[Federal Register Volume 64, Number 203 (Thursday, October 21, 1999)]
[Proposed Rules]
[Pages 56725-56731]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 99-27281]
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DEPARTMENT OF TRANSPORTATION
Research and Special Programs Administration
49 CFR Parts 192 and 195
[Docket No. RSPA-99-6355; Notice 1]
Pipeline Safety: Enhanced Safety and Environmental Protection for
Gas Transmission and Hazardous Liquid Pipelines in High Consequence
Areas
AGENCY: Research and Special Programs Administration (RSPA), DOT.
[[Page 56726]]
ACTION: Notice of public meeting and request for comments.
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SUMMARY: This notice announces a public meeting to consider the need
for additional safety and environmental regulations for gas
transmission lines and hazardous liquid pipelines in high-density
population areas, waters where a substantial likelihood of commercial
navigation exists, and areas unusually sensitive to environmental
damage. RSPA's Office of Pipeline Safety (OPS) intends to incorporate a
process into its regulations to validate pipe integrity in these high
consequence areas. The purpose of the meeting is to determine the
extent to which operators now have integrity management programs, to
explore effective ways to promote their development and implementation
by all operators, and to discuss mechanisms by which OPS could confirm
the existence and adequacy of such operator-developed programs. The
meeting will discuss a practical definition of high consequence areas,
as well as the need, if any, for increased inspection, enhanced damage
prevention, improved emergency response, and other measures to prevent
and mitigate pipeline leaks and ruptures in these areas.
DATES: The public meeting will be on November 18, 1999, from 9 a.m. to
4 p.m., through November 19, 1999, from 9 a.m. to 12 noon, at the Hyatt
Dulles Hotel, 23 Dulles Corner Boulevard, Herndon, VA 20171, (703) 713-
1234. If you want to make an oral presentation at the meeting, please
notify Jenny Donohue no later than November 12, 1999, by phone (202-
366-4046) or by Internet e-mail (donohuej@rspa.dot.gov). In addition,
no later than December 20, 1999, you may submit written comments as
described in the ADDRESSES section.
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. You also may submit written
comments to the docket electronically. To do so, log on to the
following Internet Web address: http://dms.dot.gov. Click on ``Help &
Information'' for instructions on how to file a document
electronically. All written comments should identify the docket and
notice numbers stated in the heading of this notice. Anyone desiring
confirmation of mailed comments must include a self-addressed stamped
postcard.
The Dockets Facility is located on the plaza level, Room PL-401, of
the US Department of Transportation, 400 7th St., SW, Washington, DC.
It is open from 10 a.m. to 5 p.m., Monday through Friday, except
federal holidays.
FOR FURTHER INFORMATION CONTACT: Beth Callsen (tel: 202-366-4572; E-
mail: beth.callsen@rspa.dot.gov). You can read comments and other
material in the docket on the Internet at: http://dms.dot.gov.
SUPPLEMENTARY INFORMATION:
Background
Office of Pipeline Safety (OPS) and National Transportation Safety
Board (NTSB) investigations and analyses of major pipeline incidents
have underscored the importance of ensuring safety and environmental
protection in areas of high population density and in areas unusually
sensitive to environmental damage. Congress has also directed OPS to
undertake a variety of activities concerning areas where the risk of a
pipeline spill could have significant impact (what we call high
consequence areas). For example, Congress directed OPS to prescribe, if
necessary, additional standards requiring the periodic inspection of
each pipeline in high population density areas or in areas unusually
sensitive to environmental damage (49 U.S.C. 60108 (b)).
In response to the Congressional directive, OPS created the Risk
Management Demonstration Program, the Systems Integrity Inspection
(SII) Program, and other initiatives. These programs encourage and
evaluate operator-developed safety and environmental management
processes that incorporate operator- and pipeline-specific information
and data to identify, assess, and address pipeline risks. These
programs, along with the Oil Spill Response Plan Review and Exercise
Program, have helped OPS refine regulatory oversight processes. These
processes help to ensure that pipeline operators have effective
processes in place to identify the most important risks to the public
and the environment, and to develop and implement cost-effective
preventive and mitigative actions to manage these risks. Many of these
initiatives have validated the importance of focusing resources and
establishing higher levels of protection in areas where a pipeline
spill could have significant consequences.
Through its various programs and initiatives, OPS has observed and
become familiar with the wide array of existing operator safety
programs that identify, assess, and address all significant risks to
the pipeline in an integrated manner. These operator-developed programs
closely examine internal inspection data, surveillance and operating
information such as expected population growth, land use, and
construction activity along the pipeline, and other information
relevant to assuring the pipeline's integrity in high population areas
and in environmentally sensitive areas. OPS believes the next step is
to determine the extent to which such programs exist, to develop
effective ways to encourage their development and implementation by all
operators, and to establish mechanisms by which OPS can confirm the
existence and adequacy of such operator-developed programs.
OPS believes that current pipeline safety regulations address the
most important risks to the nation's pipelines, and have served the
industry well, resulting in a good safety record compared to
competitive modes of transportation. However, safety programs based on
strict compliance with the regulations can often result in a piece-meal
approach to identifying and controlling risks, sometimes neglecting the
interrelationships among failure causes and the benefits of coordinated
risk control activities.
OPS is considering ways to further enhance safety and environmental
protection in areas where a pipeline failure could have serious
consequences for the public or the environment, i.e., high consequence
areas, through a more integrated approach to identifying and addressing
risks. A conceptual approach is described below. OPS believes that many
operators already have processes in place that are consistent with this
approach. Through this Notice and the November 18-19, 1999, public
meeting, OPS is soliciting input on this or other approaches to
improved protection for high consequence areas.
Key Elements
OPS envisions a process that places stronger regulator and operator
emphasis on high consequence areas in the vicinity of pipeline
facilities. The following key elements should be reflected in such a
process:
1. The need for pipeline-specific assessments in determining the need
for additional preventive and mitigative activities.
OPS recognizes that industry-wide requirements for specific
additional preventive or mitigative actions might not be the most
effective way of reducing risk. Companies must have the responsibility
and the necessary flexibility to consider geographic- and segment-
specific conditions in assessing the need for additional safety and
[[Page 56727]]
environmental protection programs and in developing effective programs.
2. The need to assess all risk factors and risk reduction activities in
an integrated manner.
Analyses of major pipeline incidents show that combinations of
design, operation, maintenance, and environmental factors are usually
involved, rather than a single cause. Accordingly, OPS envisions
assessment and decision processes that examine causes for pipeline
failure in a comprehensive and integrated manner. For example, data
from internal in-line inspections must be combined with other
information related to the condition of the pipe (e.g., results of
close internal surveys and patrols) to determine appropriate evaluation
and remediation activities.
3. The need for increased assurance that high consequence areas are
being protected.
OPS recognizes that existing regulations and industry practices
already focus on some high consequence areas. For example, the class
location scheme embedded in the gas pipeline regulations imposes more
stringent requirements in areas with higher population. Many liquid
pipeline operators already have formalized environmental, safety, and
health programs that focus attention and resources on areas of highest
risk. However, OPS also recognizes the need to assure the public that
the condition of the pipelines in high consequence areas is adequately
known, that current regulations and industry practices are adequate,
and that the need for additional protection has been explicitly and
responsibly considered.
OPS's Approach to Improved Protection
OPS envisions a process that would include, at the least, the
following steps:
Defining and Locating High Consequence Areas
Identifying Affected Pipeline Segments
Inspecting and Assessing the Condition of the Affected
Segments
Assessing the Need for Additional Preventive or Mitigative
Actions
Remediating and Repairing the Affected Segments as
Necessary
Implementing and Monitoring Other Cost-Effective Risk
Control Activities
Documenting Inspections, Assessments, and Actions
Reviewing and Ensuring Compliance
(See the Flowchart included in this Notice.)
Each of these steps is briefly discussed below, including key
questions for discussion.
Identifying and Locating High Consequence Areas
The first step in the process is to identify and locate the areas
where a pipeline failure could pose serious safety and environmental
consequences to the public or environment. This first step is intended
as a filtering step, focusing attention on those areas of possible high
consequence. Subsequent steps address the likelihood of such
consequences actually occurring, and the need for any action to reduce
the likelihood or consequences of a pipeline incident in these areas.
There are relevant past and current efforts to define or identify
these areas.
Class locations for gas pipelines (49 CFR 192.5) are based
on habitable structures within a 220 yard corridor on either side of
the pipeline.
Many companies have developed Geographic Information
Systems (GIS) that can provide accurate, more detailed information
concerning the proximity of population and buildings to the pipeline.
OPS, other federal agencies, and the hazardous liquid
pipeline industry are working together to develop a definition for
Unusually Environmentally Sensitive Areas (USAs), focusing on areas in
which a pipeline spill could threaten local water supplies, threatened
and endangered species, and other environmental resources (Docket No.
RSPA-99-5455; 64 FR 38173; July 15,1999). OPS is currently pilot
testing a model for defining USAs.
In high consequence areas, OPS believes that an operator should be
required to explicitly assess each area, determine the condition of the
pipeline that could affect these areas, understand the potential causes
of failure of these pipelines, and ascertain the need, through a
structured and documented process, for additional preventive or
mitigative actions.
Key questions that OPS would like to discuss at the meeting
include:
a. How should ``high consequence'' areas be defined?
1. What is the status of OPS's definition of USAs?
2. What should be the definition of ``high population density''
area for a natural gas pipeline?
3. Can operator GIS systems be used to identify high population
areas with greater precision than current class location schemes?
4. What should be the definition of ``high population density''
area for a hazardous liquid pipeline?
5. Should ``high property damage,'' ``significant disruption in
service,'' ``significant disruption in commerce,'' ``waters where a
substantial likelihood of commercial navigation exists,'' or the
potential for other significant consequences be included in the
definition of high consequence areas?
b. Should the operator or OPS be responsible for identifying the
location of high consequence areas?
c. What percentage of natural gas pipelines might be expected to
intersect high consequence areas (e.g., what percentage currently are
in Class 3 or Class 4 locations?)
d. What percentage of hazardous liquid pipelines might be expected to
intersect high consequence areas (e.g., what percentage currently are
in non-rural areas or intersect USAs).
e. What process should OPS or the industry use to ensure that the
identified high consequence areas continue to reflect current
conditions along the pipeline (e.g., population expansion, new
information on environmental resources)?
2. Identifying Affected Pipeline Segments
In this step, the specific pipeline segments whose failure could
have serious safety or environmental consequences are identified. Once
the high consequence areas are located on a map, the existing pipelines
must be overlaid to identify the segments in or in close proximity to
these areas. The physical ability of the overlaid pipeline segments to
affect the environmental resources in the area or to impact the
surrounding population must then be examined. The fact that a pipeline
is within a high consequence area (defined in the first step) does not
necessarily mean that a pipeline leak or rupture can result in
environmental damage or impact public safety. For example, the
population in a ``high population density'' area might be physically
located sufficiently far from the pipeline to preclude safety impact.
There may also be topographical barriers between the environmental
resource and the pipeline that would preclude migration of any spill
from the pipeline to the resource. This step, in conjunction with the
first screening step, allows the pipeline operator to take into account
pipeline-specific information to identify those segments of pipe that
could result in environmental damage or public safety consequences.
[[Page 56728]]
Key questions that OPS would like to discuss at the meeting
include:
Does adequate data exist for operators to reliably
ascertain the specific pipeline segments that could affect ``high
consequence'' areas?
Should pipeline segments near, but not within, high
consequence areas also be examined for possible impact? If yes, what
kinds of assumptions should be used to determine whether or not an
impact occurs (e.g., use of ``worst case discharge'' from spill
response plans)?
What would be the expected cost to an operator to perform
this step?
3. Inspecting and Assessing the Condition of the Affected Segments
The next step in the process is for the operator to understand and
assess the condition of the pipeline segments identified in Step 2.
This step, in conjunction with the following step, is intended to
ensure that the likelihood of pipeline failure due to internal or
external corrosion, construction damage, previous excavation damage, or
other mechanical damage is very low.
Undetected defects introduced by corrosion or by outside force
damage have caused major pipeline accidents. Some of the major pipeline
incidents over the last decade involved degradation of wall thickness
from dents or gouges caused by outside force or third party damage. In
some instances these dents and gouges had been in the pipe for a period
of time before failure, and the line had not been inspected using
internal inspection tools capable of detecting wall thinning or
geometric defects in the pipe. OPS is especially interested in methods
to detect and repair such defects before they lead to leaks or ruptures
in high consequence areas.
One acceptable way of performing this step would be the use of an
intelligent in-line inspection device (smart pig) appropriate to the
type of pipeline being inspected. An operator can also use alternative,
equivalent means to assess the condition of the affected segments. If
the line has recently been pigged, the operator could review the
available pig data in conjunction with other current data (e.g., from
close interval surveys) to assess the condition of the line. This step
results in an operator identifying anomalies (areas of potential loss
of wall thickness or pipe damage) that should be investigated further.
The hazardous liquid pipeline industry has developed recommended
practices for monitoring, testing, and inspection methods that go
beyond the requirements of 49 CFR part 195 (API Recommended Practices
1129, Assurance of Hazardous Liquid Pipeline System Integrity). This
document comprises a range of best practices--including design and
construction; monitoring and controls; inspections, reviews and audits;
and damage prevention--to assist pipeline operators in improving the
integrity of their pipeline systems.
Key questions that OPS would like to discuss at the meeting
include:
Are current industry standards sufficient for pipelines in
high consequence areas? For example, is the ASME B.31 standard, used by
operators to determine acceptable pipe wall loss, appropriate in high
consequence areas? Or should more conservative standards apply in these
areas?
What is the current capability of smart pigs to find prior
mechanical damage and other defects?
What alternatives to internal inspection can provide
equivalent information on pipeline condition?
How recently should a line have been pigged to provide
reliable data for this step? What factors should be considered in
making this determination (e.g., recent construction activity, cathodic
protection system performance, interference from foreign line
crossings, etc.)?
What percentage of natural gas pipelines in Class 3 or
Class 4 areas have been smart pigged in the last 5-10 years?
What percentage of hazardous liquid pipelines intersecting
non-rural or environmentally vulnerable areas might be expected to have
been smart pigged in the last 5-10 years?
What is the expected cost to an operator to pig (or
equivalent) pipeline segments that would impact high consequence areas?
How soon should the condition of the a line be assessed
after determining that it could impact a high consequence area?
What criteria should be used to identify anomalies that
require further investigation?
What is the appropriate period between pig runs for high
consequence areas? (Should this period be based on pipeline-specific
conditions impacting the likelihood of corrosion or mechanical damage?)
Should OPS specify minimum performance criteria for
internal inspection tools? If so, what should those criteria be?
4. Assessing the Need for Preventive or Mitigative Actions
In this step, the operator would determine the most likely causes
of failure in the identified high consequence areas, and determine if
any additional preventive or mitigative actions, beyond those the
regulations require or the operator performs, are needed. In addition
to assessing the need for repairs to lower the likelihood of leaks or
ruptures due to corrosion or past mechanical damage (in Step 3), the
operator should also assess the need for additional preventive actions
to lower the likelihood of failure from all potential causes (e.g.,
third party damage, geological hazards, operation and control center
malfunctions, etc.) or additional mitigative actions to reduce the
consequences should the pipeline leak or rupture.
This assessment should be performed as part of an integrated,
segment-specific assessment of the possible causes of pipeline failure,
and cost-effective actions to reduce the specific risks identified on
these segments.
Although internal inspection and remediation of the lines can help
ensure the condition of the lines, inspection and remediation does not
address many important causes of pipeline failure. For example, OPS
data show that in 1998, 37 percent of reported gas pipeline incidents
were due to outside force damage. Similarly, on hazardous liquid
pipelines, outside forces caused 26 percent of reportable events.
Additional preventive measures may be needed to reduce the likelihood
of these reported incidents, or to reduce the expected level of
consequences should an incident occur. Accordingly, in addition to
internal inspection of pipeline segments in high consequence areas, OPS
is also interested in comment on the need for additional assessments
and analyses of other preventive and mitigative measures to reduce risk
in these areas.
For example, additional preventive measures might include the
development of enhanced damage prevention programs. Recently, OPS
sponsored a multi-industry effort to define best practices in damage
prevention. Although OPS is not considering translating these best
practices into regulations, it is interested in comments on how to
otherwise promote the adoption of damage prevention best practices to
reduce the likelihood of pipeline incidents. Additional mitigative
actions might include developing enhanced emergency response plans in
high consequence areas, or using emergency flow restricting devices or
remotely controlled valves to limit the amount of product loss
following a line failure.
Key questions that OPS would like to discuss at the meeting
include:
[[Page 56729]]
What structured assessment and decision processes could
operators use to perform this step?
What percentage of the natural gas industry already has
structured processes in place to perform such assessments?
What percentage of the hazardous liquid industry already
has structured processes in place to perform such assessments?
What should be the criteria for deciding whether
additional actions by the operator are required?
What would be the expected cost of performing such an
assessment?
5. Repairing the Affected Segments as Necessary
In this step, the operator would determine which anomalies require
remediation, and the appropriate means of repair. This step, in
conjunction with the previous step, is intended to ensure that the
likelihood of pipeline failure due to internal or external corrosion,
construction damage, previous excavation damage, or other mechanical
damage is very low.
Key questions that OPS would like to discuss at the meeting
include:
Should current industry standards (e.g., ASME B.31G) be
used as the repair criteria, or do other methodologies exist or need to
be developed for pipelines in high consequence areas?
What is the status of the current rulemaking to allow
alternative repair techniques?
After an operator identifies anomalies requiring repair,
how much time should be allowed in which to complete the repair work?
What would be the expected additional cost to the
operators of more stringent inspection and repair criteria?
6. Implementing and Monitoring Other Cost-Effective Risk Control
Activities
The operator would then be expected to implement the additional
preventive and mitigative actions, and monitor their effectiveness over
time to ensure that they are producing the risk reductions envisioned.
The operator would be expected to implement the activities in a timely
manner, consistent and integrated with internal budget processes that
establish priorities and allocate resources based on risk significance
of the planned activities.
Key questions that OPS would like to discuss at the meeting
include:
How can operators monitor the effectiveness of risk
control activities?
How would integrating an implementation schedule into
normal operator maintenance schedules or budget cycles affect the cost
of implementing these activities?
7. Documenting Inspections, Assessments, and Actions
An operator would maintain records establishing compliance with any
new requirements addressing high consequence areas, including records
identifying pipe segments capable of affecting high consequence areas,
the schedule of inspections, the findings of the inspections and
assessments, and the preventive and mitigative actions taken.
A key question that OPS would like to discuss at the meeting:
What would be the expected costs and labor burdens of
these documentation requirements?
8. OPS Reviews Operator Compliance
OPS will examine the operator's records to ensure compliance. OPS
currently envisions an on-site review of the company's program
documentation and records, as well as interviews with key management
personnel responsible for implementing the process. The specific review
activities will be tailored for the company's management system and
assessment processes. Major review activities are expected to include:
Reviewing the policies, procedures, guidelines, and
manuals that describe how the company identifies the pipeline segments
that could impact high consequence areas and assesses the need for
additional protection on these segments.
Reviewing the company's assessment and decision making
processes.
Reviewing in-line inspection data and the criteria to
determine if further evaluation and repair is required.
Reviewing the status of remediation and other preventive
or mitigation actions.
Reviewing performance measures to understand, evaluate,
and demonstrate the effectiveness of the company's decisions.
Meeting with company management to understand the level of
management support and awareness of the program to protect high
consequence areas.
After the review of the operator's internal processes and
documentation, OPS will conduct field validation checks. These
validation checks will confirm that the operator has implemented the
additional preventive and mitigative activities.
The selection of field inspection sites will consider the
operator's assessment and results. Where possible, the OPS team will
perform an integrated review of information from a variety of sources
(e.g., internal inspection results, close interval surveys, leak
history, and other observed conditions) in selecting field validation
check sites.
After the OPS inspection team has completed its review and field
validation checks, the team will prepare a summary report. This summary
report will contain observations on the operator's program and
processes, as well as on the effectiveness of this program in enhancing
protection for high consequence areas. The report will document the
positive features of the company's program and any areas that need
improvement. The report will include any process improvements that OPS
has determined are necessary, and the operator's work plan for
addressing them. If compliance issues are discovered during the review,
OPS will determine the appropriate resolution of these issues through
its normal enforcement processes, and the resolution of those issues
will be included in this report.
Key questions that OPS would like to discuss at the meeting
include:
How can OPS ensure consistency of review across all
companies?
What review protocols or criteria will OPS use to evaluate
the effectiveness of an operator's assessment and decision-making
processes?
What is the appropriate avenue for public input into the
decision-making process to protect high consequence areas?
What qualifications or training should OPS inspectors have
to perform this verification?
Information Requested
Consistent with the President's regulatory policy (E.O. 12866), OPS
wants to carry out the mandate to consider additional inspections, and
other preventive and mitigative measures at the least cost to society.
Toward this end, interested persons are urged to present views on
whether additional inspection requirements or other preventive and
mitigative actions are needed to ensure adequate protection of high
consequence areas. The questions listed above provide more specific
guidance on the information being solicited for each step in the
process. In addition, and applicable to all steps in the envisioned
process, OPS is also interested in comments on the expected cumulative
costs and benefits associated with implementing the described process,
any comment on whether any of these measures would have a
disproportionate impact on small operators, and any concerns on the
information collection, recordkeeping, or reporting requirements of any
of these initiatives under the Paperwork
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Reduction Act of 1995 (44 U.S.C. 3057(d)).
Authority: 49 U.S.C. Chapter 601 and 49 CFR 1.53.
Issued in Washington, DC on October 14, 1999.
Richard B. Felder,
Associate Administrator for Pipeline Safety.
BILLING CODE 4910-60-P
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[FR Doc. 99-27281 Filed 10-20-99; 8:45 am]
BILLING CODE 4910-60-C
