[Federal Register Volume 65, Number 79 (Monday, April 24, 2000)]
[Proposed Rules]
[Pages 21695-21710]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 00-9934]


=======================================================================
-----------------------------------------------------------------------

DEPARTMENT OF TRANSPORTATION

Research and Special Programs Administration

49 CFR Part 195

[Docket No. RSPA-99-6355; Notice 3]


Pipeline Safety: Pipeline Integrity Management in High 
Consequence Areas

AGENCY: Research and Special Programs Administration (RSPA), DOT.

ACTION: Notice of proposed rulemaking.

-----------------------------------------------------------------------

SUMMARY: This document proposes regulations to test, repair and 
validate through analysis the integrity of most hazardous liquid 
pipelines that could affect populated areas, commercially navigable 
waterways, and areas unusually sensitive to environmental damage. 
RSPA's Office of Pipeline Safety (OPS) proposes to define these areas 
as high consequence areas. In these proposed high consequence areas, 
OPS is proposing that an operator develop and follow an integrity 
management program that continually assesses and evaluates the 
integrity of those pipelines that could affect a high consequence area, 
through internal inspection or pressure testing, and data integration 
and analysis.
    Through this required program, OPS expects operators to 
comprehensively evaluate the entire range of threats to pipeline 
integrity by analyzing all available information about the pipeline and 
consequences of a failure. This would include information on the 
potential for damage due to excavation, data gathered through the 
required integrity assessment, results of other inspections and tests 
required by the pipeline safety regulations, including corrosion 
control monitoring and cathodic protection surveys, and information 
about how a failure could affect the high consequence area, such as 
location of water intakes.
    The proposed rule requires an operator to take prompt action to 
address the integrity issues raised by the assessment and analysis. 
This means an operator must evaluate and repair all defects that could 
reduce a pipeline's integrity according to specified risk criteria. The 
integrity of these pipelines would be further assured through other 
remedial actions, and preventive and mitigative measures.

DATES: Interested persons are invited to submit comments on this notice 
of proposed rulemaking (NPRM) by June 23, 2000. Late filed comments 
will be considered to the extent practicable.

ADDRESSES: You may 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. It is open from 10:00 
a.m. to 5:00 p.m., Monday through Friday, except federal holidays. 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.

FOR FURTHER INFORMATION CONTACT: Mike Israni, (202) 366-4571, or by e-
mail: <a href="/cdn-cgi/l/email-protection#680501030d46011b1a090601281a1b1809460c071c460f071e"><span class="__cf_email__" data-cfemail="24494d4f410a4d5756454a4d64565754450a404b500a434b52">[email protected]</span></a>, regarding the subject matter of this 
proposed rule, or the Dockets Facility (202) 366-9329, for copies of 
this proposed rule or other material in the docket. All materials in 
this docket may be accessed electronically at http://dms.dot.gov. 
General information about the RSPA/Office of Pipeline Safety programs 
may be obtained by accessing OPS's Internet home page at http://ops.dot.gov.

SUPPLEMENTARY INFORMATION:

Background

    This proposed rulemaking is the culmination of experience gained 
from inspections, accident investigations and risk management and 
system integrity initiatives. This experience has given us the 
foundation for proposing a rulemaking that addresses in a comprehensive 
manner NTSB recommendations, Congressional mandates and pipeline safety 
and environmental issues raised over the years.

Accident analyses

    Office of Pipeline Safety (OPS) and National Transportation Safety 
Board (NTSB) investigations and analyses of major pipeline incidents 
have emphasized the importance of ensuring safety and environmental 
protection in areas of population density and in areas unusually 
sensitive to environmental

[[Page 21696]]

damage. NTSB recommendations on this subject include:
    <bullet> NTSB recommended that OPS require periodic testing and 
inspection to identify corrosion and other time-dependent damages.
    <bullet> NTSB recommended that OPS establish criteria to determine 
appropriate intervals for inspections and tests, including safe service 
intervals between pressure testing.
    <bullet> NTSB recommended that OPS determine hazards to public 
safety from electric resistance welded (ERW) pipe and establish 
standards for leak detection.
    <bullet> NTSB recommended that OPS expedite requirements for 
installing automatic or remote-operated mainline valves on high-
pressure lines in urban and environmentally sensitive areas to provide 
for rapid shutdown of failed pipeline segments.
    Several incidents, including pipeline ruptures in Bellingham, 
Washington; Simpsonville, South Carolina; Reston, Virginia; and Edison, 
New Jersey have illustrated the importance of integrating and analyzing 
data from various sources to ensure a pipeline's integrity. Our 
analyses indicate that many accidents are caused by complex factors 
involving mechanical and control system failures, previous outside 
force damage, system design errors and operator error. These accidents 
indicate the need for operators to address the potential 
interrelationship among failure causes and to implement coordinated 
risk control actions to supplement the protection of the regulations.
    We are persuaded of the urgent need to propose regulations for an 
overall pipeline integrity management program that requires continual 
assessment and evaluation through internal inspection or pressure 
testing, data integration and analysis, and follow-up remedial, 
preventive and mitigative actions.

Statutory Requirements

    Congress has directed OPS to undertake a variety of activities 
concerning areas where the risk of a pipeline spill could have 
significant impact. Required actions include:
    <bullet> 49 U.S.C. 60109(a)(2)--OPS is to prescribe standards 
establishing criteria for identifying gas pipeline facilities located 
in high-density population areas and hazardous liquid pipelines that 
cross waters where a substantial likelihood of commercial navigation 
exists, located in a high-density population area, or in an area 
unusually sensitive to environmental damage (USAs).
    <bullet> 49 U.S.C. 60102(f)(2)--OPS is to prescribe additional 
standards requiring the periodic inspection of pipelines in USAs and 
high-density population areas. The regulations are to prescribe when an 
instrumented internal inspection device, or similarly effective 
inspection method, should be used to inspect the pipeline.
    <bullet> 49 U.S.C. 60102(j)--OPS is to survey and assess the 
effectiveness of emergency flow restricting devices (EFRDs) and other 
procedures, systems, and equipment used to detect and locate hazardous 
liquid pipeline ruptures, and to prescribe regulations on the 
circumstances where an operator of a hazardous liquid pipeline facility 
must use an EFRD or such other procedure, system, or equipment.

Risk Management Initiatives

    Although the pipeline safety regulations have a demonstrated record 
in addressing risks to the nation's pipelines, safety programs based 
only on compliance with the regulations may overlook the 
interrelationships among failure causes and the benefits of coordinated 
risk control activities.
    To study and evaluate if comprehensive and integrated approaches to 
safety and environmental protection could work, OPS created the Risk 
Management Demonstration Program and the Systems Integrity Inspection 
(SII) Pilot Program. 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, in conjunction with 
compliance with existing pipeline safety regulations. These programs, 
along with the Oil Spill Response Plan Review and Exercise Program, 
have helped OPS refine its regulatory oversight to ensure that pipeline 
operators have effective processes 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. 
OPS's interim assessment of the benefits of risk management processes, 
after four years of experience with the demonstration program, 
indicates the validity of focusing resources and establishing higher 
levels of protection in areas where a pipeline spill could have 
significant consequences.

Operator-Developed Integrity Management Programs

    In evaluating the operators who applied for the Risk Management and 
SII Programs, OPS found that liquid operators have made progress in 
developing and implementing formalized management systems to identify 
and address the most significant integrity threats to their pipeline 
systems. These programs are designed to supplement the protections that 
the pipeline safety regulations provide. OPS further found that liquid 
operators generally have more experience than natural gas operators 
with using internal inspection devices.
    In the Risk Management Demonstration Program, participants perform 
systematic and comprehensive risk assessments to identify the specific 
nature and location of the most significant risks posed by operation of 
their pipeline system. An essential feature of these risk assessments 
is the integration of information from many diverse sources to fully 
understand the integrity threats at specific locations on the pipeline. 
Environmental consequences and the impact on nearby population are 
explicitly considered in these risk assessments. Through formal, risk-
based decision making processes, these companies can use the risk 
assessment results to identify projects and activities that address 
potential system integrity threats, thereby preventing pipeline 
failures. The risk management process also examines the consequences of 
potential releases and explores opportunities to minimize the 
environmental and public safety and health impacts should a failure 
occur. Participants are using these risk-based programs to 
comprehensively investigate all potential sources of risk, and 
implement risk control activities to prevent these risks or mitigate 
their consequences. These programs supplement the public and 
environmental protections the pipeline safety regulations provide.
    The SII pilot program is focused on developing a more integrity-
based approach to OPS inspections. Instead of basing inspections on a 
checklist approach to compliance with the regulations, the program 
focuses the inspection process on how an operator controls the 
integrity of the pipeline. In this program, OPS is working with the 
operator to better understand the most significant integrity threats 
and assure that programs actually address these risks. Similar to the 
Risk Management Program, the SII program focuses on how operators 
evaluate their system and make sound integrity management decisions.
    Although OPS has consulted with a limited number of operators who 
have applied for these programs, OPS discussions with other pipeline 
companies during standard inspections, in industry forums and through 
working groups have indicated that integrated

[[Page 21697]]

risk-based programs are becoming more common, particularly within the 
hazardous liquid industry. OPS has found that many liquid companies are 
using diagnostic tools and developing more sophisticated and mature 
integrity management systems.
    The hazardous liquid pipeline companies in the Risk Management and 
SII programs use internal inspection in their integrity management 
programs because of its powerful diagnostic capability. Examples of how 
these programs use internal inspection include:
    <bullet> Comparing multiple internal inspection runs over the same 
line to determine corrosion growth rates;
    <bullet> Testing new inspection techniques to detect seam flaws and 
stress corrosion cracking;
    <bullet> Overlaying internal inspection log results with Geographic 
Information System data to correlate locations of metal loss with 
cathodic protection system performance, environmentally sensitive 
areas, and other geo-spatial data;
    <bullet> Integrating hydrostatic pressure testing with internal 
inspection where appropriate;
    <bullet> Using probabilistic techniques to optimize the frequency 
at which internal inspection and pressure testing is conducted;
    <bullet> Using probabilistic approaches to prioritize and define 
the extent of anomaly excavation and repair; and
    <bullet> Developing more sophisticated analytical tools to evaluate 
internal inspection results.

New High Impact Inspection Format (NHIF)

    OPS is also working to improve overall pipeline integrity through 
the inspection process. OPS is gaining value from the approach taken in 
the Risk Management and SII programs, particularly benefitting from 
evaluating pipelines on a ``systems'' basis. Therefore, last year, OPS 
implemented this approach through a new high impact inspection format, 
evaluating pipeline systems as a whole rather than in small segments. A 
system-wide approach is a more effective and, in most cases, more 
efficient means of evaluating pipeline integrity. As part of the 
``systems'' approach, we are evaluating how pipeline operators 
integrate information about their pipeline to determine the best means 
of addressing risk. We will build on this experience in developing 
detailed inspection guidelines to evaluate compliance with the 
requirements we are proposing in this rule.
    As noted previously, accident and investigation analyses have 
identified several critical pipeline safety issues that appear to 
either cause or significantly contribute to pipeline accidents. As part 
of our NHIF process, we are evaluating how pipeline companies are 
addressing these issues and are noting the best industry practices we 
observe. Effectively managing these critical issues often relates to 
integrating information about different problems and examining their 
relationship in contributing to the potential for a failure.

Public Meeting

    On November 18 & 19, 1999, OPS hosted a public meeting in Herndon, 
VA to gather information on current pipeline assessment methods and 
integrity management programs so that OPS could develop a regulatory 
process to require testing and other means of identifying and repairing 
defects and further evaluating pipeline integrity in areas where a 
pipeline release posed the greatest safety or environmental harm. 
Topics discussed included the key elements of an effective integrity 
management program, the extent to which operators now have integrity 
management programs, and how to validate the effectiveness of such 
programs.

The Breakout Sessions

    At the meeting, OPS held breakout sessions to specifically discuss 
some key issues about how to better protect high consequence areas 
through an integrity management process.
1. The Characteristics of High Consequence Areas
    In addition to areas already given greater protection in the 
regulations or covered by the proposed USA definition (discussed later 
in this document), attendees suggested OPS consider areas in proximity 
to large bodies of water used for transportation or recreation; 
industries that impact public health and welfare, such as water 
treatment facilities and power plants; and major corridors such as road 
ways, rail roads and power lines.
    Several pipeline companies described approaches they use in their 
risk assessments and integrity evaluations to identify locations where 
a pipeline failure might have significant human health and safety 
impacts. Some participants maintained that defining actual impact zones 
would be preferable to the classic population corridor used in the gas 
regulations. For liquid lines, it was suggested that a more useable 
definition of non-rural areas than currently exists in the regulations 
may be desirable to provide greater clarity. Some participants 
suggested that OPS let operators test a definition of high consequence 
areas for a trial period.
2. Key Elements of an Integrity Management Program
    There was a general belief that many of the components of effective 
integrity management are already in the regulations, the major 
exception being effective integration of information in support of 
decision making. Attendees also pointed out that the Risk Management 
Program Standard or API standard 1129 could be used to define the 
elements of an integrity management program. Participants said that a 
successful integrity management program must be embodied within an 
environment, safety, and health management system framework. Several 
companies described elements of their environment, safety, and health 
management systems and emphasized the importance of policy, leadership, 
and continuous improvement to program success. Public representatives 
identified the need for thoroughness in assessing risks and the 
importance of better data to monitor leak and failure history. Public 
communication and local safety and planning agencies' participation in 
identifying risks were also emphasized as key program elements.
3. The Elements OPS Should Review/Evaluate/Inspect
    Participants suggested that operators have a documented integrity 
management plan that has goals and performance measures so that 
regulators could review the plan, and evaluate performance against that 
plan. Some participants said that the review should be performance-
based. It was also suggested that OPS review the results of the 
operator's audit of its own program. Concerns were raised over how OPS 
would assure staff expertise to adequately conduct performance-based 
inspections, and how OPS would establish a uniform standard against 
which to measure company performance.
4. Types of Information a Company Should Integrate To Ensure Pipeline 
Integrity
    Attendees listed a variety of information, emphasizing location-
specific information from sources such as close interval surveys, 
patrols, in-line inspection data, top-side anomaly information, 
maintenance history, third party excavation activity, physical pipe 
inspections, incident and leak history.

[[Page 21698]]

5. Key Questions for OPS to Ask During an Inspection.
    Participants emphasized that OPS should focus on the key location-
specific issues an operator identifies, examine the process an operator 
uses to address these issues, and examine changes since the last 
inspection. Several attendees suggested using SII Program Protocols in 
crafting an approach to reviewing operator programs.

Other Pre-NPRM Meetings

    Due to the complexity of the issues, OPS requested participants 
submit additional information and comments by December 20, 1999. We 
then extended the comment period to January 17, 2000 (64 FR 71713) to 
allow adequate time for commenters to prepare and submit information. 
OPS also established an electronic public discussion forum to get ideas 
on requirements for an effective integrity management programs. We 
posted a draft conceptual model for a pipeline integrity management 
process on the OPS web-site. The comments and information we received 
from the public meeting and electronic forum helped us in drafting this 
proposed rule. We discuss these comments later in this document.
    OPS also hosted a number of smaller meetings and conference calls 
to make sure we considered the broadest range of comments and 
information in drafting this NPRM. Discussion items included the areas 
that should be considered high consequence areas, reasonable milestones 
for completing benchmark or baseline testing, developing industry 
standards to support a rule, how a rule should acknowledge differences 
between the gas and liquid pipeline industries as well as among 
individual operators, and how best to involve affected communities. 
These topics were discussed with Interstate Natural Gas Association of 
America (INGAA) representatives on January 12, American Petroleum 
Institute (API) representatives on January 13 and National Association 
of Pipeline Safety Representatives (NAPSR) on January 14, February 15, 
and March 3. Discussions with public interest representatives on 
January 19 and February 29 included the National League of Cities; Safe 
Bellingham; the City of Fredericksburg, Virginia; the Environmental 
Defense Fund; the City of Austin, Texas; the Pipeline Reform Coalition; 
and the national organization of Local Emergency Planning Committees 
(LEPC's). OPS met with the NTSB on February 8. Minutes from each of 
these sessions are in the Docket.
    These meetings again showed how hazardous liquid and gas pipeline 
operators' experience differed in developing and implementing a risk-
based integrity approach to pipeline safety.

Comments Received in the Docket

    For reasons discussed later in this document, at this time we are 
applying this proposed rule to certain hazardous liquid operators i.e., 
those hazardous liquid operators operating 500 or more miles of 
pipeline used in transportation. Therefore, we will discuss only those 
comments relevant to this action. Later this year, when we issue 
proposed system integrity rules that apply to those hazardous liquid 
operators not covered by this initial action and to all natural gas 
transmission pipeline operators, we will discuss the other comments.
    We received comments relevant to this action from the following 
sources:

Trade Associations:
    American Petroleum Institute
    American Society of Safety Engineers

Interstate Hazardous Liquid Pipeline Operators:

    BP Amoco Pipeline Company
    All American Pipeline, L.P.
    Tosco Corporation
    Enbridge (U.S.) Inc.
    Air Products and Chemicals, Inc.

    Engineering firm: Advanced Technology Corporation
    Engineering Consultant: Foy Milton, P.E.

State Regulators:

    New York State Department of Public Service
    State of Florida Department(s) of Community Affairs

    Federal Agency: U.S. Department of Interior, Fish and Wildlife 
Service
    Citizen Group: SAFE Bellingham
    We discuss the comments under the applicable heading below. 
Commenters generally supported the idea of providing further protection 
for critical areas. Operators and industry groups requested regulations 
that allow flexibility. SAFE Bellingham urged stronger federal 
regulation of pipelines, to include requirements for pressure testing, 
internal inspection, leak detection systems, safety management 
practices and audits, valve location and safety condition reporting.
    As discussed later in this document, this proposal specifically 
requires an integrity assessment done by internal inspection, pressure 
testing or an equivalent technology within specified time frames 
established by specified risk criteria. The proposed program must 
comprehensively evaluate all threats to pipeline safety in high 
consequence areas. Among the required elements of an integrity 
management program are a continuous process to assess and maintain 
pipeline integrity, an analysis that integrates all information about 
the pipeline, information on how a failure would affect a high 
consequence area, and measures to prevent and mitigate pipeline 
failures, such as installing emergency flow restricting devices (EFRDs) 
and establishing or modifying systems that monitor pressure and detect 
leaks.

Scope

    The New York State Department of Public Service commented that the 
integrity management program should apply to all transmission pipeline 
facilities, not just those in areas deemed high consequence. At our 
recent meeting, NTSB also recommended that pipeline integrity 
management requirements, including testing, be applied system-wide, not 
just in high consequence areas.
    Pipeline safety regulations apply to the entire pipeline to protect 
the public and the environment from a pipeline release. We have decided 
to focus this immediate initiative on pipelines in areas where 
additional protection is the most critical--the populated areas, 
unusually sensitive environmental areas, and commercially navigable 
waterways. We believe operators should take necessary steps to develop 
and maintain an effective integrity management program for their 
pipeline system-wide. However, based on available data, OPS is 
proposing additional measures, particularly pipeline testing and 
evaluation, for those areas where additional protection is clearly 
warranted at this time. We will continue to consider whether integrity-
related actions for the rest of the pipeline should be required.
    We also intend to look at additional protection for other 
environmentally sensitive and vital resources, such as designating 
additional areas of national importance, cultural resources, sensitive 
environmental resources that do not meet the USA filtering criteria, 
wetlands and water bodies, and other transportation networks.
    Nonetheless, many of the proposed measures for high consequence 
areas may benefit other parts of the pipeline system. For example, the 
proposed rule requires an operator to analyze and integrate various 
data about the integrity of the entire pipeline. This analysis is 
likely to benefit other segments of the pipeline system. The preventive 
and

[[Page 21699]]

mitigative measures that the rule proposes an operator take to protect 
the high consequence area might also yield benefits beyond the segment 
in the critical area. Many operators will choose to extend the internal 
inspection or testing beyond the pipeline segment in or near the high 
consequence areas.

Specification vs. Performance

    Foy Milton recommended against a subjective performance-based rule, 
asserting the advantages of specification-type standards (uniformity of 
application, ease of understanding). Other commenters stated that 
regulatory requirements that set performance standards for pipeline 
operators are the most effective.
    The proposed rule uses both performance and specification-based 
language. Specification-type standards do not provide for selection of 
the most effective processes and technologies as they become available. 
OPS needs to create incentives for operators to invest in the 
development of new technology. Because internal inspection technology 
and other integrity monitoring equipment have evolved considerably in 
recent years and are expected to continue to improve, we want to 
encourage operators to use and make recommendations on how to improve 
the best available technologies and processes, rather than specifying 
only currently available technologies. Thus, the performance-based 
parts of the rule provide for operators to develop customized programs 
that address pipeline-specific characteristics, are fully integrated 
into company safety and environmental protection programs, and use the 
best available technologies to inspect and repair pipelines.
    The specification parts of the rule ensure uniformity among 
integrity management programs so that they all, at minimum, address key 
issues, such as baseline and continual inspection or testing, data 
integration, and remedial, preventive and mitigative measures.

High Consequence Areas

    OPS received several comments on how to define high consequence 
areas. Commenters said that these areas should be limited to populated 
areas, unusually sensitive areas, and commercially navigable waterways. 
API recommended that these areas be defined as high population areas of 
greater than 100,000 people, based on U.S. Census data, other populated 
areas including non-rural areas, and unusually sensitive environmental 
areas. API argued that expansion beyond these areas would dilute 
industry resources and reduce the impact of any rule on public safety 
and environmental protection. API suggested that both subcategories of 
populated areas be similarly considered in conducting risk assessments, 
but might be treated differently for prevention activities.
    Air Products and Chemicals, Inc. expressed the opinion that high 
consequence areas can differ dramatically depending on the nature of 
the product in the pipeline. They offered the example that a sensitive 
estuary might be a high consequence environment for under water 
hazardous liquid pipelines, but would be a very low consequence 
environment for an under water hydrogen pipeline.
    Fish and Wildlife Service stated high consequence areas should 
include high population areas and areas designated as critical habitats 
for threatened and endangered species, areas of national significance, 
areas migratory birds concentrate, wetlands and riparian areas, areas 
of recreational significance, and areas of tribal subsistence, 
ceremonial use, or historic value. All American Pipeline stated it 
considers all areas along its pipeline as high consequence areas, but 
distinguishes areas that have a higher consequence than others based 
on: proximity to populated places and waterways, potential to impact 
USAs or drinking water resources, and policies and regulations of 
local, county government bodies, and local political climate. New York 
State Department of Public Service stated that creating a high 
consequence area definition would be difficult, and perhaps, 
unnecessary. Rather, a model properly developed and applied to the 
entire pipeline system would distinguish high consequence components 
that are given higher priority for repair or remedial action.
    Participants at the public meeting said the high consequence area 
definition should include both safety and environmental impacts. The 
hazardous liquid industry breakout groups agreed that the definition 
should include a population component and USAs.
    We are focusing this rulemaking on areas where we have determined a 
pipeline failure could pose the greatest threat to public safety, the 
environment, and water commerce. We are designating these areas ``high 
consequence areas''. Our proposed definition does not take the type of 
product into account in defining the high consequence area. However, an 
operator needs to consider product type when determining which risk 
factors apply in establishing schedules for pipeline integrity 
assessments and other forms of evaluation.
    High consequence areas will be identified on OPS's National 
Pipeline Mapping System and made available to the public on the 
Internet.

High Population Areas and Other Populated Areas

    OPS agreed with commenters that the population definitions should 
follow the U.S. Census Bureau's work. OPS is, therefore, proposing that 
the population portion of the high consequence area definition follow 
the Census Bureau's definitions and delineations of populated areas. 
The U.S. Census Bureau is the expert on, and the collector of, 
population data. It has used its collected data to create maps of 
populated areas in the United States that anyone may access.
    To protect the public from a potential pipeline failure, we are 
proposing a definition of high consequence area that encompasses two 
population tiers: high population areas and other populated areas. 
These are areas in the United States that have significant population 
densities.
    High population areas are areas of the United States with moderate 
to high population densities. The U.S. Census Bureau calls these places 
``Urbanized Areas'', and defines them as areas that contain 50,000 or 
more people and have a population density of at least 1,000 people per 
square mile.
    Other population areas are areas the U.S. Census Bureau identifies 
as ``Places'', and defines them as areas that contain a concentrated 
population, such as an incorporated or unincorporated city, town, 
village, or other designated residential or commercial area.
    Although an operator must assess and evaluate the integrity of 
pipelines that could affect either population area, an operator might 
give different inspection priorities to the areas.
    The U.S. Census Bureau has created digital data layers and maps of 
high population areas (Urbanized Areas) and other populated areas 
(Places). OPS has obtained these data layers and will make them 
available on our National Pipeline Mapping System home page http://www.npms.rspa.dot.gov. The National Pipeline Mapping System will allow 
an operator, member of the public, or other government agency to view 
and download this data and to view pipelines in relation to these 
populated areas.

Unusually Sensitive Areas (USAs)

    We are also including unusually sensitive environmental areas 
(USAs) in our proposed high consequence area definition. These will be 
the same drinking water and ecological resource

[[Page 21700]]

areas that we recently proposed as unusually sensitive to environmental 
damage if there is a hazardous liquid pipeline release (64 FR 73464; 
December 30, 1999). The Federal Register notice gives more details of 
the proposed definition (proposed section 195.6).
    The proposed USA definition was created through a series of public 
workshops and our collaboration with a wide range of federal, state, 
public, and industry stakeholders. The identification of USAs is based 
on a multi-step process that begins by designating and assessing 
environmentally sensitive areas (ESAs), determining which of these ESAs 
are potentially more susceptible to permanent or long term damage from 
a hazardous liquid release (areas of primary concern), and finally 
identifying filtering criteria to determine which areas of primary 
concern can be reached by a release and sustain permanent or long-term 
damage. The areas that result are the proposed USAs.
    OPS is conducting a pilot test to determine if the proposed 
definition can be used to identify and locate unusually sensitive 
drinking water and ecological resources using available data from 
government agencies and environmental organizations. Texas, California, 
and Louisiana were the states chosen for the test due to the large 
number of hazardous liquid pipelines and the considerable drinking 
water and ecological resources that exist in these states. OPS is using 
the results to evaluate whether the proposed definition identifies the 
majority of unusually sensitive areas and whether environmental data is 
accessible and appropriate to support the proposed definition. Once OPS 
finishes the test, receives technical review from federal and state 
water and ecological experts and gets public comment on the proposed 
definition, it will go forward with a final rule.
    In addition, OPS believes that other sensitive and vital resources 
may need to be considered in this regulation. OPS requests comments on 
whether this regulation should cover additional areas of national 
importance, cultural resources, sensitive environmental resources that 
do not meet the USA filtering criteria, including certain wetlands and 
water bodies, and other transportation networks. OPS currently protects 
some of these resources in accordance with requirements for spill 
response planning of the Oil Pollution Act of 1990.
    We will be working with the other Federal agencies to help define 
and identify any additional resources that should be considered in this 
or future regulations. OPS is holding a technical workshop April 27-28 
to gather technical comments.

Commercially Navigable Waterways

    OPS is including commercially navigable waterways in the proposed 
high consequence area definition. Because these waterways are critical 
to interstate and foreign commerce and supply vital resources to many 
American communities, are a major means of commercial transportation, 
and are a part of a national defense system, a pipeline release in 
these areas could have significant impacts.
    We are proposing to define commercially navigable waterways as 
those waterways ``where a substantial likelihood of commercial 
navigation exists.''
    Oak Ridge National Laboratory and Vanderbilt University have 
created a geographic database of navigable waterways in and around the 
United States. The database, called the National Waterways Network, was 
created with input from the National Waterway GIS Design Committee 
which is comprised of members from the U.S. Army Corps of Engineers, 
the U.S. DOT's Bureau of Transportation Statistics (BTS), the Volpe 
National Transportation Systems Center, the Maritime Administration, 
the Military Traffic Management Command, the Tennessee Valley 
Authority, the U.S. Environmental Protection Agency, the U.S. Bureau of 
Census, the U.S. Coast Guard, and the Federal Railroad Administration. 
The database includes commercially navigable waterways and non-
commercially navigable waterways. The database can be downloaded from 
the BTS website: http://www.bts.gov/gis/ntatlas/networks.html.
    OPS will place a map and database of the commercially navigable 
waterways portion of the National Waterways Network database on the 
National Pipeline Mapping System. Operators will be able to determine 
which areas of their pipeline intersect commercially navigable 
waterways, and the public and other government agencies will be able to 
view pipelines in relation to commercially navigable waterways.

Emergency Flow Restricting Devices (EFRDs)

    OPS has been concerned for some time with the issue of the optimum 
placement of emergency flow restricting devices (EFRDs) to limit 
commodity release after the location of the release has been 
identified. EFRD means a check valve or remotely controlled valve.
    A 1991 Departmental study titled ``Emergency Flow Restricting 
Devices Study'' (1991 EFRD Study) recommended that OPS seek public 
input on the placement of EFRDs in urban areas, at water crossings, at 
other critical areas affected by commodity release, and areas in close 
proximity to the public outside of urban areas. The 1991 Study 
concluded remote control and check valves are the only effective EFRDs. 
A copy of the 1991 EFRD Study is filed in Docket No. PS-133.
    In response to 49 U.S.C. 60102(j), OPS issued an advance notice of 
proposed rulemaking (ANPRM) (59 FR 2802, Jan. 19, 1994) asking 
questions concerning the performance of leak detection equipment and 
location of EFRDs. Those responding were generally against requiring 
EFRDs. Some endorsed the selective use of EFRDs in high risk areas 
based on an operator's particular pipeline system.
    Although the number of responses was small, there was sufficient 
information to give guidance in considering the circumstances under 
which hazardous liquid pipeline operators should have EFRDs. In 
addition, past accidents, such as the 1986 Mounds View, Minnesota 
accident involving two deaths and one injury where it took one hour and 
40 minutes to isolate the ruptured section, and the 1988 Maries County, 
Missouri accident where the installation of a check valve would have 
substantially reduced the 20,554 barrel (863,268 gallons) spill, 
demonstrated the need to propose regulations requiring the selective 
use of EFRDs.
    In October 1995, we held a public workshop to discuss the issues 
involved in developing regulations on EFRDs. Participants were 
generally against installing EFRDs except in very limited situations. 
Participants had concerns about the costs and effectiveness of these 
mitigative features.
    Because environmental sensitivity of the location is a factor when 
considering installing an EFRD, we have previously deferred proposing 
requirements until there was a USA definition. Since we now have a 
proposed USA definition, and because an EFRD can minimize a spill in a 
high consequence area, we have decided to include a proposal for EFRDs 
in this rulemaking. The rule proposes that a required element of an 
integrity management program is for an operator to take preventive and 
mitigative measures to protect a high consequence area. The operator 
must conduct a risk analysis to determine what additional protections 
are needed. Installing EFRDs is one of several

[[Page 21701]]

mitigative measures the operator could take to protect a high 
consequence area.
    We are inviting comments on any needed further guidance to 
operators on when EFRDs should be installed. We also invite comment on 
the criteria for evaluating the decision on whether to install an EFRD 
or to take other measures, and if in certain limited circumstances the 
use of EFRDs should be mandatory. OPS is particularly interested in how 
the operator has determined that the measures would minimize the amount 
of product that could be released, how the measures would mitigate 
permanent damage to the environment, and how public safety has been 
protected.

Integrity Assessment Tools

    Experts in the use of internal inspection and pressure testing, API 
and technology vendors have provided information on the current state 
of technology for in-line inspection tools and pressure testing. This 
information will help operators determine the integrity assessment 
methods that will be most effective for their systems.

1. Current Capabilities of Internal Inspection Devices

    Internal inspection is one of the most useful tools in an integrity 
management program. Operators should select tools based on their 
particular requirements. At least two types of tools should be used: 
(1) Geometry pigs for detecting changes in circumference and (2) 
magnetic flux leakage pigs for determining wall anomalies, or wall loss 
due to corrosion. Both high resolution and low resolution tools have 
their place in pipeline integrity assessment.
Corrosion/Metal Loss
    With respect to corrosion, high-resolution tools can identify 
anomalies and, with the use of engineering critical assessments, use a 
conservative evaluation of the potential for the anomaly to have 
affected remaining pipe strength (or affected the pressure capacity of 
the pipeline segment). This assessment uses analytical techniques that 
consider a conservative approximation of the anomaly which estimates 
average depth of metal loss. Based on the evaluation of in-line 
inspection results, a prioritized listing of potential defects is 
developed to guide the initiation of the field digging, inspection, 
confirmation and the necessary repair program. Once in the field, 
additional calculations based on actual profile of metal loss are used 
to confirm the need and type of appropriate repair. It is the 
combination of the technological capabilities of the inspection tool, 
the expertise in performing engineering critical assessments and the 
field confirmation program that assure corrosion anomalies that pose a 
threat to the pipeline's integrity have been identified, assessed and 
addressed.
High Resolution Versus Low Resolution
    High-resolution tools can distinguish between internal and external 
corrosion and provide more extensive information to more accurately 
assess the potential for an anomaly to pose a risk. Due to the 
significantly higher costs of high-resolution tools, however, they are 
used for only those pipeline segments that, based on their unique mix 
of risk factors, justify the additional cost and analysis. For 
instance, on an older line with a higher probability of corrosion or a 
line with limited access for excavations, the operating company may 
find an advantage to spending more money on data collection and 
analysis to reduce the number of repairs required or to safely delay 
repairs until access to the site is possible (i.e. acquisition of 
permits or during winter when marshy areas are frozen). Conversely, on 
a line segment that has a lower expected risk, the low resolution tool 
may produce an appropriate field engineering assessment.
Mechanical Damage
    In-line inspection tools to measure dents or geometric deformations 
are common and are typically run routinely following installation of 
new pipelines. Technology has advanced such that geometry tools can 
normally withstand even the most extreme pipeline conditions. The tool 
is able to pass restrictions (e.g. deformations) of up to 25%, and with 
the high sensitivity of gauging systems now on the market and large 
number of sensing fingers, current tools can detect even very small 
ovalities (0.6%). OPS is concerned about improving the technology 
capability to detect gouges in dents. Following an inspection run, a 
preliminary study of recorded data is performed in the field, enabling 
operators to react quickly to the inspection results and investigate 
anomalies of concern.
Crack Detection
    Since the early 1990's, pipeline operators have successfully field 
tested internal inspection tools capable of non-destructively 
identifying fatigue cracks and stress corrosion cracking in the 
longitudinal seam. Research and development continues on these tools to 
strive for reliable identification of other types of seam defects, such 
as hook cracks. With the use of ultrasonic and MFL (transverse 
orientation) technology, pipeline segments that have experienced 
fatigue cracking can now be inspected. Cracks with a potential to 
rupture can be identified and repaired prior to growing to a critical 
stage. This is particularly important as this type of defect could 
survive initial and subsequent pressure tests but then with pressure 
cycling, grow over time to a critical stage and leak or rupture.

2. Pressure Testing

    The purpose of a pressure test is to remove defects that might 
impair the integrity of the pipeline during operation. Defects might 
exist as a result of the manufacturing process or damage to the pipe 
during shipping or even construction. The defects are identified by 
failure of the pipe during the test; the defective pipe is removed; new 
pipe is installed; and the pipe is tested again until no failure 
occurs. The pressure test provides a margin of safety for the pipeline 
by being conducted at a pressure higher than the maximum pressure at 
which pipeline safety regulations allow the pipeline to be operated. An 
operator must test to a minimum of 1.25 times maximum operating 
pressure because research has shown that at that level of pressure all 
critical defects can be identified and eliminated.
    An operator using hydrostatic pressure testing as its integrity 
assessment tool will also need to confirm the quality and effectiveness 
of its corrosion protection program for the affected segments of the 
pipeline. We expect that additional guidance on pressure testing as an 
integrity assessment method will be provided in the forthcoming 
industry consensus standard on pipeline integrity discussed later in 
this document.

3. New Technologies

    Although the proposed rule considers internal inspection, and in 
some instances, pressure testing, as the preferred integrity assessment 
tools, use of new technologies will also be allowed. OPS wants to 
encourage operators to use innovative evaluation methods and new 
technologies for their pipeline integrity management program. Thus, the 
proposed rule allows an operator to use new technology as its 
assessment tool if the operator demonstrates that this new technology 
can provide an equivalent level of protection in assessing the 
integrity of the pipeline, i.e. detecting wall loss, changes in pipe 
circumference and other defects.

[[Page 21702]]

Communications

    Although communications with the public is an important part of a 
pipeline integrity management program, the proposed rule does not 
address communications requirements. OPS has determined that the 
significance of this issue warrants further discussions with all the 
stakeholders before it proposes to require a communications plan as 
part of an integrity management program. Industry and public interest 
group representatives, such as the National League of Cities, the 
Environmental Defense Fund, and the National Organization of Local 
Emergency Planning Committees, are working to develop some models on 
communications and public education that can be pilot tested to 
determine what kind of information is most beneficial to local 
officials in preventing and responding to pipeline spills.
    OPS is considering proposing requirements for how operators are to 
communicate with local officials about results of risk assessment 
processes and measures to prevent and mitigate damage to pipelines in 
case of a failure. We are also considering requirements on how 
operators should provide the public access to this information. OPS 
invites comments on how local officials could use and benefit from risk 
assessment information, how the consequences of potential pipeline 
failures should be characterized, how risk control actions should be 
described and what performance indicators would be meaningful.

API Standard on Pipeline Integrity

    Commenters also urged the development of an industry standard, and 
OPS basing the rule on such a standard. API recently recommended a 
consensus standard be developed for pipeline system integrity in high 
consequence areas under American National Standards Institute (ANSI) 
consensus procedures. API has established a working group of technical 
experts to coordinate with OPS for the development of an ANSI pipeline 
integrity program standard. The new standard would define the 
requirements of a pipe integrity program that can affect high 
consequence areas.
    The working group intends for this standard to:
    <bullet> Establish the basic elements of a company pipe integrity 
program;
    <bullet> Establish integrity requirements that are pipeline segment 
specific and system-wide specific;
    <bullet> Establish a standard for system- or segment-specific 
historical information, such as leak history, close interval surveys, 
one-call system, previous pressure testing and in-line inspections, 
including integrating such information as part of risk-control 
decisions;
    <bullet> Establish a standard for pipe integrity assurance 
activities;
    <bullet> Establish standards for the engineering assessment of 
information, for example, evaluating remaining wall thickness using 
repair criteria;
    <bullet> Define the documentation process and provide a process for 
auditing company integrity programs.
    While technical experts are working on the standard, minutes of the 
meetings will be posted on the OPS Website so that the public can make 
comments to OPS as the process is ongoing. When this API standard is 
finalized, OPS will then consider adopting it, providing a public 
notice and comment period prior to incorporating it into a final 
regulation on pipeline system integrity.
    As will be explained in the next section, the proposed rule gives 
an operator an option to develop its own criteria in establishing 
integrity assessment (inspection or testing) schedules and intervals, 
and in establishing evaluation intervals. We expect that an industry 
consensus standard, once developed, will give operators guidance on 
this option.

The Proposed Rule

    OPS has decided to implement integrity management requirements for 
hazardous liquid and natural gas transmission operators in several 
steps. Natural gas and liquid have different physical properties, pose 
different risks and the configuration of the systems differ. OPS must 
examine how best to structure effective system integrity requirements 
for each part of the pipeline transportation system.

Which Operators Are Covered?

    In this first rulemaking, OPS is proposing to apply the system 
integrity program requirements to liquid operators operating 500 or 
more miles of pipeline used in hazardous liquid transportation. This 
proposed rule applies to all pipelines, regardless of date of 
construction. This initial action will cover approximately 87 percent 
of all the hazardous liquid pipelines in the United States. Based on 
the volume which these operators transport, they have the greatest 
potential to adversely affect the environment. While these hazardous 
liquid operators have been developing and using integrity management 
programs to manage risks on their systems, and have extensive 
experience with use of internal inspection devices, this proposed rule 
will provide direction on how they must protect critical areas. 
Further, it will assure that these protections will be put in place, 
with an operator being required to test 50 percent of the pipeline 
mileage in the most critical areas within three and a half years and 
the balance of the mileage within seven years. As proposed, an operator 
will then have to repair defects and implement preventive and 
mitigative measures.
    In the next rulemaking in this integrity series, we plan, later 
this year, to propose system integrity program requirements for the 
remaining hazardous liquid operators. Proposed system integrity 
requirements for natural gas transmission operators will then follow.
    OPS is proposing to add new sections on High Consequence Areas and 
Pipeline Integrity Management to subpart F. The proposed new section 
195.450 titled ``Definitions'' defines high consequence areas 
(described earlier in this document) and emergency flow restricting 
devices.
    The proposed new section 195.452 titled ``Pipeline integrity 
Management in High Consequence Areas'' would apply to each operator 
with 500 or more pipeline miles used in hazardous liquid 
transportation. This rule proposes requirements to test, repair and 
validate through analysis the integrity of hazardous liquid pipelines 
in high consequence areas, i.e., populated areas, areas unusually 
sensitive to environmental damage and commercially navigable waterways.

What Must an Operator Do?

    The rule proposes that, no later than one year after the effective 
date of the final rule, an operator would have to have a written 
integrity management program. The program would include a plan for 
baseline assessment (internal inspection, or pressure testing, or 
equivalent alternative technology) of all pipelines that could affect a 
high consequence area, and a framework addressing required program 
elements, including continual integrity assessment and evaluation. In 
the first year after the effective date of a final rule, we would 
expect the framework to indicate how decisions will be made to 
implement each required element. We recognize that an integrity 
management program is a dynamic program that an operator will modify 
and improve, based on evaluation of the program's effectiveness in 
reducing risk and protecting high consequence areas.

[[Page 21703]]

What Must Be in the Baseline Assessment Plan?

    The proposed baseline assessment plan must include the methods 
selected to assess the integrity of the pipeline. OPS expects an 
operator to make the best use of current and innovative technology in 
assessing the integrity of pipelines. Methods could include internal 
inspection, pressure testing or equivalent alternative technology. An 
internal inspection tool would have to be capable of detecting 
corrosion and deformation anomalies including dents, gouges and 
grooves. If pressure testing is used, an operator would also have to 
confirm the quality and effectiveness of its corrosion protection 
program and test to a minimum of 1.25 times the maximum operating 
pressure. To encourage innovation, the proposed rule also allows an 
operator to use new technology for the baseline assessment, if the 
operator demonstrates that this new technology can provide an 
equivalent level of protection in assessing the integrity of the 
pipeline.
    The proposed baseline assessment would also include a schedule for 
completing the integrity assessment of all pipelines that could affect 
a high consequence area and an explanation of the assessment methods 
the operator selected and an evaluation of risk factors the operator 
considered in establishing the assessment schedule for the pipelines.

When Must the Baseline Assessment Be Completed?

    The proposed rule requires an operator to initially assess all 
pipelines that could affect a high consequence area by seven (7) years 
from the effective date of the final rule. The proposed rule further 
requires that at least 50 percent of that mileage must be assessed by 
three and one half years from the effective date of the final rule. As 
explained in the previous section, the integrity assessment would be by 
internal inspection, pressure test or alternative equivalent 
technology. We request comments on whether seven years is an adequately 
protective minimum period to complete the baseline assessment of all 
pipelines in high consequence areas and whether three and a half years 
is an adequately protective minimum period to complete 50 percent of 
the assessments.
    The proposed rule allows an operator to use an integrity assessment 
method conducted five years before the effective date of the final rule 
as the baseline assessment if the method is at least equivalent to the 
requirements for internal inspection, pressure testing or alternative 
technology. An operator would have to maintain for review during 
inspection the results of the baseline assessment, including 
assessments conducted five years before the rule's effective date.

What Are the Criteria for Establishing an Assessment Schedule?

    For both the baseline and continual assessments, the proposed rule 
requires that an operator select one of two options. In option 1, the 
proposed rule requires that an operator base the integrity assessment 
schedule on certain risk factors. These risk factors include, but are 
not limited to, pipe material, pipe manufacturing information, local 
environmental factors that could impact the pipeline (e.g., corrosivity 
of soil, subsidence, climatic), existing or projected activities in the 
area, coating type, product transported, repair history, all previous 
data/results from pressure testing or internal inspection, geo-
technical hazards, corrosion history and pipeline leak history. OPS has 
also proposed guidance (in an Appendix C) on assigning priorities to 
these risk factors.
    In option 2, the proposed rule permits an operator to base the 
integrity assessment schedule on risk factors the operator considers 
essential in risk or consequence evaluation, provided that the operator 
demonstrates that the factors provide an equivalent level of safety and 
environmental protection to option 1.
    This option gives an operator the choice to use risk factors that 
are most closely suited to the operator's pipeline. We expect that once 
an industry consensus standard is developed, the standard can provide 
further guidance for this option.

What Are the Elements of an Integrity Management Program?

    The proposed rule gives the minimum elements that an operator must 
include in its integrity management program. Elements include: (1) A 
baseline assessment plan meeting the requirements previously described; 
(2) a continual process of assessment and evaluation to maintain a 
pipeline's integrity; (3) an analysis that integrates all available 
information about the integrity of the pipeline or the consequences of 
a failure; (4) criteria for repair actions to address integrity issues 
raised by the assessment method and data analysis; (5) identification 
of preventive and mitigative measures to protect the high consequence 
area; (6) methods to measure the program's effectiveness; and (7) a 
process for review of integrity assessment results and data analysis by 
a person qualified to evaluate the results and data. Each of these 
elements is described in the proposed rule.
    An integrity management program must be an evolving program that an 
operator continually improves as the operator gains experience from 
evaluating the effectiveness of the program in reducing risk and 
protecting high consequence areas. OPS expects that the initial program 
will consist of a framework that specifies the criteria for making 
decisions to implement each of the required elements. The program will 
change once actual decisions are made and actions implemented.

What Remedial Action Must Be Taken?

    The proposed rule requires an operator to take prompt action to 
address all pipeline integrity issues raised by the assessment method 
and data integration analysis. An operator must evaluate, and repair 
all defects that could reduce a pipeline's integrity. In establishing 
an evaluation and repair schedule, the rule proposes that an operator 
follow 49 CFR 195.401(b), which requires that if a condition on the 
pipeline is of such a nature that it presents an immediate hazard, the 
operator may not operate the affected part of the system until it has 
corrected the unsafe condition. For all other conditions, the rule 
proposes that an operator base the schedule for evaluation and repair 
on the risk factors used for establishing an assessment schedule and on 
specified criteria if the operator uses an internal inspection tool. An 
operator would have to maintain for review during inspection documents 
on remedial actions planned or taken. We invite comments on whether the 
rule should contain specific time lines for conducting repairs.

Integration of Data

    The proposed rule requires an operator to periodically evaluate the 
integrity of the pipeline that could affect a high consequence area by 
analyzing all available information about the integrity of the pipeline 
or the consequences of a failure. This information includes: (1) 
Information critical to determining the potential for, and preventing, 
damage due to excavation, including current and planned damage 
prevention activities, and development or planned development along the 
pipeline; (2) data gathered through the required integrity assessment; 
(3) information about how a failure would affect the high consequence 
area, such as location of water intake valves; (4) data gathered in 
conjunction with other inspections and

[[Page 21704]]

tests required in Part 195, including, corrosion control monitoring and 
cathodic protection surveys.
    Through this requirement, OPS expects operators to analyze the 
entire range of threats to pipeline integrity in high consequence 
areas, by integrating information from diverse sources. This analysis 
will be done in conjunction with the periodic evaluation discussed 
below.

Preventive and Mitigative Measures To Protect the High Consequence Area

    The proposed rule requires an operator to take measures to prevent 
and mitigate the consequences of a pipeline failure that could affect a 
high consequence area. These measures include conducting a risk 
analysis of the pipeline to determine if public safety or environmental 
protection would be enhanced by additional risk control actions. 
Required risk actions OPS proposes an operator consider include 
implementing damage prevention best practices, having better monitoring 
of cathodic protection where corrosion is a concern, establishing 
shorter inspection intervals, repairing defects other than those 
required by this proposed rule, installing EFRDs on the pipeline, 
establishing or modifying the systems that monitor pressure and detect 
leaks, providing additional training to personnel on response 
procedures, conducting drills with local emergency responders and 
adopting other management controls. The proposal would further require 
an operator to identify and implement other needed site-specific 
measures. As proposed, an operator would have to maintain for review 
during inspection records on any actions planned or implemented.

What Is a Continual Evaluation of a Pipeline's Integrity?

    The proposed rule requires that an operator must not only complete 
the baseline integrity assessment, but must continue to assess (by 
pressure testing, internal inspection, or new technology that provides 
an equivalent level of protection in assessing integrity) and evaluate 
the integrity of each pipeline that could affect a high consequence 
area. The integrity assessment must be done at specified intervals, as 
determined by one of two options.
    The evaluation must be done as frequently as needed to assure 
pipeline integrity by a person qualified to evaluate the results and 
other related data. The evaluation will consider the past and present 
integrity assessment results, data integration analysis, and decisions 
about repair, preventive and mitigative actions. In this evaluation, we 
propose to require an operator to consider information, such as:
    <bullet> Pipeline design features;
    <bullet> Construction practices and information;
    <bullet> Operating and accident history;
    <bullet> Maintenance and surveillance records, including cathodic 
protection records;
    <bullet> Previous inspection and testing results;
    <bullet> Damage prevention and other prevention program 
effectiveness;
    <bullet> Mitigation feature effectiveness.
    In establishing the integrity assessment intervals, an operator 
must choose one of two options. In option one, the rule proposes that 
an operator establish intervals not to exceed ten (10) years for 
assessing the pipeline's integrity. We invite comment on whether ten 
years is an adequately protective minimum period for integrity 
assessments.
    To establish the intervals, an operator would have to consider the 
risk factors previously listed for establishing an assessment schedule, 
the analysis of the results from the last integrity assessment, and the 
data integration analysis. An operator would also have to consider 
several factors concerning internal inspection results if that was the 
previous assessment method. We provide further guidance on analyzing 
internal inspection results in proposed Appendix C. We invite comment 
on whether we should specify what the evaluation interval should be.
    In option 2, the proposed rule allows an operator to establish 
intervals to assess the pipeline's integrity based on criteria the 
operator demonstrates provide an equivalent level of safety and 
environmental protection to option 1. This option gives an operator the 
choice of using innovative evaluation methods. We expect that an 
industry consensus standard would provide guidance for this option, 
should an operator choose not to develop its own criteria. We invite 
comment on other necessary guidance for this option. We also request 
comments on whether the standards in the proposed rule are clear and if 
there are ways we can make the standards more clear.

Methods To Measure the Program's Effectiveness

    Another required element of the proposed rule is that the integrity 
management program include methods to measure whether the program is 
effective in assessing and evaluating the integrity of the pipelines 
and in protecting the high consequence areas. Again, the proposal is 
performance-based to encourage the operator to choose the most 
effective risk control measures. Measures could focus on the operator's 
performance system-wide (the integrity of the pipeline in the high 
consequence area versus other pipelines in the system) or industry-wide 
(integrity management of the operator's pipelines in high consequence 
areas compared to high consequence areas across industry).

What Records Must Be Kept?

    The proposed rule requires that an operator maintain for inspection 
its written integrity management program. This proposed requirement is 
not any different from the procedural manual an operator is required to 
maintain for operations, maintenance and emergencies. An operator would 
also be required to maintain for review during inspections documents 
that support the decisions and analyses made and actions taken to 
implement each element of the integrity management program. These 
documents would include, at minimum, results of the baseline and 
periodic assessments, results of analyses and evaluations, records of 
defects detected and repairs made to those defects, records of other 
remedial actions planned or taken, and records of preventive and 
mitigative actions planned or taken.

Appendix C

    In this proposed rule, we are also adding a new Appendix C to Part 
195. This Appendix provides guidance on how to prioritize risk factors 
in determining assessment frequency, how to analyze smart pig 
inspection results, how to prioritize metal loss features, and what 
types of smart pigs to use to find pipeline anomalies. In addition, 
this Appendix includes risk indicator tables for leak history, volume 
or line size, age of the pipeline, and product transported, to help 
determine if the pipeline segment should fall into a high, medium or 
low risk category.
    By using the risk factors prioritization and risk indicator tables, 
an operator should be able to establish the priority for assessing (by 
internal inspection, pressure testing, or new technology) the integrity 
of pipeline segments. An operator can apply weights or values to the 
risk factors and then with the help of the risk tables and other 
analyses, determine which segments need immediate attention.

Regulatory Analyses and Notices

Executive Order 12866 and DOT Regulatory Policies and Procedures

    The Department of Transportation (DOT) does not consider this 
action to

[[Page 21705]]

be a significant regulatory action under section 3(f) of Executive 
Order 12866 (58 FR 51735; October 4,1993). Therefore, it was not 
forwarded to the Office of Management and Budget. This proposed rule is 
not significant under DOT's regulatory policies and procedures (44 FR 
11034: February 26, 1979).
    A regulatory evaluation of this proposal was prepared and placed in 
the docket of this action. This section summarizes the findings of that 
evaluation.
    Numerous investigations by the Office of Pipeline Safety (OPS) and 
the National Transportation Safety Board (NTSB) have highlighted the 
importance of protecting the public and environmentally sensitive areas 
from pipeline failures. NTSB has made several recommendations to ensure 
the integrity of pipelines near populated and environmentally sensitive 
areas. These recommendations included requiring periodic testing and 
inspection to identify corrosion and other damage, establishing 
criteria to determine appropriate intervals for inspections and tests, 
determining hazards to public safety from electric resistance welded 
pipe and requiring installation of automatic or remote-operated 
mainline valves on high-pressure lines to provide for rapid shutdown of 
failed pipelines.
    Congress also directed OPS to undertake additional safety measures 
in areas that are densely populated or unusually sensitive to 
environmental damage. These statutory requirements included having OPS 
prescribe standards for identifying pipelines in high density 
population areas, unusually sensitive environmental areas, and 
commercially navigable waters; issue standards requiring periodic 
inspections using internal inspection devices on pipelines in densely-
populated and environmentally sensitive areas; and survey and assess 
the effectiveness of emergency flow restricting devices, and prescribe 
regulations on circumstances where an operator must use the devices.
    This proposed rulemaking is a comprehensive response to NTSB's 
recommendations, Congressional mandates, as well as pipeline safety and 
environmental issues raised over the years.
    This proposal focuses on a systematic approach to integrity 
management to reduce the potential for hazardous liquid pipeline 
failures in populated and environmentally sensitive areas, and 
commercially navigable waterways. This proposed rulemaking requires 
pipeline operators to develop and follow an integrity management 
program that continually assesses and evaluates, through internal 
inspection or pressure testing and data integration, the integrity of 
those pipelines that could affect what we propose to designate as high 
consequence areas i.e., populated areas, areas unusually sensitive to 
environmental damage and commercially navigable waterways. The 
integrity of the pipelines would be further assured through remedial 
actions and preventive and mitigative measures.
    This initial proposed rule covers hazardous liquid pipeline 
operators operating 500 or more miles of pipeline used in 
transportation. Later this year, OPS intends to propose integrity 
management program requirements for the liquid operators not covered by 
this proposed rule and for natural gas transmission operators. OPS 
chose to start with this group of hazardous liquid operators because 
they had the greatest potential to adversely affect the environment, 
based on the volume of product they transport. Further, by focusing 
first on these liquid operators, OPS is addressing requirements for an 
estimated 86.7 percent of hazardous liquid pipelines. It is estimated 
that 29.3 thousand miles (of the 157,000 miles of hazardous liquid 
pipeline in the U.S.) will be impacted by this proposed rule.
    In discussions between OPS officials and several hazardous liquid 
pipeline operators, the operators agreed that pipeline operators 
subject to this proposal were developing integrity management programs 
and would likely have performed initial integrity testing voluntarily 
over the same period given in this proposal. The cost of developing the 
necessary program is estimated to cost the pipeline industry 
approximately $1.5 million with an additional annual cost of $66,000. 
(The program begins with a baseline assessment plan and a framework 
that addresses each required program element. The framework initially 
indicates how decisions will be made to implement each element. As 
decisions are made and operators evaluate the effectiveness of the 
program in protecting high consequence areas, the program will be 
continually updated and improved.)
    The proposal requires a baseline assessment of applicable pipelines 
through internal inspection, pressure test, or use of new technology 
capable of comparable performance. The baseline assessment must be 
completed within seven years after a final rule becomes effective. 
After this baseline assessment, an operator is further required to 
periodically retest and evaluate the pipeline to ensure its integrity. 
It is estimated that the cost of periodic retesting will generally not 
occur until the sixth year unless the baseline test indicates 
significant defects that would require earlier retesting.
    One of the many preventive or mitigative actions an operator may 
take is to install EFRD's. OPS could not estimate the total cost of 
installing EFRD's because OPS does not know how many operators will 
install them. OPS requests information from the public on how many 
operators are likely to install EFRD's and their potential benefit. OPS 
also requests information on the cost of other preventive and 
mitigative measures operators are likely to take. Periodic integrity 
assessment (internal inspection, hydrostatic testing, or an equivalent 
method, required at a maximum of 10 years after baseline assessment) is 
estimated to cost the industry $7.9 million in years 6-7 after 
implementation of a final rule and then $3.4 million thereafter.
    The benefits to this proposal can not easily be quantified but can 
be described in qualitative terms. Issuance of this proposed rule 
ensures that all operators will perform at least to a baseline safety 
level and will contribute to an overall higher level of safety and 
environmental performance nationwide. It will lead to greater 
uniformity in how risk is evaluated and addressed and will provide more 
clarity in discussion by government, industry and the public about 
safety and environmental concerns and how they can be resolved.
    Much of the proposed rule is written in performance-based language. 
A performance-based approach provides several advantages: Encouraging 
development and use of new technologies; supporting operators' 
development of more formal, structured risk evaluation programs and 
OPS's evaluation of the programs; and providing greater ability for 
operators to customize their long-term maintenance programs.
    The proposal has also stimulated the pipeline industry to begin 
developing a supplemental consensus standard to support risk-based 
approaches to integrity management. The proposal has further fostered 
development of industry-wide technical standards, such as repair 
criteria to use following an internal inspection.
    Our emphasis on an integrity-based approach encourages a balanced 
program, addressing the range of prevention and mitigation needs and 
avoiding reliance on any single tool or overemphasis on any single 
cause of failure. This orientation will lead to

[[Page 21706]]

addressing the most significant risks in populated areas, unusually 
sensitive environmental areas, and commercially navigable waterways. 
Commercially navigable waterways are included because of their 
importance as a supply route of vital resources to many American 
communities as well as their role in the national defense system. This 
integrity-based approach is the best opportunity to improve industry 
performance and assure that these high consequence areas get the 
protection they need. It also addresses the interrelationships among 
failure causes and benefits the coordination of risk control actions, 
beyond what a solely compliance-based approach would achieve.
    The proposed rule provides for a validation process, which gives 
the regulator a better opportunity to influence the methods of 
assessment and the interpretation of results. OPS will provide a 
beneficial challenge to the adequacy of an operator's decision process. 
Requiring operators to use the integrity management process, and having 
regulators validate the adequacy and implementation of this process, 
should expedite the operators' rates of remedial action, thereby 
strengthening the pipeline system and reducing the public's exposure to 
risk.
    A particularly significant benefit is the quality of information 
that will be gathered as a result of this proposal to aid operators' 
decisions about providing additional protections. Two essential 
elements of the proposed integrity management program are that an 
operator continually assess and evaluate the pipeline's integrity, and 
perform an analysis that integrates all available information about the 
pipeline's integrity. The process of planning, assessment and 
evaluation will provide operators with better data on which to judge a 
pipeline's condition and the location of potential problems that must 
be addressed.
    Integrating this data with the environmental and safety concerns 
associated with high consequence areas will help prompt operators and 
the Federal and state governments to focus time and resources on 
potential risks and consequences that require greater scrutiny and the 
need for more intensive preventive and mitigation measures. If baseline 
and periodic assessment data is not evaluated in the proper context, it 
is of little or no value. It is imperative that the information an 
operator gathers is assessed in a systematic way as part of the 
operator's ongoing examination of all threats to the pipeline 
integrity. The proposed rule is intended to accomplish that.
    The public has expressed concern about the danger hazardous liquid 
pipelines pose to their neighborhoods. The proposed integrity 
management process leads to greater accountability to the public for 
both the operator and the regulator. This accountability is enhanced 
through our choice of a map-based approach to defining the areas most 
in need of additional protection--the visual depiction of the populated 
areas, unusually sensitive environmental areas, and commercially 
navigable waterways in need of protection focuses on the safety and 
environmental issues in a manner that will be easily understandable to 
everyone. The proposed system integrity requirements and the sharing of 
information about their implementation and effectiveness will assure 
the public that operators are continually inspecting and evaluating the 
threats to pipelines that pass through or close to populated areas to 
better ensure that the pipelines are safe.
    OPS has not provided quantitative benefits for the continual 
integrity management evaluation required in this proposed rule. OPS 
does not believe, however, that requiring this comprehensive process, 
including the re-assessment of pipelines in high consequence areas at a 
minimum of once every 10 years, will not be an undue burden on 
hazardous liquid operators covered by this proposal. OPS believes the 
added security this assessment will provide and the generally expedited 
rate of strengthening the pipeline system in populated and important 
environmental areas and commercially navigable waterways, is benefit 
enough to promulgate these proposed requirements.
    A copy of the complete draft regulatory evaluation is available for 
reading in the public docket.

Regulatory Flexibility Act

    Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.) OPS 
must consider whether a rulemaking would have a significant impact on a 
substantial number of small entities. This proposed rulemaking was 
designed to impact only hazardous liquid operators operating 500 or 
more miles of pipeline. Because of this limitation on pipeline mileage, 
only 66 hazardous liquid pipeline operators (large national energy 
companies) covering 86.7 percent of regulated liquid transmission lines 
are impacted by this proposed rule. Based on this, and the evidence 
discussed above, I certify that this proposed rule will not have a 
significant impact on a substantial number of small entities.

Paperwork Reduction Act

    This notice of proposed rulemaking contains information collection 
requirements. As required by the Paperwork Reduction Act of 1995 (44 
U.S.C. 3507(d)), the Department of Transportation has submitted a copy 
of the Paperwork Reduction Act Analysis to the Office of Management and 
Budget for its review. The name of the information collection is 
``Pipeline Integrity Management in High Consequence Areas.'' The 
purpose of this information collection is designed to require operators 
of hazardous liquid pipelines to develop a program to provide direct 
integrity testing and evaluation of hazardous liquid pipelines in high 
consequence areas.
    Sixty-six hazardous liquid operators will be subject to this 
proposed rule. It is estimated that 59 of these operators will have to 
develop integrity management plans taking approximately 430 hours per 
plan. Additionally, all 66 operators will be required to update their 
plans annually. This will take approximately 33 hours per plan.
    Organizations and individuals desiring to submit comments on the 
information collection should direct them to the Office of Information 
and Regulatory Affairs, OMB, Room 10235, New Executive Office Building, 
Washington, DC 20503: Attention Desk Officer for the Department of 
Transportation. Comments must be sent within 30 days of the publication 
of this NPRM. Comments can also be sent to the Department of 
Transportation either by mail or electronically. See the Addresses 
section of this NPRM.
    The Department considers comments by the public on this proposed 
collection of information in:
    Evaluating whether the proposed collection is necessary for the 
proper performance of the functions of the Department, including 
whether the information would have a practical use;
    Evaluating the accuracy of the Department's estimate of the burden 
of the proposed collection of information, including the validity of 
assumptions used;
    Enhancing the quality, usefulness and clarity of the information to 
be collected; and minimizing the burden of collection of information on 
those who are to respond, including through the use of appropriate 
automated electronic, mechanical, or other technological collection 
techniques or other forms of information technology; e.g., permitting 
electronic submission of responses.
    According to the Paperwork Reduction Act of 1995, no persons are 
required to respond to a collection of

[[Page 21707]]

information unless a valid OMB control number is displayed. The valid 
OMB control number for this information collection will be published in 
the Federal Register after it is approved by the OMB. For more details, 
see the Paperwork Reduction Analysis available for copying and review 
in the public docket.

Executive Order 13084

    This proposed rule has been analyzed in accordance with the 
principles and criteria contained in Executive Order 13084 
(``Consultation and Coordination with Indian Tribal Governments''). 
Because this proposed rule does not significantly or uniquely affect 
the communities of the Indian tribal governments and does not impose 
substantial direct compliance costs, the funding and consultation 
requirements of Executive Order 13084 do not apply.

Executive Order 13132

    This proposed rule has been analyzed in accordance with the 
principles and criteria contained in Executive Order 13132 
(``Federalism''). This proposed rule does not propose any regulation 
that:
    (1) Has substantial direct effects on the States, the relationship 
between the national government and the States, or the distribution of 
power and responsibilities among the various levels of government;
    (2) Imposes substantial direct compliance costs on States and local 
governments; or
    (3) Preempts state law.
    Therefore, the consultation and funding requirements of Executive 
Order 13132 (64 FR 43255; August 10, 1999) do not apply. Nevertheless, 
in a November 18-19, 1999 public meeting, OPS invited National 
Association of Pipeline Safety Representatives (NAPSR), which includes 
State pipeline safety regulators, to participate in a general 
discussion on pipeline integrity. Again in January, and February 2000, 
OPS held conference calls with NAPSR, to receive their input before 
proposing an integrity management rule.

Unfunded Mandates

    This rule does not impose unfunded mandates under the Unfunded 
Mandates Reform Act of 1995. It does not result in costs of $100 
million or more to either State, local, or tribal governments, in the 
aggregate, or to the private sector, and is the least burdensome 
alternative that achieves the objective of the rule.

National Environmental Policy Act

    We have analyzed the proposed rule for purposes of the National 
Environmental Policy Act (42 U.S.C. 4321 et seq.) and have 
preliminarily determined that this action would not significantly 
affect the quality of the human environment. The Environmental 
Assessment determined that the combined impacts of the initial baseline 
assessment (testing or internal inspection), the subsequent periodic 
assessments, and additional preventive and mitigative measures that may 
be implemented in high consequence areas will result in positive 
environmental impacts. The number of incidents and the environmental 
damage from failures in high consequence areas is likely to be reduced. 
However, from a national perspective, the impact is not expected to be 
significant for the pipeline operators covered in the proposed rule, 
primarily because most of these operators are already voluntarily 
performing most of the activities proposed by the rule.
    Operators covered by the proposed rule already have internal 
inspection and testing programs. These operators typically consider the 
pipeline's proximity to populated areas and environmental resources 
when making decisions about where and when to inspect and test 
pipelines. As a result, some high consequence areas have already been 
recently assessed, and a large fraction of remaining locations would 
have been assessed in the next several years, without the provisions of 
the rule. The primary effect of the proposed rule--accelerating testing 
and inspection in some high consequence areas--only shifts the improved 
integrity assurance forward for a few years for most high consequence 
areas. Because pipeline failure rates are low, shifting the time at 
which high consequence areas are assessed forward by a few years, has 
only a small effect on the likelihood of pipeline failure in these 
locations.
    Neither internal inspection nor pressure testing provide protection 
against all threats to pipeline integrity--specifically they do not 
prevent outside force damage, the most significant contributor to 
hazardous liquid pipeline failures. The proposed rule does require 
operators to conduct an integrated assessment of all the potential 
threats to pipeline integrity, and to consider additional preventive or 
mitigative risk control measures to provide enhanced protection. If 
there is a vulnerability to a particular failure cause--like third 
party damage--these assessments should result in additional risk 
controls to address these threats. However, without knowing the 
specific high consequence area locations, the specific risks present at 
these locations, and the existing operator risk controls (including 
those that surpass the current minimum regulatory requirements), it is 
difficult to determine the impact of this requirement.
    A number of liquid operators covered by the proposed rule already 
perform integrity evaluations or formal risk assessments that consider 
the environmental sensitivity and impacts on population. These 
evaluations have already led to additional risk controls beyond 
existing requirements to improve protection for these locations. Thus, 
it is expected that additional risk controls resulting from the 
proposed integrated evaluation will be limited and customized to site-
specific conditions that the operator may not have previously 
recognized. For many high consequence areas, it is probable that 
operators will determine the existing preventive and mitigative 
activities provide adequate protection, and that the small additional 
risk reduction benefits of additional risk controls are not justified 
by their cost.
    The primary benefit of the proposed rule will be to establish 
requirements for conducting integrity assessments and periodic 
evaluations of integrity in high consequence areas. In effect, this 
will codify the integrity management programs and assessments many 
operators are currently implementing. It will also require operators 
who have little, or no, integrity assessment and evaluation programs to 
raise their level of performance. Thus, the proposed rule is expected 
to ensure a more consistent, and overall higher level of protection for 
high consequence areas across the industry.
    The Environmental Assessment of this proposal is available for 
review in the docket.

Impact on Business Processes and Computer Systems

    We do not want to impose new requirements that would mandate 
business process changes when the resources necessary to implement 
those requirements would otherwise be applied to ``Y2K'' or related 
computer problems. This proposed rule does not mandate business process 
changes or require modifications to computer systems. Because this 
proposed rule does not affect organizations' ability to respond to 
those problems, we are not delaying the effectiveness of the 
requirements.

[[Page 21708]]

List of Subjects in 49 CFR Part 195

    Petroleum products, Pipeline safety, Reporting and recordkeeping 
requirements.
    In consideration of the foregoing, OPS proposes to amend part 195 
of title 49 of the Code of Federal Regulations as follows:

PART 195--[AMENDED]

    1. The authority citation for part 195 continues to read as 
follows:

    Authority: 49 U.S.C. 60102, 60104, 60108, and 60109; and 49 CFR 
1.53.

Subpart F--Operation and Maintenance

    2. New Secs. 195.450 and 195.452 would be added under new 
undesignated center headings of ``High Consequence Areas'' and 
``Pipeline Integrity Management'' respectively, in subpart F to read as 
follows:
* * * * *
High Consequence Areas


Sec. 195.450  Definitions.

    High consequence area means:
    (1) An unusually sensitive area, as defined in Sec. 195.6,
    (2) A high population area, which means an urbanized area, as 
defined and delineated by the Census Bureau, that contains 50,000 or 
more people and has a population density of at least 1,000 people per 
square mile,
    (3) An other populated area, which means a place, as defined and 
delineated by the Census Bureau, that contains a concentrated 
population, such as an incorporated or unincorporated city, town, 
village, or other designated residential or commercial area, or
    (4) A commercially navigable waterway, which means a waterway where 
a substantial likelihood of commercial navigation exists.
    Emergency flow restricting device or EFRD means a check valve or 
remote control valve.
    (1) Check valve means a valve that permits fluid to flow freely in 
one direction and contains a mechanism to automatically prevent flow in 
the other direction.
    (2) Remote control valve or RCV means any valve that is operated 
from a location remote from where the valve is installed. Operation of 
the RCV is usually by the supervisory control and data acquisition 
(SCADA) system. The linkage between the pipeline control center and the 
RCV may be by fiber optics, microwave, telephone lines, or satellite.
Pipeline Integrity Management


Sec. 195.452  Pipeline Integrity Management in High Consequence Areas.

    (a) Which operators must comply? This section applies to each 
operator who operates 500 or more miles of pipeline used in hazardous 
liquid transportation.
    (b) What must an operator do? No later than [insert date one year 
after the effective date of the final rule], an operator must develop 
and follow a written integrity management program that includes--
    (1) A plan for baseline assessment of all pipelines that could 
affect a high consequence area (see paragraph (c) of this section); and
    (2) A framework addressing each element of the integrity management 
program, including continual integrity assessment and evaluation (see 
paragraphs (f) and (j) of this section). The framework must initially 
indicate how decisions will be made to implement each element. In 
carrying out this section, an operator must follow best industry 
practices (BIP) unless the section specifies otherwise or the operator 
demonstrates that the deviation is backed by a reliable engineering 
evaluation.
    (c) What must be in the baseline assessment plan? The written 
baseline assessment plan must include--
    (1) The methods selected to assess the integrity of the pipeline 
(pressure test conducted to a minimum of 1.25 times maximum operating 
pressure, internal inspection tool capable of detecting corrosion and 
deformation anomalies including dents, gouges and grooves,\2\ or new 
technology that the operator demonstrates can provide an equivalent 
level of protection in assessing the integrity of the pipeline);
---------------------------------------------------------------------------

    \2\ A magnetic flux leakage or ultrasonic internal inspection 
survey shall not be used for a segment constructed of low frequency 
electric resistance-welded pipe (ERW pipe) and lapwelded pipe 
susceptible to longitudinal seam failures.
---------------------------------------------------------------------------

    (2) A schedule for completing the integrity assessment of all 
pipelines that could affect a high consequence area; and
    (3) An explanation of the assessment methods selected and 
evaluation of risk factors considered in establishing the assessment 
schedule for the pipelines.
    (d) When must the baseline assessment be completed? (1) An operator 
must initially assess the integrity (by pressure test conducted to a 
minimum of 1.25 times maximum operating pressure, internal inspection 
tool capable of detecting corrosion and deformation anomalies including 
dents, gouges and grooves, or new technology that the operator 
demonstrates can provide an equivalent level of protection in assessing 
the integrity of the pipeline) of all pipelines that could affect a 
high consequence area by [insert date seven (7) years from the 
effective date of the final rule]. At least 50 percent of that mileage 
must be assessed by [insert date 42 months from the effective date of 
the final rule].
    (2) An operator may use an integrity assessment method conducted 
after [insert date five years before the effective date of the final 
rule] as the baseline assessment if the method meets the requirements 
of this section.
    (e) What are the criteria for establishing an assessment schedule 
(For both the baseline and continual assessments)? An operator must 
select one of the following options:
    (1) Option 1. An operator must base the integrity assessment 
schedule on risk factors including, but not limited to, pipe material, 
pipe manufacturing information, local environmental factors that could 
impact the pipeline (e.g., corrosivity of soil, subsidence, climatic), 
existing or projected activities in the area, coating type, product 
transported, repair history, all previous data/results from pressure 
testing or internal inspection, geo-technical hazards, corrosion 
history and pipeline leak history. See appendix C to this part for 
guidance on assigning priorities to these risk factors.
    (2) Option 2. An operator must base the integrity assessment method 
and assessment schedule on risk factors the operator considers 
essential in risk or consequence evaluation, and that the operator 
demonstrates can provide an equivalent level of safety and 
environmental protection to option 1 (paragraph (e)(1) of this 
section).
    (f) What are the elements of an integrity management program? An 
integrity management program is an evolving program that the operator 
will continually improve based on experience. A written integrity 
management program must, at minimum, include the following elements:
    (1) A baseline assessment plan meeting the requirements of 
paragraph (c) of this section;
    (2) A continual process of assessment and evaluation to maintain a 
pipeline's integrity (see paragraph (j) of this section);
    (3) An analysis that integrates all available information about the 
integrity of the pipeline or the consequences of a failure (see 
paragraph (h) of this section);
    (4) Criteria for repair actions to address integrity issues raised 
by the

[[Page 21709]]

assessment method and data analysis (see paragraph (g) of this 
section);
    (5) Identification of preventive and mitigative measures to protect 
the high consequence area (see paragraph (i) of this section);
    (6) Methods to measure the program's effectiveness (see paragraph 
(k) of this section); and
    (7) A process for review of integrity assessment results and data 
analysis by a person qualified to evaluate the results and data.
    (g) What remedial action must be taken? An operator must take 
prompt action to address all pipeline integrity issues raised by the 
assessment method and data integration analysis. An operator must 
evaluate and repair all defects that could reduce a pipeline's 
integrity. In establishing an evaluation and repair schedule, an 
operator must comply with Sec. 195.401(b), which requires that if a 
condition on the pipeline is of such a nature that it presents an 
immediate hazard, the operator may not operate the affected part of the 
system until it has corrected the unsafe condition. For all other 
conditions, an operator must base the schedule for evaluation and 
repair on the risk factors listed in paragraph (e)(1) of this section 
and on the following criteria if the assessment method is by internal 
inspection:
    (1) Data that reflects a change since last surveyed has priority 
over all other data.
    (2) Data that could indicate mechanical damage that is located on 
the top half of the pipe has priority over the same located on the 
bottom.
    (3) Data that indicates anomalies abrupt in nature has priority 
over locations that are smooth.
    (4) Data that indicates anomalies longitudinal in orientation has 
priority over transverse data.
    (5) Data that indicates anomalies over a large area has priority 
over that contained within a smaller area. See appendix C to this part 
for further guidance on analyzing internal inspection results.
    (h) Integration of data. In periodically evaluating the integrity 
of the pipeline (paragraph (j) of this section), an operator must 
analyze all available information about the integrity of the pipeline 
or the consequences of a failure. This information includes--
    (1) Information critical to determining the potential for, and 
preventing, damage due to excavation, including current and planned 
damage prevention activities, and development or planned development 
along the pipeline;
    (2) Data gathered through the integrity assessment required under 
this section.
    (3) Data gathered in conjunction with other inspections and tests 
required by this Part, including, corrosion control monitoring and 
cathodic protection surveys; and
    (4) Information about how a failure would affect the high 
consequence area, such as location of water intake valves.
    (i) Preventive and mitigative measures to protect the high 
consequence area. An operator must take measures to prevent and 
mitigate the consequences of a pipeline failure that could affect a 
high consequence area. These measures include conducting a risk 
analysis of the pipeline to determine if public safety or environmental 
protection would be enhanced by additional risk control actions. Such 
actions include, but are not limited to, implementing damage prevention 
best practices, better monitoring of cathodic protection where 
corrosion is a concern, establishing shorter inspection intervals, 
making repairs other than those required by this section, installing 
EFRDs on the pipeline, establishing or modifying the systems that 
monitor pressure and detect leaks, providing additional training to 
personnel on response procedures, conducting drills with local 
emergency responders and adopting other management controls.
    (j) What is a continual evaluation of a pipeline's integrity? (1) 
After completing the baseline integrity assessment, an operator must 
continue to assess at specified intervals (by pressure test conducted 
to a minimum of 1.25 times maximum operating pressure, internal 
inspection tool capable of detecting corrosion and deformation 
anomalies including dents, gouges and grooves, or new technology that 
the operator demonstrates can provide an equivalent level of protection 
in assessing the integrity of the pipeline), and periodically evaluate 
the integrity of each pipeline that could affect a high consequence 
area. An operator must conduct a periodic evaluation as frequently as 
needed to assure pipeline integrity. The evaluation must consider the 
past and present integrity assessment results, data integration 
analysis (paragraph (h) of this section), and decisions about repair, 
preventive and mitigative actions (paragraphs (g) and (i) of this 
section).
    (2) An operator must choose one of the following options in 
establishing the integrity assessment intervals.
    (i) Option 1. An operator must establish intervals not to exceed 10 
years for assessing the pipeline's integrity. To establish the 
intervals, an operator must use the applicable risk factors listed in 
paragraph (e)(1) of this setion, the analysis of the results from last 
integrity assessment, and data from the integration analyses. If the 
previous assessment method was by internal inspection, an operator must 
also consider the factors specified in paragraph (g) of this section. 
(See appendix C to this part for further guidance on analyzing internal 
inspection results.)
    (ii) Option 2. An operator must establish intervals to assess the 
pipeline's integrity based on criteria the operator demonstrates 
provide an equivalent level of safety and environmental protection to 
option 1 (paragraph (j)(2)(i) of this section).
    (k) Methods to measure program's effectiveness. The program must 
include methods to measure whether the program is effective in 
assessing and evaluating the integrity of the pipelines and in 
protecting the high consequence areas.
    (l) What records must be kept? An operator must maintain for review 
during an inspection--(1) A written integrity management program in 
accordance with paragraph (b) of this section.
    (2) Documents to support the decisions and analyses made and 
actions taken to implement each element of the integrity management 
program.
    3. A new appendix C would be added to part 195 to read as follows:

Appendix C To Part 195--Prioritizing Risk Factors

    This appendix gives guidance on how to prioritize risk factors 
in determining assessment frequency, how to analyze smart pig 
inspection results, how to prioritize metal loss features, and what 
types of smart pigs to use for finding pipeline anomalies. In 
addition, this appendix includes risk indicator tables for leak 
history, volume or line size, age of pipeline, and product 
transported, to help determine if the pipeline segment falls into a 
high, medium or low risk category.
    By using the risk factors prioritization and risk indicator 
tables, an operator can determine the priority for testing pipeline 
segments. An operator can determine which segments need immediate 
attention by applying weights or values to the risk factors, and 
then referring to the risk tables and other methods described below. 
The integrity assessment interval for a relatively lower-risk 
pipeline segment is not to exceed 10 years.

I. Risk factors for establishing frequency of assessment in order 
of priority.\1\
---------------------------------------------------------------------------

    \1\ US DOT study on instrumented Internal Inspection devices, 
Nov. 1992. Order of priority was determined from a survey of users.
---------------------------------------------------------------------------

    <bullet> Population areas (high population areas may be given 
priority over other populated areas), unusually sensitive 
environmental areas, and commercially navigable waters.

[[Page 21710]]

    <bullet> Results from previous testing/inspection. (See 
``Analyzing Smart Pig Inspection Results''.)
    <bullet> Leak History. (See leak history risk table.)
    <bullet> Known corrosion or condition of pipeline. (See ``metal 
loss features prioritization''.)
    <bullet> Cathodic protection history.
    <bullet> Type and quality of pipe coating (disbonded coating 
results in corrosion).
    <bullet> Age of pipe (older pipe shows more corrosion--may be 
uncoated or have an ineffective coating) and type of pipe seam. (See 
Age of Pipe risk table.)
    <bullet> Product transported (highly volatile, highly flammable 
and toxic liquids present a greater threat for both people and the 
environment. Natural gas presents a greater hazard to the public 
because it is flammable)(see Product transported risk table.)
    <bullet> Pipe wall thickness (thicker walls give a better safety 
margin).
    <bullet> Size (higher volume release if the pipe ruptures).
    <bullet> Location related to potential ground movement (e.g., 
seismic faults, rock quarries, and coal mines); climatic (permafrost 
causes settlement--Alaska); geologic (landslides or subsidence).
    <bullet> Security of throughput (effects on customers if there 
is failure requiring shutdown).
    <bullet> Time since the last in-line inspection/pressure 
testing.

II. Analyzing Smart Pig Inspection Results.\2\
---------------------------------------------------------------------------

    \2\ Presention by H. Noel Duckworth (Pipeline Consultant) at the 
Pipeline Integrity public meeting on 11/18/1999.
---------------------------------------------------------------------------

    (a) The criteria an operator should use to analyze smart pig 
inspection results to minimize pipeline failure risks include, but 
are not limited to the following:
    <bullet> Smart pig data that reflects a change since last 
surveyed should have priority over all others.
    <bullet> Smart pig data that is reflective of mechanical damage 
and is on the top half of the pipe should have priority over the 
same located on the bottom.
    <bullet> Smart pig data that is abrupt in nature should have 
priority over those locations that are smooth.
    <bullet> Smart pig data that is longitudinal in orientation 
should have priority over that which is transverse.
    <bullet> Smart pig data that cover a large area should have 
priority over that contained within a smaller area.
    (b) An operator should review smart pig results for any 
condition that could be lead to an ``immediate concern'' on the 
pipeline. These conditions may require further investigation to 
determine whether they adversely affect the safe operation of the 
pipeline system. These conditions include, but are not limited to:
    <bullet> Severe localized corrosion pitting >80% of the original 
wall thickness of the pipe. The mandatory repair is required in a 
period not exceeding x months.
    <bullet> Dents with associated metal loss. The mandatory repair 
is required in a period not exceeding x months.
    <bullet> Casing shorts and close foreign pipeline crossings with 
associated metal loss.
    <bullet> Girth weld anomalies. Depending on the length of the 
affected area of the weld.
    (c) An operator must further evaluate the immediate concern 
conditions to determine priority for their excavation, verification 
and remediation.

III. Metal Loss Feature Prioritization.\3\
---------------------------------------------------------------------------

    \3\ Guidelines to review smart pig inspection used by a 
hazardous liquid pipeline operator.
---------------------------------------------------------------------------

    An operator must prioritize all metal loss features to determine 
remedial actions for the pipeline system.
    (a) Metal loss features that calculate, using ASME B31G, a 
remaining strength working pressure that is less than the original 
design working pressure of the pipe must be considered ``priority 
metal loss features''. These features must be further evaluated 
according to paragraph III.(b) of this appendix.
    (b) Features that calculate a pressure that is less than the 
pipeline's maximum allowable working pressure require remediation. 
All of these features must be further evaluated according to 
paragraph III.(c) of this appendix.
    (c) Features that calculate a pressure that is less than the 
pipeline's normal operating pressure require immediate investigation 
and remediation.

IV. Types of Pigs to use.

    An operator should select equipment based on the particular 
situation. At least two types of pigs should be used--
    (a) Geometry pigs for detecting changes in circumference, e.g., 
bends, dents, buckles or wrinkles, due to construction flaws or soil 
movement, or other outside force damage; and
    (b) Magnetic Flux Leakage pigs for determining pipe wall 
anomalies, e.g. wall loss due to corrosion.

V. Risk indicator tables for leak history, volume or line size, age 
of pipeline, and product transported.

                              Leak History
------------------------------------------------------------------------
                                                Leak history  (Time-
              Risk indicator                    dependent defects)\1\
------------------------------------------------------------------------
High......................................  >3 Spills in last 10 years.
Low.......................................  <ls-thn-eq>3 Spills in last
                                             10 years.
------------------------------------------------------------------------
\1\ Time-dependent defects are those that result in spills due to
  corrosion, gouges, or problems developed during manufacture,
  construction or operation, etc.


                     Line Size or Volume Transported
------------------------------------------------------------------------
              Risk indicator                     Line size  (inches)
------------------------------------------------------------------------
High......................................  <gr-thn-eq> 18.
Moderate..................................  10-16 nominal diameters.
Low.......................................  <ls-thn-eq> 8 nominal
                                             diameter.
------------------------------------------------------------------------


                             Age of Pipeline
------------------------------------------------------------------------
                                              Age  (Pipeline condition
              Risk indicator                       dependent \1\)
------------------------------------------------------------------------
High......................................  > 25 years.
Low.......................................  <ls-thn-eq> 25 years.
------------------------------------------------------------------------
\1\ Depends on pipeline's coating & corrosion condition, and steel
  quality, toughness, welding.


                           Product Transported
------------------------------------------------------------------------
       Risk indicator            Considerations       Product examples
------------------------------------------------------------------------
High........................  (Highly volatile and  (Propane, butane,
                               flammable).           Natural Gas Liquid
                                                     (NGL), ammonia)
                              Highly toxic........  (Benzene, high
                                                     Hydrogen Sulfide
                                                     content crude oils)
Medium......................  Flammable--flashpoin  (Gasoline, JP4, low
                               t 100F.               flashpoint crude
                                                     oils)
Low.........................  Non-flammable--       (Diesel, fuel oil,
                               flashpoint 100+F.     kerosene, JP5, most
                                                     crude oils)
------------------------------------------------------------------------

    Considerations: The degree of acute and chronic toxicity to 
humans, wildlife, and aquatic life; reactivity; and, volatility, 
flammability, and water solubility determine the Product Indicator. 
Comprehensive Environmental Response, Compensation and Liability Act 
Reportable Quantity values may be used as an indication of chronic 
toxicity. National Fire Protection Association health factors may be 
used for rating acute hazards.

    Issued in Washington DC on April 17, 2000.
Stacey L. Gerard,
Director, Office of Policy, Regulations and Training, Office of 
Pipeline Safety.
[FR Doc. 00-9934 Filed 4-21-00; 8:45 am]
BILLING CODE 4910-60-P


</pre><script data-cfasync="false" src="/cdn-cgi/scripts/5c5dd728/cloudflare-static/email-decode.min.js"></script></body>
</html>