[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: mike.israni@rspa.dot.gov, 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
