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 rulemaking 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 rulemakings 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.

PHMSA has corrected the Final Rule published in the Federal Register on May 19, 2005 (70 FR 28833). That Final Rule amended requirements for pipeline operators in 49 CFR parts 192 and 195 to develop and implement public awareness programs and incorporated by reference the guidelines of the American Petroleum Institute (API) Recommended Practice (RP) 1162.

The final rule had an inadvertent language inconsistency between 192.616 (c), requiring operators to “follow the general program recommendations of API RP 1162”, while 195.440 (c) specified that the operator “must follow the general program recommendations, including baseline and supplemental requirements of API RP 1162”. PHMSA intended the amending language in parts 192 and 195 to be consistent. The language used in part 192 has been amended to match the language in part 195, which clarifies that the operator must follow both baseline and supplemental requirements of API RP 1162.

The document was assigned the amendment numbers 192-100 and 195-84, which were already assigned to different amendments. The correct amendment numbers are 192-99 and 195-83. These changes are effective June 20, 2005.

On February 23, 2005, the U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration, Office of Pipeline Safety (OPS) issued a final rule adopting as a final rule, the interim final rule which was issued on January 5, 1993. This final rule also made minor amendments to some of the regulations in Part 194 in response to public comments and the experience that OPS gained in implementing the interim final rule, leading spill response exercises, and responding to actual spills. The amendments were generally technical in nature and did not involve additional costs to pipeline operators or the public.

In issuing the final rule, a table was inadvertently misprinted. This table in §194.105(b)(3) specifies the potential spill volume reduction credits operators may use when they have secondary containment and other spill prevention measures on breakout tanks. These spill reduction credits are used when calculating the worst case discharge volume.  The correct table is given below:
(b) * * *
(4) Operators may claim prevention credits for breakout tank secondary containment and other specific spill prevention measures as follows:

The U.S. offshore oil and natural gas industry, in collaboration with its regulatory agencies, is hosting the Offshore Hurricane Readiness and Recovery Conference, July 26-27, 2005, at the InterContinental Houston Hotel [713-627-7600]. This conference is targeted to people in industry, government or other groups involved in Emergency Response; Design, Installation and Operation of Offshore, Shore-base Terminals; Drilling; and Offshore Oil and Gas Service and Supply. Industry experts, including representatives from the USCG and the MMS, will share their insights on:

• Perspective of Regulators
• Planning and Response Best Practices
• Metocean: Hindcast, Historical Perspectives, and Forecasting
• Performance of Drill Rigs, Production Facilities and Pipelines

On day 2, breakout sessions will delve deeper into the analysis of Hurricane Ivan and give participants the opportunity to discuss the performance and adequacy of design standards on Drilling Rigs, Production Facilities, and Pipelines. These discussions will influence the direction of future industry studies.

The conference cost is $600.00, discounted to $475 if registered by July 15, 2005 [government rates of $500 / $375]. Additional information and on-line registration is available here.

After a unanimous working committee vote in April, the proposed ASME standard on pipeline operator qualification, B31Q, went to ballot on May 27, 2005. After a 30 day ballot period, there were 7 negative ballots received. Under the ASME standard development guidelines, each negative ballot must contain specific technical reasons for the negative vote. These negative comments will be addressed to the extent possible. Any revisions will be re-balloted – hopefully by the end of this summer. The final standard could be officially approved by ASME in the 4th quarter of 2005. After that time, OPS may initiate a rulemaking to incorporate the B31Q standard into the federal pipeline safety regulations.

The Federal Energy Regulatory Commission (FERC) has amended its regulations for gaining access to critical energy infrastructure information (CEII). These changes are being made based on comments filed in response to the March 3, 2005, notice seeking public comment on the effectiveness of the Commission’s CEII rules. The final rule removes federal agency requesters from the scope of the rule, modifies the application of non-Internet public (NIP) treatment, and clarifies obligations of requesters. It also discusses changes that will be made to non-disclosure agreements. The rule is effective June 28, 2005. For additional information, please contact Jessica Roger at Jessica.roger@your-rcp.com.

The Office of Pipeline Safety (OPS) seeks public comments on two petitions for rulemaking filed by Arkema, Inc. The petitions request changes to the gas pipeline safety regulations to increase the design factor for new polyamide-11 (PA-11) pipe from 0.32 to 0.40, and to allow use of PA-11 pipe for systems operating at up to 200 pounds per square inch gauge pressure (psig). These requested changes will allow the use of PA-11 pipe in gas pipelines in place of metal pipe. Interested persons are invited to submit written comments by August 22, 2005 [docket No. PHMSA-05-21305].

Arkema asserts that pipelines with the new PA-11 material will pose less risk to the public at a design factor of 0.40 than older thermoplastic piping materials used with a 0.32 design factor and that allowing an increased design pressure will allow gas companies to replace metal piping systems with 2-inch plastic pipe operating up to 200 psig to avoid the risk of corrosion failure in steel pipes. A detailed technical justification, including performance test results for PA-11 pipe and a discussion of its history of use, is provided in the petition, which may be read in its entirety in the docket.

The Director, Office of Water, EPA Region 10, proposes to extend the area of coverage of the general NPDES permit for Offshore Oil and Gas Exploration Facilities on the Outer Continental Shelf and Contiguous State Waters (AKG280000) to include the northern portion of the Hope Basin and other Outer Continental Shelf (OCS) areas along the northeast boundary that are within the MMS current 5-year oil and gas leasing program. The proposed general permit and fact sheet may also be found on the EPA Region 10 Web site at http://www.epa.gov/r10earth.htm, click on Water Quality, then click on NPDES permits under Programs, and then click on draft permits under EPA Region 10 Information.

Brigham A. McCown has been named the Deputy Administrator for the newly created Pipeline and Hazardous Materials Safety Administration. He most recently served as the first Chief Counsel of the Federal Motor Carrier Safety Administration where he was responsible for oversight of legal and legislative issues involving the commercial motor carrier, motor coach and moving industry. Prior to joining the department in 2003, he was a member of Winstead Sechrest & Minick P.C., a Dallas based law firm where he specialized in litigation and government relations. McCown spent the last 17 years as an aviator and reserve duty with the U.S. Navy. During this time has participated in Operation Desert Storm, Haiti’s Operation Support Democracy, counter narcotics operations and most recently in Operation Unified Assistance where he participated in Tsunami relief operations in Southeast Asia. He earned a Bachelor of Arts degree in Diplomacy and Foreign Affairs from Miami University, Oxford, Ohio, in 1988, and a law degree from Northern Kentucky University in 1997.

In response to a request from the public, the Coast Guard is once again reopening the public comment period on a petition from the City of Fall River, Massachusetts. Fall River’s petition asks the Coast Guard to promulgate regulations establishing thermal and vapor dispersion exclusion zones for marine spills of liquefied natural gas, similar to Department of Transportation regulations for such spills on land contained in 49 CFR 193.2057 (Thermal radiation protection) and 193.2059 (Flammable vapor-gas dispersion protection).

A report, “LNG Facilities in Urban Areas” was not released until May 9, 2005-the day the docket was scheduled to close. On May 24, 2005, the report was filed in the docket: Clark Report, Item 76 in docket USCG-2005-19615. The Coast Guard was requested to reopen the comment period again, so that the report may be reviewed and comments on it may be submitted to the docket. In response to this request, the Coast Guard is reopening the comment period. The public is invited to review the referenced report and other material contained in the docket and to submit relevant comments by August 22, 2005 [Coast Guard docket number USCG-2004-19615]. The Coast Guard will consider the City’s petition, any comments received from the public, and other information to determine whether or not to initiate the requested rulemaking.

On June 30, 2005, the Federal Energy Regulatory Commission provided guidance on how jurisdictional natural gas companies should account for costs associated with implementation of new pipeline integrity management requirements. OPS estimates the cost of compliance with the IM Regulations for jurisdictional and non-jurisdictional entities will be $4.7 billion over 20 years. The Commission found that the costs to: (1) prepare a plan to implement the program; (2) identify high consequence areas; (3) develop and maintain a record keeping system; and (4) inspect affected pipeline segments should be expensed. The Commission further clarified that costs of modifying pipelines to permit in-line inspections, such as installing pig launchers and receivers, should be capitalized consistent with the Commission’s existing rules for plant additions. Similarly, certain costs associated with developing or enhancing computer software or costs incurred to add or replace other items of plant also should be capitalized. However, minor items of property replaced as part of a remedial action should continue to be expensed. The order makes this guidance effective January 1, 2006, and prospective in application. Amounts capitalized in periods prior to January 1, 2006, will be permitted to remain as recorded. For more information, see the Commission’s website  at www.ferc.gov, docket No. AI05-1-000.

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 http://ops.dot.gov 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 mischaracterized 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 mischaracterized 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 analyses. 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