[Federal Register Volume 63, Number 24 (Thursday, February 5, 1998)]
[Proposed Rules]
[Pages 5918-5924]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 98-2860]
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DEPARTMENT OF TRANSPORTATION
Research and Special Programs Administration
49 CFR Part 195
[Docket No. PS-144; Notice 2]
[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: Notice of Proposed Rulemaking.
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SUMMARY: This notice proposes to allow 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.
DATES: Interested persons are invited to submit comments on this notice
of proposed rulemaking (NPRM) by April 6, 1998. Late filed comments
will be considered to the extent practicable.
ADDRESSES: Written comments must be submitted in duplicate and mailed
or hand-delivered to the Dockets Unit, Room 8421, U.S. Department of
Transportation, 400 Seventh Street, SW., Washington, DC 20590-0001.
Identify the docket and notice number stated in the heading of this
notice. Comments will become part of this docket and will be available
for inspection or copying in Room 8421 between 8:30 a.m. and 5 p.m.
each business day.
[[Page 5919]]
FOR FURTHER INFORMATION CONTACT: Mike Israni, (202) 366-4571, regarding
the subject matter of this proposed rule, or Dockets Unit (202) 366-
4453, for copies of this final rule document or other material in the
docket.
SUPPLEMENTARY INFORMATION:
I. 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 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 notice of proposed rulemaking
proposes 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 rulemaking 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].
RSPA seeks 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.
II. Major features of risk-based alternative
The proposed 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 lapweld 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 lapweld pipelines, because
it can detect the type of seam failures endemic to some ERW and all
lapweld pipe. This risk-based alternative requires accelerated testing
of pre-1970 ERW and lapweld pipe susceptible to longitudinal seam
failure in certain locations (risk classification C and B) where people
might be significantly affected. However, in rural areas (risk
classification A), where consequences to the public are less
significant, the risk-based alternative allows delayed testing for pre-
1970 ERW and lapweld 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, 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 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. By taking
these potential consequences into consideration in the timing of tests,
an operator's resources will be more effectively applied to reduce
risks.
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 proposal 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 proposal
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
concept increases the priority of a limited amount of pre-1970 ERW and
all lapweld pipelines and maintains the three-year timing for risk
classification B and C lines which represent the highest risk to
people. 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
proposed alternative precludes an operator from accelerating these
schedules based on their pipeline operating and maintenance history.
5. Reduces Test Water Requirements
This proposal 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 proposal provides an
opportunity to pilot a risk-based approach to regulation. OPS
anticipates increased use of risk-based approaches in future
rulemakings.
III. Proposed Rule
RSPA is proposing to add a new section to Part 195 entitled ``Risk-
based alternative to pressure testing.'' Existing sections Sec. 195.303
``Test pressure'', and Sec. 195.304 ``Testing of components'' will be
renumbered as Sec. 195.304 and Sec. 195.305 respectively.
[[Page 5920]]
Proposed new section 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 \1\.
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\1\ 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.
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The next step is to determine the pipeline segment's proximity to
populated areas (Location).
We are not now proposing to include environmentally sensitive
locations within the risk factors for application of the alternative.
This is consistent with the API proposal for a risk based alternative.
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). While we
do not necessarily agree that a definition of USAs will provide the
sole basis for inclusion of an environmental factor for a risk-based
alternative to pressure testing, we recognize the difficulties in
including such a factor before the USA definition is formulated. The
difficulty in even articulating a factor at this time was made very
apparent by THLPSSC members at the May 1997 meeting (while one member
argued that the environmental factor under consideration for the
proposed rule was inadequate, two other members challenged that
argument) and discussions with the members and API following that
meeting. Because this alternative takes into consideration other
significant risk factors that may impact severity of a release, i.e.,
proximity to populated areas, potential volume of the product release,
the nature of product transported, pipeline failure history and
pipeline susceptible to longitudinal seam failures, it is unlikely that
pipeline testing is being undermined by not considering the
environmental factor in the interim. Therefore, we have decided to omit
an environmental factor at this time and explore the issue further once
we have defined ``unusually sensitive areas''.
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 proposed Appendix B.
The pipeline failure history, denoted in the proposed 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 proposed 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. RSPA seeks comment on whether some failures are so minimal
as to be appropriately excluded from the failure history risk factor.
If so, how should the failure be quantified? Should it only be a
reportable incident?
In addition, the proposed 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 the proposed rule will provide the pipeline industry
with the flexibility to elect alternative technology for evaluating
pipeline integrity without sacrificing safety.
IV. Rulemaking Analyses
Executive Order 12866 and DOT Regulatory Policies and Procedures
This proposed rule is a significant regulatory action under
Executive Order 12866. Therefore, this notice was reviewed by the
Office of Management and Budget. In addition, this proposed 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 proposed by the Office of Pipeline Safety. A
copy of the draft regulatory evaluation to this proposal is also
available in the docket office for review.
This section summarizes the conclusions of the draft 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 estimated as $230-$283 million).
Since the risk-based alternative maintains the necessary margins of
safety, 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 proposed 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
alternative would reduce the total amount of test water, which should
lower the waste treatment costs and generate less hazardous waste. The
alternative would allow operators to forgo testing where pipelines have
low operating pressures, transport non-volatile product, operate in
rural 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. 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 proposed
regulation offers an alternative to operators that could reduce the
impact of the earlier regulation, this
[[Page 5921]]
proposed 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.
However, RSPA does not currently have specific information about
small entities which may elect to use this alternative to pressure
testing. RSPA requests comments from small entities directed at the
impacts of this proposed rule.
Executive Order 12612
This rulemaking action will not have substantial direct effects 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.
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 proposes to amend 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 would be 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 in its place cross-reference
``Sec. 195.305(b)''.
4. In paragraph (c) of Sec. 195.302, the introductory text would be
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:
* * * * *
Sec. 195.303 and 195.304 [redesignated]
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 would be 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) through (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 \1\; or
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\1\ An environmental factor will be considered in a later
rulemaking.
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(ii) Medium risk \2\; or
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\2\ Not currently applicable; it may be applicable with addition
of environmental factor to the location indicator.
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(iii) Low risk if an area is not high or medium risk.
(2) The product indicator is--
(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
[[Page 5922]]
(ii) Low risk if the segment has experienced less than three
failures 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 lapweld 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.
(d) All pre-1970 ERW pipe and lapweld 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) of
this section 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
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Pipeline segment Risk classification Test deadline
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Pre-1970 Pipe susceptible to C or B 12/7/2000
longitudinal seam failures [defined A
in Sec. 195.303(c) & (d)]. 12/7/2002
All Other Pipeline.................... C 12/7/2002
Segments.............................. B 12/7/2004
A
Additional testing not required.
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(g) An operator must review the risk classifications at intervals
not to exceed 15 months. If the risk classification of a 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'' in its
place.
8. A new Appendix B would be added to Part 195 to read as follows:
Appendix B to Part 195--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. Secondly, the classifications must be adjusted based on
the pipeline failure history, product transported, and the release
volume potential.
Tables 2 through 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
through 6.
Table 1.--Test Requirements--Mainline Segments Outside of Terminals, Stations, and Tank Farms
----------------------------------------------------------------------------------------------------------------
Pipeline segment Risk classification Test deadline \1\ Test medium
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Pre-1970 Pipeline Segments C or B 12/7/2000 \3\ Water only.
susceptible to longitudinal A 12/7/2002 \3\ Water only.
seam failures \2\.
All Other Pipeline Segments. C 12/7/2002 \4\ Water only.
B 12/7/2004 \4\ Water/Liq.\5\
[[Page 5923]]
A Additional pressure
testing not required.
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\1\ If operational experience indicates a history of past failures for a particular pipeline system, 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
----------------------------------------------------------------------------------------------------------------
Probability of failure
Risk classification Hazard location indicator Product/volume indicator indicator
----------------------------------------------------------------------------------------------------------------
A................................ L or M L/L L
B................................
(2) Not A or C Risk
Classification
C................................ H Any Any.
----------------------------------------------------------------------------------------------------------------
H=High, M=Moderate, and 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 environmental in the future)
characteristics associated with a pipeline facility's location, a
LOCATION Indicator of H, (M) or L is selected.
Table 3.--Location Indicators--Pipeline Segments
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Indicator Population \1\ Environment \2\
------------------------------------------------------------------------
H........................... Non-rural areas ....................
M........................... .................... ....................
L........................... Rural areas ....................
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\1\ The effects of potential vapor migration should be considered for
pipeline segments transporting highly volatile or toxic products.
\2\ An environmental factor has not been included at this time, but may
be once a definition of ``unusually sensitive areas'' has been
established.
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.
Table 4.--Product Indicators
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Indicator Considerations Product examples
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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).
L........................... Non-flammable-- (Diesel, fuel oil,
flashpoint 100+F. kerosene, JP5, most
crude oils).
.......................... 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.
[[Page 5924]]
Table 5.--Volume Indicators
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Indicator Line size
------------------------------------------------------------------------
H........................................ 18''
M........................................ 10''-16'' nominal diameters.
L........................................ 8'' nominal
diameter.
------------------------------------------------------------------------
H=High, M=Moderate, and 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-
Indicator dependent defects) \2\
------------------------------------------------------------------------
H \1\.................................... > Three spills in last 10
years.
L........................................ Three spills in
last 10 years.
------------------------------------------------------------------------
H=High and 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, D.C. on January 30, 1998.
Richard B. Felder,
Associate Administrator for Pipeline Safety.
[FR Doc. 98-2860 Filed 2-4-98; 8:45 am]
BILLING CODE 4910-60-P