DOT Pipeline Compliance News

August 2005 Issue

In This Issue

DOT Pipeline Compliance Workshop – August 17-18, 2005

Join us at our Houston office for an informative, lively, and interactive workshop on DOT Pipeline Compliance and API RP 1162 for DOT Pipelines. This workshop has been attended by hundreds of pipeline personnel, with excellent feedback. Day 1 provides an overview of the DOT pipeline regulations, and is appropriate for people who are new to pipeline regulations, or who could use a refresher. Day 2 covers each of the 8 elements required in RP 1162.

Day 1: Introduction to DOT/PHMSA Pipeline Regulations

  • Agency jurisdictions – what does DOT/PHMSA regulate anyway?
    • Important definitions
    • Important letters of clarification from the agency
    • Recent EPA/DOI memorandums of understanding
  • State and Federal program variations, roles and responsibilities
  • Gas and liquid design, construction, operations, maintenance, and emergency response requirements
  • Spill response planning requirements
  • How to monitor rule-making activity and stay current with your compliance program

Your Instructor for Day 1: As principal of RCP, Mr. Byrd enjoys a solid reputation for working with the public, corporate management, and regulatory agencies to resolve complex regulatory issues. He serves on various industry association committees, works as an expert witness and consulting expert, and is frequently called upon to comment on current or proposed rule-makings at public and private meetings and conferences.

Day 2: API RP1162 Overview

The final rule incorporating by reference API Recommended Practice 1162 will go into effect June 20, 2006 for both gas (192) and liquid (195) pipeline operators. The Public Awareness/API RP1162 Overview will cover each of the 8 elements required in RP1162. The session will also include additional information about the more complex elements of stakeholder audience identification, communication methods and evaluation of effectiveness. The session will be taught by a leader in the development of RP1162 who understands the background and intent of the rule as well as the language.

Your Instructor for Day 2: Susan D. Waller has over twenty-five years of pipeline experience and has been responsible for developing and implementing effective pipeline awareness communication programs throughout North America. Ms. Waller helped lead the development of API’s Recommended Practice 1162, Public Awareness Programs for Pipeline Operators.

Increase your understanding of this new rule by attending Day 2 of the Workshop.

For additional information, including a seminar brochure, go to our website here.

Need to update your Public Awareness Program?

RCP can help develop your updated plan to meet API RP 1162 standards, and provide turnkey implementation, mail-outs, evaluations, and tracking of your program. For more information call or Click Here.

Pipeline Emergencies Training Program

The National Association of State Fire Marshals (NASFM), in conjunction with the U.S. Department of Transportation, has developed a new training program to help local emergency response agencies adequately respond to pipeline emergencies, and is currently holding regional Train-The-Trainer sessions to ensure local communities receive the crucial training. The Pipeline Emergencies training program equips experienced instructors to teach the pipeline safety curriculum to emergency responders in their regions. The course helps emergency responders understand pipeline operations, common products transmitted and distributed through them and tactical response guidelines to deal with accidents. 

The training is being conducted through normal fireman training facilities, and is coordinated through the local fire marshal organizations.  Since the pipeline industry is required to conduct liaison activities with local emergency response personnel, they will benefit by having their local emergency responders more knowledgeable about general types of pipeline emergencies.  The train-the-trainer schedule for 2005 is available online at the event website.

At the present time, this training is not being offered to industry.  However, copies of the training materials can be ordered for a nominal cost here.

Integrity Management Services

RCP can assist pipeline operators with ongoing compliance management and engineering associated with your IMP. This includes direct assessment strategies, tool and vendor selection, ILI/ECDA report analysis, corrosion control programs, repair strategies, and IMP/risk model updates. For more information on how RCP can support your ongoing IMP needs, Click Here.

Proposed Rule to Update Regulatory References to Technical Standards

The Office of Pipeline Safety proposes to update the pipeline safety regulations to incorporate by reference all or parts of new editions of voluntary consensus technical standards to enable pipeline operators to utilize current technology, materials, and practices. 49 CFR parts 192, 193, and 195 incorporate by reference all or parts of 60 standards and specifications developed and published by technical organizations.  PHMSA proposes to adopt all or part of recent editions of 39 of the 60 standards referenced in the pipeline safety regulations.  This update enables pipeline operators to utilize current technology, materials, and practices. The incorporation of the most recent editions of standards improves clarity, consistency and accuracy, and reduces unnecessary burdens on the regulated community.

Comments on the subject of this proposed rule must be received on or before September 16, 2005 [Docket No. PHMSA-05-21253].

For a complete copy of the notice from the Federal Register, please email Jessica Roger at RCP.

“Person Who Offers” a Hazardous Material for Transportation

PHMSA is amending the Hazardous Materials Regulations to add a definition for “person who offers or offeror.” The definition adopted in this final rule codifies long-standing interpretations and administrative determinations on the applicability of those regulations. This final rule makes the following revisions to the HMR:

Defining “person who offers or offeror” to mean any person who performs or is responsible for performing any pre-transportation function required by the HMR or who tenders or makes the hazardous material available to a carrier for transportation in commerce. A carrier is not an offeror when it performs a function as a condition of accepting a hazardous material for transportation in commerce or when it transfers a hazardous material to another carrier for continued transportation without performing a pre-transportation function.

Clarifying that there may be more than one offeror of a hazardous material and that each offeror is responsible only for the specific pre-transportation functions that it performs or is required to perform.

Clarifying that each offeror or carrier may rely on information provided by a previous offeror or carrier unless the offeror or carrier knows or, a reasonable person acting in the circumstances and exercising reasonable care, would have knowledge that the information provided is incorrect.

This final rule is effective October 1, 2005.

RCP Services Spotlight – Underwater Inspection Procedures and Interval Risk Modeling

Underwater Inspection Procedures – On August 10, 2004, the DOT published final amendments to 49 CFR 195.413 and 49 CFR 192.612 for Periodic Underwater Inspections of regulated pipeline facilities located in water depths of 15’ or less in the Gulf of Mexico and its inlets. Effective August 10, 2005, operators of certain hazardous liquid and gas pipelines will be required to have procedures in place to identify, inspect, and address those pipelines that are exposed or pose a hazard to navigation. RCP has experience developing comprehensive pipeline safety procedures including procedures to meet the new underwater inspection requirements. RCP can develop comprehensive and customized procedures that address these requirements, including:

  • General application criteria
  • Underwater inspection technologies most appropriate for your pipelines
  • Measures to be taken in the event pipelines are exposed or pose a threat to navigation
  • Risk-based analysis to determine appropriate inspection intervals

Inspection Interval Risk Modeling – The recently finalized regulations for Periodic Underwater Inspections are performance-based and require certain pipeline operators to develop procedures to identify and take appropriate action for lines that pose a hazard to navigation or are otherwise exposed. The Office of Pipeline Safety suggests the use of risk analysis when developing the rationale for inspection intervals. RCP’s development of a proven integrity management risk model has enabled us to translate that success into development of a similar approach to identify underwater inspection intervals.

If you would like information regarding RCP’s Underwater Inspection Procedures or Interval Risk Modeling e-mail Jessica Roger or call (713) 655-8080.

O&M Manual Up-To-Date?

RCP has the tools and expertise to develop comprehensive procedures that you need to protect your people, facilities, and environment. Click Here

Public Meeting on Applying, Interpreting, and Evaluating Data from ILI Devices

Editor’s note: I apologize for the length of the following article, but I think you will find the information very helpful in understanding OPS’s concerns on this topic.

The Office of Pipeline Safety (OPS) is hosting a public meeting to discuss concerns it has with how operators are applying, interpreting, and evaluating data acquired from In-Line Inspection Devices (ILI), and OPS’s expectations about how operators should be effectively integrating this data with other information about the operator’s pipeline. The meeting will be held Thursday, August 11, 2005, from 8:30 a.m. to 4.30 p.m. in Houston, TX, and is open to all interested parties. The meeting location has not been determined yet and will be made available on shortly.

ILI technology has been used for approximately 20 years and has become the preferred method used by pipeline operators to ensure the integrity of their pipeline assets. However, as demonstrated by recent accidents on hazardous liquid and natural gas pipeline systems, some pipelines that were inspected by ILI devices continue to fail. OPS will share its findings from these accidents and from recent Integrity Management Program (IMP) inspections. OPS needs to determine if the problem resides in the technology or in the secondary and tertiary stages of the ILI data evaluation-data characterization, validation, and mitigation. Specifically, is the problem data analysis, peer review of technicians involved in data review, lack of common standards for data review, detection thresholds, data validation, or the understanding of each tool’s strengths and weaknesses? A secondary objective of this meeting is for OPS to understand how the government, pipeline operators, standards organizations, and ILI vendors can help improve pipeline assessment using ILI technology. At this public meeting, OPS will highlight effective practices and use this medium to share these practices with the public.

The preliminary agenda for this meeting includes briefings on the following topics:

  • OPS’s Experiences on Data Extracted using ILI Devices
  • OPS Case Studies
  • Hazardous Liquid IMP Inspection Experiences
  • Views of Pipeline Operators
  • Perspective from ILI Vendors
  • Focus of Independent ILI Data Analysts
  • ILI Standards
    • Personnel Qualification and Vendor Reports
    • ILI Flaw Detection Criteria
    • ILI Data Discrimination
    • Field Evaluation of ILI Data-Statistical Sampling, Flaw Thresholds, and Tolerances
    • Contractual Criteria for Defect Reports
  • Next Steps

OPS is concerned about the secondary and tertiary evaluations being performed after ILI data is acquired because of several accidents that have occurred throughout the U.S. in the recent past. According to OPS’s experience, failures have occurred on pipelines inspected by all types of ILI tools. The following are some examples of pipelines that failed relatively soon after the pipelines were inspected, the data was analyzed, and the findings were reported to the pipeline operators:

  • In 1999, a small hazardous liquid pipeline operator used a state-of-the-art tool and mis-characterized a “wrinkle with a crack” as a “T-piece.” A few months later the pipeline ruptured at the location of this wrinkle. Most appurtenances and fittings like a T-Piece will be welded to the main pipe. However, there were no girth welds on either side of this mis-characterized T-piece as is typical for a T-piece.
  • In 2003, a hazardous liquid pipeline that was inspected just about a year before, failed in service. OPS’s investigation revealed that general corrosion caused the failure. On analyzing the data, OPS gathered that the ILI tool detected some pitting and the maximum pit depth was reported to be less that 50% of remaining wall. However, from a metallurgical analysis of the pipe segment OPS discovered 27 corrosion pits varying from 18% wall loss to 95% wall loss. The pipe failed where the wall loss was 95%.
  • In February 2004, a natural gas pipeline operator launched a geometry pig but the tool missed a series of wrinkles. One of those wrinkles ruptured. During our post-incident investigation OPS discovered that other wrinkles in the pipe were called out as pipe wall thickness changes although there were no girth welds adjacent to the location where the wall thickness changed.
  • Another hazardous liquid pipeline that was inspected seven times with different tools in a span of 10 years ruptured in 2004. The rupture was determined to have been caused by general corrosion. The general corrosion was detected by an ILI tool launched before the most recent ILI run.
  • In October 2004, a hazardous liquid pipeline operator launched three tools-a geometry pig, a corrosion detection pig, and an axial flaw detection pig-in relative succession to conduct a baseline assessment and to comply with the IMP regulations. About six months after these tools were launched, the pipeline’s seam split.
  • In November 2003, incipient third party damage caused another hazardous liquid pipeline to rupture just eight months after it was pigged. An investigation revealed several longitudinal scratches and gouges on the pipe surface that were undetected by the ILI device.

OPS has also learned that pipeline operators do not have a consistent, standardized process to evaluate and assess data extracted by ILI devices. For example, some pipeline operators provide guidance to ILI vendors, contract field inspection personnel, and company personnel on how to assess ILI data. Others rely entirely on the ILI vendor or may actively participate in data extraction, or may even conduct an independent peer review of the ILI data if they have in-house expertise. For corrosion anomalies, pipeline operators use different interaction criteria. Some pipeline operators want only the deepest pit reported on each pipe length. Others want all pit depths reported. One pipeline operator directed the ILI vendor to report all anomalies, especially those with signatures that are indecipherable. OPS believes this to be a good practice, although it is not universally applied.

OPS believes that most of the pipeline failures that occurred on pipeline segments that were inspected with ILI tools could have been prevented with the correct application of technology. The failures that OPS investigated have revealed that the larger problem may be with the machine-man interface during the latter stages of data analysis. Specifically, should the repositories of flaw signatures that ILI vendors use be improved? Must there be more attention expended on the peer review of technicians? Is the sample size used to confirm electronic data adequate or must it be increased? Should the data extraction process be more stringently monitored?

During this public meeting, OPS will seek answers to the following questions:

  • What are operators’ experiences and expectations with the capabilities of ILI technology?
  • Is there a gap in understanding ILI tool data submitted by vendors of this technology?
  • Do ILI technology vendors educate their clients about the limitations of the tool being recommended for the application?
  • What defect detection and report criteria are used? Is it developed jointly by the vendor and the pipeline operator?
  • How are tool defect identification tolerances applied in reported criteria?
  • Is there a formal detection, validation, and mitigation process used to evaluate defects? How is it communicated to the pipeline operator?
  • What process is used to arrive at the number of confirmatory digs to corroborate the data extracted by the ILI device?
  • Are the standards developed for ILI technology appropriate for the current state ILI deployment? Does the guidance meet the needs of the large or small pipeline operator who is the first-time user of such technology?

OPS expects at this public meeting to inform on the following:

  • The technique and criteria used to report defects
  • Information exchange between the ILI vendor and pipeline operator during the secondary and tertiary stages of flaw characterization
  • The currency and adequacy of performance standards for vendors of assessment technologies
  • Sufficiency and relevance of performance standards for ILI assessment technology
  • Stages in data discrimination: Detection, validation, and mitigation

Need to Update Your Current Operator Qualification Program?

We have the expertise to update your current operator qualification program to satisfy the upcoming regulation change and inspection protocols. Click Here to request more information.

Beginning Steps on Pipeline Security Legislation

The joint majority and minority staff of the Senate Committee on Commerce, Science and Transportation hosted a meeting this week to discuss sections 406-408 of S.1052, which would establish a federal pipeline security program.  The bill outlines a plan for the Federal Government to provide increased security support to the most critical interstate and intrastate natural gas and hazardous liquid transmission pipeline infrastructure and operations. It also discuses the need for an incident recovery protocol plan to ensure the continued transportation of natural gas and hazardous liquids to essential markets in the event of an incident affecting the interstate and intrastate natural gas and hazardous liquid transmission and distribution pipeline systems.

Under S.1052.407, a complete review of the pipeline security plans and inspection of the critical facilities of the 100 most critical pipeline operators will occur in order to target inspection and enforcement actions to the most vulnerable and critical pipeline assets and correctly assess regulatory demands.

The bill has the Transportation Security Administration of the Department of Homeland Security in the lead with support from both public and private entities in the form of interstate and intrastate transmission and distribution pipeline operators labor, first responders, shippers of hazardous materials, State Departments of Transportation, public safety officials and other relevant parties. But, this bill requires a memorandum of agreement with the Department of Transportation to divide up the roles and responsibilities in ensuring pipeline security between these two agencies.  The recent terrorist attack on the mass transit system in London probably increases the odds of passage of a comprehensive security package for critical transportation assets and other at-risk facilities such as chemical plants.  You can get a copy of the bill at

Integrity Management Plan Up-to-Date?

RCP has the tools and expertise to develop comprehensive Integrity Management Plans for both liquid and gas pipelines. Click Here if you would like information on RCP’s Integrity Management Services and receive a copy of our FREE Integrity Management CD.

Integrity Management Notification for Gas Transmission Lines

Current regulations (49 CFR 192, Subpart O)  require operators of gas transmission lines to notify OPS and state pipeline safety agencies of certain events related to integrity management programs for gas transmission lines. Operators are required to notify OPS of each of the following events: a) when the operator makes substantial changes to the operator’s integrity management program, b)  when the operator plans the use of technology other than in-line inspection, pressure testing, or direct assessment to perform assessments of pipeline integrity, and c). when the operator cannot meet the schedule required for remediating an identified condition and cannot provide safety through a temporary reduction in operating pressure or other action.  The Office of Pipeline Safety has issued an Advisory Bulletin (ADB-05-04) to provide guidance on notifying OPS and state agencies and describes OPS’ review of notifications. OPS expects this bulletin to improve the efficiency of the notification and review process.

For Further Information Contact: Zach Barrett by phone at (405) 954–5559 or by e-mail.

Are Your Response Plans Current?

RCP can provide audits and updates to help ensure that your spill and emergency response plans are current and meet federal and state requirements. Click Here.

Congress Clears Energy Bill

The US Senate approved a national energy plan 74-26 on July 29th. With this vote, the Conference Committee on the energy bill (H.R. 6) issued a report confirming that the reform is now ready for the President’s signature, as the bill cleared the House of Representatives earlier. The President is expected to sign the bill, thus creating “The Energy Policy Act of 2005.”  The bill provides a mix of tax breaks, fuels, employment opportunities, cleaner burning coal, and the next generation of nuclear reactors. Some highlights include:

  • FERC “shall have exclusive authority to approve or deny an application for the siting, construction, expansion, or operation of an LNG terminal.”  States maintain their existing authorities under otherwise applicable environmental laws. 
  • FERC is the lead agency in reviewing permits for projects required under Section 3 or Section 7 of the Natural Gas Act.  The Energy Bill also mandates that FERC has authority to set the schedule for “all Federal authorizations.”  The FERC record is also established as the official record for any appeals under the Coastal Zone Management Act, or in court reviews of Federal and state administrative actions related to the proposed project.  The Energy Bill also establishes the judicial review process for permitting decisions.  It also requires FERC to establish regulations for the pre-filing/public consultation process.
  • The Secretary of Interior is to conduct an inventory and analysis of oil and gas resources found in the U.S. Outer Continental Shelf within six months of enactment.  The Secretary of Interior must also submit the results of the inventory in a report to Congress, which will include a description of “how legislative, regulatory, and administrative programs or processes restrict or impede the development of identified resources and the extent to which they affect domestic supply, such as moratoria, lease terms and conditions, operational stipulations and requirements, approval delays by the Federal Government and coastal States, and local zoning restrictions for onshore processing facilities and pipeline landings.”
  • The Secretary of Commerce will have deadlines for the review of appeals on decisions regarding whether federal activities that affect the coastal zone are consistent with State management programs. 
  • “Federal Permit Streamlining Pilot Project” – The Secretaries of Interior and Agriculture, the EPA Administrator and Chief of the Army Corps of Engineers are required to enter into an MOU to establish a pilot project within 90 days of enactment.  The pilot project will be conducted in Wyoming, Montana, New Mexico, Colorado and Utah.  Within three years, the Secretary of Interior must report on the “results of the Pilot Project to date” and “whether the Pilot Project should be implemented throughout the U.S.” 
  • Energy R-O-W Corridors on Federal Land are addressed by agencies in consultation with FERC, the States, tribes and utilities with designated “corridors for oil, gas, and hydrogen pipelines and electricity transmission and distribution facilities on Federal land in eleven western States.  The designation requires, within two years, an advance environmental review likely to make the siting of facilities within designated corridors much less challenging.  Agencies have four years to designate similar corridors on federal lands in the other 39 states.  Agencies are required to expedite applications to construct or modify pipelines within [these] corridors.”
  • The Bill calls for Progress Reports on Alaska Natural Gas Pipeline within six months of enactment, and every six months thereafter until the Alaska Natural Gas Pipeline begins operating, FERC must report to Congress on “the progress made in licensing and constructing the pipeline, and any issues impeding that progress.”

For more information regarding the “Energy Policy Act of 2005” including text and highlights, visit the Committee on Energy and Commerce on their website.

Temporary Water Right Authorizations Required from Texas Commission on Environmental Quality

The Texas Commission on Environmental Quality (TCEQ) requested that the Texas Railroad Commission post an advisory notice concerning use of surface water in association with oil and gas activities.

Water flowing in Texas creeks, rivers, and bays is state water or “waters of the state.” Under Section 11 of the Texas Water Code anyone who diverts water must have authorization – or water right — from the State of Texas through the Texas Commission on Environmental Quality (TCEQ). Persons who withdraw “waters of the state” for mining, construction, and oil and gas activities must obtain a water rights permit from TCEQ. An applicant may apply for a Temporary Water Right permit for short-term use of “waters of the State.” Temporary Water Rights permits authorizing use of 10 acre feet or less and for one year or less may be issued by your closest TCEQ. Applicants who seek to use more than 10 acre-feet of water or who seek a term of more than one year (up to a maximum of three years) will need to apply through the TCEQ Water Rights Permitting Team in Austin.

TCEQ forms, fees, contacts and other information may be found online here.

Pipeline Professionals Referrals

From time to time, we are asked by pipeline operators if we know of any qualified pipeline professionals that are active in the job market.  In addition, RCP is always interested in highly qualified individuals in the job market that have expertise in regulatory compliance management.  If you are aware of any pipeline professionals that are active on the job market, please let them know to contact us.  They can send their inquiries discreetly to  At the present time, we are aware of several opportunities, including:

  • Pipeline Integrity Management – Assessment Coordinator, Data Analysis, Program Implementation Management
  • Pipeline Facility Permitting Engineer
  • Environmental Coordinator
  • FERC Inspector
  • Construction Safety Coordinator 

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