34318 Federal Register / Vol. 66, No. 124 / Wednesday, June 27, 2001 / Notices

experience in working with educational,

judicial, law enforcement, and public

health and safety organizations within

the community should be described, as

well as partnerships with organizations

representing diverse populations within

the community.

e. A personnel section which

identifies the proposed project

coordinator and other key personnel

necessary to perform the public

information campaign, enforcement

activities and evaluation component

shall be provided. This section shall

include a description of their

qualifications, the nature of their

contribution, their respective

organizational responsibilities, and the

proposed level of their effort.

Review Process and Criteria

Initially, each application will be

reviewed to confirm that the applicant

meets the eligibility requirements and

that the application contains all of the

information required by the Application

Contents section of this notice. Each

complete application from an eligible

applicant will then be evaluated by a

NHTSA Technical Evaluation

Committee. The applications will be

evaluated using the following criteria:

1. Project Plan: The overall soundness

and feasibility of the demonstration

community project plan and the

potential effectiveness of the described

public information and education

campaign and highly visible law

enforcement activities to increase seat

belt and child safety seat use among

occupants of sport utility vehicles

(SUVs) (50 percent).

2. The applicant’s planned

partnerships with other community

agencies/organizations promotes the

requisite participation among those

groups considered necessary to conduct

an effective community demonstration

project. In addition, the applicant’s

prior successful experience with

community-based coalitions

demonstrates the necessary

organizational skills to effectively

coordinate the proposed project (30

percent).

3. The proposed personnel resources

demonstrate effective project

coordination capability and the

requisite breadth of expertise to

successfully perform the described

activities that will result in increasing

seat belt and child safety seat use among

occupants of sport utility vehicles

(SUVs) (20 percent).

Terms and Conditions of Award

1. Prior to award, the recipients must

comply with the certification

requirements of 49 CFR part 20,

Department of Transportation New

Restriction on Lobbying, and 49 CFR

part 29, Department of Transportation

Government-wide Debarment and

Suspension (Nonprocurement) and

Government-wide Requirements for

Drug-Free Workplace (Grants).

2. During the effective period of the

cooperative agreements awarded as a

result of this Notice, the agreements

shall be subject to NHTSA’s General

Provisions for Assistance Agreements

(7/95).

3. Reporting Requirements and

Deliverables

a. Quarterly Reports, which shall be

due 15 days after the end of each

quarter, shall be submitted to document

project efforts and results. The reports

should include up-to-date information

summarizing accomplishments during

the quarter including: data gathered todate (such as earned and paid media

events, observation and awareness

surveys, and enforcement data);

obstacles or problems encountered and

proposed solutions; noteworthy

activities, events or successes; and

funds and in-kind contributions

expended to date. The quarterly reports

will form the basis for the final report

to disseminate the lessons learned and

successes of the recipient. The COTR

will approve invoices upon receipt of

each quarterly report.

b. Draft Final Report: The recipient

shall prepare a draft Final Report that

includes a complete description of the

overall project implementation,

including a project time-line; the

activities conducted, including partners;

data collection efforts; evaluation

methodology; and findings from the

program evaluation. In terms of

information transfer, it is important to

know what worked and what did not

work, under what circumstances, and

what can be done to avoid potential

problems in future projects. The report

should provide information that will be

helpful in assembling a ‘‘Best Practices’’

guide for use by other communities. The

grantee shall submit the draft Final

Report to the COTR 60 days prior to the

end of the performance period. The

COTR will review the draft report and

provide comments to the grantee within

30 days of receipt of the document.

c. Final Report: The grantee shall

revise the draft Final Report to reflect

the COTR’s comments. The revised final

report shall be delivered to the COTR 15

days before the end of the performance

period. For the final report, the Grantee

shall supply the COTR:

—A camera ready version of the

document as printed.

—A copy, on appropriate media

(diskette, Syquest disk, etc.), of the

document in the original program

format that was used for the

printing process.

Note: Some documents require several

different original program languages (e.g.,

PageMaker was the program format for the

general layout and design and Power Point

was used for charts and yet another was used

for photographs, etc.). Each of these

component parts should be available on disk,

properly labeled with the program format

and the file names. For example, Power Point

files should be clearly identified by both a

descriptive name and file name (e.g., 1994

Fatalities—chart1.ppt).

—A complete version of the

assembled document in portable

document format (PDF) for

placement of the report on the

world wide web (WWW). This will

be a file usually created with the

Adobe Exchange program of the

complete assembled document in

the PDF format that will actually be

placed on the WWW. The

document would be completely

assembled with all colors, charts,

side bars, photographs, and

graphics. This can be delivered to

NHTSA on a standard 1.44 diskette

(for small documents) or on any

appropriate archival media (for

large documents) such as a CD

ROM, TR–1 Mini cartridge, Syquest

disk, etc.

—Four additional hard copies of the

final document.

d. The recipients may be requested to

conduct an oral presentation of their

respective project activities for the

COTR and other interested NHTSA

personnel. For planning purposes,

assume that these presentations will be

conducted at the NHTSA Office of

Traffic and Injury Control Programs,

Washington, D.C. An original and three

copies of briefing materials shall be

submitted to the COTR.

Issued on: June 21, 2001.

Susan Gorcowski,

Acting Associate Administrator for Traffic

Safety Programs.

[FR Doc. 01–16040 Filed 6–26–01; 8:45 am]

BILLING CODE 4910–59–P

DEPARTMENT OF TRANSPORTATION

Research and Special Programs

Administration

[Docket No. RSPA–00–7666; Notice 2]

Pipeline Safety: Pipeline Integrity

Management in High Consequence

Areas (Gas Transmission Pipelines)

AGENCY: Office of Pipeline Safety,

Research and Special Programs

Administration, DOT.

Federal Register / Vol. 66, No. 124 / Wednesday, June 27, 2001 / Notices 34319

ACTION: Notice of request for comments.

SUMMARY: OPS has been meeting with

representatives of the natural gas

pipeline industry, research institutions,

State pipeline safety agencies and

public interest groups, to understand

how integrity management principles

can best be applied to improve the

safety of gas pipelines. A public meeting

was held on February 12–14, 2001, in

Arlington, VA, to present the results of

analyses and discussions, identify

issues, and obtain public comments. By

this notice we are seeking further

information and clarification, and

inviting further public comment about

integrity management concepts as they

relate to gas pipelines. This notice also

announces commencement of an

electronic public discussion forum on

gas pipeline integrity management

issues on the office of Pipeline Safety’s

internet home page.

DATES: Interested persons are invited to

submit written comments by August 13,

2001. Late-filed comments will be

considered to the extent practicable.

ADDRESSES: Submit written comments

by mail or delivery to the Dockets

Facility, U.S. Department of

Transportation, Room PL–401, 400

Seventh Street, SW., Washington, DC

20590–0001. The Dockets Facility is

located on the plaza level, Room PL–

401, of the US Department of

Transportation, 400 Seventh Street,

SW., Washington, DC 20590. It is open

from 10 a.m. to 5 p.m., Monday through

Friday, except federal holidays. All

written comments should identify the

docket and notice numbers stated in the

heading of this notice. Anyone who

wants confirmation of mailed comments

must include a self-addressed stamped

postcard.

Electronic Access

The Internet address for the electronic

discussion forum is http://ops.dot.gov/

forum. The electronic discussion forum

is discussed below under the

subheading ‘‘More Information Needed

on Gas Integrity Management Program.’’

You also may submit written

comments to the docket electronically at

the following web address: http://

dms.dot.gov. To file written comments

electronically, after logging onto http://

dms.dot.gov, click on ‘‘Electronic

Submission.’’ You can read comments

and other material in the docket at this

Web address.

FOR FURTHER INFORMATION CONTACT:

Mike Israni (tel: 202–366–4571; E-mail:

mike.israni@rspa.dot.gov). General

information about our pipeline safety

program is available at this Web

address: http://ops.dot.gov.

SUPPLEMENTARY INFORMATION:

I. Background

We have stated previously (most

recently at 66 FR 848; Jan. 4, 2001), that

we are issuing integrity management

program requirements for pipelines in

several steps. RSPA began the series of

rulemakings by issuing requirements

pertaining to hazardous liquid

operators. A final rule applying to

hazardous liquid operators with 500 or

more miles of pipeline was published

on December 1, 2000 (65 FR 75378).

This rule applies to pipelines that can

affect high consequence areas (HCAs),

which include populated areas defined

by the Census Bureau as urbanized areas

or places, unusually sensitive

environmental areas, and commercially

navigable waterways. We have proposed

a similar rule for hazardous liquid

operators with less than 500 miles of

pipeline (66 FR 15821; March 21, 2001).

We are now considering integrity

management concepts that could most

effectively be applied to gas

transmission pipelines. OPS has been

meeting with representatives of the gas

pipeline industry, research institutions,

State pipeline safety agencies and

public interest groups, to gather the

information needed to propose an

integrity management program

rulemaking pertaining to gas operators.

Since January 2000, there have been

nine meetings with State agencies,

representatives of the Interstate Natural

Gas Association of America (INGAA),

the American Gas Association (AGA),

Battelle Memorial Institute, the Gas

Technology Institute (GTI), Hartford

Steam Boiler Inspection and Insurance

Company, and operators covered under

49 CFR Part 192. (See DOT Docket No.

7666 for summaries of the meetings.)

We also have met separately with

Western States Land Commissioners,

National Governors Association,

National League of Cities, National

Council of State Legislators,

Environmental Defense Fund, Public

Interest Reform Group, and Working

Group on Communities Right-To-Know.

On February 12–14, 2001, we held a

public meeting in Arlington, VA, on

integrity management in high

consequence areas for natural gas

pipelines and enhanced

communications about hazardous liquid

and gas pipelines. At this meeting,

reports on the status of industry and

government activities on how to

improve the integrity of gas pipelines

were featured and meeting attendees

participated in in-depth discussions on

the integrity of gas pipelines. The

reports can be found in the DOT docket

(#7666) and the OPS web site under

Initiatives/Pipeline Integrity

Management Program/Gas Transmission

Operators Rule.

At the public meeting, industry and

State representatives presented their

perspectives on a number of issues

relating to integrity management.

Several members of the public also

made comments. Presentation topics

included:

• Considerations for defining HCAs

affected by gas pipelines

• Evaluation of design factors currently

used for gas transmission pipelines

• Evaluation of performance history and

experience with the impact zone in

gas transmission failures

• Integrity management best practices

and relationship between incident

causes and industry practices

• Options for various forms of direct

assessment of the integrity of gas

pipelines; their costs and

effectiveness

• Basis for establishing test pressure

intervals

• Appropriateness of using pressure

(stress) to differentiate integrity

standards for pipelines

• Status of research activities

• Status of development of new

national consensus standards

These presentations can be viewed on

the OPS web site under Initiatives/

Pipeline Integrity Management Program/

Gas Transmission Operators Rule.

Objectives

RSPA’s objective in developing a rule

on gas pipeline integrity management is

to evaluate and address threats posed by

pipeline segments in areas where the

consequences of potential pipeline

accidents pose the greatest risk to

people and their property and to

provide additional protections in these

areas. We had a similar objective when

we developed the recently issued rules

on liquid pipeline integrity management

programs, although environmental

protection also played a larger role in

those rules. We also want to minimize

any actual adverse impact of a new

safety requirements on the supply of

natural gas to customers.

Scope of an Eventual Gas Integrity

Management Rule

Our current thinking is that any

standards we eventually propose on gas

integrity management will apply to all

gas transmission lines and support

equipment, including lines transporting

petroleum gas, hydrogen, and other gas

products covered under Part 192.

34320 Federal Register / Vol. 66, No. 124 / Wednesday, June 27, 2001 / Notices

Elements of an Eventual Gas Integrity

Management Rule

We believe that to fulfill our

objectives, any rule that we propose on

integrity management programs for gas

operators would need to address the

following seven elements. We used

similar elements in developing the

liquid integrity management rules. Our

treatment of these elements will be

based on certain hypotheses that are

discussed below. We welcome comment

about these elements and hypotheses.

1. Define the areas where the potential

consequences of a gas pipeline accident

may be significant or may do

considerable harm to people and their

property. (We are calling these high

consequence areas).

• Data from sites where gas pipelines

have ruptured and exploded have

shown that the range of impact of such

explosions is limited. Therefore, the

area in which near by residents may be

harmed or their property damaged by

potential pipeline ruptures can be

mathematically modeled as a function

of the physical size of the pipeline and

the material being transported

(typically, but not exclusively, natural

gas).

• Because gas pipeline operators are

required to maintain data on the number

of buildings within 660 feet of their

pipelines, the definition of potentially

high consequences areas where

additional integrity assurance measures

are needed should incorporate these

data.

• The range of impact from the

rupture and explosion of very large

diameter (greater than 36 inches) high

pressure (greater than 1000 psi) gas

pipelines is greater than the 660 feet

currently used in the regulations.

• Special consideration must be given

to protect people living or working near

gas pipelines who would have difficulty

evacuating the area quickly (e.g.,

schools, hospitals, nursing homes,

prisons).

• Because of the relatively small

radius of impact of a gas pipeline

rupture and subsequent explosion, and

the behavior of gas products,

environmental consequences are

expected to be limited. At this time,

OPS has little information that would

indicate the definition of high

consequence areas near gas pipelines

should include environmental factors.

• Given that pipeline operators

maintain extensive data on the

distribution of people near their

pipelines, OPS intends for operators to

use these data, together with a narrative

definition of a high consequence area

(that OPS will define), to identify the

specific locations of high consequence

areas. For OPS to map high consequence

areas for public and regulatory use,

operators will have to provide data

(hard copy or digital) on the location of

people living near their pipelines as an

attribute associated with the pipeline

geospatial features. For any operator not

able to provide these data, OPS would,

instead, rely on census data to complete

the maps of high consequence areas to

be used for gas integrity purposes. OPS

is using this data to map the high

consequence areas defined in the liquid

integrity management rule.

2. Identify and evaluate the threats to

pipeline integrity in each area of

potentially high consequences.

• Effective integrity management

begins with a comprehensive threat-bythreat analysis. One approach divides

potential threats to pipeline integrity

into three categories: time dependent

(including internal corrosion, external

corrosion, and stress corrosion

cracking); static or resident (including

defects introduced during fabrication of

the pipe or construction of the pipeline);

and random (including third party

damage and outside force damage). In

addition, human error can influence any

or all of these threats.

• Identification and evaluation of the

significance of threats to pipeline

integrity must involve the integration of

numerous risk factors. Such risk factors

include, but are not limited to, pipe

characteristics (e.g., wall thickness,

coating material and coating condition;

pipe toughness; pipe strength; pipe

fabrication technique; pipe elevation

profile); internal and external

environmental factors (e.g., soil

moisture content and acidity, gas

operating temperature and moisture

content); operating and leak history

(e.g., pipe failure history, past upset

conditions that have introduced

moisture into the gas); land use (e.g.,

active farming, commercial

construction, residential construction);

protection history (e.g., corrosion

protection data, history of third party

hits and near misses, effectiveness of

local One Call systems); and the degree

of certainty about the current condition

of the pipeline (e.g., age of the pipe,

completeness of integrity-related

records, available inspection data).

• Pipelines having threats that

represent higher risks should generally

be assessed sooner than those with

threats that represent lower risk.

• Numerous studies and analyses on

leak vs. rupture thresholds of natural

gas pipelines have shown that pipelines

that operate at a stress level less than

30% SMYS fail differently (i.e., leak

rather than rupture) from those

operating at higher stress. Therefore,

different integrity assurance techniques

may be appropriate.

3. Select the assessment technologies

best suited to effectively determine the

susceptibility to failure of each pipe

segment that could affect an area of

potentially high consequences.

• An integrity baseline needs to be

established for all pipe segments that

could affect an area of potentially high

consequences. An operator will need to

evaluate the entire range of threats to

each pipeline segment’s integrity by

analyzing all available information

about the pipeline segment and

consequences of a failure on a high

consequence area. Based on the type of

threat or threats facing a pipeline

segment, an operator will choose an

appropriate assessment method or

methods to assess (i.e., inspect or test)

each segment to determine potential

problems.

• Time dependent threats will also

require periodic inspection to

characterize changes in their

significance.

• Acceptable technologies for

assessing integrity include in-line

inspection, pressure testing and direct

assessment. None of these technologies

individually is fully capable of

characterizing all potential threats to

pipeline integrity.

• OPS is co-sponsoring with industry

and state agencies an evaluation of

direct assessment technology to

determine the conditions under which

direct assessment is effective in

assessing external corrosion. The

validity of direct assessment in

assessing other threats (e.g., internal

corrosion, stress corrosion cracking) is

also being explored.

• Static threats will require pressure

testing at some time during the life of

the pipeline. If significant cyclic stress,

such as that caused by large pressure

fluctuations, is present, then pressure

testing, or an equivalent technology,

will be required periodically throughout

the life of the pipeline.

• Random threats will require the use

of two parallel integrity management

approaches. The vast majority (over

90%) of ruptures caused by random

threats occur at the time when the threat

is imminent (e.g., when the excavator

hits the pipeline). Therefore, the use of

risk management practices (or

technologies) to prevent damage or to

immediately identify the potential for

damage would be more effective than

looking for evidence of past damage.

Secondly, since some random threats do

not result in immediate pipeline

rupture, technologies that look for

evidence of past damage after the threat

Federal Register / Vol. 66, No. 124 / Wednesday, June 27, 2001 / Notices 34321

has occurred should be focused in areas

where delayed failure is most likely.

• Threats related to human error will

be addressed largely, but not

completely, through the new Operator

Qualification Rule. An integrity

management rule may need to address

more specific problems.

4. Determine time frames to conduct

a baseline integrity assessment and to

make any needed repair using a graded

(tiered) approach where assessment and

repair are prioritized according to risk.

• The time frame for conducting the

baseline assessment should be based on

a graded or tiered approach where

pipeline segments are prioritized for

assessment according to the level of risk

they pose. Thus, highest risk segments

would be scheduled for assessment first,

lowest risk last. A schedule for taking

remedial action on the pipeline segment

after the assessment would also be

based on risk factors.

• The time frame for conducting the

baseline assessment should, among

other factors, consider the impact on gas

supply to residents. This could also be

a factor in determining if a variance

from the required time frame is

warranted.

• The sequence in which the

segments are prioritized for assessment

should be determined by considering

information such as, how much pipe is

in areas of potentially high

consequences, which of these pipe

segments represent the highest risk,

which threats for these segments

represent significant risks, how much

time will be needed to develop the

infrastructure to perform the required

assessments (e.g., validate the required

assessment technologies, develop

consensus standards for the application

of these technologies, expand the

industry capability to deploy and

effectively use these technologies to

assess pipeline integrity). If the

assessment finds potential problems, the

schedule for making the repairs would

also be based on risk factors.

5. Identify and implement additional

preventive and mitigative measures

appropriate to manage significant

threats.

• Assuring a pipeline’s integrity

requires more than simple periodic

inspection of the pipe. Most threats,

including passive threats such as third

party damage, require active

management to prevent challenges to

integrity. Therefore, active integrity

management practices are necessary.

Some operators already go beyond the

current pipeline safety regulations by

implementing integrity management

practices such as ground displacement

surveys, soil corrosivity analysis, gas

sampling and sampling and analysis of

liquid removed from pipelines at low

points.

• Preventive and mitigative measures

include conducting a risk analysis of the

pipeline segment to identify additional

actions to enhance public safety. Such

actions may include damage prevention

practices, better monitoring of cathodic

protection, establishing shorter

inspection intervals, installing Remote

Control Valves (RCVs) or Automatic

Shut-Off Valves (ASVs) on pipeline

segments. Some operators, particularly

hydrogen pipeline operators, have

voluntarily installed ASVs on their

pipelines at short intervals as a

mitigative measure.

6. Continually evaluate and reassess

at the specified interval each pipeline

segment that could affect an area of

potentially high consequences using a

risk-based approach. The evaluation

considers the information the operator

has about the entire pipeline to

determine what might be relevant to the

pipeline segment.

• Managing a pipeline’s integrity

requires periodic reassessment of the

pipeline. The time frame appropriate for

this reassessment depends on numerous

factors (see Element 2 above). In the

current class location change regulation,

gas pipeline operators are required to

replace pipe segments with thickerwalled or stronger pipe (or decrease

pressure) as the near-by population

increases above threshold levels. This

requirement for thicker-walled or

stronger pipe in areas of higher

population might indicate that a longer

reassessment interval would be

appropriate where corrosion is the

dominant threat.

• If critical risk factor data are not

available to support evaluation of risks,

then the reassessment interval should be

appropriately shortened to reflect that

absence of knowledge.

• If an operator has developed a

comprehensive picture of past and

anticipated threats, including detailed

information on risk factors and records

of multiple assessments carried out over

several years, the operator might be able

to justify a longer reassessment interval.

• The periodic evaluation is based on

an information analysis of the entire

pipeline.

7. Monitor the effectiveness of the

management process designed to

provide additional assurance of integrity

in areas where the consequences of

potential pipeline accidents are greatest.

• Measures can be developed to track

actual integrity performance as well as

to determine the value of assessment

and repair activities.

• Application of integrity

management technologies that exceed

current regulations is cost effective

because many companies have made the

decision to implement such programs.

Consideration of Impact on Gas Supply

Recent events, particularly in

California and the Midwest, have

highlighted the limitations of energy

supply in certain parts of the country.

Assessing pipelines using any of the

technologies being considered may

result in a restricted gas supply because

of pipelines being taken out of service

or by reduction in throughput. Some

types of repairs will also require lines to

be taken out of service. To illustrate, we

have included a map (see sketch 1) of

Northern Natural Gas Company’s gas

transmission pipeline, which supplies

gas to the states of Iowa, Minnesota,

Wisconsin, and Michigan. If an

upstream segment of this gas

transmission pipeline were put out of

service temporarily for the test or repair,

many communities located at the end of

branch lines, which have sole source

feed (i.e., have no other tie-in’s from an

alternative source), would be affected by

the restricted gas supply. Therefore, in

developing the time frames for the

baseline assessment and continual

reassessment intervals (or for allowing a

variance), and the schedule for repairs,

we will need to consider, among other

factors, the actual adverse impact on the

public of a restricted gas supply.

34322 Federal Register / Vol. 66, No. 124 / Wednesday, June 27, 2001 / Notices

Federal Register / Vol. 66, No. 124 / Wednesday, June 27, 2001 / Notices 34323

More Information Needed on Gas

Integrity Management Program

We have summarized the areas where

OPS is seeking further information in

developing a proposed integrity

management program rule for gas

operators. The information needs are

organized under nine categories, seven

of which are the elements we see as

essential to any integrity management

program rule. We have added two other

categories to identify areas where we

need information to evaluate the effect

of an integrity management rulemaking

on costs and gas supply, both seasonally

and regionally.

To help promote discussion of these

issues, we have also developed an

electronic discussion forum on OPS’s

Internet home page. The Internet

address for this forum is http://

ops.dot.gov/forum. Because of the way

we have interspersed numerous

questions throughout this document

with extensive background and

technical information, some

commenters may find it difficult to find

the areas they would like to comment

on. The electronic forum will list all the

areas where we have asked for comment

so that commenters can easily focus on

those areas of interest to them. The

electronic forum will allow real-time

electronic discussion for 45 days. We

hope it will increase the breadth of

participation in the commenting

process. A transcript of the electronic

discussion forum will be placed in the

docket.

1. Define the Areas of Potentially High

Consequence

Because the environmental

consequences of a gas pipeline accident

tend to be localized, OPS’s approach to

defining areas of potentially high

consequences has focused on populated

areas, particularly, areas of high

population and areas where groups of

people reside who may have difficulty

evacuating an area.

Presently gas pipeline regulations are

structured to provide increasing levels

of protection, consistent with

predetermined thresholds, where

resident population is greater.

Accordingly, operators of gas pipelines

are required to monitor the number of

dwellings within 660 feet of the

pipeline, and either to lower operating

pressure or to replace the pipe with one

having greater wall thickness or strength

as the number of dwellings increases

above predefined thresholds.

The consequences of these

requirements are that—

• Gas pipeline operators have

excellent data on populations near their

pipelines, and

• Pipelines operating in areas of

higher population density (called Class

3 & 4) typically have thicker or stronger

walls than those in lower population

areas (called Class 1 & 2).

These factors, among others,

differentiate gas pipelines from those

that carry hazardous liquids.

In the technical sessions at the Public

Meeting, INGAA and AGA presented a

model that related gas pipeline diameter

and operating pressure to the physical

boundaries of the area impacted by the

heat from a gas pipeline rupture and

subsequent fire (i.e., the heat affected

zone). C–FER, a research and consulting

organization from Canada, developed

the model. C–FER validated this model

by comparing the predicted heat

affected zones with those actually

observed in several historic gas pipeline

accidents.

The model predicted that the extent of

the heat affected zone for pipelines of

up to 36 inches diameter and operating

at pressures up to 1000 psi would be

less than 660 feet. Rupture of larger

pipelines that are operating at a higher

pressure would lead to a larger heat

affected zone. To develop both the 660-

foot and the 1000-foot limits, C–FER

used a mathematical model of a burning

jet of natural gas emitted from a

ruptured pipeline. Using the results of

the model, INGAA and AGA suggested

High Consequence Areas be defined

as—

• All Class 3 & 4 locations as

presently defined in the pipeline safety

regulations;

• All locations where within 660 feet

of the pipeline there are facilities

housing people with impaired mobility

(e.g., schools, day care centers, assisted

living facilities, prisons, and hospitals);

• All locations where within 1000

feet of a pipeline that operates at

pressures exceeding 1000 psi and has

diameter greater than 30 inches there

are facilities housing people with

impaired mobility.

Critical Heat Flux

The INGAA/AGA analysis (developed

by C–FER) used 5000 btu/hr-ft2 as the

critical heat flux for defining the impact

radius. However, National Fire

Protection Association (NFPA) Standard

59A and 49 CFR Part 193 both use 4000

btu/hr-ft2 as the critical heat flux value.

OPS recognizes that the critical heat

flux is only one element in the equation

that relates pipe diameter and maximum

operating pressure to the extent of the

heat affected zone, and that C–FER

validated this equation by comparing

the predicted heat affected zones with

those actually observed in several past

gas pipeline incidents. However,

additional information would be useful

on—

• The source of the critical heat flux

used in the analysis.

• Other standards in which the 5000

btu/hr-ft2 value is used, as well as

standards in which the 4000 btu/hr-ft2

is used.

• The size of the heat affected zone in

the vicinity of a ruptured hydrogen

pipeline.

Housing

INGAA advocated that a high

consequence area be limited to areas

within an impact zone (discussed

above) where there are more than 25

houses or a facility housing people with

impaired mobility. OPS would like

comment on whether an impact zone

should be so limited, and if so, whether

25 houses is a reasonable number.

Other Considerations

OPS is seeking information to

evaluate the reasonableness of including

or excluding in a definition of high

consequence areas—

• All populous areas where the

impact radius of a pipeline rupture

would be predicted to exceed 660 feet.

• High traffic roadways, railways, and

places where people are known to

congregate (churches, beaches,

recreational facilities, museums, zoos,

camping grounds, etc.). For example,

the recent gas pipeline rupture near

Carlsbad, New Mexico occurred in an

unpopulated area. Twelve people died

in that incident.

• Areas of environmental

significance. Although environmental

consequences of a gas pipeline incident

may be localized, we recognize,

nonetheless, that a gas release can ignite

and cause damage to wildlife species

(animal and plants), and their habitat in

the area. We seek information to

determine what, if any, environmental

considerations need to be addressed.

Also of importance is whether these

areas can be readily identified so that

they can be mapped—similar to how

OPS is mapping unusually sensitive

environmental areas for the liquid

pipeline high consequence areas.

Mapping

OPS is creating the National Pipeline

Mapping System (NPMS), a database

that contains the locations and selected

attributes of natural gas transmission

lines and hazardous liquid trunk lines

and liquified natural gas facilities

operating in the United States.

Submission of this information has been

voluntary. At present, OPS has been

provided data on pipe locations for 82%

of liquid pipelines but only 40% of gas

34324 Federal Register / Vol. 66, No. 124 / Wednesday, June 27, 2001 / Notices

pipelines. OPS has also been mapping

for hazardous liquid operators the high

consequence areas defined in the liquid

integrity management rule. These areas

include populated areas, unusually

sensitive environmental areas, and

commercially navigable waterways.

These maps are useful to pipeline

operators and for community and state

needs. OPS is committed to continuing

to provide this information. OPS

intends to map the high consequence

areas that it defines in a gas integrity

management rule, similar to how it is

mapping these areas for the liquid

operators. OPS expects operators to

provide their pipeline data on both high

consequences areas and non-high

consequence areas. This information

could be in digitized form or in hard

copy. OPS would expect gas operators

to submit the high consequence area

data as an attribute associated with the

pipeline geospatial features. For

operators not supplying the population

data, OPS is considering using the

census data that it used to map the

population component of the high

consequence areas for the liquid

integrity rule. If an operator relies on

this census-based data, the operator

should be required to supplement the

census data with other pertinent data in

identifying gas high consequence areas.

Operators would submit all data

according to the NPMS standards. OPS

seeks input on the impact of this

strategy. OPS would also like comment

on whether local distribution companies

(LDCs) would prefer to use this censusbased population data to define their

high consequence areas.

2. Identify and Evaluate the Threats to

Pipeline Integrity in Each Area of

Potentially High Consequences

One of the key concepts advanced at

the Public Meeting was the need to

select the right assessment tool for each

significant threat. In the INGAA

presentation, threats were divided into

three categories: time dependent (e.g.,

internal and external corrosion), static

or resident (e.g., cracking introduced

during fabrication of the pipe or

construction of the pipeline), and

random (e.g., third party damage or

outside force damage). INGAA further

maintained that each category of threat

has technologies (or practices) useful for

managing the associated risk. For

example, time dependent threats would

require periodic inspection and static

threats would require hydrostatic testing

at some time during the life of the

pipeline (assuming that no significant

cyclic stress—such as strong pressure

fluctuations—was present). For random

threats, such as third party damage and

outside force, INGAA said that the right

tool would involve use of risk

management technologies (or practices)

to prevent damage or to immediately

identify the potential for damage, rather

than to look for evidence of past

damage. Preventive technologies or

practices might include third party

damage prevention and monitoring of

ground movement. INGAA argued that

preventive technologies and practices

are needed for these random threats

because the likelihood of immediate

rupture when the event occurs

dominates the risk.

Before an appropriate technology can

be selected to assess each significant

threat, a determination or definition of

what constitutes a significant threat has

to be made. OPS would like comment

on what best defines a threat as

significant.

Corrosion

The most prevalent time-dependent

threat is corrosion. Several technologies

exist or are in development both to

prevent corrosion and to identify the

potential for damage from corrosion.

OPS is seeking information on the

factors or combinations of factors that

provide the clearest indication that

corrosion is a significant risk to pipeline

integrity.

Third Party Damage

The most significant threat in areas of

high population is third party damage.

The vast majority (over 90%) of ruptures

caused by third party damage occur

when the threat occurs (i.e., when the

excavator hits the pipeline). However, a

small fraction of third party damage

failures do occur well after the impact.

Therefore, technologies that look for

evidence of past damage after the threat

has occurred should be focused in areas

where delayed failure is most likely.

OPS is seeking further information on

the combination of material properties

and/or operating conditions that could

increase the susceptibility of pipelines

to delayed failure following third party

damage. For example, thick walled, high

toughness pipe can sustain a strike from

a third party with a much lower

likelihood of immediate rupture than

other pipe. In combination with some

source of cyclic fatigue, such pipe can

be much more susceptible to delayed

rupture from third party damage.

Pipelines with these characteristics in

areas where the likelihood of third party

damage is high need to be assessed for

residual damage.

OPS also is seeking information on

pipeline industry efforts to explore new

technologies capable of recognizing or

preventing third party damage and to

incorporate proven technologies into

company integrity management plans.

Special Conditions

The presence of one or more critical

risk factors often indicates a

significantly increased likelihood of

other failure modes or threats. For

example, pre-1970 ERW piping is

known for seam cracking and

subsequent rupture. Such seam cracking

is difficult to detect using standard

pigging technologies. In addition, thick

walled, high toughness pipe can sustain

a strike from a third party with a much

lower likelihood of immediate rupture

than other pipe. In combination with

some source of cyclic fatigue, such pipe

can be much more susceptible to

delayed rupture from third party

damage. Further, some pipelines

operating at elevated temperature in a

potentially corrosive environment may

be especially susceptible to stress

corrosion cracking. OPS is seeking

information on any special

characteristics that can influence

pipeline risk and mode of failure. The

presence of these special characteristics

may necessitate the use of specially

designed assessment technologies.

Erosion

Some commenters have pointed out

soil erosion as a potential threat to

pipeline integrity. OPS is seeking

information on the conditions under

which soil erosion has been a significant

failure mode, including the possibility

of erosion exposing the pipeline to

external damage from passing waterborn debris, and on the practices useful

to prevent failure resulting from soil

erosion.

Operator Error

Several questioners at the public

meeting emphasized the need to address

operator error in compromising pipeline

integrity. INGAA responded that the

new Operator Qualification Rule

addresses the primary impacts of

operator error on pipeline integrity.

INGAA further said that each of the

three categories of failure causes (i.e.,

time-dependent, random, and static or

resident), the summary of failure causes

developed by Kiefner and Associates,

and the preventive and mitigative

practices documented by Hartford

Steam Boiler address operator error.

(The Kiefner and Hartford Steam Boiler

reports can be viewed on the OPS web

site under Initiatives/Pipeline Integrity

Management Program/Gas Transmission

Operator Rule ). Given these initiatives

to address operator error, OPS is seeking

information on how best to address

remaining integrity-related human error

Federal Register / Vol. 66, No. 124 / Wednesday, June 27, 2001 / Notices 34325

concerns in an integrity management

rule. In particular, OPS is interested

in—

∑ The potential for increased error in

conducting assessments and

interpreting results resulting from the

expanded application of assessment

technologies and interpretation of

assessment results that are likely to

result from an integrity management

rule, and

∑ Increased demands on the time of

experienced staff to integrate risk factor

information to identify significant

threats requiring assessment.

∑ How to increase reporting of error

within a company.

∑ How to ensure that lessons are

learned from error and incidents.

Treatment of Storage Fields

Storage fields have been the source of

pipeline integrity problems for decades.

OPS is seeking information to help

identify the cause of and prevent

piping-related failures associated with

storage fields that could affect high

consequence areas.

OPS is also interested in information

on the gas pipeline industry’s efforts to

reinvigorate the National Association of

Corrosion Engineers’ (NACE) standard

setting or develop guidance focused on

gas storage fields.

Low Stress Pipelines

The American Gas Association (AGA)

and American Public Gas Association

(APGA) maintain that—

• Pipelines operating at a stress level

below 20% specified minimum yield

strength (SMYS) are of low enough risk

that they should not be covered by a gas

integrity management program rule, and

• For pipelines operating between

20% and 30% SMYS, integrity

management practices other than

internal assessment, hydrostatic testing

and direct assessment are adequate.

(Direct assessment is a term coined by

the gas pipeline industry. The term is

described in greater detail below).

OPS is seeking the following

information to determine how best to

treat low stress pipelines in an integrity

management rule.

• Actual data on the leak and rupture

history (presented by failure mode) of

natural gas pipe operating below 20%

SMYS and between 20% and 30%

SMYS.

• Comparisons of this leak and

rupture history information with the

corresponding information for higher

stress piping (by failure mode).

• A more thorough discussion of the

process that AGA is advocating for

companies operating low stress

pipelines to follow to provide added

assurance of integrity. Questions to be

addressed include—

• Are risk profiles to be developed

and maintained for low stress pipe

segments that could affect high

consequence areas?

• How would such risk profiles be

used to support decisions on which

segments require application of more

extensive assessment technologies?

• What actions would be taken in

response to findings?

• What means should be used to

evaluate the potential consequences

associated with pipe segments that fail

by leaking? (e.g., Where does the

potential for accumulation of leaked gas

increase the likelihood of an explosion

ultimately occurring as a result of an

undetected leak?)

• What would be appropriate baseline

and reassessment intervals for low stress

lines (for those operating below 20%

SMYS and those operating between 20–

30% SMYS)?

3. Select Appropriate Assessment

Technologies

INGAA maintains that gas pipeline

integrity can be effectively assessed

using one or more of three approaches:

in-line inspection, hydrostatic testing

and the direct assessment process. (The

direct assessment process is discussed

below). INGAA further maintains that

selecting an assessment technology

should be based on an analysis of all

relevant risk factors to determine which

threats represent the most significant

risks.

Correspondence Between Threats and

Assessment Technologies

To ensure that integrity management

programs are designed to address the

full spectrum of failure causes (threats),

OPS is seeking information on the

correspondence between assessment

technologies and the threats they are

designed to detect. Available

information on the range of

effectiveness of each technology would

also be beneficial.

Experience With In-Line Inspection

OPS is seeking information on

experience with using in-line inspection

(ILI) technology. Relevant information

would include the number, type and

severity of features or defects discovered

as a function of the technology

employed, risk factors that were present,

and when and how the defects were

acted on. These data could help us in

determining the potential number of

incidents prevented through the use of

ILI technology. We are also seeking data

on estimated costs associated with

implementing ILI technology.

Effectiveness of Pressure Testing

INGAA contends that a pressure test

conducted at any time during the life of

a pipeline provides adequate assurance

that so-called static or resident defects

(e.g., cracking introduced during

fabrication or construction) are no

longer an integrity concern. The premise

behind this position is that gas pipelines

do not typically operate under cyclic

pressure loading of sufficient magnitude

to promote crack growth. Therefore, a

hydrostatic or pressure test conducted at

any time during the life of the pipeline

will forever eliminate any concern about

the risk from static or resident defects.

INGAA has not claimed that a once-ina-lifetime pressure test will eliminate

concern for other types of threats such

as time-dependent (e.g., corrosion) or

random (e.g., third party damage). OPS

is seeking information on conditions

(other than changes in cyclic pressure

loading) in which the premise that a

once-in-a-lifetime pressure test will

eliminate the risk from static or resident

defects does not apply.

Incentives To Increase the Piggability of

Lines

OPS is interested in promoting the

appropriate expanded use of in-line

inspection (or pigging) technologies.

Therefore, OPS is seeking information

on the current and near-term expected

mileage of gas transmission lines that

can be pigged, as well as on financial (or

feasibility) barriers to making other lines

piggable.

Direct Assessment

Direct assessment is a structured

process for assessing pipeline integrity.

While OPS focus on direct assessment at

this stage is on assessing external

corrosion, work is in process to explore

its application to internal corrosion and

stress corrosion cracking. The process

has four basic steps:

1. A comprehensive integrative

analysis of risk factor data is used to

determine whether direct assessment

will apply, what threats are likely to be

significant, where these significant

threats are likely to be present, and what

tools are best suited to characterize pipe

condition. Candidate data for

integration include:

• Pipe characteristics (e.g., wall

thickness, coating material and

condition, pipe toughness, pipe

strength, pipe fabrication technique,

pipe elevation profile);

• Internal and external environmental

factors (e.g., soil moisture content and

acidity, gas operating temperature and

moisture content);

• Operating and leak history (e.g.,

pipe failure history, past upset

34326 Federal Register / Vol. 66, No. 124 / Wednesday, June 27, 2001 / Notices

conditions that have introduced

moisture into the gas);

• Land use (e.g., active farming,

commercial construction, residential

construction);

• Protection history (e.g., cathodic

protection system and history, history of

third party hits and near misses,

effectiveness of local One Call systems);

• The degree of certainty about the

current condition of the pipeline (e.g.,

age of the pipe, completeness of

integrity-related records, available

inspection data).

2. An above ground examination is

made of the pipeline using one or more

direct assessment tools to identify areas

where coating defects (holidays and

disbondment) are likely to exist and

whether or not active corrosion is likely

to be present.

3. Excavation (digging bell holes) is

used to expose the pipe in areas

suspected to be experiencing active

corrosion, then the pipeline is examined

visually, and other evaluative

techniques such as ultrasonic testing are

used.

4. Information from all available

excavations is integrated and

generalized to determine whether and

where additional bell holes should be

dug to seek out additional potential

active corrosion.

Validation Process and Research &

Development Efforts on Direct

Assessment

The individual technologies

employed in direct assessment have

been utilized for pipeline integrity

assessment for many years. However,

the use of these technologies in an

integrated process that includes analysis

of risk factor data is new. Also, some

new tools such as Direct (or Alternate)

Current Voltage Gradient (DCVG or

ACVG), Pipeline Current Mapper, CScan and C-Spin are being introduced.

Therefore, the industry has undertaken

a validation process designed to

determine both the conditions under

which direct assessment is most

effective and the effectiveness of the

overall process. OPS is providing

funding for this project along with

extensive project oversight. Process

effectiveness will be evaluated by

comparing the results from direct

assessment technologies with the results

from bell hole examinations and with

the results from in-line inspection of the

same segments. Between 15–25 pipeline

operators are participating in this

validation study by contributing

existing assessment data and developing

new data from application of the

technologies. State agencies are

involved in reviewing the data.

OPS is seeking the following

information on the direct assessment

process:

• How direct assessment can be

validated and applied for external and

internal corrosion, including

applications for dry and wet gas lines;

• The need where there are multiple

threats on the same segment of pipeline

for complementary supporting

assessment techniques, or for additional

corrective and mitigative actions, to

address the multiple threats;

• Whether there are conditions where

direct assessment may not be possible or

may not give accurate information;

• The statistical basis for validating

the external and internal corrosion

direct assessment process as well as the

justification for this basis;

• How direct assessment can be

applied and evaluated for stress

corrosion cracking;

• Available standards to support the

use of all types of direct assessment that

are envisioned;

• The most important risk factors that

should be considered in analyzing the

applicability of each direct assessment

technology to each threat.

• The process for information

integration as it relates to direct

assessment.

• The application of direct

assessment to uncoated pipeline.

Local distribution companies

AGA and APGA contend that because

local distribution company (LDC)

transmission pipelines are typically so

closely coupled to the distribution

system, hydrostatic testing would result

in significant service interruptions, and

pigging would be highly uneconomical

if even possible. In a white paper

released since the public meeting, AGA

and APGA have described what

alternative technologies are available,

and why alternatives provide adequate

protection for these lines. (This paper

can be found on the OPS web site under

Initiatives/Pipeline Integrity

Management Program/Gas Transmission

Operator Rule and in the DOT docket.)

4. Determine Time Frames To Conduct

a Baseline Integrity Assessment and To

Complete Repairs Following an

Assessment Using a Graded (Tiered)

Approach That Prioritizes Pipeline

Segments Based on Risk

A time frame will have to be

determined for operators to conduct a

baseline assessment of their pipe

segments using a graded or tiered

approach. Under this approach, an

operator would prioritize all applicable

pipeline segments for assessment based

on the risk the segments pose to the

high consequence areas. The risk would

be determined from risk factors. A

schedule for completing repairs of the

segments after the assessment would

also be based on risk factors. One of the

factors in developing the required time

frame, or establishing variances from the

required time frame, would be the need

to maintain gas supply to the public.

Baseline Assessment

The INGAA presentation did not

discuss a time frame for a baseline

assessment. To help develop a required

baseline assessment schedule that

considers the various risk levels for each

pipe segment to be assessed, OPS is

seeking the following information.

• Practical considerations of

establishing a graded (or tiered)

approach for conducting a baseline

assessment. A graded approach is one

where baseline assessments of the

highest risk pipeline segments are

conducted as soon as possible with

baseline assessments for lower risk

segments completed subsequently. Risk

would be determined from risk factors,

whether specified, operator-developed

or a combination.

• The time required for the industry

to mobilize (e.g., develop models and

perform needed risk analysis, complete

demonstration of needed technologies,

train and qualify the resource base

needed to support a baseline

assessment).

• Information on the impacts to the

gas supply and to the cost of gas if a

time frame for completing a baseline

assessment were required, for example,

a time frame of 5, 10 or 15 years.

• Repair criteria currently being

considered. Criteria would include time

frames for competing repairs following

an assessment.

5. Identify and Implement Additional

Preventive and Mitigative Measures

INGAA submitted a report (prepared

by the Hartford Steam Boiler Inspection

and Insurance Company) that

summarizes the range of threats

identified as causing failure in gas

pipelines, the management practices

industry is using to manage these

threats, and the research contributing to

the understanding of the threats. (This

report is available in the DOT docket

and on the OPS web site under

Initiatives/Pipeline Integrity

Management Program/Gas Transmission

Operator Rule.)

• OPS is seeking unattributed

examples of typical decision processes

that an operator uses to manage threats

to pipeline safety by implementing

discretionary preventive or mitigative

technologies or practices such as those

Federal Register / Vol. 66, No. 124 / Wednesday, June 27, 2001 / Notices 34327

discussed in the Hartford Steam Boiler

report.

As part of the integrity management

process, an operator would need to take

additional measures to prevent and

mitigate the consequences of a pipeline

failure in high consequence areas. In the

liquid integrity management rule,

operators are required to conduct a risk

analysis of each pipeline segment to

identify additional measures to enhance

safety and environmental protection.

For gas pipelines, additional preventive

and mitigative measures could include

actions such as damage prevention best

practices, better monitoring of cathodic

protection, establishing shorter

inspection intervals, and installing

Remote Control Valves (RCVs) and

Automatic Shutdown Valves (ASVs) on

pipeline segments.

• OPS is seeking information on the

effectiveness, technical feasibility,

economic feasibility, and reduction of

risk with RCVs and ASVs.

6. A Process for Continual Evaluation

and Assessment to Maintain a Pipeline’s

Integrity

Integrity assurance involves periodic

assessment of the integrity of each

pipeline segment within a high

consequence area, periodic evaluation

of the entire pipeline to determine

threats relevant to the pipeline segment,

and repair of problems.

Periodic Reassessment

Times frames need to be developed

for an operator to periodically assess the

integrity of its pipeline segments. At the

public meeting, INGAA recommended a

periodic reassessment interval for all

technologies (i.e., in-line inspection,

direct assessment and hydrostatic

testing) of 10 years for pipe of thickness

typically used in Class 1 & 2 locations,

and 15 years for pipe of thickness

typically used in Class 3 & 4 locations.

INGAA said these reassessment

intervals were conservative estimates of

the maximum time between pipeline

inspections to prevent failure of the

largest defect and that they were

developed based on very conservative

assumptions on corrosion growth rate

that were checked against both analysis

and experience data. INGAA further

explained that these reassessment

intervals assumed that at the beginning

of the interval, the pipe thickness was

not less than that of new pipe

appropriate for the class location. Thus,

there would be variations in the actual

reassessment interval depending on the

assessment technology. INGAA noted

that an operator might be able to extend

the reassessment interval based on its

knowledge of and demonstrated control

over the principal risk factors for its

pipeline, but that if any of the data on

key risk factors were missing, then an

operator would need to develop a

shorter reassessment interval.

OPS is seeking information to help it

determine appropriate periodic

reassessment intervals. This information

could include examples detailing a

proposed reassessment interval

following a successful baseline

assessment and repair of problems

found during the assessment. These

examples could use the INGAA

proposed intervals or any other, such as

those required in the liquid pipeline

integrity management rules. The

examples could also factor in repair

criteria used to re-mediate problems

found during the baseline assessment.

In some cases pipelines have been

designed for placement in Class 3 and

4 locations by using steel with greater

toughness and strength rather using

pipe having greater wall thickness.

These pipelines are no less susceptible

to corrosion damage; therefore, OPS is

considering whether a reassessment

interval should be defined by the wall

thickness rather than by the Class

location for a pipeline segment. OPS

would also like information on how a

reassessment interval would factor in

the impact of increased ligament

strength where higher strength pipe is

used rather than thicker pipe.

Repairs

Following the reassessment, an

operator would have to schedule repairs

on the pipeline segments. This would be

done by prioritizing the anomalies

found during the assessment for

evaluation and repair. The schedule,

which would be risk-based, would need

to provide time frames for evaluating

and completing repairs. In the liquid

integrity management rule, we provided

time frames for an operator to complete

repair of certain conditions on a

pipeline following an assessment. For

those conditions not specified, we

allowed the operator to provide time

frames for evaluating and completing

the repairs. The schedule was to be

based on specified and pipeline-specific

risk factors.

Comment is sought on the time frames

to complete needed repairs and factors

that need to be considered in

establishing these time frames. One

factor could be the impact on the gas

supply. If no other guidance is available

on scheduling repairs, OPS may develop

a repair schedule similar to that used in

the liquid integrity management rule.

Evaluation

A periodic evaluation looks at all

available information about the entire

pipeline to determine what could be

relevant to the pipeline segment being

examined. The frequency at which

evaluations are conducted could be

based on risk factors, either specified

factors, operator-developed or a

combination. We seek comment on how

to determine frequency and how to

ensure that information is analyzed on

all threats to a segment.

Direct Assessment

OPS is seeking information on the

logistics of rapidly expanded use of

Direct Assessment technologies,

particularly on whether the current pool

of trained and qualified assessors would

pose any constraint to industry’s ability

to rapidly expand the use of these

technologies. This issue should also be

considered in conjunction with any

input on the best strategy for

establishing a baseline assessment

interval.

7. Monitor the Effectiveness of Pipeline

Integrity Management Efforts

OPS is seeking information on how it

could best monitor the effectiveness of

operator integrity management efforts.

Information is needed both on specific

direct performance measures and on

indirect measures derived from analysis

of assessment results and corrective

actions taken.

OPS and the industry have been

criticized for an ineffective system that

assembles incident data, analyses it for

possible implications to other pipelines,

communicates across the industry the

general lessons and implications of the

these incidents, and follows up to

evaluate the effectiveness of operator

incorporation of the general lessons

from these incidents. Some work to

address this issue is ongoing, such as

revised reporting criteria. OPS is

seeking input on potential additional

actions that could be taken jointly by

OPS and the industry to address this

concern.

8. Consideration of Impact on Gas

Supply

OPS needs information to evaluate the

effect of new safety requirements on gas

supply to residents. This is one of many

factors that OPS will need to consider

in establishing a baseline assessment

time frame. Information is needed on

how gas supply would be affected with

baseline assessment time frames of 5, 10

and 15 years. The same information is

needed for reassessment intervals of 5,

10, 15 and 20 years.

34328 Federal Register / Vol. 66, No. 124 / Wednesday, June 27, 2001 / Notices

1Pursuant to 49 CFR 1150.50(d)(2), the railroad

must file a verified notice with the Board at least

50 days before the abandonment or discontinuance

is to be consummated. While the applicant initially

indicated a proposed consummation date of June

10, 2001, because the verified notice was filed on

June 7, 2001, consummation may not take place

prior to July 27, 2001. Applicant’s representative

has subsequently confirmed that the correct

consummation date is on or after July 27, 2001.

2The Board will grant a stay if an informed

decision on environmental issues (whether raised

by a party or by the Board’s Section of

Environmental Analysis (SEA) in its independent

investigation) cannot be made before the

exemption’s effective date. See Exemption of Outof-Service Rail Lines, 5 I.C.C.2d 377 (1989). Any

request for a stay should be filed as soon as possible

so that the Board may take appropriate action before

the exemption’s effective date.

9. Other Issues Including Those Related

to Cost/Benefit

Scope of Integrity Management Planning

Earlier in this document OPS

explained its current thinking about the

scope of a proposed integrity

management rule. OPS would like

comment about its underlying

assumptions.

Cost Benefit Analysis

To support its cost benefit analysis,

OPS is seeking additional information

on the following topics:

• Benefits and costs of a company’s

active-in-line inspection and pressure

testing programs. Information could

include the results on safety such as the

reduction of accidents or leaks.

• Benefits and costs of a company’s

integrity assessment program employing

direct assessment technologies.

Information could include the types of

direct assessment that have been used or

considered. The costs associated with

the technologies. The results related to

safety, such as the reduction of

accidents or leaks reduced.

• The total mileage of gas

transmission pipeline. The number of

miles of gas transmission pipelines that

have been hydrostatically tested to

current standards. The number of miles

of gas transmission pipelines that have

been pigged at least once.

• The estimated average cost per mile

to hydrostatically test a gas transmission

pipeline. The fraction of this cost that is

associated with taking the line out of

service. Ways to minimize the cost

associated with taking the line out of

service, such as using existing looping.

• The estimated average cost per mile

to internally inspect a gas transmission

pipeline. The fraction of this cost that is

associated with taking the line out of

service. Ways to minimize the cost

associated with taking the line out of

service, such as using existing looping.

• The percentage of an operator’s

pipelines that are not capable of being

pigged. The reasons the pipeline is not

piggable, for example, because it is

telescopic, has sharp radius bends, or

has less than full opening valves The

costs to make the line piggable.

• Impacts on small businesses. The

impacts an integrity management

rulemaking will have on the company.

Include any special concerns that RSPA

should consider in addressing impacts

on small businesses. Include whether

there are alternative requirements for

small businesses that are less onerous.

• The estimated average cost per mile

to use direct assessment on a gas

transmission pipeline. The assumptions

this estimate includes on the number of

bell holes required per mile.

• The estimated average cost per mile

to change out a gas transmission

pipeline to comply with existing class

location regulations. The number of

miles per year that are typically

replaced to comply with this regulation.

• The best available data on the

actual costs associated with reported gas

pipeline incidents.

• An inventory of pipeline mileage

for pipe having diameter greater than or

equal to 30 inches and MAOP greater

than or equal to 1000 psi.

Standards

During the public meeting, INGAA

stated that consensus standards

represent a practical way to

institutionalize both the use of new

technology and the effective application

of existing technology. INGAA said that

standards currently being developed

should provide detailed information for

operators in implementing any integrity

management rule that is eventually

issued.

OPS is seeking information on the

schedule the Standards Organizations

have for completing the various

standards that relate to integrity

management that are expected to be

prepared, particularly the standards on

conducting integrity assessments and

repair criteria. The current ‘‘draft’’

Schedule on Standards is found at the

end of this Notice.

Industry Data Analysis

We believe that data sources outside

OPS incident data should be considered

in developing risk analysis and

assessment intervals. OPS seeks to

better understand the extent to which

data beyond these incident histories,

including data from all incidents and

near misses, were used to validate

industry positions.

Issued in Washington, DC, on June 19,

2001.

Jeffrey D. Wiese,

Acting Associate Administrator for Pipeline

Safety.

[FR Doc. 01–15990 Filed 6–26–01; 8:45 am]

BILLING CODE 4910–60–P

DEPARTMENT OF TRANSPORTATION

Surface Transportation Board

[STB Docket No. AB–492 (Sub–No. 2X)]

Fillmore Western Railway Company—

Abandonment Exemption—in Fillmore

County, NE

Fillmore Western Railway Company

(FWRY) has filed a notice of exemption

under 49 CFR 1152 Subpart F—Exempt

Abandonments and Discontinuances to

abandon a line of railroad between: (a)

milepost 1.7 near Fairmont and

milepost 10.0 near Geneva, NE; and (b)

milepost 8.1 near Fairmont, NE, and

milepost 23.0, near Milligan, NE, a

distance of approximately 23.2 miles in

Fillmore County, NE.1 The line traverses

United States Postal Service Zip Codes

68354, 68401, 68361, and 68406.

FWRY has certified that: (1) No local

traffic has moved over the line for at

least 2 years; (2) there has been no

overhead traffic on the line in the past

2 years; (3) no formal complaint filed by

a user of rail service on the line (or by

a state or local government entity acting

on behalf of such user) regarding

cessation of service over the line either

is pending with the Surface

Transportation Board (Board) or with

any U.S. District Court or has been

decided in favor of complainant within

the 2-year period; and (4) the

requirements at 49 CFR 1105.7

(environmental reports), 49 CFR 1105.8

(historic reports), 49 CFR 1105.11

(transmittal letter), 49 CFR 1105.12

(newspaper publication), and 49 CFR

1152.50(d)(1) (notice to governmental

agencies) have been met.

As a condition to this exemption, any

employee adversely affected by the

abandonment and discontinuance shall

be protected under Oregon Short Line R.

Co.—Abandonment—Goshen, 360 I.C.C.

91 (1979). To address whether this

condition adequately protects affected

employees, a petition for partial

revocation under 49 U.S.C. 10502(d)

must be filed. Provided no formal

expression of intent to file an offer of

financial assistance (OFA) has been

received, this exemption will be

effective on July 27, 2001, unless stayed

pending reconsideration. Petitions to

stay that do not involve environmental

issues,2 formal expressions of intent to

file an OFA under 49 CFR