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Timestamp: 2018-09-19 15:44:03
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D. Consideration by the Technical Pipeline Safety Standards Committee (TPSSC) - Phmsa-2005-23447, fr, 192-[107]
Phmsa-2005-23447, fr, 192-[107]
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D. Consideration by the Technical Pipeline Safety Standards Committee (TPSSC)
The TPSSC met on June 10, 2008, and considered the proposed rule. During this discussion, PHMSA provided its preliminary views of changes that might be made in response to comments submitted in response to the proposed rule.
PHMSA informed the TPSSC that some changes would be made in rule structure, moving some requirements to other sections for better applicability (e.g., requirements applicable to existing pipelines would be moved from the section of the rule in which construction requirements are located).
PHMSA informed the TPSSC it has not adopted the suggestion by the state pipeline safety regulatory agency that submitted comments supported by its director (a member of the committee) to place the rule in a separate subpart, as that is counter to the general structure of part 192.
TPSSC members expressed concern, as did many commenters, about reliance on individual standards or tests. In the final rule, PHMSA has allowed use of equivalent methods (e.g., for the macro etch test, hardness limits, type of crack arrestors).
PHMSA informed the TPSSC that the vast majority of commenters objected to the proposed requirement for mill hydrostatic inspection tests of longer duration and that, as a result, that change would not be included in the final rule. PHMSA also noted that most industry commenters noted that the proposed rule did not make allowances for changes in class location after a pipeline is in service, as do the existing regulations.
The anomaly repair requirements were of concern to industry, who asserted the requirements were overly conservative. PHMSA informed the TPSSC that this issue is complicated by questions recently raised concerning the applicability of remaining strength calculational methods to high-stress pipelines and that resolving those questions before completing this rule would delay issuance of the rule. PHMSA stated that it would conduct a public meeting later this year to address the global issue of appropriate calculational methods and repair criteria. Changes to this or other regulations requiring pipeline repair may be appropriate following that workshop.
Treatment of existing and pending applications for special permits was a significant concern for several members of the TPSSC. PHMSA noted that the standards in the final rule are very similar to those applied in recent special permits. PHMSA reported its intention to continue to review pending special permit applications while this rulemaking proceeded. Upon issuance of the final rule, PHMSA expects operators desiring to use alternative MAOP to comply with the rule. PHMSA will examine special permits that have already been granted, as appropriate, to determine if any modifications are needed in light of the outcome of this rulemaking.
Subsequent to discussion, the TPSSC voted unanimously to find the proposed rule and supporting regulatory evaluations technically feasible, reasonable, practicable, and cost effective, subject to incorporation of the changes discussed by PHMSA during this meeting. A transcript of the meeting is available in the docket.
E. The Final Rule
Revisions described in this section are changes to the corresponding section in the proposed rule.
E.1. In General
The rule adds a new section (§192.620) to Subpart L–Operations. This new section explains what an operator would have to do to operate at a higher MAOP than currently allowed by the design requirements. Among the conditions set forth in new §192.620 is the requirement that the pipeline be designed and constructed to more rigorous standards. These additional design and construction standards are set forth in two additional new sections (Sec. §192.112 and 192.328) located in Subpart C–Pipe Design and Subpart G–General Construction Requirements for Transmission Lines and Mains, respectively. In addition, the rule makes necessary conforming changes to existing sections on incorporation by reference (§192.7), change in class location (§192.611), and maximum allowable operating pressure (§192.619).
E.2. Amendment to §192.7–Incorporation by Reference
The rule adds ASTM Designation: A 578/A578M–96 (Re-approved 2001) ``Standard Specification for Straight-Beam Ultrasonic Examination of Plain and Clad Steel Plates for Special Applications'' to the documents incorporated by reference under §192.7. This specification prescribes standards for ultrasonic testing of steel plates. It is referenced in new §192.112.
The rule also revises the description of item (B)(1) in the table of §192.7(c)(2), API 5L ``Specification for Line Pipe,'' (43rd edition and errata), 2004, to indicate that it is referenced in new §192.112 in addition to the locations at which it was referenced previously.
E.3. New §192.112–Additional Design Requirements
The rule adds a new section to Subpart C–Pipe Design in 49 CFR Part 192. The new section, §192.112, prescribes additional design standards required for the steel pipeline to be qualified for operation at an alternative MAOP based on higher stress levels. These include requirements for rigorous steel chemistry and manufacturing practices and standards. Pipelines designed under these standards contain pipe with toughness properties to resist damage from outside forces and to control fracture initiation and growth. The considerable attention paid to the quality of seams, coatings, and fittings will prevent flaws leading to pipeline failure. Unlike other design standards, §192.112 applies to a new or existing pipeline only to the extent that an operator elects to operate at a higher alternative MAOP than allowed in current regulations.
Paragraph (a) sets high manufacturing standards for the steel plate or coil used for the pipe. The pipe would be manufactured in accordance with Level 2 of API 5L, with the ratio between diameter and wall thickness limited to prevent the occurrence of denting and ovality during construction or operation. Improved construction and inspection practices addressed elsewhere in this rule also help prevent denting and ovality.
Paragraph (a) has been revised in response to comments to add an alternative method (and applicable limit) for determining equivalent carbon content. In addition, the proposed limit on equivalent carbon content of 0.23 (Pcm formula) has been raised to 0.25. Several comments suggested deleting the limit on the ratio of pipe D/t, but this limit has been retained, as discussed above.
Paragraph (b) addresses fracture control of the metal. First PHMSA expects the metal would be tough; that is, deform plastically before fracturing. Second, the pipe would have to pass several tests designed to reduce the risk that fractures would initiate. Third, to the extent it would be physically impossible for particular pipe to meet toughness standards under certain conditions, crack arrestors would have to be added to stop a fracture within a specified length.
Paragraph (b) has been revised to allow alternate means of crack arrest. This can include the ``mechanical'' means included in the proposed rule but can also include other design features such as use of composite sleeves, spacing, increases in wall thickness at appropriate distances, etc. This paragraph has also been revised to clarify the factors that must be considered by an operator in evaluating resistance to fracture initiation and to make clear that this evaluation is intended to address the full range of relevant parameters to which the pipe will be exposed over its operating lifetime. If unexpected situations or a change in operating conditions result in a change in these parameters during operation, such that they are outside the bounds of those analyzed, operators will be required to review and update their evaluation and implement remedial measures to assure continued resistance to fracture initiation.
Paragraph (c) provides tests to verify that there are no deleterious imperfections in the plate or coil. The macro etch test will identify flaws such as segregation that impact the plate or coil quality. Surface and interior flaws such as laminations and cracking will show up in UT testing.
This paragraph has been revised, in response to comments, to change ``mill inspection program'' to an internal quality management program designed to eliminate or detect defects or inclusions that can affect pipe quality and to require that such a program be implemented at all mills involved in the process of casting the steel, rolling it into plate, coil or skelp, and the process of manufacturing the steel into line pipe. The revised paragraph also includes an alternative to the macro etch test and reference to an additional standard for UT testing the plate, coil, skelp or manufactured line pipe. (Equivalent standards are also still allowed.)
In addition to the quality of the steel, the integrity of a pipe depends on the integrity of the seams. Paragraph (d) provides for a QA program to assure tensile strength and toughness of the seams so that they resist breaking under regular operations. Hardness and UT tests after mill hydrostatic tests would ensure that the seams did not have defects or imperfections that were exposed by the stresses of the hydrostatic test pressure.
Paragraph (e) requires a mill pressure test for new pipe at a higher hoop stress than required by current regulations. The mill test is used to discover flaws introduced in manufacturing. Because the pipeline will be operated at a higher stress level, the more rigorous mill test is needed to match (or exceed) the level of safety provided for pipelines operated at less than 72 percent of SMYS. Paragraph (e) has been revised to eliminate the proposed extension of the duration of mill pressure tests.
Paragraph (f) sets rigorous standards for factory coating designed to protect the pipeline from external corrosion. A QA program must address all aspects of the application of coating that will protect the pipeline. This would include applying a coating resistant to damage during transportation and installation of the pipe and examining the coated pipeline to determine whether the applied coating is uniform and without defects. Thin spots or voids/holidays in the coating make it more likely for corrosion to occur and more difficult to protect the pipeline cathodically.
Paragraph (g) requires that factory-made fittings, induction bends, and flanges be certified as to their serviceability and quality. In addition the CE of these fittings and flanges would need to be documented, so that welding procedures could require pre-heat temperature to eliminate welding defects.
Paragraph (g) has been revised to clarify that the serviceability certification must address properties such as chemistry, minimum yield strength, and minimum wall thickness to meet design conditions. PHMSA expects that valves, flanges and fittings should be rated based upon the required specification rating class for the alternative MAOP and the operator to have documented mill reports with chemistry, minimum yield strength, and minimum wall thickness. Where specialty bends such as hot bends are used for pipeline segments operating per the alternative MAOP, PHMSA expects the operator to address properties such as chemistry, minimum yield strength, minimum wall thickness and other properties that the hot bending process could alter.
Paragraph (h) requires compressor design to limit the temperature of downstream pipe operating at an alternative MAOP to a specified maximum. Higher temperature can damage pipe coating. An exception to the specified maximum is allowed if testing of the coating shows it can withstand a higher temperature. The testing duration, qualification procedures and results must be of sufficient length and rigor to detect coating integrity issues for the type coating, operating and environmental conditions on the pipeline. Operators may also rely on a long-term coating integrity monitoring program to justify operation at higher temperatures, provided the program is submitted to and reviewed by PHMSA.
Paragraph (h) has been revised to clarify the allowed exception. Testing must address coating adhesion and condition as well as cathodic disbondment. Operators are required to submit their test results, including the acceptance criteria they applied to assure themselves that these characteristics are adequate, to the appropriate PHMSA regional office(s) and applicable state regulatory authorities at least 60 days prior to operating at elevated temperature. (State notification applies when the pipeline is located in a state where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that state.)
A subtle, but important, change has also been made in the language in this paragraph. As proposed, the discharge temperature of compressor stations would have been limited to the specified temperature. As revised, the temperature of the nearest downstream pipeline segment to operate at alternative MAOP must be limited. For situations in which the pipeline segment at the discharge of a compressor station operates at alternative MAOP, there is no practical difference. The revised language, however, allows pipeline operators to implement an alternative approach in which they would use pipe operating at conventional MAOP from the discharge of a compressor station downstream to the point at which pipe temperature will drop to the specified limit. This may provide an alternative for situations in which it may be difficult to limit the compressor station discharge to the specified limit (e.g., southern locations on hot summer days). Gas coolers may be installed at compressor stations on pipelines operating per the alternative MAOP that need to operate above 120 degrees Fahrenheit. Gas cooling at compressor stations is a long standing method for most operators to reduce gas pipeline temperatures.
E.4. New §192.328–Additional Construction Requirements
The rule also adds a new section to Subpart G–General Construction Requirements for Transmission Lines and Mains. The new section, §192.328, prescribes additional construction requirements, including rigorous QC and inspections, as conditions for operation of the steel pipeline at higher stress levels. Unlike other construction standards, §192.328 would apply to a new or existing pipeline only to the extent that an operator elects to operate at a higher alternative MAOP than allowed in current regulations.
Paragraph (a) requires a QA plan for construction. QA, also called QC, is common in modern pipeline construction. Activities such as lowering the pipe into the ditch and backfilling, if done poorly, can damage the pipe and coating. Other construction activities such as nondestructive examination of girth welds, if done poorly, will result in flaws remaining in the pipeline or failures during hydrostatic testing or while in gas service. Using a QA plan helps to verify that the basic tasks done during construction of a pipeline are done correctly.
Field application of coating is one of these basic tasks to be covered in a QA plan. During the course of analyzing requests for special permits, PHMSA discovered field coatings at one construction site which were applied at lower temperature than needed for good adhesion to the pipe. Because coating is so critical to corrosion protection, paragraph (a) requires quality assurance plans to contain specific performance measures for field coating. Field coating must meet substantially the same standards as coating applied at the mill and the individuals applying the coating must be appropriately trained and qualified.
Installation of the pipe into the ditch and backfilling of the pipe are critical operations. PHMSA has found that construction and inspection lapses during the backfilling of the pipe have resulted in pipe denting and coating damage. Sometimes during backfilling of the pipe there are design requirements for the installation of other engineered items such as concrete weights at creek and water saturated soil areas. The proper installation of these types of engineered items is critical to ensure that the pipe and coating are not damaged and the item is installed as required in the specifications. PHMSA has found operator lapses in this critical QC aspect of pipeline construction.
Paragraph (b) requires non-destructive testing of all girth welds. Although past industry practice sometimes has been to non-destructively test only a sample of girth welds, no alternative exists for verifying the integrity of the remaining welds. The initial pressure testing once construction is complete does not normally detect flaws in girth welds unless the girth weld is cracked, has severe lack of penetration or is under undue tension stresses, which would be indicative of systemic problems on the pipeline. PHMSA believes that most modern pipeline construction projects include non-destructive testing of all girth welds. However, because the regulations do not require testing of all girth welds, an operator's records for pipelines already in operation may not be complete on 100 percent of girth welds. To account for this, proposed paragraph (b) would have required testing records for only 95 percent of girth welds on existing segments. This requirement has been retained, but proposed paragraph (b) has been moved to new §192.620, as it applies to existing pipelines. This section addresses pipeline construction.
Paragraph (c) requires deeper burial of segments operated at higher stress level. A greater depth of cover decreases the risk of damage to the pipeline from excavation, including farming operations.
Paragraph (d) addresses the results of the initial strength test and the assurance these results provide that the material in the pipeline is free of pre-operational flaws which can grow to failure over time. Since the initial strength test is a destructive test, it only detects flaws that would fail at the test pressure. This could leave in place smaller flaws. To prevent this from occurring, the proposed paragraph would have disqualified any segment which experienced a failure during the initial strength test indicative of flaws in the material. Most commenters objected to this provision as too restrictive. They noted that failures can be isolated and that it was unreasonable to preclude an entire pipeline segment from operation at alternative MAOP because of a single failure. This paragraph has been revised to allow conduct of a root cause examination of a failure, including metallurgic examination of the failed pipe, as a way of justifying qualification of the pipeline segment. If that examination determines that the cause of the failure is not systemic, then the pipeline segment would not be disqualified from alternative MAOP operation. Operators must report the results of their root cause evaluation to regulators (PHMSA Regional Office or applicable state regulatory authorities). Review of these analyses by pipeline safety regulators will provide oversight for operator conclusions regarding the non-systemic nature of a failure.
Proposed paragraph (e) addressed cathodic protection on an existing segment. This paragraph has been moved to new §192.620.
Paragraph (e) (proposed as paragraph (f)) addresses electrical interference for new segments. During construction, sources of electrical interference which can impair future cathodic protection or damage the pipe prior to placing cathodic protection in service need to be identified. Addressing interference at this time supports better corrosion control. Operators will need to coordinate with electric transmission line operators prior to pipeline construction to identify locations of grounding structures and power line currents and voltages and their effect on the pipe. The additional O&M requirements of new §192.620(d)(6) require operators electing to operate existing pipelines at higher stress levels to address electrical interference prior to raising the MAOP.
E.5. Amendment to §192.611–Change in Class Location: Confirmation or Revision of Maximum Allowable Operating Pressure
The proposed rule did not include a provision to amend this section. Commenters pointed out that this section addresses changes in class location (e.g., increase in population density near the pipeline) during operation. The existing requirements allow continued operation at pressures higher than would be required for new pipe installed in the new class location, provided pressure testing has been performed at appropriate pressures. The commenters noted that without addressing operation at alternative MAOP in this section, the regulations would effectively rescind the authorization provided by this rule to operate at higher pressure whenever there was a change in class location.
PHMSA agrees that this result was not intended. This section has been revised to include provisions for pipelines operating at alternative MAOP substantially the same as those already provided for existing pipelines. Operation at higher alternative pressures can continue after a class location change, again provided that the pipeline has been tested at appropriate pressures and is not an alternative MAOP operating in a Class 3 location that is upgraded to a Class 4 location. The limits on hoop stress included in this section have been revised to reflect the higher hoop stress that will be experienced by a pipeline at alternative MAOP.
E.6. Amendment to §192.619–Maximum Allowable Operating Pressure
The final rule amends existing §192.619 by adding a new paragraph (d) providing an additional means to determine the alternative MAOP for certain steel pipelines. In addition, the rule makes conforming changes to existing paragraph (a) of the section.
E.7. New §192.620–Operation at an Alternative MAOP
The final rule adds a new section, §192.620, to subpart L of part 192, to specify what actions an operator must take in order to elect an alternative MAOP based on higher operating stress levels. The rule applies to both new and existing pipelines.
E.7.1. §192.620(a)–Calculating the Alternative MAOP
Paragraph (a) describes how to calculate the alternative MAOP based on the higher operating stress levels. Qualifying segments of pipeline would use higher design factors to calculate the alternative MAOP. For a segment currently in operation this would result in an increase in MAOP. No changes were proposed in the design factors used for segments within compressor or meter stations or segments underlying certain crossings. PHMSA expects new pipelines operating per the alternative MAOP to have road/railroad crossings, fabrications, headers, mainline valve assemblies, separators, meter stations and compressor stations designed and operated per existing design factors in §192.111.
Paragraph (a) has been revised to include new design factors for compressor/meter stations or segments underlying certain crossings. These factors apply to facilities in existence prior to the effective date of this rule. Commenters pointed out that compressor stations for existing pipelines have been designed and that failure to allow alternative design factors for them could effectively preclude operation at alternative MAOP for the existing pipelines of which they are a part. PHMSA agrees this was not our intent. The additional risk associated with use of slightly higher design factors for these facilities is marginal. At the same time, there is little additional cost associated with designing stations/crossings/fabrications/headers for future pipelines to serve at the desired MAOP using existing design factors in §192.111(b), (c), and (d). The rule includes no alternative design factors for these facilities in future pipelines, and operators must use the existing requirements.
E.7.2. §192.620(b)–Which Pipeline Qualifies
Paragraph (b) describes which segments of new or existing pipeline are qualified for operation at the alternative MAOP. The alternative MAOP is allowed only in Class 1, 2, and 3 locations. Only steel pipelines meeting the rigorous design and construction requirements of Sec. §192.112 and 192.328 and monitored by supervisory data control and acquisition systems qualify. Mechanical couplings in lieu of welding are not allowed. Although the special permits did not expressly mention mechanical couplings, PHMSA would not have granted a special permit if the pipeline involved had mechanical couplings.
As proposed, paragraph (b) would have excluded from consideration any existing pipeline that had experienced a failure indicative of materials concerns. This provision has been revised to allow root cause analysis to determine if the failure is indicative of a systemic problem and to preclude use of an alternative MAOP only if a failure is determined to be systematic in nature. Results of the analysis must be reported to regulators (PHMSA Regional Office or applicable state regulatory authorities). This is essentially the same change made for new pipelines in new §192.328(d), as described above. Paragraph (b) has also been revised to include the requirement that 95 percent of girth welds must have been examined for existing pipelines to operate at alternative MAOP. This requirement was moved from proposed §192.328(e), as discussed above.
E.7.3. Sec. §192.620(c)(1), (2), and (3)–How an Operator Selects Operation Under This Section
Paragraph (c)(1) requires an operator to notify PHMSA, and applicable state pipeline safety regulators, when it elects to establish an alternative MAOP under this section. This notification must be provided at least 180 days prior to commencing operations at the alternative MAOP established under this section. This will provide PHMSA and states sufficient time for appropriate inspection which may include checks of the manufacturing process, visits to the pipeline construction sites, analysis of operating history of existing pipelines, and review of test records, plans, and procedures.
Paragraph (c)(3) requires an operator to further notify PHMSA when it has completed the actions necessary to support operation at an alternative MAOP, by submitting a certification by a senior executive that the pipeline meets the requirements for operation at alternative MAOP. The certification is required by paragraph (c)(2). A senior executive must certify that the pipeline meets the additional design and construction regulations of this rule. A senior executive must also certify that the operator has changed its O&M procedures to include the more rigorous additional O&M requirements. In addition, a senior executive must certify that the operator has reviewed its damage prevention program in light of best practices, such as CGA best practices or some equivalent best practices, and made any needed changes to it to ensure that the program meets or exceeds those standards or practices. The certification must be submitted at least 30 days prior to operation at an alternative MAOP.
E.7.4. §192.620(c)(4)–Initial Strength Testing
Paragraph (c)(4) addresses initial strength testing requirements. In order to establish the MAOP under this section, an operator must perform the initial strength testing of a new segment at a pressure at least as great as 125 percent of the MAOP in Class 1 locations and 150 percent in Class 2 and 3 locations. Since an existing pipeline was previously operated at a lower MAOP, it may have been initially tested at a pressure less than these levels. If so, paragraph (c) allows the operator to elect to conduct a new strength test in order to raise the MAOP.
E.7.5. §192.620(c)(5)–Operation and Maintenance
Paragraph (c)(5) requires an operator to comply with the additional operating and maintenance requirements of §192.620(d). An operator must comply with these additional requirements if the operator elects to calculate the alternative MAOP for a segment under §192.620(a) and notifies PHMSA of that election.
E.7.6. §192.620(c)(6)–New Construction and Maintenance Tasks
Paragraph (c)(6) addresses the need for competent performance of both new construction, and future maintenance activities, to ensure the integrity of the segment. PHMSA now requires operators to ensure that individuals who perform pipeline O&M activities are qualified. Paragraph (c)(6) requires operators seeking to operate at the allowable higher operating stress levels to treat construction tasks as if they were covered by subpart N, ``Qualification of Pipeline Personnel.'' Subpart N (commonly known as OQ) specifies training and qualification requirements applicable to tasks that meet a four-part test in §192.801(b). Operations and maintenance tasks on the pipeline meet this test, and it is the requirements in subpart N that will govern training and qualification of personnel performing these tasks on a pipeline to be operated at an alternative MAOP. Construction tasks typically do not meet the four-part test and are not covered under subpart N. As proposed, paragraph (c)(6) (then designated (c)(5)) would have required operators to take other actions to assure qualification of personnel performing construction tasks on a pipeline intended to operate at alternative MAOP. Commenters noted that the proposed requirements were vague and subject to interpretation and suggested that PHMSA, instead, rely on the known requirements of subpart N. This paragraph has been modified, in response to these comments, to require that the requirements of subpart N be applied to construction tasks for a pipeline intended to operate at alternative MAOP regardless of the four-part test in §192.801(b).
E.7.7. §192.620(c)(7)–Recordkeeping
Paragraph (c)(7) specifies recordkeeping requirements for operators electing to establish the MAOP under this section. Existing regulations, such as Sec. §192.13, 192.517(a), and 192.709, already require operators to maintain records applicable to this section. New §192.620 is in subpart L. Because the additional requirements in this section address requirements found in other subparts of part 192, the recordkeeping requirements could cause confusion. For example, §192.620(d)(9) requires a baseline assessment for integrity for a segment operated at the higher stress level regardless of its potential impact on an HCA. Section 192.947, in subpart O, requires operators to maintain records of baseline assessments for the useful life of the pipeline. Section 192.709 requires an operator to retain records for an inspection done under subpart L for a more limited time. Accordingly, this paragraph clarifies the need to maintain all records demonstrating compliance with all alternative MAOP requirements for the useful life of the pipeline.
E.7.8 §192.620(c)(8)–Class Upgrades
Paragraph (c)(8) allows pipelines in Class 1 and 2 to be upgraded one class when class changes occur per §192.611. This paragraph precludes operation of pipeline in Class 4 at alternative MAOP.
E.8. §192.620(d)–Additional Operation and Maintenance Requirements
Paragraph (d) sets forth ten operating and maintenance requirements that supplement the existing requirements in part 192. Currently §192.605 requires an operator to develop O&M procedures to implement the requirements of subparts L and M. Since §192.620(d) is in subpart L, an operator must develop and follow the O&M procedures developed under this section. These include requirements for an operator to evaluate and address the issues associated with operating at higher pressures. Through its public education program, an operator would inform the public of any risks attributable to higher pressure operations. The additional operating and maintenance requirements address the two main risks the pipelines face, excavation damage and corrosion, through a combination of traditional practices and integrity management. Traditional practices include cathodic protection, control of gas quality, and maintenance of burial depth. Integrity management includes internal inspection on a periodic basis to identify and repair flaws before they can fail. The additional O&M and management requirements are discussed in more detail below.
E.8.1. §192.620(d)(1)–Threat Assessments
Paragraph (d)(1) requires an operator to identify and evaluate threats to the pipeline consistent with the similar procedures done under integrity management to address the risks of operating at an increased stress level.
E.8.2. §192.620(d)(2)–Public Awareness
Paragraph (d)(2) requires an operator to include any people potentially impacted by operation at a higher stress level within the outreach effort in its public education program required under existing §192.616. In order to identify this population, an operator would use a broad area measured from the centerline of the pipe plus, in HCAs, the potential impact circle recalculated to reflect operation at a higher operating stress level. This is intended to get necessary information for safety to the people potentially impacted by a failure.
E.8.3. §192.620(d)(3)–Emergency Response
Paragraph (d)(3) addresses the additional needs for responding to emergencies for operation at higher operating stress levels. Consistent with the conditions imposed in the special permits, and past experience with response issues, the paragraph requires methods such as remote control valves to provide more rapid shut-down in the event of an emergency.
E.8.4. §192.620(d)(4)–Damage Prevention
Paragraph (d)(4) addresses one of the major risks of failure faced by a pipeline, damage from outside force such as damage occurring during excavation in the right-of-way. Although the improved toughness of pipe reduces the risk of damage, it does not prevent it and additional measures are appropriate for pipelines operating at higher operating stress levels. This paragraph adds several new or more specific measures to existing requirements designed to prevent damage to pipelines from outside force.
The first more specific measure, in paragraph (d)(4)(i), addresses patrolling, required for all transmission pipelines by §192.705. More frequent patrols of the right-of-way prevent damage by giving the operator more accurate and timely information about potential sources of ground disturbance and other outside force damage. These include both naturally occurring conditions, such as wash outs, and human activity, such as construction in the vicinity of the pipeline. The requirement is for patrols to be made monthly, at intervals not to exceed 45 days. The patrolling requirement along with other right-of-
way requirements including line-of-sight markers, use of national consensus standards, and the right-of-way management plan comprise a multi-faceted approach to protecting the pipeline.
Other more specific or new measures to address damage prevention include developing and implementing a plan to monitor and address ground movement, a requirement of paragraph (d)(4)(ii). Ground movement such as earthquakes, landslides, soil erosion, and nearby demolition or tunneling can damage pipelines. Since pipelines near the surface are more likely to be damaged by surface activities, paragraph (d)(4)(iii) requires an operator to maintain the depth of cover over a pipeline or provide alternative protection. Line-of-sight markers alert excavators, emergency responders, and the general public of the presence and general location of pipelines. Paragraph (d)(4)(iv) requires these markers both to improve damage prevention and to enhance public awareness.
Damage prevention programs are improving because of the work being done by the CGA, a national, non-profit educational organization dedicated to preventing damage to pipelines and other underground utilities. The CGA has compiled best practices applicable to all parties relevant to preventing damage to underground utilities and actively promotes their use. Paragraph (d)(5)(v) requires operators electing to operate at higher stress levels to evaluate their damage prevention programs in light of industry best practices, such as those developed by CGA. An operator must identify the practices applicable to its circumstances and make appropriate changes to its damage prevention program. This approach is consistent with annual reviews of O&M programs under §192.605. An operator must include in the certification required under §192.620(c)(1) that the review and upgrade have occurred.
Paragraph (d)(4) also requires the preparation of a right-of-way management plan. In the past several years, PHMSA has seen recurring similarities in pipeline accidents on construction sites. In each case, better management of the pipeline right-of-way could have prevented the accidents. Better management includes closer attention to the qualifications of individuals critical to damage prevention, better marking practices, and closer oversight of the excavation. In 2006, PHMSA issued two advisory bulletins to alert operators of the need to pay closer attention to these important damage prevention issues. The first advisory bulletin described three accidents in which either operator personnel or contractors damaged gas transmission pipelines during excavation in the rights-of-way (ADB-06-01; 71 FR 2613; Jan.17, 2006). This bulletin advised operators to pay closer attention to integrating OQ regulations into excavation activities and providing that excavation is included as a covered task under OQ programs required by subpart N. The second advisory bulletin pointed to an additional excavation accident where the excavator struck an inadequately marked gas transmission pipeline (ADB-06-003; 71 FR 67703; Nov. 22, 2006). This advisory bulletin advised pipeline operators to pay closer attention to locating and marking pipelines before excavation activities begin and pointed to several good practices as well as the best practices described by the CGA. This paragraph requires an operator electing to operate at a higher stress level to develop a plan to manage the protection of their right-of-way from excavation activities. Each operator already has a damage prevention program, under §192.614, and a program to ensure qualification of pipeline personnel, under subpart N. This management program requires the operator to integrate activities under those programs to provide better protection for the right-of-way of the pipeline operated at the higher stress level.
E.8.5. §192.620(d)(5)–Internal Corrosion Control
Paragraph (d)(5) adds specificity to the requirements for internal corrosion control now in pipeline safety standards for pipelines operated at higher stress levels. These internal corrosion control programs must include use of gas separators or filter separators and gas quality monitoring equipment. Operators are required to use cleaning pigs and inhibitors when corrosive gas is present. (Use of cleaning pigs and inhibitors is required when the level of one corrosive contaminant, hydrogen sulfide (H2S), is between 0.5 and 1.0 grain per hundred cubic feet). Most operators who have applied for special permits to operate their pipeline at alternative MAOP limit H2S to 0.5 grain. The higher levels allowed in this rule are within typical FERC tariffs, but may present an increased likelihood of internal corrosion. Maximum levels of contaminants that could promote corrosion must be reviewed quarterly, and operators must adjust their programs as needed to monitor and mitigate any deleterious gas stream constituents. PHMSA believes the levels are fully consistent with the requirements in FERC tariffs designed to prevent internal corrosion.
E.8.6. Sec. §192.620(d)(6), (7), and (8)–External Corrosion Control
Since external corrosion is one of the greatest risks to the integrity of pipelines operating at higher stress levels, the special permits and this rule contain several measures to prevent it from occurring. These include use of effective external coating, addressing interference, early installation of cathodic protection, confirming the adequacy of coating and cathodic protection and diligent monitoring of cathodic protection levels. The requirements concerning quality of the coating and installation of cathodic protection for new pipelines are addressed in sections on design and construction, as discussed above. The remaining external corrosion provisions are addressed here.
Interference from overhead power lines, railroad signaling, stray currents, or other sources can interfere with the cathodic protection system and, if not properly mitigated, even accelerate the rate of external corrosion. Paragraph (d)(6) requires an operator to identify and address interference early before damage to the pipeline can occur.
Paragraph (d)(7) requires an operator to confirm both the effectiveness of the coating and the adequacy of the cathodic protection system soon after deciding on operation at higher operating stress levels/alternative MAOP. This is accomplished through indirect assessments, such as a CIS for cathodic protection and DCVG or ACVG for coating condition. After completion of the baseline internal inspection required by §192.620(d)(9), an operator is required to integrate the results of that inspection with the indirect assessments. An operator must take remedial action to correct any inadequacies. In HCAs, an operator must periodically repeat indirect assessment to confirm that the cathodic protection system remains as functional as when first installed.
Paragraph (d)(8) requires more rigorous attention to ensure adequate levels of cathodic protection. Regulations now require an operator discovering a low reading, meaning a reduced level of protection, to act promptly to correct the deficiency. This section puts an outer limit of six months on the time for completion of the remedial action and restoration of an adequate level of cathodic protection. In addition, the operator must confirm that its actions have been effective in restoring cathodic protection.
E.8.7. Sec. §192.620(d)(9) and (10)–Integrity Assessments
Among the most important ways of ensuring integrity during pipeline operations are the assessments done under the integrity management program requirements in subpart O. Paragraphs (d)(9) and (d)(10) require operators electing to operate at higher stress levels to perform both baseline and periodic assessments of the entire pipeline segment operating at the higher stress level, regardless of whether the pipeline segment is located in an HCA. The operator must use both a geometry tool and a high resolution magnetic flux tool for the entire pipeline segment. In very limited circumstances in which internal inspection is not possible because internal inspection tools cannot be accommodated, such as a short crossover segment connecting two pipelines in a right-of-way, an operator would substitute pressure testing or DA. The operator must then integrate the information provided by these assessments with testing done under previously described paragraphs. This analysis would form the basis for mitigating measures, and for prompt repairs under paragraph (d)(11).
E.8.8. §192.620(d)(11)–Repair Criteria
The repair criteria under paragraph (d)(11) for anomalies in a pipeline segment operating at a higher stress level are slightly more conservative than for other pipelines, including pipelines covered by an integrity management program. With the tougher pipe, better coating, construction quality inspection program, coating surveys after installation and backfill, and careful attention to damage prevention and corrosion protection, a pipeline operated at higher operating stress levels should experience few anomalies needing evaluation.
E.9. §192.620(e)–Overpressure Protection
The alternative MAOP is higher than the upper limit of the required overpressure protection under existing regulations. Paragraph (e) increases the overpressure protection limit to 104 percent of the MAOP, which is 83.2 percent of SMYS for a pipeline segment operating at the alternative MAOP in a Class 1 location.
F. Regulatory Analyses and Notices
F.1. Privacy Act Statement
Anyone may search the electronic form of all comments received for any of our dockets. You may review DOT's complete Privacy Act Statement in the Federal Register published on April 11, 2000 (65 FR 19477).
F.2. Executive Order 12866 and DOT Policies and Procedures
Due to magnitude of expected benefits, the DOT considers this rulemaking to be a significant regulatory action under section 3(f)(1) of Executive Order 12866 (58 FR 51735; Oct. 4, 1993). Therefore, DOT submitted it to the Office of Management and Budget for review. This rulemaking is also significant under DOT regulatory policies and procedures (44 FR 11034; Feb. 26, 1979).
PHMSA prepared a Regulatory Evaluation of the final rule. A copy is in Docket ID PHMSA-2005-23447.
PHMSA estimates that the rule will result in gas transmission pipeline operators uprating 3,500 miles of existing pipelines to an alternative MAOP. Additionally PHMSA estimates that, in the future, the rule will result in an annual additional 700 miles of new pipelines each year whose operators elect to use an alternative MAOP.
PHMSA expects the benefits of the rule to be substantial and in excess of $100 million per year. This expectation is based on quantified benefits in excess of $100 million per year (see below), coupled with un-quantified benefits associated with the rule that industry and PHMSA technical staff have identified. The expected benefits of the rule that cannot be readily quantified include:
 Reductions in incident consequences.
 Increases in pipeline capacity.
 Increases in the amount of natural gas filling the line, commonly called line pack.
 Reductions in adverse environmental impacts.
The rule's requirements, such as monthly right-of-way patrolling, additional internal inspections, and anomaly repair, are expected to prevent incidents that would have occurred in the absence of the rule, and to help mitigate the consequences of the incidents that do occur. In the case of new pipelines, the ability to use an alternative MAOP will make it possible to transport more product per dollar of pipeline cost than would be possible without this new rule. Quantifying the value of this increased capacity is difficult, and no estimate has been developed for this analysis. For existing pipelines, operation at a higher MAOP increases the amount of gas that can be transported. PHMSA expects the value of increased capacity due to use of alternative MAOP by gas pipelines to be significant. In areas where production is already well-established, there is an even greater potential for increased pipeline capacity. For example, one recipient of a special permit estimated a daily increase of at least 62 million standard cubic feet of gas.
Similarly, increases in line pack will produce increased benefits which are difficult to quantify. Line pack is increased due to gas compressibility at higher operating pressures which results in increased gas volumes in the pipeline. The reduced amount of exterior storage capacity needed resulting from increased line pack may result in capital or O&M savings for the pipelines or their customers. Greater line pack in a pipeline increases the ability of the operator to continue gas delivery during short outages such as maintenance and during peak flow periods. These benefits are not readily quantifiable.
The quantified benefits consist of:
 Fuel cost savings.
 Capital expenditure savings on pipe for new pipelines.
Of these, pipeline fuel cost savings is the most important contributor to the estimated benefits. Although these quantified benefits do not capture the full benefits of the rule, they exceed $100 million per year.
As a consequence of the rule, PHMSA estimates that pipeline operators will realize annually recurring benefits due to fuel cost savings of $49 million that will begin in the initial year after the rule goes into effect. Additionally, PHMSA estimates that each year pipeline operators will realize one-time benefits for savings in capital expenditures of $54.6 million (since 700 miles of new pipeline operating at an alternative MAOP are added each year, the one-time benefits resulting from this added mileage will be the same each year.) The benefits of the rule over 20 years are expected to be as presented in the following table:
Table D.2.-1–Summary and Total for the Estimated Benefits of the Rule
[Millions of dollars per year]
Estimate for year 1
benefits occurring in each subsequent
Reduced incident consequences
Not quantified.
Increased pipeline capacity
Increased line pack
Reduced adverse environmental impacts.
Other expected benefits
The present value of the benefits evaluated over 20 years at a three percent discount rate is $1,541 million, while the present value of the benefits over 20 years at a seven percent discount rate is $1,098 million. For both discount rates, the annualized benefits would be $103.6 million.
PHMSA expects the costs attributable to the rule are most likely to be incurred by operators for:
 Performing baseline internal inspections.
 Performing additional internal inspections.
 Performing anomaly repairs.
 Installing remotely controlled valves on either side of HCAs.
 Preparing threat assessments.
 Patrolling pipeline rights-of-way.
 Preparing the paperwork notifying PHMSA of the decision to use an alternative MAOP.
Overall, the costs of the rule over 20 years are expected to be as presented in the following table:
Table D.2.-2– Summary and Totals for the Estimated Costs of the Rule
Cost by year after implementation [thousands of dollars]
2nd–10th
12th–20th
Baseline internal inspections.
Additional internal inspections.
$2,912 each year.
Anomaly repairs.
$1,015.
$1,218.
$203 each year.
Remotely controlled valves.
$3,528.
$588 each year.
$588.
$30 each year.
$4,620.
$5,390 to $11,550.
$12,320.
$15,090 to $19,250.
Notifying PHMSA.
$38,462.
$618 each year
$3,733 each year
The present value of the costs evaluated over 20 years at a three percent discount rate are approximately $239 million, while the present value of the costs over 20 years at a seven percent discount rate are approximately $165 million. The annualized costs at the three percent discount rate are approximately $16 million, while the annualized costs at the seven percent discount rate are approximately $15 million.
Since the present value of the quantified benefits ($1,541 million at three percent and $1,098 million at seven percent) exceeds the present value of the costs ($328 million at three percent and $164 million at seven percent), the rule is expected to have net benefits.
F.3. Regulatory Flexibility Act
Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.), PHMSA must consider whether rulemaking actions would have a significant economic impact on a substantial number of small entities.
The final rule affects operators of gas pipelines. Based on annual reports submitted by operators, there are approximately 1,450 gas transmission and gathering systems and an equivalent number of distribution systems potentially affected by this rule. The size distribution of these operators is unknown and must be estimated.
The affected gas transmission systems all belong to NAICS 486210, Pipeline Transportation of Natural Gas. In accordance with the size standards published by the Small Business Administration, a business with $6.5 million or less in annual revenue is considered a small business in this NAICS.
Based on August 2006 information from Dunn & Bradstreet on firms in NAICS 486210, PHMSA estimates that 33 percent of the gas transmission and gathering systems have $6.5 million or less in revenue. Thus, PHMSA estimates that 479 of the gas transmission and gathering systems affected by the rule will have $6.5 million or less in annual revenue. PHMSA does not expect that any local gas distribution companies or gathering systems will be taking advantage of the potential to use an alternative MAOP.
The rule mandates no action by gas transmission pipeline operators. Rather, it provides those operators with the option of using an alternative MAOP in certain circumstances, when certain conditions can be met. Consequently, it imposes no economic burden on the affected gas pipeline operators, large or small. Based on these facts, I certify that this rule will not have a substantial economic impact on a substantial number of small entities.
F.4. Executive Order 13175
PHMSA has analyzed this rulemaking according to Executive Order 13175, ``Consultation and Coordination with Indian Tribal Governments.'' Because the rule does not significantly or uniquely affect the communities of the Indian tribal governments, nor impose substantial direct compliance costs, the funding and consultation requirements of Executive Order 13175 do not apply.
F.5. Paperwork Reduction Act
This rule adds notification paperwork requirements and record retention on pipeline operators voluntarily choosing an alternative MAOP for their pipelines. Based on analysis of the regulation, there will be an estimated nine total annual burden hours attributable to the notification and recordkeeping requirements in the first year. In following years, the annual burden is expected to decrease to one and one-half hours. The associated cost of these annual burden hours is $720 in year one, and $120 thereafter. No other burden hours and associated costs are expected. The Paperwork Reduction Act analysis in the docket has a more detailed explanation.
F.6. Unfunded Mandates Reform Act of 1995
This rule does not impose unfunded mandates under the Unfunded Mandates Reform Act of 1995. It does not result in costs of $132 million or more in any one year to either State, local, or tribal governments, in the aggregate, or to the private sector, and is the least burdensome alternative that achieves the objective of the rulemaking.
F.7. National Environmental Policy Act
PHMSA has analyzed the rulemaking for purposes of the National Environmental Policy Act (42 U.S.C. 4321 et seq.). The rulemaking will require limited physical change or other work that would disturb pipeline rights-of-way. In addition, the rule codifies the terms of special permits PHMSA has granted. Although PHMSA sought public comment on environmental impacts with respect to most requests for special permits to allow operation at pressures based on higher stress levels, no commenters addressed environmental impacts. Further, PHMSA did not receive any comment on the environmental assessment it had prepared in conjunction with the proposed rule. PHMSA has determined the rulemaking is unlikely to significantly affect the quality of the human environment. An environmental assessment document is available for review in the docket.
F.8. Executive Order 13132
PHMSA has analyzed the rulemaking according to Executive Order 13132 (64 FR 43255, Aug. 10, 1999) and concluded that no additional consultation with States, local governments or their representatives is mandated beyond the rulemaking process. The rule does not have 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. The rule does not impose substantial direct compliance costs on State or local governments.
Further, no consultation is needed to discuss the preemptive effect of the proposed rule. The pipeline safety law, specifically 49 U.S.C. 60104(c), prohibits State safety regulation of interstate pipelines. Under the pipeline safety law, States have the ability to augment pipeline safety requirements for intrastate pipelines PHMSA regulates, but may not approve safety requirements less stringent than those required by Federal law. And a State may regulate an intrastate pipeline facility PHMSA does not regulate. In addition, 49 U.S.C. 60120(c) provides that the Federal pipeline safety law ``does not affect the tort liability of any person.'' It is these statutory provisions, not the rule, that govern preemption of State law. Therefore, the consultation and funding requirements of Executive Order 13132 do not apply.
F.9. Executive Order 13211
This rulemaking is likely to increase the efficiency of gas transmission pipelines. A gas transmission pipeline operating at an increased MAOP will result in increased capacity, fuel savings, and flexibility in addressing supply demands. This is a positive rather than an adverse effect on the supply, distribution, and use of energy. Thus this rulemaking is not a ``significant energy action'' under Executive Order 13211. Further, the Administrator of the Office of Information and Regulatory Affairs has not identified this rule as a significant energy action.
List of Subjects in 49 CFR Part 192
Design pressure, Incorporation by reference, Maximum allowable operating pressure, and Pipeline safety.
■ For the reasons provided in the preamble, PHMSA amends 49 CFR part 192 as follows: