DOT Pipeline Compliance News

August 2011 Issue

In This Issue

DOT Pipeline Compliance Workshop – August 9 – 11, 2011

Join us August 9 – 11 in Houston at our new office and dedicated training facility for an informative, lively, and interactive workshop on DOT Pipeline Compliance and OPA Planning for DOT Pipelines. This workshop has been attended by hundreds of pipeline personnel, with excellent feedback. The workshop provides an overview of the DOT pipeline regulations, and is appropriate for people who are new to pipeline regulations, who could use a refresher, or anyone who needs to know the latest information in these areas.


Day 1 (August 9): Gas Pipeline Regulations (49CFR192)
The workshop will include an introduction to DOT/OPS pipeline compliance; State and Federal program variations; roles and responsibilities; design, construction, operations, maintenance, and emergency response requirements; how to monitor rulemaking activity and stay current with your compliance program; operator qualification, public awareness; with a specific emphasis on the gas integrity management regulations. Each attendee will receive general training materials which include the applicable DOT 49 CFR 192 regulations for gas pipelines (cd-rom), inspection checklists, and speaker’s PowerPoint presentation handouts.

Day 2 (August 10): Special Topics
Back by popular demand! RCP is conducting a special workshop day to discuss topics that many of our clients have expressed an interest in. The workshop topics will include: Control Room Management, Public Awareness Program Effectiveness Evaluations, PHMSA enforcement practices, Revised Reporting Requirements, and MAOP calculation and documentation requirements.

Day 3 (August 11): Liquid Pipeline Regulations (49CFR195)
The workshop will include an introduction to DOT/OPS pipeline compliance; State and Federal program variations, roles and responsibilities; design, construction, operations, maintenance, and emergency response requirements; spill response planning requirements; how to monitor rulemaking activity and stay current with your compliance program; operator qualification and public awareness. Each attendee will receive general training materials which include the applicable DOT 49 CFR 195 regulations for hazardous liquid pipelines (cd-rom), inspection checklists, and speaker’s PowerPoint presentation handouts.

To register, or for additional information, click here.

PHMSA Advisory Bulletin ADB-11-04 Damage to Pipeline Facilities Caused by Flooding

[Docket No. PHMSA-2011-0177]

The Department of Transportation/Pipeline Hazardous Materials Safety Administration (PHMSA) issued Advisory Bulletin ADB-11-04 to all owners and operators of gas and hazardous liquid pipelines regarding the potential for damage to pipeline facilities caused by severe flooding. This advisory includes actions that operators should consider taking to ensure the integrity of pipelines in case of flooding. A synopsis of these actions include:

  1. Evaluate the accessibility of pipeline facilities that may be in jeopardy
  2. Extend regulator vents and relief stacks above the level of anticipated flooding
  3. Coordinate with emergency and spill responders on pipeline location and condition
  4. Coordinate with other pipeline operators in the flood area
  5. Deploy personnel in positions to take emergency actions
  6. Determine if facilities have become submerged and in danger of being struck by vessels or debris
  7. Frequent patrols
  8. Perform surveys to determine the depth of cover over pipelines and condition of exposed pipe
  9. Ensure line markers are still in place

For a copy of ADB-11-04 contact Jessica Roger.

Control Room Management Services

RCP is able to provide pipeline operators with fully compliant, customized Control Room Management Programs that take advantage of any existing processes that are currently in place and develop new processes that are tailored to your organization’s ability to successfully implement.

RCP also has the expertise to conduct readiness assessments as well as compliance analysis of your existing Control Room Management programs. This independent analysis will take into consideration what others within the industry are doing as a benchmark as well as what the final regulations require.

For more information on how RCP can help with your Control Room Management Program, contact Jessica Roger.

PHMSA adds new Gas IM FAQ-275: Requirements for reassessments using ILI

Question: For reassessments using ILI, are verification digs required if the ILI tool does not show any defects/anomalies? The baseline assessment and/or previous reassessment was completed and anomalies were repaired, as needed.

Answer: When using in-line inspection tools for conducting integrity management baseline assessments, § 192.921(a)requires the operator to follow ASME/ANSI B31.8S, section 6.2 for special considerations for the use of in-line inspection tools. The operator must verify that an in-line inspection tool performs within its published specification with respect to detection sensitivity tolerances, classification, sizing accuracy, location accuracy, and requirements for defect assessment. An operator must not assume that results (showing no identified anomalies that exceed the reporting threshold) are reliable until the tool’s performance is confirmed by verification digs. Different tools, tool sensors, different analysts, changes in pipe cleanliness or operating parameters, etc., can affect tool performance/results.

49 CFR § 192.933 addresses integrity issues such as inline tool inspections, pressure reductions, and discovery of conditions. Section 192.921(a)(1) states that an operator must follow ASME/ANSI B31.8S, section 6.2 in selecting the appropriate internal inspection tools for the covered segment. ASME/ANSI B31.8S, sections 6.2.6 outlines the screening and examination of the in-line tool results, and states:

“Results of in-line inspection only provides indications of defects, with some characterization of the defect. Screening of this information is required in order to determine the time frame for examination and evaluation.”

“Examination consists of a variety of direct inspection techniques, including visual inspection, inspections using NDE equipment, and taking measurements, in order to characterize the defect in confirmatory excavations where anomalies are detected. Once the defect is characterized, the operator must evaluate the defect in order to determine the appropriate mitigation actions.”

An operator must have a method to accurately characterize and evaluate in-line tool results. Excavation of selected in-line tool results is a method to determine if the in-line tool including its sensors, other electronics, and evaluation models are properly evaluating the pipeline segment. When an in-line tool has no findings on a pipeline segment, excavation is still an important method of meeting the requirement to verify results. Operators must have in-line tool procedures that include a valid method such as excavation to confirm tool performance within specifications and the accuracy of in-line tool results.

PHMSA updates Distribution Integrity Management FAQ’s

PHMSA has updated the Gas Distribution Integrity Management FAQ’s. We have included a few of the more interesting FAQ’s, but you can see all of them by clicking here.

B.4.3 Will my plan be in compliance if I use SHRIMP?
The American Public Gas Association’s (APGA) Security and Integrity Foundation (SIF) developed the Simple Handy Risk based Integrity Management Plan (SHRIMP) to assist small operators in creating their written DIMP plan. Using SHRIMP does not necessarily mean that an operator will be in compliance with DIMP requirements. SHRIMP contains generic procedures. An operator’s plan needs to reflect their own procedures, information sources, and practices. The APGA SIF is identifying areas where a SHRIMP user may need to enhance or modify the plan generated by this application to be in compliance with the pipeline safety regulations. Refer to APGA SIF website for the latest information.

C.4.b.5 We used leak causes which we have experienced in the past to identify threats. For example, washouts in our system have not caused leaks in the past so washouts were not identified as a threat. Should washouts be classified as a potential threat due to the possibility of coating damage?
Yes, since the operator experiences washouts, they need to include this specific threat in their risk evaluation. The DIMP rule requires operators to consider both actual and potential threats. Even though washouts have not caused leaks in the past, the fact that pipe is located in areas subject to washouts indicates the potential for leaks due to washouts. The potential for damage (or likelihood of failure) from washout is different for different types of materials. Unsupported or washed out cast iron is much more susceptible to failure than unsupported steel or plastic. The level of risk would also be influenced by the amount of force and the frequency of the force the pipe may experience due to washouts. The measure to reduce risk from washout may require pipe to be buried deep enough to maintain the depth of cover prescribed in Section 192.327 Cover.

C.4.d.11 How can an operator demonstrate that their leak management program is effective?
Operators need to evaluate the effectiveness of their leak management program through a self-audit program. The basic elements of a leak management program are:

  1. Locate the leaks in the distribution system – (your plan needs to describe your leakage detection procedures)
  2. Evaluate the actual or potential hazards associated with these leaks (your plan needs to describe your leak classification criteria)
  3. Act appropriately to mitigate these hazards (your plan needs to describe your leak repair or monitoring schedule)
  4. Keep records (of leak surveys, leaks, and self-audit data)
  5. Self-assess to determine if additional actions are necessary to keep people and property safe (The purpose of a periodic self-assessment is to determine if the leak management program is effective and, if necessary, to identify changes necessary to ensure that it is effective. Your plan needs to include how you perform your self assessment and the results of the self-assessment.)

An operator must either include the leak management program procedures in its DIMP plan or reference the procedures in your O&M.

C.4.f.2 What constitutes a periodic evaluation?
The operator’s procedure needs to describe the actions the operator will take during the program evaluation. It should include the following actions:

  • Description of the frequency of review based on the complexity of the system and changes in factors affecting the risk of failure, not to exceed 5 years
  • Verification of general information (e.g. contact information, form names, action schedules, etc.)
  • Incorporation of new system information
  • Re-evaluation of threats and risk
  • Review of the frequency of the measures to reduce risk, where applicable
  • Review of the effectiveness of the measures to reduce risk. This includes, at minimum, reviewing the results of the performance measure(s) for each measure taken to reduce risk.
  • Review of the measures implemented to reduce risk and refine/improve as needed (i.e. add new, modify existing, or eliminate if no longer needed)
  • Review of performance measures, their effectiveness, and if they are not still appropriate, refine/improve

C.5.3 Should both steel and plastic mechanical fitting failures be reported? How about the different styles of plastic mechanical fittings? Do mechanical fitting failures in cast iron systems need to be reported?
All types of mechanical fitting failures should be included regardless of material. The objective of the data collection is to identify mechanical fittings which, based on a historical data, are susceptible to failure. The Advisory Bulletins, ADB-86-02 issued on February 26, 1986, and ADB-08-02 (73 FR 11695) issued on March 4, 2008, identified issues with mechanical fittings which could lead to failure. The bulletin advised operators to perform certain actions. Determining the apparent cause of these mechanical fitting failures is important to determine if and what type of additional actions may be needed if trends are identified. PHMSA intends for operators to report all types and all sizes of mechanical fitting failures which result in a hazardous leak. The failure can occur on a fitting connected to a pipe or a fitting that joins sections of pipe. Mechanical fittings include stab, nut follower, and bolt type fittings. The reporting requirements apply to failures in the bodies of mechanical fitting or failures in the joints between the fittings and pipe.

Operators are to report mechanical fitting failures as the result of any cause including excavation damage. Mechanical fittings are to be included regardless of the material they join. For example, include mechanical fittings which join steel to steel, steel to plastic, and plastic to plastic. Examples of the use of mechanical fittings may be found in the following applications: service tees, tapping tees, transition fittings, couplings, risers, sleeves, ells, “Ys”, and tees. Failures on fittings that are joined by solvent cement, adhesive, heat fusion, or welding are not to be reported as mechanical fitting failures.

PHMSA does not intend to collect information about failures of cast iron bell & spigot joints unless the leak resulted from a failure of a mechanical fitting used to repair or reinforce a joint.

California Decision on MAOP Determination Methodology

This is somewhat old news to some, but not everyone, so we decided to include a brief article on a recent decision (June 16, 2011) the California PUC made in regards to intrastate gas transmission operators who have relied upon the pre-1970 grandfather clause for establishing MAOP. It requires all intrastate gas transmission operators in the state of California “to develop and file for California PUC consideration a Natural Gas Transmission Pipeline Comprehensive Pressure Testing Implementation Plan to achieve the goal of orderly and cost effectively replacing or testing all natural gas transmission pipeline that have not been pressure tested.” The deadline for submittal of these plans is August 26, 2011 for four operators specifically named in the decision. The decision requires that the implementation plans outline steps each operator will take to identify and either pressure test or replace all segments of natural gas pipelines which were not pressure tested (grandfathered highest actual operating pressures in 5 years previous to 1970) or lack sufficient details related to performance of such test. The decision also requires operators to give higher priority to class 3 & 4 areas as well as class 1 & 2 HCA’s. This decision is obviously limited to pipelines under the jurisdiction of the California PUC, but is certainly noteworthy for all gas transmission pipeline operators given the heightened attention that MAOP has received during the PHMSA reauthorization hearings. For a copy of the decision, contact Jessica Roger.

MAOP Analysis Services

RCP has developed the most comprehensive MAOP analysis model on the market. Using this model, RCP has successfully conducted MAOP analysis for dozens of complex onshore/offshore gathering, transmission, and distribution pipeline systems. The analysis can be performed as a service with the results delivered on a system-by system basis as well as detailed individual record MAOP reports that indicate the regulatory code citation or letter of interpretation that is driving the calculated MAOP value. The MAOP model can also be purchased and configured to run by your personnel using your in-house data sets. For more information, visit or contact Jessica Roger.

Enforcement Proceedings Involving an Informal Hearing

[Docket No. PHMSA-2011-0161]

Subpart B of 49 CFR part 190 (190.201-190.239) provides an opportunity for a pipeline operator to submit a written answer and/or request a hearing prior to the issuance of any order that makes a finding of violation, assesses a civil penalty, or requires corrective measures to be taken. Hearings in pipeline safety enforcement cases are conducted by a hearing officer in accordance with certain procedures designed to ensure a fair and impartial decision on the merits. Formerly, hearings were held before several different attorneys from the Office of Chief Counsel and were assigned to an attorney who had no role in the investigation and prosecution of the case being heard. Now, all hearings will be held, to the extent practical, before the designated hearing officer, who will have no role in the investigation and prosecution of any enforcement cases. Effective immediately, and to the extent practical, all timely requested hearings will be held before the designated hearing officer or “Presiding Official” within PHMSA.

PHMSA published a document to explain the current hearing procedures and describe the dedicated hearing officer’s roles and responsibilities, the process for requesting a hearing, and the manner in which a case will proceed once a hearing has been requested. Contact Jessica Roger for a copy.

Technical Advisory Committees – Meeting Date Change August 2, 2011 – Arlington, VA

In a Federal Register notice published on May 20, 2011, (76 FR 29333) PHMSA announced that the Technical Pipeline Safety Standards Committee (TPSSC) and the Technical Hazardous Liquid Pipeline Safety Standards Committee (THLPSSC) would meet on August 2-3, 2011, from 9 a.m. to 5 p.m. The meeting dates have been changed.

The TPSSC and the THLPSSC will now meet on August 2, 2011, only, from 9 a.m. to 5 p.m. The meeting will be held at The Weston Arlington Gateway, 801 North Glebe Road, Arlington, VA 22203. Please refer to the May 20, 2011, (76 FR 29333) notice for more details about the meeting. (See related article in the June 2011 Edition of the DOT Pipeline Compliance News.) The TPSSC and THLPSSC will consider a draft pipeline safety report to the nation. The meeting will be open to the public.

PHMSA Public Awareness Inspection Q&As

PHMSA recently responded to Q&As regarding information contained in their Public Awareness Program Enforcement Guidance document, which contains information presented to inspectors regarding the general guidelines for performing regulatory inspections of operator’s public awareness programs. Below is a shortened summary of their responses:

  • Accuracy of Message Delivery – There was concern over PHMSA’s expectation that delivery of the message to 100 percent of the stakeholder audience was not mandated by the DOT rule or API RP 1162. PHMSA stated the operator is required to deliver the baseline message to each stakeholder audience based on the delivery frequency outlined in RP 1162. Further, they stated the operator should determine the need for additional message delivery based on the operator’s results.
  • Acceptable Annual Audit Methods – An issue was raised regarding statements included in the Guidance document suggesting regulatory inspections are disallowed as an acceptable method of an annual audit. PHMSA stated in their response they accept three annual audit methods as referenced in RP 1162 (internal self-assessments, third party audits, or regulatory inspections).
  • Use of Operator Employees to Pre-Test PAP Material – Information contained in the Guidance document suggested the use of non-operations employees was not an allowable method of focus group testing. In their response, PHMSA stated the use of non-operations employees is considered an allowable method for pre-testing of messages.
  • Use of “Other Languages” – A question was raised regarding whether the delivery of messages to both the public and emergency official audiences in languages other than English is not appropriate, as their activities require them to conduct their business primarily in English. PHMSA responded by stating, operators are required to conduct their program in English and in other languages commonly understood by a significant number and concentration of the non-English speaking population in the operator’s area. Operators should be able to provide the basis for their decisions with respect to this question.
  • Acceptable Sample Sizes and Margins of Error (MOE) for Measuring Program Effectiveness– It has been suggested the Guidance document is vague and provides little information to the inspector regarding sample sizes and MOE. PHMSA responded by stating the Guidance document will be updated regarding this issue.

For a complete listing of the PHMSA responses, please see their website.

WRGC Regional Gas Conference August 23 & 24, 2011 Tempe, AZ

Join us at the 2011 Western Regional Gas Conference at the Tempe Mission Palms Hotel & Conference Center in Tempe, Arizona. RCP representatives will be attending the conference and look forward to meeting you. Chris Foley (RCP Vice President) will be giving a presentation on “MAOP Process Management” on Tuesday, August 23. Click here to check for updates on the conference agenda and registration. (WRGC is a non-profit and volunteer-organized event to provide a venue for discussion of natural gas distribution and transmission issues.)

Bill Byrd signature
W. R. (Bill) Byrd, PE
RCP Inc.