The Department of Transportation/Pipeline Hazardous Materials Safety Administration (PHMSA) issued 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 owners and operators of natural gas pipeline and hazardous liquid pipeline systems. This advisory bulletin pertains to microalloyed high strength line pipe grades, generally Grade X-70 and above.

The Federal pipeline safety regulations in 49 CFR Parts 192 and 195 require operators of natural gas transmission, gas distribution, and hazardous liquids pipeline systems to use pipe manufactured by a listed specification in the design of pipelines in accordance with Sec. 192.7, 192.55 (a), 192.105, and Sec. 195.3, 195.106, and 195.112. Tests that have been conducted on line pipe that has been installed in pipeline systems have shown that some of the pipe material has yield strengths, tensile strengths, and/or chemical compositions that do not meet the requirements of the American Petroleum Institute, Specification for Line Pipe–5L, (API 5L), for PSL 2 and the specified pipe grade. PHMSA recently reviewed metallurgical testing results from several recent projects indicating pipe joints produced from plate or coil from the same heat may exhibit variable chemical and mechanical properties by as much as 15% lower than the strength values specified by the pipe manufacturer.

PHMSA wants to ensure that owners and operators of recently constructed pipeline systems are aware of the need to investigate whether their pipelines contain joints of pipe that do not meet minimum specification requirements.

For more information or a copy of ADB-09-01, contact Jessica Roger.

The Minerals Management Service (MMS) issued a Notice to Lessees (NTL) which updates the regulatory citations, primary functional responsibilities, and contact information for various MMS regulations, including those regulations that apply to pipeline operators on the Offshore Continental Shelf (OCS). It lists the regulatory citations and subject matter of the MMS regulations and provides the organizational office in the MMS Gulf of Mexico OCS Region (GOMR) with primary responsibility for the various functions and requirements contained therein.

NTL 2009-G14 is effective May 21, 2009 and supersedes NTL 2000-G03. For a copy of NTL 2009-G14, contact Jessica Roger.

Gas Distribution Leak Management System

Do you know what leak surveys are pending in the next 30 days and which ones are overdue?

Do you know exactly how many and what type of leaks are active on your system?

Do you know what leaks are scheduled for repair or re-survey next week?

Do you have a tool that manages and analyzes the data you will need for DIMP implementation?

Does your GIS system maintain survey, leak & repair history attributes?

How long will it take you to aggregate the leak data for the DOT Annual Report or Texas PS-95?

If you are interested in a tool that can give you the answers to these questions, contact Jessica Roger to schedule an online demonstration.

The Department of Transportation/Pipeline Hazardous Materials Safety Administration (PHMSA) has selected Annmarie Robertson, Pipeline Safety Manager for Indiana and the NAPSR Chairperson, as their State Damage Prevention Coordinator. Annmarie will report to Steve Fischer, the program manager. She will work with the PHMSA rulemaking staff on the Advance Notice of Proposed Rulemaking for federal excavation damage enforcement. She also will work with Zach Barrett’s group to support state regulators in improving damage prevention programs. Annmarie had much success with the recently passed Indiana damage prevention legislation. Michael Thompson, Pipeline Safety Chief for Oregon, is now the NAPSR chairman.

PHMSA has updated two FAQ’s relating to integrity management reporting requirements. For gas transmission, FAQ #97 was updated. For liquid pipelines, FAQ #12.1 was updated.

FAQ #97 (gas transmission pipelines)

Question: What types of notifications are required by the rule?

Answer: The notifications required by the rule are:

• Substantial change to program implementation or significant change to schedule for carrying out elements. (Within 30 days of adoption). The notification should include a description of the changes and the basis on which they were made.
• Inability to meet remediation deadlines in the rule and unable to reduce pressure (When operator determines schedules cannot be met). A description of defects/repairs needed, reason for delay, why pressure can’t be reduced, basis for concluding delay won’t jeopardize health or environment, schedule for repair, other mitigative actions planned should be included.
• Use of technology other than in-line inspection, Direct Assessment, or pressure testing for conducting assessments. (180 days prior to assessment). The operator should provide a description of the "other technology", its basis for concluding that the method will result in equivalent understanding of pipe condition, and its schedule for assessment.

In addition, all notifications must include information about the pipe segments and HCAs involved.

• Pressure reduction imposed as a result of IM anomalies extends for more than 365 days. The notification must explain the reasons for the delay and justify that the continued pressure reduction will not jeopardize the integrity of the pipeline.

FAQ #12.1 (hazardous liquid pipelines)

12.1 What types of notifications are required by the rule?

The notifications required by the rule are:

Circumstance/Type

Deadline for Submittal

Information Required

Inability to meet remediation deadlines in the rule and unable to reduce pressure

When operator determines schedules cannot be met

Description of defects/repairs needed, reason for delay, why pressure can’t be reduced, basis for concluding delay won’t jeopardize health or environment, schedule for repair, other mitigative actions planned

Pressure reduction will exceed 365 days

When pressure reduction exceeds 365 days

Reasons for the delay, description of additional remedial actions

Use of technology other than in-line inspection, pressure testing, or external corrosion direct assessment for conducting assessments

90 days prior to assessment

Description of “other technology”, basis for concluding equivalent understanding of pipe condition, schedule for assessment

Variance from 5-year re-assessment interval (unavailable technology)

180 days before end of 5-year interval

Date and method of last assessment, reason why required interval cannot be met, interim evaluation of pipe integrity, schedule for assessment

Variance from 5-year re-assessment interval (engineering basis)

270 days before end of 5-year interval

Date and method of last assessment, proposed new retest interval, actions that will provide equivalent understanding of pipe condition, summary of engineering basis

In addition, all notifications must include information about the pipe segments and HCAs involved.

The on-line integrity management notification system is also being used to allow operators to submit notification of their intent to move biofuels in their pipelines. These notifications are not required by regulation. PHMSA has asked that operators voluntarily notify when they intend to use their pipelines for biofuel transportation.

PHMSA has announced the rosters of government, industry and public representatives that will serve on the Technical Hazardous Liquid Pipeline Safety Standards Committee and the Technical Pipeline Safety Standards Committee. These committees meet at least twice yearly to review and to report on proposed Federal pipeline safety standards submitted to it by the Department of Transportation. The committees provide peer reviews of all proposed pipeline safety rules to assure technical feasibility, reasonableness, cost-effectiveness and practicability. They also evaluate cost-benefit analysis and risk assessment information on each proposal.

Technical Hazardous Liquid Pipeline Safety Standards Committee:

• John S. Bresland – U.S. Chemical Safety and Hazard Investigation Board (CSB)
• Elmer P. Danenberger – U.S. Department of Interior Minerals Management Service
• Drue Pearce – Alaska Natural Gas Transportation Projects
• Larry J. Davied – Magellan Midstream Partners, L.P.
• Denise M. Hamsher – Enbridge (USA) Pipeline
• Orville B. Harris – Longhorn Partners Pipeline, LP
• Craig O. Pierson – Marathon Ashland Pipe Line LLC
• Larry M. Shelton – Buckeye Partners LP
• Timothy P. Butters – City of Fairfax Virginia
• Geraldine E. Edens – Counsel, McKenna, Long, & Aldridge, LLP
• Richard B. Kuprewicz – Accufacts, Incorporated
• Lisa M. Parker – Parker Horn Company
• Carl M. Weimer – Pipeline Safety Trust

Technical Pipeline Safety Standards Committee:

• Drue Pearce – – Alaska Natural Gas Transportation Projects
• Lisa P. Edgar – Florida Public Utilities Commissioner
• Berne L. Mosley – Federal Energy Regulatory Commission
• Donald J. Stursma – Iowa Utilities Board
• Michael R. Comstock – City of Mesa, Arizona
• J. Andrew Drake – Spectra Energy
• Jeryl L. Mohn – Panhandle Energy
• James F. Wunderlin – Southwest Gas Corporation
• Peter G. Terranova – UGI Utilities, Incorporated
• Richard E. Feigel – Hartford Steam Boiler
• Theodore C. Lemoff – National Fire Protection Association
• Richard F. Pervarski – Virginia Utility Protection Services, LLC
• Paul S. Rothman – The Port Authority of New York and New Jersey
• Alan R. Shuman – Georgia State Fire Marshal

The State of Georgia has revised its damage prevention regulations in:

• Title 515 – Georgia Public Service Commission;
• Chapter 9 – Safe Installation and Operation of Natural Gas Transmission and Distribution Systems;
• Rule 3 – Enforcement Procedures Governing Gas Pipeline Safety;
• 9-3 Enforcement Procedures Governing Gas Pipeline Safety

Section 515-9-3-.14 "Utilities Protection Center" and the new Section 515-9-3-.15 "Damage Prevention" require that all Owners and/or Operators of a buried utility facility in Georgia shall be a member of the State-wide Utilities Protection Center, and that all Owners and/or Operators of a buried utility facility in Georgia shall comply in all respects, with Title 25, Chapter 9 of the Official Code of Georgia Annotated. The previous regulations only required that gas distribution systems comply with those requirements.

Government/Industry Pipeline R&D; Forum

June 24-25, 2009

The Government/Industry Pipeline R&D; Forum will be in Crystal City, Virginia June 24 – 25, 2009. This event is organized through a strong research enterprise between the Pipeline and Hazardous Materials Safety Administration, other State and Federal agencies and with North American natural gas and hazardous liquid pipeline operators. The forum will bring government and industry pipeline stakeholders together for the following purpose(s):

• Develop a consensus agenda of technical gaps & challenges for future R&D;
• Identify both short and long term research objectives for liquid/gas and transmission and gas distribution pipelines;
• Conduct basic road mapping on identified technical gaps so solicited research is addressing the need effectively; and
• Provide details of the ultimate research goals so appropriate end users are factored into project scopes.

Pre-forum registration closes June 19. Click here for a draft agenda, registration and hotel information. The agenda will be updated weekly as the date approaches.

The AGA Operations Conference and Biennial Exhibition was held on May 19 – 21 at the David L. Lawrence Convention Center in Pittsburgh, PA. Over 1300 industry employees attended the Operations Conference, Committee Meetings and Exhibition.

During the Distribution & Transmission Engineering Session 23, Larry Decker, presented his paper on calculating Maximum Allowable Operating Pressure (MAOP) for changing pipeline conditions. This presentation focused on lessons learned from calculating MAOP, including: what the regulations require for MAOP analysis, what the critical/non-critical data are to justify current MAOP, the MAOP formula decision tree and best practices for maintaining MAOP data. (Request a copy)

RCP representatives were at the Biennial Exhibition to demonstrate our extremely popular Leak Tracking System. There is nothing on the market like this web-based tool that effectively manages leak survey, inspection, repair and evaluation work flow all while providing a great tool to comply with upcoming DIMP requirements. If you were unable to attend, or missed the demonstration, contact Jessica Roger for a demo or more information.

Save the Dates!

If you were unable to attend our June 2 & 3 workshop, the next workshop will be held on

October 6 & 7 (Tuesday & Wednesday) – Houston, TX

Visit our Seminars webpage for updates & registration information.

The June 2nd edition of the Federal Register contained a notice that the Pipeline Siting and Stakeholder Involvement Workshop would be webcast. The workshop was held on June 1, 2009, and included a Case study of CenterPoint Energy's Carthage to Perryville Pipeline Project, presented by Debbie Ristig (CenterPoint Energy's Vice President Engineering and Compliance); and a Stakeholder Outreach Panel Discussion.

The recording is available online for the next 3 months at: http://www.capitolconnection.gmu.edu/ferc/060109/ferc060109.htm.