[Docket No. PHMSA-2014-0020]

The Department of Transportation/Pipeline Hazardous Materials Safety Administration (PHMSA) issued an Advisory Bulletin to inform pipeline operators about the deficiencies identified in Enbridge’s integrity management program, control room operator training, and public awareness program which contributed to the accident at Marshall, Michigan.

NTSB’s report on the Marshall, Michigan incident noted the probable cause of the failure was stress corrosion cracking that grew and coalesced from crack and corrosion defects under disbonded polyethylene tape. The NTSB also noted the following organizational failures:

1. Deficient integrity management procedures which allowed well-documented crack defects to propagate until the pipe failed,
2. Inadequate control room operator training which resulted in failure to recognize the rupture for 17 hours, and
3. Insufficient public awareness and education which allowed the release to continue for almost 14 hours after the first notification of an odor to local emergency response agencies.

The ADB addresses all 3 issues.

1. Integrity Management (IM): An operator’s IM program must go beyond assessing integrity and repairing defects. Pipeline risk assessment should be a continuous process and risk analysis a continual reassessment process. Operators should evaluate any changes in how assessment data is analyzed, such as changes in tool tolerances, to determine if the changes will affect previous assessments.
   
   Threat and integrity data from multiple sources must be integrated and analyzed to ensure safety and integrity. Lack of data integration was a significant contributor to the accident at Marshall, Michigan.
   
   Refer to previous Advisory Bulletin ADB-2012-10, “Using Meaningful Metrics in Conducting Integrity Management Program Evaluations” (77 FR 72435, December 5, 2012).
2. Control Room Operations: Operators are advised to regularly train their controllers and consider training controllers as teams in the recognition and response to emergency and unexpected conditions. This team training should include recognition of SCADA alarms and readings and understanding of leak detection software.
   
   Operators should also periodically evaluate their leak detection systems to ensure that they work during situations such as pipeline shutdowns, startups and column separation. If an unexpected loss of product occurs, operators should shut down the pipeline until the problem is resolved.
   
   In addition, operators should evaluate their control room scheduling policies and practices.
   
   Refer to previous Advisory Bulletins ADB 10-01, “Leak Detection on Hazardous Liquid Pipelines,” (75 FR 4134, January 26, 2010) and ADB 05-06, “Countermeasures to Prevent Human Fatigue in the Control Room” (70 FR 46917, August 11, 2005).
3. Public Awareness Programs: Operators are advised to evaluate the effectiveness of their public awareness programs and ensure local emergency response agencies are prepared to respond to early indications of a possible rupture. Public Awareness programs should be assessed against API Recommended Practice 1162.
   
   Operators should also review their procedures for communications during emergencies to ensure they comply with previous Advisory Bulletins ADB 10-08, “Emergency Preparedness Communications” (75 FR 67807, November 3, 2010) and ADB 12-09, “Communication During Emergency Situations” (77 FR 61826, October 11, 2012).

In addition, the Advisory Bulletin recommends that operators review past and future NTSB incident investigations and implement the recommendations made in the investigation reports so the entire industry can benefit from the mistakes of one operator.

For further information contact Linda Daugherty by phone at 816-329-3821 or by email at linda.daugherty@dot.gov. For a copy of ADB-2014-02, contact Jessica Roger.

[Docket No. PHMSA-2013-0004]

PHMSA is preparing to request Office of Management and Budget (OMB) approval for the revision of the gas distribution annual report currently approved under OMB control number 2137–0522. In addition to making several minor changes to the report, PHMSA will also request a new OMB control number for this information collection. Some of the changes include:

• Specify Commodity Transported: natural gas, synthetic gas, hydrogen gas, propane gas, landfill gas, and other gas.
• Specify Operator Type: investor owned, municipally owned, privately owned, cooperative and other
• Additional Material Type: adding “Reconditioned Cast Iron” as a pipe material and defining it as a cast iron gas distribution pipe that has been lined internally by use of suitable materials that ensure safe operation at a maximum allowable operating pressure (MAOP) not to exceed the previously established MAOP.
• Addition of Excavation Damage Cause Categories in Part D: added a new data collection in Excavation Damage to include the four causes from Part I of the “Damage Information Reporting Tool (DIRT) Field Form”.

PHMSA invites comments on the proposed revisions to the form and instructions. Interested persons are invited to submit comments on or before June 27, 2014. Comments may be submitted via the E-Gov Website. Identify the docket number, PHMSA–2013–0004, at the beginning of your comments.

For a copy of this PHMSA Notice, contact Jessica Roger.

The Pipeline and Hazardous Materials Safety Administration (PHMSA) proposed $9.78 million in civil penalties against pipeline operators for alleged violations of federal law in 2013 – the highest yearly amount of proposed penalties in the agency’s history. Of the $9.78 million in proposed civil penalties for 2013, 22 cases representing $1,532,300 have been resolved. There are still 41 pending cases from 2013. The agency has proposed more than $33 million in penalties in pipeline enforcement cases since 2009.

The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 authorized PHMSA to double its maximum civil penalty amount for violations of federal pipeline law. PHMSA issued a final rule in 2013 raising the maximum civil penalty amount it is authorized to impose against pipeline operators from $100,000 to $200,000 for a single violation and from $1 million to $2 million for a series of related violations. Transportation Secretary Anthony Foxx said in an April 7 statement that the Transportation Department will use its recently increased maximum civil penalty authority “whenever necessary.”

[Docket No. PHMSA-2011-0023]

The National Transportation Safety Board (NTSB) has published their report on PHMSA’s state pipeline safety program, as a result of a previous recommendation related to the San Bruno incident. NTSB assessed PHMSA’s (1) policies and procedures for managing its State Pipeline Safety Program, including guidelines to participating States, and (2) oversight of State pipeline safety programs. The report concluded that PHMSA’s guidelines, policies, and procedures for State pipeline safety programs lack elements to ensure State inspections cover all Federal requirements and pipeline operators maintain safety standards. The staffing formula in the guidelines is outdated. The guidelines also lack sufficient detail on States’ use of risk factors for scheduling inspections and do not require PHMSA evaluators to review the adequacy of States’ inspection procedures. Furthermore, PHMSA lacks formal written procedures to guide its triennial reviews of State programs’ expenditures.

NTSB also believes that PHMSA’s oversight of State pipeline safety programs also does not ensure that States comply with program evaluation requirements and properly use all grant funds. Lapses in oversight have resulted in undetected safety weaknesses in State programs. Because it has not accounted for these non-compliances, the Agency cannot be sure that States correct program deficiencies. Furthermore, PHMSA has neither provided States sufficient guidance on suspension funds nor completed financial audits of their use.

The full report is available here.

[Docket No. PHMSA-2011-0023]

The Pipeline and Hazardous Materials Safety Administration (PHMSA) held a public workshop on April 16th to explore whether applying the integrity management (IM) requirements beyond high consequence area (HCAs) would mitigate the need for class location requirements. Locations along gas pipelines are divided into classes from 1 (rural) to 4 (densely populated) and are based upon the number of buildings or dwellings for human occupancy. Allowable pipe operating stresses, as a percentage of specified minimum yield strength (SMYS), decrease as class location increases from Class 1 to Class 4 locations. Gas IMP requirements use a different approach to identify areas of higher risk along pipelines.

The workshop had presentations from PHMSA, State representatives, AGA, INGAA, GPA and APGA and other representatives to review benefits and drawbacks of both methodologies, and the implications of removing class location. AGA noted that operators have been using class location in their policies and procedures successfully since implementation and removing it from code would be complex and disruptive. AGA supports a parallel approach to allow operators to continue using class location, but also allow the use of Integrity Management principles to satisfy class location upgrade requirements in lieu of retesting or replacing operationally functional transmission pipeline that meets safety standards. NAPSR and other State Utility bodies also supported not removing class location since it would affect state code. INGAA recommended a full PIR-based approach, and also a single design factor.

Presentations from the workshop can be found through the link: http://1.usa.gov/1nfT3rP. PHMSA is giving 30 days for comments in Docket No. PHMSA-2011-0023 on www.regulations.gov.

House Bill 2982, 83rd Texas Legislature directed the Railroad Commission to regulate gathering lines in Class 1 and rural locations based on risk. The Pipeline Safety Division will be hosting a series of workshops, conducted by Polly McDonald, Director of the Pipeline Safety Division, to discuss the implementation of this new responsibility. The workshops will provide a forum for discussing what information is needed to determine risk for these gathering pipelines; what is the best way to obtain this information; how should the information be analyzed and risk-ranked; and what is the time line for implementation. Following a brief presentation, there will be an opportunity for questions and answers. There are several dates and locations scheduled at this time to select from, as shown below; all workshops will commence at 10:00 a.m. Additional locations and dates may be added in the coming weeks. Please go online at http://hb2982-workshop.eventbrite.com to register for one of these events. Doing so will allow you to print a ticket that you will need to attend the meeting. Seating will be limited, so please register early.

Contact Jessica Roger for the full announcement, with meeting dates and locations.

The Ohio Public Utilities Commission has recently updated their pipeline safety regulations. The new regulation requires that “gas gathering/processing plant pipeline operators shall comply with the applicable pipe design requirements of 49 CFR 192(C), as effective on the date referenced in paragraph (D) of rule 4901:1-16-02 of the Administrative Code, for all gas gathering pipelines and processing plant gas stub pipelines.” It expands regulation to ALL gas gathering pipelines not otherwise regulated under the Pipeline Safety Regulations (49 CFR 192) that were constructed on or after September 20, 2012 (the date the law went into effect) and carry gas from a horizontal well. The rule includes the following definitions:

• “Gas gathering pipeline” means a gathering line that is not regulated under the Natural Gas Pipeline Safety Act, but includes a pipeline used to collect and transport raw natural gas or transmission quality gas to the inlet of a gas processing plant, the inlet of a distribution system, or to a transmission line.
• “Gas gathering/processing plant pipeline operator” means any person that owns, operates, manages, controls, or leases, a gas gathering pipeline or a processing plant gas stub pipeline. A gas gathering/processing plant pipeline operator is not an operator as defined in paragraph (P) of this rule, but a person may be both an operator and a gas gathering/processing plant pipeline operator.
• “Gas processing plant” means a plant that processes raw natural gas into merchantable products, including transmission quality gas or natural gas liquids, and also may include a plant that treats raw natural gas to remove impurities such as carbon dioxide, helium, nitrogen, or water.
• “Gathering line” and “gathering of gas” have the same meaning as in the Natural Gas Pipeline Safety Act.
• “Processing plant gas stub pipeline” means a gas pipeline that transports transmission quality gas from the tailgate of a gas processing plant to the inlet of an interstate or intrastate transmission line and that is considered an extension of the gas processing plant, is not for public use, and is not regulated under the Natural Gas Pipeline Safety Act.
• “Raw natural gas” means hydrocarbons that are produced in a gaseous state from gas wells and that generally include methane, ethane, propane, butanes, pentanes, hexanes, heptanes, octanes, nonanes, and decanes, as well as other naturally occurring impurities like water, carbon dioxide, hydrogen sulfide, nitrogen, oxygen, and helium.
• “Raw natural gas liquids” means naturally occurring hydrocarbons contained in raw natural gas that are extracted in a gas processing plant and liquefied and generally include mixtures of ethane, propane, butanes, and natural gasoline.

There are no permitting requirements from the PUCO for new construction, but there is a notification requirement. The pre-construction notification form can be found on the Public Utilities Commission of Ohio’s website.

API and AOPL have overhauled an educational website about liquid pipelines. Available at www.pipeline101.org and www.pipeline101.com, the site addresses foundational questions:

• Why Do We Need Pipelines?
• How Do Pipelines Work?
• Where Are Pipelines Located?
• Are Pipelines Safe?
• How Can You Help With Safety?

The site discusses the different types of pipelines, the products they transport, the transportation process, the safety record, and actions operators take to keep pipelines safe. The site teaches about pipelines rights-of-way and markers, and offers national and regional view of major liquids pipelines. Visitors to the site are taught how to recognize a pipeline leak, what do if a leak occurs, and to Call 811 Before You Dig. The site offers hyperlinks to API, AOPL, the Common Ground Alliance and regulatory and safety oversight agencies such as PHMSA.

Sheri Baucom recently joined RCP Integrity Services as Project Manager. Her experience in the industry will be an asset in providing InLine Inspection (ILI) total project management to our clients. Her areas of expertise include: In-Line Inspection, pressure testing, cathodic protection, corrosion analysis, Direct Assessment (External Corrosion DA, Internal Corrosion DA, Stress Corrosion Cracking DA), Integrity Management Program (IMP) implementation, risk/threat analysis, Non-Destructive Evaluation (NDE) methods, pipeline rehabilitation projects, managing pipeline anomaly excavation/examination programs, defect assessment, anomaly repair, post-dig analysis and ILI vendor validation. We are looking forward to her valuable contributions to RCP Integrity Services and our clients.

Is your pipeline company merging? Divesting? Moving? Are old hands retiring, and clearing out their offices? No matter the reason, if you have interesting pipeline samples that need a new home, please let us know. We do training frequently, and would like to have physical pipe samples of corrosion, cracking, welding defects, seam defects, etc. Miniature models of smart pigs and other tools are also welcome. We promise to give them a good home – but call before shipping those 40’ pipe joints.

For more information, contact Jessica Roger. Or ship direct to: RCP Inc., 801 Louisiana Street, Suite 200, Houston, TX 77002.

For the first time, RCP is offering a 2-day workshop on Pipeline Pressure Testing. RCP personnel have established themselves as industry experts, designing, implementing and validating pressure test programs for various operators. Recent PHMSA advisories and pending regulations will soon mandate pressure tests for operating gas and liquid pipelines that have not previously been subjected to pressured leak and strength tests. This course will provide an overview of how to efficiently plan, execute and document pipeline pressure tests that consistently satisfy code requirements as defined by CFR 49 Parts 192 and 195.

More information and class registration can be found on the RCP website.