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