[Federal Register Volume 67, Number 219 (Wednesday, November 13, 2002)]
[Proposed Rules]
[Pages 68815-68827]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 02-28240]
[[Page 68815]]
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DEPARTMENT OF TRANSPORTATION
Research and Special Programs Administration
49 CFR Part 192
[Docket No. RSPA-02-13208; Notice 1]
RIN 2137-AD01
Pipeline Safety: Further Regulatory Review; Gas Pipeline Safety
Standards
AGENCY: Research and Special Programs Administration (RSPA), DOT.
ACTION: Notice of proposed rulemaking.
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SUMMARY: RSPA is proposing to change some of the safety standards for
gas pipelines. The changes are based on recommendations by the National
Association of Pipeline Safety Representatives (NAPSR) and a review of
the recommendations by the State Industry Regulatory Review Committee
(SIRRC). We believe the changes will improve the clarity and
effectiveness of the present standards.
DATES: Persons interested in submitting written comments on the rules
proposed in this notice must do so by January 13, 2003. Late filed
comments will be considered so far as practicable.
ADDRESSES: You may submit written comments by mailing or delivering an
original and two copies to the Dockets Facility, U.S. Department of
Transportation, Room PL-401, 400 Seventh Street, SW., Washington, DC
20590-0001. The Dockets Facility is open from 10 a.m. to 5 p.m., Monday
through Friday, except on Federal holidays when the facility is closed.
Or you may submit written comments to the docket electronically at the
following Web address: http://dms.dot.gov. See the SUPPLEMENTARY
INFORMATION section for additional filing information.
FOR FURTHER INFORMATION CONTACT: L.M. Furrow by phone at 202-366-4559,
by fax at 202-366-4566, by mail at U.S. Department of Transportation,
400 Seventh Street, SW., Washington, DC 20590, or by e-mail at
[email protected].
SUPPLEMENTARY INFORMATION:
Filing Information, Electronic Access, and General Program Information
All written comments should identify the docket and notice numbers
stated in the heading of this notice. Anyone who wants confirmation of
mailed comments must include a self-addressed stamped postcard. To file
written comments electronically, after logging on to http://dms.dot.gov, click on ``ES Submit.'' You can also read comments and
other material in the docket at http://dms.dot.gov. General information
about our pipeline safety program is available at http://ops.dot.gov.
Background
NAPSR is a non-profit association of officials from State agencies
that participate with RSPA in the Federal pipeline safety regulatory
program. Each year NAPSR holds regional meetings to discuss safety and
administrative issues, culminating in resolutions for program
improvement.
In 1990 we asked NAPSR to review the gas pipeline safety standards
in 49 CFR part 192. The purpose of the review was to identify standards
that NAPSR considered insufficient for safety or not clear enough to
enforce. NAPSR compiled the results of its review in a report titled
``Report on Recommendations For Revision of 49 CFR part 192,'' dated
November 20, 1992. The report, a copy of which is in the docket of the
present proceeding, recommends changes to 40 sections in part 192.
By the time NAPSR completed its report, we had published a notice
of proposed rulemaking to change many part 192 standards that we
considered unclear or overly burdensome (Docket PS-124; 57 FR 39572;
Aug. 31, 1992). Because a few of NAPSR's recommendations related to
standards we had proposed to change, we published the report for
comment in the PS-124 proceeding (58 FR 59431; Nov. 9, 1993). The PS-
124 Final Rule (61 FR 28770; June 6, 1996) included four of NAPSR's
recommended rule changes, and we scheduled the remaining
recommendations for future consideration. Later, at a meeting on
corrosion problems held in San Antonio, Texas on April 28, 1999, we
opened NAPSR's recommendations on corrosion control to further public
discussion (Docket RSPA-97-2762; 64 FR 16885; April 7, 1999).
In PS-124 we received 79 comments on NAPSR's recommendations,
primarily from pipeline trade associations, pipeline operators, and
State pipeline safety agencies. Industry commenters generally opposed
most of NAPSR's recommendations on grounds that standards would be
changed not for safety reasons or clarity but to make compliance
auditing easier. In contrast, the State agencies generally supported
NAPSR's recommendations. NAPSR denied it was merely trying to simplify
the auditing process, and said its experience provided a unique
perspective on which standards are ineffective or inappropriate.
Because industry and State views were so divergent, in October
1997, the American Gas Association (AGA), the American Public Gas
Association (APGA), and NAPSR formed SIRRC to iron out their
differences over the recommendations. SIRRC agreed on all but eight of
the recommendations scheduled for future consideration. A copy of
SIRRC's report titled ``Summary Report,'' dated April 26, 1999, is in
the docket of the present proceeding.
We have completed our review of NAPSR's 1992 recommendations as
updated by SIRRC's 1999 Summary Report. The review also covered a NAPSR
resolution on the definition of ``service line.'' Although this
resolution was not in NAPSR's 1992 report, SIRRC dealt with the
resolution in it's Summary Report.
The purpose of the review was to decide which, if any, of NAPSR's
recommendations warrant inclusion in a notice of proposed rulemaking.
If SIRRC agreed to modify a recommendation, our review focused on that
modification. If SIRRC did not reach agreement, we focused on NAPSR's
recommendation in light of SIRRC's discussion. Our responses to the
recommendations are discussed in the next section of the preamble.
Disposition of NAPSR's Recommendations
This section summarizes NAPSR's recommendations and SIRRC's
consideration of those recommendations. It also states our responses to
the recommendations. For ease of reference, we have numbered the
recommendations according to their sequence in SIRRC's Summary Report.
The following table categorizes the recommendations according to the
rulemaking status indicated by our responses:
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Recommendation No. Rulemaking status
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7, 15, 17, 20, and 26.................. Included in previous final rule
actions.
8, 9, 30............................... Proposed in ``Periodic Updates
to Pipeline Safety Regulations
(1999)'' (Docket RSPA-99-6106;
56 FR 15290; Mar. 22, 2000).
[[Page 68816]]
2, 5, 6, 11, 12, 13, 14, 29 (in part), Proposed in present action.
31, 32, 35 18, 24, 25, 28, 33 (in Alternative proposed in
part) and 34 (in part). present action.
1, 3, 4, 10, 16, 19, 21, 22, 23, 27, 29 No rulemaking action.
(in part), 33 (in part), and 34 (in
part).
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1. Section 192.3, Definitions of Main and Transmission Line. (SIRRC
Summary Report, p. 3)
Recommendation. To help distinguish mains from transmission lines,
revise the definition of ``main'' and the first paragraph of the
definition of ``transmission line'' to read:
[sbull] ``Main'' means a pipeline installed in a community to
convey gas to individual service lines or to other mains.
[sbull] ``Transmission line'' means a pipeline, or a series of
pipelines, other than a gathering line, that: (a) Transports gas from a
gathering line, storage field or another transmission line to a storage
field or to one or more distribution systems or other load centers.
SIRRC. The committee reached consensus to modify the recommendation
as follows:
[sbull] ``Main'' means a segment of pipeline in a distribution
system installed to transport gas to individual service lines or other
mains.
[sbull] In the present definition of ``transmission line,'' change
``distribution center'' to ``distribution system'' to eliminate the
only use of this undefined term in Part 192.
Response: Part 192 defines ``distribution line'' but not
``distribution system.'' So substituting ``distribution system'' for
``distribution line'' in the present ``main'' definition and for
``distribution center'' in the present ``transmission line'' definition
would not necessarily add clarity to either definition. Also, by
referring to ``mains,'' SIRRC's definition of ``main'' loops back on
itself. Therefore, we are not proposing to adopt the SIRRC's
suggestion.
2. Section 192.3, Definitions of Service Line and Service Regulator.
(SIRRC Summary Report, p. 6)
Recommendation. Adopt the following new and amended definitions to
bring Part 192 in line with acceptable arrangements of service lines:
[sbull] ``Customer meter'' means the meter that measures the
transfer of gas from an operator to a consumer.
[sbull] ``Service line'' means a distribution line that transports
gas from a common source of supply to an individual customer, two
adjacent or adjoining residential or small commercial customers, or to
an aboveground meter header supplying up to ten residential or small
commercial customer meters. A service line terminates at the outlet of
the customer meter or at the connection to a customer's piping,
whichever is further downstream, or at the connection to customer
piping if there is no meter.
[sbull] ``Service regulator'' means the device on a service line
which controls the pressure of gas delivered from a high pressure
distribution system to the level at which it is provided to the
customer. A service regulator may serve one customer meter, or up to
ten customer meters grouped on an aboveground meter header.
SIRRC. The committee suggested modification of the definitions as
follows:
[sbull] ``Customer meter'' means the meter that measures the
transfer of gas from an operator to a consumer.
[sbull] ``Service line'' means a distribution line that transports
gas from a common source of supply to an individual customer, to two
adjacent or adjoining residential or small commercial customers, or to
multiple residential or small commercial customers served through a
meter header or manifold. A service line terminates at the outlet of
the customer meter or at the connection to a customer's piping,
whichever is further downstream, or at the connection to customer
piping if there is no meter.
[sbull] ``Service regulator'' means the device on a service line
which controls the pressure of gas delivered from a higher pressure to
the pressure provided to the customer. A service regulator may serve
one customer, or multiple customers through a meter header or manifold.
Response. Although Sec. 192.3 already defines the term ``customer
meter,'' the definition of this term is included in the definition of
``service line.'' SIRRC's suggestion would merely move the ``customer
meter'' definition to an alphabetical position in Sec. 192.3. Since
``customer meter'' is used in part 192 in places other than the
``service line'' definition, we agree that an alphabetical position is
preferable. So we are proposing to amend Sec. 192.3 as SIRRC
suggested.
Under the part 192 definitions of ``service line'' and ``main,'' if
an operator runs a single line from main to supply gas to two
customers, the single line is itself a main because it is a common
source of supply for more than one service line.\1\ Typically such
single-line installations serve two or more adjacent single-family
residences through branch lines connected to the single line. They also
serve apartment buildings and shopping centers through meter manifolds,
or meter headers.
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\1\ Section 192.3 defines ``service line'' as ``a distribution
line that transports gas from a common source of supply to (1) a
customer meter or the connection to a customer's piping, whichever
is farther downstream, or (2) the connection to a customer's piping
if there is no customer meter.'' In addition, ``main'' is defined as
``a distribution line that serves as a common source of supply for
more than one service line.''
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Because these single lines are more like service lines than mains--
their size is small, their pressure is low, and they are located on
private property rather than under a public street or alley--many State
pipeline safety agencies have granted waivers for the lines, permitting
operators to treat them as service lines. Consequently, under most
State waivers, the single lines may be designed, installed, operated,
and maintained as service lines. They do not have to meet any part 192
standard that applies strictly to mains. For example, Sec. 192.327(b)
requires a minimum burial depth for mains (24 in) that is greater than
the depth Sec. 192.361 requires for service lines (12 or 18 in).
Single-line installations serving adjacent customers may also increase
safety by minimizing connections to mains. These connections are
susceptible to leaks and damage accidentally caused by street
excavation activities.
Since SIRRC's suggested definition of ``service line'' is
consistent with State waivers we considered appropriate, we are
proposing to amend Sec. 192.3 by revising the definition of ``service
line'' as SIRRC suggested. Note, however, that the proposed definition
uses the general term ``meter manifold'' instead of ``meter header or
manifold.'' If adopted as final, the proposed definition would
eliminate the need for similar waivers in the future.
We are also proposing to adopt SIRRC's suggested definition of
``service regulator.'' SIRRC's definition is
[[Page 68817]]
consistent with state waivers that distinguish regulators connected to
customer meter manifolds from regulating stations that must be
inspected under Sec. 192.739.
We are particularly interested in receiving comments on how the
term ``small commercial customers'' might be stated differently or
defined to minimize potential confusion in identifying the customers
involved. Would it be appropriate to consider a ``small commercial
customer'' as a business that receives volumes of gas similar to the
volumes that a residential customer receives?
3. Section 192.55(a)(2), Steel Pipe. (SIRRC Summary Report, p. 8)
Recommendation. Delete Sec. 192.55(a)(2)(ii), which provides
requirements for the use of new steel pipe manufactured before November
12, 1970.
SIRRC. The committee suggested that Sec. 192.55(a)(2)(ii) should
not be deleted.
Response. Although NAPSR initially thought Sec. 192.55(a)(2)(ii)
was obsolete, several PS-124 commenters said the section should remain
because operators have stockpiles of steel pipe manufactured before
1970. The SIRRC Summary Report indicates operators continue to stock
such pipe. We concur with SIRRC that Sec. 192.55(a)(2)(ii) should not
be removed.
4. Section 192.65, Transportation of Pipe. (SIRRC Summary Report, p. 9)
Recommendation. Delete Sec. 192.65(b), which provides requirements
for the use of certain steel pipe transported by railroad before
November 12, 1970.
SIRRC. The committee agreed that Sec. 192.65(b) should not be
deleted.
Response. Although NAPSR initially thought Sec. 192.55(b) was
obsolete, several PS-124 commenters said they had stockpiled pipe
manufactured before 1970. In addition, the SIRRC Summary Report
indicates that operators still have this pipe and that it may have been
transported by railroad. We concur with the SIRRC's suggestion.
5. Section 192.123, Design Limitations for Plastic Pipe. (SIRRC Summary
Report p. 10)
Recommendation. Delete the second sentence of Sec.
192.123(b)(2)(i), which allows plastic pipe manufactured before May 18,
1978, and strength rated at 73 [deg]F to be used at temperatures up to
100 [deg]F.
SIRRC. The committee agreed that the second sentence of Sec.
192.123(b)(2)(i) should be deleted.
Response. NAPSR thought the second sentence of Sec.
192.123(b)(2)(i) was obsolete. However, the PS-124 comments indicated
that several utilities had inventories of plastic pipe manufactured
before May 18, 1978, that they intended to use as replacement pipe. In
contrast, the SIRRC Summary Report states that the committee members
were unaware of any pre-1978 plastic pipe in operators' stocks.
Moreover, the committee members had reservations about using plastic
pipe of that vintage.
Assuming the SIRRC Summary Report generally reflects the present
status of operators' stocks of plastic pipe, we are proposing to delete
the second sentence of Sec. 192.123(b)(2)(i) as obsolete. If this
proposal were adopted as final, any stockpiled pre-1978 thermoplastic
pipe whose long-term hydrostatic strength was determined at 73 [deg]F
could not be used above that temperature. We are particularly
interested in hearing from industry commenters whether they still have
any stockpiles of this pipe that they plan to use at temperatures above
73 [deg]F.
6. Section 192.197(a), Control of the Pressure of Gas Delivered From
High-pressure Distribution Systems. (SIRRC Summary Report, p. 11)
Recommendation. In Sec. 192.197(a), change ``under 60 psig'' to
``60 psig or less.''
SIRRC. The committee agreed that Sec. 192.197(a) should be changed
as NAPSR recommended.
Response. Section 192.197(a) provides that in distribution systems
operated ``under 60 psig (414 kPa) gage,'' if service regulators meet
certain criteria, no other pressure limiting devices are required.
However, Sec. 192.197(b) states that if those criteria are not met in
systems operating at ``60 psig (414 kPa) gage, or less,'' additional
pressure control is required. Thus there is a 1 psi discrepancy between
these two sections. We agree with SIRRC that Sec. 192.197(a) should be
in sync with Sec. 192.197(b), particularly since Sec. 192.197(c)
applies to systems in which the operating pressure ``exceeds 60 psig
(414 kPa) gage.'' Therefore, we are proposing to change Sec.
192.197(a) as NAPSR recommended.
7. Section 192.203(b)(2), Instrument, Control, and Sampling Pipe and
Components. (SIRRC Summary Report, p. 12)
Recommendation. In Sec. 192.203(b)(2), change ``takeoff line'' to
``instrument, control, and sampling line'' to clarify the lines on
which a shutoff valve must be installed.
SIRRC. The committee agreed the recommended change to Sec.
192.203(b)(2) is not needed.
Response. In Docket PS-124, we modified Sec. 192.203(b)(2) by
excepting takeoff lines that can be isolated from sources of pressure
by other valving. The SIRRC Summary Report indicates this exception
resolved NAPSR's concern about Sec. 192.203(b)(2). Therefore, we are
adopting the SIRRC consensus that the recommended rulemaking action is
not needed.
8. Section 192.225(a), Welding: General. (SIRRC Summary Report, p. 13)
Recommendation. Change Sec. 192.225(a) to require qualification of
welding procedures according to ``American Petroleum Institute (API),
American Society of Mechanical Engineers (ASME), or other standards.''
SIRRC. The committee agreed the recommended change is needed.
However, it suggested the term ``other standards'' should be changed to
``other accepted pipeline welding standards.''
Response. We proposed to adopt the core of NAPSR's recommendation
in the proceeding called ``Periodic Updates to Pipeline Safety
Regulations (1999)'' (56 FR 15290; Mar. 22, 2000). We proposed to amend
Sec. 192.225(a)to require operators to qualify welding procedures
under either Section 5 of API 1104, ``Welding of Pipelines and Related
Facilities,'' or Section IX of the ASME Boiler and Pressure Vessel
Code. However, our proposal did not include allowing the use of ``other
accepted pipeline welding standards,'' as SIRRC suggested, because we
are not aware of any other generally accepted pipeline welding
standards.
9. Section 192.241(a), Inspection and Test of Welds. (SIRRC Summary
Report, p. 14)
Recommendation. Change Sec. 192.241(a) to require that visual
inspection of welding be conducted ``by an inspector qualified by
appropriate training and experience.''
SIRRC. The committee agreed the recommended change is needed.
However, it suggested the term ``inspector'' should be changed to
``person.''
Response. In the proceeding called ``Periodic Updates to Pipeline
Safety Regulations (1999)'' (56 FR 15290; Mar. 22, 2000), we proposed
to amend Sec. 192.241(a) as NAPSR recommended. Although we overlooked
SIRRC's suggestion to use ``person'' instead of ``inspector,'' we will
consider the suggestion in developing the final rule.
[[Page 68818]]
10. Section 192.285(c) and (d), Plastic Pipe: Qualifying Persons to
Make Joints. (SIRRC Summary Report, p. 15)
Recommendation. In Sec. 192.285, revise paragraph(c) to require
that persons who join plastic pipe requalify annually to make joints.
Also, revise paragraph (d) to require that operators maintain certain
records for use in monitoring personnel qualifications.
SIRRC. The committee did not agree that NAPSR's recommended rule
changes were needed. However, the committee did agree that in Sec.
192.285(d) the term ``his'' should be replaced by a term that is not
gender-specific.
Response. NAPSR was concerned that while most newly installed
distribution lines are made of plastic pipe, the qualification
requirements for persons who join plastic pipe are less stringent than
the qualification requirements for persons who weld steel pipe. NAPSR
felt the plastic pipe joining and welder qualification requirements
should be comparable because the consequences of failure of a plastic
pipe joint may be just as severe as the consequences of failure of a
welded joint.
We do not believe NAPSR's reasoning is sufficient to justify
stronger plastic pipe joining requirements. The skill needed for
joining plastic pipe is so much simpler than the skill needed for
welding steel pipe that the welding requirements cannot reasonably
serve as a basis for establishing more stringent plastic pipe joining
requirements. Therefore, we are not proposing to adopt NAPSR's
recommended rule changes.
It is worth noting, though, that after SIRRC completed it's report,
we published new qualification of personnel rules in Subpart N of Part
192. The competency evaluations required by these rules should enhance
the qualifications of persons who make plastic pipe joints.
Section 192.285(d) now uses the term ``his.'' As SIRRC suggested,
we are proposing to change this term to ``the operator's.''
11. Section 192.311, Repair of Plastic Pipe. (SIRRC Summary Report, p.
18)
Recommendation. Remove the requirement from Sec. 192.311 that a
``patching saddle'' must be used to repair harmful damage to new
plastic pipelines if the damaged pipe is not removed.
SIRRC. The committee agreed the recommended change is needed.
Response. We concur with NAPSR that the meaning of ``patching
saddle'' is unclear, although we have stated the term implies a plastic
saddle adhered to pipe. Still, there are various means available to
effect safe repairs, and we do not think it's necessary to limit the
method of repair. Section 192.703(b) would forbid the use of any method
that would result in an unsafe condition. So we are proposing to amend
Sec. 192.311 as NAPSR recommended.
12. Section 192.321(e), Installation of Plastic Pipe; Sec. 192.361(g),
Service Lines: Installation. (SIRRC Summary Report, p. 19)
Recommendation. To prevent underground plastic pipe from being
damaged by electrically charged tracer wire and to maintain wire
integrity, require separation between pipe and wire, where practical,
and require that tracer wire be protected against corrosion.
SIRRC. The committee agreed to accept NAPSR's recommendation. It
also agreed that Sec. 192.321, which applies to mains and transmission
lines, and Sec. 192.361, which applies to service lines, should be
changed as follows:
[sbull] Revise Sec. 192.321(e) to read as follows:
(e) Plastic pipe that is not encased must have an electrically
conducting wire or other means of locating the pipe while it is
underground. Tracer wire shall not be wrapped around the pipe and
contact with the pipe shall be minimized. Tracer wire or other metallic
elements installed for pipe locating purposes shall be resistant to
corrosion damage, either by use of coated copper wire or by other
means.
[sbull] Establish Sec. 192.361(g) to match proposed Sec.
192.321(e).
Response. Although there have been only a few instances where
highly charged tracer wire damaged buried plastic pipe, we believe
separating wire from pipe wherever practical is a reasonable safeguard.
It is also reasonable that tracer wire or other metallic means of pipe
locating be resistant to corrosion. Therefore, we are proposing to
adopt SIRRC's consensus by revising Sec. 192.321(e) and adding Sec.
192.361(g) as set forth below in the proposed amendments section of
this notice.
We recognize that continuous separation may not be ensured when
wire and pipe are installed together in the same hole made by
trenchless technology. In fact, in such cases the wire is often
randomly taped to the pipe to control separation during installation.
The proposed requirement to minimize contact with the pipe should not
deter this common installation practice.
Note that part 192 does not now require that underground plastic
service lines have a means for locating the lines. However, operators
commonly use tracer wire for this purpose as they do under existing
Sec. 192.321(e) for locating underground plastic mains and
transmission lines.
13. Section 192.353(a), Customer Meters and Regulators: Location.
(SIRRC Summary Report, p. 21)
Recommendation. Amend Sec. 192.353(a) to emphasize that vehicular
damage is a type of damage from which meters and service regulators
must be protected.
SIRRC. Although the committee members agreed that the existing rule
implicitly requires protection from vehicular damage, they did not
agree on the need to emphasize this type of damage. Industry members
thought emphasizing vehicular damage would cause more disputes with
government inspectors over what level of protection is needed.
Response. In enforcing Sec. 192.353(a), our position has been that
the provision that meters and service regulators must be protected from
``corrosion and other damage'' requires reasonable protection from
vehicular damage where warranted. SIRRC's Summary Report supports this
position. Furthermore, AGA's ``Guide for Gas Transmission and
Distribution Piping Systems,'' which advises operators on compliance
with Part 192, recognizes this requirement. It states with regard to
Sec. 192.353(a) that if the potential for vehicular damage is evident,
the meter or service regulator should be protected or an alternate
location selected.
NAPSR reported that its members had found meter sets that were
damaged by vehicles or were at serious risk of such damage. When this
information is considered in light of the industry's apparent
understanding of the present rule, it indicates some operators may have
been lax in providing needed protection. Emphasizing vehicular damage
in the present rule should at least cause operators to pay more
attention to the problem and perhaps reduce the risk of damage. So we
are proposing to adopt NAPSR's recommendation by amending Sec.
192.353(a) to emphasize vehicular damage.
Although Sec. 192.353(a) affects design and does not apply to
pipelines constructed before it went into effect, protection from
vehicular damage is also a safety concern on earlier constructed
pipelines. These pipelines, however, are subject to the general
maintenance standard of Sec. 192.703(b), which requires operators to
correct any pipeline that becomes unsafe. If the safety of a meter set
is jeopardized by
[[Page 68819]]
vehicular traffic, the operator would have to take action under Sec.
192.703(b) to correct the problem.
14. Section 192.457(b)(3), External Corrosion Control: Buried or
Submerged Pipelines Installed Before August 1, 1971; 192.465(e),
External Corrosion Control: Monitoring. (SIRRC Summary Report, p. 23)
Recommendation. Amend Sec. Sec. 192.457(b) and Sec. 192.465(e) to
clarify the meaning of ``electrical survey'' and what circumstances
make an electrical survey ``impractical.'' Also, require operators to
consider all relevant information when using an alternative to an
electrical survey.
SIRRC. The committee concluded that electrical surveys are seldom
used on distribution systems, so there is no advantage to requiring
electrical surveys as a preferred corrosion inspection method on
distribution systems. SIRRC further concluded that if electrical
surveys are not used, all available information should be used to
determine if active corrosion exists. The committee agreed that the
second sentence of Sec. 192.457(b), as it relates to distribution
lines, and Sec. 192.465(e) should be changed to read as follows:
[sbull] Sec. 192.457(b):
The operator shall determine the areas of active corrosion by
electrical survey or by analysis and review of the pipeline condition.
Analysis and review shall include, but is not limited to, leak repair
history, exposed pipe condition reports, and the pipeline environment.
For the purpose of this section, an electrical survey is a series of
closely spaced pipe-to-soil readings over a pipeline which are
subsequently analyzed to identify any locations where a corrosive
current is leaving the pipe.
[sbull] Sec. 192.465(e):
(i) For transmission pipelines, after the initial evaluation
required by paragraphs (b) and (c) of Sec. 192.455 and paragraph (b)
of Sec. 192.457, each operator shall, not less than every 3 years at
intervals not exceeding 39 months, reevaluate its unprotected pipelines
and cathodically protect them in accordance with this subpart in areas
in which active corrosion is found. The operator shall determine the
areas of active corrosion by electrical survey, or where an electrical
survey is impractical, by analysis and review of the pipeline
condition. Analysis and review shall include, but is not limited to,
leak repair history, exposed pipe condition reports, and the pipeline
environment.
(ii) For distribution pipelines, after the initial evaluation
required by paragraphs (b) and (c) of Sec. 192.455 and paragraph (b)
of Sec. 192.457, each operator shall, not less than every 3 years at
intervals not exceeding 39 months, reevaluate its unprotected pipelines
and cathodically protect them in accordance with this subpart in areas
in which active corrosion is found. The operator shall determine the
areas of active corrosion by electrical survey or by analysis and
review of the pipeline condition. Analysis and review shall include,
but is not limited to, leak repair history, exposed pipe condition
reports, and the pipeline environment.
(iii) For the purpose of this section, an electrical survey is a
series of closely spaced pipe-to-soil readings over a pipeline which
are subsequently analyzed to identify any locations where a corrosive
current is leaving the pipe.
SIRRC also agreed that ``pipeline environment'' refers to whether
soil resistivity is high or low, wet or dry, contains contaminants that
may promote corrosion, or has any other known condition that might
influence the probability of active corrosion.
Response. We recently revised the corrosion control regulations for
hazardous liquid and carbon dioxide pipelines in 49 CFR part 195
(Docket RSPA-97-2762; 66 FR 66994; Dec. 27, 2001). In doing so, we
relied on SIRRC's suggestion on monitoring unprotected gas transmission
lines as a basis for revising the requirement to monitor unprotected
pipe (see 49 CFR 195.573(b)). Because we believe SIRRC's approach is
reasonable for both transmission and distribution lines, we are
proposing to adopt the SIRRC suggestion on monitoring these lines by
revising Sec. 192.465(e) as set forth below in the proposed amendments
section of this notice.
However, rather than change the second sentence of Sec. 192.457(b)
as SIRRC suggested, we are proposing to delete the second sentence
because we think it's unnecessary. This sentence, which is repeated in
Sec. 192.465(e), is no longer needed in Sec. 192.457(b) because the
time for completing the initial evaluation of the need for corrosion
control required by Sec. 192.457(b) has expired. All subsequent
evaluations are required by Sec. 192.465(e). Also, we are proposing to
move the definition of ``active corrosion,'' now in Sec. 192.457(c),
to Sec. 192.465(e).
15. Section 192.459, External Corrosion Control: Examination of Buried
Pipeline When Exposed. (SIRRC Summary Report, p. 27)
Recommendation. Amend Sec. 192.459 to clarify that when an
operator examines the exposed portion of a buried pipeline, the
operator must determine the condition of the coating and keep a record
of the condition under Sec. 192.491.
SIRRC. The committee agreed that records of coating condition are
important in evaluating the overall condition of a pipeline, and that
this information helps meet the continuing surveillance and active
corrosion rules. The committee suggested that Sec. 192.459 be revised
to read as follows:
Whenever an operator has knowledge that any portion of a buried
pipeline is exposed, the exposed portion must be examined to
determine the condition of the coating, or if the pipeline is bare
or the coating is deteriorated, the exterior condition of the pipe.
A record of the examination results shall be made in accordance with
Sec. 192.491(c). If external corrosion is found, remedial action
must be taken to the extent required by Sec. 192.483 and the
applicable paragraphs of Sec. Sec. 192.485, 192.487, or 192.489.
Response. In light of NAPSR's recommendation and an earlier
recommendation by the National Transportation Safety Board on
inspecting exposed pipe, we revised Sec. 192.459 to require that
operators determine the extent of any corrosion that is found on the
exposed portion of a pipeline (64 FR 56981, Oct. 22, 1999). At a
minimum, the present rule requires that operators inspect exposed
pipelines to see if the coating on coated pipe has deteriorated. In
addition, Sec. 192.491(c) requires a record of each inspection ``in
sufficient detail to demonstrate the adequacy of corrosion control
measures or that a corrosive condition does not exist.'' Thus we have
essentially adopted the SIRRC consensus, because the combination of
Sec. 192.459 and Sec. 192.491(c) adequately addresses the need to
examine and record the condition of coating on exposed coated pipe.
16. Section 192.467(d), External Corrosion Control: Electrical
Isolation (SIRRC Summary Report, p. 28)
Recommendation. Amend Sec. 192.467(d) to require annual electrical
tests on casings to determine if there is contact with the encased
pipe. Also, require remedial action according to Recommendation No. 19
if contact is found.
SIRRC. The committee did not reach agreement on the need to conduct
annual tests for shorted casings, although consensus was reached on
remedial action as discussed below regarding Recommendation No. 19.
Industry's position on annual testing was that separate tests on
casings are unnecessary as long as the pipe potential is above -850Mv.
NAPSR's position was that because a shorted
[[Page 68820]]
casing shields encased pipe from protective current, the encased pipe
can corrode regardless of the potential of pipe outside the casing.
Response. A large majority of PS-124 commenters opposed NAPSR's
recommendation on the ground that no correlation had been found between
shorted casings and corrosion of the encased pipe. One commenter
alleged that the purpose of Sec. 192.467(c), which requires isolation
of gas pipe from casings, is to maintain protective current levels.
Also, several commenters addressed the shorted casing issue in
response to our San Antonio meeting notice. Five persons said shorts
should be cleared because using more protective current to offset the
short could have adverse effects. Two other commenters said that
clearing shorts can be costly if the line must be taken out of service
or replaced, and that there is no consensus on the adequacy of other
remedial measures. Another San Antonio commenter suggested the present
electrical isolation requirement of Sec. 192.467(c) is not needed
since cathodic protection has to meet the part 192 criteria for
adequacy. In this regard, AGA's Gas Piping Technology Committee (GPTC)
has submitted a rulemaking petition to rescind the requirement to
isolate gas pipe from metallic casings, arguing there are no safety
benefit from clearing shorted casings.
Considering the conflicting opinions on the need to clear shorted
casings to prevent pipe corrosion, we have decided not to propose to
adopt NAPSR's recommendation for annual testing. Instead we will
consider the recommendation in a separate rulemaking proceeding called
``Pipeline Safety: Controlling Corrosion on Gas Pipelines'' (RIN 2137-
AD63). In that proceeding, we will examine the need to change part 192
to improve the industry's corrosion control practices in light of new
technology and the new requirements for hazardous liquid and carbon
dioxide pipelines in 49 CFR part 195.
Deferring the recommendation also will give us time to gather more
information on the shorted casing issue. We are particularly interested
in receiving comments from anyone who has empirical data on the
relation of shorted casings to pipe corrosion.
17. Section 192.475(c), Internal Corrosion Control: General. (SIRRC
Summary Report, p. 29)
Recommendation. Amend Sec. 192.475(c) to express the permissible
level of hydrogen sulfide in parts-per-million as well as grains.
SIRRC. The committee agreed no further rulemaking action is needed.
Response. The PS-124 Final Rule included NAPSR's recommended change
to Sec. 192.475(c).
18. Section 192.479, Atmospheric Corrosion Control: General. (SIRRC
Summary Report, p. 30)
Recommendation. Require all aboveground pipelines exposed to the
atmosphere to meet the same atmospheric corrosion control and remedial
requirements, no matter when the pipeline was installed.
SIRRC. The resolution of the committee was that all exposed
aboveground pipe should be subject to the same atmospheric protection
standards. The committee agreed that Sec. 192.479 should be revised to
read as follows, and explained that ``active corrosion'' does not
include non-damaging corrosive films:
(a) Each aboveground pipeline or portion of a pipeline that is
exposed to the atmosphere must be cleaned and either coated or jacketed
with a material suitable for the prevention of atmospheric corrosion.
An operator need not comply with this paragraph, if the operator can
demonstrate by test, investigation, or experience in the area of
application that active corrosion does not exist.
(b) If active corrosion is found on an aboveground pipeline or
portion of pipeline, the operator shall--
(1) take prompt remedial action consistent with the severity of the
corrosion to the extent required by the applicable paragraphs of
Sec. Sec. 192.485, 192.487, or 192.489; and
(2) clean and either coat or jacket the areas of atmospheric
corrosion with a material suitable for the prevention of atmospheric
corrosion.
Response. Section 192.479 prescribes atmospheric protection
requirements according to the date of pipeline installation. Pipelines
installed after July 31, 1971, must be entirely protected from
atmospheric corrosion, except where the operator can demonstrate that a
corrosive atmosphere does not exist. In contrast, pipelines installed
before August 1, 1971, need only be protected where atmospheric
corrosion has progressed to the point that remedial action is required
under Sec. 192.485, Sec. 192.487, or Sec. 192.489. Periodic
monitoring to determine the need for remedial action is required by
Sec. 192.481.
As previously stated, we recently revised the corrosion control
regulations in 49 CFR part 195 governing hazardous liquid and carbon
dioxide pipelines. The old rule on protection from atmospheric
corrosion (Sec. 195.416(i)) required full protection of all pipelines
exposed to the atmosphere, regardless of the date of installation.
Based on San Antonio comments that the old rule was overly burdensome,
we revised the rule to allow operators to avoid coating pipelines they
demonstrate will have either a light surface oxide (a non-damaging
corrosion film) or atmospheric corrosion that will not affect safe
operation before the next scheduled inspection (Sec. 195.581).
We believe Sec. 195.581 is consistent with SIRRC's suggested
change of Sec. 192.479. Section 195.581 requires the same level of
protection for old and new pipelines. Also the exceptions for a light
surface oxide and corrosion that will not need remedial action before
the next scheduled inspection are equivalent to SIRRC's exception of
non-active corrosion. One of our goals in revising the Part 195
corrosion control regulations was to establish similar corrosion
control requirements for gas and liquid pipelines wherever appropriate.
Therefore, in keeping with this goal, we are proposing to use Sec.
195.581 instead of SIRRC's suggestion as the basis for changing Sec.
192.479. The existing standards for remedial action, Sec. Sec.
192.485, 192.487, and 192.489, will provide a benchmark for any
demonstrations that protection is not required before the next
inspection.
NAPSR did not recommend any change to the periodic monitoring
requirements of Sec. 192.481. These requirements are comparable to the
monitoring requirements for hazardous liquid and carbon dioxide
pipelines under Sec. 195.583. Both sections require monitoring for
atmospheric corrosion at least every 3 years for onshore pipelines and
every year for offshore pipelines. And both sections require remedial
action if harmful atmospheric corrosion is found. However, Sec.
195.583 specifies particular pipeline features, such as soil-to-air
interfaces, that must be inspected, and specifies what remedial action
to take. Although these differences are minor, we think the monitoring
requirements for gas and hazardous liquid pipelines should be in
accord. Therefore, we are proposing to amend Sec. 192.481 to comport
with Sec. 195.583.
PS-124 commenters representing industry largely objected to NAPSR's
recommendation to treat old and new pipelines alike. They feared they
would have to fully protect all pre-August 1971 pipelines regardless of
whether harmful corrosion was present. However, there is no basis for
this concern under proposed Sec. 192.479. Operators would not have to
protect any pre-1971 pipeline or portion of pipeline for
[[Page 68821]]
which the operator demonstrates by test, investigation, or experience
appropriate to the environment of the pipeline that corrosion will only
be a light surface oxide or not affect safe operation before the next
scheduled inspection. We believe this approach is consistent with the
present rule.
19. Section 192.483(d), Remedial Measures: General. (SIRRC Summary
Report, p. 32)
Recommendation. Specify what operators must do to protect carrier
pipe when a shorted casing cannot be cleared.
SIRRC. The committee agreed that Sec. 192.483(d) should be
established to read as follows:
(d) If it is determined that a casing is electrically shorted to a
pipeline, the operator shall:
(1) Clear the short, if practical;
(2) Fill the casing with a corrosion inhibiting material;
(3) Monitor for leakage with leak detection equipment at least once
each calendar year with intervals not exceeding 15 months; or
(4) Conduct an initial inspection with an internal inspection
device capable of detecting external corrosion in a cased pipeline, and
repeat at least every 5 years at intervals not exceeding 63 months.
Response. As stated above in response to Recommendation No. 16,
there is conflicting information on the need to clear shorted casings.
Therefore, we are not now proposing to adopt SIRRC's suggested options
for dealing with shorted casings. Instead, as with Recommendation No.
16, we will consider this recommendation in a separate rulemaking
proceeding called ``Pipeline Safety: Controlling Corrosion on Gas
Pipelines'' (RIN 2137-AD63).
20. Section 192.483(e), Remedial Measures: General. (SIRRC Summary
Report, p. 34)
Recommendation. Amend Sec. 192.483 to refer to appropriate
consensus standards that are to be used in determining the remaining
strength of corroded pipe.
SIRRC. The committee agreed that further rulemaking action is not
needed.
Response. The Final Rule in Docket PS-124 covered NAPSR's
recommendation in an amendment to Sec. 192.485(c). Thus, we agree with
SIRRC that further action is not needed.
21. Section 192.489(b), Remedial Measures: Cast Iron and Ductile Iron
Pipe. (SIRRC Summary Report, p. 35)
Recommendation. Clarify that internal sealing of graphitized pipe
is not a method of strengthening the pipe.
SIRRC. The committee agreed that the problem of graphitization
should be addressed case-by-case rather than by changing Sec. 192.489
as NAPSR recommended.
Response. New technology may result in liners that strengthen as
well as seal pipe. Therefore, we agree with SIRRC that Sec. 192.489(b)
should not be changed as NAPSR recommended.
22. Sections 192.505(a) and 192.507, Test Requirements. (SIRRC Summary
Report, p. 36)
Recommendation. Amend Sec. Sec. 192.505 and 192.507 to clarify
that the test pressure must be high enough to substantiate the maximum
allowable operating pressure (MAOP) under Sec. 192.619(a)(2)(ii).
SIRRC. The committee did not reach an agreement on this
recommendation. NAPSR members contended some operators have not
substantiated MAOP because Sec. Sec. 192.505 and 192.507 do not
specify a minimum test pressure. On the other hand, industry members
thought that because Sec. 192.503(a)(1) already requires that pressure
tests substantiate MAOP under Sec. 192.619, there is no need to repeat
the requirement in Sec. Sec. 192.505 and 192.507.
Response. We addressed this issue once before. In 1988 we amended
Sec. 192.503(a)(1) specifically to indicate that Sec. 192.619
prescribes the minimum test pressure needed to substantiate MAOP (53 FR
1635). We think this earlier action adequately clarified the minimum
test pressures, and no further action is needed.
23. Sections 192.509(b) and 192.511(b) and (c), Test Requirements.
(SIRRC Summary Report, p. 37)
Recommendation. To establish consistent leak test pressures for
mains and service lines, require that non-plastic service lines
operated at less than 1 psig be tested to at least 10 psig. Also,
require that each main and service line operated at 1 psig or more be
tested to 90 psig or 1.5 times the intended operating pressure,
whichever is higher.
SIRRC. The committee did not reach a consensus on this
recommendation. Industry members were concerned that additional
equipment would be needed to test above 90 psig, and that testing
existing service lines at higher pressures (as when service is
reinstated or connected to a new main) could cause failures. NAPSR
countered that operators could use plastic pipe test equipment, and
that a test failure indicates the line is unsafe.
Response. NAPSR felt the minimum leak test pressures prescribed by
Sec. Sec. 192.509(b) and 192.511(b) and (c) for mains and service
lines should be the same because mains and service lines are operated
together. NAPSR also felt the resulting safety factors should not
diminish as operating pressures increase, as they do under the present
rules. Many PS-124 commenters, including some operators, agreed with
NAPSR. However, AGA and other operators said there is no need to leak
test steel mains and service lines operating at less than 100 psig at
1.5 times operating pressure. These commenters argued that the purpose
of leak tests is not to assure the pipeline is unlikely to fail at
operating pressure, but to verify that the pipeline does not leak.
The regulatory history does not explain why minimum leak test
pressures under Sec. Sec. 192.509(b) and 192.511(b) and (c) are not
consistent. Nevertheless, lack of consistency, by itself, does not
justify additional or more stringent test requirements. A link between
inconsistency and safety would be needed, and NAPSR did not establish
such a link. Also, because only tests for leaks rather than pipeline
integrity are at issue, we do not think safety factors are relevant to
determining if the present leak test pressures are appropriate.
Therefore, we are not proposing to adopt NAPSR's recommendation.
24. Section 192.517, Records. (SIRRC Summary Report, p. 39)
Recommendation. To aid compliance investigations, amend Sec.
192.517 to require that operators keep records of leak tests done under
Sec. 192.509 for pipelines to operate below 100 psig, of leak tests
done under Sec. 192.511 for service lines, and of leak tests done
under Sec. 192.513 for plastic pipelines.
SIRRC. The committee disagreed about what information is needed in
leak test records. Also, industry members were concerned that
distribution operators would have to keep a very large volume of
individual records of limited use.
Response. Section 192.517 requires operators to record certain
information about pressure tests done under Sec. Sec. 192.505 and
192.507 to qualify steel pipelines to operate at 100 psig or more.
NAPSR recommended that we extend this requirement to other pipelines
that are pressure tested for leaks. While a few PS-124 commenters
supported the recommendation, most did not. Those who opposed the
recommendation generally argued that since leak tests are not as
significant as tests done under Sec. Sec. 192.505 and 192.507, it is
unnecessary to maintain the same information about both types of tests.
[[Page 68822]]
Without appropriate records, government inspection personnel have a
difficult job of determining if required leak tests were indeed done.
They may have to interview witnesses or draw inferences from related
information. On the other hand, government's need for records must be
weighed against the burden on operators to produce and maintain the
records. By and large, PS-124 commenters and SIRRC industry members did
not object to keeping records of leak tests. In fact, the SIRRC Summary
Report states that keeping some type of leak test record is a common
industry practice. It was the extent and volume of the records that
SIRRC's industry members found objectionable.
In our view, NAPSR's recommended leak test records would be too
burdensome, because the safety significance of leak tests is less than
that of pressure tests done to establish the MAOP of pipelines
operating above 100 psig. At the same time, it seems that industry's
voluntary practices may satisfy the need for records to demonstrate
compliance with leak test requirements. Therefore, while we are not
proposing to adopt NAPSR's recommendation, we are proposing to amend
Sec. 192.517 to require that operators maintain a record of each test
required by Sec. Sec. 192.509, 192.511, and 192.513 for at least 5
years. This proposal should accommodate the industry's various
voluntary recordkeeping practices, and allow time for government
inspectors to view the records. The proposed rule would apply to leak
tests done after the rule takes effect.
25. Section 192.553, Uprating: General Requirements; Sec. 192.557
Uprating: Steel Pipelines to a Pressure That Will Produce a Hoop Stress
Less Than 30% of SMYS: Plastic, Cast Iron, and Ductile Iron Pipelines.
(SIRRC Summary Report, P. 41)
Recommendation. Clarify that Sec. 192.557 does not allow MAOP to
be increased without substantiation by pressure testing.
SIRRC. The committee did not reach a resolution on this
recommendation. Industry members were concerned that NAPSR's
recommended changes to Sec. 192.557 would unintentionally prohibit the
uprating of some pipelines that could be uprated under the present
rule. However, the committee did agree that in Sec. 192.553(d) the
reference to ``this part'' should be changed to ``Sec. Sec. 192.619
and 192.621'' to specify the sections that limit MAOP.
Response. We decided not to propose to adopt NAPSR's recommendation
because we feel the requirement to base any increase in MAOP on a test
pressure is clear under Sec. 192.553(d). This section limits any
increase in MAOP to the maximum allowed for new pipelines, which, under
Sec. 192.619(a)(2)(ii), must be based on a pressure test. However, we
are proposing to adopt SIRRC's suggested change to clarify Sec.
192.553(d).
26. Section 192.607, Determination of Class Location and Confirmation
of Maximum Allowable Operating Pressure. (SIRRC Summary Report, p. 43)
Recommendation. Remove expired compliance deadlines from Sec.
192.607.
SIRRC. The committee agreed the recommendation was no longer
needed.
Response. The Final Rule in PS-124 repealed Sec. 192.607.
27. Section 192.614(b)(2), Damage Prevention Program. (SIRRC Summary
Report, p. 44)
Recommendation. Require that operators notify the public and known
excavators about excavation damage prevention programs at least once a
year.
SIRRC. The committee agreed to defer the recommendation to RSPA's
damage prevention improvement team. (The work of that team has been
assumed by the Dig Safely division of the Common Ground Alliance, a
nonprofit organization that promotes best practices in damage
prevention.)
Response. The present rule requires operators to notify the public
and known excavators ``as often as needed'' to make them aware of the
operator's program. This open-ended frequency permits operators to vary
the timing and number of notices to recipients according to the results
of their programs. Presumably fewer notices would be needed in an area
where the incidence of excavation damage is low or dropping.
Conversely, more would be needed if the incidence is high or
increasing. Although NAPSR felt the rule should prescribe a minimum
rate of notification, it did not explain why annual notification is
appropriate in all situations. And we do not have data to support such
an across-the-board rule change. Nevertheless, we think NAPSR's concern
is mitigated by the authority of RSPA and state agencies under Sec.
192.603(c) to require operators to modify their damage prevention
procedures on a case-by-case basis as needed for safety. Meanwhile, we
are working with the Common Ground Alliance to help operators improve
their public education programs. If the need for rulemaking on
notification frequency becomes apparent as a result of that effort, we
will propose the necessary rule changes.
28. Section 192.615(a)(3)(i), Emergency Plans. (SIRRC Summary Report,
p. 45)
Recommendation. Amend Sec. 192.615(a)(3)(i) to require that
operators' procedures for handling emergencies provide for prompt and
effective response to reports of gas odor inside or near buildings.
SIRRC. The committee did not reach consensus on the recommended
change to Sec. 192.615(a)(3)(i), because many operators consider gas-
odor reports to be potential, but not actual, emergencies. Instead, the
committee agreed that operating and maintenance manuals under Sec.
192.605(b) are a better place for procedures on responding to gas-odor
reports.
Response. We agree that not all reports of gas odor indicate that
gas has actually been detected. Some reports may merely indicate that
someone smells what is thought to be gas but which upon investigation
cannot be confirmed as gas. If operators had to treat all reports of
gas odor as emergencies, their ability to respond to true emergencies
might decline. Thus we are not proposing to adopt NAPSR's
recommendation.
Regardless of whether a gas odor report is an emergency, both PS-
124 commenters and SIRRC recognized the need for prompt investigation
of gas odor reports to determine if a hazardous situation exists. We
believe that by and large operators respond promptly to gas odor
reports and have procedures for doing so. Nevertheless, to insure that
operators have adequate procedures for responding promptly to gas odor
reports, we are proposing to adopt SIRRC's suggested alternative by
establishing Sec. 192.605(b)(11). Because some operators may prefer to
apply their emergency procedures to all reports of gas odor, the
proposed rule allows them to do so.
29. Section 192.625 (f), Odorization of Gas. (SIRRC Summary Report, p.
47)
Recommendation. Require that operators sample gas to assure proper
odorant concentration at least six times a year with an instrument
capable of determining the percentage of gas in air.
SIRRC. The committee did not agree on the frequency of sampling.
Industry members wanted to maintain the flexibility of the current
rule, which allows operators to determine frequency based on need.
NAPSR members wanted to add certainty to the rule by requiring a
sampling frequency that is in keeping with common practice.
[[Page 68823]]
Nevertheless, the members did agree the rule should require use of
an instrument, although they recognized that sampling for odorant
concentration could not be done without an instrument. They also agreed
the master meter exception should be relocated to minimize the
potential for confusion over the acceptability of using ``sniff''
tests.
Response. The present rule requires operators to conduct periodic
sampling to assure the proper concentration of odorant. However,
operators of master meter systems (which exist mainly in mobile home
parks and multifamily housing) do not have to conduct sampling if the
operator verifies the system receives properly odorized gas and
performs ``sniff'' tests to confirm the presence of odorant at the ends
of the system.
NAPSR intended its recommendation to address two concerns. The
first was that some operators, other than master meter operators, used
``sniff'' tests rather than instruments to determine odorant
concentration. The second was that the required sampling frequency is
vague. Regarding the first concern, both PS-124 commenters and SIRRC
recognized that the present sampling requirement cannot be satisfied
without using an appropriate test instrument. Indeed we believe use of
an instrument is common industry practice, because a sniff test cannot
accurately determine the concentration of odorant. Therefore, we are
proposing to amend Sec. 192.625(f) to state specifically that an
instrument must be used to determine odorant concentration. In
addition, we are not proposing to relocate the master meter exception,
because we do not think its present location confuses the acceptable
use of ``sniff'' tests.
As to NAPSR's second concern, we are certainly mindful of the
importance of clarity in regulations. Yet we are uneasy about proposing
a minimum sampling frequency that is not backed by consensus or a
safety justification that supports the frequency. At the same time, we
are persuaded by PS-124 commenters and SIRRC's industry members' view
that sampling frequency is more appropriately determined on the basis
of system conditions. A system might need sampling more often than six
times a year in problem locations but less often at locations where
odorant concentration consistently meets requirements. Also, under
Sec. 192.605(b)(1), each operator's operating and maintenance
procedures must provide odorant sampling frequencies, and operators
must be able to justify the frequencies. Finally, under Sec.
192.603(c), government regulators are authorized to challenge any
sampling frequencies they consider deficient on the basis of safety
data. They may also require operators to amend their procedures after
considering any relevant information the operator provides. We believe
this review and amendment process serves as a check on any possible
misuse of sampling flexibility. Therefore, we are not proposing to
establish a minimum sampling frequency.
30. Section 192.723(b)(2), Distribution Systems: Leak Surveys. (SIRRC
Summary Report, p. 49)
Recommendation. Amend Sec. 192.723(b)(2) to allow leeway in
meeting the leakage survey intervals.
SIRRC. The committee members agreed that NAPSR's recommendation was
appropriate.
Response. In the proceeding called ``Periodic Updates to Pipeline
Safety Regulations (1999)'' (56 FR 15290; Mar. 22, 2000), we proposed
to amend Sec. 192.723(b)(2) as NAPSR recommended.
31. Section 192.739(c), Pressure Limiting and Regulating Stations:
Inspection and Testing; Sec. 192.743(c), Pressure Limiting and
Regulating Stations: Testing of Relief Devices. (SIRRC Summary Report,
p. 50)
Recommendation. Clarify the meaning of ``correct pressure'' in
Sec. 192.739(c) and ``insufficient capacity'' in Sec. 192.743(c) by
cross-referencing Sec. 192.201, which limits the overpressure of
pipelines protected by pressure relieving and limiting stations.
SIRRC. The committee agreed that both sections should cross-
reference Sec. 192.201. However, the committee revised NAPSR's
recommended wording to clarify that the set point of overpressure
protective devices may be above the downstream MAOP.
Response. We are proposing to change Sec. Sec. 192.739(c) and
192.743(c) consistent with SIRRC's suggestions. The proposed changes
would require that relief devices at existing pressure limiting and
regulating stations meet the same standards for operation and relieving
capacity as newly installed relief devices. The PS-124 comments and
SIRRC's perspective indicate that industry practices are generally in
accord with this approach to compliance with Sec. Sec. 192.739(c) and
192.743(c). So we believe the proposed changes would clarify these
regulations and not add significantly to the costs of compliance.
32. Section 192.743(a) and (b), Pressure Limiting and Regulating
Stations: Testing of Relief Devices. (SIRRC Summary Report, p. 52)
Recommendation. In view of the disadvantages of testing relief
devices in place (cost, noise, and potential safety hazards from
escaping gas), change Sec. 192.743 to allow operators to use
calculations to determine if relief devices are of sufficient capacity
without first having to determine that testing the devices in place is
not feasible.
SIRRC. The committee members agreed to accept NAPSR's
recommendation.
Response. Under the present rule, operators may not use
calculations to determine necessary relief capacity until they
determine that testing existing relief devices in place is not
feasible. In addition to SIRRC, most PS-124 commenters supported
NAPSR's recommendation. For the reasons NAPSR advanced, we also believe
the recommended change is appropriate. Therefore, we are proposing to
change Sec. Sec. 192.743(a) and (b) to remove the present preference
for testing relief devices in place.
33. Section 192.745, Valve Maintenance: Transmission Lines. (SIRRC
Summary Report, p. 53)
Recommendation. For each transmission line valve inspected under
Sec. 192.745, require that operators take immediate remedial action on
any valve found to be inoperable, inaccessible, improperly supported,
subject to external loads or unusual stresses, or inadequately
protected from unauthorized operation, tampering, or damage.
SIRRC. The committee did not reach a resolution on this
recommendation. Industry members questioned the need for the
recommended changes.
Response. Section 192.745 requires annual inspection of
transmission line valves that might be needed during an emergency.
Because Sec. 192.745 requires each inspection to include partial
operation of the valve, there is no question operators must maintain
these valves in an operable condition.
Section 192.745 does not regulate how soon a valve must be
corrected if it is found inoperable. NAPSR recommended immediate
remedial action. Most PS-124 industry commenters preferred to act ``as
soon as practical,'' so they would not have to disrupt other essential
services. But NAPSR did not think this phrase reflected the urgency of
the situation.
In the absence of a specified time limit for remedial action,
operators may
[[Page 68824]]
take a reasonable time. Although a reasonable time may be satisfactory
for some maintenance duties, we agree with NAPSR that emergency valves
found inoperable need priority attention. Therefore, we are proposing
to amend Sec. 192.745 to require operators to take prompt remedial
action if any valve is found inoperable. Requiring prompt action rather
than immediate action should allow operators the latitude they sought
in scheduling maintenance activities, yet assure a timely response.
Part 192 design and construction regulations already address most
of NAPSR's other objectives. For instance, Sec. 192.179(b), a design
rule, requires that onshore transmission line block valves be readily
accessible, protected from tampering and damage, and adequately
supported. In addition, Sec. 192.317, a construction rule, requires
protection of transmission lines from external loads and unusual
stresses. Moreover, if for any reason an emergency valve becomes
unsafe, such as by damage or loss of support, Sec. 192.703(b) would
require remedial action. While Sec. 192.703 does not establish a time
limit for remedial action, we think a reasonable time is sufficient for
any deficiency that does not make the valve inoperable. Therefore, we
are not proposing to adopt NAPSR's recommendation to shorten the
allowable response time to deficiencies that do not make an emergency
valve inoperable.
Part 192 does not regulate the protection of transmission line
valves from unauthorized operation. However, operators commonly provide
valve security. And unauthorized operation of valves has not been a
significant problem on transmission lines. Also, operators of large
systems can detect unauthorized operation of valves through monitoring
of system pressures. Following the events of September 11, 2001, we
began working with operators and other federal agencies to consider the
need to improve the security of critical pipeline facilities. Given
these circumstances, we are not now proposing to regulate the
unauthorized operation of transmission line valves.
34. Section 192.747 Valve Maintenance: Distribution Systems. (SIRRC
Summary Report, p. 54)
Recommendation. Change Sec. 192.747, which requires annual
inspection and servicing of each valve that may be needed for safe
operation of a distribution system, to apply only to valves that
operators designate for use in an emergency. Also, require partial
operation of each emergency valve, and immediate remedial action if the
valve is found to be inoperable, inaccessible, improperly supported,
subject to external loads or unusual stresses, or inadequately
protected from unauthorized operation, tampering, or damage.
SIRRC. Although the committee did not reach consensus on this
recommendation, it agreed that remediation could include designation of
an alternate emergency valve. Industry members were particularly
concerned that partial operation could cause some valves to close
inadvertently, with potentially dangerous consequences, and could
damage valves not designed for frequent operation.
Response. NAPSR's rationale for limiting the present rule to
designated emergency valves was to make clear which valves are to be
inspected. However, we think Sec. 192.605(b)(1), which requires
operators to have procedures for complying with Sec. 192.747,
adequately addresses NAPSR's concern. Operators' procedures should not
only explain how to inspect and service valves, but also identify which
valves are to be inspected and serviced. In addition, valves intended
for safe operation of a distribution system may not be the same valves
operators might designate for use in an emergency. So limiting the
present rule to emergency valves for the sake of clarity could
inadvertently narrow the rule.
Still we think that any valve that may be needed for safe operation
of a distribution system should receive priority attention if it is
found inoperable. Therefore, we are proposing to amend Sec. 192.747 to
require prompt remedial action if any such valve is found inoperable,
unless the operator designates an alternate valve. For the reasons
stated above in response to Recommendation No. 33, we are not proposing
to adopt NAPSR's recommendation to require immediate remedial action on
deficient valves that remain operable. Further, because of the
possibility of adverse consequences to the valve or others, we are not
proposing to require partial operation of valves.
The accessibility of distribution system valves has been a safety
problem in some situations. For instance, if a valve essential to stop
the flow of gas in an emergency is found to be paved over, the
resulting delay in operating the valve can worsen the emergency. We
think Sec. 192.605(b)(1) addresses this problem. This rule requires
distribution operators to have and follow procedures to carry out the
safety valve maintenance requirements of Sec. 192.747. And these
procedures should identify which distribution system valves are subject
to Sec. 192.747. If an identified safety valve is paved over without
notice between annual inspections, the operator should discover the
problem no later than the next annual inspection. At that time the
operator would have to either correct the problem in order to carry out
the inspection or revise its procedures to designate an alternative
safety valve.
35. Section 192.753, Caulked Bell and Spigot Joints. (SIRRC Summary
Report, p. 57)
Recommendation. Correct the conflict between Sec. 192.621(a)(3),
which allows a pressure as high as 25 psig in cast iron pipe with
unreinforced bell and spigot joints, and Sec. 192.753(a), which
requires cast-iron bell and spigot joints subject to pressures of 25
psig or more to be sealed.
SIRRC. The committee members agreed the conflict should be
corrected.
Response. We are proposing to change Sec. 192.753 to remove the
conflict.
Regulatory Analyses and Notices
Executive Order 12866 and DOT Policies and Procedures
RSPA does not consider this proposed rulemaking to be a significant
regulatory action under Section 3(f) of Executive Order 12866 (58 FR
51735; Oct. 4, 1993). Therefore, the Office of Management and Budget
(OMB) has not received a copy of this rulemaking to review. RSPA also
does not consider this proposed rulemaking to be significant under DOT
regulatory policies and procedures (44 FR 11034: February 26, 1979).
We prepared a Draft Regulatory Evaluation of the proposed rules,
and a copy is in the docket. This regulatory evaluation concludes that
the proposed changes to existing rules may actually reduce operators'
costs to comply with those rules because some proposals have compliance
options. If you disagree with this conclusion, please provide
information to the public docket described above.
Regulatory Flexibility Act
The proposed rules are consistent with customary practices in the
gas pipeline industry. Therefore, based on the facts available about
the anticipated impacts of this proposed rulemaking, I certify,
pursuant to Section 605 of the Regulatory Flexibility Act (5 U.S.C.
605), that this proposed rulemaking would not have a significant impact
on a substantial number of small entities. If you have any information
that this conclusion about the impact on small
[[Page 68825]]
entities is not correct, please provide that information to the public
docket described above.
Executive Order 13084
The proposed rules have been analyzed in accordance with the
principles and criteria contained in Executive Order 13084,
``Consultation and Coordination with Indian Tribal Governments.''
Because the proposed rules would not significantly or uniquely affect
the communities of the Indian tribal governments and would not impose
substantial direct compliance costs, the funding and consultation
requirements of Executive Order 13084 do not apply.
Paperwork Reduction Act
Proposed Sec. Sec. 192.517(b) and 192.605(b)(11) contain minor
additional information collection requirements. Operators would be
required under Sec. 192.517(b) to maintain for 5 years records of
certain leak tests, and under Sec. 192.605(b)(11) to have procedures
for responding promptly to a report of gas odor inside or near a
building. However, we believe most operators already maintain records
of leak tests and have procedures for responding to reports of gas odor
inside or near buildings. Also, we believe the burden of retaining
these records is minimal. These records are largely computerized.
Maintaining these records on a floppy disk or computer file represents
very minimal costs. So, because the additional paperwork burdens of
this proposed rule are likely to be minimal, we believe that submitting
an analysis of the burdens to OMB under the Paperwork Reduction Act is
unnecessary. If you disagree with this conclusion, please submit your
comments to the public docket.
Unfunded Mandates Reform Act of 1995
This proposed rulemaking would not impose unfunded mandates under
the Unfunded Mandates Reform Act of 1995. It would not result in costs
of $100 million or more to either State, local, or tribal governments,
in the aggregate, or to the private sector, and would be the least
burdensome alternative that achieves the objective of the rule.
National Environmental Policy Act
We have analyzed the proposed rules for purposes of the National
Environmental Policy Act (42 U.S.C. 4321 et seq.). Because the proposed
rules parallel present requirements or practices, we have preliminarily
determined that the proposed rules would not significantly affect the
quality of the human environment. An environmental assessment document
is available for review in the docket. A final determination on
environmental impact will be made after the end of the comment period.
If you disagree with our preliminary conclusion, please submit your
comments to the docket as described above.
Impact on Business Processes and Computer Systems
We do not want to impose new requirements that would mandate
business process changes when the resources necessary to implement
those requirements would otherwise be applied to ``Y2K'' or related
computer problems. The proposed rules would not mandate business
process changes or require modifications to computer systems. Because
the proposed rules would not affect the ability of organizations to
respond to those problems, we are not proposing to delay the
effectiveness of the requirements.
Executive Order 13132
The proposed rules have been analyzed in accordance with the
principles and criteria contained in Executive Order 13132
(``Federalism''). The proposed rules do not propose any regulation
that: (1) Has substantial direct effects on the States, the
relationship between the National government and the States, or the
distribution of power and responsibilities among the various levels of
government; (2) imposes substantial direct compliance costs on State
and local governments; or (3) preempts state law. Therefore, the
consultation and funding requirements of Executive Order 13132 do not
apply.
List of Subjects in 49 CFR Part 192
Natural gas, Pipeline safety, Reporting and recordkeeping
requirements.
For the reasons discussed in the preamble, RSPA proposes to amend
49 CFR part 192 as follows:
PART 192--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE:
MINIMUM FEDERAL SAFETY STANDARDS
1. The authority citation for part 192 continues to read as
follows:
Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110,
60113, and 60118; and 49 CFR 1.53.
2. Amend Sec. 192.3 by adding definitions of ``customer meter''
and ``service regulator'' and by revising the definition of ``service
line'' as follows:
Sec. 192.3 Definitions.
* * * * *
``Customer meter'' means the meter that measures the transfer of
gas from an operator to a consumer.
* * * * *
``Service line'' means a distribution line that transports gas from
a common source of supply to an individual customer, to two adjacent or
adjoining residential or small commercial customers, or to multiple
residential or small commercial customers served through a meter
manifold. A service line terminates at the outlet of the customer meter
or at the connection to a customer's piping, whichever is further
downstream, or at the connection to customer piping if there is no
meter.
``Service regulator'' means the device on a service line which
controls the pressure of gas delivered from a higher pressure to the
pressure provided to the customer. A service regulator may serve one
customer or multiple customers through a meter header or manifold.
* * * * *
Sec. 192.123 [Amended]
3. Remove the second sentence in Sec. 192.123(b)(2)(i).
Sec. 192.197 [Amended]
4. In Sec. 192.197(a), remove the term ``under 60 p.s.i. (414 kPa)
gage'' and add the term ``60 psi (414 kPa) gage, or less,'' in its
place.
Sec. 192.285 [Amended]
5. In Sec. 192.285(d), remove the term ``his'' and add the term
``the operator's'' in its place.
6. Revise Sec. 192.311 to read as follows:
Sec. 192.311 Repair of plastic pipe.
Each imperfection or damage that would impair the serviceability of
plastic pipe must be repaired or removed.
7. Revise Sec. 192.321(e) to read as follows:
Sec. 192.321 Installation of plastic pipe.
* * * * *
(e) Plastic pipe that is not encased must have an electrically
conducting wire or other means of locating the pipe while it is
underground. Tracer wire may not be wrapped around the pipe and contact
with the pipe must be minimized. Tracer wire or other metallic elements
installed for pipe locating purposes must be resistant to corrosion
damage, either by use of coated copper wire or by other means.
* * * * *
8. Revise the first sentence of Sec. 192.353(a) to read as
follows:
[[Page 68826]]
Sec. 192.353 Customer meters and regulators: Location.
(a) Each meter and service regulator, whether inside or outside of
a building, must be installed in a readily accessible location and be
protected from corrosion, vehicular, and other damage. * * *
* * * * *
9. Add Sec. 192.361(g) to read as follows:
Sec. 192.361 Service lines: Installation.
* * * * *
(g) Locating underground service lines. Each underground service
line that is not encased must have a means of locating the pipe that
complies with Sec. 192.321(e).
Sec. 192.457 [Amended]
10. Amend Sec. 192.457 as follows:
a. Remove the second sentence in paragraph (b)(3); and
b. Remove paragraph (c).
11. Revise Sec. 192.465(e) to read as follows:
Sec. 192.465 External corrosion control: Monitoring.
* * * * *
(e) After the initial evaluation required by Sec. Sec. 192.455(b)
and (c) and 192.457(b), each operator must, not less than every 3 years
at intervals not exceeding 39 months, reevaluate its unprotected
pipelines and cathodically protect them in accordance with this subpart
in areas in which active corrosion is found. The operator must
determine the areas of active corrosion by electrical survey. However,
on distribution lines and where an electrical survey is impractical on
transmission lines, areas of active corrosion may be determined by
other means that include review and analysis of leak repair and
inspection records, corrosion monitoring records, exposed pipe
inspection records, and the pipeline environment. In this section:
(1) Active corrosion means continuing corrosion which, unless
controlled, could result in a condition that is detrimental to public
safety or the environment.
(2) Electrical survey means a series of closely spaced pipe-to-soil
readings over a pipeline that are subsequently analyzed to identify
locations where a corrosive current is leaving the pipeline.
(3) Pipeline environment includes soil resistivity (high or low),
soil moisture (wet or dry), soil contaminants that may promote
corrosive activity, and other known conditions that could affect the
probability of active corrosion.
12. Revise Sec. 192.479 to read as follows:
Sec. 192.479 Atmospheric corrosion control: General.
(a) Each operator must clean and coat each pipeline or portion of
pipeline that is exposed to the atmosphere, except pipelines under
paragraph (c) of this section.
(b) Coating material must be suitable for the prevention of
atmospheric corrosion.
(c) Except portions of pipelines in offshore splash zones or soil-
to-air interfaces, the operator need not protect against atmospheric
corrosion any pipeline for which the operator demonstrates by test,
investigation, or experience appropriate to the environment of the
pipeline that corrosion will--
(1) Only be a light surface oxide; or
(2) Not affect the safe operation of the pipeline before the next
scheduled inspection.
13. Revise Sec. 192.481 to read as follows:
Sec. 192.481 Atmospheric corrosion control: Monitoring.
(a) Each operator must inspect each pipeline or portion of pipeline
that is exposed to the atmosphere for evidence of atmospheric
corrosion, as follows:
------------------------------------------------------------------------
------------------------------------------------------------------------
(1) If the pipeline is located: Then the frequency of
inspection is:
(2) Onshore............................. At least once every 3
calendar years, but with
intervals not exceeding 39
months
(3) Offshore............................ At least once each calendar
year, but with intervals
not exceeding 15 months.
------------------------------------------------------------------------
(b) During inspections the operator must give particular attention
to pipe at soil-to-air interfaces, under thermal insulation, under
disbonded coatings, at pipe supports, in splash zones, at deck
penetrations, and in spans over water.
(c) If atmospheric corrosion is found during an inspection, the
operator must provide protection against the corrosion as required by
Sec. 192.479.
14. Amend Sec. 192.517 as follows:
a. Designate the introductory text as paragraph (a);
b. In newly designated paragraph (a), redesignate paragraphs (a),
(b), (c), (d), (e), (f), and (g) as (a)(1), (2), (3), (4), (5), (6),
and (7), respectively; and
c. Add paragraph (b) to read as follows:
Sec. 192.517 Records.
* * * * *
(b) Each operator must maintain a record of each test required by
Sec. Sec. 192.509, 192.511, and 192.513 for at least 5 years.
15. In the first sentence in Sec. 192.553(d), remove the term
``this part'' and add the term ``Sec. Sec. 192.619 and 192.621'' in
its place.
16. Add Sec. 192.605(b)(11) to read as follows:
Sec. 192.605 Procedural manual for operations, maintenance, and
emergencies.
* * * * *
(b) * * *
(11) Responding promptly to a report of gas odor inside or near a
building, unless the operator's emergency procedures under Sec.
192.615(a)(3) specifically apply to these reports.
* * * * *
17. Revise the first sentence of Sec. 192.625(f) introductory text
to read as follows:
Sec. 192.625 Odorization of gas.
* * * * *
(f) To assure the proper concentration of odorant in accordance
with this section, each operator must conduct periodic sampling of
combustible gases using an instrument capable of determining the
percentage of gas in air at which the odor becomes readily detectable.
* * *
* * * * *
18. Revise Sec. 192.739(c) to read as follows:
Sec. 192.739 Pressure limiting and regulating stations: Inspection
and testing.
* * * * *
(c) Set to control or relieve at the correct pressures consistent
with the pressure limits of Sec. 192.201(a); and
* * * * *
19. Revise Sec. 192.743 to read as follows:
Sec. 192.743 Pressure limiting and regulating stations: Capacity of
relief devices.
(a) Pressure relief devices at pressure limiting stations and
pressure regulating stations must have sufficient capacity to protect
the facilities to which they are connected consistent with the pressure
limits of Sec. 192.201(a). This capacity must be determined at
intervals not exceeding 15 months, but at least once each calendar
year, by testing the devices in place or by review and calculations.
(b) If review and calculations are used to determine if a device
has sufficient capacity, the calculated capacity must be compared with
the rated or experimentally determined relieving capacity of the device
for the conditions under which it operates. After the initial
calculations, subsequent calculations need not be made if the annual
review documents that parameters have not changed so as to cause the
rated or
[[Page 68827]]
experimentally determined relieving capacity to be insufficient.
(c) If a relief device is of insufficient capacity, a new or
additional device must be installed to provide the capacity required by
paragraph (a) of this section.
20. Amend Sec. 192.745 as follows:
a. Designate the existing text as paragraph (a); and
b. Add paragraph (b) to read as follows:
Sec. 192.745 Valve maintenance: Transmission lines.
* * * * *
(b) Each operator must take prompt remedial action to correct any
valve found inoperable.
21. Amend Sec. 192.747 as follows:
a. Designate the existing text as paragraph (a); and
b. Add paragraph (b) to read as follows:
Sec. 192.747 Valve maintenance: Distribution systems.
* * * * *
(b) Each operator must take prompt remedial action to correct any
valve found inoperable, unless the operator designates an alternate
valve.
22. In Sec. 192.753, revise the introductory text of paragraph (a)
and revise paragraph (b) to read as follows:
Sec. 192.753 Caulked bell and spigot joints.
(a) Each cast iron caulked bell and spigot joint that is subject to
pressures of more than 25 psi (172kPa) gage must be sealed with:
* * * * *
(b) Each cast iron caulked bell and spigot joint that is subject to
pressures of 25 psi (172kPa) gage or less and is exposed for any reason
must be sealed by a means other than caulking.
Issued in Washington, DC, on October 31, 2002.
Stacey L. Gerard,
Associate Administrator for Pipeline Safety.
[FR Doc. 02-28240 Filed 11-12-02; 8:45 am]
BILLING CODE 4910-60-P