[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.

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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

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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