Phmsa-2005-23447, fr, 192-[107]




Yüklə 371.59 Kb.
səhifə2/4
tarix17.04.2016
ölçüsü371.59 Kb.
1   2   3   4

C. Comments on the NPRM
PHMSA received comments from 19 organizations in response to the NPRM. These included eleven pipeline operators, four trade associations and related organizations, three steel/pipe manufacturers, and one state pipeline safety regulatory agency.
C.1. General Comments
API 5L, 44th Edition
Many commenters noted that pipe material/design requirements in American Pipeline Institute (API) Standard 5L (API 5L) have been significantly revised in the 44th edition, which they stated would be in effect by the time a final rule is issued. These commenters generally suggested that PHMSA should defer to, or incorporate, requirements from the 44th edition where applicable rather than establishing different technical requirements in regulation.
Response
API 5L, 43rd edition, is currently incorporated by reference into the Code of Federal Regulations (CFR). PHMSA has begun a technical review of the 44th edition to determine whether and to what extent it is appropriate to update this reference or if exceptions need be taken when so incorporating the standard. PHMSA cannot reference requirements in the 44th edition until this review is completed and the regulations have been revised to incorporate the new edition. Where differences in the 44th edition would affect requirements in this rule, appropriate changes will be made when that edition is incorporated.
Effect on Special Permits
All commenters who addressed the question suggested that requirements in a final rule should not apply retroactively to pipelines operating at alternative MAOP based on special permits issued after detailed review by PHMSA. One pipeline operator provided a legal analysis maintaining that such retroactive application would be contrary to PHMSA's statutory authority. These organizations also commented that PHMSA should continue review of special permit applications until the final rule is issued, noting that in many cases operation at the proposed higher MAOP is necessary to meet contractual commitments operators have made in anticipation of a special permit being granted and to meet national energy needs.

Response


As noted above, PHMSA continued reviewing special permit applications throughout this rulemaking proceeding, generally applying the same criteria adopted in this rule. Having now published the final rule, we consider it unnecessary to complete review of pending special permit applications on the subject. Accordingly, PHMSA intends to terminate these proceedings, with appropriate notice to the individual applicants.

In contrast, this regulatory action has no effect on the status of special permits or waivers currently in effect. As we explained recently in Docket No. PHMSA-2007-0033, Pipeline Safety: Administrative Procedures, Address Updates, and Technical Amendments, (FR Volume 73, No. 61, 16562, published March 28, 2008), PHMSA reserves the right to revoke or modify a special permit or waiver based on an operator's failure to comply with the conditions of the special permit/waiver or on a showing of material error, misrepresentation, or changed circumstances. Although an operator may elect to surrender its special permit at any time, nothing in this rule requires the operator to do so or otherwise triggers reopening of a special permit/waiver currently in effect. The existing MAOP special permits were issued based upon a PHMSA review of the operator's engineering, construction, O&M procedures and operating history. While some of the pipeline segments may not meet all of the requirements specified in this final rule, the operational history and O&M practices provide an equivalent level of safety as provided in this final rule. Furthermore, whether a pipeline is operating at higher MAOP under this rule or a special permit/waiver, PHMSA will monitor and enforce compliance with the applicable conditions and safety controls.

Structure

One state pipeline safety regulatory agency expressed concern about the complexity and inconsistency being added to the regulations as a result of the structure of the proposed rule. The state agency noted that the proposal would add many pages to part 192 that would apply to only a limited number of gas transmission operators. The agency suggested that it would be more effective, and cause less confusion, if requirements for pipelines operating at an alternative MAOP were presented in a separate subpart, applicable only to those pipelines.


Response
PHMSA has not previously used a separate subpart to include varied requirements applicable to specific types of pipelines. Instead, subparts have been used for individual topics, such as Corrosion Control or Integrity Management. PHMSA considers it more appropriate to incorporate requirements applicable to each subpart as the requirements in this rule implicate several subparts. PHMSA also notes that no other commenters indicated that the structure of the proposed rule was confusing. PHMSA has retained the structure of the proposal in this final rule. PHMSA intends to post this notice of final rulemaking on its web site, which will provide a reference for pipeline operators that includes all of the requirements associated with alternative MAOP in one document.
C.2. Comments on Specific Provisions in the Proposed Rule
C.2.1. Section 192.7, Incorporation by Reference
Interstate Natural Gas Association of America (INGAA) and three pipeline operators supported incorporation of American Society of Testing and Materials (ASTM) standard ASTM A-578/A578M-96 into the regulations. These commenters generally noted that this action is consistent with reliance on consensus standards, which they support. American Gas Association (AGA) and the Gas Piping Technology Committee (GPTC) took the contrary position and opposed incorporation of the ASTM standard. GPTC commented that the standard is used by one mill and that other mills use other standards (including International Standards Organization (ISO) standards). GPTC also noted that there are a number of equivalent standards and that PHMSA should not select one for incorporation. AGA added that incorporating the standard could have unintended consequences of making the rule too prescriptive and precluding the use of equivalent standards.
Response
The final rule incorporates ASTM A578/A578M-96 into the regulations. Incorporation by reference makes the provisions of the standard apply, when it is referenced in a regulation, in the same manner as if they were written in the CFR. Referencing consensus standards wherever possible is the policy of the Federal government.

This standard is referenced in the regulation for assuring plate/

coil quality control (QC). That reference requires that ultrasonic (UT) testing be conducted in accordance with the standard, API 5L paragraph 7.8.10, or equivalent. The pipe must also be manufactured in accordance with API 5L which is already referenced in §192.7. PHMSA considers that the allowance for use of an equivalent standard renders moot the concerns expressed by AGA and GPTC.
C.2.2. Design Requirements
Section 192.112(a), General Standards for the Steel Pipe
Carbon equivalent: INGAA, five pipeline operators and two pipe manufacturers all noted that the proposed limit in paragraph (a)(1) on carbon equivalent (CE) (0.23 percent Pcm) is inconsistent with the 44th edition of API 5L. INGAA and one operator suggested deleting the limit from the proposed rule. Two operators noted that the NPRM described no analysis or data showing the need for a different limit. Several commenters indicated that high-strength pipe (grades X-80 and above) is difficult to achieve with the stated limit. One operator suggested that weldability is the key issue and that allowance for a higher CE is particularly important for high-strength and strain-based pipe. A steel manufacturer objected to sole reliance on the Pcm formula for determining the CE value.
Response
PHMSA agrees that the limit in API 5L is acceptable. PHMSA has changed the limit for CE to 0.25 Pcm (Ito-Bessyo formula for CE), which is consistent with API 5L. PHMSA does not agree that no limit should be included in the CFR. PHMSA considers that a limit is necessary to assure the quality of steel used for pipelines to operate at an alternative MAOP. Weldability tests are not timely for determining the acceptability of steel, as they cannot be performed until pipe is manufactured. Recent experience with several new pipelines using X-80 steel has indicated that such high strength steel can meet the CE limit. PHMSA does not currently have experience with steels of grades higher than X-80 and will need to understand what is important for such pipe grades as they are used.

PHMSA acknowledges that there are other methods for calculating the CE value of steel. The Pcm formula included in the proposed rule is a method used by several mills. PHMSA has revised the final rule to include use of an alternate International Institute of Welding (IIW) CE formula, used by other mills for determining CE.


Diameter to thickness ratio: INGAA and three pipeline operators suggested deleting the limit in proposed paragraph (a)(3) on the ratio of pipe diameter to thickness (D/t). They maintained that this limit may be inappropriate for high-grade pipe and that the concerns that might underlie such a limit are adequately addressed by the proposed rule and common construction practices and quality assurance (QA). One operator noted that ovality and denting issues are addressed by the proposed construction requirements of §192.328, that QA is required by proposed §192.620(d)(9), and that the baseline geometry ILI and the provisions of the ASME Code would also address the underlying concerns.
Response
PHMSA has retained the proposed limit. PHMSA adopted this limit (i.e., D/t <= 100) based upon presentations made by industry experts at the public meeting on ``Reconsideration of Maximum Allowable Operating Pressure in Natural Gas Pipelines'' held on March 21, 2006 in Reston, VA. Higher D/t ratios can lead to excessive denting during transportation, construction bending, pipe stringing on the right-of-way, backfilling, and hydrostatic testing.
Section 192.112(b), Fracture Control
Several commenters noted that some requirements included in the proposed rule are being eliminated or significantly revised in the 44th edition of API 5L. The steel/pipe manufacturers suggested referencing the new standard to, among other things, avoid unnecessarily limiting approaches to deriving arrest toughness and treating all sizes and types of pipe (e.g., seamless) the same for purposes of the drop weight test.

INGAA and three pipeline operators suggested a change to allow a crack arrest design other than mechanical arrestors if crack propagation cannot be made self-limiting. (One operator noted that Clock Spring 1 is marketed as a crack arrestor). They suggested that a rule should allow an option for engineering analysis, including an analysis of consequences. One operator noted that this option could be particularly important for high-pressure, large-diameter pipelines. Two operators generally supported the proposed approach for fracture control if self-arrest is attainable. They noted that it is critical that operators have a plan and consider the potential under-conservativeness of Charpy toughness equations for high grade pipe (X-70 and above).


Response
PHMSA has not yet incorporated the 44th edition of API 5L into the regulations. PHMSA is conducting a technical review of this edition to determine if it is acceptable for incorporation. If, after that review, PHMSA determines that the standard is acceptable, PHMSA will propose to incorporate the 44th edition and change other affected rules as appropriate.

The final rule requires an overall fracture control plan to resist crack initiation and propagation and to arrest a fracture within eight pipe joints with a 99 percent occurrence probability and within five pipe joints with a 90 percent occurrence probability. Research has shown that an effective fracture plan should include acceptable Charpy impact and drop weight tear tests, which are required in this final rule.

PHMSA considers composite sleeves to be suitable mechanical crack arrestors. Operators could use composite sleeves for this purpose, install periodic joints of thicker-walled pipe, or use other design features to provide crack arrest if it is not possible to achieve the toughness properties specified in the rule and also assure self-

limiting arrest. PHMSA has revised the language in this final rule to allow additional design features and to make mechanical crack arrestors an example of such features rather than the only method allowed.


Section 192.112(c), Plate/Coil Quality Control
One pipeline operator and two pipe manufacturers suggested expanding the mill control inspection program to a full internal quality management program and including caster and plate/coil/pipe mills.

INGAA, three pipeline operators and two pipe manufacturers commented that the specificity of requirements applicable to mill inspection should be reduced. These commenters agreed that a macro etch test is appropriate but suggested that the details of how this test is applied should be left to decisions of the mill and the pipe purchaser. They suggested that API 5L provides a foundation for those decisions and the specific requirements in the proposed rule add unnecessary cost impact. One pipe manufacturer noted that the Mannesmann scale is very subjective, while a second separately commented that reference to the Mannesmann scale should be deleted because it is proprietary and thus inappropriate for inclusion in a regulation. One operator requested that the mill inspection requirements, including those for macro etch and UT examination, be explicitly limited to new pipelines, noting that it is unlikely these tests were performed for any existing pipelines and that they have minimal relevance for existing pipelines that would be subject to the proposed rule.

INGAA and four pipeline operators suggested that an alternative to the UT testing specified should be allowed for identifying laminations. They suggested that a full-body UT inspection, for example, should be acceptable.

One operator and two manufacturers commented that it is inappropriate to use the proposed macro etch test and acceptance criteria as a heat/slab rejection criteria. These commenters noted that no consensus standard references this test. The operator maintained that the test does not accomplish what PHMSA suggested in the preamble of the NPRM, that it is a lagging rather than a leading test and its use as an acceptance test without a retest allowance could result in rejection of up to 2,000 tons of steel or more. The operator suggested that this should be a mill control test rather than an acceptance test with specifics, including retest allowance, to be negotiated between the mill and pipe purchaser.

One operator and one manufacturer noted that ASTM A578 is a plate UT inspection standard. They commented that specifying this standard for coil/pipe is beyond its scope. They also commented that we gave no basis for proposing that 50 percent of surface and 90 percent of joints be examined. They noted that pipe seam welds and pipe ends are inspected radiographically or by UT and that additional UT is more appropriately a purchaser-specified requirement. Another operator also suggested that the 50 percent surface coverage requirement be deleted in favor of reference to ASTM A578/A578M.

Two manufacturers suggested that the rule allow UT on plate/coil or pipe body, noting that most United States mills lack equipment to perform ASTM A578 testing. Another manufacturer suggested that a combination of electromagnetic inspection (EMI) and UT inspection is superior and would produce the most dramatic impact. This combination, according to this manufacturer, is also applicable to seamless and electric resistance welded (ERW) pipe.

One manufacturer recommended that the inspection program of proposed section 192.112(c)(2)(ii) be limited to submerged arc welded (SAW) pipe, and that the acceptance criteria for UT testing be referenced to ASTM A578 or equivalent. This commenter noted that laminations are not a significant issue for modern pipe.
Response
PHMSA agrees that an ``internal quality management program'' is more descriptive than a ``mill control inspection program'' and that such a program should be required at all mills associated with the manufacture of steel and pipe. The final rule has been revised accordingly.

PHMSA considers that a macro etch test or other equivalent method is needed to identify inclusions that may cause centerline segregation during the continuous casting process. The acceptance criteria must be agreed to between the purchaser and the mill. PHMSA has added an alternative to the requirement for a macro etch test consisting of an operator QA monitoring plan that includes audits conducted by the operator (or an agent operating under its authority) of: (a) Steelmaking and casting facilities; (b) QC plans and manufacturing procedure specifications (MPS); (c) equipment maintenance and records of conformance; (d) applicable casting superheat and speeds; and (e) centerline segregation monitoring records to ensure mitigation of centerline segregation during the continuous casting process.

PHMSA agrees that alternate methods to test the pipe body for laminations, cracks, and inclusions should be acceptable and has revised the rule to allow methods per API 5L Section 7.8.10 or ASTM A578-Level B, or other equivalent methods. PHMSA understands that it is unlikely that many existing pipelines were manufactured using processes that included the specified examinations but does not consider that sufficient reason for excluding existing pipelines from the requirements.

The requirement for 50 percent of surface and 95 percent of lengths of pipe to be UT tested was set to ensure adequate QC standards. PHMSA agrees that the specified QC requirements also must be practical. In the final rule, we have reduced the requirement for 50 percent of surface coverage to 35 percent because we recognize that it may be difficult to achieve 50 percent coverage for pipe manufactured with helical seams.

PHMSA has not deleted reference to the Mannesmann scale, which is widely used by steel manufacturers. In addition, the regulation allows for use of equivalent measures.

PHMSA does not agree that the inspection program of proposed 192.112(c)(2)(ii) should be limited to SAW pipe. PHMSA considers this requirement to be an overall quality management tool and not just for laminations. Additionally, PHMSA notes that at least one recently constructed pipeline has had problems with laminations.


Section 192.112(d), Seam Quality Control
INGAA, four pipeline operators, and two pipe manufacturers all recommended additional reliance on the procedures of API 5L 44th edition. The manufacturers would have referenced API 5L for toughness requirements and made them applicable to weld and heat affected zone in SAW pipe only. They noted that the proposed requirement is inappropriate for ERW pipe, that the specified toughness is higher than that called for in API 5L and is not necessary. The manufacturers believe that fracture arrest capabilities are not needed in weld metal, since staggered seams in pipeline construction result in arrest occurring in the pipe body.

INGAA and three pipeline operators would have eliminated reference to specific hardness testing or a maximum hardness level, arguing that API 5L contains sufficient guidance. They further noted that the specified hardness of 280 Vickers (Hv10) is only for sour gas. One manufacturer would have relaxed the hardness requirement to 300 Hv10 and allowed for equivalent test methods (per ASTM E140). Another would have specified a maximum hardness ``appropriate for the pipeline design'' vs. specifying a limit. The first manufacturer noted that API 5L does not specify hardness limits except for sour gas service or offshore pipelines and that the technical justification for these limits on other pipe is not obvious. The manufacturers maintained that limiting hardness may not allow attaining the best weld properties and that 280 Hv10 is likely not attainable for pipe grades X-80 and above.

Two pipe manufacturers requested that the rule be clarified to indicate that the seam QC requirements apply only to longitudinal or helical seams. They noted that pipe mill jointer welds require radiography per API 1104 and that significant capital expense would be required for pipe mills to UT test jointer and skelp end welds after cold expansion and hydrostatic testing.
Response
PHMSA has not yet incorporated the 44th edition of API 5L into the regulations. PHMSA is conducting a technical review of this edition to determine if it is acceptable for incorporation. If, after review, PHMSA determines that the standard is acceptable, PHMSA will propose to incorporate the 44th edition and propose changes to other affected regulations as appropriate.

PHMSA has deleted the proposed limit on toughness. This limit was not included in the conditions applied to special permits issued for alternative MAOP operation. Pipe procured to modern standards generally meets the proposed limit, and other requirements in this rule, provide for crack arrest. Thus, PHMSA concluded that a toughness limit was not needed.

PHMSA does not agree that it is not necessary to specify a hardness limit. All recent pipelines for which special permits have been issued to operate at alternative MAOP have met the proposed hardness limit without apparent difficulty. This includes X-80 pipe. The requirement helps assure that only high-quality steel is used for pipelines to be operated at alternative MAOP. Hardness must be limited to assure welds are not susceptible to cracking. The proposed limit has been retained in the final rule.

PHMSA intends the proposed seam inspection requirements to apply to pipe seam welds and not to jointer or skelp welds. The title of this subparagraph is ``Seam quality control,'' and its requirements all refer to ``seam welds'' or ``seams.'' PHMSA does not consider that additional changes are needed to clarify the applicability of these requirements.


Section 192.112(e), Mill Hydrostatic Test
Most commenters objected to the proposed requirement that mill hydrostatic tests be held for 20 seconds. They noted that mills typically follow API 5L, which specifies a hydrostatic test of 10 seconds and that changing this standard could reduce mill productivity. One operator also noted that a more rigorous qualification test is already specified elsewhere in the proposed regulation.

One manufacturer would have limited the required maximum test pressure to 3,000 psi if there are physical limitations in mill test equipment that preclude obtaining higher pressures. The manufacturer stated that most mills cannot achieve test pressures above 3,000 psi, which is the maximum specified in API 5L and that upgrades to equipment would cost from $0.5 to $4 million per tester.


Response
PHMSA agrees that a 20-second mill hydrostatic test is not needed and has revised the final rule to reduce the required hold time to 10 seconds. While a longer mill hydrostatic test may allow the discovery of more pipe defects, the benefit is marginal. The pipeline will later be subject to a much longer hydrostatic test prior to being placed in service according to 192.505(c). Moreover, in the case of Class 1 and 2 locations, the pipe will be tested at a higher stress level than the mill hydrostatic test according to 192.620(a)(2).

PHMSA does not consider it appropriate to limit the maximum test pressure to reflect the reported mill limitations. In practice, the need for tests above 3,000 psi should be rare. Test pressures that high would only be required for pipeline in a Class 3 location operating at a very high MAOP.


Section 192.112(f), Coating
INGAA, GPTC, and eight pipeline operators all objected to the proposed requirements that would have limited operation at an alternative MAOP to pipe coated with fusion bonded epoxy (FBE). The commenters noted that specifying any single coating type would stifle innovation. They suggested that a performance-based requirement would be more appropriate. The important performance characteristics they identified include non-disbonding and non-cracking. Two operators would add non-shielding, and GPTC suggested specifying that coating must meet or exceed the protection of FBE.

GPTC and one operator requested clarification that girth welds can be coated with other than FBE. GPTC also requested clarification that the proposed requirement in subparagraph 2 that coatings used for trenchless installation must resist abrasion and other damage applies to the coatings described under subparagraph 1.


Response
PHMSA agrees that specifying a particular coating could stifle innovation and we have revised the final rule to require non-shielding coatings. Eliminating reference to FBE coating in this section obviates the need for additional changes to note that girth welds can be coated with other than FBE.

PHMSA has made a minor change in response to GPTC's request for clarification. Subparagraph 192.112(f)(2) now requires that coatings used for trenchless installation must resist abrasions and other installation damage ``in addition to being non-shielding.''


Section 192.112(g), Flanges and Fittings
INGAA and three pipeline operators generally supported the proposed requirements for certification records and a pre-heat procedure for welding of components with CE greater than 0.42 percent, but maintained that existing standards and operator supplemental requirements are adequate to assure the integrity of flanges and fittings. The operators cited specific standards to which fittings and flanges should be purchased. Another operator noted that the proposed requirements go beyond API and ASTM standards, and suggested that the new requirements should be part of an industry standard. This operator also suggested that PHMSA establish a minimum size below which certifications would not be required.

GPTC requested clarification as to what certification is required and what requirements/specifications are to be certified.


Response
PHMSA has concluded that no changes are needed to the standards proposed for flanges and fittings. It is likely that flanges and fittings procured to current standards will meet the rule's requirements. PHMSA will review the degree of compliance during inspections of pipelines being constructed or upgraded for operation at an alternative MAOP. PHMSA does not agree that the proposed requirements go beyond API and ASTM standards. Fittings, flanges and valves manufactured to API, ASTM, and/or ASME/ANSI standards should not be operated above the maximum operating pressure limits of those industry standards for the product rating. This rule change is not intended to increase maximum operating pressure limits or designated pressure or temperature rating of referenced code standards.

In the final rule, PHMSA has clarified that certification must address chemistry, strength and wall thickness.


Section 192.112(h), Compressor Stations
Commenters expressed concern about the proposed requirement to limit compressor station discharge temperatures to 120 degrees Fahrenheit (49 degrees Celsius) unless testing shows the coating can withstand higher temperatures in long-term operations. INGAA and four pipeline operators would allow ``research'' in addition to testing to permit operation above 120 degrees Fahrenheit. INGAA submitted a white paper titled ``A Review of the Performance of Fusion-Bonded Epoxy Coatings on Pipelines at Operating Temperatures Above 120 [deg]F'', dated May 16, 2008, describing research it believes is relevant. The commenters stated that more testing is not needed, because FBE coating has been shown effective by research and experience in service. They maintained that disbonding may occur but is irrelevant because FBE coating is conductive and cathodic protection is still effective.

One pipeline operator would have allowed operation at a higher compressor station discharge temperature if justified by test or data held by the manufacturer, coating applicator, or operator. The operator maintained that modern coating can withstand higher temperatures, and that maintaining 120 degrees Fahrenheit may be impractical on hot days (during which peak loads often occur) in southern locations. Another operator suggested allowing operators to rely on FBE manufacturers' specifications as the ``testing'' adequate to allow operation above 120 degrees Fahrenheit, limiting operation to 90 percent of the manufacturer's continuous operating temperature. Another operator suggested allowing a long-term coating integrity monitoring program as an alternative to designing compressor stations to limit discharge temperature to 120 degrees Fahrenheit.

A state pipeline safety regulatory agency suggested that alternative approaches be allowed. The agency suggested that operators could install heavier walled pipe and operate at conventional MAOP for the distance required to assure that pipe wall temperatures would be below 120 degrees Fahrenheit. This commenter stated its belief that this would be a simpler and cheaper solution to the concern over compressor station outlet temperature and that its use should not be precluded.
Response
PHMSA is not persuaded by the arguments put forth by commenters, and in the INGAA white paper titled ``A Review of the Performance of Fusion-Bonded Epoxy Coatings on Pipelines at Operating Temperatures Above 120 [deg]F'', dated May 16, 2008, that operation above 120 degrees Fahrenheit is simply acceptable. In fact, the INGAA white paper confirms that disbonding and possibly cracking of FBE coating is more likely to occur at operating temperatures above 120 degrees Fahrenheit. PHMSA disagrees that disbonding is irrelevant because disbonded FBE remains conductive and an operating cathodic protection system will protect the pipeline from corrosion.

External corrosion is one of the most significant threats affecting steel pipelines. PHMSA regulations require two levels of protection against this threat: Coating and cathodic protection. These requirements are intended to provide redundant protection. If coating fails, cathodic protection continues to protect the pipe. If cathodic protection fails, the coating is still present. PHMSA agrees that it is important that disbonded coating remain conductive to assure continued protection by cathodic protection. This is why the rule has been revised to require ``non-shielding'' coating. At the same time, PHMSA does not consider it acceptable to ignore known circumstances in which one of the protections against corrosion is likely to fail simply because the other exists. If PHMSA believed only one level of protection were needed, the regulations would require either coating or cathodic protection. INGAA's white paper confirms that there is a significant likelihood that one of the levels of protection against corrosion (i.e., coating) will fail if operated above 120 degrees Fahrenheit. For pipelines to be operated at an alternative MAOP, where the margin for corrosion is smaller than for pipelines conforming to the existing regulations, PHMSA will not accept this higher likelihood of failure of the coating system.

Nevertheless, PHMSA recognizes that improvements in coating systems may allow operation above 120 degrees Fahrenheit without significantly higher likelihood of disbonding. Thus, the rule allows operation above this temperature if research, testing, and field monitoring tests demonstrate that the coating type being used will withstand long-term operation at the higher temperature. The operator must assemble and maintain the data supporting higher-temperature operation. Research, testing and field monitoring must be for coating by the same manufacturer and must be specific to the brand of coating (if the manufacturer makes more than one brand), application temperature, or operating temperature rated coating.

PHMSA agrees that a long-term coating integrity monitoring program can also assure that coating remains effective at higher operating temperatures, but the effectiveness of such a program depends on how it is structured and implemented. PHMSA would expect, for example, that a monitoring program being used as a basis for operating at temperatures above 120 degrees Fahrenheit would include periodic examinations to assure coating integrity (e.g., direct current voltage gradient). PHMSA has modified the final rule to allow a long-term coating integrity monitoring program to be used as a basis for allowing pipe temperatures in excess of 120 degrees Fahrenheit, but operators must submit their programs to the PHMSA pipeline safety regional office in which the pipeline is located for review before pipeline segments may be operated at alternative MAOP at these higher temperatures. PHMSA's review will help assure that the monitoring programs are comprehensive enough to assure long-term coating integrity, to identify instances in which coating integrity becomes degraded, and to address those problems. An operator must also notify a state pipeline safety authority when the pipeline is located in a state where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that state.

Where compressor station compression ratios raise the temperature of the flowing gas to above 120 degrees Fahrenheit, operators should consider installing gas coolers at compressor stations. This practice has been successfully used in the industry to cool the gas stream to not damage the pipe external coating.

PHMSA agrees that the alternative of heavier walled pipe operated at conventional MAOP for the distance required to assure that pipe wall temperatures do not exceed 120 degrees Fahrenheit suggested by the state regulator is also an acceptable method of addressing the concern of high-temperature operation. PHMSA has made minor changes to the rule to make it clear that this option is not precluded.


C.2.3. Construction Requirements
Section 192.328(a), Quality Assurance (QA)
Four pipeline operators supported the QA requirements of proposed §192.328(a). A state pipeline safety regulator noted that subparagraph 2(ii) duplicated requirements in proposed §192.620(c)(5) and questioned why both sub-rules were needed.
Response
PHMSA's experience in regulating pipelines operating at higher MAOPs under special permits has indicated that control of quality is subject to frequent problems. As a result, PHMSA considers that an explicit requirement for a QA plan during construction is needed. The requirements of proposed §192.620(c)(5) also addressed quality concerns, but they relate principally to personnel qualification. As described below, this proposed paragraph has been revised in the final rule to more explicitly address the qualification of personnel performing construction tasks.
Section 192.328(b), Girth Welds
INGAA and four pipeline operators suggested moving the requirement for testing of girth welds on existing pipelines from §192.328 to §192.620. They believe that the requirement is inappropriately located in a construction section that is not otherwise applicable to existing pipe.

Response


PHMSA agrees and has moved this requirement in the final rule to §192.620(b) as one of the criteria for determining when an existing pipeline can be operated at alternative MAOP.

Section 192.328(c), Depth of Cover

Three pipeline operators supported the proposed depth of cover requirements, although one would clarify that they apply to new construction. Another operator suggested that allowance be made for less depth of cover if alternative means of protection are used (e.g., concrete slabs) that offer equivalent protection.
Response
PHMSA agrees that alternative protection is acceptable and has revised its proposed rule accordingly in this final rule. To satisfy the rule, alternative protection must provide equivalent protection and the operator must demonstrate this equivalence. Simply providing barriers without demonstrating that they provide equivalent protection is not sufficient.

PHMSA did not intend this requirement to apply to new construction only and thus, has not changed the requirement in the final rule. PHMSA considers that a pipeline to be operated at alternative MAOP, including existing pipelines, must have superior protection from outside force damage. PHMSA recognizes that existing pipelines constructed in compliance with §192.327 may have less cover than required in this rule. Operators of those pipelines desiring to implement alternative MAOP must provide equivalent protection for those segments not meeting the depth of cover requirements.


Section 192.328(d), Initial Strength Testing
A number of commenters objected to the proposed requirement that any failure indicative of a fault in material disqualifies a pipeline segment from operation at an alternative MAOP. The commenters suggested that a root cause analysis be permitted, consistent with previously-

issued special permits, to determine if the fault indicates a systemic issue. Disqualification is only appropriate, according to the commenters, if a systemic issue exists, and failures can result from isolated causes. One operator would also clarify that these requirements apply to base pipe material rather than flanges, gaskets, etc. Another suggested that multiple test failures can actually be beneficial, because they prompt additional failure analyses that better assure the integrity of the non-failed pipe.


Response
PHMSA agrees that a single failure can reflect an isolated cause and should not disqualify an entire segment from operation at an alternative MAOP if it can be demonstrated that the failure is not indicative of a problem that could affect the rest of the pipeline segment. PHMSA has revised the final rule to allow a root cause analysis of any failures as a way of justifying qualification of a pipeline segment. Root cause analysis must demonstrate that failures in alternative MAOP pipeline segments are not systemic. Operators are required to notify PHMSA of the results of their evaluations, which will allow us to validate their conclusions.
Section 192.328(e), Cathodic Protection
INGAA and seven pipeline operators suggested that this paragraph be deleted, since it duplicates requirements in §192.455. One of the operators further commented that whether cathodic protection was operational within 12 months becomes irrelevant once the line is assessed and its condition is known.
Response
PHMSA recognizes that §192.455 requires that cathodic protection be operational within 12 months of placing a pipeline in service but does not consider the requirement in this rule duplicative. Operators who complied with §192.455 will, of course, meet this criterion for operation at alternative MAOP. Those who did not install cathodic protection within 12 months of initial operation will not, whether or not §192.455 was effective at the time. PHMSA considers it critical that cathodic protection be provided as quickly as possible after construction, because there are some forms of corrosion that can result in high corrosion rates (e.g., microbiological corrosion and corrosion from current faults) producing significant loss of pipe wall in a short period of time. Operation at alternative MAOP is thus not allowed for those pipelines for which cathodic protection was not provided within 12 months of initial operation.

PHMSA has moved this requirement from §192.328, a section addressing construction requirements, to §192.620(d)(8), a section addressing operations and maintenance requirements. PHMSA believes that this change will help emphasize that this is not simply a re-statement of the requirement in §192.455.


Section 192.328(f), Interference Currents
Three pipeline operators supported the proposed requirements in this subparagraph (one with the understanding that §192.473 will govern for an existing Class 1 pipeline). Taking a contrary position, another operator urges PHMSA to delete this paragraph because the requirement is already addressed in the regulations and it is difficult to address all interference issues during construction without active cathodic protection (cathodic protection is not required to be in service until 12 months after construction).

Response


It is important to address the potential for interference currents as early as possible. Some pipelines have experienced significant wall loss in the first months of operation due to the effect of interference currents. While it may be true that all interference currents cannot be identified before cathodic protection is in operation, many can be anticipated and remediated during construction. These include the effects of electric transmission lines or electrified trains sharing or paralleling a right of way, or other ground beds in proximity to the pipeline's route. Operators need to address, during construction, interference currents that can be anticipated. Review of cathodic protection effectiveness once it is in operation may identify additional issues, and operators need to deal effectively with these. It is not necessary, however, and potentially deleterious to pipeline integrity to delay all actions addressing interference currents until this time. The provisions proposed in the NPRM remain unchanged in the final rule.
C.2.4. Eligibility for and Implementing Alternative MAOP
Section 192.620(a), Calculating an Alternative MAOP
Most commenters from the pipeline industry objected that the proposed requirements for calculating an alternative MAOP did not recognize that class locations may change once a pipeline is in service. They noted that §192.611 recognizes this for conventional MAOP pipelines, and allows operation following a class change at a higher MAOP than would be required for new pipe in that class provided that testing was performed at a sufficiently high pressure. The commenters sought similar treatment for alternative MAOPs in this paragraph and conforming changes to the language in §192.611 concerning class location changes. These commenters also noted that the proposed rule does not explicitly address compressor stations, meter stations, etc.

Two pipeline operators would reduce the test factor for Class 2 locations from 1.5 to 1.25. They contended that this would allow testing of Class 1 and 2 pipelines to be done together, thereby minimizing environmental disruption that would be associated with separately testing Class 2 to a higher factor. They noted that testing of both classes together would not be possible with a specified test factor of 1.5 for Class 2, since this would overstress the Class 1 pipe (i.e., exceed 100 percent SMYS).

One operator suggested allowing a test factor of 1.25 for existing pipelines and requiring 1.5 only for lines installed after the effective date of this rule. They contended that specifying 1.5 as a design factor for Class 2 results in the alternative MAOP for Class 2 pipe segments being less than currently allowed for existing pipelines.

Two operators suggested that PHMSA amend the proposed rule to explicitly state that the design factors will increase for facilities (stations, crossings, fabricated assemblies, etc.) upgraded in accordance with the rule. One suggested stating that an increase of approximately 11 percent is allowed. The other suggested specific design factors of 0.56 for station pipe, 0.67 for fabricated assemblies and uncased road/railroad crossings in Class 1 areas, and 0.56 for such assemblies/crossings in Class 2 locations.

The state pipeline safety regulatory agency commented that the rule should contain only one provision regarding the test pressure used in determining the MAOP. This commenter noted proposed §192.620(a)(2)(ii) limits MAOP to 1.5 times the test pressure in Class 2 and 3 locations and that proposed §192.620(c)(3) allows 1.25 times test pressure in all classes. The commenter contends that a reference in the latter requirement to the former creates a confusing circularity.
Response
PHMSA agrees that the proposed regulation could be more restrictive than existing requirements in §192.611 in the event of a class change. As noted in the comments, the existing regulation allows operation at a higher MAOP following a class change (i.e., higher than would be required for a new pipeline installed in that class location) provided that testing has been conducted at a sufficiently high pressure to demonstrate adequate safety. PHMSA has revised the final rule to be more consistent with §192.611 in allowing operation at a higher pressure following a class change.

PHMSA has reduced the required test pressure for existing pipelines (i.e., pipelines installed prior to the effective date of the rule) in Class 2 locations to 1.25 times MAOP. This is consistent with §192.611(a)(1). However, if Class 2 pipeline is tested at 1.25 times MAOP, then operation at an increased alternative MAOP following a class change is not allowed. Such testing does not provide sufficient assurance of safety margin for the higher population Class 3 areas. Operators who desire to operate at higher pressures following a change from Class 2 to Class 3 must test their pipe at 1.5 times alternative MAOP.

PHMSA has included alternate design factors for existing facilities and fabricated assemblies to be operated at alternative MAOP. PHMSA does not agree that design factors for facilities and fabricated assemblies are needed for new installations (i.e., those constructed after the effective date of this final rule). PHMSA expects design factors for new facilities (stations, crossings, fabricated assemblies, etc.) to be in accordance with §192.111(b), (c), and (d).
Section 192.620(b), When may an alternative MAOP be used?
Proposed paragraph b(6) limited eligibility for an alternative MAOP for pipeline segments that have previously been operated to those that have not experienced any failure during normal operations indicative of a fault in material. A number of commenters objected to this limitation, which is similar to the limitation in proposed §192.328(d) described above. Here, again, the commenters indicated that root cause analysis should be allowed and operation at an alternative MAOP should be proscribed only if the evaluation reveals a systemic issue.

GPTC requested that paragraph b(3) be clarified. That paragraph requires that segments to be operated at alternative MAOP must have remote monitoring and control provided by a supervisory control and data acquisition system. GPTC requested that PHMSA clarify the degree of ``control'' that is required and questioned whether remote control of flow and pressure are required or if remote control of valves is all that was intended.

One pipeline operator requested that either this paragraph or existing §192.611 be revised to clarify the applicability of the current 72/60/50 percent SMYS limitation on hoop stress. The operator believes it is unclear when and if the §192.611 limitations on hoop stress apply if an alternative MAOP is used.
Response
PHMSA agrees that exclusion from operation at an alternative MAOP is appropriate only if a failure during mill hydrostatic testing, construction hydrostatic testing, or operation is indicative of a systematic issue. PHMSA has revised the final rule here (in this paragraph and in §192.328(d) above) to allow root cause analysis with operators required to notify PHMSA of the results.

Control requires that operators monitor pressures and flows as well as compressor start-up and shut-down. Valves must also be able to be remotely closed. The final rule has been modified to make these requirements clear.

PHMSA has revised §192.611 to include hoop stress limits applicable to pipeline operating at alternative MAOP.
Section 192.620(c), What must an operator do to use an alternative MAOP?
INGAA and four pipeline operators suggested that an engineering analysis should be allowed for existing pipe that was not tested to 125 percent of the alternative MAOP. They noted that some existing pipe may have been tested to higher pressures but not quite to 125 percent, and that this pipe should not be automatically excluded. They noted that experience shows that the vast majority of existing pipe is tested successfully without systemic problems, and that the allowance for 95 percent vs. 100 percent of girth weld examinations in proposed §192.328(b)(2) establishes a precedent for allowing existing pipe that can not fully meet new pipe criteria to operate at an alternative MAOP.

One pipeline operator suggested that the rule either state that pressure test must be at 125 percent of alternative MAOP for Classes 1, 2, and 3 or be revised to refer to the factors in §192.620(a)(2)(ii). They contended the proposed language was unclear as to whether 125 percent is sufficient in all class locations.

A state pipeline safety regulatory agency again suggested that the rule should contain only one provision regarding test pressure (see discussion under §192.620(a) above).

Several commenters addressed training and qualification requirements in proposed §192.620(c)(5). The state agency noted that they duplicated proposed §192.328(a)(2)(ii) and essentially applied operator qualification (OQ) requirements (subpart N) to construction personnel. The state agency suggested it would be simpler and less confusing if it were done in subpart N. One pipeline operator also suggested deleting paragraph c(5) and referring to subpart N. This operator noted that the proposed rule used undefined and vague language–terms such as QC and integrity verification (which could be confused with assessments under subpart O). The operator further noted that subpart N requires OQ and that the meaning of its requirements is well known.

GPTC requested clarification that the requirements are only applicable to segments that operate at an alternative MAOP and as to the meaning of the term ``integrity verification method.''
Response
PHMSA does not agree that an engineering analysis provides an adequate basis to justify operation at alternative MAOP. Operators who desire to use an alternative MAOP for existing pipelines that were not tested to sufficient pressures should re-test their pipelines.

PHMSA has revised the final rule to refer to paragraph (a) for test pressures rather than duplicating them. PHMSA agrees that this change could help avoid confusion.

PHMSA agrees that applying the known requirements of subpart N, related to the qualification of personnel performing work on the pipeline, would likely cause less confusion than specifying the alternative, but similar, requirements included in the proposed rule. Pipeline operators are familiar with subpart N, and their training programs under that subpart have been subjected to audits by PHMSA or states, as appropriate. By its terms, though, subpart N does not apply to construction tasks, since they are not ``an operations or maintenance task''–one part of the four-part test in §192.801(b). PHMSA has revised this final rule to provide that ``construction'' tasks associated with implementing alternative MAOP be treated as covered tasks notwithstanding the definition in §192.801(b). For those tasks, then, the requirements of subpart N will apply. This change obviates the concerns expressed by GPTC and the state agency. (PHMSA disagrees with the state comment, however, that the requirement as proposed duplicated §192.328(a)(2)(ii), as the latter requirement applied only to girth weld coating and not to all construction-related tasks.)
C.2.5. Operation and Maintenance Requirements
Section 192.620(d), Additional O & M Requirements
Two pipeline operators and one state pipeline regulatory agency suggested that covered pipelines should be held to the same requirements as pipelines in HCA under subpart O. They believe that this would make most of §192.620(d) unnecessary and would increase flexibility for operators.

The state regulator noted that it would avoid confusion that might be created for covered pipelines that would be subject to both sets of requirements. One operator commented that no technical basis is provided for the proposed requirements, while subpart O is based on science and research.

Response

PHMSA disagrees with these comments and has not changed the final rule because some provisions are more restrictive than subpart O.

Section 192.620(d)(1), Identifying Threats

INGAA and three pipeline operators suggested eliminating the requirement for a threat matrix and the implied need for additional preventive and mitigative measures. They noted that operation at incrementally higher pressures does not inherently increase risk or introduce new threats and that the proposed rule already includes requirements sufficient to address the incremental change.


Response
PHMSA does not agree that the rule necessarily addresses all threats to a pipeline. The rule addresses many known threats; however, other threats may exist or develop that may affect the pipeline's integrity. It is up to the operator to identify and evaluate possible pipeline threats and therefore PHMSA retained the requirement to identify and evaluate threats consistent with §192.917. The term ``assess'' was changed to ``evaluate'' to avoid confusion with a similar term used in integrity management.

Section 192.620(d)(2), Notifying the Public

INGAA and five pipeline operators would eliminate the requirements in this proposed section. They contended they are unnecessary as they duplicate requirements in existing §192.616 for public education. They further contended that a dedicated notification, specific to operation at a higher pressure, is not needed. One operator would delete subparagraph (d)(2)(ii) and replace it with a one-time notification before operation under an alternative MAOP begins. This operator believes that the proposed requirement for a continuing information program is excessive, but that a one-time notification could be appropriate.
Response
Because of the higher consequences of operating a pipeline at a higher alternative MAOP (and thus a greater impact radius), PHMSA believes that additional public information is necessary to inform any stakeholders living along the right-of-way of this increase. Where the alternative MAOP pipeline is in an HCA already identified per Subpart O, then no additional notification is necessary beyond what is already required.
Section 192.620(d)(3), Responding to an Emergency in High Consequence Areas
Most industry commenters suggested deleting the requirement that operators be able to remotely open mainline valves. They maintained this requirement is unnecessary as an emergency response measure and is contrary to the operating practice of many gas transmission pipeline operators. Some also opposed a requirement for remote pressure monitoring, indicating that it would be costly to provide and would add no value. AGA commented that the language relating to remote control of valves was too prescriptive and could have the unintended consequence of requiring operators to make their safety procedures less stringent (presumably by allowing remote opening of valves).

GPTC and two pipeline operators questioned the requirement for remote valve operation if personnel response time to the valves exceeds one hour. They argued that the one-hour criterion is arbitrary and not justified by research. One operator suggested that it is also counter to experience. These commenters also noted that it is unclear how the response time is to be applied, from the time of notification of an event, from the time a responder is requested to go to the valve location, or from some other triggering event. GPTC suggested that PHMSA consider a requirement based on mileage, similar to §192.179. One operator indicated that the need for remote control should be based on risk analysis rather than an arbitrary specified response time.


Response
PHMSA agrees that the proposed requirement that operators be able to remotely open mainline valves is not needed for emergency response. PHMSA agrees that it is more conservative to require local action to open valves that may have been closed in response to an emergency. PHMSA has modified the final rule to eliminate the requirement that operators be able to remotely open valves. PHMSA considers it important to be able to monitor pressure in order to know that valve closure has been effective. PHMSA has retained this requirement.

PHMSA considers a one-hour response time appropriate and reasonable. It provides time to respond to events while limiting the consequences of an extended conflagration. In the final rule, PHMSA has clarified that the one-hour period begins from the time an event requiring valve closure is identified in the control room and is to be determined using normal driving conditions and speed limits.

Section 192.620(d)(4), Protecting the Right-of-way

All commenters except the state pipeline safety regulatory agency and the steel/pipe manufacturers addressed this section. All contended that the requirement to patrol the right-of-way 26 times per year was excessive and that experience indicates that more frequent patrolling does not prevent pipeline events. They maintained that the proposed frequency has no apparent basis other than that it is the patrolling frequency required for hazardous liquid pipelines and that application of a hazardous liquid pipeline frequency to gas transmission lines is inappropriate.

One operator noted that its experience with monthly patrols has demonstrated that there is very little excavation activity during winter and the summer growing season, making patrols then of little value. The commenters' proposals for alternate patrolling intervals varied, with some suggesting intervals that would vary based on the class location. INGAA suggested patrolling every 4½ months and after known events.

INGAA and one pipeline operator suggested deleting the requirement for a soil monitoring plan, because it would be costly and only duplicates other existing requirements.

INGAA and six pipeline operators suggested deleting the requirement to maintain depth of cover. In its place, they would require restoring depth of cover or providing appropriate preventive and mitigation measures only where damage may occur due to loss of cover. They noted that maintaining the original depth of cover is impractical and unnecessary. Normal erosion and other events can reduce depth of cover, but that reduction does not necessarily lead to an increased risk of damage. Action may be needed in limited circumstances and providing other protection in those circumstances may be more effective and less costly than restoring the original depth of cover. One operator suggested that a monitoring/maintaining depth of cover requirement should be driven by events or risk analysis and that discussion in the preamble of the NPRM implied such an approach. This operator suggested allowing engineered solutions in addition to restoring depth of cover.

INGAA and four pipeline operators would delete or relax the requirement for line-of-sight pipeline markers. INGAA noted that discussion at the March 2007 public meeting indicated that such markers add no value. One operator suggested that it would be more effective to emphasize one-call damage prevention in the preamble of the final rule. Another operator noted that installation of such markers is “non-trivial,” and that there is no data or analysis supporting the need for them. Yet another operator commented that the intent of the requirement is unclear and suggested that circumstances other than agricultural areas and large bodies of water (exclusions included in the proposed rule) would also make it difficult to install line-of-sight markers (e.g., steep terrain, swamps).

INGAA and five pipeline operators objected to what they characterized as an ``open ended'' requirement to implement national consensus standards for damage prevention. These commenters suggested that the requirements focus on the damage prevention best practices identified by the Common Ground Alliance (CGA) and require that operators implement the CGA best practices that apply to their situation. One operator suggested that operators be allowed to evaluate and choose among CGA practices. Another operator also supported a right to choose, indicating that the CGA guide includes no expectation that operators will adopt all best practices.

INGAA and five pipeline operators objected to the proposed requirement for a right-of-way management plan, because it duplicates existing requirements for damage prevention.


Response
PHMSA has revised the required patrol frequency to once per month, at intervals not to exceed 45 days. The decision to reduce the patrolling frequency from 26 patrols per year was based on further analysis of the value added by the cost of additional patrolling, PHMSA's greater experience with administering special permits, and comments from industry and public advocates supporting risk-based requirements rather than a one-size-fits-all approach. PHMSA believes that the right of way management plan required by §192.620(d)(4)(vi), coupled with the patrolling requirement, will provide appropriate safety coverage through requiring an operator to develop and implement an array of actions based on the risk of third-

party damage to the pipeline. These preventative actions may well include additional patrolling above what is required by this rule in areas that are more heavily-populated or that possess greater chances for third-party activities in the vicinity of a pipeline.

PHMSA has retained the requirement for a soil monitoring program. Gas transmission pipelines are often located in areas that can exhibit unstable soils, such as clay, hills, and mountainous areas. It is important to assure that stresses caused by soil movement do not damage pipelines in these areas with reduced design safety factors. PHMSA recognizes that operators may already address these issues in their damage prevention plans or other operating and maintenance procedures. If so, an additional plan is not required. Operators must be able to demonstrate, during regulatory audits, that soil monitoring is addressed within their procedures.

PHMSA has retained the requirement for line-of-sight pipeline markers. Outside damage is the most significant threat to gas transmission pipelines, resulting in the greatest number of accidents. These accidents occur despite current requirements for pipeline markers. Those requirements in §192.707 already require that markers be maintained ``as close as practical'' in the areas required to be covered. PHMSA continues to believe that it is important to provide line-of-sight markers for pipelines operating at alternative MAOP in order to reduce the frequency of outside damage. PHMSA supports one-call programs, and regularly takes actions to encourage and foster their use. Still, damage incidents occur. It is important to reinforce the need for using a one-call program by providing visual evidence that a pipeline is located in an area subject to potential excavation.

At the same time, PHMSA recognizes that installation of line-of-

sight markers is not feasible in all locations. The rule does not require installation of line-of-sight markings in agricultural areas or large water crossings such as lakes and swamps where line-of-sight markers are not practicable. The marking of pipelines is also subject to FERC orders or environmental permits and local laws/regulations. The rule does not require installation where these other authorities prohibit markers.

PHMSA also retained the requirement for a right-of-way management plan since PHMSA data indicates recurring similarities in pipeline accidents on construction sites where better management of the right-of-way could have prevented the accidents. This provision is not redundant with existing damage prevention program requirements, but requires operators to take further steps to integrate activities under those programs to provide for better protection of the right-of-way.
Section 192.620(d)(5), Controlling Internal Corrosion
INGAA, GPTC, four pipeline operators and the state pipeline safety regulatory agency would require a program to monitor gas quality and to remediate internal corrosion as needed but would delete all the specific requirements in this section. One operator suggested that a program complying with Subpart I is all that is needed. The state regulatory agency noted that the NPRM provided no rationale for more stringent or prescriptive requirements than those recently published as §192.476.

Two pipeline operators objected to the requirement for filter separators, contending that these devices are not effective for dealing with upsets involving free water and can provide a false sense of security. One suggested that other actions could be required to assure gas quality. Two other operators suggested that properly designed gas separators would be as effective as filter separators.

One operator objected to requirements for cleaning pigs, inhibitors, and sampling of accumulated liquids. Another opposed the requirement for inhibitors. These operators noted that these actions are not needed if gas monitoring confirms no deleterious constituents. They maintained that the requirements are unnecessary and can potentially result in unintended consequences and risks.

AGA contended that operators should be allowed to determine appropriate methods for monitoring gas quality and that these methods need not always require testing by individual operators. AGA believes this is especially true if tariffs and operating experience demonstrate the absence of contaminants. One pipeline operator asked that PHMSA clarify that the required chromatographs are for analysis of corrosive constituents and need not provide complete analysis for heating value or other purposes.

Two pipeline operators suggested that PHMSA define deleterious gas stream constituents of concern. Two pipeline operators suggested that the limits on gas constituents should be deleted or revised based on research and testing. They believe that the proposed limits are not technically justified. One further noted that deleterious effects may result from contaminants acting ``in concert.''

One pipeline operator would revise the requirement for review of an operator's internal corrosion monitoring and mitigation program to annual review because there is no technical justification for quarterly reviews. Another operator suggested that the gas quality requirements be deleted, as they may conflict with tariffs and result in duplicate enforcement. This operator also suggested that sampling intervals be established by reference to section §192.477 and agreed that a requirement for quarterly review of internal corrosion monitoring programs is excessive.


Response
PHMSA concludes that the proposed requirements do not duplicate or conflict with those in the recently published §192.476. The latter requirements deal principally with design considerations related to internal corrosion, while those included here address monitoring to determine whether conditions conducive to such corrosion occur. Similarly, §192.477 only requires monitoring if corrosive gas is present. The requirements included here specify contaminants to be monitored and limits to be achieved. Since §§192.476 and 192.477 represent the requirements in subpart I related to internal corrosion, PHMSA does not agree that a program complying with subpart I alone is sufficient.

PHMSA has revised the requirement for use of cleaning pigs, inhibitors, and collection of accumulated liquids to apply only in those situations in which corrosive gas is determined to be present. For the particular case of hydrogen sulfide, PHMSA has specified a limit (0.5 grain per hundred cubic feet, 8 parts per million (ppm)) above which this requirement applies.

PHMSA has retained the requirements for gas monitoring. It is important to monitor the gas stream to assure that internal corrosion will not occur or will be identified if corrosion does occur. Continuous monitoring is the most effective way of doing this. PHMSA agrees that monitoring equipment required by this rule is for the purpose of analyzing corrosive gas constituents and need not provide estimates of heating value or other characteristics. Operators can rely on others (e.g., those supplying gas to them) to perform monitoring, but they must assure that such monitoring covers all gas streams and meets the requirements of this rule, including the need for continuous monitoring. PHMSA has also retained the requirement to review the internal corrosion monitoring program quarterly. Such reviews are needed to help assure that upset conditions that could potentially cause internal corrosion are identified and addressed promptly. Annual reviews are insufficient to do this.

PHMSA has revised the limit for hydrogen sulfide to 1.0 grain per hundred cubic feet, or 16 ppm. (PHMSA has also presented this limit in both forms of measurement, as suggested by one commenter). This limit is more consistent with typical tariff limits. At the same time, the final rule requires that additional mitigative actions, including use of cleaning pigs and inhibitors be required when the hydrogen sulfide content exceeds 0.5 grain per hundred cubic feet, as this concentration increases the likelihood of internal corrosion.

The final rule clarifies that deleterious gas stream constituents also include entrained or suspended solids (regardless of size) that are detrimental to the pipeline or pipeline facilities.
Section 192.620(d)(6), Controlling Interferences That Can Impact External Corrosion
Two pipeline operators requested that we clarify that interference surveys are only required where interference is likely, are to be developed using operator judgment, and can be performed using voltage measurements versus ``current.''
Response
PHMSA has clarified the final rule to require that surveys be performed in areas where interference is suspected. Operators should consider the proximity of potential sources of interference, including electrical transmission lines, other cathodic protection systems, foreign pipelines, and electrified railways in deciding where surveys are needed. Operators must conduct surveys capable of detecting the effect of interfering currents, but these surveys need not measure ``current'' directly.
Section 192.620(d)(7), Confirming External Corrosion Control Through Indirect Assessment
INGAA and four pipeline operators requested that this section be revised to require close interval survey (CIS) alone versus one of CIS, direct current voltage gradient (DCVG), or alternating current voltage gradient (ACVG). One of these operators requested clarification that indirect examination is not necessary if additional measures are taken to assure the integrity of the pipeline. Yet another operator suggested that this section be revised to allow other methods of indirect assessment, noting that C-SCAN (which is a current measurement technique) is one possibility that appears to be precluded by the proposed language. All of these commenters plus three additional pipeline operators requested that the timeframe for conducting these examinations be relaxed from six months to one year. They noted that six months may often be impractical because of limitations associated with seasonal weather.

One pipeline operator would delete the proposed requirement for a coating survey of existing pipelines, maintaining that this examination is not needed, since the results of ILI and CIS show that the combination of coating and cathodic protection is working to protect against corrosion. This operator would move the requirement for indirect survey and coating damage remediation to §192.328 to make it clear that this is a construction requirement applicable to new pipelines only. Another operator also commented that requirements to remediate construction damaged coating should be limited to new pipe only. This operator further requested deleting the proposed requirement to repair all voltage drops classified as moderate or severe by National Association of Corrosion Engineers (NACE), since it is unnecessary and impractical to repair every voltage drop. Another operator commented that operators should be allowed to develop specific repair criteria based on their experience.

INGAA and four pipeline operators would relax the proposed requirement to remediate construction coating damage to require either remediation or appropriate cathodic protection. They suggested that the proposed requirement conflicts with the NACE standard referenced in this section (NACE RP-0502-2002) and that coating remediation is not needed as cathodic protection provides adequate protection for areas affected by coating holidays. Another operator noted that the NACE defect classification guidelines are qualitative and that interpretation differences could result in differing repair expectations.

INGAA and two pipeline operators recommended relaxing the requirement to integrate indirect assessment results with ILI from six months to one year. They believe that more rapid integration is not needed and that the value of quicker integration is not explained in the NPRM. Another operator suggested there is an inconsistency in that paragraph (ii) requires action based on the results of one assessment while paragraph (iii) requires that the results of two assessments be integrated.

INGAA and three pipeline operators would delete the periodic assessment requirements of proposed paragraph (iv). They would move the requirements for location of CIS test points in proposed subparagraph (B) to §192.328, as they contended these are more appropriate as construction requirements. These commenters would further revise the CIS location requirements to state that a CIS test station must be within one mile of each HCA, versus within each HCA. They contended that it is not practical to require a test station within each HCA, noting that the length of the pipeline in some HCAs may be very short. Another operator would combine subparagraphs (A) and (B).
Response
CIS is a technique to locate areas of poor cathodic protection and is considered a macro tool. Micro tools, such as DCVG or ACVG, must be used to locate small but critical coating holidays. C-SCAN, which is a current measurement technique, is considered a macro tool and will only find large coating holidays. Small coating holidays can be just as critical as large ones, especially in areas where cathodic protection potentials can be depressed. PHMSA considers it important to monitor coating condition. The comments suggesting that macro tools be allowed appear to be based on the premise that small coating holidays are not important as long as cathodic protection continues to protect the pipeline. As discussed above, PHMSA does not agree with this presumption, and here, again, does not agree that either coating or cathodic protection is required; both are needed. PHMSA recognizes that if one accepts the presumption that assuring coating integrity is not important on pipelines subject to cathodic protection, then prompt resolution of coating issues is not important either. Since PHMSA does not accept the premise, PHMSA has not relaxed the proposed timeframes for conducting surveys or integrating results.

In particular, PHMSA does not agree that a one year interval should be allowed to assess coating adequacy. Experience has demonstrated that significant corrosion can occur during very short intervals. PHMSA notes that the proposed requirement potentially extends the period between the beginning of pipeline operation and coating assessment to 18 months–12 months after operation in which cathodic protection must be made operational (§192.455(a)(2)) plus the six months allowed here. PHMSA considers this to be the maximum period that should be allowed before determining coating adequacy. Proper planning and scheduling should allow operators to accommodate weather and other scheduling concerns. Operators can delay the start of operation at an alternative MAOP if they cannot schedule coating surveys within six months.

PHMSA's conclusion that coating integrity is important, regardless of the presence of cathodic protection, means that determining coating adequacy is important for existing pipelines as well as new construction. As such, it is not appropriate to move this requirement to a section applicable to new construction only. Further, it is not acceptable to rely on ILI or other assessment methods to identify corrosion after it has occurred. The purpose here is to prevent corrosion. ILI or other assessments are a second level of defense, detecting corrosion after it occurs, but PHMSA does not consider them to obviate the need for actions to prevent the problem from occurring in the first place. CIS is a verified method of determining if all of a segment is protected by appropriate cathodic protection potentials. The use of CIS will allow an operator to find any ``hot spots'' along the pipeline that could cause active corrosion. The CIS will find any depressed locations whereas a test station survey may miss such locations unless they are in close proximity to the test station.

With respect to proximity to a test station, PHMSA agrees that there could be situations in which it may not be practical to locate a test station within an HCA. This could occur, for example, when the HCA is determined by an identified site near the outer radius of the potential impact circle, in which case the length of pipeline in the HCA could be very short (on the order of several feet). Still, PHMSA does not agree that this limitation should be addressed by requiring that a test station be within one mile of an HCA. PHMSA has revised the final rule to require that a test station be located within an HCA if practicable and has retained the proposed requirement that test stations be located at half-mile intervals on pipelines to be operated at alternative MAOP.


Section 192.620(d)(8), Controlling External Corrosion Through Cathodic Protection
INGAA, GPTC and eight pipeline operators considered the requirement to address inadequate cathodic protection readings in six months to be excessive. They also noted that seasonal and land use issues make responding within one year much more reasonable, and suggested the proposed rule be changed accordingly. GPTC and one operator noted that the proposed change is inconsistent with an existing PHMSA interpretation, which states that remediation of inadequate cathodic protection readings is required before the next scheduled monitoring. The operator noted that this is typically one year (not to exceed 15 months), supporting the proposed change to a one-year response in this rule.

INGAA and three pipeline operators objected to the proposed requirement to conduct CISs after remediating cathodic protection problems to evaluate effectiveness. They noted that a CIS is not needed to confirm resolution of many problems (e.g., loss of power, cut cable, short). They agreed that operators should confirm that remedial action was appropriate and effective, but contended that a requirement to perform a CIS after any remedial action is unjustified and excessive.


Response
As discussed above, experience has shown that significant corrosion damage can occur over brief periods. Pipelines operating at an alternative MAOP have less margin for corrosion than do pipelines operating at MAOP determined in accordance with §192.111. Cathodic protection is an important protection against corrosion damage, as recognized by those commenting on this rule. PHMSA does not agree that it is acceptable to wait one year to resolve known cathodic protection problems. At the same time, PHMSA recognizes that there may be situations in which remediation in six months is not practical. PHMSA has revised the final rule to require operators to notify the PHMSA Regional Office where a pipeline is located (and states where appropriate) if inadequate cathodic protection readings are not addressed within six months, providing the reason for the delay and a justification that the delay is not detrimental to pipeline safety. This will allow regulators to review the circumstances of each situation in which resolution takes longer than six months and to make a judgment of adequacy based on the particular circumstances.

PHMSA agrees that it is not necessary to perform a complete CIS again to verify that any remedial action has addressed an identified problem. Commenters are correct in noting that problems such as a cut cable or short can result in inadequate cathodic protection readings and that correction of these problems can be verified without a new CIS. PHMSA has revised the final rule to require that operators verify that corrective action is adequate, leaving the means to do so up to the operator's discretion and judgment.


Section 192.620(d)(9), Conducting a Baseline Assessment of Integrity
Proposed §192.620(d)(9)(iii) would require that headers, mainline valve by-passes, compressor station piping, meter station piping, or other short portions that cannot accommodate ILI tools be assessed using DA. INGAA and four pipeline operators objected to this requirement as unjustified and inconsistent with previous special permits. They suggested a change that would also allow pressure testing or development and implementation of a corrosion control plan. They further noted that these segments may be designed to §192.111, may not operate at an alternative MAOP, and thus may not be subject to this section.

One operator also noted that there may be portions of a pipeline facility that will not be operated at an alternative MAOP. The operator requested clarification that the proposed requirements apply only to segments that are intended to operate at an alternative MAOP. This commenter also suggested an exclusion for small pipe and equipment to be consistent with a frequently asked question (FAQ) 84 on the gas transmission integrity management Web site (http://



primis.phmsa.dot.gov/gasimp/). (The FAQ addresses whether small-diameter piping, e.g., within a compressor station, must be considered to be part of an HCA. It states that potential impact radii should be calculated, and a determination made as to whether an HCA exists, based on the diameter of individual pipeline segments.)

The same operator would also allow the baseline assessment for an existing pipeline segment to be conducted before operation at an alternative MAOP begins but within the assessment interval specified in subpart O rather than the proposed two years. The operator contended that there is no scientific basis to require assessments every two years, particularly if a pipeline segment is being managed under subpart O.


Response
PHMSA agrees that assessment of small-diameter station piping can be performed using pressure testing and has revised the final rule accordingly. PHMSA does not agree that it is acceptable for such a non-piggable pipeline to be under an unspecified corrosion control plan rather than to be subject to assessment.

PHMSA agrees that FAQ 84 addresses the same pipe, but does not agree that it is a precedent for determining whether a small-

diameter pipeline requires assessment. An FAQ is advisory in nature and this FAQ provides guidance in the context of integrity management, on whether this pipeline should itself be determined to be an HCA. For this rule, additional assessment requirements are being applied to a pipeline operating at an alternative MAOP, regardless of whether it is in an HCA. PHMSA has revised this paragraph to clarify that it applies only to a pipeline operating at an alternative MAOP. Small-diameter pipe within a station that does not operate at alternative MAOP would not be affected by these requirements. PHMSA agrees that small-diameter pipe, headers, meter stations, compressor stations, river crossings, road crossings and any other pipeline facility can be designed and constructed in accordance with §192.111 criteria and then would not be subject to alternative MAOP integrity assessment criteria such as ILI and DA.

PHMSA does not agree that it is acceptable to rely on assessments that may have been performed within the time intervals allowed by subpart O. Under subpart O, it may have been nearly ten years (in some limited cases 15 years) since a complete assessment was performed. PHMSA considers that more current information is needed before deciding that it is acceptable to operate a pipeline at an alternative MAOP. PHMSA considers the two-year period reasonable for operators to schedule and perform assessments that will result in more current information when the operating stresses on the pipeline are increased.


Section 192.620(d)(11), Making Repairs
INGAA and three pipeline operators noted that the repair requirements in the proposed rule are inconsistent with subpart O and, they believe, overly conservative and burdensome. INGAA contended that the proposed requirements will be unachievable in many cases. Another operator commented that the repair criteria proposed for Class 2 and 3 areas are extremely conservative and unnecessary.

Two pipeline operators suggested that this section be replaced with a reference to subpart O, since they believe the repair requirements of that subpart and ASME/ANSI B31.8S (referenced in subpart O) are appropriate for pipelines operating at 80 percent SMYS.

Two pipeline operators noted that the dent repair criteria in subparagraph (i)(A) are those for new pipelines following construction and before commissioning and suggested that these are inappropriate for existing pipelines. One of these operators contended that the repair criteria for existing pipelines should be as in subpart O, §192.933(d). The other noted that there is experience demonstrating that plain dents of much greater than two percent of pipe diameter in depth are not a threat to pipeline integrity.

Three pipeline operators proposed alternative repair criteria. They would require immediate repair of defects for which the failure pressure is 1.1 times the revised alternative MAOP. They would require repairs within one year for defects for which the failure pressure is 1.25 times the MAOP. They contended that these criteria are consistent with those in subpart O and ASME/ANSI B31.8S and are appropriate. They believe that the criteria in the proposed rule represent an inappropriate shortening of the time allowed to address identified defects.

Proposed subparagraph (i)(A) would require that an operator ``use the most conservative calculation for determining remaining strength'' of a pipeline segment containing an identified anomaly. INGAA and four pipeline operators contended that this requirement could be interpreted to require that multiple calculations be performed, using all available tools/models, to determine which is most conservative. They believe this is inappropriate and that operators should use the most appropriate calculational tool.
Response
PHMSA recognizes that the repair criteria in this rule are more stringent than those in subpart O. PHMSA considers this appropriate. A pipeline that will operate under alternative MAOP is subject to more stress and has less wall thickness margin to failure than most pipelines operating under subpart O (with the exception of some grandfathered lines). Most pipelines that will be subject to this rule will be new pipelines. PHMSA's repair criteria use safety factors similar to those for the design of a new pipeline based upon class location design factors, and are intended to maintain overall safety margins at corrosion anomalies based upon all operating and environmental factors. The net effect of the QA and O&M requirements in this rule for construction and operation of those pipelines covered by the rule will likely result in the need for few repairs, even with these stricter criteria. PHMSA considers these factors of safety a key element in assuring public safety on higher MAOP pipelines.

Similarly, PHMSA disagrees that failure pressures of 1.1 and 1.25 times MAOP are appropriate for immediate and one-year (respectively) repairs for all class locations. Class 2 and Class 3 locations require more stringent safety factors for anomaly evaluation and remediation due to the higher consequences to public safety that may be caused by a leak or rupture of the pipeline. As discussed extensively throughout this response to comments, pipelines to be operated at alternative MAOP will operate at higher pressures with less margin to failure than most pipelines. Use of repair criteria different from and requiring repairs quicker than in subpart O is appropriate.

With respect to dents, the repair criteria of §192.309(b) apply only for dents found during construction baseline assessments (i.e., for new pipelines). PHMSA notes that this section already requires repair of two percent dents for pipelines over 12¾ inches in diameter. The criteria for repairing dents on existing pipelines and subsequent assessments on new pipelines and existing pipelines are in §192.933(d).

PHMSA acknowledges that an operator cannot know which method for calculating remaining strength is most conservative without applying each method. Questions have been raised concerning the applicability of some current methods for calculating the remaining strength of high-strength pipelines and greater depth corrosion anomalies in all field operating conditions. PHMSA is planning to sponsor a public meeting to review these questions and help determine the adequacy of existing calculational methods for the kind of high-strength pipe that will operate at alternative MAOP. PHMSA will propose changes to this rule at a later date, if appropriate.


C.3. Comments on Regulatory Analysis
One pipeline operator submitted two comments relating directly to the regulatory analysis supporting the proposed rule.

First, the operator contends that the expected reduction in expenditure for compressors for new pipelines should not be claimed as a benefit. The operator contended that reductions may be realized for existing pipelines that operate at an alternative MAOP but not for new pipelines.

Second, the operator contended that PHMSA should not state that new design factors will result in increased capacity for new pipelines and noted that new pipelines will be designed for the required capacity. The effect of the proposed rule will be to reduce costs by allowing the use of thinner-walled pipe.

Response


PHMSA understands that the operator's statement that new pipelines will be designed for the required capacity is at the heart of both of these comments. The operator essentially contended that new pipelines that will be so designed will see no increased capacity or change in costs as a result of this rule. PHMSA does not agree. New pipelines designed with alternative MAOPs should mean less cost to the customer/public, and thus a benefit to society, due to less capital costs for the same natural gas through-put/flow volumes. Existing pipelines will be able to carry up to an additional 11 percent natural gas flow volumes based upon the overall design of the pipeline and compressor stations with this alternative MAOP.

In the absence of this rule (or of obtaining a special permit to operate at alternative MAOP) new pipelines would need to be designed for less capacity or at increased cost (due to the need to use thicker-walled pipe). Thus, there is a societal benefit to this rule in that it will allow more gas to be transported at a higher standard of safety for a given dollar investment. The companies designing and constructing new pipelines under this rule will also realize a benefit, since in the absence of this rule (or a special permit addressing the same issues) they would either have to carry less gas or incur additional costs. PHMSA has revised the discussion in the regulatory analysis to help make this point more clearly.


1   2   3   4


Verilənlər bazası müəlliflik hüququ ilə müdafiə olunur ©azrefs.org 2016
rəhbərliyinə müraciət

    Ana səhifə