[Federal Register Volume 61, Number 110 (Thursday, June 6, 1996)]
[Rules and Regulations]
[Pages 28770-28786]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-13787]
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DEPARTMENT OF TRANSPORTATION
Research and Special Programs Administration
49 CFR Part 192
[Docket PS-124; Amdt. 192-76]
RIN 2137-AC25
Regulatory Review; Gas Pipeline Safety Standards
AGENCY: Research and Special Programs Administration (RSPA), DOT.
ACTION: Final rule.
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SUMMARY: This final rule changes miscellaneous gas pipeline safety
regulations to provide clarity, eliminate unnecessary or burdensome
requirements, and foster economic growth. The changes result from a
comprehensive review of the regulations RSPA has completed under
President Clinton's Regulatory Reinvention Initiative to reduce the
burden of government regulations. The changes are intended to reduce
the costs of compliance without compromising safety.
EFFECTIVE DATE: This final rule is effective July 8, 1996. The
incorporation by reference of certain publications listed in the
regulations is approved by the Director of the Federal Register as of
July 8, 1996.
FOR FURTHER INFORMATION CONTACT: A. C. Garnett, (202) 366-2036, or L.
M. Furrow, (202) 366-4559, regarding the subject matter of this
amendment, or the Dockets Unit, (202) 366-5046 regarding copies of this
amendment or other material in the docket.
SUPPLEMENTARY INFORMATION:
Background
Early in 1992, RSPA began an extensive review of the federal gas
pipeline safety regulations (49 CFR part 192) and invited the public to
participate (57 FR 4745, Feb. 7, 1992). The review was to see what
changes were necessary to provide clarity, eliminate unnecessary or
overly burdensome requirements, and foster economic growth. As a result
of the review, RSPA published a Notice of Proposed Rulemaking (NPRM),
proposing changes to 38 regulations in part 192 (Notice 1; 57 FR 39572,
Aug. 31, 1992).
Then the National Association of Pipeline Safety Representatives
(NAPSR) reported on a separate but related review of part 192. RSPA had
asked NAPSR to identify regulations in part 192 that may not assure
safety or
[[Page 28771]]
that may be hard to enforce. Because the NAPSR report concerned a few
of the regulations covered by the NPRM and had similar goals, we
published the report and requested public comment on its various
recommended rule changes (Notice 2; 58 FR 59431, Nov. 9, 1993). At the
same time, we announced that in developing final rules under the NPRM,
we would consider comments on any NAPSR recommendations that addressed
the same issues as the NPRM. The period for public comment on the NAPSR
recommendations was extended 90 days until April 11, 1994 (Notice 3; 58
FR 68382, Dec. 27, 1993).
Later on, President Clinton launched the Regulatory Reinvention
Initiative (memorandum for Heads of Departments and Agencies; March 4,
1995), which, among other things, directed DOT and other Federal
agencies to review and revise existing regulations to remove
unnecessary or burdensome requirements. Today's publication of this
Final Rule is a major step in carrying out that directive with respect
to DOT's pipeline safety regulations.
Advisory Committee
The Technical Pipeline Safety Standards Committee (TPSSC),
consisting of 15 members, was established by statute to consider the
feasibility, reasonableness, and practicability of proposed pipeline
safety regulations. In developing the final regulations, RSPA
considered all final TPSSC votes and comments on the NPRM, including
minority positions. A more detailed consideration of the TPSSC action
is contained in the following section-by-section discussion of
comments. A record of the TPSSC deliberation is available in the
docket.
Discussion of Comments
RSPA received comments on the NPRM from 36 pipeline operators, 9
pipeline-related associations, 1 state agency, and 8 other commenters.
More commenters submitted views on the NAPSR recommendations: 58
pipeline operators, 10 pipeline-related associations, 4 state agencies,
and 5 other commenters.
The following discussion on development of the final rules explains
how we treated TPSSC positions, comments on the NPRM, and comments on
NAPSR recommendations related to NPRM proposals (Secs. 192.3, 192.475,
192.485, and 192.607). We appreciate the comments on NAPSR
recommendations that were not related to NPRM proposals. They will help
us decide appropriate responses to those recommendations in an action
separate from this rulemaking.
Small Gas Systems. The NPRM invited comments on the idea of whether
RSPA should develop separate, more appropriate safety standards for
small gas distribution systems. Such systems include master meter
systems and petroleum gas systems serving mobile home or apartment
complexes.
Although TPSSC did not address this matter, RSPA received comments
from two pipeline operators, one state agency, and one mobile home
association. The state agency said that it is not clear that separate
regulations are required. This commenter suggested that a less
complicated remedy might be to excerpt those portions of the
regulations specifically applicable to small operators (deleting, for
example, sections applicable to transmission lines) and publish the
result as a guide or as instructional material.
Three commenters supported the need for more appropriate standards
for small gas distribution systems. A mobile home association endorsed
the idea of developing standards for small gas distribution systems,
such as master-meter systems serving mobile home parks, and publishing
the standards as a new part of title 49 of the Code of Federal
Regulations. The mobile home association commented that if it were not
for the Guidance Manual for Operators of Small Gas Systems published by
RSPA, the average mobile home park operator would have difficulty
determining which regulations in part 192 apply to master-meter
systems.
RSPA believes that each of the suggestions has merit and will be
useful in developing future pipeline safety agendas.
Section 192.1, Scope of Part
Section 192.1(b)(1) excepts from the scope of part 192 certain
gathering lines on the outer continental shelf (OCS), but does not
except similar gathering lines located in State offshore waters.
Section 192.1(b)(1) reads as follows: ``This part does not apply to * *
* (o)ffshore gathering of gas upstream from the outlet flange of each
facility on the outer continental shelf where hydrocarbons are produced
or where produced hydrocarbons are first separated, dehydrated, or
otherwise processed, whichever facility is farther downstream.''
Because RSPA treats OCS and State offshore gathering alike under part
192, we proposed to delete the phrase ``on the outer continental
shelf'' so the exception would cover offshore gathering no matter where
located. We also proposed to replace ``offshore gathering of gas'' with
``offshore pipelines,'' recognizing that the excepted pipelines may be
either production or gathering lines.
Twelve TPSSC members voted for the proposal, two supported it but
recommended a change, one member opposed it, and one abstained. The
recommended change was that ``gathering of gas'' should be retained in
Sec. 192.1(b)(1), since proposed Sec. 192.9 refers to gathering under
Sec. 192.1.
We did not adopt the TPSSC minority's recommended change because
the excepted pipelines located upstream from the referenced offshore
facilities may be either production lines or gathering lines. Also, the
term ``offshore pipelines'' was used in a similar revision of 49 CFR
195.1(b)(5) that we made to clarify the jurisdiction of the hazardous
liquid pipeline regulations over offshore pipelines (Docket PS-127; 59
FR 33388; June 28, 1994). As discussed below under the Sec. 192.9
heading, Sec. 192.9 has already been revised to cross-reference
Sec. 192.1. Since the cross- reference does not refer specifically to
gathering lines, deleting the words ``gathering of gas'' from
Sec. 192.1(b)(1) should not hinder the understanding of Sec. 192.9.
RSPA received 14 comments on the proposed rule change, nine from
operators, four from pipeline-related associations, and one from a
state agency. None of these comments opposed the proposal to change
Sec. 192.1(b)(1).
Section 192.3, Definitions
1. Petroleum Gas. A revised definition of ``petroleum gas'' is
discussed below under the Sec. 192.11 heading.
2. Secretary. The proposed revision of the definition of
``Secretary'' is no longer needed. Because the term ``Secretary'' is
not used in part 192, the definition of ``Secretary'' was removed from
Sec. 192.3 in an earlier rulemaking (59 FR 17281; April 12, 1994).
3. Transmission Line. A longstanding RSPA interpretation holds that
the definition of ``transmission line'' in Sec. 192.3 encompasses lines
that link gathering lines or transmission lines to large volume
customers, such as factories or power plants. This interpretation was
founded on the definition of ``transmission line'' in the 1968 edition
of the American Society of Mechanical Engineers [ASME] B31.8 Code. This
code, which was the cornerstone of part 192, defined transmission to
end at large volume customers. RSPA proposed to codify the
interpretation by restating the definition of ``transmission line''
under part 192 to
[[Page 28772]]
include a ``large volume customer'' as an end point of transmission.
Eleven TPSSC members voted for the proposal, three supported it
with a recommended change, and one abstained. The members who
recommended a change thought that RSPA should define ``large volume
customer.'' As discussed further below, the final definition includes
an explanation of this term.
Twenty-six entities commented on the NPRM proposal, including 19
pipeline operators, five pipeline-related associations, one state
agency, and one industrial consumer. Of these commenters, only eight
expressed unqualified support. Three commenters completely opposed the
proposal, saying it was not needed or would create confusion.
RSPA continues to believe that the proposed change is needed. The
present definition does not reflect RSPA's interpretation that the term
``transmission line'' includes pipelines that connect large volume
customers to gathering or transmission lines.
Nine commenters thought the proposed definition would reclassify as
transmission those pipelines that connect large volume customers to
high pressure distribution lines. RSPA did not intend for the proposed
change to alter the classification of distribution lines that supply
large volume customers. To avoid this unintended outcome, the
definition explicitly does not include lines serving large volume
customers downstream from a distribution center.
Four commenters said that the volume of gas transported is not an
appropriate indicator of transmission. This group suggested that
engineering characteristics, such as high pressure, stress level, or
connection to a pressure limiting station are more indicative of
transmission than the volume of gas transported. However, the purpose
of the transmission proposal was not to open discussion on whether
volume is an appropriate indicator of transmission. The purpose was to
recognize that, by interpretation of the present definition, volume
already is an established indicator of transmission, and that the
interpretation should be codified. None of the commenters challenged
the correctness of the interpretation. Moreover, before publishing the
proposed definition, we referred to the 1992 edition of the ASME B31.8
Code, a widely recognized code of voluntary standards for gas piping.
Section 803.21 of the ASME B31.8 Code (1992 edition) defined
``transmission line'' as ``pipe installed for the purpose of
transmitting gas from a source or sources of supply to one or more
distribution centers or to one or more large volume customers * * *''
(emphasis added). And this definition is the same in the current 1995
edition of the code. Given our longstanding interpretation and the ASME
B31.8 Code definition, we find it reasonable to add ``large volume
customer'' to the definition of transmission line as proposed.
Three commenters wanted RSPA to define ``large volume customer.''
We agree that an explanation of ``large volume customer'' would make
the final definition more precise. Thus, we added a statement to the
final definition to explain that ``large volume customer'' includes
factories, power plants, and institutional users of gas.
We did not specify a minimum volume of gas a pipeline must
transport to a customer to qualify as transmission. Volumes vary, and
setting an arbitrary threshold might unfairly reclassify some existing
lines. However, since ``large volume customer'' and ``distribution
center'' each mark the end of transmission under the definition,
operators may use the volume of gas supplied to distribution centers as
a guide to identifying large volume customers.
The NAPSR report recommended changing the part 192 definition of
``transmission line'' so that pipelines beginning at gathering or
transmission lines and ending at ``distribution systems and other load
centers'' would be classified as transmission lines. Under this
alternative wording, load centers conceivably would include large
volume customers.
Most of the persons who commented directly on this NAPSR
recommendation opposed it. A primary objection was that the recommended
definition would needlessly reclassify as transmission low stress
pipelines between communities or between distribution systems and high
pressure transmission lines. In this regard, many commenters felt
transmission should be limited to pipelines that operate at 20 percent
or more of specified minimum yield strength (SMYS) of pipe, one of the
characteristics under the present definition. The lack of definition of
the term ``load center'' was another frequently stated reason for
opposing the NAPSR recommendation. Commenters argued that introducing
this term into the definition would lead to more, not less, confusion.
Also several commenters thought the definition of transmission line
should remain unchanged until RSPA completes its project to redefine
the term ``gathering line,'' which appears in the transmission line
definition. After considering these concerns, we agree that the NAPSR
recommendation would not strengthen the present definition and could
cause reclassification of many lines. Therefore, we did not adopt the
recommendation in the final definition.
Section 192.5, Class Locations
RSPA proposed to clarify Sec. 192.5 to minimize the possibility
that a pipeline is classified higher than required. Inasmuch as part
192 regulations become more stringent as pipeline classification
increases, any over- classification results in needless expenditures.
Fourteen TPSSC members voted for the proposal and one abstained.
Eight operators and one pipeline-related association commented on the
proposed change. While these commenters generally supported the need to
clarify Sec. 192.5, two operators suggested alternative wording. Based
on one suggestion, RSPA has combined proposed Secs. 192.5 (c)(2) and
(c)(3) into final Sec. 192.5(c)(2).
One focus of the NPRM was the cluster exception in existing
Secs. 192.5(f)(2) and (f)(3). This exception provides that if a cluster
of buildings intended for human occupancy requires a Class 2 or 3
location, the classification ends 220 yards from the nearest building
in the cluster, rather than at the end of the 1-mile class location
unit that would otherwise be the basis for classification. In the NPRM
(at 39573), we stated that adding buildings outside a cluster to those
inside the cluster would result in over-classification of the class
location unit. However, this statement was incorrect. The history of
Sec. 192.5 (35 FR 13251, August 19, 1970) shows that the cluster
exception applies only when all buildings in a 1-mile class location
unit are in a single cluster. If a class location unit contains
buildings outside a cluster or more than one cluster of buildings, all
buildings in the unit must be counted to determine the classification
of the unit. The final rule clarifies this point.
The association that commented thought we should define the term
``cluster.'' However, the term is used in its ordinary dictionary
sense, and, in RSPA's experience, has not been a significant source of
misunderstanding.
Section 192.7, Incorporation by Reference
Section 192.7 describes the incorporation by reference in part 192
of documents or portions of documents relevant to gas pipeline safety.
RSPA proposed to revise Sec. 192.7(a) to clarify that when a regulation
in part 192
[[Page 28773]]
references a document, the entire document is not necessarily
incorporated by reference. Rather, only those portions of the document
that are specifically referenced in the regulation or are essential for
compliance with the regulation are incorporated by reference. Such
portions may or may not comprise the whole document, depending on the
scope of the reference.
Fourteen TPSSC members voted for the proposal and one abstained.
Commenters on the proposed change, seven operators and one pipeline-
related association, all favored the proposal. However, two of these
commenters wanted RSPA to change the rule in a manner not proposed.
They advised changing Sec. 192.7 to require operators to follow the
latest published editions of documents, instead of particular editions,
which can become obsolete before RSPA updates the references. RSPA
believes this recommended action is inappropriate because it would hand
over an established governmental function, rulemaking, to the private
organizations who produce the referenced documents. Each newly
published edition would automatically change a pipeline safety rule and
bypass the Federal rulemaking process, which ensures fair treatment of
all affected parties.
Section 192.9, Gathering Lines
When the NPRM was published, Sec. 192.9 required gathering lines to
comply with part 192 standards applicable to transmission lines without
indicating that certain gathering lines are excepted from part 192 by
Sec. 192.1. To highlight this exception and provide a clear
understanding of which gathering lines must meet transmission line
standards, we proposed to cross-reference Sec. 192.1 in Sec. 192.9.
Thirteen TPSSC members voted for the proposal and two abstained.
RSPA received seven comments on the proposed change, six from operators
and one from a pipeline-related association. Only one commenter opposed
the proposal, saying it did not see how the change would clarify the
present rule.
Then in 1994, in a separate, unrelated action concerning the
passage of pigs, RSPA revised Sec. 192.9 to include a cross-reference
to Sec. 192.1 (59 FR 17281, April 12, 1994). Thus, Sec. 192.9 has
already been changed consistent with the proposal in this proceeding,
and no further action is necessary.
Section 192.11, Petroleum Gas Systems (Including Changes to Secs. 192.1
and 192.3)
RSPA proposed several changes to the special rules in Sec. 192.11
for petroleum gas systems: First, we proposed to require that peak
shaving plants supplying petroleum gas by pipeline to a natural gas
distribution system as well as pipeline systems transporting only
petroleum gas or petroleum gas/air mixtures comply with part 192
standards and the National Fire Protection Association (NFPA) Standards
58 and 59. Downstream from the point where a peak shaving plant injects
petroleum gas into a natural gas distribution system, only part 192
would apply. Next, we proposed that the NFPA Standards prevail in the
event of a conflict between part 192 and NFPA Standards 58 or 59. At
the same time, we said that a conflict does not exist when NFPA
Standards 58 and 59 are silent or nonspecific on a subject (such as for
corrosion protection or leak detection). In this case, the operator
would have to comply with any applicable part 192 rule. Finally, we
proposed to add a definition of ``petroleum gas'' to Sec. 192.3, and to
clarify under Sec. 192.1(b)(4) which petroleum gas systems are excepted
from part 192.
Ten TPSSC members voted for the proposal, one member supported it
with a recommended change, three members opposed it, and one abstained.
Two TPSSC members disagreed with the proposal that NFPA standards
should prevail in the event of a conflict with part 192. One TPSSC
member voted yes, but recommended that in the event of conflict the
most stringent requirement should prevail.
We explained in the NPRM why we believe the NFPA standards should
have priority in direct conflict situations. The main reason is that in
contrast to part 192, the NFPA Standards specifically cover petroleum
gas transportation. Also, NFPA Standards 58 and 59 reflect current
petroleum gas technology and safety practices. Given this special
attention to petroleum gas, we do not think there is sufficient reason
to require operators to follow part 192 instead of the NFPA Standards
in the event of conflict, even if part 192 is more stringent.
RSPA received eight comments in favor and three comments in
opposition to the proposed changes to Sec. 192.11. Those commenters who
opposed the proposal were concerned that compliance with NFPA Standards
58 and 59 would involve significant capital expenditures. However,
Sec. 192.11 already requires petroleum gas systems to meet NFPA
Standards 58 and 59. And, in accordance with 49 U.S.C. Sec. 60104(b),
none of the design, installation, construction, initial testing, or
initial inspection requirements of NFPA Standards 58 and 59 would apply
under part 192 to peak shaving plants now in existence. So,
retrofitting existing plants would not be required. Although all plants
would have to comply with the operation and maintenance requirements of
NFPA Standards 58 and 59, overall compliance costs should be small
because, as NFPA stated in its petition, most, if not all, existing
plants already comply with NFPA Standards 58 and 59 to qualify for
insurance coverage. Thus, Sec. 192.11 is revised as proposed in the
NPRM.
Proposed Sec. 192.1(b)(4)(i) would exclude from part 192 pipeline
systems that transport only petroleum gas or petroleum gas/air mixtures
to fewer than 10 customers, if no portion of the system is located in a
public place. This exclusion is in the present Sec. 192.11(a), but in
proposing to relocate it to Sec. 192.1(b)(4)(i), we omitted the
parenthetical phrase ``(such as a highway).'' One commenter objected to
the omission, saying it would leave the meaning of ``public place''
open to interpretation. However, our experience has been that the
parenthetical phrase has hindered more than helped the understanding of
public place. We have consistently interpreted ``public place'' to mean
a place which is generally open to all persons in a community as
opposed to being restricted to specific persons. We consider churches,
schools, and commercial property as well as any publicly owned right-
of-way or property which is frequented by persons to be public places.
Although Sec. 192.11(a) refers to a highway as an example of a public
place, many operators have incorrectly considered the example to
restrict, rather than define, the coverage of petroleum gas systems
with fewer than 10 customers.
Proposed Sec. 192.1(b)(4)(ii) would clarify that part 192 does not
apply to single-tank, single-customer petroleum gas systems located
entirely on the customer's premises, but partially in a public place.
These systems exist, for example, at churches or restaurants, where the
gas is used for heating or cooking. The proposal was based on the
jurisdiction of part 192 over the distribution of gas. As indicated by
the definition of ``service line'' (Sec. 192.3), part 192 does not
apply to gas distribution beyond the point where metered gas enters
customer piping. For single-tank, single-customer systems on the
customer's premises, this point normally occurs at the tank.
Three commenters protested that part 192 would still apply to
single-customer, multi-tank systems on the customer's premises,
regardless of tank size. For example, the proposed rule
[[Page 28774]]
would not exclude a two-tank system partly in a public place, even if
the total quantity of stored gas is less than in a large single-tank
system. Because the proposed exclusion did not rest on the quantity of
gas delivered to the customer, we agree that the number of tanks should
not be a factor in the exclusion of single-customer systems on the
customer's premises. Therefore, final Sec. 192.1(b)(4)(ii) omits the
term ``single-tank.''
The proposed definition of ``petroleum gas'' drew no objections
from either the TPSSC or commenters. So the definition is adopted as
proposed.
Sections 192.14 and 192.553, Conversion and Uprating
If a steel pipeline to be converted to gas service under part 192
has not been designed and constructed to meet part 192 standards, it
must be converted according to Sec. 192.14 (Sec. 192.13(a)(2)). Section
192.14(a)(4) requires that each pipeline must be pressure tested under
subpart J of part 192 to substantiate the maximum allowable operating
pressure (MAOP) permitted by subpart L of part 192. Under subpart L, to
compute the MAOP of a pipeline being converted, an operator must
determine the design pressure of the weakest element of the pipeline
(Sec. 192.619(a)(1)).
Design pressure is also a factor under Sec. 192.553, which
establishes general requirements for increasing any pipeline's MAOP
(uprating). Under Sec. 192.553(d), an increased maximum allowable
operating pressure may not exceed the MAOP part 192 allows for a new
pipeline constructed of the same materials in the same location. Thus,
to uprate a pipeline within this MAOP limit, an operator must determine
the design pressure of the weakest element of the pipeline
(Sec. 192.619(a)(1)).
Because of the role of design pressure, a steel pipeline may not be
converted or uprated when any of the pipe characteristics needed to
calculate design pressure under Sec. 192.105 is unknown. Therefore,
RSPA proposed to amend Secs. 192.14(a)(1) and 192.553(d) to permit the
conversion or uprating of steel pipelines based on an approach found in
paragraph 845.214 and Appendix N of the ASME B31.8 Code. Under the
proposal, when design pressure is unknown, operators would have to
pressure test the pipeline under Appendix N until pipe yield occurs.
The first pressure that produces pipe yield, reduced by 20 percent and
the appropriate factor under Sec. 192.619(a)(2)(ii), would be used
instead of design pressure to calculate MAOP.
Twelve TPSSC members voted for the proposed revision of
Sec. 192.14, one member supported it with a recommended change, one
member opposed it but suggested changes, and one member abstained.
Eleven members voted for the proposal regarding Sec. 192.553, two
supported it with a recommended change, one opposed it, and one
abstained. The recommended changes were to make yield testing mandatory
instead of permissive, and to allow yield testing that is based on
other than the ``first pressure'' that produces yield, since Appendix N
does not use that term. The reasons against the proposal were that
yield testing appeared to be mandatory, and use of the Appendix N
method should be discretionary.
RSPA has adopted the recommended change regarding mandatory yield
testing. Although, in the proposed rules, yield testing may have
appeared permissive, RSPA clearly intended such testing to be the only
alternative when design pressure is unknown. Therefore, in the final
rule, if factors in the design formula are unknown, a pipeline to be
converted or uprated would have to be pressure tested under Appendix N
to determine pipe yield, except as discussed below for low-stress pipe.
The TPSSC member's recommendation to delete ``first pressure'' from
the proposed rule was not adopted. Although Appendix N does not refer
to the first pressure that produces yield, paragraph 845.214(a)(2) of
the ASME B31.8 Code, which applies to the establishment of MAOP when
design pressure is unknown, provides that only the first test to yield
can be used to determine MAOP. The proposed rules were consistent with
this B31.8 standard, which precludes the use of higher yield pressures
that can result from successive testing.
RSPA did not adopt the TPSSC member's comment that use of the
Appendix N method should be discretionary. When MAOP is determined
without knowing the pipeline's design pressure, conformity to a
standardized practice (Section N5.0 of Appendix N) assures additional
safety to offset the lack of knowledge about design pressure.
RSPA received comments on the proposed rules from 11 operators and
three pipeline-related associations. Four operators and one pipeline-
related association recommended removal of the proposed requirement to
use the ``first pressure'' that produces yield. Our position on this
subject is given above in response to a similar comment by a TPSSC
member.
One operator and one pipeline-related association suggested
locating the proposed amendments in Sec. 192.105 instead of
Secs. 192.14 and 192.553. RSPA did not adopt this suggestion because
Sec. 192.105 affects the design of new pipelines, a subject the
proposed rules did not address.
One operator and two pipeline-related associations argued that
pressure testing to yield is unnecessary to qualify low-stress
distribution lines (generally lines 12\3/4\ inches or less in nominal
outside diameter operating at pressures less than 200 psig) for
conversion or uprating. Part 192 recognizes that low- stress pipelines
present a much lower risk to public safety than high-stress lines, all
other factors being equal. For example, certain welding standards in
subpart E are less stringent for pipelines to be operated below 20
percent of SMYS. Because of the lower risk, the final rule provides
that pipelines 12\3/4\ inches or less in nominal outside diameter to be
operated at a pressure less than 200 psig may be converted or uprated
without testing to yield. The MAOP of such pipelines may be determined
under Sec. 192.619(a)(1) by using 200 psig as design pressure.
An operator argued that pressure testing to yield should be
discretionary, because sufficient safety would be provided by the
proposed pressure reduction factors regardless of the level of test
pressure. The commenter was also concerned that pressure testing to
yield for an extended time could cause the growth of defects that later
cause failure during operation. Two hours was suggested as the optimum
hold time for yield testing, based on ongoing studies.
RSPA did not adopt these comments. Pressure testing to yield
exposes more material and construction defects than does testing to a
lower pressure. With fewer defects remaining after testing to yield,
greater long-term protection against failures due to the growth of
unexposed defects results. RSPA intended this extra protection,
combined with the proposed pressure reduction factors, to offset the
absence of design pressure as a limit on MAOP. Pressure testing to
yield appears to be reasonable since many operators already strength
test their pipelines at or above yield for safety and efficiency
reasons. Also, none of the other commenters or TPSSC members objected
to pressure testing to yield, except as discussed above for low-stress
lines. As to the optimum hold period for yield testing, because the
matter is still being studied by industry and is not addressed by the
procedure for yield testing under Appendix N, it is too soon to
consider
[[Page 28775]]
establishing a special hold period for yield testing under part 192.
The final rules have been drafted to improve clarity, to show their
relation to design pressure and MAOP under Sec. 192.619, and to include
the changes discussed above. The proposed amendments to
Secs. 192.14(a)(1) and 192.553(d) are revised and published as an
amendment to Sec. 192.619(a)(1), because this section deals
specifically with design pressure and MAOP. Final Sec. 192.619(a)(1),
set forth below, provides that when design pressure is unknown for
steel pipelines being converted or uprated, a reduced value of first
yield hydrostatic test pressure, instead of design pressure, is used to
compute MAOP. As discussed below, final Sec. 192.619(a)(1) does not
include the reduction factors proposed for butt and lap welded pipe
under Sec. 192.14(a)(1)(ii). If the pipeline to be converted is 12\3/4\
inches or less in nominal outside diameter, 200 psig, instead of design
pressure, may be used if the line is not yield tested. Section
192.553(d) is also revised to refer to amended Sec. 192.619(a)(1).
Also, because the 1992 edition of the ASME B31.8 Code is now out-of-
print, the 1995 edition is referenced in Sec. 192.619(a)(1) as shown by
the revisions to Appendix A of part 192 (see below).
Section 192.107, Yield Strength (S) for Steel Pipe
For pipe made according to a specification not listed in part 192
or whose specification or tensile properties are unknown,
Sec. 192.107(b)(1) provides that yield strength may be established by
tensile testing in accordance with section II-D of appendix B to part
192. When yield strength is determined by such tensile testing,
paragraph (b)(1) requires that the yield strength used in the design
formula of Sec. 192.105 be the lower of either 80 percent of the
average yield strength determined by tensile testing or the lowest
yield strength determined by tensile testing, but not over 52,000 psi.
RSPA proposed to remove this 52,000 psi upper limit on yield strength,
because higher strength pipe has become available since this limitation
was adopted, and tensile testing is a generally accepted method of
determining material properties.
Twelve TPSSC members voted for the proposal, one member supported
it with a recommended change and two abstained. The member recommending
the change felt that the proposal would be better justified if we knew
the proportion of higher strength pipe that lacks tensile documentation
and why this information is unknown. RSPA believes this information is
not essential in deciding whether to adopt the proposal because the
proposed amendment has limited application. We expect operators would
use the proposed amendment to qualify stock pipe they have stored for
maintenance and emergencies and to qualify used pipe being reclaimed.
In either case, the amount of pipe that would be qualified under
proposed Sec. 192.107(b)(1)(ii) should be very small compared with all
pipe being qualified for use in gas pipeline systems.
RSPA received six comments on the proposed amendment. The comments
came from five operators and one pipeline-related association, and all
supported the proposal. In addition, one operator recommended that RSPA
further amend Sec. 192.107 to permit the use of recognized statistical
methods to determine yield strength from tensile tests. RSPA did not
adopt this comment because this concept was not addressed in the NPRM
and would require further public comment and study.
Accordingly, Sec. 192.107 is amended as proposed in the NPRM.
Section 192.121, Design of Plastic Pipe
RSPA proposed to add the following formula to Sec. 192.121, which
would allow use of the Standard Dimension Ratio (SDR) in determining
design pressure for plastic pipe:
[GRAPHIC] [TIFF OMITTED] TR06JN96.012
SDR is a commonly used plastic pipe characteristic in the gas
pipeline industry.
Thirteen TPSSC members voted for the proposal and two abstained.
RSPA received eight responses from the public, all in favor of the
proposed rule. Therefore, the final rule is issued as proposed in the
NPRM, except that the proposed definition is reworded to conform to
standard usage. The final definition agrees with the SDR definition
given in the voluntary standard referenced in part 192 for the
manufacture of thermoplastic pipe: American Society for Testing and
Materials (ASTM) Designation D 2513, ``Standard Specification for
Thermoplastic Gas Pressure Pipe, Tubing, and Fittings'' (1990c
edition).
Section 192.123, Design Limitations for Plastic Pipe
Under Sec. 192.123, plastic pipe may not be used where pipe
operating temperatures are below -20 deg.F. RSPA proposed to lower this
limit to -40 deg.F in light of improvements in pipe technology.
Additionally, RSPA proposed to clarify Sec. 192.123(b)(2), which sets
the maximum operating temperature for thermoplastic pipe and reinforced
thermosetting plastic pipe.
Thirteen TPSSC members voted for the proposal and two abstained.
RSPA received nine comments on the proposed rule changes: six from
operators, one from a pipeline-related association, and two from
manufacturers. The operators and the association supported the proposal
or did not object to it. However, the manufacturers opposed the
proposal stating that many components other than pipe that are made for
use in gas pipeline systems do not have a low temperature rating of
-40 deg.F, although they perform satisfactorily at -20 deg.F. One of
these commenters argued that unsafe operation could occur if pipeline
designers assumed that all components, such as repair and connection
devices, fittings, valves, meters, and regulators, may be used at
-40 deg.F.
RSPA shares the manufacturers' concern. Therefore, the final rule
allows the use of plastic pipe at temperatures between -20 deg.F and
-40 deg.F only if all pipe and pipeline components whose operating
temperature will be below -20 deg.F have a manufacturer's temperature
rating consistent with that operating temperature.
Section 192.179, Transmission Line Valves
Gas transmission lines must have sectionalizing block valves spaced
according to population density under Sec. 192.179(a). RSPA proposed to
revise this rule to allow the RSPA Administrator to approve alternative
spacing where the operator demonstrates an equivalent level of pipeline
safety.
Thirteen TPSSC members voted for the proposal, one against, and one
abstained.
RSPA received comments from 12 operators, two pipeline-related
associations, and a state agency. Thirteen commenters gave their full
or qualified approval, but one association and the state agency argued
against the proposal. Those commenters expressing qualified support
generally felt that the proposal offered some benefit to pipeline
operators. However, they urged that operators be permitted to determine
spacing based on criteria similar to those for hazardous liquid
pipelines in 49 CFR 195.260(c).
RSPA did not adopt the comment that transmission line valve spacing
should be governed by criteria similar to those in 49 CFR 195.260(c).
While those criteria may be appropriate for hazardous liquid pipelines,
we have no indication they are suitable for gas
[[Page 28776]]
transmission lines. In fact, the widely accepted voluntary standard for
valve spacing, paragraph 846.11 of the ASME B31.8 Code, differs little
from existing Sec. 192.179.
As for the comments opposing the proposal, RSPA has considered the
state agency's concern that the proposed rule would infringe on the
authority of state agencies to grant waivers from Sec. 192.179 for
intrastate transmission lines. (See 49 U.S.C 60118(d)). However, this
concern has been addressed by a procedural rule (49 CFR 190.9) that
RSPA adopted to handle petitions for finding or approval under the
federal pipeline safety regulations. Under this rule, which would apply
to petitions for alternative spacing under Sec. 192.179, operators of
intrastate pipelines subject to the safety regulatory jurisdiction of a
certified state agency must submit their petitions to that agency for
review and recommendation before final action by the Administrator.
RSPA does not agree with the pipeline-related association's
suggestion that since the underlying rule is not justified, the
proposed amendment is not needed. The basis for existing Sec. 192.179
was the 1968 edition of the ASME B31.8 Code. As noted above, the
current edition of that code continues to specify valve spacing similar
to Sec. 192.179.
Section 192.203, Instrument, Control, and Sampling Pipe and Components
Under Sec. 192.203(b)(2), each takeoff line must have a shutoff
valve as near as practicable to the point of takeoff. RSPA proposed an
exception for takeoff lines on pressure regulators when the lines can
be isolated by other valves from their source of pressure.
Eleven TPSSC members voted for the proposal, one voted against it,
two members supported it with a recommended change, and one abstained.
The two members recommended that we also except instrument control
lines that are capable of being isolated from their source of pressure.
Although the industry's use of isolatable regulators gave rise to
the proposed rule change, isolation of a takeoff line from its pressure
sources applies to any takeoff line capable of such isolation, not just
takeoff lines on regulators. Therefore, the final rule excepts any
takeoff line capable of being isolated from its sources of pressure.
Thus, the term ``takeoff line'' includes instrument control lines that
are designed as takeoff lines.
RSPA received 13 public comments, all in favor of changing the
regulation. One of these commenters offered a rewording intended to
broaden the regulation to include control lines at both measuring and
regulating stations. As explained above, such control lines will be
covered by the exception when they are takeoff lines capable of
isolation from their sources of pressure.
Section 192.227, Qualification of Welders, and Sec. 192.229,
Limitations on Welders
Welders qualified to weld on pipe to be operated at any hoop stress
(Sec. 192.227(a)) must requalify every 6 months (Sec. 192.229(c)).
However, welders qualified to weld only on pipe to be operated at low
hoop stress (less than 20 percent of SMYS) need only requalify once a
year (Sec. 192.227(b)), and the requalification requirements are less
comprehensive than those for other welders.
RSPA proposed to revise Secs. 192.227 and 192.229 to allow welders
initially qualified for any hoop stress level, but who weld only on
pipe to be operated at low hoop stress, to requalify under the low-
stress requirements. Such welders would then not be permitted to weld
on pipe to be operated at 20 percent or more of SMYS unless they again
qualify under Sec. 192.227(a).
Twelve TPSSC members voted for and one against the proposed
revision of Sec. 192.227, and two abstained. The TPSSC members' vote on
Sec. 192.229 was the same as on Sec. 192.227. Eight pipeline operators
and two pipeline-related associations also agreed with the proposal.
A commenter suggested that the final rule make clear that either
existing Sec. 192.229(c) or Sec. 192.227(b) can be used to requalify
welders to weld on pipe to be operated at less than 20 percent of SMYS.
RSPA adopted the substance of this comment by adding a sentence
concerning low stress requalification to the final Sec. 192.229(c).
The commenter who opposed the proposal claimed that qualification
under Secs. 192.227(a) and (b) is inadequate. However, RSPA finds no
justification for this claim. Section 192.227 became effective in
February 1970. Our accident data in the intervening 26 years have not
indicated that field welding of steel materials in pipelines presents a
significant safety problem.
In the final rules, proposed Sec. 192.227(c) is redesignated as
Sec. 192.229(d). Thus, all requalification requirements appear in one
section.
Section 192.241, Inspection and Test of Welds
Section 192.241 requires inspection and test of welds on steel
materials in pipelines, except welds made during the manufacture of
pipe and pipeline components. Under existing Sec. 192.241(c) and
appendix A to part 192, the acceptability of a weld that is
nondestructively tested or visually inspected is determined according
to the standards in section 6 of API Standard 1104 (17th edition).
The Appendix of API Standard 1104, which is based on fracture
mechanics principles, provides more detailed acceptance standards for
weld flaws than the criteria in section 6 of API Standard 1104. RSPA
proposed to amend Sec. 192.241(c) to permit use of the Appendix as an
alternative acceptance standard for girth weld flaws, except welds
unacceptable because of a crack.
Eleven TPSSC members voted for the proposal, three members
supported it with a recommended change and one abstained. The three
members suggested that the word ``flaw'' be changed to ``defect''.
In existing Sec. 192.241, neither the word ``flaw'' nor ``defect''
is used. The rule is written in terms of weld acceptability. Therefore,
in response to the comments of the TPSSC members, the final rule is
written without using either ``flaw'' or ``defect.''
Eleven pipeline operators and three pipeline-related associations
agreed with the proposed change. Only one commenter was opposed to
allowing use of the Appendix of API Standard 1104. This commenter was
concerned that industry inspection personnel may not be qualified to
apply the complicated engineering criteria found in the Appendix. On
the contrary, personnel who would use the Appendix must be able to
apply it correctly. Under Secs. 192.243(b) and (c), operators must
ensure that nondestructive testing is performed in accordance with
written procedures by persons who have been properly trained and
qualified.
The final rule indicates that use of the Appendix is restricted to
girth welds to which the Appendix applies. For example, as Section A.1
of the Appendix provides, welds used to connect fittings and valves are
not covered. Also, the Appendix applies only to girth welds between
pipe of equal nominal wall thickness.
Section 192.243, Nondestructive Testing
For pipelines subject to nondestructive testing under part 192,
Sec. 192.243(d)(4) requires such testing for all field butt welds at
pipeline tie-ins. RSPA proposed to amend Sec. 192.243(d)(4) to add the
phrase ``including tie-ins of replacement sections.'' This change was
meant to clarify that tie-ins occur in pipeline
[[Page 28777]]
replacement, as well as in new construction.
Fourteen TPSSC members voted for the proposal and one abstained.
Comments were received from five pipeline operators and one
pipeline-related association, and all favored the proposed rule change.
Section 192.243 is amended as proposed in the NPRM.
Section 192.281, Plastic Pipe
This rule establishes standards governing the joining of plastic
pipe. RSPA proposed to revise Sec. 192.281(c), which applies to heat-
fusion joints, to cover electrofusion, a method of heat-fusion joining.
The proposal was that electrofusion joints must be made with equipment
and techniques expressly prescribed by the fittings manufacturer.
Thirteen TPSSC members voted for the proposal, one member supported
it with a recommended change, and one abstained. The recommended change
was that ``or the equivalent'' be added so that operators could use
equipment and techniques equivalent to that prescribed by fittings
manufacturers.
RSPA received 15 comments on the proposed change to
Sec. 192.281(c). Eleven commenters fully or partially agreed with the
proposed rule, while four commenters objected. A commenter who
partially agreed recommended that electrofusion be specifically
addressed in Sec. 192.285. However, RSPA finds that step unnecessary
because electrofusion is a type of heat fusion, and heat fusion is
covered by Sec. 192.285(b)(2).
The objections focused on RSPA's proposal that operators must use
``equipment and techniques expressly prescribed by the fittings
manufacturer.'' One commenter said that electrofusion equipment is
expensive and that most electrofusion fittings can be installed only by
using the fittings manufacturer's equipment. As a result, most
operators have only a single source of electrofusion fittings. However,
the commenter stated that electrofusion equipment under development
will allow the installation of several different brands of
electrofusion fittings, and that those additional sources would
encourage competitive pricing. Other operators argued they should not
be denied the use of procedures and equipment not expressly prescribed
by the fittings manufacturer, as long as the procedures are qualified
for use under Sec. 192.283.
Since the proposal was intended to relax the current regulatory
requirement, RSPA accepts the recommendations that operators should
have latitude in choosing equipment and techniques for use in
electrofusion joining. We have adopted a slight revision of the wording
proposed by three pipeline operators and one pipeline-related
association. This wording meets the ``or the equivalent''
recommendation made by the TPSSC member. Additionally, this wording
responds to the commenter's concern that the proposed wording would
deter competitive pricing. The adopted wording requires that the joints
be joined using equipment and techniques of the fittings manufacturer
or equipment and techniques shown, by testing to certain criteria of
ASTM Designation F1055, ``Standard Specification for Electrofusion Type
Polyethylene Fittings for Outside Diameter Controlled Polyethylene Pipe
and Tubing,'' to be at least equivalent to those of the fittings
manufacturer. The ASTM criteria are those adopted under the next
heading for qualifying electrofusion joining procedures.
Section 192.283, Plastic Pipe: Qualifying Joining Procedures
Section 192.283 prescribes criteria for qualifying procedures used
to join plastic pipe. RSPA proposed to amend this section by adding
more appropriate criteria for procedures used to join polyethylene
plastic pipe by electrofusion. The proposed criteria are contained in
certain sections of ASTM Designation F1055 (1987 edition).
Fourteen TPSSC members voted for the proposal and one member
abstained.
RSPA received eight comments on the proposal: seven from pipeline
operators and one from a pipeline-related association. Seven commenters
supported the proposal. But one opposed it, saying that the proposal
should be withdrawn or rewritten to accept any procedure that
demonstrates a suitable quality of joint. We believe, however, that
allowing operators to judge the quality of an electrofusion joint
without applying a recognized safety standard would be unacceptable.
Because of the failure risk of plastic pipe joints, the present rule
requires heat fusion joining methods to be qualified under generally
recognized voluntary standards, ASTM D2513 and ASTM D2517. In the
absence of safety data to the contrary, as a heat fusion method,
electrofusion procedures should likewise be qualified under an
appropriate recognized standard. Accordingly, proposed
Sec. 192.283(a)(iii) is adopted as final. However, the proposed
reference to the 1987 edition of ASTM Designation F1055 is updated to
the 1995 edition, as shown by the revisions to Appendix A of part 192
(see below). And the referenced title of paragraph 9.4 is corrected to
read ``Joint Integrity Tests.''
Sections 192.317(a), Protection From Hazards
This section requires that gas transmission lines and mains be
protected from washouts, floods, unstable soil, landslides, or other
hazards that may cause the pipeline to move or sustain abnormal loads.
Additionally, offshore pipelines must be protected from damage by mud
slides, water currents, hurricanes, ship anchors, and fishing
operations. RSPA recognized that in areas susceptible to these hazards,
such as offshore pipelines in areas where hurricanes usually pass,
complete protection against the hazards may not be feasible. We,
therefore, proposed to change the regulation to require that in
construction of transmission lines and mains, operators ``take all
practicable steps to protect'' the pipeline against the cited hazards.
Eleven TPSSC members voted for the proposal, one member supported
it with a recommended change, two members were opposed and one member
abstained. The two members who opposed it said that ``all practicable
steps to protect'' would be difficult to interpret.
Comments were received from seven pipeline operators and two
pipeline-related associations. All commenters gave their full or
qualified approval.
RSPA has issued the final rule as proposed in the NPRM. The ``all
practicable steps to protect'' wording was left in the rule to allow
operators flexibility in compliance; any tightening of this performance
wording would diminish that flexibility. RSPA will interpret or apply
the rule in light of customary pipeline design and construction
practices in the industry.
Secs. 192.319(c) and 192.327(e), Offshore Pipe in the Gulf of Mexico
and Its Inlets
Under Sec. 192.612, operators had to inspect gas pipelines in the
Gulf of Mexico and its inlets in waters up to 15 feet deep. If the
pipelines were found exposed or to be a hazard to navigation (i.e.,
buried less than 12 inches below the seabed), the operator had to bury
them to a depth of 36 inches in soil or 18 inches in rock.
The part 192 review disclosed that Secs. 192.319(c) and 192.327(e),
which govern the installation of pipe offshore, are incompatible with
the objectives of Sec. 192.612. In water between 12 and 200 feet deep,
Sec. 192.319(c) permits pipe to be installed at or above the natural
bottom. And in water less than 12 feet deep, in certain circumstances
Sec. 192.327(e) permits pipe to be buried less than 36 inches in soil
or 18 inches
[[Page 28778]]
in rock. RSPA proposed to amend Secs. 192.319(c) and 192.327(e) to
require that when pipe is installed offshore in the Gulf of Mexico and
its inlets, the pipe must be installed consistent with the burial
standards of Sec. 192.612.
Thirteen TPSSC members voted for the proposal, one member supported
it with a recommended change, and one abstained. One member supported
the proposal but recommended rewording and rearrangement for clarity,
and that Sec. 192.319(c) be moved to Sec. 192.327.
Seven operators and four pipeline-related associations supported
the proposed changes to Secs. 192.319(c) and 192.327(e). However, five
commenters recommended wording changes and rearrangement for clarity,
and five commenters suggested that Sec. 192.319(c) be moved to
Sec. 192.327. In light of the recommendations, RSPA has clarified the
final rule text, as set forth below.
One pipeline-related association opposed the proposal. It
maintained that pipe installed in water between 12 and 15 feet deep
with less than 12 inches of cover (now acceptable under Sec. 192.319(c)
but not Sec. 192.612) might not be an actual hazard to navigation. But
the proposal concerned the inconsistency of Sec. 192.612 with other
pipeline safety rules, a problem that can be resolved without reopening
the question of what is a ``hazard to navigation'' in the Gulf of
Mexico and its inlets. A ``hazard to navigation'' is defined in
Sec. 192.3 to mean ``a pipeline where the top of the pipe is less than
12 inches below the seabed in water less than 15 feet deep, as measured
from the mean low water.'' This definition was adopted in the
proceeding on Sec. 192.612 (Docket No. PS-120). Any remaining
controversy over the definition may be raised by submitting a petition
for rulemaking under 49 CFR part 106.
Section 192.321, Installation of Plastic Pipe; and Sec. 192.375,
Service Lines: Plastic
Section 192.321(a) requires that plastic pipe be installed below
ground level. RSPA proposed to allow the temporary use of uncased
(i.e., not encased) plastic pipe above ground level under certain
conditions. The proposed conditions limited the use to (1) 30 days; (2)
locations where the pipe is unlikely to be damaged (or is protected
from damage) by external forces; (3) pipe that is resistant to the
exposure to ultraviolet light and temperature extremes; and (4) pipe
that has not been previously used above ground level.
Nine TPSSC members voted for the proposal, one against, three
members supported it with a recommended change, and two abstained. The
recommended changes were similar to those made by the commenters as
discussed below.
RSPA received 18 comments on this proposal. Each commenter agreed
partially with the proposed rule. Some commenters said the current rule
should be amended to permit the permanent use of plastic above ground
when the pipe is encased in steel conduit. However, since the proposal
concerned only temporary usage, this comment was not adopted in the
final rule.
Many commenters argued that the 30-day period would be too brief.
They suggested a longer period, such as 60 or 90 days, in view of the
time it may take to complete a permanent installation. They cited the
time associated with planning, obtaining governmental permits,
acquiring easements, engaging contractors, competing work demands, and
other unforeseen events. Several commenters suggested that no specific
time limit be defined and that performance language be used.
Commenters also maintained that the proposed prohibition against
the subsequent reuse of plastic pipe above ground level is not
justified, since commercially available plastic pipe can be exposed to
ultraviolet light for at least 2 years with no degradation of its
properties. These commenters argued that the rule should permit reuse
of plastic pipe provided such use does not exceed the pipe
manufacturer's exposure limits.
RSPA agrees that in most cases 30 days may not be enough time for
operators to take full advantage of a temporary aboveground plastic
pipe installation. In a recent waiver of Sec. 192.321(a), we allowed
the applicant to install plastic pipe above ground for a time that does
not exceed the manufacturer's recommended maximum period of exposure
(60 FR 55752; Nov. 2, 1995). Although commenters indicated that
extending the limit to 2 years might not adversely affect pipeline
safety, we are not certain 2 years would be safe for all plastic
materials. Some pipe manufacturers may recommend less exposure time.
Therefore, we have chosen the manufacturer's recommended maximum period
of exposure but not longer than 2 years as the limit on the temporary
use of plastic pipe above ground. If a manufacturer has no recommended
maximum exposure period, then the limit would be 2 years. RSPA does not
believe a performance standard would provide a suitable time limit,
because the safe service life of plastic pipe exposed above ground is
too uncertain.
RSPA agrees that the final rule should not unduly hinder the use of
plastic pipe. Thus, the proposed ban on reusing plastic pipe above
ground level does not appear justified. The final rule permits
cumulative aboveground use for the manufacturer's recommended maximum
period of exposure but not longer than 2 years, provided the operator
can demonstrate the cumulative time of aboveground use. In monitoring
compliance, RSPA will consider credible evidence that demonstrates
cumulative time of use, such as business records, work orders, or
affidavits related to the pipe concerned.
RSPA recognized that the changes to Sec. 192.321 affected only
plastic mains and transmission lines. However, the need for these
changes applies as well to plastic service lines. As with transmission
lines and mains, in some situations operators may be able to save
material and construction costs of service lines located outside
buildings by temporarily installing the lines above ground. Thus,
Sec. 192.375(a), which requires that plastic service lines outside
buildings be installed below ground, is revised to allow temporary
aboveground installations in accordance with Sec. 192.321(g).
Section 192.455, External Corrosion Control: Buried or Submerged
Pipelines Installed After July 31, 1971
Under Sec. 192.455(a)(2), a pipeline must have a cathodic
protection system designed to protect the pipeline in its entirety.
RSPA proposed to remove the phrase ``in its entirety'' because it is
unnecessary to convey the meaning of the rule, and some operators have
incorrectly assumed that pipeline casings also must be protected.
In addition, Sec. 192.455(f)(1) exempts from corrosion control
requirements certain metal fittings in plastic pipelines if the fitting
is protected against corrosion by alloyage. RSPA recognized that the
word ``alloyage'' is not in common usage and proposed its replacement
with ``alloy composition'' to improve understanding.
Twelve TPSSC members voted for the proposal, two members supported
it with a recommended change and one abstained. The two members
recommended that in proposed paragraph (f)(1), the term ``corrosion
resistance'' be replaced by ``corrosion control,'' which is the term
used in the existing rule and throughout subpart I. RSPA has made this
replacement in the final rule.
Comments were received from six pipeline operators and one
pipeline-related association. Six commenters gave their full approval
and the seventh was noncommittal. Therefore, except for the previously
discussed wording
[[Page 28779]]
changes, Sec. 192.455 is adopted as proposed in the NPRM.
Section 192.475, Internal Corrosion Control: General.
Section 192.475(c) limits the hydrogen sulfide content of natural
gas stored in pipe-type or bottle-type holders to 0.1 grain per 100
standard cubic feet of gas. An operator proposed that this rule be
relaxed to allow a concentration of 0.25 grain per 100 standard cubic
feet of gas. Because the 0.25 limit is within customary industry
contract limits and is still lower than maximum allowable safe limits
set by other government agencies, RSPA proposed to increase the
allowable hydrogen sulfide limit in gas to be stored in pipe-type and
bottle-type holders to 0.25 grain per 100 standard cubic feet of gas.
This action would lower the cost of processing natural gas that
contains small quantities of hydrogen sulfide.
Thirteen TPSSC members voted for the proposal, one against, and one
member abstained.
Seven commenters supported the proposed change. No commenters
opposed the change. One state agency suggested that hydrogen sulfide
levels be expressed in parts per million in addition to grains per 100
standard cubic feet of gas. The NAPSR report also made this
recommendation, and all comments on the subject were supportive. RSPA
agrees the allowable level should be stated in parts per million and
has included this designation in the final rule.
Section 192.485, Remedial Measures: Transmission Lines
RSPA's review of Sec. 192.485, which prescribes remedial measures
for corroded transmission lines, disclosed that many operators need
guidance on how to determine the remaining strength of corroded pipe.
RSPA proposed to provide this guidance by referencing ASME B31G Manual
for Determining the Remaining Strength of Corroded Pipelines in a new
Sec. 192.485(c).
Fourteen TPSSC members voted for the proposal and one member
abstained.
Comments relevant to proposed Sec. 192.485(c) were received from 10
pipeline operators and two pipeline-related associations. Six
commenters gave their full or partial support. Another six said the
proposal was unnecessarily restrictive because it did not allow the use
of other proven industry-developed methods for determining the
remaining strength of corroded pipelines.
The most noteworthy method mentioned was the method in the American
Gas Association (AGA) report for Project PR 3-805, ``A Modified
Criterion for Evaluating the Remaining Strength of Corroded Pipe,''
(December 22, 1989; AGA catalog No. L51609). Project PR 3-805 was
undertaken to devise a criterion that, while still assuring adequate
pipeline integrity, would eliminate, as much as possible, the excess
conservatism embodied in the ASME B31G Manual. For a complex analysis,
the modified criterion can be applied by using a computer program
called RSTRENG, which is furnished with the report. The modified
criterion can also be applied with a long-hand equation, or if a
simplified analysis is preferred, with tables or curves.
Evaluating the strength of corroded pipe by procedures in ASME B31G
or the associated AGA report is subject to the limitations specified in
the procedures. For example, the procedures are not appropriate for
determining the ability of pipe to withstand stresses other than stress
from internal pressure. Thus, if corroded pipe is under significant
secondary stress (e.g., bending stress), an additional method must be
used to determine the pipe's remaining strength.
The NAPSR report recommended amending Sec. 192.483 to require the
use of appropriate guides, such as those published by ASME and the Gas
Piping Technology Committee, whenever the remaining strength of
corroded pipelines must be determined. The majority of commenters who
addressed this NAPSR recommendation opposed mandatory use of the
guides. They said operators should retain the flexibility to decide
when calculations under the guides are necessary. Even those commenters
who supported the recommendation thought the rule should permit the use
of other valid methods.
After considering the comments on proposed Sec. 192.485(c) and the
NAPSR recommendation, we believe the NAPSR recommendation would be
unduly restrictive. Operators are now free to use any valid method to
determine the remaining strength of corroded pipe, and we see no
compelling reason to restrain this flexibility. The NPRM simply
proposed to reference guidance documents that are generally available
for operators to use at their discretion. Moreover, the proposal was
written in a permissive sense to assist, but not restrict, operator
decision-making. So we have amended the regulation essentially as
proposed, but referenced both ASME B31G and the AGA report, with
RSTRENG, to expand the information provided.
Section 192.491, Corrosion Control Records
Under Sec. 192.491(a), operators must maintain records or maps
showing the location of cathodically protected piping, cathodic
protection facilities, other than unrecorded anodes installed before
August 1, 1971, and neighboring structures bonded to the cathodic
protection system. RSPA proposed to amend this requirement to relieve
operators of the burden of making precise field measurements and
preparing and maintaining records or maps showing the specific location
of millions of individual anodes.
The TPSSC members voted unanimously for the proposal.
Comments on proposed Sec. 192.491(a) were received from six
pipeline operators, two pipeline-related associations, and one state
agency. Eight commenters expressed their full or partial support with
one commenter opposed. RSPA has accepted the recommendation of two
operators that in the second sentence of proposed paragraph (a), the
phrase ``Records and maps * * *'' should, for consistency with the rest
of this section, be changed to ``Records or maps * * *.''
Section 192.491(b)(2) requires that operators retain records of
corrosion control tests, surveys, and inspections for ``as long as the
pipeline remains in service.'' RSPA proposed to reduce this retention
period to at least 5 years for many records, because 5 years was
thought to be adequate for compliance investigations and analysis of
possible corrosion problems.
The proposal did not, however, extend to records under
Secs. 192.465 (a) and (e) and 192.475(b). These records relate to tests
and inspections to determine the adequacy of, or need for, external and
internal protection on existing lines. RSPA felt strongly that these
records should continue to be kept for the service life of the
pipeline, because they provide a valuable database for use in assessing
corrosion problems.
The TPSSC unanimously supported the proposal.
Three pipeline-related associations, 10 operators, and one state
agency commented on the proposal. Four of these commenters agreed with
the proposal as written; the rest qualified their support by
recommending changes.
Five commenters, including two pipeline-related associations and a
state agency, were not persuaded of the importance of keeping records
of
[[Page 28780]]
corrosion monitoring under Sec. 192.465 for the life of the pipe. Most
of these commenters declared that 5 years would be adequate, but did
not explain why a longer period is excessive. Lacking any convincing
documentation to the contrary, RSPA believes the current rule should
stay in effect. In our experience, a history of corrosion monitoring
sheds light on the possible causes of a pipeline's condition. Such
history has proven to be a valuable resource in deciding the extent and
kind of remedial action needed when corrosion problems emerge on a
pipeline.
Regarding the proposed 5-year retention time for records other than
those required by Secs. 192.465 (a) and (e) and 192.475(b), two
commenters said the minimum time should be 3 years to coincide with the
longest interval between inspections. Two others suggested that instead
of a set time, we adopt a performance standard for record retention,
basing it on the time needed to observe trends, inquire into
compliance, or collect superseding data. All these comments provide a
reasonable basis for record retention. However, our main concern is
that operators keep records for a period that is compatible with the
occurrence of routine compliance investigations. Therefore, for
simplicity and uniformity, we have decided to adopt the proposed 5-year
minimum retention time.
The state agency that commented objected to the 5-year proposal on
grounds that it would sacrifice information about why external or
atmospheric corrosion control was not installed on pipelines under
Secs. 192.455, 192.457, and 192.479. RSPA believes the loss of this
information after 5 years would not be significant, because the
pipelines involved are covered by requirements for periodic inspections
or tests for corrosion under Secs. 192.465 and 192.481.
Section 192.553, General Requirements
(See previous discussion under Sec. 192.14).
Section 192.607, Determination of Class Location and Maximum Allowable
Operating Pressure
Because Sec. 192.607 has no continuing effect and the deadlines for
compliance have expired, RSPA proposed to remove Sec. 192.607 from part
192.
Fourteen TPSSC members voted for the proposal and one member
abstained.
Five operators, one pipeline-related association, and one state
agency commented on the proposed removal of Sec. 192.607. Four
operators and the association favored the idea. One operator and the
state agency disagreed with removal, believing the rule is needed to
tie a pipeline's maximum allowable operating pressure (MAOP) to its
class location. Similarly, the NAPSR report recommended that we only
remove the past compliance deadlines from Sec. 192.607, leaving the
rest of the rule in place to regulate the relation of class location to
stress level on high-stress pipelines.
Section 192.607 was a transitional requirement. Its purpose was to
establish plans under which operators initially determined class
locations and confirmed or revised the MAOPs of their high-stress
pipelines commensurate with their class locations. Section 192.607
provides that the plans had to be executed in accordance with
Sec. 192.611. This latter section together with Sec. 192.609 are
sufficient to require that operators have up-to-date class location
determinations for high-stress pipelines, and maintain the MAOPs of
those lines commensurate with their class locations.
Accordingly, Sec. 192.607 is removed from part 192.
Section 192.611, Change in Class Location
Section 192.611 requires confirmation or revision of a pipeline's
MAOP within 18 months after a change in class location. RSPA proposed
to reorganize Sec. 192.611 to clarify the requirement that the MAOP
resulting from confirmation or revision may not exceed the pipeline's
previous MAOP. This requirement is currently set forth in
Sec. 192.611(a)(3)(ii), suggesting that it applies only to
confirmations or revisions under paragraph (a)(3), which is not the
intent.
Fourteen TPSSC members voted for the proposal and one member
abstained.
Five operators and one pipeline-related association commented on
the proposal; each agreed with the proposal. Section 192.611 is,
therefore, adopted as proposed in the NPRM.
Section 192.614, Damage Prevention Program
To decrease excavation damage to pipelines, Sec. 192.614(b)(2)
requires operators to notify excavators and the public about the need
to locate buried pipelines before excavating. The NPRM proposed to
amend the rule to clarify that in contrast to the actual notification
required for excavators, only general notification is required for the
public. General notice can be given through newspapers, radio,
television, or other means of mass communication, as appropriate for
the public in the vicinity of the pipeline.
Fourteen TPSSC members voted for the proposal and one member
abstained.
Six pipeline operators and two pipeline-related organizations
commented. Seven commenters gave their full or qualified approval and
one commenter opposed the proposal. The qualified and negative comments
were that the rule should inform operators of the acceptable means of
notification. We do not feel it is necessary for the rule to do so,
however, because the available means of giving general public notice
are well known. The amendment to paragraph (b)(2) is adopted as
proposed.
Section 192.619, Maximum Allowable Operating Pressure: Steel or Plastic
Pipelines
Section 192.619(a) prescribes six pressure limits for use in
determining the MAOP of steel and plastic pipelines, the lowest of
which establishes the MAOP. Paragraph (a)(4) limits the MAOP of furnace
butt welded pipe to 60 percent of the mill test pressure. Paragraph
(a)(5) limits the MAOP of other steel pipe to 85 percent of the highest
test pressure to which the pipe has been subjected, whether by mill
test or by the post installation test.
RSPA proposed to repeal paragraphs (a)(4) and (a)(5), primarily
because mill tests are not an adequate MAOP consideration. However, to
assure consideration of longitudinal joint efficiency, RSPA also
proposed, in paragraph (a)(2)(iii), that the class location pressure
limit under existing paragraph (a)(2)(ii) be reduced for furnace butt
welded pipe and lap welded pipe.
Eleven TPSSC members voted for the proposal, one member supported
it with a recommended change, two members opposed it, and one
abstained. A member recommended that RSPA not adopt proposed paragraph
(a)(2)(iii) because design pressure (under paragraph (a)(1)) adequately
covers longitudinal joint concerns.
RSPA concurs with this view as explained below in response to
public comment.
Thirteen operators, four pipeline-related associations, and one
state agency commented on the proposed amendment. Two operators, one
pipeline-related association, and one state agency commented that
proposed paragraph (a)(2)(iii) could require operators to reduce the
operating pressure of some pipelines or test them to higher pressures
than they previously were tested, possibly damaging the pipelines. In
addition, some commenters stated that proposed paragraph (a)(2)(iii)
would duplicate use of longitudinal joint factors.
[[Page 28781]]
Upon further consideration of our joint efficiency concern, RSPA
concurs with these comments. Further, RSPA has no data showing that
pipelines covered by proposed paragraph (a)(2)(iii) pose a risk that
warrants pressure reduction or retesting. Therefore, although the final
rule repeals paragraphs (a)(4) and (a)(5) as proposed, proposed
paragraph (a)(2)(iii) is not adopted.
Section 192.625, Odorization of Gas
Section 192.619(f) requires operators to conduct periodic samplings
of gas to assure the proper concentration of odorant. Based on a
suggestion by the Oregon Public Utility Commission, the NPRM proposed
to allow operators of master meter systems to comply with this sampling
requirement by (1) receiving written verification from their gas
supplier that odorant meets the required concentration, and (2)
conducting periodic sniff tests at system extremities to confirm that
the gas contains odorant.
Thirteen TPSSC members voted for the proposal, one against, and one
member abstained.
Comments were received from eight pipeline operators, two pipeline-
related associations, a mobile home association, and a consultant. One
commenter favored the proposal and 11 commenters opposed it. Commenters
opposing the proposal argued that (1) gas from a transmission line may
be unodorized; (2) gas suppliers may be unwilling to provide written
verification of odorization levels because of potential legal liability
and the increased burden of providing the written verifications; (3)
the frequencies of sniff tests and written verifications are unclear;
and (4) the proposal would relax odorant monitoring requirements on gas
systems which, in general, have a relatively high leakage rate.
The purpose of the proposal was to ease the sampling requirement
for operators of master meter systems, who largely do not have the
training or resources to adequately carry out the requirement. The
alternative of getting written verifications and conducting sniff tests
should be much less burdensome than purchasing, maintaining, and using
an odorometer or contracting for odorant testing.
We do not feel this potential advantage is outweighed by any of the
negative considerations the commenters raised. First of all, most
master meter system operators purchase odorized gas from local
distribution companies. Although some operators may receive unodorized
gas from transmission lines and have to odorize the gas themselves,
this situation does not warrant rejecting the proposed alternative.
Those operators who receive unodorized gas simply would not be able to
take advantage of the alternative. Similarly, operators could not take
advantage of the alternative if their gas suppliers are unwilling to
provide requested verifications of odorant level. But again this
difficulty is no reason to deny the alternative to other operators.
Regarding the frequency of verifications and sniff tests, the proposal
called for an initial written verification from the gas supplier and
periodic sniff tests thereafter. As with periodic sampling, the
frequency of sniff tests would depend on the performance history of
odorization in the system: the longer the period of satisfactory
odorization, the longer the period between tests to assure proper
odorant levels. Testing details would be specified in the operator's
operations and maintenance manual under Sec. 192.605 and reviewed for
adequacy by government inspectors. Finally, the charge that master
meter systems have a high leakage rate was unsupported. In a 1984
report, ``Exercise of Jurisdiction Over Master Meter Gas Operators,''
RSPA concluded that master meter systems probably have a small leakage
rate in comparison to the leakage rate of utility distribution systems.
And more recent safety data continue to substantiate that conclusion.
Therefore, after weighing the comments and favorable TPSSC vote, we
have decided to amend Sec. 192.625(f) as proposed.
Section 192.705, Transmission Lines: Patrolling
Operators of transmission lines must patrol their rights-of-way for
indications of certain adverse conditions. Because of repeated
questions about whether patrols may be done from the air, RSPA proposed
to change Sec. 192.705 to include aerial patrols as an optional method
of compliance.
Fourteen TPSSC members voted for the proposal and one abstained.
Six operators and one pipeline-related association commented on the
proposal. All but two of these commenters agreed with the proposal. One
commenter that disagreed said a list of methods of compliance might be
considered exclusive, thus disallowing other appropriate methods. The
other commenter that disagreed thought the rule change unnecessary.
RSPA believes the phrase ``or other appropriate means of traversing
the right-of-way'' in the proposed and final rule eliminates any chance
the list of compliance methods might be considered exclusive. Also, the
need for the rule change is based on RSPA's experience in explaining
the meaning of ``patrol'' under Sec. 192.705. The change to
Sec. 192.705 is, therefore, adopted as proposed.
Section 192.709, Transmission Lines: Record Keeping
Section 192.709 requires operators to keep various records about
transmission lines for as long as the line remains in service. RSPA
proposed a shorter retention span that would not affect the usefulness
of records in determining an operator's level of compliance effort or
in constructing the history of an accident or safety problem. RSPA
proposed a minimum 5-year retention period for records of patrols,
surveys, inspections, and tests, and a 1-year retention period for
records of repairs on facilities other than pipe. We also proposed to
clarify the information to be recorded.
Ten TPSSC members voted for the proposal, three members supported
it with a recommended change, one member opposed it, and one abstained.
The recommended changes were that 5 years should be changed to 3-5
years or to 10 years, and that leaks and linebreaks should also be
recorded as the current Sec. 192.709 provides. The ``No'' vote was
predicated on an alleged need to keep records of repairs on valves,
compressors, and other non- pipe components for 3-5 years.
As with final Sec. 192.491(c), RSPA's main concern about non-pipe
records is that operators keep records for a minimum period that is
compatible with the occurrence of routine compliance investigations.
The suggested 3-5 years would not be long enough, and 10 years would be
excessive. Therefore, we have adopted the proposed 5-year minimum
period.
Repair records, as currently required, already provide information
about leaks and linebreaks. Thus, requirements to keep the records of
leaks and linebreaks were omitted from the proposed rule as unnecessary
in view of this existing requirement.
As for the ``No'' vote, RSPA has adopted this minority TPSSC
position as explained below in response to a comment by a state agency.
Eight operators, two pipeline-related associations, and one state
agency commented on the proposed changes to Sec. 192.709. Five of the
operators supported the proposal without suggesting any modification.
Two other operators suggested 3 years as an alternative to the
proposed 5-year minimum. But, as explained above, 3 years is
insufficient for compliance monitoring purposes.
[[Page 28782]]
One operator thought the words ``for the useful life of the pipe''
under proposed Sec. 192.709(a) could be misinterpreted. This commenter
suggested that instead we adopt the words used in Sec. 192.491(c):
``for as long as the pipeline remains in service.'' We agree that for
consistency the two sections should use similar wording to describe
similar record retention requirements. This comment was, therefore,
adopted in the final rule.
One pipeline-related association recommended that Sec. 192.709 be
like 49 CFR 195.404(c), which applies to hazardous liquid pipelines. We
did not adopt this comment because Sec. 195.404(c) specifies a 2-year
retention period for records of inspections and tests, a time we now
find to be insufficient for purposes of compliance investigations.
Otherwise the two sections are parallel. The other association
reiterated its previous comment, which we opposed as discussed above,
that record retention requirements should be performance based.
The state agency that commented objected to the proposed 1-year
retention time for non-pipe repairs, saying it was inconsistent with
the proposal to keep for at least 5 years records of inspections that
may show the need for repair. This commenter reasoned that an inspector
might not find any record showing the needed repair was made. RSPA
agrees that the two requirements should be congruent. Therefore, the
final rule requires that records of non-pipe repairs made as a result
of a required patrol, survey, inspection, or test be kept for the same
time required for records of such patrol, survey, inspection, or test.
Section 192.721, Distribution Systems: Patrolling
This section governs the frequency at which operators must patrol
mains in distribution systems. The regulation is written in performance
terms, except that mains located where anticipated movement or loading
could cause leakage must be patrolled at intervals not exceeding 4\1/2\
months, but at least four times a year. RSPA proposed a more moderate
patrol frequency of twice a year for such mains in Class 1 or 2
locations, in recognition of the lower risk in these less densely
populated locations.
Twelve TPSSC members voted for the proposal, one against, one
member supported it with a proposed change, and one abstained. The
member against the proposal said that separating requirements on the
basis of class locations is not always workable for distribution
systems. Our response to this minority view is given below following
similar comments by operators.
Four operators and two pipeline-related associations commented on
the proposal. Three of the operators and one association supported the
proposal, but the other operator and association thought class location
should not be used as a basis for patrol frequency in distribution
systems. One commenter suggested ``rural areas'' as an alternative to
Class 1 and 2 locations.
RSPA agrees that the class location concept is not easy to apply in
all distribution systems. Therefore, in the final rule, we have used
the term ``business district'' to represent areas of higher risk and
``outside business districts'' to represent areas of lower risk. A
similar classification method is already in place under Sec. 192.723
for leakage surveys in distribution systems. The new patrol requirement
matches that method. The term ``rural area'' was not adopted because it
lacks precedent in part 192.
Rulemaking Notices and Analyses
Paperwork Reduction Act
This Final Rule revises information collection requirements in part
192 that are subject to review by the Office of Management and Budget
(OMB) under the Paperwork Reduction Act of 1995 (Pub. L. 104-13). The
following revised regulations reduce the existing paperwork burden by
28,326 hours:
Secs. 192.491 (a) and (b), ``Corrosion Control Records,''
reduces the paperwork burden by 22,486 hours by reducing the number of
records, the precision of the measurements, and the amount of time the
records must be kept.
Sec. 192.709, ``Transmission Lines; Record keeping,''
reduces the paperwork burden by 5,840 hours by reducing the amount of
time the records must be kept.
Persons are not required to respond to a collection of information
unless it displays a currently valid OMB control number. OMB has
approved the revised information collection requirements of part 192
through May 31, 1999 (OMB No. 2137-0049).
Executive Order 12866 and DOT Regulatory Policies and Procedures
OMB considers this final rule to be a significant regulatory action
under section 3(f) of Executive Order 12866. Therefore, OMB has
reviewed the final rule. Also, DOT considers the final rule to be
significant under its regulatory policies and procedures (44 FR 11034,
February 26, 1979).
A final regulatory evaluation has been prepared and is available in
the Docket. RSPA estimates the changes to existing rules will result in
savings of $33,000,000 a year, without associated costs and with no
adverse effect on safety. As discussed above, these savings come from
the use of new technology, greater flexibility in constructing,
maintaining, and operating pipelines, improved clarity, and the
elimination of burdensome requirements.
Regulatory Flexibility Act.
RSPA criteria for small companies or entities are those with less
than $1,000,000 in revenues and are independently owned and operated.
Few of the companies subject to this rulemaking meet these criteria.
Accordingly, based on the facts available concerning the impact of this
final rule, I certify under Section 605 of the Regulatory Flexibility
Act that this final rule will not have a significant economic impact on
a substantial number of small entities.
E. O. 12612
The final rule would 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 Executive Order
12612 (52 FR 41685; October 30,1987), RSPA has determined that the
final rule does not have sufficient federalism implications to warrant
preparation of a Federalism Assessment.
List of Subjects in 49 CFR Part 192
Incorporation by reference, Natural gas, Pipeline safety, Reporting
and recordkeeping requirements.
In consideration of the foregoing, RSPA amends 49 CFR part 192 as
follows:
PART 192--[AMENDED]
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; 49 CFR 1.53.
2. In Sec. 192.1, paragraph (b)(1) is revised and paragraph (b)(4)
is added to read as follows:
Sec. 192.1 Scope of part.
* * * * *
(b) This part does not apply to:
(1) Offshore pipelines upstream from the outlet flange of each
facility where hydrocarbons are produced or where
[[Page 28783]]
produced hydrocarbons are first separated, dehydrated, or otherwise
processed, whichever facility is farther downstream;
* * * * *
(4) Any pipeline system that transports only petroleum gas or
petroleum gas/air mixtures to--
(i) Fewer than 10 customers, if no portion of the system is located
in a public place; or
(ii) A single customer, if the system is located entirely on the
customer's premises (no matter if a portion of the system is located in
a public place).
3. In Sec. 192.3, a definition of ``Petroleum gas'' is added and
the definition of ``Transmission line'' is revised to read as follows:
Sec. 192.3 Definitions.
* * * * *
Petroleum gas means propane, propylene, butane, (normal butane or
isobutanes), and butylene (including isomers), or mixtures composed
predominantly of these gases, having a vapor pressure not exceeding
1434 kPa (208 psig) at 38 deg.C (100 deg.F).
* * * * *
Transmission line means a pipeline, other than a gathering line,
that:
(a) Transports gas from a gathering line or storage facility to a
distribution center, storage facility, or large volume customer that is
not downstream from a distribution center;
(b) Operates at a hoop stress of 20 percent or more of SMYS; or
(c) Transports gas within a storage field. A large volume customer
may receive similar volumes of gas as a distribution center, and
includes factories, power plants, and institutional users of gas.
* * * * *
4. Section 192.5 is revised to read as follows:
Sec. 192.5 Class locations.
(a) This section classifies pipeline locations for purposes of this
part. The following criteria apply to classifications under this
section.
(1) A ``class location unit'' is an onshore area that extends 220
yards on either side of the centerline of any continuous 1- mile length
of pipeline.
(2) Each separate dwelling unit in a multiple dwelling unit
building is counted as a separate building intended for human
occupancy.
(b) Except as provided in paragraph (c) of this section, pipeline
locations are classified as follows:
(1) A Class 1 location is:
(i) An offshore area; or
(ii) Any class location unit that has 10 or fewer buildings
intended for human occupancy.
(2) A Class 2 location is any class location unit that has more
than 10 but fewer than 46 buildings intended for human occupancy.
(3) A Class 3 location is:
(i) Any class location unit that has 46 or more buildings intended
for human occupancy; or
(ii) An area where the pipeline lies within 100 yards of either a
building or a small, well-defined outside area (such as a playground,
recreation area, outdoor theater, or other place of public assembly)
that is occupied by 20 or more persons on at least 5 days a week for 10
weeks in any 12-month period. (The days and weeks need not be
consecutive.)
(4) A Class 4 location is any class location unit where buildings
with four or more stories above ground are prevalent.
(c) The length of Class locations 2, 3, and 4 may be adjusted as
follows:
(1) A Class 4 location ends 220 yards from the nearest building
with four or more stories above ground.
(2) When all buildings intended for human occupancy within a Class
2 or 3 location are in a single cluster, the class location ends 220
yards from the nearest building in the cluster.
5. Section 192.7(a) is revised to read as follows:
Sec. 192.7 Incorporation by reference.
(a) Any documents or portions thereof incorporated by reference in
this part are included in this part as though set out in full. When
only a portion of a document is referenced, the remainder is not
incorporated in this part.
* * * * *
6. Section 192.11 is revised to read as follows:
Sec. 192.11 Petroleum gas systems.
(a) Each plant that supplies petroleum gas by pipeline to a natural
gas distribution system must meet the requirements of this part and
ANSI/NFPA 58 and 59.
(b) Each pipeline system subject to this part that transports only
petroleum gas or petroleum gas/air mixtures must meet the requirements
of this part and of ANSI/NFPA 58 and 59.
(c) In the event of a conflict between this part and ANSI/NFPA 58
and 59, ANSI/NFPA 58 and 59 prevail.
7. Section 192.107(b)(1)(ii) is revised to read as follows:
Sec. 192.107 Yield strength (S) for steel pipe.
* * * * *
(b) * * *
(1) * * *
(ii) The lowest yield strength determined by the tensile tests.
* * * * *
8. Section 192.121 is revised to read as follows:
Sec. 192.121 Design of plastic pipe.
Subject to the limitations of Sec. 192.123, the design pressure for
plastic pipe is determined in accordance with either of the following
formulas:
[GRAPHIC] [TIFF OMITTED] TR06JN96.013
Where:
P=Design pressure, gauge, kPa (psig).
S=For thermoplastic pipe, the long-term hydrostatic strength determined
in accordance with the listed specification at a temperature equal to
23 deg.C (73 deg.F), 38 deg.C (100 deg.F), 49 deg.C (120 deg.F), or
60 deg.C (140 deg.F); for reinforced thermosetting plastic pipe, 75,842
kPa (11,000 psi).
t=Specified wall thickness, mm (in).
D=Specified outside diameter, mm (in).
SDR=Standard dimension ratio, the ratio of the average specified
outside diameter to the minimum specified wall thickness, corresponding
to a value from a common numbering system that was derived from the
American National Standards Institute preferred number series 10.
9. Section 192.123(b) is revised to read as follows:
Sec. 192.123 Design limitations for plastic pipe.
* * * * *
(b) * * *
(1) Below -29 deg.C (-20 deg.F), or -40 deg.C (-40 deg.F) if all
pipe and pipeline components whose operating temperature will be below
-29 deg.C (-20 deg.F) have a temperature rating by the manufacturer
consistent with that operating temperature; or
(2) Above the following applicable temperatures:
(i) For thermoplastic pipe, the temperature at which the long-term
hydrostatic strength used in the design formula under Sec. 192.121 is
determined. However, if the pipe was manufactured before May 18, 1978
and its long-term hydrostatic strength was determined at 23 deg.C
(73 deg.F), it may be used at temperatures up to 38 deg.C (100 deg.F).
(ii) For reinforced thermosetting plastic pipe, 66 deg.C
(150 deg.F).
* * * * *
[[Page 28784]]
10. The introductory text of Sec. 192.179(a) is revised to read as
follows:
Sec. 192.179 Transmission line valves.
(a) Each transmission line, other than offshore segments, must have
sectionalizing block valves spaced as follows, unless in a particular
case the Administrator finds that alternative spacing would provide an
equivalent level of safety:
* * * * *
11. Section 192.203(b)(2) is revised to read as follows:
Sec. 192.203 Instrument, control, and sampling pipe and components.
* * * * *
(b) * * *
(2) Except for takeoff lines that can be isolated from sources of
pressure by other valving, a shutoff valve must be installed in each
takeoff line as near as practicable to the point of takeoff. Blowdown
valves must be installed where necessary.
* * * * *
12. Section 192.227(b) is revised to read as follows:
Sec. 192.227 Qualification of welders.
* * * * *
(b) A welder may qualify to perform welding on pipe to be operated
at a pressure that produces a hoop stress of less than 20 percent of
SMYS by performing an acceptable test weld, for the process to be used,
under the test set forth in section I of Appendix C of this part. Each
welder who is to make a welded service line connection to a main must
first perform an acceptable test weld under section II of Appendix C of
this part as a requirement of the qualifying test.
13. In Sec. 192.229, paragraph (c) is revised and paragraph (d) is
added to read as follows:
Sec. 192.229 Limitations on welders.
* * * * *
(c) A welder qualified under Sec. 192.227(a)--
(1) May not weld on pipe to be operated at a pressure that produces
a hoop stress of 20 percent or more of SMYS unless within the preceding
6 calendar months the welder has had one weld tested and found
acceptable under section 3 or 6 of API Standard 1104, except that a
welder qualified under an earlier edition previously listed in Appendix
A of this part may weld but may not requalify under that earlier
edition; and
(2) May not weld on pipe to be operated at a pressure that produces
a hoop stress of less than 20 percent of SMYS unless the welder is
tested in accordance with paragraph (c)(1) of this section or
requalifies under paragraph (d)(1) or (d)(2) of this section.
(d) A welder qualified under Sec. 192.227(b) may not weld unless--
(1) Within the preceding 15 calendar months, but at least once each
calendar year, the welder has requalified under Sec. 192.227(b); or
(2) Within the preceding 7\1/2\ calendar months, but at least twice
each calendar year, the welder has had--
(i) A production weld cut out, tested, and found acceptable in
accordance with the qualifying test; or
(ii) For welders who work only on service lines 2 inches or smaller
in diameter, two sample welds tested and found acceptable in accordance
with the test in section III of Appendix C of this part.
14. Section 192.241(c) is revised to read as follows:
Sec. 192.241 Inspection and test of welds.
* * * * *
(c) The acceptability of a weld that is nondestructively tested or
visually inspected is determined according to the standards in section
6 of API Standard 1104. However, if a girth weld is unacceptable under
those standards for a reason other than a crack, and if the Appendix to
API Standard 1104 applies to the weld, the acceptability of the weld
may be further determined under that Appendix.
15. Section 192.243(d)(4) is revised to read as follows:
Sec. 192.243 Nondestructive testing.
* * * * *
(d) * * *
(4) At pipeline tie-ins, including tie-ins of replacement sections,
100 percent.
* * * * *
16. In Sec. 192.281, paragraph (c)(3) is redesignated as paragraph
(c)(4) and paragraph (c)(3) is added to read as follows:
Sec. 192.281 Plastic pipe.
* * * * *
(c) * * *
(3) An electrofusion joint must be joined utilizing the equipment
and techniques of the fittings manufacturer or equipment and techniques
shown, by testing joints to the requirements of
Sec. 192.283(a)(1)(iii), to be at least equivalent to those of the
fittings manufacturer.
* * * * *
17. In Sec. 192.283, the word ``or'' is removed from the end of
paragraph (a)(1)(i), paragraph (a)(1)(ii) is revised, and paragraph
(a)(1)(iii) is added to read as follows:
Sec. 192.283 Plastic pipe; qualifying joining procedures.
(a) * * *
(1) * * *
(ii) In the case of thermosetting plastic pipe, paragraph 8.5
(Minimum Hydrostatic Burst Pressure) or paragraph 8.9 (Sustained Static
Pressure Test) of ASTM D2517; or
(iii) In the case of electrofusion fittings for polyethylene pipe
and tubing, paragraph 9.1 (Minimum Hydraulic Burst Pressure Test),
paragraph 9.2 (Sustained Pressure Test), paragraph 9.3 (Tensile
Strength Test), or paragraph 9.4 (Joint Integrity Tests) of ASTM
Designation F1055.
* * * * *
18. Section 192.317(a) is revised to read as follows:
Sec. 192.317 Protection from hazards.
(a) The operator must take all practicable steps to protect each
transmission line or main from washouts, floods, unstable soil,
landslides, or other hazards that may cause the pipeline to move or to
sustain abnormal loads. In addition, the operator must take all
practicable steps to protect offshore pipelines from damage by mud
slides, water currents, hurricanes, ship anchors, and fishing
operations.
* * * * *
19. Section 192.319(c) is revised to read as follows:
Sec. 192.319 Installation of pipe in a ditch.
* * * * *
(c) All offshore pipe in water at least 12 feet deep but not more
than 200 feet deep, as measured from the mean low tide, except pipe in
the Gulf of Mexico and its inlets under 15 feet of water, must be
installed so that the top of the pipe is below the natural bottom
unless the pipe is supported by stanchions, held in place by anchors or
heavy concrete coating, or protected by an equivalent means. Pipe in
the Gulf of Mexico and its inlets under 15 feet of water must be
installed so that the top of the pipe is 36 inches below the seabed for
normal excavation or 18 inches for rock excavation.
20. In Sec. 192.321, paragraph (a) is revised and paragraph (g) is
added to read as follows:
Sec. 192.321 Installation of plastic pipe.
(a) Plastic pipe must be installed below ground level unless
otherwise permitted by paragraph (g) of this section.
* * * * *
(g) Uncased plastic pipe may be temporarily installed above ground
level under the following conditions:
[[Page 28785]]
(1) The operator must be able to demonstrate that the cumulative
aboveground exposure of the pipe does not exceed the manufacturer's
recommended maximum period of exposure or 2 years, whichever is less.
(2) The pipe either is located where damage by external forces is
unlikely or is otherwise protected against such damage.
(3) The pipe adequately resists exposure to ultraviolet light and
high and low temperatures.
21. In Sec. 192.327, the introductory text of paragraph (a) is
revised, paragraph (e) is revised, and paragraphs (f) and (g) are added
to read as follows:
Sec. 192.327 Cover.
* * * * *
(a) Except as provided in paragraphs (c), (e), (f), and (g) of this
section, each buried transmission line must be installed with a minimum
cover as follows:
* * * * *
(e) Except as provided in paragraph (c) of this section, all pipe
installed in a navigable river, stream, or harbor must be installed
with a minimum cover of 48 inches in soil or 24 inches in consolidated
rock between the top of the pipe and the natural bottom.
(f) All pipe installed offshore, except in the Gulf of Mexico and
its inlets, under water not more than 200 feet deep, as measured from
the mean low tide, must be installed as follows:
(1) Except as provided in paragraph (c) of this section, pipe under
water less than 12 feet deep, must be installed with a minimum cover of
36 inches in soil or 18 inches in consolidated rock between the top of
the pipe and the natural bottom.
(2) Pipe under water at least 12 feet deep must be installed so
that the top of the pipe is below the natural bottom, unless the pipe
is supported by stanchions, held in place by anchors or heavy concrete
coating, or protected by an equivalent means.
(g) All pipelines installed under water in the Gulf of Mexico and
its inlets, as defined in Sec. 192.3, must be installed in accordance
with Sec. 192.612(b)(3).
22. Section 192.375(a) is revised to read as follows:
Sec. 192.375 Service lines: Plastic.
(a) Each plastic service line outside a building must be installed
below ground level, except that--
(1) It may be installed in accordance with Sec. 192.321(g); and
(2) It may terminate above ground level and outside the building,
if--
(i) The above ground level part of the plastic service line is
protected against deterioration and external damage; and
(ii) The plastic service line is not used to support external
loads.
* * * * *
23. In Sec. 192.455, paragraphs (a)(2) and (f)(1) are revised to
read as follows:
Sec. 192.455 External corrosion control: Buried or submerged pipelines
installed after July 31, 1971.
(a) * * *
(2) It must have a cathodic protection system designed to protect
the pipeline in accordance with this subpart, installed and placed in
operation within 1 year after completion of construction.
* * * * *
(f) * * *
(1) For the size fitting to be used, an operator can show by test,
investigation, or experience in the area of application that adequate
corrosion control is provided by the alloy composition; and
* * * * *
24. Section 192.475(c) is revised to read as follows:
Sec. 192.475 Internal corrosion control: General.
* * * * *
(c) Gas containing more than 0.25 grain of hydrogen sulfide per 100
standard cubic feet (4 parts per million) may not be stored in pipe-
type or bottle-type holders.
25. Section 192.485(c) is added to read as follows:
Sec. 192.485 Remedial measures: Transmission lines.
* * * * *
(c) Under paragraphs (a) and (b) of this section, the strength of
pipe based on actual remaining wall thickness may be determined by the
procedure in ASME/ANSI B31G or the procedure in AGA Pipeline Research
Committee Project PR 3-805 (with RSTRENG disk). Both procedures apply
to corroded regions that do not penetrate the pipe wall, subject to the
limitations prescribed in the procedures.
26. Section 192.491 is revised to read as follows:
Sec. 192.491 Corrosion control records.
(a) Each operator shall maintain records or maps to show the
location of cathodically protected piping, cathodic protection
facilities, galvanic anodes, and neighboring structures bonded to the
cathodic protection system. Records or maps showing a stated number of
anodes, installed in a stated manner or spacing, need not show specific
distances to each buried anode.
(b) Each record or map required by paragraph (a) of this section
must be retained for as long as the pipeline remains in service.
(c) Each operator shall maintain a record of each test, survey, or
inspection required by this subpart in sufficient detail to demonstrate
the adequacy of corrosion control measures or that a corrosive
condition does not exist. These records must be retained for at least 5
years, except that records related to Secs. 192.465 (a) and (e) and
192.475(b) must be retained for as long as the pipeline remains in
service.
27. Section 192.553(d) is revised to read as follows:
Sec. 192.553 General requirements.
* * * * *
(d) Limitation on increase in maximum allowable operating pressure.
Except as provided in Sec. 192.555(c), a new maximum allowable
operating pressure established under this subpart may not exceed the
maximum that would be allowed under this part for a new segment of
pipeline constructed of the same materials in the same location.
However, when uprating a steel pipeline, if any variable necessary to
determine the design pressure under the design formula (Sec. 192.105)
is unknown, the MAOP may be increased as provided in
Sec. 192.619(a)(1).
Sec. 192.607 [Removed and reserved]
28. Section 192.607 is removed and reserved.
Sec. 192.611 [Amended]
29. In Sec. 192.611, paragraphs (b) and (c) are redesignated as (c)
and (d), respectively; paragraph (a)(3)(ii) is redesignated as
paragraph (b), and paragraph (a)(3)(iii) is redesignated as paragraph
(a)(3)(ii).
30. In Sec. 192.614, the introductory text of paragraph (b)(2) is
revised to read as follows:
Sec. 192.614 Damage prevention program.
* * * * *
(b) * * *
(2) Provide for general notification of the public in the vicinity
of the pipeline and actual notification of the persons identified in
paragraph (b)(1) of the following as often as needed to make them aware
of the damage prevention program:
* * * * *
31. In Sec. 192.619, paragraph (a)(1) is revised to read as
follows, paragraphs (a)(4) and (a)(5) are removed, paragraph (a)(6) is
redesignated as paragraph (a)(4), and paragraph (b) is amended by
removing ``(a)(6)'' and adding ``(a)(4)'' in its place:
Sec. 192.619 Maximum allowable operating pressure: Steel or plastic
pipelines.
(a) * * *
[[Page 28786]]
(1) The design pressure of the weakest element in the segment,
determined in accordance with subparts C and D of this part. However,
for steel pipe in pipelines being converted under Sec. 192.14 or
uprated under subpart K of this part, if any variable necessary to
determine the design pressure under the design formula (Sec. 192.105)
is unknown, one of the following pressures is to be used as design
pressure:
(i) Eighty percent of the first test pressure that produces yield
under section N5.0 of Appendix N of ASME B31.8, reduced by the
appropriate factor in paragraph (a)(2)(ii) of this section; or
(ii) If the pipe is 324 mm (12\3/4\ in) or less in outside diameter
and is not tested to yield under this paragraph, 1379 kPa (200 psig).
* * * * *
32. Section 192.625 (f) is revised to read as follows:
Sec. 192.625 Odorization of gas.
* * * * *
(f) Each operator shall conduct periodic sampling of combustible
gases to assure the proper concentration of odorant in accordance with
this section. Operators of master meter systems may comply with this
requirement by--
(1) Receiving written verification from their gas source that the
gas has the proper concentration of odorant; and
(2) Conducting periodic ``sniff'' tests at the extremities of the
system to confirm that the gas contains odorant.
33. Section 192.705(c) is added to read as follows:
Sec. 192.705 Transmission lines: Patrolling.
* * * * *
(c) Methods of patrolling include walking, driving, flying or other
appropriate means of traversing the right-of-way.
34. Section 192.709 is revised to read as follows:
Sec. 192.709 Transmission lines: Record keeping.
Each operator shall maintain the following records for transmission
lines for the periods specified:
(a) The date, location, and description of each repair made to pipe
(including pipe-to-pipe connections) must be retained for as long as
the pipe remains in service.
(b) The date, location, and description of each repair made to
parts of the pipeline system other than pipe must be retained for at
least 5 years. However, repairs generated by patrols, surveys,
inspections, or tests required by subparts L and M of this part must be
retained in accordance with paragraph (c) of this section.
(c) A record of each patrol, survey, inspection, and test required
by subparts L and M of this part must be retained for at least 5 years
or until the next patrol, survey, inspection, or test is completed,
whichever is longer.
35. Section 192.721(b) is revised to read as follows:
Sec. 192.721 Distribution systems: Patrolling.
* * * * *
(b) Mains in places or on structures where anticipated physical
movement or external loading could cause failure or leakage must be
patrolled--
(1) In business districts, at intervals not exceeding 4\1/2\
months, but at least four times each calendar year; and
(2) Outside business districts, at intervals not exceeding 7\1/2\
months, but at least twice each calendar year.
36. In Appendix A, section I. is amended by redesignating
subsections A. through F. as subsections B. through G., respectively,
and by adding a new subsection A.; and section II. is amended by
redesignating subsections A. through E. as subsections B. through F.,
respectively, by adding a new subsection A. and a new subsection 12. to
newly designated C., by redesignating newly designated subsections D.3.
through D.5. as subsections D.5. through D.7., respectively, and by
adding new subsections D.3. and D.4. as follows:
Appendix A--Incorporated by Reference
I. * * *
A. American Gas Association (AGA), 1515 Wilson Boulevard,
Arlington, VA 22209.
* * * * *
II. * * *
A. American Gas Association (AGA):
1. AGA Pipeline Research Committee, Project PR-3-805, ``A
Modified Criterion for Evaluating the Remaining Strength of Corroded
Pipe'' (December 22, 1989).
* * * * *
C. * * *
12. ASTM Designation: F1055 ``Standard Specification for
Electrofusion Type Polyethylene Fittings for Outside Diameter
Controlled Polyethylene Pipe and Tubing'' (F1055-95).
D. * * *
3. ASME/ANSI B31G ``Manual for Determining the Remaining
Strength of Corroded Pipelines'' (1991).
4. ASME/ANSI B31.8 ``Gas Transmission and Distribution Piping
Systems'' (1995).
* * * * *
Issued in Washington, DC, on May 28, 1996.
D.K. Sharma,
Administrator.
[FR Doc. 96-13787 Filed 6-5-96; 8:45 am]
BILLING CODE 4910-60-P