[Federal Register: April 23, 2007 (Volume 72, Number 77)]
[Rules and Regulations]
[Page 20055-20060]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr23ap07-12]
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DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials Safety Administration
49 CFR Part 192
[Docket No. PHMSA-2005-22642]
RIN 2137-AE09
Pipeline Safety: Design and Construction Standards To Reduce
Internal Corrosion in Gas Transmission Pipelines
AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA),
Department of Transportation.
ACTION: Final rule.
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SUMMARY: This final rule requires operators to use design and
construction features in new and replaced gas transmission pipelines to
reduce the risk of internal corrosion. The design and construction
features required by this rule will reduce the risk of internal
corrosion and related pipeline failures by reducing the potential for
accumulation of liquids and facilitating operation and maintenance
practices that address internal corrosion.
DATES: This final rule takes effect May 23, 2007.
FOR FURTHER INFORMATION CONTACT: Barbara Betsock by phone at (202) 366-
4361, by fax at (202) 366-4566, or by e-mail at
barbara.betsock@dot.gov.
SUPPLEMENTARY INFORMATION:
Background
We initiated this rulemaking proceeding in response to a 2003
recommendation of the National Transportation Safety Board (NTSB) and
corresponding advice of the Technical Pipeline Safety Standards
Committee (TPSSC). The NTSB recommendation arose out of its
investigation of the August 19, 2000 gas transmission pipeline
explosion near Carlsbad, New Mexico in which 12 people were killed. In
its accident investigation report, PAR-03-01, issued February 11, 2003,
the NTSB concluded that the immediate cause of the Carlsbad pipeline
failure was severe internal corrosion. The NTSB recommended that PHMSA
(1) require that new and replaced gas transmission pipelines be
designed and constructed with features to mitigate internal corrosion;
(2) require operators to ensure that their internal corrosion control
programs address water and other contaminants in the corrosion process;
and (3) change its Federal inspection to ensure adequate assessments of
pipeline operator safety programs. In 2004 and 2005, the NTSB closed as
acceptable PHMSA actions to respond to the second and third
recommendations. This rulemaking proceeding responds to the first
recommendation.
On December 15, 2005, PHMSA published a notice of proposed
rulemaking (NPRM) in the Federal Register (70 FR 74262) proposing to
require operators to use design and construction features to reduce the
risk of internal corrosion in transmission pipelines. As we explained
in the NPRM, the proposed rule was intended to prevent the risk of
internal corrosion by applying knowledge and experience about the
causes and prevention of corrosion to design of pipelines. The
incorporation of design features to address internal corrosion improves
the ability of the operator to prevent internal corrosion and
facilitates maintenance activities to control internal corrosion.
The basic requirements of this final rule are similar to those
proposed in the NPRM. New and replaced gas transmission pipelines must
be configured to reduce the risk that liquids will collect in the line;
have effective liquid removal features; and allow use of corrosion
monitoring devices in locations with significant potential for internal
corrosion. When an operator changes the configuration of a pipeline,
the operator must consider and address the impact the changes will have
on the risk of internal corrosion in an existing downstream pipeline.
This final rule does not supersede or negate the requirement to address
internal corrosion during operation and maintenance activities.
Designing and building a pipeline in accordance with the final rule
will not prevent internal corrosion unless the operator also follows a
well-planned maintenance program. For example, incorporating equipment
to measure gas quality will not prevent internal corrosion unless it is
used and the operator acts on the results.
Advisory Committee Consideration
PHMSA briefed the TPSSC in June 2005 and considered the Committee's
advice in developing the NPRM. PHMSA presented the NPRM and regulatory
evaluation to the TPSSC for formal consideration at their meeting on
June 28, 2006. At that meeting, members expressed concern that the
proposed documentation requirements were burdensome. TPSSC members
asked for information about whether PHMSA intended to require detailed
documentation of every action taken during design and construction;
what alternatives commenters suggested; and how the NTSB reached its
recommendation. PHMSA provided additional information in the form of a
concept paper on the documentation needed for compliance, an expanded
summary of comments, and excerpts from the NTSB report on the Carlsbad
incident. PHMSA briefed the TPSSC at a meeting on August 26, 2006 and
outlined changes we intended to make in response to comments. A few
members expressed individual concerns about particular issues. These
concerns are addressed in the remainder of this preamble. The TPSSC
voted unanimously to support the NPRM as technically feasible,
reasonable, cost-effective and practicable, provided the final rule
included the changes PHMSA outlined at the meeting. In addition, the
TPSSC advised PHMSA to hold discussions in an open forum on enforcement
criteria, including protocol development and recordkeeping. The final
rule is consistent with the discussion at the TPSSC meeting. In
accordance with the TPSSC's advice, PHMSA intends to convene an open
forum soon after the final rule is issued.
Comments on the NPRM
PHMSA received public comments on the NPRM from 18 commenters, 13
of them operators of gas transmission pipelines. The Gas Piping
Technology Committee, Interstate Natural Gas Association of America,
American Gas Association, the Texas Pipeline Association, and the Iowa
Utilities Board also commented. Commenters agreed with the basic
concept of the proposal--addressing internal corrosion risks during
design and construction. Most commenters viewed the documentation
requirements of the proposed rule as burdensome. Some expressed
confusion about what an operator would have to do to comply. As an
example, some questioned
[[Page 20056]]
whether the proposed rule would require an operator to conduct an
engineering analysis to justify variations in elevation due to
following the contours of the land. PHMSA has revised the rule text to
clarify the final rule and refine the documentation requirements to
ensure compliance without excessive burden. We discuss the major
comments and how we are addressing them more specifically in the
following paragraphs.
Redundancy
Some commenters contend existing regulations in 49 CFR part 192
make this rulemaking redundant and unnecessary. These commenters point
to regulations requiring operators to design new pipeline to allow the
use of instrumented internal inspection devices (Sec. 192.150); to
check for internal corrosion when pipe is removed (Sec. 192.475); to
maintain continuing surveillance (Sec. 192.613); and to develop
integrity management programs addressing internal corrosion (subpart
O). However, none of the regulations cited by commenters squarely
addresses the goals of this rulemaking and the NTSB recommendation.
The purpose of Sec. 192.150 is to allow internal inspection to
address a variety of pipeline risks. Section 192.150 incidentally aids
internal corrosion control because a pipeline designed to allow
internal inspection can also accommodate cleaning pigs. Cleaning pigs
remove liquids and contaminants from a pipeline as part of corrosion
control. In its report on the 2000 Carlsbad incident, the NTSB
recognized the value of cleaning pigs and their limitations in
addressing the internal corrosion issues in the Carlsbad incident.\1\
The NTSB recommended additional regulation to require design features
focused on internal corrosion. In addition, unlike this final rule,
Sec. 192.150 does not apply to gathering lines.
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\1\ From NTSB report PAR 03-01:
The Safety Board concludes that, as a likely result of the
partial clogging of the drip upstream of the rupture location, some
liquids bypassed the drip, continued through the pipeline, and
accumulated and caused corrosion at the eventual rupture site where
pipe bending had created a low point in the pipeline.
Periodic use of cleaning pigs can remove water and other liquid
and solid contaminants from a pipeline. One of the considerations
for the design and construction of a cleaning pig system is to make
provisions for effective collection and removal of the accumulated
materials from the pipeline after pigging [* * *]
[* * *] The Safety Board therefore concludes that if the
accident section of pipeline 1103 had been able to accommodate
cleaning pigs, and if cleaning pigs had been used regularly with the
resulting liquids and solids thoroughly removed from the pipeline
after each pig run, the internal corrosion that developed in this
section of pipe would likely have been less severe.
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The regulations requiring an operator to check line pipe removed
from a pipeline for signs of internal corrosion (Sec. 192.475) and to
maintain continuing surveillance (Sec. 192.613) are not design
requirements. These regulations are among those operation and
maintenance regulations requiring operators to monitor their pipelines
and collect and analyze information about safety risks. But these
practices usually only enable operators to detect signs of corrosion.
The actions recommended by the NTSB and addressed in this final rule
reduce the risk that internal corrosion will even initiate by designing
and constructing pipelines to reduce that risk in the first place.
Requiring operators to design their systems to reduce the risk of
internal corrosion neither duplicates nor obviates the need to detect
and monitor internal corrosion.
Some commenters said the proposed rule did not take into account
the internal corrosion management plans required by the integrity
management regulations (subpart O). In fact, we believe that the final
rule will complement the existing requirements under subpart O. Subpart
O applies only to pipelines in high consequence areas (HCAs). In those
areas, it supplements the safety protection provided by the minimum
standards. This final rule sets a minimum standard for design and
construction applicable to all onshore pipelines, regardless of
location. For pipeline in an HCA, compliance with the new standard will
facilitate addressing the risk of internal corrosion under an integrity
management program. For example, Sec. 192.927(c)(4) requires an
operator to continually monitor covered segments where internal
corrosion has been identified. A segment constructed in accordance with
this final rule will have liquid removal features and allow the use of
appropriate monitoring devices.
Exceptions Based on What the Operator Expects To Occur During
Operations
Many commenters requested an exception to the design and
construction requirements if the operator believes liquids will not
pose a problem in the line. Commenters suggested several variations.
Some commenters suggested that we establish an exception applicable if
the operator confirms liquids will not present an uncontrolled threat
(presumably because of planned corrosion control activities). Others
suggested requiring design and construction features only where
corrosive gas is transported. Others pointed to areas without a history
of internal corrosion and suggested that the rule should not apply to
pipelines installed in these areas.
PHMSA does not agree with the suggestions of these commenters and,
accordingly, is not establishing exceptions to design and construction
requirements based on expected operations. An operator needs to include
internal corrosion control measures in operation and maintenance
programs. Relying on these operation and maintenance programs alone to
control internal corrosion misses the safety and economic benefit from
good design. Building features to reduce the risk of corrosion into new
pipelines costs little and provides additional and fuller protection
against internal corrosion. Even where operators do not expect to have
liquids enter the pipeline, one commenter noted that an operator cannot
rule out upset conditions which can result in the introduction of
liquids. These can occur when there is an operational error; tertiary
recovery introduces liquids; gas comes from a new or different area of
the same field; gas from a different operator joins the gas stream;
equipment fails; or other causes. The increased risk of internal
corrosion such a situation causes, albeit possibly small, justifies the
minimal incremental cost of incorporating the measures required in the
final rule. However, in the interest of cost effectiveness, PHMSA
agrees with the need to provide operators flexibility to select design
and construction options fitting the relative risks that there will be
liquids in the pipeline in the future.
Exceptions for Particular Types of Facilities
A few commenters requested that PHMSA carve out exceptions to the
final rule for particular types of pipeline facilities. We address
these comments in the following paragraphs, by reference to the
particular pipeline facilities in issue.
Offshore pipelines. The Interstate Natural Gas Association of
America and one large gas transmission operator requested that PHMSA
carve out an exception for offshore lines. Among the reasons given were
the lower risk to public safety in the offshore environment and the
impossibility of engineering out the effects of dips and low spots
offshore. PHMSA agrees that offshore lines should be excepted from the
final rule.
Although there have been serious gas incidents offshore, these have
been caused by outside force damage sufficient to rupture the pipeline,
such as an anchor dragging or vessel
[[Page 20057]]
grounding. This sort of damage includes sources of ignition from
vessels passing overhead. In contrast, a corrosion leak in an offshore
gas pipeline poses less risk to people. Unless corrosion is widespread,
a corrosion failure is likely to leak rather than rupture and is not
likely to pose a threat to people. It is highly unlikely that a vessel
would pass over the underwater pipeline at the moment of rupture and
provide both a source of ignition triggering a fire and people to be
killed or injured. Between 2000 and 2005, there were more than twice as
many internal corrosion incidents offshore as onshore, but less damage,
even though damage includes the cost of lost gas and repair to the
underwater pipeline. There have been no injuries or fatalities.\2\
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\2\ The only fire was almost instantaneously extinguished by the
water.
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Finally, as noted by the commenters, there are more limited design
and construction options available for offshore pipelines. Pipelines
commonly follow the contours of the seabed with its natural low points.
Installing and operating liquid removal equipment is not possible at
low points in deep water. Some new pipelines are being installed in
water more than one mile deep, complicating the under water pipeline
design process. Control of liquids in the gas stream is already a
critical factor in deep water pipeline construction and operation.
Moreover, adopting this exception will not leave offshore pipelines
unprotected or allow an operator to ignore the risk of internal
corrosion. Existing regulations in subparts I and L require operators
of offshore pipelines to address internal corrosion during operation
and maintenance.
Gathering lines. The only regulated gas gathering lines are those
in populated areas, where the risk of injury or property damage in the
event of failure is greatest. By their very nature, gathering lines
regularly transport gas containing liquids--a combination known to
cause corrosion over time. Approximately a third of onshore incidents
caused by internal corrosion involve gathering lines.\3\ None of the
commenters challenged these basic facts. PHMSA does not except
gathering lines from this final rule.
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\3\ Based on data reported for incidents occurring between 2000
and 2005.
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At least one commenter suggested that gathering lines were not
within the scope of the NPRM in this rulemaking. That is not the case.
When PHMSA issued the NPRM in December 2005, gas gathering lines in
non-rural areas were subject to the same regulations applicable to
transmission pipelines (49 CFR 192.9 (2005)). The only exceptions were
the requirement that new pipelines accommodate internal inspection
devices (Sec. 192.150) and integrity management regulations (subpart
O). PHMSA published a Supplemental Notice of Proposed Rulemaking
(SNPRM) proposing changes to regulation of gathering lines on October
3, 2005 (70 FR 57536). The SNPRM on gathering lines proposed to
continue to subject gathering lines to most regulations applicable to
transmission pipelines, including both corrosion control and design and
construction requirements. The final rule on gathering lines continued
to subject gathering lines to corrosion control and design and
construction requirements such as this final rule (71 FR 13289; March
15, 2006).
Compressor stations. PHMSA is not persuaded that the final rule
should except compressor stations. The commenter suggesting an
exception did not offer a reason, and we cannot discern one.
Compressors do not operate well when liquids are present in the gas
flow. Actions to remove liquid before it enters the compressor may
result in liquid accumulation in the compressor station piping. About
forty percent of the damage caused by internal corrosion onshore
incidents between 2000 and 2005 was due to incidents at compressor
stations. People work in compressor stations. They also live near
compressor stations, particularly in suburban locations in which there
has been significant development since the transmission pipelines were
constructed.
Placement Within 49 CFR Part 192
Several commenters suggest subpart I--Requirements for Corrosion
Control--is the wrong place for a rule addressing internal corrosion
control in design and construction. Commenters cite two reasons for
their position. First, the regulations in subpart I primarily address
operation and maintenance requirements. These requirements apply to
pipelines existing when the regulations are issued. Design and
construction requirements, such as those in the final rule, apply only
to new and replaced pipelines. The commenters suggest PHMSA place these
requirements applicable only to new and replaced pipelines in one of
the subparts of 49 CFR part 192 which contain no requirements
applicable to existing pipelines. Second, some commenters suggest that
operators designing and constructing pipelines might overlook design
and construction requirements placed in subpart I. Commenters who
addressed the issue were not uniform in their suggestions for alternate
placement within Part 192. They suggest placement in subpart C--Pipe
Design, subpart D--Design of Pipeline Components, or subpart G--General
Construction Requirements for Transmission Lines and Mains.
Some regulations in subpart I already include design and
construction requirements, such as requirements for pipe coating. PHMSA
believes consolidating corrosion control requirements strengthens the
planning aspects of this regulation. To address commenters' concerns,
PHMSA has reworded the final rule to be consistent with other design
and construction requirements in the regulations. We have also added an
applicability date to the final rule clearly indicating the non-
retroactive effect of the design and construction requirements.
Finally, the final rule cross references subpart I in subpart D to
alert those designing pipelines of the need to consult corrosion
control requirements.
Recordkeeping
Many commenters and the TPSSC expressed concern about the
recordkeeping provision proposed in the NPRM, contending it would be
costly, difficult to adhere to, and burdensome. PHMSA agrees. Operators
normally maintain as-built drawings and other construction records.
These records may already contain adequate explanation of variances. If
not, some additional explanation will be necessary. We have modified
the final rule to require maintenance of records demonstrating
compliance.
Changes Affecting Downstream Pipeline
Few commenters discussed the proposal to require an operator to
address the effect changes to an existing pipeline would have on the
risk of internal corrosion in the downstream portions of the pipeline.
The Texas Pipeline Association noted that the proposal matched what
prudent operators already do and that the proposed standard was
appropriate. Another commenter noted the proposed language might be too
restrictive because it would require an operator to use equipment to
address the effects. One member of the TPSSC noted that the proposal
would apply to any change to the pipeline and suggested clarifying the
regulation to apply only to changes affecting configuration. We have
made changes to the final rule to limit applicability to changes that
have the potential for affecting downstream risk. The final rule allows
operator flexibility in addressing the risks.
[[Page 20058]]
Changes Due To Uprating
Existing pipeline safety regulations (Sec. 192.555 and Sec.
192.557) allow an operator to increase maximum allowable operating
pressure of a gas pipeline through a process called uprating. Uprating
results in operation at an increased hoop stress. A pipeline operating
at a hoop stress of 20 percent or more of the specified minimum yield
strength is considered a transmission pipeline by definition regardless
of its function (Sec. 192.3). Thus, uprating a distribution line may
result in its classification as a transmission line. A member of the
TPSSC asked whether such a change would result in the line being
considered a new transmission line subject to the design and
construction requirements of this final rule. The answer is no. The
uprated line is not newly constructed. However, to the extent an
operator makes replacements in the line in connection with uprating to
meet the requirements of Sec. 192.555(b)(2) or Sec. 192.557(b)(3),
the replacements must be designed and constructed in accordance with
this final rule. In addition, the operator would have to consider the
effect of the replacement on internal corrosion risk to the downstream
portion of the pipeline.
Terminology
The proposed rule allows an operator to deviate from specific
aspects of design and construction if the operator can demonstrate that
compliance is ``impracticable'' or ``unnecessary.'' Some commenters
said that the terms are too subjective and will result in disputes over
the appropriateness of an operator's actions. They suggest
clarification through examples. We do not agree that further
clarification is required at this time. The terms ``impracticable'' and
``unnecessary'' are used elsewhere in regulation. As long as an
operator makes a reasonable effort to address internal corrosion in
design and construction, the potential for disagreement is slight. At
the request of the TPSSC, PHMSA intends to conduct a public workshop on
implementation of this regulation. Part of the workshop could be
devoted to developing examples of situations in which regulators and
industry agree that compliance with the final rule would be
presumptively impracticable or unnecessary.
The Final Rule
The final rule adds a new subsection to Sec. 192.143 in Subpart
D--Design of Pipeline Components. The new subsection cross-references
the design and installation requirements specifically addressing
corrosion control in Subpart I--Requirements for Corrosion Control.
The final rule also adds a new section to subpart I. The new
section, Sec. 192.476, requires an operator to address internal
corrosion risk when designing and constructing a new gas transmission
line or when replacing line pipe or components in a transmission line.
Paragraph (a) addresses design and construction. It imposes a
general performance requirement--that the design and construction of
new and replaced pipelines include features to reduce the risk of
internal corrosion. More specifically, the rule identifies three
categories of corrosion control features that an operator must provide
for unless doing so is impracticable or unnecessary: (1) Configuration
to reduce the risk that liquids will collect in the line (paragraph
(a)(1)); (2) effective liquid removal features (paragraph (a)(2)); and
(3) ability to use corrosion monitoring devices in locations with
significant potential for internal corrosion (paragraph (a)(3)).
There are many design features that an operator can incorporate to
address the requirements of paragraph (a). These include the following:
An operator can minimize dead ends and low areas;
An operator can minimize aerial crossings, since these can
result in variation of temperature;
An operator can design for turbulent flow, in which the
velocity at a given point varies erratically in magnitude and
direction, to decrease the chance of liquids separating from the flow
and accumulating;
An operator can design a pipeline to minimize entry of
water and corrosive gases at receipt locations;
When corrosive gas is expected, an operator can provide
slam valves to isolate systems;
An operator can apply coatings to interior walls to
inhibit internal corrosion;
An operator can identify critical low spots and instrument
the pipeline to monitor relevant operating conditions (temperature,
pressure, velocity, dew point);
An operator can evaluate seasonal nature of delivery and
capacity patterns and design to avoid no-or low-flow conditions;
An operator can include equipment to evaluate gas
characteristics; and
An operator can include equipment to allow sampling at key
areas, such as pig traps, isolated sections with no flow, dead ends,
and river and road crossings.
Further, design should allow the use of cleaning pigs.\4\
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\4\ Section 192.150 requires an operator to design most new and
replaced transmission pipeline to allow the use of instrumented
internal inspection devices. The exceptions to Sec. 192.150 include
certain lower risk gathering lines and lines too small in diameter
to accommodate instrumented internal inspection devices. Although
neither Sec. 192.150 nor this final rule expressly requires
designing to allow the use of cleaning pigs, it is much easier to
accommodate cleaning pigs than instrumented internal inspection
devices.
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Paragraph (b) provides exceptions to applicability. The design and
construction requirements do not apply to pipeline installed or
replacements made before the effective date of the regulation. They
also do not apply to offshore pipelines.
Paragraph (c) requires an operator to consider and address the
impact of changes in the physical features of a pipeline on internal
corrosion risks of an existing downstream pipeline. This will ensure
that changes in configuration made after a pipeline begins operation do
not inadvertently increase the risk of internal corrosion. An operator
who finds an increased risk due to changes upstream might need to
install liquid removal equipment. Alternatively, after analysis, an
operator may decide operation and maintenance measures would adequately
address the impact. In its investigation of the Carlsbad accident, the
NTSB noted the impact of the addition of a pig receiver many years
after original construction.\5\ This change in configuration allowed
the liquids from pigging which were not caught in the receiver to flow
downstream supposedly to be caught in the drip installed at the time of
original construction to capture liquids before the low points near the
river. The NTSB report notes that the pig receiver was added without
also installing a separate storage leg or tank to collect the liquids
from pigging. The NTSB also notes that partial clogging of the original
drip, a maintenance issue, allowed liquids to bypass the drip and
collect at the eventual rupture site.
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\5\ NTSB Report PAR 03-01, pages 41-42.
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Paragraph (d) requires an operator to maintain records
demonstrating compliance. Written procedures supported by as-built
drawings and other construction records ordinarily will satisfy this
requirement. However, these records must adequately show why an action
described in paragraph (a)(1), (a)(2), or (a)(3) is impracticable or
unnecessary. For example, an operator might have a written design
allowing pipe to be laid following the contour of the land. To avoid
accumulation of liquid in the low spots, the design procedure might
call for incorporating
[[Page 20059]]
design features to maintain gas velocity or to remove liquids. The
actual construction records or as-built drawings would show what the
operator actually did. Another example might be a construction record
showing the use of a filter or separator at the gate station of a
distribution pipeline. Regardless of the choices in recordkeeping an
operator makes, the records must show circumstances justifying variance
based on impracticability or lack of necessity. For example, if an
operator does not provide features for effective liquid removal at low
spots, the records must show why it is not necessary to do so.
Regulatory Analyses and Notices
Privacy Act Statement
Anyone can search the electronic form of all comments received in
response to any of our dockets by the name of the individual submitting
the comment (or signing the comment, if submitted on behalf of an
association, business, labor union, etc.). The Department of
Transportation's complete Privacy Act Statement is published in the
Federal Register on April 11, 2000 (65 FR 19477), and on the Web at
http://dms.dot.gov.
Executive Order 12866 and DOT Policies and Procedures
This final rule is not a significant regulatory action under
section 3(f) of Executive Order 12866 (58 FR 51735) and, therefore, was
not subject to review by the Office of Management and Budget. This
final rule is not significant under the Regulatory Policies and
Procedures of the Department of Transportation (44 FR 11034).
Commenters pointed to discrepancies in the incident data used for
the regulatory evaluation. Those discrepancies have been corrected in
the regulatory evaluation for this final rule. One member of the TPSSC
questioned whether the analysis included consideration of
uncertainties. We have considered the comment and decided that our
analysis adequately handles uncertainty in benefits and costs.
Regulatory Flexibility Act
Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.), PHMSA
must consider whether rulemaking actions would have a significant
economic impact on a substantial number of small entities. This final
rule would affect operators of gas transmission pipelines and onshore
gas gathering pipelines. The number of small entities operating gas
transmission pipelines is not substantial and the cost of compliance
with the final rule is small. Therefore, I certify, under 5 U.S.C. 605,
that this rulemaking will not have a significant impact on a
substantial number of small entities.
Executive Order 13175
PHMSA has analyzed this final rule according to Executive Order
13175, ``Consultation and Coordination with Indian Tribal
Governments.'' Because the final rule will not significantly or
uniquely affect the communities of the Indian tribal governments nor
impose substantial direct compliance costs, the funding and
consultation requirements of Executive Order 13175 do not apply.
Paperwork Reduction Act
This final rule affects information collection that the Office of
Management and Budget has approved under Control Number 2137-0049
(recordkeeping under 49 CFR part 192). Operators of gas transmission
pipelines must keep records to show the adequacy of corrosion control
measures. In addition, they must keep construction records and make
them available to individuals operating and maintaining the pipeline.
The final rule may require some added effort to document decisions
about internal corrosion made during design and construction. Because
of existing recordkeeping needs and prudent business practice, PHMSA
estimates the added burden hours will be nominal.
Unfunded Mandates Reform Act of 1995
This final rule does not impose unfunded mandates under the
Unfunded Mandates Reform Act of 1995. It does not result in costs of
$100 million or more to either State, local, or tribal governments, in
the aggregate, or to the private sector, and is the least burdensome
alternative that achieves the objective of the rulemaking.
National Environmental Policy Act
PHMSA has analyzed the final rule for purposes of the National
Environmental Policy Act (42 U.S.C. 4321 et seq.). Because the final
rule requires limited physical change or other work that would disturb
pipeline rights-of-way, PHMSA has determined the final rule is unlikely
to affect the quality of the human environment significantly. An
environmental assessment document is available for review in the
docket.
Executive Order 13132
PHMSA has analyzed the final rule according to Executive Order
13132 (``Federalism''). The final 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. The final rule
does not impose substantial direct compliance costs on State and local
governments. Federal pipeline safety law prohibits State safety
regulation of interstate pipelines. This regulation would not preempt
state law for intrastate pipelines. Therefore, the consultation and
funding requirements of Executive Order 13132 do not apply.
Executive Order 13211
Transporting gas impacts the nation's available energy supply.
However, this final rule is not a ``significant energy action'' under
Executive Order 13211. It also is not a significant regulatory action
under Executive Order 12866 and is not likely to have a significant
adverse effect on the supply, distribution, or use of energy. Further,
the Administrator of the Office of Information and Regulatory Affairs
has not identified this final rule as a significant energy action.
List of Subjects in 49 CFR Part 192
Design and construction, Internal corrosion, Pipeline safety.
0
For the reasons provided in the preamble, PHMSA amends 49 CFR part 192
as follows:
PART 192--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE:
MINIMUM FEDERAL SAFETY STANDARDS
0
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.
0
2. Amend Sec. 192.143 by designating existing text as paragraph (a)
and adding a new paragraph (b) to read as follows:
Sec. 192.143 General requirements.
* * * * *
(b) The design and installation of pipeline components and
facilities must meet applicable requirements for corrosion control
found in subpart I of this part.
0
3. Add Sec. 192.476 to read as follows:
Sec. 192.476 Internal corrosion control: Design and construction of
transmission line.
(a) Design and construction. Except as provided in paragraph (b) of
this section, each new transmission line and each replacement of line
pipe, valve, fitting, or other line component in a transmission line
must have features incorporated into its design and construction to
reduce the risk of
[[Page 20060]]
internal corrosion. At a minimum, unless it is impracticable or
unnecessary to do so, each new transmission line or replacement of line
pipe, valve, fitting, or other line component in a transmission line
must:
(1) Be configured to reduce the risk that liquids will collect in
the line;
(2) Have effective liquid removal features whenever the
configuration would allow liquids to collect; and
(3) Allow use of devices for monitoring internal corrosion at
locations with significant potential for internal corrosion.
(b) Exceptions to applicability. The design and construction
requirements of paragraph (a) of this section do not apply to the
following:
(1) Offshore pipeline; and
(2) Pipeline installed or line pipe, valve, fitting or other line
component replaced before May 23, 2007.
(c) Change to existing transmission line. When an operator changes
the configuration of a transmission line, the operator must evaluate
the impact of the change on internal corrosion risk to the downstream
portion of an existing onshore transmission line and provide for
removal of liquids and monitoring of internal corrosion as appropriate.
(d) Records. An operator must maintain records demonstrating
compliance with this section. Provided the records show why
incorporating design features addressing paragraph (a)(1), (a)(2), or
(a)(3) of this section is impracticable or unnecessary, an operator may
fulfill this requirement through written procedures supported by as-
built drawings or other construction records.
Issued in Washington, DC on April 16, 2007.
Thomas J. Barrett,
Administrator.
[FR Doc. E7-7701 Filed 4-20-07; 8:45 am]
BILLING CODE 4910-60-P