Pipeline Safety: Enhanced Safety and Environmental Protection for Gas Transmission and Hazardous Liquid Pipelines in High Consequence Areas

DEPARTMENT OF TRANSPORTATION

Research and Special Programs Administration

49 CFR Parts 192 and 195

[Docket No. RSPA-99-6355; Notice 1]

Pipeline Safety: Enhanced Safety and Environmental Protection for

Gas Transmission and Hazardous Liquid Pipelines in High Consequence

Areas

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

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ACTION: Notice of public meeting and request for comments.

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SUMMARY: This notice announces a public meeting to consider the need

for additional safety and environmental regulations for gas

transmission lines and hazardous liquid pipelines in high-density

population areas, waters where a substantial likelihood of commercial

navigation exists, and areas unusually sensitive to environmental

damage. RSPA's Office of Pipeline Safety (OPS) intends to incorporate a

process into its regulations to validate pipe integrity in these high

consequence areas. The purpose of the meeting is to determine the

extent to which operators now have integrity management programs, to

explore effective ways to promote their development and implementation

by all operators, and to discuss mechanisms by which OPS could confirm

the existence and adequacy of such operator-developed programs. The

meeting will discuss a practical definition of high consequence areas,

as well as the need, if any, for increased inspection, enhanced damage

prevention, improved emergency response, and other measures to prevent

and mitigate pipeline leaks and ruptures in these areas.

DATES: The public meeting will be on November 18, 1999, from 9 a.m. to

4 p.m., through November 19, 1999, from 9 a.m. to 12 noon, at the Hyatt

Dulles Hotel, 23 Dulles Corner Boulevard, Herndon, VA 20171, (703) 713-

1234. If you want to make an oral presentation at the meeting, please

notify Jenny Donohue no later than November 12, 1999, by phone (202-

366-4046) or by Internet e-mail ([email protected]). In addition,

no later than December 20, 1999, you may submit written comments as

described in the ADDRESSES section.

ADDRESSES: Submit written comments by mail or delivery to the Dockets

Facility, U.S. Department of Transportation, Room PL-401, 400 Seventh

Street, SW, Washington, DC 20590-0001. You also may submit written

comments to the docket electronically. To do so, log on to the

following Internet Web address: http://dms.dot.gov. Click on ``Help &

Information'' for instructions on how to file a document

electronically. All written comments should identify the docket and

notice numbers stated in the heading of this notice. Anyone desiring

confirmation of mailed comments must include a self-addressed stamped

postcard.

The Dockets Facility is located on the plaza level, Room PL-401, of

the US Department of Transportation, 400 7th St., SW, Washington, DC.

It is open from 10 a.m. to 5 p.m., Monday through Friday, except

federal holidays.

FOR FURTHER INFORMATION CONTACT: Beth Callsen (tel: 202-366-4572; E-

mail: [email protected]). You can read comments and other

material in the docket on the Internet at: http://dms.dot.gov.

SUPPLEMENTARY INFORMATION:

Background

Office of Pipeline Safety (OPS) and National Transportation Safety

Board (NTSB) investigations and analyses of major pipeline incidents

have underscored the importance of ensuring safety and environmental

protection in areas of high population density and in areas unusually

sensitive to environmental damage. Congress has also directed OPS to

undertake a variety of activities concerning areas where the risk of a

pipeline spill could have significant impact (what we call high

consequence areas). For example, Congress directed OPS to prescribe, if

necessary, additional standards requiring the periodic inspection of

each pipeline in high population density areas or in areas unusually

sensitive to environmental damage (49 U.S.C. 60108 (b)).

In response to the Congressional directive, OPS created the Risk

Management Demonstration Program, the Systems Integrity Inspection

(SII) Program, and other initiatives. These programs encourage and

evaluate operator-developed safety and environmental management

processes that incorporate operator- and pipeline-specific information

and data to identify, assess, and address pipeline risks. These

programs, along with the Oil Spill Response Plan Review and Exercise

Program, have helped OPS refine regulatory oversight processes. These

processes help to ensure that pipeline operators have effective

processes in place to identify the most important risks to the public

and the environment, and to develop and implement cost-effective

preventive and mitigative actions to manage these risks. Many of these

initiatives have validated the importance of focusing resources and

establishing higher levels of protection in areas where a pipeline

spill could have significant consequences.

Through its various programs and initiatives, OPS has observed and

become familiar with the wide array of existing operator safety

programs that identify, assess, and address all significant risks to

the pipeline in an integrated manner. These operator-developed programs

closely examine internal inspection data, surveillance and operating

information such as expected population growth, land use, and

construction activity along the pipeline, and other information

relevant to assuring the pipeline's integrity in high population areas

and in environmentally sensitive areas. OPS believes the next step is

to determine the extent to which such programs exist, to develop

effective ways to encourage their development and implementation by all

operators, and to establish mechanisms by which OPS can confirm the

existence and adequacy of such operator-developed programs.

OPS believes that current pipeline safety regulations address the

most important risks to the nation's pipelines, and have served the

industry well, resulting in a good safety record compared to

competitive modes of transportation. However, safety programs based on

strict compliance with the regulations can often result in a piece-meal

approach to identifying and controlling risks, sometimes neglecting the

interrelationships among failure causes and the benefits of coordinated

risk control activities.

OPS is considering ways to further enhance safety and environmental

protection in areas where a pipeline failure could have serious

consequences for the public or the environment, i.e., high consequence

areas, through a more integrated approach to identifying and addressing

risks. A conceptual approach is described below. OPS believes that many

operators already have processes in place that are consistent with this

approach. Through this Notice and the November 18-19, 1999, public

meeting, OPS is soliciting input on this or other approaches to

improved protection for high consequence areas.

Key Elements

OPS envisions a process that places stronger regulator and operator

emphasis on high consequence areas in the vicinity of pipeline

facilities. The following key elements should be reflected in such a

process:

1. The need for pipeline-specific assessments in determining the need

for additional preventive and mitigative activities.

OPS recognizes that industry-wide requirements for specific

additional preventive or mitigative actions might not be the most

effective way of reducing risk. Companies must have the responsibility

and the necessary flexibility to consider geographic- and segment-

specific conditions in assessing the need for additional safety and

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environmental protection programs and in developing effective programs.

2. The need to assess all risk factors and risk reduction activities in

an integrated manner.

Analyses of major pipeline incidents show that combinations of

design, operation, maintenance, and environmental factors are usually

involved, rather than a single cause. Accordingly, OPS envisions

assessment and decision processes that examine causes for pipeline

failure in a comprehensive and integrated manner. For example, data

from internal in-line inspections must be combined with other

information related to the condition of the pipe (e.g., results of

close internal surveys and patrols) to determine appropriate evaluation

and remediation activities.

3. The need for increased assurance that high consequence areas are

being protected.

OPS recognizes that existing regulations and industry practices

already focus on some high consequence areas. For example, the class

location scheme embedded in the gas pipeline regulations imposes more

stringent requirements in areas with higher population. Many liquid

pipeline operators already have formalized environmental, safety, and

health programs that focus attention and resources on areas of highest

risk. However, OPS also recognizes the need to assure the public that

the condition of the pipelines in high consequence areas is adequately

known, that current regulations and industry practices are adequate,

and that the need for additional protection has been explicitly and

responsibly considered.

OPS's Approach to Improved Protection

OPS envisions a process that would include, at the least, the

following steps:

Defining and Locating High Consequence Areas

Identifying Affected Pipeline Segments

Inspecting and Assessing the Condition of the Affected

Segments

Assessing the Need for Additional Preventive or Mitigative

Actions

Remediating and Repairing the Affected Segments as

Necessary

Implementing and Monitoring Other Cost-Effective Risk

Control Activities

Documenting Inspections, Assessments, and Actions

Reviewing and Ensuring Compliance

(See the Flowchart included in this Notice.)

Each of these steps is briefly discussed below, including key

questions for discussion.

Identifying and Locating High Consequence Areas

The first step in the process is to identify and locate the areas

where a pipeline failure could pose serious safety and environmental

consequences to the public or environment. This first step is intended

as a filtering step, focusing attention on those areas of possible high

consequence. Subsequent steps address the likelihood of such

consequences actually occurring, and the need for any action to reduce

the likelihood or consequences of a pipeline incident in these areas.

There are relevant past and current efforts to define or identify

these areas.

Class locations for gas pipelines (49 CFR 192.5) are based

on habitable structures within a 220 yard corridor on either side of

the pipeline.

Many companies have developed Geographic Information

Systems (GIS) that can provide accurate, more detailed information

concerning the proximity of population and buildings to the pipeline.

OPS, other federal agencies, and the hazardous liquid

pipeline industry are working together to develop a definition for

Unusually Environmentally Sensitive Areas (USAs), focusing on areas in

which a pipeline spill could threaten local water supplies, threatened

and endangered species, and other environmental resources (Docket No.

RSPA-99-5455; 64 FR 38173; July 15,1999). OPS is currently pilot

testing a model for defining USAs.

In high consequence areas, OPS believes that an operator should be

required to explicitly assess each area, determine the condition of the

pipeline that could affect these areas, understand the potential causes

of failure of these pipelines, and ascertain the need, through a

structured and documented process, for additional preventive or

mitigative actions.

Key questions that OPS would like to discuss at the meeting

include:

a. How should ``high consequence'' areas be defined?

1. What is the status of OPS's definition of USAs?

2. What should be the definition of ``high population density''

area for a natural gas pipeline?

3. Can operator GIS systems be used to identify high population

areas with greater precision than current class location schemes?

4. What should be the definition of ``high population density''

area for a hazardous liquid pipeline?

5. Should ``high property damage,'' ``significant disruption in

service,'' ``significant disruption in commerce,'' ``waters where a

substantial likelihood of commercial navigation exists,'' or the

potential for other significant consequences be included in the

definition of high consequence areas?

b. Should the operator or OPS be responsible for identifying the

location of high consequence areas?

c. What percentage of natural gas pipelines might be expected to

intersect high consequence areas (e.g., what percentage currently are

in Class 3 or Class 4 locations?)

d. What percentage of hazardous liquid pipelines might be expected to

intersect high consequence areas (e.g., what percentage currently are

in non-rural areas or intersect USAs).

e. What process should OPS or the industry use to ensure that the

identified high consequence areas continue to reflect current

conditions along the pipeline (e.g., population expansion, new

information on environmental resources)?

2. Identifying Affected Pipeline Segments

In this step, the specific pipeline segments whose failure could

have serious safety or environmental consequences are identified. Once

the high consequence areas are located on a map, the existing pipelines

must be overlaid to identify the segments in or in close proximity to

these areas. The physical ability of the overlaid pipeline segments to

affect the environmental resources in the area or to impact the

surrounding population must then be examined. The fact that a pipeline

is within a high consequence area (defined in the first step) does not

necessarily mean that a pipeline leak or rupture can result in

environmental damage or impact public safety. For example, the

population in a ``high population density'' area might be physically

located sufficiently far from the pipeline to preclude safety impact.

There may also be topographical barriers between the environmental

resource and the pipeline that would preclude migration of any spill

from the pipeline to the resource. This step, in conjunction with the

first screening step, allows the pipeline operator to take into account

pipeline-specific information to identify those segments of pipe that

could result in environmental damage or public safety consequences.

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Key questions that OPS would like to discuss at the meeting

include:

Does adequate data exist for operators to reliably

ascertain the specific pipeline segments that could affect ``high

consequence'' areas?

Should pipeline segments near, but not within, high

consequence areas also be examined for possible impact? If yes, what

kinds of assumptions should be used to determine whether or not an

impact occurs (e.g., use of ``worst case discharge'' from spill

response plans)?

What would be the expected cost to an operator to perform

this step?

3. Inspecting and Assessing the Condition of the Affected Segments

The next step in the process is for the operator to understand and

assess the condition of the pipeline segments identified in Step 2.

This step, in conjunction with the following step, is intended to

ensure that the likelihood of pipeline failure due to internal or

external corrosion, construction damage, previous excavation damage, or

other mechanical damage is very low.

Undetected defects introduced by corrosion or by outside force

damage have caused major pipeline accidents. Some of the major pipeline

incidents over the last decade involved degradation of wall thickness

from dents or gouges caused by outside force or third party damage. In

some instances these dents and gouges had been in the pipe for a period

of time before failure, and the line had not been inspected using

internal inspection tools capable of detecting wall thinning or

geometric defects in the pipe. OPS is especially interested in methods

to detect and repair such defects before they lead to leaks or ruptures

in high consequence areas.

One acceptable way of performing this step would be the use of an

intelligent in-line inspection device (smart pig) appropriate to the

type of pipeline being inspected. An operator can also use alternative,

equivalent means to assess the condition of the affected segments. If

the line has recently been pigged, the operator could review the

available pig data in conjunction with other current data (e.g., from

close interval surveys) to assess the condition of the line. This step

results in an operator identifying anomalies (areas of potential loss

of wall thickness or pipe damage) that should be investigated further.

The hazardous liquid pipeline industry has developed recommended

practices for monitoring, testing, and inspection methods that go

beyond the requirements of 49 CFR part 195 (API Recommended Practices

1129, Assurance of Hazardous Liquid Pipeline System Integrity). This

document comprises a range of best practices--including design and

construction; monitoring and controls; inspections, reviews and audits;

and damage prevention--to assist pipeline operators in improving the

integrity of their pipeline systems.

Key questions that OPS would like to discuss at the meeting

include:

Are current industry standards sufficient for pipelines in

high consequence areas? For example, is the ASME B.31 standard, used by

operators to determine acceptable pipe wall loss, appropriate in high

consequence areas? Or should more conservative standards apply in these

areas?

What is the current capability of smart pigs to find prior

mechanical damage and other defects?

What alternatives to internal inspection can provide

equivalent information on pipeline condition?

How recently should a line have been pigged to provide

reliable data for this step? What factors should be considered in

making this determination (e.g., recent construction activity, cathodic

protection system performance, interference from foreign line

crossings, etc.)?

What percentage of natural gas pipelines in Class 3 or

Class 4 areas have been smart pigged in the last 5-10 years?

What percentage of hazardous liquid pipelines intersecting

non-rural or environmentally vulnerable areas might be expected to have

been smart pigged in the last 5-10 years?

What is the expected cost to an operator to pig (or

equivalent) pipeline segments that would impact high consequence areas?

How soon should the condition of the a line be assessed

after determining that it could impact a high consequence area?

What criteria should be used to identify anomalies that

require further investigation?

What is the appropriate period between pig runs for high

consequence areas? (Should this period be based on pipeline-specific

conditions impacting the likelihood of corrosion or mechanical damage?)

Should OPS specify minimum performance criteria for

internal inspection tools? If so, what should those criteria be?

4. Assessing the Need for Preventive or Mitigative Actions

In this step, the operator would determine the most likely causes

of failure in the identified high consequence areas, and determine if

any additional preventive or mitigative actions, beyond those the

regulations require or the operator performs, are needed. In addition

to assessing the need for repairs to lower the likelihood of leaks or

ruptures due to corrosion or past mechanical damage (in Step 3), the

operator should also assess the need for additional preventive actions

to lower the likelihood of failure from all potential causes (e.g.,

third party damage, geological hazards, operation and control center

malfunctions, etc.) or additional mitigative actions to reduce the

consequences should the pipeline leak or rupture.

This assessment should be performed as part of an integrated,

segment-specific assessment of the possible causes of pipeline failure,

and cost-effective actions to reduce the specific risks identified on

these segments.

Although internal inspection and remediation of the lines can help

ensure the condition of the lines, inspection and remediation does not

address many important causes of pipeline failure. For example, OPS

data show that in 1998, 37 percent of reported gas pipeline incidents

were due to outside force damage. Similarly, on hazardous liquid

pipelines, outside forces caused 26 percent of reportable events.

Additional preventive measures may be needed to reduce the likelihood

of these reported incidents, or to reduce the expected level of

consequences should an incident occur. Accordingly, in addition to

internal inspection of pipeline segments in high consequence areas, OPS

is also interested in comment on the need for additional assessments

and analyses of other preventive and mitigative measures to reduce risk

in these areas.

For example, additional preventive measures might include the

development of enhanced damage prevention programs. Recently, OPS

sponsored a multi-industry effort to define best practices in damage

prevention. Although OPS is not considering translating these best

practices into regulations, it is interested in comments on how to

otherwise promote the adoption of damage prevention best practices to

reduce the likelihood of pipeline incidents. Additional mitigative

actions might include developing enhanced emergency response plans in

high consequence areas, or using emergency flow restricting devices or

remotely controlled valves to limit the amount of product loss

following a line failure.

Key questions that OPS would like to discuss at the meeting

include:

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What structured assessment and decision processes could

operators use to perform this step?

What percentage of the natural gas industry already has

structured processes in place to perform such assessments?

What percentage of the hazardous liquid industry already

has structured processes in place to perform such assessments?

What should be the criteria for deciding whether

additional actions by the operator are required?

What would be the expected cost of performing such an

assessment?

5. Repairing the Affected Segments as Necessary

In this step, the operator would determine which anomalies require

remediation, and the appropriate means of repair. This step, in

conjunction with the previous step, is intended to ensure that the

likelihood of pipeline failure due to internal or external corrosion,

construction damage, previous excavation damage, or other mechanical

damage is very low.

Key questions that OPS would like to discuss at the meeting

include:

Should current industry standards (e.g., ASME B.31G) be

used as the repair criteria, or do other methodologies exist or need to

be developed for pipelines in high consequence areas?

What is the status of the current rulemaking to allow

alternative repair techniques?

After an operator identifies anomalies requiring repair,

how much time should be allowed in which to complete the repair work?

What would be the expected additional cost to the

operators of more stringent inspection and repair criteria?

6. Implementing and Monitoring Other Cost-Effective Risk Control

Activities

The operator would then be expected to implement the additional

preventive and mitigative actions, and monitor their effectiveness over

time to ensure that they are producing the risk reductions envisioned.

The operator would be expected to implement the activities in a timely

manner, consistent and integrated with internal budget processes that

establish priorities and allocate resources based on risk significance

of the planned activities.

Key questions that OPS would like to discuss at the meeting

include:

How can operators monitor the effectiveness of risk

control activities?

How would integrating an implementation schedule into

normal operator maintenance schedules or budget cycles affect the cost

of implementing these activities?

7. Documenting Inspections, Assessments, and Actions

An operator would maintain records establishing compliance with any

new requirements addressing high consequence areas, including records

identifying pipe segments capable of affecting high consequence areas,

the schedule of inspections, the findings of the inspections and

assessments, and the preventive and mitigative actions taken.

A key question that OPS would like to discuss at the meeting:

What would be the expected costs and labor burdens of

these documentation requirements?

8. OPS Reviews Operator Compliance

OPS will examine the operator's records to ensure compliance. OPS

currently envisions an on-site review of the company's program

documentation and records, as well as interviews with key management

personnel responsible for implementing the process. The specific review

activities will be tailored for the company's management system and

assessment processes. Major review activities are expected to include:

Reviewing the policies, procedures, guidelines, and

manuals that describe how the company identifies the pipeline segments

that could impact high consequence areas and assesses the need for

additional protection on these segments.

Reviewing the company's assessment and decision making

processes.

Reviewing in-line inspection data and the criteria to

determine if further evaluation and repair is required.

Reviewing the status of remediation and other preventive

or mitigation actions.

Reviewing performance measures to understand, evaluate,

and demonstrate the effectiveness of the company's decisions.

Meeting with company management to understand the level of

management support and awareness of the program to protect high

consequence areas.

After the review of the operator's internal processes and

documentation, OPS will conduct field validation checks. These

validation checks will confirm that the operator has implemented the

additional preventive and mitigative activities.

The selection of field inspection sites will consider the

operator's assessment and results. Where possible, the OPS team will

perform an integrated review of information from a variety of sources

(e.g., internal inspection results, close interval surveys, leak

history, and other observed conditions) in selecting field validation

check sites.

After the OPS inspection team has completed its review and field

validation checks, the team will prepare a summary report. This summary

report will contain observations on the operator's program and

processes, as well as on the effectiveness of this program in enhancing

protection for high consequence areas. The report will document the

positive features of the company's program and any areas that need

improvement. The report will include any process improvements that OPS

has determined are necessary, and the operator's work plan for

addressing them. If compliance issues are discovered during the review,

OPS will determine the appropriate resolution of these issues through

its normal enforcement processes, and the resolution of those issues

will be included in this report.

Key questions that OPS would like to discuss at the meeting

include:

How can OPS ensure consistency of review across all

companies?

What review protocols or criteria will OPS use to evaluate

the effectiveness of an operator's assessment and decision-making

processes?

What is the appropriate avenue for public input into the

decision-making process to protect high consequence areas?

What qualifications or training should OPS inspectors have

to perform this verification?

Information Requested

Consistent with the President's regulatory policy (E.O. 12866), OPS

wants to carry out the mandate to consider additional inspections, and

other preventive and mitigative measures at the least cost to society.

Toward this end, interested persons are urged to present views on

whether additional inspection requirements or other preventive and

mitigative actions are needed to ensure adequate protection of high

consequence areas. The questions listed above provide more specific

guidance on the information being solicited for each step in the

process. In addition, and applicable to all steps in the envisioned

process, OPS is also interested in comments on the expected cumulative

costs and benefits associated with implementing the described process,

any comment on whether any of these measures would have a

disproportionate impact on small operators, and any concerns on the

information collection, recordkeeping, or reporting requirements of any

of these initiatives under the Paperwork

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Reduction Act of 1995 (44 U.S.C. 3057(d)).

Authority: 49 U.S.C. Chapter 601 and 49 CFR 1.53.

Issued in Washington, DC on October 14, 1999.

Richard B. Felder,

Associate Administrator for Pipeline Safety.

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[FR Doc. 99-27281 Filed 10-20-99; 8:45 am]

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