[Federal Register Volume 66, Number 124 (Wednesday, June 27, 2001)]
[Notices]
[Pages 34318-34328]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 01-15990]
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DEPARTMENT OF TRANSPORTATION
Research and Special Programs Administration
[Docket No. RSPA-00-7666; Notice 2]
Pipeline Safety: Pipeline Integrity Management in High
Consequence Areas (Gas Transmission Pipelines)
AGENCY: Office of Pipeline Safety, Research and Special Programs
Administration, DOT.
[[Page 34319]]
ACTION: Notice of request for comments.
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SUMMARY: OPS has been meeting with representatives of the natural gas
pipeline industry, research institutions, State pipeline safety
agencies and public interest groups, to understand how integrity
management principles can best be applied to improve the safety of gas
pipelines. A public meeting was held on February 12-14, 2001, in
Arlington, VA, to present the results of analyses and discussions,
identify issues, and obtain public comments. By this notice we are
seeking further information and clarification, and inviting further
public comment about integrity management concepts as they relate to
gas pipelines. This notice also announces commencement of an electronic
public discussion forum on gas pipeline integrity management issues on
the office of Pipeline Safety's internet home page.
DATES: Interested persons are invited to submit written comments by
August 13, 2001. Late-filed comments will be considered to the extent
practicable.
ADDRESSES: Submit written comments by mail or delivery to the Dockets
Facility, U.S. Department of Transportation, Room PL-401, 400 Seventh
Street, SW., Washington, DC 20590-0001. The Dockets Facility is located
on the plaza level, Room PL-401, of the US Department of
Transportation, 400 Seventh Street, SW., Washington, DC 20590. It is
open from 10 a.m. to 5 p.m., Monday through Friday, except federal
holidays. All written comments should identify the docket and notice
numbers stated in the heading of this notice. Anyone who wants
confirmation of mailed comments must include a self-addressed stamped
postcard.
Electronic Access
The Internet address for the electronic discussion forum is http://ops.dot.gov/forum. The electronic discussion forum is discussed below
under the subheading ``More Information Needed on Gas Integrity
Management Program.''
You also may submit written comments to the docket electronically
at the following web address: http://dms.dot.gov. To file written
comments electronically, after logging onto http://dms.dot.gov, click
on ``Electronic Submission.'' You can read comments and other material
in the docket at this Web address.
FOR FURTHER INFORMATION CONTACT: Mike Israni (tel: 202-366-4571; E-
mail: [email protected]). General information about our pipeline
safety program is available at this Web address: http://ops.dot.gov.
SUPPLEMENTARY INFORMATION:
I. Background
We have stated previously (most recently at 66 FR 848; Jan. 4,
2001), that we are issuing integrity management program requirements
for pipelines in several steps. RSPA began the series of rulemakings by
issuing requirements pertaining to hazardous liquid operators. A final
rule applying to hazardous liquid operators with 500 or more miles of
pipeline was published on December 1, 2000 (65 FR 75378). This rule
applies to pipelines that can affect high consequence areas (HCAs),
which include populated areas defined by the Census Bureau as urbanized
areas or places, unusually sensitive environmental areas, and
commercially navigable waterways. We have proposed a similar rule for
hazardous liquid operators with less than 500 miles of pipeline (66 FR
15821; March 21, 2001).
We are now considering integrity management concepts that could
most effectively be applied to gas transmission pipelines. OPS has been
meeting with representatives of the gas pipeline industry, research
institutions, State pipeline safety agencies and public interest
groups, to gather the information needed to propose an integrity
management program rulemaking pertaining to gas operators. Since
January 2000, there have been nine meetings with State agencies,
representatives of the Interstate Natural Gas Association of America
(INGAA), the American Gas Association (AGA), Battelle Memorial
Institute, the Gas Technology Institute (GTI), Hartford Steam Boiler
Inspection and Insurance Company, and operators covered under 49 CFR
Part 192. (See DOT Docket No. 7666 for summaries of the meetings.) We
also have met separately with Western States Land Commissioners,
National Governors Association, National League of Cities, National
Council of State Legislators, Environmental Defense Fund, Public
Interest Reform Group, and Working Group on Communities Right-To-Know.
On February 12-14, 2001, we held a public meeting in Arlington, VA,
on integrity management in high consequence areas for natural gas
pipelines and enhanced communications about hazardous liquid and gas
pipelines. At this meeting, reports on the status of industry and
government activities on how to improve the integrity of gas pipelines
were featured and meeting attendees participated in in-depth
discussions on the integrity of gas pipelines. The reports can be found
in the DOT docket (#7666) and the OPS web site under Initiatives/
Pipeline Integrity Management Program/Gas Transmission Operators Rule.
At the public meeting, industry and State representatives presented
their perspectives on a number of issues relating to integrity
management. Several members of the public also made comments.
Presentation topics included:
Considerations for defining HCAs affected by gas pipelines
Evaluation of design factors currently used for gas
transmission pipelines
Evaluation of performance history and experience with the
impact zone in gas transmission failures
Integrity management best practices and relationship between
incident causes and industry practices
Options for various forms of direct assessment of the
integrity of gas pipelines; their costs and effectiveness
Basis for establishing test pressure intervals
Appropriateness of using pressure (stress) to differentiate
integrity standards for pipelines
Status of research activities
Status of development of new national consensus standards
These presentations can be viewed on the OPS web site under
Initiatives/Pipeline Integrity Management Program/Gas Transmission
Operators Rule.
Objectives
RSPA's objective in developing a rule on gas pipeline integrity
management is to evaluate and address threats posed by pipeline
segments in areas where the consequences of potential pipeline
accidents pose the greatest risk to people and their property and to
provide additional protections in these areas. We had a similar
objective when we developed the recently issued rules on liquid
pipeline integrity management programs, although environmental
protection also played a larger role in those rules. We also want to
minimize any actual adverse impact of a new safety requirements on the
supply of natural gas to customers.
Scope of an Eventual Gas Integrity Management Rule
Our current thinking is that any standards we eventually propose on
gas integrity management will apply to all gas transmission lines and
support equipment, including lines transporting petroleum gas,
hydrogen, and other gas products covered under Part 192.
[[Page 34320]]
Elements of an Eventual Gas Integrity Management Rule
We believe that to fulfill our objectives, any rule that we propose
on integrity management programs for gas operators would need to
address the following seven elements. We used similar elements in
developing the liquid integrity management rules. Our treatment of
these elements will be based on certain hypotheses that are discussed
below. We welcome comment about these elements and hypotheses.
1. Define the areas where the potential consequences of a gas
pipeline accident may be significant or may do considerable harm to
people and their property. (We are calling these high consequence
areas).
Data from sites where gas pipelines have ruptured and
exploded have shown that the range of impact of such explosions is
limited. Therefore, the area in which near by residents may be harmed
or their property damaged by potential pipeline ruptures can be
mathematically modeled as a function of the physical size of the
pipeline and the material being transported (typically, but not
exclusively, natural gas).
Because gas pipeline operators are required to maintain
data on the number of buildings within 660 feet of their pipelines, the
definition of potentially high consequences areas where additional
integrity assurance measures are needed should incorporate these data.
The range of impact from the rupture and explosion of very
large diameter (greater than 36 inches) high pressure (greater than
1000 psi) gas pipelines is greater than the 660 feet currently used in
the regulations.
Special consideration must be given to protect people
living or working near gas pipelines who would have difficulty
evacuating the area quickly (e.g., schools, hospitals, nursing homes,
prisons).
Because of the relatively small radius of impact of a gas
pipeline rupture and subsequent explosion, and the behavior of gas
products, environmental consequences are expected to be limited. At
this time, OPS has little information that would indicate the
definition of high consequence areas near gas pipelines should include
environmental factors.
Given that pipeline operators maintain extensive data on
the distribution of people near their pipelines, OPS intends for
operators to use these data, together with a narrative definition of a
high consequence area (that OPS will define), to identify the specific
locations of high consequence areas. For OPS to map high consequence
areas for public and regulatory use, operators will have to provide
data (hard copy or digital) on the location of people living near their
pipelines as an attribute associated with the pipeline geospatial
features. For any operator not able to provide these data, OPS would,
instead, rely on census data to complete the maps of high consequence
areas to be used for gas integrity purposes. OPS is using this data to
map the high consequence areas defined in the liquid integrity
management rule.
2. Identify and evaluate the threats to pipeline integrity in each
area of potentially high consequences.
Effective integrity management begins with a comprehensive
threat-by-threat analysis. One approach divides potential threats to
pipeline integrity into three categories: time dependent (including
internal corrosion, external corrosion, and stress corrosion cracking);
static or resident (including defects introduced during fabrication of
the pipe or construction of the pipeline); and random (including third
party damage and outside force damage). In addition, human error can
influence any or all of these threats.
Identification and evaluation of the significance of
threats to pipeline integrity must involve the integration of numerous
risk factors. Such risk factors include, but are not limited to, pipe
characteristics (e.g., wall thickness, coating material and coating
condition; pipe toughness; pipe strength; pipe fabrication technique;
pipe elevation profile); internal and external environmental factors
(e.g., soil moisture content and acidity, gas operating temperature and
moisture content); operating and leak history (e.g., pipe failure
history, past upset conditions that have introduced moisture into the
gas); land use (e.g., active farming, commercial construction,
residential construction); protection history (e.g., corrosion
protection data, history of third party hits and near misses,
effectiveness of local One Call systems); and the degree of certainty
about the current condition of the pipeline (e.g., age of the pipe,
completeness of integrity-related records, available inspection data).
Pipelines having threats that represent higher risks
should generally be assessed sooner than those with threats that
represent lower risk.
Numerous studies and analyses on leak vs. rupture
thresholds of natural gas pipelines have shown that pipelines that
operate at a stress level less than 30% SMYS fail differently (i.e.,
leak rather than rupture) from those operating at higher stress.
Therefore, different integrity assurance techniques may be appropriate.
3. Select the assessment technologies best suited to effectively
determine the susceptibility to failure of each pipe segment that could
affect an area of potentially high consequences.
An integrity baseline needs to be established for all pipe
segments that could affect an area of potentially high consequences. An
operator will need to evaluate the entire range of threats to each
pipeline segment's integrity by analyzing all available information
about the pipeline segment and consequences of a failure on a high
consequence area. Based on the type of threat or threats facing a
pipeline segment, an operator will choose an appropriate assessment
method or methods to assess (i.e., inspect or test) each segment to
determine potential problems.
Time dependent threats will also require periodic
inspection to characterize changes in their significance.
Acceptable technologies for assessing integrity include
in-line inspection, pressure testing and direct assessment. None of
these technologies individually is fully capable of characterizing all
potential threats to pipeline integrity.
OPS is co-sponsoring with industry and state agencies an
evaluation of direct assessment technology to determine the conditions
under which direct assessment is effective in assessing external
corrosion. The validity of direct assessment in assessing other threats
(e.g., internal corrosion, stress corrosion cracking) is also being
explored.
Static threats will require pressure testing at some time
during the life of the pipeline. If significant cyclic stress, such as
that caused by large pressure fluctuations, is present, then pressure
testing, or an equivalent technology, will be required periodically
throughout the life of the pipeline.
Random threats will require the use of two parallel
integrity management approaches. The vast majority (over 90%) of
ruptures caused by random threats occur at the time when the threat is
imminent (e.g., when the excavator hits the pipeline). Therefore, the
use of risk management practices (or technologies) to prevent damage or
to immediately identify the potential for damage would be more
effective than looking for evidence of past damage. Secondly, since
some random threats do not result in immediate pipeline rupture,
technologies that look for evidence of past damage after the threat
[[Page 34321]]
has occurred should be focused in areas where delayed failure is most
likely.
Threats related to human error will be addressed largely,
but not completely, through the new Operator Qualification Rule. An
integrity management rule may need to address more specific problems.
4. Determine time frames to conduct a baseline integrity assessment
and to make any needed repair using a graded (tiered) approach where
assessment and repair are prioritized according to risk.
The time frame for conducting the baseline assessment
should be based on a graded or tiered approach where pipeline segments
are prioritized for assessment according to the level of risk they
pose. Thus, highest risk segments would be scheduled for assessment
first, lowest risk last. A schedule for taking remedial action on the
pipeline segment after the assessment would also be based on risk
factors.
The time frame for conducting the baseline assessment
should, among other factors, consider the impact on gas supply to
residents. This could also be a factor in determining if a variance
from the required time frame is warranted.
The sequence in which the segments are prioritized for
assessment should be determined by considering information such as, how
much pipe is in areas of potentially high consequences, which of these
pipe segments represent the highest risk, which threats for these
segments represent significant risks, how much time will be needed to
develop the infrastructure to perform the required assessments (e.g.,
validate the required assessment technologies, develop consensus
standards for the application of these technologies, expand the
industry capability to deploy and effectively use these technologies to
assess pipeline integrity). If the assessment finds potential problems,
the schedule for making the repairs would also be based on risk
factors.
5. Identify and implement additional preventive and mitigative
measures appropriate to manage significant threats.
Assuring a pipeline's integrity requires more than simple
periodic inspection of the pipe. Most threats, including passive
threats such as third party damage, require active management to
prevent challenges to integrity. Therefore, active integrity management
practices are necessary. Some operators already go beyond the current
pipeline safety regulations by implementing integrity management
practices such as ground displacement surveys, soil corrosivity
analysis, gas sampling and sampling and analysis of liquid removed from
pipelines at low points.
Preventive and mitigative measures include conducting a
risk analysis of the pipeline segment to identify additional actions to
enhance public safety. Such actions may include damage prevention
practices, better monitoring of cathodic protection, establishing
shorter inspection intervals, installing Remote Control Valves (RCVs)
or Automatic Shut-Off Valves (ASVs) on pipeline segments. Some
operators, particularly hydrogen pipeline operators, have voluntarily
installed ASVs on their pipelines at short intervals as a mitigative
measure.
6. Continually evaluate and reassess at the specified interval each
pipeline segment that could affect an area of potentially high
consequences using a risk-based approach. The evaluation considers the
information the operator has about the entire pipeline to determine
what might be relevant to the pipeline segment.
Managing a pipeline's integrity requires periodic
reassessment of the pipeline. The time frame appropriate for this
reassessment depends on numerous factors (see Element 2 above). In the
current class location change regulation, gas pipeline operators are
required to replace pipe segments with thicker-walled or stronger pipe
(or decrease pressure) as the near-by population increases above
threshold levels. This requirement for thicker-walled or stronger pipe
in areas of higher population might indicate that a longer reassessment
interval would be appropriate where corrosion is the dominant threat.
If critical risk factor data are not available to support
evaluation of risks, then the reassessment interval should be
appropriately shortened to reflect that absence of knowledge.
If an operator has developed a comprehensive picture of
past and anticipated threats, including detailed information on risk
factors and records of multiple assessments carried out over several
years, the operator might be able to justify a longer reassessment
interval.
The periodic evaluation is based on an information
analysis of the entire pipeline.
7. Monitor the effectiveness of the management process designed to
provide additional assurance of integrity in areas where the
consequences of potential pipeline accidents are greatest.
Measures can be developed to track actual integrity
performance as well as to determine the value of assessment and repair
activities.
Application of integrity management technologies that
exceed current regulations is cost effective because many companies
have made the decision to implement such programs.
Consideration of Impact on Gas Supply
Recent events, particularly in California and the Midwest, have
highlighted the limitations of energy supply in certain parts of the
country. Assessing pipelines using any of the technologies being
considered may result in a restricted gas supply because of pipelines
being taken out of service or by reduction in throughput. Some types of
repairs will also require lines to be taken out of service. To
illustrate, we have included a map (see sketch 1) of Northern Natural
Gas Company's gas transmission pipeline, which supplies gas to the
states of Iowa, Minnesota, Wisconsin, and Michigan. If an upstream
segment of this gas transmission pipeline were put out of service
temporarily for the test or repair, many communities located at the end
of branch lines, which have sole source feed (i.e., have no other tie-
in's from an alternative source), would be affected by the restricted
gas supply. Therefore, in developing the time frames for the baseline
assessment and continual reassessment intervals (or for allowing a
variance), and the schedule for repairs, we will need to consider,
among other factors, the actual adverse impact on the public of a
restricted gas supply.
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[GRAPHIC] [TIFF OMITTED] TN27JN01.000
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More Information Needed on Gas Integrity Management Program
We have summarized the areas where OPS is seeking further
information in developing a proposed integrity management program rule
for gas operators. The information needs are organized under nine
categories, seven of which are the elements we see as essential to any
integrity management program rule. We have added two other categories
to identify areas where we need information to evaluate the effect of
an integrity management rulemaking on costs and gas supply, both
seasonally and regionally.
To help promote discussion of these issues, we have also developed
an electronic discussion forum on OPS's Internet home page. The
Internet address for this forum is http://ops.dot.gov/forum. Because of
the way we have interspersed numerous questions throughout this
document with extensive background and technical information, some
commenters may find it difficult to find the areas they would like to
comment on. The electronic forum will list all the areas where we have
asked for comment so that commenters can easily focus on those areas of
interest to them. The electronic forum will allow real-time electronic
discussion for 45 days. We hope it will increase the breadth of
participation in the commenting process. A transcript of the electronic
discussion forum will be placed in the docket.
1. Define the Areas of Potentially High Consequence
Because the environmental consequences of a gas pipeline accident
tend to be localized, OPS's approach to defining areas of potentially
high consequences has focused on populated areas, particularly, areas
of high population and areas where groups of people reside who may have
difficulty evacuating an area.
Presently gas pipeline regulations are structured to provide
increasing levels of protection, consistent with predetermined
thresholds, where resident population is greater. Accordingly,
operators of gas pipelines are required to monitor the number of
dwellings within 660 feet of the pipeline, and either to lower
operating pressure or to replace the pipe with one having greater wall
thickness or strength as the number of dwellings increases above
predefined thresholds.
The consequences of these requirements are that--
Gas pipeline operators have excellent data on populations
near their pipelines, and
Pipelines operating in areas of higher population density
(called Class 3 & 4) typically have thicker or stronger walls than
those in lower population areas (called Class 1 & 2).
These factors, among others, differentiate gas pipelines from those
that carry hazardous liquids.
In the technical sessions at the Public Meeting, INGAA and AGA
presented a model that related gas pipeline diameter and operating
pressure to the physical boundaries of the area impacted by the heat
from a gas pipeline rupture and subsequent fire (i.e., the heat
affected zone). C-FER, a research and consulting organization from
Canada, developed the model. C-FER validated this model by comparing
the predicted heat affected zones with those actually observed in
several historic gas pipeline accidents.
The model predicted that the extent of the heat affected zone for
pipelines of up to 36 inches diameter and operating at pressures up to
1000 psi would be less than 660 feet. Rupture of larger pipelines that
are operating at a higher pressure would lead to a larger heat affected
zone. To develop both the 660-foot and the 1000-foot limits, C-FER used
a mathematical model of a burning jet of natural gas emitted from a
ruptured pipeline. Using the results of the model, INGAA and AGA
suggested High Consequence Areas be defined as--
All Class 3 & 4 locations as presently defined in the
pipeline safety regulations;
All locations where within 660 feet of the pipeline there
are facilities housing people with impaired mobility (e.g., schools,
day care centers, assisted living facilities, prisons, and hospitals);
All locations where within 1000 feet of a pipeline that
operates at pressures exceeding 1000 psi and has diameter greater than
30 inches there are facilities housing people with impaired mobility.
Critical Heat Flux
The INGAA/AGA analysis (developed by C-FER) used 5000 btu/hr-ft\2\
as the critical heat flux for defining the impact radius. However,
National Fire Protection Association (NFPA) Standard 59A and 49 CFR
Part 193 both use 4000 btu/hr-ft\2\ as the critical heat flux value.
OPS recognizes that the critical heat flux is only one element in the
equation that relates pipe diameter and maximum operating pressure to
the extent of the heat affected zone, and that C-FER validated this
equation by comparing the predicted heat affected zones with those
actually observed in several past gas pipeline incidents. However,
additional information would be useful on--
The source of the critical heat flux used in the analysis.
Other standards in which the 5000 btu/hr-ft\2\ value is
used, as well as standards in which the 4000 btu/hr-ft\2\ is used.
The size of the heat affected zone in the vicinity of a
ruptured hydrogen pipeline.
Housing
INGAA advocated that a high consequence area be limited to areas
within an impact zone (discussed above) where there are more than 25
houses or a facility housing people with impaired mobility. OPS would
like comment on whether an impact zone should be so limited, and if so,
whether 25 houses is a reasonable number.
Other Considerations
OPS is seeking information to evaluate the reasonableness of
including or excluding in a definition of high consequence areas--
All populous areas where the impact radius of a pipeline
rupture would be predicted to exceed 660 feet.
High traffic roadways, railways, and places where people
are known to congregate (churches, beaches, recreational facilities,
museums, zoos, camping grounds, etc.). For example, the recent gas
pipeline rupture near Carlsbad, New Mexico occurred in an unpopulated
area. Twelve people died in that incident.
Areas of environmental significance. Although
environmental consequences of a gas pipeline incident may be localized,
we recognize, nonetheless, that a gas release can ignite and cause
damage to wildlife species (animal and plants), and their habitat in
the area. We seek information to determine what, if any, environmental
considerations need to be addressed. Also of importance is whether
these areas can be readily identified so that they can be mapped--
similar to how OPS is mapping unusually sensitive environmental areas
for the liquid pipeline high consequence areas.
Mapping
OPS is creating the National Pipeline Mapping System (NPMS), a
database that contains the locations and selected attributes of natural
gas transmission lines and hazardous liquid trunk lines and liquified
natural gas facilities operating in the United States. Submission of
this information has been voluntary. At present, OPS has been provided
data on pipe locations for 82% of liquid pipelines but only 40% of gas
[[Page 34324]]
pipelines. OPS has also been mapping for hazardous liquid operators the
high consequence areas defined in the liquid integrity management rule.
These areas include populated areas, unusually sensitive environmental
areas, and commercially navigable waterways.
These maps are useful to pipeline operators and for community and
state needs. OPS is committed to continuing to provide this
information. OPS intends to map the high consequence areas that it
defines in a gas integrity management rule, similar to how it is
mapping these areas for the liquid operators. OPS expects operators to
provide their pipeline data on both high consequences areas and non-
high consequence areas. This information could be in digitized form or
in hard copy. OPS would expect gas operators to submit the high
consequence area data as an attribute associated with the pipeline
geospatial features. For operators not supplying the population data,
OPS is considering using the census data that it used to map the
population component of the high consequence areas for the liquid
integrity rule. If an operator relies on this census-based data, the
operator should be required to supplement the census data with other
pertinent data in identifying gas high consequence areas. Operators
would submit all data according to the NPMS standards. OPS seeks input
on the impact of this strategy. OPS would also like comment on whether
local distribution companies (LDCs) would prefer to use this census-
based population data to define their high consequence areas.
2. Identify and Evaluate the Threats to Pipeline Integrity in Each Area
of Potentially High Consequences
One of the key concepts advanced at the Public Meeting was the need
to select the right assessment tool for each significant threat. In the
INGAA presentation, threats were divided into three categories: time
dependent (e.g., internal and external corrosion), static or resident
(e.g., cracking introduced during fabrication of the pipe or
construction of the pipeline), and random (e.g., third party damage or
outside force damage). INGAA further maintained that each category of
threat has technologies (or practices) useful for managing the
associated risk. For example, time dependent threats would require
periodic inspection and static threats would require hydrostatic
testing at some time during the life of the pipeline (assuming that no
significant cyclic stress--such as strong pressure fluctuations--was
present). For random threats, such as third party damage and outside
force, INGAA said that the right tool would involve use of risk
management technologies (or practices) to prevent damage or to
immediately identify the potential for damage, rather than to look for
evidence of past damage. Preventive technologies or practices might
include third party damage prevention and monitoring of ground
movement. INGAA argued that preventive technologies and practices are
needed for these random threats because the likelihood of immediate
rupture when the event occurs dominates the risk.
Before an appropriate technology can be selected to assess each
significant threat, a determination or definition of what constitutes a
significant threat has to be made. OPS would like comment on what best
defines a threat as significant.
Corrosion
The most prevalent time-dependent threat is corrosion. Several
technologies exist or are in development both to prevent corrosion and
to identify the potential for damage from corrosion. OPS is seeking
information on the factors or combinations of factors that provide the
clearest indication that corrosion is a significant risk to pipeline
integrity.
Third Party Damage
The most significant threat in areas of high population is third
party damage. The vast majority (over 90%) of ruptures caused by third
party damage occur when the threat occurs (i.e., when the excavator
hits the pipeline). However, a small fraction of third party damage
failures do occur well after the impact. Therefore, technologies that
look for evidence of past damage after the threat has occurred should
be focused in areas where delayed failure is most likely. OPS is
seeking further information on the combination of material properties
and/or operating conditions that could increase the susceptibility of
pipelines to delayed failure following third party damage. For example,
thick walled, high toughness pipe can sustain a strike from a third
party with a much lower likelihood of immediate rupture than other
pipe. In combination with some source of cyclic fatigue, such pipe can
be much more susceptible to delayed rupture from third party damage.
Pipelines with these characteristics in areas where the likelihood of
third party damage is high need to be assessed for residual damage.
OPS also is seeking information on pipeline industry efforts to
explore new technologies capable of recognizing or preventing third
party damage and to incorporate proven technologies into company
integrity management plans.
Special Conditions
The presence of one or more critical risk factors often indicates a
significantly increased likelihood of other failure modes or threats.
For example, pre-1970 ERW piping is known for seam cracking and
subsequent rupture. Such seam cracking is difficult to detect using
standard pigging technologies. In addition, thick walled, high
toughness pipe can sustain a strike from a third party with a much
lower likelihood of immediate rupture than other pipe. In combination
with some source of cyclic fatigue, such pipe can be much more
susceptible to delayed rupture from third party damage. Further, some
pipelines operating at elevated temperature in a potentially corrosive
environment may be especially susceptible to stress corrosion cracking.
OPS is seeking information on any special characteristics that can
influence pipeline risk and mode of failure. The presence of these
special characteristics may necessitate the use of specially designed
assessment technologies.
Erosion
Some commenters have pointed out soil erosion as a potential threat
to pipeline integrity. OPS is seeking information on the conditions
under which soil erosion has been a significant failure mode, including
the possibility of erosion exposing the pipeline to external damage
from passing water-born debris, and on the practices useful to prevent
failure resulting from soil erosion.
Operator Error
Several questioners at the public meeting emphasized the need to
address operator error in compromising pipeline integrity. INGAA
responded that the new Operator Qualification Rule addresses the
primary impacts of operator error on pipeline integrity. INGAA further
said that each of the three categories of failure causes (i.e., time-
dependent, random, and static or resident), the summary of failure
causes developed by Kiefner and Associates, and the preventive and
mitigative practices documented by Hartford Steam Boiler address
operator error. (The Kiefner and Hartford Steam Boiler reports can be
viewed on the OPS web site under Initiatives/Pipeline Integrity
Management Program/Gas Transmission Operator Rule ). Given these
initiatives to address operator error, OPS is seeking information on
how best to address remaining integrity-related human error
[[Page 34325]]
concerns in an integrity management rule. In particular, OPS is
interested in--
The potential for increased error in conducting
assessments and interpreting results resulting from the expanded
application of assessment technologies and interpretation of assessment
results that are likely to result from an integrity management rule,
and
Increased demands on the time of experienced staff to
integrate risk factor information to identify significant threats
requiring assessment.
How to increase reporting of error within a company.
How to ensure that lessons are learned from error and
incidents.
Treatment of Storage Fields
Storage fields have been the source of pipeline integrity problems
for decades. OPS is seeking information to help identify the cause of
and prevent piping-related failures associated with storage fields that
could affect high consequence areas.
OPS is also interested in information on the gas pipeline
industry's efforts to reinvigorate the National Association of
Corrosion Engineers' (NACE) standard setting or develop guidance
focused on gas storage fields.
Low Stress Pipelines
The American Gas Association (AGA) and American Public Gas
Association (APGA) maintain that--
Pipelines operating at a stress level below 20% specified
minimum yield strength (SMYS) are of low enough risk that they should
not be covered by a gas integrity management program rule, and
For pipelines operating between 20% and 30% SMYS,
integrity management practices other than internal assessment,
hydrostatic testing and direct assessment are adequate. (Direct
assessment is a term coined by the gas pipeline industry. The term is
described in greater detail below).
OPS is seeking the following information to determine how best to
treat low stress pipelines in an integrity management rule.
Actual data on the leak and rupture history (presented by
failure mode) of natural gas pipe operating below 20% SMYS and between
20% and 30% SMYS.
Comparisons of this leak and rupture history information
with the corresponding information for higher stress piping (by failure
mode).
A more thorough discussion of the process that AGA is
advocating for companies operating low stress pipelines to follow to
provide added assurance of integrity. Questions to be addressed
include--
Are risk profiles to be developed and maintained for low
stress pipe segments that could affect high consequence areas?
How would such risk profiles be used to support decisions
on which segments require application of more extensive assessment
technologies?
What actions would be taken in response to findings?
What means should be used to evaluate the potential
consequences associated with pipe segments that fail by leaking? (e.g.,
Where does the potential for accumulation of leaked gas increase the
likelihood of an explosion ultimately occurring as a result of an
undetected leak?)
What would be appropriate baseline and reassessment
intervals for low stress lines (for those operating below 20% SMYS and
those operating between 20-30% SMYS)?
3. Select Appropriate Assessment Technologies
INGAA maintains that gas pipeline integrity can be effectively
assessed using one or more of three approaches: in-line inspection,
hydrostatic testing and the direct assessment process. (The direct
assessment process is discussed below). INGAA further maintains that
selecting an assessment technology should be based on an analysis of
all relevant risk factors to determine which threats represent the most
significant risks.
Correspondence Between Threats and Assessment Technologies
To ensure that integrity management programs are designed to
address the full spectrum of failure causes (threats), OPS is seeking
information on the correspondence between assessment technologies and
the threats they are designed to detect. Available information on the
range of effectiveness of each technology would also be beneficial.
Experience With In-Line Inspection
OPS is seeking information on experience with using in-line
inspection (ILI) technology. Relevant information would include the
number, type and severity of features or defects discovered as a
function of the technology employed, risk factors that were present,
and when and how the defects were acted on. These data could help us in
determining the potential number of incidents prevented through the use
of ILI technology. We are also seeking data on estimated costs
associated with implementing ILI technology.
Effectiveness of Pressure Testing
INGAA contends that a pressure test conducted at any time during
the life of a pipeline provides adequate assurance that so-called
static or resident defects (e.g., cracking introduced during
fabrication or construction) are no longer an integrity concern. The
premise behind this position is that gas pipelines do not typically
operate under cyclic pressure loading of sufficient magnitude to
promote crack growth. Therefore, a hydrostatic or pressure test
conducted at any time during the life of the pipeline will forever
eliminate any concern about the risk from static or resident defects.
INGAA has not claimed that a once-in-a-lifetime pressure test will
eliminate concern for other types of threats such as time-dependent
(e.g., corrosion) or random (e.g., third party damage). OPS is seeking
information on conditions (other than changes in cyclic pressure
loading) in which the premise that a once-in-a-lifetime pressure test
will eliminate the risk from static or resident defects does not apply.
Incentives To Increase the Piggability of Lines
OPS is interested in promoting the appropriate expanded use of in-
line inspection (or pigging) technologies. Therefore, OPS is seeking
information on the current and near-term expected mileage of gas
transmission lines that can be pigged, as well as on financial (or
feasibility) barriers to making other lines piggable.
Direct Assessment
Direct assessment is a structured process for assessing pipeline
integrity. While OPS focus on direct assessment at this stage is on
assessing external corrosion, work is in process to explore its
application to internal corrosion and stress corrosion cracking. The
process has four basic steps:
1. A comprehensive integrative analysis of risk factor data is used
to determine whether direct assessment will apply, what threats are
likely to be significant, where these significant threats are likely to
be present, and what tools are best suited to characterize pipe
condition. Candidate data for integration include:
Pipe characteristics (e.g., wall thickness, coating
material and condition, pipe toughness, pipe strength, pipe fabrication
technique, pipe elevation profile);
Internal and external environmental factors (e.g., soil
moisture content and acidity, gas operating temperature and moisture
content);
Operating and leak history (e.g., pipe failure history,
past upset
[[Page 34326]]
conditions that have introduced moisture into the gas);
Land use (e.g., active farming, commercial construction,
residential construction);
Protection history (e.g., cathodic protection system and
history, history of third party hits and near misses, effectiveness of
local One Call systems);
The degree of certainty about the current condition of the
pipeline (e.g., age of the pipe, completeness of integrity-related
records, available inspection data).
2. An above ground examination is made of the pipeline using one or
more direct assessment tools to identify areas where coating defects
(holidays and disbondment) are likely to exist and whether or not
active corrosion is likely to be present.
3. Excavation (digging bell holes) is used to expose the pipe in
areas suspected to be experiencing active corrosion, then the pipeline
is examined visually, and other evaluative techniques such as
ultrasonic testing are used.
4. Information from all available excavations is integrated and
generalized to determine whether and where additional bell holes should
be dug to seek out additional potential active corrosion.
Validation Process and Research & Development Efforts on Direct
Assessment
The individual technologies employed in direct assessment have been
utilized for pipeline integrity assessment for many years. However, the
use of these technologies in an integrated process that includes
analysis of risk factor data is new. Also, some new tools such as
Direct (or Alternate) Current Voltage Gradient (DCVG or ACVG), Pipeline
Current Mapper, C-Scan and C-Spin are being introduced. Therefore, the
industry has undertaken a validation process designed to determine both
the conditions under which direct assessment is most effective and the
effectiveness of the overall process. OPS is providing funding for this
project along with extensive project oversight. Process effectiveness
will be evaluated by comparing the results from direct assessment
technologies with the results from bell hole examinations and with the
results from in-line inspection of the same segments. Between 15-25
pipeline operators are participating in this validation study by
contributing existing assessment data and developing new data from
application of the technologies. State agencies are involved in
reviewing the data.
OPS is seeking the following information on the direct assessment
process:
How direct assessment can be validated and applied for
external and internal corrosion, including applications for dry and wet
gas lines;
The need where there are multiple threats on the same
segment of pipeline for complementary supporting assessment techniques,
or for additional corrective and mitigative actions, to address the
multiple threats;
Whether there are conditions where direct assessment may
not be possible or may not give accurate information;
The statistical basis for validating the external and
internal corrosion direct assessment process as well as the
justification for this basis;
How direct assessment can be applied and evaluated for
stress corrosion cracking;
Available standards to support the use of all types of
direct assessment that are envisioned;
The most important risk factors that should be considered
in analyzing the applicability of each direct assessment technology to
each threat.
The process for information integration as it relates to
direct assessment.
The application of direct assessment to uncoated pipeline.
Local distribution companies
AGA and APGA contend that because local distribution company (LDC)
transmission pipelines are typically so closely coupled to the
distribution system, hydrostatic testing would result in significant
service interruptions, and pigging would be highly uneconomical if even
possible. In a white paper released since the public meeting, AGA and
APGA have described what alternative technologies are available, and
why alternatives provide adequate protection for these lines. (This
paper can be found on the OPS web site under Initiatives/Pipeline
Integrity Management Program/Gas Transmission Operator Rule and in the
DOT docket.)
4. Determine Time Frames To Conduct a Baseline Integrity Assessment and
To Complete Repairs Following an Assessment Using a Graded (Tiered)
Approach That Prioritizes Pipeline Segments Based on Risk
A time frame will have to be determined for operators to conduct a
baseline assessment of their pipe segments using a graded or tiered
approach. Under this approach, an operator would prioritize all
applicable pipeline segments for assessment based on the risk the
segments pose to the high consequence areas. The risk would be
determined from risk factors. A schedule for completing repairs of the
segments after the assessment would also be based on risk factors. One
of the factors in developing the required time frame, or establishing
variances from the required time frame, would be the need to maintain
gas supply to the public.
Baseline Assessment
The INGAA presentation did not discuss a time frame for a baseline
assessment. To help develop a required baseline assessment schedule
that considers the various risk levels for each pipe segment to be
assessed, OPS is seeking the following information.
Practical considerations of establishing a graded (or
tiered) approach for conducting a baseline assessment. A graded
approach is one where baseline assessments of the highest risk pipeline
segments are conducted as soon as possible with baseline assessments
for lower risk segments completed subsequently. Risk would be
determined from risk factors, whether specified, operator-developed or
a combination.
The time required for the industry to mobilize (e.g.,
develop models and perform needed risk analysis, complete demonstration
of needed technologies, train and qualify the resource base needed to
support a baseline assessment).
Information on the impacts to the gas supply and to the
cost of gas if a time frame for completing a baseline assessment were
required, for example, a time frame of 5, 10 or 15 years.
Repair criteria currently being considered. Criteria would
include time frames for competing repairs following an assessment.
5. Identify and Implement Additional Preventive and Mitigative Measures
INGAA submitted a report (prepared by the Hartford Steam Boiler
Inspection and Insurance Company) that summarizes the range of threats
identified as causing failure in gas pipelines, the management
practices industry is using to manage these threats, and the research
contributing to the understanding of the threats. (This report is
available in the DOT docket and on the OPS web site under Initiatives/
Pipeline Integrity Management Program/Gas Transmission Operator Rule.)
OPS is seeking unattributed examples of typical decision
processes that an operator uses to manage threats to pipeline safety by
implementing discretionary preventive or mitigative technologies or
practices such as those
[[Page 34327]]
discussed in the Hartford Steam Boiler report.
As part of the integrity management process, an operator would need
to take additional measures to prevent and mitigate the consequences of
a pipeline failure in high consequence areas. In the liquid integrity
management rule, operators are required to conduct a risk analysis of
each pipeline segment to identify additional measures to enhance safety
and environmental protection. For gas pipelines, additional preventive
and mitigative measures could include actions such as damage prevention
best practices, better monitoring of cathodic protection, establishing
shorter inspection intervals, and installing Remote Control Valves
(RCVs) and Automatic Shutdown Valves (ASVs) on pipeline segments.
OPS is seeking information on the effectiveness, technical
feasibility, economic feasibility, and reduction of risk with RCVs and
ASVs.
6. A Process for Continual Evaluation and Assessment to Maintain a
Pipeline's Integrity
Integrity assurance involves periodic assessment of the integrity
of each pipeline segment within a high consequence area, periodic
evaluation of the entire pipeline to determine threats relevant to the
pipeline segment, and repair of problems.
Periodic Reassessment
Times frames need to be developed for an operator to periodically
assess the integrity of its pipeline segments. At the public meeting,
INGAA recommended a periodic reassessment interval for all technologies
(i.e., in-line inspection, direct assessment and hydrostatic testing)
of 10 years for pipe of thickness typically used in Class 1 & 2
locations, and 15 years for pipe of thickness typically used in Class 3
& 4 locations. INGAA said these reassessment intervals were
conservative estimates of the maximum time between pipeline inspections
to prevent failure of the largest defect and that they were developed
based on very conservative assumptions on corrosion growth rate that
were checked against both analysis and experience data. INGAA further
explained that these reassessment intervals assumed that at the
beginning of the interval, the pipe thickness was not less than that of
new pipe appropriate for the class location. Thus, there would be
variations in the actual reassessment interval depending on the
assessment technology. INGAA noted that an operator might be able to
extend the reassessment interval based on its knowledge of and
demonstrated control over the principal risk factors for its pipeline,
but that if any of the data on key risk factors were missing, then an
operator would need to develop a shorter reassessment interval.
OPS is seeking information to help it determine appropriate
periodic reassessment intervals. This information could include
examples detailing a proposed reassessment interval following a
successful baseline assessment and repair of problems found during the
assessment. These examples could use the INGAA proposed intervals or
any other, such as those required in the liquid pipeline integrity
management rules. The examples could also factor in repair criteria
used to re-mediate problems found during the baseline assessment.
In some cases pipelines have been designed for placement in Class 3
and 4 locations by using steel with greater toughness and strength
rather using pipe having greater wall thickness. These pipelines are no
less susceptible to corrosion damage; therefore, OPS is considering
whether a reassessment interval should be defined by the wall thickness
rather than by the Class location for a pipeline segment. OPS would
also like information on how a reassessment interval would factor in
the impact of increased ligament strength where higher strength pipe is
used rather than thicker pipe.
Repairs
Following the reassessment, an operator would have to schedule
repairs on the pipeline segments. This would be done by prioritizing
the anomalies found during the assessment for evaluation and repair.
The schedule, which would be risk-based, would need to provide time
frames for evaluating and completing repairs. In the liquid integrity
management rule, we provided time frames for an operator to complete
repair of certain conditions on a pipeline following an assessment. For
those conditions not specified, we allowed the operator to provide time
frames for evaluating and completing the repairs. The schedule was to
be based on specified and pipeline-specific risk factors.
Comment is sought on the time frames to complete needed repairs and
factors that need to be considered in establishing these time frames.
One factor could be the impact on the gas supply. If no other guidance
is available on scheduling repairs, OPS may develop a repair schedule
similar to that used in the liquid integrity management rule.
Evaluation
A periodic evaluation looks at all available information about the
entire pipeline to determine what could be relevant to the pipeline
segment being examined. The frequency at which evaluations are
conducted could be based on risk factors, either specified factors,
operator-developed or a combination. We seek comment on how to
determine frequency and how to ensure that information is analyzed on
all threats to a segment.
Direct Assessment
OPS is seeking information on the logistics of rapidly expanded use
of Direct Assessment technologies, particularly on whether the current
pool of trained and qualified assessors would pose any constraint to
industry's ability to rapidly expand the use of these technologies.
This issue should also be considered in conjunction with any input on
the best strategy for establishing a baseline assessment interval.
7. Monitor the Effectiveness of Pipeline Integrity Management Efforts
OPS is seeking information on how it could best monitor the
effectiveness of operator integrity management efforts. Information is
needed both on specific direct performance measures and on indirect
measures derived from analysis of assessment results and corrective
actions taken.
OPS and the industry have been criticized for an ineffective system
that assembles incident data, analyses it for possible implications to
other pipelines, communicates across the industry the general lessons
and implications of the these incidents, and follows up to evaluate the
effectiveness of operator incorporation of the general lessons from
these incidents. Some work to address this issue is ongoing, such as
revised reporting criteria. OPS is seeking input on potential
additional actions that could be taken jointly by OPS and the industry
to address this concern.
8. Consideration of Impact on Gas Supply
OPS needs information to evaluate the effect of new safety
requirements on gas supply to residents. This is one of many factors
that OPS will need to consider in establishing a baseline assessment
time frame. Information is needed on how gas supply would be affected
with baseline assessment time frames of 5, 10 and 15 years. The same
information is needed for reassessment intervals of 5, 10, 15 and 20
years.
[[Page 34328]]
9. Other Issues Including Those Related to Cost/Benefit
Scope of Integrity Management Planning
Earlier in this document OPS explained its current thinking about
the scope of a proposed integrity management rule. OPS would like
comment about its underlying assumptions.
Cost Benefit Analysis
To support its cost benefit analysis, OPS is seeking additional
information on the following topics:
Benefits and costs of a company's active-in-line
inspection and pressure testing programs. Information could include the
results on safety such as the reduction of accidents or leaks.
Benefits and costs of a company's integrity assessment
program employing direct assessment technologies. Information could
include the types of direct assessment that have been used or
considered. The costs associated with the technologies. The results
related to safety, such as the reduction of accidents or leaks reduced.
The total mileage of gas transmission pipeline. The number
of miles of gas transmission pipelines that have been hydrostatically
tested to current standards. The number of miles of gas transmission
pipelines that have been pigged at least once.
The estimated average cost per mile to hydrostatically
test a gas transmission pipeline. The fraction of this cost that is
associated with taking the line out of service. Ways to minimize the
cost associated with taking the line out of service, such as using
existing looping.
The estimated average cost per mile to internally inspect
a gas transmission pipeline. The fraction of this cost that is
associated with taking the line out of service. Ways to minimize the
cost associated with taking the line out of service, such as using
existing looping.
The percentage of an operator's pipelines that are not
capable of being pigged. The reasons the pipeline is not piggable, for
example, because it is telescopic, has sharp radius bends, or has less
than full opening valves The costs to make the line piggable.
Impacts on small businesses. The impacts an integrity
management rulemaking will have on the company. Include any special
concerns that RSPA should consider in addressing impacts on small
businesses. Include whether there are alternative requirements for
small businesses that are less onerous.
The estimated average cost per mile to use direct
assessment on a gas transmission pipeline. The assumptions this
estimate includes on the number of bell holes required per mile.
The estimated average cost per mile to change out a gas
transmission pipeline to comply with existing class location
regulations. The number of miles per year that are typically replaced
to comply with this regulation.
The best available data on the actual costs associated
with reported gas pipeline incidents.
An inventory of pipeline mileage for pipe having diameter
greater than or equal to 30 inches and MAOP greater than or equal to
1000 psi.
Standards
During the public meeting, INGAA stated that consensus standards
represent a practical way to institutionalize both the use of new
technology and the effective application of existing technology. INGAA
said that standards currently being developed should provide detailed
information for operators in implementing any integrity management rule
that is eventually issued.
OPS is seeking information on the schedule the Standards
Organizations have for completing the various standards that relate to
integrity management that are expected to be prepared, particularly the
standards on conducting integrity assessments and repair criteria. The
current ``draft'' Schedule on Standards is found at the end of this
Notice.
Industry Data Analysis
We believe that data sources outside OPS incident data should be
considered in developing risk analysis and assessment intervals. OPS
seeks to better understand the extent to which data beyond these
incident histories, including data from all incidents and near misses,
were used to validate industry positions.
Issued in Washington, DC, on June 19, 2001.
Jeffrey D. Wiese,
Acting Associate Administrator for Pipeline Safety.
[FR Doc. 01-15990 Filed 6-26-01; 8:45 am]
BILLING CODE 4910-60-P