[Federal Register Volume 65, Number 237 (Friday, December 8, 2000)]
[Proposed Rules]
[Pages 76968-76982]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 00-31224]


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DEPARTMENT OF TRANSPORTATION

Research and Special Programs Administration

49 CFR Part 195

[Docket No. RSPA-97-2762; Notice 3]
RIN 2137-AD24


Controlling Corrosion on Hazardous Liquid and Carbon Dioxide 
Pipelines

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

ACTION: Notice of proposed rulemaking.

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SUMMARY: We are proposing to change some of the corrosion control 
standards for hazardous liquid and carbon dioxide pipelines. The 
proposed changes are based on our review of the adequacy of the present 
standards compared to similar standards for gas pipelines and 
acceptable safety practices. The proposed changes are intended to 
improve the clarity and effectiveness of the present standards and 
reduce the potential for pipeline accidents due to corrosion.

DATES: Persons interested in submitting written comments on the 
proposed rules must do so by February 6, 2001. Late filed comments will 
be considered so far as practicable.

ADDRESSES: You may submit written comments by mailing or delivering an 
original and two copies to the Dockets Facility, U.S. Department of 
Transportation, Room PL-401, 400 Seventh Street, SW., Washington, DC 
20590-0001. The Dockets Facility is open from 10:00 a.m. to 5:00 p.m., 
Monday through Friday, except on Federal holidays when the facility is 
closed. Or you may submit written comments to the docket electronically 
at the following web address: http://dms.dot.gov. See the SUPPLEMENTARY 
INFORMATION section for additional filing information.

FOR FURTHER INFORMATION CONTACT: L. M. Furrow by phone at 202-366-4559, 
by fax at 202-366-4566, by mail at U.S. Department of Transportation, 
400 Seventh Street, SW., Washington, DC 20590, or by e-mail at 
[email protected].

SUPPLEMENTARY INFORMATION:

Filing Information, Electronic Access, and General Program 
Information

    All written comments should identify the docket and notice numbers 
stated in the heading of this notice. Anyone who wants confirmation of 
mailed comments must include a self-addressed stamped postcard. To file 
written comments electronically, after logging onto http://dms.dot.gov, 
click on ``Electronic Submission.'' You can read comments and other 
material in the docket at this Web address: http://dms.dot.gov. General 
information about our pipeline safety program is available at this 
address: http://ops.dot.gov.

Background

    We have reviewed the corrosion control standards in 49 CFR part 195 
for hazardous liquid and carbon dioxide pipelines to see if any 
standards need to be made clearer, more effective, or consistent with 
acceptable safety practices. Although the likelihood of corrosion-
caused accidents harming people or the environment is relatively low, 
we undertook the review because corrosion is the second leading cause 
of reported accidents on hazardous liquid pipelines, and improving the 
standards has the potential to reduce the number of future 
accidents.\1\
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    \1\ For the period 1986 through 1999, corrosion caused 25 
percent of all incidents reported under Part 195; 3 percent of all 
deaths; 2 percent of all injuries; and 19 percent of all property 
damage.
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    The review began September 8, 1997, when we held a public meeting 
on how the part 195 corrosion control standards and the corrosion 
control standards for gas pipelines in 49 CFR part 192 might be 
improved (62 FR 44436; Aug. 21, 1997). To attract participation by 
corrosion experts, we held the public meeting in Oakbrook, Illinois, in 
conjunction with meetings of NACE International, a professional 
technical society dedicated to corrosion control.

[[Page 76969]]

    The Oakbrook meeting focused on whether we should incorporate by 
reference NACE Standard RP0169-96, ``Control of External Corrosion on 
Underground or Submerged Metallic Piping Systems,'' as a substitute for 
all or some of the part 192 and part 195 standards. Two other 
significant topics were whether part 192 and part 195 corrosion control 
standards need to be updated to ensure safety, and whether gas, 
hazardous liquid, and carbon dioxide pipelines should be subject to the 
same corrosion control standards.
    For technical and other reasons, including the document's non-
mandatory style, most meeting participants and subsequent commenters 
opposed incorporating the entire NACE Standard RP0169-96 by reference. 
But participants agreed universally that part 192 and part 195 
corrosion control standards are largely sufficient, and although some 
changes may be needed, the standards should be generally the same.
    Toward this end, we began to consider whether the more 
comprehensive part 192 standards, possibly with some changes, would be 
appropriate for hazardous liquid and carbon dioxide pipelines. For 
technical input, we met from time to time with representatives of NACE, 
the pipeline industry, and state pipeline safety agencies. At these 
meetings, we also examined whether the part 192 standards need to be 
more effective or clearer. As guidance for this assessment, the meeting 
participants developed the following principles:
     Evaluate existing data and use the evaluation to assess 
the need to change standards.
     Continue to improve public safety and environmental 
protection.
     Assess the need for corrosion control standards throughout 
the national pipeline system based on the risk associated with 
different parts of the system.
     Upgrade regulations to allow for future changes in 
pipeline industry technology and operating practices as appropriate.
     Strive for uniform interpretation/enforcement.
     To the extent practicable, involve all interested parties 
in assessing the need to change standards.
     Use the new cost/benefit policy framework being developed 
for RSPA's pipeline safety advisory committees in determining the costs 
and benefits of potential changes to standards.
     Achieve balance between performance and prescriptive 
language.
     Develop performance measures to assess the effectiveness 
of corrosion control programs.
     Focus on managing corrosion to maintain pipeline 
integrity.
     Provide adequate regulatory flexibility to allow operators 
to implement alternative measures that meet the performance 
requirements of the corrosion regulations.
    The meetings left us with various concerns about the total 
effectiveness and clarity of the part 192 corrosion control standards 
and the suitability of applying those standards to hazardous liquid and 
carbon dioxide pipelines. We also knew that the National Association of 
Pipeline Safety Representatives (NAPSR), the Gas Piping Technology 
Committee (GPTC), and the National Transportation Safety Board (NTSB) 
had at various times recommended changes to part 192 and part 195 
corrosion control standards. So, to get public comment on our concerns 
and the recommended changes, we held another public meeting on April 
28, 1999, in San Antonio, Texas (64 FR 16885; April 7, 1999). We also 
invited comments on the idea of allowing operators to follow their own 
corrosion management plans or NACE Standard RP0169-96 as an alternative 
to all or part of the part 192 or part 195 corrosion control standards.

San Antonio Meeting

    At least 180 persons attended the San Antonio public meeting. 
However, only a few persons made oral statements, which are summarized 
as follows:
    The Interstate Natural Gas Association of America (INGAA) said that 
based on the record of low numbers of deaths and injuries, not much 
change in the part 192 standards is needed, even if corrosion is the 
second leading cause of reported pipeline incidents. INGAA attributed 
the good safety record to proper management of risk, saying it would be 
nonproductive if changes to generally applicable safety standards 
caused operators to shift their limited resources away from higher risk 
areas. INGAA emphasized the use of cost/benefit assessment in 
determining the need for new or revised standards. At least two other 
meeting participants (Enron and Columbia Gulf) expressed support for 
INGAA's views.
    The American Gas Association (AGA) and American Public Gas 
Association (APGA) jointly made a statement similar to INGAA's and 
pointed out that DOT safety statistics do not justify changes in the 
present standards. AGA/APGA further noted that corrosion is not the 
second leading cause of incidents on gas distribution lines, but the 
last cause, resulting in about 4 percent of all reported incidents. The 
views of AGA/APGA were supported by at least one other meeting 
participant (Columbia Gulf) and by a majority of the persons who 
submitted written comments to the docket after the meeting. These 
subsequent written comments are condensed below under the ``Comments 
after San Antonio'' subheading.
    Another participant, Global Cathodic Protection, submitted a 
statement, backed by 72 corrosion control practitioners, that cathodic 
protection criteria in appendix D of part 192 are preferred to the 
criteria in NACE Standard RP0169-96.
    Equilon Enterprises, an operator of petroleum pipelines, did not 
support the alternative of corrosion management plans, because of the 
burden of review by government and the possibility that government 
reviewers and operator personnel may not be equally qualified to 
evaluate the plans. In addition, Equilon said that removing unnecessary 
differences between part 192 and part 195 standards would minimize 
confusion and disagreements between operators and government 
inspectors. On other points raised in the meeting notice, Equilon 
preferred that part 195 not refer to NACE Standard RP0169-96. But, 
Equilon did support the need for qualification requirements for bosses 
who lead corrosion control programs, and it thought the part 192 
standards should disallow the use of bare unprotected pipe.
    An engineering consultant said the ``instant-off'' approach to 
measuring cathodic protection was excessive. Similarly, the Equilon 
representative said that across-the-board use of the negative 850 mV 
criterion with instant-off readings is not productive, and that the 100 
mV criterion is more cost-effective in many cases. A university 
professor said that corrosion control technicians do not do instant-off 
tests the same way. But another engineering consultant noted that NACE 
has a companion standard that covers instant-off tests: TM0497-97, 
Measurement Techniques Related to Criteria for Cathodic Protection on 
Underground or Submerged Metallic Piping Systems.

Comments Submitted After the San Antonio Meeting

    Following the San Antonio public meeting, the docket remained open 
to receive written comments on the matters addressed in the meeting 
notice. Sixty-two persons filed written comments. These commenters 
included pipeline safety agencies in Arizona and Iowa, two corrosion 
control firms (Corrosion Control International and Global Cathodic 
Protection), two

[[Page 76970]]

operators of petroleum pipelines (Mobil Corporation and Tosco Refining 
Company), seven pipeline trade associations (American Gas Association 
(AGA), American Public Gas Association (APGA), Interstate Natural Gas 
Association of America, New England Gas Association, New York Gas 
Group, Ohio Gas Association, and American Petroleum Institute), six 
operators of interstate gas pipelines (CMS Energy, Columbia Energy 
Group, Duke Energy, Enron Gas Pipeline Group, KN Energy, and Phillips 
Pipe Line Company), and 43 local gas distribution companies.
    General Comments. Most of the written comments specifically address 
RSPA concerns and other topics in the San Antonio meeting notice. 
Still, there were some general comments: Two gas distribution operators 
said that requiring operators to cathodically protect cast iron or 
ductile iron pipe would have a big impact on the distribution industry. 
These operators also suggested that small fittings made of copper or 
brass and steel fittings with a corrosion resistant coating should be 
exempt from cathodic protection requirements. Other rule changes they 
suggested were intended to yield savings by specifying that electronic 
or remote data collection can be used to meet the monitoring 
requirements and by extending the interval for monitoring rectifiers 
from every 2 months to twice a year, particularly for newly 
manufactured devices.
    AGA/APGA welcomed minor rule changes that address clarity, 
consistency, technology, but said that sweeping changes are not 
justified by the safety data. They advised us to use cost/benefit 
assessment and non-regulatory approaches to perceived problems. Of the 
62 commenters, 42 expressed support for the joint comments of AGA/APGA. 
Others, such as Mobil Corporation, Enron, and the New England Gas 
Association, similarly expressed doubt that substantial changes to the 
standards were warranted in view of the incident record. One commenter, 
Kansas Gas Service, backed up its claim that the present standards are 
adequate by referring to its own record: no reported incidents for the 
period 1989-98. Tosco Refining stated that making the corrosion control 
maintenance requirements in Parts 192 and 195 alike would mitigate 
compliance difficulties for companies that operate both gas and 
petroleum pipelines.
    Comments on RSPA Concerns: This section of the preamble includes 
summaries of comments that specifically address RSPA's concerns about 
whether certain provisions of Part 192 corrosion control standards need 
to be improved. The AGA/APGA comments are identified because many 
commenters supported the AGA/APGA views. Summaries of comments on 
changes recommended by NAPSR, GPTC, and NTSB, on alternatives, and on 
topics included in the ``Public Participation'' section of the meeting 
notice are discussed afterward.

Section 192.453  Personnel Qualification

    RSPA Concern: In view of the proposed rules on qualification of 
pipeline personnel (63 FR 57269; Oct. 27, 1998) \2\, are more specific 
qualification standards needed for individuals who direct or carry out 
corrosion control procedures?
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    \2\ After the San Antonio meeting, RSPA adopted final rules on 
personnel qualification that closely paralleled the proposed rule 
(64 FR 46853; Aug. 27, 1999).
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    Comments: All 23 comments on this concern opposed changing 
Sec. 192.453. They said either the existing rule is adequate or the 
proposed rules on personnel qualification are sufficient. Most of these 
commenters also opposed establishing specific technical qualifications 
for company managers. They said these personnel need more business than 
technical knowledge to assure that corrosion and other maintenance 
problems are handled economically. AGA/APGA suggested that any 
remaining qualification issues be addressed in a non-regulatory way 
through ongoing discussions with industry training representatives at 
DOT's Transportation Safety Institute.

Section 192.455  External Corrosion: New Pipelines

    RSPA Concern: Should a cathodic protection system be installed on 
offshore pipelines in less than one year after the pipeline is 
constructed, for example, 60 days, because of the strong corrosiveness 
of salt water?
    Comments: The two comments on this concern favored a 60-day 
installation period.
    RSPA Concern: Is it in the interest of safety to exempt pipelines 
in particular environments and temporary pipelines from the coating and 
cathodic protection requirements?
    Comments: Three commenters opposed the present exemptions, either 
because corrosion leaks can happen rapidly or because the installations 
are so varied they should be handled by waivers rather than general 
exemption. At the same time, three commenters supported the exemptions, 
contending that corrosion is usually a long term problem, many 
environments are not conducive to corrosion, and required monitoring 
would detect incipient problems. AGA/APGA said that safety data do not 
suggest the present exemptions have been detrimental to safety.

Section 192.457  External Corrosion: Existing Pipelines

    RSPA Concern: Should existing compressor, regulator, and measuring 
station piping continue to be excluded from the requirement to 
cathodically protect effectively coated transmission line pipe?
    Comments: Five commenters said the piping should not be excluded, 
arguing that it does not differ from pipe that must be protected and 
that failures at these locations may have serious consequences. Three 
other commenters said they cathodically protect all their compressor, 
regulator, and measuring station piping.
    RSPA Concern: Is the present requirement to cathodically protect 
certain older existing pipelines only in areas of ``active corrosion'' 
adequate for public safety? If not, what would be a cost-effective 
alternative standard?
    Comments: Only one commenter opposed the present rule. This 
commenter contended that the entire pipeline needs protection because 
spot protection moves the corrosion problem to other places on the 
line. However, 13 commenters, including AGA/APGA, supported the present 
rule, saying that it is a cost-effective approach to protecting older 
lines, particularly since not all corrosion is detrimental to safety. 
Another commenter thought that adding cathodic protection to old bare 
lines in mildly corrosive or non-corrosive soils could accelerate the 
rate of any localized corrosion that might exist.
    RSPA Concern: Is the meaning of ``active corrosion'' clear and 
technically sound? If not, how should it be changed?
    Comments: None of the 12 comments advocated changing the present 
definition of ``active corrosion.'' Five commenters, including AGA/
APGA, thought that possible changes would be more prescriptive, less 
flexible, or not appropriate for all areas.

Section 192.461  External Corrosion: Coating

    RSPA Concern: Should the implicit requirement to coat field joints 
and repairs be expressly stated?
    Comments: Four commenters said this requirement should be expressly 
stated. But four other commenters worried that singling out any item 
would raise questions about items not listed.

[[Page 76971]]

Similarly, another commenter thought the implicit requirement was 
adequate for field joints.
    RSPA Concern: Does coating need to be compatible with the 
anticipated service conditions, including the effects of temperature?
    Comments: Four commenters agreed that such service compatibility is 
necessary. And one of these commenters suggested that a performance 
standard would improve the effectiveness of the existing rule in this 
regard. However, another commenter said the existing rule is adequate 
because service compatibility is implied.
    RSPA Concern: For offshore pipelines, during installation, are 
special measures necessary to protect against damage to coating, 
including field joint coating; and, to avoid mechanical damage, are 
special coatings needed on J-tubes, I-tubes and pipelines installed by 
the bottom tow method?
    Comments: There were no comments on this concern.

Section 192.463  External Corrosion: Cathodic Protection Criteria

    RSPA Concern: Are the cathodic protection system criteria in 
appendix D of part 192, 300 mV shift and E-log-I, obsolete, since they 
are not in section 6 of NACE Standard RP0169-96? If so, should 
operators be allowed to continue to use them on existing pipe, but not 
new pipe?
    Comments: Three commenters favored dropping these two criteria or 
at least E-log-I from appendix D. Six other commenters said they would 
support dropping the criteria only if the criteria were known to be 
ineffective or no longer in use. One commenter acknowledged using E-
log-I and two others said the two criteria are adequate and should be 
allowed. AGA/APGA and one other commenter said the NACE standard 
recognizes the use of other successful criteria, such as those in 
appendix D, and that safety data do not show that the 300 mV shift and 
E-log-I criteria result in higher leak rates or incidents.

Section 192.465  External Corrosion: Monitoring

    RSPA Concern: Does the sampling basis prescribed for inspecting 
short sections of mains or transmission lines not in excess of 100 feet 
and separately protected service lines provide effective corrosion 
control, particularly as it applies to service lines that supply gas to 
public buildings?
    Comments: Two commenters thought the present rule is ineffective, 
asserting that a single inspection is not enough to assess safety over 
a 10-year period, no matter if public buildings are involved. However, 
four commenters argued that because corrosion is slow, there has been 
no problem in sampling pipe to detect corrosion before it becomes 
critical. And two commenters said sampling is a cost-effective way to 
monitor scattered sites. AGA/APGA and two other commenters said that 
safety data do not show that sampled pipe has more corrosion-caused 
leaks than other pipe. Several commenters foresaw difficulties in 
defining a ``public building.'' Only one commenter thought that more 
frequent monitoring is needed for lines leading to public buildings 
because of the increased potential for serious consequences.

Section 192.467  External Corrosion: Electrical Isolation

    RSPA Concern: What remedial action is needed when an electrical 
short in a casing results in inadequate cathodic protection of the 
pipeline outside the casing?
    Comments: Five commenters said these shorts should be cleared 
because other options are ineffective and imposing more current to 
offset the short could have adverse effects. But two other commenters 
said that clearing shorts can be costly if the line must be taken out 
of service or replaced, and that there is no consensus on adequate 
remediation. Another observation by one commenter was that the 
electrical isolation requirements are not needed since cathodic 
protection has to meet the criteria for adequacy.
    RSPA Concern: Should newly constructed offshore pipelines be 
electrically isolated from bare steel platforms unless both are 
protected as a single unit?
    Comments: The lone commenter who addressed this concern said that 
isolation is needed, yet concluded that a rule change was not needed 
because annual surveys will identify any problem.
    RSPA Concern: Is electrical isolation needed where contact with 
aboveground structures would adversely affect cathodic protection?
    Comments: One commenter said we should require isolation in all 
such cases. Three commenters argued that while isolation is needed a 
rule change is not, because annual surveys will identify any problem. 
Three other commenters argued that isolation is not needed if the 
alternative of sufficient local protection is applied.

Section 192.471  External Corrosion: Test Leads

    RSPA Concern: Are accessible test leads needed on offshore risers 
that are electrically isolated and not accessible for testing?
    Comments: The two commenters who addressed this concern said the 
present rule is adequate because operators must demonstrate adequate 
cathodic protection, which necessitates test leads.
    RSPA Concern: For aluminum pipelines, should all test leads be 
insulated aluminum conductors and installed to avoid harm to the pipe?
    Comments: There were two comments on this concern. One said test 
leads and connection material must be compatible with aluminum. The 
other said test leads must be insulated aluminum conductors and 
installed to avoid harm to the pipe.

Section 192.473  External Corrosion: Interference Currents

    RSPA Concern: Where light rail systems exist, should operators 
specifically be required to identify and test for stray currents and 
keep records of the test results?
    Comments: Four commenters said such a specific requirement was 
needed for light rail. But three commenters disagreed, arguing the 
present rule is adequate because it requires operators to test for all 
sources of stray current, including large junk yard magnets and 
electric cranes.

Section 192.475  Internal Corrosion

    RSPA Concern: Are special requirements needed to deal with the 
problem of internal corrosion in storage field piping, as evidenced by 
piping leaks in West Virginia and several Midwestern states?
    Comments: Three commenters felt the present rule is adequate for 
all situations and specific requirements for storage fields are not 
needed. In contrast, one commenter thought the rule should specifically 
recognize the problems posed by such piping and require more coupons or 
traps where liquid might collect, pipe design that avoids liquid 
collection, use of lined pipe, periodic pigging, or dehydration. 
Another commenter thought operators should have to prepare a procedure 
and follow it to minimize internal corrosion.

Section 192.479  Atmospheric Corrosion: General

    RSPA Concern: Should new and existing pipelines be subject to the 
same protection requirements?
    Comments: One commenter saw no need to change the distinction 
between new and existing pipelines.\3\ Six others

[[Page 76972]]

supported treating all aboveground pipelines alike regardless of age, 
but two of these commenters said the rule should apply only to ``active 
corrosion,'' not to all corrosion.
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    \3\ For new aboveground pipelines, protection is required 
everywhere the pipeline is exposed to the atmosphere, unless the 
operator can demonstrate that a corrosive atmosphere does not exist. 
For old pipelines, protection is required only where harmful 
corrosion is found.
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    RSPA Concern: Is protection needed where corrosion is a light 
surface oxide or where corrosion will not likely affect the safe 
operation of the pipeline before the next scheduled inspection?
    Comments: Six commenters thought the rule should be changed to 
exclude surface oxide because it does not affect pipe integrity. 
However, one commenter thought surface oxide indicates a coating 
problem that operators should identify and track through continuing 
surveillance. One other commenter said that even if corrosion is more 
than superficial, if there is no question of safety before the next 
inspection, then there is no present need for remedial action. Another 
commenter recommended limiting the rule to ``active corrosion'' to 
exclude both superficial corrosion and corrosion that would not likely 
advance to an unacceptable stage before the next inspection.
    RSPA Concern: Is special protection needed in the splash zone of 
offshore pipelines and at soil to air interfaces of onshore pipelines?
    Comments: Three of the four comments on this concern thought the 
existing corrosion rules for buried and aboveground protection are 
adequate. The fourth commenter said any need for special protection 
would be recognized during required inspections.

Section 192.481  Atmospheric Corrosion: Monitoring

    RSPA Concern: Should the inspection interval for onshore pipelines 
be extended beyond 3 years in view of the generally low incidence of 
serious problems on protected pipelines?
    Comments: Two commenters said the present 3-year monitoring cycle 
is not too burdensome. In contrast, seven commenters recommended 
extending the inspection period beyond 3 years, saying that atmospheric 
corrosion is a long-term process. Six of these commenters recommended 
inspection every 5 years, an interval coincident with the interval of 
gas leakage surveys. One other commenter suggested the rule let 
operators determine what inspection intervals are appropriate for the 
pipelines involved.
    RSPA Concern: For onshore pipelines, are more frequent inspections 
needed at soil-to-air interfaces, under thermal insulation, at 
disbonded coatings, and at pipe supports?
    Comments: The consensus of the four comments on this concern was 
that no more frequent inspections than annual are needed at these 
locations. Two commenters said the corrosion problem at these locations 
is too site-specific for a general inspection rule requiring removal of 
coating or jackets.
    RSPA Concern: For offshore pipelines, are more frequent inspections 
needed under poorly bonded coatings and at splash zones, support 
clamps, and deck penetrations?
    Comments: There were no comments on this concern.

Section 192.491  Records

    RSPA Concern: Should operators keep records of findings of non-
corrosive conditions if

Section 192.455  Is Changed To Remove the Benefit of Such Findings?

    Comments: Two commenters agreed that if records of non-corrosive 
conditions no longer have a purpose, the recordkeeping requirement 
should be removed. But another commenter thought records of exposed 
pipe inspections under Sec. 192.459 should be kept even if no corrosion 
is found. This commenter thought such records would be useful in 
surveillance under Sec. 192.613 and in evaluating the significance of 
damaged pipe or coating.
    RSPA Concern: Is the period for keeping corrosion control 
monitoring records, ``as long as the pipeline remains in service,'' 
necessary for safety or accident investigation? If not, what is an 
appropriate period?
    Comments: One commenter believed the present retention period is 
needed to provide a very helpful general history of pipelines. But 
another commenter said that old records are never used once adverse 
conditions are corrected. Two commenters suggested the retention period 
could be reduced to 5 years or two inspection cycles, whichever is 
longer. A similar comment was 5 years or the next inspection cycle, 
whichever is longer.

Recommendations To Change Standards

National Association of Pipeline Safety Representatives

    Recommendation: With regard to Secs. 192.457 and 192.465, NAPSR 
recommended changes to clarify the meaning of an ``electrical survey'' 
and where alternatives to electrical surveys may be used.
    Comments: Three commenters reported that the State-Industry 
Regulatory Review Committee (SIRRC) had reached a consensus on 
``electrical survey'' and alternatives. SIRRC was formed by NAPSR and 
industry representatives to work out differences of opinion over 
NAPSR's 1992 recommendations to revise part 192.\4\ In a report 
transmitted to RSPA by a letter dated May 3, 1999, SIRRC concludes that 
electrical surveys are seldom used on distribution systems, so there is 
no advantage to requiring electrical surveys as a preferred corrosion 
inspection method on distribution systems. SIRRC further concludes that 
if electrical surveys are not used, all available information should be 
used to determine if active corrosion exists. Set out below are SIRRC's 
suggested revisions of Sec. 192.457(b)(3) and Sec. 192.465(e). SIRRC 
also said that in the suggested revision, ``pipeline environment'' 
refers to whether soil resistivity is high or low, wet or dry, contains 
contaminants that may promote corrosion, or has any other known 
condition that might influence the probability of active corrosion.

    \4\ NAPSR's recommendations were published in Notice 2 of Docket 
No. PS-124 (58 FR 59431; Nov. 9, 1993).
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    [192.457(b)(3)] Bare or coated distribution lines. The operator 
shall determine the areas of active corrosion by electrical survey 
or by analysis and review of the pipeline condition. Analysis and 
review shall include, but is not limited to, leak repair history, 
exposed pipe condition reports, and the pipeline environment. For 
the purpose of this section, an electrical survey is a series of 
closely spaced pipe-to-soil readings over a pipeline which are 
subsequently analyzed to identify any locations where a corrosive 
current is leaving the pipe.
    [192.465(e)] (i) For transmission pipelines, after the initial 
evaluation required by paragraphs (b) and (c) of Sec. 192.455 and 
paragraph (b) of Sec. 192.457, each operator shall, not less than 
every 3 years at intervals not exceeding 39 months, reevaluate its 
unprotected pipelines and cathodically protect them in accordance 
with this subpart in areas in which active corrosion is found. The 
operator shall determine the areas of active corrosion by electrical 
survey, or where an electrical survey is impractical, by analysis 
and review of the pipeline condition. Analysis and review shall 
include, but is not limited to, leak repair history, exposed pipe 
condition reports, and the pipeline environment.
    (ii) For distribution pipelines, after the initial evaluation 
required by paragraphs (b) and (c) of Sec. 192.455 and paragraph (b) 
of Sec. 192.457, each operator shall, not less than every 3 years at 
intervals not exceeding 39 months, reevaluate its unprotected 
pipelines and cathodically protect them in accordance with this 
subpart in areas in which active corrosion is found. The operator 
shall determine the areas of active corrosion by electrical survey 
or by analysis and review of

[[Page 76973]]

the pipeline condition. Analysis and review shall include, but is 
not limited to, leak repair history, exposed pipe condition reports, 
and the pipeline environment.
    (iii) For the purpose of this section, an electrical survey is a 
series of closely spaced pipe-to-soil readings over a pipeline which 
are subsequently analyzed to identify any locations where a 
corrosive current is leaving the pipe.

    Recommendation: With regard to Sec. 192.459, NAPSR recommended we 
require operators to record the condition of protective coatings 
whenever they inspect exposed portions of buried pipeline, arguing the 
records would provide a useful history of the condition of the 
pipelines as well as evidence that exposed pipe had been inspected as 
required.
    Comments: Three commenters reported that SIRRC reached a consensus 
on recording the condition of coating when inspecting exposed pipe. 
SIRRC said that coating condition is important in evaluating the 
overall condition of a pipeline, and that this information helps meet 
continuing surveillance and active corrosion rules. SIRRC's suggested 
revision of Sec. 192.459 follows:

    Whenever an operator has knowledge that any portion of a buried 
pipeline is exposed, the exposed portion must be examined to 
determine the condition of the coating, or if the pipeline is bare 
or the coating is deteriorated, the exterior condition of the pipe. 
A record of the examination results shall be made in accordance with 
Sec. 192.491(c). If external corrosion is found, remedial action 
must be taken to the extent required by Sec. 192.483 and the 
applicable paragraphs of Secs. 192.485, 192.487, or 192.489.

    Recommendation: With regard to Sec. 192.467(d), NAPSR recommended 
changes that would require operators to test pipeline casings annually 
for electrical isolation, and to clarify what must be done to minimize 
pipeline corrosion if isolation is not achieved.
    Comments: Three commenters reported that SIRRC did not agree on 
whether shorted casings are a problem or on the need to test casings, 
but agreed that Sec. 192.483 should be amended to include options for 
dealing with shorted casings. SIRRC said its suggested options are 
consistent with common industry practice. SIRRC also recognized that 
the options were not intended as a substitute for proper cathodic 
protection of pipe under Sec. 192.463. SIRRC's suggested revision of 
Sec. 192.483 follows:

    (d) If it is determined that a casing is electrically shorted to 
a pipeline, the operator shall: (1) clear the short, if practical; 
(2) fill the casing with a corrosion inhibiting material; (3) 
monitor for leakage with leak detection equipment at least once each 
calendar year at intervals not exceeding 15 months; or (4) conduct 
an initial inspection with an internal inspection device capable of 
detecting external corrosion in a cased pipeline, and repeat at 
least every 5 years at intervals not to exceed 63 months.

    Recommendation: With regard to Sec. 192.479(b), NAPSR recommended 
that regardless of the date of installation, all aboveground pipelines 
or portions of a pipeline that are exposed to the atmosphere be cleaned 
and either coated or jacketed with a material suitable for the 
prevention of atmospheric corrosion, unless the pipeline is in a non-
corrosive atmosphere.
    Comments: Two commenters reported that SIRRC reached a consensus 
that all aboveground pipe should be subject to the same protection 
requirement. SIRRC's suggested revision of Sec. 192.479, which would 
remove the present distinction between pipelines installed before and 
after particular dates, is set forth below. SIRRC also explained that 
the term ``active corrosion'' does not include non-damaging corrosive 
films.

    [192.479] (a) Each aboveground pipeline or portion of a pipeline 
that is exposed to the atmosphere must be cleaned and either coated 
or jacketed with a material suitable for the prevention of 
atmospheric corrosion. An operator need not comply with this 
paragraph, if the operator can demonstrate by test, investigation, 
or experience in the area of application that active corrosion does 
not exist.
    (b) If active corrosion is found on an aboveground pipeline or 
portion of pipeline, the operator shall (1) take prompt remedial 
action consistent with the severity of the corrosion to the extent 
required by the applicable paragraphs of Secs. 192.485, 192.487, or 
192.489; and (2) clean and either coat or jacket the areas of 
atmospheric corrosion with a material suitable for the prevention of 
atmospheric corrosion.

    Recommendation: With regard to the provision in Sec. 192.487(a) 
that permits general corrosion in distribution line pipe to be repaired 
instead of replaced, NAPSR recommended that the provision refer to 
generally accepted guidelines for determining what corroded areas may 
be repaired.
    Comments: Two commenters reported that SIRRC did not address this 
issue. In addition, these commenters suggested we allow operators to 
assess the serviceability of distribution line pipe that has wall 
thickness less than 30 percent of nominal wall thickness instead of 
requiring the replacement of such pipe.
    Recommendation: With regard to Sec. 192.489(b), NAPSR recommended 
that we clarify that internal sealing is not an appropriate method of 
strengthening graphitized pipe.
    Comments: Two commenters reported that SIRRC agreed to drop this 
recommendation, since advances in technology may produce strength 
enhancing liners.

Gas Piping Technology Committee

    The following recommendations are from an April 1995, rulemaking 
petition by GPTC:
    Recommendation: Remove from Sec. 192.467 the requirement that pipe 
be electrically isolated from metallic casings. GPTC argued there are 
no safety benefits from clearing shorted casings.
    Comments: There were no comments on this recommendation. But see 
the comments above on Sec. 192.467.
    Recommendation: Amend Secs. 192.465 and 192.481 to allow operators 
to take up to 39 months to carry out inspections of unprotected 
pipelines that must be done at 3-year intervals. GPTC said the extra 
time would add flexibility to the standards, with no reduction in 
safety.
    Comments: The one comment on this recommendation supported the 39-
month period but preferred a 5-year interval to match the interval of 
leakage surveys. Also, see the comments above on Secs. 192.465 and 
192.481.

National Transportation Safety Board

    As a result of a 1996 accident on a butane pipeline operated by 
Koch Pipeline Company near Lively, Texas, NTSB recommended two changes 
to the Part 195 corrosion control standards:
    Recommendation: Revise Part 195 to require pipeline operators to 
determine the condition of pipeline coating whenever pipe is exposed 
and, if degradation is found, to evaluate the coating condition of the 
pipeline. (P-98-35)
    Comments: There were no comments on this recommendation. But see 
the SIRRC comment above on Sec. 192.459.
    Recommendation: Revise Part 195 to include performance measures for 
the adequate cathodic protection of liquid pipelines. (P-98-36)
    Comment: The only comment favored adding to Part 195 either 
Appendix D or NACE cathodic protection criteria.

Alternatives

    In the San Antonio meeting notice, we suggested two alternatives to 
the present corrosion control standards: corrosion management plans and 
NACE Standard RP0169-96. Many operators get excellent results by 
applying pipeline-specific plans that contain corrosion control methods 
and management techniques not required by Part 192 or Part 195 
standards. NACE Standard

[[Page 76974]]

RP0169-96 is widely accepted as the most authoritative source of up-to-
date pipeline corrosion control practices.
    Comments: Two commenters favored corrosion management plans, saying 
they would be consistent with the risk-based approach to regulation and 
cost-effective, since many operators already use them. They also said 
that to qualify a pipeline for exemption from the standards, the plans 
should be designed to produce equal or better results than the 
standards. However, another commenter opposed the plan alternative, 
arguing that the review and evaluation process would further dilute 
government and industry resources and detract from higher priority 
safety matters. And the American Petroleum Institute opposed the plan 
alternative, saying that corrosion should be treated as part of an 
overall integrity management plan that may be developed after the 
conclusion of RSPA's risk management demonstration projects.
    Topics 4 and 6 under the next heading drew additional comments on 
the alternatives.

Topics of Particular Interest

    1. Whether any existing standards deter or disallow the use of new 
technologies, and, if so, how.
    Comments: The two comments on this topic were that while none of 
the standards disallows the use of new technology, unclear standards 
may deter such use.
    2. The costs and benefits of any suggested changes to standards and 
alternatives to standards.
    Comments: The only comment was that we should apply cost/benefit 
analysis to any suggested changes.
    3. The amount of time operators may need to prepare for compliance 
with any suggested standards or alternatives.
    Comments: The only comment was that the time needed for compliance 
depends on the suggested rule change.
    4. With regard to the corrosion management plan and NACE Standard 
alternatives--
    a. The bases for evaluating the adequacy of corrosion management 
plans.
    Comments: Two commenters said the primary basis should be whether 
corrosion is mitigated by the plan. AGA/APGA and another commenter 
suggested we defer further consideration of the plan alternative until 
completion of work by the State/Industry/DOT Regulatory Alternative 
Feasibility Team, which is considering risk-based alternatives to 
safety standards.
    b. The best way to facilitate agency review of operator decisions 
under the alternatives (e.g., prior notification, reporting, 
recordkeeping).
    Comments: Both comments on this topic were that we should review 
the decisions the same as we review decisions in operators' operating 
and maintenance plans.
    c. Whether NACE Standard RP0169-96 is adequate for pipeline 
corrosion control and, if so, should we incorporate it by reference in 
our corrosion control standards?
    Comments: Only one commenter thought NACE Standard RP0169-96 would 
be a cost-effective alternative to existing corrosion control 
standards. Although another commenter said it would be all right to 
reference NACE Standard RP0169-96, the commenter also said it would be 
better to use it as a basis for changing the standards. Ten other 
commenters opposed using NACE Standard RP0169-96. Of these, two said 
the document is not adequate by itself, and it would complicate the 
standards if only parts were referenced. AGA/APGA and two other 
commenters said NACE Standard RP0169-96 is too conservative and too 
costly to apply, but AGA/APGA and another two commenters thought it 
could serve as guidance for corrosion management plans. The reason 
given by one commenter for opposing NACE Standard RP0169-96 was that it 
does not distinguish non-hazardous corrosion from corrosion detrimental 
to public safety.
    5. For hazardous liquid pipelines--
    a. Whether additional standards are needed to further reduce the 
possibility of damage to environmentally sensitive areas.
    Comments: One commenter thought Part 195 should cross reference 
Appendix D or NACE RP0169 criteria for cathodic protection.
    b. If Part 192 standards were applied to hazardous liquid 
pipelines, the changes, if any, that would be needed to account for 
differences between gas and liquid pipelines.
    Comments: There were no comments on this topic.
    6. For gas distribution systems--
    a. Root causes of corrosion leaks on coated, uncoated, protected, 
and unprotected metallic lines.
    Comments: AGA/APGA and one other commenter said that corrosion 
leaks on distribution lines have a low probability of resulting in 
reportable incidents. Three additional commenters said that corrosion 
leaks on properly protected pipe are rare, and that most corrosion 
leaks occur on unprotected bare steel that is too costly to protect. 
These commenters contended the best approach to combating corrosion 
leaks is through aggressive leak surveys.
    b. Descriptions of operating/maintenance practices to minimize 
corrosion leaks on cathodically unprotected lines.
    Comments: Six commenters reported the use of a ranking system to 
prioritize segments of bare steel pipe for replacement, based on age, 
location, leaks, size, and cathodic protection. Other practices 
included replacement rather than repair of bare steel, and not uprating 
or reconnecting cast iron, ductile iron, or bare steel pipe. Another 
commenter said its practices are designed to enhance economic value 
rather than just meet Part 192 requirements.
    c. Descriptions of risk-based corrosion management programs.
    Comments: The only commenter said a plan should preserve the intent 
of the code but allow for geography and operating condition 
differences.
    d. The best approach to monitoring corrosion control in urban wall-
to-wall paved areas.
    Comments: One commenter suggested taking readings at test stations 
no further than one block (660 feet) apart, while another advised 1200 
feet apart. Still another commenter stressed the importance of creating 
access openings.
    7. The amount of buried piping at compressor, regulator, and 
measuring stations that is not cathodically protected.
    Comments: Three commenters said all their piping in these locations 
is protected. AGA/APGA said the data are not available, but the piping 
poses a low risk.
    8. Explicit examples of adequate compliance with particular 
standards that have had varied interpretations.
    Comments: AGA/APGA reported that while government compliance 
personnel interpret some standards inconsistently, the safety 
statistics support adequate compliance.
    9. To provide an acceptable level of safety on existing pipelines, 
must cathodic protection preserve the pipeline indefinitely or merely 
slow the rate of corrosion until the pipeline has to be rehabilitated 
or replaced?
    Comments: Two commenters said the decision should be based on a 
cost/benefit assessment, considering the possible use of new materials 
and the future need to move or replace a pipeline due to construction 
by others. One other comment was that corrosion can only be mitigated 
and to try to do otherwise would be too expensive.

[[Page 76975]]

Proposed Subpart H--Corrosion Control

    In view of the above concerns, recommendations, and comments, we 
are proposing to add to part 195 a new subpart H called Corrosion 
Control. Subpart H would prescribe corrosion control standards for new 
and existing steel pipelines to which Part 195 applies. Concerns, 
recommendations, and comments that pertain primarily to the corrosion 
control standards in Part 192 will be addressed in a future rulemaking 
proceeding on gas pipelines.
    Because commenters showed little enthusiasm for the alternatives of 
NACE Standard RP0169-96 and corrosion management plans, we did not 
include either alternative in proposed Subpart H (except as provided in 
proposed Sec. 195.567 regarding cathodic protection criteria). 
Nevertheless, because NACE Standard RP0169-96 is so widely respected, 
we would like to keep the floor open for further discussion of the 
merits of adopting it as an overall corrosion control standard for 
pipelines. In this regard, we invite interested persons to comment 
again on the pros and cons of referencing the entire NACE Standard 
RP0169-96 as an alternative to proposed Subpart H. This request for 
comment is not a rulemaking proposal. We recognize that a further 
notice of proposed rulemaking would be required before the entire NACE 
Standard RP0169-96 could be incorporated by reference as a Part 195 
safety standard.
    Proposed Subpart H includes many standards that are identical to 
present corrosion control requirements in Part 195 and standards that 
are substantially like present requirements in Part 192. The proposed 
subpart also includes standards that, while based on present Part 192 
requirements, include changes we think are beneficial improvements, 
considering acceptable safety practices. We do not intend that proposed 
subpart H results in a lessening of current requirements. Each of the 
sections in proposed Subpart H is discussed below.

Section 195.551  Scope.

    Proposed Sec. 195.551 characterizes the activities that are covered 
by the proposed standards in subpart H (i.e., protecting steel 
pipelines against external, internal, and atmospheric corrosion). 
Section 195.551 is informational in nature and would not impose any 
obligations.
    Like the present corrosion control standards in part 195 
(Secs. 195.236, 195.238, 195.242, 195.244, 195.414, 195.416, and 
195.418), proposed Subpart H would apply only to steel pipelines. In 
contrast, comparable corrosion control standards for gas pipelines 
(subpart I of Part 192) apply to pipelines made of any metal. However, 
because hazardous liquid and carbon dioxide pipelines are made of steel 
almost exclusively, such broad coverage is not warranted for pipelines 
regulated by part 195.
    Nevertheless, under Sec. 195.8, operators must give us an 
opportunity to review the safety of any pipeline that is to be 
constructed with a material other than steel. In the case of a non-
steel metallic pipeline, that review would include the operator's plans 
for corrosion control.
    You should note that ``breakout tanks'' \5\ come within the scope 
of proposed subpart H, because part 195 defines ``pipeline'' to include 
breakout tanks (Sec. 195.2). Consistent with the convention stated in 
Sec. 195.1(c), proposed subpart H standards applicable to breakout 
tanks include standards that concern breakout tanks specifically and, 
to the extent applicable, standards that concern pipeline systems, or 
pipelines, generally. Proposed standards that concern only pipe, such 
as Secs. 195.583 and 195.585, do not apply to breakout tanks because 
these standards do not affect parts of pipelines other than pipe.
---------------------------------------------------------------------------

    \5\ ``Breakout tank'' is defined in Sec. 195.2 as ``a tank used 
to (a) relieve surges in a hazardous liquid pipeline system or (b) 
receive and store hazardous liquids transported by a pipeline for 
reinjection and continued transportation by pipeline.''
---------------------------------------------------------------------------

Section 195.553  Qualification of Supervisors

    The new personnel qualification standards in subpart G of part 195 
(64 FR 46866; Aug. 27, 1999) apply to individuals who perform covered 
tasks on pipelines, including regulated corrosion control activities. 
However, supervision of covered tasks is not, itself, a covered task. 
So supervision of corrosion control activities does not come under 
Subpart G.
    We know that prevention of corrosion-caused accidents does not 
depend solely on how well personnel perform covered tasks on pipelines. 
Prevention also depends on the correctness of critical decisions that 
flow from those tasks. Indeed, many Part 195 corrosion control 
standards require operators not only to perform tasks on pipelines, but 
to decide if corrective action is needed as a result of the tasks. For 
example, under Sec. 195.416(d), operators must periodically inspect 
bare pipe and then determine if cathodic protection is needed.
    Individuals assigned to perform covered corrosion control tasks on 
pipelines, such as collecting pipe-to-soil data, may be qualified under 
subpart G without knowing what corrective action, if any, should be 
taken as a result of the tasks. Generally these critical corrosion 
control decisions are made by supervisory personnel who are in charge 
of carrying out the corrosion control procedures under Sec. 195.402(c). 
It is reasonable, we think, that individuals who direct others to carry 
out corrosion control procedures should have sufficient knowledge of 
the procedures so they understand what they are directing.
    At present, Sec. 195.403(c) regulates the qualifications of 
individuals assigned to supervise the performance of corrosion control 
procedures. This rule requires each operator to ``require and verify 
that its supervisors maintain a thorough knowledge of that portion of 
the procedures established under Sec. 195.402 for which they are 
responsible to insure compliance.'' However, Sec. 195.403(c) has been 
changed. On October 28, 2002, this rule will apply only to supervisors 
of emergency response procedures (64 FR 46866). Consequently, we are 
proposing, under Sec. 195.553, to preserve the substance of 
Sec. 195.403(c) as it now applies to supervisors of corrosion control 
procedures.

Section 195.555  External Corrosion Control; Applicability

    Proposed Sec. 195.555 designates the pipelines covered by proposed 
Secs. 195.557, 195.559, and 195.561. As stated below, these three 
proposed standards are identical to the present corrosion control 
standards in Secs. 195.238, 195.242, and 195.244 governing coating, 
cathodic protection, and test leads. Like the standards they would 
replace, the proposed standards would apply only to pipelines 
constructed, relocated, replaced, or otherwise changed after 
Secs. 195.238, 195.242, and 195.244 went into effect and to certain 
converted pipelines (see Sec. 195.5(b)). The effective dates of 
Secs. 195.238, 195.242, and 195.244 are given in Sec. 195.401(c) and 
vary by pipeline. Proposed Sec. 195.555 cross-references 
Secs. 195.401(c) and 195.5(b).
    One other existing corrosion control standard, Sec. 195.236, 
applies to the same pipelines as Secs. 195.238, 195.242, and 195.244. 
But this standard, which requires protection against external 
corrosion, is written in terms that may be too general. We think the 
standard adds nothing substantive to the more specific requirements for 
external corrosion protection in Secs. 195.238 and 195.242. So we are 
proposing to drop Sec. 195.236 and not include it in proposed subpart 
H.

[[Page 76976]]

Section 195.557  External Corrosion Control; Protective Coating

    Proposed Sec. 195.557 is identical to Sec. 195.238, which 
prescribes standards for external coating on certain buried or 
submerged pipeline components.

Section 195.559  External Corrosion Control; Cathodic Protection System

    Proposed Sec. 195.559 is identical to Sec. 195.242, which requires 
certain buried or submerged facilities to be cathodically protected.

Section 195.561  External Corrosion Control; Test Leads

    Proposed Sec. 195.561 is substantially the same as Sec. 195.244, 
which prescribes standards for the installation of test leads to 
measure cathodic protection on certain onshore pipelines. However, we 
are also proposing that at the connection to the pipeline, each bared 
test lead wire and bared metallic area must be coated with an 
electrical insulating material compatible with the pipe coating and the 
insulation on the wire. This provision is now in effect for gas 
pipelines under Sec. 192.471(c).

Section 195.563  External Corrosion Control; Additional Cathodic 
Protection Requirements

    Proposed Sec. 195.563 is comparable to Sec. 195.414(a), which 
requires all effectively coated pipelines to be cathodically protected, 
except for piping in breakout tank areas and pump stations. To avoid 
any duplication of proposed Sec. 195.559, proposed Sec. 195.563 would 
apply only to pipelines that are not protected under proposed 
Sec. 195.559. Also, we omitted the compliance dates in Sec. 195.414(a) 
from proposed Sec. 195.563 because the dates have passed.

Section 195.565  External Corrosion Control; Examination of Buried 
Pipeline When Exposed

    Proposed Sec. 195.565 is comparable to existing Sec. 195.416(e), 
which requires operators to investigate the extent of active corrosion 
found on exposed pipelines. We recently revised a parallel standard, 
Sec. 192.459, to clarify the means and bounds of corrosion 
investigations on exposed gas pipelines (64 FR 56978; Oct. 22, 1999). 
In view of this rule change, we used Sec. 192.459 as a model for 
proposed Sec. 195.565 to provide the same clarity for similar 
investigations required on hazardous liquid and carbon dioxide 
pipelines. We believe this proposal and the associated recordkeeping 
under proposed Sec. 195.587 are consistent with SIRRC's suggested 
changes to Sec. 192.459 quoted above in the discussion of NAPSR's 
Sec. 192.459 recommendation. Under proposed Sec. 195.565, operators may 
use indirect methods, including electrical surveys or smart pigs, 
besides excavation and observation to look for corrosion in the 
vicinity of an exposed portion of pipeline.
    During the course of looking for corrosion on an exposed pipeline, 
operators observe the condition of protective coating on the pipeline. 
Proposed Sec. 195.565 would codify this inherent step by requiring 
operators to first see if the coating is deteriorated before they 
examine the exposed pipeline for corrosion. Operators' records of 
inspections preserve information about examinations of exposed pipe for 
future use, such as assessing the condition of the pipeline for 
purposes of corrosion control. We think the combination of proposed 
Sec. 195.565 and records of examinations of exposed pipe would provide 
an adequate response to NTSB recommendation P-98-35 that part 195 
require operators to determine the condition of external coating on 
exposed pipelines. Proposed Sec. 195.587 (see below) would require 
operators to keep records of examinations of exposed pipe for as long 
as the pipe remains in service rather than 2 years as now required by 
Sec. 195.404(c)(3).

Section 195.567  External Corrosion Control; Cathodic Protection 
Criteria

    NTSB has recommended that Part 195 include performance measures for 
the adequacy of cathodic protection (recommendation P-98-36). We 
support NTSB's recommendation. Consequently, we are proposing, in 
Sec. 195.567, that cathodic protection comply with the criteria and 
other considerations in section 6 of NACE Standard RP0169-96.
    In developing this proposal, we considered that in our experience 
operators universally apply either NACE criteria or criteria in 
appendix D of part 192 to determine the adequacy of cathodic protection 
on pipelines that come under part 195. Similarly, the comments we 
received on performance measures for cathodic protection were divided 
between the NACE criteria and the appendix D criteria. And in its April 
1995 report of a review of the part 195 standards, NAPSR supported 
either set of criteria.
    While NACE and Appendix D criteria overlap in many respects, two 
Appendix D criteria (300 mV shift and E-log-I) are not among the NACE 
criteria. We believe they were omitted because they are outmoded and 
lack technical validation; and the comments did not dissuade us of this 
concern. Given our uncertainty about appendix D, we felt compelled to 
limit our proposal to section 6 of NACE Standard RP0169-96.
    Still it is important to recognize that under proposed Sec. 195.567 
operators would not have to use only criteria included in section 6 of 
NACE Standard RP0169-96. Paragraph 6.2.1 of NACE Standard RP0169-96 
permits operators to use any criteria that achieves corrosion control 
comparable to that attained with criteria included in section 6. In 
addition, paragraph 6.2.1 permits operators to continue to use on 
existing pipelines criteria that have been successfully applied to 
those pipelines. Thus proposed Sec. 195.567 would not deny operators 
the opportunity to use appendix D criteria that are not included in 
section 6 of NACE Standard RP0169-96 as long as the operators can meet 
the tests of comparability or successful application stated in 
paragraph 6.2.1 for the use of alternative criteria. Although section 6 
of NACE Standard RP0169-96 does not provide measures of comparability 
or successful application, to comply with paragraph 6.2.1, we believe 
there would have to be an absence of corrosion leaks on the pipeline 
between cathodic protection inspections. And, if the integrity of the 
pipeline has been checked between cathodic protection inspections by an 
internal inspection device, pressure testing, or direct examination, 
there would have to be no signs of metal loss due to corrosion.
    On the issue of correct application of the negative (cathodic) 0.85 
volt criterion, we find no difference between the NACE and appendix D 
criteria. Both require that voltage drops other than those across the 
structure-to-electrolyte boundary must be ``considered'' for valid 
interpretation of measurements taken for the negative (cathodic) 0.85 
volt criterion. NACE explains that consideration means the application 
of sound engineering practice in determining the significance of 
voltage drops by methods such as measuring or calculating the voltage 
drop, reviewing the historical performance of the cathodic protection 
system, evaluating the physical and electrical characteristics of the 
pipe and its environment, and determining whether or not there is 
physical evidence of corrosion.

Section 195.569  External Corrosion Control; Monitoring

    Proposed Sec. 195.569(a) is substantially the same as 
Sec. 195.416(a), which requires annual tests of the adequacy of 
cathodic protection. The only difference is that proposed 
Sec. 195.569(a) references proposed Sec. 195.567 as the measure of 
adequacy. Proposed Sec. 195.569(b) is

[[Page 76977]]

identical to Sec. 195.416(c), which requires bimonthly inspections of 
cathodic protection rectifiers. Although proposed Sec. 195.569(d) has 
no parallel in part 195, it is comparable to Sec. 192.465(c), which 
requires periodic inspections of items critical to cathodic protection. 
We think such inspections are common practice on pipelines subject to 
part 195. Proposed Sec. 195.569(e) is identical to Sec. 195.416(j), 
which requires inspections of systems used to protect the bottoms of 
aboveground breakout tanks.
    Proposed Sec. 195.569(c) is comparable to existing Sec. 195.416(d), 
which requires electrical inspection of unprotected ``bare pipe'' \6\ 
at least every 5 years to determine if protection is needed. However, 
like Sec. 192.465(e), proposed Sec. 195.569(c) would clarify that the 
purpose of the inspections is to detect ``active corrosion'' and would 
allow operators to use alternative means of determining active 
corrosion where an electrical survey is impractical. The term ``active 
corrosion'' would be defined essentially as it is in Sec. 192.457(c), 
but with the additional consideration of risk to the environment. 
Moreover, as SIRRC recommended for gas pipelines under Sec. 192.465(e) 
(see above), the alternative means of determining active corrosion 
would have to include an analysis and review of the pipeline's 
condition, based on leak repair history, exposed pipe inspection 
records, and the pipeline environment. In accordance with SIRRC's 
recommendation, we also included definitions of ``electrical survey'' 
and ``pipeline environment'' in proposed Sec. 195.569(c).
---------------------------------------------------------------------------

    \6\ The term ``bare pipe'' refers to pipe that is bare and to 
pipe that is ineffectively coated (see Sec. 195.414(a)).
---------------------------------------------------------------------------

    Another difference between proposed Secs. 195.569(c) and 195.416(d) 
is that, like Sec. 192.465(e), proposed Sec. 195.569(c) would require 
inspections of all unprotected pipelines, not just unprotected bare 
pipe. The impact of this change would be on unprotected buried piping 
in breakout tank areas and pump stations. At present, part 195 does not 
have a periodic inspection requirement for corrosion on unprotected 
piping in breakout tank areas and pump stations. \7\ Only minor costs 
should result from this change in coverage, for we believe that 
periodic inspection of unprotected piping in breakout tank areas and 
pump stations is a common industry practice. The requirements for 
initial electrical inspection of bare pipelines (Sec. 195.414 (b)) and 
of piping in breakout tank areas and pump stations (Sec. 195.414(c)) 
have not been included in proposed Subpart H because the periods 
allowed for compliance have expired.
---------------------------------------------------------------------------

    \7\ Bare pipe and piping in breakout tank areas and pump 
stations are treated separately under Sec. 194.414. So we do not 
consider unprotected piping in breakout tank areas and pump stations 
to come under the requirements of Sec. Sec. 194.416(d) concerning 
the periodic inspection of bare pipe.
---------------------------------------------------------------------------

    We have not proposed to increase the minimum frequency of 
inspections from every 5 years to every 3 years, which is the minimum 
frequency required by Sec. 192.465(e) for inspecting unprotected gas 
pipelines. Our safety data do not show that increasing the minimum 
frequency to every 3 years would be likely to result in fewer reported 
corrosion-caused accidents on hazardous liquid or carbon dioxide 
pipelines. Moreover, the ASME B31.4 Code, a set of voluntary safety 
standards widely followed by operators of pipelines subject to part 
195, specifies a minimum frequency of every 5 years for inspecting 
unprotected pipelines. While NACE Standard RP0169-96 requires periodic 
inspections to determine the need to protect unprotected pipelines, it 
does not prescribe the frequency of those inspections.
    We also considered the need to propose a standard comparable to 
Sec. 192.465(d), which requires gas pipeline operators to take 
``prompt'' remedial action to correct any deficiencies detected by 
monitoring external corrosion control. But we decided such a proposal 
is unnecessary because Sec. 195.401(b) requires operators to correct 
within a reasonable time any condition that could adversely affect safe 
operation, and if an immediate hazard exists, to cease operating the 
affected facility until the condition is corrected. Also, 
Sec. 195.401(b) regulates the timing of corrective responses to any 
unsafe corrosion control deficiency, not just deficiencies in external 
corrosion control.

Section 195.571  External Corrosion Control: Electrical Isolation

    Proposed Sec. 195.571 is comparable to Sec. 192.467, which requires 
electrical isolation on gas pipelines to provide for adequate cathodic 
protection and safeguards for insulating devices. Such isolation is 
also a common practice on pipelines subject to part 195. However, we 
are not proposing to include the requirements of Sec. 192.467(c) 
concerning isolation of pipelines from metallic casings. We agree with 
GPTC and commenters who believe the safety need to clear shorted 
casings is not apparent. Therefore, we have not included in proposed 
Subpart H SIRRC's recommended measures to remedy shorted casings.

Section 195.573  External Corrosion Control: Test Stations

    Proposed Sec. 195.573 is identical to Sec. 195.416(b), which 
requires maintenance of test leads to provide for monitoring the 
adequacy of cathodic protection.

Section 195.575  External Corrosion Control: Interference Currents

    Proposed Sec. 195.575 is comparable to Sec. 192.473, which requires 
operators to minimize the detrimental effects of interference currents 
on gas pipelines and adjacent structures. Although at present there are 
no standards in part 195 concerning interference problems, we believe 
that most operators already have a testing program to minimize 
interference problems. Proposed Sec. 195.575 has minor editorial 
differences from the wording of Sec. 192.473.

Section 195.577  Internal Corrosion Control

    Proposed Sec. 195.577 is comparable to Sec. 195.418, which requires 
protective measures to mitigate the effects of internal corrosion. 
However, proposed Sec. 195.577(d) differs somewhat from 
Sec. 195.418(d), which requires operators to investigate the extent of 
general corrosion found inside pipe that is removed from a pipeline. 
Proposed Sec. 195.577(d) would clarify the required investigation by 
adopting wording similar to that of proposed Sec. 195.565, which 
concerns the extent of external corrosion on exposed pipe. Also, under 
proposed Sec. 195.577(d), an investigation would be required if the 
removed pipe is corroded to the extent that it must be remedied under 
proposed Sec. 195.583, rather than if the pipe is generally corroded 
such that the wall thickness is less than that required by the pipe's 
specification tolerances, as Sec. 195.418(d) now requires. This change 
would allow operators to take full advantage of criteria for 
determining the strength of corroded pipe (see proposed Sec. 195.585). 
The change would also require consideration of the effect of corrosion 
pitting as well as general corrosion, consistent with the parallel 
requirement for gas pipelines in Sec. 192.475(b).
    Another difference between the proposed and existing standards is 
that proposed Sec. 195.577(d) drops the remedial measures 
Sec. 195.418(d) prescribes for corroded pipe. Remedial measures for 
corroded pipe would be governed by proposed Sec. 195.583. This change 
would improve the present rule by basing the need for remediation on 
the strength of corroded pipe and by allowing the use of qualified 
repair

[[Page 76978]]

methods that are not allowed under Sec. 195.418(d).

Section 195.579  Atmospheric Corrosion Control; General

    Proposed Sec. 195.579 is comparable to Sec. 195.416(i), which 
requires that all pipelines exposed to the atmosphere must be protected 
against atmospheric corrosion by a suitable coating. The comments 
indicate Sec. 195.416(i) may be overly burdensome, because it does not 
give operators leeway to avoid coating pipelines that have only a 
harmless light surface oxide or other mild form of corrosion that is 
unlikely to harm the pipeline before the next scheduled inspection. So 
proposed Sec. 195.579 includes an exception for these circumstances. 
The test, investigation, or experience used to justify an exception 
must be appropriate to the environment of the particular pipeline 
facility. In addition, this exception would not apply to splash zones 
of offshore pipelines or to soil-to-air interfaces of onshore 
pipelines.
    We did not adopt SIRRC's recommendation regarding comparable 
Sec. 192.479 (see above) to except all but ``active corrosion'' from 
the atmospheric corrosion protection requirement. The intent of the 
recommendation is to distinguish harmless rust from serious metal loss, 
but we believe this objective is better accomplished by more 
descriptive wording.

Section 195.581  Atmospheric Corrosion Control; Monitoring

    Proposed Sec. 195.581 is comparable to Sec. 192.481, which requires 
operators of gas pipelines to reevaluate the adequacy of atmospheric 
corrosion protection at least every 3 years on onshore pipelines and at 
least every year on offshore pipelines. Although Sec. 195.416(i) 
requires maintenance of protection on hazardous liquid and carbon 
dioxide pipelines, this standard may be too general because it lacks 
minimum inspection frequencies.
    In deciding what inspection frequency is most appropriate for 
onshore pipelines, we considered the majority of comments on 
Sec. 192.481 that favored lengthening the minimum inspection frequency 
from every 3 years to every 5 years. But we gave section 463.3 of the 
ASME B31.4 Code greater weight. This voluntary code, which is widely 
followed by operators of pipelines subject to Part 195, specifies a 
minimum 3-year inspection frequency for atmospheric corrosion 
protection onshore. We also considered that GPTC, in its recommendation 
regarding Sec. 192.481, did not suggest extending the minimum 3-year 
frequency more than a marginal amount to provide flexibility. Also, two 
commenters said the present 3-year frequency is not too burdensome. 
There were no comments on the frequency of inspection offshore, and the 
ASME B31.4 Code does not specify a minimum frequency.
    Proposed Sec. 195.581 would require periodic ``inspection'' rather 
than ``reevaluation'' to avoid the possibility that decisions about the 
adequacy of protection might not be based on current observations. The 
proposed rule also recognizes the importance of paying special 
attention during inspections to particular pipeline areas that have 
historically been sources of corrosion problems, such as splash zones 
and pipe surfaces underneath thermal insulation. We feel that most 
operators already inspect aboveground pipelines for corrosion at the 
proposed frequencies and give careful attention to potential problem 
areas.

Section 195.583  Remedial Measures; General

    Proposed Sec. 195.583(a) is comparable to Sec. 195.416 (f), which 
regulates the repair of pipe that has general corrosion. \8\ But 
proposed Sec. 195.583(a) reflects the wording of Sec. 192.485(a), a 
repair rule similar to Sec. 195.416(f) that bases the need for 
corrective action on whether the remaining wall thickness supports the 
maximum allowable operating pressure. At present, Sec. 195.416 (f) 
bases the need for corrective action on whether the remaining wall 
thickness is within the pipe specification tolerances. The revised 
wording would allow operators to take full advantage of criteria for 
determining the strength of corroded pipe (see proposed Sec. 195.585). 
Proposed Sec. 195.583(b) is identical to Sec. 195.416(g), which 
regulates remedial measures for localized corrosion pitting.
---------------------------------------------------------------------------

    \8\ Section 195.416(f) was revised by Amendment 195-68 (64 FR 
69660; Decemeber 14, 1999).
---------------------------------------------------------------------------

Section 195.585  Remedial Measures; Remaining Strength

    Proposed Sec. 195.585 is substantially the same as Sec. 195.416(h), 
which authorizes the use of widely accepted criteria for determining 
the remaining strength of corroded pipe.

Section 195.587  Records

    For hazardous liquid and carbon dioxide pipelines, requirements to 
keep records related to corrosion control are in Sec. 195.404. Under 
Sec. 195.404(a), operators must maintain current maps and records that 
identify and show the location of facilities that are cathodically 
protected. In addition, Sec. 195.404(c)(3) requires operators to keep 
records of required inspections and tests for at least 2 years or until 
the next inspection or test, whichever is longer.
    We are proposing to adopt new recordkeeping requirements for 
hazardous liquid and carbon dioxide pipelines comparable to those for 
gas pipelines in Sec. 192.491. Under proposed Sec. 195.587(a), 
operators would have to keep current records or maps of the location of 
cathodically protected piping (as they must now under Sec. 195.404(a)), 
of cathodic protection facilities, and of bonded structures. Also, 
under proposed Sec. 195.587(b), operators would have to keep a record 
of each analysis, check, demonstration, examination, inspection, 
investigation, review, survey, and test required by proposed Subpart H 
in sufficient detail to demonstrate the adequacy of corrosion control 
measures or that corrosion requiring control measures does not exist. 
Records required by Sec. 195.587(b) would have to be retained for at 
least 5 years, except that records related to determining the adequacy 
of, or need for, external or internal corrosion control (records 
related to proposed Secs. 195.565, 195.569(a) and (c), and 195.577(c) 
and (d)) would have to be kept as long as the pipeline is in service.
    The majority of comments on the appropriate period to keep records 
related to determining if external or internal corrosion control is 
adequate or needed did not support keeping these records for as long as 
the pipeline remains in service. Instead they mostly suggested a 
retention period of 5 years or the next one or two monitoring cycles, 
whichever is longer. But we agree with the single commenter who said 
keeping such records for the service life of the pipeline provides a 
very helpful general history. In our experience, a history of corrosion 
control monitoring is very useful in assessing the condition of a 
pipeline. If corrosion problems emerge on a pipeline, its monitoring 
history is considered in deciding the extent and kind of remedial 
action needed.
    As for other records under proposed Sec. 195.587(b) (e.g., records 
of rectifier inspections under proposed Sec. 195.569(b)), we believe 
the retention period must be compatible with the normal cycle of 
routine compliance investigations by government inspection personnel 
and long enough to provide meaningful history for investigation of an 
accident or safety problem. A minimum 5-year retention requirement 
would assure that the records are available during routine inspection

[[Page 76979]]

visits, and provide a more complete history for analyzing problems.
    Proposed Sec. 195.587(a)(2), which is based on Sec. 192.491(a), 
would require operators to have current records or maps identifying the 
location of cathodic protection facilities, galvanic anodes, and 
structures bonded to cathodic protection systems. Such records are not 
now required by Part 195, and although operators may have them, to 
minimize the recordkeeping burden, the records would only be required 
for installations made after the final rule goes into effect.
    The record retention times proposed by Sec. 195.587(b) would only 
apply to records of actions that occur after Subpart H takes effect. 
The retention times now required by Sec. 195.404(c)(3) would continue 
to apply to records of corrosion tests and inspections done before 
Subpart H takes effect.

Regulatory Analyses and Notices

Executive Order 12866 and DOT Policies and Procedures

    RSPA does not consider this proposed rulemaking to be a significant 
regulatory action under Section 3(f) of Executive Order 12866 (58 FR 
51735; Oct. 4, 1993). Therefore, the Office of Management and Budget 
(OMB) has not received a copy of this rulemaking to review. RSPA also 
does not consider this proposed rulemaking to be significant under DOT 
regulatory policies and procedures (44 FR 11034: February 26, 1979).
    We prepared a Draft Regulatory Evaluation of the proposed rules and 
a copy is in the docket. The evaluation states that the proposed rules 
are, on the whole, comparable either to existing safety standards 
currently in part 195 for hazardous liquid pipelines or to existing 
safety standards in part 192 for gas pipelines. The evaluation also 
states that the information presented at public meetings and meetings 
with industry and state representatives strongly suggests that imposing 
gas pipeline safety standards for corrosion control on hazardous liquid 
pipelines would not require a significant departure from customary 
safety practices on liquid pipelines.
    An important feature of the proposed rules not found in part 192 or 
part 195 is the reference to cathodic protection criteria in NACE 
Standard RP0169-96. The evaluation states that these criteria are well 
known and widely followed throughout the industry, as indicated by 
meetings with industry representatives and by the voluntary standards 
in the ASME B31.4 Code. The evaluation further states that operators 
who do not now apply the NACE criteria are likely to apply the criteria 
in appendix D of part 192. The proposed rules would allow use of 
appendix D criteria under conditions stated in the NACE standard.
    The evaluation concludes there should be only minimal additional 
cost, if any, for operators to comply with the proposed rules. If you 
disagree with this conclusion, please provide information to the public 
docket described above.

Regulatory Flexibility Act

    The proposed rules are consistent with customary practices for 
corrosion control in the hazardous liquid and carbon dioxide pipeline 
industry. Therefore, based on the facts available about the anticipated 
impacts of this proposed rulemaking, I certify, pursuant to section 605 
of the Regulatory Flexibility Act (5 U.S.C. 605), that this proposed 
rulemaking would not have a significant impact on a substantial number 
of small entities. If you have any information that this conclusion 
about the impact on small entities is not correct, please provide that 
information to the public docket described above.

Executive Order 13084

    The proposed rules have been analyzed in accordance with the 
principles and criteria contained in Executive Order 13084, 
``Consultation and Coordination with Indian Tribal Governments.'' 
Because the proposed rules would not significantly or uniquely affect 
the communities of the Indian tribal governments and would not impose 
substantial direct compliance costs, the funding and consultation 
requirements of Executive Order 13084 do not apply.

Paperwork Reduction Act

    Section 195.587 proposes minor additional information collection 
requirements. Operators would be required to record the location of 
certain newly installed protection facilities, and keep the records for 
as long as the pipeline concerned is in service. In addition, records 
of inspections, tests, and surveys would have to be kept for as long as 
the pipeline is in service or for 5 years, depending on the nature of 
the information recorded. The present minimum retention period for 
these records is 2 years or the prescribed interval of test or 
inspection, whichever is longer (up to 5 years in some cases).
    However, we believe operators already maintain records of the 
location of their protection facilities for as long as the pipeline is 
in service to be able to find the facilities for their own purposes and 
to carry out existing monitoring requirements in part 195. Also, we 
believe the burden of retaining inspection, test, and survey records 
for the longer period proposed would be minimal. These records are 
largely computerized. Maintaining these records on a floppy disk or 
computer file represents very minimal costs. So, because the additional 
paperwork burdens of this proposed rule are likely to be minimal, we 
believe that submitting an analysis of the burdens to OMB under the 
Paperwork Reduction Act is unnecessary. If you disagree with this 
conclusion, please submit your comments to the public docket.

Unfunded Mandates Reform Act of 1995

    This proposed rulemaking would not impose unfunded mandates under 
the Unfunded Mandates Reform Act of 1995. It would not result in costs 
of $100 million or more to either State, local, or tribal governments, 
in the aggregate, or to the private sector, and would be the least 
burdensome alternative that achieves the objective of the rule.

National Environmental Policy Act

    We have analyzed the proposed rules for purposes of the National 
Environmental Policy Act (42 U.S.C. 4321 et seq.). Because the proposed 
rules parallel present requirements or practices, we have preliminarily 
determined that the proposed rules would not significantly affect the 
quality of the human environment. An environmental assessment document 
is available for review in the docket. A final determination on 
environmental impact will be made after the end of the comment period. 
If you disagree with our preliminary conclusion, please submit your 
comments to the docket as described above.

Impact on Business Processes and Computer Systems

    We do not want to impose new requirements that would mandate 
business process changes when the resources necessary to implement 
those requirements would otherwise be applied to ``Y2K'' or related 
computer problems. The proposed rules would not mandate business 
process changes or require modifications to computer systems. Because 
the proposed rules would not affect the ability of organizations to 
respond to those problems, we are not proposing to delay the 
effectiveness of the requirements.

Executive Order 13132

    The proposed rules have been analyzed in accordance with the 
principles and criteria contained in Executive Order 13132 
(``Federalism'').

[[Page 76980]]

The proposed rules do not propose any regulation that (1) has 
substantial direct effects on the States, the relationship between the 
national government and the States, or the distribution of power and 
responsibilities among the various levels of government; (2) imposes 
substantial direct compliance costs on State and local governments; or 
(3) preempts state law. Therefore, the consultation and funding 
requirements of Executive Order 13132 do not apply. Nevertheless, 
during our review of the existing corrosion control standards, 
representatives of state pipeline safety agencies gave us advice both 
in private sessions and in the two public meetings we held. In 
addition, our pipeline safety advisory committees, which include 
representatives of state governments, were, on two occasions in 1999, 
briefed on the corrosion control review project.

List of Subjects in 49 CFR Part 195

    Ammonia, Carbon dioxide, Petroleum, Pipeline safety, Reporting and 
recordkeeping requirements.

    In consideration of the foregoing, we propose to amend 49 CFR part 
195 as follows:

PART 195--[AMENDED]

    1. The authority citation for part 195 continues to read as 
follows:

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

    2. Section 195.3 would be amended by adding paragraphs (b)(8) and 
(c)(7) to read as follows:


Sec. 195.3  Matter incorporated by reference.

* * * * *
    (b) * * *
    (8) NACE International, 1440 South Creek Drive, Houston, TX 77084.
    (c) * * *
    (7) NACE International (NACE):
    (i) NACE Standard RP0169-96, ``Control of External Corrosion on 
Underground or Submerged Metallic Pipeline Systems'' (1996).
    (ii) [Reserved]
    3. Section 195.5(b) would be revised to read as follows:


Sec. 195.5  Conversion to service subject to this part.

* * * * *
    (b) A pipeline which qualifies for use under this section need not 
comply with the corrosion control requirements of subpart H of this 
part until 12 months after it is placed in service, notwithstanding any 
earlier deadlines for compliance. The requirements of Secs. 195.557, 
195.559, and 195.561 apply to each pipeline which substantially meets 
those requirements before it is placed in service or which is a segment 
that is replaced, relocated, or substantially altered.
* * * * *
    4. Section 195.402(c)(3) would be revised to read as follows:


Sec. 195.402  Procedural manual for operations, maintenance, and 
emergencies.

* * * * *
    (c) * * *
    (3) Operating, maintaining, and repairing the pipeline system in 
accordance with each of the requirements of this subpart and subpart H 
of this part.
* * * * *


Sec. 195.404  [Amended]

    5. In Sec. 195.404, paragraph (a)(1)(v) would be removed, and 
paragraphs (a)(1)(vi) through (a)(1)(viii) would be redesignated as 
paragraphs (a)(1)(v) through (a)(1)(vii).


Secs. 195.236, 195.238, 195.242, 195.244, 195.414, 195.416, 
195.418  [Removed]

    6. The following sections would be removed and reserved: 
Secs. 195.236, 195.238, 195.242, 195.244, 195.414, 195.416, and 
195.418.
    7. Subpart H would be added to read as follows:

Subpart H--Corrosion Control

Sec.
195.551   Scope.
195.553   Qualification of supervisors.
195.555   External corrosion control; Applicability.
195.557   External corrosion control; Protective coating.
195.559   External corrosion control; Cathodic protection system.
195.561   External corrosion control; Test leads.
195.563   External corrosion control; Additional cathodic protection 
requirements.
195.565   External corrosion control; Examination of a buried 
pipeline when exposed.
195.567   External corrosion control; Cathodic protection criteria.
195.569   External corrosion control; Monitoring.
195.571   External corrosion control; Electrical isolation.
195.573   External corrosion control; Test stations.
195.575   External corrosion control; Interference currents.
195.577   Internal corrosion control.
195.579   Atmospheric corrosion control; General.
195.581   Atmospheric corrosion control; Monitoring.
195.583   Remedial measures; General.
195.585   Remedial Measures; Remaining strength.
195.587  Records.
Subpart H--Corrosion Control


Sec. 195.551  Scope.

    This subpart prescribes minimum requirements for protecting steel 
pipelines against corrosion.


Sec. 195.553  Qualification of supervisors.

    Each operator must require and verify that its supervisors maintain 
a thorough knowledge of that portion of the corrosion control 
procedures established under Sec. 195.402 for which they are 
responsible for insuring compliance.


Sec. 195.555  External corrosion control; Applicability.

    The requirements of Secs. 195.557, 195.559, and 195.561 apply only 
to--
    (a) Pipelines constructed, relocated, replaced, or otherwise 
changed after the applicable date in Sec. 195.401(c); and
    (b) Converted pipelines, if required by Sec. 195.5(b).


Sec. 195.557  External corrosion control; Protective coating.

    (a)(1) No component of a pipeline may be buried or submerged unless 
that component has an external protective coating that--
    (i) Is designed to mitigate corrosion of the buried or submerged 
component;
    (ii) Has sufficient adhesion to the metal surface to prevent under 
film migration of moisture;
    (iii) Is sufficiently ductile to resist cracking;
    (iv) Has enough strength to resist damage due to handling and soil 
stress; and
    (v) Supports any supplemental cathodic protection.
    (2) In addition, if any insulating-type coating is used, it must 
have low moisture absorption and provide high electrical resistance.
    (b) All pipe coating must be inspected just prior to lowering the 
pipe into the ditch or submerging the pipe, and any damage discovered 
must be repaired.


Sec. 195.559  External corrosion control; Cathodic protection system.

    (a) A cathodic protection system must be installed for all buried 
or submerged facilities to mitigate corrosion that might result in 
structural failure. A test procedure must be developed to determine 
whether adequate cathodic protection has been achieved.
    (b) A cathodic protection system must be installed not later than 1 
year after completing the construction.
    (c) For the bottoms of aboveground breakout tanks with greater than 
500 barrels (79.5 m\3\) capacity built to API Specification 12F, API 
Standard 620, or API Standard 650 (or its predecessor

[[Page 76981]]

Standard 12C), the installation of a cathodic protection system under 
paragraph (a) of this section after October 2, 2000, must be in 
accordance with API Recommended Practice 651, unless the operator notes 
in the procedural manual (Sec. 195.402(c)) why compliance with all or 
certain provisions of API Recommended Practice 651 is not necessary for 
the safety of a particular breakout tank.
    (d) For the internal bottom of aboveground breakout tanks built to 
API Specification 12F, API Standard 620, or API Standard 650 (or its 
predecessor Standard 12C), the installation of a tank bottom lining 
after October 2, 2000, must be in accordance with API Recommended 
Practice 652, unless the operator notes in the procedural manual 
(Sec. 195.402(c)) why compliance with all or certain provisions of API 
Recommended Practice 652 is not necessary for the safety of a 
particular breakout tank.


Sec. 195.561  External corrosion control; Test leads.

    (a) Except for offshore pipelines, electrical test leads used for 
corrosion control or electrolysis testing must be installed at 
intervals frequent enough to obtain electrical measurements indicating 
the adequacy of the cathodic protection.
    (b) Test leads must be installed as follows:
    (1) Enough looping or slack must be provided to prevent test leads 
from being unduly stressed or broken during backfilling.
    (2) Each lead must be attached to the pipe so as to prevent stress 
concentration on the pipe.
    (3) Each lead installed in a conduit must be suitably insulated 
from the conduit.
    (4) Each bared test lead wire and bared metallic area at point of 
connection to the pipeline must be coated with an electrical insulating 
material compatible with the pipe coating and the insulation on the 
wire.


Sec. 195.563  External corrosion control; Additional cathodic 
protection requirements.

    (a) Each pipeline not subject to Sec. 195.559 that has an effective 
external surface coating material must be cathodically protected. This 
requirement does not apply to breakout tank areas and buried pumping 
station piping.
    (b) For the purposes of this subpart, a pipeline does not have an 
effective external coating and shall be considered bare if the current 
required to cathodically protect it is substantially the same as if it 
were bare.


Sec. 195.565  External corrosion control; Examination of a buried 
pipeline when exposed.

    Whenever an operator has knowledge that any portion of a buried 
pipeline is exposed, the exposed portion must be examined for evidence 
of external corrosion, if the pipe is bare or if the coating is 
deteriorated. If external corrosion requiring remedial action under 
Sec. 195.583 is found, the operator must investigate circumferentially 
and longitudinally beyond the exposed portion (by visual examination, 
indirect method, or both) to determine whether additional corrosion 
requiring remedial action exists in the vicinity of the exposed 
portion.


Sec. 195.567  External corrosion control; Cathodic protection criteria.

    Cathodic protection required by this subpart must comply with one 
or more of the applicable criteria and other considerations for 
cathodic protection contained in section 6 of NACE Standard RP0169-96.


Sec. 195.569  External corrosion control; Monitoring.

    (a) Each operator must, at intervals not exceeding 15 months, but 
at least once each calendar year, conduct tests on each buried, in 
contact with the ground, or submerged pipeline facility in its pipeline 
system that is under cathodic protection to determine whether the 
protection is adequate under Sec. 195.567.
    (b) Each operator must, at intervals not exceeding 2\1/2\ months, 
but at least six times each calendar year, inspect each of its cathodic 
protection rectifiers.
    (c) Each operator must, at intervals not exceeding 5 years, 
reevaluate its unprotected pipelines and cathodically protect them in 
accordance with this subpart in areas in which active corrosion is 
found. The operator must determine the areas of active corrosion by 
electrical survey, or where an electrical survey is impractical, by 
other means that include review and analysis of leak repair and 
inspection records, corrosion monitoring records, exposed pipe 
inspection records, and the pipeline environment. In this section:
    (1) Active corrosion means continuing corrosion which, unless 
controlled, could result in a condition that is detrimental to public 
safety or the environment.
    (2) Electrical survey means a series of closely spaced pipe-to-soil 
readings over a pipeline that are subsequently analyzed to identify 
locations where a corrosive current is leaving the pipeline.
    (3) Pipeline environment includes soil resistivity (high or low), 
soil moisture (wet or dry), soil contaminants that may promote 
corrosive activity, and other known conditions that could affect the 
probability of active corrosion.
    (d) Each reverse current switch, each diode, and each interference 
bond whose failure would jeopardize structural protection must be 
electrically checked for proper performance six times each calendar 
year, but with intervals not exceeding 2\1/2\ months. Each other 
interference bond must be checked at least once each calendar year, but 
with intervals not exceeding 15 months.
    (e) For aboveground breakout tanks where corrosion of the tank 
bottom is controlled by a cathodic protection system, the cathodic 
protection system must be inspected to ensure it is operated and 
maintained in accordance with API Recommended Practice 651, unless the 
operator notes in the procedure manual (Sec. 195.402(c)) why compliance 
with all or certain provisions of API Recommended Practice 651 is not 
necessary for the safety of a particular breakout tank.


Sec. 195.571  External corrosion control; Electrical isolation.

    (a) Each buried or submerged pipeline must be electrically isolated 
from other metallic structures, unless the pipeline and the other 
structures are electrically interconnected and cathodically protected 
as a single unit.
    (b) One or more insulating devices must be installed where 
electrical isolation of a portion of a pipeline is necessary to 
facilitate the application of corrosion control.
    (c) Inspection and electrical tests must be made to assure that 
electrical isolation is adequate.
    (d) An insulating device may not be installed in an area where a 
combustible atmosphere is anticipated unless precautions are taken to 
prevent arcing.
    (e) Where a pipeline is located in close proximity to electrical 
transmission tower footings, ground cables or counterpoise, or in other 
areas where fault currents or unusual risk of lightning may be 
anticipated, it must be provided with protection against damage due to 
fault currents or lightning, and protective measures must also be taken 
at insulating devices.


Sec. 195.573  External corrosion control; Test stations.

    Each operator must maintain the test leads required for cathodic 
protection in such a condition that electrical measurements can be 
obtained to ensure adequate protection.

[[Page 76982]]

Sec. 195.575  External corrosion control; Interference currents.

    (a) Each operator whose pipeline system is subjected to stray 
currents must have a program to identify, test for, and minimize the 
detrimental effects of such currents.
    (b) Each impressed current or galvanic anode system must be 
designed and installed to minimize any adverse effects on existing 
adjacent metallic structures.


Sec. 195.577  Internal corrosion control.

    (a) No operator may transport any hazardous liquid or carbon 
dioxide that would corrode the pipe or other components of its pipeline 
system, unless it has investigated the corrosive effect of the 
hazardous liquid or carbon dioxide on the system and has taken adequate 
steps to mitigate corrosion.
    (b) If corrosion inhibitors are used to mitigate internal corrosion 
the operator must use inhibitors in sufficient quantity to protect the 
entire part of the system that the inhibitors are designed to protect 
and shall also use coupons or other monitoring equipment to determine 
their effectiveness.
    (c) The operator must, at intervals not exceeding 7\1/2\ months, 
but at least twice each calendar year, examine coupons or other types 
of monitoring equipment to determine the effectiveness of the 
inhibitors or the extent of any corrosion.
    (d) Whenever pipe is removed from a pipeline, the operator must 
inspect the internal surface of the pipe for evidence of corrosion. If 
internal corrosion requiring remedial action under Sec. 195.583 is 
found, the operator shall investigate circumferentially and 
longitudinally beyond the removed pipe (by visual examination, indirect 
method, or both) to determine whether additional corrosion requiring 
remedial action exists in the vicinity of the removed pipe.


Sec. 195.579  Atmospheric corrosion control; General.

    Each pipeline or portion of pipeline that is exposed to the 
atmosphere must be cleaned and coated with a material suitable for the 
prevention of atmospheric corrosion. However, except for portions of 
pipelines in offshore splash zones and soil-to-air interfaces, 
protection against atmospheric corrosion is not required if the 
operator demonstrates by test, investigation, or experience that 
corrosion will be limited to a light surface oxide or else will not 
affect the safe operation of the pipeline before the next scheduled 
inspection.


Sec. 195.581  Atmospheric corrosion control; Monitoring.

    (a) Each operator must, at intervals not exceeding 3 years for 
onshore pipelines or 15 months, but at least once each calendar year, 
for offshore pipelines, inspect each pipeline or portion of pipeline 
that is exposed to the atmosphere for evidence of atmospheric 
corrosion. Particular attention must be given to pipe at soil-to-air 
interfaces, under thermal insulation, under disbonded coatings, at pipe 
supports, in splash zones, at deck penetrations, and in spans over 
water.
    (b) If atmospheric corrosion is found, the operator must provide 
protection against atmospheric corrosion as required by Sec. 195.579.


Sec. 195.583  Remedial measures; General.

    (a) Any pipe that is found to be generally corroded so that the 
remaining wall thickness is less than that required for the maximum 
operating pressure of the pipeline must be replaced. However, generally 
corroded pipe need not be replaced if--
    (1) The operating pressure is reduced to be commensurate with the 
strength of the pipe, based on the actual remaining wall thickness; or
    (2) The pipe is repaired by a method that reliable engineering 
tests and analyses show can permanently restore the serviceability of 
the pipe.
    (b) If localized corrosion pitting is found to exist to a degree 
where leakage might result, the pipe must be replaced or repaired, or 
the operating pressure must be reduced commensurate with the strength 
of the pipe based on the actual remaining wall thickness in the pits.


Sec. 195.585  Remedial Measures; Remaining strength.

    Under Sec. 195.583, the strength of the pipe based on actual 
remaining wall thickness may be determined by the procedure in ASME 
B31G Manual for Determining the Remaining Strength of Corroded 
Pipelines or by the procedure developed by AGA/Battelle--A Modified 
Criterion for Evaluating the Remaining Strength of Corroded Pipe (with 
RSTRENG disk). Application of the procedure in the ASME B31G manual or 
the AGA/Battelle Modified Criterion is applicable to corroded regions 
(not penetrating the pipe wall) in existing steel pipelines in 
accordance with limitations set out in the respective procedures.


Sec. 195.587  Records.

    (a) Each operator must maintain current records or maps to show the 
location of--
    (1) Cathodically protected pipelines;
    (2) Cathodic protection facilities and galvanic anodes installed 
after [effective date of final rule]; and
    (3) Neighboring structures bonded to cathodic protection systems. 
Records or maps showing a stated number of anodes, installed in a 
stated manner or spacing, need not show specific distances to each 
buried anode.
    (b) Each operator must maintain a record of each analysis, check, 
demonstration, examination, inspection, investigation, review, survey, 
and test required by this subpart in sufficient detail to demonstrate 
the adequacy of corrosion control measures or that corrosion requiring 
control measures does not exist. These records must be retained for at 
least 5 years, except that records related to Secs. 195.565, 195.569(a) 
and (c), and 195.577(c) and (d) must be retained for as long as the 
pipeline remains in service.

    Issued in Washington, DC on December 1, 2000.
Stacey L. Gerard,
Associate Administrator for Pipeline Safety.
[FR Doc. 00-31224 Filed 12-7-00; 8:45 am]
BILLING CODE 4910-60-P