[Federal Register Volume 76, Number 165 (Thursday, August 25, 2011)]
[Proposed Rules]
[Pages 53086-53102]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2011-21753]
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DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials Safety Administration
49 CFR Part 192
[Docket No. PHMSA-2011-0023]
RIN 2137-AE72
Pipeline Safety: Safety of Gas Transmission Pipelines
AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA),
Department of Transportation (DOT).
ACTION: Advance notice of proposed rulemaking (ANPRM).
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SUMMARY: PHMSA is considering whether changes are needed to the
regulations governing the safety of gas transmission pipelines. In
particular, PHMSA is considering whether integrity management (IM)
requirements should be changed, including adding more prescriptive
language in some areas, and whether other issues related to system
integrity should be addressed by strengthening or expanding non-IM
requirements. Among the specific issues PHMSA is considering concerning
IM requirements is whether the definition of a high-consequence area
(HCA) should be revised, and whether additional restrictions should be
placed on the use of specific pipeline assessment methods. With respect
to non-IM requirements, PHMSA is considering whether revised
requirements are needed on new construction or existing pipelines
concerning mainline valves, including valve spacing and installation of
remotely operated or automatically operated valves; whether
requirements for corrosion control of steel pipelines should be
strengthened; and whether new regulations are needed to govern the
safety of gathering lines and underground gas storage facilities.
Additional issues PHMSA is considering are addressed in the
SUPPLEMENTARY INFORMATION Section under background.
DATES: Persons interested in submitting written comments on this ANPRM
must do so by December 2, 2011. PHMSA will consider late filed comments
as far as practicable.
FOR FURTHER INFORMATION CONTACT: Mike Israni, by telephone at 202-366-
4571, by fax at 202-366-4566, or by mail at U.S. DOT, PHMSA, 1200 New
Jersey Avenue, SE., PHP-1, Washington, DC 20590-0001.
ADDRESSES: You may submit comments identified by the docket number
PHMSA-2011-0023 by any of the following methods:
Web Site: http://www.regulations.gov. Follow the online
instructions for submitting comments.
Fax: 1-202-493-2251.
Mail: Hand Delivery: U.S. DOT Docket Management System,
West Building Ground Floor, Room W12-140, 1200 New Jersey Avenue, SE.,
Washington, DC 20590-0001 between 9 a.m. and 5 p.m., Monday through
Friday, except Federal holidays.
Instructions: If you submit your comments by mail, submit two
copies. To receive confirmation that PHMSA received your comments,
include a self-addressed stamped postcard.
Note: Comments are posted without changes or edits to http://www.regulations.gov, including any personal information provided.
There is a privacy statement published on http://www.regulations.gov. A glossary of terms used in this document can
be found at the following Web site: http://primis.phmsa.dot.gov/comm/.
SUPPLEMENTARY INFORMATION:
I. Background
Congress has authorized Federal regulation of the transportation of
gas by pipeline under the Commerce Clause of the U.S. Constitution. The
authorization is codified in the Pipeline Safety Laws (49 U.S.C. 60101
et seq.), a series of statutes that are administered by PHMSA. PHMSA
promulgated comprehensive minimum safety standards for the
transportation of gas by pipeline under the Pipeline Safety
[[Page 53087]]
Regulations (PSR; 49 CFR parts 190-199).
Congress established the current framework for regulating natural
gas pipelines in the Natural Gas Pipeline Safety Act of 1968, Public
Law 90-481, which has since been recodified at 49 U.S.C. 60101 et seq.
That law delegated to DOT the authority to develop, prescribe, and
enforce minimum Federal safety standards for the transportation of gas,
including natural gas, flammable gas, or toxic or corrosive gas, by
pipeline. Congress has since enacted additional legislation that is
currently codified in the Pipeline Safety Laws.
In 1992, Congress required regulations be issued to define the term
``gathering line'' and establish safety standards for certain
``regulated gathering lines.'' In 1996, Congress directed that DOT
conduct demonstration projects evaluating the application of risk
management principles to pipeline safety regulations, and mandated that
regulations be issued for the qualification and testing of certain
pipeline personnel.
In 2002, Congress required that DOT issue regulations requiring
operators of gas transmission pipelines to conduct risk analyses and to
implement IM programs under which pipeline segments in HCAs would be
subject to a baseline assessment within ten years and re-assessments at
least every seven years. PHMSA administers compliance with these
statutes and has promulgated comprehensive safety standards and
regulations for the transportation of natural gas by pipeline. That
includes regulations for the:
Design and construction of new pipeline systems or those
that have been relocated, replaced, or otherwise changed (subparts C
and D of 49 CFR part 192).
Protection of steel pipelines from the adverse effects of
internal and external corrosion (subpart I of 49 CFR part 192).
Pressure tests of new pipelines (subpart J of 49 CFR part
192).
Operation and maintenance of pipeline systems, including
establishing programs for public awareness and damage prevention, and
managing the operation of pipeline control rooms (subparts L and M of
49 CFR part 192).
Qualification of pipeline personnel (subpart N of 49 CFR
part 192).
Management of the integrity of pipelines in HCAs (subpart
O of 49 CFR part 192).
The IM requirements of subpart O of 49 CFR part 192 apply to areas
called high consequence areas or HCA's. An integrity management program
is a documented set of policies, processes, and procedures that are
implemented to ensure the integrity of a pipeline. In accordance with
pipeline safety regulations for gas transmission pipelines (subpart O
of 49CFR part 192) an operator's integrity management program must
include, at a minimum, the following elements:
a. An identification of all high consequence areas;
b. A baseline assessment plan;
c. An identification of threats to each covered pipeline segment,
which must include data integration and a risk assessment. An operator
must use the threat identification and risk assessment to prioritize
covered segments for assessment and to evaluate the merits of
additional preventive and mitigative measures for each covered segment;
d. A direct assessment plan, if applicable;
e. Provisions for remediating conditions found during an integrity
assessment;
f. A process for continual evaluation and assessment;
g. If applicable, a plan for confirmatory direct assessment meeting
the requirement;
h. Provisions for adding preventive and mitigative measures to
protect the high consequence area;
i. A performance plan that includes performance measures;
j. Record keeping provisions;
k. A management of change process;
l. A quality assurance process;
m. A communication plan that includes procedures for addressing
safety concerns raised by PHMSA or a State or local pipeline safety
authority;
n. Procedures for providing (when requested) a copy of the
operator's risk analysis or integrity management program to PHMSA or a
State or local pipeline safety authority; and
o. Procedures for ensuring that each integrity assessment is being
conducted in a manner that minimizes environmental and safety risks;
p. A process for identification and assessment of newly-identified
high consequence areas.
A high consequence area is a location that is specially defined in
the pipeline safety regulations as an area where pipeline releases
could have greater consequences to health and safety or the
environment. Regulations require a pipeline operator to take specific
steps to ensure the integrity of a pipeline for which a release could
affect an HCA and, thereby, the protection of the HCA. The PSR provide
gas transmission pipeline operators with two options by which to
identify which segments of their pipelines are in HCAs: (1) Reliance on
class locations that historically have been part of the pipeline safety
regulations for identifying pipelines in more-populated areas, or (2)
determining segments for which a specified number of structures
intended for human occupation or a so-called identified site
(representing areas where people congregate) are located within the
potential impact radius of a hypothetical pipeline rupture and
subsequent explosion.
Other recent rulemaking have addressed different but related issues
relative to pipeline safety. On October 18, 2010 (75 FR 63774) PHMSA
published an ANPRM titled ``Pipeline Safety: Safety of On-Shore
Hazardous Liquid Pipelines.'' In that rulemaking, PHMSA is considering
whether changes are needed to the regulations covering hazardous liquid
onshore pipelines. In particular, PHMSA sought comment on whether it
should extend regulation to certain pipelines currently exempt from
regulation; whether other areas along a pipeline should either be
identified for extra protection or be included as additional HCAs for
IM protection; whether to establish and/or adopt standards and
procedures for minimum leak detection requirements for all pipelines;
whether to require the installation of emergency flow restricting
devices (EFRDs) in certain areas; whether revised valve spacing
requirements are needed on new construction or existing pipelines;
whether repair timeframes should be specified for pipeline segments in
areas outside the HCAs that are assessed as part of the IM; and whether
to establish and/or adopt standards and procedures for improving the
methods of preventing, detecting, assessing and remediating stress
corrosion cracking (SCC) in hazardous liquid pipeline systems.
On December 4, 2009, PHMSA issued the Distribution Integrity
Management Final Rule, which extends the pipeline integrity management
principles that were established for hazardous liquid and natural gas
transmission pipelines, to the local natural gas distribution pipeline
systems. This regulation, which became effective in August of 2011,
requires operators of local gas distribution pipelines to evaluate the
risks on their pipeline systems, to determine their fitness for
service, and to take action to address those risks. For older gas
distribution systems, the appropriate mitigation measures could involve
major pipe rehabilitation, repair, and replacement programs. At a
minimum, these measures are needed to requalify those systems as being
fit for service.
[[Page 53088]]
II. Advance Notice of Proposed Rulemaking
PHMSA believes that the IM requirements applicable to gas
transmission pipelines contained in the Pipeline Safety Regulations (49
CFR parts 190-199) have increased the level of safety associated with
the transportation of gas in HCA's. Still, incidents with significant
consequences continue to occur on gas transmission pipelines (e.g.,
incident in San Bruno, CA September 9, 2010). PHMSA has also identified
concerns during inspections of gas transmission pipeline operator IM
programs that indicate a potential need to clarify and enhance some
requirements. PHMSA is now considering whether additional safety
measures are necessary to increase the level of safety for those
pipelines that are in non-HCA areas as well as whether the current IM
requirements need to be revised and enhanced to assure that they
continue to provide an adequate level of safety in HCAs.
Within this ANPRM, PHMSA is seeking public comment on 14 specific
topic areas in two broad categories.
1. Should IM requirements be revised and strengthened to bring more
pipeline mileage under IM requirements and to better assure safety of
pipeline segments in HCAs? Specific topics include:
Modifying the definition of an HCA.
Strengthening the Integrity Management requirements in
part 192.
Modifying repair criteria.
Revising the requirements for collecting, validating, and
integrating pipeline data.
Making requirements related to the nature and application
of risk models more prescriptive.
Strengthening requirements for applying knowledge gained
through the IM program.
Strengthening requirements on the selection and use of
assessment methods, including prescribing assessment methods for
certain threats (such as manufacturing and construction defects, SCC,
etc.) or in certain situations such as when certain knowledge is not
available or data is missing.
2. Should non-IM requirements be strengthened or expanded to
address other issues associated with pipeline system integrity?
Specific topics include:
Valve spacing and the need for remotely- or automatically-
controlled valves.
Corrosion control.
Pipe with longitudinal weld seams with systemic integrity
issues.
Establishing requirements applicable to underground gas
storage.
Management of Change.
Quality Management Systems (QMS).
Exemptions applicable to \1\ facilities installed prior to
the regulations.
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\1\ As described below, these exemptions relate to allowable
maximum operating pressure for pipelines that were in service before
the initial gas pipeline safety regulations were published. These
pipelines are commonly known as ``grandfathered'' pipelines.
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Gathering lines.
Each topic is discussed in more detail in this document.
A. Modifying the Definition of HCA
Part 192 has historically included requirements delineating
pipeline segments by class location based on the population density
near the pipeline. Class locations are based on the number of buildings
intended for human occupancy that exist within a ``class location
unit,'' defined as an area extending 220 yards (100 meters) on either
side of the centerline of any continuous one-mile (1.6 kilometers)
length of pipeline. Class locations are defined in Sec. 192.5 as:
Class 1--10 or fewer buildings intended for human
occupancy within a class location unit.
Class 2--more than ten but less than 46 buildings intended
for human occupancy.
Class 3--46 or more buildings intended for human
occupancy.
Class 4--any class location unit where buildings with four
or more stories are prevalent.
Part 192 provides additional protection for higher class location
areas, principally through provisions that require pipe in these higher
class locations to operate at lower stress levels.
With the advent of IM requirements, PHMSA introduced a new
mechanism in part 192 to define pipeline segments to which additional
requirements should apply based on the population at risk in the
vicinity of the pipeline. HCAs are defined in Sec. 192.903 using
either of two methods. Operators are allowed to pick the method they
use to identify their HCAs.
Method 1 builds on the traditional concept of class locations.
Under this method, all pipeline segments in Class 3 and 4 locations are
within an HCA. In addition, pipeline segments in Class 1 and 2
locations are within an HCA if an ``identified site'' is located within
the ``potential impact circle.'' Identified sites are defined as areas
in which 20 or more persons congregate for a specified number of days
each year or facilities occupied by persons who are confined, of
impaired mobility, or would be difficult to evacuate.
Method 2 defines HCAs based solely on potential impact circles. A
potential impact circle is an estimated zone in which the failure of a
pipeline could have significant impact on people or property. The
radius of the potential impact circle is calculated using a formula
specified in the regulations that is based on the diameter and
operating pressure of the pipeline. A pipeline segment is identified as
an HCA if the potential impact circle includes 20 or more buildings
intended for human occupancy or an identified site, regardless of class
location.
Some gas transmission pipeline operators do not collect data
concerning the number of buildings within class location units along
their pipeline, but rather design all of their pipelines as though they
were in a Class 3 or 4 location. This approach is often used by
operators of gas distribution companies that also operate small amounts
of pipeline meeting part 192's definition as transmission pipeline.
Method 1 was included in the definition of an HCA in deference to these
operators, allowing them to avoid the additional costs associated with
collecting data on nearby buildings that they have not previously
collected. Method 2 was presumed to identify pipeline segments where
incidents could produce high consequences more accurately and is
typically used by pipeline operators who have collected data on local
structures to determine class locations.
PHMSA regulates approximately 297,000 miles of onshore gas
transmission pipelines. Of these, approximately 30,300 miles (10.2%)
are in Class 2 locations, approximately 33,500 miles (11.3%) are in
Class 3 locations, and approximately 1600 miles (0.54%) are in Class 4
locations. Operators have identified approximately 19,000 miles (6.4%)
of gas transmission pipeline to be within an HCA.
IM requirements in subpart O of part 192 specify how pipeline
operators must identify, prioritize, assess, evaluate, repair and
validate; through comprehensive analyses, the integrity of gas
transmission pipelines in HCAs. Although operators may voluntarily
apply IM practices to pipeline segments that are not in HCAs, the
regulations do not require operators to do so.
A gas transmission pipeline ruptured in San Bruno, California on
September 9, 2010, resulting in eight deaths and considerable property
damage. As a result of this event, public concern has been raised
regarding whether safety requirements applicable to pipe in populated
areas can be improved. PHMSA is thus considering expanding the
definition of an HCA so that more
[[Page 53089]]
miles of pipe are subject to IM requirements.
Questions
A.1. Should PHMSA revise the existing criteria for identifying HCAs
to expand the miles of pipeline included in HCAs? If so, what
amendments to the criteria should PHMSA consider (e.g., increasing the
number of buildings intended for human occupancy in Method 2?) Have
improvements in assessment technology during the past few years led to
changes in the cost of assessing pipelines? Given that most non-HCA
mileage is already subjected to in-line inspection (ILI) does the
contemplated expansion of HCAs represent any additional cost for
conducting integrity assessments? If so, what are those costs? How
would amendments to the current criteria impact state and local
governments and other entities?
A.2. Should the HCA definition be revised so that all Class 3 and 4
locations are subject to the IM requirements? What has experience shown
concerning the HCA mileage identified through present methods (e.g.,
number of HCA miles relative to system mileage or mileage in Class 3
and 4 locations)? Should the width used for determining class location
for pipelines over 24 inches in diameter that operate above 1000 psig
be increased? How many miles of HCA covered segments are Class 1, 2, 3,
and 4? How many miles of Class 2, 3, and 4 pipe do operators have that
are not within HCAs?
A.3. Of the 19,004 miles of pipe that are identified as being
within an HCA, how many miles are in Class 1 or 2 locations?
A.4. Do existing criteria capture any HCAs that, based on risk, do
not provide a substantial benefit for inclusion as an HCA? If so, what
are those criteria? Should PHMSA amend the existing criteria in any way
which could better focus the identification of an HCA based on risk
while minimizing costs? If so, how? Would it be more beneficial to
include more miles of pipeline under existing HCA IM procedures, or, to
focus more intense safety measures on the highest risk, highest
consequence areas or something else? If so, why?
A.5. In determining whether areas surrounding pipeline right-of-
ways meet the HCA criteria as set forth in part 192, is the potential
impact radius sufficient to protect the public in the event of a gas
pipeline leak or rupture? Are there ways that PHMSA can improve the
process of right-of-ways HCA criteria determinations?
A.6. Some pipelines are located in right-of-ways also used, or
paralleling those, for electric transmission lines serving sizable
communities. Should HCA criteria be revised to capture such critical
infrastructure that is potentially at risk from a pipeline incident?
A.7. What, if any, input and/or oversight should the general public
and/or local communities provide in the identification of HCAs? If
commenters believe that the public or local communities should provide
input and/or oversight, how should PHMSA gather information and
interface with these entities? If commenters believe that the public or
local communities should provide input and/or oversight, what type of
information should be provided and should it be voluntary to do so? If
commenters believe that the public or local communities should provide
input, what would be the burden entailed in providing provide this
information? Should state and local governments should be involved in
the HCA identification and oversight process? If commenters believe
that state and local governments be involved in the HCA identification
and oversight process what would the nature of this involvement be?
A.8. Should PHMSA develop additional safety measures, including
those similar to IM, for areas outside of HCAs? If so, what would they
be? If so, what should the assessment schedule for non-HCAs be?
A.9. Should operators be required to submit to PHMSA geospatial
information related to the identification of HCAs?
A10. Why has the number of HCA miles declined over the years?
A.11. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements pursuant to the commenter's suggestions.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the
existing regulatory requirements.
B. Strengthening Requirements To Implement Preventive and Mitigative
Measures for Pipeline Segments in HCAs
Section 192.935 requires gas transmission pipeline operators to
take additional measures, beyond those already required by part 192, to
prevent a pipeline failure and to mitigate the consequences of a
potential failure in an HCA. The additional measures to be taken are
not specified. Rather, operators are required to base selection and
implementation of these measures on the threats the operator has
identified to each pipeline segment. Operators must use their
comprehensive risk analyses to identify additional measures appropriate
to the HCA. However, the rule establishes no objective criteria by
which decisions concerning additional measures must be made, nor does
it establish a standard by which such evaluations are to be performed.
PHMSA is considering revising the IM requirement to add new
requirements governing selection of additional preventive and
mitigative measures.
The current regulations state that these additional measures might
include: Installing Automatic Shut-off Valves or Remote Control Valves;
Installing computerized monitoring and leak detection systems;
replacing pipe segments with pipe of heavier wall thickness; providing
additional training to personnel on response procedures; conducting
drills with local emergency responders; and implementing additional
inspection and maintenance programs, but does not require
implementation of any of these measures. Operators are also required to
enhance their damage prevention programs and to take additional
measures to protect HCA segments subject to the threat of outside force
damage (non-excavation). Operators are required to install automatic or
remotely-operable valves if their risk analysis concludes these would
be an efficient means of adding protection to the HCA in the event of a
gas release.
The requirements of Sec. 192.935 apply only to pipeline segments
in HCAs. As discussed above, only 6.4 percent of gas transmission
pipeline mileage is currently classified as ``located within HCAs.''
Revising the criteria for identifying HCAs could, of course, increase
the number of pipeline miles to which the requirements of Sec. 192.935
apply. Still, PHMSA is considering whether these requirements, or other
requirements for additional preventive and mitigative measures, should
apply to pipelines outside of HCAs.
[[Page 53090]]
Questions
B.1. What practices do gas transmission pipeline operators now use
to make decisions as to whether/which additional preventive and
mitigative measures are to be implemented? Are these decisions guided
by any industry or consensus standards? If so, what are those industry
or consensus standards?
B.2. Have any additional preventive and mitigative measures been
voluntarily implemented in response to the requirements of Sec.
192.935? How prevalent are they? Do pipeline operators typically
implement specific measures across all HCAs in their pipeline system,
or do they target measures at individual HCAs? How many miles of HCA
are afforded additional protection by each of the measures that have
been implemented? To what extent do pipeline operators implement
selected measures to protect additional pipeline mileage not in HCAs?
B.3. Are any additional prescriptive requirements needed to improve
selection and implementation decisions? If so, what are they and why?
B.4. What measures, if any, should operators be required explicitly
to implement? Should they apply to all HCAs, or is there some
reasonable basis for tailoring explicit mandates to particular HCAs?
Should additional preventative and mitigative measures include any or
all of the following: Additional line markers (line-of-sight); depth of
cover surveys; close interval surveys for cathodic protection (CP)
verification; coating surveys and recoating to help maintain CP current
to pipe; additional right-of-way patrols; shorter ILI run intervals;
additional gas quality monitoring, sampling, and in-line inspection
tool runs; and improved standards for marking pipelines for operator
construction and maintenance and one-calls? If so, why?
B.5. Should requirements for additional preventive and mitigative
measures be established for pipeline segments not in HCAs? Should these
requirements be the same as those for HCAs or should they be different?
Should they apply to all pipeline segments not in HCAs or only to some?
If not all, how should the pipeline segments to which new requirements
apply be delineated?
B.6. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements pursuant to the commenter's suggestions.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the
existing regulatory requirements.
C. Modifying Repair Criteria
The existing IM regulations establish criteria for the timely
repair of injurious anomalies and defects discovered in the pipe (Sec.
192.933). These criteria apply to pipeline segments in an HCA, but not
to segments outside an HCA. PHMSA is considering whether changes are
needed to the IM rule related to the repair criteria to provide greater
assurance that injurious anomalies and defects are repaired before the
defect can grow to a size that leads to a leak or rupture. In addition,
PHMSA is considering whether or not to establish repair criteria for
pipeline segments located in areas outside an HCA, to provide greater
assurance that defects on non-HCA pipeline segments are repaired in a
timely manner.
In 2000 and 2002, PHMSA published final rules (65 FR 75378; 12/1/
2000 and 67 FR 2136; 1/16/2002) requiring IM Programs for hazardous
liquid pipeline operators. In 2003, similar IM regulations were enacted
for gas pipelines (68 FR 69778; 12/15/2003). Some 43.9% of the nation's
hazardous liquid pipelines (77,421 miles) and 6.5% of the natural gas
transmission pipelines (19,004 miles) can potentially affect HCAs and
thus receive the enhanced level of integrity assessment mandated by the
IM rule. As a result of assessments, over the six-year period between
2004 and 2009, hazardous liquid operators have made 6,419 repairs of
anomalies in HCAs that required immediate attention and remediated
25,027 other conditions on a scheduled basis. Between 2004 and 2009,
gas pipeline operators have repaired 1,052 anomalies that required
immediate attention and 2,239 other conditions. During this six-year
period, hazardous liquid pipelines repair rate was 41.3 repairs per 100
HCA miles and gas transmission pipelines repair rate was 17.3 repairs
per 100 HCA miles.
The gas IM regulations (Sec. 192.933) require ``prompt action'' to
address all anomalous conditions discovered. More specifically, the IM
regulation mandates ``immediate'' pressure reduction, pipeline
shutdown, or repair of the following conditions: A predicted failure
pressure less than or equal to 1.1 times (<= 1.1) the established
maximum allowable operating pressure (MAOP) at the location of the
anomaly; a dent that has any indication of metal loss, cracking, or a
stress riser; or any anomaly that in the judgment of the person
designated by the operator to evaluate assessment results requires
immediate action. Furthermore, operators must repair within one year,
smooth dents at the top of the pipeline with a depth greater than six
percent of the pipeline diameter and dents with a depth greater than
two percent of the pipeline diameter that affect pipe curvature at a
girth weld or at a longitudinal seam weld.
The method used to calculate the predicted failure pressure is
prescribed in part 192. However, the methods do not account for such
factors as inaccurate ILI tool results, low tensile steel strength due
to steel property variances, external loads such as caused by soil
movement or settlement, or vehicle or farm equipment crossing the
pipeline at grade. The IM repair criterion (predicted failure pressures
<= 1.1 MAOP) includes a 10% margin between the predicted failure
pressure and MAOP. PHMSA is considering if this is adequate to account
for the above factors as well as operational factors that allow for the
pipeline to operate up to 110% MAOP for brief periods during upset
conditions (Sec. Sec. 192.201 and 192.739).
In addition, regulations at Sec. Sec. 192.103, 192.105, 192.107,
and 192.111 require the usage of class location design factors. The
design factor is 0.72 for Class 1 locations. The reciprocal (1.39) can
be used to express a failure pressure ratio for sound pipe in a Class 1
location. The failure pressure ratio (FPR) of 1.39 indicates a safety
factor over MAOP of 39 percent. This ratio is higher in other class
locations (i.e., 1.67 in Class 2, 2.0 in Class 3, and 2.5 in Class 4).
PHMSA is considering if class location design factors should be
explicitly factored into repair criteria.
The assessments operators have been conducting on pipeline segments
in HCAs have often extended to areas beyond the HCAs. PHMSA believes
that many repairs have been made outside HCAs as in HCAs due to
anomalies identified in these extended assessments, but gas
transmission pipeline operators are not required to report these
repairs so specific data are not available. Up to now, PHMSA has
enforced the IM repair criteria as only applying to the anomalous
conditions discovered in the HCAs. If, through the integrity assessment
or information
[[Page 53091]]
analysis, the operator discovers anomalous conditions in the areas
outside the HCA, the pipeline safety regulations require operators to
use the prompt remediation requirements in Sec. 192.703 rather than
the IM repair criteria. Though the remediation requirements in Sec.
192.703 are more conservative than the IM repair criteria, this
difference is off-set by the establishment of repair time frames,
increased monitoring of any anomalous conditions, and other safety off-
sets. The safety factor associated with the repair criteria in non-HCA
is related to the class location design factor. For example, a Class 1
location has a 39% safety factor (1.67 in Class 2, 2.0 in Class 3 and
2.5 in Class 4). PHMSA is now considering whether the IM repair time
frames should also be made to apply to the pipeline segments located
outside HCAs when anomalous conditions in these areas are discovered
through the integrity assessment. This would provide greater assurance
that defects on non-HCA pipeline segments are repaired in a timely
manner.
Questions
C.1. Should the immediate repair criterion of FPR <= 1.1 be revised
to require repair at a higher threshold (i.e., additional safety margin
to failure)? Should repair safety margins be the same as new
construction standards? Should class location changes, where the class
location has changed from Class 1 to 2, 2 to 3, or 3 to 4 without pipe
replacement have repair criteria that are more stringent than other
locations? Should there be a metal loss repair criterion that requires
immediate or a specified time to repair regardless of its location (HCA
and non-HCA)?
C.2. Should anomalous conditions in non-HCA pipeline segments
qualify as repair conditions subject to the IM repair schedules? If so,
which ones? What projected costs and benefits would result from this
requirement?
C.3. Should PHMSA consider a risk tiering--where the conditions in
the HCA areas would be addressed first, followed by the conditions in
the non-HCA areas? How should PHMSA evaluate and measure risk in this
context, and what risk factors should be considered?
C.4. What should be the repair schedules for anomalous conditions
discovered in non-HCA pipeline segments through the integrity
assessment or information analysis? Would a shortened repair schedule
significantly reduce risk? Should repair schedules for anomalous
conditions in HCAs be the same as or different from those in non-HCAs?
C.5. Have ILI tool capability advances resulted in a need to update
the ``dent with metal loss'' repair criteria?
C.6. How do operators currently treat assessment tool uncertainties
when comparing assessment results to repair criteria? Should PHMSA
adopt explicit voluntary standards to account for the known accuracy of
in-line inspection tools when comparing in-line inspection tool data
with the repair criteria? Should PHMSA develop voluntary assessment
standards or prescribe ILI assessment standards including wall loss
detection threshold depth detection, probability of detection, and
sizing accuracy standards that are consistent for all ILI vendors and
operators? Should PHMSA prescribe methods for validation of ILI tool
performance such as validation excavations, analysis of as-found versus
as-predicted defect dimensions? Should PHMSA prescribe appropriate
assessment methods for pipeline integrity threats?
C.7. Should PHMSA adopt standards for conducting in-line
inspections using ``smart pigs,'' the qualification of persons
interpreting in-line inspection data, the review of ILI results
including the integration of other data sources in interpreting ILI
results, and/or the quality and accuracy of in-line inspection tool
performance, to gain a greater level of assurance that injurious
pipeline defects are discovered? Should these standards be voluntary or
adopted as requirements?
C.8. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements pursuant to the commenter's suggestions.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the
existing regulatory requirements.
D. Improving Requirements for Collecting, Validating, and Integrating
Pipeline Data
IM regulations require that gas transmission pipeline operators
gather and integrate existing data and information concerning their
entire pipeline that could be relevant to pipeline segments in HCAs
(Sec. 192.917(b)). Operators are then required to use this information
in a risk assessment of the covered segments at (Sec. 192.917(c)) that
must subsequently be used to determine whether additional preventive
and mitigative measures are needed (Sec. 192.935) and to define the
intervals at which IM reassessments must be performed (Sec. 192.939).
Operators' risk analyses and the conclusions reached using them can
only be as good as the information used to perform the analysis.
Preliminary results from the investigation of the September 9,
2010, pipeline rupture and explosion in San Bruno, CA, indicate that
the pipeline operator's records concerning the pipe segments involved
in the incident were erroneous. The errors affected basic information
about the pipeline. For example, the records indicated that pipe in the
area was 30-inch diameter seamless pipe, whereas pipe fragments
recovered after the incident showed that seamed pipe was present. Thus,
analyses performed using the information in the operator's records
before the incident could not have led to accurate conclusions
concerning risk, whether or not additional preventive and mitigative
measures were needed, or what the allowable MAOP should be. PHMSA
issued an Advisory Bulletin (76 FR 1504; January 10, 2011) on this
issue. PHMSA is considering whether more prescriptive requirements for
collecting, validating, integrating and reporting pipeline data is
necessary.
Questions
D.1. What practices are now used to acquire, integrate and validate
data (e.g., review of mill inspection reports, hydrostatic tests
reports, pipe leaks and rupture reports) concerning pipelines? Are
practices in place, such as excavations of the pipeline, to validate
data?
D.2. Do operators typically collect data when the pipeline is
exposed for maintenance or other reasons to validate information in
their records? If discrepancies are found, are investigations conducted
to determine the extent of record errors? Should these actions be
required, especially for HCA segments?
D.3. Do operators try to verify data on pipe, pipe seam type, pipe
mechanical and chemical properties, mill inspection reports,
hydrostatic tests reports, coating type and condition, pipe leaks and
ruptures, and operations and maintenance (O&M) records on a periodic
basis? Are practices in place to validate data, such as excavation and
in situ examinations of the pipeline? If so, what are these practices?
[[Page 53092]]
D.4. Should PHMSA make current requirements more prescriptive so
operators will strengthen their collection and validation practices
necessary to implement significantly improved data integration and risk
assessment practices?
D.5. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements pursuant to the commenter's suggestions.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the
existing regulatory requirements.
E. Making Requirements Related to the Nature and Application of Risk
Models More Prescriptive
As described above, current regulations require that gas
transmission pipeline operators perform risk analyses of their covered
segments and use these analyses to make certain decisions concerning
actions to assure the integrity of their pipeline and to enhance
protection against the consequences of potential incidents. The
regulations do not prescribe the type of risk analysis nor impose any
requirements regarding its breadth and scope.
PHMSA's experience in inspecting operator compliance with IM
requirements has identified that most pipeline operators use a relative
index-model approach to performing their risk assessments and that
there is a wide range in scope and quality of the resulting analyses.
It is not clear that all of the observed risk analyses can support
robust decision making and management of the pipeline risk. PHMSA is
considering making requirements related to the nature and application
of risk models more prescriptive to improve the usefulness of these
analyses in informing decisions to control risks from pipelines.
Questions
E.1. Should PHMSA either strengthen requirements on the functions
risk models must perform or mandate use of a particular risk model for
pipeline risk analyses? If so, how and which model?
E.2. It is PHMSA's understanding that existing risk models used by
pipeline operators generally evaluate the relative risk of different
segments of the operator's pipeline. PHMSA is seeking comment on
whether or not that is an accurate understanding. Are relative index
models sufficiently robust to support the decisions now required by the
regulation (e.g., evaluation of candidate preventive and mitigative
measures, and evaluation of interacting threats)?
E.3. How, if at all, are existing models used to inform executive
management of existing risks?
E.4. Can existing risk models be used to understand major
contributors to segment risk and support decisions regarding how to
manage these contributors? If so, how?
E.5. How can risk models currently used by pipeline operators be
improved to assure usefulness for these purposes?
E.6. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements pursuant to the commenters' suggestions.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the
existing regulatory requirements.
F. Strengthening Requirements for Applying Knowledge Gained Through the
IM Program
IM assessments provide information about the condition of the
pipeline segments assessed. Identified anomalies that exceed criteria
in Sec. 192.933 must be remediated immediately (Sec. 192.933(d)(1))
or within one year (Sec. 192.933(d)(2)) or must be monitored on future
assessments (Sec. 192.933(d)(3)). Operators are also expected to apply
knowledge gained through these assessments to assure the integrity of
their entire pipeline.
Section 192.917(e)(5) explicitly requires that operators must
consider other portions of their pipeline if an assessment identifies
corrosion requiring repair under the criteria of Sec. 192.933. The
operator must ``evaluate and remediate, as necessary, all pipeline
segments (both covered and non-covered) with similar material coating
and environmental characteristics.''
Section 192.917 also requires that operators conduct risk
assessments that follow American Society of Mechanical Engineers/
American National Standards Institute (ASME/ANSI) B31.8S, Section 5,
and use these analyses to prioritize segments for assessment, and to
determine what preventive and mitigative measures are needed for
segments in HCAs. Section 5.4 of ASME/ANSI B31.8S states that ``risk
assessment methods should be used in conjunction with knowledgeable,
experienced personnel * * * that regularly review the data input,
assumptions, and results of the risk assessments.'' That Section
further states ``An integral part of the risk assessment process is the
incorporation of additional data elements or changes to facility data''
and requires that operators ``incorporate the risk assessment process
into existing field reporting, engineering, and facility mapping
processes'' to facilitate such updates. Neither part 192 nor ASME/ANSI
B31.8S specifies a periodicity by which pipeline risk analyses must be
reviewed and updated. This is considered a continuous ongoing process.
PHMSA is considering strengthening requirements related to
operators' use of insights gained from implementation of its IM
program.
Questions
F.1. What practices do operators use to comply with Sec.
192.917(e)(5)?
F.2. How many times has a review of other portions of a pipeline in
accordance with Sec. 192.917(e)(5) resulted in investigation and/or
repair of pipeline segments other than the location on which corrosion
requiring repair was initially identified?
F.3. Do pipeline operators assure that their risk assessments are
updated as additional knowledge is gained, including results of IM
assessments? If so, how? How is data integration used and how often is
it updated? Is data integration used on alignment maps and layered in
such a way that technical reviews can identify integrity-related
problems and threat interactions? How often should aerial photography
and patrol information be updated for IM assessments? If the commenter
proposes a time period for updating, what is the basis for this
recommendation?
F.4. Should the regulations specify a maximum period in which
pipeline risk assessments must be reviewed and validated as current and
accurate? If so, why?
[[Page 53093]]
F.5. Are there any additional requirements PHMSA should consider to
assure that knowledge gained through IM programs is appropriately
applied to improve safety of pipeline systems?
F.6. What do operators require for data integration to improve the
safety of pipeline systems in HCAs? What is needed for data integration
into pipeline knowledge databases? Do operators include a robust
database that includes: Pipe diameter, wall thickness, grade, and seam
type; pipe coating; girth weld coating; maximum operating pressure
(MOP); HCAs; hydrostatic test pressure including any known test
failures; casings; any in-service ruptures or leaks; ILI surveys
including high resolution--magnetic flux leakage (HR-MFL), HR-geometry/
caliper tools; close interval surveys; depth of cover surveys;
rectifier readings; test point survey readings; alternating current/
direct current (AC/DC) interference surveys; pipe coating surveys; pipe
coating and anomaly evaluations from pipe excavations; SCC excavations
and findings; and pipe exposures from encroachments?
F.7. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements pursuant to the commenter's suggestions.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the
existing regulatory requirements.
G. Strengthening Requirements on the Selection and Use of Assessment
Methods
The existing IM regulations require that baseline and periodic
assessments of pipeline segments in an HCA be performed using one of
four methods:
(1) In-line inspection;
(2) Pressure test per subpart J;
(3) Direct assessment to address the threats of external and
internal corrosion and SCC; or
(4) Other technology that an operator demonstrates can provide an
equivalent understanding of the condition of line pipe.
Operators must notify PHMSA in advance if they plan to use ``other
technology.'' Operators must apply one or more methods, depending on
the threats to which the covered segment is susceptible.
The three specified assessment methods provide different levels of
understanding of pipeline integrity. In-line inspection, using modern
technology, can provide information concerning small anomalies that can
be evaluated and addressed, if needed, before they adversely affect
pipeline integrity. In-line inspection, with appropriate selection of
tools, is capable of detecting many types of anomalies including
corrosion, dents and deformation, selective seam corrosion and other
seam issues, and SCC. Pressure testing provides no information about
the existence of anomalies that do not result in leaks or failures
during the pressure test. Pressure tests are conducted at a pressure
higher than MAOP to afford a safety margin between MAOP and a pressure
at which failure might occur. Direct assessment can identify conditions
(e.g., coating holidays, presence of water in the gas stream) that
could lead to degradation and, through related excavations and direct
examination, knowledge of whether such degradation is occurring in the
locations examined. Direct assessment is not a satisfactory assessment
technology to identify or characterize threats such as material or
construction defects other than coating holidays, unless it is used
with other non-destructive exam technologies that conduct a full pipe
and weld body examination.
Standards for conducting pressure tests are specified in subpart J
of part 192 and minimum pressures for these tests can be found at
Sec. Sec. 192.505, 192.507, 192.619, 192.620. Standards for external
corrosion direct assessment (ECDA) are specified in Sec. 192.925 and
in National Association of Corrosion Engineers (NACE) NACE RP0502-2008
(incorporated by reference). Standards for internal corrosion direct
assessment (ICDA) and SCC direct assessment (SCCDA) are in Sec. Sec.
192.927 and 192.929 respectively, but in neither case is a consensus
standard incorporated as is the case for ECDA. Standards for in-line
inspection are not specified in the regulations.
PHMSA is considering strengthening the requirements for selection
and use of assessment methods.
Questions
G.1. Have any anomalies been identified that require repair through
various assessment methods (e.g., number of immediate and total repairs
per mile resulting from ILI assessments, pressure tests, or direct
assessments)?
G.2. Should the regulations require assessment using ILI whenever
possible, since that method appears to provide the most information
about pipeline conditions? Should restrictions on the use of assessment
technologies other than ILI be strengthened? If so, in what respect?
Should PHMSA prescribe or develop voluntary ILI tool types for
conducting integrity assessments for specific threats such as corrosion
metal loss, dents and other mechanical damage, longitudinal seam
quality, SCC, or other attributes?
G.3. Direct assessment is not a valid method to use where there are
pipe properties or other essential data gaps. How do operators decide
whether their knowledge of pipeline characteristics and their
confidence in that knowledge is adequate to allow the use of direct
assessment?
G.4. How many miles of gas transmission pipeline have been modified
to accommodate ILI inspection tools? Should PHMSA consider additional
requirements to expand such modifications? If so, how should these
requirements be structured?
G.5. What standards are used to conduct ILI assessments? Should
these standards be incorporated by reference into the regulations?
Should they be voluntary?
G.6. What standards are used to conduct ICDA and SCCDA assessments?
Should these standards be incorporated into the regulations? If the
commenter believes they should be incorporated into the regulations,
why? What, if any, remediation, hydrostatic test or replacement
standards should be incorporated into the regulations to address
internal corrosion and SCC?
G.7. Does NACE SP0204-2008 (formerly RP0204), ``Stress Corrosion
Cracking Direct Assessment Methodology'' address the full lifecycle
concerns associated with SCC?
G.8. Are there statistics available on the extent to which the
application of NACE SP0204-2008, or other standards, have affected the
number of SCC indications operators have detected and remediated on
their pipelines?
G.9. Should a one-time pressure test be required to address
manufacturing and construction defects?
G.10. Have operators conducted quality audits of direct assessments
to determine the effectiveness of direct assessment in identifying
pipeline defects?
G.11. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests
[[Page 53094]]
commenters to provide information and supporting data related to:
The potential costs of modifying the existing regulatory
requirements pursuant to the commenter's suggestions.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the
existing regulatory requirements.
H. Valve Spacing and the Need for Remotely or Automatically Controlled
Valves
Gas transmission pipelines are required to incorporate
sectionalizing block valves. These valves can be used to isolate a
section of the pipeline for maintenance or in response to an incident.
Valves are required to be installed at closer intervals in areas where
the population density near the pipeline is higher. Section 192.179
requires that block valves be located such that:
``(1) Each point on the pipeline in a Class 4 location must be
within 2\1/2\ miles (4 kilometers) of a valve.
(2) Each point on the pipeline in a Class 3 location must be
within 4 miles (6.4 kilometers) of a valve.
(3) Each point on the pipeline in a Class 2 location must be
within 7\1/2\ miles (12 kilometers) of a valve.
(4) Each point on the pipeline in a Class 1 location must be
within 10 miles (16 kilometers) of a valve.''
These requirements apply to initial gas transmission pipeline
construction. If population increases after a pipeline is placed in
service, such that the class location changes, operators must reduce
pressure, conduct pressure tests or verify the adequacy of prior
pressure tests, or replace the pipeline to allow continued operation at
the existing pressure. If operators replace the pipeline, then Sec.
192.13(a)(1) would require that the new pipeline be ``designed,
installed, constructed, initially inspected, and initially tested in
accordance with this part,'' including the requirements for valve
spacing. If operators reduce pressure or verify that prior pressure
tests are sufficient to justify continued operation without reducing
pressure or replacing the pipeline, then no current regulation would
require that new valves be installed to comply with the spacing
requirements in Sec. 192.179.
Sectionalizing block valves are not required to be remotely
operable or to operate automatically in the event of an unexpected
reduction in pressure (e.g., from a pipeline rupture). Congress has
previously required PHMSA to ``assess the effectiveness of remotely
controlled valves to shut off the flow of natural gas in the event of a
rupture'' and to require use of such valves if they were shown
technically and economically feasible.\2\ The National Transportation
Safety Board (NTSB) has also issued a number of recommendations
concerning requirements for use of automatic or remotely operated
mainline valves, including one following a 1994 pipeline rupture in
Edison, NJ.\3\ PHMSA's predecessor agency, the Research and Special
Programs Administration (RSPA) conducted the Congressionally-mandated
evaluation and concluded that remotely and automatically controlled
mainline valves are technically feasible but not, on a generic basis,
economically feasible.\4\ Nevertheless, IM regulations require that an
operator must install an automatic or remotely operated valve if the
operator determines, based on a risk analysis, that these would be an
efficient means of adding protection to a HCA in the event of a gas
release (Sec. 192.935(c)). In publishing this regulation, PHMSA
acknowledged its prior conclusion that installation of these valves was
not economically feasible but noted that this was a generic conclusion.
PHMSA stated that it did not expect operators to re-perform the generic
analyses but rather to ``evaluate whether the generic conclusions are
applicable to their HCA pipeline segments.'' \5\
---------------------------------------------------------------------------
\2\ Accountable Pipeline Safety and Partnership Act of 1996,
Public Law 104-304.
\3\ NTSB, ``Texas Eastern Transmission Corporation Natural Gas
Pipeline Explosion and Fire, Edison, New Jersey, March 23, 1994,''
PB95-916501, NTSB/PAR-95/01, January 18, 1995.
\4\ DOT, RSPA, ``Remotely Controlled Valves on Interstate
Natural Gas Pipelines, (Feasibility Determination Mandated by the
Accountable Pipeline Safety and Partnership Act of 1996), September
1999.
\5\ Federal Register, December 15, 2003, 68 FR 69798, column 3.
---------------------------------------------------------------------------
The incident in San Bruno, CA on September 9, 2010, has raised
public concern about the ability of pipeline operators to isolate
sections of gas transmission pipelines in the event of an accident
promptly and whether remotely or automatically operated valves should
be required to assure this. PHMSA is considering changes to its
requirements for sectionalizing block valves in response to these
concerns.
Questions
H.1. Are the spacing requirements for sectionalizing block valves
in Sec. 192.179 adequate? If not, why not and what should be the
maximum or minimum separation distance? When class locations change as
a result of population increases, should additional block valves be
required to meet the new class location requirements? Should a more
stringent minimum spacing of either remotely or automatically
controlled valves be required between compressor stations? Under what
conditions should block valves be remotely or automatically controlled?
Should there be a limit on the maximum time required for an operator's
maintenance crews to reach a block valve site if it is not a remotely
or automatically controlled valve? What projected costs and benefits
would result from a requirement for increased placement of block
valves?
H.2. Should factors other than class location be considered in
specifying required valve spacing?
H.3. Should the regulations be revised to require explicitly that
new valves must be installed in the event of a class location change to
meet the spacing requirements of Sec. 192.179? What would be the costs
and benefits associated with such a change?
H.4. Should the regulations require addition of valves to existing
pipelines under conditions other than a change in class location?
H.5. What percentage of current sectionalizing block valves are
remotely operable? What percentage operate automatically in the event
of a significant pressure reduction?
H.6. Should PHMSA consider a requirement for all sectionalizing
block valves to be capable of being controlled remotely?
H.7. Should PHMSA strengthen existing requirements by adding
prescriptive decision criteria for operator evaluation of additional
valves, remote closure, and/or valve automation? Should PHMSA set
specific guidelines for valve locations in or around HCAs? If so, what
should they be?
H.8. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements pursuant to the commenter's suggestions.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
[[Page 53095]]
The potential environmental impacts of modifying the
existing regulatory requirements.
I. Corrosion Control
Gas transmission pipelines are generally constructed of steel pipe,
and corrosion is a threat of potential concern. Requirements for
corrosion control of gas transmission pipelines are in subpart I of
part 192. This subpart includes requirements related to external
corrosion, internal corrosion, and atmospheric corrosion. However, this
subpart does not include requirements for the specific threat of SCC.
Buried pipelines installed after July 31, 1971, are required to
have a protective coating and CP unless the operator can demonstrate
that the pipeline is not in a corrosive environment. Buried pipelines
installed before that date must have CP if they have an effective
coating or, if bare or with ineffective coating, if active corrosion is
found to exist. Appendix D of part 192 provides standards for the
adequacy of CP and operators are required to conduct tests periodically
to demonstrate that these standards are met.
These requirements have proven effective in minimizing the
occurrence of incidents caused by gas transmission pipeline corrosion.
Many of the provisions in subpart I, however, are general. They
provide, for example, that each pipeline under CP ``have sufficient
test stations or other contact points for electrical measurement to
determine the adequacy of CP'' (Sec. 192.469) rather than specifying
the number or spacing of such test stations. Operators are required to
take ``prompt'' remedial action to address problems with CP (Sec.
192.465(d)), but ``prompt'' is not defined. In addition, the
regulations do not now include provisions addressing issues that
experience has shown can be important to protecting pipelines from
corrosion damage:
Surveying post-construction for coating damage, using
techniques such as direct current voltage gradient (DCVG) or
alternating current voltage gradient (ACVG). Experience has shown that
construction activities can damage coating and that identifying and
remediating these damages can help protect against corrosion damage.
Performing a post-construction close interval survey to
assess the adequacy of CP and inform the location of CP test stations.
Conducting periodic interference current surveys to detect
and address electrical currents that could reduce the effectiveness of
CP. Pipelines are often routed near, in parallel to, or in common
right-of-ways with, electrical transmission lines that can induce such
interference currents. Section 192.473 requires operators of pipelines
subject to stray currents to have a program to minimize detrimental
effects but does not require surveys, grounding mitigation, or provide
any criteria for determining the adequacy of such programs.
Requiring periodic use of an In-line Inspection Tool or
sampling of accumulated liquids to assure that internal corrosion is
not occurring.
PHMSA is considering revising subpart I to address these areas and to
improve the specificity of existing requirements.
Corrosion control regulations applicable to gas transmission
pipelines include no requirements relative to SCC. SCC is cracking
induced from the combined influence of tensile stress and a corrosive
medium. SCC has been a contributing factor in numerous pipeline
failures on hazardous liquids pipelines including a 2003 failure on a
Kinder Morgan pipeline in Arizona, a 2004 failure on an Explorer
Pipeline Company pipeline in Oklahoma, a 2005 failure on an Enterprise
Products Operating line in Missouri, and a 2008 failure on an Oneok
Natural Gas Liquids Pipeline in Iowa. More effective methods of
preventing, detecting, assessing and remediating SCC in pipelines are
important to making further reductions in pipeline failures.
PHMSA is seeking to improve understanding and mitigation of SCC
threat. To this end, PHMSA is considering whether to establish and/or
adopt standards and procedures, through a rulemaking proceeding, for
improving the methods of preventing, detecting, assessing and
remediating SCC. PHMSA is considering additional requirements to
perform periodic coating surveys at compressor discharges and other
high-temperature areas potentially susceptible to SCC.
PHMSA has taken numerous steps over many years to improve the
understanding and mitigation of SCC in pipelines. These have included
public workshops and studies on SCC. Initiatives taken, sponsored and/
or supported by PHMSA designed to enhance understanding of SCC include:
1999 and 2004 SCC Studies--Two comprehensive studies on
SCC were conducted for PHMSA's predecessor agency. First, ``Stress
Corrosion Cracking Study,'' Report No. DTRS56, prepared by General
Physics Corporation in May 1999. Second, ``Stress Corrosion Cracking
Study,'' Report No. DTRS56-02-D-70036, submitted by Michael Baker Jr.,
Inc., in September 2004. These studies sought to improve understanding
of SCC and to identify practical methods to prevent, detect and address
SCC as well as provide a framework for potential future research. The
first report noted that SCC accounted for only 1.5 percent of gas
transmission pipeline incidents in the U.S., but 17 percent of
incidents in Canada. The report concluded this disparity is not due to
some inherent difference in U.S. and Canadian pipelines, but rather,
due to the far greater occurrence of third party damage incidents in
the U.S. The 2004 study is available at http://primis.phmsa.dot.gov/meetings/DocHome.mtg?doc=1.
Gas Transmission IM Rule--The gas transmission IM rule (68
FR 69778; December 15, 2003) requires operators to consider at least
the potential threats listed in Section 2 of ASME/ANSI B31.8S, which
includes SCC. The rule also specifies requirements for use of SCC
direct assessment as a method of assessing gas transmission pipelines
susceptible to this threat, which also require the use of criteria in
ASME/ANSI B31.8S. The standard, however, addresses only high-pH SCC.
Experience has shown that SCC occurring at near-neutral conditions is
also a potential threat to gas transmission pipelines.
2003 Advisory Bulletin--In response to three SCC-driven
failures of hazardous liquid pipelines in the U.S. in 2003 and other
SCC incidents around the world, PHMSA issued an Advisory Bulletin,
``Stress Corrosion Cracking Threats to Gas and Hazardous Liquid
Pipelines'' (68 FR 58166; October 8, 2003), urging all pipeline owners
and operators to consider SCC as a possible safety risk on their
pipeline systems and to include SCC assessment and remediation in their
IM plans, for those systems subject to IM rules. For systems not
subject to the IM rules, the bulletin urged owners and operators to
assess the impact of SCC on pipeline integrity and to plan integrity
verification activities accordingly.
2003 Public Workshop--PHMSA sponsored a public workshop on
SCC on December 3, 2003, in Houston, Texas. Numerous PHMSA
representatives, state officials, industry, consultants and officials
from the National Energy Board of Canada attended and shared their
respective experiences with SCC. The workshop also served as a forum
for identifying issues for consideration in the 2004 Baker SCC study.
2005 Rulemaking--PHMSA issued rules that covered direct
assessment, a process of managing the effects of
[[Page 53096]]
external corrosion, internal corrosion or SCC on pipelines made
primarily of steel or iron. ``Standards for Direct Assessment of Gas
and Hazardous Liquid Pipelines'' (70 FR 61571; October 25, 2005).
Questions
Existing Standards
I.1. Should PHMSA revise subpart I to provide additional
specificity to requirements that are now presented in general terms, as
described above? If so, which sections should be revised? What
standards exist from which to draw more specific requirements?
I.2. Should PHMSA prescribe additional requirements for post-
construction surveys for coating damage or to determine the adequacy of
CP? If so, what factors should be addressed (e.g., pipeline operating
temperatures, coating types, etc.)?
I.3. Should PHMSA require periodic interference current surveys? If
so, to which pipelines should this requirement apply and what
acceptance criteria should be used?
I.4. Should PHMSA require additional measures to prevent internal
corrosion in gas transmission pipelines? If so, what measures should be
required?
I.5. Should PHMSA prescribe practices or standards that address
prevention, detection, assessment, and remediation of SCC on gas
transmission pipeline systems? Should PHMSA require additional surveys
or shorter IM survey internals based upon the pipeline operating
temperatures and coating types?
I.6. Does the NACE SP0204-2008 (formerly RP0204) Standard ``Stress
Corrosion Cracking Direct Assessment Methodology'' address the full
lifecycle concerns associated with SCC? Should PHMSA consider this, or
any other standards to govern the SCC assessment and remediation
procedures? Do these standards vary significantly from existing
practices associated with SCC assessments?
I.7. Are there statistics available on the extent to which the
application of the NACE Standard, or other standards, have affected the
number of SCC indications operators have detected on their pipelines
and the number of SCC-related pipeline failures? Are statistics
available that identify the number of SCC occurrences that have been
discovered at locations that meet the screening criteria in the NACE
standard and at locations that do not meet the screening criteria?
I.8. If new standards were to be developed for SCC, what key issues
should they address? Should they be voluntary?
I.9. Does the definition of corrosive gas need to clarify that
other constituents of a gas stream (e.g., water, carbon dioxide, sulfur
and hydrogen sulfide) could make the gas stream corrosive? If so, why
does it need to be clarified?
I.10. Should PHMSA prescribe for HCAs and non-HCAs external
corrosion control survey timing intervals for close interval surveys
that are used to determine the effectiveness of CP?
I.11. Should PHMSA prescribe for HCAs and non-HCAs corrosion
control measures with clearly defined conditions and appropriate
mitigation efforts? If so, why?
Existing Industry Practices
PHMSA is interested in the extent to which operators have
implemented Canadian Energy Pipeline Association (CEPA) SCC,
Recommended Practices 2nd Edition, 2007, and what the results have
been.
I.12. Are there statistics available on the extent to which gas
transmission pipeline operators apply the CEPA practices?
I.13. Are there statistics available that compare the number of SCC
indications detected and SCC-related failures between operators
applying the CEPA practices and those applying other SCC standards or
practices?
I.14. Do the CEPA practices address the full lifecycle concerns
associated with SCC? If not, which are not addressed?
I.15. Are there additional industry practices that address SCC?
The Effectiveness of SCC Detection Tools and Methods
I.16. Are there statistics available on the extent to which various
tools and methods can accurately and reliably detect and determine the
severity of SCC?
I.17. Are tools or methods available to detect accurately and
reliably the severity of SCC when it is associated with longitudinal
pipe seams?
I.18. Should PHMSA require that operators perform a critical
analysis of all factors that influence SCC to determine if SCC is a
credible threat for each pipeline segment? If so, why? What experience-
based indications have proven reliable in determining whether SCC could
be present?
I.19. Should PHMSA require an integrity assessment using methods
capable of detecting SCC whenever a credible threat of SCC is
identified?
I.20. Should PHMSA require a periodic analysis of the effectiveness
of operator corrosion management programs, which integrates information
about CP, coating anomalies, in-line inspection data, corrosion coupon
data, corrosion inhibitor usage, analysis of corrosion products,
environmental and soil data, and any other pertinent information
related to corrosion management? Should PHMSA require that operators
periodically submit corrosion management performance metric data?
I.21. Are any further actions needed to address corrosion issues?
I.22. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements pursuant to the commenter's suggestions.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the
existing regulatory requirements.
J. Pipe Manufactured Using Longitudinal Weld Seams
Most gas transmission pipelines are constructed of steel pipe. The
steel pipe is formed into pipe from steel plate, coil, or billet. The
natural gas pipeline infrastructure in the United States is comprised
of approximately 322,000 miles of transmission pipeline. Approximately
182,000 (56%) miles of gas transmission pipelines were built prior to
1970 and approximately 140,000 miles (44%) were built after 1970.
Pipelines built since the regulations (49 CFR part 192) were
implemented in early 1971 have been required to be:
Pressure tested after construction and prior to being
placed into gas service in accordance with subpart J, and
Manufactured in accordance with a referenced standard
(most gas transmission pipe has been manufactured in accordance with
American Petroleum Institute (API) API Standard 5L, 5LX or 5LS,
``Specification for Line Pipe'' (API 5L) referenced in 49 CFR part
192).
Many gas transmission pipelines built from the 1940's through 1970
were manufactured in accordance with API 5L, but may not have been
pressure tested similar to a subpart J pressure test. These pipelines
built prior to 1971 were allowed by Sec. 192.619(a) to operate
[[Page 53097]]
to an MAOP based on the highest five-year operating pressure prior to
July 1, 1970, in lieu of a pressure test. (See section N, below, for a
discussion of these exemptions.) Some of these old processes created
pipe with variable characteristics throughout the longitudinal weld or
pipe body.
Starting in the late-1960's, many pipe seam types used for the pre-
1970's pipe have been discontinued as new modern steel making and pipe
rolling practices were implemented. New steel and pipe manufacturing
technology has led to new processes, the modification or improvement of
some processes, and the abandonment of others. Many pipe manufacturing
processes that produced pipe with longitudinal seam deficiencies have
been discontinued such as low frequency electric resistance welded (LF-
ERW), direct current electric resistance welded (DC-ERW), flash welded,
furnace butt welded, and lap welded pipe.
As a result of 12 hazardous liquid pipeline failures that occurred
during 1986 and 1987 involving pre-1970 ERW pipe, PHMSA issued an Alert
Notice (ALN-88-01). Subsequent to the notice, one additional failure on
a gas transmission pipeline, and eight additional failures on hazardous
liquid pipelines, resulted in another Alert Notice (ALN-89-01). The
notices identified that some failures appeared to be due to selective
seam corrosion, but that other failures appeared to have resulted from
flat growth of manufacturing defects in the ERW seam. In these notices,
PHMSA advised all gas transmission and hazardous liquid pipeline
operators with pre-1970 ERW pipe to:
Consider hydrostatic testing on all hazardous liquid
pipelines that have not been hydrostatically tested to 125% of the
maximum allowable pressure, or alternatively reduce the operating
pressure 20%;
Avoid increasing a pipeline's long-standing operating
pressure;
Assure the effectiveness of the CP system. Consider the
use of close interval pipe-to-soil surveys after evaluating the pipe
coating and corrosion/CP history; and
In the event of an ERW seam failure, conduct metallurgical
examinations in order to determine the probable condition of the
remainder of the ERW seams in the pipeline.
The rule for gas transmission pipeline IM prescribed the following
specific requirements, for pipe in HCAs, consistent with the
recommendations in ALN-89-01:
Avoiding increasing a pipeline's long-standing operating
pressure,
If a pipeline's long-standing operating pressure is
exceeded, or if stresses leading to cyclic fatigue increases, conduct
an integrity assessment capable of detecting manufacturing and
construction defects, including seam defects,
Conduct an evaluation to determine if the pipeline is
susceptible to manufacturing and construction defects, including seam
defects. The evaluation must consider both covered segments and similar
non-covered segments, past incident history, corrosion control records,
continuing surveillance records, patrolling records, maintenance
history, internal inspection records and all other conditions specific
to each pipeline.
In 2003, PHMSA also commissioned a study \6\ of low frequency ERW
and lap welded longitudinal seam issues. The study was conducted by
Michael Baker, Inc., in collaboration with Kiefner and Associates,
Inc., and CorrMet Engineering Services, PC. The study provided
suggested guidelines that can be used to create policy for longitudinal
seam testing.
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\6\ TTO Number 5, IM Delivery Order DTRS56-02-D-70036, Low
Frequency ERW and Lap Welded Longitudinal Seam Evaluation, Final
Report, Revision 3, April 2004, available online at: http://primis.phmsa.dot.gov/iim/docstr/TTO5_LowFrequencyERW_FinalReport_Rev3_April2004.pdf.
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Since 2002, there have been at least 22 reportable incidents on gas
transmission pipeline which manufacturing or seam defects were
contributing factors. Due to recent high consequence incidents caused
by longitudinal seam failures, including the 2009 failure in Palm City,
Florida and the 2010 failure in San Bruno, California, PHMSA is
considering additional IM and pressure testing requirements for pipe
manufactured using longitudinal seam welding techniques that have not
had a subpart J pressure test.
Questions
J.1. Should all pipelines that have not been pressure tested at or
above 1.1 times MAOP or class location test criteria (Sec. Sec.
192.505, 192.619 and 192.620), be required to be pressure tested in
accordance with the present regulations? If not, should certain types
of pipe with a pipeline operating history that has shown to be
susceptible to systemic integrity issues be required to be pressure
tested in accordance with the present regulations (e.g., low-frequency
electric resistance welded (LF-ERW), direct current electric resistance
welded (DC-ERW), lap-welded, electric flash welded (EFW), furnace butt
welded, submerged arc welded, or other longitudinal seams)? If so, why?
J.2. Are alternative minimum test pressures (other than those
specified in subpart J) appropriate, and why?
J.3. Can ILI be used to find seam integrity issues? If so, what ILI
technology should be used and what inspection and acceptance criteria
should be applied?
J.4. Are other technologies available that can consistently be used
to reliably find and remediate seam integrity issues?
J.5. Should additional pressure test requirements be applied to all
pipelines, or only pipelines in HCAs, or only pipelines in Class 2, 3,
or 4 location areas?
J.6. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements pursuant to the commenter's suggestions.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the
existing regulatory requirements.
K. Establishing Requirements Applicable to Underground Gas Storage
Demand for natural gas fluctuates seasonally and sometimes based on
other factors. Gas transmission pipeline operators use underground
storage facilities as a means of accommodating these fluctuations. Gas
is injected into storage during periods of low demand and is withdrawn
for delivery to customers when demand is high. Underground storage
facilities include caverns, many in salt formations, and related wells
and piping to inject and remove gas. Underground storage caverns and
injection/withdrawal piping are not currently regulated under part 192.
Pipelines that transport gas within a storage field are defined at
Sec. 192.3 as transmission pipelines and are regulated in the same
manner as other transmission pipelines.
NTSB conducted an investigation subsequent to an accident involving
uncontrolled release of highly volatile liquids from a salt dome
storage cavern in Brenham, Texas in 1992 and
[[Page 53098]]
recommended that DOT develop safety requirements for underground
storage of highly volatile liquids and natural gas. RSPA initiated a
rulemaking proceeding as a result of this recommendation. Following a
period of study, RSPA concluded that Federal regulation of underground
gas storage was not necessary and terminated that rulemaking. RSPA
described this action in an Advisory Bulletin published in the Federal
Register on July 10, 1997 (ADB-97-04, 62 FR 37118).
RSPA noted that most persons who spoke at a public meeting held as
part of the rulemaking proceeding favored industry safety practices and
state regulation to address safety of underground storage. RSPA
commissioned a report that found that about 85 percent of surveyed
storage facilities were under state regulation, to at least some
degree. RSPA also noted that it had worked with the Interstate Oil and
Gas Compact Commission (IOGCC) to develop standards for underground
storage, which were published in a report titled: ``Natural Gas Storage
in Salt Caverns--A Guide for State Regulators'' (IOGCC Guide). RSPA
also noted that the API had published two sets of guidelines for
underground storage of liquid hydrocarbons: API RP 1114, ``Design of
Solution-Mined Underground Storage Facilities,'' June 1994, and API RP
1115, ``Operation of Solution-Mined Underground Storage Facilities,''
September 1994. RSPA encouraged operators of underground storage
facilities and state regulators to use these resources in their safety
programs.
A significant incident involving an underground gas storage
facility occurred in 2001 near Hutchinson, KS. An uncontrolled release
from an underground gas storage facility resulted in explosions and
fires. Two people were killed. Many residents were evacuated from their
homes. Some were not able to return for four months.
The Kansas Corporation Commission initiated enforcement action
against the operator of the Hutchinson storage field as a result of
safety violations associated with the accident. As part of this
enforcement proceeding, it was concluded that the storage field was an
interstate gas pipeline facility. Federal statutes provide that ``[a]
State authority may not adopt or continue in force safety standards for
interstate pipeline facilities or interstate pipeline transportation''
(49 U.S.C. Sec. 60104). There were, and remain, no Federal safety
standards against which enforcement could be taken. The enforcement
proceeding was therefore terminated.
PHMSA is considering establishing requirements within part 192
applicable to underground gas storage to help assure safety of
underground storage and to provide a firm basis for safety regulation.
PHMSA notes that the IOGCC Guide is no longer available on the IOGCC
Web site. The API documents were both updated in July, 2007 (the latter
redesignated as API 1115).
Questions
K.1. Should PHMSA develop Federal standards governing the safety of
underground gas storage facilities? If so, should they be voluntary? If
so, what portions of the facilities should be addressed in these
standards?
K.2. What current standards exist governing safety of these
facilities? What standards are presently used for conducting casing,
tubing, isolation packer, and wellbore communication and wellhead
equipment integrity tests for down-hole inspection intervals? What are
the repair and abandonment standards for casings, tubing, and wellhead
equipment when communication is found or integrity is compromised?
K.3. What standards are used to monitor external and internal
corrosion?
K.4. What standards are used for welding, pressure testing, and
design safety factors of casing and tubing including cementing and
casing and casing cement integrity tests?
K.5. Should wellhead values have emergency shutdowns both primary
and secondary? Should there be integrity and O&M intervals for key
safety and CP systems?
K.6. What standards are used for emergency shutdowns, emergency
shutdown stations, gas monitors, local emergency response
communications, public communications, and O&M Procedures?
K.7. Does the current lack of Federal standards and preemption
provisions in Federal law preclude effective regulation of underground
storage facilities by States?
K.8. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the
existing regulatory requirements.
L. Management of Change
Experience has shown that changes to physical configuration or
operational practices often cause problems in the pipeline and other
industries. Operation of a pipeline over an extended period without
change tends to ``shake out'' minor issues and lead to their
resolution. Ineffectively managed changes to pipeline systems (e.g.,
pipeline equipment, computer equipment or software used to monitor and
control the pipeline) or to practices used to construct, operate, and
maintain those systems can lead to difficulties. Changes can introduce
unintended consequences because the change was not well thought out or
was implemented in a manner not consistent with its design or planning.
Changes in procedures require people to perform new or different
actions, and failure to train them properly and in a timely manner can
result in unexpected consequences. The result can be a situation in
which risk or the likelihood of an accident is increased. A recently
completed but poorly-designed modification to the pipeline system was a
factor contributing to the Olympic Pipeline accident in Bellingham,
Washington.
PHMSA pipeline safety regulations do not now address management
process subjects such as management of change. PHMSA is considering
adding requirements in this area to provide a greater degree of control
over this element of pipeline risk.
Questions
L.1. Are there standards used by the pipeline industry to guide
management processes including management of change? Do standards
governing the management of change process include requirements for IM
procedures, O&M manuals, facility drawings, emergency response plans
and procedures, and documents required to be maintained for the life of
the pipeline?
L.2. Are standards used in other industries (e.g., Occupational
Safety and Health Administration standards at 29 CFR 1910.119)
appropriate for use in the pipeline industry?
L.3. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements.
[[Page 53099]]
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the
existing regulatory requirements.
M. Quality Management Systems (QMS)
International Standards Organization (ISO) standard ISO 8402-1986
defines quality as ``the totality of features and characteristics of a
product or service that bears its ability to satisfy stated or implied
needs.''
Quality management includes the activities and processes that an
organization uses to achieve quality. These include formulating policy,
setting objectives, planning, quality control, quality assurance,
performance monitoring, and quality improvement.
Achieving quality is critical to gas transmission pipeline design,
construction, and operations. PHMSA recognizes that pipeline operators
strive to achieve quality, but our experience has shown varying degrees
of success in accomplishing this objective among pipeline operators.
PHMSA believes that an ordered and structured approach to quality
management can help pipeline operators achieve a more consistent state
of quality and thus improve pipeline safety.
PHMSA's pipeline safety regulations do not now address process
management issues such as QMS. Section 192.328 requires a quality
assurance plan for construction of pipelines intended to operate at
alternative MAOP, but there is no similar requirement applicable to
other pipelines. Quality assurance is generally considered to be an
element of quality management. PHMSA is considering whether and how to
impose requirements related to QMS, especially their design and
application to control equipment and materials used in new construction
(e.g., quality verification of materials used in construction and
replacement, post-installation quality verification), and to control
the work product of contractors used to construct, operate, and
maintain the pipeline system (e.g., contractor qualifications,
verification of the quality of contractor work products).
Questions
M.1. What standards and practices are used within the pipeline
industry to assure quality? Do gas transmission pipeline operators have
formal QMS?
M.2. Should PHMSA establish requirements for QMS? If so, why? If
so, should these requirements apply to all gas transmission pipelines
and to the complete life cycle of a pipeline system?
M.3. Do gas transmission pipeline operators require their
construction contractors to maintain and use formal QMS? Are contractor
personnel that construct new or replacement pipelines and related
facilities already required to read and understand the specifications
and to participate in skills training prior to performing the work?
M.4. Are there any standards that exist that PHMSA could adopt or
from which PHMSA could adapt concepts for QMS?
M.5. What has been the impact on cost and safety in other
industries in which requirements for a QMS have been mandated?
M.6. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the
existing regulatory requirements.
N. Exemption of Facilities Installed Prior to the Regulations
Federal pipeline safety regulations were first established with the
initial publication of part 192 on August 19, 1970. Gas transmission
pipelines had existed for many years prior to this, some dating to as
early as 1920. Many of these older pipelines had operated safely for
years at pressures higher than would have been allowed under the new
regulations. To preclude a required reduction in the operating pressure
of these pipelines, which the agency believed would not have resulted
in a material increase in safety; an exemption was included in the
regulations allowing pipelines to operate at the highest actual
operating pressure to which they were subjected during the five years
prior to July 1, 1970.\7\ Safe operation at these pressures was deemed
to be evidence that operation could safely continue. This exemption is
still in part 192, at Sec. 192.619(a)(3). It has been modified to
accommodate later changes that redefined some onshore gathering
pipelines as transmission pipelines, allowing the MAOP for those
pipelines similarly to be established at the highest actual pressure
experienced in the five years before the redefinition.
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\7\ The pipelines that operate at MAOP determined under this
exemption are commonly referred to as ``grandfathered'' pipelines.
---------------------------------------------------------------------------
Many exempt gas transmission pipelines continue to operate in the
United States. Some of these pipelines operate at stress levels higher
than 72 percent specified minimum yield strength (SMYS), the highest
level generally allowed for more modern gas transmission pipelines.
Some operate at greater than 80 percent SMYS, the alternate MAOP
allowed for some pipelines by regulations adopted October 17, 2008 (72
FR 62148). Under these regulations, operators who seek to operate their
pipelines at up to 80 percent SMYS (in Class 1 locations) voluntarily
accept significant additional requirements applicable to design,
construction, and operation of their pipeline and intended to assure
quality and safety at these higher operating stresses. Exempt pipelines
are subject to none of these additional requirements.
Exempt pipelines that continue to operate at higher pressures
(stress levels) than the regulations would currently allow are now 40
years older than they were when part 192 was initially promulgated. In
many cases, this is more than double the operating lifetime they had
accumulated at that time. Time is an important factor in assuring
pipeline safety. Pipelines are subject to various time-dependent
degradation mechanisms including corrosion, fatigue, and other
potential causes of failure. Pipeline operators manage these
mechanisms, and many are addressed by regulations in part 192.
Part 192 also includes several provisions other than establishment
of MAOP for which an accommodation was made in the initial part 192.
These provisions allowed pipeline operators to use steel pipe that had
been manufactured before 1970 and did not meet all requirements
applicable to pipe manufactured after part 192 became effective Sec.
192.55), valves, fittings and components that did not contain all the
markings required Sec. 192.63), and pipe which had not been
transported under the standard included in the new part 192 (192.65,
subject to additional testing requirements). These provisions allowed
pipeline operators to use materials that they had purchased prior to
the effective date of the new regulations and which they maintained on
hand for repairs, replacements and new installations.
PHMSA is considering changes to its regulations that would
eliminate these
[[Page 53100]]
exemptions. PHMSA expects that materials that had been warehoused prior
to 1970 have all been used in the intervening years or, if not, are no
longer suitable for use. PHMSA is considering repealing the provisions
that allow use of such older materials. PHMSA is considering
eliminating the exemption of Sec. 192.619(a)(3) for establishing MAOP.
This would have the effect of requiring a reduction in the operating
pressure for some older gas transmission pipelines to levels applicable
to pipelines constructed since 1970.
Questions
N.1. Should PHMSA repeal provisions in part 192 that allow use of
materials manufactured prior to 1970 and that do not otherwise meet all
requirements in part 192?
N.2. Should PHMSA repeal the MAOP exemption for pre-1970 pipelines?
Should pre-1970 pipelines that operate above 72% SMYS be allowed to
continue to be operated at these levels without increased safety
evaluations such as periodic pressure tests, in-line inspections,
coating examination, CP surveys, and expanded requirements on
interference currents and depth of cover maintenance?
N.3. Should PHMSA take any other actions with respect to exempt
pipelines? Should pipelines that have not been pressure tested in
accordance with subpart J be required to be pressure tested in
accordance with present regulations?
N.4. If a pipeline has pipe with a vintage history of systemic
integrity issues in areas such as longitudinal weld seams or steel
quality, and has not been pressure tested at or above 1.1 times MAOP or
class location test criteria (Sec. Sec. 192.505, 192.619 and 192.620),
should this pipeline be required to be pressure tested in accordance
with present regulations?
N.5. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the
existing regulatory requirements.
O. Modifying the Regulation of Gas Gathering Lines
In the Natural Gas Pipeline Safety Act of 1968, Congress gave DOT
broad authority to develop, prescribe, and enforce minimum Federal
safety standards for the transportation of gas by pipeline.\8\ That
authority did not extend to the gathering of gas in rural areas, which
Congress concluded should not be subject to Federal regulation.\9\
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\8\ Public Law 90-481, 82 Stat. 720 (1968) (currently codified
with amendments at 49 U.S.C. 60101 et seq.).
\9\ H.R. REP. NO. 1390 (1968), reprinted in 1968 U.S.C.C.A.N.
3223, 3234-35.
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In 1970, DOT issued its original Federal safety standards for the
transportation of gas by pipeline.\10\ Those standards did not apply to
the gathering of gas in rural areas and defined a ``gathering line'' as
``a pipeline that transports gas from a current production facility to
a transmission line or main.''
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\10\ 35 FR 317, 318, 320 (Jan. 8, 1970); 35 FR 13248, 13258
(Aug. 19, 1970).
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In 1974, DOT issued a notice of proposed rulemaking (NPRM) to
change its definition of a gas gathering line.\11\ The NPRM noted that
the original definition had ``creat[ed] a vicious circle,'' both in
terms of determining where a gathering line begins and a transmission
line ends and where a production facility ends and a gathering line
begins. Nonetheless, DOT withdrew the NPRM four years later without
taking any final action.\12\
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\11\ 39 FR 34569 (Sept. 26, 1974).
\12\ 43 FR 42773 (Sept. 21, 1978).
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In the Pipeline Safety Act (PSA) of 1992,\13\ Congress gave DOT the
discretion to override the traditional prohibition on the regulation of
rural gathering lines. Specifically, the PSA provided DOT with the
authority to issue safety standards for ``regulated gathering lines,''
based on the functional and operational characteristics of those lines
and subject to certain additional conditions. In the Accountable
Pipeline Safety and Partnership Act of 1996, Congress made clear that
DOT had the authority to obtain information from the owners and
operators of gathering lines to determine whether those lines should be
subject to Federal safety standards.\14\
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\13\ Public Law 102-508, 106 Stat. 3289 (Oct. 24, 1992)
(currently codified at 49 U.S.C. 60101(b)). In 1991, DOT had issued
another NPRM to change the definitions for gathering line and
production facility and to add a new term, ``production field,''
into the gas pipeline safety regulations. 56 FR 48505 (Sept. 25,
1991).
\14\ Public Law 104-304, Sec. 12, 110 Stat. 3793 (Jan. 3, 1996)
(currently codified at 49 U.S.C. 60117(b)).
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In March 2006, PHMSA issued new safety requirements for ``regulated
onshore gathering lines.'' \15\ Those requirements established a new
method for determining if a pipeline is an onshore gathering line,
divided regulated onshore gas gathering lines into two risk-based
categories (Type A and Type B), and subjected such lines to certain
safety standards.
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\15\ 71 FR 13289 (Mar. 15, 2006).
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Onshore gas gathering lines are defined based on the provisions in
American Petroleum Institute Recommended Practice 80, ``Guidelines for
the Definition of Onshore Gas Gathering Lines,'' (API RP 80), a
consensus industry standard incorporated by reference. Additional
regulatory requirements for determining the beginning and endpoints of
gathering are also imposed to prevent operator manipulation and abuse.
Type A gathering lines are metallic lines with a MAOP of 20% or
more of SMYS, as well as nonmetallic lines with an MAOP of more than
125 psig, in a Class 2, 3, or 4 location. These lines are subject to
all of the requirements in part 192 that apply to transmission lines,
except for Sec. 192.150, the regulation that requires the
accommodation of smart pigs in the design and construction of certain
new and replaced pipelines, and the Integrity Management requirements
of part 192, subpart O. Operators of Type A gathering lines are also
permitted to use an alternative process for demonstrating compliance
with the requirements of part 192, subpart N, Qualification of Pipeline
Personnel.
Type B gathering lines are metallic lines with an MAOP of less than
20% of SMYS, as well as nonmetallic lines with an MAOP of 125 psig or
less, in a Class 2 location (as determined under one of three formulas)
or in a Class 3 or Class 4 location. These lines are subject to less
stringent requirements than Type A gathering lines; specifically, any
new or substantially changed Type B line must comply with the design,
installation, construction, and initial testing and inspection
requirements applicable to transmission lines and, if of metallic
construction, the corrosion control requirements for transmission
lines. Operators must also include Type B gathering lines in their
damage prevention and public education programs, establish the MAOP of
those lines under Sec. 192.619, and comply with the requirements for
maintaining and installing line markers that apply to transmission
lines.
Recent developments in the field of gas exploration and production,
such as shale gas, indicate that the existing framework for regulating
gas gathering lines may no longer be appropriate.
[[Page 53101]]
Gathering lines are being constructed to transport ``shale'' gas that
range from 12 to 36 inches in diameter with an MAOP of 1480 psig, far
exceeding the historical operating parameters of such lines. Current
estimates also indicate that there are approximately 230,000 miles of
gas gathering lines in the U.S., and that PHMSA only regulates about
20,150 miles of those lines. Moreover, enforcement of the current
requirements has been hampered by the conflicting and ambiguous
language of API RP 80, a complex standard that can produce multiple
classifications for the same pipeline system. PHMSA has also identified
a regulatory gap that permits the potential abuse of the incidental
gathering line designation under that standard.
Questions
O.1. Should PHMSA amend 49 CFR part 191 to require the submission
of annual, incident, and safety-related conditions reports by the
operators of all gathering lines?
O.2. Should PHMSA amend 49 CFR part 192 to include a new definition
for the term ``gathering line''?
O.3. Are there any difficulties in applying the definitions
contained in RP 80? If so, please explain.
O.4. Should PHMSA consider establishing a new, risk-based regime of
safety requirements for large-diameter, high-pressure gas gathering
lines in rural locations? If so, what requirements should be imposed?
O.5. Should PHMSA consider short sections of pipeline downstream of
processing, compression, and similar equipment to be a continuation of
gathering? If so, what are the appropriate risk factors that should be
considered in defining the scope of that limitation (e.g. doesn't leave
the operator's property, not longer than 1000 feet, crosses no public
rights-of-way)?
O.6. Should PHMSA consider adopting specific requirements for
pipelines associated with landfill gas systems? If so, what regulations
should be adopted and why? Should PHMSA consider adding regulations to
address the risks associated with landfill gas that contains higher
concentrations of hydrogen sulfide and/or carbon dioxide?
O.7. Internal corrosion is an elevated threat to gathering systems
due to the composition of the gas transported. Should PHMSA enhance its
requirements for internal corrosion control for gathering pipelines?
Should this include required cleaning on a periodic basis?
O.8. Should PHMSA apply its Gas Integrity Management Requirements
to onshore gas gathering lines? If so, to what extent should those
regulations be applied and why?
O.9. If commenters suggest modification to the existing regulatory
requirements, PHMSA requests that commenters be as specific as
possible. In addition, PHMSA requests commenters to provide information
and supporting data related to:
The potential costs of modifying the existing regulatory
requirements.
The potential quantifiable safety and societal benefits of
modifying the existing regulatory requirements.
The potential impacts on small businesses of modifying the
existing regulatory requirements.
The potential environmental impacts of modifying the existing
regulatory requirements.
IV. Regulatory Notices
A. Executive Order 12866, Executive Order 13563, and DOT Regulatory
Policies and Procedures
Executive Orders 12866 and 13563 require agencies to regulate in
the ``most cost-effective manner,'' to make a ``reasoned determination
that the benefits of the intended regulation justify its costs,'' and
to develop regulations that ``impose the least burden on society.'' We
therefore request comments, including specific data if possible,
concerning the costs and benefits of revising the pipeline safety
regulations to accommodate any of the changes suggested in this advance
notice.
B. Executive Order 13132: Federalism
Executive Order 13132 requires agencies to assure meaningful and
timely input by state and local officials in the development of
regulatory policies that may have a substantial, direct effect on the
states, on the relationship between the national government and the
states, or on the distribution of power and responsibilities among the
various levels of government. PHMSA is inviting comments on the effect
a possible rulemaking adopting any of the amendments discussed in this
document may have on the relationship between national government and
the states.
C. Regulatory Flexibility Act
Under the Regulatory Flexibility Act of 1980 (5 U.S.C. 601 et
seq.), PHMSA must consider whether a proposed rule would have a
significant economic impact on a substantial number of small entities.
``Small entities'' include small businesses, not-for-profit
organizations that are independently owned and operated and are not
dominant in their fields, and governmental jurisdictions with
populations under 50,000. If your business or organization is a small
entity and if adoption of any of the amendments discussed in this ANPRM
could have a significant economic impact on your operations, please
submit a comment to explain how and to what extent your business or
organization could be affected and whether there are alternative
approaches to this regulations the agency should consider that would
minimize any significant impact on small business while still meeting
the agency's statutory objectives.
D. National Environmental Policy Act
The National Environmental Policy Act of 1969 requires Federal
agencies to consider the consequences of Federal actions and that they
prepare a detailed statement analyzing them if the action significantly
affects the quality of the human environment. Interested parties are
invited to address the potential environmental impacts of this ANPRM.
We are particularly interested in comments about compliance measures
that would provide greater benefit to the human environment or on
alternative actions the agency could take that would provide beneficial
impacts.
E. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
Executive Order 13175 requires agencies to assure meaningful and
timely input from Indian Tribal Government representatives in the
development of rules that ``significantly or uniquely affect'' Indian
communities and that impose ``substantial and direct compliance costs''
on such communities. We invite Indian Tribal governments to provide
comments on any aspect of this ANPRM that may affect Indian
communities.
F. Paperwork Reduction Act
Under 5 CFR part 1320, PHMSA analyzes any paperwork burdens if any
information collection will be required by a rulemaking. We invite
comment on the need for any collection of information and paperwork
burdens, if any.
G. Privacy Act Statement
Anyone can search the electronic form of comments received in
response to any of our dockets by the name of the individual submitting
the comment (or signing the comment, if submitted on
[[Page 53102]]
behalf of an association, business, labor union, etc.). DOT's complete
Privacy Act Statement was published in the Federal Register on April
11, 2000 (65 FR 19477).
Authority: 49 U.S.C. 60101 et seq.; 49 CFR 1.53.
Issued in Washington, DC, on August 18, 2011.
Jeffrey D. Wiese,
Associate Administrator for Pipeline Safety.
[FR Doc. 2011-21753 Filed 8-24-11; 8:45 am]
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