Pipeline safety: Instrumented internal inspection devices; passage,
[Federal Register: June 28, 2004 (Volume 69, Number 123)]
[Rules and Regulations]
[Page 36024-36029]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr28jn04-11]
DEPARTMENT OF TRANSPORTATION
Research and Special Programs Administration
[Docket No. RSPA-03-16330; Amdt. 192-97]
RIN 2137-AB71
Pipeline Safety: Passage of Internal Inspection Devices
AGENCY: Research and Special Programs Administration (RSPA), DOT.
ACTION: Final rule.
SUMMARY: The Research and Special Programs Administration (RSPA) published a regulation requiring that new gas transmission lines and sections of existing transmission lines in which pipe or components are replaced be designed and constructed to accommodate the passage of instrumented internal inspection devices. Responding to petitions for reconsideration, RSPA stayed enforcement on some facilities and invited comments on proposed changes to the regulation. The present action concludes our consideration of the petitions and comments. For existing onshore transmission lines, this action restricts the regulation to replacements of pipe or components. For offshore transmission lines, the regulation is restricted to certain new lines that run between platforms or from platforms to shore. The action aligns the regulation with the supporting congressional directive and a related Marine Board recommendation.
DATES: This Final Rule takes effect July 28, 2004. Offshore transmission lines covered by revised Sec. 192.150 are those on which construction begins after December 28, 2005.
FOR FURTHER INFORMATION CONTACT: L. M. Furrow by phone at 202-366-4559, by fax at 202-366-4566, by mail at U.S. Department of Transportation, 400 Seventh Street, SW., Washington, DC 20590, or by e-mail at buck.furrow@rspa.dot.gov.
SUPPLEMENTARY INFORMATION:
Background
This proceeding began when RSPA proposed regulations (49 CFR 192.150 and 195.120) that would require operators, except in certain impracticable situations, to design and construct new and replacement gas transmission lines and new and replacement hazardous liquid pipelines to accommodate the passage of instrumented internal inspection devices (57 FR 54745; Nov. 20, 1992) (``Notice 1'').\1\ The proposed regulations were in response to congressional directives in Sections 108(b) and 207(b) of the Pipeline Safety Reauthorization Act of 1988 (Pub. L. 100-561; Oct. 31, 1988).\2\
\1\ The proposed gas transmission line regulation (49 CFR 192.150) was substantially identical to the proposed regulation for hazardous liquid pipelines (49 CFR 195.120). Proposed Sec. 192.150 reads as follows:
Sec. 192.150 Provision for internal passage of inspection devices.
(a) Except as provided in paragraph (b) of this section, each new transmission line and each replacement transmission line must be designed and constructed to accommodate the passage of instrumented internal inspection devices.
(b) Paragraph (a) of this section does not apply to manifolds, station piping (such as compressor stations, metering stations, or regulator stations), cross-overs, and fittings that provide branch line junctures (such as tees and other lateral connections), and any other piping that the Administrator finds in a particular case would be impracticable to design and construct to accommodate the passage of an instrumented internal inspection device. In the case of fittings providing branch line junctures, however, restraining elements must be added to the fitting so that pigs can pass in the direction of straight flow.
\2\ Section 108(b) added the following new Section 3(g) to the Natural Gas Pipeline Safety Act of 1968: (g) Instrumented Internal Inspection Devices.--The Secretary shall, by regulation, establish minimum Federal safety standards requiring that--
(1) the design and construction of new transmission facilities, and
(2) when replacement of existing transmission facilities or equipment is required, the replacement of such existing facilities, be carried out, to the extent practicable, in a manner so as to accommodate the passage through such transmission facilities of instrumented internal inspection devices (commonly referred to as ``smart pigs'').
Section 207(b) added a similar new section 203(k) to the Hazardous Liquid Pipeline Safety Act of 1979.
Instrumented internal inspection devices, also called ``smart pigs,'' travel with the flow of fluid in pipelines. Along the way, they collect data that operators subsequently analyze and investigate to learn the physical condition of the pipeline. However, operators cannot use smart pigs in pipelines that contain obstructions to their passage, such as short radius bends or valves that do not open fully. The purpose of the proposed regulations was to make pipelines open to the passage of smart pigs wherever practicable.
Persons who submitted written comments on the proposed regulations generally sought to expand the number of impracticable situations in which design and construction for the passage of smart pigs would not be mandatory. In a Final Rule document (59 FR 17281; April 12, 1994) (``1994 Final Rule''), we responded to these comments by including the following additional exceptions in final Sec. Sec. 192.150 and 195.120:
Pipe for which there is no commercially available smart pig.
Transmission lines in Class 4 (urban) locations that operate with a gas distribution system.
Piping associated with storage facilities.
Emergency or other unforeseen construction problems for which the operator seeks post-construction approval.
Offshore pipelines less than 10 inches in nominal diameter that transport gas or hazardous liquid to onshore facilities.
In the 1994 Final Rule, we also changed the proposed regulations in response to comments that the terms ``replacement transmission line'' and ``replacement pipeline'' were unclear. We had used these terms to identify which existing pipelines operators
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would have to modify to accommodate the passage of smart pigs. The commenters suggested several alternative terms, including ``replaced component'' or ``replaced line section.'' Although we agreed the proposed terms lacked clarity, we did not use the suggested alternatives in final Sec. Sec. 192.150(a) and 195.120(a). Instead the final rules required that when operators replace any line pipe or component, they must design and construct the entire line section containing the replacement to accommodate the passage of smart pigs (``replacement provision'').\3\ Also, based on the definition of ``line section'' in Sec. 195.2, we added the following definition to Sec. 192.3: ``Line section means a continuous run of transmission line between adjacent compressor stations, between a compressor station and storage facilities, between a compressor station and a block valve, or between adjacent block valves.'' We rejected as fruitless the idea of applying the proposed terms just to replaced pipe or components. Our reasoning was that if operators never replaced some existing obstructions, the pipelines would never accommodate the passage of smart pigs, or become piggable.
\3\ Final Sec. Sec. 192.150(a) and 195.120(a) are substantially identical. Final Sec. 192.150(a) reads as follows: Sec. 192.150 Passage of internal inspection devices.
(a) Except as provided in paragraphs (b) and (c) of this section, each new transmission line and each line section of a transmission line where the line pipe, valve, fitting, or other line component is replaced must be designed and constructed to accommodate the passage of instrumented internal inspection devices.
After publication of the 1994 Final Rule, the American Gas Association (AGA) and the Interstate Natural Gas Association of America (INGAA) asked us to stay the effective date of the replacement provision. They argued that construction projects require lengthy advance planning for, among other things, design, contracting, funding, and government approvals, and that compliance with Sec. 192.150 would cause adverse consequences. In addition, AGA and INGAA each submitted a petition for reconsideration of the replacement provision, citing procedural errors. INGAA also sought exemption of all offshore gas transmission lines from Sec. 192.150.
In view of the serious nature of these requests, on May 12, 1994, we suspended enforcement of the replacement provision, except as it applies to the pipe or component being replaced. Subsequently we published a notice proposing changes to Sec. 192.150 that would relax the effect of the regulation, but not fully grant the petitions for reconsideration (59 FR 49896; Sept. 30, 1994) (Notice of Proposed Rulemaking (NPRM)). Specifically the proposed changes would do the following:
For transmission lines in Class 1 and 2 locations (areas of low population), limit the replacement provision to the component being replaced, if modifying the entire line section is infeasible and unnecessary for future safety.
For transmission lines in Class 1 and 2 locations, postpone mandatory compliance with the replacement provision, apart from the component being replaced, until February 2, 1995.
Exempt all offshore transmission lines (other than new transmission lines 10\3/4\ inches or larger) if the operator runs cleaning pigs regularly to remove condensate and inspects risers regularly for corrosion.
We did not propose similar changes to Sec. 195.120 primarily because no one requested reconsideration of Sec. 195.120. The lack of a request was most likely because hazardous liquid pipelines have historically been designed for the passage of internal inspection equipment. We also thought the risk of environmental damage posed by hazardous liquid spills weighed against changing Sec. 195.120. Nevertheless, since there was no apparent need to change Sec. 195.120, we announced in the NPRM that we would begin to enforce the replacement provision of that regulation in full. We also said we would continue to suspend enforcement on gas transmission lines until February 2, 1995, or until we completed action on compliance dates, whichever occurred first (59 FR 49897).
After reviewing the comments on the NPRM, we realized we would not complete the rulemaking before February 2, 1995. So on January 30, 1995, we issued another suspension of enforcement (60 FR 7133; Feb. 7, 1995). On existing onshore transmission lines, we continued the previous suspension, and on offshore transmission lines, we suspended enforcement of Sec. 192.150 entirely. We said these suspensions would stay in effect until we responded to the comments on the NPRM and established new compliance dates. The suspensions did not affect new onshore transmission lines or replacements of pipe or components in existing onshore transmission lines.
Comments on the NPRM
Fifty-seven persons responded to the invitation to comment on the NPRM. Comments came from pipeline operators, pipeline trade associations, and government agencies.
AGA considered the proposed changes to Sec. 192.150 impracticable and unreasonable, and said they would not significantly reduce industry's costs of compliance. AGA estimated that even if the replacement provision applied only to Class 3 and 4 pipelines, compliance would cost industry more than $100 million a year. It urged us to rescind the replacement provision rather than adopt the proposed changes.
Other commenters largely objected to the replacement provision without directly addressing the proposed changes. Most of these commenters saw the replacement provision as an unnecessary high-cost burden that would cause the delay of other maintenance work or safety objectives. Many of them suggested that on existing transmission lines Sec. 192.150 should apply only to replacements of pipe and components. Four commenters argued we should not apply the replacement provision to Class 3 transmission lines operated with distribution systems because these lines have constraints similar to those of exempt Class 4 lines. Six commenters, including INGAA, expected improvements in the technology of smart pigs would make the replacement provision unnecessary. INGAA also suggested that preparing line sections for smart pig inspections before deciding the inspections are needed is not proper risk management.
Six commenters, including INGAA, suggested that Sec. 192.150 should exempt all offshore transmission lines. Two of these commenters urged exemption without the proposed preconditions, which they argued were unnecessary in view of usual operating practices and corrosion control regulations. Mostly these commenters contended that designing and constructing these lines to provide for the future use of smart pigs would be very costly, technically difficult, and of almost no benefit to the public because of the remote location. They attributed the costs and difficulties to the normal configuration of offshore transmission lines, essentially an underwater network of different pipe sizes with multiple right-angle connections, making smart pig passage from one line to another and installation of launcher or receivers at connection point impracticable. However, two commenters supported the Marine Board's recommendation (discussed below) that, whenever reasonably practical, operators design new medium-to-large-diameter lines running between platforms and platforms to shore for the passage of smart pigs.
Several commenters addressed the question of what alternative to the replacement provision would ensure
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that existing transmission lines eventually accommodate the passage of smart pigs. A few commenters said there was no alternative. Others said the accommodation of smart pigs would gradually result from planned replacement programs or from a combination of replaced pipe and components, new installations, and removal of obstructions. Two commenters stated the alternative was continuously improving technology.
Advisory Committee Consideration
The Technical Pipeline Safety Standards Committee (TPSSC) considered the NPRM at a meeting in Washington, DC, on May 2, 1995. TPSSC is a statutory, advisory committee that advises RSPA on proposed safety standards and other policies for gas pipelines. The committee has an authorized membership of 15 persons, five each representing government, industry, and the public. Each member has qualifications to consider the technical feasibility, reasonableness, cost-effectiveness, and practicability of proposed gas pipeline safety standards. A transcript of the meeting is available in the Nassif Building, Room 7128, 400 Seventh Street, SW, Washington, DC 20590-0001.
TPSSC's discussion at the meeting dwelled on the replacement provision of Sec. 192.150(a). One member thought the provision put too much emphasis on a single method of evaluating pipeline integrity (using smart pigs) when alternatives are available. Other members questioned the benefit of requiring operators to do more than just insure that replacement pipe and components accommodate the passage of smart pigs. Still other members were concerned the replacement provision would cause an undesirable reallocation of resources by reducing funds available for more important maintenance needs. In the end, TPSSC voted nine to one to recommend that we amend the replacement provision to apply only to replacements of pipe or components.
The rest of TPSSC's discussion concerned application of Sec. 192.150 to offshore transmission lines. One member stated emphatically that the regulation should not apply offshore because the cost of design and construction would be too great. An industry representative in the audience added that normal sub-sea designs inherently do not permit the passage of smart pigs due to right angles between connecting pipelines. This industry representative also said that other than in a few places, running smart pigs in offshore gas transmission lines was not technically feasible. With little further discussion, TPSSC voted unanimously to recommend that we exempt all offshore transmission lines from Sec. 192.150.
Resolving the Issues
Essentially we face two issues in deciding whether to change Sec. 192.150: The first is whether the replacement provision is justified. And the second is whether to exclude additional transmission lines from coverage.
Replacement provision. The controversy over the replacement provision began with our response to Notice 1 commenters who requested clarification of the term ``replacement transmission line.'' We had used the term in proposed Sec. 192.150(a) to identify the portions of existing transmission line that operators would have to design and construct to accommodate the passage of smart pigs.
A strong inference of what ``replacement transmission line'' meant is found in the following excerpt from Notice 1 concerning the purpose of the proposed regulations:
Sections 108(b) and 207(b) of the Reauthorization Act (Pub. L. 100-561) require DOT to require operators to design and construct certain new pipeline facilities and replacement pipeline facilities (i.e., pipeline facilities that replace existing facilities), to the extent practicable, to accommodate the passage of smart pigs. To meet this statutory requirement, the rules proposed by this notice would, with limited exceptions, prohibit any physical restriction on the passage of a smart pig in the design or construction of new or replacement pipelines. (57 FR 54746).
In the first sentence of the excerpt, the term ``replacement pipeline facilities'' identifies which existing facilities Congress wanted operators to design and construct to accommodate the passage of smart pigs. The parenthetical expression leaves no doubt that we intended the term to mean ``facilities that replace existing facilities.'' The second sentence further explains that to meet this congressional directive on existing facilities, the proposed rules would prohibit restrictions in ``replacement pipelines.'' Given that in Part 192 a ``transmission line'' is a type of ``pipeline'' which in turn is a type of ``pipeline facility'' (see Sec. 192.3), it follows that in Notice 1 we intended ``replacement transmission line'' to refer to a transmission line that replaces an existing transmission line.
This interpretation of Notice 1 is consistent with the legislative history of Pub. L.100-561. In its report on H.R. 2266, the House bill that led to the pig passage requirement, the Committee on Energy and Commerce discussed the limited effect the bill would have on existing pipelines. The Committee said the ``requirement would only apply to repairs or replacements that * * * could be done in a manner to facilitate the use of smart pigs.'' (H.R. Rept. 100-445, Part 1, 100th Cong., 1st Sess., at 15, emphasis added).
In the 1994 Final Rule, however, we did not refer to Notice 1 or the Committee report to answer commenters' questions about the meaning of ``replacement transmission line.'' Instead we dropped the term from the final regulations in favor of the replacement provision, which has a much broader effect than the design and construction of replacements. It requires that each transmission line section containing a replacement must be designed and constructed to accommodate the passage of smart pigs.
To justify this change in the final regulations, we pointed to Notice 1 comments that suggested alternatives to ``replacement transmission line,'' such as ``replacement line section'' or ``replacement transmission section.'' However, these comments were made by persons who suggested that for existing transmission lines we restrict application of the proposed rules to actual replacements. Thus, in the present reconsideration of the replacement provision, we looked for a better reason that would explain the change.
We believe that reason lies in the explanation we gave in the 1994 Final Rule for rejecting the idea that ``replacement'' should mean only replacement of pipe or components. We said if the regulations were so limited, ``then pipelines with restrictive components, such as elbows and tight radius field bends (which when properly maintained never need replacement) would never be piggable.'' (59 FR 17279). We amplified this reasoning--that some existing pipelines might never become piggable--when, in the same paragraph, we said the clear intent of the congressional mandate was to improve an existing pipeline's piggability. A further example of this reasoning is in the NPRM. There we explained that applying Sec. 192.150 to single components rather than line sections ``would result in virtually no change in the `piggability' of existing pipelines'' and that ``Congress clearly intended that change in the `piggability' occur.'' (59 FR 49897). It seems, therefore, that our strong interest in carrying out the will of Congress to make existing transmission lines piggable was behind the replacement provision in Sec. 192.150.
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Notwithstanding this prior reasoning, recent legislation and RSPA rulemaking have reduced the significance of the replacement provision in reaching the piggability goal. Section 14 of the Pipeline Safety Improvement Act of 2002 (Pub. L. 107-355; Dec. 17, 2002) requires gas pipeline operators to analyze and reduce the risks to their facilities in highly populated areas using integrity management programs prescribed by DOT regulations. Last year RSPA published the required regulations on integrity management programs (68 FR 69778; Dec. 15, 2003). The backbone of the regulations is a requirement to use smart pigs, pressure testing, direct assessment, or an equivalent technology periodically to assess the effects of potential risks on pipeline integrity. Comments submitted in response to the rulemaking proposal indicated that operators strongly prefer to use smart pigs as the method of assessment and will modify their transmission lines as necessary to accommodate smart pigs. For convenience of pig launching and retrieving and to maximize pigging benefits, planned modifications most likely will include considerable mileage outside areas covered by the new regulations. We believe this approach is prudent because pigging yields much more information about the condition of a pipeline and should lower compliance costs when widely used. Thus, regardless of the replacement provision, the new integrity management regulations should result in increased piggability of existing transmission lines in and near areas of high population, areas where the risk of damage from a pipeline rupture is greatest.
In sum, the NPRM commenters and the TPSSC opposed the replacement provision and did not back our NPRM proposal to relax it. Moreover, the goal of the replacement provision--ensuring the piggability of existing transmission--will likely be met in and near areas of greatest risk through compliance with the new integrity management regulations. Therefore, upon further consideration of the record and the integrity management rulemaking, we have decided to revise the replacement provision of Sec. 192.150(a) to apply only to replacements of pipe or components. Because this decision is consistent with our long-running stay of enforcement, it should not affect operators' current methods of compliance. Also, it will enable operators to focus their line modification resources on areas of greatest risk rather than spread them helter-skelter across their systems as the present rule requires.
Offshore transmission lines. The offshore issue first arose when 11 commenters to Notice 1 suggested we exempt all offshore pipelines from the final regulations. The commenters generally said design features, including short bends and right-angle connections, made it impracticable for offshore pipelines to accommodate the passage of smart pigs. Because of these comments, we exempted offshore pipelines less than 10 inches in nominal diameter that transport gas or hazardous liquid to onshore facilities (Sec. 192.150(b)(7) and Sec. 195.120(b)(6)).
INGAA was dissatisfied with this outcome and, in its petition for reconsideration, asked us to exempt all new and replacement offshore transmission lines from Sec. 192.150. Among other things, INGAA argued that making offshore transmission lines piggable would be of little benefit because the offshore location and operators' maintenance practices significantly limit the risk they pose. Largely accepting this argument, in the NPRM we proposed to modify the offshore exemption in Sec. 192.150(b)(7). The modified exemption would cover all existing transmission lines and new transmission lines less than 10\3/4\ inches in outside diameter if operators regularly run cleaning pigs through the lines to remove condensate and regularly inspect risers for corrosion.
To support our decision to continue applying Sec. 192.150 to new lines 10\3/4\ inches or larger in outside diameter, we noted that nothing in the record showed that offshore transmission lines are incapable of being designed and constructed to accommodate smart pigs. We also relied on a 1994 report titled ``Improving the Safety of Marine Pipelines'' prepared by a committee of scientists and engineers expert in offshore development and management. The Marine Board of the National Research Council established the committee in response to requests by RSPA and the Minerals Management Service to review and assess various offshore pipeline issues. The report is available on the Web from the National Academies Press at http://books.nap.edu/books/0309050472/ html/. After concluding that modification of existing
pipelines to accommodate smart pigs would generally be uneconomic, the committee recommended that ``[n]ew medium-to large-diameter pipelines running from platform to platform or platform to shore should be designed to accommodate smart pigs whenever reasonably practical.''
As stated above, NPRM commenters generally opposed applying Sec. 192.150 to offshore transmission lines, and the TPSSC supported that view. The rationale related to customary offshore construction practices and the inability to run pigs through interconnected lines. However, no commenter or TPSSC member objected specifically to applying the regulation to new lines 10\3/4\ inches or larger in outside diameter, and two commenters supported the idea within the limits of the Marine Board's recommendation. By comparison, since the 1994 Final Rule took effect, Sec. 195.120 has required operators to design and construct offshore hazardous liquid pipelines 10\3/4\ inches or larger in outside diameter to accommodate the passage of smart pigs. And nothing presented by the NPRM commenters suggests operators cannot similarly design and construct new gas transmission lines.
All these considerations, especially the Marine Board's recommendation, weigh toward continuing to apply Sec. 192.150 to new offshore transmission lines 10\3/4\ inches or larger in outside diameter. At the same time, we agree with the two NPRM commenters who suggested we limit the regulation's offshore coverage to new lines running from platform to platform or platform to shore whenever reasonably practical, as the Marine Board recommended. We also agree with the commenters who suggested that conditioning the exemption of other offshore lines on certain maintenance practices is unnecessary. As discussed in the NPRM, operators regularly remove condensate from transmission lines, and Part 192 already requires regular inspections for corrosion.
However, before making a final decision, we sought further public input because the offshore issue had not been aired for some time. So we published a notice (68 FR 67128; Dec. 1, 2003) seeking comments on the following questions:
Do operators of offshore gas transmission lines still object to applying Sec. 192.150 to new offshore transmission lines 10 inches or larger?
If the answer is yes, given that new hazardous liquid pipelines 10 inches or larger are meeting Sec. 195.120, what differences are there between gas and liquid pipeline design and construction practices that would justify exempting new offshore gas transmission lines 10 inches or larger from Sec. 192.150?
Regarding the Marine Board's recommendation, when would it not be ``reasonably practical'' to design new gas transmission lines 10 inches or larger running between platforms or
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platforms and shore to accommodate the passage of smart pigs?
We received four responses to the request for comments: Barb Sachau of Florham Park, New Jersey; Duke Energy Gas Transmission Corporation (Duke); El Paso Pipeline Group (El Paso); and INGAA. Of these commenters, only Duke offered useful information in response to the questions. Ms. Sachau merely urged us to adopt the utmost safety standards. El Paso supported INGAA's petition for reconsideration, but said it could not respond properly to the questions because the on-line docket (Docket No. RSPA-03-16330) did not contain the ``technical material'' referenced in INGAA's petition or the Marine Board study. El Paso said it needed more time for research, and asked us to extend the comment period 30 days. INGAA also requested more time to submit comments (15 days), stating that its time had been occupied by work related to RSPA's new Integrity Management Rule, published December 15, 2003, and by end-of-year holidays.
We did not grant El Paso's or INGAA's request to extend the comment period, because both commenters offered weak excuses for not meeting the deadline and did not suggest what new information we would receive if the deadline were extended. We especially differed with El Paso's contention that the ``technical material'' mentioned in INGAA's petition and the Marine Board study were not in the on-line docket. The only reference to technical material occurs on page 6 of the petition, where INGAA states: ``RSPA was provided with an abundance of technical reasons why offshore pipelines cannot be smart pigged.'' The context clearly implies that INGAA was referring to technical reasons contained in the rulemaking record. The 1994 Final Rule discusses these reasons, and we put a copy of the 1994 Final Rule in the on-line docket to make it easier for persons to respond to the request for comments. In addition, the notice included a Web address for the Marine Board study, effectively placing that study in the on-line docket. Although the comment deadline was not extended, our customary policy is to consider late-filed comments whenever practical, but neither commenter submitted anything more to the docket.
In its comments on the offshore issue, Duke opposed applying Sec. 192.150 to existing offshore gas pipelines. Yet it supported the Marine Board's recommendation on the design of certain new offshore pipelines, calling the recommendation an appropriate application of the congressional requirement. As to when designing for pig passage would not be reasonably practical, Duke suggested it would not be practical if pig launching or receiving were constrained by platform space or configuration. Nor would it be reasonably practical, Duke said, if the new pipeline were designed to have multiple lateral connections between launching and receiving points. Similarly, a participant at the May 2, 1995 TPSSC meeting suggested design would not be practical if it includes a lateral connection large enough to cause a smart pig to turn.
We agree it makes little sense to design and construct a new platform-connected transmission line for smart pig passage if the platform lacks room for equipment and handling needed to launch or retrieve smart pigs. We are less certain, however, about the consequences of designs that provide taps for future lateral connections, either through manifolds or more than one individual connection. While comments indicate that right-angle connections are common on offshore pipelines and impede smart pig passage from laterals to trunklines, it is not clear that these connections necessarily restrict the passage of smart pigs through the trunkline. Wye connections can be used in some situations to alleviate problems that might arise from right-angle connections, although they may not be suitable in all situations. Thus to be sure the pig passage requirement is not frustrated by designs that include taps for lateral connections, we believe operators should consider using non-obstructive alternatives wherever reasonably practical. Thus we are willing to exempt designs with obstructive taps only if the operator has considered alternative designs and can explain why they are not reasonably practical for the intended application.
Accordingly, based on our earlier conclusions and Duke's latest input, we are revising Sec. 192.150(b)(7) consistent with the Marine Board's recommendation. New offshore transmission lines 10'' inches or more in outside diameter that run from platform to platform or platform to shore will have to be designed and constructed to accommodate the passage of smart pigs. This requirement will not apply, however, if platform space or configuration is not compatible with launching or retrieving smart pigs. Nor will it apply if the design includes one or more taps for lateral connections and the operator can demonstrate, based on investigation or experience, that use of a tap that does not obstruct the passage of instrumented internal inspection devices is not reasonably practical under the design circumstances.
Although Sec. 192.150 already applies to new offshore transmission lines 10\3/4\ inches or more in outside diameter, because of our long- running suspension of enforcement, operators will probably need time to plan for compliance with revised Sec. 192.150(b)(7). So we decided to require compliance only on lines on which construction begins more than 18 months after the date of publication of the present Final Rule.
The changes we are making to Sec. 192.150 remove the need to continue in force the suspension of enforcement dated January 30, 1995 (60 FR 7133; Feb. 7, 1995). Therefore, we are withdrawing the suspension as of the effective date of this Final Rule, which is shown in ``Dates'' heading above.
Regulatory Analyses and Notices
Executive Order 12866 and DOT Policies and Procedures
We do not consider this rulemaking to be a significant regulatory action under Section 3(f) of Executive Order 12866 (58 FR 51735; Oct. 4, 1993). Therefore, the Office of Management and Budget (OMB) has not received a copy of this rulemaking to review. In addition, we do not consider this rulemaking to be significant under DOT regulatory policies and procedures (44 FR 11034: February 26, 1979).
This rulemaking merely relaxes certain provisions of the 1994 Final Rule. It does not establish any new requirements. It will reduce the costs to pipeline operators by limiting the amount of pipelines and pipeline components that operators must modify onshore and reduce the amount of pipeline offshore that is subject to regulation. A copy of the regulatory evaluation is available in the public docket for review.
Regulatory Flexibility Act
This rulemaking relaxes certain provisions of Sec. 192.150 and does not establish any new requirements. Therefore, based on these facts, I certify, under Section 605 of the Regulatory Flexibility Act (5 U.S.C. 605), that this rulemaking will not have a significant impact on a substantial number of small entities.
Executive Order 13084
We have analyzed this rulemaking according to the principles and criteria contained in Executive Order 13084, ``Consultation and Coordination with Indian Tribal Governments.'' Because the rulemaking will not significantly or uniquely affect the communities of the Indian tribal governments and will not impose substantial direct compliance
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costs, the funding and consultation requirements of Executive Order 13084 do not apply.
Paperwork Reduction Act
This rulemaking does not contain any additional information collection requirements.
Unfunded Mandates Reform Act of 1995
This rulemaking will not impose unfunded mandates under the Unfunded Mandates Reform Act of 1995. It would not result in costs of $100 million or more to either State, local, or tribal governments, in the aggregate, or to the private sector, and would be the least burdensome alternative that achieves the objective of the rule.
National Environmental Policy Act
Because this rulemaking merely relaxes certain provisions of Sec. 192.150 and does not establish any new requirements, it does not create any significant environmental issues. Therefore, we have not analyzed this rulemaking under the National Environmental Policy Act (42 U.S.C. 4321 et seq.).
Executive Order 13132
We have analyzed this rulemaking according to the principles and criteria contained in Executive Order 13132 (``Federalism''). The rulemaking does not establish any regulation that: (1) Has a substantial direct effect on the States, the relationship between the National government and the States, or the distribution of power and responsibilities among the various levels of government; (2) imposes substantial direct compliance cost on State and local governments; or (3) preempts State law. Therefore, the consultation and funding requirements of Executive Order 13132 do not apply.
Executive Order 13211
This rulemaking is not a ``Significant energy action'' under Executive Order 13211. It is not a significant regulatory action under Executive Order 12866 and is not likely to have a significant adverse effect on the supply, distribution, or use of energy. Further, this rulemaking has not been designated by the Administrator of the Office of Information and Regulatory Affairs as a significant energy action.
List of Subjects in 49 CFR Part 192
Natural gas, Pipeline safety, Reporting and recordkeeping requirements.
0 For the reasons discussed in this preamble, RSPA amends 49 CFR Part 192 as follows:
PART 192--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: MINIMUM FEDERAL SAFETY STANDARDS
0 1. The authority citation for part 192 continues to read as follows:
Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110, 60113, and 60118; and 49 CFR 1.53.
0 2. Revise Sec. 192.150(a) and (b)(7) to read as follows:
Sec. 192.150 Passage of internal inspection devices.
(a) Except as provided in paragraphs (b) and (c) of this section, each new transmission line and each replacement of line pipe, valve, fitting, or other line component in a transmission line must be designed and constructed to accommodate the passage of instrumented internal inspection devices.
(b) * * *
(7) Offshore transmission lines, except transmission lines 10\3/4\ inches (273 millimeters) or more in outside diameter on which construction begins after December 28, 2005, that run from platform to platform or platform to shore unless--
(i) Platform space or configuration is incompatible with launching or retrieving instrumented internal inspection devices; or
(ii) If the design includes taps for lateral connections, the operator can demonstrate, based on investigation or experience, that there is no reasonably practical alternative under the design circumstances to the use of a tap that will obstruct the passage of instrumented internal inspection devices; and * * * * *
Issued in Washington, DC, on June 23, 2004. Samuel G. Bonasso, Deputy Administrator.
[FR Doc. 04-14638 Filed 6-25-04; 8:45 am]
BILLING CODE 4910-60-P
