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Gas distribution integrity management rule is on its way.

Later this year, the Pipeline and Hazardous Materials Safety Administration (PHMSA) will propose a major new regulation requiring utilities to prepare and follow written distribution integrity management programs (DIMP).

PHMSA published new rules requiring integrity management programs for hazardous liquid pipelines in 2000 and for natural gas transmission pipelines in 2003. Under these rules, operators of hazardous liquid and gas transmission pipelines were required to identify the threats to their pipelines, analyze the risk posed by these threats, collect information about the physical condition of their pipelines, and take actions to address applicable threats and integrity concerns before pipeline accidents could occur. The early results of these programs led PHMSA to consider whether a similar regulatory approach would be appropriate for gas distribution pipelines.

Advisory Group Formed

In 2005, PHMSA convened a working group composed of federal and state regulators, industry and the public to advise PHMSA on how to approach DIME The group quickly concluded that causes of and solutions to accidents on distribution fines were so different from those of oil and gas transmission lines that a different approach was necessary. It recommended the PHMSA enact a high-level, flexible rule with seven elements:

1. Develop an integrity management plan.

2. Know your infrastructure.

3. Identify threats (existing and potential).

4. Assess and prioritize risk.

5. Identify and implement measures to mitigate risks.

6. Measure performance, monitor results, and evaluate effectiveness.

7. Report results.

In December 2005, PHMSA submitted a report to Congress outlining how it would approach DIMP regulation. This "Phase 1 Report" is available for download from PHMSA's website. The current best guess is that PHMSA will propose a DIMP rule in early summer 2007, issue a final rule in early 2008 and--assuming PHMSA allows one year for implementation--operators will have until early 2009 to develop and follow a written DIMP plan.

While PHMSA has yet to issue proposed DIMP rules, its Phase 1 Report to Congress and guidelines being prepared by the Gas Piping Technology Committee (GPTC) provide some indication on what to expect.

Know Your Infrastructure

Infrastructure means the distribution piping system and all of its various components--piping, valves, regulators, cathodic protection systems, etc. Knowledge means knowing information about the design and construction of the piping--the material of construction, diameter, operating pressure, coating, etc. Knowledge also includes knowing operation and maintenance information. Has the pipe ever leaked? Have repairs been required? What were the causes of leaks? Have cathodic protection levels been adequate? Have visual inspections found problems with the pipe or coating?

Knowledge of the infrastructure forms the foundation for the entire DIMP plan. A DIMP plan for a bare steel system that has a history of corrosion leaks will be very different from a plan for an all-plastic system. The better the information that goes into this process, the better the final product will be.

Committee Guidance

The draft gas piping technology committee guidance contains an extensive list of knowledge elements. However, some elements will have a greater impact on the DIMP plan than others. For example, the material of construction will have a major impact on whether corrosion is a significant threat to a pipeline segment. On the other hand, the type of valve used for sectionalizing may have very little or no impact on the significance of any threat on a particular pipe segment.

The operator must decide whether to treat its distribution system as a single segment or treat different parts of the system as separate segments under its DIMP plan. An operator might choose to segment its system if parts of the system are significantly different than other parts, such as:

* Operate at significantly different pressures (e.g. 7 inches water column vs. 60 psia),

* Are constructed of different materials (e.g. polyethylene vs. bare steel or cast iron),

* Were installed in different eras (1950s vs. 1990s),

* Have significantly different maintenance histories (e.g. many leaks vs. few leaks), or

* Are operated as separate distribution systems (e.g. few or no interconnects).

Identifying Threats

The third of the seven elements of the DIMP rule will require each utility to identify threats to the integrity of its system. "Threats" are whatever can damage the pipe and cause accidents. The PHMSA's Phase 1 DIMP Report lists eight primary threats to distribution integrity:

1. Excavation.

2. Other outside force damage.

3. Natural forces.

4. Corrosion.

5. Material or welds (defects).

6. Equipment (malfunction).

7. Operations (errors).

8. Other.

Each operator will be required to assess whether any of these threats is significant on all of any portion of its distribution system. In doing this assessment, the operator will use the knowledge of the design, construction, operation and maintenance of its system that resides in its records and/or the experience of its operations and maintenance personnel.

There are many different approaches to the process of assessing threats. We do not expect that either the PHMSA rule or the GPTC guidance will force all operators to use the same method. The GPTC guidance, however, offers a series of questions that operators could consider in assessing each threat. For example, to assess the threat of external corrosion an operator would first consider the pipe material. If the pipe segment is plastic, corrosion is not a threat. If the segment is steel, the operator would consider additional questions such as:

* Is it coated and cathodically protected?

* Have cathodic protection levels been consistently adequate?

* Have there been corrosion leaks on this piping?

* Have exposed pipe inspections found coating damage or corrosion?

The answers to these questions provide the basis for ranking the significance of the threat of external corrosion to the pipeline segment.

Risk Assessment

The fourth of the seven elements of an operator's DIMP will be to assess and prioritize risk. Risk is a combination of the likelihood that a problem (e.g. excavation damage) will occur and the consequences that might result if it did occur. For example, bare, unprotected steel pipe that has a history of corrosion leaks has a greater probability of corroding than coated, cathodically protected steel pipe that has never had a corrosion leak. The pipe diameter, pressure, and location (e.g. rural or downtown, paved or unpaved) may impact the consequences in the event corrosion was to occur.

The GPTC guidance lists two methods for assessing and prioritizing risk. The methods ate relying on the judgment of operating and maintenance personnel (e.g. the "Subject Matter Expert Method") of using mathematical models (e.g. "Algorithm Methods"). There are a number of predictive models available and no doubt more will be developed as a result of the DIMP rulemaking.

Many models assign a numeric score to the factors that affect the probability or consequence of a threat, which, when totaled, produces a comparative risk score for each pipe segment. Other methods may simply ask the operator to rank the probability and consequences as low, medium or high, based on the operator's judgment of these factors.

Documenting the risk assessment and prioritizing process will be critical for the operator to be able to defend its plan internally and externally with state and federal regulators.

Taking Steps

The fifth of the seven elements of an operator's DIMP plan will be to identify and implement measures to mitigate the risks that were identified and prioritized in the previous step. Mitigating risk means taking steps to reduce the likelihood and/or the consequences of a problem.

The draft GPTC guidance offers a number of examples of risk-mitigating steps for each of the eight threats to distribution system integrity. Once an operator determines that a particular threat is significant on all or part of its system, the operator must determine what, if any, additional steps it must take to reduce the risk of that threat.

Operators may determine that no additional actions are required. Many operators are already taking steps to address problem areas of their systems and these measures may be sufficient to address identified threats.

Leak Management

The PHMSA DIMP working group also had extensive discussions about the significance of leaks for distribution integrity. On one hand, every leak is a loss of integrity of the pipeline. On the other hand, most leaks ate found and repaired before they become a threat to public safety. It was agreed that DIMP programs should include a program to manage leaks. The five elements of a leak management plan are:

* Locate the leaks in the distribution system,

* Evaluate the actual or potential hazards associated with these leaks,

* Act appropriately to mitigate these hazards,

* Keep records, and

* Self-assess to determine if additional actions are necessary to keep people and property sale.

Note that operators that always repair any leak, regardless of potential hazard, may omit the evaluation elements, however, any operator that allows some non-hazardous leaks to be monitored instead of being immediately repaired must include criteria in its DIMP plan for evaluating the potential hazard posed by each leak. The existing GPTC guidance includes a leak classification system that meets the intent of this requirement. The rule is not expected to force all operators to use the GPTC leak classification system. If an operator has a leak management system that includes the five previously listed criteria, it should include that in its DIMP plan.

Measure Performance

The sixth element of an operator's DIMP plan will be to measure performance, monitor results and evaluate effectiveness of the operator's DIMP plan. For each threat that the operator has identified as significant for all or any part of its system, one or more performance measures must be identified to allow the operator to determine if its DIMP program is achieving the desired results.

Each operator's DIMP plan will include both internal and external performance measures. Internal measures are those measures the operator tracks to self-assess whether the DIMP plan is working. External measures are data that will be submitted to federal and/or state regulators to be used to track the statewide or nationwide effectiveness of the DIMP regulations.

Tracking the number of corrosion leaks year to year might be a performance measure to determine if a program is effective at reducing the threat of corrosion. Similarly, tracking the number of dig-ins may be used to measure the effectiveness of damage prevention programs. APGA expects the final DIMP rule to leave it to each operator to define what internal performance measures are appropriate.

However, the rule may specify some information operators need to collect and submit to PHMSA and/or state pipeline safety agencies. The GPTC guidance will provide some examples of possible internal performance measures for each threat. Operators may choose from the GPTC list or develop their own internal measures.

If performance measures show a trend in the right direction, e.g. fewer corrosion leaks are occuring year to year, that indicates the operator's DIMP plan is working. If trends in the performance measures for any particular threat are going in the wrong direction, the operator will have to reconsider how it addresses that threat. This could mean going back to the list of mitigation options and trying something else.


The last of the seven elements is reporting. During the Phase 1 working group deliberations, various external performance measures were considered. It was recognized early on that reportable incidents were not a good performance measure since there are too few reportable incidents each year and too much variability year to year to allow for meaningful trending of reportable incidents. Likewise, leak repair data submitted in annual reports includes both hazardous and non-hazardous leaks and is not a reliable measure of safety.

One suggestion was to track trends in leaks that pose an immediate hazard to the public, e.g. Class 1 leaks under the GPTC system. This would require a change to the annual reporting forms as well as to the leak record keeping systems of many utilities. To minimize reporting burdens it is hoped that DIMP data can be included with each operator's annual report to PHMSA.

APGA/PHMSA Assistance

As much as PHMSA has sought to minimize the burdens of this rule, it recognizes that the majority of the distribution utilities that must comply with the DIMP rule are small and that compliance may pose an extreme burden to these utilities.

In August 2006, the APGA Security and Integrity Foundation (SIF) received funding from PHMSA to develop a model DIMP plan for small systems (referred to as "SHRIMP"--Simple Handy Risk-based Integrity Management Plan). The model plan will address each of the seven elements and provide a leak-management system.

As envisioned, it will function like tax preparation software, asking the user questions about the distribution system construction and maintenance history and generating an operator-specific written DIMP plan at the end of the process.

The goal is to have the model plan available at the same time PHMSA issues its final rule so that operators can compare the costs and benefits of using SHRIMP to develop their DIMP plan vs. other options. APGA also plans to conduct a series of state and regional workshops to assist operators to understand the rule and use the model plan to comply.

Author: John Erickson, PE, is vice president of operations, for the American Public Gas Association (APGA) in Washington, DC.
Distribution systems subject to 49 CFR 192

# of customers (from EIA Form 176)

 Municipal Investor-owned

<100 20
100-1000 438 35
1000-10000 354 59
10000-100000 50 69
100000-1 million 6 96
>1 million 0 10

Note: Table made from bar graph.
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Comment:Gas distribution integrity management rule is on its way.
Author:Erickson, John
Publication:Pipeline & Gas Journal
Geographic Code:1USA
Date:Jun 1, 2007
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