Federal Register / Vol. 65, No. 79 / Monday, April 24, 2000 / Proposed Rules 21695

1 5 U.S.C. 603.

2 5 U.S.C. 605(b). The RFA, see 5 U.S.C. 601 et.

seq., has been amended by the Contract With

America Advancement Act of 1996, Public Law

104–121, 110 Stat. 847 (1996) (CWAAA). Title II of

the CWAAA is the Small Business Regulatory

Enforcement Fairness Act of 1996.

3 5 U.S.C. 605(b).

(an area extending approximately 20

miles from the coast); (5) to accept a

proof of passing certificate from the

United States Coast Guard training

program, which includes both

theoretical examinations and practical

demonstrations of the candidate’s

ability to operate GMDSS equipment, as

evidence that an applicant has met the

obligations for any GMDSS operator

license issued by the Commission; and

(6) to remove the certification for Class

A, B, and S emergency position

indicating radiobeacons, which operate

at 121.5 MHz and 243 MHz, due to their

ineffectiveness in lifesaving operations.

Regulatory Flexibility Analysis

The Regulatory Flexibility Act (RFA) 1

requires that an agency prepare a

regulatory flexibility analysis for notice

and comment rulemakings, unless the

agency certifies that ‘‘the rule will not,

if promulgated, have a significant

economic impact on a substantial

number of small entities.’’ 2 In this

Notice of Proposed Rule Making, the

Commission proposes to consolidate,

revise, and streamline the Commission’s

Rules governing maritime

communications. The purpose of these

proposed rule changes is to address new

international maritime requirements,

improve the operational ability of all

users of marineradios and remove

unnecessary or duplicative

requirements from the Commission’s

Rules. In an effort to clarify the existing

regulations, the Commission also

proposes to make minor and nonsubstantive modifications to Part 80 of

the Commission’s Rules. The proposed

rule changes do not impose any

additional compliance burden on small

entities regulated by the Commission.

Accordingly, the Commission certifies,

pursuant to section 605(b) of the RFA,

that the rules proposed in this Notice of

Proposed Rule Making will not, if

promulgated, have a significant

economic impact upon a substantial

number of small entities, as that term is

defined by the RFA.3 The Commission

shall send a copy of this Notice of

Proposed Rule Making, including a copy

of this certification, to the Chief Counsel

for Advocacy of the Small Business

Administration in accordance with the

RFA. We shall also publish a copy of

this certification in the Federal Register.

List of Subjects 47 CFR Parts 13 and 80

Communications equipment, Radio.

Federal Communications Commission.

Magalie Roman Salas,

Secretary.

[FR Doc. 00–10091 Filed 4–21–00; 8:45 am]

BILLING CODE 6712–01–P

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 email: mike.israni@rspa.dot.gov,

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

21696 Federal Register / Vol. 65, No. 79 / Monday, April 24, 2000 / Proposed Rules

damage. NTSB recommendations on

this subject include:

• NTSB recommended that OPS

require periodic testing and inspection

to identify corrosion and other timedependent damages.

• NTSB recommended that OPS

establish criteria to determine

appropriate intervals for inspections

and tests, including safe service

intervals between pressure testing.

• NTSB recommended that OPS

determine hazards to public safety from

electric resistance welded (ERW) pipe

and establish standards for leak

detection.

• 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:

• 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).

• 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.

• 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 pipelinespecific 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 costeffective 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

Federal Register / Vol. 65, No. 79 / Monday, April 24, 2000 / Proposed Rules 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:

•Comparing multiple internal

inspection runs over the same line to

determine corrosion growth rates;

•Testing new inspection techniques

to detect seam flaws and stress

corrosion cracking;

• 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;

• Integrating hydrostatic pressure

testing with internal inspection where

appropriate;

• Using probabilistic techniques to

optimize the frequency at which

internal inspection and pressure testing

is conducted;

• Using probabilistic approaches to

prioritize and define the extent of

anomaly excavation and repair; and

• 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 locationspecific 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.

21698 Federal Register / Vol. 65, No. 79 / Monday, April 24, 2000 / Proposed Rules

5. Key Questions for OPS to Ask During

an Inspection.

Participants emphasized that OPS

should focus on the key locationspecific 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 riskbased 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

Federal Register / Vol. 65, No. 79 / Monday, April 24, 2000 / Proposed Rules 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

21700 Federal Register / Vol. 65, No. 79 / Monday, April 24, 2000 / Proposed Rules

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 noncommercially 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

Federal Register / Vol. 65, No. 79 / Monday, April 24, 2000 / Proposed Rules 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, highresolution 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 highresolution 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 nondestructively 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.

21702 Federal Register / Vol. 65, No. 79 / Monday, April 24, 2000 / Proposed Rules

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:

• Establish the basic elements of a

company pipe integrity program;

• Establish integrity requirements

that are pipeline segment specific and

system-wide specific;

• 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;

• Establish a standard for pipe

integrity assurance activities;

• Establish standards for the

engineering assessment of information,

for example, evaluating remaining wall

thickness using repair criteria;

• 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.

Federal Register / Vol. 65, No. 79 / Monday, April 24, 2000 / Proposed Rules 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

21704 Federal Register / Vol. 65, No. 79 / Monday, April 24, 2000 / Proposed Rules

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:

• Pipeline design features;

• Construction practices and

information;

• Operating and accident history;

• Maintenance and surveillance

records, including cathodic protection

records;

• Previous inspection and testing

results;

• Damage prevention and other

prevention program effectiveness;

• 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 performancebased 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

Federal Register / Vol. 65, No. 79 / Monday, April 24, 2000 / Proposed Rules 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 remoteoperated mainline valves on highpressure 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

21706 Federal Register / Vol. 65, No. 79 / Monday, April 24, 2000 / Proposed Rules

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 mapbased 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

Federal Register / Vol. 65, No. 79 / Monday, April 24, 2000 / Proposed Rules 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.

21708 Federal Register / Vol. 65, No. 79 / Monday, April 24, 2000 / Proposed Rules

2A magnetic flux leakage or ultrasonic internal

inspection survey shall not be used for a segment

constructed of low frequency electric resistancewelded pipe (ERW pipe) and lapwelded pipe

susceptible to longitudinal seam failures.

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 §§ 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

§ 195.450 Definitions.

High consequence area means:

(1) An unusually sensitive area, as

defined in § 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

§ 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 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

Federal Register / Vol. 65, No. 79 / Monday, April 24, 2000 / Proposed Rules 21709

1US DOT study on instrumented Internal

Inspection devices, Nov. 1992. Order of priority was

determined from a survey of users.

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 § 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

• Population areas (high population areas

may be given priority over other populated

areas), unusually sensitive environmental

areas, and commercially navigable waters.

21710 Federal Register / Vol. 65, No. 79 / Monday, April 24, 2000 / Proposed Rules

2Presention by H. Noel Duckworth (Pipeline

Consultant) at the Pipeline Integrity public meeting

on 11/18/1999.

3 Guidelines to review smart pig inspection used

by a hazardous liquid pipeline operator.

• Results from previous testing/inspection.

(See ‘‘Analyzing Smart Pig Inspection

Results’’.)

• Leak History. (See leak history risk

table.)

• Known corrosion or condition of

pipeline. (See ‘‘metal loss features

prioritization’’.)

• Cathodic protection history.

• Type and quality of pipe coating

(disbonded coating results in corrosion).

• 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.)

• 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.)

• Pipe wall thickness (thicker walls give a

better safety margin).

• Size (higher volume release if the pipe

ruptures).

• Location related to potential ground

movement (e.g., seismic faults, rock quarries,

and coal mines); climatic (permafrost causes

settlement—Alaska); geologic (landslides or

subsidence).

• Security of throughput (effects on

customers if there is failure requiring

shutdown).

• Time since the last in-line inspection/

pressure testing.

II. Analyzing Smart Pig Inspection Results.2

(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:

• Smart pig data that reflects a change

since last surveyed should have priority over

all others.

• 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.

• Smart pig data that is abrupt in nature

should have priority over those locations that

are smooth.

• Smart pig data that is longitudinal in

orientation should have priority over that

which is transverse.

• 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:

• 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.

• Dents with associated metal loss. The

mandatory repair is required in a period not

exceeding x months.

• Casing shorts and close foreign pipeline

crossings with associated metal loss.

• 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

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

Risk indicator Leak history

(Time-dependent defects)1

High ............... >3 Spills in last 10 years.

Low ................ ≤3 Spills in last 10 years.

1Time-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 ............... ≥ 18.

Moderate ....... 10–16 nominal diameters.

Low ................ ≤ 8 nominal diameter.

AGE OF PIPELINE

Risk indicator

Age

(Pipeline condition

dependent 1)

High ............... > 25 years.

Low ................ ≤ 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 flammable) ....................................... (Propane, butane, Natural Gas Liquid (NGL), ammonia)

Highly toxic ...................................................................... (Benzene, high Hydrogen Sulfide content crude oils)

Medium ................................ Flammable—flashpoint <100F ........................................ (Gasoline, JP4, low flashpoint crude oils)

Low ....................................... Non-flammable—flashpoint 100+F .................................. (Diesel, fuel oil, 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