75378 Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations

DEPARTMENT OF TRANSPORTATION

Research and Special Programs

Administration

49 CFR Part 195

[Docket No. RSPA–99–6355; Amendment

195–70]

RIN 2137–AD45

Pipeline Safety: Pipeline Integrity

Management in High Consequence

Areas (Hazardous Liquid Operators

With 500 or More Miles of Pipeline)

AGENCY: Research and Special Programs

Administration (RSPA), DOT.

ACTION: Final rule.

SUMMARY: This final rule specifies

regulations to assess, evaluate, repair

and validate through comprehensive

analysis the integrity of hazardous

liquid pipeline segments that, in the

event of a leak or failure, could affect

populated areas, areas unusually

sensitive to environmental damage and

commercially navigable waterways. OPS

is requiring that an operator develop

and follow an integrity management

program that provides for continually

assessing the integrity of all pipeline

segments that could affect these high

consequence areas, through internal

inspection, pressure testing, or other

equally effective assessment means. The

program must also provide for

periodically evaluating the pipeline

segments through comprehensive

information analysis, remediating

potential problems found through the

assessment and evaluation, and

ensuring additional protection to the

segments and the high consequence

areas through preventive and mitigative

measures.

Through this required program,

hazardous liquid operators will

comprehensively evaluate the entire

range of threats to each pipeline

segment’s integrity by analyzing all

available information about the pipeline

segment and consequences of a failure

on a high consequence area. This

includes analyzing information on the

potential for damage due to excavation;

data gathered through the required

integrity assessment; results of other

inspections, tests, surveillance and

patrols 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.

The final 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 all defects and repair

those could reduce a pipeline’s

integrity. An operator must develop a

schedule that prioritizes the defects for

evaluation and repair, including time

frames for promptly reviewing and

analyzing the integrity assessment

results and completing the repairs. An

operator must also provide additional

protection for these pipeline segments

through other remedial actions, and

preventive and mitigative measures.

DATES: Effective Date: This final rule

takes effect March 31, 2001.

Compliance Dates: An operator must

complete an identification of all

pipeline segments that could affect a

high consequence area no later than

December 31, 2001. An operator must

develop a written integrity management

program no later than March 31, 2002.

Comment Date: Interested persons are

invited to submit comment on the

provisions of the rule concerning

actions an operator must take to address

integrity issues on the pipeline

(§ 195.452(h)) by March 31, 2001. At the

end of the comment period, we will

publish a document modifying these

remedial action provisions or a

document stating that the provisions

will remain unchanged.

ADDRESSES: Comments limited to the

provisions on actions an operator must

take to address pipeline integrity issues

(§ 195.452(h)) must be sent 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 number stated in the heading of

this rule.

FOR FURTHER INFORMATION CONTACT:

Mike Israni, (202) 366–4571, or by email: mike.israni@rspa.dot.gov,

regarding the subject matter of this final

rule, or the Dockets Facility (202) 366–

9329, for copies of this final 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

Notice of Proposed Rulemaking

On April 24, 2000, OPS published a

notice of proposed rulemaking (65 FR

21695) that proposed pipeline integrity

management program requirements for

hazardous liquid operators that operated

500 or more miles of pipeline. The

proposed requirements were to apply to

hazardous liquid pipelines that could

affect areas we proposed as high

consequence areas—populated areas,

areas unusually sensitive to

environmental damage, and

commercially navigable waterways.

OPS issued the proposal after a public

meeting that OPS hosted on November

18 & 19, 1999, to gather information on

current pipeline assessment methods

and integrity management programs.

OPS had also established an electronic

public discussion forum to gather

further information. Comments and

information gathered from these forums

were used in developing the proposed

rule for larger hazardous liquid

operations. The proposed rule was the

first in a series of rulemakings that will

require all regulated pipeline operators

to have integrity management programs.

The notice proposed that a hazardous

liquid operator develop and follow an

integrity management program. Among

the proposed required elements of a

program were—

• Baseline assessment of all pipelines

that could affect a high consequence

area. The integrity of these pipelines

was to be assessed by internal

inspection, pressure test, or equivalent

alternative new technology. The

assessment had to be completed in

seven years, with 50% of the pipeline

mileage done in three and one-half

years.

• Continual assessment of all

pipelines that could affect a high

consequence area. An operator would

have to continue to assess, at intervals

not to exceed ten-years, and periodically

evaluate the integrity of the pipelines.

• Data integration. An operator would

have to integrate all information about

the pipeline from diverse sources to

analyze the entire range of threats to a

pipeline’s integrity.

• Prompt remedial action. An

operator would have to take prompt

action to address all integrity issues

raised by the integrity assessment and

data integration analysis.

• Preventive and mitigative measures.

An operator would have to evaluate the

need for additional measures to prevent

and mitigate pipeline failures, such as

installing emergency flow restricting

devices (EFRDs) and establishing or

Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations 75379

modifying systems that monitor

pressure and detect leaks.

• Performance measures to measure

the effectiveness of the program.

The proposed rule permitted two

options in establishing baseline and

continual assessment schedules. An

operator choosing the first option would

have to base the schedule on specified

risk factors. With the second option, an

operator would base the schedule on

risk factors the operator considered

essential in risk or consequence

evaluation.

The NPRM explained in great detail

the background of the proposed rule for

the integrity management program (65

FR 21695; April 24, 2000).

In the NPRM, we said that we

intended to apply integrity management

program requirements to all regulated

pipeline operators but that we would

implement the requirements in several

steps; when we were done, all regulated

operators would be required to have an

integrity management program. We

explained that because natural gas and

hazardous liquid have different physical

properties, pose different risks, and the

configuration of the systems differ, and

because we needed to gather more

information about smaller liquid

operations, we were beginning the series

of integrity management program

proposals with hazardous liquid

operators operating 500 or more miles of

pipeline. We further stated that

proposed regulatory requirements for

the other operators would soon follow.

The proposed rulemaking was the

culmination of experience gained from

inspections, accident investigations and

risk management and system integrity

initiatives. This experience was the

foundation for proposing a rulemaking

that addressed in a comprehensive

manner NTSB recommendations,

Congressional mandates and pipeline

safety and environmental issues raised

over the years. To recap the history of

the rulemaking—

• The rulemaking addressed several

recommendations NTSB made to OPS

concerning pipeline safety.

(1) Require periodic testing and

inspection to identify corrosion and

other time-dependent damages.

(2) Establish criteria to determine

appropriate intervals for inspections

and tests, including safe service

intervals between pressure testing.

(3) Determine hazards to public safety

from electric resistance welded (ERW)

pipe and establish standards for leak

detection, and 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.

• Our analyses of several pipeline

ruptures in Bellingham, Washington;

Simpsonville, South Carolina; Reston,

Virginia; and Edison, New Jersey,

brought to light 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.

• The rulemaking also addressed

several Congressional mandates to OPS

concerning areas where the risk of a

pipeline spill could have significant

impact.

(1) 49 U.S.C. 60109(a)—prescribe

standards establishing criteria for

identifying gas pipeline facilities

located in high-density population areas

and for hazardous liquid pipelines that

cross waters where a substantial

likelihood of commercial navigation

exists, or are located in a high-density

population area, or are located in an

area unusually sensitive to

environmental damage (USAs).

(2) 49 U.S.C. 60102(f)(2)—prescribe, if

necessary, additional standards

requiring the periodic inspection of

pipelines in USAs and high-density

population areas, and those crossing

commercially navigable waterways, to

include any circumstances when an

instrumented internal inspection

device, or similarly effective inspection

method, should be used to inspect the

pipeline.

(3) 49 U.S.C. 60102(j)—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 standards 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 and Inspection

Initiatives

The proposed rulemaking was also

based on what we had learned about

integrity management programs from

our risk management and pipeline

inspection activities, particularly the

Risk Management Demonstration

Program, the Systems Integrity

Inspection (SII) Pilot Program and the

new high impact format for inspections.

(These programs and activities are

discussed in greater detail in the NPRM

(65 FR 21695).)

In the Risk Management

Demonstration and Systems Integrity

Inspection Pilot Programs, we studied

and evaluated comprehensive and

integrated approaches to safety and

environmental protection. These

approaches incorporated operator- and

pipeline-specific information and data

to identify, assess, and address pipeline

risks, in conjunction with compliance

with existing pipeline safety

regulations. From these programs, we

also learned about the extent and variety

of internal inspection and other

diagnostic tools that hazardous liquid

pipeline operators use in their integrity

management programs.

OPS implemented a systems approach

through a new high impact inspection

format that evaluates pipeline systems

as a whole rather than in small

segments. We found that a system-wide

approach is a more effective and, in

most cases, more efficient means of

evaluating pipeline integrity. As part of

this approach, we have been evaluating

how pipeline operators integrate

information about their pipelines to

determine the best means of addressing

risk. This experience is helping us to

develop detailed inspection guidelines

to evaluate compliance with the

requirements of this rule.

Advisory Committee Consideration

The Technical Hazardous Liquid

Pipeline Safety Standards Committee

(THLPSSC) is the Federal advisory

committee charged with responsibility

for advising on the technical feasibility,

reasonableness, cost-effectiveness, and

practicability of proposed hazardous

liquid pipeline safety standards. The 15

member committee has balanced

membership with individuals having

the requisite expertise who represent

industry, government, and the general

public.

We presented the proposed rule to the

Technical Hazardous Liquid Pipeline

Safety Standards Committee at its

meeting on May 4, 2000. At the request

of various committee members, who

believed that they had not had sufficient

time to review the proposed rule, which

was published in April, 2000, formal

consideration of the proposal was

postponed to September. In preparation

for this consideration, the draft costbenefit analysis was mailed to the

members on June 16, 2000 and the

members were briefed on the proposed

rule in a teleconference on August 24,

2000.

The committee began consideration of

the proposed rule at a September 11,

2000 meeting (by teleconference) and

completed consideration at a September

22, 2000 meeting (by teleconference). At

the September 22 meeting, ten of the

eleven participating THLPSSC members

voted to accept the proposed rule

provided several changes were made.

75380 Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations

One member abstained from the general

vote, but voted on the individual

changes. These changes as well as other

comments including minority views are

described below. A more complete

description can be found in the

transcript of the committee’s

consideration of the proposed rule

which is available in the docket.

Various committee members had

earlier expressed concern about the

quality of the cost-benefit analysis.

Concerns expressed included the lack of

clear articulation of the benefits and the

failure to follow the framework for costbenefit analysis developed for use in

pipeline safety rulemaking. In response

to these concerns, OPS committed to

revise the cost-benefit analysis to be

more consistent with the framework

prior to publication of a final rule.

Discussion of the issue at the September

22nd meeting indicated that members

did not want to delay the issuance of a

final rule, but that they believed that the

quality of the cost-benefit analysis to be

important. The committee voted

unanimously that it could not conclude

that the proposed rule is reasonable at

this time until OPS completed a more

meaningful cost-benefit analysis based

on the framework. The committee

recommended that this be done prior to

issuance of the final rule.

In addition, the committee

unanimously made the following

recommendations for changes to the

proposed rule:

• Add pipeline stress to the list of

risk factors to be considered in

determining the frequency of integrity

assessment.

• Clarify OPS’s responsibility to

identify, generate, publish, and update

maps of high consequence areas.

• Establish time requirements for

completion of repairs following

detection of the defects. The timing may

be tiered.

• Require leak detection capability.

• Specify the date (for example,

January 1995) for acceptability of data

from previously conducted internal

inspections. This date should be

consistent with the proposed 5 year

look-back.

With the exception of item 2

(responsibility for maps), RSPA has

made changes to the final rule that

address each of these recommendations.

RSPA is addressing item 2 in this

preamble, under the topic heading

‘‘Definition of High Consequence

Areas—Identification’’, rather than in

language of the rule. That section

describes the process through which

RSPA intends to make maps identifying

high consequence areas available to the

operators and the public.

In addition to the formal

recommendations of the committee,

individual committee members raised

two issues about which there was

general agreement. The first of these

concerned the need to clarify the

applicability of the rule to offshore

areas. This issue is addressed under the

topic heading ‘‘Applicability (Coverage)

of the Rule.’’ The second of these was

the need to clarify the use of internal

inspection to assess the integrity of pre1970 electric resistance welded (ERW)

pipe. The committee member was

concerned that a footnote in the

proposed rule would preclude internal

inspection of this type of pipe.

Accordingly, RSPA has modified the

rule to address the issue. We discuss the

rule modification later under the topic

heading ‘‘Program Implementation and

Integrity Assessment Time Frames,

Assessment Methods and Criteria.’’

Prior to the meeting, one committee

member had raised the issue of

requirements for emergency flow

restricting devices. RSPA had indicated

that it was considering including

criteria for requiring the use of such

devices. After a brief discussion in the

meeting, the member decided not to

pursue a formal recommendation by the

committee. As discussed later in the

Preamble under the topic heading

‘‘Requirements for Preventive and

Mitigative Measures, including,

Emergency Flow Restricting Devices

(EFRDs) and Leak Detection Devices’’,

RSPA has modified the rule’s provisions

concerning emergency flow restricting

devices.

There was some discussion in the

various meetings that indicated some

concern about how RSPA would be able

to enforce broad requirements for

programs. Some committee members

suggested the need for specific criteria

that inspectors could apply in reviewing

an operator’s program. Although these

discussions did not result in formal

recommendations by the committee,

RSPA has included additional

specificity in the final rule that will aid

in reviewing integrity management

programs. In addition, enforceability is

discussed elsewhere in this preamble.

The committee also discussed three

other issues about which there was not

general agreement. Four members of the

committee believed that the final rule or

a future modification should require

leak detection systems and specify

performance standards for those

systems. The proposed rule did not

propose to require or set standards for

leak detection systems. (Current

regulations require computational

pipeline monitoring leak detection

systems to comply with API 1130, the

industry consensus standard.) Industry

members raised concerns about the

scope of the current proposed rule and

offered to brief the committee at a future

meeting on the range of leak detection

systems currently available. As noted

above, the committee finally

recommended by unanimous consent

that the final rule require that pipelines

affecting high consequence areas have

the capability of detecting leaks. As

explained later in the Preamble under

the topic heading ‘‘Requirements for

Preventive and Mitigative Measures,

including, Emergency Flow Restricting

Devices (EFRDs) and Leak Detection

Devices’’, we have revised the rule to

address this recommendation.

A second area of discussion about

which there was not agreement was a

motion to reduce the time for

completion of the initial baseline

assessment from seven years to three

years. RSPA’s rationale for not reducing

this time frame is discussed elsewhere

in this preamble.

The third area was a motion to reduce

the time interval for subsequent

assessments from ten years to five years.

The committee was evenly divided on

this issue. As discussed elsewhere in

this document under the heading

‘‘Program Implementation and Integrity

Assessment Time Frames, Assessment

Methods and Criteria’’, RSPA has

decided to modify the time interval for

integrity re-assessments subsequent to

the baseline assessment.

Comments to NPRM

We received comments from 36

sources in response to the NPRM:

2 Trade associations with members

affected by this rulemaking

American Petroleum Institute (API)

American Water Works Association

(AWWA)

3 Trade associations with members not

directly affected by this rulemaking

American Gas Association (AGA)

New York Gas Group

Interstate National Gas Association of

America (INGAA)

8 Individual liquid operators

Tosco Corporation

Chevron Pipe Line Company

BP Amoco

Colonial Pipeline Company

Koch Pipeline Company

Equilon Pipeline Company

Enbridge (U.S.) Inc. and Lakehead

Pipe Line Partners

Dynegy Midstream Services

4 Operators not directly affected by this

rulemaking

The Peoples Gas Light and Coke

Company (LDC and intrastate)

Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations 75381

1The Department of the Interior submitted

comments to the docket in the USA rulemaking

(RSPA–99–5455). We will consider and address

those comments in that rulemaking. The DOI

comments we discuss in this rulemaking were made

during the inter-agency meetings.

Tennessee Gas Company (natural gas

transmission)

Enron Pipeline Group(natural gas

transmission)

Consumers Energy (natural gas

transmission and distribution)

2 State agencies

Lower Colorado River Authority

(LCRA)

State of Missouri—Department of

Natural Resources

6 Advocacy groups

Robert B. Rackleff, Friends of the

Aquifer

Pipeline Survivor’s(sic) Association

Environmental Defense

National Pipeline Reform Coalition

Fuel Safe Washington

Harry S. Kottke and Delbert L. Moine,

representing Ohio Pennsylvania

Landowners Association (OPLA)

4 Federal agencies

Environmental Protection Agency,

Region III

Environmental Protection Agency, Oil

Program Center

Department of Energy

National Transportation Safety Board

2 Cities

Austin, Texas

Bellingham, Washington

3 Consultants/Contractors

Batten and Associates

Dr. Neb I. Uzelac

SEFBO

2 Individuals

U.S. Senator John Breaux

Dene Miller Alden

General Comments

Virtually all commenters were

supportive of the need for additional

and stronger regulations in this area,

and provided comments and

suggestions focusing on specific details

and language of the proposed rule.

Commenters generally fell into one of

two groups: those that thought the

general structure of the proposed rule

was adequate and provided the

appropriate balance between

prescriptive requirements and pipelinespecific analysis, and those that

believed the proposed rule was not

sufficiently strong, broad enough in

scope, or specific.

All commenters were positive about

the need for additional communication

among industry, public safety officials,

regulators, and the public concerning

pipeline risks. We have decided to

address the topic of public

communication and interaction in a

subsequent related rulemaking. We will

address these comments in more detail

in that rulemaking.

The trade associations and operators

that are not directly affected by this

rulemaking provided comments in

anticipation of future integrity

management program regulations that

would affect them. We will use these

comments when preparing the proposed

rulemakings for the other operators.

We have summarized the comments

we received under the following topic

areas:

1. Clarity and Specificity in the

Proposed Rule

2. Remedial Actions

3. Review, Approval, and Enforcement

Processes

4. Program Implementation and

Integrity Assessment Time Frames,

Assessment Methods and Criteria

5. Applicability (Coverage) of the Rule

6. Consensus Standard on Pipeline

Integrity

7. Definition of High Consequence Areas

8. Requirements for Preventive and

Mitigative Measures, including,

Emergency Flow Restricting Devices

(EFRDs) and Leak Detection Devices

9. Methods to Measure Program

Effectiveness

10. Cost Benefit Analysis

11. Information for Local Officials and

the Public

12. Appendix C Guidance

In addition, there were a variety of

technical comments and suggestions

concerning specific details of proposed

Appendix C, and other technical

language in the proposed rule. We did

not include discussion of these detailed

technical comments here but we did

consider them in preparing the final

rule and revising the Appendix.

RSPA personnel also had numerous

discussions with representatives from

several federal government agencies

during this rulemaking to resolve issues

the agencies had raised about the

proposed rule. These agencies included

the Environment and Natural Resources

Division of the Department of Justice,

(DOJ/ENRD); Fish and Wildlife Service

(FWS), Bureau of Land Management,

Office of Environmental Policy and

Compliance and National Park Service

from the Department of the Interior

(DOI),1 the Office of Ground Water and

Drinking Water, Oil Program Center,

and Region 3 from the Environmental

Protection Agency (EPA); the National

Transportation Safety Board (NTSB), the

Council on Environmental Quality

(CEQ); and the Office of Management

and Budget. Where we have made

changes to the rule to address comments

these agencies raised during the

discussions, we have so indicated.

1. Clarity and Specificity in the

Proposed Rule

The proposed rule used primarily

performance-based language to allow

operators to use pipeline- and locationspecific information to determine the

necessary integrity management

practices. The proposed rule used

specification language to prescribe the

required elements of an integrity

management program and baseline

assessment plan, the allowable methods

of integrity assessment and the required

intervals for conducting baseline and

continual assessments. The proposed

rule also specified that an operator was

to follow best industry practices unless

a rule section specified otherwise or the

operator could justify reasons for

deviating from such practices and that

the deviation was supported by a

reliable engineering evaluation.

The proposed rule recognized that an

integrity management program was an

evolving program that an operator

needed to continually improve.

API and the liquid operators

supported the proposed rule’s holistic

approach to pipeline integrity

management that incorporated risk

assessment and risk-based decision

making. API further praised the use of

performance-based language in OPS’s

regulations. Koch commented that ‘‘a

pipeline integrity management program

allows an operator to consider the

unique factors that impact a specific

pipeline or pipeline segment and is

more effective in improving pipeline

safety than prescriptive regulations that

treat all pipelines, no matter what their

characteristics or where they are

located, the same.’’

Environmental Defense, other

advocacy groups, and other commenters

maintained that the rule should have

more specific requirements. These

commenters stated that without such

specificity, OPS would not be able to

evaluate the adequacy of operator

programs and enforce the rule. The City

of Austin cautioned against a

performance-based approach and urged

us to clearly define the performance

requirements and standards for

monitoring, inspection and response.

NTSB reiterated its ongoing concern

that OPS have regulations that contain

measurable standards for performance.

EPA Oil Program Center commented

that the proposed rule failed to include

the specific requirements for an

integrity management program or the

process for determining if a pipeline

will affect a high consequence area. The

City of Austin said the rule should

75382 Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations

2Our using performance-based language in the

rule is consistent with the Administration’s policy

of using performance-based standards. (See

Executive Order 12866, Section 1(b) The Principles

of Regulation (September 30, 1993).)

require an operator to determine the

potential impact for a worst case spill.

Colonial Pipeline recommended that the

rule clarify, either in the regulatory

language or through guidance, how

pipelines outside the high consequence

area could affect the area.

API recommended that the rule

recognize the value of planning changes

and allow an operator to make changes

to the baseline assessment plan.

DOJ/ENRD expressed concern that the

proposed rule’s language about an

integrity program being an evolving

program that an operator had to

continually improve left too much to the

operator’s discretion. DOJ/ENRD had

similar concerns with the language

about an operator using and

documenting a practice other than a

standard industry practice. DOJ/ENRD

further thought a deviation from a

standard practice should only be

allowed when new technology is being

used. DOJ/ENRD also strongly urged

substantial revisions of the proposed

rule to improve its enforceability. DOJ/

ENRD wanted clearly stated and

unambiguous requirements for specific

actions that achieve measurable results,

the violation of which subject the

operator to meaningful penalties.

NTSB expressed concern about the

proposed rule’s use of the term best

industry practices without explaining

where these practices could be found.

EPA Region III also questioned who

would be responsible for establishing,

compiling, and disseminating the best

industry practices.

API commented that the term best

industry practices may cause

controversy over its meaning and

suggested that the term proven industry

practices would be more appropriate.

Response:

To achieve effective integrity

management programs that evolve and

take advantage of changing

technologies, the final rule uses both

performance and specification-based

language.

Based on our considerable experience

with performance-based regulations,

OPS believes that performance-based

language will best achieve effective

integrity management programs that are

sufficiently flexible to reflect pipelinespecific conditions and risks.2 However,

we recognize that certain elements of

the rule need to be written in

specification language.

Performance-based standards allow an

operator to select the most effective

processes and technologies as they

become available. OPS wants to create

incentives for operators to invest in the

development of new technology.

Because internal inspection technology

and other integrity monitoring

equipment have changed considerably

in recent years and are expected to

continue to improve, we want to

encourage operators to use and strive to

improve the best available technologies

and processes. Thus, rather than only

specify the use of currently available

technologies, parts of the rule are

performance-based to allow 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 assess and repair pipelines.

The specification parts of the rule

ensure uniformity among integrity

management programs so that they all

address key issues, such as baseline and

continual integrity assessment intervals,

information integration and analysis

requirements, and time frames to review

and analyze integrity assessment results

and to complete remedial actions.

As suggested by commenters, we have

revised the rule to allow an operator to

modify its baseline assessment plan and

to clarify the basis for an operator

changing and improving its integrity

management program. We have added a

provision allowing an operator to

modify its baseline assessment plan so

long as the operator documents the

modification and reasons for the

modification. An operator would have

to document any modification at the

time the decision is made to modify the

plan, not at the time the modification is

implemented. OPS enforcement

personnel would review these

supporting documents during a field

inspection.

Although reworded, the rule still

provides that an integrity management

program is a continually changing

program. However, the rule now

specifies that an operator must

continually change the program to

reflect operating experience,

conclusions drawn from results of the

integrity assessments, and other

maintenance and surveillance data, and

evaluation of consequences of a failure

on the high consequence area. The rule

also clarifies that an operator’s integrity

management program will evolve from

the initial program framework the

operator develops.

We have revised the rule to clarify

that the integrity management program

requirements apply to each pipeline

segment that could affect a high

consequence areas. An operator’s

program must address the risk factors

each pipeline segment poses to a high

consequence area.

The proposed rule specified required

elements of an operator’s integrity

management program. Other than some

minor word changes and edits, we have

not changed those elements in the final

rule. We believe these elements will

ensure sound integrity management

programs.

However, to address commenters’

concerns that the proposed rule failed to

specify a process for determining if a

release could affect a high consequence

area, we have added two related

requirements: that, as a first step, an

operator identify all pipeline segments

that could affect a high consequence

area and also include a process in its

program for identifying which pipeline

segments could affect a high

consequence area. (Identifying those

segments that could affect an area

involves determining if a release from a

segment in or near a high consequence

area could affect the area.) Although we

did not propose these requirements in

the notice, we believe they were

implicit. Whether explicitly stated or

not, an operator would have to identify

which pipeline segments could affect a

high consequence area before

determining how the line pipe in those

segments would be assessed. Moreover,

since the trigger for the integrity

management program requirements is

whether a pipeline segment could affect

a high consequence area, an essential

element must be a process for

identifying those pipeline segments that

could affect the defined high

consequence areas. In the Appendix to

the rule, we have also provided

guidance to help an operator in

identifying high consequence areas and

in evaluating how a pipeline release

could affect a high consequence area.

This guidance will help an operator in

developing the required process.

The final rule requires that an

operator follow recognized industry

practices unless the rule otherwise

requires a different practice or the

operator can demonstrate that an

alternative practice is supported by a

reliable engineering evaluation.

Paragraph (b)(3) does not affect an

operator’s obligation to comply with all

other requirements in this rule. In the

final rule, we have changed the term

best industry practices to recognized

industry practices. We believe this is an

easily understood term by operators and

enforcement personnel. Recognized

industry practices include those found

in national consensus standards or

reference guides, and generally conform

to the practices of the American

Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations 75383

National Standards Institute.

Companies’ successful use of these

practices helps determine their validity

and acceptance. We have further revised

the provision to clarify the basis for an

operator using an alternative practice.

The rule now provides that an

operator’s selection of an alternative

must be based on a reliable engineering

evaluation. Use of an alternative must

provide an equivalent level of public

safety and environmental protection. An

operator must document its use of an

alternative practice from when the

operator makes the decision to use the

alternative. An operator must be able to

provide the documentation to OPS

enforcement personnel for review

during a field inspection.

We have not limited an operator’s use

of alternative practices to only when

new technology is being used. For

example, an alternative practice could

be one that has been successfully used

in other countries or by other pipeline

companies but has not yet been codified

into a national consensus standard. OPS

wants to encourage operators to use

innovative practices that are based on

sound engineering judgment. OPS also

wants to encourage innovation in

technology and recognizes that an

existing technology may be improved

and given a new application.

We have also revised language

throughout the rule to make the rule

clearer and more understandable. These

changes have not affected the

requirements of the rule, most have

simply been made to improve the rule’s

overall clarity and to ensure the

consistency in use of terms. Others have

been made to address DOJ’s concerns

about making the rule more specific and

enforceable and clarifying the operator’s

required responsibilities under the rule.

Any substantive changes are discussed

in this document.

2. Remedial Actions—Proposed Section

195.452(g)

The proposed rule required an

operator to take prompt action to

address all pipeline integrity issues

raised by the integrity assessment and

data integration analysis. The rule

proposed that an operator evaluate and

repair all defects that could reduce a

pipeline’s integrity, and establish an

evaluation and repair schedule. The rule

did not propose time frames for making

the repairs, other than an operator could

not operate the affected part of its

pipeline system until it had corrected a

condition presenting an immediate

hazard. The NPRM also asked for

comment on whether the rule should

contain specific time lines for

conducting repairs.

API was against specific time lines

and said that criteria for when repairs

should be implemented could not be

reduced to simple statements suitable

for inclusion in the rule. API added that

the consensus standard will offer

guidance to operators. Enbridge stated

that a one-size-fits-all time frame for

conducting repairs is not practical or

technically justified; however, Enbridge

said that it supported the goal of

ensuring that no imminent hazard is left

unaddressed.

Environmental Defense recommended

a relatively short time to conduct repairs

after serious defects are identified, e.g.,

one month to complete repairs unless

pipeline pressure is significantly

reduced. The City of Austin said that

the rule should include repair time

lines, acceptable methods of

remediation and a better definition of

what pipeline flaws constitute an

immediate hazard. The City of

Bellingham also recommended that the

rule establish a specific and expeditious

deadline for conducting repairs. EPA

Region III commented that the proposed

rule did not define what conditions

constituted immediate hazard

conditions.

Peoples Energy commented that the

proposed language about which

anomalies an operator had to evaluate

and repair only applied to defects that

could reduce integrity. Peoples Energy

pointed out that this determination

could not be made until an operator

reviewed all data.

DOJ/ENRD questioned the ability to

enforce performance-based standards,

particularly with respect to the

proposed repair provisions. DOJ/ENRD

requested that the regulation be written

in language that requires an operator to

take specific action. DOJ/ENRD based its

concerns on its experience with

enforcing the Clean Water Act. DOJ/

ENRD was particularly concerned that

the proposed rule would not ensure that

repairs were made before failures

occurred and strongly recommended

that language be added specifying when

an operator would have to make repairs

on the pipeline. DOJ/ENRD also strongly

urged that the rule include a provision

establishing a cut-off time for when an

operator had to review and analyze the

results from an internal inspection, and

recommended a phased-in approach.

Response: We have rewritten the

remedial action section of the final rule

to accommodate DOJ/ENRD’s and other

commenters’ concerns. To be consistent

with the wording used to describe

required program elements, we have

renamed the section to reflect the

broader actions an operator must take to

address integrity issues raised by the

assessments. The rule has been revised

to specify time frames for reviewing and

analyzing the results of an integrity

assessment and for completing repairs

of certain conditions (see § 195.452(h)).

The rule still requires an operator to

take prompt action to address all

pipeline integrity issues raised by the

integrity assessment and information

integration. The rule now clarifies that

an operator is required to evaluate all

anomalies and repair those that could

affect the pipeline’s integrity. Prompt

action means that an operator must

make the repair as soon as practical.

However, an operator must prioritize

the repairs according to the severity of

each anomaly and address first those

anomalies that pose the greatest risk to

the pipeline’s integrity.

The rule now requires that an

operator complete repairs according to a

schedule that prioritizes anomalies

found during the integrity assessment

for evaluation and repair. In this

schedule, an operator would have to

provide for review and analysis of the

integrity assessment results by a date

certain. The review and analysis must

be done by a qualified person (i.e., a

person who has the requisite knowledge

and technical expertise to review the

results and analyze the data.) For the

first three years after the rule’s effective

date, an operator would determine the

period by which the results would have

to be reviewed and analyzed and

commit that date in writing in its

schedule. After the third year, an

operator’s schedule must provide for

review and analysis of the integrity

assessment results within 120 days of

conducting each assessment. The rule

allows more flexibility in the first three

years so that OPS can review the

adequacy of time frames operators

establish, and gather sufficient

information to determine what the

required standard for review and

analysis of assessment results should be.

OPS recognizes that a time frame

depends, in part, on the availability of

persons with expertise to evaluate the

data. OPS further recognizes that a

quality review and analysis takes time.

By the end of the third year OPS will

have sufficient information to be able to

determine if it should revise the 120-day

required period.

An operator’s schedule also has to

provide time frames for evaluating and

completing repairs. A qualified person

must conduct the evaluation (i.e., a

person with the requisite knowledge

and technical expertise.) Because an

operator must prioritize the repairs, the

rule provides that the operator is to base

the repair schedule on specified risk

factors and pipeline-specific risk factors

75384 Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations

the operator develops. For conditions

not specified in the rule, the operator

determines the schedule for evaluation

and repair. However, the rule provides

the time frames in which an operator

must complete repair of certain

conditions on the pipeline. These

conditions are listed as immediate

repair conditions, 60-day conditions

and 6-month conditions. The time frame

required for repair starts at the time the

operator discovers the condition on the

pipeline, which occurs when an

operator has adequate information about

the condition to determine the need for

repair. Depending on circumstances, an

operator could have adequate

information when the operator receives

the preliminary internal inspection

report, gathers and integrates

information from other inspections or

the periodic evaluation, excavates the

anomaly, or receives the final internal

inspection report.

In the proposed rule we used the term

immediate hazard for certain

conditions, and referenced § 195.401(b).

In the final rule we refer to these as

immediate repair conditions and

identify several. Under § 195.401(b), an

immediate hazard condition requires

that an operator shut down the pipeline

until the operator has corrected the

condition. With an immediate repair

condition, as long as safety is

maintained, an operator will either be

able to temporarily reduce operating

pressure or shut down the pipeline until

the operator can complete the repair of

the condition.

An operator may deviate from the

rule’s specified repair times if the

operator justifies the reasons why the

schedule cannot be met and that the

changed schedule will not jeopardize

public safety or environmental

protection. OPS enforcement personnel

will review any justifications and

supporting documents during site

inspections. In certain cases when an

operator cannot meet the required

schedule and cannot provide safety

through a temporary reduction in

operating pressure, the operator must

notify OPS. This will allow OPS to

determine the extent of review needed

and if an inspection is needed. The rule

specifies how an operator must notify

OPS.

In the NPRM we discussed the

consensus standard that an ANSI

workgroup was developing on integrity

management. OPS has been

participating in the work group. In the

notice, we said that we would consider

adopting all, or part of, the standard

once it was final, but only after public

notice and comment. (More discussion

about the consensus standard appears

later in this document under the topic

heading ‘‘Consensus standard on

pipeline integrity.’’) The standard is not

yet final. However, OPS is basing the

provisions in section 195.452(h) on

initial indications of what will be in the

final consensus standard. We believe

that the criteria being considered by the

standard’s workgroup adequately

address pipeline integrity concerns

because the criteria are based on a

structured methodology for evaluation

of internal inspection devices data. The

methodology is a recognized industry

practice. The criteria are also based on

well-established consensus standards,

such as the American Society of

Mechanical Engineers (ASME) B31.4

standard. ASME B31.4 is a widelyrecognized and long accepted standard

on liquid transportation systems for

hydrocarbons, liquid petroleum gas,

anhydrous ammonia, and alcohols. (The

regulations in 49 CFR Part 195 were

developed from ASME B31.4.)

Although a consensus integrity

standard is not yet final, we have made

available at OPS’s website, notes of the

meetings, and a peer review draft of the

standard on Managing Pipeline System

Integrity. The standard is expected to be

completed and published in December,

2000.

We recognize that we have completely

restructured the section of the rule

pertaining to actions an operator must

take to address pipeline integrity issues.

Because of the extensive changes to this

section of the rule, we are allowing 60

days comment on the provisions in

section 195.452(h). Based on the

comments we receive, we will consider

modifying the provisions. At the end of

the comment period, we will either

issue a modification or a notice stating

that the section stands as written.

An operator has one year from the

effective date of the rule to develop the

framework for an integrity management

program. An operator has 31⁄2 years

from the rule’s effective date to conduct

a baseline integrity assessment of the

highest risk line pipe segments. An

operator is not likely to take remedial

actions required by this rule until after

the integrity assessment. Thus, remedial

action criteria are not needed until some

time after the rule’s effective date. We

expect to issue any modifications so that

operators have ample time to

incorporate the modifications into their

program framework. If we are delayed in

issuing the modification so that

operators do not have adequate lead

time, we will then consider further

delaying the compliance date for section

195.452(h). Until OPS announces a

modification, operators can base their

program remedial action criteria on

those set forth in this rule.

3. Review, Approval and Enforcement

Processes

Some commenters questioned why

the proposed rule did not provide for

adequate and timely OPS review and

approval of an operator’s baseline plan,

integrity assessments, and integrity

program. The proposed rule requires an

operator to maintain for inspection

written documentation of its program

and assessment plan, and of any

evaluation or analysis made to support

a decision or action. The rule did not

propose requirements for formal

transmittal of baseline assessment plans,

assessment results, or integrity

management programs to OPS for

approval.

Lower Colorado River Authority

(LCRA) supported the flexibility of a

performance-based approach but

cautioned that the commensurate

accountability component seemed to be

missing. LCRA explained that the

proposed rule did not provide a

mechanism for OPS review, or approval

of critical decisions made by an operator

or indicate that OPS would have any

involvement in program

implementation. The City of Austin

maintained that the proposed rule

seemed to continue reliance on the

regulated community to implement

pipeline safety regulations at their own

discretion, with only minimal

regulatory oversight. The City of Austin

cautioned that close regulatory review

and oversight are needed and strongly

urged OPS to require all integrity

management programs to be submitted

for OPS approval, as well as assessment

reports.

EPA Oil Program Center expressed

concern that the proposed rule relied

‘‘heavily on a pipeline operator’s

assessments, assumptions, and

evaluations, yet requires no formal

approval process by the Office of

Pipeline Safety or certification by a

third party, such as a Professional

Engineer.’’

Several commenters questioned OPS’s

ability to adequately enforce the

proposed rule because of inadequate

data, knowledge, or expertise. EPA

Region III stated that the bulk of

expertise in this subject area seemed to

reside with the pipeline industry

because of the proposed rule’s reliance

on industry’s efforts to evaluate and

resolve risk issues concerning pipelines.

Region III further stated that OPS must

obtain and/or develop independent

expertise and knowledge for effective

oversight. Friends of the Aquifer

commented that because of the lack of

Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations 75385

accurate data about pipeline spills, OPS

would not be able to judge the adequacy

of the risk factors included in an

operator’s plan.

Response: OPS agrees that an effective

and credible inspection process is

critical to achieving the objectives of the

rule. OPS is developing protocols and

criteria for detailed inspection of

operator baseline assessment plans and

integrity management programs to

ensure that operators comply with the

requirements of the rule, and that

operators use structured, documented,

and technically defensible processes

and models to support assessment

priorities and time frames, decisions on

remediation, prevention and mitigation,

and measures of program effectiveness.

OPS has already developed expertise

in enforcing performance-based

regulations and in evaluating risk-based

decision processes. OPS has contracted

for additional training in specific

technical areas to improve the

qualifications of its enforcement

personnel. OPS plans to have a

sufficient base of trained enforcement

personnel who will review the integrity

management programs during on-site

inspections of pipeline operators. OPS

will contract for any needed technical

expertise to supplement the knowledge

of its enforcement personnel.

We are not requiring formal approval

of an operator’s integrity management

program or of decisions and analyses

made to develop and implement the

program. Rather, a multi-disciplined

team composed of OPS regional

inspectors, and technical specialists

from headquarters will conduct integrity

management program inspections. In

addition, OPS will contract for other

technical expertise, as needed. We are

also planning how best to involve state

pipeline safety inspectors in the review.

We have also added requirements that

an operator provide advance notice to

OPS when the operator plans to use

other technology (other than internal

inspection or pressure test) for a

baseline or continual integrity

assessment or intends to justify a longer

continual assessment period. (We

discuss these advance notice

requirements later in the document.) We

determined that an advance notice

requirement was necessary in certain

instances to give OPS enforcement

personnel additional time to review and

evaluate an operator’s rationale and

supporting documentation.

The rule continues to require an

operator to document all aspects of its

integrity management program so that

OPS enforcement personnel can review

these documents during an inspection

to determine an operator’s compliance

with the rule. We have clarified the

language in the final rule concerning the

types of documents an operator is

required to maintain. Required

documents include those to support

decisions and analyses made, as well as

modifications, justifications, deviations,

variances and determinations made, and

actions taken to implement and evaluate

each of the required program elements.

This requirement is no different from

other requirements in the pipeline

safety regulations that an operator

maintain current maps and records of its

pipeline system, maintain a procedural

manual for operations, maintenance and

emergencies and maintain other records

of tests and inspections. In Appendix C

we have provided some examples of

records an operator would have to

maintain for inspection. We also discuss

recordkeeping requirements in greater

detail later in this document in the

section by section analysis (section

195.452(1)).

4. Program Implementation and

Integrity Assessment Time Frames,

Assessment Methods and Criteria—

Proposed Sections 195.452(b)–(e) and (j)

The notice proposed that an operator

develop and follow a written integrity

management program within one year

after the final rule’s effective date. The

proposed rule included a seven-year

time frame for the baseline assessment,

with an operator having to assess 50%

of the mileage within 3.5 years, and a

ten-year maximum interval for

continual integrity re-assessments. The

notice proposed that an operator

conduct the integrity assessment by

internal inspection, pressure test, or

new technology that could provide

equivalent protection to the other two

methods.

The proposed rule disallowed use of

a magnetic flux leakage or ultrasonic

internal inspection device for a pipeline

segment constructed of low frequency

ERW pipe or lapwelded pipe

susceptible to longitudinal seam

failures. This was done to be consistent

with current requirements in section

195.303 providing that an operator’s

program for testing a pipeline on riskbased criteria provide for pressure

testing of a segment constructed of

either of those types of pipe.

The notice also proposed allowing as

a baseline assessment an integrity

assessment that an operator had

conducted within five years prior to the

effective date of a final rule.

The proposed rule permitted an

operator to choose between two options

in establishing baseline and continual

assessment schedules. The first option

specified risk factors to use in

establishing the schedule. The second

option permitted an operator to base the

schedule on risk factors the operator

considered essential in risk or

consequence evaluation. This option

would have given an operator some

flexibility to establish re-assessment

intervals exceeding ten years.

Implementation

API recommended that program

implementation be keyed to OPS

making available to operators a

complete set of maps designating the

high consequence areas rather than to

the final rule’s effective date.

The National Pipeline Reform

Coalition objected to the one-year

program development period based on

OPS’s estimate in its cost/benefit

analysis of how long it would take an

operator to develop an integrity

management program. OPS had

estimated 430 hours.

Assessment Time Frames

API and the industry commenters

suggested that OPS establish January 1,

1995 as the cut off date for acceptability

of prior integrity assessments, rather

than tying the cutoff date to a final rule

date. Enbridge and Lakehead asked that

operators be allowed to justify older

assessments, rather than OPS arbitrarily

excluding those older than five years.

API also said that the proposed sevenyear baseline and ten-year re-assessment

periods were reasonable, and would

allow operators to make decisions based

on the characteristics of their pipeline

system.The hazardous liquid operators

re-iterated and concurred with API’s

comments.

Advocacy and environmental groups,

and other commenters objected to the

proposed seven-year baseline

assessment and ten-year re-assessment

periods. Some also objected to allowing

a five-year old prior assessment to

satisfy the baseline assessment.

Environmental Defense suggested a

three-year maximum, only allowing

baseline assessments that have occurred

within two years of the rule. For the

continual re-assessment interval,

Environmental Defense recommended

that OPS follow the California model,

and require re-assessment every five

years. The City of Bellingham suggested

that baseline assessments should be

completed in one to three years, and

periodic updates within five years. Fuel

Safe Washington objected to allowing

any prior baseline assessments, and

suggested that baseline assessment be

completed within 18 months, and that

re-assessment be required at a maximum

of five years, three years for pipelines

constructed prior to 1970, and one year

75386 Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations

for pipelines located in unusually

sensitive environmental areas. Pipeline

Survivor’s Association argued that

baseline assessments should be

completed in three years, with 50% of

that mileage being assessed in 18

months, prior assessments be limited to

one year before the rule, and reassessments intervals be shortened to

five years. The City of Austin

recommended five years for establishing

the baseline, 2.5 years to complete 50%

of the baseline, and five years for

reassessment. Batten & Associates

recommended a baseline assessment

period of three years, limiting prior

allowable integrity assessments to one

year before the rule’s effective date, and

re-assessment intervals of three years.

LCRA recommended a seven-year time

frame for completing the baseline

integrity assessment and shortening the

ten-year time frame for re-assessment in

some instances based on pipelinespecific risk factors (e.g., age of pipe,

leak history, etc.).

Several federal agencies also objected

to the proposed integrity assessment

time frames. NTSB urged us to reduce

the period for the baseline assessment

because it could not find sufficient data

in the proposed rule to justify the sevenyear period. EPA Oil Program Center

suggested a five-year time frame for

completing the baseline, with 50% of

the mileage completed within 30

months. EPA Region III also

recommended a five-year continual

assessment period because it would

provide useful integrity/deterioration

information, without imposing too great

a burden. DOJ/ENRD raised concern

with the proposed seven-year baseline

and ten-year continual assessment

intervals and strongly recommended

shorter baseline and continual integrity

assessment intervals. DOJ/ENRD said

OPS could not demonstrate that defects

would not propagate to failure within

the proposed seven-year period. DOJ/

ENRD also questioned the basis for

OPS’s assumption that a ten-year

interval was reasonable if a pipeline was

adequately cathodically protected.

Assessment Schedule Criteria

The City of Austin recommended

eliminating Option 2—allowing an

operator to establish an assessment

schedule based on factors it determines

essential—because it would not be

feasible for an operator to demonstrate

‘‘an equivalent level of safety and

environmental protection as Option 1

given the extremely complex interworkings of the many potential risk

factors.’’ The advocacy groups argued

for dropping Option 2 from the rule

because it provided the operator too

much discretion. EPA Region III also

stated that Option 2 may provide ‘‘too

loose a regimen’’ and supported the

approach described in Option 1.

Environmental Defense preferred ‘‘a

modified Option 1 in which operators

could identify and report any additional

risk factors to those specified in the

rule.’’ The National Pipeline Reform

Coalition also recommended

eliminating Option 2 because Option 1

allowed enough flexibility for an

operator to determine that a specified

risk factor had little or no applicability

to its operations and discount the factor.

Several commenters suggested risk

factors that the rule require for

establishing assessment frequency.

NTSB recommended that OPS not let an

operator determine what factors are

essential for ensuring a pipeline

system’s safety and environmental

protection; rather the rule should

specify minimum factors that an

operator must consider in establishing

an assessment schedule. NTSB

suggested these factors include the

results from previous inspections, the

pipeline’s leak history, material and

coating conditions, cathodic protection

history, type of pipe seams, product

transported, operating pipe stress levels,

defect types and sizes detectable by the

inspection method used, defect growth

rates, and effectiveness of actions taken

to correct chronic problems, such as

corrosion. EPA Region III suggested that

risk factors for establishing frequency of

assessment should also include, product

specific differences, location related to

the ability of the operator to detect and

respond to a leak (e.g., pipelines deep

underground) and non-standard or other

than recognized pipeline installations

(e.g., horizontal directional drilling).

National Pipeline Reform Coalition

suggested risk factors such as pipe

material and manufacturing processes,

highly corrosive soils, and highly

volatile products being transported.

Dynegy suggested that highly volatile

liquids not be treated as other hazardous

liquids because they do not pose the

same potential for damage to sensitive

environmental areas. SEFBO

recommended that the rule distinguish

overhead suspension pipeline bridges

from other above ground pipeline

support structures because more

sophisticated skills and experience are

required to inspect and maintain cable

structures. Sen. Breaux also urged that

we address the role of these bridges in

high consequence areas.

Assessment Methods

API expressed satisfaction that the

proposed rule not only recognized that

internal inspection tools provide

valuable information but also

recognized that a single tool or integrity

assessment methodology is not always

the answer, and that integrity can be

assessed by various inspection methods.

API and Equilon, however, suggested

that we delete the footnote in the

proposed rule preventing operators from

using magnetic flux or ultrasonic

internal inspection tools on low

frequency electric resistance (ERW)

welded pipe. API suggested language to

ensure that the integrity of ERW seams

is adequately assessed. Colonial

Pipeline was pleased that the rule

recognized the value of internal

inspection technology and recognized

that technology is constantly evolving.

Koch suggested that the rule allow an

alternative assessment methodology in

situations where it would be

appropriate to conduct an assessment by

means other than internal inspection,

pressure test, or equivalent new

technology. Peoples Energy questioned

why the proposed rule did not allow for

use of current technology, such as sonic

or optical methods, that could be made

feasible for pipelines.

Dynegy pointed out that a leak during

a hydrostatic test could damage the

environment and that installing magnets

needed for instrumented internal

inspection could also damage an area.

Response:

Implementation

The final rule keeps the one-year

period from the rule’s effective date for

an operator to develop an integrity

management program. However, the

rule now requires that an operator

identify all pipeline segments that could

affect high consequence areas within

nine months from the rule’s effective

date. Although implicit that an operator

would have to identify the pipeline

segments that were covered by the rule,

the proposed rule did not propose that

an operator do this. Because

identification is a necessary first step in

the integrity management process, we

did not think it unreasonable to make it

an explicit requirement.

We have also clarified that during the

first year an operator must develop a

program framework that addresses each

element of the integrity management

program. The rule further clarifies that

a program begins with the initial

framework. Once the program

framework is developed, an operator

will then have to implement and follow

the program. Because an integrity

management program is dynamic, the

rule provides that an operator must also

continually change the program as the

operator gains experience.

Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations 75387

Assessment Intervals

We have not revised the time period

for an operator to conduct a baseline

assessment. OPS believes that a sevenyear baseline integrity assessment cycle

will result in a higher quality integrity

assessment and analysis of the

assessment results to better ensure the

integrity of each pipeline segment.

Further, OPS believes that this schedule

will effectively double the rate of

assessment currently being conducted.

Finally, we decided not to establish a

shorter baseline interval because an

analysis OPS conducted found that

internal inspection resources needed to

meet demand for baseline assessment

are marginally adequate until the year

2007. This finding took into account

resources that will be needed

concurrently for other assessments

(apart from those this rule requires).

(See memorandum from Noel

Duckworth, dated October 1, 2000. This

memorandum is in the docket.) We

expect that internal inspection will be

the primary choice of operators.

Moreover, once we establish similar

integrity management program

requirements for liquid operators with

smaller operations and for natural gas

operators, these operators will all be

drawing on the same market of vendors.

Thus, to ensure that operators have

adequate time to conduct high quality

integrity assessments and to analyze the

results from the assessments, we have

kept the seven-year baseline interval.

Moreover, to ensure that the highest

risk pipe is assessed early in the cycle,

we have clarified that an operator must

assess at least 50% of the pipe,

beginning with the highest risk pipe, in

the first 3.5 years of the seven-year

baseline period. This requirement,

coupled with the requirement to base

the assessment intervals on risk-based

factors and analyses, should ensure that

an operator assesses the highest risk

segments in a shorter time frame. An

operator’s schedule and rationale for

establishing the assessment intervals are

subject to review during an inspection.

The rule continues to allow as a

baseline assessment an integrity

assessment that an operator has

conducted five years before the rule’s

effective date. However, we have

revised the rule so that if an operator

chooses to use a prior integrity

assessment, the operator must then reassess the pipe segment according to the

continual integrity re-assessment

requirements (discussed below). We

believe that some operators will opt for

using a prior integrity assessment to

address integrity issues on a pipeline

segment that need prioritized remedial

action.

One of the greatest concerns

expressed by Federal government

agencies, environmental groups and

other advocacy groups (as discussed

above) was that the proposed ten-year

continual re-assessment interval was too

long to ensure public safety and

environmental protection. Because of

the concern expressed, we did

additional research and reconsidered

the issue. Based on what we found, we

have revised the final rule to shorten the

continual re-assessment interval. The

rule now requires an operator to

establish intervals not to exceed five (5)

years for continually assessing the line

pipe’s integrity, unless the operator can

demonstrate that one of the limited

exceptions applies.

In deciding on the five-year interval,

we relied extensively on an analysis

OPS conducted on internal inspection

devices (Noel Duckworth memorandum

dated October 1, 2000). The analysis is

available in the docket. The analysis

found that, in 1999, the three major

internal inspection devices vendors in

the U.S. logged 30,000 miles, at 68%

utilization capacity, and in 2000, the

vendors expect to log 45,000 miles at

90% utilization (maximum attainable).

According to the memorandum, the

analyst estimated that the total capacity

of these three internal inspection device

vendors would likely increase to about

87,000 miles by 2007. Our current

estimates indicate that this rule is likely

to apply to 35,500 miles of hazardous

liquid pipeline. (Because of the location

of pig launchers and receptors, which

are typically located near pump stations

50 miles apart, operators will be

internally inspecting more than the

35,500 miles of hazardous liquid

pipeline required under the rule. We

expect that at least 25–30% additional

mileage or 44,375 miles will be

internally inspected.) Additional

internal inspection requirements will

also be generated by future rules that

will apply to smaller hazardous liquid

operators and to natural gas operators.

Therefore, according to the Duckworth

memorandum, the three big vendors

should be able to meet the demand for

internal inspection devices, although

demand will stress the capacity of the

market. The memorandum noted that

more is involved in integrity assessment

than just running the internal inspection

devices, and analyzing the data, but also

about the planning/scheduling process

between internal inspection tool

companies and pipeline operators.

Based on these findings, coupled with

the insistent urging of several federal

agencies (DOJ, NTSB, and EPA), and

many other commenters, who argued

that a shorter continual integrity reassessment interval was essential to

protect public safety and the

environment, we have reduced the reassessment interval to a general

requirement of five years, providing for

exceptions.

The five-year integrity re-assessment

period is not absolute. The rule allows

variance in limited instances from the

five-year period: when there is an

engineering basis for a longer period or

when the best technology needed to

assess the segment is temporarily

unavailable. For example, an operator

may be able to justify an engineering

basis for a longer assessment interval on

a segment of line pipe, if the operator

can support the justification by a

reliable engineering evaluation

combined with the use of other

technology, such as external monitoring

technologies, that provides an

equivalent understanding of the

condition of the line pipe. Or an

operator may require a longer

assessment period for a segment of line

pipe because the best assessment

technology, given the risk factors of the

segment, is not available. An operator

would then have to justify the reasons

why it could not comply with the

required assessment period and also

demonstrate the actions it is taking to

evaluate the integrity of the pipeline

segment in the interim. In either

instance, an operator would have to

notify OPS before the end of the fiveyear period that the operator will be

justifying a longer period. If the

justification is based on engineering

reasons, the operator must provide nine

months notice before the end of the fiveyears. For unavailable technology, the

operator must provide 90-days notice.

Advance notice will give OPS sufficient

lead time to review an operator’s

justification and supporting documents.

The rule continues to require that an

operator base both the baseline and

continual assessment intervals on the

risk the pipeline segment poses to the

high consequence area. To establish the

assessment intervals, the rule requires

that an operator use specified risk

factors, the analysis of the results from

the last integrity assessment, and

information from the integration

analyses. These factors and information

will help the operator to prioritize the

pipeline segments for assessment.

OPS inspectors will carefully evaluate

each operator’s methodology for

determining the baseline and continual

integrity assessment schedules to ensure

that the highest risk segments are being

addressed in the earliest time frames.

OPS inspectors will also review an

75388 Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations

operator’s justification for deviating

from the required five-year reassessment interval. We have added the

requirement for advance notice to OPS

when an operator may vary from the

five-year interval so that OPS inspectors

have adequate time to review and

evaluate the justification supporting the

variance.

Assessment Criteria

We agree that appropriate flexibility

for establishing an assessment schedule

based on risk factors can be achieved by

modifying Option 1 and deleting Option

2. The final rule requires that an

operator base its integrity assessment

schedule on all risk factors that reflect

the risk conditions on the pipeline

segment. The rule also specifies certain

factors that an operator must consider.

These factors include those we

proposed in the NPRM plus others

suggested by NTSB, EPA, the THLPSSC

and other commenters. However, the

rule does not preclude an operator from

including other risk factors specific to

the pipeline being assessed. OPS wants

to encourage operators to supplement

the specified risk factors with factors

relevant to the pipeline segment being

assessed.

We have not changed the final rule to

establish separate requirements for

highly volatile liquids and other

hazardous liquids, or for overhead

suspension pipeline bridges. However,

because highly volatile liquids and

overhead suspension bridge pipelines

may pose unique risks to a high

consequence area, an operator’s

integrity management program must

consider and address these risks. In the

rule, we have added pipeline

suspension bridges and product

transported to the list of factors an

operator must consider when

establishing an assessment schedule.

The Appendix provides an operator

further guidance on establishing

integrity assessment intervals.

Assessment Methods

The rule continues to allow a choice

in the integrity assessment method—

internal inspection tool, pressure test, or

other technology that an operator

demonstrates can provide an equivalent

understanding of the condition of the

line pipe. We did not provide for

another assessment method in lieu of

the three permitted methods. We believe

that the three permitted methods give an

operator sufficient flexibility to conduct

integrity assessments appropriate to

each pipeline segment that must be

assessed.

The rule provides that an operator

choosing assessment by internal

inspection must use a tool or tools

capable of detecting corrosion and

deformation anomalies, including dents,

gouges and grooves.

We have revised the rule to delete the

footnote about not using a magnetic flux

leakage or ultrasonic internal inspection

tool on ERW pipe. We recognize that

technology in the internal inspection

industry has been changing rapidly.

Now, there are readily available tools,

for example, ultrasonic (shear wave) and

circumferential magnetic flux leakage

tools, that can detect longitudinal seam

failures. Therefore, the rule now allows

an operator to use integrity assessment

methods on ERW pipe and on

lapwelded pipe susceptible to

longitudinal seam failures that can

assess seam integrity and can detect

corrosion and deformation anomalies.

An operator’s integrity management

program would also have to address the

special risks of these types of pipe.

In the final rule we clarified that a

pressure test must be conducted

according to the requirements for

pressure testing found in Part 195,

subpart E. An operator choosing to

assess by pressure test should also

evaluate its corrosion control program

before deciding on this option.

OPS inspectors will review the

operator’s selection of assessment

methods for the relevant pipeline

segments. OPS personnel will

particularly look at the adequacy of the

operator’s corrosion control program

when evaluating an operator’s choice to

pressure test.

We used the term new technology in

the proposed rule as an operator’s third

option. In the final rule, we changed

that term to other technology. Other

technology would include new or

existing technology that is adapted for

pipeline use and provides an equivalent

understanding of the condition of the

line pipe as the other two methods. We

have also changed the language that the

other technology must provide an

equivalent level of protection in

assessing the integrity of the line pipe to

that it must provide an equivalent

understanding of the line pipe. We

believe this language better reflects what

an assessment tool does i.e., it does not

protect the pipe but gives the operator

an understanding of the condition of the

line pipe.

If an operator chooses other

technology as its assessment method,

the operator must notify OPS 90 days

before using the technology so that OPS

has adequate time to review the

technology.

5. Applicability (Coverage) of the Rule—

Proposed Section 195.452(a)

The proposed rule applied to

operators that operate 500 or more miles

of hazardous liquid pipeline used in

transportation. If an operator fell into

that category it would then have to

develop an integrity management

program for all segments of pipeline that

could affect a high consequence area.

EPA Oil Program Center, the National

Pipeline Reform Coalition, and other

advocates suggested that this rule

should apply to all hazardous liquid

pipelines. EPA Oil Program Center

expressed confusion about whether the

rule applied only to pipelines that were

500 miles long or longer. The City of

Austin pointed out that smaller

operators might be more likely to have

poorer maintenance and operating

practices. BP Amoco also urged OPS to

require all hazardous liquid operators to

comply with the proposed rule,

expressing concerns that pipeline

companies might structure their

operations in a manner to avoid

applicability of the rule.

NTSB suggested that integrity

management requirements should apply

to hazardous liquid pipelines no matter

where they are located, not just those

pipeline segments that could affect high

consequence areas.

API and the individual operators

commented on the need for greater

clarity in the portions of a pipeline

facility to which the rule would apply.

These commenters said that OPS

needed to clarify whether the integrity

management program requirements

were limited to the line pipe or were

intended to cover other facilities

included in the definition of pipeline

(e.g., pump stations, valves, breakout

tanks). The pipeline industry

commenters suggested that the rule be

limited to the line pipe and that we

address integrity issues for the other

pipeline facilities in a separate

rulemaking.

API also suggested that the final rule

clarify that it is limited to onshore

pipeline systems, and that OPS conduct

a separate rulemaking on integrity

management for offshore pipeline

systems. API, and other industry

commenters, explained that offshore

lines may not be capable of

accommodating internal inspection

devices. API also noted that offshore

pipelines pose different risks from

onshore pipelines. BP Amoco thought it

appropriate to include only offshore

pipelines that could affect USAs in an

integrity management program because

offshore operations pose a limited, if

any, risk to public safety. The company

Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations 75389

listed technical factors that should be

considered in establishing integrity

requirements for these lines. Chevron

also noted that offshore lines present

technical and configurational

differences from onshore lines.

SEFBO and Sen. Breaux commented

that the rule should clearly distinguish

overhead suspension pipeline bridges

because of the different skills and

experience required for inspection and

maintenance of such structures. Dynegy

recommended that the rule exempt

highly volatile liquid product pipelines

that traverse wet or flooded areas,

instead, that we cover those lines under

the gas integrity management program

rule.

Response: The final rule clarifies that

it applies to each operator who owns or

operates a total of 500 or more miles of

pipeline used in hazardous liquid

transportation. If an operator has 500 or

more miles of pipeline in its system,

then the operator’s integrity

management program must address the

risks on each pipeline segment in its

system that could affect a high

consequence area. The length of an

individual pipeline segment that could

affect the high consequence area is

irrelevant to whether it is covered.

Moreover, as we explained in the

NPRM, we have no intention of

excluding hazardous liquid operators

with smaller operations. Our public

discussions had given us ample

information to proceed with a proposed

rulemaking aimed at larger liquid

operators. While we proceeded with the

first part of the rulemaking (liquid

operators owning or operating 500 or

more miles of pipeline), we continued

to obtain further information about

smaller liquid operations so that we

could propose integrity management

program requirements applicable to

those systems. The next step in our

series of rulemakings that will

ultimately require all regulated pipeline

operators to have integrity management

programs is to propose integrity

management program requirements for

hazardous liquid operators who own or

operate less than 500 miles of pipeline.

In this rulemaking we have not

extended the pipeline integrity

requirements to pipelines beyond those

that could affect a high consequence

area. We continue to focus on pipeline

segments that could affect the areas we

define as high consequence areas:

populated areas, unusually sensitive

environmental areas and commercially

navigable waterways. However, we

expect that many of the measures the

rule requires for pipeline segments that

could affect high consequence areas will

benefit other parts of the pipeline

system not covered by the rule. For

example, the final rule requires an

operator to analyze and integrate

various information about the integrity

of the entire pipeline. This analysis is

likely to benefit other segments of the

pipeline system. The additional

preventive and mitigative measures that

an operator must take to protect the high

consequence area should also yield

benefits beyond the segment in the

critical area.

Because of the location of launchers

and receivers on a pipeline, an

assessment by internal inspection is

likely to benefit an additional 25–30%

of pipeline beyond that covered by this

rule. An operator may also choose to

extend the integrity assessment beyond

the pipeline segment that could affect

the high consequence area.

The final rule clarifies the pipeline

facilities covered by the integrity

management program requirements. The

integrity management program

requirements apply to each pipeline

segment that could affect the high

consequence area. We are using the term

pipeline as it is defined in § 195.2; the

term includes, but is not limited to, line

pipe, valves, and other appurtenances

connected to line pipe, pumping units,

metering and delivery stations, and

breakout tanks. Integrity management

addresses more than material issues in

line pipe, but other issues such as

adequacy of procedures, operator

training, and other issues related to the

pipeline facilities.

The rule clarifies that the baseline

integrity assessment, which involves

internal inspection, pressure test, or

other equivalent technology applies

only to the line pipe. (Line pipe is

defined in § 195.2.) The continual

integrity assessments, done at intervals

not to exceed five years, also are limited

to the line pipe.

The continual evaluation and

information analysis requirements,

however, apply to the entire pipeline.

To ensure that a high consequence area

receives broad protection, an operator

must evaluate all threats to and from the

pipeline, and consider how operating

experience in other locations on the

pipeline could be relevant to a segment

that could affect a high consequence

area. Thus, the rule requires an operator

to periodically evaluate the integrity of

each pipeline segment that could affect

a high consequence area by analyzing

all available information about the

entire pipeline. This information would

include 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 segment; information about

how a failure would affect location of

water intake; and information gathered

in conjunction with other inspections,

tests, surveillance and patrols required

in Part 195, including, corrosion control

monitoring and cathodic protection

surveys. This information analysis will

be done in conjunction with the

periodic evaluation and continual

integrity assessment of each pipeline

segment.

The rule does not apply to all offshore

pipelines, only to those offshore

pipeline segments (and onshore

pipeline segments) that could affect a

high consequence area. Offshore

pipelines could, particularly, affect

unusually sensitive environmental areas

(USAs) and commercially navigable

waterways. We are including these

offshore pipeline segments because of

their potential to impair unusually

sensitive ecological resources, to disrupt

the flow of goods to communities, or to

impair unusually sensitive drinking

water resources. We discuss later in this

document all areas that are included as

high consequence areas. (See discussion

under topic heading ‘‘Definition of High

Consequence Areas.’’) We also explain

how these areas will be shown on the

National Pipeline Mapping System

(NPMS).

We have also added offshore

pipelines to the list in Appendix C of

risk factors that an operator should

consider in establishing an integrity

assessment schedule. Generally, risks

associated with offshore lines are

because of climatic or geological factors.

We did not accept the

recommendation to exempt highly

volatile liquid (HVL) product pipelines

from this rule. (HVLs are covered under

Part 195 because they are and behave

like hazardous liquids when transported

by pipeline under pressure.) Rather, as

discussed previously in this document,

we have added highly volatile liquids

(or product transported) and pipeline

suspension bridges to the list of risk

factors an operator must consider in

establishing an integrity assessment

interval. And as we discuss later in the

document, these factors have also been

added to the specified factors an

operator must consider when analyzing

the need for additional protective

measures for the pipeline segment.

6. Consensus Standard on Pipeline

Integrity

In the NPRM, OPS mentioned that

API was sponsoring an American

National Standards Institute (ANSI)

work group to develop a consensus

75390 Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations

standard on integrity management. We

said that we expected the consensus

standard would provide detailed

guidance to operators developing and

implementing an integrity management

program. We further said that once the

standard was final, we would consider

adopting it into the integrity

management rule, but only after we had

provided a public notice and comment

period prior to incorporating it into the

rule. The work group is continuing its

work on the standard and is seeking

comment on the draft of the standard.

There was a difference of opinion

among commenters concerning an

industry group’s role in coordinating the

development of a standard.

Environmental Defense and other public

advocates, expressed concern over API’s

role, and suggested use of a neutral

engineering society. The City of Austin

urged RSPA to develop standards using

a team of stakeholders that includes the

regulated community, local officials,

experienced safety engineers, and other

appropriate experts.

API responded that the standard is

being developed using the procedures of

the American National Standards

Institute and includes broad

participation from operators, vendors,

representatives from the American

Society of Mechanical Engineers

(ASME), the National Association of

Corrosion Engineers, OPS, and pipeline

safety advocates.

EPA Region III said that the pursuit of

an industry consensus standard by both

the API and OPS is encouraging, but

asked about the direct involvement in

that process by OPS and other federal

agencies, and the current review

procedures for such standards.

Response: The standard being

developed will be a consensus standard

of the American National Standards

Institute (ANSI), developed using the

standard development procedures of

this independent organization. The

work group of technical experts

includes representatives from

government, industry, and members of

the American Society of Mechanical

Engineers (ASME). When the work

group was created in February 2000,

environmental and other advocacy

groups were invited to join the work

group.

The work group’s meetings are open

to the public. Public participation has

been encouraged. Minutes of the

meetings have been posted on OPS’s

website. The resulting draft standard is

being distributed for public comment

before publishing, allowing input and

review from all stakeholders.

The Executive Committee of ASME

B31.4 has also agreed, at OPS’s request,

to undertake a peer review of this ANSI

standard to ensure that the standard

adequately addresses the regulatory

requirements. The ASME Executive

Committee is expected to complete this

peer review during fall 2000.

Accordingly, we believe that the ongoing standard development process has

the appropriate and adequate checks

and balances built in to produce a

technically sound product that can

support the development and

implementation of high quality integrity

management programs. We expect this

standard will provide more detailed

guidance to operators on the specific

elements and acceptable processes of an

integrity management program, and can

supplement the performance-based

portions of the rule. Once the consensus

standard is final, we will consider

adopting, all or part of it into this final

rule. However, we will only do so after

we have provided for public notice and

comment.

7. Definition of High Consequence

Areas—Proposed Section 195.450

The proposed rule’s definition of high

consequence areas had three

components: populated areas, areas

unusually sensitive to environmental

damage and commercially navigable

waterways.

Populated Areas

The notice proposed that populated

areas consist of high population areas

and other populated areas. The

proposed rule based these areas on

Census Bureau definitions.

The City of Austin thought that the

population component of the definition

was too vague. They commented that

because Census figures were only

updated every ten years, that high

growth areas could be penalized, and

that smaller clusters of dense

population would not be included. The

City wanted OPS to supplement the

Census data with local data on utility

connections. The City of Austin also

stated that OPS incorrectly stated the

Census Bureau’s definition of an

urbanized area.

USAs

The environmental component of the

proposed high consequence area

definition used OPS’s recently proposed

definition of Unusually Sensitive Areas

(USAs) (64 FR 73464; Dec. 30, 1999).

Many commented that this proposed

definition is too restrictive, and should

be expanded to include all

environmentally sensitive areas. EPA

Oil Program Center expressed concern

that OPS’s methodology would fail ‘‘to

protect even the most vulnerable of

sensitive environmental populations

and their habitat.’’ EPA Region III said

that the definition should include

product-specific differences. Friends of

the Aquifer stated that ‘‘the rule

proposes an eccentric and far too

narrow definition of natural areas .’’

AWWA also commented that the USA

definition was inadequate because it

excludes many sources of drinking

water. Environmental Defense suggested

we include all environmentally

sensitive areas without the filtering

system the proposed USA definition

used. Friends of the Aquifer also wanted

all environmentally sensitive areas

included. Batten & Associates thought

the proposed USA definition was too

restrictive and would fail to protect

many drinking water resources and

habitats for threatened and endangered

species.

Commercially Navigable Waterways

API and liquid operators questioned

the inclusion of commercially navigable

waterways into the high consequence

area definition. API pointed out that

Congress required OPs to identify

hazardous liquid pipelines that cross

waters where a substantial likelihood of

commercial navigation exists and once

identified, issue standards, if necessary,

requiring periodic inspection of the

pipelines in these areas. API said that

OPS had not determined the necessity

for including these waterways in areas

that trigger additional integrity

protections. BP Amoco said the rule

should be limited to protection of public

safety, rather than commercial interests.

Enbridge and Lakehead also questioned

why waterways that are not otherwise

environmentally sensitive should be

included for protection.

EPA Region III said that we should

also consider recreational and

waterways other than those for

commercial use. Environmental

Defense, Batten, City of Austin and

other commented that we should

consider all navigable waterways as

high consequence areas, because of the

environmental consequences a

hazardous liquid release could have on

such waters.

Other Areas

EPA Region III maintained that

product specific differences should be

incorporated into the definition.

Environmental Defense, Batten and

other commenters wanted OPS to

expand the definition of high

consequences areas to include cultural,

recreational, tribal and economic

resources. Environmental Defense

suggested we include national parks,

wilderness areas, and wildlife refuges.

Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations 75391

The City of Bellingham asked that we

consider addressing integrity

management programs for pipeline

located outside the high consequence

areas.

The City of Austin commented that

the definition failed to include areas

that are of high consequence due to

preservation or recreational value alone.

The City suggested including all state,

national, and local parkland, refuges

and wilderness areas, and preserves

designated for water quality protection

and wildlife.

API argued against expanding the

definition to include cultural resources,

environmental resources other than

those identified as USAs, and other

areas of national importance. They

argued that including these areas would

dilute available resources and focus

from the populated and environmental

areas that need greater protection, and

that many other Federal, state, and local

regulations are in place to minimize the

effects of hazardous liquid pipelines on

these other areas.

During discussions with

representatives from DOJ/ENRD, DOI,

and EPA, we were strongly urged to

include other areas as high consequence

areas: all waters of the United States,

wetlands and wildlife refuges,

wilderness areas, fish hatcheries, units

of the National Park System, and wild

and scenic rivers. DOI, DOJ and EPA

strongly recommended that the National

Parks and National Fish Hatcheries be

included in the definition.

Identification of High Consequence

Areas

API and liquid operators wanted OPS

to clarify its commitment to identify

high consequence areas, to generate and

publish maps of the areas, and to

periodically update the maps. These

commenters said that such information

was necessary before operators could

assess pipelines and take appropriate

preventive and mitigative measures.

Response: The final rule continues to

focus on areas where we have

determined a hazardous liquid pipeline

failure could pose the greatest threat to

public safety, unusually sensitive

environmental areas (including drinking

water and ecological resources), and

water commerce that is essential for

communities’ safety and public health

or for national security. We have not

revised the definition to incorporate

product-specific differences; rather,

other parts of the rule address the risks

associated with different products the

pipeline is transporting (e.g., when

considering risk factors for establishing

assessment intervals).

Populated Areas

In the final rule, we have not changed

the definition of populated ares that is

based on the Census Bureau’s

definitions and delineations. We

disagree that we misstated the Census

Bureau’s definition of urbanized areas.

The only change we have made is in the

terms we are using. What Census

Bureau calls an urbanized area, we are

calling a high population area. The

additional populated areas that the

Census Bureau calls a census designated

place, we are calling an other populated

area. We have chosen these definitions

to avoid confusion over the term places,

which the Census Bureau used to

include both urbanized and census

designated places. Our National

Pipeline Mapping Systems (NPMS) will

use the same titles and definitions used

in this final rule.

We are using Census Bureau data for

the population component because it is

the recognized expert and source for

general population data in the

communities of the United States. The

data are standardized, publicly available

and in a format that allows OPS and

others to create maps of the populated

areas. OPS currently does not have the

resources to gather local data on utility

connections. However, nothing

precludes an operator from

supplementing the maps we will

provide with other data pertinent to its

pipeline. (As discussed later in this

Preamble under the sub-topic heading

‘‘Identification of high consequence

areas’’, an operator will have the

ongoing responsibility to incorporate

newly-identified populated areas and

unusually sensitive environmental areas

into its assessment plan.)

Populated areas consist of high

population and other populated areas.

High population areas are the Census

Bureau’s urbanized areas. These areas

contain 50,000 or more people and have

a population density of at least 1,000

people per square mile. Other populated

areas are the Census Bureau’s places

minus the urbanized areas. These areas

contain concentrations of people and

include incorporated or unincorporated

cities, towns, villages, or other

designated residential or commercial

areas.

We believe the population component

of the high consequences area definition

picks up most areas where pipelines can

pose a threat to public safety. However,

we are aware that there may be other

areas where people congregate near

pipelines, but do not fall within either

sub-component of the population

definition. Two recent and tragic

accidents illustrate the dangers that

pipelines pose to public safety in these

areas. In Bellingham, Washington, a

pipeline release into a creek ignited and

resulted in the deaths of three young

people who were in the recreational

park through which the creek flowed.

An explosion that occurred on one of

the three adjacent large natural gas

pipelines near Carlsbad, New Mexico,

killed 12 people, including five

children, who had been camping near

the pipeline.

Although this rule is not including

areas where people congregate in the

high consequence area definition, OPS

is considering addressing these areas in

a future rulemaking. In the meantime

we encourage operators to consider

addressing in their integrity

management programs areas where

people congregate and to determine if

there are pipeline segments in or near

these areas that could affect the area.

Operators should be able to recognize

these areas, through fly overs or other

surveillance made of their pipelines, or

through consultation with local officials

in the community.

USAs

The rule’s definition of high

consequence areas will incorporate the

final definition of Unusually Sensitive

Areas, which OPS expects to issue in

November 2000 (Docket No. RSPA–99–

5455). The USA rulemaking will

address the resolution of the above

comments and other submitted to the

docket for that rulemaking. Because of

the dependence of this rulemaking on

the final definition of USAs, this rule

will not be effective until March 31,

2001.

Commercially Navigable Waterways

Our inclusion of commercially

navigable waterways for public safety

and secondary reasons is not based on

the ecological sensitivity of these

waterways. Parts of waterways sensitive

for ecological purposes are covered in

the proposed USA definition, to the

extent that they contain occurrences of

a threatened and endangered species,

critically imperiled or imperiled

species, depleted marine mammal,

depleted multi-species area, Western

Hemispheric Shorebird Reserve

Network or Ramsar site. In this rule,

only those pipeline segments that could

affect a commercially navigable

waterway are covered. We are including

commercially navigable waterways as

high consequence areas because these

waterways are a major means of

commercial transportation, are critical

to interstate and foreign commerce,

supply vital resources to many

American communities, and are part of

75392 Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations

3OPS uses state data bases as the primary data

source for the USA model. The drinking water USA

model relies on data solely provided by the States.

State aquifer maps are used to determine aquifer

classifications. State data on well location depth,

and source are used to identify the aquifers used

by the wells. The ecological USA model uses data

from the state Natural Heritage Programs (NHP) on

rare and endangered species locations. OPS is also

using the Environmental Sensitivity Index and

related ecological data sets to augment the NHP

data.

a national defense system. A pipeline

release could have significant

consequences on such vital areas by

interrupting supply operations due to

potentially long response and recovery

operations that occur with hazardous

liquid spills. As explained later, OPS

will map these waterways on its

National Pipeline Mapping System.

Other Areas

As discussed above, representatives of

several Federal government agencies

urged us to include other areas in the

definition of high consequence areas.

We have decided not to include these

suggested areas in this rulemaking.

Although we have not included the

other suggested areas in this

rulemaking, we are considering

extending protection to other

environmentally sensitive and vital

resources through future rulemaking.

Other areas that will be considered

include National Parks, National

Wildlife Refuges, National Wilderness

Areas, National Forests, and other

cultural resources and sensitive

environmental resources that do not

meet the USA filtering criteria.

Identification of High Consequence

Areas

OPS will identify high consequence

areas on its National Pipeline Mapping

System (NPMS). Operators, other

government agencies and the public will

have access to these maps through the

Internet. Individuals will be able to

view high consequence areas nationally

or by state, county, zip code, or zooming

in or out of a particular area. An

operator will then be able to determine

which of its pipeline segments intersect

or have the ability to affect a high

consequence area.

OPS will identify the locations of

USAs through a comprehensive

collection and analysis of drinking

water and ecological resource data,

contingent on the availability of funding

and resources.3 OPS will make its USA

maps, including the drinking water

data, available through the National

Pipeline Mapping System. Barring

unforeseen resource demands, OPS’s

current plan is to have the USAs in the

top ten states (covering 75% of total

pipeline mileage) available by the end of

December 2000. Maps of the USAs in

the next ten states (90% of total pipeline

mileage) should be available by April

2001. And we plan to have the maps of

the remaining states (100% of total

pipeline mileage) available by December

2001.

Some of the information that OPS is

purchasing, such as discrete sets of

ecological data from the Nature

Conservancy and other sources, will not

be publicly available. Operators may

need to contact resource agencies to

obtain additional information on a

particular species or drinking water

intake in an USA.

OPS will use the National Waterways

Network database to identify

commercially navigable waterways. The

commercially navigable waterways map

and database will be available through

the National Pipeline Mapping System.

The Bureau of Transportation Statistics

also has a database that includes

commercially navigable waterways and

non-commercially navigable waterways.

The database can be downloaded from

the BTS website: http://www.bts.gov/

gis/ntatlas/networks.html.

OPS will use the Census Bureau’s

data to identify high population and

other populated areas. We will use the

Census Bureau’s urbanized area data to

identify high population areas and their

places data to identify other populated

areas. Their data on places includes

both urbanized areas and other

populated areas. OPS will filter out the

urbanized areas data from the places

data so that the resulting map and

database will clearly distinguish other

populated areas from the urbanized or

high population area data. Operators

and the public will be able to view the

high population and other populated

areas maps together or separately on the

National Pipeline Mapping System.

OPS recognizes that inventories and

maps of high consequence areas have to

be updated on a periodic basis to

incorporate new information and

databases. OPS intends to update the

high consequence area maps every five

years, contingent on the availability of

funding and resources. OPS will review

new or revised programs and databases

at that time to incorporate appropriate

programs and databases into the high

consequence area definition and model.

OPS will announce in the Federal

Register and through other

communication networks when revised

high consequence area maps are

available for given areas.

Changes, particularly population

changes, will occur around an operator’s

pipeline. Although OPS intends to

periodically update the maps, it remains

an operator’s responsibility to keep

information about its pipelines up to

date. By continually evaluating its entire

pipeline and analyzing all available

information about the integrity of the

pipeline, an operator should be aware of

population and ecological changes that

are occurring around the pipeline and

continue to update its maps and

integrity management program to

accommodate these changes.

In the rule we have added

requirements about how an operator is

to incorporate any newly-identified high

consequence areas into its baseline

assessment plan and integrity program.

The rule provides that when an operator

has information (from the information

analysis or from Census Bureau maps)

that the population density around a

pipeline segment has changed so as to

fall within the definition of a high

population area or other populated area,

the operator must incorporate the area

into its baseline assessment plan as a

high consequence area within one year

from the date the area is identified.

Similarly, an operator must incorporate

a new unusually sensitive

environmental area into its plan within

one year from the date the area is

identified. The rule further requires an

operator to complete the baseline

assessment of any line pipe that could

affect the newly-identified high

consequence area within five years from

the date the area is identified.

We thought it necessary to add these

requirements because of the concerns

many commenters expressed about who

would be responsible identifying high

consequence areas and how updates

would be handled. Although OPS is

taking primary responsibility for

mapping these areas, an operator has a

corresponding responsibility to

continually evaluate its pipeline and

update information about the pipeline.

8. Requirements for Preventive and

Mitigative Measures, Including,

Emergency Flow Restricting Devices

(EFRDs) and Leak Detection Systems—

Proposed Section 195.452(i)

The proposed rule required an

operator to conduct a risk analysis to

assess the risks to its pipeline system

and determine what additional

preventive and mitigative measures are

needed to protect a high consequence

area. The proposal identified possible

preventive or mitigative measures an

operator could take to protect a high

consequence area, such as

implementing damage prevention best

practices, establishing or modifying leak

detection systems, and providing

additional training on response

procedures.

Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations 75393

Installing EFRDs was one of several

mitigative measures the rule proposed.

However, the proposal did not require

an operator to install EFRDs or define

the conditions under which an operator

should install EFRDs. In the NPRM we

specifically invited comment on any

needed further guidance to operators on

when EFRDs should be installed. We

also invited 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, we should mandate the

use of EFRDs.

EPA Region III supported the

preventive and mitigative measures the

rule proposed but argued against leaving

the need for particular actions to the

operator. Region III was concerned that

without active and knowledgeable

regulatory oversight, strict methodology,

or the required participation of a risk

assessment professional, an operator

would be unlikely to find any of the

measures necessary. Environmental

Defense said that the rule should

include specific requirements for

operators to use preventive strategies.

NTSB expressed concern with operators

using risk management principles to

determine the need for additional

protective measures and recommended

that the rule include minimum criteria.

EPA Oil Program Center said that the

rule should prescribe circumstances in

which EFRDs or other protective and

mitigative measures must be used. EPA

Oil Programs further commented that if

the rule allows an operator to conduct

a risk assessment to determine if EFRDs

or other protective measures are needed,

then the rule should prescribe a specific

risk assessment protocol.

Environmental Defense, Batten and

other advocates recommended that the

rule include performance standards for

leak detection, EFRD spacing and

damage prevention best practices.

Environmental Defense and Pipeline

Survivor’s Association recommended

that leak detection systems be capable of

detecting a leak of one gallon/minute or

more and that EFRD spacing prevent

releases of more than 10,000 gallons of

hazardous liquid into a high

consequence area. The City of Austin

supported requiring EFRDs in all high

consequence areas and that they be

spaced to restrict the worst case spill to

10,000 gallons. Batten suggested that

leak detection devices be capable of

detecting within 15 minutes a leak of

ten gallons or more and that pipe

segments between EFRDs be able to

contain no more than 50,000 gallons

when located in a high consequence

area.

AWWA encouraged the placement of

EFRDs to the greatest extent possible to

protect public water supplies,

suggesting that EFRDs be used as the

standard against which other mitigation

strategies are measured. LCRA

commented that EFRDs should be

required on either side of a river

crossing. EPA Region III also

encouraged using EFRDs whenever

necessary to protect a high consequence

area.

API and operators commented that

the proposed rule is reasonable and that

OPS should ensure risk mitigation

decisions made within an integrity

management program include

considering the use of EFRDs rather

than requiring such placement or

prescribing minimum spacing. Enbridge

and Lakehead supported EFRDs as one

of various preventive or mitigative

actions an operator should consider but

said there was no one distance or

placement specification appropriate for

all pipeline systems. Many cited

research by the California State Fire

Marshall, and Southwest Research to

support their argument that there are

many site and flow-specific factors that

operators must consider in making risk

mitigation decisions. Several industry

commenters also noted the possible

environmental disadvantage to EFRDs,

including the possibility of valve

leakage or inadvertent closure resulting

in over pressurization, as well as the

environmental impacts of installing and

maintaining valves in or near

environmentally sensitive areas.

Response: The final rule continues to

require an operator to take additional

measures to prevent and mitigate the

consequences of a pipeline failure that

could affect a high consequence area. It

is up to each operator to conduct a risk

analysis of the pipeline segment to

identify additional actions to enhance

public safety or environmental

protection. For this risk analysis, the

rule clarifies that an operator must

evaluate the likelihood of a pipeline

release occurring, how a release could

affect the high consequence area, and

what risk factors the operator should

consider. The rule continues to list

some additional preventive and

mitigative measures an operator should

consider. The list is not an exhaustive

recitation of every preventive or

mitigative measure that could enhance

public safety or environmental

protection.

One of the listed measures is for an

operator to modify the systems that

monitor pressure and detect leaks.

Operators use various procedures and

methods to detect the movement of

product through the pipeline. For

example, computational pipeline

monitoring, SCADA systems, and

station sensors, measure deviations from

measured values (pressures, flows)

beyond established norms. The pipeline

safety regulations do not require an

operator to have a leak detection system.

However, if an operator has a softwarebased leak detection system, the

regulations require the operator to use

an industry document (API 1130) in

designing, evaluating, operating,

maintaining and testing its softwarebased system. (See § 195.444.)

Moreover, whenever a leak detection

system is installed or a component

replaced, API 1130 must be followed.

The final rule requires an operator to

have a means to detect leaks on its

pipeline system. (We provide several

examples of types of leak detection

systems later in this document when we

discuss Section 195.452(i).) We have rewritten the rule to require an operator

to evaluate the leak detection’s

capability to protect the high

consequence area and to modify, as

needed, to protect the high consequence

area. The rule includes factors that an

operator must consider in making its

evaluation. OPS enforcement personnel

will review the adequacy of this

evaluation process during site

inspections.

Another protective measure the rule

identifies is for an operator to install an

EFRD on the pipeline segment. The final

rule does not prescribe the specific

conditions under which EFRDs or other

preventive or mitigative measures are

required. Rather, the final rule requires

an operator to develop and apply risk

assessment and decision-making

processes that reflect pipeline-specific

conditions and operating environments.

The rule now specifies criteria that an

operator must consider when

conducting the analysis to identify

additional protective measures. An

operator is not limited to these criteria;

rather, an operator must consider these

criteria in addition to all other criteria

specific to the pipeline segment.

In the final rule, OPS has not

specified the circumstances when an

operator must use a particular protective

measure or install an EFRD. However,

we have revised the rule to require that

an operator install an EFRD if the

operator determines that one is needed

to protect the high consequence area.

The rule also specifies factors that an

operator must consider in making this

determination. OPS will review during

inspection the adequacy of the analysis

and the appropriateness of the

operator’s decision on the need to

install an EFRD.

75394 Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations

OPS has been studying for some time

the issue of the optimum placement of

emergency flow restricting devices to

limit commodity release after the

location of the release has been

identified. In the NPRM, we explained

in detail the research OPS has

conducted in this area. (See 65 FR

21695; April 24, 2000.) In addition to

comment the NPRM solicited, OPS had

previously issued an advance notice of

proposed rulemaking asking questions

concerning the performance of leak

detection equipment and location of

EFRDs, and held a public workshop to

discuss the issues involved in

developing regulations on EFRDs.

Our study of the issue led us to

conclude that the decision to install an

EFRD should not be mandatory but

should be left to the operator.

Nonetheless, the rule requires an

operator to consider certain specified

criteria in deciding whether an EFRD

will protect the high consequence area.

OPS is requiring an operator to

determine whether to install an EFRD

based on the operator’s risk analysis,

because, we believe, prescriptive valve

installation and spacing requirements

would ignore the site-specific variables

and unique flow characteristics of a

pipeline segment. Prescriptive

requirements could also overlook the

potential sensitivity of a specific high

consequence area. For example, locating

an EFRD near a body of water to reduce

the potential volume released might

necessitate locating the valve in

sensitive wetlands or a flood plain of a

river, which creates myriad other

problems. Also, a prescriptive approach

detracts from the process of evaluating

a host of alternative measures to

enhance protection to high consequence

areas.

9. Methods To Measure Program’s

Effectiveness—Proposed Section

195.452(k)

In the NPRM we proposed that an

operator’s 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

consequences areas. NTSB commented

that this requirement has to contain

unequivocal guidance if operators are to

use it to improve their programs, and

suggested that we develop measures.

EPA Region III commented that a

measurement based on some industrywide average should not be used

because it could lower the bar for

management, technology, and

innovation.

Response: We have not revised the

provision on program performance

measures other than to clarify that an

operator is to measure the effectiveness

of the program on each pipeline

segment. In Appendix C we have

described types of program measures

and included examples of methods that

an operator can use to evaluate the

effectiveness of its integrity

management program.

10. Cost Benefit Analysis

The comments we received on the

proposed rule’s cost benefit analysis are

addressed below under the Regulatory

Analyses and Notices section.

11. Information for Local Officials and

the Public

In the NPRM, OPS invited 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. We further said that

because of the significance of this issue

we planned on extensive discussions

with all the stakeholders before

proposing communications

requirements as part of an integrity

management program.

Many provided comments relevant to

the issue of communications with local

officials. Tosco agreed that research is

needed on the types and amount of

information to distribute to local

officials and made available to the

general public to determine the most

effective means to keep those entities

informed. Environmental Defense, the

Pipeline Survivor’s Association, and

Batten listed information they thought

operators should make available to

public officials and the public.

American Water Works Association

strongly supported the need for

communication, but provided no

specific guidance on content.

Lower Colorado River Authority

(LCRA) promoted public involvement in

the preparation and implementation of

integrity management programs,

maintaining that with public

involvement, pipeline operators would

have a better understanding of the

vulnerability of the resources. LCRA

further commented that public

confidence in the pipeline industry

would be enhanced if the results of the

integrity assessments were made

available. The City of Bellingham also

recommended that integrity

management programs be developed in

consultation with appropriate state and

local officials before the operator

finalizes the program. The National

Pipeline Reform Coalition also

recommended that local communities

have a role in developing the programs,

citing the evidence of the role of the

City of Bellingham in developing a

safety plan for Olympic Pipe Line

Company.

Response: Requirements for

communication of integrity management

information to local public officials and

to the public will be the subject of a

future rulemaking. We will use the

comments received in this rulemaking

in developing the communications

rulemaking. A communications work

team, consisting of representatives from

environmental and public safety

organizations, pipeline companies, and

government has formed to aid the

Hazardous Liquid Advisory Committee

(THLPSSC) in developing

communications issues. Notices of

meetings of the work group will be

published in the Federal Register. Notes

from the meetings will be posted on

OPS’s web site.

12. Appendix C Guidance

Proposed Appendix C provided

operators 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. The proposed Appendix also

included 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.

There were a variety of comments

concerning Appendix C. Some

addressed the role of Appendix C in the

overall rule, and others provided

specific technical comments on detailed

aspects of the Appendix (which are not

summarized here).

API and other liquid operators

commented that Appendix C ‘‘is not

sufficiently rigorous or technically

accurate to be used as guidance for

prioritizing risk’’ and provided a list of

problems they have identified. API

recommended that OPS not include the

Appendix in the final rulemaking, but

that OPS and the integrity standard

work group develop technically

accurate, rigorous guidance for

prioritizing risk factors.

The City of Austin recommended that

Appendix C be included as part of the

rule because it specifies how an

operator should implement the

proposed regulation. Fuel Safe

Washington stated that ‘‘Appendix C is

completely undermined by allowing

operators to apply their own weights or

values to the risk factors.’’

Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations 75395

Response: An Appendix is guidance

that is intended to give advice to

operators on how to implement the

requirements of the integrity

management rule. An Appendix does

not have the same force as the

regulation itself. An operator does not

have to follow the guidance. However,

if an operator incorporates parts of the

Appendix into its integrity management

program, an operator must then comply

with those provisions.

OPS continues to believe that the

guidance provided in Appendix C will

be helpful to operators in developing

and implementing their integrity

management programs. (Operators may

supplement this guidance with the

industry consensus standard or choose

not to use the guidance.) We also

continue to believe that the guidance

should not be included in the body of

the rule because it would unnecessarily

inhibit operators from identifying the

best pipeline- and segment-specific

tools, risk factors, and repair techniques,

and would require changes in the rule

as new technologies or information is

developed.

The Final Rule

The new section 195.450 titled

‘‘Definitions’’ defines high consequence

areas. High consequence areas include—

• Unusually sensitive areas—these

areas will be defined in the USA

rulemaking (Docket No. RSPA–99–5455)

and will include drinking water and

ecological resources;

• High population areas—these are

areas defined and delineated by the

Census Bureau as urbanized areas.

• Other populated areas—these are

areas defined and delineated by the

Census Bureau as places that contain a

concentrated population.

• Commercially navigable

waterways—these are waterways where

a substantial likelihood of commercial

navigation exists.

The integrity management program

requirements will apply to pipeline

segments that could affect these high

consequence areas. OPS will map these

areas on its National Pipeline Mapping

System, and make the maps publicly

available.

This section also defines emergency

flow restricting devices to include check

valves and remote control valves. This

definition is used in § 195.452(i) of the

rule that addresses additional

preventive and mitigative measures an

operator must consider for pipeline

segments that could affect a high

consequence area.

The new section 195.452 titled

‘‘Pipeline Integrity Management in High

Consequence Areas’’ imposes integrity

management program requirements on

each operator who owns or operates a

total of 500 or more pipeline miles used

in hazardous liquid transportation.

For an operator covered by the rule,

the rule requires the operator to

develop, implement and follow an

integrity management program that

provides for continually assessing the

integrity of those pipeline segments that

could affect a high consequence area,

through internal inspection, pressure

testing, or other equally effective

assessment means. An operator’s

program must also provide for

evaluating the segments through

comprehensive information analysis,

remediating potential integrity problems

found through the assessment and

evaluation, and ensuring additional

protection though preventive and

mitigative measures.

Through this required program, a

hazardous liquid operator must

comprehensively evaluate the entire

range of threats to each pipeline

segment’s integrity by analyzing all

available information about the entire

pipeline and its relevance to the

segment that could affect a high

consequence area. Information an

operator must evaluate includes

information on the potential for damage

due to excavation; data gathered

through the required integrity

assessment; results of other inspections,

tests, surveillance and patrols 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.

The final rule requires an operator to

take prompt action to address all

integrity issues raised by the integrity

assessment and information analysis.

This means an operator must evaluate

all anomalies and repair those could

reduce a pipeline’s integrity. An

operator must develop a schedule that

prioritizes the anomalies for evaluation

and repair. The schedule must include

time frames for promptly reviewing and

analyzing the integrity assessment

results and completing the repairs. An

operator must also maintain, and further

protect the integrity of these pipeline

segments, through other remedial

actions, and preventive and mitigative

measures.

Which Operators Must Comply? Section

195.452(a)

This rule specifies pipeline system

integrity management program

requirements for each operator who

owns or operates a total of 500 or more

miles of hazardous liquid pipeline. This

action covers approximately 87 percent

of all the hazardous liquid pipelines in

the United States. Based on the volume

of hazardous liquid these pipelines

transport, they have the greatest

potential to adversely affect the

environment.

For an operator covered by this rule,

the requirements apply to all the

operator’s pipeline segments (offshore

or onshore), regardless of date of

construction, that could affect a high

consequence area. The rule specifies

how operators must provide additional

protection to critical areas (i.e., high

consequence areas) through integrity

management programs. Further, it

assures that these protections will be

put in place, with an operator being

required to initially assess 50 percent of

the line pipe that could affect critical

areas, beginning with the highest risk

pipe, within 3.5 years and the balance

within seven years. An operator will

then have to evaluate and repair defects

within specified time frames and

implement additional preventive and

mitigative measures. An operator is also

required to continually re-assess its

pipeline segments at intervals not longer

than five-years, as well as periodically

evaluate each pipeline segment by

analyzing all available information

about the integrity of the entire pipeline,

and its relevance to segments that could

affect the high consequence areas.

What Must an Operator Do? Section

195.454(b)

The rule requires that, no later than

one year after the rule’s effective date,

an operator must develop a written

integrity management program that

addresses the risks on each pipeline

segment that could affect a high

consequence area. An operator must

then implement and follow the program

it has developed. Initially, the program

will consist of a framework. An operator

must include in its integrity

management program—

• An identification of all pipeline

segments that could affect a high

consequence area. Because

identification of the pipeline segments

is the trigger for all other integrity

management requirements, the

identification must be done within nine

months from the rule’s effective date.

• A plan for baseline assessment. The

assessment of the line pipe must be

done by internal inspection, pressure

test, or other technology that provides

an equivalent understanding of the

condition of the line pipe.

• A program framework that

addresses each of the required program

elements, including continual integrity

assessment and evaluation. In the first

year after the rule’s effective date, the

75396 Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations

framework must indicate how decisions

will be made to implement each

required program element. The

framework will evolve into an integrity

management program as the operator

makes decisions and gains experience.

An integrity management program is a

dynamic program that an operator must

continually change as the operator gains

more information about the pipeline

and the results of the assessments.

To carry out the rule’s requirements,

an operator must follow recognized

industry practices unless the rule

specifies otherwise or the operator

chooses an alternative practice that is

supported by a reliable engineering

evaluation and provides an equivalent

level of public safety and environmental

protection. Recognized industry

practices include national consensus

standards and practices found in

reference guides. Allowing the use of

alternative practices in the rule should

encourage operators to use innovative

technology in implementing the

integrity management program’s

requirements.

What Must Be in the Baseline

Assessment Plan? Section 195.452(c)

The rule requires an operator to

include in its written baseline

assessment plan each of the following

elements.

• The methods selected to assess the

integrity of the line pipe of each

segment that could affect a high

consequence area;

• A schedule for completing the

integrity assessment;

• 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 pipeline

segments.

The rule allows an operator to modify

the baseline assessment plan provided

the operator documents the

modifications and reasons for the

modifications. As discussed later under

the section on recordkeeping

requirements (§ 195.452(l)), these are

documents an operator is required to

maintain for inspection. Enforcement

personnel will look to see that an

operator has documented the

modification well before the operator

has implemented the modification.

OPS expects an operator to make the

best use of current and innovative

technology in assessing the integrity of

the line pipe. Therefore, the rule allows

an operator to conduct an integrity

assessment by—

• Internal inspection tool or tools

capable of detecting corrosion and

deformation anomalies including dents,

gouges and grooves. For electric

resistance welded (ERW) pipe or lap

welded pipe susceptible to longitudinal

seam failures, the rule provides that the

integrity assessment methods must be

capable of assessing seam integrity and

of detecting corrosion and deformation

anomalies. An operator’s program

would also have to address any risk

factors associated with these types of

pipe;

• Pressure test conducted in

accordance with Part 195, subpart E; or

• Other technology that provides an

equivalent understanding of the

condition of the line pipe.

Internal inspection is one of the most

useful tools in an integrity management

program. We expect an operator to

consider at least two types of internal

inspection tools for the integrity

assessment of the line pipe: geometry

pigs for detecting changes in

circumference and metal loss tools

(magnetic flux leakage (MFL) pigs or

ultra sonic pigs) for determining wall

anomalies, or wall loss due to corrosion.

Both high resolution and low resolution

tools can be beneficial in integrity

assessment. For example—

Corrosion/metal loss: With respect to

corrosion, high-resolution tools can

identify anomalies and, with the use of

engineering critical assessments, use a

conservative evaluation of the potential

for the anomaly to have affected

remaining pipe strength (or affected the

pressure capacity of the pipeline

segment). This assessment uses

analytical techniques that estimate

average depth of metal loss. Based on

the evaluation of internal 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.

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.

Mechanical Damage: Internal

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%).

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.

The rule also permits integrity

assessment of the line pipe by pressure

test. An operator must conduct a

pressure test according to the

requirements prescribed in Part 195,

subpart E.

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,

construction or operation. 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.

OPS expects that an operator choosing

this method of integrity assessment for

a pipeline segment will review its

corrosion control monitoring program

for that segment. OPS inspectors will

review these documents when

evaluating an operator’s choice of

pressure test as an assessment method.

To encourage innovation, the final

rule also allows an operator to use other

technology for the integrity assessment,

if the operator demonstrates that an

alternative technology can provide an

equivalent understanding of the

condition of the line pipe as the other

permitted assessment methods.

An operator choosing this option

must notify OPS at least 90 days before

conducting the assessment with the

other technology. The rule specifies

Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations 75397

how notification can be made: by mail

or facsimile. Advance notice is

necessary so that OOPS enforcement

personnel have adequate time to review

the operator’s basis for using the

technology.

When Must the Baseline Assessment Be

Completed? Section 195.452(d)

The rule requires an operator to

establish a baseline assessment schedule

to determine the priority for assessing

the pipeline segments covered by the

rule. An operator must complete the

baseline integrity assessment within

seven years after the rule’s effective

date. An operator is further required to

assess at least 50% of the covered line

pipe, beginning with the highest risk

pipe, within 3.5 years from the rule’s

effective date. This requirement, in

conjunction with the requirement to

base the assessment intervals on riskbased factors, should ensure that an

operator assesses the highest risk

pipeline segments earlier in the cycle.

The final rule allows an operator to

use an integrity assessment method

conducted five years before the rule’s

effective date as the baseline assessment

if the method is at least equivalent to

the requirements for internal inspection,

pressure testing or alternative

technology. However, if an operator

decides to use a prior integrity

assessment as its baseline assessment,

the operator must then re-assess the

integrity of the line pipe within five

years. The re-assessment would have to

comply with the continual integrity

assessment requirements in § 195.452(j).

As we discuss later in this document

when explaining § 195.452(j), the rule

allows for deviations from the five-year

requirement in certain limited

instances.

Because population and ecological

changes may occur around an operator’s

pipeline, an operator must, as part of its

periodic evaluation and information

analysis, keep informed about how such

changes are affecting each pipeline

segment. If the population density

around a pipeline segment changes so as

to fall within the definition of a high

population area or another populated

area, the rule requires an operator to

incorporate the area into its baseline

assessment plan as a high consequence

area. This must be done within one year

from when the area is identified. An

operator must then assess the integrity

of any line pipe that could affect that

newly identified high consequence area

within five years from when the area is

identified. Similarly, the rule requires

an operator to incorporate a new

unusually sensitive environmental area

into its baseline plan within one year

from when the area is identified and to

assess the new area within five years.

What are the Risk Factors for

Establishing an Assessment Schedule?

Section 195.452(e)

For both the baseline and continual

integrity assessments, an operator must

establish a schedule that prioritizes the

pipeline segments for assessment so that

the higher risk segments are assessed

earlier in the cycle. The rule requires an

operator to base the assessment

schedule on all risk factors that reflect

the risk conditions on each pipeline

segment. The rule further specifies some

factors an operator must consider in

establishing a schedule. An operator is

not limited to these factors; rather, an

operator must supplement the listed

factors with those that are specific or

unique to the pipeline segment being

assessed.

In Appendix C, we provide guidance

to an operator on how to determine risk

factors for a pipeline segment and use

them to develop an integrity assessment

schedule. The guidance includes an

example of risk factors that we apply to

a hypothetical pipeline segment to

establish an assessment frequency.

What Are the Elements of an Integrity

Management Program? Section

195.452(f)

The final rule requires an operator to

include certain minimum elements in

its integrity management program.

Initially, an operator must develop a

framework containing these elements.

The framework evolves into a program

as the operator gains experience, makes

decisions and implements actions. The

required program elements include—

• A process for identifying which

pipeline segments could affect a high

consequence area. The Appendix gives

guidance to help an operator evaluate

how a pipeline segment could affect an

area, which will help an operator in

developing this process. The guidance

lists factors an operator needs to

consider when evaluating the pipeline

segment’s ability to affect a high

consequence area.

• A baseline assessment plan

(discussed in § 195.452(c));

• An analysis that integrates all

available information about the integrity

of the entire pipeline, its relevance to

the particular segment, and the

consequences of a failure;

• Criteria for repair actions to address

integrity issues raised by the assessment

methods and information analysis;

• A continual process of assessment

and evaluation to maintain a pipeline’s

integrity;

• Identification of preventive and

mitigative measures to protect the high

consequence area;

• Methods to measure the program’s

effectiveness; and

• A process for review of integrity

assessment results and information

analysis by a person qualified to

evaluate the results and information. An

operator must use qualified persons

with the necessary technical expertise to

evaluate and analyze the results and

data from the integrity assessments, the

periodic evaluation, the information

analyses, etc.

To be effective, an integrity

management program must constantly

change. 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 evolves

from the framework and must continue

to change to reflect operating

experience, conclusions drawn from

results of the integrity assessments, and

other maintenance and surveillance

data, and evaluation of consequences of

a failure on the high consequence area.

What is an Information Analysis?

Section 195.452(g)

The final rule requires an operator to

periodically evaluate the integrity of

each pipeline segment that could affect

a high consequence area by analyzing

all available information about the

integrity of the entire pipeline and the

consequences of a failure. The analysis

applies to the entire pipeline to

determine the relevance to a particular

pipeline segment. Required information

an operator must evaluate includes—

• 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

segment;

• Data gathered through the required

baseline and continual integrity

assessments;

• Data gathered in conjunction with

other inspections, tests, surveillance

and patrols required in Part 195. This

would include information from

corrosion control monitoring and

cathodic protection surveys;

• Information about how a failure

would affect the high consequence area,

such as location of the water intake.

Through this requirement to integrate

and analyze information from diverse

sources, OPS expects an operator to

analyze its entire pipeline to evaluate

the entire range of threats to each

pipeline segment that could affect a

high consequence area. An operator will

75398 Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations

conduct this analysis in conjunction

with the required periodic evaluation

discussed below (section 195.452(j)).

What Actions Must Be Taken To

Address Integrity Issues? Section

195.452(h)

The rule requires an operator to take

prompt action to address all pipeline

integrity issues raised by the integrity

assessment and information analysis. By

prompt action we mean that an operator

must prioritize repairs according to the

severity of the anomaly and address first

those anomalies that pose the greatest

risk to the pipeline’s integrity. The rule

clarifies that an operator must evaluate

all anomalies and repair those that

could affect the pipeline’s integrity. Any

repair made must be done according to

the pipeline repair requirements in 49

CFR § 195.422.

The rule requires that an operator

develop a schedule that prioritizes the

anomalies found during the integrity

assessment and information analysis for

evaluation and repair. In this schedule,

an operator would have to provide for

prompt review and analysis of the

integrity assessment results by a date

certain. For the first three years after the

rule’s effective date, an operator would

determine the period by which the

results would have to be reviewed and

analyzed and commit to that date in its

schedule. After the third year, an

operator’s schedule must provide for

reviewing and analyzing the results of

the integrity assessment within 120 days

of conducting the assessment.

An operator’s schedule also has to

provide time frames for evaluating and

completing repairs. The rule provides

that an operator is to base the schedule

on specified risk factors and pipelinespecific risk factors the operator

develops. For conditions not specified

in the rule and those the rule identifies

as other conditions, the operator

determines the schedule for evaluation

and repair. However, the rule provides

the time frames in which an operator

must complete repair of certain

conditions on the pipeline. These

conditions are listed as immediate

repair conditions, 60-day conditions

and 6-month conditions. Of course, the

rule cannot identify all conditions that

an operator will have to evaluate and

repair. A condition an operator

discovers may qualify as an immediate

repair, 60-day or 6-month condition

even though it is not listed in the rule.

The rule simply provides common

examples of such conditions.

The schedule required for repair starts

at the time the operator discovers the

condition on the pipeline, which occurs

when an operator has adequate

information about the condition to

determine the need for repair.

Depending on circumstances, an

operator could have adequate

information when the operator receives

the preliminary internal inspection

report, gathers and integrates

information from other inspections or

the periodic evaluation, excavates the

anomaly or, receives the final internal

inspection report.

An operator may deviate from the

rule’s specified repair times (immediate

repair, 60-day, 6-month) if the operator

justifies the reasons why the schedule

cannot be met and that the changed

schedule will not jeopardize public

safety or environmental protection. An

operator’s justification for a deviation

would be one of the records the operator

is required to maintain for inspection.

(See section 195.452(l).) An operator

must notify OPS if the operator cannot

meet the schedule and cannot provide

safety through a temporary reduction in

operating pressure until a permanent

repair is made. The operator would have

to provide OPS 90-days notice by mail

or facsimile.

What Preventive and Mitigative

Measures Must an Operator Take To

Protect the High Consequence Area?

Section 195.452(i)

The final rule requires an operator to

take measures to prevent and mitigate

the consequences of a pipeline failure

that could affect a high consequence

area. An operator must conduct a risk

analysis of each pipeline segment to

identify additional actions to enhance

public safety or environmental

protection. The rule lists some

additional preventive or mitigative

measures an operator needs to consider

for the pipeline segment, including

installing emergency flow restricting

devices and modifying the leak

detection systems. An operator is not

limited to the listed measures but

should also identify additional

protective measures not listed.

The rule requires that, in identifying

the need for additional preventive and

mitigative measures, the operator

evaluate the likelihood of a pipeline

release occurring and how a release

could affect the high consequence area.

An operator must consider all relevant

risk factors in making this

determination; the rule lists some that

an operator must consider. An operator

is to supplement the listed risk factors

with any other factors specific or unique

to the pipeline segment. Listed factors

include—terrain surrounding the

pipeline, including drainage systems

such as small streams and other smaller

waterways that could act as a conduit to

the high consequence area; elevation

profile; characteristics of the product

transported; amount of product that

could be released; possibility of a

spillage in a farm field following the

drain tile into a waterway; ditches along

side a roadway the pipeline crosses;

physical support of the pipeline

segment such as by a cable suspension

bridge; and exposure of the pipeline to

operating pressure exceeding

established maximum operating

pressure. In addition, Appendix C to the

rule provides an operator with further

guidance on evaluating how each

pipeline segment could affect a high

consequence area.

Leak Detection

The final rule requires an operator to

have some means to detect leaks on its

pipeline system. The rule further

requires an operator to evaluate the

capability of its leak detection means

and modify the capability, as necessary,

to protect the high consequence area.

The rule lists factors that an operator

must consider when making this

evaluation. Again, the list is not

exclusive. It is simply a starting point

that an operator must supplement with

factors relevant to each pipeline

segment being evaluated.

Some examples of leak detection

systems include—

Dynamic flow modeling: This model

simulates the operating conditions of

the pipeline through hydraulic

calculations, then compares the

computed pressures (based on flow rate,

temperature, pipe profile, and density)

against real time data obtained from

various measuring points along the

pipeline. Deviations are compared

against alarm set points. When the

deviations exceed the set points, the

system alarms. These systems are

normally integrated with the pipeline

SCADA communications technology.

Leak location information is not

provided.

Tracer chemical: This approach

requires mixing a very small amount

(ppb to ppm of total volume) of a

specific volatile chemical tracer with

the contents of a pipeline. The chemical

tracer is not a component of the pipeline

contents and does not occur naturally in

the soil. After the pipeline is inoculated

with the tracer chemical, samples of the

vapor contained in the soil outside the

pipeline are collected. The soil vapor

samples are obtained from probes or

other devices installed intermittently

along the pipeline. The vapor samples

are analyzed by a gas chromatograph for

the specific tracer chemical that was

mixed with the pipeline contents.

Presence of the tracer chemical in the

Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations 75399

sample can only occur through an active

release of pipeline product mixed with

the tracer into the soil. These systems

are able to provide single or continuous

liquid tightness tests and will provide

release location information.

Release Detection Cable: Release

detection sensing cables are designed to

alarm after contact with liquid

hydrocarbons at any point along their

length. The presence of hydrocarbons

creates a circuit between two sensing

wires and triggers an alarm. Typically,

leak detection cable is installed in

slotted PVC conduit that is buried in the

pipe trench along or below the pipeline.

These systems provide continuous

monitoring via electronic control units

capable of interfacing with SCADA

technology and are able to provide leak

location information.

Shut-in (static) released detection:

This technique consists of a pressure

test, with the pipeline filled with its

normal contents. Between shipments,

the pipeline is pressured against a

closed valve(s). This release detection

tool allows the operator to analyze the

pipeline in a static (no flow) mode,

without the complications of dynamic

modeling. With the pipeline blocked,

the pressure (compensated for

temperature fluctuations) in a section

should remain constant. The pressure is

then monitored for any unexplained

pressure losses. This test does not

provide leak location information.

Pressure point analysis release

detection software: Software for this

system incorporates two independent

methods of release detection: pressure

point analysis and mass balance. Pattern

recognition algorithms that distinguish

normal operating events from leaks are

used. With an appropriate

communications system, this system

can provide the calculated location of a

release.

Emergency flow restricting devices

(EFRDs)

The rule requires an operator to

install an EFRD if the operator

determines that an EFRD is needed on

a pipeline segment to protect a high

consequence area in the event of a

hazardous liquid pipeline release. The

rule lists certain factors that an operator

must consider in making this

determination, to be supplemented with

other factors the operator determines are

relevant to the pipeline segment being

evaluated. Listed factors an operator

must consider include the swiftness of

leak detection and pipeline shutdown

capabilities, the type of commodity

carried, the rate of potential leakage, the

volume that can be released, topography

or pipeline profile, the potential for

ignition, proximity to power sources,

location of nearest response personnel,

specific terrain between the pipeline

and the high consequence area, and

benefits expected by reducing the spill

size.

Installing an EFRD on a pipeline

segment is only one of several possible

preventive or mitigative measure that an

operator can take to provide additional

protection to a high consequence area.

What is a Process for Continual

Evaluation and Assessment to Maintain

a Pipeline’s Integrity? Section 195.452(j)

The integrity assessment requirements

do not stop with the baseline integrity

assessment. An operator must continue

to assess the integrity of the line pipe

and evaluate the integrity of each

pipeline segment that could affect a

high consequence area. The rule

requires an operator to conduct a

periodic evaluation of each pipeline

segment, as frequently as needed, to

assure the pipeline’s integrity. An

operator would determine frequency

based on specified risk factors plus

other factors specific to the pipeline

segment.

The evaluation is based, in part, on

the information analysis the operator

has made of the entire pipeline to

determine what history and operations

elsewhere could be relevant to the

segment. The evaluation must also

consider the past and present integrity

assessment results, and decisions about

repair, and preventive and mitigative

actions. The evaluation must be done by

a person qualified to evaluate the results

and other related data.

As with the baseline assessment, the

continual integrity assessment method

must be by internal inspection, pressure

test, or other technology that provides

an equivalent understanding of the

condition of the line pipe. As with the

baseline assessment, if an operator

chooses other technology as a reassessment method, the operator must

give 90-days advance notice (by mail or

facsimile) to OPS.

An operator must conduct the

integrity re-assessment at intervals not

to exceed five years, except in those

limited instances where the operator

can clearly justify an extended interval.

The rule requires that an operator base

the continual assessment intervals on

the risk the line pipe poses to the high

consequence area to determine the

priority for assessing the pipeline

segments. An operator must establish

the assessment intervals using specified

risk factors (supplemented by risk

factors relevant to the pipeline

segment), the information analysis, and

analysis of the results from the last

integrity assessment.

The rule recognizes limited

exceptions to the five-year period.

• An operator may be able to justify

an engineering basis for a longer

assessment interval on a segment of line

pipe. The operator must support the

justification by a reliable engineering

evaluation combined with the use of

other technology, such as external

monitoring technologies. An operator

would also have to demonstrate that the

other technology would provide an

understanding of the line pipe

equivalent to that obtained by an

assessment conducted at an interval of

five years or less.

• The other exception is that an

operator may not be able to conduct an

integrity assessment on a segment of

pipe within the required period because

sophisticated internal inspection

devices or other technology is not

available. An operator must justify the

reasons why it cannot comply with the

required assessment period of not more

than five years and must also

demonstrate the actions it is taking to

evaluate the integrity of the pipeline

segment in the interim.

In either instance, the operator must

inform OPS of its proposed variance

from intervals of not more than five

years. A 90-day advance notice before

the end of intervals of not more than

five years is needed if the operator will

require a longer assessment interval

because sophisticated technology is not

available. If the operator is justifying a

longer assessment interval on an

engineering basis, notice must be given

nine months before the end of the

interval of five years or less.

• The engineering-based exception

has been included in the rule to

encourage the use of advanced

alternative technologies. It is intended

for use in those instances where an

operator is employing an advanced

alternative technology and should

therefore be dictated by the use of such

technology. It is intended to be a limited

exception to the interval of five years or

less and not to exceed an additional two

years whenever possible.

What Methods To Measure Program

Effectiveness Must Be Used? Section

195.452(k)

The final rule requires that an

operator include in its integrity

management program methods to

measure whether the program is

effective in assessing and evaluating the

integrity of each pipeline segment and

in protecting the high consequence

areas. Because performance measures

must be tailored to an individual

75400 Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations

program, the rule does not specify the

measures an operator has to include.

However, in the Appendix C to this

rule we have provided guidance on

performance measures. The guidance

also gives examples of categories of

performance measures that an operator

should consider. Examples of measures

that an operator could adapt for its

program include—

• Selected Activity Measures—

Measures that monitor the surveillance

and preventive activities the operator

has implemented.

• Deterioration Measures—Operation

and Maintenance trends that indicate

when the integrity of the system is

weakening despite preventive measures.

• Failure Measures—Leak History,

incident response, product loss, etc.

These measures will indicate progress

towards fewer spills and less damage.

• Internal vs. External Comparisons.

Comparing data that could affect a high

consequence area with data from

pipeline segments in other areas of the

system, and comparing data external to

the pipeline segment.

What Records Must Be Kept? Section

195.452(l)

The final rule requires that an

operator maintain certain records for

inspection, including its written

integrity management program. This

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 inspection

documents that support the decisions

and analyses made, and actions taken to

implement and evaluate each element of

the integrity management program. This

would also include records

documenting any modifications,

justifications, variances, deviations and

determinations made. Again, this

requirement is no different from the

myriad documents an operator now

maintains to comply with the other

provisions of the pipeline safety

regulations.

The rule cannot possibly list all

records that an operator would have to

maintain to demonstrate its compliance

with the integrity management program

requirements. Appendix C provides

examples of some documents that an

operator would need to maintain for

inspection. The list is not exhaustive.

Listed examples include:

• Record identifying all pipeline

segments that could affect a high

consequence area;

• Baseline assessment plan that

includes each required plan element;

• Modifications to the baseline

assessment plan and reasons for the

modifications;

• Use of and support for alternative

practices;

• An integrity management program

framework that includes each of the

required program elements, updates and

modifications to the initial framework

and eventual program;

• Process for establishing the baseline

and continual re-assessment intervals;

• Process for identifying population

changes around a pipeline segment;

• Any variance from the required reassessment intervals, and reasons for the

deviation;

• Results of the baseline and

continual integrity assessments;

• Results of the information analyses

and periodic evaluations;

• Process for integrating and

analyzing information about the

integrity of a pipeline;

• Process and risk factors used for

determining the frequency of periodic

evaluations;

• Schedule for reviewing and

analyzing integrity assessment results;

• Schedule for evaluating and

repairing anomalies found during the

integrity assessment;

• Any deviation from the required

repair schedule for the listed conditions;

• Criteria for repair actions; records of

anomalies detected actions taken to

evaluate and repair the anomalies;

• Records of other remedial actions

planned or taken;

• Risk analysis to identify additional

preventive or mitigative measures,

records of preventive and mitigative

actions planned or taken;

• Criteria and process for determining

EFRD installation;

• Criteria and process for evaluating

leak detection capability;

• Program performance measures.

Appendix C

We are adding a new Appendix C to

Part 195. This Appendix gives guidance

to help an operator implement the

requirements of the integrity

management program rule. An operator

is not required to use this guidance. The

Appendix contains guidance on—

• Information an operator may use to

identify a high consequence area and

factors an operator may use to consider

the potential impacts of a release on a

high consequence area;

• Risk factors an operator may use to

determine an integrity assessment

schedule;

• Safety risk indicator tables for leak

history, volume or line size, age of

pipeline, and product transported, an

operator may use to determine if a

pipeline segment falls into a high,

medium or low risk category.

• Types of internal inspection tools

an operator may use to find pipeline

anomalies;

• Measures an operator could use to

measure an integrity management

program’s performance; and

• Types of records an operator will

have to maintain.

Regulatory Analyses and Notices

Executive Order 12866 and DOT

Regulatory Policies and Procedures

The Department of Transportation

(DOT) considers this action to be a

significant regulatory action under

section 3(f) of Executive Order 12866

(58 FR 51735; October 4,1993).

Therefore, it was forwarded to the Office

of Management and Budget. This final

rule is significant under DOT’s

regulatory policies and procedures (44

FR 11034: February 26, 1979).

Consideration of Public Comments

We received a number of comments

that related to the draft Regulatory

Evaluation that accompanied the

proposed rule (65 FR 21695). OPS has

considered those comments and has

made changes in this evaluation where

appropriate. Provided below is a

summary of the comments and any

changes made to the Regulatory

Evaluation.

1. Costs for Developing Integrity

Management Programs. Commenters

suggested that the costs for developing

integrity management programs were

underestimated. The comments

suggested that integrity management

programs can cost $75–$300 thousand,

rather than the $25–$75 thousand range

used in the draft evaluation. OPS

acknowledges that its estimate of the

costs to prepare integrity management

programs may have been too low. OPS

has used the suggested range in this

evaluation. OPS has continued to

assume that 10 percent of the operators

covered by the rule (those who own or

operate 500 or more miles of hazardous

liquid pipeline) will have already

developed company-specific integrity

management programs. Operators’ costs

to develop these programs have already

been expended; operators will incur no

further costs as a result of this rule. OPS

has revised the estimated cost that will

be incurred by the remaining 90 percent

of covered operators for developing

programs to $100 thousand. (It is

assumed that the programs operators

develop that comply with the final rule

will be less costly than the

comprehensive programs that some

operators have developed voluntarily.)

Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations 75401

2. Costs for Periodic Update and

Documentation. Commenters also

suggested that the costs for periodic

program updates and documentation

(called ‘‘reports’’ in the draft evaluation)

were underestimated. They estimated a

range of $50–150 thousand for this

work. OPS agrees that the estimate in

the draft evaluation was unrealistically

low. In that evaluation, the only

documentation considered was records

of assessments, which were assumed to

be produced by lower level personnel

under general supervision. The draft

evaluation failed to consider the need to

evaluate whether changes to the

program are needed, because technology

or the pipeline changes or because high

consequence areas are redrawn (as they

will be periodically), and to make those

changes. Operators will expend

resources to evaluate these things, even

if few changes are made. This will add

costs. No update or changes will be

required in some years, when the only

expense will be to consider new

information to ascertain whether an

update is needed. OPS cannot accept,

however, the presumption that the range

of such annual costs will significantly

overlap the range of costs to develop the

programs in the first place, as suggested

by the comment. Significantly less work

is involved in updating an existing

program. For purposes of this

evaluation, OPS included the need to

update an integrity management

program. Costs for this effort were

estimated at $8,000 per year, which is

considered reasonable compared to the

estimated cost for developing the

program initially. Routine

documentation is estimated at $2,000

annually, an increase of a factor of two

from the estimate included in the draft

evaluation. The net annual cost for

updates and documentation is thus

$10,000 per operator or $660 thousand

in total.

OPS also included in this final

evaluation costs for data integration.

These costs will include a need to

realign company-internal data

management systems in the first year

and continuing costs for the

professional review of the integrated

data related to the integrity of pipelines

in high consequence areas. OPS has

estimated costs for these activities at

$50,000 per operator in the first year

after the rule (when internal data

management realignment will occur)

and $25,000 per year thereafter.

3. New Assessment will be Required.

Commenters disagreed with the

assumption in the draft evaluation that

no additional integrity assessment

would be required, since operators were

conducting internal inspection and

pressure testing at a rate sufficient to

complete all required baseline

assessment in the first seven years after

the effective date of the rule. The total

number of affected pipeline miles has

also increased since the proposed rule.

Because of these changes, OPS agrees

that integrity assessment of the number

of pipeline miles affected by the final

rule will require an increase in the rate

of assessment represented by recent

industry practice. OPS continues to

assume that initial assessment would

have proceeded at the current rate if

there were no rule. OPS has estimated

costs for assessment that will be

required above that rate to assure that

all affected pipeline is assessed in the

seven years following the effective date

of the rule.

4. Need for More Detailed Cost-benefit

Analysis. Commenters, including the

Technical Hazardous Liquid Pipeline

Safety Standards Committee (Advisory

Committee), contended that the

Regulatory Evaluation is not consistent

with the OPS framework for cost-benefit

analyses or in conformance with

applicable standards. They suggested

that OPS perform a more rigorous

evaluation, perhaps in parallel with the

rulemaking. They recommended that

the suggested analysis quantify the

benefits of the proposed rule, which was

not done for the draft evaluation. The

Advisory Committee unanimously voted

that the Cost-Benefit Analysis was not

sufficient. Commenters also cited failure

to identify a specific target problem.

OPS has revised the regulatory

evaluation to more closely follow the

form of the framework. This included

identifying the target problem. OPS

agrees with the concerns of the

Advisory Committee and other

commenters but notes that it does not

have adequate data on pipeline spills to

accurately gauge the benefits of this

rule. The DOT Inspector General, in its

audit report, ‘‘Pipeline Safety Program

Report No. RT–2000–069, March 12,

2000, stated, ‘‘OPS accident database

contains inaccurate causal information

and underestimates property damage.’’

These problems make it difficult to

prepare a more rigorous analysis. OPS

has done some further research to

examine the availability of additional

data. OPS turned to data from the

National Oceanographic and

Atmospheric Administration (NOAA),

the lead Federal Agency on quantifying

the costs of hazardous liquid spills.

In their paper, Putting Response and

Natural Resource Damage Costs in

Perspective, Douglas Helton and Tony

Penn, employees of NOAA, wrote that,

‘‘[t]he total private and social cost of oil

spills is of great interest to industry,

responders, and regulators, but

relatively few incidents have been

examined in detail. Furthermore,

publicly available cost data are often

limited to State and Federal response

costs and natural resource damages.

Significant categories of costs, such as

private response costs, third party

claims, and vessel or facility repair

costs, are often not publicly available.’’

The authors further warn that, ‘‘[w]hen

cost estimates are reported, they should

be considered partial and spill volumes

should be viewed with some

skepticism.’’ They conclude that,

‘‘[f]ailure to consider these additional

cost categories because of unavailable

data may result in erroneous

conclusions regarding the total cost of

spills and the significance of any one

category.’’

Helton and Penn studied 48 spills

between 1984 and 1997. (Note that most

were not from pipelines.) Cost

categories varied widely. Third party

claims varied from less than 1% to more

than 95% of total damages. Natural

resource damages also varied from

under 3% to 95%. Response costs also

varied widely. The data set included 5

pipeline oil spills. The total known

costs of the pipeline spills ranged from

$4.3 million to $71.4 million.

The report concludes that, ‘‘[s]pills

are costly events, and depending on the

size and location of the spill may cost

millions of dollars * * * The inability

to account for all the costs of spills also

has implications in other regulatory

programs. Costs per unit spilled are

often used in regulatory settings and the

lack of complete data on the total costs

of spills might result in inadequate

liability limits.’’

OPS recognizes its data problems. To

illustrate a few examples, the original

estimate of the PEPCO spill the operator

provided was $50,000 + of property

damage. On further prodding the

operator responded with supplemental

reports raising costs to over $50 million.

Note that OPS reporting of accidents

lumps together the categories of product

lost, property damage and response

costs, and environmental damage. This

makes any kind of analysis extremely

difficult.

A closer examination of OPS spill

reports confirmed the DOT Inspector

General’s audit conclusion that OPS

data collection concerning costs of oil

spills is poor. The cause of this problem

is two-fold.

(1) The need to collect improved data

by requiring operators to report their

data by category, for example to

separately indicate cost of product loss,

property damage to the operator, private

parties, and to the public in terms of

75402 Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations

natural resource damages. A more

detailed listing of the costs of

restoration and clean-up is necessary for

better analysis, and

(2) Presently, accident reporting

regulations require that operators report

accident cost no later than 30 days from

the incident occurrence. Supplemental

reports are required thereafter when

new information is available. Because of

the complexity of some major oil spills,

cleanup and restoration costs may not

be known for several years after the

spill. In a 1997 accident that OPS

recently reexamined, the final costs

have not been decided because the case

is still under litigation.

Pipeline operators, as well as OPS,

have not been diligent in requesting and

providing supplemental reports. OPS

will soon be taking corrective actions to

ensure that timely and accurate

supplemental reports are provided. In

the absence of appropriate data OPS

recognizes that it cannot appropriately

determine the benefits of regulations

which reduce the number of oil spills.

However, as the data from NOAA

indicate as well as the recent

information from the PEPCO spill, even

the reported costs from oil spills

represent a significant social cost to

society. OPS regrets its data problems.

However, as NOAA reports, OPS is not

alone among Federal regulatory agencies

in collecting insufficient spill data. OPS

has recently proposed changes to its gas

accident reporting. It will be proposing

changes to its oil spill accident

reporting requirements in the future.

However, the importance of this

regulation in preventing the

consequences of releases from

hazardous liquid pipelines that could

affect high consequence areas requires

that OPS place this requirement on the

industry in the absence of complete

spill data. As stated in this evaluation,

OPS concludes that the rule is justified

based on the modest costs to implement

and the subjective benefits of improving

knowledge of pipe condition,

addressing public concerns, and

reducing the frequency and

consequence of pipeline releases that

affect high consequence areas. OPS

concludes that this is adequate

justification.

5. The definition of high consequence

areas should be expanded to include all

national parks and fish hatcheries. The

Department of the Interior and the

Environmental Protection Agency

strongly recommended that the National

Parks and National Fish Hatcheries be

included as high consequence areas. We

have not included these areas in the

definition of high consequence areas.

We will consider additional protection

for these areas, among others, in a future

rulemaking.

The following section summarizes the

final regulatory evaluation’s findings.

Hazardous liquid pipeline spills can

adversely affect human health and the

environment. The magnitude of this

impact differs. There are some areas in

which the impact of a spill will be more

significant than it would be in others

due to concentrations of people who

could be affected or to the presence of

environmental resources that are

unusually sensitive to damage. Because

of the potential for dire consequences of

pipeline failures in certain areas, these

areas merit a higher level of protection.

OPS is promulgating this regulation to

afford the necessary additional

protection to these high consequence

areas.

Numerous investigations by 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 remotelyoperated 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 rulemaking addresses the target

problem described above, and is a

comprehensive response to NTSB’s

recommendations and Congressional

mandates, as well as pipeline safety and

environmental issues raised over the

years.

This rule focuses on a systematic

approach to integrity management to

reduce the potential for hazardous

liquid pipeline failures that could affect

populated and unusually sensitive

environmental areas, and commercially

navigable waterways. This rulemaking

requires pipeline operators to develop

and follow an integrity management

program that continually assesses,

through internal inspection, pressure

testing, or equivalent alternative

technology, the integrity of those

pipeline segments that could affect areas

we have defined as high consequence

areas i.e., populated areas, areas

unusually sensitive to environmental

damage, and commercially navigable

waterways. The program must also

evaluate the segments through

comprehensive information analysis,

remediate integrity problems and

provide additional protection through

preventive and mitigative measures.

This final rule (the first in a series of

integrity management program

regulations) covers hazardous liquid

pipeline operators that own or operate

500 or more miles of pipeline used in

transportation. OPS intends to propose

integrity management program

requirements for the liquid operators

not covered by this final rule and for

natural gas transmission operators. OPS

chose to start the series with this group

of hazardous liquid operators because

the pipelines they operate have the

greatest potential to adversely affect the

environment, based on the volume of

product these pipelines 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 approximately 35.5

thousand miles (of the 157,000 miles of

hazardous liquid pipeline in the U.S.)

will be impacted by this final rule.

We have estimated the cost to develop

the necessary program at approximately

$5.94 million, with an additional annual

cost for program upkeep and reporting

of $660,000. An operator’s program

begins with a baseline assessment plan

and a framework that addresses each

required program element. The

framework indicates how decisions will

initially 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 rule requires a baseline

assessment of covered pipeline

segments through internal inspection,

pressure test, or use of other technology

capable of comparable performance. The

baseline assessment must be completed

Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations 75403

within seven years after the final rule

becomes effective. After this baseline

assessment, an operator is further

required to periodically re-assess and

evaluate the pipeline segment to ensure

its integrity. It is estimated that the cost

of periodic reassessment will generally

not occur until the sixth year unless the

baseline assessment indicates

significant defects that would require

earlier reassessment. Integrating

information related to the pipeline’s

integrity is a key element of the integrity

management program. Costs will be

incurred in realigning existing data

systems to permit integration and in

analysis of the integrated data by

knowledgeable pipeline safety

professionals. The total costs for the

information integration requirements in

this rule are $2.95 million in the first

year and $1.5 million annually

thereafter.

The rule requires operators to identify

additional preventive or mitigative

measures that would enhance public

safety or environmental protection

based on a risk analysis of the pipeline

segment. One of the many preventive or

mitigative actions an operator may take

is to install an EFRD on the pipeline

segment. OPS could not estimate the

total cost of installing EFRDs because

OPS does not know how many operators

will install them. Additionally,

requirements have been added for an

operator to evaluate its leak detection

capability and modify that capability, if

necessary. OPS does not know how

many operators currently have leak

detection systems or how many will be

installed or upgraded as a result of this

rule. OPS was therefore also unable to

estimate the total costs of the leak

detection requirements.

Affected operators will be required to

assess more line pipe in segments that

could affect high consequence areas as

a result of this rule than they would

have been expected to assess if the rule

had not been issued. Integrity

assessment consists of a baseline

assessment, to be conducted over the

first seven years after the effective date

of the rule, and subsequent reassessment at intervals not to exceed

every five years.

OPS has estimated the annual cost of

additional baseline assessment that will

be required by this rule as $9.95 million.

The cost for additional re-assessment

that will be required to meet the fiveyear re-assessment requirement is $17

million per year. Cost impact will be

greater in the sixth and seventh years

after the effective date of the rule due to

an overlap between baseline inspection

and the initial subsequent testing. The

additional costs in these two years are

estimated at $38.2 million.

The benefits of this rule can not easily

be quantified but can be described in

qualitative terms. Issuance of this final

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 final 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 rule has also stimulated the

pipeline industry to begin developing a

supplemental consensus standard to

support risk-based approaches to

integrity management. The rule 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

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 final rule provides for a

verification 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 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

rule is intended to accomplish that.

The public has expressed concern

about the danger hazardous liquid

pipelines pose to their neighborhoods.

The integrity management process leads

to greater accountability to the public

for both the operator and the regulator.

This accountability is enhanced through

our choice of a map-based approach to

defining the areas most in need of

additional protection—the visual

depiction of the populated areas,

unusually sensitive environmental

areas, and commercially navigable

waterways in need of protection focuses

on the safety and environmental issues

in a manner that will be easily

understandable to everyone. The 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.

75404 Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations

OPS has not provided quantitative

benefits for the continual integrity

management evaluation required in this

final 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 five years, will 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 requirements.

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 rulemaking was designed to impact

only those hazardous liquid operators

that own or operate 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 final rule.

Based on this, and the evidence

discussed above, I certify that this final

rule will not have a significant impact

on a substantial number of small

entities.

Paperwork Reduction Act

This rule 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.

Several commenters (pipeline

operators and trade associations),

suggested that OPS underestimated the

time and cost to develop the necessary

program as well as the time and costs to

revise the program. OPS concurs with

these comments and has revised the

costs burden hours as shown below.

Sixty-six hazardous liquid operators

will be subject to this final rule. It is

estimated that 59 of these operators will

have to develop integrity management

programs taking approximately 2800

hours per program. (Ten percent of

hazardous liquid operators are

estimated to already have sufficient

programs to comply with the rule.) Each

of the 59 operators would also have to

devote 1,000 in the first year to integrate

this data into current management

information systems.

Additionally, all 66 operators will be

required to update their programs on a

continual basis. This will take

approximately 330 hours per program

annually. An additional 500 hours per

operator (for the 90% of operators who

do not have a program or whose

program does not comply with the rule)

will be required to annually integrate

the data into the operator’s current

management information systems.

Operators are required to either use

hydrostatic testing or smart pigging as a

method to assess their pipelines.

However, operators can use another

technology if it can demonstrate it

provides an equivalent understanding of

the condition of the line pipe as the

other two assessment methods.

Operators have to provide OPS 90-days

notice (by mail or facsimile) before

using the other technology. OPS

believes that few operators will choose

this option. If they do choose an

alternate technology, notice preparation

should take approximately one hour.

Because OPS believes few if any

operators will elect to use other

technologies, the burden was

considered minimal and therefore not

calculated.

Additionally, operators could seek a

variance in limited situations from the

required five-year continual reassessment interval if they can provide

the necessary justification and

supporting documentation. Notice

would have to be provided to OPS when

an operator seeks a variance. OPS

believes that approximately 10% of

operators may request a variance. This

is approximately 7 operators. The

advance notification can be in the form

of letter or fax. OPS believes the burden

of a letter or fax is minimal and

therefore did not add it to the overall

burden hours discussed above.

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, D.C. 20503: Attention Desk

Officer for the Department of

Transportation. Comments must be sent

within 30 days of the publication of this

final rule.

The Office of Management and Budget

is specifically interested in the

following issues concerning the

information collection:

• Evaluating whether the 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 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

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 final 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 final 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 final rule has been analyzed in

accordance with the principles and

criteria contained in Executive Order

13132 (‘‘Federalism’’). This final rule

does not adopt 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,

Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations 75405

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 final rule in

accordance with section 102(2)(c) of the

National Environmental Policy Act (42

U.S.C. Section 4332), the Council on

Environmental Quality regulations (40

CFR Sections 1500–1508), and DOT

Order 5610.1D, and have determined

that this action would not significantly

affect the quality of the human

environment. We updated the

Environmental Assessment that

supported the proposed rule (65 FR

21695) to reflect the provisions of the

final rule.

The final Environmental Assessment

determined that the combined impacts

of the initial baseline assessment

(pressure testing or internal inspection),

the subsequent periodic assessments,

and additional preventive and

mitigative measures that may be

implemented to protect high

consequence areas will result in positive

environmental impacts. The number of

incidents and the environmental

damage from failures in and near high

consequence areas are likely to be

reduced. However, from a national

perspective, the impact is not expected

to be significant for the pipeline

operators covered by the final rule. The

following discussion summarizes the

analysis provided in the final

Environmental Assessment.

Many operators covered by the final

rule already have internal inspection

and testing programs. These operators

typically place a high priority on the

pipeline’s proximity to populated areas,

recreation and conservation areas, and

environmental resources when making

decisions about where and when to

inspect and test pipelines. As a result,

pipelines that could affect some of the

defined high consequence areas have

already been recently assessed, and a

sizeable fraction of pipelines in the

remaining locations would likely have

been assessed in the next several years,

without the provisions of the rule. The

primary effect of the rule—accelerating

integrity assessment of pipeline

segments that could affect 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 these segments are assessed

forward by a few years, has only a small

effect on the likelihood of pipeline

failures in or near high consequence

areas.

Neither internal inspection nor

pressure testing protect against all

threats to pipeline integrity.

Specifically, they do not prevent outside

force damage, the most significant

contributor to hazardous liquid pipeline

failures. However, the rule does require

operators to conduct an integrated

analysis and evaluation 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

evaluations 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 rule already perform integrity

evaluations or formal risk assessments

that consider the impacts of pipeline

system failures on the environment and

population in proximity to their lines.

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 integrated evaluation will be limited

with most new actions customized to

address site-specific integrity issues 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 risk

reduction benefits of additional risk

controls are not justified.

The primary benefits of the final rule

will be to establish requirements for

conducting integrity assessments and

periodic evaluations of the pipeline

segments that could affect high

consequence areas. In effect, this will

establish uniform integrity management

programs across the pipeline industry

and enhance the integrity assessment

activities many operators are currently

implementing. It will also require

operators who have minimal, or no,

integrity assessment and evaluation

programs to raise their level of

performance. Thus, the rule is expected

to ensure a more consistent, and overall

higher level of integrity assurance for

high consequence areas across the

industry.

In accordance with 40 CFR Section

1508.13, based on the updated

Environmental Assessment, and no

receipt of comment or information

showing otherwise, we have prepared a

Finding of No Significant Impact

(FONSI) for this final rule. The updated

Environmental Assessment and the

Finding of No Significant Impact are

available for review in the docket.

List of Subjects in 49 CFR Part 195

Carbon dioxide, High consequence

areas, Integrity assurance, Petroleum,

Pipeline safety, Reporting and

recordkeeping requirements.

In consideration of the foregoing, OPS

is amending 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. 5103, 60102, 60104,

60108, 60109, 60118; and 49 CFR 1.53.

Subpart F—Operation and

Maintenance

2. New §§ 195.450 and 195.452 are

added under new undesignated

centerheadings of ‘‘High Consequence

Areas’’ and ‘‘Pipeline Integrity

Management’’, respectively, to subpart F

to read as follows:

High Consequence Areas

195.450 Definitions.

Pipeline Integrity Management

195.452 Pipeline integrity management in

high consequence areas.

High Consequence Areas

§ 195.450 Definitions.

The following definitions apply to

this section and § 195.452:

Emergency flow restricting device or

EFRD means a check valve or remote

control valve as follows:

(1) Check valve means a valve that

permits fluid to flow freely in one

direction and contains a mechanism to

75406 Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations

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. The RCV is usually

operated 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.

High consequence area means:

(1) A commercially navigable

waterway, which means a waterway

where a substantial likelihood of

commercial navigation exists;

(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;

(4) An unusually sensitive area, as

defined in § 195.6.

Pipeline Integrity Management

§ 195.452 Pipeline integrity management in

high consequence areas.

(a) Which operators must comply?

This section applies to each operator

who owns or operates a total of 500 or

more miles of hazardous liquid pipeline

subject to this part.

(b) What must an operator do? (1) No

later than March 31, 2002, an operator

must develop a written integrity

management program that addresses the

risks on each pipeline segment that

could affect a high consequence area.

An operator must include in the

program:

(i) An identification of all pipeline

segments that could affect a high

consequence area. A pipeline segment

in a high consequence area is presumed

to affect that area unless the operator’s

risk assessment effectively demonstrates

otherwise. (See Appendix C of this part

for guidance on identifying pipeline

segments.) An operator must complete

this identification no later than

December 31, 2001;

(ii) A plan for baseline assessment of

the line pipe (see paragraph (c) of this

section);

(iii) 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.

(2) An operator must implement and

follow the program it develops.

(3) In carrying out this section, an

operator must follow recognized

industry practices unless the section

specifies otherwise or the operator

demonstrates that an alternative practice

is supported by a reliable engineering

evaluation and provides an equivalent

level of public safety and environmental

protection.

(c) What must be in the baseline

assessment plan? (1) An operator must

include each of the following elements

in its written baseline assessment plan:

(i) The methods selected to assess the

integrity of the line pipe. For low

frequency electric resistance welded

pipe or lap welded pipe susceptible to

longitudinal seam failure, an operator

must select integrity assessment

methods capable of assessing seam

integrity and of detecting corrosion and

deformation anomalies. An operator

must assess the integrity of the line pipe

by:

(A) Internal inspection tool or tools

capable of detecting corrosion and

deformation anomalies including dents,

gouges and grooves;

(B) Pressure test conducted in

accordance with subpart E of this part;

or

(C) Other technology that the operator

demonstrates can provide an equivalent

understanding of the condition of the

line pipe. An operator choosing this

option must notify the Office of Pipeline

Safety (OPS) 90 days before conducting

the assessment, by sending a notice to

the address specified in § 195.58 or to

the facsimile number specified in

§ 195.56;

(ii) A schedule for completing the

integrity assessment;

(iii) An explanation of the assessment

methods selected and evaluation of risk

factors considered in establishing the

assessment schedule.

(2) An operator must document, prior

to implementing any changes to the

plan, any modification to the plan, and

reasons for the modification.

(d) When must the baseline

assessment be completed? (1) Time

period. An operator must establish a

baseline assessment schedule to

determine the priority for assessing the

pipeline segments. An operator must

complete the baseline assessment by

March 31, 2008. An operator must

assess at least 50% of the line pipe

subject to the requirements of this

section, beginning with the highest risk

pipe, by September 30, 2004.

(2) Prior assessment. To satisfy the

requirements of paragraph (c)(1)(i) of

this section, an operator may use an

integrity assessment conducted after

January 1, 1996, if the integrity

assessment method meets the

requirements of this section. However, if

an operator uses this prior assessment as

its baseline assessment, the operator

must re-assess the line pipe according to

the requirements of paragraph (j)(3) of

this section.

(3) Newly-identified areas. (i) When

information is available from the

information analysis (see paragraph (g)

of this section), or from Census Bureau

maps, that the population density

around a pipeline segment has changed

so as to fall within the definition in

§ 195.450 of a high population area or

other populated area, the operator must

incorporate the area into its baseline

assessment plan as a high consequence

area within one year from the date the

area is identified. An operator must

complete the baseline assessment of any

line pipe that could affect the newlyidentified high consequence area within

five years from the date the area is

identified.

(ii) An operator must incorporate a

new unusually sensitive area into its

baseline assessment plan within one

year from the date the area is identified.

An operator must complete the baseline

assessment of any line pipe that could

affect the newly-identified high

consequence area within five years from

the date the area is identified.

(e) What are the risk factors for

establishing an assessment schedule (for

both the baseline and continual integrity

assessments)? (1) An operator must

establish an integrity assessment

schedule that prioritizes pipeline

segments for assessment (see paragraphs

(d)(1) and (j)(3) of this section). An

operator must base the assessment

schedule on all risk factors that reflect

the risk conditions on the pipeline

segment. The factors an operator must

consider include, but are not limited to:

(i) Results of the previous integrity

assessment, defect type and size that the

assessment method can detect, and

defect growth rate;

(ii) Pipe size, material, manufacturing

information, coating type and condition,

and seam type;

(iii) Leak history, repair history and

cathodic protection history;

(iv) Product transported;

(v) Operating stress level;

(vi) Existing or projected activities in

the area;

(vii) Local environmental factors that

could affect the pipeline (e.g.,

corrosivity of soil, subsidence, climatic);

(viii) geo-technical hazards; and

Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations 75407

(ix) Physical support of the segment

such as by a cable suspension bridge.

(2) Appendix C of this part provides

further guidance on risk factors.

(f) What are the elements of an

integrity management program? An

integrity management program begins

with the initial framework. An operator

must continually change the program to

reflect operating experience,

conclusions drawn from results of the

integrity assessments, and other

maintenance and surveillance data, and

evaluation of consequences of a failure

on the high consequence area. An

operator must include, at minimum,

each of the following elements in its

written integrity management program:

(1) A process for identifying which

pipeline segments could affect a high

consequence area;

(2) A baseline assessment plan

meeting the requirements of paragraph

(c) of this section;

(3) An analysis that integrates all

available information about the integrity

of the entire pipeline and the

consequences of a failure (see paragraph

(g) of this section);

(4) Criteria for repair actions to

address integrity issues raised by the

assessment methods and information

analysis (see paragraph (h) of this

section);

(5) A continual process of assessment

and evaluation to maintain a pipeline’s

integrity (see paragraph (j) of this

section);

(6) Identification of preventive and

mitigative measures to protect the high

consequence area (see paragraph (i) of

this section);

(7) Methods to measure the program’s

effectiveness (see paragraph (k) of this

section);

(8) A process for review of integrity

assessment results and information

analysis by a person qualified to

evaluate the results and information (see

paragraph (h)(2) of this section).

(g) What is an information analysis?

In periodically evaluating the integrity

of each pipeline segment (paragraph (j)

of this section), an operator must

analyze all available information about

the integrity of the entire pipeline and

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

segment;

(2) Data gathered through the integrity

assessment required under this section;

(3) Data gathered in conjunction with

other inspections, tests, surveillance

and patrols 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 the water intake.

(h) What actions must be taken to

address integrity issues? (1) General

requirements. An operator must take

prompt action to address all pipeline

integrity issues raised by the assessment

and information analysis. An operator

must evaluate all anomalies and repair

those anomalies that could reduce a

pipeline’s integrity. An operator must

comply with § 195.422 in making a

repair.

(2) Discovery of a condition.

Discovery of a condition occurs when

an operator has adequate information

about the condition to determine the

need for repair. Depending on

circumstances, an operator may have

adequate information when the operator

receives the preliminary internal

inspection report, gathers and integrates

information from other inspections or

the periodic evaluation, excavates the

anomaly, or when an operator receives

the final internal inspection report. The

date of discovery can be no later than

the date of the integrity assessment

results or the final report.

(3) Review of integrity assessment. An

operator must include in its schedule

for evaluation and repair (as required by

paragraph (h)(4) of this section), a

schedule for promptly reviewing and

analyzing the integrity assessment

results. After March 31, 2004, an

operator’s schedule must provide for

review of the integrity assessment

results within 120 days of conducting

each assessment. The operator must

obtain and assess a final report within

an additional 90 days.

(4) Schedule for repairs. An operator

must complete repairs according to a

schedule that prioritizes the conditions

for evaluation and repair. An operator

must base the schedule on the risk

factors listed in paragraph (e)(1) of this

section and any pipeline-specific risk

factors the operator develops. If an

operator cannot meet the schedule for

any of the conditions addressed in

paragraphs (h)(5)(i) through (iv) of this

section, the operator must justify the

reasons why the schedule cannot be met

and that the changed schedule will not

jeopardize public safety or

environmental protection. An operator

must notify OPS if the operator cannot

meet the schedule and cannot provide

safety through a temporary reduction in

operating pressure until a permanent

repair is made. An operator must send

a notice to the address specified in

§ 195.58 or to the facsimile number

specified in § 195.56.

(5) Special requirements for

scheduling repairs—(i) Immediate

repair conditions. An operator’s

evaluation and repair schedule must

provide for immediate repair

conditions. To maintain safety, an

operator will need to temporarily reduce

operating pressure or shut down the

pipeline until the operator can complete

the repair of these conditions. An

operator must base the temporary

operating pressure reduction on

remaining wall thickness. An operator

must treat the following conditions as

immediate repair conditions:

(A) Metal loss greater than 80% of

nominal wall regardless of dimensions.

(B) Predicted burst pressure less than

the maximum operating pressure at the

location of the anomaly. Burst pressure

has been calculated from the remaining

strength of the pipe, using a suitable

metal loss strength calculation, e.g.,

ASME/ANSI B31G (‘‘Manual for

Determining the Remaining Strength of

Corroded Pipelines’’ (1991)) or AGA

Pipeline Research Committee Project

PR–3–805 (‘‘A Modified Criterion for

Evaluating the Remaining Strength of

Corroded Pipe’’ (December 1989)).

These documents are available at the

addresses listed at § 195.3.

(C) Dents on the top of the pipeline

(above 4 and 8 o’clock position) with

any indicated metal loss.

(D) Significant anomaly that in the

judgment of the person evaluating the

assessment results requires immediate

action.

(ii) 60-day conditions. Except for

conditions listed in paragraph (h)(5)(i)

of this section, an operator must

schedule for evaluation and repair all

dents, regardless of size, located on the

top of the pipeline (above 4 and 8

o’clock position) within 60 days of

discovery of the condition.

(iii) Six-month conditions. Except for

conditions listed in paragraph (h)(5)(i)

or (ii) of this section, an operator must

schedule evaluation and repair of the

following within six months of

discovery of the condition:

(A) Dents with metal loss or dents that

affect pipe curvature at a girth or seam

weld.

(B) Dents with reported depths greater

than 6% of the pipe diameter.

(C) Remaining strength of the pipe

results in a safe operating pressure that

is less than the current established MOP

at the location of the anomaly using a

suitable safe operating pressure

calculation method (e.g., ASME/ANSI

B31G (‘‘Manual for Determining the

Remaining Strength of Corroded

Pipelines’’ (1991)) or AGA Pipeline

75408 Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations

Research Committee Project PR–3–805

(‘‘A Modified Criterion for Evaluating

the Remaining Strength of Corroded

Pipe’’ (December 1989)). These

documents are available at the addresses

listed at § 195.3.

(D) Areas of general corrosion with a

predicted metal loss of >50% of

nominal wall.

(E) Predicted metal loss of >50% of

nominal wall at crossings of another

pipeline.

(F) Weld anomalies with a predicted

metal loss >50% of nominal wall.

(G) Potential crack indications that

when excavated are determined to be

cracks.

(H) Corrosion of or along seam welds.

(I) Gouges or grooves greater than

12.5% of nominal wall.

(iv) Other conditions. An operator

must schedule evaluation and repair of

the following conditions:

(A) Data that reflect a change since

last assessed.

(B) Data that indicate mechanical

damage that is located on the top half

of the pipe.

(C) Data that indicate anomalies

abrupt in nature.

(D) Data that indicate anomalies

longitudinal in orientation.

(E) Data that indicate anomalies over

a large area.

(F) Anomalies located in or near

casings, crossings of another pipeline,

and areas with suspect cathodic

protection.

(i) What preventive and mitigative

measures must an operator take to

protect the high consequence area? (1)

General requirements. 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 segment to identify additional

actions to enhance public safety or

environmental protection. Such actions

may 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,

installing EFRDs on the pipeline

segment, 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.

(2) Risk analysis criteria. In

identifying the need for additional

preventive and mitigative measures, an

operator must evaluate the likelihood of

a pipeline release occurring and how a

release could affect the high

consequence area. This determination

must consider all relevant risk factors,

including, but not limited to:

(i) Terrain surrounding the pipeline

segment, including drainage systems

such as small streams and other smaller

waterways that could act as a conduit to

the high consequence area;

(ii) Elevation profile;

(iii) Characteristics of the product

transported;

(iv) Amount of product that could be

released;

(v) Possibility of a spillage in a farm

field following the drain tile into a

waterway;

(vi) Ditches along side a roadway the

pipeline crosses;

(vii) Physical support of the pipeline

segment such as by a cable suspension

bridge;

(viii) Exposure of the pipeline to

operating pressure exceeding

established maximum operating

pressure.

(3) Leak detection. An operator must

have a means to detect leaks on its

pipeline system. An operator must

evaluate the capability of its leak

detection means and modify, as

necessary, to protect the high

consequence area. An operator’s

evaluation must, at least, consider, the

following factors—length and size of the

pipeline, type of product carried, the

pipeline’s proximity to the high

consequence area, the swiftness of leak

detection, location of nearest response

personnel, leak history, and risk

assessment results.

(4) Emergency Flow Restricting

Devices (EFRD). If an operator

determines that an EFRD is needed on

a pipeline segment to protect a high

consequence area in the event of a

hazardous liquid pipeline release, an

operator must install the EFRD. In

making this determination, an operator

must, at least, consider the following

factors—the swiftness of leak detection

and pipeline shutdown capabilities, the

type of commodity carried, the rate of

potential leakage, the volume that can

be released, topography or pipeline

profile, the potential for ignition,

proximity to power sources, location of

nearest response personnel, specific

terrain between the pipeline segment

and the high consequence area, and

benefits expected by reducing the spill

size.

(j) What is a continual process of

evaluation and assessment to maintain

a pipeline’s integrity? (1) General. After

completing the baseline integrity

assessment, an operator must continue

to assess the line pipe at specified

intervals and periodically evaluate the

integrity of each pipeline segment that

could affect a high consequence area.

(2) Evaluation. An operator must

conduct a periodic evaluation as

frequently as needed to assure pipeline

integrity. An operator must base the

frequency of evaluation on risk factors

specific to its pipeline, including the

factors specified in paragraph (e) of this

section. The evaluation must consider

the past and present integrity

assessment results, information analysis

(paragraph (g) of this section), and

decisions about repair, and preventive

and mitigative actions (paragraphs (h)

and (i) of this section).

(3) Assessment intervals. An operator

must establish intervals not to exceed

five (5) years for continually assessing

the line pipe’s integrity. An operator

must base the assessment intervals on

the risk the line pipe poses to the high

consequence area to determine the

priority for assessing the pipeline

segments. An operator must establish

the assessment intervals based on the

factors specified in paragraph (e) of this

section, the analysis of the results from

the last integrity assessment, and the

information analysis required by

paragraph (g) of this section.

(4) Variance from the 5-year intervals

in limited situations—(i) Engineering

basis. An operator may be able to justify

an engineering basis for a longer

assessment interval on a segment of line

pipe. The justification must be

supported by a reliable engineering

evaluation combined with the use of

other technology, such as external

monitoring technology, that provides an

understanding of the condition of the

line pipe equivalent to that which is

obtainable under paragraph (j)(2) of this

section. An operator must notify OPS

nine months before the end of the

intervals of five years or less of the

reason why the operator intends to

justify a longer interval. An operator

must send a notice to the address

specified in § 195.58 or to the facsimile

number specified in § 195.56. The

notice must state a proposed alternative

interval.

(ii) Unavailable technology. An

operator may require a longer

assessment period for a segment of line

pipe (for example, because sophisticated

internal inspection technology is not

available). An operator must justify the

reasons why it cannot comply with the

required assessment period and must

also demonstrate the actions it is taking

to evaluate the integrity of the pipeline

segment in the interim. An operator

must notify OPS 180 days before the

end of the intervals of five years or less

that the operator may require a longer

assessment interval. An operator must

Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations 75409

send a notice to the address specified in

§ 195.58 or to the facsimile number

specified in § 195.56. The Operator may

have up to an additional 180 days to

complete the assessment.

(5) Assessment methods. An operator

must assess the integrity of the line pipe

by:

(i) Internal inspection tool or tools

capable of detecting corrosion and

deformation anomalies including dents,

gouges and grooves;

(ii) Pressure test conducted in

accordance with subpart E of this part;

or

(iii) Other technology that the

operator demonstrates can provide an

equivalent understanding of the

condition of the line pipe. An operator

choosing this option must notify OPS 60

days before conducting the assessment,

by sending a notice to the address

specified in § 195.58 or to the facsimile

number specified in § 195.56.

(6) However, for low frequency

electric resistance welded pipe or lap

welded pipe susceptible to longitudinal

seam failure, an operator must select

integrity assessment methods capable of

assessing seam integrity and of detecting

corrosion and deformation anomalies.

(k) What methods to measure program

effectiveness must be used? An

operator’s program must include

methods to measure whether the

program is effective in assessing and

evaluating the integrity of each pipeline

segment and in protecting the high

consequence areas. See Appendix C of

this part for guidance on methods that

can be used to evaluate a program’s

effectiveness.

(l) What records must be kept? An

operator must maintain for review

during an inspection:

(i) A written integrity management

program in accordance with paragraph

(b) of this section.

(ii) Documents to support the

decisions and analyses, including any

modifications, justifications, variances,

deviations and determinations made,

and actions taken, to implement and

evaluate each element of the integrity

management program listed in

paragraph (f) of this section.

(2) See Appendix C of this part for

examples of records an operator would

be required to keep.

3. A new Appendix C is added to part

195 to read as follows:

Appendix C to Part 195—Guidance for

Implementation of Integrity

Management Program

This Appendix gives guidance to help an

operator implement the requirements of the

integrity management program rule in

§§ 195.450 and 195.452. Guidance is

provided on:

(1) Information an operator may use to

identify a high consequence area and factors

an operator can use to consider the potential

impacts of a release on an area;

(2) Risk factors an operator can use to

determine an integrity assessment schedule;

(3) Safety risk indicator tables for leak

history, volume or line size, age of pipeline,

and product transported, an operator may use

to determine if a pipeline segment falls into

a high, medium or low risk category;

(4) Types of internal inspection tools an

operator could use to find pipeline

anomalies;

(5) Measures an operator could use to

measure an integrity management program’s

performance; and

(6) Types of records an operator will have

to maintain.

I. Identifying a high consequence area and

factors for considering a pipeline segment’s

potential impact on a high consequence area.

A. The rule defines a High Consequence

Area as a high population area, an other

populated area, an unusually sensitive area,

or a commercially navigable waterway. The

Office of Pipeline Safety (OPS) will map

these areas on the National Pipeline Mapping

System (NPMS). An operator, member of the

public, or other government agency may view

and download the data from the NPMS home

page http://www.npms.rspa.dot.gov. OPS

will maintain the NPMS and update it

periodically. However, it is an operator’s

responsibility to ensure that it has identified

all high consequence areas that could be

affected by a pipeline segment. An operator

is also responsible for periodically evaluating

its pipeline segments to look for population

or environmental changes that may have

occurred around the pipeline and to keep its

program current with this information. (Refer

to § 195.452(d)(3).) For more information to

help in identifying high consequence areas,

an operator may refer to:

(1) Digital Data on populated areas

available on U.S. Census Bureau maps.

(2) Geographic Database on the commercial

navigable waterways available on http://

www.bts.gov/gis/ntatlas/networks.html.

(3) The Bureau of Transportation Statistics

database that includes commercially

navigable waterways and non-commercially

navigable waterways. The database can be

downloaded from the BTS website at http:/

/www.bts.gov/gis/ntatlas/networks.html.

B. The rule requires an operator to include

a process in its program for identifying which

pipeline segments could affect a high

consequence area and to take measures to

prevent and mitigate the consequences of a

pipeline failure that could affect a high

consequence area. (See §§ 195.452 (f) and (i).)

Thus, an operator will need to consider how

each pipeline segment could affect a high

consequence area. The primary source for the

listed risk factors is a US DOT study on

instrumented Internal Inspection devices

(November 1992). Other sources include the

National Transportation Safety Board, the

Environmental Protection Agency and the

Technical Hazardous Liquid Pipeline Safety

Standards Committee. The following list

provides guidance to an operator on both the

mandatory and additional factors:

(1) Terrain surrounding the pipeline. An

operator should consider the contour of the

land profile and if it could allow the liquid

from a release to enter a high consequence

area. An operator can get this information

from topographical maps such as U.S.

Geological Survey quadrangle maps.

(2) Drainage systems such as small streams

and other smaller waterways that could serve

as a conduit to a high consequence area.

(3) Crossing of farm tile fields. An operator

should consider the possibility of a spillage

in the field following the drain tile into a

waterway.

(4) Crossing of roadways with ditches

along the side. The ditches could carry a

spillage to a waterway.

(5) The nature and characteristics of the

product the pipeline is transporting (refined

products, crude oils, highly volatile liquids,

etc.) Highly volatile liquids becomes gaseous

when exposed to the atmosphere. A spillage

could create a vapor cloud that could settle

into the lower elevation of the ground profile.

(6) Physical support of the pipeline

segment such as by a cable suspension

bridge. An operator should look for stress

indicators on the pipeline (strained supports,

inadequate support at towers), atmospheric

corrosion, vandalism, and other obvious

signs of improper maintenance.

(7) Operating condition of pipeline

(pressure, flow rate, etc.) Exposure of the

pipeline to operating pressure exceeding

established maximum operating pressure.

(8) The hydraulic gradient of pipeline.

(9) The diameter of pipeline, the potential

release volume, and the distance between the

isolation points.

(10) Potential physical pathways between

the pipeline and the high consequence area.

(11) Response capability (time to respond,

nature of response).

(12) Potential natural forces inherent in the

area (flood zones, earthquakes, subsidence

areas, etc.)

II. Risk factors for establishing frequency of

assessment.

A. By assigning weights or values to the

risk factors, and using the risk indicator

tables, an operator can determine the priority

for assessing pipeline segments, beginning

with those segments that are of highest risk,

that have not previously been assessed. This

list provides some guidance on some of the

risk factors to consider (see § 195.452(e)). An

operator should also develop factors specific

to each pipeline segment it is assessing,

including:

(1) Populated areas, unusually sensitive

environmental areas, National Fish

Hatcheries, commercially navigable waters,

areas where people congregate.

(2) Results from previous testing/

inspection. (See § 195.452(h).)

(3) Leak History. (See leak history risk

table.)

(4) Known corrosion or condition of

pipeline. (See § 195.452(g).)

(5) Cathodic protection history.

(6) Type and quality of pipe coating

(disbonded coating results in corrosion).

(7) 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.)

(8) Product transported (highly volatile,

highly flammable and toxic liquids present a

75410 Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations

greater threat for both people and the

environment) (see Product transported risk

table.)

(9) Pipe wall thickness (thicker walls give

a better safety margin)

(10) Size of pipe (higher volume release if

the pipe ruptures).

(11) Location related to potential ground

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

and coal mines); climatic (permafrost causes

settlement—Alaska); geologic (landslides or

subsidence).

(12) Security of throughput (effects on

customers if there is failure requiring

shutdown).

(13) Time since the last internal

inspection/pressure testing.

(14) With respect to previously discovered

defects/anomalies, the type, growth rate, and

size.

(15) Operating stress levels in the pipeline.

(16) Location of the pipeline segment as it

relates to the ability of the operator to detect

and respond to a leak. (e.g., pipelines deep

underground, or in locations that make leak

detection difficult without specific sectional

monitoring and/or significantly impede

access for spill response or any other

purpose).

(17) Physical support of the segment such

as by a cable suspension bridge.

(18) Non-standard or other than recognized

industry practice on pipeline installation (e.g.,

horizontal directional drilling).

B. Example: This example illustrates a

hypothetical model used to establish an

integrity assessment schedule for a

hypothetical pipeline segment. After we

determine the risk factors applicable to the

pipeline segment, we then assign values or

numbers to each factor, such as, high (5),

moderate (3), or low (1). We can determine

an overall risk classification (A, B, C) for the

segment using the risk tables and a sliding

scale (values 5 to 1) for risk factors for which

tables are not provided. We would classify a

segment as C if it fell above 2⁄3 of maximum

value (highest overall risk value for any one

segment when compared with other segments

of a pipeline), a segment as B if it fell

between 1⁄3 to 2⁄3 of maximum value, and the

remaining segments as A.

i. For the baseline assessment schedule, we

would plan to assess 50% of all pipeline

segments covered by the rule, beginning with

the highest risk segments, within the first 31⁄2

years and the remaining segments within the

seven-year period. For the continuing

integrity assessments, we would plan to

assess the C segments within the first two (2)

years of the schedule, the segments classified

as moderate risk no later than year three or

four and the remaining lowest risk segments

no later than year five (5).

ii. For our hypothetical pipeline segment,

we have chosen the following risk factors and

obtained risk factor values from the

appropriate table. The values assigned to the

risk factors are for illustration only.

Age of pipeline: assume 30 years old (refer to

‘‘Age of Pipeline’’ risk table)—

Risk Value=5

Pressure tested: tested once during

construction—

Risk Value=5

Coated: (yes/no)—yes

Coating Condition: Recent excavation of

suspected areas showed holidays in

coating (potential corrosion risk)—

Risk Value=5

Cathodically Protected: (yes/no)—yes—Risk

Value=1

Date cathodic protection installed: five years

after pipeline was constructed (Cathodic

protection installed within one year of

the pipeline’s construction is generally

considered low risk.)—Risk Value=3

Close interval survey: (yes/no)—no—Risk

Value =5

Internal Inspection tool used: (yes/no)—yes.

Date of pig run? In last five years—Risk

Value=1

Anomalies found: (yes/no)—yes, but do not

pose an immediate safety risk or

environmental hazard—Risk Value=3

Leak History: yes, one spill in last 10 years.

(refer to ‘‘Leak History’’ risk table)—Risk

Value=2

Product transported: Diesel fuel. Product low

risk. (refer to ‘‘Product’’ risk table)—Risk

Value=1

Pipe size: 16 inches. Size presents moderate

risk (refer to ‘‘Line Size’’ risk table)—

Risk Value=3

iii. Overall risk value for this hypothetical

segment of pipe is 34. Assume we have two

other pipeline segments for which we

conduct similar risk rankings. The second

pipeline segment has an overall risk value of

20, and the third segment, 11. For the

baseline assessment we would establish a

schedule where we assess the first segment

(highest risk segment) within two years, the

second segment within five years and the

third segment within seven years. Similarly,

for the continuing integrity assessment, we

could establish an assessment schedule

where we assess the highest risk segment no

later than the second year, the second

segment no later than the third year, and the

third segment no later than the fifth year.

III. Safety risk indicator tables for leak

history, volume or line size, age of pipeline,

and product transported.

LEAK HISTORY

Safety 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

Safety risk

indicator Line size

High ................. ≥ 18′′

Moderate ......... 10′′—16′′ nominal diameters

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

AGE OF PIPELINE

Safety 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

Safety risk

indicator Considerations 1 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).

1The 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.

IV. Types of internal inspection tools to

use.

An operator should consider at least two

types of internal inspection tools for the

integrity assessment from the following list.

The type of tool or tools an operator selects

will depend on the results from previous

internal inspection runs, information

analysis and risk factors specific to the

pipeline segment:

(1) Geometry Internal inspection tools for

detecting changes to ovality, e.g., bends,

dents, buckles or wrinkles, due to

construction flaws or soil movement, or other

outside force damage;

(2) Metal Loss Tools (Ultrasonic and

Magnetic Flux Leakage) for determining pipe

wall anomalies, e.g., wall loss due to

corrosion.

Federal Register / Vol. 65, No. 232 / Friday, December 1, 2000 / Rules and Regulations 75411

(3) Crack Detection Tools for detecting

cracks and crack-like features, e.g., stress

corrosion cracking (SCC), fatigue cracks,

narrow axial corrosion, toe cracks, hook

cracks, etc.

V. Methods to measure performance.

A. General. (1) This guidance is to help an

operator establish measures to evaluate the

effectiveness of its integrity management

program. The performance measures required

will depend on the details of each integrity

management program and will be based on

an understanding and analysis of the failure

mechanisms or threats to integrity of each

pipeline segment.

(2) An operator should select a set of

measurements to judge how well its program

is performing. An operator’s objectives for its

program are to ensure public safety, prevent

or minimize leaks and spills and prevent

property and environmental damage. A

typical integrity management program will be

an ongoing program and it may contain many

elements. Therefore, several performance

measure are likely to be needed to measure

the effectiveness of an ongoing program.

B. Performance measures. These measures

show how a program to control risk on

pipeline segments that could affect a high

consequence area is progressing under the

integrity management requirements.

Performance measures generally fall into

three categories:

(1) Selected Activity Measures—Measures

that monitor the surveillance and preventive

activities the operator has implemented.

These measure indicate how well an operator

is implementing the various elements of its

integrity management program.

(2) Deterioration Measures—Operation and

maintenance trends that indicate when the

integrity of the system is weakening despite

preventive measures. This category of

performance measure may indicate that the

system condition is deteriorating despite well

executed preventive activities.

(3) Failure Measures—Leak History,

incident response, product loss, etc. These

measures will indicate progress towards

fewer spills and less damage.

C. Internal vs. External Comparisons.

These comparisons show how a pipeline

segment that could affect a high consequence

area is progressing in comparison to the

operator’s other pipeline segments that are

not covered by the integrity management

requirements and how that pipeline segment

compares to other operators’ pipeline

segments.

(1) Internal—Comparing data from the

pipeline segment that could affect the high

consequence area with data from pipeline

segments in other areas of the system may

indicate the effects from the attention given

to the high consequence area.

(2) External—Comparing data external to

the pipeline segment (e.g., OPS incident data)

may provide measures on the frequency and

size of leaks in relation to other companies.

D. Examples. Some examples of

performance measures an operator could use

include—

(1) A performance measurement goal to

reduce the total volume from unintended

releases by -% (percent to be determined by

operator) with an ultimate goal of zero.

(2) A performance measurement goal to

reduce the total number of unintended

releases (based on a threshold of 5 gallons)

by ll-% (percent to be determined by

operator) with an ultimate goal of zero.

(3) A performance measurement goal to

document the percentage of integrity

management activities completed during the

calendar year.

(4) A performance measurement goal to

track and evaluate the effectiveness of the

operator’s community outreach activities.

(5) A narrative description of pipeline

system integrity, including a summary of

performance improvements, both qualitative

and quantitative, to an operator’s integrity

management program prepared periodically.

(6) A performance measure based on

internal audits of the operator’s pipeline

system per 49 CFR Part 195.

(7) A performance measure based on

external audits of the operator’s pipeline

system per 49 CFR Part 195.

(8) A performance measure based on

operational events (for example: relief

occurrences, unplanned valve closure,

SCADA outages, etc.) that have the potential

to adversely affect pipeline integrity.

(9) A performance measure to demonstrate

that the operator’s integrity management

program reduces risk over time with a focus

on high risk items.

(10) A performance measure to

demonstrate that the operator’s integrity

management program for pipeline stations

and terminals reduces risk over time with a

focus on high risk items.

VI. Examples of types of records an

operator must maintain.

The rule requires an operator to maintain

certain records. (See § 195.452(l)). This

section provides examples of some records

that an operator would have to maintain for

inspection to comply with the requirement.

This is not an exhaustive list.

(1) a process for identifying which

pipelines could affect a high consequence

area and a document identifying all pipeline

segments that could affect a high

consequence area;

(2) a plan for baseline assessment of the

line pipe that includes each required plan

element;

(3) modifications to the baseline plan and

reasons for the modification;

(4) use of and support for an alternative

practice;

(5) a framework addressing each required

element of the integrity management

program, updates and changes to the initial

framework and eventual program;

(6) a process for identifying a new high

consequence area and incorporating it into

the baseline plan, particularly, a process for

identifying population changes around a

pipeline segment;

(7) an explanation of methods selected to

assess the integrity of line pipe;

(8) a process for review of integrity

assessment results and data analysis by a

person qualified to evaluate the results and

data;

(9) the process and risk factors for

determining the baseline assessment interval;

(10) results of the baseline integrity

assessment;

(11) the process used for continual

evaluation, and risk factors used for

determining the frequency of evaluation;

(12) process for integrating and analyzing

information about the integrity of a pipeline,

information and data used for the

information analysis;

(13) results of the information analyses and

periodic evaluations;

(14) the process and risk factors for

establishing continual re-assessment

intervals;

(15) justification to support any variance

from the required re-assessment intervals;

(16) integrity assessment results and

anomalies found, process for evaluating and

repairing anomalies, criteria for repair

actions and actions taken to evaluate and

repair the anomalies;

(17) other remedial actions planned or

taken;

(18) schedule for reviewing and analyzing

integrity assessment results;

(19) schedule for evaluation and repair of

anomalies, justification to support deviation

from required repair times;

(20) risk analysis used to identify

additional preventive or mitigative measures,

records of preventive and mitigative actions

planned or taken;

(21) criteria for determining EFRD

installation;

(22) criteria for evaluating and modifying

leak detection capability;

(23) methods used to measure the

program’s effectiveness.

Issued in Washington DC on November 14,

2000.

Kelley S. Coyner,

Administrator.

[FR Doc. 00–29570 Filed 11–30–00; 8:45 am]

BILLING CODE 4910–60–P