DOT Pipeline Compliance News
December 2009 Special Edition

This is a special edition of the RCP DOT Pipeline Compliance Newsletter. Unfortunately the DIMP and Control Room Management regulations were published immediately after the December newsletter was distributed. We felt that these new regulations were significant enough to warrant a special edition of our newsletter versus waiting until January’s edition was distributed. The articles provide a breakdown of the rule requirements, including some pertinent elements that were only included in the preamble to these rules. As usual, RCP is available to discuss these issues and provide support where desired.

Distribution Integrity Management Program – Final Rule
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On December 4th, The Department of Transportation/Pipeline Hazardous Materials Safety Administration (PHMSA) published the final rule for Distribution Integrity Management Programs (DIMP) which is applicable to gas distribution operators and becomes effective on February 2, 2010. The DIMP regulations are listed in Part 192 as a new Subpart P – Gas Distribution Pipeline Integrity Management and include the following provisions.

Five new definitions have been incorporated under 192.1001. Some key definitions include:

• Excavation Damage follows closely with the Common Ground Alliance definition. This is defined in the rule as “any impact that results in the need to repair or replace an underground facility due to a weakening, or the partial or complete destruction, of the facility, including, but not limited to, the protective coating, lateral support, cathodic protection or the housing for the line device or facility.”
• Hazardous Leak “means a leak that represents an existing or probable hazard to persons or property and requires immediate repair or continuous action until the conditions are no longer hazardous.”
• Small LPG Operator “means an operator of a liquefied petroleum gas (LPG) distribution pipeline that serves fewer than 100 customers from a single source.”

• Knowledge of the gas distribution system developed from reasonable available information. In the preamble, “PHMSA does not intend that operators expend excessive effort, review every record available in their archives, or explore every nuance about their pipelines. At the same time, PHMSA expects that operators will devote sufficient effort to develop as thorough an understanding of their pipelines as they can while using reasonable effort.”
• Identify threats such as corrosion, natural forces, excavation damage, other outside force damage, material, weld or joint failure (including compression couplings), equipment failure, incorrect operations, and other concerns.
• Evaluate and rank risks associated with the distribution systems. The risk assessment process allows distribution systems to be divided and evaluated based upon geographic location or by regions with similar characteristics or for which similar actions would result in reduced risk.
• Identify and implement measures to address risk, including effective leak management programs.
• Measure performance, monitor results, and evaluate effectiveness of the operator’s DIMP. PHMSA will revise the gas distribution annual report to include the following information. Gas distribution operators are expected to periodically review this and other data to evaluate whether their DIMP programs are being effectively implemented.
• Number of hazardous leaks either eliminated or repaired, categorized by cause
• Number of hazardous leaks either eliminated or repaired, categorized by material
• Total number of leaks either eliminated or repaired, categorized by cause
• Number of excavation damages
• Periodic evaluation and improvement of their DIMP, including re-evaluation of threats and risks across the entire distribution pipeline system. PHMSA mandates that a complete program re-evaluation occur at least every 5 years. In the preamble PHMSA explained their intention for re-evaluation frequency. “An operator should re-evaluate its IM program whenever changes occur in the system that may result in new knowledge, new threats or other information that would permit improvement in their IM program. For some operators, this may be more frequent than an annual basis. For other operators, these types of changes may occur seldomly.”
• Report results of the four performance measures listed above as part of the gas distribution pipeline annual report.

• Include information on the annual report related to compression coupling failures that result in hazardous leaks.
• Records that demonstrate compliance with this rule must be retained for a minimum of 10 years, including copies of superseded IM plans.
• Requires installation of excess flow valves on any new or replaced service lines that service a single family residence after February 2, 2010. Operators are required to include on the annual report, the number of excess flow valves installed. There are some exceptions to the excess flow valve installation requirements, including:
  
  • Service lines that do not operate at 10 psig or greater throughout the year
  • Experience with contaminants in the gas stream that would interfere with the excess flow valve operation or cause loss of service to the residence
  • The excess flow valve would interfere with necessary operations and maintenance activities such as blowing liquids from the line
  • An excess flow valve meeting minimum performance standards is not commercially available.
• The final rule also allows for gas distribution operators to propose alternative frequencies for inspections and tests required by Part 192. An operator must submit a proposal to PHMSA and the applicable state agency requesting the change in inspection frequency, including the basis of the engineering analysis that provides for equivalent or improved overall level of safety.
• The preamble addressed whether the final rule applies towards new construction activities. PHMSA explains in the preamble that the final rule applies to existing gas distribution systems and is not intended to address construction of new gas distribution systems.
• Several items that were originally proposed were not included in the final rule. The two primary issues not included in the final rule were plastic pipe failure reporting and assuring individual performance (performance through people).

DIMP Services

RCP is able to provide gas distribution operators with fully compliant, customized Distribution Integrity 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 has modified our popular web-based compliance management system to incorporate all aspects of DIMP workflow, data management, risk analysis, and performance reporting. This system is easy to use, fast to implement, includes a robust GIS web portal and document manager, and is extremely cost effective. In fact, many of our existing clients are requesting that we convert some of their existing business processes into our compliance management system (customer databases, one-call screening, audit action item tracking, contractor work order generation, change management). The DIMP module seamlessly integrates with existing compliance processes to provide real-time risk as new data is incorporated from leak management, damage prevention, corrosion control and other day-to-day compliance activities.

RCP has been asked by several gas distribution operators to conduct DIMP readiness assessments and assist with their DIMP implementation strategy. This type of service evaluates existing operator processes for data capture, leak management, damage prevention, corrosion control, etc. against DIMP implementation requirements. Where existing processes need to be modified or created, RCP will help the operator develop and implement those in a timely and cost effective manner.

Finally, RCP can assist gas distribution operators with developing and implementing a DIMP risk analysis process that fits your existing organization and data management processes. This includes evaluation of your pipeline system configuration (ex. material, size, geographic locations, etc) to identify the optimal configuration to perform risk modeling and developing a risk algorithm that is simple to run and easy to interpret the results. Our current gas transmission and liquid integrity risk models have been developed on common platforms and completely transparent so that the pipeline operator have the ability to make modifications without having to sign long-term license agreements and download “black-box” software applications.

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

Control Room Management – Final Rule
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On December 3, 2009, The Department of Transportation/Pipeline Hazardous Materials Safety Administration (PHMSA) published their final rule on control room management for gas and liquid pipeline operators. The rule for gas pipelines is very similar to the rule for liquid pipelines, with some exemptions for certain gas pipelines, and some differences in how API RP 1165 is incorporated into the liquid rule. In general, the rules require that the operator:

• Establish and follow written control room management procedures
• Define the roles and responsibilities of a controller during normal, abnormal, and emergency operating conditions
• Establish shift change procedures, and record shift change information
• Manage fatigue, by establishing shift lengths and schedule rotations that provide controllers off-duty time sufficient to achieve eight hours of continuous sleep; educating controllers and supervisors in fatigue mitigation strategies and how off-duty activities contribute to fatigue; training controllers and supervisors to recognize the effects of fatigue; and establishing a maximum limit on controller hours-of-service
• Establish a written alarm management plan
• Review SCADA safety-related alarm operations to ensure alarms are accurate and support safe pipeline operations
• Require field personnel to contact the control room when emergency conditions exist and when making field changes that affect control room operations
• Review reportable incidents to determine if control room actions contributed to the event, and correct deficiencies
• Establish a controller training program that gives a controller a working knowledge of the pipeline system and that addresses the following topics: roles and responsibilities defined by the operator, recognizing and responding to abnormal operating conditions, communication responsibilities during emergency responses, advance review of seldom-used operating procedures, and lessons learned from incident reviews

• Test and verify an internal communication plan for manual operation of the pipeline
• Test any backup SCADA systems
• Verify the correct safety-related alarm set-point values and alarm descriptions
• Review the alarm management plan
• Monitor the content and volume of general activity being directed to and required of each controller to assure controllers have sufficient time to analyze and react to incoming alarms
• Review the training program

• Comply with API RP 1165 “Recommended Practice for Pipeline SCADA Displays”
• Conduct a point-to-point verification between SCADA displays and related field equipment
• Consult with control room representatives when planning and implementing physical changes to pipeline equipment or configuration.

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.

We have received considerable interest from many different pipeline operators to facilitate the development of a Control Room Management framework program in addition to a site-specific control room implementation program. If your company is interested in participating in this joint effort, please contact Jessica Roger.