[Federal Register Volume 68, Number 18 (Tuesday, January 28, 2003)]
[Proposed Rules]
[Pages 4278-4335]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 03-603]



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Part II





Department of Transportation





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Research and Special Programs Administration



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49 CFR Part 192



Pipeline Safety: Pipeline Integrity Management in High Consequence 
Areas (Gas Transmission Pipelines); Proposed Rule

  Federal Register / Vol. 68, No. 18 / Tuesday, January 28, 2003 / 
Proposed Rules  

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DEPARTMENT OF TRANSPORTATION

Research and Special Programs Administration

49 CFR Part 192

[Docket No. RSPA-00-7666; Notice 4]
RIN 2137-AD54


Pipeline Safety: Pipeline Integrity Management in High 
Consequence Areas (Gas Transmission Pipelines)

AGENCY: Office of Pipeline Safety (OPS), Research and Special Programs 
Administration (RSPA), DOT.

ACTION: Notice of proposed rulemaking.

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SUMMARY: This document proposes to establish a rule to require 
operators to develop integrity management programs for gas transmission 
pipelines that, in the event of a failure, could impact high 
consequence areas (HCAs). These integrity management programs would 
focus on requiring operators to comprehensively evaluate their 
pipelines, and take measures to protect pipeline segments located in 
high consequence areas. RSPA/OPS recently finalized the definition of 
high consequence areas by a separate rulemaking. This proposed rule 
proposes to expand the definition of HCAs by adding consideration of 
people living at distances greater than 660 feet from large diameter 
high pressure pipelines. The current HCA definition only requires 
consideration of people living at distances up to 660 feet from 
pipelines.

DATES: Interested persons are invited to submit written comments by 
March 31, 2003. Late-filed comments will be considered to the extent 
practicable.

ADDRESSES:

Filing Information

    You may submit written comments by mail or delivery to the Dockets 
Facility, U.S. Department of Transportation, Room PL-401, 400 Seventh 
Street, SW., Washington, DC 20590-0001. It is open from 10 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 desiring confirmation of mailed comments 
must include a self-addressed stamped postcard.

Electronic Access

    You may also submit written comments to the docket electronically. 
To submit comments electronically, access the following Internet Web 
address: http://dms.dot.gov. Click on ``Help & Information'' for 
instructions on how to file a document electronically.

Privacy Act Information

    Anyone is able to search the electronic form of all comments 
received into any of our dockets by the name of the individual 
submitting the comment (or signing the comment, if submitted on behalf 
of an association, business, labor union, etc.). You may review DOT's 
complete Privacy Act Statement in the Federal Register published on 
April 11, 2000 (Volume 65, Number 70; Pages 19477-78) or you may visit 
http://dms.dot.gov.

General Information

    You may contact the Dockets Facility by phone at (202) 366-9329, 
for copies of this proposed rule or other material in the docket. All 
materials in this docket may be accessed electronically at http://dms.dot.gov/search. Once you access this address, type in the last four 
digits of the docket number shown at the beginning of this notice (in 
this case 7666), and click on search. You will then be connected to all 
relevant information.

FOR FURTHER INFORMATION CONTACT: Mike Israni by phone at (202) 366-
4571, by fax at (202) 366-4566, or by e-mail at 
[email protected], regarding the subject matter of this proposed 
rule. General information about the RSPA/OPS programs may be obtained 
by accessing RSPA's Internet page at http://RSPA.dot.gov.

SUPPLEMENTARY INFORMATION: RSPA/OPS believes it can best assure 
pipeline integrity by requiring each operator to: (a) Implement a 
comprehensive integrity management program; (b) conduct a baseline 
assessment and periodic reassessments focused on identifying and 
characterizing applicable threats; (c) mitigate significant defects 
discovered in this process; and (d) monitor the effectiveness of their 
programs so appropriate modifications can be recognized and 
implemented. This approach also recognizes that improving integrity 
requires operators to gather and evaluate data on the performance 
trends resulting from their programs, and to make improvements and 
corrections based on this evaluation. This proposed rule does not apply 
to gas gathering or to gas distribution lines. This proposed rule will 
satisfy Congressional mandates for RSPA/OPS to prescribe standards that 
establish criteria for identifying each gas pipeline facility located 
in a high-density population area and to prescribe standards requiring 
the periodic inspection of pipelines located in these areas, including 
the circumstances under which an inspection can be conducted using an 
instrumented internal inspection device (smart pig) or an equally 
effective alternative inspection method. The proposed rule also 
incorporates the required elements for gas integrity management 
programs recently mandated in the Pipeline Safety Improvement Act of 
2002, which was signed into law on December 17, 2002.

Background

    RSPA/OPS is in the midst of promulgating a series of rules intended 
to require pipeline operators to develop integrity management programs 
for their entire systems, and to conduct baseline and periodic 
assessments of pipeline segments the failure of which could imperil the 
health and safety of nearby residents and cause significant damage to 
their property. These integrity management programs, written 
differently for the liquid and natural gas pipeline systems, are 
designed with the goal of identifying the best method(s) for 
maintaining the structural soundness (i.e., integrity) of transmission 
pipelines operating across the United States. RSPA/OPS began this 
series of integrity management 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). The hazardous liquid rule 
applies to pipeline segments that can affect high consequence areas 
(HCAs), which under the liquid rule criteria include populated areas 
defined by the Census Bureau as urbanized areas or places, unusually 
sensitive environmental areas, and commercially navigable waterways. 
RSPA/OPS issued a similar rule for hazardous liquid operators with less 
than 500 miles of pipeline (66 FR 2136; January 16, 2001).
    Earlier this year, RSPA/OPS explained in the Federal Register that 
we were beginning the integrity management rulemakings for gas 
transmission lines by first proposing a definition of HCAs (67 FR 1108; 
January 9, 2002). We also described our plan to propose integrity 
management program requirements for gas transmission pipelines 
affecting those areas. In that proposed rule on HCAs ( January 9, 
2002), we also said we had decided first to propose the definition of 
HCAs and then to propose the gas integrity management rule. We chose to 
propose the regulation in two separate steps for a number of reasons. 
For example, operators already have good information

[[Page 4279]]

(through the Class Location Requirements) on where the potential 
consequences of a gas pipeline accident may be most significant. In 
addition, since we were still collecting information and verifying the 
validity of assessment methods other than internal inspection and 
pressure testing, presenting the gas pipeline integrity management 
requirements as a single rule would delay review of the HCA definition. 
RSPA/OPS recently finalized the definition of HCAs (67 FR 50824; August 
6, 2002).
    In the current definition of HCAs (August 6, 2002), we noted four 
significant characteristics of gas pipelines ruptures and explosions 
that are relevant in defining HCAs. These same characteristics are 
useful here in the context of developing integrity management 
regulations. Those characteristics are: (1) The effects of a gas 
pipeline rupture and subsequent explosion are highly localized. The 
physical properties of natural gas dictate that it rises upward from a 
rupture as the gas expands into the air; (2) The zone of damage or heat 
affected zone following a rupture is related to the line's diameter and 
the pressure at which the pipeline is operated; (3) The size of the 
heat affected zone from pipeline ruptures where pipe diameter was less 
than 36 inches and operating pressures were at or below 1000 psig, was 
limited to a diameter of 660 feet; and (4) The heat affected zone for 
pipelines of 36 inches or greater, operating at pressures in excess of 
1000 psig, can extend 1000 feet. Based on these findings, the HCA 
definition included language that would require operators of large 
diameter pipelines operating at high pressures to include areas within 
a 1000 foot radius from the pipeline. This proposed rule, referred to 
as the gas integrity management program (IMP) rule, will expand the 
current definition of HCAs (August 6, 2002), by adding consideration of 
people living at distances greater than 660 feet from large diameter 
high pressure pipelines. This expansion is based on the need to provide 
the same level of added protection to population groups, as the current 
HCAs provide to facilities that house people who are difficult to 
evacuate, people with impaired mobility, people who are confined, and 
areas where people congregate. This population group living at 
distances greater than 660 feet was inadvertently omitted from the 
definition when we proposed and later finalized the HCA definition.
    The HCA definition for gas transmission lines was based on broad 
corridors that could potentially be impacted from a pipeline rupture 
and explosion. However, additional calculations have to be used to 
determine the likely actual area that would be impacted. This proposed 
gas integrity management rule provides a method to analyze how a 
pipeline segment will impact an HCA if the segment fails. The 
definitions of a potential impact circle and potential impact zone that 
we are proposing, that are based on a mathematical equation, will 
essentially determine the likely actual area within an HCA that would 
be impacted. Whereas the HCA definition is based on broad corridors 
(i.e., lateral distances perpendicular to pipeline) but not 
longitudinal distances (i.e., axially along the pipeline), the 
potential impact circle and potential impact zones that we are 
proposing will provide longitudinal distances to define the actual area 
of impact in an HCA, and narrow the area to which the proposed 
assessment and repair requirements will apply.
    This proposed rule also defines a Moderate Risk Area as an area 
located within a Class 3 or Class 4 location, but not within the 
potential impact zone. Whether a building located in a rural area, such 
as a rural church, which is currently included in the High Consequence 
Area definition, should be designated as a Moderate Risk Area requiring 
less frequent assessment or requiring enhanced preventive and 
mitigative measures is an issue for public comment that we discuss 
later in this document.
    The process of identifying pipeline segments that are located in 
high consequence areas and moderate risk areas is described below under 
Covered Segments.

Pipeline Safety Improvement Act of 2002

    On November 15, 2002, Congress passed H.R. 3609, the Pipeline 
Safety Improvement Act of 2002. The President signed the bill on 
December 17, 2002. Section 14 of H.R. 3609 contains requirements for 
integrity management programs for gas pipelines located in high 
consequence areas. The proposed rule which RSPA has been working on for 
some time is substantially in alinement with section 14 of H.R. 3609. 
However, there are differences. We have incorporated the requirements 
of section 14 into this proposed rule. These areas include the 
intervals for conducting baseline and reassessment testing, 
consideration of testing done prior to the final rule, the 
incorporation of issues raised by State and local authorities, the 
conduct of testing in an environmentally appropriate manner, a 
requirement that the operator notify RSPA of changes to its program, 
and a means to make copies of operator records available to State 
interstate agents.

Rule Synopsis

    The elements of an integrity management program are to consist of: 
(i) An identification of covered pipeline segments and the potential 
impact zone for each segment; (ii) a baseline assessment plan; (iii) an 
identification of threats to each covered pipeline segment, including 
risk assessments of each covered segment; (iv) a direct assessment 
plan, if direct assessment is to be used; (v) provisions for 
remediating conditions found; (vi) a process for continual evaluation 
and assessment; (vii) preventive and mitigative measures; (viii) a 
performance plan as outlined in ASME/ANSI B31.8S, Section 9; (ix) 
recordkeeping requirements; (x) a management of change process as 
outlined in ASME/ANSI B31.8S, Section 11; (xi) a quality assurance 
process as outlined in ASME/ANSI B31.8S, Section 12; (xiii) a 
communication plan based on ASME/ANSI B31.8S, Section 10, to include a 
process for addressing safety concerns raised by OPS, including safety 
concerns OPS raises on behalf of a State authority with which OPS has 
an interstate agent agreement and of local authorities; (xiv) a process 
for providing, by electronic or other means, a copy of the operator's 
integrity management program to a State authority with which OPS has an 
interstate agent agreement; and (xv) a process for ensuring that each 
integrity assessment is being conducted in a manner that minimizes 
environmental and safety risks.

Covered Segments

    Operators must identify covered segments prior to performing 
assessments. A covered segment is any transmission pipeline segment. 
The approach involves six steps that rely on the definitions contained 
in section 192.761. Those six steps are: (1) Identify all high 
consequence areas for the pipeline using the HCA definition as expanded 
by this proposed rule; (2) calculate the Potential Impact Radius (PIR) 
for each covered segment in the pipeline; (3) determine the Threshold 
Radius associated with the PIR for each segment; (4) identify Potential 
Impact Circles for the pipeline; (5) identify the Potential Impact 
Zones (PIZ) for the pipeline, and based on that zone for covered 
segments located in Class 3 and Class 4 locations, identify the 
moderate

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risk areas; and (6) determine the priority of each covered pipeline 
segment (i.e., segments subject to the proposed rule that are within a 
potential impact zone are considered higher impact zones; those 
segments outside a PIZ are considered lower impact zones). Additional 
detail on identifying covered segments is provided elsewhere in this 
preamble and in the Definitions located at section 192.761 of the 
proposed rule.

Assessment Methods

    There are four acceptable assessment methods defined by this rule. 
They are: (a) Internal inspection (also know as in-line inspection, ILI 
and pig testing); (b) pressure testing; (c) direct assessment, (a 
process that includes data gathering, indirect examination and/or 
analysis, direct examination, and post assessment evaluation); and (d) 
any other method that can provide an equivalent understanding of the 
condition of line pipe. In addition, the rule proposes a method known 
as confirmatory direct assessment that an operator could use as an 
interim reassessment method.
    The Pipeline Safety Improvement Act of 2002 provides for assessment 
by ``an alternative method that the Secretary determines would provide 
an equal or greater level of safety.'' Because the primary function of 
internal inspection tools or pressure testing is to determine the 
condition the pipe is in, we have determined that equivalent or greater 
safety can be provided by ``other technology that an operator 
demonstrates can provide an equivalent understanding of the condition 
of the line pipe.'' We used this language in the liquid integrity 
management program rules and are proposing to include it under the list 
of allowable assessment methods for the baseline assessment and 
reassessments.
    The rule proposes to allow direct assessment as a supplemental 
assessment method on any covered pipeline segment and as a primary 
assessment method on a covered pipeline where in-line inspection and 
pressure testing are not possible or economically feasible or where the 
pipeline operates at a low stress. None of the permitted assessment 
methods listed above is fully capable of characterizing all potential 
threats to pipeline integrity. Currently, direct assessment is only an 
acceptable inspection method for assessing external corrosion, internal 
corrosion and stress corrosion cracking. In addition, if no other 
assessment method is feasible, direct assessment may be used to 
evaluate third party damage. Operators choosing direct assessment 
technologies must undertake extra excavations and direct examinations 
during the period while direct assessment is being validated.
    Some additional details regarding direct assessment are highlighted 
here for the purpose of acquainting readers of this proposed rule with 
some of the basic principles associated with the use of direct 
assessment. First, for purposes of this rulemaking, above-ground 
inspection techniques (such as close interval surveys, direct current 
voltage gradient, and pipeline current mapper) are considered indirect 
examinations. Second, visual inspection, ultrasonic testing and x-ray 
examinations are considered direct examinations. Third, all three 
threats considered under direct assessment (external corrosion, 
internal corrosion, and stress corrosion cracking) are direct 
examination of pipe. Fourth, operators who assert that their pipelines 
cannot be internally inspected or pressure tested are required to 
include written justification in their plans explaining why their 
pipeline(s) cannot be tested using these methods. Fifth, operators who 
assert that internal inspection or pressure testing is not economically 
feasible will likewise be required to include written justification in 
their plans indicating why these methods are not economically feasible.
    Another concept in the proposed rule is the use of Confirmatory 
Direct Assessment to evaluate a segment for the presence of corrosion 
and third party damage. This is a more streamlined assessment method 
that uses the steps involved in direct assessment to identify these 
significant threats to a pipeline's integrity. As discussed later in 
this document, RSPA/OPS is proposing that an operator use this method 
as an initial reassessment method within the required seven-year 
reassessment interval, if the operator has, within the proposed limits, 
established a longer reassessment interval for a particular segment. 
The follow up reassessment by pressure test, internal inspection or 
direct assessment would then be conducted at the established interval.
    Additional information about direct assessment and confirmatory 
direct assessment is provided elsewhere in this preamble and at section 
192.763(h) of the proposed rule.

Baseline Assessment Periods

    Under this proposal, operators are required to complete a one-time 
baseline assessment on each covered segment. After a baseline 
assessment is completed on a segment, an operator will be required to 
reassess the covered pipeline segment at the specified interval. 
Operators using pressure testing or internal inspection as an 
assessment method are required to complete the baseline assessment of a 
segment located in an HCA within 10 years of December 17, 2002 (the 
date the Pipeline Safety Improvement Act was signed into law). 50% of 
the covered segments would have to be assessed within five years. 
Operators using pressure testing or internal inspection as an 
assessment method are permitted 13 years to assess pipeline segments 
located in Class 3 and 4 locations where the area being assessed is not 
within the potential impact zone i.e., the areas we are proposing to 
define as moderate risk areas. (Additional detail on potential impact 
zones is provided in the Definitions section (Sec.  192.761) of this 
proposed rule and in the guidance that follows the proposed rule text.) 
If direct assessment is used as an assessment method, the proposal is 
for the operator to complete the baseline assessment within seven years 
for segments located in HCAs, with 50% of the segments having to be 
assessed within four years. Ten years would be allowed for a pipeline 
segment located in a Class 3 or 4 location where the segment being 
assessed is not within the potential impact zone i.e, is within a 
moderate risk area. Additional detail on baseline assessments is 
provided elsewhere in this preamble and at section 192.763(g) of the 
proposed rule. The timing of baseline assessments is covered in more 
detail at section 192.763(g)(4).
    The Pipeline Safety Improvement Act of 2002 provides that a 
baseline assessment is to be completed ``not later than 10 years after 
the date of enactment * * *'' The Act further provides that at least 
50% of covered facilities are to be assessed ``not later than 5 years 
after such date * * *'' Our proposal for baseline assessment using 
internal inspection, pressure test or equivalent technology is 
consistent with that requirement. We propose a shorter time frame for 
baseline assessment by direct assessment. The primary reason for 
proposing a shorter time frame is that direct assessment technologies 
are still under development and additional information needs to be 
gathered on their effectiveness. However, RSPA/OPS has been sponsoring 
research on direct assessment that should help expedite its validity as 
a method for assessment. Based on the results from this research OPS 
may be able to lengthen the time frame from five years to up to ten 
years.

Reassessment Intervals

    The Pipeline Safety Improvement Act requires a minimum seven-year 
reassessment period. Thus, under the proposed rule we set a 
reassessment

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interval of seven years for operators using pressure test, internal 
inspection or equivalent technology, and a five year interval for an 
operator using direct assessment that directly examines and remediates 
defects by sampling. However, an operator using pressure test, internal 
inspection or equivalent technology could establish a longer interval, 
within established limits if the operator by the seventh year conducts 
a reassessment using confirmatory direct assessment and then conducts 
the follow up reassessment by the chosen method in the year the 
operator has set for the interval. The interval for reassessment begins 
to run on a segment after the operator has completed the previous 
assessment for that segment.
    Under the proposed rule, an operator establishes the reassessment 
interval for covered segments based on the type of assessment method 
the operator plans on using. The type of method used establishes the 
maximum interval. For operators using pressure testing, internal 
inspection, or alternative technology as an assessment method, the 
operator is to base the intervals on the identified threats for the 
segment or on the stress level of the pipeline and then refer to ASME/
ANSI B31.8S, Section 8 to establish the interval. Under either option, 
the proposed maximum interval is ten years and 15 years for a pipeline 
operating at below 50% SMYS. However, because a reassessment must be 
conducted by the seventh year, under the proposal, if an operator 
establishes an interval of ten years for a segment, the operator would 
have to complete a confirmatory direct assessment by the seventh year, 
and then in the tenth year do a follow up reassessment using pressure 
test, internal inspection tool, direct assessment or alternative 
equivalent technology.
    OPS has predicated the proposed 15-year maximum reassessment 
interval for pipelines operating below 50% SMYS on several factors.
    [sbull] Greater safety margin the current regulations provide. 
Current pipeline safety requirements provide a greater safety margin 
against corrosion for gas pipelines located in populated areas. For 
example, the regulations require pipelines that are located in Class 3 
and 4 locations (high population areas) to be of greater wall thickness 
than pipelines located in Classes 1 and 2 locations. And operators must 
replace the existing pipe with thicker, stronger pipe when population 
density increases (i.e., the class location changes). Thus, pipelines 
located in populated areas are less susceptible to corrosion-induced 
rupture, because it takes much longer for corrosion to penetrate the 
pipe to a depth where the corrosion causes any concern.
    [sbull] The actual reassessment interval is based on risk factors. 
The reassessment interval will depend on numerous risk factors, such as 
the baseline assessment results, the remediation of defects found 
during the baseline and the integration of data concerning other risk 
factors. Thus, higher risk pipe will be reassessed sooner.
    [sbull] Gas supply interruptions. Gas transmission pipelines 
typically feed directly into customer distribution lines without an 
intermediate storage location. A pipeline's operating pressure is 
generally lower (i.e., pipeline is at a lower stress level) when it is 
at the transition phase into a distribution line. This close coupling 
between the transmission and distribution systems increases the 
likelihood of a supply interruption if a single line is shutdown for 
assessment or repair. The 15-year maximum is intended to minimize these 
supply interruptions.
    [sbull] Industry consensus standards. ASME B31.8S specifies a 
reassessment interval of 15 years for pipelines operating below 50% 
SMYS, and 20 years for pipelines operating between 20% and 30% SMYS. 
These reassessment intervals are based on a mathematical model Kiefner 
and Associates developed.
    These factors led us to conclude that the proposed 15-year maximum 
reassessment interval for pipelines operating below 50% was reasonable 
for operators yet would ensure safety. Again, as discussed previously, 
an operator would have to complete a confirmatory direct assessment by 
the seventh year.
    RSPA/OPS is inviting public comment on whether we should allow a 
maximum 20-year reassessment interval (with a confirmatory direct 
assessment in the seventh and 14th years) on pipelines operating at 
less than 30% SMYS, and reassessment by the confirmatory direct 
assessment method only every seven years for pipelines operating below 
20% SMYS. The proposed confirmatory direct assessment method could be 
further streamlined for pipelines operating below 20% SMYS. OPS is 
considering a maximum interval of 20 years for pipelines operating 
between 20% to 30% SMYS (with a confirmatory direct assessment by the 
7th and 14th years) because numerous studies and analyses have 
demonstrated that these low stress pipelines tend to leak, rather than 
to rupture. Current gas pipeline safety regulations recognize the 
reduced risk that low stress levels pose, and structure the 
requirements accordingly. Examples of different requirements for 
pipelines operating at lower stress are in Sec.  192.65 (Transportation 
of pipe), Sec.  192.227 (Qualification of welders), Sec.  192.241 
(Inspection and test of welds), Sec.  192.309 (Repair of steel pipe), 
Sec.  192.315 (Wrinkle bend in steel pipe), Sec.  192.319 (installation 
of pipe in a ditch, Sec.  192.505 (Strength requirements for steel 
pipeline to operate at a hoop stress of 30% or more of SMYS), Sec.  
192.711 (General requirements for repair procedures), and Sec.  192.717 
(Permanent field repair of leaks).
    The maximum reassessment interval for operators using direct 
assessment as an assessment method is five years under this proposal, 
provided an operator directly examines and remediates defects by 
sampling. The reassessment interval under direct assessment would be 
expanded to ten years if an operator conducts a direct examination of 
all indications and remediates the anomalies. If an operator 
establishes an interval of more than seven years on a segment, the 
operator would have to conduct a confirmatory direct assessment by the 
seventh year. Additional detail on reassessment intervals is provided 
elsewhere in this preamble and at section 192.763(k) of the proposed 
rule.
    RSPA/OPS is inviting public comment on whether we should allow an 
operator using direct assessment a maximum ten-year reassessment 
interval on a pipeline operating at less than 30% SMYS regardless of 
whether the operator excavates and remediates all anomalies on that 
line, or at least remediates the highest-risk anomalies. Again, the 
operator would have to conduct a confirmatory direct assessment by the 
seventh year of the interval.
    The number of excavations (Dig Criteria) proposed for the direct 
assessment method follow those being developed by the National 
Association of Corrosion Engineers (NACE) Recommended Practices on 
Direct Assessment, with the following deviations:
    (1) In each External Corrosion Direct Assessment (ECDA) region 
where all indications categorized as ``immediate'' are present, we 
propose that the operator reduce operating pressure by at least 20% 
until such indications have been excavated and mitigated.
    (2) In each ECDA region where indications categorized as 
``scheduled''are present, we propose the operator continue the 
excavations until at least two indications are excavated having 
corrosion of depth no greater than 20% of wall thickness.

[[Page 4282]]

    (3) In each ECDA region, we propose to require one excavation; 
however, the excavation must be made at a location the operator 
considers most suspect, not at any random place.
    RSPA/OPS is inviting public comment on whether the benefits of 
these proposed requirements that are more extensive than the NACE 
Recommended Practices currently being developed are worth the cost.

External Corrosion Direct Assessment and Internal Corrosion Direct 
Assessment

    Work jointly funded by the gas pipeline industry and RSPA/OPS is 
ongoing to develop, validate and standardize the application of the 
direct assessment process to external corrosion (ECDA) and internal 
corrosion (ICDA). Future work is planned to develop, validate and 
standardize a direct assessment process for application to the stress 
corrosion cracking (SCCDA) threat. Furthermore, significant anecdotal 
evidence exists that the ECDA process may be capable of identifying 
coating damage associated with third party impacts on pipelines, but 
formal validation of this capability has not occurred.
    ICDA is an assessment process that first identifies areas along the 
pipeline where water or other electrolytes introduced by an upset 
condition may reside, then focuses direct examination on the locations 
in each area where internal corrosion is most likely to exist. If no 
evidence of internal corrosion exists in these most likely locations, 
then the entire section can be considered to be free of internal 
corrosion. An operator using direct assessment as a method to address 
internal corrosion in a pipeline segment must follow the requirements 
in ASME/ANSI B31.8S, Appendix SP-B2, and in this section. Additional 
detail on ICDA is provided elsewhere in this preamble and at section 
192.763(h)(3) of the proposed rule.
    ECDA is an assessment process that combines assembly and analysis 
of risk factor data, indirect examination using above ground detection 
instruments, direct examination of suspected areas on the pipeline and 
post-assessment evaluation. The current approach being incorporated in 
the consensus standard under development for ECDA is to locate areas 
suspected of having external corrosion by identifying defects in the 
pipe coating, then excavating those defects in areas where corrosion 
activity is suspected. While all indications discovered by ECDA that 
are not adequately protected by the cathodic protection system at the 
time of the assessment will be excavated and directly examined, only a 
fraction of the ECDA indications that are protected by cathodic 
protection systems at the time of the assessment will be excavated. 
Additional detail is provided elsewhere in this preamble and at section 
192.763(h)(4) of the proposed rule.

The Role of Consensus Standards

    The underpinning analysis for this rulemaking was a consensus 
standard development effort. Completing this effort required nearly two 
years. This effort required assembling the best integrity assurance 
practices currently used by gas pipeline operators, and incorporating 
these practices into consensus standards. In addition the direct 
assessment process, which was conceived as a way to assess the 
integrity of gas pipelines for which in-line-inspection and pressure 
testing are not possible or economically feasible, needed to be 
developed, documented, and standardized. Some consensus standards on 
gas pipeline integrity management that we are considering incorporating 
by reference have been published. Others are still under development.
    A major effort has been underway for several years to develop 
consensus standards supporting integrity management practices for gas 
pipelines. These standards are a necessary component in assuring the 
quality of implementation of any new assessment requirement. ASME/ANSI 
B31.8, Supplement, issued early this year, structures industry 
knowledge and best practices into requirements for an integrity 
management program and a set of prescriptive requirements for assessing 
pipeline integrity. In addition this standard describes the 
requirements an operator must follow to implement a performance-based 
program. The ASME/ANSI standard represents a significant advance in the 
documentation of demonstrated integrity management practices.
    Although many of the tools employed in the direct assessment 
process have been in use for sometime, the use of these tools in the 
integrity assessment process is new. The National Association of 
Corrosion Engineers (NACE) undertook development of a Recommended 
Practices to support direct assessment and to expand the standardized 
application of In-Line Inspection (ILI).
    RSPA/OPS is relying heavily on the technical content of these 
standards. RSPA/OPS has been directly involved in the development of 
these standards, both to ensure that the standards reflect the 
knowledge and perspective of RSPA/OPS, and to provide the basis for 
expanding requirements as needed within the Integrity Management 
Program (IMP) Rule. RSPA/OPS involvement included participation in the 
teams that developed the ASME/ANSI B31.8S standard, and ongoing 
participation in the development of the NACE Recommended Practice on 
Direct Assessment. In addition, RSPA/OPS supported participation by 
pipeline safety representatives from several States in the standards 
development and review process.
    This proposed rulemaking is the culmination of experience gained 
from inspections, accident investigations and risk management and 
system integrity initiatives. This experience is the foundation for 
proposing a rulemaking that addresses, in a comprehensive manner, the 
National Transportation Safety Board's (NTSB) recommendations, 
Congressional mandates, including the mandates in the Pipeline Safety 
Improvement Act of 2002, and pipeline safety and environmental issues 
raised over the years. These issues and considerations include:
    [sbull] Several NTSB recommendations concerning pipeline safety, 
including those which:
    (1) Require periodic testing and inspection to identify corrosion 
and other time-dependent damage.
    (2) Require the establishment of criteria to determine appropriate 
intervals for inspections and tests, including safe service intervals 
between pressure testing.
    (3) Determine hazards to public safety from electric resistance 
welded (ERW) pipe and take appropriate regulatory action.
    (4) Expedite requirements for installing automatic or remote-
operated mainline valves on high-pressure lines to provide for rapid 
shutdown of failed pipeline segments.
    [sbull] Our analyses of several pipeline ruptures in Bellingham, 
Washington; Simpsonville, South Carolina; Reston, Virginia; and Edison, 
New Jersey, brought to light the need for operators to address the 
potential interrelationship among factors affecting failure causes and 
to implement coordinated risk control actions to supplement the 
protection provided by compliance with current regulations.
    [sbull] Our analysis of the rupture in Carlsbad, New Mexico, 
highlighting the need for methods to assess internal corrosion in 
pipelines that are not piggable.
    [sbull] Several Congressional mandates identify areas where the 
risk of a

[[Page 4283]]

pipeline failure could have significant impact. These specify that 
RSPA/OPS:

    (1) Prescribe standards establishing criteria for identifying 
gas pipeline facilities located in high-density population areas (49 
U.S.C. 60109(a)(2)).
    (2) Prescribe, if necessary, additional standards requiring the 
periodic inspection of pipelines in high-density population areas, 
to include any circumstances when an instrumented internal 
inspection device, or similarly effective inspection method, should 
be used to inspect the pipeline (49 U.S.C. 60102(f)(2)).
    (3) Survey and assess the effectiveness of Remote Control Valves 
(RCVs) to shut off the flow of natural gas in the event of a rupture 
of an interstate natural gas pipeline facility and make 
determination about whether the use of these valves is technically 
and economically feasible and would reduce risks associated with a 
rupture of an interstate natural gas pipeline facility. If the use 
of these valves determined to be technically and economically 
feasible and would reduce risks associated with a rupture of an 
interstate natural gas pipeline facility, then prescribe standards 
on the circumstances where an operator of a gas transmission 
pipeline facility must use an RCV (49 U.S.C. 60102(j)).

Risk Management and Systems Integrity Inspection Initiatives

    This proposed rulemaking is also based on what we learned about 
integrity management programs from our risk management and pipeline 
inspection activities, particularly the Risk Management Demonstration 
Program, the Systems Integrity Inspection (SII) Pilot Program and the 
new high impact approach to inspections. These precursor activities 
began in 1997.
    In the Risk Management Demonstration and Systems Integrity 
Inspection Pilot Programs, we studied and evaluated comprehensive and 
integrated approaches to safety and environmental protection. These 
approaches incorporated operator- and pipeline-specific information and 
data to identify, assess, and address pipeline risks, in conjunction 
with compliance with existing pipeline safety regulations. From these 
programs, we also expanded our knowledge of the extent and variety of 
internal inspection and other diagnostic tools that hazardous liquid 
pipeline operators use in their integrity management programs. We also 
learned of the wide variability in the extent and effectiveness of 
programs in use by operators to support management of pipeline 
integrity.
    Additionally, based on risk management principles, RSPA/OPS 
implemented a systems approach through a new high impact inspection 
format that evaluates pipeline systems as a whole, rather than in small 
segments. The focus of the high impact inspection is on understanding 
how operators are addressing the issues that have been recognized as 
important through past inspections and incident history. High impact 
inspections are carried out periodically for each operator and the 
results are documented using heavier reliance on narrative description 
rather than on acceptability check marks. We found that a system-wide 
approach rooted in evaluation of operator response to incidents and 
recognized performance issues is a more effective and, in most cases, 
more efficient means of evaluating pipeline integrity. As part of this 
approach, we evaluate how pipeline operators integrate information 
about their pipelines to identify sources of risk and to determine the 
best means of addressing risk. This experience is helping us develop 
detailed inspection guidelines to evaluate compliance with the 
requirements of this rule.
    RSPA/OPS continues to meet 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 (IMP) rulemaking pertaining to gas 
operators. Since January 2000, RSPA/OPS has attended several meetings 
with 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, several gas pipeline operators and 
several representatives of State pipeline safety agencies. (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, RSPA/OPS held a public meeting in 
Arlington, VA, on integrity management in high consequence areas for 
natural 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 RSPA/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.

Gas Advisory Committee Consideration

    The Technical Pipeline Safety Standards Committee (TPSSC) is the 
Federal advisory committee charged with responsibility for advising on 
the technical feasibility, reasonableness, cost-effectiveness, and 
practicability of gas pipeline safety standards. The 15 member 
committee is comprised of individuals from industry, government, and 
the general public.
    On February 7, 2001, RSPA/OPS briefed TPSSC members on gas 
integrity management program development. After canceling the September 
13, 2001 meeting with TPSSC members, we sent all presentation materials 
and progress reports to committee members by mail for their comments or 
concerns. In May, 2002, we sent a document highlighting major issues in 
the gas integrity management rule to the TPSSC members. On July 18, 
2002 the TPSSC met to review the Gas Transmission Pipeline HCA Rule and 
the cost-benefit analysis for the Gas Pipeline Integrity Management 
Program Rule. The committee voted unanimously to accept the cost 
benefit analysis as the basis for proceeding with the integrity 
management rule provided RSPA/OPS gives consideration to several 
issues. These issues and the related RSPA/OPS positions are summarized 
below.
    The committee noted that the pipeline covered by the IMP Rule would 
include class 3 and 4 locations. RSPA's initial estimates of the total 
mileage in Class 3 and 4 locations turned out to be low because it was 
based on earlier data. Natural gas transmission pipeline operators were 
required to include in their 2001 annual reports the breakdown of their 
onshore pipeline mileage by class location, but this information was 
not available at the time the preliminary draft analysis discussed with 
the TPSSC was prepared.
    RSPA/OPS has modified the cost benefit analysis to use the 
industry-reported mileage in classes 3 and 4. Because the industry 
regularly determines the classification of its lines, industry is in a 
better position than RSPA/OPS to estimate the amount of this mileage. 
RSPA/OPS is aware that there may be some discrepancy both between RSPA/
OPS and operators and among operators as to how to calculate Class 3 
locations. The variation in the manner in which class 3 locations are 
calculated involves the concept of clustering of buildings intended for

[[Page 4284]]

human occupancy in identifying pipe segments subject to the 
requirements associated with class 3 locations. The presence of 
individual isolated buildings within a sliding mile segment will count 
to raise the classification of the segment to Class 3. The question is 
whether the immediate area around the isolated building should be 
routinely classified as a Class 3 cluster. RSPA/OPS does not believe 
that these isolated buildings are commonly included as Class 3 clusters 
and does not intend this proposed rule to result in a change of 
existing practice in this regard.
    The committee questioned whether RSPA/OPS intends to use the HCA 
definition as the starting point for identifying segments requiring 
additional integrity assurance measures, and to allow use of the 
potential impact zone to reduce the length of pipe subject to the IMP 
Rule. Committee members expressed concern both as to the appearance of 
leaving out some portions of HCAs and at the costs of including 
protections for areas which do not pose the same risks to population as 
other HCAs. With respect to the first point, the proposed rule includes 
all pipe segments within HCAs in the requirements for integrity 
management. However, if the segment is within a class 3 or class 4 
location, but not within the potential impact zone, that is, the 
segment is in a moderate risk area, the proposed time for completing 
the baseline assessment will be extended to 13 years. RSPA/OPS expects 
that during the next seven to ten years, many companies will choose to 
make many segments in Class 3 locations piggable in their entirety and 
new technology will be available to minimize the cost associated with 
assessing these segments. However, an option RSPA/OPS is considering is 
to not require any assessment of segments located within a Moderate 
Risk Area, but, rather, to require enhanced preventive and mitigative 
measures on these segments. Our premise is that if houses are mostly 
clustered in one area of a Class 3 rectangle, a pipeline failure in an 
area beyond the cluster (i.e., in the moderate risk area) may have 
little, if any, impact on the area with the cluster of homes. RSPA/OPS 
desires information on this option, and underlying assumptions, along 
with any cost information related to the proposed rule.
    Committee members representing distribution companies expressed 
concern that they currently treat all their lines as Class 3 or 4 to 
avoid costly excavation and replacement of pipes when population 
densities increase. They are concerned that this decision will require 
them to perform segment identification for their lines. This would be 
an unnecessary cost if the distribution company intends to assess all 
transmission lines they operate. RSPA/OPS intends that operators 
choosing to classify their entire system as Class 3 or 4 without regard 
to population density will be allowed to do so without having to do 
segment identification according the provisions of the rule. However, 
these operators will not be relieved of requirements to evaluate the 
risk-based priority of segments in developing assessment schedules.
    The committee expressed some concern that the approach being taken 
in the rule will lead to doubling protections on pipeline segments near 
population groups, since existing regulations already require lowering 
pipe stress levels in Class 3 and 4 locations. RSPA/OPS acknowledges 
this point, but notes that a significant consideration in our decision 
to allow a longer reassessment interval than that for liquid pipelines 
is that the thicker/stronger pipe in areas subject to the integrity 
management rule lengthens the time for time-dependent deterioration 
mechanisms to cause significant pipe deterioration.

Notice on Integrity Management Concepts and Hypotheses (Gas 
Transmission Pipelines)

    On June 27, 2001, RSPA/OPS issued a notice of request for comments 
(66 FR 34318) that stated the objective in developing a rule on gas 
pipeline integrity management and described the scope and the elements 
of an eventual gas integrity management rule. We described seven 
elements that should be included in any integrity rule to fulfill our 
objectives. We used similar elements to those employed in structuring 
the liquid integrity management rules. Those seven elements were then 
elaborated upon through a set of hypotheses that we discussed in detail 
in the notice. The notice invited comment about these elements and 
hypotheses.
    In addition, the notice summarized the areas where RSPA/OPS was 
seeking further information to support development of the proposed 
integrity management program rule for gas operators. The information 
needs were organized under the seven elements that we saw as essential 
to any integrity management program rule, and under two other 
categories where additional information was needed to evaluate the 
effect of an integrity management rulemaking on costs and gas supply, 
both seasonally and regionally.

Electronic Discussion Forum

    RSPA/OPS also used an electronic discussion forum from June 27 
through August 13, 2001, titled ``More Information Needed on Gas 
Integrity Management Program'' to help promote discussion of these 
issues. The electronic forum listed all the areas where we had asked 
for comment so that commenters could easily focus on those areas of 
interest to them. A transcript of the electronic discussion forum is 
included in the docket.

Comments to Notice on Integrity Management Concepts and Hypotheses (Gas 
Transmission Pipelines)

    Comments to the docket were provided by one state, five industry 
associations (including one association of industrial gas consumers), 
sixteen companies or groups of companies that operate gas pipelines, 
one company that operates hazardous liquid pipelines, and one company 
that builds pipeline bridges.
    Comments on all elements envisioned for the gas pipeline integrity 
management concept, except the element defining high consequence areas, 
are summarized below. Comments on the HCA element are discussed in a 
separate proposed rule published in the Federal Register on January 9, 
2002 (67 FR 1108). RSPA/OPS recently finalized the definition of HCAs 
(67 FR 50824; August 6, 2002).

Scope

    In the notice we indicated that we are considering applying the gas 
integrity management concept to all gas transmission lines and support 
equipment, including lines transporting petroleum gas, hydrogen, and 
other gas products covered under part 192.
    The American Gas Association (AGA) and American Public Gas 
Association (APGA) commented that the integrity rule should apply to 
gas transmission pipelines operating at or above a hoop stress level of 
20% SMYS. These commenters said the rule should also not include 
pipelines in commercially navigable waterways or environmentally 
sensitive areas because Congress did not direct this coverage. They 
also said RSPA/OPS should give special consideration to pipelines 
operating at a hoop stress between 20% and 30% SMYS. Because these 
lines fail by leak rather than by rupture, different assurance methods 
should be considered.
    This proposed rule covers gas transmission pipelines, including 
pipelines transporting petroleum gas, hydrogen, and other gas products

[[Page 4285]]

covered under Part 192 in the high consequence areas. The definition 
for a transmission line is found in section Sec.  192.3. This proposed 
rule does not apply to gas gathering lines or to gas distribution 
lines.

Performance-Based Option

    Numerous companies argued that we should allow a performance-based 
option because a purely prescriptive rule would not allow companies to 
effectively and cost beneficially address the unique features of their 
systems.
    We are proposing a minimum set of criteria for an operator to 
qualify for a performance-based option. Operators who satisfy this 
minimum set of criteria will be eligible to deviate from certain 
requirements--the time frame for remediating anomalies identified 
during the assessment, the conditions for using direct assessment as a 
primary assessment method and the reassessment interval (for example, 
the reassessment interval for on a segment assessed by the DA method 
could be extended to ten years). However, even if an extended interval 
were allowed, the operator would still have to conduct a confirmatory 
direct assessment in the seventh year of the interval. We are 
incorporating these performance-based considerations because RSPA/OPS 
recognizes that improving pipeline integrity can only be accomplished 
through operators improving their understanding of the condition of 
their piping and taking appropriate action based on this understanding. 
Operators who excel in these aspects of integrity management should 
have limited flexibility in making key integrity management decisions.
    The proposed conditions an operator would have to satisfy before 
being allowed to deviate from some of the program's requirements 
include--
    1. The operator must have completed a baseline assessment of all 
covered segments and at least one other assessment. Problems identified 
in the second assessment must be remediated. Also the results and 
insights from the second assessment must be incorporated into the 
operator's risk model.
    2. An operator must also demonstrate that it has an exceptional 
integrity management program. To demonstrate this an operator must show 
that its program meets the performance-based requirements of ASME/ANSI 
B31.8S, has a history of measurable performance improvement, and 
includes, at minimum:
    (1) A documented state-of-the-art risk analysis process;
    (2) Complete documentation of all risk factor data used to support 
the program;
    (3) A state-of-the-art data integration process;
    (4) A process that explicitly develops lessons learned from 
assessment of covered pipe segments and applies these lessons to pipe 
segments not covered by the Rule;
    (5) A process for evaluating all incidents, including their causes, 
within the operator's sector of the pipeline industry for implications 
both to the integrity of the operator's pipelines and to its integrity 
management program;
    (6) A documented performance history that confirms the continuing 
performance improvement realized under the performance-based program; 
and
    (7) The extensive set of performance measures documented in the 
operator's performance plan (ASME B31.8S, Section 9) are accessible to 
state and federal regulators. These measures would be updated by the 
operator on a frequency consistent with its performance plan.

Define the Areas of Potentially High Consequence

    In the FR notice of June 27, 2001, we said the first element of the 
integrity management concept involves defining the areas where the 
potential consequences of a gas pipeline accident may be significant or 
may do considerable harm to people and their property. In a rule issued 
on August 6, 2002, we defined these high consequence areas. (67 FR 
50824). The definition of high consequence areas (HCAs) includes: (a) 
Current Class 3 and 4 Locations; (b) pipe segments in the area that 
would be impacted by a potential pipeline rupture where there is a 
facility housing people who are confined, have impaired mobility or are 
difficult to evacuate (e.g., hospital, church, school, prison, day care 
facility, retirement facility; and (c) pipe segments near areas where a 
specified number of people congregate on a specified number of days per 
year (e.g., camping grounds, outdoor recreational facility). The 
defined areas were those that would be impacted by a potential pipeline 
rupture, 300, 660 or 1000 feet from the pipeline depending on the 
diameter and operating pressure of the pipeline.

RSPA/OPS Decision on Using Potential Impact Radius in the HCAs

    This proposed rule presents requirements to improve the integrity 
of pipelines located in areas of potentially high consequences. As 
discussed earlier, this proposed rule expands the current HCA 
definition, by presenting requirements to improve the integrity of 
pipelines located near people living at distances greater than 660 feet 
from large high pressure pipelines. This proposed expansion is based on 
the need to provide the same level of added protection to population 
groups, as the HCA definition provides to facilities that house people 
who are confined, difficult to evacuate, or of impaired mobility, and 
to areas where people congregate. The number of buildings intended for 
human occupancy within the potential impact circle is discussed under 
the proposed rule section of this preamble. The basis for identifying 
the physical area where concentrations of people are located so 
additional protective measures can be applied is discussed below.

The Size of the Zone That Could Be Impacted by a Gas Pipeline Rupture 
and Explosion

    Since existing regulations provide a basic level of protection, the 
primary focus of the integrity management rulemaking is on reducing the 
likelihood of a gas release in areas where the potential consequences 
are greatest. The HCA definition includes areas where a pipeline lies 
within 660 feet of a building housing people who would be difficult to 
evacuate (e.g., hospital, school, retirement facility) or where 20 or 
more people congregate at least 50 days in any 12-month period. The 
area is expanded to 1000 feet if the pipeline is greater than 30 inches 
in diameter and operates at pressures greater than 1000 psig. In 
addition, in this proposed rule we are expanding the HCA definition by 
proposing to include a new component of high concentration of buildings 
(as discussed above) intended for human occupancy beyond 660 feet. The 
1000-foot limit was based on a mathematical model (developed by C-FER 
under INGAA funding) that describes a heat affected zone following a 
pipeline rupture. This heat affected zone is bounded by a ``potential 
impact radius.'' This model includes numerous assumptions on the size 
and orientation of the pipe rupture, the physical behavior of the jet 
issuing from a ruptured pipeline (the pipeline is assumed to fail by a 
double-ended rupture), the time of ignition of the gas jet, the rate of 
decay in the flow of gas issuing from the pipeline, the dominant heat 
transfer mode, and the criterion for determining the radius within 
which physical damage results from the heat from a burning gas jet. 
Given the complexity of this analysis and the scope of assumptions 
needed, the only

[[Page 4286]]

way to validate the adequacy of the resulting mathematical relationship 
was to compare its predictions of potential impact radius with actual 
observed burn zone following historic gas pipeline ruptures. This 
comparison was carried out using the C-FER model which successfully 
predicted the radius of the burn zone surrounding ruptured gas 
pipelines.

Incorporating Mathematical Formulation Describing the Heat Affected 
Zone Into the Rule

    We are proposing to require operators to calculate the potential 
impact radius within the HCA. This potential impact radius would be 
used to identify the areas within HCAs where the consequences of a 
rupture would be greatest. An operator would first focus any additional 
integrity measures on concentrations of people or hard to evacuate 
buildings or areas where people congregate within the impact radius, 
then on the rest of the HCA. Using more realistic criteria to define 
areas where an operator would focus additional integrity assurance 
measures will allow an operator to better allocate its resources toward 
areas that need the greatest protection. This approach will 
particularly benefit operators of small-diameter, low pressure 
pipelines, where the range of impact following a potential rupture 
would be small. This approach would also benefit the public because 
operators of very large diameter, very high pressure pipelines would 
have an increased impact radius to consider for evaluating where 
additional integrity assurance measures are required.

Identify and Evaluate the Threats to Pipeline Integrity in Each Area of 
Potentially High Consequences

    The second element of integrity management discussed in the FR 
notice of June 27, 2001, involves identification of potential threats 
to the pipeline. In the notice we mentioned one approach suggested by 
industry in our past discussions was to divide 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 time-independent 
(including third party damage and outside force damage; this threat 
category was called ``random'' in the FR notice). These three 
categories are adopted here primarily to focus resource allocation 
decisions on useful strategies to improve integrity (e.g., integrity 
management for the ``time-independent'' category clearly must 
incorporate significant preventive measures), but do not eliminate the 
need for operators to consider all major threats to pipeline integrity. 
In addition, we said that human error can influence any or all of these 
threats and therefore must be considered as a potential contributing 
factor to each threat.
    For the gas pipeline IMP proposed rule, we decided to propose that 
the operator make a threat-by-threat analysis of the entire pipeline. 
Such an analysis will require identification and evaluation of the 
significance of threats to pipeline integrity, which must necessarily 
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).
    The RSPA/OPS data on causes of gas transmission pipeline accidents 
(i.e., threats to the pipeline) show that between 1990 and1999, there 
were total 777 reported accidents. The causes of these accidents are 
broken down as follows:

--319 (41%) were due to outside force damage (30% third party, 11% 
earth quakes/floods, and other outside forces);
--173 (22%) were due to corrosion (105 (14%) internal, 67 (9%) 
external);
--119 (15%) were due to construction and material defects; and
--166 (21%) were due to other causes.

    The data indicates that the two greatest threats to a pipeline are 
from outside force damage (41%), and corrosion (22%). Our data also 
shows there are more failures from internal corrosion than from 
external corrosion. The internal corrosion is caused by moisture and 
acidity present in the gas transmission lines at low or near low 
points. The rupture of the gas transmission pipeline in Carlsbad, New 
Mexico resulted from internal corrosion. Because corrosion can occur 
either internally or externally, it essential that gas pipeline 
operators consider both threats.
    We believe this threat-by-threat analysis is necessary not only 
because it will require the operator to assemble and use a 
comprehensive set of risk factor data to identify the presence of 
potential threats, but also because it will support determination of 
the assessment approach or approaches needed to characterize the 
significance of these threats.
    Our concept of integrity management also includes the following 
hypotheses: (1) Pipeline segments having threats that represent higher 
risks should generally be assessed sooner than those with threats that 
represent lower risk and (2) 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. We have discussed this issue 
elsewhere in this document and have requested comment.

Comments on RSPA/OPS Hypotheses

    INGAA provided many comments on this hypothesis. The primary source 
of information referenced by INGAA was the technical reports prepared 
by their contractors during the eighteen month interaction among INGAA, 
RSPA/OPS and the states on technical issues, and the consensus 
standards currently in preparation. These reports are available in the 
Docket. Comments from INGAA included the following:
    INGAA offered the opinion that laws should be enacted to support 
strong One-Call Programs. It also pointed out that seam cracking in 
pre-1970 ERW piping has been observed only in piping from certain 
manufacturers. Not all pre-1970 pipe has that problem.
    INGAA also expressed the opinion that soil erosion is not a 
significant direct threat to pipeline integrity, however it may lead to 
increased importance of third-party damage when it results in shallow 
cover. In addition, it noted that some materials and construction 
techniques are more susceptible to damage from massive soil movement 
than others, and that this issue is treated more completely in ASME 
B31.8 S which was under development at the time of the comment, but has 
subsequently been issued.
    On the subject of operator error, INGAA noted that performance 
measures are needed to evaluate the importance of this threat to 
pipeline integrity. Lessons learned from observed operator errors 
should then be

[[Page 4287]]

translated into improvements in operating procedures and communicated 
among operators. Effective management of change and quality control/
assurance programs will also reduce the likelihood of operator error 
contributing to pipeline failure. Consensus standards were under 
development at the time of the INGAA response on qualification and 
certification of individuals involved in analyzing in-line inspection 
(ILI) results. INGAA expressed concern about the increased demand for 
ILI services potentially leading to lengthened time requirements by ILI 
vendors to produce assessment reports, with related implications to the 
ability of the industry to meet repair and mitigation requirements.
    On the subject of gas storage field pipeline systems, INGAA stated 
that those in high consequence areas should be treated in the same way 
as natural gas transmission pipelines.
    AGA/APGA also noted that the process for managing pipeline 
integrity should not be affected by the operating stress level. Lower 
stress pipeline operators should be required to develop and follow 
integrity management programs having the same elements as operators of 
higher stress pipelines. Only the tools and techniques used to assess 
the pipeline and the reassessment intervals should require 
customization.
    NYGAS indicated that it is important to ensure that staff 
conducting and analyzing results from assessment of pipeline integrity 
be qualified. In the cases where the operator qualification rule does 
not apply, operators must ensure proper qualification of these people, 
and monitor performance measures designed to reveal potential problems 
with personnel qualification. NISource commented that there needs to be 
a clear means of identifying a threat as ``significant.''
    In aggregate these comments are consistent with the RSPA/OPS 
decisions to require threat-by-threat analysis of the pipelines and to 
acknowledge the differences in failure mode for pipe operating at 
stress levels below 30% SMYS by imposing somewhat different 
requirements for these lines.

Select Appropriate Assessment Technologies

    The third element of integrity management discussed in the June 27, 
2001 FR notice, involves identification of potential threats to the 
pipeline in areas of concern. In the notice we used the following 
hypotheses to support selection of 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:
    [sbull] 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.
    [sbull] Time dependent threats will require periodic inspection to 
characterize changes in their significance.
    [sbull] 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. (Note: RSPA/OPS is co-
sponsoring with industry an evaluation of direct assessment technology 
to determine the conditions under which direct assessment is effective 
in assessing external corrosion. The effectiveness of direct assessment 
in assessing other threats (e.g., internal corrosion, stress corrosion 
cracking) is also under evaluation for validation.
    [sbull] Unless the operator demonstrates by evaluation that they 
are not a threat to the integrity of a pipe segment, 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. If operating conditions for a pipeline with 
potential seam problems from manufacture are to be changed 
significantly, then the pipeline must by pressure tested prior to the 
change of operation.
    [sbull] Time-independent threats will require the use of two 
parallel integrity management approaches. The vast majority (over 90%) 
of ruptures caused by time-independent threats occur at the time that 
the activity takes place (e.g., when the excavator hits the pipeline), 
and not at some later time. 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 time-independent 
threats do not result in immediate pipeline rupture, technologies that 
look for evidence of past damage after the threat has occurred should 
be focused in areas where delayed failure is most likely.
    [sbull] Threats related to human error will be addressed largely, 
but not completely, through the new Operator Qualification Rule. The 
integrity management rule will require operators to evaluate the impact 
of operator error on the primary threats to pipeline integrity.

Comments

    INGAA summarized the capability of pipeline in Classes 3 and 4 for 
using internal inspection tools as follows: 24.4% is easily piggable, 
25.3% can be easily made piggable, 45.9% would be very costly to make 
piggable, and 4.4% cannot be pigged.
    INGAA provided a set of examples of situations and conditions which 
may adversely impact the accuracy of results from the indirect 
processes used in external corrosion direct assessment. These include:
    [sbull] Rocky backfill with little or no soil around the pipe.
    [sbull] Very dry, cracked soil where little soil contact is made 
with the pipe.
    [sbull] High-dielectric coatings (such as polyethylene tape) that 
have the propensity to shield the pipe from the flow of cathodic 
protection current, where no orifices to the soil/water interface are 
present.
    [sbull] Resolution and sensitivity of survey equipment.
    [sbull] Correct selection of the proper diagnostic tool matched to 
the suspected integrity threat.
    [sbull] Bare or unprotected pipelines.
    INGAA stated that data from the ongoing external corrosion direct 
assessment process development effort will need to be combined with 
data from application of the process over time to allow statistical 
analysis describing reasonable confidence bands.
    A preliminary model was presented by INGAA that describes the use 
of the four step direct assessment process in assessing a pipeline for 
SCC. This description relies heavily on the assembly and integration of 
risk factor data that could indicate the possible presence of SCC. 
These risk factor data are presented in the appendix of ASME B31.8S.
    AGA/APGA commented that not all pipelines should be required to be 
pressure tested for manufacturing or construction defects at sometime 
during their lifetime. For example, a pipeline should not require 
pressure testing if it has not experienced leaks during its lifetime. 
This argument assumes that

[[Page 4288]]

operation of the line is not subjected to pressure cycling of 
sufficient magnitude and frequency to produce growth of existing 
cracks. AGA/APGA does support existing requirements to pressure test 
all new pipelines before operation.
    AGA/APGA commented that pipelines operating at hoop stress levels 
between 20% and 30% SMYS, where the failure mode is leakage not 
rupture, should be allowed to use assurance technologies, including 
mitigation measures, other than pigging, pressure testing and direct 
assessment. An AGA paper, dated April 26, 2001, on ``Integrity 
Management for Low Stress Pipelines'' (copy filed in the Docket) 
further expands on these alternate technologies and mitigation 
measures.
    AGA/APGA indicated that direct assessment is: (a) Currently being 
validated and imbedded in a NACE consensus standard; (b) being 
evaluated for application to bare pipelines; and (c) should not be 
defined in an overly prescriptive manner.
    AGA/APGA summarized the strengths and limitations of pressure 
testing and in-line inspection. They noted that all forms of integrity 
testing will have some impact on gas supply reliability, and that 
severe constraints or cut-off will be required with pressure testing.
    The following table was developed by AGA/APGA on miles of member 
companies with various assessment capability.

----------------------------------------------------------------------------------------------------------------
                                                                       Temp          Extensive
                                     Miles in        Currently    conversion for   retrofit for      Cannot be
       Company membership           classes 3&4    piggable  (in    pigging  (in    pigging \1\     pigged \2\
                                                     percent)        percent)      (in percent)    (in percent)
----------------------------------------------------------------------------------------------------------------
AGA.............................          13,500              12              10              43              35
APGA............................           3,000              13  ..............              41             46
----------------------------------------------------------------------------------------------------------------
\1\ Retrofit costs range from $5,000 to $250,000 per mile.
\2\ Costs range estimated to be from $1M to $8M per mile to replace pipe (in urban areas).

    The Florida Public Service Commission recommended that both 
magnetic flux leakage (MFL) pigging and pressure testing be carried out 
at intervals of five to seven years, not to exceed ten years. They also 
indicated that Florida gas pipes are typically less than twelve inches 
in diameter and therefore should be inspected at ten year intervals.
    Pacific Gas & Electric Company (PG&E) also indicated that increased 
leak patrol frequency should be used to minimize the threat of leakage 
from pipe segments operating at low hoop stress (e.g., less than 30% 
SMYS).
    PG&E commented that pipe segments operating at low stress levels 
should not be required to conduct a pressure test once in the pipeline 
life, but rather operating history should be used to validate material 
strength. They also noted they found direct assessment to be a good 
tool to identify residual third party damage.
    PG&E noted that they do consider erosion to be one of the Outside 
Forces that needs to be considered, and they conduct annual erosion 
surveys to support mitigative action where erosion is identified.
    PG&E summarized the reasons why some of its pipe is not piggable 
because of the presence of one or more of the following: telescopic 
construction, random diameter construction, sharp radius bends, and 
less than full opening valves.
    NYGAS commented that local distribution company (LDC) transmission 
lines are typically sole source lines and are closely coupled to the 
distribution system. These facts will greatly increase the cost and 
impact on customer supply of pigging and pressure testing.
    NYGAS further commented, with supporting analysis from Kiefner and 
Associates, that under typical cyclic loading conditions, the fatigue 
life of a gas pipeline operating at stresses of 72% SMYS is 100 to 400 
times longer than hazardous liquid pipelines, and that lowering the 
operating stress level to below 30% SMYS will increase this factor to 
between 900 and 3600. Therefore, pressure testing at some time during 
the life of a low stress pipe should not be required. NYGAS also noted 
that experience has demonstrated ILI technologies do not perform 
satisfactorily at pressures below 400 psi.
    NISource commented that it does not believe an integrity baseline 
needs to be established for all pipe segments. In particular, low 
stress pipelines have a ``baseline'' established through application of 
the exiting regulations and monitoring for evidence of leaks. Current 
practices identify the physical conditions which increase the potential 
for gas accumulation resulting from a leak, and the presence of these 
conditions leads to increased monitoring.
    The Association of Texas Intrastate Natural Gas Pipelines commented 
that it would be useful if the rule spelled out the process by which 
new assessment technologies would be approved by RSPA/OPS.
    Several operators expressed concern about their ability to de-water 
a pipe segment that is not piggable following a pressure test. 
Inability to de-water would lead to increased likelihood of internal 
corrosion. This fact supports the advisability of allowing direct 
assessment as an alternative assessment technology.
    Comments from the public and the pipeline industry generally 
supported RSPA/OPS's approach in developing this proposed rule. The 
commenters generally agreed that the proposed rule should include: (1) 
A threat-by-threat analysis of each pipeline segment; (2) at least one 
pressure test during the life of a pipeline to characterize its 
susceptibility to material and construction defects, unless the 
operator can justify why a pressure test is not necessary; (3) periodic 
assessment of each pipeline segment for third party damage (denting), 
unless the operator can justify why such assessment is not necessary. A 
decision to forgo periodic assessment must address loading conditions 
(e.g., cyclic loading), pipe susceptibility to delayed failure (e.g., 
at Edison, NJ), and pipe exposure to potential third party damage; and 
(4) a description of how to apply direct assessment, including the 
conditions under which it is not appropriate, and conservative criteria 
for pipe excavation for direct examination.

Baseline Assessment and Remediation

    The fourth element of integrity management discussed in the June 
27, 2001 FR notice, related to the baseline assessment and remediation 
time frame. To determine time frames to conduct a baseline integrity 
assessment and to complete remediation following an assessment using an 
approach that prioritizes pipeline segments based on risk, we used the 
following hypotheses:
    [sbull] The time frame for conducting the baseline assessment 
should be based on a graded or tiered approach where pipeline segments 
are prioritized for

[[Page 4289]]

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.
    [sbull] 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.
    [sbull] 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.

Comments on Baseline Assessment and Remediation

    INGAA commented that several practical factors will influence the 
time frame for completing a baseline assessment. These include time 
for: (a) Program development (suggested, 18 months); (b) assembly and 
analysis of risk factor data (suggested, 18 months); (c) limitations on 
the availability of assessment tools from vendors; and (d) potential 
detrimental impacts on supply to critical customers. Given these 
factors, INGAA estimated that the shortest time for completing baseline 
assessments would be about ten (10) years after promulgation of the 
rule. Even if ten years were allowed, INGAA estimated in an early 
analysis that the economic cost to customers over the ten year baseline 
assessment period would range from $3.9 to $6.1 billion.
    INGAA reported that repair time frames should consider the results 
of a recently completed analysis by Kiefner and Associates in which the 
allowable repair time is related to the calculated (or pressure tested) 
safe operating pressure. Three categories were defined: (a) Segments 
with a safe operating pressure of 110% of MAOP or less should be 
repaired immediately, (b) those with a safe operating pressure of less 
than 139% of MAOP but above 110% of MAOP should be repaired on a 
defined schedule, and (c) those with a with a safe operating pressure 
of greater than 139% of MAOP require interval monitoring. Interval 
monitoring implies reassessment on a ten year interval to assure that 
sub-critical anomalies will not fail during that time.
    AGA/APGA commented that factors considered in determining the time 
frame for the baseline assessment should include scope of the rule 
(i.e., only above 20% SMYS), availability of pigging equipment, 
availability of properly qualified people, and the impact on the gas 
supply. Considering these factors, they believe that a minimum of ten 
(10) years should be allowed to complete the baseline assessment, with 
half of the pipeline completed within five years and variances 
available for those unable to meet the schedule.
    AGA/APGA agree that repairs should be scheduled to reflect the 
seriousness of the defect. However, engineering distinctions among the 
gas pipeline systems dictate that the highly prescriptive approach to 
repair requirements in the Large Liquid Pipeline Operator Rule is 
inappropriate. RSPA/OPS should consider the guidance on repair and 
mitigation being developed by the ASME/ANSI B31.8S.
    The Association of Texas Intrastate Natural Gas Pipelines commented 
that it would be useful if RSPA/OPS included a special provision for 
assessment interval for new pipe segments or replaced pipe segments.
    PG&E supported a ten year baseline assessment period. PG&E 
commented that practical considerations (e.g., long-lead materials, 
construction difficulties, and economies of scale) should be considered 
in developing assessment schedules to ensure that economic efficiencies 
can be realized while satisfying the intent of any rule that the 
highest risk segments be assessed first.
    Enron commented that a ten year baseline assessment interval seems 
appropriate, and that reassessment in class 1 and 2 locations should be 
on the same interval, but that reassessment in Class 3 and 4 locations 
should be on a fifteen year interval. Enron also strongly urged RSPA/
OPS to allow operators to carry out repairs consistently with existing 
procedures rather than imposing a prescriptive repair time frame.
    Baseline assessment factors: The recent pipeline safety law 
(Pipeline Safety Improvement Act of 2002) requires that an operator 
conduct a baseline assessment not later than ten years from the date 
the law is enacted. This time frame is consistent with the baseline 
time frame we were considering based on our study of the relevant 
influencing factors. The law further requires that at least 50% of 
facilities in high consequence areas must be assessed no later than 5 
years from enactment. This requirement is also consistent with what we 
were considering. Our proposal incorporates these requirements.
    The factors we considered relevant to establishing the time frame 
for an operator to conduct the baseline assessment include:
    [sbull] The desire to establish an integrity baseline for all 
affected pipe segments as quickly as possible.
    [sbull] The ability of the gas pipeline service industry to expand 
both its assessment equipment, and, of equal importance, its qualified 
technical staff.
    [sbull] The ability of the pipeline industry to gather and 
integrate risk factor data necessary to characterize the significance 
of threats to pipe integrity.
    [sbull] The time required for the pipeline industry to modify its 
lines to accommodate in-line inspection equipment.
    [sbull] The impact on critical gas supply and the associated impact 
on the price of natural gas. INGAA recently funded a study to evaluate 
the supply and consumer cost impacts associated with various baseline 
assessment intervals. The study did not include the actual cost of 
modifying the pipeline to accommodate ILI equipment, and the study 
assumed operators would perfectly coordinate their assessment 
activities to minimize the impact on customers. The study included 
supply impacts resulting from modifying a pipeline to accept ILI 
equipment and from the assessment activity itself. Supply impacts 
associated with remediation or repair of defects discovered during the 
assessment were not included. The study included differences in the 
supply impacts associated with different assessment technologies.
    The INGAA analysis found that consumer cost impact was more 
significant with short baseline assessment periods than with longer 
times. The cost impacts in the current analysis were estimated to be 
$7.2B for a 14-year baseline period, $13.1B for a 10-year baseline 
period, and $20.1B for a 5-year baseline period. Although not 
quantifiable in the model, the potential for critical supply 
interruptions, resulting from the need to perform assessments during 
high demand periods and the increased difficulty of coordinating 
assessments on lines

[[Page 4290]]

feeding the same customers, increases as the baseline period decreases.
    [sbull] Class location requirements. The gas pipeline safety 
regulations have class location requirements that the liquid 
regulations do not. As population increases near a pipeline, the class 
location requirements require establishment of an additional margin of 
safety. To comply with class location requirements, gas transmission 
pipeline operators maintain data on the number of residences and other 
buildings located near their pipelines. Based on threshold levels of 
near-by dwellings and buildings, operators are required to constrain 
the maximum stress level in the pipeline to successively lower levels 
as the number of dwellings increases. When a class location changes to 
a higher class, an operator must reduce the stress level on the line 
either by reducing pressure, or in some cases, by replacing the pipe. 
If an operator replaces the pipe, an operator may use thicker walled or 
higher strength pipe to ensure that the capacity of the pipeline is not 
reduced.
    The result is that, while gas pipelines in locations of potentially 
high consequence typically operate at stress levels of 40% SMYS (Class 
4) or 50% SMYS (Class 3), corresponding liquid pipelines typically 
operate at 72% SMYS. A higher stress is typically associated with 
thinner walled piping or a smaller margin to failure for a given defect 
size. Therefore, time dependent threats such as external corrosion, 
which occur at a rate dependent on factors such as soil chemistry, 
coating integrity and cathodic protection effectiveness, have less wall 
thickness to penetrate before a critical defect depth is reached and 
the pipeline ruptures. The lower stress levels and thicker walls of gas 
pipelines imply that, other factors being equal, corrosion would take 
longer to penetrate to a critical depth.
    These factors support a baseline assessment interval of ten years 
for operators using in-line-assessment or pressure testing, with at 
least 50% of the covered segments (the higher risk segments) being 
assessed within five years. However, for operators using direct 
assessment as the primary assessment technology, we are proposing a 
baseline assessment interval of seven years to account for the early 
state of development of these processes and to allow time to develop 
data on their validity. The highest risk half of the segments being 
assessed by direct assessment will, however, be assessed during the 
first four of these seven years. This proposal is consistent with The 
Pipeline Safety Improvement Act of 2002 (HR 3609, signed into law Dec. 
17, 2002) which provides for a baseline assessment ``not later than 10 
years'' after the law's enactment, with 50 % having to be assessed 
``not later than 5 years'' after enactment. As noted earlier, RSPA/OPS 
is proposing to require operators choosing direct assessment 
technologies to undertake extra excavations and direct examinations 
during the period while validation is continuing.
    Our proposal on the baseline assessment also allows for an 
assessment conducted five years before the law's enactment or date the 
final rule is effective, whichever is earlier, as a baseline assessment 
if it satisfies the specified assessment criteria. If an operator 
chooses this option, under our proposal, the operator would then have 
to begin complying with the requirements for reassessment of the 
segment.

Identify and Implement Additional Preventive and Mitigative Measures

    The fifth element of integrity management discussed in the June 27, 
2001, FR notice, related to identification and implementation of 
additional preventive and mitigative measures. We used the following 
hypotheses in the notice:
    [sbull] 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.
    [sbull] 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, and 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 closer together than required as a 
mitigative measure.

Comments

    INGAA described a general process used by operators to make 
decisions on adding risk control or mitigation features beyond those 
required by regulation. The process involves establishment of a budget 
for additional safety enhancements and allocating that budget based on 
some structured form of risk assessment process, including feedback on 
potential risks from people in the field.
    The conclusions of two INGAA-sponsored reports on the value of RCVs 
and ASVs include:
    1. Neither RCVs nor ASVs will reduce fatalities or injuries to the 
public.
    2. Neither control valve system will significantly reduce property 
damage.
    3. RCVs and ASVs increase the likelihood of service disruption 
(RCVs in particular).
    4. RCVs and ASVs can reduce the amount of product lost.
    5. Costs for RCVs or ASVs outweigh measurable benefits.
    According to INGAA, the only substantive benefit of RCVs and ASVs 
is that they result in faster valve closure following an incident.
    Air Products and chemicals, an operator of 700 miles of pipeline 
for transporting industrial gas such as hydrogen, currently uses 
twenty-five excess flow valves along the 150 miles of pipe it operates 
in what it considers to be high consequence areas. These valves were 
added as a result of its risk analysis process.
    GPTC noted that it expects ANSI to publish a technical report 
describing industry practices and ideas for managing integrity this 
Fall and requests that RSPA/OPS consider information in this document 
as part of its Rulemaking effort.

Remote Control Valves (RCVs)

    In response to a Congressional mandate following the March 1994 gas 
transmission pipeline failure at Edison, NJ (Accountable Pipeline 
Safety and Partnership Act of 1996; codified at 49 U.S.C. 60102(j)), 
RSPA/OPS surveyed and assessed the effectiveness of remotely controlled 
valves (RCVs) on interstate natural gas pipelines. We examined the 
technical and economic feasibility of RCVs to rapidly shut down a gas 
transmission pipeline after a rupture.
    RSPA/OPS conducted a public meeting in October 1997 to gather data 
on the technical and economic feasibility of installing RCVs. There was 
general agreement by the meeting participants, and in written comments 
following the meeting (contained in Docket No. RSPA-97-2879), that RCVs 
are technically feasible, but are not economically justifiable from a 
cost-benefit standpoint. This result is because most casualties and 
property

[[Page 4291]]

damage occur within ten minutes after a pipeline rupture. Although an 
RCV can be closed within two or three minutes to isolate a pipeline 
section, a safe condition is not achieved until the gas between valves 
has either escaped or burned off, which is almost always a longer time 
period than ten minutes.
    These findings from the public meeting were reinforced by the 
results of a Gas Research Institute (GRI) study of 80 gas transmission 
pipeline failures over a twelve year period which showed that quick 
closure of valves could have prevented only one injury out of a total 
of 28 fatalities and 116 injuries.
    We closely monitored a one year field evaluation of 90 RCVs 
installed by Texas Eastern Transmission Company, mostly in New Jersey 
and Pennsylvania. The RCVs' reliability was demonstrated by the fact 
that there were no unplanned closures of the valves during the year 
and, of the 200 plus valve cycles executed remotely, the valves closed 
100 percent of the time on the first attempt.
    RSPA/OPS completed a study in September 1999 titled ``Remotely 
Controlled Valves on Interstate Natural Gas Pipelines,'' available in 
Docket RSPA-97-2879. The study shows that installing and using RCVs can 
effectively limit the time required to isolate ruptured pipe sections 
when manual valve operation is not feasible, thereby minimizing the 
consequences of certain gas pipeline ruptures. The study supports RCVs' 
effectiveness, technical feasibility, and potential for reducing risk. 
The study indicates that the quantifiable costs of RCV installations 
would almost always exceed the benefits.
    However, we believe that significant risk exists at some locations 
as long as gas is being supplied to a rupture site, and operators 
currently lack the ability to quickly close existing manual valves. Any 
fire would be of greater intensity, and would have greater potential 
for damaging surrounding infrastructure, if the fire were replenished 
with gas over a protracted period of time. Therefore, we held another 
public meeting in November 1999 to consider the need for a rulemaking 
to establish time limits for isolating ruptured sections of gas 
transmission pipelines. No new data were presented at the hearing to 
establish critical locations where RCVs should be installed.
    Consistent with the hypotheses prepared earlier, RSPA/OPS decided 
to incorporate a provision in the rule requiring operators to evaluate 
the potential value of a spectrum of preventive and mitigative 
measures, and to act on the results of this evaluation. So that RSPA/
OPS may understand the basis on which operator decisions are made, we 
will require operators to document their decision processes and 
decision criteria for RSPA/OPS review during inspections. Measures to 
be considered by operators will include those practices set forth in 
ASME B31.8S, as well as use of RCVs and ASVs. While these two types of 
valves have been analyzed generically for gas pipelines, RSPA/OPS 
believes that each operator should consider the merits of installing 
these mitigative measures at critical locations on their pipelines and 
make installation decisions based on pipeline-specific and site-
specific evaluations.

A Process for Continual Evaluation and Assessment To Maintain a 
Pipeline's Integrity

    The sixth element of integrity management discussed in the June 27, 
2001 FR notice, related to the process for continual evaluation and 
assessment of pipelines to maintain their integrity. We used the 
following hypothesis in the notice:
    Operators should continually evaluate and reassess at the specified 
interval each pipeline segment that could affect an area of potentially 
high consequence 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.
    [sbull] Managing a pipeline's integrity requires periodic 
reassessment of the pipeline. The time frame appropriate for this 
reassessment depends on numerous factors. In the current class location 
change regulation, gas pipeline operators are required to replace pipe 
segments with thicker-walled or stronger pipe (or to 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.
    [sbull] 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.
    [sbull] 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 (see the discussion above on performance-based requirements).
    [sbull] The periodic evaluation is based on an information analysis 
of the entire pipeline.

Comments

    INGAA's comments included a discussion of the results of a Battelle 
analysis on assessment intervals. The analysis indicated that while the 
recommended reassessment interval in their report was developed based 
on the assumption that operators would use thicker pipe to address the 
Class Location requirements, the recommended interval would not be 
affected if operators chose to use higher strength pipe (rather than 
thicker pipe) to comply with changes in class location.
    In addition, INGAA offered the opinion that the series of new 
integrity management regulations will lead to a situation in which the 
demand for assessment equipment and people qualified in its use and in 
interpretation of results will outpace the supply. This factor should 
be considered in determining the baseline and reassessment interval 
requirements.
    INGAA recommended that RSPA/OPS solicit information from direct 
assessment service providers to evaluate the ability of the service 
providers to respond to the requirements for increased assessment 
included in the new IMP Rules.
    AGA/APGA urged RSPA/OPS not to require reassessment on a prescribed 
interval. Intervals should be dictated by analysis using accepted risk 
principles along with results from the baseline assessment. If a 
prescriptive requirement on reassessment interval is needed, then RSPA/
OPS should allow operators to deviate from that interval if it can 
justify such a deviation.
    NYGAS commented that local distribution companies (LDCs) need 
greater flexibility in managing repairs and mitigative action than is 
implicit in the repair provisions of the liquid operator rule for 
operators with 500 or more miles of pipeline. The absence of such 
flexibility will lead to gas supply interruptions to customers.
    RSPA believes that once the baseline assessment has been completed, 
the availability of qualified vendors and assessment equipment are no 
longer factors, since it is quite likely that the pipeline service 
industry will expand to meet the new higher level of demand. In 
addition, the major line modifications required to accommodate in-line 
inspection (ILI) equipment should be completed. Some of the factors 
influencing reassessment intervals are discussed above under baseline 
intervals. Other factors that influence

[[Page 4292]]

the periodic reassessment interval include:
    [sbull] The stress level at which the pipeline operates;
    [sbull] The growth rate of corrosion defects; and
    [sbull] The repair criteria used in remediating defects discovered 
in previous assessments.
    Figure 7-1 and Table 8-1 in ANSI/ASME B31.8S sumarize the relevant 
factors for determining a reassessment interval. The corrosion rates 
reflected in these charts represent the high end of historically 
observed corrosion, but are not the highest rates that might be 
experienced under special conditions, such as the presence of 
microbiologically influenced corrosion (MIC). Table 8-1 relates the 
recommended reassessment interval in years to the stress level of the 
pipe (% SMYS), the type of assessment carried out, and the significance 
of defects left in the pipeline following mitigation or repair. For a 
typical pipe segment in a Class 3 Location, the stress level would be 
50% SMYS. At this stress, if a pressure test were carried out at 1.39 
times the maximum allowable operating pressure (MAOP), then the 
recommended reassessment interval would be 10 years. This same 
recommended reassessment interval would result if ILI were used and all 
defects were repaired that had a predicted failure pressure below 1.39 
times the MAOP. The recommendations for reassessment intervals 
following use of direct assessment are closely related to the details 
of the excavation criteria used in examining indications. The intervals 
shown in (Table 8-1 in ASME B31.8S) are based on technical analysis of 
time-dependent failure mechanisms (e.g., external corrosion).
    The recently-enacted pipeline safety law (HR 3609 signed into law 
Dec. 17, 2002) requires that reassessment be done at minimum intervals 
of seven-years. Thus, in our proposed rule, we have established a 
seven-year interval, but we also allow the operator to establish the 
intervals depending on the assessment method. Depending on the 
assessment method, the maximum interval an operator is allowed to 
establish could be longer than seven years. However, if the period is 
longer than seven years, the operator would have to conduct an interim 
reassessment by confirmatory direct assessment by the seventh year and 
then conduct the follow up reassessment in the year the operator has 
established. Thus, in the seven-year period an operator must either 
reassess a covered segment using the assessment method the operator has 
chosen, or if the operator has established a longer interval, conduct a 
confirmatory direct assessment by the seventh year with a follow up 
reassessment in the year the operator sets. Our proposal takes into 
account the factors we have discussed above.

Monitor the Effectiveness of Pipeline Integrity Management Efforts

    The seventh element of integrity management discussed in the June 
27, 2001 FR notice, related to monitoring the effectiveness of pipeline 
integrity management activities. We used the following hypothesis in 
the notice:
    [sbull] Measures can be developed to track actual integrity 
performance as well as to determine the value of assessment and repair 
activities.
    [sbull] Application of integrity management technologies that 
exceed current regulations is cost effective because many companies 
made the decision to implement such programs.

Comments

    INGAA suggested that RSPA/OPS should consider including the 
following performance measures:
    [sbull] Number of miles of pipeline inspected under IMP.
    [sbull] Repairs:
    1. Number of immediate repairs completed as a result of the IMP 
inspection program; and
    2. Number of scheduled repairs completed as a result of the IMP 
inspection program.
    [sbull] Number of leaks, failures and incidents (classified by 
cause).
    AGA/APGA suggested that RSPA/OPS should work with stakeholders to 
develop performance measures immediately after promulgation of the 
integrity management rule. Additionally, in using these measures, RSPA/
OPS must avoid inappropriate comparisons of performance among operators 
with vastly different systems.
    NYGAS stated that performance measures should be properly used to 
monitor the effectiveness of integrity management efforts within 
individual companies, not to compare the performance among operators.
    The Association of Texas Intrastate Natural Gas Pipelines commented 
that it would be useful for RSPA/OPS to establish performance measures 
that relate to each operator's integrity management plan, rather than 
requiring one-size-fits-all reporting requirements.
    Enron commented that if RSPA/OPS were to increase the time for 
required submission of written pipeline incident reports by an 
additional sixty days, then there would be an opportunity to include 
better information on the evaluated cause of each incident.
    The recently published standard ASME B31.8S discusses operator 
performance plans in Chapter 9. This discussion describes four measures 
that are required to be monitored by all operators using the standard. 
These measures are:
    [sbull] Number of miles of pipeline inspected (assessed) versus 
program requirements;
    [sbull] Number of immediate repairs completed as a result of the 
integrity management inspection program;
    [sbull] Number of scheduled repairs completed as a result of the 
integrity management inspection program; and
    [sbull] Number of leaks, failures and incidents (classified by 
cause).
    RSPA/OPS is proposing to require operators to track and record 
these four overall performance measures, and make them electronically 
accessible (in real time) to RSPA/OPS for review. In addition, RSPA/OPS 
proposes to require operators to develop performance plans consistent 
with ASME B31.8S, and to define the extended set of measures that it 
will track. OPS will be able to review these measures during periodic 
field inspections. Appendix SP-A of ASME B31.8S tabulates suggested 
measures for each threat to which a pipeline might be subject.

Consideration of Impact on Gas Supply

    The eighth consideration of integrity management discussed in the 
June 27, 2001 FR notice, related to the impact of the rule on gas 
supply. Performing an assessment test on gas transmission pipelines has 
the effect of restricting gas flow. Unless adequate time is allowed and 
the assessment process is carefully managed, this flow restriction can 
significantly impact gas supply and cost to customers.
    Different assessment technologies have different restrictions on 
gas supply. In-line-inspection merely restricts flow for the relatively 
short time when the instrumented internal inspection device (pig) is in 
the pipe. However, preparing the pipe to make it able to be internally 
inspected (piggable), requires termination of the gas flow in the 
segment being tested while modifications are made. At present over 75% 
of gas transmission lines are not piggable or can be made piggable only 
with extensive modifications. Pressure testing requires termination of 
gas flow in the section being tested each time it is carried out. 
Direct assessment requires flow restriction (associated with lowering 
the pressure as a safety measure) while selected locations along the 
pipe are being excavated and directly examined.

[[Page 4293]]

    We indicated above that assessing pipelines using any of the 
technologies under consideration may result in a restricted gas supply 
because of the need to take pipelines out of service or by reduction in 
throughput. In addition, some types of repairs will also require lines 
to be taken out of service. If an upstream segment of this gas 
transmission pipeline were put out of service temporarily for test or 
repair, many communities located at the end of branch lines, could be 
negatively impacted by the restricted gas supply. This effect would be 
caused by the fact that the lines are often sole source feed, (i.e., 
have no other tie-in's from an alternative source.) Because of this 
factor, the proposed rule allows a waiver of a reassessment interval 
greater than seven years, if the operator demonstrates that it cannot 
maintain local product supply, and OPS determines that a waiver would 
not be inconsistent with pipeline safety. This proposal is consistent 
with the provision in the Pipeline Safety Improvement Act of 2002. 
Because a waiver requires public notice and comment, we are proposing 
180-day advance notification.

INGAA Report

    INGAA commissioned an extensive analysis of the economic impact of 
a gas IMP rule. The analysis, performed by Energy & Environment 
Analysis, Inc., evaluated this impact using various assumptions on the 
fraction of the affected pipe that is currently not piggable that will 
be assessed by pigging, pressure testing, or direct assessment. The 
time frame during which the baseline assessment must be performed was 
also a parameter in the analysis, varying from five to fifteen years. 
While (at the time of the INGAA comment--August 14, 2001) sufficient 
detail was not available to evaluate the credibility of the analysis 
and its underlying assumptions, the estimated economic impact on gas 
consumers for the ten year baseline period is large, ranging from $3.9 
billion to $6.1 billion. (Note, this analysis and a peer review of 
report performed by the Volpe National Transportation Systems Center 
(Volpe Center) and the Department of Energy (DOE) have recently been 
completed and are discussed below).
    AGA/APGA commented that some forms of assessment (e.g., pressure 
testing) would require outages from 3 to 9 days. Customers would in 
some cases be without gas during that time, and restoration of gas 
supply would require extensive work, for example, re-lighting pilot 
lights of each affected customer.

Discussions on the INGAA Report on ``Consumer Effects of the 
Anticipated Integrity Rule for High Consequence Areas'' (February 2, 
2002)

    On April 3, 2002, RSPA/OPS held a meeting with INGAA, Energy and 
Environment Associates (EEA), the Volpe Center, and DOE to discuss the 
INGAA report on ``Consumer Effects of the Anticipated Integrity Rule 
for High Consequence Areas'' (February 2, 2002). The meeting was 
designed to allow RSPA/OPS, and several reviewers retained by RSPA/OPS, 
to explore the reasonableness of the results in the INGAA-sponsored 
report. The focus of discussion was on the assumptions made in the 
analysis. The report was produced in response to the initial need to 
understand the supply and economic implications of allowing or 
disallowing direct assessment as a primary assessment technology, and 
later was expanded to evaluate the supply and economic implications of 
various baseline assessment intervals ranging from 5 to 15 years.
    The report focuses on interstate transmission pipelines. INGAA 
indicated the industry expects that most HCA mileage will lie in Class 
3 and 4 Locations, and that approximately 5% of pipeline is in class 3 
and 4 locations, but that the HCA definition will include some pipe 
segments in other locations as well. INGAA said that Class 3 and 4 
Locations are scattered throughout the pipeline system so they appear 
in about 60% of valve stations and 80% of the discharges from 
compressor locations.
    INGAA further stated that a periodic inspection program was useful 
only to identify the presence of dynamic failure mechanisms or threats 
(i.e., corrosion). They questioned the value of periodic assessment of 
pipelines for static threats (i.e., material and construction) or 
random threats (e.g., third-party damage).
    The reviewers at the meeting requested clarification of the study 
assumption regarding the fraction of lines that are assumed to be in-
line-inspected. Scenarios 1, 2 and 3 in the report assume segments 
described as ``currently piggable'' and ``relatively easy to make 
piggable'' are treated as ``easy to pig'' (i.e., about 50%). The other 
scenarios, 3A, 3B and 3C in the report assume that only ``currently 
piggable'' segments are treated as ``easy to pig'' (i.e., about 25%). 
This difference in assumptions complicates comparison between Scenarios 
1, 2 & 3 and Scenarios 3A, 3B & 3C. EEA stated that market evaluations 
do show that there are capacity choke points and that spot market 
prices respond to capacity restrictions. Examples include recent price 
spikes in the States of California and New York. These capacity 
restriction effects were the focus of the study. No account was taken 
of the cost incurred by operators making lines piggable, although the 
capacity impacts associated with these maintenance activities were 
considered.
    Other key assumptions in the analysis include: (1) 80% of mainline 
pipe and 50% of laterals/connections will be inspected (these numbers 
are supported by consideration of the distribution of segments that can 
affect HCAs throughout the pipeline systems and by the fact that even 
operators using direct assessment as their primary assessment approach 
will be required to reduce pressure in long segments of their lines 
during the direct examination step of the process). (2) Effects on 
consumers with limited options and flexibility in gas providers will be 
much more severe (e.g., Florida has one transmission line, with a 
second to come in service this summer. Load factor on the line is 
greater than 80% and any interruptions would have significant 
downstream effect, and therefore cost impacts). It was noted by INGAA 
at the meeting that gas supply interruptions are not as routinely 
buffered by storage capacity as liquid petroleum products, which are 
normally stored in tanks. (3) The industrial sector is more elastic 
than the residential sector. Demand there was adjusted significantly 
when gas prices were high over the last couple years. (4) The analysis 
assumes that the impact of supply restrictions occurs at the time the 
restriction occurs rather than at a later time, as would occur because 
of long-term supply contracts. (5) Both pipeline capacity and demand 
are assumed to increase, as described in the base case of ``The 
Pipeline and Storage Infrastructure for a 30 Trillion Cubic Feet (TCF) 
Market'' better known as the ``30 TCF study.''
    The TCF study uses the EEA Gas Market Data and Forecasting System. 
This model was developed in 1995 requiring over ten person years of 
effort. The model is rigorously calibrated to actual historical 
behavior. Price differences are calculated as a function of load 
factor. The calibration is updated annually.
    The model is a fairly coarse one in which multiple supply lines 
between market centers are modeled as a single line. However, the model 
appropriately considers the effects of capacity restrictions in one 
line in a corridor, and does not assume that a single line out of 
service terminates supply through the corridor in which it resides. 
This effect is treated separately from the model and

[[Page 4294]]

provided as an input to the model. The inputs to the model are 
developed assuming perfect communication among operators with lines in 
a single corridor, or supplying a single market center such that 
operators do not take multiple lines out of service that would compound 
the impact on capacity restriction at that market center. Taking 
multiple lines out of service in a single corridor might be necessary, 
if the baseline assessment interval were sufficiently short to require 
such action.
    As the market becomes thinner (i.e., supply is restricted relative 
to demand at a market center) consumers bid against each other causing 
spot market prices to rise. Costs developed in the model may be 
overstated over a 10-year period, because all consumers do not pay spot 
prices. As pipelines are re-contracted, however, those costs will be 
reflected in the new contracts.
    In response to questions about why pipe assessments carried out 
prior to the rule currently being considered have not strongly affected 
gas prices, INGAA indicated that people who currently administer active 
pigging programs represent only about 25% of the total pipeline mileage 
and implemented their programs over about a 20 year period. INGAA said 
that in response to the anticipated rule, operators would have to 
assess a significant fraction of their systems (the segments covered by 
a rule) over ten years. The associated supply impacts and consumer 
costs will therefore be much larger.
    The reviewers at the meeting suggested it would be very useful if 
INGAA would summarize all major assumptions and discuss the direction 
and approximate magnitude (e.g., small medium, large) of the effect of 
each assumption on the resultant cost impact. INGAA agreed to consider 
how best to respond to comments raised during the meeting and in the 
review documents that had been prepared in advance by Volpe and DOE 
reviewers. For detailed discussion on this subject see minutes of this 
meeting in the docket.

Other Issues Including Those Related to Cost/Benefit

    The ninth consideration of integrity management discussed in the 
June 27, 2001 FR notice, related to other issues including those 
related to the cost/benefit analysis.

Comments

    INGAA commented that RSPA/OPS should perform its cost-benefit 
analysis starting with current industry practices (as described in 
recent INGAA reports) as the baseline. They also provided some data on 
the number of incidents and property damage over the past fifteen 
years, but did not provide any information on the impact of incidents 
and leaks on the cost of gas to customers.
    INGAA provided preliminary information on the estimated costs of 
inspection of all transmission pipelines for three different scenarios 
on inspection of hard-to-pig (HTP) pipelines. These preliminary costs 
include estimates to convert HTP segments to make them piggable. The 
inspections were assumed to be carried out over a ten year period.

------------------------------------------------------------------------
                                                               Consumer
                                                             cost for 10
                    Scenario description                        years
                                                                period
                                                              (millions)
------------------------------------------------------------------------
\1/2\ HTP portion pigged, \1/2\ HTP portion DA.............       $3,892
\1/2\ HTP portion pigged, \1/2\ HTP portion Hydro..........        6,095
\1/3\ HTP portion pigged, \1/3\ HTP portion DA, \1/3\ HTP          4,048
 portion DA................................................
------------------------------------------------------------------------

    The numbers in this table were updated through the completed INGAA/
EEA analysis discussed above.
    On the question of small business impacts, INGAA noted that no more 
than 50,000 miles of approximately 274,000 miles of natural gas 
transmission pipelines (and probably much less) could be owned by small 
businesses. Also, many of the contractors likely to be involved in 
inspections are small businesses. Finally, the potential exists that 
increased gas costs will impact small business customers.
    AGA/APGA strongly suggested that RSPA/OPS develop the integrity 
rule for gas transmission pipelines around a performance-based 
approach.
    The Florida Public Service Commission noted that performance type 
regulations can only work if operators are willing to share information 
on both performance and potential problems with the regulators. They 
believe that the risk management demonstration program has shown the 
operators are unwilling to openly share needed information.
    The New York Gas Group strongly supports the development of a 
performance-based rule that will allow companies the flexibility needed 
to manage the risks associated with their pipelines, as effectively as 
possible. They asserted that this position is supported by the NY State 
Public Service Commission staff.
    The Process Gas Consumers Group (PGC) commented that RSPA/OPS 
should give strong consideration to any potential economic impact of 
interruptions in gas supply to industrial concerns that rely on gas in 
the conduct of their business.

Conclusions From the Consumer Cost Impact Evaluation

    Consumer cost and supply availability are major factors in 
establishing the period for operators to complete the baseline 
assessment. There are numerous assumptions made in the INGAA study. In 
general they are designed to underestimate the predicted cost impact. 
For example, the study does try to optimize time of testing, and assume 
infinite availability of pig vendors and equipment. However, there are 
also assumptions in the study that would lead to prediction of higher 
cost impact than might realistically be expected. For example, the 
study does not assume learning on the part of the operators, and the 
analysis reflects marginal costs rather than contracted costs.
    The EEA analysis found that consumer cost impact was more 
significant with short baseline assessment periods than with longer 
times. The cost impacts were estimated to be $7.2 billion for a 14-year 
baseline period, $13.1 billion for a 10-year baseline period, and $20.1 
billion for a 5-year baseline period. Although not quantifiable in the 
model, the potential for critical supply interruptions, resulting from 
the need to perform assessments during high demand periods and the 
increased difficulty of coordinating assessments on lines feeding the 
same customers, increases as the baseline period decreases.

RSPA's Conclusions About the INGAA Study

    From its review of the INGAA study RSPA concluded that--
    Study Performers. The organization that performed the study for 
INGAA is recognized as an expert in the type of analysis performed. 
This conclusion is supported by the fact that EEA has been called to 
testify on significant supply issues before Congress, and that the gas 
pipeline industry is using the results of the study on which the 
present impact analysis is based as a major factor in expansion 
decisions.
    Study Conservatism. The peer review identified several assumptions 
used in the analysis in which it would lead to over-prediction of the 
gas supply and cost impacts, as well as some areas where the model 
would be expected to result in under-estimation of these impacts. In 
balance, the model together with its major assumptions seems to produce 
a reasonable, possibly an

[[Page 4295]]

underestimate, of the anticipated supply and cost impacts.
    Baseline Assessment Time Frame. The decision on a baseline 
assessment interval must reflect the need to expedite pipeline 
assessment without dramatically impacting gas availability and price. 
The INGAA/EEA analysis supports the conclusion that a ten-year baseline 
assessment requirement is consistent with managing supply and cost 
impacts resulting from the new assessment requirements. The predicted 
impact on consumer energy cost associated with this baseline time frame 
is $13.1 billion. While this is a very large cost, it represents a 
small percentage impact on total gas costs over the time period of the 
analysis. RSPA has concluded that a ten-year baseline assessment 
period, with 50% of covered segments being assessed within five years, 
will allow the impact on gas supply and cost to be adequately managed 
by the operators.

Mapping

    We stated in the proposed rule on high consequence areas (67 FR 
1108; January 9, 2002), that RSPA/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.
    RSPA/OPS will require operators to provide their pipeline data by a 
separate rulemaking on mapping. Submission of this information has been 
voluntary in the past. At present, RSPA/OPS has received data on pipe 
locations for 90% of liquid pipelines but only 52% of gas pipelines. 
Currently, RSPA/OPS has no data on areas of higher population density 
(Class 3 and 4 locations) associated with gas pipelines. Present gas 
pipeline regulations are structured to provide increasing levels of 
protections, consistent with predetermined thresholds. Accordingly, gas 
pipeline operators are required to monitor data on the number of 
dwellings within 660 feet of their pipelines to either lower operating 
pressure or to replace the pipe with one having greater wall thickness 
or strength as the number of dwellings increases above predefined 
threshold. RSPA/OPS therefore believes that operators have excellent 
data on population and places where people congregate near their 
pipelines.
    Maps incorporating these data would be useful not only to pipeline 
operators, but also to federal and state inspectors and for local 
officials and community needs. RSPA/OPS intends to use operator-
supplied information 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. A separate rulemaking on mapping will 
address this issue.

Treatment of Storage Fields

    Storage fields have provided a source of pipeline integrity 
problems for decades. RSPA/OPS asked for information to help identify 
the cause of and prevent piping-related failures associated with 
storage fields that could affect high consequence areas. INGAA stated 
that those in high consequence areas should be treated in the same way 
as natural gas transmission pipelines.
    The proposed rule requirements will include pipelines within the 
storage fields because under Sec.  192.3(c) such pipelines are defined 
as transmission lines.

The Proposed Rule

    RSPA/OPS is proposing a modification to section 192.761 and 
addition of a new section 192.763 to subpart M: High Consequences Area 
Definitions and Integrity Management Programs. The Sec.  192.761 titled 
``Definitions'' defined ``high consequence areas'' in a recently issued 
final rule (67 FR 50824; August 6, 2002); and proposed a new section 
192.763 ``Pipeline Integrity Management in High Consequence Areas'' is 
described in this rule.

High Consequence Area Definitions--Sec.  192.761

    The definition of high consequence areas recently published in the 
Federal Register (67 FR 50824; August 6, 2002) includes: (a) Current 
Class 3 locations; (b) current Class 4 locations; (c) an area that 
extends 300 feet from the centerline of the pipeline to the identified 
site for a pipeline not more than 12 inches in diameter and having a 
maximum operating pressure lower than 1200 psig; (d) an area of 1000 
feet from the centerline of the pipeline to the identified site for a 
pipeline greater than 30 inches in diameter operating at a pressure 
greater than 1000 psig; (e) an area that extends 660 feet from the 
centerline of the pipeline to the identified site for all other 
pipelines. The areas of 300, 660 and 1000 feet are corridors that have 
been determined based on generalized estimates of potential rupture 
consequences. An identified site is defined as a building or outside 
area that can be identified by one of several means and that houses 
people who are difficult to evacuate or have impaired mobility (e.g., 
hospital, church, school, prisons, day care facility); or where there 
is evidence that 20 or more people congregate at least 50 days in a 
year (e.g. beach, camping ground, religious facility). The full text of 
the HCA definition can be reviewed in the Federal Register document 
referenced above.
    An identified site can be identified by one of several means listed 
in the rule: it is visibly marked, it is licensed or registered, it is 
on a list or map maintained by or available from a Federal, State or 
local agency or a publicly or commercially available database or it is 
know by public officials. RSPA/OPS is inviting comment on whether we 
should use the term public safety officials ( e.g. Police, Fire 
department) and/or emergency response officials instead of public 
officials. Currently, pipeline operators are required to conduct 
liaison activities with public safety officials or emergency safety 
officials. We would like comment on whether the term ``public safety 
officials or emergency response official'' will cover the persons 
having the relevant information about these identified sites.
    On September 5, 2002, the American Gas Association (AGA), the 
American Public Gas Association (APGA), the Interstate Natural Gas 
Association of America (INGAA), and the New York Gas Group (NYGAS) 
filed a petition for the reconsideration of the final rule on the 
definition of HCAs for gas transmission pipelines (67 FR 50835; August 
8, 2002). This petition is in the docket. The petition raised the 
following issues.
    (1) The splitting of the gas integrity rule into two rulemakings--
the definition and the integrity requirements--causes confusion, 
particularly, since the Potential Impact Zone concept was not included 
in the definition.
    (2) The HCA definition should clarify that it applies to those gas 
transmission pipelines that have the potential to impact high 
population density areas and does not apply to distribution pipelines.
    (3) The identified site component (buildings and outside areas) is 
overly broad. The definition should instead use the language in 192.5.
    RSPA/OPS believes issuance of this proposed rule will alleviate 
most of the concerns raised in the petition. As previously discussed, 
the HCA rule only defines general areas of high consequence. It 
includes corridors (lateral distances of 300, 660, and 1000 feet), but 
not axial distances along the pipeline. The axial distances can only be 
determined by analysis of potential

[[Page 4296]]

impact zones which are covered in this proposed rule. We have put the 
proposed potential impact zones definition under the same section 
192.761, where HCAs are defined.
    The petitioners argued it would be difficult to identify a building 
or outside area that is frequented by 20 or more persons on at least 50 
days in any 12-month period, and would include isolated and 
infrequently occupied buildings. RSPA/OPS does not know how many rural 
buildings would be covered by the HCA definition or how many miles of 
pipeline segments would have to be added to the assessment plans to 
include these buildings which are populated for a short time relative 
to the other populated areas. We are trying to focus on high risk areas 
for assessment. Instead of including rural buildings, such as rural 
churches as High Consequence Areas, we could designate them as Moderate 
Risk Areas requiring less frequent assessment or requiring enhanced 
preventive and mitigative measures only. We would like public comment 
on this issue. We are proposing to define a Moderate Risk Area as an 
area located within a Class 3 or Class 4 location, but not within the 
potential impact zone.
    This proposed rule presents requirements to improve the integrity 
of pipelines located in areas of potentially high consequences that go 
beyond those HCAs. The proposed IMP rule proposes to expand the 
definition of HCA by adding consideration of people living at distances 
greater than 660 feet from large diameter high pressure pipelines. 
Populated areas at distances less than 660 feet are already accounted 
for under Class 3 and 4 locations, however, populated areas beyond 660 
feet were left out of the HCA final rule of August 6, 2002 (67 FR 
50824). In this proposed rule, we are adding a new proposed HCA 
component of populated areas in paragraph 192.761 (g). We are proposing 
to require that an operator consider 20 or more buildings intended for 
human occupancy within an potential impact circle of radius 1000 feet 
or larger. We calculated that 20 buildings within a circular area of a 
1000-foot radius represent a resident density equivalent to 46 
buildings within a rectangular area one mile long and 1320 feet wide 
(current Class 3 location definition). Therefore, by using 20 or more 
buildings within circular area of radius 1000 feet we are, including 
areas having the same density of population as Class 3 locations.
    To understand the provisions of this proposed rule, it is necessary 
to understand both the pipe segments covered by the proposal and the 
ranking of integrity improvement requirements for those pipe segments. 
The approach involves the six steps that rely on the definitions below: 
(1) Identify all HCAs for the pipeline using the HCA definitions as 
expanded by this proposed rule; (2) calculate the Potential Impact 
Radius (PIR) for each segment in the pipeline; (3) determine the 
Threshold Radius associated with the PIR for each segment; (4) identify 
Potential Impact Circles for the pipeline; (5) identify Potential 
Impact Zones (PIZ) for the pipeline and in Class 3 and Class 4 
locations, identify the moderate risk areas; and (6) determine the 
priority of each segment covered by this proposed rule--covered 
segments located within a potential impact zone are considered higher 
priority, whereas those located outside a PIZ are considered lower 
priority.
    The following proposed definitions help to understand these six 
steps:
    Potential Impact Circle (PIC)--PIC is a circle of radius equal to 
the threshold radius used to establish higher priority areas within 
HCAs. A potential impact circle contains any of the following (for 
greater clarity see the diagram in Appendix E):
    [sbull] 20 or more buildings intended for human occupancy within a 
circle of radius 1000 feet, or larger if the threshold radius is 
greater than 1000 feet;
    [sbull] A facility that houses people who are difficult to evacuate 
as defined in Sec.  192.761; or
    [sbull] A place where people congregate as defined in Sec.  
192.761.
    Potential Impact Radius (PIR)--PIR means the radius of a circle 
within which the potential failure of a pipeline could have significant 
impact on people or property. PIR is determined by the formula r = 0.69 
* (square root of (p*d\2\)), where ``r'' is the radius of a circular 
area surrounding the point of failure (ft), ``p'' is the maximum 
allowable operating pressure (MAOP) in the pipeline segment (psi), and 
``d'' is the diameter of the pipeline (inches). (Note: 0.69 is the 
factor for natural gas. This number will vary for other gases depending 
upon their heat of combustion. An operator transporting gas other than 
natural gas must use Section 3.2 of ASME/ANSI B31.8S to calculate the 
impact radius formula).
    Potential Impact Zone (PIZ)--PIZ is a rectangular area along the 
pipeline derived from the potential impact circle. The potential impact 
zone extends axially along the length of the pipeline from the center 
of the first potential impact circle to the center of the last 
contiguous potential impact circle, and extends perpendicular to the 
pipe out to the threshold radius on either side of the centerline of 
the pipe. For greater clarity see the diagram in Appendix E.
    Threshold Radius--Threshold Radius is a bounding radius intended to 
provide an additional margin of safety beyond the distance calculated 
to be the potential impact radius. If the calculated potential impacted 
radius is less than 300 feet, the operator must use a threshold of 300 
feet. If the calculated potential impacted radius exceeds 300 feet but 
is less than 660 feet, the threshold is 660 feet. If the calculated 
potential impacted radius exceeds 660 feet, but is less than 1000 feet, 
the threshold is 1000 feet. And, if the calculated potential impact 
radius exceeds 1000 feet, the threshold is 15% greater than the actual 
calculated impacted radius.

Pipeline Integrity Management in High Consequence Areas--Proposed 
Section 192.763

    The proposed new Sec.  192.763 titled ``Pipeline integrity 
management in high consequence areas'' imposes integrity management 
program requirements on all gas transmission pipelines covered under 
Part 192 that impact high consequence areas.
    The proposed rule requires an operator of a transmission line to 
develop and follow an integrity management program that provides for 
continually assessing the integrity of all pipeline segments in the 
high consequence areas using internal inspection, pressure testing, 
direct assessment or other equally effective assessment means. The 
proposed rule further requires that the program provide for evaluating 
the entire range of threats to the integrity of each pipeline segment 
through comprehensive information analysis. Further, for each covered 
pipeline segment, the operator must provide additional protection to a 
pipeline segment's integrity though remedial actions and enhanced 
preventive and mitigative measures.
(a) Which Operators Must Comply? Proposed Sec.  192.763(a)
    The rule proposes that any operator of a gas transmission pipeline 
must comply with the integrity management program requirements.
(b) Which Pipeline Segments are Covered? Proposed Sec.  192.763(b)
    Any gas transmission pipeline located in a high consequence area, 
including transmission pipelines transporting petroleum gas, hydrogen, 
and other gas products covered under Part 192. Gas transmission is 
defined in Sec.  192.3, and

[[Page 4297]]

includes pipelines within storage fields as transmission lines. Thus, 
this proposed rule covers pipelines within storage fields. Pipeline, by 
definition, means all parts of those physical facilities through which 
gas moves in transportation, including pipe, valves and other 
appurtenances attached to pipe, compressor units, metering stations, 
regulator stations, delivery stations, holders, and fabricated 
assemblies. The proposed rule does not apply to gas gathering or to gas 
distribution lines.
(c) What Must an Operator Do? Proposed Sec.  192.763(c)
    The rule proposes that no later than one year after the effective 
date of the final rule, each operator is required to establish a 
written integrity management program that addresses the threats on each 
pipeline segment that could impact a high consequence area. The 
operator would then implement and follow the program it has developed. 
Initially, the program would consist of a framework. Within one year 
after the final rule becomes effective, we would expect an operator's 
integrity management program to consist of:
    [sbull] Identification of all pipeline segments that are in a high 
consequence area as defined in Sec.  192.761 (and expanded by this 
proposed rule). It would also include categorization of whether these 
segments fall into a potential impact zone. All segments identified 
will be required to have enhanced integrity protection. The 
identification of potential impact zones is required to determine the 
length of baseline assessment intervals for these segments. Because 
identification of the pipeline segments is the trigger for all other 
integrity management requirements, the identification must be done 
within one year from the final rule's effective date. When evaluating 
the consequences of a failure within the potential impact zone the 
operator refer to Section 3.3 of ASME/ANSI B31.8S for a minimum set of 
consequence factors to consider.
    [sbull] A program framework that addresses each of the required 
program elements, including continual integrity assessment and 
evaluation. The framework is required to document how decisions will 
initially be made to implement each element. To be effective, an 
integrity management program must constantly change. RSPA/OPS expects 
that the initial program will consist of a framework that specifies the 
criteria for making decisions to implement each of the required 
elements. The program evolves from the framework and must continue to 
change to reflect operating experience, conclusions drawn from results 
of the integrity assessments, and other maintenance and surveillance 
data, and evaluation of consequences of a failure on the high 
consequence area. In addition, the program must evolve to reflect the 
best practices used in the pipeline industry to assure pipeline 
integrity. An operator will have to document any change it makes to its 
program before implementing the change. In addition, if a change is 
significant enough that it affects the program's implementation or 
significantly modifies the program, the operator must notify OPS within 
30 days of adopting the change into its program. An initial decision on 
the type of assessment method an operator is going to use is not 
considered a significant change.
    [sbull] A plan for baseline assessment of the pipeline. The plan 
must identify segments to be assessed, applicable threats for each 
segment, method(s) selected to assess each pipeline segment (including 
internal inspection tool or tools, pressure test, direct assessment, or 
other technology that the operator demonstrates can provide an 
equivalent understanding of the condition of the line pipe), the basis 
on which each assessment method was selected, and a schedule for 
completing the baseline integrity assessment. An operator would also 
have to show that it is conducting the assessment in a manner that 
minimizes environmental and safety risks. See also the preamble 
discussion under section 192.763(e).
    [sbull] A direct assessment plan for operators intending to use one 
of the direct assessment processes, describing how these processes will 
be used, including identification of External Corrosion Direct 
Assessment Regions.
    To carry out the requirements of the proposed rule, an operator 
would, where specified, follow the prescriptive requirements of ASME/
ANSI B31.8S, and its appendices, unless the proposed rule provides 
otherwise, or the operator demonstrates that an alternative practice is 
supported by a reliable engineering evaluation and provides an 
equivalent level of safety for the public and their property.
    Performance-Based Option. ASME/ANSI B31.8S provides the essential 
features of both a performance-based and a prescriptive integrity 
management program. The proposed rule allows an operator to use a 
performance-based approach if the operator satisfies certain 
exceptional performance requirements. If the operator satisfies these 
requirements, the proposal would allow an operator to deviate from 
certain integrity management performance requirements--the time frame 
for reassessment, as long as a confirmatory direct assessment were done 
every seven years, using direct assessment as a primary method without 
having to satisfy the pre-conditions and the time frames for 
remediating anomalies found during the assessment.
    [sbull] Exceptional Performance. To show exceptional performance 
the rule proposes that an operator have completed a baseline assessment 
of all covered pipeline segments, and at least one other assessment; 
remediate all anomalies identified in the second assessment according 
to specified requirements; and incorporate the results and lessons 
learned from the second assessment into the operator's risk model. An 
operator would also have to demonstrate that it has an exceptional 
integrity management program that meets the performance-based 
requirements of ASME/ANSI B31.8S, has a history of measurable 
performance improvement, and includes, at minimum:
    (A) A state-of-the-art process for risk analysis;
    (B) all risk factor data used to support the program;
    (C) a state-of-the-art data integration process;
    (D) a process that applies lessons learned from assessment of 
covered pipe segments to pipe segments not covered by this section;
    (E) a process for evaluating all incidents, including their causes, 
within the operator's sector of the pipeline industry for implications 
both to the operator's pipeline system and to the operator's integrity 
management program;
    (F) a performance matrix that confirms the continuing performance 
improvement realized under the performance-based program;
    (G) a set of performance measures beyond those that are required 
that are part of the operator's performance plan and are made 
accessible in real time to OPS and state pipeline safety enforcement 
officials; and
    (H) an analysis that supports the desired integrity reassessment 
interval and the remediation methods to be used for all pipe segments.
(d) What Are the Elements of an Integrity Management Program? Proposed 
Sec.  192.763(d)
    The proposed rule requires an operator to include certain minimum 
elements in its integrity management program that are either specified 
in the proposed rule or in the ASME/ANSI B31.8S standard. Initially, an 
operator

[[Page 4298]]

must develop a framework describing these elements. The framework 
describes how each element of the program will be carried out initially 
and documents expected near-term improvements to be implemented to 
these processes. Over time, this framework evolves into a program 
description as the operator learns from its experience and that of 
other operators, and incorporates that knowledge into an ever-improving 
process description. The proposed required program elements include:
    [sbull] A process for identifying all potential threats to pipeline 
integrity in each high consequence area. Section 2.2 of ANSI/ASME 
B31.8S standard describes how all significant threats to the pipeline 
can be grouped into 9 categories. It further regroups these 9 
categories of threats into three types: time dependent threats (e.g., 
external corrosion, internal corrosion, stress corrosion cracking); 
stable or static threats (e.g., manufacturing related defects 
(defective pipe seam, defective pipe), welding/fabrication related 
(defective girth or fabrication weld, wrinkle bend , etc.), equipment 
failure (gasket, control/relief valve, pump seal, etc.); and time 
independent threats (e.g., third party damage).
    [sbull] A baseline assessment plan (discussed in Sec.  192.763(e).
    [sbull] Criteria for remedial actions to address integrity issues 
raised by the assessment methods and information analysis, (criteria 
for repair are discussed in B31.8S, Section 7). These criteria 
recognize that the nature and timing of action related to a defect 
depend on the severity of the defect. Some require immediate action, 
some require mitigation over a prescribed period, and some must be 
monitored to ensure they do not represent a future threat to the 
integrity of the pipeline. ASME B31.8S, Section 7, also recognizes that 
the repair threshold an operator chooses for taking action on a 
recognized defect is related to the time acceptable before a follow-up 
reassessment is performed. If only very small defects are not mitigated 
in the pipe, then a longer time is acceptable before reassessment is 
needed. Repair criteria in Section 7 of ASME B31.8S reflect the current 
reality that developing assessment techniques, such as direct 
assessment, are not yet as mature as in-line-inspection and pressure 
testing. Therefore, operators choosing direct assessment must either 
excavate all indications, or they must reassess their pipe at shorter 
time intervals.
    [sbull] A risk analysis that considers all available information 
about the integrity of the entire pipeline, evaluates its relevance to 
each segment within an HCA, and estimates the likelihood and 
consequences of a failure. Requirements and guidance on the gathering, 
review and integration of risk factor data is provided in ASME B31.8S, 
Section 4. Acceptable approaches to analyzing the risks associated with 
each segment are presented in ASME B31.8S, Section 5. The purpose of 
this analysis is to utilize the best available information, including 
operating experience on the entire pipeline, to determine the 
susceptibility to failure of each segment to each potential threat, 
then to estimate the relative magnitude of the threat so assessment 
actions can be prioritized.
    [sbull] A continual process of assessment and evaluation to 
maintain a pipeline's integrity: Reassessment intervals for different 
assessment techniques, pipe stress levels and characteristics of 
residual defects (e.g., predicted failure pressure, hydro-test 
pressure, or DA repair scope) are discussed in ASME B31.8S, Section 8, 
and summarized in Table 8-1.
    [sbull] Identification of preventive and mitigative measures to 
protect the high consequence area: ASME B31.8S presents an extensive 
listing of preventive measures in Section 7. RSPA/OPS expects each 
operator to evaluate the value of instituting these practices in the 
light of information on threats posed to each segment and to implement 
applicable and cost-beneficial measures.
    [sbull] A performance plan, including methods to measure the 
effectiveness of the program: Performance measurement is treated in the 
discussion of performance planning in Section 9 of ASME B31.8S, and 
candidate measures for each threat are presented in Appendix SP-A.
    [sbull] A process for review of integrity assessment results and 
information analysis by a person qualified to evaluate the results and 
information. An operator must use qualified persons with the necessary 
technical expertise to evaluate and analyze the results and data from 
the integrity assessments, the periodic evaluation, the information 
analyses, etc. Qualifications for these people must be documented and 
records made available to verify qualifications.
    [sbull] A management of change process, as outlined in ASME/ANSI 
B31.8S, Section 11.
    [sbull] A quality assurance process, as outlined in ASME/ANSI 
B31.8S, Section 12.
    [sbull] A communication plan that includes the elements of ASME/
ANSI B31.8S, Section 10, and that includes a process for addressing 
safety concerns raised by OPS, including safety concerns OPS raises on 
behalf of a State or local authority with which OPS has an interstate 
agent agreement.
    [sbull] A process for providing, by electronic or other means, a 
copy of the operator's integrity management program to a State 
authority with which OPS has an interstate agent agreement.
    [sbull] A process for ensuring that each integrity assessment is 
being conducted in a manner that minimizes environmental and safety 
risks.
    One of the most important elements of an integrity management 
program is operator qualification. This proposed rule requires an 
operator to verify that supervisors possess and maintain a thorough 
knowledge of the integrity management program and its elements for 
which they are responsible. Individuals who qualify as supervisors for 
any aspect of integrity management programs must have appropriate 
training or experience in that area. This proposed rule requires the 
operator to document requirements for these supervisory individuals and 
others, who are responsible for gathering and interpreting the results 
of integrity assessments.
(e) What Must Be in the Baseline Assessment Plan? Proposed Sec.  
192.763(e)
    The proposed rule requires that an operator must include in its 
written baseline assessment plan each of the following elements:
    [sbull] Potential threats to the integrity of each pipeline 
segment. Candidate threats are discussed in this section under Sec.  
192.763(f).
    [sbull] The method or methods selected to assess the integrity of 
the line pipe in the high consequence area. The integrity assessment 
method(s) used must be based on threats to which the segment is 
susceptible. More than one method and/or tool may be required to 
address all the threats in the pipeline segment. An operator must 
assess the integrity of the line pipe by: internal inspection tool or 
tools capable of detecting corrosion, and any other threats to which 
the pipe segment is susceptible; pressure test conducted in accordance 
with subpart J; direct assessment in accordance with the proposed 
requirements; or other technology that the operator demonstrates can 
provide an equivalent understanding of the condition of the line pipe. 
An operator choosing to use the other technology option must notify 
RSPA/OPS 180 days before conducting the assessment. RSPA/OPS expects an 
operator to make the best use of current and innovative technology in 
assessing the integrity of the line pipe.

[[Page 4299]]

    [sbull] A schedule for completing the integrity assessment.
    [sbull] An explanation of the assessment methods the operator 
selected and an evaluation of risk factors the operator considered in 
establishing the assessment schedule for the pipeline segments.
    [sbull] For an operator using direct assessment, a plan that takes 
into consideration the definition of ECDA and ICDA Regions and the 
complementary tools to be used for each ECDA regions.
    [sbull] A process describing how the operator is ensuring that the 
baseline assessment is being conducted in a manner that minimizes 
environmental and safety risks (e.g., where would launchers and 
receivers be placed; how the operator plans to dispose of hydrostatic 
test water; how low point drains would be tested; what extra attention 
would be given during excavations.). This proposed requirement applies 
to any assessment method the operator uses and to the reassessments, 
not just the baseline assessment.
    Direction on the analysis of threats, including the data 
requirements, and on the selection of assessment techniques is provided 
in ASME B31.8S, Appendix SP-A.
    Internal inspection is one of the most useful tools in an integrity 
management program. Depending on the threats present, RSPA/OPS expects 
an operator, with pipelines that are piggable or that can easily be 
made piggable, to consider using geometry tools (for detecting changes 
in circumference) and metal loss tools (for determining wall anomalies, 
or wall loss due to corrosion). Both high resolution and low resolution 
metal loss tools can be beneficial in integrity assessment. For details 
of each internal inspection tool, including their selection, 
capabilities, effectiveness, and use, operators should refer to Section 
6 of the ANSI/ASME B31.8S. This standard discusses corrosion/metal loss 
tools for internal and external corrosion threat, crack detection tools 
corrosion cracking threat, metal loss or geometry tool for third party 
and mechanical damage threat.
    This proposed rule will allow ``other technology'' as one of the 
four methods to assess the condition of pipeline segments that could 
impact high consequence areas. RSPA/OPS expects that as these tools are 
developed they may become useful assessment tools or as complements to 
direct assessment tools. We expect these tools could be used where 
internal inspection tools cannot be used, where pressure testing is not 
feasible, and where only one type of currently proven direct assessment 
tool could be used or where pipeline is not easily accessible for 
direct assessment. Some examples of such applications are, cased piping 
(i.e., under either a river or road crossing), pipe in frozen ground or 
where bare pipe needs to be examined. Two examples of emerging 
technologies currently being reviewed and evaluated by RSPA/OPS are: 
(1) Long-range ultrasonic testing or guided wave ultrasonic testing for 
in-service monitoring of corrosion and other metal loss defects; and 
(2) ``No-Pig'' technology, a tool that can determine internal and 
external corrosion of the pipeline from above ground.
(f) How Does an Operator Identify Potential Threats to Pipeline 
Integrity? Proposed Sec.  192.763(f)
    The proposed rule requires each operator to identify and evaluate 
all potential threats to pipeline integrity in each area of potential 
high consequence. Threats that an operator must consider include, but 
are not limited to:
    [sbull] Time dependent threats such as internal corrosion, external 
corrosion, and stress corrosion cracking;
    [sbull] Static or resident threats such as fabrication or 
construction defects;
    [sbull] Time independent threats such as third party damage and 
outside force damage; and
    [sbull] The effect of human error.
    The nine threat categories that comprise the first three general 
types of threat are discussed in ASME B31.8S, Appendix SP-A. In this 
Appendix human error is treated as a contributing factor to many of the 
major threats rather than as a separate threat. For example, it may be 
the dominant cause of rupture for third party damage incidents in which 
the equipment operator attempted to locate the pipeline before 
beginning excavation, but was given erroneous information about the 
location of the pipeline. In that Appendix, soil erosion is not treated 
as a separate threat, but viewed as a contributor to making the pipe 
more vulnerable to third party damage or outside force damage. Appendix 
SP-A presents detailed prescriptive requirements for managing the 
integrity of each of the nine threat categories. These requirements 
include the minimum data set needed to evaluate the presence of a 
threat, integrity assessment options, responses and mitigation 
approaches, assessment intervals and candidate performance measures.
    The proposed rule also requires each operator to: (1) Collect data 
needed to evaluate each threat; (2) integrate numerous risk factors; 
(3) evaluate the susceptibility of each affected segment to each 
threat; and (4) prioritize affected segments in accordance with the 
ASME/ANSI B31.8S. The minimum sets of data needed to evaluate each of 
the nine threat categories are presented in Appendix SP-A of that 
standard.
    Data integration requirements in the proposed rule should be 
satisfied by addressing the requirements in ASME/ANSI B31.8S, Section 
4. Data integration must go beyond risk modeling to include 
consideration of specific locations where combination of these risk 
factors may lead to increased risk significance. Examples of data 
integration are presented in Section 4 of the referenced standard.
    Human error analysis required by the proposed rule should follow 
the proposed training requirements.
    If piping with certain material coating and environmental 
characteristics is in an HCA and the assessment shows it to be severely 
corroded, then other similar piping outside the high consequence area 
must also be evaluated, and mitigated as appropriate. This provision is 
critical in ensuring that the knowledge accumulated in implementing the 
integrity management requirements on pipe segments within HCAs is 
effectively utilized to improve integrity throughout the system.
    The following additional requirements and guidance applies to the 
assessment process:
    [sbull] Pipelines exposed to threats that represent higher risks 
should generally be assessed sooner than those with threats that 
represent lower risk. Thus, for the baseline assessment, 50% of covered 
segments (the higher risk segments) will have to be assessed within 
five years if pressure test, internal inspection or alternative 
equivalent technology is used, and within four years if direct 
assessment is used. The determination of which segments are at higher 
risk should be made using methods discussed in ASME B31.8S, Section 5. 
Here several alternative risk assessment approaches are described for 
use in ranking segments for integrity assessment.
    [sbull] 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. These low stress pipes have been shown both by 
fracture mechanics analysis and by evaluation of failure experience 
data to fail by leaking, not by rupture. Therefore, the techniques most 
effective in assuring the integrity of these

[[Page 4300]]

pipelines could reasonably involve a combination of integrity 
assessment techniques and enhanced leak detection.
    [sbull] The proposed rule applies to transmission pipelines, as 
that term is defined in Sec.  192.5. There may be some transmission 
pipelines operating at less than 20% SMYS that are covered by the 
proposed rule. Pipelines operating at that low stress level are 
unlikely to rupture and therefore, pose little risk. We have requested 
comment on establishing longer reassessment intervals for these low 
stress lines.
    [sbull] As a part of its regular surveillance program operators 
would have to determine whether new construction activity or newly 
identified recreational activity may add pipe segments to those that 
can affect an HCA. When such conditions are identified, but no less 
than annually, the operator must reevaluate which pipeline segments can 
affect HCAs.
(g) How Is the Baseline Assessment To Be Conducted? Proposed Sec.  
192.763(g)
    The proposed rule requires that an operator must select the 
assessment technologies best suited to effectively determine the 
susceptibility to failure of each pipe segment that could impact an 
area of potentially high consequences. Assessment tool selection should 
be based first on the threats to which a segment is susceptible, and 
second on which assessment techniques can reasonably be applied. More 
than one method and/or tool may be required to address all the threats 
to which a pipeline segment is susceptible. The order in which 
assessment is carried out must take into account priorities determined 
by a risk assessment. In addition, the proposed rule stipulates that an 
operator must assess the integrity of the line pipe by applying one or 
more of the techniques below depending on the threats to which the 
segment is susceptible:
    [sbull] Internal inspection tool or tools for detecting corrosion 
and deformation anomalies as appropriate. For guidance on selecting 
appropriate internal inspection tools an operator must refer to ASME/
ANSI B31.8S standard.
    [sbull] Pressure test conducted in accordance with subpart J of 
part 192.
    [sbull] Direct assessment method for external corrosion threats, 
internal corrosion threats, stress corrosion cracking, and third party 
damage (if other assessment methods are not feasible). This method must 
be carried out in accordance with the ASME/ANSI B31.8S standard and the 
specified proposed requirements.
    [sbull] Other technology that the operator demonstrates can provide 
an equivalent understanding of the condition of the line pipe. An 
operator choosing this option must notify RSPA/OPS 180 days before 
conducting the assessment.
    The proposed rule requires operators to evaluate and assess for 
third party damage. For gas transmission pipe segments in Class 3 and 4 
locations, the major cause of failure is third party damage. This 
probably results from a higher level of excavation activity in higher 
populated areas, combined with the fact that thicker and stronger pipe 
in classes 3 and 4 are less susceptible to corrosion failure. The vast 
majority of third party damage failures (approximately 90%) occur at 
the time the third party contact occurs. However, a small fraction of 
these failures are delayed after the initial contact (e.g., the rupture 
at Edison, New Jersey). Therefore, some consideration needs to be given 
to delayed failures. The primary cause of delayed failure from third 
party damage is believed to be cyclic fatigue from pressure cycling. 
Gas pipelines are not typically subject to this type of pressure 
fluctuation.
    Given the considerations above, it is clear that lowering the risk 
associated with third party damage requires that the third party damage 
threat must be addressed through comprehensive preventive measures. In 
addition, each operator must evaluate whether cyclic fatigue of 
sufficient magnitude or other loading condition (including ground 
movement, suspension bridge condition) necessitate a periodic 
assessment for dents and gouges. These evaluations must assume the 
presence of deep dents, and determine whether known and anticipated 
loading conditions would lead to failure of such hypothesized dents. 
The results of these evaluations together with the criteria used to 
evaluate the significance of this threat must be documented in the 
operators integrity management plan. Operators must assess segments 
which are vulnerable to delayed failure following third party damage 
using ILI tools such as deformation or geometry tools. Direct 
assessment may be used as primary assessment method for third party 
damage, if no other approach is feasible. Direct assessment has been 
successfully used to screen piping for the presence of significant 
residual third party damage, thereby supporting evaluation of the need 
for additional assessment and focusing on the segments where the use of 
internal inspection tools is most necessary. Under such conditions, it 
may be used in combination with data collection and integration to 
evaluate segment susceptibility to third party damage. In addition, 
operators unable or who believe it unnecessary to use a geometry tool 
must excavate and directly examine indications from ILI runs or from 
direct assessment that are suspected of resulting from third party 
damage. The comprehensive preventive measures employed must be 
documented in the operators integrity management program, and measures 
of their effectiveness established and monitored.
    To address manufacturing and construction defects (including seam 
defects), the rule proposes that an operator must a pressure test at 
least once in the life of the segment unless the operator can document 
in its assessment plan why pressure testing is not required. At anytime 
the historic operating pressure or other stress conditions is 
anticipated to change, then the operator must assess the pipeline using 
appropriate assessment technology prior to making the change in 
operating condition. The methods an operator selects to assess low 
frequency electric resistance welded (ERW) pipe or lap welded pipe 
susceptible to seam failures must be capable of assessing seam 
integrity and of detecting corrosion anomalies.
    The present understanding of the conditions leading to failure from 
materials and construction defects has improved significantly as a 
result of analyzing failure experience. For example, while some pre-
1970 ERW piping has experienced failures resulting from seams defects, 
only certain manufacturers'' pipe has demonstrated susceptibility to 
this type of failure. In addition, a once-in-a-life pressure test has 
proven to significantly lower the likelihood of failure in these 
susceptible pipe segments. Further, piping that has not been hydro-
tested has shown susceptibility only when operating parameters are 
changed significantly. Therefore, careful analysis of industry 
operating experience and comparison of the root causes of historic 
failures with the operators pipe will allow operators to determine the 
risk of failure from these mechanisms. Incident root cause analysis 
also indicates that any anticipated increase in operational pressure 
will require the operator to perform a hydro-test prior to changing 
operational characteristics. This requirement applies even if an 
operator plans to increase operating pressure from the historic level, 
but not to exceed the MAOP.
    Time period. Each operator must prepare a baseline assessment plan 
that documents the order in which each pipeline segment will be 
assessed according to level of risk the segment

[[Page 4301]]

poses. Operators must complete the baseline assessment within the 
specified time frame regardless of the stress level at which the 
pipeline is operating. The plan for conducting the baseline assessment 
must, among other considerations, minimize the impact on gas supply to 
residents.
    [sbull] An operator using pressure test or internal inspection tool 
assessment method on a segment located in an HCA and in the potential 
impact zone must complete the baseline assessment within ten years from 
December 17, 2002 (the date of enactment of the Pipeline Safety 
Improvement Act of 2002). An operator must assess at least 50% of the 
line pipe, beginning with the highest risk pipe, by 5 years from 
December 17, 2002.
    [sbull] An operator using pressure test or internal inspection tool 
assessment method within an HCA but outside of the potential impact 
zone (also known as a moderate risk area) must complete the baseline 
assessment within 13 years from December 17, 2002 (the date of 
enactment of the Pipeline Safety Improvement Act of 2002).
    [sbull] An operator using direct assessment has seven years to 
complete the baseline assessment and has to assess at least 50% of the 
line pipe beginning with the highest risk pipe within four years.
    [sbull] An operator using direct assessment as an assessment method 
on a pipeline segment located within a moderate risk area (area in a 
Class 3 or Class 4 location, but not within the potential impact zone), 
must complete the baseline assessment of the line pipe within 10 years.
    The proposed rule specifies the conditions under which direct 
assessment can be used as a primary assessment tool. The primary reason 
that the shorter time frame for completing the assessment using the 
direct assessment process is that the processes are still 
developmental, and additional information must be gathered on the 
method's effectiveness so that any needed adjustments can be made. 
These adjustments will then be reflected in the second assessment 
process. The seven-year period is based on RSPA/OPS's assessment of the 
minimum time needed to collect and analyze risk factor data, to develop 
internal practices and expertise in application of the processes, and 
to allow the service industry to develop and qualify people needed to 
responsibly apply the processes. The time frame selected is compatible 
with that required for completion of baseline assessments in the 
hazardous liquid pipeline rule. In addition, the riskiest half of the 
covered segments have to be assessed during the first four years of the 
seven-year period.
    Prior assessment. The proposed rule allows an operator to use an 
integrity assessment conducted five years previously from December 17, 
2002 (the date of enactment of the Pipeline Safety Improvement Act of 
2002) as the baseline assessment if the previous integrity assessment 
method meets the proposed requirements. However, if an operator uses 
this prior assessment as its baseline assessment, the operator must 
reassess the line pipe according to the proposed reassessment 
requirements.
    Newly-identified areas. When information is available from the 
information analysis that the population density around a pipeline 
segment has changed so as to fall within the definition in Sec.  
192.761 of a high consequence area, the operator must incorporate the 
area into its baseline assessment plan as a high consequence area 
within one year from the date the area is identified. An operator must 
complete the baseline assessment of any line pipe that could affect the 
newly-identified high consequence area within 10 years (or 7 years if 
direct assessment is being used) from the date the area is identified.
    Background on Direct Assessment. Significant development work was 
carried out during the past two years to expand the use of indirect 
assessment tools (e.g., Close Interval Surveys, Direct Current Voltage 
Gradient, Pipeline Current Mapper, electromagnetic tools) into an 
integrated integrity assessment process capable of identifying pipeline 
defects based on a combination of data analysis and integration, above 
ground assessment, and direct examination. These efforts are resulting 
in the production of an industry consensus standard on External 
Corrosion Direct Assessment, and towards the production of standards on 
direct assessment as applied to internal corrosion and stress corrosion 
cracking.
    RSPA/OPS, along with representatives from several States, 
participated in the standard development process. This participation 
led to the identification of several areas where we believe that 
additional requirements are needed. These additional requirements would 
help ensure the application of the standards is carried out by 
competent practitioners, and that innovations developed by more 
experienced practitioners will be available for use by less experienced 
operators. Additional requirements could also strengthen those areas 
where we believe too much discretion is allowed the operator in 
establishing basic decision criteria needed to apply the Standards. As 
additional experience is gained in the use of direct assessment 
processes, RSPA/OPS can consider relaxing these requirements.
(h) When Can Direct Assessment Be Used and Under What Conditions? 
Proposed Sec.  192.763(h)
    Direct assessment is an integrity assessment method that utilizes a 
process to evaluate certain threats (i.e., external corrosion, internal 
corrosion and stress corrosion cracking) to pipeline integrity. The 
process includes assembly and integration of risk factor data, indirect 
examination or analysis to identify areas of suspected corrosion, 
direct examination of the pipeline in these areas, and post assessment 
evaluation. The process typically makes use of data on the pipeline, 
its environment and its operating history to determine the significance 
of potential threats to integrity and to identify indirect assessment 
techniques (either analytical or above-ground examination) that an 
operator can use to determine where a threat possibly damaged the 
pipeline. Once suspect locations are identified and ranked, then direct 
physical examination determines the extent of damage and the need for 
mitigative action. Each threat to which direct assessment is applicable 
uses a somewhat different process to evaluate the presence of the 
threat.
    While the direct assessment process itself is new, operators have 
used the analytical techniques, above-ground measurement tools, and 
direct examination technologies that the process employs, for many 
years. Examples of above-ground techniques with long prior use include 
close interval surveys (CIS), direct current voltage gradient (DCVG), 
and pipeline current mapper (PCM). Examples of direct examination 
techniques with long prior use include direct physical examination, 
ultrasonic testing, and x-ray examination.
    Why consider allowing the use of direct assessment? Although in-
line inspection (pigging) technologies and pressure testing have been 
used for years, there are several reasons for allowing direct 
assessment as an assessment method.
    INGAA reports that, at present, 24.4% of its members' transmission 
pipelines are already piggable. According to INGAA, another 25.3% can 
easily be made piggable, 45.9% ([sim]82,620 miles) would be very costly 
to pig and 4.4% ([sim]7,920 miles) cannot be pigged. AGA indicates that 
35% of its members' pipelines ([sim]4,725 miles) are not piggable. They 
could only be made

[[Page 4302]]

piggable with extensive modifications, at a cost of between $1M and $8M 
per mile. APGA indicates that the comparable percentage of mileage for 
its members is 46% ([sim]1,380 miles). Based on these industry-provided 
numbers, the cost of making the ``very costly'' lines piggable, 
excluding the increased cost of gas supply due to capacity 
restrictions, can be estimated to be between $88B and $710B. While 
these numbers are exceedingly large and rely on the AGA costs, 
developed for making difficult to pig lines piggable in urban areas, 
they do indicate that much work on existing lines would be needed to 
make all gas transmission lines piggable using today's ILI technology. 
INGAA also argues that pressure testing much of the currently non-
piggable pipeline could be costly or impractical because of service 
interruptions needed to complete the hydro-test, and because the 
process introduces electrolytes into the system that will be difficult 
to completely remove, thereby increasing the likelihood for future 
internal corrosion.
    In addition to the feasibility of ILI and the costs associated with 
making lines piggable, the cost to consumers and the potential of 
critical supply interruptions are other factors in the RSPA/OPS 
decision to allow direct assessment. The INGAA study, as mentioned 
previously, evaluated the cost to consumers associated with capacity 
restrictions resulting from gas pipe integrity assessment. This study 
evaluated capacity restrictions and related consumer cost impacts for 
integrity assessment scenarios involving different mixes of ILI, hydro-
test and direct assessment technologies. For a baseline assessment time 
frame of ten years, the study determined that the difference in cost to 
the consumer (excluding the cost of making lines piggable) between 
conducting direct assessment on twenty-five percent and zero percent of 
piping would be over two billion dollars. Some supply interruptions 
could also result if direct assessment were not allowed as an 
alternative assessment technology.
    What threats are direct assessment capable of characterizing? Work 
jointly funded by the gas pipeline industry and RSPA/OPS is ongoing to 
develop, validate and standardize the application of the direct 
assessment process to the assessment of external corrosion (ECDA) and 
internal corrosion (ICDA). Future work is planned to develop, validate 
and standardize a direct assessment process for application to the 
stress corrosion cracking (SCCDA) threat. Furthermore, significant 
anecdotal evidence exists that the ECDA process may be capable of 
identifying coating damage associated with third party impacts on the 
pipeline, but formal validation of this capability has not yet been 
performed.
    The current strategy, being incorporated in the developing 
consensus standard for external corrosion direct assessment for use 
with the ECDA process, is to locate areas suspected of having external 
corrosion by identifying defects in the pipe coating, then excavating 
those defects in areas where corrosion activity is suspected. While all 
indications discovered by ECDA that are not adequately protected by the 
cathodic protection system at the time of the assessment will be 
excavated and directly examined, only a fraction of the ECDA 
indications that are protected by cathodic protection systems at the 
time of the assessment will be excavated. This excavation strategy is 
incorporated in the draft NACE consensus standard on ECDA. The draft 
standard describes the process by which operators make decisions on the 
need for continued excavation of features in an ECDA region, based on 
the severity of defects revealed in previous excavations. If excavation 
of the indications that are expected to be most severe reveal no 
significant pipe damage, then further excavations in that region are 
not necessary. If excavation continues to reveal significant pipe 
damage, then a larger fraction of protected indications would be 
excavated.
    An approach is under development by the Gas Technology Institute 
(GTI) for ultimate incorporation in a NACE consensus standard to locate 
internal corrosion (ICDA). The process, using direct assessment, is 
focused exclusively on pipe transporting nominally clean dry gas, in 
which moisture (electrolyte) has been introduced by abnormal operation. 
Further, it assumes that internal corrosion will only occur if moisture 
is present at the location in question. The Southwest Research 
Institute, under GTI funding, developed a mathematical model to predict 
locations where moisture would accumulate along the line, if it were 
introduced during an upset condition. These models, together with a 
common sense approach to identifying other pockets where moisture might 
accumulate, are to be used to identify areas where excavations and 
direct examination is required. While not yet validated, this approach 
is drawn from industry experience and is based on reasonable 
assumptions about the most likely location of internal corrosion.
    There is a need for alternative assessment technologies capable of 
finding and characterizing pipe defects. RSPA/OPS decided to allow 
selective use of direct assessment for application in characterizing 
certain integrity-threatening defects in pipe that cannot (for economic 
or operational configuration) be pigged or hydro-tested. The conditions 
for use of direct assessment are based on draft NACE consensus 
standards with additional requirements that reflect the developmental 
nature of the processes.
Under What Conditions Can Direct Assessment Be Used?
    The proposed rule proposes to allow an operator to use direct 
assessment as a supplement to the other allowable assessment methods, 
and to use direct assessment as a primary assessment method for 
external corrosion, internal corrosion, or stress corrosion cracking 
only when the operator can demonstrate that a specified condition 
exists. These conditions are when the other assessment methods cannot 
be applied to the pipeline segment for economic or technological 
reasons; the other assessment methods would result in a substantial 
impact on gas customers; excavation and direct examination will be done 
on the entire covered pipeline segment; or the covered pipeline segment 
operates at a maximum allowable operating pressure below 30% SMYS. To 
use direct assessment as a primary method for external corrosion, 
internal corrosion or stress corrosion cracking, the operator has to 
follow ASME/ANSI B31.8S and additional requirements set forth in the 
proposed rule.
    In addition, to use direct assessment as the primary assessment 
method for third party damage, an operator has to show that no other 
assessment method is feasible, and that the operator will combine the 
method with data collection and integration to evaluate the segment's 
susceptibility to third party damage.
    An operator choosing the external corrosion direct assessment 
(ECDA) method as its primary assessment technology must prepare a 
detailed plan in which the following information is documented:
    [sbull] Data requirements for using ECDA; these must include as a 
minimum the data requirements specified in Appendix SP-A1 for external 
corrosion in ASME B31.8S.
    [sbull] Criteria for evaluating ECDA feasibility.
    [sbull] Criteria for defining ECDA Regions. Further discussion is 
presented later in this section.

[[Page 4303]]

    [sbull] The basis on which two complementary tools are selected for 
assessing each ECDA Region. Further information is in Appendix E.
    [sbull] Criteria for identifying and documenting indications that 
must later be characterized for severity and considered for direct 
examination. These criteria must consider, as a minimum, the known 
sensitivities of assessment tools, the procedures for the use of each 
tool, and the approach to be used for decreasing the physical spacing 
at which indirect assessment tool readings are to be taken when 
presence of a defect is suspected.
    [sbull] Criteria for characterizing indications identified in the 
ECDA process. These criteria must define how an indication will be 
characterized as severe, moderate or minor.
    [sbull] Criteria for defining the urgency of excavation and direct 
examination of each indication. These criteria must define the urgency 
of excavating the indication as immediate, scheduled or monitored.
    [sbull] Criteria for scheduling excavation of each urgency level of 
indication. These criteria are discussed at greater length below.
    [sbull] Criteria for data gathering associated with each 
excavation.
    [sbull] Criteria for the qualification of people who carry out and 
interpret the results from the direct assessment process.
    [sbull] Criteria and measures for long-term process effectiveness 
evaluation.

Completion of the Following Four Steps

    Step 1: Pre-Assessment--As part of the Pre-Assessment step, the 
pipeline operator must analyze and integrate the risk factor data to 
determine whether conditions exist that would preclude the effective 
use of ECDA. The following conditions may rule out ECDA application or 
make it difficult to apply. Should any of these conditions exist, the 
operator must document in the ECDA Plan why ECDA is considered to be 
valid and the special provisions it will implement to ensure ECDA 
effectiveness.
    [sbull] The presence of coatings that cause electrical shielding;
    [sbull] Backfill around the pipe with significant rock content or 
the presence of rock ledges;
    [sbull] Situations impeding timely above-ground data gathering;
    [sbull] Locations with adjacent buried metallic structures; and
    [sbull] Inaccessible areas.
    As part of the Pre-Assessment step, the operator must select at 
least two different indirect examination methods for each location 
where ECDA is to be applied along the pipeline. These methods must be 
selected based on their ability to detect external corrosion activity 
and deficiencies in the pipe coating under the conditions expected to 
be encountered. The tools selected must be complementary, such that the 
strengths of one tool overlap the limitations of the other. Appendix E 
presents information to support selection of the two complementary 
tools. A few examples of indirect examination tools are Close Interval 
Surveys (CIS), Direct (or Alternate) Current Voltage Gradient (DCVG or 
ACVG), and electromagnetic techniques (e.g., Pipeline Current Mapper 
(PCM) and C-Scan).
    Direct assessment with only one inspection tool will be permitted 
to assess for external corrosion only if the operator develops and 
documents a plan specifying and justifying the special tool or tools 
being used. The conditions where this deviation is permitted are as 
follows:
    [sbull] Pipe in frozen ground;
    [sbull] Pipe under paved roadways; and
    [sbull] Pipe in cased crossings (either road or river).
    ECDA Region: As part of the Pre-Assessment step, the operator must 
define ECDA regions. An ``ECDA Region'' is a portion of a pipeline, not 
necessarily contiguous, that has similar physical characteristics, 
operating and corrosion history, expected future corrosion conditions, 
and in which the same indirect assessment tools are used. Due to their 
similarity, these regions will be used in each of the remaining three 
steps in the ECDA process. In these subsequent steps, ECDA regions are 
used to support aggregation and evaluation of indirect and direct 
examination data. Additionally, ECDA regions may be redefined, or the 
ECDA process may be determined to be inapplicable for an entire region.
    Step 2: Indirect Examination--The operator must carry out the 
indirect examination step using the tools selected for each ECDA 
Region. In defining the boundaries for use of each pair of ECDA tools, 
the operator must ensure completeness of coverage by providing for some 
overlap between adjacent regions. The following additional provisions 
must be incorporated when the ECDA process is applied to a segment of 
pipe:
    [sbull] Repeat indirect inspections on a sample basis to ensure 
consistent data are obtained.
    [sbull] Select intervals for capturing tool readings that are 
closely spaced enough to ensure consistent data are obtained. Data 
sampling intervals (locations of test points) for indirect examination 
tools should typically be no greater than the local depth of coverage 
of the pipeline.
    [sbull] Indirect inspections using the two complementary tools in 
an ECDA Region should be carried out as close together in time as 
practical.
    [sbull] Above ground measurements should be geo-referenced and 
documented so inspection results can be compared and excavation 
locations accurately identified.
    After indirect examination measurements are completed for an ECDA 
Region, the operator must align the measures taken with the 
complementary tools and evaluate the consistency of the observations 
using the following guidance:
    [sbull] If the results from the two complementary tools are not 
consistent and cannot be explained by differences in the capabilities 
of the tools, then either direct examination or additional indirect 
inspections must be used to evaluate the reasons for the differences.
    [sbull] If additional indirect inspections or direct examinations 
are not carried out or if they do not resolve the inconsistencies, then 
the feasibility of ECDA must be reevaluated.
    [sbull] Indications must be identified and located following 
indirect inspection, and the severity of each indication must be 
classified as severe, moderate or minor using the criteria in the ECDA 
Plan.
    [sbull] These classifications should be conservatively developed 
the first time the process is applied. Results from the Pre-Assessment 
step (Step 1) must next be compared with prior history for each ECDA 
Region.
    [sbull] If assessment results are not consistent with operating 
history, then the operator must reassess the feasibility of ECDA.
    Step 3: Direct Examination (Excavation and Data Gathering)--The 
operator must next use the results from the indirect examination step 
to develop and carry out a direct examination plan. The activities to 
be included in this step are listed below:
    [sbull] The order and timing of excavations in the direct 
examination step must be determined from results of the indirect 
examination step. Both order and timing are derived from a 
classification of the indications. Criteria developed in the ECDA Plan 
must be used to determine whether each indication is classified as 
requiring immediate action, scheduled action or monitoring.
    [sbull] All indications that are categorized as ``immediate 
action'' require direct examination (excavation). Should any of these 
indications be associated with defects that require immediate 
mitigation, the operator must reduce

[[Page 4304]]

operating pressure by at least 20% in the associated ECDA Region and 
not exceed this pressure until 100% of such indications are excavated, 
evaluated and mitigated as necessary.
    [sbull] All excavations of ``immediate action'' indications must be 
carried out promptly after indirect examination step is complete. An 
operator must take prompt action to address all anomalous conditions 
found.
    [sbull] A minimum of one direct examination (excavation) is 
required for each ECDA Region. This examination must be made at the 
most severe indication, based on risk evaluation of the indications. If 
no indications are shown in the ECDA Region, then the excavation must 
be made at a location that the operator considers to be the most 
suspect.
    [sbull] At least two indications found in each ECDA Region 
categorized as ``scheduled action,'' require direct examination. 
Excavation of ``scheduled action'' indications must continue, in 
priority order, until at least two indications are excavated having 
corrosion of depth no greater than 20% of the wall thickness.
    [sbull] The operator must collect all data specified in its ECDA 
Plan for each excavation completed. These data are to be used in 
determining the nature and timing of remediation as well as in the 
fourth step of the ECDA process, the Post Assessment step.
    [sbull] Except for conditions specified in the body of the rule 
Section (h)(4), the operator must carry out remediation on a time frame 
and in a manner specified by ASME B31.8S. Remedial action must be 
consistent with a determination of remaining strength using ASME B31G, 
RSTRENG, or equivalent.
    [sbull] If any exposed segment has significant coating degradation 
or corrosion, then the operator must increase the size of that 
excavation until coating and pipe are determined to be adequate.
    [sbull] The operator must identify the root cause of all 
significant corrosion activity revealed by excavation.
    [sbull] When ECDA identifies any defect in an ECDA Region that 
requires immediate mitigation, or when the root cause of any defect is 
a condition that ECDA is ineffective at assessing (e.g., MIC or 
shielded corrosion), then an alternate assessment technology must be 
used for that ECDA Region.
    Step 4: Post-Assessment--The operator must carry out a Post 
Assessment step to determine the reassessment interval and to evaluate 
the overall effectiveness of the ECDA process. In carrying out this 
step, the following requirements apply:
    [sbull] The reassessment interval must be determined based on the 
largest defect remaining in the pipe segment and on the corrosion rate 
appropriate for the pipe, soil and protection conditions. The largest 
remaining defect must be taken to be the size of the largest defect 
discovered in the ECDA segment. The corrosion growth rate must be 
conservatively estimated based on data taken during the direct 
examination. The reassessment interval must be estimated as half the 
time required for the largest defect to grow to a critical size.
    [sbull] An operator that directly examines and appropriately 
remediates defects consistent with the sampling provisions presented in 
this rule must reassess each segment at an interval not to exceed every 
five years.
    [sbull] An operator that examines all anomalies by excavation and 
remediates these anomalies may be allowed to extend the reassessment 
interval from 5 years, as specified in the main body of the rule, 
paragraph (g)(4)of the proposed rule, to as much as 10 years.
    [sbull] The operator must define and monitor measures to determine 
the effectiveness of the ECDA process. Measures should be developed to 
track: (a) The effectiveness of the overall process (e.g., the change 
in the calculated reassessment interval); (b) the extent and severity 
of corrosion found; (c) the number of indications in each 
classification located on successive applications of ECDA; and (d) the 
time from discovery of an indication categorized as immediate action or 
scheduled action to its excavation.
    Additional Documentation Requirements: In addition to the ECDA 
Plan, the operator must document all data on Pre-Assessment, Indirect 
Examination, verification of indirect examination by excavation, Direct 
Examination and Post-Assessment, and performance measures. The operator 
must also have procedures documenting communications requirements among 
various organizations conducting each step of the direct assessment 
process.

Internal Corrosion Direct Assessment

    Internal corrosion direct assessment (ICDA) is a process that 
identifies areas along the pipeline where water or other electrolyte 
introduced by an upset condition may reside, then focuses direct 
examination on the locations in each area where internal corrosion is 
most likely to exist. If no evidence of internal corrosion exists in 
these most likely locations, then the entire section can be considered 
to be free of internal corrosion. An operator using direct assessment 
as a method to address internal corrosion in a pipeline segment must 
follow the requirements in ASME/ANSI B31.8S, Appendix SP-B2, and in 
this section.
    For internal corrosion direct assessment, in addition to 
requirements in ASME/ANSI B31.8S, Appendix SP-B2, an operator must 
carry out the process described below. This process consists of four 
steps: pre-assessment, identification of ICDA regions and excavation 
locations, direct examination, and post assessment and continuing 
evaluation. The process is designed to evaluate potential for internal 
corrosion caused by water, CO2, O2, chlorides, hydrogen sulfide and 
other contaminants present in the gas, as well as MIC.
    Step 1: Pre-assessment--The first step in the ICDA process is pre-
assessment. In this step the operator gathers information needed to 
support identification of areas where internal corrosion is most likely 
to exist. This step requires the operator to:
    [sbull] Gather all data elements listed in Appendix SP-A2 of ASME/
ANSI B31.8S.
    [sbull] Assemble information needed to determine where internal 
corrosion is most likely to occur including: (a) Location of all gas 
input and withdrawal points on the line; (b) location of all low points 
on the line such as sags, drips, inclines, valves, manifolds, dead-
legs, and traps; (c) the elevation profile of the pipeline in 
sufficient detail that angles of inclination can be calculated for all 
pipe segments; (d) the diameter of the pipeline, and the range of 
expected gas velocities in the pipeline.
    [sbull] Assemble and evaluate operating experience data that would 
provide an indication of historic upsets in gas conditions, locations 
where these upsets have occurred, and any indications of damage 
resulting from these upset conditions.
    Step 2: Identification of ICDA Regions and Excavation Locations--
The principal innovation of the gas pipeline industry in its 
development of the ICDA Process is the capability to evaluate the 
critical slope of a pipeline beyond which moisture in the gas is 
unlikely to be carried over. The primary assumptions in this analysis 
include: (a) For internal corrosion to occur an electrolyte such as 
water must be present in the pipeline; (b) the gas being transported is 
nominally clean and dry but may potentially be subject to upset 
conditions; (c) any entrained moisture carried in the gas stream will 
either evaporate or accumulate in a film along the wall of the pipe and 
be carried downstream by the shear force of the gas movement; (d) there 
is a critical pipe

[[Page 4305]]

angle above which gas that is swept along the wall will not progress 
downstream because the gravitational force will exceed the shear force 
of the gas on the liquid film.
    The purpose of this step is to define ICDA Regions, and to use 
these regions to identify areas where excavation and direct physical 
examination of the pipeline is needed to look for internal corrosion. 
ICDA Regions are regions along the pipeline where internal corrosion 
may occur and further evaluation is needed. An ICDA Region is bounded 
by a location where a new gas stream enters the pipe and the nearest 
location downstream of that point where a the pipe slope exceeds the 
critical angle, given local gas velocity. The operator identifies these 
ICDA Regions by applying the results of the mathematical flow model as 
represented in Graph E.III.1 in Appendix E of this document. Flow 
modeling must include explicit consideration of changes in pipe 
diameter as well as locations where gas enters a line (providing 
potential to introduce moisture) and locations down stream of gas draw-
offs (where gas velocity is reduced).
    Once the ICDA Regions are identified, the most likely locations for 
internal corrosion in each region can be identified. A minimum of two 
locations must be identified for excavation in each ICDA Region. One 
location is the low point (e.g., sags, drips, valves, manifolds, dead-
legs, traps) nearest to the beginning of the ICDA Region. The second 
location is at the upstream end of the pipe incline nearest the end of 
the ICDA Region. The first point represents the most likely locations 
for accumulation of electrolyte in the ICDA Region, and the second 
point represents the location furthest from the beginning of the ICDA 
Region where internal corrosion may occur..
    Step 3: Direct Examination--At a minimum the operator must excavate 
the two locations described above, in each ICDA Region where the 
potential for moisture accumulation exists, and must perform direct 
examination for internal corrosion by inspecting both locations. 
Acceptable direct examination technologies are described in ASME/ANSI 
B31.8S, Appendix SP-B2, and include ultrasonic examination and x-ray.
    If no internal corrosion exists at either of these locations, then 
the remainder of the ICDA Region is likely to be corrosion free. 
However, if corrosion exists at either of these locations, then either 
much more extensive excavation is required or an alternative assessment 
technology (e.g., in-line-inspection) will be required to characterize 
the pipe for internal corrosion. At any location where indications of 
metal loss exist, mitigation must be undertaken.
    Step 4: Post Assessment and Continuing Evaluation--After completing 
excavation and needed mitigation of the two suspect locations in each 
ICDA Region, the operator must document and implement a program of 
continuing monitoring for segments where internal corrosion has been 
identified. This program may include use of coupons located in 
suspected areas, but must include periodic reassessment at the 
prescribed interval. In addition, fluids drawn off of the pipeline at 
low points must be retained and chemically analyzed for the presence of 
corrosion products. Evidence of corrosion products must be interpreted 
as requiring further excavations of locations down stream where 
moisture might accumulate, or use of an alternative assessment 
technology such as in-line-inspection.

Stress Corrosion Cracking (SCC)

    As described in ASME/ANSI B31.8S, Appendix SP-B3, direct assessment 
techniques represent the single most significant historic approach to 
evaluate for the presence of stress corrosion cracking (SCC). Only 
recently ILI tools have become available to reliably identify SCC in 
pipelines, and the use of these tools must be guided by a pre-
assessment review that identifies where to look for the possibility of 
SCC.
    For SCC direct assessment, in addition to text in ASME B31.8S 
standard, an operator must consider the following condition:
    [sbull] Systematic SCC data collection, evaluation and accumulation 
process must be instituted for all segments that satisfy the criteria 
in the ASME B31.8S standard. This process must include gathering and 
evaluating data related to SCC at all excavation sites where the 
criteria indicate the potential for SCC.
    [sbull] If any evidence of SCC is discovered, then the operator 
must select and implement a suitable assessment approach.
    Confirmatory Direct Assessment is a more focused application of the 
principles and techniques of direct assessment. It utilizes process 
steps similar to direct assessment to evaluate for the presence of 
suspected corrosion and third party damage, but it is not as involved 
as direct assessment. The rule proposes that an operator use 
confirmatory direct assessment to reassess a pipeline segment within 
the required seven-year interval if the operator has established a 
longer reassessment interval for that segment.
    For example, in the proposed rule, if an operator is using pressure 
testing or internal inspection, it could establish a ten-year 
reassessment interval for a covered segment. By the seventh year, the 
operator would have to conduct a confirmatory direct assessment on that 
segment to identify corrosion or third party damage. The operator would 
then have to conduct the follow up reassessment in the tenth year. If 
the operator has established a seven-year or shorter interval for the 
segment, the operator would not have to conduct the confirmatory direct 
assessment.
    The rule proposes that the confirmatory direct assessment method be 
used to identify internal and external corrosion and third party 
damage. For external corrosion, an operator's plan to use this method 
would have to include steps for pre-assessment, indirect examination, 
direct examination, and remediation.
    [sbull] The pre-assessment would be the same as that proposed for 
direct assessment;
    [sbull] The indirect examination would be the same as that proposed 
for direct assessment except the examination can be conducted using 
only one indirect examination tool most suitable for the application.
    [sbull] The direct examination would follow that for the direct 
assessment, except that all immediate action indications must be 
excavated n each ECDA region, and at least one high risk indication 
that meets the criteria of scheduled action must be excavated in each 
ECDA region. No excavation is required for indications categorized as 
monitored indications.
    [sbull] The remediation requirements follow those proposed for 
direct assessment.
    For internal corrosion, an operator's plan to use this method would 
have to include steps for pre-assessment, identification of ICDA 
Regions, identification of excavation locations, direct examination and 
remediation.
    [sbull] The pre-assessment would follow that proposed for direct 
assessment.
    [sbull] The identification of ICDA Regions would follow that 
proposed for direct assessment.
    [sbull] The identification of excavation locations and excavation 
would follow that proposed for direct assessment, except that the 
operator must identify for excavation at least one high risk location 
in each ICDA Region.
    [sbull] The direct examination (excavation) and remediation would 
follow that for direct assessment, except one high risk location in 
each ICDA Region is to be chosen for excavation.

[[Page 4306]]

    For identifying third party damage, the operator's confirmatory 
direct assessment plan would include identification of pipeline 
segments where construction or other groundbreaking activity was 
reported near the pipeline right-of-way since the previous assessment.
(i) What Actions Must Be Taken To Address Integrity Issues? Proposed 
Sec.  192.763(i)
    The proposed rule requires that an operator must take prompt action 
to address all anomalous conditions that the operator discovers through 
the integrity assessment or information analysis. In addressing all 
conditions, an operator must evaluate all anomalous conditions and 
remediate those that could reduce a pipeline's integrity. An operator 
must be able to demonstrate that the remediation of the condition will 
ensure that the condition is unlikely to pose a threat to the long-term 
integrity of the pipeline. If an operator is unable to respond within 
the time limits for certain conditions specified below, operating 
pressure of the pipeline must be temporary reduced. An operator must 
determine the temporary reduction in operating pressure for dents and 
gouges using section 851.42 of ASME/ANSI B31.8; and for corrosion using 
ASME/ANSI B31G, RSTRENG, or equivalent, or by reducing the operating 
pressure to a level not exceeding 80% of the level at the time the 
integrity assessment results were received. A reduction in operating 
pressure cannot exceed 365 days without an operator taking further 
remedial action on anomalies that could reduce a pipeline's integrity. 
An operator must comply with Section 7 of ASME/ANSI B31.8S when 
defining the time frame for making a repair. Section 7 of this standard 
defines conditions for which the required response is ``immediate'' or 
can be ``scheduled,'' and other conditions for which the indications 
can be ``monitored.'' ``Immediate response,'' means that upon discovery 
of the condition the operator will immediately either shut the line 
down or reduce pressure to 80% of its previous level or less, if 
necessary to achieve a safe condition, and maintain that lower pressure 
until the defect is mitigated. Under no circumstances shall this 
temporary pressure reduction be extended beyond 365 days after the 
condition is discovered. Immediate response conditions are defined for 
threats including corrosion, stress corrosion cracking and third party 
damage. In addition, conditions for which the ratio of the predicted 
failure pressure to the MAOP is determined to be less than or equal to 
1.1, require immediate response. ``Scheduled response,'' means that the 
indications must be reviewed within six months of discovery and 
response plans developed consistent with the severity of the defect. 
Figure 7-1 of ASME/ANSI B31.8S presents criteria for remediation time 
as a function of the stress level of the pipe and the severity of the 
defect (i.e., the ratio of the predicted failure pressure to the MAOP). 
``Monitored defects,'' are those for which the response time for 
mitigation is greater than the reassessment interval, and, therefore, 
the indications will be reexamined as part of the reassessment process.
    The proposed rule also defines ``discovery of condition.'' 
Discovery of a condition occurs when an operator has adequate 
information about the condition to determine that the condition 
presents a potential threat to the integrity of the pipeline. An 
operator must promptly, but no later than 180 days after an integrity 
assessment, obtain sufficient information about a condition to make 
that determination If the operator cannot make the necessary 
determination within the 180 day period, them it must notify RSPA/OPS 
of the reasons for the delay and the expected time for completing the 
assessment.
    Except for special requirements for scheduling remediation of 
certain conditions specified in paragraph (h)(4) of the proposed rule, 
an operator is required by the proposed rule to follow a threat by 
threat schedule specified in the ASME/ANSI B31.8S Standard. An operator 
must complete remediation of a condition according to a schedule that 
prioritizes the conditions for evaluation and remediation. If an 
operator cannot meet the schedule for any condition, the operator must 
justify the reasons why it cannot meet the schedule and that the 
changed schedule will not jeopardize public safety. An operator must 
notify RSPA/OPS if it cannot meet the schedule and cannot provide 
safety through a temporary reduction in operating pressure. An operator 
must send the notice to the address specified in paragraph (n) of the 
proposed rule.
    The proposed rule also tabulates special conditions for scheduled 
remediation as follows:
    Immediate repair conditions. An operator's evaluation and 
remediation schedule must provide for immediate repair conditions. To 
maintain safety, an operator must temporarily reduce operating pressure 
or shut down the pipeline until the operator completes the repair of 
these conditions. Consistent with ASME B31.8S, Chapter 7, an operator 
must treat the following conditions as immediate repair conditions:
    [sbull] A calculation of the remaining strength of the pipe shows a 
predicted failure pressure less than 1.1 times the established maximum 
operating pressure at the location of the anomaly. Suitable remaining 
strength calculation methods include, but are not limited to, ASME/ANSI 
B31G (``Manual for Determining the Remaining Strength of Corroded 
Pipelines'' (1991) or AGA Pipeline Research Committee Project PR-3-805 
(``A Modified Criterion for Evaluating the Remaining Strength of 
Corroded Pipe'' (December 1989)). These documents are available at the 
addresses listed in Appendix A to Part 192.
    [sbull] A dent that has any indication of metal loss, cracking or a 
stress riser.
    [sbull] An anomaly that in the judgment of the person designated by 
the operator to evaluate the assessment results requires immediate 
action. Such an evaluation is required by all operators using direct 
assessment.
    180-day evaluation. Except for conditions listed in ``immediate 
repair'' conditions of this section, an operator must complete 
evaluation and schedule remediation of the following within 180 days of 
discovery of the condition:
    [sbull] Calculation of the remaining strength of the pipe shows a 
predicted failure pressure between 1.1 times the established maximum 
operating pressure at the location of the anomaly, and the ratio of the 
predicted failure pressure to the MAOP shown in Figure 7-1 of ASME 
B31.8S to be appropriate for the stress level of the pipe and the 
reassessment interval. For example, if the pipe is operating at 50% 
SMYS and the reassessment interval is ten (10) years, then the 
predicted failure pressure ratio for scheduling examination and 
remediation during that ten year period would be 1.39.
    180 day remediation. The following conditions must be remediated 
within 180 days of discovery of the condition:
    [sbull] A dent with a depth greater than 6% of the pipeline 
diameter (greater than 0.50 inches in depth for a pipeline diameter 
less than Nominal Pipe Size (NPS) 12).
    [sbull] A dent with a depth greater than 2% of the pipeline's 
diameter (0.250 inches in depth for a pipeline diameter less than NPS 
12) that affects pipe curvature at a girth weld or a longitudinal seam 
weld.
    [sbull] A potential crack indication that when excavated is 
determined to be a crack.
    [sbull] Corrosion of or along a longitudinal seam weld.

[[Page 4307]]

    [sbull] A gouge or groove greater than 12.5% of nominal wall.
    Scheduled Remediation. The ASME/ANSI B31.8S Standard includes 
provisions for scheduled repairs over a period exceeding 180 days. For 
all indications that are not excavated and remediated within 180 days, 
the following requirements apply:
    [sbull] For segments assessed using ILI techniques, the failure 
pressure must be determined and remediation carried out on a time frame 
consistent with Figure 7-1 in ASME/ANSI B31.8S.
    [sbull] For segments assessed using direct assessment, at least one 
direct examination, beyond those required in Paragraph (g)(4) of the 
proposed rule, of a scheduled indication must be carried out in each 
ECDA Region between assessments. The results of this direct examination 
must be compared with those from earlier direct examination results for 
consistency. Should the defect be larger than any of those identified 
in previous excavations in that region, then further excavation must be 
carried out until the requirements in Paragraph (g)(4) of the proposed 
rule are satisfied.
(j) What Additional Preventive and Mitigative Measures Must an Operator 
Take To Protect the High Consequence Area? Proposed Sec.  192.763(j)
    The proposed rule includes the following general requirement: An 
operator must take measures to prevent and mitigate the consequences of 
a pipeline failure that could affect a high consequence area in 
accordance with the standard ASME/ANSI B31.8S. Table 7-1 in the ASME 
standard describes some preventive and mitigative measures appropriate 
for each threat. In addition, operators must conduct risk analysis of 
their pipeline segments to identify additional actions to enhance 
public safety. Such actions include, but are not limited to, installing 
Automatic Shut-off valves or Remote Control Valves, computerized 
monitoring and leak detection systems, extensive inspection and 
maintenance programs, and heavier wall thickness.
    Automatic Shut-off valve (ASV) or Remote Control Valves (RCV). If 
an operator determines that an ASV or RCV is needed on a pipeline 
segment to protect high consequence areas in the event of gas release, 
an operator must install the ASV or RCV. In making that determination 
an operator must at least consider magnitude of leak detection and pipe 
shutdown capabilities, the type of gas, pressure, the rate of potential 
release, the potential for ignition, location of nearest response 
personnel, and benefits expected by reducing the volume of gas release. 
The operator must document the criteria used in evaluating the need for 
ASVs and RCVs, and document the decisions resulting from application of 
these criteria.
(k) What Is a Continual Process of Evaluation and Assessment To 
Maintain a Pipeline's Integrity? Proposed Sec.  192.763(k)
    The integrity assessment requirements proposed in this rule do not 
stop with the baseline integrity assessment. An operator must, on a 
continual basis, assess the integrity of the line pipe and evaluate the 
integrity of each pipeline segment that could affect a high consequence 
area. The proposed rule requires an operator to conduct a periodic 
evaluation of each pipeline segment, as frequently as needed, to assure 
the pipeline's integrity. An operator would determine frequency based 
on threats specific to the pipeline segment, plus threats specified in 
proposed Sec.  192.763(e) and in Section 2 of the ANSI/ASME B31.8S 
Standard.
    The evaluation is based in part, on the information analysis the 
operator conducts of the entire pipeline to determine what history and 
operations elsewhere could be relevant to the segment. The evaluation 
must also consider the past and present integrity assessment results, 
and decisions about repair, and preventive and mitigative actions. The 
evaluation must be carried out by a person qualified to evaluate the 
results and other related data.
    As with the baseline assessment, the continual integrity assessment 
method must be by internal inspection, pressure test, direct 
assessment, or other technology that provides an equivalent 
understanding of the condition of the line pipe. As with the baseline 
assessment, if an operator chooses other technology as a reassessment 
method, the operator must give 90-days advance notice (by mail or 
facsimile) to RSPA/OPS. As with the baseline assessment, an operator 
must have a process for ensuring that the assessment is being done in a 
manner to minimize environmental and safety risks.
    Each covered pipeline segment must be reassessed at seven-year 
intervals, or five years if direct assessment is used and the operator 
directly examines and remediates defects by sampling. The period for 
reassessment begins with the completion of the prior assessment on that 
segment. The proposed rule allows an operator to base the reassessment 
interval on the risk the pipe poses to the high consequence area to 
determine the priority for assessing the pipeline segments. If the 
operator establishes a reassessment interval for the covered segment 
that is greater than seven years, the operator must within the seven-
year period, conduct a reassessment by confirmatory direct assessment 
on the covered segment, and then conduct the follow-up reassessment at 
the established interval. The length of the interval will depend on the 
method of assessment.
    If an operator uses pressure testing or internal inspection as an 
assessment method, the operator must establish the reassessment 
interval for covered pipeline segments by either basing the intervals 
on the identified threats for the segment (as identified in the 
proposed rule and in ASME/ANSI B31.8S, Table 8-2, section 8) and on the 
analysis of the results from the last integrity assessment and from the 
required data integration or by using the intervals for different 
stress levels of pipeline specified in ASME/ANSI B31.8S, Table 8-1, 
section 8. However, under either option, the maximum reassessment 
interval must not exceed ten (10) years for a pipeline operating at or 
above 50% SMYS, and 15 years for a pipeline operating below 50% SMYS. 
These maximum assessment intervals will be acceptable, only if the 
operator demonstrates it has enhanced preventive and mitigative 
programs in place and the operator conducts a confirmatory direct 
assessment within the seven-year interval.
    An operator that establishes the maximum period allowed for 
reassessment must conduct a confirmatory direct assessment within the 
seven-year interval and demonstrate that it has implemented enhanced 
preventive and mitigative measures for the segment.
    If an operator uses direct assessment, it must determine the 
reassessment interval according to a calculation. The reassessment 
interval cannot exceed five years, if an operator directly examines and 
remediates defects by sampling, or ten years, if an operator conducts a 
direct examination of all anomalies and remediates these anomalies. A 
ten-year interval would necessitate an interim reassessment by 
confirmatory direct assessment in the seventh year.
    The proposed rule requires each operator to evaluate the cause of 
threats for which mitigative action was undertaken, and determine 
whether there is reason to reassess the pipe at shorter intervals based 
on the nature of significant threats. For example, if the dominant 
cause of pipe deterioration in a particular segment was MIC, then the 
operator is required to reassess its similar pipe segments on a shorter

[[Page 4308]]

interval, consistent with the growth rate of MIC corrosion.
    OPS can only allow a waiver of a maximum reassessment interval 
greater than seven years in two instances--for lack of internal 
inspection tools or to maintain local product supply- and if OPS 
determines that such a waiver would not be inconsistent with pipeline 
safety. Because public notice and comment is required for a waiver, we 
are proposing an operator provide 180 days advance notification.
    The proposed rule requires the operator to assess the integrity of 
the line pipe by one or more of the following techniques:
    [sbull] Internal inspection tool or tools; for details on selecting 
appropriate internal inspection tools an operator must refer to ASME/
ANSI B31.8S section 6.2.
    [sbull] Pressure test conducted in accordance with Subpart J of 
Part 192.
    [sbull] Direct assessment method for external corrosion threats, 
internal corrosion threats, and other threats must be carried out in 
accordance with the ASME/ANSI B31.8S standard Section 6.3 and paragraph 
(h) of the proposed rule.
    [sbull] Other technology that the operator demonstrates can provide 
an equivalent understanding of the condition of the line pipe. An 
operator choosing this option must notify RSPA/OPS 180 days before 
conducting the assessment, by sending a notice to the address or to the 
facsimile number specified in paragraph (n) of the proposed rule.
(l) What Methods To Measure Program Effectiveness Must Be Used? 
Proposed Sec.  192.763(l)
    The proposed rule requires an operator to include in its integrity 
management program methods to measure the program's effectiveness in 
assessing and evaluating the integrity of each pipeline segment and in 
protecting the high consequence areas. The proposed rule requires that 
an operator use four overall performance measures specified in Section 
9.4 of ASME/ANSI B31.8S and specific measures for each identified 
threat specified in ASME/ANSI B31.8S, Appendix SP-A.
    The performance measures help an operator determine whether all 
integrity management program objectives were accomplished and whether 
pipeline integrity and safety are effectively improved through the 
integrity management program. Proper selection and evaluation of 
performance measures are an essential activity in determining integrity 
management program effectiveness. According to ASME/ANSI B31.8S 
Standard, evaluations must be performed at least annually to provide a 
continuing measure of integrity management program effectiveness over 
time. This standard lists four overall program measurements that must 
be determined and documented. Those measurements are: (1) Number of 
miles of pipeline inspected versus program requirements; (2) number of 
immediate repairs completed as a result of integrity management 
inspection program; (3) number of scheduled repairs completed as result 
of the integrity management inspection program; (4) number of leaks, 
failures and incidents.
    The proposed rule requires that an operator periodically make 
available for inspection the four primary performance measures 
enumerated above from Section 9.4 in ASME/ANSI B31.8S.
(m) What Records Must be Kept? Proposed Sec.  192.763(m)
    The proposed rule requires that an operator maintain certain 
records for inspection, including its written integrity management 
program, and, if applicable, its plan for using direct assessment. This 
requirement is not different from the procedural manual an operator is 
required to maintain for operations, maintenance and emergencies. An 
operator would also be required to maintain for review during 
inspection, any documents that support the decisions and analyses made, 
and actions taken to implement and evaluate each element of the 
integrity management program. This would include records documenting 
any modifications, justifications, variances, deviations and 
determinations made. All records required under direct assessment must 
also be maintained and available for RSPA/OPS review during 
inspections. Again, this requirement is no different from the myriad of 
documents an operator now maintains to comply with the other provisions 
of the pipeline safety regulations.
(n) Where Does an Operator Send a Notification? Proposed Sec.  
192.763(n)
    This section of the proposed rule clarifies that any required 
notification must be sent to the Information Resources Manager, Office 
of Pipeline Safety, Research and Special Programs Administration, U.S. 
Department of Transportation, Room 7128, 400 Seventh Street SW., 
Washington, DC 20590, or to the facsimile number (202) 366-7128. 
Notification is required when an operator: (a) Uses alternative 
technology for an integrity assessment; (b) cannot meet its schedules 
for identification of segments and identification of ECDA regions if 
applicable; (c) cannot meet schedules for evaluating and remediating 
anomalous conditions; (d) adopts certain changes into its program; and 
(f) seeks a waiver from a reassessment interval greater than seven 
years.

Appendix E to Part 192

    We are adding a new Appendix E to Part 192. This Appendix gives 
guidance on determining a potential impact zone within a high 
consequence area and shows diagram of a potential impact zone under 
figure E.I.1. This Appendix describes the steps an operator needs to 
perform in order to determine segments covered under potential impact 
zones. This Appendix also provides recommendations on how to select 
external corrosion direct assessment (ECDA) Tools and how to identify 
ECDA Regions. In addition, this Appendix provides a spreadsheet under 
Graph E.III.1 for calculating critical angle for liquid hold-up for 
internal corrosion direct assessment (ICDA).
    An operator is required to follow the recommendations on ECDA Tool 
selection and ECDA Regions, unless the operator notes in its plan the 
reasons why compliance with all or certain provisions is not necessary 
to maintain integrity of their specific pipeline system. The Appendix 
contains recommendations on:
    [sbull] Selection of indirect inspection tools for direct 
assessment: how selection of indirect inspection tools may vary along a 
segment; minimum number of tools needed for all ECDA locations and 
items that should be considered when selecting indirect inspection 
tools; and conditions under which some indirect inspection tools may 
not be practical or reliable.
    [sbull] Identification of ECDA Regions: how to (a) Collect 
appropriate risk factor data; (b) define criteria to identify ECDA 
regions; and (c) identify locations having similar physical 
characteristics, soil conditions, corrosion protection maintenance. In 
addition, guidance on establishing ECDA Regions is presented by 
illustrating an example of the ECDA regions for a hypothetical 
pipeline.
    [sbull] Internal Corrosion Direct Assessment: how to calculate 
critical angle for liquid hold-up using a graph from GRI report GRI-02/
0057. The approach helps determine if internal corrosion is likely to 
or unlikely to exist in a chosen length of pipe.

Regulatory Analyses and Notices

Executive Order 12866 and DOT Regulatory Policies and Procedures

    The Department of Transportation (DOT) considers this action to be 
a significant regulatory action under

[[Page 4309]]

section 3(f) of Executive Order 12866 (58 FR 51735; October 4, 1993). 
Therefore, it was forwarded to the Office of Management and Budget. 
This proposed rule is significant under DOT's regulatory policies and 
procedures (44 FR 11034: February 26, 1979) because of its significant 
public and government interest. A regulatory evaluation of this 
proposed rule on Integrity Management for gas transmission pipelines 
has been prepared and placed in the docket.

Cost-Benefit Analysis

    A copy of the draft regulatory evaluation has been placed in the 
docket for this proposed rule. The following section summarizes the 
draft regulatory evaluation's findings.
    Natural and other gas pipeline ruptures can adversely affect human 
health and property. However, the magnitude of this impact differs from 
area to area. There are some areas in which the impact of an accident 
will be more significant than it would be in others due to 
concentrations of people who could be affected. Because of the 
potential for dire consequences of pipeline failures in certain areas, 
these areas merit a higher level of protection. RSPA/OPS is proposing 
this regulation to afford the necessary additional protection to these 
high consequence areas.
    Numerous investigations by RSPA/OPS and the National Transportation 
Safety Board (NTSB) have highlighted the importance of protecting the 
public and environmentally sensitive areas from pipeline failures. NTSB 
has made several recommendations to ensure the integrity of pipelines 
near populated and environmentally sensitive areas. These 
recommendations included requiring periodic testing and inspection to 
identify corrosion and other damage, establishing criteria to determine 
appropriate intervals for inspections and tests, determining hazards to 
public safety from electric resistance welded pipe and requiring 
installation of automatic or remotely-operated mainline valves on high-
pressure lines to provide for rapid shutdown of failed pipelines.
    Congress also directed RSPA/OPS to undertake additional safety 
measures in areas that are densely populated. These statutory 
requirements included having RSPA/OPS prescribe standards for 
identifying pipelines in high density population area and issue 
standards requiring periodic inspections using internal inspection 
devices on pipelines in densely-populated and environmentally sensitive 
areas, and to require reassessment of these areas at least every seven 
years.
    This proposed rulemaking addresses the target problem described 
above, and is a comprehensive approach to certain NTSB recommendations 
and Congressional mandates, as well as pipeline safety and 
environmental issues raised over the years.
    This proposed rule focuses on a systematic approach to integrity 
management to reduce the potential for natural and other gas 
transmission pipeline failures that could affect populated areas. This 
proposed rulemaking requires pipeline operators to develop and follow 
an integrity management program that continually assesses, through 
internal inspection, pressure testing, direct assessment or equivalent 
alternative technology, the integrity of those pipeline segments that 
could affect areas we have defined as high consequence areas i.e., 
areas with specified population densities, buildings containing 
populations of limited mobility, and areas where people gather that 
occur along the route of the pipeline. The program must also evaluate 
the segments through comprehensive information analysis, remediate 
integrity problems and provide additional protection through preventive 
and mitigative measures.
    This proposed rule (the third in a series of integrity management 
program regulations) covers operators of transmission pipelines for 
natural and other gases. RSPA/OPS chose to start the series with 
hazardous liquid pipeline operators because the pipelines they operate 
have the greatest potential to adversely affect the environment. This 
proposed rule completes the application of integrity management to all 
interstate (and many intrastate) pipelines.
    We have estimated the cost for operators to identify pipeline 
segments that can affect high consequence areas at approximately $23.34 
million, the cost to develop the necessary programs at approximately 
$90.9 million (with an additional one-time cost of $367,400 to provide 
RSPA/OPS and state inspectors with real-time access to performance 
measures) and an annual cost for program upkeep and reporting of $13.36 
million. An operator's program begins with a baseline assessment plan 
and a framework that addresses each required program element. The 
framework indicates how decisions will be made to implement each 
element. As decisions are made and operators evaluate the effectiveness 
of the program in protecting high consequence areas, the program will 
be updated and improved, as needed.
    The proposed rule requires a baseline assessment of covered 
pipeline segments through internal inspection, pressure test, direct 
assessment or use of other technology capable of equivalent 
performance. Unless an operator uses direct assessment, the baseline 
assessment must be completed within ten years after December 17, 2002 
(the date the Pipeline Safety Improvement Act of 2002 was signed into 
law), with at least 50% of covered segments being assessed within five 
years. With direct assessment the baseline assessment must be completed 
in seven years, with 50% of the covered segments completed within four 
and 1/2 years. Until we see the results from operators' assessments we 
cannot determine whether direct assessment by itself is adequate to 
assess pipeline integrity or whether pigging might also be needed. The 
period for a baseline assessment may extend to 13 years, or ten years 
for direct assessment, for segments in moderate risk areas, that is, 
areas within a class 3 or 4 location that are not in the impact zone 
from a potential rupture.
    After this baseline assessment, the rule further proposes that an 
operator periodically reassess and evaluate the pipeline segment to 
ensure its integrity within a ten-year interval for pipelines operating 
at greater than 50 percent of specified minimum yield strength (SMYS) 
and a fifteen-year interval for pipelines operating below 50 percent 
SMYS. However, to meet the requirements of the Pipeline Safety 
Improvement Act of 2002, if an operator establishes an interval greater 
than seven years, the operator will need to conduct an interim 
reassessment by the seventh year using a more-focused direct assessment 
(Confirmatory Direct Assessment) method. If an operator elects to 
perform a reassessment, using one of the other methods, every seven 
years, the operator need not use the confirmatory direct assessment. 
The proposed reassessment interval for pipelines assessed with direct 
assessment is five years unless all anomalies are excavated, in which 
case it is ten years.
    Confirmatory direct assessment is a more-focused application of the 
principles and techniques of direct assessment, that is concentrated on 
identifying critical segments of suspected corrosion and third party 
damage. RSPA/OPS has structured the proposed requirements for 
confirmatory direct assessment in a manner intended to allow maximum 
flexibility for operators. Indirect examinations may be performed using 
only one, rather than two, tools. Corrosion regions may be larger than 
for regular direct

[[Page 4310]]

assessments. The number of excavations required per region is less. 
These changes will allow operators to plan and conduct confirmatory 
direct assessments in a manner that is most cost-effective, i.e., 
identifies areas of concern at lowest cost.
    There is no data available at present regarding the cost to 
implement confirmatory direct assessment. The flexibility included in 
these proposed requirements means that costs may vary depending on 
assumptions the operator makes in planning and conducting these 
assessments. For purposes of this evaluation, the RSPA/OPS assumes that 
the cost will be less than, but more than half, that of direct 
assessment, or $3,000 per mile. Actual costs for many operators may be 
lower, and the total cost estimates in this analysis are thus expected 
to be conservatively high.
    It is estimated that the cost of periodic reassessment will 
generally not occur until the sixth year (when reassessment costs will 
begin for a pipeline baseline assessed using direct assessment) unless 
the baseline assessment indicates significant defects that would 
require earlier reassessment.
    RSPA/OPS believes that the higher the operating pressure of a 
pipeline, the greater the potential risk the pipeline poses to the 
general public. That is because a failure of a pipeline operating at a 
higher pressure will result in a larger impact area and potentially 
more significant consequences. It is under this assumption that RSPA/
OPS is proposing the shortest assessments intervals for pipelines that 
operate at or above pressures of 50 percent of SMYS. By basing the 
assessment interval according to pipeline pressure, operators will have 
to focus their safety resources on lines that pose the greatest danger. 
RSPA/OPS believes that varying the assessment interval according to the 
risk provides the greatest reward per dollar of safety operators will 
expend.
    Integrating information related to the pipeline's integrity is a 
key element of the integrity management program. Costs will be incurred 
in realigning existing data systems to permit integration and in 
analysis of the integrated data by knowledgeable pipeline safety 
professionals. The total costs for the information integration 
requirements in this proposed rule are $31.5 million in the first year 
and $15.75 million annually thereafter.
    The proposed rule requires operators to evaluate the risk of 
pipeline segments that can affect high consequence areas to determine 
if additional preventive or mitigative measures that would enhance 
public safety should be implemented. One of the many additional 
preventive or mitigative actions that the notice proposes an operator 
take is to install automatic shutoff valves or remotely controlled 
valves. RSPA/OPS could not estimate the total cost of installing such 
valves because there are too many factors that would have to be 
analyzed in order to produce a valid estimate of how many operators 
will install them. However, based on the results of a generic 
feasibility study on remotely controlled valves that RSPA/OPS completed 
in 1999, we concluded that conversion of existing sectional block 
valves to remote operation was not economically feasible. Operator- and 
location-specific factors could change this conclusion for individual 
valves but RSPA/OPS could not analyze these specific factors for 
individual block valves and therefore, did not estimate the total cost 
for installing remote valves. RSPA/OPS presumes that operators will 
analyze valve-specific factors and will not replace valves unless that 
action is cost-beneficial. RSPA/OPS estimates that the cost to 
operators to perform the required risk analyses will be approximately 
$24.1 million.
    Affected operators will be required to assess more line pipe in 
segments that could affect high consequence areas as a result of this 
proposed rule than they would have been expected to assess if the 
proposed rule had not been issued. Integrity assessment consists of a 
baseline assessment, and subsequent reassessment. The period in which 
baseline assessments must be completed depends upon the assessment 
method chosen and the grade of the high consequence areas. The baseline 
period for most pipe is ten years for pipeline to be assessed with in-
line inspection or hydrostatic testing and five years for pipeline to 
be assessed using direct assessment. These periods are extended to 13 
and 7 years, respectively, for pipeline that can affect lower grade 
high consequence areas, containing relatively lower population 
densities. Reassessments must be conducted at no less than ten year 
intervals for pipeline operating above 50 percent SMYS and 15 years for 
pipeline operating at less than 50 percent SMYS. The proposed 
reassessment interval for pipe assessed with direct assessment is five 
years unless all anomalies are excavated, in which case the interval 
may be extended to ten years. Confirmatory direct assessments would be 
required to be performed at least every seven years, if an operator 
established a reassessment interval longer than seven years.
    RSPA/OPS analyzed two scenarios, varying the amount of pipeline 
that operators are expected to modify to accommodate in-line 
inspection. This approach was taken, because of industry comments that 
significant amounts of pipeline would likely be modified and the costs 
for that work. Some pipe already can accommodate in-line inspection 
tools. Some can be modified to accommodate the in-line inspection tools 
with relatively simple modifications. Others require much more 
extensive retrofits. Until we see results of operators assessments we 
can not judge whether direct assessment is sufficient or pigging is 
needed. One of the analyzed scenarios assumed that only the piping that 
can easily be modified would be changed. The other scenario was based 
on the assumption that a portion of the pipe requiring more extensive 
changes would also be modified. As a result of this work, RSPA/OPS has 
estimated the annual cost of additional baseline assessment that will 
be required by this proposed rule as between approximately $59 million 
and $298 million annually. The cost for additional re-assessment is 
estimated at approximately $32 million per year.
    Although there are a variety of benefits associated with this 
proposed rule, the principal benefits are difficult, if not impossible, 
to quantify. The proposed integrity management program requirements 
will ensure that all gas transmission operators perform at least to an 
established baseline safety level and will raise the overall level of 
safety performance nationwide. The proposed rule will lead to greater 
uniformity in how risk is evaluated and addressed and will provide a 
better and clearer basis for government, industry and the public to 
discuss safety concerns and how they can be resolved. Public awareness 
of the integrity program will lead citizens to be more informed about 
pipeline safety and provide information to operators about activities 
on the pipeline right-of-way that will help to improve safety. The 
integrated integrity management programs that operators will be 
required to implement in response to this proposed rule will result in 
a higher level of safety, which should in turn result in improved 
public confidence in the safety of natural gas transmission pipelines. 
Operators have begun integrity programs on their own because they have 
recognized the importance of knowing the condition of their pipelines 
and having the public assured that the lines are safe. After a major 
pipeline accident, and the accompanying national spotlight from the 
media the public becomes alarmed with the potential threat that 
pipelines pose. Pipelines that are presently unpiggable

[[Page 4311]]

have most likely not been inspected. The public becomes very concerned 
when it becomes aware that ``aging'' pipelines underground in their 
community have never been internally inspected. The only method to 
reassure the public of the safety of pipelines is that there are 
requirements that these pipelines be internally inspected and evaluated 
on a periodic basis. This improved confidence is consistent with the 
objectives of the Administration's National Energy Plan. The importance 
of integrity management is also reflected in its inclusion in the 
requirements of the Pipeline Safety Improvement Act of 2002.
    RSPA/OPS, as well as the pipeline industry has gained valuable 
knowledge from accidents and near misses in the 90's. RSPA/OPS has 
found that operators have gathered valuable information but that they 
have not used that information effectively or used it to maximum 
effect. Analysis of recent major accidents indicates that better use of 
existing information through data integration and evaluation has the 
potential to prevent major accidents. Data integration requirements 
should lead operators to make better and more informed decisions about 
what preventive and mitigative actions to take and how to set 
priorities. RSPA/OPS believes that it is possible for operators to 
gather and integrate the necessary data and implement the needed 
changes with little additional investment.
    The benefits that can be quantified are expected reductions in 
deaths, serious injuries, and property damage costs resulting from 
accidents on gas transmission pipelines. RSPA/OPS has developed a 
level-of-magnitude estimate of these benefits. That estimate is based 
on the accident data reported to RSPA/OPS over a sixteen year period 
(1986 to 2001). RSPA/OPS estimates that the benefit of completely 
eliminating the fatalities, serious injuries, and property damage 
caused by those accidents would be equivalent to approximately $53.25 
million per year. RSPA/OPS does not expect that this rule will 
eliminate all accidents on natural gas transmission pipelines that 
would result in deaths, serious injuries, or property damage. RSPA/OPS 
does expect that the proposed rule will significantly reduce the 
frequency and consequences of such accidents. The magnitude of the 
expected reduction cannot now be estimated with certainty. RSPA/OPS 
concludes, however, that the reduction will be significant.
    RSPA/OPS notes that the consequences of future accidents, in the 
absence of any new actions to improve pipeline safety, would likely be 
higher than would be indicated by historical precedents. The reason for 
this is continued increase in the population living near, and utilizing 
land near, pipelines. Accidents that occur in rural settings typically 
have resulted in fewer deaths, serious injuries, and property damage 
than accidents that occur in developed areas. As the amount of 
development near pipelines increases, relatively more accidents would 
be expected to occur in developed areas and the consequences of those 
accidents would be expected to increase.
    As a result of these factors, RSPA/OPS concludes that the 
quantifiable benefits of the proposed rule are on the order of $40 
million per year. This is less than, but on the same order of magnitude 
as, the continuing costs. Initial costs, for program development and 
modification of pipelines to facilitate testing, are significantly 
higher. The quantifiable benefits alone cannot justify those costs. 
They need not, however. Recently, gas transmission pipeline operators 
have indicated that, of the choices of testing available, they 
frequently are going to choose internal inspection as the best long 
term investment and while the costs are higher for the modifications 
needed to operate this method, the operators clearly think the 
investment is worthwhile.
    The principal benefit to be derived from the proposed rule is one 
that cannot easily be quantified. That is improved public confidence in 
pipeline safety. That confidence has been shaken by accidents in recent 
years. It is necessary that actions be taken to restore that 
confidence. Improved public confidence in pipeline safety will, in 
turn, produce additional benefit. It will result in improved ability to 
site and construct the additional pipelines that will be needed to 
serve growing demand for natural gas in the United States, as indicated 
in the National Energy Plan. This growth results not only from 
increasing population, but from increased use of natural gas, as an 
environmentally desirable fuel, for generating electricity and other 
industrial uses. Inability to meet these increased demands will 
challenge our nation's ability to realized desired environmental goals.
    RSPA/OPS discussed the draft regulatory analysis with the Technical 
Pipeline Safety Standards Committee (TPSSC) at a public meeting on July 
18, 2002. The TPSSC, composed equally of representatives of industry, 
government, and groups representative of public involvement in pipeline 
safety issues, provided numerous comments on the draft analysis. 
Industry members of the TPSSC indicated that, to a much greater degree 
than RSPA/OPS had estimated, the industry would choose to modify 
existing pipeline to make it possible to inspect using in-line 
inspection tools. The TPSSC also commented that costs had been greatly 
underestimated, primarily because the additional mileage they will need 
to internally inspect in order to inspect segments that can affect high 
and lower risk areas will be much larger than the amount estimated in 
the draft regulatory analysis. The much larger total amount of mileage 
that will require inspection could lead to supply disruptions while 
testing and repair is underway. Nevertheless, the committee unanimously 
concluded that the expected benefit in terms of improved public 
confidence in pipeline safety is substantial and justifies the expected 
costs and that with edits, the RSPA/OPS draft regulatory analysis 
provided a basis for proposing this rule. RSPA/OPS has revised the 
draft regulatory analysis in response to the TPSSC comments.
    With the increased understanding of the condition of the pipeline 
that will result from the added assessments and repairs required in the 
proposed rule, there is the potential for pressures to be maintained 
that would otherwise have to be reduced to allow adequate safety 
margins. Additional demand for supply may potentially be better met by 
not having to impose restrictions to the flow of natural gas through 
existing transmission pipelines in areas where population is increasing 
and pipe replacement or pressure reductions would be required. Current 
requirements provide that natural gas transmission pipelines in areas 
that would be defined as high consequence areas operate at pressures 
that limit stresses in the pipe walls to levels significantly below 
those allowed in more rural areas. The reduced stresses are intended to 
provide additional margin against accidents that might result from 
unknown damage or degradation mechanisms. The proposed requirements 
would result in operators inspecting for, identifying, and remediating 
such damage. RSPA/OPS has experience, through the Risk Management 
Demonstration Program, that indicates that the improved confidence in 
pipeline integrity afforded by the type of integrated integrity 
management program required by this rule can lead RSPA/OPS to allow 
operation at higher pressures in these areas. Down the road with the 
program, applying that experience may make it possible for RSPA/OPS to 
approve operation of pipelines in some areas at higher pressures, 
allowing additional

[[Page 4312]]

natural gas to be supplied by the existing infrastructure. (The 
particular circumstances of each area would have to be taken into 
account in deciding whether operation at increased pressure is 
acceptable).
    The quantitative estimates of benefits also considers only direct 
effects, i.e., damages caused by the explosion and fire resulting from 
a natural gas transmission pipeline rupture. There are other 
consequences of such accidents that can be avoided or prevented. 
Unplanned business interruption can have a severe economic impact on 
the area in which an accident occurs. Temporary cessations in 
operation, longer term pressure restrictions, and repair efforts often 
require interruption of natural gas supply to some customers. In some 
areas, this can include entire communities that may be served by sole 
source laterals receiving gas from transmission lines in the vicinity 
of the accident. Interruption of natural gas service has both economic 
and safety consequences. Service must be restored in a controlled 
manner to avoid subsequent explosions from natural gas escaping into 
businesses and residences from open pilot valves. Gas distribution 
company employees must enter each customer's premises, isolate pilot 
valves, purge piping of air that may have become entrained, and relight 
pilot lights. This is a labor intensive effort that can take several 
days for a moderately-sized community. An integrity management program 
will allow an operator to identify and repair defects that could lead 
to accidents before they occur. Since these tests and repairs can be 
planned, their performance can be done at the optimum time to minimize 
detrimental effects on businesses, homes and supply generally.
    Consistent with RSPA/OPS practice, much of the proposed rule is 
written in performance-based language. This approach stimulates the 
development and use of new technologies for assessing pipeline 
integrity which may allow more accurate detection of problems that can 
now be found or detection of problems that have heretofore been 
difficult to find.
    The performance approach also results in supporting operators' 
development of more formal, structured risk evaluation programs and 
RSPA/OPS's evaluation of the programs. Most important, the performance 
approach encourages a balanced program, addressing the range of 
prevention and mitigation needs and avoiding reliance on any single 
tool or overemphasis on any single cause of failure. This will lead to 
addressing the most significant risks in the most effective manner. 
This integrity-based approach provides a good opportunity to improve 
industry performance and assure that these high consequence areas get 
the protection they need.
    A particularly significant benefit is the quality of information 
that will be gathered as a result of this proposal to aid operators' 
decisions about providing additional protections. Two essential 
elements of the integrity management program are that an operator 
continually assesses and evaluates the pipeline's integrity, and 
performs an analysis that integrates all available information about 
the pipeline's integrity. The process of planning, assessment and 
evaluation will provide operators with better data on which to judge a 
pipeline's condition and the location of potential problems that must 
be addressed.
    Integrating this data with the safety concerns associated with high 
consequence areas will help prompt operators and the Federal and state 
governments to focus time and resources on potential risks and 
consequences that require greater scrutiny and the need for more 
intensive preventive and mitigation measures. If baseline and periodic 
assessment data is not evaluated in the proper context, it is of little 
or no value. It is imperative that the information an operator gathers 
is assessed in a systematic way as part of the operator's ongoing 
examination of all threats to the pipeline integrity. The proposed rule 
is intended to accomplish that.
    The proposed rule has also stimulated the pipeline industry to 
develop supplemental consensus standards to support risk-based 
approaches to integrity management. These standards will lead to better 
quality control on a national basis, particularly important in the area 
of using new assessment technologies where correct application is 
critical to achieving the desired safety outcome. Without such 
standards, there have been instances of incorrect application of 
assessment technology leading to incidents. These and future incidents 
of this type can be avoided.
    The proposed rule provides for a verification process, which gives 
the regulator a better opportunity to influence the methods of 
assessment and the interpretation of results. RSPA/OPS will provide a 
beneficial challenge to the adequacy of an operator's decision process. 
Requiring operators to use the integrity management process, and having 
regulators validate the adequacy and implementation of this process, 
should expedite the operators' rates of remedial action, thereby 
strengthening the pipeline system and reducing the public's exposure to 
risk.
    RSPA/OPS does not believe that requiring this comprehensive 
process, including the re-assessment of pipelines in high consequence 
areas at the proposed intervals, will be an undue burden on natural and 
other gas transmission pipeline operators covered by this proposal. 
RSPA/OPS believes the added security this assessment will provide and 
the generally expedited rate of strengthening the pipeline system in 
populated areas is benefit enough to promulgate these requirements.

Regulatory Flexibility Act

    Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq. RSPA/OPS 
must consider whether this rulemaking would have a significant impact 
on a substantial number of small entities. RSPA/OPS estimates that 
there are 668 gas transmission operators that could potentially be 
impacted by this proposed rulemaking. This data comes from RSPA/OPS 
user fee data base. A pipeline company would be impacted if its 
pipeline could effect a high consequence area (HCA). HCA's are located 
primarily urban areas but include rural areas where more than 20 people 
congregate.
    The Small Business Administration (SBA) defines small entities in 
the gas transmission industry as those with revenues of less than $6 
million annually. RSPA/OPS does not collect information on operator 
revenues. The Census Bureau however does collect data on natural gas 
transmission pipeline companies. Natural gas transmission companies are 
listed under North American Industry Classification System (NAICS) 
486210 Pipeline Transmission of Natural Gas. The 1977 Census lists 
1,450 establishments. Establishments in the case of gas transmission 
companies means unique pipelines. Seven hundred and fifty two of these 
establishments have revenues under $5 million annually. These 
establishments are aggregated into firms. NAICS 486210 has 155 firms. 
Seventy-one of these firms have revenues of less than $5 million 
annually and could be considered small entities under the SBA.
    It is evident from the discussion above that several of the 668 
transmission operators reporting to RSPA/OPS are in fact establishments 
and not firms. RSPA/OPS does not have information on how many unique 
firms there are among the establishments that report.
    RSPA/OPS does not have detailed information on the number of small 
entities in the gas transmission industry.

[[Page 4313]]

Some of the companies in the Census Bureau's figures are gas 
distribution companies that have transmission lines that serves their 
gas distribution business. Many of these transmission lines that serve 
gas distribution companies may be in HCA's. Other limited mileage 
transmission lines serve the fuel needs of one industrial plant. Many 
of these industrial transmission lines may be in rural areas and 
outside the scope of this proposed rule.
    RSPA/OPS has never received comments from small gas transmission 
operators concerning the burdens of its regulations. While RSPA/OPS 
believes that the costs of this proposal will be proportionate to the 
amount of mileage the pipeline company operates RSPA/OPS, seeks public 
input on any potential undue impact that this proposal would have on 
any small entities.
    INGAA estimates that its members account for 80% of the gas 
pipeline transmission mileage in the United States. INGAA has only 24 
members however, 3 of these members are not U.S. gas transmission 
operators. Therefore, approximately 21 companies account for 80% of the 
U.S. gas transmission pipeline mileage. The remainder of the pipeline 
companies in this industry share only 20% of the total pipeline 
mileage.
    Because the remaining companies have relatively small mileage 
compared to the top 20, many may fall entirely outside of HCA's, and 
will therefore not be impacted by this proposed rule. However, if they 
are impacted by this proposal, their costs of compliance will be 
significantly lower than those with thousands of miles of pipeline as 
the costs of inspection and planning should be considerably lower. 
Nevertheless, RSPA/OPS stands ready to provide special help to any 
small operators to assist them in complying with this proposed rule. 
Based on the above discussion I certify that this proposed rule will 
not have a significant impact on a substantial number of small 
entities.

Paperwork Reduction Act

    This proposed rule contains information collection requirements. As 
required by the Paperwork Reduction Act of 1995 (44 U.S.C. 3507(d)), 
the Department of Transportation has submitted a copy of the Paperwork 
Reduction Act analysis to the Office of Management and Budget for its 
review. The name of the information collection is ``Pipeline Integrity 
Management in High Consequence Areas Gas Transmission Pipeline 
Operators.'' The purpose of this information collection is designed to 
require operators of gas transmission pipelines to develop a program to 
provide direct integrity testing and evaluation of gas transmission 
pipelines in high consequence areas.
    The following is a summary of the highlights of the paperwork 
reduction act analysis. The complete analysis can be found in the 
public docket.
    There are 668 gas transmission operators that could potentially be 
subject to this proposed rule. It is estimated that 296 of these gas 
transmission operators have 40 or more miles of pipeline. The remaining 
372 operators have less than 40 miles of pipeline. It is estimated that 
the operators with more than 40 miles of pipeline will have 
considerably more time and expense to develop integrity management 
programs. However, before operators can develop integrity management 
programs they must determine how much of their pipeline is located in 
high consequence areas (HCA's). It is estimated that it will take the 
operators with 40 or more miles of pipeline 1,000 hours to estimated 
the amount of pipeline impacted. Operators with less than 40 miles of 
pipeline will take only 250 hours.
    It is estimated that operators with 40 or more miles of pipeline 
will need 3,968 hours to develop an integrity management plan 
framework. For operators with less than 40 miles of pipeline it is 
estimated this task will take 2,400 hours. However, it is estimated 
that 25% of the companies with more 40 miles or more of pipeline 
already have integrity management program frameworks.
    Additionally, all the operators will be required to integrate the 
new data they collect into their current management systems. The time 
to integrate the data the first year will be 2,040 hours for the 
companies with 40 or more miles of pipeline and 510 hours for companies 
with less than 40 miles of pipeline. It is estimated that 25% of all 
operators with 40 or more miles of pipeline already have a system for 
integrate their data.
    It will take operators initially, approximately 16 hours of a 
computer programmer's time to provide OPS and state pipeline safety 
offices ``real time'' access to their performance measures via the 
operator's web site or a dial-up modem.
    The integrity management plans need to be modified on a yearly 
basis. RSPA/OPS estimates that it will take all operators regardless of 
size 313 hours per year to update their plans annually. RSPA/OPS 
further estimates it will take an additional 160 hours per operator to 
perform the necessary record keeping annually. Finally RSPA/OPS 
estimates it will take operators with 40 or more miles of pipeline 1020 
hours to annually integrate the necessary data. It will take operators 
with less than 40 miles of pipeline approximately 255 hours to annually 
integrate the necessary data.
    Comments concerning this information collection should include the 
docket number of this proposal. They should be sent to Docket Facility, 
U.S. Department of Transportation, Plaza 401, 400 Seventh Street, SW, 
Washington, DC 20590-0001. Comments are specifically requested 
concerning:
    Whether the collection is necessary for the proper performance of 
the functions of the Department, including whether the information 
would have a practical use;
    The accuracy of the Department's estimate of the burden of 
collection of information including the validity of assumptions used;
    The quality, usefulness and clarity of the information to be 
collected; and minimizing the burden of collection of information on 
those who are to respond, including through the use of appropriate 
automated electronic, mechanical, or other technological collection 
techniques or other forms of information technology e.g., permitting 
electronic submission of responses.
    According to the Paperwork Reduction Act of 1995, no persons are 
required to respond to a collection of information unless a valid OMB 
control number is displayed. The valid OMB control number for this 
information collection will be published in the Federal Register after 
it is approved by the OMB. For details see, the complete Paperwork 
Reduction analysis available for copying and review in the public 
docket.

Executive Order 13084

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

Executive Order 13132

    This proposed rule has been analyzed in accordance with the 
principles and criteria contained in Executive Order 13132 
(``Federalism''). This proposed rule does not propose any regulation 
that:

[[Page 4314]]

    (1) Has substantial direct effects on the States, the relationship 
between the national government and the States, or the distribution of 
power and responsibilities among the various levels of government;
    (2) Imposes substantial direct compliance costs on States and local 
governments; or
    (3) Preempts state law.
    Therefore, the consultation and funding requirements of Executive 
Order 13132 (64 FR 43255; August 10, 1999) do not apply. Nevertheless, 
in November 18-19, 1999, and in February 12-14, 2001 public meetings, 
RSPA/OPS invited National Association of Pipeline Safety 
Representatives (NAPSR), which includes State pipeline safety 
regulators, to participate in a general discussion on pipeline 
integrity. Since then, RSPA/OPS has held conference calls with NAPSR, 
to receive their input before proposing an HCA definition and integrity 
management rule.

Executive Order 13211

    This rulemaking is not a ``significant energy action'' within the 
meaning of Executive Order 13211 (``Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use''). It is a 
significant regulatory action under Executive Order 12866 because of 
its significant public and government interest. As concluded from our 
Energy Impact Statement below it is not likely to have a significant 
adverse effect on the supply, distribution, or use of energy. Further, 
this rulemaking has not been designated by the Administrator of the 
Office of Information and Regulatory Affairs as a significant energy 
action.

Summary of the Energy Impact Statement

(For a detailed Energy Impact Statement, please refer to Docket RSPA-
00-7666)

    RSPA/OPS is currently proposing regulations to assess, evaluate, 
remediate, and validate the integrity of natural gas transmission 
pipelines through comprehensive analysis and inspection of pipeline 
systems. The proposed rule applies to all gas transmission lines, 
including lines transporting petroleum gas, hydrogen, and other gas 
products covered under 49 CFR Part 192.
    In compliance with the Executive Order 13211 (66 FR 28355), RSPA/
OPS has evaluated the effects of proposed rule on energy supply, 
distribution, or use. RSPA/OPS has determined that this proposed 
regulatory action will not have significant adverse effects on energy 
supply, distribution, or use.
    The proposed rule will not have any significant impact on the 
wellhead production capacity or prices. The proposed rule affects 
natural gas transmission lines in high consequence areas (HCAs) and has 
no effect on the wellhead production capacity or prices. The proposed 
rule does not impact gathering lines and offshore transmission lines, 
and has limited effect on the onshore transmission lines that are not 
located in the HCAs. Therefore, the proposed rule will have no 
significant impact on natural gas production or wellhead prices. RSPA/
OPS estimates that the proposed rule will directly affect 42,268 miles 
of transmission lines in a network of 300,000 miles of transmission 
lines, as well as 900,000 miles of distribution lines. Therefore, a 
relatively small proportion of pipelines will be affected by the 
proposed rule.
    The proposed rule may affect the movement of natural gas in certain 
areas during integrity inspection. Inspection requirements may 
temporarily affect transportation capacity in some pipelines. Built-in 
redundancies, such as, loop lines, multiple lines, storage facilities, 
are part of natural gas transportation infrastructures. The intricate 
interconnections between pipelines, the availability of storage at the 
market centers, and a well-developed capacity release market all 
contribute towards meeting natural gas demand with efficient movement 
of supply. Most inspections can be conducted without any significant 
disruption of throughput especially during off-peak seasons.
    The proposed rule may not have any significant price effects on 
end-use consumers. In general, inter-fuel competition and gas-storage 
availability play significant roles in short-term price determination 
in U.S. because of extensive fuel switching capability in industry and 
power generation and the existence of a sizable storage capacity. 
Weather is the other significant player determining the spot market 
prices. Transportation cost only accounts for a small proportion of the 
cost paid by the end-users. The pipeline capacity reduction due to the 
proposed integrity rule may to a large extent be pre-planned and the 
market would have time to adjust for the reduction, minimizing 
shortages and avoiding short-term price increases.
    However, because the percentage of assessments that the industry 
maintains will be done by internal inspection, much more than 42,268 
miles of pipeline cited earlier may in fact be assessed. The reason for 
this is because internal inspection devices are inserted and removed 
from the pipeline segment near compressor stations which are up to 50 
miles apart. The HCAs may be only a few miles of this entire 50 mile 
section. The industry maintains that 50% of all lines or approximately 
150,000 miles of all gas pipelines will be internally inspected. If 
this is correct then, temporary impact on local gas supplies may be 
realized. While RSPA/OPS did not estimate the size of such temporary 
impacts it could lead to small changes in natural gas prices for 
certain areas on the spot market. Not withstanding possible temporary 
price fluctuations in the spot market, RSPA/OPS believes the proposed 
regulation will not significantly impact the overall energy supply, 
distribution, and use.

Unfunded Mandates

    This proposed rule does impose unfunded mandates under the Unfunded 
Mandates Reform Act of 1995, because it may result in the expenditure 
by the private sector of 100 million or more in any one year. The cost-
benefit analysis estimating yearly cost for operators to meet the 
proposed rule requirements has been placed in the docket. State 
regulators have participated in our meetings with the industry and 
research institutions on various integrity management issue discussions 
and have provided recommendations during our meetings and conference 
calls. We believe it is the least burdensome alternative that achieves 
the objective of the rule, because it gives options to industry on how 
to implement the rule.

National Environmental Policy Act

    We have evaluated the proposed rule for purposes of the National 
Environmental Policy Act (42 U.S.C. 4321 et seq.) and have 
preliminarily concluded that this action would not significantly affect 
the quality of the human environment. The Environmental Assessment 
determined that the combined impacts of the baseline assessment 
(pressure testing, internal inspection, or direct assessment), the 
periodic reassessments, and the additional preventive and mitigative 
measures that may be implemented for gas pipeline segments that could 
affect high consequence areas will result in positive environmental 
impacts. The number of incidents and the environmental damage from 
failures near high consequence areas is likely to be reduced. However, 
from a national perspective, the impact is not expected to be 
significant.

[[Page 4315]]

    Although the effects of the proposed rule will likely lead to fewer 
incidents, gas pipeline leaks that lead to adverse environmental 
impacts are rare under current conditions. Although the damage from 
failures could be reduced, the environmental damage resulting from gas 
pipeline failures is usually minor under current conditions. The 
effects are typically negligible, but can consist of localized, 
temporary damage to the environment in the immediate vicinity of the 
failure location on the pipeline.
    Some operators covered by the proposed rule already have integrity 
assessment programs. These operators typically consider the pipeline's 
proximity to populated areas when making decisions about where and when 
to inspect and test pipelines. As a result, some pipeline segments that 
could impact high consequence areas have already been recently 
assessed, and others would be assessed in the next several years 
without the provisions of the proposed rule. The primary effect of the 
proposed rule--accelerating integrity assessment in some high 
consequence areas--shifts increased integrity assurance forward for a 
few years for some segments that could affect high consequence areas. 
Because pipeline failure rates are low, shifting the time at which 
these segments are assessed forward by a few years has only a small 
effect on the likelihood of pipeline failure in these locations.
    The proposed rule does require operators to conduct an integrated 
assessment of the potential threats to pipeline integrity, and to 
consider additional preventive and mitigative risk control measures to 
provide enhanced protection. If there is a vulnerability to a 
particular failure cause, these assessments should result in additional 
risk controls to address these threats. However, without knowing the 
specific high consequence area locations, the specific risks present at 
these locations, and the existing operator risk controls (including 
those that surpass the current minimum regulatory requirements), it is 
difficult to determine the impact of this requirement.
    Some gas pipeline operators already perform integrity evaluations 
or risk assessments that consider the environmental and population 
impacts. These evaluations have already led to additional risk controls 
beyond existing requirements to improve protection for these locations. 
For many segments, it is probable that operators will determine that 
the existing preventive and mitigative activities provide adequate 
protection to high consequence areas, and that the small additional 
risk reduction benefits of additional risk controls are not justified.
    The primary benefit of the proposed rule will be to establish 
requirements for conducting integrity assessments and periodic 
evaluations of integrity of segments that could impact high consequence 
areas. This will codify the integrity management programs and 
assessments operators are currently implementing. It will also require 
other operators, who have little, or no, integrity assessment and 
evaluation programs to raise their level of performance. Thus, the 
proposed rule is expected to ensure a more consistent, and overall 
higher level of protection for high consequence areas across the 
industry.
    The Environmental Assessment of this proposed rule is available for 
review in the docket.

List of Subjects in 49 CFR Part 192

    High consequence areas, potential impact areas, pipeline safety, 
and record-keeping requirements.

    In consideration of the foregoing, RSPA/OPS proposes to amend part 
192 of title 49 of the Code of Federal Regulations as follows:

PART 192--[AMENDED]

    1. The authority citation for part 192 continues to read as 
follows:

    Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110, 
60113, and 60118; and 49 CFR 1.53.

    2. In subpart M, under the undesignated centerheading ``High 
Consequence Areas,'' in Sec.  192.761, in the definition beginning ``A 
high consequence area,'' the word ``A'' is removed, paragraphs (a) and 
(b) are revised, paragraph (g) is added, and new definitions of 
Confirmatory direct assessment, Direct assessment, Moderate risk area, 
Potential impact circle, Potential impact radius, Potential impact 
zone, and Threshold radius are added alphabetically to read as follows:


Sec.  192.761  Definitions.

    The following definitions apply to this section and Sec.  192.763:
    Confirmatory direct assessment is a streamlined integrity 
assessment method that utilizes process steps similar to direct 
assessment to evaluate for the presence of corrosion and third party 
damage.
    Direct assessment is an integrity assessment method that utilizes a 
process to evaluate certain threats (i.e., external corrosion, internal 
corrosion and stress corrosion cracking) to a pipeline's integrity. The 
process includes the gathering and integration of risk factor data, 
indirect examination or analysis to identify areas of suspected 
corrosion, direct examination of the pipeline in these areas, and post 
assessment evaluation.
    High consequence area means any of the following areas:
    (a) An area defined as a Class 3 location under Sec.  192.5, except 
for an area within the class 3 location defined as a moderate risk 
area.
    (b) An area defined as a Class 4 location under Sec.  192.5, except 
for an area with the class 4 area defined as a moderate risk area.
    (c) * * *
    (d) * * *
    (e) * * *
    (f) * * *
    (g) An area of a circle of threshold radius 1000 feet or larger 
that has a cluster of 20 or more buildings intended for human 
occupancy. The threshold radius is measured from the centerline of the 
pipeline to the nearest building in the cluster.
    Moderate risk area means an area located within a Class 3 or Class 
4 location, but not within the potential impact zone.
    Potential impact circle is a circle of radius equal to the 
threshold radius and is used to establish the higher priority area 
within a Class 3 or 4 area of a high consequence area. A potential 
impact circle contains any of the following within its radius (refer to 
the diagram in Appendix E):
    (1) Twenty or more buildings intended for human occupancy within a 
1000-foot or larger circle of radius;
    (2) A facility that is occupied by persons who are hard to evacuate 
as defined in Sec.  192.761 no matter the size of the circle of radius; 
or
    (3) A place where people congregate as defined in Sec.  192.761, no 
matter the size of the circle of radius.
    Potential impact radius (PIR) means the radius of a circle within 
which the potential failure of a pipeline could have significant impact 
on people or property. PIR is determined by the formula r = 0.69 * 
(square root of (p*d2)), where ``r'' is the radius of a circular area 
surrounding the point of failure (ft), ``p'' is the maximum allowable 
operating pressure (MAOP) in the pipeline segment (psi) and ``d'' is 
the diameter of the pipeline (inches). Note: 0.69 is the factor for 
natural gas. This number will vary for other gases depending upon their 
heat of combustion. An operator transporting gas other than natural gas 
must use Section 3.2 of ASME/ANSI B31.8S to calculate the impact radius 
formula.

[[Page 4316]]

(See Appendix A to this part 192 for incorporation by reference and 
availability information.)
    Potential impact zone is a rectangular area along the pipeline 
derived from the potential impact circle. The potential impact zone 
extends axially along the length of the pipeline from the center of the 
first potential impact circle to the center of the last contiguous 
potential impact circle, and extends perpendicular to the pipe out to 
the threshold radius on either side of the centerline of the pipe. 
(Refer to the diagram in Appendix E).
    Threshold radius is an additional area of safety beyond the 
distance calculated as the potential impact radius. If the calculated 
potential impact radius is less than 300 feet, the operator must use a 
threshold radius of 300 feet. If the calculated potential impact radius 
exceeds 300 feet but is less than 660 feet, the threshold radius is 660 
feet. If the calculated potential impact radius exceeds 660 feet, but 
is less than 1000 feet, the threshold radius is 1000 feet. And, if the 
calculated potential impact radius exceeds 1000 feet, the threshold 
radius is 15% greater than the actual calculated impact radius.
    3. A new Sec.  192.763 is added under a new undesignated 
centerheading of ``Pipeline Integrity Management'', in subpart M to 
read as follows:

Pipeline Integrity Management


Sec.  192.763  Pipeline integrity management in high consequence areas.

    (a) Which operators must comply?
    This section applies to each operator who owns or operates a 
transmission line that transports gas, including, petroleum gas, 
hydrogen, or other gas product covered under this part.
    (b) Which pipeline segments are covered?
    Transmission pipeline segments as defined in Sec.  192.3 that are 
in a high consequence area, as defined in Sec.  192.761.
    (c) What must an operator do?
    (1) General requirements. No later than [one year from the 
effective date of the final rule], an operator must develop and follow 
a written integrity management program that addresses the risks on each 
pipeline segment covered by this section. An operator must--
    (i) Identify all high consequence areas as defined in Sec.  
192.761, and identify the potential impact zone within each high 
consequence area. Based on the identification of the potential impact 
zone within Class 3 and Class 4 locations, identify all moderate risk 
areas. The identification must include the calculation used in 
determining the threshold radius for each covered pipeline segment, and 
any process and factors used in determining the potential impact zone.
    (ii) Develop a framework addressing each element required to be in 
an integrity management program, that includes a plan for baseline 
assessment of the line pipe (see paragraphs (e) and (g) of this 
section), and a plan for continual integrity assessment and evaluation 
(see paragraphs (d) and (k) of this section). The framework must 
document how decisions will initially be made to implement each program 
element, and planned near-term improvements to program elements and 
decision processes.
    (iii) Develop a plan that describes how the operator will use 
direct assessment as part of its integrity assessment (see paragraph 
(h) of this section), to include identification of External Corrosion 
Direct Assessment Regions and Internal Corrosion Direct Assessment 
Regions. This requirement only applies to an operator that plans to use 
direct assessment.
    (iv) Develop a process for continual improvement of the framework 
into an ongoing integrity management program.
    (2) Time period. An operator must complete the requirements of 
paragraph (c)(1) no later than [12 months from the effective date of 
the final rule].
    (3) Implementation. An operator must implement and follow the 
program it develops. In carrying out this section, an operator must 
follow the requirements of this section and of ASME/ANSI B31.8S, and 
its appendices, where specified. (See Appendix A to this part 192 for 
incorporation by reference and availability information.) An operator 
may follow an equivalent standard or practice only when the operator 
demonstrates the alternative standard or practice provides an 
equivalent level of safety to the public and property. In the event of 
a conflict between this section and ASME/ANSI B31.8S, the requirements 
in this section control.
    (4) Program changes. An operator must document, prior to 
implementing any change to its program, any change to the program and 
reasons for the change. In addition, an operator must notify OPS in 
accordance with paragraph (n) of this section of any change to the 
program that substantially affect the program's implementation or 
significantly modifies the program or schedule for carrying out the 
program elements. An operator must provide the notification within 30 
days after adopting this type of change into its program.
    (5) Performance-based option. ASME/ANSI B31.8S provides the 
essential features of both a performance-based and a prescriptive 
integrity management program. An operator that uses a performance-based 
approach that satisfies the requirements in paragraph (c)(5)(i) may 
deviate from certain requirements in this section, as provided in 
paragraph (c)(5)(ii).
    (i) Exceptional performance. To deviate from any of the 
requirements set forth in paragraph (c)(5)(ii), an operator must have 
completed a baseline assessment of all pipeline segments covered by 
this section, in accordance with paragraph (g) of this section, and at 
least one other assessment. An operator must remediate all anomalies 
identified in the second assessment according to the requirements in 
paragraph (i), and incorporate the results and lessons learned from the 
second assessment into the operator's risk model. An operator must also 
demonstrate that it has an exceptional integrity management program 
that meets the performance-based requirements of ASME/ANSI B31.8S, has 
a history of measurable performance improvement, and includes, at 
minimum--
    (A) A state-of-the-art process for risk analysis;
    (B) All risk factor data used to support the program;
    (C) A state-of-the-art data integration process;
    (D) A process that applies lessons learned from assessment of 
covered pipe segments to pipe segments not covered by this section;
    (E) A process for evaluating all incidents, including their causes, 
within the operator's sector of the pipeline industry for implications 
both to the operator's pipeline system and to the operator's integrity 
management program;
    (F) A performance matrix that confirms the continuing performance 
improvement realized under the performance-based program;
    (G) A set of performance measures beyond those required in 
paragraph (l) of this section that are part of the operator's 
performance plan (see paragraph (d)(1)(viii)) and are made accessible 
in real time to OPS and state pipeline safety enforcement officials;
    (H) An analysis that supports the desired integrity reassessment 
interval and the remediation methods to be used for all pipe segments.
    (ii) Deviation. Once an operator has demonstrated that it has 
satisfied the requirements of paragraph (c)(5)(i), the operator may 
deviate from the prescriptive requirements of ASME/ANSI B31.8S and of 
this section only in the following instances.

[[Page 4317]]

    (A) The time frame for reassessment as provided in paragraph (k), 
except that reassessment by some method (e.g., confirmatory direct 
assessment) must be carried out at intervals no longer than seven 
years;
    (B) Direct assessment as a primary assessment method without having 
to meet the conditions specified in paragraph (h)(1); and
    (C) The time frame for remediation as provided in paragraph (i).
    (d) What are the elements of an integrity management program?
    (1) General. An operator's initial integrity management program 
framework and subsequent integrity management program must, at minimum, 
contain the following elements. (When indicated, refer to ASME/ANSI 
B31.8S for more detailed information on the listed element.)
    (i) An identification of covered pipeline segments and the 
potential impact zone for each segment. An identification includes a 
calculation of the potential impact radius and threshold radius for 
each segment.
    (ii) A baseline assessment plan meeting the requirements of 
paragraphs (e) and (g) of this section.
    (iii) An identification of threats to each covered pipeline 
segment, which includes a risk assessment to evaluate the failure 
likelihood of each covered segment. An operator will use the threat 
identification and risk assessment to prioritize segments for 
assessment (paragraphs (g) and (k)) and evaluate the merits of 
additional preventive and mitigative measures (paragraph (j)). The 
identification and risk assessment process must comply with the 
requirements in paragraph (f) of this section.
    (iv) A direct assessment plan, if applicable, meeting the 
requirements of paragraph (h) of this section.
    (v) Provisions meeting the requirements of paragraph (i) of this 
section for remediating conditions found during an integrity 
assessment.
    (vi) A process for continual evaluation and assessment meeting the 
requirements of paragraphs (h)(6) and (k) of this section. If 
applicable, the process must include a plan for confirmatory direct 
assessment meeting the requirements of paragraph (h)(6).
    (vii) Preventive and mitigative measures meeting the requirements 
of paragraph (j) of this section.
    (viii) A performance plan as outlined in ASME/ANSI B31.8S, Section 
9 that includes performance measures meeting the requirements of 
paragraph (l) of this section.
    (ix) Record keeping requirements meeting the requirements of 
paragraph (m) of this section.
    (x) A management of change process as outlined in ASME/ANSI B31.8S, 
Section 11.
    (xi) A quality assurance process as outlined in ASME/ANSI B31.8S, 
Section 12.
    (xii) A communication plan that includes the elements of ASME/ANSI 
B31.8S, Section 10, and that includes a process for addressing safety 
concerns raised by OPS, including safety concerns OPS raises on behalf 
of a State or local authority with which OPS has an interstate agent 
agreement.
    (xiii) A process for providing, by electronic or other means, a 
copy of the operator's integrity management program to a State 
authority with which OPS has an interstate agent agreement.
    (xiv) A process for ensuring that each integrity assessment is 
being conducted in a manner that minimizes environmental and safety 
risks.
    (2) Training. (i) Supervisory personnel. An operator's integrity 
management program must provide that each supervisor possesses and 
maintains a thorough knowledge of the operator's integrity management 
program and the elements for which the supervisor is responsible. The 
program must provide that any person who qualifies as a supervisor for 
the integrity management program has appropriate training or experience 
in the area for which the person is responsible.
    (ii) Persons who evaluate. An operator's integrity management 
program must provide criteria for the qualification of persons who 
review and analyze results from integrity assessments and evaluations. 
These criteria include criteria for persons who carry out and interpret 
the results from the direct assessment process.
    (3) Newly-identified areas. The program must provide for 
identification and assessment of newly-identified high consequence 
areas. When an operator has information that the area around a pipeline 
segment satisfies any of the definitions for high consequence areas in 
Sec.  192.761, the operator must incorporate the area into its 
integrity management program within one year from the date the area is 
identified.
    (e) What must be in the baseline assessment plan? An operator must 
include each of the following elements in its written baseline 
assessment plan:
    (1) Identification of the potential threats to each of the covered 
pipeline segments. (See paragraph (f) of this section);
    (2) The methods selected to assess the integrity of the line pipe, 
including an explanation of why the assessment method was selected to 
address the identified threats to each covered segment. The integrity 
assessment method an operator uses must be based on the threats 
identified to the segment (see paragraph (f) of this section). More 
than one method may be required to address all the threats to the 
pipeline segment;
    (3) A schedule for completing the integrity assessment of all 
covered line segments, including, risk factors considered in 
establishing the assessment schedule;
    (4) If applicable, a direct assessment plan that meets the 
requirements of paragraph (h) of this section.
    (5) A process describing how the operator is ensuring that the 
baseline assessment is being conducted in a manner that minimizes 
environmental and safety risks.
    (f) How does an operator identify potential threats to pipeline 
integrity?
    (1) Threat identification. An operator must identify and evaluate 
all potential threats to each covered pipeline segment. Potential 
threats that an operator must consider include, but are not limited to, 
the threats listed in ASME/ANSI B31.8S , section 2 and the following:
    (i) Time dependent threats such as internal corrosion, external 
corrosion, and stress corrosion cracking;
    (ii) Static or resident threats, such as fabrication or 
construction defects;
    (iii) Time independent threats such as third party damage and 
outside force damage; and
    (iv) Human error.
    (2) Data gathering and integration. To identify and evaluate the 
potential threats to a covered pipeline segment, an operator must 
gather and integrate data and information on the entire pipeline that 
could be relevant to the covered segment. In performing this data 
gathering and integration, an operator must follow the requirements in 
ASME/ANSI B31.8S, section 4. At a minimum, an operator must gather and 
evaluate the set of data specified in Appendix SP-A to ASME/ANSI 
B31.8S, and consider both on the covered segment and similar segments, 
past incident history, corrosion control records, continuing 
surveillance records, patrolling records, maintenance history, and all 
other conditions specific to each pipeline.
    (3) Risk assessment. An operator is to conduct a risk assessment on 
each covered segment that follows ASME/ANSI B31.8S, section 5, and uses 
the threats identified for each segment. An operator will use the risk 
assessment to prioritize the segments for the baseline

[[Page 4318]]

and continual re-assessments (paragraphs (e), (g) and (k) of this 
section), and in determining what additional preventive and mitigative 
measures are needed (paragraph (j) of this section).
    (g) How is the baseline assessment to be conducted?
    (1) Assessment methods. An operator must assess the integrity of 
the line pipe in each covered segment by applying one or more of the 
following methods depending on the threats to which the segment is 
susceptible. An operator must select the method or methods best suited 
to address the threats identified to the segment (See paragraph (f) of 
this section).
    (i) Internal inspection tool or tools capable of detecting 
corrosion, and any other threats to which the pipe segment is 
susceptible. An operator must follow ASME/ANSI B31.8S in selecting the 
appropriate internal inspection tools.
    (ii) Pressure test conducted in accordance with subpart J of this 
part;
    (iii) Direct assessment to address threats of external corrosion, 
internal corrosion, and stress corrosion cracking. An operator must 
conduct the direct assessment in accordance with ASME/ANSI B31.8S and 
paragraph (h) of this section;
    (iv) Other technology that an operator demonstrates can provide an 
equivalent understanding of the condition of the line pipe. An operator 
choosing this option must notify the Office of Pipeline Safety (OPS) 
180 days before conducting the assessment, in accordance with paragraph 
(n) of this section.
    (2) Prioritizing segments. An operator must prioritize the covered 
pipeline segments for the baseline assessment according to a risk 
analysis that considers the potential threats to each segment. The risk 
analysis must comply with the requirements in paragraph (f) of this 
section.
    (3) Assessment for particular threats. In choosing an assessment 
method for the baseline assessment, an operator must take the following 
actions to address particular threats that it has identified. (See 
paragraph (f) of this section).
    (i) Third party damage. An operator must address the third party 
damage threat through the following:
    (A) Preventive measures. An operator must implement comprehensive 
additional preventive measures (see paragraph (j)) to address the 
threat, and monitor the effectiveness of the preventive measures.
    (B) Assessment tools. An operator must assess covered segments that 
are vulnerable to delayed failure following third party damage using 
internal inspection tools, such as deformation or geometry tools. An 
operator may use direct assessment as the primary assessment method for 
third party damage only if no other approach is feasible, and it is 
combined with data collection and integration to evaluate segment 
susceptibility to third party damage. An operator that does not use a 
geometry tool for the internal inspection or uses direct assessment 
must excavate and directly examine all indications that could be the 
result of third party damage.
    (ii) Cyclic fatigue. An operator must evaluate whether cyclic 
fatigue or other loading condition (including ground movement, 
suspension bridge condition) necessitates a periodic assessment for 
dents and gouges. An evaluation must assume the presence of deep dents, 
and determine whether loading conditions would lead to failure of such 
hypothesized dents. An operator must use the results from an evaluation 
together with the criteria used to evaluate the significance of this 
threat.
    (iii) Manufacturing and construction defects. To address 
manufacturing and construction defects (including seam defects), an 
operator must perform a pressure test at least once in the life of the 
segment unless the operator demonstrates why pressure testing is not 
necessary to address this threat. If an operator does not perform a 
pressure test, and at anytime the historic operating pressure or other 
stress condition changes, including any condition that affects cyclic 
fatigue, the operator must, prior to changing the stress condition, 
assess the pipeline using an assessment method allowed by this section.
    (iv) ERW pipe. The methods an operator selects to assess low 
frequency electric resistance welded pipe or lap welded pipe 
susceptible to seam failures must be capable of assessing seam 
integrity and of detecting seam corrosion anomalies.
    (v) Corrosion. If an operator finds corrosion on a covered pipeline 
segment that could adversely affect the integrity of the line 
(conditions specified in paragraph (i)), the operator must conduct an 
integrity assessment and remediate all pipeline segments with similar 
material coating and environmental characteristics. An operator must 
establish a schedule for evaluating and remediating the similar 
segments that is consistent with the operator's established operating 
and maintenance procedures under Part 192 for testing and repair.
    (4) Time period. An operator must comply with the following 
requirements in conducting the baseline assessment of the covered 
segments.
    (i) Internal inspection or pressure test. An operator that uses an 
internal inspection tool or pressure test as an integrity assessment 
method must comply with the following time periods for conducting the 
assessment.
    (A) Unless the exception in paragraph (g)(4)(i)(B) of this section 
applies, an operator using a pressure test or internal inspection tool 
as an assessment method must complete the baseline assessment by 
December 17, 2012. An operator must assess at least 50% of the line 
pipe being assessed by either of these methods beginning with the 
highest risk pipe, by December 17, 2007. An operator must prioritize 
segments for assessment in accordance with paragraphs (f)(3) and (g)(2) 
of this section, giving highest priority to those segments located in 
the potential impact zone (refer to Appendix E for guidance).
    (B) An operator using a pressure test or internal inspection tool 
as an assessment method on a pipeline segment located in a moderate 
risk area (an area within a Class 3 or Class 4 location, but not within 
the potential impact zone), must complete the baseline assessment by 
December 17, 2015.
    (ii) Direct assessment. An operator that uses direct assessment as 
an integrity assessment method must comply with the following time 
periods for conducting the assessment.
    (A) Unless the exception in paragraph (g)(4)(ii)(B) applies, an 
operator using direct assessment as an assessment method must complete 
the baseline assessment by December 17, 2009. An operator must assess 
at least 50% of the line pipe being assessed by this method, beginning 
with the highest risk pipe, by December 17, 2006. Direct assessment 
must be carried out in accordance with paragraph (h) of this section. 
An operator must prioritize segments for assessment in accordance with 
paragraphs (f)(3) and (g)(2) of this section, giving highest priority 
to those segments located in the potential impact zone (refer to 
Appendix E for guidance).
    (B) An operator using direct assessment as an assessment method on 
a pipeline segment located within a moderate risk area (area in a Class 
3 or Class 4 location, but not within the potential impact zone), must 
complete the baseline assessment of the line pipe being assessed by 
this method by December 17, 2012.
    (5) Prior assessment. An operator may use an integrity assessment 
conducted after December 17, 2007 as a baseline assessment, if the 
integrity assessment method meets the requirements of this

[[Page 4319]]

section. However, if an operator uses this prior assessment as its 
baseline assessment, the operator must reassess the line pipe according 
to the requirements of paragraph (k) of this section.
    (6) Newly identified areas. When the operator has information that 
the area around a pipeline segment satisfies any of the definitions in 
Sec.  192.761, the operator must incorporate the area into its baseline 
assessment plan as a high consequence area within one year from the 
date the area is identified. An operator must complete the baseline 
assessment of any line pipe in the newly identified high consequence 
area within 10 years (7 years if direct assessment is being used) from 
the date the area is identified.
    (h) When can direct assessment be used and under what conditions?
    (1) General. (i) An operator may use direct assessment as a 
supplement to the other assessment methods allowed under this section. 
However, an operator may use direct assessment as a primary assessment 
method for external corrosion, internal corrosion, or stress corrosion 
cracking only when the operator can demonstrate one of the following 
conditions applies--
    (A) The operator demonstrates that other assessment methods allowed 
under this section can not be applied to the pipeline segment for 
economic or technological reasons;
    (B) The operator demonstrates that other assessment methods allowed 
under this section would result in a substantial impact on gas 
customers, as for example, when only one pipeline delivers gas to homes 
or local businesses, and service would be completely shut down during 
the assessment;
    (C) The operator will excavate and conduct a direct examination of 
the entire covered pipeline segment in accordance with the requirements 
of this paragraph; or
    (D) The covered pipeline segment operates at a maximum allowable 
operating pressure below 30% SMYS.
    (ii) An operator using direct assessment as a supplemental 
assessment method must have a plan that follows the requirements for 
confirmatory direct assessment in paragraph (h)(6) of this section. An 
operator using direct assessment as a primary assessment method must 
have a plan that complies with the requirements for use of direct 
assessment in ASME/ANSI B31.8S, section 6.4 and in this section.
    (2) Specific threats. An operator may only use direct assessment as 
a primary assessment method for external corrosion, internal corrosion, 
and stress corrosion cracking. An operator may use direct assessment as 
the primary assessment method for third party damage only if no other 
assessment method is feasible, and the operator uses it in combination 
with data collection and integration to evaluate the segment's 
susceptibility to third party damage.
    (3) External corrosion direct assessment (ECDA). An operator that 
uses direct assessment as the primary method to assess external 
corrosion must follow the requirements in this section and in ASME/ANSI 
B31.8S, Section 6 and Appendix SP-B.
    (i) ECDA plan. An operator using External Corrosion Direct 
Assessment (ECDA) must prepare a plan that includes--
    (A) A process that provides, according to the requirements of this 
paragraph, for Pre-Assessment, Indirect Examination, Direct 
Examination, and Post-Assessment.
    (B) Data requirements for using ECDA. These must, at a minimum, 
include the data requirements for external corrosion specified in 
Appendix SP-A1 to ASME/ANSI B31.8S.
    (C) Criteria for evaluating ECDA feasibility, in accordance with 
paragraph (h)(3)(ii)(A) of this section.
    (D) Criteria for defining ECDA Regions, in accordance with 
paragraph (h)(3)(ii)(B) of this section.
    (E) The basis on which an operator selects two complementary 
assessment tools to assess each ECDA Region. Guidance on selecting 
tools is found in Appendix E of this part.
    (F) Criteria for identifying and documenting those indications that 
must be considered for direct examination. Minimum criteria include the 
known sensitivities of assessment tools, the procedures for using each 
tool, and the approach to be used for decreasing the physical spacing 
of indirect assessment tool readings when the presence of a defect is 
suspected.
    (G) Criteria for characterizing indications identified in the ECDA 
process. These criteria must define how an operator will characterize 
an indication as severe, moderate or minor (See paragraph (h)(3)(iv) of 
this section).
    (H) Criteria for defining the urgency of excavation and direct 
examination of each indication. These criteria must specify how an 
operator will define the urgency of excavating the indication as 
immediate, scheduled or monitored. Monitored indications are defects 
that are not serious and may or may not require direct examination.
    (I) Criteria for scheduling excavation of each urgency level of 
indication, in accordance with paragraph (h)(3)(v) of this section.
    (J) Criteria for data gathering associated with each excavation.
    (K) Criteria for the qualification of persons who carry out and 
interpret the results from the direct assessment process (See paragraph 
(d)(2)(ii) of this section).
    (L) Criteria and measures for evaluating the long-term 
effectiveness of the ECDA process (See paragraph (h)(3)(vii) of this 
section).
    (ii) Pre-assessment. An operator using ECDA must conduct a pre-
assessment, in which the operator analyzes and integrates the data and 
information required in paragraph (f) of this section to carry out the 
following--
    (A) Feasibility. An operator will use the data to determine whether 
any of the following conditions exists that is likely to preclude the 
effective use of ECDA. If any of the listed conditions is present, the 
operator must demonstrate why the use of ECDA would be a more effective 
method to assess external corrosion than the other assessment methods 
allowed under this section and specify the provisions the operator will 
implement to ensure ECDA effectiveness.
    (1) The presence of a coating that causes electrical shielding;
    (2) Backfill around the pipe with significant rock content or the 
presence of rock ledges;
    (3) Situations impeding timely above-ground data gathering;
    (4) Locations with adjacent buried metallic structures;
    (5) Inaccessible areas.
    (B) ECDA Region. An operator must use the data gathered to define 
all ECDA regions within the covered pipeline segment. ECDA regions are 
those portions within a pipeline segment, not necessarily contiguous, 
that have similar physical characteristics, operating and corrosion 
history, expected future corrosion conditions, and which are suitable 
for the same indirect assessment methods. An operator may redefine ECDA 
regions at any time the information the operator develops in conducting 
justifies a redefinition. If a condition, such as those specified in 
paragraph (h)(3)(vi)(C) of this section, exists for which ECDA is 
ineffective at assessing, an operator must select an alternate 
assessment technology allowed under this section.
    (iii) Indirect examination. An operator's ECDA plan must provide 
for indirect examination of the ECDA regions. In carrying out the 
indirect examination, an operator must follow ASME/ANSI B31.8S, 
Appendix SP-B2 and the requirements of this section.

[[Page 4320]]

    (A) Unless the exception in paragraph (h)(3)(iii)(B) of this 
section applies, an operator must select at least two different, but 
complementary, indirect examination methods, for each location where 
ECDA is to be applied along the pipeline segment. An operator must 
select the methods that can best detect external corrosion activity and 
holidays in the pipe coating under the conditions the operator expects 
to find on the pipeline. (Appendix E gives guidance on selecting two 
complementary methods). Indirect examination methods include, but are 
not limited to, Close Interval Surveys (CIS), Direct (or Alternate) 
Current Voltage Gradient (DCVG or ACVG), and electromagnetic 
techniques, such as Pipeline Current Mapper (PCM), and C-Scan). An 
operator must perform the indirect examination using the complementary 
methods selected for each ECDA Region. An operator must define the 
boundaries for use of each pair of ECDA tools, and ensure complete 
coverage through overlap between adjacent ECDA regions.
    (B) If one of the following conditions applies, an operator must 
use one indirect examination tool and one alternative (e.g. ultrasonic) 
tool to assess for external corrosion, unless the operator demonstrates 
that one method will be adequate to assure the integrity of the segment 
being assessed for external corrosion.
    (1) Pipe in frozen ground;
    (2) Pipe under paved roadways;
    (3) Pipe in cased crossings (either road or river).
    (C) An operator must also provide for the following in its indirect 
examination.
    (1) Repeating indirect examination methods on a sample basis to 
ensure consistent data are obtained;
    (2) Selecting intervals for capturing tool readings that are 
closely spaced enough to ensure consistent data are obtained. Data 
sampling intervals (locations of test points) for indirect examination 
methods should typically be no greater than the local depth of coverage 
of the pipeline;.
    (3) Carrying out indirect examination in an ECDA Region using the 
two complementary tools as close together in time as practical;
    (4) Geo-referencing above ground measurements to compare 
examination results and accurately identify excavation locations.
    (iv) Post-indirect examination. After an operator completes its 
indirect examination measurements for an ECDA Region, the operator must 
align the measures with the complementary tools and evaluate the 
consistency of the observations.
    (A) If the results from the two complementary tools are not 
consistent and cannot be explained by differences in the tools' 
capabilities, the operator must either conduct a direct examination or 
additional indirect examinations to evaluate the reasons for the 
differences.
    (B) If additional indirect inspections or direct examinations are 
not carried out or if they do not resolve the inconsistencies, the 
operator must re-evaluate the feasibility of ECDA.
    (C) An operator must identify and locate indications following the 
indirect inspection, and classify the severity of each indication as 
severe, moderate or minor using the criteria in the ECDA Plan. (See 
paragraph (h)(3)(i) of this section). These classifications must be 
conservatively developed the first time the process is applied.
    (D) An operator must compare the results from the pre-assessment 
step with the prior history for each ECDA Region. If assessment results 
are not consistent with operating history, the operator must reassess 
the feasibility of ECDA.
    (v) Direct examination. An operator's ECDA plan must include a 
process for using the results from the indirect examination to develop 
and carry out a direct examination plan. A direct examination includes 
an excavation to confirm the ability of the indirect examination to 
locate external corrosion. To carry out the direct examination an 
operator must--
    (A) Determine the order and timing of excavations from results of 
the indirect examination integrated with the risk factor data. An 
operator must base both order and timing on a classification of the 
indications as immediate action, scheduled action or monitored action. 
(See paragraph (h)(3)(i) of this section).
    (B) Make a direct examination (excavation) of all indications that 
meet the criteria for immediate action. An operator must excavate all 
immediate action indications promptly, but no later than six months 
after completing the indirect examination. If an operator finds any 
evidence of severe corrosion in an ECDA region, the operator must 
evaluate the entire covered segment and all other covered and non-
covered segments in the operator's pipeline system with similar 
characteristics, for corrosion, and take appropriate action for that 
segment, which could include an integrity assessment, remediation, or 
additional preventive or mitigative measures.
    (C) Make a direct examination of at least two of the highest risk 
indications in each ECDA Region that meet the criteria of scheduled 
action. An operator must excavate each scheduled action indication in 
order of priority, until the operator excavates at least two 
indications that have a corrosion of depth no greater than 20% of the 
wall thickness.
    (D) Make a direct examination of at least one of the highest risk 
indications in an ECDA region that contains only monitored indications.
    (E) Make a minimum of one direct examination in each ECDA Region. 
This examination must be made at the indication of highest risk. If no 
indications are shown in the ECDA Region, then the excavation must be 
made at a location that the operator considers to be the most suspect.
    (vi) Remediation. Except for conditions specified in paragraph 
(i)(4) of this section, an operator must remediate indications found 
during the direct assessment according to the requirements in ASME/ANSI 
B31.8S, section 7. Remediation must be consistent with a determination 
of remaining strength using ASME B31G or RSTRENG. (See Appendix A to 
this part 192 for incorporation by reference and availability 
information). If an operator finds an indication is associated with a 
defect that requires immediate remediation, the operator must reduce 
operating pressure by at least 20% in the associated ECDA Region and 
not increase this pressure until the operator has excavated, evaluated 
and remediated, as necessary, 100% of such indications within the 
region. In remediating a condition, an operator must also comply with 
the following--
    (A) If any exposed segment has significant coating degradation or 
corrosion, the operator must increase the size of that excavation until 
coating and pipe are determined to be adequate.
    (B) The operator must identify the root cause of all significant 
corrosion activity revealed by excavation.
    (C) When an operator identifies any defect in an ECDA Region that 
requires immediate mitigation, or determines that the root cause of any 
defect is a condition that ECDA is ineffective at assessing (e.g., MIC 
or shielded corrosion), the operator must for the current assessment 
cycle reassess the entire ECDA Region, using an alternative assessment 
method allowed by this section.
    (vii) Post-Assessment. An operator must determine the reassessment 
interval for the pipeline segment and evaluate the overall 
effectiveness of the ECDA process.
    (A) Reassessment. An operator must determine the reassessment 
interval according to the requirements in paragraph (k)(3) of this 
section.

[[Page 4321]]

    (B) Performance measures. An operator must define and monitor 
measures to determine the effectiveness of the ECDA process. At 
minimum, these measures must track--
    (1) The effectiveness of the overall process (e.g., the change in 
the calculated reassessment interval);
    (2) The extent and severity of corrosion found;
    (3) The number of indications in each classification located on 
successive applications of ECDA; and
    (4) The time from discovery of an indication categorized as 
immediate action or scheduled action to its excavation.
    (4) Internal corrosion direct assessment (ICDA). ICDA is a process 
that identifies areas along the pipeline where water or other 
electrolyte introduced by an upset condition may reside, then focuses 
direct examination on the locations in each area where internal 
corrosion is most likely to exist. An operator using direct assessment 
as an assessment method to address internal corrosion in a pipeline 
segment must follow the requirements in ASME/ANSI B31.8S, Appendix SP-
B2, and in this section.
    (i) ICDA plan. An operator that uses direct assessment to assess 
internal corrosion must prepare a plan that, at minimum, provides for 
the following--
    (A) A process for data gathering to evaluate the potential for 
internal corrosion, and to support pre-assessment in accordance with 
paragraph (h)(4) (ii) (A) of this section;
    (B) Identification of ICDA Regions, in accordance with paragraph 
(h)(4)(ii)(B) of this section;
    (C) Identification of excavation locations and direct examination 
of the locations in accordance with paragraphs (h)(4)(ii)(C) and 
(h)(4)(ii)(D) of this section;
    (D) Post assessment and continuing evaluation in accordance with 
paragraph (h)(4)(ii)(E).
    (ii) Corrosion identification. An operator must have a process to 
evaluate the potential for internal corrosion caused by water, 
CO2, O2, chlorides, hydrogen sulfide and other 
contaminants present in the gas, and for MIC. This process must, in 
accordance with the requirements of this paragraph, provide for pre-
assessment, identification of ICDA regions and excavation locations, 
direct examination and post assessment.
    (A) Pre-assessment. An operator must gather information needed to 
identify areas along the covered pipeline segment where internal 
corrosion is most likely to exist. An operator will use this 
information to identify the locations where water may accumulate, to 
identify ICDA regions, and to support the flow model. This information 
includes, but is not limited to--
    (1) All data elements listed in Appendix SP-A2 of ASME/ANSI B31.8S.
    (2) Information needed to support a flow model that an operator 
uses to determine areas along the pipeline where internal corrosion is 
most likely to occur. This information, includes, but is not limited 
to, location of all gas input and withdrawal points on the line; 
location of all low points on the line such as sags, drips, inclines, 
valves, manifolds, dead-legs, and traps; the elevation profile of the 
pipeline in sufficient detail that angles of inclination can be 
calculated for all pipe segments; and the diameter of the pipeline, and 
the range of expected gas velocities in the pipeline.
    (3) Operating experience data that would provide an indication of 
historic upsets in gas conditions, locations where these upsets have 
occurred, and any indications of damage resulting from these upset 
conditions.
    (B) Identification of ICDA regions. An operator must define all 
ICDA Regions within each covered pipeline segment. An ICDA region 
extends from the location where water may first enter the pipeline and 
encompasses the entire area along the pipeline where internal corrosion 
may occur and further evaluation is needed. To identify ICDA regions, 
an operator must apply the results of a mathematical flow model that 
defines the critical pipe incline above which water film cannot be 
transported by the gas. This flow model must consider changes in pipe 
diameter, locations where gas enters a line (potential to introduce 
moisture) and locations downstream of gas draw-offs (gas velocity is 
reduced). Graph E.III.A in Appendix E of this Part provides the flow 
model.
    (C) Identification of excavation locations. After identifying the 
ICDA regions, an operator must then identify for excavation the most 
likely locations for internal corrosion in each region. An operator 
must identify a minimum of two locations for excavation in each ICDA 
Region. One location must be the low point (e.g., sags, drips, valves, 
manifolds, dead-legs, traps) nearest to the beginning of the ICDA 
Region. The second location must be at the upstream end of the pipe 
incline nearest the end of the ICDA Region.
    (D) Direct examination. An operator must, at a minimum, excavate in 
each ICDA Region the two locations identified for excavation in 
paragraph (h)(4)(ii)(C), and must perform a direct examination for 
internal corrosion at each location, using ultrasonic thickness 
measurements. If corrosion exists at either location, the operator 
must--
    (1) Remediate the conditions it finds in accordance with paragraph 
(i) of this section;
    (2) As part of the operator's current integrity assessment either 
perform additional excavations in the ICDA region or use an alternative 
assessment method allowed by this section to assess the pipe for 
internal corrosion; and
    (3) Evaluate all pipeline segments (both covered and non-covered) 
in the operator's pipeline system with similar characteristics to those 
in which the corrosion was found, and remediate the conditions it finds 
in accordance with paragraph (i) of this section.
    (E) Post Assessment and Continuing Evaluation. An operator must 
continually monitor each covered segment where internal corrosion has 
been identified using techniques such as coupons or electronic probes. 
An operator must also periodically draw off fluids at low points and 
chemically analyze the fluids for the presence of corrosion products. 
The frequency of the monitoring and fluid analysis must be based on 
results from past and present integrity assessment results and risk 
factors specific to that pipeline. If an operator finds any evidence of 
corrosion products the operator must, either--
    (1) conduct excavations at locations downstream where moisture 
might accumulate; or
    (2) assess the segment using another integrity assessment method 
allowed by this section, and remediate the conditions it finds in 
accordance with paragraph (i) of this section. The interval for re-
assessing the segment with another assessment method must not exceed 
the time frames specified in paragraph (k)(3)(ii) of this section.
    (5) Stress Corrosion Cracking (SCC). An operator using direct 
assessment as an integrity assessment method to address stress 
corrosion cracking must develop and follow a plan that provides for--
    (i) Development and implementation of a systematic SCC data 
collection and evaluation process for all segments to identify if the 
conditions for SCC are present and to prioritize the segments for 
assessment. An operator may refer to ASME/ANSI B31.8S, Appendix SP-A3 
for identifying the threat of SCC. This process must include gathering 
and evaluating data related to SCC at all excavation sites where the 
criteria indicate the potential for SCC. This data includes at minimum, 
the data specified

[[Page 4322]]

in ASME/ANSI B31.8S, Appendix SP-A3.
    (ii) Selection and implementation of an integrity assessment method 
and remediation of the threat, if conditions for SCC are identified. An 
operator must use the bell hole examination and evaluation technique to 
assess SCC, as specified in ASME/ANSI B31.8S, Appendix SP-A3.
    (6) Confirmatory direct assessment. An operator using the 
confirmatory direct assessment method as allowed in paragraph (k)(3) of 
this section must have a plan that meets the following requirements:
    (i) Threats. For any covered segment on which confirmatory direct 
assessment is used, the focus must be on identifying damage resulting 
from external corrosion, internal corrosion and third party damage.
    (ii) External corrosion plan. An operator's plan for confirmatory 
direct assessment for identifying external corrosion must includes 
processes for pre-assessment, indirect examination, direct examination 
and remediation.
    (A) The pre-assessment must follow the requirements in paragraph 
(h)(3)(ii) of this section, and include identification of External 
Corrosion Direct Assessment (ECDA) regions.
    (B) The indirect examination must follow the requirements in 
paragraph (h)(3)(iii) of this section, except that the examination may 
be conducted using only one indirect examination tool suitable for the 
application.
    (C) The direct examination must follow the requirements in 
paragraph (h)(3)(v) of this section with the following exceptions--
    (1) Excavation of all immediate action indications is required in 
each ECDA region;
    (2) Excavation of at least one high risk indication that meets the 
criteria of scheduled action is required in each ECDA region; and
    (3) No excavation is required for indications categorized as 
monitored indications.
    (D) The remediation must follow the requirements in paragraph 
(h)(3)(vi) of this section.
    (iii) Internal Corrosion plan. An operator's plan for confirmatory 
direct assessment for identifying internal corrosion must include 
processes for pre-assessment, identification of Internal Corrosion 
Direct Assessment (ICDA) Regions, identification of excavation 
locations, direct examination and remediation.
    (A) The pre-assessment must follow the requirements in paragraph 
(h)(4)(ii)(A) of this section.
    (B) The identification of ICDA Regions must follow the requirements 
in paragraph (h)(4)(ii)(B) of this section.
    (C) The identification of excavation locations and excavation must 
follow the requirements in paragraph (h)(4)(ii)(C) of this section, 
except that the operator must identify for excavation at least one high 
risk location in each ICDA Region.
    (D) The direct examination (excavation) and remediation must follow 
the requirements in paragraph (h)(4)(ii)(D) of this section, except 
that the operator is to choose one high risk location in each ICDA 
Region for excavation.
    (iv) Third party damage. An operator's plan for confirmatory direct 
assessment for identifying third party damage must include 
identification of pipeline segments where construction or other 
groundbreaking activity was reported near the pipeline right-of-way 
since the previous assessment. The confirmatory direct assessment for 
third part damage must follow the requirements in paragraph (g)(3)(i) 
of this section.
    (i) What actions must be taken to address integrity issues?
    (1) General requirements. An operator must take prompt action to 
address all anomalous conditions that the operator discovers through 
the integrity assessment. In addressing all conditions, an operator 
must evaluate all anomalous conditions and remediate those that could 
reduce a pipeline's integrity. An operator must be able to demonstrate 
that the remediation of the condition will ensure that the condition is 
unlikely to pose a threat to the long-term integrity of the pipeline. 
If an operator is unable to respond within the time limits for certain 
conditions specified below, the operator must temporarily reduce the 
operating pressure of the pipeline. An operator must determine the 
temporary reduction in operating pressure using section 851.42 of ASME/
ANSI B31.8 for dents and gouges, ASME/ANSI B31G or RSTRENG for 
corrosion, or reducing the operating pressure to a level not exceeding 
80% of the level at the time the condition was discovered. (See 
Appendix A to this part 192 for incorporation by reference and 
availability information). A reduction in operating pressure cannot 
exceed 365 days without an operator taking further remedial action to 
ensure the safety of the pipeline.
    (2) Discovery of condition. Discovery of a condition occurs when an 
operator has adequate information about the condition to determine that 
the condition presents a potential threat to the integrity of the 
pipeline. An operator must promptly, but no later than 180 days after 
conducting an integrity assessment, obtain sufficient information about 
a condition to make that determination, unless the operator 
demonstrates that the 180-day period is impracticable. If the operator 
cannot make the necessary determination within the 180-day period, an 
operator must notify OPS of the reasons for the delay and the expected 
time for obtaining the information.
    (3) Schedule for evaluation and remediation. An operator must 
complete remediation of a condition according to a schedule that 
prioritizes the conditions for evaluation and remediation. Unless a 
special requirement for remediating certain conditions applies, as 
provided in paragraph (h)(3)(vii) or paragraph (i)(4) of this section, 
an operator must follow the schedule in ASME/ANSI B31.8S. If an 
operator cannot meet the schedule for any condition, the operator must 
justify the reasons why it cannot meet the schedule and that the 
changed schedule will not jeopardize public safety. An operator must 
notify OPS in accordance with paragraph (n) of this section if it 
cannot meet the schedule and cannot provide safety through a temporary 
reduction in operating pressure.
    (4) Special requirements for scheduling remediation.
    (i) Immediate repair conditions. An operator's evaluation and 
remediation schedule must follow ASME/ANSI B31.8S, Section 7 in 
providing for immediate repair conditions. To maintain safety, an 
operator must temporarily reduce operating pressure or shut down the 
pipeline until the operator completes the repair of these conditions. 
An operator must treat the following conditions as immediate repair 
conditions:
    (A) A calculation of the remaining strength of the pipe shows a 
predicted failure pressure less than 1.1 times the established maximum 
operating pressure at the location of the anomaly. Suitable remaining 
strength calculation methods include, ASME/ANSI B31G ``Manual for 
Determining the Remaining Strength of Corroded Pipelines'' (1991); AGA 
Pipeline Research Committee Project PR-3-805 (``A Modified Criterion 
for Evaluating the Remaining Strength of Corroded Pipe'' (December 
1989)); or an alternative equivalent method of remaining strength 
calculation. These documents are incorporated by reference and 
available at the addresses listed in Appendix A to Part 192.

[[Page 4323]]

    (B) A dent that has any indication of metal loss, cracking or a 
stress riser.
    (C) An anomaly that in the judgment of the person designated by the 
operator to evaluate the assessment results requires immediate action.
    (ii) 180-day remediation. Except for conditions listed in paragraph 
(i)(4)(i) of this section, an operator must remediate any of the 
following within 180 days of discovery of the condition:
    (A) A dent with a depth greater than 6% of the pipeline diameter 
(greater than 0.50 inches in depth for a pipeline diameter less than 
Nominal Pipe Size (NPS) 12).
    (B) A dent with a depth greater than 2% of the pipeline's diameter 
(0.250 inches in depth for a pipeline diameter less than NPS 12) that 
affects pipe curvature at a girth weld or a longitudinal seam weld.
    (iii) Remediation longer than 180 days. An operator may take more 
than 180 days following discovery of the condition to remediate any of 
the following conditions unless the anomaly grows to critical stage. If 
the anomaly grows to critical stage, the operator must follow the 
immediate repair requirements in paragraph (i)(4)(i) of this section.
    (A) In a segment assessed by internal inspection, a calculation of 
the remaining strength of the pipe shows a predicted failure pressure 
greater than 1.1 times the established maximum operating pressure at 
the location of the anomaly. An operator must remediate the condition 
in accordance with ASME/ANSI B31.8S, Section 7, Figure 7-1.
    (B) In a segment assessed by any integrity assessment method, an 
anomalous condition other than those listed in paragraphs (i)(4)(i) or 
(ii) of this section.
    (j) What additional preventive and mitigative measures must an 
operator take to protect the high consequence area?
    (1) General Requirements. An operator must take measures to prevent 
a pipeline failure and to mitigate the consequences of a pipeline 
failure in a high consequence area. An operator's measures will be 
based on the threats it has identified to each pipeline segment (see 
paragraph (f)). These measures include an operator conducting, in 
accordance with one of the risk assessment approaches in ASME/ANSI 
B31.8S, Section 5, a risk analysis of the covered pipeline segments to 
identify additional actions to enhance public safety. Such actions 
include, but are not limited to, installing Automatic Shut-off valves 
or Remote Control Valves, installing computerized monitoring and leak 
detection systems, replacing pipe segments with pipe of heavier wall 
thickness, providing additional training to personnel on response 
procedures, conducting drills with local emergency responders and 
implementing additional extensive inspection and maintenance programs.
    (2) Third Party Damage and Outside Force Damage. An operator must 
take additional measures to prevent and minimize the consequence of a 
release from third party damage or outside force damage. These measures 
must be in addition to any already required under this Part. An 
operator may follow ASME/ANSI B31.8S, Table 7-1 of Section 7 in 
identifying these measures. To minimize the consequences from third 
party damage, including vandalism, measures include, but are not 
limited to, increasing the frequency of aerial and foot patrols, 
participating in one-call systems, conducting extensive public 
education campaigns, increasing marker frequency, increasing cover 
depth, and adding leakage control measures. To minimize the 
consequences from outside force damage (e.g. earth movement, floods, 
unstable suspension bridge) these measures include, but are not limited 
to, increasing the frequency of aerial and foot patrols, adding 
external protection, reducing external stress, and relocating the line.
    (3) Automatic Shut-off valve (ASV) or Remote Control Valves (RCV). 
If an operator determines that an ASV or RCV is needed on a pipeline 
segment to protect a high consequence area in the event of a gas 
release, an operator must install the ASV or RCV. In making that 
determination, an operator must, at least, consider the following 
factors--swiftness of leak detection and pipe shutdown capabilities, 
the type of gas being transported, operating pressure, the rate of 
potential release, pipeline profile, the potential for ignition, and 
location of nearest response personnel.
    (k) What is a continual process of evaluation and assessment to 
maintain a pipeline's integrity?
    (1) General. After completing the baseline integrity assessment of 
a covered segment, an operator must continue to assess the line pipe of 
that segment at the intervals specified in paragraph (k)(3) and 
periodically evaluate the integrity of each covered pipeline segment as 
provided in paragraph (k)(2). The reassessment period for a segment 
begins upon completion of the prior assessment.
    (2) Evaluation. An operator must conduct a periodic evaluation as 
frequently as needed to assure pipeline integrity. The periodic 
evaluation must be based on a data integration of the entire pipeline 
as specified in paragraph (f) of this section to identify the threats 
specific to a pipeline segment. The evaluation must consider the past 
and present integrity assessment results, data integration information 
(paragraph (f) of this section), and decisions about remediation and 
preventive and mitigative actions (paragraphs (i) and (j) of this 
section).
    (3) Re-Assessment intervals. An operator must establish a re-
assessment interval for each covered pipeline segment. An operator must 
comply with the following requirements in establishing the interval for 
the operator's covered pipeline segments.
    (i) General. Unless a period of less than seven years is specified, 
each covered pipeline segment must be re-assessed at a seven-year 
interval. If the operator establishes a reassessment interval for the 
covered segment that is greater than seven years, the operator must 
within the seven-year period, conduct a confirmatory direct assessment 
on the covered segment, and then conduct the follow-up reassessment. 
The reassessment done by confirmatory direct assessment must be done in 
accordance with paragraph (h)(6) of this section.
    (ii) Pressure test or internal inspection, or other equivalent 
technology.
    (A) An operator that uses pressure testing or internal inspection 
as an assessment method must establish the reassessment interval for 
covered pipeline segments by--
    (1) Basing the intervals on the identified threats for the segment 
as listed in paragraph (f) of this section and in ASME/ANSI B31.8S, 
Table 8-2, section 8, and on the analysis of the results from the last 
integrity assessment and from the data integration required by 
paragraph (f) of this section; or
    (2) Using the intervals for different stress levels of pipeline 
specified in ASME/ANSI B31.8S, Table 8-1, section 8.
    (B) However, under either option, the maximum reassessment interval 
must not exceed ten (10) years for a pipeline operating at or above 50% 
SMYS, and 15 years for a pipeline operating below 50% SMYS. An operator 
choosing the maximum period allowed for reassessment must demonstrate 
that it has implemented enhanced preventive and mitigative measures for 
the segment.
    (iii) Direct assessment.
    (A) An operator that uses direct assessment must determine the 
reassessment interval according to the following calculation.

[[Page 4324]]

    (1) Determine the largest defect most likely to remain in the 
segment and the corrosion rate appropriate for the pipe, soil and 
protection conditions.
    (2) Take the largest remaining defect as the size of the largest 
defect discovered in the ECDA or ICDA segment.
    (3) Estimate the reassessment interval as half the time required 
for the largest defect to grow to a critical size.
    (B) However, the reassessment interval cannot exceed five (5) 
years, if an operator directly examines and remediates defects by 
sampling, or ten (10) years, if an operator conducts a direct 
examination of all anomalies and remediates these anomalies.
    (4) Waiver from interval greater than 7 years in limited 
situations. In the following limited instances, OPS may allow a waiver 
from a reassessment interval greater than seven years but within the 
maximum allowable interval if OPS finds a waiver would not be 
inconsistent with pipeline safety.
    (i) Lack of internal inspection tools. An operator may be able to 
justify a longer assessment period for a covered segment if internal 
inspection tools are not available to assess the line pipe. An operator 
must demonstrate that the internal inspection tools cannot be obtained 
within the required assessment period and must also demonstrate the 
actions it is taking to evaluate the integrity of the pipeline segment 
in the interim. An operator must, in accordance with paragraph (n) of 
this section, notify OPS 180 days before the end of the required 
reassessment interval that the operator may require a longer assessment 
interval, and provide an estimate of when the assessment can be 
completed.
    (ii) Maintain local product supply. An operator may be able to 
justify a longer assessment period for a covered segment if the 
operator demonstrates that the reassessment will shut off the local 
product supply, and that alternative supply is not available. An 
operator must, in accordance with paragraph (n) of this section, notify 
OPS 180 days before the end of the required reassessment interval that 
the operator may require a longer assessment interval, and provide an 
estimate of when the assessment can be completed.
    (5) Assessment methods. In conducting the integrity reassessment, 
an operator must assess the integrity of the line pipe by any of the 
following methods.
    (i) Internal inspection tool or tools capable of detecting 
corrosion, and any other threats to which the pipe segment is 
susceptible. An operator must follow ASME/ANSI B31.8S, section 6.2, in 
selecting the appropriate internal inspection tools;
    (ii) Pressure test conducted in accordance with subpart J of this 
Part;
    (iii) Direct assessment to address threats of external corrosion 
threats, internal corrosion, and stress corrosion cracking that is 
conducted in accordance with ASME/ANSI B31.8S section 6.3, and 
paragraph (h) of this section;
    (iv) Other technology that an operator demonstrates can provide an 
equivalent understanding of the condition of the line pipe. An operator 
choosing this option must notify the Office of Pipeline Safety (OPS) 
180 days before conducting the assessment, in accordance with paragraph 
(n) of this section.
    (v) Confirmatory direct assessment when used on a covered segment 
that is scheduled for reassessment at a period longer than seven years. 
An operator using this reassessment method must comply with paragraph 
(h)(6) of this section.
    (l) What methods must be used to measure program effectiveness? (1) 
General. An operator must include in its integrity management program 
methods to measure whether the program is effective in assessing and 
evaluating the integrity of each pipeline segment and in protecting the 
high consequence areas. These measures must include the four overall 
performance measures specified in ASME/ANSI B31.8S, Section 9.4, and 
the specific measures for each identified threat specified in ASME/ANSI 
B31.8S, Appendix SP-A. An operator must make the four overall 
performance measures accessible in real time to OPS and state pipeline 
safety enforcement officials.
    (2) Direct assessment. In addition to the general requirements for 
performance measures, an operator using direct assessment to assess the 
external corrosion threat must define and monitor measures to determine 
the effectiveness of the ECDA process. These measures must meet the 
requirements of paragraph (h)(3)(vii) of this section.
    (m) What records must be kept? An operator must maintain for review 
during an inspection--
    (1) A written baseline assessment plan in accordance with 
paragraphs (e) and (g) of this section;
    (2) A written integrity management program in accordance with the 
requirements of this section.
    (3) Documents to support the decisions, analyses and processes 
developed and used to implement and evaluate each element of the 
baseline assessment plan and integrity management program. Documents 
include those developed and used in support of any identification, 
calculation, amendment, modification, justification, deviation and 
determination made, and any action taken to implement and evaluate any 
of the program elements.
    (4) Documents that demonstrate personnel have the required 
training, including a description of the training program, in 
accordance with paragraph (d)(2) of this section.
    (5) Documents to carry out the requirements in paragraph (h) of 
this section for a direct assessment plan.
    (6) Documents demonstrating the integrity management program has 
been provided to the interstate agent, and that any safety concerns 
raised by OPS on behalf of an interstate agent have been addressed.
    (n) How does an operator notify OPS? An operator must provide 
notification required by this section by--
    (1) Sending the notification to the Information Resources Manager, 
Office of Pipeline Safety, Research and Special Programs 
Administration, U.S. Department of Transportation, Room 7128, 400 
Seventh Street SW., Washington DC 20590;
    (2) Sending the notification by facsimile to (202) 366-7128; or
    (3) Entering the information directly on the Integrity Management 
Database (IMDB) Web site at http://primis.rspa.dot.gov/imdb/.
    3. Appendix A to Part 192, section II.D would be amended by adding 
paragraph (9) to read as follows:

Appendix A to Part 192--Incorporated by Reference

* * * * *
    II. * * *
    D. * * *
    (9) ASME/ANSI B31.8S 2001 Supplement to B31.8 on Managing System 
Integrity of Gas Pipelines, January 31, 2002.
    4. A new Appendix E to Part 192 would be added to part 192 to read 
as follows:

Appendix E to Part 192

I. Guidance on Determining a Potential Impact Zone Within a High 
Consequence Area

    Within each high consequence area, an operator is to calculate the 
potential impact zone. (Refer to figure E.I.1 for the diagram of a 
potential impact zone) High consequence areas and potential impact zone 
are defined in Sec.  192.761. The potential impact zone will help an 
operator determine the area where segments must be given priority for 
assessment.

[[Page 4325]]

    The Potential Impact Zone definition (Sec.  192.761) expands the 
area protected and provides the basis for prioritizing the pipeline 
segments for assessment and remediation. The priority an operator is to 
give each covered segment depends on the population density within the 
potential impact radius. An operator will need to perform the 
following--
    (1) Identify all high consequence areas;
    (2) Calculate the Potential Impact Radius (PIR) for each pipeline 
segment;
    (3) Determine the Threshold Radius associated with the PIR for each 
segment;
    (4) Identify the Potential Impact Circle for each segment;
    (5) Identify the Potential Impact Zone for each segment;
    (6) Determine the priority of each segment giving higher priority 
to any segment within a potential impact zone.

II. Guidance on ECDA Tool Selection and Definition of External 
Corrosion Direct Assessment (ECDA) Regions

    This section gives guidance to help an operator implement the 
requirements for a direct assessment plan in Sec.  192.763 (h). An 
operator that chooses to use direct assessment to assess the threat of 
external corrosion on the operator's covered pipeline segments may 
refer to this guidance for selecting inspection tools to carry out the 
indirect inspection requirements and for defining external corrosion 
regions.

A. Selection of Indirect Inspection Tools

    The rule (Sec.  192.763(h)(3)(iii)), requires an operator to select 
a minimum of two indirect inspection tools for all ECDA locations along 
the pipeline segment.
    [sbull] The pipeline operator must select indirect inspection tools 
based on their ability to reliably detect corrosion activity under the 
specific pipeline conditions to be encountered.
    [sbull] The ``indirect inspection tool selection'' column in Table 
E.II.1 includes items that should be considered when selecting indirect 
inspection tools.
    [sbull] Table E.II.2 provides guidance on selecting indirect 
inspection tools and specifically addresses conditions under which some 
indirect inspection tools may not be practical or reliable.
    [sbull] The pipeline operator does not have to use the same 
indirect inspection tools at all locations along the pipeline segment. 
Figure E.II.1 demonstrates how the selection of indirect inspection 
tools may vary along a segment.

B. Identification of ECDA Regions

    The rule (Sec.  192.763(h)(3)(ii)) requires an operator to analyze 
data it has collected to identify ECDA regions.
    [sbull] The definition of ECDA regions will evolve through the 
Indirect Inspection Step and the Direct Examination Step. An operator 
is expected to establish a preliminary definition and fine tune it 
later in the ECDA process.
    [sbull] The pipeline operator should define criteria for 
identifying ECDA regions.
    [sbull] An ECDA region should include locations that have similar 
physical characteristics, corrosion histories, expected future 
corrosion conditions, and use the same indirect inspection tools.
    [sbull] The pipeline operator should consider physical 
characteristics, soil conditions, and corrosion protection mechanisms 
that the pipeline operator considers significant in affecting external 
corrosion when defining criteria for identifying ECDA regions. Table 
E.1 may be used as guidance in establishing ECDA regions.
    [sbull] A single ECDA region does not need to be contiguous. That 
is, an ECDA region may be broken along the pipeline, for example, if 
similar conditions are encountered on either side of a river crossing.
    [sbull] An operator should include the entire pipeline segment in 
an ECDA region.
    [sbull] Figure E.II.2 gives an example definition of ECDA regions 
for a given pipeline.
    [sbull] A pipeline operator should define five distinct areas based 
on soil characteristics and previous history.
    [sbull] Based on the choice of indirect inspection tools, the soil 
characteristics, and the previous history, the pipeline operator should 
define seven ECDA regions.
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Notes

    1 = Applicable: Small coating holidays (isolated & typically < 
1sq. in.) and conditions that do not cause fluctuations in CP 
potentials under normal operating conditions.
    2 = Applicable: Large coating holidays (isolated or continuous) 
or conditions that cause fluctuations in CP potentials under normal 
operating conditions.
    NA: Not Applicable to this tool without additional 
considerations.
    Shielding by Disbonded Coating: None of these survey tools is 
capable in the detection of this type coating condition that 
exhibits no physical orifice to the soil. If there is a pathway to 
the soil through a small holiday or orifice, then tools such as DCVG 
or electromagnetic methods may detect these defect areas. This 
definition pertains to only one type of shielding from disbonded 
coatings. We also find current shielding from other metallic 
structures and from geological conditions.
    Pipe Depths: All of the survey tools are sensitive in the 
detection of coating holidays where pipe burials exceed normal 
depths. Field conditions and terrain may affect depth ranges and 
detection sensitivity.
    Limitations & Detection Capabilities: All survey methods are 
limited in sensitivity to the type and make up of the soil, presence 
of rock and rock ledges, type coating such as high dielectric tapes, 
construction practices, interference currents, other structures, 
etc. At least two or more survey methods may be required in order to 
get desired results and confidence levels required.


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    Issued in Washington, DC on January 22, 2003.
Stacey L. Gerard,
Associate Administrator for Pipeline Safety.
[FR Doc. 03-603 Filed 1-27-03; 8:45 am]
BILLING CODE 4910-60-C