed in the class
location report which is available for
review in the docket while formulating
comments.
A.4. Do existing criteria capture any
HCAs that, based on risk, do not provide
a substantial benefit for inclusion as an
HCA? If so, what are those criteria?
Should PHMSA amend the existing
criteria in any way which could better
focus the identification of an HCA based
on risk while minimizing costs? If so,
how? Would it be more beneficial to
include more miles of pipeline under
existing HCA IM procedures, or, to focus
more intense safety measures on the
highest risk, highest consequence areas
or something else? If so why?
1. INGAA and several pipeline
operators commented the method
described in paragraph 2 in the
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definition of HCA in § 192.903
appropriately focuses attention on atrisk populations. They contended that
the method described in paragraph 1 in
the definition of HCA in § 192.903
captures some inappropriate areas.
2. Texas Pipeline Association, Texas
Oil & Gas Association, and Ameren
Illinois contended the existing criteria
do not capture areas not posing risk.
They noted the criteria were based on
the science of pipeline accidents to
identify high-risk areas.
3. Paiute and Southwest Gas
commented neither more HCA miles nor
additional safety measures are needed.
They contended existing criteria are
adequate and rule provisions for
preventive and mitigative measures and
to consider pipe with similar conditions
when anomalies are found in HCA are
sufficient to address non-HCA pipeline
segments.
4. APGA recommended the
regulations be modified to treat
transmission pipelines operated by local
distribution companies, most of which
operate at less than 30 percent SMYS,
under distribution integrity
management rather than transmission
IM. APGA suggested this is an optimum
time to make this change, which was
discussed in the phase 1 work leading
up to the distribution IM rule. Atmos
agreed, noting failure by leakage rather
than rupture, similar to distribution
pipelines, is much more prevalent for
this low-stress pipeline and it thus
poses much lower risks.
5. Northern Natural Gas suggested
PHMSA revisit its treatment of ‘‘well
defined areas’’ that constitute identified
sites. They contended current practice
treats an entire area as an identified site
even if only an unoccupied corner is
within the PIR and persons congregating
are outside that critical radius.
6. MidAmerican suggested PHMSA
consider adding a multiplier to the PIR
equation for higher-stress pipelines.
They contended this could capture more
high-risk pipe without adversely
affecting low-stress pipelines that pose
considerably less risk.
7. Atmos commented no change
should be made which would increase
the amount of HCA mileage, contending
that this would dilute the current focus
on high-risk pipe.
8. INGAA and several of its members
suggested PHMSA rely on its Integrity
Management—Continuous Improvement
(IMCI) initiative to address pipeline in
non-HCA areas.
Response to Question A.4 Comments
PHMSA appreciates the information
provided by the commenters. PHMSA
agrees that the existing method for
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identifying HCAs and calculating PIR is
appropriate and is not proposing a
change to either. However, PHMSA
disagrees that existing requirements are
sufficient for non-HCAs segments.
PHMSA believes non-HCA segments
where people congregate should be
afforded additional protections.
Therefore, PHMSA is proposing that
selected IM program elements
(assessment and remediation of defects)
be applied to MCAs.
A.5. In determining whether areas
surrounding pipeline right-of-ways meet
the HCA criteria as set forth in part 192,
is the potential impact radius sufficient
to protect the public in the event of a
gas pipeline leak or rupture? Are there
ways that PHMSA can improve the
process of right-of-ways HCA criteria
determinations?
1. INGAA, AGA, GPTC and a number
of pipeline operators contended the
existing PIR criteria are sufficiently
conservative. They noted the criteria
were derived from scientific analysis of
the consequences of past pipeline
accidents. Texas Pipeline Association
and Texas Oil & Gas Association
commented there is no reason to modify
the PIR criteria or to establish alternate
criteria to define HCAs; they contended
there is no evidence the current PIR
definition has provided insufficient
protection to the public.
2. One private citizen and Alaska’s
Department of Natural Resources
suggested HCA criteria should be
revised to consider parallel pipelines in
a common right of way, contending that
an accident on one pipeline could
impact adjacent lines, thus
compounding consequences. They
further suggested requirements for
pipelines in common rights of way
should include minimum spacing
between the pipelines.
3. An anonymous commenter
suggested plume releases be considered
to determine which pipeline segments
can affect an HCA, contending that this
would be a good practice.
4. AGA, Texas Pipeline Association,
Texas Oil & Gas Association, GPTC, and
several pipeline operators cautioned
against use of the term ‘‘right of way’’
in the context of defining HCAs. They
noted this term is imprecise and the
actual location of the pipeline, rather
than an ill-defined right of way, is the
important factor in evaluating risk.
5. Accufacts, INGAA, and numerous
pipeline operators cautioned against
discussions that imply that the PIR
concept is applicable to considerations
of risk from pipeline leaks. These
commenters noted that the PIR is based
on the consequences of a pipeline
rupture and resulting conflagrations and
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was never intended to address leaks not
involving fires.
6. ITT Exelis Geospatial Systems, a
company providing services to the
pipeline industry, noted accurate
location of a pipeline is as important to
assuring adequate protection of highrisk populations as is the calculation of
PIR.
7. Accufacts suggested PHMSA
require a report of the actual impact
area, including aerial photographs,
within 24 hours of any pipeline rupture.
Accufacts contended this data would
provide a further basis for continuing
review of PIR adequacy.
Response to Question A.5 Comments
PHMSA appreciates the information
provided by the commenters. PHMSA
agrees that the existing definition of PIR
is appropriate at this time. PHMSA
believes that adjusting the PIR formula
based on parallel pipelines in the rightof-way, or other right-of-way factors, are
premature at this time. Also, PHMSA
acknowledges that the PIR approach
only applies such incidents resulting in
explosions and fires. While certain gases
might be better modeled using plume
models, such models have not been
carefully studied or developed.
However, PHMSA plans to pursue
(outside the scope of this rulemaking)
additional incident reporting
requirements for the purpose of further
evaluating the extent of damage
following incidents.
A.6. Some pipelines are located in
right-of-ways also used, or paralleling
those, for electric transmission lines
serving sizable communities. Should
HCA criteria be revised to capture such
critical infrastructure that is potentially
at risk from a pipeline incident?
1. INGAA, AGA, Texas Pipeline
Association, Texas Oil & Gas
Association, and many pipeline
operators objected to any potential
inclusion of ‘‘critical infrastructure’’ in
HCA criteria. They noted there is no
history of problems caused by impacts
on infrastructure, there is little public
risk involved, data regarding such
infrastructure would be difficult for
pipeline operators to obtain, and issues
involving potential interactions with
critical infrastructure are usually
addressed during pipeline planning and
construction.
2. GPTC and Nicor recommended
HCA criteria not be revised to include
critical infrastructure. They noted the
intent of defining HCAs is to address
risk to life and not property damage and
damages to local infrastructure are
unlikely to result in consequences
similar to those that could affect
population concentrations near the
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pipeline. Atmos agreed, noting planning
for accident-caused outages is a
responsibility of electric system
operators.
3. Pipeline Safety Trust, Accufacts,
NAPSR, Alaska Department of Natural
Resources, California Public Utilities
Commission and ITT Exelis Geospatial
Systems recommended critical
infrastructure be included among HCAdefining criteria. Several of these
commenters suggested infrastructure
beyond electric transmission be
considered, including, for example,
water and sewage treatment plants, fire
stations, and communications facilities.
The commenters noted damages to
critical infrastructure can lead to
cascading effects and additional public
safety consequences. ITT Exelis
acknowledged these considerations may
be secondary to loss of life but
contended they are still important to
public safety.
4. Northern Natural Gas, Kern River,
MidAmerican, Paiute, and Southwest
Gas noted determining the impact of
damages to infrastructure items is
complex. These commenters suggested
it is not practical to define what
constitutes ‘‘critical’’ infrastructure,
from a public safety standpoint, on a
generic basis. They recommended
PHMSA leave consequence
determination to operators, as part of
their risk assessments, providing
additional guidance for such
considerations if needed.
5. An anonymous commenter
suggested more frequent tests of
cathodic protection and coating surveys
be required in areas potentially subject
to induced currents from nearby electric
transmission infrastructure.
Response to Question A.6 Comments
PHMSA appreciates the information
provided by the commenters. PHMSA
agrees that there have been relatively
few pipeline incidents that have had a
major impact on critical infrastructure.
PHMSA also acknowledges that the PIR
formula was developed based on life
safety (i.e., heat flux that result in
fatalities). However, PHMSA is also
aware of recent incidents that, among
other consequences, damaged and
caused temporary closure of interstate
highways. Among them are the 2012
incident at Sissonville, WV and the
2010 incident at New Delhi, LA, which
also resulted in one fatality. Even
though PHMSA is not proposing to
revise the HCA criteria or the PIR
formula, PHMSA is proposing to
include major highways in the MCA
criteria.
A.7. What, if any, input and/or
oversight should the general public and/
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or local communities provide in the
identification of HCAs? If commenters
believe that the public or local
communities should provide input and/
or oversight, how should PHMSA gather
information and interface with these
entities? If commenters believe that the
public or local communities should
provide input and/or oversight, what
type of information should be provided
and should it be voluntary to do so? If
commenters believe that the public or
local communities should provide
input, what would be the burden
entailed in providing provide this
information? Should state and local
governments be involved in the HCA
identification and oversight process? If
commenters believe that state and local
governments be involved in the HCA
identification and oversight process
what would the nature of this
involvement be?
1. INGAA and its pipeline operator
members commented no additional
public involvement is needed. INGAA
noted consultation is required under the
current regulations, and it seldom
identifies any relevant information.
Additional involvement, INGAA
contends, would likely lead to
inconsistencies and would degrade the
technical/scientific basis for
determining HCAs.
2. AGA and several of its member
companies suggested local government
agencies should provide information
when requested by pipeline operators.
They contended additional required
involvement would pose an additional
burden on pipeline operators while
adding no benefit. AGA noted
information from its members suggests
that local government agencies very
rarely point out identified sites not
otherwise known to the pipeline
operator.
3. Texas Pipeline Association, Texas
Oil & Gas Association, GPTC, Nicor,
Ameren Illinois and Oleksa and
Associates (a pipeline industry
consultant) suggested further
involvement of local governments not
be required. These commenters
contended pipeline operators have more
relevant knowledge and involvement of
inexperienced entities in identifying
HCAs is more likely to result in
confusion than useful information. The
Texas associations suggested current
public awareness requirements afford
sufficient involvement of local agencies.
4. Accufacts noted local governmental
agencies have maps identifying
locations important to public safety and
suggested these maps should be used by
pipeline operators in HCA
determinations. Accufacts believes this
could assist operators in assuring
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consideration of accurate, complete, and
current information.
5. Northern Natural Gas reported it
has a phone number and email address
that local residents and agencies can use
to provide input to its HCA
determinations. Northern further
reported no HCAs have been identified
from information provided via these
avenues that were not otherwise known
to the company.
6. Public commenters suggested local
residents and government agencies
should receive more information
concerning pipelines and HCAs. One
commenter suggested operators should
provide copies of IM plans upon
request, and should provide prior
notification to residents within a PIR of
assessments and a subsequent report of
assessment results or problems
otherwise identified. This individual
also suggested locations of HCAs and
assessment trend results should be
provided to local communities upon
request. The League of Women Voters of
Pennsylvania suggested distribution
integrity management plans should be
readily available and the public should
be involved in decisions related to those
plans.
7. Pipeline Safety Trust commented
public review should be part of any
process by which PHMSA reviews or
approves of HCA identifications.
8. Wyoming County Pennsylvania
Commissioners suggested stakeholder
meetings and public comment periods
be required as part of HCA
identification. They noted local
residents know their communities better
than others, including expected changes
that could affect HCA identification.
9. AGA and several of its member
operators recommended local
governments play no role in oversight of
HCA determinations. They contended
this would increase burden and result in
inconsistencies and confusion.
10. An anonymous commenter
suggested existing public awareness
contacts should be used to improve
HCA determinations. The commenter
expressed the belief this existing
structure could allow low-cost
involvement of local officials in such
determinations.
11. The NTSB suggested PHMSA
work with states to employ oversight of
pipeline IM plans based on objective
metrics. The NTSB noted this would be
consistent with recommendation P–11–
20 resulting from its investigation of the
San Bruno, CA pipeline accident.
12. Iowa Association of Municipal
Utilities noted local government
employees are involved when HCA
determinations are made by municipal
utilities and further requirements for
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local involvement would be
inappropriate for such operators.
Response to Question A.7 Comments
PHMSA appreciates the information
provided by the commenters. PHMSA is
continuing to evaluate this aspect of
integrity management but has not yet
reached any conclusions. PHMSA may
consider this input for future action, if
applicable.
A.8. Should PHMSA develop
additional safety measures, including
those similar to IM, for areas outside of
HCAs? If so, what would they be? If so,
what should the assessment schedule
for non-HCAs be?
1. Pipeline operators and their
associations generally agreed additional
measures were not needed outside HCA.
INGAA and several transmission
pipeline operators suggested operators
be allowed to apply the principles of
ASME/ANSI B31.8S voluntarily, as
needed. INGAA noted this is the
concept behind its Integrity
Management—Continuous Improvement
(IMCI) initiative.
2. AGA and a number of its member
operators noted the regulations already
require implementation of preventive
and mitigative measures outside of HCA
for low-stress pipe (§ 192.935(d)). These
requirements include using qualified
personnel to conduct work that could
adversely affect the integrity of the
covered segment, collecting excavation
damage information, and participating
in one-call systems.
3. Ameren Illinois and MidAmerican
commented additional measures are not
needed, because existing operations &
maintenance requirements already
assure integrity.
4. GPTC and Nicor agreed, noting it
would be inappropriate to apply IM
measures outside of HCA and existing
requirements are assuring an adequate
level of safety.
5. Atmos contended the existing
provision requiring that operators
evaluate and remediate non-HCA
pipeline segments when corrosion is
found during an IM assessment of a
covered pipeline segment
(§ 192.917(e)(5)) already provides that
actions be taken to assure the integrity
of non-HCA pipeline segments.
6. Texas Pipeline Association and
Texas Oil & Gas Association would not
object to a phased expansion of IM
requirements provided that required
assessment intervals are scientifically
based. The associations noted Texas
pipelines are already subject to the
broader requirements of the Texas IM
rule. They commented phased
implementation would assure the nexthighest risks are addressed first and
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would allow time for IM-support
resources to grow.
7. Iowa Association of Municipal
Utilities commented new requirements
are not needed for its members’
pipelines. These lines are smalldiameter, low-pressure, odorized, and
already pose low risk.
8. Northern Natural Gas suggested
PHMSA expand the HCA definition
gradually over time rather than
imposing IM requirements outside HCA.
Northern commented such an approach
would retain and expand the focus on
areas posing the highest risk.
9. Accufacts commented repair
criteria, including required response
times, and reporting of anomalies
should be the same in- or outside HCA,
since the progression of an anomaly to
failure is unrelated to whether the
anomaly exists within or outside of an
HCA.
10. Pipeline Safety Trust suggested
non-HCA pipeline segments should be
subject to a baseline of IM requirements.
11. The Commissioners of Wyoming
County Pennsylvania suggested PHMSA
consolidate operators’ best practices and
require assessment of all pipe frequently
enough to realize a benefit. They
commented this approach would assure
a consistent level of public protection
regardless of the practices of individual
pipeline operators.
12. California Public Utilities
Commission noted this question would
be moot if method 2 for defining HCA
is eliminated.
Response to Question A.8 Comments
PHMSA appreciates the information
provided by the commenters. Although
most industry commenters did not
support expansion of integrity
management requirements outside
HCAs, PHMSA believes additional
protections are needed for pipeline
segments where people are expected
within the PIR. In this NPRM, PHMSA
proposes an approach that balances the
need to provide additional protections
for persons within the potential impact
radius (PIR) of a pipeline rupture
(outside of a defined HCA), and the
need to prudently apply IM resources in
a fashion that continues to emphasize
the risk priority of HCAs. The proposed
regulation would require selected
aspects of IM programs (namely,
integrity assessments and repair criteria)
to be applicable for selected non-HCA
segments defined as MCAs. An MCA
would be a segment located where
persons live and work and could
reasonably be expected to be located
within a pipeline PIR. PHMSA would
propose requirements that integrity
assessments be conducted, and that
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20749
injurious anomalies and defects be
repaired in a timely manner, using
similar standards in place for HCAs.
However, the other program elements of
a full IM program contained in 49 CFR
part 192, subpart O would not be
required for MCA segments.
A.9. Should operators be required to
submit to PHMSA geospatial
information related to the identification
of HCAs?
1. Most industry commenters,
including INGAA, AGA, and numerous
pipeline operators supported this
proposed requirement. They noted
submission of this data will be required
for PHMSA to comply with the mapping
provisions of the Pipeline Safety,
Regulatory Certainty, and Job Creation
Act of 2011.
2. Accufacts, Alaska Department of
Natural Resources, California Public
Utility Commission, and one private
citizen agreed, suggesting PHMSA
should know where HCAs are located
and that this information is important to
emergency responders. CPUC also
suggested operators should be required
to submit this information to State
regulatory authorities as well.
3. Pipeline Safety Trust also
supported this proposal, adding the
information should be shared with the
public.
4. League of Women Voters of
Pennsylvania and Accufacts also
supported making maps identifying
pipeline locations, including HCA,
available to the public.
5. Atmos, Northern Natural Gas, Kern
River, Nicor, and GPTC opposed a
requirement to submit this information.
They noted this is a large amount of
information which is available for
audits and questioned how it would be
used by PHMSA and how related
security issues would be addressed.
6. Ameren Illinois suggested a
requirement to submit HCA locations is
not needed, since location data on the
entire pipeline system must already be
submitted to the National Pipeline
Mapping System.
7. Texas Pipeline Association, Texas
Oil & Gas Association, and
MidAmerican agreed that providing
HCA information as part of NPMS
submissions is adequate. They noted
this is consistent with Section 6 of the
Pipeline Safety, Regulatory Certainty,
and Job Creation Act of 2011.
Response to Question A.9 Comments
PHMSA appreciates the information
provided by the commenters. Most
commenters supported the submittal of
HCA information in geospatial format.
As noted by one commenter, this is
required by the Act. Although outside
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the scope of this rulemaking, PHMSA is
pursuing data reporting improvements
by proposing revisions to its currently
approved information collection for the
National Pipeline Mapping System.
PHMSA has published several Federal
Register notices and held several public
workshops on the proposals.
A.10. Why has the number of HCA
miles declined over the years?
1. Responses to this question
consisted of speculation regarding
reasons why the number of HCA miles
may have declined. No commenters
reported having specific data to describe
the reducing trend.
2. AGA suggested pipe replacement,
reductions in MAOP, and use of better
data could be among the many reasons
for a decline in HCA mileage.
3. INGAA speculated the reduction
could be a result of operators changing
from method 1 to method 2 to identify
HCAs and abandoning or retiring older
pipelines.
4. Texas Pipeline Association, Texas
Oil & Gas Association, Atmos, and a
private citizen agreed a change in the
method for identifying HCAs is a likely
reason for the decreasing mileage trend.
5. Northern Natural Gas commented
changes in land use over time result in
changes in the pipeline segments
identified as HCA. Northern noted it has
changed from method 1 to method 2 for
identifying HCA but that the change had
resulted in an increase in HCA mileage
rather than a decrease. Kern River also
reported that its HCA mileage is
increasing, citing changes in land use
along the pipeline as the reason for this
change.
6. GPTC and Nicor suggested
operational changes and removal of pipe
from service could be the cause of the
observed changes.
7. Iowa Utilities Board noted
reductions in pressure and other
operational changes can eliminate
covered pipeline segments. IUB also
suggested a change from method 1 to
method 2 and better analyses of
potential impact circles, etc. could have
resulted in decreased HCA mileage.
8. MidAmerican noted its HCA
mileage has fluctuated but remains
relatively constant overall. They noted
periodic fluctuations result from
changes in various parameters that go
into identifying HCAs.
9. A private citizen suggested
operators may be buying properties
within potential impact circles and
razing them or that new pipelines in
rural areas may be replacing current
pipelines.
10. An anonymous commenter
suggested HCA mileage is decreasing
because operators are getting better at
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identifying HCAs. The commenter noted
operators have been doing so for 9 years.
Response to Question A.10 Comments
PHMSA appreciates the information
provided by the commenters. PHMSA
considered this input in its evaluation
mandated by the Act.
A.11. If commenters suggest
modification to the existing regulatory
requirements, PHMSA requests that
commenters be as specific as possible.
1. Accufacts commented property
damage costs reported to PHMSA
following pipeline incidents appear to
be understated. Accufacts noted this
raises serious questions about the
validity of cost-benefit analyses
performed using this data.
2. Iowa Association of Municipal
Utilities commented the costs to comply
with IM-like requirements are not
justified for small, low-pressure
transmission pipelines such as those
operated by its members. Significant
costs to develop IM plans, evaluate
remote valves, and comply with other
IM requirements must be passed on to
a small rate base for many municipal
utilities.
3. ITT Exelis Geospatial Systems
suggested HCA criteria be revised and
requirements for protection of critical
infrastructure and populated areas be
made more prescriptive. They
commented such changes would require
that leak surveys be performed more
frequently, providing improved safety.
4. ITT Exelis Geospatial Systems
reported its leak detection systems,
developed as part of research jointly
sponsored with DOT and other agencies,
could facilitate this testing and initial
costs would be offset by longer term
savings.
5. California Public Utilities
Commission observed the public has
indicated its desire for more
prescriptive safety requirements.
Response to Question A.11 Comments
The Act requires that the Secretary of
Transportation to evaluate whether
integrity management requirements
should be expanded beyond HCAs and
whether such expansion would mitigate
the need for class location requirements.
The proposed rulemaking does not
change the HCA definition. However,
PHMSA is proposing pipeline
assessment requirements in new
§ 192.710 for newly defined moderate
consequence areas (MCAs). PHMSA is
also proposing new requirements in
§ 192.607 for verification of pipeline
material and § 192.624 for MAOP
verification would also apply to MCAs.
PHMSA performed a Preliminary
Regulatory Impact Analysis, using the
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best available data and information. It is
available on the docket and PHMSA
invites comments on the PRIA.
B. Strengthening Requirements To
Implement Preventive and Mitigative
Measures for Pipeline Segments in
HCAs
Section 192.935 requires gas
transmission pipeline operators to take
additional measures, beyond those
already required by part 192, to prevent
a pipeline failure and to mitigate the
consequences of a potential failure in a
HCA following the completion of a risk
assessment. Section 192.935(a) specifies
examples of additional measures, which
include, but are not limited to installing
automatic Shut-off Valves or Remote
Control Valves; installing computerized
monitoring and leak detection systems;
replacing pipe segments with pipe of
heavier wall thickness; providing
additional training to personnel on
response procedures; conducting drills
with local emergency responders; and
implementing additional inspection and
maintenance programs. In the ANPRM,
PHMSA expressed concern that these
additional measures are not explicitly
required. As a result, operators may not
be employing the appropriate additional
measures as intended. Section
192.935(b) specifies that operators are
also required to enhance their damage
prevention programs and to take
additional measures to protect HCA
segments subject to the threat of outside
force damage (non-excavation). PHMSA
also noted in the ANPRM that the
provisions in § 192.935 only apply to
HCAs and that the expansion of the
HCA definition would increase the
mileage of pipelines subject to
§ 192.935. Further, PHMSA
acknowledged the consideration of
expanding preventive and mitigative
measures to pipelines outside of HCAs.
The following are general comments
received related to the topic as well as
comments related to the specific
questions:
General Comments for Topic B
1. INGAA suggested PHMSA can
substantially improve prevention and
mitigation of accidents caused by
excavation damage by facilitating full
implementation of state damage
prevention programs. INGAA further
suggested PHMSA actively promote the
use of 811 one-call programs. INGAA
noted excavation damage remains the
most prevalent cause of serious
incidents and failure to notify is a
primary cause of these incidents. Many
pipeline operators supported the
INGAA comments.
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2. INGAA, supported by many of its
pipeline operator members, noted it has
a policy goal to apply integrity
management principles, voluntarily, to
pipelines beyond HCAs. Their goal is to
address 90 percent of the population
near pipelines by 2020 and 100 percent
by 2030 through application of
appropriate principles from ASME/
ANSI B31.8S.
3. AGA supported application of IM
principles, but not assessment
requirements, outside HCAs. AGA
commented requiring operators to
understand and address risks is a good
application of IM principles. Many
pipeline operators supported the AGA
comments.
4. AGA commented the ANPRM
incorrectly states that § 192.935 applies
only to pipe within HCAs. AGA noted
paragraph (d) of that section applies to
low-stress pipe in Class 3 and 4 areas
that is not in HCAs.
5. California Public Utilities
Commission suggested pipelines
installed prior to the promulgation of
federal pipeline safety requirements (socalled ‘‘pre-code’’ pipe) be reassessed
more frequently.
6. Alaska Natural Gas Development
Authority commented Alaska’s
experience indicates improved pipeline
design and construction requirements
are needed to assure pipeline integrity.
These would include stronger pipe,
improved requirements for mainline
valves (including spacing and remote
operation), and improved corrosion
control. The Authority also commented
that design requirements need to
accommodate likely changes in class
location, noting that explosive growth in
some Alaska areas has resulted in rapid
changes from Class 1 to Class 3.
7. One private citizen suggested some
level of assessment should be required
for all pipelines.
8. Another private citizen suggested
integrity management plans for densely
populated areas (Class 4 and Class 5—
a new class suggested by the commenter
encompassing cities with population
greater than 100,000) should be
developed in consultation with local
emergency responders. The commenter
further suggested these plans should be
available at the FERC environmental
impact study stage and should be
reviewed with local authorities.
9. Another private citizen suggested
information should be shared across
pipeline operators, noting this would
augment the knowledge of individual
companies and improve safety.
Similarly, the commenter suggested
PHMSA require operators to submit a
list of preventive and mitigative
measures that have been implemented
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and reports of their effectiveness. The
commenter noted PHMSA should know
this information but apparently does
not, as indicated by questions posed in
this ANPRM (particularly questions B.1
and B.2).
Comments Submitted for Questions in
Topic B
B.1. What practices do gas
transmission pipeline operators now use
to make decisions as to whether/which
additional preventive and mitigative
measures are to be implemented? Are
these decisions guided by any industry
or consensus standards? If so, what are
those industry or consensus standards?
1. Most industry commenters
indicated ASME/ANSI B31.8S is a
common standard used to guide
decisions concerning preventive and
mitigative measures. INGAA suggested
enhancing this standard would be the
best approach to provide additional
guidance for selection and
implementation of these measures.
Other commenters also cited the GPTC
Guide as a useful guideline. INGAA
listed other standards used by pipeline
operators, including:
• Common Ground Alliance Best
Practices
• Pipelines and Informed Planning
Alliance Recommended Practices
• API–RP 1162—Public Awareness
Programs,
• API–RP 1166—Excavation Monitoring
• NACE SP0169, other associated NACE
standards
• Gas Piping Technology Committee
guidance materials
• RSTRENG—A Modified Criterion for
Evaluating the Remaining Strength of
Corroded Pipe
• INGAA Foundation Guidelines for
Evaluation and Mitigation of
Expanded Pipes
AGA also noted that operators are
guided by their own risk assessments.
Many pipeline operators supported the
INGAA and AGA comments.
2. Northern Natural Gas reported it
does not rely on a specific consensus
standard to select preventive and
mitigative measures. It relies, instead,
on company subject matter experts
guided by statistical analyses of their
risk model.
3. Paiute and Southwest Gas reported
they use an algorithm combining risk
scores, threats, and the value of specific
measures. Company engineers analyze
the results of applying this algorithm
and develop preventive and mitigative
measure implementation plans.
4. An anonymous commenter noted
many pipeline operators are
implementing actions that could be
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considered preventive and mitigative
measures but these actions may not be
identified as such if they are
implemented as part of operations and
maintenance activities and not
specifically included in IM plans.
5. INGAA suggested PHMSA would
benefit by applying ASME/ANSI B31.8S
in its IM enforcement activities.
B.2. Have any additional preventive
and mitigative measures been
voluntarily implemented in response to
the requirements of § 192.935? How
prevalent are they? Do pipeline
operators typically implement specific
measures across all HCAs in their
pipeline system, or do they target
measures at individual HCAs? How
many miles of HCA are afforded
additional protection by each of the
measures that have been implemented?
To what extent do pipeline operators
implement selected measures to protect
additional pipeline mileage not in
HCAs?
1. INGAA reported many pipeline
operators have implemented additional
preventive and mitigative measures.
INGAA does not keep data on this and
did not provide examples. Some
pipeline operators submitted examples
in support of the INGAA comments.
Preventive and mitigative measures
cited in these examples include:
• Additional reconnaissance (after
seismic events, floods, etc.);
• Concrete mats over pipelines in
areas particularly susceptible to
excavation damage;
• Encroachment sensors;
• Remotely operated valves;
• Removal of casings;
• Completion of CIS surveys;
• Clearing of rights-of-way;
• Derating/deactivating of pipelines;
• Relocation of pipelines;
• Increased inspection of river
crossings;
• Lowering of shallow pipelines;
• Installation of additional marker
posts;
• Revising marking standards for
locates;
• Completing depth-of-cover surveys;
• Enhancing right-of-way patrols.
In addition, one pipeline operator
reported augmented implementation of
many requirements of part 192 and
implementation of some requirements
(e.g., operator qualification) beyond
their specified bounds.
2. AGA also reported many additional
preventive and mitigative actions have
been implemented but, again, does not
keep data on them. Examples cited by
AGA and its operator members included
increased use of indirect inspection
tools, increased patrols, and
investigation of apparent instances of
encroachment.
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3. GPTC reported data is not collected
concerning voluntary measures.
4. Texas Pipeline Association and
Texas Oil & Gas Association similarly
reported that they do not collect this
data, and there was only limited
response to a survey of their operators
regarding this question. The
associations reported their
understanding that measures are not
generally implemented system-wide.
5. California Public Utilities
Commission reported some CA
operators are stationing personnel at the
location of excavations near
transmission pipelines. CAPUC also
noted California’s one-call law requires
a mandatory field meeting before any
excavation near a transmission pipeline
operating above 60 psi.
6. An anonymous commenter
suggested operators avoid implementing
non-required actions for fear they will
lead to new requirements.
7. Industry comments indicated data
is not collected concerning the extent of
implementation of voluntary preventive
and mitigative measures. Some
measures are implemented in specific
HCAs while others may be implemented
more broadly across a pipeline system.
The extent depends largely on the threat
being addressed and its prevalence.
8. Northern Natural Gas reported it
has implemented voluntary measures
outside HCA, citing as examples highvisibility markers in Class 1 areas and
use of LIDAR leak detection. Northern
reported broad implementation of
voluntary measures is more prevalent
than site specific use.
9. MidAmerican reported virtually all
of its transmission pipeline mileage is
subject to at least one preventive and
mitigative measure.
10. Paiute reported nine measures are
applied to all of its 856 miles of
transmission pipeline while 13 are
applicable to all 27 miles of HCA.
11. Similarly, Southwest Gas has
implemented nine measures on 841
miles and 13 on all 191 miles of HCA.
12. AGA reported that approximately
195,000 non-HCA miles have been
assessed, generally through assessing
pipe upstream and downstream of the
HCA segment.
B.3. Are any additional prescriptive
requirements needed to improve
selection and implementation
decisions? If so, what are they and why?
1. Industry commenters unanimously
agreed no new prescriptive
requirements are needed. INGAA
pointed out selection of preventive and
mitigative measures is based on criteria
in consensus standards and operator
judgment. INGAA contended this allows
appropriate customization and results in
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improved safety. AGA agreed, noting
operators are in the best position to
decide what is needed for their pipeline
systems. GPTC stated that its Guide is
sufficient, and there has been no
demonstrated safety need for additional
requirements. Several pipeline operators
suggested conducting assessments and
making repairs provides the most
effective safety improvement.
2. Paiute and Southwest Gas
suggested a best practices workshop to
share industry experience could be
beneficial.
3. Accufacts suggested additional
prescriptiveness is needed to guide
decisions regarding remote and
automatically operated valves in HCA.
4. The Alaska Department of Natural
Resources would suggest signoff by a
professional engineer on preventive and
mitigative action decisions.
5. The NTSB recommended improved
use of metrics in inspection protocols,
citing their recommendations P–11–18
and 19.
6. One private citizen suggested the
lack of specifically-required actions in
the regulations represents a deficiency
in the pipeline safety regulatory
program. The commenter suggested the
extent of operator judgment be limited
and that state and local officials should
participate in developing a list of
applicable preventive and mitigative
actions.
7. An anonymous commenter
suggested including more examples of
preventive and mitigative actions in the
regulations would help guide operator
consideration of appropriate actions.
The commenter also suggested operators
be required to update their risk
analyses, and selection of preventive
and mitigative actions, more frequently
including after changes in their pipeline
systems or the occurrence of significant
events.
B.4. What measures, if any, should
operators be required explicitly to
implement? Should they apply to all
HCAs, or is there some reasonable basis
for tailoring explicit mandates to
particular HCAs? Should additional
preventative and mitigative measures
include any or all of the following:
Additional line markers (line-of-sight);
depth of cover surveys; close interval
surveys for cathodic protection (CP)
verification; coating surveys and
recoating to help maintain CP current to
pipe; additional right-of-way patrols;
shorter ILI run intervals; additional gas
quality monitoring, sampling, and inline
inspection tool runs; and improved
standards for marking pipelines for
operator construction and maintenance
and one-calls? If so, why?
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1. INGAA, supported by many of its
pipeline operator members, commented
prescriptive requirements are not
needed. INGAA contended prescriptive
requirements are neither effective nor
efficient and that ASME/ANSI B31.8S
and the GPTC Guide provide sufficient
guidance.
2. AGA commented one-call
requirements and the actions required
by the Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011
are the only actions that should be
required on a system-wide basis. AGA
further suggested it could be appropriate
to apply the additional measures
required of low-pressure pipelines in
§ 192.935(d) to pipelines operating
above 30 percent SMYS.
3. Texas Pipeline Association and
Texas Oil & Gas Association
recommended no new requirements be
adopted applying specific preventive
and mitigative actions throughout
pipeline systems. The associations
noted part 192 already requires
application of some measures
throughout pipeline systems and
expressed their conclusion these
already-specified measures are
sufficient.
4. MidAmerican commented requiring
application of specified measures
throughout pipeline systems would
provide a disincentive for the
application of other measures which
could be more appropriate.
5. The NTSB recommended
requirements for leak detection in
SCADA systems should be improved,
citing their recommendation P–11–10.
6. California Public Utilities
Commission recommended operators be
required to station stand-by personnel at
excavations near transmission pipelines
and operator procedures should specify
the actions these stand-by personnel
must take. CPUC further suggested these
standby activities should be a covered
task under operators’ personnel
qualification programs.
7. Pipeline Safety Trust recommended
PHMSA mandate the NTSB
recommendations, noting many are
similar to the specific measures
suggested in this question. PST further
commented operators should not be
allowed sufficient latitude to render a
regulation meaningless.
8. An anonymous commenter
suggested the regulations should not
specify particular preventive and
mitigative measures but should
emphasize consideration of potential
accident consequences when selecting
actions. The commenter noted there are
too many variables to specify particular
actions in regulation.
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9. A private citizen suggested
operators should be required to conduct
drills with local responders periodically
as part of their integrity management
programs. The commenter noted such
drills would improve coordination and
would validate the ability to respond in
the event of an emergency.
10. A private citizen suggested
stronger enforcement is needed based
on the belief that operators should
already be taking many of the actions
suggested in this question.
11. With respect to the specific
actions suggested in this question:
a. Line-of-sight markers: National
Utility Locating Contractors Association
recommended line-of-sight markers be
required, noting that they would reduce
the instances of excavators failing to call
for a locate, which the Common Ground
Alliance’s Damage Information
Reporting Tool (DIRT) continues to
indicate is a major cause of excavation
damage. The Association further
recommended the message on markers
should be visible from all angles, noting
that most current markers are only
visible from two directions. The
Commissioners of Wyoming County
Pennsylvania, and MidAmerican
suggested line-of-sight markers should
be required, noting that they are a lowcost good practice for improving safety.
An industry consultant disagreed,
noting installation would be impractical
in many areas where the sight line is
obscured by crops, terrain, etc.
b. Depth of cover: MidAmerican
opposed required depth of cover
surveys, commenting they are not a
good indicator of likely damage and
such surveys are inherently inaccurate.
Texas Pipeline Association and Texas
Oil & Gas Association suggested
compliance with depth of cover
requirements over time is impractical.
They noted operators do not have full
control over rights of way and that
owners can make changes. For example,
a landowner may pave an area following
grading which reduces the depth of
cover. California Public Utilities
Commission recommended depth of
cover surveys be required wherever
external corrosion direct assessment is
applied and where vehicles or other
loads capable of damaging the pipeline
have access to the surface over the
pipeline. Wyoming County
Pennsylvania’s Commissioners
suggested depth of cover surveys be
required as a good safety practice.
c. Close interval surveys:
MidAmerican recommended against
requiring these surveys. The company
noted they are only one means of
determining the adequacy of cathodic
protection. The Commissioners of
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Wyoming County Pennsylvania
recommended such surveys be required
as a good safety practice.
d. Coating surveys and re-coating:
MidAmerican opposed a requirement
for coating surveys, noting holidays are
found and repaired through in-line
inspection and external direct
assessment. The company further noted
pipe replacement is often a superior
repair to recoating. The Wyoming
County Commissioner commented
periodic coating surveys are a good
practice and recommended that they be
required.
e. Additional right of way patrols:
MidAmerican and the Wyoming County
Commissioners agreed increased
frequency of patrols would be
appropriate. MidAmerican noted patrols
are a relatively low cost action that
generates useful data.
f. Shorter ILI intervals: MidAmerican
opposed shorter intervals, noting many
lines cannot accommodate in-line
inspection or more frequent runs. The
Wyoming County Commissioners
argued that frequent assessment is a
good practice that should be required.
g. Additional gas quality monitoring:
MidAmerican opposed such a
requirement, arguing it would be
redundant for distribution pipeline
operators receiving gas from suppliers.
The Wyoming County Commissioners
argued frequent gas monitoring would
be a good practice.
h. Improved pipeline marking
standards: MidAmerican agreed
implementing new marking standards
would be a low cost action. Wyoming
County again noted this is a good
practice.
B.5. Should requirements for
additional preventive and mitigative
measures be established for pipeline
segments not in HCAs? Should these
requirements be the same as those for
HCAs or should they be different?
Should they apply to all pipeline
segments not in HCAs or only to some?
If not all, how should the pipeline
segments to which new requirements
apply be delineated?
1. INGAA, supported by many of its
member companies, argued preventive
and mitigative measures should be
applied to non-HCA areas on a risk basis
rather than by prescriptive requirement.
INGAA commented this is a more
effective and efficient means of
increasing pipeline safety.
2. AGA commented codifying
different requirements for non-HCA
areas would likely cause confusion and
extending existing IM requirements to
non-HCA areas would create an
enormous burden for PHMSA and
states. AGA noted the NTSB has already
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questioned the ability of regulators to
apply the existing IM inspection
protocols to HCA mileage. AGA
recommended one-call and the actions
required by statute be the only
additional measures required systemwide.
3. GPTC, Texas Pipeline Association,
Texas Oil & Gas Association, and two
pipeline operators opposed
requirements for preventive and
mitigative actions in non-HCA areas.
These commenters argued it is
important to allow pipeline operators
the flexibility to select actions that are
appropriate to their circumstances and
implementing actions required
arbitrarily would be expensive and
ineffective.
4. Northern Natural Gas suggested
PHMSA expand the HCA definition
gradually over time rather than
imposing IM requirements outside HCA.
Northern commented such an approach
would retain and expand the focus on
areas posing the highest risk.
5. MidAmerican opposed additional
requirements for preventive and
mitigative actions, noting all pipeline is
covered by other requirements in part
192 and it is better to focus enhanced
requirements on areas posing highest
risk.
6. AGA commented measures
required in HCA should always be equal
to or more stringent than measures
required outside of HCA. AGA noted
this is a fundamental principle of
integrity management: Focusing on
areas posing higher risks.
7. Ameren Illinois and an anonymous
commenter suggested better
enforcement and/or specificity for
provisions requiring operators consider
other areas of their systems when
problems are discovered would be more
effective than requiring preventive and
mitigative measures outside HCA.
8. ITT Exelis Geospatial Systems
commented requirements should be the
same in- or outside HCA. They
contended non-HCA areas are not
monitored for leakage as often as Class
3 and 4 locations. They suggested their
LIDAR system would allow effective
and efficient leak surveys in all
locations.
9. A public citizen recommended
exposed pipe be wrapped in bright
colors and protected from damage
whether inside or outside of HCA. The
commenter suggested analysis of data
from CGA’s Damage Information
Reporting Tool would be an effective
preventive measure.
B.6. If commenters suggest
modification to the existing regulatory
requirements, PHMSA requests that
commenters be as specific as possible.
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In addition, PHMSA requests
commenters to provide information and
supporting data related to, among other
factors, the potential costs of modifying
the existing regulatory requirements
pursuant to the commenter’s
suggestions.
1. Northern Natural Gas reported the
additional cost of preventative and
mitigative measures it employs,
including instrumented aerial leakage
surveys, close-interval surveys,
additional mailings and additional
signage, has been approximately
$950,000. Northern further reported the
approximate cost of conducting
assessments through in-line inspection
or pressure testing for all highconsequence areas every seven years is
$45,000,000 and reduction of the
inspection interval would increase the
cost accordingly.
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Response to Topic B comments
Section 5 of the Act requires that the
Secretary of Transportation complete an
evaluation and issue a report on
whether integrity management
requirements should be expanded
beyond HCAs and whether such
expansion would mitigate the need for
class location requirements. Aspects of
this topic that relate to applying a risk
analysis to determine additional
preventive and mitigative measures for
non-HCA pipeline segments will be
addressed later, pending completion of
the evaluation and report. PHMSA will
review the comments received on this
topic and will address them in the
future in light of these statutory
requirements.
Section 3 of the Act requires that the
Secretary of Transportation complete an
evaluation and issue a report on the
impact of excavation damage on
pipeline safety. Aspects of this topic
that relate to additional preventive and
mitigative measures for damage
prevention will be addressed after
completion of the evaluation and report.
PHMSA will review the comments
received on this topic and will address
them in the future in light of this
evaluation and report.
Section 6 of the Act requires that the
Secretary of Transportation provide
guidance on public awareness and
emergency response plans. Aspects of
this topic that relate to additional
preventive and mitigative measures for
public awareness and emergency
response will be further evaluated in
conjunction with this statutory
mandate. PHMSA will review the
comments received on this topic and
will address them in the future in light
of this evaluation.
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Two specific areas of preventive and
mitigative actions addressed in the IM
requirements (49 CFR 192.935) are leak
detection and automatic/remote control
valves. The IM rule does not require
specific measures be taken to address
these aspects of pipeline design and
operations, but does include them
among candidate preventive and
mitigative measures operators should
consider. Both of these topics are the
subject of recommendations that the
NTSB made (recommendations P–11–10
and P–11–11) following the San Bruno
explosion. In response to these
recommendations, PHMSA conducted a
public workshop on March 27, 2012, to
seek stakeholder input on these issues,
and is sponsoring additional research
and development to further inform
PHMSA’s response on these issues.
Aspects of this topic that relate to leak
detection and automatic/remote control
valves will be addressed after
completion and evaluation of the above
activities. PHMSA will review the
comments received on leak detection
and automatic/remote control valves
and will address them in the future in
light of this evaluation.
PHMSA is proposing to add
requirements for enhanced preventive
and mitigative measures to address
internal and external corrosion control.
The intent of the IM rulemaking is to
enhance protections for high
consequence areas. PHMSA believes
that enhanced requirements for internal
corrosion and external corrosion control
are prudent. To address internal
corrosion, PHMSA is proposing specific
requirements for operators to monitor
gas quality and contaminants and to
take actions to mitigate adverse
conditions. To address external
corrosion, PHMSA is proposing specific
requirements for operators to monitor
and confirm the effectiveness of external
corrosion control through electrical
interference surveys and indirect
assessments, including cathodic
protection surveys and coating surveys,
to take actions needed to mitigate
conditions that are unfavorable to
effective cathodic protection, and to
integrate the results of these surveys
with integrity assessment and other
integrity-related data. PHMSA addresses
this topic in more detail in response to
comments related to Topic I, Corrosion
Control.
Note: Specific comments submitted for
Topic B that are related to risk and integrity
assessments are addressed under Topics E
and G.
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C. Modifying Repair Criteria
The existing integrity management
regulations establish criteria for the
timely repair of injurious anomalies and
defects discovered in the pipe (49 CFR
192.933). These criteria apply to
pipeline segments in an HCA, but not to
segments outside an HCA. The ANPRM
announced that PHMSA is considering
amending the integrity management rule
by revising the repair criteria to provide
greater assurance that injurious
anomalies and defects are repaired
before the defect can grow to a size that
leads to a leak or rupture. In addition,
PHMSA is considering establishing
repair criteria for pipeline segments
located in areas that are not in an HCA
in order to provide greater assurance
that defects on non-HCA pipeline
segments are repaired in a timely
manner. The following are general
comments received related to the topic
and then comments related to the
specific questions:
General Comments for Topic C
1. INGAA reported its members’
commitment to apply ASME/ANSI
B31.8S corrosion anomaly criteria both
inside and outside of HCAs. INGAA
noted that new research to refine and
extend the technical bases for
responding to corrosion anomalies
identified primarily by ILI has been
completed by Pipeline Research Council
International, whose report was
expected to be published in the first
quarter of 2012. INGAA also reported a
commitment to develop and use criteria
for mitigation of dents, corrosion
pitting, expanded pipe corrosion, and
selective seam weld corrosion.
Numerous pipeline operators supported
INGAA’s comments.
2. AGA suggested that ASME/ANSI
B31.8S should be the basis for defining
anomalies requiring remediation.
Anomalies not meeting the criteria in
that standard, in AGA’s opinion, do not
require repair. AGA further commented
that risk prioritization of maintenance
and anomaly response should not be
regulated because operators are in the
best position to know the factors
influencing prioritization for
apparently-similar anomalies. AGA also
suggested that PHMSA review INGAA’s
paper ‘‘Anomaly Response and
Mitigation Outside of High Consequence
Areas when Using in Line Inspection,’’
dated May 30, 2010, as this paper forms
the basis for current industry response
outside of HCAs. Numerous pipeline
operators supported AGA’s comments.
3. Accufacts contended that there
have been too many corrosion-caused
ruptures occurring shortly after in-line
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inspection runs and that this indicates
the need for more prescriptive criteria
for corrosion evaluation and
remediation.
4. Alaska Department of Natural
Resources commented that repairs
should be made using permanent
methods, and that clamps and similar
repairs are not sufficient.
Response to General Comments for
Topic C
PHMSA appreciates the information
provided by the commenters. Because
the current repair criteria only address
corrosion metal loss as an immediate
condition, PHMSA agrees that more
prescriptive repair criteria are needed to
address significant corrosion metal loss
that does not meet the immediate repair
criterion, similar to the hazardous liquid
integrity management repair criteria at
49 CFR 195.452(h). In addition, other
conditions that are not currently
addressed in the repair criteria, such as
stress corrosion cracking and selective
seam weld corrosion, are addressed in
ASME B31.8S and other sources, but not
explicitly addressed in part 192.
PHMSA is proposing to enhance the
repair criteria for HCA segments and is
also proposing to add specific repair
criteria for pipeline in non-HCA
segments. In general, PHMSA is
proposing to add more immediate repair
conditions and more one-year
conditions for HCA segments. The
additional criteria address conditions
not previously addressed, such as stress
corrosion cracking, and also include
more specific one-year criteria for
corrosion metal loss, based on the
design factor for the class location in
which the pipeline is located, to address
corrosion metal loss that reduces the
design safety factor of the pipe. PHMSA
is also proposing to apply similar repair
criteria in non-HCA segments, except
that response times will be tiered, with
longer response times for nonimmediate conditions. PHMSA
reviewed available industry literature,
including ASME/ANSI B31.8S, in
developing the proposed repair criteria.
Specific aspects of the proposed rules
are discussed in response to the specific
questions for Topic C, below.
PHMSA has not addressed the
specific procedures and techniques for
performing repairs in this rulemaking,
but may do so at a later date.
Comments Submitted for Questions in
Topic C
C.1. Should the immediate repair
criterion of failure pressure ratio (FPR)
≤1.1 be revised to require repair at a
higher threshold (i.e., additional safety
margin to failure)? Should repair safety
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margins be the same as new
construction standards? Should class
location changes, where the class
location has changed from Class 1 to 2,
2 to 3, or 3 to 4 without pipe
replacement have repair criteria that are
more stringent than other locations?
Should there be a metal loss repair
criterion that requires immediate or a
specified time to repair regardless of its
location (HCA and non-HCA)?
1. INGAA, supported by numerous
pipeline operators, commented the FPR
criterion need not be changed, noting
there have been no reported incidents
due to the criterion being too lax.
INGAA also objected to PHMSA’s
characterization of this issue, noting
that repair criteria already exceed 1.1
FPR; the 1.1 FPR criterion in the
regulations governs response to
anomalies and not the criteria to which
repairs must be made.
2. AGA, supported by numerous of its
pipeline operator members, commented
that the FPR criterion should not be
changed. AGA contended that the
criterion already provides a 10 percent
safety margin and is based on sound
engineering practices.
3. Northern Natural Gas and Kern
River stated that conservatism is present
in burst pressure calculations and in the
measurement of anomalies (considering
tool tolerance), providing a safety
margin greater than 10 percent.
4. Accufacts argued against changing
the FPR criterion, but suggested that
PHMSA require operators to use better
assumptions in their failure analyses.
Accufacts suggested that the regulations
should focus on preventing failures but
that existing safety margins need not be
increased.
5. Texas Pipeline Association, Texas
Oil & Gas Association, Atmos, and
MidAmerican opposed changes to this
criterion. These commenters noted that
experience through the baseline
inspections has demonstrated the
criterion is adequate and ASME/ANSI
B31.8S remains a good guide for
anomaly response. Atmos added that
this criterion separates immediate
repairs from scheduled repairs: It allows
a risk-based focus on more serious
anomalies but does not mean that
anomalies providing more than 10
percent margin to burst pressure are
never addressed.
6. California Public Utilities
Commission suggested that the FPR
criterion be increased to 1.25 times
MAOP. CPUC noted that the 10 percent
margin in the current criterion can be
completely erased by the 10 percent
margin to safety relief settings allowed
by § 192.201.
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7. INGAA commented that additional
repair criteria are not needed. INGAA
noted that §§ 192.485(a) and 192.713(a)
already specify repair criteria applicable
to pipe outside HCA. Numerous
pipeline operators supported INGAA’s
comments.
8. AGA, supported by numerous of its
pipeline operator members, suggested
that safety margins for repairs need not
be the same as those for new
construction. AGA argued that the
construction margins are intended to
address potential unknowns and forces
applied during construction, which are
not applicable to repairs.
9. Accufacts, Northern Natural Gas,
and an anonymous commenter agreed
that repairs, once initiated, should meet
new construction safety margins.
10. INGAA and several of its pipeline
operator members argued that repair
criteria should not be more stringent
where class location has changed.
INGAA noted that § 192.611 does not
change the original design criteria for
segments that have been subject to a
change in class location and there is no
incident experience suggesting that
additional safety margin is needed in
these cases.
11. Northern Natural Gas and Kern
River argued against a change in repair
criteria where class location has
changed, noting that the likelihood of
failure of an anomaly is not affected by
the class location and that treatment in
accordance with integrity management
requirements already considers risk.
12. MidAmerican, Paiute, and
Southwest Gas added that use of the
factor failure pressure divided by MAOP
in ASME/ANSI B31.8S already reflects
any change in MAOP necessitated by a
change in class location.
13. Accufacts commented that repair
criteria should be commensurate with
the more restrictive design criteria of
higher class locations.
14. INGAA commented no new metal
loss criterion is needed, noting that its
members use HCA response criteria as
a guide for responding to indications of
metal loss outside of HCAs. Numerous
pipeline operators supported INGAA’s
comments.
15. AGA commented any metal loss
criterion should reflect current science
and should be the same regardless of
class location. AGA suggested that
immediate response to any indication of
a dent with metal loss is not needed,
noting that there have been many
examples of dents with metal loss not
sufficient to require recalculating
remaining strength. AGA also noted the
external corrosion direct assessment
standard requires a similar response
regardless of whether an indication is in
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or outside HCA. Numerous pipeline
operators supported AGA’s comments.
16. Accufacts encouraged PHMSA to
establish a prompt-action criterion for
wall loss inside or outside HCAs,
suggesting the focus should be on
preventing ruptures regardless of where
they occur. Accufacts also cautioned
PHMSA against accepting studies
attempting to show that 80 percent wall
loss is sometimes acceptable, and stated
that continued operation with such wall
loss is too risky for onshore pipelines.
Response to Question C.1 Comments
PHMSA appreciates the information
provided by the commenters. The
majority of comments supported no
changes to the immediate repair
criterion of predicted failure pressure of
less than or equal to 1.1 times MAOP for
HCAs, and PHMSA is not proposing to
change this criterion; however, PHMSA
is proposing several changes to enhance
the repair criteria both for HCA
segments and non-HCA segments. For
immediate conditions, PHMSA
proposes to add the following to the
immediate repair criteria: Metal loss
greater than 80% of nominal wall
thickness, indication of metal-loss
affecting certain types of longitudinal
seams, significant stress corrosion
cracking, and selective seam weld
corrosion. These additional repair
criteria would address specific issues or
gaps with the existing criteria. The
methods specified in the IM rule to
calculate predicted failure pressure are
explicitly not valid if metal loss exceeds
80% of wall thickness. Corrosion
affecting a longitudinal seam, especially
associated with seam types that are
known to be susceptible to latent
manufacturing defects such as the failed
pipe at San Bruno, and selective seam
weld corrosion are known near-term
integrity threats. Stress corrosion
cracking is listed in ASME B31.8S as an
immediate repair condition, which is
not reflected in the current IM
regulations. PHMSA proposes to add
requirements to address these gaps.
The current regulations include no
explicit metal loss repair criteria, other
than one immediate condition. The
regulations direct operators to use
Figure 4 in ASME B31.8S to determine
non-immediate metal loss repair
criteria. PHMSA now proposes to
explicitly include selected metal loss
repair conditions in the one-year
criteria. These proposed criteria are
consistent with similar criteria currently
invoked in the hazardous liquid
integrity management rule at 40 CFR
195.452(h). In addition, PHMSA
proposes to incorporate safety factors
commensurate with the class location in
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which the pipeline is located, to include
predicted failure pressure less than or
equal to 1.25 times MAOP for Class 1
locations, 1.39 times MAOP for Class 2
locations, 1.67 times MAOP for Class 3
locations, and 2.00 times MAOP for
Class 4 locations in HCAs. Lastly, in
response to the lessons learned from the
Marshall, Michigan, rupture, PHMSA
proposes to include any crack or cracklike defect that does not meet the
proposed immediate criteria as a one
year condition. PHMSA proposes to
apply these same criteria as two-year
conditions for non-HCAs.
PHMSA agrees with Accufacts’
comment that the regulations should
focus on preventing failures but that
existing safety margins are adequate
when properly applied. Therefore, the
proposed rule does not propose to
increase safety margins such as the
design factor. PHMSA maintains that
the proposed changes discussed above
provide a tiered, risk-based approach to
metal loss repair criteria and by
requiring predicted failure pressures as
a function of class locations does not
compound safety margins. Counter to
INGAA’s and AGA’s comments that
repair criteria should not be more
stringent where class location has
changed, PHMSA believes the tiered
approach to metal loss repair criteria,
which is a function of class location,
provides a logical framework to address
the risk presented by these types of
pipeline anomalies.
In conjunction with enhanced repair
criteria, PHMSA is proposing specific
new regulations to require that operators
properly analyze uncertainties and other
factors that could lead to nonconservative predictions of failure
pressure, and time remaining to failure,
when evaluating ILI anomaly
indications. PHMSA specifically is
proposing that operators must analyze
specific known sources of uncertainty
regarding ILI tool performance, anomaly
interactions, and other sources of
uncertainty when determining if an
anomaly meets any repair criterion.
C.2. Should anomalous conditions in
non-HCA pipeline segments qualify as
repair conditions subject to the IM
repair schedules? If so, which ones?
What projected costs and benefits would
result from this requirement?
1. INGAA suggested that new criteria
are not needed, commenting that
operators generally treat non-HCA
anomalies in a manner similar to HCA
anomalies, except for response time.
INGAA stated that industry costs to
address non-HCA anomalies should be
nominal unless immediate response is
required because this is consistent with
current operator practice, which INGAA
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stated is to apply ASME/ANSI B31.8S
response criteria for anomalies both
inside and outside HCAs.
2. Texas Pipeline Association and
Texas Oil & Gas Association commented
that differing repair criteria, if any,
should be based upon the population at
risk, since there is no valid engineering
basis for treating anomalies differently
depending on location.
3. Atmos and Northern Natural Gas
suggested that non-HCA anomalies
should be treated like HCA anomalies,
although additional schedule flexibility
should be allowed. Northern reported
that it applies HCA metal loss criteria
everywhere because it is prudent,
although response time differs for nonHCA anomalies. Northern reported that
it has expended approximately $7.7
million on anomaly repairs, $7 million
of which was outside an HCA.
4. Kern River agreed that IM
schedules are too stringent to apply
everywhere and providing schedule
flexibility will reduce costs.
5. MidAmerican disagreed with the
suggestion that non-HCA and HCA
anomalies be treated alike.
MidAmerican commented that it is
illogical to back off from focusing
sooner on anomalies that pose greater
risks.
6. California Public Utilities
Commission commented that all
locations identified by the method
described in paragraph 1 in the
definition of HCA in § 192.903 should
be subject to HCA repair criteria.
7. Pipeline Safety Trust, Accufacts,
and NAPSR commented that the same
repair criteria and response schedule
should apply regardless of where an
anomaly is located. These commenters
contended that there is no logical
justification for different treatment, that
any risk to the pipeline and public
safety should be resolved, and that a
pipeline accident anywhere is seen by
the public as a failure to exercise
adequate control of pipeline safety.
NAPSR, in particular, suggested that all
anomalies should be repaired
immediately, regardless of where they
are located.
8. Iowa Utilities Board, Iowa
Association of Municipal Utilities,
GPTC, Nicor, Ameren Illinois and an
anonymous commenter contended that
HCA repair criteria should not be
applied outside HCAs. These
commenters noted that there has been
no demonstrated safety need for new
criteria, that non-HCA anomalies are
adequately addressed under existing
operations and maintenance
requirements, and that the cost to apply
HCA repair criteria everywhere is not
justified. IAMU particularly noted that
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existing requirements are adequate for
small, low-pressure transmission
pipelines such as those operated by its
members.
9. A private citizen supported
application of HCA repair criteria in
non-HCA areas, particularly where there
are ‘‘receptors,’’ which the commenter
defines as ‘‘something which needs to
be protected.’’
Response to Question C.2 Comments
PHMSA appreciates the information
provided by the commenters. PHMSA
proposes to modify the general
requirement for repair of pipelines to
include immediate repair condition
criteria, one-year conditions, and
monitored conditions. The definition of
these conditions would be the same as
the existing definitions for covered
segments (i.e., HCA segments) in the IM
rule; however, PHMSA proposes that
those conditions that must be repaired
within one year in a HCA segment
would be required to be repaired within
two years in a non-HCA segment.
Defects that meet any of the immediate
criteria are considered to be near-term
threats to pipeline integrity and would
be required to be repaired immediately
regardless of location.
PHMSA believes that establishing
these non-HCA segment repair
conditions are important because, even
though they are not within the defined
high consequence locations, they could
be located in populated areas and are
not without consequence. For example,
as reported by operators in the 2011
annual reports, while there are
approximately 20,000 miles of gas
transmission pipe in HCA segments,
there are approximately 65,000 miles of
pipe in Class 2, 3, and 4 populated
areas. PHMSA believes it is prudent and
appropriate to include criteria to assure
the timely repair of injurious pipeline
defects in non-HCA segments. These
changes will ensure the prompt
remediation of anomalous conditions on
all gas pipeline segments while allowing
operators to allocate their resources to
high consequence areas on a higher
priority basis.
C.3. Should PHMSA consider a risk
tiering—where the conditions in the
HCA areas would be addressed first,
followed by the conditions in the nonHCA areas? How should PHMSA
evaluate and measure risk in this
context, and what risk factors should be
considered?
1. INGAA, and many pipeline
operators, opposed the suggested
tiering. They commented that anomalies
meeting response criteria should be
addressed in an appropriate time frame
whether inside or outside HCAs.
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2. AGA, supported by many of its
operator members, suggested that
PHMSA not adopt any risk tiering
beyond the current requirements to
focus first on HCA anomalies. AGA
noted that outside factors, e.g.,
permitting, affect the timing and the
sequence of repairs.
3. Texas Pipeline Association and
Texas Oil & Gas Association commented
that PHMSA should allow risk tiering
system-wide, not just in differentiating
between responses in and outside HCA.
The associations suggested that this
could be an improvement to
requirements addressing anomalies. At
the same time, they noted the
description in the ANPRM is sketchy
and requested PHMSA propose specific
requirements for comment.
4. Iowa Association of Municipal
Utilities commented that no new
requirements are needed, and that the
existing requirements are sufficient for
the small, low-stress transmission
pipelines operated by its members.
5. Atmos commented that the risk
tiering concept is confusing and stated
that it was considered and rejected
when the initial IM rules were
promulgated.
6. Northern Natural Gas commented
that allowing a longer response time for
anomalies outside HCA would be a form
of risk tiering. The company reported it
has incorporated this practice in its
procedures.
7. Accufacts agreed that a focus on
HCA anomalies is needed but cautioned
against ignoring anomalies outside
HCAs. Accufacts noted the progression
of an anomaly to failure does not
depend on whether or not it is located
in an HCA.
Response to Question C.3 Comments
PHMSA appreciates the information
provided by the commenters. Current
regulations do not prescribe response
timeframes for anomalies outside HCAs.
As stated by Northern Natural Gas,
allowing a longer response time for
anomalies outside HCAs (compared to
response times for anomalies inside
HCAs) would be a form of risk-tiering.
PHMSA is proposing such an approach,
which would establish three timeframes
for performing repairs in non-HCA
areas: Immediate repair conditions, 2year repair conditions, and monitored
conditions. These changes will ensure
the prompt remediation of anomalous
conditions on all gas pipeline segments,
while allowing operators to allocate
their resources to those areas that
present a higher risk.
C.4. What should be the repair
schedules for anomalous conditions
discovered in non-HCA pipeline
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20757
segments through the integrity
assessment or information analysis?
Would a shortened repair schedule
significantly reduce risk? Should repair
schedules for anomalous conditions in
HCAs be the same as or different from
those in non-HCAs?
1. INGAA commented that repair
schedules outside HCAs should be
similar to those in HCAs but should
allow for more scheduling latitude. This
comment was supported by comments
received from many of its operator
members. They also noted that adding
requirements to repair non-HCA
anomalies would significantly increase
the number of required repairs and that
an inappropriate requirement for rapid
response would dilute the focus on risksignificant repairs. INGAA suggested
that repair schedules should be more a
function of anomaly growth rates than
location along the pipeline. INGAA
further suggested that inappropriately
rapid response schedules would
increase risk; experience shows that
most anomalies that have been found
and repaired are old, do not require a
rapid response, and that mandating
rapid response to such anomalies would
necessarily dilute other safety activities.
2. Texas Pipeline Association and
Texas Oil & Gas Association expressed
doubt that significant risk reduction
would result from shortened repair
schedules, given the logistics and
related work involved in repairs.
3. GPTC, Nicor, and an anonymous
commenter objected to applying HCA
repair criteria outside HCAs. They
believe that the costs for such an
approach are not justified and non-HCA
anomalies are appropriately dealt with
under operations and maintenance
requirements and procedures.
4. Ameren Illinois, Paiute, and
Southwest Gas agreed that prescriptive
repair schedules are not needed outside
HCAs. They expressed a belief that
operators must have scheduling
flexibility to accommodate the needs of
their operations.
5. MidAmerican suggested that
immediate repair criteria be applied
both in HCAs and outside HCAs, but
that other criteria be limited to HCAs.
6. Northern Natural Gas suggested
that PHMSA should require operators to
determine response schedules for nonHCA anomalies as part of this
rulemaking.
7. Iowa Association of Municipal
Utilities commented that the existing
requirements are sufficient for the small,
low-stress transmission pipelines
operated by its members.
8. California Public Utilities
Commission commented that all method
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1 HCA locations should be subject to
HCA repair criteria.
9. MidAmerican, Paiute, and
Southwest Gas commented that
shortened response schedules will not
reduce risk. These operators suggested
that response times should be based on
risk rather than being established
arbitrarily.
Response to Question C.4 Comments
PHMSA appreciates the information
provided by the commenters. PHMSA
believes repair schedules outside HCAs
should be similar to those in HCAs but
should allow for more scheduling
latitude. PHMSA proposes to establish
three timeframes for remediating defects
in non-HCA areas: Immediate repair
conditions, 2-year repair conditions
(rather than one-year for HCAs), and
monitored conditions. These changes
will ensure the prompt remediation of
anomalous conditions on all gas
pipeline segments, commensurate with
risk, while allowing operators to
allocate their resources to those areas
that present a higher risk.
C.5. Have ILI tool capability advances
resulted in a need to update the ‘‘dent
with metal loss’’ repair criteria?
1. INGAA commented that ILI tool
capabilities have improved to the point
where it is appropriate to revise the
dent-with-metal loss criterion. This
comment was supported by comments
received from many of its operator
members. INGAA suggested that Section
851.4(f) of ASME/ANSI B31.8 provides
appropriate guidance in this area.
2. AGA suggested that it would be
appropriate to eliminate the immediate
response criterion for ‘‘dent with metal
loss.’’ This comment was supported by
comments received from many of its
operator members. They commented
that industry experience has shown that
many dents do not require immediate
repair.
3. Texas Pipeline Association, Texas
Oil & Gas Association, MidAmerican,
Paiute, Southwest Gas, and Atmos
supported revising this criterion. These
commenters noted that improvements in
ILI allow better distinction between a
gouge and corrosion wall loss.
MidAmerican further commented that
there are problems with implementing
§ 192.933 as written.
4. Northern Natural Gas stated that it
would support treating these anomalies
as mechanical damage, and suggested
that this would simplify the regulations.
5. Ameren Illinois suggested further
study of this proposal taking into
account current ILI technology.
6. Accufacts and an anonymous
commenter opposed changes to this
criterion. These commenters suggested
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that ILI is still not adequate to
determine reliably the time to failure of
this compound threat.
7. GPTC and Nicor suggested that
PHMSA consider updating the Dent
Study technical report 35 that discusses
reliability and application of ILI.
Response to Question C.5 Comments
PHMSA appreciates the information
provided by the commenters. PHMSA is
not proposing to update the dent-withmetal-loss criterion at this time. PHMSA
will continue to evaluate this criterion,
including consideration of additional
research to better define the repair
criteria for this specific type of defect.
C.6. How do operators currently treat
assessment tool uncertainties when
comparing assessment results to repair
criteria? Should PHMSA adopt explicit
voluntary standards to account for the
known accuracy of in-line inspection
tools when comparing in-line inspection
tool data with the repair criteria?
Should PHMSA develop voluntary
assessment standards or prescribe ILI
assessment standards including wall
loss detection threshold depth
detection, probability of detection, and
sizing accuracy standards that are
consistent for all ILI vendors and
operators? Should PHMSA prescribe
methods for validation of ILI tool
performance such as validation
excavations, analysis of as-found versus
as-predicted defect dimensions? Should
PHMSA prescribe appropriate
assessment methods for pipeline
integrity threats?
1. INGAA, supported by many of its
member companies, reported that
operators use many methods to
accommodate ILI uncertainties, not
simply adding tool tolerance to results.
INGAA suggested API–1163, In-line
Inspection Systems Qualification
Standard, as an appropriate guide.
INGAA noted this standard is nonprescriptive; INGAA expressed its belief
prescriptive standards would stifle
innovation. INGAA also reported that
ASME has plans to update its standard
on ‘‘Gas Transmission and Distribution
Piping Systems,’’ ASME/ANSI B31.8S,
regarding treatment of uncertainties
based on the results of Pipeline
Research Council International (PRCI)
research that was underway at the time
comments were submitted.
2. AGA and a number of pipeline
operators suggested that tool tolerances
should be added to ILI results.
3. Texas Pipeline Association, Texas
Oil & Gas Association, and Atmos
35 Baker and Kiefner & Associates, ‘‘Dent Study
Technical Report,’’ (November 2004, OPS TTO
Number 10, available at https://
primis.phmsa.dot.gov/gasimp/techreports.htm).
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reported their understanding that most
operators follow ASME/ANSI B31.8S as
a guide.
4. Northern Natural Gas and Kern
River expressed their conclusion that
PHMSA’s Gas Integrity Management
Program Frequently Asked Question
FAQ–68 provides sufficient guidance on
the treatment of uncertainties (FAQs can
be viewed at https://
primis.phmsa.dot.gov/gasimp/
faqs.htm). They noted that technology is
developing rapidly in this area, which
they imply is a reason not to impose
prescriptive requirements.
5. Texas Pipeline Association and
Texas Oil & Gas Association agreed that
prescriptive requirements should not be
imposed, because the rapidlydeveloping technology would soon
render them obsolete.
6. GPTC, Nicor, MidAmerican, and
Atmos argued that prescriptive methods
for validating tool performance are not
an appropriate subject for regulation.
7. Ameren Illinois commented that it
sees no technical justification for
establishing requirements in this area.
8. Accufacts suggested that PHMSA
specify minimum standards for ILI
validation, including specifying a
required number of digs. Alaska
Department of Natural Resources and
California Public Utilities Commission
took a similar stance, all arguing that
standards assure public confidence and
consistency of results.
9. A private citizen commented that
voluntary standards are not sufficient
because they cannot be enforced.
10. An anonymous commenter
recommended against adopting
requirements for treatment of
inaccuracies. The commenter opined
that operators are doing better in this
area, contending that smaller operators,
in particular, needed time to learn. The
commenter suggested that specific rules
would set many operators back.
11. INGAA and many of its pipeline
operators commented that incorporating
standards into part 192 that compete
with industry standards would be
counterproductive. INGAA noted that
API–1163, API–579–1, Fitness-forService, and ASNT ILI–PQ, In-Line
Inspection Personnel Qualification and
Certification Standard, are already in
wide use and contended specifying
standards in the regulations would stifle
further development.
12. GPTC and Nicor agreed with
INGAA, noting that the regulatory
approval process cannot keep up with
technological development.
13. Northern Natural Gas
recommended that PHMSA not adopt
standards for addressing ILI
inaccuracies, contending the many
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different tools currently in use would
make this impractical.
14. MidAmerican reported its belief
that operators have sufficient incentive
to work with ILI vendors to assure
appropriate validation of ILI results.
15. Paiute and Southwest Gas argued
against adoption of regulatory standards
to treat ILI uncertainties, noting that this
subject is already addressed in ASME/
ANSI B31.8S.
16. AGA, supported by a number of
its member companies, suggested that
PHMSA should not prescribe IM
methods, noting that operators have
demonstrated the ability to conduct
assessments without them.
17. Accufacts, Alaska Natural Gas
Development Authority, and California
Public Utilities Commission argued for
requirements prescribing assessment
methods for various threats. These
commenters suggested that such
requirements would be a bridge to better
risk management strategies and
contended that there is currently an
over-reliance on direct assessment.
Response to Question C.6 Comments
PHMSA appreciates the information
provided by the commenters. The
majority of comments do not support
adopting explicit standards or analytical
methodologies to account for the known
accuracy of in-line inspection tools.
PHMSA concurs that prescriptive rules
to account for the accuracy of in-line
inspection tools is not practical,
however it is beneficial to all to clarify
PHMSA’s expectations with respect to
current performance-based regulations
in this area which specify that internal
inspection may be used to identify and
evaluate potential pipeline threats.
Therefore, PHMSA proposes to add
detailed performance-based rule
language to require that operators using
ILI must explicitly consider
uncertainties in reported results
(including tool tolerance, anomaly
findings, and unity chart plots or
equivalent for determining
uncertainties) in identifying anomalies.
While ASME/ANSI B31.8S discusses
uncertainties, PHMSA believes it will
improve the visibility and emphasis on
this important issue to explicitly
address uncertainties in the rule text.
C.7. Should PHMSA adopt standards
for conducting in-line inspections using
‘‘smart pigs,’’ the qualification of
persons interpreting in-line inspection
data, the review of ILI results including
the integration of other data sources in
interpreting ILI results, and/or the
quality and accuracy of in-line
inspection tool performance, to gain a
greater level of assurance that injurious
pipeline defects are discovered? Should
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these standards be voluntary or adopted
as requirements?
1. AGA and its pipeline operator
members argued against the adoption of
standards. AGA commented that
voluntary use has proven to be
sufficient and expressed its position that
consensus standards should not be
adopted into regulations until
widespread experience has been gained
with their use. AGA contended that
premature adoption would stifle
technological innovation.
2. INGAA and many of its members
commented that PHMSA’s process for
review and adoption of standards must
be streamlined if existing consensus
standards are incorporated into
regulations. Such improvements,
INGAA contended, would assure that
standard improvements are adopted
without delay.
3. An anonymous commenter, GPTC,
and Nicor cited similar concerns in
suggesting that standards not be adopted
into regulations, contending that the
rulemaking process cannot keep up with
technological change.
4. Texas Pipeline Association and
Texas Oil & Gas Association objected to
the adoption of ILI standards in
regulations, contending that voluntary
use is more appropriate.
5. MidAmerican commented that
operator qualification requirements
should be applied to ILI, as this would
provide higher assurance of defect
discovery. Beyond this, however,
MidAmerican contended that the use of
consensus standards should remain
voluntary, as this allows the operator to
select those standards most appropriate
to its circumstances.
6. Paiute and Southwest Gas objected
to the incorporation of ILI standards
into regulations. The companies
expressed a belief that there is no
technical basis for doing so. They
commented that the question, as posed
in the ANPRM, implies that anomalies
are not now being found and contended
that there is no evidence to support this
implication.
7. A private citizen, Thomas Lael, and
Alaska Department of Natural Resources
commented that PHMSA should require
operators to meet specified standards.
Mr. Lael referred to an incident that
occurred following a pipeline
assessment conducted in Ohio in 2011;
Mr. Lael contended that the reasons the
incident cause was not identified by the
assessment are unknown to the public.
8. Pipeline Safety Trust commented
that PHMSA should assure assessment
tools are capable and are used properly.
9. The NTSB recommended that
PHMSA require all pipelines to be made
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piggable, giving priority to older lines,
citing their recommendation P–11–17.
Response to Question C.7 Comments
PHMSA appreciates the information
provided by the commenters. The
majority of industry comments do not
support the incorporation of ILI
standards into regulations. However,
based on the information presented
below, PHMSA has concluded that it is
prudent to propose incorporating
available consensus ILI standards into
the regulations. The current pipeline
safety regulations for integrity
management of segments in HCAs
contained in 49 CFR 192.921 and
192.937 require that operators assess the
material condition of pipelines in
certain circumstances and allow use of
in-line inspection tools for these
assessments. PHMSA proposes to
incorporate similar requirements for
non-HCA pipe segments in § 192.710.
Operators are required to follow the
requirements of ASME/ANSI B31.8S in
selecting the appropriate ILI tools.
However, ASME B31.8S provides only
limited guidance for conducting ILI
assessments. At the time the integrity
management rules were promulgated,
there was no consensus industry
standard that addressed performance of
ILI. Three related standards have since
been published: API STD 1163–2005,
NACE SP0102–2010, and ANSI/ASNT
ILI–PQ–2010. API–1163 serves as an
umbrella document to be used with and
complement the NACE and ASNT
standards. These three standards have
enabled service providers and pipeline
operators to provide processes that will
qualify the equipment, people,
processes, and software utilized in the
in-line inspection industry. The
incorporation of these standards into
pipeline safety regulations developed
through best practices of the industry
based on the experience of numerous
operators will promote high quality and
more consistent assessment practices.
Therefore, PHMSA is proposing to
incorporate these industry standards
into the regulations to provide clearer
guidance for conducting integrity
assessments with in-line inspection.
PHMSA will continue to evaluate the
need for additional guidance for
conducting integrity assessments.
C.8. If commenters suggest
modification to the existing regulatory
requirements, PHMSA requests that
commenters be as specific as possible.
In addition, PHMSA requests
commenters to provide information and
supporting data related to:
• The potential costs of modifying the
existing regulatory requirements
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pursuant to the commenter’s
suggestions.
• The potential quantifiable safety
and societal benefits of modifying the
existing regulatory requirements.
• The potential impacts on small
businesses of modifying the existing
regulatory requirements.
• The potential environmental
impacts of modifying the existing
regulatory requirements.
No comments were received in
response to this question.
D. Improving the Collection, Validation,
and Integration of Pipeline Data
The ANPRM requested comments
regarding whether more prescriptive
requirements for collecting, validating,
integrating and reporting pipeline data
are necessary. The current IM
regulations require that gas transmission
pipeline operators gather and integrate
existing data and information
concerning their entire pipeline that
could be relevant to pipeline segments
in HCAs (§ 192.917(b)). Operators are
then required to use this information in
a risk assessment of the HCA segments
(§ 192.917(c)) that must subsequently be
used to determine whether additional
preventive and mitigative measures are
needed (§ 192.935) and to define the
intervals at which IM reassessments
must be performed (§ 192.939).
Operators’ risk analyses and
conclusions can only be as good as the
information used to perform the
analyses. On August 30, 2011, after the
ANPRM was issued, the NTSB adopted
its report on the gas pipeline accident
that occurred on September 9, 2010, in
San Bruno, California. Results from the
NTSB investigation indicate that the
pipeline operator’s records regarding the
physical attributes of the pipe segments
involved in the incident were
erroneous. NTSB recommendation P–
11–19 recommended that PHMSA
require IM programs be assessed to
assure that they are based on clear and
meaningful metrics. In addition, Section
23 of the Act requires verification to
ensure that records accurately reflect the
physical and operational characteristics
of pipelines. PHMSA issued an
Advisory Bulletin (76 FR 1504; January
10, 2011) on this issue. The following
are general comments received related
to the topic as well as comments related
to the specific questions:
General Comments for Topic D
1. INGAA reported that it is presently
working on data integration guidelines.
INGAA cautioned that requirements in
this area can be very costly, since they
often necessitate redesign of existing
data management systems.
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2. AGA commented that no records
requirements would have prevented the
San Bruno accident, and stated that
verifying records does not assure
completeness, as unknown parameters
remain unknown.
3. A private citizen suggested that
PHMSA should require operators to
identify segments where they lack
knowledge of critical parameters. The
commenter suggested that this could
facilitate emergency communications
and help prioritize pipe replacement
programs.
Response to General Comments for
Topic D
PHMSA appreciates the information
provided by the commenters. PHMSA is
proposing to clarify requirements for
collecting, validating, and integrating
data. The current rule invokes ASME/
ANSI B31.8S requirements for data
collection and integration. To provide
greater visibility and emphasis on this
important aspect of integrity
management, PHMSA is proposing to
place these requirements in the rule
text, rather than incorporating ASME/
ANSI B31.8S by reference. The
proposed requirements clarify PHMSA’s
expectations regarding the minimum list
of data an operator must collect, and
also includes performance-based
language that requires the operator to
validate data it will use to make
integrity-related decisions, and require
operators to integrate all such data in a
way that improves the analysis. The
proposed rule would also require
operators to use reliable, objective data
to the maximum extent practical. To the
degree that subjective data from subject
matter experts must be used, PHMSA
proposes to require that an operator’s
program include specific integrity
assessment and findings data for the
threat features to compensate for subject
matter expert (SME) bias. The
importance of these aspects of integrity
management was emphasized by both
the NTSB (Recommendation P–11–19)
and Congress (The Act, Section
11(a)(4)).
Comments Submitted for Questions in
Topic D
D.1. What practices are now used to
acquire, integrate and validate data
(e.g., review of mill inspection reports,
hydrostatic tests reports, pipe leaks and
rupture reports) concerning pipelines?
Are practices in place, such as
excavations of the pipeline, to validate
data?
1. INGAA reported that its members
have completed a concerted effort to
validate pipeline historical records
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pursuant to PHMSA Advisory Bulletin
11–01 (issued January 10, 2011).
2. Texas Pipeline Association and
Texas Oil & Gas Association commented
that there is no great benefit to be gained
from adding a verification requirement
for historical data to the regulations.
The associations believe that most
operators will correct their records
when they become aware of errors
regardless of how the erroneous
information is discovered. The
associations suggested that there could
be value in validating databases against
original records, since an underlying
problem of the San Bruno accident was
errors in transferring original records
into a database.
3. Ameren Illinois reported that it
collects data on exposed pipe in
accordance with §§ 192.459 and
192.475.
4. Northern Natural Gas and Kern
River reported that their primary
integration tool is integrity alignment
sheets, which show the class location,
profile, aerial photography, alignment
and structure data, in-line inspection
results, other integrity data, i.e., closeinterval survey or pressure test results
and pipe, coating and appurtenance
data. Data is validated as opportunities
arise.
5. Paiute and Southwest Gas reported
that they confirm the location and
properties of its pipeline as
opportunities arise; more data are
collected as assessments are conducted.
6. California Public Utilities
Commission suggested that operators be
explicitly required to obtain all
historical records and that there be an
officer statement that a thorough search
for all records has been conducted.
7. A private citizen commented on the
lack of some historical data, implying
that operators should be required to
validate their knowledge of older
pipelines.
8. An anonymous commenter stated
that older data is typically not validated.
9. INGAA and AGA reported that
pipeline operators take advantage of
exposed pipe to collect and validate
data on in-service pipelines. This
includes excavations for ILI validation,
those conducted as part of direct
assessment, and removed or replaced
pipelines. A number of pipeline
operators provided comments
supporting the comments of each
association.
10. GPTC and Nicor suggested that
excavations not be required for the sole
purpose of validating data, contending
that the risks posed by such a
requirement would outweigh any
benefit obtained.
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11. MidAmerican reported that it
validates information when pipeline is
excavated and through its routine
practices.
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Response to Question D.1 Comments
PHMSA appreciates the information
provided by the commenters. See
response to question D.4.
D.2. Do operators typically collect
data when the pipeline is exposed for
maintenance or other reasons to
validate information in their records? If
discrepancies are found, are
investigations conducted to determine
the extent of record errors? Should these
actions be required, especially for HCA
segments?
1. AGA, Paiute, and Southwest Gas
reported that operators use exposed
pipe as an opportunity to collect
information. AGA further suggested,
however, that PHMSA should not draft
a rule governing these practices. AGA
contended the circumstances of pipe
exposures vary too much to be
addressed by a regulatory requirement.
AGA expressed its conclusion that the
requirements in § 192.605(b)(3) provide
adequate guidance and that section 23
of the Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011
provides additional guidance. AGA
noted that operators investigate
identified inaccuracies and errors. A
number of other pipeline operators
provided comments supporting AGA’s
comments.
2. Texas Pipeline Association, Texas
Oil & Gas Association, Atmos,
MidAmerican, and Ameren Illinois
reported that operators typically collect
information on pipe type and condition,
but not on historical information and
pipe specifications. They commented
that collecting this information would
require additional testing and pose
operational impacts.
3. Iowa Utilities Board and Iowa
Association of Municipal Utilities
commented that any new requirement
should be limited to collecting readily
obtainable data, principally that which
can be determined visually. They
suggested that the data elements in
ANPRM questions D.1 and D.3 go
beyond what can readily be observed or
obtained and it would be impractical to
require this data to be collected during
pipe exposures.
4. California Public Utilities
Commission commented that any new
requirements to collect data during pipe
exposures should address all instances
of exposure rather than be limited to
HCAs, noting that non-HCA segments
can become HCA segments due to
changes in land use near the pipeline.
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5. Thomas Lael and Alaska
Department of Natural Resources
commented that operators should be
required to collect specific data during
pipe exposures. These commenters
contended that not all operators
currently collect available data during
pipe exposures.
6. MidAmerican, Paiute, and
Southwest Gas commented that no new
requirements are needed because the
requirements in part 192 and guidance
in ASME/ANSI B31.8S are sufficient.
7. An anonymous commenter
suggested that operators be required to
collect data if they do not have enough
information to analyze the risks of the
pipeline segment.
Response to Question D.2 Comments
PHMSA appreciates the information
provided by the commenters. The
expanded rule language does not
impose new requirements for collecting
specific data during pipe exposures, but
the response to question D.4 discusses
proposed changes to collection and
validation practices to improve data
integration and risk assessment
practices.
D.3. Do operators try to verify data on
pipe, pipe seam type, pipe mechanical
and chemical properties, mill inspection
reports, hydrostatic tests reports,
coating type and condition, pipe leaks
and ruptures, and operations and
maintenance (O&M) records on a
periodic basis? Are practices in place to
validate data, such as excavation and in
situ examinations of the pipeline? If so,
what are these practices?
1. AGA, GPTC, Nicor, Paiute, and
Southwest Gas reported that operators
do try to verify information but that
operator practices are too numerous to
list in response to this general question.
They contended that the requirements
for external corrosion control in
§ 192.459 and for internal corrosion
control in § 192.475 and the guidance in
Advisory Bulletin 11–01 are sufficient
and no new requirements are needed. A
number of other pipeline operators
provided comments supporting AGA’s
comments.
2. INGAA, supported by many of its
pipeline operator members, commented
that there are limited, if any, methods to
determine accurately mechanical
properties of pipe that is in situ.
INGAA’s comments listed a number of
methods that can be used to obtain
approximate values for some pipe
characteristics, such as steel hardness
and yield strength.
3. Texas Pipeline Association and
Texas Oil & Gas Association commented
that operators do not validate mill data
after initial construction.
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4. Ameren Illinois reported that data
review and correction is a normal part
of the business of pipeline operation.
Ameren commented that additional
work in this area is likely to result from
Advisory Bulletin 11–01.
5. Northern Natural Gas reported that
data correction occurs when a
discrepancy is identified. Northern also
noted that it has added data to its risk
model over time, principally related to
determination of the potential
consequences of a pipeline accident.
6. MidAmerican commented that
operators validate pipeline information
periodically.
7. California Public Utilities
Commission reported that California
pipeline operators have begun
validating pipeline data since the San
Bruno accident. CPUC commented that
operators should determine pipeline
specifications for all exposed facilities
and use them to validate their records.
8. Paiute and Southwest Gas reported
that it is their practice to obtain pipeline
data before an integrity management
excavation and then to validate that
information in the field.
9. MidAmerican reported that it uses
a geospatial database as its principal
tool for collecting and validating
pipeline information.
10. An anonymous commenter
suggested that pipeline operators do not
routinely collect information to validate
their databases during pipeline
excavations.
Response to Question D.3 Comments
PHMSA appreciates the information
provided by the commenters. See
response to question D.4.
D.4. Should PHMSA make current
requirements more prescriptive so
operators will strengthen their collection
and validation practices necessary to
implement significantly improved data
integration and risk assessment
practices?
1. INGAA, GPTC, Nicor, Ameren
Illinois, MidAmerican, Paiute and
Southwest Gas commented that
additional prescriptive requirements are
not needed. These commenters
suggested that Advisory Bulletin ADB–
11–01, subpart O of part 192, and
ASME/ANSI B31.8S are sufficient to
govern these practices. INGAA added
requirements for data validation during
excavations could introduce workplace
hazards that would outweigh any
benefit to be gained. In the event
PHMSA proceeds to propose new
requirements, INGAA requested they be
limited to a reasonable process and
allow assumptions to be made to fill
information gaps, suggesting this would
be a more cost-effective approach than
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rigorous requirements to collect and
validate all information. A number of
other pipeline operators provided
comments supporting INGAA’s
comments.
2. AGA, supported by a number of its
pipeline operator members, commented
that there is no evidence to support a
need for more prescriptive requirements
leading to better data collection or
validation and, therefore, no such
requirements are needed.
3. Pipeline Safety Trust, NAPSR,
California Public Utilities Commission,
and Commissioners of Wyoming
County, Pennsylvania, commented that
requirements for data collection,
validation, and use should be more
prescriptive. These commenters noted
that the investigation of the San Bruno
accident identified at least one pipeline
operator was not doing an adequate job
of data validation. They noted that
NTSB recommendations P–11–18 and
P–11–19 apply to this topic. NAPSR
specifically requested that new
requirements specify precise inspection
criteria.
4. Texas Pipeline Association and
Texas Oil & Gas Association suggested
that there is no value in periodic
validation of pipeline data and new
requirements are not needed in this
area. Northern Natural Gas agreed,
noting that pipeline data does not
change over time, and relevant data that
is subject to change, is that data needed
to evaluate the consequences of
potential pipeline accidents.
5. Accufacts commented that more
specific criteria, including minimum
data requirements, are needed for record
retention. Accufacts noted that integrity
management is data-based and that too
many operators claim that data is lost or
cannot be found.
6. Alaska Department of Natural
Resources suggested that data
integration should be required in
interpreting ILI results.
7. An anonymous commenter
suggested that specific requirements are
not needed in this area, contending that
most data has been validated through
normal operator practices.
8. A private citizen suggested that
PHMSA require pipeline operators to
post all records for access by state and
local government officials, PHMSA, and
the media. The commenter suggested
such a ‘‘sunshine’’ provision would
improve recordkeeping, even if no one
ever examines the posted records.
Response to Question D.4 Comments
PHMSA appreciates the information
provided by the commenters in
response to questions D.1 through D.4.
Commenters disagreed on the need and
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benefit of making current requirements
more prescriptive so operators will
strengthen their collection and
validation practices. PHMSA believes
enhancing regulations in this area is an
important element of good integrity
management practices. On July 21,
2011, in response to the San Bruno
incident, PHMSA sponsored a public
workshop on risk assessment and
related data analysis and recordkeeping
issues to seek input from stakeholders.
Based in part on the input received at
this workshop, and the information
submitted in response to the ANPRM,
PHMSA proposes to clarify the
performance-based requirements for
collecting, validating, and integrating
pipeline data by adding specificity to
the data integration language,
establishing a number of pipeline
attributes that must be included in these
analyses, explicitly requiring that
operators integrate analyzed
information, and ensuring data is
reliable. The rule also requires operators
to use validated, objective data to the
maximum extent practical. PHMSA also
understands that objective sources such
as as—built drawings, alignment sheets,
material specifications, and design,
construction, inspection, testing,
maintenance, manufacturer, or other
related documents are not always
available or obtainable. To the degree
that subjective data from subject matter
experts must be used, PHMSA proposes
to require that an operator’s program
include specific features to compensate
for subject matter expert bias. PHMSA
believes that these proposed changes
would not impose new requirements or
more prescriptive requirements, but
clarifies the intent of the regulation.
However, PHMSA requests public
comment on whether and the extent to
which this proposal may change
behavior.
D.5. If commenters suggest
modification to the existing regulatory
requirements, PHMSA requests that
commenters be as specific as possible.
In addition, PHMSA requests
commenters to provide information and
supporting data related to:
• The potential costs of modifying the
existing regulatory requirements
pursuant to the commenter’s
suggestions.
• The potential quantifiable safety
and societal benefits of modifying the
existing regulatory requirements.
• The potential impacts on small
businesses of modifying the existing
regulatory requirements.
• The potential environmental
impacts of modifying the existing
regulatory requirements.
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No comments were received in
response to this question.
E. Making Requirements Related to the
Nature and Application of Risk Models
More Prescriptive
The ANPRM requested comments
regarding whether requirements related
to the nature and application of risk
models should be made more
prescriptive to improve the usefulness
of these analyses in controlling risks
from pipelines. Current regulations
require that gas transmission pipeline
operators perform risk analyses of their
pipelines and use these analyses to
make certain decisions to assure the
integrity of their pipeline and to
enhance protection against the
consequences of potential incidents.
The regulations do not prescribe the
type of risk analysis nor do they impose
any requirements regarding its breadth
and scope, other than requiring that it
consider the entire pipeline. PHMSA’s
experience in inspecting operator
compliance with IM requirements has
identified that most pipeline operators
use a relative index-model approach to
performing their risk assessments and
that there is a wide range in scope and
quality of the resulting analyses. It is not
clear that all of the observed risk
analyses can support robust decisionmaking and management of the pipeline
risk. The following are general
comments received related to the topic
as well as comments related to the
specific questions:
General Comments for Topic E
1. INGAA and Chevron commented
that continuing the performance-based
regulatory approach, exemplified by
integrity management, is critically
important to pipeline safety. They
suggested that prescriptive management
systems are task oriented, do not adjust
easily to new information or knowledge,
inhibit innovation, and could thwart
safety improvements. A number of other
pipeline operators provided comments
supporting INGAA’s comments.
2. Accufacts commented that risk
management approaches permitted in
IM need additional prescriptive
measures to clarify strengths and
weaknesses and to assure compliance.
Public perception resulting from the
number of serious incidents is that
current risk analysis and risk
management approaches are not
sufficient. The impression is that risk
management is being used to justify
unwise lowest cost decisions rather than
being used as a tool to avoid failure.
Accufacts further suggested that
interactive threats need to be addressed
by prescriptive requirements in safety
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regulations because operators may be
under the illusion that some of the more
serious threats are stable after almost 10
years of IM regulation.
3. Oleksa and Associates suggested
that it would be statistically more valid
for many (perhaps most) operators for
PHMSA to perform continual evaluation
and assessment using established
performance measures along with data
submitted by operators on annual,
incident, and safety-related condition
reports, and then to promulgate more
prescriptive regulations resulting from
that assessment. Oleksa suggested that it
may be time to re-evaluate the overall
concept of integrity management to
determine whether it makes sense for
each operator to make assessments that
might be more valid if made on a
national level. Oleksa also stated that
there should be a concerted effort in
promulgating any new regulations
towards making the regulations simple
enough so that they can be understood
relatively easily.
4. TransCanada commented that
PHMSA’s IM regulations should provide
explicit metrics for operators to
demonstrate safety decision processes
without restricting the opportunity to
use more accurate and advanced
methods. TransCanada said that any
efforts to make risk models more
prescriptive should focus on process
elements while providing operators the
flexibility to build processes which
recognize the unique characteristics of
their pipeline systems. The company
also opined that issuing more detailed
guidelines on specific integrity
management plan elements would
enhance the current, performance-based
approach and generate additional
benefits that the public and operators
desire.
5. Dominion East Ohio Gas opposed
making requirements for risk models
more prescriptive. Like INGAA, they
that noted prescriptive management
systems are task oriented and do not
adjust easily to new information or
knowledge. They inhibit innovation and
could thwart safety improvements.
6. NAPSR strongly urged PHMSA to
make the nature and application of risk
models more prescriptive. NAPSR
commented that PHMSA has not
provided any data that supports the
theory that risk modeling provides a
stronger safety environment and
contended that, in fact, the opposite
may be occurring.
7. A private citizen suggested that
PHMSA correlate the quality of an
operator’s risk model with the number
of enforcement actions against that
operator.
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8. A private citizen suggested that risk
analysis requirements should remain
flexible, commenting that prescribed
methods or requirements could mask
operator-specific issues.
Response to General Comments for
Topic E
PHMSA appreciates the information
provided by the commenters. PHMSA
agrees that prescriptive rules for risk
assessments are not appropriate because
one-size-fits-all regulations would not
be effective for such a diverse industry.
However, PHMSA does believe that
operator risk models and risk
assessments should have substantially
improved since the initial framework
programs established nearly 10 years
ago. While simple index or relative
(qualitative) ranking models were useful
to prioritize HCA segments for purposes
of scheduling integrity baseline
assessments, those models have limited
utility to perform the analyses needed to
better understand pipeline risks, better
understand failure mechanisms
(especially for interacting threats), or to
identify effective preventive and
mitigative measures. PHMSA is
proposing to further clarify its
expectations for this aspect of the
performance-based regulations to
further improve pipeline safety. On July
21, 2011, PHMSA sponsored a public
workshop on risk assessment to seek
input from stakeholders. PHMSA has
evaluated the input it received at this
workshop. PHMSA proposes to clarify
the risk assessment aspects of the IM
rule to explicitly articulate functional
requirements and to assure that risk
assessments are adequate to: (1)
Evaluate the effects of interacting
threats, (2) determine intervals for
continual integrity reassessments, (3)
determine additional preventive and
mitigative measures needed, (4) analyze
how a potential failure could affect
HCAs, including the consequences of
the entire worst-case incident scenario
from initial failure to incident
termination, (5) identify the
contribution to risk of each risk factor,
or each unique combination of risk
factors that interact or simultaneously
contribute to risk at a common location,
(6) account and compensate for
uncertainties in the model and the data
used in the risk assessment, and (7)
evaluate predicted risk reduction
associated with preventive and
mitigative measures. In addition, in
response to NTSB recommendation P–
11–18, PHMSA proposes to require that
operators validate their risk models in
light of incident, leak, and failure
history and other historical information.
PHMSA also proposes to expand the list
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of example preventive and mitigative
measures to include the following items:
establish and implement adequate
operations and maintenance processes
that could affect safety; establish and
deploy adequate resources for
successful execution of activities,
processes, and systems associated with
operations, maintenance, preventive
measures, mitigative measures, and
managing pipeline integrity; and correct
the root cause of past incidents to
prevent recurrence.
In response to Oleksa’s comments,
PHMSA is addressing performance
measures outside of this rulemaking.
Performance measures will be addressed
separately in response to NTSB safety
recommendations P–11–18 and P–11–
19.
Comments Submitted for Questions in
Topic E
E.1. Should PHMSA either strengthen
requirements on the functions risk
models must perform or mandate use of
a particular risk model for pipeline risk
analyses? If so, how and which model?
1. INGAA, AGA, and many pipeline
operators reported that they do not
believe there is a pipeline safety benefit
for PHMSA to ‘‘strengthen’’ or revise the
requirements on functions that risk
models must perform or in mandating
the use of specific risk models. These
commenters noted that there is a
tremendous amount of diversity in the
pipeline systems of individual operators
and operators must have the flexibility
to select the risk model that best
supports their systems.
2. GPTC commented that there is no
‘one-size-fits-all’ risk model. GPTC
further commented PHMSA has offered
no data supporting the need to
strengthen requirements or mandate a
particular risk model.
3. Kern River noted that differences
exist between pipeline operators on how
much detail is needed in their risk
assessment models. The specific factors
and required risk model complexity will
differ for each pipeline company based
on its active threats, the preventive and
mitigative measures employed, its data
acquisition methods and the amount of
required data.
4. MidAmerican commented that no
change is needed to requirements
concerning risk models. MidAmerican
noted that ASME/ANSI B31.8S provides
extremely detailed requirements in this
area, and suggested that operators
should have the freedom to choose the
risk model best suited to their operation.
Northern Natural Gas agreed, noting that
there are large differences within the
industry on the complexity of the risk
assessment models used based on the
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pipeline age and configuration, threats,
and data available.
5. Paiute and Southwest Gas opposed
more restrictive requirements for risk
modeling. They noted that operators
have a decade of experience working
with IM and therefore, should have the
flexibility to choose the risk model that
best suits their system.
6. Accufacts commented that this is
an area that needs more prescriptive
requirements. Accufacts questioned
whether the current approach of
reliance on risk modeling is even
appropriate. They stated that there
appears to be a disconnect between the
use of risk models and risk analysis
with pipeline operation and the ability
of regulators to apply and enforce the
approach.
7. TransCanada noted that mandating
the use of a specific risk model may
result in a more uniform approach
across the industry, but may also force
operators to abandon their existing risk
models, including the improvements
made to them based on 10 years of
integrity management experience. This
would not appear to advance risk
modeling and might even be
counterproductive.
8. WKM Consultancy commented that
mandating a specific risk assessment
model would not be a beneficial
addition to regulations. Such a mandate
would stifle creativity and require
extensive definitions and
documentation of that methodology. A
mandated model would introduce a
prescriptive element with substantial
‘‘overhead’’ related to the maintenance
of the model’s documentation by the
regulators. They suggested that a better
solution would be to develop guidelines
of essential ingredients necessary in any
pipeline risk assessment.
9. An anonymous commenter
opposed requiring the use of a specific
risk model, suggesting that operators
should use models with which they are
comfortable. The commenter did suggest
that PHMSA strengthen requirements
concerning the use of risk models for
purposes other than risk-ranking
segments, expressing a belief that most
operators are using their models only for
that purpose.
10. California Public Utilities
Commission recommended that PHMSA
require statistical data be maintained
and used to support the weightings
assigned by risk models to various
threats.
Response to Question E.1 Comments
PHMSA appreciates the information
provided by the commenters. A large
number of comments do not support
adding a requirement for a specific risk
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assessment model or for strengthening
or revising the required functions that
risk models must perform. PHMSA
agrees that prescribing the use of
particular risk assessment models is not
appropriate for such a diverse industry,
and notes that relative index models
have been successfully used to rank
pipelines to prioritize baseline
assessments. However, PHMSA believes
that the integrity management rule
anticipates that operators would
continually improve their risk
assessment processes and that there are
specific risk assessment attributes
related to the nature and application of
risk models that need clarification. Such
attributes and shortcomings were
discussed at the ‘‘Improving Pipeline
Risk Assessments and Recordkeeping’’
workshop with stakeholders, held on
July 21, 2011.
PHMSA proposes to articulate clear
functional requirements, in
performance-based terms, for risk
assessment methods used by operators.
While PHMSA does not propose to
prescribe the specific risk assessment
model operators must use, PHMSA does
propose to clarify the characteristics of
a mature risk assessment program.
These include: (1) Identifying risk
drivers; (2) evaluating interactive
threats; (3) assuring the use of traceable
and verifiable information and data; (4)
accounting for uncertainties in the risk
model and the data used; (5)
incorporating a root cause analysis of
past incidents; (6) validating the risk
model in light of incident, leak and
failure history and other historical
information; (7) using the risk
assessment to establish criteria for
acceptable risk levels; and (8)
determining what additional preventive
and mitigative measures are needed to
achieve risk reduction goals. PHMSA
proposes to clarify that the risk
assessment method selected by the
operator must be capable of successfully
performing these functions.
E.2. It is PHMSA’s understanding that
existing risk models used by pipeline
operators generally evaluate the relative
risk of different segments of the
operator’s pipeline. PHMSA is seeking
comment on whether or not that is an
accurate understanding. Are relative
index models sufficiently robust to
support the decisions now required by
the regulation (e.g., evaluation of
candidate preventive and mitigative
measures, and evaluation of interacting
threats)?
1. Industry commenters, including
INGAA, AGA, Texas Pipeline
Association, Texas Oil & Gas
Association, WKM Consultancy, and
many pipeline operators reported that
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PHMSA’s understanding is correct and
that risk models in use generally
evaluate the relative risk of different
segments of the operator’s pipeline.
AGA noted that operators have selected
and implemented the risk models that
allowed them to prioritize the covered
segments for the baseline assessment
and subsequent reassessments and that
this complied with the Pipeline Safety
Improvement Act of 2002.
2. AGA, supported by a number of its
pipeline operator members, commented
that risk models currently in use are
sufficiently robust. Ameren Illinois and
GPTC expressed a similar belief.
3. INGAA, supported by some of its
members, noted that there is room for
improvement in the current practices of
risk modeling. INGAA reported that the
industry has established committees to
identify advancements in risk modeling.
4. WKM Consultancy commented that
the more robust of the relative risk
index techniques are often capable of
fulfilling some aspects of IM risk
management requirements such as
prioritization, but that other aspects of
the risk management requirements are
not well supported by relative risk
assessments. They suggested that some
risk assessment models in current use
could benefit from application of more
robust and modern techniques.
5. Kern River commented that a
relative risk model is sufficiently robust
to support decisions on preventive and
mitigative measures and assessment
intervals.
6. MidAmerican reported that its risk
model complies with ASME/ANSI
B31.8S and is sufficiently robust to
support decisions that are not
specifically related to assessments.
MidAmerican further stated that its risk
model produces results consistent with
its subject matter expert assessments of
relative risk.
7. Paiute and Southwest Gas reported
their conclusion that their risk models
are robust and support the process of
evaluation and selection of preventive
and mitigative measures.
8. Texas Pipeline Association and
Texas Oil & Gas Association noted that
all sources of information relative to the
integrity of a transmission pipeline
segment and the identified risk should
be used in the selection of preventive
and mitigative measures. Atmos agreed,
noting that preventive and mitigative
measures for a given pipeline segment
are based on the identified threats.
9. A private citizen suggested that
consideration of system-wide high risk
(e.g., urban areas) should be required,
contending relative risk is not good
enough when an entire system poses
high risks.
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Response to Question E.2 Comments
PHMSA appreciates the information
provided by the commenters. Although
a large number of comments contend
risk models currently in use are
sufficiently robust, PHMSA believes
that there are specific risk assessment
attributes not found in many of the
simple index or relative risk models
currently in use. The July 21, 2011,
workshop on ‘‘Improving Pipeline Risk
Assessments and Recordkeeping’’
identified several shortcomings in risk
assessments conducted using
qualitative, index, or relative risk
methodologies, and PHMSA is
proposing to clarify requirements to
address these issues including the need
for better or more prescriptive guidance
to address data gaps, data integration,
uncertainty, interacting threats, risk
management, and quantitative
approaches instead of subjective or
qualitative approaches. The proposed
regulation would require operators to
conduct risk assessments that effectively
analyze the identified threats and
potential consequences of an incident
for each HCA segment. Additionally, the
proposed regulation would require the
risk assessment to include evaluation of
the effects of interacting threats,
including those threats and anomalous
conditions not previously evaluated. It
should be further noted that the intent
of the original IM rule is that any risk
assessment would consider system-wide
risk.
E.3. How, if at all, are existing models
used to inform executive management
of existing risks?
1. INGAA commented that operators
should develop internal communication
plans and they should follow Section
10.3 of ASME/ANSI B31.8S in doing so.
AGA similarly noted that the methods
used to disseminate results of the risk
evaluation to executive management are
operator specific and detailed in the
operator’s integrity management plan. A
number of pipeline operators provided
comments supporting both INGAA’s
and AGA’s comments.
2. Texas Pipeline Association and
Texas Oil & Gas Association noted that
the results of risk modeling are usually
used in conjunction with assessment
results to inform executive management
of actions required beyond normal
repair, additional preventive and
mitigative measures, discussion of high
risk pipelines, and progress in meeting
assessment goals.
3. WKM Consultancy commented that
operators are obliged to communicate
all aspects of integrity management to
higher level managers at regular
intervals. They noted that all prudent
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operators are very interested in risk
management and results of risk
modeling are usually a centerpiece of
discussion and decision-making.
4. Ameren Illinois reported that its IM
plan provides for informing executive
management of existing risks.
5. Atmos reported that it provides
executive management with periodic
updates on the status of its integrity
management program. During these
updates, Atmos’ executive management
reviews baseline assessment plans,
assessment results, anomalies
discovered and mitigated, anomalies
discovered and scheduled for repair,
leading causes of anomalies, and
preventive and mitigative actions taken.
6. Kern River noted that it provides its
executive management with reports
describing integrity management
program activities and results and that
the company engages the use of the risk
model as an input to financial planning
and maintenance planning.
MidAmerican also reported that risk
scores are used to support capital,
operating and maintenance
expenditures to executive management.
7. Northern Natural Gas reported that
it provides executive management with
reports describing integrity management
program activities and results. Its
executive management is engaged in the
process and the use of the risk model to
prioritize projects.
8. Paiute and Southwest Gas reported
that integrity management activities are
discussed with executive management
quarterly.
9. An anonymous commenter
suggested that operators generally do
not use risk models to inform
executives, because they would have to
explain the models in order to do so.
Response to Question E.3 Comments
PHMSA appreciates the information
provided by the commenters. PHMSA
understands that internal company
processes for communication with
executive management are specific to
each company. To strengthen the
application of risk assessment, PHMSA
is proposing to clarify requirements by
providing more specific and detailed
examples of the kinds of preventive and
mitigative measures operators should
consider. The proposed rulemaking
would include the following specific
examples of preventive and mitigative
measures that operators should
consider: Establish and implement
adequate operations and maintenance
processes; establish and deploy
adequate resources for successful
execution of activities, processes, and
systems associated with operations,
maintenance, preventive measures,
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mitigative measures, and managing
pipeline integrity; and correct the root
cause of past incidents to prevent
recurrence. The last item necessarily
requires a robust root cause analysis that
identifies underlying programmatic or
policy issues that create or facilitate
conditions or circumstances that
ultimately lead to pipeline failures.
E.4. Can existing risk models be used
to understand major contributors to
segment risk and support decisions
regarding how to manage these
contributors? If so, how?
1. INGAA and many of its pipeline
operator members commented that
existing models can and do provide an
understanding of segment risk through
threat identification, performing ‘‘what
if’’ analyses, and identifying preventive
and mitigative measures that will
reduce risk.
2. AGA and GPTC noted that existing
models selected by operators are
sufficiently robust to allow the
integration of large volumes of data and
information to achieve a comprehensive
overall risk evaluation for their systems.
These risk models allow an operator to
understand the specific threats
associated with each pipeline segment
and the preventive and mitigative
measures that would be most
appropriate. A number of pipeline
operators provided comments
supporting AGA’s comments.
3. WKM Consultancy opined that
currently used risk assessment models
generally can significantly improve the
ability to manage risks. They noted that
a formal risk assessment provides the
structure to increase understanding,
reduce subjectivity, and ensure that
important considerations are not
overlooked.
4. Atmos reported that its model can
be used to generate a report listing the
significant variables contributing to a
relatively higher risk factor score, and
that if a contributing variable can be
controlled, the risk model can support
further actions to control the variable.
5. Ameren Illinois reported that it
uses a robust risk model that can
integrate various risk factors in order to
evaluate its system.
6. Kern River and Northern Natural
Gas commented that existing risk
models can be used to understand major
contributors to segment risk and support
decisions regarding how to manage
these contributors. By identifying threat
drivers in the risk results and analyzing
the data used by the model, integrity
management personnel are able to
reduce risk through preventive and
mitigative measures, improvements in
data quality, and shorter reassessment
intervals.
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7. MidAmerican reported that its risk
model is used to understand major
contributors to risk and to support
decisions regarding how to manage
those contributors.
8. Paiute and Southwest Gas reported
that they conduct a review of threatspecific indices to identify the major
contributors to risk for each threat.
9. Texas Pipeline Association and
Texas Oil & Gas Association noted that
risk modeling can be used to generate
reports listing the significant variables
contributing to high risk scores.
10. An anonymous commenter noted
that risk models can serve these
functions and some operators use them
in this way. The commenter opined that
most operators ‘‘aren’t there yet,’’ and
that operators who use models for this
purpose have more enthusiasm for
integrity management and more
executive management support.
Response to Question E.4 Comments
PHMSA appreciates the information
provided by the commenters. The
majority of the comments suggest that
current risk models provide an adequate
understanding of major contributors to
risk. PHMSA believes it is prudent to
clarify the required attributes of risk
assessment in this area and proposes to
include performance-based language to
assure that risk assessments adequately
identify the contribution to risk of each
risk factor, or each unique combination
of risk factors that interact or
simultaneously contribute to risk at a
common location.
E.5. How can risk models currently
used by pipeline operators be improved
to assure usefulness for these purposes?
1. INGAA noted that continuous
improvement is required, and that
industry is working on improvements to
ASME/ANSI B31.8S. AGA similarly
noted that risk models are periodically
improved by operators by integrating
new data and the results of integrity
assessments. A number of pipeline
operators provided comments
supporting INGAA’s and AGA’s
comments.
2. GPTC commented that new data
and information are received on an
ongoing basis. This new data, and
results of integrity assessments, are
reviewed, integrated, and added to risk
models periodically.
3. WKM Consultancy suggested that a
limited amount of standardization
would be appropriate. They opined that
this would ensure that all risk
assessments contain, at a minimum, a
short list of essential ingredients. For
example, all assessments should
produce a profile showing changes in
risk along a pipeline route.
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4. Ameren Illinois reported that its
risk model allows for integration of
information for continuous
improvement.
5. Atmos commented that there is the
potential for the risk model process to
handle unknown data in a more useful
manner. Atmos suggested that a higher
risk score with ‘‘known’’ data attributes
should be considered more relevant for
decisions on preventive and mitigative
measures than a similar score derived
from ‘‘unknown’’ data attributes.
6. Kern River suggested that industrywide research into failure probabilities
and effectiveness of preventive and
mitigative measures would facilitate
more rigorous quantitative models. Kern
River noted that vendors are
continuously improving risk models.
7. MidAmerican suggested that risk
models could be improved with better
tracking, recording, and retrieval of
assessment results. With feedback and
information sharing, refining
coefficients within the model will
produce more accurate risk results.
8. Northern Natural Gas reported that
its risk assessment process is improved
every year and that its risk model
vendor is heavily involved with the
company in understanding how the risk
results are used.
9. Paiute and Southwest Gas
suggested that risk models will be
improved as additional information is
gained through an assessment cycle and
that this continuous improvement
process will then repeat through
subsequent assessment cycles.
10. Texas Pipeline Association and
Texas Oil & Gas Association observed
that there is no ‘one size fits all’ solution
to this issue.
Response to Question E.5 Comments
PHMSA appreciates the information
provided by the commenters. The
comments speak in general terms about
incremental improvement of existing
index-type or qualitative relative risk
models. PHMSA believes that such
models, while appropriate and useful
for limited purposes such as ranking
segments to prioritize baseline
assessments, fall far short of the type of
model needed to fully execute a mature
integrity management program. PHMSA
proposes to clearly articulate the
requirements for validation of the risk
assessment and proposes to clarify that
an operator must ensure validity of the
methods used to conduct the risk
assessment in light of incident, leak,
and failure history and other historical
information. Additionally, the proposed
rule would require that validation must:
(1) Ensure the risk assessment methods
produce a risk characterization that is
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consistent with the operator’s and
industry experience, including
evaluations of the cause of past
incidents as determined by root cause
analysis or other means; and (2) include
analysis of the factors used to
characterize both the probability of loss
of pipeline integrity and consequences
of the postulated loss of pipeline
integrity.
E.6. If commenters suggest
modification to the existing regulatory
requirements, PHMSA requests that
commenters be as specific as possible.
In addition, PHMSA requests
commenters to provide information and
supporting data related to:
• The potential costs of modifying the
existing regulatory requirements
pursuant to the commenter’s
suggestions.
• The potential quantifiable safety
and societal benefits of modifying the
existing regulatory requirements.
• The potential impacts on small
businesses of modifying the existing
regulatory requirements.
• The potential environmental
impacts of modifying the existing
regulatory requirements.
No comments were received in
response to this question.
F. Strengthening Requirements for
Applying Knowledge Gained Through
the IM Program
The ANPRM requested comments
regarding strengthening requirements
related to operators’ use of insights
gained from implementation of an IM
program. IM assessments provide
information about the condition of the
pipeline. Identified anomalies that
exceed criteria in § 192.933 must be
remediated immediately
(§ 192.933(d)(1)) or within one year
(§ 192.933(d)(2)) or must be monitored
on future assessments (§ 192.933(d)(3)).
Operators are also expected to apply
knowledge gained through these
assessments to assure the integrity of
their entire pipeline as part of its threat
identification and risk analysis process
in accordance with § 192.917.
Section 192.917(e)(5) explicitly
requires that operators must evaluate
other portions of their pipeline if an
assessment identifies corrosion
requiring repair under the criteria of
§ 192.933. The operator must ‘‘evaluate
and remediate, as necessary, all pipeline
segments (both covered and noncovered) with similar material coating
and environmental characteristics.’’
Section 192.917 also requires that
operators conduct risk assessments that
follow American Society of Mechanical
Engineers/American National Standards
Institute (ASME/ANSI) B31.8S, Section
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5, and use these analyses to prioritize
segments for assessment, and to
determine what preventive and
mitigative measures are needed for
segments in HCAs. Section 5.4 of
ASME/ANSI B31.8S states that ‘‘risk
assessment methods should be used in
conjunction with knowledgeable,
experienced personnel . . . that
regularly review the data input,
assumptions, and results of the risk
assessments.’’ That section further
states, ‘‘an integral part of the risk
assessment process is the incorporation
of additional data elements or changes
to facility data,’’ and requires that
operators ‘‘incorporate the risk
assessment process into existing field
reporting, engineering, and facility
mapping processes’’ to facilitate such
updates. Neither part 192 nor ASME/
ANSI B31.8S specifies a frequency at
which pipeline risk analyses must be
reviewed and updated; instead, this is
considered to be a continuous, ongoing
process. The following are general
comments received related to the topic
as well as comments related to the
specific questions:
General Comment for Topic F
1. MidAmerican suggested that
application of knowledge gained
through integrity management should
not be treated any differently than any
other information gained from work on
or surveillance of the pipeline.
MidAmerican considers this to be
adequately addressed by § 192.613.
Response
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PHMSA continues to believe that
there are many important integrity
management requirements related to
insights gained from implementation of
the IM program beyond those covered
by the continuing surveillance
requirements of § 192.613. Integrity
management assessments provide
information about the condition of the
pipeline and operators are expected to
apply the knowledge gained through
these assessments to assure the integrity
of their entire pipeline. PHMSA believes
that the knowledge gained through IM
assessments should be integrated into
the risk assessment process, which is
not required by § 192.613.
Comments Submitted for Questions in
Topic F
F.1. What practices do operators use
to comply with § 192.917(e)(5)?
1. INGAA and a number of pipeline
operators noted that operators use
available information and field
knowledge to comply with this
requirement.
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2. AGA, supported by a number of its
member companies, reported that
operator practices are too distinct and
varied to list. AGA stated that
§ 192.917(e)(5) is prescriptive enough
and no new requirements are needed.
3. GPTC and Nicor cited NACE
SP0169 and NACE RP0177 as examples
of standards that can be used to guide
compliance with § 192.917(e)(5).
4. Texas Pipeline Association and
Texas Oil & Gas Association commented
that operators use cathodic protection
surveys and/or spot checks to determine
whether failure is likely.
5. Northern Natural Gas reported that
it takes the actions specified in
§ 192.917(e)(5) and includes
consideration of incidents and safety
related conditions.
6. Kern River, Paiute, and Southwest
Gas stated that they use root cause
evaluations of incidents to comply with
§ 192.917(e)(5).
Response to Question F.1 Comments
PHMSA appreciates the information
provided by the commenters. The
comments provide little information
related to specific operator practices for
compliance with § 192.917(e)(5).
PHMSA is not proposing to amend
§ 192.917(e)(5) at this time; however,
PHMSA proposes to clarify
requirements in § 192.917(b) to ensure
that the data gathering and integration
process includes an analysis of both the
HCA segments and similar non-HCA
segments and integrates information
about pipeline attributes and other
relevant information, including data
gathered through integrity assessments.
F.2. How many times has a review of
other portions of a pipeline in
accordance with § 192.917(e)(5) resulted
in investigation and/or repair of
pipeline segments other than the
location on which corrosion requiring
repair was initially identified?
1. Based on a limited response by
their members to a survey, Texas
Pipeline Association and Texas Oil &
Gas Association reported that repair of
corrosion beyond the initially-identified
anomaly is rare.
2. Ameren Illinois reported that it has
experienced two instances in which it
repaired other segments after identifying
corrosion on a covered pipeline
segment.
3. MidAmerican reported that it has
experienced a few instances of corrosion
where coating was damaged during
installation of a vent, and some at airto-soil interfaces.
4. Northern Natural Gas has
experienced no instances in which other
pipeline segments required repair.
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Northern added that corrosion wall loss
requiring repair is, itself, rare.
5. Paiute and Southwest Gas reported
that they had not identified any
immediate repair corrosion conditions.
Response to Question F.2 Comments
PHMSA appreciates the information
provided by the commenters. See the
response to question F.1.
F.3. Do pipeline operators assure that
their risk assessments are updated as
additional knowledge is gained,
including results of IM assessments? If
so, how? How is data integration used
and how often is it updated? Is data
integration used on alignment maps and
layered in such a way that technical
reviews can identify integrity-related
problems and threat interactions? How
often should aerial photography and
patrol information be updated for IM
assessments? If the commenter proposes
a time period for updating, what is the
basis for this recommendation?
1. INGAA and several pipeline
operators reported that operators update
risk analyses whenever new information
is obtained and particularly after
unexpected events.
2. AGA, GPTC, Nicor, Kern River, and
TransCanada commented that risk
analyses are updated at least annually.
3. Northern Natural Gas reported that
its procedures provide for updating to
include assessment results and changes
in environmental factors.
4. Paiute and Southwest Gas reported
that risk model updating is a continuous
process. Rankings are updated at 18- to
24-month intervals. Ameren Illinois and
Atmos similarly reported that updating
is an ongoing activity.
5. Texas Pipeline Association and
Texas Oil & Gas Association commented
that most operators have dedicated
teams to perform risk model updates.
6. Alaska Department of Natural
Resources commented that risk models
should be reviewed whenever
significant operational or environmental
changes occur. AKDNR contended that
risk models are not valid if there are
significant changes in these areas.
7. NAPSR reported its conclusion that
risk models should be updated after
every O&M activity or any finding that
a required activity was not performed.
8. INGAA and a number of pipeline
operators reported that data is updated
using a common spatial reference
system, e.g., maps or tables, and the
frequency of data integration varies by
operator.
9. AGA, supported by a number of its
member companies, reported that data
integration does not always involve use
of geospatial tools.
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10. Atmos reported that it uses
internal teams of subject matter experts
for data integration and that its maps are
not layered for technical data use.
11. Northern Natural Gas, Paiute, and
Southwest Gas stated that they perform
integration on alignment sheets based
on integrity management summaries
and subject matter expert reviews.
12. Texas Pipeline Association and
Texas Oil & Gas Association reported
that many pipeline operators are
migrating to GIS systems.
13. INGAA and many pipeline
operators commented that information
from aerial photography should be
updated annually. They noted that this
would be consistent with the frequency
of reviewing HCA designations and
operator budgeting and contended that
more frequent updates would not
increase risk model accuracy. INGAA
suggested that other information,
including information related to
external events, should be updated
based on the nature and severity of
experienced events.
14. AGA, Paiute, and Southwest Gas
noted that not all operators use aerial
photography and expressed their belief
that such use should not be required.
AGA noted that there are many tools,
including routine patrols, to gather data
about the pipeline environment. A
number of member pipeline operators
supported AGA’s comments.
15. Northern Natural Gas reported
that it updates information periodically,
but with no set frequency. Northern
noted that some areas are stable while
change can occur rapidly in others.
16. Texas Pipeline Association and
Texas Oil & Gas Association
recommended annual updates as a
minimum. The associations noted that
this recognizes the time required to
produce/acquire assessment data.
needed to assure the integrity of each
HCA segment is adequate, if properly
implemented, and is not proposing a
prescribed frequency at this time.
However, PHMSA proposes to clarify
requirements in §§ 192.917 and
192.937(b) to ensure the continual
process of evaluation and assessment is
based on an updated and effective data
integration and risk assessment process
as specified in § 192.917.
F.4. Should the regulations specify a
maximum period in which pipeline risk
assessments must be reviewed and
validated as current and accurate? If so,
why?
1. INGAA and numerous pipeline
operators recommended that reviews be
annual, as suggested in PHMSA’s Gas
Integrity Management Program
Frequently Asked Question FAQ–234,
arguing that this is practical and
sufficient (FAQs can be viewed at
https://primis.phmsa.dot.gov/gasimp/
faqs.htm).
2. AGA, GPTC, and a number of other
pipeline operators commented that no
maximum period should be specified
for review of risk assessments. These
commenters argued that no one-size-fitsall interval would be appropriate and
expressed their conclusion that the
current requirements in § 192.937 are
adequate.
3. California Public Utilities
Commission recommended that reviews
be required annually, at intervals not to
exceed 15 months, consistent with other
requirements within part 192.
4. An anonymous commenter
suggested that a specified review period
would be counterproductive, arguing
that most operators would simply
default to the required interval, even if
more frequent reviews were appropriate.
Response to Question F.3 Comments
PHMSA appreciates the information
provided by the commenters. After
review of the comments, PHMSA agrees
that annual updates are desirable and
many operators perform full updates, or
partial data updates (such as updating
aerial photos), annually. Some pipeline
segments may be in rapidly changing,
dynamic environments, while others
may remain static for years. PHMSA
also agrees that prescriptive
requirements to perform a full risk
assessment annually are not necessary
and potentially burdensome, especially
for very small operators, whose systems
and conditions do not change often.
PHMSA is satisfied that the current
requirement, which contains a
performance based requirement to
update risk assessments as frequently as
PHMSA appreciates the information
provided by the commenters. See
PHMSA response to comments related
to Question F.3.
F.5. Are there any additional
requirements PHMSA should consider
to assure that knowledge gained through
IM programs is appropriately applied to
improve safety of pipeline systems?
1. INGAA and many pipeline
operators opined that no new
requirements are needed in this area.
They noted that prescriptive
requirements often become out of date
as technology improves.
2. AGA and numerous pipeline
operators agreed that no new
requirements are needed, noting that
existing regulations and sharing of
information through industry groups is
sufficient.
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Response to Question F.4 Comments
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3. Texas Pipeline Association and
Texas Oil & Gas Association opined that
existing requirements are adequate.
4. Accufacts suggested that
requirements should be more
prescriptive concerning threat
evaluation and interactive threats, as
this is the heart of integrity
management.
5. An anonymous commenter
suggested that new requirements be
established governing assessments
conducted by pressure testing. The
commenter opined that the
requirements in subpart J are inadequate
and represent an ‘‘easy out’’ for some
operators.
Response to Question F.5 Comments
PHMSA appreciates the information
provided by the commenters. While
PHMSA believes that explicit
requirements should be included to
address interactive threats, PHMSA also
believes that prescriptive rules for how
an operator must evaluate interactive
threats are not practical. Therefore,
PHMSA proposes to clarify
performance-based requirements to
include an evaluation of the effects of
interacting threats and for the continual
process of evaluation and assessment to
include interacting threats in
identification of threats specific to each
HCA segment. Comments on integrity
assessment methods are addressed in
Topic G.
F.6. What do operators require for
data integration to improve the safety of
pipeline systems in HCAs? What is
needed for data integration into pipeline
knowledge databases? Do operators
include a robust database that includes:
Pipe diameter, wall thickness, grade,
and seam type; pipe coating; girth weld
coating; maximum operating pressure
(MOP); HCAs; hydrostatic test pressure
including any known test failures;
casings; any in-service ruptures or leaks;
ILI surveys including high resolution—
magnetic flux leakage (HR–MFL), HR
geometry/caliper tools; close interval
surveys; depth of cover surveys; rectifier
readings; test point survey readings;
alternating current/direct current (AC/
DC) interference surveys; pipe coating
surveys; pipe coating and anomaly
evaluations from pipe excavations; SCC
excavations and findings; and pipe
exposures from encroachments?
1. INGAA, supported by a number of
pipeline operators, commented that
experience and information gained from
a variety of sources, including GIS data,
corrosion data, ILI data/results, work
management activities, SCADA,
encroachments, leaks etc., is utilized in
data integration. INGAA reported that
operators have made major investments
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in database applications to meet
changing organizational and regulatory
requirements and to manage increasing
volumes of data effectively. Tools
generally are available for integrating
data into pipeline knowledge databases.
For integration purposes, the database
must contain adequate metadata
elements such that dates, if important,
and location and length attributes are
maintained. Currently-available systems
support these needs. INGAA expressed
concern over use of the term ‘‘robust
database,’’ since this could be construed
to mean that all applicable data must be
maintained in a common database or
other venue which does not meet the
particular needs of the operator. INGAA
reported that it has an active Integrity
Management—Continuous Improvement
(IMCI) team addressing improvement in
these processes and management
systems.
2. AGA, GPTC, and a number of
pipeline operators commented that a
prescriptive requirement would be
inappropriate because there is too much
variability among operators and their
risk assessment methods. AGA
expressed its conclusion that there is no
single methodology that incorporates
the wide variety of pipeline information
used by operators.
3. MidAmerican suggested that an
operator needs a robust computer model
to integrate diverse data dynamically
into one table with one set stationing.
4. Kern River reported that it uses
extensive GIS and cathodic protection
databases for these purposes.
5. An anonymous commenter
recommended that PHMSA require
knowledge of cathodic protection
current level, amount, and direction of
current flow. The commenter opined
that this information is not now
generally collected, and that it would
allow for early detection of coating
failures and CP interferences.
Response to Question F.6 Comments
PHMSA appreciates the information
provided by the commenters. An
integral part of applying information
from the IM Program to the risk
assessment and other analyses is the
collection, validation, and integration of
pipeline data. PHMSA proposes to
clarify the data integration language in
the requirements by repealing the
reference to ASME/ANSI B31.8S and
including requirements associated with
data integration directly in the rule text:
(1) Establishing a number of pipeline
attributes that must be included in these
analyses, (2) clarifying that operators
must integrate analyzed information,
and (3) ensuring that data are verified
and validated.
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F.7. If commenters suggest
modification to the existing regulatory
requirements, PHMSA requests that
commenters be as specific as possible.
In addition, PHMSA requests
commenters to provide information and
supporting data related to:
• The potential costs of modifying the
existing regulatory requirements
pursuant to the commenter’s
suggestions.
• The potential quantifiable safety
and societal benefits of modifying the
existing regulatory requirements.
• The potential impacts on small
businesses of modifying the existing
regulatory requirements.
• The potential environmental
impacts of modifying the existing
regulatory requirements.
No comments were received in
response to this question.
G. Strengthening Requirements on the
Selection and Use of Assessment
Methods
The existing IM regulations require
that baseline and periodic assessments
of pipeline segments in an HCA be
performed using one of four methods:
(1) In-line inspection;
(2) Pressure test in accordance with
subpart J;
(3) Direct assessment to address the
threats of external and internal
corrosion and SCC; or
(4) Other technology that an operator
demonstrates can provide an equivalent
understanding of the condition of line
pipe.
Operators must notify PHMSA in
advance if they plan to use ‘‘other
technology.’’ Operators must apply one
or more methods, depending on the
threats to which the HCA segment is
susceptible. The ANPRM requested
comments related to the applicability,
selection, and use of each assessment
method, existing consensus standards
and requirements, and the potential
need to strengthen the requirements.
The ANPRM then listed questions for
consideration and comment. The
following are general comments
received related to the topic as well as
comments related to the specific
questions:
General Comments for Topic G
1. INGAA, supported by a number of
its pipeline operator members, noted
that they are committed to work with
technology providers and researchers to
improve the integrity management
assessment capabilities of its members.
Further, INGAA members are sharing
their experiences with applying these
new and improved assessment methods
to specific threats. INGAA opined that
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a great advantage of the integrity
management structure, as opposed to a
prescriptive regulatory regime, is the
creation of an environment conducive to
technological development, innovation
and improved knowledge.
2. Accufacts suggested that a more
prescriptive regulation is needed
clarifying the applicability and
limitations of direct assessment.
Accufacts is concerned that operators
are selecting direct assessment due to a
cost bias while ignoring that it cannot be
used for all threats and should not be
used on some pipeline segments.
3. Chevron commented that PHMSA
should continue to allow operators to
select and use the most effective method
to assess each pipeline segment.
4. NAPSR recommended that PHMSA
implement a regulatory change that
requires both ILI and pressure testing for
all transmission pipelines and requires
a reduction in MAOP until either the ILI
or the pressure tests are performed.
5. MidAmerican, a gas distribution
company, noted that many of its
transmission pipelines are short, small
diameter lines that cannot be pigged.
6. Dominion East Ohio suggested that
PHMSA should be funding more
research leading to the development of
assessment tools, particularly smart
tools, to increase the number of
assessment options available rather than
limiting the tools that can be used.
7. A public citizen commented that
pipe with unknown or uncertain
specifications should be subject to the
most stringent testing requirements.
8. Two public citizens addressed
required assessment intervals. One
suggested that all pipe that puts the
public at significant risk should be
tested, by hydro testing or some other
means, at approximately ten-year
intervals. Another commenter
recommended that assessments be
required more frequently in densely
populated areas.
9. PST opined that the need to ask the
questions in this section makes clear
that PHMSA’s current level of oversight
and review of IM planning and
implementation is inadequate, and calls
into question the value of many IM
programs, particularly those relying to
any extent on direct assessment
methods. PST recommended that the
regulations be significantly strengthened
to require PHMSA’s review and
administration approval of any IM
program.
Response
PHMSA appreciates the information
provided by the commenters. PHMSA
agrees that pipeline operators should be
able to select the best assessment
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method applicable for its pipelines and
circumstances. PHMSA also agrees with
NAPSR and other commenters that
additional requirements are needed for
assessing more miles of pipeline that
pose a risk to the public. PHMSA has
also identified the need to address
specific issues related to the selection of
integrity assessment methods that have
been identified following the San Bruno
incident, especially related to the use of
direct assessment. Therefore, PHMSA
proposes to add more specific
requirements related to (1) performance
of integrity assessments for pipe not
covered by subpart O (i.e., pipeline not
located in a high consequence area) that
represents risk to the public, and (2)
selection of assessment methods.
Specifically, PHMSA proposes to revise
the requirements in §§ 192.921 and
192.937 as follows: (1) Allow direct
assessment only if a line is not capable
of inspection by internal inspection
tools; (2) add a newly defined
assessment method: ‘‘spike’’ hydrostatic
test; (3) add excavation and in situ
direct examination as an allowed
assessment method; and (4) add guided
wave ultrasonic testing (GWUT) as an
allowed assessment method. In
addition, PHMSA proposes to add a
new § 192.710 to require that a
significant portion of pipelines not
covered by subpart O be periodically
assessed using integrity assessment
techniques similar to those proposed for
HCA segments. Specifically, PHMSA
proposes to require that all pipeline
segments in class 3 and class 4 locations
and moderate consequence area as
defined in § 192.3 if the pipe segment
can accommodate inspection by means
of instrumented inline inspection tools
(i.e., ‘‘smart pigs’’), be periodically
assessed. Although PHMSA proposes to
provide selected, more prescriptive
requirements for the selection of
assessment methods, the pipeline safety
regulations would continue to allow the
use of other technology that an operator
demonstrates can provide an equivalent
understanding of the condition of the
line pipe (comparable to a specified
integrity assessment such as pressure
testing or inline inspection), in order to
continue to encourage research and
development of more effective
assessment technologies similar to the
successful development of GWUT. For
non-HCA segments, operator
notification to PHMSA of the selection
of other technologies would not be
required.
PHMSA understands the Pipeline
Safety Trust’s recommendation that the
regulations require PHMSA’s review
and approval of any IM program.
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PHMSA believes its current approach to
inspection of operator IM programs is
both flexible and appropriate.
Comments Submitted for Questions in
Topic G
G.1. Have any anomalies been
identified that require repair through
various assessment methods (e.g.,
number of immediate and total repairs
per mile resulting from ILI assessments,
pressure tests, or direct assessments)?
1. INGAA reported that operators
have used in-line inspection, pressure
testing, and direct assessment, with inline inspection being most prevalent.
INGAA commented that all three
methods have been successful at
identifying anomalies requiring repair.
A number of pipeline operators
supported INGAA’s comments.
2. AGA and Ameren Illinois stated
that all assessment methods used by
pipeline operators have been used to
identify, or have identified, anomalies
requiring repair. A number of pipeline
operators supported AGA’s comments.
3. Accufacts recommended that
PHMSA publically report the number of
anomalies discovered and repaired by
anomaly type, time to repair, state, and
assessment method for both HCAs and
non-HCAs.
4. Texas Pipeline Association, Texas
Oil & Gas Association, Atmos, Paiute,
and Southwest Gas noted that the
transmission pipeline annual report
includes the number of immediate and
scheduled anomalies identified by each
assessment method.
5. ITT Exelis Geospatial Systems
reported that aerial leak surveys using
laser technology, which is not one of the
assessment methods specified in the
regulations, have been successful in
identifying pipeline leaks.
6. Kern River reported that it did not
identify any immediate or scheduled
repairs from January 1, 2004, through
December 31, 2010.
7. MidAmerican noted that it has used
all three allowed assessment methods.
Approximately 42 percent of the
company’s pipeline has been assessed
using direct assessment. All anomalies
requiring repair have been identified
using in-line inspection.
8. Northern Natural Gas reported that
it identified seven immediate repair
anomalies in the period from January 1,
2004, through December 31, 2010. The
total number of repairs made during this
same period averaged 0.1 per mile.
9. An anonymous commenter noted
that few leaks are detected using subpart
J pressure testing.
10. GPTC reported that it has no data
with which to respond to this question.
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Response to Question G.1 Comments
PHMSA appreciates the information
provided by the commenters. PHMSA
agrees that all three methods have been
successful at identifying anomalies
requiring repair. However, by its nature,
direct assessment is a sampling-type
assessment method. Hydrostatic
pressure testing and in-line inspection
both assess the entire segment. PHMSA,
therefore, believes that these methods
provide a higher level of assurance
(though still not 100%) that no injurious
pipeline defects remain in the pipe after
the assessment is completed and
anomalies repaired. Based on this
inherent difference, PHMSA proposes to
revise the requirements to: (1) Allow
direct assessment only if a line is not
capable of inspection by internal
inspection tools; (2) add a newly
defined assessment method: ‘‘spike’’
hydrostatic test; (3) add excavation and
in situ direct examination as an allowed
assessment method; and (4) add guided
wave ultrasonic testing (GWUT) as an
allowed assessment method.
G.2. Should the regulations require
assessment using ILI whenever possible,
since that method appears to provide
the most information about pipeline
conditions? Should restrictions on the
use of assessment technologies other
than ILI be strengthened? If so, in what
respect? Should PHMSA prescribe or
develop voluntary ILI tool types for
conducting integrity assessments for
specific threats such as corrosion metal
loss, dents and other mechanical
damage, longitudinal seam quality,
SCC, or other attributes?
1. INGAA, supported by a number of
its pipeline operator members, noted
that ILI is effective, but has its own
limitations; pressure testing and direct
assessment can provide information that
ILI cannot. INGAA commented that
operators must be allowed to use all
assessment techniques without
encumbrances or conditions because all
techniques are effective.
2. AGA and a number of its members
commented that ILI is one option of a
variety of methods available to operators
and suggested that applying additional
ILI assessment requirements would
hinder operators’ ability to select the
tool with the appropriate capabilities to
address pipeline threats. AGA
commented that this would be
inappropriate and operators must be
allowed to use any of the three
assessment methods, without
conditions, based on the circumstances
and threats applicable to their pipelines.
3. Air Products and Chemicals, Inc.
opposed a requirement to use ILI
whenever possible. The company noted
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that one of the benefits of the current IM
framework is the flexibility it provides
to operators in how to achieve
regulatory goals. Air Products noted that
use of alternative methods is already
constrained by regulation and
contended that the existing limitations
are adequate and it would be
inappropriate for PHMSA to specify
particular tool types for individual
threats. Atmos agreed, noting that ILI is
not the only assessment method
applicable to many threats. Atmos noted
that ILI technology is developing at a
rapid pace, and suggested that
prescribing certain tool types could
limit future advancements or cause the
rate of development to be slowed.
4. TransCanada opposed requiring use
of ILI. The company noted that ILI has
its advantages, but it also has
limitations, and commented that
operators must be able to select the
methods best suited to evaluate
identified threats, given the wide range
of circumstances and threats that may
be applicable to particular pipeline
segments.
5. NACE International noted that
assessments using only ILI do not
necessarily provide the most
information about pipeline conditions;
other assessment methods may be more
appropriate for some threats. NACE also
noted that not all pipelines are piggable.
NACE believes that each assessment
method has strengths and weaknesses,
each should be used where appropriate,
and overly prescriptive rules can
supplant sound engineering judgment,
stifle innovation, and prevent the
development of new technologies.
6. Accufacts commented that all new
pipelines should be configured to
permit ILI and a timetable should be
established to convert older pipelines
for ILI. At the same time, Accufacts
cautioned that one particular approach
to ILI should not be oversold, and
suggested that limitations on use of
certain assessment methods should be
strongly clarified in regulations.
Accufacts suggested that PHMSA needs
to clarify the major strengths and
weaknesses of the various assessment
methods identified and to improve
subpart J, including requiring the
reporting of hydro testing pressure
ranges, both minimum and maximum
pressures, as a percentage of SMYS
when appropriate.
7. MidAmerican suggested that
operators be allowed to address threats
by category using the guidance in
ASME/ANSI B31.8S. MidAmerican
noted that it cannot use ILI on all of its
transmission pipelines, 42 percent of
which have been assessed using direct
assessment. MidAmerican suggested
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that operators continue to use their
threat assessments to determine which
pipelines should be retrofitted to
accommodate ILI.
8. Northern Natural Gas reported that
it uses ILI whenever possible but it
cannot be used on all of its lines due to
their small diameter. Northern noted
that pressure testing and direct
assessment may be more appropriate for
some threats and that the operator is
responsible for selecting the best
assessment method. Northern opined
that the guidance on tool selection in
ASME/ANSI B31.8S is sufficient.
9. Texas Pipeline Association and
Texas Oil & Gas Association
recommended that ILI not be the
required assessment method of choice
and that operators continue to have the
flexibility to select the appropriate
assessment method, noting that other
methods may be better for a particular
threat. The associations noted that ILI
technology is improving rapidly and
expressed concern that rulemaking
cannot keep pace with technological
advancement and that prescribing tools
could result in assessments being
conducted with inferior technology.
10. Thomas M. Lael, an industry
consultant, noted that no assessment
method, including ILI, is perfect. Lael
suggested that use of alternating
methods be required to realize the
strengths of all methods.
11. A citizen commenter suggested
that use of direct assessment be limited,
since it does not provide sufficient
information about the pipeline.
12. An anonymous commenter noted
that requiring ILI would not be cost
beneficial, because corrosion metal loss
is a relatively slow process.
13. GPTC noted that ILI cannot be
used on all pipelines and recommended
that operators have the latitude to select
the assessment method most
appropriate for their pipelines. Oleksa
and Associates similarly noted that ILI
cannot be used on some pipelines.
14. Paiute and Southwest Gas
opposed a requirement to use ILI
whenever possible. The companies
noted that ILI provides current pipe
conditions but no information on
environmental conditions surrounding
the pipe. They commented that
operators should not be discouraged
from using any appropriate assessment
method.
15. Ameren Illinois opposed requiring
the use of ILI, noting that it is neither
practical nor feasible to require ILI
assessments on all pipelines.
16. California Public Utilities
Commission recommended that
pressure testing and ILI be the only
methods allowed for IM assessments.
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CPUC suggested that the use of direct
assessment be limited to confirmatory
direct assessments and lines that have
been pressure tested to subpart J
requirements. CPUC further
recommended that the regulations
prescribe acceptable ILI tool types to
address specific threats.
17. A private citizen suggested that
pressure testing should not be allowed
as an assessment method because it
provides no information about
anomalies not resulting in leaks or
failures. The commenter suggested that
use of pressure testing should be limited
to verifying the integrity of new or
repaired pipelines.
Response to Question G.2 Comments
PHMSA appreciates the information
provided by the commenters. PHMSA
agrees that operators should be able to
select the methods best suited to
evaluate identified threats. However,
PHMSA believes rulemaking for
strengthening requirements for the
selection and use of assessment
methods is needed to address specific
issues identified from the San Bruno
incident. PHMSA proposes more
prescriptive guidance for the selection
of assessment methods, especially
related to the use of direct assessment
and to assess for cracks and crack-like
defects, as indicated in the response to
general comments, above. For HCA
segments, PHMSA proposes that the use
of direct assessment as the assessment
method would be allowed only if the
pipeline is not capable of being
inspected by internal, in-line inspection
tools. For non-HCA segments,
assessments would have to be done
within 15 years and every 20 years
thereafter. To facilitate the identification
of non-HCA areas that require integrity
assessment, PHMSA proposes to define
a ‘‘Moderate Consequence Area’’ or
MCA. PHMSA also proposes additional
requirements for selection and use of
internal inspection tools, including a
requirement to explicitly consider
uncertainties such as tool tolerance in
reported results in identifying
anomalies.
PHMSA disagrees with the suggestion
that pressure testing should not be
allowed as an assessment method. In
many circumstances, pressure testing is
a good indicator of a pipeline’s integrity.
Although it does not assess subcritical
defects, it provides assurance of
adequate design safety margin and can
be useful in particular for lines that are
not piggable.
G.3. Direct assessment is not a valid
method to use where there are pipe
properties or other essential data gaps.
How do operators decide whether their
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knowledge of pipeline characteristics
and their confidence in that knowledge
is adequate to allow the use of direct
assessment?
1. Industry commenters, including
AGA, INGAA, Texas Pipeline
Association, Texas Oil and Gas
Association, and numerous pipeline
operators noted that the requirements
applicable to direct assessment,
specified in NACE Standard SP0502–
2008 and incorporated into subpart O by
reference, require a feasibility study to
determine if use of direct assessment is
appropriate. If it cannot be determined
during the pre-assessment phase that
adequate data is available, another
assessment method must be selected.
Industry commenters noted that it is the
operator’s responsibility to select an
appropriate assessment method.
2. Paiute and Southwest Gas
disagreed with the statement that
‘‘direct assessment is not a valid method
to use where there are pipe properties
or other essential data gaps.’’ The
companies noted that the data gathered
and evaluated conforms to Section 4 of
ASME/ANSI B31.8S (incorporated by
reference) which allows use of
conservative proxy values when data
gaps exist.
3. California Public Utilities
Commission recommended that
pressure testing and ILI be the only
methods allowed for IM assessments.
CPUC suggested that use of direct
assessment be limited to confirmatory
direct assessments and lines that have
been pressure tested to subpart J
requirements.
Response to Question G.3 Comments
PHMSA appreciates the information
provided by the commenters. PHMSA
agrees that pressure testing and ILI are
preferred integrity assessment methods,
over direct assessment. However, when
properly implemented, DA can be a
valuable integrity assessment tool.
PHMSA proposes to retain direct
assessment as an assessment method
where warranted, but proposes to revise
the requirements in §§ 192.921 and
192.937 to allow use of direct
assessment or other method only if a
line is not capable of inspection by
internal inspection tools.
G.4. How many miles of gas
transmission pipeline have been
modified to accommodate ILI inspection
tools? Should PHMSA consider
additional requirements to expand such
modifications? If so, how should these
requirements be structured?
1. A number of industry commenters
submitted data concerning the number
of pipeline miles that have been
modified to accommodate ILI:
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• INGAA reported that more than
30,000 miles of pipeline have been
modified across the industry.
• Atmos reported that it has modified
approximately 2,800 miles.
• Northern Natural Gas reported that
it has modified approximately 2,500
miles.
• MidAmerican reported that it has
modified 38 miles.
• Paiute and Southwest Gas reported
that they have made modifications but
have not tracked the total mileage on
which they were performed.
• Ameren Illinois and Kern River
reported that they have modified no
pipelines. Kern River noted specifically
that all of its mainline is piggable.
2. AGA reported that it has no data
concerning the number of miles
modified, but noted that operators are
required to assure that new and
replaced pipelines can accommodate ILI
tools. AGA contended that modifying
pipelines to accommodate ILI tools is
more onerous for intrastate transmission
pipeline operators than for interstate
operators. A number of operators
supported AGA’s comments.
3. Texas Pipeline Association and
GPTC reported that they have no data
with which to respond to this question.
4. California Public Utilities
Commission supported additional
requirements to expand modifications to
accommodate ILI but reported that it has
no opinion on how these requirements
should be structured.
5. MidAmerican noted that one-third
of its 770 miles of transmission pipeline
is of a diameter smaller than available
ILI tools.
6. Northern Natural Gas commented
that PHMSA should not consider
additional requirements to expand
modifications of pipelines to
accommodate ILI tools, and that the
inspection method and determination to
assess additional line segments outside
of HCAs should be based on specific
risk factors and type and configuration
of pipeline facility. The company noted
that some lines cannot be assessed using
ILI.
7. Paiute and Southwest Gas noted
that § 192.150 requires that newly
constructed or replacement pipelines be
designed to accommodate ILI tools.
They contended that the decision to
modify other pipelines should be an
operator decision based on the best
assessment method.
8. Texas Pipeline Association and
Texas Oil & Gas Association opined that
PHMSA does not need to develop
additional requirements for the
modification of transmission pipelines
to accommodate ILI tools. The
associations noted that the regulations
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already cover this for new and
replacement pipelines and that there is
a financial incentive for operators to use
ILI tools versus other assessment
methods. Atmos agreed, also noting that
there are numerous advantages to ILI
that incentivize operators to use that
method when they can.
9. Accufacts commented that PHMSA
should report publicly the number of
miles of transmission pipeline that can
be inspected by ILI as well as the
number of miles inspected by other
assessment methods both for HCAs and
non-HCAs.
Response to Question G.4 Comments
PHMSA appreciates the information
provided by the commenters. In its
report on the San Bruno incident, the
NTSB recommended that all natural gas
transmission pipelines be configured so
as to accommodate in-line inspection
tools, with priority given to older
pipelines (recommendation P–11–17).
In its initial response to the NTSB
recommendation, PHMSA stated that
implementing this recommendation will
involve significant technical and
economic challenges and is likely to
require time to implement. Additional
data is needed to evaluate this issue.
Therefore, further rulemaking will be
considered separately in order to
complete this evaluation. PHMSA will
review the comments received on the
ANPRM and will address this issue in
the future.
G.5. What standards are used to
conduct ILI assessments? Should these
standards be incorporated by reference
into the regulations? Should they be
voluntary?
1. INGAA, supported by a number of
its operator members, noted that
standards are continuously upgraded
and improved and recommended that
PHMSA adopt performance-based
language that will allow operators to
select appropriate standards.
2. AGA, supported by a number of its
members, noted that ILI technology is
advancing rapidly and it would be
unwise to restrict innovation by
handcuffing it to a slow-developing
rulemaking process. AGA recommended
that PHMSA not adopt ILI standards
into the code. Ameren Illinois agreed
that standards should not be
incorporated, because to do so would
limit operators’ ability to use up-to-date
standards.
3. GPTC argued that there is no
justification to enact additional
prescriptive regulations for ILI
assessments of pipelines. GPTC
contended that performance standards
allow operators to select the best
approach.
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4. Atmos, MidAmerican, Northern
Natural Gas, Paiute, and Southwest Gas
all cited one or more of API1163, ASNT
ILI–PQ–2005 and RP0102–2002, and
ASME/ANSI B31.8S as standards used
to conduct ILI assessments. All agreed
that use of industry standards should
remain voluntary. Paiute and Southwest
Gas, in particular, commented that
technology is developing rapidly, and
that incorporating current standards
into the regulations may hold operators
accountable to a level of performance
that may be outdated.
5. Texas Pipeline Association and
Texas Oil & Gas Association also
opposed incorporating ILI standards
into the regulations. TPA commented
that there are incentives for operators to
take appropriate measures to obtain
accurate and reliable ILI results.
6. An anonymous commenter
suggested that incorporating standards
could be counterproductive, since
operators would usually stop with the
required actions. The commenter
suggested that a better approach would
be to require operators to have precise
specifications, guidelines, and a written
process for ILI, none of which should be
developed by the operator’s ILI vendor.
The commenter also suggested that a
similar approach be adopted for stress
corrosion cracking direct assessment
(SCCDA).
7. California Public Utilities
Commission and a private citizen
recommended that standards be
incorporated for mandatory compliance,
arguing that this is necessary to assure
quality and accuracy.
Response to Question G.5 Comments
PHMSA appreciates the information
provided by the commenters. The
current pipeline safety regulations in 49
CFR 192.921 and 192.937 require that
operators assess the material condition
of pipelines in certain circumstances
and allow use of in-line inspection tools
for these assessments. Operators are
required to follow the requirements of
ASME/ANSI B31.8S in selecting the
appropriate ILI tools. ASME B31.8S
provides limited guidance for
conducting ILI assessments. At the time
these rules were promulgated, there was
no consensus industry standard that
addressed ILI. Three related standards
have been published: API STD 1163–
2005, NACE SP0102–2010, and ANSI/
ASNT ILI–PQ–2010. These standards
address the qualification of inline
inspection systems, the procedure for
performing ILI, and the qualification of
personnel conducting ILI, respectively.
The incorporation of these standards
into pipeline safety regulations will
promote a higher level of safety by
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establishing consistent standards.
Therefore, PHMSA is proposing to
incorporate these industry standards
into the regulations to provide better
guidance for conducting integrity
assessments with in-line inspection.
PHMSA also encourages and actively
supports the development of new and
better technology for integrity
assessments. Therefore, the rule also
allows the application and use of new
technology, provided that PHMSA is
notified in advance. PHMSA will
continue to evaluate the need for
additional guidance for conducting
integrity assessments or applying new
technology.
G.6. What standards are used to
conduct internal corrosion direct
assessment (ICDA) and SCCDA
assessments? Should these standards be
incorporated into the regulations? If the
commenter believes they should be
incorporated into the regulations, why?
What, if any, remediation, hydrostatic
test or replacement standards should be
incorporated into the regulations to
address internal corrosion and SCC?
1. INGAA commented that standards
exist for ICDA and SCCDA. AGA agreed
that NACE SP0206 addresses ICDA and
SP0204 addresses SCCDA. AGA
opposed adopting these standards into
the regulations, however, commenting
that a standard must be demonstrated to
be effective before it can be
incorporated. AGA noted that there are
long-standing issues with the ICDA
standard. Numerous pipeline operators
provided comments supporting the
INGAA and AGA comments.
2. GPTC, Atmos, Ameren Illinois,
MidAmerican, Paiute, Southwest Gas,
Texas Gas Association and Texas Oil &
Gas Association all referenced one or
more of: NACE SP0502, NACE SP0206,
ASME/ANSI B31.8S, and GRI02–0057.
All agreed that the standards should not
be incorporated by reference, arguing
that this would stifle innovation or
require operators to follow requirements
that may become outdated, or both.
Paiute and Southwest Gas specifically
recommended that PHMSA collect
additional information on industry best
practices and compile/review IM results
related to internal corrosion and SCC
before taking any action towards
incorporating the standards.
3. NACE International reported its
conclusion that the existing standards
for ICDA and SCCDA should be
incorporated into regulations. NACE
also cautioned that overly-prescriptive
regulations can prevent innovation and
development of new technologies.
4. Northern Natural Gas reported that
it used NACE SP0206 in developing its
ICDA procedures and there would be no
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impact on the company if the standard
were adopted into regulations. Northern
further reported it does not use SCCDA.
5. Accufacts commented that few
technical gains have been made in the
abilities of direct assessment methods to
reliably identify or assess at-risk
anomalies, especially with regards to
SCC.
6. California Public Utilities
Commission argued that pressure testing
and ILI should be the only assessment
methods allowed. The Commission
contended that direct assessment should
be limited to use during confirmatory
direct assessments and for lines that
have been pressure tested to subpart J
requirements.
7. An anonymous commenter noted
that Kiefner, NACE, and ASTM all
provide useful references for SCCDA
and ICDA.
8. INGAA, supported by several of its
operator members, noted that ASME/
ANSI B31.8S addresses remediation and
pressure testing. INGAA recommended
that PHMSA adopt the 2010 version of
this standard, arguing that it is
improved over the 2004 standard that is
currently incorporated by reference into
Section 192.7 and that it addresses nearneutral SCC. The 2010 edition also
includes specific guidance for SCC
mitigation by means of hydrostatic
pressure testing in the event SCC is
identified on a pipeline.
9. MidAmerican reported that it uses
ASME B31G to determine remaining
wall strength and that it remediates
conditions in accordance with
§ 192.933(d) and ASME/ANSI B31.8S.
Response to Question G.6 comments
PHMSA appreciates the information
provided by the commenters. Section
192.927 specifies requirements for gas
transmission pipeline operators who use
ICDA for IM assessments. The
requirements in § 192.927 were
promulgated before there were
consensus standards published that
addressed ICDA. Section 192.927
requires that operators follow ASME/
ANSI B31.8S provisions related to
ICDA. PHMSA has reviewed NACE
SP0206–2006 and finds that it is more
comprehensive and rigorous than either
§ 192.927 or ASME B31.8S in many
respects. In addition, Section 192.929
specifies requirements for gas
transmission pipeline operators who use
SCCDA for IM assessments. The
requirements in § 192.929 were
promulgated before there were
consensus industry standards published
that addressed SCCDA. Section 192.929
requires that operators follow Appendix
A3 of ASME/ANSI B31.8S. This
appendix provides some guidance for
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conducting SCCDA, but is limited to
SCC that occurs in high-pH
environments. Experience has shown
that pipelines also can experience SCC
degradation in areas where the
surrounding soil has a pH near neutral
(referred to as near-neutral SCC). NACE
Standard Practice SP0204–2008
addresses near-neutral SCC in addition
to high-pH SCC. In addition, the NACE
recommended practice provides
technical guidelines and process
requirements which are both more
comprehensive and rigorous for
conducting SCCDA than either
§ 192.929 or ASME/ANSI B31.8S.
Therefore, PHMSA is proposing to
incorporate these industry standards
into the regulations to provide better
guidance for conducting integrity
assessments with ICDA or SCCDA.
PHMSA will continue to evaluate the
need for additional guidance for
conducting integrity assessments.
G.7. Does NACE SP0204–2008
(formerly RP0204), ‘‘Stress Corrosion
Cracking Direct Assessment
Methodology’’ address the full life cycle
concerns associated with SCC?
1. INGAA suggested NACE SP0204,
by itself, does not address the full life
cycle concerns of SCC but in
combination with ASME/ANSI B31.8S
the full life cycle concerns are
addressed. A number of pipeline
operators supported INGAA’s
comments.
2. AGA, supported by a number of its
members, suggested PHMSA should
determine whether NACE SP0204
addresses full life cycle concerns.
3. GPTC, Texas Pipeline Association,
Texas Oil & Gas Association, and
Ameren Illinois commented it was not
clear what PHMSA meant by ‘‘full life
cycle concerns.’’
4. NACE International reported that
SP0204 does not address the full life
cycle concerns of SCC; however, NACE
noted that it has developed a 2011
‘‘Guide to Improving Pipeline Safety by
Corrosion Management’’ which will be
converted into a NACE standard.
5. MidAmerican reported its
conclusion that NACE SP0204 does
address full life cycle concerns.
6. Paiute and Southwest Gas reported
their conclusion that the existing
standards are adequate, but deferred to
NACE concerning the breadth of
coverage of NACE standards.
Response to Question G.7 Comments
PHMSA appreciates the information
provided by the commenters. PHMSA
believes that NACE SP0204–2008 is the
best available guidance and is proposing
to incorporate this industry standard
into the regulations for conducting
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integrity assessments with SCCDA. In
addition, other proposed requirements
for integrity assessments and
remediation in §§ 192.710, 192.713,
192.624, and subpart O provide greater
assurance that the full life cycle
concerns associated with SCC are
addressed.
G.8. Are there statistics available on
the extent to which the application of
NACE SP0204–2008, or other standards,
have affected the number of SCC
indications operators have detected and
remediated on their pipelines?
1. Industry commenters responding to
this question unanimously noted that no
statistics have been collected on the use
of NACE SP0204. INGAA noted, in
addition, that the SCC Joint Industry
Project (JIP) represents the experience of
operators of 160,000 miles of gas
transmission pipeline.
2. Paiute and Southwest Gas reported
that they have not identified any SCC on
their pipeline systems.
3. An anonymous commenter noted
that there has been one incident
attributed to factors not addressed in
current standards. The commenter
noted that the only common factors
among SCC colonies was high soil
resistivity and disbanded coating.
Response to Question G.8 Comments
PHMSA appreciates the information
provided by the commenters. As
described in the response to Question
G.6, PHMSA is proposing to incorporate
NACE SP0204–2008 into the
regulations. PHMSA will continue to
gather information in this area and will
evaluate the need for more specific
requirements or guidance to address the
threat of SCC.
G.9. Should a one-time pressure test
be required to address manufacturing
and construction defects?
1. INGAA and a number of its
pipeline operators argued that this
should be a case-by-case decision
guided by INGAA’s Fitness for Service
protocol. INGAA noted that new
pipelines require a part 192, subpart J,
pressure test while older pipelines may
have been strength tested.
2. AGA, supported by a number of its
pipeline operators, opined that a onetime pressure test is sufficient. AGA
noted that Congress accepted the
stability of pipelines that had undergone
a post construction pressure test.
3. GPTC argued that a one-time
pressure test is sufficient; however, such
a test should not be mandated for
pipelines not tested after construction
unless a significant risk has been
demonstrated. GPTC noted that
manufacturing and construction defects
are not time-related.
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4. American Public Gas Association
objected to any requirement for a onetime pressure test, noting that it is not
practical to conduct such a test on most
transmission pipelines operated by
municipal pipeline operators.
5. Atmos noted that the decision to
perform one-time pressure tests to
address manufacturing and construction
defects requires more information and
consideration than can be conveyed in
response to a single question. Atmos
reported that it could not determine if
the one-time pressure test requirement
would apply to all pipeline segments or
to pipelines with certain characteristics.
Some of Atmos’ pipelines could not be
removed from service for testing
without impacts on customers.
6. Ameren Illinois argued that no onetime pressure test should be required,
noting that a pressure test is already
required before a pipeline is placed in
service.
7. Northern Natural Gas argued that a
one-time pressure test should not be
required in all cases. Northern noted
that assessment of manufacturing and
construction defect threats should be
determined based on the risk level and
pipeline type for pipeline segments do
not have an existing pressure test.
8. MidAmerican opined that a onetime pressure test should be a
requirement for manufacturing and
construction defects, noting defects that
survive a pressure test are unlikely to
fail during the useful life of the
pipeline.
9. Oleksa and Associates noted that:
(1) A one-time pressure test is all that
is needed for manufacturing and
construction defects; (2) an in-service
pipeline should only be pressure tested
if there is clear reason to believe a
strength test would be beneficial; and
(3) many pipelines operate at such low
levels of stress that a strength test is not
necessary.
10. Paiute and Southwest Gas
commented that a pressure test should
be conducted in accordance with
subpart J when initially placing a
pipeline in service. The operators
reported that they support the Pipeline
Safety, Regulatory Certainty, and Job
Creation Act of 2011 which will require
systematic pressure testing (or other
alternative methods of equal or greater
effectiveness) of certain, previously
untested transmission pipelines located
in HCAs and operating at a pressure
greater than 30% SMYS. Texas Pipeline
Association and Texas Oil & Gas
Association agreed, noting that testing
of new pipelines is already required and
the Act requires use of pressure testing
or alternate means to verify MAOP.
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11. Thomas Lael and California Public
Utilities Commission argued that all
pipelines should be subjected to a
pressure test. CPUC noted that an
unspecified technical paper published
by Kiefner shows that a pressure test to
1.25 times MAOP will be sufficient to
demonstrate the stability of
manufacturing and construction defects
and girth welds.
12. The NTSB recommended that
PHMSA amend part 192 so that
manufacturing and construction defects
can only be considered stable if a gas
pipeline has been subjected to a postconstruction hydrostatic pressure test of
at least 1.25 times the MAOP.
13. Accufacts suggested that a
requirement for a one-time pressure test
is needed, noting the NTSB safety
recommendations issued following San
Bruno made it clear that there are
problems with the current IM
regulations, especially as they relate to
systems that were in operation before
the implementation of federal
regulations.
14. A private citizen suggested that a
one-time pressure test or reduction of
MAOP should be required for all lowfrequency electric resistance welded
(LFERW) pipe.
15. A private citizen suggested that a
one-time pressure test conducted in
combination with ILI should be required
as a baseline for subsequent ILI
inspections.
16. An anonymous commenter opined
that no one-time pressure test is needed
unless there is a history of seam failure
or SCC.
Response to Question G.9 Comments
PHMSA appreciates the information
provided by the commenters. The
majority of comments support
performance of a one-time pressure test
to address manufacturing and
construction defects. The ANPRM
requested comments regarding proposed
changes to part 192 regulations that
would repeal 49 CFR 192.619(c) and the
NTSB issued recommendations to
repeal 49 CFR 192.619(c) for all gas
transmission pipelines (P–11–14) and to
require a pressure test before concluding
that manufacturing- and constructionrelated defects can be considered stable
(P–11–15). In addition, Section 23 of the
Act requires issuance of regulations
regarding the use of tests to confirm the
material strength of previously untested
natural gas transmission lines.
An Integrity Verification Process (IVP)
workshop was held in 2013. At the
workshop, PHMSA, the National
Association of State Pipeline Safety
Representatives, and various other
stakeholders presented information and
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comments were sought on a proposed
IVP that will help address these issues.
Key aspects of the proposed IVP process
include criteria for establishing which
pipe segments would be subject to the
IVP, technical requirements for
verifying material properties where
adequate records are not available, and
technical requirements for reestablishing MAOP where adequate
records are not available or the existing
MAOP was established under
§ 192.619(c). Comments were received
from the American Gas Association, the
Interstate Natural Gas Association of
America, and other stakeholders and
addressed the draft IVP flow chart,
technical concerns for implementing the
proposed IVP, and other issues. The
detailed comments are available on
Docket No. PHMSA–2013–0119.
PHMSA considered and incorporated
the stakeholder input, as appropriate
into this NPRM, which proposes
requirements to address pipelines that
established MAOP under 49 CFR
192.619(c), manufacturing and
construction defect stability, verification
of MAOP (where records that establish
MAOP are not available or inadequate),
and verification and documentation of
pipeline material for certain onshore,
steel, gas transmission pipelines.
G.10. Have operators conducted
quality audits of direct assessments to
determine the effectiveness of direct
assessment in identifying pipeline
defects?
1. INGAA, AGA, GPTC, and
numerous pipeline operators noted that
direct assessment is a cyclical process
that continually incorporates analysis of
information made available from the
direct and indirect assessment tools
used. The direct assessment process
requires that more restrictive criteria be
applied on first use and as operators
become more experienced with the
methodology and gather more data on
the pipeline, more informed pipeline
integrity decisions are made. The
commenters stated that operators using
the direct assessment process must
continuously assess the effectiveness of
the methodology.
2. Paiute and Southwest gas
commented that operators confirm the
findings of the pre-assessment and
indirect assessment steps as part of the
four-step direct assessment process.
Validation digs are required to confirm
the effectiveness of the direct
assessment process.
3. Texas Pipeline Association and
Texas Oil & Gas Association noted that
direct examinations are made as part of
every direct assessment. In Texas,
operators have generally been required
by the Railroad Commission to
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20775
demonstrate comparisons of direct
assessment results to ILI results on a
portion of their pipeline where both
have been performed. The associations
contended that this process of validating
should be considered a quality audit.
4. Northern Natural Gas agreed that
verification of the effectiveness of direct
assessment is already a part of the
required post-assessment step of the
four-step direct assessment process.
Ameren Illinois agreed that this process
is effectively a quality audit.
5. Atmos reported that records are
kept of the indicated anomalies and the
actual anomalies discovered through
direct examination, thus assuring the
quality and validation of direct
assessments.
6. Accufacts opined that there appear
to be serious deficiencies in the
application of direct assessment on gas
pipelines.
7. An anonymous commenter noted
that direct assessment, if used correctly,
is informative and proactive, and best
suited to identify preventive and
mitigative actions and to establish
assessment intervals.
Response to Question G.10 Comments
PHMSA appreciates the information
provided by the commenters. The
majority of comments state that quality
audits are performed for direct
assessments, however, PHMSA believes,
as one comment suggests, that there are
weaknesses in the use of direct
assessments. For example, SCCDA is not
as effective, and does not provide an
equivalent understanding of pipe
conditions with respect to SCC defects,
as ILI or hydrostatic pressure testing.
Accordingly, PHMSA proposes to revise
the requirements in §§ 192.921 and
192.937 for direct assessment to allow
use of this method only if a line is not
capable of inspection by internal
inspection tools.
G.11. If commenters suggest
modification to the existing regulatory
requirements, PHMSA requests that
commenters be as specific as possible.
In addition, PHMSA requests
commenters to provide information and
supporting data related to:
• The potential costs of modifying the
existing regulatory requirements
pursuant to the commenter’s
suggestions.
• The potential quantifiable safety
and societal benefits of modifying the
existing regulatory requirements.
• The potential impacts on small
businesses of modifying the existing
regulatory requirements.
• The potential environmental
impacts of modifying the existing
regulatory requirements.
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No comments were received in
response to this question.
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H. Valve Spacing and the Need for
Remotely or Automatically Controlled
Valves
The ANPRM requested comments
regarding proposed changes to the
requirements for sectionalizing block
valves. Gas transmission pipelines are
required to incorporate sectionalizing
block valves. These valves can be used
to isolate a section of the pipeline for
maintenance or in response to an
incident. Valves are required to be
installed at closer intervals in areas
where the population density near the
pipeline is higher.
Sectionalizing block valves are not
required to be remotely-operable or to
operate automatically in the event of an
unexpected reduction in pressure (e.g.,
from a pipeline rupture). Congress has
previously required PHMSA to ‘‘assess
the effectiveness of remotely controlled
valves to shut off the flow of natural gas
in the event of a rupture’’ and to require
use of such valves if they were shown
technically and economically feasible.36
The NTSB has also issued a number of
recommendations concerning
requirements for use of automatic- or
remotely-operated mainline valves,
including one following a 1994 pipeline
rupture in Edison, NJ.37 The incident in
San Bruno, CA on September 9, 2010,
has raised public concern about the
ability of pipeline operators to isolate
sections of gas transmission pipelines in
the event of an accident promptly and
whether remotely or automatically
operated valves should be required to
assure this.
The ANPRM then listed questions for
consideration and comment. The
following are general comments
received related to the topic as well as
comments related to the specific
questions:
General Comments for Topic H
1. INGAA argued that while valves,
spacing, and selection are important,
public safety requires a broader review
of incident responses and consequences.
Performance-based Incident Mitigation
Management (IMM), using valves and
other tools, will, according to INGAA,
improve incident response, reduce
incident duration and minimize adverse
impacts. IMM plans identify
comprehensive actions that improve
36 Accountable Pipeline Safety and Partnership
Act of 1996, Public Law 104–304.
37 National Transportation Safety Board, ‘‘Texas
Eastern Transmission Corporation Natural Gas
Pipeline Explosion and Fire, Edison, New Jersey,
March 23, 1994,’’ PB95–916501, NTSB/PAR–95/01,
January 18, 1995.
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mitigation performance and minimize
overall incident impact. These plans
cover various aspects of response,
including how operators detect failures,
how they place and operate valves, how
they evacuate natural gas from pipeline
segments, and how they prioritize
coordination efforts with emergency
responders. A number of pipeline
operators supported INGAA’s
comments, including Panhandle,
TransCanada, Spectra Williams,
Southern Star, and others.
2. AGA submitted a white paper that
discussed potential benefits associated
with remote control valves and
automatic shutoff valves; however, the
paper acknowledged that these valves
will not prevent incidents. A number of
pipeline operators supported AGA’s
comments.
3. APGA reported automatic or
remotely-controlled valves are not
practical for municipal pipeline
operators because they do not have
remote monitoring or control of their
pipelines. APGA also cautioned that the
use of automatic valves could lead to
false closures, an unintended and
adverse consequence.
4. Atmos commented that the existing
requirements for valve spacing allow for
safe and reliable service to its
customers. The company noted that
requiring the installation of remote
control valves or automatic shutoff
valves would add minimal value to the
overall safety and operation of its
transmission pipeline systems. In
addition, industry studies have
concluded that remote or automatic
features on block valves would not
reduce injuries or fatalities associated
with an incident.
5. MidAmerican commented that
installation of automatic shutoff valves
would be costly, have minimal impact
on improving safety, and could cause
customer outages on its pipeline system.
At the same time, MidAmerican
acknowledged that some applications of
remote/automatic control valves could
have merit, but that the election should
lie with the operator given the
complexity of pipeline systems and
other factors that bear on that decision.
MidAmerican reported its conclusion
that ASME/ANSI B31.8S provides
adequate guidance for the installation of
sectionalizing valves. While
MidAmerican opposes a requirement to
install automatic or remotely-controlled
valves, the company suggested factors
PHMSA should consider if it decides to
adopt such a requirement. Specifically,
PHMSA should allow operators
flexibility in deciding between
automatic and remote valves and should
clarify when action on a pipeline is
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considered a new installation versus a
repair or replacement in-kind.
6. TransCanada noted that industry
studies have shown automatic or remote
block valves do not prevent incidents
and have a minimal effect on significant
consequences, since most of the human
impacts from a rupture occur in the first
few seconds, well before any valve
technology could reduce the flow of
natural gas. TransCanada supports the
use of Incident Mitigation Management
(IMM) to improve incident response,
reduce incident duration, and minimize
adverse impacts.
7. Chevron argued operators should
have the flexibility to select the most
effective measures based on specific
locations, risks, and conditions of the
pipeline segment. Chevron noted that
the Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011
requires a study of incident response in
HCAs that must consider the swiftness
of leak detection and pipeline shutdown capabilities and the location of
the nearest personnel. The study must
also evaluate the costs, risks, and
benefits of installing automatic or
remote controlled shut-off valves.
8. A private citizen suggested that
periodic drills be held with local
emergency responders, pipeline
operators should provide specialized
equipment to local responders in
densely populated areas, and pipeline
operators pay a fee to those
municipalities to support incident
response. The commenter further
recommended that leak detection
analyses be computerized.
9. Dominion East Ohio contended that
current regulations are adequate and
that automatic shutoff valves and
remote control valves are an important
preventive and mitigative measure to
consider using. However, these valves
do not prevent accidents and have very
limited impact in preventing injuries
and deaths caused by an initial pipeline
failure.
10. Accufacts suggested that further
prescriptive regulation is required
concerning the placement, selection,
and choice of manual, remotelycontrolled, or automatic shutoff valves.
11. The Pipeline Safety Trust (PST)
questioned the conclusions of the DOT
study, ‘‘Remotely Controlled Valves on
Interstate Natural Gas Pipelines,
(Feasibility Determination Mandated by
the Accountable Pipeline Safety and
Partnership Act of 1996), September
1999, which concluded that remote
control valves were and remain
economically unfeasible. The PST noted
that the study also stated that there
could be a potential benefit in
terminating the gas flow to a rupture
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expeditiously particularly in heavily
populated and commercial areas. PST
suggested PHMSA commission an
independent analysis to reach a
conclusion regarding whether to require
these valves.
12. A private citizen suggested that
local authorities regularly review
incidents in densely populated areas, as
self-policing by pipeline operators is
insufficient. The commenter also
recommended that pipeline
construction and modifications be
subject to signoff by a licensed
professional engineer and be certified
for compliance with applicable
regulations by a corporate officer subject
to criminal penalties, in order to reduce
the incentive to cut corners.
13. Northern Natural Gas and a
private citizen recommended that the
current one-call exemptions for
government agencies be eliminated.
Comments Submitted for Questions in
Topic H
H.1. Are the spacing requirements for
sectionalizing block valves in § 192.179
adequate? If not, why not and what
should be the maximum or minimum
separation distance? When class
locations change as a result of
population increases, should additional
block valves be required to meet the new
class location requirements? Should a
more stringent minimum spacing of
either remotely or automatically
controlled valves be required between
compressor stations? Under what
conditions should block valves be
remotely or automatically controlled?
Should there be a limit on the maximum
time required for an operator’s
maintenance crews to reach a block
valve site if it is not a remotely or
automatically controlled valve? What
projected costs and benefits would
result from a requirement for increased
placement of block valves?
1. AGA and a number of pipeline
operators contended that the existing
requirements in § 192.179 are adequate.
AGA noted that studies have shown
there is no safety benefit to having more
remote or automatic valves and
operators should be permitted to
determine the need for additional valves
and spacing. AGA contended that there
is no safety reason to change the
existing regulation and argued that
remote or automatic valves should not
be mandated for any specific set of
circumstances, since they are only one
option for pipeline shutdown.
2. Texas Pipeline Association and
Texas Oil & Gas Association commented
that spacing requirements for natural
gas transmission lines have been shown
to be adequate for emergency situations.
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Both associations observed that block
valves are not in place to prevent
accidents and that the greatest impact of
an accident is from the initial gas
release, before automatic or remote
valves could actuate. The associations
also noted that the addition of more
block valves would increase the risk to
aboveground infrastructure.
3. Accufacts contended that the
existing spacing requirements are
inadequate and noted that valve spacing
plays a significant role in the ‘‘isolation
blowdown’’ time, or the time to
depressurize a gas pipeline segment
once isolation valves are closed after a
rupture. Accufacts also recommended
that additional sectionalizing valves be
required when class locations change.
4. Iowa Utilities Board (IUB)
suggested that ease of access and the
time to respond should be factors
relevant to a decision as to whether to
install automatic or remote valves. IUB
noted that the considerations are
different for valves in remote areas
compared to urban valves.
5. California Public Utilities Board
reported that the issue of valve spacing
is under review by the State.
6. A private citizen suggested that
valves be required at one-mile intervals
in densely populated urban areas and
that they close automatically in the
event of an incident, since the duration
of the fire resulting from an incident is
directly proportional to the volume of
gas between valves. AGA commented
that it is not the amount of gas between
valves but rather it is the volume
between a valve and a rupture that
determines the volume released.
7. Wyoming County Pennsylvania’s
Commissioners suggested that it is
necessary to modify separation
distances and to establish adequate
distances for gathering lines, including
in Class 1 areas. The Commissioners
acknowledged that the spacing required
for Class 3 locations may be more
acceptable than the spacing required for
Class 1 areas, but noted that it will take
longer to reach a block valve with 10
mile spacing in Pennsylvania’s
Marcellus Shale regions.
8. An anonymous commenter
responded that current valve spacing
requirements are adequate and
suggested that automation be required if
it would take 20 to 30 minutes to
respond to a mainline valve.
9. AGA, supported by a number of
pipeline operators, noted that operators
evaluate the need for additional block
valves when they become aware of
changes in class location.
10. Atmos commented that the need
for additional block valves should be
evaluated when class locations change,
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if pipe replacement is needed to comply
with the new class locations. Atmos
recommended valve installations, if any,
should only be required within the
replaced pipeline section. Atmos further
recommended that automatic or remote
valves should not be required between
compressor stations due to the risk of
false closures and the extensive
modifications that would be required.
11. MidAmerican opposed a
requirement to install new block valves
when a class location changes or to
establish more stringent spacing
requirements, noting that ASME/ANSI
B31.8 provides adequate guidance for
block valve considerations. Texas
Pipeline Association, Texas Oil & Gas
Association, and Northern Natural Gas
agreed, noting that the required class
location study includes consideration of
current spacing as well as other criteria.
12. The Commissioners of Wyoming
County Pennsylvania stated that it is
imperative that a suitable number of
additional block valves be required
when population increases and class
location changes, arguing that this is
necessary to assure adequate public
safety measures are in place.
13. An anonymous commenter
suggested that new valves should not be
required when HCA or class location
boundaries change, noting that such
changes occur rather frequently.
14. Northern Natural Gas argued that
a prescriptive standard for valve spacing
may not necessarily provide additional
risk reduction, noting that many Class 2
and 3 locations are short pipe segments
within an extended Class 1 location.
15. Texas Pipeline Association and
Texas Oil & Gas Association noted that
more block valves would not decrease
the damage from a pipeline accident,
noting that PHMSA studies have shown
that fatalities and significant property
damage occur within 3 minutes of a
pipeline rupture while a remotelyoperated valve takes 10 minutes to
close. This and other studies have
shown the only benefit to adding more
valves is reducing the amount of gas lost
in an accident.
16. Accufacts contended that a more
scientific discussion will demonstrate a
maximum spacing of eight miles will
provide sufficient risk reduction.
17. MidAmerican suggested that block
valves should be automatic or remotelyoperated only when adequate response
times cannot be achieved by operator
personnel. When response times are
adequate, MidAmerican contended that
use of automatic or remote valves
should be at the operator’s discretion.
18. Northern Natural Gas suggested
that the decision to use remote or
automatic shut-off valves should be
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based on the operator’s risk assessment
and should be made, by the operator, on
a case-by-case basis.
19. Paiute and Southwest Gas argued
that operators should have the
flexibility to evaluate and determine
whether remote or automatic valves
would be beneficial. The companies
noted that § 192.935 already requires the
consideration of additional valves as a
preventive and mitigative measure.
20. Accufacts contended that
decisions on valve spacing and whether
they should be manual, remote, or
automatic will be dependent on the time
established for first responders to safely
enter an actual gas transmission impact
zone following rupture. Accufacts noted
that California has set a goal of 30
minutes for first response time.
21. A private citizen suggested that
automatic shutoff valves should be used
in densely populated areas because they
provide the most rapid response.
22. The Commissioners of Wyoming
County Pennsylvania suggested that
standardization is necessary with
remotely and automatically controlled
shutoffs. The Commissioners contended
that the operator needs to employ
remote or automatic valves when
transmission and gathering lines are
routed through areas that are not easily
accessible.
23. INGAA noted that § 192.620
requires a one-hour time frame for
closing a valve, and contended this is
practical for valves that would isolate
pipelines in HCAs and consistent with
requirements for alternative MAOP in
§ 192.620. A number of pipeline
operators supported INGAA’s
comments.
24. Atmos suggested that mandating a
minimum time to reach a valve site is
impractical, because many variables
exist in a dynamic state that affect an
operator’s ability to reach a block valve
site.
25. MidAmerican opposed a specified
time frame for response to a valve site,
noting that operators should respond in
an expedient manner without specified
time limits.
26. Northern Natural Gas suggested
PHMSA consider a two-hour response
time for valves in HCA.
27. Texas Pipeline Association and
Texas Oil & Gas Association noted that
conditions determine how quickly an
operator can reach a valve site in the
event of an incident and operators make
every effort to respond expeditiously
when an incident occurs. The
associations opposed adoption of a
required response time.
28. TransCanada reported its
conclusion that having personnel on site
within one hour is reasonable for
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planning purposes. If this cannot be
met, TransCanada suggested that
possible valve automation should be
required.
29. The Commissioners of Wyoming
County Pennsylvania reported their
conclusion that there would be value in
establishing a maximum response time,
especially in Class 1 locations where
block valves may be 10 miles apart.
30. INGAA and a number of its
pipeline operator members noted that
studies have shown consistently that
there is no value in installing additional
block valves or in automating valves.
They suggested that it would be more
beneficial to apply resources that would
be required to comply with any new
requirements in this area towards
preventing accidents.
31. MidAmerican reported that
installing additional block valves would
entail significant costs and suggested
that increasing the number of valves
could cost in excess of $40 million for
its pipeline system. Northern Natural
Gas agreed that costs could be
substantial, without providing a specific
estimate for its pipeline system.
32. Paiute and Southwest Gas
estimated that costs to install new
valves could range from $100,000 to $1
million per installation.
33. An anonymous commenter
estimated that retrofitting a 36-inch
valve for remote operation would cost
approximately $30,000 plus subsequent
maintenance costs.
34. Accufacts noted that the San
Bruno accident demonstrated that there
is a cost associated with not properly
spacing, installing or automating valves
in high consequence areas.
H.2. Should factors other than class
location be considered in specifying
required valve spacing?
1. INGAA, AGA, GPTC and several
pipeline operators took the position that
no new requirements are needed. These
associations argued that § 192.179
provides appropriate minimum
standards and reported that operators
install additional valves in accordance
with their integrity management plans
or other factors that they consider
voluntarily.
2. Paiute and Southwest Gas opined
that no additional criteria are needed.
They noted that numerous industry
studies have shown that there is little or
no safety benefit to installing additional
automatic or remote valves. They
suggested that operators should have the
flexibility to determine, based on local
circumstances, where additional valves
are needed.
3. Atmos suggested that valve
accessibility be given more
consideration, noting that installing
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valves in locations that provide
improved accessibility could lead to
spacing greater than allowed under
current regulations. Atmos further
suggested that environmental factors
such as water crossings and areas prone
to flooding should be taken into
consideration.
4. MidAmerican opined that
additional factors should be considered
and pointed to ASME/ANSI B31.8 for
examples.
5. Accufacts concluded that
additional factors need to be taken into
consideration, noting that protection of
identified sites in Class 1 and 2
locations will require shorter valve
spacing than is currently required by
regulations.
6. The California Public Utilities
Commission noted that there are
numerous factors to be considered that
affect response time, and that this issue
is under review by the State.
7. The Texas Pipeline Association,
Texas Oil & Gas Association, and
Commissioners of Wyoming County
Pennsylvania suggested that factors
other than class location should not be
added to the regulations. They noted
that class location serves as a surrogate
for the level of risk posed by a pipeline.
H.3. Should the regulations be revised
to require explicitly that new valves
must be installed in the event of a class
location change to meet the spacing
requirements of § 192.179? What would
be the costs and benefits associated with
such a change?
1. INGAA and a number of its
pipeline operator members opposed
applying § 192.179 requirements
retroactively to class location changes.
INGAA suggested that, rather than
absorbing the cost of installing new
valves, other preventive and mitigative
measures applied through an integrity
management plan would produce
greater benefits.
2. AGA and a number of its members
opposed requiring new valves be
installed when class location changes,
arguing that no safety benefit will result.
3. Northern Natural Gas expressed its
opinion that current regulations are
adequate, noting that class location
change studies require consideration of
block valve spacing.
4. MidAmerican opined that the
existing regulations are adequate and
noted that ASME/ANSI B31.8 provides
other factors for consideration.
5. GPTC expressed its belief that
existing requirements are adequate,
noting that operators voluntarily
consider other factors in establishing
valve locations.
6. Atmos suggested that PHMSA not
require the installation of new valves
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due to changes in class location, but
stated the agency should consider the
need for additional block valves if pipe
replacement is needed as a result of the
change.
7. Accufacts suggested that new
valves should be required following
class location changes, but suggested
that a reasonable time should be
provided for such valves to be installed
and operational.
8. The Texas Pipeline Association and
Texas Oil & Gas Association commented
that no safety benefit has been
demonstrated for the installation of
additional valves. The associations
suggested that installing additional
valves could be counterproductive,
since more above-ground valves could
pose an additional risk to the public.
9. The California Public Utilities
Commission opined that the regulations
should require explicitly that additional
valves be installed when class location
changes, but expressly withheld an
opinion on related costs.
10. A private citizen suggested that all
requirements related to class location
should apply when class location
changes, unless PHMSA adopts an
expanded definition for HCA to replace
class location considerations.
11. An anonymous commenter stated
that most operators anticipate changes
to Class 3 or 4 when pipelines are
designed and constructed. The
commenter estimated that installing a
new 36-inch valve would cost $70 to
$100 thousand, not including down
time and lost product.
12. The Commissioners of Wyoming
County Pennsylvania commented that
the regulations need to be revised to
explicitly require that new valves be
installed when class locations change.
The Commissioners suggested that this
needs to extend to both transmission
and gathering lines in Class 1 areas.
H.4. Should the regulations require
addition of valves to existing pipelines
under conditions other than a change in
class location?
1. INGAA and a number of pipeline
operators noted that studies have
indicated valve spacing has limited
impact on the duration of an incident.
INGAA suggested that a performancebased approach to incident mitigation
management would better inform valve
placement.
2. AGA opposed requiring additional
valves under any scenario. A number of
pipeline operators supported AGA’s
comments.
3. Accufacts suggested that new
valves should be installed when a site
becomes an HCA regardless of class
location, but a reasonable time should
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be allowed for such valves to be
installed and become operational.
4. Ameren Illinois opposed requiring
new valves under other conditions,
opining that existing requirements are
adequate.
5. GPTC and Atmos commented that
existing regulations are a sufficient
baseline for determining valve location,
noting that operators often use more
stringent spacing criteria during initial
construction.
6. MidAmerican opposed requiring
that installation of new valves on
existing pipelines for any reason other
than a class location change, noting that
ASME/ANSI B31.8 provides additional
factors for operators to consider in
determining valve location.
7. Northern Natural Gas noted that
existing regulations require that
operators consider additional valves as
a preventive and mitigative measure and
expressed its conclusion that this
requirement is sufficient.
8. Paiute and Southwest Gas
suggested that operators should have the
flexibility to evaluate and determine
where remotely-controlled or automatic
valves would be beneficial. The
companies noted that § 192.935 requires
the consideration of additional valves as
a preventive and mitigative measure and
industry studies indicate little or no
safety benefit to installing additional
valves.
9. The California Public Utilities
Commission suggested that conditions
that would impede access to a valve
may need to be considered in
determining valve placement.
H.5. What percentage of current
sectionalizing block valves are remotely
operable? What percentage operate
automatically in the event of a
significant pressure reduction?
1. INGAA estimated that 40 to 50
percent of mainline block valves are
remotely-operated or automatic. INGAA
did not provide an estimate specifically
for automatic valves. INGAA noted that
application of Incident Mitigation
Management would lead operators to
conclusions as to whether a valve
should be remote or automatic. A
number of pipeline operators supported
INGAA’s comments.
2. AGA and GPTC reported that they
have no data with which to respond to
this question.
3. Ameren Illinois reported that it has
no remotely-controlled valves.
4. Atmos reported that remote and
automatic valves are not installed
routinely. Remotely-controlled valves
are installed on a small number of select
pipelines, representing approximately
0.1 percent of all valves.
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5. Kern River reported that 66 percent
of its mainline block valves, and all
block valves in HCA, are remotelycontrolled.
6. MidAmerican reported that less
than one percent of its valves are
remotely-controlled and a similarly
small percentage of them are automatic.
7. Northern Natural Gas reported that
remotely-controlled valves are located
only at compressor stations on its
pipeline system.
8. Paiute reported that less than 10
percent of the valves on its system are
remotely-controlled. Paiute has no
automatic valves.
9. Southwest Gas reported that it has
no remotely-controlled or automatic
valves, due to the urban nature of its
pipeline system.
10. Texas Pipeline Association
reported that a limited survey of its
members indicated the number of
remotely-controlled valves varies from 1
to 18 percent; the number of automatic
valves varies from zero to 18 percent.
H.6. Should PHMSA consider a
requirement for all sectionalizing block
valves to be capable of being controlled
remotely?
1. INGAA and a number of pipeline
operators opposed consideration of such
a requirement. They commented that no
one solution should be mandated and
Incident Mitigation Management should
guide operators to decisions as to which
valves should be remote or automatic.
2. AGA and a number of pipeline
operators also opposed consideration of
such a requirement, noting remotelycontrolled valves are only one option for
shutting down a pipeline.
3. Accufacts opposed such a generic
requirement, noting small-diameter gas
transmission pipelines may not merit
automation because of the science of
pipeline diameter rupture associated
with high heat flux releases.
4. GPTC opined that remotelycontrolled valves do not improve safety,
thus there is no basis for requiring their
use. GPTC noted that operators
voluntarily consider many factors in
establishing valve locations.
5. Atmos opposed consideration of
this requirement, noting there are issues
with false closures and the costs of
conversion or installation are extensive.
Atmos also noted that industry studies
have shown no increase in safety from
having more remotely-controlled or
automatic valves.
6. Kern River opined that this should
be an operator decision, noting that
integrity management regulations
require the consideration of remote or
automatic valves as part of identifying
preventive and mitigative measures.
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7. MidAmerican strongly opposed
requiring all sectionalizing block valves
to be remotely controlled. MidAmerican
stated that the location and type of valve
should be based on an engineering
assessment. A requirement that all
valves be remote would increase costs
and may provide disincentives to
installation of additional valves.
8. Northern Natural Gas opposed such
a requirement, commenting this should
be a case-by-case decision based on risk
reduction.
9. Paiute and Southwest Gas reported
their conclusion that the existing
requirements in § 192.179 are adequate.
The companies recommended that
operators have the flexibility to evaluate
and determine where remote or
automatic valves would be beneficial.
They noted that § 192.935 requires the
consideration of additional valves as a
preventive and mitigative measure and
industry studies indicate little or no
safety benefit to installing additional
remote or automatic valves.
10. The Texas Pipeline Association
and Texas Oil & Gas Association
opposed consideration of a requirement
that all block valves be remotelyoperable. The associations noted that it
would be tremendously expensive to do
so, and it would require power and
communication sources that may not be
readily available at valve sites.
11. The California Public Utilities
Commission commented that this could
be impractical for distribution systems
considering space limitations and the
practicability of supplying
communication facilities for valves.
This issue is under review by the State
for transmission facilities.
12. The Iowa Utilities Board noted
that remotely-operated valves require a
SCADA or other type of remote
monitoring and operating system. A
requirement that all sectionalizing
valves be remotely-operable would thus
be a de facto requirement that all
operators, regardless of size or the
potential consequences of an accident,
install a SCADA system. Small
operators and municipal utilities in
Iowa do not have such systems.
13. The Commissioners of Wyoming
County Pennsylvania commented that it
might be desirable for all valves to be
remotely-operable or automatic, but
PHMSA must consider what is
reasonable and adequate.
14. An anonymous commenter
opposed consideration of a requirement
that all valves be remotely-operable,
noting that most gas pipeline accident
consequences occur immediately upon
release, before a remote valve could
have any effect.
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H.7. Should PHMSA strengthen
existing requirements by adding
prescriptive decision criteria for
operator evaluation of additional valves,
remote closure, and/or valve
automation? Should PHMSA set specific
guidelines for valve locations in or
around HCAs? If so, what should they
be?
1. INGAA and a number of pipeline
operators opposed PHMSA’s
establishment of prescriptive criteria,
suggesting instead that PHMSA develop
guidance for Incident Mitigation
Management.
2. AGA, GPTC, and a number of
pipeline operators commented that
requirements in § 192.179 are adequate.
AGA noted that operators already
consider additional valves in their
emergency response portfolio and
install them where economically,
technically, and operationally feasible.
Some operators noted that numerous
industry studies indicate that there is
little or no safety benefit to installing
additional remote or automatic valves
and § 192.935 already requires the
consideration of additional valves as a
preventive and mitigative measure.
3. Accufacts supported the
consideration of prescriptive criteria,
arguing that prescriptive regulation
should be mandated for certain gas
transmission pipelines in HCAs,
especially larger-diameter pipelines in
certain areas where manual closure
times can be long.
4. Ameren Illinois opposed additional
prescriptive criteria, arguing that
existing requirements are sufficient and
that additional valves should be
considered when economically,
technically, and operationally feasible
to address specific safety concerns.
5. California Public Utilities
Commission expressed its conclusion
that prescriptive decision criteria may
need to be added for all Method 1 HCA
locations.
6. The Iowa Utilities Board, the Texas
Pipeline Association and the Texas Oil
& Gas Association questioned whether it
is possible to write prescriptive decision
criteria that can reasonably address all
possible situations and circumstances or
always provide the best option. These
commenters suggested that operator
judgment and discretion should play a
part in these decisions.
7. MidAmerican expressed its belief
that pipeline safety would not be
enhanced by additional prescriptive
criteria and opposed specific
requirements for valve location near
HCAs, noting that ASME/ANSI B31.8
provides considerations for operators to
take into account when deciding on
valve locations.
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8. An anonymous commenter
suggested that prescriptive criteria
could be useful in assuring a degree of
consistency among pipeline operators.
H.8. If commenters suggest
modification to the existing regulatory
requirements, PHMSA requests that
commenters be as specific as possible.
In addition, PHMSA requests
commenters to provide information and
supporting data related to:
• The potential costs of modifying the
existing regulatory requirements
pursuant to the commenter’s
suggestions.
• The potential quantifiable safety
and societal benefits of modifying the
existing regulatory requirements.
• The potential impacts on small
businesses of modifying the existing
regulatory requirements.
• The potential environmental
impacts of modifying the existing
regulatory requirements.
No comments were received in
response to this question.
Response to Topic H Comments
PHMSA appreciates the information
provided by the commenters. Based on
the investigation of the San Bruno
incident, the NTSB recommended (P–
11–11) that PHMSA promulgate
regulations to explicitly require that
automatic shutoff valves or remote
control valves in high consequence
areas and in Class 3 and 4 locations be
installed and spaced at intervals
considering the population factors listed
in the regulations. In addition, Section
4 of the Act requires issuance of
regulations on the use of automatic or
remote-controlled shut-off valves, or
equivalent technology, if appropriate,
and where economically, technically,
and operationally feasible. The Act also
requires the Comptroller General of the
United States to complete a study on the
ability of transmission pipeline facility
operators to respond to a hazardous
liquid or gas release from a pipeline
segment located in a high-consequence
area. On March 27, 2012, PHMSA
sponsored a public workshop to seek
stakeholder input on this issue. On
October 5, 2012, PHMSA also briefed
stakeholders, via a webcast, on the
status of an ongoing study conducted by
Oak Ridge National Laboratory on
understanding the application of
automatic control and remote control
shutoff valves. The final study was
published in December 2012. PHMSA
also included this topic in the July 18,
2012 Pipeline Research Forum. PHMSA
will take further action on this topic
after completion of the assessment of
the findings from these activities.
PHMSA will consider the comments
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comments related to the specific
questions:
I. Corrosion Control
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received on the ANPRM and will
consider this topic in future rulemaking,
as required.
1. AGA opined that the questions
posed under this topic are unclear and
disjointed and do not differentiate
between distribution and transmission
pipelines. In addition, AGA stated that
PHMSA did not provide a rationale for
why there is any concern over subpart
I. A number of pipeline operators
supported AGA’s comments.
2. MidAmerican noted that PHMSA
says current requirements are adequate
yet goes on to propose new
requirements.
3. INGAA reported that its members
commit to mitigating corrosion
anomalies in accordance with ASME/
ANSI B31.8S, both inside and outside
HCAs. INGAA argued that enhanced
external corrosion management
methods, such as close interval surveys
and post-construction coating surveys,
should not be required singularly and
arbitrarily by new prescriptive
regulations, since these methods can be
redundant or inferior when combined
with other assessment techniques.
INGAA argued that these methods
should continue to be used by operators
on a threat-specific basis, as is currently
practiced under performance-based
regulations and consensus-based IM
programs. A number of pipeline
operators supported INGAA’s
comments.
4. Chevron argued that more
prescriptive requirements are
unnecessary, noting that current
regulations allow operators the
flexibility to select the most effective
corrosion control method for the
specific corrosion threats to a pipeline
segment.
5. MidAmerican reported that it has
never identified internal corrosion on its
pipeline system and prescriptive
requirements related to that threat
would divert resources. MidAmerican
opined that subpart I provides an
adequate level of safety and any changes
in that subpart should be approached
carefully because they could be
beneficial or detrimental for reducing
risk. MidAmerican further noted that
NACE SP0204 and ASME/ANSI B31.8S
provide adequate guidance in this area.
6. TransCanada suggested that
PHMSA incorporate the new SCC
management provision in ASME/ANSI
B31.8S as the basis for identifying and
mitigating SCC and be responsive to
further enhancements. TransCanada
also suggested that the best way to
manage corrosion anomalies is through
assessments.
Gas transmission pipelines are
generally constructed of steel pipe, and
corrosion is a potential threat. Subpart
I of part 192 addresses the requirements
for corrosion control of gas transmission
pipelines, including the requirements
related to external corrosion, internal
corrosion, and atmospheric corrosion.
However, this subpart does not include
requirements for the specific threat of
Stress Corrosion Cracking (SCC). The
ANPRM requested comments regarding
revisions to subpart I to improve the
specificity of existing requirements and
to add requirements relative to SCC.
Existing requirements have proven
effective in reducing the occurrence of
incidents caused by external corrosion.
Many of the provisions in subpart I,
however, are general in nature. In
addition, the current regulations do not
include provisions that address issues
that experience has shown are
important to protecting pipelines from
corrosion damage, including:
• Post-construction surveys for
coating damage.
• Post-construction close interval
survey (CIS) to assess the adequacy of
cathodic protection (CP) and inform the
location of CP test stations.
• Periodic interference current
surveys to detect and address electrical
currents that could reduce the
effectiveness of CP.
• Periodic use of cleaning pigs or
sampling of accumulated liquids to
assure that internal corrosion is not
occurring.
Corrosion control regulations
applicable to gas transmission pipelines
currently do not include requirements
relative to SCC. SCC is cracking induced
from the combined influence of tensile
stress and a corrosive medium. SCC has
caused numerous pipeline failures on
hazardous liquids pipelines, including a
2003 failure on a Kinder Morgan
pipeline in Arizona, a 2004 failure on an
Explorer Pipeline Company pipeline in
Oklahoma, a 2005 failure on an
Enterprise Products Operating line in
Missouri, and a 2008 failure on an
Oneok NGL Pipeline in Iowa. More
effective methods of preventing,
detecting, assessing and remediating
SCC in pipelines are important to
making further reductions in pipeline
failures.
The ANPRM then listed questions for
consideration and comment. The
following are general comments
received related to the topic as well as
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7. Dominion East Ohio opined that
existing regulations in this area are
adequate.
8. NAPSR urged PHMSA to establish
or adopt standards or procedures,
through a rulemaking proceeding, for
improving the methods of preventing,
detecting, assessing, and remediating
stress corrosion cracking. NAPSR also
suggested that PHMSA consider
additional requirements to perform
periodic coating surveys at compressor
discharges and other high-temperature
areas potentially susceptible to SCC and
develop a training module for pipeline
operators and federal and state
inspectors that would include the
identification of potential areas of SCC,
detecting, assessing and remediating
SCC.
9. A private citizen reported that his
analysis of data from over 5000
lightning strikes indicates that cathodic
protection systems make pipelines a
frequent target for lightning.
10. A private citizen suggested that
enforcement of cathodic protection
requirements be strengthened, stating
that the number of enforcement actions
indicates that operators are not
operating or maintaining CP as required.
11. A private citizen suggested that inline inspection (ILI) capable of detecting
seam issues should be required for pipe
susceptible to selective seam weld
corrosion, since pressure testing is not
adequate to detect non-leak anomalies.
If not possible, the commenter would
require that this pipe be replaced.
Response
PHMSA appreciates the information
provided by the commenters. In light of
the contributing factors to the San
Bruno incident, including PG&E’s
reliance on direct assessment under
circumstances for which direct
assessment was not effective, and the
incident in Marshall, Michigan, where
fracture features were consistent with
stress corrosion cracking, PHMSA
believes that more specific measures are
needed to address both stress corrosion
cracking and selective seam weld
corrosion. Based on lessons learned
from incident investigations, such as the
2012 incident in Sissonville, West
Virginia and the 2007 incident in Delhi,
Louisiana, and improved capabilities of
corrosion evaluation tools and methods,
PHMSA believes that more specific
minimum requirements are needed for
control of both internal and external
corrosion. In addition, cathodic
protection is a well-established
corrosion control tool, and PHMSA
believes the benefits of cathodic
protection outweigh any potential risks.
Therefore, PHMSA proposes several
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enhancements to subpart I for corrosion
control and subparts M and O for
assessment, including specific
requirements to address stress corrosion
cracking and selective seam weld
corrosion, and enhanced corrosion
control measures for HCAs, which are
discussed in more detail in response to
specific questions, below.
Comments Submitted for Questions in
Topic I
I.1. Should PHMSA revise subpart I to
provide additional specificity to
requirements that are now presented in
general terms? If so, which sections
should be revised? What standards exist
from which to draw more specific
requirements?
1. INGAA and a number of pipeline
operators commented that adding
prescriptive requirements would be
disruptive to operators, noting PHMSA
has acknowledged the effectiveness of
performance-based elements of the
current requirements.
2. The AGA, the GPTC, the Texas
Pipeline Association, the Texas Oil &
Gas Association, and numerous pipeline
operators questioned the need to amend
subpart I. AGA noted that this is one of
the more prescriptive sections of the
code and has a 40-year history of
demonstrated effectiveness.
3. Ameren Illinois opined it is not
necessary to revise subpart I, because
integrity management regulations
require operators to identify threats and
to manage them.
4. MidAmerican opposed more
specific requirements for corrosion
control, noting that there is wide
diversity among pipelines and it is
unlikely that a single set of specific
requirements would apply effectively to
all pipelines. MidAmerican suggested
that additional specific requirements
must be tailored to a wide range of
pipeline configurations to be of any
value.
5. Northern Natural Gas reported that
IM results demonstrate that corrosion
has been adequately addressed on its
pipeline system.
6. Paiute and Southwest Gas noted
that subpart I is one of the most
prescriptive sections of the code,
subpart O provides an additional layer
of regulation, and NACE standards are
robust and incorporated by reference.
7. Panhandle Energy commented that
existing performance based regulations
require the pipeline operator to
establish procedures to determine the
adequacy of CP monitoring locations
and appropriate remediation schedules
based on circumstances that are unique
to each pipeline. Panhandle observed
that PHMSA appears to be attempting to
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establish ‘‘One Size Fits All’’
prescriptive requirements and opined
that such changes would have no
positive effect on safety and may be
detrimental.
8. Accufacts observed that too many
pipeline operators are assuming that IM
assessments can replace subpart I
requirements when the intent was that
the regulations work in conjunction
with one another. Accufacts suggested
that prescriptive regulation is needed to
avoid serious misapplication of the IM
section and to assure that subpart I
regulations are implemented to keep
corrosion under control.
9. Panhandle observed that the
ANPRM states that ‘‘prompt’’ as used in
§ 192.465(d) is not defined, and does not
recognize the definition of ‘‘prompt
remedial action’’ outlined in the 1989
Office of Pipeline Safety’s Operation
and Enforcement Manual. Panhandle
noted that the enforcement guidance
requires PHMSA to evaluate the
circumstances and provide rationale for
any determination of ‘‘unreasonable
delay’’ in any enforcement action
associated with § 192.465(d). Panhandle
observed that such evaluations are
inherent in the enforcement of
performance-based regulations and
stand in sharp contrast to the ‘‘checkbox’’ enforcement mentality of
prescriptive regulations. Panhandle
complained that the language of the
ANPRM contradicts more than 20 years
of enforcement history. Panhandle
interpreted the ANPRM to mean that
PHMSA has no authority to interpret
part 192 other than through rulemaking.
10. An anonymous commenter
suggested that PHMSA delete the
requirement regarding 300 mV pipe-tosoil reading shift and adopt NACE
SP0169.
11. The California Public Utilities
Commission suggested that PHMSA
consider modifying acceptance criteria
to be based on instant-off readings,
arguing that this would provide
improved specificity concerning IR
drop.
Response to Question I.1 Comments
PHMSA appreciates the information
provided by the commenters. The
majority of industry comments do not
support revising subpart I to provide
additional specificity to requirements.
However, for the reasons discussed in
this NPRM, PHMSA believes that
certain regulations can be improved to
better address issues that experience has
shown can be important to protecting
pipelines from corrosion damage, and
that prudent operators currently
implement. Therefore, PHMSA proposes
to amend subparts G and I to: (1)
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Enhance requirements for electrical
surveys (i.e., close interval surveys); (2)
require post construction surveys for
coating damage; (3) require interference
current surveys; (4) add more explicit
requirements for internal corrosion
control; and (5) revise Appendix D to
better align with the criteria for cathodic
protection in NACE SP0169. Included in
these changes is a new definition of the
terms ‘‘electrical survey’’ and ‘‘close
interval survey.’’ To conform to the
revised definition of ‘‘electrical survey,’’
the use of that term in subpart O would
be replaced with ‘‘indirect assessment’’
to accommodate other techniques in
addition to close-interval surveys.
I.2. Should PHMSA prescribe
additional requirements for postconstruction surveys for coating damage
or to determine the adequacy of CP? If
so, what factors should be addressed
e.g., pipeline operating temperatures,
coating types, etc.)?
1. INGAA and a number of pipeline
operators argued that post-construction
surveys are of limited use, arguing that
they can identify damaged coating but
not necessarily areas where SCC can
occur.
2. AGA, supported by a number of its
pipeline operator members, opined that
existing requirements for postconstruction surveys for coating damage
and cathodic protection are sufficient
and operators need flexibility to apply
their resources to the highest risk areas.
3. GPTC agreed that existing
regulations are sufficient, noting that
operators are not experiencing
difficulties related to post-construction
surveys for coating damage or for
determining the adequacy of CP.
4. Ameren Illinois noted that part 192
requirements are followed for the
installation of new coated steel pipe and
it will develop a process to deal with
any problems that may be identified
through integrity management. Atmos
agreed, noting that post-construction
baseline surveys are typically
performed.
5. Kern River opined that corrosion
control measures and mitigation are site
specific and therefore universal
conditions and mitigation requirements
would likely be ineffective and
inefficient. Performance-based criteria
are the best way to ensure the integrity
of the pipeline with the most innovative
and effective solutions.
6. MidAmerican opposed new
requirements, noting that areas of
coating damage on pipelines are
protected from corrosion by cathodic
protection and existing requirements are
adequate in this area.
7. NACE concluded that current
regulations have proven adequate and
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noted that PHMSA acknowledges in the
ANPRM that ‘‘[T]hese requirements
have proven effective in minimizing the
occurrence of incidents caused by gas
transmission pipeline corrosion.’’
8. Paiute and Southwest Gas opined
that current requirements for coatings
(§ 192.461) and cathodic protection
(§ 192.463) are sufficient.
9. Northern Natural Gas stated that no
new requirements are needed, observing
that it takes action when CP surveys
indicate a concern.
10. Panhandle argued that the
proposed requirement for post
construction coating does not address
the cause of coating damage during
construction and INGAA best practices
have proven to be an effective means to
provide pipeline safety, affording
flexibility and recognizing the inherent
limitations of coating surveys.
Panhandle observed that PHMSA’s
requirements for the investigation of
anomalies found during post
construction coating surveys on
alternate MAOP lines are overly
conservative, waste resources, do not
enhance pipeline safety, and should not
be considered for use in any proposed
rulemaking. Panhandle further
recommended that any proposed
regulations related to pipeline
temperature should not use the 120
degrees Fahrenheit value used in
§ 192.620, since studies have
demonstrated pipeline coatings can
withstand temperatures up to 150
degrees. Panhandle further argued that
industry experience verifies that the
vast majority of coating holidays
associated with pipeline construction
are not an integrity threat when
cathodic protection is applied to the
pipeline. It also suggested that
verification of pipeline integrity through
ILI or pressure testing better utilizes
resources than excavation and repair of
pinholes in pipeline coating systems.
11. Panhandle observed that, from its
experience with over 900 completed
excavations, the coating anomaly
ranking system of NACE SP0502 is
extremely conservative and should only
be used as part of the ECDA process.
12. Texas Pipeline Association and
Texas Oil & Gas Association suggested
that PHMSA should consider requiring
close interval surveys at 5-year
intervals.
13. TransCanada noted that enhanced
external corrosion management
methods, such as close interval surveys
and post construction coating surveys,
have proven effective in helping
identify and mitigate certain corrosion
damage conditions. TransCanada
argued, however, that these methods
should not be required singularly and
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arbitrarily by new prescriptive
requirements, as they can be redundant
or inferior when combined with other
assessment techniques.
14. Pipeline Safety Trust suggested
that additional post-construction
surveying should be required to identify
damage to or weakness in coating and
to ensure the integrity of CP.
15. An anonymous commenter
suggested that PHMSA require close
interval survey before energizing new
CP components, after backfill has
settled, noting that this would ensure
test stations are located in areas that
will assure adequate protection.
16. The Commissioners of Wyoming
County Pennsylvania recommended that
PHMSA review operator practices and
codify the ‘‘best practices’’ in this area.
Response to Question I.2 Comments
PHMSA appreciates the information
provided by the commenters. The
majority of industry comments do not
support revising subpart I to prescribe
additional requirements for postconstruction surveys for coating damage
or to determine the adequacy of CP.
However, as detailed in the ANPRM,
experience has shown that construction
activities can damage coating and that
identifying and remediating this damage
can help protect pipeline integrity.
PHMSA does agree that prescriptive
practices for conducting coating
surveys, as well as the criteria for
remediation and other responses to
indications of coating damage, are not
always appropriate because coating
damage is case-specific. Therefore,
PHMSA proposes to add a requirement
that each coating be assessed to ensure
integrity of the coating using direct
current voltage gradient (DCVG) or
alternating current voltage gradient
(ACVG) and damage be remediated if
damage is discovered. In addition, for
HCA segments, PHMSA proposes
enhanced preventive and mitigative
measures and repair criteria for repair of
coating with a voltage drop classified as
moderate or severe.
I.3. Should PHMSA require periodic
interference current surveys? If so, to
which pipelines should this requirement
apply and what acceptance criteria
should be used?
1. INGAA and a number of pipeline
operators recommended that PHMSA
not establish new requirements in this
area without discussing the topic with
operators first. INGAA pointed out that
guidance already exists in the form of
Advisory Bulletin ADB–03–06 and
NACE SP0169.
2. Kern River opposed new
requirements for periodic surveys,
arguing that §§ 192.465, 192.467, and
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192.473 adequately address the
concerns.
3. Ameren Illinois also opposed new
requirements. Ameren reported that it
conducts testing annually at sites where
stray currents are expected and noted
that integrity management regulations
already require operators to identify and
address threats.
4. NACE International suggested that
current regulations are adequate and
have served the public interest. NACE
noted operators are currently taking
action to identify interference currents
and protect their pipelines, and it has
provided guidance through standards
and technical papers.
5. Atmos noted that interference
surveys would be a part of an
investigation into cathodic protection
systems that do not provide minimum
levels of protection. Operators are
already required to maintain minimum
levels of protection.
6. Northern Natural Gas reported that
it conducts additional surveys when
issues are discovered during periodic
maintenance, when new foreign line
crossing are installed, or for new
construction, but opposed new
requirements in this area.
7. Paiute and Southwest Gas opposed
new requirements, noting that operators
should have the flexibility to allocate
their resources in a manner that best
suits their system.
8. Panhandle opposed new
requirements, noting that existing
performance-based regulations have
proven adequate to address the threat of
stray currents. Panhandle commented
that the gas pipeline industry
recognized and reacted to the threat of
AC interference decades prior to the
ANPRM, and suggested that the lack of
justification from PHMSA on this issue
is a strong indicator that industry has
reacted appropriately to integrity threats
in accordance with the requirements of
§ 192.473. Panhandle noted that
interference currents have been
addressed in several industry standards
and publications. In particular, Section
9, Control of Interference Currents, of
NACE SP0169, Control of External
Corrosion on Underground of
Submerged Metallic Piping Systems,
provides guidance for the detection and
mitigation of interference currents.
9. Texas Pipeline Association and
Texas Oil & Gas Association stated that
current regulations are sufficient;
however, if new regulations are
promulgated, the associations
recommended that PHMSA use the
liquid pipeline requirement for periodic
interference surveys and be applicable
only to foreign line crossings and
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pipelines near large DC-powered
equipment.
10. An anonymous commenter stated
that new regulations are not needed, as
most operators will conduct surveys on
their own, generally when pipe-to-soil
readings drop.
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Response to Question I.3 Comments
PHMSA appreciates the information
provided by the commenters. Industry
comments do not support revising
subpart I to require periodic interference
current surveys. However, as detailed in
the ANPRM, pipelines are often routed
near, in parallel with, or in common
rights-of-way with, electrical
transmission lines or other pipelines
that can induce interference currents,
which, in turn, can induce corrosion.
Recent incidents on pipelines operated
by Kern River and Center Point are
examples of incidents this requirement
seeks to prevent. Section 192.473
currently requires that operators of
pipelines subject to stray currents have
a program to minimize detrimental
effects but does not require surveys,
mitigation, or provide any criteria for
determining the adequacy of such
programs. Therefore, PHMSA proposes
to add a requirement that the continuing
program to minimize the detrimental
effects of stray currents must include:
(1) Interference surveys to detect the
presence and level of any electrical
current that could impact external
corrosion where interference is
suspected; (2) analysis of the results of
the survey; and (3) prompt remediation
of problems after completing the survey
to protect the pipeline segment from
deleterious current. For HCA segments,
PHMSA proposes to address this in
enhanced preventive and mitigative
measures, and to include performance
criteria.
I.4. Should PHMSA require additional
measures to prevent internal corrosion
in gas transmission pipelines? If so,
what measures should be required?
1. INGAA, AGA, GPTC, and
numerous pipeline operators contended
that existing requirements are adequate
to manage internal corrosion. INGAA
noted that subparts I and O include
requirements for controlling internal
corrosion and assessments are being
performed on almost all gas
transmission lines. INGAA further
commented that controlling gas quality
is most important.
2. Ameren Illinois opposed new
requirements addressing internal
corrosion, noting that § 192.475
addresses the topic and subpart O
requires operators to respond to risks
that are identified.
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3. Kern River and Northern Natural
Gas opposed new requirements, noting
that industry data show IC is a minor
threat to natural gas transmission
pipelines. Kern River commented that
ASME/ANSI B31.8S, Appendix A2,
covers the analysis of gas constituents.
Northern monitors gas quality and takes
corrective action as needed.
4. MidAmerican opposed new
requirements, commenting that internal
corrosion is a regional problem and does
not occur in many areas of the country.
MidAmerican requested that current
integrity management regulations be
revised to eliminate the need to conduct
internal corrosion direct assessment
when internal corrosion is not a threat.
5. NACE International opined that
current regulations in subpart I are
adequate to address internal corrosion,
and PHMSA’s proposed prescriptive
requirements are not feasible.
6. Panhandle observed that
requirements to minimize the potential
for internal corrosion in gas
transmission pipelines are included in
§§ 192.475, 192.476, and 192.477. In
addition, OPS issued ADB–00–02
requiring pipeline operators to review
their internal corrosion monitoring
programs and operation. IM regulations
in subpart O require integrity
management assessments that address
the threat of internal corrosion. INGAA
members report that completion of
baseline assessments required by
subpart O will result in the assessment
of more than half of the gas transmission
pipeline mileage in the U.S. Panhandle
commented that several proposed
prescriptive internal corrosion
requirements provided in the ANPRM
are not feasible and noted that liquids
tend to accumulate in low spots that
typically are not accessible for
sampling. Panhandle opined that
vigilant enforcement of gas quality
standards is the most essential
component of an internal corrosion
control program.
7. Texas Pipeline Association and
Texas Oil & Gas Association argued that
no benefit would be gained by
additional requirements in this area.
The associations observed that internal
corrosion threats are highly localized
and monitoring and remediation efforts
must be customized for local conditions.
8. IUB noted that not all pipelines are
susceptible to internal corrosion and
commented that operators and state
inspection personnel should not be
unduly burdened by additional
measures when problems do not exist.
9. An anonymous commenter
suggested that PHMSA require each
operator to have a subject matter expert
well qualified in internal corrosion,
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arguing that most operators currently
rely on third-party contractors.
Response to Question I.4 Comments
PHMSA appreciates the information
provided by the commenters. The
majority of industry comments do not
support revising subpart I to require
additional measures to prevent internal
corrosion in gas transmission pipelines.
However, the current requirements for
internal corrosion control are nonspecific and PHMSA believes that there
is benefit in enhancing the current
internal corrosion control requirements
to establish a more effective minimum
standard for internal corrosion
management. Therefore, PHMSA
proposes to add a requirement that each
operator develop and implement a
program to monitor for and mitigate the
presence of, deleterious gas stream
constituents and that the program be
reviewed at least semi-annually. For
HCA segments, PHMSA proposes to
address this in enhanced preventive and
mitigative measures to include objective
performance criteria.
I.5. Should PHMSA prescribe
practices or standards that address
prevention, detection, assessment, and
remediation of SCC on gas transmission
pipeline systems? Should PHMSA
require additional surveys or shorter IM
survey internals based upon the
pipeline operating temperatures and
coating types?
1. INGAA and a number of pipeline
operators recommended that PHMSA
avoid prescriptive requirements for the
prevention, detection, assessment, and
remediation of SCC. The commenters
noted that SCC varies from pipeline to
pipeline and suggested that threat
management should be through a
framework of processes and decision
making that can tailor threat
management to the requirements of each
pipeline.
2. AGA and a number of its pipeline
operators also objected to new
requirements in this area, noting that
numerous industry documents exist that
provide guidance to address SCC.
3. Panhandle suggested that PHMSA
avoid prescriptive standards for the
prevention, detection, assessment, and
remediation of SCC on gas transmission
systems given the complex and variable
nature of the factors contributing to the
formation and growth of SCC, arguing
performance-based standards allow
operators the maximum flexibility to
develop and apply situational
techniques for detecting, assessing, and
remediating this threat. Panhandle
noted that multiple standards and
publications are available to address
internal corrosion and that the Pipeline
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Research Council International (PRCI)
has ongoing research in this area.
Panhandle expressed the view that
voluntary use of performance based
standards, allowing operator flexibility
in detecting, assessing and remediating
this threat, will ensure that the methods
used in managing these types of
anomalies continue to improve.
4. GPTC, Ameren Illinois, Atmos,
Paiute, and Southwest Gas argued that
existing regulations are sufficient and
noted that there are numerous industry
documents that provide additional
guidance for addressing SCC.
5. TransCanada suggested that
PHMSA adopt the current version of
ASME/ANSI B31.8S.
6. The Commissioners of Wyoming
County Pennsylvania opined that it is
reasonable for PHMSA to prescribe
practices or standards that address
prevention, detection, assessment and
remediation of SCC on transmission and
gas gathering lines, including those in
Class 1 locations. The Commissioners
argued that it is important to address
this aspect of corrosion given aging of
existing pipelines and the significant
number of new pipelines.
7. Air Products and Chemicals argued
that operators should not be required to
undertake SCC prevention, detection,
assessment and remediation activities
where a pipeline does not meet the
B31.8S criterion for SCC. Air Products
further commented that it is important
that PHMSA’s regulations and standards
reflect the threshold concept of
susceptibility to SCC, and that a
pipeline that does not meet the B31.8S
criteria for SCC risk should not be
required to undertake SCC prevention,
detection, assessment, and remediation
activities.
8. NACE International stated that
overly prescriptive rules can supplant
sound engineering judgment and
prevent innovation and the
development of new technologies.
9. Northern Natural Gas argued that
the current regulations and industry
standards provide adequate guidance
and that the assessment criteria address
operating temperature and coating type.
Northern Natural Gas noted that
operating temperature is addressed in
PHMSA Gas FAQ 223 and that the
reassessment interval should be
determined by the results of the
integrity assessment performed
pursuant to ASME B31.8S.
10. MidAmerican pointed out that
these concerns are addressed in the preassessment phase of direct assessment
and adequately covered in ASME/ANSI
B31.8S.
11. Texas Pipeline Association and
Texas Oil & Gas Association suggested
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that additional regulations related to
SCC could prove beneficial. At the same
time, the associations recommended
that PHMSA not require additional
surveys or shorter intervals, arguing that
the current regulations are based on
sound engineering practices.
12. A private citizen commented that
SCC should be addressed as part of a
comprehensive corrosion control
program.
13. An anonymous commenter noted
that a reliable survey technique for SCC
does not now exist and suggested that
PHMSA require shorter assessment
intervals for pipelines with a history of
SCC.
14. INGAA argued that pipe
temperature and coating are not
sufficient to identify SCC. INGAA
contended that ASME/ANSI B31.8S
adequately covers prevention, detection,
assessments, and remediation of SCC
and criteria to capture all pipe
potentially susceptible to SCC would be
overly conservative. A number of
pipeline operators supported INGAA’s
comments.
15. NACE International opined that
there are too many factors involved, and
they are too interrelated and locationspecific, to allow prescribing an optimal
assessment interval for SCC.
Response to Question I.5 Comments
PHMSA appreciates the information
provided by the commenters. The
majority of industry comments do not
support new requirements for the
prevention, detection, assessment, and
remediation of SCC. PHMSA recognizes
that SCC is an important safety concern,
but does not believe the current
methods for managing SCC anomalies
supports prescribing a detailed SCC
management approach that would be
effective for all operators. PHMSA does
not propose to amend subpart I to
prescribe an SCC management plan at
this time. PHMSA will continue to
study this issue and support ongoing
research. PHMSA plans to hold a public
forum on the development of SCC
standards in the future. Once that
process is complete, PHMSA will
consider new minimum safety standards
for managing the threat of SCC.
However, under topics C and G, above,
PHMSA does propose to include more
specific requirements for conducting
integrity assessments for the threat of
SCC and for enhancing the HCA and
non-HCA repair criteria to address SCC.
I.6. Does the NACE SP0204–2008
(formerly RP0204) Standard ‘‘Stress
Corrosion Cracking Direct Assessment
Methodology’’ address the full life cycle
concerns associated with SCC? Should
PHMSA consider this, or any other
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standards to govern the SCC assessment
and remediation procedures? Do these
standards vary significantly from
existing practices associated with SCC
assessments?
1. INGAA and a number of pipeline
operators stated that NACE SP0204 does
not address the full life cycle of
concerns of SCC. INGAA added that
SP0204, along with ASME/ANSI
B31.8S, NACE publication 35103, STP–
TP–011, and Canadian recommended
practices, do cover the full life cycle
concerns.
2. NACE International reported that
its standard (SP0204) does not address
the full life cycle concerns of SCC.
3. GPTC noted that existing
regulations and standards address SCC
concerns and commented that it is not
clear what is meant by ‘‘full life cycle
concerns.’’
4. Ameren Illinois argued that full life
cycle concerns are addressed in the preassessment phase of stress corrosion
cracking direct assessment (SCCDA) and
new prescriptive requirements are not
needed.
5. Northern Natural Gas commented
that ASME/ANSI B31.8S should be used
in conjunction with NACE SP0204.
6. Panhandle reported that SCCDA
was never intended to address full life
cycle management for SCC. The
standard does not address aspects such
as the formation or nucleation of cracks
or calculations to assess the severity of
cracks. Panhandle opined that the
collective body of SCC research does
address the full life cycle, but cautioned
the full body of knowledge of all
documents must be considered as some
may be dated and do not reflect current
knowledge on SCC management.
7. An anonymous commenter
suggested that NACE SP0204 does not
address full life cycle concerns, noting
that SCC has been found in
circumstances where the standard
would suggest it should not be
expected.
Response to Question I.6 Comments
PHMSA appreciates the information
provided by the commenters and agrees
that sufficient information is not
available at this time to specify
prescriptive standards for SCC
management. See the response to
comments received on question I.5.
I.7. Are there statistics available on
the extent to which the application of
the NACE Standard, or other standards,
have affected the number of SCC
indications operators have detected on
their pipelines and the number of SCCrelated pipeline failures? Are statistics
available that identify the number of
SCC occurrences that have been
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discovered at locations that meet the
screening criteria in the NACE standard
and at locations that do not meet the
screening criteria?
1. INGAA, GPTC, Texas Pipeline
Association, Texas Oil & Gas
Association, and numerous pipeline
operators reported that no data has been
collected on the application of any
current standard. INGAA added that
available statistics indicate that the
annual number of failures due to SCC is
generally decreasing and noted that a
high percentage of in-service failures,
failures during hydro testing, and
instances where SCC cracks greater than
10 percent were found during
excavations have met the screening
criteria of ASME/ANSI B31.8S (which
are identical to the NACE criteria).
2. Northern Natural Gas reported that
it has found one instance of SCC and no
segments were identified subject to
similar circumstances.
Response to Question I.7 Comments
PHMSA appreciates the information
provided by the commenters and agrees
that sufficient information is not
available at this time to specify
prescriptive standards for SCC
management. PHMSA will be studying
this issue and soliciting further input
from stakeholders in the future. See the
response to comments received on
question I.5.
I.8. If new standards were to be
developed for SCC, what key issues
should they address? Should they be
voluntary?
1. NACE International suggested that
existing standards should be updated
and improved rather than developing
new standards, noting that such
updating is as normal part of the
standards process.
2. INGAA and a number of its
pipeline operators supported the
development of voluntary standards to
cover detection, assessment, mitigation,
periodic assessment, and evaluation of
effectiveness.
3. Panhandle supported the
development of industry standards to
manage SCC but does not believe that
such a document can be completed until
the gaps in the understanding of SCC
have been addressed.
4. GPTC, Ameren Illinois, and
Northern Natural Gas opined that the
combination of ASME/ANSI B31.8S and
ASME STP–PT–011 provide adequate
guidance.
5. Atmos recommended that further
investigation be required if SCC outside
of the criterion specified in NACE
SP0204–2008 is found. Atmos stated
that any new standards that are
developed should be voluntary so that
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operators have additional
methodologies available for mitigating
the threat of SCC as currently required
by § 192.929.
6. Texas Pipeline Association and
Texas Oil & Gas Association
recommended any new standards for
SCC apply only to Class 1 locations,
based on their conclusion that pipe
designed for Class 2 conditions (and
above) is not susceptible to SCC.
Response to Question I.8 Comments
PHMSA appreciates the information
provided by the commenters and agrees
that sufficient information is not
available at this time to specify
prescriptive standards for SCC
management. PHMSA will be studying
this issue and soliciting further input
from stakeholders in the future. See the
response to comments received on
question I.5.
I.9. Does the definition of corrosive
gas need to clarify that other
constituents of a gas stream (e.g., water,
carbon dioxide, sulfur and hydrogen
sulfide) could make the gas stream
corrosive? If so, why does it need to be
clarified?
1. INGAA, supported by a number of
its pipeline operators, opined that the
existing regulations are adequate, and
commented that prescriptive limits,
such as those in § 192.620, would not be
as effective in reducing the potential for
internal corrosion.
2. GPTC recommended that § 192.476
be revised to reflect only those liquids
that act as an electrolyte (i.e., water).
3. AGA sees no need to clarify the
definition and noted that the stated
constituents pose no threat if water is
not present.
4. Atmos, Paiute, and Southwest Gas
noted that gas tariffs maintain gas
quality and water must be present with
the constituents listed to produce a
corrosive gas stream. Paiute opined that
§ 192.929 and ASME/ANSI B31.8S are
sufficient.
5. NACE International expressed
uncertainty as to why the definition
needs to be clarified. NACE also noted
that there are more factors than those
listed in the question that affect the
corrosiveness of a gas stream.
6. MidAmerican, Ameren Illinois, and
Northern Natural Gas noted that ASME/
ANSI B31.8S requires analysis of gas
constituents and argued that operators
know what constitutes a corrosive gas
stream. The operators do not believe the
definition needs to be changed.
7. Kern River suggested that the
definition should be changed, noting
that water must be present, in addition
to the listed constituents, to make a gas
stream corrosive.
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8. Texas Pipeline Association and
Texas Oil & Gas Association suggested
no change to the definition is needed,
since operators understand the listed
constituents, when combined with
water, can cause internal corrosion.
9. An anonymous commenter
suggested that PHMSA not attempt to
list constituents that could make a gas
stream corrosive, arguing there are too
many scenarios to cover. The
commenter noted that the issue is not
simple: H2O w/o free O2, or CO2 or
sulfur alone are not corrosive.
Response to Question I.9 Comments
PHMSA appreciates the information
provided by commenters, and consistent
with the majority of comments, PHMSA
does not propose to revise the definition
of corrosive gas at this time. However,
PHMSA does propose to clarify the
regulations by listing examples of
constituents that are potentially
corrosive, and to propose objective
performance criteria for monitoring gas
stream contaminants for HCA segments.
I.10. Should PHMSA prescribe for
HCAs and non-HCAs external corrosion
control survey timing intervals for close
interval surveys that are used to
determine the effectiveness of CP?
1. INGAA, supported by a number of
pipeline operators, suggested that safety
would be best served by following a
risk-based approach to determine
intervals for corrosion control or close
interval surveys, arguing that
prescriptive requirements applicable to
all pipelines would divert safety
resources from other high-risk tasks.
2. AGA, GPTC, and a number of
pipeline operators argued that there is
no reason for PHMSA to specify timing
of close interval surveys, contending
that the current subpart I requirements
have proven to be successful and the
use of CIS as an indirect assessment tool
is built into NACE SP0502.
3. Ameren Illinois opposed the
prescribed intervals for close interval
surveys, arguing that § 192.463 and
192.465 are adequate. In addition,
Ameren noted that § 192.917(e)(5)
requires an operator to evaluate and
remediate corrosion in both covered and
non-covered segments when corrosion
is found.
4. Atmos opposed required timing for
close interval surveys, arguing that CIS
is just one tool that can be used to
determine the effectiveness of CP.
5. MidAmerican expressed its
conclusion that establishing required
timing intervals for close interval
surveys would not be beneficial.
MidAmerican noted that specific
pipeline characteristics need to be taken
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into consideration in establishing
inspection intervals.
6. Paiute and Southwest Gas opposed
required periodicity for close interval
surveys, arguing that NACE SP0207
provides adequate guidance.
7. Northern Natural Gas commented
that PHMSA should not prescribe
external corrosion control survey
intervals for close interval surveys,
noting that its integrity management
program demonstrates that external
corrosion is being managed effectively.
8. Texas Pipeline Association and
Texas Oil & Gas Association argued that
industry experience demonstrates
existing requirements are adequate.
9. An anonymous commenter
suggested that specified periodicity for
close interval surveys could have
benefit, especially where a history of
external corrosion exists.
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Response to Question I.10 Comments
PHMSA appreciates the information
provided by the commenters. Recent
experience, including the December
2012 explosion near Sissonville, WV
and the 2007 incident near Delhi, LA,
underscores the need to be more
attentive to external corrosion
mitigation activities. PHMSA proposes
to enhance the requirements of subpart
I to require that operators conduct closeinterval surveys if annual test station
readings indicate that cathodic
protection is below the level of
protection required in subpart I, or to
restore adequate corrosion control. For
HCA segments, PHMSA proposes to
address these requirements in enhanced
preventive and mitigative measures, to
include an objective timeframe for
restoration of deficient cathodic
protection.
I.11. Should PHMSA prescribe for
HCAs and non-HCAs corrosion control
measures with clearly defined
conditions and appropriate mitigation
efforts? If so, why?
1. INGAA stated it does not believe it
is feasible to develop prescriptive
measures that identify necessary and
sufficient monitoring and mitigation
efforts in all environments. A number of
pipeline operators supported INGAA’s
comments.
2. AGA and a number of its operator
members expressed their conclusion
that the requirements of subpart I are
sufficient, noting that they address HCA
and non HCA alike.
3. GPTC commented that the question
does not make clear why additional
measures should be prescribed given
that operators have been successfully
mitigating corrosion deficiencies for
many years.
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4. Ameren Illinois expressed its
conclusion that the science of corrosion
mitigation is sufficiently advanced and
appropriate mitigation measures are
well known. Atmos, Paiute, and
Southwest Gas agreed, concluding that
subpart I is sufficient when
implemented properly by appropriately
trained and qualified personnel.
5. MidAmerican opposed new
requirements, arguing that current
regulations address all practical
mitigation efforts.
6. Texas Pipeline Association and
Texas Oil & Gas Association suggested
that more time should be allowed before
additional prescriptive requirements on
cathodic protection are considered,
noting that corrosion leaks are trending
downward.
7. The Commissioners of Wyoming
County Pennsylvania suggested that it is
reasonable that PHMSA prescribe
corrosion control measures for HCAs
and non-HCAs with clearly defined
conditions and appropriate mitigation
efforts. They cited information from
NACE indicating that 25 percent of all
accidents are caused by corrosion and
these accidents account for 36 percent
of all accident damage. The
Commissioners noted that gathering
lines in the Marcellus Shale area have
diameters and pressures similar to
transmission lines and should be
subjected to the same requirements.
8. An anonymous commenter
recommended that PHMSA not
prescribe specific measures.
Response to Question I.11 Comments
PHMSA appreciates the comments
provided, and consistent with the
majority of comments, does not propose
additional regulatory changes at this
time, other than to prescribe measures
to promptly restore cathodic protection,
as discussed in the response to
comments received for question I.10.
PHMSA is interested in the extent to
which operators have implemented
Canadian Energy Pipeline Association
(CEPA) SCC, Recommended Practices
2nd Edition, 2007, and what the results
have been.
I.12. Are there statistics available on
the extent to which gas transmission
pipeline operators apply the Canadian
Energy Pipeline Association (CEPA)
practices?
I.13. Are there statistics available that
compare the number of SCC indications
detected and SCC-related failures
between operators applying the CEPA
practices and those applying other SCC
standards or practices?
1. INGAA reported that most major
operators in North America have
adopted threat management closely
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20787
aligned to CEPA standards, but that no
specific data exist that correlate the use
of CEPA methods to anomaly detection.
INGAA reported a Joint Industry Project
(JIP) study that shows that applying
NACE SP0204, ASME/ANSI B31.8S,
CEPA, and other standards has led to a
significant reduction in in-service
failures. Numerous pipeline operators
supported INGAA comments.
2. AGA, supported by a number of its
pipeline operator members, questioned
why a discussion of CEPA standards
was included in the ANPRM. AGA
suggested that CEPA practices are well
suited to Canadian infrastructure, but
not necessarily applicable in the United
States and noted that CEPA is not often
discussed by Canadian members at AGA
meetings.
3. GPTC expressed that its
membership has little knowledge of
CEPA standards, commented that it is
not clear what is meant by full life cycle
concerns, and argued that existing
standards and regulations adequately
address SCC concerns. GPTC is not
aware of any data correlating the
efficacy of CEPA to other standards.
4. Paiute and Southwest Gas reported
that they have not implemented CEPA
standards.
Response to Questions I.12 and I.13
Comments
PHMSA appreciates the information
provided by the commenters. PHMSA
acknowledges the comments provided
on the use of the CEPA SCC
Recommended Practice and will
consider that standard in its study of
comprehensive safety requirements for
SCC.
I.14. Do the CEPA practices address
the full life cycle concerns associated
with SCC? If not, which are not
addressed?
1. INGAA reported its conclusion that
CEPA standards address full life cycle
concerns for near-neutral SCC. Many
management techniques in CEPA
standards are also applicable to high-pH
SCC, but the two are not identical.
Several pipeline operators supported
INGAA’s comments.
2. Texas Pipeline Association and
Texas Oil & Gas Association expressed
their conclusion that CEPA standards
address the full life cycle concerns of
SCC.
Response to Question I.14 Comments
PHMSA appreciates the information
provided by the commenters. PHMSA
acknowledges the comments provided
on the use of the CEPA SCC
Recommended Practice and will
consider that standard in its study of
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comprehensive safety requirements for
SCC.
I.15. Are there additional industry
practices that address SCC?
1. INGAA, supported by a number of
its pipeline operator members, reported
that there are no related European
standards and Australia has a standard
similar to ASME/ANSI B31.8S. INGAA
noted that SCC failures of pipelines
installed since 1980 are rare and
observed that quality coating and
cathodic protection are the most
effective means of preventing SCC.
2. GPTC stated that NACE SP0204 and
35103, ASME/ANSI B31.8S, and GPTC
guide material address SCC. Paiute and
Southwest Gas agreed that NACE
standards and GPTC provide relevant
guidance.
3. AGA commented that it does not
have the statistics available to advise
whether or not additional requirements
are needed to address SCC threats.
4. Atmos, Texas Pipeline Association
and Texas Oil & Gas Association
reported that they have no knowledge of
other SCC standards or practices.
5. Northern Natural Gas cited ASME/
ANSI B31.8S and ASME STP–PT–011.
Response to Question I.15 Comments
PHMSA appreciates the information
provided by the commenters. PHMSA
acknowledges the comments provided
on the standards, and will consider
these standards in its study of
comprehensive safety requirements for
SCC.
I.16. Are there statistics available on
the extent to which various tools and
methods can accurately and reliably
detect and determine the severity of
SCC?
1. INGAA noted that the measurement
of ILI crack detection tool performance
is an ongoing research activity, both
within JIP Phase II and within the
Pipeline Research Council International,
which is actively supported by the tool
vendors and the pipeline operators.
Several issues regarding the acquisition
and interpretation of information need
to be standardized by the practitioners
before a clear picture can emerge. The
implications of tool tolerance on
predicted failure pressure are being
studied in the JIP Phase II.
2. GPTC, Atmos, Paiute, Southwest
Gas, and an anonymous commenter
reported that they are unaware of any
relevant statistics.
3. Northern Natural Gas reported that
it has used electro-magnetic acoustic
transducer (EMAT) ILI with some
success.
4. Panhandle commented that
magnetic particle inspection (MPI) is
effective at locating surface-breaking
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linear indications, a subset of SCC.
Furthermore, abrasive wheel grinding in
conjunction with MPI is an effective
method to size the length and depth of
surface-breaking linear indications,
limited by the amount of metal that can
be removed from in-service pipelines.
Panhandle noted that PRCI research
indicates that laser UT techniques can
effectively locate and size SCC, but this
method is relatively new and Panhandle
has no experience with its use.
Panhandle also reported that the use of
EMAT has yet to be acknowledged as a
replacement for hydrostatic testing but
it is being evaluated in Phase II of the
SCC Joint Industry Project (JIP); results
of the study will be used to determine
the path forward for EMAT technology.
5. Texas Pipeline Association and
Texas Oil & Gas Association reported
that they have no knowledge of relevant
references other than the Baker study.
Response to Question I.16 Comments
PHMSA appreciates the information
provided by the commenters and will
consider this information in its study of
comprehensive safety requirements for
SCC.
I.17. Are tools or methods available to
detect accurately and reliably the
severity of SCC when it is associated
with longitudinal pipe seams?
1. INGAA and a number of pipeline
operators noted that detecting SCC close
to a longitudinal seam is difficult and
even harder near a girth weld. INGAA
commented that developing tools to
reliably detect and assess SCC near
longitudinal seams is a continuing
challenge.
2. GPTC reported that SCC tools are
available; however, GPTC cautioned
that the ability to accurately and reliably
detect the severity of SCC associated
with longitudinal seams is dependent
on specific operating conditions.
3. Atmos commented that it knows of
no tools that can accurately detect and
estimate the severity of SCC near a
longitudinal seam.
4. Paiute and Southwest Gas reported
that tools are being developed but are,
as of yet, not accurate at determining the
severity of SCC associated with
longitudinal seams.
5. Northern Natural Gas reported that
it has used electro-magnetic acoustic
transducer (EMAT) ILI with some
success. Panhandle added that
difficulties in using EMAT are further
complicated when cracking is
associated with a longitudinal seam.
6. Texas Pipeline Association and
Texas Oil & Gas Association expressed
their conclusion that the best methods
to assess for SCC near longitudinal
seams are pressure testing and EMAT,
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although they noted that some operators
have had success with transverse flux
ILI.
7. An anonymous commenter
reported that new ILI tools exist but that
analysts are not yet consistent in using
them.
Response to Question I.17 Comments
PHMSA appreciates the information
provided by the commenters and will
consider this information in its study of
comprehensive safety requirements for
SCC.
I.18. Should PHMSA require that
operators perform a critical analysis of
all factors that influence SCC to
determine if SCC is a credible threat for
each pipeline segment? If so, why? What
experience based indications have
proven reliable in determining whether
SCC could be present?
1. INGAA, supported by a number of
pipeline operators, noted that operators
are already required to perform an
analysis to determine the likelihood of
SCC. INGAA added that operators
address the pipelines with the highest
likelihood of SCC and apply lessons
learned, as appropriate, to lowerlikelihood pipelines.
2. Texas Pipeline Association and
Texas Oil & Gas Association indicated
that a requirement to perform a critical
analysis for SCC is unnecessary, since
guidance in ASME/ANSI B31.8S is
sufficient. Northern Natural Gas also
stated that additional requirements are
unnecessary, noting that it conducted an
analysis of critical factors affecting SCC
and identified no new factors over those
in B31.8S, Appendix 3.
3. Atmos stated that PHMSA’s
question was unclear whether to expand
the threat of SCC to all pipeline
segments or expand the requirements
for investigating the presence of SCC
within HCA segments? Atmos
concluded that subpart O requirements
provide a framework for operators to
integrate data, rank risk, identify threats,
and apply appropriate mitigative
actions; additional requirements are not
needed.
4. Texas Pipeline Association and
Texas Oil & Gas Association suggested
that PHMSA conduct a workshop to
share industry experience with SCC.
Response to Question I.18 Comments
PHMSA appreciates the information
provided by the commenters and will
consider this information in its study of
comprehensive safety requirements for
SCC.
I.19. Should PHMSA require an
integrity assessment using methods
capable of detecting SCC whenever a
credible threat of SCC is identified?
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1. INGAA, Panhandle, Atmos, and
Northern Natural Gas noted that subpart
O already requires that all credible
threats be identified and assessed. A
number of pipeline operators supported
INGAA’s comments.
2. Texas Pipeline Association and
Texas Oil & Gas Association also
indicated that they read subpart O as
requiring assessment using a method
that can detect SCC if that threat is
credible. The associations both added,
however, that they would not object to
making this requirement more explicit.
3. GPTC opined that existing
regulations and standards are adequate
to address SCC issues.
4. Southwest Gas opposed a new
requirement, noting that § 192.929 and
ASME/ANSI B31.8S are sufficient.
Response to Question I.19 Comments
PHMSA appreciates the information
provided by the commenters and will
consider this information in its study of
comprehensive safety requirements for
SCC. As indicated above in the response
to comments received on question I.5,
PHMSA proposes more explicit
requirements for selection of
appropriate methods for integrity
assessments for SCC.
I.20. Should PHMSA require a
periodic analysis of the effectiveness of
operator corrosion management
programs, which integrates information
about CP, coating anomalies, in-line
inspection data, corrosion coupon data,
corrosion inhibitor usage, analysis of
corrosion products, environmental and
soil data, and any other pertinent
information related to corrosion
management? Should PHMSA require
that operators periodically submit
corrosion management performance
metric data?
1. INGAA, Kern River, Paiute, and
Southwest Gas commented that these
issues are already addressed in subpart
O, which requires operators to keep
records, measure program effectiveness,
continually evaluate and assess systems,
integrate data, and show continual
improvement. INGAA added that
metrics bearing on the effectiveness of a
corrosion control program are already
among those required to be collected by
ASME/ANSI B31.8S. These metrics are
not required to be submitted, but are
available for review during inspections.
A number of pipeline operators
supported INGAA’s comments.
2. MidAmerican commented that
subparts I and O include these
requirements. Northern Natural Gas
agreed that it manages these threats
through O&M and IM activities.
3. Panhandle noted that subpart I
requires operators to maintain effective
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corrosion control programs to mitigate
the threat of corrosion and § 192.945
requires operators to measure, on a
semi-annual basis, whether the integrity
management program is effective in
assessing and evaluating the integrity of
each covered pipeline segment and in
protecting HCAs.
4. GPTC and AGA, supported by a
number of its pipeline operator
members, opposed requiring operators
to submit corrosion management
metrics. AGA noted that operators need
flexibility to select the appropriate
analysis methods and key performance
indicators. Furthermore, operators
review corrosion control program
effectiveness, and plans of intrastate
operators are reviewed by state
commissions.
5. Ameren Illinois opposed new
requirements, noting that subpart O
already requires operators to identify
and respond to risks.
6. Atmos questioned whether PHMSA
is proposing to measure the
effectiveness of corrosion management
programs across all pipeline segments or
to measure the effectiveness of corrosion
management programs in HCA
segments. Atmos added that the data
points enumerated by PHMSA in this
question would be difficult to gather on
an operator’s entire pipeline system.
7. Texas Pipeline Association and
Texas Oil & Gas Association stated that
they do not see a need for a requirement
to periodically analyze the effectiveness
of an operator’s corrosion management
program, arguing that existing
requirements are sufficient.
8. Panhandle argued that the
standardization of corrosion control
efforts, as would be required for
performance metric tracking, would
require additional prescriptive
requirements in subpart O. Panhandle
does not believe that elimination of
performance-based language is
beneficial.
9. The Commissioners of Wyoming
County Pennsylvania suggested that any
communication between operators and
PHMSA regarding corrosion
management would be helpful in
facilitating operator compliance and
best practices.
10. Paiute and Southwest Gas
reported that they opposed a
requirement to report additional
performance metrics absent a definition
of how new data would be collected and
used.
the San Bruno pipeline incident,
including a specific recommendation
(P–11–19) that PHMSA establish
standards for evaluating effective
program performance. PHMSA will
evaluate standards for integration of
pipeline corrosion data to enhance
corrosion management performance as
part of its response to that
recommendation.
I.21. Are any further actions needed
to address corrosion issues?
1. INGAA, supported by a number of
its pipeline operator members,
commented that continued study and
evaluation of the root causes of the San
Bruno explosion, documentation of
findings, and communication of results
are needed rather than additional
prescriptive requirements.
2. AGA, GPTC, and a number of
pipeline operators argued that no
further action is needed, given that
current methodologies adequately
address corrosion issues and operators
are subject to periodic audits by federal
and state safety regulators.
3. Accufacts suggested that PHMSA
needs to assure that IM programs are not
solely relied upon to prevent corrosion
failure.
4. Texas Pipeline Association and
Texas Oil & Gas Association reported
that they do not see any deficiencies
necessitating new regulations.
Response to Question I.20 Comments
PHMSA appreciates the information
provided by the commenters. Following
publication of the ANPRM, the NTSB
issued recommendations in response to
J. Pipe Manufactured Using
Longitudinal Weld Seams
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Response to Question I.21 Comments
PHMSA appreciates the information
provided by the commenters. As
discussed above, PHMSA is proposing
some enhanced measures for corrosion
control in subpart I and subpart O.
I.22. If commenters suggest
modification to the existing regulatory
requirements, PHMSA requests that
commenters be as specific as possible.
In addition, PHMSA requests
commenters to provide information and
supporting data related to:
• The potential costs of modifying the
existing regulatory requirements
pursuant to commenter’s suggestions.
• The potential quantifiable safety
and societal benefits of modifying the
existing regulatory requirements.
• The potential impacts on small
businesses of modifying the existing
regulatory requirements.
• The potential environmental
impacts of modifying the existing
regulatory requirements.
No comments were received in
response to this question.
The ANPRM requested comments
regarding additional integrity
management and pressure testing
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requirements for pipe manufactured
using longitudinal seam welding
techniques that have not had a subpart
J pressure test. Pipelines built since the
regulations (49 CFR part 192) were
implemented in early 1971 must be:
• Pressure tested after construction
and prior to being placed into gas
service in accordance with subpart J;
and
• Manufactured in accordance with a
referenced standard (most gas
transmission pipe has been
manufactured in accordance with
American Petroleum Institute Standard
5L, 5LX or 5LS, ‘‘Specification for Line
Pipe’’ (API 5L) referenced in 49 CFR
part 192).
Many gas transmission pipelines built
from the 1940’s through 1970 were
manufactured in accordance with API
5L, but may not have been pressure
tested similar to a subpart J pressure
test. For pipelines built prior to 1971,
§ 192.619(a) allows MAOP to be based
on the highest 5-year operating pressure
established prior to July 1, 1970, in lieu
of a pressure test. Accordingly, some of
this pre-existing pipe possesses variable
characteristics throughout the
longitudinal weld or pipe body.
As a result of 12 hazardous liquid
pipeline failures that occurred during
1986 and 1987 involving pre-1970 ERW
pipe, PHMSA issued an alert notice
(ALN–88–01, January 28, 1988) to
advise operators with pre-1970 ERW
pipe of the 12 pipeline failures and the
actions to take. Subsequent to this
notice, one additional failure on a gas
transmission pipeline, and eight
additional failures on hazardous liquid
pipelines occurred, which resulted in
PHMSA issuing another alert notice
(ALN–89–01, March 8, 1989) to advise
operators of additional findings since
the previous alert notice. These notices
identified the fact that some failures
appeared to be due to selective seam
weld corrosion, but that other failures
appeared to have resulted from flat
growth of manufacturing defects in the
ERW seam. In these notices, PHMSA
specifically advised all gas transmission
and hazardous liquid pipeline operators
with pre-1970 ERW pipe to consider
hydrostatic testing of affected pipelines,
to avoid increasing a pipeline’s longstanding operating pressure, to assure
effectiveness of the CP system, and to
conduct metallurgical exams in the
event of an ERW seam failure.
Since 2002, there have been at least
22 reportable incidents on gas
transmission pipeline caused by
manufacturing or seam defects. In
addition, recent high consequence
incidents, including the 2009 failure in
Palm City, Florida and the 2010 failure
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in San Bruno, California, have been
caused by longitudinal seam failures.
The ANPRM listed questions for
consideration and comment. The
following are general comments
received related to the topic as well as
comments related to the specific
questions:
General Comment for Topic J
1. Texas Pipeline Association and
Texas Oil & Gas Association suggested
that seam issues are best addressed
through inspection, detection,
remediation, and monitoring, based on
specific segments, not a one-size-fits-all
requirement.
Response to General Comment for
Topic J
PHMSA appreciates the comment and
agrees that a one-size-fits-all
requirement is not the best approach.
Accordingly, PHMSA proposes
requirements for verification of MAOP
in new § 192.624 for onshore, steel, gas
transmission pipelines, that are located
in an HCA or MCA and meet any of the
conditions in § 192.624(a)(1) through
(a)(3). Verification of MAOP includes
establishing and documenting MAOP if
the pipeline segment: (1) Has
experienced a reportable in-service
incident, as defined in § 191.3, since its
most recent successful subpart J
pressure test, due to an original
manufacturing-related defect, a
construction-, installation-, or
fabrication-related defect, or a crackingrelated defect, including, but not limited
to, seam cracking, girth weld cracking,
selective seam weld corrosion, hard
spot, or stress corrosion cracking and
the pipeline segment is located in one
of the following locations: (i) A high
consequence area as defined in
§ 192.903; (ii) a class 3 or class 4
location; or (iii) a moderate consequence
area as defined in § 192.3 if the pipe
segment can accommodate inspection
by means of instrumented inline
inspection tools (i.e., ‘‘smart pigs’’); (2)
Pressure test records necessary to
establish maximum allowable operating
pressure per subpart J for the pipeline
segment, including, but not limited to,
records required by § 192.517(a), are not
reliable, traceable, verifiable, and
complete and the pipeline segment is
located in one of the following
locations: (i) A high consequence area as
defined in § 192.903; or (ii) a class 3 or
class 4 location; or (3) the pipeline
segment maximum allowable operating
pressure was established in accordance
with § 192.619(c) of this subpart before
[effective date of rule] and is located in
one of the following areas: (i) A high
consequence area as defined in
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§ 192.903; (ii) a class 3 or class 4
location; or (iii) a moderate consequence
area as defined in § 192.3 if the pipe
segment can accommodate inspection
by means of instrumented inline
inspection tools (i.e., ‘‘smart pigs’’).
In addition, the proposed rule would
allow operators to select from among
several approaches to verify MAOP
based on segment specific issues and
limitations, such as pressure testing,
pressure reduction based on historical
operating pressure, and engineering
critical assessment.
Comments submitted for questions in
Topic J.
J.1. Should all pipelines that have not
been pressure tested at or above 1.1
times MAOP or class location test
criteria (§§ 192.505, 192.619 and
192.620), be required to be pressure
tested in accordance with the present
regulations? If not, should certain types
of pipe with a pipeline operating history
that has shown to be susceptible to
systemic integrity issues be required to
be pressure tested in accordance with
the present regulations (e.g., lowfrequency electric resistance welded
(LF–ERW), direct current electric
resistance welded (DC–ERW), lapwelded, electric flash welded (EFW),
furnace butt welded, submerged arc
welded, or other longitudinal seams)? If
so, why?
1. AGA, GPTC, and numerous
pipeline operators opposed a
requirement to pressure test all lines not
previously tested. These commenters
supported the more-limited testing
mandated by the Pipeline Safety,
Regulatory Certainty, and Job Creation
Act of 2011. AGA noted that Congress
considered and rejected proposals for
more extensive testing.
2. AGA, GPTC, Iowa Utilities Board,
Iowa Association of Municipal Utilities,
Texas Pipeline Association, Texas Oil &
Gas Association, and several
distribution pipeline operators objected
to requiring pressure testing of
distribution pipelines. The commenters
argued that the impact of resulting
service disruptions was overlooked.
Pressure testing would necessitate
disruptions of three to seven days for
many distribution pipelines, sometimes
involving service to an entire town. In
some cases, establishing an alternate
supply is not always possible. In
addition, some in-service lines are not
configured in a manner that would
support testing. For these reasons, the
commenters argued that the high costs
to perform pressure tests were
inappropriate absent some
demonstration of actual risk.
MidAmerican added a suggestion that
such a requirement of this type be
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limited to pipelines operating above 30
percent of specified minimum yield
strength (SMYS). Northern Natural Gas
agreed with MidAmerican’s suggestion
and would further limit any testing
requirement to pipelines outside of
Class 1 locations and subject to seam
issues.
3. INGAA, GPTC, Texas Pipeline
Association, Texas Oil & Gas
Association, and several pipeline
operators opposed a blanket testing
requirement for older pipelines. The
commenters noted that more than sixty
percent of in-service pipelines were
installed prior to 1970, and have
operated safely. INGAA argued that the
objective of any action in this area
should not be pressure testing, per se,
but verification of fitness for service.
INGAA noted that all of the listed pipe
types are addressed in its Fitness for
Service protocol, which would be more
effective and efficient than a
prescriptive test requirement. A number
of additional pipeline operators
supported INGAA’s comments.
4. Accufacts recommended that all
pipelines with at-risk seam anomalies
be pressure tested to at least 90%
SMYS, with priority given to lines
operating under an MAOP established
in accordance with 49 CFR 192.619(c).
5. Texas Pipeline Association and
Texas Oil & Gas Association noted that
pressure testing alone, is not sufficient
to prove the integrity of pipelines
subject to seam issues. The associations
argued that verification must also
consider any degradation mechanism
present in the seam.
6. Dominion East Ohio supported a
requirement to pressure test pipe
susceptible to seam failure for which
adequate test documentation does not
exist.
7. Pipeline Safety Trust, California
Public Utilities Commission,
Commissioners of Wyoming County
Pennsylvania, and an anonymous
commenter supported requiring a
pressure test for all pipelines not
already tested to current requirements.
The commenters argued that integrity
management should have led to
necessary testing but has not done so in
all cases. They also noted that such a
requirement would respond to an NTSB
recommendation.
8. The Environmental Defense Fund
(EDF) cautioned that any requirement
for pressure testing should assure that
the amount of gas blown down to the
atmosphere is minimized. It noted that
methane is a potent greenhouse gas, and
uncontrolled blowdown of 182,000
miles of gas transmission pipeline
would be approximately equivalent to
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the annual greenhouse gas release from
9–14 million autos.
Response to Question J.1 Comments
PHMSA appreciates the information
provided by the commenters. This
NPRM proposes requirements for
verification of MAOP in new § 192.624
for onshore, steel, gas transmission
pipelines that are located in an HCA or
MCA and meet any of the conditions in
§ 192.624(a)(1) through (a)(3).
Verification of MAOP includes
establishing and documenting MAOP
using one or more of the methods in
§ 192.624(c)(1) through (c)(6). With
regard to the EDF comment regarding
the environmental cost due to gas blow
down during pressure testing, PHMSA
considered this in the rule development.
The proposed rulemaking is written to
minimize pressure testing. The Integrity
Verification Process allows MAOP
verification through ILI and ECA.
PHMSA believes operators will pressure
test as a last resort because it is the
costliest methodology. PHMSA
estimates that the rule would result in
approximately 1,300 miles of pipe being
pressure tested. The gas release from
controlled low volume release during
pressure testing is much less than an
uncontrolled high volume release as a
result of rupture. The proposed rule is
expected to prevent incidents, leaks,
and other types of failures that might
occur, thereby preventing future
releases of greenhouse gases (GHG) to
the atmosphere, thus avoiding
additional contributions to global
climate change. PHMSA estimated net
GHG emissions abatement over 15 years
of 69,000 to 122,000 metric tons of
methane and 14,000 to 22,000 metric
tons of carbon dioxide, based on the
estimated number of incidents averted
and emissions from pressure tests and
ILI upgrades.
J.2. Are alternative minimum test
pressures (other than those specified in
subpart J) appropriate, and why?
1. INGAA, supported by a number of
pipeline operators, argued that there is
no evidence suggesting that subpart J
test pressures are inadequate. INGAA
added that there are circumstances in
which additional tests to 1.25 times
MAOP may be appropriate to verify
fitness for service. This is consistent
with ASME/ANSI B31.8S and addressed
in its Fitness for Service protocol.
2. Texas Pipeline Association, Texas
Oil & Gas Association, and Atmos
argued that a pressure test at the time of
construction is adequate. The
associations further added that
operating practices since part 192
became effective can also verify fitness
for service, if primary test records are
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not available, particularly if MAOP is
reduced.
3. AGA, GPTC, and a number of
pipeline operators commented that any
test to pressures greater than MAOP has
some value. AGA noted that even tests
to 1.1 times MAOP would identify the
most severe defects that have the
potential to adversely affect pipeline
integrity.
4. MidAmerican suggested that a
fitness for service evaluation should be
allowed if there are service interruption
issues and for pre-1970 pipelines.
MidAmerican would allow testing for
existing pipelines, to 1.1 or 1.25 times
MAOP or to mill test pressures if they
are less than would be required by
subpart J.
5. An anonymous commenter argued
that alternative minimum test pressures
are not appropriate, since they provide
no more information than successful
operation at normal operating pressures.
6. Accufacts suggested that pipelines
tested to lower pressures and that have
been subject to aggressive operating
cycles be considered for high-pressure
testing. Accufacts would also require
test pressures be recorded both in psig
and percent SMYS.
Response to Question J.2 Comments
PHMSA appreciates the information
provided by the commenters. Following
publication of the ANPRM, the NTSB
issued its report on the San Bruno
incident that included a
recommendation for this issue (P–11–
15). The NTSB recommended that
PHMSA amend its regulations so that
manufacturing- and construction-related
defects can only be considered ‘‘stable’’
if a gas pipeline has been subjected to
a post-construction hydrostatic pressure
test of at least 1.25 times the MAOP.
This NPRM proposes to revise the
integrity management requirement in
192.917(e)(3) to allow the presumption
of stable manufacturing and
construction defects only if the pipe has
been pressure tested to at least 1.25
times MAOP. In addition, PHMSA
proposes to revise pressure test safety
factors in § 192.619(a)(2)(ii) to
correspond to at least 1.25 MAOP for
newly installed pipelines.
J.3. Can ILI be used to find seam
integrity issues? If so, what ILI
technology should be used and what
inspection and acceptance criteria
should be applied?
1. INGAA and numerous pipeline
operators noted that ILI tools can
examine seam issues but the technology
to identify and evaluate seam anomalies
is still evolving. INGAA added that
there are significant burdens associated
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with requiring pressure testing as an
alternative.
2. AGA reported that its discussions
with ILI vendors have identified that ILI
can detect seam issues but detection is
dependent on many conditions and is
not guaranteed.
3. Texas Pipeline Association and
Texas Oil & Gas Association argued that
ILI conducted using a multi-purpose
tool can provide a seam assessment
equivalent to pressure testing for
detection of seam integrity issues,
depending on anomaly characteristics
and the ILI method used.
4. Northern Natural Gas commented
that ILI can be used to detect seam
anomalies. Analysis of anomalies is
based on the log-secant method with
consideration of toughness to determine
the predicted failure pressure ratio. The
response criteria can then be based on
the failure pressure versus maximum
allowable operating pressure, similar to
wall loss. Northern noted that this is
consistent with ASME/ANSI B31.8 and
B31.8S.
5. Accufacts commented that ILI
cannot, at present, reliably detect all
seam anomalies.
Response to Question J.3 Comments
PHMSA appreciates the information
provided by the commenters. PHMSA
proposes requirements in the
rulemaking to address the use of ILI for
seam integrity issues. This includes
incorporating industry standard NACE
SP0102–2010 into the regulations to
provide better guidance for conducting
integrity assessments with in-line
inspection. In addition, for pipe
segments subject to MAOP verification
in new § 192.624, specific guidance is
provided for analyzing crack stability
when using engineering critical
assessment in conjunction with inline
inspection to address seam or other
cracking issues.
J.4. Are other technologies available
that can consistently be used to reliably
find and remediate seam integrity
issues?
1. INGAA and numerous pipeline
operators noted that magnetic particle
inspection is now being used by many
operators when pipe with disbanded
coating is exposed.
2. GPTC, Northern Natural Gas, and
MidAmerican reported that there are
other methods that are useful under
some circumstances, such as x-ray or
other forms of radiography and guided
wave ultrasound.
3. Texas Pipeline Association, Texas
Oil & Gas Association, and Atmos noted
that radiography, ultrasonic testing
(UT), and shear wave UT are now being
tested.
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4. AGA, supported by a number of its
pipeline operator members, noted that
operators must have the flexibility to
select appropriate tools without prior
PHMSA approval. AGA argued that
technology is advancing rapidly and
that PHMSA stifles advancement by
requiring prior approval of new
inspection tools. AGA argued that some
requirements being imposed on the use
of other technologies are effectively
regulations imposed without formal
rulemaking, citing limitations imposed
on the use of guided wave ultrasound as
an example.
5. Atmos recommended that PHMSA
modify its regulations to allow operators
to use appropriate methods to evaluate
seam integrity without requiring
approval as ‘‘other technology.’’
6. Accufacts opined that pressure
testing and cyclic monitoring and
analysis are the only useful technologies
currently available.
Response to Question J.4 Comments
PHMSA appreciates the information
provided by the commenters. PHMSA
proposes requirements in the
rulemaking to address the use of best
available technology, including use of
electromagnetic acoustic transducers
(EMAT) or ultrasonic testing (UT) tools
to assess seam integrity issues. In
addition, proposed requirements
include performing fracture mechanics
modeling for failure stress pressure and
cyclic fatigue crack growth analysis to
assess crack or crack-like defects. These
requirements would apply to any
segment that required verification of
MAOP.
J.5. Should additional pressure test
requirements be applied to all pipelines,
or only pipelines in HCAs, or only
pipelines in Class 2, 3, or 4 location
areas?
1. INGAA and several pipeline
operators argued that existing
requirements are adequate and any
verification beyond those requirements
should rely on INGAA’s Fitness for
Service protocol. INGAA argued that its
protocol is consistent with Section 23 of
the Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011.
2. MidAmerican suggested any new
requirements should focus on pipe with
manufacturing and construction defects
and should prioritize pipelines in Class
3 and 4 areas and HCAs. MidAmerican
sees little benefit in testing other
pipelines.
3. An anonymous commenter
recommended additional unspecified
requirements be applied to pipelines in
Class 3 and 4 areas and HCAs.
4. The California Public Utilities
Commission would apply pressure
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testing requirements to HCAs that are
determined by the method described in
paragraph 1 in the definition of HCA in
§ 192.903, as a minimum.
5. The Iowa Utilities Board and the
Iowa Association of Municipal Utilities
argued that class location is not a
reasonable basis for determining where
to apply pressure testing requirements,
given that class location has no
relationship to risk. These commenters
noted that small-diameter, low-pressure
lines could be Class 3, even with no
structures intended for human
occupancy within a potential impact
radius.
6. The Commissioners of Wyoming
County Pennsylvania would apply
requirements to all transmission and
gathering pipelines, including those in
Class 1 locations.
7. Thomas Lael noted that all
pipelines have been tested once, after
construction.
Response to Question J.5 Comments
PHMSA appreciates the information
provided by the commenters. This
NPRM proposes requirements for
verification of MAOP in new § 192.624
for onshore, steel, gas transmission
pipelines that are located in an HCA or
MCA and meet any of the conditions in
§ 192.624(a)(1) through (a)(3). Use of the
MCA location criteria would apply to
pipe segments where dwellings,
occupied sites, or interstate highways,
freeways, and expressways, and other
principal 4-lane arterial roadways are
located within the potential impact
radius, but would not necessarily
include all class 3 or 4 locations.
Verification of MAOP includes
establishing and documenting MAOP
using one or more of the methods in
192.624(c)(1) through (c)(6). In addition,
this NPRM proposes requirements for
verification of pipeline material in new
§ 192.607 for existing onshore, steel, gas
transmission pipelines that are located
in an HCA or class 3 or class 4 locations.
J.6. If commenters suggest
modification to the existing regulatory
requirements, PHMSA requests that
commenters be as specific as possible.
In addition, PHMSA requests
commenters to provide information and
supporting data related to:
• The potential costs of modifying the
existing regulatory requirements
pursuant to commenter’s suggestions.
• The potential quantifiable safety
and societal benefits of modifying the
existing regulatory requirements.
• The potential impacts on small
businesses of modifying the existing
regulatory requirements.
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• The potential environmental
impacts of modifying the existing
regulatory requirements.
No comments were received in
response to this question.
K. Establishing Requirements
Applicable to Underground Gas Storage
Underground storage facilities are
comprised of wells and associated
separation, compression, and metering
facilities to inject and withdraw natural
gas at high pressures from depleted
hydrocarbon reservoirs and salt caverns.
Pipelines that transport gas within a
storage field are defined in § 192.3 as
transmission pipelines and are regulated
by PHMSA, while underground storage
facilities including surface and
subsurface well casing, tubing, and
valves are not currently regulated under
part 192. In the ANPRM, PHMSA
provided a brief history of a 1992
accident that occurred in Brenham,
Texas an involving underground storage
facility. This incident involved an
uncontrolled release of highly volatile
liquids from a salt dome storage cavern
that resulted in 3 fatalities, 21 people
treated for injuries at area hospitals, and
damages in excess of $9 million.
Following the incident, the National
Transportation Safety Board (NTSB)
conducted an investigation that resulted
in a recommendation for the Research
and Special Programs Administration,
the precursor to PHMSA, to initiate a
rulemaking proceeding. Following a
period of study, RSPA terminated that
rulemaking. RSPA described this action
in an Advisory Bulletin published in the
Federal Register on July 10, 1997 (ADB–
97–04, 62 FR 37118).
Since publication of the 1997
Advisory Bulletin, significant incidents
have continued to occur involving
underground gas storage facilities. The
most significant incident occurred in
2001 near Hutchinson, Kansas. An
uncontrolled release from an
underground gas storage facility
resulted in an explosion and fire, in
which two people were killed. Many
residents were evacuated from their
homes and were not able to return for
four months.
The Kansas Corporation Commission
initiated enforcement action against the
operator of the Hutchinson storage field
as a result of safety violations associated
with the accident. As part of this
enforcement proceeding, it was
concluded that the storage field was an
interstate gas pipeline facility. Federal
statutes provide that ‘‘[a] State authority
may not adopt or continue in force
safety standards for interstate pipeline
facilities or interstate pipeline
transportation’’ (49 U.S.C. 60104). There
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were, and remain, no federal safety
standards against which enforcement
could be taken. Therefore, the
enforcement proceeding was
terminated.
The ANPRM listed questions for
consideration and comment. The
following are general comments
received related to this topic as well as
comments related to the specific
questions:
General Comments for Topic K
1. AGA, supported by a number of
pipeline operators, suggested that any
proceeding addressing gas storage be
conducted under a docket separate from
any pipeline requirements, arguing that
the relevant engineering and regulatory
concepts are vastly different.
2. The Kansas Department of Health
and Environment (KDHE) noted that the
ANPRM misstated the agency that took
enforcement action in the case of the
Kansas gas storage incident previously
discussed. That action was taken by
KDHE, and not the Kansas Corporation
Commission, as stated.
3. Kansas Corporation Commission
recommended that PHMSA work with
the states to have Congress amend the
Pipeline Safety Act to allow the states
to regulate interstate and intrastate gas
storage wellbores. KCC noted that
current federal regulations undermine
the ability of states to regulate gas
storage facilities, as in the 2001 accident
where Kansas attempted to take
enforcement as a result of a serious
incident but was precluded from doing
so by pre-emption of federal regulations.
4. The Interstate Oil & Gas Compact
Commission argued that states should
be mandated to regulate gas storage
wellbores, whether interstate or
intrastate.
5. The Texas Pipeline Association and
Texas Oil & Gas Association opposed
new requirements, arguing that there
has been no demonstration of undue
risk or insufficiency of current
regulations.
Comments submitted for questions in
Topic K.
K.1. Should PHMSA develop Federal
standards governing the safety of
underground gas storage facilities? If so,
should they be voluntary? If so, what
portions of the facilities should be
addressed in these standards?
1. INGAA suggested that PHMSA
develop high-level, performance-based
guidelines that acknowledge and reflect
existing applicable state rules to address
regional and geologic variations in
underground storage activity.
Development of guidelines should
follow PHMSA’s current practice of
stakeholder involvement leading to
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development of a consensus standard
and its subsequent adoption into
regulations. INGAA reported that it is
committed to developing a standard
under the auspices of the American
Petroleum Institute (API), with work
beginning in 2012. INGAA cautioned
that it is important to understand, and
clearly state, the scope of ‘‘gas storage,’’
which it contends begins at and
includes the wing valve at the wellhead,
the wellhead components, the well bore,
and the ‘‘underground container’’ (i.e.,
the geologic formation). INGAA stated
that PHMSA should recognize the limits
and requirements imposed on gas
storage by FERC, arguing that no new
regulations are needed in these areas. A
number of pipeline operators supported
INGAA’s comments, and have
submitted separate comments
addressing one or more of these points.
2. AGA suggested that PHMSA adopt
federal performance standards, in
conjunction with API. AGA argued that
one-size-fits-all requirements are not
appropriate in this area, since they
would fail to recognize variations in
wells and the geologic diversity of
storage caverns and structures. AGA
argued that no new requirements are
needed governing maximum operating
parameters and environmental
conditions, since these are addressed
adequately by existing federal and state
certification and compliance programs
related to gas storage facilities. AGA
recommended that any new standards
should be mandatory, but also recognize
regional variations by state due to
geologic and geographical diversity
among storage fields. A number of
pipeline operators supported AGA’s
comments.
3. INGAA, the Kansas Corporation
Commission, and the Interstate Oil &
Gas Compact Commission
recommended that compliance with any
new standards be mandatory, but that
regulatory authority should be delegated
to the states since PHMSA lacks
relevant technical expertise. A number
of pipeline operators supported this
comment.
4. The Kansas Corporation
Commission and the Interstate Oil & Gas
Compact Commission recommended
that any new standards cover all
portions of a storage facility and that
PHMSA enter into a memorandum of
understanding with FERC regarding gas
containment.
5. Southern Star Central Gas Pipeline
agreed that the development of
requirements for operation of gas storage
facilities is appropriate but explicitly
disagreed with Kansas Corporation
Commission’s suggestion that
development be delegated to states.
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Southern Star indicated that it would
not object to the delegation of
inspection and enforcement to federal
standards. Southern Star noted that a
federal court has held only federal
regulations can be enforced against its
storage facilities. The company also
argued that no new requirements are
needed for storage reservoirs given
existing FERC regulations.
6. GPTC, Nicor, Ameren Illinois, and
Atmos argued that existing regulations
are sufficient and that no new standards
are needed. GPTC and Nicor added that
if PHMSA elects to develop new
requirements, they should be limited to
facilities ‘‘affecting interstate or foreign
commerce.’’ Atmos added that geology
and circumstances vary considerably
among gas storage facilities and states
have the requisite expertise to regulate
storage safety.
7. Texas Pipeline Association and
Texas Oil & Gas Association argued that
PHMSA lacks the expertise to regulate
wellbores and therefore should not
attempt to develop gas storage
regulations.
8. FERC, NAPSR, Interstate Oil & Gas
Compact Commission, Iowa Utilities
Board, Kansas Corporation Commission,
and Railroad Commission of Texas
recommended that PHMSA seek
statutory authority to confer jurisdiction
over all gas storage facilities to the
states. The commenters argued that
states have expertise on local geology
and storage fields and could therefore
regulate in a fashion similar to that of
production facilities. The commenters
referred to PHMSA’s Advisory Bulletin
ADB 97–04 as a further basis for this
recommendation. FERC further
suggested that PHMSA delegate
inspection and enforcement activities to
states if statutory changes are not
forthcoming.
9. The Alaska Department of Natural
Resources recommended that PHMSA
develop standards in consultation with
the states.
10. The NTSB encouraged the
development of gas storage regulations,
noting that this was the subject of its
recommendation P–93–9, which it
closed as ‘‘unacceptable action,’’ after a
rulemaking proceeding to regulate
underground gas storage was terminated
in 1997.
11. A private citizen suggested that
there should be some level of regulation,
as gas storage is currently insufficiently
regulated.
12. NAPSR commented that, in many
states, the agency familiar with gas
storage issues is not responsible for
regulation of pipeline safety. As a result,
NAPSR stated that certification of
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additional state agencies may be
required.
13. An anonymous commenter
suggested that PHMSA should develop
requirements applicable to piping
within gas storage facilities. The
commenter argued that caverns, well
heads, casing, tubing, fresh water, and
brine pumping are generally regulated
by states.
14. ITT Exelis Geospatial Systems
suggested that PHMSA consider
requirements for leak detection, noting
that their LIDAR system could serve this
purpose.
K.2. What current standards exist
governing safety of these facilities? What
standards are presently used for
conducting casing, tubing, isolation
packer, and wellbore communication
and wellhead equipment integrity tests
for down-hole inspection intervals?
What are the repair and abandonment
standards for casings, tubing, and
wellhead equipment when
communication is found or integrity is
compromised?
1. AGA, INGAA, GPTC, Texas
Pipeline Association, Texas Oil & Gas
Association and numerous pipeline
operators noted that FERC, EPA, and the
states regulate various aspects of gas
storage. Commenters reported that state
regulations generally provide standards
for wells and that EPA regulations
provide standards for caverns. AGA
described the aspects regulated by
FERC, EPA, and the states and suggested
provisions of each which might be
considered for new PHMSA regulations.
For example, it was recommended that
a federal guideline be established to
require a storage operator notificationreview-and-approval process for third
party wells encroaching on storage
containers, which is a requirement some
states currently have in place.
Commenters reported that repaired
wells must meet state standards for new
wells and state requirements for
abandonment vary. AGA indicated that
interstate storage operators use state
requirements as guidance in the absence
of federal regulations.
2. The Kansas Department of Health
and Environment, the Kansas
Corporation Commission, the Railroad
Commission of Texas, the Interstate Oil
& Gas Compact Association, Ameren
Illinois, and Atmos reported that states
generally regulate gas storage. For
example, in Texas, Statewide Rule 16
applies and KDHE submitted a copy of
its gas storage regulations.
3. Texas Pipeline Association and
Texas Oil & Gas Association noted that
Texas requirements for gas storage are
more similar to provisions that would
govern production drilling and
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operations rather than pipeline
operations.
K.3. What standards are used to
monitor external and internal
corrosion?
1. AGA, INGAA, and numerous
pipeline operators noted that varying
approaches are used and argued that
prescriptive standards would be
inappropriate given that no one tool is
applicable to all wells and well casings
are not available for direct examination.
2. The Railroad Commission of Texas
reported that its regulations require
integrity testing every five years or after
a well work over. Texas regulations also
require periodic casing inspections and
a pipeline integrity program.
3. Northern Natural Gas reported that
it uses the same measures to monitor
corrosion in its gas storage facilities as
it does for its pipelines.
K.4. What standards are used for
welding, pressure testing, and design
safety factors of casing and tubing
including cementing and casing and
casing cement integrity tests?
1. INGAA, AGA, the Texas Pipeline
Association, the Texas Oil & Gas
Association and numerous pipeline
operators noted that state requirements
reflect unique situations, welding is
seldom used, pressure capacity is
demonstrated by historical record, and
casing requirements are customized for
local geologic conditions. Welding,
when used, is generally performed to
procedures compliant with ASTM
B31.8, part 192, and inspection is
conducted to API–1104 criteria.
2. The Railroad Commission of Texas
reported that Texas regulations are
flexible to allow for site-specific
decisions.
K.5. Should wellhead valves have
emergency shutdowns both primary and
secondary? Should there be integrity
and O&M intervals for key safety and CP
systems?
1. INGAA, AGA, and several pipeline
operators reported that storage in salt
domes generally requires emergency
shutdown systems; these systems are
generally not required for storage in
depleted gas fields or aquifers but may
be required depending on local site
conditions. The commenters indicated
that testing intervals are set in
accordance with operator procedures
and CP testing is based on an operator’s
local experience.
2. The Railroad Commission of Texas,
the Texas Pipeline Association, and the
Texas Oil & Gas Association reported
that Texas’ regulations require
emergency shutdown systems and
annual drills.
3. The Kansas Department of Health
and Environment suggested that at least
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the primary well should have an
emergency shutdown system. KDHE
stated that O&M intervals should be
established for key safety systems and
attached a copy of the relevant Kansas
regulations to its comments.
4. Northern Natural Gas suggested
that emergency shutoffs should only be
required when the well is within 330
feet of a structure intended for human
occupancy. Northern stated that
intervals should be established for O&M
activities and CP systems.
5. GPTC and Nicor expressed their
opinion that no new regulations are
needed in this area; decisions on
emergency shutdown should be made
based on local circumstances.
K.6. What standards are used for
emergency shutdowns, emergency
shutdown stations, gas monitors, local
emergency response communications,
public communications, and O&M
Procedures?
1. AGA, GPTC, and several pipeline
operators reported that operators
generally follow DOT regulations, where
applicable, and industry good practices.
2. The NTSB commented that gas
storage facility information should be
made available to emergency
responders, per its recommendation P–
11–8.
3. The Railroad Commission of Texas,
the Texas Pipeline Association, the
Texas Oil & Gas Association, and Atmos
reported that states establish standards
in these areas through their regulations.
4. The Kansas Department of Health
and Environment reported that these
standards are specified in its
regulations, and submitted a copy of its
regulations as an attachment to its
comments.
K.7. Does the current lack of Federal
standards and preemption provisions in
Federal law preclude effective
regulation of underground storage
facilities by States?
1. INGAA, supported by several of its
member companies, noted that
jurisdiction over gas storage facilities in
interstate pipeline systems is federal.
2. AGA and several of its pipeline
operator members suggested that federal
standards could assure a degree of
consistency, and uniform standards
would promote integrity and safety.
AGA opined that implementation of
federal standards could be delegated to
the states.
3. GPTC and Nicor opined that federal
regulations are not needed; as states are
not now precluded from regulating gas
storage and many do so.
4. The Texas Pipeline Association, the
Texas Oil & Gas Association, Atmos,
Ameren Illinois, and Northern Natural
Gas opined that effective state
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regulation is not now precluded. The
commenters stated that state regulation
in combination with applicable FERC
and DOT requirements has been
demonstrated to assure safety
successfully.
5. The Kansas Department of Health
and Environment and the Kansas
Corporation Commission noted that
state regulation of the safety of interstate
gas storage facilities is currently
precluded. When Kansas attempted to
enforce its requirements following an
accident at an interstate storage facility,
it was prevented from doing so by a
federal court on the basis of federal
preemption. The agencies noted that
lack of action by PHMSA or FERC on
interstate gas storage facility safety
precludes states from taking any action
and leaves these facilities essentially
unregulated.
K.8. If commenters suggest
modification to the existing regulatory
requirements, PHMSA requests that
commenters be as specific as possible.
In addition, PHMSA requests
commenters to provide information and
supporting data related to:
• The potential costs of modifying the
existing regulatory requirements.
• The potential quantifiable safety
and societal benefits of modifying the
existing regulatory requirements.
• The potential impacts on small
businesses of modifying the existing
regulatory requirements.
• The potential environmental
impacts of modifying the existing
regulatory requirements.
No comments were received in
response to this question.
Response to All Topic K Comments
Since the publication of the ANPRM
and the close of its comment period,
Southern California Gas Company’s
(SoCal Gas) Aliso Canyon Natural Gas
Storage Facility Well SS25 failed,
causing a sustained and uncontrolled
natural gas leak near Los Angeles,
California. The failure, possibly from
the downhole well casing, resulted in
the relocation of more than 4,400
families according to the Aliso Canyon
Incident Command briefing report
issued on February 1, 2016. On January
6, 2016, California Governor Jerry
Brown issued a proclamation declaring
the Aliso Canyon incident a state
emergency. On February 5, 2016,
PHMSA issued an advisory bulletin in
the Federal Register (81 FR 6334) to
remind all owners and operators of
underground storage facilities used for
the storage of natural gas to consider the
overall integrity of the facilities to
ensure the safety of the public and
operating personnel and to protect the
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20795
environment. The advisory bulletin
specifically reminded these operators to
review their operations and identify the
potential of facility leaks and failures,
review the operation of their shut-off
and isolation systems, and maintain
updated emergency plans. In addition,
PHMSA used the advisory bulletin to
advocate the review of a previous
advisory bulletin (97–04) dated July 10,
1997 and the voluntary implementation
of American Petroleum Institute (API)
1170 ‘‘Design and Operation of
Solution-mined Salt Caverns Used for
Natural Gas Storage, First Edition, July
2015,’’ API RP 1171 ‘‘Functional
Integrity of Natural Gas Storage in
Depleted Hydrocarbon Reservoirs and
Aquifer Reservoirs, First Edition,
September 2015,’’ and Interstate Oil and
Gas Compact Commission (IOGCC)
standards entitled ‘‘Natural Gas Storage
in Salt Caverns—A Guide for State
Regulators’’ (IOGCC Guide), as
applicable. PHMSA will consider
proposing a separate rulemaking to
address the safety of underground
natural gas storage facilities. Proposing
a separate rulemaking that specifically
focuses on improving the safety of
underground natural gas storage
facilities will allow PHMSA to fully
consider the impacts of incidents that
have occurred since the close of the
initial comment period. It will also
allow the Agency to consider voluntary
consensus standards that were
developed after the close of the
comment period for this ANPRM, and to
solicit feedback from additional
stakeholders and members of the public
to inform the development of potential
regulations.
L. Management of Change
The ANPRM requested comments
regarding the addition of requirements
for the management of change to
provide a greater degree of control over
this element of pipeline risk,
particularly following changes to
physical configuration or operational
practices. Operation of a pipeline over
an extended period without effective
management of change, such as changes
to pipeline systems (e.g., pipeline
equipment, computer equipment or
software used to monitor and control
the pipeline) or to practices used to
construct, operate, and maintain those
systems, can result in safety issues.
Changes can introduce unintended
consequences if the change is not well
thought out or is implemented in a
manner not consistent with its design or
planning. Similarly, changes in
procedures require people to perform
new or different actions, and failure to
train them properly and in a timely
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manner can result in unexpected
consequences. The result can be a
situation in which risk or the likelihood
of an accident is increased. A recently
completed but poorly-designed
modification to the pipeline system was
a factor contributing to the Olympic
Pipeline accident in Bellingham,
Washington. The following are general
comments received related to this topic
as well as comments related to the
specific questions:
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General Comments for Topic L
1. INGAA and several of its pipeline
operator members disagreed with the
implication in the ANPRM that change
management is not now addressed in
regulations. They pointed out that
§ 192.911(k) and ASME/ANSI B31.8S
(incorporated by reference) already
address this subject. INGAA reported
that its members are committed to
clarifying and expanding the use of a
formal ‘‘management of change’’
process, and to facilitating its consistent
application as a key management
system. INGAA expressed its belief that
the full adoption of ASME/ANSI B31.8S
will facilitate the widespread
application of these principles.
Dominion East Ohio Gas also noted that
part 192 already contains a management
of change process. In addition, Chevron
noted that management of change
programs are generally specific to the
organizational, operational, and
ownership structures of the company,
and part 192 already addresses this
subject.
2. A private citizen opined that
management of change is necessarily an
integral part of quality management
systems and another private citizen
supported management of change
requirements, noting that accidents
often result from changes to systems.
The Alaska Department of Natural
Resources also supported PHMSA’s goal
of establishing management of change
requirements or guidelines.
Response to General Comments for
Topic L
PHMSA appreciates the information
provided by the commenters. PHMSA
agrees management of change is
currently addressed in § 192.911(k).
However, because of its importance, and
consistent with INGAA members’
commitment to expanding use of formal
MOC processes, PHMSA believes it is
prudent to provide greater emphasis on
MOC directly within the rule text.
Therefore, PHMSA proposes to clarify
integrity management requirements for
management of change by explicitly
including aspects of an effective
management of change process into the
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rule text to emphasize the current
requirements. In addition, PHMSA also
proposes to add a new subsection
192.13(d) that would apply to onshore
gas transmission pipelines, and require
that an evaluation must be performed to
evaluate and mitigate, as necessary, the
risk to the public and environment as an
integral part of managing pipeline
design, construction, operation,
maintenance and integrity, including
management of change. The new
paragraph would also articulate the
general requirements for a management
of change process, consistent with
Section 192.911(k).
Comments submitted for questions in
Topic L.
L.1. Are there standards used by the
pipeline industry to guide management
processes including management of
change? Do standards governing the
management of change process include
requirements for IM procedures, O&M
manuals, facility drawings, emergency
response plans and procedures, and
documents required to be maintained
for the life of the pipeline?
1. AGA, supported by several of its
members, and several transmission
pipeline operators questioned why this
question was in the ANPRM, noting that
management of change requirements are
already promulgated in § 192.911(k).
GPTC added that § 192.909 also
addresses this subject.
2. INGAA reported that Section 11 of
ASME/ANSI B31.8S is the industry
standard in this area, and all of the
considerations in this question are
included in operators’ management of
change processes. Several pipeline
operators supported this comment.
3. Atmos reported that it is not aware
of any standards used by the industry to
guide management of change processes.
Atmos does not have a formal
management of change process, except
in its integrity management program,
but expressed its conclusion that
existing practices within the company
contribute to its ability to manage
change.
4. Texas Pipeline Association (TPA)
reported that its members do not have
formal management of change processes
but comply with regulations that
address proxy requirements (e.g.,
§ 192.911). TPA expressed its belief that
part 192, taken as a whole, includes
management of change requirements to
which its members adhere. Texas Oil &
Gas Association supported TPA’s
comments.
5. California Public Utilities
Commission reported that it is unaware
of any pipeline industry standards in
this area.
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6. An anonymous commenter opined
that most operators do not have
management of change processes.
7. The NTSB recommended that
PHMSA require operators of natural gas
transmission and distribution pipelines
and hazardous liquid pipelines to
ensure that their control room operators
immediately notify the relevant 911
emergency call centers of possible
ruptures (Recommendation P–11–9).
8. TransCanada reported that it is
committed to clarifying and expanding
the use of a formal ‘‘management of
change’’ process. TransCanada
expressed its conclusion that the full
adoption of ASME/ANSI B31.8S will
facilitate the widespread application of
management of change principles.
Response to Question L.1 Comments
PHMSA appreciates the information
provided by the commenters, which did
not identify any standards beyond
ASME/ANSI B31.8S, which is already
invoked by part 192, and used by the
pipeline industry to guide management
processes including management of
change. See response to the general
comments for Topic L, above.
L.2. Are standards used in other
industries (e.g., Occupational Safety
and Health Administration standards at
29 CFR 1910.119) appropriate for use in
the pipeline industry?
1. INGAA reported that Section 11 of
ASME/ANSI B31.8S is based on OSHA’s
Process Safety Management (PSM)
standards. INGAA noted that OSHA
worked with industry in developing
PSM standards that would identify
potential threats and assure that
mitigative actions were taken. Several
pipeline operators supported INGAA’s
comments.
2. AGA and GPTC expressed their
belief that there is no benefit in
comparing standards with other
industries, reiterating that §§ 192.909
and 192.911 and ASME/ANSI B31.8S
already include management of change.
Several pipeline operators supported
AGA’s comments.
3. The Texas Pipeline Association and
the Texas Oil & Gas Association
reported that their members are aware of
standards used in other industries but
do not believe they are appropriate or
applicable to the pipeline industry.
4. The Iowa Association of Municipal
Utilities expressed its conclusion that
OSHA standards are complicated and
would be unduly costly for small
municipal utilities.
5. Accufacts noted that transportation
pipelines are specifically excluded from
OSHA regulation; however, this does
not prevent PHMSA from incorporating
elements of 29 CFR 1910.119 into the
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federal pipeline safety regulations in
order to mandate a more prudent
pipeline safety culture.
6. Atmos reported that it has no
experience with standards used in other
industries but noted that OSHA
standards appear to be directed toward
situations where processes interact such
that a change in one process affects a
second or third process.
7. Ameren Illinois suggested that
standards from other industries would
need to be studied to determine if they
are applicable to the pipeline industry.
8. An anonymous commenter
suggested that the OSHA standards are
a good model for pipelines, as they are
well written and thought out.
Response to Question L.2 Comments
PHMSA appreciates the information
provided by the commenters. See
response to the general comments for
Topic L, above.
L.3. If commenters suggest
modification to the existing regulatory
requirements, PHMSA requests that
commenters be as specific as possible.
In addition, PHMSA requests
commenters to provide information and
supporting data related to:
• The potential costs of modifying the
existing regulatory requirements.
• The potential quantifiable safety
and societal benefits of modifying the
existing regulatory requirements.
• The potential impacts on small
businesses of modifying the existing
regulatory requirements.
• The potential environmental
impacts of modifying the existing
regulatory requirements.
No comments were received in
response to this question.
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M. Quality Management Systems (QMS)
The ANPRM requested comments on
whether and how to impose
requirements related to quality
management systems. Quality
management includes the activities and
processes that an organization uses to
achieve quality. These include
formulating policy, setting objectives,
planning, quality control, quality
assurance, performance monitoring, and
quality improvement.
Achieving quality is critical to gas
transmission pipeline design,
construction, and operations. PHMSA
recognizes that pipeline operators strive
to achieve quality, but our experience
has shown varying degrees of success in
accomplishing this objective among
pipeline operators. PHMSA believes
that an ordered and structured approach
to quality management can help
pipeline operators achieve a more
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consistent state of quality and thus
improve pipeline safety.
PHMSA’s pipeline safety regulations
do not currently address process
management issues such as quality
management systems. Section 192.328
requires a quality assurance plan for the
construction of pipelines intended to
operate at an alternative MAOP, but
there is no similar requirement
applicable to other pipelines. Quality
assurance is generally considered to be
an element of quality management.
Important elements of quality
management systems are their design
and application to control (1) the
equipment and materials used in new
construction (e.g., quality verification of
materials used in construction and
replacement, post-installation quality
verification), and (2) the contractor work
product used to construct, operate, and
maintain the pipeline system (e.g.,
contractor qualifications, verification of
the quality of contractor work products).
The ANPRM then listed questions for
consideration and comment. The
following are general comments
received related to this topic as well as
comments related to the specific
questions:
General Comments for Topic M
1. MidAmerican suggested that
PHMSA work with the committees for
ASME/ANSI B31.8 and B31.8S to
address these topics more fully, if
PHMSA believes more is needed.
MidAmerican opined that a general rule
addressing quality management systems
would divert resources and adversely
affect safety, if applied to this already
heavily-regulated industry.
2. The Alaska Department of Natural
Resources supported quality
management systems and suggested that
pipeline operators should apply such
standards to their contractors.
3. A private citizen supported quality
management systems, noting that this is
an area that would be difficult to
regulate but might be an element in
incentive programs.
Comments submitted for questions in
Topic M.
M.1. What standards and practices
are used within the pipeline industry to
assure quality? Do gas transmission
pipeline operators have formal QMS?
1. INGAA opined that achieving
consistent quality materials,
construction and management is an
appropriate focus for the INGAA
Foundation, which has sponsored and
will continue to sponsor workshops on
this subject. INGAA reported that the
Foundation plans to publish five
relevant White Papers in 2012 and its
Integrity Management—Continuous
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20797
Improvement team is currently working
on guidelines. INGAA also noted that
there are elements of a quality
management system in ASME/ANSI
B31.8S, already incorporated by
reference, including quality assurance/
quality control, management of change,
communication and performance
measurement, Standards, specifications,
and procedures governing pipe and
appurtenances form part of a pipeline
quality management system. INGAA
cited ISO (9001:2008/29001:2010) and
API (Spec Q1) quality management
standards as references that are
available for operator use. INGAA
further noted that API published Spec
Q2 in December 2011. Several pipeline
operators supported INGAA’s
comments.
2. AGA, GPTC, Nicor, Atmos, the
Texas Pipeline Association, and the
Texas Oil & Gas Association suggested
that part 192, taken as a whole, is
essentially a quality management
system. AGA provided a summary
listing of part 192 requirements that
assure quality. A number of additional
pipeline operators supported AGA’s
comments.
3. Ameren Illinois reported that it has
a quality assurance program for pipeline
construction that includes building
alliances with excavators and other
elements.
4. Paiute and Southwest Gas reported
that their practices beyond compliance
with part 192 requirements include
operator qualification (OQ) for
construction, an internal quality
assurance group, root cause analysis of
events, and quality control verification
of OQ.
5. MidAmerican reported that it has
no formal quality management system
but applies standards to assure quality
processes. In particular, ASME/ANSI
B31.8 and B31.8S and ANSI/ISO/ASQ
Q9004–2000 were used to guide its
company quality programs.
MidAmerican also has a contractor
oversight program.
6. An anonymous commenter opined
that most operators have a quality
management system, often incorporated
into their SCADA system, to satisfy
customers or end user requirements.
The commenter suggested that some of
these systems have only recently been
modified to address internal corrosion
mechanisms, often identified as part of
operators’ integrity management
programs.
M.2. Should PHMSA establish
requirements for QMS? If so, why? If so,
should these requirements apply to all
gas transmission pipelines and to the
complete life cycle of a pipeline system?
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1. INGAA, supported by a number of
its pipeline operator members, asserted
that no new requirements are
appropriate at this time. INGAA noted
that much work is ongoing in this area
and it may be appropriate to adopt some
standards (e.g., API Q1 or Q2) in the
future.
2. AGA, GPTC, the Texas Pipeline
Association, the Texas Oil & Gas
Association, Oleksa and Associates, and
numerous pipeline operators expressed
an opinion that new quality assurance
requirements are not needed. These
commenters view part 192 as quality
assurance requirements and argue that a
new programmatic requirement would
not be beneficial.
3. TransCanada opined that quality
management systems need to be
adopted throughout the entire industry
and embraced by operators and
contractors alike, arguing that this
would provide a more consistent level
of quality throughout the industry.
TransCanada opined that the INGAA
Foundation is the appropriate venue in
which to develop guidelines.
4. Northern Natural Gas opined that
the existing process, which includes
PHMSA/State inspections, is adequate.
5. A private citizen commented that
quality management systems should be
required to improve pipeline safety,
including documentation,
investigations, validation, audits/
inspections, change management,
training, and quality/management
oversight.
6. An anonymous commenter opined
that no new requirements are needed,
arguing that most operators have such
systems.
M.3. Do gas transmission pipeline
operators require their construction
contractors to maintain and use formal
QMS? Are contractor personnel that
construct new or replacement pipelines
and related facilities already required to
read and understand the specifications
and to participate in skills training prior
to performing the work?
1. INGAA reported that most of its
members apply quality management
principles, including requiring
contractors conform to specified
requirements, though the approach
varies from operator to operator. INGAA
acknowledged, however, that ‘‘[t]here is
room to establish a more structured
approach to QMS for operators and
construction contractors’’ to assure more
consistency. A number of pipeline
operators supported INGAA’s
comments.
2. AGA reported that transmission
operators have the means to assure
contractor work quality and that most
LDC operators impose operator
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qualification (OQ) and other specific
requirements on their construction
contractors.
3. The Texas Pipeline Association and
the Texas Oil & Gas Association
encouraged PHMSA not to adopt
requirements for operators to train
construction personnel. The
associations expressed concerns over
potential liability and their preference
for a performance-based standard.
4. Ameren Illinois, Atmos, and
MidAmerican reported that they apply
operator qualification (OQ)
requirements on their contractors.
5. Northern Natural Gas, Paiute, and
Southwest Gas reported that they do not
require contractors to have formal QMS
but do require conformance to various
standards.
6. Oleksa and Associates reported its
experience that operators require
construction contractors to meet the
same standards as their employees.
7. GPTC, Nicor, and an anonymous
commenter suggested that compliance
with construction regulations contribute
to QMS through requirements for
specifications and inspections.
8. NAPSR, the Texas Pipeline
Association, and the Texas Oil & Gas
Association suggested that operator
qualification (OQ) requirements be
applied to construction, since this
would apply formal QMS to the full
range of construction and operation.
M.4. Are there any standards that
exist that PHMSA could adopt or from
which PHMSA could adapt concepts for
QMS?
1. INGAA and a number of pipeline
operators suggested that several
standards could be used as general
references, including ISO 9001:2008
(Quality Management Systems), ISO
29001:2010 (Oil and Gas) and API Spec
Q1 (Oil and Gas). INGAA opined that
compliance with these standards should
not be required, and added that
additional standards, white papers, and
guidance are under development.
2. The AGA, GPTC, Nicor, and
Ameren Illinois opposed new
requirements in this area. AGA opined
that part 192 is already ‘‘saturated’’ with
this type of requirement. A number of
additional pipeline operators supported
AGA’s comments.
3. The NTSB recommended
improvement to PHMSA’s drug and
alcohol requirements, citing their
recommendations P–11–12 & 13.
4. A private citizen suggested that, by
extrapolating from the practices of a
pipeline operator with a good safety
record. The commenter stated that
useful references include the Baldrige
Performance Excellence Program and
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Quality Management Standard ISO
9000.
M.5. What has been the impact on
cost and safety in other industries in
which requirements for a QMS have
been mandated?
1. INGAA reported that quality
management systems have been
demonstrated to reduce risk and opined
that the keys to a successful QMS are
simplicity, empowerment,
accountability and ease of
implementation. A number of pipeline
operators supported INGAA’s
comments.
M.6. If commenters suggest
modification to the existing regulatory
requirements, PHMSA requests that
commenters be as specific as possible.
In addition, PHMSA requests
commenters to provide information and
supporting data related to:
• The potential costs of modifying the
existing regulatory requirements.
• The potential quantifiable safety
and societal benefits of modifying the
existing regulatory requirements.
• The potential impacts on small
businesses of modifying the existing
regulatory requirements.
• The potential environmental
impacts of modifying the existing
regulatory requirements.
No comments were received in
response to this question.
Response to All Topic M Comments
PHMSA appreciates the information
provided by the commenters. PHMSA
does not propose additional rulemaking
for this topic at this time. PHMSA will
review the comments received on the
ANPRM and will consider them in
future rulemaking.
N. Exemption of Facilities Installed
Prior to the Regulations
The ANPRM requested comments
regarding proposed changes to part 192
regulations that would eliminate
provisions that exempt pipelines from
pressure test requirements to establish
MAOP. Federal pipeline safety
regulations were first established with
the initial publication of part 192 on
August 19, 1970 (35 FR 13248). Gas
transmission pipelines had existed for
many years prior to this, some dating to
as early as 1920. Many of these older
pipelines had operated safely for years
at pressures higher than would have
been allowed under the new
regulations. It was concluded that a
required reduction in the operating
pressure of these pipelines would not
have resulted in a material increase in
safety. Therefore, a provision was
included in the regulations
(§ 192.619(c)) that allowed pipelines to
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operate at the highest actual operating
pressure to which they were subjected
during the 5 years prior to July 1, 1970.
The safe operation of these pipelines at
these pressures was deemed to be
evidence that operation could safely
continue.
Many gas transmission pipelines
continue to operate in the United States
under an MAOP established in
accordance with § 192.619(c). Some of
these pipelines operate at stress levels
higher than 72 percent specified
minimum yield strength (SMYS), the
highest level generally allowed for more
modern gas transmission pipelines.
Some pipelines operate at greater than
80 percent SMYS, the alternate MAOP
allowed for some pipelines by
regulations adopted October 17, 2008
(72 FR 62148). Under these regulations,
operators who seek to operate their
pipelines at up to 80 percent SMYS (in
Class 1 locations) voluntarily accept
significant additional requirements
applicable to design, construction, and
operation of their pipeline that are
intended to assure quality and safety at
these higher operating stresses.
Pipelines that operate under an MAOP
established in accordance with
§ 192.619(c) are subject to none of these
additional requirements.
Part 192 also includes several
provisions other than establishment of
MAOP for which an accommodation
was made in the initial part 192. These
provisions allowed pipeline operators to
use steel pipe that had been
manufactured before 1970 and did not
meet all requirements applicable to pipe
manufactured after part 192 became
effective (192.55); valves, fittings and
components that did not contain all the
markings required (192.63); and pipe
which had not been transported under
the standard included in the new part
192 (192.65, subject to additional testing
requirements).
The ANPRM then listed questions for
consideration and comment. The
following are general comments
received related to this topic as well as
comments related to the specific
questions:
General Comments for Topic N
1. INGAA and a number of pipeline
operators opined that age alone is not an
appropriate criterion for determining a
pipeline’s fitness for service. Old pipe
that is well maintained operates safely
and unfit pipe should be replaced
regardless of age. INGAA suggested that
fitness for service of pipe in HCAs
should be evaluated using available
records, if adequate, or through new
testing. INGAA attached a white paper
to its comments that described its
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Fitness for Service protocol. INGAA also
cautioned that any requirement to
reconfirm MAOP should be subject to a
rigorous cost-benefit analysis, as
hydrostatic testing is very expensive
and could require outages of up to
several weeks.
2. A private citizen suggested phasing
out sub-standard or systems that predate regulatory requirements where
public safety is concerned, implying
that this has been done in other areas
(citing elimination of radium dial
watches and leaking underground
storage tanks as examples).
3. A private citizen suggested that
legacy facilities should be subject to a
timetable to come into full compliance
with current regulations, arguing that
this would improve safety and
knowledge of older facilities.
Response to General Comments for
Topic N
PHMSA appreciates the information
provided by the commenters. NTSB
recommended that regulatory
exemptions be repealed. In addition,
section 23 of the Act addressed gas
transmission pipelines without records
sufficient to validate MAOP. In response
to these concerns, this NPRM proposes
requirements for verification of
maximum allowable operating pressure
(MAOP) in new § 192.624 for onshore,
steel, gas transmission pipelines that are
located in an HCA or MCA and meet
any of the conditions in § 192.624(a)(1)
through (a)(3). Verification of MAOP
includes establishing and documenting
MAOP if the pipeline MAOP was
established in accordance with
§ 192.619(c), the grandfather clause. In
addition, this NPRM proposes
requirements for verification of pipeline
material in accordance with new
§ 192.607 for existing onshore, steel, gas
transmission pipelines that are located
in an HCA or class 3 or class 4 locations.
Comments Submitted for Questions in
Topic N
N.1. Should PHMSA repeal
provisions in part 192 that allow use of
materials manufactured prior to 1970
and that do not otherwise meet all
requirements in part 192?
1. INGAA, supported by several
pipeline operators, suggested age, alone,
should not be a criterion for
determining fitness for service, noting
some pre-regulation materials (e.g.,
seamless pipe) are as good as today’s.
2. AGA, GPTC, and numerous
pipeline operators noted it is illogical to
storehouse pre-1970 materials for
installation now. AGA indicated that it
thus did not understand the purpose of
the ANPRM question.
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3. Iowa Utilities Board, NAPSR, Texas
Pipeline Association, Texas Oil & Gas
Association, Accufacts, Alaska
Department of Natural Resources,
Atmos, Commissioners of Wyoming
County Pennsylvania, Professional
Engineers in California Government,
and an anonymous commenter
encouraged repeal of this allowance.
Some of these commenters would allow
a specified time period for operators to
come into compliance.
4. Thomas Lael and MidAmerican
recommended operators be allowed to
continue use of materials that have
already been placed into service,
arguing that they have been
demonstrated safe through integrity
management.
5. Ameren Illinois and Northern
Natural Gas opposed repeal of this
provision.
Response to Question N.1 Comments
PHMSA appreciates the information
provided by the commenters. As stated
above, this NPRM proposes
requirements for verification of MAOP
in new § 192.624 for onshore, steel, gas
transmission pipelines that are located
in an HCA or MCA and meet any of the
conditions in § 192.624(a)(1) through
(a)(3). In addition, this NPRM proposes
requirements for verification of pipeline
material in accordance with new
§ 192.607 for existing onshore, steel, gas
transmission pipelines that are located
in an HCA or class 3 or class 4 locations.
N.2. Should PHMSA repeal the MAOP
exemption for pre-1970 pipelines?
Should pre-1970 pipelines that operate
above 72% SMYS be allowed to
continue to be operated at these levels
without increased safety evaluations
such as periodic pressure tests, in-line
inspections, coating examination, CP
surveys, and expanded requirements on
interference currents and depth of cover
maintenance?
1. INGAA and a number of pipeline
operators opposed repeal of this
exemption. INGAA suggested its Fitness
for Service protocol be used to assure
continued safety of old pipe.
2. AGA, GPTC, Texas Pipeline
Association, Texas Oil & Gas
Association and numerous pipeline
operators commented that the wording
of this question creates a false
impression. There is no exemption for
MAOP. Rather, the regulations establish
requirements for determining MAOP
and the only ‘‘exemption’’ is to a postconstruction hydrostatic test, since the
pipeline was in service at the time the
regulations became effective.
3. AGA, supported by several of its
pipeline operator members, contended
the appropriate method for verifying
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MAOP of older pipelines is for PHMSA
to follow Section 23 of the Pipeline
Safety, Regulatory Certainty, and Job
Creation Act of 2011. AGA opposed
eliminating § 192.619(c) for determining
MAOP of older pipelines, arguing that it
would cripple the nation’s gas pipeline
capacity. A number of additional
pipeline operators joined AGA in
opposing any new requirement to
pressure test all older pipelines, arguing
costs would be excessive and there
would be significant potential to
interrupt gas services. AGA included a
white paper with its comments
outlining its suggested approach to
MAOP verification.
4. Accufacts, Texas Pipeline
Association, and Texas Oil & Gas
Association opposed requiring all pre1970 pipelines to reduce MAOP, if
necessary, to a pressure that would
impose stresses no greater than 72
percent SMYS. Accufacts noted this
pipe is still safe at its current operating
pressure if it is managed properly, but
suggested a possible focus on interactive
threats that might make seam welds
unstable.
5. Ameren Illinois opposed modifying
MAOP requirements for pre-1970
pipelines.
6. NAPSR, the NTSB, and
Professional Engineers in California
Government supported repeal of
exemptions applying to MAOP of pre1970 pipelines. NAPSR added PHMSA
should not allow any pipeline to operate
at pressures above that which would
impose stresses greater than 72 percent
SMYS.
7. MidAmerican suggested use of a
performance-based approach, which
might include a fitness for service
determination for pipe in Class 2, 3, or
4 areas or HCA.
8. Commissioners of Wyoming County
Pennsylvania would support repeal of
MAOP exemptions because pipeline
infrastructure is aging and they see
additional safety measures needed.
Response to Question N.2 Comments
PHMSA appreciates the information
provided by the commenters. As stated
above, this NPRM proposes
requirements for verification of MAOP
in new § 192.624 for onshore, steel, gas
transmission pipelines that are located
in an HCA or MCA and meet any of the
conditions in § 192.624(a)(1) through
(a)(3). Verification of MAOP includes
establishing and documenting MAOP if
the pipeline segment: (1) Has
experienced a reportable in-service
incident, as defined in § 191.3, since its
most recent successful subpart J
pressure test, due to an original
manufacturing-related defect, a
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construction-, installation-, or
fabrication-related defect, or a crackingrelated defect, including, but not limited
to, seam cracking, girth weld cracking,
selective seam weld corrosion, hard
spot, or stress corrosion cracking and
the pipeline segment is located in one
of the following locations: (i) A high
consequence area as defined in
§ 192.903; (ii) a class 3 or class 4
location; or (iii) a moderate consequence
area as defined in § 192.3 if the pipe
segment can accommodate inspection
by means of instrumented inline
inspection tools (i.e., ‘‘smart pigs’’); (2)
Pressure test records necessary to
establish maximum allowable operating
pressure per subpart J for the pipeline
segment, including, but not limited to,
records required by § 192.517(a), are not
reliable, traceable, verifiable, and
complete and the pipeline segment is
located in one of the following
locations: (i) A high consequence area as
defined in § 192.903; or (ii) a class 3 or
class 4 location; or (3) the pipeline
segment maximum allowable operating
pressure was established in accordance
with § 192.619(c) of this subpart before
[effective date of rule] and is located in
one of the following areas:
(i) A high consequence area as
defined in § 192.903; (ii) a class 3 or
class 4 location; or (iii) a moderate
consequence area as defined in § 192.3
if the pipe segment can accommodate
inspection by means of instrumented
inline inspection tools (i.e., ‘‘smart
pigs’’).
N.3. Should PHMSA take any other
actions with respect to exempt
pipelines? Should pipelines that have
not been pressure tested in accordance
with subpart J be required to be pressure
tested in accordance with present
regulations?
1. AGA and a number of pipeline
operators opposed any requirement to
pressure test all pipelines that have not
been tested in accordance with subpart
J, arguing Congress considered and
rejected this approach in developing the
Pipeline Safety, Regulatory Certainty,
and Job Creation Act of 2011. The
commenters argue such a requirement
would cripple the pipeline industry and
support the alternative requirements
included in the Act.
2. MidAmerican suggests a focus on
pipe in Class 3 or 4 areas or HCAs. The
company suggests no new requirements
are needed if records are complete for
pipe in these areas or it has been tested
to 1.25 times MAOP. Otherwise,
MidAmerican would subject such
pipelines to a fitness for service
determination.
3. The NTSB would require all pre1970 pipelines to be pressure tested,
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including a spike test, citing their
recommendation P–11–14.
4. Texas Pipeline Association and
Texas Oil & Gas Association opposed a
requirement to test all pipelines not
previously subject to subpart J tests,
arguing testing per the construction
codes in effect when the pipelines were
constructed and safe operating
experience since then is adequate
assurance of suitability.
5. Ameren Illinois reported the State
of Illinois imposed pressure testing
requirements before federal pipeline
safety regulations were adopted in 1970.
6. Iowa Utilities Board and Iowa
Association of Municipal Utilities
recommended any new pressure test
requirement be limited to pipeline
segments in HCA and which operate at
pressures where a rupture could occur
(generally greater than 30 percent
SMYS). These commenters argued the
serious impacts of service interruptions
pressure testing would be necessary for
testing have not been appreciated and
the cost for such testing of other
pipelines would be unjustified absent
any specific demonstration of risk.
7. Commissioners of Wyoming County
Pennsylvania and Professional
Engineers in California Government
(PECG) would require pressure testing
for pipelines not previously tested to
subpart J requirements, since this would
assure public safety. PECG would also
require testing if adequate records of
prior tests do not exist, noting California
has experienced two failures to date of
pipeline not adequately tested. PECG
would also require all testing,
modification, and replacement be
observed by a certified inspector loyal to
public safety interests.
8. An anonymous commenter would
require subpart J testing but would
allow schedule flexibility.
Response to Question N.3 Comments
PHMSA appreciates the information
provided by the commenters. This
NPRM proposes requirements for
verification of MAOP in new § 192.624
for onshore, steel, gas transmission
pipelines that are located in an HCA or
MCA and meet any of the conditions in
§ 192.624(a)(1) through (a)(3).
Verification of MAOP includes
establishing and documenting MAOP
using one or more of the methods in
192.624(c)(1) through (c)(6). In addition,
this NPRM proposes requirements for
verification of pipeline material in new
§ 192.607 for existing onshore, steel, gas
transmission pipelines that are located
in an HCA or class 3 or class 4 locations.
N.4. If a pipeline has pipe with a
vintage history of systemic integrity
issues in areas such as longitudinal
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weld seams or steel quality, and has not
been pressure tested at or above 1.1
times MAOP or class location test
criteria (§§ 192.505, 192.619 and
192.620), should this pipeline be
required to be pressure tested in
accordance with present regulations?
1. AGA and several pipeline operators
opposed requiring hydrostatic tests for
systemic issues, arguing it could
potentially affect all pipelines. AGA
noted Congress had considered and
rejected this approach in developing the
Pipeline Safety, Regulatory Certainty,
and Job Creation Act of 2011. AGA
supports the requirements in Section 23
of the Act. AGA further argued hold
times in subpart J are excessive since
defects that fail will likely do so in the
first 30 minutes and urged PHMSA not
to require any special testing for
pipelines operating at less than 30
percent SMYS since they are likely to
fail by leakage rather than rupture.
2. GPTC and Nicor opposed a blanket
requirement for hydrostatic testing.
They would test only in event of a
demonstrated safety issue and only if a
risk evaluation indicates testing is
appropriate. For distribution operators,
these commenters would treat any
safety issues in distribution integrity
management programs.
3. Atmos would not require pressure
testing for systemic issues, arguing these
are addressed adequately by subpart O.
4. Accufacts would require testing,
focusing first on pipe in HCAs, at
pressures greater than 1.1 times MAOP.
Accufacts understands some operators
are arguing for a 1.1 x MAOP test
pressure and considers that to be
insufficient.
5. MidAmerican would allow a riskbased alternative approach for problem
pipe.
6. Texas Pipeline Association and
Texas Oil & Gas Association would
require assessments appropriate to a
specific threat rather than a blanket
requirement for pressure testing.
7. An anonymous commenter
supported pressure testing for pipe
subject to systemic issues.
Response to Question N.4 Comments
PHMSA appreciates the information
provided by the commenters. This
NPRM proposes requirements for
verification of MAOP in new § 192.624
for onshore, steel, gas transmission
pipelines that are located in an HCA or
MCA and meet any of the conditions in
§ 192.624(a)(1) through (a)(3).
N.5. If commenters suggest
modification to the existing regulatory
requirements, PHMSA requests that
commenters be as specific as possible.
In addition, PHMSA requests
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commenters to provide information and
supporting data related to:
• The potential costs of modifying the
existing regulatory requirements.
• The potential quantifiable safety
and societal benefits of modifying the
existing regulatory requirements.
• The potential impacts on small
businesses of modifying the existing
regulatory requirements.
• The potential environmental
impacts of modifying the existing
regulatory requirements.
No comments were received in
response to this question.
O. Modifying the Regulation of Gas
Gathering Lines
The ANPRM requested comments
regarding modifying the regulations
relative to gas gathering lines. In March
2006, PHMSA issued new safety
requirements for ‘‘regulated onshore
gathering lines.’’ 38 Those requirements
established a new method for
determining if a pipeline is an onshore
gathering line, divided regulated
onshore gas gathering lines into two
risk-based categories (Type A and Type
B), and subjected such lines to certain
safety standards.
The 2006 rule defined onshore gas
gathering lines based on the provisions
in American Petroleum Institute
Recommended Practice 80, ‘‘Guidelines
for the Definition of Onshore Gas
Gathering Lines,’’ (API RP 80), a
consensus industry standard
incorporated by reference. Additional
regulatory requirements for determining
the beginning and endpoints of
gathering, modifying the application of
API RP 80, were also imposed to
improve clarity and consistency in their
application.
In practice, however, the use of API
RP 80, even as modified by the
additional regulations, is difficult for
operators to apply consistently to
complex gathering system
configurations. Enforcement of the
current requirements has been
hampered by the conflicting and
ambiguous language of API RP 80, a
complex standard that can produce
multiple classifications for the same
pipeline system, which can lead to the
potential misapplication of the
incidental gathering line designation
under that standard. In addition, recent
developments in the field of gas
exploration and production, such as
shale gas, indicate that the existing
framework for regulating gas gathering
lines may need to be expanded.
Gathering lines are being constructed to
transport ‘‘shale’’ gas that range from 4
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20801
to 36 inches in diameter with MAOPs
up to 1480 psig, far exceeding the
historical operating parameters
(pressure and diameter). The risks
considered during the development of
the 2006 rule did not foresee gathering
lines of these diameters and pressures.
Currently, according to 2011 annual
reports submitted by pipeline operators,
PHMSA only regulates about 8845 miles
of Type A gathering lines, 5178 miles of
Type B gathering lines, and about 6258
miles of offshore gathering lines, for a
total of approximately 20,281 miles of
regulated gas gathering pipelines. Gas
gathering lines are currently not
regulated if they are in Class 1 locations.
Current estimates also indicate that
there are approximately 132,500 miles
of Type A gas gathering lines located in
Class 1 areas (of which approximately
61,000 miles are estimated to be 8-inch
diameter or greater), and approximately
106,000 miles of Type B gas gathering
lines located in Class 1 areas. Also,
there are approximately 2,300 miles of
Type B gas gathering lines located in
Class 2 areas, some of which may not be
regulated in accordance with
§ 192.8(b)(2).
The ANPRM then listed questions for
consideration and comment. The
following are general comments
received related to this topic as well as
comments related to the specific
questions:
General Comments for Topic O
1. Gas Processors Association (GPA)
recommended PHMSA complete the
study required by Section 21 of the
Pipeline Safety, Regulatory Certainty,
and Job Creation Act of 2011 before
proposing any substantive regulations
regarding gathering lines. The
Association sees this as an essential prerequisite and indicated it would
establish a working group to work with
PHMSA on the study. Following the
study, GPA would then have PHMSA
begin any rulemaking process with
another ANPRM, focused on the issues
to be addressed in changing regulation
of gathering lines. Independent
Petroleum Association of America,
American Petroleum Institute,
Oklahoma Independent Petroleum
Association, and Chevron agreed any
change to gathering line regulations
before the required report to Congress
would be inconsistent with the Act.
2. Independent Petroleum Association
of America, American Petroleum
Institute, Oklahoma Independent
Petroleum Association, and Chevron
argued no change in the gathering line
regulatory regime is justified. IPAA and
API argued gathering lines can be
regulated based only on actual, vs.
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speculative, risk, and that any change
without such demonstrated risk would
be arbitrary, capricious, and contrary to
law.
3. Atmos would require new gathering
lines operating above 20 percent SMYS
to meet requirements in § 192.9(c), and
those below 20 percent SMYS
§ 192.9(d). These paragraphs are,
respectively, requirements applicable to
Type A and Type B gathering lines. The
‘‘type’’ of a gathering line is established
in accordance with requirements in
§ 192.8, and is based on the pipe
material and MAOP of the line. Atmos
argued, however, that class location
changes over time and determining
applicable requirements for new
gathering lines based on stress levels
would provide for public safety without
the problems or confusion that could
result from subsequent class location
changes.
4. Texas Pipeline Association and
Texas Oil & Gas Association suggested
PHMSA treat gathering lines under a
separate docket and collect data under
the current regulatory regime before
making any changes. The associations
suggested a delay in rulemaking of 3 to
5 years to accumulate data from
recently-promulgated changes in
reporting requirements. The
associations argued changes made
without gathering and reviewing that
data could be found unnecessary and
would divert resources from higher risk
needs. Atmos agreed any rulemaking
concerning gathering lines should be
conducted under a separate docket due
to the complexity of the issues involved.
5. Dominion East Ohio Gas argued it
is too soon for wholesale changes to the
new federal regulations applicable to
gas gathering lines. The company
suggested one proposed change would
be to consider ‘‘Incidental Gathering’’ as
defined in API RP 80.
6. NAPSR and Commissioners of
Wyoming County Pennsylvania
suggested PHMSA assert regulatory
authority beginning at the wellhead or
first metering point. They argued the
regulatory gap that results from
excluding production facilities from
regulation produces risks, especially in
areas where high-pressure wells are
being drilled in urban areas. NAPSR
further stated that PHMSA should
consider short sections of pipeline
downstream of processing, compression,
and similar equipment to be a
continuation of gathering. The
functional name of a segment of
pipeline is not important, i.e.,
production, gathering, transmission. All
pipelines should be treated the same in
terms of safety from the well head to the
city gate.
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7. Commissioners of Wyoming County
Pennsylvania recommended PHMSA
regulate gathering lines in Class 1 areas.
The Commissioners noted many new
gathering lines, some operating at high
pressures, are being constructed in Class
1 areas of the Marcellus Shale Region,
and regulation of these lines is
necessary to ensure public safety. The
Commissioners noted Pennsylvania law
gives the state’s public utilities
commission authority to regulate
pipelines but requires that they be no
more stringent than federal regulations.
8. The League of Women Voters of
Pennsylvania would regulate gathering
lines in the same manner as
transmission and would further require
that gas in pipelines of both types be
odorized.
9. Pipeline Safety Trust would have
PHMSA assure gathering lines are
displayed on the National Pipeline
Mapping System.
Response to General Comments for
Topic O
PHMSA appreciates the information
provided by the commenters. The
commenters are correct that the Act
required several actions related to gas
gathering lines including a requirement
that a study to be conducted prior to
issuing new rules. We would note,
however, that PHMSA is only
proceeding with the issuance of an
NPRM proposing expanded
requirements and needed clarity with
regard to issues that had been identified
prior to enactment of the Act. The study
has been completed and submitted to
Congress and placed on the docket.
PHMSA invites public comment on the
study, which will inform the final rule.
In addition, recent developments in the
field of gas exploration and production,
such as shale gas, indicate that the
existing framework for regulating gas
gathering lines may need to be
expanded. Gathering lines are being
constructed to transport ‘‘shale’’ gas that
range from 4 to 36 inches in diameter
with MAOPs up to 1,480 psig, far
exceeding the historical operating
parameters of such lines.
Currently, according to 2011 annual
reports submitted by pipeline operators,
PHMSA only regulates about 8845 miles
of Type A gathering lines, 5,178 miles
of Type B gathering lines, and about
6,258 miles of offshore gathering lines,
for a total of approximately 20,281 miles
of regulated gas gathering pipelines. Gas
gathering lines are currently not
regulated if they are in Class 1 locations.
Current estimates also indicate that
there are approximately 132,500 miles
of Type A gas gathering lines located in
Class 1 areas, and approximately
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106,000 miles of Type B gas gathering
lines located in Class 1 areas. Also,
there are approximately 2,300 miles of
Type B gas gathering lines located in
Class 2 areas, some of which may not be
regulated in accordance with
§ 192.8(b)(2).
Moreover, enforcement of the current
requirements has been hampered by the
conflicting and ambiguous language of
API RP 80, a complex standard that can
produce multiple classifications for the
same pipeline system because numerous
factors are involved, including the
locations of treatment facilities,
processing plants, and compressors, the
relative spacing of production fields,
and the commingling of gas. This can
lead to the potential misapplication of
the incidental gathering line designation
under that standard.
In this NPRM, PHMSA proposes to
extend existing requirements for Type B
gathering lines to Type A gathering lines
in Class 1 locations, if the nominal
diameter is 8’’ or greater.
Comments submitted for questions in
Topic O.
O.1. Should PHMSA amend 49 CFR
part 191 to require the submission of
annual, incident, and safety-related
conditions reports by the operators of all
gathering lines?
1. AGA, GPTC, Texas Pipeline
Association, Texas Oil & Gas
Association, and several pipeline
operators opposed requiring annual
reports for unregulated gas gathering
pipelines, arguing such a requirement
would be unduly burdensome with no
safety benefit. These commenters agreed
incident reports for unregulated
gathering lines could be useful as a
means to determine the effectiveness of
safety practices on these pipelines.
2. Gas Producers Association opposed
expanding reporting requirements to
Class 1 gathering pipelines. The
Association noted gathering lines in
other class locations are currently
subject to reporting requirements and
suggested there were other means for
PHMSA to collect data on Class 1 lines
without requiring burdensome
reporting. In the specific case of safetyrelated condition reports, the
Association argued requiring reporting
is clearly premature, because the
purpose of these reports is to highlight
problems in which PHMSA may elect to
become involved and PHMSA presently
does not regulate these pipelines.
3. Texas Pipeline Association and
Texas Oil & Gas Association would
support requiring incidents to be
reported for all gathering pipelines as a
first step in collecting data to determine
whether other changes are needed.
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4. Atmos would support limited
reporting for Class 1 gathering lines, to
include incidents and total mileage.
5. NAPSR, Alaska Department of
Natural Resources, Pipeline Safety
Trust, and Commissioners of Wyoming
County Pennsylvania would require
operators of Class 1 gathering pipelines
to submit reports, because these
pipelines can affect public safety and
should be held accountable.
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Response to Question O.1 Comments
PHMSA appreciates the information
provided by the commenters. The
comments provide varied support for
requiring submission of annual,
incident, and safety-related conditions
reports by the operators of all gathering
lines. PHMSA believes these reports
would provide valuable information,
combined with the results of the
congressionally required study, to
support evaluation of the effectiveness
of safety practices on these pipelines
and determination of any needed
additional requirements beyond those
proposed in this NPRM. Accordingly,
PHMSA proposes to delete the
exemption for reporting requirements
for operators of unregulated onshore gas
gathering lines.
O.2. Should PHMSA amend 49 CFR
part 192 to include a new definition for
the term ‘‘gathering line’’?
1. AGA and several pipeline operators
opposed a change to the definition of
gathering lines, noting API RP–80, with
restrictions as specified in current
regulations, is a good working
definition.
2. Independent Petroleum Association
of America, American Petroleum
Institute, Oklahoma Independent
Petroleum Association, Atmos, and
Chevron argued that API RP 80, as
currently specified, is the appropriate
means for defining gathering lines. They
argued it is based on a pipeline’s
function rather than its location and
changes could infringe on production
facilities, regulation of which is
precluded by statute.
3. Gas Processors Association
opposed changing the definition of
gathering line or extending regulation to
lines in Class 1 areas. The Association
noted excluding Class 1 lines from
regulation is risk-based and expressed
its interest in continuing the risk-based
approach to regulation represented by
the 2006 rule.
4. NAPSR, GPTC, Accufacts, Thomas
Lael, and Nicor supported simplifying
the definition of gathering lines. These
commenters noted that API RP–80 is
confusing. One commenter referred to
its application as a ‘‘nightmare.’’ The
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definition in Texas regulations was
suggested as one possible model.
5. Oklahoma Independent Petroleum
Association strongly opposed changes to
the definitions of gathering line or
production facilities.
6. Texas Pipeline Association and
Texas Oil & Gas Association would not
change the definition of gathering lines
at this time, arguing data gathering, a
necessary first step, is not yet complete.
7. The State of Washington Citizens
Advisory Committee and a private
citizen urged changes to the definitions
of gathering, transmission, and
distribution pipelines, arguing that the
current definitions are confusing and
employ circular logic.
8. Pipeline Safety Trust would revise
the definition of gathering in a manner
that does not allow operators to choose
whether their pipeline is gathering or
not on the basis of where they decide to
install equipment. PST noted there is
significant overlap among pipeline
types in size, operating pressure, and
attendant risks.
9. Alaska Department of Natural
Resources and Commissioners of
Wyoming County Pennsylvania urged a
revision to the definition of gathering
lines, in light of shale gas development
which, the commenters contended,
produces risks approximately
equivalent to those from transmission
pipelines.
Response to Question O.2 Comments
PHMSA appreciates the information
provided by the commenters. Industry
commenters opposed a change to the
definition of gathering lines, whereas
NAPSR and other commenters
supported revision of the definition of
gathering lines and classified API RP–80
as confusing. As discussed above,
PHMSA believes revision of the
definition of gathering lines is needed
and also proposes a new definition for
onshore production facility/operation.
In addition, see response to question
O.3 comments.
O.3. Are there any difficulties in
applying the definitions contained in RP
80? If so, please explain.
1. Independent Petroleum Association
of America, American Petroleum
Institute, Oklahoma Independent
Petroleum Association, and Chevron
were emphatic in declaring there are no
difficulties in applying API RP–80.
IPAA and API noted that significant
difficulties among gathering lines made
RP–80 difficult to develop.
2. AGA and a number of pipeline
operators reported RP–80 is clear and
there are no difficulties with its
application.
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3. Gas Processors Association would
retain the RP–80 definition, at least
until the study required by the Act is
completed. GPA acknowledged that
application of RP–80 has been difficult,
but stated that it has been difficult to
craft a simpler definition.
4. Texas Pipeline Association and
Texas Oil & Gas Association reported
application of RP–80 has been
challenging. The associations opined
this has resulted from complexities in
gathering pipeline systems and
confusion caused by PHMSA guidance
and interpretations.
5. Accufacts, NAPSR, GPTC, and
Nicor commented RP–80 is too
complex, not understandable to the
public, and subject to misuse by
operators.
Response to Question O.3 Comments
PHMSA appreciates the information
provided by the commenters. Industry
commenters stated there are no
difficulties in applying the definitions
contained in API RP 80, whereas
Accufacts, NAPSR and other
commenters contend that API RP 80 is
too complex, not understandable, and
subject to misuse. PHMSA enforcement
of the current requirements has been
hampered by the conflicting and
ambiguous language of API RP 80,
which is complex and can produce
multiple classifications for the same
pipeline system. In the 2006 rulemaking
which incorporated by reference the API
RP 80, PHMSA expressed reservations
concerning the ability to effectively and
consistently apply the document as
written, echoing NAPSR’s comments at
the time. Additionally, in 2006, PHMSA
imposed limiting regulatory language in
part 192 in an attempt to curtail the
potential for misapplication of the
language contained in RP–80. These
limitations and their intended
application were discussed in great
detail in the Supplemental Notice of
Proposed Rulemaking [Docket No.
RSPA–1998–4868; Notice 5]. Because of
the ambiguous language and
terminology in the RP–80, e.g.
separators are defined for both
production and gathering almost
verbatim, experience has shown that
facilities are being classified as
production much further downstream
than was ever intended. The application
of ‘‘incidental gathering’’ as used in API
RP–80 has not been applied as intended
in some cases. Several recent
interpretations letters have been issued
by PHMSA on this topic including an
expressed intent to clarify the issue in
future rulemaking. Therefore, PHMSA
believes revision of the definition of
gathering lines is needed and proposes
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deleting the use of API RP 80 as the
basis for determining regulated
gathering lines and would establish the
new definition for onshore production
facility/operation and a revised
definition for gathering line as the basis
for determining the beginning and
endpoints of each gathering line.
O.4. Should PHMSA consider
establishing a new, risk-based regime of
safety requirements for large-diameter,
high-pressure gas gathering lines in
rural locations? If so, what requirements
should be imposed?
1. Commissioners of Wyoming County
Pennsylvania and 24 private citizens
encouraged PHMSA to regulate
gathering lines in Class 1 locations. The
commenters noted many such pipelines
will exist in shale gas areas, many of
them large-diameter and operating at
high pressures, and contended these
pipelines currently are being ignored by
federal and state regulators. They noted
the pipeline that ruptured causing the
San Bruno accident was operated at a
pressure considerably lower than some
gathering lines in shale gas areas.
2. AGA, GPTC, and a number of
pipeline operators argued no new
requirements are needed and the
effectiveness of the 2006 changes to
regulation needs to be reviewed first, in
accordance with the Act.
3. Gas Processors Association, Texas
Pipeline Association, and Texas Oil &
Gas Association contended PHMSA
must gather additional data on Class 1
gathering lines before deciding whether
to regulate them, arguing that only a
detailed study can determine whether
new regulations are appropriate.
4. Oklahoma Independent Petroleum
Association cautioned any regulatory
change needs to be supported by science
and a comprehensive cost-benefit
analysis.
5. Independent Petroleum Association
of America, American Petroleum
Institute, Oklahoma Independent
Petroleum Association, and Chevron
argued any change in the regulatory
regime for gathering lines is unjustified.
The commenters contended such lines
only operate at high pressures when
new, that pressure decreases as wells
deplete, and that the record shows these
lines are safe.
6. A private citizen who operates an
outdoor gear supply business in a shale
gas region argued reduced use of
recreational areas, caused by concerns
over nearby pipelines, will adversely
impact his and similar businesses.
7. Alaska Department of Natural
Resources would establish risk-based
safety requirements for gathering
pipelines.
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8. NAPSR would establish new,
prescriptive requirements for largediameter, high-pressure gathering lines.
9. Pipeline Safety Trust argued the
composition of gas carried in many
gathering lines leads to increased risk of
corrosion and additional corrosion and
testing requirements should thus be
considered.
10. A private citizen, arguing for
regulation of Class 1 gathering lines,
noted experience has shown Class 1
locations change to Class 2 or 3
locations while the pipeline remains
unchanged and, the commenter
contended, unsafe.
11. Pipeline Safety Trust, Accufacts,
and NAPSR would regulate gathering
lines the same as transmission
pipelines. PST would include integrity
management requirements for lines
operating at greater than 20 percent
SMYS. NAPSR would impose IM if
greater than 30 percent SMYS.
12. ITT Exelis Geospatial Systems
contended that safety criteria applicable
to a pipeline should be based on the
specifications of the line.
Response to Question O.4 Comments
PHMSA appreciates the information
provided by the commenters. The
comments provide varied opinions for
establishing new, risk-based safety
requirements for gas gathering lines in
rural locations. Several comments
recommended PHMSA gather additional
data on gathering lines before deciding
to issue revised regulations. PHMSA
believes rulemaking should proceed
now to address the identified issues
with regulation of gathering lines.
Therefore, PHMSA proposes to extend
existing requirements for Type B
gathering lines to Type A gathering lines
in Class 1 locations, if the nominal
diameter is 8″ or greater. Integrity
management requirements would not be
applied to gathering lines at this time.
O.5. Should PHMSA consider short
sections of pipeline downstream of
processing, compression, and similar
equipment to be a continuation of
gathering? If so, what are the
appropriate risk factors that should be
considered in defining the scope of that
limitation (e.g., doesn’t leave the
operator’s property, not longer than
1000 feet, crosses no public rights of
way)?
1. The AGA, the GPTC, and a number
of pipeline operators suggested that the
piping mentioned in O.5 be considered
as gathering. The commenters
contended that this is clearly
‘‘incidental gathering’’ in API RP–80,
particularly if below 20 percent SMYS,
and that some agencies are presently
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treating this pipeline inappropriately as
transmission pipeline.
2. Oleksa and Associates contended
that the types of pipeline described in
the question are ‘‘incidental gathering.’’
Oleksa argued that the length of these
pipeline sections should not be the
determining factor in their definition
but, rather, risk elements and public
safety impact should be afforded more
importance.
3. The Gas Processors Association, the
Texas Pipeline Association, and the
Texas Oil & Gas Association would
continue to treat these types of pipelines
as gathering. They argued that this
reflects the practical realities in the field
regarding the ability to locate gatheringrelated equipment. GPA urged PHMSA
to retain the concept of incidental
gathering in any future change to the
regulations, arguing this would continue
a consistent regulatory approach to
gathering pipelines.
4. The Independent Petroleum
Association of America, the American
Petroleum Institute, the Oklahoma
Independent Petroleum Association,
and Chevron contended that the safety
record in the Barnett Shale area
demonstrates further regulation of
downstream pipelines and compression
is not needed.
5. Commissioners of Wyoming County
Pennsylvania would treat gathering
lines as transmission lines, arguing that
this would preclude the need to answer
any of these questions.
6. The Delaware Solid Waste
Authority (DSWA) argued for the
continued treatment of the listed
pipeline sections as part of gathering for
landfill gas operations. DSWA noted
that landfills may use intermediate
compression to improve collection
efficiency and may have pipe at
pressure leading to flares etc.
7. Waste Management contended that
piping that is an active part of a landfill
gas collection and control system
should be exempt from regulation as
this piping is generally on landfill
property and poses no risk to the public.
8. The National Solid Waste
Management Association and Waste
Management supported PHMSA’s
interpretation that pipelines operating at
vacuum, such as landfill systems up to
the compressor/blower should be
unregulated.
Response to Question O.5 Comments
PHMSA appreciates the information
provided by the commenters. See
PHMSA’s response to Question O.3,
above.
O.6. Should PHMSA consider
adopting specific requirements for
pipelines associated with landfill gas
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systems? If so, what regulations should
be adopted and why? Should PHMSA
consider adding regulations to address
the risks associated with landfill gas
that contains higher concentrations of
hydrogen sulfide and/or carbon
dioxide?
1. The AGA, the GPTC, and a number
of pipeline operators contended that
RP–80 makes clear that these pipelines
are production piping and therefore
regulation is prohibited. In addition,
they argued that risk doesn’t justify
regulating these lines; the situation is
similar to production and is already
managed well. They also noted that
landfill systems are generally
constructed with non-corrosive
materials. The commenters agreed that
piping from landfills to transmission or
distribution pipelines is gathering and
should be regulated.
2. Oleksa and Associates contended
that landfill pipelines are distribution
pipelines, if they carry gas to end use
customers.
3. The APGA argued that new
requirements are appropriate, as landfill
gas is different from natural gas. The
APGA contended that application of
current regulations often produces
absurd results. APGA would add new
requirements applicable to systems with
high concentrations of hydrogen sulfide
and allow systems with low
concentrations to use current
requirements.
4. The Delaware Solid Waste
Authority argued that no new
requirements are needed, because these
systems operate at low pressures and
existing requirements are sufficient.
5. NAPSR encouraged that PHMSA
establish jurisdiction over and
requirements for landfill gas systems,
arguing that many operate as
distribution pipelines. NAPSR also
recommended that PHMSA develop
requirements for odorizing landfill gas,
since normal methods cannot be used.
6. The National Solid Waste
Management Association and Waste
Management argued that landfill gas
lines under the control of a landfill
operator or gas developer should remain
unregulated because they pose minimal
risk. They also contended that lines
delivering landfill gas to distant users
should also remain unregulated because
they are mostly buried, are generally
constructed of plastic pipe, and pose
low risk due to low pressure, their
dedicated nature, and lack of
interconnects.
7. The National Solid Waste
Management Association (NSWMA)
noted that these pipelines are already
regulated by the EPA and the states and
argued that additional regulation would
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confer limited additional benefits.
NSWMA argued that no requirements
are needed to address internal
corrosion, because these pipeline
systems are generally constructed of
plastic pipe and corrosive gas
constituents are limited to prevent
destruction of gas processing
equipment. NSWMA suggested that
PHMSA work with the EPA to obtain
data on the landfill experience needed
to support any future decision to
regulate in this area.
8. Oleksa and Associates and the
Delaware Solid Waste Authority would
have PHMSA modify the regulations to
clarify that pipe downstream of
intermediate compression is
unregulated, even if at pressure. They
argued that the EPA has regulated such
pipelines successfully and there is no
safety case for applying part 192. DSWA
further notes that most landfill pipeline
is constructed of plastic pipe and not
subject to internal corrosion.
9. Oleksa and Associates, the GPTC,
Nicor, Waste Management, and the
Delaware Solid Waste Authority would
exempt landfill gas systems from
requirements for odorization and odor
sampling. They argued that there is a
strong odor inherent to landfill gas, the
sampling of which is not practical.
Response to Question O.6 Comments
PHMSA appreciates the information
provided by the commenters. PHMSA is
not proposing rulemaking to address
landfill gas systems at this time, but
would note that a pipeline that
transports landfill gas away from the
landfill facility to another destination is
transporting gas. PHMSA will consider
comments on this aspect of Topic O in
the future.
O.7. Internal corrosion is an elevated
threat to gathering systems due to the
composition of the gas transported.
Should PHMSA enhance its
requirements for internal corrosion
control for gathering pipelines? Should
this include required cleaning on a
periodic basis?
1. AGA, GPTC, and a number of
pipeline operators commented that new
requirements are not needed. They
argued existing part 192 requirements
are adequate for internal corrosion
protection and unregulated gathering
lines are rural and pose little risk.
2. AGA and a number of pipeline
operators opposed a requirement for
periodic cleaning of gathering lines.
They noted existing lines are not
configured to accommodate cleaning
pigs and retrofitting them would be a
major cost with no safety benefit.
3. Gas Producers Association noted
internal corrosion is only one of many
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threats, existing regulations are
adequate, and thus no new requirements
are needed.
4. Texas Pipeline Association and
Texas Oil & Gas Association opposed
establishing internal corrosion
requirements for gathering pipelines.
The associations noted risk from IC is
not prevalent for many gathering
pipelines and suggested the need to
collect data (e.g., incidents) to
determine whether new requirements
are needed.
5. Accufacts would require, as a
minimum, use of cleaning pigs and
analysis of removed materials.
6. NAPSR, Alaska Department of
Natural Resources, and Commissioners
of Wyoming County Pennsylvania
would enhance internal corrosion
requirements and require periodic
cleaning.
Response to Question O.7 Comments
PHMSA appreciates the information
provided by the commenters. The
majority of comments do not support
enhancement of requirements for
internal corrosion control for gathering
pipelines. PHMSA is not proposing
rulemaking specifically to address the
need for additional internal corrosion
requirements for gathering lines at this
time. However, the proposed
requirements in subpart I applicable to
transmission lines; except the
requirements in §§ 192.461(f),
192.465(f), 192.473(c) and 192.478,
would be applicable to regulated Type
A onshore gathering lines.
O.8. Should PHMSA apply its Gas
Integrity Management Requirements to
onshore gas gathering lines? If so, to
what extent should those regulations be
applied and why?
1. The AGA and several pipeline
operators suggested that PHMSA
consider applying some IM
requirements to Type A gathering lines,
since these lines represent conditions
and risks similar to transmission
pipelines. They consider IM
inappropriate for Type B gathering
lines, since these lines pose low risk
and operate at hoop stresses similar to
distribution pipelines.
2. The Gas Producers Association, the
Texas Pipeline Association, the Texas
Oil & Gas Association, and Atmos
argued that it would be inappropriate to
apply integrity management
requirements to gathering pipelines.
They noted that IM is a risk-based
approach and that there is no evidence
that gathering pipelines pose a risk that
justifies application of IM.
3. The GPTC and Nicor opined that
extending some aspects of gas
transmission IM to non-rural, metallic
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Type A gathering lines could provide
enhanced protection to the public, since
the operation and risk of these pipelines
is similar to transmission pipelines.
They cautioned, however, that the costs
to impose IM on gathering pipelines
would be significant. They considered
IM inappropriate for Type B gathering
lines since these lines are, by definition,
of lower pressure and lower risk.
4. The Commissioners of Wyoming
County Pennsylvania would apply IM to
all onshore gathering pipelines. They
would also apply requirements
applicable to Class 2 transmission
pipelines to Class 1 gathering pipelines,
arguing that Class 1 areas will grow and
class location will change.
5. Accufacts and the Alaska
Department of Natural Resources would
apply IM to gathering lines. Accufacts
suggested an initial focus on largediameter, high-pressure lines, since
these lines are subject to failure by
rupture.
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Response to Question O.8 Comments
PHMSA appreciates the information
provided by the commenters. PHMSA
does not propose rulemaking to apply
integrity management requirements to
gathering lines at this time.
O.9. If commenters suggest
modification to the existing regulatory
requirements, PHMSA requests that
commenters be as specific as possible.
In addition, PHMSA requests
commenters to provide information and
supporting data related to:
• The potential costs of modifying the
existing regulatory requirements.
• The potential quantifiable safety
and societal benefits of modifying the
existing regulatory requirements.
• The potential impacts on small
businesses of modifying the existing
regulatory requirements.
• The potential environmental
impacts of modifying the existing
regulatory requirements.
No comments were received in
response to this question.
IV. Other Proposals
Inspection of Pipelines Following
Extreme Weather Events.
Pipeline regulation prescribes
requirements for the surveillance and
periodic patrolling of the pipeline to
observe surface conditions on and
adjacent to the transmission line rightof-way for indications of leaks,
construction activity, and other factors
affecting safety and operation, including
unusual operating and maintenance
conditions. The probable cause of the
2011 hazardous liquid pipeline accident
resulting in a crude oil spill into the
Yellowstone River near Laurel,
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Montana, is scouring at a river crossing
due to flooding. This is a recent
example of extreme weather that
resulted in a pipeline incident. PHMSA
has determined that additional
regulations are needed to require, and
establish standards for, the inspection of
the pipeline and right-of-way for ‘‘other
factors affecting safety and operation’’
following an extreme weather event
such as a hurricane or flood, landslide,
an earthquake, a natural disaster, or
other similar event. The proposed rule
would add a new paragraph (c) to
section 192.613 to require such
inspections, specify the timeframe in
which such inspections should
commence, and specify the appropriate
remedial actions that must be taken to
ensure safe pipeline operations. The
new paragraph (c) would apply to
onshore pipelines and their rights-ofway.
Notification for 7-Year Reassessment
Interval Extension.
Section 5 of the Act identifies a
technical correction amending Section
60109(c)(3)(B) of Title 49 of the United
States Code to allow the Secretary of
Transportation to extend the 7-year
reassessment interval for an additional 6
months if the operator submits written
notice to the Secretary justifying the
need for the extension. PHMSA
proposes to codify this statutory
requirement.
Reporting Exceedances of Maximum
Allowable Operating Pressure.
Section 23 of the Act requires
operators to report each exceedance of
the maximum allowable operating
pressure (MAOP) that exceeds the
margin (build-up) allowed for operation
of pressure-limiting or control devices.
PHMSA proposes to codify this
statutory requirement.
Consideration of Seismicity.
Section 29 of the Act states that in
identifying and evaluating all potential
threats to each pipeline segment, an
operator of a pipeline facility must
consider the seismicity of the area.
PHMSA proposes to codify this
statutory requirement to explicitly
reference seismicity for data gathering
and integration, threat identification,
and implementation of preventive and
mitigative measures.
Safety Features for In-line Inspection
(ILI), Scraper, and Sphere Facilities.
PHMSA is proposing to add explicit
requirements for safety features on
launchers and receivers associated with
ILI, scraper and sphere facilities.
Consensus Standards for Pipeline
Assessments.
PHMSA is proposing to incorporate
by reference consensus standards for
assessing the physical condition of in-
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service pipelines using in-line
inspection, internal corrosion direct
assessment, and stress corrosion
cracking direct assessment.
V. Section-by-Section Analysis
§ 191.1 Scope.
Section 191.1 prescribes requirements
for the reporting of incidents, safetyrelated conditions, and annual pipeline
summary data by operators of gas
pipeline facilities. Currently, onshore
gas gathering pipelines are exempt from
reporting, as specified in paragraph
(b)(4) of this section. In March 2012, the
Government Accountability Office
(GAO) issued a report (GAO–12–388)
that contained a recommendation for
DOT to collect data on federally
unregulated hazardous liquid and gas
gathering pipelines. PHMSA has
determined that the statute requires the
collection of additional information
about gathering lines and that these
reports and the congressionally required
study support evaluation of the
effectiveness of safety practices on these
pipelines. Furthermore, PHMSA has
inquired into whether any additional
requirements are needed beyond those
proposed in this NPRM. Accordingly,
the proposed rule would repeal the
exemption for reporting requirements
for operators of unregulated onshore gas
gathering lines by deleting § 191.1(b)(4),
adding a new § 191.1(c), and making
other conforming editorial amendments.
In addition, Section 23 of the Act
requires PHMSA to promulgate rules
that require operators to report each
exceedance of the maximum allowable
operating pressure (MAOP) that exceeds
the margin (build-up) allowed for
operation of pressure-limiting or control
devices. The proposed rule would
amend 191.1 to include MAOP
exceedances within the scope of part
191.
§ 191.23 Reporting safety-related
conditions.
Section 23 of the Act requires
operators to report each exceedance of
the maximum allowable operating
pressure (MAOP) that exceeds the
margin (build-up) allowed for operation
of pressure-limiting or control devices.
On December 21, 2012, PHMSA
published advisory bulletin ADB–2012–
11, which advised operators of their
responsibility under Section 23 of the
Act to report such exceedances. PHMSA
proposes to revise § 191.23 to codify this
requirement.
§ 191.25 Filing safety-related
condition reports.
Section 23 of the Act requires
operators to report each exceedance of
the maximum allowable operating
pressure (MAOP) that exceeds the
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margin (build-up) allowed for operation
of pressure-limiting or control devices.
As described above, PHMSA proposes
to revise § 191.23 to codify this
requirement. Section 191.25 would also
be revised to provide consistent
procedure, format, and structure for
filing of such reports by all operators.
§ 192.3 Definitions.
Section 192.3 provides definitions for
various terms used throughout part 192.
In support of other regulations proposed
in this NPRM, PHMSA is proposing to
amend the definitions of ‘‘Electrical
survey,’’ ‘‘(Onshore) gathering line,’’ and
‘‘Transmission line,’’ and add new
definitions for ‘‘Close interval survey,’’
‘‘Distribution center, ’’ ‘‘Dry gas or dry
natural gas,’’ ‘‘Gas processing plant,’’
‘‘Gas treatment facility,’’ ‘‘Hard spot,’’
‘‘In-line inspection (ILI),’’ ‘‘In-line
inspection tool or instrumented internal
inspection device,’’ ‘‘Legacy
construction technique,’’ ‘‘Legacy pipe,’’
‘‘Moderate consequence area,’’ ‘‘Modern
pipe,’’ ‘‘Occupied site,’’ ‘‘Onshore
production facility or onshore
production operation,’’ ‘‘Significant
Seam Cracking,’’ ‘‘Significant Stress
Corrosion Cracking,’’ and ‘‘Wrinkle
bend.’’ These changes will define these
terms as used in the proposed changes
to part 192. Many of the terms (such as
in-line inspection, dry gas, hard spot,
etc.) clarify technical definitions of
terms used in part 192 or proposed in
this rulemaking.
The revised definition for ‘‘(Onshore)
gathering line,’’ and the new definitions
for ‘‘Gas processing plant,’’ ‘‘Gas
treatment facility,’’ and ‘‘Onshore
production facility or onshore
production operation,’’ are necessary
because of ambiguous language and
terminology in the current definition of
regulated gas gathering lines, which
invoke by reference API RP–80. The
application of ‘‘incidental gathering’’ as
used in API RP–80 has not been applied
as intended in some cases. Several
recent interpretation letters have been
issued by PHMSA on this topic
including an expressed intent to clarify
the issue in future rulemaking.
Therefore, PHMSA believes revision of
the definition of gathering lines is
needed and proposes repealing the use
of API RP 80 as the basis for
determining regulated gathering lines
and would establish the new definition
for ‘‘onshore production facility/
operation, gas treatment facility, and
gas processing plant,’’ and a revised
definition for ‘‘(onshore) gathering line’’
as the basis for determining the
beginning and endpoints of each
gathering line.
The revised definition for ‘‘Electrical
survey’’ aligns with the amended
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definition recommended in a petition
dated March 26, 2012, from the Gas
Piping Technology Committee (GPTC).
With regard to the new terms
‘‘moderate consequence area’’ or MCA,
and ‘‘occupied site,’’ the definitions are
based on the same methodology as
‘‘high consequence area’’ and
‘‘identified site’’ as defined in § 192.903.
Moderate consequence areas will be
used to define the subset of non-HCA
locations where integrity assessments
are required (§ 192.710), where material
documentation verification is required
(§ 192.607), and where MAOP
verification is required (§§ 192.619(e)
and 192.624). The criteria for
determining MCA locations would use
the same process and same definitions
that are currently used to identify HCAs,
except that the threshold for buildings
intended for human occupancy and the
threshold for persons that occupy other
defined sites located within the
potential impact radius would both be
lowered from 20 to 5. This approach is
proposed as a means to minimize the
effort needed on the part of operators to
identify the MCAs, since transmission
operators must have already performed
the analysis in order to have identified
the HCAs or to verify that they have no
HCAs. In response to NTSB
recommendation P–14–01, which was
issued as a result of the Sissonville,
West Virginia incident, the MCA
definition would also include locations
where interstate highways, freeways,
and expressways, and other principal 4lane arterial roadways are located
within the potential impact radius.
With regard to the new terms ‘‘legacy
construction technique’’ and ‘‘legacy
pipe,’’ the definitions are used in
proposed and § 192.624 to identify pipe
to which the proposed material
verification and MAOP verification
requirements would apply. The
definitions are based on historical
technical issues associated with past
pipeline failures.
§ 192.5 Class locations.
Section 23 of the Act requires the
Secretary of Transportation to require
verification of records used to establish
MAOP to ensure they accurately reflect
the physical and operational
characteristics of certain pipelines and
to confirm the established MAOP of the
pipelines. PHMSA has determined that
an important aspect of compliance with
this requirement is to assure that
pipeline class location records are
complete and accurate. The proposed
rule would add a new paragraph
§ 192.5(d) to require each operator of
transmission pipelines to make and
retain for the life of the pipeline records
documenting class locations and
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demonstrating how an operator
determined class locations in
accordance with this section.
§ 192.7 What documents are
incorporated by reference partly or
wholly in this part?
Section 192.7 lists documents that are
incorporated by reference in part 192.
PHMSA proposes conforming
amendments to § 192.7 in the rule text
to reflect other changes proposed in this
NPRM.
§ 192.8 How are onshore gathering
lines and regulated onshore gathering
lines determined?
Section 192.8 defines the upstream
and downstream endpoints of gas
gathering pipelines. Recent
developments in the field of gas
exploration and production, such as
shale gas, indicate that the existing
framework for regulating gas gathering
lines may no longer be appropriate.
Gathering lines are being constructed to
transport ‘‘shale’’ gas that range from 4
to 36 inches in diameter with MAOPs of
up to 1480 psig, far exceeding the
historical operating parameters of such
lines.
Currently, according to the 2011
annual reports submitted by pipeline
operators, PHMSA only regulates about
8,845 miles of Type A gathering lines,
5,178 miles of Type B gathering lines,
and about 6,258 miles of offshore
gathering lines, for a total of
approximately 20,281 miles of regulated
gas gathering pipelines. Gas gathering
lines are currently not regulated if they
are in Class 1 locations. Current
estimates also indicate that there are
approximately 132,500 miles of Type A
gas gathering lines located in Class 1
areas (of which approximately 61,000
miles are estimated to be 8-inch
diameter or greater), and approximately
106,000 miles of Type B gas gathering
lines located in Class 1 areas. Also,
there are approximately 2,300 miles of
Type B gas gathering lines located in
Class 2 areas, some of which may not be
regulated in accordance with
§ 192.8(b)(2).
Moreover, enforcement of the current
requirements has been hampered by the
conflicting and ambiguous language of
API RP 80, a complex standard that can
produce multiple classifications for the
same pipeline system. PHMSA has also
identified a regulatory gap that permits
the potential misapplication of the
incidental gathering line designation
under that standard. Consequently, to
address these issues and gaps, the
proposed rule would repeal the use of
API RP 80 as the basis for determining
regulated gathering lines and would
establish a new definition for onshore
production facility/operation and a
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revised definition for gathering line as
the basis for determining the beginning
and endpoints of each gathering line.
The definition of onshore production
facility/operation includes initial
preparation of gas for transportation at
the production facility, including
separation, lifting, stabilizing, and
dehydration. Pipelines commonly
referred to as ‘‘farm taps’’ serving
residential/commercial customers or
industrial customers are not classified
as gathering, but would continue to be
classified as transmission or distribution
as defined in § 192.3.
§ 192.9 What requirements apply to
gathering lines?
Section 192.9 identifies those portions
of part 192 that apply to regulated gas
gathering lines. For the same reasons
discussed under § 192.8, above, the
proposed rule would expand and clarify
the requirements that apply to gathering
lines. PHMSA proposes to extend
existing regulatory requirements for
Type B gathering lines to Type A
gathering lines in Class 1 locations, if
the nominal diameter of the line is 8″ or
greater.
In addition, on August 20, 2014, the
GAO released a report (GAO Report 14–
667) to address the increased risk posed
by new gathering pipeline construction
in shale development areas. GAO
recommended that a rulemaking be
pursued for gathering pipeline safety
that addresses the risks of largerdiameter, higher-pressure gathering
pipelines, including subjecting such
pipelines to emergency response
planning requirements that currently do
not apply. Currently, Type A gathering
lines are subject to the emergency
planning requirements in § 192.615 and
only include gathering lines in Class 2,
3, and 4 locations that have a Maximum
Allowable Operating Pressure (MAOP)
with a hoop stress of 20% or more for
metallic pipe and MAOP of more than
125 psig for non-metallic pipe. Further,
gathering lines that are located in Class
1 areas (e.g., rural areas) are not
considered Type A gathering lines even
if they meet the pressure criteria
specified in the preceding sentence.
PHMSA is proposing to create subdivisions of Type A gathering lines
(Type A, Area 1 and Type A, Area 2).
The new designation ‘‘Type A, Area 1
gathering lines’’ would apply to
currently regulated Type A gathering
lines. The new designation ‘‘Type A,
Area 2 gathering lines’’ would apply to
gathering lines with a diameter of 8-inch
or greater that meet all of the qualifying
parameters for currently regulated Type
A gathering, but are located in Class 1
locations. PHMSA proposes to address
the GAO recommendation by requiring
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the newly proposed Type A, Area 2
regulated onshore gathering lines,
which include lines in Class 1 locations
with a nominal diameter of 8-inch or
greater, to develop procedures, training,
notifications, and carry out emergency
plans as described in § 192.615, in
addition to a limited set of other specific
requirements, including corrosion
protection and damage prevention.
§ 192.13 General.
Section 192.13 prescribes general
requirements for gas pipelines. PHMSA
has determined that safety and
environmental protection would be
improved by generally requiring
operators to evaluate and mitigate risks
during all phases of the useful life of a
pipeline as an integral part of managing
pipeline design, construction, operation,
maintenance and integrity, including
management of change. This proposed
rule would add a new paragraph (d) to
establish a general clause requiring
onshore gas transmission pipeline
operators to evaluate and mitigate risks
to the public and environment as part of
managing pipeline design, construction,
operation, maintenance, and integrity,
including management of change. The
new paragraph would also invoke the
requirements for management of change
as outlined in ASME/ANSI B31.8S,
section 11, and explicitly articulate the
requirements for a management of
change process that are applicable to
onshore gas transmission pipelines.
Section 23 of the Act requires the
Secretary of Transportation to require
verification of records used to establish
MAOP to ensure they accurately reflect
the physical and operational
characteristics of certain pipelines and
to confirm the established MAOP of the
pipelines. PHMSA has determined that
an important aspect of compliance with
this requirement is to assure that
records that demonstrate compliance
with part 192 are complete and
accurate. The proposed rule would add
a new paragraph (e) that clearly
articulates the requirements for records
preparation and retention and requires
that records be reliable, traceable,
verifiable, and complete. Further, the
proposed Appendix A would provide
specific requirements for records
retention for transmission pipelines.
In addition, conforming amendments
to paragraphs (a) and (b) list the
effective date of the proposed
requirements for newly regulated
onshore gathering lines.
§ 192.67 Records: Materials.
Section 23 of the Act requires the
Secretary of Transportation to require
verification of records used to establish
MAOP to ensure they accurately reflect
the physical and operational
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characteristics of certain pipelines and
to confirm the established MAOP of the
pipelines. PHMSA has determined that
compliance requires that pipeline
material records are complete and
accurate. The proposed rule would add
a new § 192.67 to require each operator
of transmission pipelines to make and
retain for the life of the pipeline the
original steel pipe manufacturing
records that document tests,
inspections, and attributes required by
the manufacturing specification in effect
at the time the pipe was manufactured.
§ 192.127 Records: Pipe design.
Section 23 of the Act requires the
Secretary of Transportation to require
verification of records used to establish
MAOP to ensure they accurately reflect
the physical and operational
characteristics of certain pipelines and
to confirm the established MAOP of the
pipelines. PHMSA has determined that
compliance requires that pipe design
records are complete and accurate. The
proposed rule would add a new
§ 192.127 to require each operator of
transmission pipelines to make and
retain for the life of the pipeline records
documenting pipe design to withstand
anticipated external pressures and
determination of design pressure for
steel pipe.
§ 192.150 Passage of internal
inspection devices.
The current pipeline safety
regulations in 49 CFR 192.150 require
that pipelines be designed and
constructed to accommodate in-line
inspection devices. Part 192 is silent on
technical standards or guidelines for
implementing requirements to assure
pipelines are designed and constructed
for ILI assessments. At the time these
rules were promulgated, there was no
consensus industry standard that
addressed design and construction
requirements for ILI. NACE Standard
Practice, NACE SP0102–2010, ‘‘In-line
Inspection of Pipelines,’’ has since been
published and provides guidance in this
area in Section 7. The incorporation of
this standard into § 192.150 will
promote a higher level of safety by
establishing consistent standards for the
design and construction of line pipe to
accommodate ILI devices.
§ 192.205 Records: Pipeline
components.
Section 23 of the Act requires the
Secretary of Transportation to require
verification of records used to establish
MAOP to ensure they accurately reflect
the physical and operational
characteristics of certain pipelines and
to confirm the established MAOP of the
pipelines. PHMSA has determined that
compliance requires that pipeline
component records are complete and
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accurate. The proposed rule would add
a new § 192.205 to require each operator
of transmission pipelines to make and
retain records documenting
manufacturing and testing information
for valves and other pipeline
components.
§ 192.227 Qualification of welders.
Section 23 of the Act requires the
Secretary of Transportation to require
verification of records used to establish
MAOP to ensure they accurately reflect
the physical and operational
characteristics of certain pipelines and
to confirm the established MAOP of the
pipelines. PHMSA has determined that
compliance requires that pipeline
welding records are complete and
accurate. The proposed rule would add
a new paragraph § 192.227(c) to require
each operator of transmission pipelines
to make and retain for the life of the
pipeline records demonstrating each
individual welder qualification in
accordance with this section.
§ 192.285 Plastic pipe: Qualifying
persons to make joints.
Section 23 of the Act requires the
Secretary of Transportation to require
verification of records used to establish
MAOP to ensure they accurately reflect
the physical and operational
characteristics of certain pipelines and
to confirm the established MAOP of the
pipelines. PHMSA has determined that
compliance requires that pipeline
qualification records are complete and
accurate. The proposed rule would add
a new paragraph § 192.285(e) to require
each operator of transmission pipelines
to make and retain for the life of the
pipeline records demonstrating plastic
pipe joining qualifications in
accordance with this section.
§ 192.319 Installation of pipe in a
ditch.
Section 192.319 prescribes
requirements for installing pipe in a
ditch, including requirements to protect
pipe coating from damage during the
process. However, during handling,
lowering, and backfilling, sometimes
pipe coating is damaged, which can
compromise its ability to protect against
external corrosion. An example of the
consequences of such damage occurred
in 2011 on the Bison Pipeline, operated
by TransCanada Northern Border
Pipeline, Inc. In this case, the probable
cause of the incident was attributed to
latent coating and mechanical damage
caused during construction, which
subsequently caused the pipeline to fail.
To help prevent recurrence of such
incidents, PHMSA has determined that
additional requirements are needed to
verify that pipeline coating systems for
protection against external corrosion are
not damaged during the installation and
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backfill process. Accordingly, this
proposed rule would add a new
paragraph (d) to require that onshore gas
transmission operators perform an
above-ground indirect assessment to
identify locations of suspected damage
promptly after backfill is completed and
remediate any moderate or severe
coating damage. Mechanical damage is
also detectable by these indirect
assessment methods, since the forces
that are able to mechanically damage
steel pipe usually result in detectable
coating defects. Paragraph (d) does not
apply to gas gathering lines or
distribution mains. In addition,
paragraph (d) would require each
operator of transmission pipelines to
make and retain for the life of the
pipeline records documenting the
coating assessment findings and repairs.
§ 192.452 How does this subpart
apply to converted pipelines and
regulated onshore gathering lines?
Section 192.452 prescribes corrosion
control requirements for regulated
onshore gathering lines. PHMSA
proposes conforming amendments to
the rule text in paragraph (b) to reflect
other changes proposed in this NPRM
for gas gathering lines.
§ 192.461 External corrosion control:
Protective coating.
Section 192.461 prescribes
requirements for protective coating
systems. However, certain types of
coating systems that have been used
extensively in the pipeline industry can
impede the process of cathodic
protection if the coating disbonds from
the pipe. The NTSB determined that
this was a significant contributing factor
in the major crude oil spill that occurred
near Marshall, Michigan, in 2010.
PHMSA has determined that additional
requirements are needed to specify that
coating should not impede cathodic
protection and to ensure operators
verify that pipeline coating systems for
protection against external corrosion
have not become compromised or
damaged during the installation and
backfill process. Accordingly, this
proposed rule would amend paragraph
(a)(4) to require that coating have
sufficient strength to resist damage
during installation and backfill, and add
a new paragraph (f) to require that
onshore gas transmission operators
perform an above-ground indirect
assessment to identify locations of
suspected damage promptly after
backfill is completed or anytime there is
an indication that the coating might be
compromised. It would also require
prompt remediation of any moderate or
severe coating damage.
§ 192.465 External corrosion control:
Monitoring.
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Section 192.465 currently prescribes
that operators monitor cathodic
protection and take prompt remedial
action to correct deficiencies indicated
by the monitoring. The provisions in
§ 192.465 do not specify the remedial
actions required to correct deficiencies
and do not define ‘‘prompt.’’ To address
this potential issue, the proposed rule
would amend paragraph (d) to require
that remedial action must be completed
promptly, but no later than the next
monitoring interval specified in
§ 192.465 or within one year, whichever
is less. In addition, a new paragraph (f)
is added to require onshore gas
transmission operators to perform closeinterval surveys if annual test station
readings indicate cathodic protection is
below the level of protection required in
subpart I. Unless it is impractical to do
so, close interval surveys must be
completed with the protective current
interrupted. Impracticality must be
based on a technical reason, for
example, a pipeline protected by direct
buried sacrificial anodes (anodes
directly connected to the pipeline), and
not on cost impact. The proposed rule
would also require each operator to take
remedial action to correct any
deficiencies indicated by the
monitoring.
§ 192.473 External corrosion control:
Interference currents.
Interference currents can negate the
effectiveness of cathodic protection
systems. Section 192.473 prescribes
general requirements to minimize the
detrimental effects of interference
currents. However, specific
requirements to monitor and mitigate
detrimental interference currents have
not been prescribed in subpart I. In
2003, PHMSA issued advisory bulletin
ADB–03–06 (68 FR 64189). The bulletin
advised each operator of a natural gas
transmission or hazardous liquid
pipeline to determine whether new steel
pipelines are susceptible to detrimental
effects from stray electrical currents.
Based on this evaluation, an operator
should carefully monitor and take
action to mitigate detrimental effects.
The operator should give special
attention to a new pipeline’s physical
location, particularly where that
location may subject the new pipeline to
stray currents from other underground
facilities, including other pipelines or
induced currents from electrical
transmission lines, whether
aboveground or underground. Operators
were strongly encouraged to review
their corrosion control programs and to
have qualified corrosion personnel
present during construction to identify,
mitigate, and monitor any detrimental
stray currents that might damage new
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pipelines. Since the advisory bulletin,
PHMSA continues to identify cases
where significant pipeline defects are
attributed to corrosion caused by
interference currents. Examples include
CenterPoint Energy’s CP line (2007),
Keystone Pipeline (2012) and Overland
Pass Pipeline (2012). Therefore, PHMSA
has determined that additional
requirements are needed to explicitly
require that operators conduct
interference surveys and to timely
remediate adverse conditions. The
proposed rule would add new
paragraph (c) to require that onshore gas
transmission operator programs include
interference surveys to detect the
presence of interference currents and to
require taking remedial actions
promptly after completion of the survey
to adequately protect the pipeline
segment from detrimental interference
currents, but no later than 6 months in
any case.
§ 192.478 Internal corrosion control:
Monitoring.
Section 192.477 prescribes
requirements to monitor internal
corrosion if corrosive gas is being
transported. However, the existing rules
do not prescribe that operators
continually or periodically monitor the
gas stream for the introduction of
corrosive constituents through system
changes, changing gas supply, upset
conditions, or other changes. This could
result in pipelines that are not
monitored for internal corrosion,
because an initial assessment did not
identify the presence of corrosive gas. In
September 2000, following the Carlsbad
explosion, PHMSA issued Advisory
Bulletin 00–02, dated 9/1/2000 (65 FR
53803). The bulletin advised owners
and operators of natural gas
transmission pipelines to review their
internal corrosion monitoring programs
and consider factors that influence the
formation of internal corrosion,
including gas quality and operating
parameters. Pipeline operators continue
to report incidents attributed to internal
corrosion. Between 2002 and November
2012, 206 incidents have been reported
that were attributed to internal
corrosion. PHMSA has determined that
additional requirements are needed to
assure that operators effectively monitor
gas stream quality to identify if and
when corrosive gas is being transported
and to mitigate deleterious gas stream
constituents (e.g., contaminants or
liquids). The proposed rule would add
the new section 192.478 to require
monitoring for deleterious gas stream
constituents for onshore gas
transmission operators, and require that
gas monitoring data be evaluated
quarterly. In addition, the proposed rule
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would add a requirement for onshore
gas transmission operators to review the
internal corrosion monitoring and
mitigation program semi-annually and
adjust the program as necessary to
mitigate the presence of deleterious gas
stream constituents. This is in addition
to existing requirements to check
coupons or other means to monitor for
the actual presence of internal corrosion
in the case of transporting a known
corrosive gas stream.
§ 192.485 Remedial measures:
Transmission lines.
Section 192.485 prescribes
requirements for remedial measures to
address general corrosion and localized
corrosion pitting in transmission lines.
For such conditions it specifies that the
strength of pipe based on actual
remaining wall thickness may be
determined by the procedure in ASME/
ANSI B31G or the procedure in AGA
Pipeline Research Committee Project PR
3–805 (RSTRENG). PHMSA has
determined that additional requirements
are needed to assure such calculations
have a sound basis. The proposed rule
would revise section 192.485(c) to
specify that pipe and material properties
used in remaining strength calculations
must be documented in reliable,
traceable, verifiable, and complete
records. If such records are not
available, pipe and material properties
used in the remaining strength
calculations must be based on
properties determined and documented
in accordance with § 192.607.
§ 192.493 In-line inspection of
pipelines.
The current pipeline safety
regulations in 49 CFR 192.921 and
192.937 require that operators assess the
material condition of pipelines in
certain circumstances (e.g., IM
assessments for pipelines that could
affect high consequence areas) and
allow use of in-line inspection tools for
these assessments. Operators of gas
transmission pipelines are required to
follow the requirements of ASME/ANSI
B31.8S, ‘‘Managing System Integrity of
Gas Pipelines,’’ in conducting their IM
activities. ASME B31.8S provides
limited guidance for conducting ILI
assessments. Part 192 is silent on
technical standards or guidelines for
performing ILI assessments or
implementing these requirements. At
the time these rules were promulgated,
there was no consensus industry
standard that addressed ILI. Three
related standards have since been
published:
• API STD 1163–2005, ‘‘In-Line
Inspection Systems Qualification
Standard.’’ This Standard serves as an
umbrella document to be used with and
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complement the NACE and ASNT
standards below, which are
incorporated by reference in API STD
1163.
• NACE Standard Practice, NACE
SP0102–2010, ‘‘In-line Inspection of
Pipelines.’’
• ANSI/ASNT ILI–PQ–2010, ‘‘In-line
Inspection Personnel Qualification and
Certification.’’
The API standard is more
comprehensive and rigorous than
requirements currently incorporated
into 49 CFR part 192. The incorporation
of this standard into pipeline safety
regulations will promote a higher level
of safety by establishing consistent
standards to qualify the equipment,
people, processes and software utilized
by the in-line inspection industry. The
API standard addresses in detail each of
the following aspects of ILI inspections,
most of which are not currently
addressed in the regulations:
• Systems qualification process
• Personnel qualification
• In-line inspection system selection
• Qualification of performance
specifications
• System operational validation
• System Results qualification
• Reporting requirements
• Quality management system
The incorporation of this standard
into pipeline safety regulations will
promote a higher level of safety by
establishing consistent standards for
conducting ILI assessments of line pipe.
The NACE standard covers in detail
each of the following aspects of ILI
assessments, most of which are not
currently addressed in part 192 or in
ASME B31.8S:
• Tool selection
• Evaluation of pipeline compatibility
with ILI
• Logistical guidelines, which
includes survey acceptance criteria and
reporting
• Scheduling
• New construction (planning for
future ILI in new lines)
• Data analysis
• Data management
• The NACE standard provides a
standardized questionnaire and
specifies that the completed
questionnaire should be provided to the
ILI vendor. The questionnaire lists
relevant parameters and characteristics
of the pipeline section to be inspected.
PHMSA believes that the consistency,
accuracy and quality of pipeline in-line
inspections would be improved by
incorporating the consensus NACE
standard into the regulations.
The NACE standard applies to ‘‘free
swimming’’ inspection tools that are
carried down the pipeline by the
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transported fluid. It does not apply to
tethered or remotely controlled ILI tools,
which can also be used in special
circumstances (e.g., examination of
laterals). While their use is less
prevalent than free swimming tools,
some pipeline IM assessments have
been conducted using these tools.
PHMSA considers that many of the
provisions in the NACE standard can be
applied to tethered or remotely
controlled ILI tools. Therefore, PHMSA
is proposing to allow the use of these
tools, provided they generally comply
with the applicable sections of the
NACE standard.
The ANSI/ASNT standard provides
for qualification and certification
requirements that are not addressed by
49 CFR part 192. The incorporation of
this standard into pipeline safety
regulations will promote a higher level
of safety by establishing consistent
standards to qualify the equipment,
people, processes and software utilized
by the in-line inspection industry. The
ANSI/ASNT standard addresses in
detail each of the following aspects,
which are not currently addressed in the
regulations:
• Requirements for written
procedures
• Personnel qualification levels
• Education, training and experience
requirements
• Training programs
• Examinations (testing of personnel)
• Personnel certification and
recertification
• Personnel technical performance
evaluations
The proposed rule adds a new
§ 192.493 to require compliance with
the requirements and recommendations
of the three consensus standards
discussed above when conducting inline inspection of pipelines.
§ 192.503 General requirements.
Section 192.503 prescribes the general
test requirements for the operation of a
new segment of pipeline, or returning to
service a segment of pipeline that has
been relocated or replaced. The
proposed rule would add additional
requirements to § 192.503(a)(1) to reflect
other requirements for determination of
MAOP. These include § 192.620 for
alternative MAOP determination
requirements and new § 192.624 for
verification of MAOP for onshore, steel,
gas transmission pipeline segments that:
(1) Has experienced a reportable inservice incident, as defined in § 191.3,
since its most recent successful subpart
J pressure test, due to an original
manufacturing-related defect, a
construction-, installation-, or
fabrication-related defect, or a crackingrelated defect, including, but not limited
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to, seam cracking, girth weld cracking,
selective seam weld corrosion, hard
spot, or stress corrosion cracking and
the pipeline segment is located in one
of the following locations: (i) A high
consequence area as defined in
§ 192.903; (ii) a class 3 or class 4
location; or (iii) a moderate consequence
area as defined in § 192.3 if the pipe
segment can accommodate inspection
by means of instrumented inline
inspection tools (i.e., ‘‘smart pigs’’); (2)
Pressure test records necessary to
establish maximum allowable operating
pressure per subpart J for the pipeline
segment, including, but not limited to,
records required by § 192.517(a), are not
reliable, traceable, verifiable, and
complete and the pipeline segment is
located in one of the following
locations: (i) A high consequence area as
defined in § 192.903; or (ii) a class 3 or
class 4 location; or (3) the pipeline
segment maximum allowable operating
pressure was established in accordance
with § 192.619(c) of this subpart before
[effective date of rule] and is located in
one of the following areas: (i) A high
consequence area as defined in
§ 192.903; (ii) a class 3 or class 4
location; or (iii) a moderate consequence
area as defined in § 192.3 if the pipe
segment can accommodate inspection
by means of instrumented inline
inspection tools (i.e., ‘‘smart pigs’’).
§ 192.506 Transmission lines: Spike
hydrostatic pressure test for existing
steel pipe with integrity threats.
The NTSB recommended repealing
§ 192.619(c) and requiring that all gas
transmission pipelines constructed
before 1970 be subjected to a hydrostatic
pressure test that incorporates a spike
test (recommendation P–11–14).
Currently, part 192 does not contain any
requirement for operators to conduct
spike hydrostatic pressure tests. In
response to the NTSB recommendation,
this NPRM proposes requirements for
verification of MAOP in new § 192.624,
which requires that MAOP be
established and documented for
pipelines located in either an HCA or
MCA meeting the conditions in
§ 192.624(a)(1) through (3) using one or
more of the methods in § 192.624(c)(1)
through (6). The pressure test method
requires performance of a spike pressure
test in accordance with new § 192.506 if
the pipeline includes legacy pipe or was
constructed using legacy construction
techniques or if the pipeline has
experienced a reportable in-service
incident, as defined in § 191.3, since its
most recent successful subpart J
pressure test, due to an original
manufacturing-related defect, a
construction-, installation-, or
fabrication-related defect, or a crack or
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crack-like defect, including, but not
limited to, seam cracking, girth weld
cracking, selective seam weld corrosion,
hard spot, or stress corrosion cracking.
§ 192.517 Records.
Section 192.517 prescribes the record
requirements for each test performed
under §§ 192.505 and 192.507. The
proposed rule would revise § 192.517 to
add the record requirements for
§ 192.506.
§ 192.605 Procedural manual for
operations, maintenance, and
emergencies.
Section 192.605 prescribes
requirements for the operator’s
procedural manual for operations,
maintenance, and emergencies. Part 192
contains numerous requirements
intended to protect pipelines from
overpressure events. These include
mandatory pressure relieving or
pressure limiting devices, inspections
and tests of such devices, establishment
of maximum allowable operating
pressure, and administrative
requirements to not operate the pipeline
at pressures that exceed the MAOP,
among others. Implicit in the
requirements of § 192.605 is the intent
for operators to establish operational
and maintenance controls and
procedures to effectively implement
these requirements and preclude
operation at pressures that exceed
MAOP. PHMSA expects that operator’s
procedures should already address this
aspect of operations and maintenance,
as it is a long-standing, critical aspect of
safe pipeline operations. However,
§ 192.605 does not explicitly prescribe
this aspect of the procedural controls. In
addition, as a result of the San Bruno
incident, Congress mandated in Section
23 of the Act that any exceedance of
MAOP on a gas transmission pipeline be
reported to PHMSA. As part of such
reporting, the operator should inform
PHMSA of the cause(s) of each
exceedance. On December 21, 2012,
PHMSA published advisory bulletin
ADB–2012–11, which advised
transmission operators of their
responsibility under Section 23 of the
Act to report exceedances of MAOP that
exceeds the margin (build-up) allowed
for operation of pressure-limiting or
control devices (i.e., report any pressure
exceedances over the pressure limiting
or control device set point as defined in
applicable sections of §§ 192.201(a)(2)
or 192.739). Between December 21, 2012
and June 30, 2013, PHMSA received 14
such notifications. Therefore, PHMSA
has determined that an additional
requirement is needed to explicitly
require procedures to maintain and
operate pressure relieving devices and
to control operating pressure to prevent
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exceedance of MAOP. The proposed
rule clarifies the existing requirements
regarding such procedural controls.
§ 192.607 Verification of pipeline
material: Onshore steel transmission
pipelines.
Section 23 of the Act requires the
Secretary of Transportation to require
verification of records used to establish
MAOP to ensure they accurately reflect
the physical and operational
characteristics of the pipelines and to
confirm the established MAOP of the
pipelines. PHMSA issued Advisory
Bulletin 11–01 on January 10, 2011 (76
FR 1504) and Advisory Bulletin 12–06
on May 7, 2012 (77 FR 26822) to inform
operators of this requirement. Operators
have submitted information in their
2012 Annual Reports indicating that a
portion of transmission pipeline
segments do not have adequate records
to establish MAOP or to accurately
reflect the physical and operational
characteristics of the pipeline.
Therefore, PHMSA has determined that
additional rules are needed to
implement this requirement of the Act.
Specifically, PHMSA has determined
that additional rules are needed to
require that operators conduct tests and
other actions needed to understand the
physical and operational characteristics
for those segments where adequate
records are not available, and to
establish standards for performing these
actions.
This issue was addressed in detail at
the Integrity Verification Process
workshop on August 7, 2013. Major
issues that were discussed include the
scope of information needed and the
methodology for verifying material
properties. The most difficult
information to obtain, from a technical
perspective, is the strength of the steel.
Conventional techniques would include
cutting out a piece of pipe and
destructively testing it to determine
yield and ultimate tensile strength.
PHMSA proposes to address this in the
rule by allowing new non-destructive
techniques if they can be validated to
produce accurate results for the grade
and type of pipe being evaluated. Such
techniques have already been
successfully validated for some grades
of pipe.
Another issue is the extremely high
cost of excavating the pipeline in order
to verify the material, and determining
how much pipeline needs to be exposed
and tested in order to have assurance of
pipeline properties. PHMSA proposes to
address this issue by specifying that
operators take advantage of
opportunities when the pipeline is
exposed for other reasons, such as
maintenance and repair, by requiring
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that material properties be verified
whenever the pipe is exposed. Over
time, pipeline operators will develop a
substantial set of verified material data,
which will provide assurance that
material properties are reliably known
for the entire population of inadequately
documented segments. PHMSA
proposes to require that operators
continue this opportunistic material
verification process until the operator
has completed enough verifications to
obtain high confidence that only a small
percentage of inadequately documented
pipe lengths have properties that are
inconsistent with operators’ past
assumptions. The rule would specify
the number of excavations required to
achieve this level of confidence.
Lastly, PHMSA proposes criteria that
would require material verification for
higher risk locations. Therefore, the
proposed rule would add requirements
for verification of pipeline material in
new § 192.607 for existing onshore,
steel, gas transmission pipelines that are
located in an HCA or a class 3 or class
4 location. PHMSA believes this
approach appropriately addresses
pipeline segment risk without extending
the requirement to all pipelines where
risk and potential consequences are not
as significant, such as pipeline in
remote rural areas.
Requirements are also included to
ensure that the results of this process
are documented in records that are
reliable, traceable, verifiable, and
complete that must be retained for the
life of the pipeline.
§ 192.613 Continuing surveillance.
Section 192.613 prescribes general
requirements for continuing
surveillance of the pipeline to
determine and take action due to
changes in the pipeline from, among
other things, unusual operating and
maintenance conditions. The 2011
hazardous liquid pipeline accident
resulting in a crude oil spill into the
Yellowstone River near Laurel, Montana
was probably caused by scouring at a
river crossing due to flooding. Based on
recent examples of extreme weather
events that did result, or could have
resulted, in pipeline incidents, PHMSA
has determined that additional
requirements are needed to assure that
operator procedures adequately address
inspection of the pipeline and right-ofway for ‘‘other factors affecting safety
and operation’’ following an extreme
weather event such as a hurricane or
flood, landslide, an earthquake, a
natural disaster, or other similar event.
The proposed rule would add a new
paragraph (c) to require such
inspections, specify the timeframe in
which such inspections should
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commence, and specify the appropriate
remedial actions must be taken to
ensure safe pipeline operations. The
new paragraph (c) would apply to both
onshore transmission pipelines and
their rights-of-way.
§ 192.619 Maximum allowable
operating pressure: Steel or plastic
pipelines.
The NTSB issued its report on the San
Bruno incident that included a
recommendation (P–11–15) that
PHMSA amend its regulations so that
manufacturing and construction-related
defects can only be considered ‘‘stable’’
if a gas pipeline has been subjected to
a post-construction hydrostatic pressure
test of at least 1.25 times the MAOP.
This NPRM proposes to revise the test
pressure factors in § 192.619(a)(2)(ii) to
correspond to at least 1.25 MAOP for
newly installed pipelines.
In addition, Section 23 of the Act
requires verification of records to
confirm the established MAOP of the
pipelines. Operators have submitted
information in their 2012 Annual
Reports indicating that a portion of gas
transmission pipeline segments do not
have adequate records to establish
MAOP. For pipelines without an
adequately documented basis for
MAOP, the proposed rule adds a new
paragraph (e) to § 192.619 to require that
certain onshore steel transmission
pipelines that meet the criteria specified
in § 192.624(a), and that do not have
adequate records to establish MAOP,
must establish and document MAOP in
accordance with new § 192.624 using
one or more of the methods in
§ 192.624(c)(1) through (6), as discussed
in more detail below.
The proposed rule would also add a
new paragraph (f) to explicitly require
that records documenting tests, design,
and other information necessary to
establish MAOP be retained for the life
of the pipeline.
Lastly, the rule would incorporate
conforming changes to § 192.619(a) to
reflect changes to gas gathering
regulations proposed in §§ 192.8 and
192.9.
§ 192.624 Maximum allowable
operating pressure verification: Onshore
steel transmission pipelines.
Section 23 of the Act requires
verification of records used to establish
MAOP for pipe in class 3 and class 4
locations and high-consequence areas in
Class 1 and 2 locations to ensure they
accurately reflect the physical and
operational characteristics of the
pipelines and to confirm the established
MAOP of the pipelines. Operators have
submitted information in their 2012
Annual Reports indicating that some gas
transmission pipeline segments do not
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have adequate records or testing to
establish MAOP. For pipelines so
identified, the Act requires that PHMSA
promulgate regulations to require
operators to test the segments to confirm
the material strength of the pipe in
HCAs that operate at stress levels greater
than or equal to 30% SMYS. Such tests
must be performed by pressure testing
or other methods determined by the
Secretary to be of equal or greater
effectiveness.
As a result of its investigation of the
San Bruno accident, NTSB issued two
related recommendations. NTSB
recommended that PHMSA repeal
§ 192.619(c) and require that all gas
transmission pipelines constructed
before 1970 be subjected to a hydrostatic
pressure test that incorporates a spike
test (P–11–14). NTSB also
recommended that PHMSA amend the
Federal pipeline safety regulations so
that manufacturing- and constructionrelated defects can only be considered
stable if a gas pipeline has been
subjected to a post-construction
hydrostatic pressure test of at least 1.25
times the maximum allowable operating
pressure (P–11–15).
The proposed rule would add a new
§ 192.624 to address these mandates and
recommendations. The rule would
require that operators re-establish and
document MAOP for certain onshore
steel transmission pipelines located in
an HCA or MCA that meet one or more
of the criteria specified in § 192.624(a).
Those criteria include: (1) Has
experienced a reportable in-service
incident, as defined in § 191.3, since its
most recent successful subpart J
pressure test, due to an original
manufacturing-related defect, a
construction-, installation-, or
fabrication-related defect, or a crackingrelated defect, including, but not limited
to, seam cracking, girth weld cracking,
selective seam weld corrosion, hard
spot, or stress corrosion cracking and
the pipeline segment is located in one
of the following locations: (i) A high
consequence area as defined in
§ 192.903; (ii) a class 3 or class 4
location; or (iii) a moderate consequence
area as defined in § 192.3 if the pipe
segment can accommodate inspection
by means of instrumented inline
inspection tools (i.e., ‘‘smart pigs’’); (2)
Pressure test records necessary to
establish maximum allowable operating
pressure per subpart J for the pipeline
segment, including, but not limited to,
records required by § 192.517(a), are not
reliable, traceable, verifiable, and
complete and the pipeline segment is
located in one of the following
locations: (i) A high consequence area as
defined in § 192.903; or (ii) a class 3 or
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class 4 location; or (3) the pipeline
segment maximum allowable operating
pressure was established in accordance
with § 192.619(c) of this subpart before
[effective date of rule] and is located in
one of the following areas: (i) A high
consequence area as defined in
§ 192.903; (ii) a class 3 or class 4
location; or (iii) a moderate consequence
area as defined in § 192.3 if the pipe
segment can accommodate inspection
by means of instrumented inline
inspection tools (i.e., ‘‘smart pigs’’).
The methods specified in § 192.624
include the pressure test method. If the
pipeline includes legacy pipe or was
constructed using legacy construction
techniques or the pipeline has
experienced a reportable in-service
incident, as defined in § 191.3, since its
most recent successful subpart J
pressure test, due to an original
manufacturing-related defect, a
construction-, installation-, or
fabrication-related defect, or a crack or
crack-like defect, a spike pressure test in
accordance with new § 192.506 would
be required. For modern pipe without
the aforementioned risk factors, a
pressure test in accordance with
§ 192.505 would be allowed.
Other methods to reestablish MAOP
for pipe currently operating under
§ 192.619(c) would also be allowed.
PHMSA has determined that the
following methods would provide equal
or greater effectiveness as a pressure
test:
(i) De-rating the pipe segment such
that the new MAOP is less than
historical actual sustained operating
pressure by using a safety factor of 0.80
times the sustained operating pressure
(equivalent to a pressure test using gas
or water as the test medium with a test
pressure of 1.25 times MAOP). For
segments that operate at stress levels of
less than 30% SMYS a safety factor of
0.90 times sustained operating pressure
is allowed (equivalent to a pressure test
of 1.11 times MAOP), supplemented
with additional integrity assessments,
and preventive and mitigative measures
specified in the proposed rule.
(ii) Replacement of the pipe, which
would require a new pressure test that
conforms with subpart J before being
placed in service,
(iii) An in-line inspection and
Engineering Critical Assessment process
using technical criteria to establish a
safety margin equivalent to that
provided by a pressure test, or
(iv) Use of other technology that the
operator demonstrates provides an
equivalent or greater level of safety,
provided PHMSA is notified in advance.
The proposed rule establishes
requirements for pipelines operating at
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20813
stress levels of less than 30% of SMYS
based on technical information
provided in Interstate Natural Gas
Association of America/American Gas
Association Final Report No. 13–180,
‘‘Leak vs. Rupture Thresholds for
Material and Construction Anomalies,’’
December 2013. The report references a
2010 study by Kiefner & Associates, Inc.
‘‘Numerical Modeling and Validation
for Determination of the Leak/Rupture
Boundary for Low-Stress Pipelines’’
performed under contract to the Gas
Technology Institute (GTI). The Kiefner/
GTI report evaluated theoretical fracture
models and supporting test data in order
to define a possible leak-rupture
threshold stress level. The report
pointed out that ‘‘no evidence was
found that a propagating ductile rupture
could arise from an incident attributable
to any one of these causes in a pipeline
that is being operated at a hoop stress
level of 30% of SMYS or less.’’ In
addition, the INGAA/AGA report
included a review of Kiefner &
Associates, Inc. failure investigation
reports, which concluded that all
manufacturing related defects failing
under the action of hoop stress alone
failed as leaks if the hoop stress level
was 30% SMYS or less except for one
case out of 94 which failed at 27% of
SMYS. The INGAA/AGA report states
that a hydrostatic test to 1.25 times the
MAOP is unnecessary to reasonably
assure stability of pipe manufacturing
construction related features in pipe
meeting the following conditions: (1)
Ductile fracture initiation is assured by
showing that the pipe has an operating
temperature above the brittle fracture
initiation temperature; (2) interaction
with in-service degradation mechanics
such as selective seam weld corrosion or
previous mechanical damage is absent;
(3) hoop stress is 30% or less; (4) mill
pressure testing was conducted at 60%
SMYS or more, established by
documented conformance to applicable
pipe product specifications (e.g., API
5L) or company specifications; and (5)
pipe is 6 NPS or smaller. For pipes that
are 8 NPS or larger but still meeting the
conditions mentioned above,
hydrostatic pressure testing to 1.25
times the MAOP is still prudent, since
theoretical analysis as well as full scale
laboratory tests show that failure as a
rupture is possible for stress thresholds
below 30% of SMYS. However, NPS 8
pipe may be prioritized lower than
larger pipe because there were no
reported incidents of service rupture in
pipe that size where all other criteria
were met. PHMSA plans to limit stress
levels, pressures, and pipe diameters
that can meet the potential impact
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radius and require alternative integrity
and preventative and mitigative
measures for pipelines that use these
criteria to establish MAOP.
The above approach implements the
regulatory mandate in the Act for
segments in HCAs. In addition, the
scope includes additional pipe segments
in the newly defined moderate
consequence areas. This approach is
intended to address the NTSB
recommendations and to provide
increased safety in areas where a
pipeline rupture would have a
significant impact on the public or the
environment. PHMSA does not propose
to repeal 49 CFR 192.619(c) for
segments located outside of HCAs or
MCAs where the routine presence of
persons is not expected.
The Engineering Critical Assessment
process requires the conservative
analysis of: Any in-service cracks, cracklike defects remaining in the pipe, or the
largest possible crack that could remain
in the pipe, including crack dimensions
(length and depth) to determine the
predicted failure pressure (PFP) of each
defect; failure mode (ductile, brittle, or
both) for the microstructure, location,
type of defect, and operating conditions
(which includes pressure cycling); and
failure stress and crack growth analysis
to determine the remaining life of the
pipeline. An Engineering Critical
Assessment must use techniques and
procedures developed and confirmed
through research findings provided by
PHMSA, and other reputable technical
sources for longitudinal seam and crack
growth such as PHMSA’s
Comprehensive Study to Understand
Longitudinal ERW Seam Research &
Development study task reports: Battelle
Final Reports (‘‘Battelle’s Experience
with ERW and Flash Weld Seam
Failures: Causes and Implications’’—
Task 1.4), Report No. 13–002 (‘‘Models
for Predicting Failure Stress Levels for
Defects Affecting ERW and FlashWelded Seams’’—Subtask 2.4), Report
No. 13–021 (‘‘Predicting Times to
Failure for ERW Seam Defects that Grow
by Pressure-Cycle-Induced Fatigue’’—
Subtask 2.5), and ‘‘Final Summary
Report and Recommendations for the
Comprehensive Study to Understand
Longitudinal ERW Seam Failures—
Phase 1’’—Task 4.5), which can be
found on the internet at: https://
primis.phmsa.dot.gov/matrix/
PrjHome.rdm?prj=390.
Section 23 requires pipeline operators
to conduct a records verification for
pipelines located in certain areas to
ensure that the records accurately reflect
the physical and operational
characteristics of the pipelines and
confirm the established MAOP.
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Congress further directed DOT to
require the owner or operator to
reconfirm a maximum allowable
operating pressure for pipelines with
insufficient records. This rule proposes
methods for satisfying this direction
from Congress. In analyzing the impact
of the proposed methods, PHMSA
determined that they would result in
large cost savings ($2.67 billion over 15
years discounted at 7%, $3.67 billion
discounted at 3%) relative to current
regulatory requirements for pipelines
with insufficient records in 49 CFR
192.107(b), The results of that action
indicated that problems similar to those
that contributed to the San Bruno
incidents are more widespread than
previously believed. As a result, the
proposed rule would establish
consistent standards by which operators
would correct these issues in a way that
is more cost effective than the current
regulations would require (which could
require more extensive destructive
testing, pressure testing, and/or pipe
replacement). PHMSA did not identify
any significant adverse safety impacts
from allowing operators to use the
proposed methods instead of those in
the current regulations. See section
4.1.2.3 in the regulatory impact analysis
for the analysis of the cost savings.
PHMSA estimated the cost savings to
operators associated with the Section
23(c) mileage. Existing regulatory
requirements [§ 192.107(b)] related to
bad or missing records would be more
costly for operators to achieve
compliance. Under existing regulations,
in order for pipelines with insufficient
records to maintain operating pressure,
operators must excavate the pipeline at
every 10 lengths of pipe (commonly
referred to as joints) in accordance with
section II–D of appendix B of part 192
(as specified in § 192.107(b)), do a
cutout, determine material properties by
destructive tensile test, and repair the
pipe. The process is similar to doing a
repair via pipe replacement. PHMSA
developed a blended average for
performing such a cutout material
verification ($75,000) by reviewing
typical costs to repair a small segment
of pipe by pipe replacement. The
blended average accounted for various
pipe diameters and regional cost
variance. PHMSA assumed each joint is
40 feet long; ten joints is 400 ft. The
number of cutouts required by existing
rules is therefore the miles subject to
this requirement multiplied by 5,280/
400.
The proposed rule would allow
operators to perform a sampling
program that opportunistically takes
advantage of repairs and replacement
projects to verify material properties at
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the same time. Over time, operators will
collect enough information gain
significant confidence in the material
properties of pipe subject to this
requirement. The proposed rule
nominally targets conducting an average
of one material documentation process
per mile. In addition, operators would
be allowed to perform nondestructive
examinations, in lieu of cutouts and
destructive testing, when the technology
provides a demonstrable level of
confidence in the result. PHMSA
estimated that the incremental unit cost
of adding material documentation
activities to a repair or replacement
activity would be approximately
$17,000 per instance.
The proposed methods for addressing
pipelines with insufficient records are
exclusively applicable to HCA and all
Class 3 and 4 locations. Therefore, if the
proposed rule were in effect, operators
would be able to use the new methods
for addressing pipeline with insufficient
records in HCA and all Class 3 and 4
locations, but they would be required to
comply with existing (more expensive)
requirements for addressing the same
issue for pipelines located outside HCA
and all Class 3 and 4 locations.
Locations outside HCAs and all Class 3
and 4 are by definition lower risk,
meaning if incidents occur, the
consequences are expected to be smaller
than HCA and all Class 3 and 4
locations. PHMSA is considering
including provisions in the final rule
that would enable operators to use the
proposed methods for addressing
pipelines with insufficient records in
locations outside HCAs and all Class 3
and 4. To maintain flexibility, the
proposed methods may be an option to
existing requirements—as opposed to a
replacement of those requirements.
PHMSA requests comments on the
impacts of allowing operators to use the
new methods for addressing insufficient
records beyond HCAs and all Class 3
and 4 locations. What safety risks, if
any, should PHMSA consider? What are
the potential cost savings?
§ 192.710 Pipeline assessments.
Currently, part 192 does not contain
any requirement for operators to
conduct integrity assessments of
onshore transmission pipelines that are
not HCA segments as defined in
§ 192.903 and therefore not subject to
subpart O; i.e., pipelines that are not
located in a high consequence area
(HCA). Currently, only approximately
7% of onshore gas transmission
pipelines are located in HCAs. However,
coincident with integrity assessments of
HCA segments, industry has, as a
practical matter, assessed substantial
amounts of pipeline in non-HCA
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segments. For example, INGAA noted
(see Topic A comments, above) that
approximately 90 percent of Class 3 and
4 mileage not in HCAs are presently
assessed through over-testing during IM
assessments. This is due, in large part,
because ILI or pressure testing, by their
nature, assess large continuous
segments that may contain some HCA
segments but that could also contain
significant amounts of non- HCA
segments. In addition, based on the
integrity management principle of
continuous improvement, INGAA
members have committed (via its IMCI
action plan discussed under Topic A,
above) to first extend some degree of
integrity management to approximately
90 percent of people who live, work or
otherwise congregate near pipelines
(that is, within the pipelines’ Potential
Impact Radius, or PIR) by 2012. By
2020, INGAA operators have committed
to perform full integrity management on
pipelines covering 90 percent of the PIR
population. At a minimum, all ASME/
ANSI B31.8S requirements will be
applied, including mitigating corrosion
anomalies and applying integrity
management principles. Continuing to
areas of less population density, INGAA
members plan to apply integrity
management principles to pipelines
covering 100 percent of the PIR
population by 2030.
Given this level of commitment,
PHMSA has determined that it is
appropriate to codify requirements that
additional gas transmission pipelines
have an integrity assessment on a
periodic basis to monitor for, detect, and
remediate deleterious pipeline defects
and injurious anomalies. However,
INGAA does not represent all pipeline
operators subject to part 192. In
addition, in order to achieve the desired
outcome of performing assessments in
areas where people live, work, or
congregate, while minimizing the cost of
identifying such locations, PHMSA
proposes to base the requirements for
identifying those locations on processes
already being implemented by pipeline
operators.
The proposed rule would add a new
§ 192.710 to require that pipeline
segments in moderate consequence
areas that can accommodate inspection
by means of instrumented inline
inspection tools (i.e., ‘‘smart pigs’’) be
assessed within 15 years and every 20
years thereafter. PHMSA proposes to
define a new term ‘‘moderate
consequence area’’ or MCA. The
definition is based on the same
methodology as ‘‘high consequence
areas’’ as specified in § 192.903, but
with less stringent criteria. Moderate
consequence areas will be used to
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define the subset of locations where
integrity assessments are required. This
approach is proposed as a means to
minimize the effort needed on the part
of operators to identify the MCAs, since
transmission operators must have
already performed the analysis in order
to have identified the HCAs, or verify
that they have no HCAs. In addition, the
MCA definition would include locations
where interstate highways, freeways,
and expressways, and other principal 4lane arterial roadways are located
within the PIR.
Because significant non-HCA pipeline
mileage has been previously assessed in
conjunction with an assessment of HCA
segments in the same pipeline, PHMSA
also proposes to allow the use of those
prior assessments for non-HCA
segments to comply with the new
§ 192.710, provided that the assessment
was conducted in conjunction with an
integrity assessment required by subpart
O.
The proposed rule would also require
that the assessment required by new
§ 192.710 be conducted using the same
methods as proposed for HCAs (see
§ 192.921, below).
§ 192.711 Transmission lines:
General requirements for repair
procedures.
Section 192.711 prescribes general
requirements for repair procedures. For
non-HCA segments, the existing rule
requires that permanent repairs be made
as soon as feasible. However, no specific
repair criteria are provided and no
specific timeframe or pressure reduction
requirements are provided. PHMSA has
determined that more specific repair
criteria are needed for pipelines not
covered under the integrity management
rule. The proposed rule would amend
paragraph (b)(1) of section 192.711 to
require that specific conditions (i.e.,
repair criteria) defined in proposed
§ 192.713 (see below) be remediated,
and to require a reduction of operating
pressure for conditions that present an
immediate hazard.
§ 192.713 Transmission lines:
Permanent field repair of imperfections
and damages.
Section 192.713 prescribes
requirements for the permanent repair
of pipeline imperfection or damage that
impairs the serviceability of pipe in a
steel transmission line operating at or
above 40 percent of SMYS. PHMSA has
determined that more explicit
requirements are needed to better
identify criteria for the severity of
imperfection or damage that must be
repaired, and to identify the timeframe
within which repairs must be made.
Further, PHMSA has determined that
such repair criteria should apply to any
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transmission pipeline not covered under
subpart O, Integrity Management
regulations. PHMSA believes that
establishing these non-HCA segment
repair conditions are important because,
even though they are not within the
defined high consequence locations,
they could be located in populated areas
and are not without consequence. For
example, as reported by operators in the
2011 annual reports, while there are
approximately 20,000 miles of gas
transmission pipe in HCA segments,
there are approximately 65,000 miles of
pipe in Class 2, 3, and 4 populated
areas. PHMSA believes it is prudent and
appropriate to include criteria to assure
the timely repair of injurious pipeline
defects in non-HCA segments. These
changes will ensure the prompt
remediation of anomalous conditions,
while allowing operators to allocate
their resources to high consequence
areas on a higher priority basis. The
proposed rule would amend § 192.713
to establish immediate, two-year, and
monitored conditions which the
operator must remediate or monitor to
assure pipeline safety. PHMSA proposes
to use the same criteria as proposed for
HCAs (see 192.933, below), except that
conditions for which a one-year
response is required in HCAs would
require a two-year response in non-HCA
segments. In addition, PHMSA proposes
to prescribe more explicit requirements
for in situ evaluation of cracks and
crack-like defects using in-the-ditch
tools whenever required, such as when
an ILI, SCCDA, pressure test failure, or
other assessment identifies anomalies
that suggest the presence of such
defects.
§ 192.750 Launcher and receiver
safety.
PHMSA has determined that more
explicit requirements are needed for
safety when performing maintenance
activities that utilize launchers and
receivers to insert and remove
maintenance tools and devices. Such
facilities are subjected to pipeline
system pressures. Current regulations
for hazardous liquid pipelines (part 195)
have, since 1981, contained such safety
requirements for scraper and sphere
facilities (re: § 195.426). However,
current regulations for gas pipelines
(part 192) do not similarly require
controls or instrumentation to protect
against inadvertent breach of system
integrity due to incorrect operation of
launchers and receivers for in-line
inspection tools, scraper, and sphere
facilities. Accordingly, the proposed
rule would add a new section § 192.750
to require a suitable means to relieve
pressure in the barrel and either a
means to indicate the pressure in the
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barrel or a means to prevent opening if
pressure has not been relieved.
§ 192.911 What are the elements of
an integrity management program?
Paragraph (k) of § 192.911 requires
that integrity management programs
include a management of change
process as outlined in ASME/ANSI
B31.8S, section 11. PHMSA has
determined that specific attributes and
features of the management of change
process as currently specified in ASME/
ANSI B31.8S, section 11, should be
codified directly within the text of
§ 192.911(k). The proposed rule would
amend paragraph (k) to specify that the
features of the operator’s management of
change process must include the reason
for change, authority for approving
changes, analysis of implications,
acquisition of required work permits,
documentation, communication of
change to affected parties, time
limitations, and qualification of staff.
These general attributes of change
management are already required by
virtue of being invoked by reference to
ASME/ANSI B31.8S. However, PHMSA
believes it will improve the visibility
and emphasis on these important
program elements to require them
directly in the rule text.
§ 192.917 How does an operator
identify potential threats to pipeline
integrity and use the threat
identification in its integrity program?
Section 192.917 requires that integrity
management programs for covered
pipeline segments identify potential
threats to pipeline integrity and use the
threat identification in its integrity
program. Included within this
performance-based process are
requirements to identify threats to
which the pipeline is susceptible,
collect data for analysis, and perform a
risk assessment. Special requirements
are included to address plastic pipe and
particular threats such as third party
damage and manufacturing and
construction defects. Following the San
Bruno accident, the NTSB
recommended that Pacific Gas and
Electric (PG&E) assess every aspect of its
integrity management program, paying
particular attention to the areas
identified in the investigation, and
implement a revised program that
includes, at a minimum,
(1) a revised risk model to reflect the
Pacific Gas and Electric Company’s
actual recent experience data on leaks,
failures, and incidents;
(2) consideration of all defect and leak
data for the life of each pipeline,
including its construction, in risk
analysis for similar or related segments
to ensure that all applicable threats are
adequately addressed;
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(3) a revised risk analysis
methodology to ensure that assessment
methods are selected for each pipeline
segment that address all applicable
integrity threats, with particular
emphasis on design/material and
construction threats; and
(4) an improved self-assessment that
adequately measures whether the
program is effectively assessing and
evaluating the integrity of each covered
pipeline segment (NTSB
recommendation P–11–29).
In addition, the NTSB recommended
that PG&E conduct threat assessments
using the revised risk analysis
methodology incorporated in its
integrity management program, as
recommended in Safety
Recommendation P–11–29, and report
the results of those assessments to the
California Public Utilities Commission
and the Pipeline and Hazardous
Materials Safety Administration (NTSB
recommendation P–11–30). PHMSA has
also analyzed the issues the NTSB
identified in the investigation related to
information analysis and risk
assessment. PHMSA held a workshop
on July 21, 2011 to address perceived
shortcomings in the implementation of
integrity management risk assessment
processes and the information and data
analysis (including records) upon which
such risk assessments are based.
PHMSA sought input from stakeholders
on these issues and has determined that
additional clarification and specificity is
needed for existing performance-based
rules. These clarifications define and
emphasize the specific functions that
are required for risk assessment and
effective risk management.
These aspects of integrity
management have been an integral part
of PHMSA’s expectations for integrity
management since the inception of the
program. As specified in § 192.907(a),
PHMSA expected operators to start with
a framework, which would evolve into
a more detailed and comprehensive
program, and that the operator must
continually improve its integrity
management program, as it learned
more about the process and about the
material condition of its pipelines
through integrity assessments.
PHMSA elaborated on this
philosophy in the notice of final
rulemaking for subpart O (68 FR 69778):
or at the level of detail expected of final
integrity management plans. The framework
is an initial document that evolves into a
more detailed and comprehensive program.
The clarifications and additional
specificity proposed in this NPRM (with
respect to processes for implementing
the threat identification, risk
assessment, and preventive and
mitigative measures program elements),
reflect PHMSA’s expectation regarding
the degree of progress operators should
be making, or should have made, during
the first 10 years of the integrity
management program.
The current integrity management
rule invokes ASME/ANSI B31.8S by
reference to require that operators
implement specific attributes and
features of the threat identification, data
analysis, and risk assessment process.
PHMSA has determined that those
specific attributes and features of the
threat identification, data analysis, and
risk assessment processes as currently
specified in ASME/ANSI B31.8S,
section 11, should be codified within
the text of § 192.917. While continuing
to incorporate the industry standard by
reference, the proposed rule would
amend § 192.917 to insert certain
critical features of the industry standard
(ASME/ANSI B31.8S) directly into the
body of the Federal regulation.
Specifically, PHMSA proposes to
specify several pipeline attributes that
must be included in pipeline risk
assessments and to explicitly require
that operators integrate analyzed
information, and ensure that data be
verified and validated to the maximum
extent practical. PHMSA also
acknowledges that objective,
documented data is not always available
or obtainable. To the degree that
subjective data from subject matter
experts must be used, PHMSA proposes
to require that an operator’s program
include specific features to compensate
for subject matter expert bias.
In addition, PHMSA proposes to
clarify the performance-based risk
assessment aspects of the IM rule to
specify that operators perform risk
assessments that are adequate to
evaluate the effects of interacting
threats; determine additional preventive
and mitigative measures needed,
analyze how a potential failure could
affect high consequence areas, including
the consequences of the entire worstThe intent of allowing a framework was to
case incident scenario from initial
acknowledge that an operator cannot develop failure to incident termination; identify
a complete, fully mature integrity
the contribution to risk of each risk
management plan in a year. Nevertheless, it
factor, or each unique combination of
is important that an operator have thought
risk factors that interact or
through how the various elements of its plan
simultaneously contribute to risk at a
relate to each other early in the development
common location, account for, and
of its plan. The framework serves this
compensate for, uncertainties in the
purpose. . . . It need not be fully developed
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model and the data used in the risk
assessment; and evaluate risk reduction
associated with candidate risk reduction
activities such as preventive and
mitigative measures. In addition, in
response to specific NTSB
recommendation P–11–18, PHMSA
proposes performance-based language to
require that operators validate their risk
models in light of incident, leak, and
failure history and other historical
information. Such features are currently
requirements by virtue of being invoked
by reference in ASME/ANSI B31.8S.
However, PHMSA believes that these
important aspects of integrity
management will receive greater
emphasis and awareness if incorporated
directly into the rule text. The proposed
rule would also amend the requirements
for plastic pipe to provide specific
examples of integrity threats for plastic
pipe that must be addressed.
Lastly, PHMSA proposes to revise the
criteria in § 192.917(e)(3) and (4) for
addressing the threat of manufacturing
and construction defects and
concluding that latent defects are stable
as recommended in NTSB
recommendation P–11–15.
§ 192.921 How is the baseline
assessment to be conducted?
Section 192.921 requires that
pipelines subject to integrity
management rules have an integrity
assessment. Current rules allow the use
of in-line inspection, pressure testing in
accordance with subpart J, direct
assessment for the threats of external
corrosion, internal corrosion, and stress
corrosion cracking, and other
technology that the operator
demonstrates provides an equivalent
level of understanding of the condition
of the pipeline. Following the San
Bruno accident, PHMSA has determined
that baseline assessment methods
should be clarified to emphasize in-line
inspection and pressure testing over
direct assessment. At San Bruno, PG&E
relied heavily on direct assessment
under circumstances for which direct
assessment was not effective. Further,
ongoing research and industry response
to the ANPRM is beginning to indicate
that stress corrosion cracking direct
assessment is not as effective, and does
not provide an equivalent
understanding of pipe conditions with
respect to SCC defects, as ILI or
hydrostatic pressure testing at test
pressures that exceed those test
pressures required by subpart J (i.e.,
‘‘spike’’ hydrostatic pressure test).
Therefore, the proposed rule would
require that direct assessment only be
allowed when the pipeline cannot be
assessed using in-line inspection tools.
The proposed rule would also add three
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additional assessment methods: (1) A
‘‘spike’’ hydrostatic pressure test, which
is particularly well suited to address
SCC and other cracking or crack-like
defects, (2) guided wave ultrasonic
testing (GWUT) which is particularly
appropriate in cases where short
segments, such as road or railroad
crossing, are difficult to assess, and (3)
excavation with direct in situ
examination.
The current rule merely indicates that
in-line inspection (ILI) is an accepted
assessment method. The regulations are
currently silent on a number of issues
that significantly impact the quality and
effectiveness of ILI assessment results.
Such considerations are described in
ASME/ANSI B31.8S, but limited
guidance is provided. As discussed
above, the proposed rule strengthens
guidance in this area by adding a new
§ 192.493 to require compliance with
the requirements and recommendations
of API STD 1163–2005, NACE SP0102–
2010, and ANSI/ASNT ILI–PQ–2010
when conducting in-line inspection of
pipelines. Section 192.921(a)(1) would
be revised to require compliance with
§ 192.493 instead of ASME B31.8S for
baseline ILI assessments for covered
segments. In addition, a person
qualified by knowledge, training, and
experience would be required to analyze
the data obtained from an internal
inspection tool to determine if a
condition could adversely affect the safe
operation of the pipeline, and must
explicitly consider uncertainties in
reported results (including, but not
limited to, tool tolerance, detection
threshold, probability of detection,
probability of identification, sizing
accuracy, conservative anomaly
interaction criteria, location accuracy,
anomaly findings, and unity chart plots
or equivalent for determining
uncertainties and verifying actual tool
performance) in identifying and
characterizing anomalies.
GWUT has been in use by pipeline
operators for several years. Previously,
operators were required by
§ 192.921(a)(4) to submit a notification
to PHMSA as an ‘‘other technology’’
assessment method, in order to use
GWUT. In 2007, PHMSA developed
guidelines for how it would evaluate
notifications for use of GWUT. These
guidelines have been effectively used
for seven years, and PHMSA has gained
confidence that GWUT can be
effectively used to assess the integrity of
short segments of pipe. PHMSA
proposes to incorporate these guidelines
into a new Appendix F, which would be
invoked in § 192.921. Therefore,
notification for use of GWUT would no
longer be required.
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ASME B31.8S, Section 6.1, describes
both excavation and direct in situ
examination as specialized integrity
assessment methods, applicable to
particular circumstances:
It is important to note that some of the
integrity assessment methods discussed in
para. 6 only provide indications of defects.
Examination using visual inspection and a
variety of nondestructive examination (NDE)
techniques are required, followed by
evaluation of these inspection results in order
to characterize the defect. The operator may
choose to go directly to examination and
evaluation for the entire length of the
pipeline segment being assessed, in lieu of
conducting inspections. For example, the
operator may wish to conduct visual
examination of aboveground piping for the
external corrosion threat. Since the pipe is
accessible for this technique and external
corrosion can be readily evaluated,
performing in-line inspection is not
necessary.
PHMSA proposes to clarify its
requirements to explicitly add
excavation and direct in situ
examination as acceptable assessment
methods.
PHMSA also proposes that mandatory
integrity assessments proposed for nonHCA segments (see § 192.710, above)
could also use these assessment
methods.
§ 192.923 How is direct assessment
used and for what threats?
As discussed in the changes to
§§ 192.927 and 192.929 below, the
proposed rule would incorporate by
reference NACE SP0206–2006, ‘‘Internal
Corrosion Direct Assessment
Methodology for Pipelines Carrying
Normally Dry Natural Gas,’’ for
addressing ICDA and NACE SP0204–
2008, ‘‘Stress Corrosion Cracking Direct
Assessment,’’ for addressing SCCDA.
Sections 192.923(b)(2) and (b)(3) would
be revised to require compliance with
these standards.
§ 192.927 What are the requirements
for using Internal Corrosion Direct
Assessment (ICDA)?
Internal corrosion (IC) is a
degradation mechanism in which steel
pipe loses wall thickness due to
corrosion initiating on the inside surface
of the pipe. IC is one of several threats
that can impact pipeline integrity. IM
regulations in 49 CFR part 192 require
that pipeline operators assess covered
pipe segments periodically to detect
degradation from threats that their
analyses have indicated could affect the
segment. Not all covered segments are
subject to an IC threat, but some are. IC
direct assessment (ICDA) is an
assessment technique that can be used
to address this threat for gas pipelines.
ICDA involves evaluation and analysis
to determine locations at which a
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corrosive environment is likely to exist
inside a pipeline followed by excavation
and direct examination of the pipe wall
to determine whether IC is occurring.
Section 192.927 specifies
requirements for gas transmission
pipeline operators who use ICDA for IM
assessments. The requirements in
§ 192.927 were promulgated before the
NACE standard was published. They
require that operators follow ASME/
ANSI B31.8S provisions related to
ICDA. PHMSA has reviewed the NACE
standard and finds that it is more
comprehensive and rigorous than either
§ 192.927 or ASME B31.8S in many
respects. Some of the most important
features in the NACE standard are:
• The NACE standard requires more
direct examinations in most cases.
• The NACE standard encompasses
the entire pipeline segment and requires
that all inputs and outputs be evaluated.
• The NACE standard indirect
inspection model is different than the
Gas Technology Institute (GTI) model
currently referenced in § 192.927, but is
considered to be equivalent or superior.
Its range of applicability with respect to
operating pressure is greater than the
GTI model, thus allowing use of ICDA
in pipelines with lower operating
pressures and higher flow velocities.
• The NACE standard provides
additional guidance on how to
effectively determine areas to excavate
for detailed examinations for internal
corrosion.
The existing requirements in
§ 192.927 have one particular aspect
that has proven problematic. The
definition of regions and requirements
for selection of direct examination
locations in the regulations are tied to
the covered segment. Covered segment
boundaries are determined by
population density and other
consequence factors without regard to
the orientation of the pipe and the
presence of locations at which corrosive
agents may be introduced or may collect
and where internal corrosion would
most likely be detected (e.g., low spots).
Section 192.927 requires that locations
selected for excavation and detailed
examination be within covered
segments, meaning that the locations at
which IC would most likely be detected
may not be examined. Thus, the existing
requirements do not always facilitate
the discovery of internal corrosion that
could affect covered segments. PHMSA
is proposing to address this problem by
incorporating NACE SP0206–2006 and
by establishing additional requirements
for addressing covered segments within
the technical process defined by NACE
SP0206–2006.
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This proposed rule would require that
operators perform two direct
examinations within each covered
segment the first time ICDA is
performed. These examinations are in
addition to those required to comply
with the NACE standard practice. The
additional examinations are consistent
with the current requirement in
§ 192.927(c)(5)(ii) that operators apply
more restrictive criteria when
conducting ICDA for the first time and
are intended to provide a verification,
within the HCA, that the results of
applying the NACE process for the ICDA
are acceptable. Applying the NACE
process requires a more precise
knowledge of the pipeline’s orientation
(particularly slope) than operators may
have in many cases. Conducting
examinations within the HCA during
the first application of ICDA will verify
that application of the ICDA process
provides adequate information about the
covered segment. Operators who
identify IC on these additional
examinations, even though excavations
at locations determined using the NACE
process did not identify any, will know
that improvements to their knowledge
of pipeline orientation or other
adjustments to their application of the
NACE process to the covered segment
will be needed for future uses of ICDA.
§ 192.927(b) and (c) are revised to
address these issues.
§ 192.929 What are the requirements
for using Direct Assessment for Stress
Corrosion Cracking (SCCDA)?
Stress corrosion cracking (SCC) is a
degradation mechanism in which steel
pipe develops tight cracks through the
combined action of corrosion and
tensile stress (residual or applied).
These cracks can grow or coalesce to
affect the integrity of the pipeline. SCC
is one of several threats that can impact
pipeline integrity. IM regulations in 49
CFR part 192 require that pipeline
operators assess covered pipe segments
periodically to detect degradation from
threats that their analyses have
indicated could affect the segment,
though not all covered segments are
subject to an SCC threat. SCC direct
assessment (SCCDA) is an assessment
technique that can be used to address
this threat.
Section 192.929 specifies
requirements for gas transmission
pipeline operators who use SCCDA for
IM assessments. The requirements in
§ 192.929 were promulgated before
NACE Standard Practice SP0204–2008
was published. They require that
operators follow Appendix A3 of
ASME/ANSI B31.8S. This appendix
provides some guidance for conducting
SCCDA, but is limited to SCC that
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occurs in high-pH environments.
Experience has shown that pipelines
also can experience SCC degradation in
areas where the surrounding soil has a
pH near neutral (referred to as nearneutral SCC). NACE Standard Practice
SP0204–2008 addresses near-neutral
SCC in addition to high-pH SCC. In
addition, the NACE Standard provides
technical guidelines and process
requirements which are both more
comprehensive and rigorous for
conducting SCCDA than do § 192.929 or
ASME/ANSI B31.8S.
The NACE standard provides
additional guidance on:
• The factors that are important in the
formation of SCC on a pipeline and
what data should be collected;
• Additional factors, such as existing
corrosion, which could cause SCC to
form;
• Comprehensive data collection
guidelines, including the relative
importance of each type of data;
• Requirements to conduct close
interval surveys of cathodic protection
or other above-ground surveys to
supplement the data collected during
pre-assessment;
• Ranking factors to consider for
selecting excavation locations for both
near neutral and high pH SCC;
• Requirements on conducting direct
examinations, including procedures for
collecting environmental data,
preparing the pipe surface for
examination, and conducting Magnetic
Particle Inspection (MPI) examinations
of the pipe; and
• Post assessment analysis of results
to determine SCCDA effectiveness and
assure continual improvement.
NACE SP0204–2008 provides
comprehensive guidelines on
conducting SCCDA which are
commensurate with the state of the art.
It is more comprehensive in scope than
Appendix A3 of ASME/ANSI B31.8S.
PHMSA has concluded the quality and
consistency of SCCDA conducted under
IM requirements would be improved by
requiring the use of NACE SP0204–
2008. Revisions to § 192.929 are
proposed to address these issues.
§ 192.933 What actions must be
taken to address integrity issues?
Section 192.933 specifies those
injurious anomalies and defects which
must be remediated, and the timeframe
within which remediation must occur.
PHMSA has determined that the
existing rule has gaps, some injurious
anomalies and defects are not identified
in the rule as requiring remediation in
a timely manner commensurate with
their seriousness. The proposed rule
would designate the following types of
anomalies/defects as immediate
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conditions: Metal loss greater than 80%
of nominal wall thickness; indication of
metal-loss affecting certain longitudinal
seams; significant stress corrosion
cracking; and selective seam weld
corrosion. The proposed rule would also
designate the following types of
anomalies/defects as one-year
conditions: Calculation of the remaining
strength of the pipe shows a predicted
failure pressure ratio at the location of
the anomaly less than or equal to 1.25
for Class 1 locations, 1.39 for Class 2
locations, 1.67 for Class 3 locations, and
2.00 for Class 4 locations (comparable to
the alternative design factor specified in
§ 192.620(a)); area of general corrosion
with a predicted metal loss greater than
50% of nominal wall; predicted metal
loss greater than 50% of nominal wall
that is located at a crossing of another
pipeline, or is in an area with
widespread circumferential corrosion,
or is in an area that could affect a girth
weld; gouge or groove greater than
12.5% of nominal wall; and any
indication of crack or crack-like defect
other than an immediate condition.
The methods specified in the IM rule
to calculate predicted failure pressure
are explicitly not valid if metal exceeds
80% of wall thickness. Corrosion
affecting a longitudinal seam, especially
associated with seam types that are
known to be susceptible to latent
manufacturing defects such as the failed
pipe at San Bruno, and selective seam
weld corrosion, are known time
sensitive integrity threats. Stress
corrosion cracking is listed in ASME/
ANSI B31.8S as an immediate repair
condition, which is not reflected in the
current IM regulations. PHMSA
proposes to add requirements to address
these gaps.
With respect to SCC, PHMSA has
incorporated repair criteria to address
NTSB recommendation P–12–3 that
resulted from the investigation of the
Marshall, Michigan crude oil accident.
From its investigation, the NTSB
recommended that PHMSA revise
§ 195.452 to clearly state (1) when an
engineering assessment of crack defects,
including environmentally assisted
cracks, must be performed; (2) the
acceptable methods for performing these
engineering assessments, including the
assessment of cracks coinciding with
corrosion with a safety factor that
considers the uncertainties associated
with sizing of crack defects; (3) criteria
for determining when a probable crack
defect in a pipeline segment must be
excavated and time limits for
completing those excavations; (4)
pressure restriction limits for crack
defects that are not excavated by the
required date; and (5) acceptable
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methods for determining crack growth
for any cracks allowed to remain in the
pipe, including growth caused by
fatigue, corrosion fatigue, or stress
corrosion cracking as applicable (NTSB
recommendation P–12–3). Although the
recommendation was focused on part
195, the issue applies to gas pipelines
regulated under part 192. PHMSA
proposes to allow the use of engineering
assessment to evaluate if SCC is
significant (and thus categorized as an
‘‘immediate’’ condition), or not
significant (and thus categorized as a
‘‘one-year’’ condition), but that an
engineering assessment not be allowed
to justify not remediating any known
indications of SCC. Further, PHMSA
proposes to adopt the definition of
significant SCC from NACE SP0204–
2008.
The current rule includes no explicit
metal loss repair criteria for one-year
conditions, other than one immediate
condition. The rule does direct
operators to use Figure 4 in ASME
B31.8S to determine non-immediate
metal loss repair criteria. PHMSA
proposes to repeal the reference to
Figure 4, and explicitly include selected
metal loss repair conditions in the oneyear criteria. These new criteria are
consistent with similar criteria currently
invoked in the hazardous liquid
integrity management rule at 40 CFR
195.452(h). In addition, PHMSA
proposes to incorporate safety factors
commensurate with the class location in
which the pipeline is located, to include
predicted failure pressure less than or
equal to 1.25 times MAOP for Class 1
locations, 1.39 times MAOP for Class 2
locations, 1.67 times MAOP for Class 3
locations, and 2.00 times MAOP for
Class 4 locations in HCAs. Lastly, in
response to the lessons learned from the
Marshall, Michigan rupture, PHMSA
proposes to include any crack or cracklike defect that does not meet the
proposed immediate criteria, as a one
year condition.
In addition, as a result of its
investigation of the Marshall, Michigan
crude oil spill, the NTSB recommended
that PHMSA revise § 195.452(h)(2), the
‘‘discovery of condition,’’ to require, in
cases where a determination about
pipeline threats has not been obtained
within 180 days following the date of
inspection, that pipeline operators
notify the Pipeline and Hazardous
Materials Safety Administration and
provide an expected date when
adequate information will become
available (NTSB recommendation P–12–
4). Although the recommendation was
focused on part 195, the issue applies to
gas pipelines regulated under part 192.
Accordingly, PHMSA proposes to
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amend paragraph (b) of § 192.933 to
require that operators notify PHMSA
whenever the operator cannot obtain
sufficient information to determine if a
condition presents a potential threat to
the integrity of the pipeline, within 180
days of completing the assessment.
Lastly, PHMSA proposes to require
that pipe and material properties used
in remaining strength calculations must
be documented in reliable, traceable,
verifiable, and complete records. If such
records are not available, pipe and
material properties used in the
remaining strength calculations would
be required to be based on properties
determined and documented in
accordance with § 192.607.
§ 192.935 What additional
preventive and mitigative measures
must an operator take?
Section 192.935 requires an operator
to take additional measures beyond
those already required by part 192 to
prevent a pipeline failure and to
mitigate the consequences of a pipeline
failure in a high consequence area
(HCA). An operator must conduct a risk
analysis to identify the additional
measures to protect the high
consequence area and improve public
safety. As discussed above, PHMSA
proposes to amend § 192.917 to clarify
the guidance for risk analyses operators
use to evaluate and select additional
preventive and mitigative measures. In
addition, PHMSA has determined that
some additional prescriptive preventive
and mitigative measures are needed to
assure that public safety is enhanced in
HCAs and affords greater protections for
HCAs. This proposed rule would
expand the listing of example
preventive and mitigative measures
operators must consider, require that
seismicity be analyzed to mitigate the
threat of outside force damage, and
would add specific enhanced measures
for managing external corrosion and
internal corrosion inside HCAs.
With respect to additional preventive
and mitigative measures operators must
consider, PHMSA proposes to specify
that preventive and mitigative measures
include (i) correction of the root causes
of past incidents in order to prevent
recurrence, (ii) adequate operations and
maintenance processes, (iii) adequate
resources for successful execution of
safety related activities, (iv) additional
right-of-way patrols, (v) hydrostatic tests
in areas where material has quality
issues or lost records, (vi) tests to
determine material mechanical and
chemical properties for unknown
properties that are needed to assure
integrity or substantiate MAOP
evaluations including material property
tests from removed pipe that is
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representative of the in-service pipeline,
(vii) re-coating of damaged, poorly
performing, or disbonded coatings, and
(viii) additional depth-of-cover survey at
roads, streams and rivers, among others.
These example preventive and
mitigative measures do not alter the
fundamental requirement to identify
and implement preventive and
mitigative measures, but do provide
additional guidance and clarify
PHMSA’s expectations with this
important aspect of integrity
management.
Section 29 of the Act requires
operators to consider seismicity when
evaluating threats. Accordingly, PHMSA
proposes to include seismicity of the
area in evaluating preventive and
mitigative measures with respect to the
threat of outside force damage.
With respect to internal corrosion and
external corrosion, PHMSA proposes to
add new paragraphs (f) and (g) to
§ 192.935 to specify that an operator
must enhance its corrosion control
program in HCAs to provide additional
protections from the threat of corrosion.
More specifically, operators would be
required to conduct periodic closeinterval surveys, coating surveys,
interference surveys, and gas-quality
monitoring inside HCAs. The
requirements would include specific
minimum performance standards for
these activities.
Lastly, to conform to the revised
definition of ‘‘electrical survey,’’ the use
of that term in § 192.935 would be
replaced with ‘‘indirect assessment’’ to
accommodate other techniques in
addition to close-interval surveys.
§ 192.937 What is a continual
process of evaluation and assessment to
maintain a pipeline’s integrity?
Section 192.937 requires that
operators continue to periodically assess
HCA segments and periodically evaluate
the integrity of each covered pipeline
segment. PHMSA has determined that
conforming amendments would be
needed to implement, and be consistent
with, the changes discussed above for
§§ 192.917, 192.921, 192.933, and
192.935. The proposed rule would
require that the continual process of
evaluation and assessment implement
and be consistent with data integration
and risk assessment information in
order to identify the threats specific to
each HCA segment, including
interacting threats, and the risk
represented by these threats (§ 192.917),
selection and use of assessment
methods (§ 192.921), decisions about
remediation (§ 192.933), and identify
additional preventive and mitigative
measures (§ 192.935) to avert or reduce
threats to acceptable levels.
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§ 192.939 What are the required
reassessment intervals?
Section 192.939 specifies
reassessment intervals for pipelines
subject to integrity management
requirements. Section 5 of the Act
includes a technical correction that
clarified that periodic reassessments
must occur, at a minimum of once every
7 calendar years, but that the Secretary
may extend such deadline for an
additional 6 months if the operator
submits written notice to the Secretary
with sufficient justification of the need
for the extension. PHMSA would expect
that any justification, at a minimum,
would need to demonstrate that the
extension does not pose a safety risk. By
this rulemaking, PHMSA intends to
codify this technical correction. The
proposed rule would implement this
statutory requirement.
§ 192.941 What is a low stress
reassessment?
Section 192.941, among other
requirements, specifies that, to address
the threat of external corrosion on
cathodically protected pipe in a HCA
segment, an operator must perform an
electrical survey (i.e. indirect
examination tool/method) at least every
7 years on the HCA segment. PHMSA
proposes to make conforming edits to
the language of this requirement to
accommodate the revised definition of
the term ‘‘electrical survey.’’ To conform
to the revised definition of ‘‘electrical
survey,’’ the use of that term in
§ 192.941 would be replaced with
‘‘indirect assessment’’ to accommodate
other techniques in addition to closeinterval surveys.
Appendix A to Part 192—Records
Retention Schedule for Transmission
Pipelines
As discussed under § 192.13, above,
the proposed rule would more clearly
articulate the requirements for records
preparation and retention for
transmission pipelines and to require
that records be reliable, traceable,
verifiable, and complete. New appendix
A to part 192 provides specific
requirements and records retention
periods.
Appendix D to Part 192—Criteria for
Cathodic Protection and Determination
of Measurements
Appendix D to part 192 specifies
requirements for cathodic protection of
steel, cast iron & ductile pipelines.
PHMSA has determined that this
guidance needs to be updated to
incorporate lessons learned since this
appendix was first promulgated in 1971.
The proposed rule would update
appendix D accordingly by eliminating
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outdated guidance on cathodic
protection and interpretation of voltage
measurement to better align with
current standards.
Appendix E to Part 192—Guidance on
Determining High Consequence Areas
and on Carrying out Requirements in
the Integrity Management Rule
Appendix E to part 192 provides
guidance for preventive and mitigative
measures for HCA segment subject to
subpart O. PHMSA proposes to make
conforming edits to the language in this
appendix to accommodate the revised
definition of the term ‘‘electrical
survey.’’ To conform to the revised
definition of ‘‘electrical survey,’’ the use
of that term in Appendix E would be
replaced with ‘‘indirect assessment’’ to
accommodate other techniques in
addition to close-interval surveys.
Appendix F to Part 192—Criteria for
Conducting Integrity Assessments Using
Guided Wave Ultrasonic Testing
(GWUT)
As discussed under § 192.941 above,
a new appendix F to part 192 is
proposed to provide specific
requirements and acceptance criteria for
the use of GWUT as an integrity
assessment method. Operators must
apply all 18 criteria defined in
Appendix F to use GWUT as an
integrity assessment method. If an
operator applied GWUT technology in a
manner that does not conform to
Appendix F, it would be considered
‘‘other technology’’ in §§ 192.710,
192.921, and 192. 937.
VI. Availability of Standards
Incorporated by Reference
PHMSA currently incorporates by
reference into 49 CFR parts 192, 193,
and 195 all or parts of more than 60
standards and specifications developed
and published by standard developing
organizations (SDOs). In general, SDOs
update and revise their published
standards every 3 to 5 years to reflect
modern technology and best technical
practices.
The National Technology Transfer
and Advancement Act of 1995 (Pub. L.
104–113) directs Federal agencies to use
voluntary consensus standards in lieu of
government-written standards whenever
possible. Voluntary consensus standards
are standards developed or adopted by
voluntary bodies that develop, establish,
or coordinate technical standards using
agreed-upon procedures. In addition,
Office of Management and Budget
(OMB) issued OMB Circular A–119 to
implement Section 12(d) of Public Law
104–113 relative to the utilization of
consensus technical standards by
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Federal agencies. This circular provides
guidance for agencies participating in
voluntary consensus standards bodies
and describes procedures for satisfying
the reporting requirements in Public
Law 104–113.
In accordance with the preceding
provisions, PHMSA has the
responsibility for determining, via
petitions or otherwise, which currently
referenced standards should be updated,
revised, or removed, and which
standards should be added to 49 CFR
parts 192, 193, and 195. Revisions to
incorporated by reference materials in
49 CFR parts 192, 193, and 195 are
handled via the rulemaking process,
which allows for the public and
regulated entities to provide input.
During the rulemaking process, PHMSA
must also obtain approval from the
Office of the Federal Register to
incorporate by reference any new
materials.
On January 3, 2012, President Obama
signed the Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011,
Public Law 112–90. Section 24 states:
‘‘Beginning 1 year after the date of
enactment of this subsection, the
Secretary may not issue guidance or a
regulation pursuant to this chapter that
incorporates by reference any
documents or portions thereof unless
the documents or portions thereof are
made available to the public, free of
charge, on an Internet Web site.’’ 49
U.S.C. 60102(p).
On August 9, 2013, Public Law 113–
30 revised 49 U.S.C. 60102(p) to replace
‘‘1 year’’ with ‘‘3 years’’ and remove the
phrases ‘‘guidance or’’ and ‘‘, on an
Internet Web site.’’ This resulted in the
current language in 49 U.S.C. 60102(p),
which now reads as follows:
‘‘Beginning 3 years after the date of
enactment of this subsection, the
Secretary may not issue a regulation
pursuant to this chapter that
incorporates by reference any
documents or portions thereof unless
the documents or portions thereof are
made available to the public, free of
charge.’’
Further, the Office of the Federal
Register issued a November 7, 2014,
rulemaking (79 FR 66278) that revised 1
CFR 51.5 to require that agencies detail
in the preamble of a proposed
rulemaking the ways the materials it
proposes to incorporate by reference are
reasonably available to interested
parties, or how the agency worked to
make those materials reasonably
available to interested parties. In
relation to this proposed rulemaking,
PHMSA has contacted each SDO and
has requested a hyperlink to a free copy
of each standard that has been proposed
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for incorporation by reference. Access to
these standards will be granted until the
end of the comment period for this
proposed rulemaking. Access to these
documents can be found on the PHMSA
Web site at the following URL: https://
www.phmsa.dot.gov/pipeline/regs
under ‘‘Standards Incorporated by
Reference.’’
Consistent with the proposed
amendments in this document, PHMSA
proposes to incorporate by reference the
following materials identified as
follows:
• API Standard 1163–2005, ‘‘In-line
Inspection Systems Qualification
Standards.’’—This Standard serves as an
umbrella document to be used with and
complement companion standards.
NACE RP0102 Standard Recommended
Practice, In-Line Inspections of
Pipelines; and ASNT ILI–PQ In-Line
Inspection Personnel Qualification &
Certification all have been developed
enabling service providers and pipeline
operators to provide rigorous processes
that will consistently qualify the
equipment, people, processes and
software utilized in the in-line
inspection industry.
• NACE Standard Practice 0102–
2010, ‘‘Inline Inspection of
Pipelines.’’—This standard is intended
for use by individuals and teams
planning, implementing, and managing
ILI projects and programs. The
incorporation of this standard into the
Federal pipeline safety regulations
would promote a higher level of safety
by establishing consistent standards to
qualify the equipment, people,
processes, and software utilized by the
ILI industry.
• NACE Standard Practice 0204–
2008, ‘‘Stress Corrosion Cracking Direct
Assessment.’’—The standard practice
for SCCDA presented in this standard
addresses the situation in which a
pipeline company has identified a
portion of its pipeline as an area of
interest with respect to SCC based on its
history, operations, and risk assessment
process and has decided that direct
assessment is an appropriate approach
for integrity assessment. This standard
provides guidance for managing SCC by
selecting potential pipeline segments,
selecting dig sites within those
segments, inspecting the pipe, collecting
and analyzing data during the dig,
establishing a mitigation program,
defining the reevaluation interval, and
evaluating the effectiveness of the
SCCDA process.
• NACE Standard Practice 0206–
2006, ‘‘International Corrosion Direct
Assessment Methodology for Pipelines
Carrying Normally Dry Natural Gas.’’
This standard covers the NACE internal
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corrosion direct assessment (ICDA)
process for normally dry natural gas
pipeline systems. This standard is
intended to serve as a guide for applying
the NACE DG–ICDA process on natural
gas pipeline systems that meet the
feasibility requirements of Paragraph 3.3
of this standard.
• ANSI/ASNT ILI–PQ–2010, ‘‘In-line
Inspection Personnel Qualification and
Certification.’’ The ASNT standard
provides for qualification and
certification requirements that are not
addressed in part 192. The
incorporation of this standard into the
Federal pipeline safety regulations
would promote a higher level of safety
by establishing consistent standards to
qualify the equipment, people,
processes, and software utilized by the
ILI industry.
• Battelle’s Experience with ERW and
Flash Welding Seam Failures: Causes
and Implications (Task 1.4). This report
presents an evaluation of the database
dealing with failures originating in
electric resistance welds (ERW) and
flash weld (FW) seam defects as
quantified by Battelle’s archives and the
related literature.
• Battelle Memorial Institute,
‘‘Models for Predicting Failure Stress
Levels for Defects Affecting ERW and
Flash-Welded Seams’’ (Subtask 2.4).
This document presents an analysis of
two known defect assessment methods
in an effort to find suitable ways to
satisfactorily predict the failure stress
levels of defects in or adjacent to ERW
or flash-welded line pipe seams.
• Battelle Final Report No. 13–021,
‘‘Predicting Times to Failures for ERW
Seam Defects that Grow by Pressure
Cycle Induced Fatigue (Subtask 2.5).’’
The work described in this report is part
of a comprehensive study of ERW seam
integrity and its impact on pipeline
safety. The objective of this part of the
work is to identify appropriate means
for predicting the remaining lives of
defects that remain after a seam integrity
assessment and that may become
enlarged by pressure-cycle-induced
fatigue.
• Battelle Memorial Institute, ‘‘Final
Summary Report and recommendations
for the Comprehensive Study to
Understand Longitudinal ERW Seam
Failures—Phase 1’’ (Task 4.5).—This
report summarizes work completed as
part of a comprehensive project that
resulted from a contract with Battelle,
working with Kiefner and Associates
(KAI) and Det Norske Veritas (DNV) as
subcontractors, to address the concerns
identified in NTSB recommendation (P–
09–1) regarding the safety and
performance of ERW pipe.
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VII. Regulatory Analysis and Notices
This proposed rule 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 design, installation,
inspection, emergency plans and
procedures, testing, construction,
extension, operation, replacement, and
maintenance of pipeline facilities. The
amendments to the requirements for
petroleum gas pipelines addressed in
this rulemaking are issued under this
authority.
Executive Orders 12866 and 13563, and
DOT Policies and Procedures
This proposed rule is a significant
regulatory action under section 3(f) of
Executive Order 12866 and, therefore,
was reviewed by the Office of
Management and Budget. This proposed
rule is significant under the Regulatory
Policies and Procedures of the
Department of Transportation.
(44 FR 11034, February 26, 1979).
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Executive Orders 12866 and 13563
require that proposed rules deemed
‘‘significant’’ include a Regulatory
Impact Analysis, and that this analysis
requires quantified estimates of the
benefits and costs of the rule. PHMSA
is providing the PRIA for this proposed
rule simultaneously with this
document, and it is available in the
docket.
PHMSA estimates the total present
value of benefits from the proposed rule
to be approximately $3,234 to $3,738
million 39 using a 7% discount rate
($4,050 to $4,663 million using a 3%
discount rate) and the present value of
costs to be approximately $597 million
using a 7% discount rate ($711 million
using a 3% discount rate). The table in
the executive summary provides a
detailed estimate of the average annual
costs and benefits for each major topic
area.
Regulatory Flexibility Act
The Regulatory Flexibility Act (RFA),
as amended by the Small Business
Regulatory Flexibility Fairness Act of
1996, requires Federal regulatory
agencies to prepare an Initial Regulatory
Flexibility Analysis (IFRA) for any
proposed rule subject to notice-andcomment rulemaking under the
Administrative Procedure Act unless
the agency head certifies that the
making will not have a significant
economic impact on a substantial
number of small entities. PHMSA has
39 Range reflects uncertainty in defect failure rates
for Topic Area 1.
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data on gas transmission pipeline
operators affected by the proposed rule.
However, PHMSA does not have data on
currently unregulated gas gathering
pipeline operators. Therefore, PHMSA
prepared an IFRA which is available in
the docket for the rulemaking.
Executive Order 13175
PHMSA has analyzed this proposed
rule according to the principles and
criteria in Executive Order 13175,
‘‘Consultation and Coordination with
Indian Tribal Governments.’’ Because
this proposed rule would not
significantly or uniquely affect the
communities of the Indian tribal
governments or impose substantial
direct compliance costs, the funding
and consultation requirements of
Executive Order 13175 do not apply.
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
rulemaking will impact the information
collections described below.
Based on the proposals in this rule,
PHMSA will submit an information
collection revision request to OMB for
approval based on the requirements in
this proposed rule. The information
collection is contained in the pipeline
safety regulations, 49 CFR parts 190
through 199. The following information
is provided for each information
collection: (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 burden for
the following information collections
are estimated to be revised as follows:
1. Title: Recordkeeping Requirements
for Gas Pipeline Operators.
OMB Control Number: 2137–0049.
Current Expiration Date: 04/30/2018.
Abstract: A person owning or
operating a natural gas pipeline facility
is required to maintain records, make
reports, and provide information to the
Secretary of Transportation at the
Secretary’s request. Based on the
proposed revisions in this rule, PHMSA
estimates that 100 new Type A, Area 2
gas gathering pipeline operators ∼ (2200
Type A, Area 2 miles w/o prior
regulation/22) will be new to these
requirements. PHMSA estimates that it
will take these 100 operators 6 hours to
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create and maintain records associated
with Emergency Planning requirements.
Therefore, PHMSA expects to add 100
responses and 600 hours to this
information collection as a result of the
provisions in the proposed rule.
Affected Public: Natural Gas Pipeline
Operators.
Annual Reporting and Recordkeeping
Burden:
Total Annual Responses: 12,400.
Total Annual Burden Hours: 941,054.
Frequency of Collection: On occasion.
2. Title: Reporting Safety-Related
Conditions on Gas, Hazardous Liquid,
and Carbon Dioxide Pipelines and
Liquefied Natural Gas Facilities.
OMB Control Number: 2137–0578.
Current Expiration Date: 7/31/2017.
Abstract: 49 U.S.C. 60102 requires
each operator of a pipeline facility
(except master meter operators) to
submit to DOT a written report on any
safety-related condition that causes or
has caused a significant change or
restriction in the operation of a pipeline
facility or a condition that is a hazards
to life, property or the environment.
Based on the proposed revisions in this
rule, PHMSA estimates that an
additional 71,109 miles of pipe will
become subject to the safety related
condition reporting requirements.
PHMSA estimates that such reports will
be submitted at a rate of 0.23 reports per
1,000 miles. PHMSA expects that,
collectively, Type A, Area 2 lines will
submit approximately 16 reports on an
annual basis. As a result, PHMSA is
adding an additional 16 responses and
96 burden hours to this information
collection.
Affected Public: Operators of Natural
Gas, Hazardous Liquid, and Liquefied
Natural Gas pipelines.
Annual Reporting and Recordkeeping
Burden:
Total Annual Responses: 158.
Total Annual Burden Hours: 948.
Frequency of Collection: On occasion.
3. Title: Pipeline Integrity
Management in High Consequence
Areas Gas Transmission Pipeline
Operators.
OMB Control Number: 2137–0610.
Current Expiration Date: 3/31/2016.
Abstract: This information collection
request pertains to Gas Transmission
operators jurisdictional to 49 CFR part
192 subpart O—Gas Transmission
Integrity Management Program. PHMSA
is proposing that operators subject to
Integrity Management requirements
provide PHMSA notice when 180 days
is insufficient to conduct an integrity
assessment following the discovery of a
condition (192.933). PHMSA estimates
that 20% of the 721 operators (721*.2 =
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144 operators) will file such a
notification. PHMSA estimates that each
notification will take about 30 minutes.
Based on this provision, PHMSA
proposes to add 144 responses and 72
hours to this information collection.
Affected Public: Gas Transmission
operators.
Annual Reporting and Recordkeeping
Burden:
Total Annual Responses: 877.
Total Annual Burden Hours:
1,018,879.
Frequency of Collection: On occasion.
4. Title: Incident and Annual Reports
for Gas Pipeline Operators.
OMB Control Number: 2137–0522.
Current Expiration Date: 10/31/2017.
Abstract: This information collection
covers the collection of information
from Gas pipeline operators for
Incidents and Annual reports. PHMSA
is revising the Gas Transmission
Incident report to incorporate Moderate
Consequence Areas and to address
Gathering line operators that are only
subject to reporting. PHMSA estimates
that operators of currently exempt gas
gathering pipelines will have to submit
incident reports for 27.5 incidents over
the next three years, an average of 9
reports annually. However, the
proposed rule is expected to reduce the
number of incidents by at least 10 each
year which would result in a cumulative
increase of zero incidents.
PHMSA is also revising the Gas
Transmission and Gas Gathering Annual
Report to collect additional information
including mileage of pipe subject to the
IVP and MCA criteria. Based on the
proposed revisions, PHMSA estimates
that an additional annual 500 reports to
the current 1,440 reports will be
submitted based on the required
reporting of non-regulated gathering
lines and gathering lines now subject to
certain safety provisions. Further
PHMSA estimates that the Annual
report will require an additional 5
hours/report to the currently approved
42 hours due to collection of MCA data
and IVP provisions. Therefore the
overall burden allotted for the reporting
of Gas annual reports will increase by
30,700 hours from 60,480 hours (42
hours*1,440 reports) to 91,180 hours (47
hours*1,940 reports).
As a result of the provisions
mentioned above, the burden for this
information collection will increase by
500 responses and 30,700 burden hours.
Affected Public: Natural Gas Pipeline
Operators.
Annual Reporting and Recordkeeping
Burden:
Total Annual Responses: 12,664.
Total Annual Burden Hours: 103,182
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Frequency of Collection: On occasion.
5. Title: National Registry of Pipeline
and LNG Operators.
OMB Control Number: 2137–0627.
Current Expiration Date: 05/31/2018.
Abstract: The National Registry of
Pipeline and LNG Operators serves as
the storehouse for the reporting
requirements for an operator regulated
or subject to reporting requirements
under 49 CFR part 192, 193, or 195. This
registry incorporates the use of two
forms. The forms for assigning and
maintaining Operator Identification
(OPID) information are the Operator
Assignment Request Form (PHMSA F
1000.1) and Operator Registry
Notification Form (PHMSA F 1000.2).
PHMSA plans to make revisions to the
form/instructions to account for
‘‘reporting only’’ gathering operators.
PHMSA estimates that 500 gas gathering
operators will require a new OPID.
Based on a 3 year average this results in
an additional 167 responses a year
initially. In addition to the OPID
assignment, PHMSA estimates that 123
gathering operators will submit approx.
1 notification per year. PHMSA
estimates that each submission will take
approx. 1 hour to complete. Based on
these provisions, PHMSA expects this
information collection to increase by
290 responses and 290 burden hours.
Affected Public: Operators of Natural
Gas, Hazardous Liquid, and Liquefied
Natural Gas pipelines.
Annual Reporting and Recordkeeping
Burden:
Total Annual Responses: 920.
Total Annual Burden Hours: 920.
Frequency of Collection: On occasion.
Requests for copies of these
information collections should be
directed to Angela Dow or Cameron
Satterthwaite, Office of Pipeline Safety
(PHP–30), Pipeline Hazardous Materials
Safety Administration (PHMSA), 2nd
Floor, 1200 New Jersey Avenue SE.,
Washington, DC 20590–0001,
Telephone (202) 366–4595.
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
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20823
of appropriate automated, electronic,
mechanical, or other technological
collection techniques.
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 June
7, 2016.
Unfunded Mandates Reform Act of 1995
An evaluation of Unfunded Mandates
Reform Act (UMRA) considerations is
performed as part of the Preliminary
Regulatory Impact Assessment. The
estimated costs to the States are
approximately $1.3 million per year and
are significantly less than the UMRA
criterion of $151 million per year ($100
million, adjusted for inflation). The
estimated costs to the private sector are
in excess of the UMRA criterion of $151
million per year. A copy of the
Preliminary Regulatory Impact
Assessment is available for review in
the docket.
National Environmental Policy Act
PHMSA analyzed this proposed rule
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 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
proposed action is in the docket.
Executive Order 13132
PHMSA has analyzed this proposed
rule according to Executive Order 13132
(‘‘Federalism’’). The proposed rule does
not have a substantial direct effect 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. This proposed
rule does not impose substantial direct
compliance costs on State and local
governments. This proposed rule would
not preempt state law for intrastate
pipelines. Therefore, the consultation
and funding requirements of Executive
Order 13132 do not apply.
Executive Order 13211
This proposed rule is not 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
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supply, distribution, or energy use.
Further, the Office of Information and
Regulatory Affairs has not designated
this proposed rule as a significant
energy action.
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 in the
Federal Register published on April 11,
2000 (70 FR 19477) or visit https://
dms.dot.gov.
Regulation Identifier Number (RIN)
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 number contained in the
heading of this document can be used
to cross-reference this action with the
Unified Agenda.
List of Subjects
49 CFR Part 191
Pipeline reporting requirements,
Integrity Management, Pipeline safety,
Gas gathering.
49 CFR Part 192
Incorporation by reference, Pipeline
Safety, Fire prevention, Security
measures.
In consideration of the foregoing,
PHMSA proposes to amend 49 CFR
parts 191 and 192 as follows:
PART 191—TRANSPORTATION OF
NATURAL AND OTHER GAS BY
PIPELINE; ANNUAL, INCIDENT, AND
OTHER REPORTING
§ 191.23 Reporting safety-related
conditions.
1. The authority citation for part 191
is revised to read as follows:
■
Authority: 49 U.S.C. 5121, 60102, 60103,
60104, 60108, 60117, 60118, 60124, 60132,
and 60139; and 49 CFR 1.97.
2. In § 191.1, paragraphs (a) and (b)(2)
and (3) are revised, paragraph (b)(4) is
deleted, and paragraph (c) is added to
read as follows:
■
mstockstill on DSK4VPTVN1PROD with PROPOSALS2
§ 191.1
Scope.
(a) This part prescribes requirements
for the reporting of incidents, safetyrelated conditions, exceedances of
maximum allowable operating pressure
(MAOP), annual pipeline summary data,
National Operator Registry information,
and other miscellaneous conditions by
operators of gas pipeline facilities
located in the United States or Puerto
Rico, including pipelines within the
limits of the Outer Continental Shelf as
that term is defined in the Outer
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Continental Shelf Lands Act (43 U.S.C.
1331). This part applies to offshore
gathering lines and to onshore gathering
lines, whether designated as ‘‘regulated
onshore gathering lines’’ or not (as
determined in § 192.8 of this chapter).
(b) * * *
(2) Pipelines on the Outer Continental
Shelf (OCS) that are producer-operated
and cross into State waters without first
connecting to a transporting operator’s
facility on the OCS, upstream (generally
seaward) of the last valve on the last
production facility on the OCS. Safety
equipment protecting PHMSA-regulated
pipeline segments is not excluded.
Producing operators for those pipeline
segments upstream of the last valve of
the last production facility on the OCS
may petition the Administrator, or
designee, for approval to operate under
PHMSA regulations governing pipeline
design, construction, operation, and
maintenance under 49 CFR 190.9; or
(3) Pipelines on the Outer Continental
Shelf upstream of the point at which
operating responsibility transfers from a
producing operator to a transporting
operator.
(c) Sections 191.22(b) and 191.29 do
not apply to gathering of gas—
(1) Through a pipeline that operates at
less than 0 psig (0 kPa);
(2) Through an onshore pipeline that
is not a regulated onshore gathering line
(as determined in § 192.8 of this
chapter); and
(3) Within inlets of the Gulf of
Mexico, except for the requirements in
§ 192.612.
■ 3. In § 191.23, revise paragraph (a)(5),
add paragraph (a)(9), and revise
paragraph (b)(4) to read as follows:
(a) * * **
(5) Any malfunction or operating error
that causes the pressure of a distribution
or gathering pipeline or LNG facility
that contains or processes gas or LNG to
rise above its maximum allowable
operating pressure (or working pressure
for LNG facilities) plus the margin
(build-up) allowed for operation of
pressure limiting or control devices.
*
*
*
*
*
(9) For transmission pipelines, each
exceedance of the maximum allowable
operating pressure that exceeds the
margin (build-up) allowed for operation
of pressure-limiting or control devices
as specified in §§ 192.201, 192.620(e),
and 192.739, as applicable.
(b) * * *
(4) Is corrected by repair or
replacement in accordance with
applicable safety standards before the
deadline for filing the safety-related
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condition report, except that reports are
required for conditions under paragraph
(a)(1) of this section other than localized
corrosion pitting on an effectively
coated and cathodically protected
pipeline and any condition under
paragraph (a)(9) of this section.
■ 4. Section 191.25 is revised to read as
follows:
§ 191.25
reports.
Filing safety-related condition
(a) Each report of a safety-related
condition under § 191.23(a)(1) through
(8) must be filed (received by the
Associate Administrator, OPS) within
five working days (not including
Saturday, Sunday, or Federal Holidays)
after the day a representative of the
operator first determines that the
condition exists, but not later than 10
working days after the day a
representative of the operator discovers
the condition. Separate conditions may
be described in a single report if they
are closely related. Reports may be
transmitted by electronic mail to
InformationResourcesManager@dot.gov
or by facsimile at (202) 366–7128.
(b) Each report of a maximum
allowable operating pressure
exceedance meeting the requirements of
criteria in § 191.23(a)(9) for a gas
transmission pipeline must be reported
within five calendar days of the
exceedance using the reporting methods
and report requirements described in
§ 191.25(c).
(c) Reports may be filed by emailing
information to InformationResources
Manager@dot.gov.or by fax to (202) 366–
7128. The report must be headed
‘‘Safety-Related Condition Report’’ or
for § 191.23(a)(9) ‘‘Maximum Allowable
Operating Pressure Exceedances’’, and
provide the following information:
(1) Name, principal address, and
operator identification number (OPID)
of operator.
(2) Date of report.
(3) Name, job title, and business
telephone number of person submitting
the report.
(4) Name, job title, and business
telephone number of person who
determined that the condition exists.
(5) Date condition was discovered and
date condition was first determined to
exist.
(6) Location of condition, with
reference to the State (and town, city, or
county) or Offshore site, and as
appropriate, nearest street address,
offshore platform, survey station
number, milepost, landmark, or name of
pipeline.
(7) Description of the condition,
including circumstances leading to its
discovery, any significant effects of the
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condition on safety, and the name of the
commodity transported or stored.
(8) The corrective action taken
(including reduction of pressure or
shutdown) before the report is
submitted and the planned follow-up
future corrective action, including the
anticipated schedule for starting and
concluding such action.
■ 4a. In § 191.29, paragraph (c) is added
to read as follows:
§ 191.29 National Pipeline Mapping
System.
*
*
*
*
*
(c) This section does not apply to
gathering lines.
PART 192—TRANSPORTATION OF
NATURAL AND OTHER GAS BY
PIPELINE: MINIMUM FEDERAL
SAFETY STANDARDS
5. The authority citation for part 192
is revised to read as follows:
■
Authority: 49 U.S.C. 5103, 60102, 60104,
60108, 60109, 60110, 60113, 60116, 60118,
60137, and 60139; and 49 CFR 1.97.
6. In § 192.3:
a. Add definitions for ‘‘Close interval
survey’’, ‘‘Distribution center’’, and
‘‘Dry gas or dry natural gas’’ in
alphabetical order;
■ b. Revise the definition of ‘‘Electrical
survey’’;
■ c. Add definitions for ‘‘Gas processing
plant’’ and ‘‘Gas treatment facility,’’ in
alphabetical order;
■ d. Revise the definition of ‘‘Gathering
line’’;
■ e. Add definitions for ‘‘Hard spot’’,
‘‘In-line inspection (ILI)’’, ‘‘In-line
inspection tool or instrumented internal
inspection device’’, ‘‘Legacy
construction techniques’’, ‘‘Legacy
pipe’’, ‘‘Moderate consequence area’’,
‘‘Modern pipe’’, ‘‘Occupied site’’,
‘‘Onshore production facility/
operation’’, ‘‘Significant seam cracking’’,
‘‘Significant stress corrosion cracking’’,
in alphabetical order;
■ f. Revise the definition of
‘‘Transmission line’’ and its note; and
■ g. Add a definition for ‘‘Wrinkle
bend’’ in alphabetical order.
The additions and revisions to read as
follows:
■
■
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§ 192.3
Definitions.
*
*
*
*
*
Close interval survey means a series of
closely spaced pipe-to-electrolyte
potential measurements taken to assess
the adequacy of cathodic protection or
to identify locations where a current
may be leaving the pipeline that may
cause corrosion and for the purpose of
quantifying voltage (IR) drops other than
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those across the structure electrolyte
boundary.
*
*
*
*
*
Distribution center means a location
where gas volumes are either metered or
have pressure or volume reductions
prior to delivery to customers through a
distribution line.
*
*
*
*
*
Dry gas or dry natural gas means gas
with less than 7 pounds of water per
million (MM) cubic feet and not subject
to excessive upsets allowing electrolytes
into the gas stream.
Electrical survey means a series of
closely spaced measurements of the
potential difference between two
reference electrodes to determine where
the current is leaving the pipe on
ineffectively coated or bare pipelines.
*
*
*
*
*
Gas processing plant means a natural
gas processing operation, other than
production processing, operated for the
purpose of extracting entrained natural
gas liquids and other associated nonentrained liquids from the gas stream
and does not include a natural gas
processing plant located on a
transmission line, commonly referred to
as a straddle plant.
Gas treatment facility means one or a
series of gas treatment operations,
operated for the purpose of removing
impurities (e.g., water, solids, basic
sediment and water, sulfur compounds,
carbon dioxide, etc.) that is not
associated with a processing plant or
compressor station and is not on a
transmission line.
Gathering line (Onshore) means a
pipeline, or a connected series of
pipelines, and equipment used to
collect gas from the endpoint of a
production facility/operation and
transport it to the furthermost point
downstream of the endpoints described
in paragraphs (1) through (4) of this
definition:
(1) The inlet of 1st gas processing
plant, unless the operator submits a
request for approval to the Associate
Administrator of Pipeline Safety that
demonstrates, using sound engineering
principles, that gathering extends to a
further downstream plant other than a
plant located on a transmission line and
the Associate Administrator of Pipeline
Safety approves such request;
(2) The outlet of gas treatment facility
that is not associated with a processing
plant or compressor station;
(3) Outlet of the furthermost
downstream compressor used to
facilitate delivery into a pipeline, other
than another gathering line; or
(4) The point where separate
production fields are commingled,
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provided the distance between the
interconnection of the fields does not
exceed 50 miles, unless the Associate
Administrator of Pipeline Safety finds a
longer separation distance is justified in
a particular case (see § 190.9 of this
chapter).
(5) Gathering may continue beyond
the endpoints described in paragraphs
(1) through (4) of this definition to the
point gas is delivered into another
pipeline, provided that it only does the
following:
(i) It delivers gas into another
gathering line;
(A) It does not leave the operator’s
facility surface property (owned or
leased, not necessarily the fence line);
(B) It does not leave an adjacent
property owned or leased by another
pipeline operator’s property—where
custody transfer takes place; or
(C) It does not exceed a length of one
mile, and it does not cross a state or
federal highway or an active railroad; or
(ii) It transports gas to production or
gathering facilities for use as fuel, gas
lift, or gas injection gas.
(6) Pipelines that serve residential,
commercial, or industrial customers that
originate at a tap on gathering lines are
not gathering lines; they are service
lines and are commonly referred to as
farm taps.
*
*
*
*
*
Hard spot means steel pipe material
with a minimum dimension greater than
two inches (50.8 mm) in any direction
and hardness greater than or equal to
Rockwell 35 HRC (Brinnel 327 HB or
Vickers 345 HV10).
*
*
*
*
*
In-line inspection (ILI) means the
inspection of a pipeline from the
interior of the pipe using an in-line
inspection tool, which is also called
intelligent or smart pigging.
In-line inspection tool or
instrumented internal inspection device
means a device or vehicle that uses a
non-destructive testing technique to
inspect the pipeline from the inside,
which is also called an intelligent or
smart pig.
Legacy construction techniques mean
usage of any historic, now-abandoned,
construction practice to construct or
repair pipe segments, including any of
the following techniques:
(1) Wrinkle bends;
(2) Miter joints exceeding three
degrees;
(3) Dresser couplings;
(4) Non-standard fittings or field
fabricated fittings (e.g., orange-peeled
reducers) with unknown pressure
ratings;
(5) Acetylene welds;
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(6) Bell and spigots; or
(7) Puddle welds.
Legacy pipe means steel pipe
manufactured using any of the following
techniques, regardless of the date of
manufacture:
(1) Low-Frequency Electric Resistance
Welded (LF–ERW);
(2) Direct-Current Electric Resistance
Welded (DC–ERW);
(3) Single Submerged Arc Welded
(SSAW);
(4) Electric Flash Welded (EFW);
(5) Wrought iron;
(6) Pipe made from Bessemer steel; or
(7) Any pipe with a longitudinal joint
factor, as defined in § 192.113, less than
1.0 (such as lap-welded pipe) or with a
type of longitudinal joint that is
unknown or cannot be determined,
including pipe of unknown
manufacturing specification.
*
*
*
*
*
Moderate consequence area means an
onshore area that is within a potential
impact circle, as defined in § 192.903,
containing five (5) or more buildings
intended for human occupancy, an
occupied site, or a right-of-way for a
designated interstate, freeway,
expressway, and other principal 4-lane
arterial roadway as defined in the
Federal Highway Administration’s
Highway Functional Classification
Concepts, Criteria and Procedures, and
does not meet the definition of high
consequence area, as defined in
§ 192.903. The length of the moderate
consequence area extends axially along
the length of the pipeline from the
outermost edge of the first potential
impact circle that contains either an
occupied site, five (5) or more buildings
intended for human occupancy, or a
right-of-way for a designated interstate,
freeway, expressway, or other principal
4-lane arterial roadway, to the outermost
edge of the last contiguous potential
impact circle that contains either an
occupied site, five (5) or more buildings
intended for human occupancy, or a
right-of-way for a designated interstate,
freeway, expressway, or other principal
4-lane arterial roadway.
Modern pipe means any steel pipe
that it is not legacy pipe, regardless of
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the date of manufacture, and has a
longitudinal joint factor of 1.0 as
defined in § 192.113. Modern pipe refers
to all pipe that is not legacy pipe.
*
*
*
*
*
Occupied site means each of the
following areas:
(1) An outside area or open structure
that is occupied by five (5) or more
persons on at least 50 days in any
twelve (12)-month period. (The days
need not be consecutive.) Examples
include but are not limited to, beaches,
playgrounds, recreational facilities,
camping grounds, outdoor theaters,
stadiums, recreational areas near a body
of water, or areas outside a rural
building such as a religious facility; or
(2) A building that is occupied by five
(5) or more persons on at least five (5)
days a week for ten (10) weeks in any
twelve (12)-month period. (The days
and weeks need not be consecutive.)
Examples include, but are not limited
to, religious facilities, office buildings,
community centers, general stores, 4–H
facilities, or roller skating rinks.
*
*
*
*
*
Onshore production facility or
onshore production operation means
wellbores, equipment, piping, and
associated appurtenances confined to
the physical acts of extraction or
recovery of gas from the earth and the
initial preparation for transportation.
Preparation for transportation does not
necessarily mean the gas will meet
‘‘pipeline quality’’ specifications as may
be commonly understood or contained
in many contractual agreements. Piping
as used in this definition may include
individual well flow lines, equipment
piping, and transfer lines between
production operation equipment
components. Production facilities
terminate at the furthermost
downstream point where: Measurement
for the purposes of calculating minerals
severance occurs; or there is
commingling of the flow stream from
two or more wells.
*
*
*
*
*
Significant seam cracking means
cracks or crack-like flaws in the
longitudinal seam or heat affected zone
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of a seam weld where the deepest crack
is greater than or equal to 10% of wall
thickness or the total interacting length
of the cracks is equal to or greater than
75% of the critical length of a 50%
through-wall flaw that would fail at a
failure pressure less than or equal to
110% of SMYS, as determined in
accordance with fracture mechanics
failure pressure evaluation methods
(§§ 192.624(c) and (d)) for the failure
mode using conservative Charpy energy
values of the crack-related conditions.
Significant stress corrosion cracking
means a stress corrosion cracking (SCC)
cluster in which the deepest crack, in a
series of interacting cracks, is greater
than 10% of the wall thickness and the
total interacting length of the cracks is
equal to or greater than 75% of the
critical length of a 50% through-wall
flaw that would fail at a stress level of
110% of SMYS.
*
*
*
*
*
Transmission line means a pipeline,
other than a gathering line, that:
transports gas from a gathering line or
storage facility to a distribution center,
storage facility, or large volume
customer that is not down-stream from
a distribution center; has an MAOP of
20 percent or more of SMYS; or
transports gas within a storage field.
Note: A large volume customer
(factories, power plants, and
institutional users of gas) may receive
similar volumes of gas as a distribution
center.
*
*
*
*
*
Wrinkle bend. (1) Means a bend in the
pipe that was formed in the field during
construction such that the inside radius
of the bend has one or more ripples
with:
(i) An amplitude greater than or equal
to 1.5 times the wall thickness of the
pipe, measured from peak to valley of
the ripple; or
(ii) With ripples less than 1.5 times
the wall thickness of the pipe and with
a wrinkle length (peak to peak) to
wrinkle height (peak to valley) ratio
under 12.
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D = The outside diameter of the pipe, in.
(mm),
h = The crest-to-trough height of the ripple,
in. (mm), and
S = The maximum operating hoop stress, psi
(S/145, MPa).
7. In § 192.5, paragraph (d) is added to
read as follows:
■
§ 192.5
Class locations.
*
*
*
*
*
(d) Records for transmission pipelines
documenting class locations and
demonstrating how an operator
determined class locations in
accordance with this section must be
retained for the life of the pipeline.
■ 8. Amend § 192.7 by removing and
reserving paragraph (b)(4) and adding
paragraphs (b)(10), (g)(2) through (4),
(k), and (l).
The additions read as follows:
§ 192.7 What documents are incorporated
by reference partly or wholly in this part?
*
*
*
*
*
(b) * * *
(10) API STD 1163–2005, ‘‘In-Line
Inspection Systems Qualification
Standard,’’ 1st edition, August 2001,
(API STD 1163), IBR approved for
§ 192.493.
*
*
*
*
*
(g) * * *
(2) NACE Standard Practice 0102–
2010, ‘‘Inline Inspection of Pipelines,’’
Revised 2010, (NACE SP0102), IBR
approved for §§ 192.150(a) and 192.493.
(3) NACE Standard Practice 0204–
2008, ‘‘Stress Corrosion Cracking Direct
Assessment,’’ Revised 2008, (NACE
SP0204), Reaffirmed 2008, IBR
approved for §§ 192.923(b)(3) and
192.929.
(4) NACE Standard Practice 0206–
2006, ‘‘International Corrosion Direct
Assessment Methodology for Pipelines
Carrying Normally Dry Natural Gas,’’
(NACE SP0206–2006), IBR approved for
§§ 192.923(b)(2), 192.927(b), and
192.927(c).
*
*
*
*
*
(k) American Society for
Nondestructive Testing (ASNT), P.O.
Box 28518, 1711 Arlingate Lane,
Columbus, OH 43228, phone (800) 222–
2768, https://www.asnt.org/.
(1) ANSI/ASNT ILI–PQ–2010, ‘‘In-line
Inspection Personnel Qualification and
Certification,’’ 2010, (ANSI/ASNT ILI–
PQ–2010), IBR approved for § 192.493.
(2) [Reserved]
(l) Battelle Memorial Institute, 505
King Avenue, Columbus, OH 43201,
phone (800) 201–2011, https://
www.battelle.org/.
(1) Battelle’s Experience with ERW
and Flash Welding Seam Failures:
Causes and Implications (Task 1.4), IBR
approved for § 192.624(c) and (d).
(2) Battelle Memorial Institute,
‘‘Models for Predicting Failure Stress
Levels for Defects Affecting ERW and
Flash-Welded Seams’’ (Subtask 2.4), IBR
approved for § 192.624(c) and (d).
(3) Battelle Final Report No. 13–021,
‘‘Predicting Times to Failures for ERW
Seam Defects that Grow by Pressure
Cycle Induced Fatigue (Subtask 2.5),
IBR approved for § 192.624(c) and (d).
(4) Battelle Memorial Institute, ‘‘Final
Summary Report and recommendations
for the Comprehensive Study to
20827
Understand Longitudinal ERW Seam
Failures—Phase 1’’ (Task 4.5), IBR
approved for § 192.624(c) and (d).
■ 9. Section 192.8 is revised to read as
follows:
§ 192.8 How are onshore gathering lines
and regulated onshore gathering lines
determined?
(a) Each operator must determine and
maintain records documenting the
beginning and endpoints of each
gathering line it operates using the
definitions of onshore production
facility (or onshore production
operation), gas processing facility, gas
treatment facility, and onshore gathering
line as defined in § 192.3 by [date 6
months after effective date of the final
rule] or before the pipeline is placed
into operation, whichever is later.
(b) Each operator must determine and
maintain records documenting the
beginning and endpoints of each
regulated onshore gathering line it
operates as determined in § 192.8(c) by
[date 6 months after effective date of the
final rule] or before the pipeline is
placed into operation, whichever is
later.
(c) For purposes of part 191 of this
chapter and § 192.9, ‘‘regulated onshore
gathering line’’ means:
(1) Each onshore gathering line (or
segment of onshore gathering line) with
a feature described in the second
column that lies in an area described in
the third column; and
(2) As applicable, additional lengths
of line described in the fourth column
to provide a safety buffer:
Type
Feature
Area
A .........
—Metallic and the MAOP produces a hoop
stress of less than 20 percent of SMYS.
If the stress level is unknown, an operator must determine the stress level according to the applicable provisions in
subpart C of this part.
—Non-metallic and the MAOP is more
than 125 psig (862 kPa).
—Non-metallic and the MAOP produces a
hoop stress of less than 20 percent of
SMYS. If the stress level is unknown, an
operator must determine the stress level
according to the applicable provisions in
subpart C of this part.
—Non-metallic and thew MAOP is 125
psig (862 kPa) or less.
Area 1. Class 2, 3, or 4 location (see
§ 192.5).
Area 2. Class 1 location with a nominal diameter of 8 inches or greater.
None.
Area 1. Class 3, or 4 location .....................
Area 2. An area within a Class 2 location
the operator determines by using any of
the following three methods:
(a) A Class 2 location;
(b) An area extending 150 feet (45.7 m) on
each side of the centerline of any continuous 1 mile (1.6 km) of pipeline and including more than 10 but fewer than 46
dwellings; or
(c) An area extending 150 feet (45.7 m) on
each side of the centerline of any continuous 1000 feet (305 m) of pipeline and
including 5 or more dwellings.
If the gathering line is in Area 2(b) or 2(c),
the additional lengths of line extend upstream and downstream from the area to
a point where the line is at least 150 feet
(45.7 m) from the nearest dwelling in the
area. However, if a cluster of dwellings
in Area 2(b) or 2(c) qualifies a line as
Type B, the Type B classification ends
150 feet (45.7 m) from the nearest dwelling in the cluster.
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B .........
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10. In § 192.9, paragraphs (c), (d), and
(e) are revised and paragraph (f) is
added to read as follows:
■
§ 192.9 What requirements apply to
gathering lines?
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*
*
*
*
*
(c) Type A, Area 1 lines. An operator
of a Type A, Area 1 regulated onshore
gathering line must comply with the
requirements of this part applicable to
transmission lines, except the
requirements in §§ 192.13, 192.150,
192.319, 192.461(f), 192.465(f),
192.473(c), 192.478, 192.710, 192.713,
and in subpart O of this part. However,
an operator of a Type A, Area 1
regulated onshore gathering line in a
Class 2 location may demonstrate
compliance with subpart N by
describing the processes it uses to
determine the qualification of persons
performing operations and maintenance
tasks.
(d) Type A, Area 2 and Type B lines.
An operator of a Type A, Area 2 or Type
B regulated onshore gathering line must
comply with the following
requirements:
(1) If a line is new, replaced,
relocated, or otherwise changed, the
design, installation, construction, initial
inspection, and initial testing must be in
accordance with requirements of this
part applicable to transmission lines;
(2) If the pipeline is metallic, control
corrosion according to requirements of
subpart I of this part applicable to
transmission lines;
(3) Carry out a damage prevention
program under § 192.614;
(4) Establish a public education
program under § 192.616;
(5) Establish the MAOP of the line
under § 192.619;
(6) Install and maintain line markers
according to the requirements for
transmission lines in § 192.707;
(7) Conduct leakage surveys in
accordance with § 192.706 using leak
detection equipment and promptly
repair hazardous leaks that are
discovered in accordance with
§ 192.703(c); and
(8) For a Type A, Area 2 regulated
onshore gathering line only, develop
procedures, training, notifications,
emergency plans and implement as
described in § 192.615.
(e) If a regulated onshore gathering
line existing on [effective date of the
final rule] was not previously subject to
this part, an operator has until [date two
years after effective date of the final
rule] to comply with the applicable
requirements of this section, unless the
Administrator finds a later deadline is
justified in a particular case.
(f) If, after [effective date of the final
rule], a change in class location or
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increase in dwelling density causes an
onshore gathering line to be a regulated
onshore gathering line, the operator has
one year for Type A, Area 2 and Type
B lines and two years for Type A, Area
1 lines after the line becomes a
regulated onshore gathering line to
comply with this section.
■ 11. In § 192.13, paragraphs (a) and (b)
are revised and paragraphs (d) and (e)
are added to read as follows:
§ 192.13 What general requirements apply
to pipelines regulated under this part?
(a) No person may operate a segment
of pipeline listed in the first column
that is readied for service after the date
in the second column, unless:
(1) The pipeline has been designed,
installed, constructed, initially
inspected, and initially tested in
accordance with this part; or
(2) The pipeline qualifies for use
under this part according to the
requirements in § 192.14.
Pipeline
Date
Offshore gathering line ..........
Regulated onshore gathering
line to which this part did
not apply until April 14,
2006.
Regulated onshore gathering
line to which this part did
not apply until [effective
date of the final rule].
July 31, 1977.
March 15
2007.
All other pipelines ..................
[date 1 year
after effective date of
the final
rule].
March 12,
1971.
(b) No person may operate a segment
of pipeline listed in the first column
that is replaced, relocated, or otherwise
changed after the date in the second
column, unless the replacement,
relocation or change has been made
according to the requirements in this
part.
Pipeline
Date
Offshore gathering line ..........
Regulated onshore gathering
line to which this part did
not apply until April 14,
2006.
Regulated onshore gathering
line to which this part did
not apply until [effective
date of the final rule].
July 31, 1977.
March 15,
2007.
All other pipelines ..................
*
*
*
*
(d) Each operator of an onshore gas
transmission pipeline must evaluate and
mitigate, as necessary, risks to the
public and environment as an integral
part of managing pipeline design,
construction, operation, maintenance,
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§ 192.67
Sfmt 4702
Records: Materials.
Each operator of transmission
pipelines must acquire and retain for
the life of the pipeline the original steel
pipe manufacturing records that
document tests, inspections, and
attributes required by the manufacturing
specification in effect at the time the
pipe was manufactured, including, but
not limited to, yield strength, ultimate
tensile strength, and chemical
composition of materials for pipe in
accordance with § 192.55.
■ 13. Section 192.127 is added to
subpart B to read as follows:
§ 192.127
[date 1 year
after effective date of
the final
rule].
November 12,
1970.
*
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and integrity, including management of
change. Each operator of an onshore gas
transmission pipeline must develop and
follow a management of change process,
as outlined in ASME/ANSI B31.8S,
section 11, that addresses technical,
design, physical, environmental,
procedural, operational, maintenance,
and organizational changes to the
pipeline or processes, whether
permanent or temporary. A management
of change process must include the
following: reason for change, authority
for approving changes, analysis of
implications, acquisition of required
work permits, documentation,
communication of change to affected
parties, time limitations, and
qualification of staff.
(e) Each operator must make and
retain records that demonstrate
compliance with this part.
(1) Operators of transmission
pipelines must keep records for the
retention period specified in appendix
A to part 192.
(2) Records must be reliable,
traceable, verifiable, and complete.
(3) For pipeline material
manufactured before [effective date of
the final rule] and for which records are
not available, each operator must reestablish pipeline material
documentation in accordance with the
requirements of § 192.607.
■ 12. Section 192.67 is added to subpart
A to read as follows:
Records: Pipe design.
Each operator of transmission
pipelines must make and retain for the
life of the pipeline records documenting
pipe design to withstand anticipated
external pressures and loads in
accordance with § 192.103 and
determination of design pressure for
steel pipe in accordance with § 192.105.
■ 14. In § 192.150, paragraph (a) is
revised to read as follows:
§ 192.150
devices.
Passage of internal inspection
(a) Except as provided in paragraphs
(b) and (c) of this section, each new
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transmission line and each replacement
of line pipe, valve, fitting, or other line
component in a transmission line must
be designed and constructed to
accommodate the passage of
instrumented internal inspection
devices, in accordance with the
requirements and recommendations in
NACE SP0102–2010, section 7
(incorporated by reference, see § 192.7).
*
*
*
*
*
■ 15. Section 192.205 is added to
subpart D to read as follows:
§ 192.205
Records: Pipeline components.
Each operator of transmission
pipelines must acquire and retain
records documenting the manufacturing
standard and pressure rating to which
each valve was manufactured and tested
in accordance with this subpart.
Flanges, fittings, branch connections,
extruded outlets, anchor forgings, and
other components with material yield
strength grades of 42,000 psi or greater
must have records documenting the
manufacturing specification in effect at
the time of manufacture, including, but
not limited to, yield strength, ultimate
tensile strength, and chemical
composition of materials.
■ 16. In § 192.227, paragraph (c) is
added to read as follows:
§ 192.227 Qualification of welders and
welding operators.
*
*
*
*
*
(c) Records for transmission pipelines
demonstrating each individual welder
qualification in accordance with this
section must be retained for the life of
the pipeline.
■ 17. In § 192.285, paragraph (e) is
added to read as follows:
§ 192.285 Plastic pipe: Qualifying persons
to make joints.
*
*
*
*
*
(e) For transmission pipelines, records
demonstrating plastic pipe joining
qualifications in accordance with this
section must be retained for the life of
the pipeline.
18. In § 192.319, paragraph (d) is
added to read as follows:
§ 192.319
Installation of pipe in a ditch.
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*
*
*
*
*
(d) Promptly after a ditch for a steel
onshore transmission line is backfilled,
but not later than three months after
placing the pipeline in service, the
operator must perform an assessment to
ensure integrity of the coating using
direct current voltage gradient (DCVG)
or alternating current voltage gradient
(ACVG). The operator must repair any
coating damage classified as moderate
or severe (voltage drop greater than 35%
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for DCVG or 50 dBmv for ACVG) in
accordance with section 4 of NACE
SP0502 (incorporated by reference, see
§ 192.7) within six months of the
assessment. Each operator of
transmission pipelines must make and
retain for the life of the pipeline records
documenting the coating assessment
findings and repairs.
■ 19. In § 192.452, the introductory text
of paragraph (b) is revised to read as
follows:
§ 192.452 How does this subpart apply to
converted pipelines and regulated onshore
gathering lines?
*
*
*
*
*
(b) Regulated onshore gathering lines.
For any regulated onshore gathering line
under § 192.9 existing on [effective date
of the final rule], that was not
previously subject to this part, and for
any onshore gathering line that becomes
a regulated onshore gathering line under
§ 192.9 after April 14, 2006, because of
a change in class location or increase in
dwelling density:
*
*
*
*
*
■ 20. In § 192.461, paragraph (a)(4) is
revised and paragraph (f) is added to
read as follows:
§ 192.461 External corrosion control:
Protective coating.
(a) * * *
(4) Have sufficient strength to resist
damage due to handling (including but
not limited to transportation,
installation, boring, and backfilling) and
soil stress; and
*
*
*
*
*
(f) Promptly, but no later than three
months after backfill of an onshore
transmission pipeline ditch following
repair or replacement (if the repair or
replacement results in 1,000 feet or
more of backfill length along the
pipeline), conduct surveys to assess any
coating damage to ensure integrity of the
coating using direct current voltage
gradient (DCVG) or alternating current
voltage gradient (ACVG). Remediate any
coating damage classified as moderate
or severe (voltage drop greater than 35%
for DCVG or 50 dBmv for ACVG) in
accordance with section 4 of NACE
SP0502 (incorporated by reference, see
§ 192.7) within six months of the
assessment.
■ 21. In § 192.465, the section heading
and paragraph (d) are revised and
paragraph (f) is added to read as follows:
§ 192.465 External corrosion control:
Monitoring and remediation.
*
*
*
*
*
(d) Each operator must promptly
correct any deficiencies indicated by the
inspection and testing provided in
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20829
paragraphs (a), (b) and (c) of this
section. Remedial action must be
completed promptly, but no later than
the next monitoring interval in
§ 192.465 or within one year, whichever
is less.
*
*
*
*
*
(f) For onshore transmission lines,
where any annual test station reading
(pipe-to-soil potential measurement)
indicates cathodic protection levels
below the required levels in Appendix
D of this part, the operator must
determine the extent of the area with
inadequate cathodic protection. Close
interval surveys must be conducted in
both directions from the test station
with a low cathodic protection (CP)
reading at a minimum of approximately
five foot intervals. Close interval
surveys must be conducted, where
practical based upon geographical,
technical, or safety reasons. Close
interval surveys required by this part
must be completed with the protective
current interrupted unless it is
impractical to do so for technical or
safety reasons. Remediation of areas
with insufficient cathodic protection
levels or areas where protective current
is found to be leaving the pipeline must
be performed in accordance with
paragraph (d) of this section. The
operator must confirm restoration of
adequate cathodic protection by close
interval survey over the entire area.
■ 22. In § 192.473, paragraph (c) is
added to read as follows:
§ 192.473 External corrosion control:
Interference currents.
*
*
*
*
*
(c) For onshore gas transmission
pipelines, the program required by
paragraph (a) of this section must
include:
(1) Interference surveys for a pipeline
system to detect the presence and level
of any electrical stray current.
Interference surveys must be taken on a
periodic basis including, when there are
current flow increases over pipeline
segment grounding design, from any colocated pipelines, structures, or high
voltage alternating current (HVAC)
power lines, including from additional
generation, a voltage up rating,
additional lines, new or enlarged power
substations, new pipelines or other
structures;
(2) Analysis of the results of the
survey to determine the cause of the
interference and whether the level could
impact the effectiveness of cathodic
protection; and
(3) Implementation of remedial
actions to protect the pipeline segment
from detrimental interference currents
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promptly but no later than six months
after completion of the survey.
■ 23. Section 192.478 is added to read
as follows:
mstockstill on DSK4VPTVN1PROD with PROPOSALS2
§ 192.478 Internal corrosion control:
Onshore transmission monitoring and
mitigation.
(a) For onshore transmission
pipelines, each operator must develop
and implement a monitoring and
mitigation program to identify
potentially corrosive constituents in the
gas being transported and mitigate the
corrosive effects. Potentially corrosive
constituents include but are not limited
to: carbon dioxide, hydrogen sulfide,
sulfur, microbes, and free water, either
by itself or in combination. Each
operator must evaluate the partial
pressure of each corrosive constituent
by itself or in combination to evaluate
the effect of the corrosive constituents
on the internal corrosion of the pipe and
implement mitigation measures.
(b) The monitoring and mitigation
program in paragraph (a) of this section
must include:
(1) At points where gas with
potentially corrosive contaminants
enters the pipeline, the use of gasquality monitoring equipment to
determine the gas stream constituents;
(2) Product sampling, inhibitor
injections, in-line cleaning pigging,
separators or other technology to
mitigate the potentially corrosive gas
stream constituents;
(3) Evaluation twice each calendar
year, at intervals not to exceed 71⁄2
months, of gas stream and liquid quality
samples and implementation of
adjustments and mitigative measures to
ensure that potentially corrosive gas
stream constituents are effectively
monitored and mitigated.
(c) If corrosive gas is being
transported, coupons or other suitable
means must be used to determine the
effectiveness of the steps taken to
minimize internal corrosion. Each
coupon or other means of monitoring
internal corrosion must be checked at
least twice each calendar year, at
intervals not exceeding 71⁄2 months.
(d) Each operator must review its
monitoring and mitigation program at
least twice each calendar year, at
intervals not to exceed 71⁄2 months,
based on the results of its gas stream
sampling and internal corrosion
monitoring in (a) and (b) and implement
adjustments in its monitoring for and
mitigation of the potential for internal
corrosion due to the presence of
potentially corrosive gas stream
constituents.
■ 24. In § 192.485, paragraph (c) is
revised to read as follows:
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§ 192.485 Remedial measures:
Transmission lines.
27. Section 192.506 is added to read
as follows:
■
*
*
*
*
*
(c) Under paragraphs (a) and (b) of
this section, the strength of pipe based
on actual remaining wall thickness may
be determined by the procedure in
ASME/ANSI B31G (incorporated by
reference, see § 192.7) or the procedure
in PRCI PR 3–805 (R–STRENG)
(incorporated by reference, see § 192.7)
for corrosion defects. Both procedures
apply to corroded regions that do not
penetrate the pipe wall over 80 percent
of the wall thickness and are subject to
the limitations prescribed in the
procedures, including the appropriate
use of class location and pipe
longitudinal seam factors in pressure
calculations for pipe defects. When
determining the predicted failure
pressure (PFP) for gouges, scrapes,
selective seam weld corrosion, and
crack-related defects, appropriate failure
criteria must be used and justification of
the criteria must be documented. Pipe
and material properties used in
remaining strength calculations and the
pressure calculations made under this
paragraph must be documented in
reliable, traceable, verifiable, and
complete records. If such records are not
available, pipe and material properties
used in the remaining strength
calculations must be based on
properties determined and documented
in accordance with § 192.607.
■ 25. Section 192.493 is added to
subpart I to read as follows:
§ 192.493
In-line inspection of pipelines.
When conducting in-line inspection
of pipelines required by this part, each
operator must comply with the
requirements and recommendations of
API STD 1163, In-line Inspection
Systems Qualification Standard; ANSI/
ASNT ILI–PQ–2010, In-line Inspection
Personnel Qualification and
Certification; and NACE SP0102–2010,
In-line Inspection of Pipelines
(incorporated by reference, see § 192.7).
Assessments may also be conducted
using tethered or remotely controlled
tools, not explicitly discussed in NACE
SP0102–2010, provided they comply
with those sections of NACE SP0102–
2010 that are applicable.
■ 26. In § 192.503, paragraph (a)(1) is
revised to read as follows:
§ 192.503
General requirements.
(a) * * *
(1) It has been tested in accordance
with this subpart and § 192.619,
192.620, or 192.624 to substantiate the
maximum allowable operating pressure;
and
*
*
*
*
*
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§ 192.506 Transmission lines: Spike
hydrostatic pressure test for existing steel
pipe with integrity threats.
(a) Each segment of an existing steel
pipeline that is operated at a hoop stress
level of 30% of specified minimum
yield strength or more and has been
found to have integrity threats that
cannot be addressed by other means
such as in-line inspection or direct
assessment must be strength tested by a
spike hydrostatic pressure test in
accordance with this section to
substantiate the proposed maximum
allowable operating pressure.
(b) The spike hydrostatic pressure test
must use water as the test medium.
(c) The baseline test pressure without
the additional spike test pressure is the
test pressure specified in
§ 192.619(a)(2), 192.620(a)(2), or
192.624, whichever applies.
(d) The test must be conducted by
maintaining the pressure at or above the
baseline test pressure for at least 8 hours
as specified in § 192.505(e).
(e) After the test pressure stabilizes at
the baseline pressure and within the
first two hours of the 8-hour test
interval, the hydrostatic pressure must
be raised (spiked) to a minimum of the
lesser of 1.50 times MAOP or 105%
SMYS. This spike hydrostatic pressure
test must be held for at least 30 minutes.
(f) If the integrity threat being
addressed by the spike test is of a timedependent nature such as a cracking
threat, the operator must establish an
appropriate retest interval and conduct
periodic retests at that interval using the
same spike test pressure. The
appropriate retest interval and periodic
tests for the time-dependent threat must
be determined in accordance with the
methodology in § 192.624(d).
(g) Alternative technology or
alternative technical evaluation process.
Operators may use alternative
technology or an alternative technical
evaluation process that provides a
sound engineering basis for establishing
a spike hydrostatic pressure test or
equivalent. If an operator elects to use
alternative technology or an alternative
technical evaluation process, the
operator must notify PHMSA at least
180 days in advance of use in
accordance with § 192.624(e). The
operator must submit the alternative
technical evaluation to the Associate
Administrator of Pipeline Safety with
the notification and must obtain a ‘‘no
objection letter’’ from the Associate
Administrator of Pipeline Safety prior to
usage of alternative technology or an
alternative technical evaluation process.
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The notification must include the
following details:
(1) Descriptions of the technology or
technologies to be used for all tests,
examinations, and assessments;
(2) Procedures and processes to
conduct tests, examinations, and
assessments, perform evaluations,
analyze defects and flaws, and
remediate defects discovered;
(3) Data requirements including
original design, maintenance and
operating history, anomaly or flaw
characterization;
(4) Assessment techniques and
acceptance criteria;
(5) Remediation methods for
assessment findings;
(6) Spike hydrostatic pressure test
monitoring and acceptance procedures,
if used;
(7) Procedures for remaining crack
growth analysis and pipe segment life
analysis for the time interval for
additional assessments, as required; and
(8) Evidence of a review of all
procedures and assessments by a subject
matter expert(s) in both metallurgy and
fracture mechanics.
■ 28. In § 192.517, the introductory text
of paragraph (a) is revised to read as
follows:
§ 192.517
Records.
(a) Each operator must make, and
retain for the useful life of the pipeline,
a record of each test performed under
§§ 192.505, 192.506, and 192.507. The
record must contain at least the
following information:
*
*
*
*
*
■ 29. In § 192.605, paragraph (b)(5) is
revised to read as follows:
§ 192.605 Procedural manual for
operations, maintenance, and emergencies.
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*
*
*
*
*
(b) * * *
(5) Operating pipeline controls and
systems and operating and maintaining
pressure relieving or pressure limiting
devices, including those for starting up
and shutting down any part of the
pipeline, so that the MAOP limit as
prescribed by this part cannot be
exceeded by more than the margin
(build-up) allowed for operation of
pressure relieving devices or pressurelimiting or control devices as specified
in § 192.201, 192.620(e), 192.731,
192.739, or 192.743, whichever applies.
*
*
*
*
*
■ 30. Section 192.607 is added to read
as follows:
§ 192.607 Verification of pipeline material:
Onshore steel transmission pipelines.
(a) Applicable locations. Each
operator must follow the requirements
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of paragraphs (b) through (d) of this
section for each segment of onshore,
steel, gas transmission pipeline installed
before [effective date of the final rule]
that does not have reliable, traceable,
verifiable, and complete material
documentation records for line pipe,
valves, flanges, and components and
meets any of the following conditions:
(1) The pipeline is located in a High
Consequence Area as defined in
§ 192.903; or
(2) The pipeline is located in a class
3 or class 4 location.
(b) Material documentation plan.
Each operator must prepare a material
documentation plan to implement all
actions required by this section by [date
180 days after the effective date of the
final rule].
(c) Material documentation. Each
operator must have reliable, traceable,
verifiable, and complete records
documenting the following:
(1) For line pipe and fittings, records
must document diameter, wall
thickness, grade (yield strength and
ultimate tensile strength), chemical
composition, seam type, coating type,
and manufacturing specification.
(2) For valves, records must document
either the applicable standards to which
the component was manufactured, the
manufacturing rating, or the pressure
rating. For valves with pipe weld ends,
records must document the valve
material grade and weld end bevel
condition to ensure compatibility with
pipe end conditions;
(3) For flanges, records must
document either the applicable
standards to which the component was
manufactured, the manufacturing rating,
or the pressure rating, and the material
grade and weld end bevel condition to
ensure compatibility with pipe end
conditions;
(4) For components, records must
document the applicable standards to
which the component was
manufactured to ensure pressure rating
compatibility.
(d) Verification of material properties.
For any material documentation records
for line pipe, valves, flanges, and
components specified in paragraph (c)
of this section that are not available, the
operator must take the following actions
to determine and verify the physical
characteristics.
(1) Develop and implement
procedures for conducting nondestructive or destructive tests,
examinations, and assessments for line
pipe at all above ground locations.
(2) Develop and implement
procedures for conducting destructive
tests, examinations, and assessments for
buried line pipe at all excavations
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associated with replacements or
relocations of pipe segments that are
removed from service.
(3) Develop and implement
procedures for conducting nondestructive or destructive tests,
examinations, and assessments for
buried line pipe at all excavations
associated with anomaly direct
examinations, in situ evaluations,
repairs, remediations, maintenance, or
any other reason for which the pipe
segment is exposed, except for segments
exposed during excavation activities
that are in compliance with § 192.614,
until completion of the minimum
number of excavations as follows:
(i) The operator must define a
separate population of undocumented
or inadequately documented pipeline
segments for each unique combination
of the following attributes: wall
thicknesses (within 10 percent of the
smallest wall thickness in the
population), grade, manufacturing
process, pipe manufacturing dates
(within a two year interval) and
construction dates (within a two year
interval).
(ii) Assessments must be
proportionally spaced throughout the
pipeline segment. Each length of the
pipeline segment equal to 10 percent of
the total length must contain 10 percent
of the total number of required
excavations, e.g. a 200 mile population
would require 15 excavations for each
20 miles. For each population defined
according to paragraph (d)(3)(i) of this
section, the minimum number of
excavations at which line pipe must be
tested to verify pipeline material
properties is the lesser of the following:
(A) 150 excavations; or
(B) If the segment is less than 150
miles, a number of excavations equal to
the population’s pipeline mileage (i.e.,
one set of properties per mile), rounded
up to the nearest whole number. The
mileage for this calculation is the
cumulative mileage of pipeline
segments in the population without
reliable, traceable, verifiable, and
complete material documentation.
(iii) At each excavation, tests for
material properties must determine
diameter, wall thickness, yield strength,
ultimate tensile strength, Charpy vnotch toughness (where required for
failure pressure and crack growth
analysis), chemical properties, seam
type, coating type, and must test for the
presence of stress corrosion cracking,
seam cracking, or selective seam weld
corrosion using ultrasonic inspection,
magnetic particle, liquid penetrant, or
other appropriate non-destructive
examination techniques. Determination
of material property values must
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conservatively account for measurement
inaccuracy and uncertainty based upon
comparison with destructive test results
using unity charts.
(iv) If non-destructive tests are
performed to determine strength or
chemical composition, the operator
must use methods, tools, procedures,
and techniques that have been
independently validated by subject
matter experts in metallurgy and
fracture mechanics to produce results
that are accurate within 10% of the
actual value with 95% confidence for
strength values, within 25% of the
actual value with 85% confidence for
carbon percentage and within 20% of
the actual value with 90% confidence
for manganese, chromium,
molybdenum, and vanadium percentage
for the grade of steel being tested.
(v) The minimum number of test
locations at each excavation or aboveground location is based on the number
of joints of line pipe exposed, as
follows:
(A) 10 joints or less: one set of tests
for each joint.
(B) 11 to 100 joints: one set of tests for
each five joints, but not less than 10 sets
of tests.
(C) Over 100 joints: one set of tests for
each 10 joints, but not less than 20 sets
of tests.
(vi) For non-destructive tests, at each
test location, a set of material properties
tests must be conducted at a minimum
of five places in each circumferential
quadrant of the pipe for a minimum
total of 20 test readings at each pipe
cylinder location.
(vii) For destructive tests, at each test
location, a set of materials properties
tests must be conducted on each
circumferential quadrant of a test pipe
cylinder removed from each location,
for a minimum total of four tests at each
location.
(viii) If the results of all tests
conducted in accordance with
paragraphs (d)(3)(i) and (ii) of this
section verify that material properties
are consistent with all available
information for each population, then
no additional excavations are necessary.
However, if the test results identify line
pipe with properties that are not
consistent with existing expectations
based on all available information for
each population, then the operator must
perform tests at additional excavations.
The minimum number of excavations
that must be tested depends on the
number of inconsistencies observed
between as-found tests and available
operator records, in accordance with the
following table:
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Number of
excavations with
inconsistency
between test
results and
existing
expectations
based on all
available
information for
each population
0 ................................
1 ................................
2 ................................
>2 ..............................
Minimum number of
total required
excavations for
population.
The lesser of:
150 (or pipeline mileage)
225 (or pipeline mileage times 1.5)
300 (or pipeline mileage times 2)
350 (or pipeline mileage times 2.3)
(ix) The tests conducted for a single
excavation according to the
requirements of paragraphs (d)(3)(iii)
through (vii) of this section count as one
sample under the sampling
requirements of paragraphs (d)(3)(i), (ii),
and (viii) of this section.
(4) For mainline pipeline components
other than line pipe, the operator must
develop and implement procedures for
establishing and documenting the ANSI
rating and material grade (to assure
compatibility with pipe ends).
(i) Materials in compressor stations,
meter stations, regulator stations,
separators, river crossing headers,
mainline valve assemblies, operator
piping, or cross-connections with
isolation valves from the mainline
pipeline are not required to be tested for
chemical and mechanical properties.
(ii) Verification of mainline material
properties is required for non-line pipe
components, including but not limited
to, valves, flanges, fittings, fabricated
assemblies, and other pressure retaining
components appurtenances that are:
(A) 2-inch nominal diameter and
larger; or
(B) Material grades greater than
42,000 psi (X–42); or
(C) Appurtenances of any size that are
directly installed on the pipeline and
cannot be isolated from mainline
pipeline pressures.
(iii) Procedures for establishing
material properties for non-line pipe
components where records are
inadequate must be based upon
documented manufacturing
specifications. Where specifications are
not known, usage of manufacturer’s
stamped or tagged material pressure
ratings and material type may be used
to establish pressure rating. The
operator must document the basis of the
material properties established using
such procedures.
(5) The material properties
determined from the destructive or non-
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destructive tests required by this section
cannot be used to raise the original
grade or specification of the material,
which must be based upon the
applicable standard referenced in
§ 192.7.
(6) If conditions make material
verification by the above methods
impracticable or if the operator chooses
to use ‘‘other technology’’ or ‘‘new
technology’’ (alternative technical
evaluation process plan), the operator
must notify PHMSA at least 180 days in
advance of use in accordance with
paragraph § 192.624(e) of this section.
The operator must submit the
alternative technical evaluation process
plan to the Associate Administrator of
Pipeline Safety with the notification and
must obtain a ‘‘no objection letter’’ from
the Associate Administrator of Pipeline
Safety prior to usage of an alternative
evaluation process.
■ 31. In § 192.613, paragraph (c) is
added to read as follows:
§ 192.613
Continuing surveillance.
*
*
*
*
*
(c) Following an extreme weather
event such as a hurricane or flood, an
earthquake, landslide, a natural disaster,
or other similar event that has the
likelihood of damage to infrastructure,
an operator must inspect all potentially
affected onshore transmission pipeline
facilities to detect conditions that could
adversely affect the safe operation of
that pipeline.
(1) Inspection method. An operator
must consider the nature of the event
and the physical characteristics,
operating conditions, location, and prior
history of the affected pipeline in
determining the appropriate method for
performing the initial inspection to
determine damage and the need for the
additional assessments required under
the introductory text of paragraph (c) in
this section.
(2) Time period. The inspection
required under the introductory text of
paragraph (c) of this section must
commence within 72 hours after the
cessation of the event, defined as the
point in time when the affected area can
be safely accessed by the personnel and
equipment, including availability of
personnel and equipment, required to
perform the inspection as determined
under paragraph (c)(1) of this section,
whichever is sooner.
(3) Remedial action. An operator must
take appropriate remedial action to
ensure the safe operation of a pipeline
based on the information obtained as a
result of performing the inspection
required under the introductory text of
paragraph (c) in this section. Such
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actions might include, but are not
limited to:
(i) Reducing the operating pressure or
shutting down the pipeline;
(ii) Modifying, repairing, or replacing
any damaged pipeline facilities;
(iii) Preventing, mitigating, or
eliminating any unsafe conditions in the
pipeline right-of-way;
(iv) Performing additional patrols,
surveys, tests, or inspections;
(v) Implementing emergency response
activities with Federal, State, or local
personnel; or
(vi) Notifying affected communities of
the steps that can be taken to ensure
public safety.
■ 32. In § 192.619, paragraphs (a)(2)
through (4) are revised and paragraphs
(e) and (f) are added to read as follows:
§ 192.619 Maximum allowable operating
pressure: Steel or plastic pipelines.
(a) * * *
(2) The pressure obtained by dividing
the pressure to which the segment was
tested after construction as follows:
(i) For plastic pipe in all locations, the
test pressure is divided by a factor of
1.5.
(ii) For steel pipe operated at 100
p.s.i. (689 kPa) gage or more, the test
pressure is divided by a factor
determined in accordance with the
following table:
Factors 1, segment—
Class location
1
2
3
4
Installed before (Nov.
12, 1970)
.......................................................
.......................................................
.......................................................
.......................................................
Installed after (Nov. 11,
1970) and before [effective date of the final rule]
1.1
1.25
1.4
1.4
Installed after [effective
date of the final rule
minus 1 day]
1.1
1.25
1.5
1.5
Converted under
§ 192.14
1.25
1.25
1.5
1.5
1.25
1.25
1.5
1.5
1 For offshore segments installed, uprated or converted after July 31, 1977, that are not located on an offshore platform, the factor is 1.25. For
segments installed, uprated or converted after July 31, 1977, that are located on an offshore platform or on a platform in inland navigable waters,
including a pipe riser, the factor is 1.5.
(3) The highest actual operating
pressure to which the segment was
subjected during the 5 years preceding
the applicable date in the second
column. This pressure restriction
applies unless the segment was tested
according to the requirements in
paragraph (a)(2) of this section after the
applicable date in the third column or
the segment was uprated according to
the requirements in subpart K of this
part:
Pressure date
—Onshore gathering line that first became subject to
this part (other than § 192.612) after April 13, 2006 but
before [effective date of the final rule].
—Onshore gathering line that first became subject to
this part (other than § 192.612) on or after [effective
date of the final rule].
—Onshore transmission line that was a gathering line
not subject to this part before March 15, 2006.
Offshore gathering lines ...................................................
All other pipelines .............................................................
mstockstill on DSK4VPTVN1PROD with PROPOSALS2
Pipeline segment
March 15, 2006, or date line becomes subject to this
part, whichever is later.
(4) The pressure determined by the
operator to be the maximum safe
pressure after considering material
records, including material properties
verified in accordance with § 192.607,
and the history of the segment,
particularly known corrosion and the
actual operating pressure.
*
*
*
*
*
(e) Notwithstanding the requirements
in paragraphs (a) through (d) of this
section, onshore steel transmission
pipelines that meet the criteria specified
in § 192.624(a) must establish and
document the maximum allowable
operating pressure in accordance with
§ 192.624 using one or more of the
following:
(1) Method 1: Pressure Test—Pressure
test in accordance with § 192.624(c)(1)(i)
or spike hydrostatic pressure test in
accordance with § 192.624(c)(1)(ii), as
applicable;
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[date one year after effective date of the final rule], or
date line becomes subject to this part, whichever is
later.
March 15, 2006, or date line becomes subject to this
part, whichever is later.
July 1, 1976 .....................................................................
July 1, 1970 .....................................................................
(2) Method 2: Pressure Reduction—
Reduction in pipeline maximum
allowable operating pressure in
accordance with § 192.624(c)(2);
(3) Method 3: Engineering Critical
Assessment—Engineering assessment
and analysis activities in accordance
with § 192.624(c)(3);
(4) Method 4: Pipe Replacement—
Replacement of the pipeline segment in
accordance with § 192.624(c)(4);
(5) Method 5: Pressure Reduction for
Segments with Small PIR and
Diameter—Reduction of maximum
allowable operating pressure and other
preventive measures for pipeline
segments with small PIRs and
diameters, in accordance with
§ 192.624(c)(5); or
(6) Method 6: Alternative
Technology—Alternative procedure in
accordance with § 192.624(c)(6).
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5 years preceding applicable date in second column.
July 1, 1971.
July 1, 1965.
(f) Operators must maintain all
records necessary to establish and
document the MAOP of each pipeline as
long as the pipe or pipeline remains in
service. Records that establish the
pipeline MAOP, include, but are not
limited to, design, construction,
operation, maintenance, inspection,
testing, material strength, pipe wall
thickness, seam type, and other related
data. Records must be reliable,
traceable, verifiable, and complete.
■ 33. Section 192.624 is added to read
as follows:
§ 192.624 Maximum allowable operating
pressure verification: Onshore steel
transmission pipelines.
(a) Applicable locations. The operator
of a pipeline segment meeting any of the
following conditions must establish the
maximum allowable operating pressure
using one or more of the methods
specified in § 192.624(c)(1) through (6):
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(1) The pipeline segment has
experienced a reportable in-service
incident, as defined in § 191.3 of this
chapter, since its most recent successful
subpart J pressure test, due to an
original manufacturing-related defect, a
construction-, installation-, or
fabrication-related defect, or a crackingrelated defect, including, but not limited
to, seam cracking, girth weld cracking,
selective seam weld corrosion, hard
spot, or stress corrosion cracking and
the pipeline segment is located in one
of the following locations:
(i) A high consequence area as
defined in § 192.903;
(ii) A class 3 or class 4 location; or
(iii) A moderate consequence area as
defined in § 192.3 if the pipe segment
can accommodate inspection by means
of instrumented inline inspection tools
(i.e., ‘‘smart pigs’’).
(2) Pressure test records necessary to
establish maximum allowable operating
pressure per subpart J for the pipeline
segment, including, but not limited to,
records required by § 192.517(a), are not
reliable, traceable, verifiable, and
complete and the pipeline is located in
one of the following locations:
(i) A high consequence area as
defined in § 192.903; or
(ii) A class 3 or class 4 location
(3) The pipeline segment maximum
allowable operating pressure was
established in accordance with
§ 192.619(c) before [effective date of the
final rule] and is located in one of the
following areas:
(i) A high consequence area as
defined in § 192.903;
(ii) A class 3 or class 4 location; or
(iii) A moderate consequence area as
defined in § 192.3 if the pipe segment
can accommodate inspection by means
of instrumented inline inspection tools
(i.e., ‘‘smart pigs’’).
(b) Completion date. For pipelines
installed before [effective date of the
final rule], all actions required by this
section must be completed according to
the following schedule:
(1) The operator must develop and
document a plan for completion of all
actions required by this section by [date
1 year after effective date of the final
rule].
(2) The operator must complete all
actions required by this section on at
least 50% of the mileage of locations
that meet the conditions of § 192.624(a)
by [date 8 years after effective date of
the final rule].
(3) The operator must complete all
actions required by this section on
100% of the mileage of locations that
meet the conditions of § 192.624(a) by
[date 15 years after effective date of the
final rule].
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(4) If operational and environmental
constraints limit the operator from
meeting the deadlines in § 192.614(b)(2)
and (3), the operator may petition for an
extension of the completion deadlines
by up to one year, upon submittal of a
notification to the Associate
Administrator of the Office of Pipeline
Safety in accordance with paragraph (e)
of this section. The notification must
include an up-to-date plan for
completing all actions in accordance
with paragraph (b)(1) of this section, the
reason for the requested extension,
current status, proposed completion
date, remediation activities outstanding,
and any needed temporary safety
measures to mitigate the impact on
safety.
(c) Maximum allowable operating
pressure determination. The operator of
a pipeline segment meeting the criteria
in paragraph (a) of this section must
establish its maximum allowable
operating pressure using one of the
following methods:
(1) Method 1: Pressure test.(i) Perform
a pressure test in accordance with
§ 192.505(c). The maximum allowable
operating pressure will be equal to the
test pressure divided by the greater of
either 1.25 or the applicable class
location factor in § 192.619(a)(2)(ii) or
§ 192.620(a)(2)(ii).
(ii) If the pipeline segment includes
legacy pipe or was constructed using
legacy construction techniques or the
pipeline has experienced an incident, as
defined by § 191.3 of this chapter, since
its most recent successful subpart J
pressure test, due to an original
manufacturing-related defect, a
construction-, installation-, or
fabrication-related defect, or a crack or
crack-like defect, including, but not
limited to, seam cracking, girth weld
cracking, selective seam weld corrosion,
hard spot, or stress corrosion cracking,
then the operator must perform a spike
pressure test in accordance with
§ 192.506. The maximum allowable
operating pressure will be equal to the
test pressure specified in § 192.506(c)
divided by the greater of 1.25 or the
applicable class location factor in
§ 192.619(a)(2)(ii) or § 192.620(a)(2)(ii).
(iii) If the operator has reason to
believe any pipeline segment may be
susceptible to cracks or crack-like
defects due to assessment, leak, failure,
or manufacturing vintage histories, or
any other available information about
the pipeline, the operator must estimate
the remaining life of the pipeline in
accordance with paragraph (d) of this
section.
(2) Method 2: Pressure reduction. The
pipeline maximum allowable operating
pressure will be no greater than the
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highest actual operating pressure
sustained by the pipeline during the 18
months preceding [effective date of the
final rule] divided by the greater of 1.25
or the applicable class location factor in
§ 192.619(a)(2)(ii) or § 192.620(a)(2)(ii).
The highest actual sustained pressure
must have been reached for a minimum
cumulative duration of 8 hours during
a continuous 30-day period. The value
used as the highest actual sustained
operating pressure must account for
differences between discharge and
upstream pressure on the pipeline by
use of either the lowest pressure value
for the entire segment or using the
operating pressure gradient (i.e., the
location-specific operating pressure at
each location).
(i) Where the pipeline segment has
had a class location change in
accordance with § 192.611 and pipe
material and pressure test records are
not available, the operator must reduce
the pipeline segment MAOP as follows:
(A) For segments where a class
location changed from 1 to 2, from 2 to
3, or from 3 to 4, reduce the pipeline
maximum allowable operating pressure
to no greater than the highest actual
operating pressure sustained by the
pipeline during the 18 months
preceding [effective date of the final
rule], divided by 1.39 for class 1 to 2,
1.67 for class 2 to 3, and 2.00 for class
3 to 4.
(B) For segments where a class
location changed from 1 to 3, reduce the
pipeline maximum allowable operating
pressure to no greater than the highest
actual operating pressure sustained by
the pipeline during the 18 months
preceding [effective date of the final
rule], divided by 2.00.
(ii) If the operator has reason to
believe any pipeline segment contains
or may be susceptible to cracks or cracklike defects due to assessment, leak,
failure, or manufacturing vintage
histories, or any other available
information about the pipeline, the
operator must estimate the remaining
life of the pipeline in accordance with
paragraph (d) of this section.
(iii) Future uprating of the segment in
accordance with subpart K of this part
is allowed if the maximum allowable
operating pressure is established using
Method 2 described in paragraph (c)(2)
of this section.
(iv) If an operator elects to use
Method 2 described in paragraph (c)(2)
of this section, but desires to use a less
conservative pressure reduction factor,
the operator must notify PHMSA in
accordance with paragraph (e) of this
section no later than seven calendar
days after establishing the reduced
maximum allowable operating pressure.
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The notification must include the
following details:
(A) Descriptions of the operational
constraints, special circumstances, or
other factors that preclude, or make it
impractical, to use the pressure
reduction factor specified in
§ 192.624(c)(2);
(B) The fracture mechanics modeling
for failure stress pressures and cyclic
fatigue crack growth analysis that
complies with paragraph (d) of this
section;
(C) Justification that establishing
maximum allowable operating pressure
by another method allowed by this
section is impractical;
(D) Justification that the reduced
maximum allowable operating pressure
determined by the operator is safe based
on analysis of the condition of the
pipeline segment, including material
records, material properties verified in
accordance § 192.607, and the history of
the segment, particularly known
corrosion and leakage, and the actual
operating pressure, and additional
compensatory preventive and mitigative
measures taken or planned.
(E) Planned duration for operating at
the requested maximum allowable
operating pressure, long term
remediation measures and justification
of this operating time interval, including
fracture mechanics modeling for failure
stress pressures and cyclic fatigue
growth analysis and other validated
forms of engineering analysis that have
been reviewed and confirmed by subject
matter experts in metallurgy and
fracture mechanics.
(3) Method 3: Engineering critical
assessment. Conduct an engineering
critical assessment and analysis (ECA)
to establish the material condition of the
segment and maximum allowable
operating pressure. An ECA is an
analytical procedure, based on fracture
mechanics principles, relevant material
properties (mechanical and fracture
resistance properties), operating history,
operational environment, in-service
degradation, possible failure
mechanisms, initial and final defect
sizes, and usage of future operating and
maintenance procedures to determine
the maximum tolerable sizes for
imperfections. The ECA must assess:
threats; loadings and operational
circumstances relevant to those threats
including along the right-of way;
outcomes of the threat assessment;
relevant mechanical and fracture
properties; in-service degradation or
failure processes; initial and final defect
size relevance. The ECA must quantify
the coupled effects of any defect in the
pipeline.
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(i) ECA analysis. (A) The ECA must
integrate and analyze the results of the
material documentation program
required by § 192.607, if applicable, and
the results of all tests, direct
examinations, destructive tests, and
assessments performed in accordance
with this section, along with other
pertinent information related to pipeline
integrity, including but not limited to
close interval surveys, coating surveys,
and interference surveys required by
subpart I of this part, root cause
analyses of prior incidents, prior
pressure test leaks and failures, other
leaks, pipe inspections, and prior
integrity assessments, including those
required by § 192.710 and subpart O of
this part.
(B) The ECA must analyze any cracks
or crack-like defects remaining in the
pipe, or that could remain in the pipe,
to determine the predicted failure
pressure (PFP) of each defect. The ECA
must use the techniques and procedures
in Battelle Final Reports (‘‘Battelle’s
Experience with ERW and Flash Weld
Seam Failures: Causes and
Implications’’—Task 1.4), Report No.
13–002 (‘‘Models for Predicting Failure
Stress Levels for Defects Affecting ERW
and Flash-Welded Seams’’—Subtask
2.4), Report No. 13–021 (‘‘Predicting
Times to Failure for ERW Seam Defects
that Grow by Pressure-Cycle-Induced
Fatigue’’—Subtask 2.5) and (‘‘Final
Summary Report and Recommendations
for the Comprehensive Study to
Understand Longitudinal ERW Seam
Failures—Phase 1’’—Task 4.5)
(incorporated by reference, see § 192.7)
or other technically proven methods
including but not limited to API RP
579–1/ASME FFS–1, June 5, 2007, (API
579–1, Second Edition)—Level II or
Level III, CorLasTM, or PAFFC. The ECA
must use conservative assumptions for
crack dimensions (length and depth)
and failure mode (ductile, brittle, or
both) for the microstructure, location,
type of defect, and operating conditions
(which includes pressure cycling). If
actual material toughness is not known
or not adequately documented by
reliable, traceable, verifiable, and
complete records, then the operator
must determine a Charpy v-notch
toughness based upon the material
documentation program specified in
§ 192.607 or use conservative values for
Charpy v-notch toughness as follows:
body toughness of less than or equal to
5.0 ft-lb and seam toughness of less than
or equal to 1 ft-lb.
(C) The ECA must analyze any metal
loss defects not associated with a dent
including corrosion, gouges, scrapes or
other metal loss defects that could
remain in the pipe to determine the
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predicted failure pressure (PFP). ASME/
ANSI B31G (incorporated by reference,
see § 192.7) or AGA Pipeline Research
Committee Project PR–3–805
(‘‘RSTRENG,’’ incorporated by
reference, see § 192.7) must be used for
corrosion defects. Both procedures
apply to corroded regions that do not
penetrate the pipe wall over 80 percent
of the wall thickness and are subject to
the limitations prescribed in the
equations procedures. The ECA must
use conservative assumptions for metal
loss dimensions (length, width, and
depth). When determining PFP for
gouges, scrapes, selective seam weld
corrosion, crack-related defects, or any
defect within a dent, appropriate failure
criteria and justification of the criteria
must be used. If SMYS or actual
material yield and ultimate tensile
strength is not known or not adequately
documented by reliable, traceable,
verifiable, and complete records, then
the operator must assume grade A pipe
or determine the material properties
based upon the material documentation
program specified in § 192.607.
(D) The ECA must analyze interacting
defects to conservatively determine the
most limiting PFP for interacting
defects. Examples include but are not
limited to, cracks in or near locations
with corrosion metal loss, dents with
gouges or other metal loss, or cracks in
or near dents or other deformation
damage. The ECA must document all
evaluations and any assumptions used
in the ECA process.
(E) The maximum allowable operating
pressure must be established at the
lowest PFP for any known or postulated
defect, or interacting defects, remaining
in the pipe divided by the greater of
1.25 or the applicable factor listed in
§ 192.619(a)(2)(ii) or § 192.620(a)(2)(ii).
(ii) Use of prior pressure test. If
pressure test records as described in
subpart J of this part and § 192.624(c)(1)
exist for the segment, then an in-line
inspection program is not required,
provided that the remaining life of the
most severe defects that could have
survived the pressure test have been
calculated and a re-assessment interval
has been established. The appropriate
retest interval and periodic tests for
time-dependent threats must be
determined in accordance with the
methodology in § 192.624(d) Fracture
mechanics modeling for failure stress
and crack growth analysis.
(iii) In-line inspection. If the segment
does not have records for a pressure test
in accordance with subpart J of this part
and § 192.624(c)(1), the operator must
develop and implement an inline
inspection (ILI) program using tools that
can detect wall loss, deformation from
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dents, wrinkle bends, ovalities,
expansion, seam defects including
cracking and selective seam weld
corrosion, longitudinal, circumferential
and girth weld cracks, hard spot
cracking, and stress corrosion cracking.
At a minimum, the operator must
conduct an assessment using high
resolution magnetic flux leakage (MFL)
tool, a high resolution deformation tool,
and either an electromagnetic acoustic
transducer (EMAT) or ultrasonic testing
(UT) tool.
(A) In lieu of the tools specified in
paragraph § 192.624(c)(3)(i), an operator
may use ‘‘other technology’’ if it is
validated by a subject matter expert in
metallurgy and fracture mechanics to
produce an equivalent understanding of
the condition of the pipe. If an operator
elects to use ‘‘other technology,’’ it must
notify the Associate Administrator of
Pipeline Safety, at least 180 days prior
to use, in accordance with paragraph (e)
of this section and receive a ‘‘no
objection letter’’ from the Associate
Administrator of Pipeline Safety prior to
its usage. The ‘‘other technology’’
notification must have:
(1) Descriptions of the technology or
technologies to be used for all tests,
examinations, and assessments
including characterization of defect size
crack assessments (length, depth, and
volumetric); and
(2) Procedures and processes to
conduct tests, examinations, and
assessments, perform evaluations,
analyze defects and remediate defects
discovered.
(B) If the operator has information
that indicates a pipeline includes
segments that might be susceptible to
hard spots based on assessment, leak,
failure, manufacturing vintage history,
or other information, then the ILI
program must include a tool that can
detect hard spots.
(C) If the pipeline has had a reportable
incident, as defined in § 192.3,
attributed to a girth weld failure since
its most recent pressure test, then the ILI
program must include a tool that can
detect girth weld defects unless the ECA
analysis performed in accordance with
paragraph § 192.624(c)(3)(iii) includes
an engineering evaluation program to
analyze the susceptibility of girth weld
failure due to lateral stresses.
(D) Inline inspection must be
performed in accordance with
§ 192.493.
(E) All MFL and deformation tools
used must have been validated to
characterize the size of defects within
10% of the actual dimensions with 90%
confidence. All EMAT or UT tools must
have been validated to characterize the
size of cracks, both length and depth,
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within 20% of the actual dimensions
with 80% confidence, with like-similar
analysis from prior tool runs done to
ensure the results are consistent with
the required corresponding hydrostatic
test pressure for the segment being
evaluated.
(F) Interpretation and evaluation of
assessment results must meet the
requirements of §§ 192.710, 192.713,
and subpart O of this part, and must
conservatively account for the accuracy
and reliability of ILI, in-the-ditch
examination methods and tools, and any
other assessment and examination
results used to determine the actual
sizes of cracks, metal loss, deformation
and other defect dimensions by
applying the most conservative limit of
the tool tolerance specification. ILI and
in-the-ditch examination tools and
procedures for crack assessments
(length, depth, and volumetric) must
have performance and evaluation
standards confirmed for accuracy
through confirmation tests for the type
defects and pipe material vintage being
evaluated. Inaccuracies must be
accounted for in the procedures for
evaluations and fracture mechanics
models for predicted failure pressure
determinations.
(G) Anomalies detected by ILI
assessments must be repaired in
accordance with applicable repair
criteria in §§ 192.713 and 192.933.
(iv) If the operator has reason to
believe any pipeline segment contains
or may be susceptible to cracks or cracklike defects due to assessment, leak,
failure, or manufacturing vintage
histories, or any other available
information about the pipeline, the
operator must estimate the remaining
life of the pipeline in accordance with
paragraph § 192.624(d).
(4) Method 4: Pipe replacement.
Replace the pipeline segment.
(5) Method 5: Pressure reduction for
segments with small potential impact
radius and diameter. Pipelines with a
maximum allowable operating pressure
less than 30 percent of specified
minimum yield strength, a potential
impact radius (PIR) less than or equal to
150 feet, nominal diameter equal to or
less than 8-inches, and which cannot be
assessed using inline inspection or
pressure test, may establish the
maximum allowable operating pressure
as follows:
(i) Reduce the pipeline maximum
allowable operating pressure to no
greater than the highest actual operating
pressure sustained by the pipeline
during 18 months preceding [effective
date of the final rule], divided by 1.1.
The highest actual sustained pressure
must have been reached for a minimum
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cumulative duration of eight hours
during one continuous 30-day period.
The reduced maximum allowable
operating pressure must account for
differences between discharge and
upstream pressure on the pipeline by
use of either the lowest value for the
entire segment or the operating pressure
gradient (i.e., the location specific
operating pressure at each location);
(ii) Conduct external corrosion direct
assessment in accordance with
§ 192.925, and internal corrosion direct
assessment in accordance with
§ 192.927;
(iii) Develop and implement
procedures for conducting nondestructive tests, examinations, and
assessments for cracks and crack-like
defects, including but not limited to
stress corrosion cracking, selective seam
weld corrosion, girth weld cracks, and
seam defects, for pipe at all excavations
associated with anomaly direct
examinations, in situ evaluations,
repairs, remediations, maintenance, or
any other reason for which the pipe
segment is exposed, except for segments
exposed during excavation activities
that are in compliance with § 192.614;
(iv) Conduct monthly patrols in Class
1 and 2 locations, at an interval not to
exceed 45 days; weekly patrols in Class
3 locations not to exceed 10 days; and
semi-weekly patrols in Class 4 locations,
at an interval not to exceed six days, in
accordance with § 192.705;
(v) Conduct monthly, instrumented
leakage surveys in Class 1 and 2
locations, at intervals not to exceed 45
days; weekly leakage surveys in Class 3
locations at intervals not to exceed 10
days; and semi-weekly leakage surveys
in Class 4 locations, at intervals not to
exceed six days, in accordance with
§ 192.706; and
(vi) Odorize gas transported in the
segment, in accordance with § 192.625;
(vii) If the operator has reason to
believe any pipeline segment contains
or may be susceptible to cracks or cracklike defects due to assessment, leak,
failure, or manufacturing vintage
histories, or any other available
information about the pipeline, the
operator must estimate the remaining
life of the pipeline in accordance with
paragraph § 192.624(d).
(viii) Under Method 5 described in
paragraph (c)(5) of this section, future
uprating of the segment in accordance
with subpart K of this part is allowed.
(6) Method 6: Alternative technology.
Operators may use an alternative
technical evaluation process that
provides a sound engineering basis for
establishing maximum allowable
operating pressure. If an operator elects
to use alternative technology, the
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operator must notify PHMSA at least
180 days in advance of use in
accordance with paragraph (e) of this
section. The operator must submit the
alternative technical evaluation to
PHMSA with the notification and obtain
a ‘‘no objection letter’’ from the
Associate Administrator of Pipeline
Safety prior to usage of alternative
technology. The notification must
include the following details:
(i) Descriptions of the technology or
technologies to be used for tests,
examinations, and assessments,
establishment of material properties,
and analytical techniques, with likesimilar analysis from prior tool runs
done to ensure the results are consistent
with the required corresponding
hydrostatic test pressure for the segment
being evaluated.
(ii) Procedures and processes to
conduct tests, examinations, and
assessments, perform evaluations,
analyze defects and flaws, and
remediate defects discovered;
(iii) Methodology and criteria used to
determine reassessment period or need
for a reassessment including references
to applicable regulations from this part
and industry standards;
(iv) Data requirements including
original design, maintenance and
operating history, anomaly or flaw
characterization;
(v) Assessment techniques and
acceptance criteria, including anomaly
detection confidence level, probability
of detection, and uncertainty of PFP
quantified as a fraction of specified
minimum yield strength;
(vi) If the operator has reason to
believe any pipeline segment contains
or may be susceptible to cracks or cracklike defects due to assessment, leak,
failure, or manufacturing vintage
histories, or any other available
information about the pipeline, the
operator must estimate the remaining
life of the pipeline in accordance with
paragraph (d) of this section;
(vii) Remediation methods with
proven technical practice;
(viii) Schedules for assessments and
remediation;
(ix) Operational monitoring
procedures;
(x) Methodology and criteria used to
justify and establish the maximum
allowable operating pressure; and
(xi) Documentation requirements for
the operator’s process, including records
to be generated.
(d) Fracture mechanics modeling for
failure stress and crack growth analysis.
(1) If the operator has reason to believe
any pipeline segment contains or may
be susceptible to cracks or crack-like
defects due to assessment, leak, failure,
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or manufacturing vintage histories, or
any other available information about
the pipeline, the operator must perform
fracture mechanics modeling for failure
stress pressure and crack growth
analysis to determine the remaining life
of the pipeline at the maximum
allowable operating pressure based on
the applicable test pressures in
accordance with § 192.506 including the
remaining crack flaw size in the
pipeline segment, any pipe failure or
leak mechanisms identified during
pressure testing, pipe characteristics,
material toughness, failure mechanism
for the microstructure(ductile and brittle
or both), location and type of defect,
operating environment, and operating
conditions including pressure cycling.
Fatigue analysis must be performed
using a recognized form of the Paris Law
as specified in Battelle’s Final Report
No. 13–021; Subtask 2.5 (incorporated
by reference, see § 192.7) or other
technically appropriate engineering
methodology validated by a subject
matter expert in metallurgy and fracture
mechanics to give conservative
predictions of flaw growth and
remaining life. When assessing other
degradation processes, the analysis must
be performed using recognized rate
equations whose applicability and
validity is demonstrated for the case
being evaluated. For cases involving
calculation of the critical flaw size,
conservative remaining life analysis
must assess the smallest critical sizes
and use a lower-bound toughness. For
cases dealing with an estimating of the
defect sizes that would survive a hydro
test pressure, conservative remaining
life analysis that must assess the largest
surviving sizes and use upper-bound
values of material strength and
toughness. The analysis must include a
sensitivity analysis to determine
conservative estimates of time to failure
for cracks. Material strength and
toughness values used must reflect the
local conditions for growth, and use
data that is case specific to estimate the
range of strength and toughness for such
analysis. When the strength and
toughness and limits on their ranges are
unknown, the analysis must assume
material strength and fracture toughness
levels corresponding to the type of
assessment being performed, as follows:
(i) For an assessment using a
hydrostatic pressure test use a full size
equivalent Charpy upper-shelf energy
level of 120 ft-lb and a flow stress equal
to the minimum specified ultimate
tensile strength of the base pipe
material. The purpose of using the high
level of Charpy energy and flow stress
(equal to the ultimate tensile strength) is
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for an operator to calculate the largest
defects that could have survived a given
level of hydrostatic test. The resulting
maximum-size defects lead to the
shortened predicted times to failure,
(ii) For ILI assessments unless actual
ranges of values of strength and
toughness are known, the analysis must
use the specified minimum yield
strength and the specified minimum
ultimate tensile strength and Charpy
toughness valves lower than or equal to:
5.0 ft-lb for body cracks; 1.0 ft-lb for
ERW seam bond line defects such as
cold weld, lack of fusion, and selective
seam weld corrosion defects.
(iii) The sensitivity analysis to
determine the time to failure for a crack
must include operating history, pressure
tests, pipe geometry, wall thickness,
strength level, flow stress, and operating
environment for the pipe segment being
assessed, including at a minimum the
role of the pressure-cycle spectrum.
(2) If actual material toughness is not
known or not adequately documented
for fracture mechanics modeling for
failure stress pressure, the operator must
use a conservative Charpy energy value
to determine the toughness based upon
the material documentation program
specified in § 192.607; or use maximum
Charpy energy values of 5.0 ft-lb for
body cracks; 1.0 ft-lb for cold weld, lack
of fusion, and selective seam weld
corrosion defects as documented in
Battelle Final Reports (‘‘Battelle’s
Experience with ERW and Flash Weld
Seam Failures: Causes and
Implications’’—Task 1.4), No. 13–002
(‘‘Models for Predicting Failure Stress
Levels for Defects Affecting ERW and
Flash-Welded Seams’’—Subtask 2.4),
Report No. 13–021 (‘‘Predicting Times
to Failure for ERW Seam Defects that
Grow by Pressure-Cycle-Induced
Fatigue’’—Subtask 2.5) and (‘‘Final
Summary Report and Recommendations
for the Comprehensive Study to
Understand Longitudinal ERW Seam
Failures—Phase 1’’—Task 4.5)
(incorporated by reference, see § 192.7);
or other appropriate technology or
technical publications that an operator
demonstrates can provide a conservative
Charpy energy values of the crackrelated conditions of the line pipe.
(3) The analysis must account for
metallurgical properties at the location
being analyzed (such as in the
properties of the parent pipe, weld heat
affected zone, or weld metal bond line),
and must account for the likely failure
mode of anomalies (such as brittle
fracture, ductile fracture or both). If the
likely failure mode is uncertain or
unknown, the analysis must analyze
both failure modes and use the more
conservative result. Appropriate fracture
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mechanics modeling for failure stress
pressures in the brittle failure mode is
the Raju/Newman Model (Task 4.5) and
for the ductile failure mode is the
Modified LnSec (Task 4.5) and Raju/
Newman Models or other provenequivalent engineering fracture
mechanics models for determining
conservative failure pressures may be
used.
(4) If the predicted remaining life of
the pipeline calculated by this analysis
is 5 years or less, then the operator must
perform a pressure test in accordance
with paragraph (c)(1) of this section or
reduce the maximum allowable
operating pressure of the pipeline in
accordance with paragraph (c)(2) of this
section to establish the maximum
allowable operating pressure within 1year of analysis;
(5) The operator must re-evaluate the
remaining life of the pipeline before
50% of the remaining life calculated by
this analysis has expired, but within 15
years. The operator must determine and
document if further pressure tests or use
of other methods are required at that
time. The operator must continue to reevaluate the remaining life of the
pipeline before 50% of the remaining
life calculated in the most recent
evaluation has expired. If the analysis
results show that a 50% remaining life
reduction does not give a sufficient
safety factor based upon technical
evaluations then a more conservative
remaining life safety factor must be
used.
(6) The analysis required by this
paragraph (d) of this section must be
reviewed and confirmed by a subject
matter expert in both metallurgy and
fracture mechanics.
(e) Notifications. An operator must
submit all notifications required by this
section to the Associate Administrator
for Pipeline Safety, by:
(1) Sending the notification to the
Office of Pipeline Safety, Pipeline and
Hazardous Material Safety
Administration, U.S. Department of
Transportation, Information Resources
Manager, PHP–10, 1200 New Jersey
Avenue SE., Washington, DC 20590–
0001;
(2) Sending the notification to the
Information Resources Manager by
facsimile to (202) 366–7128; or
(3) Sending the notification to the
Information Resources Manager by
email to
InformationResourcesManager@dot.gov.
(4) An operator must also send a copy
to a State pipeline safety authority when
the pipeline is located in a State where
PHMSA has an interstate agent
agreement, or an intrastate pipeline is
regulated by that State.
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(f) Records. Each operator must keep
for the life of the pipeline reliable,
traceable, verifiable, and complete
records of the investigations, tests,
analyses, assessments, repairs,
replacements, alterations, and other
actions made in accordance with the
requirements of this section.
■ 34. Section 192.710 is added to read
as follows:
§ 192.710
Pipeline assessments.
(a) Applicability. (1) This section
applies to onshore transmission
pipeline segments that are located in:
(i) A class 3 or class 4 location; or
(ii) A moderate consequence area as
defined in § 192.3 if the pipe segment
can accommodate inspection by means
of instrumented inline inspection tools
(i.e., ‘‘smart pigs’’).
(2) This section does not apply to a
pipeline segment located in a high
consequence area as defined in
§ 192.903.
(b) General. (1) An operator must
perform initial assessments in
accordance with this section no later
than [date 15 years after effective date
of the final rule] and periodic
reassessments every 20 years thereafter,
or a shorter reassessment internal based
upon the type anomaly, operational,
material, and environmental conditions
found on the pipeline segment, or as
otherwise necessary to ensure public
safety.
(2) Prior assessment. An operator may
use a prior assessment conducted before
[effective date of the final rule] as an
initial assessment for the segment, if the
assessment meets the subpart O of this
part requirements for in-line inspection.
If an operator uses this prior assessment
as its initial assessment, the operator
must reassess the pipeline segment
according to the reassessment interval
specified in paragraph (b)(1) of this
section.
(3) MAOP verification. An operator
may use an integrity assessment to meet
the requirements of this section if the
pipeline segment assessment is
conducted in accordance with the
integrity assessment requirements of
§ 192.624(c) for establishing MAOP.
(c) Assessment method. The initial
assessments and the reassessments
required by paragraph (b) of this section
must be capable of identifying
anomalies and defects associated with
each of the threats to which the pipeline
is susceptible and must be performed
using one or more of the following
methods:
(1) Internal inspection tool or tools
capable of detecting corrosion,
deformation and mechanical damage
(including dents, gouges and grooves),
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material cracking and crack-like defects
(including stress corrosion cracking,
selective seam weld corrosion,
environmentally assisted cracking, and
girth weld cracks), hard spots, and any
other threats to which the segment is
susceptible. When performing an
assessment using an in-line inspection
tool, an operator must comply with
§ 192.493;
(2) Pressure test conducted in
accordance with subpart J of this part.
The use of pressure testing is
appropriate for threats such as internal
corrosion, external corrosion, and other
environmentally assisted corrosion
mechanisms, manufacturing and related
defect threats, including defective pipe
and pipe seams, dents and other forms
of mechanical damage;
(3) ‘‘Spike’’ hydrostatic pressure test
in accordance with § 192.506;
(4) Excavation and in situ direct
examination by means of visual
examination and direct measurement
and recorded non-destructive
examination results and data needed to
assess all threats, including but not
limited to, ultrasonic testing (UT),
radiography, and magnetic particle
inspection (MPI);
(5) Guided wave ultrasonic testing
(GWUT) as described in appendix F;
(6) Direct assessment to address
threats of external corrosion, internal
corrosion, and stress corrosion cracking.
Use of direct assessment is allowed only
if the line is not capable of inspection
by internal inspection tools and is not
practical to assess (due to low operating
pressures and flows, lack of inspection
technology, and critical delivery areas
such as hospitals and nursing homes)
using the methods specified in
paragraphs (d)(1) through (5) of this
section. An operator must conduct the
direct assessment in accordance with
the requirements listed in § 192.923 and
with the applicable requirements
specified in §§ 192.925, 192.927 or
192.929; or
(7) Other technology or technologies
that an operator demonstrates can
provide an equivalent understanding of
the line pipe for each of the threats to
which the pipeline is susceptible.
(8) For segments with MAOP less than
30% of the SMYS, an operator must
assess for the threats of external and
internal corrosion, as follows:
(i) External corrosion. An operator
must take one of the following actions
to address external corrosion on a low
stress segment:
(A) Cathodically protected pipe. To
address the threat of external corrosion
on cathodically protected pipe, an
operator must perform an indirect
assessment (i.e. indirect examination
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tool/method such as close interval
survey, alternating current voltage
gradient, direct current voltage gradient,
or equivalent) at least every seven years
on the segment. An operator must use
the results of each survey as part of an
overall evaluation of the cathodic
protection and corrosion threat for the
segment. This evaluation must consider,
at minimum, the leak repair and
inspection records, corrosion
monitoring records, exposed pipe
inspection records, and the pipeline
environment.
(B) Unprotected pipe or cathodically
protected pipe where indirect
assessments are impractical. To address
the threat of external corrosion on
unprotected pipe or cathodically
protected pipe where indirect
assessments are impractical, an operator
must—
(1) Conduct leakage surveys as
required by § 192.706 at 4-month
intervals; and
(2) Every 18 months, identify and
remediate areas of active corrosion by
evaluating leak repair and inspection
records, corrosion monitoring records,
exposed pipe inspection records, and
the pipeline environment.
(ii) Internal corrosion. To address the
threat of internal corrosion on a low
stress segment, an operator must—
(A) Conduct a gas analysis for
corrosive agents at least twice each
calendar year;
(B) Conduct periodic testing of fluids
removed from the segment. At least
once each calendar year test the fluids
removed from each storage field that
may affect a segment; and
(C) At least every seven (7) years,
integrate data from the analysis and
testing required by paragraphs
(c)(8)(ii)(A) and (B) of this section with
applicable internal corrosion leak
records, incident reports, safety-related
condition reports, repair records, patrol
records, exposed pipe reports, and test
records, and define and implement
appropriate remediation actions.
(d) Data analysis. A person qualified
by knowledge, training, and experience
must analyze the data obtained from an
assessment performed under paragraph
(b) of this section to determine if a
condition could adversely affect the safe
operation of the pipeline. In addition,
an operator must explicitly consider
uncertainties in reported results
(including, but not limited to, tool
tolerance, detection threshold,
probability of detection, probability of
identification, sizing accuracy,
conservative anomaly interaction
criteria, location accuracy, anomaly
findings, and unity chart plots or
equivalent for determining uncertainties
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and verifying tool performance) in
identifying and characterizing
anomalies.
(e) Discovery of condition. Discovery
of a condition occurs when an operator
has adequate information to determine
that a condition exists. An operator
must promptly, but no later than 180
days after an assessment, obtain
sufficient information about a condition
to make the determination required
under paragraph (d), unless the operator
can demonstrate that that 180-days is
impracticable.
(f) Remediation. An operator must
comply with the requirements in
§ 192.713 if a condition that could
adversely affect the safe operation of a
pipeline is discovered.
(g) Consideration of information. An
operator must consider all available
information about a pipeline in
complying with the requirements in
paragraphs (a) through (f) of this section.
■ 35. In § 192.711, paragraph (b)(1) is
revised to read as follows:
§ 192.711 Transmission lines: General
requirements for repair procedures.
*
*
*
*
*
(b) * * *
(1) Non integrity management repairs.
Whenever an operator discovers any
condition that could adversely affect the
safe operation of a pipeline segment not
covered under subpart O of this part,
Gas Transmission Pipeline Integrity
Management, it must correct the
condition as prescribed in § 192.713.
However, if the condition is of such a
nature that it presents an immediate
hazard to persons or property, the
operator must reduce the operating
pressure to a level not exceeding 80%
of the operating pressure at the time the
condition was discovered and take
additional immediate temporary
measures in accordance with paragraph
(a) of this section to protect persons or
property. The operator must make
permanent repairs as soon as feasible.
*
*
*
*
*
■ 36. Section 192.713 is revised to read
as follows:
§ 192.713 Transmission lines: Permanent
field repair of imperfections and damages.
(a) This section applies to
transmission lines. Line segments that
are located in high consequence areas,
as defined in § 192.903, must also
comply with applicable actions
specified by the integrity management
requirements in subpart O of this part.
(b) General. Each operator must, in
repairing its pipeline systems, ensure
that the repairs are made in a safe
manner and are made so as to prevent
damage to persons, property, or the
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environment. Operating pressure must
be at a safe level during repair
operations.
(c) Repair. Each imperfection or
damage that impairs the serviceability of
pipe in a steel transmission line
operating at or above 40 percent of
SMYS must be—
(1) Removed by cutting out and
replacing a cylindrical piece of pipe; or
(2) Repaired by a method that reliable
engineering tests and analyses show can
permanently restore the serviceability of
the pipe.
(d) Remediation schedule. For
pipelines not located in high
consequence areas, an operator must
complete the remediation of a condition
according to the following schedule:
(1) Immediate repair conditions. An
operator must repair the following
conditions immediately upon discovery:
(i) A calculation of the remaining
strength of the pipe shows a predicted
failure pressure less than or equal to 1.1
times the maximum allowable operating
pressure at the location of the anomaly.
Suitable remaining strength calculation
methods include, ASME/ANSI B31G;
RSTRENG; or an alternative equivalent
method of remaining strength
calculation. These documents are
incorporated by reference and available
at the addresses listed in § 192.7(c). Pipe
and material properties used in
remaining strength calculations must be
documented in reliable, traceable,
verifiable, and complete records. If such
records are not available, pipe and
material properties used in the
remaining strength calculations must be
based on properties determined and
documented in accordance with
§ 192.607.
(ii) A dent that has any indication of
metal loss, cracking or a stress riser.
(iii) Metal loss greater than 80% of
nominal wall regardless of dimensions.
(iv) An indication of metal-loss
affecting a detected longitudinal seam, if
that seam was formed by direct current
or low-frequency or high frequency
electric resistance welding or by electric
flash welding.
(v) Any indication of significant stress
corrosion cracking (SCC).
(vi) Any indication of significant
selective seam weld corrosion (SSWC).
(vii) An indication or anomaly that in
the judgment of the person designated
by the operator to evaluate the
assessment results requires immediate
action.
(2) Until the remediation of a
condition specified in paragraph (d)(1)
of this section is complete, an operator
must reduce the operating pressure of
the affected pipeline to the lower of:
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(i) A level that restores the safety
margin commensurate with the design
factor for the Class Location in which
the affected pipeline is located,
determined using ASME/ANSI B31G
(‘‘Manual for Determining the
Remaining Strength of Corroded
Pipelines’’ (1991) or AGA Pipeline
Research Committee Project PR–3–805
(‘‘A Modified Criterion for Evaluating
the Remaining Strength of Corroded
Pipe’’ (December 1989)) (‘‘RSTRENG,’’
incorporated by reference, see § 192.7)
for corrosion defects. Both procedures
apply to corroded regions that do not
penetrate the pipe wall over 80 percent
of the wall thickness and are subject to
the limitations prescribed in the
equations procedures. When
determining the predicted failure
pressure (PFP) for gouges, scrapes,
selective seam weld corrosion, crackrelated defects, appropriate failure
criteria and justification of the criteria
must be used. If SMYS or actual
material yield and ultimate tensile
strength is not known or not adequately
documented by reliable, traceable,
verifiable, and complete records, then
the operator must assume grade A pipe
or determine the material properties
based upon the material documentation
program specified in § 192.607; or
(ii) 80% of pressure at the time of
discovery, whichever is lower.
(3) Two-year conditions. An operator
must repair the following conditions
within two years of discovery:
(i) A smooth dent located between the
8 o’clock and 4 o’clock positions (upper
2/3 of the pipe) with a depth greater
than 6% of the pipeline diameter
(greater than 0.50 inches in depth for a
pipeline diameter less than nominal
pipe size (NPS) 12).
(ii) A dent with a depth greater than
2% of the pipeline’s diameter (0.250
inches in depth for a pipeline diameter
less than NPS 12) that affects pipe
curvature at a girth weld or at a
longitudinal or helical (spiral) seam
weld.
(iii) A calculation of the remaining
strength of the pipe shows a predicted
failure pressure ratio (FPR) at the
location of the anomaly less than or
equal to 1.25 for Class 1 locations, 1.39
for Class 2 locations, 1.67 for Class 3
locations, and 2.00 for Class 4 locations.
This calculation must adequately
account for the uncertainty associated
with the accuracy of the tool used to
perform the assessment.
(iv) An area of corrosion with a
predicted metal loss greater than 50% of
nominal wall.
(v) Predicted metal loss greater than
50% of nominal wall that is located at
a crossing of another pipeline, or is in
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an area with widespread circumferential
corrosion, or is in an area that could
affect a girth weld.
(vi) A gouge or groove greater than
12.5% of nominal wall.
(vii) Any indication of crack or cracklike defect other than an immediate
condition.
(4) Monitored conditions. An operator
does not have to schedule the following
conditions for remediation, but must
record and monitor the conditions
during subsequent risk assessments and
integrity assessments for any change
that may require remediation:
(i) A dent with a depth greater than
6% of the pipeline diameter (greater
than 0.50 inches in depth for a pipeline
diameter less than NPS 12) located
between the 4 o’clock position and the
8 o’clock position (bottom 1/3 of the
pipe).
(ii) A dent located between the 8
o’clock and 4 o’clock positions (upper
2/3 of the pipe) with a depth greater
than 6% of the pipeline diameter
(greater than 0.50 inches in depth for a
pipeline diameter less than nominal
pipe size (NPS) 12), and engineering
analyses of the dent demonstrate critical
strain levels are not exceeded.
(e) Other conditions. Unless another
timeframe is specified in paragraph (d)
of this section, an operator must take
appropriate remedial action to correct
any condition that could adversely
affect the safe operation of a pipeline
system in accordance with the criteria,
schedules and methods defined in the
operator’s Operating and Maintenance
procedures.
(f) In situ direct examination of crack
defects. Whenever required by this part,
operators must perform direct
examination of known locations of
cracks or crack-like defects using
inverse wave field extrapolation (IWEX),
phased array, automated ultrasonic
testing (AUT), or equivalent technology
that has been validated to detect tight
cracks (equal to or less than 0.008
inches). In-the-ditch examination tools
and procedures for crack assessments
(length, depth, and volumetric) must
have performance and evaluation
standards, including pipe or weld
surface cleanliness standards for the
inspection, confirmed by subject matter
experts qualified by knowledge,
training, and experience in direct
examination inspection and in
metallurgy and fracture mechanics for
accuracy for the type of defects and pipe
material being evaluated. The
procedures must account for
inaccuracies in evaluations and fracture
mechanics models for failure pressure
determinations.
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37. Section 192.750 is added to read
as follows:
■
§ 192.750
Launcher and receiver safety.
Any launcher or receiver used after
[date 6 months after effective date of the
final rule], must be equipped with a
device capable of safely relieving
pressure in the barrel before removal or
opening of the launcher or receiver
barrel closure or flange and insertion or
removal of in-line inspection tools,
scrapers, or spheres. The operator must
use a suitable device to indicate that
pressure has been relieved in the barrel
or must provide a means to prevent
opening of the barrel closure or flange,
or prevent insertion or removal of inline inspection tools, scrapers, or
spheres, if pressure has not been
relieved.
■ 38. In § 192.911, paragraph (k) is
revised to read as follows:
§ 192.911 What are the elements of an
integrity management program?
*
*
*
*
*
(k) A management of change process
as required by § 192.13(d).
*
*
*
*
*
■ 39. In § 192.917, paragraphs (a), (b),
(c), (d), (e)(2), (e)(3), and (e)(4) are
revised to read as follows:
§ 192.917 How does an operator identify
potential threats to pipeline integrity and
use the threat identification in its integrity
program?
(a) Threat identification. An operator
must identify and evaluate all potential
threats to each covered pipeline
segment. Potential threats that an
operator must consider include, but are
not limited to, the threats listed in
ASME/ANSI B31.8S (incorporated by
reference, see § 192.7), section 2, which
are grouped under the following four
threats:
(1) Time dependent threats such as
internal corrosion, external corrosion,
and stress corrosion cracking;
(2) Stable threats, such as
manufacturing, welding/fabrication, or
equipment defects;
(3) Time independent threats such as
third party/mechanical damage,
incorrect operational procedure,
weather related and outside force,
including consideration of seismicity,
geology, and soil stability of the area;
and
(4) Human error such as operational
mishaps and design and construction
mistakes.
(b) Data gathering and integration. To
identify and evaluate the potential
threats to a covered pipeline segment,
an operator must gather, verify, validate,
and integrate existing data and
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information on the entire pipeline that
could be relevant to the covered
segment. In performing data gathering
and integration, an operator must follow
the requirements in ASME/ANSI
B31.8S, section 4. At a minimum, an
operator must gather and evaluate the
set of data specified in paragraph (b)(1)
of this section and appendix A to
ASME/ANSI B31.8S. The evaluation
must analyze both the covered segment
and similar non-covered segments, and
must:
(1) Integrate information about
pipeline attributes and other relevant
information, including, but not limited
to:
(i) Pipe diameter, wall thickness,
grade, seam type and joint factor;
(ii) Manufacturer and manufacturing
date, including manufacturing data and
records;
(iii) Material properties including, but
not limited to, diameter, wall thickness,
grade, seam type, hardness, toughness,
hard spots, and chemical composition;
(iv) Equipment properties;
(v) Year of installation;
(vi) Bending method;
(vii) Joining method, including
process and inspection results;
(viii) Depth of cover surveys
including stream and river crossings,
navigable waterways, and beach
approaches;
(ix) Crossings, casings (including if
shorted), and locations of foreign line
crossings and nearby high voltage power
lines;
(x) Hydrostatic or other pressure test
history, including test pressures and test
leaks or failures, failure causes, and
repairs;
(xi) Pipe coating methods (both
manufactured and field applied)
including method or process used to
apply girth weld coating, inspection
reports, and coating repairs;
(xii) Soil, backfill;
(xiii) Construction inspection reports,
including but not limited to:
(A) Girth weld non-destructive
examinations;
(B) Post backfill coating surveys;
(C) Coating inspection (‘‘jeeping’’)
reports;
(xiv) Cathodic protection installed,
including but not limited to type and
location;
(xv) Coating type;
(xvi) Gas quality;
(xvii) Flow rate;
(xviii) Normal maximum and
minimum operating pressures,
including maximum allowable
operating pressure (MAOP);
(xix) Class location;
(xx) Leak and failure history
including any in-service ruptures or
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leaks from incident reports, abnormal
operations, safety related conditions
(both reported and unreported) and
failure investigations required by
§ 192.617, and their identified causes
and consequences;
(xxi) Coating condition;
(xxii) CP system performance;
(xxiii) Pipe wall temperature;
(xxiv) Pipe operational and
maintenance inspection reports,
including but not limited to:
(A) Data gathered through integrity
assessments required under this part,
including but not limited to in-line
inspections, pressure tests, direct
assessment, guided wave ultrasonic
testing, or other methods;
(B) Close interval survey (CIS) and
electrical survey results;
(C) Cathodic protection (CP) rectifier
readings;
(D) CP test point survey readings and
locations;
(E) AC/DC and foreign structure
interference surveys;
(F) Pipe coating surveys, including
surveys to detect coating damage,
disbonded coatings, or other conditions
that compromise the effectiveness of
corrosion protection, including but not
limited to direct current voltage gradient
or alternating current voltage gradient
inspections;
(G) Results of examinations of
exposed portions of buried pipelines
(e.g., pipe and pipe coating condition,
see § 192.459), including the results of
any non-destructive examinations of the
pipe, seam or girth weld, i.e. bell hole
inspections;
(H) Stress corrosion cracking (SCC)
excavations and findings;
(I) Selective seam weld corrosion
(SSWC) excavations and findings;
(J) Gas stream sampling and internal
corrosion monitoring results, including
cleaning pig sampling results;
(xxv) Outer Diameter/Inner Diameter
corrosion monitoring;
(xxvi) Operating pressure history and
pressure fluctuations, including analysis
of effects of pressure cycling and
instances of exceeding MAOP by any
amount;
(xxvii) Performance of regulators,
relief valves, pressure control devices,
or any other device to control or limit
operating pressure to less than MAOP;
(xxviii) Encroachments and right-ofway activity, including but not limited
to, one-call data, pipe exposures
resulting from encroachments, and
excavation activities due to
development or planned development
along the pipeline;
(xxix) Repairs;
(xxx) Vandalism;
(xxxi) External forces;
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(xxxii) Audits and reviews;
(xxxiii) Industry experience for
incident, leak and failure history;
(xxxiv) Aerial photography;
(xxxv) Exposure to natural forces in
the area of the pipeline, including
seismicity, geology, and soil stability of
the area; and
(xxxvi) Other pertinent information
derived from operations and
maintenance activities and any
additional tests, inspections, surveys,
patrols, or monitoring required under
this part.
(2) Use objective, traceable, verified,
and validated information and data as
inputs, to the maximum extent
practicable. If input is obtained from
subject matter experts (SMEs), the
operator must employ measures to
adequately correct any bias in SME
input. Bias control measures may
include training of SMEs and use of
outside technical experts (independent
expert reviews) to assess quality of
processes and the judgment of SMEs.
Operator must document the names of
all SMEs and information submitted by
the SMEs for the life of the pipeline.
(3) Identify and analyze spatial
relationships among anomalous
information (e.g., corrosion coincident
with foreign line crossings; evidence of
pipeline damage where overhead
imaging shows evidence of
encroachment). Storing or recording the
information in a common location,
including a geographic information
system (GIS), alone, is not sufficient;
and
(4) Analyze the data for
interrelationships among pipeline
integrity threats, including
combinations of applicable risk factors
that increase the likelihood of incidents
or increase the potential consequences
of incidents.
(c) Risk assessment. An operator must
conduct a risk assessment that analyzes
the identified threats and potential
consequences of an incident for each
covered segment. The risk assessment
must include evaluation of the effects of
interacting threats, including the
potential for interactions of threats and
anomalous conditions not previously
evaluated. An operator must ensure
validity of the methods used to conduct
the risk assessment in light of incident,
leak, and failure history and other
historical information. Validation must
ensure the risk assessment methods
produce a risk characterization that is
consistent with the operator’s and
industry experience, including
evaluations of the cause of past
incidents, as determined by root cause
analysis or other equivalent means, and
include sensitivity analysis of the
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factors used to characterize both the
probability of loss of pipeline integrity
and consequences of the postulated loss
of pipeline integrity. An operator must
use the risk assessment to determine
additional preventive and mitigative
measures needed (§ 192.935) for each
covered segment, and periodically
evaluate the integrity of each covered
pipeline segment (§ 192.937(b)). The
risk assessment must:
(1) Analyze how a potential failure
could affect high consequence areas,
including the consequences of the entire
worst-case incident scenario from initial
failure to incident termination;
(2) Analyze the likelihood of failure
due to each individual threat or risk
factor, and each unique combination of
threats or risk factors that interact or
simultaneously contribute to risk at a
common location;
(3) Lead to better understanding of the
nature of the threat, the failure
mechanisms, the effectiveness of
currently deployed risk mitigation
activities, and how to prevent, mitigate,
or reduce those risks;
(4) Account for, and compensate for,
uncertainties in the model and the data
used in the risk assessment; and
(5) Evaluate the potential risk
reduction associated with candidate risk
reduction activities such as preventive
and mitigative measures and reduced
anomaly remediation and assessment
intervals.
(d) Plastic transmission pipeline. An
operator of a plastic transmission
pipeline must assess the threats to each
covered segment using the information
in sections 4 and 5 of ASME B31.8S,
and consider any threats unique to the
integrity of plastic pipe such as poor
joint fusion practices, pipe with poor
slow crack growth (SCG) resistance,
brittle pipe, circumferential cracking,
hydrocarbon softening of the pipe,
internal and external loads, longitudinal
or lateral loads, proximity to elevated
heat sources, and point loading.
(e) * * *
(2) Cyclic fatigue. An operator must
evaluate whether cyclic fatigue or other
loading conditions (including ground
movement, suspension bridge
condition) could lead to a failure of a
deformation, including a dent or gouge,
crack, or other defect in the covered
segment. The evaluation must assume
the presence of threats in the covered
segment that could be exacerbated by
cyclic fatigue. An operator must use the
results from the evaluation together
with the criteria used to evaluate the
significance of this threat to the covered
segment to prioritize the integrity
baseline assessment or reassessment.
Fracture mechanics modeling for failure
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stress pressures and cyclic fatigue crack
growth analysis must be conducted in
accordance with § 192.624(d) for cracks.
Cyclic fatigue analysis must be
annually, not to exceed 15 months.
(3) Manufacturing and construction
defects. An operator must analyze the
covered segment to determine the risk of
failure from manufacturing and
construction defects (including seam
defects) in the covered segment. The
analysis must consider the results of
prior assessments on the covered
segment. An operator may consider
manufacturing and construction related
defects to be stable defects only if the
covered segment has been subjected to
hydrostatic pressure testing satisfying
the criteria of subpart J of this part of at
least 1.25 times MAOP, and the segment
has not experienced an in-service
incident attributed to a manufacturing
or construction defect since the date of
the pressure test. If any of the following
changes occur in the covered segment,
an operator must prioritize the covered
segment as a high risk segment for the
baseline assessment or a subsequent
reassessment, and must reconfirm or
reestablish MAOP in accordance with
§ 192.624(c).
(i) The segment has experienced an
in-service incident, as described in
§ 192.624(a)(1);
(ii) MAOP increases; or
(iii) The stresses leading to cyclic
fatigue increase.
(4) ERW pipe. If a covered pipeline
segment contains low frequency electric
resistance welded pipe (ERW), lap
welded pipe, pipe with seam factor less
than 1.0 as defined in § 192.113, or
other pipe that satisfies the conditions
specified in ASME/ANSI B31.8S,
Appendices A4.3 and A4.4, and any
covered or non-covered segment in the
pipeline system with such pipe has
experienced seam failure (including, but
not limited to pipe body cracking, seam
cracking and selective seam weld
corrosion), or operating pressure on the
covered segment has increased over the
maximum operating pressure
experienced during the preceding five
years (including abnormal operation as
defined in § 192.605(c)), or MAOP has
been increased, an operator must select
an assessment technology or
technologies with a proven application
capable of assessing seam integrity and
seam corrosion anomalies. The operator
must prioritize the covered segment as
a high risk segment for the baseline
assessment or a subsequent
reassessment. Pipe with cracks must be
evaluated using fracture mechanics
modeling for failure stress pressures and
cyclic fatigue crack growth analysis to
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estimate the remaining life of the pipe
in accordance with § 192.624(c) and (d).
*
*
*
*
*
■ 40. In § 192.921, paragraph (a) is
revised to read as follows:
§ 192.921 How is the baseline assessment
to be conducted?
(a) Assessment methods. An operator
must assess the integrity of the line pipe
in each covered segment by applying
one or more of the following methods
for each threat to which the covered
segment is susceptible. An operator
must select the method or methods best
suited to address the threats identified
to the covered segment (See § 192.917).
In addition, an operator may use an
integrity assessment to meet the
requirements of this section if the
pipeline segment assessment is
conducted in accordance with the
integrity assessment requirements of
§ 192.624(c) for establishing MAOP.
(1) Internal inspection tool or tools
capable of detecting corrosion,
deformation and mechanical damage
(including dents, gouges and grooves),
material cracking and crack-like defects
(including stress corrosion cracking,
selective seam weld corrosion,
environmentally assisted cracking, and
girth weld cracks), hard spots with
cracking, and any other threats to which
the covered segment is susceptible.
When performing an assessment using
an in-line inspection tool, an operator
must comply with § 192.493. A person
qualified by knowledge, training, and
experience must analyze the data
obtained from an internal inspection
tool to determine if a condition could
adversely affect the safe operation of the
pipeline. In addition, an operator must
explicitly consider uncertainties in
reported results (including, but not
limited to, tool tolerance, detection
threshold, probability of detection,
probability of identification, sizing
accuracy, conservative anomaly
interaction criteria, location accuracy,
anomaly findings, and unity chart plots
or equivalent for determining
uncertainties and verifying actual tool
performance) in identifying and
characterizing anomalies;
(2) Pressure test conducted in
accordance with subpart J of this part.
An operator must use the test pressures
specified in table 3 of section 5 of
ASME/ANSI B31.8S to justify an
extended reassessment interval in
accordance with § 192.939. The use of
pressure testing is appropriate for
threats such as internal corrosion,
external corrosion, and other
environmentally assisted corrosion
mechanisms, manufacturing and related
defect threats, including defective pipe
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and pipe seams, stress corrosion
cracking, selective seam weld corrosion,
dents and other forms of mechanical
damage;
(3) ‘‘Spike’’ hydrostatic pressure test
in accordance with § 192.506. The use
of spike hydrostatic pressure testing is
appropriate for threats such as stress
corrosion cracking, selective seam weld
corrosion, manufacturing and related
defects, including defective pipe and
pipe seams, and other forms of defect or
damage involving cracks or crack-like
defects;
(4) Excavation and in situ direct
examination by means of visual
examination, direct measurement, and
recorded non-destructive examination
results and data needed to assess all
threats, including but not limited to,
ultrasonic testing (UT), radiography,
and magnetic particle inspection (MPI);
(5) Guided Wave Ultrasonic Testing
(GWUT) conducted as described in
Appendix F;
(6) Direct assessment to address
threats of external corrosion, internal
corrosion, and stress corrosion cracking.
Use of direct assessment is allowed only
if the line is not capable of inspection
by internal inspection tools and is not
practical to assess using the methods
specified in paragraphs (d)(1) through
(5) of this section. An operator must
conduct the direct assessment in
accordance with the requirements listed
in § 192.923 and with the applicable
requirements specified in § 192.925,
192.927, or 192.929; or
(7) Other technology that an operator
demonstrates can provide an equivalent
understanding of the condition of the
line pipe for each of the threats to which
the pipeline is susceptible. An operator
choosing this option must notify the
Office of Pipeline Safety (OPS) 180 days
before conducting the assessment, in
accordance with § 192.949 and receive a
‘‘no objection letter’’ from the Associate
Administrator of Pipeline Safety. An
operator must also notify the
appropriate State or local pipeline safety
authority when a covered segment is
located in a State where OPS has an
interstate agent agreement, or an
intrastate covered segment is regulated
by that State.
*
*
*
*
*
■ 41. In § 192.923, paragraphs (b)(2) and
(b)(3) are revised to read as follows:
§ 192.923 How is direct assessment used
and for what threats?
*
*
*
*
*
(b) * * *
(2) NACE SP0206–2006 and § 192.927
if addressing internal corrosion (ICDA).
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(3) NACE SP0204–2008 and § 192.929
if addressing stress corrosion cracking
(SCCDA).
*
*
*
*
*
■ 42. In § 192.927, paragraphs (b) and
(c) are revised to read as follows:
§ 192.927 What are the requirements for
using Internal Corrosion Direct Assessment
(ICDA)?
*
*
*
*
*
(b) General requirements. An operator
using direct assessment as an
assessment method to address internal
corrosion in a covered pipeline segment
must follow the requirements in this
section and in NACE SP0206–2006
(incorporated by reference, see § 192.7).
The Dry Gas (DG) Internal Corrosion
Direct Assessment (ICDA) process
described in this section applies only
for a segment of pipe transporting
normally dry natural gas (see definition
§ 192.3), and not for a segment with
electrolyte normally present in the gas
stream. If an operator uses ICDA to
assess a covered segment operating with
electrolyte present in the gas stream, the
operator must develop a plan that
demonstrates how it will conduct ICDA
in the segment to effectively address
internal corrosion, and must notify the
Office of Pipeline Safety (OPS) 180 days
before conducting the assessment in
accordance with § 192.921(a)(4) or
§ 192.937(c)(4).
(c) The ICDA plan. An operator must
develop and follow an ICDA plan that
meets all requirements and
recommendations contained in NACE
SP0206–2006 and that implements all
four steps of the DG–ICDA process
including pre-assessment, indirect
inspection, detailed examination, and
post-assessment. The plan must identify
where all ICDA Regions with covered
segments are located in the transmission
system. An ICDA Region is a continuous
length of pipe (including weld joints)
uninterrupted by any significant change
in water or flow characteristics that
includes similar physical characteristics
or operating history. An ICDA Region
extends from the location where liquid
may first enter the pipeline and
encompasses the entire area along the
pipeline where internal corrosion may
occur until a new input introduces the
possibility of water entering the
pipeline. In cases where a single
covered segment is partially located in
two or more ICDA regions, the four-step
ICDA process must be completed for
each ICDA region in which the covered
segment is partially located in order to
complete the assessment of the covered
segment.
(1) Preassessment. An operator must
comply with the requirements and
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recommendations in NACE SP0206–
2006 in conducting the preassessment
step of the ICDA process.
(2) Indirect Inspection. An operator
must comply with the requirements and
recommendations in NACE SP0206–
2006, and the following additional
requirements, in conducting the Indirect
Inspection step of the ICDA process.
Operators must explicitly document the
results of its feasibility assessment as
required by NACE SP0206–2006,
Section 3.3; if any condition that
precludes the successful application of
ICDA applies, then ICDA may not be
used, and another assessment method
must be selected. When performing the
indirect inspection, the operator must
use pipeline specific data, exclusively.
The use of assumed pipeline or
operational data is prohibited. When
calculating the critical inclination angle
of liquid holdup and the inclination
profile of the pipeline, the operator
must consider the accuracy, reliability,
and uncertainty of data used to make
those calculations, including but not
limited to gas flow velocity (including
during upset conditions), pipeline
elevation profile survey data (including
specific profile at features with
inclinations such as road crossing, river
crossings, drains, valves, drips, etc.),
topographical data, depth of cover, etc.
The operator must select locations for
direct examination, and establish the
extent of pipe exposure needed (i.e., the
size of the bell hole), to explicitly
account for these uncertainties and their
cumulative effect on the precise location
of predicted liquid dropout.
(3) Detailed examination. An operator
must comply with the requirements and
recommendations in NACE SP0206–
2006 in conducting the detailed
examination step of the ICDA process.
In addition, on the first use of ICDA for
a covered segment, an operator must
identify a minimum of two locations for
excavation within each covered segment
associated with the ICDA Region and
must perform a detailed examination for
internal corrosion at each location using
ultrasonic thickness measurements,
radiography, or other generally accepted
measurement techniques. One location
must be the low point (e.g., sags, drips,
valves, manifolds, dead-legs, traps)
within the covered segment nearest to
the beginning of the ICDA Region. The
second location must be further
downstream, within a covered segment,
near the end of the ICDA Region. If
corrosion is found at any location, the
operator must—
(i) Evaluate the severity of the defect
(remaining strength) and remediate the
defect in accordance with § 192.933, if
the condition is in a covered segment,
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or in accordance with §§ 192.485 and
192.713 if the condition is not in a
covered segment;
(ii) Expand the detailed examination
program, whenever internal corrosion is
discovered, to determine all locations
that have internal corrosion within the
ICDA region, and accurately
characterize the nature, extent, and root
cause of the internal corrosion. In cases
where the internal corrosion was
identified within the ICDA region but
outside the covered segment, the
expanded detailed examination program
must also include at least two detailed
examinations within each covered
segment associated with the ICDA
region, at the location within the
covered segment(s) most likely to have
internal corrosion. One location must be
the low point (e.g., sags, drips, valves,
manifolds, dead-legs, traps) within the
covered segment nearest to the
beginning of the ICDA Region. The
second location must be further
downstream, within the covered
segment. In instances of first use of
ICDA for a covered segment, where
these locations have already been
examined per paragraph (c)(3) of this
section, two additional detailed
examinations must be conducted within
the covered segment; and
(iii) Expand the detailed examination
program to evaluate the potential for
internal corrosion in all pipeline
segments (both covered and noncovered) in the operator’s pipeline
system with similar characteristics to
the ICDA region in which the corrosion
was found and remediate identified
instances of internal corrosion in
accordance with § 192.933 or § 192.713,
as appropriate.
(4) Post-assessment evaluation and
monitoring. An operator must comply
with the requirements and
recommendations in NACE SP0206–
2006 in performing the post assessment
step of the ICDA process. In addition to
the post-assessment requirements and
recommendations in NACE SP0206–
2006, the evaluation and monitoring
process must also include—
(i) Evaluating the effectiveness of
ICDA as an assessment method for
addressing internal corrosion and
determining whether a covered segment
should be reassessed at more frequent
intervals than those specified in
§ 192.939. An operator must carry out
this evaluation within a year of
conducting an ICDA;
(ii) Validation of the flow modeling
calculations by comparison of actual
locations of discovered internal
corrosion with locations predicted by
the model (if the flow model cannot be
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validated, then ICDA is not feasible for
the segment); and
(iii) Continually monitoring each
ICDA region which contains a covered
segment where internal corrosion has
been identified by using techniques
such as coupons or UT sensors or
electronic probes, and by periodically
drawing off liquids at low points and
chemically analyzing the liquids for the
presence of corrosion products. An
operator must base the frequency of the
monitoring and liquid analysis on
results from all integrity assessments
that have been conducted in accordance
with the requirements of this subpart,
and risk factors specific to the ICDA
region. At a minimum, the monitoring
frequency must be two times each
calendar year, but at intervals not
exceeding 71⁄2 months. If an operator
finds any evidence of corrosion
products in the ICDA region, the
operator must take prompt action in
accordance with one of the two
following required actions and
remediate the conditions the operator
finds in accordance with § 192.933.
(A) Conduct excavations of, and
detailed examinations at, locations
downstream from where the electrolyte
might have entered the pipe to
investigate and accurately characterize
the nature, extent, and root cause of the
corrosion, including the monitoring and
mitigation requirements of § 192.478; or
(B) Assess the covered segment using
ILI tools capable of detecting internal
corrosion.
(5) Other requirements—The ICDA
plan must also include the following:
(i) Criteria an operator will apply in
making key decisions (e.g., ICDA
feasibility, definition of ICDA Regions
and Sub-regions, conditions requiring
excavation) in implementing each stage
of the ICDA process;
(ii) Provisions that analysis be carried
out on the entire pipeline in which
covered segments are present, except
that application of the remediation
criteria of § 192.933 may be limited to
covered segments.
■ 43. Section 192.929 is revised to read
as follows:
§ 192.929 What are the requirements for
using direct assessment for stress
corrosion cracking (SCCDA)?
(a) Definition. Stress corrosion
cracking direct assessment (SCCDA) is a
process to assess a covered pipe
segment for the presence of SCC by
systematically gathering and analyzing
excavation data for pipe having similar
operational characteristics and residing
in a similar physical environment.
(b) General requirements. An operator
using direct assessment as an integrity
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assessment method to address stress
corrosion cracking in a covered pipeline
segment must develop and follow an
SCCDA plan that meets all requirements
and recommendations contained in
NACE SP0204–2008 and that
implements all four steps of the SCCDA
process including pre-assessment,
indirect inspection, detailed
examination and post-assessment. As
specified in NACE SP0204–2008,
Section 1.1.7, SCCDA is complementary
with other inspection methods such as
in-line inspection (ILI) or hydrostatic
testing and is not necessarily an
alternative or replacement for these
methods in all instances. In addition,
the plan must provide for—
(1) Data gathering and integration. An
operator’s plan must provide for a
systematic process to collect and
evaluate data for all covered segments to
identify whether the conditions for SCC
are present and to prioritize the covered
segments for assessment in accordance
with NACE SP0204–2008, sections 3
and 4, and table 1. This process must
also include gathering and evaluating
data related to SCC at all sites an
operator excavates during the conduct
of its pipeline operations (both within
and outside covered segments) where
the criteria in NACE SP0204–2008
indicate the potential for SCC. This data
gathering process must be conducted in
accordance with NACE SP0204–2008,
section 5.3, and must include, at
minimum, all data listed in NACE
SP0204–2008, table 2. Further, the
following factors must be analyzed as
part of this evaluation:
(i) The effects of a carbonatebicarbonate environment, including the
implications of any factors that promote
the production of a carbonatebicarbonate environment such as soil
temperature, moisture, the presence or
generation of carbon dioxide, and/or
Cathodic Protection (CP).
(ii) The effects of cyclic loading
conditions on the susceptibility and
propagation of SCC in both high-pH and
near-neutral-pH environments.
(iii) The effects of variations in
applied CP such as overprotection, CP
loss for extended periods, and high
negative potentials.
(iv) The effects of coatings that shield
CP when disbonded from the pipe.
(v) Other factors which affect the
mechanistic properties associated with
SCC including but not limited to
historical and present-day operating
pressures, high tensile residual stresses,
flowing product temperatures, and the
presence of sulfides.
(2) Indirect inspection. In addition to
the requirements and recommendations
of NACE SP0204–2008, section 4, the
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plan’s procedures for indirect
inspection must include provisions for
conducting at least two above ground
surveys using complementary
measurement tools most appropriate for
the pipeline segment based on the data
gathering and integration step.
(3) Direct examination. In addition to
the requirements and recommendations
of NACE SP0204–2008, the plan’s
procedures for direct examination must
provide for conducting a minimum of
three direct examinations within the
SCC segment at locations determined to
be the most likely for SCC to occur.
(4) Remediation and mitigation. If any
indication of SCC is discovered in a
segment, an operator must mitigate the
threat in accordance with one of the
following applicable methods:
(i) Removing the pipe with SCC,
remediating the pipe with a Type B
sleeve, hydrostatic testing in accordance
with (b)(4)(ii), below, or by grinding out
the SCC defect and repairing the pipe.
If grinding is used for repair, the repair
procedure must include: Nondestructive
testing for any remaining cracks or other
defects; measuring remaining wall
thickness; and the remaining strength of
the pipe at the repair location must be
determined using ASME/ANSI B31G or
RSTRENG and must be sufficient to
meet the design requirements of subpart
C of this part. Pipe and material
properties used in remaining strength
calculations must be documented in
reliable, traceable, verifiable, and
complete records. If such records are not
available, pipe and material properties
used in the remaining strength
calculations must be based on
properties determined and documented
in accordance with § 192.607.
(ii) Significant SCC must be mitigated
using a hydrostatic testing program to a
minimum test pressure equal to 105
percent of the specified minimum yield
strength of the pipe for 30 minutes
immediately followed by a pressure test
in accordance with § 192.506, but not
lower than 1.25 times MAOP. The test
pressure for the entire sequence must be
continuously maintained for at least 8
hours, in accordance with § 192.506 and
must be above the minimum test factors
in § 192.619(a)(2)(ii) or 192.620(a)(2)(ii),
but not lower than 1.25 times maximum
allowable operating pressure. Any test
failures due to SCC must be repaired by
replacement of the pipe segment, and
the segment re-tested until the pipe
passes the complete test without
leakage. Pipe segments that have SCC
present, but that pass the pressure test,
may be repaired by grinding in
accordance with paragraph (b)(4)(i) of
this section.
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(5) Post assessment. In addition to the
requirements and recommendations of
NACE SP0204–2008, sections 6.3,
periodic reassessment, and 6.4,
effectiveness of SCCDA, the operator’s
procedures for post assessment must
include development of a reassessment
plan based on the susceptibility of the
operator’s pipe to SCC as well as on the
mechanistic behavior of identified
cracking. Reassessment intervals must
comply with § 192.939. Factors that
must be considered include, but are not
limited to:
(i) Evaluation of discovered crack
clusters during the direct examination
step in accordance with NACE RP0204–
2008, sections 5.3.5.7, 5.4, and 5.5;
(ii) Conditions conducive to creation
of the carbonate-bicarbonate
environment;
(iii) Conditions in the application (or
loss) of CP that can create or exacerbate
SCC;
(iv) Operating temperature and
pressure conditions including operating
stress levels on the pipe;
(v) Cyclic loading conditions;
(vi) Mechanistic conditions that
influence crack initiation and growth
rates;
(vii) The effects of interacting crack
clusters;
(viii) The presence of sulfides; and.
(ix) Disbonded coatings that shield CP
from the pipe.
■ 44. In § 192.933, paragraphs (a)(1), (b),
(d)(1) are revised and paragraphs
(d)(2)(iii) through (vii) are added to read
as follows:
§ 192.933 What actions must be taken to
address integrity issues?
(a) * * *
(1) Temporary pressure reduction. If
an operator is unable to respond within
the time limits for certain conditions
specified in this section, the operator
must temporarily reduce the operating
pressure of the pipeline or take other
action that ensures the safety of the
covered segment. An operator must
determine any temporary reduction in
operating pressure required by this
section using ASME/ANSI B31G
(incorporated by reference, see § 192.7)
or AGA Pipeline Research Council
International, PR–3–805 (R–STRENG)
(incorporated by reference, see § 192.7)
to determine the safe operating pressure
that restores the safety margin
commensurate with the design factor for
the Class Location in which the affected
pipeline is located, or reduce the
operating pressure to a level not
exceeding 80 percent of the operating
pressure at the time the condition was
discovered. Pipe and material properties
used in remaining strength calculations
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must be documented in reliable,
traceable, verifiable, and complete
records. If such records are not
available, pipe and material properties
used in the remaining strength
calculations must be based on
properties determined and documented
in accordance with § 192.607. An
operator must notify PHMSA in
accordance with § 192.949 if it cannot
meet the schedule for evaluation and
remediation required under paragraph
(c) of this section and cannot provide
safety through temporary reduction in
operating pressure or other action. An
operator must also notify a State
pipeline safety authority when either a
covered segment is located in a State
where PHMSA has an interstate agent
agreement, or an intrastate covered
segment is regulated by that State.
*
*
*
*
*
(b) Discovery of condition. Discovery
of a condition occurs when an operator
has adequate information about a
condition to determine that the
condition presents a potential threat to
the integrity of the pipeline. For the
purposes of this section, a condition
that presents a potential threat includes,
but is not limited to, those conditions
that require remediation or monitoring
listed under paragraphs (d)(1) through
(3) of this section. An operator must
promptly, but no later than 180 days
after conducting an integrity
assessment, obtain sufficient
information about a condition to make
that determination, unless the operator
demonstrates that the 180-day period is
impracticable. In cases where a
determination is not made within the
180-day period the operator must notify
OPS, in accordance with § 192.949, and
provide an expected date when
adequate information will become
available.
*
*
*
*
*
(d) * * *
(1) Immediate repair conditions. An
operator’s evaluation and remediation
schedule must follow ASME/ANSI
B31.8S, section 7 in providing for
immediate repair conditions. To
maintain safety, an operator must
temporarily reduce operating pressure
in accordance with paragraph (a) of this
section or shut down the pipeline until
the operator completes the repair of
these conditions. An operator must treat
the following conditions as immediate
repair conditions:
(i) Calculation of the remaining
strength of the pipe shows a predicted
failure pressure less than or equal to 1.1
times the maximum allowable operating
pressure at the location of the anomaly
for any class location. Suitable
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remaining strength calculation methods
include ASME/ANSI B31G
(incorporated by reference, see § 192.7),
PRCI PR–3–805 (R–STRENG)
(incorporated by reference, see § 192.7);
or an alternative method of remaining
strength calculation that will provide an
equally conservative result. Pipe and
material properties used in remaining
strength calculations must be
documented in reliable, traceable,
verifiable, and complete records. If such
records are not available, pipe and
material properties used in the
remaining strength calculations must be
based on properties determined and
documented in accordance with
§ 192.607.
(ii) A dent that has any indication of
metal loss, cracking, or a stress riser.
(iii) An indication or anomaly that in
the judgment of the person designated
by the operator to evaluate the
assessment results requires immediate
action.
(iv) Metal loss greater than 80% of
nominal wall regardless of dimensions.
(v) An indication of metal-loss
affecting a detected longitudinal seam, if
that seam was formed by direct current,
low-frequency, or high frequency
electric resistance welding or by electric
flash welding.
(vi) Any indication of significant
stress corrosion cracking (SCC).
(vii) Any indication of significant
selective seam weld corrosion (SSWC).
(2) * * *.
(iii) A calculation of the remaining
strength of the pipe shows a predicted
failure pressure ratio at the location of
the anomaly less than or equal to 1.25
for Class 1 locations, 1.39 for Class 2
locations, 1.67 for Class 3 locations, and
2.00 for Class 4 locations.
(iv) An area of general corrosion with
a predicted metal loss greater than 50%
of nominal wall.
(v) Predicted metal loss greater than
50% of nominal wall that is located at
a crossing of another pipeline, or is in
an area with widespread circumferential
corrosion, or is in an area that could
affect a girth weld.
(vi) A gouge or groove greater than
12.5% of nominal wall.
(vii) Any indication of crack or cracklike defect other than an immediate
condition.
*
*
*
*
*
■ 45. In § 192.935, paragraphs (a), (b)(2),
and (d)(3) are revised and paragraphs (f)
and (g) are added to read as follows:
§ 192.935 What additional preventive and
mitigative measures must an operator take?
(a) General requirements. An operator
must take additional measures beyond
those already required by part 192 to
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prevent a pipeline failure and to
mitigate the consequences of a pipeline
failure in a high consequence area. Such
additional measures must be based on
the risk analyses required by § 192.917,
and must include, but are not limited to:
Correction of the root causes of past
incidents to prevent recurrence;
establishing and implementing adequate
operations and maintenance processes
that could increase safety; establishing
and deploying adequate resources for
successful execution of preventive and
mitigative measures; installing
automatic shut-off valves or remote
control valves; installing pressure
transmitters on both sides of automatic
shut-off valves and remote control
valves that communicate with the
pipeline control center; installing
computerized monitoring and leak
detection systems; replacing pipe
segments with pipe of heavier wall
thickness or higher strength; conducting
additional right-of-way patrols;
conducting hydrostatic tests in areas
where material has quality issues or lost
records; tests to determine material
mechanical and chemical properties for
unknown properties that are needed to
assure integrity or substantiate MAOP
evaluations including material property
tests from removed pipe that is
representative of the in-service pipeline;
re-coating of damaged, poorly
performing or disbonded coatings;
applying additional depth-of-cover
survey at roads, streams and rivers;
remediating inadequate depth-of-cover;
providing additional training to
personnel on response procedures,
conducting drills with local emergency
responders; and implementing
additional inspection and maintenance
programs.
(b) * * *
(2) Outside force damage. If an
operator determines that outside force
(e.g., earth movement, loading,
longitudinal, or lateral forces, seismicity
of the area, floods, unstable suspension
bridge) is a threat to the integrity of a
covered segment, the operator must take
measures to minimize the consequences
to the covered segment from outside
force damage. These measures include,
but are not limited to, increasing the
frequency of aerial, foot or other
methods of patrols, adding external
protection, reducing external stress,
relocating the line, or geospatial, GIS,
and deformation in-line inspections.
*
*
*
*
*
(d) * * *
(3) Perform semi-annual,
instrumented leak surveys (quarterly for
unprotected pipelines or cathodically
protected pipe where indirect
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assessments, i.e. indirect examination
tool/method such as close interval
survey, alternating current voltage
gradient, direct current voltage gradient,
or equivalent, are impractical).
*
*
*
*
*
(f) Internal corrosion. As an operator
gains information about internal
corrosion, it must enhance its internal
corrosion management program, as
required under subpart I of this part,
with respect to a covered segment to
prevent and minimize the consequences
of a release due to internal corrosion. At
a minimum, as part of this
enhancement, operators must—
(1) Monitor for, and mitigate the
presence of, deleterious gas stream
constituents.
(2) At points where gas with
potentially deleterious contaminants
enters the pipeline, use filter separators
or separators and continuous gas quality
monitoring equipment.
(3) At least once per quarter, use gas
quality monitoring equipment that
includes, but is not limited to, a
moisture analyzer, chromatograph,
carbon dioxide sampling, and hydrogen
sulfide sampling.
(4) Use cleaning pigs and sample
accumulated liquids and solids,
including tests for microbiologically
induced corrosion.
(5) Use inhibitors when corrosive gas
or corrosive liquids are present.
(6) Address potentially corrosive gas
stream constituents as specified in
§ 192.478(a), where the volumes exceed
these amounts over a 24-hour interval in
the pipeline as follows:
(i) Limit carbon dioxide to three
percent by volume;
(ii) Allow no free water and otherwise
limit water to seven pounds per million
cubic feet of gas; and
(iii) Limit hydrogen sulfide to 1.0
grain per hundred cubic feet (16 ppm)
of gas. If the hydrogen sulfide
concentration is greater than 0.5 grain
per hundred cubic feet (8 ppm) of gas,
implement a pigging and inhibitor
injection program to address deleterious
gas stream constituents, including
follow-up sampling and quality testing
of liquids at receipt points.
(7) Review the program at least semiannually based on the gas stream
experience and implement adjustments
to monitor for, and mitigate the
presence of, deleterious gas stream
constituents.
(g) External corrosion. As an operator
gains information about external
corrosion, it must enhance its external
corrosion management program, as
required under subpart I of this part,
with respect to a covered segment to
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prevent and minimize the consequences
of a release due to external corrosion. At
a minimum, as part of this
enhancement, operators must—
(1) Control electrical interference
currents that can adversely affect
cathodic protection as follows:
(i) As frequently as needed (such as
when new or uprated high voltage
alternating current power lines greater
than or equal to 69 kVA or electrical
substations are co-located near the
pipeline), but not to exceed every seven
years, perform the following:
(A) Conduct an interference survey (at
times when voltages are at the highest
values for a time period of at least 24hours) to detect the presence and level
of any electrical current that could
impact external corrosion where
interference is suspected;
(B) Analyze the results of the survey
to identify locations where interference
currents are greater than or equal to 20
Amps per meter squared; and
(C) Take any remedial action needed
within six months after completing the
survey to protect the pipeline segment
from deleterious current. Remedial
action means the implementation of
measures including, but not limited to,
additional grounding along the pipeline
to reduce interference currents. Any
location with interference currents
greater than 50 Amps per meter squared
must be remediated. If any AC
interference between 20 and 50 Amps
per meter squared is not remediated, the
operator must provide and document an
engineering justification.
(2) Confirm the adequacy of external
corrosion control through indirect
assessment as follows:
(i) Periodically (as frequently as
needed but at intervals not to exceed
seven years) assess the adequacy of the
cathodic protection through an indirect
method such as close-interval survey,
and the integrity of the coating using
direct current voltage gradient (DCVG)
or alternating current voltage gradient
(ACVG).
(ii) Remediate any damaged coating
with a voltage drop classified as
moderate or severe (IR drop greater than
35% for DCVG or 50 dBmv for ACVG)
under section 4 of NACE RP0502–2008
(incorporated by reference, see § 192.7).
(iii) Integrate the results of the
indirect assessment required under
paragraph (g)(2)(i) of this section with
the results of the most recent integrity
assessment required by this subpart and
promptly take any needed remedial
actions no later than 6 months after
assessment finding.
(iv) Perform periodic assessments as
follows:
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(A) Conduct periodic close interval
surveys with current interrupted to
confirm voltage drops in association
with integrity assessments under
sections §§ 192.921 and 192.937 of this
subpart.
(B) Locate pipe-to-soil test stations at
half-mile intervals within each covered
segment, ensuring at least one station is
within each high consequence area, if
practicable.
(C) Integrate the results with those of
the baseline and periodic assessments
for integrity done under sections
§§ 192.921 and 192.937 of this subpart.
(3) Control external corrosion through
cathodic protection as follows:
(i) If an annual test station reading
indicates cathodic protection below the
level of protection required in subpart I
of this part, complete assessment and
remedial action, as required in
§ 192.465(f), within 6 months of the
failed reading or notify each PHMSA
pipeline safety regional office where the
pipeline is in service and demonstrate
that the integrity of the pipeline is not
compromised if the repair takes longer
than 6 months. An operator must also
notify a State pipeline safety authority
when the pipeline is located in a State
where PHMSA has an interstate agent
agreement, or an intrastate pipeline is
regulated by that State; and
(ii) Remediate insufficient cathodic
protection levels or areas where
protective current is found to be leaving
the pipeline in accordance with
paragraph (g)(3)(i) of this section,
including use of indirect assessments or
direct examination of the coating in
areas of low CP readings unless the
reason for the failed reading is
determined to be a short to an adjacent
foreign structure, rectifier connection or
power input problem that can be
remediated and restoration of adequate
cathodic protection can be verified. The
operator must confirm restoration of
adequate corrosion control by a close
interval survey on both sides of the
affected test stations to the adjacent test
stations.
■ 46. In § 192.937, paragraphs (b) and
(c) are revised to read as follows:
§ 192.937 What is a continual process of
evaluation and assessment to maintain a
pipeline’s integrity?
*
*
*
*
*
(b) Evaluation. An operator must
conduct a periodic evaluation as
frequently as needed to assure the
integrity of each covered segment. The
periodic evaluation must be based on a
data integration and risk assessment of
the entire pipeline as specified in
§ 192.917, which incorporates an
analysis of updated pipeline design,
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construction, operation, maintenance,
and integrity information. For plastic
transmission pipelines, the periodic
evaluation is based on the threat
analysis specified in § 192.917(d). For
all other transmission pipelines, the
evaluation must consider the past and
present integrity assessment results,
data integration and risk assessment
information (§ 192.917), and decisions
about remediation (§ 192.933). The
evaluation must identify the threats
specific to each covered segment,
including interacting threats and the
risk represented by these threats, and
identify additional preventive and
mitigative measures (§ 192.935) to avert
or reduce risks.
(c) Assessment methods. An operator
must assess the integrity of the line pipe
in each covered segment by applying
one or more of the following methods
for each threat to which the covered
segment is susceptible. An operator
must select the method or methods best
suited to address the threats identified
to the covered segment (See § 192.917).
An operator may use an integrity
assessment to meet the requirements of
this section if the pipeline segment
assessment is conducted in accordance
with the integrity assessment
requirements of § 192.624(c) for
establishing MAOP.
(1) Internal inspection tool or tools
capable of detecting corrosion,
deformation and mechanical damage
(including dents, gouges and grooves),
material cracking and crack-like defects
(including stress corrosion cracking,
selective seam weld corrosion,
environmentally assisted cracking, and
girth weld cracks), hard spots, and any
other threats to which the covered
segment is susceptible. When
performing an assessment using an inline inspection tool, an operator must
comply with § 192.493. A person
qualified by knowledge, training, and
experience must analyze the data
obtained from an assessment performed
under paragraph (b) of this section to
determine if a condition could adversely
affect the safe operation of the pipeline.
In addition, an operator must explicitly
consider uncertainties in reported
results (including, but not limited to,
tool tolerance, detection threshold,
probability of detection, probability of
identification, sizing accuracy,
conservative anomaly interaction
criteria, location accuracy, anomaly
findings, and unity chart plots or
equivalent for determining uncertainties
and verifying tool performance) in
identifying and characterizing
anomalies.
(2) Pressure test conducted in
accordance with subpart J of this part.
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An operator must use the test pressures
specified in table 3 of section 5 of
ASME/ANSI B31.8S to justify an
extended reassessment interval in
accordance with § 192.939. The use of
pressure testing is appropriate for time
dependent threats such as internal
corrosion, external corrosion, and other
environmentally assisted corrosion
mechanisms and for manufacturing and
related defect threats, including
defective pipe and pipe seams.
(3) ‘‘Spike’’ hydrostatic pressure test
in accordance with § 192.506. The use
of spike hydrostatic pressure testing is
appropriate for threats such as stress
corrosion cracking, selective seam weld
corrosion, manufacturing and related
defects, including defective pipe and
pipe seams, and other forms of defect or
damage involving cracks or crack-like
defects.
(4) Excavation and in situ direct
examination by means of visual
examination, direct measurement, and
recorded non-destructive examination
results and data needed to assess all
threats, including but not limited to,
ultrasonic testing (UT), radiography,
and magnetic particle inspection (MPI).
An operator must explicitly consider
uncertainties in in situ direct
examination results (including, but not
limited to, tool tolerance, detection
threshold, probability of detection,
probability of identification, sizing
accuracy, and usage unity chart plots or
equivalent for determining uncertainties
and verifying performance on the type
defects being evaluated) in identifying
and characterizing anomalies.
(5) Guided Wave Ultrasonic Testing
(GWUT) conducted as described in
Appendix F;
(6) Direct assessment to address
threats of external corrosion, internal
corrosion, and stress corrosion cracking.
Use of direct assessment is allowed only
if the line is not capable of inspection
by internal inspection tools and is not
practical to assess using the methods
specified in paragraphs (c)(1) through
(5) of this section. An operator must
conduct the direct assessment in
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Code section
accordance with the requirements listed
in § 192.923 and with the applicable
requirements specified in § 192.925,
192.927, or 192.929;
(7) Other technology that an operator
demonstrates can provide an equivalent
understanding of the condition of the
line pipe. An operator choosing this
option must notify the Office of Pipeline
Safety (OPS) 180 days before conducting
the assessment, in accordance with
§ 192.949 and receive a ‘‘no objection
letter’’ from the Associate Administrator
of Pipeline Safety. An operator must
also notify the appropriate State or local
pipeline safety authority when a
covered segment is located in a State
where OPS has an interstate agent
agreement, or an intrastate covered
segment is regulated by that State.
(8) Confirmatory direct assessment
when used on a covered segment that is
scheduled for reassessment at a period
longer than seven years. An operator
using this reassessment method must
comply with § 192.931.
■ 47. In § 192.939, the introductory text
of paragraph (a) is revised to read as
follows:
§ 192.939 What are the required
reassessment intervals?
*
*
*
*
*
(a) Pipelines operating at or above
30% SMYS. An operator must establish
a reassessment interval for each covered
segment operating at or above 30%
SMYS in accordance with the
requirements of this section. The
maximum reassessment interval by an
allowable reassessment method is seven
calendar years. Operators may request a
six month extension of the sevencalendar year reassessment interval if
the operator submits written notice to
OPS, in accordance with § 192.949, with
sufficient justification of the need for
the extension. If an operator establishes
a reassessment interval that is greater
than seven calendar years, the operator
must, within the seven-calendar year
period, conduct a confirmatory direct
assessment on the covered segment, and
then conduct the follow-up
reassessment at the interval the operator
has established. A reassessment carried
out using confirmatory direct
assessment must be done in accordance
with § 192.931. The table that follows
this section sets forth the maximum
allowed reassessment intervals.
*
*
*
*
*
■ 48. In § 192.941, paragraphs (b)(1) and
the introductory text to (b)(2) are revised
to read as follows:
§ 192.941 What is a low stress
reassessment?
*
*
*
*
*
(b) * * *
(1) Cathodically protected pipe. To
address the threat of external corrosion
on cathodically protected pipe in a
covered segment, an operator must
perform an indirect assessment (i.e.
indirect examination tool/method such
as close interval survey, alternating
current voltage gradient, direct current
voltage gradient, or equivalent) at least
every seven years on the covered
segment. An operator must use the
results of each indirect assessment as
part of an overall evaluation of the
cathodic protection and corrosion threat
for the covered segment. This evaluation
must consider, at minimum, the leak
repair and inspection records, corrosion
monitoring records, exposed pipe
inspection records, and the pipeline
environment.
(2) Unprotected pipe or cathodically
protected pipe where indirect
assessments are impractical. If an
indirect assessment is impractical on
the covered segment an operator must—
*
*
*
*
*
■ 49. Appendix A to part 192 is revised
to read as follows:
Appendix A to Part 192—Records
Retention Schedule for Transmission
Pipelines
Appendix A summarizes the part 192
records retention requirements. As required
by § 192.13(e), records must be readily
retrievable and must be reliable, traceable,
verifiable, and complete.
Summary of records requirement
(Note: referenced code section specifies
requirements. This summary provided for
convenience only.)
Section title
Retention time
Subpart A—General
§ 192.5(d) .................
Class locations .....................................
§ 192.13(e) ...............
What general requirements apply to
pipelines regulated under this part?.
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Records that demonstrate how an operator determined class locations and the actual class locations.
Records that demonstrate compliance with this
part. At a minimum, operators must prepare and
maintain the records specified in appendix A to
part 192.
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Life of pipeline.
As specified in this appendix.
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Summary of records requirement
(Note: referenced code section specifies
requirements. This summary provided for
convenience only.)
Code section
Section title
§ 192.14(b) ...............
Conversion to service subject to this
part.
§ 192.16(d) ...............
Customer notification ...........................
Records of investigations, tests, repairs, replacements, and alterations made under the requirements of § 192.14(a).
Records of a copy of the notice currently in use
and evidence that notices have been sent to customers.
Retention time
Life of pipeline.
3 years.
Subpart B—Materials
§ 192.67 ...................
Records: Materials and pipe ................
Records for steel pipe manufacturing tests, inspections, and attributes.
Life of pipeline.
Subpart C—Pipe Design
§ 192.112 .................
§ 192.127 .................
Additional design requirements for
steel pipe using alternative maximum allowable operating pressure.
Records: Pipe Design for External
Loads and Internal Pressures.
Records for alternative MAOP demonstrating compliance with this section.
Life of pipeline.
Design records for external loads and internal pressure.
Life of pipeline.
Subpart D—Design of Pipeline Components
§ 192.144 .................
Qualifying metallic components ...........
§ 192.150 .................
Passage of internal inspection devices
§ 192.153 .................
§ 192.205 .................
Components fabricated by welding .....
Records: Pipeline components ............
Records indicating manufacturer and pressure ratings of metallic components.
Records of each new transmission line replacement
of pipe, valves, fittings, or other line component
showing that the replacement is constructed to
accommodate internal inspection devices as required by § 192.150.
Records of strength tests ..........................................
Records documenting the manufacturing standard,
tests, and pressure rating to which valves,
flanges, fittings, branch connections, extruded
outlets, anchor forgings, tap connections, and
other components were manufactured and tested
in accordance with this subpart.
Life of pipeline.
Life of pipeline.
Life of pipeline.
Life of pipeline.
Subpart E—Welding of Steel in Pipelines
§ 192.225(b) .............
Welding procedures .............................
§ 192.227(c) .............
Qualification of welders and welding
operators.
Nondestructive testing .........................
§ 192.243(f) ..............
Records of welding procedures, including results of
qualifying procedure tests.
Records demonstrating welder qualification .............
Records showing by milepost, engineering station,
or by geographic feature, the number of girth
welds made, the number nondestructively tested,
the number rejected, and the disposition of the
rejects.
Life of pipeline.
Life of pipeline.
Life of pipeline.
Subpart F—Joining of Materials Other Than by Welding
§ 192.283 .................
§ 192.285(e) .............
Plastic pipe: Qualifying joining procedures.
Plastic pipe: Qualifying persons to
make joints.
Records of joining procedures, including results of
qualifying procedure tests.
Records demonstrating plastic pipe joining qualifications.
Life of pipeline.
Life of pipeline.
Subpart G—General Construction Requirements for Transmission Lines and Mains
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§ 192.303 .................
§ 192.305 .................
§ 192.307 .................
§ 192.319(d) .............
§ 192.328 .................
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Compliance with specifications or
standards.
Inspection: General ..............................
Inspection of materials .........................
Installation of pipe in a ditch ................
Additional construction requirements
for steel pipe using alternative maximum allowable operating pressure.
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Records of written specifications or standards that
apply to each transmission line or main.
Transmission line or main inspections .....................
Pipe and component materials inspections ..............
Records documenting the coating assessment findings and repairs.
Records for alternative MAOP demonstrating compliance with this section including: quality assurance, girth weld non-destructive examinations,
depth of cover, initial strength testing (pressure
tests and root cause analysis of failed pipe), and
impacts of interference currents.
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Life of pipeline.
Life of pipeline.
Life of pipeline.
Life of pipeline.
Life of pipeline.
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Federal Register / Vol. 81, No. 68 / Friday, April 8, 2016 / Proposed Rules
Code section
Summary of records requirement
(Note: referenced code section specifies
requirements. This summary provided for
convenience only.)
Section title
Retention time
Subpart H—Customer Meters, Service Regulators, and Service Lines
§ 192.383 .................
Excess flow valve installation ..............
Number of excess flow valves installed, as reported
as part of annual report.
Life of pipeline.
Subpart I—Requirements for Corrosion Control
§ 192.452(a) .............
§ 192.459 .................
How does this subpart apply to converted pipelines and regulated onshore gathering lines?.
Exposed buried pipe inspection ...........
§ 192.461 .................
External corrosion control: Protective
coating.
§ 192.465(a) .............
§ 192.465(b) .............
External corrosion control: Monitoring
External corrosion control: Monitoring—rectifiers.
External corrosion control: Monitoring—stray
current/interference
mitigation and critical interference
bonds.
External corrosion control: Monitoring—active corrosion zones.
External corrosion control: Electrical
isolation.
External corrosion control: Interference
currents.
Internal pipe inspection ........................
§ 192.465(c) .............
§ 192.465(e) .............
§ 192.467(d) .............
§ 192.473 .................
§ 192.475 .................
§ 192.476(d) .............
§ 192.477 .................
§ 192.478 .................
§ 192.478(b)(3) ........
Internal corrosion control: Design and
construction of transmission line.
Coupons or other means for monitoring internal corrosion.
Internal corrosion control: Onshore
transmission monitoring and mitigation.
Gas and Liquid Samples .....................
Atmospheric corrosion control: Monitoring.
§ 192.485(c) .............
Remedial
lines.
§ 192.491(a) and (b)
Corrosion control records ....................
§ 192.491(c) .............
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§ 192.481(a) .............
Corrosion control records ....................
measures:
Transmission
Records demonstrating compliance by the applicable deadlines.
Life of pipeline.
Records of examinations for evidence of external
corrosion whenever any portion of a buried pipeline is exposed.
Records of protective coating type, coating installation and procedures, surveys, and remediation of
coating defects.
Records of pipe to soil measurements .....................
Records of rectifier inspections ................................
Life of pipeline.
Records of inspections of each reverse current
switch, each diode, and each interference bond
whose failure would jeopardize structure protection.
Records of re-evaluation of cathodically unprotected pipelines.
Records of inspection and electrical tests made to
assure that electrical isolation is adequate.
Records of surveys, analysis, and remediation of
interference currents.
Records demonstrating whenever any pipe is removed from a pipeline for any reason, the internal surface was inspected for evidence of corrosion.
Records demonstrating compliance with this section
Life of pipeline.
Life of pipeline.
5 years.
5 years.
Life of pipeline.
Life of pipeline.
Life of pipeline.
Life of pipeline.
Life of pipeline.
Records demonstrating the effectiveness of each
coupon or other means of monitoring procedures
used to minimize internal corrosion.
Records demonstrating compliance with this section
for internal monitoring and mitigation program.
Life of pipeline.
Records showing evaluation twice each calendar
year of gas stream and liquid quality samples.
Records of inspection of each pipeline or portion of
pipeline that is exposed to the atmosphere for
evidence of atmospheric corrosion.
Pipe and material properties used in remaining
strength calculations and remaining strength calculations must be documented in reliable, traceable, verifiable, and complete records.
Records or maps showing the location of cathodically protected piping, cathodic protection facilities, galvanic anodes, and neighboring structures
bonded to the cathodic protection system.
Records of each test, survey, or inspection required
by subpart I in sufficient detail to demonstrate the
adequacy of corrosion control measures or that a
corrosive condition does not exist.
Records related to §§ 192.465(a) and (e) and
192.475(b) must be retained for as long as the
pipeline remains in service.
Life of pipeline.
Life of pipeline.
5 years.
Life of pipeline.
Life of pipeline.
5 years.
Life of pipeline.
Subpart J—Test Requirements
§ 192.517(a) .............
Records ................................................
§ 192.517(b) .............
Records ................................................
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Records of each test performed under §§ 192.505,
192.506, and 192.507.
Records of each test required by §§ 192.509,
192.511, and 192.513.
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Life of pipeline.
5 years.
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Code section
Summary of records requirement
(Note: referenced code section specifies
requirements. This summary provided for
convenience only.)
Section title
Retention time
Subpart K—Uprating
§ 192.553(b) .............
General requirements ..........................
Records of each investigation required by subpart
K, of all work performed, and of each pressure
test conducted, in connection with uprating of a
segment of pipeline.
Life of pipeline.
Subpart L—Operations
§ 192.603(b) .............
General provisions ...............................
§ 192.605 .................
Procedural manual for operations,
maintenance, and emergencies.
Procedural manual for operations,
maintenance, and emergencies.
Procedural manual for operations,
maintenance, and emergencies.
§ 192.605 .................
§ 192.605 .................
§ 192.605(b)(12) ......
Procedural manual for operations,
maintenance, and emergencies.
§ 192.605(c) .............
Procedural manual for operations,
maintenance, and emergencies.
Verification of Pipeline Material: Onshore steel transmission pipelines.
§ 192.607(c) .............
§ 192.609 .................
§ 192.613(a) .............
§ 192.613(b) .............
§ 192.613(c)(1) .........
Change in class location: Required
study.
Change in class location: Confirmation
or revision of maximum allowable
operating pressure.
Underwater inspection and reburial of
pipelines in the Gulf of Mexico and
its inlets.
Continuing surveillance ........................
Continuing surveillance ........................
Continuing surveillance ........................
§ 192.613(c)(3) .........
§ 192.614 .................
Continuing surveillance ........................
Damage prevention program ...............
§ 192.614 .................
Damage prevention program ...............
§ 192.615 .................
§ 192.615 .................
Emergency plans .................................
Emergency plans .................................
§ 192.616 .................
§ 192.617 .................
Public awareness .................................
Investigation of failures ........................
§ 192.619 .................
Maximum allowable operating pressure: Steel or plastic pipelines.
§ 192.620(c)(7) .........
Alternative maximum allowable operating pressure for certain steel pipelines.
Maximum allowable operating pressure verification: Onshore steel
transmission pipelines.
§ 192.611 .................
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§ 192.612 .................
§ 192.624(f) ..............
§ 192.625 .................
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Records necessary to administer the procedures
established under § 192.605 for operations, maintenance, and emergencies including class location and changes in §§ 192.5, 192.609, and
192.611.
Records for O&M Manual—review and update once
per calendar year, not to exceed 15 months.
Records for Emergency Plan—review and update
once per calendar year, not to exceed 15 months.
Records for Operator Qualification Plan—review
and update once per calendar year, not to exceed 15 months.
Records for Control Room Management (CRM)—
review and update once per calendar year, not to
exceed 15 months.
For gas transmission operators, a record of the abnormal operations.
Traceable, verifiable, and complete records that
demonstrate and authenticate data and information regarding the properties outlined in
§ 192.607(c)(1) through (4).
Records for class location studies required by this
section.
Records for revisions of maximum allowable operating pressure due to class location changes to
confirm to § 192.611.
Records of Underwater inspection in Gulf of Mexico—periodic, as indicated in operators O&M
Manual.
Records of continuing surveillance findings .............
Records of remedial actions .....................................
Records of inspections performed following extreme
events.
Records of remedial actions .....................................
Damage Prevention/One Call records ......................
Records of Damage Prevention meetings with
Emergency Responder/Public Officials.
Records of training ....................................................
Records of each review that procedures were effectively followed after each emergency.
Records showing Public Education Activities ...........
Procedures for analyzing accidents and failures as
described in § 192.617 to determine the causes
of the failure and minimizing the possibility of a
recurrence. Records of accident/failure reports.
Traceable, verifiable, and complete records that
demonstrate and authenticate data and information regarding the maximum allowable operating
pressures outlined in § 192.619(a) through (d).
Records demonstrating compliance with paragraphs
§ 192.620(b), (c)(6), and (d).
Reliable, traceable, verifiable, and complete records
of the investigations, tests, analyses, assessments, repairs, replacements, alterations, and
other actions made under the requirements of
§ 192.624.
Records of Odorometer Readings—periodic, as indicated in operators O&M Manual.
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08APP2
Life of pipeline.
5 years.
5 years.
5 years.
5 years.
Life of pipeline.
Life of pipeline.
Life of pipeline.
Life of pipeline.
5 years.
5 years.
Life of pipeline.
5 years.
Life of pipeline.
5 years (or as indicated
by state one call,
whichever is longer).
5 years.
5 years.
5 years.
5 years.
Life of pipeline.
Life of pipeline.
Life of pipeline.
Life of pipeline.
5 years.
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Federal Register / Vol. 81, No. 68 / Friday, April 8, 2016 / Proposed Rules
Summary of records requirement
(Note: referenced code section specifies
requirements. This summary provided for
convenience only.)
Code section
Section title
§ 192.631(a) .............
Control room management ..................
§ 192.631(j) ..............
Control room management ..................
Records of control room management procedures
that implement the requirements of this section.
(1) Records that demonstrate compliance with the
requirements of this section; and.
(2) Documentation to demonstrate that any deviation from the procedures required by this section was necessary for the safe operation of a
pipeline facility.
Retention time
Life of pipeline.
1 year, or the last 2 periodic tests or validations, whichever is
longer.
Subpart M—Maintenance
§ 192.703(c) .............
§ 192.705 .................
§ 192.706 .................
§ 192.709(a) .............
§ 192.709(b) and (c)
§ 192.710 .................
§ 192.713(c) .............
§ 192.713(d) .............
§ 192.731 .................
§ 192.736 .................
§ 192.739 .................
§ 192.743 .................
§ 192.745 .................
§ 192.749 .................
General ................................................
Transmission lines: Patrolling ..............
Records of hazardous and non-hazardous leaks .....
Records of periodic right-of-way patrols—frequency
dependent on class location.
Transmission lines: Leakage surveys .. Records of periodic leakage surveys—frequency
dependent on class location.
Transmission lines: Record keeping .... Records for the date, location, and description of
each repair made to pipe (including pipe-to-pipe
connections).
Transmission lines: Record keeping .... (b) Records of the date, location, and description of
each repair made to parts of the pipeline system
other than pipe must be retained for at least 5
years.
(c) A record of each patrol, survey, inspection, test,
and repair required by subparts L and M of this
part must be retained for at least 5 years or until
the next patrol, survey, inspection, or test is completed, whichever is longer.*
Pipeline assessments .......................... Records of pipeline assessments in class 3 or class
4 locations and moderate consequence area as
defined in § 192.3 if the pipe segment can accommodate inspection by means of instrumented
inline inspection tools (i.e., ‘‘smart pigs’’).
Transmission lines: Permanent field Records of each repair made to transmission lines
repair of imperfections and damages.
must be documented.
Transmission lines: Permanent field Repair and remediation schedules, pressure reducrepair of imperfections and damages.
tions and remaining strength calculations must be
documented.
Compressor stations: Inspection and Records of inspections and tests of pressure relievtesting of relief devices.
ing and other remote control shutdown devices.
Compressor stations: Gas detection ... Records of inspections and tests of gas detection
systems—periodic, as indicated in operators
O&M Manual.
Pressure limiting and regulating sta- Records of inspections and tests of pressure relief
tions: Inspection and testing.
devices and pressure regulating stations and
equipment.
Pressure limiting and regulating sta- Records of capacity calculations or verifications for
tions: Capacity of relief devices.
pressure relief devices (except rupture discs).
Valve maintenance: Transmission lines Records of inspections of emergency valves ...........
Vault maintenance ............................... Records of inspections of vaults containing pressure regulating or pressure limiting equipment.
Life of pipeline.
5 years.
5 years.
Life of pipeline.
5 years.*
Life of pipeline.
Life of pipeline.
Life of pipeline.
5 years.
5 years.
5 years.
5 years.
5 years.
5 years.
Subpart N—Qualification of Pipeline Personnel
mstockstill on DSK4VPTVN1PROD with PROPOSALS2
§ 192.807 .................
Operator qualification recordkeeping ...
Records that demonstrate compliance with subpart
N of this part Records supporting an individual’s
current qualification shall be maintained while the
individual is performing the covered task.**
Records of prior qualification and records of individuals no longer performing covered tasks shall be
retained for a period of five years..
5 years.**
Subpart O—Gas Transmission Integrity Management
§ 192.947 .................
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Integrity management ..........................
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Records that demonstrate compliance with all of
the requirements of subpart O of this part.
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Life of pipeline.
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Federal Register / Vol. 81, No. 68 / Friday, April 8, 2016 / Proposed Rules
50. Appendix D to part 192 is revised
to read as follows:
■
Appendix D to Part 192—Criteria for
Cathodic Protection and Determination
of Measurements
I. Criteria for cathodic protection—
A. Steel, cast iron, and ductile iron
structures.
(1) A negative (cathodic) voltage across the
structure electrolyte boundary of at least 0.85
volt, with reference to a saturated coppercopper sulfate reference electrode, often
referred to as a half cell. Determination of
this voltage must be made in accordance with
sections II and IV of this appendix.
(2) A minimum negative (cathodic)
polarization voltage shift of 100 millivolts.
This polarization voltage shift must be
determined in accordance with sections III
and IV of this appendix.
B. Aluminum structures.
(1) Except as provided in paragraphs B(2)
and (3) of this section, a minimum negative
(cathodic) polarization voltage shift of 100
millivolts. This polarization voltage shift
must be determined in accordance with
sections III and IV of this appendix.
(2) Notwithstanding the minimum criteria
in paragraph B(1) of this section, if aluminum
is cathodically protected at voltages in excess
of 1.20 volts as measured with reference to
a copper-copper sulfate reference electrode,
in accordance with section II of this
appendix, the aluminum may suffer
corrosion resulting from the build-up of
alkali on the metal surface. A voltage in
excess of 1.20 volts may not be used unless
previous test results indicate no appreciable
corrosion will occur in the particular
environment.
(3) Since aluminum may suffer from
corrosion under high pH conditions, and
since application of cathodic protection
tends to increase the pH at the metal surface,
careful investigation or testing must be made
before applying cathodic protection to stop
pitting attack on aluminum structures in
environments with a natural pH in excess of
8.
C. Copper structures. A minimum negative
(cathodic) polarization voltage shift of 100
millivolts. This polarization voltage shift
must be determined in accordance with
sections III and IV of this appendix.
D. Metals of different anodic potentials. A
negative (cathodic) voltage, measured in
accordance with section IV of this appendix,
equal to that required for the most anodic
metal in the system must be maintained. If
amphoteric structures are involved that could
be damaged by high alkalinity covered by
paragraphs B(2) and (3) of this section, they
must be electrically isolated with insulating
flanges, or the equivalent.
II. Interpretation of voltage measurement.
Structure-to-electrolyte potential
measurements must be made utilizing
measurement techniques that will minimize
voltage (IR) drops other than those across the
structure electrolyte boundary. All voltage
(IR) drops other than those across the
structure electrolyte boundary will be
differentiated, such that the resulting
measurement accurately reflects the
structure-to-electrolyte potential.
III. Determination of polarization voltage
shift. The polarization voltage shift must be
determined by interrupting the protective
current and measuring the polarization
decay. When the current is initially
interrupted, an immediate voltage shift
occurs often referred to as an instant off
potential. The voltage reading after the
immediate shift must be used as the base
reading from which to measure polarization
decay in paragraphs A(2), B(1), and C of
section I of this appendix.
IV. Reference electrodes (half cells).
A. Except as provided in paragraphs B and
C of this section, negative (cathodic) voltage
must be measured between the structure
surface and a saturated copper-copper sulfate
reference electrode contacting the electrolyte.
B. Other standard reference electrodes may
be substituted for the saturated coppercopper sulfate electrode. Two commonly
used reference electrodes are listed below
along with their voltage equivalent to ¥0.85
volt as referred to a saturated copper-copper
sulfate reference electrode:
(1) Saturated KCL calomel half cell:¥0.78
volt.
(2) Silver-silver chloride reference
electrode used in sea water: ¥0.80 volt.
C. In addition to the standard reference
electrode, an alternate metallic material or
structure may be used in place of the
saturated copper-copper sulfate reference
electrode if its potential stability is assured
and if its voltage equivalent referred to a
saturated copper-copper sulfate reference
electrode is established.
51. In appendix E, Tables E.II.1 and
E.II.3 are revised to read as follows:
■
Appendix E to Part 192—Guidance on
Determining High Consequence Areas
and on Carrying out Requirements in
the Integrity Management Rule
*
*
*
*
*
II. Guidance on Assessment Methods and
Additional Preventive and Mitigative
Measures for Transmission Pipelines
*
*
*
*
*
TABLE E.II.1—PREVENTIVE AND MITIGATIVE MEASURES FOR TRANSMISSION PIPELINES OPERATING BELOW 30% SMYS
NOT IN AN HCA BUT IN A CLASS 3 OR CLASS 4 LOCATION
Existing part 192 requirements
(Column 4)
Additional (to part 192 requirements)
preventive and mitigative measures
(Column 2)
Primary
(Column 3)
Secondary
External Corrosion ...............
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(Column 1) Threat
455—(Gen. Post 1971),
457—(Gen. Pre—1971).
459—(Examination), 461—
(Ext. coating).
463—(CP), 465—(Monitoring).
603—(Gen Operation) .......
For Cathodically Protected Transmission Pipeline:
613—(Surveillance) ...........
• Perform semi-annual leak surveys.
............................................
For Unprotected Transmission Pipelines or for Cathodically Protected Pipe where indirect assessments (i.e., indirect examination tool/method such
as close interval survey, alternating current voltage
gradient, direct current voltage gradient, or equivalent) are impractical:
............................................
53(a)—(Materials) ..............
• Perform quarterly leak surveys.
Perform semi-annual leak surveys.
Internal Corrosion ................
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18:57 Apr 07, 2016
467—(Elect isolation),
469—Test stations).
471—(Test leads), 473—
(Interference).
479—(Atmospheric), 481—
(Atmospheric).
485—(Remedial), 705—
(Patrol).
706— (Leak survey),
711—(Repair—gen.).
717—(Repair—perm.) .......
475—(Gen IC), 477—(IC
monitoring).
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20854
Federal Register / Vol. 81, No. 68 / Friday, April 8, 2016 / Proposed Rules
TABLE E.II.1—PREVENTIVE AND MITIGATIVE MEASURES FOR TRANSMISSION PIPELINES OPERATING BELOW 30% SMYS
NOT IN AN HCA BUT IN A CLASS 3 OR CLASS 4 LOCATION—Continued
Existing part 192 requirements
(Column 1) Threat
(Column 2)
Primary
(Column 4)
Additional (to part 192 requirements)
preventive and mitigative measures
(Column 3)
Secondary
603—(Gen Oper’n).
614—(Dam. Prevent),
616—(Public education).
705—(Patrol), 707—(Line
markers).
3rd Party Damage ...............
485—(Remedial), 705—
(Patrol).
706—(Leak survey), 711
(Repair—gen.).
717—(Repair—perm.).
103—(Gen. Design), 111—
(Design factor).
317—(Hazard prot), 327—
(Cover).
............................................
613—(Surveillance).
............................................
• Participation in state one-call system.
615—(Emerg. Plan) ...........
• Use of qualified operator employees and contractors
to perform marking and locating of buried structures
and in direct supervision of excavation work.
AND
• Either monitoring of excavations near operator’s
transmission pipelines in class 3 and 4 locations.
Any indications of unreported construction activity
would require a follow up investigation to determine
if mechanical damage occurred.
711—(Repair—gen.),
717—(Repair—perm.).
*
*
*
*
*
TABLE E.II.3—PREVENTIVE AND MITIGATIVE MEASURES ADDRESSING TIME DEPENDENT AND INDEPENDENT THREATS FOR
TRANSMISSION PIPELINES THAT OPERATE BELOW 30% SMYS, IN HCAS
Existing part 192 requirements
Additional (to part 192 requirements)
preventive and mitigative measures
Threat
Primary
mstockstill on DSK4VPTVN1PROD with PROPOSALS2
603—(Gen. Operation).
613—(Surveillance).
........................................
For Unprotected Transmission. Pipelines or for Cathodically
Protected Pipe where Indirect Assessments are Impracticable
........................................
........................................
• Conduct quarterly leak surveys AND
• Every 11⁄2 years, determine areas of active corrosion by
evaluation of leak repair and inspection records, corrosion
monitoring records, exposed pipe inspection records, and
the pipeline environment.
485—(Remedial).
705—(Patrol).
706—(Leak survey).
711—(Repair—gen.).
717—(Repair—perm.).
475—(Gen. IC) ..............
........................................
477—(IC monitoring) .....
........................................
485—(Remedial) ...........
53(a)—(Materials) ..........
• Obtain and review gas analysis data each calendar year for
corrosive agents from transmission pipelines in HCA,
• Periodic testing of fluid removed from pipelines. Specifically, once each year from each storage field that may affect transmission pipelines in HCA, AND
• At least every 7 years, integrate data obtained with applicable internal corrosion leak records, incident reports, safety
related condition reports, repair records, patrol records, exposed pipe reports, and test records.
705—(Patrol) .................
706—(Leak survey) .......
711—(Repair—gen.).
VerDate Sep<11>2014
........................................
........................................
473—(Interference).
479—(Atmospheric) .......
481—(Atmospheric) .......
Internal Corrosion ............
455—(Gen. Post 1971)
457—(Gen. Pre-1971) ...
459—(Examination).
461—(Ext. coating).
463—(CP).
465—(Monitoring) ..........
467—(Elect isolation) ....
469—(Test stations).
471—(Test leads) ..........
External Corrosion ...........
Secondary
603—(Gen. Oper.).
613—(Surveil.).
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For Cathodically Protected Transmission Pipelines
• Perform an indirect assessment (i.e. indirect examination
tool/method such as close interval survey, alternating current voltage gradient, direct current voltage gradient, or
equivalent) at least every 7 years. Results are to be utilized
as part of an overall evaluation of the CP system and corrosion threat for the covered segment. Evaluation shall include consideration of leak repair and inspection records,
corrosion monitoring records, exposed pipe inspection
records, and the pipeline environment.
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20855
TABLE E.II.3—PREVENTIVE AND MITIGATIVE MEASURES ADDRESSING TIME DEPENDENT AND INDEPENDENT THREATS FOR
TRANSMISSION PIPELINES THAT OPERATE BELOW 30% SMYS, IN HCAS—Continued
Existing part 192 requirements
Additional (to part 192 requirements)
preventive and mitigative measures
Threat
Primary
717—(Repair—perm.).
103—(Gen. Design) ......
111—(Design factor) .....
615— (Emerg. Plan) .....
........................................
317—(Hazard prot.) .......
3rd Party Damage ...........
Secondary
........................................
• Participation in state one-call system,
• Use of qualified operator employees and contractors to perform marking and locating of buried structures and in direct
supervision of excavation work, AND
• Either monitoring of excavations near operator’s transmission pipelines, or bi-monthly patrol of transmission pipelines in HCAs or class 3 and 4 locations. Any indications of
unreported construction activity would require a follow up
investigation to determine if mechanical damage occurred.
327—(Cover).
614—(Dam. Prevent).
616—(Public educat.).
705—(Patrol).
707—(Line markers).
711—(Repair—gen.).
717—(Repair—perm.).
52. Appendix F to part 192 is added
to read as follows:
■
mstockstill on DSK4VPTVN1PROD with PROPOSALS2
Appendix F to Part 192—Criteria for
Conducting Integrity Assessments Using
Guided Wave Ultrasonic Testing
(GWUT)
This appendix defines criteria which must
be properly implemented for use of Guided
Wave Ultrasonic Testing (GWUT) as an
integrity assessment method. Any
application of GWUT that does not conform
to these criteria is considered ‘‘other
technology’’ as described by §§ 192.710(c)(7),
192.921(a)(7), and 192.937(c)(7), for which
OPS must be notified 180 days prior to use
in accordance with § 192.921(a)(7) or
192.937(c)(7). GWUT in the ‘‘Go-No Go’’
mode means that all indications (wall loss
anomalies) above the testing threshold (a
maximum of 5% of cross sectional area (CSA)
sensitivity) be directly examined, in-line tool
inspected, pressure tested or replaced prior
to completing the integrity assessment on the
cased carrier pipe.
I. Equipment and software: Generation.
The equipment and the computer software
used are critical to the success of the
inspection. Guided Ultrasonics LTD (GUL)
Wavemaker G3 or G4 with software version
3 or higher, or equipment and software with
equivalent capabilities and sensitivities, must
be used.
II. Inspection range. The inspection range
and sensitivity are set by the signal to noise
(S/N) ratio but must still keep the maximum
threshold sensitivity at 5% cross sectional
area (CSA). A signal that has an amplitude
that is at least twice the noise level can be
reliably interpreted. The greater the S/N ratio
the easier it is to identify and interpret
signals from small changes. The signal to
noise ratio is dependent on several variables
such as surface roughness, coating, coating
condition, associated pipe fittings (T’s,
elbows, flanges), soil compaction, and
environment. Each of these affects the
propagation of sound waves and influences
the range of the test. It may be necessary to
inspect from both ends of the pipeline
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18:57 Apr 07, 2016
Jkt 238001
segment to achieve a full inspection. In
general the inspection range can approach 60
to 100 feet for a 5% CSA, depending on field
conditions.
III. Complete pipe inspection. To ensure
that the entire pipeline segment is assessed
there should be at least a 2 to 1 signal to
noise ratio across the entire pipeline segment
that is inspected. This may require multiple
GWUT shots. Double ended inspections are
expected. These two inspections are to be
overlaid to show the minimum 2 to 1 S/N
ratio is met in the middle. If possible, show
the same near or midpoint feature from both
sides and show an approximate 5% distance
overlap.
IV. Sensitivity.
A. The detection sensitivity threshold
determines the ability to identify a cross
sectional change. The maximum threshold
sensitivity cannot be greater than 5% of the
cross sectional area (CSA).
B. The locations and estimated CSA of all
metal loss features in excess of the detection
threshold must be determined and
documented.
C. All defect indications in the ‘‘Go-No Go’’
mode above the 5% testing threshold must be
directly examined, in-line inspected,
pressure tested, or replaced prior to
completing the integrity assessment.
V. Wave frequency. Because a single wave
frequency may not detect certain defects, a
minimum of three frequencies must be run
for each inspection to determine the best
frequency for characterizing indications. The
frequencies used for the inspections must be
documented and must be in the range
specified by the manufacturer of the
equipment.
VI. Signal or wave type: Torsional and
longitudinal. Both torsional and longitudinal
waves must be used and use must be
documented.
VII. Distance amplitude correction (DAC)
curve and weld calibration.
A. The Distance Amplitude Correction
curve accounts for coating, pipe diameter,
pipe wall and environmental conditions at
the assessment location. The DAC curve must
be set for each inspection as part of
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establishing the effective range of a GWUT
inspection.
B. DAC curves provide a means for
evaluating the cross sectional area change of
reflections at various distances in the test
range by assessing signal to noise ratio. A
DAC curve is a means of taking apparent
attenuation into account along the time base
of a test signal. It is a line of equal sensitivity
along the trace which allows the amplitudes
of signals at different axial distances from the
collar to be compared.
VIII. Dead zone. The dead zone is the area
adjacent to the collar in which the
transmitted signal blinds the received signal,
making it impossible to obtain reliable
results. Because the entire line must be
inspected, inspection procedures must
account for the dead zone by requiring the
movement of the collar for additional
inspections. An alternate method of
obtaining valid readings in the dead zone is
to use B-scan ultrasonic equipment and
visual examination of the external surface.
The length of the dead zone and the near
field for each inspection must be
documented.
IX. Near field effects. The near field is the
region beyond the dead zone where the
receiving amplifiers are increasing in power,
before the wave is properly established.
Because the entire line must be inspected,
inspection procedures must account for the
near field by requiring the movement of the
collar for additional inspections. An alternate
method of obtaining valid readings in the
near field is to use B-scan ultrasonic
equipment and visual examination of the
external surface. The length of the dead zone
and the near field for each inspection must
be documented.
X. Coating type.
A. Coatings can have the effect of
attenuating the signal. Their thickness and
condition are the primary factors that affect
the rate of signal attenuation. Due to their
variability, coatings make it difficult to
predict the effective inspection distance.
B. Several coating types may affect the
GWUT results to the point that they may
reduce the expected inspection distance. For
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example, concrete coated pipe may be
problematic when well bonded due to the
attenuation effects. If an inspection is done
and the required sensitivity is not achieved
for the entire length of the cased pipe, then
another type of assessment method must be
utilized.
XI. End seal. Operators must remove the
end seal from the casing at each GWUT test
location to facilitate visual inspection.
Operators must remove debris and water
from the casing at the end seals. Any
corrosion material observed must be
removed, collected and reviewed by the
operator’s corrosion technician. The end seal
does not interfere with the accuracy of the
GWUT inspection but may have a dampening
effect on the range.
XII. Weld calibration to set DAC curve.
Accessible welds, along or outside the pipe
segment to be inspected, must be used to set
the DAC curve. A weld or welds in the access
hole (secondary area) may be used if welds
along the pipe segment are not accessible. In
order to use these welds in the secondary
area, sufficient distance must be allowed to
account for the dead zone and near field.
There must not be a weld between the
transducer collar and the calibration weld. A
conservative estimate of the predicted
amplitude for the weld is 25% CSA (cross
sectional area) and can be used if welds are
not accessible. Calibrations (setting of the
DAC curve) should be on pipe with similar
properties such as wall thickness and
coating. If the actual weld cap height is
different from the assumed weld cap height,
the estimated CSA may be inaccurate and
adjustments to the DAC curve may be
required. Alternative means of calibration
can be used if justified by sound engineering
analysis and evaluation.
XIII. Validation of operator training.
A. There is no industry standard for
qualifying GWUT service providers. Pipeline
operators must require all guided wave
service providers to have equipment-specific
training and experience for all GWUT
equipment operators which includes training
for:
(1) Equipment operation;
(2) Field data collection; and
(3) Data interpretation on cased and buried
pipe.
B. Only individuals who have been
qualified by the manufacturer or an
independently assessed evaluation procedure
similar to ISO 9712 (Sections: 5
Responsibilities; 6 Levels of Qualification; 7
Eligibility; and 10 Certification), as specified
above, may operate the equipment.
C. A Senior level GWUT equipment
operator with pipeline specific experience
must provide onsite oversight of the
inspection and approve the final reports. A
senior level GWUT equipment operator must
have additional training and experience,
including but not limited to training specific
to cased and buried pipe, with a quality
control program which conforms to section
12 of ASME B31.8S.
D. Training and experience minimums for
senior level GWUT equipment operators:
(1) Equipment Manufacturer’s minimum
qualification for equipment operation and
data collection with specific endorsements
for casings and buried pipe
(2) Training, qualification and experience
in testing procedures and frequency
determination
(3) Training, qualification and experience
in conversion of guided wave data into pipe
features and estimated metal loss (estimated
cross-sectional area loss and circumferential
extent)
(4) Equipment Manufacturer’s minimum
qualification with specific endorsements for
data interpretation of anomaly features for
pipe within casings and buried pipe.
XIV. Equipment: Traceable from vendor to
inspection company. The operator must
maintain documentation of the version of the
GWUT software used and the serial number
of the other equipment such as collars,
cables, etc., in the report.
XV. Calibration onsite. The GWUT
equipment must be calibrated for
performance in accordance with the
manufacturer’s requirements and
specifications, including the frequency of
calibrations. A diagnostic check and system
check must be performed on-site each time
the equipment is relocated. If on-site
diagnostics show a discrepancy with the
manufacturer’s requirements and
specifications, testing must cease until the
equipment can be restored to manufacturer’s
specifications.
XVI. Use on shorted casings (direct or
electrolytic). GWUT may not be used to
assess shorted casings. GWUT operators must
have operations and maintenance procedures
(see § 192.605) to address the effect of
shorted casings on the GWUT signal. The
equipment operator must clear any evidence
of interference, other than some slight
dampening of the GWUT signal from the
shorted casing, according to their operating
and maintenance procedures. All shorted
casings found while conducting GWUT
inspections must be addressed by the
operator’s standard operating procedures.
XVII. Direct examination of all indications
above the detection sensitivity threshold.
The use of GWUT in the ‘‘Go-No Go’’ mode
requires that all indications (wall loss
anomalies) above the testing threshold (5% of
CSA sensitivity) be directly examined (or
replaced) prior to completing the integrity
assessment on the cased carrier pipe. If this
cannot be accomplished then alternative
methods of assessment (such as hydrostatic
pressure tests or ILI) must be utilized.
XVIII. Timing of direct examination of all
indications above the detection sensitivity
threshold. Operators must either replace or
conduct direct examinations of all
indications identified above the detection
sensitivity threshold according to the table
below. Operators must conduct leak surveys
and reduce operating pressure as specified
until the pipe is replaced or direct
examinations are completed.
Required response to GWUT indications
GWUT Criterion
mstockstill on DSK4VPTVN1PROD with PROPOSALS2
Over the detection sensitivity threshold
(maximum of 5%
CSA).
Operating pressure
less than or equal to
30% SMYS
Operating pressure over 30 and less than or
equal to 50% SMYS
Operating pressure over 50% SMYS
Replace or direct examination within 12
months, and instrumented leak survey
once every 30 calendar days.
Replace or direct examination within 6
months, instrumented leak survey once
every 30 calendar days, and maintain
MAOP below the operating pressure at
time of discovery.
Replace or direct examination within 6
months, instrumented leak survey once
every 30 calendar days, and reduce MAOP
to 80% of operating pressure at time of discovery.
Issued in Washington, DC, on March 17,
2016, under authority delegated in 49 CFR
part 1.97(a).
Jeffrey D. Wiese,
Associate Administrator for Pipeline Safety.
[FR Doc. 2016–06382 Filed 4–7–16; 8:45 am]
BILLING CODE 4910–60–P
VerDate Sep<11>2014
18:57 Apr 07, 2016
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PO 00000
Frm 00136
Fmt 4701
Sfmt 9990
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08APP2
]]>Agencies
[Federal Register Volume 81, Number 68 (Friday, April 8, 2016)]
[Proposed Rules]
[Pages 20721-20856]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-06382]
[[Page 20721]]
Vol. 81
Friday,
No. 68
April 8, 2016
Part II
Department of Transportation
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Pipeline and Hazardous Materials Safety Administration
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49 CFR Parts 191 and 192
Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines;
Proposed Rule
Federal Register / Vol. 81 , No. 68 / Friday, April 8, 2016 /
Proposed Rules
[[Page 20722]]
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DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials Safety Administration
49 CFR Parts 191 and 192
[Docket No. PHMSA-2011-0023]
RIN 2137-AE72
Pipeline Safety: Safety of Gas Transmission and Gathering
Pipelines
AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA),
Department of Transportation (DOT).
ACTION: Notice of proposed rulemaking.
-----------------------------------------------------------------------
SUMMARY: This Notice of Proposed Rulemaking (NPRM) proposes to revise
the Pipeline Safety Regulations applicable to the safety of onshore gas
transmission and gathering pipelines. PHMSA proposes changes to the
integrity management (IM) requirements and proposes changes to address
issues related to non-IM requirements. This NPRM also proposes
modifying the regulation of onshore gas gathering lines.
DATES: Persons interested in submitting written comments on this NPRM
must do so by June 7, 2016.
ADDRESSES: You may submit comments identified by the docket number
PHMSA-2011-0023 by any of the following methods:
Federal eRulemaking Portal: https://www.regulations.gov.
Follow the online instructions for submitting comments.
Fax: 1-202-493-2251.
Mail: Hand Delivery: U.S. DOT Docket Management System,
West Building Ground Floor, Room W12-140, 1200 New Jersey Avenue SE.,
Washington, DC 20590-0001 between 9 a.m. and 5 p.m., Monday through
Friday, except Federal holidays.
Instructions: If you submit your comments by mail, submit two
copies. To receive confirmation that PHMSA received your comments,
include a self-addressed stamped postcard.
Note: Comments are posted without changes or edits to https://www.regulations.gov, including any personal information provided. There
is a privacy statement published on https://www.regulations.gov.
FOR FURTHER INFORMATION CONTACT: Mike Israni, by telephone at 202-366-
4571, or by mail at U.S. DOT, PHMSA, 1200 New Jersey Avenue SE., PHP-
30, Washington, DC 20590-0001.
SUPPLEMENTARY INFORMATION:
Outline of This Document
I. Executive Summary
A. Purpose of the Regulatory Action
B. Summary of the Major Provisions of the Regulatory Action in
Question
C. Costs and Benefits
II. Background
A. Detailed Overview
B. Advance Notice of Proposed Rulemaking
C. National Transportation Safety Board Recommendations
D. Pipeline Safety, Regulatory Certainty, and Job Creation Act
of 2011
E. Summary of Each Topic Under Consideration
F. Integrity Verification Process Workshop
III. Analysis of Comments on the Advance Notice of Proposed
Rulemaking
A. Modifying the Definition of HCA
B. Strengthening Requirements To Implement Preventive and
Mitigative Measures for Pipeline Segments in HCAs
C. Modifying Repair Criteria
D. Improving Requirements for Collecting, Validating, and
Integrating Pipeline Data
E. Making Requirements Related to the Nature and Application of
Risk Models More Prescriptive
F. Strengthening Requirements for Applying Knowledge Gained
Through the IM Program
G. Strengthening Requirements on the Selection and Use of
Assessment Methods
H. Valve Spacing and the Need for Remotely or Automatically
Controlled Valves
I. Corrosion Control
J. Pipe Manufactured Using Longitudinal Weld Seams
K. Establishing Requirements Applicable to Underground Gas
Storage
L. Management of Change
M. Quality Management Systems (QMS)
N. Exemption of Facilities Installed Prior to the Regulations
O. Modifying the Regulation of Gas Gathering Lines
IV. Other Proposals
V. Section-by-Section Analysis
VI. Availability of Standards Incorporated by Reference
VII. Regulatory Analysis and Notices
I. Executive Summary
A. Purpose of the Regulatory Action
PHMSA believes that the current regulatory requirements applicable
to gas pipeline systems have increased the level of safety associated
with the transportation of gas. Still, incidents with significant
consequences and various causes continue to occur on gas pipeline
systems. PHMSA has also identified concerns during inspections of gas
pipeline operator programs that indicate a potential need to clarify
and enhance some requirements. Based on this experience, this NPRM
proposes additional safety measures to increase the level of safety for
those pipelines that are not in HCAs as well as clarifications and
selected enhancements to integrity management requirements to improve
safety in HCAs.
On August 25, 2011, PHMSA published an Advance Notice of Proposed
Rulemaking (ANPRM) to seek feedback and comments regarding the revision
of the Pipeline Safety Regulations applicable to the safety of gas
transmission and gas gathering pipelines. In particular, PHMSA
requested comments regarding whether integrity management (IM)
requirements should be changed and whether other issues related to
system integrity should be addressed by strengthening or expanding non-
IM requirements.
Subsequent to issuance of the ANPRM, the National Transportation
Safety Board (NTSB) adopted its report on the San Bruno accident on
August 30, 2011. The NTSB issued safety recommendations P-11-1 and P-
11-2 and P-11-8 through -20 to PHMSA, and issued safety recommendations
P-10-2 through -4 to Pacific Gas & Electric (PG&E), among others.
Several of these NTSB recommendations related directly to the topics
addressed in the August 25, 2011 ANPRM and have an impact on the
proposed approach to rulemaking. Also subsequent to issuance of the
ANPRM, the Pipeline Safety, Regulatory Certainty, and Job Creation Act
of 2011 (the Act) was enacted on January 3, 2012. Several of the Act's
statutory requirements related directly to the topics addressed in the
August 25, 2011 ANPRM and have an impact on the proposed approach to
rulemaking.
Congress has authorized Federal regulation of the transportation of
gas by pipeline in the Pipeline Safety Laws (49 U.S.C. 60101 et seq.),
a series of statutes that are administered by the DOT, PHMSA. PHMSA has
used that authority to promulgate comprehensive minimum safety
standards for the transportation of gas by pipeline.
Congress established the current framework for regulating pipelines
transporting gas in the Natural Gas Pipeline Safety Act of 1968, Public
Law 90-481. That law delegated to DOT the authority to develop,
prescribe, and enforce minimum Federal safety standards for the
transportation of gas, including natural gas, flammable gas, or toxic
or corrosive gas, by pipeline. Congress has since enacted additional
legislation that is currently codified in the Pipeline Safety Laws,
including:
In 1992, Congress required regulations be issued to define the
term ``gathering line'' and establish safety standards for certain
``regulated gathering lines,'' Public Law 102-508. In 1996, Congress
directed that DOT conduct demonstration projects evaluating the
application of risk management principles to pipeline safety
regulation, and
[[Page 20723]]
mandated that regulations be issued for the qualification and
testing of certain pipeline personnel, Public Law 104-304. In 2002,
Congress required that DOT issue regulations requiring operators of
gas transmission pipelines to conduct risk analyses and to implement
IM programs under which pipeline segments in high consequence areas
(HCA) would be subject to a baseline assessment within 10 years and
re-assessments at least every seven years, and required that
standards be issued for assessment of pipelines using direct
assessment, Public Law 107-355.
B. Summary of the Major Provisions of the Regulatory Action in Question
PHMSA plans to address several of the topics in the ANPRM in
separate rulemakings because of the diverse scope and nature of several
NTSB recommendations and the statutory requirements of the Act that
were covered in the ANPRM. This proposed rule addresses several IM
topics, including: Revision of IM repair criteria for pipeline segments
in HCAs to address cracking defects, non-immediate corrosion metal loss
anomalies, and other defects; explicitly including functional
requirements related to the nature and application of risk models
currently invoked by reference to industry standards; explicitly
specifying requirements for collecting, validating, and integrating
pipeline data models currently invoked by reference to industry
standards; strengthening requirements for applying knowledge gained
through the IM Program models currently invoked by reference to
industry standards; strengthening requirements on the selection and use
of direct assessment methods models by incorporating recently issued
industry standards by reference; adding requirements for monitoring gas
quality and mitigating internal corrosion, and adding requirements for
external corrosion management programs including above ground surveys,
close interval surveys, and electrical interference surveys; and
explicitly including requirements for management of change currently
invoked by reference to industry standards. With respect to non-IM
requirements, this NPRM proposes: A new ``moderate consequence areas''
definition; adding requirements for monitoring gas quality and
mitigating internal corrosion; adding requirements for external
corrosion management programs including above ground surveys, close
interval surveys, and electrical interference surveys; additional
requirements for management of change, including invoking the
requirements of ASME/ANSI B31.8S, Section 11; establishing repair
criteria for pipeline segments located in areas not in an HCA; and
requirements for verification of maximum allowable operating pressure
(MAOP) in accordance with new Sec. 192.624 and for verification of
pipeline material in accordance with new section Sec. 192.607 for
certain onshore, steel, gas transmission pipelines. This includes
establishing and documenting MAOP if the pipeline MAOP was established
in accordance with Sec. 192.619(c) or the pipeline meets other
criteria indicating a need for establishing MAOP.
In addition, this NPRM proposes modifying the regulation of onshore
gas gathering lines. The proposed rulemaking would repeal the exemption
for reporting requirements for gas gathering line operators and repeal
the use of API RP 80 for determining regulated onshore gathering lines
and add a new definition for ``onshore production facility/operation''
and a revised definition for ``gathering lines.'' The proposed
rulemaking would also extend certain part 192 regulatory requirements
to Type A lines in Class 1 locations for lines 8 inches or greater.
Requirements that would apply to previously unregulated pipelines
meeting these criteria would be limited to damage prevention, corrosion
control (for metallic pipe), public education program, maximum
allowable operating pressure limits, line markers, and emergency
planning.
This NPRM also proposes requirements for additional topics that
have arisen since issuance of the ANPRM. These include: (1) Requiring
inspections by onshore pipeline operators of areas affected by an
extreme weather event such as a hurricane or flood, landslide, an
earthquake, a natural disaster, or other similar event; (2) revising
the regulations to allow extension of the IM 7-year reassessment
interval upon written notice per Section 5 of the Act; (3) adding a
requirement to report each exceedance of the MAOP that exceeds the
margin (build-up) allowed for operation of pressure-limiting or control
devices per Section 23 of the Act; (4) adding requirements to ensure
consideration of seismicity of the area in identifying and evaluating
all potential threats per Section 29 of the Act; (5) adding regulations
to require safety features on launchers and receivers for in-line
inspection, scraper, and sphere facilities; and (6) incorporating
consensus standards into the regulations for assessing the physical
condition of in-service pipelines using in-line inspection, internal
corrosion direct assessment, and stress corrosion cracking direct
assessment.
The overall goal of this proposed rule is to increase the level of
safety associated with the transportation of gas by proposing
requirements to address the causes of recent incidents with significant
consequences, clarify and enhance some existing requirements, and
address certain statutory mandates of the Act and NTSB
recommendations.\1\
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\1\ PHMSA plans to initiative separate rulemaking to address
other topics included in the ANPRM and that would implement other
requirements of the Act and NTSB recommendations.
---------------------------------------------------------------------------
C. Costs and Benefits
Consistent with Executive Orders 12866 and 13563, PHMSA has
prepared an assessment of the benefits and costs of the proposed rule
as well as reasonable alternatives. PHMSA is publishing the Preliminary
Regulatory Impact Analysis (PRIA) for this proposed rule simultaneously
with this document, and it is available in the docket.
PHMSA estimates the total (15-year) present value of benefits from
the proposed rule to be approximately $3,234 to $3,738 million \2\
using a 7% discount rate ($4,050 to $4,663 million using a 3% discount
rate) and the present value of costs to be approximately $597 million
using a 7% discount rate ($711 million using a 3% discount rate). The
table below summarizes the average annual present value benefits and
costs by topic area. The majority of benefits reflect cost savings from
material verification (processes to determine maximum allowable
operating pressure for segments for which records are inadequate) under
the proposed rule compared to existing regulations; the range in these
benefits reflects different effectiveness assumptions for estimating
safety benefits. Costs reflect primarily integrity verification and
assessment costs (pressure tests, inline inspection, and direct
assessments). The proposed gas gathering regulations account for the
next largest portion of benefits and costs and primarily reflect safety
provisions and associated risk reductions on previously unregulated
lines.
---------------------------------------------------------------------------
\2\ Range reflects uncertainty in defect failure rates for Topic
Area 1.
[[Page 20724]]
Summary of Average Annual Present Value Benefits and Costs \1\
[Millions; 2015$]
----------------------------------------------------------------------------------------------------------------
7% discount rate 3% discount rate
Topic area -----------------------------------------------------
Benefits Costs Benefits Costs
----------------------------------------------------------------------------------------------------------------
Re-establish MAOP, verify material properties, and $196.9-$230.5 $17.8 $247.8-$288.6 $22.0
integrity assessments outside HCAs.......................
Integrity management process clarifications............... n.e. 2.2 n.e. 1.3
Management of change process improvement.................. 1.1 0.7 1.2 0.8
Corrosion control......................................... 5.5 6.3 5.9 7.9
Pipeline inspection following extreme events.............. 0.3 0.1 0.3 0.1
MAOP exceedance reports and records verification.......... n.e. 0.2 n.e. 0.2
Launcher/receiver pressure relief......................... 0.4 0.0 0.6 0.0
Gas gathering regulations................................. 11.3 12.6 14.2 15.1
-----------------------------------------------------
Total................................................. 215.6-249.2 39.8 270-310.8 47.4
----------------------------------------------------------------------------------------------------------------
HCA = high consequence area.
MAOP = maximum allowable operating pressure.
n.e. = not estimated.
\1\ Total over 15-year study period divided by 15. Additional costs to states estimated not to exceed $1.5
million per year. Range of benefits reflects range in estimated defect failure rates.
\2\ Break even value of benefits, based on the average consequences for incidents in high consequence areas,
would equate to less than one incident averted over the 15-year study period.
For the seven percent discount rate scenario, approximately 13
percent of benefits are due to safety benefits from incidents averted,
82 percent represent cost savings from MAOP verification in Topic Area
1, and four percent are attributable to reductions in greenhouse gas
emissions. (For the three percent discount rate scenario, these
percentages are approximately 13, 83, and 3 percent, respectively.)
II. Background
A. Detailed Overview
Introduction
The significant and expected growth in the nation's production and
use of natural gas is placing unprecedented demands on the nation's
pipeline system, underscoring the importance of moving this energy
product safely and efficiently. With changing spatial patterns of
natural gas production and use and an aging pipeline network, improved
documentation and data collection are increasingly necessary for the
industry to make reasoned safety choices and for preserving public
confidence in its ability to do so. Congress recognized these needs
when passing the Pipeline Safety, Regulatory Certainty, and Job
Creation Act of 2011, calling for an examination of a broad range of
issues pertaining to the safety of the nation's pipeline network,
including a thorough application of the risk-based integrity
assessment, repair, and validation system known as ``integrity
management'' (IM).
This proposed rulemaking advances the goals established by Congress
in the 2011 Act, which are consistent with the emerging needs of the
natural gas pipeline system. This proposed rule also advances an
important discussion about the need to adapt and expand risk-based
safety practices in light of changing markets and a growing national
population whose location choices increasingly encroach on existing
pipelines. As some severe pipeline accidents have occurred in areas
outside of high consequence areas (HCA) where the application of IM
principles is not required, and as gas pipelines continue to experience
failures from causes that IM was intended to address, this conversation
is increasingly important.
This proposed rule strengthens protocols for IM, including
protocols for inspections and repairs, and improves and streamlines
information collection to help drive risk-based identification of the
areas with the greatest safety deficiencies. Further, this proposed
rule establishes requirements to periodically assess and extend aspects
of IM to pipeline segments in locations where the surrounding
population is expected to potentially be at risk from an incident. Even
though these segments are not within currently defined HCAs, they could
be located in areas with significant populations where incidents could
have serious consequences. This change would facilitate prompt
identification and remediation of potentially hazardous defects and
anomalies while still allowing operators to make risk-based decisions
on where to allocate their maintenance and repair resources.
Natural Gas Infrastructure Overview
The U.S. natural gas pipeline network is designed to transport
natural gas to and from most locations in the lower 48 States.
Approximately two-thirds of the lower 48 States depend almost entirely
on the interstate transmission pipeline system for their supplies of
natural gas.\3\ To envision the scope of the nation's natural gas
pipeline infrastructure, it is best to consider it in three
interconnected parts that together transport natural gas from the
production field, where gas is extracted from underground, to its end
users, where the gas is used as an energy fuel or chemical feedstock.
These three parts are referred to as gathering, transmission, and
distribution systems. Because this proposed rule applies only to gas
gathering and transmission lines, this document will not discuss
natural gas distribution infrastructure and its associated issues.
Currently, there are over 11,000 miles of onshore gas gathering
pipelines and 297,814 miles of onshore gas transmission pipelines
throughout the U.S.\4\
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\3\ U.S. Department of Energy, ``Appendix B: Natural Gas,''
Quadrennial Energy Review Report: Energy Transmission, Storage, and
Distribution Infrastructure, p. NG-28, April 2015.
\4\ US DOT Pipeline and Hazardous Materials Safety
Administration Data as of 9/25/2015.
---------------------------------------------------------------------------
Gas gathering lines are pipelines used to transport natural gas
from production sites to central collection points, which are often gas
treatment plants where pipeline-quality gas is separated from petroleum
liquids and various impurities. Historically, these lines were of
smaller diameters than gas transmission lines and operated at lower
pressures. However, due to changing demand factors, some gathering
lines are being constructed with diameters equal to or larger than
typical transmission lines and are being operated at much higher
pressures.
Transmission pipelines primarily transport natural gas from gas
treatment
[[Page 20725]]
plants and gathering systems to bulk customers, local distribution
networks, and storage facilities. Transmission pipelines are typically
made of steel and can range in size from several inches to several feet
in diameter. They can operate over a wide range of pressures, from
relatively low (200 pounds per square inch) to over 1,500 pounds per
square inch gage (psig). They can operate within the geographic
boundaries of a single State, or span hundreds of miles, crossing one
or more State lines.
Regulatory History
PHMSA and its State partners regulate pipeline safety for
jurisdictional \5\ gas gathering, transmission, and distribution
systems under minimum Federal safety standards authorized by statute
\6\ and codified in the Pipeline Safety Regulations at 49 CFR parts
190-199.
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\5\ Typically, onshore pipelines involved in the
``transportation of gas''--see 49 CFR 192.1 and 192.3 for detailed
applicability.
\6\ Title 49, United States Code, Subtitle VIII, Pipelines,
Sections 60101, et. seq.
---------------------------------------------------------------------------
Federal regulation of gas pipeline safety began in 1968 with the
creation of the Office of Pipeline Safety and their subsequent issuance
of interim minimum Federal safety standards for gas pipeline facilities
and the transportation of natural and other gas in accordance with the
Natural Gas Pipeline Safety Act of 1968 (Pub. L. 90-481). These Federal
safety standards were upgraded several times over the following decades
to address different aspects of natural gas transportation by pipeline,
including construction standards, pipeline materials, design standards,
class locations, corrosion control, and maximum allowable operating
pressure (MAOP).
These original Pipeline Safety Regulations were not designed with
risk-based regulations in mind. In the mid-1990s, following models from
other industries such as nuclear power, PHMSA started to explore
whether a risk-based approach to regulation could improve safety of the
public and the environment. During this time, PHMSA found that many
operators were performing forms of IM that varied in scope and
sophistication but that there were no minimum standards or
requirements.
In response to a hazardous liquid incident in Bellingham, WA, in
1999 that killed 3 people and a gas transmission incident in Carlsbad,
NM, in 2000 that killed 12, IM regulations for gas transmission
pipelines were finalized in 2004.\7\ The primary goal of the 2004 IM
regulations was to provide a structure to operators for focusing their
resources on improving pipeline integrity in the areas where a failure
would have the greatest impact on public safety. Further objectives
included accelerating the integrity assessment of pipelines in HCAs,
improving IM systems within companies, improving the government's
ability to review the adequacy of integrity programs and plans, thus
providing increased public assurance in pipeline safety.
---------------------------------------------------------------------------
\7\ [68 FR 69778, Dec. 15, 2003] 49 CFR part 192 [Docket No.
RSPA-00-7666; Amendment 192-95] Pipeline Safety: Pipeline Integrity
Management in High Consequence Areas (Gas Transmission Pipelines).
---------------------------------------------------------------------------
The IM regulations specify how pipeline operators must conduct
comprehensive analyses to identify, prioritize, assess, evaluate,
repair, and validate the integrity of gas transmission pipelines in
HCAs, which are typically areas where population is highly
concentrated. Currently, approximately 7 percent of onshore gas
transmission pipeline mileage is located in HCAs. PHMSA and state
inspectors review operators' written IM programs and associated records
to verify that the operators have used all available information about
their pipelines to assess risks and take appropriate actions to
mitigate those risks.
Since the implementation of the IM regulations more than 10 years
ago, many factors have changed. Most importantly, sweeping changes in
the natural gas industry have caused significant shifts in supply and
demand, and the nation's relatively safe but aging pipeline network
faces increased pressures from these changes as well as from the
increased exposure caused by a growing and geographically dispersing
population. Long-identified pipeline safety issues, some of which IM
set out to address, remain problems. Infrequent but severe accidents
indicate that some pipelines continue to be vulnerable to failures
stemming from outdated construction methods or materials. Some severe
pipeline accidents have occurred in areas outside HCAs where the
application of IM principles is not required. Gas pipelines continue to
experience failures from causes that IM was intended to address, such
as corrosion, and the measures currently in use have not always been
effective in identifying and preventing these causes of pipeline
damage.
There is a pressing need for an improved strategy to protect the
safety and integrity of the nation's pipeline system. Following a
significant pipeline incident in 2010 at San Bruno, CA, in which 8
people died and more than 50 people were injured, Congress, the
National Transportation Safety Board (NTSB), and the Government
Accountability Office (GAO) charged PHMSA with improving IM. Comments
from a 2011 advanced notice of proposed rulemaking (ANPRM) suggested
there were many common-sense improvements that could be made to IM, as
well as a clear need to extend certain IM provisions to pipelines not
now covered by the IM regulations. A large portion of the transmission
pipeline industry has voluntarily committed to extending certain IM
provisions to non-HCA pipe, which clearly underscores the common
understanding of the need for this strategy.
Through this proposed rule, PHMSA is taking action to deliver a
comprehensive strategy to improve gas transmission pipeline safety and
reliability, through both immediate improvements to IM and a long-range
review of risk management and information needs, while also accounting
for a changing landscape and a changing population.
Supply Changes
The U.S. natural gas industry has undergone changes of
unprecedented magnitude and pace, increasing production by 33 percent
between 2005 and 2013, from 19.5 trillion cubic feet per year to 25.7
trillion cubic feet per year.\8\ Driving these changes has been a shift
towards the production of ``unconventional'' natural gas supplies using
improved technology to extract gas from low permeability shales. The
increased use of directional drilling and improvements to a long-
existing industrial technique--hydraulic fracturing, which began as an
experiment in 1947--made the recovery of unconventional natural gas
easier and economically viable. This shift in production has decreased
prices and spurred tremendous increases in the use of natural gas.
---------------------------------------------------------------------------
\8\ U.S. Department of Energy, ``Appendix B: Natural Gas,''
Quadrennial Energy Review Report: Energy Transmission, Storage, and
Distribution Infrastructure, p. NG-2, April 2015.
---------------------------------------------------------------------------
While conventional natural gas production in the U.S. has fallen
over the past decade by about 14 billion cubic feet per day, overall
natural gas production has grown due to increased unconventional shale
gas production. In 2004, unconventional shale gas accounted for about 5
percent of the total natural gas production in the U.S. Since then,
unconventional shale gas
[[Page 20726]]
production has increased more than tenfold from 2.7 Bcf/d to about 35.0
Bcf/d in 2014 \9\ and now accounts for about half of overall gas
production in the U.S.\10\
---------------------------------------------------------------------------
\9\ Id., at NG-7.
\10\ Id.
---------------------------------------------------------------------------
This increase in unconventional natural gas production shifted
production away from traditional gas-rich regions towards onshore shale
gas regions. In 2004, the Gulf of Mexico produced about 20 percent of
the nation's natural gas supply, but by2013, that number had fallen to
5 percent. During that same time, Pennsylvania's share of production
grew from 1 percent to 13 percent. An analysis conducted by the
Department of Energy's (DOE) Office of Energy Policy and Systems
Analysis projects that the most significant increases in production
through 2030 will occur in the Marcellus and Utica Basins in the
Appalachian Basin,\11\ which will continue to fuel growth in natural
gas production from current levels of 66.5 Bcf/d to more than 93.5 Bcf/
d.\12\
---------------------------------------------------------------------------
\11\ Id., at NG-6.
\12\ Id.
---------------------------------------------------------------------------
Demand Changes
The recent increase in domestic natural gas production has led to
decreased gas price volatility and lower average prices.\13\ In 2004,
the outlook for natural gas production and demand growth was weak.
Monthly average spot prices at Henry Hub \14\ were high, fluctuating
between $4 per million British thermal units (Btu) and $7 per million
Btu. Prices rose above $11 per million Btu for several months in both
2005 and 2008.\15\ Since 2008, after production shifted to onshore
unconventional shale resources, and price volatility fell away
following the Great Recession, natural gas has traded between about $2
per million Btu and $5 per million Btu.\16\
---------------------------------------------------------------------------
\13\ Id., at NG-11.
\14\ Henry Hub is a Louisiana natural gas distribution hub where
conventional Gulf of Mexico natural gas can be directed to gas
transmission lines running to different parts of the country. Gas
bought and sold at the Henry hub serves as the national benchmark
for U.S. natural gas prices. (Id., at NG-29, NG-30).
\15\ Energy Information Administration, Natural Gas Spot and
Futures Prices, https://www.eia.gov/dnav/ng/ng_pri_fut_s1_m.htm,
retrieved 14 October 2015.
\16\ Id., at NG-11.
---------------------------------------------------------------------------
These historically low prices for this commodity are fueling
tremendous consumption growth and changes in markets and spatial
patterns of consumption. A shift towards natural gas-fueled electric
power generation is helping to serve the needs of the nation's growing
population while helping reduce greenhouse gas emissions, and American
industries are taking advantage of cheap energy by investing in onshore
production capacity, while also exploring economic opportunities for
international energy export.
Plentiful domestic natural gas supply and comparatively low natural
gas prices have changed the economics of electric power markets.\17\
Further, new environmental standards at the local, state, regional, and
Federal levels have encouraged switching to fuels with lower emissions
profiles, including natural gas and renewables. U.S. natural gas
consumption for power generation grew from 15.8 billion cubic feet per
day (Bcf/d) in 2005 to 22.2 Bcf/d in 2013, and demand is projected to
increase by another 8.9 Bcf/d by 2030.\18\ Net gas-fired electricity
generation increased 73 percent nationally from 2003 to 2013, and
natural gas-fired power plants accounted for more than 50 percent of
new utility-scale generating capacity added in 2013. To accommodate
continued future growth in natural gas-fueled power, changes in
pipeline infrastructure will be needed, including reversals of existing
pipelines; additional lines to gas-fired generators; looping of the
existing network, where pipelines are laid parallel to one another
along a single right-of-way to increase capacity; and potentially new
pipelines as well.
---------------------------------------------------------------------------
\17\ Id., at NG-9.
\18\ Id.
---------------------------------------------------------------------------
Further, the increased availability of low-cost natural gas has
brought jobs back to American soil, and increasing investment in
projects designed to take advantage of the significant increase in
supplies of low-cost gas available in the U.S. suggests this trend will
continue.\19\ Moreover, low domestic prices and high international
prices have made natural gas export increasingly attractive to American
businesses. The Federal Energy Regulatory Commission, as of September
2015, estimated U.S. LNG prices at $2.25-$2.41 per million Btu, while
prices in areas of Asia, Europe, and South America ranged from $6.30 to
$7.62 per million Btu.\20\ Due to high capital investment barriers and
coordination difficulties between pipeline shippers, the maritime
shipping industry, and pipeline operators, there are not enough ships
and processing facilities to transport enough LNG to equalize prices.
Taking advantage of these price differentials, liquefied natural gas
exporting terminals in the U.S. and British Columbia, Canada, are
projected to demand between 5.1 Bcf/d and 8.3 Bcf/d of gas by 2030.\21\
---------------------------------------------------------------------------
\19\ Id., at NG-10.
\20\ https://www.ferc.gov/market-oversight/mkt-gas/overview/ngas-ovr-lng-wld-pr-est.pdf.
\21\ U.S. Department of Energy, ``Appendix B: Natural Gas,''
Quadrennial Energy Review Report: Energy Transmission, Storage, and
Distribution Infrastructure, p. NG-11, April 2015.
---------------------------------------------------------------------------
Increasing Pressures on the Existing Pipeline System Due to Supply and
Demand Changes
Despite the significant increase in domestic gas production, the
widespread distribution of domestic gas demand, combined with
significant flexibility and capacity in the existing transmission
system, mitigates the level of pipeline expansion and investment
required to accommodate growing and shifting demand. Some of the new
gas production is located near existing or emerging sources of demand,
which reduces the need for additional natural gas pipeline
infrastructure. In many instances where new natural gas pipelines are
needed, the network is being expanded by participants pursuing lowest-
cost options to move product to market--often making investments to
enhance network capacity on existing lines rather than increasing
coverage through new infrastructure. Where this capacity is not
increasing via additional mileage, it is increasing through larger
pipeline diameters or higher operating pressures. In short, the
nation's existing, and in many cases, aging, pipeline system is facing
the full brunt of this dramatic increase in natural gas supply and the
shifting energy needs of the country.
The U.S. Energy Information Administration estimates that between
2004 and 2013, the natural gas industry spent about $56 billion
expanding the natural gas pipeline network. Between 2008 and 2013,
pipeline capacity additions totaled more than 110 Bcf/d.\22\ Despite
this increase in capacity, gas transmission mileage decreased from
299,358 miles in 2010 to 298,287 miles in 2013.
---------------------------------------------------------------------------
\22\ Id., at NG-31.
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Building new infrastructure, or replacing and modernizing old
infrastructure, is expensive and requires a long lead-time for
planning. Frequently, the most inexpensive way to move new production
to demand centers is by using available existing infrastructure. For
several reasons, the U.S.'s extensive pre-existing gas network is
currently underutilized: (1) Pipelines are long-lived assets that
reflect historic supply and demand trends; (2) pipelines often are
sized to meet high initial production levels and
[[Page 20727]]
have excess long-term capacity due to changing economics; and (3)
pipelines that were built specifically to provide gas to residential
and commercial consumers in cold-weather regions but not for power
generation are often under-utilized during off-peak seasons.
In cases where utilization of the existing pipeline network is
high, the next most cost-effective solution is to add capacity to
existing lines via compression. While this is technically a form of
infrastructure investment, it is less costly, faster, and simpler for
market participants in comparison to building a new pipeline. Adding
compression, however, may raise average pipeline operating pressures,
exposing previously hidden defects.
Developers also recognize that building new pipelines is
challenging due to societal fears and cost, so new pipelines are
typically designed in such a way that they can handle additional
capacity if needed. In New England, new pipeline projects have been
proposed to address pending supply constraints and higher prices.
However, public acceptance presents a substantial challenge to natural
gas pipeline development. Investments and proposals to pay for new
natural gas transmission pipeline capacity and services often face
significant challenges in determining feasible rights of way and
developing community support for the projects.
Data Challenges
Because there is so much emphasis on using the existing pipeline
system to meet the country's energy needs, it is increasingly important
for that system to be safe and efficient. In order to keep the public
safe and to assure the nation's energy security, operators and
regulators must have an intimate understanding of the threats to and
operations of the entire pipeline system.
Data gathering and integration are important elements of good IM
practices, and while many strides have been made over the years to
collect more and better data, several data gaps still exist.
Ironically, the comparatively positive safety record of the nation's
pipeline system to date makes it harder to quantify some of these gaps.
Over the 20-year period of 1995-2014, transmission facilities accounted
for 42 fatalities and 174 injuries, or about one-seventh of the total
fatalities and injuries on the nation's natural gas pipeline
system.\23\ Over the 4-year period of 2011-2014, there was only 1
transmission-related fatality. Fortunately, there have been only
limited ``worst-case scenarios'' to evaluate for cost/benefit analysis
of measures to improve safety, so there are limited bases for
projecting the possible impacts of low-probability, high-consequence
events.
---------------------------------------------------------------------------
\23\ PHMSA, Pipeline Incident 20-Year Trends, https://www.phmsa.dot.gov/pipeline/library/data-stats/pipelineincidenttrends.
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On September 9, 2010, a 30-inch-diameter segment of an intrastate
natural gas transmission pipeline owned and operated by the Pacific Gas
and Electric Company ruptured in a residential area of San Bruno,
California. The rupture produced a crater about 72 feet long by 26 feet
wide. The section of pipe that ruptured, which was about 28 feet long
and weighed about 3,000 pounds, was found 100 feet south of the crater.
The natural gas that was released subsequently ignited, resulting in a
fire that destroyed 38 homes and damaged 70. Eight people were killed,
many were injured, and many more were evacuated from the area.
The San Bruno incident exposed several problems in the way data on
pipeline conditions is collected and managed, showing that many
operators have inadequate records regarding the physical and
operational characteristics of their pipelines. Many of these records
are necessary for the correct setting and validation of MAOP, which is
critically important for providing an appropriate margin of safety to
the public.
Much of operator and PHMSA's data is obtained through testing and
inspection under IM requirements. However, this testing can be
expensive, and the approaches to obtaining data that are most efficient
over the long term may require significant upfront costs to modernize
pipes and make them suitable for automated inspection. As a result,
there continue to be data gaps that make it hard to fully understand
the risks to and the integrity of the nation's pipeline system.
To assess a pipeline's integrity, operators generally choose
between three methods of testing a pipeline: Inline inspection (ILI),
pressure testing, and direct assessment (DA). There is a marked
difference in the distribution of assessment methods between interstate
and intrastate pipelines. In 2013, we estimate that about two-thirds of
interstate pipeline mileage was suitable for in-line inspection,
compared to only about half of intrastate pipeline mileage. Because a
larger percentage of intrastate pipelines are unable to accommodate ILI
tools, intrastate operators use more pressure testing and DA than
interstate operators.
ILIs are performed by using special tools, sometimes referred to as
``smart pigs,'' which are usually pushed through a pipeline by the
pressure of the product being transported. As the tool travels through
the pipeline, it identifies and records potential pipe defects or
anomalies. Because these tests can be performed with product in the
pipeline, the pipeline does not have to be taken out of service for
testing to occur, which can prevent excessive cost to the operator and
possible service disruptions to consumers. Further, ILI is a non-
destructive testing technique, and it can be less costly on a per-unit
basis to perform than other assessment methods.
Pressure tests are typically used by pipeline operators as a means
to determine the integrity (or strength) of the pipeline immediately
after construction and before placing the pipeline in service, as well
as periodically during a pipeline's operating life. In a pressure test,
a test medium inside the pipeline is pressurized to a level greater
than the normal operating pressure of the pipeline. This test pressure
is held for a number of hours to ensure there are no leaks in the
pipeline.
Direct assessment (DA) is the evaluation of various locations on a
pipeline for corrosion threats. Operators will review records,
indirectly inspect the pipeline, or use mathematical models and
environmental surveys to find likely locations on a pipeline where
corrosion might be occurring. Areas that are likely to have suffered
from corrosion are subsequently excavated and examined. DA can be
prohibitively expensive to use unless targeting specific locations,
which may not give an accurate representation of the condition of
lengths of entire pipeline segments.
Ongoing research and industry response to the ANPRM \24\ appear to
indicate that ILI and spike hydrostatic pressure testing is more
effective than DA for identifying pipe conditions that are related to
stress corrosion cracking defects. Both regulators and operators have
expressed interest in improving ILI methods as an alternative to
hydrostatic testing for better risk evaluation and management of
pipeline safety. Hydrostatic pressure testing can result in substantial
costs, occasional disruptions in service, and substantial methane
emissions due to the routine evacuation of natural gas from pipelines
prior to tests. Further, many operators prefer not to use hydrostatic
pressure tests because it can potentially be a
[[Page 20728]]
destructive method of testing.\25\ ILI testing can obtain data along a
pipeline not otherwise obtainable via other assessment methods,
although this method also has certain limitations.
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\24\ ``Pipeline Safety: Safety of Gas Transmission Pipelines--
Advanced Notice of Proposed Rulemaking,'' 76 FR 5308; August 25,
2011.
\25\ National Transportation Safety Board, ``Pacific Gas and
Electric Company; Natural Gas Transmission Pipeline Rupture and
Fire; San Bruno, California; September 9, 2010,'' Pipeline Accident
Report NTSB/PAR-11-01, Page 96, 2011.
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In this proposed rulemaking, PHMSA would expand the range of
permissible assessment methods while imposing new requirements to guide
operators' selection of appropriate methods. Allowing alternatives to
hydrostatic testing (including ILI technologies), combined with further
research and development to make ILI testing more accurate, could help
to drive innovation in pipeline integrity testing technologies. This
could eventually lead to improved safety and system reliability through
better data collection and assessment.
Increased and Changing Use, Coupled With Age, Exposure to Weather, and
Other Factors Can Increase the Risk of Pipeline Incidents
While the existing pipeline network's capacity is expected to bear
the brunt of the increasing demand for natural gas in this country, due
in part due to the location of new gas resources, new production
patterns are causing unique concerns for some pipeline operators. The
significant growth of production outside the Gulf Coast region--
especially in Pennsylvania and Ohio--is causing a reorientation of the
nation's transmission pipeline network. The most significant of these
changes will require reversing flows on pipelines to move Marcellus and
Utica gas to the southeastern Atlantic region and the Midwest.
Reversing a pipeline's flow can cause added stresses on the system
due to changes in pressure gradients, flow rates, and product velocity,
which can create new risks of internal corrosion. Occasional failures
on natural gas transmission pipelines have occurred after operational
changes that include flow reversals and product changes. PHMSA has
noticed a large number of recent or proposed flow reversals and product
changes on a number of gas transmission lines. In response to this
phenomenon, PHMSA issued an Advisory Bulletin notifying operators of
the potentially significant impacts such changes may have on the
integrity of a pipeline.\26\
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\26\ ``Pipeline Safety: Guidance for Pipeline Flow Reversals,
Product Changes, and Conversion to Service,'' ADB PHMSA-2014-0040,
79 FR 56121; September 18, 2014.
---------------------------------------------------------------------------
Further, the rise of shale gas production is altering not just the
extent, but also the characteristics of the nation's gas gathering
systems. Gas fields are being developed in new geographic areas, thus
requiring entirely new gathering systems and expanded networks of
gathering lines. Producers are employing gathering lines with diameters
as large as 36 inches and maximum operating pressures up to 1480 psig,
far exceeding historical design and operating pressure of typical
gathering lines and making them similar to large transmission lines.
Most of these new gas gathering lines are unregulated, and PHMSA does
not collect incident data or report annual data on these unregulated
lines.
However, PHMSA is aware of incidents that show gathering lines are
subject to the same sorts of failures common to other pipelines that
the agency does regulate. For example, on November 14, 2008, three
homes were destroyed and one person was injured when a gas gathering
line ruptured in Grady County, OK. On June 8, 2010, two workers died
when a bulldozer struck a gas gathering line in Darrouzett, TX, and on
June 29, 2010, three men working on a gas gathering line in Grady
County, OK, were injured when it ruptured. The dramatic expansion in
natural gas production and changes in typical gathering line
characteristics require PHMSA to review its regulatory approach to gas
gathering pipelines to address new safety and environmental risks.
In addition to demands placed on the nation's pipeline system due
to increased and changing use, there are many other factors--including
recurring issues that IM was initially developed to address--that
affect the integrity of the nation's pipelines.
Data indicate that some pipelines continue to be vulnerable to
issues stemming from outdated construction methods or materials. Much
of the older line pipe in the nation's gas transmission infrastructure
was made before the 1970s using techniques that have proven to contain
latent defects due to the manufacturing process. For example, line pipe
manufactured using low frequency electric resistance welding is
susceptible to seam failure. Because these manufacturing techniques
were used during the time before the Federal gas regulations were
issued, many of those pipes are subsequently exempt from certain
regulations, most notably the requirement to pressure test the pipeline
or otherwise verify its integrity to establish MAOP. A substantial
amount of this type of pipe is still in service. The IM regulations
include specific requirements for evaluating such pipe if located in
HCAs, but infrequent-yet-severe failures that are attributed to
longitudinal seam defects continue to occur. The NTSB's investigation
of the San Bruno incident determined that the pipe failed due to a
similar defect. Additionally, between 2010 and 2014, fifteen other
reportable incidents were attributed to seam failures, resulting in
over $8 million of property damage.
The nation's pipeline system also faces a greater risk from failure
due to extreme weather events such as hurricanes, floods, mudslides,
tornadoes, and earthquakes. A 2011 crude oil spill into the Yellowstone
River near Laurel, MT, was caused by channel migration and river bottom
scour, leaving a large span of the pipeline exposed to prolonged
current forces and debris washing downstream in the river. Those
external forces damaged the exposed pipeline. In October 1994, flooding
along the San Jacinto River led to the failure of eight hazardous
liquid pipelines and also undermined a number of other pipelines. The
escaping products were ignited, leading to smoke inhalation and burn
injuries of 547 people. From 2003 to 2013, there were 85 reportable
incidents in which storms or other severe natural force conditions
damaged pipelines and resulted in their failure. Operators reported
total damages of over $104M from these incidents. PHMSA has issued
several Advisory Bulletins to operators warning about extreme weather
events and the consequences of flooding events, including river scour
and river channel migration.
Considering recent incidents and many of the factors outlined
above, PHMSA believes IM has led to several improvements in managing
pipeline safety, yet the agency believes there is still more to do to
improve the safety of natural gas transmission pipelines and ensure
public confidence.
Challenges to Modernization and Historical Problems Underscore the Need
for a Clear Strategy To Protect the Safety and Integrity of the
Nation's Pipeline System
The current IM program is both a set of regulations and an overall
regulatory approach to improve pipeline operators' ability to identify
and mitigate the risks to their pipeline systems. The objectives of IM
are to accelerate and improve the quality of integrity assessments,
promote more rigorous and systematic management of integrity,
strengthen oversight, and increase public confidence. On the operator
level, an IM program consists of multiple
[[Page 20729]]
components, including adopting procedures and processes to identify
HCAs, determining likely threats to the pipeline within the HCA,
evaluating the physical integrity of the pipe within the HCA, and
repairing or remediating any pipeline defects found. Because these
procedures and processes are complex and interconnected, effective
implementation of an IM program relies on continual evaluation and data
integration.
The initial definition for HCAs was finalized on August 6,
2002,\27\ providing concentrations of populations with corridors of
protection spanning 300, 660, or 1,000 feet, depending on the diameter
and MAOP of the particular pipeline.\28\ In a later NPRM,\29\ PHMSA
proposed changes to the definition of a HCA by introducing the concept
of a covered segment, which PHMSA defined as the length of gas
transmission pipeline that could potentially impact an HCA.\30\
Previously, only distances from the pipeline centerline related to HCA
definitions. PHMSA also proposed using Potential Impact Circles,
Potential Impact Zones, and Potential Impact Radii (PIR) to identify
covered segments instead of a fixed corridor width. The final Gas
Transmission Pipeline Integrity Management Rule, incorporating the new
HCA definition, was issued on December 15, 2003.\31\
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\27\ ``Pipeline Safety: High Consequence Areas for Gas
Transmission Pipelines,'' Final rule, 67 FR 50824; August 6, 2002.
\28\ The influence of the existing class location concept on the
early definition of HCAs is evident from the use of class locations
themselves in the definition, and the use of fixed 660 ft.
distances, which corresponds to the corridor width used in the class
location definition. This concept was later significantly revised,
as discussed later, in favor of a variable corridor width (referred
to as the Potential Impact Radius) based on case-specific pipe size
and operating pressure.
\29\ ``Pipeline Safety: Pipeline Integrity Management in High
Consequence Areas (Gas Transmission Pipelines),'' Notice of Proposed
Rulemaking, 68 FR 4278; January 28, 2003.
\30\ HCA and PIR definitions are in 49 CFR 192.903.
\31\ ``Pipeline Safety: Pipeline Integrity Management in High
Consequence Areas (Gas Transmission Pipelines),'' Final rule, 68 FR
69778; December 15, 2003.
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The incident at San Bruno in 2010 motivated a comprehensive
reexamination of gas transmission pipeline safety. Congress responded
to concerns in light of the San Bruno incident by passing the Pipeline
Safety, Regulatory Certainty, and Job Creation Act of 2011, which
directed the DOT to reexamine many of its safety requirements,
including the expansion of IM regulations for transmission pipelines.
Further, both the NTSB and the GAO issued several recommendations
to PHMSA to improve its IM program and pipeline safety. The NTSB noted,
in a 2015 study,\32\ that IM requirements have reduced the rate of
failures due to deterioration of pipe welds, corrosion, and material
failures. However, pipeline incidents in high-consequence areas due to
other factors increased between 2010 and 2013, and the overall
occurrence of gas transmission pipeline incidents in high-consequence
areas has remained stable. The NTSB also found many types of basic data
necessary to support comprehensive probabilistic modeling of pipeline
risks are not currently available.
---------------------------------------------------------------------------
\32\ National Transportation Safety Board, ``Safety Study:
Integrity Management of Gas Transmission Pipelines in High
Consequence Areas,'' NTSB SS-15/01, January 27, 2015.
---------------------------------------------------------------------------
Many of these mandates and recommendations caused PHMSA to evaluate
whether IM system requirements, or elements thereof, should be expanded
beyond HCAs to afford protection to a larger percentage of the nation's
population. Additionally, several of these mandates and recommendations
asked PHMSA to enhance the existing IM regulations by addressing MAOP
verification, inadequate operator records, legacy pipe issues, and
inadequate integrity assessments. Further, PHMSA was charged with
reducing data gaps and improving data integration, considering the
regulatory framework for gas gathering systems, and deleting the
``grandfather clause'' to require all gas transmission pipelines
constructed before 1970 be subjected to a hydrostatic spike pressure
test. This proposed rule addresses several of the recommendations from
the 2015 study including P-15-18 (IM-ILI capability), P-15-20 (IM-ILI
tools), P-15-21 (IM-Direct Assessments), and P-21 (IM-Data
Integration).
PHMSA Is Delivering a Comprehensive Strategy To Protect the Nation's
Pipeline System While Accounting for a Changing Landscape and a
Changing Population
To address these statutory mandates, the post-San Bruno NTSB and
GAO recommendations, and other pipeline safety mandates, PHMSA posed a
series of questions to the public in the context of an August 2011
ANPRM titled ``Pipeline Safety: Safety of Gas Transmission Pipelines''
(PHMSA-2011-0023). In that document, PHMSA asked whether the
regulations governing the safety of gas transmission pipelines needed
changing. In particular, PHMSA asked whether IM requirements should be
changed, including through adding more prescriptive language in some
areas, and whether other issues related to system integrity should be
addressed by strengthening or expanding non-IM requirements. Among the
specific issues PHMSA considered concerning IM requirements were
whether the definition of an HCA should be revised, and whether
additional restrictions should be placed on the use of specific
pipeline assessment methods. In the ANPRM, PHMSA also considered
changes to non-IM requirements, including valve spacing and
installation, corrosion control, and whether regulations for gathering
lines needed to be modified.
PHMSA received 103 comments in response to the ANPRM, which are
summarized in more detail later in this document. Feedback from the
ANPRM helped to identify a series of common-sense improvements to IM,
including improvements to assessment goals such as integrity
verification, MAOP verification, and material documentation; clarified
repair criteria; clarified protocol for identifying threats, risk
assessments and management, and prevention and mitigation measures;
expanded and enhanced corrosion control; requirements for inspecting
pipelines after incidents of extreme weather; and new guidance on how
to calculate MAOP in order to set operating parameters more accurately
and predict the risks of an incident.
Many of these aspects of IM have been an integral part of PHMSA's
expectations since the inception of the IM program. As specified in the
first IM rule, PHMSA expects operators to start with an IM framework,
evolve a more detailed and comprehensive IM program, and continually
improve their IM programs as they learn more about the IM process and
the material condition of their pipelines through integrity
assessments. This NPRM's proposals regarding operators' processes for
implementing IM reflect PHMSA's expectations regarding the degree of
progress operators should be making, or should have made, during the
first 10 years of IM program implementation.
To address issues involving the increased risk posed by larger-
diameter, higher-pressure gathering lines, PHMSA is proposing to issue
requirements for certain currently unregulated gas gathering pipelines
that are intended to prevent the most frequent causes of failure--
corrosion and excavation damage--and to improve emergency response
preparedness. Minimum Federal safety standards would also bring an
appropriate level of consistency to the current mix of regulations that
differ from state to state.
[[Page 20730]]
PHMSA believes these proposed changes will improve the safety and
protection of pipeline workers, the public, property, and the
environment by improving the detection and remediation of unsafe
conditions, ensuring that certain currently unregulated pipelines are
subject to appropriate regulatory oversight, and speeding mitigation of
adverse effects of pipeline failures. In addition to safety benefits,
the rule is expected to improve the performance and extend the economic
life of critical pipeline infrastructure that transports domestically
produced natural gas energy, thus supporting national economic and
security energy objectives.
Looking at Risk Beyond HCAs
In addition to the common sense improvements to IM, responses to
the ANPRM reinforced the importance of carefully reconsidering the
scope of areas covered by IM. While PHMSA's IM program manages risks
primarily by focusing oversight on areas with the greatest population
density, responses to the ANPRM highlight the imperative of protecting
the safety of communities throughout the country in light of a changing
landscape of production, consumption, and product movement that merits
a refreshed look at the current scope of IM coverage.
In the 2011 Act, Congress required PHMSA to have pipeline operators
conduct a records verification to ensure that their records accurately
reflect the physical and operational characteristics of pipelines in
certain HCAs and class locations, and to confirm the established MAOP
of the pipelines. The results of that action indicate that problems
similar to the contributing factors of the San Bruno incident are more
widespread than previously believed, affecting both HCA and non-HCA
segments. This indicates that a rupture on the scale of San Bruno, with
the potential to affect populations, the environment, or commerce,
could occur elsewhere on the nation's pipeline system.
In fact, devastating incidents have occurred outside of HCAs in
rural areas where populations are sparse but present. On August 19,
2000, a 30-inch-diameter gas transmission pipeline ruptured adjacent to
the Pecos River near Carlsbad, NM. The released gas ignited and burned
for 55 minutes. Twelve persons who were camping under a concrete-decked
steel bridge that supported the pipeline across the river were killed,
and their vehicles were destroyed. Two nearby steel suspension bridges
for gas pipelines crossing the river were damaged extensively.
On December 14, 2007, two men were driving in a pickup truck on
Interstate 20 near Delhi, LA, when a 30-inch gas transmission pipeline
ruptured. One of the men was killed, and the other was injured.
On December 11, 2012, a 20-inch-diameter gas transmission line
ruptured in a sparsely populated area about 106 feet west of Interstate
77 (I-77) in Sissonville, WV. An area of fire damage about 820 feet
wide extended nearly 1,100 feet along the pipeline right-of-way. Three
houses were destroyed by the fire, and several other houses were
damaged. Reported losses, repairs, and upgrades from this incident
totaled over $8.5 million, and major transportation delays occurred. I-
77 was closed in both directions because of the fire and resulting
damage to the road surface. The northbound lanes were closed for about
14 hours, and the southbound lanes were closed for about 19 hours while
the road was resurfaced, causing delays to both travelers and
commercial shipping.
Because the nation's population is growing, moving, and dispersing,
population density is a changing measure, and we need to be prepared
for further shifts in the coming decades. The current definition of an
HCA uses building density as a proxy for approximating the presence of
communities and surrounding infrastructure. This can be a meaningful
metric for prioritizing implementation of safety and risk management
protocols for areas where an accident would have the greatest
likelihood of putting human life in danger, but it is not necessarily
an accurate reflection of whether an incident will have a significant
impact on people. Requiring assessment and repair criteria for
pipelines that, if ruptured, could pose a threat to areas where any
people live, work, or congregate would improve public safety and would
improve public confidence in the nation's natural gas pipeline system.
Feedback from industry indicated that some pipeline operators are
already moving towards expanding the protections of IM beyond HCAs. In
2012, the Interstate Natural Gas Association of America (INGAA) issued
a ``Commitment to Pipeline Safety,'' \33\ underscoring its efforts
towards a goal of zero incidents, a committed safety culture, a pursuit
of constant improvement, and applying IM principles on a system-wide
basis. INGAA divides the commitment into four stages:
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\33\ Letter from Terry D. Boss, Senior Vice President of
Environment, Safety and Operations to Mike Israni, Pipeline and
Hazardous Materials Safety Administration, U.S. Department of
Transportation, dated January 20, 2012, ``Safety of Gas Transmission
Pipelines, Docket No. PHMSA-2011-0023.'' INGAA represents companies
that operate approximately 65 percent of the gas transmission
pipelines, but INGAA does not represent all pipeline operators
subject to 49 CFR part 192.
---------------------------------------------------------------------------
Stage 1--INGAA members will complete an initial assessment
using some degree of IM on their pipelines, covering 90% of the
population living, working, or congregating along INGAA member
pipelines, by the end of 2012. This represents roughly 64% of INGAA
member pipeline mileage, including the 4% of pipelines that are in
HCAs.
Stage 2--By 2020, INGAA members will consistently and
comprehensively apply IM principles to those pipelines.
Stage 3--By 2030, INGAA members will apply IM principles
to pipelines, extending IM protection to 100% of the population living
along INGAA member pipelines. This stage would cover roughly 16% of
pipeline mileage, bringing the total coverage by 2030 to approximately
80% of INGAA's pipeline mileage.
Stage 4--Beyond 2030, INGAA members will apply IM
principles to the remaining 20% of pipeline mileage where no population
resides.
To accomplish this commitment, INGAA's members are performing
actions that include applying risk management beyond HCAs; raising the
standards for corrosion management; demonstrating ``fitness for
service'' on pre-regulation pipelines; and evaluating, refining, and
improving operators' ability to assess and mitigate safety threats.
Ultimately, these actions aim to extend protection to people who live
near pipelines but not within defined HCAs.
INGAA's commitment and other stakeholder feedback on this issue
have triggered an important exchange about measuring the risks that
exist in less-densely populated areas and the impacts of expanding
greater protections to those areas. If constant improvement and zero
incidents are goals for pipeline operators, INGAA's plan to extend and
prioritize IM assessments and principles to all parts of their pipeline
networks that are located near any concentrations of population is an
effective way to achieve those goals. Such an approach is needed to
help clarify vulnerabilities and prioritize improvements, and this
proposed rulemaking takes important steps forward towards developing
such an approach.
[[Page 20731]]
The question then, is how to implement risk management standards
that most accurately target the safety of communities, while also
providing sufficient ability to prioritize areas of greatest possible
risk and/or impact. Addressing that question has been, and remains, an
important part of this proposed rule, recognizing that the answer will
remain fluid based on factors that continue to change.
Given INGAA's commitment, feedback from the ANPRM, the results of
incident investigations, and IM considerations, PHMSA has determined it
is appropriate to improve aspects of the current IM program and codify
requirements for additional gas transmission pipelines to receive
integrity assessments on a periodic basis to monitor for, detect, and
remediate pipeline defects and anomalies. In addition, in order to
achieve the desired outcome of performing assessments in areas where
people live, work, or congregate, while minimizing the cost of
identifying such locations, PHMSA proposes to base the requirements for
identifying those locations on processes already being implemented by
pipeline operators and that protect people on a risk-prioritized basis.
Establishing integrity assessment requirements and associated
repair conditions for non-HCA pipe segments is important for providing
safety to the public. Although those segments are not within defined
HCAs, they will usually be located in populated areas, and pipeline
accidents in these areas may cause fatalities, significant property
damage, or disrupt livelihoods. This rulemaking proposes a newly
defined moderate consequence area (MCA) to identify additional non-HCA
pipeline segments that would require integrity assessments, thus
assuring timely discovery and repair of pipeline defects in MCA
segments. These changes would ensure prompt remediation of anomalous
conditions that could potentially impact people, property, or the
environment, and commensurate with the severity of the defects, while
at the same time allowing operators to allocate their resources to HCAs
on a higher-priority basis. INGAA's commitment and PHMSA's MCA
definition are comparable, which shows a common understanding of the
importance of this issue and a path towards a solution.
B. Advance Notice of Proposed Rulemaking
On August 25, 2011, PHMSA published an Advance Notice of Proposed
Rulemaking (ANPRM) to seek public comments regarding the revision of
the Pipeline Safety Regulations applicable to the safety of gas
transmission pipelines. In particular, PHMSA requested comments
regarding whether integrity management (IM) requirements should be
changed and whether other issues related to system integrity should be
addressed by strengthening or expanding non-IM requirements. The ANPRM
may be viewed at https://www.regulations.gov by searching for Docket ID
PHMSA-2011-0023. As mentioned above, pursuant to the related issues
raised by the NTSB recommendations and statutory requirements of the
Act, PHMSA is issuing separate rulemaking for several of the topics in
the ANPRM. These topics are so designated in the following list.
Specifically, the ANPRM sought comments on the following topics:
A. Modifying the Definition of HCA (to be addressed in separate
rulemaking),
B. Strengthening Requirements to Implement Preventive and
Mitigative Measures for Pipeline Segments in HCAs (partially addressed
in separate rulemaking--aspects related to Remote Control Valves and
Leak Detection will be addressed in separate rulemaking, other aspects
are being addressed in this NPRM),
C. Modifying Repair Criteria,
D. Improving Requirements for Collecting, Validating, and
Integrating Pipeline Data,
E. Making Requirements Related to the Nature and Application of
Risk Models More Prescriptive,
F. Strengthening Requirements for Applying Knowledge Gained Through
the IM Program,
G. Strengthening Requirements on the Selection and Use of
Assessment Methods,
H. Valve Spacing and the Need for Remotely or Automatically
Controlled Valves (to be addressed in separate rulemaking),
I. Corrosion Control,
J. Pipe Manufactured Using Longitudinal Weld Seams,
K. Establishing Requirements Applicable to Underground Gas Storage
(to be considered for separate rulemaking),
L. Management of Change,
M. Quality Management Systems (QMS) (to be considered for separate
rulemaking),
N. Exemption of Facilities Installed Prior to the Regulations,
O. Modifying the Regulation of Gas Gathering Lines.
A summary of comments and responses to those comments are provided
later in the document.
C. National Transportation Safety Board Recommendations
On August 30, 2011, following the issuance of the ANPRM, the NTSB
adopted its report on the gas pipeline accident that occurred on
September 9, 2010, in San Bruno, California. On September 26, 2011, the
NTSB issued safety recommendations P-11-8 through -20 to PHMSA, and
issued safety recommendations P-10-2 through -4 to Pacific Gas &
Electric (PG&E), among others. The NTSB made these recommendations
following its investigation of the tragic September 9, 2010 natural gas
pipeline rupture in the city of San Bruno, California. Several of the
NTSB recommendations related directly to the topics addressed in the
August 25, 2011 ANPRM and impacted the proposed approach to rulemaking.
The potentially impacted topics and the related NTSB recommendations
include, but are not limited to:
Topic B--Strengthening Requirements to Implement
Preventive and Mitigative Measures for Pipeline Segments in HCAs. NTSB
Recommendation P-11-10: ``Require 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; such tools
could include a real-time leak detection system and appropriately
spaced flow and pressure transmitters along covered transmission
lines.''
Topic D--Improving Requirements for Collecting,
Validating, and Integrating Pipeline Data. NTSB Recommendation P-11-19:
``(1) Develop and implement standards for integrity management and
other performance-based safety programs that require operators of all
types of pipeline systems to regularly assess the effectiveness of
their programs using clear and meaningful metrics, and to identify and
then correct deficiencies; and (2) make those metrics available in a
centralized database.''
Topic G--Strengthening Requirements on the Selection and
Use of Assessment Methods. NTSB Recommendation P-11-17: ``Require that
all natural gas transmission pipelines be configured so as to
accommodate in-line inspection tools, with priority given to older
pipelines.''
Topic H--Valve Spacing and the Need for Remotely or
Automatically Controlled Valves. NTSB Recommendation P-11-11: ``Amend
Title 49 Code of Federal Regulations Section 192.935(c) to directly
require that automatic shutoff valves or remote
[[Page 20732]]
control valves in high consequence areas and in class 3 and 4 locations
be installed and spaced at intervals that consider the population
factors listed in the regulations.''
Topic J--Pipe Manufactured Using Longitudinal Weld Seams.
NTSB Recommendation P-11-15: ``Amend Title 49 Code of Federal
Regulations Part 192 of the Federal pipeline safety regulations so that
manufacturing- and construction-related defects can only be considered
stable if a gas pipeline has been subjected to a post-construction
hydrostatic pressure test of at least 1.25 times the maximum allowable
operating pressure.''
Topic N--Exemption of Facilities Installed Prior to the
Regulations. NTSB Recommendation P-11-14: Amend title 49 Code of
Federal Regulations 192.619 to repeal exemptions from pressure test
requirements and require that all gas transmission pipelines
constructed before 1970 be subjected to a hydrostatic pressure test
that incorporates a spike test.''
D. Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011
Also subsequent to issuance of the ANPRM, the Pipeline Safety,
Regulatory Certainty, and Job Creation Act of 2011 (the Act) was
enacted on January 3, 2012. Several of the Act's statutory requirements
relate directly to the topics addressed in the August 25, 2011 ANPRM.
The related topics and statutory citations include, but are not limited
to:
[cir] Section 5(e)--Allow periodic reassessments to be extended for
an additional 6 months if the operator submits sufficient
justification.
[cir] Section 5(f)--Requires regulations issued by the Secretary,
if any, to expand integrity management system requirements, or elements
thereof, beyond high-consequence areas.
[cir] Section 21--Regulation of Gas (and Hazardous Liquid)
Gathering Lines
[cir] Section 23--Testing regulations to confirm the material
strength of previously untested natural gas transmission pipelines.
[cir] Section 29--Consider seismicity when evaluating pipeline
threats.
E. Summary of Each Topic Under Consideration
This NPRM proposes new requirements and revisions to existing
requirements to address topics discussed in the ANPRM, including some
topics from the Act and the NTSB recommendations. Each topic area
discussed in the ANPRM, as well as additional topics that have arisen
since issuance of the ANPRM, is summarized below. Details of the
changes proposed in this rule are discussed below in section V.
Section-by-Section Analysis.
Topic A--Modifying the Definition of HCA. The ANPRM
requested comments regarding expanding the definition of an HCA so that
more miles of pipe would be subject to IM requirements and so that all
Class 3 and 4 locations would be subject to the IM requirements. The
Act, Section 5, requires that the Secretary of Transportation complete
an evaluation and issue a report on whether integrity management
requirements should be expanded beyond HCAs and whether such expansion
would mitigate the need for class location requirements. PHMSA has
prepared the class location report and a copy is available in the
docket (www.regulations.gov) for this proposed rulemaking. PHMSA
invites commenters to review the class location report when formulating
their comments.
Although PHMSA is not proposing to expand the definition of an HCA,
PHMSA is proposing to expand certain IM requirements beyond HCAs by
creating a new ``moderate consequence areas (MCA).'' MCAs would be used
to define the subset of non-HCA pipeline locations where periodic
integrity assessments are required (Sec. 192.710), where material
documentation verification is required (Sec. 192.607), and where MAOP
verification is required (Sec. Sec. 192.619(e) and 192.624). The
proposed criteria for determining MCA locations would use the same
process and the same definitions as currently used to identify HCAs,
except that the threshold for buildings intended for human occupancy
and the threshold for persons that occupy other defined sites, that are
located within the potential impact radius, would both be lowered from
20 to 5. The intention is that any pipeline location at which persons
are normally expected to be located would be afforded extra safety
protections described above. In addition, as a result of the
Sissonville, West Virginia incident, NTSB issued recommendation P-14-
01, to revise the gas regulations to add principal arterial roadways
including interstates, other freeways and expressways, and other
principal arterial roadways as defined in the Federal Highway
Administration's Highway Functional Classification Concepts, Criteria
and Procedures to the list of ``identified sites'' that establish a
high consequence area. PHMSA proposes to meet the intent of NTSB's
recommendation by incorporating designated interstates, freeways,
expressways, and other principal 4-lane arterial roadways (as opposed
to NTSB's all ``other principal arterial roadways'') within the new
definition of MCAs. PHMSA believes this approach would be cost-
beneficial. The Sissonville, WV, incident location would not meet the
current definition of an HCA, but would, however, meet the proposed
definition of an MCA. PHMSA considered expanding the scope of HCAs
instead of creating Moderate Consequence Areas. Such an approach was
contemplated in the 2011 ANPRM and PHMSA received a number of comments
on this approach. PHMSA concluded that this approach would be counter
to a graded approach based on risk (i.e., risk based gradation of
requirements to apply progressively more protection for progressively
greater consequence locations). By simply expanding HCAs, PHMSA would
be simply lowering the threshold for what is considered ``high
consequence.'' Expanding HCAs would require that all integrity
management program elements (specified in subpart O) be applied to pipe
located in a newly designated HCA. The proposed rule would only apply
three IM program elements (assessment, periodic reassessment, and
remediation of discovered defects) to the category of pipe that has
lesser consequences than HCAs (i.e., MCAs), but not to segments without
any structure or site within the PIR (arguably ``low consequence
areas''). There would be additional significant costs to apply all
other integrity management program elements (most notably the risk
analysis and preventive/mitigative measures program elements) to
additional segments currently not designated as HCA. Also, if HCAs were
expanded, long term reassessment costs would approximately triple
(compared to the proposed MCA requirements) based on an almost 3:1
ratio of reassessment interval. For the above reasons, PHMSA is not
proposing to expand HCAs. Instead, PHMSA is proposing to create and
apply selected integrity management requirements to a category of
lesser consequence areas defined as MCAs. With regard to the criteria
for defining HCAs, PHMSA also considered several alternatives,
including more relaxed population density and excluding small pipe
diameters.
In addition, a major constituency of the pipeline industry (INGAA)
has committed to apply IM principles to all segments where any persons
are located. This is comparable to PHMSA's proposed MCA definition.
PHMSA seeks comment on the relative merits of expanding High
Consequence Areas
[[Page 20733]]
versus creating a new category of ``Moderate Consequence Areas.''
Another alternative PHMSA considered was a shorter a compliance
deadline (10 years) and a shorter reassessment interval (15 years) for
MCA assessments. The assessment timeframes in the proposed rule were
selected based on a graded approach which would apply relaxed
timeframes to MCAs, as compared to HCAs. The industry was originally
required to perform baseline assessments for approximately 20,000 miles
of HCA pipe within approximately 8 years from the effective date of the
integrity management rule. PHMSA estimates that approximately 41,000
miles of pipe would require an assessment within 15 years under this
proposed rule, thus constituting a comparable level of effort on the
part of industry. The maximum HCA reassessment interval is 20 years for
low stress pipe. The 20 year interval was selected to align with the
longest interval allowed for any HCA pipe, which is 20 years for pipe
operating less than 30% SMYS. A reassessment interval of 15 years for
MCAs would be shorter than the reassessment interval for some HCAs.
PHMSA also considered that compliance with the proposed rule would be
performed in parallel with ongoing HCA reassessments at the same time,
thus resulting in greater demand for ILI tools and industry resources
than during the original IM baseline assessment period. In addition,
the proposed rule incorporates other assessment goals, including
integrity verification, maximum allowable operating pressure (MAOP)
verification, and material documentation, thus constituting a larger/
more costly assessment effort than originally required under IM rules.
For the above reasons, PHMSA believes that this proposed rule would
require full utilization or expansion of industry resources devoted to
assessments. Therefore, PHMSA believes that compressing the timeframes
would place unreasonably high demands on the industry's assessment
capabilities. PHMSA also considered the possibility that placing
burdensome demands on the industry's assessment capability might drive
assessment costs higher. PHMSA seeks comments on the potential safety
benefits, avoided lost gas, economic costs, and operational
considerations involved in longer or shorter compliance periods for
initial MCA assessment periods and re-assessment intervals.
More generally, PHMSA seeks comment on the approach and scope of
the proposed rule with respect to applying integrity management program
elements to additional pipe segments not currently designated as HCA,
including, inter alia, alternative definitions of ``Moderate
Consequence Area'' and limits on the categories of pipeline to be
regulated within this new area.
Topic B--Strengthening Requirements to Implement
Preventive and Mitigative Measures for Pipeline Segments in HCAs. The
ANPRM requested comments regarding whether the requirements of Section
49 CFR 192.935 for pipelines in HCAs should be more prescriptive and
whether these requirements, or other requirements for additional
preventive and mitigative measures, should apply to pipelines outside
of HCAs. Section 5 of the Act requires the Secretary of Transportation
to evaluate and report to Congress on expanding IM requirements to non-
HCA pipelines. PHMSA will further evaluate applying P&M measures to
non-HCA areas after this evaluation is complete.
This NPRM proposes rulemaking for amending the integrity management
rule to add requirements for selected preventive and mitigative
measures (internal and external corrosion control).
Two special topics associated with preventive and mitigative
measures, leak detection and automatic valve upgrades, were addressed
by the NTSB and Congress. The NTSB 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; such tools could include a real-time leak detection system and
appropriately spaced flow and pressure transmitters along covered
transmission lines (recommendation P-11-10). In addition, Section 8 of
the Act requires issuance of a report on leak detection systems used by
operators of hazardous liquid pipelines which was completed and
submitted to Congress in December 2012. Although that study is specific
to hazardous liquid pipelines, its analysis and conclusions could
influence PHMSA's approach to leak detection for gas pipelines. In
response to the NTSB recommendations, PHMSA conducted as part of a
larger study on pipeline leak detection technology a public workshop in
2012. This study, among other things, examined how enhancements to
SCADA systems can improve recognition of pipeline leak locations.
Additionally, in 2012 PHMSA held a pipeline research forum to identify
technological gaps, potentially including the advancement of leak
detection methodologies. PHMSA is developing a rulemaking with respect
to leak detection in consideration of these studies and ongoing
research. In addition, PHMSA is focusing this rulemaking on regulations
oriented toward preventing incidents. Leak detection (in the context of
mitigating pipe breaks as described in NTSB P-11-10) \34\ and automatic
valve upgrades are features that serve to mitigate the consequences of
incidents after they occur but do not prevent them. In order to not
delay the important requirements proposed in this NPRM, PHMSA will
address the topic of incident mitigation later in a separate
rulemaking. It is anticipated that advancing rulemaking to address the
NTSB recommendations will follow assessment of the results of these
actions.
---------------------------------------------------------------------------
\34\ Leak detection in the context of detecting small, latent
leaks such as leaks at fittings typical of gas distribution systems,
and is outside the scope of the ANPRM, Topic B.
---------------------------------------------------------------------------
PHMSA completed and submitted the valve study to congress in
December 2012. PHMSA is developing a separate rulemaking related to the
need for remotely or automatically controlled valves to addresses the
NTSB recommendations and statutory requirements related to this topic
as discussed under Topic H.
Topic C--Modifying Repair Criteria. The ANPRM requested
comments regarding amending the integrity management regulations by
revising the repair criteria for pipelines in HCAs to provide greater
assurance that injurious anomalies and defects are repaired before the
defect can grow to a size that leads to a leak or rupture. PHMSA is
proposing in this rule to revise the repair criteria for pipelines in
HCAs. Revisions include repair criteria for cracks and crack-like
defects, corrosion metal loss for defects less severe than an immediate
condition (already included), and mechanical damage defects.
In addition, the ANPRM requested comments regarding establishing
repair criteria for pipeline segments located in areas that are not in
HCAs. PHMSA is proposing rulemaking for establishing repair criteria
for pipelines that are not in HCAs. Such repair criteria would be
similar to the repair criteria for HCAs, with more relaxed deadlines
for non-immediate conditions. It is acknowledged that applying repair
criteria to pipelines that are not in HCAs is one of the factors to be
considered in the integrity management evaluation required in the Act,
as discussed in Topic A above.
Topic D--Improving Requirements for Collecting,
Validating, and Integrating Pipeline Data. The ANPRM
[[Page 20734]]
requested comments regarding whether more prescriptive requirements for
collecting, validating, integrating, and reporting pipeline data are
necessary. PHMSA also discussed this topic in a 2012 pipeline safety
data workshop.
PHMSA issued Advisory Bulletin 12-06 to remind operators of gas
pipeline facilities to verify their records relating to operating
specifications for maximum allowable operating pressure (MAOP) required
by 49 CFR 192.517. On January 10, 2011, PHMSA also issued Advisory
Bulletin 11-01, which reminded operators that if they are relying on
the review of design, construction, inspection, testing and other
related data to establish MAOP, they must ensure that the records used
are reliable, traceable, verifiable, and complete. PHMSA is proposing
in this rule to add specificity to the data integration language in the
IM rule to establish a number of pipeline attributes that must be
included in these analyses, by explicitly requiring that operators
integrate analyzed information, and by requiring that data be verified
and validated. In addition, PHMSA has determined that additional rules
are needed to ensure that records used to establish MAOP are reliable,
traceable, verifiable, and complete. The proposed rule would add a new
paragraph (e) to section 192.619 to codify this requirement and to
require that such records be retained for the life of the pipeline.
Topic E--Making Requirements Related to the Nature and
Application of Risk Models More Detailed. The ANPRM requested comments
regarding making requirements related to the nature and application of
risk models more specific to improve the usefulness of these analyses
in informing decisions to control risks from pipelines. This NPRM
contains proposed requirements that address this topic.
Topic F--Strengthening Requirements for Applying Knowledge
Gained Through the IM Program. The ANPRM requested comments regarding
strengthening requirements related to operators' use of insights gained
from implementation of its IM program. In this NPRM, PHMSA proposes
detailed requirements for strengthening integrity management
requirements for applying knowledge gained through the IM Program.
These requirements include provisions for analyzing interacting
threats, potential failures, and worst-case incident scenarios from
initial failure to incident termination. Though not proposed, PHMSA
seeks comment on whether a time period for updating aerial photography
and patrol information should be established.
Topic G--Strengthening Requirements on the Selection and
Use of Assessment Methods for pipelines requiring assessment. The ANPRM
requested comments regarding the applicability, selection, and use of
assessment methods, including the application of existing consensus
standards. NTSB recommendation P-11-17 related to this topic,
recommends that all gas pipelines be upgraded to accommodate ILI tools.
PHMSA will consider separate rulemaking for upgrading pipelines pending
further evaluation of the issue from new data being collected in the
annual reports.
This NPRM proposes to strengthen requirements for the selection and
use of assessment methods. The proposed rule would provide more
detailed guidance for the selection of assessment methods, including
the requirements in new Sec. 192.493 when performing an assessment
using an in-line inspection tool. This NPRM also proposes to add more
specific requirements for use of internal inspection tools to require
that an operator using this method must explicitly consider
uncertainties in reported results when identifying anomalies. In
addition, the proposed rulemaking would add a ``spike'' hydrostatic
pressure test, which is particularly well suited to address SCC and
other cracking or crack-like defects, guided wave ultrasonic testing
(GWUT), which is particularly appropriate in cases where short
segments, such as roads or railroad crossings, are difficult to assess,
and excavation and in situ direct examination, which is well suited to
address crossovers and other short, easily accessible segments that are
impractical to assess by remote technology, as allowed assessment
methods and would revise the requirements for direct assessment to
allow its use only if a line is not capable of inspection by internal
inspection tools.
The issue of selection and use of assessment methods is related to
the statutory mandate in the Act for the Comptroller General of the
United States to evaluate whether risk-based reassessment intervals are
a more effective alternative. The Act requires an evaluation of
reassessment intervals and the anomalies found in reassessments. While
not directly addressing selection of assessment methods, the results of
the evaluation will have an influence on the general approach for
conducting future integrity assessments. PHMSA will consider the
Comptroller General's evaluation when it becomes available. Additional
rulemaking may be considered after PHMSA considers the results of the
evaluation.
Topic H--Valve Spacing and the Need for Remotely or
Automatically Controlled Valves. The ANPRM requested comments regarding
proposed changes to the requirements for sectionalizing block valves.
In response to the NTSB recommendations, PHMSA held a public workshop
in 2012 on pipeline valve issues, which included the need for
additional valve installation on both natural gas and hazardous liquid
transmission pipelines. PHMSA also included this topic in the 2012
Pipeline Research Forum. In addition, Section 4 of the Act requires
issuance of regulations on the use of automatic or remote-controlled
shut-off valves, or equivalent technology, where economically,
technically, and operationally feasible on transmission pipeline
facilities constructed or entirely replaced after the date of the final
rule. The Act also requires completion of a study by the Comptroller
General of the United States on the ability of transmission pipeline
facility operators to respond to a hazardous liquid or gas release from
a pipeline segment located in an HCA. Separate rulemaking on this topic
will be considered based on the results of the study.
Topic I--Corrosion Control. The ANPRM requested comments
regarding proposed revisions to subpart I to improve the specificity of
existing requirements. This NPRM proposes to revise subpart I,
including a general update to the technical requirements in appendix D
to part 192 for cathodic protection.
Topic J--Pipe Manufactured Using Longitudinal Weld Seams.
In recommendation P-11-15, the NTSB recommended that PHMSA amend its
regulations to require that any longitudinal seam in an HCA be pressure
tested in order to consider the seam to be ``stable.'' This issue is
addressed in Topic N. PHMSA proposes to address this issue by revising
the integrity management requirements in Sec. 192.917(e)(3) to specify
that longitudinal seams may not be treated as stable defects unless the
segment has been pressure tested (and therefore would require an
integrity assessment for seam threats). Also, PHMSA proposes to add new
requirements for verification of maximum allowable operating pressure
(MAOP) in new Sec. 192.624.
Topic K--Establishing Requirements Applicable to
Underground Gas Storage. The ANPRM requested comments regarding
establishing requirements within part 192 applicable to underground gas
storage in order to help assure safety of
[[Page 20735]]
underground storage and to provide a firm basis for safety regulation.
PHMSA will consider proposing a separate rulemaking that specifically
focuses on improving the safety of underground natural gas storage
facilities will allow PHMSA to fully consider the impacts of incidents
that have occurred since the close of the initial comment period. It
will also allow the Agency to consider voluntary consensus standards
that were developed after the close of the comment period for this
ANPRM, and to solicit feedback from additional stakeholders and members
of the public to inform the development of potential regulations.
Topic L--Management of Change. The ANPRM requested
comments regarding adding requirements for management of change to
provide a greater degree of control over this element of pipeline risk.
This NPRM contains proposed requirements that address this topic.
Specifically, PHMSA proposes to revise the general applicability
requirements in Sec. 192.13 to require each operator of an onshore gas
transmission pipeline to develop and follow a management of change
process, as outlined in ASME/ANSI B31.8S, section 11, that addresses
technical, design, physical, environmental, procedural, operational,
maintenance, and organizational changes to the pipeline or processes,
whether permanent or temporary.
Topic M--Quality Management Systems (QMS). The ANPRM
requested comments regarding whether and how to impose requirements
related to quality management systems. PHMSA will consider separate
rulemaking for this topic.
Topic N--Exemption of Facilities Installed Prior to the
Regulations. The ANPRM requested comments regarding proposed changes to
part 192 regulations that would repeal exemptions to pressure test
requirements. The NTSB recommended that PHMSA repeal 49 CFR 192.619(c)
and require that all gas transmission pipelines be pressure tested to
establish MAOP (recommendation P-11-14). In addition, section 23 of the
Act requires issuance of regulations requiring tests to confirm the
material strength of previously untested natural gas transmission
lines. In response to the NTSB recommendation and the Act, this NPRM
proposes requirements for verification of maximum allowable operating
pressure (MAOP) in accordance with new Sec. 192.624 for certain
onshore, steel, gas transmission pipelines, including establishing and
documenting MAOP if the pipeline MAOP was established in accordance
with Sec. 192.619(c).
The Act also requires verification of records to ensure they
accurately reflect the physical and operational characteristics of the
pipelines and to confirm the established maximum allowable operating
pressure of the pipelines. PHMSA issued Advisory Bulletin 12-06 on May
7, 2012 to notify operators of this required action. PHMSA has
initiated an information collection effort to gather data needed to
accurately characterize the quantity and location of pre-1970 gas
transmission pipeline operating under an MAOP established by 49 CFR
192.619(c). This NPRM proposes requirements in new Sec. 192.607 for
certain onshore, steel, gas transmission pipelines to confirm and
record the physical and operational characteristics of pipelines for
which adequate records are not available.
Topic O--Modifying the Regulation of Gas Gathering Lines.
The ANPRM requested comments regarding modifying the regulations
relative to gas gathering lines. The Act required several actions
related to this topic, including: review existing regulations for
gathering lines; provide a report to Congress; and make recommendations
on: (1) The sufficiency of existing regulations, (2) the economic
impacts, technical practicability, and challenges of applying existing
federal regulations to gathering lines, and (3) subject to a risk-based
assessment, the need to modify or revoke existing exemptions from
Federal regulation for gas and hazardous liquid gathering lines. PHMSA
proposes to address aspects of this topic identified before enactment
of the Act in this NPRM. The report submitted to Congress will be
evaluated to determine the need for any future rulemaking, specifically
the need to apply integrity management concepts to gas gathering lines.
In addition, on August 20, 2014, the Government Accountability
Office (GAO) released a report (GAO Report 14-667) to address the
increased risk posed by new gathering pipeline construction in shale
development areas. The GAO recommended that rulemaking be pursued for
gathering pipeline safety that addresses the risks of larger-diameter,
higher-pressure gathering pipelines, including subjecting such
pipelines to emergency response planning requirements that currently do
not apply. PHMSA proposes to address this recommendation as described
below in the ``Section-by-Section Analysis'' under Sec. 192.9.
Additional Topics
Inspection of Pipelines Following a Severe Weather Event.
Existing pipeline regulations prescribe requirements for surveillance
periodically patrolling of pipeline to observe surface conditions on
and adjacent to the transmission line right-of-way for indications of
leaks, construction activity, and other factors affecting safety and
operation, including unusual operating and maintenance conditions. The
cause of the 2011 hazardous liquid pipeline accident resulting in a
crude oil spill into the Yellowstone River near Laurel, Montana was
scouring at the river crossing due to flooding. In this case, annual
heavy flooding occurred in the Spring of the 2011. In late May, the
operator shut down the pipeline for several hours to assess the state
of the pipeline. Following the assessment, the operator restarted the
pipeline and agreed to monitor the river area on a daily basis. On July
1, 2011 the pipeline ruptured which resulted in the release of 1,500
barrels of crude oil into the Yellowstone River. A second break, due to
exposure to flood conditions, occurred several years later on the same
pipeline led to an additional spill in the Yellowstone River. Other
examples include Hurricane Katrina (2005) which resulted in significant
damage to the oil and gas production structures and the San Jacinto
flood (1994) which resulted in 8 ruptures and undermining of 29 other
pipelines. In the context of the San Jacinto flood, ``undermining''
occurred when support material for the pipelines was removed due to
erosion driven by the floodwaters. As a result, the unsupported
pipelines were subjected to stress from the floodwaters that resulted
in fatigue cracks in the pipe walls. Based on these examples of extreme
weather events that did result, or could have resulted, in pipeline
incidents, PHMSA has determined that additional regulations are needed
to require, and establish standards for, inspection of the pipeline and
right-of-way for ``other factors affecting safety and operation''
following an extreme weather event, such as a hurricane or flood, an
earthquake, a natural disaster, or other similar event that has the
likelihood of damage to infrastructure. The proposed rule would require
such inspections, specify the timeframe in which such inspections
should commence, and specify the appropriate remedial actions that must
be taken to ensure safe pipeline operations. The new regulation would
apply to onshore transmission pipelines and their rights-of-way.
[[Page 20736]]
Notification for 7-Year Reassessment Interval Extension.
Subsection 5(e) of the Act identifies a technical correction amending
section 60109(c)(3)(B) of title 49 of the United States Code to allow
the Secretary of Transportation to extend the 7- calendar year
reassessment interval for an additional 6 months if the operator
submits written notice to the Secretary with sufficient justification
of the need for the extension. PHMSA would expect that any
justification, at a minimum, would need to demonstrate that the
extension does not pose a safety risk. PHMSA proposes to codify this
statutory requirement.
Reporting Exceedances of Maximum Allowable Operating
Pressure. Section 23 of the Act requires operators to report to PHMSA
each exceedance of the maximum allowable operating pressure (MAOP) that
exceeds the margin (build-up) allowed for operation of pressure-
limiting or control devices. Implicit in Sec. 192.605 is the intent
for operators to establish operational and maintenance controls and
procedures to effectively preclude operation at pressures that exceed
MAOP. PHMSA expects that operators' procedures should already address
this aspect of operations and maintenance, as it is a long-standing,
critical aspect of safe pipeline operations. PHMSA issued ADB 12-11 to
address exceedances of MAOP. However, PHMSA proposes to codify this
statutory requirement in Sec. 192.605.
Consideration of Seismicity. Section 29 of the Act states
that in identifying and evaluating all potential threats to each
pipeline segment, an operator of a pipeline facility must consider the
seismicity of the area. PHMSA proposes to codify this statutory
requirement by adding requirements to explicitly reference seismicity
for data gathering and integration, threat identification, and
implementation of preventive and mitigative measures.
Safety Regulations for In-line Inspection (ILI), Scraper,
and Sphere Facilities. PHMSA is proposing to add explicit requirements
for safety features on launchers and receivers associated with ILI,
scraper and sphere facilities.
Consensus Standards for Pipeline Assessments. The proposed
rule would incorporate by reference industry standards for assessing
the physical condition of in-service pipelines using in-line
inspection, internal corrosion direct assessment, and stress corrosion
cracking direct assessment. Periodic assessment of the condition of gas
transmission pipelines in HCAs is required by 49 CFR 192.921 and
192.937. The regulations provide minimal requirements for the use of
these assessment techniques since at the time these regulations were
established, industry standards did not exist addressing how these
techniques should be applied. Incorporation of standards subsequently
published by the American Petroleum Institute (API), the National
Association of Corrosion Engineers (NACE), and the American Society of
Nondestructive Testing (ASNT) would assure better consistency, accuracy
and quality in pipeline assessments conducted using these techniques.
F. Integrity Verification Process Workshop
An Integrity Verification Process (IVP) workshop was held on August
7, 2013. At the workshop, PHMSA, the National Association of State
Pipeline Safety Representatives and various other stakeholders
presented information and comments were sought on a proposed IVP that
will help address mandates set forth in Section 23, Maximum Allowable
Operating Pressure, of the Act and the NTSB Recommendations P-11-14
(repeal pressure test exemptions) and P-11-15 (stability of
manufacturing and construction defects). Key aspects of the proposed
IVP process include criteria for establishing which pipe segments would
be subject to the IVP, technical requirements for verifying material
properties where adequate records are not available, and technical
requirements for re-establishing MAOP where adequate records are not
available or the existing MAOP was established under Sec. 192.619(c).
Comments were received from the American Gas Association, the
Interstate Natural Gas Association of America, and other stakeholders
addressing the draft IVP flow chart, technical concerns for
implementing the proposed IVP, and other issues. The detailed comments
are available under Docket No. PHMSA-2013-0119. PHMSA considered and
incorporated the stakeholder input, as appropriate, into this NPRM,
which proposes requirements to address the current exemptions to
pressure test requirements, manufacturing and construction defect
stability, verification of MAOP where records to establish MAOP are not
available or inadequate (new Sec. Sec. 192.619(e) and 192.624), and
verification and documentation of pipeline material for certain
onshore, steel, gas transmission pipelines (new Sec. 192.607).
III. Analysis of Comments on the ANPRM
In Section II of the ANPRM, PHMSA sought comments concerning the
significance of the proposed issues to pipeline safety; whether new/
revised regulations are needed and, if so, suggestions as to what
changes are needed; and likely costs that would be associated with
implementing any new/revised requirements. PHMSA posed specific
questions to solicit stakeholder input. These included questions
related to 15 specific topic areas in two broad categories:
1. Should IM requirements be revised and strengthened to bring more
pipeline mileage under IM requirements and to better assure safety of
pipeline segments in HCAs? Specific topics included:
A. Modifying the Definition of HCA,
B. Strengthening Requirements to Implement Preventive and
Mitigative Measures for Pipeline Segments in HCAs,
C. Modifying Repair Criteria,
D. Improving Requirements for Collecting, Validating, and
Integrating Pipeline Data,
E. Making Requirements Related to the Nature and Application of
Risk Models More Prescriptive,
F. Strengthening Requirements for Applying Knowledge Gained Through
the IM Program,
G. Strengthening Requirements on the Selection and Use of
Assessment Methods.
2. Should non-IM requirements be strengthened or expanded to
address other issues associated with pipeline system integrity.
Specific topics included:
H. Valve Spacing and the Need for Remotely or Automatically
Controlled Valves,
I. Corrosion Control,
J. Pipe Manufactured Using Longitudinal Weld Seams,
K. Establishing Requirements Applicable to Underground Gas Storage,
L. Management of Change,
M. Quality Management Systems (QMS),
N. Exemption of Facilities Installed Prior to the Regulations,
O. Modifying the Regulation of Gas Gathering Lines.
PHMSA received a total of 1,463 comments; 1,080 from industry
sources (Trade Associations/Unions, Pipeline Operators and
Consultants); 316 comments from the public (Environmental Groups,
Government Agencies/Municipalities, NAPSR and individual members of the
general public); and 67 general comments not directly related to the
ANPRM questions or categories. Commenters included:
[[Page 20737]]
Citizen Groups
[cir] Environmental Defense Fund (EDF)
[cir] League of Women Voters of Pennsylvania (LWV)
[cir] Pipeline Safety Trust (PST)
[cir] State of Washington Citizens Advisory Committee on Pipeline
Safety (CCOPS)
Consultants
[cir] Accufacts Inc.
[cir] Oleksa and Associates, Inc.
[cir] Thomas M. Lael
[cir] WKM Consultancy, LLC
Government Agencies
[cir] California Public Utilities Commission (CPUC)
[cir] City and County of San Francisco (CCSF)
[cir] Federal Energy Regulatory Commission (FERC)
[cir] Harris County Fire Marshal's Office (HCFM)
[cir] Interstate Oil and Gas Compact Commission (IOGCC)
[cir] Iowa Utilities Board
[cir] Kansas Corporation Commission (KCC)
[cir] Kansas Department of Health and Environment (KDHE)
[cir] National Association of Pipeline Safety Representatives
(NAPSR)
[cir] National Transportation Safety Board (NTSB)
[cir] Railroad Commission of Texas (TRRC)
[cir] State of Alaska--AK Natural Gas Development Authority (AKN)
[cir] State of Alaska Dept. of Natural Resources (AKDNR)
[cir] Wyoming County Commissioners of Pennsylvania (WYCTY)
Pipeline Industry
[cir] Air Products and Chemicals, Inc.
[cir] Alliance Pipeline
[cir] Ameren Illinois (AmerenIL)
[cir] Atmos Energy
[cir] Avista Corporation
[cir] CenterPoint Energy
[cir] CenterPoint Energy Resources Corp.
[cir] Chevron
[cir] Dominion East Ohio Gas (DEOG)
[cir] El Paso (EPPG)
[cir] ITT Exelis Geospatial Systems
[cir] Kern River Gas Transmission Company
[cir] MidAmerican Energy Company
[cir] National Fuel Gas Supply Corporation
[cir] National Grid
[cir] Nicor Gas
[cir] NiSource Gas Transmission & Storage
[cir] Northern Natural Gas
[cir] Paiute Pipeline Company
[cir] Panhandle Energy
[cir] Questar Gas Company
[cir] Questar Pipeline Company
[cir] SCGC and SDG&E (Sempra)
[cir] Southern Star Central Gas Pipeline, Inc.
[cir] Southwest Gas Corporation
[cir] Spectra Energy
[cir] TransCanada
[cir] TransCanada Corporation
[cir] Waste Management, Inc
[cir] Williams Gas Pipeline
Municipalities
[cir] Delaware Solid Waste Authority (DSWA)
[cir] Iowa Association of Municipal Utilities (IAMU)
Trade Associations
[cir] American Gas Association (AGA)
[cir] American Public Gas Association (APGA)
[cir] Gas Processors Association (GPA)
[cir] Gas Piping Technology Committee (GPTC)
[cir] Independent Petroleum Association of America, its Cooperating
Associations, and the American Petroleum Institute (IPAA/API)
[cir] Interstate Natural Gas Association of America (INGAA)
[cir] NACE International
[cir] National Solid Waste Management Association (NSWMA)
[cir] National Utility Locating Contractors Association (Locators)
[cir] Oklahoma Independent Petroleum Association (OKIPA)
[cir] Texas Oil and Gas Association (TXOGA)
[cir] Texas Pipeline Association (TPA)
Trade Unions
[cir] Professional Engineers in California Government (PECG)
31 Private Citizens
Commenters responded to ANPRM questions, but also submitted
comments on subjects generally related to gas pipeline safety
regulation (but not related to an ANPRM topic) and general comments
related to a topic but not in response to any specific question. This
NPRM presents a summary of the comments received (similar or duplicate
comments are consolidated). The general (no-topic) comments are
presented first under the heading ``General Comments.'' Comments on
each topic follow under the heading ``Comments on ANPRM Section II
Topics on Which PHMSA Sought Comment,'' beginning with general comments
related to the topic and then proceeding to each individual question.
General Comments
General Industry Comments
1. A number of commenters associated with the pipeline industry
suggested that PHMSA should defer action on the changes discussed in
the ANPRM until the studies required by the Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011 are completed. They contended
the Act presents critical issues that require priority attention. They
believe the questions raised by Congress, and to which the studies are
addressed, could lead to fundamental changes in how pipeline safety is
regulated and these changes need to be understood before new rules are
written. Several commenters also suggested PHMSA lacks the resources to
pursue simultaneously the required studies and complicated rulemakings.
The Railroad Commission of Texas also suggested no new requirements be
proposed until the effects of the new Act are understood, since they
believe that the Act will change the scope of regulatory authority and
impose additional costs on industry and regulators.
Response
PHMSA has placed studies and evaluations that relate to the topics
in this proposed rulemaking on the docket. PHMSA seeks public comment
on those reports and will consider comments before finalizing this
rule. Other topics not addressed in this rulemaking that require
additional study or evaluation will be addressed separately. Areas for
safety improvement that have previously been identified and that are
not dependent on the outcome of the required studies are also the
subject of the proposals in this Notice.
2. INGAA, AGA, and several pipeline operators and consultants
commented that the ANPRM suggested that PHMSA intends to pursue
prescriptive regulation in a number of areas. They objected to this
approach. They prefer performance-based regulation, under which
operators have greater flexibility in deciding how the required safety
goal can be met, considering the specific circumstances of their
pipeline systems. They noted that integrity management, a performance-
based approach, has greatly improved pipeline safety, and suggested
PHMSA consider expanding the elements to be covered in an IM plan and
providing more well-defined guidelines on how these expanded plans
should evolve over time. They noted that implementing pipeline safety
regulations is a complex process and implementing prescriptive
requirements is usually inefficient. They also noted that prescriptive
requirements tend to discourage technological advancements which can
lead to improved means to assure safety.
Response
PHMSA believes performance-based regulations are central to
improving pipeline performance. In some instances, however,
prescriptive
[[Page 20738]]
requirements may be necessary to provide the requisite improvement to
pipeline safety performance; for example, requirements for corrosion
control, repair conditions, and repair criteria to more specifically
address significant corrosion issues. In these cases, the unsafe
condition can be clearly specified, and steps necessary to remediate
the risk are well-understood engineering practice. PHMSA is committed
to an efficient and effective approach to pipeline safety, and using
prescriptive regulatory requirements only where necessary.
3. AGA, Texas Pipeline Association, Texas Oil and Gas Association,
and a number of pipeline operators objected to the scope and pace of
change in pipeline safety regulation. These commenters noted that the
ANPRM covered a number of complex issues. In addition, they noted that
pipeline operators are still implementing a number of large new
initiatives including control room management, public awareness,
distribution integrity management, and damage prevention. They
commented that the industry needs time to complete implementing these
other new regulations and PHMSA and the industry need time to evaluate
the effect they have on pipeline safety. AGA specifically expressed
concern that the pace of change could result in unintended adverse
consequences. The Texas Associations suggested that any expansion of
non-HCA regulations should address highest risks first and be
structured to tailor requirements to different pipeline conditions
because other approaches are likely to result in increased costs with
little safety benefit. MidAmerican commented that the ANPRM appeared to
be based on an incorrect assumption that there are no current
requirements applicable to non-HCA pipe; they noted that part 192
includes many requirements applicable to non-HCA segments and that they
assure safety. Atmos suggested PHMSA avoid the ``one size fits all''
approach to pipeline safety regulations.
Response
PHMSA understands that assimilation of change is an important
consideration and agrees that the ANPRM covers a number of complex
issues. Many of the more complex issues contemplated in the ANPRM, such
as leak detection and automatic valves, will be addressed by separate
rulemaking so that more careful and detailed analysis can be completed.
However, PHMSA is proposing rulemaking in a number of areas to assure
that the regulations continue to provide an adequate level of safety
for both HCAs and non-HCAs. Additional discussion of the basis for the
proposed rulemaking is presented in the response to comments received
for each ANPRM topic and in Section V below (Section-by-Section
Analysis).
4. A number of industry commenters suggested that PHMSA exercise
care in developing broad requirements that may be inappropriate for
some types of pipelines. In particular, APGA noted that
``transmission'' pipeline operated by local distribution companies is
very different from long-distance transmission lines. They are
typically smaller diameter, operate at lower pressures, and are often
made of plastic. AGA and distribution pipeline operators noted that
leaks are a routine management issue for distribution pipelines and
those requirements appropriate to leak response for transmission
pipelines would not be appropriate in a distribution context. The Texas
Oil & Gas Association requested that any changes be examined for
possible unexpected impact on gathering lines, which also differ from
transmission pipelines.
Response
PHMSA is aware of the varying nature of pipeline systems. One
aspect of performance-based requirements is the ability of operators to
customize the integrity management program so that it is appropriate to
its circumstances.
5. AGA and some pipeline operators noted that the ANPRM suggested
that PHMSA intends to extrapolate hazardous liquid pipeline experience
to gas pipelines. In particular, they expressed concern regarding the
discussion of leak detection. They noted pin-point leak detection may
be practical for non-compressible liquids but is not for gas.
Response
PHMSA appreciates the significant differences between hazardous
liquid pipelines and gas pipelines with respect to leak detection.
PHMSA is sponsoring studies and research to address leak detection in a
responsible way, while still being responsive to related NTSB
recommendations. PHMSA is considering separate rulemaking for leak
detection that will address these studies and research.
6. Pipeline industry trade associations reported that their members
plan to implement voluntary approaches to improve pipeline safety.
INGAA reported it has implemented a strategy to achieve a goal of zero
pipeline incidents. This strategy includes voluntary application of IM
principles to non-HCA pipeline segments where people live. Their goal
is to apply ASME/ANSI B31.8S, Managing System Integrity of Gas
Pipelines, principles to 90 percent of people who live or work in close
proximity to pipelines by 2020, and 100 percent by 2030. INGAA's
strategy also includes assuring the fitness for service of pipelines
installed before federal safety regulations were promulgated, improving
incident response time (to less than one hour in populated areas), and
implementing the Pipelines and Informed Planning Alliance (PIPA)
guidelines. AGA similarly reported their intentions to address
improvements to safety proactively by applying Operator Qualification
to new construction, continuing to advance IM principles (including
developing industry guidelines for data management and data quality),
and working with a coalition of PIPA stakeholders to adopt PIPA-
recommended best practices, among other initiatives.
Response
PHMSA commends the pipeline industry for these initiatives and is
committed to working with the industry to improve performance toward
the goal of zero pipeline incidents.
7. A number of comments addressed the cost-benefit analyses that
will be required in support of rulemaking that results from this ANPRM.
AGA noted that a detailed estimate has not been completed but that
preliminary evaluations suggest that the cost of implementing the
initiatives included in the ANPRM could well exceed the cost of
implementing the 2003 gas transmission IM rule. APGA agreed that some
of the concepts discussed in the ANPRM are potentially very costly and
must be considered carefully. Accufacts cautioned PHMSA to be wary of
efforts to distort the cost-benefit analyses by hyper inflating costs.
As an example, Accufacts pointed to estimates of costs to perform
hydrostatic tests ranging from $500,000 to $1,000,000 per mile compared
to costs of $29,400 to $40,000 per mile cited in the NTSB report on the
San Bruno accident.
Response
PHMSA acknowledges that estimates of hydrostatic test costs can
vary and that there is risk in using overstated estimates in the
analysis of benefits and costs since regulatory decisions regarding
public safety can be based on these results. For the Preliminary
Regulatory Impact Assessment (PRIA) for this proposed rule PHMSA used
vendor pricing data to develop unit costs for pressure testing. These
costs represent the contractor's costs to complete an eight hour
pressure test for
[[Page 20739]]
various segment diameters and lengths. PHMSA applied a multiplier to
account for other operator costs, such as manifold installation and
operational oversight, and also added estimated costs to provide
temporary gas supplies and the market value of lost gas. Based on these
data and assumptions, PHMSA estimated per mile pressure test costs
range from approximately $60,000 per mile (12'' diameter, 10 mile
segment) to 630,000 (36'' diameter, one mile segment). Detailed
explanations of these unit costs are available in the PRIA, provided in
the regulatory docket.
8. AGA and several pipeline operators suggested PHMSA should
establish jointly with industry a committee to evaluate pipeline data
and to determine whether more data is needed. They commented industry
has repeatedly made this request and PHMSA has, to date, not responded.
They contended PHMSA's current analysis of pipeline safety performance
data is inadequate. Similarly, Panhandle Energy noted a number of the
questions in the ANPRM requested data on various subjects; Panhandle
expressed its belief that PHMSA collects and has access to at least
some of data requested, and this data, collected pursuant to regulatory
requirements, should be more complete, and consistently collected and
reported, than piecemeal collections of data in response to this ANPRM.
Expressing a somewhat contrary view, El Paso suggested more data should
be collected and analyzed before notices of proposed rulemakings are
prepared; PHMSA needs to collect and analyze data to determine the
proper path for future requirements, if any.
Response
In response to NTSB recommendation P-11-19, PHMSA held a pipeline
safety data workshop in January 2013. The workshop: (1) Summarized the
data OPS collects, who it is collected from, and why it is collected;
(2) addressed how stakeholders, including OPS, industry, and the public
use the data; (3) addressed data quality improvement efforts and
performance measures; and (4) discussed the best method(s) for
collecting, analyzing, and ensuring transparency of additional data
needed to improve performance measures. PHMSA considered the results of
the workshop as well as the comments to the ANPRM related to pipeline
safety performance data.
9. APGA suggested PHMSA revise the definitions of transmission and
distribution pipelines to be more risk-based. APGA contended that the
current definitions are not risk-based and lead to inappropriate
outcomes. In particular, classification of some pipelines as
``transmission'' based on functional aspects of the current definition
leads to inappropriate application of requirements. In a similar vein,
Oleksa and Associates suggested it may be time to reduce IM
requirements on low-stress transmission pipelines, which pose lower
risk than high-stress lines. Texas Pipeline Association and Texas Oil &
Gas Association commented PHMSA should not extrapolate experience with
interstate pipelines to intrastate lines, which differ in design and
operation.
Response
The definition of transmission vs. distribution pipelines and the
applicability requirements for integrity management in High Consequence
Areas is not within the scope of this proposed rule. The general topic
of the scope and applicability of integrity management is addressed in
the class location report which available in the docket.
10. Northern Natural Gas recommended all exemptions from one-call
requirements be eliminated. They noted excavation damage remains, by
far, the single greatest threat to pipeline safety and management of
excavation damage, through one-call programs, has been demonstrated to
be an effective means of countering that threat.
Response
This comment is not within the scope of the ANPRM topics. However,
PHMSA has revised the pipeline safety regulations related to pipeline
damage prevention programs, which includes one-call programs, in an
final rule issued July 23, 2015 (80 FR 43836).
11. The Gas Processors Association, Texas Pipeline Association, and
Texas Oil & Gas Association commented regarding current efforts to
clarify the applicability of part 192 requirements, particularly
requirements for distribution integrity management, to farm taps. They
suggested PHMSA is engaged in an expansion of requirements in this area
without notice or a demonstrated safety need. They suggested PHMSA
initiate a rulemaking specifically to clarify requirements applicable
to farm taps.
Response
Treatment of farm taps is not within the scope of the ANPRM topics.
However, PHMSA has engaged in dialogue with industry on this topic and
will continue to consider options to address this issue in a separate
action.
12. Northern Natural Gas suggested PHMSA reduce the time allowed
for conducting a baseline assessment in cases where a new HCA is found,
tailored to the circumstances of the particular segment. Northern
expressed its belief this would address threats to integrity in areas
affecting population more quickly than current requirements.
Response
Currently, Sec. 192.905(c) requires that newly identified HCAs be
incorporated into the baseline assessment plan within one year. PHMSA
does not currently have plans to address this requirement. However,
periodically DOT or PHMSA seeks public input on retrospective review of
existing regulations under Executive Order 13563. PHMSA encourages the
commenter to raise this issue the next time DOT or PHMSA solicits
comments on retrospective review of existing regulations.
13. Alliance Pipeline suggested many pipeline safety questions can
be answered by applying INGAA's five guiding principles of pipeline
safety. They noted INGAA has developed the Integrity Management-
Continuous Improvement (IMCI) Initiative to implement these principles
and suggested PHMSA actively engage with INGAA in developing workable
solutions to pipeline safety issues.
Response
PHMSA appreciates the industry efforts to improve pipeline safety
and is committed to working with all stakeholders toward this end.
14. Paiute Pipeline and Southwest Gas commented integrity
management requirements have not been in effect long enough to gauge
their effectiveness and decide whether additional changes are needed.
The companies noted the first, baseline assessments of pipeline
segments subject to those requirements are only now being completed.
AGA and other pipeline operators agreed, noting IM is still new,
operators are still refining their processes, and PHMSA should approach
change with caution.
Response
While the first round of baseline assessments are only now being
completed, the gas IM rule has been in place approximately 10 years.
PHMSA expects that operator IM programs should have significantly
matured in this timeframe.
15. Panhandle Energy suggested that PHMSA evaluate rule changes
that could have prevented incidents which occurred in recent years. Any
initiatives that would not have contributed to improved safety, they
suggest, should be postponed or treated as lower priority activities.
Panhandle suggested rulemaking without a sound basis is not
[[Page 20740]]
only ineffective but counterproductive in that it diverts resources
that could have been used to improve safety. Questar Gas similarly
commented PHMSA needs to minimize unnecessary activities that
inappropriately divert safety resources. Questar also recommended that
PHMSA explicitly consider the diversity within the regulated community.
Response
One of the major motivations for PHMSA's issuance of the ANPRM was
to solicit information useful to ensuring that pipeline safety reforms
have a sound basis. PHMSA is also required by Executive Orders 12866
and 13563 to ensure that the benefits of its rules justify the costs,
to the extent permitted by law. PHMSA has prepared an initial
regulatory impact analysis for this proposed rule, which is available
in the docket for this rule. PHMSA encourages the commenter as well as
other members of the public to review the analysis and provide input
for improving the final rule.
16. AGA and several pipeline operators commented that, while
enhancements can be made, IM requirements need not be subjected to
wholesale change. They cited GAO and NTSB reports on the efficacy of
transmission pipeline integrity management and the lack of pipeline
safety issues among the NTSB's ``Most Wanted'' issues.
Response
While PHMSA believes that IM has led to improvements in managing
pipeline integrity, recent incidents and accidents demonstrate that
much work remains to improve pipeline safety.
17. AGA and pipeline operators noted that transmission and
distribution integrity management are not distinct activities for most
intrastate pipeline operators. They contended that the ANPRM seemed to
be based on a presumption that operators manage their transmission and
distribution pipeline safety differently, and that this assumption is
without basis.
Response
PHMSA has promulgated specific IM rules for both transmission and
distribution systems with a view toward allowing operators to customize
their performance based programs as appropriate to their specific
systems.
18. AGA and several pipeline operators suggested that any changes
to public awareness requirements should be made at the state level.
They noted that federal requirements in this area are new and that
effectiveness reviews are still in progress.
Response
This issue is not within the scope of the ANPRM. However, PHMSA has
revised the pipeline safety regulations related to pipeline damage
prevention programs in a final rule issued July 23, 2015 (80 FR 43836).
19. NACE International suggested that adopting its standards for
corrosion control would be the best means to accomplish the goal of
maintaining pipelines safe and functional for long periods of time.
Response
This NPRM proposes to incorporate industry consensus standards into
the regulations for assessing the physical condition of in-service
pipelines using in-line inspection, internal corrosion direct
assessment, and stress corrosion cracking direct assessment. In
addition, this NPRM proposes to enhance subpart I requirements for
corrosion control and to revise Appendix D to improve requirements for
cathodic protection.
20. The NTSB commented that regulations for gas transmission
pipelines can and should be improved and expressed its support for the
overall intent of the ANPRM. The NTSB noted publication of the ANPRM
prior to its recommendations resulting from the San Bruno incident
investigation precluded any mention in the ANPRM of these NTSB safety
recommendations. The NTSB suggested PHMSA should seek comment on its
recommendations.
Response
PHMSA has reviewed the NTSB recommendations that were issued on
September 26, 2011 and found that several recommendations related
directly to the topics addressed in the ANPRM and that may impact the
proposed approach to rulemaking. The topics impacted are discussed
above in the Background section above, in sections II.C and II.E, and
include NTSB Recommendations P-11-10, P-11-11, P-11-14, P-11-15, P-11-
17, and P-11-19. The NTSB's other recommendations will be addressed in
separate proceedings.
21. El Paso suggested that the proper approach to attain the
highest pipeline safety levels is through a structured, deliberate
rulemaking that closely examines all issue aspects prior to making
informed decisions.
Response
PHMSA agrees and is taking a careful, structured, and phased
approach to enhancing pipeline safety regulations and IM performance
standards.
22. Thomas M. Lael, a pipeline industry consultant, suggested any
new regulations be concise and clear. He contended past lack of clarity
has created the need for many re-interpretations and enforcement
problems.
Response
PHMSA concurs but also notes that performance-based regulations, by
their nature, are not as specific, nor as easily measurable, as
prescriptive regulations, but are more likely to improve safety and the
cost-effectiveness of regulations. PHMSA provides guidance to help
stakeholders understand the intent and scope of performance-based
regulations.
General Public Comments
1. A member of the public stated that the ANPRM did not provide
specific options for consideration. As written, only those with direct
involvement in the industry could understand it well enough to comment.
Presenting the options more specifically would allow for better
informed public comment. The discussion should also include a regional
component, since issues affecting different states/regions are not the
same.
Response
By its nature, the ANPRM did not propose specific alternatives or
rules, but solicited input to help inform future proposals. This NPRM
provides specific proposed rules for public comment.
2. The Alaska Natural Gas Development Authority stated that the
regulations should require consideration of earthquakes, as recent
history shows they can be very important to safety of high-pressure gas
lines.
Response
Section 29 of the Act states that in identifying and evaluating all
potential threats to each pipeline segment, an operator of a pipeline
facility shall consider the seismicity of the area. Rulemaking for this
issue is addressed in this NPRM and would add requirements to
explicitly reference seismicity for data gathering and integration,
threat identification and implementation of preventive and mitigative
measures.
3. The Environmental Defense Fund pointed out that methane is a
very potent greenhouse gas. They commented that PHMSA should consider
and minimize the potential environmental effects of any future
rulemaking. They suggested EPA's Natural Gas Star program as a model.
[[Page 20741]]
Response
The proposals in this rulemaking are designed to minimize the risk
of pipeline failures, which will result in environmental benefits. The
draft environmental assessment addresses the environmental effects of
this rulemaking.
In addition, the RIA provides estimates of the environmental
benefits of this proposed rule. Natural gas transported in transmission
pipelines contains heat-trapping gases that contribute to global
climate change and its attendant societal costs. Of these gases, of
primary importance for evaluation are methane--by far, the largest
constituent of natural gas--and carbon dioxide. Other natural gas
components (ethane, propane, etc.) contribute as well, but they account
for a much smaller percentage of the natural gas mixture and, as a
result, are much less significant than methane in terms of their
environmental impact. The proposed rule is expected to prevent
incidents, leaks, and other types of failures that might occur, thereby
preventing future releases of greenhouse gases (GHG) to the atmosphere,
thus avoiding additional contributions to global climate change. PHMSA
estimated net GHG emissions abatement over 15 years of 69,000 to
122,000 metric tons of methane and 14,000 to 22,000 metric tons of
carbon dioxide, based on the estimated number of incidents averted and
emissions from pressure tests and ILI upgrades.
4. A member of the public questioned the openness and clarity of
PHMSA's enforcement of pipeline safety regulations, and the use of
civil penalty revenues.
Response
This comment is not within the scope of the ANPRM topics, however,
it should be noted that PHMSA embraces transparency in its regulatory
oversight program and has established a Pipeline Safety Stakeholder
Communications Web site, https://primis.phmsa.dot.gov/comm/, which
presents a variety of reports detailing enforcement activity. These
reports are offered on both nationwide and operator-specific bases.
5. One member of the public suggested that DOT define ``safe
corridors'' for above-ground construction of pipelines. The commenter
suggested this would be similar, in principle, to the interstate
highway system. It would help to keep pipelines separated from
residences, avoid corrosive environments, and make pipelines available
for routine direct examination. At a minimum, this commenter suggested
the regulations should specify a minimum separation between new
pipelines and residences, as does the New Jersey state code, or
homebuyers be informed when a home is within the potential impact
radius of a gas transmission pipeline so they may make an informed
buying decision.
Response
This comment addresses pipeline siting and routing, which is
outside the scope of PHMSA's statutory authority. As specified in 49
U.S.C. 60104, Requirements and Limitations of the Act, PHMSA is
prohibited from regulating activities associated with locating and
routing pipelines. Paragraph (e) of the statute states ``Location and
routing of facilities.--This chapter does not authorize the Secretary
of Transportation to prescribe the location or routing of a pipeline
facility.'' However, PHMSA is an active participant in the Pipeline and
Informed Planning Alliance (PIPA) and encourages all stakeholders to
learn about, and become involved with, PIPA. More information can be
obtained online at: https://primis.phmsa.dot.gov/comm/pipa/landuseplanning.htm.
6. One member of the public noted there is an increasing trend in
significant incidents and suggested that this trend may be related to
undue influence of the pipeline industry on the regulations under which
it operates. The commenter recommended regulations should not be
weakened in favor of industry. The League of Women Voters of
Pennsylvania also recommended that regulatory agencies be insulated
from political and other influences of natural gas pipeline companies
to avoid the appearance of a conflict of interest.
Response
PHMSA appreciates these comments. PHMSA is committed to improving
pipeline safety, and that is the goal of this endeavor. Significant
incidents on Gas Transmission (GT) pipelines have averaged between 70
and 80 incidents per year over the past 9 years. The existing integrity
management regulations in 49 CFR part 192, subpart O, addresses
pipeline integrity in HCAs, which is only about 7 percent of the GT
pipeline mileage. This proposed NPRM is focused on strengthening
requirements in HCAs and applying integrity management principles to
areas outside HCAs to better address safety issues. In addition, the
proposed rule seeks to address significant issues that caused or
contributed to the San Bruno accident, which include lack of pressure
test, inadequate records, poor materials, and inadequate integrity
assessment. The operator reports submitted to PHMSA as mandated by the
Act confirm that these issues are widespread for both HCA and non-HCA
pipe segments.
7. The Harris County Fire Marshall's Office (HCFM) suggested
stiffer regulations are needed for gas transmission pipeline safety,
because of the large potential for negative impact and catastrophic
consequences. HCFM expressed concern about corrosion control and
current inspection practices for aging transmission infrastructure.
Response
This NPRM proposes enhanced corrosion control requirements,
including periodic close interval surveys, post construction surveys
for coating damage, and interference current surveys. This NPRM also
proposes enhanced requirements for internal corrosion and external
corrosion management programs.
8. The Pipeline Safety Trust (PST) commented that the ANPRM,
itself, may heighten and fuel existing public concerns about pipeline
safety. PST noted that many of the questions asked the industry to
provide information they believe the public would believe PHMSA should
already have. PST expressed its view that the number and types of
questions asked in the ANPRM reflect gaps in PHMSA's knowledge of gas
transmission pipeline systems and operator practices.
Response
PHMSA appreciates these comments. PHMSA is committed to improving
pipeline safety and stakeholder input is valuable to the regulatory
process.
9. Professional Engineers in California Government (PECG) commented
that private companies should not be solely responsible for the safety
of their pipelines. PECG contended that this approach has not worked.
PECG also suggested PHMSA examine options for increasing the number of
inspectors at state pipeline regulatory agencies and require public
inspectors be on site for pipeline construction and testing. They
contended such inspection is necessary to assure that older pipelines
are tested adequately and replaced when needed.
Response
PHMSA appreciates these comments. PHMSA is committed to ensuring
that operators maintain and operate their pipelines safely. This
rulemaking contains a number of measures aimed at enhancing oversight.
10. The City and County of San Francisco (CCSF) noted the scope of
potential rulemaking discussed in the
[[Page 20742]]
ANPRM did not include consideration of PHMSA's coordination with and
oversight of state certified agencies. In order to ensure the proper
oversight over natural gas transmission operators and the safe
operation of natural gas transmission lines, CCSF believes PHMSA must
address its state certification program and its oversight of state
enforcement of pipeline safety standards. CCSF recommended PHMSA
publish regulations for certification of state programs. They cited
NTSB recommendation P-11-20 and asserted PHMSA has not corrected
inadequate practices of the California Public Utilities Commission.
Response
This comment is outside the scope of this rulemaking. PHMSA is
addressing NTSB recommendation P-11-20 separately.
11. Two members of the public suggested the processes of the
Federal Energy Regulatory Commission (FERC) for siting pipelines should
be revised. One suggested a Commission on Public Accountability and
Safety Standards be established, consisting of a majority of local
public officials, first responder experts, and independent qualified
engineers, to make recommendations for FERC's pre-application process
and standards. The purpose would be to assure standards require public
accountability for review and vetting of pipeline safety issues with
local authorities when pipelines are proposed. The other commenter
suggested the relationship between FERC and DOT should be clarified,
that a company's enforcement history be taken into account in siting
decisions, and PHMSA be a full party to all FERC proceedings. The
commenter believes this is necessary because FERC does not have a
public safety mandate.
Response
PHMSA is a separate agency from FERC and has no statutory authority
with respect to pipeline siting or approval. As specified in 49 U.S.C.
60104, Requirements and Limitations of the Act, PHMSA is prohibited
from regulating activities associated with locating and routing
pipelines. Paragraph (e) of the statute states ``Location and routing
of facilities.--This chapter does not authorize the Secretary of
Transportation to prescribe the location or routing of a pipeline
facility.'' However, PHMSA is an active participant in the Pipeline and
Informed Planning Alliance (PIPA) and encourages all stakeholders to
learn about, and become involved with, PIPA. More information can be
obtained online at: https://primis.phmsa.dot.gov/comm/pipa/landuseplanning.htm.
12. Two members of the public commented federal regulations should
not override local ordinances. They noted the concern of local
authorities is safety, while others are concerned about industry costs.
They believe federal regulations that allow operators significant
discretion are a poor basis to supersede specific local requirements.
Response
PHMSA appreciates these comments. Federal regulations provide for a
uniform body of standards and requirements related to pipeline safety.
PHMSA is receptive to input from state and local authorities on
pipeline safety issues. States and local authorities may adopt
requirements that are more stringent than and consistent with the
federal regulations for their intrastate pipelines if they have a 49
U.S.C. 60105 certification.
13. One member of the public suggested regulations require periodic
safety audits by an auditor not selected by the pipeline operator. The
commenter further suggested that local authorities should have approval
authority in the choice of the auditor. The commenter contended this
approach would strengthen public confidence in pipeline safety.
Response
PHMSA appreciates this comment. Highly trained federal and state
pipeline inspectors conduct inspections of pipeline operators, their
facilities, and their compliance programs on a regular basis.
Comments on ANPRM Section II Topics on Which PHMSA Sought Comment
In section II of the ANPRM, commenters were urged to consider
whether additional safety measures are necessary to increase the level
of safety for those pipelines that are in non-HCA areas as well as
whether the current IM requirements need to be clarified and in some
cases enhanced to assure that they continue to provide an adequate
level of safety in HCAs. PHMSA posed specific questions to solicit
stakeholder input. These included questions related to the following
topics:
A. Modifying the Definition of HCA,
B. Strengthening Requirements to Implement Preventive and
Mitigative Measures for Pipeline Segments in HCAs,
C. Modifying Repair Criteria,
D. Improving Requirements for Collecting, Validating, and
Integrating Pipeline Data,
E. Making requirements Related to the Nature and Application of
Risk Models More Prescriptive,
F. Strengthening Requirements for Applying Knowledge Gained Through
the IM Program
G. Strengthening Requirements on the Selection and Use of
Assessment Methods,
H. Valve Spacing and the Need for Remotely or Automatically
Controlled Valves,
I. Corrosion Control,
J. Pipe Manufactured Using Longitudinal Weld Seams,
K. Establishing Requirements Applicable to Underground Gas Storage,
L. Management of Change,
M. Quality Management Systems (QMS),
N. Exemption of Facilities Installed Prior to the Regulations,
O. Modifying the Regulation of Gas Gathering Lines.
Each topic is summarized as presented in the ANPRM, then general
comments related to the topic are presented, followed by each
individual question and comments received for the question.
A. Modifying the Definition of HCA
The ANPRM stated that ``IM requirements in subpart O of part 192
specify how pipeline operators must identify, prioritize, assess,
evaluate, repair and validate; [sic] through comprehensive analyses,
the integrity of gas transmission pipelines in HCAs. Although operators
may voluntarily apply IM practices to pipeline segments that are not in
HCAs, the regulations do not require operators to do so. A gas
transmission pipeline ruptured in San Bruno, California on September 9,
2010, resulting in eight deaths and considerable property damage. As a
result of this event, public concern has been raised regarding whether
safety requirements applicable to pipe in populated areas can be
improved. PHMSA is thus considering expanding the definition of an HCA
so that more miles of pipe are subject to IM requirements.'' The ANPRM
then listed questions for consideration and comment. The following are
general comments received related to the topic as well as comments
related to the specific questions:
General Comments for Topic A
1. INGAA and a number of pipeline operators noted this is an
opportune time for considering the next steps in integrity management,
since baseline assessments under the current IM rules are now being
completed. INGAA noted its policy goal is to apply IM principles
[[Page 20743]]
(as described in ASME/ANSI B31.8S) beyond HCAs, covering 90 percent of
people living near transmission pipelines by 2020 and 100 percent by
2030. TransCanada submitted information in support of INGAA's proposal,
noting that by the end of 2012 the company will have assessed more than
85 percent of its US pipeline mileage covering more than 95 percent of
people living near their pipelines. Thus, the current IM rules are
having a significant positive impact on pipeline safety. TransCanada
believes significant technological challenges would be encountered if
IM regulations were extended to all pipelines.
2. MidAmerican commented it would be reasonable to differentiate
between transmission pipelines operating above and below 30 percent
specified minimum yield strength (SMYS) in terms of IM requirements.
They estimated that less than 3 percent of local distribution company
(LDC) transmission lines operate at greater than 30 percent SMYS.
3. MidAmerican and a member of the public suggested PHMSA eliminate
class locations in favor of better-defined HCAs. They contend such a
change would result in administrative savings for pipeline operators.
4. Southwest Gas and Paiute commented no new regulations should be
promulgated in this area until the study required by the Pipeline
Safety, Regulatory Certainty, and Job Creation Act of 2011 is
completed.
Response to General Comments for Topic A
PHMSA appreciates the information provided by the commenters.
Section 5 of the Pipeline Safety, Regulatory Certainty, and Job
Creation Act of 2011 (the Act) (Pub. L. 112-90) requires the Secretary
of Transportation to ``evaluate (1) whether integrity management system
requirements, or elements thereof, should be expanded beyond high-
consequence areas; and (2) with respect to gas transmission pipeline
facilities, whether applying integrity management program requirements,
or elements thereof, to additional areas would mitigate the need for
class location requirements.'' PHMSA has completed the report mandated
by the Act that documents that evaluation and addresses whether
integrity management (IM) program requirements should be expanded
beyond high consequence areas (HCAs) and, specifically for gas
transmission pipelines regulated under 49 Code of Federal Regulations
(CFR) part 192, whether such expansion would mitigate the need for
class location designations and corresponding requirements. The class
location report is available for review in the docket.
In October 2010 and August 2011, the Pipeline and Hazardous
Materials Safety Administration (PHMSA) published notices in the
Federal Register to solicit comments on revising the pipeline safety
regulations applicable to hazardous liquid and natural gas transmission
pipelines including expansion of IM program requirements beyond HCAs.
In general, industry representatives and pipeline operators were
opposed to any expansion of HCAs and in favor of eliminating class
locations on newly constructed pipelines, whereas public interest
groups were in favor of expanding HCA but against curtailing class
location requirements.
PHMSA has carefully considered the input and comments. At this time
PHMSA plans to propose an approach that balances the need to provide
additional protections for persons within the potential impact radius
(PIR) of a pipeline rupture (outside of a defined HCA), and the need to
prudently apply IM resources in a fashion that continues to emphasize
the risk priority of HCAs. PHMSA, therefore, is considering an approach
that would require selected aspects of IM programs (namely, integrity
assessments and repair criteria) to be applicable for non-HCA segments.
For hazardous liquid pipelines, PHMSA would propose to apply these
requirements to non-HCA pipeline segments. For gas transmission
pipelines, PHMSA would propose to apply these requirements where
persons live and work and could reasonably be expected to be located
within a pipeline PIR. Under this approach, PHMSA would propose
requirements that integrity assessments be conducted, and that
injurious anomalies and defects be repaired in a timely manner, using
similar standards in place for HCAs. However, the other program
elements of a full IM program contained in 49 CFR part 192, subpart O,
or 49 CFR 195.452 (as applicable) would not be required for non-HCA
segments.
The Act also required the Secretary of Transportation to evaluate
if expanding IM outside of HCAs, as discussed above, would mitigate the
need for class location requirements. In August 2013, PHMSA published a
notice in the Federal Register (78 FR 53086) soliciting comments on
expanding IM program requirements and mitigating class location
requirements. In addition, PHMSA held a Class Location Workshop on
April 16, 2014, to discuss the notice and comments were received from
stakeholders, including industry representatives, pipeline operators,
state regulatory agencies, and the public. Overall, the majority of
stakeholder responses suggested that PHMSA not change the current class
location approach for class locations and class location changes as
population increases used for establishing MAOP and operation and
maintenance (O&M) surveys for existing pipelines. For new transmission
pipelines, some industry groups and operators supported some type of
bifurcated approach for existing and new pipelines as described above.
Based upon stakeholder input and findings from lessons learned,
incident investigations, assessments, IM, and operating, maintenance,
design and construction considerations, PHMSA believes the application
of integrity management assessment and remediation requirements to MCAs
does not warrant elimination of class locations. Class locations affect
all gas pipelines, including transmission (interstate and intrastate),
gathering, and distribution pipelines, whether they are constructed of
steel pipe or plastic pipe. Class location is integral to determining
MAOPs, design pressures, pipeline repairs, high consequence areas
(HCAs), and operating and maintenance inspections and surveillance
intervals. Class locations affect 12 subparts and 28 sections of 49 CFR
part 192 for gas pipelines. The subparts and sections are listed and
discussed in Sections 3.1.2.4 and 3.7.2.2. While assessment and
remediation of defects on gas transmission pipelines is an important
risk mitigation program, it does not adequately compensate for other
aspects of class location as it relates to other types of gas pipelines
and as it relates (for all gas pipelines) to the original pipeline
design and construction such as the design factor, initial pressure
testing, establishment of MAOP, O&M activities, and other aspects of
pipeline safety, that are based on class location. Thus, PHMSA has
determined not to eliminate class location requirements.
With respect to the application of gas transmission IM requirements
to pipeline operating at less than 30% SMYS, as part of its
consideration of the issues discussed in Topics J and N, PHMSA
considered but rejected the suggestion that pipelines operating less
than 30% SMYS be differentiated from those operating at higher stress
levels.
Comments submitted for questions in Topic A.
A.1--Should PHMSA revise the existing criteria for identifying HCAs
to expand the miles of pipeline included in HCAs? If so, what
amendments to the criteria should PHMSA consider (e.g.,
[[Page 20744]]
increasing the number of buildings intended for human occupancy in
Method 2?) Have improvements in assessment technology during the past
few years led to changes in the cost of assessing pipelines? Given that
most non-HCA mileage is already subjected to in-line inspection (ILI),
does the contemplated expansion of HCAs represent any additional cost
for conducting integrity assessments? If so, what are those costs? How
would amendments to the current criteria impact state and local
governments and other entities?
1. INGAA, industry consultant Thomas Lael, and a number of pipeline
operators commented that modification of the HCA definition is
unnecessary. They contended that the current definition is already
risk-based and provides an effective basis for IM requirements along
with a reasonable point from which to expand the application of IM
principles by voluntary action. Accufacts commented that PHMSA should
focus on closing gaps and loopholes rather than increasing HCA mileage,
and that increasing covered mileage would only create the illusion of
more safety.
2. AGA, APGA, and a number of gas distribution pipeline operators
also opposed changes to the definition. They commented that other
requirements of part 192 already address the primary threats for pipe
outside HCA. They noted that much effort went into establishing the
current definition, there is no safety rationale to abandon it, and
change would be inconsistent with risk-based principles and would
dilute safety efforts. AGA further noted that imprudent expansion would
be contrary to Congressional intent, in that it would dilute the focus
on densely populated and environmentally sensitive areas. AGA commented
that PHMSA should make no change in this area before completing the
related studies required by the Pipeline Safety, Regulatory Certainty,
and Job Creation Act of 2011.
3. Taking a contrary position, a number of commenters not
affiliated with the pipeline industry supported increasing the pipeline
mileage classified as HCA. One private citizen suggested that all
pipelines in cities with population greater than 100,000 should be
classified as HCA. This commenter believes that existing regulations
result in insufficient requirements for urban pipelines. Another
citizen suggested that all high-stress lines with a ``receptor,'' which
he defines as ``something which needs to be protected,'' should be
assessed. If changes to the HCA definition are needed to accomplish
this, then he contended those changes should be made. The Pipeline
Safety Trust would strengthen IM requirements and expand them to all
transmission pipelines, although they allow that the details could be
different for pipelines not currently classified as HCA. PST believes
this would be an effective way to identify and eliminate threats.
4. The Oklahoma Independent Petroleum Association (OKIPA) commented
that any changes to the HCA definition must be supported by a
scientifically-valid assessment of risks and a complete cost-benefit
analysis.
5. The Iowa Association of Municipal Utilities commented that PHMSA
should not revise the HCA definition without taking into account the
differences between high-pressure transmission pipelines and low-
pressure, low-risk lines that are also classified as transmission. IAMU
reported ``transmission lines'' operated by Iowa Municipal Utilities
are typically 2 to 4 inches in diameter and have potential impact radii
less than 90 feet.
6. The Texas Pipeline Association and Texas Oil & Gas Association
contended that expanding HCA pipeline mileage would increase assessment
costs, particularly if the arbitrary requirement for reassessments
every 7 years is not changed. These associations also believe that
additional assessments will result in significant service
interruptions. They suggested that assessment requirements be expanded
to other pipelines, if needed, rather than changing the definition of
HCA, contending that this would allow a more reasoned approach not
burdened by the requirement for 7-year reassessments.
7. The Texas Pipeline Association, Texas Oil & Gas Association and
several pipeline operators disagreed with the ANPRM assertion that most
non-HCA transmission pipeline has been subject to ILI inspections. They
noted much non-HCA pipeline has been pigged (i.e., assessed using an
in-line inspection tool) but that intrastate transmission pipelines are
typically not piggable.
8. MidAmerican suggested that there is no reason to believe that
changes to the HCA definition would improve safety. They also noted
that the effects of other recent regulatory changes have not yet been
realized and could mask any effect of changes in HCA. At the same time,
the company noted that revising the definition of an HCA to encompass
potential impact circles with 15 structures intended for human
occupancy, vs. the current 20, would increase the amount of HCA mileage
on its pipeline system by about 10 percent, contending that the safety
benefit of such a change would be questionable. They suggested it would
be better to focus on pipe in HCAs rather than adding lower-risk pipe,
since part 192 already provides a good level of safety for all
pipelines.
9. INGAA and a number of pipeline operators commented that
increasing the amount of HCA mileage would add or increase costs for
hundreds of state and local government agencies. The increases would
result from increased demands for identification, certification, and
compliance auditing.
10. Northern Natural Gas suggested that PHMSA consider expanding
HCA coverage by modifying the specifics of Method 2 for defining HCAs
over time. Changes could include reducing the number of structures in
potential impact circles that define an HCA, reducing the number of
people that defines an identified site, etc. The company believes this
kind of change would have the benefit of continued use of the
``science'' represented by the C-FER Technologies circle for
determining HCAs (see part 192, appendix E, figure E.I.A). Northern
also suggested PHMSA define a time period for occupation of an
identified site which, they contended, would eliminate the need to
address locations where a gathering of people is truly transient.
11. TransCanada reported its belief that the current HCA criteria
provide an appropriate risk focus. In support of this belief, they
noted that only 3 percent of their US transmission pipeline mileage is
in HCAs but this includes 45 percent of the population within a
potential impact radius of their pipelines.
12. The Iowa Utilities Board opposed changes to the HCA criteria to
encompass more mileage. IUB commented that such changes would divert
resources from application to higher-risk pipeline segments and there
has been no demonstration that non-HCA pipeline segments pose as much
risk as those currently defined as HCA.
13. Two private citizens and the Commissioners of Wyoming County,
Pennsylvania, suggested the existence of one structure intended for
human occupancy within a potential impact circle should be sufficient
to define an HCA. These commenters noted that catastrophic consequences
(i.e., loss of life) are still possible in such sparsely populated
areas. The Commissioners noted homes in their jurisdiction generally
did not encroach on the pipelines; the homes were there first and the
pipeline encroached on what should have been a safe zone around the
home. They implied pipeline operators should expect a higher burden to
assure safety in such circumstances.
[[Page 20745]]
14. The Pipeline Safety Trust commented that there should be a
single set of criteria defining HCAs and that these criteria should be
known to the public. They contended the public currently has no
information on the criteria defining HCAs.
15. The California Public Utilities Commission commented that HCA
criteria should be revised to include more pipeline mileage and that
method 2 (use of potential impact circles) should be eliminated.
16. The Alaska Natural Gas Development Authority suggested that the
definition of an HCA should accommodate the phenomenon of rapid growth
in previously rural areas. They noted that such growth has occurred
within Alaska due, in part, to disposal of state lands.
17. NAPSR suggested that PHMSA require all transmission pipelines
to meet Class 3 and 4 requirements and eliminate HCAs. NAPSR contended
that focusing resources on higher-risk pipelines is bad public policy,
since an accident anywhere poses a risk to public safety and reduces
public confidence.
18. The Texas Pipeline Association, Texas Oil & Gas Association and
several pipeline operators objected to the implication in the ANPRM
that assessment costs have decreased. They contended that costs have
actually increased due to such factors as operational cost escalation
and increased costs to address cased pipeline segments.
19. INGAA and a number of pipeline operators contended that costs
cannot be estimated accurately absent a specific regulatory proposal.
They suggested that additional costs would be minimal if expanding HCA
mileage results in actions similar to INGAA's Integrity Management--
Continuous Improvement (IMCI) action plan, but that costs could be high
if different requirements are imposed.
20. INGAA reported that a recent survey showed that its members'
identified baseline IM assessments will cover 64 percent of members'
pipeline mileage, only 4 percent of which is in HCAs. INGAA stated that
these assessments will have covered 90 percent of the population within
a potential impact radius of the pipelines.
21. Southwest Gas and Paiute provided cost estimates for conducting
IM assessments on their pipeline systems: $45,000 per mile for direct
assessment, up to $125,000 per mile for in-line inspection, and from
$200,000 to $2 million per instance where changes need to be made to a
pipeline to accommodate instrumented pigs.
22. The California Public Utilities Commission and MidAmerican
commented that costs would increase if the changes suggested in the
ANPRM were made, but they provided no specific estimates.
23. APGA noted that costs incurred by or passed on to municipal
utilities are costs to local governments, since the utilities are,
themselves, government agencies.
24. Paiute and Southwest Gas noted that costs to local governments,
including preparation of permits, paving repairs, etc., can be high.
25. An anonymous commenter suggested that costs are not likely to
increase much, since most operators already assess more than HCAs and
IM has fostered growth in ILI vendors.
26. Kern River noted that its costs would not increase much, since
the company is already under similar restrictive requirements via
special permit.
27. Accufacts noted that safety is not free. They suggested that
relative ranking of assessment methods, by cost, is not likely to have
changed. They cautioned that costs used in cost-benefit analyses
supporting any rules must be credible and should have an auditable
trail available to the public. They suggested that serious accidents
can be a ``cost'' of associated deregulation and lack of proper,
effective, and efficient safety regulatory oversight for this critical
infrastructure.
Response to Question A.1 Comments
PHMSA appreciates the information provided by the commenters. PHMSA
agrees that the definition of HCAs is adequate, and does not propose to
modify the definition of scope of HCAs in this proposed rulemaking.
However, to afford additional protections to other segments along the
pipeline, PHMSA is proposing to apply selected IM program elements
(namely assessment and remediation of defects) to areas outside HCAs
that are newly defined as MCAs. PHMSA believe this approach applies
appropriate risk-based levels of safety.
A.2. Should the HCA definition be revised so that all Class 3 and 4
locations are subject to the IM requirements? What has experience shown
concerning the HCA mileage identified through present methods (e.g.,
number of HCA miles relative to system mileage or mileage in Class 3
and 4 locations)? Should the width used for determining class location
for pipelines over 24 inches in diameter that operate above 1000 psig
be increased? How many miles of HCA covered segments are Class 1, 2, 3,
and 4? How many miles of Class 2, 3, and 4 pipe do operators have that
are not within HCAs?
A.3. Of the 19,004 miles of pipe that are identified as being
within an HCA, how many miles are in Class 1 or 2 locations?
1. Industry trade associations, pipeline operators, and the Iowa
Utilities Board objected to the suggestion all Class 3 and 4 locations
should be treated as HCA. They noted class location does not have a
direct relationship to risk. Small, low-pressure pipelines with no
structures intended for human occupancy within the PIR (or for which
the PIR is contained entirely within the right of way) could be Class 3
or 4 under current definitions. INGAA noted approximately 90 percent of
Class 3 and 4 mileage not in HCA is presently assessed through over
testing during IM assessments. Kern River commented that class location
is an outmoded system that is confusing and unduly complex. Many of
these commenters noted there is no demonstration of need for including
all Class 3 and 4 areas, since existing HCA criteria adequately
identify areas posing higher risks.
2. Public commenters took a contrary position, suggesting class
locations are a reasonable basis for increasing HCA mileage. Pipeline
Safety Trust and California Public Utilities Commission commented all
Class 3 and 4 locations should be HCA. They noted these are all highly
populated areas putting more people at risk from pipeline accidents.
CPUC noted the location of the significant 2010 pipeline accident in
San Bruno, CA, could have avoided HCA classification if method 2 of the
current definition had been used. An anonymous commenter supported this
position, suggesting all Class 3 and 4 locations be treated as HCA and
use of method 2 be restricted to Class 1 and 2 locations; this
commenter contended use of method 2 to exclude some portions of Class 3
and 4 locations from HCA classification is inappropriate. This
commenter further suggested the definition of Class 4 locations be
revised, contending that the criterion of 4-story buildings being
``prevalent'' is not specific enough. Thomas Lael, an industry
consultant, suggested all Class 4 locations should be HCA. Lael
contended that this would be an easy change and would assure that the
highest risk pipe is included.
3. NAPSR also suggested all Class 3 and 4 locations should be
classified as HCA. NAPSR noted this is an alternative to their
preferred solution of eliminating HCA and requiring that all
transmission pipelines meet Class 3 and 4 requirements.
[[Page 20746]]
4. One public commenter went further. He suggested a new
classification, Class 5, be established encompassing all pipeline in
cities with populations of more than 100,000. He further suggested pipe
in this new class should meet enhanced construction requirements,
including required installation of automatic valves to isolate the
pipeline in the event of an incident. He contended the existing
regulations impose inadequate safety requirements on urban pipelines.
5. Accufacts suggested PHMSA focus first on closing loopholes and
gaps rather than increasing HCA mileage. They commented increasing
covered mileage without closing gaps would produce only the illusion of
safety.
6. Northern Natural Gas suggested PHMSA consider an option of
eliminating method 2 of the current HCA definition. They contended such
a change would be easy to accomplish. At the same time, they questioned
its efficacy, suggesting that it would result in limited or no increase
in safety while imposing large costs.
7. INGAA and many pipeline operators objected to the suggested
increase in the width of a class location unit for larger, high-
pressure pipelines. They noted such a change would contravene the goals
of IM and divert resources to pipe of lower risk, and pipe of this type
posing high risks to population concentrations is already included as
HCA based on its potential impact radius (which could be larger than
220 yards).
8. Here, again, public commenters generally took a contrary
position. Pipeline Safety Trust suggested class location width should
be at least as much as the potential impact radius. PST noted the PIR
is intended to focus on areas requiring more protection while the
existing class location width is arbitrary. Two private citizens
agreed, one noting that large-diameter, high-pressure gathering
pipelines in the Marcellus shale area are located slightly more than
220 yards from pre-existing houses and the other suggesting the class
location width in higher-class areas should be 220 yards or the PIR,
whichever is larger. Accufacts would go further, suggesting class
location width be increased for large-diameter pipe regardless of
pressure. Accufacts contended diameter is a more significant factor in
determining the potential extent of post-accident damage than is
pressure, noting the devastation resulting from the San Bruno accident
extended to a much greater distance than the PIR. The Texas Pipeline
Association and Texas Oil & Gas Association commented no change should
be made until the studies required by the Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011 are completed.
9. INGAA and a number of pipeline companies submitted data
concerning the amount of pipeline mileage currently in HCAs. INGAA's
data is based on a survey of its members.
----------------------------------------------------------------------------------------------------------------
INGAA Paiute SWGas MidAmerican Northern Natural
----------------------------------------------------------------------------------------------------------------
Class 1........... 475 miles HCA, 1 mile HCA, 632 <1 of 382 miles 0.63 miles HCA, 0.1% of all
103,286 not. not. are HCA. 493.11 not. mileage is HCA.
Class 2........... 535 miles HCA, 0 miles HCA, 55 <1 of 20 miles 0.98 miles HCA, 2% of mileage is
11,318 not. not. are HCA. 101.92 not. HCA.
Class 3........... 4,100 miles HCA, 26 miles HCA, 142 185 miles HCA, 44.96 miles HCA, 27% of mileage
4, 646 not. not. 242 not. 128.38 not. is HCA.
Class 4........... 24 miles HCA, 5 None of less than 6 miles HCA, 5 no HCA mileage... no data
not. 1 mile is HCA. not. reported.
----------------------------------------------------------------------------------------------------------------
10. Iowa Association of Municipal Utilities reported its members
have zero HCA miles in any class. Most member transmission pipelines
are in Class 1 locations. Members have 1.46 miles of Class 2 pipe and
one mile in Class 3.
11. Ameren Illinois reported 3.5 of its 82 HCA miles are in Class 1
or 2.
12. Kern River reported it has 18.51 HCA miles in Class 1 and 3.14
miles in Class 2, of a total of 95.96 miles of HCA.
13. On March 15, 2012, PHMSA received a petition for rulemaking
from the Jersey City Mayor's office contending that the current Class
Location system ``does not sufficiently reflect high density urban
areas, as the regulation fails to contemplate either (1) the dramatic
differences in population densities between highly congested areas and
other less dense Class 4 Locations, or (2) the full continuum of
population densities found in urban areas themselves.'' Based on this,
Jersey City petitioned PHMSA to add three (3) new Class Locations,
which would be defined as follows:
A Class 5 location is any class location unit that
includes one or more building(s) with between four (4) and eight (8)
stories;
A Class 6 location is any class location unit that
includes one or more building(s) with between nine (9) and forty (40)
stories;
A Class 7 location is any class location unit that
includes at least one building with at least forty-one (41) stories.
Response to Questions A.2 and A.3 Comments
PHMSA appreciates the information provided by the commenters. PHMSA
agrees that HCAs should not be based exclusively on class location.
Similarly, PHMSA does not propose to define MCAs based on class
location. PHMSA proposes that moderate consequence area means an
onshore area that is within a potential impact circle, as defined in
Sec. 192.903, containing five (5) or more buildings intended for human
occupancy, an occupied site, or a right-of-way for a designated
interstate, freeway, expressway, and other principal 4-lane arterial
roadway as defined in the Federal Highway Administration's Highway
Functional Classification Concepts, Criteria and Procedures, and does
not meet the definition of high consequence area, as defined in Sec.
192.903. This assures a comparable level of safety for all pipelines,
regardless of class location. As a result, PHMSA is not proposing to
expand class locations in this proposed rule. The issue of expanding
class locations is addressed in the class location report which is
available for review in the docket while formulating comments.
A.4. Do existing criteria capture any HCAs that, based on risk, do
not provide a substantial benefit for inclusion as an HCA? If so, what
are those criteria? Should PHMSA amend the existing criteria in any way
which could better focus the identification of an HCA based on risk
while minimizing costs? If so, how? Would it be more beneficial to
include more miles of pipeline under existing HCA IM procedures, or, to
focus more intense safety measures on the highest risk, highest
consequence areas or something else? If so why?
1. INGAA and several pipeline operators commented the method
described in paragraph 2 in the
[[Page 20747]]
definition of HCA in Sec. 192.903 appropriately focuses attention on
at-risk populations. They contended that the method described in
paragraph 1 in the definition of HCA in Sec. 192.903 captures some
inappropriate areas.
2. Texas Pipeline Association, Texas Oil & Gas Association, and
Ameren Illinois contended the existing criteria do not capture areas
not posing risk. They noted the criteria were based on the science of
pipeline accidents to identify high-risk areas.
3. Paiute and Southwest Gas commented neither more HCA miles nor
additional safety measures are needed. They contended existing criteria
are adequate and rule provisions for preventive and mitigative measures
and to consider pipe with similar conditions when anomalies are found
in HCA are sufficient to address non-HCA pipeline segments.
4. APGA recommended the regulations be modified to treat
transmission pipelines operated by local distribution companies, most
of which operate at less than 30 percent SMYS, under distribution
integrity management rather than transmission IM. APGA suggested this
is an optimum time to make this change, which was discussed in the
phase 1 work leading up to the distribution IM rule. Atmos agreed,
noting failure by leakage rather than rupture, similar to distribution
pipelines, is much more prevalent for this low-stress pipeline and it
thus poses much lower risks.
5. Northern Natural Gas suggested PHMSA revisit its treatment of
``well defined areas'' that constitute identified sites. They contended
current practice treats an entire area as an identified site even if
only an unoccupied corner is within the PIR and persons congregating
are outside that critical radius.
6. MidAmerican suggested PHMSA consider adding a multiplier to the
PIR equation for higher-stress pipelines. They contended this could
capture more high-risk pipe without adversely affecting low-stress
pipelines that pose considerably less risk.
7. Atmos commented no change should be made which would increase
the amount of HCA mileage, contending that this would dilute the
current focus on high-risk pipe.
8. INGAA and several of its members suggested PHMSA rely on its
Integrity Management--Continuous Improvement (IMCI) initiative to
address pipeline in non-HCA areas.
Response to Question A.4 Comments
PHMSA appreciates the information provided by the commenters. PHMSA
agrees that the existing method for identifying HCAs and calculating
PIR is appropriate and is not proposing a change to either. However,
PHMSA disagrees that existing requirements are sufficient for non-HCAs
segments. PHMSA believes non-HCA segments where people congregate
should be afforded additional protections. Therefore, PHMSA is
proposing that selected IM program elements (assessment and remediation
of defects) be applied to MCAs.
A.5. In determining whether areas surrounding pipeline right-of-
ways meet the HCA criteria as set forth in part 192, is the potential
impact radius sufficient to protect the public in the event of a gas
pipeline leak or rupture? Are there ways that PHMSA can improve the
process of right-of-ways HCA criteria determinations?
1. INGAA, AGA, GPTC and a number of pipeline operators contended
the existing PIR criteria are sufficiently conservative. They noted the
criteria were derived from scientific analysis of the consequences of
past pipeline accidents. Texas Pipeline Association and Texas Oil & Gas
Association commented there is no reason to modify the PIR criteria or
to establish alternate criteria to define HCAs; they contended there is
no evidence the current PIR definition has provided insufficient
protection to the public.
2. One private citizen and Alaska's Department of Natural Resources
suggested HCA criteria should be revised to consider parallel pipelines
in a common right of way, contending that an accident on one pipeline
could impact adjacent lines, thus compounding consequences. They
further suggested requirements for pipelines in common rights of way
should include minimum spacing between the pipelines.
3. An anonymous commenter suggested plume releases be considered to
determine which pipeline segments can affect an HCA, contending that
this would be a good practice.
4. AGA, Texas Pipeline Association, Texas Oil & Gas Association,
GPTC, and several pipeline operators cautioned against use of the term
``right of way'' in the context of defining HCAs. They noted this term
is imprecise and the actual location of the pipeline, rather than an
ill-defined right of way, is the important factor in evaluating risk.
5. Accufacts, INGAA, and numerous pipeline operators cautioned
against discussions that imply that the PIR concept is applicable to
considerations of risk from pipeline leaks. These commenters noted that
the PIR is based on the consequences of a pipeline rupture and
resulting conflagrations and was never intended to address leaks not
involving fires.
6. ITT Exelis Geospatial Systems, a company providing services to
the pipeline industry, noted accurate location of a pipeline is as
important to assuring adequate protection of high-risk populations as
is the calculation of PIR.
7. Accufacts suggested PHMSA require a report of the actual impact
area, including aerial photographs, within 24 hours of any pipeline
rupture. Accufacts contended this data would provide a further basis
for continuing review of PIR adequacy.
Response to Question A.5 Comments
PHMSA appreciates the information provided by the commenters. PHMSA
agrees that the existing definition of PIR is appropriate at this time.
PHMSA believes that adjusting the PIR formula based on parallel
pipelines in the right-of-way, or other right-of-way factors, are
premature at this time. Also, PHMSA acknowledges that the PIR approach
only applies such incidents resulting in explosions and fires. While
certain gases might be better modeled using plume models, such models
have not been carefully studied or developed. However, PHMSA plans to
pursue (outside the scope of this rulemaking) additional incident
reporting requirements for the purpose of further evaluating the extent
of damage following incidents.
A.6. Some pipelines are located in right-of-ways also used, or
paralleling those, for electric transmission lines serving sizable
communities. Should HCA criteria be revised to capture such critical
infrastructure that is potentially at risk from a pipeline incident?
1. INGAA, AGA, Texas Pipeline Association, Texas Oil & Gas
Association, and many pipeline operators objected to any potential
inclusion of ``critical infrastructure'' in HCA criteria. They noted
there is no history of problems caused by impacts on infrastructure,
there is little public risk involved, data regarding such
infrastructure would be difficult for pipeline operators to obtain, and
issues involving potential interactions with critical infrastructure
are usually addressed during pipeline planning and construction.
2. GPTC and Nicor recommended HCA criteria not be revised to
include critical infrastructure. They noted the intent of defining HCAs
is to address risk to life and not property damage and damages to local
infrastructure are unlikely to result in consequences similar to those
that could affect population concentrations near the
[[Page 20748]]
pipeline. Atmos agreed, noting planning for accident-caused outages is
a responsibility of electric system operators.
3. Pipeline Safety Trust, Accufacts, NAPSR, Alaska Department of
Natural Resources, California Public Utilities Commission and ITT
Exelis Geospatial Systems recommended critical infrastructure be
included among HCA-defining criteria. Several of these commenters
suggested infrastructure beyond electric transmission be considered,
including, for example, water and sewage treatment plants, fire
stations, and communications facilities. The commenters noted damages
to critical infrastructure can lead to cascading effects and additional
public safety consequences. ITT Exelis acknowledged these
considerations may be secondary to loss of life but contended they are
still important to public safety.
4. Northern Natural Gas, Kern River, MidAmerican, Paiute, and
Southwest Gas noted determining the impact of damages to infrastructure
items is complex. These commenters suggested it is not practical to
define what constitutes ``critical'' infrastructure, from a public
safety standpoint, on a generic basis. They recommended PHMSA leave
consequence determination to operators, as part of their risk
assessments, providing additional guidance for such considerations if
needed.
5. An anonymous commenter suggested more frequent tests of cathodic
protection and coating surveys be required in areas potentially subject
to induced currents from nearby electric transmission infrastructure.
Response to Question A.6 Comments
PHMSA appreciates the information provided by the commenters. PHMSA
agrees that there have been relatively few pipeline incidents that have
had a major impact on critical infrastructure. PHMSA also acknowledges
that the PIR formula was developed based on life safety (i.e., heat
flux that result in fatalities). However, PHMSA is also aware of recent
incidents that, among other consequences, damaged and caused temporary
closure of interstate highways. Among them are the 2012 incident at
Sissonville, WV and the 2010 incident at New Delhi, LA, which also
resulted in one fatality. Even though PHMSA is not proposing to revise
the HCA criteria or the PIR formula, PHMSA is proposing to include
major highways in the MCA criteria.
A.7. What, if any, input and/or oversight should the general public
and/or local communities provide in the identification of HCAs? If
commenters believe that the public or local communities should provide
input and/or oversight, how should PHMSA gather information and
interface with these entities? If commenters believe that the public or
local communities should provide input and/or oversight, what type of
information should be provided and should it be voluntary to do so? If
commenters believe that the public or local communities should provide
input, what would be the burden entailed in providing provide this
information? Should state and local governments be involved in the HCA
identification and oversight process? If commenters believe that state
and local governments be involved in the HCA identification and
oversight process what would the nature of this involvement be?
1. INGAA and its pipeline operator members commented no additional
public involvement is needed. INGAA noted consultation is required
under the current regulations, and it seldom identifies any relevant
information. Additional involvement, INGAA contends, would likely lead
to inconsistencies and would degrade the technical/scientific basis for
determining HCAs.
2. AGA and several of its member companies suggested local
government agencies should provide information when requested by
pipeline operators. They contended additional required involvement
would pose an additional burden on pipeline operators while adding no
benefit. AGA noted information from its members suggests that local
government agencies very rarely point out identified sites not
otherwise known to the pipeline operator.
3. Texas Pipeline Association, Texas Oil & Gas Association, GPTC,
Nicor, Ameren Illinois and Oleksa and Associates (a pipeline industry
consultant) suggested further involvement of local governments not be
required. These commenters contended pipeline operators have more
relevant knowledge and involvement of inexperienced entities in
identifying HCAs is more likely to result in confusion than useful
information. The Texas associations suggested current public awareness
requirements afford sufficient involvement of local agencies.
4. Accufacts noted local governmental agencies have maps
identifying locations important to public safety and suggested these
maps should be used by pipeline operators in HCA determinations.
Accufacts believes this could assist operators in assuring
consideration of accurate, complete, and current information.
5. Northern Natural Gas reported it has a phone number and email
address that local residents and agencies can use to provide input to
its HCA determinations. Northern further reported no HCAs have been
identified from information provided via these avenues that were not
otherwise known to the company.
6. Public commenters suggested local residents and government
agencies should receive more information concerning pipelines and HCAs.
One commenter suggested operators should provide copies of IM plans
upon request, and should provide prior notification to residents within
a PIR of assessments and a subsequent report of assessment results or
problems otherwise identified. This individual also suggested locations
of HCAs and assessment trend results should be provided to local
communities upon request. The League of Women Voters of Pennsylvania
suggested distribution integrity management plans should be readily
available and the public should be involved in decisions related to
those plans.
7. Pipeline Safety Trust commented public review should be part of
any process by which PHMSA reviews or approves of HCA identifications.
8. Wyoming County Pennsylvania Commissioners suggested stakeholder
meetings and public comment periods be required as part of HCA
identification. They noted local residents know their communities
better than others, including expected changes that could affect HCA
identification.
9. AGA and several of its member operators recommended local
governments play no role in oversight of HCA determinations. They
contended this would increase burden and result in inconsistencies and
confusion.
10. An anonymous commenter suggested existing public awareness
contacts should be used to improve HCA determinations. The commenter
expressed the belief this existing structure could allow low-cost
involvement of local officials in such determinations.
11. The NTSB suggested PHMSA work with states to employ oversight
of pipeline IM plans based on objective metrics. The NTSB noted this
would be consistent with recommendation P-11-20 resulting from its
investigation of the San Bruno, CA pipeline accident.
12. Iowa Association of Municipal Utilities noted local government
employees are involved when HCA determinations are made by municipal
utilities and further requirements for
[[Page 20749]]
local involvement would be inappropriate for such operators.
Response to Question A.7 Comments
PHMSA appreciates the information provided by the commenters. PHMSA
is continuing to evaluate this aspect of integrity management but has
not yet reached any conclusions. PHMSA may consider this input for
future action, if applicable.
A.8. Should PHMSA develop additional safety measures, including
those similar to IM, for areas outside of HCAs? If so, what would they
be? If so, what should the assessment schedule for non-HCAs be?
1. Pipeline operators and their associations generally agreed
additional measures were not needed outside HCA. INGAA and several
transmission pipeline operators suggested operators be allowed to apply
the principles of ASME/ANSI B31.8S voluntarily, as needed. INGAA noted
this is the concept behind its Integrity Management--Continuous
Improvement (IMCI) initiative.
2. AGA and a number of its member operators noted the regulations
already require implementation of preventive and mitigative measures
outside of HCA for low-stress pipe (Sec. 192.935(d)). These
requirements include using qualified personnel to conduct work that
could adversely affect the integrity of the covered segment, collecting
excavation damage information, and participating in one-call systems.
3. Ameren Illinois and MidAmerican commented additional measures
are not needed, because existing operations & maintenance requirements
already assure integrity.
4. GPTC and Nicor agreed, noting it would be inappropriate to apply
IM measures outside of HCA and existing requirements are assuring an
adequate level of safety.
5. Atmos contended the existing provision requiring that operators
evaluate and remediate non-HCA pipeline segments when corrosion is
found during an IM assessment of a covered pipeline segment (Sec.
192.917(e)(5)) already provides that actions be taken to assure the
integrity of non-HCA pipeline segments.
6. Texas Pipeline Association and Texas Oil & Gas Association would
not object to a phased expansion of IM requirements provided that
required assessment intervals are scientifically based. The
associations noted Texas pipelines are already subject to the broader
requirements of the Texas IM rule. They commented phased implementation
would assure the next-highest risks are addressed first and would allow
time for IM-support resources to grow.
7. Iowa Association of Municipal Utilities commented new
requirements are not needed for its members' pipelines. These lines are
small-diameter, low-pressure, odorized, and already pose low risk.
8. Northern Natural Gas suggested PHMSA expand the HCA definition
gradually over time rather than imposing IM requirements outside HCA.
Northern commented such an approach would retain and expand the focus
on areas posing the highest risk.
9. Accufacts commented repair criteria, including required response
times, and reporting of anomalies should be the same in- or outside
HCA, since the progression of an anomaly to failure is unrelated to
whether the anomaly exists within or outside of an HCA.
10. Pipeline Safety Trust suggested non-HCA pipeline segments
should be subject to a baseline of IM requirements.
11. The Commissioners of Wyoming County Pennsylvania suggested
PHMSA consolidate operators' best practices and require assessment of
all pipe frequently enough to realize a benefit. They commented this
approach would assure a consistent level of public protection
regardless of the practices of individual pipeline operators.
12. California Public Utilities Commission noted this question
would be moot if method 2 for defining HCA is eliminated.
Response to Question A.8 Comments
PHMSA appreciates the information provided by the commenters.
Although most industry commenters did not support expansion of
integrity management requirements outside HCAs, PHMSA believes
additional protections are needed for pipeline segments where people
are expected within the PIR. In this NPRM, PHMSA proposes an approach
that balances the need to provide additional protections for persons
within the potential impact radius (PIR) of a pipeline rupture (outside
of a defined HCA), and the need to prudently apply IM resources in a
fashion that continues to emphasize the risk priority of HCAs. The
proposed regulation would require selected aspects of IM programs
(namely, integrity assessments and repair criteria) to be applicable
for selected non-HCA segments defined as MCAs. An MCA would be a
segment located where persons live and work and could reasonably be
expected to be located within a pipeline PIR. PHMSA would propose
requirements that integrity assessments be conducted, and that
injurious anomalies and defects be repaired in a timely manner, using
similar standards in place for HCAs. However, the other program
elements of a full IM program contained in 49 CFR part 192, subpart O
would not be required for MCA segments.
A.9. Should operators be required to submit to PHMSA geospatial
information related to the identification of HCAs?
1. Most industry commenters, including INGAA, AGA, and numerous
pipeline operators supported this proposed requirement. They noted
submission of this data will be required for PHMSA to comply with the
mapping provisions of the Pipeline Safety, Regulatory Certainty, and
Job Creation Act of 2011.
2. Accufacts, Alaska Department of Natural Resources, California
Public Utility Commission, and one private citizen agreed, suggesting
PHMSA should know where HCAs are located and that this information is
important to emergency responders. CPUC also suggested operators should
be required to submit this information to State regulatory authorities
as well.
3. Pipeline Safety Trust also supported this proposal, adding the
information should be shared with the public.
4. League of Women Voters of Pennsylvania and Accufacts also
supported making maps identifying pipeline locations, including HCA,
available to the public.
5. Atmos, Northern Natural Gas, Kern River, Nicor, and GPTC opposed
a requirement to submit this information. They noted this is a large
amount of information which is available for audits and questioned how
it would be used by PHMSA and how related security issues would be
addressed.
6. Ameren Illinois suggested a requirement to submit HCA locations
is not needed, since location data on the entire pipeline system must
already be submitted to the National Pipeline Mapping System.
7. Texas Pipeline Association, Texas Oil & Gas Association, and
MidAmerican agreed that providing HCA information as part of NPMS
submissions is adequate. They noted this is consistent with Section 6
of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of
2011.
Response to Question A.9 Comments
PHMSA appreciates the information provided by the commenters. Most
commenters supported the submittal of HCA information in geospatial
format. As noted by one commenter, this is required by the Act.
Although outside
[[Page 20750]]
the scope of this rulemaking, PHMSA is pursuing data reporting
improvements by proposing revisions to its currently approved
information collection for the National Pipeline Mapping System. PHMSA
has published several Federal Register notices and held several public
workshops on the proposals.
A.10. Why has the number of HCA miles declined over the years?
1. Responses to this question consisted of speculation regarding
reasons why the number of HCA miles may have declined. No commenters
reported having specific data to describe the reducing trend.
2. AGA suggested pipe replacement, reductions in MAOP, and use of
better data could be among the many reasons for a decline in HCA
mileage.
3. INGAA speculated the reduction could be a result of operators
changing from method 1 to method 2 to identify HCAs and abandoning or
retiring older pipelines.
4. Texas Pipeline Association, Texas Oil & Gas Association, Atmos,
and a private citizen agreed a change in the method for identifying
HCAs is a likely reason for the decreasing mileage trend.
5. Northern Natural Gas commented changes in land use over time
result in changes in the pipeline segments identified as HCA. Northern
noted it has changed from method 1 to method 2 for identifying HCA but
that the change had resulted in an increase in HCA mileage rather than
a decrease. Kern River also reported that its HCA mileage is
increasing, citing changes in land use along the pipeline as the reason
for this change.
6. GPTC and Nicor suggested operational changes and removal of pipe
from service could be the cause of the observed changes.
7. Iowa Utilities Board noted reductions in pressure and other
operational changes can eliminate covered pipeline segments. IUB also
suggested a change from method 1 to method 2 and better analyses of
potential impact circles, etc. could have resulted in decreased HCA
mileage.
8. MidAmerican noted its HCA mileage has fluctuated but remains
relatively constant overall. They noted periodic fluctuations result
from changes in various parameters that go into identifying HCAs.
9. A private citizen suggested operators may be buying properties
within potential impact circles and razing them or that new pipelines
in rural areas may be replacing current pipelines.
10. An anonymous commenter suggested HCA mileage is decreasing
because operators are getting better at identifying HCAs. The commenter
noted operators have been doing so for 9 years.
Response to Question A.10 Comments
PHMSA appreciates the information provided by the commenters. PHMSA
considered this input in its evaluation mandated by the Act.
A.11. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible.
1. Accufacts commented property damage costs reported to PHMSA
following pipeline incidents appear to be understated. Accufacts noted
this raises serious questions about the validity of cost-benefit
analyses performed using this data.
2. Iowa Association of Municipal Utilities commented the costs to
comply with IM-like requirements are not justified for small, low-
pressure transmission pipelines such as those operated by its members.
Significant costs to develop IM plans, evaluate remote valves, and
comply with other IM requirements must be passed on to a small rate
base for many municipal utilities.
3. ITT Exelis Geospatial Systems suggested HCA criteria be revised
and requirements for protection of critical infrastructure and
populated areas be made more prescriptive. They commented such changes
would require that leak surveys be performed more frequently, providing
improved safety.
4. ITT Exelis Geospatial Systems reported its leak detection
systems, developed as part of research jointly sponsored with DOT and
other agencies, could facilitate this testing and initial costs would
be offset by longer term savings.
5. California Public Utilities Commission observed the public has
indicated its desire for more prescriptive safety requirements.
Response to Question A.11 Comments
The Act requires that the Secretary of Transportation to evaluate
whether integrity management requirements should be expanded beyond
HCAs and whether such expansion would mitigate the need for class
location requirements. The proposed rulemaking does not change the HCA
definition. However, PHMSA is proposing pipeline assessment
requirements in new Sec. 192.710 for newly defined moderate
consequence areas (MCAs). PHMSA is also proposing new requirements in
Sec. 192.607 for verification of pipeline material and Sec. 192.624
for MAOP verification would also apply to MCAs. PHMSA performed a
Preliminary Regulatory Impact Analysis, using the best available data
and information. It is available on the docket and PHMSA invites
comments on the PRIA.
B. Strengthening Requirements To Implement Preventive and Mitigative
Measures for Pipeline Segments in HCAs
Section 192.935 requires gas transmission pipeline operators to
take additional measures, beyond those already required by part 192, to
prevent a pipeline failure and to mitigate the consequences of a
potential failure in a HCA following the completion of a risk
assessment. Section 192.935(a) specifies examples of additional
measures, which include, but are not limited to installing automatic
Shut-off Valves or Remote Control Valves; installing computerized
monitoring and leak detection systems; replacing pipe segments with
pipe of heavier wall thickness; providing additional training to
personnel on response procedures; conducting drills with local
emergency responders; and implementing additional inspection and
maintenance programs. In the ANPRM, PHMSA expressed concern that these
additional measures are not explicitly required. As a result, operators
may not be employing the appropriate additional measures as intended.
Section 192.935(b) specifies that operators are also required to
enhance their damage prevention programs and to take additional
measures to protect HCA segments subject to the threat of outside force
damage (non-excavation). PHMSA also noted in the ANPRM that the
provisions in Sec. 192.935 only apply to HCAs and that the expansion
of the HCA definition would increase the mileage of pipelines subject
to Sec. 192.935. Further, PHMSA acknowledged the consideration of
expanding preventive and mitigative measures to pipelines outside of
HCAs. The following are general comments received related to the topic
as well as comments related to the specific questions:
General Comments for Topic B
1. INGAA suggested PHMSA can substantially improve prevention and
mitigation of accidents caused by excavation damage by facilitating
full implementation of state damage prevention programs. INGAA further
suggested PHMSA actively promote the use of 811 one-call programs.
INGAA noted excavation damage remains the most prevalent cause of
serious incidents and failure to notify is a primary cause of these
incidents. Many pipeline operators supported the INGAA comments.
[[Page 20751]]
2. INGAA, supported by many of its pipeline operator members, noted
it has a policy goal to apply integrity management principles,
voluntarily, to pipelines beyond HCAs. Their goal is to address 90
percent of the population near pipelines by 2020 and 100 percent by
2030 through application of appropriate principles from ASME/ANSI
B31.8S.
3. AGA supported application of IM principles, but not assessment
requirements, outside HCAs. AGA commented requiring operators to
understand and address risks is a good application of IM principles.
Many pipeline operators supported the AGA comments.
4. AGA commented the ANPRM incorrectly states that Sec. 192.935
applies only to pipe within HCAs. AGA noted paragraph (d) of that
section applies to low-stress pipe in Class 3 and 4 areas that is not
in HCAs.
5. California Public Utilities Commission suggested pipelines
installed prior to the promulgation of federal pipeline safety
requirements (so-called ``pre-code'' pipe) be reassessed more
frequently.
6. Alaska Natural Gas Development Authority commented Alaska's
experience indicates improved pipeline design and construction
requirements are needed to assure pipeline integrity. These would
include stronger pipe, improved requirements for mainline valves
(including spacing and remote operation), and improved corrosion
control. The Authority also commented that design requirements need to
accommodate likely changes in class location, noting that explosive
growth in some Alaska areas has resulted in rapid changes from Class 1
to Class 3.
7. One private citizen suggested some level of assessment should be
required for all pipelines.
8. Another private citizen suggested integrity management plans for
densely populated areas (Class 4 and Class 5--a new class suggested by
the commenter encompassing cities with population greater than 100,000)
should be developed in consultation with local emergency responders.
The commenter further suggested these plans should be available at the
FERC environmental impact study stage and should be reviewed with local
authorities.
9. Another private citizen suggested information should be shared
across pipeline operators, noting this would augment the knowledge of
individual companies and improve safety. Similarly, the commenter
suggested PHMSA require operators to submit a list of preventive and
mitigative measures that have been implemented and reports of their
effectiveness. The commenter noted PHMSA should know this information
but apparently does not, as indicated by questions posed in this ANPRM
(particularly questions B.1 and B.2).
Comments Submitted for Questions in Topic B
B.1. What practices do gas transmission pipeline operators now use
to make decisions as to whether/which additional preventive and
mitigative measures are to be implemented? Are these decisions guided
by any industry or consensus standards? If so, what are those industry
or consensus standards?
1. Most industry commenters indicated ASME/ANSI B31.8S is a common
standard used to guide decisions concerning preventive and mitigative
measures. INGAA suggested enhancing this standard would be the best
approach to provide additional guidance for selection and
implementation of these measures. Other commenters also cited the GPTC
Guide as a useful guideline. INGAA listed other standards used by
pipeline operators, including:
Common Ground Alliance Best Practices
Pipelines and Informed Planning Alliance Recommended Practices
API-RP 1162--Public Awareness Programs,
API-RP 1166--Excavation Monitoring
NACE SP0169, other associated NACE standards
Gas Piping Technology Committee guidance materials
RSTRENG--A Modified Criterion for Evaluating the Remaining
Strength of Corroded Pipe
INGAA Foundation Guidelines for Evaluation and Mitigation of
Expanded Pipes
AGA also noted that operators are guided by their own risk
assessments. Many pipeline operators supported the INGAA and AGA
comments.
2. Northern Natural Gas reported it does not rely on a specific
consensus standard to select preventive and mitigative measures. It
relies, instead, on company subject matter experts guided by
statistical analyses of their risk model.
3. Paiute and Southwest Gas reported they use an algorithm
combining risk scores, threats, and the value of specific measures.
Company engineers analyze the results of applying this algorithm and
develop preventive and mitigative measure implementation plans.
4. An anonymous commenter noted many pipeline operators are
implementing actions that could be considered preventive and mitigative
measures but these actions may not be identified as such if they are
implemented as part of operations and maintenance activities and not
specifically included in IM plans.
5. INGAA suggested PHMSA would benefit by applying ASME/ANSI B31.8S
in its IM enforcement activities.
B.2. Have any additional preventive and mitigative measures been
voluntarily implemented in response to the requirements of Sec.
192.935? How prevalent are they? Do pipeline operators typically
implement specific measures across all HCAs in their pipeline system,
or do they target measures at individual HCAs? How many miles of HCA
are afforded additional protection by each of the measures that have
been implemented? To what extent do pipeline operators implement
selected measures to protect additional pipeline mileage not in HCAs?
1. INGAA reported many pipeline operators have implemented
additional preventive and mitigative measures. INGAA does not keep data
on this and did not provide examples. Some pipeline operators submitted
examples in support of the INGAA comments. Preventive and mitigative
measures cited in these examples include:
Additional reconnaissance (after seismic events, floods,
etc.);
Concrete mats over pipelines in areas particularly
susceptible to excavation damage;
Encroachment sensors;
Remotely operated valves;
Removal of casings;
Completion of CIS surveys;
Clearing of rights-of-way;
Derating/deactivating of pipelines;
Relocation of pipelines;
Increased inspection of river crossings;
Lowering of shallow pipelines;
Installation of additional marker posts;
Revising marking standards for locates;
Completing depth-of-cover surveys;
Enhancing right-of-way patrols.
In addition, one pipeline operator reported augmented
implementation of many requirements of part 192 and implementation of
some requirements (e.g., operator qualification) beyond their specified
bounds.
2. AGA also reported many additional preventive and mitigative
actions have been implemented but, again, does not keep data on them.
Examples cited by AGA and its operator members included increased use
of indirect inspection tools, increased patrols, and investigation of
apparent instances of encroachment.
[[Page 20752]]
3. GPTC reported data is not collected concerning voluntary
measures.
4. Texas Pipeline Association and Texas Oil & Gas Association
similarly reported that they do not collect this data, and there was
only limited response to a survey of their operators regarding this
question. The associations reported their understanding that measures
are not generally implemented system-wide.
5. California Public Utilities Commission reported some CA
operators are stationing personnel at the location of excavations near
transmission pipelines. CAPUC also noted California's one-call law
requires a mandatory field meeting before any excavation near a
transmission pipeline operating above 60 psi.
6. An anonymous commenter suggested operators avoid implementing
non-required actions for fear they will lead to new requirements.
7. Industry comments indicated data is not collected concerning the
extent of implementation of voluntary preventive and mitigative
measures. Some measures are implemented in specific HCAs while others
may be implemented more broadly across a pipeline system. The extent
depends largely on the threat being addressed and its prevalence.
8. Northern Natural Gas reported it has implemented voluntary
measures outside HCA, citing as examples high-visibility markers in
Class 1 areas and use of LIDAR leak detection. Northern reported broad
implementation of voluntary measures is more prevalent than site
specific use.
9. MidAmerican reported virtually all of its transmission pipeline
mileage is subject to at least one preventive and mitigative measure.
10. Paiute reported nine measures are applied to all of its 856
miles of transmission pipeline while 13 are applicable to all 27 miles
of HCA.
11. Similarly, Southwest Gas has implemented nine measures on 841
miles and 13 on all 191 miles of HCA.
12. AGA reported that approximately 195,000 non-HCA miles have been
assessed, generally through assessing pipe upstream and downstream of
the HCA segment.
B.3. Are any additional prescriptive requirements needed to improve
selection and implementation decisions? If so, what are they and why?
1. Industry commenters unanimously agreed no new prescriptive
requirements are needed. INGAA pointed out selection of preventive and
mitigative measures is based on criteria in consensus standards and
operator judgment. INGAA contended this allows appropriate
customization and results in improved safety. AGA agreed, noting
operators are in the best position to decide what is needed for their
pipeline systems. GPTC stated that its Guide is sufficient, and there
has been no demonstrated safety need for additional requirements.
Several pipeline operators suggested conducting assessments and making
repairs provides the most effective safety improvement.
2. Paiute and Southwest Gas suggested a best practices workshop to
share industry experience could be beneficial.
3. Accufacts suggested additional prescriptiveness is needed to
guide decisions regarding remote and automatically operated valves in
HCA.
4. The Alaska Department of Natural Resources would suggest signoff
by a professional engineer on preventive and mitigative action
decisions.
5. The NTSB recommended improved use of metrics in inspection
protocols, citing their recommendations P-11-18 and 19.
6. One private citizen suggested the lack of specifically-required
actions in the regulations represents a deficiency in the pipeline
safety regulatory program. The commenter suggested the extent of
operator judgment be limited and that state and local officials should
participate in developing a list of applicable preventive and
mitigative actions.
7. An anonymous commenter suggested including more examples of
preventive and mitigative actions in the regulations would help guide
operator consideration of appropriate actions. The commenter also
suggested operators be required to update their risk analyses, and
selection of preventive and mitigative actions, more frequently
including after changes in their pipeline systems or the occurrence of
significant events.
B.4. What measures, if any, should operators be required explicitly
to implement? Should they apply to all HCAs, or is there some
reasonable basis for tailoring explicit mandates to particular HCAs?
Should additional preventative and mitigative measures include any or
all of the following: Additional line markers (line-of-sight); depth of
cover surveys; close interval surveys for cathodic protection (CP)
verification; coating surveys and recoating to help maintain CP current
to pipe; additional right-of-way patrols; shorter ILI run intervals;
additional gas quality monitoring, sampling, and inline inspection tool
runs; and improved standards for marking pipelines for operator
construction and maintenance and one-calls? If so, why?
1. INGAA, supported by many of its pipeline operator members,
commented prescriptive requirements are not needed. INGAA contended
prescriptive requirements are neither effective nor efficient and that
ASME/ANSI B31.8S and the GPTC Guide provide sufficient guidance.
2. AGA commented one-call requirements and the actions required by
the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011
are the only actions that should be required on a system-wide basis.
AGA further suggested it could be appropriate to apply the additional
measures required of low-pressure pipelines in Sec. 192.935(d) to
pipelines operating above 30 percent SMYS.
3. Texas Pipeline Association and Texas Oil & Gas Association
recommended no new requirements be adopted applying specific preventive
and mitigative actions throughout pipeline systems. The associations
noted part 192 already requires application of some measures throughout
pipeline systems and expressed their conclusion these already-specified
measures are sufficient.
4. MidAmerican commented requiring application of specified
measures throughout pipeline systems would provide a disincentive for
the application of other measures which could be more appropriate.
5. The NTSB recommended requirements for leak detection in SCADA
systems should be improved, citing their recommendation P-11-10.
6. California Public Utilities Commission recommended operators be
required to station stand-by personnel at excavations near transmission
pipelines and operator procedures should specify the actions these
stand-by personnel must take. CPUC further suggested these standby
activities should be a covered task under operators' personnel
qualification programs.
7. Pipeline Safety Trust recommended PHMSA mandate the NTSB
recommendations, noting many are similar to the specific measures
suggested in this question. PST further commented operators should not
be allowed sufficient latitude to render a regulation meaningless.
8. An anonymous commenter suggested the regulations should not
specify particular preventive and mitigative measures but should
emphasize consideration of potential accident consequences when
selecting actions. The commenter noted there are too many variables to
specify particular actions in regulation.
[[Page 20753]]
9. A private citizen suggested operators should be required to
conduct drills with local responders periodically as part of their
integrity management programs. The commenter noted such drills would
improve coordination and would validate the ability to respond in the
event of an emergency.
10. A private citizen suggested stronger enforcement is needed
based on the belief that operators should already be taking many of the
actions suggested in this question.
11. With respect to the specific actions suggested in this
question:
a. Line-of-sight markers: National Utility Locating Contractors
Association recommended line-of-sight markers be required, noting that
they would reduce the instances of excavators failing to call for a
locate, which the Common Ground Alliance's Damage Information Reporting
Tool (DIRT) continues to indicate is a major cause of excavation
damage. The Association further recommended the message on markers
should be visible from all angles, noting that most current markers are
only visible from two directions. The Commissioners of Wyoming County
Pennsylvania, and MidAmerican suggested line-of-sight markers should be
required, noting that they are a low-cost good practice for improving
safety. An industry consultant disagreed, noting installation would be
impractical in many areas where the sight line is obscured by crops,
terrain, etc.
b. Depth of cover: MidAmerican opposed required depth of cover
surveys, commenting they are not a good indicator of likely damage and
such surveys are inherently inaccurate. Texas Pipeline Association and
Texas Oil & Gas Association suggested compliance with depth of cover
requirements over time is impractical. They noted operators do not have
full control over rights of way and that owners can make changes. For
example, a landowner may pave an area following grading which reduces
the depth of cover. California Public Utilities Commission recommended
depth of cover surveys be required wherever external corrosion direct
assessment is applied and where vehicles or other loads capable of
damaging the pipeline have access to the surface over the pipeline.
Wyoming County Pennsylvania's Commissioners suggested depth of cover
surveys be required as a good safety practice.
c. Close interval surveys: MidAmerican recommended against
requiring these surveys. The company noted they are only one means of
determining the adequacy of cathodic protection. The Commissioners of
Wyoming County Pennsylvania recommended such surveys be required as a
good safety practice.
d. Coating surveys and re-coating: MidAmerican opposed a
requirement for coating surveys, noting holidays are found and repaired
through in-line inspection and external direct assessment. The company
further noted pipe replacement is often a superior repair to recoating.
The Wyoming County Commissioner commented periodic coating surveys are
a good practice and recommended that they be required.
e. Additional right of way patrols: MidAmerican and the Wyoming
County Commissioners agreed increased frequency of patrols would be
appropriate. MidAmerican noted patrols are a relatively low cost action
that generates useful data.
f. Shorter ILI intervals: MidAmerican opposed shorter intervals,
noting many lines cannot accommodate in-line inspection or more
frequent runs. The Wyoming County Commissioners argued that frequent
assessment is a good practice that should be required.
g. Additional gas quality monitoring: MidAmerican opposed such a
requirement, arguing it would be redundant for distribution pipeline
operators receiving gas from suppliers. The Wyoming County
Commissioners argued frequent gas monitoring would be a good practice.
h. Improved pipeline marking standards: MidAmerican agreed
implementing new marking standards would be a low cost action. Wyoming
County again noted this is a good practice.
B.5. Should requirements for additional preventive and mitigative
measures be established for pipeline segments not in HCAs? Should these
requirements be the same as those for HCAs or should they be different?
Should they apply to all pipeline segments not in HCAs or only to some?
If not all, how should the pipeline segments to which new requirements
apply be delineated?
1. INGAA, supported by many of its member companies, argued
preventive and mitigative measures should be applied to non-HCA areas
on a risk basis rather than by prescriptive requirement. INGAA
commented this is a more effective and efficient means of increasing
pipeline safety.
2. AGA commented codifying different requirements for non-HCA areas
would likely cause confusion and extending existing IM requirements to
non-HCA areas would create an enormous burden for PHMSA and states. AGA
noted the NTSB has already questioned the ability of regulators to
apply the existing IM inspection protocols to HCA mileage. AGA
recommended one-call and the actions required by statute be the only
additional measures required system-wide.
3. GPTC, Texas Pipeline Association, Texas Oil & Gas Association,
and two pipeline operators opposed requirements for preventive and
mitigative actions in non-HCA areas. These commenters argued it is
important to allow pipeline operators the flexibility to select actions
that are appropriate to their circumstances and implementing actions
required arbitrarily would be expensive and ineffective.
4. Northern Natural Gas suggested PHMSA expand the HCA definition
gradually over time rather than imposing IM requirements outside HCA.
Northern commented such an approach would retain and expand the focus
on areas posing the highest risk.
5. MidAmerican opposed additional requirements for preventive and
mitigative actions, noting all pipeline is covered by other
requirements in part 192 and it is better to focus enhanced
requirements on areas posing highest risk.
6. AGA commented measures required in HCA should always be equal to
or more stringent than measures required outside of HCA. AGA noted this
is a fundamental principle of integrity management: Focusing on areas
posing higher risks.
7. Ameren Illinois and an anonymous commenter suggested better
enforcement and/or specificity for provisions requiring operators
consider other areas of their systems when problems are discovered
would be more effective than requiring preventive and mitigative
measures outside HCA.
8. ITT Exelis Geospatial Systems commented requirements should be
the same in- or outside HCA. They contended non-HCA areas are not
monitored for leakage as often as Class 3 and 4 locations. They
suggested their LIDAR system would allow effective and efficient leak
surveys in all locations.
9. A public citizen recommended exposed pipe be wrapped in bright
colors and protected from damage whether inside or outside of HCA. The
commenter suggested analysis of data from CGA's Damage Information
Reporting Tool would be an effective preventive measure.
B.6. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible.
[[Page 20754]]
In addition, PHMSA requests commenters to provide information and
supporting data related to, among other factors, the potential costs of
modifying the existing regulatory requirements pursuant to the
commenter's suggestions.
1. Northern Natural Gas reported the additional cost of
preventative and mitigative measures it employs, including instrumented
aerial leakage surveys, close-interval surveys, additional mailings and
additional signage, has been approximately $950,000. Northern further
reported the approximate cost of conducting assessments through in-line
inspection or pressure testing for all high-consequence areas every
seven years is $45,000,000 and reduction of the inspection interval
would increase the cost accordingly.
Response to Topic B comments
Section 5 of the Act requires that the Secretary of Transportation
complete an evaluation and issue a report on whether integrity
management requirements should be expanded beyond HCAs and whether such
expansion would mitigate the need for class location requirements.
Aspects of this topic that relate to applying a risk analysis to
determine additional preventive and mitigative measures for non-HCA
pipeline segments will be addressed later, pending completion of the
evaluation and report. PHMSA will review the comments received on this
topic and will address them in the future in light of these statutory
requirements.
Section 3 of the Act requires that the Secretary of Transportation
complete an evaluation and issue a report on the impact of excavation
damage on pipeline safety. Aspects of this topic that relate to
additional preventive and mitigative measures for damage prevention
will be addressed after completion of the evaluation and report. PHMSA
will review the comments received on this topic and will address them
in the future in light of this evaluation and report.
Section 6 of the Act requires that the Secretary of Transportation
provide guidance on public awareness and emergency response plans.
Aspects of this topic that relate to additional preventive and
mitigative measures for public awareness and emergency response will be
further evaluated in conjunction with this statutory mandate. PHMSA
will review the comments received on this topic and will address them
in the future in light of this evaluation.
Two specific areas of preventive and mitigative actions addressed
in the IM requirements (49 CFR 192.935) are leak detection and
automatic/remote control valves. The IM rule does not require specific
measures be taken to address these aspects of pipeline design and
operations, but does include them among candidate preventive and
mitigative measures operators should consider. Both of these topics are
the subject of recommendations that the NTSB made (recommendations P-
11-10 and P-11-11) following the San Bruno explosion. In response to
these recommendations, PHMSA conducted a public workshop on March 27,
2012, to seek stakeholder input on these issues, and is sponsoring
additional research and development to further inform PHMSA's response
on these issues. Aspects of this topic that relate to leak detection
and automatic/remote control valves will be addressed after completion
and evaluation of the above activities. PHMSA will review the comments
received on leak detection and automatic/remote control valves and will
address them in the future in light of this evaluation.
PHMSA is proposing to add requirements for enhanced preventive and
mitigative measures to address internal and external corrosion control.
The intent of the IM rulemaking is to enhance protections for high
consequence areas. PHMSA believes that enhanced requirements for
internal corrosion and external corrosion control are prudent. To
address internal corrosion, PHMSA is proposing specific requirements
for operators to monitor gas quality and contaminants and to take
actions to mitigate adverse conditions. To address external corrosion,
PHMSA is proposing specific requirements for operators to monitor and
confirm the effectiveness of external corrosion control through
electrical interference surveys and indirect assessments, including
cathodic protection surveys and coating surveys, to take actions needed
to mitigate conditions that are unfavorable to effective cathodic
protection, and to integrate the results of these surveys with
integrity assessment and other integrity-related data. PHMSA addresses
this topic in more detail in response to comments related to Topic I,
Corrosion Control.
Note: Specific comments submitted for Topic B that are related
to risk and integrity assessments are addressed under Topics E and
G.
C. Modifying Repair Criteria
The existing integrity management regulations establish criteria
for the timely repair of injurious anomalies and defects discovered in
the pipe (49 CFR 192.933). These criteria apply to pipeline segments in
an HCA, but not to segments outside an HCA. The ANPRM announced that
PHMSA is considering amending the integrity management rule by revising
the repair criteria to provide greater assurance that injurious
anomalies and defects are repaired before the defect can grow to a size
that leads to a leak or rupture. In addition, PHMSA is considering
establishing repair criteria for pipeline segments located in areas
that are not in an HCA in order to provide greater assurance that
defects on non-HCA pipeline segments are repaired in a timely manner.
The following are general comments received related to the topic and
then comments related to the specific questions:
General Comments for Topic C
1. INGAA reported its members' commitment to apply ASME/ANSI B31.8S
corrosion anomaly criteria both inside and outside of HCAs. INGAA noted
that new research to refine and extend the technical bases for
responding to corrosion anomalies identified primarily by ILI has been
completed by Pipeline Research Council International, whose report was
expected to be published in the first quarter of 2012. INGAA also
reported a commitment to develop and use criteria for mitigation of
dents, corrosion pitting, expanded pipe corrosion, and selective seam
weld corrosion. Numerous pipeline operators supported INGAA's comments.
2. AGA suggested that ASME/ANSI B31.8S should be the basis for
defining anomalies requiring remediation. Anomalies not meeting the
criteria in that standard, in AGA's opinion, do not require repair. AGA
further commented that risk prioritization of maintenance and anomaly
response should not be regulated because operators are in the best
position to know the factors influencing prioritization for apparently-
similar anomalies. AGA also suggested that PHMSA review INGAA's paper
``Anomaly Response and Mitigation Outside of High Consequence Areas
when Using in Line Inspection,'' dated May 30, 2010, as this paper
forms the basis for current industry response outside of HCAs. Numerous
pipeline operators supported AGA's comments.
3. Accufacts contended that there have been too many corrosion-
caused ruptures occurring shortly after in-line
[[Page 20755]]
inspection runs and that this indicates the need for more prescriptive
criteria for corrosion evaluation and remediation.
4. Alaska Department of Natural Resources commented that repairs
should be made using permanent methods, and that clamps and similar
repairs are not sufficient.
Response to General Comments for Topic C
PHMSA appreciates the information provided by the commenters.
Because the current repair criteria only address corrosion metal loss
as an immediate condition, PHMSA agrees that more prescriptive repair
criteria are needed to address significant corrosion metal loss that
does not meet the immediate repair criterion, similar to the hazardous
liquid integrity management repair criteria at 49 CFR 195.452(h). In
addition, other conditions that are not currently addressed in the
repair criteria, such as stress corrosion cracking and selective seam
weld corrosion, are addressed in ASME B31.8S and other sources, but not
explicitly addressed in part 192. PHMSA is proposing to enhance the
repair criteria for HCA segments and is also proposing to add specific
repair criteria for pipeline in non-HCA segments. In general, PHMSA is
proposing to add more immediate repair conditions and more one-year
conditions for HCA segments. The additional criteria address conditions
not previously addressed, such as stress corrosion cracking, and also
include more specific one-year criteria for corrosion metal loss, based
on the design factor for the class location in which the pipeline is
located, to address corrosion metal loss that reduces the design safety
factor of the pipe. PHMSA is also proposing to apply similar repair
criteria in non-HCA segments, except that response times will be
tiered, with longer response times for non-immediate conditions. PHMSA
reviewed available industry literature, including ASME/ANSI B31.8S, in
developing the proposed repair criteria. Specific aspects of the
proposed rules are discussed in response to the specific questions for
Topic C, below.
PHMSA has not addressed the specific procedures and techniques for
performing repairs in this rulemaking, but may do so at a later date.
Comments Submitted for Questions in Topic C
C.1. Should the immediate repair criterion of failure pressure
ratio (FPR) <=1.1 be revised to require repair at a higher threshold
(i.e., additional safety margin to failure)? Should repair safety
margins be the same as new construction standards? Should class
location changes, where the class location has changed from Class 1 to
2, 2 to 3, or 3 to 4 without pipe replacement have repair criteria that
are more stringent than other locations? Should there be a metal loss
repair criterion that requires immediate or a specified time to repair
regardless of its location (HCA and non-HCA)?
1. INGAA, supported by numerous pipeline operators, commented the
FPR criterion need not be changed, noting there have been no reported
incidents due to the criterion being too lax. INGAA also objected to
PHMSA's characterization of this issue, noting that repair criteria
already exceed 1.1 FPR; the 1.1 FPR criterion in the regulations
governs response to anomalies and not the criteria to which repairs
must be made.
2. AGA, supported by numerous of its pipeline operator members,
commented that the FPR criterion should not be changed. AGA contended
that the criterion already provides a 10 percent safety margin and is
based on sound engineering practices.
3. Northern Natural Gas and Kern River stated that conservatism is
present in burst pressure calculations and in the measurement of
anomalies (considering tool tolerance), providing a safety margin
greater than 10 percent.
4. Accufacts argued against changing the FPR criterion, but
suggested that PHMSA require operators to use better assumptions in
their failure analyses. Accufacts suggested that the regulations should
focus on preventing failures but that existing safety margins need not
be increased.
5. Texas Pipeline Association, Texas Oil & Gas Association, Atmos,
and MidAmerican opposed changes to this criterion. These commenters
noted that experience through the baseline inspections has demonstrated
the criterion is adequate and ASME/ANSI B31.8S remains a good guide for
anomaly response. Atmos added that this criterion separates immediate
repairs from scheduled repairs: It allows a risk-based focus on more
serious anomalies but does not mean that anomalies providing more than
10 percent margin to burst pressure are never addressed.
6. California Public Utilities Commission suggested that the FPR
criterion be increased to 1.25 times MAOP. CPUC noted that the 10
percent margin in the current criterion can be completely erased by the
10 percent margin to safety relief settings allowed by Sec. 192.201.
7. INGAA commented that additional repair criteria are not needed.
INGAA noted that Sec. Sec. 192.485(a) and 192.713(a) already specify
repair criteria applicable to pipe outside HCA. Numerous pipeline
operators supported INGAA's comments.
8. AGA, supported by numerous of its pipeline operator members,
suggested that safety margins for repairs need not be the same as those
for new construction. AGA argued that the construction margins are
intended to address potential unknowns and forces applied during
construction, which are not applicable to repairs.
9. Accufacts, Northern Natural Gas, and an anonymous commenter
agreed that repairs, once initiated, should meet new construction
safety margins.
10. INGAA and several of its pipeline operator members argued that
repair criteria should not be more stringent where class location has
changed. INGAA noted that Sec. 192.611 does not change the original
design criteria for segments that have been subject to a change in
class location and there is no incident experience suggesting that
additional safety margin is needed in these cases.
11. Northern Natural Gas and Kern River argued against a change in
repair criteria where class location has changed, noting that the
likelihood of failure of an anomaly is not affected by the class
location and that treatment in accordance with integrity management
requirements already considers risk.
12. MidAmerican, Paiute, and Southwest Gas added that use of the
factor failure pressure divided by MAOP in ASME/ANSI B31.8S already
reflects any change in MAOP necessitated by a change in class location.
13. Accufacts commented that repair criteria should be commensurate
with the more restrictive design criteria of higher class locations.
14. INGAA commented no new metal loss criterion is needed, noting
that its members use HCA response criteria as a guide for responding to
indications of metal loss outside of HCAs. Numerous pipeline operators
supported INGAA's comments.
15. AGA commented any metal loss criterion should reflect current
science and should be the same regardless of class location. AGA
suggested that immediate response to any indication of a dent with
metal loss is not needed, noting that there have been many examples of
dents with metal loss not sufficient to require recalculating remaining
strength. AGA also noted the external corrosion direct assessment
standard requires a similar response regardless of whether an
indication is in
[[Page 20756]]
or outside HCA. Numerous pipeline operators supported AGA's comments.
16. Accufacts encouraged PHMSA to establish a prompt-action
criterion for wall loss inside or outside HCAs, suggesting the focus
should be on preventing ruptures regardless of where they occur.
Accufacts also cautioned PHMSA against accepting studies attempting to
show that 80 percent wall loss is sometimes acceptable, and stated that
continued operation with such wall loss is too risky for onshore
pipelines.
Response to Question C.1 Comments
PHMSA appreciates the information provided by the commenters. The
majority of comments supported no changes to the immediate repair
criterion of predicted failure pressure of less than or equal to 1.1
times MAOP for HCAs, and PHMSA is not proposing to change this
criterion; however, PHMSA is proposing several changes to enhance the
repair criteria both for HCA segments and non-HCA segments. For
immediate conditions, PHMSA proposes to add the following to the
immediate repair criteria: Metal loss greater than 80% of nominal wall
thickness, indication of metal-loss affecting certain types of
longitudinal seams, significant stress corrosion cracking, and
selective seam weld corrosion. These additional repair criteria would
address specific issues or gaps with the existing criteria. The methods
specified in the IM rule to calculate predicted failure pressure are
explicitly not valid if metal loss exceeds 80% of wall thickness.
Corrosion affecting a longitudinal seam, especially associated with
seam types that are known to be susceptible to latent manufacturing
defects such as the failed pipe at San Bruno, and selective seam weld
corrosion are known near-term integrity threats. Stress corrosion
cracking is listed in ASME B31.8S as an immediate repair condition,
which is not reflected in the current IM regulations. PHMSA proposes to
add requirements to address these gaps.
The current regulations include no explicit metal loss repair
criteria, other than one immediate condition. The regulations direct
operators to use Figure 4 in ASME B31.8S to determine non-immediate
metal loss repair criteria. PHMSA now proposes to explicitly include
selected metal loss repair conditions in the one-year criteria. These
proposed criteria are consistent with similar criteria currently
invoked in the hazardous liquid integrity management rule at 40 CFR
195.452(h). In addition, PHMSA proposes to incorporate safety factors
commensurate with the class location in which the pipeline is located,
to include predicted failure pressure less than or equal to 1.25 times
MAOP for Class 1 locations, 1.39 times MAOP for Class 2 locations, 1.67
times MAOP for Class 3 locations, and 2.00 times MAOP for Class 4
locations in HCAs. Lastly, in response to the lessons learned from the
Marshall, Michigan, rupture, PHMSA proposes to include any crack or
crack-like defect that does not meet the proposed immediate criteria as
a one year condition. PHMSA proposes to apply these same criteria as
two-year conditions for non-HCAs.
PHMSA agrees with Accufacts' comment that the regulations should
focus on preventing failures but that existing safety margins are
adequate when properly applied. Therefore, the proposed rule does not
propose to increase safety margins such as the design factor. PHMSA
maintains that the proposed changes discussed above provide a tiered,
risk-based approach to metal loss repair criteria and by requiring
predicted failure pressures as a function of class locations does not
compound safety margins. Counter to INGAA's and AGA's comments that
repair criteria should not be more stringent where class location has
changed, PHMSA believes the tiered approach to metal loss repair
criteria, which is a function of class location, provides a logical
framework to address the risk presented by these types of pipeline
anomalies.
In conjunction with enhanced repair criteria, PHMSA is proposing
specific new regulations to require that operators properly analyze
uncertainties and other factors that could lead to non-conservative
predictions of failure pressure, and time remaining to failure, when
evaluating ILI anomaly indications. PHMSA specifically is proposing
that operators must analyze specific known sources of uncertainty
regarding ILI tool performance, anomaly interactions, and other sources
of uncertainty when determining if an anomaly meets any repair
criterion.
C.2. Should anomalous conditions in non-HCA pipeline segments
qualify as repair conditions subject to the IM repair schedules? If so,
which ones? What projected costs and benefits would result from this
requirement?
1. INGAA suggested that new criteria are not needed, commenting
that operators generally treat non-HCA anomalies in a manner similar to
HCA anomalies, except for response time. INGAA stated that industry
costs to address non-HCA anomalies should be nominal unless immediate
response is required because this is consistent with current operator
practice, which INGAA stated is to apply ASME/ANSI B31.8S response
criteria for anomalies both inside and outside HCAs.
2. Texas Pipeline Association and Texas Oil & Gas Association
commented that differing repair criteria, if any, should be based upon
the population at risk, since there is no valid engineering basis for
treating anomalies differently depending on location.
3. Atmos and Northern Natural Gas suggested that non-HCA anomalies
should be treated like HCA anomalies, although additional schedule
flexibility should be allowed. Northern reported that it applies HCA
metal loss criteria everywhere because it is prudent, although response
time differs for non-HCA anomalies. Northern reported that it has
expended approximately $7.7 million on anomaly repairs, $7 million of
which was outside an HCA.
4. Kern River agreed that IM schedules are too stringent to apply
everywhere and providing schedule flexibility will reduce costs.
5. MidAmerican disagreed with the suggestion that non-HCA and HCA
anomalies be treated alike. MidAmerican commented that it is illogical
to back off from focusing sooner on anomalies that pose greater risks.
6. California Public Utilities Commission commented that all
locations identified by the method described in paragraph 1 in the
definition of HCA in Sec. 192.903 should be subject to HCA repair
criteria.
7. Pipeline Safety Trust, Accufacts, and NAPSR commented that the
same repair criteria and response schedule should apply regardless of
where an anomaly is located. These commenters contended that there is
no logical justification for different treatment, that any risk to the
pipeline and public safety should be resolved, and that a pipeline
accident anywhere is seen by the public as a failure to exercise
adequate control of pipeline safety. NAPSR, in particular, suggested
that all anomalies should be repaired immediately, regardless of where
they are located.
8. Iowa Utilities Board, Iowa Association of Municipal Utilities,
GPTC, Nicor, Ameren Illinois and an anonymous commenter contended that
HCA repair criteria should not be applied outside HCAs. These
commenters noted that there has been no demonstrated safety need for
new criteria, that non-HCA anomalies are adequately addressed under
existing operations and maintenance requirements, and that the cost to
apply HCA repair criteria everywhere is not justified. IAMU
particularly noted that
[[Page 20757]]
existing requirements are adequate for small, low-pressure transmission
pipelines such as those operated by its members.
9. A private citizen supported application of HCA repair criteria
in non-HCA areas, particularly where there are ``receptors,'' which the
commenter defines as ``something which needs to be protected.''
Response to Question C.2 Comments
PHMSA appreciates the information provided by the commenters. PHMSA
proposes to modify the general requirement for repair of pipelines to
include immediate repair condition criteria, one-year conditions, and
monitored conditions. The definition of these conditions would be the
same as the existing definitions for covered segments (i.e., HCA
segments) in the IM rule; however, PHMSA proposes that those conditions
that must be repaired within one year in a HCA segment would be
required to be repaired within two years in a non-HCA segment. Defects
that meet any of the immediate criteria are considered to be near-term
threats to pipeline integrity and would be required to be repaired
immediately regardless of location.
PHMSA believes that establishing these non-HCA segment repair
conditions are important because, even though they are not within the
defined high consequence locations, they could be located in populated
areas and are not without consequence. For example, as reported by
operators in the 2011 annual reports, while there are approximately
20,000 miles of gas transmission pipe in HCA segments, there are
approximately 65,000 miles of pipe in Class 2, 3, and 4 populated
areas. PHMSA believes it is prudent and appropriate to include criteria
to assure the timely repair of injurious pipeline defects in non-HCA
segments. These changes will ensure the prompt remediation of anomalous
conditions on all gas pipeline segments while allowing operators to
allocate their resources to high consequence areas on a higher priority
basis.
C.3. Should PHMSA consider a risk tiering--where the conditions in
the HCA areas would be addressed first, followed by the conditions in
the non-HCA areas? How should PHMSA evaluate and measure risk in this
context, and what risk factors should be considered?
1. INGAA, and many pipeline operators, opposed the suggested
tiering. They commented that anomalies meeting response criteria should
be addressed in an appropriate time frame whether inside or outside
HCAs.
2. AGA, supported by many of its operator members, suggested that
PHMSA not adopt any risk tiering beyond the current requirements to
focus first on HCA anomalies. AGA noted that outside factors, e.g.,
permitting, affect the timing and the sequence of repairs.
3. Texas Pipeline Association and Texas Oil & Gas Association
commented that PHMSA should allow risk tiering system-wide, not just in
differentiating between responses in and outside HCA. The associations
suggested that this could be an improvement to requirements addressing
anomalies. At the same time, they noted the description in the ANPRM is
sketchy and requested PHMSA propose specific requirements for comment.
4. Iowa Association of Municipal Utilities commented that no new
requirements are needed, and that the existing requirements are
sufficient for the small, low-stress transmission pipelines operated by
its members.
5. Atmos commented that the risk tiering concept is confusing and
stated that it was considered and rejected when the initial IM rules
were promulgated.
6. Northern Natural Gas commented that allowing a longer response
time for anomalies outside HCA would be a form of risk tiering. The
company reported it has incorporated this practice in its procedures.
7. Accufacts agreed that a focus on HCA anomalies is needed but
cautioned against ignoring anomalies outside HCAs. Accufacts noted the
progression of an anomaly to failure does not depend on whether or not
it is located in an HCA.
Response to Question C.3 Comments
PHMSA appreciates the information provided by the commenters.
Current regulations do not prescribe response timeframes for anomalies
outside HCAs. As stated by Northern Natural Gas, allowing a longer
response time for anomalies outside HCAs (compared to response times
for anomalies inside HCAs) would be a form of risk-tiering. PHMSA is
proposing such an approach, which would establish three timeframes for
performing repairs in non-HCA areas: Immediate repair conditions, 2-
year repair conditions, and monitored conditions. These changes will
ensure the prompt remediation of anomalous conditions on all gas
pipeline segments, while allowing operators to allocate their resources
to those areas that present a higher risk.
C.4. What should be the repair schedules for anomalous conditions
discovered in non-HCA pipeline segments through the integrity
assessment or information analysis? Would a shortened repair schedule
significantly reduce risk? Should repair schedules for anomalous
conditions in HCAs be the same as or different from those in non-HCAs?
1. INGAA commented that repair schedules outside HCAs should be
similar to those in HCAs but should allow for more scheduling latitude.
This comment was supported by comments received from many of its
operator members. They also noted that adding requirements to repair
non-HCA anomalies would significantly increase the number of required
repairs and that an inappropriate requirement for rapid response would
dilute the focus on risk-significant repairs. INGAA suggested that
repair schedules should be more a function of anomaly growth rates than
location along the pipeline. INGAA further suggested that
inappropriately rapid response schedules would increase risk;
experience shows that most anomalies that have been found and repaired
are old, do not require a rapid response, and that mandating rapid
response to such anomalies would necessarily dilute other safety
activities.
2. Texas Pipeline Association and Texas Oil & Gas Association
expressed doubt that significant risk reduction would result from
shortened repair schedules, given the logistics and related work
involved in repairs.
3. GPTC, Nicor, and an anonymous commenter objected to applying HCA
repair criteria outside HCAs. They believe that the costs for such an
approach are not justified and non-HCA anomalies are appropriately
dealt with under operations and maintenance requirements and
procedures.
4. Ameren Illinois, Paiute, and Southwest Gas agreed that
prescriptive repair schedules are not needed outside HCAs. They
expressed a belief that operators must have scheduling flexibility to
accommodate the needs of their operations.
5. MidAmerican suggested that immediate repair criteria be applied
both in HCAs and outside HCAs, but that other criteria be limited to
HCAs.
6. Northern Natural Gas suggested that PHMSA should require
operators to determine response schedules for non-HCA anomalies as part
of this rulemaking.
7. Iowa Association of Municipal Utilities commented that the
existing requirements are sufficient for the small, low-stress
transmission pipelines operated by its members.
8. California Public Utilities Commission commented that all method
[[Page 20758]]
1 HCA locations should be subject to HCA repair criteria.
9. MidAmerican, Paiute, and Southwest Gas commented that shortened
response schedules will not reduce risk. These operators suggested that
response times should be based on risk rather than being established
arbitrarily.
Response to Question C.4 Comments
PHMSA appreciates the information provided by the commenters. PHMSA
believes repair schedules outside HCAs should be similar to those in
HCAs but should allow for more scheduling latitude. PHMSA proposes to
establish three timeframes for remediating defects in non-HCA areas:
Immediate repair conditions, 2-year repair conditions (rather than one-
year for HCAs), and monitored conditions. These changes will ensure the
prompt remediation of anomalous conditions on all gas pipeline
segments, commensurate with risk, while allowing operators to allocate
their resources to those areas that present a higher risk.
C.5. Have ILI tool capability advances resulted in a need to update
the ``dent with metal loss'' repair criteria?
1. INGAA commented that ILI tool capabilities have improved to the
point where it is appropriate to revise the dent-with-metal loss
criterion. This comment was supported by comments received from many of
its operator members. INGAA suggested that Section 851.4(f) of ASME/
ANSI B31.8 provides appropriate guidance in this area.
2. AGA suggested that it would be appropriate to eliminate the
immediate response criterion for ``dent with metal loss.'' This comment
was supported by comments received from many of its operator members.
They commented that industry experience has shown that many dents do
not require immediate repair.
3. Texas Pipeline Association, Texas Oil & Gas Association,
MidAmerican, Paiute, Southwest Gas, and Atmos supported revising this
criterion. These commenters noted that improvements in ILI allow better
distinction between a gouge and corrosion wall loss. MidAmerican
further commented that there are problems with implementing Sec.
192.933 as written.
4. Northern Natural Gas stated that it would support treating these
anomalies as mechanical damage, and suggested that this would simplify
the regulations.
5. Ameren Illinois suggested further study of this proposal taking
into account current ILI technology.
6. Accufacts and an anonymous commenter opposed changes to this
criterion. These commenters suggested that ILI is still not adequate to
determine reliably the time to failure of this compound threat.
7. GPTC and Nicor suggested that PHMSA consider updating the Dent
Study technical report \35\ that discusses reliability and application
of ILI.
---------------------------------------------------------------------------
\35\ Baker and Kiefner & Associates, ``Dent Study Technical
Report,'' (November 2004, OPS TTO Number 10, available at https://primis.phmsa.dot.gov/gasimp/techreports.htm).
---------------------------------------------------------------------------
Response to Question C.5 Comments
PHMSA appreciates the information provided by the commenters. PHMSA
is not proposing to update the dent-with-metal-loss criterion at this
time. PHMSA will continue to evaluate this criterion, including
consideration of additional research to better define the repair
criteria for this specific type of defect.
C.6. How do operators currently treat assessment tool uncertainties
when comparing assessment results to repair criteria? Should PHMSA
adopt explicit voluntary standards to account for the known accuracy of
in-line inspection tools when comparing in-line inspection tool data
with the repair criteria? Should PHMSA develop voluntary assessment
standards or prescribe ILI assessment standards including wall loss
detection threshold depth detection, probability of detection, and
sizing accuracy standards that are consistent for all ILI vendors and
operators? Should PHMSA prescribe methods for validation of ILI tool
performance such as validation excavations, analysis of as-found versus
as-predicted defect dimensions? Should PHMSA prescribe appropriate
assessment methods for pipeline integrity threats?
1. INGAA, supported by many of its member companies, reported that
operators use many methods to accommodate ILI uncertainties, not simply
adding tool tolerance to results. INGAA suggested API-1163, In-line
Inspection Systems Qualification Standard, as an appropriate guide.
INGAA noted this standard is non-prescriptive; INGAA expressed its
belief prescriptive standards would stifle innovation. INGAA also
reported that ASME has plans to update its standard on ``Gas
Transmission and Distribution Piping Systems,'' ASME/ANSI B31.8S,
regarding treatment of uncertainties based on the results of Pipeline
Research Council International (PRCI) research that was underway at the
time comments were submitted.
2. AGA and a number of pipeline operators suggested that tool
tolerances should be added to ILI results.
3. Texas Pipeline Association, Texas Oil & Gas Association, and
Atmos reported their understanding that most operators follow ASME/ANSI
B31.8S as a guide.
4. Northern Natural Gas and Kern River expressed their conclusion
that PHMSA's Gas Integrity Management Program Frequently Asked Question
FAQ-68 provides sufficient guidance on the treatment of uncertainties
(FAQs can be viewed at https://primis.phmsa.dot.gov/gasimp/faqs.htm).
They noted that technology is developing rapidly in this area, which
they imply is a reason not to impose prescriptive requirements.
5. Texas Pipeline Association and Texas Oil & Gas Association
agreed that prescriptive requirements should not be imposed, because
the rapidly-developing technology would soon render them obsolete.
6. GPTC, Nicor, MidAmerican, and Atmos argued that prescriptive
methods for validating tool performance are not an appropriate subject
for regulation.
7. Ameren Illinois commented that it sees no technical
justification for establishing requirements in this area.
8. Accufacts suggested that PHMSA specify minimum standards for ILI
validation, including specifying a required number of digs. Alaska
Department of Natural Resources and California Public Utilities
Commission took a similar stance, all arguing that standards assure
public confidence and consistency of results.
9. A private citizen commented that voluntary standards are not
sufficient because they cannot be enforced.
10. An anonymous commenter recommended against adopting
requirements for treatment of inaccuracies. The commenter opined that
operators are doing better in this area, contending that smaller
operators, in particular, needed time to learn. The commenter suggested
that specific rules would set many operators back.
11. INGAA and many of its pipeline operators commented that
incorporating standards into part 192 that compete with industry
standards would be counterproductive. INGAA noted that API-1163, API-
579-1, Fitness-for-Service, and ASNT ILI-PQ, In-Line Inspection
Personnel Qualification and Certification Standard, are already in wide
use and contended specifying standards in the regulations would stifle
further development.
12. GPTC and Nicor agreed with INGAA, noting that the regulatory
approval process cannot keep up with technological development.
13. Northern Natural Gas recommended that PHMSA not adopt standards
for addressing ILI inaccuracies, contending the many
[[Page 20759]]
different tools currently in use would make this impractical.
14. MidAmerican reported its belief that operators have sufficient
incentive to work with ILI vendors to assure appropriate validation of
ILI results.
15. Paiute and Southwest Gas argued against adoption of regulatory
standards to treat ILI uncertainties, noting that this subject is
already addressed in ASME/ANSI B31.8S.
16. AGA, supported by a number of its member companies, suggested
that PHMSA should not prescribe IM methods, noting that operators have
demonstrated the ability to conduct assessments without them.
17. Accufacts, Alaska Natural Gas Development Authority, and
California Public Utilities Commission argued for requirements
prescribing assessment methods for various threats. These commenters
suggested that such requirements would be a bridge to better risk
management strategies and contended that there is currently an over-
reliance on direct assessment.
Response to Question C.6 Comments
PHMSA appreciates the information provided by the commenters. The
majority of comments do not support adopting explicit standards or
analytical methodologies to account for the known accuracy of in-line
inspection tools. PHMSA concurs that prescriptive rules to account for
the accuracy of in-line inspection tools is not practical, however it
is beneficial to all to clarify PHMSA's expectations with respect to
current performance-based regulations in this area which specify that
internal inspection may be used to identify and evaluate potential
pipeline threats. Therefore, PHMSA proposes to add detailed
performance-based rule language to require that operators using ILI
must explicitly consider uncertainties in reported results (including
tool tolerance, anomaly findings, and unity chart plots or equivalent
for determining uncertainties) in identifying anomalies. While ASME/
ANSI B31.8S discusses uncertainties, PHMSA believes it will improve the
visibility and emphasis on this important issue to explicitly address
uncertainties in the rule text.
C.7. Should PHMSA adopt standards for conducting in-line
inspections using ``smart pigs,'' the qualification of persons
interpreting in-line inspection data, the review of ILI results
including the integration of other data sources in interpreting ILI
results, and/or the quality and accuracy of in-line inspection tool
performance, to gain a greater level of assurance that injurious
pipeline defects are discovered? Should these standards be voluntary or
adopted as requirements?
1. AGA and its pipeline operator members argued against the
adoption of standards. AGA commented that voluntary use has proven to
be sufficient and expressed its position that consensus standards
should not be adopted into regulations until widespread experience has
been gained with their use. AGA contended that premature adoption would
stifle technological innovation.
2. INGAA and many of its members commented that PHMSA's process for
review and adoption of standards must be streamlined if existing
consensus standards are incorporated into regulations. Such
improvements, INGAA contended, would assure that standard improvements
are adopted without delay.
3. An anonymous commenter, GPTC, and Nicor cited similar concerns
in suggesting that standards not be adopted into regulations,
contending that the rulemaking process cannot keep up with
technological change.
4. Texas Pipeline Association and Texas Oil & Gas Association
objected to the adoption of ILI standards in regulations, contending
that voluntary use is more appropriate.
5. MidAmerican commented that operator qualification requirements
should be applied to ILI, as this would provide higher assurance of
defect discovery. Beyond this, however, MidAmerican contended that the
use of consensus standards should remain voluntary, as this allows the
operator to select those standards most appropriate to its
circumstances.
6. Paiute and Southwest Gas objected to the incorporation of ILI
standards into regulations. The companies expressed a belief that there
is no technical basis for doing so. They commented that the question,
as posed in the ANPRM, implies that anomalies are not now being found
and contended that there is no evidence to support this implication.
7. A private citizen, Thomas Lael, and Alaska Department of Natural
Resources commented that PHMSA should require operators to meet
specified standards. Mr. Lael referred to an incident that occurred
following a pipeline assessment conducted in Ohio in 2011; Mr. Lael
contended that the reasons the incident cause was not identified by the
assessment are unknown to the public.
8. Pipeline Safety Trust commented that PHMSA should assure
assessment tools are capable and are used properly.
9. The NTSB recommended that PHMSA require all pipelines to be made
piggable, giving priority to older lines, citing their recommendation
P-11-17.
Response to Question C.7 Comments
PHMSA appreciates the information provided by the commenters. The
majority of industry comments do not support the incorporation of ILI
standards into regulations. However, based on the information presented
below, PHMSA has concluded that it is prudent to propose incorporating
available consensus ILI standards into the regulations. The current
pipeline safety regulations for integrity management of segments in
HCAs contained in 49 CFR 192.921 and 192.937 require that operators
assess the material condition of pipelines in certain circumstances and
allow use of in-line inspection tools for these assessments. PHMSA
proposes to incorporate similar requirements for non-HCA pipe segments
in Sec. 192.710. Operators are required to follow the requirements of
ASME/ANSI B31.8S in selecting the appropriate ILI tools. However, ASME
B31.8S provides only limited guidance for conducting ILI assessments.
At the time the integrity management rules were promulgated, there was
no consensus industry standard that addressed performance of ILI. Three
related standards have since been published: API STD 1163-2005, NACE
SP0102-2010, and ANSI/ASNT ILI-PQ-2010. API-1163 serves as an umbrella
document to be used with and complement the NACE and ASNT standards.
These three standards have enabled service providers and pipeline
operators to provide processes that will qualify the equipment, people,
processes, and software utilized in the in-line inspection industry.
The incorporation of these standards into pipeline safety regulations
developed through best practices of the industry based on the
experience of numerous operators will promote high quality and more
consistent assessment practices. Therefore, PHMSA is proposing to
incorporate these industry standards into the regulations to provide
clearer guidance for conducting integrity assessments with in-line
inspection. PHMSA will continue to evaluate the need for additional
guidance for conducting integrity assessments.
C.8. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements
[[Page 20760]]
pursuant to the commenter's suggestions.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the
existing regulatory requirements.
No comments were received in response to this question.
D. Improving the Collection, Validation, and Integration of Pipeline
Data
The ANPRM requested comments regarding whether more prescriptive
requirements for collecting, validating, integrating and reporting
pipeline data are necessary. The current IM regulations require that
gas transmission pipeline operators gather and integrate existing data
and information concerning their entire pipeline that could be relevant
to pipeline segments in HCAs (Sec. 192.917(b)). Operators are then
required to use this information in a risk assessment of the HCA
segments (Sec. 192.917(c)) that must subsequently be used to determine
whether additional preventive and mitigative measures are needed (Sec.
192.935) and to define the intervals at which IM reassessments must be
performed (Sec. 192.939). Operators' risk analyses and conclusions can
only be as good as the information used to perform the analyses. On
August 30, 2011, after the ANPRM was issued, the NTSB adopted its
report on the gas pipeline accident that occurred on September 9, 2010,
in San Bruno, California. Results from the NTSB investigation indicate
that the pipeline operator's records regarding the physical attributes
of the pipe segments involved in the incident were erroneous. NTSB
recommendation P-11-19 recommended that PHMSA require IM programs be
assessed to assure that they are based on clear and meaningful metrics.
In addition, Section 23 of the Act requires verification to ensure that
records accurately reflect the physical and operational characteristics
of pipelines. PHMSA issued an Advisory Bulletin (76 FR 1504; January
10, 2011) on this issue. The following are general comments received
related to the topic as well as comments related to the specific
questions:
General Comments for Topic D
1. INGAA reported that it is presently working on data integration
guidelines. INGAA cautioned that requirements in this area can be very
costly, since they often necessitate redesign of existing data
management systems.
2. AGA commented that no records requirements would have prevented
the San Bruno accident, and stated that verifying records does not
assure completeness, as unknown parameters remain unknown.
3. A private citizen suggested that PHMSA should require operators
to identify segments where they lack knowledge of critical parameters.
The commenter suggested that this could facilitate emergency
communications and help prioritize pipe replacement programs.
Response to General Comments for Topic D
PHMSA appreciates the information provided by the commenters. PHMSA
is proposing to clarify requirements for collecting, validating, and
integrating data. The current rule invokes ASME/ANSI B31.8S
requirements for data collection and integration. To provide greater
visibility and emphasis on this important aspect of integrity
management, PHMSA is proposing to place these requirements in the rule
text, rather than incorporating ASME/ANSI B31.8S by reference. The
proposed requirements clarify PHMSA's expectations regarding the
minimum list of data an operator must collect, and also includes
performance-based language that requires the operator to validate data
it will use to make integrity-related decisions, and require operators
to integrate all such data in a way that improves the analysis. The
proposed rule would also require operators to use reliable, objective
data to the maximum extent practical. To the degree that subjective
data from subject matter experts must be used, PHMSA proposes to
require that an operator's program include specific integrity
assessment and findings data for the threat features to compensate for
subject matter expert (SME) bias. The importance of these aspects of
integrity management was emphasized by both the NTSB (Recommendation P-
11-19) and Congress (The Act, Section 11(a)(4)).
Comments Submitted for Questions in Topic D
D.1. What practices are now used to acquire, integrate and validate
data (e.g., review of mill inspection reports, hydrostatic tests
reports, pipe leaks and rupture reports) concerning pipelines? Are
practices in place, such as excavations of the pipeline, to validate
data?
1. INGAA reported that its members have completed a concerted
effort to validate pipeline historical records pursuant to PHMSA
Advisory Bulletin 11-01 (issued January 10, 2011).
2. Texas Pipeline Association and Texas Oil & Gas Association
commented that there is no great benefit to be gained from adding a
verification requirement for historical data to the regulations. The
associations believe that most operators will correct their records
when they become aware of errors regardless of how the erroneous
information is discovered. The associations suggested that there could
be value in validating databases against original records, since an
underlying problem of the San Bruno accident was errors in transferring
original records into a database.
3. Ameren Illinois reported that it collects data on exposed pipe
in accordance with Sec. Sec. 192.459 and 192.475.
4. Northern Natural Gas and Kern River reported that their primary
integration tool is integrity alignment sheets, which show the class
location, profile, aerial photography, alignment and structure data,
in-line inspection results, other integrity data, i.e., close-interval
survey or pressure test results and pipe, coating and appurtenance
data. Data is validated as opportunities arise.
5. Paiute and Southwest Gas reported that they confirm the location
and properties of its pipeline as opportunities arise; more data are
collected as assessments are conducted.
6. California Public Utilities Commission suggested that operators
be explicitly required to obtain all historical records and that there
be an officer statement that a thorough search for all records has been
conducted.
7. A private citizen commented on the lack of some historical data,
implying that operators should be required to validate their knowledge
of older pipelines.
8. An anonymous commenter stated that older data is typically not
validated.
9. INGAA and AGA reported that pipeline operators take advantage of
exposed pipe to collect and validate data on in-service pipelines. This
includes excavations for ILI validation, those conducted as part of
direct assessment, and removed or replaced pipelines. A number of
pipeline operators provided comments supporting the comments of each
association.
10. GPTC and Nicor suggested that excavations not be required for
the sole purpose of validating data, contending that the risks posed by
such a requirement would outweigh any benefit obtained.
[[Page 20761]]
11. MidAmerican reported that it validates information when
pipeline is excavated and through its routine practices.
Response to Question D.1 Comments
PHMSA appreciates the information provided by the commenters. See
response to question D.4.
D.2. Do operators typically collect data when the pipeline is
exposed for maintenance or other reasons to validate information in
their records? If discrepancies are found, are investigations conducted
to determine the extent of record errors? Should these actions be
required, especially for HCA segments?
1. AGA, Paiute, and Southwest Gas reported that operators use
exposed pipe as an opportunity to collect information. AGA further
suggested, however, that PHMSA should not draft a rule governing these
practices. AGA contended the circumstances of pipe exposures vary too
much to be addressed by a regulatory requirement. AGA expressed its
conclusion that the requirements in Sec. 192.605(b)(3) provide
adequate guidance and that section 23 of the Pipeline Safety,
Regulatory Certainty, and Job Creation Act of 2011 provides additional
guidance. AGA noted that operators investigate identified inaccuracies
and errors. A number of other pipeline operators provided comments
supporting AGA's comments.
2. Texas Pipeline Association, Texas Oil & Gas Association, Atmos,
MidAmerican, and Ameren Illinois reported that operators typically
collect information on pipe type and condition, but not on historical
information and pipe specifications. They commented that collecting
this information would require additional testing and pose operational
impacts.
3. Iowa Utilities Board and Iowa Association of Municipal Utilities
commented that any new requirement should be limited to collecting
readily obtainable data, principally that which can be determined
visually. They suggested that the data elements in ANPRM questions D.1
and D.3 go beyond what can readily be observed or obtained and it would
be impractical to require this data to be collected during pipe
exposures.
4. California Public Utilities Commission commented that any new
requirements to collect data during pipe exposures should address all
instances of exposure rather than be limited to HCAs, noting that non-
HCA segments can become HCA segments due to changes in land use near
the pipeline.
5. Thomas Lael and Alaska Department of Natural Resources commented
that operators should be required to collect specific data during pipe
exposures. These commenters contended that not all operators currently
collect available data during pipe exposures.
6. MidAmerican, Paiute, and Southwest Gas commented that no new
requirements are needed because the requirements in part 192 and
guidance in ASME/ANSI B31.8S are sufficient.
7. An anonymous commenter suggested that operators be required to
collect data if they do not have enough information to analyze the
risks of the pipeline segment.
Response to Question D.2 Comments
PHMSA appreciates the information provided by the commenters. The
expanded rule language does not impose new requirements for collecting
specific data during pipe exposures, but the response to question D.4
discusses proposed changes to collection and validation practices to
improve data integration and risk assessment practices.
D.3. Do operators try to verify data on pipe, pipe seam type, pipe
mechanical and chemical properties, mill inspection reports,
hydrostatic tests reports, coating type and condition, pipe leaks and
ruptures, and operations and maintenance (O&M) records on a periodic
basis? Are practices in place to validate data, such as excavation and
in situ examinations of the pipeline? If so, what are these practices?
1. AGA, GPTC, Nicor, Paiute, and Southwest Gas reported that
operators do try to verify information but that operator practices are
too numerous to list in response to this general question. They
contended that the requirements for external corrosion control in Sec.
192.459 and for internal corrosion control in Sec. 192.475 and the
guidance in Advisory Bulletin 11-01 are sufficient and no new
requirements are needed. A number of other pipeline operators provided
comments supporting AGA's comments.
2. INGAA, supported by many of its pipeline operator members,
commented that there are limited, if any, methods to determine
accurately mechanical properties of pipe that is in situ. INGAA's
comments listed a number of methods that can be used to obtain
approximate values for some pipe characteristics, such as steel
hardness and yield strength.
3. Texas Pipeline Association and Texas Oil & Gas Association
commented that operators do not validate mill data after initial
construction.
4. Ameren Illinois reported that data review and correction is a
normal part of the business of pipeline operation. Ameren commented
that additional work in this area is likely to result from Advisory
Bulletin 11-01.
5. Northern Natural Gas reported that data correction occurs when a
discrepancy is identified. Northern also noted that it has added data
to its risk model over time, principally related to determination of
the potential consequences of a pipeline accident.
6. MidAmerican commented that operators validate pipeline
information periodically.
7. California Public Utilities Commission reported that California
pipeline operators have begun validating pipeline data since the San
Bruno accident. CPUC commented that operators should determine pipeline
specifications for all exposed facilities and use them to validate
their records.
8. Paiute and Southwest Gas reported that it is their practice to
obtain pipeline data before an integrity management excavation and then
to validate that information in the field.
9. MidAmerican reported that it uses a geospatial database as its
principal tool for collecting and validating pipeline information.
10. An anonymous commenter suggested that pipeline operators do not
routinely collect information to validate their databases during
pipeline excavations.
Response to Question D.3 Comments
PHMSA appreciates the information provided by the commenters. See
response to question D.4.
D.4. Should PHMSA make current requirements more prescriptive so
operators will strengthen their collection and validation practices
necessary to implement significantly improved data integration and risk
assessment practices?
1. INGAA, GPTC, Nicor, Ameren Illinois, MidAmerican, Paiute and
Southwest Gas commented that additional prescriptive requirements are
not needed. These commenters suggested that Advisory Bulletin ADB-11-
01, subpart O of part 192, and ASME/ANSI B31.8S are sufficient to
govern these practices. INGAA added requirements for data validation
during excavations could introduce workplace hazards that would
outweigh any benefit to be gained. In the event PHMSA proceeds to
propose new requirements, INGAA requested they be limited to a
reasonable process and allow assumptions to be made to fill information
gaps, suggesting this would be a more cost-effective approach than
[[Page 20762]]
rigorous requirements to collect and validate all information. A number
of other pipeline operators provided comments supporting INGAA's
comments.
2. AGA, supported by a number of its pipeline operator members,
commented that there is no evidence to support a need for more
prescriptive requirements leading to better data collection or
validation and, therefore, no such requirements are needed.
3. Pipeline Safety Trust, NAPSR, California Public Utilities
Commission, and Commissioners of Wyoming County, Pennsylvania,
commented that requirements for data collection, validation, and use
should be more prescriptive. These commenters noted that the
investigation of the San Bruno accident identified at least one
pipeline operator was not doing an adequate job of data validation.
They noted that NTSB recommendations P-11-18 and P-11-19 apply to this
topic. NAPSR specifically requested that new requirements specify
precise inspection criteria.
4. Texas Pipeline Association and Texas Oil & Gas Association
suggested that there is no value in periodic validation of pipeline
data and new requirements are not needed in this area. Northern Natural
Gas agreed, noting that pipeline data does not change over time, and
relevant data that is subject to change, is that data needed to
evaluate the consequences of potential pipeline accidents.
5. Accufacts commented that more specific criteria, including
minimum data requirements, are needed for record retention. Accufacts
noted that integrity management is data-based and that too many
operators claim that data is lost or cannot be found.
6. Alaska Department of Natural Resources suggested that data
integration should be required in interpreting ILI results.
7. An anonymous commenter suggested that specific requirements are
not needed in this area, contending that most data has been validated
through normal operator practices.
8. A private citizen suggested that PHMSA require pipeline
operators to post all records for access by state and local government
officials, PHMSA, and the media. The commenter suggested such a
``sunshine'' provision would improve recordkeeping, even if no one ever
examines the posted records.
Response to Question D.4 Comments
PHMSA appreciates the information provided by the commenters in
response to questions D.1 through D.4. Commenters disagreed on the need
and benefit of making current requirements more prescriptive so
operators will strengthen their collection and validation practices.
PHMSA believes enhancing regulations in this area is an important
element of good integrity management practices. On July 21, 2011, in
response to the San Bruno incident, PHMSA sponsored a public workshop
on risk assessment and related data analysis and recordkeeping issues
to seek input from stakeholders. Based in part on the input received at
this workshop, and the information submitted in response to the ANPRM,
PHMSA proposes to clarify the performance-based requirements for
collecting, validating, and integrating pipeline data by adding
specificity to the data integration language, establishing a number of
pipeline attributes that must be included in these analyses, explicitly
requiring that operators integrate analyzed information, and ensuring
data is reliable. The rule also requires operators to use validated,
objective data to the maximum extent practical. PHMSA also understands
that objective sources such as as--built drawings, alignment sheets,
material specifications, and design, construction, inspection, testing,
maintenance, manufacturer, or other related documents are not always
available or obtainable. To the degree that subjective data from
subject matter experts must be used, PHMSA proposes to require that an
operator's program include specific features to compensate for subject
matter expert bias. PHMSA believes that these proposed changes would
not impose new requirements or more prescriptive requirements, but
clarifies the intent of the regulation. However, PHMSA requests public
comment on whether and the extent to which this proposal may change
behavior.
D.5. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements pursuant to the commenter's suggestions.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the
existing regulatory requirements.
No comments were received in response to this question.
E. Making Requirements Related to the Nature and Application of Risk
Models More Prescriptive
The ANPRM requested comments regarding whether requirements related
to the nature and application of risk models should be made more
prescriptive to improve the usefulness of these analyses in controlling
risks from pipelines. Current regulations require that gas transmission
pipeline operators perform risk analyses of their pipelines and use
these analyses to make certain decisions to assure the integrity of
their pipeline and to enhance protection against the consequences of
potential incidents. The regulations do not prescribe the type of risk
analysis nor do they impose any requirements regarding its breadth and
scope, other than requiring that it consider the entire pipeline.
PHMSA's experience in inspecting operator compliance with IM
requirements has identified that most pipeline operators use a relative
index-model approach to performing their risk assessments and that
there is a wide range in scope and quality of the resulting analyses.
It is not clear that all of the observed risk analyses can support
robust decision-making and management of the pipeline risk. The
following are general comments received related to the topic as well as
comments related to the specific questions:
General Comments for Topic E
1. INGAA and Chevron commented that continuing the performance-
based regulatory approach, exemplified by integrity management, is
critically important to pipeline safety. They suggested that
prescriptive management systems are task oriented, do not adjust easily
to new information or knowledge, inhibit innovation, and could thwart
safety improvements. A number of other pipeline operators provided
comments supporting INGAA's comments.
2. Accufacts commented that risk management approaches permitted in
IM need additional prescriptive measures to clarify strengths and
weaknesses and to assure compliance. Public perception resulting from
the number of serious incidents is that current risk analysis and risk
management approaches are not sufficient. The impression is that risk
management is being used to justify unwise lowest cost decisions rather
than being used as a tool to avoid failure. Accufacts further suggested
that interactive threats need to be addressed by prescriptive
requirements in safety
[[Page 20763]]
regulations because operators may be under the illusion that some of
the more serious threats are stable after almost 10 years of IM
regulation.
3. Oleksa and Associates suggested that it would be statistically
more valid for many (perhaps most) operators for PHMSA to perform
continual evaluation and assessment using established performance
measures along with data submitted by operators on annual, incident,
and safety-related condition reports, and then to promulgate more
prescriptive regulations resulting from that assessment. Oleksa
suggested that it may be time to re-evaluate the overall concept of
integrity management to determine whether it makes sense for each
operator to make assessments that might be more valid if made on a
national level. Oleksa also stated that there should be a concerted
effort in promulgating any new regulations towards making the
regulations simple enough so that they can be understood relatively
easily.
4. TransCanada commented that PHMSA's IM regulations should provide
explicit metrics for operators to demonstrate safety decision processes
without restricting the opportunity to use more accurate and advanced
methods. TransCanada said that any efforts to make risk models more
prescriptive should focus on process elements while providing operators
the flexibility to build processes which recognize the unique
characteristics of their pipeline systems. The company also opined that
issuing more detailed guidelines on specific integrity management plan
elements would enhance the current, performance-based approach and
generate additional benefits that the public and operators desire.
5. Dominion East Ohio Gas opposed making requirements for risk
models more prescriptive. Like INGAA, they that noted prescriptive
management systems are task oriented and do not adjust easily to new
information or knowledge. They inhibit innovation and could thwart
safety improvements.
6. NAPSR strongly urged PHMSA to make the nature and application of
risk models more prescriptive. NAPSR commented that PHMSA has not
provided any data that supports the theory that risk modeling provides
a stronger safety environment and contended that, in fact, the opposite
may be occurring.
7. A private citizen suggested that PHMSA correlate the quality of
an operator's risk model with the number of enforcement actions against
that operator.
8. A private citizen suggested that risk analysis requirements
should remain flexible, commenting that prescribed methods or
requirements could mask operator-specific issues.
Response to General Comments for Topic E
PHMSA appreciates the information provided by the commenters. PHMSA
agrees that prescriptive rules for risk assessments are not appropriate
because one-size-fits-all regulations would not be effective for such a
diverse industry. However, PHMSA does believe that operator risk models
and risk assessments should have substantially improved since the
initial framework programs established nearly 10 years ago. While
simple index or relative (qualitative) ranking models were useful to
prioritize HCA segments for purposes of scheduling integrity baseline
assessments, those models have limited utility to perform the analyses
needed to better understand pipeline risks, better understand failure
mechanisms (especially for interacting threats), or to identify
effective preventive and mitigative measures. PHMSA is proposing to
further clarify its expectations for this aspect of the performance-
based regulations to further improve pipeline safety. On July 21, 2011,
PHMSA sponsored a public workshop on risk assessment to seek input from
stakeholders. PHMSA has evaluated the input it received at this
workshop. PHMSA proposes to clarify the risk assessment aspects of the
IM rule to explicitly articulate functional requirements and to assure
that risk assessments are adequate to: (1) Evaluate the effects of
interacting threats, (2) determine intervals for continual integrity
reassessments, (3) determine additional preventive and mitigative
measures needed, (4) analyze how a potential failure could affect HCAs,
including the consequences of the entire worst-case incident scenario
from initial failure to incident termination, (5) identify the
contribution to risk of each risk factor, or each unique combination of
risk factors that interact or simultaneously contribute to risk at a
common location, (6) account and compensate for uncertainties in the
model and the data used in the risk assessment, and (7) evaluate
predicted risk reduction associated with preventive and mitigative
measures. In addition, in response to NTSB recommendation P-11-18,
PHMSA proposes to require that operators validate their risk models in
light of incident, leak, and failure history and other historical
information. PHMSA also proposes to expand the list of example
preventive and mitigative measures to include the following items:
establish and implement adequate operations and maintenance processes
that could affect safety; establish and deploy adequate resources for
successful execution of activities, processes, and systems associated
with operations, maintenance, preventive measures, mitigative measures,
and managing pipeline integrity; and correct the root cause of past
incidents to prevent recurrence.
In response to Oleksa's comments, PHMSA is addressing performance
measures outside of this rulemaking. Performance measures will be
addressed separately in response to NTSB safety recommendations P-11-18
and P-11-19.
Comments Submitted for Questions in Topic E
E.1. Should PHMSA either strengthen requirements on the functions
risk models must perform or mandate use of a particular risk model for
pipeline risk analyses? If so, how and which model?
1. INGAA, AGA, and many pipeline operators reported that they do
not believe there is a pipeline safety benefit for PHMSA to
``strengthen'' or revise the requirements on functions that risk models
must perform or in mandating the use of specific risk models. These
commenters noted that there is a tremendous amount of diversity in the
pipeline systems of individual operators and operators must have the
flexibility to select the risk model that best supports their systems.
2. GPTC commented that there is no `one-size-fits-all' risk model.
GPTC further commented PHMSA has offered no data supporting the need to
strengthen requirements or mandate a particular risk model.
3. Kern River noted that differences exist between pipeline
operators on how much detail is needed in their risk assessment models.
The specific factors and required risk model complexity will differ for
each pipeline company based on its active threats, the preventive and
mitigative measures employed, its data acquisition methods and the
amount of required data.
4. MidAmerican commented that no change is needed to requirements
concerning risk models. MidAmerican noted that ASME/ANSI B31.8S
provides extremely detailed requirements in this area, and suggested
that operators should have the freedom to choose the risk model best
suited to their operation. Northern Natural Gas agreed, noting that
there are large differences within the industry on the complexity of
the risk assessment models used based on the
[[Page 20764]]
pipeline age and configuration, threats, and data available.
5. Paiute and Southwest Gas opposed more restrictive requirements
for risk modeling. They noted that operators have a decade of
experience working with IM and therefore, should have the flexibility
to choose the risk model that best suits their system.
6. Accufacts commented that this is an area that needs more
prescriptive requirements. Accufacts questioned whether the current
approach of reliance on risk modeling is even appropriate. They stated
that there appears to be a disconnect between the use of risk models
and risk analysis with pipeline operation and the ability of regulators
to apply and enforce the approach.
7. TransCanada noted that mandating the use of a specific risk
model may result in a more uniform approach across the industry, but
may also force operators to abandon their existing risk models,
including the improvements made to them based on 10 years of integrity
management experience. This would not appear to advance risk modeling
and might even be counterproductive.
8. WKM Consultancy commented that mandating a specific risk
assessment model would not be a beneficial addition to regulations.
Such a mandate would stifle creativity and require extensive
definitions and documentation of that methodology. A mandated model
would introduce a prescriptive element with substantial ``overhead''
related to the maintenance of the model's documentation by the
regulators. They suggested that a better solution would be to develop
guidelines of essential ingredients necessary in any pipeline risk
assessment.
9. An anonymous commenter opposed requiring the use of a specific
risk model, suggesting that operators should use models with which they
are comfortable. The commenter did suggest that PHMSA strengthen
requirements concerning the use of risk models for purposes other than
risk-ranking segments, expressing a belief that most operators are
using their models only for that purpose.
10. California Public Utilities Commission recommended that PHMSA
require statistical data be maintained and used to support the
weightings assigned by risk models to various threats.
Response to Question E.1 Comments
PHMSA appreciates the information provided by the commenters. A
large number of comments do not support adding a requirement for a
specific risk assessment model or for strengthening or revising the
required functions that risk models must perform. PHMSA agrees that
prescribing the use of particular risk assessment models is not
appropriate for such a diverse industry, and notes that relative index
models have been successfully used to rank pipelines to prioritize
baseline assessments. However, PHMSA believes that the integrity
management rule anticipates that operators would continually improve
their risk assessment processes and that there are specific risk
assessment attributes related to the nature and application of risk
models that need clarification. Such attributes and shortcomings were
discussed at the ``Improving Pipeline Risk Assessments and
Recordkeeping'' workshop with stakeholders, held on July 21, 2011.
PHMSA proposes to articulate clear functional requirements, in
performance-based terms, for risk assessment methods used by operators.
While PHMSA does not propose to prescribe the specific risk assessment
model operators must use, PHMSA does propose to clarify the
characteristics of a mature risk assessment program. These include: (1)
Identifying risk drivers; (2) evaluating interactive threats; (3)
assuring the use of traceable and verifiable information and data; (4)
accounting for uncertainties in the risk model and the data used; (5)
incorporating a root cause analysis of past incidents; (6) validating
the risk model in light of incident, leak and failure history and other
historical information; (7) using the risk assessment to establish
criteria for acceptable risk levels; and (8) determining what
additional preventive and mitigative measures are needed to achieve
risk reduction goals. PHMSA proposes to clarify that the risk
assessment method selected by the operator must be capable of
successfully performing these functions.
E.2. It is PHMSA's understanding that existing risk models used by
pipeline operators generally evaluate the relative risk of different
segments of the operator's pipeline. PHMSA is seeking comment on
whether or not that is an accurate understanding. Are relative index
models sufficiently robust to support the decisions now required by the
regulation (e.g., evaluation of candidate preventive and mitigative
measures, and evaluation of interacting threats)?
1. Industry commenters, including INGAA, AGA, Texas Pipeline
Association, Texas Oil & Gas Association, WKM Consultancy, and many
pipeline operators reported that PHMSA's understanding is correct and
that risk models in use generally evaluate the relative risk of
different segments of the operator's pipeline. AGA noted that operators
have selected and implemented the risk models that allowed them to
prioritize the covered segments for the baseline assessment and
subsequent reassessments and that this complied with the Pipeline
Safety Improvement Act of 2002.
2. AGA, supported by a number of its pipeline operator members,
commented that risk models currently in use are sufficiently robust.
Ameren Illinois and GPTC expressed a similar belief.
3. INGAA, supported by some of its members, noted that there is
room for improvement in the current practices of risk modeling. INGAA
reported that the industry has established committees to identify
advancements in risk modeling.
4. WKM Consultancy commented that the more robust of the relative
risk index techniques are often capable of fulfilling some aspects of
IM risk management requirements such as prioritization, but that other
aspects of the risk management requirements are not well supported by
relative risk assessments. They suggested that some risk assessment
models in current use could benefit from application of more robust and
modern techniques.
5. Kern River commented that a relative risk model is sufficiently
robust to support decisions on preventive and mitigative measures and
assessment intervals.
6. MidAmerican reported that its risk model complies with ASME/ANSI
B31.8S and is sufficiently robust to support decisions that are not
specifically related to assessments. MidAmerican further stated that
its risk model produces results consistent with its subject matter
expert assessments of relative risk.
7. Paiute and Southwest Gas reported their conclusion that their
risk models are robust and support the process of evaluation and
selection of preventive and mitigative measures.
8. Texas Pipeline Association and Texas Oil & Gas Association noted
that all sources of information relative to the integrity of a
transmission pipeline segment and the identified risk should be used in
the selection of preventive and mitigative measures. Atmos agreed,
noting that preventive and mitigative measures for a given pipeline
segment are based on the identified threats.
9. A private citizen suggested that consideration of system-wide
high risk (e.g., urban areas) should be required, contending relative
risk is not good enough when an entire system poses high risks.
[[Page 20765]]
Response to Question E.2 Comments
PHMSA appreciates the information provided by the commenters.
Although a large number of comments contend risk models currently in
use are sufficiently robust, PHMSA believes that there are specific
risk assessment attributes not found in many of the simple index or
relative risk models currently in use. The July 21, 2011, workshop on
``Improving Pipeline Risk Assessments and Recordkeeping'' identified
several shortcomings in risk assessments conducted using qualitative,
index, or relative risk methodologies, and PHMSA is proposing to
clarify requirements to address these issues including the need for
better or more prescriptive guidance to address data gaps, data
integration, uncertainty, interacting threats, risk management, and
quantitative approaches instead of subjective or qualitative
approaches. The proposed regulation would require operators to conduct
risk assessments that effectively analyze the identified threats and
potential consequences of an incident for each HCA segment.
Additionally, the proposed regulation would require the risk assessment
to include evaluation of the effects of interacting threats, including
those threats and anomalous conditions not previously evaluated. It
should be further noted that the intent of the original IM rule is that
any risk assessment would consider system-wide risk.
E.3. How, if at all, are existing models used to inform executive
management of existing risks?
1. INGAA commented that operators should develop internal
communication plans and they should follow Section 10.3 of ASME/ANSI
B31.8S in doing so. AGA similarly noted that the methods used to
disseminate results of the risk evaluation to executive management are
operator specific and detailed in the operator's integrity management
plan. A number of pipeline operators provided comments supporting both
INGAA's and AGA's comments.
2. Texas Pipeline Association and Texas Oil & Gas Association noted
that the results of risk modeling are usually used in conjunction with
assessment results to inform executive management of actions required
beyond normal repair, additional preventive and mitigative measures,
discussion of high risk pipelines, and progress in meeting assessment
goals.
3. WKM Consultancy commented that operators are obliged to
communicate all aspects of integrity management to higher level
managers at regular intervals. They noted that all prudent operators
are very interested in risk management and results of risk modeling are
usually a centerpiece of discussion and decision-making.
4. Ameren Illinois reported that its IM plan provides for informing
executive management of existing risks.
5. Atmos reported that it provides executive management with
periodic updates on the status of its integrity management program.
During these updates, Atmos' executive management reviews baseline
assessment plans, assessment results, anomalies discovered and
mitigated, anomalies discovered and scheduled for repair, leading
causes of anomalies, and preventive and mitigative actions taken.
6. Kern River noted that it provides its executive management with
reports describing integrity management program activities and results
and that the company engages the use of the risk model as an input to
financial planning and maintenance planning. MidAmerican also reported
that risk scores are used to support capital, operating and maintenance
expenditures to executive management.
7. Northern Natural Gas reported that it provides executive
management with reports describing integrity management program
activities and results. Its executive management is engaged in the
process and the use of the risk model to prioritize projects.
8. Paiute and Southwest Gas reported that integrity management
activities are discussed with executive management quarterly.
9. An anonymous commenter suggested that operators generally do not
use risk models to inform executives, because they would have to
explain the models in order to do so.
Response to Question E.3 Comments
PHMSA appreciates the information provided by the commenters. PHMSA
understands that internal company processes for communication with
executive management are specific to each company. To strengthen the
application of risk assessment, PHMSA is proposing to clarify
requirements by providing more specific and detailed examples of the
kinds of preventive and mitigative measures operators should consider.
The proposed rulemaking would include the following specific examples
of preventive and mitigative measures that operators should consider:
Establish and implement adequate operations and maintenance processes;
establish and deploy adequate resources for successful execution of
activities, processes, and systems associated with operations,
maintenance, preventive measures, mitigative measures, and managing
pipeline integrity; and correct the root cause of past incidents to
prevent recurrence. The last item necessarily requires a robust root
cause analysis that identifies underlying programmatic or policy issues
that create or facilitate conditions or circumstances that ultimately
lead to pipeline failures.
E.4. Can existing risk models be used to understand major
contributors to segment risk and support decisions regarding how to
manage these contributors? If so, how?
1. INGAA and many of its pipeline operator members commented that
existing models can and do provide an understanding of segment risk
through threat identification, performing ``what if'' analyses, and
identifying preventive and mitigative measures that will reduce risk.
2. AGA and GPTC noted that existing models selected by operators
are sufficiently robust to allow the integration of large volumes of
data and information to achieve a comprehensive overall risk evaluation
for their systems. These risk models allow an operator to understand
the specific threats associated with each pipeline segment and the
preventive and mitigative measures that would be most appropriate. A
number of pipeline operators provided comments supporting AGA's
comments.
3. WKM Consultancy opined that currently used risk assessment
models generally can significantly improve the ability to manage risks.
They noted that a formal risk assessment provides the structure to
increase understanding, reduce subjectivity, and ensure that important
considerations are not overlooked.
4. Atmos reported that its model can be used to generate a report
listing the significant variables contributing to a relatively higher
risk factor score, and that if a contributing variable can be
controlled, the risk model can support further actions to control the
variable.
5. Ameren Illinois reported that it uses a robust risk model that
can integrate various risk factors in order to evaluate its system.
6. Kern River and Northern Natural Gas commented that existing risk
models can be used to understand major contributors to segment risk and
support decisions regarding how to manage these contributors. By
identifying threat drivers in the risk results and analyzing the data
used by the model, integrity management personnel are able to reduce
risk through preventive and mitigative measures, improvements in data
quality, and shorter reassessment intervals.
[[Page 20766]]
7. MidAmerican reported that its risk model is used to understand
major contributors to risk and to support decisions regarding how to
manage those contributors.
8. Paiute and Southwest Gas reported that they conduct a review of
threat-specific indices to identify the major contributors to risk for
each threat.
9. Texas Pipeline Association and Texas Oil & Gas Association noted
that risk modeling can be used to generate reports listing the
significant variables contributing to high risk scores.
10. An anonymous commenter noted that risk models can serve these
functions and some operators use them in this way. The commenter opined
that most operators ``aren't there yet,'' and that operators who use
models for this purpose have more enthusiasm for integrity management
and more executive management support.
Response to Question E.4 Comments
PHMSA appreciates the information provided by the commenters. The
majority of the comments suggest that current risk models provide an
adequate understanding of major contributors to risk. PHMSA believes it
is prudent to clarify the required attributes of risk assessment in
this area and proposes to include performance-based language to assure
that risk assessments adequately identify the contribution to risk of
each risk factor, or each unique combination of risk factors that
interact or simultaneously contribute to risk at a common location.
E.5. How can risk models currently used by pipeline operators be
improved to assure usefulness for these purposes?
1. INGAA noted that continuous improvement is required, and that
industry is working on improvements to ASME/ANSI B31.8S. AGA similarly
noted that risk models are periodically improved by operators by
integrating new data and the results of integrity assessments. A number
of pipeline operators provided comments supporting INGAA's and AGA's
comments.
2. GPTC commented that new data and information are received on an
ongoing basis. This new data, and results of integrity assessments, are
reviewed, integrated, and added to risk models periodically.
3. WKM Consultancy suggested that a limited amount of
standardization would be appropriate. They opined that this would
ensure that all risk assessments contain, at a minimum, a short list of
essential ingredients. For example, all assessments should produce a
profile showing changes in risk along a pipeline route.
4. Ameren Illinois reported that its risk model allows for
integration of information for continuous improvement.
5. Atmos commented that there is the potential for the risk model
process to handle unknown data in a more useful manner. Atmos suggested
that a higher risk score with ``known'' data attributes should be
considered more relevant for decisions on preventive and mitigative
measures than a similar score derived from ``unknown'' data attributes.
6. Kern River suggested that industry-wide research into failure
probabilities and effectiveness of preventive and mitigative measures
would facilitate more rigorous quantitative models. Kern River noted
that vendors are continuously improving risk models.
7. MidAmerican suggested that risk models could be improved with
better tracking, recording, and retrieval of assessment results. With
feedback and information sharing, refining coefficients within the
model will produce more accurate risk results.
8. Northern Natural Gas reported that its risk assessment process
is improved every year and that its risk model vendor is heavily
involved with the company in understanding how the risk results are
used.
9. Paiute and Southwest Gas suggested that risk models will be
improved as additional information is gained through an assessment
cycle and that this continuous improvement process will then repeat
through subsequent assessment cycles.
10. Texas Pipeline Association and Texas Oil & Gas Association
observed that there is no `one size fits all' solution to this issue.
Response to Question E.5 Comments
PHMSA appreciates the information provided by the commenters. The
comments speak in general terms about incremental improvement of
existing index-type or qualitative relative risk models. PHMSA believes
that such models, while appropriate and useful for limited purposes
such as ranking segments to prioritize baseline assessments, fall far
short of the type of model needed to fully execute a mature integrity
management program. PHMSA proposes to clearly articulate the
requirements for validation of the risk assessment and proposes to
clarify that an operator must ensure validity of the methods used to
conduct the risk assessment in light of incident, leak, and failure
history and other historical information. Additionally, the proposed
rule would require that validation must: (1) Ensure the risk assessment
methods produce a risk characterization that is consistent with the
operator's and industry experience, including evaluations of the cause
of past incidents as determined by root cause analysis or other means;
and (2) include analysis of the factors used to characterize both the
probability of loss of pipeline integrity and consequences of the
postulated loss of pipeline integrity.
E.6. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements pursuant to the commenter's suggestions.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the
existing regulatory requirements.
No comments were received in response to this question.
F. Strengthening Requirements for Applying Knowledge Gained Through the
IM Program
The ANPRM requested comments regarding strengthening requirements
related to operators' use of insights gained from implementation of an
IM program. IM assessments provide information about the condition of
the pipeline. Identified anomalies that exceed criteria in Sec.
192.933 must be remediated immediately (Sec. 192.933(d)(1)) or within
one year (Sec. 192.933(d)(2)) or must be monitored on future
assessments (Sec. 192.933(d)(3)). Operators are also expected to apply
knowledge gained through these assessments to assure the integrity of
their entire pipeline as part of its threat identification and risk
analysis process in accordance with Sec. 192.917.
Section 192.917(e)(5) explicitly requires that operators must
evaluate other portions of their pipeline if an assessment identifies
corrosion requiring repair under the criteria of Sec. 192.933. The
operator must ``evaluate and remediate, as necessary, all pipeline
segments (both covered and non-covered) with similar material coating
and environmental characteristics.''
Section 192.917 also requires that operators conduct risk
assessments that follow American Society of Mechanical Engineers/
American National Standards Institute (ASME/ANSI) B31.8S, Section
[[Page 20767]]
5, and use these analyses to prioritize segments for assessment, and to
determine what preventive and mitigative measures are needed for
segments in HCAs. Section 5.4 of ASME/ANSI B31.8S states that ``risk
assessment methods should be used in conjunction with knowledgeable,
experienced personnel . . . that regularly review the data input,
assumptions, and results of the risk assessments.'' That section
further states, ``an integral part of the risk assessment process is
the incorporation of additional data elements or changes to facility
data,'' and requires that operators ``incorporate the risk assessment
process into existing field reporting, engineering, and facility
mapping processes'' to facilitate such updates. Neither part 192 nor
ASME/ANSI B31.8S specifies a frequency at which pipeline risk analyses
must be reviewed and updated; instead, this is considered to be a
continuous, ongoing process. The following are general comments
received related to the topic as well as comments related to the
specific questions:
General Comment for Topic F
1. MidAmerican suggested that application of knowledge gained
through integrity management should not be treated any differently than
any other information gained from work on or surveillance of the
pipeline. MidAmerican considers this to be adequately addressed by
Sec. 192.613.
Response
PHMSA continues to believe that there are many important integrity
management requirements related to insights gained from implementation
of the IM program beyond those covered by the continuing surveillance
requirements of Sec. 192.613. Integrity management assessments provide
information about the condition of the pipeline and operators are
expected to apply the knowledge gained through these assessments to
assure the integrity of their entire pipeline. PHMSA believes that the
knowledge gained through IM assessments should be integrated into the
risk assessment process, which is not required by Sec. 192.613.
Comments Submitted for Questions in Topic F
F.1. What practices do operators use to comply with Sec.
192.917(e)(5)?
1. INGAA and a number of pipeline operators noted that operators
use available information and field knowledge to comply with this
requirement.
2. AGA, supported by a number of its member companies, reported
that operator practices are too distinct and varied to list. AGA stated
that Sec. 192.917(e)(5) is prescriptive enough and no new requirements
are needed.
3. GPTC and Nicor cited NACE SP0169 and NACE RP0177 as examples of
standards that can be used to guide compliance with Sec.
192.917(e)(5).
4. Texas Pipeline Association and Texas Oil & Gas Association
commented that operators use cathodic protection surveys and/or spot
checks to determine whether failure is likely.
5. Northern Natural Gas reported that it takes the actions
specified in Sec. 192.917(e)(5) and includes consideration of
incidents and safety related conditions.
6. Kern River, Paiute, and Southwest Gas stated that they use root
cause evaluations of incidents to comply with Sec. 192.917(e)(5).
Response to Question F.1 Comments
PHMSA appreciates the information provided by the commenters. The
comments provide little information related to specific operator
practices for compliance with Sec. 192.917(e)(5). PHMSA is not
proposing to amend Sec. 192.917(e)(5) at this time; however, PHMSA
proposes to clarify requirements in Sec. 192.917(b) to ensure that the
data gathering and integration process includes an analysis of both the
HCA segments and similar non-HCA segments and integrates information
about pipeline attributes and other relevant information, including
data gathered through integrity assessments.
F.2. How many times has a review of other portions of a pipeline in
accordance with Sec. 192.917(e)(5) resulted in investigation and/or
repair of pipeline segments other than the location on which corrosion
requiring repair was initially identified?
1. Based on a limited response by their members to a survey, Texas
Pipeline Association and Texas Oil & Gas Association reported that
repair of corrosion beyond the initially-identified anomaly is rare.
2. Ameren Illinois reported that it has experienced two instances
in which it repaired other segments after identifying corrosion on a
covered pipeline segment.
3. MidAmerican reported that it has experienced a few instances of
corrosion where coating was damaged during installation of a vent, and
some at air-to-soil interfaces.
4. Northern Natural Gas has experienced no instances in which other
pipeline segments required repair. Northern added that corrosion wall
loss requiring repair is, itself, rare.
5. Paiute and Southwest Gas reported that they had not identified
any immediate repair corrosion conditions.
Response to Question F.2 Comments
PHMSA appreciates the information provided by the commenters. See
the response to question F.1.
F.3. Do pipeline operators assure that their risk assessments are
updated as additional knowledge is gained, including results of IM
assessments? If so, how? How is data integration used and how often is
it updated? Is data integration used on alignment maps and layered in
such a way that technical reviews can identify integrity-related
problems and threat interactions? How often should aerial photography
and patrol information be updated for IM assessments? If the commenter
proposes a time period for updating, what is the basis for this
recommendation?
1. INGAA and several pipeline operators reported that operators
update risk analyses whenever new information is obtained and
particularly after unexpected events.
2. AGA, GPTC, Nicor, Kern River, and TransCanada commented that
risk analyses are updated at least annually.
3. Northern Natural Gas reported that its procedures provide for
updating to include assessment results and changes in environmental
factors.
4. Paiute and Southwest Gas reported that risk model updating is a
continuous process. Rankings are updated at 18- to 24-month intervals.
Ameren Illinois and Atmos similarly reported that updating is an
ongoing activity.
5. Texas Pipeline Association and Texas Oil & Gas Association
commented that most operators have dedicated teams to perform risk
model updates.
6. Alaska Department of Natural Resources commented that risk
models should be reviewed whenever significant operational or
environmental changes occur. AKDNR contended that risk models are not
valid if there are significant changes in these areas.
7. NAPSR reported its conclusion that risk models should be updated
after every O&M activity or any finding that a required activity was
not performed.
8. INGAA and a number of pipeline operators reported that data is
updated using a common spatial reference system, e.g., maps or tables,
and the frequency of data integration varies by operator.
9. AGA, supported by a number of its member companies, reported
that data integration does not always involve use of geospatial tools.
[[Page 20768]]
10. Atmos reported that it uses internal teams of subject matter
experts for data integration and that its maps are not layered for
technical data use.
11. Northern Natural Gas, Paiute, and Southwest Gas stated that
they perform integration on alignment sheets based on integrity
management summaries and subject matter expert reviews.
12. Texas Pipeline Association and Texas Oil & Gas Association
reported that many pipeline operators are migrating to GIS systems.
13. INGAA and many pipeline operators commented that information
from aerial photography should be updated annually. They noted that
this would be consistent with the frequency of reviewing HCA
designations and operator budgeting and contended that more frequent
updates would not increase risk model accuracy. INGAA suggested that
other information, including information related to external events,
should be updated based on the nature and severity of experienced
events.
14. AGA, Paiute, and Southwest Gas noted that not all operators use
aerial photography and expressed their belief that such use should not
be required. AGA noted that there are many tools, including routine
patrols, to gather data about the pipeline environment. A number of
member pipeline operators supported AGA's comments.
15. Northern Natural Gas reported that it updates information
periodically, but with no set frequency. Northern noted that some areas
are stable while change can occur rapidly in others.
16. Texas Pipeline Association and Texas Oil & Gas Association
recommended annual updates as a minimum. The associations noted that
this recognizes the time required to produce/acquire assessment data.
Response to Question F.3 Comments
PHMSA appreciates the information provided by the commenters. After
review of the comments, PHMSA agrees that annual updates are desirable
and many operators perform full updates, or partial data updates (such
as updating aerial photos), annually. Some pipeline segments may be in
rapidly changing, dynamic environments, while others may remain static
for years. PHMSA also agrees that prescriptive requirements to perform
a full risk assessment annually are not necessary and potentially
burdensome, especially for very small operators, whose systems and
conditions do not change often. PHMSA is satisfied that the current
requirement, which contains a performance based requirement to update
risk assessments as frequently as needed to assure the integrity of
each HCA segment is adequate, if properly implemented, and is not
proposing a prescribed frequency at this time. However, PHMSA proposes
to clarify requirements in Sec. Sec. 192.917 and 192.937(b) to ensure
the continual process of evaluation and assessment is based on an
updated and effective data integration and risk assessment process as
specified in Sec. 192.917.
F.4. Should the regulations specify a maximum period in which
pipeline risk assessments must be reviewed and validated as current and
accurate? If so, why?
1. INGAA and numerous pipeline operators recommended that reviews
be annual, as suggested in PHMSA's Gas Integrity Management Program
Frequently Asked Question FAQ-234, arguing that this is practical and
sufficient (FAQs can be viewed at https://primis.phmsa.dot.gov/gasimp/faqs.htm).
2. AGA, GPTC, and a number of other pipeline operators commented
that no maximum period should be specified for review of risk
assessments. These commenters argued that no one-size-fits-all interval
would be appropriate and expressed their conclusion that the current
requirements in Sec. 192.937 are adequate.
3. California Public Utilities Commission recommended that reviews
be required annually, at intervals not to exceed 15 months, consistent
with other requirements within part 192.
4. An anonymous commenter suggested that a specified review period
would be counterproductive, arguing that most operators would simply
default to the required interval, even if more frequent reviews were
appropriate.
Response to Question F.4 Comments
PHMSA appreciates the information provided by the commenters. See
PHMSA response to comments related to Question F.3.
F.5. Are there any additional requirements PHMSA should consider to
assure that knowledge gained through IM programs is appropriately
applied to improve safety of pipeline systems?
1. INGAA and many pipeline operators opined that no new
requirements are needed in this area. They noted that prescriptive
requirements often become out of date as technology improves.
2. AGA and numerous pipeline operators agreed that no new
requirements are needed, noting that existing regulations and sharing
of information through industry groups is sufficient.
3. Texas Pipeline Association and Texas Oil & Gas Association
opined that existing requirements are adequate.
4. Accufacts suggested that requirements should be more
prescriptive concerning threat evaluation and interactive threats, as
this is the heart of integrity management.
5. An anonymous commenter suggested that new requirements be
established governing assessments conducted by pressure testing. The
commenter opined that the requirements in subpart J are inadequate and
represent an ``easy out'' for some operators.
Response to Question F.5 Comments
PHMSA appreciates the information provided by the commenters. While
PHMSA believes that explicit requirements should be included to address
interactive threats, PHMSA also believes that prescriptive rules for
how an operator must evaluate interactive threats are not practical.
Therefore, PHMSA proposes to clarify performance-based requirements to
include an evaluation of the effects of interacting threats and for the
continual process of evaluation and assessment to include interacting
threats in identification of threats specific to each HCA segment.
Comments on integrity assessment methods are addressed in Topic G.
F.6. What do operators require for data integration to improve the
safety of pipeline systems in HCAs? What is needed for data integration
into pipeline knowledge databases? Do operators include a robust
database that includes: Pipe diameter, wall thickness, grade, and seam
type; pipe coating; girth weld coating; maximum operating pressure
(MOP); HCAs; hydrostatic test pressure including any known test
failures; casings; any in-service ruptures or leaks; ILI surveys
including high resolution--magnetic flux leakage (HR-MFL), HR geometry/
caliper tools; close interval surveys; depth of cover surveys;
rectifier readings; test point survey readings; alternating current/
direct current (AC/DC) interference surveys; pipe coating surveys; pipe
coating and anomaly evaluations from pipe excavations; SCC excavations
and findings; and pipe exposures from encroachments?
1. INGAA, supported by a number of pipeline operators, commented
that experience and information gained from a variety of sources,
including GIS data, corrosion data, ILI data/results, work management
activities, SCADA, encroachments, leaks etc., is utilized in data
integration. INGAA reported that operators have made major investments
[[Page 20769]]
in database applications to meet changing organizational and regulatory
requirements and to manage increasing volumes of data effectively.
Tools generally are available for integrating data into pipeline
knowledge databases. For integration purposes, the database must
contain adequate metadata elements such that dates, if important, and
location and length attributes are maintained. Currently-available
systems support these needs. INGAA expressed concern over use of the
term ``robust database,'' since this could be construed to mean that
all applicable data must be maintained in a common database or other
venue which does not meet the particular needs of the operator. INGAA
reported that it has an active Integrity Management--Continuous
Improvement (IMCI) team addressing improvement in these processes and
management systems.
2. AGA, GPTC, and a number of pipeline operators commented that a
prescriptive requirement would be inappropriate because there is too
much variability among operators and their risk assessment methods. AGA
expressed its conclusion that there is no single methodology that
incorporates the wide variety of pipeline information used by
operators.
3. MidAmerican suggested that an operator needs a robust computer
model to integrate diverse data dynamically into one table with one set
stationing.
4. Kern River reported that it uses extensive GIS and cathodic
protection databases for these purposes.
5. An anonymous commenter recommended that PHMSA require knowledge
of cathodic protection current level, amount, and direction of current
flow. The commenter opined that this information is not now generally
collected, and that it would allow for early detection of coating
failures and CP interferences.
Response to Question F.6 Comments
PHMSA appreciates the information provided by the commenters. An
integral part of applying information from the IM Program to the risk
assessment and other analyses is the collection, validation, and
integration of pipeline data. PHMSA proposes to clarify the data
integration language in the requirements by repealing the reference to
ASME/ANSI B31.8S and including requirements associated with data
integration directly in the rule text: (1) Establishing a number of
pipeline attributes that must be included in these analyses, (2)
clarifying that operators must integrate analyzed information, and (3)
ensuring that data are verified and validated.
F.7. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements pursuant to the commenter's suggestions.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the
existing regulatory requirements.
No comments were received in response to this question.
G. Strengthening Requirements on the Selection and Use of Assessment
Methods
The existing IM regulations require that baseline and periodic
assessments of pipeline segments in an HCA be performed using one of
four methods:
(1) In-line inspection;
(2) Pressure test in accordance with subpart J;
(3) Direct assessment to address the threats of external and
internal corrosion and SCC; or
(4) Other technology that an operator demonstrates can provide an
equivalent understanding of the condition of line pipe.
Operators must notify PHMSA in advance if they plan to use ``other
technology.'' Operators must apply one or more methods, depending on
the threats to which the HCA segment is susceptible. The ANPRM
requested comments related to the applicability, selection, and use of
each assessment method, existing consensus standards and requirements,
and the potential need to strengthen the requirements. The ANPRM then
listed questions for consideration and comment. The following are
general comments received related to the topic as well as comments
related to the specific questions:
General Comments for Topic G
1. INGAA, supported by a number of its pipeline operator members,
noted that they are committed to work with technology providers and
researchers to improve the integrity management assessment capabilities
of its members. Further, INGAA members are sharing their experiences
with applying these new and improved assessment methods to specific
threats. INGAA opined that a great advantage of the integrity
management structure, as opposed to a prescriptive regulatory regime,
is the creation of an environment conducive to technological
development, innovation and improved knowledge.
2. Accufacts suggested that a more prescriptive regulation is
needed clarifying the applicability and limitations of direct
assessment. Accufacts is concerned that operators are selecting direct
assessment due to a cost bias while ignoring that it cannot be used for
all threats and should not be used on some pipeline segments.
3. Chevron commented that PHMSA should continue to allow operators
to select and use the most effective method to assess each pipeline
segment.
4. NAPSR recommended that PHMSA implement a regulatory change that
requires both ILI and pressure testing for all transmission pipelines
and requires a reduction in MAOP until either the ILI or the pressure
tests are performed.
5. MidAmerican, a gas distribution company, noted that many of its
transmission pipelines are short, small diameter lines that cannot be
pigged.
6. Dominion East Ohio suggested that PHMSA should be funding more
research leading to the development of assessment tools, particularly
smart tools, to increase the number of assessment options available
rather than limiting the tools that can be used.
7. A public citizen commented that pipe with unknown or uncertain
specifications should be subject to the most stringent testing
requirements.
8. Two public citizens addressed required assessment intervals. One
suggested that all pipe that puts the public at significant risk should
be tested, by hydro testing or some other means, at approximately ten-
year intervals. Another commenter recommended that assessments be
required more frequently in densely populated areas.
9. PST opined that the need to ask the questions in this section
makes clear that PHMSA's current level of oversight and review of IM
planning and implementation is inadequate, and calls into question the
value of many IM programs, particularly those relying to any extent on
direct assessment methods. PST recommended that the regulations be
significantly strengthened to require PHMSA's review and administration
approval of any IM program.
Response
PHMSA appreciates the information provided by the commenters. PHMSA
agrees that pipeline operators should be able to select the best
assessment
[[Page 20770]]
method applicable for its pipelines and circumstances. PHMSA also
agrees with NAPSR and other commenters that additional requirements are
needed for assessing more miles of pipeline that pose a risk to the
public. PHMSA has also identified the need to address specific issues
related to the selection of integrity assessment methods that have been
identified following the San Bruno incident, especially related to the
use of direct assessment. Therefore, PHMSA proposes to add more
specific requirements related to (1) performance of integrity
assessments for pipe not covered by subpart O (i.e., pipeline not
located in a high consequence area) that represents risk to the public,
and (2) selection of assessment methods. Specifically, PHMSA proposes
to revise the requirements in Sec. Sec. 192.921 and 192.937 as
follows: (1) Allow direct assessment only if a line is not capable of
inspection by internal inspection tools; (2) add a newly defined
assessment method: ``spike'' hydrostatic test; (3) add excavation and
in situ direct examination as an allowed assessment method; and (4) add
guided wave ultrasonic testing (GWUT) as an allowed assessment method.
In addition, PHMSA proposes to add a new Sec. 192.710 to require that
a significant portion of pipelines not covered by subpart O be
periodically assessed using integrity assessment techniques similar to
those proposed for HCA segments. Specifically, PHMSA proposes to
require that all pipeline segments in class 3 and class 4 locations and
moderate consequence area as defined in Sec. 192.3 if the pipe segment
can accommodate inspection by means of instrumented inline inspection
tools (i.e., ``smart pigs''), be periodically assessed. Although PHMSA
proposes to provide selected, more prescriptive requirements for the
selection of assessment methods, the pipeline safety regulations would
continue to allow the use of other technology that an operator
demonstrates can provide an equivalent understanding of the condition
of the line pipe (comparable to a specified integrity assessment such
as pressure testing or inline inspection), in order to continue to
encourage research and development of more effective assessment
technologies similar to the successful development of GWUT. For non-HCA
segments, operator notification to PHMSA of the selection of other
technologies would not be required.
PHMSA understands the Pipeline Safety Trust's recommendation that
the regulations require PHMSA's review and approval of any IM program.
PHMSA believes its current approach to inspection of operator IM
programs is both flexible and appropriate.
Comments Submitted for Questions in Topic G
G.1. Have any anomalies been identified that require repair through
various assessment methods (e.g., number of immediate and total repairs
per mile resulting from ILI assessments, pressure tests, or direct
assessments)?
1. INGAA reported that operators have used in-line inspection,
pressure testing, and direct assessment, with in-line inspection being
most prevalent. INGAA commented that all three methods have been
successful at identifying anomalies requiring repair. A number of
pipeline operators supported INGAA's comments.
2. AGA and Ameren Illinois stated that all assessment methods used
by pipeline operators have been used to identify, or have identified,
anomalies requiring repair. A number of pipeline operators supported
AGA's comments.
3. Accufacts recommended that PHMSA publically report the number of
anomalies discovered and repaired by anomaly type, time to repair,
state, and assessment method for both HCAs and non-HCAs.
4. Texas Pipeline Association, Texas Oil & Gas Association, Atmos,
Paiute, and Southwest Gas noted that the transmission pipeline annual
report includes the number of immediate and scheduled anomalies
identified by each assessment method.
5. ITT Exelis Geospatial Systems reported that aerial leak surveys
using laser technology, which is not one of the assessment methods
specified in the regulations, have been successful in identifying
pipeline leaks.
6. Kern River reported that it did not identify any immediate or
scheduled repairs from January 1, 2004, through December 31, 2010.
7. MidAmerican noted that it has used all three allowed assessment
methods. Approximately 42 percent of the company's pipeline has been
assessed using direct assessment. All anomalies requiring repair have
been identified using in-line inspection.
8. Northern Natural Gas reported that it identified seven immediate
repair anomalies in the period from January 1, 2004, through December
31, 2010. The total number of repairs made during this same period
averaged 0.1 per mile.
9. An anonymous commenter noted that few leaks are detected using
subpart J pressure testing.
10. GPTC reported that it has no data with which to respond to this
question.
Response to Question G.1 Comments
PHMSA appreciates the information provided by the commenters. PHMSA
agrees that all three methods have been successful at identifying
anomalies requiring repair. However, by its nature, direct assessment
is a sampling-type assessment method. Hydrostatic pressure testing and
in-line inspection both assess the entire segment. PHMSA, therefore,
believes that these methods provide a higher level of assurance (though
still not 100%) that no injurious pipeline defects remain in the pipe
after the assessment is completed and anomalies repaired. Based on this
inherent difference, PHMSA proposes to revise the requirements to: (1)
Allow direct assessment only if a line is not capable of inspection by
internal inspection tools; (2) add a newly defined assessment method:
``spike'' hydrostatic test; (3) add excavation and in situ direct
examination as an allowed assessment method; and (4) add guided wave
ultrasonic testing (GWUT) as an allowed assessment method.
G.2. Should the regulations require assessment using ILI whenever
possible, since that method appears to provide the most information
about pipeline conditions? Should restrictions on the use of assessment
technologies other than ILI be strengthened? If so, in what respect?
Should PHMSA prescribe or develop voluntary ILI tool types for
conducting integrity assessments for specific threats such as corrosion
metal loss, dents and other mechanical damage, longitudinal seam
quality, SCC, or other attributes?
1. INGAA, supported by a number of its pipeline operator members,
noted that ILI is effective, but has its own limitations; pressure
testing and direct assessment can provide information that ILI cannot.
INGAA commented that operators must be allowed to use all assessment
techniques without encumbrances or conditions because all techniques
are effective.
2. AGA and a number of its members commented that ILI is one option
of a variety of methods available to operators and suggested that
applying additional ILI assessment requirements would hinder operators'
ability to select the tool with the appropriate capabilities to address
pipeline threats. AGA commented that this would be inappropriate and
operators must be allowed to use any of the three assessment methods,
without conditions, based on the circumstances and threats applicable
to their pipelines.
3. Air Products and Chemicals, Inc. opposed a requirement to use
ILI whenever possible. The company noted
[[Page 20771]]
that one of the benefits of the current IM framework is the flexibility
it provides to operators in how to achieve regulatory goals. Air
Products noted that use of alternative methods is already constrained
by regulation and contended that the existing limitations are adequate
and it would be inappropriate for PHMSA to specify particular tool
types for individual threats. Atmos agreed, noting that ILI is not the
only assessment method applicable to many threats. Atmos noted that ILI
technology is developing at a rapid pace, and suggested that
prescribing certain tool types could limit future advancements or cause
the rate of development to be slowed.
4. TransCanada opposed requiring use of ILI. The company noted that
ILI has its advantages, but it also has limitations, and commented that
operators must be able to select the methods best suited to evaluate
identified threats, given the wide range of circumstances and threats
that may be applicable to particular pipeline segments.
5. NACE International noted that assessments using only ILI do not
necessarily provide the most information about pipeline conditions;
other assessment methods may be more appropriate for some threats. NACE
also noted that not all pipelines are piggable. NACE believes that each
assessment method has strengths and weaknesses, each should be used
where appropriate, and overly prescriptive rules can supplant sound
engineering judgment, stifle innovation, and prevent the development of
new technologies.
6. Accufacts commented that all new pipelines should be configured
to permit ILI and a timetable should be established to convert older
pipelines for ILI. At the same time, Accufacts cautioned that one
particular approach to ILI should not be oversold, and suggested that
limitations on use of certain assessment methods should be strongly
clarified in regulations. Accufacts suggested that PHMSA needs to
clarify the major strengths and weaknesses of the various assessment
methods identified and to improve subpart J, including requiring the
reporting of hydro testing pressure ranges, both minimum and maximum
pressures, as a percentage of SMYS when appropriate.
7. MidAmerican suggested that operators be allowed to address
threats by category using the guidance in ASME/ANSI B31.8S. MidAmerican
noted that it cannot use ILI on all of its transmission pipelines, 42
percent of which have been assessed using direct assessment.
MidAmerican suggested that operators continue to use their threat
assessments to determine which pipelines should be retrofitted to
accommodate ILI.
8. Northern Natural Gas reported that it uses ILI whenever possible
but it cannot be used on all of its lines due to their small diameter.
Northern noted that pressure testing and direct assessment may be more
appropriate for some threats and that the operator is responsible for
selecting the best assessment method. Northern opined that the guidance
on tool selection in ASME/ANSI B31.8S is sufficient.
9. Texas Pipeline Association and Texas Oil & Gas Association
recommended that ILI not be the required assessment method of choice
and that operators continue to have the flexibility to select the
appropriate assessment method, noting that other methods may be better
for a particular threat. The associations noted that ILI technology is
improving rapidly and expressed concern that rulemaking cannot keep
pace with technological advancement and that prescribing tools could
result in assessments being conducted with inferior technology.
10. Thomas M. Lael, an industry consultant, noted that no
assessment method, including ILI, is perfect. Lael suggested that use
of alternating methods be required to realize the strengths of all
methods.
11. A citizen commenter suggested that use of direct assessment be
limited, since it does not provide sufficient information about the
pipeline.
12. An anonymous commenter noted that requiring ILI would not be
cost beneficial, because corrosion metal loss is a relatively slow
process.
13. GPTC noted that ILI cannot be used on all pipelines and
recommended that operators have the latitude to select the assessment
method most appropriate for their pipelines. Oleksa and Associates
similarly noted that ILI cannot be used on some pipelines.
14. Paiute and Southwest Gas opposed a requirement to use ILI
whenever possible. The companies noted that ILI provides current pipe
conditions but no information on environmental conditions surrounding
the pipe. They commented that operators should not be discouraged from
using any appropriate assessment method.
15. Ameren Illinois opposed requiring the use of ILI, noting that
it is neither practical nor feasible to require ILI assessments on all
pipelines.
16. California Public Utilities Commission recommended that
pressure testing and ILI be the only methods allowed for IM
assessments. CPUC suggested that the use of direct assessment be
limited to confirmatory direct assessments and lines that have been
pressure tested to subpart J requirements. CPUC further recommended
that the regulations prescribe acceptable ILI tool types to address
specific threats.
17. A private citizen suggested that pressure testing should not be
allowed as an assessment method because it provides no information
about anomalies not resulting in leaks or failures. The commenter
suggested that use of pressure testing should be limited to verifying
the integrity of new or repaired pipelines.
Response to Question G.2 Comments
PHMSA appreciates the information provided by the commenters. PHMSA
agrees that operators should be able to select the methods best suited
to evaluate identified threats. However, PHMSA believes rulemaking for
strengthening requirements for the selection and use of assessment
methods is needed to address specific issues identified from the San
Bruno incident. PHMSA proposes more prescriptive guidance for the
selection of assessment methods, especially related to the use of
direct assessment and to assess for cracks and crack-like defects, as
indicated in the response to general comments, above. For HCA segments,
PHMSA proposes that the use of direct assessment as the assessment
method would be allowed only if the pipeline is not capable of being
inspected by internal, in-line inspection tools. For non-HCA segments,
assessments would have to be done within 15 years and every 20 years
thereafter. To facilitate the identification of non-HCA areas that
require integrity assessment, PHMSA proposes to define a ``Moderate
Consequence Area'' or MCA. PHMSA also proposes additional requirements
for selection and use of internal inspection tools, including a
requirement to explicitly consider uncertainties such as tool tolerance
in reported results in identifying anomalies.
PHMSA disagrees with the suggestion that pressure testing should
not be allowed as an assessment method. In many circumstances, pressure
testing is a good indicator of a pipeline's integrity. Although it does
not assess subcritical defects, it provides assurance of adequate
design safety margin and can be useful in particular for lines that are
not piggable.
G.3. Direct assessment is not a valid method to use where there are
pipe properties or other essential data gaps. How do operators decide
whether their
[[Page 20772]]
knowledge of pipeline characteristics and their confidence in that
knowledge is adequate to allow the use of direct assessment?
1. Industry commenters, including AGA, INGAA, Texas Pipeline
Association, Texas Oil and Gas Association, and numerous pipeline
operators noted that the requirements applicable to direct assessment,
specified in NACE Standard SP0502-2008 and incorporated into subpart O
by reference, require a feasibility study to determine if use of direct
assessment is appropriate. If it cannot be determined during the pre-
assessment phase that adequate data is available, another assessment
method must be selected. Industry commenters noted that it is the
operator's responsibility to select an appropriate assessment method.
2. Paiute and Southwest Gas disagreed with the statement that
``direct assessment is not a valid method to use where there are pipe
properties or other essential data gaps.'' The companies noted that the
data gathered and evaluated conforms to Section 4 of ASME/ANSI B31.8S
(incorporated by reference) which allows use of conservative proxy
values when data gaps exist.
3. California Public Utilities Commission recommended that pressure
testing and ILI be the only methods allowed for IM assessments. CPUC
suggested that use of direct assessment be limited to confirmatory
direct assessments and lines that have been pressure tested to subpart
J requirements.
Response to Question G.3 Comments
PHMSA appreciates the information provided by the commenters. PHMSA
agrees that pressure testing and ILI are preferred integrity assessment
methods, over direct assessment. However, when properly implemented, DA
can be a valuable integrity assessment tool. PHMSA proposes to retain
direct assessment as an assessment method where warranted, but proposes
to revise the requirements in Sec. Sec. 192.921 and 192.937 to allow
use of direct assessment or other method only if a line is not capable
of inspection by internal inspection tools.
G.4. How many miles of gas transmission pipeline have been modified
to accommodate ILI inspection tools? Should PHMSA consider additional
requirements to expand such modifications? If so, how should these
requirements be structured?
1. A number of industry commenters submitted data concerning the
number of pipeline miles that have been modified to accommodate ILI:
INGAA reported that more than 30,000 miles of pipeline
have been modified across the industry.
Atmos reported that it has modified approximately 2,800
miles.
Northern Natural Gas reported that it has modified
approximately 2,500 miles.
MidAmerican reported that it has modified 38 miles.
Paiute and Southwest Gas reported that they have made
modifications but have not tracked the total mileage on which they were
performed.
Ameren Illinois and Kern River reported that they have
modified no pipelines. Kern River noted specifically that all of its
mainline is piggable.
2. AGA reported that it has no data concerning the number of miles
modified, but noted that operators are required to assure that new and
replaced pipelines can accommodate ILI tools. AGA contended that
modifying pipelines to accommodate ILI tools is more onerous for
intrastate transmission pipeline operators than for interstate
operators. A number of operators supported AGA's comments.
3. Texas Pipeline Association and GPTC reported that they have no
data with which to respond to this question.
4. California Public Utilities Commission supported additional
requirements to expand modifications to accommodate ILI but reported
that it has no opinion on how these requirements should be structured.
5. MidAmerican noted that one-third of its 770 miles of
transmission pipeline is of a diameter smaller than available ILI
tools.
6. Northern Natural Gas commented that PHMSA should not consider
additional requirements to expand modifications of pipelines to
accommodate ILI tools, and that the inspection method and determination
to assess additional line segments outside of HCAs should be based on
specific risk factors and type and configuration of pipeline facility.
The company noted that some lines cannot be assessed using ILI.
7. Paiute and Southwest Gas noted that Sec. 192.150 requires that
newly constructed or replacement pipelines be designed to accommodate
ILI tools. They contended that the decision to modify other pipelines
should be an operator decision based on the best assessment method.
8. Texas Pipeline Association and Texas Oil & Gas Association
opined that PHMSA does not need to develop additional requirements for
the modification of transmission pipelines to accommodate ILI tools.
The associations noted that the regulations already cover this for new
and replacement pipelines and that there is a financial incentive for
operators to use ILI tools versus other assessment methods. Atmos
agreed, also noting that there are numerous advantages to ILI that
incentivize operators to use that method when they can.
9. Accufacts commented that PHMSA should report publicly the number
of miles of transmission pipeline that can be inspected by ILI as well
as the number of miles inspected by other assessment methods both for
HCAs and non-HCAs.
Response to Question G.4 Comments
PHMSA appreciates the information provided by the commenters. In
its report on the San Bruno incident, the NTSB recommended that all
natural gas transmission pipelines be configured so as to accommodate
in-line inspection tools, with priority given to older pipelines
(recommendation P-11-17). In its initial response to the NTSB
recommendation, PHMSA stated that implementing this recommendation will
involve significant technical and economic challenges and is likely to
require time to implement. Additional data is needed to evaluate this
issue. Therefore, further rulemaking will be considered separately in
order to complete this evaluation. PHMSA will review the comments
received on the ANPRM and will address this issue in the future.
G.5. What standards are used to conduct ILI assessments? Should
these standards be incorporated by reference into the regulations?
Should they be voluntary?
1. INGAA, supported by a number of its operator members, noted that
standards are continuously upgraded and improved and recommended that
PHMSA adopt performance-based language that will allow operators to
select appropriate standards.
2. AGA, supported by a number of its members, noted that ILI
technology is advancing rapidly and it would be unwise to restrict
innovation by handcuffing it to a slow-developing rulemaking process.
AGA recommended that PHMSA not adopt ILI standards into the code.
Ameren Illinois agreed that standards should not be incorporated,
because to do so would limit operators' ability to use up-to-date
standards.
3. GPTC argued that there is no justification to enact additional
prescriptive regulations for ILI assessments of pipelines. GPTC
contended that performance standards allow operators to select the best
approach.
[[Page 20773]]
4. Atmos, MidAmerican, Northern Natural Gas, Paiute, and Southwest
Gas all cited one or more of API1163, ASNT ILI-PQ-2005 and RP0102-2002,
and ASME/ANSI B31.8S as standards used to conduct ILI assessments. All
agreed that use of industry standards should remain voluntary. Paiute
and Southwest Gas, in particular, commented that technology is
developing rapidly, and that incorporating current standards into the
regulations may hold operators accountable to a level of performance
that may be outdated.
5. Texas Pipeline Association and Texas Oil & Gas Association also
opposed incorporating ILI standards into the regulations. TPA commented
that there are incentives for operators to take appropriate measures to
obtain accurate and reliable ILI results.
6. An anonymous commenter suggested that incorporating standards
could be counterproductive, since operators would usually stop with the
required actions. The commenter suggested that a better approach would
be to require operators to have precise specifications, guidelines, and
a written process for ILI, none of which should be developed by the
operator's ILI vendor. The commenter also suggested that a similar
approach be adopted for stress corrosion cracking direct assessment
(SCCDA).
7. California Public Utilities Commission and a private citizen
recommended that standards be incorporated for mandatory compliance,
arguing that this is necessary to assure quality and accuracy.
Response to Question G.5 Comments
PHMSA appreciates the information provided by the commenters. The
current pipeline safety regulations in 49 CFR 192.921 and 192.937
require that operators assess the material condition of pipelines in
certain circumstances and allow use of in-line inspection tools for
these assessments. Operators are required to follow the requirements of
ASME/ANSI B31.8S in selecting the appropriate ILI tools. ASME B31.8S
provides limited guidance for conducting ILI assessments. At the time
these rules were promulgated, there was no consensus industry standard
that addressed ILI. Three related standards have been published: API
STD 1163-2005, NACE SP0102-2010, and ANSI/ASNT ILI-PQ-2010. These
standards address the qualification of inline inspection systems, the
procedure for performing ILI, and the qualification of personnel
conducting ILI, respectively. The incorporation of these standards into
pipeline safety regulations will promote a higher level of safety by
establishing consistent standards. Therefore, PHMSA is proposing to
incorporate these industry standards into the regulations to provide
better guidance for conducting integrity assessments with in-line
inspection. PHMSA also encourages and actively supports the development
of new and better technology for integrity assessments. Therefore, the
rule also allows the application and use of new technology, provided
that PHMSA is notified in advance. PHMSA will continue to evaluate the
need for additional guidance for conducting integrity assessments or
applying new technology.
G.6. What standards are used to conduct internal corrosion direct
assessment (ICDA) and SCCDA assessments? Should these standards be
incorporated into the regulations? If the commenter believes they
should be incorporated into the regulations, why? What, if any,
remediation, hydrostatic test or replacement standards should be
incorporated into the regulations to address internal corrosion and
SCC?
1. INGAA commented that standards exist for ICDA and SCCDA. AGA
agreed that NACE SP0206 addresses ICDA and SP0204 addresses SCCDA. AGA
opposed adopting these standards into the regulations, however,
commenting that a standard must be demonstrated to be effective before
it can be incorporated. AGA noted that there are long-standing issues
with the ICDA standard. Numerous pipeline operators provided comments
supporting the INGAA and AGA comments.
2. GPTC, Atmos, Ameren Illinois, MidAmerican, Paiute, Southwest
Gas, Texas Gas Association and Texas Oil & Gas Association all
referenced one or more of: NACE SP0502, NACE SP0206, ASME/ANSI B31.8S,
and GRI02-0057. All agreed that the standards should not be
incorporated by reference, arguing that this would stifle innovation or
require operators to follow requirements that may become outdated, or
both. Paiute and Southwest Gas specifically recommended that PHMSA
collect additional information on industry best practices and compile/
review IM results related to internal corrosion and SCC before taking
any action towards incorporating the standards.
3. NACE International reported its conclusion that the existing
standards for ICDA and SCCDA should be incorporated into regulations.
NACE also cautioned that overly-prescriptive regulations can prevent
innovation and development of new technologies.
4. Northern Natural Gas reported that it used NACE SP0206 in
developing its ICDA procedures and there would be no impact on the
company if the standard were adopted into regulations. Northern further
reported it does not use SCCDA.
5. Accufacts commented that few technical gains have been made in
the abilities of direct assessment methods to reliably identify or
assess at-risk anomalies, especially with regards to SCC.
6. California Public Utilities Commission argued that pressure
testing and ILI should be the only assessment methods allowed. The
Commission contended that direct assessment should be limited to use
during confirmatory direct assessments and for lines that have been
pressure tested to subpart J requirements.
7. An anonymous commenter noted that Kiefner, NACE, and ASTM all
provide useful references for SCCDA and ICDA.
8. INGAA, supported by several of its operator members, noted that
ASME/ANSI B31.8S addresses remediation and pressure testing. INGAA
recommended that PHMSA adopt the 2010 version of this standard, arguing
that it is improved over the 2004 standard that is currently
incorporated by reference into Section 192.7 and that it addresses
near-neutral SCC. The 2010 edition also includes specific guidance for
SCC mitigation by means of hydrostatic pressure testing in the event
SCC is identified on a pipeline.
9. MidAmerican reported that it uses ASME B31G to determine
remaining wall strength and that it remediates conditions in accordance
with Sec. 192.933(d) and ASME/ANSI B31.8S.
Response to Question G.6 comments
PHMSA appreciates the information provided by the commenters.
Section 192.927 specifies requirements for gas transmission pipeline
operators who use ICDA for IM assessments. The requirements in Sec.
192.927 were promulgated before there were consensus standards
published that addressed ICDA. Section 192.927 requires that operators
follow ASME/ANSI B31.8S provisions related to ICDA. PHMSA has reviewed
NACE SP0206-2006 and finds that it is more comprehensive and rigorous
than either Sec. 192.927 or ASME B31.8S in many respects. In addition,
Section 192.929 specifies requirements for gas transmission pipeline
operators who use SCCDA for IM assessments. The requirements in Sec.
192.929 were promulgated before there were consensus industry standards
published that addressed SCCDA. Section 192.929 requires that operators
follow Appendix A3 of ASME/ANSI B31.8S. This appendix provides some
guidance for
[[Page 20774]]
conducting SCCDA, but is limited to SCC that occurs in high-pH
environments. Experience has shown that pipelines also can experience
SCC degradation in areas where the surrounding soil has a pH near
neutral (referred to as near-neutral SCC). NACE Standard Practice
SP0204-2008 addresses near-neutral SCC in addition to high-pH SCC. In
addition, the NACE recommended practice provides technical guidelines
and process requirements which are both more comprehensive and rigorous
for conducting SCCDA than either Sec. 192.929 or ASME/ANSI B31.8S.
Therefore, PHMSA is proposing to incorporate these industry standards
into the regulations to provide better guidance for conducting
integrity assessments with ICDA or SCCDA. PHMSA will continue to
evaluate the need for additional guidance for conducting integrity
assessments.
G.7. Does NACE SP0204-2008 (formerly RP0204), ``Stress Corrosion
Cracking Direct Assessment Methodology'' address the full life cycle
concerns associated with SCC?
1. INGAA suggested NACE SP0204, by itself, does not address the
full life cycle concerns of SCC but in combination with ASME/ANSI
B31.8S the full life cycle concerns are addressed. A number of pipeline
operators supported INGAA's comments.
2. AGA, supported by a number of its members, suggested PHMSA
should determine whether NACE SP0204 addresses full life cycle
concerns.
3. GPTC, Texas Pipeline Association, Texas Oil & Gas Association,
and Ameren Illinois commented it was not clear what PHMSA meant by
``full life cycle concerns.''
4. NACE International reported that SP0204 does not address the
full life cycle concerns of SCC; however, NACE noted that it has
developed a 2011 ``Guide to Improving Pipeline Safety by Corrosion
Management'' which will be converted into a NACE standard.
5. MidAmerican reported its conclusion that NACE SP0204 does
address full life cycle concerns.
6. Paiute and Southwest Gas reported their conclusion that the
existing standards are adequate, but deferred to NACE concerning the
breadth of coverage of NACE standards.
Response to Question G.7 Comments
PHMSA appreciates the information provided by the commenters. PHMSA
believes that NACE SP0204-2008 is the best available guidance and is
proposing to incorporate this industry standard into the regulations
for conducting integrity assessments with SCCDA. In addition, other
proposed requirements for integrity assessments and remediation in
Sec. Sec. 192.710, 192.713, 192.624, and subpart O provide greater
assurance that the full life cycle concerns associated with SCC are
addressed.
G.8. Are there statistics available on the extent to which the
application of NACE SP0204-2008, or other standards, have affected the
number of SCC indications operators have detected and remediated on
their pipelines?
1. Industry commenters responding to this question unanimously
noted that no statistics have been collected on the use of NACE SP0204.
INGAA noted, in addition, that the SCC Joint Industry Project (JIP)
represents the experience of operators of 160,000 miles of gas
transmission pipeline.
2. Paiute and Southwest Gas reported that they have not identified
any SCC on their pipeline systems.
3. An anonymous commenter noted that there has been one incident
attributed to factors not addressed in current standards. The commenter
noted that the only common factors among SCC colonies was high soil
resistivity and disbanded coating.
Response to Question G.8 Comments
PHMSA appreciates the information provided by the commenters. As
described in the response to Question G.6, PHMSA is proposing to
incorporate NACE SP0204-2008 into the regulations. PHMSA will continue
to gather information in this area and will evaluate the need for more
specific requirements or guidance to address the threat of SCC.
G.9. Should a one-time pressure test be required to address
manufacturing and construction defects?
1. INGAA and a number of its pipeline operators argued that this
should be a case-by-case decision guided by INGAA's Fitness for Service
protocol. INGAA noted that new pipelines require a part 192, subpart J,
pressure test while older pipelines may have been strength tested.
2. AGA, supported by a number of its pipeline operators, opined
that a one-time pressure test is sufficient. AGA noted that Congress
accepted the stability of pipelines that had undergone a post
construction pressure test.
3. GPTC argued that a one-time pressure test is sufficient;
however, such a test should not be mandated for pipelines not tested
after construction unless a significant risk has been demonstrated.
GPTC noted that manufacturing and construction defects are not time-
related.
4. American Public Gas Association objected to any requirement for
a one-time pressure test, noting that it is not practical to conduct
such a test on most transmission pipelines operated by municipal
pipeline operators.
5. Atmos noted that the decision to perform one-time pressure tests
to address manufacturing and construction defects requires more
information and consideration than can be conveyed in response to a
single question. Atmos reported that it could not determine if the one-
time pressure test requirement would apply to all pipeline segments or
to pipelines with certain characteristics. Some of Atmos' pipelines
could not be removed from service for testing without impacts on
customers.
6. Ameren Illinois argued that no one-time pressure test should be
required, noting that a pressure test is already required before a
pipeline is placed in service.
7. Northern Natural Gas argued that a one-time pressure test should
not be required in all cases. Northern noted that assessment of
manufacturing and construction defect threats should be determined
based on the risk level and pipeline type for pipeline segments do not
have an existing pressure test.
8. MidAmerican opined that a one-time pressure test should be a
requirement for manufacturing and construction defects, noting defects
that survive a pressure test are unlikely to fail during the useful
life of the pipeline.
9. Oleksa and Associates noted that: (1) A one-time pressure test
is all that is needed for manufacturing and construction defects; (2)
an in-service pipeline should only be pressure tested if there is clear
reason to believe a strength test would be beneficial; and (3) many
pipelines operate at such low levels of stress that a strength test is
not necessary.
10. Paiute and Southwest Gas commented that a pressure test should
be conducted in accordance with subpart J when initially placing a
pipeline in service. The operators reported that they support the
Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011
which will require systematic pressure testing (or other alternative
methods of equal or greater effectiveness) of certain, previously
untested transmission pipelines located in HCAs and operating at a
pressure greater than 30% SMYS. Texas Pipeline Association and Texas
Oil & Gas Association agreed, noting that testing of new pipelines is
already required and the Act requires use of pressure testing or
alternate means to verify MAOP.
[[Page 20775]]
11. Thomas Lael and California Public Utilities Commission argued
that all pipelines should be subjected to a pressure test. CPUC noted
that an unspecified technical paper published by Kiefner shows that a
pressure test to 1.25 times MAOP will be sufficient to demonstrate the
stability of manufacturing and construction defects and girth welds.
12. The NTSB recommended that PHMSA amend part 192 so that
manufacturing and construction defects can only be considered stable if
a gas pipeline has been subjected to a post-construction hydrostatic
pressure test of at least 1.25 times the MAOP.
13. Accufacts suggested that a requirement for a one-time pressure
test is needed, noting the NTSB safety recommendations issued following
San Bruno made it clear that there are problems with the current IM
regulations, especially as they relate to systems that were in
operation before the implementation of federal regulations.
14. A private citizen suggested that a one-time pressure test or
reduction of MAOP should be required for all low-frequency electric
resistance welded (LFERW) pipe.
15. A private citizen suggested that a one-time pressure test
conducted in combination with ILI should be required as a baseline for
subsequent ILI inspections.
16. An anonymous commenter opined that no one-time pressure test is
needed unless there is a history of seam failure or SCC.
Response to Question G.9 Comments
PHMSA appreciates the information provided by the commenters. The
majority of comments support performance of a one-time pressure test to
address manufacturing and construction defects. The ANPRM requested
comments regarding proposed changes to part 192 regulations that would
repeal 49 CFR 192.619(c) and the NTSB issued recommendations to repeal
49 CFR 192.619(c) for all gas transmission pipelines (P-11-14) and to
require a pressure test before concluding that manufacturing- and
construction-related defects can be considered stable (P-11-15). In
addition, Section 23 of the Act requires issuance of regulations
regarding the use of tests to confirm the material strength of
previously untested natural gas transmission lines.
An Integrity Verification Process (IVP) workshop was held in 2013.
At the workshop, PHMSA, the National Association of State Pipeline
Safety Representatives, and various other stakeholders presented
information and comments were sought on a proposed IVP that will help
address these issues. Key aspects of the proposed IVP process include
criteria for establishing which pipe segments would be subject to the
IVP, technical requirements for verifying material properties where
adequate records are not available, and technical requirements for re-
establishing MAOP where adequate records are not available or the
existing MAOP was established under Sec. 192.619(c). Comments were
received from the American Gas Association, the Interstate Natural Gas
Association of America, and other stakeholders and addressed the draft
IVP flow chart, technical concerns for implementing the proposed IVP,
and other issues. The detailed comments are available on Docket No.
PHMSA-2013-0119. PHMSA considered and incorporated the stakeholder
input, as appropriate into this NPRM, which proposes requirements to
address pipelines that established MAOP under 49 CFR 192.619(c),
manufacturing and construction defect stability, verification of MAOP
(where records that establish MAOP are not available or inadequate),
and verification and documentation of pipeline material for certain
onshore, steel, gas transmission pipelines.
G.10. Have operators conducted quality audits of direct assessments
to determine the effectiveness of direct assessment in identifying
pipeline defects?
1. INGAA, AGA, GPTC, and numerous pipeline operators noted that
direct assessment is a cyclical process that continually incorporates
analysis of information made available from the direct and indirect
assessment tools used. The direct assessment process requires that more
restrictive criteria be applied on first use and as operators become
more experienced with the methodology and gather more data on the
pipeline, more informed pipeline integrity decisions are made. The
commenters stated that operators using the direct assessment process
must continuously assess the effectiveness of the methodology.
2. Paiute and Southwest gas commented that operators confirm the
findings of the pre-assessment and indirect assessment steps as part of
the four-step direct assessment process. Validation digs are required
to confirm the effectiveness of the direct assessment process.
3. Texas Pipeline Association and Texas Oil & Gas Association noted
that direct examinations are made as part of every direct assessment.
In Texas, operators have generally been required by the Railroad
Commission to demonstrate comparisons of direct assessment results to
ILI results on a portion of their pipeline where both have been
performed. The associations contended that this process of validating
should be considered a quality audit.
4. Northern Natural Gas agreed that verification of the
effectiveness of direct assessment is already a part of the required
post-assessment step of the four-step direct assessment process. Ameren
Illinois agreed that this process is effectively a quality audit.
5. Atmos reported that records are kept of the indicated anomalies
and the actual anomalies discovered through direct examination, thus
assuring the quality and validation of direct assessments.
6. Accufacts opined that there appear to be serious deficiencies in
the application of direct assessment on gas pipelines.
7. An anonymous commenter noted that direct assessment, if used
correctly, is informative and proactive, and best suited to identify
preventive and mitigative actions and to establish assessment
intervals.
Response to Question G.10 Comments
PHMSA appreciates the information provided by the commenters. The
majority of comments state that quality audits are performed for direct
assessments, however, PHMSA believes, as one comment suggests, that
there are weaknesses in the use of direct assessments. For example,
SCCDA is not as effective, and does not provide an equivalent
understanding of pipe conditions with respect to SCC defects, as ILI or
hydrostatic pressure testing. Accordingly, PHMSA proposes to revise the
requirements in Sec. Sec. 192.921 and 192.937 for direct assessment to
allow use of this method only if a line is not capable of inspection by
internal inspection tools.
G.11. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements pursuant to the commenter's suggestions.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the
existing regulatory requirements.
[[Page 20776]]
No comments were received in response to this question.
H. Valve Spacing and the Need for Remotely or Automatically Controlled
Valves
The ANPRM requested comments regarding proposed changes to the
requirements for sectionalizing block valves. Gas transmission
pipelines are required to incorporate sectionalizing block valves.
These valves can be used to isolate a section of the pipeline for
maintenance or in response to an incident. Valves are required to be
installed at closer intervals in areas where the population density
near the pipeline is higher.
Sectionalizing block valves are not required to be remotely-
operable or to operate automatically in the event of an unexpected
reduction in pressure (e.g., from a pipeline rupture). Congress has
previously required PHMSA to ``assess the effectiveness of remotely
controlled valves to shut off the flow of natural gas in the event of a
rupture'' and to require use of such valves if they were shown
technically and economically feasible.\36\ The NTSB has also issued a
number of recommendations concerning requirements for use of automatic-
or remotely-operated mainline valves, including one following a 1994
pipeline rupture in Edison, NJ.\37\ The incident in San Bruno, CA on
September 9, 2010, has raised public concern about the ability of
pipeline operators to isolate sections of gas transmission pipelines in
the event of an accident promptly and whether remotely or automatically
operated valves should be required to assure this.
---------------------------------------------------------------------------
\36\ Accountable Pipeline Safety and Partnership Act of 1996,
Public Law 104-304.
\37\ National Transportation Safety Board, ``Texas Eastern
Transmission Corporation Natural Gas Pipeline Explosion and Fire,
Edison, New Jersey, March 23, 1994,'' PB95-916501, NTSB/PAR-95/01,
January 18, 1995.
---------------------------------------------------------------------------
The ANPRM then listed questions for consideration and comment. The
following are general comments received related to the topic as well as
comments related to the specific questions:
General Comments for Topic H
1. INGAA argued that while valves, spacing, and selection are
important, public safety requires a broader review of incident
responses and consequences. Performance-based Incident Mitigation
Management (IMM), using valves and other tools, will, according to
INGAA, improve incident response, reduce incident duration and minimize
adverse impacts. IMM plans identify comprehensive actions that improve
mitigation performance and minimize overall incident impact. These
plans cover various aspects of response, including how operators detect
failures, how they place and operate valves, how they evacuate natural
gas from pipeline segments, and how they prioritize coordination
efforts with emergency responders. A number of pipeline operators
supported INGAA's comments, including Panhandle, TransCanada, Spectra
Williams, Southern Star, and others.
2. AGA submitted a white paper that discussed potential benefits
associated with remote control valves and automatic shutoff valves;
however, the paper acknowledged that these valves will not prevent
incidents. A number of pipeline operators supported AGA's comments.
3. APGA reported automatic or remotely-controlled valves are not
practical for municipal pipeline operators because they do not have
remote monitoring or control of their pipelines. APGA also cautioned
that the use of automatic valves could lead to false closures, an
unintended and adverse consequence.
4. Atmos commented that the existing requirements for valve spacing
allow for safe and reliable service to its customers. The company noted
that requiring the installation of remote control valves or automatic
shutoff valves would add minimal value to the overall safety and
operation of its transmission pipeline systems. In addition, industry
studies have concluded that remote or automatic features on block
valves would not reduce injuries or fatalities associated with an
incident.
5. MidAmerican commented that installation of automatic shutoff
valves would be costly, have minimal impact on improving safety, and
could cause customer outages on its pipeline system. At the same time,
MidAmerican acknowledged that some applications of remote/automatic
control valves could have merit, but that the election should lie with
the operator given the complexity of pipeline systems and other factors
that bear on that decision. MidAmerican reported its conclusion that
ASME/ANSI B31.8S provides adequate guidance for the installation of
sectionalizing valves. While MidAmerican opposes a requirement to
install automatic or remotely-controlled valves, the company suggested
factors PHMSA should consider if it decides to adopt such a
requirement. Specifically, PHMSA should allow operators flexibility in
deciding between automatic and remote valves and should clarify when
action on a pipeline is considered a new installation versus a repair
or replacement in-kind.
6. TransCanada noted that industry studies have shown automatic or
remote block valves do not prevent incidents and have a minimal effect
on significant consequences, since most of the human impacts from a
rupture occur in the first few seconds, well before any valve
technology could reduce the flow of natural gas. TransCanada supports
the use of Incident Mitigation Management (IMM) to improve incident
response, reduce incident duration, and minimize adverse impacts.
7. Chevron argued operators should have the flexibility to select
the most effective measures based on specific locations, risks, and
conditions of the pipeline segment. Chevron noted that the Pipeline
Safety, Regulatory Certainty, and Job Creation Act of 2011 requires a
study of incident response in HCAs that must consider the swiftness of
leak detection and pipeline shut-down capabilities and the location of
the nearest personnel. The study must also evaluate the costs, risks,
and benefits of installing automatic or remote controlled shut-off
valves.
8. A private citizen suggested that periodic drills be held with
local emergency responders, pipeline operators should provide
specialized equipment to local responders in densely populated areas,
and pipeline operators pay a fee to those municipalities to support
incident response. The commenter further recommended that leak
detection analyses be computerized.
9. Dominion East Ohio contended that current regulations are
adequate and that automatic shutoff valves and remote control valves
are an important preventive and mitigative measure to consider using.
However, these valves do not prevent accidents and have very limited
impact in preventing injuries and deaths caused by an initial pipeline
failure.
10. Accufacts suggested that further prescriptive regulation is
required concerning the placement, selection, and choice of manual,
remotely-controlled, or automatic shutoff valves.
11. The Pipeline Safety Trust (PST) questioned the conclusions of
the DOT study, ``Remotely Controlled Valves on Interstate Natural Gas
Pipelines, (Feasibility Determination Mandated by the Accountable
Pipeline Safety and Partnership Act of 1996), September 1999, which
concluded that remote control valves were and remain economically
unfeasible. The PST noted that the study also stated that there could
be a potential benefit in terminating the gas flow to a rupture
[[Page 20777]]
expeditiously particularly in heavily populated and commercial areas.
PST suggested PHMSA commission an independent analysis to reach a
conclusion regarding whether to require these valves.
12. A private citizen suggested that local authorities regularly
review incidents in densely populated areas, as self-policing by
pipeline operators is insufficient. The commenter also recommended that
pipeline construction and modifications be subject to signoff by a
licensed professional engineer and be certified for compliance with
applicable regulations by a corporate officer subject to criminal
penalties, in order to reduce the incentive to cut corners.
13. Northern Natural Gas and a private citizen recommended that the
current one-call exemptions for government agencies be eliminated.
Comments Submitted for Questions in Topic H
H.1. Are the spacing requirements for sectionalizing block valves
in Sec. 192.179 adequate? If not, why not and what should be the
maximum or minimum separation distance? When class locations change as
a result of population increases, should additional block valves be
required to meet the new class location requirements? Should a more
stringent minimum spacing of either remotely or automatically
controlled valves be required between compressor stations? Under what
conditions should block valves be remotely or automatically controlled?
Should there be a limit on the maximum time required for an operator's
maintenance crews to reach a block valve site if it is not a remotely
or automatically controlled valve? What projected costs and benefits
would result from a requirement for increased placement of block
valves?
1. AGA and a number of pipeline operators contended that the
existing requirements in Sec. 192.179 are adequate. AGA noted that
studies have shown there is no safety benefit to having more remote or
automatic valves and operators should be permitted to determine the
need for additional valves and spacing. AGA contended that there is no
safety reason to change the existing regulation and argued that remote
or automatic valves should not be mandated for any specific set of
circumstances, since they are only one option for pipeline shutdown.
2. Texas Pipeline Association and Texas Oil & Gas Association
commented that spacing requirements for natural gas transmission lines
have been shown to be adequate for emergency situations. Both
associations observed that block valves are not in place to prevent
accidents and that the greatest impact of an accident is from the
initial gas release, before automatic or remote valves could actuate.
The associations also noted that the addition of more block valves
would increase the risk to aboveground infrastructure.
3. Accufacts contended that the existing spacing requirements are
inadequate and noted that valve spacing plays a significant role in the
``isolation blowdown'' time, or the time to depressurize a gas pipeline
segment once isolation valves are closed after a rupture. Accufacts
also recommended that additional sectionalizing valves be required when
class locations change.
4. Iowa Utilities Board (IUB) suggested that ease of access and the
time to respond should be factors relevant to a decision as to whether
to install automatic or remote valves. IUB noted that the
considerations are different for valves in remote areas compared to
urban valves.
5. California Public Utilities Board reported that the issue of
valve spacing is under review by the State.
6. A private citizen suggested that valves be required at one-mile
intervals in densely populated urban areas and that they close
automatically in the event of an incident, since the duration of the
fire resulting from an incident is directly proportional to the volume
of gas between valves. AGA commented that it is not the amount of gas
between valves but rather it is the volume between a valve and a
rupture that determines the volume released.
7. Wyoming County Pennsylvania's Commissioners suggested that it is
necessary to modify separation distances and to establish adequate
distances for gathering lines, including in Class 1 areas. The
Commissioners acknowledged that the spacing required for Class 3
locations may be more acceptable than the spacing required for Class 1
areas, but noted that it will take longer to reach a block valve with
10 mile spacing in Pennsylvania's Marcellus Shale regions.
8. An anonymous commenter responded that current valve spacing
requirements are adequate and suggested that automation be required if
it would take 20 to 30 minutes to respond to a mainline valve.
9. AGA, supported by a number of pipeline operators, noted that
operators evaluate the need for additional block valves when they
become aware of changes in class location.
10. Atmos commented that the need for additional block valves
should be evaluated when class locations change, if pipe replacement is
needed to comply with the new class locations. Atmos recommended valve
installations, if any, should only be required within the replaced
pipeline section. Atmos further recommended that automatic or remote
valves should not be required between compressor stations due to the
risk of false closures and the extensive modifications that would be
required.
11. MidAmerican opposed a requirement to install new block valves
when a class location changes or to establish more stringent spacing
requirements, noting that ASME/ANSI B31.8 provides adequate guidance
for block valve considerations. Texas Pipeline Association, Texas Oil &
Gas Association, and Northern Natural Gas agreed, noting that the
required class location study includes consideration of current spacing
as well as other criteria.
12. The Commissioners of Wyoming County Pennsylvania stated that it
is imperative that a suitable number of additional block valves be
required when population increases and class location changes, arguing
that this is necessary to assure adequate public safety measures are in
place.
13. An anonymous commenter suggested that new valves should not be
required when HCA or class location boundaries change, noting that such
changes occur rather frequently.
14. Northern Natural Gas argued that a prescriptive standard for
valve spacing may not necessarily provide additional risk reduction,
noting that many Class 2 and 3 locations are short pipe segments within
an extended Class 1 location.
15. Texas Pipeline Association and Texas Oil & Gas Association
noted that more block valves would not decrease the damage from a
pipeline accident, noting that PHMSA studies have shown that fatalities
and significant property damage occur within 3 minutes of a pipeline
rupture while a remotely-operated valve takes 10 minutes to close. This
and other studies have shown the only benefit to adding more valves is
reducing the amount of gas lost in an accident.
16. Accufacts contended that a more scientific discussion will
demonstrate a maximum spacing of eight miles will provide sufficient
risk reduction.
17. MidAmerican suggested that block valves should be automatic or
remotely-operated only when adequate response times cannot be achieved
by operator personnel. When response times are adequate, MidAmerican
contended that use of automatic or remote valves should be at the
operator's discretion.
18. Northern Natural Gas suggested that the decision to use remote
or automatic shut-off valves should be
[[Page 20778]]
based on the operator's risk assessment and should be made, by the
operator, on a case-by-case basis.
19. Paiute and Southwest Gas argued that operators should have the
flexibility to evaluate and determine whether remote or automatic
valves would be beneficial. The companies noted that Sec. 192.935
already requires the consideration of additional valves as a preventive
and mitigative measure.
20. Accufacts contended that decisions on valve spacing and whether
they should be manual, remote, or automatic will be dependent on the
time established for first responders to safely enter an actual gas
transmission impact zone following rupture. Accufacts noted that
California has set a goal of 30 minutes for first response time.
21. A private citizen suggested that automatic shutoff valves
should be used in densely populated areas because they provide the most
rapid response.
22. The Commissioners of Wyoming County Pennsylvania suggested that
standardization is necessary with remotely and automatically controlled
shutoffs. The Commissioners contended that the operator needs to employ
remote or automatic valves when transmission and gathering lines are
routed through areas that are not easily accessible.
23. INGAA noted that Sec. 192.620 requires a one-hour time frame
for closing a valve, and contended this is practical for valves that
would isolate pipelines in HCAs and consistent with requirements for
alternative MAOP in Sec. 192.620. A number of pipeline operators
supported INGAA's comments.
24. Atmos suggested that mandating a minimum time to reach a valve
site is impractical, because many variables exist in a dynamic state
that affect an operator's ability to reach a block valve site.
25. MidAmerican opposed a specified time frame for response to a
valve site, noting that operators should respond in an expedient manner
without specified time limits.
26. Northern Natural Gas suggested PHMSA consider a two-hour
response time for valves in HCA.
27. Texas Pipeline Association and Texas Oil & Gas Association
noted that conditions determine how quickly an operator can reach a
valve site in the event of an incident and operators make every effort
to respond expeditiously when an incident occurs. The associations
opposed adoption of a required response time.
28. TransCanada reported its conclusion that having personnel on
site within one hour is reasonable for planning purposes. If this
cannot be met, TransCanada suggested that possible valve automation
should be required.
29. The Commissioners of Wyoming County Pennsylvania reported their
conclusion that there would be value in establishing a maximum response
time, especially in Class 1 locations where block valves may be 10
miles apart.
30. INGAA and a number of its pipeline operator members noted that
studies have shown consistently that there is no value in installing
additional block valves or in automating valves. They suggested that it
would be more beneficial to apply resources that would be required to
comply with any new requirements in this area towards preventing
accidents.
31. MidAmerican reported that installing additional block valves
would entail significant costs and suggested that increasing the number
of valves could cost in excess of $40 million for its pipeline system.
Northern Natural Gas agreed that costs could be substantial, without
providing a specific estimate for its pipeline system.
32. Paiute and Southwest Gas estimated that costs to install new
valves could range from $100,000 to $1 million per installation.
33. An anonymous commenter estimated that retrofitting a 36-inch
valve for remote operation would cost approximately $30,000 plus
subsequent maintenance costs.
34. Accufacts noted that the San Bruno accident demonstrated that
there is a cost associated with not properly spacing, installing or
automating valves in high consequence areas.
H.2. Should factors other than class location be considered in
specifying required valve spacing?
1. INGAA, AGA, GPTC and several pipeline operators took the
position that no new requirements are needed. These associations argued
that Sec. 192.179 provides appropriate minimum standards and reported
that operators install additional valves in accordance with their
integrity management plans or other factors that they consider
voluntarily.
2. Paiute and Southwest Gas opined that no additional criteria are
needed. They noted that numerous industry studies have shown that there
is little or no safety benefit to installing additional automatic or
remote valves. They suggested that operators should have the
flexibility to determine, based on local circumstances, where
additional valves are needed.
3. Atmos suggested that valve accessibility be given more
consideration, noting that installing valves in locations that provide
improved accessibility could lead to spacing greater than allowed under
current regulations. Atmos further suggested that environmental factors
such as water crossings and areas prone to flooding should be taken
into consideration.
4. MidAmerican opined that additional factors should be considered
and pointed to ASME/ANSI B31.8 for examples.
5. Accufacts concluded that additional factors need to be taken
into consideration, noting that protection of identified sites in Class
1 and 2 locations will require shorter valve spacing than is currently
required by regulations.
6. The California Public Utilities Commission noted that there are
numerous factors to be considered that affect response time, and that
this issue is under review by the State.
7. The Texas Pipeline Association, Texas Oil & Gas Association, and
Commissioners of Wyoming County Pennsylvania suggested that factors
other than class location should not be added to the regulations. They
noted that class location serves as a surrogate for the level of risk
posed by a pipeline.
H.3. Should the regulations be revised to require explicitly that
new valves must be installed in the event of a class location change to
meet the spacing requirements of Sec. 192.179? What would be the costs
and benefits associated with such a change?
1. INGAA and a number of its pipeline operator members opposed
applying Sec. 192.179 requirements retroactively to class location
changes. INGAA suggested that, rather than absorbing the cost of
installing new valves, other preventive and mitigative measures applied
through an integrity management plan would produce greater benefits.
2. AGA and a number of its members opposed requiring new valves be
installed when class location changes, arguing that no safety benefit
will result.
3. Northern Natural Gas expressed its opinion that current
regulations are adequate, noting that class location change studies
require consideration of block valve spacing.
4. MidAmerican opined that the existing regulations are adequate
and noted that ASME/ANSI B31.8 provides other factors for
consideration.
5. GPTC expressed its belief that existing requirements are
adequate, noting that operators voluntarily consider other factors in
establishing valve locations.
6. Atmos suggested that PHMSA not require the installation of new
valves
[[Page 20779]]
due to changes in class location, but stated the agency should consider
the need for additional block valves if pipe replacement is needed as a
result of the change.
7. Accufacts suggested that new valves should be required following
class location changes, but suggested that a reasonable time should be
provided for such valves to be installed and operational.
8. The Texas Pipeline Association and Texas Oil & Gas Association
commented that no safety benefit has been demonstrated for the
installation of additional valves. The associations suggested that
installing additional valves could be counterproductive, since more
above-ground valves could pose an additional risk to the public.
9. The California Public Utilities Commission opined that the
regulations should require explicitly that additional valves be
installed when class location changes, but expressly withheld an
opinion on related costs.
10. A private citizen suggested that all requirements related to
class location should apply when class location changes, unless PHMSA
adopts an expanded definition for HCA to replace class location
considerations.
11. An anonymous commenter stated that most operators anticipate
changes to Class 3 or 4 when pipelines are designed and constructed.
The commenter estimated that installing a new 36-inch valve would cost
$70 to $100 thousand, not including down time and lost product.
12. The Commissioners of Wyoming County Pennsylvania commented that
the regulations need to be revised to explicitly require that new
valves be installed when class locations change. The Commissioners
suggested that this needs to extend to both transmission and gathering
lines in Class 1 areas.
H.4. Should the regulations require addition of valves to existing
pipelines under conditions other than a change in class location?
1. INGAA and a number of pipeline operators noted that studies have
indicated valve spacing has limited impact on the duration of an
incident. INGAA suggested that a performance-based approach to incident
mitigation management would better inform valve placement.
2. AGA opposed requiring additional valves under any scenario. A
number of pipeline operators supported AGA's comments.
3. Accufacts suggested that new 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.
4. Ameren Illinois opposed requiring new valves under other
conditions, opining that existing requirements are adequate.
5. GPTC and Atmos commented that existing regulations are a
sufficient baseline for determining valve location, noting that
operators often use more stringent spacing criteria during initial
construction.
6. MidAmerican opposed requiring that installation of new valves on
existing pipelines for any reason other than a class location change,
noting that ASME/ANSI B31.8 provides additional factors for operators
to consider in determining valve location.
7. Northern Natural Gas noted that existing regulations require
that operators consider additional valves as a preventive and
mitigative measure and expressed its conclusion that this requirement
is sufficient.
8. Paiute and Southwest Gas suggested that operators should have
the flexibility to evaluate and determine where remotely-controlled or
automatic valves would be beneficial. The companies noted that Sec.
192.935 requires the consideration of additional valves as a preventive
and mitigative measure and industry studies indicate little or no
safety benefit to installing additional valves.
9. The California Public Utilities Commission suggested that
conditions that would impede access to a valve may need to be
considered in determining valve placement.
H.5. What percentage of current sectionalizing block valves are
remotely operable? What percentage operate automatically in the event
of a significant pressure reduction?
1. INGAA estimated that 40 to 50 percent of mainline block valves
are remotely-operated or automatic. INGAA did not provide an estimate
specifically for automatic valves. INGAA noted that application of
Incident Mitigation Management would lead operators to conclusions as
to whether a valve should be remote or automatic. A number of pipeline
operators supported INGAA's comments.
2. AGA and GPTC reported that they have no data with which to
respond to this question.
3. Ameren Illinois reported that it has no remotely-controlled
valves.
4. Atmos reported that remote and automatic valves are not
installed routinely. Remotely-controlled valves are installed on a
small number of select pipelines, representing approximately 0.1
percent of all valves.
5. Kern River reported that 66 percent of its mainline block
valves, and all block valves in HCA, are remotely-controlled.
6. MidAmerican reported that less than one percent of its valves
are remotely-controlled and a similarly small percentage of them are
automatic.
7. Northern Natural Gas reported that remotely-controlled valves
are located only at compressor stations on its pipeline system.
8. Paiute reported that less than 10 percent of the valves on its
system are remotely-controlled. Paiute has no automatic valves.
9. Southwest Gas reported that it has no remotely-controlled or
automatic valves, due to the urban nature of its pipeline system.
10. Texas Pipeline Association reported that a limited survey of
its members indicated the number of remotely-controlled valves varies
from 1 to 18 percent; the number of automatic valves varies from zero
to 18 percent.
H.6. Should PHMSA consider a requirement for all sectionalizing
block valves to be capable of being controlled remotely?
1. INGAA and a number of pipeline operators opposed consideration
of such a requirement. They commented that no one solution should be
mandated and Incident Mitigation Management should guide operators to
decisions as to which valves should be remote or automatic.
2. AGA and a number of pipeline operators also opposed
consideration of such a requirement, noting remotely-controlled valves
are only one option for shutting down a pipeline.
3. Accufacts opposed such a generic requirement, noting small-
diameter gas transmission pipelines may not merit automation because of
the science of pipeline diameter rupture associated with high heat flux
releases.
4. GPTC opined that remotely-controlled valves do not improve
safety, thus there is no basis for requiring their use. GPTC noted that
operators voluntarily consider many factors in establishing valve
locations.
5. Atmos opposed consideration of this requirement, noting there
are issues with false closures and the costs of conversion or
installation are extensive. Atmos also noted that industry studies have
shown no increase in safety from having more remotely-controlled or
automatic valves.
6. Kern River opined that this should be an operator decision,
noting that integrity management regulations require the consideration
of remote or automatic valves as part of identifying preventive and
mitigative measures.
[[Page 20780]]
7. MidAmerican strongly opposed requiring all sectionalizing block
valves to be remotely controlled. MidAmerican stated that the location
and type of valve should be based on an engineering assessment. A
requirement that all valves be remote would increase costs and may
provide disincentives to installation of additional valves.
8. Northern Natural Gas opposed such a requirement, commenting this
should be a case-by-case decision based on risk reduction.
9. Paiute and Southwest Gas reported their conclusion that the
existing requirements in Sec. 192.179 are adequate. The companies
recommended that operators have the flexibility to evaluate and
determine where remote or automatic valves would be beneficial. They
noted that Sec. 192.935 requires the consideration of additional
valves as a preventive and mitigative measure and industry studies
indicate little or no safety benefit to installing additional remote or
automatic valves.
10. The Texas Pipeline Association and Texas Oil & Gas Association
opposed consideration of a requirement that all block valves be
remotely-operable. The associations noted that it would be tremendously
expensive to do so, and it would require power and communication
sources that may not be readily available at valve sites.
11. The California Public Utilities Commission commented that this
could be impractical for distribution systems considering space
limitations and the practicability of supplying communication
facilities for valves. This issue is under review by the State for
transmission facilities.
12. The Iowa Utilities Board noted that remotely-operated valves
require a SCADA or other type of remote monitoring and operating
system. A requirement that all sectionalizing valves be remotely-
operable would thus be a de facto requirement that all operators,
regardless of size or the potential consequences of an accident,
install a SCADA system. Small operators and municipal utilities in Iowa
do not have such systems.
13. The Commissioners of Wyoming County Pennsylvania commented that
it might be desirable for all valves to be remotely-operable or
automatic, but PHMSA must consider what is reasonable and adequate.
14. An anonymous commenter opposed consideration of a requirement
that all valves be remotely-operable, noting that most gas pipeline
accident consequences occur immediately upon release, before a remote
valve could have any effect.
H.7. Should PHMSA strengthen existing requirements by adding
prescriptive decision criteria for operator evaluation of additional
valves, remote closure, and/or valve automation? Should PHMSA set
specific guidelines for valve locations in or around HCAs? If so, what
should they be?
1. INGAA and a number of pipeline operators opposed PHMSA's
establishment of prescriptive criteria, suggesting instead that PHMSA
develop guidance for Incident Mitigation Management.
2. AGA, GPTC, and a number of pipeline operators commented that
requirements in Sec. 192.179 are adequate. AGA noted that operators
already consider additional valves in their emergency response
portfolio and install them where economically, technically, and
operationally feasible. Some operators noted that numerous industry
studies indicate that there is little or no safety benefit to
installing additional remote or automatic valves and Sec. 192.935
already requires the consideration of additional valves as a preventive
and mitigative measure.
3. Accufacts supported the consideration of prescriptive criteria,
arguing that prescriptive regulation should be mandated for certain gas
transmission pipelines in HCAs, especially larger-diameter pipelines in
certain areas where manual closure times can be long.
4. Ameren Illinois opposed additional prescriptive criteria,
arguing that existing requirements are sufficient and that additional
valves should be considered when economically, technically, and
operationally feasible to address specific safety concerns.
5. California Public Utilities Commission expressed its conclusion
that prescriptive decision criteria may need to be added for all Method
1 HCA locations.
6. The Iowa Utilities Board, the Texas Pipeline Association and the
Texas Oil & Gas Association questioned whether it is possible to write
prescriptive decision criteria that can reasonably address all possible
situations and circumstances or always provide the best option. These
commenters suggested that operator judgment and discretion should play
a part in these decisions.
7. MidAmerican expressed its belief that pipeline safety would not
be enhanced by additional prescriptive criteria and opposed specific
requirements for valve location near HCAs, noting that ASME/ANSI B31.8
provides considerations for operators to take into account when
deciding on valve locations.
8. An anonymous commenter suggested that prescriptive criteria
could be useful in assuring a degree of consistency among pipeline
operators.
H.8. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements pursuant to the commenter's suggestions.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the
existing regulatory requirements.
No comments were received in response to this question.
Response to Topic H Comments
PHMSA appreciates the information provided by the commenters. Based
on the investigation of the San Bruno incident, the NTSB recommended
(P-11-11) that PHMSA promulgate regulations to explicitly require that
automatic shutoff valves or remote control valves in high consequence
areas and in Class 3 and 4 locations be installed and spaced at
intervals considering the population factors listed in the regulations.
In addition, Section 4 of the Act requires issuance of regulations on
the use of automatic or remote-controlled shut-off valves, or
equivalent technology, if appropriate, and where economically,
technically, and operationally feasible. The Act also requires the
Comptroller General of the United States to complete a study on the
ability of transmission pipeline facility operators to respond to a
hazardous liquid or gas release from a pipeline segment located in a
high-consequence area. On March 27, 2012, PHMSA sponsored a public
workshop to seek stakeholder input on this issue. On October 5, 2012,
PHMSA also briefed stakeholders, via a webcast, on the status of an
ongoing study conducted by Oak Ridge National Laboratory on
understanding the application of automatic control and remote control
shutoff valves. The final study was published in December 2012. PHMSA
also included this topic in the July 18, 2012 Pipeline Research Forum.
PHMSA will take further action on this topic after completion of the
assessment of the findings from these activities. PHMSA will consider
the comments
[[Page 20781]]
received on the ANPRM and will consider this topic in future
rulemaking, as required.
I. Corrosion Control
Gas transmission pipelines are generally constructed of steel pipe,
and corrosion is a potential threat. Subpart I of part 192 addresses
the requirements for corrosion control of gas transmission pipelines,
including the requirements related to external corrosion, internal
corrosion, and atmospheric corrosion. However, this subpart does not
include requirements for the specific threat of Stress Corrosion
Cracking (SCC). The ANPRM requested comments regarding revisions to
subpart I to improve the specificity of existing requirements and to
add requirements relative to SCC.
Existing requirements have proven effective in reducing the
occurrence of incidents caused by external corrosion. Many of the
provisions in subpart I, however, are general in nature. In addition,
the current regulations do not include provisions that address issues
that experience has shown are important to protecting pipelines from
corrosion damage, including:
Post-construction surveys for coating damage.
Post-construction close interval survey (CIS) to assess
the adequacy of cathodic protection (CP) and inform the location of CP
test stations.
Periodic interference current surveys to detect and
address electrical currents that could reduce the effectiveness of CP.
Periodic use of cleaning pigs or sampling of accumulated
liquids to assure that internal corrosion is not occurring.
Corrosion control regulations applicable to gas transmission
pipelines currently do not include requirements relative to SCC. SCC is
cracking induced from the combined influence of tensile stress and a
corrosive medium. SCC has caused numerous pipeline failures on
hazardous liquids pipelines, including a 2003 failure on a Kinder
Morgan pipeline in Arizona, a 2004 failure on an Explorer Pipeline
Company pipeline in Oklahoma, a 2005 failure on an Enterprise Products
Operating line in Missouri, and a 2008 failure on an Oneok NGL Pipeline
in Iowa. More effective methods of preventing, detecting, assessing and
remediating SCC in pipelines are important to making further reductions
in pipeline failures.
The ANPRM then listed questions for consideration and comment. The
following are general comments received related to the topic as well as
comments related to the specific questions:
General Comments for Topic I
1. AGA opined that the questions posed under this topic are unclear
and disjointed and do not differentiate between distribution and
transmission pipelines. In addition, AGA stated that PHMSA did not
provide a rationale for why there is any concern over subpart I. A
number of pipeline operators supported AGA's comments.
2. MidAmerican noted that PHMSA says current requirements are
adequate yet goes on to propose new requirements.
3. INGAA reported that its members commit to mitigating corrosion
anomalies in accordance with ASME/ANSI B31.8S, both inside and outside
HCAs. INGAA argued that enhanced external corrosion management methods,
such as close interval surveys and post-construction coating surveys,
should not be required singularly and arbitrarily by new prescriptive
regulations, since these methods can be redundant or inferior when
combined with other assessment techniques. INGAA argued that these
methods should continue to be used by operators on a threat-specific
basis, as is currently practiced under performance-based regulations
and consensus-based IM programs. A number of pipeline operators
supported INGAA's comments.
4. Chevron argued that more prescriptive requirements are
unnecessary, noting that current regulations allow operators the
flexibility to select the most effective corrosion control method for
the specific corrosion threats to a pipeline segment.
5. MidAmerican reported that it has never identified internal
corrosion on its pipeline system and prescriptive requirements related
to that threat would divert resources. MidAmerican opined that subpart
I provides an adequate level of safety and any changes in that subpart
should be approached carefully because they could be beneficial or
detrimental for reducing risk. MidAmerican further noted that NACE
SP0204 and ASME/ANSI B31.8S provide adequate guidance in this area.
6. TransCanada suggested that PHMSA incorporate the new SCC
management provision in ASME/ANSI B31.8S as the basis for identifying
and mitigating SCC and be responsive to further enhancements.
TransCanada also suggested that the best way to manage corrosion
anomalies is through assessments.
7. Dominion East Ohio opined that existing regulations in this area
are adequate.
8. NAPSR urged PHMSA to establish or adopt standards or procedures,
through a rulemaking proceeding, for improving the methods of
preventing, detecting, assessing, and remediating stress corrosion
cracking. NAPSR also suggested that PHMSA consider additional
requirements to perform periodic coating surveys at compressor
discharges and other high-temperature areas potentially susceptible to
SCC and develop a training module for pipeline operators and federal
and state inspectors that would include the identification of potential
areas of SCC, detecting, assessing and remediating SCC.
9. A private citizen reported that his analysis of data from over
5000 lightning strikes indicates that cathodic protection systems make
pipelines a frequent target for lightning.
10. A private citizen suggested that enforcement of cathodic
protection requirements be strengthened, stating that the number of
enforcement actions indicates that operators are not operating or
maintaining CP as required.
11. A private citizen suggested that in-line inspection (ILI)
capable of detecting seam issues should be required for pipe
susceptible to selective seam weld corrosion, since pressure testing is
not adequate to detect non-leak anomalies. If not possible, the
commenter would require that this pipe be replaced.
Response
PHMSA appreciates the information provided by the commenters. In
light of the contributing factors to the San Bruno incident, including
PG&E's reliance on direct assessment under circumstances for which
direct assessment was not effective, and the incident in Marshall,
Michigan, where fracture features were consistent with stress corrosion
cracking, PHMSA believes that more specific measures are needed to
address both stress corrosion cracking and selective seam weld
corrosion. Based on lessons learned from incident investigations, such
as the 2012 incident in Sissonville, West Virginia and the 2007
incident in Delhi, Louisiana, and improved capabilities of corrosion
evaluation tools and methods, PHMSA believes that more specific minimum
requirements are needed for control of both internal and external
corrosion. In addition, cathodic protection is a well-established
corrosion control tool, and PHMSA believes the benefits of cathodic
protection outweigh any potential risks. Therefore, PHMSA proposes
several
[[Page 20782]]
enhancements to subpart I for corrosion control and subparts M and O
for assessment, including specific requirements to address stress
corrosion cracking and selective seam weld corrosion, and enhanced
corrosion control measures for HCAs, which are discussed in more detail
in response to specific questions, below.
Comments Submitted for Questions in Topic I
I.1. Should PHMSA revise subpart I to provide additional
specificity to requirements that are now presented in general terms? If
so, which sections should be revised? What standards exist from which
to draw more specific requirements?
1. INGAA and a number of pipeline operators commented that adding
prescriptive requirements would be disruptive to operators, noting
PHMSA has acknowledged the effectiveness of performance-based elements
of the current requirements.
2. The AGA, the GPTC, the Texas Pipeline Association, the Texas Oil
& Gas Association, and numerous pipeline operators questioned the need
to amend subpart I. AGA noted that this is one of the more prescriptive
sections of the code and has a 40-year history of demonstrated
effectiveness.
3. Ameren Illinois opined it is not necessary to revise subpart I,
because integrity management regulations require operators to identify
threats and to manage them.
4. MidAmerican opposed more specific requirements for corrosion
control, noting that there is wide diversity among pipelines and it is
unlikely that a single set of specific requirements would apply
effectively to all pipelines. MidAmerican suggested that additional
specific requirements must be tailored to a wide range of pipeline
configurations to be of any value.
5. Northern Natural Gas reported that IM results demonstrate that
corrosion has been adequately addressed on its pipeline system.
6. Paiute and Southwest Gas noted that subpart I is one of the most
prescriptive sections of the code, subpart O provides an additional
layer of regulation, and NACE standards are robust and incorporated by
reference.
7. Panhandle Energy commented that existing performance based
regulations require the pipeline operator to establish procedures to
determine the adequacy of CP monitoring locations and appropriate
remediation schedules based on circumstances that are unique to each
pipeline. Panhandle observed that PHMSA appears to be attempting to
establish ``One Size Fits All'' prescriptive requirements and opined
that such changes would have no positive effect on safety and may be
detrimental.
8. Accufacts observed that too many pipeline operators are assuming
that IM assessments can replace subpart I requirements when the intent
was that the regulations work in conjunction with one another.
Accufacts suggested that prescriptive regulation is needed to avoid
serious misapplication of the IM section and to assure that subpart I
regulations are implemented to keep corrosion under control.
9. Panhandle observed that the ANPRM states that ``prompt'' as used
in Sec. 192.465(d) is not defined, and does not recognize the
definition of ``prompt remedial action'' outlined in the 1989 Office of
Pipeline Safety's Operation and Enforcement Manual. Panhandle noted
that the enforcement guidance requires PHMSA to evaluate the
circumstances and provide rationale for any determination of
``unreasonable delay'' in any enforcement action associated with Sec.
192.465(d). Panhandle observed that such evaluations are inherent in
the enforcement of performance-based regulations and stand in sharp
contrast to the ``check-box'' enforcement mentality of prescriptive
regulations. Panhandle complained that the language of the ANPRM
contradicts more than 20 years of enforcement history. Panhandle
interpreted the ANPRM to mean that PHMSA has no authority to interpret
part 192 other than through rulemaking.
10. An anonymous commenter suggested that PHMSA delete the
requirement regarding 300 mV pipe-to-soil reading shift and adopt NACE
SP0169.
11. The California Public Utilities Commission suggested that PHMSA
consider modifying acceptance criteria to be based on instant-off
readings, arguing that this would provide improved specificity
concerning IR drop.
Response to Question I.1 Comments
PHMSA appreciates the information provided by the commenters. The
majority of industry comments do not support revising subpart I to
provide additional specificity to requirements. However, for the
reasons discussed in this NPRM, PHMSA believes that certain regulations
can be improved to better address issues that experience has shown can
be important to protecting pipelines from corrosion damage, and that
prudent operators currently implement. Therefore, PHMSA proposes to
amend subparts G and I to: (1) Enhance requirements for electrical
surveys (i.e., close interval surveys); (2) require post construction
surveys for coating damage; (3) require interference current surveys;
(4) add more explicit requirements for internal corrosion control; and
(5) revise Appendix D to better align with the criteria for cathodic
protection in NACE SP0169. Included in these changes is a new
definition of the terms ``electrical survey'' and ``close interval
survey.'' To conform to the revised definition of ``electrical
survey,'' the use of that term in subpart O would be replaced with
``indirect assessment'' to accommodate other techniques in addition to
close-interval surveys.
I.2. Should PHMSA prescribe additional requirements for post-
construction surveys for coating damage or to determine the adequacy of
CP? If so, what factors should be addressed e.g., pipeline operating
temperatures, coating types, etc.)?
1. INGAA and a number of pipeline operators argued that post-
construction surveys are of limited use, arguing that they can identify
damaged coating but not necessarily areas where SCC can occur.
2. AGA, supported by a number of its pipeline operator members,
opined that existing requirements for post-construction surveys for
coating damage and cathodic protection are sufficient and operators
need flexibility to apply their resources to the highest risk areas.
3. GPTC agreed that existing regulations are sufficient, noting
that operators are not experiencing difficulties related to post-
construction surveys for coating damage or for determining the adequacy
of CP.
4. Ameren Illinois noted that part 192 requirements are followed
for the installation of new coated steel pipe and it will develop a
process to deal with any problems that may be identified through
integrity management. Atmos agreed, noting that post-construction
baseline surveys are typically performed.
5. Kern River opined that corrosion control measures and mitigation
are site specific and therefore universal conditions and mitigation
requirements would likely be ineffective and inefficient. Performance-
based criteria are the best way to ensure the integrity of the pipeline
with the most innovative and effective solutions.
6. MidAmerican opposed new requirements, noting that areas of
coating damage on pipelines are protected from corrosion by cathodic
protection and existing requirements are adequate in this area.
7. NACE concluded that current regulations have proven adequate and
[[Page 20783]]
noted that PHMSA acknowledges in the ANPRM that ``[T]hese requirements
have proven effective in minimizing the occurrence of incidents caused
by gas transmission pipeline corrosion.''
8. Paiute and Southwest Gas opined that current requirements for
coatings (Sec. 192.461) and cathodic protection (Sec. 192.463) are
sufficient.
9. Northern Natural Gas stated that no new requirements are needed,
observing that it takes action when CP surveys indicate a concern.
10. Panhandle argued that the proposed requirement for post
construction coating does not address the cause of coating damage
during construction and INGAA best practices have proven to be an
effective means to provide pipeline safety, affording flexibility and
recognizing the inherent limitations of coating surveys. Panhandle
observed that PHMSA's requirements for the investigation of anomalies
found during post construction coating surveys on alternate MAOP lines
are overly conservative, waste resources, do not enhance pipeline
safety, and should not be considered for use in any proposed
rulemaking. Panhandle further recommended that any proposed regulations
related to pipeline temperature should not use the 120 degrees
Fahrenheit value used in Sec. 192.620, since studies have demonstrated
pipeline coatings can withstand temperatures up to 150 degrees.
Panhandle further argued that industry experience verifies that the
vast majority of coating holidays associated with pipeline construction
are not an integrity threat when cathodic protection is applied to the
pipeline. It also suggested that verification of pipeline integrity
through ILI or pressure testing better utilizes resources than
excavation and repair of pinholes in pipeline coating systems.
11. Panhandle observed that, from its experience with over 900
completed excavations, the coating anomaly ranking system of NACE
SP0502 is extremely conservative and should only be used as part of the
ECDA process.
12. Texas Pipeline Association and Texas Oil & Gas Association
suggested that PHMSA should consider requiring close interval surveys
at 5-year intervals.
13. TransCanada noted that enhanced external corrosion management
methods, such as close interval surveys and post construction coating
surveys, have proven effective in helping identify and mitigate certain
corrosion damage conditions. TransCanada argued, however, that these
methods should not be required singularly and arbitrarily by new
prescriptive requirements, as they can be redundant or inferior when
combined with other assessment techniques.
14. Pipeline Safety Trust suggested that additional post-
construction surveying should be required to identify damage to or
weakness in coating and to ensure the integrity of CP.
15. An anonymous commenter suggested that PHMSA require close
interval survey before energizing new CP components, after backfill has
settled, noting that this would ensure test stations are located in
areas that will assure adequate protection.
16. The Commissioners of Wyoming County Pennsylvania recommended
that PHMSA review operator practices and codify the ``best practices''
in this area.
Response to Question I.2 Comments
PHMSA appreciates the information provided by the commenters. The
majority of industry comments do not support revising subpart I to
prescribe additional requirements for post-construction surveys for
coating damage or to determine the adequacy of CP. However, as detailed
in the ANPRM, experience has shown that construction activities can
damage coating and that identifying and remediating this damage can
help protect pipeline integrity. PHMSA does agree that prescriptive
practices for conducting coating surveys, as well as the criteria for
remediation and other responses to indications of coating damage, are
not always appropriate because coating damage is case-specific.
Therefore, PHMSA proposes to add a requirement that each coating be
assessed to ensure integrity of the coating using direct current
voltage gradient (DCVG) or alternating current voltage gradient (ACVG)
and damage be remediated if damage is discovered. In addition, for HCA
segments, PHMSA proposes enhanced preventive and mitigative measures
and repair criteria for repair of coating with a voltage drop
classified as moderate or severe.
I.3. Should PHMSA require periodic interference current surveys? If
so, to which pipelines should this requirement apply and what
acceptance criteria should be used?
1. INGAA and a number of pipeline operators recommended that PHMSA
not establish new requirements in this area without discussing the
topic with operators first. INGAA pointed out that guidance already
exists in the form of Advisory Bulletin ADB-03-06 and NACE SP0169.
2. Kern River opposed new requirements for periodic surveys,
arguing that Sec. Sec. 192.465, 192.467, and 192.473 adequately
address the concerns.
3. Ameren Illinois also opposed new requirements. Ameren reported
that it conducts testing annually at sites where stray currents are
expected and noted that integrity management regulations already
require operators to identify and address threats.
4. NACE International suggested that current regulations are
adequate and have served the public interest. NACE noted operators are
currently taking action to identify interference currents and protect
their pipelines, and it has provided guidance through standards and
technical papers.
5. Atmos noted that interference surveys would be a part of an
investigation into cathodic protection systems that do not provide
minimum levels of protection. Operators are already required to
maintain minimum levels of protection.
6. Northern Natural Gas reported that it conducts additional
surveys when issues are discovered during periodic maintenance, when
new foreign line crossing are installed, or for new construction, but
opposed new requirements in this area.
7. Paiute and Southwest Gas opposed new requirements, noting that
operators should have the flexibility to allocate their resources in a
manner that best suits their system.
8. Panhandle opposed new requirements, noting that existing
performance-based regulations have proven adequate to address the
threat of stray currents. Panhandle commented that the gas pipeline
industry recognized and reacted to the threat of AC interference
decades prior to the ANPRM, and suggested that the lack of
justification from PHMSA on this issue is a strong indicator that
industry has reacted appropriately to integrity threats in accordance
with the requirements of Sec. 192.473. Panhandle noted that
interference currents have been addressed in several industry standards
and publications. In particular, Section 9, Control of Interference
Currents, of NACE SP0169, Control of External Corrosion on Underground
of Submerged Metallic Piping Systems, provides guidance for the
detection and mitigation of interference currents.
9. Texas Pipeline Association and Texas Oil & Gas Association
stated that current regulations are sufficient; however, if new
regulations are promulgated, the associations recommended that PHMSA
use the liquid pipeline requirement for periodic interference surveys
and be applicable only to foreign line crossings and
[[Page 20784]]
pipelines near large DC-powered equipment.
10. An anonymous commenter stated that new regulations are not
needed, as most operators will conduct surveys on their own, generally
when pipe-to-soil readings drop.
Response to Question I.3 Comments
PHMSA appreciates the information provided by the commenters.
Industry comments do not support revising subpart I to require periodic
interference current surveys. However, as detailed in the ANPRM,
pipelines are often routed near, in parallel with, or in common rights-
of-way with, electrical transmission lines or other pipelines that can
induce interference currents, which, in turn, can induce corrosion.
Recent incidents on pipelines operated by Kern River and Center Point
are examples of incidents this requirement seeks to prevent. Section
192.473 currently requires that operators of pipelines subject to stray
currents have a program to minimize detrimental effects but does not
require surveys, mitigation, or provide any criteria for determining
the adequacy of such programs. Therefore, PHMSA proposes to add a
requirement that the continuing program to minimize the detrimental
effects of stray currents must include: (1) Interference surveys to
detect the presence and level of any electrical current that could
impact external corrosion where interference is suspected; (2) analysis
of the results of the survey; and (3) prompt remediation of problems
after completing the survey to protect the pipeline segment from
deleterious current. For HCA segments, PHMSA proposes to address this
in enhanced preventive and mitigative measures, and to include
performance criteria.
I.4. Should PHMSA require additional measures to prevent internal
corrosion in gas transmission pipelines? If so, what measures should be
required?
1. INGAA, AGA, GPTC, and numerous pipeline operators contended that
existing requirements are adequate to manage internal corrosion. INGAA
noted that subparts I and O include requirements for controlling
internal corrosion and assessments are being performed on almost all
gas transmission lines. INGAA further commented that controlling gas
quality is most important.
2. Ameren Illinois opposed new requirements addressing internal
corrosion, noting that Sec. 192.475 addresses the topic and subpart O
requires operators to respond to risks that are identified.
3. Kern River and Northern Natural Gas opposed new requirements,
noting that industry data show IC is a minor threat to natural gas
transmission pipelines. Kern River commented that ASME/ANSI B31.8S,
Appendix A2, covers the analysis of gas constituents. Northern monitors
gas quality and takes corrective action as needed.
4. MidAmerican opposed new requirements, commenting that internal
corrosion is a regional problem and does not occur in many areas of the
country. MidAmerican requested that current integrity management
regulations be revised to eliminate the need to conduct internal
corrosion direct assessment when internal corrosion is not a threat.
5. NACE International opined that current regulations in subpart I
are adequate to address internal corrosion, and PHMSA's proposed
prescriptive requirements are not feasible.
6. Panhandle observed that requirements to minimize the potential
for internal corrosion in gas transmission pipelines are included in
Sec. Sec. 192.475, 192.476, and 192.477. In addition, OPS issued ADB-
00-02 requiring pipeline operators to review their internal corrosion
monitoring programs and operation. IM regulations in subpart O require
integrity management assessments that address the threat of internal
corrosion. INGAA members report that completion of baseline assessments
required by subpart O will result in the assessment of more than half
of the gas transmission pipeline mileage in the U.S. Panhandle
commented that several proposed prescriptive internal corrosion
requirements provided in the ANPRM are not feasible and noted that
liquids tend to accumulate in low spots that typically are not
accessible for sampling. Panhandle opined that vigilant enforcement of
gas quality standards is the most essential component of an internal
corrosion control program.
7. Texas Pipeline Association and Texas Oil & Gas Association
argued that no benefit would be gained by additional requirements in
this area. The associations observed that internal corrosion threats
are highly localized and monitoring and remediation efforts must be
customized for local conditions.
8. IUB noted that not all pipelines are susceptible to internal
corrosion and commented that operators and state inspection personnel
should not be unduly burdened by additional measures when problems do
not exist.
9. An anonymous commenter suggested that PHMSA require each
operator to have a subject matter expert well qualified in internal
corrosion, arguing that most operators currently rely on third-party
contractors.
Response to Question I.4 Comments
PHMSA appreciates the information provided by the commenters. The
majority of industry comments do not support revising subpart I to
require additional measures to prevent internal corrosion in gas
transmission pipelines. However, the current requirements for internal
corrosion control are non-specific and PHMSA believes that there is
benefit in enhancing the current internal corrosion control
requirements to establish a more effective minimum standard for
internal corrosion management. Therefore, PHMSA proposes to add a
requirement that each operator develop and implement a program to
monitor for and mitigate the presence of, deleterious gas stream
constituents and that the program be reviewed at least semi-annually.
For HCA segments, PHMSA proposes to address this in enhanced preventive
and mitigative measures to include objective performance criteria.
I.5. Should PHMSA prescribe practices or standards that address
prevention, detection, assessment, and remediation of SCC on gas
transmission pipeline systems? Should PHMSA require additional surveys
or shorter IM survey internals based upon the pipeline operating
temperatures and coating types?
1. INGAA and a number of pipeline operators recommended that PHMSA
avoid prescriptive requirements for the prevention, detection,
assessment, and remediation of SCC. The commenters noted that SCC
varies from pipeline to pipeline and suggested that threat management
should be through a framework of processes and decision making that can
tailor threat management to the requirements of each pipeline.
2. AGA and a number of its pipeline operators also objected to new
requirements in this area, noting that numerous industry documents
exist that provide guidance to address SCC.
3. Panhandle suggested that PHMSA avoid prescriptive standards for
the prevention, detection, assessment, and remediation of SCC on gas
transmission systems given the complex and variable nature of the
factors contributing to the formation and growth of SCC, arguing
performance-based standards allow operators the maximum flexibility to
develop and apply situational techniques for detecting, assessing, and
remediating this threat. Panhandle noted that multiple standards and
publications are available to address internal corrosion and that the
Pipeline
[[Page 20785]]
Research Council International (PRCI) has ongoing research in this
area. Panhandle expressed the view that voluntary use of performance
based standards, allowing operator flexibility in detecting, assessing
and remediating this threat, will ensure that the methods used in
managing these types of anomalies continue to improve.
4. GPTC, Ameren Illinois, Atmos, Paiute, and Southwest Gas argued
that existing regulations are sufficient and noted that there are
numerous industry documents that provide additional guidance for
addressing SCC.
5. TransCanada suggested that PHMSA adopt the current version of
ASME/ANSI B31.8S.
6. The Commissioners of Wyoming County Pennsylvania opined that it
is reasonable for PHMSA to prescribe practices or standards that
address prevention, detection, assessment and remediation of SCC on
transmission and gas gathering lines, including those in Class 1
locations. The Commissioners argued that it is important to address
this aspect of corrosion given aging of existing pipelines and the
significant number of new pipelines.
7. Air Products and Chemicals argued that operators should not be
required to undertake SCC prevention, detection, assessment and
remediation activities where a pipeline does not meet the B31.8S
criterion for SCC. Air Products further commented that it is important
that PHMSA's regulations and standards reflect the threshold concept of
susceptibility to SCC, and that a pipeline that does not meet the
B31.8S criteria for SCC risk should not be required to undertake SCC
prevention, detection, assessment, and remediation activities.
8. NACE International stated that overly prescriptive rules can
supplant sound engineering judgment and prevent innovation and the
development of new technologies.
9. Northern Natural Gas argued that the current regulations and
industry standards provide adequate guidance and that the assessment
criteria address operating temperature and coating type. Northern
Natural Gas noted that operating temperature is addressed in PHMSA Gas
FAQ 223 and that the reassessment interval should be determined by the
results of the integrity assessment performed pursuant to ASME B31.8S.
10. MidAmerican pointed out that these concerns are addressed in
the pre-assessment phase of direct assessment and adequately covered in
ASME/ANSI B31.8S.
11. Texas Pipeline Association and Texas Oil & Gas Association
suggested that additional regulations related to SCC could prove
beneficial. At the same time, the associations recommended that PHMSA
not require additional surveys or shorter intervals, arguing that the
current regulations are based on sound engineering practices.
12. A private citizen commented that SCC should be addressed as
part of a comprehensive corrosion control program.
13. An anonymous commenter noted that a reliable survey technique
for SCC does not now exist and suggested that PHMSA require shorter
assessment intervals for pipelines with a history of SCC.
14. INGAA argued that pipe temperature and coating are not
sufficient to identify SCC. INGAA contended that ASME/ANSI B31.8S
adequately covers prevention, detection, assessments, and remediation
of SCC and criteria to capture all pipe potentially susceptible to SCC
would be overly conservative. A number of pipeline operators supported
INGAA's comments.
15. NACE International opined that there are too many factors
involved, and they are too interrelated and location-specific, to allow
prescribing an optimal assessment interval for SCC.
Response to Question I.5 Comments
PHMSA appreciates the information provided by the commenters. The
majority of industry comments do not support new requirements for the
prevention, detection, assessment, and remediation of SCC. PHMSA
recognizes that SCC is an important safety concern, but does not
believe the current methods for managing SCC anomalies supports
prescribing a detailed SCC management approach that would be effective
for all operators. PHMSA does not propose to amend subpart I to
prescribe an SCC management plan at this time. PHMSA will continue to
study this issue and support ongoing research. PHMSA plans to hold a
public forum on the development of SCC standards in the future. Once
that process is complete, PHMSA will consider new minimum safety
standards for managing the threat of SCC. However, under topics C and
G, above, PHMSA does propose to include more specific requirements for
conducting integrity assessments for the threat of SCC and for
enhancing the HCA and non-HCA repair criteria to address SCC.
I.6. Does the NACE SP0204-2008 (formerly RP0204) Standard ``Stress
Corrosion Cracking Direct Assessment Methodology'' address the full
life cycle concerns associated with SCC? Should PHMSA consider this, or
any other standards to govern the SCC assessment and remediation
procedures? Do these standards vary significantly from existing
practices associated with SCC assessments?
1. INGAA and a number of pipeline operators stated that NACE SP0204
does not address the full life cycle of concerns of SCC. INGAA added
that SP0204, along with ASME/ANSI B31.8S, NACE publication 35103, STP-
TP-011, and Canadian recommended practices, do cover the full life
cycle concerns.
2. NACE International reported that its standard (SP0204) does not
address the full life cycle concerns of SCC.
3. GPTC noted that existing regulations and standards address SCC
concerns and commented that it is not clear what is meant by ``full
life cycle concerns.''
4. Ameren Illinois argued that full life cycle concerns are
addressed in the pre-assessment phase of stress corrosion cracking
direct assessment (SCCDA) and new prescriptive requirements are not
needed.
5. Northern Natural Gas commented that ASME/ANSI B31.8S should be
used in conjunction with NACE SP0204.
6. Panhandle reported that SCCDA was never intended to address full
life cycle management for SCC. The standard does not address aspects
such as the formation or nucleation of cracks or calculations to assess
the severity of cracks. Panhandle opined that the collective body of
SCC research does address the full life cycle, but cautioned the full
body of knowledge of all documents must be considered as some may be
dated and do not reflect current knowledge on SCC management.
7. An anonymous commenter suggested that NACE SP0204 does not
address full life cycle concerns, noting that SCC has been found in
circumstances where the standard would suggest it should not be
expected.
Response to Question I.6 Comments
PHMSA appreciates the information provided by the commenters and
agrees that sufficient information is not available at this time to
specify prescriptive standards for SCC management. See the response to
comments received on question I.5.
I.7. Are there statistics available on the extent to which the
application of the NACE Standard, or other standards, have affected the
number of SCC indications operators have detected on their pipelines
and the number of SCC-related pipeline failures? Are statistics
available that identify the number of SCC occurrences that have been
[[Page 20786]]
discovered at locations that meet the screening criteria in the NACE
standard and at locations that do not meet the screening criteria?
1. INGAA, GPTC, Texas Pipeline Association, Texas Oil & Gas
Association, and numerous pipeline operators reported that no data has
been collected on the application of any current standard. INGAA added
that available statistics indicate that the annual number of failures
due to SCC is generally decreasing and noted that a high percentage of
in-service failures, failures during hydro testing, and instances where
SCC cracks greater than 10 percent were found during excavations have
met the screening criteria of ASME/ANSI B31.8S (which are identical to
the NACE criteria).
2. Northern Natural Gas reported that it has found one instance of
SCC and no segments were identified subject to similar circumstances.
Response to Question I.7 Comments
PHMSA appreciates the information provided by the commenters and
agrees that sufficient information is not available at this time to
specify prescriptive standards for SCC management. PHMSA will be
studying this issue and soliciting further input from stakeholders in
the future. See the response to comments received on question I.5.
I.8. If new standards were to be developed for SCC, what key issues
should they address? Should they be voluntary?
1. NACE International suggested that existing standards should be
updated and improved rather than developing new standards, noting that
such updating is as normal part of the standards process.
2. INGAA and a number of its pipeline operators supported the
development of voluntary standards to cover detection, assessment,
mitigation, periodic assessment, and evaluation of effectiveness.
3. Panhandle supported the development of industry standards to
manage SCC but does not believe that such a document can be completed
until the gaps in the understanding of SCC have been addressed.
4. GPTC, Ameren Illinois, and Northern Natural Gas opined that the
combination of ASME/ANSI B31.8S and ASME STP-PT-011 provide adequate
guidance.
5. Atmos recommended that further investigation be required if SCC
outside of the criterion specified in NACE SP0204-2008 is found. Atmos
stated that any new standards that are developed should be voluntary so
that operators have additional methodologies available for mitigating
the threat of SCC as currently required by Sec. 192.929.
6. Texas Pipeline Association and Texas Oil & Gas Association
recommended any new standards for SCC apply only to Class 1 locations,
based on their conclusion that pipe designed for Class 2 conditions
(and above) is not susceptible to SCC.
Response to Question I.8 Comments
PHMSA appreciates the information provided by the commenters and
agrees that sufficient information is not available at this time to
specify prescriptive standards for SCC management. PHMSA will be
studying this issue and soliciting further input from stakeholders in
the future. See the response to comments received on question I.5.
I.9. Does the definition of corrosive gas need to clarify that
other constituents of a gas stream (e.g., water, carbon dioxide, sulfur
and hydrogen sulfide) could make the gas stream corrosive? If so, why
does it need to be clarified?
1. INGAA, supported by a number of its pipeline operators, opined
that the existing regulations are adequate, and commented that
prescriptive limits, such as those in Sec. 192.620, would not be as
effective in reducing the potential for internal corrosion.
2. GPTC recommended that Sec. 192.476 be revised to reflect only
those liquids that act as an electrolyte (i.e., water).
3. AGA sees no need to clarify the definition and noted that the
stated constituents pose no threat if water is not present.
4. Atmos, Paiute, and Southwest Gas noted that gas tariffs maintain
gas quality and water must be present with the constituents listed to
produce a corrosive gas stream. Paiute opined that Sec. 192.929 and
ASME/ANSI B31.8S are sufficient.
5. NACE International expressed uncertainty as to why the
definition needs to be clarified. NACE also noted that there are more
factors than those listed in the question that affect the corrosiveness
of a gas stream.
6. MidAmerican, Ameren Illinois, and Northern Natural Gas noted
that ASME/ANSI B31.8S requires analysis of gas constituents and argued
that operators know what constitutes a corrosive gas stream. The
operators do not believe the definition needs to be changed.
7. Kern River suggested that the definition should be changed,
noting that water must be present, in addition to the listed
constituents, to make a gas stream corrosive.
8. Texas Pipeline Association and Texas Oil & Gas Association
suggested no change to the definition is needed, since operators
understand the listed constituents, when combined with water, can cause
internal corrosion.
9. An anonymous commenter suggested that PHMSA not attempt to list
constituents that could make a gas stream corrosive, arguing there are
too many scenarios to cover. The commenter noted that the issue is not
simple: H2O w/o free O2, or CO2 or
sulfur alone are not corrosive.
Response to Question I.9 Comments
PHMSA appreciates the information provided by commenters, and
consistent with the majority of comments, PHMSA does not propose to
revise the definition of corrosive gas at this time. However, PHMSA
does propose to clarify the regulations by listing examples of
constituents that are potentially corrosive, and to propose objective
performance criteria for monitoring gas stream contaminants for HCA
segments.
I.10. Should PHMSA prescribe for HCAs and non-HCAs external
corrosion control survey timing intervals for close interval surveys
that are used to determine the effectiveness of CP?
1. INGAA, supported by a number of pipeline operators, suggested
that safety would be best served by following a risk-based approach to
determine intervals for corrosion control or close interval surveys,
arguing that prescriptive requirements applicable to all pipelines
would divert safety resources from other high-risk tasks.
2. AGA, GPTC, and a number of pipeline operators argued that there
is no reason for PHMSA to specify timing of close interval surveys,
contending that the current subpart I requirements have proven to be
successful and the use of CIS as an indirect assessment tool is built
into NACE SP0502.
3. Ameren Illinois opposed the prescribed intervals for close
interval surveys, arguing that Sec. 192.463 and 192.465 are adequate.
In addition, Ameren noted that Sec. 192.917(e)(5) requires an operator
to evaluate and remediate corrosion in both covered and non-covered
segments when corrosion is found.
4. Atmos opposed required timing for close interval surveys,
arguing that CIS is just one tool that can be used to determine the
effectiveness of CP.
5. MidAmerican expressed its conclusion that establishing required
timing intervals for close interval surveys would not be beneficial.
MidAmerican noted that specific pipeline characteristics need to be
taken
[[Page 20787]]
into consideration in establishing inspection intervals.
6. Paiute and Southwest Gas opposed required periodicity for close
interval surveys, arguing that NACE SP0207 provides adequate guidance.
7. Northern Natural Gas commented that PHMSA should not prescribe
external corrosion control survey intervals for close interval surveys,
noting that its integrity management program demonstrates that external
corrosion is being managed effectively.
8. Texas Pipeline Association and Texas Oil & Gas Association
argued that industry experience demonstrates existing requirements are
adequate.
9. An anonymous commenter suggested that specified periodicity for
close interval surveys could have benefit, especially where a history
of external corrosion exists.
Response to Question I.10 Comments
PHMSA appreciates the information provided by the commenters.
Recent experience, including the December 2012 explosion near
Sissonville, WV and the 2007 incident near Delhi, LA, underscores the
need to be more attentive to external corrosion mitigation activities.
PHMSA proposes to enhance the requirements of subpart I to require that
operators conduct close-interval surveys if annual test station
readings indicate that cathodic protection is below the level of
protection required in subpart I, or to restore adequate corrosion
control. For HCA segments, PHMSA proposes to address these requirements
in enhanced preventive and mitigative measures, to include an objective
timeframe for restoration of deficient cathodic protection.
I.11. Should PHMSA prescribe for HCAs and non-HCAs corrosion
control measures with clearly defined conditions and appropriate
mitigation efforts? If so, why?
1. INGAA stated it does not believe it is feasible to develop
prescriptive measures that identify necessary and sufficient monitoring
and mitigation efforts in all environments. A number of pipeline
operators supported INGAA's comments.
2. AGA and a number of its operator members expressed their
conclusion that the requirements of subpart I are sufficient, noting
that they address HCA and non HCA alike.
3. GPTC commented that the question does not make clear why
additional measures should be prescribed given that operators have been
successfully mitigating corrosion deficiencies for many years.
4. Ameren Illinois expressed its conclusion that the science of
corrosion mitigation is sufficiently advanced and appropriate
mitigation measures are well known. Atmos, Paiute, and Southwest Gas
agreed, concluding that subpart I is sufficient when implemented
properly by appropriately trained and qualified personnel.
5. MidAmerican opposed new requirements, arguing that current
regulations address all practical mitigation efforts.
6. Texas Pipeline Association and Texas Oil & Gas Association
suggested that more time should be allowed before additional
prescriptive requirements on cathodic protection are considered, noting
that corrosion leaks are trending downward.
7. The Commissioners of Wyoming County Pennsylvania suggested that
it is reasonable that PHMSA prescribe corrosion control measures for
HCAs and non-HCAs with clearly defined conditions and appropriate
mitigation efforts. They cited information from NACE indicating that 25
percent of all accidents are caused by corrosion and these accidents
account for 36 percent of all accident damage. The Commissioners noted
that gathering lines in the Marcellus Shale area have diameters and
pressures similar to transmission lines and should be subjected to the
same requirements.
8. An anonymous commenter recommended that PHMSA not prescribe
specific measures.
Response to Question I.11 Comments
PHMSA appreciates the comments provided, and consistent with the
majority of comments, does not propose additional regulatory changes at
this time, other than to prescribe measures to promptly restore
cathodic protection, as discussed in the response to comments received
for question I.10.
PHMSA is interested in the extent to which operators have
implemented Canadian Energy Pipeline Association (CEPA) SCC,
Recommended Practices 2nd Edition, 2007, and what the results have
been.
I.12. Are there statistics available on the extent to which gas
transmission pipeline operators apply the Canadian Energy Pipeline
Association (CEPA) practices?
I.13. Are there statistics available that compare the number of SCC
indications detected and SCC-related failures between operators
applying the CEPA practices and those applying other SCC standards or
practices?
1. INGAA reported that most major operators in North America have
adopted threat management closely aligned to CEPA standards, but that
no specific data exist that correlate the use of CEPA methods to
anomaly detection. INGAA reported a Joint Industry Project (JIP) study
that shows that applying NACE SP0204, ASME/ANSI B31.8S, CEPA, and other
standards has led to a significant reduction in in-service failures.
Numerous pipeline operators supported INGAA comments.
2. AGA, supported by a number of its pipeline operator members,
questioned why a discussion of CEPA standards was included in the
ANPRM. AGA suggested that CEPA practices are well suited to Canadian
infrastructure, but not necessarily applicable in the United States and
noted that CEPA is not often discussed by Canadian members at AGA
meetings.
3. GPTC expressed that its membership has little knowledge of CEPA
standards, commented that it is not clear what is meant by full life
cycle concerns, and argued that existing standards and regulations
adequately address SCC concerns. GPTC is not aware of any data
correlating the efficacy of CEPA to other standards.
4. Paiute and Southwest Gas reported that they have not implemented
CEPA standards.
Response to Questions I.12 and I.13 Comments
PHMSA appreciates the information provided by the commenters. PHMSA
acknowledges the comments provided on the use of the CEPA SCC
Recommended Practice and will consider that standard in its study of
comprehensive safety requirements for SCC.
I.14. Do the CEPA practices address the full life cycle concerns
associated with SCC? If not, which are not addressed?
1. INGAA reported its conclusion that CEPA standards address full
life cycle concerns for near-neutral SCC. Many management techniques in
CEPA standards are also applicable to high-pH SCC, but the two are not
identical. Several pipeline operators supported INGAA's comments.
2. Texas Pipeline Association and Texas Oil & Gas Association
expressed their conclusion that CEPA standards address the full life
cycle concerns of SCC.
Response to Question I.14 Comments
PHMSA appreciates the information provided by the commenters. PHMSA
acknowledges the comments provided on the use of the CEPA SCC
Recommended Practice and will consider that standard in its study of
[[Page 20788]]
comprehensive safety requirements for SCC.
I.15. Are there additional industry practices that address SCC?
1. INGAA, supported by a number of its pipeline operator members,
reported that there are no related European standards and Australia has
a standard similar to ASME/ANSI B31.8S. INGAA noted that SCC failures
of pipelines installed since 1980 are rare and observed that quality
coating and cathodic protection are the most effective means of
preventing SCC.
2. GPTC stated that NACE SP0204 and 35103, ASME/ANSI B31.8S, and
GPTC guide material address SCC. Paiute and Southwest Gas agreed that
NACE standards and GPTC provide relevant guidance.
3. AGA commented that it does not have the statistics available to
advise whether or not additional requirements are needed to address SCC
threats.
4. Atmos, Texas Pipeline Association and Texas Oil & Gas
Association reported that they have no knowledge of other SCC standards
or practices.
5. Northern Natural Gas cited ASME/ANSI B31.8S and ASME STP-PT-011.
Response to Question I.15 Comments
PHMSA appreciates the information provided by the commenters. PHMSA
acknowledges the comments provided on the standards, and will consider
these standards in its study of comprehensive safety requirements for
SCC.
I.16. Are there statistics available on the extent to which various
tools and methods can accurately and reliably detect and determine the
severity of SCC?
1. INGAA noted that the measurement of ILI crack detection tool
performance is an ongoing research activity, both within JIP Phase II
and within the Pipeline Research Council International, which is
actively supported by the tool vendors and the pipeline operators.
Several issues regarding the acquisition and interpretation of
information need to be standardized by the practitioners before a clear
picture can emerge. The implications of tool tolerance on predicted
failure pressure are being studied in the JIP Phase II.
2. GPTC, Atmos, Paiute, Southwest Gas, and an anonymous commenter
reported that they are unaware of any relevant statistics.
3. Northern Natural Gas reported that it has used electro-magnetic
acoustic transducer (EMAT) ILI with some success.
4. Panhandle commented that magnetic particle inspection (MPI) is
effective at locating surface-breaking linear indications, a subset of
SCC. Furthermore, abrasive wheel grinding in conjunction with MPI is an
effective method to size the length and depth of surface-breaking
linear indications, limited by the amount of metal that can be removed
from in-service pipelines. Panhandle noted that PRCI research indicates
that laser UT techniques can effectively locate and size SCC, but this
method is relatively new and Panhandle has no experience with its use.
Panhandle also reported that the use of EMAT has yet to be acknowledged
as a replacement for hydrostatic testing but it is being evaluated in
Phase II of the SCC Joint Industry Project (JIP); results of the study
will be used to determine the path forward for EMAT technology.
5. Texas Pipeline Association and Texas Oil & Gas Association
reported that they have no knowledge of relevant references other than
the Baker study.
Response to Question I.16 Comments
PHMSA appreciates the information provided by the commenters and
will consider this information in its study of comprehensive safety
requirements for SCC.
I.17. Are tools or methods available to detect accurately and
reliably the severity of SCC when it is associated with longitudinal
pipe seams?
1. INGAA and a number of pipeline operators noted that detecting
SCC close to a longitudinal seam is difficult and even harder near a
girth weld. INGAA commented that developing tools to reliably detect
and assess SCC near longitudinal seams is a continuing challenge.
2. GPTC reported that SCC tools are available; however, GPTC
cautioned that the ability to accurately and reliably detect the
severity of SCC associated with longitudinal seams is dependent on
specific operating conditions.
3. Atmos commented that it knows of no tools that can accurately
detect and estimate the severity of SCC near a longitudinal seam.
4. Paiute and Southwest Gas reported that tools are being developed
but are, as of yet, not accurate at determining the severity of SCC
associated with longitudinal seams.
5. Northern Natural Gas reported that it has used electro-magnetic
acoustic transducer (EMAT) ILI with some success. Panhandle added that
difficulties in using EMAT are further complicated when cracking is
associated with a longitudinal seam.
6. Texas Pipeline Association and Texas Oil & Gas Association
expressed their conclusion that the best methods to assess for SCC near
longitudinal seams are pressure testing and EMAT, although they noted
that some operators have had success with transverse flux ILI.
7. An anonymous commenter reported that new ILI tools exist but
that analysts are not yet consistent in using them.
Response to Question I.17 Comments
PHMSA appreciates the information provided by the commenters and
will consider this information in its study of comprehensive safety
requirements for SCC.
I.18. Should PHMSA require that operators perform a critical
analysis of all factors that influence SCC to determine if SCC is a
credible threat for each pipeline segment? If so, why? What experience
based indications have proven reliable in determining whether SCC could
be present?
1. INGAA, supported by a number of pipeline operators, noted that
operators are already required to perform an analysis to determine the
likelihood of SCC. INGAA added that operators address the pipelines
with the highest likelihood of SCC and apply lessons learned, as
appropriate, to lower-likelihood pipelines.
2. Texas Pipeline Association and Texas Oil & Gas Association
indicated that a requirement to perform a critical analysis for SCC is
unnecessary, since guidance in ASME/ANSI B31.8S is sufficient. Northern
Natural Gas also stated that additional requirements are unnecessary,
noting that it conducted an analysis of critical factors affecting SCC
and identified no new factors over those in B31.8S, Appendix 3.
3. Atmos stated that PHMSA's question was unclear whether to expand
the threat of SCC to all pipeline segments or expand the requirements
for investigating the presence of SCC within HCA segments? Atmos
concluded that subpart O requirements provide a framework for operators
to integrate data, rank risk, identify threats, and apply appropriate
mitigative actions; additional requirements are not needed.
4. Texas Pipeline Association and Texas Oil & Gas Association
suggested that PHMSA conduct a workshop to share industry experience
with SCC.
Response to Question I.18 Comments
PHMSA appreciates the information provided by the commenters and
will consider this information in its study of comprehensive safety
requirements for SCC.
I.19. Should PHMSA require an integrity assessment using methods
capable of detecting SCC whenever a credible threat of SCC is
identified?
[[Page 20789]]
1. INGAA, Panhandle, Atmos, and Northern Natural Gas noted that
subpart O already requires that all credible threats be identified and
assessed. A number of pipeline operators supported INGAA's comments.
2. Texas Pipeline Association and Texas Oil & Gas Association also
indicated that they read subpart O as requiring assessment using a
method that can detect SCC if that threat is credible. The associations
both added, however, that they would not object to making this
requirement more explicit.
3. GPTC opined that existing regulations and standards are adequate
to address SCC issues.
4. Southwest Gas opposed a new requirement, noting that Sec.
192.929 and ASME/ANSI B31.8S are sufficient.
Response to Question I.19 Comments
PHMSA appreciates the information provided by the commenters and
will consider this information in its study of comprehensive safety
requirements for SCC. As indicated above in the response to comments
received on question I.5, PHMSA proposes more explicit requirements for
selection of appropriate methods for integrity assessments for SCC.
I.20. Should PHMSA require a periodic analysis of the effectiveness
of operator corrosion management programs, which integrates information
about CP, coating anomalies, in-line inspection data, corrosion coupon
data, corrosion inhibitor usage, analysis of corrosion products,
environmental and soil data, and any other pertinent information
related to corrosion management? Should PHMSA require that operators
periodically submit corrosion management performance metric data?
1. INGAA, Kern River, Paiute, and Southwest Gas commented that
these issues are already addressed in subpart O, which requires
operators to keep records, measure program effectiveness, continually
evaluate and assess systems, integrate data, and show continual
improvement. INGAA added that metrics bearing on the effectiveness of a
corrosion control program are already among those required to be
collected by ASME/ANSI B31.8S. These metrics are not required to be
submitted, but are available for review during inspections. A number of
pipeline operators supported INGAA's comments.
2. MidAmerican commented that subparts I and O include these
requirements. Northern Natural Gas agreed that it manages these threats
through O&M and IM activities.
3. Panhandle noted that subpart I requires operators to maintain
effective corrosion control programs to mitigate the threat of
corrosion and Sec. 192.945 requires operators to measure, on a semi-
annual basis, whether the integrity management program is effective in
assessing and evaluating the integrity of each covered pipeline segment
and in protecting HCAs.
4. GPTC and AGA, supported by a number of its pipeline operator
members, opposed requiring operators to submit corrosion management
metrics. AGA noted that operators need flexibility to select the
appropriate analysis methods and key performance indicators.
Furthermore, operators review corrosion control program effectiveness,
and plans of intrastate operators are reviewed by state commissions.
5. Ameren Illinois opposed new requirements, noting that subpart O
already requires operators to identify and respond to risks.
6. Atmos questioned whether PHMSA is proposing to measure the
effectiveness of corrosion management programs across all pipeline
segments or to measure the effectiveness of corrosion management
programs in HCA segments. Atmos added that the data points enumerated
by PHMSA in this question would be difficult to gather on an operator's
entire pipeline system.
7. Texas Pipeline Association and Texas Oil & Gas Association
stated that they do not see a need for a requirement to periodically
analyze the effectiveness of an operator's corrosion management
program, arguing that existing requirements are sufficient.
8. Panhandle argued that the standardization of corrosion control
efforts, as would be required for performance metric tracking, would
require additional prescriptive requirements in subpart O. Panhandle
does not believe that elimination of performance-based language is
beneficial.
9. The Commissioners of Wyoming County Pennsylvania suggested that
any communication between operators and PHMSA regarding corrosion
management would be helpful in facilitating operator compliance and
best practices.
10. Paiute and Southwest Gas reported that they opposed a
requirement to report additional performance metrics absent a
definition of how new data would be collected and used.
Response to Question I.20 Comments
PHMSA appreciates the information provided by the commenters.
Following publication of the ANPRM, the NTSB issued recommendations in
response to the San Bruno pipeline incident, including a specific
recommendation (P-11-19) that PHMSA establish standards for evaluating
effective program performance. PHMSA will evaluate standards for
integration of pipeline corrosion data to enhance corrosion management
performance as part of its response to that recommendation.
I.21. Are any further actions needed to address corrosion issues?
1. INGAA, supported by a number of its pipeline operator members,
commented that continued study and evaluation of the root causes of the
San Bruno explosion, documentation of findings, and communication of
results are needed rather than additional prescriptive requirements.
2. AGA, GPTC, and a number of pipeline operators argued that no
further action is needed, given that current methodologies adequately
address corrosion issues and operators are subject to periodic audits
by federal and state safety regulators.
3. Accufacts suggested that PHMSA needs to assure that IM programs
are not solely relied upon to prevent corrosion failure.
4. Texas Pipeline Association and Texas Oil & Gas Association
reported that they do not see any deficiencies necessitating new
regulations.
Response to Question I.21 Comments
PHMSA appreciates the information provided by the commenters. As
discussed above, PHMSA is proposing some enhanced measures for
corrosion control in subpart I and subpart O.
I.22. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements pursuant to commenter's suggestions.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the
existing regulatory requirements.
No comments were received in response to this question.
J. Pipe Manufactured Using Longitudinal Weld Seams
The ANPRM requested comments regarding additional integrity
management and pressure testing
[[Page 20790]]
requirements for pipe manufactured using longitudinal seam welding
techniques that have not had a subpart J pressure test. Pipelines built
since the regulations (49 CFR part 192) were implemented in early 1971
must be:
Pressure tested after construction and prior to being
placed into gas service in accordance with subpart J; and
Manufactured in accordance with a referenced standard
(most gas transmission pipe has been manufactured in accordance with
American Petroleum Institute Standard 5L, 5LX or 5LS, ``Specification
for Line Pipe'' (API 5L) referenced in 49 CFR part 192).
Many gas transmission pipelines built from the 1940's through 1970
were manufactured in accordance with API 5L, but may not have been
pressure tested similar to a subpart J pressure test. For pipelines
built prior to 1971, Sec. 192.619(a) allows MAOP to be based on the
highest 5-year operating pressure established prior to July 1, 1970, in
lieu of a pressure test. Accordingly, some of this pre-existing pipe
possesses variable characteristics throughout the longitudinal weld or
pipe body.
As a result of 12 hazardous liquid pipeline failures that occurred
during 1986 and 1987 involving pre-1970 ERW pipe, PHMSA issued an alert
notice (ALN-88-01, January 28, 1988) to advise operators with pre-1970
ERW pipe of the 12 pipeline failures and the actions to take.
Subsequent to this notice, one additional failure on a gas transmission
pipeline, and eight additional failures on hazardous liquid pipelines
occurred, which resulted in PHMSA issuing another alert notice (ALN-89-
01, March 8, 1989) to advise operators of additional findings since the
previous alert notice. These notices identified the fact that some
failures appeared to be due to selective seam weld corrosion, but that
other failures appeared to have resulted from flat growth of
manufacturing defects in the ERW seam. In these notices, PHMSA
specifically advised all gas transmission and hazardous liquid pipeline
operators with pre-1970 ERW pipe to consider hydrostatic testing of
affected pipelines, to avoid increasing a pipeline's long-standing
operating pressure, to assure effectiveness of the CP system, and to
conduct metallurgical exams in the event of an ERW seam failure.
Since 2002, there have been at least 22 reportable incidents on gas
transmission pipeline caused by manufacturing or seam defects. In
addition, recent high consequence incidents, including the 2009 failure
in Palm City, Florida and the 2010 failure in San Bruno, California,
have been caused by longitudinal seam failures.
The ANPRM listed questions for consideration and comment. The
following are general comments received related to the topic as well as
comments related to the specific questions:
General Comment for Topic J
1. Texas Pipeline Association and Texas Oil & Gas Association
suggested that seam issues are best addressed through inspection,
detection, remediation, and monitoring, based on specific segments, not
a one-size-fits-all requirement.
Response to General Comment for Topic J
PHMSA appreciates the comment and agrees that a one-size-fits-all
requirement is not the best approach. Accordingly, PHMSA proposes
requirements for verification of MAOP in new Sec. 192.624 for onshore,
steel, gas transmission pipelines, that are located in an HCA or MCA
and meet any of the conditions in Sec. 192.624(a)(1) through (a)(3).
Verification of MAOP includes establishing and documenting MAOP if the
pipeline segment: (1) Has experienced a reportable in-service incident,
as defined in Sec. 191.3, since its most recent successful subpart J
pressure test, due to an original manufacturing-related defect, a
construction-, installation-, or fabrication-related defect, or a
cracking-related defect, including, but not limited to, seam cracking,
girth weld cracking, selective seam weld corrosion, hard spot, or
stress corrosion cracking and the pipeline segment is located in one of
the following locations: (i) A high consequence area as defined in
Sec. 192.903; (ii) a class 3 or class 4 location; or (iii) a moderate
consequence area as defined in Sec. 192.3 if the pipe segment can
accommodate inspection by means of instrumented inline inspection tools
(i.e., ``smart pigs''); (2) Pressure test records necessary to
establish maximum allowable operating pressure per subpart J for the
pipeline segment, including, but not limited to, records required by
Sec. 192.517(a), are not reliable, traceable, verifiable, and complete
and the pipeline segment is located in one of the following locations:
(i) A high consequence area as defined in Sec. 192.903; or (ii) a
class 3 or class 4 location; or (3) the pipeline segment maximum
allowable operating pressure was established in accordance with Sec.
192.619(c) of this subpart before [effective date of rule] and is
located in one of the following areas: (i) A high consequence area as
defined in Sec. 192.903; (ii) a class 3 or class 4 location; or (iii)
a moderate consequence area as defined in Sec. 192.3 if the pipe
segment can accommodate inspection by means of instrumented inline
inspection tools (i.e., ``smart pigs'').
In addition, the proposed rule would allow operators to select from
among several approaches to verify MAOP based on segment specific
issues and limitations, such as pressure testing, pressure reduction
based on historical operating pressure, and engineering critical
assessment.
Comments submitted for questions in Topic J.
J.1. Should all pipelines that have not been pressure tested at or
above 1.1 times MAOP or class location test criteria (Sec. Sec.
192.505, 192.619 and 192.620), be required to be pressure tested in
accordance with the present regulations? If not, should certain types
of pipe with a pipeline operating history that has shown to be
susceptible to systemic integrity issues be required to be pressure
tested in accordance with the present regulations (e.g., low-frequency
electric resistance welded (LF-ERW), direct current electric resistance
welded (DC-ERW), lap-welded, electric flash welded (EFW), furnace butt
welded, submerged arc welded, or other longitudinal seams)? If so, why?
1. AGA, GPTC, and numerous pipeline operators opposed a requirement
to pressure test all lines not previously tested. These commenters
supported the more-limited testing mandated by the Pipeline Safety,
Regulatory Certainty, and Job Creation Act of 2011. AGA noted that
Congress considered and rejected proposals for more extensive testing.
2. AGA, GPTC, Iowa Utilities Board, Iowa Association of Municipal
Utilities, Texas Pipeline Association, Texas Oil & Gas Association, and
several distribution pipeline operators objected to requiring pressure
testing of distribution pipelines. The commenters argued that the
impact of resulting service disruptions was overlooked. Pressure
testing would necessitate disruptions of three to seven days for many
distribution pipelines, sometimes involving service to an entire town.
In some cases, establishing an alternate supply is not always possible.
In addition, some in-service lines are not configured in a manner that
would support testing. For these reasons, the commenters argued that
the high costs to perform pressure tests were inappropriate absent some
demonstration of actual risk. MidAmerican added a suggestion that such
a requirement of this type be
[[Page 20791]]
limited to pipelines operating above 30 percent of specified minimum
yield strength (SMYS). Northern Natural Gas agreed with MidAmerican's
suggestion and would further limit any testing requirement to pipelines
outside of Class 1 locations and subject to seam issues.
3. INGAA, GPTC, Texas Pipeline Association, Texas Oil & Gas
Association, and several pipeline operators opposed a blanket testing
requirement for older pipelines. The commenters noted that more than
sixty percent of in-service pipelines were installed prior to 1970, and
have operated safely. INGAA argued that the objective of any action in
this area should not be pressure testing, per se, but verification of
fitness for service. INGAA noted that all of the listed pipe types are
addressed in its Fitness for Service protocol, which would be more
effective and efficient than a prescriptive test requirement. A number
of additional pipeline operators supported INGAA's comments.
4. Accufacts recommended that all pipelines with at-risk seam
anomalies be pressure tested to at least 90% SMYS, with priority given
to lines operating under an MAOP established in accordance with 49 CFR
192.619(c).
5. Texas Pipeline Association and Texas Oil & Gas Association noted
that pressure testing alone, is not sufficient to prove the integrity
of pipelines subject to seam issues. The associations argued that
verification must also consider any degradation mechanism present in
the seam.
6. Dominion East Ohio supported a requirement to pressure test pipe
susceptible to seam failure for which adequate test documentation does
not exist.
7. Pipeline Safety Trust, California Public Utilities Commission,
Commissioners of Wyoming County Pennsylvania, and an anonymous
commenter supported requiring a pressure test for all pipelines not
already tested to current requirements. The commenters argued that
integrity management should have led to necessary testing but has not
done so in all cases. They also noted that such a requirement would
respond to an NTSB recommendation.
8. The Environmental Defense Fund (EDF) cautioned that any
requirement for pressure testing should assure that the amount of gas
blown down to the atmosphere is minimized. It noted that methane is a
potent greenhouse gas, and uncontrolled blowdown of 182,000 miles of
gas transmission pipeline would be approximately equivalent to the
annual greenhouse gas release from 9-14 million autos.
Response to Question J.1 Comments
PHMSA appreciates the information provided by the commenters. This
NPRM proposes requirements for verification of MAOP in new Sec.
192.624 for onshore, steel, gas transmission pipelines that are located
in an HCA or MCA and meet any of the conditions in Sec. 192.624(a)(1)
through (a)(3). Verification of MAOP includes establishing and
documenting MAOP using one or more of the methods in Sec.
192.624(c)(1) through (c)(6). With regard to the EDF comment regarding
the environmental cost due to gas blow down during pressure testing,
PHMSA considered this in the rule development. The proposed rulemaking
is written to minimize pressure testing. The Integrity Verification
Process allows MAOP verification through ILI and ECA. PHMSA believes
operators will pressure test as a last resort because it is the
costliest methodology. PHMSA estimates that the rule would result in
approximately 1,300 miles of pipe being pressure tested. The gas
release from controlled low volume release during pressure testing is
much less than an uncontrolled high volume release as a result of
rupture. The proposed rule is expected to prevent incidents, leaks, and
other types of failures that might occur, thereby preventing future
releases of greenhouse gases (GHG) to the atmosphere, thus avoiding
additional contributions to global climate change. PHMSA estimated net
GHG emissions abatement over 15 years of 69,000 to 122,000 metric tons
of methane and 14,000 to 22,000 metric tons of carbon dioxide, based on
the estimated number of incidents averted and emissions from pressure
tests and ILI upgrades.
J.2. Are alternative minimum test pressures (other than those
specified in subpart J) appropriate, and why?
1. INGAA, supported by a number of pipeline operators, argued that
there is no evidence suggesting that subpart J test pressures are
inadequate. INGAA added that there are circumstances in which
additional tests to 1.25 times MAOP may be appropriate to verify
fitness for service. This is consistent with ASME/ANSI B31.8S and
addressed in its Fitness for Service protocol.
2. Texas Pipeline Association, Texas Oil & Gas Association, and
Atmos argued that a pressure test at the time of construction is
adequate. The associations further added that operating practices since
part 192 became effective can also verify fitness for service, if
primary test records are not available, particularly if MAOP is
reduced.
3. AGA, GPTC, and a number of pipeline operators commented that any
test to pressures greater than MAOP has some value. AGA noted that even
tests to 1.1 times MAOP would identify the most severe defects that
have the potential to adversely affect pipeline integrity.
4. MidAmerican suggested that a fitness for service evaluation
should be allowed if there are service interruption issues and for pre-
1970 pipelines. MidAmerican would allow testing for existing pipelines,
to 1.1 or 1.25 times MAOP or to mill test pressures if they are less
than would be required by subpart J.
5. An anonymous commenter argued that alternative minimum test
pressures are not appropriate, since they provide no more information
than successful operation at normal operating pressures.
6. Accufacts suggested that pipelines tested to lower pressures and
that have been subject to aggressive operating cycles be considered for
high-pressure testing. Accufacts would also require test pressures be
recorded both in psig and percent SMYS.
Response to Question J.2 Comments
PHMSA appreciates the information provided by the commenters.
Following publication of the ANPRM, the NTSB issued its report on the
San Bruno incident that included a recommendation for this issue (P-11-
15). The NTSB recommended that PHMSA amend its regulations so that
manufacturing- and construction-related defects can only be considered
``stable'' if a gas pipeline has been subjected to a post-construction
hydrostatic pressure test of at least 1.25 times the MAOP. This NPRM
proposes to revise the integrity management requirement in
192.917(e)(3) to allow the presumption of stable manufacturing and
construction defects only if the pipe has been pressure tested to at
least 1.25 times MAOP. In addition, PHMSA proposes to revise pressure
test safety factors in Sec. 192.619(a)(2)(ii) to correspond to at
least 1.25 MAOP for newly installed pipelines.
J.3. Can ILI be used to find seam integrity issues? If so, what ILI
technology should be used and what inspection and acceptance criteria
should be applied?
1. INGAA and numerous pipeline operators noted that ILI tools can
examine seam issues but the technology to identify and evaluate seam
anomalies is still evolving. INGAA added that there are significant
burdens associated
[[Page 20792]]
with requiring pressure testing as an alternative.
2. AGA reported that its discussions with ILI vendors have
identified that ILI can detect seam issues but detection is dependent
on many conditions and is not guaranteed.
3. Texas Pipeline Association and Texas Oil & Gas Association
argued that ILI conducted using a multi-purpose tool can provide a seam
assessment equivalent to pressure testing for detection of seam
integrity issues, depending on anomaly characteristics and the ILI
method used.
4. Northern Natural Gas commented that ILI can be used to detect
seam anomalies. Analysis of anomalies is based on the log-secant method
with consideration of toughness to determine the predicted failure
pressure ratio. The response criteria can then be based on the failure
pressure versus maximum allowable operating pressure, similar to wall
loss. Northern noted that this is consistent with ASME/ANSI B31.8 and
B31.8S.
5. Accufacts commented that ILI cannot, at present, reliably detect
all seam anomalies.
Response to Question J.3 Comments
PHMSA appreciates the information provided by the commenters. PHMSA
proposes requirements in the rulemaking to address the use of ILI for
seam integrity issues. This includes incorporating industry standard
NACE SP0102-2010 into the regulations to provide better guidance for
conducting integrity assessments with in-line inspection. In addition,
for pipe segments subject to MAOP verification in new Sec. 192.624,
specific guidance is provided for analyzing crack stability when using
engineering critical assessment in conjunction with inline inspection
to address seam or other cracking issues.
J.4. Are other technologies available that can consistently be used
to reliably find and remediate seam integrity issues?
1. INGAA and numerous pipeline operators noted that magnetic
particle inspection is now being used by many operators when pipe with
disbanded coating is exposed.
2. GPTC, Northern Natural Gas, and MidAmerican reported that there
are other methods that are useful under some circumstances, such as x-
ray or other forms of radiography and guided wave ultrasound.
3. Texas Pipeline Association, Texas Oil & Gas Association, and
Atmos noted that radiography, ultrasonic testing (UT), and shear wave
UT are now being tested.
4. AGA, supported by a number of its pipeline operator members,
noted that operators must have the flexibility to select appropriate
tools without prior PHMSA approval. AGA argued that technology is
advancing rapidly and that PHMSA stifles advancement by requiring prior
approval of new inspection tools. AGA argued that some requirements
being imposed on the use of other technologies are effectively
regulations imposed without formal rulemaking, citing limitations
imposed on the use of guided wave ultrasound as an example.
5. Atmos recommended that PHMSA modify its regulations to allow
operators to use appropriate methods to evaluate seam integrity without
requiring approval as ``other technology.''
6. Accufacts opined that pressure testing and cyclic monitoring and
analysis are the only useful technologies currently available.
Response to Question J.4 Comments
PHMSA appreciates the information provided by the commenters. PHMSA
proposes requirements in the rulemaking to address the use of best
available technology, including use of electromagnetic acoustic
transducers (EMAT) or ultrasonic testing (UT) tools to assess seam
integrity issues. In addition, proposed requirements include performing
fracture mechanics modeling for failure stress pressure and cyclic
fatigue crack growth analysis to assess crack or crack-like defects.
These requirements would apply to any segment that required
verification of MAOP.
J.5. Should additional pressure test requirements be applied to all
pipelines, or only pipelines in HCAs, or only pipelines in Class 2, 3,
or 4 location areas?
1. INGAA and several pipeline operators argued that existing
requirements are adequate and any verification beyond those
requirements should rely on INGAA's Fitness for Service protocol. INGAA
argued that its protocol is consistent with Section 23 of the Pipeline
Safety, Regulatory Certainty, and Job Creation Act of 2011.
2. MidAmerican suggested any new requirements should focus on pipe
with manufacturing and construction defects and should prioritize
pipelines in Class 3 and 4 areas and HCAs. MidAmerican sees little
benefit in testing other pipelines.
3. An anonymous commenter recommended additional unspecified
requirements be applied to pipelines in Class 3 and 4 areas and HCAs.
4. The California Public Utilities Commission would apply pressure
testing requirements to HCAs that are determined by the method
described in paragraph 1 in the definition of HCA in Sec. 192.903, as
a minimum.
5. The Iowa Utilities Board and the Iowa Association of Municipal
Utilities argued that class location is not a reasonable basis for
determining where to apply pressure testing requirements, given that
class location has no relationship to risk. These commenters noted that
small-diameter, low-pressure lines could be Class 3, even with no
structures intended for human occupancy within a potential impact
radius.
6. The Commissioners of Wyoming County Pennsylvania would apply
requirements to all transmission and gathering pipelines, including
those in Class 1 locations.
7. Thomas Lael noted that all pipelines have been tested once,
after construction.
Response to Question J.5 Comments
PHMSA appreciates the information provided by the commenters. This
NPRM proposes requirements for verification of MAOP in new Sec.
192.624 for onshore, steel, gas transmission pipelines that are located
in an HCA or MCA and meet any of the conditions in Sec. 192.624(a)(1)
through (a)(3). Use of the MCA location criteria would apply to pipe
segments where dwellings, occupied sites, or interstate highways,
freeways, and expressways, and other principal 4-lane arterial roadways
are located within the potential impact radius, but would not
necessarily include all class 3 or 4 locations. Verification of MAOP
includes establishing and documenting MAOP using one or more of the
methods in 192.624(c)(1) through (c)(6). In addition, this NPRM
proposes requirements for verification of pipeline material in new
Sec. 192.607 for existing onshore, steel, gas transmission pipelines
that are located in an HCA or class 3 or class 4 locations.
J.6. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements pursuant to commenter's suggestions.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
[[Page 20793]]
The potential environmental impacts of modifying the
existing regulatory requirements.
No comments were received in response to this question.
K. Establishing Requirements Applicable to Underground Gas Storage
Underground storage facilities are comprised of wells and
associated separation, compression, and metering facilities to inject
and withdraw natural gas at high pressures from depleted hydrocarbon
reservoirs and salt caverns. Pipelines that transport gas within a
storage field are defined in Sec. 192.3 as transmission pipelines and
are regulated by PHMSA, while underground storage facilities including
surface and subsurface well casing, tubing, and valves are not
currently regulated under part 192. In the ANPRM, PHMSA provided a
brief history of a 1992 accident that occurred in Brenham, Texas an
involving underground storage facility. This incident involved an
uncontrolled release of highly volatile liquids from a salt dome
storage cavern that resulted in 3 fatalities, 21 people treated for
injuries at area hospitals, and damages in excess of $9 million.
Following the incident, the National Transportation Safety Board (NTSB)
conducted an investigation that resulted in a recommendation for the
Research and Special Programs Administration, the precursor to PHMSA,
to initiate a rulemaking proceeding. Following a period of study, RSPA
terminated that rulemaking. RSPA described this action in an Advisory
Bulletin published in the Federal Register on July 10, 1997 (ADB-97-04,
62 FR 37118).
Since publication of the 1997 Advisory Bulletin, significant
incidents have continued to occur involving underground gas storage
facilities. The most significant incident occurred in 2001 near
Hutchinson, Kansas. An uncontrolled release from an underground gas
storage facility resulted in an explosion and fire, in which two people
were killed. Many residents were evacuated from their homes and were
not able to return for four months.
The Kansas Corporation Commission initiated enforcement action
against the operator of the Hutchinson storage field as a result of
safety violations associated with the accident. As part of this
enforcement proceeding, it was concluded that the storage field was an
interstate gas pipeline facility. Federal statutes provide that ``[a]
State authority may not adopt or continue in force safety standards for
interstate pipeline facilities or interstate pipeline transportation''
(49 U.S.C. 60104). There were, and remain, no federal safety standards
against which enforcement could be taken. Therefore, the enforcement
proceeding was terminated.
The ANPRM listed questions for consideration and comment. The
following are general comments received related to this topic as well
as comments related to the specific questions:
General Comments for Topic K
1. AGA, supported by a number of pipeline operators, suggested that
any proceeding addressing gas storage be conducted under a docket
separate from any pipeline requirements, arguing that the relevant
engineering and regulatory concepts are vastly different.
2. The Kansas Department of Health and Environment (KDHE) noted
that the ANPRM misstated the agency that took enforcement action in the
case of the Kansas gas storage incident previously discussed. That
action was taken by KDHE, and not the Kansas Corporation Commission, as
stated.
3. Kansas Corporation Commission recommended that PHMSA work with
the states to have Congress amend the Pipeline Safety Act to allow the
states to regulate interstate and intrastate gas storage wellbores. KCC
noted that current federal regulations undermine the ability of states
to regulate gas storage facilities, as in the 2001 accident where
Kansas attempted to take enforcement as a result of a serious incident
but was precluded from doing so by pre-emption of federal regulations.
4. The Interstate Oil & Gas Compact Commission argued that states
should be mandated to regulate gas storage wellbores, whether
interstate or intrastate.
5. The Texas Pipeline Association and Texas Oil & Gas Association
opposed new requirements, arguing that there has been no demonstration
of undue risk or insufficiency of current regulations.
Comments submitted for questions in Topic K.
K.1. Should PHMSA develop Federal standards governing the safety of
underground gas storage facilities? If so, should they be voluntary? If
so, what portions of the facilities should be addressed in these
standards?
1. INGAA suggested that PHMSA develop high-level, performance-based
guidelines that acknowledge and reflect existing applicable state rules
to address regional and geologic variations in underground storage
activity. Development of guidelines should follow PHMSA's current
practice of stakeholder involvement leading to development of a
consensus standard and its subsequent adoption into regulations. INGAA
reported that it is committed to developing a standard under the
auspices of the American Petroleum Institute (API), with work beginning
in 2012. INGAA cautioned that it is important to understand, and
clearly state, the scope of ``gas storage,'' which it contends begins
at and includes the wing valve at the wellhead, the wellhead
components, the well bore, and the ``underground container'' (i.e., the
geologic formation). INGAA stated that PHMSA should recognize the
limits and requirements imposed on gas storage by FERC, arguing that no
new regulations are needed in these areas. A number of pipeline
operators supported INGAA's comments, and have submitted separate
comments addressing one or more of these points.
2. AGA suggested that PHMSA adopt federal performance standards, in
conjunction with API. AGA argued that one-size-fits-all requirements
are not appropriate in this area, since they would fail to recognize
variations in wells and the geologic diversity of storage caverns and
structures. AGA argued that no new requirements are needed governing
maximum operating parameters and environmental conditions, since these
are addressed adequately by existing federal and state certification
and compliance programs related to gas storage facilities. AGA
recommended that any new standards should be mandatory, but also
recognize regional variations by state due to geologic and geographical
diversity among storage fields. A number of pipeline operators
supported AGA's comments.
3. INGAA, the Kansas Corporation Commission, and the Interstate Oil
& Gas Compact Commission recommended that compliance with any new
standards be mandatory, but that regulatory authority should be
delegated to the states since PHMSA lacks relevant technical expertise.
A number of pipeline operators supported this comment.
4. The Kansas Corporation Commission and the Interstate Oil & Gas
Compact Commission recommended that any new standards cover all
portions of a storage facility and that PHMSA enter into a memorandum
of understanding with FERC regarding gas containment.
5. Southern Star Central Gas Pipeline agreed that the development
of requirements for operation of gas storage facilities is appropriate
but explicitly disagreed with Kansas Corporation Commission's
suggestion that development be delegated to states.
[[Page 20794]]
Southern Star indicated that it would not object to the delegation of
inspection and enforcement to federal standards. Southern Star noted
that a federal court has held only federal regulations can be enforced
against its storage facilities. The company also argued that no new
requirements are needed for storage reservoirs given existing FERC
regulations.
6. GPTC, Nicor, Ameren Illinois, and Atmos argued that existing
regulations are sufficient and that no new standards are needed. GPTC
and Nicor added that if PHMSA elects to develop new requirements, they
should be limited to facilities ``affecting interstate or foreign
commerce.'' Atmos added that geology and circumstances vary
considerably among gas storage facilities and states have the requisite
expertise to regulate storage safety.
7. Texas Pipeline Association and Texas Oil & Gas Association
argued that PHMSA lacks the expertise to regulate wellbores and
therefore should not attempt to develop gas storage regulations.
8. FERC, NAPSR, Interstate Oil & Gas Compact Commission, Iowa
Utilities Board, Kansas Corporation Commission, and Railroad Commission
of Texas recommended that PHMSA seek statutory authority to confer
jurisdiction over all gas storage facilities to the states. The
commenters argued that states have expertise on local geology and
storage fields and could therefore regulate in a fashion similar to
that of production facilities. The commenters referred to PHMSA's
Advisory Bulletin ADB 97-04 as a further basis for this recommendation.
FERC further suggested that PHMSA delegate inspection and enforcement
activities to states if statutory changes are not forthcoming.
9. The Alaska Department of Natural Resources recommended that
PHMSA develop standards in consultation with the states.
10. The NTSB encouraged the development of gas storage regulations,
noting that this was the subject of its recommendation P-93-9, which it
closed as ``unacceptable action,'' after a rulemaking proceeding to
regulate underground gas storage was terminated in 1997.
11. A private citizen suggested that there should be some level of
regulation, as gas storage is currently insufficiently regulated.
12. NAPSR commented that, in many states, the agency familiar with
gas storage issues is not responsible for regulation of pipeline
safety. As a result, NAPSR stated that certification of additional
state agencies may be required.
13. An anonymous commenter suggested that PHMSA should develop
requirements applicable to piping within gas storage facilities. The
commenter argued that caverns, well heads, casing, tubing, fresh water,
and brine pumping are generally regulated by states.
14. ITT Exelis Geospatial Systems suggested that PHMSA consider
requirements for leak detection, noting that their LIDAR system could
serve this purpose.
K.2. What current standards exist governing safety of these
facilities? What standards are presently used for conducting casing,
tubing, isolation packer, and wellbore communication and wellhead
equipment integrity tests for down-hole inspection intervals? What are
the repair and abandonment standards for casings, tubing, and wellhead
equipment when communication is found or integrity is compromised?
1. AGA, INGAA, GPTC, Texas Pipeline Association, Texas Oil & Gas
Association and numerous pipeline operators noted that FERC, EPA, and
the states regulate various aspects of gas storage. Commenters reported
that state regulations generally provide standards for wells and that
EPA regulations provide standards for caverns. AGA described the
aspects regulated by FERC, EPA, and the states and suggested provisions
of each which might be considered for new PHMSA regulations. For
example, it was recommended that a federal guideline be established to
require a storage operator notification-review-and-approval process for
third party wells encroaching on storage containers, which is a
requirement some states currently have in place. Commenters reported
that repaired wells must meet state standards for new wells and state
requirements for abandonment vary. AGA indicated that interstate
storage operators use state requirements as guidance in the absence of
federal regulations.
2. The Kansas Department of Health and Environment, the Kansas
Corporation Commission, the Railroad Commission of Texas, the
Interstate Oil & Gas Compact Association, Ameren Illinois, and Atmos
reported that states generally regulate gas storage. For example, in
Texas, Statewide Rule 16 applies and KDHE submitted a copy of its gas
storage regulations.
3. Texas Pipeline Association and Texas Oil & Gas Association noted
that Texas requirements for gas storage are more similar to provisions
that would govern production drilling and operations rather than
pipeline operations.
K.3. What standards are used to monitor external and internal
corrosion?
1. AGA, INGAA, and numerous pipeline operators noted that varying
approaches are used and argued that prescriptive standards would be
inappropriate given that no one tool is applicable to all wells and
well casings are not available for direct examination.
2. The Railroad Commission of Texas reported that its regulations
require integrity testing every five years or after a well work over.
Texas regulations also require periodic casing inspections and a
pipeline integrity program.
3. Northern Natural Gas reported that it uses the same measures to
monitor corrosion in its gas storage facilities as it does for its
pipelines.
K.4. What standards are used for welding, pressure testing, and
design safety factors of casing and tubing including cementing and
casing and casing cement integrity tests?
1. INGAA, AGA, the Texas Pipeline Association, the Texas Oil & Gas
Association and numerous pipeline operators noted that state
requirements reflect unique situations, welding is seldom used,
pressure capacity is demonstrated by historical record, and casing
requirements are customized for local geologic conditions. Welding,
when used, is generally performed to procedures compliant with ASTM
B31.8, part 192, and inspection is conducted to API-1104 criteria.
2. The Railroad Commission of Texas reported that Texas regulations
are flexible to allow for site-specific decisions.
K.5. Should wellhead valves have emergency shutdowns both primary
and secondary? Should there be integrity and O&M intervals for key
safety and CP systems?
1. INGAA, AGA, and several pipeline operators reported that storage
in salt domes generally requires emergency shutdown systems; these
systems are generally not required for storage in depleted gas fields
or aquifers but may be required depending on local site conditions. The
commenters indicated that testing intervals are set in accordance with
operator procedures and CP testing is based on an operator's local
experience.
2. The Railroad Commission of Texas, the Texas Pipeline
Association, and the Texas Oil & Gas Association reported that Texas'
regulations require emergency shutdown systems and annual drills.
3. The Kansas Department of Health and Environment suggested that
at least
[[Page 20795]]
the primary well should have an emergency shutdown system. KDHE stated
that O&M intervals should be established for key safety systems and
attached a copy of the relevant Kansas regulations to its comments.
4. Northern Natural Gas suggested that emergency shutoffs should
only be required when the well is within 330 feet of a structure
intended for human occupancy. Northern stated that intervals should be
established for O&M activities and CP systems.
5. GPTC and Nicor expressed their opinion that no new regulations
are needed in this area; decisions on emergency shutdown should be made
based on local circumstances.
K.6. What standards are used for emergency shutdowns, emergency
shutdown stations, gas monitors, local emergency response
communications, public communications, and O&M Procedures?
1. AGA, GPTC, and several pipeline operators reported that
operators generally follow DOT regulations, where applicable, and
industry good practices.
2. The NTSB commented that gas storage facility information should
be made available to emergency responders, per its recommendation P-11-
8.
3. The Railroad Commission of Texas, the Texas Pipeline
Association, the Texas Oil & Gas Association, and Atmos reported that
states establish standards in these areas through their regulations.
4. The Kansas Department of Health and Environment reported that
these standards are specified in its regulations, and submitted a copy
of its regulations as an attachment to its comments.
K.7. Does the current lack of Federal standards and preemption
provisions in Federal law preclude effective regulation of underground
storage facilities by States?
1. INGAA, supported by several of its member companies, noted that
jurisdiction over gas storage facilities in interstate pipeline systems
is federal.
2. AGA and several of its pipeline operator members suggested that
federal standards could assure a degree of consistency, and uniform
standards would promote integrity and safety. AGA opined that
implementation of federal standards could be delegated to the states.
3. GPTC and Nicor opined that federal regulations are not needed;
as states are not now precluded from regulating gas storage and many do
so.
4. The Texas Pipeline Association, the Texas Oil & Gas Association,
Atmos, Ameren Illinois, and Northern Natural Gas opined that effective
state regulation is not now precluded. The commenters stated that state
regulation in combination with applicable FERC and DOT requirements has
been demonstrated to assure safety successfully.
5. The Kansas Department of Health and Environment and the Kansas
Corporation Commission noted that state regulation of the safety of
interstate gas storage facilities is currently precluded. When Kansas
attempted to enforce its requirements following an accident at an
interstate storage facility, it was prevented from doing so by a
federal court on the basis of federal preemption. The agencies noted
that lack of action by PHMSA or FERC on interstate gas storage facility
safety precludes states from taking any action and leaves these
facilities essentially unregulated.
K.8. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the
existing regulatory requirements.
No comments were received in response to this question.
Response to All Topic K Comments
Since the publication of the ANPRM and the close of its comment
period, Southern California Gas Company's (SoCal Gas) Aliso Canyon
Natural Gas Storage Facility Well SS25 failed, causing a sustained and
uncontrolled natural gas leak near Los Angeles, California. The
failure, possibly from the downhole well casing, resulted in the
relocation of more than 4,400 families according to the Aliso Canyon
Incident Command briefing report issued on February 1, 2016. On January
6, 2016, California Governor Jerry Brown issued a proclamation
declaring the Aliso Canyon incident a state emergency. On February 5,
2016, PHMSA issued an advisory bulletin in the Federal Register (81 FR
6334) to remind all owners and operators of underground storage
facilities used for the storage of natural gas to consider the overall
integrity of the facilities to ensure the safety of the public and
operating personnel and to protect the environment. The advisory
bulletin specifically reminded these operators to review their
operations and identify the potential of facility leaks and failures,
review the operation of their shut-off and isolation systems, and
maintain updated emergency plans. In addition, PHMSA used the advisory
bulletin to advocate the review of a previous advisory bulletin (97-04)
dated July 10, 1997 and the voluntary implementation of American
Petroleum Institute (API) 1170 ``Design and Operation of Solution-mined
Salt Caverns Used for Natural Gas Storage, First Edition, July 2015,''
API RP 1171 ``Functional Integrity of Natural Gas Storage in Depleted
Hydrocarbon Reservoirs and Aquifer Reservoirs, First Edition, September
2015,'' and Interstate Oil and Gas Compact Commission (IOGCC) standards
entitled ``Natural Gas Storage in Salt Caverns--A Guide for State
Regulators'' (IOGCC Guide), as applicable. PHMSA will consider
proposing a separate rulemaking to address the safety of underground
natural gas storage facilities. Proposing a separate rulemaking that
specifically focuses on improving the safety of underground natural gas
storage facilities will allow PHMSA to fully consider the impacts of
incidents that have occurred since the close of the initial comment
period. It will also allow the Agency to consider voluntary consensus
standards that were developed after the close of the comment period for
this ANPRM, and to solicit feedback from additional stakeholders and
members of the public to inform the development of potential
regulations.
L. Management of Change
The ANPRM requested comments regarding the addition of requirements
for the management of change to provide a greater degree of control
over this element of pipeline risk, particularly following changes to
physical configuration or operational practices. Operation of a
pipeline over an extended period without effective management of
change, such as changes to pipeline systems (e.g., pipeline equipment,
computer equipment or software used to monitor and control the
pipeline) or to practices used to construct, operate, and maintain
those systems, can result in safety issues. Changes can introduce
unintended consequences if the change is not well thought out or is
implemented in a manner not consistent with its design or planning.
Similarly, changes in procedures require people to perform new or
different actions, and failure to train them properly and in a timely
[[Page 20796]]
manner can result in unexpected consequences. The result can be a
situation in which risk or the likelihood of an accident is increased.
A recently completed but poorly-designed modification to the pipeline
system was a factor contributing to the Olympic Pipeline accident in
Bellingham, Washington. The following are general comments received
related to this topic as well as comments related to the specific
questions:
General Comments for Topic L
1. INGAA and several of its pipeline operator members disagreed
with the implication in the ANPRM that change management is not now
addressed in regulations. They pointed out that Sec. 192.911(k) and
ASME/ANSI B31.8S (incorporated by reference) already address this
subject. INGAA reported that its members are committed to clarifying
and expanding the use of a formal ``management of change'' process, and
to facilitating its consistent application as a key management system.
INGAA expressed its belief that the full adoption of ASME/ANSI B31.8S
will facilitate the widespread application of these principles.
Dominion East Ohio Gas also noted that part 192 already contains a
management of change process. In addition, Chevron noted that
management of change programs are generally specific to the
organizational, operational, and ownership structures of the company,
and part 192 already addresses this subject.
2. A private citizen opined that management of change is
necessarily an integral part of quality management systems and another
private citizen supported management of change requirements, noting
that accidents often result from changes to systems. The Alaska
Department of Natural Resources also supported PHMSA's goal of
establishing management of change requirements or guidelines.
Response to General Comments for Topic L
PHMSA appreciates the information provided by the commenters. PHMSA
agrees management of change is currently addressed in Sec. 192.911(k).
However, because of its importance, and consistent with INGAA members'
commitment to expanding use of formal MOC processes, PHMSA believes it
is prudent to provide greater emphasis on MOC directly within the rule
text.
Therefore, PHMSA proposes to clarify integrity management
requirements for management of change by explicitly including aspects
of an effective management of change process into the rule text to
emphasize the current requirements. In addition, PHMSA also proposes to
add a new subsection 192.13(d) that would apply to onshore gas
transmission pipelines, and require that an evaluation must be
performed to evaluate and mitigate, as necessary, the risk to the
public and environment as an integral part of managing pipeline design,
construction, operation, maintenance and integrity, including
management of change. The new paragraph would also articulate the
general requirements for a management of change process, consistent
with Section 192.911(k).
Comments submitted for questions in Topic L.
L.1. Are there standards used by the pipeline industry to guide
management processes including management of change? Do standards
governing the management of change process include requirements for IM
procedures, O&M manuals, facility drawings, emergency response plans
and procedures, and documents required to be maintained for the life of
the pipeline?
1. AGA, supported by several of its members, and several
transmission pipeline operators questioned why this question was in the
ANPRM, noting that management of change requirements are already
promulgated in Sec. 192.911(k). GPTC added that Sec. 192.909 also
addresses this subject.
2. INGAA reported that Section 11 of ASME/ANSI B31.8S is the
industry standard in this area, and all of the considerations in this
question are included in operators' management of change processes.
Several pipeline operators supported this comment.
3. Atmos reported that it is not aware of any standards used by the
industry to guide management of change processes. Atmos does not have a
formal management of change process, except in its integrity management
program, but expressed its conclusion that existing practices within
the company contribute to its ability to manage change.
4. Texas Pipeline Association (TPA) reported that its members do
not have formal management of change processes but comply with
regulations that address proxy requirements (e.g., Sec. 192.911). TPA
expressed its belief that part 192, taken as a whole, includes
management of change requirements to which its members adhere. Texas
Oil & Gas Association supported TPA's comments.
5. California Public Utilities Commission reported that it is
unaware of any pipeline industry standards in this area.
6. An anonymous commenter opined that most operators do not have
management of change processes.
7. The NTSB recommended that PHMSA require operators of natural gas
transmission and distribution pipelines and hazardous liquid pipelines
to ensure that their control room operators immediately notify the
relevant 911 emergency call centers of possible ruptures
(Recommendation P-11-9).
8. TransCanada reported that it is committed to clarifying and
expanding the use of a formal ``management of change'' process.
TransCanada expressed its conclusion that the full adoption of ASME/
ANSI B31.8S will facilitate the widespread application of management of
change principles.
Response to Question L.1 Comments
PHMSA appreciates the information provided by the commenters, which
did not identify any standards beyond ASME/ANSI B31.8S, which is
already invoked by part 192, and used by the pipeline industry to guide
management processes including management of change. See response to
the general comments for Topic L, above.
L.2. Are standards used in other industries (e.g., Occupational
Safety and Health Administration standards at 29 CFR 1910.119)
appropriate for use in the pipeline industry?
1. INGAA reported that Section 11 of ASME/ANSI B31.8S is based on
OSHA's Process Safety Management (PSM) standards. INGAA noted that OSHA
worked with industry in developing PSM standards that would identify
potential threats and assure that mitigative actions were taken.
Several pipeline operators supported INGAA's comments.
2. AGA and GPTC expressed their belief that there is no benefit in
comparing standards with other industries, reiterating that Sec. Sec.
192.909 and 192.911 and ASME/ANSI B31.8S already include management of
change. Several pipeline operators supported AGA's comments.
3. The Texas Pipeline Association and the Texas Oil & Gas
Association reported that their members are aware of standards used in
other industries but do not believe they are appropriate or applicable
to the pipeline industry.
4. The Iowa Association of Municipal Utilities expressed its
conclusion that OSHA standards are complicated and would be unduly
costly for small municipal utilities.
5. Accufacts noted that transportation pipelines are specifically
excluded from OSHA regulation; however, this does not prevent PHMSA
from incorporating elements of 29 CFR 1910.119 into the
[[Page 20797]]
federal pipeline safety regulations in order to mandate a more prudent
pipeline safety culture.
6. Atmos reported that it has no experience with standards used in
other industries but noted that OSHA standards appear to be directed
toward situations where processes interact such that a change in one
process affects a second or third process.
7. Ameren Illinois suggested that standards from other industries
would need to be studied to determine if they are applicable to the
pipeline industry.
8. An anonymous commenter suggested that the OSHA standards are a
good model for pipelines, as they are well written and thought out.
Response to Question L.2 Comments
PHMSA appreciates the information provided by the commenters. See
response to the general comments for Topic L, above.
L.3. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the
existing regulatory requirements.
No comments were received in response to this question.
M. Quality Management Systems (QMS)
The ANPRM requested comments on whether and how to impose
requirements related to quality management systems. Quality management
includes the activities and processes that an organization uses to
achieve quality. These include formulating policy, setting objectives,
planning, quality control, quality assurance, performance monitoring,
and quality improvement.
Achieving quality is critical to gas transmission pipeline design,
construction, and operations. PHMSA recognizes that pipeline operators
strive to achieve quality, but our experience has shown varying degrees
of success in accomplishing this objective among pipeline operators.
PHMSA believes that an ordered and structured approach to quality
management can help pipeline operators achieve a more consistent state
of quality and thus improve pipeline safety.
PHMSA's pipeline safety regulations do not currently address
process management issues such as quality management systems. Section
192.328 requires a quality assurance plan for the construction of
pipelines intended to operate at an alternative MAOP, but there is no
similar requirement applicable to other pipelines. Quality assurance is
generally considered to be an element of quality management. Important
elements of quality management systems are their design and application
to control (1) the equipment and materials used in new construction
(e.g., quality verification of materials used in construction and
replacement, post-installation quality verification), and (2) the
contractor work product used to construct, operate, and maintain the
pipeline system (e.g., contractor qualifications, verification of the
quality of contractor work products).
The ANPRM then listed questions for consideration and comment. The
following are general comments received related to this topic as well
as comments related to the specific questions:
General Comments for Topic M
1. MidAmerican suggested that PHMSA work with the committees for
ASME/ANSI B31.8 and B31.8S to address these topics more fully, if PHMSA
believes more is needed. MidAmerican opined that a general rule
addressing quality management systems would divert resources and
adversely affect safety, if applied to this already heavily-regulated
industry.
2. The Alaska Department of Natural Resources supported quality
management systems and suggested that pipeline operators should apply
such standards to their contractors.
3. A private citizen supported quality management systems, noting
that this is an area that would be difficult to regulate but might be
an element in incentive programs.
Comments submitted for questions in Topic M.
M.1. What standards and practices are used within the pipeline
industry to assure quality? Do gas transmission pipeline operators have
formal QMS?
1. INGAA opined that achieving consistent quality materials,
construction and management is an appropriate focus for the INGAA
Foundation, which has sponsored and will continue to sponsor workshops
on this subject. INGAA reported that the Foundation plans to publish
five relevant White Papers in 2012 and its Integrity Management--
Continuous Improvement team is currently working on guidelines. INGAA
also noted that there are elements of a quality management system in
ASME/ANSI B31.8S, already incorporated by reference, including quality
assurance/quality control, management of change, communication and
performance measurement, Standards, specifications, and procedures
governing pipe and appurtenances form part of a pipeline quality
management system. INGAA cited ISO (9001:2008/29001:2010) and API (Spec
Q1) quality management standards as references that are available for
operator use. INGAA further noted that API published Spec Q2 in
December 2011. Several pipeline operators supported INGAA's comments.
2. AGA, GPTC, Nicor, Atmos, the Texas Pipeline Association, and the
Texas Oil & Gas Association suggested that part 192, taken as a whole,
is essentially a quality management system. AGA provided a summary
listing of part 192 requirements that assure quality. A number of
additional pipeline operators supported AGA's comments.
3. Ameren Illinois reported that it has a quality assurance program
for pipeline construction that includes building alliances with
excavators and other elements.
4. Paiute and Southwest Gas reported that their practices beyond
compliance with part 192 requirements include operator qualification
(OQ) for construction, an internal quality assurance group, root cause
analysis of events, and quality control verification of OQ.
5. MidAmerican reported that it has no formal quality management
system but applies standards to assure quality processes. In
particular, ASME/ANSI B31.8 and B31.8S and ANSI/ISO/ASQ Q9004-2000 were
used to guide its company quality programs. MidAmerican also has a
contractor oversight program.
6. An anonymous commenter opined that most operators have a quality
management system, often incorporated into their SCADA system, to
satisfy customers or end user requirements. The commenter suggested
that some of these systems have only recently been modified to address
internal corrosion mechanisms, often identified as part of operators'
integrity management programs.
M.2. Should PHMSA establish requirements for QMS? If so, why? If
so, should these requirements apply to all gas transmission pipelines
and to the complete life cycle of a pipeline system?
[[Page 20798]]
1. INGAA, supported by a number of its pipeline operator members,
asserted that no new requirements are appropriate at this time. INGAA
noted that much work is ongoing in this area and it may be appropriate
to adopt some standards (e.g., API Q1 or Q2) in the future.
2. AGA, GPTC, the Texas Pipeline Association, the Texas Oil & Gas
Association, Oleksa and Associates, and numerous pipeline operators
expressed an opinion that new quality assurance requirements are not
needed. These commenters view part 192 as quality assurance
requirements and argue that a new programmatic requirement would not be
beneficial.
3. TransCanada opined that quality management systems need to be
adopted throughout the entire industry and embraced by operators and
contractors alike, arguing that this would provide a more consistent
level of quality throughout the industry. TransCanada opined that the
INGAA Foundation is the appropriate venue in which to develop
guidelines.
4. Northern Natural Gas opined that the existing process, which
includes PHMSA/State inspections, is adequate.
5. A private citizen commented that quality management systems
should be required to improve pipeline safety, including documentation,
investigations, validation, audits/inspections, change management,
training, and quality/management oversight.
6. An anonymous commenter opined that no new requirements are
needed, arguing that most operators have such systems.
M.3. Do gas transmission pipeline operators require their
construction contractors to maintain and use formal QMS? Are contractor
personnel that construct new or replacement pipelines and related
facilities already required to read and understand the specifications
and to participate in skills training prior to performing the work?
1. INGAA reported that most of its members apply quality management
principles, including requiring contractors conform to specified
requirements, though the approach varies from operator to operator.
INGAA acknowledged, however, that ``[t]here is room to establish a more
structured approach to QMS for operators and construction contractors''
to assure more consistency. A number of pipeline operators supported
INGAA's comments.
2. AGA reported that transmission operators have the means to
assure contractor work quality and that most LDC operators impose
operator qualification (OQ) and other specific requirements on their
construction contractors.
3. The Texas Pipeline Association and the Texas Oil & Gas
Association encouraged PHMSA not to adopt requirements for operators to
train construction personnel. The associations expressed concerns over
potential liability and their preference for a performance-based
standard.
4. Ameren Illinois, Atmos, and MidAmerican reported that they apply
operator qualification (OQ) requirements on their contractors.
5. Northern Natural Gas, Paiute, and Southwest Gas reported that
they do not require contractors to have formal QMS but do require
conformance to various standards.
6. Oleksa and Associates reported its experience that operators
require construction contractors to meet the same standards as their
employees.
7. GPTC, Nicor, and an anonymous commenter suggested that
compliance with construction regulations contribute to QMS through
requirements for specifications and inspections.
8. NAPSR, the Texas Pipeline Association, and the Texas Oil & Gas
Association suggested that operator qualification (OQ) requirements be
applied to construction, since this would apply formal QMS to the full
range of construction and operation.
M.4. Are there any standards that exist that PHMSA could adopt or
from which PHMSA could adapt concepts for QMS?
1. INGAA and a number of pipeline operators suggested that several
standards could be used as general references, including ISO 9001:2008
(Quality Management Systems), ISO 29001:2010 (Oil and Gas) and API Spec
Q1 (Oil and Gas). INGAA opined that compliance with these standards
should not be required, and added that additional standards, white
papers, and guidance are under development.
2. The AGA, GPTC, Nicor, and Ameren Illinois opposed new
requirements in this area. AGA opined that part 192 is already
``saturated'' with this type of requirement. A number of additional
pipeline operators supported AGA's comments.
3. The NTSB recommended improvement to PHMSA's drug and alcohol
requirements, citing their recommendations P-11-12 & 13.
4. A private citizen suggested that, by extrapolating from the
practices of a pipeline operator with a good safety record. The
commenter stated that useful references include the Baldrige
Performance Excellence Program and Quality Management Standard ISO
9000.
M.5. What has been the impact on cost and safety in other
industries in which requirements for a QMS have been mandated?
1. INGAA reported that quality management systems have been
demonstrated to reduce risk and opined that the keys to a successful
QMS are simplicity, empowerment, accountability and ease of
implementation. A number of pipeline operators supported INGAA's
comments.
M.6. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the
existing regulatory requirements.
No comments were received in response to this question.
Response to All Topic M Comments
PHMSA appreciates the information provided by the commenters. PHMSA
does not propose additional rulemaking for this topic at this time.
PHMSA will review the comments received on the ANPRM and will consider
them in future rulemaking.
N. Exemption of Facilities Installed Prior to the Regulations
The ANPRM requested comments regarding proposed changes to part 192
regulations that would eliminate provisions that exempt pipelines from
pressure test requirements to establish MAOP. Federal pipeline safety
regulations were first established with the initial publication of part
192 on August 19, 1970 (35 FR 13248). Gas transmission pipelines had
existed for many years prior to this, some dating to as early as 1920.
Many of these older pipelines had operated safely for years at
pressures higher than would have been allowed under the new
regulations. It was concluded that a required reduction in the
operating pressure of these pipelines would not have resulted in a
material increase in safety. Therefore, a provision was included in the
regulations (Sec. 192.619(c)) that allowed pipelines to
[[Page 20799]]
operate at the highest actual operating pressure to which they were
subjected during the 5 years prior to July 1, 1970. The safe operation
of these pipelines at these pressures was deemed to be evidence that
operation could safely continue.
Many gas transmission pipelines continue to operate in the United
States under an MAOP established in accordance with Sec. 192.619(c).
Some of these pipelines operate at stress levels higher than 72 percent
specified minimum yield strength (SMYS), the highest level generally
allowed for more modern gas transmission pipelines. Some pipelines
operate at greater than 80 percent SMYS, the alternate MAOP allowed for
some pipelines by regulations adopted October 17, 2008 (72 FR 62148).
Under these regulations, operators who seek to operate their pipelines
at up to 80 percent SMYS (in Class 1 locations) voluntarily accept
significant additional requirements applicable to design, construction,
and operation of their pipeline that are intended to assure quality and
safety at these higher operating stresses. Pipelines that operate under
an MAOP established in accordance with Sec. 192.619(c) are subject to
none of these additional requirements.
Part 192 also includes several provisions other than establishment
of MAOP for which an accommodation was made in the initial part 192.
These provisions allowed pipeline operators to use steel pipe that had
been manufactured before 1970 and did not meet all requirements
applicable to pipe manufactured after part 192 became effective
(192.55); valves, fittings and components that did not contain all the
markings required (192.63); and pipe which had not been transported
under the standard included in the new part 192 (192.65, subject to
additional testing requirements).
The ANPRM then listed questions for consideration and comment. The
following are general comments received related to this topic as well
as comments related to the specific questions:
General Comments for Topic N
1. INGAA and a number of pipeline operators opined that age alone
is not an appropriate criterion for determining a pipeline's fitness
for service. Old pipe that is well maintained operates safely and unfit
pipe should be replaced regardless of age. INGAA suggested that fitness
for service of pipe in HCAs should be evaluated using available
records, if adequate, or through new testing. INGAA attached a white
paper to its comments that described its Fitness for Service protocol.
INGAA also cautioned that any requirement to reconfirm MAOP should be
subject to a rigorous cost-benefit analysis, as hydrostatic testing is
very expensive and could require outages of up to several weeks.
2. A private citizen suggested phasing out sub-standard or systems
that pre-date regulatory requirements where public safety is concerned,
implying that this has been done in other areas (citing elimination of
radium dial watches and leaking underground storage tanks as examples).
3. A private citizen suggested that legacy facilities should be
subject to a timetable to come into full compliance with current
regulations, arguing that this would improve safety and knowledge of
older facilities.
Response to General Comments for Topic N
PHMSA appreciates the information provided by the commenters. NTSB
recommended that regulatory exemptions be repealed. In addition,
section 23 of the Act addressed gas transmission pipelines without
records sufficient to validate MAOP. In response to these concerns,
this NPRM proposes requirements for verification of maximum allowable
operating pressure (MAOP) in new Sec. 192.624 for onshore, steel, gas
transmission pipelines that are located in an HCA or MCA and meet any
of the conditions in Sec. 192.624(a)(1) through (a)(3). Verification
of MAOP includes establishing and documenting MAOP if the pipeline MAOP
was established in accordance with Sec. 192.619(c), the grandfather
clause. In addition, this NPRM proposes requirements for verification
of pipeline material in accordance with new Sec. 192.607 for existing
onshore, steel, gas transmission pipelines that are located in an HCA
or class 3 or class 4 locations.
Comments Submitted for Questions in Topic N
N.1. Should PHMSA repeal provisions in part 192 that allow use of
materials manufactured prior to 1970 and that do not otherwise meet all
requirements in part 192?
1. INGAA, supported by several pipeline operators, suggested age,
alone, should not be a criterion for determining fitness for service,
noting some pre-regulation materials (e.g., seamless pipe) are as good
as today's.
2. AGA, GPTC, and numerous pipeline operators noted it is illogical
to storehouse pre-1970 materials for installation now. AGA indicated
that it thus did not understand the purpose of the ANPRM question.
3. Iowa Utilities Board, NAPSR, Texas Pipeline Association, Texas
Oil & Gas Association, Accufacts, Alaska Department of Natural
Resources, Atmos, Commissioners of Wyoming County Pennsylvania,
Professional Engineers in California Government, and an anonymous
commenter encouraged repeal of this allowance. Some of these commenters
would allow a specified time period for operators to come into
compliance.
4. Thomas Lael and MidAmerican recommended operators be allowed to
continue use of materials that have already been placed into service,
arguing that they have been demonstrated safe through integrity
management.
5. Ameren Illinois and Northern Natural Gas opposed repeal of this
provision.
Response to Question N.1 Comments
PHMSA appreciates the information provided by the commenters. As
stated above, this NPRM proposes requirements for verification of MAOP
in new Sec. 192.624 for onshore, steel, gas transmission pipelines
that are located in an HCA or MCA and meet any of the conditions in
Sec. 192.624(a)(1) through (a)(3). In addition, this NPRM proposes
requirements for verification of pipeline material in accordance with
new Sec. 192.607 for existing onshore, steel, gas transmission
pipelines that are located in an HCA or class 3 or class 4 locations.
N.2. Should PHMSA repeal the MAOP exemption for pre-1970 pipelines?
Should pre-1970 pipelines that operate above 72% SMYS be allowed to
continue to be operated at these levels without increased safety
evaluations such as periodic pressure tests, in-line inspections,
coating examination, CP surveys, and expanded requirements on
interference currents and depth of cover maintenance?
1. INGAA and a number of pipeline operators opposed repeal of this
exemption. INGAA suggested its Fitness for Service protocol be used to
assure continued safety of old pipe.
2. AGA, GPTC, Texas Pipeline Association, Texas Oil & Gas
Association and numerous pipeline operators commented that the wording
of this question creates a false impression. There is no exemption for
MAOP. Rather, the regulations establish requirements for determining
MAOP and the only ``exemption'' is to a post-construction hydrostatic
test, since the pipeline was in service at the time the regulations
became effective.
3. AGA, supported by several of its pipeline operator members,
contended the appropriate method for verifying
[[Page 20800]]
MAOP of older pipelines is for PHMSA to follow Section 23 of the
Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011.
AGA opposed eliminating Sec. 192.619(c) for determining MAOP of older
pipelines, arguing that it would cripple the nation's gas pipeline
capacity. A number of additional pipeline operators joined AGA in
opposing any new requirement to pressure test all older pipelines,
arguing costs would be excessive and there would be significant
potential to interrupt gas services. AGA included a white paper with
its comments outlining its suggested approach to MAOP verification.
4. Accufacts, Texas Pipeline Association, and Texas Oil & Gas
Association opposed requiring all pre-1970 pipelines to reduce MAOP, if
necessary, to a pressure that would impose stresses no greater than 72
percent SMYS. Accufacts noted this pipe is still safe at its current
operating pressure if it is managed properly, but suggested a possible
focus on interactive threats that might make seam welds unstable.
5. Ameren Illinois opposed modifying MAOP requirements for pre-1970
pipelines.
6. NAPSR, the NTSB, and Professional Engineers in California
Government supported repeal of exemptions applying to MAOP of pre-1970
pipelines. NAPSR added PHMSA should not allow any pipeline to operate
at pressures above that which would impose stresses greater than 72
percent SMYS.
7. MidAmerican suggested use of a performance-based approach, which
might include a fitness for service determination for pipe in Class 2,
3, or 4 areas or HCA.
8. Commissioners of Wyoming County Pennsylvania would support
repeal of MAOP exemptions because pipeline infrastructure is aging and
they see additional safety measures needed.
Response to Question N.2 Comments
PHMSA appreciates the information provided by the commenters. As
stated above, this NPRM proposes requirements for verification of MAOP
in new Sec. 192.624 for onshore, steel, gas transmission pipelines
that are located in an HCA or MCA and meet any of the conditions in
Sec. 192.624(a)(1) through (a)(3). Verification of MAOP includes
establishing and documenting MAOP if the pipeline segment: (1) Has
experienced a reportable in-service incident, as defined in Sec.
191.3, since its most recent successful subpart J pressure test, due to
an original manufacturing-related defect, a construction-,
installation-, or fabrication-related defect, or a cracking-related
defect, including, but not limited to, seam cracking, girth weld
cracking, selective seam weld corrosion, hard spot, or stress corrosion
cracking and the pipeline segment is located in one of the following
locations: (i) A high consequence area as defined in Sec. 192.903;
(ii) a class 3 or class 4 location; or (iii) a moderate consequence
area as defined in Sec. 192.3 if the pipe segment can accommodate
inspection by means of instrumented inline inspection tools (i.e.,
``smart pigs''); (2) Pressure test records necessary to establish
maximum allowable operating pressure per subpart J for the pipeline
segment, including, but not limited to, records required by Sec.
192.517(a), are not reliable, traceable, verifiable, and complete and
the pipeline segment is located in one of the following locations: (i)
A high consequence area as defined in Sec. 192.903; or (ii) a class 3
or class 4 location; or (3) the pipeline segment maximum allowable
operating pressure was established in accordance with Sec. 192.619(c)
of this subpart before [effective date of rule] and is located in one
of the following areas:
(i) A high consequence area as defined in Sec. 192.903; (ii) a
class 3 or class 4 location; or (iii) a moderate consequence area as
defined in Sec. 192.3 if the pipe segment can accommodate inspection
by means of instrumented inline inspection tools (i.e., ``smart
pigs'').
N.3. Should PHMSA take any other actions with respect to exempt
pipelines? Should pipelines that have not been pressure tested in
accordance with subpart J be required to be pressure tested in
accordance with present regulations?
1. AGA and a number of pipeline operators opposed any requirement
to pressure test all pipelines that have not been tested in accordance
with subpart J, arguing Congress considered and rejected this approach
in developing the Pipeline Safety, Regulatory Certainty, and Job
Creation Act of 2011. The commenters argue such a requirement would
cripple the pipeline industry and support the alternative requirements
included in the Act.
2. MidAmerican suggests a focus on pipe in Class 3 or 4 areas or
HCAs. The company suggests no new requirements are needed if records
are complete for pipe in these areas or it has been tested to 1.25
times MAOP. Otherwise, MidAmerican would subject such pipelines to a
fitness for service determination.
3. The NTSB would require all pre-1970 pipelines to be pressure
tested, including a spike test, citing their recommendation P-11-14.
4. Texas Pipeline Association and Texas Oil & Gas Association
opposed a requirement to test all pipelines not previously subject to
subpart J tests, arguing testing per the construction codes in effect
when the pipelines were constructed and safe operating experience since
then is adequate assurance of suitability.
5. Ameren Illinois reported the State of Illinois imposed pressure
testing requirements before federal pipeline safety regulations were
adopted in 1970.
6. Iowa Utilities Board and Iowa Association of Municipal Utilities
recommended any new pressure test requirement be limited to pipeline
segments in HCA and which operate at pressures where a rupture could
occur (generally greater than 30 percent SMYS). These commenters argued
the serious impacts of service interruptions pressure testing would be
necessary for testing have not been appreciated and the cost for such
testing of other pipelines would be unjustified absent any specific
demonstration of risk.
7. Commissioners of Wyoming County Pennsylvania and Professional
Engineers in California Government (PECG) would require pressure
testing for pipelines not previously tested to subpart J requirements,
since this would assure public safety. PECG would also require testing
if adequate records of prior tests do not exist, noting California has
experienced two failures to date of pipeline not adequately tested.
PECG would also require all testing, modification, and replacement be
observed by a certified inspector loyal to public safety interests.
8. An anonymous commenter would require subpart J testing but would
allow schedule flexibility.
Response to Question N.3 Comments
PHMSA appreciates the information provided by the commenters. This
NPRM proposes requirements for verification of MAOP in new Sec.
192.624 for onshore, steel, gas transmission pipelines that are located
in an HCA or MCA and meet any of the conditions in Sec. 192.624(a)(1)
through (a)(3). Verification of MAOP includes establishing and
documenting MAOP using one or more of the methods in 192.624(c)(1)
through (c)(6). In addition, this NPRM proposes requirements for
verification of pipeline material in new Sec. 192.607 for existing
onshore, steel, gas transmission pipelines that are located in an HCA
or class 3 or class 4 locations.
N.4. If a pipeline has pipe with a vintage history of systemic
integrity issues in areas such as longitudinal
[[Page 20801]]
weld seams or steel quality, and has not been pressure tested at or
above 1.1 times MAOP or class location test criteria (Sec. Sec.
192.505, 192.619 and 192.620), should this pipeline be required to be
pressure tested in accordance with present regulations?
1. AGA and several pipeline operators opposed requiring hydrostatic
tests for systemic issues, arguing it could potentially affect all
pipelines. AGA noted Congress had considered and rejected this approach
in developing the Pipeline Safety, Regulatory Certainty, and Job
Creation Act of 2011. AGA supports the requirements in Section 23 of
the Act. AGA further argued hold times in subpart J are excessive since
defects that fail will likely do so in the first 30 minutes and urged
PHMSA not to require any special testing for pipelines operating at
less than 30 percent SMYS since they are likely to fail by leakage
rather than rupture.
2. GPTC and Nicor opposed a blanket requirement for hydrostatic
testing. They would test only in event of a demonstrated safety issue
and only if a risk evaluation indicates testing is appropriate. For
distribution operators, these commenters would treat any safety issues
in distribution integrity management programs.
3. Atmos would not require pressure testing for systemic issues,
arguing these are addressed adequately by subpart O.
4. Accufacts would require testing, focusing first on pipe in HCAs,
at pressures greater than 1.1 times MAOP. Accufacts understands some
operators are arguing for a 1.1 x MAOP test pressure and considers that
to be insufficient.
5. MidAmerican would allow a risk-based alternative approach for
problem pipe.
6. Texas Pipeline Association and Texas Oil & Gas Association would
require assessments appropriate to a specific threat rather than a
blanket requirement for pressure testing.
7. An anonymous commenter supported pressure testing for pipe
subject to systemic issues.
Response to Question N.4 Comments
PHMSA appreciates the information provided by the commenters. This
NPRM proposes requirements for verification of MAOP in new Sec.
192.624 for onshore, steel, gas transmission pipelines that are located
in an HCA or MCA and meet any of the conditions in Sec. 192.624(a)(1)
through (a)(3).
N.5. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the
existing regulatory requirements.
No comments were received in response to this question.
O. Modifying the Regulation of Gas Gathering Lines
The ANPRM requested comments regarding modifying the regulations
relative to gas gathering lines. In March 2006, PHMSA issued new safety
requirements for ``regulated onshore gathering lines.'' \38\ Those
requirements established a new method for determining if a pipeline is
an onshore gathering line, divided regulated onshore gas gathering
lines into two risk-based categories (Type A and Type B), and subjected
such lines to certain safety standards.
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\38\ 71 FR 13289 (March 15, 2006).
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The 2006 rule defined onshore gas gathering lines based on the
provisions in American Petroleum Institute Recommended Practice 80,
``Guidelines for the Definition of Onshore Gas Gathering Lines,'' (API
RP 80), a consensus industry standard incorporated by reference.
Additional regulatory requirements for determining the beginning and
endpoints of gathering, modifying the application of API RP 80, were
also imposed to improve clarity and consistency in their application.
In practice, however, the use of API RP 80, even as modified by the
additional regulations, is difficult for operators to apply
consistently to complex gathering system configurations. Enforcement of
the current requirements has been hampered by the conflicting and
ambiguous language of API RP 80, a complex standard that can produce
multiple classifications for the same pipeline system, which can lead
to the potential misapplication of the incidental gathering line
designation under that standard. In addition, recent developments in
the field of gas exploration and production, such as shale gas,
indicate that the existing framework for regulating gas gathering lines
may need to be expanded. Gathering lines are being constructed to
transport ``shale'' gas that range from 4 to 36 inches in diameter with
MAOPs up to 1480 psig, far exceeding the historical operating
parameters (pressure and diameter). The risks considered during the
development of the 2006 rule did not foresee gathering lines of these
diameters and pressures.
Currently, according to 2011 annual reports submitted by pipeline
operators, PHMSA only regulates about 8845 miles of Type A gathering
lines, 5178 miles of Type B gathering lines, and about 6258 miles of
offshore gathering lines, for a total of approximately 20,281 miles of
regulated gas gathering pipelines. Gas gathering lines are currently
not regulated if they are in Class 1 locations. Current estimates also
indicate that there are approximately 132,500 miles of Type A gas
gathering lines located in Class 1 areas (of which approximately 61,000
miles are estimated to be 8-inch diameter or greater), and
approximately 106,000 miles of Type B gas gathering lines located in
Class 1 areas. Also, there are approximately 2,300 miles of Type B gas
gathering lines located in Class 2 areas, some of which may not be
regulated in accordance with Sec. 192.8(b)(2).
The ANPRM then listed questions for consideration and comment. The
following are general comments received related to this topic as well
as comments related to the specific questions:
General Comments for Topic O
1. Gas Processors Association (GPA) recommended PHMSA complete the
study required by Section 21 of the Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011 before proposing any
substantive regulations regarding gathering lines. The Association sees
this as an essential pre-requisite and indicated it would establish a
working group to work with PHMSA on the study. Following the study, GPA
would then have PHMSA begin any rulemaking process with another ANPRM,
focused on the issues to be addressed in changing regulation of
gathering lines. Independent Petroleum Association of America, American
Petroleum Institute, Oklahoma Independent Petroleum Association, and
Chevron agreed any change to gathering line regulations before the
required report to Congress would be inconsistent with the Act.
2. Independent Petroleum Association of America, American Petroleum
Institute, Oklahoma Independent Petroleum Association, and Chevron
argued no change in the gathering line regulatory regime is justified.
IPAA and API argued gathering lines can be regulated based only on
actual, vs.
[[Page 20802]]
speculative, risk, and that any change without such demonstrated risk
would be arbitrary, capricious, and contrary to law.
3. Atmos would require new gathering lines operating above 20
percent SMYS to meet requirements in Sec. 192.9(c), and those below 20
percent SMYS Sec. 192.9(d). These paragraphs are, respectively,
requirements applicable to Type A and Type B gathering lines. The
``type'' of a gathering line is established in accordance with
requirements in Sec. 192.8, and is based on the pipe material and MAOP
of the line. Atmos argued, however, that class location changes over
time and determining applicable requirements for new gathering lines
based on stress levels would provide for public safety without the
problems or confusion that could result from subsequent class location
changes.
4. Texas Pipeline Association and Texas Oil & Gas Association
suggested PHMSA treat gathering lines under a separate docket and
collect data under the current regulatory regime before making any
changes. The associations suggested a delay in rulemaking of 3 to 5
years to accumulate data from recently-promulgated changes in reporting
requirements. The associations argued changes made without gathering
and reviewing that data could be found unnecessary and would divert
resources from higher risk needs. Atmos agreed any rulemaking
concerning gathering lines should be conducted under a separate docket
due to the complexity of the issues involved.
5. Dominion East Ohio Gas argued it is too soon for wholesale
changes to the new federal regulations applicable to gas gathering
lines. The company suggested one proposed change would be to consider
``Incidental Gathering'' as defined in API RP 80.
6. NAPSR and Commissioners of Wyoming County Pennsylvania suggested
PHMSA assert regulatory authority beginning at the wellhead or first
metering point. They argued the regulatory gap that results from
excluding production facilities from regulation produces risks,
especially in areas where high-pressure wells are being drilled in
urban areas. NAPSR further stated that PHMSA should consider short
sections of pipeline downstream of processing, compression, and similar
equipment to be a continuation of gathering. The functional name of a
segment of pipeline is not important, i.e., production, gathering,
transmission. All pipelines should be treated the same in terms of
safety from the well head to the city gate.
7. Commissioners of Wyoming County Pennsylvania recommended PHMSA
regulate gathering lines in Class 1 areas. The Commissioners noted many
new gathering lines, some operating at high pressures, are being
constructed in Class 1 areas of the Marcellus Shale Region, and
regulation of these lines is necessary to ensure public safety. The
Commissioners noted Pennsylvania law gives the state's public utilities
commission authority to regulate pipelines but requires that they be no
more stringent than federal regulations.
8. The League of Women Voters of Pennsylvania would regulate
gathering lines in the same manner as transmission and would further
require that gas in pipelines of both types be odorized.
9. Pipeline Safety Trust would have PHMSA assure gathering lines
are displayed on the National Pipeline Mapping System.
Response to General Comments for Topic O
PHMSA appreciates the information provided by the commenters. The
commenters are correct that the Act required several actions related to
gas gathering lines including a requirement that a study to be
conducted prior to issuing new rules. We would note, however, that
PHMSA is only proceeding with the issuance of an NPRM proposing
expanded requirements and needed clarity with regard to issues that had
been identified prior to enactment of the Act. The study has been
completed and submitted to Congress and placed on the docket. PHMSA
invites public comment on the study, which will inform the final rule.
In addition, recent developments in the field of gas exploration and
production, such as shale gas, indicate that the existing framework for
regulating gas gathering lines may need to be expanded. Gathering lines
are being constructed to transport ``shale'' gas that range from 4 to
36 inches in diameter with MAOPs up to 1,480 psig, far exceeding the
historical operating parameters of such lines.
Currently, according to 2011 annual reports submitted by pipeline
operators, PHMSA only regulates about 8845 miles of Type A gathering
lines, 5,178 miles of Type B gathering lines, and about 6,258 miles of
offshore gathering lines, for a total of approximately 20,281 miles of
regulated gas gathering pipelines. Gas gathering lines are currently
not regulated if they are in Class 1 locations. Current estimates also
indicate that there are approximately 132,500 miles of Type A gas
gathering lines located in Class 1 areas, and approximately 106,000
miles of Type B gas gathering lines located in Class 1 areas. Also,
there are approximately 2,300 miles of Type B gas gathering lines
located in Class 2 areas, some of which may not be regulated in
accordance with Sec. 192.8(b)(2).
Moreover, enforcement of the current requirements has been hampered
by the conflicting and ambiguous language of API RP 80, a complex
standard that can produce multiple classifications for the same
pipeline system because numerous factors are involved, including the
locations of treatment facilities, processing plants, and compressors,
the relative spacing of production fields, and the commingling of gas.
This can lead to the potential misapplication of the incidental
gathering line designation under that standard.
In this NPRM, PHMSA proposes to extend existing requirements for
Type B gathering lines to Type A gathering lines in Class 1 locations,
if the nominal diameter is 8'' or greater.
Comments submitted for questions in Topic O.
O.1. Should PHMSA amend 49 CFR part 191 to require the submission
of annual, incident, and safety-related conditions reports by the
operators of all gathering lines?
1. AGA, GPTC, Texas Pipeline Association, Texas Oil & Gas
Association, and several pipeline operators opposed requiring annual
reports for unregulated gas gathering pipelines, arguing such a
requirement would be unduly burdensome with no safety benefit. These
commenters agreed incident reports for unregulated gathering lines
could be useful as a means to determine the effectiveness of safety
practices on these pipelines.
2. Gas Producers Association opposed expanding reporting
requirements to Class 1 gathering pipelines. The Association noted
gathering lines in other class locations are currently subject to
reporting requirements and suggested there were other means for PHMSA
to collect data on Class 1 lines without requiring burdensome
reporting. In the specific case of safety-related condition reports,
the Association argued requiring reporting is clearly premature,
because the purpose of these reports is to highlight problems in which
PHMSA may elect to become involved and PHMSA presently does not
regulate these pipelines.
3. Texas Pipeline Association and Texas Oil & Gas Association would
support requiring incidents to be reported for all gathering pipelines
as a first step in collecting data to determine whether other changes
are needed.
[[Page 20803]]
4. Atmos would support limited reporting for Class 1 gathering
lines, to include incidents and total mileage.
5. NAPSR, Alaska Department of Natural Resources, Pipeline Safety
Trust, and Commissioners of Wyoming County Pennsylvania would require
operators of Class 1 gathering pipelines to submit reports, because
these pipelines can affect public safety and should be held
accountable.
Response to Question O.1 Comments
PHMSA appreciates the information provided by the commenters. The
comments provide varied support for requiring submission of annual,
incident, and safety-related conditions reports by the operators of all
gathering lines. PHMSA believes these reports would provide valuable
information, combined with the results of the congressionally required
study, to support evaluation of the effectiveness of safety practices
on these pipelines and determination of any needed additional
requirements beyond those proposed in this NPRM. Accordingly, PHMSA
proposes to delete the exemption for reporting requirements for
operators of unregulated onshore gas gathering lines.
O.2. Should PHMSA amend 49 CFR part 192 to include a new definition
for the term ``gathering line''?
1. AGA and several pipeline operators opposed a change to the
definition of gathering lines, noting API RP-80, with restrictions as
specified in current regulations, is a good working definition.
2. Independent Petroleum Association of America, American Petroleum
Institute, Oklahoma Independent Petroleum Association, Atmos, and
Chevron argued that API RP 80, as currently specified, is the
appropriate means for defining gathering lines. They argued it is based
on a pipeline's function rather than its location and changes could
infringe on production facilities, regulation of which is precluded by
statute.
3. Gas Processors Association opposed changing the definition of
gathering line or extending regulation to lines in Class 1 areas. The
Association noted excluding Class 1 lines from regulation is risk-based
and expressed its interest in continuing the risk-based approach to
regulation represented by the 2006 rule.
4. NAPSR, GPTC, Accufacts, Thomas Lael, and Nicor supported
simplifying the definition of gathering lines. These commenters noted
that API RP-80 is confusing. One commenter referred to its application
as a ``nightmare.'' The definition in Texas regulations was suggested
as one possible model.
5. Oklahoma Independent Petroleum Association strongly opposed
changes to the definitions of gathering line or production facilities.
6. Texas Pipeline Association and Texas Oil & Gas Association would
not change the definition of gathering lines at this time, arguing data
gathering, a necessary first step, is not yet complete.
7. The State of Washington Citizens Advisory Committee and a
private citizen urged changes to the definitions of gathering,
transmission, and distribution pipelines, arguing that the current
definitions are confusing and employ circular logic.
8. Pipeline Safety Trust would revise the definition of gathering
in a manner that does not allow operators to choose whether their
pipeline is gathering or not on the basis of where they decide to
install equipment. PST noted there is significant overlap among
pipeline types in size, operating pressure, and attendant risks.
9. Alaska Department of Natural Resources and Commissioners of
Wyoming County Pennsylvania urged a revision to the definition of
gathering lines, in light of shale gas development which, the
commenters contended, produces risks approximately equivalent to those
from transmission pipelines.
Response to Question O.2 Comments
PHMSA appreciates the information provided by the commenters.
Industry commenters opposed a change to the definition of gathering
lines, whereas NAPSR and other commenters supported revision of the
definition of gathering lines and classified API RP-80 as confusing. As
discussed above, PHMSA believes revision of the definition of gathering
lines is needed and also proposes a new definition for onshore
production facility/operation. In addition, see response to question
O.3 comments.
O.3. Are there any difficulties in applying the definitions
contained in RP 80? If so, please explain.
1. Independent Petroleum Association of America, American Petroleum
Institute, Oklahoma Independent Petroleum Association, and Chevron were
emphatic in declaring there are no difficulties in applying API RP-80.
IPAA and API noted that significant difficulties among gathering lines
made RP-80 difficult to develop.
2. AGA and a number of pipeline operators reported RP-80 is clear
and there are no difficulties with its application.
3. Gas Processors Association would retain the RP-80 definition, at
least until the study required by the Act is completed. GPA
acknowledged that application of RP-80 has been difficult, but stated
that it has been difficult to craft a simpler definition.
4. Texas Pipeline Association and Texas Oil & Gas Association
reported application of RP-80 has been challenging. The associations
opined this has resulted from complexities in gathering pipeline
systems and confusion caused by PHMSA guidance and interpretations.
5. Accufacts, NAPSR, GPTC, and Nicor commented RP-80 is too
complex, not understandable to the public, and subject to misuse by
operators.
Response to Question O.3 Comments
PHMSA appreciates the information provided by the commenters.
Industry commenters stated there are no difficulties in applying the
definitions contained in API RP 80, whereas Accufacts, NAPSR and other
commenters contend that API RP 80 is too complex, not understandable,
and subject to misuse. PHMSA enforcement of the current requirements
has been hampered by the conflicting and ambiguous language of API RP
80, which is complex and can produce multiple classifications for the
same pipeline system. In the 2006 rulemaking which incorporated by
reference the API RP 80, PHMSA expressed reservations concerning the
ability to effectively and consistently apply the document as written,
echoing NAPSR's comments at the time. Additionally, in 2006, PHMSA
imposed limiting regulatory language in part 192 in an attempt to
curtail the potential for misapplication of the language contained in
RP-80. These limitations and their intended application were discussed
in great detail in the Supplemental Notice of Proposed Rulemaking
[Docket No. RSPA-1998-4868; Notice 5]. Because of the ambiguous
language and terminology in the RP-80, e.g. separators are defined for
both production and gathering almost verbatim, experience has shown
that facilities are being classified as production much further
downstream than was ever intended. The application of ``incidental
gathering'' as used in API RP-80 has not been applied as intended in
some cases. Several recent interpretations letters have been issued by
PHMSA on this topic including an expressed intent to clarify the issue
in future rulemaking. Therefore, PHMSA believes revision of the
definition of gathering lines is needed and proposes
[[Page 20804]]
deleting the use of API RP 80 as the basis for determining regulated
gathering lines and would establish the new definition for onshore
production facility/operation and a revised definition for gathering
line as the basis for determining the beginning and endpoints of each
gathering line.
O.4. Should PHMSA consider establishing a new, risk-based regime of
safety requirements for large-diameter, high-pressure gas gathering
lines in rural locations? If so, what requirements should be imposed?
1. Commissioners of Wyoming County Pennsylvania and 24 private
citizens encouraged PHMSA to regulate gathering lines in Class 1
locations. The commenters noted many such pipelines will exist in shale
gas areas, many of them large-diameter and operating at high pressures,
and contended these pipelines currently are being ignored by federal
and state regulators. They noted the pipeline that ruptured causing the
San Bruno accident was operated at a pressure considerably lower than
some gathering lines in shale gas areas.
2. AGA, GPTC, and a number of pipeline operators argued no new
requirements are needed and the effectiveness of the 2006 changes to
regulation needs to be reviewed first, in accordance with the Act.
3. Gas Processors Association, Texas Pipeline Association, and
Texas Oil & Gas Association contended PHMSA must gather additional data
on Class 1 gathering lines before deciding whether to regulate them,
arguing that only a detailed study can determine whether new
regulations are appropriate.
4. Oklahoma Independent Petroleum Association cautioned any
regulatory change needs to be supported by science and a comprehensive
cost-benefit analysis.
5. Independent Petroleum Association of America, American Petroleum
Institute, Oklahoma Independent Petroleum Association, and Chevron
argued any change in the regulatory regime for gathering lines is
unjustified. The commenters contended such lines only operate at high
pressures when new, that pressure decreases as wells deplete, and that
the record shows these lines are safe.
6. A private citizen who operates an outdoor gear supply business
in a shale gas region argued reduced use of recreational areas, caused
by concerns over nearby pipelines, will adversely impact his and
similar businesses.
7. Alaska Department of Natural Resources would establish risk-
based safety requirements for gathering pipelines.
8. NAPSR would establish new, prescriptive requirements for large-
diameter, high-pressure gathering lines.
9. Pipeline Safety Trust argued the composition of gas carried in
many gathering lines leads to increased risk of corrosion and
additional corrosion and testing requirements should thus be
considered.
10. A private citizen, arguing for regulation of Class 1 gathering
lines, noted experience has shown Class 1 locations change to Class 2
or 3 locations while the pipeline remains unchanged and, the commenter
contended, unsafe.
11. Pipeline Safety Trust, Accufacts, and NAPSR would regulate
gathering lines the same as transmission pipelines. PST would include
integrity management requirements for lines operating at greater than
20 percent SMYS. NAPSR would impose IM if greater than 30 percent SMYS.
12. ITT Exelis Geospatial Systems contended that safety criteria
applicable to a pipeline should be based on the specifications of the
line.
Response to Question O.4 Comments
PHMSA appreciates the information provided by the commenters. The
comments provide varied opinions for establishing new, risk-based
safety requirements for gas gathering lines in rural locations. Several
comments recommended PHMSA gather additional data on gathering lines
before deciding to issue revised regulations. PHMSA believes rulemaking
should proceed now to address the identified issues with regulation of
gathering lines. Therefore, PHMSA proposes to extend existing
requirements for Type B gathering lines to Type A gathering lines in
Class 1 locations, if the nominal diameter is 8'' or greater. Integrity
management requirements would not be applied to gathering lines at this
time.
O.5. Should PHMSA consider short sections of pipeline downstream of
processing, compression, and similar equipment to be a continuation of
gathering? If so, what are the appropriate risk factors that should be
considered in defining the scope of that limitation (e.g., doesn't
leave the operator's property, not longer than 1000 feet, crosses no
public rights of way)?
1. The AGA, the GPTC, and a number of pipeline operators suggested
that the piping mentioned in O.5 be considered as gathering. The
commenters contended that this is clearly ``incidental gathering'' in
API RP-80, particularly if below 20 percent SMYS, and that some
agencies are presently treating this pipeline inappropriately as
transmission pipeline.
2. Oleksa and Associates contended that the types of pipeline
described in the question are ``incidental gathering.'' Oleksa argued
that the length of these pipeline sections should not be the
determining factor in their definition but, rather, risk elements and
public safety impact should be afforded more importance.
3. The Gas Processors Association, the Texas Pipeline Association,
and the Texas Oil & Gas Association would continue to treat these types
of pipelines as gathering. They argued that this reflects the practical
realities in the field regarding the ability to locate gathering-
related equipment. GPA urged PHMSA to retain the concept of incidental
gathering in any future change to the regulations, arguing this would
continue a consistent regulatory approach to gathering pipelines.
4. The Independent Petroleum Association of America, the American
Petroleum Institute, the Oklahoma Independent Petroleum Association,
and Chevron contended that the safety record in the Barnett Shale area
demonstrates further regulation of downstream pipelines and compression
is not needed.
5. Commissioners of Wyoming County Pennsylvania would treat
gathering lines as transmission lines, arguing that this would preclude
the need to answer any of these questions.
6. The Delaware Solid Waste Authority (DSWA) argued for the
continued treatment of the listed pipeline sections as part of
gathering for landfill gas operations. DSWA noted that landfills may
use intermediate compression to improve collection efficiency and may
have pipe at pressure leading to flares etc.
7. Waste Management contended that piping that is an active part of
a landfill gas collection and control system should be exempt from
regulation as this piping is generally on landfill property and poses
no risk to the public.
8. The National Solid Waste Management Association and Waste
Management supported PHMSA's interpretation that pipelines operating at
vacuum, such as landfill systems up to the compressor/blower should be
unregulated.
Response to Question O.5 Comments
PHMSA appreciates the information provided by the commenters. See
PHMSA's response to Question O.3, above.
O.6. Should PHMSA consider adopting specific requirements for
pipelines associated with landfill gas
[[Page 20805]]
systems? If so, what regulations should be adopted and why? Should
PHMSA consider adding regulations to address the risks associated with
landfill gas that contains higher concentrations of hydrogen sulfide
and/or carbon dioxide?
1. The AGA, the GPTC, and a number of pipeline operators contended
that RP-80 makes clear that these pipelines are production piping and
therefore regulation is prohibited. In addition, they argued that risk
doesn't justify regulating these lines; the situation is similar to
production and is already managed well. They also noted that landfill
systems are generally constructed with non-corrosive materials. The
commenters agreed that piping from landfills to transmission or
distribution pipelines is gathering and should be regulated.
2. Oleksa and Associates contended that landfill pipelines are
distribution pipelines, if they carry gas to end use customers.
3. The APGA argued that new requirements are appropriate, as
landfill gas is different from natural gas. The APGA contended that
application of current regulations often produces absurd results. APGA
would add new requirements applicable to systems with high
concentrations of hydrogen sulfide and allow systems with low
concentrations to use current requirements.
4. The Delaware Solid Waste Authority argued that no new
requirements are needed, because these systems operate at low pressures
and existing requirements are sufficient.
5. NAPSR encouraged that PHMSA establish jurisdiction over and
requirements for landfill gas systems, arguing that many operate as
distribution pipelines. NAPSR also recommended that PHMSA develop
requirements for odorizing landfill gas, since normal methods cannot be
used.
6. The National Solid Waste Management Association and Waste
Management argued that landfill gas lines under the control of a
landfill operator or gas developer should remain unregulated because
they pose minimal risk. They also contended that lines delivering
landfill gas to distant users should also remain unregulated because
they are mostly buried, are generally constructed of plastic pipe, and
pose low risk due to low pressure, their dedicated nature, and lack of
interconnects.
7. The National Solid Waste Management Association (NSWMA) noted
that these pipelines are already regulated by the EPA and the states
and argued that additional regulation would confer limited additional
benefits. NSWMA argued that no requirements are needed to address
internal corrosion, because these pipeline systems are generally
constructed of plastic pipe and corrosive gas constituents are limited
to prevent destruction of gas processing equipment. NSWMA suggested
that PHMSA work with the EPA to obtain data on the landfill experience
needed to support any future decision to regulate in this area.
8. Oleksa and Associates and the Delaware Solid Waste Authority
would have PHMSA modify the regulations to clarify that pipe downstream
of intermediate compression is unregulated, even if at pressure. They
argued that the EPA has regulated such pipelines successfully and there
is no safety case for applying part 192. DSWA further notes that most
landfill pipeline is constructed of plastic pipe and not subject to
internal corrosion.
9. Oleksa and Associates, the GPTC, Nicor, Waste Management, and
the Delaware Solid Waste Authority would exempt landfill gas systems
from requirements for odorization and odor sampling. They argued that
there is a strong odor inherent to landfill gas, the sampling of which
is not practical.
Response to Question O.6 Comments
PHMSA appreciates the information provided by the commenters. PHMSA
is not proposing rulemaking to address landfill gas systems at this
time, but would note that a pipeline that transports landfill gas away
from the landfill facility to another destination is transporting gas.
PHMSA will consider comments on this aspect of Topic O in the future.
O.7. Internal corrosion is an elevated threat to gathering systems
due to the composition of the gas transported. Should PHMSA enhance its
requirements for internal corrosion control for gathering pipelines?
Should this include required cleaning on a periodic basis?
1. AGA, GPTC, and a number of pipeline operators commented that new
requirements are not needed. They argued existing part 192 requirements
are adequate for internal corrosion protection and unregulated
gathering lines are rural and pose little risk.
2. AGA and a number of pipeline operators opposed a requirement for
periodic cleaning of gathering lines. They noted existing lines are not
configured to accommodate cleaning pigs and retrofitting them would be
a major cost with no safety benefit.
3. Gas Producers Association noted internal corrosion is only one
of many threats, existing regulations are adequate, and thus no new
requirements are needed.
4. Texas Pipeline Association and Texas Oil & Gas Association
opposed establishing internal corrosion requirements for gathering
pipelines. The associations noted risk from IC is not prevalent for
many gathering pipelines and suggested the need to collect data (e.g.,
incidents) to determine whether new requirements are needed.
5. Accufacts would require, as a minimum, use of cleaning pigs and
analysis of removed materials.
6. NAPSR, Alaska Department of Natural Resources, and Commissioners
of Wyoming County Pennsylvania would enhance internal corrosion
requirements and require periodic cleaning.
Response to Question O.7 Comments
PHMSA appreciates the information provided by the commenters. The
majority of comments do not support enhancement of requirements for
internal corrosion control for gathering pipelines. PHMSA is not
proposing rulemaking specifically to address the need for additional
internal corrosion requirements for gathering lines at this time.
However, the proposed requirements in subpart I applicable to
transmission lines; except the requirements in Sec. Sec. 192.461(f),
192.465(f), 192.473(c) and 192.478, would be applicable to regulated
Type A onshore gathering lines.
O.8. Should PHMSA apply its Gas Integrity Management Requirements
to onshore gas gathering lines? If so, to what extent should those
regulations be applied and why?
1. The AGA and several pipeline operators suggested that PHMSA
consider applying some IM requirements to Type A gathering lines, since
these lines represent conditions and risks similar to transmission
pipelines. They consider IM inappropriate for Type B gathering lines,
since these lines pose low risk and operate at hoop stresses similar to
distribution pipelines.
2. The Gas Producers Association, the Texas Pipeline Association,
the Texas Oil & Gas Association, and Atmos argued that it would be
inappropriate to apply integrity management requirements to gathering
pipelines. They noted that IM is a risk-based approach and that there
is no evidence that gathering pipelines pose a risk that justifies
application of IM.
3. The GPTC and Nicor opined that extending some aspects of gas
transmission IM to non-rural, metallic
[[Page 20806]]
Type A gathering lines could provide enhanced protection to the public,
since the operation and risk of these pipelines is similar to
transmission pipelines. They cautioned, however, that the costs to
impose IM on gathering pipelines would be significant. They considered
IM inappropriate for Type B gathering lines since these lines are, by
definition, of lower pressure and lower risk.
4. The Commissioners of Wyoming County Pennsylvania would apply IM
to all onshore gathering pipelines. They would also apply requirements
applicable to Class 2 transmission pipelines to Class 1 gathering
pipelines, arguing that Class 1 areas will grow and class location will
change.
5. Accufacts and the Alaska Department of Natural Resources would
apply IM to gathering lines. Accufacts suggested an initial focus on
large-diameter, high-pressure lines, since these lines are subject to
failure by rupture.
Response to Question O.8 Comments
PHMSA appreciates the information provided by the commenters. PHMSA
does not propose rulemaking to apply integrity management requirements
to gathering lines at this time.
O.9. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the
existing regulatory requirements.
No comments were received in response to this question.
IV. Other Proposals
Inspection of Pipelines Following Extreme Weather Events.
Pipeline regulation prescribes requirements for the surveillance
and periodic patrolling of the pipeline to observe surface conditions
on and adjacent to the transmission line right-of-way for indications
of leaks, construction activity, and other factors affecting safety and
operation, including unusual operating and maintenance conditions. The
probable cause of the 2011 hazardous liquid pipeline accident resulting
in a crude oil spill into the Yellowstone River near Laurel, Montana,
is scouring at a river crossing due to flooding. This is a recent
example of extreme weather that resulted in a pipeline incident. PHMSA
has determined that additional regulations are needed to require, and
establish standards for, the inspection of the pipeline and right-of-
way for ``other factors affecting safety and operation'' following an
extreme weather event such as a hurricane or flood, landslide, an
earthquake, a natural disaster, or other similar event. The proposed
rule would add a new paragraph (c) to section 192.613 to require such
inspections, specify the timeframe in which such inspections should
commence, and specify the appropriate remedial actions that must be
taken to ensure safe pipeline operations. The new paragraph (c) would
apply to onshore pipelines and their rights-of-way.
Notification for 7-Year Reassessment Interval Extension.
Section 5 of the Act identifies a technical correction amending
Section 60109(c)(3)(B) of Title 49 of the United States Code to allow
the Secretary of Transportation to extend the 7-year reassessment
interval for an additional 6 months if the operator submits written
notice to the Secretary justifying the need for the extension. PHMSA
proposes to codify this statutory requirement.
Reporting Exceedances of Maximum Allowable Operating Pressure.
Section 23 of the Act requires operators to report each exceedance
of the maximum allowable operating pressure (MAOP) that exceeds the
margin (build-up) allowed for operation of pressure-limiting or control
devices. PHMSA proposes to codify this statutory requirement.
Consideration of Seismicity.
Section 29 of the Act states that in identifying and evaluating all
potential threats to each pipeline segment, an operator of a pipeline
facility must consider the seismicity of the area. PHMSA proposes to
codify this statutory requirement to explicitly reference seismicity
for data gathering and integration, threat identification, and
implementation of preventive and mitigative measures.
Safety Features for In-line Inspection (ILI), Scraper, and Sphere
Facilities.
PHMSA is proposing to add explicit requirements for safety features
on launchers and receivers associated with ILI, scraper and sphere
facilities.
Consensus Standards for Pipeline Assessments.
PHMSA is proposing to incorporate by reference consensus standards
for assessing the physical condition of in-service pipelines using in-
line inspection, internal corrosion direct assessment, and stress
corrosion cracking direct assessment.
V. Section-by-Section Analysis
Sec. 191.1 Scope.
Section 191.1 prescribes requirements for the reporting of
incidents, safety-related conditions, and annual pipeline summary data
by operators of gas pipeline facilities. Currently, onshore gas
gathering pipelines are exempt from reporting, as specified in
paragraph (b)(4) of this section. In March 2012, the Government
Accountability Office (GAO) issued a report (GAO-12-388) that contained
a recommendation for DOT to collect data on federally unregulated
hazardous liquid and gas gathering pipelines. PHMSA has determined that
the statute requires the collection of additional information about
gathering lines and that these reports and the congressionally required
study support evaluation of the effectiveness of safety practices on
these pipelines. Furthermore, PHMSA has inquired into whether any
additional requirements are needed beyond those proposed in this NPRM.
Accordingly, the proposed rule would repeal the exemption for reporting
requirements for operators of unregulated onshore gas gathering lines
by deleting Sec. 191.1(b)(4), adding a new Sec. 191.1(c), and making
other conforming editorial amendments. In addition, Section 23 of the
Act requires PHMSA to promulgate rules that require operators to report
each exceedance of the maximum allowable operating pressure (MAOP) that
exceeds the margin (build-up) allowed for operation of pressure-
limiting or control devices. The proposed rule would amend 191.1 to
include MAOP exceedances within the scope of part 191.
Sec. 191.23 Reporting safety-related conditions.
Section 23 of the Act requires operators to report each exceedance
of the maximum allowable operating pressure (MAOP) that exceeds the
margin (build-up) allowed for operation of pressure-limiting or control
devices. On December 21, 2012, PHMSA published advisory bulletin ADB-
2012-11, which advised operators of their responsibility under Section
23 of the Act to report such exceedances. PHMSA proposes to revise
Sec. 191.23 to codify this requirement.
Sec. 191.25 Filing safety-related condition reports.
Section 23 of the Act requires operators to report each exceedance
of the maximum allowable operating pressure (MAOP) that exceeds the
[[Page 20807]]
margin (build-up) allowed for operation of pressure-limiting or control
devices. As described above, PHMSA proposes to revise Sec. 191.23 to
codify this requirement. Section 191.25 would also be revised to
provide consistent procedure, format, and structure for filing of such
reports by all operators.
Sec. 192.3 Definitions.
Section 192.3 provides definitions for various terms used
throughout part 192. In support of other regulations proposed in this
NPRM, PHMSA is proposing to amend the definitions of ``Electrical
survey,'' ``(Onshore) gathering line,'' and ``Transmission line,'' and
add new definitions for ``Close interval survey,'' ``Distribution
center, '' ``Dry gas or dry natural gas,'' ``Gas processing plant,''
``Gas treatment facility,'' ``Hard spot,'' ``In-line inspection
(ILI),'' ``In-line inspection tool or instrumented internal inspection
device,'' ``Legacy construction technique,'' ``Legacy pipe,''
``Moderate consequence area,'' ``Modern pipe,'' ``Occupied site,''
``Onshore production facility or onshore production operation,''
``Significant Seam Cracking,'' ``Significant Stress Corrosion
Cracking,'' and ``Wrinkle bend.'' These changes will define these terms
as used in the proposed changes to part 192. Many of the terms (such as
in-line inspection, dry gas, hard spot, etc.) clarify technical
definitions of terms used in part 192 or proposed in this rulemaking.
The revised definition for ``(Onshore) gathering line,'' and the
new definitions for ``Gas processing plant,'' ``Gas treatment
facility,'' and ``Onshore production facility or onshore production
operation,'' are necessary because of ambiguous language and
terminology in the current definition of regulated gas gathering lines,
which invoke by reference API RP-80. The application of ``incidental
gathering'' as used in API RP-80 has not been applied as intended in
some cases. Several recent interpretation letters have been issued by
PHMSA on this topic including an expressed intent to clarify the issue
in future rulemaking. Therefore, PHMSA believes revision of the
definition of gathering lines is needed and proposes repealing the use
of API RP 80 as the basis for determining regulated gathering lines and
would establish the new definition for ``onshore production facility/
operation, gas treatment facility, and gas processing plant,'' and a
revised definition for ``(onshore) gathering line'' as the basis for
determining the beginning and endpoints of each gathering line.
The revised definition for ``Electrical survey'' aligns with the
amended definition recommended in a petition dated March 26, 2012, from
the Gas Piping Technology Committee (GPTC).
With regard to the new terms ``moderate consequence area'' or MCA,
and ``occupied site,'' the definitions are based on the same
methodology as ``high consequence area'' and ``identified site'' as
defined in Sec. 192.903. Moderate consequence areas will be used to
define the subset of non-HCA locations where integrity assessments are
required (Sec. 192.710), where material documentation verification is
required (Sec. 192.607), and where MAOP verification is required
(Sec. Sec. 192.619(e) and 192.624). The criteria for determining MCA
locations would use the same process and same definitions that are
currently used to identify HCAs, except that the threshold for
buildings intended for human occupancy and the threshold for persons
that occupy other defined sites located within the potential impact
radius would both be lowered from 20 to 5. This approach is proposed as
a means to minimize the effort needed on the part of operators to
identify the MCAs, since transmission operators must have already
performed the analysis in order to have identified the HCAs or to
verify that they have no HCAs. In response to NTSB recommendation P-14-
01, which was issued as a result of the Sissonville, West Virginia
incident, the MCA definition would also include locations where
interstate highways, freeways, and expressways, and other principal 4-
lane arterial roadways are located within the potential impact radius.
With regard to the new terms ``legacy construction technique'' and
``legacy pipe,'' the definitions are used in proposed and Sec. 192.624
to identify pipe to which the proposed material verification and MAOP
verification requirements would apply. The definitions are based on
historical technical issues associated with past pipeline failures.
Sec. 192.5 Class locations.
Section 23 of the Act requires the Secretary of Transportation to
require verification of records used to establish MAOP to ensure they
accurately reflect the physical and operational characteristics of
certain pipelines and to confirm the established MAOP of the pipelines.
PHMSA has determined that an important aspect of compliance with this
requirement is to assure that pipeline class location records are
complete and accurate. The proposed rule would add a new paragraph
Sec. 192.5(d) to require each operator of transmission pipelines to
make and retain for the life of the pipeline records documenting class
locations and demonstrating how an operator determined class locations
in accordance with this section.
Sec. 192.7 What documents are incorporated by reference partly or
wholly in this part?
Section 192.7 lists documents that are incorporated by reference in
part 192. PHMSA proposes conforming amendments to Sec. 192.7 in the
rule text to reflect other changes proposed in this NPRM.
Sec. 192.8 How are onshore gathering lines and regulated onshore
gathering lines determined?
Section 192.8 defines the upstream and downstream endpoints of gas
gathering pipelines. Recent developments in the field of gas
exploration and production, such as shale gas, indicate that the
existing framework for regulating gas gathering lines may no longer be
appropriate. Gathering lines are being constructed to transport
``shale'' gas that range from 4 to 36 inches in diameter with MAOPs of
up to 1480 psig, far exceeding the historical operating parameters of
such lines.
Currently, according to the 2011 annual reports submitted by
pipeline operators, PHMSA only regulates about 8,845 miles of Type A
gathering lines, 5,178 miles of Type B gathering lines, and about 6,258
miles of offshore gathering lines, for a total of approximately 20,281
miles of regulated gas gathering pipelines. Gas gathering lines are
currently not regulated if they are in Class 1 locations. Current
estimates also indicate that there are approximately 132,500 miles of
Type A gas gathering lines located in Class 1 areas (of which
approximately 61,000 miles are estimated to be 8-inch diameter or
greater), and approximately 106,000 miles of Type B gas gathering lines
located in Class 1 areas. Also, there are approximately 2,300 miles of
Type B gas gathering lines located in Class 2 areas, some of which may
not be regulated in accordance with Sec. 192.8(b)(2).
Moreover, enforcement of the current requirements has been hampered
by the conflicting and ambiguous language of API RP 80, a complex
standard that can produce multiple classifications for the same
pipeline system. PHMSA has also identified a regulatory gap that
permits the potential misapplication of the incidental gathering line
designation under that standard. Consequently, to address these issues
and gaps, the proposed rule would repeal the use of API RP 80 as the
basis for determining regulated gathering lines and would establish a
new definition for onshore production facility/operation and a
[[Page 20808]]
revised definition for gathering line as the basis for determining the
beginning and endpoints of each gathering line. The definition of
onshore production facility/operation includes initial preparation of
gas for transportation at the production facility, including
separation, lifting, stabilizing, and dehydration. Pipelines commonly
referred to as ``farm taps'' serving residential/commercial customers
or industrial customers are not classified as gathering, but would
continue to be classified as transmission or distribution as defined in
Sec. 192.3.
Sec. 192.9 What requirements apply to gathering lines?
Section 192.9 identifies those portions of part 192 that apply to
regulated gas gathering lines. For the same reasons discussed under
Sec. 192.8, above, the proposed rule would expand and clarify the
requirements that apply to gathering lines. PHMSA proposes to extend
existing regulatory requirements for Type B gathering lines to Type A
gathering lines in Class 1 locations, if the nominal diameter of the
line is 8'' or greater.
In addition, on August 20, 2014, the GAO released a report (GAO
Report 14-667) to address the increased risk posed by new gathering
pipeline construction in shale development areas. GAO recommended that
a rulemaking be pursued for gathering pipeline safety that addresses
the risks of larger-diameter, higher-pressure gathering pipelines,
including subjecting such pipelines to emergency response planning
requirements that currently do not apply. Currently, Type A gathering
lines are subject to the emergency planning requirements in Sec.
192.615 and only include gathering lines in Class 2, 3, and 4 locations
that have a Maximum Allowable Operating Pressure (MAOP) with a hoop
stress of 20% or more for metallic pipe and MAOP of more than 125 psig
for non-metallic pipe. Further, gathering lines that are located in
Class 1 areas (e.g., rural areas) are not considered Type A gathering
lines even if they meet the pressure criteria specified in the
preceding sentence. PHMSA is proposing to create sub-divisions of Type
A gathering lines (Type A, Area 1 and Type A, Area 2). The new
designation ``Type A, Area 1 gathering lines'' would apply to currently
regulated Type A gathering lines. The new designation ``Type A, Area 2
gathering lines'' would apply to gathering lines with a diameter of 8-
inch or greater that meet all of the qualifying parameters for
currently regulated Type A gathering, but are located in Class 1
locations. PHMSA proposes to address the GAO recommendation by
requiring the newly proposed Type A, Area 2 regulated onshore gathering
lines, which include lines in Class 1 locations with a nominal diameter
of 8-inch or greater, to develop procedures, training, notifications,
and carry out emergency plans as described in Sec. 192.615, in
addition to a limited set of other specific requirements, including
corrosion protection and damage prevention.
Sec. 192.13 General.
Section 192.13 prescribes general requirements for gas pipelines.
PHMSA has determined that safety and environmental protection would be
improved by generally requiring operators to evaluate and mitigate
risks during all phases of the useful life of a pipeline as an integral
part of managing pipeline design, construction, operation, maintenance
and integrity, including management of change. This proposed rule would
add a new paragraph (d) to establish a general clause requiring onshore
gas transmission pipeline operators to evaluate and mitigate risks to
the public and environment as part of managing pipeline design,
construction, operation, maintenance, and integrity, including
management of change. The new paragraph would also invoke the
requirements for management of change as outlined in ASME/ANSI B31.8S,
section 11, and explicitly articulate the requirements for a management
of change process that are applicable to onshore gas transmission
pipelines.
Section 23 of the Act requires the Secretary of Transportation to
require verification of records used to establish MAOP to ensure they
accurately reflect the physical and operational characteristics of
certain pipelines and to confirm the established MAOP of the pipelines.
PHMSA has determined that an important aspect of compliance with this
requirement is to assure that records that demonstrate compliance with
part 192 are complete and accurate. The proposed rule would add a new
paragraph (e) that clearly articulates the requirements for records
preparation and retention and requires that records be reliable,
traceable, verifiable, and complete. Further, the proposed Appendix A
would provide specific requirements for records retention for
transmission pipelines.
In addition, conforming amendments to paragraphs (a) and (b) list
the effective date of the proposed requirements for newly regulated
onshore gathering lines.
Sec. 192.67 Records: Materials.
Section 23 of the Act requires the Secretary of Transportation to
require verification of records used to establish MAOP to ensure they
accurately reflect the physical and operational characteristics of
certain pipelines and to confirm the established MAOP of the pipelines.
PHMSA has determined that compliance requires that pipeline material
records are complete and accurate. The proposed rule would add a new
Sec. 192.67 to require each operator of transmission pipelines to make
and retain for the life of the pipeline the original steel pipe
manufacturing records that document tests, inspections, and attributes
required by the manufacturing specification in effect at the time the
pipe was manufactured.
Sec. 192.127 Records: Pipe design.
Section 23 of the Act requires the Secretary of Transportation to
require verification of records used to establish MAOP to ensure they
accurately reflect the physical and operational characteristics of
certain pipelines and to confirm the established MAOP of the pipelines.
PHMSA has determined that compliance requires that pipe design records
are complete and accurate. The proposed rule would add a new Sec.
192.127 to require each operator of transmission pipelines to make and
retain for the life of the pipeline records documenting pipe design to
withstand anticipated external pressures and determination of design
pressure for steel pipe.
Sec. 192.150 Passage of internal inspection devices.
The current pipeline safety regulations in 49 CFR 192.150 require
that pipelines be designed and constructed to accommodate in-line
inspection devices. Part 192 is silent on technical standards or
guidelines for implementing requirements to assure pipelines are
designed and constructed for ILI assessments. At the time these rules
were promulgated, there was no consensus industry standard that
addressed design and construction requirements for ILI. NACE Standard
Practice, NACE SP0102-2010, ``In-line Inspection of Pipelines,'' has
since been published and provides guidance in this area in Section 7.
The incorporation of this standard into Sec. 192.150 will promote a
higher level of safety by establishing consistent standards for the
design and construction of line pipe to accommodate ILI devices.
Sec. 192.205 Records: Pipeline components.
Section 23 of the Act requires the Secretary of Transportation to
require verification of records used to establish MAOP to ensure they
accurately reflect the physical and operational characteristics of
certain pipelines and to confirm the established MAOP of the pipelines.
PHMSA has determined that compliance requires that pipeline component
records are complete and
[[Page 20809]]
accurate. The proposed rule would add a new Sec. 192.205 to require
each operator of transmission pipelines to make and retain records
documenting manufacturing and testing information for valves and other
pipeline components.
Sec. 192.227 Qualification of welders.
Section 23 of the Act requires the Secretary of Transportation to
require verification of records used to establish MAOP to ensure they
accurately reflect the physical and operational characteristics of
certain pipelines and to confirm the established MAOP of the pipelines.
PHMSA has determined that compliance requires that pipeline welding
records are complete and accurate. The proposed rule would add a new
paragraph Sec. 192.227(c) to require each operator of transmission
pipelines to make and retain for the life of the pipeline records
demonstrating each individual welder qualification in accordance with
this section.
Sec. 192.285 Plastic pipe: Qualifying persons to make joints.
Section 23 of the Act requires the Secretary of Transportation to
require verification of records used to establish MAOP to ensure they
accurately reflect the physical and operational characteristics of
certain pipelines and to confirm the established MAOP of the pipelines.
PHMSA has determined that compliance requires that pipeline
qualification records are complete and accurate. The proposed rule
would add a new paragraph Sec. 192.285(e) to require each operator of
transmission pipelines to make and retain for the life of the pipeline
records demonstrating plastic pipe joining qualifications in accordance
with this section.
Sec. 192.319 Installation of pipe in a ditch.
Section 192.319 prescribes requirements for installing pipe in a
ditch, including requirements to protect pipe coating from damage
during the process. However, during handling, lowering, and
backfilling, sometimes pipe coating is damaged, which can compromise
its ability to protect against external corrosion. An example of the
consequences of such damage occurred in 2011 on the Bison Pipeline,
operated by TransCanada Northern Border Pipeline, Inc. In this case,
the probable cause of the incident was attributed to latent coating and
mechanical damage caused during construction, which subsequently caused
the pipeline to fail. To help prevent recurrence of such incidents,
PHMSA has determined that additional requirements are needed to verify
that pipeline coating systems for protection against external corrosion
are not damaged during the installation and backfill process.
Accordingly, this proposed rule would add a new paragraph (d) to
require that onshore gas transmission operators perform an above-ground
indirect assessment to identify locations of suspected damage promptly
after backfill is completed and remediate any moderate or severe
coating damage. Mechanical damage is also detectable by these indirect
assessment methods, since the forces that are able to mechanically
damage steel pipe usually result in detectable coating defects.
Paragraph (d) does not apply to gas gathering lines or distribution
mains. In addition, paragraph (d) would require each operator of
transmission pipelines to make and retain for the life of the pipeline
records documenting the coating assessment findings and repairs.
Sec. 192.452 How does this subpart apply to converted pipelines
and regulated onshore gathering lines?
Section 192.452 prescribes corrosion control requirements for
regulated onshore gathering lines. PHMSA proposes conforming amendments
to the rule text in paragraph (b) to reflect other changes proposed in
this NPRM for gas gathering lines.
Sec. 192.461 External corrosion control: Protective coating.
Section 192.461 prescribes requirements for protective coating
systems. However, certain types of coating systems that have been used
extensively in the pipeline industry can impede the process of cathodic
protection if the coating disbonds from the pipe. The NTSB determined
that this was a significant contributing factor in the major crude oil
spill that occurred near Marshall, Michigan, in 2010. PHMSA has
determined that additional requirements are needed to specify that
coating should not impede cathodic protection and to ensure operators
verify that pipeline coating systems for protection against external
corrosion have not become compromised or damaged during the
installation and backfill process. Accordingly, this proposed rule
would amend paragraph (a)(4) to require that coating have sufficient
strength to resist damage during installation and backfill, and add a
new paragraph (f) to require that onshore gas transmission operators
perform an above-ground indirect assessment to identify locations of
suspected damage promptly after backfill is completed or anytime there
is an indication that the coating might be compromised. It would also
require prompt remediation of any moderate or severe coating damage.
Sec. 192.465 External corrosion control: Monitoring.
Section 192.465 currently prescribes that operators monitor
cathodic protection and take prompt remedial action to correct
deficiencies indicated by the monitoring. The provisions in Sec.
192.465 do not specify the remedial actions required to correct
deficiencies and do not define ``prompt.'' To address this potential
issue, the proposed rule would amend paragraph (d) to require that
remedial action must be completed promptly, but no later than the next
monitoring interval specified in Sec. 192.465 or within one year,
whichever is less. In addition, a new paragraph (f) is added to require
onshore gas transmission operators to perform close-interval surveys if
annual test station readings indicate cathodic protection is below the
level of protection required in subpart I. Unless it is impractical to
do so, close interval surveys must be completed with the protective
current interrupted. Impracticality must be based on a technical
reason, for example, a pipeline protected by direct buried sacrificial
anodes (anodes directly connected to the pipeline), and not on cost
impact. The proposed rule would also require each operator to take
remedial action to correct any deficiencies indicated by the
monitoring.
Sec. 192.473 External corrosion control: Interference currents.
Interference currents can negate the effectiveness of cathodic
protection systems. Section 192.473 prescribes general requirements to
minimize the detrimental effects of interference currents. However,
specific requirements to monitor and mitigate detrimental interference
currents have not been prescribed in subpart I. In 2003, PHMSA issued
advisory bulletin ADB-03-06 (68 FR 64189). The bulletin advised each
operator of a natural gas transmission or hazardous liquid pipeline to
determine whether new steel pipelines are susceptible to detrimental
effects from stray electrical currents. Based on this evaluation, an
operator should carefully monitor and take action to mitigate
detrimental effects. The operator should give special attention to a
new pipeline's physical location, particularly where that location may
subject the new pipeline to stray currents from other underground
facilities, including other pipelines or induced currents from
electrical transmission lines, whether aboveground or underground.
Operators were strongly encouraged to review their corrosion control
programs and to have qualified corrosion personnel present during
construction to identify, mitigate, and monitor any detrimental stray
currents that might damage new
[[Page 20810]]
pipelines. Since the advisory bulletin, PHMSA continues to identify
cases where significant pipeline defects are attributed to corrosion
caused by interference currents. Examples include CenterPoint Energy's
CP line (2007), Keystone Pipeline (2012) and Overland Pass Pipeline
(2012). Therefore, PHMSA has determined that additional requirements
are needed to explicitly require that operators conduct interference
surveys and to timely remediate adverse conditions. The proposed rule
would add new paragraph (c) to require that onshore gas transmission
operator programs include interference surveys to detect the presence
of interference currents and to require taking remedial actions
promptly after completion of the survey to adequately protect the
pipeline segment from detrimental interference currents, but no later
than 6 months in any case.
Sec. 192.478 Internal corrosion control: Monitoring.
Section 192.477 prescribes requirements to monitor internal
corrosion if corrosive gas is being transported. However, the existing
rules do not prescribe that operators continually or periodically
monitor the gas stream for the introduction of corrosive constituents
through system changes, changing gas supply, upset conditions, or other
changes. This could result in pipelines that are not monitored for
internal corrosion, because an initial assessment did not identify the
presence of corrosive gas. In September 2000, following the Carlsbad
explosion, PHMSA issued Advisory Bulletin 00-02, dated 9/1/2000 (65 FR
53803). The bulletin advised owners and operators of natural gas
transmission pipelines to review their internal corrosion monitoring
programs and consider factors that influence the formation of internal
corrosion, including gas quality and operating parameters. Pipeline
operators continue to report incidents attributed to internal
corrosion. Between 2002 and November 2012, 206 incidents have been
reported that were attributed to internal corrosion. PHMSA has
determined that additional requirements are needed to assure that
operators effectively monitor gas stream quality to identify if and
when corrosive gas is being transported and to mitigate deleterious gas
stream constituents (e.g., contaminants or liquids). The proposed rule
would add the new section 192.478 to require monitoring for deleterious
gas stream constituents for onshore gas transmission operators, and
require that gas monitoring data be evaluated quarterly. In addition,
the proposed rule would add a requirement for onshore gas transmission
operators to review the internal corrosion monitoring and mitigation
program semi-annually and adjust the program as necessary to mitigate
the presence of deleterious gas stream constituents. This is in
addition to existing requirements to check coupons or other means to
monitor for the actual presence of internal corrosion in the case of
transporting a known corrosive gas stream.
Sec. 192.485 Remedial measures: Transmission lines.
Section 192.485 prescribes requirements for remedial measures to
address general corrosion and localized corrosion pitting in
transmission lines. For such conditions it specifies that the strength
of pipe based on actual remaining wall thickness may be determined by
the procedure in ASME/ANSI B31G or the procedure in AGA Pipeline
Research Committee Project PR 3-805 (RSTRENG). PHMSA has determined
that additional requirements are needed to assure such calculations
have a sound basis. The proposed rule would revise section 192.485(c)
to specify that pipe and material properties used in remaining strength
calculations must be documented in reliable, traceable, verifiable, and
complete records. If such records are not available, pipe and material
properties used in the remaining strength calculations must be based on
properties determined and documented in accordance with Sec. 192.607.
Sec. 192.493 In-line inspection of pipelines.
The current pipeline safety regulations in 49 CFR 192.921 and
192.937 require that operators assess the material condition of
pipelines in certain circumstances (e.g., IM assessments for pipelines
that could affect high consequence areas) and allow use of in-line
inspection tools for these assessments. Operators of gas transmission
pipelines are required to follow the requirements of ASME/ANSI B31.8S,
``Managing System Integrity of Gas Pipelines,'' in conducting their IM
activities. ASME B31.8S provides limited guidance for conducting ILI
assessments. Part 192 is silent on technical standards or guidelines
for performing ILI assessments or implementing these requirements. At
the time these rules were promulgated, there was no consensus industry
standard that addressed ILI. Three related standards have since been
published:
API STD 1163-2005, ``In-Line Inspection Systems
Qualification Standard.'' This Standard serves as an umbrella document
to be used with and complement the NACE and ASNT standards below, which
are incorporated by reference in API STD 1163.
NACE Standard Practice, NACE SP0102-2010, ``In-line
Inspection of Pipelines.''
ANSI/ASNT ILI-PQ-2010, ``In-line Inspection Personnel
Qualification and Certification.''
The API standard is more comprehensive and rigorous than
requirements currently incorporated into 49 CFR part 192. The
incorporation of this standard into pipeline safety regulations will
promote a higher level of safety by establishing consistent standards
to qualify the equipment, people, processes and software utilized by
the in-line inspection industry. The API standard addresses in detail
each of the following aspects of ILI inspections, most of which are not
currently addressed in the regulations:
Systems qualification process
Personnel qualification
In-line inspection system selection
Qualification of performance specifications
System operational validation
System Results qualification
Reporting requirements
Quality management system
The incorporation of this standard into pipeline safety regulations
will promote a higher level of safety by establishing consistent
standards for conducting ILI assessments of line pipe. The NACE
standard covers in detail each of the following aspects of ILI
assessments, most of which are not currently addressed in part 192 or
in ASME B31.8S:
Tool selection
Evaluation of pipeline compatibility with ILI
Logistical guidelines, which includes survey acceptance
criteria and reporting
Scheduling
New construction (planning for future ILI in new lines)
Data analysis
Data management
The NACE standard provides a standardized questionnaire
and specifies that the completed questionnaire should be provided to
the ILI vendor. The questionnaire lists relevant parameters and
characteristics of the pipeline section to be inspected.
PHMSA believes that the consistency, accuracy and quality of
pipeline in-line inspections would be improved by incorporating the
consensus NACE standard into the regulations.
The NACE standard applies to ``free swimming'' inspection tools
that are carried down the pipeline by the
[[Page 20811]]
transported fluid. It does not apply to tethered or remotely controlled
ILI tools, which can also be used in special circumstances (e.g.,
examination of laterals). While their use is less prevalent than free
swimming tools, some pipeline IM assessments have been conducted using
these tools. PHMSA considers that many of the provisions in the NACE
standard can be applied to tethered or remotely controlled ILI tools.
Therefore, PHMSA is proposing to allow the use of these tools, provided
they generally comply with the applicable sections of the NACE
standard.
The ANSI/ASNT standard provides for qualification and certification
requirements that are not addressed by 49 CFR part 192. The
incorporation of this standard into pipeline safety regulations will
promote a higher level of safety by establishing consistent standards
to qualify the equipment, people, processes and software utilized by
the in-line inspection industry. The ANSI/ASNT standard addresses in
detail each of the following aspects, which are not currently addressed
in the regulations:
Requirements for written procedures
Personnel qualification levels
Education, training and experience requirements
Training programs
Examinations (testing of personnel)
Personnel certification and recertification
Personnel technical performance evaluations
The proposed rule adds a new Sec. 192.493 to require compliance
with the requirements and recommendations of the three consensus
standards discussed above when conducting in-line inspection of
pipelines.
Sec. 192.503 General requirements.
Section 192.503 prescribes the general test requirements for the
operation of a new segment of pipeline, or returning to service a
segment of pipeline that has been relocated or replaced. The proposed
rule would add additional requirements to Sec. 192.503(a)(1) to
reflect other requirements for determination of MAOP. These include
Sec. 192.620 for alternative MAOP determination requirements and new
Sec. 192.624 for verification of MAOP for onshore, steel, gas
transmission pipeline segments that: (1) Has experienced a reportable
in-service incident, as defined in Sec. 191.3, since its most recent
successful subpart J pressure test, due to an original manufacturing-
related defect, a construction-, installation-, or fabrication-related
defect, or a cracking-related defect, including, but not limited to,
seam cracking, girth weld cracking, selective seam weld corrosion, hard
spot, or stress corrosion cracking and the pipeline segment is located
in one of the following locations: (i) A high consequence area as
defined in Sec. 192.903; (ii) a class 3 or class 4 location; or (iii)
a moderate consequence area as defined in Sec. 192.3 if the pipe
segment can accommodate inspection by means of instrumented inline
inspection tools (i.e., ``smart pigs''); (2) Pressure test records
necessary to establish maximum allowable operating pressure per subpart
J for the pipeline segment, including, but not limited to, records
required by Sec. 192.517(a), are not reliable, traceable, verifiable,
and complete and the pipeline segment is located in one of the
following locations: (i) A high consequence area as defined in Sec.
192.903; or (ii) a class 3 or class 4 location; or (3) the pipeline
segment maximum allowable operating pressure was established in
accordance with Sec. 192.619(c) of this subpart before [effective date
of rule] and is located in one of the following areas: (i) A high
consequence area as defined in Sec. 192.903; (ii) a class 3 or class 4
location; or (iii) a moderate consequence area as defined in Sec.
192.3 if the pipe segment can accommodate inspection by means of
instrumented inline inspection tools (i.e., ``smart pigs'').
Sec. 192.506 Transmission lines: Spike hydrostatic pressure test
for existing steel pipe with integrity threats.
The NTSB recommended repealing Sec. 192.619(c) and requiring that
all gas transmission pipelines constructed before 1970 be subjected to
a hydrostatic pressure test that incorporates a spike test
(recommendation P-11-14). Currently, part 192 does not contain any
requirement for operators to conduct spike hydrostatic pressure tests.
In response to the NTSB recommendation, this NPRM proposes requirements
for verification of MAOP in new Sec. 192.624, which requires that MAOP
be established and documented for pipelines located in either an HCA or
MCA meeting the conditions in Sec. 192.624(a)(1) through (3) using one
or more of the methods in Sec. 192.624(c)(1) through (6). The pressure
test method requires performance of a spike pressure test in accordance
with new Sec. 192.506 if the pipeline includes legacy pipe or was
constructed using legacy construction techniques or if the pipeline has
experienced a reportable in-service incident, as defined in Sec.
191.3, since its most recent successful subpart J pressure test, due to
an original manufacturing-related defect, a construction-,
installation-, or fabrication-related defect, or a crack or crack-like
defect, including, but not limited to, seam cracking, girth weld
cracking, selective seam weld corrosion, hard spot, or stress corrosion
cracking.
Sec. 192.517 Records.
Section 192.517 prescribes the record requirements for each test
performed under Sec. Sec. 192.505 and 192.507. The proposed rule would
revise Sec. 192.517 to add the record requirements for Sec. 192.506.
Sec. 192.605 Procedural manual for operations, maintenance, and
emergencies.
Section 192.605 prescribes requirements for the operator's
procedural manual for operations, maintenance, and emergencies. Part
192 contains numerous requirements intended to protect pipelines from
overpressure events. These include mandatory pressure relieving or
pressure limiting devices, inspections and tests of such devices,
establishment of maximum allowable operating pressure, and
administrative requirements to not operate the pipeline at pressures
that exceed the MAOP, among others. Implicit in the requirements of
Sec. 192.605 is the intent for operators to establish operational and
maintenance controls and procedures to effectively implement these
requirements and preclude operation at pressures that exceed MAOP.
PHMSA expects that operator's procedures should already address this
aspect of operations and maintenance, as it is a long-standing,
critical aspect of safe pipeline operations. However, Sec. 192.605
does not explicitly prescribe this aspect of the procedural controls.
In addition, as a result of the San Bruno incident, Congress mandated
in Section 23 of the Act that any exceedance of MAOP on a gas
transmission pipeline be reported to PHMSA. As part of such reporting,
the operator should inform PHMSA of the cause(s) of each exceedance. On
December 21, 2012, PHMSA published advisory bulletin ADB-2012-11, which
advised transmission operators of their responsibility under Section 23
of the Act to report exceedances of MAOP that exceeds the margin
(build-up) allowed for operation of pressure-limiting or control
devices (i.e., report any pressure exceedances over the pressure
limiting or control device set point as defined in applicable sections
of Sec. Sec. 192.201(a)(2) or 192.739). Between December 21, 2012 and
June 30, 2013, PHMSA received 14 such notifications. Therefore, PHMSA
has determined that an additional requirement is needed to explicitly
require procedures to maintain and operate pressure relieving devices
and to control operating pressure to prevent
[[Page 20812]]
exceedance of MAOP. The proposed rule clarifies the existing
requirements regarding such procedural controls.
Sec. 192.607 Verification of pipeline material: Onshore steel
transmission pipelines.
Section 23 of the Act requires the Secretary of Transportation to
require verification of records used to establish MAOP to ensure they
accurately reflect the physical and operational characteristics of the
pipelines and to confirm the established MAOP of the pipelines. PHMSA
issued Advisory Bulletin 11-01 on January 10, 2011 (76 FR 1504) and
Advisory Bulletin 12-06 on May 7, 2012 (77 FR 26822) to inform
operators of this requirement. Operators have submitted information in
their 2012 Annual Reports indicating that a portion of transmission
pipeline segments do not have adequate records to establish MAOP or to
accurately reflect the physical and operational characteristics of the
pipeline. Therefore, PHMSA has determined that additional rules are
needed to implement this requirement of the Act. Specifically, PHMSA
has determined that additional rules are needed to require that
operators conduct tests and other actions needed to understand the
physical and operational characteristics for those segments where
adequate records are not available, and to establish standards for
performing these actions.
This issue was addressed in detail at the Integrity Verification
Process workshop on August 7, 2013. Major issues that were discussed
include the scope of information needed and the methodology for
verifying material properties. The most difficult information to
obtain, from a technical perspective, is the strength of the steel.
Conventional techniques would include cutting out a piece of pipe and
destructively testing it to determine yield and ultimate tensile
strength. PHMSA proposes to address this in the rule by allowing new
non-destructive techniques if they can be validated to produce accurate
results for the grade and type of pipe being evaluated. Such techniques
have already been successfully validated for some grades of pipe.
Another issue is the extremely high cost of excavating the pipeline
in order to verify the material, and determining how much pipeline
needs to be exposed and tested in order to have assurance of pipeline
properties. PHMSA proposes to address this issue by specifying that
operators take advantage of opportunities when the pipeline is exposed
for other reasons, such as maintenance and repair, by requiring that
material properties be verified whenever the pipe is exposed. Over
time, pipeline operators will develop a substantial set of verified
material data, which will provide assurance that material properties
are reliably known for the entire population of inadequately documented
segments. PHMSA proposes to require that operators continue this
opportunistic material verification process until the operator has
completed enough verifications to obtain high confidence that only a
small percentage of inadequately documented pipe lengths have
properties that are inconsistent with operators' past assumptions. The
rule would specify the number of excavations required to achieve this
level of confidence.
Lastly, PHMSA proposes criteria that would require material
verification for higher risk locations. Therefore, the proposed rule
would add requirements for verification of pipeline material in new
Sec. 192.607 for existing onshore, steel, gas transmission pipelines
that are located in an HCA or a class 3 or class 4 location. PHMSA
believes this approach appropriately addresses pipeline segment risk
without extending the requirement to all pipelines where risk and
potential consequences are not as significant, such as pipeline in
remote rural areas.
Requirements are also included to ensure that the results of this
process are documented in records that are reliable, traceable,
verifiable, and complete that must be retained for the life of the
pipeline.
Sec. 192.613 Continuing surveillance.
Section 192.613 prescribes general requirements for continuing
surveillance of the pipeline to determine and take action due to
changes in the pipeline from, among other things, unusual operating and
maintenance conditions. The 2011 hazardous liquid pipeline accident
resulting in a crude oil spill into the Yellowstone River near Laurel,
Montana was probably caused by scouring at a river crossing due to
flooding. Based on recent examples of extreme weather events that did
result, or could have resulted, in pipeline incidents, PHMSA has
determined that additional requirements are needed to assure that
operator procedures adequately address inspection of the pipeline and
right-of-way for ``other factors affecting safety and operation''
following an extreme weather event such as a hurricane or flood,
landslide, an earthquake, a natural disaster, or other similar event.
The proposed rule would add a new paragraph (c) to require such
inspections, specify the timeframe in which such inspections should
commence, and specify the appropriate remedial actions must be taken to
ensure safe pipeline operations. The new paragraph (c) would apply to
both onshore transmission pipelines and their rights-of-way.
Sec. 192.619 Maximum allowable operating pressure: Steel or
plastic pipelines.
The NTSB issued its report on the San Bruno incident that included
a recommendation (P-11-15) that PHMSA amend its regulations so that
manufacturing and construction-related defects can only be considered
``stable'' if a gas pipeline has been subjected to a post-construction
hydrostatic pressure test of at least 1.25 times the MAOP. This NPRM
proposes to revise the test pressure factors in Sec. 192.619(a)(2)(ii)
to correspond to at least 1.25 MAOP for newly installed pipelines.
In addition, Section 23 of the Act requires verification of records
to confirm the established MAOP of the pipelines. Operators have
submitted information in their 2012 Annual Reports indicating that a
portion of gas transmission pipeline segments do not have adequate
records to establish MAOP. For pipelines without an adequately
documented basis for MAOP, the proposed rule adds a new paragraph (e)
to Sec. 192.619 to require that certain onshore steel transmission
pipelines that meet the criteria specified in Sec. 192.624(a), and
that do not have adequate records to establish MAOP, must establish and
document MAOP in accordance with new Sec. 192.624 using one or more of
the methods in Sec. 192.624(c)(1) through (6), as discussed in more
detail below.
The proposed rule would also add a new paragraph (f) to explicitly
require that records documenting tests, design, and other information
necessary to establish MAOP be retained for the life of the pipeline.
Lastly, the rule would incorporate conforming changes to Sec.
192.619(a) to reflect changes to gas gathering regulations proposed in
Sec. Sec. 192.8 and 192.9.
Sec. 192.624 Maximum allowable operating pressure verification:
Onshore steel transmission pipelines.
Section 23 of the Act requires verification of records used to
establish MAOP for pipe in class 3 and class 4 locations and high-
consequence areas in Class 1 and 2 locations to ensure they accurately
reflect the physical and operational characteristics of the pipelines
and to confirm the established MAOP of the pipelines. Operators have
submitted information in their 2012 Annual Reports indicating that some
gas transmission pipeline segments do not
[[Page 20813]]
have adequate records or testing to establish MAOP. For pipelines so
identified, the Act requires that PHMSA promulgate regulations to
require operators to test the segments to confirm the material strength
of the pipe in HCAs that operate at stress levels greater than or equal
to 30% SMYS. Such tests must be performed by pressure testing or other
methods determined by the Secretary to be of equal or greater
effectiveness.
As a result of its investigation of the San Bruno accident, NTSB
issued two related recommendations. NTSB recommended that PHMSA repeal
Sec. 192.619(c) and require that all gas transmission pipelines
constructed before 1970 be subjected to a hydrostatic pressure test
that incorporates a spike test (P-11-14). NTSB also recommended that
PHMSA amend the Federal pipeline safety regulations so that
manufacturing- and construction-related defects can only be considered
stable if a gas pipeline has been subjected to a post-construction
hydrostatic pressure test of at least 1.25 times the maximum allowable
operating pressure (P-11-15).
The proposed rule would add a new Sec. 192.624 to address these
mandates and recommendations. The rule would require that operators re-
establish and document MAOP for certain onshore steel transmission
pipelines located in an HCA or MCA that meet one or more of the
criteria specified in Sec. 192.624(a). Those criteria include: (1) Has
experienced a reportable in-service incident, as defined in Sec.
191.3, since its most recent successful subpart J pressure test, due to
an original manufacturing-related defect, a construction-,
installation-, or fabrication-related defect, or a cracking-related
defect, including, but not limited to, seam cracking, girth weld
cracking, selective seam weld corrosion, hard spot, or stress corrosion
cracking and the pipeline segment is located in one of the following
locations: (i) A high consequence area as defined in Sec. 192.903;
(ii) a class 3 or class 4 location; or (iii) a moderate consequence
area as defined in Sec. 192.3 if the pipe segment can accommodate
inspection by means of instrumented inline inspection tools (i.e.,
``smart pigs''); (2) Pressure test records necessary to establish
maximum allowable operating pressure per subpart J for the pipeline
segment, including, but not limited to, records required by Sec.
192.517(a), are not reliable, traceable, verifiable, and complete and
the pipeline segment is located in one of the following locations: (i)
A high consequence area as defined in Sec. 192.903; or (ii) a class 3
or class 4 location; or (3) the pipeline segment maximum allowable
operating pressure was established in accordance with Sec. 192.619(c)
of this subpart before [effective date of rule] and is located in one
of the following areas: (i) A high consequence area as defined in Sec.
192.903; (ii) a class 3 or class 4 location; or (iii) a moderate
consequence area as defined in Sec. 192.3 if the pipe segment can
accommodate inspection by means of instrumented inline inspection tools
(i.e., ``smart pigs'').
The methods specified in Sec. 192.624 include the pressure test
method. If the pipeline includes legacy pipe or was constructed using
legacy construction techniques or the pipeline has experienced a
reportable in-service incident, as defined in Sec. 191.3, since its
most recent successful subpart J pressure test, due to an original
manufacturing-related defect, a construction-, installation-, or
fabrication-related defect, or a crack or crack-like defect, a spike
pressure test in accordance with new Sec. 192.506 would be required.
For modern pipe without the aforementioned risk factors, a pressure
test in accordance with Sec. 192.505 would be allowed.
Other methods to reestablish MAOP for pipe currently operating
under Sec. 192.619(c) would also be allowed. PHMSA has determined that
the following methods would provide equal or greater effectiveness as a
pressure test:
(i) De-rating the pipe segment such that the new MAOP is less than
historical actual sustained operating pressure by using a safety factor
of 0.80 times the sustained operating pressure (equivalent to a
pressure test using gas or water as the test medium with a test
pressure of 1.25 times MAOP). For segments that operate at stress
levels of less than 30% SMYS a safety factor of 0.90 times sustained
operating pressure is allowed (equivalent to a pressure test of 1.11
times MAOP), supplemented with additional integrity assessments, and
preventive and mitigative measures specified in the proposed rule.
(ii) Replacement of the pipe, which would require a new pressure
test that conforms with subpart J before being placed in service,
(iii) An in-line inspection and Engineering Critical Assessment
process using technical criteria to establish a safety margin
equivalent to that provided by a pressure test, or
(iv) Use of other technology that the operator demonstrates
provides an equivalent or greater level of safety, provided PHMSA is
notified in advance.
The proposed rule establishes requirements for pipelines operating
at stress levels of less than 30% of SMYS based on technical
information provided in Interstate Natural Gas Association of America/
American Gas Association Final Report No. 13-180, ``Leak vs. Rupture
Thresholds for Material and Construction Anomalies,'' December 2013.
The report references a 2010 study by Kiefner & Associates, Inc.
``Numerical Modeling and Validation for Determination of the Leak/
Rupture Boundary for Low-Stress Pipelines'' performed under contract to
the Gas Technology Institute (GTI). The Kiefner/GTI report evaluated
theoretical fracture models and supporting test data in order to define
a possible leak-rupture threshold stress level. The report pointed out
that ``no evidence was found that a propagating ductile rupture could
arise from an incident attributable to any one of these causes in a
pipeline that is being operated at a hoop stress level of 30% of SMYS
or less.'' In addition, the INGAA/AGA report included a review of
Kiefner & Associates, Inc. failure investigation reports, which
concluded that all manufacturing related defects failing under the
action of hoop stress alone failed as leaks if the hoop stress level
was 30% SMYS or less except for one case out of 94 which failed at 27%
of SMYS. The INGAA/AGA report states that a hydrostatic test to 1.25
times the MAOP is unnecessary to reasonably assure stability of pipe
manufacturing construction related features in pipe meeting the
following conditions: (1) Ductile fracture initiation is assured by
showing that the pipe has an operating temperature above the brittle
fracture initiation temperature; (2) interaction with in-service
degradation mechanics such as selective seam weld corrosion or previous
mechanical damage is absent; (3) hoop stress is 30% or less; (4) mill
pressure testing was conducted at 60% SMYS or more, established by
documented conformance to applicable pipe product specifications (e.g.,
API 5L) or company specifications; and (5) pipe is 6 NPS or smaller.
For pipes that are 8 NPS or larger but still meeting the conditions
mentioned above, hydrostatic pressure testing to 1.25 times the MAOP is
still prudent, since theoretical analysis as well as full scale
laboratory tests show that failure as a rupture is possible for stress
thresholds below 30% of SMYS. However, NPS 8 pipe may be prioritized
lower than larger pipe because there were no reported incidents of
service rupture in pipe that size where all other criteria were met.
PHMSA plans to limit stress levels, pressures, and pipe diameters that
can meet the potential impact
[[Page 20814]]
radius and require alternative integrity and preventative and
mitigative measures for pipelines that use these criteria to establish
MAOP.
The above approach implements the regulatory mandate in the Act for
segments in HCAs. In addition, the scope includes additional pipe
segments in the newly defined moderate consequence areas. This approach
is intended to address the NTSB recommendations and to provide
increased safety in areas where a pipeline rupture would have a
significant impact on the public or the environment. PHMSA does not
propose to repeal 49 CFR 192.619(c) for segments located outside of
HCAs or MCAs where the routine presence of persons is not expected.
The Engineering Critical Assessment process requires the
conservative analysis of: Any in-service cracks, crack-like defects
remaining in the pipe, or the largest possible crack that could remain
in the pipe, including crack dimensions (length and depth) to determine
the predicted failure pressure (PFP) of each defect; failure mode
(ductile, brittle, or both) for the microstructure, location, type of
defect, and operating conditions (which includes pressure cycling); and
failure stress and crack growth analysis to determine the remaining
life of the pipeline. An Engineering Critical Assessment must use
techniques and procedures developed and confirmed through research
findings provided by PHMSA, and other reputable technical sources for
longitudinal seam and crack growth such as PHMSA's Comprehensive Study
to Understand Longitudinal ERW Seam Research & Development study task
reports: Battelle Final Reports (``Battelle's Experience with ERW and
Flash Weld Seam Failures: Causes and Implications''--Task 1.4), Report
No. 13-002 (``Models for Predicting Failure Stress Levels for Defects
Affecting ERW and Flash-Welded Seams''--Subtask 2.4), Report No. 13-021
(``Predicting Times to Failure for ERW Seam Defects that Grow by
Pressure-Cycle-Induced Fatigue''--Subtask 2.5), and ``Final Summary
Report and Recommendations for the Comprehensive Study to Understand
Longitudinal ERW Seam Failures--Phase 1''--Task 4.5), which can be
found on the internet at: https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=390.
Section 23 requires pipeline operators to conduct a records
verification for pipelines located in certain areas to ensure that the
records accurately reflect the physical and operational characteristics
of the pipelines and confirm the established MAOP. Congress further
directed DOT to require the owner or operator to reconfirm a maximum
allowable operating pressure for pipelines with insufficient records.
This rule proposes methods for satisfying this direction from Congress.
In analyzing the impact of the proposed methods, PHMSA determined that
they would result in large cost savings ($2.67 billion over 15 years
discounted at 7%, $3.67 billion discounted at 3%) relative to current
regulatory requirements for pipelines with insufficient records in 49
CFR 192.107(b), The results of that action indicated that problems
similar to those that contributed to the San Bruno incidents are more
widespread than previously believed. As a result, the proposed rule
would establish consistent standards by which operators would correct
these issues in a way that is more cost effective than the current
regulations would require (which could require more extensive
destructive testing, pressure testing, and/or pipe replacement). PHMSA
did not identify any significant adverse safety impacts from allowing
operators to use the proposed methods instead of those in the current
regulations. See section 4.1.2.3 in the regulatory impact analysis for
the analysis of the cost savings.
PHMSA estimated the cost savings to operators associated with the
Section 23(c) mileage. Existing regulatory requirements [Sec.
192.107(b)] related to bad or missing records would be more costly for
operators to achieve compliance. Under existing regulations, in order
for pipelines with insufficient records to maintain operating pressure,
operators must excavate the pipeline at every 10 lengths of pipe
(commonly referred to as joints) in accordance with section II-D of
appendix B of part 192 (as specified in Sec. 192.107(b)), do a cutout,
determine material properties by destructive tensile test, and repair
the pipe. The process is similar to doing a repair via pipe
replacement. PHMSA developed a blended average for performing such a
cutout material verification ($75,000) by reviewing typical costs to
repair a small segment of pipe by pipe replacement. The blended average
accounted for various pipe diameters and regional cost variance. PHMSA
assumed each joint is 40 feet long; ten joints is 400 ft. The number of
cutouts required by existing rules is therefore the miles subject to
this requirement multiplied by 5,280/400.
The proposed rule would allow operators to perform a sampling
program that opportunistically takes advantage of repairs and
replacement projects to verify material properties at the same time.
Over time, operators will collect enough information gain significant
confidence in the material properties of pipe subject to this
requirement. The proposed rule nominally targets conducting an average
of one material documentation process per mile. In addition, operators
would be allowed to perform nondestructive examinations, in lieu of
cutouts and destructive testing, when the technology provides a
demonstrable level of confidence in the result. PHMSA estimated that
the incremental unit cost of adding material documentation activities
to a repair or replacement activity would be approximately $17,000 per
instance.
The proposed methods for addressing pipelines with insufficient
records are exclusively applicable to HCA and all Class 3 and 4
locations. Therefore, if the proposed rule were in effect, operators
would be able to use the new methods for addressing pipeline with
insufficient records in HCA and all Class 3 and 4 locations, but they
would be required to comply with existing (more expensive) requirements
for addressing the same issue for pipelines located outside HCA and all
Class 3 and 4 locations. Locations outside HCAs and all Class 3 and 4
are by definition lower risk, meaning if incidents occur, the
consequences are expected to be smaller than HCA and all Class 3 and 4
locations. PHMSA is considering including provisions in the final rule
that would enable operators to use the proposed methods for addressing
pipelines with insufficient records in locations outside HCAs and all
Class 3 and 4. To maintain flexibility, the proposed methods may be an
option to existing requirements--as opposed to a replacement of those
requirements. PHMSA requests comments on the impacts of allowing
operators to use the new methods for addressing insufficient records
beyond HCAs and all Class 3 and 4 locations. What safety risks, if any,
should PHMSA consider? What are the potential cost savings?
Sec. 192.710 Pipeline assessments.
Currently, part 192 does not contain any requirement for operators
to conduct integrity assessments of onshore transmission pipelines that
are not HCA segments as defined in Sec. 192.903 and therefore not
subject to subpart O; i.e., pipelines that are not located in a high
consequence area (HCA). Currently, only approximately 7% of onshore gas
transmission pipelines are located in HCAs. However, coincident with
integrity assessments of HCA segments, industry has, as a practical
matter, assessed substantial amounts of pipeline in non-HCA
[[Page 20815]]
segments. For example, INGAA noted (see Topic A comments, above) that
approximately 90 percent of Class 3 and 4 mileage not in HCAs are
presently assessed through over-testing during IM assessments. This is
due, in large part, because ILI or pressure testing, by their nature,
assess large continuous segments that may contain some HCA segments but
that could also contain significant amounts of non- HCA segments. In
addition, based on the integrity management principle of continuous
improvement, INGAA members have committed (via its IMCI action plan
discussed under Topic A, above) to first extend some degree of
integrity management to approximately 90 percent of people who live,
work or otherwise congregate near pipelines (that is, within the
pipelines' Potential Impact Radius, or PIR) by 2012. By 2020, INGAA
operators have committed to perform full integrity management on
pipelines covering 90 percent of the PIR population. At a minimum, all
ASME/ANSI B31.8S requirements will be applied, including mitigating
corrosion anomalies and applying integrity management principles.
Continuing to areas of less population density, INGAA members plan to
apply integrity management principles to pipelines covering 100 percent
of the PIR population by 2030.
Given this level of commitment, PHMSA has determined that it is
appropriate to codify requirements that additional gas transmission
pipelines have an integrity assessment on a periodic basis to monitor
for, detect, and remediate deleterious pipeline defects and injurious
anomalies. However, INGAA does not represent all pipeline operators
subject to part 192. In addition, in order to achieve the desired
outcome of performing assessments in areas where people live, work, or
congregate, while minimizing the cost of identifying such locations,
PHMSA proposes to base the requirements for identifying those locations
on processes already being implemented by pipeline operators.
The proposed rule would add a new Sec. 192.710 to require that
pipeline segments in moderate consequence areas that can accommodate
inspection by means of instrumented inline inspection tools (i.e.,
``smart pigs'') be assessed within 15 years and every 20 years
thereafter. PHMSA proposes to define a new term ``moderate consequence
area'' or MCA. The definition is based on the same methodology as
``high consequence areas'' as specified in Sec. 192.903, but with less
stringent criteria. Moderate consequence areas will be used to define
the subset of locations where integrity assessments are required. This
approach is proposed as a means to minimize the effort needed on the
part of operators to identify the MCAs, since transmission operators
must have already performed the analysis in order to have identified
the HCAs, or verify that they have no HCAs. In addition, the MCA
definition would include locations where interstate highways, freeways,
and expressways, and other principal 4-lane arterial roadways are
located within the PIR.
Because significant non-HCA pipeline mileage has been previously
assessed in conjunction with an assessment of HCA segments in the same
pipeline, PHMSA also proposes to allow the use of those prior
assessments for non-HCA segments to comply with the new Sec. 192.710,
provided that the assessment was conducted in conjunction with an
integrity assessment required by subpart O.
The proposed rule would also require that the assessment required
by new Sec. 192.710 be conducted using the same methods as proposed
for HCAs (see Sec. 192.921, below).
Sec. 192.711 Transmission lines: General requirements for repair
procedures.
Section 192.711 prescribes general requirements for repair
procedures. For non-HCA segments, the existing rule requires that
permanent repairs be made as soon as feasible. However, no specific
repair criteria are provided and no specific timeframe or pressure
reduction requirements are provided. PHMSA has determined that more
specific repair criteria are needed for pipelines not covered under the
integrity management rule. The proposed rule would amend paragraph
(b)(1) of section 192.711 to require that specific conditions (i.e.,
repair criteria) defined in proposed Sec. 192.713 (see below) be
remediated, and to require a reduction of operating pressure for
conditions that present an immediate hazard.
Sec. 192.713 Transmission lines: Permanent field repair of
imperfections and damages.
Section 192.713 prescribes requirements for the permanent repair of
pipeline imperfection or damage that impairs the serviceability of pipe
in a steel transmission line operating at or above 40 percent of SMYS.
PHMSA has determined that more explicit requirements are needed to
better identify criteria for the severity of imperfection or damage
that must be repaired, and to identify the timeframe within which
repairs must be made. Further, PHMSA has determined that such repair
criteria should apply to any transmission pipeline not covered under
subpart O, Integrity Management regulations. PHMSA believes that
establishing these non-HCA segment repair conditions are important
because, even though they are not within the defined high consequence
locations, they could be located in populated areas and are not without
consequence. For example, as reported by operators in the 2011 annual
reports, while there are approximately 20,000 miles of gas transmission
pipe in HCA segments, there are approximately 65,000 miles of pipe in
Class 2, 3, and 4 populated areas. PHMSA believes it is prudent and
appropriate to include criteria to assure the timely repair of
injurious pipeline defects in non-HCA segments. These changes will
ensure the prompt remediation of anomalous conditions, while allowing
operators to allocate their resources to high consequence areas on a
higher priority basis. The proposed rule would amend Sec. 192.713 to
establish immediate, two-year, and monitored conditions which the
operator must remediate or monitor to assure pipeline safety. PHMSA
proposes to use the same criteria as proposed for HCAs (see 192.933,
below), except that conditions for which a one-year response is
required in HCAs would require a two-year response in non-HCA segments.
In addition, PHMSA proposes to prescribe more explicit requirements for
in situ evaluation of cracks and crack-like defects using in-the-ditch
tools whenever required, such as when an ILI, SCCDA, pressure test
failure, or other assessment identifies anomalies that suggest the
presence of such defects.
Sec. 192.750 Launcher and receiver safety.
PHMSA has determined that more explicit requirements are needed for
safety when performing maintenance activities that utilize launchers
and receivers to insert and remove maintenance tools and devices. Such
facilities are subjected to pipeline system pressures. Current
regulations for hazardous liquid pipelines (part 195) have, since 1981,
contained such safety requirements for scraper and sphere facilities
(re: Sec. 195.426). However, current regulations for gas pipelines
(part 192) do not similarly require controls or instrumentation to
protect against inadvertent breach of system integrity due to incorrect
operation of launchers and receivers for in-line inspection tools,
scraper, and sphere facilities. Accordingly, the proposed rule would
add a new section Sec. 192.750 to require a suitable means to relieve
pressure in the barrel and either a means to indicate the pressure in
the
[[Page 20816]]
barrel or a means to prevent opening if pressure has not been relieved.
Sec. 192.911 What are the elements of an integrity management
program?
Paragraph (k) of Sec. 192.911 requires that integrity management
programs include a management of change process as outlined in ASME/
ANSI B31.8S, section 11. PHMSA has determined that specific attributes
and features of the management of change process as currently specified
in ASME/ANSI B31.8S, section 11, should be codified directly within the
text of Sec. 192.911(k). The proposed rule would amend paragraph (k)
to specify that the features of the operator's management of change
process must include the reason for change, authority for approving
changes, analysis of implications, acquisition of required work
permits, documentation, communication of change to affected parties,
time limitations, and qualification of staff. These general attributes
of change management are already required by virtue of being invoked by
reference to ASME/ANSI B31.8S. However, PHMSA believes it will improve
the visibility and emphasis on these important program elements to
require them directly in the rule text.
Sec. 192.917 How does an operator identify potential threats to
pipeline integrity and use the threat identification in its integrity
program?
Section 192.917 requires that integrity management programs for
covered pipeline segments identify potential threats to pipeline
integrity and use the threat identification in its integrity program.
Included within this performance-based process are requirements to
identify threats to which the pipeline is susceptible, collect data for
analysis, and perform a risk assessment. Special requirements are
included to address plastic pipe and particular threats such as third
party damage and manufacturing and construction defects. Following the
San Bruno accident, the NTSB recommended that Pacific Gas and Electric
(PG&E) assess every aspect of its integrity management program, paying
particular attention to the areas identified in the investigation, and
implement a revised program that includes, at a minimum,
(1) a revised risk model to reflect the Pacific Gas and Electric
Company's actual recent experience data on leaks, failures, and
incidents;
(2) consideration of all defect and leak data for the life of each
pipeline, including its construction, in risk analysis for similar or
related segments to ensure that all applicable threats are adequately
addressed;
(3) a revised risk analysis methodology to ensure that assessment
methods are selected for each pipeline segment that address all
applicable integrity threats, with particular emphasis on design/
material and construction threats; and
(4) an improved self-assessment that adequately measures whether
the program is effectively assessing and evaluating the integrity of
each covered pipeline segment (NTSB recommendation P-11-29).
In addition, the NTSB recommended that PG&E conduct threat
assessments using the revised risk analysis methodology incorporated in
its integrity management program, as recommended in Safety
Recommendation P-11-29, and report the results of those assessments to
the California Public Utilities Commission and the Pipeline and
Hazardous Materials Safety Administration (NTSB recommendation P-11-
30). PHMSA has also analyzed the issues the NTSB identified in the
investigation related to information analysis and risk assessment.
PHMSA held a workshop on July 21, 2011 to address perceived
shortcomings in the implementation of integrity management risk
assessment processes and the information and data analysis (including
records) upon which such risk assessments are based. PHMSA sought input
from stakeholders on these issues and has determined that additional
clarification and specificity is needed for existing performance-based
rules. These clarifications define and emphasize the specific functions
that are required for risk assessment and effective risk management.
These aspects of integrity management have been an integral part of
PHMSA's expectations for integrity management since the inception of
the program. As specified in Sec. 192.907(a), PHMSA expected operators
to start with a framework, which would evolve into a more detailed and
comprehensive program, and that the operator must continually improve
its integrity management program, as it learned more about the process
and about the material condition of its pipelines through integrity
assessments.
PHMSA elaborated on this philosophy in the notice of final
rulemaking for subpart O (68 FR 69778):
The intent of allowing a framework was to acknowledge that an
operator cannot develop a complete, fully mature integrity
management plan in a year. Nevertheless, it is important that an
operator have thought through how the various elements of its plan
relate to each other early in the development of its plan. The
framework serves this purpose. . . . It need not be fully developed
or at the level of detail expected of final integrity management
plans. The framework is an initial document that evolves into a more
detailed and comprehensive program.
The clarifications and additional specificity proposed in this NPRM
(with respect to processes for implementing the threat identification,
risk assessment, and preventive and mitigative measures program
elements), reflect PHMSA's expectation regarding the degree of progress
operators should be making, or should have made, during the first 10
years of the integrity management program.
The current integrity management rule invokes ASME/ANSI B31.8S by
reference to require that operators implement specific attributes and
features of the threat identification, data analysis, and risk
assessment process. PHMSA has determined that those specific attributes
and features of the threat identification, data analysis, and risk
assessment processes as currently specified in ASME/ANSI B31.8S,
section 11, should be codified within the text of Sec. 192.917. While
continuing to incorporate the industry standard by reference, the
proposed rule would amend Sec. 192.917 to insert certain critical
features of the industry standard (ASME/ANSI B31.8S) directly into the
body of the Federal regulation. Specifically, PHMSA proposes to specify
several pipeline attributes that must be included in pipeline risk
assessments and to explicitly require that operators integrate analyzed
information, and ensure that data be verified and validated to the
maximum extent practical. PHMSA also acknowledges that objective,
documented data is not always available or obtainable. To the degree
that subjective data from subject matter experts must be used, PHMSA
proposes to require that an operator's program include specific
features to compensate for subject matter expert bias.
In addition, PHMSA proposes to clarify the performance-based risk
assessment aspects of the IM rule to specify that operators perform
risk assessments that are adequate to evaluate the effects of
interacting threats; determine additional preventive and mitigative
measures needed, analyze how a potential failure could affect high
consequence areas, including the consequences of the entire worst-case
incident scenario from initial failure to incident termination;
identify the contribution to risk of each risk factor, or each unique
combination of risk factors that interact or simultaneously contribute
to risk at a common location, account for, and compensate for,
uncertainties in the
[[Page 20817]]
model and the data used in the risk assessment; and evaluate risk
reduction associated with candidate risk reduction activities such as
preventive and mitigative measures. In addition, in response to
specific NTSB recommendation P-11-18, PHMSA proposes performance-based
language to require that operators validate their risk models in light
of incident, leak, and failure history and other historical
information. Such features are currently requirements by virtue of
being invoked by reference in ASME/ANSI B31.8S. However, PHMSA believes
that these important aspects of integrity management will receive
greater emphasis and awareness if incorporated directly into the rule
text. The proposed rule would also amend the requirements for plastic
pipe to provide specific examples of integrity threats for plastic pipe
that must be addressed.
Lastly, PHMSA proposes to revise the criteria in Sec.
192.917(e)(3) and (4) for addressing the threat of manufacturing and
construction defects and concluding that latent defects are stable as
recommended in NTSB recommendation P-11-15.
Sec. 192.921 How is the baseline assessment to be conducted?
Section 192.921 requires that pipelines subject to integrity
management rules have an integrity assessment. Current rules allow the
use of in-line inspection, pressure testing in accordance with subpart
J, direct assessment for the threats of external corrosion, internal
corrosion, and stress corrosion cracking, and other technology that the
operator demonstrates provides an equivalent level of understanding of
the condition of the pipeline. Following the San Bruno accident, PHMSA
has determined that baseline assessment methods should be clarified to
emphasize in-line inspection and pressure testing over direct
assessment. At San Bruno, PG&E relied heavily on direct assessment
under circumstances for which direct assessment was not effective.
Further, ongoing research and industry response to the ANPRM is
beginning to indicate that stress corrosion cracking direct assessment
is not as effective, and does not provide an equivalent understanding
of pipe conditions with respect to SCC defects, as ILI or hydrostatic
pressure testing at test pressures that exceed those test pressures
required by subpart J (i.e., ``spike'' hydrostatic pressure test).
Therefore, the proposed rule would require that direct assessment only
be allowed when the pipeline cannot be assessed using in-line
inspection tools. The proposed rule would also add three additional
assessment methods: (1) A ``spike'' hydrostatic pressure test, which is
particularly well suited to address SCC and other cracking or crack-
like defects, (2) guided wave ultrasonic testing (GWUT) which is
particularly appropriate in cases where short segments, such as road or
railroad crossing, are difficult to assess, and (3) excavation with
direct in situ examination.
The current rule merely indicates that in-line inspection (ILI) is
an accepted assessment method. The regulations are currently silent on
a number of issues that significantly impact the quality and
effectiveness of ILI assessment results. Such considerations are
described in ASME/ANSI B31.8S, but limited guidance is provided. As
discussed above, the proposed rule strengthens guidance in this area by
adding a new Sec. 192.493 to require compliance with the requirements
and recommendations of API STD 1163-2005, NACE SP0102-2010, and ANSI/
ASNT ILI-PQ-2010 when conducting in-line inspection of pipelines.
Section 192.921(a)(1) would be revised to require compliance with Sec.
192.493 instead of ASME B31.8S for baseline ILI assessments for covered
segments. In addition, a person qualified by knowledge, training, and
experience would be required to analyze the data obtained from an
internal inspection tool to determine if a condition could adversely
affect the safe operation of the pipeline, and must explicitly consider
uncertainties in reported results (including, but not limited to, tool
tolerance, detection threshold, probability of detection, probability
of identification, sizing accuracy, conservative anomaly interaction
criteria, location accuracy, anomaly findings, and unity chart plots or
equivalent for determining uncertainties and verifying actual tool
performance) in identifying and characterizing anomalies.
GWUT has been in use by pipeline operators for several years.
Previously, operators were required by Sec. 192.921(a)(4) to submit a
notification to PHMSA as an ``other technology'' assessment method, in
order to use GWUT. In 2007, PHMSA developed guidelines for how it would
evaluate notifications for use of GWUT. These guidelines have been
effectively used for seven years, and PHMSA has gained confidence that
GWUT can be effectively used to assess the integrity of short segments
of pipe. PHMSA proposes to incorporate these guidelines into a new
Appendix F, which would be invoked in Sec. 192.921. Therefore,
notification for use of GWUT would no longer be required.
ASME B31.8S, Section 6.1, describes both excavation and direct in
situ examination as specialized integrity assessment methods,
applicable to particular circumstances:
It is important to note that some of the integrity assessment
methods discussed in para. 6 only provide indications of defects.
Examination using visual inspection and a variety of nondestructive
examination (NDE) techniques are required, followed by evaluation of
these inspection results in order to characterize the defect. The
operator may choose to go directly to examination and evaluation for
the entire length of the pipeline segment being assessed, in lieu of
conducting inspections. For example, the operator may wish to
conduct visual examination of aboveground piping for the external
corrosion threat. Since the pipe is accessible for this technique
and external corrosion can be readily evaluated, performing in-line
inspection is not necessary.
PHMSA proposes to clarify its requirements to explicitly add
excavation and direct in situ examination as acceptable assessment
methods.
PHMSA also proposes that mandatory integrity assessments proposed
for non-HCA segments (see Sec. 192.710, above) could also use these
assessment methods.
Sec. 192.923 How is direct assessment used and for what threats?
As discussed in the changes to Sec. Sec. 192.927 and 192.929
below, the proposed rule would incorporate by reference NACE SP0206-
2006, ``Internal Corrosion Direct Assessment Methodology for Pipelines
Carrying Normally Dry Natural Gas,'' for addressing ICDA and NACE
SP0204-2008, ``Stress Corrosion Cracking Direct Assessment,'' for
addressing SCCDA. Sections 192.923(b)(2) and (b)(3) would be revised to
require compliance with these standards.
Sec. 192.927 What are the requirements for using Internal
Corrosion Direct Assessment (ICDA)?
Internal corrosion (IC) is a degradation mechanism in which steel
pipe loses wall thickness due to corrosion initiating on the inside
surface of the pipe. IC is one of several threats that can impact
pipeline integrity. IM regulations in 49 CFR part 192 require that
pipeline operators assess covered pipe segments periodically to detect
degradation from threats that their analyses have indicated could
affect the segment. Not all covered segments are subject to an IC
threat, but some are. IC direct assessment (ICDA) is an assessment
technique that can be used to address this threat for gas pipelines.
ICDA involves evaluation and analysis to determine locations at which a
[[Page 20818]]
corrosive environment is likely to exist inside a pipeline followed by
excavation and direct examination of the pipe wall to determine whether
IC is occurring.
Section 192.927 specifies requirements for gas transmission
pipeline operators who use ICDA for IM assessments. The requirements in
Sec. 192.927 were promulgated before the NACE standard was published.
They require that operators follow ASME/ANSI B31.8S provisions related
to ICDA. PHMSA has reviewed the NACE standard and finds that it is more
comprehensive and rigorous than either Sec. 192.927 or ASME B31.8S in
many respects. Some of the most important features in the NACE standard
are:
The NACE standard requires more direct examinations in
most cases.
The NACE standard encompasses the entire pipeline segment
and requires that all inputs and outputs be evaluated.
The NACE standard indirect inspection model is different
than the Gas Technology Institute (GTI) model currently referenced in
Sec. 192.927, but is considered to be equivalent or superior. Its
range of applicability with respect to operating pressure is greater
than the GTI model, thus allowing use of ICDA in pipelines with lower
operating pressures and higher flow velocities.
The NACE standard provides additional guidance on how to
effectively determine areas to excavate for detailed examinations for
internal corrosion.
The existing requirements in Sec. 192.927 have one particular
aspect that has proven problematic. The definition of regions and
requirements for selection of direct examination locations in the
regulations are tied to the covered segment. Covered segment boundaries
are determined by population density and other consequence factors
without regard to the orientation of the pipe and the presence of
locations at which corrosive agents may be introduced or may collect
and where internal corrosion would most likely be detected (e.g., low
spots). Section 192.927 requires that locations selected for excavation
and detailed examination be within covered segments, meaning that the
locations at which IC would most likely be detected may not be
examined. Thus, the existing requirements do not always facilitate the
discovery of internal corrosion that could affect covered segments.
PHMSA is proposing to address this problem by incorporating NACE
SP0206-2006 and by establishing additional requirements for addressing
covered segments within the technical process defined by NACE SP0206-
2006.
This proposed rule would require that operators perform two direct
examinations within each covered segment the first time ICDA is
performed. These examinations are in addition to those required to
comply with the NACE standard practice. The additional examinations are
consistent with the current requirement in Sec. 192.927(c)(5)(ii) that
operators apply more restrictive criteria when conducting ICDA for the
first time and are intended to provide a verification, within the HCA,
that the results of applying the NACE process for the ICDA are
acceptable. Applying the NACE process requires a more precise knowledge
of the pipeline's orientation (particularly slope) than operators may
have in many cases. Conducting examinations within the HCA during the
first application of ICDA will verify that application of the ICDA
process provides adequate information about the covered segment.
Operators who identify IC on these additional examinations, even though
excavations at locations determined using the NACE process did not
identify any, will know that improvements to their knowledge of
pipeline orientation or other adjustments to their application of the
NACE process to the covered segment will be needed for future uses of
ICDA. Sec. 192.927(b) and (c) are revised to address these issues.
Sec. 192.929 What are the requirements for using Direct Assessment
for Stress Corrosion Cracking (SCCDA)?
Stress corrosion cracking (SCC) is a degradation mechanism in which
steel pipe develops tight cracks through the combined action of
corrosion and tensile stress (residual or applied). These cracks can
grow or coalesce to affect the integrity of the pipeline. SCC is one of
several threats that can impact pipeline integrity. IM regulations in
49 CFR part 192 require that pipeline operators assess covered pipe
segments periodically to detect degradation from threats that their
analyses have indicated could affect the segment, though not all
covered segments are subject to an SCC threat. SCC direct assessment
(SCCDA) is an assessment technique that can be used to address this
threat.
Section 192.929 specifies requirements for gas transmission
pipeline operators who use SCCDA for IM assessments. The requirements
in Sec. 192.929 were promulgated before NACE Standard Practice SP0204-
2008 was published. They require that operators follow Appendix A3 of
ASME/ANSI B31.8S. This appendix provides some guidance for conducting
SCCDA, but is limited to SCC that occurs in high-pH environments.
Experience has shown that pipelines also can experience SCC degradation
in areas where the surrounding soil has a pH near neutral (referred to
as near-neutral SCC). NACE Standard Practice SP0204-2008 addresses
near-neutral SCC in addition to high-pH SCC. In addition, the NACE
Standard provides technical guidelines and process requirements which
are both more comprehensive and rigorous for conducting SCCDA than do
Sec. 192.929 or ASME/ANSI B31.8S.
The NACE standard provides additional guidance on:
The factors that are important in the formation of SCC on
a pipeline and what data should be collected;
Additional factors, such as existing corrosion, which
could cause SCC to form;
Comprehensive data collection guidelines, including the
relative importance of each type of data;
Requirements to conduct close interval surveys of cathodic
protection or other above-ground surveys to supplement the data
collected during pre-assessment;
Ranking factors to consider for selecting excavation
locations for both near neutral and high pH SCC;
Requirements on conducting direct examinations, including
procedures for collecting environmental data, preparing the pipe
surface for examination, and conducting Magnetic Particle Inspection
(MPI) examinations of the pipe; and
Post assessment analysis of results to determine SCCDA
effectiveness and assure continual improvement.
NACE SP0204-2008 provides comprehensive guidelines on conducting
SCCDA which are commensurate with the state of the art. It is more
comprehensive in scope than Appendix A3 of ASME/ANSI B31.8S. PHMSA has
concluded the quality and consistency of SCCDA conducted under IM
requirements would be improved by requiring the use of NACE SP0204-
2008. Revisions to Sec. 192.929 are proposed to address these issues.
Sec. 192.933 What actions must be taken to address integrity
issues?
Section 192.933 specifies those injurious anomalies and defects
which must be remediated, and the timeframe within which remediation
must occur. PHMSA has determined that the existing rule has gaps, some
injurious anomalies and defects are not identified in the rule as
requiring remediation in a timely manner commensurate with their
seriousness. The proposed rule would designate the following types of
anomalies/defects as immediate
[[Page 20819]]
conditions: Metal loss greater than 80% of nominal wall thickness;
indication of metal-loss affecting certain longitudinal seams;
significant stress corrosion cracking; and selective seam weld
corrosion. The proposed rule would also designate the following types
of anomalies/defects as one-year conditions: Calculation of the
remaining strength of the pipe shows a predicted failure pressure ratio
at the location of the anomaly less than or equal to 1.25 for Class 1
locations, 1.39 for Class 2 locations, 1.67 for Class 3 locations, and
2.00 for Class 4 locations (comparable to the alternative design factor
specified in Sec. 192.620(a)); area of general corrosion with a
predicted metal loss greater than 50% of nominal wall; predicted metal
loss greater than 50% of nominal wall that is located at a crossing of
another pipeline, or is in an area with widespread circumferential
corrosion, or is in an area that could affect a girth weld; gouge or
groove greater than 12.5% of nominal wall; and any indication of crack
or crack-like defect other than an immediate condition.
The methods specified in the IM rule to calculate predicted failure
pressure are explicitly not valid if metal exceeds 80% of wall
thickness. Corrosion affecting a longitudinal seam, especially
associated with seam types that are known to be susceptible to latent
manufacturing defects such as the failed pipe at San Bruno, and
selective seam weld corrosion, are known time sensitive integrity
threats. Stress corrosion cracking is listed in ASME/ANSI B31.8S as an
immediate repair condition, which is not reflected in the current IM
regulations. PHMSA proposes to add requirements to address these gaps.
With respect to SCC, PHMSA has incorporated repair criteria to
address NTSB recommendation P-12-3 that resulted from the investigation
of the Marshall, Michigan crude oil accident. From its investigation,
the NTSB recommended that PHMSA revise Sec. 195.452 to clearly state
(1) when an engineering assessment of crack defects, including
environmentally assisted cracks, must be performed; (2) the acceptable
methods for performing these engineering assessments, including the
assessment of cracks coinciding with corrosion with a safety factor
that considers the uncertainties associated with sizing of crack
defects; (3) criteria for determining when a probable crack defect in a
pipeline segment must be excavated and time limits for completing those
excavations; (4) pressure restriction limits for crack defects that are
not excavated by the required date; and (5) acceptable methods for
determining crack growth for any cracks allowed to remain in the pipe,
including growth caused by fatigue, corrosion fatigue, or stress
corrosion cracking as applicable (NTSB recommendation P-12-3). Although
the recommendation was focused on part 195, the issue applies to gas
pipelines regulated under part 192. PHMSA proposes to allow the use of
engineering assessment to evaluate if SCC is significant (and thus
categorized as an ``immediate'' condition), or not significant (and
thus categorized as a ``one-year'' condition), but that an engineering
assessment not be allowed to justify not remediating any known
indications of SCC. Further, PHMSA proposes to adopt the definition of
significant SCC from NACE SP0204-2008.
The current rule includes no explicit metal loss repair criteria
for one-year conditions, other than one immediate condition. The rule
does direct operators to use Figure 4 in ASME B31.8S to determine non-
immediate metal loss repair criteria. PHMSA proposes to repeal the
reference to Figure 4, and explicitly include selected metal loss
repair conditions in the one-year criteria. These new criteria are
consistent with similar criteria currently invoked in the hazardous
liquid integrity management rule at 40 CFR 195.452(h). In addition,
PHMSA proposes to incorporate safety factors commensurate with the
class location in which the pipeline is located, to include predicted
failure pressure less than or equal to 1.25 times MAOP for Class 1
locations, 1.39 times MAOP for Class 2 locations, 1.67 times MAOP for
Class 3 locations, and 2.00 times MAOP for Class 4 locations in HCAs.
Lastly, in response to the lessons learned from the Marshall, Michigan
rupture, PHMSA proposes to include any crack or crack-like defect that
does not meet the proposed immediate criteria, as a one year condition.
In addition, as a result of its investigation of the Marshall,
Michigan crude oil spill, the NTSB recommended that PHMSA revise Sec.
195.452(h)(2), the ``discovery of condition,'' to require, in cases
where a determination about pipeline threats has not been obtained
within 180 days following the date of inspection, that pipeline
operators notify the Pipeline and Hazardous Materials Safety
Administration and provide an expected date when adequate information
will become available (NTSB recommendation P-12-4). Although the
recommendation was focused on part 195, the issue applies to gas
pipelines regulated under part 192. Accordingly, PHMSA proposes to
amend paragraph (b) of Sec. 192.933 to require that operators notify
PHMSA whenever the operator cannot obtain sufficient information to
determine if a condition presents a potential threat to the integrity
of the pipeline, within 180 days of completing the assessment.
Lastly, PHMSA proposes to require that pipe and material properties
used in remaining strength calculations must be documented in reliable,
traceable, verifiable, and complete records. If such records are not
available, pipe and material properties used in the remaining strength
calculations would be required to be based on properties determined and
documented in accordance with Sec. 192.607.
Sec. 192.935 What additional preventive and mitigative measures
must an operator take?
Section 192.935 requires an operator to take additional measures
beyond those already required by part 192 to prevent a pipeline failure
and to mitigate the consequences of a pipeline failure in a high
consequence area (HCA). An operator must conduct a risk analysis to
identify the additional measures to protect the high consequence area
and improve public safety. As discussed above, PHMSA proposes to amend
Sec. 192.917 to clarify the guidance for risk analyses operators use
to evaluate and select additional preventive and mitigative measures.
In addition, PHMSA has determined that some additional prescriptive
preventive and mitigative measures are needed to assure that public
safety is enhanced in HCAs and affords greater protections for HCAs.
This proposed rule would expand the listing of example preventive and
mitigative measures operators must consider, require that seismicity be
analyzed to mitigate the threat of outside force damage, and would add
specific enhanced measures for managing external corrosion and internal
corrosion inside HCAs.
With respect to additional preventive and mitigative measures
operators must consider, PHMSA proposes to specify that preventive and
mitigative measures include (i) correction of the root causes of past
incidents in order to prevent recurrence, (ii) adequate operations and
maintenance processes, (iii) adequate resources for successful
execution of safety related activities, (iv) additional right-of-way
patrols, (v) hydrostatic tests in areas where material has quality
issues or lost records, (vi) tests to determine material mechanical and
chemical properties for unknown properties that are needed to assure
integrity or substantiate MAOP evaluations including material property
tests from removed pipe that is
[[Page 20820]]
representative of the in-service pipeline, (vii) re-coating of damaged,
poorly performing, or disbonded coatings, and (viii) additional depth-
of-cover survey at roads, streams and rivers, among others. These
example preventive and mitigative measures do not alter the fundamental
requirement to identify and implement preventive and mitigative
measures, but do provide additional guidance and clarify PHMSA's
expectations with this important aspect of integrity management.
Section 29 of the Act requires operators to consider seismicity
when evaluating threats. Accordingly, PHMSA proposes to include
seismicity of the area in evaluating preventive and mitigative measures
with respect to the threat of outside force damage.
With respect to internal corrosion and external corrosion, PHMSA
proposes to add new paragraphs (f) and (g) to Sec. 192.935 to specify
that an operator must enhance its corrosion control program in HCAs to
provide additional protections from the threat of corrosion. More
specifically, operators would be required to conduct periodic close-
interval surveys, coating surveys, interference surveys, and gas-
quality monitoring inside HCAs. The requirements would include specific
minimum performance standards for these activities.
Lastly, to conform to the revised definition of ``electrical
survey,'' the use of that term in Sec. 192.935 would be replaced with
``indirect assessment'' to accommodate other techniques in addition to
close-interval surveys.
Sec. 192.937 What is a continual process of evaluation and
assessment to maintain a pipeline's integrity?
Section 192.937 requires that operators continue to periodically
assess HCA segments and periodically evaluate the integrity of each
covered pipeline segment. PHMSA has determined that conforming
amendments would be needed to implement, and be consistent with, the
changes discussed above for Sec. Sec. 192.917, 192.921, 192.933, and
192.935. The proposed rule would require that the continual process of
evaluation and assessment implement and be consistent with data
integration and risk assessment information in order to identify the
threats specific to each HCA segment, including interacting threats,
and the risk represented by these threats (Sec. 192.917), selection
and use of assessment methods (Sec. 192.921), decisions about
remediation (Sec. 192.933), and identify additional preventive and
mitigative measures (Sec. 192.935) to avert or reduce threats to
acceptable levels.
Sec. 192.939 What are the required reassessment intervals?
Section 192.939 specifies reassessment intervals for pipelines
subject to integrity management requirements. Section 5 of the Act
includes a technical correction that clarified that periodic
reassessments must occur, at a minimum of once every 7 calendar years,
but that the Secretary may extend such deadline for an additional 6
months if the operator submits written notice to the Secretary with
sufficient justification of the need for the extension. PHMSA would
expect that any justification, at a minimum, would need to demonstrate
that the extension does not pose a safety risk. By this rulemaking,
PHMSA intends to codify this technical correction. The proposed rule
would implement this statutory requirement.
Sec. 192.941 What is a low stress reassessment?
Section 192.941, among other requirements, specifies that, to
address the threat of external corrosion on cathodically protected pipe
in a HCA segment, an operator must perform an electrical survey (i.e.
indirect examination tool/method) at least every 7 years on the HCA
segment. PHMSA proposes to make conforming edits to the language of
this requirement to accommodate the revised definition of the term
``electrical survey.'' To conform to the revised definition of
``electrical survey,'' the use of that term in Sec. 192.941 would be
replaced with ``indirect assessment'' to accommodate other techniques
in addition to close-interval surveys.
Appendix A to Part 192--Records Retention Schedule for Transmission
Pipelines
As discussed under Sec. 192.13, above, the proposed rule would
more clearly articulate the requirements for records preparation and
retention for transmission pipelines and to require that records be
reliable, traceable, verifiable, and complete. New appendix A to part
192 provides specific requirements and records retention periods.
Appendix D to Part 192--Criteria for Cathodic Protection and
Determination of Measurements
Appendix D to part 192 specifies requirements for cathodic
protection of steel, cast iron & ductile pipelines. PHMSA has
determined that this guidance needs to be updated to incorporate
lessons learned since this appendix was first promulgated in 1971. The
proposed rule would update appendix D accordingly by eliminating
outdated guidance on cathodic protection and interpretation of voltage
measurement to better align with current standards.
Appendix E to Part 192--Guidance on Determining High Consequence Areas
and on Carrying out Requirements in the Integrity Management Rule
Appendix E to part 192 provides guidance for preventive and
mitigative measures for HCA segment subject to subpart O. PHMSA
proposes to make conforming edits to the language in this appendix to
accommodate the revised definition of the term ``electrical survey.''
To conform to the revised definition of ``electrical survey,'' the use
of that term in Appendix E would be replaced with ``indirect
assessment'' to accommodate other techniques in addition to close-
interval surveys.
Appendix F to Part 192--Criteria for Conducting Integrity Assessments
Using Guided Wave Ultrasonic Testing (GWUT)
As discussed under Sec. 192.941 above, a new appendix F to part
192 is proposed to provide specific requirements and acceptance
criteria for the use of GWUT as an integrity assessment method.
Operators must apply all 18 criteria defined in Appendix F to use GWUT
as an integrity assessment method. If an operator applied GWUT
technology in a manner that does not conform to Appendix F, it would be
considered ``other technology'' in Sec. Sec. 192.710, 192.921, and
192. 937.
VI. Availability of Standards Incorporated by Reference
PHMSA currently incorporates by reference into 49 CFR parts 192,
193, and 195 all or parts of more than 60 standards and specifications
developed and published by standard developing organizations (SDOs). In
general, SDOs update and revise their published standards every 3 to 5
years to reflect modern technology and best technical practices.
The National Technology Transfer and Advancement Act of 1995 (Pub.
L. 104-113) directs Federal agencies to use voluntary consensus
standards in lieu of government-written standards whenever possible.
Voluntary consensus standards are standards developed or adopted by
voluntary bodies that develop, establish, or coordinate technical
standards using agreed-upon procedures. In addition, Office of
Management and Budget (OMB) issued OMB Circular A-119 to implement
Section 12(d) of Public Law 104-113 relative to the utilization of
consensus technical standards by
[[Page 20821]]
Federal agencies. This circular provides guidance for agencies
participating in voluntary consensus standards bodies and describes
procedures for satisfying the reporting requirements in Public Law 104-
113.
In accordance with the preceding provisions, PHMSA has the
responsibility for determining, via petitions or otherwise, which
currently referenced standards should be updated, revised, or removed,
and which standards should be added to 49 CFR parts 192, 193, and 195.
Revisions to incorporated by reference materials in 49 CFR parts 192,
193, and 195 are handled via the rulemaking process, which allows for
the public and regulated entities to provide input. During the
rulemaking process, PHMSA must also obtain approval from the Office of
the Federal Register to incorporate by reference any new materials.
On January 3, 2012, President Obama signed the Pipeline Safety,
Regulatory Certainty, and Job Creation Act of 2011, Public Law 112-90.
Section 24 states: ``Beginning 1 year after the date of enactment of
this subsection, the Secretary may not issue guidance or a regulation
pursuant to this chapter that incorporates by reference any documents
or portions thereof unless the documents or portions thereof are made
available to the public, free of charge, on an Internet Web site.'' 49
U.S.C. 60102(p).
On August 9, 2013, Public Law 113-30 revised 49 U.S.C. 60102(p) to
replace ``1 year'' with ``3 years'' and remove the phrases ``guidance
or'' and ``, on an Internet Web site.'' This resulted in the current
language in 49 U.S.C. 60102(p), which now reads as follows:
``Beginning 3 years after the date of enactment of this subsection,
the Secretary may not issue a regulation pursuant to this chapter that
incorporates by reference any documents or portions thereof unless the
documents or portions thereof are made available to the public, free of
charge.''
Further, the Office of the Federal Register issued a November 7,
2014, rulemaking (79 FR 66278) that revised 1 CFR 51.5 to require that
agencies detail in the preamble of a proposed rulemaking the ways the
materials it proposes to incorporate by reference are reasonably
available to interested parties, or how the agency worked to make those
materials reasonably available to interested parties. In relation to
this proposed rulemaking, PHMSA has contacted each SDO and has
requested a hyperlink to a free copy of each standard that has been
proposed for incorporation by reference. Access to these standards will
be granted until the end of the comment period for this proposed
rulemaking. Access to these documents can be found on the PHMSA Web
site at the following URL: https://www.phmsa.dot.gov/pipeline/regs under
``Standards Incorporated by Reference.''
Consistent with the proposed amendments in this document, PHMSA
proposes to incorporate by reference the following materials identified
as follows:
API Standard 1163-2005, ``In-line Inspection Systems
Qualification Standards.''--This Standard serves as an umbrella
document to be used with and complement companion standards. NACE
RP0102 Standard Recommended Practice, In-Line Inspections of Pipelines;
and ASNT ILI-PQ In-Line Inspection Personnel Qualification &
Certification all have been developed enabling service providers and
pipeline operators to provide rigorous processes that will consistently
qualify the equipment, people, processes and software utilized in the
in-line inspection industry.
NACE Standard Practice 0102-2010, ``Inline Inspection of
Pipelines.''--This standard is intended for use by individuals and
teams planning, implementing, and managing ILI projects and programs.
The incorporation of this standard into the Federal pipeline safety
regulations would promote a higher level of safety by establishing
consistent standards to qualify the equipment, people, processes, and
software utilized by the ILI industry.
NACE Standard Practice 0204-2008, ``Stress Corrosion
Cracking Direct Assessment.''--The standard practice for SCCDA
presented in this standard addresses the situation in which a pipeline
company has identified a portion of its pipeline as an area of interest
with respect to SCC based on its history, operations, and risk
assessment process and has decided that direct assessment is an
appropriate approach for integrity assessment. This standard provides
guidance for managing SCC by selecting potential pipeline segments,
selecting dig sites within those segments, inspecting the pipe,
collecting and analyzing data during the dig, establishing a mitigation
program, defining the reevaluation interval, and evaluating the
effectiveness of the SCCDA process.
NACE Standard Practice 0206-2006, ``International
Corrosion Direct Assessment Methodology for Pipelines Carrying Normally
Dry Natural Gas.'' This standard covers the NACE internal corrosion
direct assessment (ICDA) process for normally dry natural gas pipeline
systems. This standard is intended to serve as a guide for applying the
NACE DG-ICDA process on natural gas pipeline systems that meet the
feasibility requirements of Paragraph 3.3 of this standard.
ANSI/ASNT ILI-PQ-2010, ``In-line Inspection Personnel
Qualification and Certification.'' The ASNT standard provides for
qualification and certification requirements that are not addressed in
part 192. The incorporation of this standard into the Federal pipeline
safety regulations would promote a higher level of safety by
establishing consistent standards to qualify the equipment, people,
processes, and software utilized by the ILI industry.
Battelle's Experience with ERW and Flash Welding Seam
Failures: Causes and Implications (Task 1.4). This report presents an
evaluation of the database dealing with failures originating in
electric resistance welds (ERW) and flash weld (FW) seam defects as
quantified by Battelle's archives and the related literature.
Battelle Memorial Institute, ``Models for Predicting
Failure Stress Levels for Defects Affecting ERW and Flash-Welded
Seams'' (Subtask 2.4). This document presents an analysis of two known
defect assessment methods in an effort to find suitable ways to
satisfactorily predict the failure stress levels of defects in or
adjacent to ERW or flash-welded line pipe seams.
Battelle Final Report No. 13-021, ``Predicting Times to
Failures for ERW Seam Defects that Grow by Pressure Cycle Induced
Fatigue (Subtask 2.5).'' The work described in this report is part of a
comprehensive study of ERW seam integrity and its impact on pipeline
safety. The objective of this part of the work is to identify
appropriate means for predicting the remaining lives of defects that
remain after a seam integrity assessment and that may become enlarged
by pressure-cycle-induced fatigue.
Battelle Memorial Institute, ``Final Summary Report and
recommendations for the Comprehensive Study to Understand Longitudinal
ERW Seam Failures--Phase 1'' (Task 4.5).--This report summarizes work
completed as part of a comprehensive project that resulted from a
contract with Battelle, working with Kiefner and Associates (KAI) and
Det Norske Veritas (DNV) as subcontractors, to address the concerns
identified in NTSB recommendation (P-09-1) regarding the safety and
performance of ERW pipe.
[[Page 20822]]
VII. Regulatory Analysis and Notices
This proposed rule 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 design,
installation, inspection, emergency plans and procedures, testing,
construction, extension, operation, replacement, and maintenance of
pipeline facilities. The amendments to the requirements for petroleum
gas pipelines addressed in this rulemaking are issued under this
authority.
Executive Orders 12866 and 13563, and DOT Policies and Procedures
This proposed rule is a significant regulatory action under section
3(f) of Executive Order 12866 and, therefore, was reviewed by the
Office of Management and Budget. This proposed rule is significant
under the Regulatory Policies and Procedures of the Department of
Transportation.
(44 FR 11034, February 26, 1979).
Executive Orders 12866 and 13563 require that proposed rules deemed
``significant'' include a Regulatory Impact Analysis, and that this
analysis requires quantified estimates of the benefits and costs of the
rule. PHMSA is providing the PRIA for this proposed rule simultaneously
with this document, and it is available in the docket.
PHMSA estimates the total present value of benefits from the
proposed rule to be approximately $3,234 to $3,738 million \39\ using a
7% discount rate ($4,050 to $4,663 million using a 3% discount rate)
and the present value of costs to be approximately $597 million using a
7% discount rate ($711 million using a 3% discount rate). The table in
the executive summary provides a detailed estimate of the average
annual costs and benefits for each major topic area.
---------------------------------------------------------------------------
\39\ Range reflects uncertainty in defect failure rates for
Topic Area 1.
---------------------------------------------------------------------------
Regulatory Flexibility Act
The Regulatory Flexibility Act (RFA), as amended by the Small
Business Regulatory Flexibility Fairness Act of 1996, requires Federal
regulatory agencies to prepare an Initial Regulatory Flexibility
Analysis (IFRA) for any proposed rule subject to notice-and-comment
rulemaking under the Administrative Procedure Act unless the agency
head certifies that the making will not have a significant economic
impact on a substantial number of small entities. PHMSA has data on gas
transmission pipeline operators affected by the proposed rule. However,
PHMSA does not have data on currently unregulated gas gathering
pipeline operators. Therefore, PHMSA prepared an IFRA which is
available in the docket for the rulemaking.
Executive Order 13175
PHMSA has analyzed this proposed rule according to the principles
and criteria in Executive Order 13175, ``Consultation and Coordination
with Indian Tribal Governments.'' Because this proposed rule would not
significantly or uniquely affect the communities of the Indian tribal
governments or impose substantial direct compliance costs, the funding
and consultation requirements of Executive Order 13175 do not apply.
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 rulemaking will
impact the information collections described below.
Based on the proposals in this rule, PHMSA will submit an
information collection revision request to OMB for approval based on
the requirements in this proposed rule. The information collection is
contained in the pipeline safety regulations, 49 CFR parts 190 through
199. The following information is provided for each information
collection: (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
burden for the following information collections are estimated to be
revised as follows:
1. Title: Recordkeeping Requirements for Gas Pipeline Operators.
OMB Control Number: 2137-0049.
Current Expiration Date: 04/30/2018.
Abstract: A person owning or operating a natural gas pipeline
facility is required to maintain records, make reports, and provide
information to the Secretary of Transportation at the Secretary's
request. Based on the proposed revisions in this rule, PHMSA estimates
that 100 new Type A, Area 2 gas gathering pipeline operators ~ (2200
Type A, Area 2 miles w/o prior regulation/22) will be new to these
requirements. PHMSA estimates that it will take these 100 operators 6
hours to create and maintain records associated with Emergency Planning
requirements. Therefore, PHMSA expects to add 100 responses and 600
hours to this information collection as a result of the provisions in
the proposed rule.
Affected Public: Natural Gas Pipeline Operators.
Annual Reporting and Recordkeeping Burden:
Total Annual Responses: 12,400.
Total Annual Burden Hours: 941,054.
Frequency of Collection: On occasion.
2. Title: Reporting Safety-Related Conditions on Gas, Hazardous
Liquid, and Carbon Dioxide Pipelines and Liquefied Natural Gas
Facilities.
OMB Control Number: 2137-0578.
Current Expiration Date: 7/31/2017.
Abstract: 49 U.S.C. 60102 requires each operator of a pipeline
facility (except master meter operators) to submit to DOT a written
report on any safety-related condition that causes or has caused a
significant change or restriction in the operation of a pipeline
facility or a condition that is a hazards to life, property or the
environment. Based on the proposed revisions in this rule, PHMSA
estimates that an additional 71,109 miles of pipe will become subject
to the safety related condition reporting requirements. PHMSA estimates
that such reports will be submitted at a rate of 0.23 reports per 1,000
miles. PHMSA expects that, collectively, Type A, Area 2 lines will
submit approximately 16 reports on an annual basis. As a result, PHMSA
is adding an additional 16 responses and 96 burden hours to this
information collection.
Affected Public: Operators of Natural Gas, Hazardous Liquid, and
Liquefied Natural Gas pipelines.
Annual Reporting and Recordkeeping Burden:
Total Annual Responses: 158.
Total Annual Burden Hours: 948.
Frequency of Collection: On occasion.
3. Title: Pipeline Integrity Management in High Consequence Areas
Gas Transmission Pipeline Operators.
OMB Control Number: 2137-0610.
Current Expiration Date: 3/31/2016.
Abstract: This information collection request pertains to Gas
Transmission operators jurisdictional to 49 CFR part 192 subpart O--Gas
Transmission Integrity Management Program. PHMSA is proposing that
operators subject to Integrity Management requirements provide PHMSA
notice when 180 days is insufficient to conduct an integrity assessment
following the discovery of a condition (192.933). PHMSA estimates that
20% of the 721 operators (721*.2 =
[[Page 20823]]
144 operators) will file such a notification. PHMSA estimates that each
notification will take about 30 minutes. Based on this provision, PHMSA
proposes to add 144 responses and 72 hours to this information
collection.
Affected Public: Gas Transmission operators.
Annual Reporting and Recordkeeping Burden:
Total Annual Responses: 877.
Total Annual Burden Hours: 1,018,879.
Frequency of Collection: On occasion.
4. Title: Incident and Annual Reports for Gas Pipeline Operators.
OMB Control Number: 2137-0522.
Current Expiration Date: 10/31/2017.
Abstract: This information collection covers the collection of
information from Gas pipeline operators for Incidents and Annual
reports. PHMSA is revising the Gas Transmission Incident report to
incorporate Moderate Consequence Areas and to address Gathering line
operators that are only subject to reporting. PHMSA estimates that
operators of currently exempt gas gathering pipelines will have to
submit incident reports for 27.5 incidents over the next three years,
an average of 9 reports annually. However, the proposed rule is
expected to reduce the number of incidents by at least 10 each year
which would result in a cumulative increase of zero incidents.
PHMSA is also revising the Gas Transmission and Gas Gathering
Annual Report to collect additional information including mileage of
pipe subject to the IVP and MCA criteria. Based on the proposed
revisions, PHMSA estimates that an additional annual 500 reports to the
current 1,440 reports will be submitted based on the required reporting
of non-regulated gathering lines and gathering lines now subject to
certain safety provisions. Further PHMSA estimates that the Annual
report will require an additional 5 hours/report to the currently
approved 42 hours due to collection of MCA data and IVP provisions.
Therefore the overall burden allotted for the reporting of Gas annual
reports will increase by 30,700 hours from 60,480 hours (42 hours*1,440
reports) to 91,180 hours (47 hours*1,940 reports).
As a result of the provisions mentioned above, the burden for this
information collection will increase by 500 responses and 30,700 burden
hours.
Affected Public: Natural Gas Pipeline Operators.
Annual Reporting and Recordkeeping Burden:
Total Annual Responses: 12,664.
Total Annual Burden Hours: 103,182
Frequency of Collection: On occasion.
5. Title: National Registry of Pipeline and LNG Operators.
OMB Control Number: 2137-0627.
Current Expiration Date: 05/31/2018.
Abstract: The National Registry of Pipeline and LNG Operators
serves as the storehouse for the reporting requirements for an operator
regulated or subject to reporting requirements under 49 CFR part 192,
193, or 195. This registry incorporates the use of two forms. The forms
for assigning and maintaining Operator Identification (OPID)
information are the Operator Assignment Request Form (PHMSA F 1000.1)
and Operator Registry Notification Form (PHMSA F 1000.2). PHMSA plans
to make revisions to the form/instructions to account for ``reporting
only'' gathering operators. PHMSA estimates that 500 gas gathering
operators will require a new OPID. Based on a 3 year average this
results in an additional 167 responses a year initially. In addition to
the OPID assignment, PHMSA estimates that 123 gathering operators will
submit approx. 1 notification per year. PHMSA estimates that each
submission will take approx. 1 hour to complete. Based on these
provisions, PHMSA expects this information collection to increase by
290 responses and 290 burden hours.
Affected Public: Operators of Natural Gas, Hazardous Liquid, and
Liquefied Natural Gas pipelines.
Annual Reporting and Recordkeeping Burden:
Total Annual Responses: 920.
Total Annual Burden Hours: 920.
Frequency of Collection: On occasion.
Requests for copies of these information collections should be
directed to Angela Dow or Cameron Satterthwaite, Office of Pipeline
Safety (PHP-30), Pipeline Hazardous Materials Safety Administration
(PHMSA), 2nd Floor, 1200 New Jersey Avenue SE., Washington, DC 20590-
0001, Telephone (202) 366-4595.
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.
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 June 7, 2016.
Unfunded Mandates Reform Act of 1995
An evaluation of Unfunded Mandates Reform Act (UMRA) considerations
is performed as part of the Preliminary Regulatory Impact Assessment.
The estimated costs to the States are approximately $1.3 million per
year and are significantly less than the UMRA criterion of $151 million
per year ($100 million, adjusted for inflation). The estimated costs to
the private sector are in excess of the UMRA criterion of $151 million
per year. A copy of the Preliminary Regulatory Impact Assessment is
available for review in the docket.
National Environmental Policy Act
PHMSA analyzed this proposed rule 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 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 proposed action is in the docket.
Executive Order 13132
PHMSA has analyzed this proposed rule according to Executive Order
13132 (``Federalism''). The proposed rule does not have a substantial
direct effect 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. This proposed
rule does not impose substantial direct compliance costs on State and
local governments. This proposed rule would not preempt state law for
intrastate pipelines. Therefore, the consultation and funding
requirements of Executive Order 13132 do not apply.
Executive Order 13211
This proposed rule is not 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
[[Page 20824]]
supply, distribution, or energy use. Further, the Office of Information
and Regulatory Affairs has not designated this proposed rule as a
significant energy action.
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
in the Federal Register published on April 11, 2000 (70 FR 19477) or
visit https://dms.dot.gov.
Regulation Identifier Number (RIN)
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 number contained in the heading
of this document can be used to cross-reference this action with the
Unified Agenda.
List of Subjects
49 CFR Part 191
Pipeline reporting requirements, Integrity Management, Pipeline
safety, Gas gathering.
49 CFR Part 192
Incorporation by reference, Pipeline Safety, Fire prevention,
Security measures.
In consideration of the foregoing, PHMSA proposes to amend 49 CFR
parts 191 and 192 as follows:
PART 191--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE;
ANNUAL, INCIDENT, AND OTHER REPORTING
0
1. The authority citation for part 191 is revised to read as follows:
Authority: 49 U.S.C. 5121, 60102, 60103, 60104, 60108, 60117,
60118, 60124, 60132, and 60139; and 49 CFR 1.97.
0
2. In Sec. 191.1, paragraphs (a) and (b)(2) and (3) are revised,
paragraph (b)(4) is deleted, and paragraph (c) is added to read as
follows:
Sec. 191.1 Scope.
(a) This part prescribes requirements for the reporting of
incidents, safety-related conditions, exceedances of maximum allowable
operating pressure (MAOP), annual pipeline summary data, National
Operator Registry information, and other miscellaneous conditions by
operators of gas pipeline facilities located in the United States or
Puerto Rico, including pipelines within the limits of the Outer
Continental Shelf as that term is defined in the Outer Continental
Shelf Lands Act (43 U.S.C. 1331). This part applies to offshore
gathering lines and to onshore gathering lines, whether designated as
``regulated onshore gathering lines'' or not (as determined in Sec.
192.8 of this chapter).
(b) * * *
(2) Pipelines on the Outer Continental Shelf (OCS) that are
producer-operated and cross into State waters without first connecting
to a transporting operator's facility on the OCS, upstream (generally
seaward) of the last valve on the last production facility on the OCS.
Safety equipment protecting PHMSA-regulated pipeline segments is not
excluded. Producing operators for those pipeline segments upstream of
the last valve of the last production facility on the OCS may petition
the Administrator, or designee, for approval to operate under PHMSA
regulations governing pipeline design, construction, operation, and
maintenance under 49 CFR 190.9; or
(3) Pipelines on the Outer Continental Shelf upstream of the point
at which operating responsibility transfers from a producing operator
to a transporting operator.
(c) Sections 191.22(b) and 191.29 do not apply to gathering of
gas--
(1) Through a pipeline that operates at less than 0 psig (0 kPa);
(2) Through an onshore pipeline that is not a regulated onshore
gathering line (as determined in Sec. 192.8 of this chapter); and
(3) Within inlets of the Gulf of Mexico, except for the
requirements in Sec. 192.612.
0
3. In Sec. 191.23, revise paragraph (a)(5), add paragraph (a)(9), and
revise paragraph (b)(4) to read as follows:
Sec. 191.23 Reporting safety-related conditions.
(a) * * **
(5) Any malfunction or operating error that causes the pressure of
a distribution or gathering pipeline or LNG facility that contains or
processes gas or LNG to rise above its maximum allowable operating
pressure (or working pressure for LNG facilities) plus the margin
(build-up) allowed for operation of pressure limiting or control
devices.
* * * * *
(9) For transmission pipelines, each exceedance of the maximum
allowable operating pressure that exceeds the margin (build-up) allowed
for operation of pressure-limiting or control devices as specified in
Sec. Sec. 192.201, 192.620(e), and 192.739, as applicable.
(b) * * *
(4) Is corrected by repair or replacement in accordance with
applicable safety standards before the deadline for filing the safety-
related condition report, except that reports are required for
conditions under paragraph (a)(1) of this section other than localized
corrosion pitting on an effectively coated and cathodically protected
pipeline and any condition under paragraph (a)(9) of this section.
0
4. Section 191.25 is revised to read as follows:
Sec. 191.25 Filing safety-related condition reports.
(a) Each report of a safety-related condition under Sec.
191.23(a)(1) through (8) must be filed (received by the Associate
Administrator, OPS) within five working days (not including Saturday,
Sunday, or Federal Holidays) after the day a representative of the
operator first determines that the condition exists, but not later than
10 working days after the day a representative of the operator
discovers the condition. Separate conditions may be described in a
single report if they are closely related. Reports may be transmitted
by electronic mail to InformationResourcesManager@dot.gov or by
facsimile at (202) 366-7128.
(b) Each report of a maximum allowable operating pressure
exceedance meeting the requirements of criteria in Sec. 191.23(a)(9)
for a gas transmission pipeline must be reported within five calendar
days of the exceedance using the reporting methods and report
requirements described in Sec. 191.25(c).
(c) Reports may be filed by emailing information to
InformationResourcesManager@dot.gov.or by fax to (202) 366-7128. The
report must be headed ``Safety-Related Condition Report'' or for Sec.
191.23(a)(9) ``Maximum Allowable Operating Pressure Exceedances'', and
provide the following information:
(1) Name, principal address, and operator identification number
(OPID) of operator.
(2) Date of report.
(3) Name, job title, and business telephone number of person
submitting the report.
(4) Name, job title, and business telephone number of person who
determined that the condition exists.
(5) Date condition was discovered and date condition was first
determined to exist.
(6) Location of condition, with reference to the State (and town,
city, or county) or Offshore site, and as appropriate, nearest street
address, offshore platform, survey station number, milepost, landmark,
or name of pipeline.
(7) Description of the condition, including circumstances leading
to its discovery, any significant effects of the
[[Page 20825]]
condition on safety, and the name of the commodity transported or
stored.
(8) The corrective action taken (including reduction of pressure or
shutdown) before the report is submitted and the planned follow-up
future corrective action, including the anticipated schedule for
starting and concluding such action.
0
4a. In Sec. 191.29, paragraph (c) is added to read as follows:
Sec. 191.29 National Pipeline Mapping System.
* * * * *
(c) This section does not apply to gathering lines.
PART 192--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE:
MINIMUM FEDERAL SAFETY STANDARDS
0
5. The authority citation for part 192 is revised to read as follows:
Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110,
60113, 60116, 60118, 60137, and 60139; and 49 CFR 1.97.
0
6. In Sec. 192.3:
0
a. Add definitions for ``Close interval survey'', ``Distribution
center'', and ``Dry gas or dry natural gas'' in alphabetical order;
0
b. Revise the definition of ``Electrical survey'';
0
c. Add definitions for ``Gas processing plant'' and ``Gas treatment
facility,'' in alphabetical order;
0
d. Revise the definition of ``Gathering line'';
0
e. Add definitions for ``Hard spot'', ``In-line inspection (ILI)'',
``In-line inspection tool or instrumented internal inspection device'',
``Legacy construction techniques'', ``Legacy pipe'', ``Moderate
consequence area'', ``Modern pipe'', ``Occupied site'', ``Onshore
production facility/operation'', ``Significant seam cracking'',
``Significant stress corrosion cracking'', in alphabetical order;
0
f. Revise the definition of ``Transmission line'' and its note; and
0
g. Add a definition for ``Wrinkle bend'' in alphabetical order.
The additions and revisions to read as follows:
Sec. 192.3 Definitions.
* * * * *
Close interval survey means a series of closely spaced pipe-to-
electrolyte potential measurements taken to assess the adequacy of
cathodic protection or to identify locations where a current may be
leaving the pipeline that may cause corrosion and for the purpose of
quantifying voltage (IR) drops other than those across the structure
electrolyte boundary.
* * * * *
Distribution center means a location where gas volumes are either
metered or have pressure or volume reductions prior to delivery to
customers through a distribution line.
* * * * *
Dry gas or dry natural gas means gas with less than 7 pounds of
water per million (MM) cubic feet and not subject to excessive upsets
allowing electrolytes into the gas stream.
Electrical survey means a series of closely spaced measurements of
the potential difference between two reference electrodes to determine
where the current is leaving the pipe on ineffectively coated or bare
pipelines.
* * * * *
Gas processing plant means a natural gas processing operation,
other than production processing, operated for the purpose of
extracting entrained natural gas liquids and other associated non-
entrained liquids from the gas stream and does not include a natural
gas processing plant located on a transmission line, commonly referred
to as a straddle plant.
Gas treatment facility means one or a series of gas treatment
operations, operated for the purpose of removing impurities (e.g.,
water, solids, basic sediment and water, sulfur compounds, carbon
dioxide, etc.) that is not associated with a processing plant or
compressor station and is not on a transmission line.
Gathering line (Onshore) means a pipeline, or a connected series of
pipelines, and equipment used to collect gas from the endpoint of a
production facility/operation and transport it to the furthermost point
downstream of the endpoints described in paragraphs (1) through (4) of
this definition:
(1) The inlet of 1st gas processing plant, unless the operator
submits a request for approval to the Associate Administrator of
Pipeline Safety that demonstrates, using sound engineering principles,
that gathering extends to a further downstream plant other than a plant
located on a transmission line and the Associate Administrator of
Pipeline Safety approves such request;
(2) The outlet of gas treatment facility that is not associated
with a processing plant or compressor station;
(3) Outlet of the furthermost downstream compressor used to
facilitate delivery into a pipeline, other than another gathering line;
or
(4) The point where separate production fields are commingled,
provided the distance between the interconnection of the fields does
not exceed 50 miles, unless the Associate Administrator of Pipeline
Safety finds a longer separation distance is justified in a particular
case (see Sec. 190.9 of this chapter).
(5) Gathering may continue beyond the endpoints described in
paragraphs (1) through (4) of this definition to the point gas is
delivered into another pipeline, provided that it only does the
following:
(i) It delivers gas into another gathering line;
(A) It does not leave the operator's facility surface property
(owned or leased, not necessarily the fence line);
(B) It does not leave an adjacent property owned or leased by
another pipeline operator's property--where custody transfer takes
place; or
(C) It does not exceed a length of one mile, and it does not cross
a state or federal highway or an active railroad; or
(ii) It transports gas to production or gathering facilities for
use as fuel, gas lift, or gas injection gas.
(6) Pipelines that serve residential, commercial, or industrial
customers that originate at a tap on gathering lines are not gathering
lines; they are service lines and are commonly referred to as farm
taps.
* * * * *
Hard spot means steel pipe material with a minimum dimension
greater than two inches (50.8 mm) in any direction and hardness greater
than or equal to Rockwell 35 HRC (Brinnel 327 HB or Vickers 345 HV10).
* * * * *
In-line inspection (ILI) means the inspection of a pipeline from
the interior of the pipe using an in-line inspection tool, which is
also called intelligent or smart pigging.
In-line inspection tool or instrumented internal inspection device
means a device or vehicle that uses a non-destructive testing technique
to inspect the pipeline from the inside, which is also called an
intelligent or smart pig.
Legacy construction techniques mean usage of any historic, now-
abandoned, construction practice to construct or repair pipe segments,
including any of the following techniques:
(1) Wrinkle bends;
(2) Miter joints exceeding three degrees;
(3) Dresser couplings;
(4) Non-standard fittings or field fabricated fittings (e.g.,
orange-peeled reducers) with unknown pressure ratings;
(5) Acetylene welds;
[[Page 20826]]
(6) Bell and spigots; or
(7) Puddle welds.
Legacy pipe means steel pipe manufactured using any of the
following techniques, regardless of the date of manufacture:
(1) Low-Frequency Electric Resistance Welded (LF-ERW);
(2) Direct-Current Electric Resistance Welded (DC-ERW);
(3) Single Submerged Arc Welded (SSAW);
(4) Electric Flash Welded (EFW);
(5) Wrought iron;
(6) Pipe made from Bessemer steel; or
(7) Any pipe with a longitudinal joint factor, as defined in Sec.
192.113, less than 1.0 (such as lap-welded pipe) or with a type of
longitudinal joint that is unknown or cannot be determined, including
pipe of unknown manufacturing specification.
* * * * *
Moderate consequence area means an onshore area that is within a
potential impact circle, as defined in Sec. 192.903, containing five
(5) or more buildings intended for human occupancy, an occupied site,
or a right-of-way for a designated interstate, freeway, expressway, and
other principal 4-lane arterial roadway as defined in the Federal
Highway Administration's Highway Functional Classification Concepts,
Criteria and Procedures, and does not meet the definition of high
consequence area, as defined in Sec. 192.903. The length of the
moderate consequence area extends axially along the length of the
pipeline from the outermost edge of the first potential impact circle
that contains either an occupied site, five (5) or more buildings
intended for human occupancy, or a right-of-way for a designated
interstate, freeway, expressway, or other principal 4-lane arterial
roadway, to the outermost edge of the last contiguous potential impact
circle that contains either an occupied site, five (5) or more
buildings intended for human occupancy, or a right-of-way for a
designated interstate, freeway, expressway, or other principal 4-lane
arterial roadway.
Modern pipe means any steel pipe that it is not legacy pipe,
regardless of the date of manufacture, and has a longitudinal joint
factor of 1.0 as defined in Sec. 192.113. Modern pipe refers to all
pipe that is not legacy pipe.
* * * * *
Occupied site means each of the following areas:
(1) An outside area or open structure that is occupied by five (5)
or more persons on at least 50 days in any twelve (12)-month period.
(The days need not be consecutive.) Examples include but are not
limited to, beaches, playgrounds, recreational facilities, camping
grounds, outdoor theaters, stadiums, recreational areas near a body of
water, or areas outside a rural building such as a religious facility;
or
(2) A building that is occupied by five (5) or more persons on at
least five (5) days a week for ten (10) weeks in any twelve (12)-month
period. (The days and weeks need not be consecutive.) Examples include,
but are not limited to, religious facilities, office buildings,
community centers, general stores, 4-H facilities, or roller skating
rinks.
* * * * *
Onshore production facility or onshore production operation means
wellbores, equipment, piping, and associated appurtenances confined to
the physical acts of extraction or recovery of gas from the earth and
the initial preparation for transportation. Preparation for
transportation does not necessarily mean the gas will meet ``pipeline
quality'' specifications as may be commonly understood or contained in
many contractual agreements. Piping as used in this definition may
include individual well flow lines, equipment piping, and transfer
lines between production operation equipment components. Production
facilities terminate at the furthermost downstream point where:
Measurement for the purposes of calculating minerals severance occurs;
or there is commingling of the flow stream from two or more wells.
* * * * *
Significant seam cracking means cracks or crack-like flaws in the
longitudinal seam or heat affected zone of a seam weld where the
deepest crack is greater than or equal to 10% of wall thickness or the
total interacting length of the cracks is equal to or greater than 75%
of the critical length of a 50% through-wall flaw that would fail at a
failure pressure less than or equal to 110% of SMYS, as determined in
accordance with fracture mechanics failure pressure evaluation methods
(Sec. Sec. 192.624(c) and (d)) for the failure mode using conservative
Charpy energy values of the crack-related conditions.
Significant stress corrosion cracking means a stress corrosion
cracking (SCC) cluster in which the deepest crack, in a series of
interacting cracks, is greater than 10% of the wall thickness and the
total interacting length of the cracks is equal to or greater than 75%
of the critical length of a 50% through-wall flaw that would fail at a
stress level of 110% of SMYS.
* * * * *
Transmission line means a pipeline, other than a gathering line,
that: transports gas from a gathering line or storage facility to a
distribution center, storage facility, or large volume customer that is
not down-stream from a distribution center; has an MAOP of 20 percent
or more of SMYS; or transports gas within a storage field.
Note: A large volume customer (factories, power plants, and
institutional users of gas) may receive similar volumes of gas as a
distribution center.
* * * * *
Wrinkle bend. (1) Means a bend in the pipe that was formed in the
field during construction such that the inside radius of the bend has
one or more ripples with:
(i) An amplitude greater than or equal to 1.5 times the wall
thickness of the pipe, measured from peak to valley of the ripple; or
(ii) With ripples less than 1.5 times the wall thickness of the
pipe and with a wrinkle length (peak to peak) to wrinkle height (peak
to valley) ratio under 12.
[GRAPHIC] [TIFF OMITTED] TP08AP16.000
[[Page 20827]]
D = The outside diameter of the pipe, in. (mm),
h = The crest-to-trough height of the ripple, in. (mm), and
S = The maximum operating hoop stress, psi (S/145, MPa).
0
7. In Sec. 192.5, paragraph (d) is added to read as follows:
Sec. 192.5 Class locations.
* * * * *
(d) Records for transmission pipelines documenting class locations
and demonstrating how an operator determined class locations in
accordance with this section must be retained for the life of the
pipeline.
0
8. Amend Sec. 192.7 by removing and reserving paragraph (b)(4) and
adding paragraphs (b)(10), (g)(2) through (4), (k), and (l).
The additions read as follows:
Sec. 192.7 What documents are incorporated by reference partly or
wholly in this part?
* * * * *
(b) * * *
(10) API STD 1163-2005, ``In-Line Inspection Systems Qualification
Standard,'' 1st edition, August 2001, (API STD 1163), IBR approved for
Sec. 192.493.
* * * * *
(g) * * *
(2) NACE Standard Practice 0102-2010, ``Inline Inspection of
Pipelines,'' Revised 2010, (NACE SP0102), IBR approved for Sec. Sec.
192.150(a) and 192.493.
(3) NACE Standard Practice 0204-2008, ``Stress Corrosion Cracking
Direct Assessment,'' Revised 2008, (NACE SP0204), Reaffirmed 2008, IBR
approved for Sec. Sec. 192.923(b)(3) and 192.929.
(4) NACE Standard Practice 0206-2006, ``International Corrosion
Direct Assessment Methodology for Pipelines Carrying Normally Dry
Natural Gas,'' (NACE SP0206-2006), IBR approved for Sec. Sec.
192.923(b)(2), 192.927(b), and 192.927(c).
* * * * *
(k) American Society for Nondestructive Testing (ASNT), P.O. Box
28518, 1711 Arlingate Lane, Columbus, OH 43228, phone (800) 222-2768,
https://www.asnt.org/.
(1) ANSI/ASNT ILI-PQ-2010, ``In-line Inspection Personnel
Qualification and Certification,'' 2010, (ANSI/ASNT ILI-PQ-2010), IBR
approved for Sec. 192.493.
(2) [Reserved]
(l) Battelle Memorial Institute, 505 King Avenue, Columbus, OH
43201, phone (800) 201-2011, https://www.battelle.org/.
(1) Battelle's Experience with ERW and Flash Welding Seam Failures:
Causes and Implications (Task 1.4), IBR approved for Sec. 192.624(c)
and (d).
(2) Battelle Memorial Institute, ``Models for Predicting Failure
Stress Levels for Defects Affecting ERW and Flash-Welded Seams''
(Subtask 2.4), IBR approved for Sec. 192.624(c) and (d).
(3) Battelle Final Report No. 13-021, ``Predicting Times to
Failures for ERW Seam Defects that Grow by Pressure Cycle Induced
Fatigue (Subtask 2.5), IBR approved for Sec. 192.624(c) and (d).
(4) Battelle Memorial Institute, ``Final Summary Report and
recommendations for the Comprehensive Study to Understand Longitudinal
ERW Seam Failures--Phase 1'' (Task 4.5), IBR approved for Sec.
192.624(c) and (d).
0
9. Section 192.8 is revised to read as follows:
Sec. 192.8 How are onshore gathering lines and regulated onshore
gathering lines determined?
(a) Each operator must determine and maintain records documenting
the beginning and endpoints of each gathering line it operates using
the definitions of onshore production facility (or onshore production
operation), gas processing facility, gas treatment facility, and
onshore gathering line as defined in Sec. 192.3 by [date 6 months
after effective date of the final rule] or before the pipeline is
placed into operation, whichever is later.
(b) Each operator must determine and maintain records documenting
the beginning and endpoints of each regulated onshore gathering line it
operates as determined in Sec. 192.8(c) by [date 6 months after
effective date of the final rule] or before the pipeline is placed into
operation, whichever is later.
(c) For purposes of part 191 of this chapter and Sec. 192.9,
``regulated onshore gathering line'' means:
(1) Each onshore gathering line (or segment of onshore gathering
line) with a feature described in the second column that lies in an
area described in the third column; and
(2) As applicable, additional lengths of line described in the
fourth column to provide a safety buffer:
----------------------------------------------------------------------------------------------------------------
Type Feature Area Safety buffer
----------------------------------------------------------------------------------------------------------------
A................................... --Metallic and the MAOP Area 1. Class 2, 3, or None.
produces a hoop stress 4 location (see Sec.
of less than 20 percent 192.5).
of SMYS. If the stress Area 2. Class 1
level is unknown, an location with a
operator must determine nominal diameter of 8
the stress level inches or greater.
according to the
applicable provisions
in subpart C of this
part.
--Non-metallic and the
MAOP is more than 125
psig (862 kPa).
B................................... --Non-metallic and the Area 1. Class 3, or 4 If the gathering line
MAOP produces a hoop location. is in Area 2(b) or
stress of less than 20 Area 2. An area within 2(c), the additional
percent of SMYS. If the a Class 2 location the lengths of line extend
stress level is operator determines by upstream and
unknown, an operator using any of the downstream from the
must determine the following three area to a point where
stress level according methods:. the line is at least
to the applicable (a) A Class 2 location; 150 feet (45.7 m) from
provisions in subpart C (b) An area extending the nearest dwelling
of this part. 150 feet (45.7 m) on in the area. However,
--Non-metallic and thew each side of the if a cluster of
MAOP is 125 psig (862 centerline of any dwellings in Area 2(b)
kPa) or less. continuous 1 mile (1.6 or 2(c) qualifies a
km) of pipeline and line as Type B, the
including more than 10 Type B classification
but fewer than 46 ends 150 feet (45.7 m)
dwellings; or. from the nearest
(c) An area extending dwelling in the
150 feet (45.7 m) on cluster.
each side of the
centerline of any
continuous 1000 feet
(305 m) of pipeline
and including 5 or
more dwellings..
----------------------------------------------------------------------------------------------------------------
[[Page 20828]]
0
10. In Sec. 192.9, paragraphs (c), (d), and (e) are revised and
paragraph (f) is added to read as follows:
Sec. 192.9 What requirements apply to gathering lines?
* * * * *
(c) Type A, Area 1 lines. An operator of a Type A, Area 1 regulated
onshore gathering line must comply with the requirements of this part
applicable to transmission lines, except the requirements in Sec. Sec.
192.13, 192.150, 192.319, 192.461(f), 192.465(f), 192.473(c), 192.478,
192.710, 192.713, and in subpart O of this part. However, an operator
of a Type A, Area 1 regulated onshore gathering line in a Class 2
location may demonstrate compliance with subpart N by describing the
processes it uses to determine the qualification of persons performing
operations and maintenance tasks.
(d) Type A, Area 2 and Type B lines. An operator of a Type A, Area
2 or Type B regulated onshore gathering line must comply with the
following requirements:
(1) If a line is new, replaced, relocated, or otherwise changed,
the design, installation, construction, initial inspection, and initial
testing must be in accordance with requirements of this part applicable
to transmission lines;
(2) If the pipeline is metallic, control corrosion according to
requirements of subpart I of this part applicable to transmission
lines;
(3) Carry out a damage prevention program under Sec. 192.614;
(4) Establish a public education program under Sec. 192.616;
(5) Establish the MAOP of the line under Sec. 192.619;
(6) Install and maintain line markers according to the requirements
for transmission lines in Sec. 192.707;
(7) Conduct leakage surveys in accordance with Sec. 192.706 using
leak detection equipment and promptly repair hazardous leaks that are
discovered in accordance with Sec. 192.703(c); and
(8) For a Type A, Area 2 regulated onshore gathering line only,
develop procedures, training, notifications, emergency plans and
implement as described in Sec. 192.615.
(e) If a regulated onshore gathering line existing on [effective
date of the final rule] was not previously subject to this part, an
operator has until [date two years after effective date of the final
rule] to comply with the applicable requirements of this section,
unless the Administrator finds a later deadline is justified in a
particular case.
(f) If, after [effective date of the final rule], a change in class
location or increase in dwelling density causes an onshore gathering
line to be a regulated onshore gathering line, the operator has one
year for Type A, Area 2 and Type B lines and two years for Type A, Area
1 lines after the line becomes a regulated onshore gathering line to
comply with this section.
0
11. In Sec. 192.13, paragraphs (a) and (b) are revised and paragraphs
(d) and (e) are added to read as follows:
Sec. 192.13 What general requirements apply to pipelines regulated
under this part?
(a) No person may operate a segment of pipeline listed in the first
column that is readied for service after the date in the second column,
unless:
(1) The pipeline has been designed, installed, constructed,
initially inspected, and initially tested in accordance with this part;
or
(2) The pipeline qualifies for use under this part according to the
requirements in Sec. 192.14.
------------------------------------------------------------------------
Pipeline Date
------------------------------------------------------------------------
Offshore gathering line................... July 31, 1977.
Regulated onshore gathering line to which March 15 2007.
this part did not apply until April 14,
2006.
Regulated onshore gathering line to which [date 1 year after effective
this part did not apply until [effective date of the final rule].
date of the final rule].
All other pipelines....................... March 12, 1971.
------------------------------------------------------------------------
(b) No person may operate a segment of pipeline listed in the first
column that is replaced, relocated, or otherwise changed after the date
in the second column, unless the replacement, relocation or change has
been made according to the requirements in this part.
------------------------------------------------------------------------
Pipeline Date
------------------------------------------------------------------------
Offshore gathering line................... July 31, 1977.
Regulated onshore gathering line to which March 15, 2007.
this part did not apply until April 14,
2006.
Regulated onshore gathering line to which [date 1 year after effective
this part did not apply until [effective date of the final rule].
date of the final rule].
All other pipelines....................... November 12, 1970.
------------------------------------------------------------------------
* * * * *
(d) Each operator of an onshore gas transmission pipeline must
evaluate and mitigate, as necessary, risks to the public and
environment as an integral part of managing pipeline design,
construction, operation, maintenance, and integrity, including
management of change. Each operator of an onshore gas transmission
pipeline must develop and follow a management of change process, as
outlined in ASME/ANSI B31.8S, section 11, that addresses technical,
design, physical, environmental, procedural, operational, maintenance,
and organizational changes to the pipeline or processes, whether
permanent or temporary. A management of change process must include the
following: reason for change, authority for approving changes, analysis
of implications, acquisition of required work permits, documentation,
communication of change to affected parties, time limitations, and
qualification of staff.
(e) Each operator must make and retain records that demonstrate
compliance with this part.
(1) Operators of transmission pipelines must keep records for the
retention period specified in appendix A to part 192.
(2) Records must be reliable, traceable, verifiable, and complete.
(3) For pipeline material manufactured before [effective date of
the final rule] and for which records are not available, each operator
must re-establish pipeline material documentation in accordance with
the requirements of Sec. 192.607.
0
12. Section 192.67 is added to subpart A to read as follows:
Sec. 192.67 Records: Materials.
Each operator of transmission pipelines must acquire and retain for
the life of the pipeline the original steel pipe manufacturing records
that document tests, inspections, and attributes required by the
manufacturing specification in effect at the time the pipe was
manufactured, including, but not limited to, yield strength, ultimate
tensile strength, and chemical composition of materials for pipe in
accordance with Sec. 192.55.
0
13. Section 192.127 is added to subpart B to read as follows:
Sec. 192.127 Records: Pipe design.
Each operator of transmission pipelines must make and retain for
the life of the pipeline records documenting pipe design to withstand
anticipated external pressures and loads in accordance with Sec.
192.103 and determination of design pressure for steel pipe in
accordance with Sec. 192.105.
0
14. In Sec. 192.150, paragraph (a) is revised to read as follows:
Sec. 192.150 Passage of internal inspection devices.
(a) Except as provided in paragraphs (b) and (c) of this section,
each new
[[Page 20829]]
transmission line and each replacement of line pipe, valve, fitting, or
other line component in a transmission line must be designed and
constructed to accommodate the passage of instrumented internal
inspection devices, in accordance with the requirements and
recommendations in NACE SP0102-2010, section 7 (incorporated by
reference, see Sec. 192.7).
* * * * *
0
15. Section 192.205 is added to subpart D to read as follows:
Sec. 192.205 Records: Pipeline components.
Each operator of transmission pipelines must acquire and retain
records documenting the manufacturing standard and pressure rating to
which each valve was manufactured and tested in accordance with this
subpart. Flanges, fittings, branch connections, extruded outlets,
anchor forgings, and other components with material yield strength
grades of 42,000 psi or greater must have records documenting the
manufacturing specification in effect at the time of manufacture,
including, but not limited to, yield strength, ultimate tensile
strength, and chemical composition of materials.
0
16. In Sec. 192.227, paragraph (c) is added to read as follows:
Sec. 192.227 Qualification of welders and welding operators.
* * * * *
(c) Records for transmission pipelines demonstrating each
individual welder qualification in accordance with this section must be
retained for the life of the pipeline.
0
17. In Sec. 192.285, paragraph (e) is added to read as follows:
Sec. 192.285 Plastic pipe: Qualifying persons to make joints.
* * * * *
(e) For transmission pipelines, records demonstrating plastic pipe
joining qualifications in accordance with this section must be retained
for the life of the pipeline.
18. In Sec. 192.319, paragraph (d) is added to read as follows:
Sec. 192.319 Installation of pipe in a ditch.
* * * * *
(d) Promptly after a ditch for a steel onshore transmission line is
backfilled, but not later than three months after placing the pipeline
in service, the operator must perform an assessment to ensure integrity
of the coating using direct current voltage gradient (DCVG) or
alternating current voltage gradient (ACVG). The operator must repair
any coating damage classified as moderate or severe (voltage drop
greater than 35% for DCVG or 50 dB[mu]v for ACVG) in accordance with
section 4 of NACE SP0502 (incorporated by reference, see Sec. 192.7)
within six months of the assessment. Each operator of transmission
pipelines must make and retain for the life of the pipeline records
documenting the coating assessment findings and repairs.
0
19. In Sec. 192.452, the introductory text of paragraph (b) is revised
to read as follows:
Sec. 192.452 How does this subpart apply to converted pipelines and
regulated onshore gathering lines?
* * * * *
(b) Regulated onshore gathering lines. For any regulated onshore
gathering line under Sec. 192.9 existing on [effective date of the
final rule], that was not previously subject to this part, and for any
onshore gathering line that becomes a regulated onshore gathering line
under Sec. 192.9 after April 14, 2006, because of a change in class
location or increase in dwelling density:
* * * * *
0
20. In Sec. 192.461, paragraph (a)(4) is revised and paragraph (f) is
added to read as follows:
Sec. 192.461 External corrosion control: Protective coating.
(a) * * *
(4) Have sufficient strength to resist damage due to handling
(including but not limited to transportation, installation, boring, and
backfilling) and soil stress; and
* * * * *
(f) Promptly, but no later than three months after backfill of an
onshore transmission pipeline ditch following repair or replacement (if
the repair or replacement results in 1,000 feet or more of backfill
length along the pipeline), conduct surveys to assess any coating
damage to ensure integrity of the coating using direct current voltage
gradient (DCVG) or alternating current voltage gradient (ACVG).
Remediate any coating damage classified as moderate or severe (voltage
drop greater than 35% for DCVG or 50 dB[mu]v for ACVG) in accordance
with section 4 of NACE SP0502 (incorporated by reference, see Sec.
192.7) within six months of the assessment.
0
21. In Sec. 192.465, the section heading and paragraph (d) are revised
and paragraph (f) is added to read as follows:
Sec. 192.465 External corrosion control: Monitoring and remediation.
* * * * *
(d) Each operator must promptly correct any deficiencies indicated
by the inspection and testing provided in paragraphs (a), (b) and (c)
of this section. Remedial action must be completed promptly, but no
later than the next monitoring interval in Sec. 192.465 or within one
year, whichever is less.
* * * * *
(f) For onshore transmission lines, where any annual test station
reading (pipe-to-soil potential measurement) indicates cathodic
protection levels below the required levels in Appendix D of this part,
the operator must determine the extent of the area with inadequate
cathodic protection. Close interval surveys must be conducted in both
directions from the test station with a low cathodic protection (CP)
reading at a minimum of approximately five foot intervals. Close
interval surveys must be conducted, where practical based upon
geographical, technical, or safety reasons. Close interval surveys
required by this part must be completed with the protective current
interrupted unless it is impractical to do so for technical or safety
reasons. Remediation of areas with insufficient cathodic protection
levels or areas where protective current is found to be leaving the
pipeline must be performed in accordance with paragraph (d) of this
section. The operator must confirm restoration of adequate cathodic
protection by close interval survey over the entire area.
0
22. In Sec. 192.473, paragraph (c) is added to read as follows:
Sec. 192.473 External corrosion control: Interference currents.
* * * * *
(c) For onshore gas transmission pipelines, the program required by
paragraph (a) of this section must include:
(1) Interference surveys for a pipeline system to detect the
presence and level of any electrical stray current. Interference
surveys must be taken on a periodic basis including, when there are
current flow increases over pipeline segment grounding design, from any
co-located pipelines, structures, or high voltage alternating current
(HVAC) power lines, including from additional generation, a voltage up
rating, additional lines, new or enlarged power substations, new
pipelines or other structures;
(2) Analysis of the results of the survey to determine the cause of
the interference and whether the level could impact the effectiveness
of cathodic protection; and
(3) Implementation of remedial actions to protect the pipeline
segment from detrimental interference currents
[[Page 20830]]
promptly but no later than six months after completion of the survey.
0
23. Section 192.478 is added to read as follows:
Sec. 192.478 Internal corrosion control: Onshore transmission
monitoring and mitigation.
(a) For onshore transmission pipelines, each operator must develop
and implement a monitoring and mitigation program to identify
potentially corrosive constituents in the gas being transported and
mitigate the corrosive effects. Potentially corrosive constituents
include but are not limited to: carbon dioxide, hydrogen sulfide,
sulfur, microbes, and free water, either by itself or in combination.
Each operator must evaluate the partial pressure of each corrosive
constituent by itself or in combination to evaluate the effect of the
corrosive constituents on the internal corrosion of the pipe and
implement mitigation measures.
(b) The monitoring and mitigation program in paragraph (a) of this
section must include:
(1) At points where gas with potentially corrosive contaminants
enters the pipeline, the use of gas-quality monitoring equipment to
determine the gas stream constituents;
(2) Product sampling, inhibitor injections, in-line cleaning
pigging, separators or other technology to mitigate the potentially
corrosive gas stream constituents;
(3) Evaluation twice each calendar year, at intervals not to exceed
7\1/2\ months, of gas stream and liquid quality samples and
implementation of adjustments and mitigative measures to ensure that
potentially corrosive gas stream constituents are effectively monitored
and mitigated.
(c) If corrosive gas is being transported, coupons or other
suitable means must be used to determine the effectiveness of the steps
taken to minimize internal corrosion. Each coupon or other means of
monitoring internal corrosion must be checked at least twice each
calendar year, at intervals not exceeding 7\1/2\ months.
(d) Each operator must review its monitoring and mitigation program
at least twice each calendar year, at intervals not to exceed 7\1/2\
months, based on the results of its gas stream sampling and internal
corrosion monitoring in (a) and (b) and implement adjustments in its
monitoring for and mitigation of the potential for internal corrosion
due to the presence of potentially corrosive gas stream constituents.
0
24. In Sec. 192.485, paragraph (c) is revised to read as follows:
Sec. 192.485 Remedial measures: Transmission lines.
* * * * *
(c) Under paragraphs (a) and (b) of this section, the strength of
pipe based on actual remaining wall thickness may be determined by the
procedure in ASME/ANSI B31G (incorporated by reference, see Sec.
192.7) or the procedure in PRCI PR 3-805 (R-STRENG) (incorporated by
reference, see Sec. 192.7) for corrosion defects. Both procedures
apply to corroded regions that do not penetrate the pipe wall over 80
percent of the wall thickness and are subject to the limitations
prescribed in the procedures, including the appropriate use of class
location and pipe longitudinal seam factors in pressure calculations
for pipe defects. When determining the predicted failure pressure (PFP)
for gouges, scrapes, selective seam weld corrosion, and crack-related
defects, appropriate failure criteria must be used and justification of
the criteria must be documented. Pipe and material properties used in
remaining strength calculations and the pressure calculations made
under this paragraph must be documented in reliable, traceable,
verifiable, and complete records. If such records are not available,
pipe and material properties used in the remaining strength
calculations must be based on properties determined and documented in
accordance with Sec. 192.607.
0
25. Section 192.493 is added to subpart I to read as follows:
Sec. 192.493 In-line inspection of pipelines.
When conducting in-line inspection of pipelines required by this
part, each operator must comply with the requirements and
recommendations of API STD 1163, In-line Inspection Systems
Qualification Standard; ANSI/ASNT ILI-PQ-2010, In-line Inspection
Personnel Qualification and Certification; and NACE SP0102-2010, In-
line Inspection of Pipelines (incorporated by reference, see Sec.
192.7). Assessments may also be conducted using tethered or remotely
controlled tools, not explicitly discussed in NACE SP0102-2010,
provided they comply with those sections of NACE SP0102-2010 that are
applicable.
0
26. In Sec. 192.503, paragraph (a)(1) is revised to read as follows:
Sec. 192.503 General requirements.
(a) * * *
(1) It has been tested in accordance with this subpart and Sec.
192.619, 192.620, or 192.624 to substantiate the maximum allowable
operating pressure; and
* * * * *
0
27. Section 192.506 is added to read as follows:
Sec. 192.506 Transmission lines: Spike hydrostatic pressure test for
existing steel pipe with integrity threats.
(a) Each segment of an existing steel pipeline that is operated at
a hoop stress level of 30% of specified minimum yield strength or more
and has been found to have integrity threats that cannot be addressed
by other means such as in-line inspection or direct assessment must be
strength tested by a spike hydrostatic pressure test in accordance with
this section to substantiate the proposed maximum allowable operating
pressure.
(b) The spike hydrostatic pressure test must use water as the test
medium.
(c) The baseline test pressure without the additional spike test
pressure is the test pressure specified in Sec. 192.619(a)(2),
192.620(a)(2), or 192.624, whichever applies.
(d) The test must be conducted by maintaining the pressure at or
above the baseline test pressure for at least 8 hours as specified in
Sec. 192.505(e).
(e) After the test pressure stabilizes at the baseline pressure and
within the first two hours of the 8-hour test interval, the hydrostatic
pressure must be raised (spiked) to a minimum of the lesser of 1.50
times MAOP or 105% SMYS. This spike hydrostatic pressure test must be
held for at least 30 minutes.
(f) If the integrity threat being addressed by the spike test is of
a time-dependent nature such as a cracking threat, the operator must
establish an appropriate retest interval and conduct periodic retests
at that interval using the same spike test pressure. The appropriate
retest interval and periodic tests for the time-dependent threat must
be determined in accordance with the methodology in Sec. 192.624(d).
(g) Alternative technology or alternative technical evaluation
process. Operators may use alternative technology or an alternative
technical evaluation process that provides a sound engineering basis
for establishing a spike hydrostatic pressure test or equivalent. If an
operator elects to use alternative technology or an alternative
technical evaluation process, the operator must notify PHMSA at least
180 days in advance of use in accordance with Sec. 192.624(e). The
operator must submit the alternative technical evaluation to the
Associate Administrator of Pipeline Safety with the notification and
must obtain a ``no objection letter'' from the Associate Administrator
of Pipeline Safety prior to usage of alternative technology or an
alternative technical evaluation process.
[[Page 20831]]
The notification must include the following details:
(1) Descriptions of the technology or technologies to be used for
all tests, examinations, and assessments;
(2) Procedures and processes to conduct tests, examinations, and
assessments, perform evaluations, analyze defects and flaws, and
remediate defects discovered;
(3) Data requirements including original design, maintenance and
operating history, anomaly or flaw characterization;
(4) Assessment techniques and acceptance criteria;
(5) Remediation methods for assessment findings;
(6) Spike hydrostatic pressure test monitoring and acceptance
procedures, if used;
(7) Procedures for remaining crack growth analysis and pipe segment
life analysis for the time interval for additional assessments, as
required; and
(8) Evidence of a review of all procedures and assessments by a
subject matter expert(s) in both metallurgy and fracture mechanics.
0
28. In Sec. 192.517, the introductory text of paragraph (a) is revised
to read as follows:
Sec. 192.517 Records.
(a) Each operator must make, and retain for the useful life of the
pipeline, a record of each test performed under Sec. Sec. 192.505,
192.506, and 192.507. The record must contain at least the following
information:
* * * * *
0
29. In Sec. 192.605, paragraph (b)(5) is revised to read as follows:
Sec. 192.605 Procedural manual for operations, maintenance, and
emergencies.
* * * * *
(b) * * *
(5) Operating pipeline controls and systems and operating and
maintaining pressure relieving or pressure limiting devices, including
those for starting up and shutting down any part of the pipeline, so
that the MAOP limit as prescribed by this part cannot be exceeded by
more than the margin (build-up) allowed for operation of pressure
relieving devices or pressure-limiting or control devices as specified
in Sec. 192.201, 192.620(e), 192.731, 192.739, or 192.743, whichever
applies.
* * * * *
0
30. Section 192.607 is added to read as follows:
Sec. 192.607 Verification of pipeline material: Onshore steel
transmission pipelines.
(a) Applicable locations. Each operator must follow the
requirements of paragraphs (b) through (d) of this section for each
segment of onshore, steel, gas transmission pipeline installed before
[effective date of the final rule] that does not have reliable,
traceable, verifiable, and complete material documentation records for
line pipe, valves, flanges, and components and meets any of the
following conditions:
(1) The pipeline is located in a High Consequence Area as defined
in Sec. 192.903; or
(2) The pipeline is located in a class 3 or class 4 location.
(b) Material documentation plan. Each operator must prepare a
material documentation plan to implement all actions required by this
section by [date 180 days after the effective date of the final rule].
(c) Material documentation. Each operator must have reliable,
traceable, verifiable, and complete records documenting the following:
(1) For line pipe and fittings, records must document diameter,
wall thickness, grade (yield strength and ultimate tensile strength),
chemical composition, seam type, coating type, and manufacturing
specification.
(2) For valves, records must document either the applicable
standards to which the component was manufactured, the manufacturing
rating, or the pressure rating. For valves with pipe weld ends, records
must document the valve material grade and weld end bevel condition to
ensure compatibility with pipe end conditions;
(3) For flanges, records must document either the applicable
standards to which the component was manufactured, the manufacturing
rating, or the pressure rating, and the material grade and weld end
bevel condition to ensure compatibility with pipe end conditions;
(4) For components, records must document the applicable standards
to which the component was manufactured to ensure pressure rating
compatibility.
(d) Verification of material properties. For any material
documentation records for line pipe, valves, flanges, and components
specified in paragraph (c) of this section that are not available, the
operator must take the following actions to determine and verify the
physical characteristics.
(1) Develop and implement procedures for conducting non-destructive
or destructive tests, examinations, and assessments for line pipe at
all above ground locations.
(2) Develop and implement procedures for conducting destructive
tests, examinations, and assessments for buried line pipe at all
excavations associated with replacements or relocations of pipe
segments that are removed from service.
(3) Develop and implement procedures for conducting non-destructive
or destructive tests, examinations, and assessments for buried line
pipe at all excavations associated with anomaly direct examinations, in
situ evaluations, repairs, remediations, maintenance, or any other
reason for which the pipe segment is exposed, except for segments
exposed during excavation activities that are in compliance with Sec.
192.614, until completion of the minimum number of excavations as
follows:
(i) The operator must define a separate population of undocumented
or inadequately documented pipeline segments for each unique
combination of the following attributes: wall thicknesses (within 10
percent of the smallest wall thickness in the population), grade,
manufacturing process, pipe manufacturing dates (within a two year
interval) and construction dates (within a two year interval).
(ii) Assessments must be proportionally spaced throughout the
pipeline segment. Each length of the pipeline segment equal to 10
percent of the total length must contain 10 percent of the total number
of required excavations, e.g. a 200 mile population would require 15
excavations for each 20 miles. For each population defined according to
paragraph (d)(3)(i) of this section, the minimum number of excavations
at which line pipe must be tested to verify pipeline material
properties is the lesser of the following:
(A) 150 excavations; or
(B) If the segment is less than 150 miles, a number of excavations
equal to the population's pipeline mileage (i.e., one set of properties
per mile), rounded up to the nearest whole number. The mileage for this
calculation is the cumulative mileage of pipeline segments in the
population without reliable, traceable, verifiable, and complete
material documentation.
(iii) At each excavation, tests for material properties must
determine diameter, wall thickness, yield strength, ultimate tensile
strength, Charpy v-notch toughness (where required for failure pressure
and crack growth analysis), chemical properties, seam type, coating
type, and must test for the presence of stress corrosion cracking, seam
cracking, or selective seam weld corrosion using ultrasonic inspection,
magnetic particle, liquid penetrant, or other appropriate non-
destructive examination techniques. Determination of material property
values must
[[Page 20832]]
conservatively account for measurement inaccuracy and uncertainty based
upon comparison with destructive test results using unity charts.
(iv) If non-destructive tests are performed to determine strength
or chemical composition, the operator must use methods, tools,
procedures, and techniques that have been independently validated by
subject matter experts in metallurgy and fracture mechanics to produce
results that are accurate within 10% of the actual value with 95%
confidence for strength values, within 25% of the actual value with 85%
confidence for carbon percentage and within 20% of the actual value
with 90% confidence for manganese, chromium, molybdenum, and vanadium
percentage for the grade of steel being tested.
(v) The minimum number of test locations at each excavation or
above-ground location is based on the number of joints of line pipe
exposed, as follows:
(A) 10 joints or less: one set of tests for each joint.
(B) 11 to 100 joints: one set of tests for each five joints, but
not less than 10 sets of tests.
(C) Over 100 joints: one set of tests for each 10 joints, but not
less than 20 sets of tests.
(vi) For non-destructive tests, at each test location, a set of
material properties tests must be conducted at a minimum of five places
in each circumferential quadrant of the pipe for a minimum total of 20
test readings at each pipe cylinder location.
(vii) For destructive tests, at each test location, a set of
materials properties tests must be conducted on each circumferential
quadrant of a test pipe cylinder removed from each location, for a
minimum total of four tests at each location.
(viii) If the results of all tests conducted in accordance with
paragraphs (d)(3)(i) and (ii) of this section verify that material
properties are consistent with all available information for each
population, then no additional excavations are necessary. However, if
the test results identify line pipe with properties that are not
consistent with existing expectations based on all available
information for each population, then the operator must perform tests
at additional excavations. The minimum number of excavations that must
be tested depends on the number of inconsistencies observed between as-
found tests and available operator records, in accordance with the
following table:
------------------------------------------------------------------------
Number of excavations with inconsistency
between test results and existing Minimum number of total
expectations based on all available required excavations for
information for each population population. The lesser of:
------------------------------------------------------------------------
0......................................... 150 (or pipeline mileage)
1......................................... 225 (or pipeline mileage
times 1.5)
2......................................... 300 (or pipeline mileage
times 2)
>2........................................ 350 (or pipeline mileage
times 2.3)
------------------------------------------------------------------------
(ix) The tests conducted for a single excavation according to the
requirements of paragraphs (d)(3)(iii) through (vii) of this section
count as one sample under the sampling requirements of paragraphs
(d)(3)(i), (ii), and (viii) of this section.
(4) For mainline pipeline components other than line pipe, the
operator must develop and implement procedures for establishing and
documenting the ANSI rating and material grade (to assure compatibility
with pipe ends).
(i) Materials in compressor stations, meter stations, regulator
stations, separators, river crossing headers, mainline valve
assemblies, operator piping, or cross-connections with isolation valves
from the mainline pipeline are not required to be tested for chemical
and mechanical properties.
(ii) Verification of mainline material properties is required for
non-line pipe components, including but not limited to, valves,
flanges, fittings, fabricated assemblies, and other pressure retaining
components appurtenances that are:
(A) 2-inch nominal diameter and larger; or
(B) Material grades greater than 42,000 psi (X-42); or
(C) Appurtenances of any size that are directly installed on the
pipeline and cannot be isolated from mainline pipeline pressures.
(iii) Procedures for establishing material properties for non-line
pipe components where records are inadequate must be based upon
documented manufacturing specifications. Where specifications are not
known, usage of manufacturer's stamped or tagged material pressure
ratings and material type may be used to establish pressure rating. The
operator must document the basis of the material properties established
using such procedures.
(5) The material properties determined from the destructive or non-
destructive tests required by this section cannot be used to raise the
original grade or specification of the material, which must be based
upon the applicable standard referenced in Sec. 192.7.
(6) If conditions make material verification by the above methods
impracticable or if the operator chooses to use ``other technology'' or
``new technology'' (alternative technical evaluation process plan), the
operator must notify PHMSA at least 180 days in advance of use in
accordance with paragraph Sec. 192.624(e) of this section. The
operator must submit the alternative technical evaluation process plan
to the Associate Administrator of Pipeline Safety with the notification
and must obtain a ``no objection letter'' from the Associate
Administrator of Pipeline Safety prior to usage of an alternative
evaluation process.
0
31. In Sec. 192.613, paragraph (c) is added to read as follows:
Sec. 192.613 Continuing surveillance.
* * * * *
(c) Following an extreme weather event such as a hurricane or
flood, an earthquake, landslide, a natural disaster, or other similar
event that has the likelihood of damage to infrastructure, an operator
must inspect all potentially affected onshore transmission pipeline
facilities to detect conditions that could adversely affect the safe
operation of that pipeline.
(1) Inspection method. An operator must consider the nature of the
event and the physical characteristics, operating conditions, location,
and prior history of the affected pipeline in determining the
appropriate method for performing the initial inspection to determine
damage and the need for the additional assessments required under the
introductory text of paragraph (c) in this section.
(2) Time period. The inspection required under the introductory
text of paragraph (c) of this section must commence within 72 hours
after the cessation of the event, defined as the point in time when the
affected area can be safely accessed by the personnel and equipment,
including availability of personnel and equipment, required to perform
the inspection as determined under paragraph (c)(1) of this section,
whichever is sooner.
(3) Remedial action. An operator must take appropriate remedial
action to ensure the safe operation of a pipeline based on the
information obtained as a result of performing the inspection required
under the introductory text of paragraph (c) in this section. Such
[[Page 20833]]
actions might include, but are not limited to:
(i) Reducing the operating pressure or shutting down the pipeline;
(ii) Modifying, repairing, or replacing any damaged pipeline
facilities;
(iii) Preventing, mitigating, or eliminating any unsafe conditions
in the pipeline right-of-way;
(iv) Performing additional patrols, surveys, tests, or inspections;
(v) Implementing emergency response activities with Federal, State,
or local personnel; or
(vi) Notifying affected communities of the steps that can be taken
to ensure public safety.
0
32. In Sec. 192.619, paragraphs (a)(2) through (4) are revised and
paragraphs (e) and (f) are added to read as follows:
Sec. 192.619 Maximum allowable operating pressure: Steel or plastic
pipelines.
(a) * * *
(2) The pressure obtained by dividing the pressure to which the
segment was tested after construction as follows:
(i) For plastic pipe in all locations, the test pressure is divided
by a factor of 1.5.
(ii) For steel pipe operated at 100 p.s.i. (689 kPa) gage or more,
the test pressure is divided by a factor determined in accordance with
the following table:
--------------------------------------------------------------------------------------------------------------------------------------------------------
Factors \1\, segment--
---------------------------------------------------------------------------------------------------
Installed after (Nov.
Class location Installed before (Nov. 11, 1970) and before Installed after Converted under Sec.
12, 1970) [effective date of the [effective date of the 192.14
final rule] final rule minus 1 day]
--------------------------------------------------------------------------------------------------------------------------------------------------------
1................................................... 1.1 1.1 1.25 1.25
2................................................... 1.25 1.25 1.25 1.25
3................................................... 1.4 1.5 1.5 1.5
4................................................... 1.4 1.5 1.5 1.5
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ For offshore segments installed, uprated or converted after July 31, 1977, that are not located on an offshore platform, the factor is 1.25. For
segments installed, uprated or converted after July 31, 1977, that are located on an offshore platform or on a platform in inland navigable waters,
including a pipe riser, the factor is 1.5.
(3) The highest actual operating pressure to which the segment was
subjected during the 5 years preceding the applicable date in the
second column. This pressure restriction applies unless the segment was
tested according to the requirements in paragraph (a)(2) of this
section after the applicable date in the third column or the segment
was uprated according to the requirements in subpart K of this part:
------------------------------------------------------------------------
Pipeline segment Pressure date Test date
------------------------------------------------------------------------
--Onshore gathering line that March 15, 2006, or 5 years
first became subject to this date line becomes preceding
part (other than Sec. subject to this part, applicable date
192.612) after April 13, 2006 whichever is later. in second
but before [effective date of column.
the final rule].
--Onshore gathering line that [date one year after
first became subject to this effective date of the
part (other than Sec. final rule], or date
192.612) on or after line becomes subject
[effective date of the final to this part,
rule]. whichever is later.
--Onshore transmission line March 15, 2006, or
that was a gathering line not date line becomes
subject to this part before subject to this part,
March 15, 2006. whichever is later.
Offshore gathering lines...... July 1, 1976.......... July 1, 1971.
All other pipelines........... July 1, 1970.......... July 1, 1965.
------------------------------------------------------------------------
(4) The pressure determined by the operator to be the maximum safe
pressure after considering material records, including material
properties verified in accordance with Sec. 192.607, and the history
of the segment, particularly known corrosion and the actual operating
pressure.
* * * * *
(e) Notwithstanding the requirements in paragraphs (a) through (d)
of this section, onshore steel transmission pipelines that meet the
criteria specified in Sec. 192.624(a) must establish and document the
maximum allowable operating pressure in accordance with Sec. 192.624
using one or more of the following:
(1) Method 1: Pressure Test--Pressure test in accordance with Sec.
192.624(c)(1)(i) or spike hydrostatic pressure test in accordance with
Sec. 192.624(c)(1)(ii), as applicable;
(2) Method 2: Pressure Reduction--Reduction in pipeline maximum
allowable operating pressure in accordance with Sec. 192.624(c)(2);
(3) Method 3: Engineering Critical Assessment--Engineering
assessment and analysis activities in accordance with Sec.
192.624(c)(3);
(4) Method 4: Pipe Replacement--Replacement of the pipeline segment
in accordance with Sec. 192.624(c)(4);
(5) Method 5: Pressure Reduction for Segments with Small PIR and
Diameter--Reduction of maximum allowable operating pressure and other
preventive measures for pipeline segments with small PIRs and
diameters, in accordance with Sec. 192.624(c)(5); or
(6) Method 6: Alternative Technology--Alternative procedure in
accordance with Sec. 192.624(c)(6).
(f) Operators must maintain all records necessary to establish and
document the MAOP of each pipeline as long as the pipe or pipeline
remains in service. Records that establish the pipeline MAOP, include,
but are not limited to, design, construction, operation, maintenance,
inspection, testing, material strength, pipe wall thickness, seam type,
and other related data. Records must be reliable, traceable,
verifiable, and complete.
0
33. Section 192.624 is added to read as follows:
Sec. 192.624 Maximum allowable operating pressure verification:
Onshore steel transmission pipelines.
(a) Applicable locations. The operator of a pipeline segment
meeting any of the following conditions must establish the maximum
allowable operating pressure using one or more of the methods specified
in Sec. 192.624(c)(1) through (6):
[[Page 20834]]
(1) The pipeline segment has experienced a reportable in-service
incident, as defined in Sec. 191.3 of this chapter, since its most
recent successful subpart J pressure test, due to an original
manufacturing-related defect, a construction-, installation-, or
fabrication-related defect, or a cracking-related defect, including,
but not limited to, seam cracking, girth weld cracking, selective seam
weld corrosion, hard spot, or stress corrosion cracking and the
pipeline segment is located in one of the following locations:
(i) A high consequence area as defined in Sec. 192.903;
(ii) A class 3 or class 4 location; or
(iii) A moderate consequence area as defined in Sec. 192.3 if the
pipe segment can accommodate inspection by means of instrumented inline
inspection tools (i.e., ``smart pigs'').
(2) Pressure test records necessary to establish maximum allowable
operating pressure per subpart J for the pipeline segment, including,
but not limited to, records required by Sec. 192.517(a), are not
reliable, traceable, verifiable, and complete and the pipeline is
located in one of the following locations:
(i) A high consequence area as defined in Sec. 192.903; or
(ii) A class 3 or class 4 location
(3) The pipeline segment maximum allowable operating pressure was
established in accordance with Sec. 192.619(c) before [effective date
of the final rule] and is located in one of the following areas:
(i) A high consequence area as defined in Sec. 192.903;
(ii) A class 3 or class 4 location; or
(iii) A moderate consequence area as defined in Sec. 192.3 if the
pipe segment can accommodate inspection by means of instrumented inline
inspection tools (i.e., ``smart pigs'').
(b) Completion date. For pipelines installed before [effective date
of the final rule], all actions required by this section must be
completed according to the following schedule:
(1) The operator must develop and document a plan for completion of
all actions required by this section by [date 1 year after effective
date of the final rule].
(2) The operator must complete all actions required by this section
on at least 50% of the mileage of locations that meet the conditions of
Sec. 192.624(a) by [date 8 years after effective date of the final
rule].
(3) The operator must complete all actions required by this section
on 100% of the mileage of locations that meet the conditions of Sec.
192.624(a) by [date 15 years after effective date of the final rule].
(4) If operational and environmental constraints limit the operator
from meeting the deadlines in Sec. 192.614(b)(2) and (3), the operator
may petition for an extension of the completion deadlines by up to one
year, upon submittal of a notification to the Associate Administrator
of the Office of Pipeline Safety in accordance with paragraph (e) of
this section. The notification must include an up-to-date plan for
completing all actions in accordance with paragraph (b)(1) of this
section, the reason for the requested extension, current status,
proposed completion date, remediation activities outstanding, and any
needed temporary safety measures to mitigate the impact on safety.
(c) Maximum allowable operating pressure determination. The
operator of a pipeline segment meeting the criteria in paragraph (a) of
this section must establish its maximum allowable operating pressure
using one of the following methods:
(1) Method 1: Pressure test.(i) Perform a pressure test in
accordance with Sec. 192.505(c). The maximum allowable operating
pressure will be equal to the test pressure divided by the greater of
either 1.25 or the applicable class location factor in Sec.
192.619(a)(2)(ii) or Sec. 192.620(a)(2)(ii).
(ii) If the pipeline segment includes legacy pipe or was
constructed using legacy construction techniques or the pipeline has
experienced an incident, as defined by Sec. 191.3 of this chapter,
since its most recent successful subpart J pressure test, due to an
original manufacturing-related defect, a construction-, installation-,
or fabrication-related defect, or a crack or crack-like defect,
including, but not limited to, seam cracking, girth weld cracking,
selective seam weld corrosion, hard spot, or stress corrosion cracking,
then the operator must perform a spike pressure test in accordance with
Sec. 192.506. The maximum allowable operating pressure will be equal
to the test pressure specified in Sec. 192.506(c) divided by the
greater of 1.25 or the applicable class location factor in Sec.
192.619(a)(2)(ii) or Sec. 192.620(a)(2)(ii).
(iii) If the operator has reason to believe any pipeline segment
may be susceptible to cracks or crack-like defects due to assessment,
leak, failure, or manufacturing vintage histories, or any other
available information about the pipeline, the operator must estimate
the remaining life of the pipeline in accordance with paragraph (d) of
this section.
(2) Method 2: Pressure reduction. The pipeline maximum allowable
operating pressure will be no greater than the highest actual operating
pressure sustained by the pipeline during the 18 months preceding
[effective date of the final rule] divided by the greater of 1.25 or
the applicable class location factor in Sec. 192.619(a)(2)(ii) or
Sec. 192.620(a)(2)(ii). The highest actual sustained pressure must
have been reached for a minimum cumulative duration of 8 hours during a
continuous 30-day period. The value used as the highest actual
sustained operating pressure must account for differences between
discharge and upstream pressure on the pipeline by use of either the
lowest pressure value for the entire segment or using the operating
pressure gradient (i.e., the location-specific operating pressure at
each location).
(i) Where the pipeline segment has had a class location change in
accordance with Sec. 192.611 and pipe material and pressure test
records are not available, the operator must reduce the pipeline
segment MAOP as follows:
(A) For segments where a class location changed from 1 to 2, from 2
to 3, or from 3 to 4, reduce the pipeline maximum allowable operating
pressure to no greater than the highest actual operating pressure
sustained by the pipeline during the 18 months preceding [effective
date of the final rule], divided by 1.39 for class 1 to 2, 1.67 for
class 2 to 3, and 2.00 for class 3 to 4.
(B) For segments where a class location changed from 1 to 3, reduce
the pipeline maximum allowable operating pressure to no greater than
the highest actual operating pressure sustained by the pipeline during
the 18 months preceding [effective date of the final rule], divided by
2.00.
(ii) If the operator has reason to believe any pipeline segment
contains or may be susceptible to cracks or crack-like defects due to
assessment, leak, failure, or manufacturing vintage histories, or any
other available information about the pipeline, the operator must
estimate the remaining life of the pipeline in accordance with
paragraph (d) of this section.
(iii) Future uprating of the segment in accordance with subpart K
of this part is allowed if the maximum allowable operating pressure is
established using Method 2 described in paragraph (c)(2) of this
section.
(iv) If an operator elects to use Method 2 described in paragraph
(c)(2) of this section, but desires to use a less conservative pressure
reduction factor, the operator must notify PHMSA in accordance with
paragraph (e) of this section no later than seven calendar days after
establishing the reduced maximum allowable operating pressure.
[[Page 20835]]
The notification must include the following details:
(A) Descriptions of the operational constraints, special
circumstances, or other factors that preclude, or make it impractical,
to use the pressure reduction factor specified in Sec. 192.624(c)(2);
(B) The fracture mechanics modeling for failure stress pressures
and cyclic fatigue crack growth analysis that complies with paragraph
(d) of this section;
(C) Justification that establishing maximum allowable operating
pressure by another method allowed by this section is impractical;
(D) Justification that the reduced maximum allowable operating
pressure determined by the operator is safe based on analysis of the
condition of the pipeline segment, including material records, material
properties verified in accordance Sec. 192.607, and the history of the
segment, particularly known corrosion and leakage, and the actual
operating pressure, and additional compensatory preventive and
mitigative measures taken or planned.
(E) Planned duration for operating at the requested maximum
allowable operating pressure, long term remediation measures and
justification of this operating time interval, including fracture
mechanics modeling for failure stress pressures and cyclic fatigue
growth analysis and other validated forms of engineering analysis that
have been reviewed and confirmed by subject matter experts in
metallurgy and fracture mechanics.
(3) Method 3: Engineering critical assessment. Conduct an
engineering critical assessment and analysis (ECA) to establish the
material condition of the segment and maximum allowable operating
pressure. An ECA is an analytical procedure, based on fracture
mechanics principles, relevant material properties (mechanical and
fracture resistance properties), operating history, operational
environment, in-service degradation, possible failure mechanisms,
initial and final defect sizes, and usage of future operating and
maintenance procedures to determine the maximum tolerable sizes for
imperfections. The ECA must assess: threats; loadings and operational
circumstances relevant to those threats including along the right-of
way; outcomes of the threat assessment; relevant mechanical and
fracture properties; in-service degradation or failure processes;
initial and final defect size relevance. The ECA must quantify the
coupled effects of any defect in the pipeline.
(i) ECA analysis. (A) The ECA must integrate and analyze the
results of the material documentation program required by Sec.
192.607, if applicable, and the results of all tests, direct
examinations, destructive tests, and assessments performed in
accordance with this section, along with other pertinent information
related to pipeline integrity, including but not limited to close
interval surveys, coating surveys, and interference surveys required by
subpart I of this part, root cause analyses of prior incidents, prior
pressure test leaks and failures, other leaks, pipe inspections, and
prior integrity assessments, including those required by Sec. 192.710
and subpart O of this part.
(B) The ECA must analyze any cracks or crack-like defects remaining
in the pipe, or that could remain in the pipe, to determine the
predicted failure pressure (PFP) of each defect. The ECA must use the
techniques and procedures in Battelle Final Reports (``Battelle's
Experience with ERW and Flash Weld Seam Failures: Causes and
Implications''--Task 1.4), Report No. 13-002 (``Models for Predicting
Failure Stress Levels for Defects Affecting ERW and Flash-Welded
Seams''--Subtask 2.4), Report No. 13-021 (``Predicting Times to Failure
for ERW Seam Defects that Grow by Pressure-Cycle-Induced Fatigue''--
Subtask 2.5) and (``Final Summary Report and Recommendations for the
Comprehensive Study to Understand Longitudinal ERW Seam Failures--Phase
1''--Task 4.5) (incorporated by reference, see Sec. 192.7) or other
technically proven methods including but not limited to API RP 579-1/
ASME FFS-1, June 5, 2007, (API 579-1, Second Edition)--Level II or
Level III, CorLasTM, or PAFFC. The ECA must use conservative
assumptions for crack dimensions (length and depth) and failure mode
(ductile, brittle, or both) for the microstructure, location, type of
defect, and operating conditions (which includes pressure cycling). If
actual material toughness is not known or not adequately documented by
reliable, traceable, verifiable, and complete records, then the
operator must determine a Charpy v-notch toughness based upon the
material documentation program specified in Sec. 192.607 or use
conservative values for Charpy v-notch toughness as follows: body
toughness of less than or equal to 5.0 ft-lb and seam toughness of less
than or equal to 1 ft-lb.
(C) The ECA must analyze any metal loss defects not associated with
a dent including corrosion, gouges, scrapes or other metal loss defects
that could remain in the pipe to determine the predicted failure
pressure (PFP). ASME/ANSI B31G (incorporated by reference, see Sec.
192.7) or AGA Pipeline Research Committee Project PR-3-805
(``RSTRENG,'' incorporated by reference, see Sec. 192.7) must be used
for corrosion defects. Both procedures apply to corroded regions that
do not penetrate the pipe wall over 80 percent of the wall thickness
and are subject to the limitations prescribed in the equations
procedures. The ECA must use conservative assumptions for metal loss
dimensions (length, width, and depth). When determining PFP for gouges,
scrapes, selective seam weld corrosion, crack-related defects, or any
defect within a dent, appropriate failure criteria and justification of
the criteria must be used. If SMYS or actual material yield and
ultimate tensile strength is not known or not adequately documented by
reliable, traceable, verifiable, and complete records, then the
operator must assume grade A pipe or determine the material properties
based upon the material documentation program specified in Sec.
192.607.
(D) The ECA must analyze interacting defects to conservatively
determine the most limiting PFP for interacting defects. Examples
include but are not limited to, cracks in or near locations with
corrosion metal loss, dents with gouges or other metal loss, or cracks
in or near dents or other deformation damage. The ECA must document all
evaluations and any assumptions used in the ECA process.
(E) The maximum allowable operating pressure must be established at
the lowest PFP for any known or postulated defect, or interacting
defects, remaining in the pipe divided by the greater of 1.25 or the
applicable factor listed in Sec. 192.619(a)(2)(ii) or Sec.
192.620(a)(2)(ii).
(ii) Use of prior pressure test. If pressure test records as
described in subpart J of this part and Sec. 192.624(c)(1) exist for
the segment, then an in-line inspection program is not required,
provided that the remaining life of the most severe defects that could
have survived the pressure test have been calculated and a re-
assessment interval has been established. The appropriate retest
interval and periodic tests for time-dependent threats must be
determined in accordance with the methodology in Sec. 192.624(d)
Fracture mechanics modeling for failure stress and crack growth
analysis.
(iii) In-line inspection. If the segment does not have records for
a pressure test in accordance with subpart J of this part and Sec.
192.624(c)(1), the operator must develop and implement an inline
inspection (ILI) program using tools that can detect wall loss,
deformation from
[[Page 20836]]
dents, wrinkle bends, ovalities, expansion, seam defects including
cracking and selective seam weld corrosion, longitudinal,
circumferential and girth weld cracks, hard spot cracking, and stress
corrosion cracking. At a minimum, the operator must conduct an
assessment using high resolution magnetic flux leakage (MFL) tool, a
high resolution deformation tool, and either an electromagnetic
acoustic transducer (EMAT) or ultrasonic testing (UT) tool.
(A) In lieu of the tools specified in paragraph Sec.
192.624(c)(3)(i), an operator may use ``other technology'' if it is
validated by a subject matter expert in metallurgy and fracture
mechanics to produce an equivalent understanding of the condition of
the pipe. If an operator elects to use ``other technology,'' it must
notify the Associate Administrator of Pipeline Safety, at least 180
days prior to use, in accordance with paragraph (e) of this section and
receive a ``no objection letter'' from the Associate Administrator of
Pipeline Safety prior to its usage. The ``other technology''
notification must have:
(1) Descriptions of the technology or technologies to be used for
all tests, examinations, and assessments including characterization of
defect size crack assessments (length, depth, and volumetric); and
(2) Procedures and processes to conduct tests, examinations, and
assessments, perform evaluations, analyze defects and remediate defects
discovered.
(B) If the operator has information that indicates a pipeline
includes segments that might be susceptible to hard spots based on
assessment, leak, failure, manufacturing vintage history, or other
information, then the ILI program must include a tool that can detect
hard spots.
(C) If the pipeline has had a reportable incident, as defined in
Sec. 192.3, attributed to a girth weld failure since its most recent
pressure test, then the ILI program must include a tool that can detect
girth weld defects unless the ECA analysis performed in accordance with
paragraph Sec. 192.624(c)(3)(iii) includes an engineering evaluation
program to analyze the susceptibility of girth weld failure due to
lateral stresses.
(D) Inline inspection must be performed in accordance with Sec.
192.493.
(E) All MFL and deformation tools used must have been validated to
characterize the size of defects within 10% of the actual dimensions
with 90% confidence. All EMAT or UT tools must have been validated to
characterize the size of cracks, both length and depth, within 20% of
the actual dimensions with 80% confidence, with like-similar analysis
from prior tool runs done to ensure the results are consistent with the
required corresponding hydrostatic test pressure for the segment being
evaluated.
(F) Interpretation and evaluation of assessment results must meet
the requirements of Sec. Sec. 192.710, 192.713, and subpart O of this
part, and must conservatively account for the accuracy and reliability
of ILI, in-the-ditch examination methods and tools, and any other
assessment and examination results used to determine the actual sizes
of cracks, metal loss, deformation and other defect dimensions by
applying the most conservative limit of the tool tolerance
specification. ILI and in-the-ditch examination tools and procedures
for crack assessments (length, depth, and volumetric) must have
performance and evaluation standards confirmed for accuracy through
confirmation tests for the type defects and pipe material vintage being
evaluated. Inaccuracies must be accounted for in the procedures for
evaluations and fracture mechanics models for predicted failure
pressure determinations.
(G) Anomalies detected by ILI assessments must be repaired in
accordance with applicable repair criteria in Sec. Sec. 192.713 and
192.933.
(iv) If the operator has reason to believe any pipeline segment
contains or may be susceptible to cracks or crack-like defects due to
assessment, leak, failure, or manufacturing vintage histories, or any
other available information about the pipeline, the operator must
estimate the remaining life of the pipeline in accordance with
paragraph Sec. 192.624(d).
(4) Method 4: Pipe replacement. Replace the pipeline segment.
(5) Method 5: Pressure reduction for segments with small potential
impact radius and diameter. Pipelines with a maximum allowable
operating pressure less than 30 percent of specified minimum yield
strength, a potential impact radius (PIR) less than or equal to 150
feet, nominal diameter equal to or less than 8-inches, and which cannot
be assessed using inline inspection or pressure test, may establish the
maximum allowable operating pressure as follows:
(i) Reduce the pipeline maximum allowable operating pressure to no
greater than the highest actual operating pressure sustained by the
pipeline during 18 months preceding [effective date of the final rule],
divided by 1.1. The highest actual sustained pressure must have been
reached for a minimum cumulative duration of eight hours during one
continuous 30-day period. The reduced maximum allowable operating
pressure must account for differences between discharge and upstream
pressure on the pipeline by use of either the lowest value for the
entire segment or the operating pressure gradient (i.e., the location
specific operating pressure at each location);
(ii) Conduct external corrosion direct assessment in accordance
with Sec. 192.925, and internal corrosion direct assessment in
accordance with Sec. 192.927;
(iii) Develop and implement procedures for conducting non-
destructive tests, examinations, and assessments for cracks and crack-
like defects, including but not limited to stress corrosion cracking,
selective seam weld corrosion, girth weld cracks, and seam defects, for
pipe at all excavations associated with anomaly direct examinations, in
situ evaluations, repairs, remediations, maintenance, or any other
reason for which the pipe segment is exposed, except for segments
exposed during excavation activities that are in compliance with Sec.
192.614;
(iv) Conduct monthly patrols in Class 1 and 2 locations, at an
interval not to exceed 45 days; weekly patrols in Class 3 locations not
to exceed 10 days; and semi-weekly patrols in Class 4 locations, at an
interval not to exceed six days, in accordance with Sec. 192.705;
(v) Conduct monthly, instrumented leakage surveys in Class 1 and 2
locations, at intervals not to exceed 45 days; weekly leakage surveys
in Class 3 locations at intervals not to exceed 10 days; and semi-
weekly leakage surveys in Class 4 locations, at intervals not to exceed
six days, in accordance with Sec. 192.706; and
(vi) Odorize gas transported in the segment, in accordance with
Sec. 192.625;
(vii) If the operator has reason to believe any pipeline segment
contains or may be susceptible to cracks or crack-like defects due to
assessment, leak, failure, or manufacturing vintage histories, or any
other available information about the pipeline, the operator must
estimate the remaining life of the pipeline in accordance with
paragraph Sec. 192.624(d).
(viii) Under Method 5 described in paragraph (c)(5) of this
section, future uprating of the segment in accordance with subpart K of
this part is allowed.
(6) Method 6: Alternative technology. Operators may use an
alternative technical evaluation process that provides a sound
engineering basis for establishing maximum allowable operating
pressure. If an operator elects to use alternative technology, the
[[Page 20837]]
operator must notify PHMSA at least 180 days in advance of use in
accordance with paragraph (e) of this section. The operator must submit
the alternative technical evaluation to PHMSA with the notification and
obtain a ``no objection letter'' from the Associate Administrator of
Pipeline Safety prior to usage of alternative technology. The
notification must include the following details:
(i) Descriptions of the technology or technologies to be used for
tests, examinations, and assessments, establishment of material
properties, and analytical techniques, with like-similar analysis from
prior tool runs done to ensure the results are consistent with the
required corresponding hydrostatic test pressure for the segment being
evaluated.
(ii) Procedures and processes to conduct tests, examinations, and
assessments, perform evaluations, analyze defects and flaws, and
remediate defects discovered;
(iii) Methodology and criteria used to determine reassessment
period or need for a reassessment including references to applicable
regulations from this part and industry standards;
(iv) Data requirements including original design, maintenance and
operating history, anomaly or flaw characterization;
(v) Assessment techniques and acceptance criteria, including
anomaly detection confidence level, probability of detection, and
uncertainty of PFP quantified as a fraction of specified minimum yield
strength;
(vi) If the operator has reason to believe any pipeline segment
contains or may be susceptible to cracks or crack-like defects due to
assessment, leak, failure, or manufacturing vintage histories, or any
other available information about the pipeline, the operator must
estimate the remaining life of the pipeline in accordance with
paragraph (d) of this section;
(vii) Remediation methods with proven technical practice;
(viii) Schedules for assessments and remediation;
(ix) Operational monitoring procedures;
(x) Methodology and criteria used to justify and establish the
maximum allowable operating pressure; and
(xi) Documentation requirements for the operator's process,
including records to be generated.
(d) Fracture mechanics modeling for failure stress and crack growth
analysis. (1) If the operator has reason to believe any pipeline
segment contains or may be susceptible to cracks or crack-like defects
due to assessment, leak, failure, or manufacturing vintage histories,
or any other available information about the pipeline, the operator
must perform fracture mechanics modeling for failure stress pressure
and crack growth analysis to determine the remaining life of the
pipeline at the maximum allowable operating pressure based on the
applicable test pressures in accordance with Sec. 192.506 including
the remaining crack flaw size in the pipeline segment, any pipe failure
or leak mechanisms identified during pressure testing, pipe
characteristics, material toughness, failure mechanism for the
microstructure(ductile and brittle or both), location and type of
defect, operating environment, and operating conditions including
pressure cycling. Fatigue analysis must be performed using a recognized
form of the Paris Law as specified in Battelle's Final Report No. 13-
021; Subtask 2.5 (incorporated by reference, see Sec. 192.7) or other
technically appropriate engineering methodology validated by a subject
matter expert in metallurgy and fracture mechanics to give conservative
predictions of flaw growth and remaining life. When assessing other
degradation processes, the analysis must be performed using recognized
rate equations whose applicability and validity is demonstrated for the
case being evaluated. For cases involving calculation of the critical
flaw size, conservative remaining life analysis must assess the
smallest critical sizes and use a lower-bound toughness. For cases
dealing with an estimating of the defect sizes that would survive a
hydro test pressure, conservative remaining life analysis that must
assess the largest surviving sizes and use upper-bound values of
material strength and toughness. The analysis must include a
sensitivity analysis to determine conservative estimates of time to
failure for cracks. Material strength and toughness values used must
reflect the local conditions for growth, and use data that is case
specific to estimate the range of strength and toughness for such
analysis. When the strength and toughness and limits on their ranges
are unknown, the analysis must assume material strength and fracture
toughness levels corresponding to the type of assessment being
performed, as follows:
(i) For an assessment using a hydrostatic pressure test use a full
size equivalent Charpy upper-shelf energy level of 120 ft-lb and a flow
stress equal to the minimum specified ultimate tensile strength of the
base pipe material. The purpose of using the high level of Charpy
energy and flow stress (equal to the ultimate tensile strength) is for
an operator to calculate the largest defects that could have survived a
given level of hydrostatic test. The resulting maximum-size defects
lead to the shortened predicted times to failure,
(ii) For ILI assessments unless actual ranges of values of strength
and toughness are known, the analysis must use the specified minimum
yield strength and the specified minimum ultimate tensile strength and
Charpy toughness valves lower than or equal to: 5.0 ft-lb for body
cracks; 1.0 ft-lb for ERW seam bond line defects such as cold weld,
lack of fusion, and selective seam weld corrosion defects.
(iii) The sensitivity analysis to determine the time to failure for
a crack must include operating history, pressure tests, pipe geometry,
wall thickness, strength level, flow stress, and operating environment
for the pipe segment being assessed, including at a minimum the role of
the pressure-cycle spectrum.
(2) If actual material toughness is not known or not adequately
documented for fracture mechanics modeling for failure stress pressure,
the operator must use a conservative Charpy energy value to determine
the toughness based upon the material documentation program specified
in Sec. 192.607; or use maximum Charpy energy values of 5.0 ft-lb for
body cracks; 1.0 ft-lb for cold weld, lack of fusion, and selective
seam weld corrosion defects as documented in Battelle Final Reports
(``Battelle's Experience with ERW and Flash Weld Seam Failures: Causes
and Implications''--Task 1.4), No. 13-002 (``Models for Predicting
Failure Stress Levels for Defects Affecting ERW and Flash-Welded
Seams''--Subtask 2.4), Report No. 13-021 (``Predicting Times to Failure
for ERW Seam Defects that Grow by Pressure-Cycle-Induced Fatigue''--
Subtask 2.5) and (``Final Summary Report and Recommendations for the
Comprehensive Study to Understand Longitudinal ERW Seam Failures--Phase
1''--Task 4.5) (incorporated by reference, see Sec. 192.7); or other
appropriate technology or technical publications that an operator
demonstrates can provide a conservative Charpy energy values of the
crack-related conditions of the line pipe.
(3) The analysis must account for metallurgical properties at the
location being analyzed (such as in the properties of the parent pipe,
weld heat affected zone, or weld metal bond line), and must account for
the likely failure mode of anomalies (such as brittle fracture, ductile
fracture or both). If the likely failure mode is uncertain or unknown,
the analysis must analyze both failure modes and use the more
conservative result. Appropriate fracture
[[Page 20838]]
mechanics modeling for failure stress pressures in the brittle failure
mode is the Raju/Newman Model (Task 4.5) and for the ductile failure
mode is the Modified LnSec (Task 4.5) and Raju/Newman Models or other
proven-equivalent engineering fracture mechanics models for determining
conservative failure pressures may be used.
(4) If the predicted remaining life of the pipeline calculated by
this analysis is 5 years or less, then the operator must perform a
pressure test in accordance with paragraph (c)(1) of this section or
reduce the maximum allowable operating pressure of the pipeline in
accordance with paragraph (c)(2) of this section to establish the
maximum allowable operating pressure within 1-year of analysis;
(5) The operator must re-evaluate the remaining life of the
pipeline before 50% of the remaining life calculated by this analysis
has expired, but within 15 years. The operator must determine and
document if further pressure tests or use of other methods are required
at that time. The operator must continue to re-evaluate the remaining
life of the pipeline before 50% of the remaining life calculated in the
most recent evaluation has expired. If the analysis results show that a
50% remaining life reduction does not give a sufficient safety factor
based upon technical evaluations then a more conservative remaining
life safety factor must be used.
(6) The analysis required by this paragraph (d) of this section
must be reviewed and confirmed by a subject matter expert in both
metallurgy and fracture mechanics.
(e) Notifications. An operator must submit all notifications
required by this section to the Associate Administrator for Pipeline
Safety, by:
(1) Sending the notification to the Office of Pipeline Safety,
Pipeline and Hazardous Material Safety Administration, U.S. Department
of Transportation, Information Resources Manager, PHP-10, 1200 New
Jersey Avenue SE., Washington, DC 20590-0001;
(2) Sending the notification to the Information Resources Manager
by facsimile to (202) 366-7128; or
(3) Sending the notification to the Information Resources Manager
by email to InformationResourcesManager@dot.gov.
(4) An operator must also send a copy to a State pipeline safety
authority when the pipeline is located in a State where PHMSA has an
interstate agent agreement, or an intrastate pipeline is regulated by
that State.
(f) Records. Each operator must keep for the life of the pipeline
reliable, traceable, verifiable, and complete records of the
investigations, tests, analyses, assessments, repairs, replacements,
alterations, and other actions made in accordance with the requirements
of this section.
0
34. Section 192.710 is added to read as follows:
Sec. 192.710 Pipeline assessments.
(a) Applicability. (1) This section applies to onshore transmission
pipeline segments that are located in:
(i) A class 3 or class 4 location; or
(ii) A moderate consequence area as defined in Sec. 192.3 if the
pipe segment can accommodate inspection by means of instrumented inline
inspection tools (i.e., ``smart pigs'').
(2) This section does not apply to a pipeline segment located in a
high consequence area as defined in Sec. 192.903.
(b) General. (1) An operator must perform initial assessments in
accordance with this section no later than [date 15 years after
effective date of the final rule] and periodic reassessments every 20
years thereafter, or a shorter reassessment internal based upon the
type anomaly, operational, material, and environmental conditions found
on the pipeline segment, or as otherwise necessary to ensure public
safety.
(2) Prior assessment. An operator may use a prior assessment
conducted before [effective date of the final rule] as an initial
assessment for the segment, if the assessment meets the subpart O of
this part requirements for in-line inspection. If an operator uses this
prior assessment as its initial assessment, the operator must reassess
the pipeline segment according to the reassessment interval specified
in paragraph (b)(1) of this section.
(3) MAOP verification. An operator may use an integrity assessment
to meet the requirements of this section if the pipeline segment
assessment is conducted in accordance with the integrity assessment
requirements of Sec. 192.624(c) for establishing MAOP.
(c) Assessment method. The initial assessments and the
reassessments required by paragraph (b) of this section must be capable
of identifying anomalies and defects associated with each of the
threats to which the pipeline is susceptible and must be performed
using one or more of the following methods:
(1) Internal inspection tool or tools capable of detecting
corrosion, deformation and mechanical damage (including dents, gouges
and grooves), material cracking and crack-like defects (including
stress corrosion cracking, selective seam weld corrosion,
environmentally assisted cracking, and girth weld cracks), hard spots,
and any other threats to which the segment is susceptible. When
performing an assessment using an in-line inspection tool, an operator
must comply with Sec. 192.493;
(2) Pressure test conducted in accordance with subpart J of this
part. The use of pressure testing is appropriate for threats such as
internal corrosion, external corrosion, and other environmentally
assisted corrosion mechanisms, manufacturing and related defect
threats, including defective pipe and pipe seams, dents and other forms
of mechanical damage;
(3) ``Spike'' hydrostatic pressure test in accordance with Sec.
192.506;
(4) Excavation and in situ direct examination by means of visual
examination and direct measurement and recorded non-destructive
examination results and data needed to assess all threats, including
but not limited to, ultrasonic testing (UT), radiography, and magnetic
particle inspection (MPI);
(5) Guided wave ultrasonic testing (GWUT) as described in appendix
F;
(6) Direct assessment to address threats of external corrosion,
internal corrosion, and stress corrosion cracking. Use of direct
assessment is allowed only if the line is not capable of inspection by
internal inspection tools and is not practical to assess (due to low
operating pressures and flows, lack of inspection technology, and
critical delivery areas such as hospitals and nursing homes) using the
methods specified in paragraphs (d)(1) through (5) of this section. An
operator must conduct the direct assessment in accordance with the
requirements listed in Sec. 192.923 and with the applicable
requirements specified in Sec. Sec. 192.925, 192.927 or 192.929; or
(7) Other technology or technologies that an operator demonstrates
can provide an equivalent understanding of the line pipe for each of
the threats to which the pipeline is susceptible.
(8) For segments with MAOP less than 30% of the SMYS, an operator
must assess for the threats of external and internal corrosion, as
follows:
(i) External corrosion. An operator must take one of the following
actions to address external corrosion on a low stress segment:
(A) Cathodically protected pipe. To address the threat of external
corrosion on cathodically protected pipe, an operator must perform an
indirect assessment (i.e. indirect examination
[[Page 20839]]
tool/method such as close interval survey, alternating current voltage
gradient, direct current voltage gradient, or equivalent) at least
every seven years on the segment. An operator must use the results of
each survey as part of an overall evaluation of the cathodic protection
and corrosion threat for the segment. This evaluation must consider, at
minimum, the leak repair and inspection records, corrosion monitoring
records, exposed pipe inspection records, and the pipeline environment.
(B) Unprotected pipe or cathodically protected pipe where indirect
assessments are impractical. To address the threat of external
corrosion on unprotected pipe or cathodically protected pipe where
indirect assessments are impractical, an operator must--
(1) Conduct leakage surveys as required by Sec. 192.706 at 4-month
intervals; and
(2) Every 18 months, identify and remediate areas of active
corrosion by evaluating leak repair and inspection records, corrosion
monitoring records, exposed pipe inspection records, and the pipeline
environment.
(ii) Internal corrosion. To address the threat of internal
corrosion on a low stress segment, an operator must--
(A) Conduct a gas analysis for corrosive agents at least twice each
calendar year;
(B) Conduct periodic testing of fluids removed from the segment. At
least once each calendar year test the fluids removed from each storage
field that may affect a segment; and
(C) At least every seven (7) years, integrate data from the
analysis and testing required by paragraphs (c)(8)(ii)(A) and (B) of
this section with applicable internal corrosion leak records, incident
reports, safety-related condition reports, repair records, patrol
records, exposed pipe reports, and test records, and define and
implement appropriate remediation actions.
(d) Data analysis. A person qualified by knowledge, training, and
experience must analyze the data obtained from an assessment performed
under paragraph (b) of this section to determine if a condition could
adversely affect the safe operation of the pipeline. In addition, an
operator must explicitly consider uncertainties in reported results
(including, but not limited to, tool tolerance, detection threshold,
probability of detection, probability of identification, sizing
accuracy, conservative anomaly interaction criteria, location accuracy,
anomaly findings, and unity chart plots or equivalent for determining
uncertainties and verifying tool performance) in identifying and
characterizing anomalies.
(e) Discovery of condition. Discovery of a condition occurs when an
operator has adequate information to determine that a condition exists.
An operator must promptly, but no later than 180 days after an
assessment, obtain sufficient information about a condition to make the
determination required under paragraph (d), unless the operator can
demonstrate that that 180-days is impracticable.
(f) Remediation. An operator must comply with the requirements in
Sec. 192.713 if a condition that could adversely affect the safe
operation of a pipeline is discovered.
(g) Consideration of information. An operator must consider all
available information about a pipeline in complying with the
requirements in paragraphs (a) through (f) of this section.
0
35. In Sec. 192.711, paragraph (b)(1) is revised to read as follows:
Sec. 192.711 Transmission lines: General requirements for repair
procedures.
* * * * *
(b) * * *
(1) Non integrity management repairs. Whenever an operator
discovers any condition that could adversely affect the safe operation
of a pipeline segment not covered under subpart O of this part, Gas
Transmission Pipeline Integrity Management, it must correct the
condition as prescribed in Sec. 192.713. However, if the condition is
of such a nature that it presents an immediate hazard to persons or
property, the operator must reduce the operating pressure to a level
not exceeding 80% of the operating pressure at the time the condition
was discovered and take additional immediate temporary measures in
accordance with paragraph (a) of this section to protect persons or
property. The operator must make permanent repairs as soon as feasible.
* * * * *
0
36. Section 192.713 is revised to read as follows:
Sec. 192.713 Transmission lines: Permanent field repair of
imperfections and damages.
(a) This section applies to transmission lines. Line segments that
are located in high consequence areas, as defined in Sec. 192.903,
must also comply with applicable actions specified by the integrity
management requirements in subpart O of this part.
(b) General. Each operator must, in repairing its pipeline systems,
ensure that the repairs are made in a safe manner and are made so as to
prevent damage to persons, property, or the environment. Operating
pressure must be at a safe level during repair operations.
(c) Repair. Each imperfection or damage that impairs the
serviceability of pipe in a steel transmission line operating at or
above 40 percent of SMYS must be--
(1) Removed by cutting out and replacing a cylindrical piece of
pipe; or
(2) Repaired by a method that reliable engineering tests and
analyses show can permanently restore the serviceability of the pipe.
(d) Remediation schedule. For pipelines not located in high
consequence areas, an operator must complete the remediation of a
condition according to the following schedule:
(1) Immediate repair conditions. An operator must repair the
following conditions immediately upon discovery:
(i) A calculation of the remaining strength of the pipe shows a
predicted failure pressure less than or equal to 1.1 times the maximum
allowable operating pressure at the location of the anomaly. Suitable
remaining strength calculation methods include, ASME/ANSI B31G;
RSTRENG; or an alternative equivalent method of remaining strength
calculation. These documents are incorporated by reference and
available at the addresses listed in Sec. 192.7(c). Pipe and material
properties used in remaining strength calculations must be documented
in reliable, traceable, verifiable, and complete records. If such
records are not available, pipe and material properties used in the
remaining strength calculations must be based on properties determined
and documented in accordance with Sec. 192.607.
(ii) A dent that has any indication of metal loss, cracking or a
stress riser.
(iii) Metal loss greater than 80% of nominal wall regardless of
dimensions.
(iv) An indication of metal-loss affecting a detected longitudinal
seam, if that seam was formed by direct current or low-frequency or
high frequency electric resistance welding or by electric flash
welding.
(v) Any indication of significant stress corrosion cracking (SCC).
(vi) Any indication of significant selective seam weld corrosion
(SSWC).
(vii) An indication or anomaly that in the judgment of the person
designated by the operator to evaluate the assessment results requires
immediate action.
(2) Until the remediation of a condition specified in paragraph
(d)(1) of this section is complete, an operator must reduce the
operating pressure of the affected pipeline to the lower of:
[[Page 20840]]
(i) A level that restores the safety margin commensurate with the
design factor for the Class Location in which the affected pipeline is
located, determined using ASME/ANSI B31G (``Manual for Determining the
Remaining Strength of Corroded Pipelines'' (1991) or AGA Pipeline
Research Committee Project PR-3-805 (``A Modified Criterion for
Evaluating the Remaining Strength of Corroded Pipe'' (December 1989))
(``RSTRENG,'' incorporated by reference, see Sec. 192.7) for corrosion
defects. Both procedures apply to corroded regions that do not
penetrate the pipe wall over 80 percent of the wall thickness and are
subject to the limitations prescribed in the equations procedures. When
determining the predicted failure pressure (PFP) for gouges, scrapes,
selective seam weld corrosion, crack-related defects, appropriate
failure criteria and justification of the criteria must be used. If
SMYS or actual material yield and ultimate tensile strength is not
known or not adequately documented by reliable, traceable, verifiable,
and complete records, then the operator must assume grade A pipe or
determine the material properties based upon the material documentation
program specified in Sec. 192.607; or
(ii) 80% of pressure at the time of discovery, whichever is lower.
(3) Two-year conditions. An operator must repair the following
conditions within two years of discovery:
(i) A smooth dent located between the 8 o'clock and 4 o'clock
positions (upper 2/3 of the pipe) with a depth greater than 6% of the
pipeline diameter (greater than 0.50 inches in depth for a pipeline
diameter less than nominal pipe size (NPS) 12).
(ii) A dent with a depth greater than 2% of the pipeline's diameter
(0.250 inches in depth for a pipeline diameter less than NPS 12) that
affects pipe curvature at a girth weld or at a longitudinal or helical
(spiral) seam weld.
(iii) A calculation of the remaining strength of the pipe shows a
predicted failure pressure ratio (FPR) at the location of the anomaly
less than or equal to 1.25 for Class 1 locations, 1.39 for Class 2
locations, 1.67 for Class 3 locations, and 2.00 for Class 4 locations.
This calculation must adequately account for the uncertainty associated
with the accuracy of the tool used to perform the assessment.
(iv) An area of corrosion with a predicted metal loss greater than
50% of nominal wall.
(v) Predicted metal loss greater than 50% of nominal wall that is
located at a crossing of another pipeline, or is in an area with
widespread circumferential corrosion, or is in an area that could
affect a girth weld.
(vi) A gouge or groove greater than 12.5% of nominal wall.
(vii) Any indication of crack or crack-like defect other than an
immediate condition.
(4) Monitored conditions. An operator does not have to schedule the
following conditions for remediation, but must record and monitor the
conditions during subsequent risk assessments and integrity assessments
for any change that may require remediation:
(i) A dent with a depth greater than 6% of the pipeline diameter
(greater than 0.50 inches in depth for a pipeline diameter less than
NPS 12) located between the 4 o'clock position and the 8 o'clock
position (bottom 1/3 of the pipe).
(ii) A dent located between the 8 o'clock and 4 o'clock positions
(upper 2/3 of the pipe) with a depth greater than 6% of the pipeline
diameter (greater than 0.50 inches in depth for a pipeline diameter
less than nominal pipe size (NPS) 12), and engineering analyses of the
dent demonstrate critical strain levels are not exceeded.
(e) Other conditions. Unless another timeframe is specified in
paragraph (d) of this section, an operator must take appropriate
remedial action to correct any condition that could adversely affect
the safe operation of a pipeline system in accordance with the
criteria, schedules and methods defined in the operator's Operating and
Maintenance procedures.
(f) In situ direct examination of crack defects. Whenever required
by this part, operators must perform direct examination of known
locations of cracks or crack-like defects using inverse wave field
extrapolation (IWEX), phased array, automated ultrasonic testing (AUT),
or equivalent technology that has been validated to detect tight cracks
(equal to or less than 0.008 inches). In-the-ditch examination tools
and procedures for crack assessments (length, depth, and volumetric)
must have performance and evaluation standards, including pipe or weld
surface cleanliness standards for the inspection, confirmed by subject
matter experts qualified by knowledge, training, and experience in
direct examination inspection and in metallurgy and fracture mechanics
for accuracy for the type of defects and pipe material being evaluated.
The procedures must account for inaccuracies in evaluations and
fracture mechanics models for failure pressure determinations.
0
37. Section 192.750 is added to read as follows:
Sec. 192.750 Launcher and receiver safety.
Any launcher or receiver used after [date 6 months after effective
date of the final rule], must be equipped with a device capable of
safely relieving pressure in the barrel before removal or opening of
the launcher or receiver barrel closure or flange and insertion or
removal of in-line inspection tools, scrapers, or spheres. The operator
must use a suitable device to indicate that pressure has been relieved
in the barrel or must provide a means to prevent opening of the barrel
closure or flange, or prevent insertion or removal of in-line
inspection tools, scrapers, or spheres, if pressure has not been
relieved.
0
38. In Sec. 192.911, paragraph (k) is revised to read as follows:
Sec. 192.911 What are the elements of an integrity management
program?
* * * * *
(k) A management of change process as required by Sec. 192.13(d).
* * * * *
0
39. In Sec. 192.917, paragraphs (a), (b), (c), (d), (e)(2), (e)(3),
and (e)(4) are revised to read as follows:
Sec. 192.917 How does an operator identify potential threats to
pipeline integrity and use the threat identification in its integrity
program?
(a) Threat identification. An operator must identify and evaluate
all potential threats to each covered pipeline segment. Potential
threats that an operator must consider include, but are not limited to,
the threats listed in ASME/ANSI B31.8S (incorporated by reference, see
Sec. 192.7), section 2, which are grouped under the following four
threats:
(1) Time dependent threats such as internal corrosion, external
corrosion, and stress corrosion cracking;
(2) Stable threats, such as manufacturing, welding/fabrication, or
equipment defects;
(3) Time independent threats such as third party/mechanical damage,
incorrect operational procedure, weather related and outside force,
including consideration of seismicity, geology, and soil stability of
the area; and
(4) Human error such as operational mishaps and design and
construction mistakes.
(b) Data gathering and integration. To identify and evaluate the
potential threats to a covered pipeline segment, an operator must
gather, verify, validate, and integrate existing data and
[[Page 20841]]
information on the entire pipeline that could be relevant to the
covered segment. In performing data gathering and integration, an
operator must follow the requirements in ASME/ANSI B31.8S, section 4.
At a minimum, an operator must gather and evaluate the set of data
specified in paragraph (b)(1) of this section and appendix A to ASME/
ANSI B31.8S. The evaluation must analyze both the covered segment and
similar non-covered segments, and must:
(1) Integrate information about pipeline attributes and other
relevant information, including, but not limited to:
(i) Pipe diameter, wall thickness, grade, seam type and joint
factor;
(ii) Manufacturer and manufacturing date, including manufacturing
data and records;
(iii) Material properties including, but not limited to, diameter,
wall thickness, grade, seam type, hardness, toughness, hard spots, and
chemical composition;
(iv) Equipment properties;
(v) Year of installation;
(vi) Bending method;
(vii) Joining method, including process and inspection results;
(viii) Depth of cover surveys including stream and river crossings,
navigable waterways, and beach approaches;
(ix) Crossings, casings (including if shorted), and locations of
foreign line crossings and nearby high voltage power lines;
(x) Hydrostatic or other pressure test history, including test
pressures and test leaks or failures, failure causes, and repairs;
(xi) Pipe coating methods (both manufactured and field applied)
including method or process used to apply girth weld coating,
inspection reports, and coating repairs;
(xii) Soil, backfill;
(xiii) Construction inspection reports, including but not limited
to:
(A) Girth weld non-destructive examinations;
(B) Post backfill coating surveys;
(C) Coating inspection (``jeeping'') reports;
(xiv) Cathodic protection installed, including but not limited to
type and location;
(xv) Coating type;
(xvi) Gas quality;
(xvii) Flow rate;
(xviii) Normal maximum and minimum operating pressures, including
maximum allowable operating pressure (MAOP);
(xix) Class location;
(xx) Leak and failure history including any in-service ruptures or
leaks from incident reports, abnormal operations, safety related
conditions (both reported and unreported) and failure investigations
required by Sec. 192.617, and their identified causes and
consequences;
(xxi) Coating condition;
(xxii) CP system performance;
(xxiii) Pipe wall temperature;
(xxiv) Pipe operational and maintenance inspection reports,
including but not limited to:
(A) Data gathered through integrity assessments required under this
part, including but not limited to in-line inspections, pressure tests,
direct assessment, guided wave ultrasonic testing, or other methods;
(B) Close interval survey (CIS) and electrical survey results;
(C) Cathodic protection (CP) rectifier readings;
(D) CP test point survey readings and locations;
(E) AC/DC and foreign structure interference surveys;
(F) Pipe coating surveys, including surveys to detect coating
damage, disbonded coatings, or other conditions that compromise the
effectiveness of corrosion protection, including but not limited to
direct current voltage gradient or alternating current voltage gradient
inspections;
(G) Results of examinations of exposed portions of buried pipelines
(e.g., pipe and pipe coating condition, see Sec. 192.459), including
the results of any non-destructive examinations of the pipe, seam or
girth weld, i.e. bell hole inspections;
(H) Stress corrosion cracking (SCC) excavations and findings;
(I) Selective seam weld corrosion (SSWC) excavations and findings;
(J) Gas stream sampling and internal corrosion monitoring results,
including cleaning pig sampling results;
(xxv) Outer Diameter/Inner Diameter corrosion monitoring;
(xxvi) Operating pressure history and pressure fluctuations,
including analysis of effects of pressure cycling and instances of
exceeding MAOP by any amount;
(xxvii) Performance of regulators, relief valves, pressure control
devices, or any other device to control or limit operating pressure to
less than MAOP;
(xxviii) Encroachments and right-of-way activity, including but not
limited to, one-call data, pipe exposures resulting from encroachments,
and excavation activities due to development or planned development
along the pipeline;
(xxix) Repairs;
(xxx) Vandalism;
(xxxi) External forces;
(xxxii) Audits and reviews;
(xxxiii) Industry experience for incident, leak and failure
history;
(xxxiv) Aerial photography;
(xxxv) Exposure to natural forces in the area of the pipeline,
including seismicity, geology, and soil stability of the area; and
(xxxvi) Other pertinent information derived from operations and
maintenance activities and any additional tests, inspections, surveys,
patrols, or monitoring required under this part.
(2) Use objective, traceable, verified, and validated information
and data as inputs, to the maximum extent practicable. If input is
obtained from subject matter experts (SMEs), the operator must employ
measures to adequately correct any bias in SME input. Bias control
measures may include training of SMEs and use of outside technical
experts (independent expert reviews) to assess quality of processes and
the judgment of SMEs. Operator must document the names of all SMEs and
information submitted by the SMEs for the life of the pipeline.
(3) Identify and analyze spatial relationships among anomalous
information (e.g., corrosion coincident with foreign line crossings;
evidence of pipeline damage where overhead imaging shows evidence of
encroachment). Storing or recording the information in a common
location, including a geographic information system (GIS), alone, is
not sufficient; and
(4) Analyze the data for interrelationships among pipeline
integrity threats, including combinations of applicable risk factors
that increase the likelihood of incidents or increase the potential
consequences of incidents.
(c) Risk assessment. An operator must conduct a risk assessment
that analyzes the identified threats and potential consequences of an
incident for each covered segment. The risk assessment must include
evaluation of the effects of interacting threats, including the
potential for interactions of threats and anomalous conditions not
previously evaluated. An operator must ensure validity of the methods
used to conduct the risk assessment in light of incident, leak, and
failure history and other historical information. Validation must
ensure the risk assessment methods produce a risk characterization that
is consistent with the operator's and industry experience, including
evaluations of the cause of past incidents, as determined by root cause
analysis or other equivalent means, and include sensitivity analysis of
the
[[Page 20842]]
factors used to characterize both the probability of loss of pipeline
integrity and consequences of the postulated loss of pipeline
integrity. An operator must use the risk assessment to determine
additional preventive and mitigative measures needed (Sec. 192.935)
for each covered segment, and periodically evaluate the integrity of
each covered pipeline segment (Sec. 192.937(b)). The risk assessment
must:
(1) Analyze how a potential failure could affect high consequence
areas, including the consequences of the entire worst-case incident
scenario from initial failure to incident termination;
(2) Analyze the likelihood of failure due to each individual threat
or risk factor, and each unique combination of threats or risk factors
that interact or simultaneously contribute to risk at a common
location;
(3) Lead to better understanding of the nature of the threat, the
failure mechanisms, the effectiveness of currently deployed risk
mitigation activities, and how to prevent, mitigate, or reduce those
risks;
(4) Account for, and compensate for, uncertainties in the model and
the data used in the risk assessment; and
(5) Evaluate the potential risk reduction associated with candidate
risk reduction activities such as preventive and mitigative measures
and reduced anomaly remediation and assessment intervals.
(d) Plastic transmission pipeline. An operator of a plastic
transmission pipeline must assess the threats to each covered segment
using the information in sections 4 and 5 of ASME B31.8S, and consider
any threats unique to the integrity of plastic pipe such as poor joint
fusion practices, pipe with poor slow crack growth (SCG) resistance,
brittle pipe, circumferential cracking, hydrocarbon softening of the
pipe, internal and external loads, longitudinal or lateral loads,
proximity to elevated heat sources, and point loading.
(e) * * *
(2) Cyclic fatigue. An operator must evaluate whether cyclic
fatigue or other loading conditions (including ground movement,
suspension bridge condition) could lead to a failure of a deformation,
including a dent or gouge, crack, or other defect in the covered
segment. The evaluation must assume the presence of threats in the
covered segment that could be exacerbated by cyclic fatigue. An
operator must use the results from the evaluation together with the
criteria used to evaluate the significance of this threat to the
covered segment to prioritize the integrity baseline assessment or
reassessment. Fracture mechanics modeling for failure stress pressures
and cyclic fatigue crack growth analysis must be conducted in
accordance with Sec. 192.624(d) for cracks. Cyclic fatigue analysis
must be annually, not to exceed 15 months.
(3) Manufacturing and construction defects. An operator must
analyze the covered segment to determine the risk of failure from
manufacturing and construction defects (including seam defects) in the
covered segment. The analysis must consider the results of prior
assessments on the covered segment. An operator may consider
manufacturing and construction related defects to be stable defects
only if the covered segment has been subjected to hydrostatic pressure
testing satisfying the criteria of subpart J of this part of at least
1.25 times MAOP, and the segment has not experienced an in-service
incident attributed to a manufacturing or construction defect since the
date of the pressure test. If any of the following changes occur in the
covered segment, an operator must prioritize the covered segment as a
high risk segment for the baseline assessment or a subsequent
reassessment, and must reconfirm or reestablish MAOP in accordance with
Sec. 192.624(c).
(i) The segment has experienced an in-service incident, as
described in Sec. 192.624(a)(1);
(ii) MAOP increases; or
(iii) The stresses leading to cyclic fatigue increase.
(4) ERW pipe. If a covered pipeline segment contains low frequency
electric resistance welded pipe (ERW), lap welded pipe, pipe with seam
factor less than 1.0 as defined in Sec. 192.113, or other pipe that
satisfies the conditions specified in ASME/ANSI B31.8S, Appendices A4.3
and A4.4, and any covered or non-covered segment in the pipeline system
with such pipe has experienced seam failure (including, but not limited
to pipe body cracking, seam cracking and selective seam weld
corrosion), or operating pressure on the covered segment has increased
over the maximum operating pressure experienced during the preceding
five years (including abnormal operation as defined in Sec.
192.605(c)), or MAOP has been increased, an operator must select an
assessment technology or technologies with a proven application capable
of assessing seam integrity and seam corrosion anomalies. The operator
must prioritize the covered segment as a high risk segment for the
baseline assessment or a subsequent reassessment. Pipe with cracks must
be evaluated using fracture mechanics modeling for failure stress
pressures and cyclic fatigue crack growth analysis to estimate the
remaining life of the pipe in accordance with Sec. 192.624(c) and (d).
* * * * *
0
40. In Sec. 192.921, paragraph (a) is revised to read as follows:
Sec. 192.921 How is the baseline assessment to be conducted?
(a) Assessment methods. An operator must assess the integrity of
the line pipe in each covered segment by applying one or more of the
following methods for each threat to which the covered segment is
susceptible. An operator must select the method or methods best suited
to address the threats identified to the covered segment (See Sec.
192.917). In addition, an operator may use an integrity assessment to
meet the requirements of this section if the pipeline segment
assessment is conducted in accordance with the integrity assessment
requirements of Sec. 192.624(c) for establishing MAOP.
(1) Internal inspection tool or tools capable of detecting
corrosion, deformation and mechanical damage (including dents, gouges
and grooves), material cracking and crack-like defects (including
stress corrosion cracking, selective seam weld corrosion,
environmentally assisted cracking, and girth weld cracks), hard spots
with cracking, and any other threats to which the covered segment is
susceptible. When performing an assessment using an in-line inspection
tool, an operator must comply with Sec. 192.493. A person qualified by
knowledge, training, and experience must analyze the data obtained from
an internal inspection tool to determine if a condition could adversely
affect the safe operation of the pipeline. In addition, an operator
must explicitly consider uncertainties in reported results (including,
but not limited to, tool tolerance, detection threshold, probability of
detection, probability of identification, sizing accuracy, conservative
anomaly interaction criteria, location accuracy, anomaly findings, and
unity chart plots or equivalent for determining uncertainties and
verifying actual tool performance) in identifying and characterizing
anomalies;
(2) Pressure test conducted in accordance with subpart J of this
part. An operator must use the test pressures specified in table 3 of
section 5 of ASME/ANSI B31.8S to justify an extended reassessment
interval in accordance with Sec. 192.939. The use of pressure testing
is appropriate for threats such as internal corrosion, external
corrosion, and other environmentally assisted corrosion mechanisms,
manufacturing and related defect threats, including defective pipe
[[Page 20843]]
and pipe seams, stress corrosion cracking, selective seam weld
corrosion, dents and other forms of mechanical damage;
(3) ``Spike'' hydrostatic pressure test in accordance with Sec.
192.506. The use of spike hydrostatic pressure testing is appropriate
for threats such as stress corrosion cracking, selective seam weld
corrosion, manufacturing and related defects, including defective pipe
and pipe seams, and other forms of defect or damage involving cracks or
crack-like defects;
(4) Excavation and in situ direct examination by means of visual
examination, direct measurement, and recorded non-destructive
examination results and data needed to assess all threats, including
but not limited to, ultrasonic testing (UT), radiography, and magnetic
particle inspection (MPI);
(5) Guided Wave Ultrasonic Testing (GWUT) conducted as described in
Appendix F;
(6) Direct assessment to address threats of external corrosion,
internal corrosion, and stress corrosion cracking. Use of direct
assessment is allowed only if the line is not capable of inspection by
internal inspection tools and is not practical to assess using the
methods specified in paragraphs (d)(1) through (5) of this section. An
operator must conduct the direct assessment in accordance with the
requirements listed in Sec. 192.923 and with the applicable
requirements specified in Sec. 192.925, 192.927, or 192.929; or
(7) Other technology that an operator demonstrates can provide an
equivalent understanding of the condition of the line pipe for each of
the threats to which the pipeline is susceptible. An operator choosing
this option must notify the Office of Pipeline Safety (OPS) 180 days
before conducting the assessment, in accordance with Sec. 192.949 and
receive a ``no objection letter'' from the Associate Administrator of
Pipeline Safety. An operator must also notify the appropriate State or
local pipeline safety authority when a covered segment is located in a
State where OPS has an interstate agent agreement, or an intrastate
covered segment is regulated by that State.
* * * * *
0
41. In Sec. 192.923, paragraphs (b)(2) and (b)(3) are revised to read
as follows:
Sec. 192.923 How is direct assessment used and for what threats?
* * * * *
(b) * * *
(2) NACE SP0206-2006 and Sec. 192.927 if addressing internal
corrosion (ICDA).
(3) NACE SP0204-2008 and Sec. 192.929 if addressing stress
corrosion cracking (SCCDA).
* * * * *
0
42. In Sec. 192.927, paragraphs (b) and (c) are revised to read as
follows:
Sec. 192.927 What are the requirements for using Internal Corrosion
Direct Assessment (ICDA)?
* * * * *
(b) General requirements. An operator using direct assessment as an
assessment method to address internal corrosion in a covered pipeline
segment must follow the requirements in this section and in NACE
SP0206-2006 (incorporated by reference, see Sec. 192.7). The Dry Gas
(DG) Internal Corrosion Direct Assessment (ICDA) process described in
this section applies only for a segment of pipe transporting normally
dry natural gas (see definition Sec. 192.3), and not for a segment
with electrolyte normally present in the gas stream. If an operator
uses ICDA to assess a covered segment operating with electrolyte
present in the gas stream, the operator must develop a plan that
demonstrates how it will conduct ICDA in the segment to effectively
address internal corrosion, and must notify the Office of Pipeline
Safety (OPS) 180 days before conducting the assessment in accordance
with Sec. 192.921(a)(4) or Sec. 192.937(c)(4).
(c) The ICDA plan. An operator must develop and follow an ICDA plan
that meets all requirements and recommendations contained in NACE
SP0206-2006 and that implements all four steps of the DG-ICDA process
including pre-assessment, indirect inspection, detailed examination,
and post-assessment. The plan must identify where all ICDA Regions with
covered segments are located in the transmission system. An ICDA Region
is a continuous length of pipe (including weld joints) uninterrupted by
any significant change in water or flow characteristics that includes
similar physical characteristics or operating history. An ICDA Region
extends from the location where liquid may first enter the pipeline and
encompasses the entire area along the pipeline where internal corrosion
may occur until a new input introduces the possibility of water
entering the pipeline. In cases where a single covered segment is
partially located in two or more ICDA regions, the four-step ICDA
process must be completed for each ICDA region in which the covered
segment is partially located in order to complete the assessment of the
covered segment.
(1) Preassessment. An operator must comply with the requirements
and recommendations in NACE SP0206-2006 in conducting the preassessment
step of the ICDA process.
(2) Indirect Inspection. An operator must comply with the
requirements and recommendations in NACE SP0206-2006, and the following
additional requirements, in conducting the Indirect Inspection step of
the ICDA process. Operators must explicitly document the results of its
feasibility assessment as required by NACE SP0206-2006, Section 3.3; if
any condition that precludes the successful application of ICDA
applies, then ICDA may not be used, and another assessment method must
be selected. When performing the indirect inspection, the operator must
use pipeline specific data, exclusively. The use of assumed pipeline or
operational data is prohibited. When calculating the critical
inclination angle of liquid holdup and the inclination profile of the
pipeline, the operator must consider the accuracy, reliability, and
uncertainty of data used to make those calculations, including but not
limited to gas flow velocity (including during upset conditions),
pipeline elevation profile survey data (including specific profile at
features with inclinations such as road crossing, river crossings,
drains, valves, drips, etc.), topographical data, depth of cover, etc.
The operator must select locations for direct examination, and
establish the extent of pipe exposure needed (i.e., the size of the
bell hole), to explicitly account for these uncertainties and their
cumulative effect on the precise location of predicted liquid dropout.
(3) Detailed examination. An operator must comply with the
requirements and recommendations in NACE SP0206-2006 in conducting the
detailed examination step of the ICDA process. In addition, on the
first use of ICDA for a covered segment, an operator must identify a
minimum of two locations for excavation within each covered segment
associated with the ICDA Region and must perform a detailed examination
for internal corrosion at each location using ultrasonic thickness
measurements, radiography, or other generally accepted measurement
techniques. One location must be the low point (e.g., sags, drips,
valves, manifolds, dead-legs, traps) within the covered segment nearest
to the beginning of the ICDA Region. The second location must be
further downstream, within a covered segment, near the end of the ICDA
Region. If corrosion is found at any location, the operator must--
(i) Evaluate the severity of the defect (remaining strength) and
remediate the defect in accordance with Sec. 192.933, if the condition
is in a covered segment,
[[Page 20844]]
or in accordance with Sec. Sec. 192.485 and 192.713 if the condition
is not in a covered segment;
(ii) Expand the detailed examination program, whenever internal
corrosion is discovered, to determine all locations that have internal
corrosion within the ICDA region, and accurately characterize the
nature, extent, and root cause of the internal corrosion. In cases
where the internal corrosion was identified within the ICDA region but
outside the covered segment, the expanded detailed examination program
must also include at least two detailed examinations within each
covered segment associated with the ICDA region, at the location within
the covered segment(s) most likely to have internal corrosion. One
location must be the low point (e.g., sags, drips, valves, manifolds,
dead-legs, traps) within the covered segment nearest to the beginning
of the ICDA Region. The second location must be further downstream,
within the covered segment. In instances of first use of ICDA for a
covered segment, where these locations have already been examined per
paragraph (c)(3) of this section, two additional detailed examinations
must be conducted within the covered segment; and
(iii) Expand the detailed examination program to evaluate the
potential for internal corrosion in all pipeline segments (both covered
and non-covered) in the operator's pipeline system with similar
characteristics to the ICDA region in which the corrosion was found and
remediate identified instances of internal corrosion in accordance with
Sec. 192.933 or Sec. 192.713, as appropriate.
(4) Post-assessment evaluation and monitoring. An operator must
comply with the requirements and recommendations in NACE SP0206-2006 in
performing the post assessment step of the ICDA process. In addition to
the post-assessment requirements and recommendations in NACE SP0206-
2006, the evaluation and monitoring process must also include--
(i) Evaluating the effectiveness of ICDA as an assessment method
for addressing internal corrosion and determining whether a covered
segment should be reassessed at more frequent intervals than those
specified in Sec. 192.939. An operator must carry out this evaluation
within a year of conducting an ICDA;
(ii) Validation of the flow modeling calculations by comparison of
actual locations of discovered internal corrosion with locations
predicted by the model (if the flow model cannot be validated, then
ICDA is not feasible for the segment); and
(iii) Continually monitoring each ICDA region which contains a
covered segment where internal corrosion has been identified by using
techniques such as coupons or UT sensors or electronic probes, and by
periodically drawing off liquids at low points and chemically analyzing
the liquids for the presence of corrosion products. An operator must
base the frequency of the monitoring and liquid analysis on results
from all integrity assessments that have been conducted in accordance
with the requirements of this subpart, and risk factors specific to the
ICDA region. At a minimum, the monitoring frequency must be two times
each calendar year, but at intervals not exceeding 7\1/2\ months. If an
operator finds any evidence of corrosion products in the ICDA region,
the operator must take prompt action in accordance with one of the two
following required actions and remediate the conditions the operator
finds in accordance with Sec. 192.933.
(A) Conduct excavations of, and detailed examinations at, locations
downstream from where the electrolyte might have entered the pipe to
investigate and accurately characterize the nature, extent, and root
cause of the corrosion, including the monitoring and mitigation
requirements of Sec. 192.478; or
(B) Assess the covered segment using ILI tools capable of detecting
internal corrosion.
(5) Other requirements--The ICDA plan must also include the
following:
(i) Criteria an operator will apply in making key decisions (e.g.,
ICDA feasibility, definition of ICDA Regions and Sub-regions,
conditions requiring excavation) in implementing each stage of the ICDA
process;
(ii) Provisions that analysis be carried out on the entire pipeline
in which covered segments are present, except that application of the
remediation criteria of Sec. 192.933 may be limited to covered
segments.
0
43. Section 192.929 is revised to read as follows:
Sec. 192.929 What are the requirements for using direct assessment
for stress corrosion cracking (SCCDA)?
(a) Definition. Stress corrosion cracking direct assessment (SCCDA)
is a process to assess a covered pipe segment for the presence of SCC
by systematically gathering and analyzing excavation data for pipe
having similar operational characteristics and residing in a similar
physical environment.
(b) General requirements. An operator using direct assessment as an
integrity assessment method to address stress corrosion cracking in a
covered pipeline segment must develop and follow an SCCDA plan that
meets all requirements and recommendations contained in NACE SP0204-
2008 and that implements all four steps of the SCCDA process including
pre-assessment, indirect inspection, detailed examination and post-
assessment. As specified in NACE SP0204-2008, Section 1.1.7, SCCDA is
complementary with other inspection methods such as in-line inspection
(ILI) or hydrostatic testing and is not necessarily an alternative or
replacement for these methods in all instances. In addition, the plan
must provide for--
(1) Data gathering and integration. An operator's plan must provide
for a systematic process to collect and evaluate data for all covered
segments to identify whether the conditions for SCC are present and to
prioritize the covered segments for assessment in accordance with NACE
SP0204-2008, sections 3 and 4, and table 1. This process must also
include gathering and evaluating data related to SCC at all sites an
operator excavates during the conduct of its pipeline operations (both
within and outside covered segments) where the criteria in NACE SP0204-
2008 indicate the potential for SCC. This data gathering process must
be conducted in accordance with NACE SP0204-2008, section 5.3, and must
include, at minimum, all data listed in NACE SP0204-2008, table 2.
Further, the following factors must be analyzed as part of this
evaluation:
(i) The effects of a carbonate-bicarbonate environment, including
the implications of any factors that promote the production of a
carbonate-bicarbonate environment such as soil temperature, moisture,
the presence or generation of carbon dioxide, and/or Cathodic
Protection (CP).
(ii) The effects of cyclic loading conditions on the susceptibility
and propagation of SCC in both high-pH and near-neutral-pH
environments.
(iii) The effects of variations in applied CP such as
overprotection, CP loss for extended periods, and high negative
potentials.
(iv) The effects of coatings that shield CP when disbonded from the
pipe.
(v) Other factors which affect the mechanistic properties
associated with SCC including but not limited to historical and
present-day operating pressures, high tensile residual stresses,
flowing product temperatures, and the presence of sulfides.
(2) Indirect inspection. In addition to the requirements and
recommendations of NACE SP0204-2008, section 4, the
[[Page 20845]]
plan's procedures for indirect inspection must include provisions for
conducting at least two above ground surveys using complementary
measurement tools most appropriate for the pipeline segment based on
the data gathering and integration step.
(3) Direct examination. In addition to the requirements and
recommendations of NACE SP0204-2008, the plan's procedures for direct
examination must provide for conducting a minimum of three direct
examinations within the SCC segment at locations determined to be the
most likely for SCC to occur.
(4) Remediation and mitigation. If any indication of SCC is
discovered in a segment, an operator must mitigate the threat in
accordance with one of the following applicable methods:
(i) Removing the pipe with SCC, remediating the pipe with a Type B
sleeve, hydrostatic testing in accordance with (b)(4)(ii), below, or by
grinding out the SCC defect and repairing the pipe. If grinding is used
for repair, the repair procedure must include: Nondestructive testing
for any remaining cracks or other defects; measuring remaining wall
thickness; and the remaining strength of the pipe at the repair
location must be determined using ASME/ANSI B31G or RSTRENG and must be
sufficient to meet the design requirements of subpart C of this part.
Pipe and material properties used in remaining strength calculations
must be documented in reliable, traceable, verifiable, and complete
records. If such records are not available, pipe and material
properties used in the remaining strength calculations must be based on
properties determined and documented in accordance with Sec. 192.607.
(ii) Significant SCC must be mitigated using a hydrostatic testing
program to a minimum test pressure equal to 105 percent of the
specified minimum yield strength of the pipe for 30 minutes immediately
followed by a pressure test in accordance with Sec. 192.506, but not
lower than 1.25 times MAOP. The test pressure for the entire sequence
must be continuously maintained for at least 8 hours, in accordance
with Sec. 192.506 and must be above the minimum test factors in Sec.
192.619(a)(2)(ii) or 192.620(a)(2)(ii), but not lower than 1.25 times
maximum allowable operating pressure. Any test failures due to SCC must
be repaired by replacement of the pipe segment, and the segment re-
tested until the pipe passes the complete test without leakage. Pipe
segments that have SCC present, but that pass the pressure test, may be
repaired by grinding in accordance with paragraph (b)(4)(i) of this
section.
(5) Post assessment. In addition to the requirements and
recommendations of NACE SP0204-2008, sections 6.3, periodic
reassessment, and 6.4, effectiveness of SCCDA, the operator's
procedures for post assessment must include development of a
reassessment plan based on the susceptibility of the operator's pipe to
SCC as well as on the mechanistic behavior of identified cracking.
Reassessment intervals must comply with Sec. 192.939. Factors that
must be considered include, but are not limited to:
(i) Evaluation of discovered crack clusters during the direct
examination step in accordance with NACE RP0204-2008, sections 5.3.5.7,
5.4, and 5.5;
(ii) Conditions conducive to creation of the carbonate-bicarbonate
environment;
(iii) Conditions in the application (or loss) of CP that can create
or exacerbate SCC;
(iv) Operating temperature and pressure conditions including
operating stress levels on the pipe;
(v) Cyclic loading conditions;
(vi) Mechanistic conditions that influence crack initiation and
growth rates;
(vii) The effects of interacting crack clusters;
(viii) The presence of sulfides; and.
(ix) Disbonded coatings that shield CP from the pipe.
0
44. In Sec. 192.933, paragraphs (a)(1), (b), (d)(1) are revised and
paragraphs (d)(2)(iii) through (vii) are added to read as follows:
Sec. 192.933 What actions must be taken to address integrity issues?
(a) * * *
(1) Temporary pressure reduction. If an operator is unable to
respond within the time limits for certain conditions specified in this
section, the operator must temporarily reduce the operating pressure of
the pipeline or take other action that ensures the safety of the
covered segment. An operator must determine any temporary reduction in
operating pressure required by this section using ASME/ANSI B31G
(incorporated by reference, see Sec. 192.7) or AGA Pipeline Research
Council International, PR-3-805 (R-STRENG) (incorporated by reference,
see Sec. 192.7) to determine the safe operating pressure that restores
the safety margin commensurate with the design factor for the Class
Location in which the affected pipeline is located, or reduce the
operating pressure to a level not exceeding 80 percent of the operating
pressure at the time the condition was discovered. Pipe and material
properties used in remaining strength calculations must be documented
in reliable, traceable, verifiable, and complete records. If such
records are not available, pipe and material properties used in the
remaining strength calculations must be based on properties determined
and documented in accordance with Sec. 192.607. An operator must
notify PHMSA in accordance with Sec. 192.949 if it cannot meet the
schedule for evaluation and remediation required under paragraph (c) of
this section and cannot provide safety through temporary reduction in
operating pressure or other action. An operator must also notify a
State pipeline safety authority when either a covered segment is
located in a State where PHMSA has an interstate agent agreement, or an
intrastate covered segment is regulated by that State.
* * * * *
(b) Discovery of condition. Discovery of a condition occurs when an
operator has adequate information about a condition to determine that
the condition presents a potential threat to the integrity of the
pipeline. For the purposes of this section, a condition that presents a
potential threat includes, but is not limited to, those conditions that
require remediation or monitoring listed under paragraphs (d)(1)
through (3) of this section. An operator must promptly, but no later
than 180 days after conducting an integrity assessment, obtain
sufficient information about a condition to make that determination,
unless the operator demonstrates that the 180-day period is
impracticable. In cases where a determination is not made within the
180-day period the operator must notify OPS, in accordance with Sec.
192.949, and provide an expected date when adequate information will
become available.
* * * * *
(d) * * *
(1) Immediate repair conditions. An operator's evaluation and
remediation schedule must follow ASME/ANSI B31.8S, section 7 in
providing for immediate repair conditions. To maintain safety, an
operator must temporarily reduce operating pressure in accordance with
paragraph (a) of this section or shut down the pipeline until the
operator completes the repair of these conditions. An operator must
treat the following conditions as immediate repair conditions:
(i) Calculation of the remaining strength of the pipe shows a
predicted failure pressure less than or equal to 1.1 times the maximum
allowable operating pressure at the location of the anomaly for any
class location. Suitable
[[Page 20846]]
remaining strength calculation methods include ASME/ANSI B31G
(incorporated by reference, see Sec. 192.7), PRCI PR-3-805 (R-STRENG)
(incorporated by reference, see Sec. 192.7); or an alternative method
of remaining strength calculation that will provide an equally
conservative result. Pipe and material properties used in remaining
strength calculations must be documented in reliable, traceable,
verifiable, and complete records. If such records are not available,
pipe and material properties used in the remaining strength
calculations must be based on properties determined and documented in
accordance with Sec. 192.607.
(ii) A dent that has any indication of metal loss, cracking, or a
stress riser.
(iii) An indication or anomaly that in the judgment of the person
designated by the operator to evaluate the assessment results requires
immediate action.
(iv) Metal loss greater than 80% of nominal wall regardless of
dimensions.
(v) An indication of metal-loss affecting a detected longitudinal
seam, if that seam was formed by direct current, low-frequency, or high
frequency electric resistance welding or by electric flash welding.
(vi) Any indication of significant stress corrosion cracking (SCC).
(vii) Any indication of significant selective seam weld corrosion
(SSWC).
(2) * * *.
(iii) A calculation of the remaining strength of the pipe shows a
predicted failure pressure ratio at the location of the anomaly less
than or equal to 1.25 for Class 1 locations, 1.39 for Class 2
locations, 1.67 for Class 3 locations, and 2.00 for Class 4 locations.
(iv) An area of general corrosion with a predicted metal loss
greater than 50% of nominal wall.
(v) Predicted metal loss greater than 50% of nominal wall that is
located at a crossing of another pipeline, or is in an area with
widespread circumferential corrosion, or is in an area that could
affect a girth weld.
(vi) A gouge or groove greater than 12.5% of nominal wall.
(vii) Any indication of crack or crack-like defect other than an
immediate condition.
* * * * *
0
45. In Sec. 192.935, paragraphs (a), (b)(2), and (d)(3) are revised
and paragraphs (f) and (g) are added to read as follows:
Sec. 192.935 What additional preventive and mitigative measures must
an operator take?
(a) General requirements. An operator must take additional measures
beyond those already required by part 192 to prevent a pipeline failure
and to mitigate the consequences of a pipeline failure in a high
consequence area. Such additional measures must be based on the risk
analyses required by Sec. 192.917, and must include, but are not
limited to: Correction of the root causes of past incidents to prevent
recurrence; establishing and implementing adequate operations and
maintenance processes that could increase safety; establishing and
deploying adequate resources for successful execution of preventive and
mitigative measures; installing automatic shut-off valves or remote
control valves; installing pressure transmitters on both sides of
automatic shut-off valves and remote control valves that communicate
with the pipeline control center; installing computerized monitoring
and leak detection systems; replacing pipe segments with pipe of
heavier wall thickness or higher strength; conducting additional right-
of-way patrols; conducting hydrostatic tests in areas where material
has quality issues or lost records; tests to determine material
mechanical and chemical properties for unknown properties that are
needed to assure integrity or substantiate MAOP evaluations including
material property tests from removed pipe that is representative of the
in-service pipeline; re-coating of damaged, poorly performing or
disbonded coatings; applying additional depth-of-cover survey at roads,
streams and rivers; remediating inadequate depth-of-cover; providing
additional training to personnel on response procedures, conducting
drills with local emergency responders; and implementing additional
inspection and maintenance programs.
(b) * * *
(2) Outside force damage. If an operator determines that outside
force (e.g., earth movement, loading, longitudinal, or lateral forces,
seismicity of the area, floods, unstable suspension bridge) is a threat
to the integrity of a covered segment, the operator must take measures
to minimize the consequences to the covered segment from outside force
damage. These measures include, but are not limited to, increasing the
frequency of aerial, foot or other methods of patrols, adding external
protection, reducing external stress, relocating the line, or
geospatial, GIS, and deformation in-line inspections.
* * * * *
(d) * * *
(3) Perform semi-annual, instrumented leak surveys (quarterly for
unprotected pipelines or cathodically protected pipe where indirect
assessments, i.e. indirect examination tool/method such as close
interval survey, alternating current voltage gradient, direct current
voltage gradient, or equivalent, are impractical).
* * * * *
(f) Internal corrosion. As an operator gains information about
internal corrosion, it must enhance its internal corrosion management
program, as required under subpart I of this part, with respect to a
covered segment to prevent and minimize the consequences of a release
due to internal corrosion. At a minimum, as part of this enhancement,
operators must--
(1) Monitor for, and mitigate the presence of, deleterious gas
stream constituents.
(2) At points where gas with potentially deleterious contaminants
enters the pipeline, use filter separators or separators and continuous
gas quality monitoring equipment.
(3) At least once per quarter, use gas quality monitoring equipment
that includes, but is not limited to, a moisture analyzer,
chromatograph, carbon dioxide sampling, and hydrogen sulfide sampling.
(4) Use cleaning pigs and sample accumulated liquids and solids,
including tests for microbiologically induced corrosion.
(5) Use inhibitors when corrosive gas or corrosive liquids are
present.
(6) Address potentially corrosive gas stream constituents as
specified in Sec. 192.478(a), where the volumes exceed these amounts
over a 24-hour interval in the pipeline as follows:
(i) Limit carbon dioxide to three percent by volume;
(ii) Allow no free water and otherwise limit water to seven pounds
per million cubic feet of gas; and
(iii) Limit hydrogen sulfide to 1.0 grain per hundred cubic feet
(16 ppm) of gas. If the hydrogen sulfide concentration is greater than
0.5 grain per hundred cubic feet (8 ppm) of gas, implement a pigging
and inhibitor injection program to address deleterious gas stream
constituents, including follow-up sampling and quality testing of
liquids at receipt points.
(7) Review the program at least semi-annually based on the gas
stream experience and implement adjustments to monitor for, and
mitigate the presence of, deleterious gas stream constituents.
(g) External corrosion. As an operator gains information about
external corrosion, it must enhance its external corrosion management
program, as required under subpart I of this part, with respect to a
covered segment to
[[Page 20847]]
prevent and minimize the consequences of a release due to external
corrosion. At a minimum, as part of this enhancement, operators must--
(1) Control electrical interference currents that can adversely
affect cathodic protection as follows:
(i) As frequently as needed (such as when new or uprated high
voltage alternating current power lines greater than or equal to 69 kVA
or electrical substations are co-located near the pipeline), but not to
exceed every seven years, perform the following:
(A) Conduct an interference survey (at times when voltages are at
the highest values for a time period of at least 24-hours) to detect
the presence and level of any electrical current that could impact
external corrosion where interference is suspected;
(B) Analyze the results of the survey to identify locations where
interference currents are greater than or equal to 20 Amps per meter
squared; and
(C) Take any remedial action needed within six months after
completing the survey to protect the pipeline segment from deleterious
current. Remedial action means the implementation of measures
including, but not limited to, additional grounding along the pipeline
to reduce interference currents. Any location with interference
currents greater than 50 Amps per meter squared must be remediated. If
any AC interference between 20 and 50 Amps per meter squared is not
remediated, the operator must provide and document an engineering
justification.
(2) Confirm the adequacy of external corrosion control through
indirect assessment as follows:
(i) Periodically (as frequently as needed but at intervals not to
exceed seven years) assess the adequacy of the cathodic protection
through an indirect method such as close-interval survey, and the
integrity of the coating using direct current voltage gradient (DCVG)
or alternating current voltage gradient (ACVG).
(ii) Remediate any damaged coating with a voltage drop classified
as moderate or severe (IR drop greater than 35% for DCVG or 50
dB[micro]v for ACVG) under section 4 of NACE RP0502-2008 (incorporated
by reference, see Sec. 192.7).
(iii) Integrate the results of the indirect assessment required
under paragraph (g)(2)(i) of this section with the results of the most
recent integrity assessment required by this subpart and promptly take
any needed remedial actions no later than 6 months after assessment
finding.
(iv) Perform periodic assessments as follows:
(A) Conduct periodic close interval surveys with current
interrupted to confirm voltage drops in association with integrity
assessments under sections Sec. Sec. 192.921 and 192.937 of this
subpart.
(B) Locate pipe-to-soil test stations at half-mile intervals within
each covered segment, ensuring at least one station is within each high
consequence area, if practicable.
(C) Integrate the results with those of the baseline and periodic
assessments for integrity done under sections Sec. Sec. 192.921 and
192.937 of this subpart.
(3) Control external corrosion through cathodic protection as
follows:
(i) If an annual test station reading indicates cathodic protection
below the level of protection required in subpart I of this part,
complete assessment and remedial action, as required in Sec.
192.465(f), within 6 months of the failed reading or notify each PHMSA
pipeline safety regional office where the pipeline is in service and
demonstrate that the integrity of the pipeline is not compromised if
the repair takes longer than 6 months. An operator must also notify a
State pipeline safety authority when the pipeline is located in a State
where PHMSA has an interstate agent agreement, or an intrastate
pipeline is regulated by that State; and
(ii) Remediate insufficient cathodic protection levels or areas
where protective current is found to be leaving the pipeline in
accordance with paragraph (g)(3)(i) of this section, including use of
indirect assessments or direct examination of the coating in areas of
low CP readings unless the reason for the failed reading is determined
to be a short to an adjacent foreign structure, rectifier connection or
power input problem that can be remediated and restoration of adequate
cathodic protection can be verified. The operator must confirm
restoration of adequate corrosion control by a close interval survey on
both sides of the affected test stations to the adjacent test stations.
0
46. In Sec. 192.937, paragraphs (b) and (c) are revised to read as
follows:
Sec. 192.937 What is a continual process of evaluation and assessment
to maintain a pipeline's integrity?
* * * * *
(b) Evaluation. An operator must conduct a periodic evaluation as
frequently as needed to assure the integrity of each covered segment.
The periodic evaluation must be based on a data integration and risk
assessment of the entire pipeline as specified in Sec. 192.917, which
incorporates an analysis of updated pipeline design, construction,
operation, maintenance, and integrity information. For plastic
transmission pipelines, the periodic evaluation is based on the threat
analysis specified in Sec. 192.917(d). For all other transmission
pipelines, the evaluation must consider the past and present integrity
assessment results, data integration and risk assessment information
(Sec. 192.917), and decisions about remediation (Sec. 192.933). The
evaluation must identify the threats specific to each covered segment,
including interacting threats and the risk represented by these
threats, and identify additional preventive and mitigative measures
(Sec. 192.935) to avert or reduce risks.
(c) Assessment methods. An operator must assess the integrity of
the line pipe in each covered segment by applying one or more of the
following methods for each threat to which the covered segment is
susceptible. An operator must select the method or methods best suited
to address the threats identified to the covered segment (See Sec.
192.917). An operator may use an integrity assessment to meet the
requirements of this section if the pipeline segment assessment is
conducted in accordance with the integrity assessment requirements of
Sec. 192.624(c) for establishing MAOP.
(1) Internal inspection tool or tools capable of detecting
corrosion, deformation and mechanical damage (including dents, gouges
and grooves), material cracking and crack-like defects (including
stress corrosion cracking, selective seam weld corrosion,
environmentally assisted cracking, and girth weld cracks), hard spots,
and any other threats to which the covered segment is susceptible. When
performing an assessment using an in-line inspection tool, an operator
must comply with Sec. 192.493. A person qualified by knowledge,
training, and experience must analyze the data obtained from an
assessment performed under paragraph (b) of this section to determine
if a condition could adversely affect the safe operation of the
pipeline. In addition, an operator must explicitly consider
uncertainties in reported results (including, but not limited to, tool
tolerance, detection threshold, probability of detection, probability
of identification, sizing accuracy, conservative anomaly interaction
criteria, location accuracy, anomaly findings, and unity chart plots or
equivalent for determining uncertainties and verifying tool
performance) in identifying and characterizing anomalies.
(2) Pressure test conducted in accordance with subpart J of this
part.
[[Page 20848]]
An operator must use the test pressures specified in table 3 of section
5 of ASME/ANSI B31.8S to justify an extended reassessment interval in
accordance with Sec. 192.939. The use of pressure testing is
appropriate for time dependent threats such as internal corrosion,
external corrosion, and other environmentally assisted corrosion
mechanisms and for manufacturing and related defect threats, including
defective pipe and pipe seams.
(3) ``Spike'' hydrostatic pressure test in accordance with Sec.
192.506. The use of spike hydrostatic pressure testing is appropriate
for threats such as stress corrosion cracking, selective seam weld
corrosion, manufacturing and related defects, including defective pipe
and pipe seams, and other forms of defect or damage involving cracks or
crack-like defects.
(4) Excavation and in situ direct examination by means of visual
examination, direct measurement, and recorded non-destructive
examination results and data needed to assess all threats, including
but not limited to, ultrasonic testing (UT), radiography, and magnetic
particle inspection (MPI). An operator must explicitly consider
uncertainties in in situ direct examination results (including, but not
limited to, tool tolerance, detection threshold, probability of
detection, probability of identification, sizing accuracy, and usage
unity chart plots or equivalent for determining uncertainties and
verifying performance on the type defects being evaluated) in
identifying and characterizing anomalies.
(5) Guided Wave Ultrasonic Testing (GWUT) conducted as described in
Appendix F;
(6) Direct assessment to address threats of external corrosion,
internal corrosion, and stress corrosion cracking. Use of direct
assessment is allowed only if the line is not capable of inspection by
internal inspection tools and is not practical to assess using the
methods specified in paragraphs (c)(1) through (5) of this section. An
operator must conduct the direct assessment in accordance with the
requirements listed in Sec. 192.923 and with the applicable
requirements specified in Sec. 192.925, 192.927, or 192.929;
(7) Other technology that an operator demonstrates can provide an
equivalent understanding of the condition of the line pipe. An operator
choosing this option must notify the Office of Pipeline Safety (OPS)
180 days before conducting the assessment, in accordance with Sec.
192.949 and receive a ``no objection letter'' from the Associate
Administrator of Pipeline Safety. An operator must also notify the
appropriate State or local pipeline safety authority when a covered
segment is located in a State where OPS has an interstate agent
agreement, or an intrastate covered segment is regulated by that State.
(8) Confirmatory direct assessment when used on a covered segment
that is scheduled for reassessment at a period longer than seven years.
An operator using this reassessment method must comply with Sec.
192.931.
0
47. In Sec. 192.939, the introductory text of paragraph (a) is revised
to read as follows:
Sec. 192.939 What are the required reassessment intervals?
* * * * *
(a) Pipelines operating at or above 30% SMYS. An operator must
establish a reassessment interval for each covered segment operating at
or above 30% SMYS in accordance with the requirements of this section.
The maximum reassessment interval by an allowable reassessment method
is seven calendar years. Operators may request a six month extension of
the seven-calendar year reassessment interval if the operator submits
written notice to OPS, in accordance with Sec. 192.949, with
sufficient justification of the need for the extension. If an operator
establishes a reassessment interval that is greater than seven calendar
years, the operator must, within the seven-calendar year period,
conduct a confirmatory direct assessment on the covered segment, and
then conduct the follow-up reassessment at the interval the operator
has established. A reassessment carried out using confirmatory direct
assessment must be done in accordance with Sec. 192.931. The table
that follows this section sets forth the maximum allowed reassessment
intervals.
* * * * *
0
48. In Sec. 192.941, paragraphs (b)(1) and the introductory text to
(b)(2) are revised to read as follows:
Sec. 192.941 What is a low stress reassessment?
* * * * *
(b) * * *
(1) Cathodically protected pipe. To address the threat of external
corrosion on cathodically protected pipe in a covered segment, an
operator must perform an indirect assessment (i.e. indirect examination
tool/method such as close interval survey, alternating current voltage
gradient, direct current voltage gradient, or equivalent) at least
every seven years on the covered segment. An operator must use the
results of each indirect assessment as part of an overall evaluation of
the cathodic protection and corrosion threat for the covered segment.
This evaluation must consider, at minimum, the leak repair and
inspection records, corrosion monitoring records, exposed pipe
inspection records, and the pipeline environment.
(2) Unprotected pipe or cathodically protected pipe where indirect
assessments are impractical. If an indirect assessment is impractical
on the covered segment an operator must--
* * * * *
0
49. Appendix A to part 192 is revised to read as follows:
Appendix A to Part 192--Records Retention Schedule for Transmission
Pipelines
Appendix A summarizes the part 192 records retention
requirements. As required by Sec. 192.13(e), records must be
readily retrievable and must be reliable, traceable, verifiable, and
complete.
----------------------------------------------------------------------------------------------------------------
Summary of records
requirement (Note:
referenced code section
Code section Section title specifies requirements. Retention time
This summary provided for
convenience only.)
----------------------------------------------------------------------------------------------------------------
Subpart A--General
----------------------------------------------------------------------------------------------------------------
Sec. 192.5(d)................. Class locations........ Records that demonstrate how Life of pipeline.
an operator determined
class locations and the
actual class locations.
Sec. 192.13(e)................ What general Records that demonstrate As specified in this
requirements apply to compliance with this part. appendix.
pipelines regulated At a minimum, operators
under this part?. must prepare and maintain
the records specified in
appendix A to part 192.
[[Page 20849]]
Sec. 192.14(b)................ Conversion to service Records of investigations, Life of pipeline.
subject to this part. tests, repairs,
replacements, and
alterations made under the
requirements of Sec.
192.14(a).
Sec. 192.16(d)................ Customer notification.. Records of a copy of the 3 years.
notice currently in use and
evidence that notices have
been sent to customers.
----------------------------------------------------------------------------------------------------------------
Subpart B--Materials
----------------------------------------------------------------------------------------------------------------
Sec. 192.67................... Records: Materials and Records for steel pipe Life of pipeline.
pipe. manufacturing tests,
inspections, and attributes.
----------------------------------------------------------------------------------------------------------------
Subpart C--Pipe Design
----------------------------------------------------------------------------------------------------------------
Sec. 192.112.................. Additional design Records for alternative MAOP Life of pipeline.
requirements for steel demonstrating compliance
pipe using alternative with this section.
maximum allowable
operating pressure.
Sec. 192.127.................. Records: Pipe Design Design records for external Life of pipeline.
for External Loads and loads and internal pressure.
Internal Pressures.
----------------------------------------------------------------------------------------------------------------
Subpart D--Design of Pipeline Components
----------------------------------------------------------------------------------------------------------------
Sec. 192.144.................. Qualifying metallic Records indicating Life of pipeline.
components. manufacturer and pressure
ratings of metallic
components.
Sec. 192.150.................. Passage of internal Records of each new Life of pipeline.
inspection devices. transmission line
replacement of pipe,
valves, fittings, or other
line component showing that
the replacement is
constructed to accommodate
internal inspection devices
as required by Sec.
192.150.
Sec. 192.153.................. Components fabricated Records of strength tests... Life of pipeline.
by welding.
Sec. 192.205.................. Records: Pipeline Records documenting the Life of pipeline.
components. manufacturing standard,
tests, and pressure rating
to which valves, flanges,
fittings, branch
connections, extruded
outlets, anchor forgings,
tap connections, and other
components were
manufactured and tested in
accordance with this
subpart.
----------------------------------------------------------------------------------------------------------------
Subpart E--Welding of Steel in Pipelines
----------------------------------------------------------------------------------------------------------------
Sec. 192.225(b)............... Welding procedures..... Records of welding Life of pipeline.
procedures, including
results of qualifying
procedure tests.
Sec. 192.227(c)............... Qualification of Records demonstrating welder Life of pipeline.
welders and welding qualification.
operators.
Sec. 192.243(f)............... Nondestructive testing. Records showing by milepost, Life of pipeline.
engineering station, or by
geographic feature, the
number of girth welds made,
the number nondestructively
tested, the number
rejected, and the
disposition of the rejects.
----------------------------------------------------------------------------------------------------------------
Subpart F--Joining of Materials Other Than by Welding
----------------------------------------------------------------------------------------------------------------
Sec. 192.283.................. Plastic pipe: Records of joining Life of pipeline.
Qualifying joining procedures, including
procedures. results of qualifying
procedure tests.
Sec. 192.285(e)............... Plastic pipe: Records demonstrating Life of pipeline.
Qualifying persons to plastic pipe joining
make joints. qualifications.
----------------------------------------------------------------------------------------------------------------
Subpart G--General Construction Requirements for Transmission Lines and Mains
----------------------------------------------------------------------------------------------------------------
Sec. 192.303.................. Compliance with Records of written Life of pipeline.
specifications or specifications or standards
standards. that apply to each
transmission line or main.
Sec. 192.305.................. Inspection: General.... Transmission line or main Life of pipeline.
inspections.
Sec. 192.307.................. Inspection of materials Pipe and component materials Life of pipeline.
inspections.
Sec. 192.319(d)............... Installation of pipe in Records documenting the Life of pipeline.
a ditch. coating assessment findings
and repairs.
Sec. 192.328.................. Additional construction Records for alternative MAOP Life of pipeline.
requirements for steel demonstrating compliance
pipe using alternative with this section
maximum allowable including: quality
operating pressure. assurance, girth weld non-
destructive examinations,
depth of cover, initial
strength testing (pressure
tests and root cause
analysis of failed pipe),
and impacts of interference
currents.
----------------------------------------------------------------------------------------------------------------
[[Page 20850]]
Subpart H--Customer Meters, Service Regulators, and Service Lines
----------------------------------------------------------------------------------------------------------------
Sec. 192.383.................. Excess flow valve Number of excess flow valves Life of pipeline.
installation. installed, as reported as
part of annual report.
----------------------------------------------------------------------------------------------------------------
Subpart I--Requirements for Corrosion Control
----------------------------------------------------------------------------------------------------------------
Sec. 192.452(a)............... How does this subpart Records demonstrating Life of pipeline.
apply to converted compliance by the
pipelines and applicable deadlines.
regulated onshore
gathering lines?.
Sec. 192.459.................. Exposed buried pipe Records of examinations for Life of pipeline.
inspection. evidence of external
corrosion whenever any
portion of a buried
pipeline is exposed.
Sec. 192.461.................. External corrosion Records of protective Life of pipeline.
control: Protective coating type, coating
coating. installation and
procedures, surveys, and
remediation of coating
defects.
Sec. 192.465(a)............... External corrosion Records of pipe to soil Life of pipeline.
control: Monitoring. measurements.
Sec. 192.465(b)............... External corrosion Records of rectifier 5 years.
control: Monitoring-- inspections.
rectifiers.
Sec. 192.465(c)............... External corrosion Records of inspections of 5 years.
control: Monitoring-- each reverse current
stray current/ switch, each diode, and
interference each interference bond
mitigation and whose failure would
critical interference jeopardize structure
bonds. protection.
Sec. 192.465(e)............... External corrosion Records of re-evaluation of Life of pipeline.
control: Monitoring-- cathodically unprotected
active corrosion zones. pipelines.
Sec. 192.467(d)............... External corrosion Records of inspection and Life of pipeline.
control: Electrical electrical tests made to
isolation. assure that electrical
isolation is adequate.
Sec. 192.473.................. External corrosion Records of surveys, Life of pipeline.
control: Interference analysis, and remediation
currents. of interference currents.
Sec. 192.475.................. Internal pipe Records demonstrating Life of pipeline.
inspection. whenever any pipe is
removed from a pipeline for
any reason, the internal
surface was inspected for
evidence of corrosion.
Sec. 192.476(d)............... Internal corrosion Records demonstrating Life of pipeline.
control: Design and compliance with this
construction of section.
transmission line.
Sec. 192.477.................. Coupons or other means Records demonstrating the Life of pipeline.
for monitoring effectiveness of each
internal corrosion. coupon or other means of
monitoring procedures used
to minimize internal
corrosion.
Sec. 192.478.................. Internal corrosion Records demonstrating Life of pipeline.
control: Onshore compliance with this
transmission section for internal
monitoring and monitoring and mitigation
mitigation. program.
Sec. 192.478(b)(3)............ Gas and Liquid Samples. Records showing evaluation Life of pipeline.
twice each calendar year of
gas stream and liquid
quality samples.
Sec. 192.481(a)............... Atmospheric corrosion Records of inspection of 5 years.
control: Monitoring. each pipeline or portion of
pipeline that is exposed to
the atmosphere for evidence
of atmospheric corrosion.
Sec. 192.485(c)............... Remedial measures: Pipe and material properties Life of pipeline.
Transmission lines. used in remaining strength
calculations and remaining
strength calculations must
be documented in reliable,
traceable, verifiable, and
complete records.
Sec. 192.491(a) and (b)....... Corrosion control Records or maps showing the Life of pipeline.
records. location of cathodically
protected piping, cathodic
protection facilities,
galvanic anodes, and
neighboring structures
bonded to the cathodic
protection system.
Sec. 192.491(c)............... Corrosion control Records of each test, 5 years.
records. survey, or inspection
required by subpart I in
sufficient detail to
demonstrate the adequacy of
corrosion control measures
or that a corrosive
condition does not exist.
Records related to Sec. Life of pipeline.
Sec. 192.465(a) and (e)
and 192.475(b) must be
retained for as long as the
pipeline remains in service.
----------------------------------------------------------------------------------------------------------------
Subpart J--Test Requirements
----------------------------------------------------------------------------------------------------------------
Sec. 192.517(a)............... Records................ Records of each test Life of pipeline.
performed under Sec. Sec.
192.505, 192.506, and
192.507.
Sec. 192.517(b)............... Records................ Records of each test 5 years.
required by Sec. Sec.
192.509, 192.511, and
192.513.
----------------------------------------------------------------------------------------------------------------
[[Page 20851]]
Subpart K--Uprating
----------------------------------------------------------------------------------------------------------------
Sec. 192.553(b)............... General requirements... Records of each Life of pipeline.
investigation required by
subpart K, of all work
performed, and of each
pressure test conducted, in
connection with uprating of
a segment of pipeline.
----------------------------------------------------------------------------------------------------------------
Subpart L--Operations
----------------------------------------------------------------------------------------------------------------
Sec. 192.603(b)............... General provisions..... Records necessary to Life of pipeline.
administer the procedures
established under Sec.
192.605 for operations,
maintenance, and
emergencies including class
location and changes in
Sec. Sec. 192.5,
192.609, and 192.611.
Sec. 192.605.................. Procedural manual for Records for O&M Manual-- 5 years.
operations, review and update once per
maintenance, and calendar year, not to
emergencies. exceed 15 months.
Sec. 192.605.................. Procedural manual for Records for Emergency Plan-- 5 years.
operations, review and update once per
maintenance, and calendar year, not to
emergencies. exceed 15 months.
Sec. 192.605.................. Procedural manual for Records for Operator 5 years.
operations, Qualification Plan--review
maintenance, and and update once per
emergencies. calendar year, not to
exceed 15 months.
Sec. 192.605(b)(12)........... Procedural manual for Records for Control Room 5 years.
operations, Management (CRM)--review
maintenance, and and update once per
emergencies. calendar year, not to
exceed 15 months.
Sec. 192.605(c)............... Procedural manual for For gas transmission Life of pipeline.
operations, operators, a record of the
maintenance, and abnormal operations.
emergencies.
Sec. 192.607(c)............... Verification of Traceable, verifiable, and Life of pipeline.
Pipeline Material: complete records that
Onshore steel demonstrate and
transmission pipelines. authenticate data and
information regarding the
properties outlined in Sec.
192.607(c)(1) through (4).
Sec. 192.609.................. Change in class Records for class location Life of pipeline.
location: Required studies required by this
study. section.
Sec. 192.611.................. Change in class Records for revisions of Life of pipeline.
location: Confirmation maximum allowable operating
or revision of maximum pressure due to class
allowable operating location changes to confirm
pressure. to Sec. 192.611.
Sec. 192.612.................. Underwater inspection Records of Underwater 5 years.
and reburial of inspection in Gulf of
pipelines in the Gulf Mexico--periodic, as
of Mexico and its indicated in operators O&M
inlets. Manual.
Sec. 192.613(a)............... Continuing surveillance Records of continuing 5 years.
surveillance findings.
Sec. 192.613(b)............... Continuing surveillance Records of remedial actions. Life of pipeline.
Sec. 192.613(c)(1)............ Continuing surveillance Records of inspections 5 years.
performed following extreme
events.
Sec. 192.613(c)(3)............ Continuing surveillance Records of remedial actions. Life of pipeline.
Sec. 192.614.................. Damage prevention Damage Prevention/One Call 5 years (or as
program. records. indicated by state one
call, whichever is
longer).
Sec. 192.614.................. Damage prevention Records of Damage Prevention 5 years.
program. meetings with Emergency
Responder/Public Officials.
Sec. 192.615.................. Emergency plans........ Records of training......... 5 years.
Sec. 192.615.................. Emergency plans........ Records of each review that 5 years.
procedures were effectively
followed after each
emergency.
Sec. 192.616.................. Public awareness....... Records showing Public 5 years.
Education Activities.
Sec. 192.617.................. Investigation of Procedures for analyzing Life of pipeline.
failures. accidents and failures as
described in Sec. 192.617
to determine the causes of
the failure and minimizing
the possibility of a
recurrence. Records of
accident/failure reports.
Sec. 192.619.................. Maximum allowable Traceable, verifiable, and Life of pipeline.
operating pressure: complete records that
Steel or plastic demonstrate and
pipelines. authenticate data and
information regarding the
maximum allowable operating
pressures outlined in Sec.
192.619(a) through (d).
Sec. 192.620(c)(7)............ Alternative maximum Records demonstrating Life of pipeline.
allowable operating compliance with paragraphs
pressure for certain Sec. 192.620(b), (c)(6),
steel pipelines. and (d).
Sec. 192.624(f)............... Maximum allowable Reliable, traceable, Life of pipeline.
operating pressure verifiable, and complete
verification: Onshore records of the
steel transmission investigations, tests,
pipelines. analyses, assessments,
repairs, replacements,
alterations, and other
actions made under the
requirements of Sec.
192.624.
Sec. 192.625.................. Odorization of gas..... Records of Odorometer 5 years.
Readings--periodic, as
indicated in operators O&M
Manual.
[[Page 20852]]
Sec. 192.631(a)............... Control room management Records of control room Life of pipeline.
management procedures that
implement the requirements
of this section.
Sec. 192.631(j)............... Control room management (1) Records that demonstrate 1 year, or the last 2
compliance with the periodic tests or
requirements of this validations, whichever
section; and. is longer.
(2) Documentation to
demonstrate that any
deviation from the
procedures required by this
section was necessary for
the safe operation of a
pipeline facility.
----------------------------------------------------------------------------------------------------------------
Subpart M--Maintenance
----------------------------------------------------------------------------------------------------------------
Sec. 192.703(c)............... General................ Records of hazardous and non- Life of pipeline.
hazardous leaks.
Sec. 192.705.................. Transmission lines: Records of periodic right-of- 5 years.
Patrolling. way patrols--frequency
dependent on class location.
Sec. 192.706.................. Transmission lines: Records of periodic leakage 5 years.
Leakage surveys. surveys--frequency
dependent on class location.
Sec. 192.709(a)............... Transmission lines: Records for the date, Life of pipeline.
Record keeping. location, and description
of each repair made to pipe
(including pipe-to-pipe
connections).
Sec. 192.709(b) and (c)....... Transmission lines: (b) Records of the date, 5 years.*
Record keeping. location, and description
of each repair made to
parts of the pipeline
system other than pipe must
be retained for at least 5
years.
(c) A record of each patrol, .......................
survey, inspection, test,
and repair required by
subparts L and M of this
part must be retained for
at least 5 years or until
the next patrol, survey,
inspection, or test is
completed, whichever is
longer.*
Sec. 192.710.................. Pipeline assessments... Records of pipeline Life of pipeline.
assessments in class 3 or
class 4 locations and
moderate consequence area
as defined in Sec. 192.3
if the pipe segment can
accommodate inspection by
means of instrumented
inline inspection tools
(i.e., ``smart pigs'').
Sec. 192.713(c)............... Transmission lines: Records of each repair made Life of pipeline.
Permanent field repair to transmission lines must
of imperfections and be documented.
damages.
Sec. 192.713(d)............... Transmission lines: Repair and remediation Life of pipeline.
Permanent field repair schedules, pressure
of imperfections and reductions and remaining
damages. strength calculations must
be documented.
Sec. 192.731.................. Compressor stations: Records of inspections and 5 years.
Inspection and testing tests of pressure relieving
of relief devices. and other remote control
shutdown devices.
Sec. 192.736.................. Compressor stations: Records of inspections and 5 years.
Gas detection. tests of gas detection
systems--periodic, as
indicated in operators O&M
Manual.
Sec. 192.739.................. Pressure limiting and Records of inspections and 5 years.
regulating stations: tests of pressure relief
Inspection and testing. devices and pressure
regulating stations and
equipment.
Sec. 192.743.................. Pressure limiting and Records of capacity 5 years.
regulating stations: calculations or
Capacity of relief verifications for pressure
devices. relief devices (except
rupture discs).
Sec. 192.745.................. Valve maintenance: Records of inspections of 5 years.
Transmission lines. emergency valves.
Sec. 192.749.................. Vault maintenance...... Records of inspections of 5 years.
vaults containing pressure
regulating or pressure
limiting equipment.
----------------------------------------------------------------------------------------------------------------
Subpart N--Qualification of Pipeline Personnel
----------------------------------------------------------------------------------------------------------------
Sec. 192.807.................. Operator qualification Records that demonstrate 5 years.**
recordkeeping. compliance with subpart N
of this part Records
supporting an individual's
current qualification shall
be maintained while the
individual is performing
the covered task.**
Records of prior
qualification and records
of individuals no longer
performing covered tasks
shall be retained for a
period of five years..
----------------------------------------------------------------------------------------------------------------
Subpart O--Gas Transmission Integrity Management
----------------------------------------------------------------------------------------------------------------
Sec. 192.947.................. Integrity management... Records that demonstrate Life of pipeline.
compliance with all of the
requirements of subpart O
of this part.
----------------------------------------------------------------------------------------------------------------
[[Page 20853]]
0
50. Appendix D to part 192 is revised to read as follows:
Appendix D to Part 192--Criteria for Cathodic Protection and
Determination of Measurements
I. Criteria for cathodic protection--
A. Steel, cast iron, and ductile iron structures.
(1) A negative (cathodic) voltage across the structure
electrolyte boundary of at least 0.85 volt, with reference to a
saturated copper-copper sulfate reference electrode, often referred
to as a half cell. Determination of this voltage must be made in
accordance with sections II and IV of this appendix.
(2) A minimum negative (cathodic) polarization voltage shift of
100 millivolts. This polarization voltage shift must be determined
in accordance with sections III and IV of this appendix.
B. Aluminum structures.
(1) Except as provided in paragraphs B(2) and (3) of this
section, a minimum negative (cathodic) polarization voltage shift of
100 millivolts. This polarization voltage shift must be determined
in accordance with sections III and IV of this appendix.
(2) Notwithstanding the minimum criteria in paragraph B(1) of
this section, if aluminum is cathodically protected at voltages in
excess of 1.20 volts as measured with reference to a copper-copper
sulfate reference electrode, in accordance with section II of this
appendix, the aluminum may suffer corrosion resulting from the
build-up of alkali on the metal surface. A voltage in excess of 1.20
volts may not be used unless previous test results indicate no
appreciable corrosion will occur in the particular environment.
(3) Since aluminum may suffer from corrosion under high pH
conditions, and since application of cathodic protection tends to
increase the pH at the metal surface, careful investigation or
testing must be made before applying cathodic protection to stop
pitting attack on aluminum structures in environments with a natural
pH in excess of 8.
C. Copper structures. A minimum negative (cathodic) polarization
voltage shift of 100 millivolts. This polarization voltage shift
must be determined in accordance with sections III and IV of this
appendix.
D. Metals of different anodic potentials. A negative (cathodic)
voltage, measured in accordance with section IV of this appendix,
equal to that required for the most anodic metal in the system must
be maintained. If amphoteric structures are involved that could be
damaged by high alkalinity covered by paragraphs B(2) and (3) of
this section, they must be electrically isolated with insulating
flanges, or the equivalent.
II. Interpretation of voltage measurement. Structure-to-
electrolyte potential measurements must be made utilizing
measurement techniques that will minimize voltage (IR) drops other
than those across the structure electrolyte boundary. All voltage
(IR) drops other than those across the structure electrolyte
boundary will be differentiated, such that the resulting measurement
accurately reflects the structure-to-electrolyte potential.
III. Determination of polarization voltage shift. The
polarization voltage shift must be determined by interrupting the
protective current and measuring the polarization decay. When the
current is initially interrupted, an immediate voltage shift occurs
often referred to as an instant off potential. The voltage reading
after the immediate shift must be used as the base reading from
which to measure polarization decay in paragraphs A(2), B(1), and C
of section I of this appendix.
IV. Reference electrodes (half cells).
A. Except as provided in paragraphs B and C of this section,
negative (cathodic) voltage must be measured between the structure
surface and a saturated copper-copper sulfate reference electrode
contacting the electrolyte.
B. Other standard reference electrodes may be substituted for
the saturated copper-copper sulfate electrode. Two commonly used
reference electrodes are listed below along with their voltage
equivalent to -0.85 volt as referred to a saturated copper-copper
sulfate reference electrode:
(1) Saturated KCL calomel half cell:-0.78 volt.
(2) Silver-silver chloride reference electrode used in sea
water: -0.80 volt.
C. In addition to the standard reference electrode, an alternate
metallic material or structure may be used in place of the saturated
copper-copper sulfate reference electrode if its potential stability
is assured and if its voltage equivalent referred to a saturated
copper-copper sulfate reference electrode is established.
0
51. In appendix E, Tables E.II.1 and E.II.3 are revised to read as
follows:
Appendix E to Part 192--Guidance on Determining High Consequence Areas
and on Carrying out Requirements in the Integrity Management Rule
* * * * *
II. Guidance on Assessment Methods and Additional Preventive and
Mitigative Measures for Transmission Pipelines
* * * * *
Table E.II.1--Preventive and Mitigative Measures for Transmission Pipelines Operating Below 30% SMYS not in an
HCA but in a Class 3 or Class 4 Location
----------------------------------------------------------------------------------------------------------------
Existing part 192 requirements (Column 4) Additional (to
------------------------------------------------ part 192 requirements)
(Column 1) Threat preventive and mitigative
(Column 2) Primary (Column 3) Secondary measures
----------------------------------------------------------------------------------------------------------------
External Corrosion................. 455--(Gen. Post 1971), 603--(Gen Operation).. For Cathodically Protected
457--(Gen. Pre--1971). Transmission Pipeline:
459--(Examination), 613--(Surveillance)... Perform semi-
461--(Ext. coating). annual leak surveys.
463--(CP), 465-- ...................... For Unprotected
(Monitoring). Transmission Pipelines or
for Cathodically Protected
Pipe where indirect
assessments (i.e.,
indirect examination tool/
method such as close
interval survey,
alternating current
voltage gradient, direct
current voltage gradient,
or equivalent) are
impractical:
467--(Elect
isolation), 469--Test
stations).
471--(Test leads),
473--(Interference).
479--(Atmospheric),
481--(Atmospheric).
485--(Remedial), 705--
(Patrol).
706-- (Leak survey),
711--(Repair--gen.).
717--(Repair--perm.).. ...................... Perform quarterly
leak surveys.
Internal Corrosion................. 475--(Gen IC), 477-- 53(a)--(Materials).... Perform semi-annual leak
(IC monitoring). surveys.
[[Page 20854]]
485--(Remedial), 705-- 603--(Gen Oper'n).....
(Patrol).
706--(Leak survey), 613--(Surveillance)...
711 (Repair--gen.).
717--(Repair--perm.)..
3rd Party Damage................... 103--(Gen. Design), ...................... Participation in
111--(Design factor). state one-call system.
317--(Hazard prot), 615--(Emerg. Plan).... Use of qualified
327--(Cover). operator employees and
contractors to perform
marking and locating of
buried structures and in
direct supervision of
excavation work.
614--(Dam. Prevent), ...................... AND
616--(Public
education).
705--(Patrol), 707-- Either monitoring
(Line markers). of excavations near
operator's transmission
pipelines in class 3 and 4
locations. Any indications
of unreported construction
activity would require a
follow up investigation to
determine if mechanical
damage occurred.
711--(Repair--gen.),
717--(Repair--perm.).
----------------------------------------------------------------------------------------------------------------
* * * * *
Table E.II.3--Preventive and Mitigative Measures Addressing Time Dependent and Independent Threats for
Transmission Pipelines That Operate Below 30% SMYS, in HCAs
----------------------------------------------------------------------------------------------------------------
Existing part 192 requirements Additional (to part 192
Threat ---------------------------------------------- requirements) preventive and
Primary Secondary mitigative measures
----------------------------------------------------------------------------------------------------------------
External Corrosion................ 455--(Gen. Post 1971) ..................... For Cathodically Protected
Transmission Pipelines
457--(Gen. Pre-1971). ..................... Perform an indirect
assessment (i.e. indirect
examination tool/method such
as close interval survey,
alternating current voltage
gradient, direct current
voltage gradient, or
equivalent) at least every 7
years. Results are to be
utilized as part of an
overall evaluation of the CP
system and corrosion threat
for the covered segment.
Evaluation shall include
consideration of leak repair
and inspection records,
corrosion monitoring records,
exposed pipe inspection
records, and the pipeline
environment.
459--(Examination)...
461--(Ext. coating)..
463--(CP)............
465--(Monitoring).... 603--(Gen. Operation)
467--(Elect 613--(Surveillance)..
isolation).
469--(Test stations).
471--(Test leads).... ..................... For Unprotected Transmission.
Pipelines or for Cathodically
Protected Pipe where Indirect
Assessments are Impracticable
473--(Interference)..
479--(Atmospheric)... ..................... Conduct quarterly
leak surveys AND
481--(Atmospheric)... ..................... Every 1\1/2\ years,
determine areas of active
corrosion by evaluation of
leak repair and inspection
records, corrosion monitoring
records, exposed pipe
inspection records, and the
pipeline environment.
485--(Remedial)......
705--(Patrol)........
706--(Leak survey)...
711--(Repair--gen.)..
717--(Repair--perm.).
Internal Corrosion................ 475--(Gen. IC)....... ..................... Obtain and review gas
analysis data each calendar
year for corrosive agents
from transmission pipelines
in HCA,
477--(IC monitoring). ..................... Periodic testing of
fluid removed from pipelines.
Specifically, once each year
from each storage field that
may affect transmission
pipelines in HCA, AND
485--(Remedial)...... 53(a)--(Materials)... At least every 7
years, integrate data
obtained with applicable
internal corrosion leak
records, incident reports,
safety related condition
reports, repair records,
patrol records, exposed pipe
reports, and test records.
705--(Patrol)........ 603--(Gen. Oper.)....
706--(Leak survey)... 613--(Surveil.)......
711--(Repair--gen.)..
[[Page 20855]]
717--(Repair--perm.).
3rd Party Damage.................. 103--(Gen. Design)... 615-- (Emerg. Plan).. Participation in
state one-call system,
111--(Design factor). ..................... Use of qualified
operator employees and
contractors to perform
marking and locating of
buried structures and in
direct supervision of
excavation work, AND
317--(Hazard prot.).. ..................... Either monitoring of
excavations near operator's
transmission pipelines, or bi-
monthly patrol of
transmission pipelines in
HCAs or class 3 and 4
locations. Any indications of
unreported construction
activity would require a
follow up investigation to
determine if mechanical
damage occurred.
327--(Cover).........
614--(Dam. Prevent)..
616--(Public educat.)
705--(Patrol)........
707--(Line markers)..
711--(Repair--gen.)..
717--(Repair--perm.).
----------------------------------------------------------------------------------------------------------------
0
52. Appendix F to part 192 is added to read as follows:
Appendix F to Part 192--Criteria for Conducting Integrity Assessments
Using Guided Wave Ultrasonic Testing (GWUT)
This appendix defines criteria which must be properly
implemented for use of Guided Wave Ultrasonic Testing (GWUT) as an
integrity assessment method. Any application of GWUT that does not
conform to these criteria is considered ``other technology'' as
described by Sec. Sec. 192.710(c)(7), 192.921(a)(7), and
192.937(c)(7), for which OPS must be notified 180 days prior to use
in accordance with Sec. 192.921(a)(7) or 192.937(c)(7). GWUT in the
``Go-No Go'' mode means that all indications (wall loss anomalies)
above the testing threshold (a maximum of 5% of cross sectional area
(CSA) sensitivity) be directly examined, in-line tool inspected,
pressure tested or replaced prior to completing the integrity
assessment on the cased carrier pipe.
I. Equipment and software: Generation. The equipment and the
computer software used are critical to the success of the
inspection. Guided Ultrasonics LTD (GUL) Wavemaker G3 or G4 with
software version 3 or higher, or equipment and software with
equivalent capabilities and sensitivities, must be used.
II. Inspection range. The inspection range and sensitivity are
set by the signal to noise (S/N) ratio but must still keep the
maximum threshold sensitivity at 5% cross sectional area (CSA). A
signal that has an amplitude that is at least twice the noise level
can be reliably interpreted. The greater the S/N ratio the easier it
is to identify and interpret signals from small changes. The signal
to noise ratio is dependent on several variables such as surface
roughness, coating, coating condition, associated pipe fittings
(T's, elbows, flanges), soil compaction, and environment. Each of
these affects the propagation of sound waves and influences the
range of the test. It may be necessary to inspect from both ends of
the pipeline segment to achieve a full inspection. In general the
inspection range can approach 60 to 100 feet for a 5% CSA, depending
on field conditions.
III. Complete pipe inspection. To ensure that the entire
pipeline segment is assessed there should be at least a 2 to 1
signal to noise ratio across the entire pipeline segment that is
inspected. This may require multiple GWUT shots. Double ended
inspections are expected. These two inspections are to be overlaid
to show the minimum 2 to 1 S/N ratio is met in the middle. If
possible, show the same near or midpoint feature from both sides and
show an approximate 5% distance overlap.
IV. Sensitivity.
A. The detection sensitivity threshold determines the ability to
identify a cross sectional change. The maximum threshold sensitivity
cannot be greater than 5% of the cross sectional area (CSA).
B. The locations and estimated CSA of all metal loss features in
excess of the detection threshold must be determined and documented.
C. All defect indications in the ``Go-No Go'' mode above the 5%
testing threshold must be directly examined, in-line inspected,
pressure tested, or replaced prior to completing the integrity
assessment.
V. Wave frequency. Because a single wave frequency may not
detect certain defects, a minimum of three frequencies must be run
for each inspection to determine the best frequency for
characterizing indications. The frequencies used for the inspections
must be documented and must be in the range specified by the
manufacturer of the equipment.
VI. Signal or wave type: Torsional and longitudinal. Both
torsional and longitudinal waves must be used and use must be
documented.
VII. Distance amplitude correction (DAC) curve and weld
calibration.
A. The Distance Amplitude Correction curve accounts for coating,
pipe diameter, pipe wall and environmental conditions at the
assessment location. The DAC curve must be set for each inspection
as part of establishing the effective range of a GWUT inspection.
B. DAC curves provide a means for evaluating the cross sectional
area change of reflections at various distances in the test range by
assessing signal to noise ratio. A DAC curve is a means of taking
apparent attenuation into account along the time base of a test
signal. It is a line of equal sensitivity along the trace which
allows the amplitudes of signals at different axial distances from
the collar to be compared.
VIII. Dead zone. The dead zone is the area adjacent to the
collar in which the transmitted signal blinds the received signal,
making it impossible to obtain reliable results. Because the entire
line must be inspected, inspection procedures must account for the
dead zone by requiring the movement of the collar for additional
inspections. An alternate method of obtaining valid readings in the
dead zone is to use B-scan ultrasonic equipment and visual
examination of the external surface. The length of the dead zone and
the near field for each inspection must be documented.
IX. Near field effects. The near field is the region beyond the
dead zone where the receiving amplifiers are increasing in power,
before the wave is properly established. Because the entire line
must be inspected, inspection procedures must account for the near
field by requiring the movement of the collar for additional
inspections. An alternate method of obtaining valid readings in the
near field is to use B-scan ultrasonic equipment and visual
examination of the external surface. The length of the dead zone and
the near field for each inspection must be documented.
X. Coating type.
A. Coatings can have the effect of attenuating the signal. Their
thickness and condition are the primary factors that affect the rate
of signal attenuation. Due to their variability, coatings make it
difficult to predict the effective inspection distance.
B. Several coating types may affect the GWUT results to the
point that they may reduce the expected inspection distance. For
[[Page 20856]]
example, concrete coated pipe may be problematic when well bonded
due to the attenuation effects. If an inspection is done and the
required sensitivity is not achieved for the entire length of the
cased pipe, then another type of assessment method must be utilized.
XI. End seal. Operators must remove the end seal from the casing
at each GWUT test location to facilitate visual inspection.
Operators must remove debris and water from the casing at the end
seals. Any corrosion material observed must be removed, collected
and reviewed by the operator's corrosion technician. The end seal
does not interfere with the accuracy of the GWUT inspection but may
have a dampening effect on the range.
XII. Weld calibration to set DAC curve. Accessible welds, along
or outside the pipe segment to be inspected, must be used to set the
DAC curve. A weld or welds in the access hole (secondary area) may
be used if welds along the pipe segment are not accessible. In order
to use these welds in the secondary area, sufficient distance must
be allowed to account for the dead zone and near field. There must
not be a weld between the transducer collar and the calibration
weld. A conservative estimate of the predicted amplitude for the
weld is 25% CSA (cross sectional area) and can be used if welds are
not accessible. Calibrations (setting of the DAC curve) should be on
pipe with similar properties such as wall thickness and coating. If
the actual weld cap height is different from the assumed weld cap
height, the estimated CSA may be inaccurate and adjustments to the
DAC curve may be required. Alternative means of calibration can be
used if justified by sound engineering analysis and evaluation.
XIII. Validation of operator training.
A. There is no industry standard for qualifying GWUT service
providers. Pipeline operators must require all guided wave service
providers to have equipment-specific training and experience for all
GWUT equipment operators which includes training for:
(1) Equipment operation;
(2) Field data collection; and
(3) Data interpretation on cased and buried pipe.
B. Only individuals who have been qualified by the manufacturer
or an independently assessed evaluation procedure similar to ISO
9712 (Sections: 5 Responsibilities; 6 Levels of Qualification; 7
Eligibility; and 10 Certification), as specified above, may operate
the equipment.
C. A Senior level GWUT equipment operator with pipeline specific
experience must provide onsite oversight of the inspection and
approve the final reports. A senior level GWUT equipment operator
must have additional training and experience, including but not
limited to training specific to cased and buried pipe, with a
quality control program which conforms to section 12 of ASME B31.8S.
D. Training and experience minimums for senior level GWUT
equipment operators:
(1) Equipment Manufacturer's minimum qualification for equipment
operation and data collection with specific endorsements for casings
and buried pipe
(2) Training, qualification and experience in testing procedures
and frequency determination
(3) Training, qualification and experience in conversion of
guided wave data into pipe features and estimated metal loss
(estimated cross-sectional area loss and circumferential extent)
(4) Equipment Manufacturer's minimum qualification with specific
endorsements for data interpretation of anomaly features for pipe
within casings and buried pipe.
XIV. Equipment: Traceable from vendor to inspection company. The
operator must maintain documentation of the version of the GWUT
software used and the serial number of the other equipment such as
collars, cables, etc., in the report.
XV. Calibration onsite. The GWUT equipment must be calibrated
for performance in accordance with the manufacturer's requirements
and specifications, including the frequency of calibrations. A
diagnostic check and system check must be performed on-site each
time the equipment is relocated. If on-site diagnostics show a
discrepancy with the manufacturer's requirements and specifications,
testing must cease until the equipment can be restored to
manufacturer's specifications.
XVI. Use on shorted casings (direct or electrolytic). GWUT may
not be used to assess shorted casings. GWUT operators must have
operations and maintenance procedures (see Sec. 192.605) to address
the effect of shorted casings on the GWUT signal. The equipment
operator must clear any evidence of interference, other than some
slight dampening of the GWUT signal from the shorted casing,
according to their operating and maintenance procedures. All shorted
casings found while conducting GWUT inspections must be addressed by
the operator's standard operating procedures.
XVII. Direct examination of all indications above the detection
sensitivity threshold.
The use of GWUT in the ``Go-No Go'' mode requires that all
indications (wall loss anomalies) above the testing threshold (5% of
CSA sensitivity) be directly examined (or replaced) prior to
completing the integrity assessment on the cased carrier pipe. If
this cannot be accomplished then alternative methods of assessment
(such as hydrostatic pressure tests or ILI) must be utilized.
XVIII. Timing of direct examination of all indications above the
detection sensitivity threshold. Operators must either replace or
conduct direct examinations of all indications identified above the
detection sensitivity threshold according to the table below.
Operators must conduct leak surveys and reduce operating pressure as
specified until the pipe is replaced or direct examinations are
completed.
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Required response to GWUT indications
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Operating pressure Operating pressure over 30
GWUT Criterion less than or equal to and less than or equal to Operating pressure over
30% SMYS 50% SMYS 50% SMYS
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Over the detection sensitivity Replace or direct Replace or direct Replace or direct
threshold (maximum of 5% CSA). examination within examination within 6 examination within 6
12 months, and months, instrumented leak months, instrumented
instrumented leak survey once every 30 leak survey once every
survey once every 30 calendar days, and 30 calendar days, and
calendar days. maintain MAOP below the reduce MAOP to 80% of
operating pressure at operating pressure at
time of discovery. time of discovery.
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Issued in Washington, DC, on March 17, 2016, under authority
delegated in 49 CFR part 1.97(a).
Jeffrey D. Wiese,
Associate Administrator for Pipeline Safety.
[FR Doc. 2016-06382 Filed 4-7-16; 8:45 am]
BILLING CODE 4910-60-P
