[Federal Register: October 17, 2008 (Volume 73, Number 202)]
[Rules and Regulations]
[Page 62147-62181]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr17oc08-16]
[[Page 62147]]
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Part V
Department of Transportation
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Pipeline and Hazardous Materials Safety Administration
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49 CFR Part 192
Pipeline Safety: Standards for Increasing the Maximum Allowable
Operating Pressure for Gas Transmission Pipelines; Final Rule
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DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials Safety Administration
49 CFR Part 192
[Docket No. PHMSA-2005-23447]
RIN 2137-AE25
Pipeline Safety: Standards for Increasing the Maximum Allowable
Operating Pressure for Gas Transmission Pipelines
AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA),
Department of Transportation (DOT).
ACTION: Final rule.
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SUMMARY: PHMSA is amending the pipeline safety regulations to prescribe
safety requirements for the operation of certain gas transmission
pipelines at pressures based on higher operating stress levels. The
result is an increase of maximum allowable operating pressure (MAOP)
over that currently allowed in the regulations. Improvements in
pipeline technology assessment methodology, maintenance practices, and
management processes over the past twenty-five years have significantly
reduced the risk of failure in pipelines and necessitate updating the
standards that govern the MAOP. This rule will generate significant
public benefits by reducing the number and consequences of potential
incidents and boosting the potential capacity and efficiency of
pipeline infrastructure, while promoting rigorous life-cycle
maintenance and investment in improved pipe technology.
DATES: Effective Date: This final rule takes effect November 17, 2008.
Incorporation by Reference Date: The incorporation by reference of
a certain publication listed in this rule is approved by the Director
of the Federal Register as of November 17, 2008.
FOR FURTHER INFORMATION CONTACT: Alan Mayberry by phone at (202) 366-
5124, or by e-mail at alan.mayberry@dot.gov.
SUPPLEMENTARY INFORMATION:
Table of Contents
A. Purpose of the Rulemaking
B. Background
B.1. Current Regulations
B.2. Evolution in Views on Pressure
B.3. History of PHMSA Consideration
B.4. Safety Conditions in Special Permits
B.5. Codifying the Special Permit Standards
B.6. How to Handle Special Permits and Requests for Special
Permits
B.7. Statutory Considerations
C. Comments on the NPRM
C.1. General Comments
C.2. Comments on Specific Provisions in the Proposed Rule
C.2.1. Section 192.7, Incorporation by Reference
C.2.2. Design Requirements
C.2.3. Construction Requirements
C.2.4. Eligibility for and Implementing Alternative MAOP
C.2.5. Operation and Maintenance Requirements
C.3. Comments on Regulatory Analysis
D. Consideration by the Technical Pipeline Safety Standards
Committee
E. The Final Rule
E.1. In General
E.2. Amendment to Sec. 192.7--Incorporation by Reference
E.3. New Sec. 192.112--Additional Design Requirements
E.4. New Sec. 192.328--Additional Construction Requirements
E.5. Amendment to Sec. 192.611--Change in Class Location:
Confirmation or Revision of Maximum Operating Pressure
E.6. Amendment to Sec. 192.619--Maximum Allowable Operating
Pressure
E.7. New Sec. 192.620--Operation at an Alternative MAOP
E.7.1. Sec. 192.620(a)--Calculating the Alternative MAOP
E.7.2. Sec. 192.620(b)--Which Pipelines Qualify
E.7.3. Sec. Sec. 192.620(c)(1), (2), and (3)--How an Operator
Selects Operation Under This Section
E.7.4. Sec. 192.620(c)(4)--Initial Strength Testing
E.7.5. Sec. 192.620(c)(5)--Operation and Maintenance
E.7.6. Sec. 192.620(c)(6)--New Construction and Maintenance
Tasks
E.7.7. Sec. 192.620(c)(7)--Recordkeeping
E.7.8. Sec. 192.620(c)(8)--Class Upgrades
E.8. Sec. 192.620(d)--Additional Operation and Maintenance
Requirements
E.8.1. Sec. 192.620(d)(1)--Threat Assessments
E.8.2. Sec. 192.620(d)(1)--Public Awareness
E.8.3. Sec. 192.620(d)(2)--Emergency Response
E.8.4. Sec. 192.620(d)(3)--Damage Prevention
E.8.5. Sec. 192.620(d)(4)--Internal Corrosion Control
E.8.6. Sec. Sec. 192.620(d)(5), (6), and (7)--External
Corrosion Control
E.8.7. Sec. Sec. 192.620(d)(8) and (9)--Integrity Assessments
E.8.8. Sec. 192.620(d)(10)--Repair Criteria
E.9. Sec. 192.620(e)--Overpressure Protection--Proposed Sec.
192.620(e)
F. Regulatory Analyses and Notices
F.1. Privacy Act Statement
F.2. Executive Order 12866 and DOT Policies and Procedures
F.3. Regulatory Flexibility Act
F.4. Executive Order 13175
F.5. Paperwork Reduction Act
F.6. Unfunded Mandates Reform Act of 1995
F.7. National Environmental Policy Act
F.8. Executive Order 13132
F.9. Executive Order 13211
A. Purpose of the Rulemaking
PHMSA published a Notice of Proposed Rulemaking (NPRM) on March 12,
2008 (73 FR 13167), to establish standards under which certain natural
or other gas (gas) transmission pipelines would be allowed to operate
at higher maximum allowable operating pressure (MAOP). The proposed
changes were made possible by dramatic improvements in pipeline
technology and risk controls over the past 25 years. The current
standards for calculating MAOP on gas transmission pipelines were
adopted in 1970, in the original pipeline safety regulations
promulgated under Federal law. Almost all risk controls on gas
transmission pipelines have been strengthened in the intervening years,
beginning with the introduction of improved manufacturing, metallurgy,
testing, and assessment tools and standards. Pipe manufactured and
tested to modern standards is far less likely to contain defects that
can grow to failure over time than pipe manufactured and installed a
generation ago. Likewise, modern maintenance practices, if consistently
followed, significantly reduce the risk that corrosion, or other
defects affecting pipeline integrity, will develop in installed
pipelines. Most recently, operators' development and implementation of
integrity management programs have increased understanding about the
condition of pipelines and how to reduce pipeline risks. In view of
these developments, PHMSA concludes that certain gas transmission
pipelines can be safely and reliably operated at pressures above
current Federal pipeline safety design limits. With appropriate
conditions and controls, permitting operation at higher pressures will
increase energy capacity and efficiency without diminishing system
safety.
Currently, PHMSA has granted special permits on a case-by-case
basis to allow operation of particular pipeline segments at a higher
MAOP than currently allowed under the existing design requirements.
These special permits, that have been granted, have been limited to
operation in Class 1, 2, and 3 locations and conditioned on
demonstrated rigor in the pipeline's design and construction and the
operator's performance of additional safety measures. Building on the
record of success developed in the special permit proceedings, PHMSA is
codifying the conditions and limitations of the special permits into
standards of general applicability.
B. Background
B.1. Current Regulations
The design factor specified in Sec. 192.105 restricts the MAOP of
a steel
[[Page 62149]]
gas transmission pipeline based on stress levels and class location.
For most steel pipelines, the MAOP is defined in Sec. 192.619 based on
design pressure calculated using a formula, found at Sec. 192.111,
which includes the design factor. The regulations establish four
classifications based on population density, ranging from Class 1
(undeveloped, rural land) through Class 4 (densely populated urban
areas). In sparsely populated Class 1 locations, the design factor
specified in Sec. 192.105 restricts the stress level at which a
pipeline can be operated to 72 percent of the specified minimum yield
strength (SMYS) of the steel. The operating pressures in more populated
Class 2 and Class 3 locations are limited to 60 and 50 percent of SMYS,
respectively. Paragraph (c) of Sec. 192.619 provides an exception to
this calculation of MAOP for pipelines built before the issuance of the
Federal pipeline safety standards. A pipeline that is ``grandfathered''
under this section may be operated at a stress level exceeding 72
percent of SMYS if it was operated at that pressure for five years
prior to July 1, 1970.
Part 192 also prescribes safety standards for designing,
constructing, operating, and maintaining steel pipelines used to
transport gas. Although these standards have always included several
requirements for initial and periodic testing and inspection, prior to
2003, part 192 contained no Federal requirements for internal
inspection of existing pipelines. Internal inspection is performed
using a tool known as an ``instrumented pig'' (or ``smart pig''). Many
pipelines constructed before the advent of this technology cannot
accommodate an instrumented pig and, accordingly, cannot be inspected
internally. Beginning in 1994, PHMSA required operators to design new
pipelines so that they could accommodate instrumented pigs, paving the
way for internal inspection (59 FR 17281; Apr. 12, 1994).
In December 2003, PHMSA adopted its gas transmission integrity
management rule, requiring operators to develop and implement plans to
extend additional protections, including internal inspection, to
pipelines located in ``high consequence areas'' (HCAs) (68 FR 69816).
Integrity management programs, as required by subpart O of part 192,
include threat assessments, both baseline and periodic internal
inspection, pressure testing, or direct assessment (DA), and additional
measures designed to prevent and mitigate pipeline failures and their
consequences. AN HCA, as defined in Sec. 192.903, is a geographic
territory in which, by virtue of its population density and proximity
to a pipeline, a pipeline failure would pose a higher risk to people.
In addition to class location, one of the criteria for identifying an
HCA is a potential impact circle surrounding a pipeline. The
calculation of the circle includes a factor for the MAOP, with the
result that a higher MAOP results in a larger impact circle.
B.2. Evolution in Views on Pressure
Absent any defects, and with proper maintenance and management
practices, steel pipe can last for many decades in gas service.
However, the manufacture of the steel or rolling of the pipe can
introduce flaws. In addition, during construction, improper backfilling
can damage the pipe and pipe coating. Over time, damaged coating
unchecked can allow corrosion to continue and cause leaks. Excavation-
related damage can produce an immediate pipeline failure or leave a
dent or coating damage that could grow to failure over time.
The regulations on MAOP in part 192 have their origin in
engineering standards developed in the 1950s, when industry had
relatively limited information about the material properties of pipe
and limited ability to evaluate a pipeline's integrity during its
operating lifetime. Early pipeline codes allowed maximum operating
pressures to be set at a fixed amount under the pressure of the initial
strength test without regard to SMYS. Pipeline engineers developing
consensus standards looked for ways to lengthen the time before defects
initiated during manufacture, construction, or operation could grow to
failure. Their solutions focused on tests done at the mill to evaluate
the ability of the pipe to contain pressure during operation. They
added an additional factor to the hydrostatic test pressure of the mill
test. At the time during the 1950's, the consensus standard, known as
the B31.8 Code, used this conservative margin of safety for gas pipe
design. A 25 percent margin of safety translated into a design factor
limiting stress level to 72 percent of SMYS in rural areas.
Specifically, the MAOP of 72 percent of SMYS comes from dividing the
typical maximum mill test pressure of 90 percent of SMYS by 1.25. When
issuing the first Federal pipeline safety regulations in 1970,
regulators incorporated this design factor, as found in the 1968
edition of the B31.8 Code, into the requirements for determining the
MAOP.
Even as the Federal regulations were being developed, some
technical support existed for operation at a higher stress level,
provided initial strength testing resulted in operators removing
defects. In 1968, the American Gas Association published Report No.
L30050 entitled Study of Feasibility of Basing Natural Gas Pipeline
Operating Pressure on Hydrostatic Test Pressure prepared by the
Battelle Memorial Institute. The research study concluded that:
It is inherently safer to base the MAOP on the test
pressure, which demonstrates the actual in-place yield strength of the
pipeline, than to base it on SMYS alone.
High pressure hydrostatic testing is able to remove
defects that may fail in service.
Hydrostatic testing to actual yield, as determined with a
pressure-volume plot, does not damage a pipeline.
The report specifically recommended setting the MAOP as a
percentage of the field test pressure. In particular, it recommended
setting the MAOP at 80 percent of the test pressure when the minimum
test pressure was 90 percent of SMYS or higher. Although the committee
responsible for the B31.8 Code received the report, the committee
deferred consideration of its findings at that time because the Federal
regulators had already begun the process to incorporate the 1968
edition of the B31.8 Code into the Federal pipeline safety standards.
More than a decade later, the committee responsible for development
of the B31.8 Code, now under the auspices of the American Society of
Mechanical Engineers (ASME), revisited the question of the design
factor it had deferred in the late 1960s. The committee determined
pipelines could operate safely at stress levels up to 80 percent of
SMYS. ASME updated the design factors in a 1990 addendum to the 1989
edition of the B31.8 Code, and they remain in the current edition.
Although part 192 incorporates parts of the B31.8 Code by reference, it
does not incorporate the updated design factors. With the benefit of
operating experience with pipelines, it seems clear that operating
pressure plays a less critical role in pipeline integrity and failure
consequence than other factors within the operator's control.
By any measure, new technologies and risk controls have had a far
greater impact on pipeline safety and integrity. A great deal of
progress has occurred in the manufacture of steel pipe and in its
initial inspection and testing. Technological advances in metallurgy
and pipe manufacture decrease the risk of incipient flaws occurring and
going undetected during manufacture. The detailed standards now
followed in steel and pipe manufacturing provide
[[Page 62150]]
engineers considerable information about their material properties.
Toughness standards make new steel pipe more likely to resist fracture
and to survive mechanical damage. Knowledge about the material
properties allows engineers to predict how quickly flaws, whether
inherent or introduced during construction or operation, will grow to
failure under known operating conditions.
Initial inspection and hydrostatic testing of pipelines allow
operators to discover flaws that have occurred prior to operation, such
as during transportation or construction. They also serve to validate
the integrity of the pipeline before operation. Initial pressure
testing causes longitudinal and some other flaws introduced during
manufacture, transportation, or construction to grow to the point of
failure. Initial pressure testing detects all but one type of
manufacturing or construction defect that could cause failure in the
near-term. The sole type of defect that pressure testing may not
identify, a flaw in a girth weld, is detectable through pre-operational
non-destructive testing, which is required in this rule.
The most common defects initiated during operation are caused by
mechanical damage or corrosion. Improvements in technology have
resulted in internal inspection techniques that provide operators a
significant amount of information about defects. Although there is
significant variance in the capability of the tools used for internal
inspections, each provides the operator information about flaws in the
pipeline that an operator would not otherwise have. An operator can
then examine these flaws to determine whether they are defects
requiring repair. In addition, internal inspections with in-line
inspection (ILI) devices, unlike pressure testing, are not destructive
and can be done while the pipeline is in operation. Initial internal
inspection establishes a baseline. Operators can use subsequent
internal inspections at appropriate intervals to monitor for changes in
flaws already discovered or to find new flaws requiring repair or
monitoring. Internal inspections, and other improved life-cycle
management practices, increase the likelihood operators will detect any
flaws that remain in the pipe after initial inspection and testing, or
that develop after construction, well before the flaws grow to failure.
B.3. History of PHMSA Consideration
Although the agency had never formally revisited its part 192 MAOP
standards, prior to this rulemaking, developments in related arenas
have increasingly set the stage for changes to those standards.
Grandfathered pipelines have operated successfully at higher stress
levels in the United States during more than 35 years of Federal safety
regulation. Many of these grandfathered pipelines have operated at
higher stress levels for more than 50 years without a higher rate of
failure. We have also been aware of pipelines outside the United States
operating successfully at the higher stress levels permitted under the
ASME standard. A technical study published in December 2000 by R.J.
Eiber, M. McLamb, and W.B. McGehee, Quantifying Pipeline Design at 72%
SMYS as a Precursor to Increasing the Design Stress Level, GRI-00/0233,
further raised interest in the issue.
In connection with our issuance of the 2003 gas transmission
integrity management regulations, PHMSA announced a policy to grant
``class location'' waivers (now called special permits) to operators
demonstrating an alternative integrity management program for the
affected pipeline. A ``class location'' waiver allows an operator to
maintain current operating pressure on a pipeline following an increase
in population that changes the class location. Absent a waiver, the
operator would have to reduce pressure or replace the pipe with thicker
walled pipe. PHMSA held a meeting on April 14-15, 2004, to discuss the
criteria for the waivers. In a notice seeking public involvement in the
process (69 FR 22116; Apr. 23, 2004), PHMSA announced:
Waivers will only be granted when pipe condition and active
integrity management provides a level of safety greater than or
equal to a pipe replacement or pressure reduction.
A second notice (69 FR 38948; June 29, 2004) announced the
criteria. The criteria included the use of high quality manufacturing
and construction processes, effective coating, and a lack of systemic
problems identified in internal inspections Although the class location
special permits/waivers do not address increases in stress levels per
se, the risk management approach developed in those cases takes account
of operating pressure and addresses many of the same concerns. The same
risk management approach, and many of the specific criteria applied in
the class location waivers, guided PHMSA's handling of the special
permits discussed below and, ultimately, this rule.
Beginning in 2005, operators began addressing the issue of stress
level directly with requests that PHMSA allow operation at the MAOP
levels that the ASME B31.8 Code would allow. With the increasing
interest, PHMSA held a public meeting on March 21, 2006, to discuss
whether to allow increased MAOP consistent with the updated ASME
standards. PHMSA also solicited technical papers on the issue. Papers
filed in response, as well as the transcript of the public meeting, are
in the docket for this rulemaking. Later in 2006, PHMSA again sought
public comment at a meeting of its advisory committee, the Technical
Pipeline Safety Standards Committee (TPSSC). The transcript and
briefing materials for the June 28, 2006, meeting are in the docket for
the advisory committee, Docket ID PHMSA-RSPA-1998-4470-204, 220. This
docket can be found at http://www.regulations.gov. Comments and papers
written during the period these efforts were undertaken overwhelmingly
supported examining increased MAOP as a way to increase energy
efficiency and capacity while maintaining safety.
B.4. Safety Conditions in Special Permits
In 2005, operators began requesting waivers, now called special
permits, to allow operation at the MAOP levels that the ASME B31.8 Code
would allow. In some cases, operators filed these requests at the same
time they were seeking approval from the Federal Energy Regulatory
Commission (FERC) to build new gas transmission pipelines. In other
cases, operators sought relief from current MAOP limits for existing
pipelines that had been built to more rigorous design and construction
standards.
In developing an approach to the requests, PHMSA examined the
operating history of lines already operated at higher stress levels.
Canadian and British standards have allowed operation at the higher
stress levels for some time. The Canadian pipeline authority, which has
allowed higher stress levels since 1973, reports the following
regarding pipelines operating at stress levels higher than 72 percent
of SMYS:
About 6,000 miles of pipelines on the Alberta system,
ranging from six to 42 inches in diameter, were installed or upgraded
between the early 1970s and 2005;
About 4,500 miles of pipelines on the Mainline system east
of the Alberta-Saskatchewan border, ranging from 20 to 42 inches in
diameter, were installed or upgraded between the early 1970s and 2005;
and,
[[Page 62151]]
More than 600 miles in the Foothills Pipe Line system,
ranging from 36 to 40 inches in diameter, were installed between 1979
and 1998.
In the United Kingdom, about 1,140 miles of the Northern pipeline
system have been uprated to operate at higher stress level in the past
ten years. Accident rates for pipelines in these countries have not
indicated a measurable increased risk from operation at these higher
operating stress levels.
In the United States, some 5,000 miles of gas transmission lines
have MAOPs that were grandfathered under Sec. 192.619(c), when the
Federal pipeline safety regulations were adopted in the early 1970s,
continue to operate at stress levels higher than 72 percent of SMYS.
After some accidents caused by corrosion on grandfathered pipelines,
PHMSA considered whether to remove the exception in Sec. 192.619(c).
In 1992, PHMSA decided to continue to allow operation at the
grandfathered pressures (57 FR 41119; Sept. 9, 1992). PHMSA based its
decision on the operating history of two of the operators whose
pipelines contained most of the mileage operated at the grandfathered
pressures. PHMSA noted the incident rate on these pipelines, operated
at stress levels above 72 percent of SMYS, was between 10 percent and
50 percent of the incident rate of pipelines operated at the lower
pressure. Texas Eastern Gas Pipeline Company (now Spectra Energy), the
operator of many of the grandfathered pipelines, attributed the lower
incident rate to aggressive inspection and maintenance. This included
initial hydrostatic testing to 100 percent of SMYS, internal
inspection, visual examination of anomalies found during internal
inspection, repair of defects, and selective pressure testing to
validate the results of the internal inspection. Internal inspection
was not in common use in the industry prior to the 1980s. PHMSA's
statistics show these pipelines continue to have an equivalent safety
record when compared with pipelines operating according to the design
factors in the pipeline safety regulations.
PHMSA also considered technical studies and required companies
seeking special permits to provide information about the pipelines'
design and construction and to specify the additional inspection and
testing to be used. PHMSA also considered how to handle findings that
could compromise the long-term serviceability of the pipe. PHMSA
concluded that pipelines can operate safely and reliably at stress
levels up to 80 percent of SMYS if the pipeline has well-established
metallurgical properties and can be managed to protect it against known
threats, such as corrosion and mechanical damage.
Early and vigilant corrosion protection reduces the possibility of
corrosion occurring. At the earliest stage, this includes care in
applying a protective coating before transporting the pipe to the
right-of-way. With the newer coating materials and careful application,
coating provides considerable protection against external corrosion and
facilitates the application of induced current, commonly called
cathodic protection, to prevent corrosion from developing at any breaks
that may occur in the coating. Regularly monitoring the level of
protection and addressing any low readings will detect and correct
conditions that can cause corrosion at an early stage. Vigilant
corrosion protection includes close attention to operating conditions
that lead to internal corrosion, such as poor gas quality. In addition,
for new pipelines, operators' compliance with a rule issued last year
requiring greater attention to internal corrosion protection during
design and construction (72 FR 20059; Apr. 23, 2007) will prevent
internal corrosion. Finally, corrosion protection includes internal
inspection and other assessment techniques for early detection of both
internal and external corrosion.
One of the major causes of serious pipeline failure is mechanical
damage caused by outside forces, such as an equipment strike during
excavation activities. Burying the pipeline deeper, increased
patrolling, and additional line marking help prevent the risk that
excavation will cause mechanical damage. Further, enhanced pipe
properties increase the pipe's resistance to immediate puncture from a
single equipment strike. Improved toughness increases the ability of
the pipe to withstand mechanical damage from an outside force and may
also limit any failure consequences to leaks rather than ruptures. This
toughness usually allows time for the operator to detect the damage
during internal inspection well before the pipe fails.
To evaluate each request for a special permit, PHMSA established a
docket and sought public comment on the request. We received several
public comments, most in response to the first special permits
considered. Many of the comments supported granting the special
permits. Those who were not supportive may have underestimated the
significance of the safety upgrades required for the special permits. A
few commenters raised technical concerns. Among these were questions
about the impact of rail crossings and blasting activities in the
vicinity of the pipeline. The special permits did not change the
current requirements where road crossings exist and added a requirement
to monitor activities, such as blasting, that could impact earth
movement. Some commenters expressed concern about the impact radius of
the pipeline operating at a higher stress level. PHMSA included
supplemental safety criteria to address the increased radius. The
remainder of the comments addressed concerns, such as compensation or
aesthetics, which were outside the scope of the special permits. PHMSA
special permits do not address issues on siting, which are governed by
the FERC.
PHMSA expects to issue seven special permits, and possibly more, in
response to these requests. In each case, PHMSA has provided oversight
to confirm the line pipe is, or will be (for pipe yet to be
constructed), as free of inherent flaws as possible, that construction
and operation do not introduce flaws, and that any flaws are detected
before they can fail. PHMSA accomplishes this by imposing a series of
conditions on the grant of special permits. The conditions imposed as
part of the special permits are designed to address the potential
additional risk involved in operating the pipeline at a higher stress
level. A proposed pipeline must be built to rigorous design and
construction standards, and the operator requesting a special permit
for an existing pipeline must demonstrate that the pipeline was built
to rigorous design and construction standards. These additional design
and construction standards focused on producing a high quality pipeline
that is free from inherent defects that could grow more rapidly under
operation at a higher stress level and is more resistant to expected
operational risks. In addition, PHMSA requires the operator of a
pipeline receiving a special permit to comply with operation and
maintenance (O&M) requirements that exceed current pipeline safety
regulations. These additional O&M and integrity management requirements
focused on the potential for corrosion and mechanical damage and on
detecting defects before the defects can grow to failure.
B.5. Codifying the Special Permit Standards
This rule puts in place a process for managing the life-cycle of a
pipeline operating at a higher stress level based on our experience
with the special permits. Integrity management focuses on managing and
extending the service
[[Page 62152]]
life of the pipeline. Life-cycle management goes beyond the operations
and maintenance practices, including integrity management, to address
steel production, pipeline manufacture, pipeline design, and
installation.
Industry experience with integrity management demonstrates the
value of life-cycle management. Through baseline assessments in
integrity management programs, gas transmission operators identified
and repaired 2,883 defects in the first three years of the program
(2004, 2005, and 2006). More than 2,000 of these were discovered in the
first two years as operators assessed their highest risk, generally
older, pipelines. In a September 2006 report, GAO-09-946, the
Government Accountability Office noted this data as an early indication
of improvement in pipeline safety. In order to qualify for operation at
higher stress levels under this rule, pipelines will be designed and
constructed under more rigorous standards. Baseline assessment of these
lines will likely uncover few defects, but removing those few defects
will result in safer pipelines. In addition, the results of the
baseline assessment will aid in evaluating anomalies discovered during
future assessments.
This rule, based on the terms and conditions of the special permits
allowing operation at higher stress levels, imposes similar terms and
conditions and limitations on operators seeking to apply the new rule.
The terms and conditions, which include meeting design standards that
go beyond current regulation, address the safety concerns related to
operating the pipeline at a higher stress level. PHMSA will step up
inspection and oversight of pipeline design and construction, in
addition to review and inspection of enhanced life-cycle management
requirements for these pipelines.
With special permits, PHMSA individually examined the design,
construction, and O&M plans for a particular pipeline before allowing
operation at a higher pressure than currently authorized. In each case,
PHMSA conditioned approval on compliance with a series of rigorous
design, construction, O&M, and management standards, including enhanced
damage prevention practices. PHMSA's experience with these requests for
special permits led to the conclusion that a rule of general
applicability is appropriate. With a rule of general applicability, the
conditions for approval are established for all without need to craft
the conditions based on individual evaluation. Thus, this rule sets
rigorous safety standards. In place of individual examination, the rule
requires senior executive certification of an operator's adherence to
the more rigorous safety standards. An operator seeking to operate at a
higher pressure than allowed by current regulation must certify that a
pipeline is built according to rigorous design and construction
standards and must agree to operate under stringent O&M standards.
After PHMSA or state pipeline safety authority (when the pipeline is
located in a state where PHMSA has an interstate agent agreement, or an
intrastate pipeline is regulated by that state) receives an operator's
certification indicating its intention to operate at a higher operating
stress level, PHMSA or the state would then follow up with the operator
to verify compliance. As with the special permits, this rule would
allow an operator to qualify both new and existing segments of pipeline
for operation at the higher MAOP, provided the operator meets the
conditions for the pipeline segment.
Several types of pipeline segments will not qualify under this
rule. These include the following:
Pipeline segments in densely populated Class 4 locations.
In addition to the increased consequences of failure in a Class 4
location, the level of activity in such a location increases the risk
of excavation damage.
Pipeline segments of grandfathered pipeline already
operating at a higher stress level but not constructed in accordance
with modern standards. Although grandfathered pipeline has been
operated successfully at the higher stress level, PHMSA or the state
would examine any further increases individually through the special
permit process.
Bare or ineffectively coated pipe. This pipe lacks the
coating needed to prevent corrosion and to make cathodic protection
effective.
Pipelines with wrinkle bends. Section 192.315(a) currently
prohibits wrinkle bends in pipeline operating at hoop stress exceeding
30 percent of SMYS.
Pipelines experiencing failures indicative of a systemic
problem, such as seam flaws, during initial hydrostatic testing. Such
pipe is more likely to have inherent defects that can grow to failure
more rapidly at higher stress levels.
Pipe manufactured by certain processes, such as low
frequency electric welding process.
Pipeline segments which cannot accommodate internal
inspection devices.
We are establishing slightly different requirements for segments
that have already been operating and those which are to be newly built.
Some variation is necessary or appropriate for an existing pipeline.
For example, the requirement for cathodically protecting pipeline
within 12 months of construction is an existing requirement for all
pipelines. A requirement for the operator of an existing pipeline
segment to prove that the segment was in fact cathodically protected
within 12 months of construction provides greater confidence in the
condition of the existing segment. Allowing proof of five percent fewer
nondestructive tests done on an existing segment at the time of
construction recognizes the possibility that some welds may not be
tested when 100 percent nondestructive testing is not required. The
overriding principle in the variation is to allow qualification of a
quality pipeline with minimal distinction. Based on our review of
requests for special permits on existing pipelines, PHMSA does not
believe the more rigorous standards we are requiring are too high for
existing segments of modern design and construction. Setting the
qualification standards lower for existing pipeline segments could
encourage operators to construct a pipeline at the lower standards and
seek to raise the operating pressure at some future date.
PHMSA acknowledges this rule may not cover all conditions
encountered by a pipeline operator. Further, operators may have
innovative alternative methods to the guidelines contained in this
rule. To that end, operators may apply to PHMSA or state pipeline
safety authority (when the pipeline is located in a state where PHMSA
has an interstate agent agreement, or an intrastate pipeline is
regulated by that state) for a special permit requesting to implement
the alternative methods.
B.6. How To Handle Special Permits and Requests for Special Permits
A number of pipeline operators have submitted requests for special
permits seeking relief from the current design requirements to allow
operation at higher stress levels. For the most part, this rule
addresses the relief requested. PHMSA has already granted many of these
under terms and conditions that may vary slightly from those in this
final rule. In some cases, the relief granted is specific to the relief
requested by the operator and extends beyond the scope of this
rulemaking. PHMSA has continued review of pending special permit
applications while working on this rulemaking, in recognition that a
final rule may not be issued by the time an operator intended to
operate its pipeline at a higher operating stress level. With the
publication of this final
[[Page 62153]]
rule, this case-by-case approach to approving operation under a special
permit at higher operating stress levels is no longer needed.
PHMSA will terminate its review of any pending applications for
special permits associated with operation at higher operating stress
levels once this final rule is issued. Operators of those pipelines
must comply with this final rule in order to operate their pipelines at
a higher alternative MAOP. PHMSA will examine special permits that have
already been granted, as appropriate, to determine if any modifications
are needed in light of safety decisions made in preparing this rule.
B.7. Statutory Considerations
Under 49 U.S.C. 60102(a), PHMSA has broad authority to issue safety
standards for the design, construction, O&M of gas transmission
pipelines. Under 49 U.S.C. 60104(b), PHMSA may not require an operator
to modify or replace existing pipelines to meet a new design or
construction standard. Although this rule includes design and
construction standards, these standards simply add more rigorous, non-
mandatory requirements. This rule does not require an operator to
modify or replace existing pipelines or to design and construct new
pipeline in accordance with these non-mandatory standards. If, however,
a new or existing pipeline meets these more rigorous standards, the
rule allows an operator to elect to calculate the MAOP for the pipeline
based on a higher stress level. This would allow operation at an
increased pressure over that otherwise allowed for pipeline built since
the Federal regulations were issued in the 1970s. To operate at the
higher pressure, the operator would have to comply with more rigorous
O&M, and management requirements.
Under 49 U.S.C. 60102(b), a gas pipeline safety standard must be
practicable and designed to meet the need for gas pipeline safety and
for protection of the environment. PHMSA must consider several factors
in issuing a safety standard. These factors include the relevant
available pipeline safety and environmental information, the
appropriateness of the standard for the type of pipeline, the
reasonableness of the standard, and reasonably identifiable or
estimated costs and benefits. PHMSA has considered these factors in
developing this rule and provides its analysis in the preamble.
PHMSA must also consider any comments received from the public and
any comments and recommendations of the TPSSC. These are discussed
below.
C. Comments on the NPRM
PHMSA received comments from 19 organizations in response to the
NPRM. These included eleven pipeline operators, four trade associations
and related organizations, three steel/pipe manufacturers, and one
state pipeline safety regulatory agency.
C.1. General Comments
API 5L, 44th Edition
Many commenters noted that pipe material/design requirements in
American Pipeline Institute (API) Standard 5L (API 5L) have been
significantly revised in the 44th edition, which they stated would be
in effect by the time a final rule is issued. These commenters
generally suggested that PHMSA should defer to, or incorporate,
requirements from the 44th edition where applicable rather than
establishing different technical requirements in regulation.
Response
API 5L, 43rd edition, is currently incorporated by reference into
the Code of Federal Regulations (CFR). PHMSA has begun a technical
review of the 44th edition to determine whether and to what extent it
is appropriate to update this reference or if exceptions need be taken
when so incorporating the standard. PHMSA cannot reference requirements
in the 44th edition until this review is completed and the regulations
have been revised to incorporate the new edition. Where differences in
the 44th edition would affect requirements in this rule, appropriate
changes will be made when that edition is incorporated.
Effect on Special Permits
All commenters who addressed the question suggested that
requirements in a final rule should not apply retroactively to
pipelines operating at alternative MAOP based on special permits issued
after detailed review by PHMSA. One pipeline operator provided a legal
analysis maintaining that such retroactive application would be
contrary to PHMSA's statutory authority. These organizations also
commented that PHMSA should continue review of special permit
applications until the final rule is issued, noting that in many cases
operation at the proposed higher MAOP is necessary to meet contractual
commitments operators have made in anticipation of a special permit
being granted and to meet national energy needs.
Response
As noted above, PHMSA continued reviewing special permit
applications throughout this rulemaking proceeding, generally applying
the same criteria adopted in this rule. Having now published the final
rule, we consider it unnecessary to complete review of pending special
permit applications on the subject. Accordingly, PHMSA intends to
terminate these proceedings, with appropriate notice to the individual
applicants.
In contrast, this regulatory action has no effect on the status of
special permits or waivers currently in effect. As we explained
recently in Docket No. PHMSA-2007-0033, Pipeline Safety: Administrative
Procedures, Address Updates, and Technical Amendments, (FR Volume 73,
No. 61, 16562, published March 28, 2008), PHMSA reserves the right to
revoke or modify a special permit or waiver based on an operator's
failure to comply with the conditions of the special permit/waiver or
on a showing of material error, misrepresentation, or changed
circumstances. Although an operator may elect to surrender its special
permit at any time, nothing in this rule requires the operator to do so
or otherwise triggers reopening of a special permit/waiver currently in
effect. The existing MAOP special permits were issued based upon a
PHMSA review of the operator's engineering, construction, O&M
procedures and operating history. While some of the pipeline segments
may not meet all of the requirements specified in this final rule, the
operational history and O&M practices provide an equivalent level of
safety as provided in this final rule. Furthermore, whether a pipeline
is operating at higher MAOP under this rule or a special permit/waiver,
PHMSA will monitor and enforce compliance with the applicable
conditions and safety controls.
Structure
One state pipeline safety regulatory agency expressed concern about
the complexity and inconsistency being added to the regulations as a
result of the structure of the proposed rule. The state agency noted
that the proposal would add many pages to part 192 that would apply to
only a limited number of gas transmission operators. The agency
suggested that it would be more effective, and cause less confusion, if
requirements for pipelines operating at an alternative MAOP were
presented in a separate subpart, applicable only to those pipelines.
[[Page 62154]]
Response
PHMSA has not previously used a separate subpart to include varied
requirements applicable to specific types of pipelines. Instead,
subparts have been used for individual topics, such as Corrosion
Control or Integrity Management. PHMSA considers it more appropriate to
incorporate requirements applicable to each subpart as the requirements
in this rule implicate several subparts. PHMSA also notes that no other
commenters indicated that the structure of the proposed rule was
confusing. PHMSA has retained the structure of the proposal in this
final rule. PHMSA intends to post this notice of final rulemaking on
its web site, which will provide a reference for pipeline operators
that includes all of the requirements associated with alternative MAOP
in one document.
C.2. Comments on Specific Provisions in the Proposed Rule
C.2.1. Section 192.7, Incorporation by Reference
Interstate Natural Gas Association of America (INGAA) and three
pipeline operators supported incorporation of American Society of
Testing and Materials (ASTM) standard ASTM A-578/A578M-96 into the
regulations. These commenters generally noted that this action is
consistent with reliance on consensus standards, which they support.
American Gas Association (AGA) and the Gas Piping Technology Committee
(GPTC) took the contrary position and opposed incorporation of the ASTM
standard. GPTC commented that the standard is used by one mill and that
other mills use other standards (including International Standards
Organization (ISO) standards). GPTC also noted that there are a number
of equivalent standards and that PHMSA should not select one for
incorporation. AGA added that incorporating the standard could have
unintended consequences of making the rule too prescriptive and
precluding the use of equivalent standards.
Response
The final rule incorporates ASTM A578/A578M-96 into the
regulations. Incorporation by reference makes the provisions of the
standard apply, when it is referenced in a regulation, in the same
manner as if they were written in the CFR. Referencing consensus
standards wherever possible is the policy of the Federal government.
This standard is referenced in the regulation for assuring plate/
coil quality control (QC). That reference requires that ultrasonic (UT)
testing be conducted in accordance with the standard, API 5L paragraph
7.8.10, or equivalent. The pipe must also be manufactured in accordance
with API 5L which is already referenced in Sec. 192.7. PHMSA considers
that the allowance for use of an equivalent standard renders moot the
concerns expressed by AGA and GPTC.
C.2.2. Design Requirements
Section 192.112(a), General Standards for the Steel Pipe
Carbon equivalent: INGAA, five pipeline operators and two pipe
manufacturers all noted that the proposed limit in paragraph (a)(1) on
carbon equivalent (CE) (0.23 percent Pcm) is inconsistent with the 44th
edition of API 5L. INGAA and one operator suggested deleting the limit
from the proposed rule. Two operators noted that the NPRM described no
analysis or data showing the need for a different limit. Several
commenters indicated that high-strength pipe (grades X-80 and above) is
difficult to achieve with the stated limit. One operator suggested that
weldability is the key issue and that allowance for a higher CE is
particularly important for high-strength and strain-based pipe. A steel
manufacturer objected to sole reliance on the Pcm formula for
determining the CE value.
Response
PHMSA agrees that the limit in API 5L is acceptable. PHMSA has
changed the limit for CE to 0.25 Pcm (Ito-Bessyo formula for CE), which
is consistent with API 5L. PHMSA does not agree that no limit should be
included in the CFR. PHMSA considers that a limit is necessary to
assure the quality of steel used for pipelines to operate at an
alternative MAOP. Weldability tests are not timely for determining the
acceptability of steel, as they cannot be performed until pipe is
manufactured. Recent experience with several new pipelines using X-80
steel has indicated that such high strength steel can meet the CE
limit. PHMSA does not currently have experience with steels of grades
higher than X-80 and will need to understand what is important for such
pipe grades as they are used.
PHMSA acknowledges that there are other methods for calculating the
CE value of steel. The Pcm formula included in the proposed rule is a
method used by several mills. PHMSA has revised the final rule to
include use of an alternate International Institute of Welding (IIW) CE
formula, used by other mills for determining CE.
Diameter to thickness ratio: INGAA and three pipeline operators
suggested deleting the limit in proposed paragraph (a)(3) on the ratio
of pipe diameter to thickness (D/t). They maintained that this limit
may be inappropriate for high-grade pipe and that the concerns that
might underlie such a limit are adequately addressed by the proposed
rule and common construction practices and quality assurance (QA). One
operator noted that ovality and denting issues are addressed by the
proposed construction requirements of Sec. 192.328, that QA is
required by proposed Sec. 192.620(d)(9), and that the baseline
geometry ILI and the provisions of the ASME Code would also address the
underlying concerns.
Response
PHMSA has retained the proposed limit. PHMSA adopted this limit
(i.e., D/t <= 100) based upon presentations made by industry experts at
the public meeting on ``Reconsideration of Maximum Allowable Operating
Pressure in Natural Gas Pipelines'' held on March 21, 2006 in Reston,
VA. Higher D/t ratios can lead to excessive denting during
transportation, construction bending, pipe stringing on the right-of-
way, backfilling, and hydrostatic testing.
Section 192.112(b), Fracture Control
Several commenters noted that some requirements included in the
proposed rule are being eliminated or significantly revised in the 44th
edition of API 5L. The steel/pipe manufacturers suggested referencing
the new standard to, among other things, avoid unnecessarily limiting
approaches to deriving arrest toughness and treating all sizes and
types of pipe (e.g., seamless) the same for purposes of the drop weight
test.
INGAA and three pipeline operators suggested a change to allow a
crack arrest design other than mechanical arrestors if crack
propagation cannot be made self-limiting. (One operator noted that
Clock Spring \1\ is marketed as a crack arrestor). They suggested that
a rule should allow an option for engineering analysis, including an
analysis of consequences. One operator noted that this option could be
particularly important for high-pressure, large-diameter pipelines. Two
operators generally supported the proposed approach for fracture
control if self-arrest is attainable. They noted that it is critical
that operators have a plan and consider the potential under-
[[Page 62155]]
conservativeness of Charpy toughness equations for high grade pipe (X-
70 and above).
---------------------------------------------------------------------------
\1\ Clock Spring is a commercially available composite sleeve
used for pipeline repairs.
---------------------------------------------------------------------------
Response
PHMSA has not yet incorporated the 44th edition of API 5L into the
regulations. PHMSA is conducting a technical review of this edition to
determine if it is acceptable for incorporation. If, after that review,
PHMSA determines that the standard is acceptable, PHMSA will propose to
incorporate the 44th edition and change other affected rules as
appropriate.
The final rule requires an overall fracture control plan to resist
crack initiation and propagation and to arrest a fracture within eight
pipe joints with a 99 percent occurrence probability and within five
pipe joints with a 90 percent occurrence probability. Research has
shown that an effective fracture plan should include acceptable Charpy
impact and drop weight tear tests, which are required in this final
rule.
PHMSA considers composite sleeves to be suitable mechanical crack
arrestors. Operators could use composite sleeves for this purpose,
install periodic joints of thicker-walled pipe, or use other design
features to provide crack arrest if it is not possible to achieve the
toughness properties specified in the rule and also assure self-
limiting arrest. PHMSA has revised the language in this final rule to
allow additional design features and to make mechanical crack arrestors
an example of such features rather than the only method allowed.
Section 192.112(c), Plate/Coil Quality Control
One pipeline operator and two pipe manufacturers suggested
expanding the mill control inspection program to a full internal
quality management program and including caster and plate/coil/pipe
mills.
INGAA, three pipeline operators and two pipe manufacturers
commented that the specificity of requirements applicable to mill
inspection should be reduced. These commenters agreed that a macro etch
test is appropriate but suggested that the details of how this test is
applied should be left to decisions of the mill and the pipe purchaser.
They suggested that API 5L provides a foundation for those decisions
and the specific requirements in the proposed rule add unnecessary cost
impact. One pipe manufacturer noted that the Mannesmann scale is very
subjective, while a second separately commented that reference to the
Mannesmann scale should be deleted because it is proprietary and thus
inappropriate for inclusion in a regulation. One operator requested
that the mill inspection requirements, including those for macro etch
and UT examination, be explicitly limited to new pipelines, noting that
it is unlikely these tests were performed for any existing pipelines
and that they have minimal relevance for existing pipelines that would
be subject to the proposed rule.
INGAA and four pipeline operators suggested that an alternative to
the UT testing specified should be allowed for identifying laminations.
They suggested that a full-body UT inspection, for example, should be
acceptable.
One operator and two manufacturers commented that it is
inappropriate to use the proposed macro etch test and acceptance
criteria as a heat/slab rejection criteria. These commenters noted that
no consensus standard references this test. The operator maintained
that the test does not accomplish what PHMSA suggested in the preamble
of the NPRM, that it is a lagging rather than a leading test and its
use as an acceptance test without a retest allowance could result in
rejection of up to 2,000 tons of steel or more. The operator suggested
that this should be a mill control test rather than an acceptance test
with specifics, including retest allowance, to be negotiated between
the mill and pipe purchaser.
One operator and one manufacturer noted that ASTM A578 is a plate
UT inspection standard. They commented that specifying this standard
for coil/pipe is beyond its scope. They also commented that we gave no
basis for proposing that 50 percent of surface and 90 percent of joints
be examined. They noted that pipe seam welds and pipe ends are
inspected radiographically or by UT and that additional UT is more
appropriately a purchaser-specified requirement. Another operator also
suggested that the 50 percent surface coverage requirement be deleted
in favor of reference to ASTM A578/A578M.
Two manufacturers suggested that the rule allow UT on plate/coil or
pipe body, noting that most United States mills lack equipment to
perform ASTM A578 testing. Another manufacturer suggested that a
combination of electromagnetic inspection (EMI) and UT inspection is
superior and would produce the most dramatic impact. This combination,
according to this manufacturer, is also applicable to seamless and
electric resistance welded (ERW) pipe.
One manufacturer recommended that the inspection program of
proposed section 192.112(c)(2)(ii) be limited to submerged arc welded
(SAW) pipe, and that the acceptance criteria for UT testing be
referenced to ASTM A578 or equivalent. This commenter noted that
laminations are not a significant issue for modern pipe.
Response
PHMSA agrees that an ``internal quality management program'' is
more descriptive than a ``mill control inspection program'' and that
such a program should be required at all mills associated with the
manufacture of steel and pipe. The final rule has been revised
accordingly.
PHMSA considers that a macro etch test or other equivalent method
is needed to identify inclusions that may cause centerline segregation
during the continuous casting process. The acceptance criteria must be
agreed to between the purchaser and the mill. PHMSA has added an
alternative to the requirement for a macro etch test consisting of an
operator QA monitoring plan that includes audits conducted by the
operator (or an agent operating under its authority) of: (a)
Steelmaking and casting facilities; (b) QC plans and manufacturing
procedure specifications (MPS); (c) equipment maintenance and records
of conformance; (d) applicable casting superheat and speeds; and (e)
centerline segregation monitoring records to ensure mitigation of
centerline segregation during the continuous casting process.
PHMSA agrees that alternate methods to test the pipe body for
laminations, cracks, and inclusions should be acceptable and has
revised the rule to allow methods per API 5L Section 7.8.10 or ASTM
A578-Level B, or other equivalent methods. PHMSA understands that it is
unlikely that many existing pipelines were manufactured using processes
that included the specified examinations but does not consider that
sufficient reason for excluding existing pipelines from the
requirements.
The requirement for 50 percent of surface and 95 percent of lengths
of pipe to be UT tested was set to ensure adequate QC standards. PHMSA
agrees that the specified QC requirements also must be practical. In
the final rule, we have reduced the requirement for 50 percent of
surface coverage to 35 percent because we recognize that it may be
difficult to achieve 50 percent coverage for pipe manufactured with
helical seams.
PHMSA has not deleted reference to the Mannesmann scale, which is
widely used by steel manufacturers. In
[[Page 62156]]
addition, the regulation allows for use of equivalent measures.
PHMSA does not agree that the inspection program of proposed
192.112(c)(2)(ii) should be limited to SAW pipe. PHMSA considers this
requirement to be an overall quality management tool and not just for
laminations. Additionally, PHMSA notes that at least one recently
constructed pipeline has had problems with laminations.
Section 192.112(d), Seam Quality Control
INGAA, four pipeline operators, and two pipe manufacturers all
recommended additional reliance on the procedures of API 5L 44th
edition. The manufacturers would have referenced API 5L for toughness
requirements and made them applicable to weld and heat affected zone in
SAW pipe only. They noted that the proposed requirement is
inappropriate for ERW pipe, that the specified toughness is higher than
that called for in API 5L and is not necessary. The manufacturers
believe that fracture arrest capabilities are not needed in weld metal,
since staggered seams in pipeline construction result in arrest
occurring in the pipe body.
INGAA and three pipeline operators would have eliminated reference
to specific hardness testing or a maximum hardness level, arguing that
API 5L contains sufficient guidance. They further noted that the
specified hardness of 280 Vickers (Hv10) is only for sour gas. One
manufacturer would have relaxed the hardness requirement to 300 Hv10
and allowed for equivalent test methods (per ASTM E140). Another would
have specified a maximum hardness ``appropriate for the pipeline
design'' vs. specifying a limit. The first manufacturer noted that API
5L does not specify hardness limits except for sour gas service or
offshore pipelines and that the technical justification for these
limits on other pipe is not obvious. The manufacturers maintained that
limiting hardness may not allow attaining the best weld properties and
that 280 Hv10 is likely not attainable for pipe grades X-80 and above.
Two pipe manufacturers requested that the rule be clarified to
indicate that the seam QC requirements apply only to longitudinal or
helical seams. They noted that pipe mill jointer welds require
radiography per API 1104 and that significant capital expense would be
required for pipe mills to UT test jointer and skelp end welds after
cold expansion and hydrostatic testing.
Response
PHMSA has not yet incorporated the 44th edition of API 5L into the
regulations. PHMSA is conducting a technical review of this edition to
determine if it is acceptable for incorporation. If, after review,
PHMSA determines that the standard is acceptable, PHMSA will propose to
incorporate the 44th edition and propose changes to other affected
regulations as appropriate.
PHMSA has deleted the proposed limit on toughness. This limit was
not included in the conditions applied to special permits issued for
alternative MAOP operation. Pipe procured to modern standards generally
meets the proposed limit, and other requirements in this rule, provide
for crack arrest. Thus, PHMSA concluded that a toughness limit was not
needed.
PHMSA does not agree that it is not necessary to specify a hardness
limit. All recent pipelines for which special permits have been issued
to operate at alternative MAOP have met the proposed hardness limit
without apparent difficulty. This includes X-80 pipe. The requirement
helps assure that only high-quality steel is used for pipelines to be
operated at alternative MAOP. Hardness must be limited to assure welds
are not susceptible to cracking. The proposed limit has been retained
in the final rule.
PHMSA intends the proposed seam inspection requirements to apply to
pipe seam welds and not to jointer or skelp welds. The title of this
subparagraph is ``Seam quality control,'' and its requirements all
refer to ``seam welds'' or ``seams.'' PHMSA does not consider that
additional changes are needed to clarify the applicability of these
requirements.
Section 192.112(e), Mill Hydrostatic Test
Most commenters objected to the proposed requirement that mill
hydrostatic tests be held for 20 seconds. They noted that mills
typically follow API 5L, which specifies a hydrostatic test of 10
seconds and that changing this standard could reduce mill productivity.
One operator also noted that a more rigorous qualification test is
already specified elsewhere in the proposed regulation.
One manufacturer would have limited the required maximum test
pressure to 3,000 psi if there are physical limitations in mill test
equipment that preclude obtaining higher pressures. The manufacturer
stated that most mills cannot achieve test pressures above 3,000 psi,
which is the maximum specified in API 5L and that upgrades to equipment
would cost from $0.5 to $4 million per tester.
Response
PHMSA agrees that a 20-second mill hydrostatic test is not needed
and has revised the final rule to reduce the required hold time to 10
seconds. While a longer mill hydrostatic test may allow the discovery
of more pipe defects, the benefit is marginal. The pipeline will later
be subject to a much longer hydrostatic test prior to being placed in
service according to 192.505(c). Moreover, in the case of Class 1 and 2
locations, the pipe will be tested at a higher stress level than the
mill hydrostatic test according to 192.620(a)(2).
PHMSA does not consider it appropriate to limit the maximum test
pressure to reflect the reported mill limitations. In practice, the
need for tests above 3,000 psi should be rare. Test pressures that high
would only be required for pipeline in a Class 3 location operating at
a very high MAOP.
Section 192.112(f), Coating
INGAA, GPTC, and eight pipeline operators all objected to the
proposed requirements that would have limited operation at an
alternative MAOP to pipe coated with fusion bonded epoxy (FBE). The
commenters noted that specifying any single coating type would stifle
innovation. They suggested that a performance-based requirement would
be more appropriate. The important performance characteristics they
identified include non-disbonding and non-cracking. Two operators would
add non-shielding, and GPTC suggested specifying that coating must meet
or exceed the protection of FBE.
GPTC and one operator requested clarification that girth welds can
be coated with other than FBE. GPTC also requested clarification that
the proposed requirement in subparagraph 2 that coatings used for
trenchless installation must resist abrasion and other damage applies
to the coatings described under subparagraph 1.
Response
PHMSA agrees that specifying a particular coating could stifle
innovation and we have revised the final rule to require non-shielding
coatings. Eliminating reference to FBE coating in this section obviates
the need for additional changes to note that girth welds can be coated
with other than FBE.
PHMSA has made a minor change in response to GPTC's request for
clarification. Subparagraph 192.112(f)(2)
[[Page 62157]]
now requires that coatings used for trenchless installation must resist
abrasions and other installation damage ``in addition to being non-
shielding.''
Section 192.112(g), Flanges and Fittings
INGAA and three pipeline operators generally supported the proposed
requirements for certification records and a pre-heat procedure for
welding of components with CE greater than 0.42 percent, but maintained
that existing standards and operator supplemental requirements are
adequate to assure the integrity of flanges and fittings. The operators
cited specific standards to which fittings and flanges should be
purchased. Another operator noted that the proposed requirements go
beyond API and ASTM standards, and suggested that the new requirements
should be part of an industry standard. This operator also suggested
that PHMSA establish a minimum size below which certifications would
not be required.
GPTC requested clarification as to what certification is required
and what requirements/specifications are to be certified.
Response
PHMSA has concluded that no changes are needed to the standards
proposed for flanges and fittings. It is likely that flanges and
fittings procured to current standards will meet the rule's
requirements. PHMSA will review the degree of compliance during
inspections of pipelines being constructed or upgraded for operation at
an alternative MAOP. PHMSA does not agree that the proposed
requirements go beyond API and ASTM standards. Fittings, flanges and
valves manufactured to API, ASTM, and/or ASME/ANSI standards should not
be operated above the maximum operating pressure limits of those
industry standards for the product rating. This rule change is not
intended to increase maximum operating pressure limits or designated
pressure or temperature rating of referenced code standards.
In the final rule, PHMSA has clarified that certification must
address chemistry, strength and wall thickness.
Section 192.112(h), Compressor Stations
Commenters expressed concern about the proposed requirement to
limit compressor station discharge temperatures to 120 degrees
Fahrenheit (49 degrees Celsius) unless testing shows the coating can
withstand higher temperatures in long-term operations. INGAA and four
pipeline operators would allow ``research'' in addition to testing to
permit operation above 120 degrees Fahrenheit. INGAA submitted a white
paper titled ``A Review of the Performance of Fusion-Bonded Epoxy
Coatings on Pipelines at Operating Temperatures Above 120 [deg]F'',
dated May 16, 2008, describing research it believes is relevant. The
commenters stated that more testing is not needed, because FBE coating
has been shown effective by research and experience in service. They
maintained that disbonding may occur but is irrelevant because FBE
coating is conductive and cathodic protection is still effective.
One pipeline operator would have allowed operation at a higher
compressor station discharge temperature if justified by test or data
held by the manufacturer, coating applicator, or operator. The operator
maintained that modern coating can withstand higher temperatures, and
that maintaining 120 degrees Fahrenheit may be impractical on hot days
(during which peak loads often occur) in southern locations. Another
operator suggested allowing operators to rely on FBE manufacturers'
specifications as the ``testing'' adequate to allow operation above 120
degrees Fahrenheit, limiting operation to 90 percent of the
manufacturer's continuous operating temperature. Another operator
suggested allowing a long-term coating integrity monitoring program as
an alternative to designing compressor stations to limit discharge
temperature to 120 degrees Fahrenheit.
A state pipeline safety regulatory agency suggested that
alternative approaches be allowed. The agency suggested that operators
could install heavier walled pipe and operate at conventional MAOP for
the distance required to assure that pipe wall temperatures would be
below 120 degrees Fahrenheit. This commenter stated its belief that
this would be a simpler and cheaper solution to the concern over
compressor station outlet temperature and that its use should not be
precluded.
Response
PHMSA is not persuaded by the arguments put forth by commenters,
and in the INGAA white paper titled ``A Review of the Performance of
Fusion-Bonded Epoxy Coatings on Pipelines at Operating Temperatures
Above 120 [deg]F'', dated May 16, 2008, that operation above 120
degrees Fahrenheit is simply acceptable. In fact, the INGAA white paper
confirms that disbonding and possibly cracking of FBE coating is more
likely to occur at operating temperatures above 120 degrees Fahrenheit.
PHMSA disagrees that disbonding is irrelevant because disbonded FBE
remains conductive and an operating cathodic protection system will
protect the pipeline from corrosion.
External corrosion is one of the most significant threats affecting
steel pipelines. PHMSA regulations require two levels of protection
against this threat: Coating and cathodic protection. These
requirements are intended to provide redundant protection. If coating
fails, cathodic protection continues to protect the pipe. If cathodic
protection fails, the coating is still present. PHMSA agrees that it is
important that disbonded coating remain conductive to assure continued
protection by cathodic protection. This is why the rule has been
revised to require ``non-shielding'' coating. At the same time, PHMSA
does not consider it acceptable to ignore known circumstances in which
one of the protections against corrosion is likely to fail simply
because the other exists. If PHMSA believed only one level of
protection were needed, the regulations would require either coating or
cathodic protection. INGAA's white paper confirms that there is a
significant likelihood that one of the levels of protection against
corrosion (i.e., coating) will fail if operated above 120 degrees
Fahrenheit. For pipelines to be operated at an alternative MAOP, where
the margin for corrosion is smaller than for pipelines conforming to
the existing regulations, PHMSA will not accept this higher likelihood
of failure of the coating system.
Nevertheless, PHMSA recognizes that improvements in coating systems
may allow operation above 120 degrees Fahrenheit without significantly
higher likelihood of disbonding. Thus, the rule allows operation above
this temperature if research, testing, and field monitoring tests
demonstrate that the coating type being used will withstand long-term
operation at the higher temperature. The operator must assemble and
maintain the data supporting higher-temperature operation. Research,
testing and field monitoring must be for coating by the same
manufacturer and must be specific to the brand of coating (if the
manufacturer makes more than one brand), application temperature, or
operating temperature rated coating.
PHMSA agrees that a long-term coating integrity monitoring program
can also assure that coating remains effective at higher operating
temperatures, but the effectiveness of such a program depends on how it
is structured and implemented. PHMSA would expect, for example, that a
monitoring program being used as a basis for operating at temperatures
above 120 degrees Fahrenheit would include periodic examinations to
assure
[[Page 62158]]
coating integrity (e.g., direct current voltage gradient). PHMSA has
modified the final rule to allow a long-term coating integrity
monitoring program to be used as a basis for allowing pipe temperatures
in excess of 120 degrees Fahrenheit, but operators must submit their
programs to the PHMSA pipeline safety regional office in which the
pipeline is located for review before pipeline segments may be operated
at alternative MAOP at these higher temperatures. PHMSA's review will
help assure that the monitoring programs are comprehensive enough to
assure long-term coating integrity, to identify instances in which
coating integrity becomes degraded, and to address those problems. An
operator must also notify a state pipeline safety authority when the
pipeline is located in a state where PHMSA has an interstate agent
agreement, or an intrastate pipeline is regulated by that state.
Where compressor station compression ratios raise the temperature
of the flowing gas to above 120 degrees Fahrenheit, operators should
consider installing gas coolers at compressor stations. This practice
has been successfully used in the industry to cool the gas stream to
not damage the pipe external coating.
PHMSA agrees that the alternative of heavier walled pipe operated
at conventional MAOP for the distance required to assure that pipe wall
temperatures do not exceed 120 degrees Fahrenheit suggested by the
state regulator is also an acceptable method of addressing the concern
of high-temperature operation. PHMSA has made minor changes to the rule
to make it clear that this option is not precluded.
C.2.3. Construction Requirements
Section 192.328(a), Quality Assurance (QA)
Four pipeline operators supported the QA requirements of proposed
Sec. 192.328(a). A state pipeline safety regulator noted that
subparagraph 2(ii) duplicated requirements in proposed Sec.
192.620(c)(5) and questioned why both sub-rules were needed.
Response
PHMSA's experience in regulating pipelines operating at higher
MAOPs under special permits has indicated that control of quality is
subject to frequent problems. As a result, PHMSA considers that an
explicit requirement for a QA plan during construction is needed. The
requirements of proposed Sec. 192.620(c)(5) also addressed quality
concerns, but they relate principally to personnel qualification. As
described below, this proposed paragraph has been revised in the final
rule to more explicitly address the qualification of personnel
performing construction tasks.
Section 192.328(b), Girth Welds
INGAA and four pipeline operators suggested moving the requirement
for testing of girth welds on existing pipelines from Sec. 192.328 to
Sec. 192.620. They believe that the requirement is inappropriately
located in a construction section that is not otherwise applicable to
existing pipe.
Response
PHMSA agrees and has moved this requirement in the final rule to
Sec. 192.620(b) as one of the criteria for determining when an
existing pipeline can be operated at alternative MAOP.
Section 192.328(c), Depth of Cover
Three pipeline operators supported the proposed depth of cover
requirements, although one would clarify that they apply to new
construction. Another operator suggested that allowance be made for
less depth of cover if alternative means of protection are used (e.g.,
concrete slabs) that offer equivalent protection.
Response
PHMSA agrees that alternative protection is acceptable and has
revised its proposed rule accordingly in this final rule. To satisfy
the rule, alternative protection must provide equivalent protection and
the operator must demonstrate this equivalence. Simply providing
barriers without demonstrating that they provide equivalent protection
is not sufficient.
PHMSA did not intend this requirement to apply to new construction
only and thus, has not changed the requirement in the final rule. PHMSA
considers that a pipeline to be operated at alternative MAOP, including
existing pipelines, must have superior protection from outside force
damage. PHMSA recognizes that existing pipelines constructed in
compliance with Sec. 192.327 may have less cover than required in this
rule. Operators of those pipelines desiring to implement alternative
MAOP must provide equivalent protection for those segments not meeting
the depth of cover requirements.
Section 192.328(d), Initial Strength Testing
A number of commenters objected to the proposed requirement that
any failure indicative of a fault in material disqualifies a pipeline
segment from operation at an alternative MAOP. The commenters suggested
that a root cause analysis be permitted, consistent with previously-
issued special permits, to determine if the fault indicates a systemic
issue. Disqualification is only appropriate, according to the
commenters, if a systemic issue exists, and failures can result from
isolated causes. One operator would also clarify that these
requirements apply to base pipe material rather than flanges, gaskets,
etc. Another suggested that multiple test failures can actually be
beneficial, because they prompt additional failure analyses that better
assure the integrity of the non-failed pipe.
Response
PHMSA agrees that a single failure can reflect an isolated cause
and should not disqualify an entire segment from operation at an
alternative MAOP if it can be demonstrated that the failure is not
indicative of a problem that could affect the rest of the pipeline
segment. PHMSA has revised the final rule to allow a root cause
analysis of any failures as a way of justifying qualification of a
pipeline segment. Root cause analysis must demonstrate that failures in
alternative MAOP pipeline segments are not systemic. Operators are
required to notify PHMSA of the results of their evaluations, which
will allow us to validate their conclusions.
Section 192.328(e), Cathodic Protection
INGAA and seven pipeline operators suggested that this paragraph be
deleted, since it duplicates requirements in Sec. 192.455. One of the
operators further commented that whether cathodic protection was
operational within 12 months becomes irrelevant once the line is
assessed and its condition is known.
Response
PHMSA recognizes that Sec. 192.455 requires that cathodic
protection be operational within 12 months of placing a pipeline in
service but does not consider the requirement in this rule duplicative.
Operators who complied with Sec. 192.455 will, of course, meet this
criterion for operation at alternative MAOP. Those who did not install
cathodic protection within 12 months of initial operation will not,
whether or not Sec. 192.455 was effective at the time. PHMSA considers
it critical that cathodic protection be provided as quickly as possible
after construction, because there are some forms of corrosion that can
result in high corrosion rates (e.g., microbiological corrosion and
corrosion from current
[[Page 62159]]
faults) producing significant loss of pipe wall in a short period of
time. Operation at alternative MAOP is thus not allowed for those
pipelines for which cathodic protection was not provided within 12
months of initial operation.
PHMSA has moved this requirement from Sec. 192.328, a section
addressing construction requirements, to Sec. 192.620(d)(8), a section
addressing operations and maintenance requirements. PHMSA believes that
this change will help emphasize that this is not simply a re-statement
of the requirement in Sec. 192.455.
Section 192.328(f), Interference Currents
Three pipeline operators supported the proposed requirements in
this subparagraph (one with the understanding that Sec. 192.473 will
govern for an existing Class 1 pipeline). Taking a contrary position,
another operator urges PHMSA to delete this paragraph because the
requirement is already addressed in the regulations and it is difficult
to address all interference issues during construction without active
cathodic protection (cathodic protection is not required to be in
service until 12 months after construction).
Response
It is important to address the potential for interference currents
as early as possible. Some pipelines have experienced significant wall
loss in the first months of operation due to the effect of interference
currents. While it may be true that all interference currents cannot be
identified before cathodic protection is in operation, many can be
anticipated and remediated during construction. These include the
effects of electric transmission lines or electrified trains sharing or
paralleling a right of way, or other ground beds in proximity to the
pipeline's route. Operators need to address, during construction,
interference currents that can be anticipated. Review of cathodic
protection effectiveness once it is in operation may identify
additional issues, and operators need to deal effectively with these.
It is not necessary, however, and potentially deleterious to pipeline
integrity to delay all actions addressing interference currents until
this time. The provisions proposed in the NPRM remain unchanged in the
final rule.
C.2.4. Eligibility for and Implementing Alternative MAOP
Section 192.620(a), Calculating an Alternative MAOP
Most commenters from the pipeline industry objected that the
proposed requirements for calculating an alternative MAOP did not
recognize that class locations may change once a pipeline is in
service. They noted that Sec. 192.611 recognizes this for conventional
MAOP pipelines, and allows operation following a class change at a
higher MAOP than would be required for new pipe in that class provided
that testing was performed at a sufficiently high pressure. The
commenters sought similar treatment for alternative MAOPs in this
paragraph and conforming changes to the language in Sec. 192.611
concerning class location changes. These commenters also noted that the
proposed rule does not explicitly address compressor stations, meter
stations, etc.
Two pipeline operators would reduce the test factor for Class 2
locations from 1.5 to 1.25. They contended that this would allow
testing of Class 1 and 2 pipelines to be done together, thereby
minimizing environmental disruption that would be associated with
separately testing Class 2 to a higher factor. They noted that testing
of both classes together would not be possible with a specified test
factor of 1.5 for Class 2, since this would overstress the Class 1 pipe
(i.e., exceed 100 percent SMYS).
One operator suggested allowing a test factor of 1.25 for existing
pipelines and requiring 1.5 only for lines installed after the
effective date of this rule. They contended that specifying 1.5 as a
design factor for Class 2 results in the alternative MAOP for Class 2
pipe segments being less than currently allowed for existing pipelines.
Two operators suggested that PHMSA amend the proposed rule to
explicitly state that the design factors will increase for facilities
(stations, crossings, fabricated assemblies, etc.) upgraded in
accordance with the rule. One suggested stating that an increase of
approximately 11 percent is allowed. The other suggested specific
design factors of 0.56 for station pipe, 0.67 for fabricated assemblies
and uncased road/railroad crossings in Class 1 areas, and 0.56 for such
assemblies/crossings in Class 2 locations.
The state pipeline safety regulatory agency commented that the rule
should contain only one provision regarding the test pressure used in
determining the MAOP. This commenter noted proposed Sec.
192.620(a)(2)(ii) limits MAOP to 1.5 times the test pressure in Class 2
and 3 locations and that proposed Sec. 192.620(c)(3) allows 1.25 times
test pressure in all classes. The commenter contends that a reference
in the latter requirement to the former creates a confusing
circularity.
Response
PHMSA agrees that the proposed regulation could be more restrictive
than existing requirements in Sec. 192.611 in the event of a class
change. As noted in the comments, the existing regulation allows
operation at a higher MAOP following a class change (i.e., higher than
would be required for a new pipeline installed in that class location)
provided that testing has been conducted at a sufficiently high
pressure to demonstrate adequate safety. PHMSA has revised the final
rule to be more consistent with Sec. 192.611 in allowing operation at
a higher pressure following a class change.
PHMSA has reduced the required test pressure for existing pipelines
(i.e., pipelines installed prior to the effective date of the rule) in
Class 2 locations to 1.25 times MAOP. This is consistent with Sec.
192.611(a)(1). However, if Class 2 pipeline is tested at 1.25 times
MAOP, then operation at an increased alternative MAOP following a class
change is not allowed. Such testing does not provide sufficient
assurance of safety margin for the higher population Class 3 areas.
Operators who desire to operate at higher pressures following a change
from Class 2 to Class 3 must test their pipe at 1.5 times alternative
MAOP.
PHMSA has included alternate design factors for existing facilities
and fabricated assemblies to be operated at alternative MAOP. PHMSA
does not agree that design factors for facilities and fabricated
assemblies are needed for new installations (i.e., those constructed
after the effective date of this final rule). PHMSA expects design
factors for new facilities (stations, crossings, fabricated assemblies,
etc.) to be in accordance with Sec. 192.111(b), (c), and (d).
Section 192.620(b), When may an alternative MAOP be used?
Proposed paragraph b(6) limited eligibility for an alternative MAOP
for pipeline segments that have previously been operated to those that
have not experienced any failure during normal operations indicative of
a fault in material. A number of commenters objected to this
limitation, which is similar to the limitation in proposed Sec.
192.328(d) described above. Here, again, the commenters indicated that
root cause analysis should be allowed and operation at an alternative
MAOP
[[Page 62160]]
should be proscribed only if the evaluation reveals a systemic issue.
GPTC requested that paragraph b(3) be clarified. That paragraph
requires that segments to be operated at alternative MAOP must have
remote monitoring and control provided by a supervisory control and
data acquisition system. GPTC requested that PHMSA clarify the degree
of ``control'' that is required and questioned whether remote control
of flow and pressure are required or if remote control of valves is all
that was intended.
One pipeline operator requested that either this paragraph or
existing Sec. 192.611 be revised to clarify the applicability of the
current 72/60/50 percent SMYS limitation on hoop stress. The operator
believes it is unclear when and if the Sec. 192.611 limitations on
hoop stress apply if an alternative MAOP is used.
Response
PHMSA agrees that exclusion from operation at an alternative MAOP
is appropriate only if a failure during mill hydrostatic testing,
construction hydrostatic testing, or operation is indicative of a
systematic issue. PHMSA has revised the final rule here (in this
paragraph and in Sec. 192.328(d) above) to allow root cause analysis
with operators required to notify PHMSA of the results.
Control requires that operators monitor pressures and flows as well
as compressor start-up and shut-down. Valves must also be able to be
remotely closed. The final rule has been modified to make these
requirements clear.
PHMSA has revised Sec. 192.611 to include hoop stress limits
applicable to pipeline operating at alternative MAOP.
Section 192.620(c), What must an operator do to use an alternative
MAOP?
INGAA and four pipeline operators suggested that an engineering
analysis should be allowed for existing pipe that was not tested to 125
percent of the alternative MAOP. They noted that some existing pipe may
have been tested to higher pressures but not quite to 125 percent, and
that this pipe should not be automatically excluded. They noted that
experience shows that the vast majority of existing pipe is tested
successfully without systemic problems, and that the allowance for 95
percent vs. 100 percent of girth weld examinations in proposed Sec.
192.328(b)(2) establishes a precedent for allowing existing pipe that
can not fully meet new pipe criteria to operate at an alternative MAOP.
One pipeline operator suggested that the rule either state that
pressure test must be at 125 percent of alternative MAOP for Classes 1,
2, and 3 or be revised to refer to the factors in Sec.
192.620(a)(2)(ii). They contended the proposed language was unclear as
to whether 125 percent is sufficient in all class locations.
A state pipeline safety regulatory agency again suggested that the
rule should contain only one provision regarding test pressure (see
discussion under Sec. 192.620(a) above).
Several commenters addressed training and qualification
requirements in proposed Sec. 192.620(c)(5). The state agency noted
that they duplicated proposed Sec. 192.328(a)(2)(ii) and essentially
applied operator qualification (OQ) requirements (subpart N) to
construction personnel. The state agency suggested it would be simpler
and less confusing if it were done in subpart N. One pipeline operator
also suggested deleting paragraph c(5) and referring to subpart N. This
operator noted that the proposed rule used undefined and vague
language--terms such as QC and integrity verification (which could be
confused with assessments under subpart O). The operator further noted
that subpart N requires OQ and that the meaning of its requirements is
well known.
GPTC requested clarification that the requirements are only
applicable to segments that operate at an alternative MAOP and as to
the meaning of the term ``integrity verification method.''
Response
PHMSA does not agree that an engineering analysis provides an
adequate basis to justify operation at alternative MAOP. Operators who
desire to use an alternative MAOP for existing pipelines that were not
tested to sufficient pressures should re-test their pipelines.
PHMSA has revised the final rule to refer to paragraph (a) for test
pressures rather than duplicating them. PHMSA agrees that this change
could help avoid confusion.
PHMSA agrees that applying the known requirements of subpart N,
related to the qualification of personnel performing work on the
pipeline, would likely cause less confusion than specifying the
alternative, but similar, requirements included in the proposed rule.
Pipeline operators are familiar with subpart N, and their training
programs under that subpart have been subjected to audits by PHMSA or
states, as appropriate. By its terms, though, subpart N does not apply
to construction tasks, since they are not ``an operations or
maintenance task''--one part of the four-part test in Sec. 192.801(b).
PHMSA has revised this final rule to provide that ``construction''
tasks associated with implementing alternative MAOP be treated as
covered tasks notwithstanding the definition in Sec. 192.801(b). For
those tasks, then, the requirements of subpart N will apply. This
change obviates the concerns expressed by GPTC and the state agency.
(PHMSA disagrees with the state comment, however, that the requirement
as proposed duplicated Sec. 192.328(a)(2)(ii), as the latter
requirement applied only to girth weld coating and not to all
construction-related tasks.)
C.2.5. Operation and Maintenance Requirements
Section 192.620(d), Additional O & M Requirements
Two pipeline operators and one state pipeline regulatory agency
suggested that covered pipelines should be held to the same
requirements as pipelines in HCA under subpart O. They believe that
this would make most of Sec. 192.620(d) unnecessary and would increase
flexibility for operators.
The state regulator noted that it would avoid confusion that might
be created for covered pipelines that would be subject to both sets of
requirements. One operator commented that no technical basis is
provided for the proposed requirements, while subpart O is based on
science and research.
Response
PHMSA disagrees with these comments and has not changed the final
rule because some provisions are more restrictive than subpart O.
Section 192.620(d)(1), Identifying Threats
INGAA and three pipeline operators suggested eliminating the
requirement for a threat matrix and the implied need for additional
preventive and mitigative measures. They noted that operation at
incrementally higher pressures does not inherently increase risk or
introduce new threats and that the proposed rule already includes
requirements sufficient to address the incremental change.
Response
PHMSA does not agree that the rule necessarily addresses all
threats to a pipeline. The rule addresses many known threats; however,
other threats may exist or develop that may affect the pipeline's
integrity. It is up to the operator to identify and evaluate possible
pipeline threats and therefore PHMSA retained the requirement to
identify and evaluate threats consistent with Sec. 192.917. The term
``assess'' was changed to ``evaluate'' to avoid
[[Page 62161]]
confusion with a similar term used in integrity management.
Section 192.620(d)(2), Notifying the Public
INGAA and five pipeline operators would eliminate the requirements
in this proposed section. They contended they are unnecessary as they
duplicate requirements in existing Sec. 192.616 for public education.
They further contended that a dedicated notification, specific to
operation at a higher pressure, is not needed. One operator would
delete subparagraph (d)(2)(ii) and replace it with a one-time
notification before operation under an alternative MAOP begins. This
operator believes that the proposed requirement for a continuing
information program is excessive, but that a one-time notification
could be appropriate.
Response
Because of the higher consequences of operating a pipeline at a
higher alternative MAOP (and thus a greater impact radius), PHMSA
believes that additional public information is necessary to inform any
stakeholders living along the right-of-way of this increase. Where the
alternative MAOP pipeline is in an HCA already identified per Subpart
O, then no additional notification is necessary beyond what is already
required.
Section 192.620(d)(3), Responding to an Emergency in High Consequence
Areas
Most industry commenters suggested deleting the requirement that
operators be able to remotely open mainline valves. They maintained
this requirement is unnecessary as an emergency response measure and is
contrary to the operating practice of many gas transmission pipeline
operators. Some also opposed a requirement for remote pressure
monitoring, indicating that it would be costly to provide and would add
no value. AGA commented that the language relating to remote control of
valves was too prescriptive and could have the unintended consequence
of requiring operators to make their safety procedures less stringent
(presumably by allowing remote opening of valves).
GPTC and two pipeline operators questioned the requirement for
remote valve operation if personnel response time to the valves exceeds
one hour. They argued that the one-hour criterion is arbitrary and not
justified by research. One operator suggested that it is also counter
to experience. These commenters also noted that it is unclear how the
response time is to be applied, from the time of notification of an
event, from the time a responder is requested to go to the valve
location, or from some other triggering event. GPTC suggested that
PHMSA consider a requirement based on mileage, similar to Sec.
192.179. One operator indicated that the need for remote control should
be based on risk analysis rather than an arbitrary specified response
time.
Response
PHMSA agrees that the proposed requirement that operators be able
to remotely open mainline valves is not needed for emergency response.
PHMSA agrees that it is more conservative to require local action to
open valves that may have been closed in response to an emergency.
PHMSA has modified the final rule to eliminate the requirement that
operators be able to remotely open valves. PHMSA considers it important
to be able to monitor pressure in order to know that valve closure has
been effective. PHMSA has retained this requirement.
PHMSA considers a one-hour response time appropriate and
reasonable. It provides time to respond to events while limiting the
consequences of an extended conflagration. In the final rule, PHMSA has
clarified that the one-hour period begins from the time an event
requiring valve closure is identified in the control room and is to be
determined using normal driving conditions and speed limits.
Section 192.620(d)(4), Protecting the Right-of-way
All commenters except the state pipeline safety regulatory agency
and the steel/pipe manufacturers addressed this section. All contended
that the requirement to patrol the right-of-way 26 times per year was
excessive and that experience indicates that more frequent patrolling
does not prevent pipeline events. They maintained that the proposed
frequency has no apparent basis other than that it is the patrolling
frequency required for hazardous liquid pipelines and that application
of a hazardous liquid pipeline frequency to gas transmission lines is
inappropriate.
One operator noted that its experience with monthly patrols has
demonstrated that there is very little excavation activity during
winter and the summer growing season, making patrols then of little
value. The commenters' proposals for alternate patrolling intervals
varied, with some suggesting intervals that would vary based on the
class location. INGAA suggested patrolling every 4\1/2\ months and
after known events.
INGAA and one pipeline operator suggested deleting the requirement
for a soil monitoring plan, because it would be costly and only
duplicates other existing requirements.
INGAA and six pipeline operators suggested deleting the requirement
to maintain depth of cover. In its place, they would require restoring
depth of cover or providing appropriate preventive and mitigation
measures only where damage may occur due to loss of cover. They noted
that maintaining the original depth of cover is impractical and
unnecessary. Normal erosion and other events can reduce depth of cover,
but that reduction does not necessarily lead to an increased risk of
damage. Action may be needed in limited circumstances and providing
other protection in those circumstances may be more effective and less
costly than restoring the original depth of cover. One operator
suggested that a monitoring/maintaining depth of cover requirement
should be driven by events or risk analysis and that discussion in the
preamble of the NPRM implied such an approach. This operator suggested
allowing engineered solutions in addition to restoring depth of cover.
INGAA and four pipeline operators would delete or relax the
requirement for line-of-sight pipeline markers. INGAA noted that
discussion at the March 2007 public meeting indicated that such markers
add no value. One operator suggested that it would be more effective to
emphasize one-call damage prevention in the preamble of the final rule.
Another operator noted that installation of such markers is ``non-
trivial,'' and that there is no data or analysis supporting the need
for them. Yet another operator commented that the intent of the
requirement is unclear and suggested that circumstances other than
agricultural areas and large bodies of water (exclusions included in
the proposed rule) would also make it difficult to install line-of-
sight markers (e.g., steep terrain, swamps).
INGAA and five pipeline operators objected to what they
characterized as an ``open ended'' requirement to implement national
consensus standards for damage prevention. These commenters suggested
that the requirements focus on the damage prevention best practices
identified by the Common Ground Alliance (CGA) and require that
operators implement the CGA best practices that apply to their
situation. One operator suggested that operators be allowed to evaluate
and choose among CGA practices. Another operator also supported a right
to choose, indicating that the CGA guide includes no expectation that
operators will adopt all best practices.
[[Page 62162]]
INGAA and five pipeline operators objected to the proposed
requirement for a right-of-way management plan, because it duplicates
existing requirements for damage prevention.
Response
PHMSA has revised the required patrol frequency to once per month,
at intervals not to exceed 45 days. The decision to reduce the
patrolling frequency from 26 patrols per year was based on further
analysis of the value added by the cost of additional patrolling,
PHMSA's greater experience with administering special permits, and
comments from industry and public advocates supporting risk-based
requirements rather than a one-size-fits-all approach. PHMSA believes
that the right of way management plan required by Sec.
192.620(d)(4)(vi), coupled with the patrolling requirement, will
provide appropriate safety coverage through requiring an operator to
develop and implement an array of actions based on the risk of third-
party damage to the pipeline. These preventative actions may well
include additional patrolling above what is required by this rule in
areas that are more heavily-populated or that possess greater chances
for third-party activities in the vicinity of a pipeline.
PHMSA has retained the requirement for a soil monitoring program.
Gas transmission pipelines are often located in areas that can exhibit
unstable soils, such as clay, hills, and mountainous areas. It is
important to assure that stresses caused by soil movement do not damage
pipelines in these areas with reduced design safety factors. PHMSA
recognizes that operators may already address these issues in their
damage prevention plans or other operating and maintenance procedures.
If so, an additional plan is not required. Operators must be able to
demonstrate, during regulatory audits, that soil monitoring is
addressed within their procedures.
PHMSA has retained the requirement for line-of-sight pipeline
markers. Outside damage is the most significant threat to gas
transmission pipelines, resulting in the greatest number of accidents.
These accidents occur despite current requirements for pipeline
markers. Those requirements in Sec. 192.707 already require that
markers be maintained ``as close as practical'' in the areas required
to be covered. PHMSA continues to believe that it is important to
provide line-of-sight markers for pipelines operating at alternative
MAOP in order to reduce the frequency of outside damage. PHMSA supports
one-call programs, and regularly takes actions to encourage and foster
their use. Still, damage incidents occur. It is important to reinforce
the need for using a one-call program by providing visual evidence that
a pipeline is located in an area subject to potential excavation.
At the same time, PHMSA recognizes that installation of line-of-
sight markers is not feasible in all locations. The rule does not
require installation of line-of-sight markings in agricultural areas or
large water crossings such as lakes and swamps where line-of-sight
markers are not practicable. The marking of pipelines is also subject
to FERC orders or environmental permits and local laws/regulations. The
rule does not require installation where these other authorities
prohibit markers.
PHMSA also retained the requirement for a right-of-way management
plan since PHMSA data indicates recurring similarities in pipeline
accidents on construction sites where better management of the right-
of-way could have prevented the accidents. This provision is not
redundant with existing damage prevention program requirements, but
requires operators to take further steps to integrate activities under
those programs to provide for better protection of the right-of-way.
Section 192.620(d)(5), Controlling Internal Corrosion
INGAA, GPTC, four pipeline operators and the state pipeline safety
regulatory agency would require a program to monitor gas quality and to
remediate internal corrosion as needed but would delete all the
specific requirements in this section. One operator suggested that a
program complying with Subpart I is all that is needed. The state
regulatory agency noted that the NPRM provided no rationale for more
stringent or prescriptive requirements than those recently published as
Sec. 192.476.
Two pipeline operators objected to the requirement for filter
separators, contending that these devices are not effective for dealing
with upsets involving free water and can provide a false sense of
security. One suggested that other actions could be required to assure
gas quality. Two other operators suggested that properly designed gas
separators would be as effective as filter separators.
One operator objected to requirements for cleaning pigs,
inhibitors, and sampling of accumulated liquids. Another opposed the
requirement for inhibitors. These operators noted that these actions
are not needed if gas monitoring confirms no deleterious constituents.
They maintained that the requirements are unnecessary and can
potentially result in unintended consequences and risks.
AGA contended that operators should be allowed to determine
appropriate methods for monitoring gas quality and that these methods
need not always require testing by individual operators. AGA believes
this is especially true if tariffs and operating experience demonstrate
the absence of contaminants. One pipeline operator asked that PHMSA
clarify that the required chromatographs are for analysis of corrosive
constituents and need not provide complete analysis for heating value
or other purposes.
Two pipeline operators suggested that PHMSA define deleterious gas
stream constituents of concern. Two pipeline operators suggested that
the limits on gas constituents should be deleted or revised based on
research and testing. They believe that the proposed limits are not
technically justified. One further noted that deleterious effects may
result from contaminants acting ``in concert.''
One pipeline operator would revise the requirement for review of an
operator's internal corrosion monitoring and mitigation program to
annual review because there is no technical justification for quarterly
reviews. Another operator suggested that the gas quality requirements
be deleted, as they may conflict with tariffs and result in duplicate
enforcement. This operator also suggested that sampling intervals be
established by reference to section Sec. 192.477 and agreed that a
requirement for quarterly review of internal corrosion monitoring
programs is excessive.
Response
PHMSA concludes that the proposed requirements do not duplicate or
conflict with those in the recently published Sec. 192.476. The latter
requirements deal principally with design considerations related to
internal corrosion, while those included here address monitoring to
determine whether conditions conducive to such corrosion occur.
Similarly, Sec. 192.477 only requires monitoring if corrosive gas is
present. The requirements included here specify contaminants to be
monitored and limits to be achieved. Since Sec. Sec. 192.476 and
192.477 represent the requirements in subpart I related to internal
corrosion, PHMSA does not agree that a program complying with subpart I
alone is sufficient.
PHMSA has revised the requirement for use of cleaning pigs,
inhibitors, and collection of accumulated liquids to apply only in
those situations in which corrosive gas is determined to be
[[Page 62163]]
present. For the particular case of hydrogen sulfide, PHMSA has
specified a limit (0.5 grain per hundred cubic feet, 8 parts per
million (ppm)) above which this requirement applies.
PHMSA has retained the requirements for gas monitoring. It is
important to monitor the gas stream to assure that internal corrosion
will not occur or will be identified if corrosion does occur.
Continuous monitoring is the most effective way of doing this. PHMSA
agrees that monitoring equipment required by this rule is for the
purpose of analyzing corrosive gas constituents and need not provide
estimates of heating value or other characteristics. Operators can rely
on others (e.g., those supplying gas to them) to perform monitoring,
but they must assure that such monitoring covers all gas streams and
meets the requirements of this rule, including the need for continuous
monitoring. PHMSA has also retained the requirement to review the
internal corrosion monitoring program quarterly. Such reviews are
needed to help assure that upset conditions that could potentially
cause internal corrosion are identified and addressed promptly. Annual
reviews are insufficient to do this.
PHMSA has revised the limit for hydrogen sulfide to 1.0 grain per
hundred cubic feet, or 16 ppm. (PHMSA has also presented this limit in
both forms of measurement, as suggested by one commenter). This limit
is more consistent with typical tariff limits. At the same time, the
final rule requires that additional mitigative actions, including use
of cleaning pigs and inhibitors be required when the hydrogen sulfide
content exceeds 0.5 grain per hundred cubic feet, as this concentration
increases the likelihood of internal corrosion.
The final rule clarifies that deleterious gas stream constituents
also include entrained or suspended solids (regardless of size) that
are detrimental to the pipeline or pipeline facilities.
Section 192.620(d)(6), Controlling Interferences That Can Impact
External Corrosion
Two pipeline operators requested that we clarify that interference
surveys are only required where interference is likely, are to be
developed using operator judgment, and can be performed using voltage
measurements versus ``current.''
Response
PHMSA has clarified the final rule to require that surveys be
performed in areas where interference is suspected. Operators should
consider the proximity of potential sources of interference, including
electrical transmission lines, other cathodic protection systems,
foreign pipelines, and electrified railways in deciding where surveys
are needed. Operators must conduct surveys capable of detecting the
effect of interfering currents, but these surveys need not measure
``current'' directly.
Section 192.620(d)(7), Confirming External Corrosion Control Through
Indirect Assessment
INGAA and four pipeline operators requested that this section be
revised to require close interval survey (CIS) alone versus one of CIS,
direct current voltage gradient (DCVG), or alternating current voltage
gradient (ACVG). One of these operators requested clarification that
indirect examination is not necessary if additional measures are taken
to assure the integrity of the pipeline. Yet another operator suggested
that this section be revised to allow other methods of indirect
assessment, noting that C-SCAN (which is a current measurement
technique) is one possibility that appears to be precluded by the
proposed language. All of these commenters plus three additional
pipeline operators requested that the timeframe for conducting these
examinations be relaxed from six months to one year. They noted that
six months may often be impractical because of limitations associated
with seasonal weather.
One pipeline operator would delete the proposed requirement for a
coating survey of existing pipelines, maintaining that this examination
is not needed, since the results of ILI and CIS show that the
combination of coating and cathodic protection is working to protect
against corrosion. This operator would move the requirement for
indirect survey and coating damage remediation to Sec. 192.328 to make
it clear that this is a construction requirement applicable to new
pipelines only. Another operator also commented that requirements to
remediate construction damaged coating should be limited to new pipe
only. This operator further requested deleting the proposed requirement
to repair all voltage drops classified as moderate or severe by
National Association of Corrosion Engineers (NACE), since it is
unnecessary and impractical to repair every voltage drop. Another
operator commented that operators should be allowed to develop specific
repair criteria based on their experience.
INGAA and four pipeline operators would relax the proposed
requirement to remediate construction coating damage to require either
remediation or appropriate cathodic protection. They suggested that the
proposed requirement conflicts with the NACE standard referenced in
this section (NACE RP-0502-2002) and that coating remediation is not
needed as cathodic protection provides adequate protection for areas
affected by coating holidays. Another operator noted that the NACE
defect classification guidelines are qualitative and that
interpretation differences could result in differing repair
expectations.
INGAA and two pipeline operators recommended relaxing the
requirement to integrate indirect assessment results with ILI from six
months to one year. They believe that more rapid integration is not
needed and that the value of quicker integration is not explained in
the NPRM. Another operator suggested there is an inconsistency in that
paragraph (ii) requires action based on the results of one assessment
while paragraph (iii) requires that the results of two assessments be
integrated.
INGAA and three pipeline operators would delete the periodic
assessment requirements of proposed paragraph (iv). They would move the
requirements for location of CIS test points in proposed subparagraph
(B) to Sec. 192.328, as they contended these are more appropriate as
construction requirements. These commenters would further revise the
CIS location requirements to state that a CIS test station must be
within one mile of each HCA, versus within each HCA. They contended
that it is not practical to require a test station within each HCA,
noting that the length of the pipeline in some HCAs may be very short.
Another operator would combine subparagraphs (A) and (B).
Response
CIS is a technique to locate areas of poor cathodic protection and
is considered a macro tool. Micro tools, such as DCVG or ACVG, must be
used to locate small but critical coating holidays. C-SCAN, which is a
current measurement technique, is considered a macro tool and will only
find large coating holidays. Small coating holidays can be just as
critical as large ones, especially in areas where cathodic protection
potentials can be depressed. PHMSA considers it important to monitor
coating condition. The comments suggesting that macro tools be allowed
appear to be based on the premise that small coating holidays are not
important as long as cathodic protection continues to protect the
pipeline. As discussed above, PHMSA does not agree with this
presumption, and here, again, does not agree that
[[Page 62164]]
either coating or cathodic protection is required; both are needed.
PHMSA recognizes that if one accepts the presumption that assuring
coating integrity is not important on pipelines subject to cathodic
protection, then prompt resolution of coating issues is not important
either. Since PHMSA does not accept the premise, PHMSA has not relaxed
the proposed timeframes for conducting surveys or integrating results.
In particular, PHMSA does not agree that a one year interval should
be allowed to assess coating adequacy. Experience has demonstrated that
significant corrosion can occur during very short intervals. PHMSA
notes that the proposed requirement potentially extends the period
between the beginning of pipeline operation and coating assessment to
18 months--12 months after operation in which cathodic protection must
be made operational (Sec. 192.455(a)(2)) plus the six months allowed
here. PHMSA considers this to be the maximum period that should be
allowed before determining coating adequacy. Proper planning and
scheduling should allow operators to accommodate weather and other
scheduling concerns. Operators can delay the start of operation at an
alternative MAOP if they cannot schedule coating surveys within six
months.
PHMSA's conclusion that coating integrity is important, regardless
of the presence of cathodic protection, means that determining coating
adequacy is important for existing pipelines as well as new
construction. As such, it is not appropriate to move this requirement
to a section applicable to new construction only. Further, it is not
acceptable to rely on ILI or other assessment methods to identify
corrosion after it has occurred. The purpose here is to prevent
corrosion. ILI or other assessments are a second level of defense,
detecting corrosion after it occurs, but PHMSA does not consider them
to obviate the need for actions to prevent the problem from occurring
in the first place. CIS is a verified method of determining if all of a
segment is protected by appropriate cathodic protection potentials. The
use of CIS will allow an operator to find any ``hot spots'' along the
pipeline that could cause active corrosion. The CIS will find any
depressed locations whereas a test station survey may miss such
locations unless they are in close proximity to the test station.
With respect to proximity to a test station, PHMSA agrees that
there could be situations in which it may not be practical to locate a
test station within an HCA. This could occur, for example, when the HCA
is determined by an identified site near the outer radius of the
potential impact circle, in which case the length of pipeline in the
HCA could be very short (on the order of several feet). Still, PHMSA
does not agree that this limitation should be addressed by requiring
that a test station be within one mile of an HCA. PHMSA has revised the
final rule to require that a test station be located within an HCA if
practicable and has retained the proposed requirement that test
stations be located at half-mile intervals on pipelines to be operated
at alternative MAOP.
Section 192.620(d)(8), Controlling External Corrosion Through Cathodic
Protection
INGAA, GPTC and eight pipeline operators considered the requirement
to address inadequate cathodic protection readings in six months to be
excessive. They also noted that seasonal and land use issues make
responding within one year much more reasonable, and suggested the
proposed rule be changed accordingly. GPTC and one operator noted that
the proposed change is inconsistent with an existing PHMSA
interpretation, which states that remediation of inadequate cathodic
protection readings is required before the next scheduled monitoring.
The operator noted that this is typically one year (not to exceed 15
months), supporting the proposed change to a one-year response in this
rule.
INGAA and three pipeline operators objected to the proposed
requirement to conduct CISs after remediating cathodic protection
problems to evaluate effectiveness. They noted that a CIS is not needed
to confirm resolution of many problems (e.g., loss of power, cut cable,
short). They agreed that operators should confirm that remedial action
was appropriate and effective, but contended that a requirement to
perform a CIS after any remedial action is unjustified and excessive.
Response
As discussed above, experience has shown that significant corrosion
damage can occur over brief periods. Pipelines operating at an
alternative MAOP have less margin for corrosion than do pipelines
operating at MAOP determined in accordance with Sec. 192.111. Cathodic
protection is an important protection against corrosion damage, as
recognized by those commenting on this rule. PHMSA does not agree that
it is acceptable to wait one year to resolve known cathodic protection
problems. At the same time, PHMSA recognizes that there may be
situations in which remediation in six months is not practical. PHMSA
has revised the final rule to require operators to notify the PHMSA
Regional Office where a pipeline is located (and states where
appropriate) if inadequate cathodic protection readings are not
addressed within six months, providing the reason for the delay and a
justification that the delay is not detrimental to pipeline safety.
This will allow regulators to review the circumstances of each
situation in which resolution takes longer than six months and to make
a judgment of adequacy based on the particular circumstances.
PHMSA agrees that it is not necessary to perform a complete CIS
again to verify that any remedial action has addressed an identified
problem. Commenters are correct in noting that problems such as a cut
cable or short can result in inadequate cathodic protection readings
and that correction of these problems can be verified without a new
CIS. PHMSA has revised the final rule to require that operators verify
that corrective action is adequate, leaving the means to do so up to
the operator's discretion and judgment.
Section 192.620(d)(9), Conducting a Baseline Assessment of Integrity
Proposed Sec. 192.620(d)(9)(iii) would require that headers,
mainline valve by-passes, compressor station piping, meter station
piping, or other short portions that cannot accommodate ILI tools be
assessed using DA. INGAA and four pipeline operators objected to this
requirement as unjustified and inconsistent with previous special
permits. They suggested a change that would also allow pressure testing
or development and implementation of a corrosion control plan. They
further noted that these segments may be designed to Sec. 192.111, may
not operate at an alternative MAOP, and thus may not be subject to this
section.
One operator also noted that there may be portions of a pipeline
facility that will not be operated at an alternative MAOP. The operator
requested clarification that the proposed requirements apply only to
segments that are intended to operate at an alternative MAOP. This
commenter also suggested an exclusion for small pipe and equipment to
be consistent with a frequently asked question (FAQ) 84 on the
gas transmission integrity management Web site (http://
primis.phmsa.dot.gov/gasimp/). (The FAQ addresses whether small-
diameter piping, e.g., within a compressor station, must be considered
to be part of an HCA. It states that potential impact
[[Page 62165]]
radii should be calculated, and a determination made as to whether an
HCA exists, based on the diameter of individual pipeline segments.)
The same operator would also allow the baseline assessment for an
existing pipeline segment to be conducted before operation at an
alternative MAOP begins but within the assessment interval specified in
subpart O rather than the proposed two years. The operator contended
that there is no scientific basis to require assessments every two
years, particularly if a pipeline segment is being managed under
subpart O.
Response
PHMSA agrees that assessment of small-diameter station piping can
be performed using pressure testing and has revised the final rule
accordingly. PHMSA does not agree that it is acceptable for such a non-
piggable pipeline to be under an unspecified corrosion control plan
rather than to be subject to assessment.
PHMSA agrees that FAQ 84 addresses the same pipe, but does
not agree that it is a precedent for determining whether a small-
diameter pipeline requires assessment. An FAQ is advisory in nature and
this FAQ provides guidance in the context of integrity management, on
whether this pipeline should itself be determined to be an HCA. For
this rule, additional assessment requirements are being applied to a
pipeline operating at an alternative MAOP, regardless of whether it is
in an HCA. PHMSA has revised this paragraph to clarify that it applies
only to a pipeline operating at an alternative MAOP. Small-diameter
pipe within a station that does not operate at alternative MAOP would
not be affected by these requirements. PHMSA agrees that small-diameter
pipe, headers, meter stations, compressor stations, river crossings,
road crossings and any other pipeline facility can be designed and
constructed in accordance with Sec. 192.111 criteria and then would
not be subject to alternative MAOP integrity assessment criteria such
as ILI and DA.
PHMSA does not agree that it is acceptable to rely on assessments
that may have been performed within the time intervals allowed by
subpart O. Under subpart O, it may have been nearly ten years (in some
limited cases 15 years) since a complete assessment was performed.
PHMSA considers that more current information is needed before deciding
that it is acceptable to operate a pipeline at an alternative MAOP.
PHMSA considers the two-year period reasonable for operators to
schedule and perform assessments that will result in more current
information when the operating stresses on the pipeline are increased.
Section 192.620(d)(11), Making Repairs
INGAA and three pipeline operators noted that the repair
requirements in the proposed rule are inconsistent with subpart O and,
they believe, overly conservative and burdensome. INGAA contended that
the proposed requirements will be unachievable in many cases. Another
operator commented that the repair criteria proposed for Class 2 and 3
areas are extremely conservative and unnecessary.
Two pipeline operators suggested that this section be replaced with
a reference to subpart O, since they believe the repair requirements of
that subpart and ASME/ANSI B31.8S (referenced in subpart O) are
appropriate for pipelines operating at 80 percent SMYS.
Two pipeline operators noted that the dent repair criteria in
subparagraph (i)(A) are those for new pipelines following construction
and before commissioning and suggested that these are inappropriate for
existing pipelines. One of these operators contended that the repair
criteria for existing pipelines should be as in subpart O, Sec.
192.933(d). The other noted that there is experience demonstrating that
plain dents of much greater than two percent of pipe diameter in depth
are not a threat to pipeline integrity.
Three pipeline operators proposed alternative repair criteria. They
would require immediate repair of defects for which the failure
pressure is 1.1 times the revised alternative MAOP. They would require
repairs within one year for defects for which the failure pressure is
1.25 times the MAOP. They contended that these criteria are consistent
with those in subpart O and ASME/ANSI B31.8S and are appropriate. They
believe that the criteria in the proposed rule represent an
inappropriate shortening of the time allowed to address identified
defects.
Proposed subparagraph (i)(A) would require that an operator ``use
the most conservative calculation for determining remaining strength''
of a pipeline segment containing an identified anomaly. INGAA and four
pipeline operators contended that this requirement could be interpreted
to require that multiple calculations be performed, using all available
tools/models, to determine which is most conservative. They believe
this is inappropriate and that operators should use the most
appropriate calculational tool.
Response
PHMSA recognizes that the repair criteria in this rule are more
stringent than those in subpart O. PHMSA considers this appropriate. A
pipeline that will operate under alternative MAOP is subject to more
stress and has less wall thickness margin to failure than most
pipelines operating under subpart O (with the exception of some
grandfathered lines). Most pipelines that will be subject to this rule
will be new pipelines. PHMSA's repair criteria use safety factors
similar to those for the design of a new pipeline based upon class
location design factors, and are intended to maintain overall safety
margins at corrosion anomalies based upon all operating and
environmental factors. The net effect of the QA and O&M requirements in
this rule for construction and operation of those pipelines covered by
the rule will likely result in the need for few repairs, even with
these stricter criteria. PHMSA considers these factors of safety a key
element in assuring public safety on higher MAOP pipelines.
Similarly, PHMSA disagrees that failure pressures of 1.1 and 1.25
times MAOP are appropriate for immediate and one-year (respectively)
repairs for all class locations. Class 2 and Class 3 locations require
more stringent safety factors for anomaly evaluation and remediation
due to the higher consequences to public safety that may be caused by a
leak or rupture of the pipeline. As discussed extensively throughout
this response to comments, pipelines to be operated at alternative MAOP
will operate at higher pressures with less margin to failure than most
pipelines. Use of repair criteria different from and requiring repairs
quicker than in subpart O is appropriate.
With respect to dents, the repair criteria of Sec. 192.309(b)
apply only for dents found during construction baseline assessments
(i.e., for new pipelines). PHMSA notes that this section already
requires repair of two percent dents for pipelines over 12\3/4\ inches
in diameter. The criteria for repairing dents on existing pipelines and
subsequent assessments on new pipelines and existing pipelines are in
Sec. 192.933(d).
PHMSA acknowledges that an operator cannot know which method for
calculating remaining strength is most conservative without applying
each method. Questions have been raised concerning the applicability of
some current methods for calculating the remaining strength of high-
strength pipelines and greater depth corrosion anomalies in all field
operating
[[Page 62166]]
conditions. PHMSA is planning to sponsor a public meeting to review
these questions and help determine the adequacy of existing
calculational methods for the kind of high-strength pipe that will
operate at alternative MAOP. PHMSA will propose changes to this rule at
a later date, if appropriate.
C.3. Comments on Regulatory Analysis
One pipeline operator submitted two comments relating directly to
the regulatory analysis supporting the proposed rule.
First, the operator contends that the expected reduction in
expenditure for compressors for new pipelines should not be claimed as
a benefit. The operator contended that reductions may be realized for
existing pipelines that operate at an alternative MAOP but not for new
pipelines.
Second, the operator contended that PHMSA should not state that new
design factors will result in increased capacity for new pipelines and
noted that new pipelines will be designed for the required capacity.
The effect of the proposed rule will be to reduce costs by allowing the
use of thinner-walled pipe.
Response
PHMSA understands that the operator's statement that new pipelines
will be designed for the required capacity is at the heart of both of
these comments. The operator essentially contended that new pipelines
that will be so designed will see no increased capacity or change in
costs as a result of this rule. PHMSA does not agree. New pipelines
designed with alternative MAOPs should mean less cost to the customer/
public, and thus a benefit to society, due to less capital costs for
the same natural gas through-put/flow volumes. Existing pipelines will
be able to carry up to an additional 11 percent natural gas flow
volumes based upon the overall design of the pipeline and compressor
stations with this alternative MAOP.
In the absence of this rule (or of obtaining a special permit to
operate at alternative MAOP) new pipelines would need to be designed
for less capacity or at increased cost (due to the need to use thicker-
walled pipe). Thus, there is a societal benefit to this rule in that it
will allow more gas to be transported at a higher standard of safety
for a given dollar investment. The companies designing and constructing
new pipelines under this rule will also realize a benefit, since in the
absence of this rule (or a special permit addressing the same issues)
they would either have to carry less gas or incur additional costs.
PHMSA has revised the discussion in the regulatory analysis to help
make this point more clearly.
D. Consideration by the Technical Pipeline Safety Standards Committee
(TPSSC)
The TPSSC met on June 10, 2008, and considered the proposed rule.
During this discussion, PHMSA provided its preliminary views of changes
that might be made in response to comments submitted in response to the
proposed rule.
PHMSA informed the TPSSC that some changes would be made in rule
structure, moving some requirements to other sections for better
applicability (e.g., requirements applicable to existing pipelines
would be moved from the section of the rule in which construction
requirements are located).
PHMSA informed the TPSSC it has not adopted the suggestion by the
state pipeline safety regulatory agency that submitted comments
supported by its director (a member of the committee) to place the rule
in a separate subpart, as that is counter to the general structure of
part 192.
TPSSC members expressed concern, as did many commenters, about
reliance on individual standards or tests. In the final rule, PHMSA has
allowed use of equivalent methods (e.g., for the macro etch test,
hardness limits, type of crack arrestors).
PHMSA informed the TPSSC that the vast majority of commenters
objected to the proposed requirement for mill hydrostatic inspection
tests of longer duration and that, as a result, that change would not
be included in the final rule. PHMSA also noted that most industry
commenters noted that the proposed rule did not make allowances for
changes in class location after a pipeline is in service, as do the
existing regulations.
The anomaly repair requirements were of concern to industry, who
asserted the requirements were overly conservative. PHMSA informed the
TPSSC that this issue is complicated by questions recently raised
concerning the applicability of remaining strength calculational
methods to high-stress pipelines and that resolving those questions
before completing this rule would delay issuance of the rule. PHMSA
stated that it would conduct a public meeting later this year to
address the global issue of appropriate calculational methods and
repair criteria. Changes to this or other regulations requiring
pipeline repair may be appropriate following that workshop.
Treatment of existing and pending applications for special permits
was a significant concern for several members of the TPSSC. PHMSA noted
that the standards in the final rule are very similar to those applied
in recent special permits. PHMSA reported its intention to continue to
review pending special permit applications while this rulemaking
proceeded. Upon issuance of the final rule, PHMSA expects operators
desiring to use alternative MAOP to comply with the rule. PHMSA will
examine special permits that have already been granted, as appropriate,
to determine if any modifications are needed in light of the outcome of
this rulemaking.
Subsequent to discussion, the TPSSC voted unanimously to find the
proposed rule and supporting regulatory evaluations technically
feasible, reasonable, practicable, and cost effective, subject to
incorporation of the changes discussed by PHMSA during this meeting. A
transcript of the meeting is available in the docket.
E. The Final Rule
Revisions described in this section are changes to the
corresponding section in the proposed rule.
E.1. In General
The rule adds a new section (Sec. 192.620) to Subpart L--
Operations. This new section explains what an operator would have to do
to operate at a higher MAOP than currently allowed by the design
requirements. Among the conditions set forth in new Sec. 192.620 is
the requirement that the pipeline be designed and constructed to more
rigorous standards. These additional design and construction standards
are set forth in two additional new sections (Sec. Sec. 192.112 and
192.328) located in Subpart C--Pipe Design and Subpart G--General
Construction Requirements for Transmission Lines and Mains,
respectively. In addition, the rule makes necessary conforming changes
to existing sections on incorporation by reference (Sec. 192.7),
change in class location (Sec. 192.611), and maximum allowable
operating pressure (Sec. 192.619).
E.2. Amendment to Sec. 192.7--Incorporation by Reference
The rule adds ASTM Designation: A 578/A578M--96 (Re-approved 2001)
``Standard Specification for Straight-Beam Ultrasonic Examination of
Plain and Clad Steel Plates for Special Applications'' to the documents
incorporated by reference under Sec. 192.7. This specification
prescribes standards for ultrasonic testing of steel plates. It is
referenced in new Sec. 192.112.
[[Page 62167]]
The rule also revises the description of item (B)(1) in the table
of Sec. 192.7(c)(2), API 5L ``Specification for Line Pipe,'' (43rd
edition and errata), 2004, to indicate that it is referenced in new
Sec. 192.112 in addition to the locations at which it was referenced
previously.
E.3. New Sec. 192.112--Additional Design Requirements
The rule adds a new section to Subpart C--Pipe Design in 49 CFR
Part 192. The new section, Sec. 192.112, prescribes additional design
standards required for the steel pipeline to be qualified for operation
at an alternative MAOP based on higher stress levels. These include
requirements for rigorous steel chemistry and manufacturing practices
and standards. Pipelines designed under these standards contain pipe
with toughness properties to resist damage from outside forces and to
control fracture initiation and growth. The considerable attention paid
to the quality of seams, coatings, and fittings will prevent flaws
leading to pipeline failure. Unlike other design standards, Sec.
192.112 applies to a new or existing pipeline only to the extent that
an operator elects to operate at a higher alternative MAOP than allowed
in current regulations.
Paragraph (a) sets high manufacturing standards for the steel plate
or coil used for the pipe. The pipe would be manufactured in accordance
with Level 2 of API 5L, with the ratio between diameter and wall
thickness limited to prevent the occurrence of denting and ovality
during construction or operation. Improved construction and inspection
practices addressed elsewhere in this rule also help prevent denting
and ovality.
Paragraph (a) has been revised in response to comments to add an
alternative method (and applicable limit) for determining equivalent
carbon content. In addition, the proposed limit on equivalent carbon
content of 0.23 (Pcm formula) has been raised to 0.25. Several comments
suggested deleting the limit on the ratio of pipe D/t, but this limit
has been retained, as discussed above.
Paragraph (b) addresses fracture control of the metal. First PHMSA
expects the metal would be tough; that is, deform plastically before
fracturing. Second, the pipe would have to pass several tests designed
to reduce the risk that fractures would initiate. Third, to the extent
it would be physically impossible for particular pipe to meet toughness
standards under certain conditions, crack arrestors would have to be
added to stop a fracture within a specified length.
Paragraph (b) has been revised to allow alternate means of crack
arrest. This can include the ``mechanical'' means included in the
proposed rule but can also include other design features such as use of
composite sleeves, spacing, increases in wall thickness at appropriate
distances, etc. This paragraph has also been revised to clarify the
factors that must be considered by an operator in evaluating resistance
to fracture initiation and to make clear that this evaluation is
intended to address the full range of relevant parameters to which the
pipe will be exposed over its operating lifetime. If unexpected
situations or a change in operating conditions result in a change in
these parameters during operation, such that they are outside the
bounds of those analyzed, operators will be required to review and
update their evaluation and implement remedial measures to assure
continued resistance to fracture initiation.
Paragraph (c) provides tests to verify that there are no
deleterious imperfections in the plate or coil. The macro etch test
will identify flaws such as segregation that impact the plate or coil
quality. Surface and interior flaws such as laminations and cracking
will show up in UT testing.
This paragraph has been revised, in response to comments, to change
``mill inspection program'' to an internal quality management program
designed to eliminate or detect defects or inclusions that can affect
pipe quality and to require that such a program be implemented at all
mills involved in the process of casting the steel, rolling it into
plate, coil or skelp, and the process of manufacturing the steel into
line pipe. The revised paragraph also includes an alternative to the
macro etch test and reference to an additional standard for UT testing
the plate, coil, skelp or manufactured line pipe. (Equivalent standards
are also still allowed.)
In addition to the quality of the steel, the integrity of a pipe
depends on the integrity of the seams. Paragraph (d) provides for a QA
program to assure tensile strength and toughness of the seams so that
they resist breaking under regular operations. Hardness and UT tests
after mill hydrostatic tests would ensure that the seams did not have
defects or imperfections that were exposed by the stresses of the
hydrostatic test pressure.
Paragraph (e) requires a mill pressure test for new pipe at a
higher hoop stress than required by current regulations. The mill test
is used to discover flaws introduced in manufacturing. Because the
pipeline will be operated at a higher stress level, the more rigorous
mill test is needed to match (or exceed) the level of safety provided
for pipelines operated at less than 72 percent of SMYS. Paragraph (e)
has been revised to eliminate the proposed extension of the duration of
mill pressure tests.
Paragraph (f) sets rigorous standards for factory coating designed
to protect the pipeline from external corrosion. A QA program must
address all aspects of the application of coating that will protect the
pipeline. This would include applying a coating resistant to damage
during transportation and installation of the pipe and examining the
coated pipeline to determine whether the applied coating is uniform and
without defects. Thin spots or voids/holidays in the coating make it
more likely for corrosion to occur and more difficult to protect the
pipeline cathodically.
Paragraph (g) requires that factory-made fittings, induction bends,
and flanges be certified as to their serviceability and quality. In
addition the CE of these fittings and flanges would need to be
documented, so that welding procedures could require pre-heat
temperature to eliminate welding defects.
Paragraph (g) has been revised to clarify that the serviceability
certification must address properties such as chemistry, minimum yield
strength, and minimum wall thickness to meet design conditions. PHMSA
expects that valves, flanges and fittings should be rated based upon
the required specification rating class for the alternative MAOP and
the operator to have documented mill reports with chemistry, minimum
yield strength, and minimum wall thickness. Where specialty bends such
as hot bends are used for pipeline segments operating per the
alternative MAOP, PHMSA expects the operator to address properties such
as chemistry, minimum yield strength, minimum wall thickness and other
properties that the hot bending process could alter.
Paragraph (h) requires compressor design to limit the temperature
of downstream pipe operating at an alternative MAOP to a specified
maximum. Higher temperature can damage pipe coating. An exception to
the specified maximum is allowed if testing of the coating shows it can
withstand a higher temperature. The testing duration, qualification
procedures and results must be of sufficient length and rigor to detect
coating integrity issues for the type coating, operating and
environmental conditions on the pipeline. Operators
[[Page 62168]]
may also rely on a long-term coating integrity monitoring program to
justify operation at higher temperatures, provided the program is
submitted to and reviewed by PHMSA.
Paragraph (h) has been revised to clarify the allowed exception.
Testing must address coating adhesion and condition as well as cathodic
disbondment. Operators are required to submit their test results,
including the acceptance criteria they applied to assure themselves
that these characteristics are adequate, to the appropriate PHMSA
regional office(s) and applicable state regulatory authorities at least
60 days prior to operating at elevated temperature. (State notification
applies when the pipeline is located in a state where PHMSA has an
interstate agent agreement, or an intrastate pipeline is regulated by
that state.)
A subtle, but important, change has also been made in the language
in this paragraph. As proposed, the discharge temperature of compressor
stations would have been limited to the specified temperature. As
revised, the temperature of the nearest downstream pipeline segment to
operate at alternative MAOP must be limited. For situations in which
the pipeline segment at the discharge of a compressor station operates
at alternative MAOP, there is no practical difference. The revised
language, however, allows pipeline operators to implement an
alternative approach in which they would use pipe operating at
conventional MAOP from the discharge of a compressor station downstream
to the point at which pipe temperature will drop to the specified
limit. This may provide an alternative for situations in which it may
be difficult to limit the compressor station discharge to the specified
limit (e.g., southern locations on hot summer days). Gas coolers may be
installed at compressor stations on pipelines operating per the
alternative MAOP that need to operate above 120 degrees Fahrenheit. Gas
cooling at compressor stations is a long standing method for most
operators to reduce gas pipeline temperatures.
E.4. New Sec. 192.328--Additional Construction Requirements
The rule also adds a new section to Subpart G--General Construction
Requirements for Transmission Lines and Mains. The new section, Sec.
192.328, prescribes additional construction requirements, including
rigorous QC and inspections, as conditions for operation of the steel
pipeline at higher stress levels. Unlike other construction standards,
Sec. 192.328 would apply to a new or existing pipeline only to the
extent that an operator elects to operate at a higher alternative MAOP
than allowed in current regulations.
Paragraph (a) requires a QA plan for construction. QA, also called
QC, is common in modern pipeline construction. Activities such as
lowering the pipe into the ditch and backfilling, if done poorly, can
damage the pipe and coating. Other construction activities such as
nondestructive examination of girth welds, if done poorly, will result
in flaws remaining in the pipeline or failures during hydrostatic
testing or while in gas service. Using a QA plan helps to verify that
the basic tasks done during construction of a pipeline are done
correctly.
Field application of coating is one of these basic tasks to be
covered in a QA plan. During the course of analyzing requests for
special permits, PHMSA discovered field coatings at one construction
site which were applied at lower temperature than needed for good
adhesion to the pipe. Because coating is so critical to corrosion
protection, paragraph (a) requires quality assurance plans to contain
specific performance measures for field coating. Field coating must
meet substantially the same standards as coating applied at the mill
and the individuals applying the coating must be appropriately trained
and qualified.
Installation of the pipe into the ditch and backfilling of the pipe
are critical operations. PHMSA has found that construction and
inspection lapses during the backfilling of the pipe have resulted in
pipe denting and coating damage. Sometimes during backfilling of the
pipe there are design requirements for the installation of other
engineered items such as concrete weights at creek and water saturated
soil areas. The proper installation of these types of engineered items
is critical to ensure that the pipe and coating are not damaged and the
item is installed as required in the specifications. PHMSA has found
operator lapses in this critical QC aspect of pipeline construction.
Paragraph (b) requires non-destructive testing of all girth welds.
Although past industry practice sometimes has been to non-destructively
test only a sample of girth welds, no alternative exists for verifying
the integrity of the remaining welds. The initial pressure testing once
construction is complete does not normally detect flaws in girth welds
unless the girth weld is cracked, has severe lack of penetration or is
under undue tension stresses, which would be indicative of systemic
problems on the pipeline. PHMSA believes that most modern pipeline
construction projects include non-destructive testing of all girth
welds. However, because the regulations do not require testing of all
girth welds, an operator's records for pipelines already in operation
may not be complete on 100 percent of girth welds. To account for this,
proposed paragraph (b) would have required testing records for only 95
percent of girth welds on existing segments. This requirement has been
retained, but proposed paragraph (b) has been moved to new Sec.
192.620, as it applies to existing pipelines. This section addresses
pipeline construction.
Paragraph (c) requires deeper burial of segments operated at higher
stress level. A greater depth of cover decreases the risk of damage to
the pipeline from excavation, including farming operations.
Paragraph (d) addresses the results of the initial strength test
and the assurance these results provide that the material in the
pipeline is free of pre-operational flaws which can grow to failure
over time. Since the initial strength test is a destructive test, it
only detects flaws that would fail at the test pressure. This could
leave in place smaller flaws. To prevent this from occurring, the
proposed paragraph would have disqualified any segment which
experienced a failure during the initial strength test indicative of
flaws in the material. Most commenters objected to this provision as
too restrictive. They noted that failures can be isolated and that it
was unreasonable to preclude an entire pipeline segment from operation
at alternative MAOP because of a single failure. This paragraph has
been revised to allow conduct of a root cause examination of a failure,
including metallurgic examination of the failed pipe, as a way of
justifying qualification of the pipeline segment. If that examination
determines that the cause of the failure is not systemic, then the
pipeline segment would not be disqualified from alternative MAOP
operation. Operators must report the results of their root cause
evaluation to regulators (PHMSA Regional Office or applicable state
regulatory authorities). Review of these analyses by pipeline safety
regulators will provide oversight for operator conclusions regarding
the non-systemic nature of a failure.
Proposed paragraph (e) addressed cathodic protection on an existing
segment. This paragraph has been moved to new Sec. 192.620.
Paragraph (e) (proposed as paragraph (f)) addresses electrical
interference for new segments. During construction, sources of
electrical interference which can impair future cathodic protection or
[[Page 62169]]
damage the pipe prior to placing cathodic protection in service need to
be identified. Addressing interference at this time supports better
corrosion control. Operators will need to coordinate with electric
transmission line operators prior to pipeline construction to identify
locations of grounding structures and power line currents and voltages
and their effect on the pipe. The additional O&M requirements of new
Sec. 192.620(d)(6) require operators electing to operate existing
pipelines at higher stress levels to address electrical interference
prior to raising the MAOP.
E.5. Amendment to Sec. 192.611--Change in Class Location: Confirmation
or Revision of Maximum Allowable Operating Pressure
The proposed rule did not include a provision to amend this
section. Commenters pointed out that this section addresses changes in
class location (e.g., increase in population density near the pipeline)
during operation. The existing requirements allow continued operation
at pressures higher than would be required for new pipe installed in
the new class location, provided pressure testing has been performed at
appropriate pressures. The commenters noted that without addressing
operation at alternative MAOP in this section, the regulations would
effectively rescind the authorization provided by this rule to operate
at higher pressure whenever there was a change in class location.
PHMSA agrees that this result was not intended. This section has
been revised to include provisions for pipelines operating at
alternative MAOP substantially the same as those already provided for
existing pipelines. Operation at higher alternative pressures can
continue after a class location change, again provided that the
pipeline has been tested at appropriate pressures and is not an
alternative MAOP operating in a Class 3 location that is upgraded to a
Class 4 location. The limits on hoop stress included in this section
have been revised to reflect the higher hoop stress that will be
experienced by a pipeline at alternative MAOP.
E.6. Amendment to Sec. 192.619--Maximum Allowable Operating Pressure
The final rule amends existing Sec. 192.619 by adding a new
paragraph (d) providing an additional means to determine the
alternative MAOP for certain steel pipelines. In addition, the rule
makes conforming changes to existing paragraph (a) of the section.
E.7. New Sec. 192.620--Operation at an Alternative MAOP
The final rule adds a new section, Sec. 192.620, to subpart L of
part 192, to specify what actions an operator must take in order to
elect an alternative MAOP based on higher operating stress levels. The
rule applies to both new and existing pipelines.
E.7.1. Sec. 192.620(a)--Calculating the Alternative MAOP
Paragraph (a) describes how to calculate the alternative MAOP based
on the higher operating stress levels. Qualifying segments of pipeline
would use higher design factors to calculate the alternative MAOP. For
a segment currently in operation this would result in an increase in
MAOP. No changes were proposed in the design factors used for segments
within compressor or meter stations or segments underlying certain
crossings. PHMSA expects new pipelines operating per the alternative
MAOP to have road/railroad crossings, fabrications, headers, mainline
valve assemblies, separators, meter stations and compressor stations
designed and operated per existing design factors in Sec. 192.111.
Paragraph (a) has been revised to include new design factors for
compressor/meter stations or segments underlying certain crossings.
These factors apply to facilities in existence prior to the effective
date of this rule. Commenters pointed out that compressor stations for
existing pipelines have been designed and that failure to allow
alternative design factors for them could effectively preclude
operation at alternative MAOP for the existing pipelines of which they
are a part. PHMSA agrees this was not our intent. The additional risk
associated with use of slightly higher design factors for these
facilities is marginal. At the same time, there is little additional
cost associated with designing stations/crossings/fabrications/headers
for future pipelines to serve at the desired MAOP using existing design
factors in Sec. 192.111(b), (c), and (d). The rule includes no
alternative design factors for these facilities in future pipelines,
and operators must use the existing requirements.
E.7.2. Sec. 192.620(b)--Which Pipeline Qualifies
Paragraph (b) describes which segments of new or existing pipeline
are qualified for operation at the alternative MAOP. The alternative
MAOP is allowed only in Class 1, 2, and 3 locations. Only steel
pipelines meeting the rigorous design and construction requirements of
Sec. Sec. 192.112 and 192.328 and monitored by supervisory data
control and acquisition systems qualify. Mechanical couplings in lieu
of welding are not allowed. Although the special permits did not
expressly mention mechanical couplings, PHMSA would not have granted a
special permit if the pipeline involved had mechanical couplings.
As proposed, paragraph (b) would have excluded from consideration
any existing pipeline that had experienced a failure indicative of
materials concerns. This provision has been revised to allow root cause
analysis to determine if the failure is indicative of a systemic
problem and to preclude use of an alternative MAOP only if a failure is
determined to be systematic in nature. Results of the analysis must be
reported to regulators (PHMSA Regional Office or applicable state
regulatory authorities). This is essentially the same change made for
new pipelines in new Sec. 192.328(d), as described above. Paragraph
(b) has also been revised to include the requirement that 95 percent of
girth welds must have been examined for existing pipelines to operate
at alternative MAOP. This requirement was moved from proposed Sec.
192.328(e), as discussed above.
E.7.3. Sec. Sec. 192.620(c)(1), (2), and (3)--How an Operator Selects
Operation Under This Section
Paragraph (c)(1) requires an operator to notify PHMSA, and
applicable state pipeline safety regulators, when it elects to
establish an alternative MAOP under this section. This notification
must be provided at least 180 days prior to commencing operations at
the alternative MAOP established under this section. This will provide
PHMSA and states sufficient time for appropriate inspection which may
include checks of the manufacturing process, visits to the pipeline
construction sites, analysis of operating history of existing
pipelines, and review of test records, plans, and procedures.
Paragraph (c)(3) requires an operator to further notify PHMSA when
it has completed the actions necessary to support operation at an
alternative MAOP, by submitting a certification by a senior executive
that the pipeline meets the requirements for operation at alternative
MAOP. The certification is required by paragraph (c)(2). A senior
executive must certify that the pipeline meets the additional design
and construction regulations of this rule. A senior executive must also
certify that the operator has changed its O&M procedures to include the
more rigorous
[[Page 62170]]
additional O&M requirements. In addition, a senior executive must
certify that the operator has reviewed its damage prevention program in
light of best practices, such as CGA best practices or some equivalent
best practices, and made any needed changes to it to ensure that the
program meets or exceeds those standards or practices. The
certification must be submitted at least 30 days prior to operation at
an alternative MAOP.
E.7.4. Sec. 192.620(c)(4)--Initial Strength Testing
Paragraph (c)(4) addresses initial strength testing requirements.
In order to establish the MAOP under this section, an operator must
perform the initial strength testing of a new segment at a pressure at
least as great as 125 percent of the MAOP in Class 1 locations and 150
percent in Class 2 and 3 locations. Since an existing pipeline was
previously operated at a lower MAOP, it may have been initially tested
at a pressure less than these levels. If so, paragraph (c) allows the
operator to elect to conduct a new strength test in order to raise the
MAOP.
E.7.5. Sec. 192.620(c)(5)--Operation and Maintenance
Paragraph (c)(5) requires an operator to comply with the additional
operating and maintenance requirements of Sec. 192.620(d). An operator
must comply with these additional requirements if the operator elects
to calculate the alternative MAOP for a segment under Sec. 192.620(a)
and notifies PHMSA of that election.
E.7.6. Sec. 192.620(c)(6)--New Construction and Maintenance Tasks
Paragraph (c)(6) addresses the need for competent performance of
both new construction, and future maintenance activities, to ensure the
integrity of the segment. PHMSA now requires operators to ensure that
individuals who perform pipeline O&M activities are qualified.
Paragraph (c)(6) requires operators seeking to operate at the allowable
higher operating stress levels to treat construction tasks as if they
were covered by subpart N, ``Qualification of Pipeline Personnel.''
Subpart N (commonly known as OQ) specifies training and qualification
requirements applicable to tasks that meet a four-part test in Sec.
192.801(b). Operations and maintenance tasks on the pipeline meet this
test, and it is the requirements in subpart N that will govern training
and qualification of personnel performing these tasks on a pipeline to
be operated at an alternative MAOP. Construction tasks typically do not
meet the four-part test and are not covered under subpart N. As
proposed, paragraph (c)(6) (then designated (c)(5)) would have required
operators to take other actions to assure qualification of personnel
performing construction tasks on a pipeline intended to operate at
alternative MAOP. Commenters noted that the proposed requirements were
vague and subject to interpretation and suggested that PHMSA, instead,
rely on the known requirements of subpart N. This paragraph has been
modified, in response to these comments, to require that the
requirements of subpart N be applied to construction tasks for a
pipeline intended to operate at alternative MAOP regardless of the
four-part test in Sec. 192.801(b).
E.7.7. Sec. 192.620(c)(7)--Recordkeeping
Paragraph (c)(7) specifies recordkeeping requirements for operators
electing to establish the MAOP under this section. Existing
regulations, such as Sec. Sec. 192.13, 192.517(a), and 192.709,
already require operators to maintain records applicable to this
section. New Sec. 192.620 is in subpart L. Because the additional
requirements in this section address requirements found in other
subparts of part 192, the recordkeeping requirements could cause
confusion. For example, Sec. 192.620(d)(9) requires a baseline
assessment for integrity for a segment operated at the higher stress
level regardless of its potential impact on an HCA. Section 192.947, in
subpart O, requires operators to maintain records of baseline
assessments for the useful life of the pipeline. Section 192.709
requires an operator to retain records for an inspection done under
subpart L for a more limited time. Accordingly, this paragraph
clarifies the need to maintain all records demonstrating compliance
with all alternative MAOP requirements for the useful life of the
pipeline.
E.7.8 Sec. 192.620(c)(8)--Class Upgrades
Paragraph (c)(8) allows pipelines in Class 1 and 2 to be upgraded
one class when class changes occur per Sec. 192.611. This paragraph
precludes operation of pipeline in Class 4 at alternative MAOP.
E.8. Sec. 192.620(d)--Additional Operation and Maintenance
Requirements
Paragraph (d) sets forth ten operating and maintenance requirements
that supplement the existing requirements in part 192. Currently Sec.
192.605 requires an operator to develop O&M procedures to implement the
requirements of subparts L and M. Since Sec. 192.620(d) is in subpart
L, an operator must develop and follow the O&M procedures developed
under this section. These include requirements for an operator to
evaluate and address the issues associated with operating at higher
pressures. Through its public education program, an operator would
inform the public of any risks attributable to higher pressure
operations. The additional operating and maintenance requirements
address the two main risks the pipelines face, excavation damage and
corrosion, through a combination of traditional practices and integrity
management. Traditional practices include cathodic protection, control
of gas quality, and maintenance of burial depth. Integrity management
includes internal inspection on a periodic basis to identify and repair
flaws before they can fail. The additional O&M and management
requirements are discussed in more detail below.
E.8.1. Sec. 192.620(d)(1)--Threat Assessments
Paragraph (d)(1) requires an operator to identify and evaluate
threats to the pipeline consistent with the similar procedures done
under integrity management to address the risks of operating at an
increased stress level.
E.8.2. Sec. 192.620(d)(2)--Public Awareness
Paragraph (d)(2) requires an operator to include any people
potentially impacted by operation at a higher stress level within the
outreach effort in its public education program required under existing
Sec. 192.616. In order to identify this population, an operator would
use a broad area measured from the centerline of the pipe plus, in
HCAs, the potential impact circle recalculated to reflect operation at
a higher operating stress level. This is intended to get necessary
information for safety to the people potentially impacted by a failure.
E.8.3. Sec. 192.620(d)(3)--Emergency Response
Paragraph (d)(3) addresses the additional needs for responding to
emergencies for operation at higher operating stress levels. Consistent
with the conditions imposed in the special permits, and past experience
with response issues, the paragraph requires methods such as remote
control valves to provide more rapid shut-down in the event of an
emergency.
E.8.4. Sec. 192.620(d)(4)--Damage Prevention
Paragraph (d)(4) addresses one of the major risks of failure faced
by a pipeline, damage from outside force such as damage occurring
during excavation in the right-of-way. Although
[[Page 62171]]
the improved toughness of pipe reduces the risk of damage, it does not
prevent it and additional measures are appropriate for pipelines
operating at higher operating stress levels. This paragraph adds
several new or more specific measures to existing requirements designed
to prevent damage to pipelines from outside force.
The first more specific measure, in paragraph (d)(4)(i), addresses
patrolling, required for all transmission pipelines by Sec. 192.705.
More frequent patrols of the right-of-way prevent damage by giving the
operator more accurate and timely information about potential sources
of ground disturbance and other outside force damage. These include
both naturally occurring conditions, such as wash outs, and human
activity, such as construction in the vicinity of the pipeline. The
requirement is for patrols to be made monthly, at intervals not to
exceed 45 days. The patrolling requirement along with other right-of-
way requirements including line-of-sight markers, use of national
consensus standards, and the right-of-way management plan comprise a
multi-faceted approach to protecting the pipeline.
Other more specific or new measures to address damage prevention
include developing and implementing a plan to monitor and address
ground movement, a requirement of paragraph (d)(4)(ii). Ground movement
such as earthquakes, landslides, soil erosion, and nearby demolition or
tunneling can damage pipelines. Since pipelines near the surface are
more likely to be damaged by surface activities, paragraph (d)(4)(iii)
requires an operator to maintain the depth of cover over a pipeline or
provide alternative protection. Line-of-sight markers alert excavators,
emergency responders, and the general public of the presence and
general location of pipelines. Paragraph (d)(4)(iv) requires these
markers both to improve damage prevention and to enhance public
awareness.
Damage prevention programs are improving because of the work being
done by the CGA, a national, non-profit educational organization
dedicated to preventing damage to pipelines and other underground
utilities. The CGA has compiled best practices applicable to all
parties relevant to preventing damage to underground utilities and
actively promotes their use. Paragraph (d)(5)(v) requires operators
electing to operate at higher stress levels to evaluate their damage
prevention programs in light of industry best practices, such as those
developed by CGA. An operator must identify the practices applicable to
its circumstances and make appropriate changes to its damage prevention
program. This approach is consistent with annual reviews of O&M
programs under Sec. 192.605. An operator must include in the
certification required under Sec. 192.620(c)(1) that the review and
upgrade have occurred.
Paragraph (d)(4) also requires the preparation of a right-of-way
management plan. In the past several years, PHMSA has seen recurring
similarities in pipeline accidents on construction sites. In each case,
better management of the pipeline right-of-way could have prevented the
accidents. Better management includes closer attention to the
qualifications of individuals critical to damage prevention, better
marking practices, and closer oversight of the excavation. In 2006,
PHMSA issued two advisory bulletins to alert operators of the need to
pay closer attention to these important damage prevention issues. The
first advisory bulletin described three accidents in which either
operator personnel or contractors damaged gas transmission pipelines
during excavation in the rights-of-way (ADB-06-01; 71 FR 2613; Jan.17,
2006). This bulletin advised operators to pay closer attention to
integrating OQ regulations into excavation activities and providing
that excavation is included as a covered task under OQ programs
required by subpart N. The second advisory bulletin pointed to an
additional excavation accident where the excavator struck an
inadequately marked gas transmission pipeline (ADB-06-003; 71 FR 67703;
Nov. 22, 2006). This advisory bulletin advised pipeline operators to
pay closer attention to locating and marking pipelines before
excavation activities begin and pointed to several good practices as
well as the best practices described by the CGA. This paragraph
requires an operator electing to operate at a higher stress level to
develop a plan to manage the protection of their right-of-way from
excavation activities. Each operator already has a damage prevention
program, under Sec. 192.614, and a program to ensure qualification of
pipeline personnel, under subpart N. This management program requires
the operator to integrate activities under those programs to provide
better protection for the right-of-way of the pipeline operated at the
higher stress level.
E.8.5. Sec. 192.620(d)(5)--Internal Corrosion Control
Paragraph (d)(5) adds specificity to the requirements for internal
corrosion control now in pipeline safety standards for pipelines
operated at higher stress levels. These internal corrosion control
programs must include use of gas separators or filter separators and
gas quality monitoring equipment. Operators are required to use
cleaning pigs and inhibitors when corrosive gas is present. (Use of
cleaning pigs and inhibitors is required when the level of one
corrosive contaminant, hydrogen sulfide (H2S), is between
0.5 and 1.0 grain per hundred cubic feet). Most operators who have
applied for special permits to operate their pipeline at alternative
MAOP limit H2S to 0.5 grain. The higher levels allowed in
this rule are within typical FERC tariffs, but may present an increased
likelihood of internal corrosion. Maximum levels of contaminants that
could promote corrosion must be reviewed quarterly, and operators must
adjust their programs as needed to monitor and mitigate any deleterious
gas stream constituents. PHMSA believes the levels are fully consistent
with the requirements in FERC tariffs designed to prevent internal
corrosion.
E.8.6. Sec. Sec. 192.620(d)(6), (7), and (8)--External Corrosion
Control
Since external corrosion is one of the greatest risks to the
integrity of pipelines operating at higher stress levels, the special
permits and this rule contain several measures to prevent it from
occurring. These include use of effective external coating, addressing
interference, early installation of cathodic protection, confirming the
adequacy of coating and cathodic protection and diligent monitoring of
cathodic protection levels. The requirements concerning quality of the
coating and installation of cathodic protection for new pipelines are
addressed in sections on design and construction, as discussed above.
The remaining external corrosion provisions are addressed here.
Interference from overhead power lines, railroad signaling, stray
currents, or other sources can interfere with the cathodic protection
system and, if not properly mitigated, even accelerate the rate of
external corrosion. Paragraph (d)(6) requires an operator to identify
and address interference early before damage to the pipeline can occur.
Paragraph (d)(7) requires an operator to confirm both the
effectiveness of the coating and the adequacy of the cathodic
protection system soon after deciding on operation at higher operating
stress levels/alternative MAOP. This is accomplished through indirect
assessments, such as a CIS for cathodic protection and DCVG or ACVG for
coating condition. After completion of the baseline internal inspection
[[Page 62172]]
required by Sec. 192.620(d)(9), an operator is required to integrate
the results of that inspection with the indirect assessments. An
operator must take remedial action to correct any inadequacies. In
HCAs, an operator must periodically repeat indirect assessment to
confirm that the cathodic protection system remains as functional as
when first installed.
Paragraph (d)(8) requires more rigorous attention to ensure
adequate levels of cathodic protection. Regulations now require an
operator discovering a low reading, meaning a reduced level of
protection, to act promptly to correct the deficiency. This section
puts an outer limit of six months on the time for completion of the
remedial action and restoration of an adequate level of cathodic
protection. In addition, the operator must confirm that its actions
have been effective in restoring cathodic protection.
E.8.7. Sec. Sec. 192.620(d)(9) and (10)--Integrity Assessments
Among the most important ways of ensuring integrity during pipeline
operations are the assessments done under the integrity management
program requirements in subpart O. Paragraphs (d)(9) and (d)(10)
require operators electing to operate at higher stress levels to
perform both baseline and periodic assessments of the entire pipeline
segment operating at the higher stress level, regardless of whether the
pipeline segment is located in an HCA. The operator must use both a
geometry tool and a high resolution magnetic flux tool for the entire
pipeline segment. In very limited circumstances in which internal
inspection is not possible because internal inspection tools cannot be
accommodated, such as a short crossover segment connecting two
pipelines in a right-of-way, an operator would substitute pressure
testing or DA. The operator must then integrate the information
provided by these assessments with testing done under previously
described paragraphs. This analysis would form the basis for mitigating
measures, and for prompt repairs under paragraph (d)(11).
E.8.8. Sec. 192.620(d)(11)--Repair Criteria
The repair criteria under paragraph (d)(11) for anomalies in a
pipeline segment operating at a higher stress level are slightly more
conservative than for other pipelines, including pipelines covered by
an integrity management program. With the tougher pipe, better coating,
construction quality inspection program, coating surveys after
installation and backfill, and careful attention to damage prevention
and corrosion protection, a pipeline operated at higher operating
stress levels should experience few anomalies needing evaluation.
E.9. Sec. 192.620(e)--Overpressure Protection
The alternative MAOP is higher than the upper limit of the required
overpressure protection under existing regulations. Paragraph (e)
increases the overpressure protection limit to 104 percent of the MAOP,
which is 83.2 percent of SMYS for a pipeline segment operating at the
alternative MAOP in a Class 1 location.
F. Regulatory Analyses and Notices
F.1. 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 (65 FR 19477).
F.2. Executive Order 12866 and DOT Policies and Procedures
Due to magnitude of expected benefits, the DOT considers this
rulemaking to be a significant regulatory action under section 3(f)(1)
of Executive Order 12866 (58 FR 51735; Oct. 4, 1993). Therefore, DOT
submitted it to the Office of Management and Budget for review. This
rulemaking is also significant under DOT regulatory policies and
procedures (44 FR 11034; Feb. 26, 1979).
PHMSA prepared a Regulatory Evaluation of the final rule. A copy is
in Docket ID PHMSA-2005-23447.
PHMSA estimates that the rule will result in gas transmission
pipeline operators uprating 3,500 miles of existing pipelines to an
alternative MAOP. Additionally PHMSA estimates that, in the future, the
rule will result in an annual additional 700 miles of new pipelines
each year whose operators elect to use an alternative MAOP.
PHMSA expects the benefits of the rule to be substantial and in
excess of $100 million per year. This expectation is based on
quantified benefits in excess of $100 million per year (see below),
coupled with un-quantified benefits associated with the rule that
industry and PHMSA technical staff have identified. The expected
benefits of the rule that cannot be readily quantified include:
Reductions in incident consequences.
Increases in pipeline capacity.
Increases in the amount of natural gas filling the line,
commonly called line pack.
Reductions in adverse environmental impacts.
The rule's requirements, such as monthly right-of-way patrolling,
additional internal inspections, and anomaly repair, are expected to
prevent incidents that would have occurred in the absence of the rule,
and to help mitigate the consequences of the incidents that do occur.
In the case of new pipelines, the ability to use an alternative MAOP
will make it possible to transport more product per dollar of pipeline
cost than would be possible without this new rule. Quantifying the
value of this increased capacity is difficult, and no estimate has been
developed for this analysis. For existing pipelines, operation at a
higher MAOP increases the amount of gas that can be transported. PHMSA
expects the value of increased capacity due to use of alternative MAOP
by gas pipelines to be significant. In areas where production is
already well-established, there is an even greater potential for
increased pipeline capacity. For example, one recipient of a special
permit estimated a daily increase of at least 62 million standard cubic
feet of gas.
Similarly, increases in line pack will produce increased benefits
which are difficult to quantify. Line pack is increased due to gas
compressibility at higher operating pressures which results in
increased gas volumes in the pipeline. The reduced amount of exterior
storage capacity needed resulting from increased line pack may result
in capital or O&M savings for the pipelines or their customers. Greater
line pack in a pipeline increases the ability of the operator to
continue gas delivery during short outages such as maintenance and
during peak flow periods. These benefits are not readily quantifiable.
The quantified benefits consist of:
Fuel cost savings.
Capital expenditure savings on pipe for new pipelines.
Of these, pipeline fuel cost savings is the most important
contributor to the estimated benefits. Although these quantified
benefits do not capture the full benefits of the rule, they exceed $100
million per year.
As a consequence of the rule, PHMSA estimates that pipeline
operators will realize annually recurring benefits due to fuel cost
savings of $49 million that will begin in the initial year after the
rule goes into effect. Additionally, PHMSA estimates that each year
pipeline operators will realize one-time benefits for savings in
capital expenditures of $54.6 million (since 700 miles of new pipeline
operating at an alternative MAOP are added each year,
[[Page 62173]]
the one-time benefits resulting from this added mileage will be the
same each year.) The benefits of the rule over 20 years are expected to
be as presented in the following table:
Table D.2.-1--Summary and Total for the Estimated Benefits of the Rule
[Millons of dollars per year]
------------------------------------------------------------------------
Estimate of new
Estimate for year benefits occurring
Benefit 1 in each subsequent
year
------------------------------------------------------------------------
Reduced incident consequences... Not quantified.... Not quantified.
Fuel cost savings............... $49.0............. $49.0
Reduced capital expenditures.... $54.6............. $54.6
Increased pipeline capacity..... Not quantified.... Not quantified.
Increased line pack............. Not quantified.... Not quantified.
Reduced adverse environmental Not quantified.... Not quantified.
impacts.
Other expected benefits......... Not quantified.... Not quantified.
---------------------------------------
Total....................... $103.6............ $103.6
------------------------------------------------------------------------
The present value of the benefits evaluated over 20 years at a
three percent discount rate is $1,541 million, while the present value
of the benefits over 20 years at a seven percent discount rate is
$1,098 million. For both discount rates, the annualized benefits would
be $103.6 million.
PHMSA expects the costs attributable to the rule are most likely to
be incurred by operators for:
Performing baseline internal inspections.
Performing additional internal inspections.
Performing anomaly repairs.
Installing remotely controlled valves on either side of
HCAs.
Preparing threat assessments.
Patrolling pipeline rights-of-way.
Preparing the paperwork notifying PHMSA of the decision to
use an alternative MAOP.
Overall, the costs of the rule over 20 years are expected to be as
presented in the following table:
Table D.2.-2-- Summary and Totals for the Estimated Costs of the Rule
----------------------------------------------------------------------------------------------------------------
Cost by year after implementation [thousands of dollars]
Cost item -------------------------------------------------------------------------------
1st 2nd--10th 11th 12th--20th
----------------------------------------------------------------------------------------------------------------
Baseline internal inspections... $29,119........... None.............. None.............. None
Additional internal inspections. None.............. None.............. $17,471........... $2,912 each year.
Anomaly repairs................. $1,015............ None.............. $1,218............ $203 each year.
Remotely controlled valves...... $3,528............ $588 each year.... $588.............. $588 each year.
Threat Assessments.............. $180.............. $30 each year..... $30............... $30 each year.
Patrolling...................... $4,620............ $5,390 to $11,550. $12,320........... $15,090 to
$19,250.
Notifying PHMSA................. Nominal........... Nominal........... Nominal........... Nominal.
-------------------------------------------------------------------------------
Total....................... $38,462........... $618 each year $31,627........... $3,733 each year
plus patrolling plus patrolling
costs. costs.
----------------------------------------------------------------------------------------------------------------
The present value of the costs evaluated over 20 years at a three
percent discount rate are approximately $239 million, while the present
value of the costs over 20 years at a seven percent discount rate are
approximately $165 million. The annualized costs at the three percent
discount rate are approximately $16 million, while the annualized costs
at the seven percent discount rate are approximately $15 million.
Since the present value of the quantified benefits ($1,541 million
at three percent and $1,098 million at seven percent) exceeds the
present value of the costs ($328 million at three percent and $164
million at seven percent), the rule is expected to have net benefits.
F.3. 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.
The final rule affects operators of gas pipelines. Based on annual
reports submitted by operators, there are approximately 1,450 gas
transmission and gathering systems and an equivalent number of
distribution systems potentially affected by this rule. The size
distribution of these operators is unknown and must be estimated.
The affected gas transmission systems all belong to NAICS 486210,
Pipeline Transportation of Natural Gas. In accordance with the size
standards published by the Small Business Administration, a business
with $6.5 million or less in annual revenue is considered a small
business in this NAICS.
Based on August 2006 information from Dunn & Bradstreet on firms in
NAICS 486210, PHMSA estimates that 33 percent of the gas transmission
and gathering systems have $6.5 million or less in revenue. Thus, PHMSA
estimates that 479 of the gas transmission and gathering systems
affected by the rule will have $6.5 million or less in annual revenue.
PHMSA does not expect that
[[Page 62174]]
any local gas distribution companies or gathering systems will be
taking advantage of the potential to use an alternative MAOP.
The rule mandates no action by gas transmission pipeline operators.
Rather, it provides those operators with the option of using an
alternative MAOP in certain circumstances, when certain conditions can
be met. Consequently, it imposes no economic burden on the affected gas
pipeline operators, large or small. Based on these facts, I certify
that this rule will not have a substantial economic impact on a
substantial number of small entities.
F.4. Executive Order 13175
PHMSA has analyzed this rulemaking according to Executive Order
13175, ``Consultation and Coordination with Indian Tribal
Governments.'' Because the rule does 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.
F.5. Paperwork Reduction Act
This rule adds notification paperwork requirements and record
retention on pipeline operators voluntarily choosing an alternative
MAOP for their pipelines. Based on analysis of the regulation, there
will be an estimated nine total annual burden hours attributable to the
notification and recordkeeping requirements in the first year. In
following years, the annual burden is expected to decrease to one and
one-half hours. The associated cost of these annual burden hours is
$720 in year one, and $120 thereafter. No other burden hours and
associated costs are expected. The Paperwork Reduction Act analysis in
the docket has a more detailed explanation.
F.6. Unfunded Mandates Reform Act of 1995
This rule does not impose unfunded mandates under the Unfunded
Mandates Reform Act of 1995. It does not result in costs of $132
million or more in any one year to either State, local, or tribal
governments, in the aggregate, or to the private sector, and is the
least burdensome alternative that achieves the objective of the
rulemaking.
F.7. National Environmental Policy Act
PHMSA has analyzed the rulemaking for purposes of the National
Environmental Policy Act (42 U.S.C. 4321 et seq.). The rulemaking will
require limited physical change or other work that would disturb
pipeline rights-of-way. In addition, the rule codifies the terms of
special permits PHMSA has granted. Although PHMSA sought public comment
on environmental impacts with respect to most requests for special
permits to allow operation at pressures based on higher stress levels,
no commenters addressed environmental impacts. Further, PHMSA did not
receive any comment on the environmental assessment it had prepared in
conjunction with the proposed rule. PHMSA has determined the rulemaking
is unlikely to significantly affect the quality of the human
environment. An environmental assessment document is available for
review in the docket.
F.8. Executive Order 13132
PHMSA has analyzed the rulemaking according to Executive Order
13132 (64 FR 43255, Aug. 10, 1999) and concluded that no additional
consultation with States, local governments or their representatives is
mandated beyond the rulemaking process. The 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 rule does
not impose substantial direct compliance costs on State or local
governments.
Further, no consultation is needed to discuss the preemptive effect
of the proposed rule. The pipeline safety law, specifically 49 U.S.C.
60104(c), prohibits State safety regulation of interstate pipelines.
Under the pipeline safety law, States have the ability to augment
pipeline safety requirements for intrastate pipelines PHMSA regulates,
but may not approve safety requirements less stringent than those
required by Federal law. And a State may regulate an intrastate
pipeline facility PHMSA does not regulate. In addition, 49 U.S.C.
60120(c) provides that the Federal pipeline safety law ``does not
affect the tort liability of any person.'' It is these statutory
provisions, not the rule, that govern preemption of State law.
Therefore, the consultation and funding requirements of Executive Order
13132 do not apply.
F.9. Executive Order 13211
This rulemaking is likely to increase the efficiency of gas
transmission pipelines. A gas transmission pipeline operating at an
increased MAOP will result in increased capacity, fuel savings, and
flexibility in addressing supply demands. This is a positive rather
than an adverse effect on the supply, distribution, and use of energy.
Thus this rulemaking is not a ``significant energy action'' under
Executive Order 13211. Further, the Administrator of the Office of
Information and Regulatory Affairs has not identified this rule as a
significant energy action.
List of Subjects in 49 CFR Part 192
Design pressure, Incorporation by reference, Maximum allowable
operating pressure, and 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. In Sec. 192.7, in paragraph (c)(2) amend the table of referenced
material by revising item (B)(1), redesignating items (C)(6) through
(C)(13) as (C)(7) through (C)(14), and adding a new item (C)(6) to read
as follows:
Sec. 192.7 What documents are incorporated by reference partly or
wholly in this part?
* * * * *
(c) * * *
(2) * * *
[[Page 62175]]
------------------------------------------------------------------------
Source and name of referenced material 49 CFR reference
------------------------------------------------------------------------
B. * * *................................... * * *
(1) API Specification 5L ``Specification Sec. Sec. 192.55(e);
for Line Pipe,'' (43rd edition and 192.112; 192.113; Item I
errata), 2004. of Appendix B.
* * * * * * *
C. * * *................................... ...........................
(6) ASTM Designation: A 578/A578M-96 (Re- Sec. Sec.
approved 2001) ``Standard Specification 192.112(c)(2)(iii).
for Straight-Beam Ultrasonic Examination
of Plain and Clad Steel Plates for Special
Applications''.
* * * * * * *
------------------------------------------------------------------------
0
3. Add Sec. 192.112 to subpart C to read as follows:
Sec. 192.112 Additional design requirements for steel pipe using
alternative maximum allowable operating pressure.
For a new or existing pipeline segment to be eligible for operation
at the alternative maximum allowable operating pressure (MAOP)
calculated under Sec. 192.620, a segment must meet the following
additional design requirements. Records for alternative MAOP must be
maintained, for the useful life of the pipeline, demonstrating
compliance with these requirements:
------------------------------------------------------------------------
The pipeline segment must meet these
To address this design issue: additional requirements:
------------------------------------------------------------------------
(a) General standards for the (1) The plate, skelp, or coil used
steel pipe. for the pipe must be micro-alloyed,
fine grain, fully killed,
continuously cast steel with
calcium treatment.
(2) The carbon equivalents of the
steel used for pipe must not exceed
0.25 percent by weight, as
calculated by the Ito-Bessyo
formula (Pcm formula) or 0.43
percent by weight, as calculated by
the International Institute of
Welding (IIW) formula.
(3) The ratio of the specified
outside diameter of the pipe to the
specified wall thickness must be
less than 100. The wall thickness
or other mitigative measures must
prevent denting and ovality
anomalies during construction,
strength testing and anticipated
operational stresses.
(4) The pipe must be manufactured
using API Specification 5L, product
specification level 2 (incorporated
by reference, see Sec. 192.7) for
maximum operating pressures and
minimum and maximum operating
temperatures and other requirements
under this section.
(b) Fracture control.............. (1) The toughness properties for
pipe must address the potential for
initiation, propagation and arrest
of fractures in accordance with:
(i) API Specification 5L
(incorporated by reference, see
Sec. 192.7); or
(ii) American Society of Mechanical
Engineers (ASME) B31.8
(incorporated by reference, see
Sec. 192.7); and
(iii) Any correction factors needed
to address pipe grades, pressures,
temperatures, or gas compositions
not expressly addressed in API
Specification 5L, product
specification level 2 or ASME B31.8
(incorporated by reference, see
Sec. 192.7).
(2) Fracture control must:
(i) Ensure resistance to fracture
initiation while addressing the
full range of operating
temperatures, pressures, gas
compositions, pipe grade and
operating stress levels, including
maximum pressures and minimum
temperatures for shut-in
conditions, that the pipeline is
expected to experience. If these
parameters change during operation
of the pipeline such that they are
outside the bounds of what was
considered in the design
evaluation, the evaluation must be
reviewed and updated to assure
continued resistance to fracture
initiation over the operating life
of the pipeline;
(ii) Address adjustments to
toughness of pipe for each grade
used and the decompression behavior
of the gas at operating parameters;
(iii) Ensure at least 99 percent
probability of fracture arrest
within eight pipe lengths with a
probability of not less than 90
percent within five pipe lengths;
and
(iv) Include fracture toughness
testing that is equivalent to that
described in supplementary
requirements SR5A, SR5B, and SR6 of
API Specification 5L (incorporated
by reference, see Sec. 192.7) and
ensures ductile fracture and arrest
with the following exceptions:
(A) The results of the Charpy impact
test prescribed in SR5A must
indicate at least 80 percent
minimum shear area for any single
test on each heat of steel; and
(B) The results of the drop weight
test prescribed in SR6 must
indicate 80 percent average shear
area with a minimum single test
result of 60 percent shear area for
any steel test samples. The test
results must ensure a ductile
fracture and arrest.
(3) If it is not physically possible
to achieve the pipeline toughness
properties of paragraphs (b)(1) and
(2) of this section, additional
design features, such as mechanical
or composite crack arrestors and/or
heavier walled pipe of proper
design and spacing, must be used to
ensure fracture arrest as described
in paragraph (b)(2)(iii) of this
section.
(c) Plate/coil quality control.... (1) There must be an internal
quality management program at all
mills involved in producing steel,
plate, coil, skelp, and/or rolling
pipe to be operated at alternative
MAOP. These programs must be
structured to eliminate or detect
defects and inclusions affecting
pipe quality.
(2) A mill inspection program or
internal quality management program
must include (i) and either (ii) or
(iii):
(i) An ultrasonic test of the ends
and at least 35 percent of the
surface of the plate/coil or pipe
to identify imperfections that
impair serviceability such as
laminations, cracks, and
inclusions. At least 95 percent of
the lengths of pipe manufactured
must be tested. For all pipelines
designed after [the effective date
of the final rule], the test must
be done in accordance with ASTM
A578/A578M Level B, or API 5L
Paragraph 7.8.10 (incorporated by
reference, see Sec. 192.7) or
equivalent method, and either
[[Page 62176]]
(ii) A macro etch test or other
equivalent method to identify
inclusions that may form centerline
segregation during the continuous
casting process. Use of sulfur
prints is not an equivalent method.
The test must be carried out on the
first or second slab of each
sequence graded with an acceptance
criteria of one or two on the
Mannesmann scale or equivalent; or
(iii) A quality assurance monitoring
program implemented by the operator
that includes audits of: (a) all
steelmaking and casting facilities,
(b) quality control plans and
manufacturing procedure
specifications, (c) equipment
maintenance and records of
conformance, (d) applicable casting
superheat and speeds, and (e)
centerline segregation monitoring
records to ensure mitigation of
centerline segregation during the
continuous casting process.
(d) Seam quality control.......... (1) There must be a quality
assurance program for pipe seam
welds to assure tensile strength
provided in API Specification 5L
(incorporated by reference, see
Sec. 192.7) for appropriate
grades.
(2) There must be a hardness test,
using Vickers (Hv10) hardness test
method or equivalent test method,
to assure a maximum hardness of 280
Vickers of the following:
(i) A cross section of the weld seam
of one pipe from each heat plus one
pipe from each welding line per
day; and
(ii) For each sample cross section,
a minimum of 13 readings (three for
each heat affected zone, three in
the weld metal, and two in each
section of pipe base metal).
(3) All of the seams must be
ultrasonically tested after cold
expansion and mill hydrostatic
testing.
(e) Mill hydrostatic test......... (1) All pipe to be used in a new
pipeline segment must be
hydrostatically tested at the mill
at a test pressure corresponding to
a hoop stress of 95 percent SMYS
for 10 seconds. The test pressure
may include a combination of
internal test pressure and the
allowance for end loading stresses
imposed by the pipe mill
hydrostatic testing equipment as
allowed by API Specification 5L,
Appendix K (incorporated by
reference, see Sec. 192.7).
(2) Pipe in operation prior to
November 17, 2008, must have been
hydrostatically tested at the mill
at a test pressure corresponding to
a hoop stress of 90 percent SMYS
for 10 seconds.
(f) Coating....................... (1) The pipe must be protected
against external corrosion by a non-
shielding coating.
(2) Coating on pipe used for
trenchless installation must be non-
shielding and resist abrasions and
other damage possible during
installation.
(3) A quality assurance inspection
and testing program for the coating
must cover the surface quality of
the bare pipe, surface cleanliness
and chlorides, blast cleaning,
application temperature control,
adhesion, cathodic disbondment,
moisture permeation, bending,
coating thickness, holiday
detection, and repair.
(g) Fittings and flanges.......... (1) There must be certification
records of flanges, factory
induction bends and factory weld
ells. Certification must address
material properties such as
chemistry, minimum yield strength
and minimum wall thickness to meet
design conditions.
(2) If the carbon equivalents of
flanges, bends and ells are greater
than 0.42 percent by weight, the
qualified welding procedures must
include a pre-heat procedure.
(3) Valves, flanges and fittings
must be rated based upon the
required specification rating class
for the alternative MAOP.
(h) Compressor stations........... (1) A compressor station must be
designed to limit the temperature
of the nearest downstream segment
operating at alternative MAOP to a
maximum of 120 degrees Fahrenheit
(49 degrees Celsius) or the higher
temperature allowed in paragraph
(h)(2) of this section unless a
long-term coating integrity
monitoring program is implemented
in accordance with paragraph (h)(3)
of this section.
(2) If research, testing and field
monitoring tests demonstrate that
the coating type being used will
withstand a higher temperature in
long-term operations, the
compressor station may be designed
to limit downstream piping to that
higher temperature. Test results
and acceptance criteria addressing
coating adhesion, cathodic
disbondment, and coating condition
must be provided to each PHMSA
pipeline safety regional office
where the pipeline is in service at
least 60 days prior to operating
above 120 degrees Fahrenheit (49
degrees Celsius). An operator must
also notify a State pipeline safety
authority when the pipeline is
located in a State where PHMSA has
an interstate agent agreement, or
an intrastate pipeline is regulated
by that State.
(3) Pipeline segments operating at
alternative MAOP may operate at
temperatures above 120 degrees
Fahrenheit (49 degrees Celsius) if
the operator implements a long-term
coating integrity monitoring
program. The monitoring program
must include examinations using
direct current voltage gradient
(DCVG), alternating current voltage
gradient (ACVG), or an equivalent
method of monitoring coating
integrity. An operator must specify
the periodicity at which these
examinations occur and criteria for
repairing identified indications.
An operator must submit its long-
term coating integrity monitoring
program to each PHMSA pipeline
safety regional office in which the
pipeline is located for review
before the pipeline segments may be
operated at temperatures in excess
of 120 degrees Fahrenheit (49
degrees Celsius). An operator must
also notify a State pipeline safety
authority when the pipeline is
located in a State where PHMSA has
an interstate agent agreement, or
an intrastate pipeline is regulated
by that State.
------------------------------------------------------------------------
0
4. Add Sec. 192.328 to subpart G to read as follows:
Sec. 192.328 Additional construction requirements for steel pipe
using alternative maximum allowable operating pressure.
For a new or existing pipeline segment to be eligible for operation
at the alternative maximum allowable operating pressure calculated
under Sec. 192.620, a segment must meet the following additional
construction requirements. Records must be maintained, for the useful
life of the pipeline, demonstrating compliance with these requirements:
[[Page 62177]]
------------------------------------------------------------------------
To address this construction The pipeline segment must meet this
issue: additional construction requirement:
------------------------------------------------------------------------
(a) Quality assurance............ (1) The construction of the
pipeline segment must be done under
a quality assurance plan addressing
pipe inspection, hauling and
stringing, field bending, welding,
non-destructive examination of
girth welds, applying and testing
field applied coating, lowering of
the pipeline into the ditch,
padding and backfilling, and
hydrostatic testing.
(2) The quality assurance plan for
applying and testing field applied
coating to girth welds must be:
(i) Equivalent to that required
under Sec. 192.112(f)(3) for
pipe; and
(ii) Performed by an individual with
the knowledge, skills, and ability
to assure effective coating
application.
(b) Girth welds.................. (1) All girth welds on a new
pipeline segment must be non-
destructively examined in
accordance with Sec. 192.243(b)
and (c).
(c) Depth of cover............... (1) Notwithstanding any lesser
depth of cover otherwise allowed in
Sec. 192.327, there must be at
least 36 inches (914 millimeters)
of cover or equivalent means to
protect the pipeline from outside
force damage.
(2) In areas where deep tilling or
other activities could threaten the
pipeline, the top of the pipeline
must be installed at least one foot
below the deepest expected
penetration of the soil.
(d) Initial strength testing..... (1) The pipeline segment must not
have experienced failures
indicative of systemic material
defects during strength testing,
including initial hydrostatic
testing. A root cause analysis,
including metallurgical examination
of the failed pipe, must be
performed for any failure
experienced to verify that it is
not indicative of a systemic
concern. The results of this root
cause analysis must be reported to
each PHMSA pipeline safety regional
office where the pipe is in service
at least 60 days prior to operating
at the alternative MAOP. An
operator must also notify a State
pipeline safety authority when the
pipeline is located in a State
where PHMSA has an interstate agent
agreement, or an intrastate
pipeline is regulated by that
State.
(e) Interference currents........ (1) For a new pipeline segment, the
construction must address the
impacts of induced alternating
current from parallel electric
transmission lines and other known
sources of potential interference
with corrosion control.
------------------------------------------------------------------------
0
5. Amend Sec. 192.611 by revising paragraph (a)(1) and (a)(3)(i) and
(ii) and adding new paragraph (a)(3)(iii) to read as follows:
Sec. 192.611 Change in class location: Confirmation or revision of
maximum allowable operating pressure.
(a) * * *
(1) If the segment involved has been previously tested in place for
a period of not less than 8 hours:
(i) The maximum allowable operating pressure is 0.8 times the test
pressure in Class 2 locations, 0.667 times the test pressure in Class 3
locations, or 0.555 times the test pressure in Class 4 locations. The
corresponding hoop stress may not exceed 72 percent of the SMYS of the
pipe in Class 2 locations, 60 percent of SMYS in Class 3 locations, or
50 percent of SMYS in Class 4 locations.
(ii) The alternative maximum allowable operating pressure is 0.8
times the test pressure in Class 2 locations and 0.667 times the test
pressure in Class 3 locations. For pipelines operating at alternative
maximum allowable pressure per Sec. 192.620, the corresponding hoop
stress may not exceed 80 percent of the SMYS of the pipe in Class 2
locations and 67 percent of SMYS in Class 3 locations.
* * * * *
(3) * * *
(i) The maximum allowable operating pressure after the
requalification test is 0.8 times the test pressure for Class 2
locations, 0.667 times the test pressure for Class 3 locations, and
0.555 times the test pressure for Class 4 locations.
(ii) The corresponding hoop stress may not exceed 72 percent of the
SMYS of the pipe in Class 2 locations, 60 percent of SMYS in Class 3
locations, or 50 percent of SMYS in Class 4 locations.
(iii) For pipeline operating at an alternative maximum allowable
operating pressure per Sec. 192.620, the alternative maximum allowable
operating pressure after the requalification test is 0.8 times the test
pressure for Class 2 locations and 0.667 times the test pressure for
Class 3 locations. The corresponding hoop stress may not exceed 80
percent of the SMYS of the pipe in Class 2 locations and 67 percent of
SMYS in Class 3 locations.
* * * * *
0
6. Amend Sec. 192.619 by revising paragraph (a) introductory text and
by adding paragraph (d) to read as follows:
Sec. 192.619 Maximum allowable operating pressure: Steel or plastic
pipelines.
(a) No person may operate a segment of steel or plastic pipeline at
a pressure that exceeds a maximum allowable operating pressure
determined under paragraph (c) or (d) of this section, or the lowest of
the following:
* * * * *
(d) The operator of a pipeline segment of steel pipeline meeting
the conditions prescribed in Sec. 192.620(b) may elect to operate the
segment at a maximum allowable operating pressure determined under
Sec. 192.620(a).
0
7. Add Sec. 192.620 to subpart L to read as follows:
Sec. 192.620 Alternative maximum allowable operating pressure for
certain steel pipelines.
(a) How does an operator calculate the alternative maximum
allowable operating pressure? An operator calculates the alternative
maximum allowable operating pressure by using different factors in the
same formulas used for calculating maximum allowable operating pressure
under Sec. 192.619(a) as follows:
(1) In determining the alternative design pressure under Sec.
192.105, use a design factor determined in accordance with Sec.
192.111(b), (c), or (d) or, if none of these paragraphs apply, in
accordance with the following table:
------------------------------------------------------------------------
Alternative
Class location design factor
(F)
------------------------------------------------------------------------
1...................................................... 0.80
2...................................................... 0.67
3...................................................... 0.56
------------------------------------------------------------------------
(i) For facilities installed prior to November 17, 2008, for which
Sec. 192.111(b), (c), or (d) apply, use the following design factors
as alternatives for the factors specified in those paragraphs: Sec.
192.111(b)--0.67 or less; 192.111(c) and (d)--0.56 or less.
(ii) [Reserved]
(2) The alternative maximum allowable operating pressure is the
lower of the following:
(i) The design pressure of the weakest element in the pipeline
segment, determined under subparts C and D of this part.
(ii) The pressure obtained by dividing the pressure to which the
pipeline segment was tested after construction by
[[Page 62178]]
a factor determined in the following table:
------------------------------------------------------------------------
Alternative
Class location test factor
------------------------------------------------------------------------
1...................................................... 1.25
2...................................................... \1\ 1.50
3...................................................... 1.50
------------------------------------------------------------------------
\1\ For Class 2 alternative maximum allowable operating pressure
segments installed prior to November 17, 2008, the alternative test
factor is 1.25.
(b) When may an operator use the alternative maximum allowable
operating pressure calculated under paragraph (a) of this section? An
operator may use an alternative maximum allowable operating pressure
calculated under paragraph (a) of this section if the following
conditions are met:
(1) The pipeline segment is in a Class 1, 2, or 3 location;
(2) The pipeline segment is constructed of steel pipe meeting the
additional design requirements in Sec. 192.112;
(3) A supervisory control and data acquisition system provides
remote monitoring and control of the pipeline segment. The control
provided must include monitoring of pressures and flows, monitoring
compressor start-ups and shut-downs, and remote closure of valves;
(4) The pipeline segment meets the additional construction
requirements described in Sec. 192.328;
(5) The pipeline segment does not contain any mechanical couplings
used in place of girth welds;
(6) If a pipeline segment has been previously operated, the segment
has not experienced any failure during normal operations indicative of
a systemic fault in material as determined by a root cause analysis,
including metallurgical examination of the failed pipe. The results of
this root cause analysis must be reported to each PHMSA pipeline safety
regional office where the pipeline is in service at least 60 days prior
to operation at the alternative MAOP. An operator must also notify a
State pipeline safety authority when the pipeline is located in a State
where PHMSA has an interstate agent agreement, or an intrastate
pipeline is regulated by that State; and
(7) At least 95 percent of girth welds on a segment that was
constructed prior to November 17, 2008, must have been non-
destructively examined in accordance with Sec. 192.243(b) and (c).
(c) What is an operator electing to use the alternative maximum
allowable operating pressure required to do? If an operator elects to
use the alternative maximum allowable operating pressure calculated
under paragraph (a) of this section for a pipeline segment, the
operator must do each of the following:
(1) Notify each PHMSA pipeline safety regional office where the
pipeline is in service of its election with respect to a segment at
least 180 days before operating at the alternative maximum allowable
operating pressure. An operator must also notify a State pipeline
safety authority when the pipeline is located in a State where PHMSA
has an interstate agent agreement, or an intrastate pipeline is
regulated by that State.
(2) Certify, by signature of a senior executive officer of the
company, as follows:
(i) The pipeline segment meets the conditions described in
paragraph (b) of this section; and
(ii) The operating and maintenance procedures include the
additional operating and maintenance requirements of paragraph (d) of
this section; and
(iii) The review and any needed program upgrade of the damage
prevention program required by paragraph (d)(4)(v) of this section has
been completed.
(3) Send a copy of the certification required by paragraph (c)(2)
of this section to each PHMSA pipeline safety regional office where the
pipeline is in service 30 days prior to operating at the alternative
MAOP. An operator must also send a copy to a State pipeline safety
authority when the pipeline is located in a State where PHMSA has an
interstate agent agreement, or an intrastate pipeline is regulated by
that State.
(4) For each pipeline segment, do one of the following:
(i) Perform a strength test as described in Sec. 192.505 at a test
pressure calculated under paragraph (a) of this section or
(ii) For a pipeline segment in existence prior to November 17,
2008, certify, under paragraph (c)(2) of this section, that the
strength test performed under Sec. 192.505 was conducted at a test
pressure calculated under paragraph (a) of this section, or conduct a
new strength test in accordance with paragraph (c)(4)(i) of this
section.
(5) Comply with the additional operation and maintenance
requirements described in paragraph (d) of this section.
(6) If the performance of a construction task associated with
implementing alternative MAOP can affect the integrity of the pipeline
segment, treat that task as a ``covered task'', notwithstanding the
definition in Sec. 192.801(b) and implement the requirements of
subpart N as appropriate.
(7) Maintain, for the useful life of the pipeline, records
demonstrating compliance with paragraphs (b), (c)(6), and (d) of this
section.
(8) A Class 1 and Class 2 pipeline location can be upgraded one
class due to class changes per Sec. 192.611(a)(3)(i). All class
location changes from Class 1 to Class 2 and from Class 2 to Class 3
must have all anomalies evaluated and remediated per: The ``original
pipeline class grade'' Sec. 192.620(d)(11) anomaly repair
requirements; and all anomalies with a wall loss equal to or greater
than 40 percent must be excavated and remediated. Pipelines in Class 4
may not operate at an alternative MAOP.
(d) What additional operation and maintenance requirements apply to
operation at the alternative maximum allowable operating pressure? In
addition to compliance with other applicable safety standards in this
part, if an operator establishes a maximum allowable operating pressure
for a pipeline segment under paragraph (a) of this section, an operator
must comply with the additional operation and maintenance requirements
as follows:
------------------------------------------------------------------------
To address increased risk of a
maximum allowable operating
pressure based on higher stress Take the following additional step:
levels in the following areas:
------------------------------------------------------------------------
(1) Identifying and evaluating Develop a threat matrix consistent
threats. with Sec. 192.917 to do the
following:
(i) Identify and compare the
increased risk of operating the
pipeline at the increased stress
level under this section with
conventional operation; and
(ii) Describe and implement
procedures used to mitigate the
risk.
(2) Notifying the public.......... (i) Recalculate the potential impact
circle as defined in Sec. 192.903
to reflect use of the alternative
maximum operating pressure
calculated under paragraph (a) of
this section and pipeline operating
conditions; and
(ii) In implementing the public
education program required under
Sec. 192.616, perform the
following:
[[Page 62179]]
(A) Include persons occupying
property within 220 yards of the
centerline and within the potential
impact circle within the targeted
audience; and
(B) Include information about the
integrity management activities
performed under this section within
the message provided to the
audience.
(3) Responding to an emergency in (i) Ensure that the identification
an area defined as a high of high consequence areas reflects
consequence area in Sec. the larger potential impact circle
192.903. recalculated under paragraph
(d)(1)(i) of this section.
(ii) If personnel response time to
mainline valves on either side of
the high consequence area exceeds
one hour (under normal driving
conditions and speed limits) from
the time the event is identified in
the control room, provide remote
valve control through a supervisory
control and data acquisition
(SCADA) system, other leak
detection system, or an alternative
method of control.
(iii) Remote valve control must
include the ability to close and
monitor the valve position (open or
closed), and monitor pressure
upstream and downstream.
(iv) A line break valve control
system using differential pressure,
rate of pressure drop or other
widely-accepted method is an
acceptable alternative to remote
valve control.
(4) Protecting the right-of-way... (i) Patrol the right-of-way at
intervals not exceeding 45 days,
but at least 12 times each calendar
year, to inspect for excavation
activities, ground movement, wash
outs, leakage, or other activities
or conditions affecting the safety
operation of the pipeline.
(ii) Develop and implement a plan to
monitor for and mitigate
occurrences of unstable soil and
ground movement.
(iii) If observed conditions
indicate the possible loss of
cover, perform a depth of cover
study and replace cover as
necessary to restore the depth of
cover or apply alternative means to
provide protection equivalent to
the originally-required depth of
cover.
(iv) Use line-of-sight line markers
satisfying the requirements of Sec.
192.707(d) except in agricultural
areas, large water crossings or
swamp, steep terrain, or where
prohibited by Federal Energy
Regulatory Commission orders,
permits, or local law.
(v) Review the damage prevention
program under Sec. 192.614(a) in
light of national consensus
practices, to ensure the program
provides adequate protection of the
right-of-way. Identify the
standards or practices considered
in the review, and meet or exceed
those standards or practices by
incorporating appropriate changes
into the program.
(vi) Develop and implement a right-
of-way management plan to protect
the pipeline segment from damage
due to excavation activities.
(5) Controlling internal corrosion (i) Develop and implement a program
to monitor for and mitigate the
presence of, deleterious gas stream
constituents.
(ii) At points where gas with
potentially deleterious
contaminants enters the pipeline,
use filter separators or separators
and gas quality monitoring
equipment.
(iii) Use gas quality monitoring
equipment that includes a moisture
analyzer, chromatograph, and
periodic hydrogen sulfide sampling.
(iv) Use cleaning pigs and
inhibitors, and sample accumulated
liquids when corrosive gas is
present.
(v) Address deleterious gas stream
constituents as follows:
(A) Limit carbon dioxide to 3
percent by volume;
(B) Allow no free water and
otherwise limit water to seven
pounds per million cubic feet of
gas; and
(C) Limit hydrogen sulfide to 1.0
grain per hundred cubic feet (16
ppm) of gas, where the hydrogen
sulfide is greater than 0.5 grain
per hundred cubic feet (8 ppm) of
gas, implement a pigging and
inhibitor injection program to
address deleterious gas stream
constituents, including follow-up
sampling and quality testing of
liquids at receipt points.
(vi) Review the program at least
quarterly based on the gas stream
experience and implement
adjustments to monitor for, and
mitigate the presence of,
deleterious gas stream
constituents.
(6) Controlling interference that (i) Prior to operating an existing
can impact external corrosion. pipeline segment at an alternate
maximum allowable operating
pressure calculated under this
section, or within six months after
placing a new pipeline segment in
service at an alternate maximum
allowable operating pressure
calculated under this section,
address any interference currents
on the pipeline segment.
(ii) To address interference
currents, perform the following:
(A) Conduct an interference survey
to detect the presence and level of
any electrical current that could
impact external corrosion where
interference is suspected;
(B) Analyze the results of the
survey; and
(C) Take any remedial action needed
within 6 months after completing
the survey to protect the pipeline
segment from deleterious current.
(7) Confirming external corrosion (i) Within six months after placing
control through indirect the cathodic protection of a new
assessment. pipeline segment in operation, or
within six months after certifying
a segment under Sec.
192.620(c)(1) of an existing
pipeline segment under this
section, assess the adequacy of the
cathodic protection through an
indirect method such as close-
interval survey, and the integrity
of the coating using direct current
voltage gradient (DCVG) or
alternating current voltage
gradient (ACVG).
(ii) Remediate any construction
damaged coating with a voltage drop
classified as moderate or severe
(IR drop greater than 35% for DCVG
or 50 dB[mu]v for ACVG) under
section 4 of NACE RP-0502-2002
(incorporated by reference, see
Sec. 192.7).
(iii) Within six months after
completing the baseline internal
inspection required under paragraph
(8) of this section, integrate the
results of the indirect assessment
required under paragraph (6)(i) of
this section with the results of
the baseline internal inspection
and take any needed remedial
actions.
(iv) For all pipeline segments in
high consequence areas, perform
periodic assessments as follows:
[[Page 62180]]
(A) Conduct periodic close interval
surveys with current interrupted to
confirm voltage drops in
association with periodic
assessments under subpart O of this
part.
(B) Locate pipe-to-soil test
stations at half-mile intervals
within each high consequence area
ensuring at least one station is
within each high consequence area,
if practicable.
(C) Integrate the results with those
of the baseline and periodic
assessments for integrity done
under paragraphs (d)(8) and (d)(9)
of this section.
(8) Controlling external corrosion (i) If an annual test station
through cathodic protection. reading indicates cathodic
protection below the level of
protection required in subpart I of
this part, complete remedial action
within six months of the failed
reading or notify each PHMSA
pipeline safety regional office
where the pipeline is in service
demonstrating that the integrity of
the pipeline is not compromised if
the repair takes longer than 6
months. An operator must also
notify a State pipeline safety
authority when the pipeline is
located in a State where PHMSA has
an interstate agent agreement, or
an intrastate pipeline is regulated
by that State; and
(ii) After remedial action to
address a failed reading, confirm
restoration of adequate corrosion
control by a close interval survey
on either side of the affected test
station to the next test station.
(iii) If the pipeline segment has
been in operation, the cathodic
protection system on the pipeline
segment must have been operational
within 12 months of the completion
of construction.
(9) Conducting a baseline (i) Except as provided in paragraph
assessment of integrity. (d)(8)(iii) of this section, for a
new pipeline segment operating at
the new alternative maximum
allowable operating pressure,
perform a baseline internal
inspection of the entire pipeline
segment as follows:
(A) Assess using a geometry tool
after the initial hydrostatic test
and backfill and within six months
after placing the new pipeline
segment in service; and
(B) Assess using a high resolution
magnetic flux tool within three
years after placing the new
pipeline segment in service at the
alternative maximum allowable
operating pressure.
(ii) Except as provided in paragraph
(d)(8)(iii) of this section, for an
existing pipeline segment, perform
a baseline internal assessment
using a geometry tool and a high
resolution magnetic flux tool
before, but within two years prior
to, raising pressure to the
alternative maximum allowable
operating pressure as allowed under
this section.
(iii) If headers, mainline valve by-
passes, compressor station piping,
meter station piping, or other
short portion of a pipeline segment
operating at alternative maximum
allowable operating pressure cannot
accommodate a geometry tool and a
high resolution magnetic flux tool,
use direct assessment (per Sec.
192.925, Sec. 192.927 and/or Sec.
192.929) or pressure testing (per
subpart J of this part) to assess
that portion.
(10) Conducting periodic (i) Determine a frequency for
assessments of integrity. subsequent periodic integrity
assessments as if all the
alternative maximum allowable
operating pressure pipeline
segments were covered by subpart O
of this part and
(ii) Conduct periodic internal
inspections using a high resolution
magnetic flux tool on the frequency
determined under paragraph
(d)(9)(i) of this section, or
(iii) Use direct assessment (per
Sec. 192.925, Sec. 192.927 and/
or Sec. 192.929) or pressure
testing (per subpart J of this
part) for periodic assessment of a
portion of a segment to the extent
permitted for a baseline assessment
under paragraph (d)(8)(iii) of this
section.
(11) Making repairs............... (i) Perform the following when
evaluating an anomaly:
(A) Use the most conservative
calculation for determining
remaining strength or an
alternative validated calculation
based on pipe diameter, wall
thickness, grade, operating
pressure, operating stress level,
and operating temperature: and
(B) Take into account the tolerances
of the tools used for the
inspection.
(ii) Repair a defect immediately if
any of the following apply:
(A) The defect is a dent discovered
during the baseline assessment for
integrity under paragraph (d)(8) of
this section and the defect meets
the criteria for immediate repair
in Sec. 192.309(b).
(B) The defect meets the criteria
for immediate repair in Sec.
192.933(d).
(C) The alternative maximum
allowable operating pressure was
based on a design factor of 0.67
under paragraph (a) of this section
and the failure pressure is less
than 1.25 times the alternative
maximum allowable operating
pressure.
(D) The alternative maximum
allowable operating pressure was
based on a design factor of 0.56
under paragraph (a) of this section
and the failure pressure is less
than or equal to 1.4 times the
alternative maximum allowable
operating pressure.
(iii) If paragraph (d)(10)(ii) of
this section does not require
immediate repair, repair a defect
within one year if any of the
following apply:
(A) The defect meets the criteria
for repair within one year in Sec.
192.933(d).
(B) The alternative maximum
allowable operating pressure was
based on a design factor of 0.80
under paragraph (a) of this section
and the failure pressure is less
than 1.25 times the alternative
maximum allowable operating
pressure.
(C) The alternative maximum
allowable operating pressure was
based on a design factor of 0.67
under paragraph (a) of this section
and the failure pressure is less
than 1.50 times the alternative
maximum allowable operating
pressure.
(D) The alternative maximum
allowable operating pressure was
based on a design factor of 0.56
under paragraph (a) of this section
and the failure pressure is less
than or equal to 1.80 times the
alternative maximum allowable
operating pressure.
(iv) Evaluate any defect not
required to be repaired under
paragraph (d)(10)(ii) or (iii) of
this section to determine its
growth rate, set the maximum
interval for repair or re-
inspection, and repair or re-
inspect within that interval.
------------------------------------------------------------------------
[[Page 62181]]
(e) Is there any change in overpressure protection associated with
operating at the alternative maximum allowable operating pressure?
Notwithstanding the required capacity of pressure relieving and
limiting stations otherwise required by Sec. 192.201, if an operator
establishes a maximum allowable operating pressure for a pipeline
segment in accordance with paragraph (a) of this section, an operator
must:
(1) Provide overpressure protection that limits mainline pressure
to a maximum of 104 percent of the maximum allowable operating
pressure; and
(2) Develop and follow a procedure for establishing and maintaining
accurate set points for the supervisory control and data acquisition
system.
Issued in Washington, DC, on October 2, 2008.
Carl T. Johnson,
Administrator.
[FR Doc. E8-23915 Filed 10-16-08; 8:45 am]
BILLING CODE 4910-60-P