Integrity Management: Program Modifications and Clarifications-Request for Comments, 74265-74270 [05-24061]
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Federal Register / Vol. 70, No. 240 / Thursday, December 15, 2005 / Proposed Rules
of line pipe, valve, fitting, or other line
component in a transmission line to
reduce the risk that liquids will collect
in the line. At a minimum, unless an
operator shows that it is impracticable
or unnecessary to do so, an operator
must:
(1) Configure new pipeline or
replacement of line pipe, valve, fitting,
or other line component to reduce the
risk that liquids will collect in the line;
and
(2) Equip the new pipeline or
replacement pipe with effective liquid
removal features.
(b) Monitoring. An operator must
design and construct each new
transmission line and each replacement
of line pipe, valve, fitting, or other line
component in a transmission line to
reduce the risk of internal corrosion. At
a minimum, unless an operator shows
that it is impracticable or unnecessary to
do so, an operator must use pipeline
design and construction that allows use
of corrosion monitoring devices at
locations with significant potential for
internal corrosion.
(c) Change to existing system. An
operator must evaluate the impact that
new or replaced line pipe, valve, fitting,
or other line component may have on
internal corrosion risk to the
downstream portion of an existing
pipeline and use equipment to remove
liquids and to monitor corrosion as
appropriate.
(d) Records. An operator must
document the design and construction
decisions related to internal corrosion.
Documentation must include the
reasons, and any engineering analysis,
for each decision.
Issued in Washington, DC, on December
12, 2005.
Stacey L. Gerard,
Associate Administrator for Pipeline Safety.
[FR Doc. 05–24063 Filed 12–12–05; 1:29 pm]
BILLING CODE 4910–60–P
DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials
Safety Administration
49 CFR Parts 192 and 195
[Docket No. PHMSA–04–18938]
RIN 2137–AE07
Integrity Management: Program
Modifications and Clarifications—
Request for Comments
Pipeline and Hazardous
Materials Safety Administration
(PHMSA), DOT.
ACTION: Notice of proposed rulemaking.
AGENCY:
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SUMMARY: PHMSA proposes revisions to
the current Pipeline Safety Regulations
for Pipeline Integrity Management in
High Consequence Areas. The revisions
address a petition from the hazardous
liquid pipeline industry. The revisions
are to: allow more flexibility in
reassessment intervals for hazardous
liquid pipelines by adding an eightmonth window to the five-year time
frame for operators to complete
reassessment; and require both
hazardous liquid pipeline and gas
transmission pipeline operators to
notify PHMSA whenever they reduce
pipeline pressure to make a repair and
to provide reasons for pressure
reduction. Another notification,
including reasons for repair delay,
would be required when a pressure
reduction exceeds 365 days.
Also, PHMSA proposes to correct
existing provisions for calculating a
pressure reduction when making an
immediate repair on a hazardous liquid
pipeline. The proposed correction
would allow operators to use another
acceptable method to calculate reduced
operating pressure when a specified
formula is not applicable or results in a
calculated pressure higher than
operating pressure.
Finally, PHMSA seeks the submittal
of engineering analyses and technical
data. These submittals are to provide the
basis for modifying the required time
periods for remediating certain
conditions found during a hazardous
liquid pipeline integrity assessment.
PHMSA will use this data to evaluate
the scope and scale of repair issues to
develop an accurate basis for
determining if any additional flexibility
is needed in the repair schedules.
DATES: Interested persons may submit
written comments on the proposed
regulatory changes by February 13,
2006. Interested persons may submit
written engineering analysis and
technical data by April 14, 2006. Latefiled comments will be considered to
the extent possible.
ADDRESSES: Comments should reference
Docket No. PHMSA–04–18938 and may
be submitted in the following ways:
• DOT Web site: https://dms.dot.gov.
To submit comments on the DOT
electronic docket site, click ‘‘Comment/
Submissions,’’ click ‘‘Continue,’’ fill in
the requested information, click
‘‘Continue,’’ enter your comment, then
click ‘‘Submit.’’
• Fax: 1–202–493–2251.
• Mail: Docket Management System:
U.S. Department of Transportation, 400
Seventh Street, SW., Nassif Building,
Room PL–401, Washington, DC 20590–
0001.
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• Hand Delivery: DOT Docket
Management System, Room PL–401 on
the plaza of the Nassif Building, 400
Seventh Street, SW., Washington, DC
between 9 a.m. and 5 p.m., Monday
through Friday, except Federal holidays.
• E-Gov Web site: https://
www.Regulations.gov. This site allows
the public to enter comments on any
Federal Register notice issued by any
agency.
Instructions: You should identify
docket number PHMSA–04–18938 at
the beginning of your comments. If you
submit your comments by mail, you
should send two copies. If you wish to
receive PHMSA’s confirmation receipt
of your comments, you should include
a self-addressed stamped postcard.
Internet users may submit comments at
https://www.regulations.gov, and may
access all comments received by DOT at
https://dms.dot.gov by performing a
simple search for the docket number.
Note: All comments will be posted
without changes or edits to https://
dms.dot.gov including any personal
information provided. Please see the
Privacy Act heading under Section V,
Regulatory Analyses and Notices, of the
SUPPLEMENTARY INFORMATION.
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 you may visit
https://dms.dot.gov.
FOR FURTHER INFORMATION CONTACT:
Shauna Turnbull by phone at (202) 366–
3731 or via e-mail at
shauna.turnbull@dot.gov. For questions
on technical issues, contact Mike Israni
at (202) 366–4571 or via e-mail at
mike.israni@dot.gov.
SUPPLEMENTARY INFORMATION:
I. Background
Statutory and Regulatory Requirements
The Nation’s existing pipeline
infrastructure, much of which is over 50
years old, requires regular safety and
environmental reviews to ensure its
reliability. To address several statutory
mandates and National Transportation
Safety Board (NTSB) recommendations
on actions to improve pipeline safety,
PHMSA 1 issued Integrity Management
1 The former Research and Special Programs
Administration (RSPA) was the entity responsible
for issuing the hazardous liquid pipeline and gas
transmission pipeline integrity management
program regulations. RSPA divided into two new
agencies on February 20, 2005. The newly formed
PHMSA assumed responsibility for pipeline safety
and hazardous materials management regulatory
oversight.
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Program (IMP) regulations for operators
of hazardous liquid pipelines with more
than 500 miles of pipeline (65 FR 75378;
Dec. 1, 2000). PHMSA finalized the
regulation’s repair criteria provisions on
January 14, 2002 (67 FR 1650), and
extended the IMP regulations to
operators with fewer than 500 miles of
hazardous liquid pipeline on January
16, 2002 (67 FR 2136). These regulations
are found at 49 CFR 195.452.
During development of proposed IMP
requirements for operators of gas
transmission pipelines, Congress passed
the Pipeline Safety Improvement Act of
2002, subsequently codified at 49 U.S.C.
60101 et seq. Section 60109 required
issuance of regulations by December 17,
2003, prescribing standards for a gas
transmission pipeline operator’s
adoption and implementation of an
IMP. The statute also prescribed
minimum requirements to be included
in these programs.
PHMSA issued IMP regulations for
gas transmission pipelines on December
15, 2003. These regulations are found in
49 CFR Part 192, Subpart O. Both the
hazardous liquid pipeline and gas
transmission pipeline IMP regulations
require operators to continually assess,
evaluate, repair, and validate through
comprehensive analysis, integrity of
pipeline segments in areas where a leak
or rupture would do the most damage,
such as in populated and
environmentally sensitive areas. These
areas are called ‘‘High Consequence
Areas’’ (HCAs).
PHMSA has broad authority under 49
U.S.C. 60102 to issue regulations
applying to design, installation,
inspection, emergency plans and
procedures, testing, construction,
extension, operation, replacement, and
maintenance of pipeline facilities. The
IMP requirements were issued under
this authority and addressed the
following statutory mandates:
• 49 U.S.C. 60109(a)—to prescribe
standards establishing criteria for
identifying gas pipeline facilities
located in high-density population areas
and hazardous liquid pipeline facilities
that cross waters where a substantial
likelihood of commercial navigation
exists, located in a high-density
population area, or in an area unusually
sensitive to environmental damage
(USAs);
• 49 U.S.C. 60102(f)(2)—to prescribe
additional standards requiring the
periodic inspection of pipelines in
USAs and high-density population
areas;
• 49 U.S.C. 60102(j)—to survey and
assess the effectiveness of emergency
flow restricting devices (EFRD) and
other procedures, systems, and
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equipment used to detect and locate
hazardous liquid pipeline ruptures and
to prescribe regulations on the
circumstances where a hazardous liquid
pipeline operator must use an EFRD or
similar equipment; and
• 49 U.S.C. 60109(c)—to issue
regulations prescribing standards to
direct gas transmission pipeline
operators to conduct a risk analysis and
adopt and implement an integrity
management program.
The proposed revisions in this NPRM
simply modify several of the
requirements in the hazardous liquid
pipeline and gas transmission pipeline
IMP regulations.
Also, 49 U.S.C. 60109(b) requires a
pipeline safety standard to be
practicable and designed to meet the
need for environmental safety and
protection. Pursuant to 60109(b)(2),
PHMSA considered many factors in
issuing revisions proposed in this
NPRM. PHMSA must also consider
comments received from the public
along with comments and
recommendations from the Technical
Hazardous Liquid Pipeline and
Technical Pipeline Safety Standards
Committees as appropriate. PHMSA will
address public comments and advisory
committee comments when a final rule
is prepared on these proposed revisions.
Hazardous Liquid Pipeline IMP
Overview
Hazardous liquid pipeline IMP
regulations apply to any hazardous
liquid or carbon dioxide pipeline that
could affect an HCA. Hazardous liquid
pipeline HCAs are defined as populated
areas, areas unusually sensitive to
environmental damage, and
commercially navigable waterways.
Among other specifications, the
regulations require operators to conduct
a baseline assessment and periodically
evaluate the integrity of each pipeline
segment that could affect an HCA.
Operators must also remediate, and
have a schedule for evaluation and
remediation of, anomalous conditions
discovered from these assessments. For
certain conditions, the regulations
prescribe time frames for an operator to
remediate the defect. These conditions
are categorized into immediate, 60-day,
or 180-day repair conditions.
Gas Transmission Pipeline IMP
Overview
Gas transmission pipeline IMP
regulations apply to gas transmission
pipelines located in HCAs. A gas
transmission pipeline HCA is defined
by either of two methods: (a) a Class 3
or 4 location and any area outside a
Class 3 or 4 location where the Potential
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Impact Radius is greater than 660 feet
(200 meters), and the area within a
Potential Impact Circle contains 20 or
more buildings intended for human
occupancy; or (b) an identified site,
which is an area meeting one of three
subcriteria:
(1) An outside area or open structure
occupied by 20 or more people at least
50 days a year (days need not be
consecutive);
(2) A building occupied by 20 or more
people on at least 5 days a week for 10
weeks in a year (days and weeks need
not be consecutive); or
(3) The area within a Potential Impact
Circle containing 20 or more buildings
intended for human occupancy (unless
the exception in method (a) applies).
Gas transmission pipeline operators
must complete a baseline assessment
and conduct continual integrity
assessment of pipeline segments in
HCAs and address all anomalous
conditions discovered. An operator
must remediate anomalies according to
a schedule prioritizing conditions for
evaluation and remediation. Time
frames are specified for certain
conditions, categorized as immediate,
one-year, or monitored conditions.
Industry Petition for IMP Modifications
and Clarifications
On June 18, 2004, the American
Petroleum Institute (API) and the
Association of Oil Pipe Lines
(hereinafter collectively referred to as
‘‘API’’) petitioned PHMSA for changes
to the hazardous liquid pipeline IMP
regulations. The petition sought changes
in three areas:
(1) adding flexibility to reassessment
intervals;
(2) adding flexibility to scheduling
repairs; and
(3) providing for notification when an
operator is unable to make a repair
because of permitting or other problems.
On August 27, 2004, PHMSA
personnel met with API representatives
to further discuss API’s proposed
changes; a meeting summary is in the
docket.
NPRM Changes and Information
Request
(1) Flexibility in Reassessment
Interval. To preserve a pipeline’s
integrity, § 195.452(j) requires a
continual evaluation and assessment of
each hazardous liquid pipeline segment
that could affect an HCA. Under
§ 195.452(j)(3), an operator is required to
establish intervals not to exceed five
years for continually assessing the
pipe’s integrity. The API petition
requests the reassessment interval be
extended from a maximum of 5 years to
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not longer than 68 months. API
maintains that adding a window of time
to complete a reassessment gives
operators flexibility when having to
factor in events affecting reassessment.
Such events could include weather
conditions, scheduling difficulties in
getting certain tools, species’ life cycle
activities, and permitting problems.
API’s petition also notes the expanded
interval would be consistent with other
pipeline safety regulations specifying
time frames for completing required
activities.
PHMSA agrees adding an eight-month
window to the hazardous liquid
pipeline five-year reassessment interval
will give operators flexibility in
scheduling and completing
reassessment, without compromising
pipeline safety. Such a change is
consistent with other pipeline safety
regulations specifying time frames for
an operator to complete an inspection.
(2) Scheduling Repairs. API’s petition
also recommends modifying the
‘‘Special requirements for scheduling
remediation’’ in § 195.452(h)(4) to allow
application of engineering judgment and
additional flexibility. API suggests an
approach aligned with Part 192 gas
transmission pipeline IMP repair
criteria, such as:
• expanding immediate repairs to
include any dent with cracking
indications (rather than just top side
dents with cracking);
• removing 3% dents from 60-day
conditions;
• creating a 365-day condition
category; and
• creating a monitored conditions
category consisting of ‘‘other
conditions’’, and some of the 180-day
conditions.
API gives the following reasons for
requesting these revisions to the
hazardous liquid pipeline repair
criteria:
• the designation of 60- and 180-day
conditions in Part 195 does not focus on
the physical significance of an anomaly
based on the likelihood pipe may fail;
• data indicate operators are not
finding significant 60-day conditions;
• the excavation necessary to
examine anomalies and to conduct
repairs is the most expensive part of the
process; operators seek to schedule
excavations for repairs as efficiently as
possible while still making timely
repairs;
• the length of time for getting
necessary permits and approvals can
exceed the required time frames for
making repairs;
• the extension of 60- and 180-day
conditions to 365-day conditions will
allow permitting agencies and operators
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to focus Federal streamlining efforts on
those repairs that may pose an
immediate risk;
• environmental considerations to
protect important species will affect
operators’ ability to schedule necessary
pipeline integrity activities; and
• repair criteria based on immediate,
scheduled, and monitored repairs
would work well for the hazardous
liquid pipeline industry, especially
considering its high usage of in-line
inspection tools.
Request for Data
PHMSA and API discussed the need
for more information (data on types of
defects currently requiring remediation
within 60 and 180 days), before PHMSA
could determine if regulatory or some
other action would be needed to address
API’s request. To better determine what
type of action, if any, is needed PHMSA
is requesting data and comments on the
following topics:
• an identification of the
characteristics of defects requiring
short-term (60- and 180-day)
remediation;
• an evaluation of defects to find out
which are stable;
• a sound engineering or technical
basis for checking rather than repairing
these defects; and
• the development of criteria
allowing operators to use logs from
internal inspection tool runs to identify
stable defects.
(3) Notification of Special
Circumstances. API believes the
hazardous liquid pipeline IMP rule fails
to recognize that an operator may not be
able to make a repair within a required
period. API requests changing the rule
to allow an operator to notify PHMSA
when the operator has taken all
available steps and is still unable to
conduct an investigation or repair a
specific condition. API maintains such
a change would alert PHMSA to the
myriad real-world conditions (weather,
electrical outage, and permitting
requirements) that can interfere with
repair periods and would also protect
operators from enforcement action for
events over which an operator has no
control. API further believes notification
would help PHMSA recognize patterns
potentially affecting pipeline safety,
such as new or changed permit criteria.
Both the hazardous liquid pipeline
(§ 195.452(h)) and gas transmission
pipeline (§ 192.933) IMP remediation
requirements require an operator to
temporarily reduce pressure or to shut
down the pipeline until the operator
completes repair of an immediate repair
condition. Gas transmission pipeline
operators are also required to reduce
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pressure if they cannot meet a specified
time limit for making a repair, or to take
other action to ensure segment safety.
The regulations do not require
notification when an operator reduces
pressure. Notification is required only
when a hazardous liquid pipeline or gas
transmission pipeline operator cannot
meet its schedule for evaluating and
remediating any condition and cannot
provide safety though a temporary
reduction in operating pressure. Any
pressure reduction longer than 365 days
must also be justified.
PHMSA agrees with API that
notifying PHMSA of the reasons for an
operator making a pressure reduction
would give the agency better
information on conditions that could
interfere with an operator’s ability to
complete remediation of defects found
during an integrity assessment.
However, the usefulness of such
information is not limited to repairs
made on hazardous liquid pipelines.
Therefore, PHMSA is proposing to
revise remediation requirements to
require both gas transmission pipeline
and hazardous liquid pipeline operators
to notify PHMSA when a pressure
reduction is made on a segment covered
under IMP to remediate a defect, and to
provide the reasons for the pressure
reduction. Instead of only requiring
notification when an operator cannot
meet repair schedules and cannot
provide safety through a temporary
reduction in operating pressure, an
operator would be required to notify
PHMSA any time it reduces operating
pressure to make a repair, and to give
the pressure reduction reasons. If a
repair takes longer than 365 days, an
operator would again have to notify
PHMSA and provide the reasons for the
delay. Operators would still be required
to take further remedial action to ensure
pipeline safety when a pressure
reduction exceeds 365 days.
For gas transmission pipeline
operators, State notification
requirements would continue to apply
for intrastate gas transmission pipelines
and interstate gas transmission
pipelines in States where PHMSA has
an interstate agent agreement. However,
we are proposing to delete the
requirement for notification of local
pipeline safety authorities. PHMSA is
not aware of any instance where an
intrastate gas transmission pipeline
would be regulated by a local authority
rather than a State public safety
authority. Furthermore, PHMSA
interstate agreements are only with State
pipeline safety authorities.
PHMSA proposes these revisions to
get a better understanding of the reasons
hazardous liquid pipeline and gas
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transmission pipeline operators are
delayed in making repairs. PHMSA
further hopes to work with the U.S.
Department of Energy to analyze
whether prolonged pressure reductions
have potential impact on the Nation’s
energy supply. This notification will
also give PHMSA better information on:
• whether permitting issues are
involved in pressure reduction;
• what causes schedule delays
(permitting, scheduling, other); and
• where and under what
circumstances PHMSA can help
expedite permits for repairs.
(4) Formula for Reducing Operating
Pressure. Section 195.452(h)(4) requires
a hazardous liquid pipeline operator to
calculate a temporary reduction in
operating pressure using the formula in
section 451.7 of ASME/ANSI B31.4
when making an immediate repair. The
requirement was meant to ensure an
additional safety margin is provided
while an operator makes an immediate
repair. However, a recent frequently
asked question highlighted that this
formula does not always apply and may
result in a calculated pressure higher
than the original operating pressure. In
addition, the formula only applies to
metal loss anomalies, not to immediate
repair conditions not involving metal
loss. Therefore, PHMSA proposes to
correct the provision by allowing a
hazardous liquid pipeline operator to
use the ASME/ANSI B31.4 formula only
if applicable. If not applicable to the
anomaly, or if the formula results in a
calculated pressure higher than original
operating pressure, an operator would
be allowed to use another acceptable
means to calculate a pressure reduction.
Regulatory Analyses and Notices
Executive Order 12866 and DOT
Regulatory Policies and Procedures
DOT does not consider this action to
be a significant regulatory action under
section 3(f) of Executive Order 12866
(58 FR 51735; October 4, 1993). This
NPRM is nonsignificant under DOT’s
regulatory policies and procedures (44
FR 11034; February 26, 1979). PHMSA
prepared a Draft Regulatory Evaluation
for this NPRM and placed it in the
public docket.
The proposed changes to add
flexibility to scheduling continuous
assessment would create ongoing
benefits and have no cost effects. These
adjustments would create positive net
benefits. PHMSA believes the proposed
change to the notification requirement
for pressure reduction would create
added continuing costs, with an
estimated six notifications per operator
each year. However, notification
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requirements have no significant cost
for either operators or industry overall.
The benefits are expected to offset costs.
Together, these proposed changes to
IMP regulations for hazardous liquid
and gas transmission pipelines are
expected to create positive net benefits.
Regulatory Flexibility Act
Under the Regulatory Flexibility Act
(5 U.S.C. 601 et seq.) PHMSA must
consider whether a rulemaking would
have a significant impact on a
substantial number of small entities.
The requirements proposed in this
NPRM do not apply to a substantial
number of small entities. The proposed
revisions to the IMP rules will affect
hazardous liquid pipeline operators and
gas transmission pipeline operators.
Most hazardous liquid pipeline
operators and gas transmission pipeline
operators do not meet the Small
Business Administration’s small
business definition, which is either 6
million in revenue (for natural gas
pipelines under North American
Industry Classification System (NAICS)
486210) or 1,500 employees (for crude
oil and refined petroleum product
pipelines under NAICS 486110 and
486910). Additionally, notification costs
per operator are about $194.50 annually.
This is less than 0.01 percent of the $6
million gross revenue. This is not a
significant burden on pipeline
operators, including small businesses.
The proposed changes to add
flexibility to scheduling continuous
assessment would create ongoing
benefits and have no cost effects. These
modifications would create positive net
benefits. The changed notification
requirements for pressure reduction
would create negligible added costs as
well as benefits; however, the benefits
are expected to offset costs. Together,
these proposed changes to the IMP
regulations for hazardous liquid and gas
transmission pipelines are expected to
create positive net benefits to the
affected industry.
Based on the cost benefit analysis and
the determination that hazardous liquid
pipeline and gas transmission pipeline
operators do not generally fall into the
Small Business Administration’s
revenue or employee size guidelines, it
is unlikely (under section 605 of the
Regulatory Flexibility Act) the proposed
regulatory changes will have any
significant impact on a substantial
number of small entities. PHMSA
invites comments on these assumptions.
Paperwork Reduction Act
This NPRM proposes minimal
information collection requirements.
Based on information currently
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available to PHMSA, 74 notifications
were submitted by 26 operators over
three years. Of these 74 notifications, 36
of them, or about 50 percent, were due
to an operator’s inability to meet repair
schedules or reduce pressure. The
proposed notification modifications will
increase notification frequency. PHMSA
estimates, on average, the proposed
changes will result in six notifications
per operator annually. The estimated
average time to prepare a notification
request is 30 minutes. Consequently,
there should be no significant cost or
hourly burden on individual operators
or the industry because of the
notification requirement in this
proposal. PHMSA evaluated the NPRM,
as required by the Paperwork Reduction
Act of 1995 (44 U.S.C. 3507(d)), and
believes there will be no significant
paperwork burden on industry or
individual operators because of the
NPRM. As required by the Paperwork
Reduction Act of 1995 (44 U.S.C.
3507(d)), PHMSA will present a
separate paperwork analysis to the
Office of Management and Budget for
review. A copy of the analysis will also
be entered in the docket.
Executive Order 13084
This NPRM has been analyzed under
principles and criteria contained in
Executive Order 13084 (‘‘Consultation
and Coordination with Indian Tribal
Governments’’). Because this NPRM
does not significantly or uniquely affect
communities of Indian tribal
governments and does not impose
substantial direct compliance costs, the
funding and consultation requirements
of Executive Order 13084 do not apply.
Executive Order 13132
PHMSA analyzed this NPRM under
principles and criteria contained in
Executive Order 13132 (Federalism).
None of the proposed actions: (1) Has
substantial direct effects on States,
relationships between the National
Government and the States, or
distribution of power and
responsibilities among various levels of
government; (2) imposes substantial
direct compliance costs on States and
local governments; or (3) preempts State
law. Therefore, the consultation and
funding requirements of Executive
Order 13132 (64 FR 43255; August 10,
1999) do not apply.
Executive Order 13211
This NPRM 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 NPRM as a significant energy
action.
Unfunded Mandates
This NPRM does not impose
unfunded mandates under the 1995
Unfunded Mandates Reform Act. It does
not result in costs of $100 million or
more to either State, local, or tribal
governments, in aggregate, or to the
private sector, and is the least
burdensome alternative for achieving
the NPRM objectives.
National Environmental Policy Act
PHMSA analyzed this NPRM in
accordance with section 102(2)(c) of the
National Environmental Policy Act (42
U.S.C. 4332), the Council on
Environmental Quality regulations (40
CFR 1500–1508), and DOT Order
5610.1D, and has preliminarily
determined this action will not
significantly affect human environment
quality. The Environmental Assessment
is in the Docket.
List of Subjects in 49 CFR Parts 192 and
195
Pipeline safety, Reporting and
recordkeeping requirements.
For the reasons set forth in the
preamble, PHMSA proposes to amend
49 CFR parts 192 and 195 as follows:
PART 192—TRANSPORTATION OF
NATURAL AND OTHER GAS BY
PIPELINE: MINIMUM FEDERAL
SAFETY STANDARDS
1. The authority citation for Part 192
continues to read as follows:
Authority: 49 U.S.C. 5103, 60102, 60104,
60108, 60109, 60110, 60113, and 60118; and
49 CFR 1.53.
2. Amend § 192.933 by revising
paragraphs (a) and (c) to read as follows:
§ 192.933 What actions must be taken to
address integrity issues?
(a) General requirements. An operator
must take prompt action to address all
anomalous conditions that the operator
discovers through the integrity
assessment. In addressing all
conditions, an operator must evaluate
all anomalous conditions and remediate
those that could reduce a pipeline’s
integrity. An operator must be able to
demonstrate that the remediation of the
condition will ensure that the condition
is unlikely to pose a threat to the
integrity of the pipeline until the next
reassessment of the covered segment.
(1) Pressure reduction. If an operator
is unable to respond within the time
VerDate Aug<31>2005
14:18 Dec 14, 2005
Jkt 208001
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. If pressure is reduced,
an operator must determine the
temporary reduction in operating
pressure using ASME/ANSI B31G (ibr,
see § 192.7) or AGA Pipeline Research
Committee Project PR–3–805
(‘‘RSTRENG’’; ibr, see § 192.7) or reduce
the operating pressure to a level not
exceeding 80 percent of the level at the
time the condition was discovered. (See
appendix A to this part for information
on availability of incorporation by
reference information).
(i) Notice. An operator must notify
PHMSA in accordance with § 192.949
whenever it reduces operating pressure
to make a repair under this subpart.
This will include any temporary
reduction in pressure required by this
section. This notice must include the
reasons for the pressure reduction. 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.
(ii) Long-term pressure reduction.
When a pressure reduction exceeds 365
days, an operator must again notify
PHMSA under § 192.949 with the
reasons causing the delay. 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. In
addition, an operator must provide a
technical justification that the
continued pressure restriction will not
jeopardize the integrity of the pipeline.
(2) [Reserved]
*
*
*
*
*
(c) Schedule for evaluation and
remediation. An operator must complete
remediation of a condition according to
a schedule that prioritizes the
conditions for evaluation and
remediation. Unless a special
requirement for remediating certain
conditions applies, as provided in
paragraph (d) of this section, an operator
must follow the schedule in ASME/
ANSI B31.8S (ibr, see § 192.7), section 7,
Figure 4. If an operator cannot meet the
schedule for any condition, the operator
must justify the reasons why it cannot
meet the schedule and that the changed
schedule will not jeopardize public
safety.
*
*
*
*
*
PO 00000
Frm 00055
Fmt 4702
Sfmt 4702
74269
PART 195—TRANSPORTATION OF
HAZARDOUS LIQUIDS BY PIPELINE
3. The authority citation for part 195
continues to read as follows:
Authority: 49 U.S.C. 5103, 60102, 60104,
60108, 60109, 60118; and 49 CFR 1.53.
4. Amend § 195.452 by revising paragraphs
(h)(1), (h)(3), (h)(4)(i) introductory text and
the first sentence of paragraph (j)(3) to read
as follows:
§ 195.452 Pipeline integrity management in
high consequence areas.
*
*
*
*
*
(h) * * *
(1) General requirements. An operator
must take prompt action to address all
anomalous conditions that the operator
discovers through the integrity
assessment or information analysis. In
addressing all conditions, an operator
must evaluate all anomalous conditions
and remediate those that could reduce
a pipeline’s integrity. An operator must
be able to demonstrate that the
remediation of the condition will ensure
that the condition is unlikely to pose a
threat to the long-term integrity of the
pipeline. An operator must comply with
§ 195.422 when making a repair.
(i) Pressure reduction. An operator
must notify PHMSA in accordance with
paragraph (m) of this section whenever
it reduces operating pressure to make a
repair under this section. This will
include any temporary reduction in
pressure required by paragraph (h) (4) (i)
of this section. This notice must include
the reasons for the pressure reduction.
(ii) Long-term pressure reduction.
When a pressure reduction exceeds 365
days, an operator must again notify
PHMSA in accordance with paragraph
(m) of this section with the reasons
causing the delay. An operator must
also take further remedial action to
ensure the safety of the pipeline.
*
*
*
*
*
(3) Schedule for evaluation and
remediation. An operator must complete
remediation of a condition according to
a schedule that prioritizes the
conditions for evaluation and
remediation. If an operator cannot meet
the schedule for any condition, the
operator must justify the reasons why it
cannot meet the schedule and that the
changed schedule will not jeopardize
public safety or environmental
protection.
(4) Special requirements for
scheduling remediation. (i) Immediate
repair conditions. An operator’s
evaluation and remediation schedule
must provide for immediate repair
conditions. To maintain safety, an
operator must temporarily reduce
operating pressure or shut down the
E:\FR\FM\15DEP1.SGM
15DEP1
74270
Federal Register / Vol. 70, No. 240 / Thursday, December 15, 2005 / Proposed Rules
pipeline until the operator completes
the repair of these conditions. An
operator must calculate the temporary
reduction in operating pressure using
the formula in section 451.7 of ASME/
ANSI B31.4 (ibr, see § 195.3), if
applicable. If the formula is not
applicable to the type of anomaly or the
calculated pressure results in a higher
operating pressure, an operator must use
an alternative acceptable method to
calculate a reduced operating pressure.
An operator must treat the following
conditions as immediate repair
conditions:
*
*
*
*
*
(j) * * *
(3) Assessment intervals. An operator
must establish five-year intervals, not to
exceed 68 months, for continually
assessing the line pipe’s integrity.* * *
*
*
*
*
*
Issued in Washington, DC, on December
12, 2005.
Stacey L. Gerard,
Associate Administrator for Pipeline Safety.
[FR Doc. 05–24061 Filed 12–12–05; 1:29 pm]
BILLING CODE 4910–60–P
DEPARTMENT OF TRANSPORTATION
National Highway Traffic Safety
Administration
49 CFR Part 571
[Docket No. NHTSA–2005–21462]
RIN 2127–AJ37
Federal Motor Vehicle Safety
Standards; Air Brake Systems
National Highway Traffic
Safety Administration (NHTSA),
Department of Transportation.
ACTION: Notice of proposed rulemaking
(NPRM).
AGENCY:
SUMMARY: The agency is proposing to
amend our air brake standard to
improve the stopping distance
performance of truck tractors. Based on
current safety trend data and brake
system technologies for truck tractors,
we are proposing to reduce the required
stopping distance for these vehicles by
20 to 30 percent. We have tentatively
concluded that truck tractors are
capable of achieving a reduction in
stopping distance within this range with
existing technologies.
We also discuss research and request
comment concerning improving the
braking performance of other types of
heavy vehicles, i.e., trailers, straight
trucks, and buses. The agency may
address improved braking performance
VerDate Aug<31>2005
14:18 Dec 14, 2005
Jkt 208001
for these other vehicles in a future
rulemaking.
You should submit comments
early enough to ensure that Docket
Management receives them not later
than April 14, 2006.
ADDRESSES: You may submit comments
(identified by the DOT DMS Docket
Number) by any of the following
methods:
• Web site: https://dms.dot.gov.
Follow the instructions for submitting
comments on the DOT electronic docket
site.
• Fax: (202) 493–2251.
• Mail: Docket Management Facility,
U.S. Department of Transportation, 400
Seventh Street, SW., Nassif Building,
Room PL–401, Washington, DC 20590–
001.
• Hand Delivery: Room PL–401 on
the plaza level of the Nassif Building,
400 Seventh Street, SW., Washington,
DC, between 9 a.m. and 5 p.m., Monday
through Friday, except Federal
Holidays.
• Federal eRulemaking Portal: Go to
https://www.regulations.gov. Follow the
online instructions for submitting
comments.
Instructions: All submissions must
include the agency name and docket
number or Regulatory Identification
Number (RIN) for this rulemaking. For
detailed instructions on submitting
comments and additional information
on the rulemaking process, see the
Request for Comments heading under
the SUPPLEMENTARY INFORMATION section
of this document. Note that all
comments received will be posted
without change to https://dms.dot.gov,
including any personal information
provided. You may review DOT’s
complete Privacy Act Statement in the
Federal Register published on April 11,
2000 (Volume 65, Number 70; Pages
19477–78) or you may visit https://
dms.dot.gov.
Docket: For access to the docket to
read background documents or
comments received, go to https://
dms.dot.gov at any time or to Room PL–
401 on the plaza level of the Nassif
Building, 400 Seventh Street, SW.,
Washington, DC, between 9 a.m. and 5
p.m., Monday through Friday, except
Federal Holidays.
FOR FURTHER INFORMATION CONTACT: The
following persons at the National
Highway Traffic Safety Administration:
For non-legal issues: Mr. Jeff Woods
of the NHTSA Office of Rulemaking at
(202) 366–6206.
For legal issues: Mr. Christopher
Calamita of the NHTSA Office of Chief
Counsel at (202) 366–2992.
DATES:
PO 00000
Frm 00056
Fmt 4702
Sfmt 4702
You may send mail to both of these
officials at the National Highway Traffic
Safety Administration, 400 Seventh St.,
SW., Washington, DC 20590.
SUPPLEMENTARY INFORMATION:
I. Background
II. Safety Issues
III. Heavy Truck Braking Performance
A. NHTSA Research
B. Industry Research
C. Agency Proposal
IV. Benefits and Costs of Improved Stopping
Distances
V. Lead Time
VI. Ongoing and Future Research
VII. Request for Comments
VIII.Rulemaking Analyses and Notices
I. Background
On March 10, 1995, we published
three final rules as a part of a
comprehensive effort to improve the
braking ability of medium and heavy
vehicles 1 (60 FR 13216 and 60 FR
13287). The major focus of that effort
was to improve the directional stability
and control of heavy vehicles during
braking through antilock brake system
(ABS) requirements. However, the 1995
effort also reinstated stopping distance
requirements for air-braked vehicles,
and established different stopping
distances for different types of heavy
vehicles. Previous stopping distance
requirements for medium and heavy
vehicles had been invalidated in 1978
by the United States Court of Appeals
for the 9th Circuit because of issues
with the reliability of ABS then in use.
See, PACCAR v. NHTSA, 573 F.2d 632
(9th Cir. 1978) cert. denied, 439 U.S.
862 (1978).
The current stopping distance
requirements under Federal Motor
Vehicle Safety Standard No. 121, Air
brake systems, as established under the
1995 final rule, are determined
according to vehicle type. Under the
loaded-60-mph stopping distance
requirements of FMVSS No. 121, airbraked buses must comply with a
stopping distance of 280 feet, air-braked
single-unit trucks must comply with a
stopping distance of 310 feet, and airbraked truck tractors must comply with
a stopping distance requirement of 355
feet.2 Under the unloaded-60-mph
1 Medium and heavy weight vehicles are
hydraulic-braked vehicles over 10,000 pounds gross
vehicle weight rating (GVWR) (i.e., trucks and
buses), and all vehicles with a GVWR greater than
10,000 pounds equipped with air brake systems
(i.e., trucks, buses, and trailers); here after referred
to collectively as heavy vehicles. Large trucks are
a segment of heavy vehicles and are defined as
trucks, including truck tractors, with a GVWR
greater than 10,000 pounds.
2 For heavy truck tractors (tractors), the current
stopping distance test at GVWR is conducted with
the tractor coupled to an un-braked control trailer,
with weight placed over the fifth wheel of the
E:\FR\FM\15DEP1.SGM
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]]>Agencies
[Federal Register Volume 70, Number 240 (Thursday, December 15, 2005)]
[Proposed Rules]
[Pages 74265-74270]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 05-24061]
-----------------------------------------------------------------------
DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials Safety Administration
49 CFR Parts 192 and 195
[Docket No. PHMSA-04-18938]
RIN 2137-AE07
Integrity Management: Program Modifications and Clarifications--
Request for Comments
AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA),
DOT.
ACTION: Notice of proposed rulemaking.
-----------------------------------------------------------------------
SUMMARY: PHMSA proposes revisions to the current Pipeline Safety
Regulations for Pipeline Integrity Management in High Consequence
Areas. The revisions address a petition from the hazardous liquid
pipeline industry. The revisions are to: allow more flexibility in
reassessment intervals for hazardous liquid pipelines by adding an
eight-month window to the five-year time frame for operators to
complete reassessment; and require both hazardous liquid pipeline and
gas transmission pipeline operators to notify PHMSA whenever they
reduce pipeline pressure to make a repair and to provide reasons for
pressure reduction. Another notification, including reasons for repair
delay, would be required when a pressure reduction exceeds 365 days.
Also, PHMSA proposes to correct existing provisions for calculating
a pressure reduction when making an immediate repair on a hazardous
liquid pipeline. The proposed correction would allow operators to use
another acceptable method to calculate reduced operating pressure when
a specified formula is not applicable or results in a calculated
pressure higher than operating pressure.
Finally, PHMSA seeks the submittal of engineering analyses and
technical data. These submittals are to provide the basis for modifying
the required time periods for remediating certain conditions found
during a hazardous liquid pipeline integrity assessment. PHMSA will use
this data to evaluate the scope and scale of repair issues to develop
an accurate basis for determining if any additional flexibility is
needed in the repair schedules.
DATES: Interested persons may submit written comments on the proposed
regulatory changes by February 13, 2006. Interested persons may submit
written engineering analysis and technical data by April 14, 2006.
Late-filed comments will be considered to the extent possible.
ADDRESSES: Comments should reference Docket No. PHMSA-04-18938 and may
be submitted in the following ways:
DOT Web site: https://dms.dot.gov. To submit comments on
the DOT electronic docket site, click ``Comment/Submissions,'' click
``Continue,'' fill in the requested information, click ``Continue,''
enter your comment, then click ``Submit.''
Fax: 1-202-493-2251.
Mail: Docket Management System: U.S. Department of
Transportation, 400 Seventh Street, SW., Nassif Building, Room PL-401,
Washington, DC 20590-0001.
Hand Delivery: DOT Docket Management System, Room PL-401
on the plaza of the Nassif Building, 400 Seventh Street, SW.,
Washington, DC between 9 a.m. and 5 p.m., Monday through Friday, except
Federal holidays.
E-Gov Web site: https://www.Regulations.gov. This site
allows the public to enter comments on any Federal Register notice
issued by any agency.
Instructions: You should identify docket number PHMSA-04-18938 at
the beginning of your comments. If you submit your comments by mail,
you should send two copies. If you wish to receive PHMSA's confirmation
receipt of your comments, you should include a self-addressed stamped
postcard. Internet users may submit comments at https://
www.regulations.gov, and may access all comments received by DOT at
https://dms.dot.gov by performing a simple search for the docket number.
Note: All comments will be posted without changes or edits to https://
dms.dot.gov including any personal information provided. Please see the
Privacy Act heading under Section V, Regulatory Analyses and Notices,
of the Supplementary Information.
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 you may visit https://dms.dot.gov.
FOR FURTHER INFORMATION CONTACT: Shauna Turnbull by phone at (202) 366-
3731 or via e-mail at shauna.turnbull@dot.gov. For questions on
technical issues, contact Mike Israni at (202) 366-4571 or via e-mail
at mike.israni@dot.gov.
SUPPLEMENTARY INFORMATION:
I. Background
Statutory and Regulatory Requirements
The Nation's existing pipeline infrastructure, much of which is
over 50 years old, requires regular safety and environmental reviews to
ensure its reliability. To address several statutory mandates and
National Transportation Safety Board (NTSB) recommendations on actions
to improve pipeline safety, PHMSA \1\ issued Integrity Management
[[Page 74266]]
Program (IMP) regulations for operators of hazardous liquid pipelines
with more than 500 miles of pipeline (65 FR 75378; Dec. 1, 2000). PHMSA
finalized the regulation's repair criteria provisions on January 14,
2002 (67 FR 1650), and extended the IMP regulations to operators with
fewer than 500 miles of hazardous liquid pipeline on January 16, 2002
(67 FR 2136). These regulations are found at 49 CFR 195.452.
---------------------------------------------------------------------------
\1\ The former Research and Special Programs Administration
(RSPA) was the entity responsible for issuing the hazardous liquid
pipeline and gas transmission pipeline integrity management program
regulations. RSPA divided into two new agencies on February 20,
2005. The newly formed PHMSA assumed responsibility for pipeline
safety and hazardous materials management regulatory oversight.
---------------------------------------------------------------------------
During development of proposed IMP requirements for operators of
gas transmission pipelines, Congress passed the Pipeline Safety
Improvement Act of 2002, subsequently codified at 49 U.S.C. 60101 et
seq. Section 60109 required issuance of regulations by December 17,
2003, prescribing standards for a gas transmission pipeline operator's
adoption and implementation of an IMP. The statute also prescribed
minimum requirements to be included in these programs.
PHMSA issued IMP regulations for gas transmission pipelines on
December 15, 2003. These regulations are found in 49 CFR Part 192,
Subpart O. Both the hazardous liquid pipeline and gas transmission
pipeline IMP regulations require operators to continually assess,
evaluate, repair, and validate through comprehensive analysis,
integrity of pipeline segments in areas where a leak or rupture would
do the most damage, such as in populated and environmentally sensitive
areas. These areas are called ``High Consequence Areas'' (HCAs).
PHMSA has broad authority under 49 U.S.C. 60102 to issue
regulations applying to design, installation, inspection, emergency
plans and procedures, testing, construction, extension, operation,
replacement, and maintenance of pipeline facilities. The IMP
requirements were issued under this authority and addressed the
following statutory mandates:
49 U.S.C. 60109(a)--to prescribe standards establishing
criteria for identifying gas pipeline facilities located in high-
density population areas and hazardous liquid pipeline facilities that
cross waters where a substantial likelihood of commercial navigation
exists, located in a high-density population area, or in an area
unusually sensitive to environmental damage (USAs);
49 U.S.C. 60102(f)(2)--to prescribe additional standards
requiring the periodic inspection of pipelines in USAs and high-density
population areas;
49 U.S.C. 60102(j)--to survey and assess the effectiveness
of emergency flow restricting devices (EFRD) and other procedures,
systems, and equipment used to detect and locate hazardous liquid
pipeline ruptures and to prescribe regulations on the circumstances
where a hazardous liquid pipeline operator must use an EFRD or similar
equipment; and
49 U.S.C. 60109(c)--to issue regulations prescribing
standards to direct gas transmission pipeline operators to conduct a
risk analysis and adopt and implement an integrity management program.
The proposed revisions in this NPRM simply modify several of the
requirements in the hazardous liquid pipeline and gas transmission
pipeline IMP regulations.
Also, 49 U.S.C. 60109(b) requires a pipeline safety standard to be
practicable and designed to meet the need for environmental safety and
protection. Pursuant to 60109(b)(2), PHMSA considered many factors in
issuing revisions proposed in this NPRM. PHMSA must also consider
comments received from the public along with comments and
recommendations from the Technical Hazardous Liquid Pipeline and
Technical Pipeline Safety Standards Committees as appropriate. PHMSA
will address public comments and advisory committee comments when a
final rule is prepared on these proposed revisions.
Hazardous Liquid Pipeline IMP Overview
Hazardous liquid pipeline IMP regulations apply to any hazardous
liquid or carbon dioxide pipeline that could affect an HCA. Hazardous
liquid pipeline HCAs are defined as populated areas, areas unusually
sensitive to environmental damage, and commercially navigable
waterways. Among other specifications, the regulations require
operators to conduct a baseline assessment and periodically evaluate
the integrity of each pipeline segment that could affect an HCA.
Operators must also remediate, and have a schedule for evaluation and
remediation of, anomalous conditions discovered from these assessments.
For certain conditions, the regulations prescribe time frames for an
operator to remediate the defect. These conditions are categorized into
immediate, 60-day, or 180-day repair conditions.
Gas Transmission Pipeline IMP Overview
Gas transmission pipeline IMP regulations apply to gas transmission
pipelines located in HCAs. A gas transmission pipeline HCA is defined
by either of two methods: (a) a Class 3 or 4 location and any area
outside a Class 3 or 4 location where the Potential Impact Radius is
greater than 660 feet (200 meters), and the area within a Potential
Impact Circle contains 20 or more buildings intended for human
occupancy; or (b) an identified site, which is an area meeting one of
three subcriteria:
(1) An outside area or open structure occupied by 20 or more people
at least 50 days a year (days need not be consecutive);
(2) A building occupied by 20 or more people on at least 5 days a
week for 10 weeks in a year (days and weeks need not be consecutive);
or
(3) The area within a Potential Impact Circle containing 20 or more
buildings intended for human occupancy (unless the exception in method
(a) applies).
Gas transmission pipeline operators must complete a baseline
assessment and conduct continual integrity assessment of pipeline
segments in HCAs and address all anomalous conditions discovered. An
operator must remediate anomalies according to a schedule prioritizing
conditions for evaluation and remediation. Time frames are specified
for certain conditions, categorized as immediate, one-year, or
monitored conditions.
Industry Petition for IMP Modifications and Clarifications
On June 18, 2004, the American Petroleum Institute (API) and the
Association of Oil Pipe Lines (hereinafter collectively referred to as
``API'') petitioned PHMSA for changes to the hazardous liquid pipeline
IMP regulations. The petition sought changes in three areas:
(1) adding flexibility to reassessment intervals;
(2) adding flexibility to scheduling repairs; and
(3) providing for notification when an operator is unable to make a
repair because of permitting or other problems.
On August 27, 2004, PHMSA personnel met with API representatives to
further discuss API's proposed changes; a meeting summary is in the
docket.
NPRM Changes and Information Request
(1) Flexibility in Reassessment Interval. To preserve a pipeline's
integrity, Sec. 195.452(j) requires a continual evaluation and
assessment of each hazardous liquid pipeline segment that could affect
an HCA. Under Sec. 195.452(j)(3), an operator is required to establish
intervals not to exceed five years for continually assessing the pipe's
integrity. The API petition requests the reassessment interval be
extended from a maximum of 5 years to
[[Page 74267]]
not longer than 68 months. API maintains that adding a window of time
to complete a reassessment gives operators flexibility when having to
factor in events affecting reassessment. Such events could include
weather conditions, scheduling difficulties in getting certain tools,
species' life cycle activities, and permitting problems. API's petition
also notes the expanded interval would be consistent with other
pipeline safety regulations specifying time frames for completing
required activities.
PHMSA agrees adding an eight-month window to the hazardous liquid
pipeline five-year reassessment interval will give operators
flexibility in scheduling and completing reassessment, without
compromising pipeline safety. Such a change is consistent with other
pipeline safety regulations specifying time frames for an operator to
complete an inspection.
(2) Scheduling Repairs. API's petition also recommends modifying
the ``Special requirements for scheduling remediation'' in Sec.
195.452(h)(4) to allow application of engineering judgment and
additional flexibility. API suggests an approach aligned with Part 192
gas transmission pipeline IMP repair criteria, such as:
expanding immediate repairs to include any dent with
cracking indications (rather than just top side dents with cracking);
removing 3% dents from 60-day conditions;
creating a 365-day condition category; and
creating a monitored conditions category consisting of
``other conditions'', and some of the 180-day conditions.
API gives the following reasons for requesting these revisions to
the hazardous liquid pipeline repair criteria:
the designation of 60- and 180-day conditions in Part 195
does not focus on the physical significance of an anomaly based on the
likelihood pipe may fail;
data indicate operators are not finding significant 60-day
conditions;
the excavation necessary to examine anomalies and to
conduct repairs is the most expensive part of the process; operators
seek to schedule excavations for repairs as efficiently as possible
while still making timely repairs;
the length of time for getting necessary permits and
approvals can exceed the required time frames for making repairs;
the extension of 60- and 180-day conditions to 365-day
conditions will allow permitting agencies and operators to focus
Federal streamlining efforts on those repairs that may pose an
immediate risk;
environmental considerations to protect important species
will affect operators' ability to schedule necessary pipeline integrity
activities; and
repair criteria based on immediate, scheduled, and
monitored repairs would work well for the hazardous liquid pipeline
industry, especially considering its high usage of in-line inspection
tools.
Request for Data
PHMSA and API discussed the need for more information (data on
types of defects currently requiring remediation within 60 and 180
days), before PHMSA could determine if regulatory or some other action
would be needed to address API's request. To better determine what type
of action, if any, is needed PHMSA is requesting data and comments on
the following topics:
an identification of the characteristics of defects
requiring short-term (60- and 180-day) remediation;
an evaluation of defects to find out which are stable;
a sound engineering or technical basis for checking rather
than repairing these defects; and
the development of criteria allowing operators to use logs
from internal inspection tool runs to identify stable defects.
(3) Notification of Special Circumstances. API believes the
hazardous liquid pipeline IMP rule fails to recognize that an operator
may not be able to make a repair within a required period. API requests
changing the rule to allow an operator to notify PHMSA when the
operator has taken all available steps and is still unable to conduct
an investigation or repair a specific condition. API maintains such a
change would alert PHMSA to the myriad real-world conditions (weather,
electrical outage, and permitting requirements) that can interfere with
repair periods and would also protect operators from enforcement action
for events over which an operator has no control. API further believes
notification would help PHMSA recognize patterns potentially affecting
pipeline safety, such as new or changed permit criteria.
Both the hazardous liquid pipeline (Sec. 195.452(h)) and gas
transmission pipeline (Sec. 192.933) IMP remediation requirements
require an operator to temporarily reduce pressure or to shut down the
pipeline until the operator completes repair of an immediate repair
condition. Gas transmission pipeline operators are also required to
reduce pressure if they cannot meet a specified time limit for making a
repair, or to take other action to ensure segment safety. The
regulations do not require notification when an operator reduces
pressure. Notification is required only when a hazardous liquid
pipeline or gas transmission pipeline operator cannot meet its schedule
for evaluating and remediating any condition and cannot provide safety
though a temporary reduction in operating pressure. Any pressure
reduction longer than 365 days must also be justified.
PHMSA agrees with API that notifying PHMSA of the reasons for an
operator making a pressure reduction would give the agency better
information on conditions that could interfere with an operator's
ability to complete remediation of defects found during an integrity
assessment. However, the usefulness of such information is not limited
to repairs made on hazardous liquid pipelines. Therefore, PHMSA is
proposing to revise remediation requirements to require both gas
transmission pipeline and hazardous liquid pipeline operators to notify
PHMSA when a pressure reduction is made on a segment covered under IMP
to remediate a defect, and to provide the reasons for the pressure
reduction. Instead of only requiring notification when an operator
cannot meet repair schedules and cannot provide safety through a
temporary reduction in operating pressure, an operator would be
required to notify PHMSA any time it reduces operating pressure to make
a repair, and to give the pressure reduction reasons. If a repair takes
longer than 365 days, an operator would again have to notify PHMSA and
provide the reasons for the delay. Operators would still be required to
take further remedial action to ensure pipeline safety when a pressure
reduction exceeds 365 days.
For gas transmission pipeline operators, State notification
requirements would continue to apply for intrastate gas transmission
pipelines and interstate gas transmission pipelines in States where
PHMSA has an interstate agent agreement. However, we are proposing to
delete the requirement for notification of local pipeline safety
authorities. PHMSA is not aware of any instance where an intrastate gas
transmission pipeline would be regulated by a local authority rather
than a State public safety authority. Furthermore, PHMSA interstate
agreements are only with State pipeline safety authorities.
PHMSA proposes these revisions to get a better understanding of the
reasons hazardous liquid pipeline and gas
[[Page 74268]]
transmission pipeline operators are delayed in making repairs. PHMSA
further hopes to work with the U.S. Department of Energy to analyze
whether prolonged pressure reductions have potential impact on the
Nation's energy supply. This notification will also give PHMSA better
information on:
whether permitting issues are involved in pressure
reduction;
what causes schedule delays (permitting, scheduling,
other); and
where and under what circumstances PHMSA can help expedite
permits for repairs.
(4) Formula for Reducing Operating Pressure. Section 195.452(h)(4)
requires a hazardous liquid pipeline operator to calculate a temporary
reduction in operating pressure using the formula in section 451.7 of
ASME/ANSI B31.4 when making an immediate repair. The requirement was
meant to ensure an additional safety margin is provided while an
operator makes an immediate repair. However, a recent frequently asked
question highlighted that this formula does not always apply and may
result in a calculated pressure higher than the original operating
pressure. In addition, the formula only applies to metal loss
anomalies, not to immediate repair conditions not involving metal loss.
Therefore, PHMSA proposes to correct the provision by allowing a
hazardous liquid pipeline operator to use the ASME/ANSI B31.4 formula
only if applicable. If not applicable to the anomaly, or if the formula
results in a calculated pressure higher than original operating
pressure, an operator would be allowed to use another acceptable means
to calculate a pressure reduction.
Regulatory Analyses and Notices
Executive Order 12866 and DOT Regulatory Policies and Procedures
DOT does not consider this action to be a significant regulatory
action under section 3(f) of Executive Order 12866 (58 FR 51735;
October 4, 1993). This NPRM is nonsignificant under DOT's regulatory
policies and procedures (44 FR 11034; February 26, 1979). PHMSA
prepared a Draft Regulatory Evaluation for this NPRM and placed it in
the public docket.
The proposed changes to add flexibility to scheduling continuous
assessment would create ongoing benefits and have no cost effects.
These adjustments would create positive net benefits. PHMSA believes
the proposed change to the notification requirement for pressure
reduction would create added continuing costs, with an estimated six
notifications per operator each year. However, notification
requirements have no significant cost for either operators or industry
overall. The benefits are expected to offset costs. Together, these
proposed changes to IMP regulations for hazardous liquid and gas
transmission pipelines are expected to create positive net benefits.
Regulatory Flexibility Act
Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.) PHMSA
must consider whether a rulemaking would have a significant impact on a
substantial number of small entities. The requirements proposed in this
NPRM do not apply to a substantial number of small entities. The
proposed revisions to the IMP rules will affect hazardous liquid
pipeline operators and gas transmission pipeline operators. Most
hazardous liquid pipeline operators and gas transmission pipeline
operators do not meet the Small Business Administration's small
business definition, which is either 6 million in revenue (for natural
gas pipelines under North American Industry Classification System
(NAICS) 486210) or 1,500 employees (for crude oil and refined petroleum
product pipelines under NAICS 486110 and 486910). Additionally,
notification costs per operator are about $194.50 annually. This is
less than 0.01 percent of the $6 million gross revenue. This is not a
significant burden on pipeline operators, including small businesses.
The proposed changes to add flexibility to scheduling continuous
assessment would create ongoing benefits and have no cost effects.
These modifications would create positive net benefits. The changed
notification requirements for pressure reduction would create
negligible added costs as well as benefits; however, the benefits are
expected to offset costs. Together, these proposed changes to the IMP
regulations for hazardous liquid and gas transmission pipelines are
expected to create positive net benefits to the affected industry.
Based on the cost benefit analysis and the determination that
hazardous liquid pipeline and gas transmission pipeline operators do
not generally fall into the Small Business Administration's revenue or
employee size guidelines, it is unlikely (under section 605 of the
Regulatory Flexibility Act) the proposed regulatory changes will have
any significant impact on a substantial number of small entities. PHMSA
invites comments on these assumptions.
Paperwork Reduction Act
This NPRM proposes minimal information collection requirements.
Based on information currently available to PHMSA, 74 notifications
were submitted by 26 operators over three years. Of these 74
notifications, 36 of them, or about 50 percent, were due to an
operator's inability to meet repair schedules or reduce pressure. The
proposed notification modifications will increase notification
frequency. PHMSA estimates, on average, the proposed changes will
result in six notifications per operator annually. The estimated
average time to prepare a notification request is 30 minutes.
Consequently, there should be no significant cost or hourly burden on
individual operators or the industry because of the notification
requirement in this proposal. PHMSA evaluated the NPRM, as required by
the Paperwork Reduction Act of 1995 (44 U.S.C. 3507(d)), and believes
there will be no significant paperwork burden on industry or individual
operators because of the NPRM. As required by the Paperwork Reduction
Act of 1995 (44 U.S.C. 3507(d)), PHMSA will present a separate
paperwork analysis to the Office of Management and Budget for review. A
copy of the analysis will also be entered in the docket.
Executive Order 13084
This NPRM has been analyzed under principles and criteria contained
in Executive Order 13084 (``Consultation and Coordination with Indian
Tribal Governments''). Because this NPRM does not significantly or
uniquely affect communities of Indian tribal governments and does not
impose substantial direct compliance costs, the funding and
consultation requirements of Executive Order 13084 do not apply.
Executive Order 13132
PHMSA analyzed this NPRM under principles and criteria contained in
Executive Order 13132 (Federalism). None of the proposed actions: (1)
Has substantial direct effects on States, relationships between the
National Government and the States, or distribution of power and
responsibilities among various levels of government; (2) imposes
substantial direct compliance costs on States and local governments; or
(3) preempts State law. Therefore, the consultation and funding
requirements of Executive Order 13132 (64 FR 43255; August 10, 1999) do
not apply.
Executive Order 13211
This NPRM 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 74269]]
supply, distribution, or energy use. Further, the Office of Information
and Regulatory Affairs has not designated this NPRM as a significant
energy action.
Unfunded Mandates
This NPRM does not impose unfunded mandates under the 1995 Unfunded
Mandates Reform Act. It does not result in costs of $100 million or
more to either State, local, or tribal governments, in aggregate, or to
the private sector, and is the least burdensome alternative for
achieving the NPRM objectives.
National Environmental Policy Act
PHMSA analyzed this NPRM in accordance with section 102(2)(c) of
the National Environmental Policy Act (42 U.S.C. 4332), the Council on
Environmental Quality regulations (40 CFR 1500-1508), and DOT Order
5610.1D, and has preliminarily determined this action will not
significantly affect human environment quality. The Environmental
Assessment is in the Docket.
List of Subjects in 49 CFR Parts 192 and 195
Pipeline safety, Reporting and recordkeeping requirements.
For the reasons set forth in the preamble, PHMSA proposes to amend
49 CFR parts 192 and 195 as follows:
PART 192--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE:
MINIMUM FEDERAL SAFETY STANDARDS
1. The authority citation for Part 192 continues to read as
follows:
Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110,
60113, and 60118; and 49 CFR 1.53.
2. Amend Sec. 192.933 by revising paragraphs (a) and (c) to read
as follows:
Sec. 192.933 What actions must be taken to address integrity issues?
(a) General requirements. An operator must take prompt action to
address all anomalous conditions that the operator discovers through
the integrity assessment. In addressing all conditions, an operator
must evaluate all anomalous conditions and remediate those that could
reduce a pipeline's integrity. An operator must be able to demonstrate
that the remediation of the condition will ensure that the condition is
unlikely to pose a threat to the integrity of the pipeline until the
next reassessment of the covered segment.
(1) 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. If
pressure is reduced, an operator must determine the temporary reduction
in operating pressure using ASME/ANSI B31G (ibr, see Sec. 192.7) or
AGA Pipeline Research Committee Project PR-3-805 (``RSTRENG''; ibr, see
Sec. 192.7) or reduce the operating pressure to a level not exceeding
80 percent of the level at the time the condition was discovered. (See
appendix A to this part for information on availability of
incorporation by reference information).
(i) Notice. An operator must notify PHMSA in accordance with Sec.
192.949 whenever it reduces operating pressure to make a repair under
this subpart. This will include any temporary reduction in pressure
required by this section. This notice must include the reasons for the
pressure reduction. 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.
(ii) Long-term pressure reduction. When a pressure reduction
exceeds 365 days, an operator must again notify PHMSA under Sec.
192.949 with the reasons causing the delay. 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. In addition,
an operator must provide a technical justification that the continued
pressure restriction will not jeopardize the integrity of the pipeline.
(2) [Reserved]
* * * * *
(c) Schedule for evaluation and remediation. An operator must
complete remediation of a condition according to a schedule that
prioritizes the conditions for evaluation and remediation. Unless a
special requirement for remediating certain conditions applies, as
provided in paragraph (d) of this section, an operator must follow the
schedule in ASME/ANSI B31.8S (ibr, see Sec. 192.7), section 7, Figure
4. If an operator cannot meet the schedule for any condition, the
operator must justify the reasons why it cannot meet the schedule and
that the changed schedule will not jeopardize public safety.
* * * * *
PART 195--TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE
3. The authority citation for part 195 continues to read as
follows:
Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60118;
and 49 CFR 1.53.
4. Amend Sec. 195.452 by revising paragraphs (h)(1), (h)(3),
(h)(4)(i) introductory text and the first sentence of paragraph
(j)(3) to read as follows:
Sec. 195.452 Pipeline integrity management in high consequence areas.
* * * * *
(h) * * *
(1) General requirements. An operator must take prompt action to
address all anomalous conditions that the operator discovers through
the integrity assessment or information analysis. In addressing all
conditions, an operator must evaluate all anomalous conditions and
remediate those that could reduce a pipeline's integrity. An operator
must be able to demonstrate that the remediation of the condition will
ensure that the condition is unlikely to pose a threat to the long-term
integrity of the pipeline. An operator must comply with Sec. 195.422
when making a repair.
(i) Pressure reduction. An operator must notify PHMSA in accordance
with paragraph (m) of this section whenever it reduces operating
pressure to make a repair under this section. This will include any
temporary reduction in pressure required by paragraph (h) (4) (i) of
this section. This notice must include the reasons for the pressure
reduction.
(ii) Long-term pressure reduction. When a pressure reduction
exceeds 365 days, an operator must again notify PHMSA in accordance
with paragraph (m) of this section with the reasons causing the delay.
An operator must also take further remedial action to ensure the safety
of the pipeline.
* * * * *
(3) Schedule for evaluation and remediation. An operator must
complete remediation of a condition according to a schedule that
prioritizes the conditions for evaluation and remediation. If an
operator cannot meet the schedule for any condition, the operator must
justify the reasons why it cannot meet the schedule and that the
changed schedule will not jeopardize public safety or environmental
protection.
(4) Special requirements for scheduling remediation. (i) Immediate
repair conditions. An operator's evaluation and remediation schedule
must provide for immediate repair conditions. To maintain safety, an
operator must temporarily reduce operating pressure or shut down the
[[Page 74270]]
pipeline until the operator completes the repair of these conditions.
An operator must calculate the temporary reduction in operating
pressure using the formula in section 451.7 of ASME/ANSI B31.4 (ibr,
see Sec. 195.3), if applicable. If the formula is not applicable to
the type of anomaly or the calculated pressure results in a higher
operating pressure, an operator must use an alternative acceptable
method to calculate a reduced operating pressure. An operator must
treat the following conditions as immediate repair conditions:
* * * * *
(j) * * *
(3) Assessment intervals. An operator must establish five-year
intervals, not to exceed 68 months, for continually assessing the line
pipe's integrity.* * *
* * * * *
Issued in Washington, DC, on December 12, 2005.
Stacey L. Gerard,
Associate Administrator for Pipeline Safety.
[FR Doc. 05-24061 Filed 12-12-05; 1:29 pm]
BILLING CODE 4910-60-P
