Are You Ready For DIMP?

November 2009 Vol. 236 No. 11

Eric Kirkpatrick, Structural Integrity Associates, Inc

In August, the Pipeline and Hazardous Materials Safety Administration (PHMSA) informed the Technical Pipeline Safety Standards Committee (TPSSC) that the proposed rule on Gas Distribution Pipeline Integrity Management (commonly referred to as DIMP) has been approved by the DOT and sent to the Office of Management and Budget (OMB). The OMB is expected to review and approve a DIMP rule in the 4th quarter of 2009. Perhaps by the time you read this the final rule may already be published.

The Notice of Proposed Rulemaking (NOPR) issued in June 2008 requires each operator of a gas distribution system to fully implement an integrity management program within 18 months that contains the following elements:

  • Knowledge
  • Identify Threats
  • Evaluate and Prioritize Risk
  • Identify and Implement Measures to address Risk
  • Measure Performance, Monitor Results, and Evaluate Effectiveness
  • Periodic Evaluation and Improvement
  • Report Results

Eighteen months will go by very quickly! So, what can operators be doing right now? The following is provided to help gauge your readiness:

The NOPR requires that operators demonstrate an understanding of their gas distribution system. Operators will therefore want to assess the manner in which they collect data, and subsequently how they turn that data into information and knowledge that can be used in their Integrity Program.

Operators will want to survey and determine what information they already have and in what format it exists (paper, spreadsheet, database, etc.). The NOPR requires that operators gather data from the following sources to indentify existing and potential threats: incident and leak history, corrosion control records, continuing surveillance records, patrolling records, maintenance history, and ‘‘one-call’’ and excavation damage experience.

It is suggested that operators perform a gap analysis between the data (and data format) they currently have available and what they ultimately desire to support their integrity program. In doing so, they will want to consider the following questions:

  • Does my leak repair data contain sufficient root cause, facility type and location detail to support my goals for threat identification and risk evaluation?
  • How do I collect information on incidents that are not otherwise recorded in Leak Records and Reportable Gas Incidents? Am I capturing what I need?
  • Does my equipment failure reporting process provide data that I can use to identify threats?
  • Am I able to data-mine my corrosion records in a manner that will support the program?
  • Do my main and service records provide sufficient detail and accessible format to support the program?
  • Do my surveillance and patrol records provide information on areas of my system that are susceptible to threats from natural forces such as earth movement, flood prone areas and seismic fault lines?
  • Is my one call and excavation damage data organized in a manner that allows me to determine which areas of the system have the highest ratio of damage per ticket?
  • Does the data available support the manner in which I desire to perform risk evaluation and prioritization?
  • Does the data allow me to target mitigation efforts to those areas/facilities of highest risk, or do I have to broadly apply mitigation due to lack of adequate knowledge?
  • Does my data allow me to adequately measure performance, monitor results and evaluate effectiveness?

Not all knowledge is bound up in databases. Operators will also want to carefully consider and plan the manner in which they collect and record knowledge from subject matter experts within their organization. Employees who regularly perform system maintenance and other activities may have knowledge that is not readily apparent to the rest of the organization. These subject matter experts may also play key roles in threat identification and the evaluation and prioritization of risk.

Identify Threats
The NOPR requires operators to consider the following categories of threats: corrosion, natural forces, excavation damage, other outside force damage, material or weld failure, equipment malfunction, and inappropriate operation. The last category of threat is “any other concerns that could threaten the integrity of the pipeline.”

Operators may wish to familiarize themselves with NTSB reports and PHMSA bulletins related to gas distribution. The respective websites are:
NTSB Pipeline Accident Reports:
NTSB Safety Recommendation Letters:
PHMSA Advisory Bulletins:

Though far from complete, and certainly not applicable to every operator’s system, following is a more detailed list of possible subcategories of threats that operators may wish to consider:

Evaluate and Prioritize Risk

  • The NOPR established the following requirements for risk evaluation and prioritization:
  • Consider each applicable current and potential threat
  • Consider the likelihood of failure (relative probability) associated with each threat
  • Consider the potential consequences of such a failure
  • Estimate and prioritize risks

There are many possible methodologies that may be employed to evaluate and prioritize risk, ranging from Subject Matter Expert methods that rely on knowledgeable persons to statistical and mathematical methods that use algorithms to convert data into risk scores. After performing a gap analysis on data availability, operators should determine what approach to take initially in order to fully implement their program within the 18 month time requirement.
Operators may also wish to establish their long-range goals for risk evaluation, such as deployment and/or enhancement of a GIS based system to facilitate program objectives. These long-range goals may not be achievable within the first 18 months so operators may wish to craft a road-map of how they intend to progress over time.

Identify And Implement Measures To address Risk
The NOPR requires operators to determine and implement measures designed to reduce the risks from failure of its gas distribution pipeline system. Operators can start this process by ensuring that they have implemented an effective leak management program and enhanced their damage prevention program as required by §192.614 of Code of Federal Regulations Part 192.

Operators should ensure that they put in place a sufficiently aggressive schedule that ensures completion of risk identification and risk assessment processes in time to allow for implementation of appropriate mitigation within the 18-month time requirement.

Measure Performance, Monitor Results, and Evaluate Effectiveness
The NOPR requires that operators develop and monitor performance measures from an established baseline to evaluate the effectiveness of its Integrity Management program and provides a number of mandatory performance measures. In addition to the list of mandatory measures, the rule also states: “any additional measures to evaluate the effectiveness of the operator’s program in controlling each identified threat”. It is strongly suggested that operators establish performance measures as soon as possible in order to ensure that appropriate data will be available to establish the baseline and systems in place for ongoing monitoring of results.

Operators have a number of resources available to assist them. These include:

  • The PHMSA website for Distribution Integrity Management
  • ANSI GPTC Z380.1-2009 Guide Material for Distribution Integrity Management Program
  • Training, conferences, workshops and webinars available from many of the industry’s gas associations, among them the SGA and NGA.
  • Written DIMP programs are available from some of the gas associations as well as private consulting firms.
  • Risk assessment software and support from many leading software firms.

Roles And Responsibilities
Successful implementation of a Gas Distribution Integrity Management program will require a clear plan of action and focused effort. Operators should ensure that they have allocated sufficient resources and have established clear accountability, roles and responsibilities within their organization at the very onset of their efforts. Remember, from the date the rule is published, operators may have less than 390 workdays to implement their programs.

Eric Kirkpatrick is a Senior Associate with Structural Integrity Associates and is the principal architect of the leading DIMP plan framework and implementation guide developed for the Northeast Gas Association (NGA) and Southern Gas Association (SGA). He has more than 25 years of experience in gas transmission and distribution engineering, maintenance and operations. He holds a BS degree and Professional Engineering License in Mechanical Engineering as well as a Master of Business Administration degree. He can be reached at