Changes to PHMSA Rules Affect Wide Range of Inspections, Reports

June 2015, Vol. 242, No. 6

W.R. Byrd and Deborah J. Brunt, RCP Inc., Houston, TX

The Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) published a new final rule amending the pipeline safety regulations for both gas (§192) and liquid (§195) in multiple subject areas. The final rule also made several editorial changes in the regulations. The changes are effective Oct. 1.

Areas addressed included post-construction inspections, leak surveys of Type B onshore gas gathering lines, qualifying plastic pipe joiners, regulation of ethanol, transportation of pipe, filing of offshore pipeline condition reports and calculation of pressure reductions for hazardous liquid pipeline anomalies.

PHMSA modified the gas and hazardous liquid regulations (§ 192.305 and § 195.204) to require that post-construction inspections of gas transmission and hazardous liquids pipelines be performed by a person other than the one who performed the construction task. PHMSA has identified poor quality of construction as an issue for several years and this change was proposed to address it.

This topic was the most controversial of all the proposed items. Operators commented that the proposed rule will result in a significant impact on cost. However, PHMSA believes allowing individuals to inspect their own work defeats, in part, the measure of safety garnered from such inspections.

The preamble of the rule explains that the intention is not to require third-party inspections or to prohibit any person from a company to inspect the work of another person from the same company. Only the person who performed the construction task will be excluded from conducting the inspection.

The inspection required by this new regulation will have to be documented, and presumably include the names of the person doing the work and the person inspecting it.

Leak Surveys for Type B Gas Gathering Lines (§ 192.9)

PHMSA now requires that operators of Type B gathering lines perform leak surveys in accordance with § 192.706 and repair any hazardous leaks discovered. This requires leak surveying on the same schedule that transmission lines are leak surveyed (once each calendar year not to exceed 15 months for odorized lines and more frequently for non-odorized lines in Class 3 and Class 4 locations).

Operators of Type B gathering lines now must design, construct, install, test and inspect any new Type B lines using the requirements for transmission lines. Steel Type B gathering lines must comply with 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 maximum allowable operating pressure (MAOP) of those lines under § 192.619, and maintain and install line markers as required for transmission lines. This amendment adds one more recognized risk control activity, leak surveying, for Type B gathering lines and continues to align the requirements with those of transmission lines.

PHMSA believes about half of all Type B gathering line mileage is already being inspected. If this is true, then many operators will not be affected by this new requirement. PHMSA did not address whether those operators are repairing any hazardous leaks found as required in the new amendment.

Qualifying Plastic Pipe Joiners (§ 192.285(c))

The new regulation requires that plastic pipe joiners must be requalified each calendar year (not to exceed 15 months) or after any production joint has been found unacceptable.

Previous regulations require that a person must be requalified, if during any 12-month period that person: (1) does not make any joints under that procedure, or (2) three joints or 3% of the joints made, whichever is greater, are found unacceptable.

This change will affect operators in two ways. It provides some extra flexibility in allowing up to 15 months to requalify plastic joiners, but it also makes the requirement more stringent by allowing only one poor production joint before requalification is required.

Comments received by PHMSA on the one unacceptable joint requiring re-qualification indicated there are circumstances and field conditions that can affect the quality of a joint, and thus they did not agree with this “zero-tolerance” proposal for plastic joiners. PHMSA’s response was that, if an unacceptable joint is a result of factors clearly beyond the joiner’s control, it does not expect those conditions to affect the requalification of the joiner.

PHMSA also said if an individual fusing a joint realizes that it is a bad joint, cuts it out and fuses another (acceptable) joint immediately following, they do not expect the joiner would have to requalify.

Mill Tests to Operate at Alternative MAOP (§ 192.112(e))

The allowance for combining loading stresses imposed by pipe mill hydrostatic testing equipment with the internal test pressure has been eliminated. Eliminating the allowance to combine equipment loading stresses will essentially increase the internal test pressure of the mill tests for new pipe to be operated at an alternative MAOP.

Along with pipe mill dimensional checks for expansion, this will help ensure that all new pipes to be operated at an alternative MAOP receive an adequate mill test and have adequate strength. Several years ago, PHMSA found construction projects in which new pipe did not meet the strength requirement specified in the pipeline safety regulations. Pipe 15% below the mandated SMYS was found on several new pipeline projects.

On May 21, 2009, PHMSA issued an advisory bulletin (ADB–09– 01), ‘‘Pipeline Safety: Potential Low and Variable Yield and Tensile Strength and Chemical Composition Properties in High Strength Line Pipe,’’ to address the issue. With alternative MAOP pipelines operating at up to 80% SMYS, PHMSA wanted to eliminate any potential low-strength pipe in these pipelines.

Operators who install pipelines that will operate at alternative MAOP must ensure that the steel mills from which they purchase the pipe will conduct tests that comply with this new requirement.

Transportation of Ethanol (§ 195.2)

The definition of “hazardous liquid” has been modified to include ethanol. Operators who operate ethanol pipelines will have to comply with all the requirements of Part 195, effective Oct. 1. Affected operators should start planning for this change and implementing the requirements.

Transportation of Pipe (§ 192.65)

The current requirement in § 192.65 for transportation of pipe by railroad (must be done in accordance with API Recommended Practice 5L1) has an exception for any pipe transported prior to Nov. 12, 1970; however, the exception for gas transmission pipe has been eliminated. All pipe transported by rail must be transported in accordance with API 5L1, if the pipe will be operated at a hoop stress of 20% or more of SMYS and has a diameter-to-wall-thickness ratio of 70-to-1 or more.

It is unlikely operators would still have uninstalled pipe that was transported by rail prior to Nov. 12, 1970 in their stock. Thus, this change should have minimal or no effect on operators.

Offshore Pipeline (§ 191.27 and § 195.57)

In 1991 the original requirement to inspect underwater pipelines and report the results was implemented. This was modified in 2004 to establish risk-based inspections. However, the requirement to report the results of the inspections was not modified.

Because inspections of shallow-water pipelines are now based on risk rather than required for all underwater pipelines, reports to PHMSA are no longer required 60 days after inspections. This reporting requirement has been removed from the gas and hazardous liquid regulations.

Operators must, however, still report to the National Response Center within 24 hours all instances of exposed pipelines or pipelines that pose a hazard to navigation.

The requirements for pressure-reduction calculations have been clarified. ASME/ANSI B31G and PRCI PR-3-805 (R-STRENG) have historically been used to calculate the required pressure reduction. However, these methods are to determine the remaining strength of a pipeline that has experienced bulk metal loss (general or localized corrosion), and are not applicable to other threats such as cracking or interactive threats, such as dents with gouges.

If no “suitable remaining strength calculation method” can be identified, then the pressure must be reduced a minimum of 20% from the actual operating pressure of the past two months.

National Pipeline Mapping System (NPMS)

PHMSA added sections 191.7(e), 191.29 and 195.58(e), and 195.61 to codify the statutory requirement for submission of information to the NPMS. Operators will continue to submit data to NPMS following the guidelines in the NPMS Operator Standards manual.

The definition “welding operator” (“a person who operates machine or automated welding equipment”) was added to the regulations. Welding operators are now specifically included in the requirements for welding procedures and qualifications. Additionally, Section 12 of API 1104 and Appendix A of API 1104, which is equivalent to Section IX of the ASME Boiler and Pressure Code, have been added as an option for qualifying welders and welding operators and for evaluating welds.

PHMSA proposed to amend § 192.625(b)(3) to state that the length of a lateral line, for purposes of calculating whether at least 50% of the line is in a Class 1 or Class 2 location, be measured between the distribution center and the first upstream connection to the transmission line.

This proposal was removed due to comments received and discussions at the Gas Pipeline Advisory Committee (GPAC) meetings. PHMSA will re-evaluate the proposal and may consider it in a future rulemaking action.

All ASME pressure vessels to be used in gas meter stations, compressor stations and other locations subject to testing for Class 3 or Class 4 requirements must be designed and pressure tested to 1.5 times the MAOP. The ASME Boiler and Pressure Code Section VIII specifies pressure tests must be done to 1.3 times the MAOP.

Operators must ensure any pressure vessels purchased for use in stations or Class 3 or Class 4 locations have been tested to PHMSA requirements, not ASME Boiler and Pressure Code requirements, in order to comply with this regulation.

In the current regulations, § 192.505(d) allows an exception for testing if a component other than pipe is the only item being replaced or added. However, this exception only applies to steel pipelines to be operated at 30% or more of SMYS. A similar exception is not allowed if the component other than pipe is being replaced or added to steel pipelines that operate at less than 30% of SMYS (§§ 192.507 and 192.509), service lines (§ 192.511) or plastic pipelines (CFR 192.513).

Requirements for testing of components, now found in § 192.505(d), were moved to § 192.503, “general requirements,” so it is now applicable to all pipelines, mains and service lines. This provides greater flexibility for operators and changes the regulations so that pipelines operated at lower stress levels do not have more stringent requirements than those operated at higher stress levels.

Alternative MAOP Notifications

Current requirements in § 192.620(c)(1) state that an operator must notify PHMSA and any applicable state agencies at least 180 days prior to operating a pipeline at an alternative MAOP.

For new pipelines to be operated using an alternative MAOP, notification to PHMSA and the applicable state agencies will be required at least 60 days prior to the earliest start date of either pipe manufacturing or construction activities.

For pipelines already in service, the 180-day notification requirement remains. These notifications allow PHMSA to schedule inspections at pipe and coating mills and at construction sites prior to the start of construction.

Operators need to be aware of the new requirement when planning new alternative MAOP pipelines to ensure notification is made to PHMSA within the required time.

Authors: W.R. (Bill) Byrd is founder and principal of RCP Inc., an engineering and regulatory consulting firm serving the energy pipeline industry throughout North America. He is on the board of the Pipeline Research Council International (PRCI), is a past Chair of the ASME Pipeline Systems Division, and is the current Chair of the ASME Safety Engineering and Risk Analysis Division. He is a licensed professional engineer in four states and graduated with honors from Georgia Institute of Technology for both his M.S. and B.S. in Mechanical Engineering.
Deborah J. Brunt is an executive consultant for RCP Inc. She retired as director of Engineering after 25 years with New Mexico Gas Company and began working for RCP in 2012. She is a registered professional engineer in New Mexico and has a B.S. in Mechanical Engineering with honors from Oregon State University.

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