Source: https://www.federalregister.gov/documents/2011/11/29/2011-29852/pipeline-safety-miscellaneous-changes-to-pipeline-safety-regulations
Timestamp: 2018-03-19 18:56:08
Document Index: 487975016

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A Proposed Rule by the Pipeline and Hazardous Materials Safety Administration on 11/29/2011
Submit comments by February 3, 2012.
73570-73581 (12 pages)
2011-29852
Responsibility To Conduct Construction Inspections—NAPSR-CR-1-02
Leak Surveys for Type B Gathering Lines
III. Qualifying Plastic Pipe Joiners
Mill Hydrostatic Tests for Pipe To Operate at Alternative MAOP
Regulating the Transportation of Ethanol by Pipeline
Limitation of Indirect Costs in State Grants
Offshore Pipeline Condition Reports
Calculating Pressure Reductions for Hazardous Liquid Pipeline Integrity Anomalies
Testing Components Other Than Pipe Installed in Low-Pressure Gas Pipelines
Welders vs. Welding Operators
Components Fabricated by Welding
Odorization of Gas Transmission Lateral Lines
Description of the Reasons That Action by PHMSA Is Being Considered
Description of the Projected Reporting, Recordkeeping, and Other Compliance Requirements of the Proposed Rule, Including an Estimate of the Classes of Small Entities That Will Be Subject to the Rule, and the Type of Professional Skills Necessary for Preparation of the Report or Record
Description of Any Significant Alternatives to the Proposed Rule That Accomplish the Stated Objectives of Applicable Statutes and That Minimize Any Significant Economic Impact of the Proposed Rule on Small Entities, Including Alternatives Considered
https://www.federalregister.gov/d/2011-29852 https://www.federalregister.gov/d/2011-29852
PHMSA is proposing to make miscellaneous changes to the pipeline safety regulations. The proposed changes would correct errors, address inconsistencies, and respond to rulemaking petitions. The requirements in several subject matter areas would be affected, including the performance of post-construction inspections; leak surveys of Type B onshore gas gathering lines; the requirements for qualifying plastic pipe joiners; the regulation of ethanol; the transportation of pipe; the filing of offshore pipeline condition reports; the calculation of pressure reductions for hazardous liquid pipeline anomalies; and the odorization of gas transmission lateral lines.
The proposed changes are addressed on an individual basis and, where appropriate, would be made applicable to the safety standards for both gas and hazardous liquid pipelines. Editorial changes are also included.
Comments should reference Docket No. PHMSA-2010-0026 and may be submitted in the following ways:
Privacy Act Statement: Anyone may search the electronic form of all comments received for any of our dockets. You may review DOT's complete Privacy Act Statement published in the Federal Register on April 11, 2000 (70 FR 19477), or visit http://dms.dot.gov.
John A. Gale, Director of Standards and Rulemaking by telephone at (202) 366-4046 or by Email at john.gale@dot.gov.
PHMSA is proposing to make miscellaneous changes to the pipeline safety regulations. The proposed changes would be relatively minor, would impose minimal (if any) burden, and would clarify the existing regulations. The following issues are addressed below:
○ Responsibility to Conduct Construction Inspections
○ Leak Surveys for Type B Gathering Lines
○ Qualifying Plastic Pipe Joiners
○ Mill Hydrostatic Tests for Pipe to Operate at Alternative MAOP
○ Regulating the Transportation of Ethanol by Pipeline
○ Limitation of Indirect Costs in State Grants
○ Transportation of Pipe
○ Threading Copper Pipe
○ Offshore Pipeline Condition Reports
○ Calculating Pressure Reductions for Hazardous Liquid Pipeline Integrity Anomalies
○ Testing Components other than Pipe Installed in Low-Pressure Gas Pipelines
○ Alternative MAOP Notifications
○ National Pipeline Mapping System
○ Welders vs. Welding Operators
○ Components Fabricated by Welding
○ Odorization of Gas
○ Editorial Amendments
Section 192.305 states that each gas transmission line or main must be inspected to ensure that it is constructed in accordance with the requirements of 49 CFR part 192. These inspections are important because transmission pipelines and mains are generally buried after construction. Subsequent examinations often involve a difficult excavation process.
The National Association of Pipeline Safety Representatives (NAPSR) [1] has suggested that the current regulation should be changed to require a greater degree of independence. Specifically, NAPSR believes that contractors who install a transmission line or main should be prohibited from inspecting their own work for compliance purposes.
PHMSA agrees with NAPSR. Section 192.305 does not prohibit a contractor who installs a transmission line or main from inspecting their own work; that lack of independence raises public safety concerns. PHMSA believes the same concerns apply to non-contractor pipeline personnel as well. Accordingly, PHMSA is proposing to revise § 192.305 to specify that a transmission pipeline or main cannot be inspected by someone who participated in its construction.
Section 195.204 imposes a similar construction inspection requirement for hazardous liquid pipelines. PHMSA has proposed to make the same rule change applicable to § 195.204.
In March 2006 (71 FR 13289), PHMSA established a new method for determining whether a gas pipeline is an “onshore gathering line.” PHMSA also imposed new safety standards for “regulated onshore gathering lines,” which divided regulated onshore gathering lines into two risk-based categories.
Type A gathering lines are metallic lines with a MAOP of 20% or more of specified minimum yield strength (SMYS), as well as nonmetallic lines with an MAOP of more than 125 psig, in a Class 2, 3, or 4 location. These lines are subject to all of the requirements in Part 192 that apply to transmission lines, except for the regulation that requires the accommodation of in-line inspection tools in the design and construction of certain new and replaced pipelines (49 CFR 192.150) and Start Printed Page 73571the integrity management requirements of Part 192, Subpart O. Operators of Type A gathering lines are also permitted to use an alternative process for demonstrating compliance with the requirements of Part 192, Subpart N, Qualification of Pipeline Personnel.
Type B gathering lines includes metallic lines with a MAOP of less than 20% of SMYS, as well as nonmetallic lines with a MAOP of 125 psig or less, in a Class 2 location (as determined under one of three formulas) or in a Class 3 or Class 4 location. These lines are subject to less stringent requirements than Type A gathering lines. Specifically, any new or substantially changed Type B line must comply with the design, installation, construction, and initial testing and inspection requirements for transmission lines and, if of metallic construction, the corrosion control requirements for transmission lines. Operators must also include Type B gathering lines in their damage prevention and public education programs, establish the MAOP of those lines under 49 CFR 192.619, and comply with the requirements for maintaining and installing line markers that apply to transmission lines.
NAPSR notes that the current regulations do not require leak surveys of Type B gathering lines. NAPSR states that gas leaks are the primary hazard from low-stress pipelines, including Type B gathering lines, and that leak detection is a necessary risk-management measure. NAPSR further notes that 49 CFR 192.706 requires leak surveys of transmission lines at intervals not exceeding 15 months, but at least once each calendar year, and more frequently in densely populated areas. NAPSR believes that operators of Type B gathering lines should be subject to the same requirements.
NAPSR notes that operators had to perform leak surveys of non-rural gas gathering lines prior to the March 2006 final rule. NAPSR also states that some Type B gathering lines are located under broad paved areas where electrical surveys (another means of detecting pipe damage) may be difficult to perform and leaking gas could migrate under the pavement and accumulate in surrounding structures. NAPSR believes that leak detection surveys should be required to ensure the safety of these lines.
PHMSA agrees. Leak surveys are an effective means of ensuring the integrity of low-stress pipelines. Accordingly, this proposed rule would require operators of Type B gathering lines to perform leak surveys in accordance with § 192.706.
Section 192.285 contains requirements for qualifying persons to make joints in plastic pipe. Under § 192.285(c), “[a] person must be re-qualified under an applicable procedure, if during any 12-month period that person: (1) Does not make any joints under that procedure; or (2) Has three joints or three percent of the joints made, whichever is greater, under that procedure that are found unacceptable by testing under § 192.513.”
NAPSR (2008-03-AC-1) has two concerns with the current requirements. First, NAPSR states that many operators are required to perform requalification on a less than 12-month period to ensure that joiners are not disqualified. According to NAPSR, this leads to a regressing requalification schedule (i.e., scheduling requalification for a period less than 12 months) and occasionally requires tests at times that are not advantageous from a cost and quality standpoint. NAPSR notes that most of the periodic requirements in 49 CFR part 192 avoid this problem by providing flexibility in the performance interval, such as requiring actions annually not to exceed 15 months. NAPSR suggests that the same flexibility be applied to plastic pipe joiner qualification.
NAPSR's second concern is with the number of unacceptable joints permitted under the current regulation. NAPSR notes that the installation of proper joints is important to ensuring the safety of plastic pipelines, and that allowing a joiner with a demonstrated inability to join pipe to continue to engage in that activity is inconsistent with pipeline safety. NAPSR suggests that the current requirement should be revised to require requalification of a joiner if any production joint is found unacceptable by the required testing.
PHMSA agrees with NAPSR in both respects. Accordingly, the proposed rule would revise § 192.285 to provide greater scheduling flexibility and require requalification of a joiner if any production joint is found unacceptable.
Section 192.112 specifies additional design requirements for new or existing pipeline segments to qualify for the alternative MAOP permitted under 49 CFR 192.620. PHMSA is proposing to revise paragraph (e)(1) of § 192.112 by eliminating the allowance for combining loading stresses imposed by pipe mill hydrostatic testing equipment for the required mill hydrostatic test.
Mill hydrostatic testing is used to ensure that new pipe has adequate strength. Section 192.112 applies to pipe that will operate at the higher stresses allowed under the alternate MAOP. Therefore, it is important that adequate strength be assured. During the 2008 construction season, PHMSA identified a number of cases where new pipe did not meet its specified strength requirements. Eliminating the allowance to combine equipment loading stresses will have the effect of increasing the internal test pressure for mill hydrostatic tests for new pipe to be operated at alternate MAOP. When combined with pipe mill dimensional checks for expansion, that change will help assure that all new pipes for this service receive an adequate mill test and have adequate strength.
On August 10, 2007, (72 FR 45002; Docket number PHMSA-2007-28136) PHMSA published a policy statement and request for comment on the transportation of ethanol, ethanol blends, and other biofuels by pipeline. PHMSA noted in the policy statement that the demand for biofuels was projected to increase in the future as a result of several Federal energy policy initiatives, and that the predominant modes for transporting such commodities (i.e., truck, rail, or barge) would expand over time to include greater use of pipelines. PHMSA also stated that ethanol and other biofuels are substances that “may pose an unreasonable risk to life or property” within the meaning of 49 U.S.C. 60101(a)(4)(B) and accordingly these materials constitute “hazardous liquids for purposes of the pipeline safety laws and regulations. PHMSA went on to say that the agency was considering a possible modification to § 195.2 to include ethanol and biofuels in the definition of hazardous liquid. PHMSA invited comment on that proposal and other issues related to the transportation of biofuels by pipeline.
Nine organizations submitted comments. Two trade associations concerned with hazardous liquid pipeline issues (American Petroleum Institute and Association of Oil Pipelines) submitted joint comments. Two associations dedicated to the use of bio-fuels (National Biodiesel Board and Renewable Fuels Association) submitted separate comments. Two standards developing organizations (American Society of Mechanical Engineers and National Fire Protection Association), one state pipeline safety regulator (Iowa Utilities Board), NAPSR, and one Start Printed Page 73572biofuels producer (Imperium Renewables, Inc.) also submitted comments.
All of the commenters agreed that the transportation of biofuels by pipeline is likely to increase in the future, and that pure ethanol should be classified as a hazardous liquid under the Pipeline Safety Laws (49 U.S.C. 60101 et seq.). However, several commenters stated that a similar classification was not warranted for pure biodiesel, which has chemical properties that are different from ethanol. Most of the comments on the transportation of biodiesel focused on biodiesel-petroleum blends. As explained in the August 2007 policy statement, the transportation of biodiesel-petroleum blends is already subject to the Pipeline Safety Laws and Regulations, because petroleum and petroleum products are both defined as hazardous liquids.
PHMSA is proposing to modify its definition of hazardous liquid to include ethanol. Such a change would make clear that the transportation of pure ethanol by pipeline is subject to the requirements of 49 CFR part 195. Operators are reminded that biodiesel-petroleum and ethanol-petroleum blends are already subject to those regulations. Though PHMSA is not revising its August 10, 2007 policy statement, PHMSA is deferring a final decision on whether the definition of a hazardous liquid in 49 CFR 195.2 should be revised to include pure biodiesel. In its August 2007 policy statement, PHMSA also requested comment on whether research and development would be appropriate to support the transportation of biofuels by pipeline and for efforts to assure appropriate emergency response to pipeline accidents involving biofuels. PHMSA will consider comments in these areas in a separate proceeding.
PHMSA reimburses the states for a portion of the costs accrued in administering their pipeline safety programs, and Congress appropriates the funds used to make these reimbursements on a regular basis. The Pipeline Inspection Protection Enforcement and Safety Act of 2006 (PIPES Act) removed a provision that imposed a 20% cap on indirect expenses allocated to the pipeline safety program grants.
PHMSA believes that the amount of state pipeline safety grants which may be allocated to indirect expenses should be limited. Such a limitation ensures that grant funds are used principally for functions that serve directly to support implementing a pipeline safety oversight program. Accordingly, PHMSA proposes to incorporate the 20% limitation on indirect expenses into the regulations governing grants to state pipeline safety programs.
Section 192.65 states that pipe having a diameter-to-wall-thickness ratio of 70 to 1, or more, must be transported in accordance with the American Petroleum Institute's (API) Recommended Practices 5L1. An exception is provided for certain pipe transported before November 12, 1970. That exception allows operators to use pipe stockpiled prior to the effective date of the original pipeline safety regulations, the transportation of which cannot be verified under API standards.
During its investigation of a July 2002 pipeline incident, the National Transportation Safety Board (NTSB) found that the growth of a fatigue crack, introduced to the pipe due to inadequate loading during transportation, was a causal factor in the pipe failure. NTSB recommended that PHMSA revise its regulations to require that the transportation of all pipe be subject to the referenced API standards.
PHMSA agrees with NTSB's recommendation and proposes to delete the exclusion in § 192.65(a)(2). The amount, if any, of pipe transported prior to November 12, 1970, which remains in operator stockpiles is likely to be very small. Therefore, this change will have minimal impact on pipeline operators.
Section 192.279 specifies when copper pipe may be threaded and refers to Table C1 of American Society of Mechanical Engineers (ASME) ASME/ANSI B16.5. In a letter dated June 11, 2009, the Gas Piping Technology Committee (GPTC) advised PHMSA that Table C1 was deleted in the most recent version of the ASME/ANSI B16.5, which is incorporated into 49 CFR part 192 by reference. GPTC stated that the information in Table C1 was taken from a different ASME standard, ASME B36.10M, “Standard for Welded and Seamless Wrought Steel Pipe,” and that this standard should be substituted as a more appropriate reference. PHMSA agrees with GPTC and is proposing to incorporate the suggested reference to ASME B36.10M in § 192.279.
In a December 1991 final rule (56 FR 637770-637771), PHMSA's predecessor agency, the Research and Special Programs Administration (RSPA), complied with a statutory mandate in Public Law 101-599 (Nov. 16, 1990) by establishing new requirements for pipelines in the Gulf of Mexico (Gulf) and its inlets. Specifically, RSPA promulgated §§ 192.612(a) and 195.413(a), which required each operator to conduct an underwater inspection of all of those lines after October 3, 1989, and before November 16, 1992. RSPA also issued §§ 191.27 and 195.57, which required operators to submit a report to RSPA within 60 days of completing those inspections.
In an August 2004 final rule (69 FR 48400), RSPA amended §§ 192.612(a) and 195.413(a) to require each operator to prepare and follow written procedures for identifying any shallow-water pipelines in the Gulf and its inlets that could be exposed or present a hazard to navigation. RSPA also amended the other provisions in §§ 192.612 and 195.413 to require operators to conduct appropriate periodic inspections of those pipelines, and to take steps to promptly report, mark, and rebury any line found to be exposed or a hazard to navigation. RSPA did not repeal or modify the reporting requirements in §§ 191.27 or 195.57.
Sections 192.612(a) and 195.413(a) no longer require operators to perform an underwater inspection of all pipelines in the Gulf and its inlets. See also Public Law 102-508 (Oct. 24, 1992) (modifying statutory mandate for underwater inspection, reporting, and reburial of pipelines in the Gulf and its inlets). Rather, those regulations only call for periodic, risk-based inspections of shallow-water pipelines. The filing of a written report within 60 days of completing all of those inspections is not consistent with such a regime. Sections 192.612(c) and 195.413(c) also require operators to file a written report with the National Response Center within 24 hours of discovering that a pipeline in those areas is exposed or a hazard to navigation. That reporting requirement is sufficient to meet PHMSA's current information collection needs.
Accordingly, PHMSA is proposing to repeal §§ 191.27 and 195.57.
Section 195.452(h)(4)(i) specifies the actions that an operator of hazardous liquid pipelines must take after discovering an immediate repair condition. One of those actions is a temporary reduction in operating pressure as determined under the formula provided in section 451.6.2.2(b) of ASME/ANSI B31.4. The particular focus of that pressure reduction formula Start Printed Page 73573is corrosion. However, corrosion is only one of the threats that could cause an immediate repair condition under § 195.452(h)(i).
PHMSA sought to modify § 195.452(h)(4)(i) in a July 17, 2007, final rule (72 FR 39017) to provide for alternative methods of calculating a pressure reduction for immediate repair conditions caused by threats other than corrosion. The Office of the Federal Register was unable to incorporate that change due to inaccurate amendatory instructions. PHMSA is again revising § 195.452(h)(4)(i) as part of this rule to make the same change as published in the July 17, 2007, final rule with corrected amendatory instructions.
Section 192.505 specifies strength test requirements for steel pipe to operate at a hoop stress of 30 percent or more of SMYS. Paragraph (d) of § 192.505 provides an exception if a component other than pipe is the only item being replaced or added. It states that a post-installation strength test is not required if the manufacturer certifies that the component was tested to at least the pressure required for the pipeline to which it is being added, manufactured under a quality control system that assures adequate strength, or carries a pressure rating established through applicable ASME/ANSI, MSS specifications or by unit strength calculations. A similar exception is not provided if a component other than pipe is the only item being replaced or added to steel pipeline systems that operate at less than 30 percent of SMYS (§§ 192.507 and 192.509), service lines (§ 192.511), or plastic pipelines (CFR 192.513).
In a letter dated March 25, 2010, GPTC petitioned PHMSA to create such an exception by repealing paragraph (d) of § 192.505 and adding that provision to § 192.503, which imposes general requirements applicable to testing all gas pipelines. GPTC argued that the primary purpose of a post-installation strength test is to prove the integrity of the entire pipeline system. GPTC further noted that the most important parts of a single-component replacement to be checked are the joints that connect the component to the pipeline, and that these joints are currently exempted from testing for all gas pipelines by paragraph (d) of § 192.503. These joints are also required to be leak tested at operating pressure, a requirement that would not be changed by GPTC's petition.
If a component other than pipe is the only item being replaced or added to a low-stress steel line, a service line, or a plastic pipeline and the manufacturer of the component provides the certification required under § 192.505(d), PHMSA agrees that a strength test after installation is not necessary to ensure public safety. Such testing must necessarily be performed prior to installation and not as part of a test of the overall pipeline system. PHMSA proposes to grant the GPTC petition as part of this rulemaking by deleting paragraph (d) of § 192.505 and adding that provision as a new paragraph (e) to § 192.503.
Section 192.620(c)(1) requires an operator to notify PHMSA, and in some instances the appropriate State authority, upon electing to establish a higher alternative MAOP. Such notification must be provided at least 180 days prior to commencing operations at the alternative MAOP. The 180-day allowance provides PHMSA and state regulators with sufficient time to conduct any needed inspections, including checks of the manufacturing process, visits to the pipeline construction sites, analysis of operating history of existing pipelines, and review of test records, plans, and procedures.
Operators are expected to provide PHMSA's regional offices with notice of planned alternative MAOP design and operations as early as practical, and prior to the start of pipe manufacturing and/or construction activities. Such notification avoids unnecessary delays in PHMSA's review of applicable procedures, specifications, manufacturing of pipe and external coating, field construction activities, operations & maintenance plans, and all other required documentation.
Consistent with that practice, PHMSA is proposing to revise § 192.620 to require that operators notify PHMSA field offices 180 days prior to pipe manufacturing and/or construction activities. PHMSA is also proposing to revise § 192.620(c)(8) to correct a typographical error related to the reference to § 192.611(a).
The National Pipeline Mapping System (NPMS) is a geospatial dataset that contains information about PHMSA-regulated gas transmission pipelines, hazardous liquid pipelines, and hazardous liquid low-stress gathering lines. The NPMS also contains data layers for all liquefied natural gas plants and a partial dataset of PHMSA-regulated breakout tanks.
The NPMS project began in 1998 and data submission became mandatory as a result of the Pipeline Safety Improvement Act of 2002. Operators are currently required to make a submission to the NPMS once every 12 months, or to notify NPMS staff if there were no changes during that time. An NPMS submission consists of geospatial data, attribute data and metadata, public contact information, and a transmittal letter. These requirements and acceptable formats are explained in full in the NPMS Operator Standards Manual (http://www.npms.phmsa.dot.gov/​Documents/​Operator_​Standards.pdf).
PHMSA is seeking to improve its ability to compare Annual Report statistics with NPMS data. This will aid PHMSA in accurately portraying our nation's pipeline transportation network, allocating its resources, achieving the goal of becoming a data-driven organization, and conducting operator compliance efforts. The ability to accurately identify and track operators' physical assets is beneficial to PHMSA, pipeline operators, and all stakeholders who utilize such data, and ultimately helps promote pipeline safety.
Section 60132 of the Pipeline Safety Laws requires pipeline operators to make a submission to the NPMS once every 12 months, or to notify the NPMS if there were no changes from the previous submission. To ensure that all operators are complying with this requirement, PHMSA proposes to add an NPMS submission requirement to the Code of Federal Regulations.
In an Advisory Bulletin issued on July 31, 2008, PHMSA requested that operators submit their NPMS data concurrently with hazardous liquid and gas transmission annual report submissions. Annual reports are due on March 15 each year for gas transmission operators and on June 15 for LNG plant operators. Annual reports represent assets as of December 31 of the previous year. In an advisory bulletin issued on May 17, 2011, PHMSA temporarily extended those timelines for the 2010 calendar year for the owners and operators of gas transmission and gathering lines, hazardous liquid lines, and LNG facilities to account for recent revisions to the agency's reporting forms.
Toward these ends, PHMSA proposes to:
1. Require operators to follow the submission rules and dates set forth in the July 31, 2008, Advisory Bulletin. Gas transmission operators and LNG plant operators will make their NPMS submissions on or before March 15, representing assets as of December 31 of the previous year. Hazardous liquid operators will make their NPMS Start Printed Page 73574submissions on or before June 15, representing assets as of December 31, of the previous year. To expedite processing, PHMSA urges operators to submit their NPMS data as early in the year as possible. A rulemaking published on November 26, 2010, requires operators to use the same Operator ID number (OPID) for the same asset for all PHMSA reporting requirements. Therefore, an OPID used in an annual report submission must match the same asset described in an NPMS submission.
2. Codify the statutory requirement for submission of NPMS data in 49 CFR parts 192, 193, and 195. An NPMS submission consists of geospatial data, attribute data and metadata, public contact information, and a transmittal letter.
For information about acceptable submission formats and the components of each element, refer to the latest edition of the NPMS Operator Standards Manual. Incomplete submissions, or submissions in unacceptable formats, will be deemed noncompliant with this regulation.
The use of mechanized and automatic welding has become more common in pipeline construction, and the operators of such equipment must be qualified to ensure their work meets pipeline safety standards. The requirements for welders and welding operations are prescribed in subpart D, Construction, of 49 CFR parts 192 and 195. Welding operators of mechanized and automatic welding equipment have never been specifically addressed in those regulations.
The ASME Boiler and Pressure Vessel Code (BPVC) Section IX defines a welder as “[o]ne who performs manual or semi-automatic welding.” and a welding operator as “[o]ne who operates machine or automatic welding equipment.” Moreover, both the ASME BPVC Section IX and API 1104 have specific processes for the qualification of welding operators and automatic welding equipment. PHMSA's expectations of qualified personnel are consistent with the requirements in these two standards.
PHMSA is proposing to add a reference to these requirements in the applicable sections of subpart D in 49 CFR parts 192 and 195 to clarify the qualification standards for welding operators. This change will not affect the current industry practice; rather, it addresses the distinction between welders and welding operators and the specific qualification requirements under the current standards incorporated by reference in 49 CFR parts 192 and 195. Those standards are designed to ensure that qualified personnel are used for welding processes whether they are performed by welders or welding operators.
Pressure vessels can be found in meter stations, compressor stations, and other pipeline facilities to facilitate the removal of liquids and other materials from the gas stream. These vessels are designed, fabricated, and tested in accordance with the requirements of ASME BPVC Section VIII, as required by § 192.153 and § 192.165(b)(3), and the additional test requirements of § 192.505(b).
However, the pressure test requirements in ASME BPVC Section VIII were lowered from a test factor of 1.5 to 1.3 by an earlier edition of the ASME BPVC than the edition which is currently incorporated by reference. This revision created a difference in pressure testing requirements of the ASME BPVC from the test requirements of § 192.505(b), which requires a test factor of 1.5 times MAOP for meter and compressor stations, as well as any other Class 3 location. PHMSA has not reduced the testing requirements of these vessels and they must be tested to at least the pressure required for the pipeline to which they are being added.
Because the standard ASME pressure vessel test in ASME BPVC Section VIII is 1.3 times MAOP, an operator must specify the correct test pressure when placing an order for an ASME vessel to ensure it is designed and tested to the requirements of 49 CFR part 192. Unless a vessel is special ordered with a test pressure of 1.5 times MAOP prescribed by the purchaser, the vessel will be tested in accordance with the standard test factor of 1.3. If the vessel is not tested to 1.5 times MAOP, it cannot be used in a compressor or meter station, or other Class 3 location. The failure to meet this requirement can potentially lead to exceeding the design parameters of the vessel during subsequent testing of the pipeline system.
A clarification is being added to § 192.153 as a new paragraph (e) to clearly specify the design and test requirements for pressure vessels in meter stations, compressor stations, and other locations that are tested to Class 3 requirements. All ASME pressure vessels subject to § 192.153 and § 192.165(b)(3) must be designed and tested at a pressure that is 1.5 times MAOP, in lieu of the standard ASME BPVC Section VIII test pressure of 1.3 times MAOP. Additionally, § 192.165(b)(3) is being revised to refer the reader to this requirement.
This is not a change to the pressure testing requirements, as the requirements found in part 192 have not changed. This clarification is made to ensure a clear understanding of PHMSA's pressure testing requirements for certain ASME BPVC vessels in compressor and meter stations, and other Class 3 locations.
Section 192.625 contains requirements for operators to odorize combustible gas in a transmission line in Class 3 or Class 4 locations, “so that at a concentration in air of one-fifth of the lower explosive limit, the gas is readily detectable by a person with a normal sense of smell.” Certain exceptions are recognized by regulation, including for a lateral line “which transports gas to a distribution center, [if] at least 50 percent of the length of that line is in a Class 1 or Class 2 location.”
Section 192.625 does not specify a clear method for calculating the length of a lateral line, and that has led to inconsistency in applying the odorization requirement. To address that concern, PHMSA proposes to amend § 192.625(b)(3) to state that the length of a lateral line for purposes of calculating whether at least 50 percent is in a Class 1 or Class 2 location is measured between the distribution center and the first upstream connection to the transmission line.
(1) In § 195.571, to revise the reference to NACE Standard on Cathodic Protection as Incorporated by Reference in § 195.3.
(2) In § 195.3B(9), to amend ANSI/API Recommended Practice 651 to show the correct source and reference material as §§ 195.565 and 195.573(d).
(3) In § 195.2, to amend the definition of “Alarm” to correct an error in the codification of the new control room management regulations (74 FR 63310).
(4) In §§ 192.925(b) and (b)(2), to replace “indirect examination” with “indirect inspection” to maintain consistency with § 192.925(a) and the applicable NACE standard.
(5) In § 195.428(c), to replace “§ 5.1.2” with “§ 7.1.2” to correctly reference the overfill protection requirements for aboveground breakout tanks in the 2010 edition of API Standard 2510, which is now incorporated by reference (see § 195.3).Start Printed Page 73575
Executive Orders 12866 and 13563 require agencies to regulate in the “most cost-effective manner,” to make a “reasoned determination that the benefits of the intended regulation justify its costs,” and to develop regulations that “impose the least burden on society.” In this notice, PHMSA is proposing to amend miscellaneous provisions to clarify and eliminate unduly burdensome requirements. PHMSA is also responding to requests from industry and State pipeline safety representatives to revise its regulations. PHMSA anticipates the proposals contained in this rule will have economic benefits to the regulated community by increasing the clarity of its regulations and reducing compliance costs.
Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.), PHMSA must consider whether rulemaking actions would have a significant economic impact on a substantial number of small entities. PHMSA is proposing to make miscellaneous changes to the pipeline safety regulations.
PHMSA, pipeline operators, and others have identified certain errors, inconsistencies, and deficiencies in the Pipeline Safety Regulations concerning the following subjects: (1) Performance of post-construction inspections; (2) leak surveys of Type B onshore gas gathering lines; (3) the requirements for qualifying plastic pipe joiners; (4) the transportation of ethanol by pipeline; (5) the transportation of pipe; (6) the filing of offshore pipeline condition reports; (7) the calculation of pressure reductions for hazardous pipeline anomalies; and (8) the odorization of gas transmission lateral lines. PHMSA wishes to address these issues.
Under the pipeline safety laws, 49 U.S.C. 60101 et seq., the Secretary of Transportation must prescribe minimum safety standards for pipeline transportation and for pipeline facilities. The Secretary has delegated this authority to the PHMSA Administrator. 49 CFR 1.53(a). The proposed rule would effect changes in the regulations consistent with the protection of persons and property, while changing unduly burdensome or nonsensical requirements.
In general, the proposed rule will apply to pipeline operators, some of which may qualify as a small business as defined in Section 601(3) of the Regulatory Flexibility Act. Some pipelines are operated by jurisdictions with a population of less than 50,000 people, and thus qualifying as small governmental jurisdictions.
Some portions of the rule apply to manufacturers of pipeline components, as well as the contractors constructing or repairing a pipeline. Many of these concerns may qualify as a small business concern.
The proposed rule does not directly impose any reporting or recordkeeping requirement. But the rule does create an obligation to perform leak surveys of Type B gathering lines. This sort of survey is currently required of transmission lines. This requirement is expected to apply only to small business entities, and not small governmental entities, because small jurisdictions typically operate distribution or transmission systems, to which the requirement will not apply. Professional inspectors will be needed to comply with this requirement, but the time required for compliance will vary greatly with each system.
The remainder of the proposed rule does not impose any compliance, recordkeeping, or reporting requirement; it does, however, affect the timing and substance of the reports that must be created and maintained under existing regulations. The rule proposes that operators notify PHMSA field offices 180 days prior to pipe manufacturing or construction activities. Currently existing regulations require operators to notify PHMSA 180 days in advance of operating a pipeline at a higher alternative MAOP. Because operators must currently provide PHMSA with notice of alternative design as early as practical, and prior to pipe manufacturing or construction activities, the proposed rule does not impose any additional reporting requirement.
Additionally, the proposed rule changes the reporting requirement for submissions to the National Pipeline Mapping System (NPMS). Submissions to the NPMS are mandatory as a result of the Pipeline Safety Improvement Act of 2002. At present, NPMS submissions are due every 12 months; the proposed rule would require establish due dates for NPMS submissions that coincide with the due dates for annual reports.
PHMSA is unaware of any duplicative, overlapping, or conflicting federal rules. As noted below, PHMSA seeks comments and information about any such rules.
PHMSA is unaware of any alternatives which would produce smaller economic impacts on small entities while at the same time meeting the objectives of the relevant statutes. Several provisions of the proposed rule are specifically designed to eliminate confusion and potentially lower costs for regulated entities. For example, the proposed addition of 49 CFR 192.153(e) is designed to prevent regulated entities from purchasing pressure vessels that do not comply with § 192.505(b), but that do comply with ASME Boiler and Pressure Vessel Code Section VII, as required by § 192.165(b)(3). PHMSA seeks comments about lower-cost alternatives which would meet the stated objectives.
Questions for Comment to Assist Regulatory Flexibility analysis:
1. Please provide any data concerning the number of small entities which may be affected.
2. Please provide comment on any or all of the provisions in the proposed rule with regard to (a) the impact of the provisions, if any, and (b) any alternatives PHMSA should consider, paying specific attention to the effect of the rule on small entities.Start Printed Page 73576
3. Please describe ways in which the rule could be modified to reduce any costs or burdens for small entities.
4. Please identify all relevant Federal, state, local, or industry rules or policies that may duplicate, overlap, or conflict with the proposed rule and have not already been incorporated by reference.
PHMSA has analyzed this proposed rule according to the principles and criteria in Executive Order 13175, “Consultation and Coordination with Indian Tribal Governments.” Because this proposed rule does not significantly or uniquely affect the communities of the Indian tribal governments or impose substantial direct compliance costs, the funding and consultation requirements of Executive Order 13175 do not apply.
This proposed rule imposes no new requirements for recordkeeping and reporting.
This proposed rule does not impose unfunded mandates under the Unfunded Mandates Reform Act of 1995. It would not result in costs of $100 million, adjusted for inflation, or more in any one year to either State, local, or tribal governments, in the aggregate, or to the private sector, and is the least burdensome alternative that achieves the objective of the proposed rule.
The National Environmental Policy Act (42 U.S.C. 4321-4375) requires that Federal agencies analyze proposed actions to determine whether those actions will have a significant impact on the human environment. The Council on Environmental Quality regulations requires Federal agencies to conduct an environmental review considering (1) The need for the proposed action, (2) alternatives to the proposed action, (3) probable environmental impacts of the proposed action and alternatives, and (4) the agencies and persons consulted during the consideration process. 40 CFR 1508.9(b).
PHMSA is proposing to make non-substantive amendments and editorial changes to the pipeline safety regulations. That includes modifying the requirements for the performance of post-construction inspections; the conduct of leak surveys of Type B onshore gas gathering lines; the requirements for qualifying plastic pipe joiners; the regulation of ethanol; the transportation of pipe; the filing of offshore pipeline condition reports; the calculation of pressure reductions for hazardous liquid pipeline anomalies; and the odorization of gas transmission lateral lines.
(1) No action or
(2) Propose revisions to the pipeline safety regulations to incorporate the amendments previously and minor editorial changes.
Alternative 1: PHMSA has an obligation to ensure the safe and effective transportation of hazardous liquids and gases by pipeline. The changes proposed in this NPRM serve that purpose by clarifying the pipeline safety regulations and eliminating unduly burdensome requirements. A failure to undertake these actions would allow for the continued imposition of unnecessary compliance costs without increasing public safety. Accordingly, PHMSA rejected the no action alternative.
Alternative 2: PHMSA is proposing to make certain amendments, corrections and editorial changes to the pipeline safety regulations. These revisions would eliminate inconsistencies and respond to several petitions for rulemaking and recommendations from our stakeholders, thereby facilitating the safe and effective transportation of hazardous liquids and gases by pipeline. The changes proposed in this NPRM serve that purpose by clarifying the pipeline safety regulations and eliminating unduly burdensome requirements.
The Nation's pipelines are located throughout the United States in a variety of diverse environments; from offshore locations, to highly populated urban sites, to unpopulated rural areas. The pipeline infrastructure is a network of over 2.5 million miles of pipeline that move millions of gallons of hazardous liquids and over 55 billion cubic feet of natural gas daily. The biggest source of energy is petroleum, including oil and natural gas. Together, these commodities supply 65 percent of the energy in the United States.
The physical environment potentially affected by the proposed rule includes the airspace, water resources (e.g., oceans, streams, lakes), cultural and historical resources (e.g., properties listed on the National Register of Historic Places), biological and ecological resources (e.g., coastal zones, wetlands, plant and animal species and their habitat, forests, grasslands, offshore marine ecosystems), and special ecological resources (e.g., threatened and endangered plant and animal species and their habitat, national and State parklands, biological reserves, wild and scenic rivers) that exist directly adjacent to and within the vicinity of pipelines.
Because the pipelines subject to the proposed rule contain hazardous materials, resources within the physically affected environment, as well as public health and safety, may be affected by gas pipeline incidents such as spills and leaks. Incidents on pipelines can result in fires and explosions, resulting in damage to the local environment. In addition, since pipelines often contain gas streams laden with condensates and natural gas liquids, failures also result in spills of these liquids, which can cause environmental harm. Depending on the size of a spill or gas leak, and the nature of the impact zone, the environmental impacts could vary from property damage and environmental damage to injuries or, on rare occasions, fatalities.
The proposed amendments are not substantive in nature and would have little or no impact on the human environment. Thus it is possible that, on a national scale, the cumulative environmental damage from pipelines is reduced, or at a minimum unchanged.
Various industry associations and State regulatory agencies were consulted in the development of this proposed rulemaking.
PHMSA has preliminarily determined that the selected alternative would not have a significant impact on the human environment and welcomes comment on any of these conclusions.
PHMSA has analyzed this proposed rule according to Executive Order 13132 (“Federalism”). The proposed rule does not have a substantial direct effect on the states, the relationship between the national government and the states, or the distribution of power and responsibilities among the various levels of government. This proposed rule does not impose substantial direct compliance costs on state and local governments. This proposed rule does Start Printed Page 73577not preempt state law for intrastate pipelines. Therefore, the consultation and funding requirements of Executive Order 13132 do not apply.
Authority: 49 U.S.C. 5121, 60102, 60103, 60104, 60108, 60117, 60118, and 60124, and 49 CFR 1.53.
2. In § 191.7, paragraph (a) is revised and paragraph (e) is added to read as follows:
(a) General. Except as provided in paragraphs (b) and (e) of this section, an operator must submit each report required by this part electronically to the Pipeline and Hazardous Materials Safety Administration at http://opsweb.phmsa.dot.gov unless an alternative reporting method is authorized in accordance with paragraph (d) of this section.
(e) Exceptions. An operator must provide the National Pipeline Mapping System data to the address identified in the NPMS Operator Standards manual available at www.npms.phmsa.dot.gov or by contacting the PHMSA Geospatial Information Systems Manager at (202) 366-4595.
3. Section 191.27 is removed.
4. Section 191.29 is added to read as follows:
(a) (1) Each operator of a gas transmission pipeline or liquefied natural gas facility must provide the following geospatial data to PHMSA for that pipeline or facility:
(i) Geospatial data, attributes, metadata, and transmittal letter appropriate for use in the National Pipeline Mapping System. Acceptable formats and additional information are specified in the NPMS Operator Standards Manual available at www.npms.phmsa.dot.gov or by contacting the PHMSA Geographic Information Systems Manager at (202) 366-4595.
(ii) The name and address for the operator.
(iii) The name and contact information of a pipeline company employee who will serve as a contact for questions from the general public about the operator's NPMS data, which is displayed on a public Web site.
(2) This information must be submitted each year, not later than March 15, representing assets as of December 31 of the previous year. If no changes have occurred since the previous year's submission, comply with the guidance provided in the NPMS Operator Standards manual available at www.npms.phmsa.dot.gov or contact the PHMSA Geospatial Information Systems Manager at (202) 366-4595.
5. The authority citation for part 192 continues to read as follows:
6. In § 192.3, definitions for “Welder” and “Welding Operator” are added in appropriate alphabetical order to read as follows:
7. In § 192.7 paragraph (c)(2) amend the Table of referenced material by redesignating items D.(6) through D.(9) as D.(7) and D.(10) and adding a new D.(6) to read as follows:
Source and name of referenced material 49 CFR reference
(6) ASME/ANSI B36.10M, “Standard for Welded and Seamless Wrought Steel Pipe” § 192.279
(7) Conduct leakage surveys in accordance with § 192.706 using leak detection equipment and fix hazardous leaks that are discovered in accordance with § 192.703(c).
9. In § 192.65, paragraph (a) is revised to read as follows.
(a) Railroad. In a pipeline to be operated at a hoop stress of 20 percent or more of SMYS, an operator may not use pipe having an outer diameter to wall thickness of 70 to 1, or more, that is transported by railroad unless the transportation is performed in accordance with API RP 5LI.
(e) Mill hydrostatic test (1) All pipe to be used in a new pipeline segment must be hydrostatically tested at the mill at a test pressure corresponding to a hoop stress of 95 percent SMYS for 10 seconds. (2) Pipe in operation prior to December 22, must have been hydrostatically tested at the mill at a test pressure corresponding to a hoop stress of 90 percent SMYS for 10 seconds. (3) Pipe in operation on or after November 17, 2008, but before [INSERT DATE OF FINAL RULE], must have been hydrostatically tested at the mill at a test pressure corresponding to a hoop stress of 95 percent SMYS for 10 seconds. The test pressure may include a combination of internal test pressure and the allowance for end loading stresses imposed by the pipe mill hydrostatic testing equipment as allowed by API Specification 5L, Appendix K (incorporated by reference, see § 192.7).
(e) A component having a design pressures established in accordance with paragraph (a) or paragraph (b) of this section and subject to the strength testing requirements of § 192.505(b) must be tested to at least 1.5 times the maximum allowable operating pressure.
(3) Be manufactured in accordance with section VIII of the ASME Boiler and Pressure Vessel Code (incorporated by reference, see § 192.7) and the additional requirements of § 192.153(e), except that liquid separators constructed of pipe and fittings without internal welding must be fabricated with a design factor of 0.4, or less.
(a) Welding must be performed by a qualified welder or welding operator in accordance with welding procedures qualified in accordance with API 1104 (incorporated by reference, see § 192.7) or section IX of the ASME Boiler and Pressure Vessel Code “Welding and Brazing Qualifications” (incorporated by reference, see § 192.7) to produce welds which meet the requirements of this subpart. The quality of the test welds used to qualify welding procedures must be determined by destructive testing in accordance with the referenced welding standard(s).
(a) Except as provided in paragraph (b) of this section, each welder or welding operator must be qualified in accordance with section 6, 12, or 13 of API 1104 (incorporated by reference, see § 192.7) or section IX of the ASME Boiler and Pressure Vessel Code (incorporated by reference, see § 192.7). However, a welder or welding operator qualified under an earlier edition than the edition listed in § 192.7 of this part may weld but may not re-qualify under that earlier edition.
(b) A welder or welding operator may qualify to perform welding on pipe to be operated at a pressure that produces a hoop stress of less than 20 percent of SMYS by performing an acceptable test weld, for the process to be used, under the test set forth in section I of Appendix C of this part. Each welder or welding operator who is to make a welded service line connection to a main must first perform an acceptable test weld under section II of Appendix C of this part as a requirement of the qualifying test.
(b) A welder or welding operator may not weld with a particular welding process unless, within the preceding 6 calendar months, the welder or welding operator has engaged in welding with that process.
(1) May not weld on pipe to be operated at a pressure that produces a hoop stress of 20 percent or more of SMYS unless within the preceding 6 calendar months the welder or welding operator has had one weld tested and found acceptable under section 6 or section 9 of API Standard 1104 (incorporated by reference, see § 192.7). Alternatively, a welder or welding operator may maintain an ongoing qualification status by performing welds tested and found acceptable under the above acceptance criteria at least twice each calendar year, but at intervals not exceeding 71/2 months. A welder or welding operator qualified under an earlier edition of a standard than the edition listed in § 192.7 of this part may weld but may not re-qualify under that earlier edition; and
(ii) Two sample welds tested and found acceptable in accordance with the test in section III of Appendix C of this part or a welder or welding operator who works only on service lines 2 inches (51 millimeters) or smaller in diameter.
(c) The acceptability of a weld that is nondestructively tested or visually Start Printed Page 73579inspected is determined according to the standards in Section 9 or Appendix A of API Standard 1104, as applicable (incorporated by reference, see § 192.7).
(e) Except for a welder or welding operator whose work is isolated from the principal welding activity, a sample of each welder's or welding operator's work for each day must be nondestructively tested, when nondestructive testing is required under § 192.241(b).
18. Section 192.279 is revised to read as follows:
§ 192.279
Copper pipe may not be threaded except that copper pipe used for joining screw fittings or valves may be threaded if the wall thickness is equivalent to the comparable size of Schedule 40 or heavier wall pipe as listed in Table 1 of ASME B36.10M, Standard for Welded and Seamless Wrought Steel Pipe (incorporated by reference, see § 192.7).
19. In § 192.285, paragraph (c) is revised to read as follows:
(c) A person must be re-qualified under an applicable procedure if:
(1) During any calendar year (not exceeding 15 months) that person does not make any joints under that procedure; or
(2) Any production joint is found unacceptable by testing under § 192.513.
20. Section 192.305 is revised to read as follows:
Each transmission line and main must be inspected to ensure that it is constructed in accordance with this subpart. An inspection may not be performed by a person who participated in the construction of that transmission line or main.
21. In Section 192.503, add new paragraph (e) to read as follows:
(e) If a component other than pipe is the only item being replaced or added to a pipeline, a strength test after installation is not required, if the manufacturer of the component certifies all of the below requirements and the operator maintains these certifications for the in service life of the component:
22. In Section 192.505, paragraph (d) is removed and paragraph (e) is re-designated as paragraph (d).
23. In § 192.620, paragraph (c)(1) and the first sentence of paragraph (c)(8) are revised to read as follows:
(1) For pipelines already in service, notify the PHMSA pipeline safety regional office where the pipeline is in service of the intention to use the alternative pressure at least 180 days before operating at the alternative maximum allowable operating pressure. For new pipelines, notify the PHMSA pipeline safety regional office 180 days prior to start of pipe manufacturing and/or construction activities. 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.
24. In § 192.625, paragraph (b)(3) is revised to read as follows:
(3) In the case of a lateral line which transports gas to a distribution center, at least 50 percent of the length of that line is in a Class 1 or Class 2 location as measured between the distribution center and the first upstream connection to the transmission line;
25. In § 192.925, the introductory text of paragraph (b) and the introductory text of (b)(2) are revised to read as follows:
(b) General requirements. An operator that uses direct assessment to assess the threat of external corrosion must follow the requirements in this section, in ASME/ANSI B31.8S (incorporated by reference, see § 192.7), section 6.4, and in NACE SP0502-2008 (incorporated by reference, see § 192.7). An operator must develop and implement a direct assessment plan that has procedures addressing pre-assessment, indirect inspection, direct examination, and post assessment. If the ECDA detects pipeline coating damage, the operator must also integrate the data from the ECDA with other information from the data integration (§ 192.917(b)) to evaluate the covered segment for the threat of third party damage and to address the threat as required by § 192.917(e)(1).
(2) Indirect inspection. In addition to the requirements in ASME/ANSI B31.8S section 6.4 and NACE SP0502-2008, section 4, the plan's procedures for indirect inspection of the ECDA regions must include—
26. The authority citation for Part 195 continues to read as follows:
27. In § 195.2, the definitions of “alarm”, and “hazardous liquid” are revised and definitions for “welder” and “welder operator” are added in appropriate alphabetical order to read as follows:
28. In § 195.3(c), paragraph entry B (9) is revised to read:
Start Printed Page 73580
(9) ANSI/API Recommended Practice 651, “Cathodic Protection of Aboveground Petroleum Storage Tanks” (3rd edition, January 2007) §§ 195.565, 195.573(d).
30. In § 195.58, paragraph (a) is revised and a new paragraph (e) is added to read as follows:
(1) Geospatial data, attributes, metadata and transmittal letter appropriate for use in the National Pipeline Mapping System. Acceptable formats and additional information are specified in the NPMS Operator Standards manual available at www.npms.phmsa.dot.gov or by contacting the PHMSA Geospatial Information Systems Manager at (202) 366-4595.
(2) The name and address for the operator.
(3) The name and contact information of a pipeline company employee who will serve as a contact for questions from the general public about the operator's NPMS data, which is displayed on a public Web site.
(b) This information must be submitted each year, not later than June 15, representing assets as of December 31 of the previous year. If no changes have occurred since the previous year's submission, see the information provided in the NPMS Operator Standards manual available at www.npms.phmsa.dot.gov or by contacting the PHMSA Geospatial Information Systems Manager at (202) 366-4595.
32. Section 195.204 is revised to read as follows:
Inspection must be provided to ensure the installation of pipe or pipeline systems in accordance with the requirements of this subpart. No person may be used to perform inspections unless that person has been trained and is qualified in the phase of construction to be inspected. An inspection may not be performed by a person who participated in the installation of the pipe or pipeline systems.
33. In § 195.214, paragraph (a) is revised to read as follows:
(a) Welding must be performed by a qualified welder or welding operator in accordance with welding procedures qualified in accordance with API 1104 (incorporated by reference, see § 192.7) or section IX of the ASME Boiler and Pressure Vessel Code “Welding and Brazing Qualifications” (incorporated by reference, see § 192.7) to produce welds meeting the requirements of this subpart. The quality of the test welds used to qualify welding procedures must be determined by destructive testing in accordance with the referenced welding standard(s).
34. In § 195.222 the heading, paragraph (a), the introductory text of (b), and paragraph (b)(2) are revised to read as follows:
Welding: Qualification of welders and welding operators.
(a) Each welder or welding operator must be qualified in accordance with sections 6, 12, or 13 of API 1104 (incorporated by reference, see § 195.3) or section IX of the ASME Boiler and Pressure Vessel Code, (incorporated by reference, see § 195.3) except that a welder or welding operator qualified under an earlier edition than an edition listed in § 195.3 may weld but may not re-qualify under that earlier edition.
(2) Had one welded tested and found acceptable under section 9 or Appendix A of API 1104 (incorporated by reference, see § 195.3).
35. In § 195.228, paragraph (b) is revised to read as follows:
(b) The acceptability of a weld is determined according to the standards in section 9 or Appendix A of API 1104 (incorporated by reference, see § 195.3).
36. In § 195.234, paragraph (d) is revised to read as follows:
37. In § 195.307 paragraphs (c) and (d) are revised to read as follows:
(c) For aboveground breakout tanks built to API Standard 650 (incorporated by reference, see § 195.3) and first placed in service after October 2, 2000, testing must be in accordance with Section 5.3.5 of API Standard 650 (incorporated by reference, see § 195.3).
(d) For aboveground atmospheric pressure breakout tanks constructed of carbon and low alloy steel, welded or riveted, and non-refrigerated and tanks built to API Standard 650 or its predecessor Standard 12 C that are returned to service after October 2, 2000, the necessity for the hydrostatic testing of repair, alteration, and reconstruction is covered in Section 12.3 of API Standard 653 (incorporated by reference, see § 195.3).
38. In § 195.428, paragraph (c) is revised to read as follows:
(c) Aboveground breakout tanks that are constructed or significantly altered according to API Standard 2510 after October 2, 2000, must have an overfill protection system installed according to section 7.1.2 of API Standard 2510. Other aboveground breakout tanks with 600 gallons (2271 liters) or more of storage capacity that are constructed or significantly altered after October 2, 2000, must have an overfill protection system installed according to API Recommended Practice 2350 (incorporated by reference, see § 195.3). However, an operator need not comply with any part of API Recommended Practice 2350 for a particular breakout tank if the operator describes in the manual required by § 195.402 why compliance with that part is not necessary for safety of the tank.
39. In § 195.452, paragraph (h)(4)(i) introductory text is revised to read as follows:
(4) * * * (i) Immediate repair conditions. An operator's evaluation and remediation schedule must provide for immediate repair conditions. To maintain safety, an operator must temporarily reduce the operating pressure or shut down the pipeline until the operator completes the repair of these conditions. An operator's evaluation and remediation schedule must provide for immediate repair conditions. To maintain safety, an operator must temporarily reduce the operating pressure or shut down the pipeline until the operator completes the repair of these conditions. An operator must calculate the temporary reduction in operating pressure using the formulas in paragraph (h)(4)(i)(B) of this section, if applicable, or when the formulas in paragraph (h)(4)(i)(B) of this section are not applicable by using a pressure reduction determination in accordance with § 195.106 and the appropriate remaining pipe wall thickness, or if all of these are unknown a minimum 20 percent or greater operating pressure reduction must be implemented until the anomaly is repaired. If the formula is not applicable to the type of anomaly or would produce a higher operating pressure, an operator must use an alternative acceptable method to calculate a reduced operating pressure. An operator must treat the following conditions as immediate repair conditions:
40. Section 195.571 is revised to read as follows:
Cathodic protection required by this subpart must comply with one or more of the applicable criteria and other considerations for cathodic protection contained in paragraphs 6.2.2, 6.2.3, 6.2.4, 6.2.5 and 6.3 of NACE Standard RP 0169 (incorporated by reference, see § 195.3).
41. The authority citation for Part 198 continues to read as follows:
42. In § 198.13, a new paragraph (g) is added to read as follows:
§ 198.13
(g) Indirect cost rate reimbursement is limited to a maximum of 20% of Direct Costs of the Pipeline Safety Program.
Issued in Washington, DC, on November 19, 2011.
[FR Doc. 2011-29852 Filed 11-28-11; 8:45 am]