[Federal Register Volume 63, Number 213 (Wednesday, November 4, 1998)]
[Rules and Regulations]
[Pages 59475-59482]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 98-29242]


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DEPARTMENT OF TRANSPORTATION

Research and Special Programs Administration

49 CFR Part 195

[Docket No. PS-144; Amdt. 195-65]
RIN 2137-AC 78


Risk-Based Alternative to Pressure Testing Older Hazardous Liquid 
and Carbon Dioxide Pipelines Rule

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

ACTION: Final rule.

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SUMMARY: This final rule allows operators of older hazardous liquid and 
carbon dioxide pipelines to elect a risk-based alternative in lieu of 
the existing rule. The existing rule requires the hydrostatic pressure 
testing of certain older pipelines. The risk-based alternative would 
allow operators to elect an approach to evaluating the integrity of 
these lines that takes into account individual risk factors. This would 
allow operators to focus resources on higher risk pipelines and effect 
a greater reduction in the overall risk from pipeline accidents.

DATE: This final rule takes effect November 4, 1998.

FOR FURTHER INFORMATION CONTACT: Mike Israni, (202) 366-4571, or e-
mail: [email protected], regarding the subject matter of this 
final rule, or Dockets Unit (202) 366-4046, for copies of this final 
rule document or other material in the docket.

SUPPLEMENTARY INFORMATION:

Background

    On June 7, 1994, RSPA published a final rule, ``Pressure Testing 
Older Hazardous Liquid and Carbon Dioxide Pipelines,'' (Amdt. 195-51; 
59 FR 29379) to ensure that certain older pipelines have an adequate 
safety margin between their maximum operating pressure and test 
pressure. This safety margin is to be provided by pressure testing 
according to part 195 standards or operation at 80 percent or less of a 
qualified prior test or operating pressure. The pipelines covered by 
the rule are steel interstate pipelines constructed before January 8, 
1971, steel interstate offshore gathering lines constructed before 
August 1, 1977, or steel intrastate pipelines constructed before 
October 21, 1985, that transport hazardous liquids subject to part 195. 
Also covered are steel carbon dioxide pipelines constructed before July 
12, 1991, subject to part 195.
    On June 23, 1995, the American Petroleum Institute (API) filed a 
petition on behalf of many liquid pipeline operators that proposed a 
risk-based alternative to the required pressure testing rule. API 
indicated that its proposal would allow operators to focus resources on 
higher risk pipelines and to effect a greater reduction in the overall 
risk from pipeline accidents.
    In order to determine whether the API proposal had merit, RSPA held 
a public meeting on March 25, 1996. On May 8 and November 7, 1996, and 
on May 17, 1997, RSPA briefed the Technical Hazardous Liquid Pipeline 
Safety

[[Page 59476]]

Standards Committee (THLPSSC) on the API proposal and steps taken by 
RSPA to develop a proposed rule. As discussed in more detail below, 
RSPA finds considerable merit in a risk-based approach to pressure 
testing of older hazardous liquid pipelines. It provides accelerated 
testing of electric resistance welded (ERW) pipe, incorporates the use 
of new technology, and provides for continuing internal inspection of 
older pipelines through a pigging program. RSPA has been working 
actively with the pipeline industry to develop a risk management 
framework for pipeline regulations. The API proposal is consistent with 
the risk assessment and management approach to safety. The API proposal 
provides an opportunity to pilot a risk-based approach in a rulemaking 
forum. Accordingly, this final rule requires a risk-based alternative 
to the pressure testing rule that has been modeled after the API 
proposal.
    RSPA has extended time for compliance with the pressure testing 
rule in order to allow completion of this final rule on a risk-based 
alternative. The deadline for complying with Sec. 195.302(c)(1) is 
extended to December 7, 1998. The deadline for complying with 
Sec. 195.302(c)(2)(i) is extended to December 7, 2000. The deadline for 
complying with Sec. 195.302(c)(2)(ii) is extended to December 7, 2003. 
(62 FR 54591; October 21, 1997).

Major Features of Risk-Based Alternative

    The risk-based alternative to the rule requiring the pressure 
testing of older pipelines has six main features:

1. Highest Priority Is Given to the Highest Risk Facilities; Lowest 
Risk Facilities Are Excepted From Additional Measures

    Pre-1970 electric resistance welded (ERW) and lapwelded pipelines 
susceptible to longitudinal seam failures exhibit the highest potential 
risk because of their combination of probability of failure and 
potential for larger volume releases as evidenced by historical 
records. Pressure testing is the only available technology for 
verifying the integrity of pre-1970 ERW and lapwelded pipelines, 
because it can detect the type of seam failures endemic to some ERW and 
all lapwelded pipe. This risk-based alternative requires accelerated 
testing of pre-1970 ERW and lapwelded pipe susceptible to longitudinal 
seam failure in certain locations (risk classification C and B) where 
people and environment might be significantly affected. However, in 
locations (risk classification A) where consequences to the public or 
environment are less significant, the risk-based alternative allows 
delayed testing for pre-1970 ERW and lapwelded pipe susceptible to 
longitudinal failure and allows the operator to determine the need for 
pressure testing of other types of pipe.

2. Consequence Factors Such as Location (Population and Environment), 
Product Type, and Release Potential Are Taken Into Consideration When 
Setting Testing Priorities

    This risk-based alternative takes into account the most significant 
variables that may impact the severity of a release, i.e., location 
with respect to populated and environmentally sensitive \1\ areas, the 
nature of the product transported, and the potential volume of product 
release. Historically, a very small percentage of releases adversely 
impacted public safety and environment. By taking these potential 
consequences into consideration in the timing of tests, an operator's 
resources will be more effectively applied to reduce risks.
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    \1\ ``Environmentally sensitive areas'' is not currently 
defined, but operators are encouraged to use their best judgment in 
applying this factor. This factor may be defined in future 
rulemaking.
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3. Best Available Technology Is Applied To Verify Pipeline Integrity

    The risk-based alternative encourages the use of the most effective 
means to ensure pipeline integrity. This rule utilizes the strength of 
two primary technologies--pressure testing and magnetic flux leakage/
ultrasonic internal inspection devices. Each technology provides 
testing advantages in particular circumstances. This rule allows the 
operator to evaluate the pipeline risk considerations and to choose the 
most appropriate technology.

4. Timing of Tests Is Based on Risk

    Considering the probability and consequence factors, the risk-based 
rule increases the priority of a limited amount of pre-1970 ERW and all 
lapwelded pipelines and maintains the three-year timing for risk 
classification B and C lines which represent the highest risk to people 
and environment. Pipelines with lower risks (risk classification A) are 
allowed a longer testing schedule or are eliminated (non-high risk pre-
1970 ERW pipelines) from a mandatory testing requirement. Nothing in 
this rule precludes an operator from accelerating these schedules based 
on their pipeline operating and maintenance history.

5. Reduces Test Water Requirements

    This rule would allow operators options that require less test 
water and generate less water requiring treatment.

6. Provides an Opportunity To Reduce Operating Costs and Maintain the 
Necessary Margins of Safety by Applying the Risk-Based Concept

    Acceptance and implementation of this rule provides an opportunity 
to pilot a risk-based approach to regulation. OPS anticipates increased 
use of risk-based approaches in future rulemakings.

Proposed Rule

    RSPA published an NPRM (63 FR 5918; February 5, 1998), proposing to 
add a new section to Part 195 entitled ``Risk-based alternative to 
pressure testing.'' NPRM also proposed that existing Sec. 195.303 
``Test pressure'', and Sec. 195.304 ``Testing of components'' would be 
renumbered as Sec. 195.304 and Sec. 195.305 respectively. The comment 
period closed April 6, 1998. Commenters included an industry 
association, two pipeline operating companies and a safety consultant.

Advisory Committee Review

    On May 6, 1998, RSPA submitted the proposed rule and regulatory 
evaluation to the Technical Hazardous Liquid Pipeline Safety Standards 
Committee (THLPSSC). Each proposed hazardous liquid pipeline safety 
standard must be submitted to the THLPSSC for Committee's view as to 
its technical feasibility, reasonableness, cost-effectiveness, and 
practicability. At the meeting, the THLPSSC declined to approve the 
proposed rule and unanimously requested that ``environmentally 
sensitive areas'' be included within the consequence factors for 
setting testing priorities. Some members argued that not including an 
environmental factor at this time would result in many segments of 
pipeline remaining untested for many more years. The Committee asked 
that the proposed rule be resubmitted for consideration through a mail 
ballot. On May 12, 1998, RSPA sent letter ballots to THLPSSC members to 
vote on revised language to be included in the final rule. RSPA 
received 10 of 12 ballots. All 10 members voted to approve the proposed 
rule provided the revised language was included. The THLPSSC also 
recommended discussion in the preamble to the final rule of the need to 
include consideration of environmentally sensitive areas even before a 
clear definition of the term is developed.

[[Page 59477]]

    RSPA did not include an environmental factor in the proposed rule 
because of the lack of agreement on a definition. Following public 
briefings on the progress of the rulemaking at the THLPSSC meetings in 
November 1996 and May 1997, API objected to inclusion of an 
environmental factor as premature in light of the ongoing rulemaking to 
define unusually sensitive areas (USAs). At that time, RSPA intended to 
include an interim definition that could later be replaced, if 
appropriate, by the definition of USAs.
    Although we do not necessarily agree that a definition of USAs 
should be the sole basis for inclusion of an environmental factor for a 
risk-based alternative to pressure testing, we recognized in the 
proposed rule the difficulties of defining an environmental factor 
before the USA definition is formulated. The difficulty in articulating 
a factor was made very apparent by THLPSSC members at the May 1997 
meeting. One member argued that the environmental factor under 
consideration for the proposed rule was inadequate; two other members 
challenged that argument. Discussions with the members and API 
following that meeting indicated little chance of agreement on a 
definition prior to definition of USAs. Based on the discussion at the 
THLPSSC on May 6, 1998, it appears that there is broad agreement that 
environmentally sensitive areas will be considered by the industry even 
in the absence of a definition. Accordingly, we are following the 
advice of the THLPSSC and including environmentally sensitive areas 
within the consequence factors in this final rule. We recognize that we 
may need to revisit this issue once we have defined ``unusually 
sensitive areas.''

The Final Rule

    The new Sec. 195.303 ``Risk-based alternative to pressure testing'' 
would allow an operator of older hazardous liquid and carbon dioxide 
pipeline to elect an approach to evaluating the integrity of lines that 
takes into account individual risk factors. This alternative 
establishes test priorities based on the inherent risk of a given 
pipeline segment. Each pipeline is assigned a risk classification based 
on several indicators. In assigning a risk classification to a given 
pipeline segment, the first step is to determine whether or not the 
segment contains pre-1970 ERW and lap-weld pipe susceptible to 
longitudinal seam failures. Certain pre-1970 ERW and lap-weld pipeline 
segments are susceptible to longitudinal seam failures. An operator 
must consider the seam-related leak history of the pipe and pipe 
manufacturing information as available, which may include the pipe 
steel's mechanical properties, including fracture toughness; the 
manufacturing process and controls related to seam properties, 
including whether the ERW process was high-frequency or low-frequency, 
whether the weld seam was heat treated, whether the seam was inspected, 
the test pressure and duration during mill hydrotest; the quality 
control of the steel-making process; and other factors pertinent to 
seam properties and quality.
    The next step is to determine the pipeline segment's proximity to 
populated and environmentally sensitive areas (Location). 
``Environmentally sensitive areas'' is not currently defined. However, 
we expect operators to use their best judgment in applying this factor. 
Some good examples of areas which would be environmentally sensitive 
are waters used for drinking and fishing. This environmental factor may 
be defined in a future rulemaking.
    The risk classification of a segment is also adjusted based on the 
pipeline failure history, the product transported, and the volume 
potentially releasable in a failure. Additional guidance for use of the 
alternative is provided in a new appendix B.
    The pipeline failure history, denoted in the final rule as 
``Probability of Failure Indicator,'' is an important factor. The 
history of past failures (types of failures, number of failures, sizes 
of releases, etc.) plays an important role in determining the chances 
of future occurrences for a particular pipeline system. Therefore, it 
has been included as risk factor in the matrix for determining the risk 
classification. In the final rule the probability of failure indicator 
is considered ``high risk'' if the pipeline segment has experienced 
more than three failures in last 10 years due to time-dependent defects 
(due to corrosion, gouges, or problems developed during manufacture, 
construction or operation, etc.). Pipeline operators should make an 
appropriate investigation of spills to determine whether they are due 
to time-dependent defects. An operator's determination should be based 
on sound engineering judgment and be documented. In addition, the final 
rule provides compliance dates and recordkeeping requirements for those 
operators who elect the risk-based alternative to pressure testing of 
older hazardous liquid and carbon dioxide pipelines.
    RSPA believes this rule will provide the pipeline industry with the 
flexibility to elect alternative technology for evaluating pipeline 
integrity without sacrificing safety.

Discussion of Comments

    RSPA received four comments in response to the NPRM. Commenters 
included one industry association (API), two pipeline operating 
companies, and a safety consultant. Three commenters including API 
expressed strong support, but one commenter (a safety consultant) 
opposed issuing this risk-based rule.
    Performance measures--In the proposed rule, RSPA sought comment and 
information on how to measure the performance of this risk-based 
alternative to determine effectiveness, particularly in comparison with 
the pressure test rule. RSPA received no comment. RSPA plans to examine 
the future performance of those pipeline segments that are pressure 
tested and compare it to the future performance of pipeline segments 
that are internally inspected or that are not tested at all.
    Failure history--In the proposed rule, RSPA sought comment on 
excluding insignificant failures from the failure history risk factor. 
RSPA also sought comment on whether the failure should be quantified or 
if only a reportable incident should be considered.
    One operator commented that only Department Of Transportation (DOT) 
reportable incidents be included. API commented that spills, regardless 
of whether reportable or not, should be included in the risk-based 
alternative engineering evaluation process by the operator making its 
own engineering judgment. The judgment should be documented and 
applied, when appropriate, to the failure history risk factor. API 
believes that proper documentation removes subjective judgments during 
agency audits/evaluations of the use of the risk-based alternative.
    One commenter asked whether third party damage resulting in the 
immediate release of product would be considered a time-dependent 
defect in Table 6.
    RSPA agrees that proper documentation would clarify the validity of 
decisions about whether spills are related to time-dependent defects or 
are truly insignificant during agency evaluation of the use of the 
risk-based alternative. This also eliminates need for failures to be 
quantified. Third party damage resulting in the immediate release of 
product does not constitute a time-dependent defect. Time-dependent 
defects are defects that result in spills due to corrosion, gouges, or 
problems developed during manufacture, construction or operation, etc. 
This is already covered in subnote 2 in Table 6

[[Page 59478]]

of Appendix B. Therefore, no changes have been made to Table 6.
    Opposition to issuing the risk-based rule--One commenter (a safety 
consultant) opposed issuing this rule. Commenter argued that this rule 
might have been more meritorious had it been proposed after the results 
were in on the risk management demonstration projects. This commenter 
said that the notice published in the Federal Register on November 15, 
1996 (61 FR 58605) states that the demonstration projects will test 
whether allowing operators the flexibility to allocate safety resources 
through risk management is an effective way to improve safety, 
environmental protection, and reliability. They will also provide data 
on how to administer risk management as a permanent feature of the 
Federal pipeline safety program if risk management proves to be viable 
regulation alternative. Therefore, this commenter said this rulemaking 
should be delayed until the completion of the risk management 
demonstration projects. This commenter also contended that the purpose 
of the API petition requesting the risk-based alternative was to 
reduce, or delay, the economic burden on pipeline companies as a result 
of the requirements of the final rule for pressure testing published by 
RSPA on June 7, 1994, (59 FR 29379).
    RSPA disagrees that this rule should be delayed until completion of 
the risk management demonstration projects. The Accountable Pipeline 
Safety and Partnership Act of 1996 (Pub. L. 104-304, Oct. 12, 1996) 
that establishes the Risk Management Demonstration Program contemplates 
a limited number of projects. RSPA will approve no more than ten (10). 
Currently, none of projects being considered addresses the pressure 
testing of older pipelines that are impacted by the June 1994 pressure 
test rule. The Demonstration Program is looking at whole set of 
activities rather than focusing on an individual regulation. Also, 
delay until completion of the projects would unreasonably delay 
addressing issues of older hazardous liquid pipelines. These pipelines 
include high risk ERW pipelines.
    The risk-based approach to older pipelines provides an opportunity 
to pilot a risk-based approach in a rulemaking forum as opposed to a 
demonstration project forum. RSPA believes this rule will provide the 
pipeline industry with the flexibility to elect alternative technology 
for evaluating pipeline integrity without sacrificing safety.
    Proposed Sec. 195.303(b)(4)(ii)--API suggested that this paragraph 
be revised to clarify that up to three time-dependent failures in 10 
years would be low-risk. The proposed rule inadvertently limited the 
low risk assignation to two failures. This is inconsistent with the 
proposed Table 6. We agree and have revised this paragraph to be 
consistent with Table 6.
    Proposed Sec. 195.303(c): API said that the last sentence in the 
text of Sec. 195.303(c) should be clarified so that operators 
understand that for those segments that fall under Risk Classification 
A ``no additional measures'' refers to no additional measures under 
this subpart (i.e. subpart E--Pressure Testing). API said that the last 
sentence as proposed appears to be broader. We have revised this 
section for clarity as recommended by the API.
    Proposed Sec. 195.303(g): API said that the text of Sec. 195.303(g) 
should be clarified so that operators understand that pressure testing 
under the risk-based alternative, like the existing final rule, would 
be a one-time test. The review of risk classifications should be 
required only for those pipeline segments that have not yet been tested 
under Sec. 195.303(a) or Sec. 195.303(c). We agree and have clarified 
the wording.
    Proposed Sec. 195.303(i): API said that requiring operators to give 
a written notification and get approval from the Administrator before 
discontinuing from this program, should be eliminated from this 
rulemaking. Adding that this section is confusing, contradictory and 
results in a different standard of care for the risk-based alternative 
compared with the existing final rule. API said that operators should 
have flexibility to elect test portions and change plans of their 
system using the existing final rule and portions of their systems 
under the risk based alternative. The intent of Sec. 195.303(i) 
requirement is to avoid operators switching from one testing program to 
another, causing delays in testing. Eliminating this requirement may 
make it difficult to enforce the regulatory deadlines. Requirements in 
this rule does not prevent an operator from choosing pressure testing 
for some segments and risk-based alternative for the remaining segments 
of a pipeline. Therefore, this section is retained.
    Do previous in-line inspections on pipeline systems constitute 
compliance? API and one commenter requested that RSPA should allow 
previous in-line inspections and subsequent maintenance of a pipeline 
documented by company records as in compliance with this rule. RSPA 
will accept previous in-line inspections on pipeline conducted in the 
five years prior to the effective date of this final rule provided that 
anomalies found by previous smart pig runs have been repaired and 
pipeline has been maintained. RSPA will not accept older in-line 
inspections for the following reasons: (1) Technology keeps changing 
rapidly and internal inspection devices have greatly improved in recent 
years, (2) older internal inspection devices probably did not provide 
adequate data, (3) new corrosion or other defects may have developed 
since last in-line inspection.
    Appendix B Table 1--API suggested that term ``pipeline system'' be 
changed to ``pipeline segment'' in Footnote 1 to Table 1, for clarity 
and agreement with the intent of the risk-based rule. We agree.
    Additional Clarifying Guidance for both Operators and Inspectors--A 
number of operators (via API) offered suggestions for ways of making 
the rule more understandable, including rearranging the tables in the 
appendix, making the tables more explicit or providing flow charts that 
visually clarify the decision-making paths. RSPA realizes that a 
flowchart or decision tree with a couple of examples could aid the 
operators. However, the need to avoid further delay in addressing the 
issues of older hazardous liquid pipelines makes it impossible for RSPA 
to prepare such additional aids to implementation at this stage. 
Nothing precludes API with the help of its members from developing a 
flowchart and perhaps a few examples on how to apply this risk-based 
rule for its members.

V. Rulemaking Analyses

Executive Order 12866 and DOT Regulatory Policies and Procedures

    This final rule is a significant regulatory action under Executive 
Order 12866. Therefore, this rule was reviewed by the Office of 
Management and Budget. In addition, this final rule is significant 
under DOT's regulatory policies and procedures (44 FR 11034; February 
26, 1979) because it is the first explicitly risk-based approach to 
rulemaking final by the Office of Pipeline Safety. A copy of the 
regulatory evaluation to this rule is also available in the docket 
office for review.
    This section summarizes the conclusions of the regulatory 
evaluation. RSPA's pressure testing final rule was published on June 7, 
1994 (59 FR 29379) along with a regulatory evaluation which found that 
the rule had a positive net benefit to the public, i.e., the benefits 
of the rule exceeded the cost (Present value costs of the earlier 
proposal were estimated to be between $134-$179 million in 1997 dollars 
while the present value benefits were

[[Page 59479]]

estimated as $230-$283 million). RSPA believes that the risk-based 
alternative maintains the necessary margins of safety, therefore, the 
benefits of this alternative should be similar to the benefits of the 
earlier proposal. The present value costs for the risk-based 
alternative are estimated to be between $88.4-$98.4 million for reasons 
described below. The final rule allows the use of alternative 
technology (smart pigs) for evaluating pipeline integrity. On average 
smart pig testing is less expensive than pressure testing by $2,650/
mile. In some cases smart pig technology provides more information 
about pipeline anomalies than pressure testing. The risk-based 
alternative would reduce the total amount of test water, which should 
lower the waste treatment costs and generate less hazardous waste. The 
risk-based alternative would allow operators to forgo testing where 
pipelines have low operating pressures, transport non-volatile product, 
operate in rural and environmentally non-sensitive areas, and have good 
records on pipeline failure history.
    This risk-based approach is an ongoing process. RSPA believes that 
the risk-based alternative maintains the necessary margins of safety 
for the public and environment. Moreover, RSPA concludes that this 
alternative has the potential for positive improvements for the 
environment while reducing operating costs by allowing operators to 
elect those test methods most appropriate to the circumstances of each 
pipeline.

Regulatory Flexibility Act

    The regulatory flexibility analysis of the earlier final rule 
concluded that it would not have a significant impact on a substantial 
number of small entities. RSPA believes that because this regulation 
offers an alternative to operators that could reduce the less than 
significant impact of the earlier regulation even further, this rule 
does not have a significant impact on a substantial number of small 
entities. Based on the facts available about the anticipated impact of 
this rulemaking action, I certify pursuant to Section 605 of the 
Regulatory Flexibility Act (5 U.S.C. 605) that the action will not have 
a significant economic impact on a substantial number of small 
entities.
    RSPA, in the proposed rule, had requested comments from small 
entities which might be impacted by this rule. We received no comments. 
This supports our earlier conclusion that this rule will have no 
significant impact on a substantial number of small entities.

Executive Order 12612

    This rule will not have substantial direct effect on states, on the 
relationship between the Federal Government and the states, or on the 
distribution of power and responsibilities among the various levels of 
government. Therefore, in accordance with E.O. 12612 (52 FR 41685; 
October 30, 1987), RSPA has determined that this final rule does not 
have sufficient federalism implications to warrant preparation of a 
Federalism Assessment.

Executive Order 13084

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

Unfunded Mandates

    This rule does not impose unfunded mandates under the Unfunded 
Mandates Reform Act of 1995. It does 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 is the least burdensome 
alternative that achieves the objective of the rule.

Paperwork Reduction Act

    This rule does not substantially modify the paperwork burden on 
pipeline operators. Under the current pressure testing regulations 
operators are required to have testing plans, schedules, and records. 
The risk-based alternative would require the same or equivalent plans, 
schedules, and records for either pressure testing or internal 
inspection. Therefore, there is no additional paperwork required. 
Operators who choose the risk-based alternative will be required to 
have records that the pipeline segment which is not being tested 
qualifies for the risk-based alternative. According to conversations 
between OPS and the pipeline industry some of this information is 
already available in the form of drawings or plans that can be found 
either in operators' Facility Response Plans required by the Oil 
Pollution Act of 1990 (OPA 90) or in emergency response plans required 
by RSPA.
    Operators will be required to periodically review the pipelines 
that qualify for the risk-based alternative to ensure that they still 
qualify. OPS believes that operators can conduct this review as part of 
their normal procedures.
    Because of the above analysis, OPS does not believe that operators 
will have any additional paperwork burden because of this alternative, 
and therefore no separate paperwork submission is required.

National Environmental Policy Act

    RSPA has analyzed this action for purposes of the National 
Environmental Policy Act (42 U.S.C. 4321 et seq.) and has determined 
that this action would not significantly affect the quality of the 
human environment. An Environmental Assessment and a Finding of No 
Significant Impact are in the docket.

List of Subjects in 49 CFR Part 195

    Anhydrous ammonia, Carbon dioxide, Petroleum, Pipeline safety, 
Reporting and recordkeeping requirements.

    In consideration of the foregoing, RSPA amends part 195 of title 49 
of the Code of Federal Regulations as follows:

PART 195--[AMENDED]

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

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

    2. Section 195.302 is amended by adding a new paragraph (b)(4) to 
read as follows:


Sec. 195.302  General requirements.

* * * * *
    (b) * * *
    (4) Those portions of older hazardous liquid and carbon dioxide 
pipelines for which an operator has elected the risk-based alternative 
under Sec. 195.303 and which are not required to be tested based on the 
risk-based criteria.
* * * * *
    3. Section 195.302(a) is amended by removing cross-reference 
``Sec. 195.304(b)'' and adding cross-reference ``Sec. 195.305(b)''.
    4. In paragraph (c) of Sec. 195.302, the introductory text is 
revised to read as follows:


Sec. 195.302  General requirements.

* * * * *
    (c) Except for pipelines that transport HVL onshore, low-stress 
pipelines, and pipelines covered under Sec. 195.303, the following 
compliance deadlines apply to pipelines under paragraphs (b)(1) and 
(b)(2)(i) of this section that have not been pressure tested under this 
subpart:
* * * * *

[[Page 59480]]

Secs. 195.303 and 195.304  [Redesignated as Secs. 195.304 and 195.305]

    5. Section 195.303 Test pressure. and Sec. 195.304 Testing of 
components. are redesignated as Sec. 195.304 Test pressure. and 
Sec. 195.305 Testing of components.
    6. Part 195 is amended by adding a new Sec. 195.303 to read as 
follows:


Sec. 195.303  Risk-based alternative to pressure testing older 
hazardous liquid and carbon dioxide pipelines.

    (a) An operator may elect to follow a program for testing a 
pipeline on risk-based criteria as an alternative to the pressure 
testing in Sec. 195.302(b)(1)(i)-(iii) and Sec. 195.302(b)(2)(i) of 
this subpart. Appendix B provides guidance on how this program will 
work. An operator electing such a program shall assign a risk 
classification to each pipeline segment according to the indicators 
described in paragraph (b) of this section as follows:
    (1) Risk Classification A if the location indicator is ranked as 
low or medium risk, the product and volume indicators are ranked as low 
risk, and the probability of failure indicator is ranked as low risk;
    (2) Risk Classification C if the location indicator is ranked as 
high risk; or
    (3) Risk Classification B.
    (b) An operator shall evaluate each pipeline segment in the program 
according to the following indicators of risk:
    (1) The location indicator is--
    (i) High risk if an area is non-rural or environmentally sensitive 
\1\; or
    (ii) Medium risk; or
    (iii) Low risk if an area is not high or medium risk.
    (2) The product indicator is 1
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    \1\ (See Appendix B, Table C).
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    (i) High risk if the product transported is highly toxic or is both 
highly volatile and flammable;
    (ii) Medium risk if the product transported is flammable with a 
flashpoint of less than 100 deg. F, but not highly volatile; or
    (iii) Low risk if the product transported is not high or medium 
risk.
    (3) The volume indicator is--
    (i) High risk if the line is at least 18 inches in nominal 
diameter;
    (ii) Medium risk if the line is at least 10 inches, but less than 
18 inches, in nominal diameter; or
    (iii) Low risk if the line is not high or medium risk.
    (4) The probability of failure indicator is--
    (i) High risk if the segment has experienced more than three 
failures in the last 10 years due to time-dependent defects (e.g., 
corrosion, gouges, or problems developed during manufacture, 
construction or operation, etc.); or
    (ii) Low risk if the segment has experienced three failures or less 
in the last 10 years due to time-dependent defects.
    (c) The program under paragraph (a) of this section shall provide 
for pressure testing for a segment constructed of electric resistance-
welded (ERW) pipe and lapwelded pipe manufactured prior to 1970 
susceptible to longitudinal seam failures as determined through 
paragraph (d) of this section. The timing of such pressure test may be 
determined based on risk classifications discussed under paragraph (b) 
of this section. For other segments, the program may provide for use of 
a magnetic flux leakage or ultrasonic internal inspection survey as an 
alternative to pressure testing and, in the case of such segments in 
Risk Classification A, may provide for no additional measures under 
this subpart.
    (d) All pre-1970 ERW pipe and lapwelded pipe is deemed susceptible 
to longitudinal seam failures unless an engineering analysis shows 
otherwise. In conducting an engineering analysis an operator must 
consider the seam-related leak history of the pipe and pipe 
manufacturing information as available, which may include the pipe 
steel's mechanical properties, including fracture toughness; the 
manufacturing process and controls related to seam properties, 
including whether the ERW process was high-frequency or low-frequency, 
whether the weld seam was heat treated, whether the seam was inspected, 
the test pressure and duration during mill hydrotest; the quality 
control of the steel-making process; and other factors pertinent to 
seam properties and quality.
    (e) Pressure testing done under this section must be conducted in 
accordance with this subpart. Except for segments in Risk 
Classification B which are not constructed with pre-1970 ERW pipe, 
water must be the test medium.
    (f) An operator electing to follow a program under paragraph (a) 
must develop plans that include the method of testing and a schedule 
for the testing by December 7, 1998. The compliance deadlines for 
completion of testing are as shown in the table below:

                  Table.--Sec.  195.303--Test Deadlines
------------------------------------------------------------------------
                                         Risk
        Pipeline segment            classification       Test deadline
------------------------------------------------------------------------
Pre-1970 Pipe susceptible to      C or B              12/7/2000.
 longitudinal seam failures       A                   12/7/2002.
 [defined in Sec.  195.303(c) &
 (d)].
All Other Pipeline Segments.....  C                   12/7/2002.
                                  B                   12/7/2004.
                                  A                   Additional testing
                                                       not required.
------------------------------------------------------------------------

    (g) An operator must review the risk classifications for those 
pipeline segments which have not yet been tested under paragraph (a) of 
this section or otherwise inspected under paragraph (c) of this section 
at intervals not to exceed 15 months. If the risk classification of an 
untested or uninspected segment changes, an operator must take 
appropriate action within two years, or establish the maximum operating 
pressure under Sec. 195.406(a)(5).
    (h) An operator must maintain records establishing compliance with 
this section, including records verifying the risk classifications, the 
plans and schedule for testing, the conduct of the testing, and the 
review of the risk classifications.
    (i) An operator may discontinue a program under this section only 
after written notification to the Administrator and approval, if 
needed, of a schedule for pressure testing.


Sec. 195.406  [Amended]

    7. Section 195.406(a)(4) is amended by removing cross-reference 
``Sec. 195.304'' and adding cross-reference ``Sec. 195.305''
    8. A new Appendix B is added to part 195 to read as follows:

Appendix B--Risk-Based Alternative to Pressure Testing Older 
Hazardous Liquid and Carbon Dioxide Pipelines

Risk-Based Alternative

    This Appendix provides guidance on how a risk-based alternative 
to pressure testing older hazardous liquid and carbon dioxide 
pipelines rule allowed by Sec. 195.303 will work. This risk-based 
alternative establishes test priorities for older pipelines, not 
previously pressure tested, based on the inherent risk of a given 
pipeline segment. The first step is to determine the classification 
based on the type of pipe or on the pipeline segment's proximity to 
populated or environmentally sensitive area. Secondly, the 
classifications must be adjusted based on the pipeline failure 
history, product transported, and the release volume potential.

[[Page 59481]]

    Tables 2-6 give definitions of risk classification A, B, and C 
facilities. For the purposes of this rule, pipeline segments 
containing high risk electric resistance-welded pipe (ERW pipe) and 
lapwelded pipe manufactured prior to 1970 and considered a risk 
classification C or B facility shall be treated as the top priority 
for testing because of the higher risk associated with the 
susceptibility of this pipe to longitudinal seam failures.
    In all cases, operators shall annually, at intervals not to 
exceed 15 months, review their facilities to reassess the 
classification and shall take appropriate action within two years or 
operate the pipeline system at a lower pressure. Pipeline failures, 
changes in the characteristics of the pipeline route, or changes in 
service should all trigger a reassessment of the originally 
classification.
    Table 1 explains different levels of test requirements depending 
on the inherent risk of a given pipeline segment. The overall risk 
classification is determined based on the type of pipe involved, the 
facility's location, the product transported, the relative volume of 
flow and pipeline failure history as determined from Tables 2-6.

          Table 1. Test Requirements--Mainline Segments Outside of Terminals, Stations, and Tank Farms
----------------------------------------------------------------------------------------------------------------
         Pipeline segment           Risk classification           Test deadline \1\              Test medium
----------------------------------------------------------------------------------------------------------------
Pre-1970 Pipeline Segments         C or B                 12/7/2000 \3\...................  Water only.
 susceptible to longitudinal seam  A                      12/7/2002 \3\...................  Water only.
 failures \2\.
All Other Pipeline Segments......  C                      12/7/2002 \4\...................  Water only.
                                   B                      12/7/2004 \4\...................  Water/Liq.\5\
                                   A                      Additional pressure testing not
                                                           required.
----------------------------------------------------------------------------------------------------------------
\1\ If operational experience indicates a history of past failures for a particular pipeline segment, failure
  causes (time-dependent defects due to corrosion, construction, manufacture, or transmission problems, etc.)
  shall be reviewed in determining risk classification (See Table 6) and the timing of the pressure test should
  be accelerated.
\2\ All pre-1970 ERW pipeline segments may not require testing. In determining which ERW pipeline segments
  should be included in this category, an operator must consider the seam-related leak history of the pipe and
  pipe manufacturing information as available, which may include the pipe steel's mechanical properties,
  including fracture toughness; the manufacturing process and controls related to seam properties, including
  whether the ERW process was high-frequency or low-frequency, whether the weld seam was heat treated, whether
  the seam was inspected, the test pressure and duration during mill hydrotest; the quality control of the steel-
  making process; and other factors pertinent to seam properties and quality.
\3\ For those pipeline operators with extensive mileage of pre-1970 ERW pipe, any waiver requests for timing
  relief should be supported by an assessment of hazards in accordance with location, product, volume, and
  probability of failure considerations consistent with Tables 3, 4, 5, and 6.
\4\ A magnetic flux leakage or ultrasonic internal inspection survey may be utilized as an alternative to
  pressure testing where leak history and operating experience do not indicate leaks caused by longitudinal
  cracks or seam failures.
\5\ Pressure tests utilizing a hydrocarbon liquid may be conducted, but only with a liquid which does not
  vaporize rapidly.

    Using LOCATION, PRODUCT, VOLUME, and FAILURE HISTORY 
``Indicators'' from Tables 3, 4, 5, and 6 respectively, the overall 
risk classification of a given pipeline or pipeline segment can be 
established from Table 2. The LOCATION Indicator is the primary 
factor which determines overall risk, with the PRODUCT, VOLUME, and 
PROBABILITY OF FAILURE Indicators used to adjust to a higher or 
lower overall risk classification per the following table.

                                          Table 2.--Risk Classification
----------------------------------------------------------------------------------------------------------------
                                     Hazard location          Product/volume          Probability of failure
      Risk classification               indicator                indicator                   indicator
----------------------------------------------------------------------------------------------------------------
A..............................  L or M.................  L/L...................  L.
B..............................                           Not A or C Risk Classification
C..............................  H......................  Any...................  Any.
----------------------------------------------------------------------------------------------------------------
H=High    M=Moderate    L=Low.
Note: For Location, Product, Volume, and Probability of Failure Indicators, see Tables 3, 4, 5, and 6.

    Table 3 is used to establish the LOCATION Indicator used in 
Table 2. Based on the population and environment characteristics 
associated with a pipeline facility's location, a LOCATION Indicator 
of H, M or L is selected.

                                Table 3.--Location Indicators--Pipeline Segments
----------------------------------------------------------------------------------------------------------------
               Indicator                                  Population \1\                      Environment \2\
----------------------------------------------------------------------------------------------------------------
H......................................  Non-rural areas................................  Environmentally
                                                                                           sensitive \2\ areas.
M                                        ...............................................  ......................
L......................................  Rural areas....................................  Not environmentally
                                                                                           sensitive \2\ areas.
----------------------------------------------------------------------------------------------------------------
\1\ The effects of potential vapor migration should be considered for pipeline segments transporting highly
  volatile or toxic products.
\2\ We expect operators to use their best judgment in applying this factor.

    Tables 4, 5 and 6 are used to establish the PRODUCT, VOLUME, and 
PROBABILITY OF FAILURE Indicators respectively, in Table 2. The 
PRODUCT Indicator is selected from Table 4 as H, M, or L based on 
the acute and chronic hazards associated with the product 
transported. The VOLUME Indicator is selected from Table 5 as H, M, 
or L based on the nominal diameter of the pipeline. The Probability 
of Failure Indicator is selected from Table 6.

[[Page 59482]]



                      Table 4.--Product Indicators
------------------------------------------------------------------------
          Indicator              Considerations       Product examples
------------------------------------------------------------------------
H...........................  (Highly volatile and  (Propane, butane,
                               flammable).           Natural Gas Liquid
                                                     (NGL), ammonia)
                              Highly toxic........  (Benzene, high
                                                     Hydrogen Sulfide
                                                     content crude
                                                     oils).
M...........................  Flammable--flashpoin  (Gasoline, JP4, low
                               t <100F.              flashpoint crude
                                                     oils).
This section has been         Non-flammable--       (Diesel, fuel oil,
 revised to include            flashpoint 100+F.     kerosene, JP5, most
 reference to ANSI/NFPA 59A                          crude oils).
 in paragraph (a) as
 follows: L.
                              Highly volatile and   Carbon Dioxide.
                               non-flammable/non-
                               toxic.
------------------------------------------------------------------------

    Considerations: The degree of acute and chronic toxicity to 
humans, wildlife, and aquatic life; reactivity; and, volatility, 
flammability, and water solubility determine the Product Indicator. 
Comprehensive Environmental Response, Compensation and Liability Act 
Reportable Quantity values can be used as an indication of chronic 
toxicity. National Fire Protection Association health factors can be 
used for rating acute hazards.

                       Table 5.--Volume Indicators
------------------------------------------------------------------------
             Indicator                            Line size
------------------------------------------------------------------------
H.................................  18''.
M.................................  10''-16'' nominal diameters.
L.................................  8'' nominal diameter.
------------------------------------------------------------------------
H=High    M=Moderate    L=Low.

    Table 6 is used to establish the PROBABILITY OF FAILURE 
Indicator used in Table 2. The ``Probability of Failure'' Indicator 
is selected from Table 6 as H or L.

               Table 6.--Probability of Failure Indicators
                         [in each haz. location]
------------------------------------------------------------------------
                                       Failure history (time-dependent
             Indicator                          defects) \2\
------------------------------------------------------------------------
H \1\.............................  >Three spills in last 10 years.
L.................................  Three spills in last 10
                                     years.
------------------------------------------------------------------------
H=High    L=Low.
\1\ Pipeline segments with greater than three product spills in the last
  10 years should be reviewed for failure causes as described in subnote
  \2\. The pipeline operator should make an appropriate investigation
  and reach a decision based on sound engineering judgment, and be able
  to demonstrate the basis of the decision.
\2\ Time-Dependent Defects are defects that result in spills due to
  corrosion, gouges, or problems developed during manufacture,
  construction or operation, etc.

    Issued in Washington, DC, on October 26, 1998.
Kelley S. Coyner,
Administrator, Research and Special Programs Administration.
[FR Doc. 98-29242 Filed 11-3-98; 8:45 am]
BILLING CODE 4910-60-P