[Federal Register Volume 69, Number 66 (Tuesday, April 6, 2004)]
[Rules and Regulations]
[Pages 18228-18242]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 04-6398]



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Part III





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); Correction; Final Rule

  Federal Register / Vol. 69, No. 66 / Tuesday, April 6, 2004 / Rules 
and Regulations  

[[Page 18228]]


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DEPARTMENT OF TRANSPORTATION

Research and Special Programs Administration

49 CFR Part 192

[Docket No. RSPA-00-7666; Amendment 192-95]
RIN 2137-AD54


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

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

ACTION: Final rule; correction & petition for reconsideration.

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SUMMARY: This document corrects a final rule published in the Federal 
Register on December 15, 2003 (68 FR 69778). That rule requires 
operators to develop integrity management programs for gas transmission 
pipelines located where a leak or rupture could do the most harm, i.e., 
could impact high consequence areas (HCAs). The rule requires gas 
transmission pipeline operators to perform ongoing assessments of 
pipeline integrity, to improve data collection, integration, and 
analysis, to remediate the pipeline as necessary, and to implement 
additional preventive and mitigative actions. This document makes minor 
editorial corrections and clarifies the intent of several provisions in 
the rule. This document also addresses a petition for reconsideration 
filed by the Interstate Natural Gas Association of America (INGAA).

EFFECTIVE DATE: The effective date is April 6, 2004.

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 the final 
rule.

SUPPLEMENTARY INFORMATION:

Background

    On December 15, 2003, RSPA/OPS published a final rule (68 FR 69778) 
that requires operators of gas transmission pipelines to develop and 
implement a comprehensive integrity management program for pipeline 
segments where a failure would have the greatest impact to the public 
or property.

Errors and Language in the Rule Needing Correction or Clarification

    OPS has identified errors in the published final rule (68 FR 69778; 
December 15, 2003), such as incorrect reference numbers, editorial 
errors, incorrect terms and misspellings. OPS has also identified 
language in several provisions of the rule that is confusing and needs 
clarification. Thus, this document either corrects the rule because of 
mistakes found since the rule was published or clarifies the language 
and intent of the rule. None of these substantively changes any 
requirement in the rule.

Petition for Reconsideration

    On January 15, 2004, the Interstate Natural Gas Association of 
America (INGAA) filed a petition for reconsideration of the final rule 
on gas integrity management identifying corrections INGAA believed were 
needed in the rule. This document addresses that petition. This 
document addresses mistakes the petitioner has identified in the rule 
and clarifies ambiguous language the petitioner identified. However, 
this document does not address what INGAA identified as mistakes but 
that would substantively change the rule. (See section below titled 
``Recommended changes not made'').

Corrections and Clarifications

    Section 192.901 states that the integrity management program 
regulations apply to gas transmission pipelines. In the Preamble to the 
final rule, we stated our intent that the integrity management program 
requirements apply to gas transmission pipelines and not to gas 
gathering or distribution lines. However, Sec.  192.9 provides that 
except for the requirements in Sec. Sec.  192.1 and 192.150, operators 
of gathering lines must follow the requirements for transmission 
pipelines. We have clarified in Sec.  192.9 that gathering lines are 
not subject to the requirements of subpart O. This clarification is to 
ensure that there is no misunderstanding about which gas pipelines the 
integrity management program requirements are intended to apply.
    The final rule includes a definition for identified sites in Sec.  
192.903. One component of this definition is any building that is 
occupied by 20 or more persons for specified periods and that meets 
other specified criteria. The rule language is correct. However, in the 
preamble of the final rule, we incorrectly described the component as 
``buildings housing 50 or more people.'' The preamble discussion should 
have said ``buildings housing 20 or more people'' to match the rule 
requirement.
    Section 192.903 included allowed an operator to choose one of two 
methods for identifying a high consequence area. Method 1 involves 
designating all class 3 and 4 areas as high consequence areas, and was 
intended to relieve operators from the need to calculate and evaluate 
potential impact circles in these areas. We intended, however, that an 
operator would have to calculate and evaluate potential impact circles 
on any transmission pipeline not in a class 3 or class 4 area. We used 
the phrase ``outside a Class 3 or Class 4 location'' to describe these 
high consequence areas. However, this phrase could be interpreted to 
include areas more than 660 feet from a pipeline where the pipeline is 
in a class 3 or 4 area. We did not intend for an operator to evaluate 
any areas further than 660 feet from the pipeline in these areas, since 
the pipeline is already in a high consequence area under the criteria 
of method 1. We replaced this phrase with ``in a Class 1 or Class 2 
location'' to make it clear that we are referring to an evaluation of 
pipeline segments not already classified as high consequence areas.
    In addition, another criterion under method 1 refers to potential 
impact circles containing an identified site, which again could be 
interpreted as requiring operators to calculate potential impact 
circles within existing class 3 and 4 areas. We have revised this 
criterion (paragraph (1)(iv)) to clarify that the evaluation need only 
be performed in class 1 and 2 areas, where the existence of an 
identified site might require that the area be considered a high 
consequence area.
    Several provisions in the rule require notification to OPS and in 
some instances to a State pipeline safety authority when a State acts 
as an interstate agent on a covered segment of transmission pipeline or 
the State regulates a covered segment on an intrastate transmission 
pipeline. The language requiring the state notification was confusing. 
We have clarified the language.
    The Preamble discussed the necessity of keeping state regulators 
informed versus the need to keep an operator's information about its 
system secure. Where security of information was a concern, we limited 
the information submission to OPS or to an interstate agent, as the 
statute required. Where security was not an issue, the rule included 
state notification on an intrastate transmission line regulated by the 
State. However, in two provisions on notification when an operator uses 
other technology to assess a covered segment for the baseline or 
reassessment (Sec. Sec.  192.921(a)(4) and 192.937(c)(4)), we 
inadvertently left out the notification to a State when it is either an 
interstate

[[Page 18229]]

agent or regulates an intrastate transmission covered segment. We have 
corrected these omissions.
    Section 192.913 of the final rule establishes conditions under 
which an operator may deviate from specific provisions of the rule, by 
establishing a performance-based program. One of the required criteria 
is that an operator have completed at least two integrity assessments 
on all covered pipeline segments (Sec.  192.913(b)(2)(i)). This was a 
mistake. The rule should have limited the prior integrity assessment to 
those segments the operator wants to include under the performance-
based option. We have revised the criterion to require that at least 
two assessments must have been completed on all segments to be included 
in the operator's performance-based program. This change clarifies that 
an operator may establish a performance-based program covering only a 
portion of its pipeline segments subject to the final rule. The 
remaining covered segments would still be subject to the more 
prescriptive approach.
    In Sec.  192.917, paragraph (a) lists the types of threats an 
operator is to consider in its threat identification. We have revised 
the paragraph to clarify that the threats listed in the rule restate 
the threats listed in the ASME/ANSI B31.8S standard, and are not in 
addition to those in the standard.
    In Sec.  192.917, paragraph (b) requires an operator to gather and 
integrate data from its entire pipeline system that could be relevant 
to identifying potential threats to the covered pipeline segment. 
Although it seems self-evident that an operator must only gather and 
integrate existing data about its pipeline system, industry has 
expressed concern that an operator will be required to create data. We 
have revised the paragraph to clarify that the data has to exist before 
it is gathered and integrated for analysis.
    In Sec.  192.917, paragraph (e) requires an operator to analyze its 
pipeline to identify specific potential threats to the pipeline. This 
document revises two paragraphs in this section (paragraphs (e)(1) and 
(e)(3)) to provide additional clarity on information that must be 
included in these analyses. Paragraph (e)(1) now specifies that an 
operator is to use information from a direct assessment to help define 
where third party damage may exist. Similarly, paragraph (e)(3) now 
specifies that an operator is to use information from prior integrity 
assessments to determine the risk of failure in the covered segment 
from manufacturing and construction defects.
    In Sec.  192.917, paragraph (e)(3) also establishes requirements 
specific to pipe for which an operator has identified the threat of 
manufacturing and construction defects. This paragraph states that an 
operator may consider such defects to be stable defects if the 
operating conditions on the covered segment have not changed 
significantly ``since December 17, 1998.'' We intended this provision 
to provide for a retrospective evaluation of five years, beginning from 
the date on which integrity management requirements were first 
established by the Pipeline Safety Improvement Act of 2002. These 
requirements would also apply, however, for pipeline in areas which may 
be identified as high consequence areas many years in the future. For 
such pipe, a retrospective evaluation reaching back to 1998 would not 
make sense. This paragraph has been revised to require that the 
retrospective evaluation cover 5 years, regardless of when the high 
consequence area is identified.
    In Sec.  192.917, paragraph (e)(4) establishes requirements 
specific to low-frequency electric resistance welded (ERW) pipe and lap 
welded pipe that satisfies conditions in an industry standard, ASME/
ANSI B31.8S. The rule incorporates by reference the industry standard. 
The preamble to the final rule stated that these requirements would 
apply to pipe that has a history of seam failures. However, this 
criterion was inadvertently omitted from the rule. We have added the 
criterion with additional clarification. We have clarified that when a 
covered pipe segment has low frequency ERW pipe, lap welded or other 
pipe that satisfies the conditions in ASME B31.8S, Appendices A.4.3 and 
A4.4, and any such pipe in the system has a history of seam failure, or 
operating pressure on the covered segment has increased over the 
maximum operating pressure experienced during the preceding five years, 
the operator must prioritize the covered segment as a high risk segment 
for assessment purposes and must use a specified type of assessment 
technology. We have also clarified the capabilities that are required 
of the assessment technology.
    In Sec.  192.921, paragraph (a)(2) requires that a pressure test 
used for the baseline assessment of a covered pipeline segment must be 
conducted in accordance with subpart J of part 192. The test pressures 
required by subpart J, while adequate to demonstrate the segment's 
integrity, are lower than required to justify some of the reassessment 
intervals under Sec.  192.939. To avoid confusion, we have added a 
sentence providing that higher test pressures that are in accordance 
with Table 3 of Section 5 of ASME/ANSI B31.8S may be needed to justify 
an extended reassessment interval under Sec.  192.939.
    In Sec.  192.921, paragraph (g) requires that an assessment be 
completed for newly-installed pipe within ten years from when the pipe 
is installed. This paragraph allows a pressure test, meeting the 
requirements of 49 CFR part 192, subpart J, which would normally be 
conducted as part of installation, to be used to meet this requirement. 
The reference to this pressure test in the final rule referred to it as 
a post-installation test. That term was incorrect because subpart J 
allows reliance on tests conducted prior to installation. There is no 
technical reason to deviate from the established subpart J 
requirements, and the final rule has been changed to delete the term 
post-installation.
    Section 192.925 sets forth the requirements for external corrosion 
direct assessment. The threat identification section (Sec.  192.917) 
requires operators to take actions to address particular threats. One 
of these threats is third-party damage. The data from a direct 
assessment can be relevant to identifying this damage, such as 
identifying coating damage that may indicate damage from a third party 
excavation. In Sec.  192.925 we are adding a sentence to clarify that 
operators are to integrate data from the external corrosion direct 
assessment with data from internal inspection tools and other 
information relevant to the pipeline to help identify and address 
third-party damage.
    In Sec.  192.927, paragraph (b) includes requirements for the 
internal corrosion direct assessment (ICDA) process for the dry gas 
system. If an operator uses ICDA to assess a segment operating with 
electrolyte present in the gas stream, the operator must develop a plan 
that demonstrates how it will conduct ICDA in the segment to 
effectively address internal corrosion. This ICDA application would be 
other technology that requires notification to OPS and to the State 
pipeline safety authority, when applicable. We have clarified that an 
operator using ICDA for a wet gas system must provide this required 
notification.
    In Sec.  192.927, paragraph (c)(3) includes criteria to identify 
locations where direct examination of the pipe must be conducted when 
an operator is using ICDA. These criteria specified a minimum of two 
direct examinations, one of which must be at the low spot within the 
covered segment nearest to the beginning of the ICDA region and the 
second ``at the upstream end of the pipe containing a covered segment,

[[Page 18230]]

having a slope not exceeding the critical angle of inclination nearest 
the end of the ICDA region.'' The wording of the second required 
location has caused confusion. We have clarified the language to 
specify that the second location be `` farther downstream within a 
covered segment near the end of the ICDA Region.'' There is no 
technical difference in this change; the revised wording more clearly 
describes the requirement.
    In Sec.  192.927, paragraph (c)(4)(i) requires that operators using 
internal corrosion direct assessment (ICDA) evaluate its effectiveness 
as an assessment method and in determining whether more frequent 
reassessments are required. In the final rule, this paragraph required 
that this evaluation be done ``in the same year in which ICDA is 
used.'' This could be unnecessarily burdensome, or even impractical, 
for situations in which ICDA is used late in a calendar year, as it 
would essentially require that the evaluations be performed 
immediately. This was not intended. This requirement has been revised 
to specify that the evaluation be carried out within a year of 
conducting the ICDA.
    In Sec.  192.933, paragraph (b) specifies that discovery of a 
condition is considered to occur when an operator has adequate 
information to determine that the condition ``presents a potential 
threat to the integrity of the pipeline.'' As we explained in the 
Preamble to the final rule (68 FR 69797-98), adequate information to 
make this determination includes information that the condition is one 
included in ASME/ANSI B31.8S as needing a response. To further clarify 
the types of conditions that might be potential threats to a system's 
integrity we have added a sentence that explains that a potential 
threat includes the immediate repair, one-year and monitored conditions 
listed in the rule. The rule does not list all conditions that might 
present a potential threat but gives examples of those that are most 
common. Although a monitored condition does not present an immediate 
threat or need remediation within a year, it is a condition that 
presents a potential threat because a change could occur making the 
threat to the pipeline's integrity more immediate.
    To protect against third-party damage, paragraph (b)(1)(iv) of 
Sec.  192.935 requires an operator to monitor excavations near its 
pipelines or investigate when the operator finds evidence of any 
excavation it did not monitor. Although not intended, this paragraph 
could be read as requiring an operator to investigate (i.e., excavate 
or conduct above ground measurements) whenever the operator finds 
evidence of encroachment involving excavation, even if the operator had 
monitored the excavation. This paragraph has been revised to reflect 
our intent that the investigation be limited to instances when the 
operator did not monitor the excavation.
    In Sec.  192.935, paragraph (d) specifies requirements for 
additional preventive and mitigative measures for a pipeline operating 
below 30% SMYS located in a Class 3 or Class 4 area but not in a high 
consequence area. Although the guidance table in appendix E had 
included measures to address external and internal corrosion threats, 
and additional preventive and mitigative measures for a pipeline 
operating below 30% SMYS located in a high consequence area, we did not 
include these measures in the rule language itself. We have added these 
measures to the rule.
    In Sec.  192.937, paragraph (c)(2) specifies that a pressure test 
used to reassess a covered pipeline segment must be conducted in 
accordance with Subpart J of Part 192. This reference to subpart J is 
revised to include Table 3 of Section 5 of ASME/ANSI B31.8S, for the 
reasons given in Sec.  192.921(a)(2) above.
    In Sec.  192.939, paragraph (a) specifies reassessment intervals 
for a pipeline operating at or above 30% SMYS and paragraph (b) 
specifies reassessment intervals for a pipeline operating below 30% 
SMYS. Both paragraphs state that the minimum reassessment interval is 
seven years. This has been corrected now to state that the maximum 
reassessment interval is seven years.
    In Sec.  192.945, paragraph (a) requires an operator to include in 
its integrity management program methods to measure, on a semi-annual 
basis, whether the program is effective in assessing and evaluating the 
integrity of each covered pipeline segment and in protecting the high 
consequence areas. These measures include the four overall performance 
measures and the specific measures for each identified threat specified 
in ASME/ANSI B31.8S, appendix A. RSPA/OPS had intended that an operator 
submit only the four overall performance measures, by electronic or 
other means, on a semi-annual frequency. The additional measures are to 
be reviewed during inspections. However, the final rule mistakenly 
requires all measures to be submitted semi-annually. We have corrected 
paragraph (a) to specify that an operator submit the four overall 
performance measures semi-annually. In addition, we have included the 
dates by which an operator is to submit these semi-annual performance 
measures. Similarly, our intent was that performance measures related 
to external corrosion direct assessment were to be reviewed during 
inspection, not submitted to OPS. Accordingly, we have removed the 
requirement in paragraph (b) that these measures be submitted semi-
annually.
    Some of the examples in section I of appendix E that illustrate the 
methods for identifying high consequence areas are inconsistent with 
the definition in Sec.  192.903. We have deleted the examples to avoid 
any confusion about the definition. The illustrative figure in this 
appendix, Figure E.I.A, is accurate, and has been retained.
    Section II of appendix E provides additional guidance for operators 
on assessment methods and additional preventive and mitigative 
measures. Some, but not all, of the guidance in this appendix is 
applicable to pipelines operating below 30% SMYS. However, the title of 
the appendix incorrectly states that the guidance is only for 
assessment methods and applies only to pipelines operating below 30% 
SMYS. This is being corrected. The paragraphs in this appendix that 
refer to Tables E.II.1 and E.II.2 are also corrected to more accurately 
describe the information in those tables.
    Table E.II.1, in appendix E, describes additional preventive and 
mitigative measures that must be taken for pipelines in class 3 or 
class 4 areas but not in high consequence areas. The title of the table 
and the heading for column 4 inaccurately refer to assessment methods, 
which are not described in this table. We have corrected the title and 
column heading.

Recommended Changes Not Made

    In the petition for reconsideration of the final rule, several of 
the changes INGAA recommended are substantive changes to the final 
rule. The recommended changes were neither errors we had made in 
drafting the rule nor language we believe needs clarification. We have 
not made these changes because they do not reflect our intent and would 
substantively change the intent of the rule. Specifically, we have not 
included the following changes in this document.

     In Sec.  192.913(b)(2)(ii), we have not changed 
the word ``anomalies'' to ``defects''. We use the word ``anomalies'' 
throughout the rule.
     In Sec.  192.917(a), we have not deleted the 
description of the four types of general threats an operator must 
identify. INGAA noted that this listing is redundant to the 
descriptions in ASME/ANSI B31.8S. We consider the nature of these 
threats as key to

[[Page 18231]]

understanding the rule; therefore, the listing should be included in 
the rule. As we described above, we have clarified the language in this 
section to correct any impression that the described threats are in 
addition to those in the standard.
     In Sec.  192.917(b), we have not, as INGAA 
suggested, substituted ``similar segments'' for the word ``entire'' in 
the requirement that an operator gather and integrate information on 
its entire pipeline system that could be relevant to the covered 
segment. A crucial element of integrity management is the integration 
of relevant information from the entire system, not just from certain 
segments of the system.
     In Sec.  192.921(e), we have not adopted the 
suggestion that a prior assessment done before December 17, 2002 
substantially meet the baseline requirements for the prior assessment 
to qualify as a baseline assessment. We believe that what constitutes 
substantial compliance is too subjective. There would be constant 
disagreement between operators and regulators about what substantial 
compliance means. We allowed more flexible requirements for a prior 
assessment under the performance-based option because that option sets 
additional and more stringent requirements. Those additional 
requirements are not present when a prior assessment is used under the 
non performance-based approach. Furthermore, to give operators 
flexibility in the use of prior assessments, in the final rule we 
deleted the proposed requirement that set a five-year period before 
December 17, 2002 and allowed any prior assessment before December 17, 
2002 so long as it meets certain requirements.
     In Sec.  192.927(c)(5)(iii), we have not deleted 
the word ``entire'' from the requirement that an operator's internal 
corrosion direct assessment plan provide for an analysis carried out on 
the entire pipeline in which covered segments are present.
     In Sec.  192.937(b), we have not deleted the 
word ``entire'' from the requirement that an operator conduct a 
periodic evaluation that is based on a data integration and risk 
assessment of the entire pipeline.
     Several provisions in the rule differentiate 
requirements based on whether a transmission pipeline is operating 
below 30% SMYS, operating at or above 30% SMYS up to 50% SMYS or 
operating at or above 59% SMYS. We have not changed the categories. 
However, we recognize that these categories are changed in the draft 
2004 version of the ASME B31.8S standard. Once that standard is 
finalized and if we adopt it into the rule, then we will change the 
stress classifications.
     We have not moved the notification procedures in 
Sec. Sec.  192.941 and 192.951 to Part 191. These procedures are 
specific to notification for integrity management program purposes.

List of Subjects in 49 CFR Part 192

    High consequence areas, Incorporation by reference, Integrity 
management, Pipeline safety, Potential impact areas, Reporting and 
recordkeeping requirements.

PART 192--[AMENDED]

0
Accordingly, 49 CFR part 192 is corrected by making the following 
correcting amendments:
0
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.

0
2. Section 192.9 is revised to read as follows:


Sec.  192.9  Gathering lines.

    Except as provided in Sec. Sec.  192.1 and192.150, and in subpart 
O, each operator of a gathering line must comply with the requirements 
of this part applicable to transmission lines.
* * * * *

0
3. Section 192.903 is amended as follows:
0
a. In the definition of ``Assessment'', the word ``nondestructive'' is 
removed;
0
b. In the definition of ``Confirmatory direct assessment'', the word 
``integrity'' is added in the first sentence before the words 
``assessment method'';
0
c. The definition of ``High consequence area'' is revised; and
0
d. The definition of ``Identified site'' is amended by removing '')'' 
at the end of paragraphs (a) and (b).
    The additions and revisions read as follows:


Sec.  192.903  What definitions apply to this subpart?

* * * * *
    High consequence area means an area established by one of the 
methods described in paragraphs (1) or (2) as follows:
    (1) An area defined as--
    (i) A Class 3 location under Sec.  192.5; or
    (ii) A Class 4 location under Sec.  192.5; or
    (iii) Any area in a Class 1 or Class 2 location where the potential 
impact radius is greater than 660 feet (200 meters), and the area 
within a potential impact circle contains 20 or more buildings intended 
for human occupancy; or
    (iv) Any area in a Class 1 or Class 2 location where the potential 
impact radius contains an identified site.
    (2) The area within a potential impact circle containing--
    (i) 20 or more buildings intended for human occupancy, unless the 
exception in paragraph
    (4) applies; or
    (ii) An identified site.
* * * * *

0
4. Section 192.909 is amended by revising paragraph (b) to read as 
follows:


Sec.  192.909  How can an operator change its integrity management 
program?

* * * * *
    (b) Notification. An operator must notify OPS, in accordance with 
Sec.  192.949, of any change to the program that may substantially 
affect the program's implementation or may significantly modify the 
program or schedule for carrying out the program elements. An operator 
must also notify a State or local pipeline safety authority when either 
a covered segment is located in a State where OPS has an interstate 
agent agreement, or an intrastate covered segment is regulated by that 
State. An operator must provide the notification within 30 days after 
adopting this type of change into its program.
* * * * *


Sec.  192.911  [Amended]

0
5. In Sec.  192.911, paragraph (i) is amended by removing ``Sec.  
192.943'' and adding ``Sec.  192.945'' in its place.

0
6. In Sec.  192.913:
0
a. Paragraph (b)(1) (vii) is amended by removing ``Sec.  192.943'' and 
adding ``Sec.  192.945'' in its place; and
0
b. Paragraph (b)(2)(i) is revised to read as follows:


Sec.  192.913  When may an operator deviate its program from certain 
requirements of this subpart?

* * * * *
    (b) * * *
    (2) * * *
    (i) Have completed at least two integrity assessments on each 
covered pipeline segment the operator is including under the 
performance-based approach, and be able to demonstrate that each 
assessment effectively addressed the identified threats on the covered 
segment.
* * * * *

0
7. In Sec.  192.917:
0
a. Paragraph (a) introductory text is revised;
0
b. Paragraph (b) is revised;
0
c. Paragraphs (e)(1), (e)(3) and (e)(4) are revised; and

[[Page 18232]]

0
d. Paragraph (e)(5) is amended by removing ``Sec.  192.931'' and adding 
``Sec.  192.933'' in its place.
    The revisions read as follows:


Sec.  192.917  How does an operator identify potential threats to 
pipeline integrity and use the threat identification in its integrity 
program?

    (a) 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 (ibr, see Sec.  192.7), section 
2, which are grouped under the following four categories:
* * * * *
    (b) Data gathering and integration. To identify and evaluate the 
potential threats to a covered pipeline segment, an operator must 
gather and integrate existing 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 A to 
ASME/ANSI B31.8S, and consider both on the covered segment and similar 
non-covered segments, past incident history, corrosion control records, 
continuing surveillance records, patrolling records, maintenance 
history, internal inspection records and all other conditions specific 
to each pipeline.
* * * * *
    (e) * * *
    (1) Third party damage. An operator must utilize the data 
integration required in paragraph (b) of this section and ASME/ANSI 
B31.8S, Appendix A7 to determine the susceptibility of each covered 
segment to the threat of third party damage. If an operator identifies 
the threat of third party damage, the operator must implement 
comprehensive additional preventive measures in accordance with Sec.  
192.935 and monitor the effectiveness of the preventive measures. If, 
in conducting a baseline assessment under Sec.  192.921, or a 
reassessment under Sec.  192.937, an operator uses an internal 
inspection tool or external corrosion direct assessment, the operator 
must integrate data from these assessments with data related to any 
encroachment or foreign line crossing on the covered segment, to define 
where potential indications of third party damage may exist in the 
covered segment.
    An operator must also have procedures in its integrity management 
program addressing actions it will take to respond to findings from 
this data integration.
    (2) * * *
    (3) Manufacturing and construction defects. If an operator 
identifies the threat of manufacturing and construction defects 
(including seam defects) in the covered segment, an operator must 
analyze the covered segment to determine the risk of failure from these 
defects. The analysis must consider the results of prior assessments on 
the covered segment. An operator may consider manufacturing and 
construction related defects to be stable defects if the operating 
pressure on the covered segment has not increased over the maximum 
operating pressure experienced during the five years preceding 
identification of the high consequence area. If any of the following 
changes occur in the covered segment, an operator must prioritize the 
covered segment as a high risk segment for the baseline assessment or a 
subsequent reassessment.

    (i) Operating pressure increases above the maximum operating 
pressure experienced during the preceding five years;
    (ii) MAOP increases; or
    (iii) The stresses leading to cyclic fatigue increase.

    (4) ERW pipe. If a covered pipeline segment contains low frequency 
electric resistance welded pipe (ERW), lap welded pipe or other pipe 
that satisfies the conditions specified in ASME/ANSI B31.8S, Appendices 
A4.3 and A4.4, and any covered or noncovered segment in the pipeline 
system with such pipe has experienced seam failure, or operating 
pressure on the covered segment has increased over the maximum 
operating pressure experienced during the preceding five years, an 
operator must select an assessment technology or technologies with a 
proven application capable of assessing seam integrity and seam 
corrosion anomalies. The operator must prioritize the covered segment 
as a high risk segment for the baseline assessment or a subsequent 
reassessment.
* * * * *

0
8. In Sec.  192.921:
0
a. Paragraphs (a)(2) and (a)(4) are revised;
0
b. Paragraph (c) is amended by removing ``Sec.  192.917(d)'' and adding 
``Sec.  192.917(e)'' in its place;
0
c. Paragraph (f) is amended by removing ``Sec.  192.205'' and adding 
``Sec.  192.905'' in its place; and
0
d. Paragraph (g) to revised.
    The revisions read as follows:


Sec.  192.921  How is the baseline assessment to be conducted?

    (a) * * *
    (1) * * *
    (2) Pressure test conducted in accordance with subpart J of this 
part. An operator must use the test pressures specified in Table 3 of 
section 5 of ASME/ANSI B31.8S, to justify an extended reassessment 
interval in accordance with Sec.  192.939.
    (3) * * *
    (4) 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 Sec.  
192.949. An operator must also notify a State or local pipeline safety 
authority when either a covered segment is located in a State where OPS 
has an interstate agent agreement, or an intrastate covered segment is 
regulated by that State.
* * * * *
    (g) Newly installed pipe. An operator must complete the baseline 
assessment of a newly-installed segment of pipe covered by this subpart 
within ten (10) years from the date the pipe is installed. An operator 
may conduct a pressure test in accordance with paragraph (a)(2) of this 
section, to satisfy the requirement for a baseline assessment.
* * * * *

0
9. Section 192.925 is amended by revising paragraph (b) to read as 
follows:


Sec.  192.925  What are the requirements for using External Corrosion 
Direct Assessment (ECDA)?

* * * * *
    (b) General requirements. An operator that uses direct assessment 
to assess the threat of external corrosion must follow the requirements 
in this section, in ASME/ANSI B31.8S (ibr, see Sec.  192.7), section 
6.4, and in NACE RP 0502-2002 (ibr, see Sec.  192.7). An operator must 
develop and implement a direct assessment plan that has procedures 
addressing preassessment, indirect examination, direct examination, and 
post-assessment. If the ECDA detects pipeline coating damage, the 
operator must also integrate the data from the ECDA with other 
information from the data integration (Sec.  192.917(b)) to evaluate 
the covered segment for the threat of third party damage, and to 
address the threat as required by Sec.  192.917(e)(1).
* * * * *

0
10. Section 192.927 is amended by revising paragraphs (b), (c)(3)

[[Page 18233]]

introductory text and (c)(4)(i) to read as follows:


Sec.  192.927  What are the requirements for using Internal Corrosion 
Direct Assessment (ICDA)?

* * * * *
    (b) General requirements. An operator using direct assessment as an 
assessment method to address internal corrosion in a covered pipeline 
segment must follow the requirements in this section and in ASME/ANSI 
B31.8S (ibr, see Sec.  192.7), section 6.4 and appendix B2. The ICDA 
process described in this section applies only for a segment of pipe 
transporting nominally dry natural gas, and not for a segment with 
electrolyte nominally present in the gas stream. If an operator uses 
ICDA to assess a covered segment operating with electrolyte present in 
the gas stream, the operator must develop a plan that demonstrates how 
it will conduct ICDA in the segment to effectively address internal 
corrosion, and must provide notification in accordance with Sec.  
192.921 (a)(4) or Sec.  192.937(c)(4).
    (c) * * *
    (3) Identification of locations for excavation and direct 
examination. An operator's plan must identify the locations where 
internal corrosion is most likely in each ICDA region. In the location 
identification process, an operator must identify a minimum of two 
locations for excavation within each ICDA Region within a covered 
segment and must perform a direct examination for internal corrosion at 
each location, using ultrasonic thickness measurements, radiography, or 
other generally accepted measurement technique. One location must be 
the low point (e.g., sags, drips, valves, manifolds, dead-legs, traps) 
within the covered segment nearest to the beginning of the ICDA Region. 
The second location must be further downstream, within a covered 
segment, near the end of the ICDA Region. If corrosion exists at either 
location, the operator must--
    (4) * * *
    (i) Evaluating the effectiveness of ICDA as an assessment method 
for addressing internal corrosion and determining whether a covered 
segment should be reassessed at more frequent intervals than those 
specified in Sec.  192.939. An operator must carry out this evaluation 
within a year of conducting an ICDA; and
* * * * *

0
11. Section 192.929 is amended by revising paragraph (a) to read as 
follows:


Sec.  192.929  What are the requirements for using Direct Assessment 
for Stress Corrosion Cracking (SCCDA)?

    (a) Definition. Stress Corrosion Cracking Direct Assessment (SCCDA) 
is a process to assess a covered pipe segment for the presence of SCC 
primarily by systematically gathering and analyzing excavation data for 
pipe having similar operational characteristics and residing in a 
similar physical environment.
* * * * *

0
12. Section 192.933 is amended by revising paragraphs (b), (c) and 
(d)(1)(iii) to read as follows:


Sec.  192.933  What actions must be taken to address integrity issues?

* * * * *
    (b) Discovery of condition. Discovery of a condition occurs when an 
operator has adequate information about a condition to determine that 
the condition presents a potential threat to the integrity of the 
pipeline. A condition that presents a potential threat includes, but is 
not limited to, those conditions that require remediation or monitoring 
listed under paragraphs (d)(1) through (d)(3) of this section. 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.
    (c) 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 (d) of this section, an operator must follow the 
schedule in ASME/ANSI B31.8S (ibr, see Sec.  192.7), section 7, Figure 
4. 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 Sec.  192.949 if it cannot 
meet the schedule and cannot provide safety through a temporary 
reduction in operating pressure or other action. An operator must also 
notify a State or local pipeline safety authority when either a covered 
segment is located in a State where OPS has an interstate agent 
agreement, or an intrastate covered segment is regulated by that State.
    (d) * * *
    (1) * * *
    (iii) An indication or anomaly that in the judgment of the person 
designated by the operator to evaluate the assessment results requires 
immediate action.
* * * * *

0
13. In Sec.  192.935:
0
a. The section heading of Sec.  192.935 is revised;
0
b. Paragraphs (b)(1) introductory text, (b)(1)(ii), and (b)(1)(iv) are 
revised; and
0
c. Paragraph (d) introductory text is revised and paragraph (d)(3) is 
added.
0
The additions and revisions are as follows:


Sec.  192.935  What additional preventive and mitigative measures must 
an operator take?

* * * * *
    (b) * * *
    (1) Third party damage. An operator must enhance its damage 
prevention program, as required under Sec.  192.614 of this part, with 
respect to a covered segment to prevent and minimize the consequences 
of a release due to third party damage. Enhanced measures to an 
existing damage prevention program include, at a minimum--
    (i) * * *
    (ii) Collecting in a central database information that is location 
specific on excavation damage that occurs in covered and non covered 
segments in the transmission system and the root cause analysis to 
support identification of targeted additional preventative and 
mitigative measures in the high consequence areas. This information 
must include recognized damage that is not required to be reported as 
an incident under part 191.
    (iii) * * *
    (iv) Monitoring of excavations conducted on covered pipeline 
segments by pipeline personnel. If an operator finds physical evidence 
of encroachment involving excavation that the operator did not monitor 
near a covered segment, an operator must either excavate the area near 
the encroachment or conduct an above ground survey using methods 
defined in NACE RP-0502-2002 (ibr, see Sec.  192.7). An operator must 
excavate, and remediate, in accordance with ANSI/ASME B31.8S and Sec.  
192.933 any indication of coating holidays or discontinuity warranting 
direct examination.
* * * * *
    (d) Pipelines operating below 30% SMYS. An operator of a 
transmission pipeline operating below 30% SMYS located in a high 
consequence area must follow the requirements in paragraphs (d)(1) and 
(d)(2)of this section, the requirements for a low stress external 
corrosion reassessment in Sec.  192.941(b) and the requirements for a 
low stress

[[Page 18234]]

internal corrosion reassessment in Sec.  192.941(c). An operator of a 
transmission pipeline operating below 30% SMYS located in a Class 3 or 
Class 4 area but not in a high consequence area must follow the 
requirements in paragraphs (d)(1), (d)(2) and (d)(3) of this section.
    (1) * * *
    (2) * * *
    (3) Perform semi-annual leak surveys (quarterly for unprotected 
pipelines or cathodically protected pipe where electrical surveys are 
impractical).
* * * * *

0
14. Section 192.937 is amended by revising paragraphs (c)(2) and (c)(4) 
to read as follows:


Sec.  192.937  What is a continual process of evaluation and assessment 
to maintain a pipeline's integrity?

* * * * *
    (c) * * *
    (2) Pressure test conducted in accordance with subpart J of this 
part. An operator must use the test pressures specified in Table 3 of 
section 5 of ASME/ANSI B31.8S, to justify an extended reassessment 
interval in accordance with Sec.  192.939.
    (3) * * *
    (4) 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 Sec.  
192.949. An operator must also notify a State or local pipeline safety 
authority when either a covered segment is located in a State where OPS 
has an interstate agent agreement, or an intrastate covered segment is 
regulated by that State.
* * * * *

0
15. In Sec.  192.939:
0
a. Paragraphs (a) introductory text and (a)(1)(i) are revised;
0
b. Paragraph (a)(3) is amended by removing the word ``calculation'' at 
the end of the first sentence and adding the word ``method'' in its 
place;
0
c. Paragraph (b) introductory text is amended by removing the word 
``minimum'' in the beginning of the second sentence and adding the word 
``maximum'' in its place; and
0
d. Paragraph (b)(5) is revised and the undesignated paragraph before 
the table is designated as paragraph (b)(6).
0
The revisions read as follows:


Sec.  192.939  What are the required reassessment intervals?

* * * * *
    (a) Pipelines operating at or above 30% SMYS. An operator must 
establish a reassessment interval for each covered segment operating at 
or above 30% SMYS in accordance with the requirements of this section. 
The maximum reassessment interval by an allowable reassessment method 
is seven years. If an operator establishes a reassessment interval 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 at the interval 
the operator has established. A reassessment carried out using 
confirmatory direct assessment must be done in accordance with Sec.  
192.931. The table that follows this section sets forth the maximum 
allowed reassessment intervals.
    (1) * * *
    (i) Basing the interval on the identified threats for the covered 
segment (see Sec.  192.917) and on the analysis of the results from the 
last integrity assessment and from the data integration and risk 
assessment required by Sec.  192.917; or
* * * * *
    (b) * * *
    (5) Reassessment by the low stress assessment method at 7-year 
intervals in accordance with Sec.  192.941 with reassessment by one of 
the methods listed in paragraphs (b)(1) through (b)(3) of this section 
by year 20 of the interval.
    The following table sets forth the maximum reassessment intervals. 
Also refer to Appendix E.II for guidance on Assessment Methods and 
Assessment Schedule for Transmission Pipelines Operating Below 30% 
SMYS. In case of conflict between the rule and the guidance in the 
Appendix, the requirements of the rule control. An operator must comply 
with the following requirements in establishing a reassessment interval 
for a covered segment:
* * * * *


Sec.  192.941  [Amended]

0
16. In Sec.  192.941, paragraph (b)(2)(ii) is amended by removing the 
term ``1\1/2\ years'' in the first sentence and adding ``18 months'' in 
its place.

0
17. Section 192.943 is amended by revising paragraph (a)(1) to read as 
follows:


Sec.  192.943  When can an operator deviate from these reassessment 
intervals?

* * * * *
    (a) * * *
    (1) Lack of internal inspection tools. An operator who uses 
internal inspection as an assessment method may be able to justify a 
longer reassessment period for a covered segment if internal inspection 
tools are not available to assess the line pipe. To justify this, the 
operator must demonstrate that it cannot obtain the internal inspection 
tools within the required reassessment period and that the actions the 
operator is taking in the interim ensure the integrity of the covered 
segment.
* * * * *

0
18. Section 192.945 is amended as follows:
0
a. Paragraph (a) to revised; and
0
b. Paragraph (b) is amended by removing the last sentence.


Sec.  192.945  What methods must an operator use to measure program 
effectiveness?

    (a) General. An operator must include in its integrity management 
program methods to measure, on a semi-annual basis, whether the program 
is effective in assessing and evaluating the integrity of each covered 
pipeline segment and in protecting the high consequence areas. These 
measures must include the four overall performance measures specified 
in ASME/ANSI B31.8S (ibr, see Sec.  192.7), section 9.4, and the 
specific measures for each identified threat specified in ASME/ANSI 
B31.8S, Appendix A. An operator must submit the four overall 
performance measures, by electronic or other means, on a semi-annual 
frequency to OPS in accordance with Sec.  192.951. An operator must 
submit its first report on overall performance measures by August 31, 
2004. Thereafter, the performance measures must be complete through 
June 30 and December 31 of each year and must be submitted within 2 
months after those dates.
* * * * *


Sec.  192.947  [Amended]

0
19. In Sec.  192.947 second sentence is amended by removing ``minium'' 
and adding ``minimum'' in its place.

Appendix A to Part 192 [Amended]

0
20. Appendix A to part 192 is amended by redesignating paragraph 
numbers II. F. and II. G. as paragraph numbers II. H. and II. I., 
respectively.

0
21. Appendix E to part 192 is revised to read as follows:

Appendix E to Part 192--Guidance on Determining High Consequence Areas 
and on Carrying out Requirements in the Integrity Management Rule

I. Guidance on Determining a High Consequence Area

    To determine which segments of an operator's transmission pipeline 
system are covered for purposes of the integrity

[[Page 18235]]

management program requirements, an operator must identify the high 
consequence areas. An operator must use method (a) or (b) from the 
definition in Sec.  192.903 to identify a high consequence area. An 
operator may apply one method to its entire pipeline system, or an 
operator may apply one method to individual portions of the pipeline 
system. (Refer to figure E.I.A for a diagram of a high consequence 
area).
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[GRAPHIC] [TIFF OMITTED] TR06AP04.003

II. Guidance on Assessment Methods and Additional Preventive and 
Mitigative Measures for Transmission Pipelines

    (a) Table E.II.1 gives guidance to help an operator implement 
requirements on additional preventive and mitigative measures for 
addressing time dependent and independent threats for a transmission 
pipeline operating below 30% SMYS not in an HCA (i.e. outside of 
potential impact circle) but located within a Class 3 or Class 4 
Location.
    (b) Table E.II.2 gives guidance to help an operator implement 
requirements on assessment methods for addressing time dependent and 
independent threats for a transmission pipeline in an HCA.
    (c) Table E.II.3 gives guidance on preventative & mitigative 
measures addressing time dependent and independent threats for 
transmission pipelines that operate below 30% SMYS, in HCAs.

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BILLING CODE 4910-60-C

    Issued in Washington, DC, on March 17, 2004.
Samuel G. Bonasso,
Deputy Administrator.
[FR Doc. 04-6398 Filed 4-5-04; 8:45 am]
BILLING CODE 4910-60-P