The material presented today and on the DIMP website was created - - PDF document

1 The material presented today and on the DIMP website was created through a collaboration of 6 State regulators and 6 OPS team members called the State-Federal DIMP Implementation Team. The Team was created about 5 years ago to support improvements in the integrity of the Nation’s gas distribution pipeline systems through development of inspection methods and guidance for evaluation of an Operator’s Distribution Integrity Management Program. Note that some material presented today was created through a consensus process. States will implement the DIMP rule under their individual state statutory authority and may establish their own procedures, inspection forms, and guidance in implementing the DIMP rule. Since State authority and regulatory structures differ, operators should contact the regulatory authority exercising jurisdiction over the their distribution pipeline for more information.

Today, we will discuss the following topics. (see slide if you desire to read the topics

• ut)

Finally, we will cover finish with a Q&A session. Note to presenter – The presentation is segmented into the following topics to allow for customization to your specific audience and their needs. When printing out the slides and speaker notes, be sure to use the “fit to page” print feature so as to have all the speaker notes for each slide. Portions can be deleted for the presentation to fit communication needs as well as time constraints. Time estimates provided for presenting the sections can be shortened by providing less discussion with each slide.

1. Safety Culture (slides 3-8) – time estimate 10 minutes 2. Initial Inspection Results and Findings (slides 9-44) – time estimate 40 minutes 3. Mechanical Fitting Failure Report Data/Analysis (slides 45-52) – time estimate 10 minutes 4. DIMP Inspection Forms (slides 53-55) – time estimate <5 minutes 5. DIMP Website and Performance Measures Reporting (slides 56-66) – time estimate 10 minutes 6. Current Regulatory Topics for Distribution Operators (slides 67-76) – time estimate 10 minutes

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• 7. Questions and Answers (last slide) – variable time estimate

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This section of the presentation is on DIMP Inspection Results and Findings

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Pipelines Will be Needed for the Foreseeable Future Pipelines are Private Infrastructure Serving Public Purposes for a Profit No Pipeline Operator Wants to Have an Accident, and the Regulator Less So

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DIMP Plan development and implementation were required to be complete August 2, 2011. State Programs and PHMSA have been conducting DIMP inspections since the implementation date of the Rule Today’s presentation will include some of the key findings from the inspections conducted to date and discussion of the expectations of regulators on these findings Regulators have commented that performance language based regulatory programs is a challenge to inspect. Time during inspections is required for drill downs of data sets and gathering a comprehensive understanding of an operator’s system. Inspectors are required to use judgment during their inspections in making decisions

• n compliance.

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The discussion of inspection findings is structured based on the requirements of the DIMP Rule, specifically those required elements in 192.1007. 192.1007 requires that a written integrity management plan must contain procedures for developing

and implementing the elements of 192.1007

(a) To meet the Knowledge of the system requirement, an operator must demonstrate an understanding of its gas distribution system developed from reasonably available information. (b) To address Threats identification, the operator must consider the categories of threats to each gas distribution pipeline: Corrosion, natural forces, excavation damage, other outside force damage, material, weld or joint failure (including compression coupling), equipment failure, incorrect operation, and other concerns that could threaten the integrity of its pipeline. (c) An operator must evaluate the risks associated with its distribution pipeline. In this evaluation, the operator must determine the relative importance of each threat and estimate and rank the risks posed to its pipeline. This evaluation must consider each applicable current and potential threat, the likelihood of failure associated with each threat, and the potential consequences of such a failure. (d) Identify and implement measures to address risks. An operator must determine and implement measures designed to reduce the risks from failure of its gas distribution pipeline. These measures must include an effective leak management program (unless all leaks are repaired when found). (e) The rule requires the operator to measure performance, monitor results, and evaluate effectiveness. An

• perator must develop and monitor performance measures from an established baseline to evaluate the

effectiveness of its IM program. (f) To address Periodic Evaluation and Improvement, an operator must re-evaluate threats and risks on its entire pipeline system and consider the relevance of threats in one location to other areas. (g) Operators are required to report, on an annual basis, the four measures listed in paragraphs (e)(1)(i) through (e)(1)(iv) of this section, as part of the annual report required by §191.11. An operator also must report the four measures to the state pipeline safety authority if a state exercises jurisdiction over the operator's pipeline. We will also discuss §192.1011 What records must an operator keep? An operator must maintain records demonstrating compliance with the requirements of this subpart for at least 10 years. The records must include copies of superseded integrity management plans developed under this subpart.

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Regulatory Expectations are that a DIMP was developed and implemented by August 2, 2011, and the Program should continue to be used, developed, and mature. Inspection Experience and feedback from some Operators is that DIMP inspection are positive experiences based on the interactions with Inspectors that provide meaningful insights into DIMP Implementation and solution-oriented comments. Operators should trust that they have implemented a sound DIMP, and do what your plan tells you to do. Communication within the organization of what DIMP means to each individual group is important for its successful implementation. Implementation may require a change in culture to put pipeline safety first and change the way business is done. The importance and usefulness of DIMP is not always understood - The DIMP is not just another book on the shelf, and resources must be allocated to manage the program.

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192.1007 requires that a written integrity management plan must contain procedures

for developing and implementing specific elements. The NAPSR/PHMSA DIMP

Implementation Team is compiling inspection issues associated with specific Program Development Models and working with the various Model Providers to resolve identified issues, as desired by the model provider. With regards to comments on Operator’s IM Plans and Models used to develop IM Plan, the following findings have been identified (during some of the inspections conducted to date):

• In some cases, Operations, Maintenance, and Inspection procedures were not adequately

integrated or referenced, when appropriate. An operator may need to provide reference to a specific O&M Procedure such as leak classification and monitoring procedures in the DIMP Plan.

• Procedures regarding roles and responsibilities need to be included in the plan. Plans

were found lacking specificity such as: who, what, when, where, how. For example, who will lead the periodic review – by position title; how will it be conducted – in person or via email or conference call; how often and what time of year; what procedures will be used to conduct the review and implement the necessary plan revisions.

• Some of the Plans were not state specific. Multistate operators are expected to address

local conditions in the plans and risk rankings and mitigative measures must be state

• specific. Although this is not specifically stated in the rule, it is impossible for a regulator in

Illinois to determine if the risk ranking makes sense when Iowa assets are included in the

• ranking. Therefore an operator may be allowed to have one multi-state plan, but be

required to have separate risk ranking and mitigative measures by state.

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Pre-DIMP risk reduction measures need to be incorporated into the DIMP plan. Operators may have been performing actions that exceeded code requirements prior to the effective date of the DIMP Rule, and these are referred to as Accelerated and Additional actions. These need to be accounted for as the evaluation of risk is now based on these actions being performed as a basis. Actions that the DIMP identifies as needed to reduce risk are now “required by the code”. If risk evaluation concludes new or additional risk reduction measures are not needed to address a particular threat, that is acceptable but needs to be explained and documented in the Plan. The DIMP rules may require something that is already being done in another context – copy it over or link to it as a reference in the DIMP. The Plan should culminate in a ranked/prioritized list of threats, risk reduction measures identified to be implemented, and metrics to measures the performance

• f the DIMP.

Treat DIMP as a tool to analyze needs and progress, not as a regulatory exercise.

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An operator should be able to demonstrate knowledge of their system by providing documentation and discussing their primary threats, the actions they are taking to address them, and the metrics used to measure their performance. [Conveniently, this is the last table on the inspection form.]

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With regards to comments associated with 192.1007 (a) Operator’s Knowledge of gas distribution system, the following findings have been identified (during some

• f the inspections conducted to date):
• Inspectors discovered a lack of criteria for subject matter expert (SME) selection.

The plan must define some criteria for SME selection to ensure that individuals with the proper knowledge of the system serve. Where DIMP relies upon subject matter expert (SME) input, the operator must be able to demonstrate why the SME is an expert

• Documents, such as meeting decision summaries must be retained to support

conclusions and risk prioritization modifications based on SME input. This is necessary to support risk ranking changes.

• Operators must specify how field discovery of inaccurate information is to be

relayed to DIMP team and eventually integrated into the DIMP data used for risk ranking and mitigative action implementation.

• Some Operators have modified field data acquisition forms and internal processes

to incorporate new information and correct inaccurate information

• The Plan must reference a missing information list when it resides outside of the

DIMP plan. It is difficult to determine if the data collection process will address all missing data if a consolidated list is not available for review.

• Procedures for identification of additional information must be included or
• referenced. The actual collection process for field personnel must be included or

referenced to ensure consistent collection and processing. <continued on next slide>

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192.1007 (a) Knowledge. Findings continued.

• Specific source data was not always listed in some plans inspected, including the

types of documents used. For example, if leak history is used to determine corrosion threats for a specific segment of pipeline, the Plan must state that this type of documentation was and is to be used.

• If there is no missing or unknown information, the DIMP must state this
• assumption. An operator must be prepared to explain how they determined that no

data was missing.

• When the need for additional information collection has been identified, a

procedure for collecting, recording and integrating the data into the DIMP evaluations must be included in the Plan or a reference must be made to an O&M procedure.

• If the plan does not include a listing of the data that is needed to fill gaps, it is

impossible to determine if procedures are in place to collect the necessary data.

• Some Plans inspected lacked procedures for recording new pipe data. In this case

a reference could be made to the existing as-built data collection process. However, the plan should include a methodical process used to integrate the information into the risk model.

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192.1007 (a) Knowledge. Findings continued.

Data quality is a common concern, and Data cleanup and scrubbing is often required. Outdated, incomplete, obvious errors. Outdated data systems difficult to use or sort. Data acquisition forms may need to be updated and revised. Reasonable balance between SME and hard data is important and it is dependent upon the operator’s specific data systems. Integration of data to identify existing and potential threats requires an appropriate level of resource allocation, and it can be quite time and resource intensive to do the job well. When scrubbed data becomes available threat identification may need to be re-run.

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Some Operators are struggling with potential threats, and these include threats that are known potential threats that the Operator has not experienced yet (from industry or PHMSA information) as well as threats that have not resulted in a leak (e.g., near misses).

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The DIMP Rule specifies 8 threats to the integrity of a distribution pipeline system that Operators must address. However, the rule also requires that operators consider reasonably available information to identify existing and potential threats. Additional work is required to evaluate the operator’s specific and unique operating environment to determine which additional existing and potential threats must be considered.

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192.1007.(b) Identify threats. Operators must consider the following categories of threats to each gas distribution pipeline: Corrosion, natural forces, excavation damage, other outside force damage, material, weld or joint failure (including compression coupling), equipment failure, incorrect operation, and other concerns that could threaten the integrity of its pipeline.

Some inspections have identified that operators:

• Output from model plans needs to be customized to reflect local conditions and include procedures.

Some DIMP Plans lack adequate details.

• Plan lacks specificity regarding the Operator’s unique operating environment. For example one

inspection identified a system located in a flood plain. The operator had not considered 10 year flood data which may need to be included. If included, mitigative measures may need to be implemented under the DIMP plan.

• Failed to consider applicable operating and environmental factors affecting consequence (e.g.,

paved areas, business districts, hard to evacuate institutions). These are considered to be operating environment factors and must be considered as additional factors relating to Consequence of Failure when evaluating risk.

• The Plan needs to include a listing of specific records used to identify threats.
• In some cases, Plans did not establish time interval for reevaluation of threats. Maximum intervals

must be defined and the Plan should include triggers that would prompt more frequent evaluations. If unknowns are discovered that could significantly affect the output of the plan or mitigative measures, the operator may need to conduct more frequent reviews.

• Each operator must include or reference procedures to identify new or potential treats and the

communication process necessary to ensure that the threats are properly ranked and mitigation measures are implemented.

• The Plan must include or reference procedures to evaluate and obtain data from external sources.

What sources will be used, who will collect and compile the data, how will the relevance of the data be evaluated and what process will be used to incorporate the data into the risk evaluation process.

• NOTE: Some operators have chosen to address the threat of excavation damage outside of the

DIMP threat evaluation process. Since excavation damage is one of the specific threats requiring evaluation, some method must be developed in the DIMP to include the threat of excavation damage to pipelines. While Excavation can be a very dominate threat, it is important to ensure, as some

• perators have done, that the COF factor is appropriately weighted so that risks are ranked correctly.

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An example would be the appropriate weighting of the excavation threat in a rural setting versus an urban locale.

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 Threat Identification

 What can Cause Operator’s Pipelines to Fail?

 Data Gathering and Integration

 What does Best Available Information Say About Threats to an Operators Pipeline?  What does Best Available Information Say About the Condition of an Operator’s Pipeline?

 Risk Assessment

 How Likely are Identified Threats to Cause Failures of Covered Segments?  What are the Consequences of Failure?

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There are many sources for information on existing and potential threats to the integrity of distribution pipelines GUIDE MATERIAL APPENDIX G-192-8, Section 4.3 Sample threat identification method. Table 4.1 further breaks down the threats into subcategories. This is a good source for reviewing possible threats to the integrity of a pipeline system that are specific to distribution systems. [continued on next page]

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Listing from GPTC continued. GUIDE MATERIAL APPENDIX G-192-8, Section 4.3 Sample threat identification method. Table 4.1 further breaks down the threats into subcategories. This is a good source for reviewing possible threats to the integrity of a pipeline system that are specific to distribution systems.

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Some Operators are struggling with potential threats: [Material to consider include] Threats the Operator has not previously experienced (from industry or PHMSA information) Threats from aging infrastructure and materials with identified performance issues may need to be considered existing threats depending on the materials in question and the operating environment Threats that endangered facilities but have not resulted in a leak (e.g., exposed pipe, near misses). Non-leak threats (overpressure, exposure) Manufacturing and Construction Threats Maintenance history

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Examples of potential threats often not being considered:

• Over pressurization events
• Regulator malfunction or freeze-up
• Cross-bores into sewer lines
• Materials, Equipment, Practices, etc. with identified performance issues
• Vehicular or Industrial activities
• Incorrect maintenance procedures or faulty components
• Rodents, plastic eating bugs, tree roots
• Other potential threats specific to the operator's unique operating environment

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An Operator Must : Consider and Evaluate Existing and Potential Threats Justify Elimination of Threats from Consideration So, there is more to do than account for just Time Dependent and Time Independent Threats An Operator must look at “near misses”, known threats identified in Industry literature, PHMSA Advisory Bulletins, etc. and understand how threats interact with each other An Operator should also consider that Interactive Threats (interaction of multiple threats) can be a potential threat.

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Interactive threats are potential threats! Distribution Operators should look to their Leak and Incident history and Operations and Maintenance history to identify interactive threats specific to their system.

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Some interacting threats to consider include, but are not limited to, the following:

• Slow crack growth in older plastics where pipeline was pinched during operational

event or where over-squeeze occurred due to improper tools or procedure

• Slow crack growth in older plastics where non-modern construction practices

were used

• Water main leakage areas or areas of soil subsidence with cast iron mains
• Installation of mechanical fittings without restraint (category 2 & 3) in soils or

conditions (excavation damage) that cause pipe to pull out of fitting

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To effectively Evaluate and Rank Risks, Software enhancements or program augmentation can be required to “canned” programs and existing systems that were

• riginally designed and implemented for specific purposes.

Validation of risk results that a DIMP provides by SMEs is important to ensure results are reasonable.

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An operator must evaluate the risks associated with its distribution pipeline. In this evaluation, the operator must determine the relative importance of each threat and estimate and rank the risks posed to its pipeline. This evaluation must consider each applicable current and potential threat, the likelihood of failure associated with each threat, and the potential consequences of such a failure.

• Some inspections have indicated that system subdivision is not sufficient to

analyze risk(s). For example, if the system includes PE pipe of various vintages and manufacturers, the operator should subdivide the system grouping pipe that has experienced issues separate from pipe that has not experienced issues. In the case of pre 1973 Aldyl A or other problematic materials, issues must be tracked separately from other PE pipe in the system.

• Some plans do not consider non-leak failures in analyzing risk. Operators must

address failures that do not result in a release to identify potential threats. Overpressure issues would fall into this category as well as coating failures.

• Plans must include analysis of flood data, where applicable. This issue was

identified on a system that is prone to frequent flooding. The 10-year flood data review was a period acceptable for the specific region. Each operator must determine the appropriate data to use based on local operating conditions.

• Risk ranking must include all risks to facilities. Obviously, all risks must be

addressed including grade 3 leaks, potential threats and consequences, etc.

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192.1007(c) Evaluate and rank risk. Findings continued.

• The Consequence of Failure (“COF”) can be diluted by Frequency of Failure (“FOF”) – a larger range under

COF is needed. If the consequence factors are too low, the analysis is essentially a likelihood of failure analysis, rather than a risk analysis. For example, a prison located near a large main would likely be a larger risk even if the likelihood of the main failing is small. If it did, loss of life could be very high. In the instance

• bserved, the values assigned did not contain a large enough span and when information was inputted, the

FOF was diluting the COF. Weight of consequence of failure (COF) is often predetermined by a model vendor and the method of determination is not explained in plan. Inspector must be provided with this information to determine the adequacy of the program.

• Weight of consequence of failure (COF) may be predetermined by vendor and method of

determination is not explained in plan. Inspector must be provided with this information to determine the adequacy of the program.

• Plan lacks explanation of data validation process. Most of the operators have discovered that data validation is

required due to ever changing processes and procedures over the years. The operator needs to ensure that they are comparing apples to apples. For example, if the leak cause categories have changed over the years, the operator needs to ensure that leak causes identified under a previous program are compared to the appropriate categories under the new cause codes.

• Validation of the risk ranking model was not always explained in an operator’s DIMP; “How do we know it’s

working?” is an important question to ask. Occasionally, SME ranking is grossly different from model output. Why? The results must be validated and the validation process must be documented.

• One model only addressed mains; no risks specific to services. There are hazards unique to services, such as

damage to meter sets. Excavation damage frequencies could also be higher on services than on mains under paved streets. The entire system must be addressed.

• Subdivision of information did not include additional criteria adopted since August 2nd, COF revisions. In this

case the operator was tweaking the COF weighting to provide a more accurate risk ranking however, they had not rerun the risk ranking and entered the information into the plan provided during the inspection. Discussions were held with the operator to review the appropriate timelines for incorporating changes to the program. Essentially, the review was being conducted of an outdated plan.

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Identifying measures to reduce risk requires good analysis, and tying performance measures to provides an understanding of whether the implemented measure is reducing risks. Criteria to determine when measures to address risk are needed requires somewhat quantifiable results, and operators need to look for opportunities to identify criteria.

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192.1007(d) requires operators to identify and implement measures to address

• risks. These measures must include an effective leak management program (unless

all leaks are repaired when found). In this context, “repair when found” means just

• that. If an operator doesn’t repair immediately, then they are not “repairing when

found” even though they may not use a multi-level grading system for the leaks they find.

• Links between the risks identified and implemented measures to reduce risk need

to be clearly stated. Operators must be prepared to demonstrate the direct link from risk identification to the measure used to reduce the specific risk.

• All operators must have an effective leak management plan, unless they repair all

leaks when found. If the management plan is not included within the DIMP plan, the Plan must at least provide reference to the leak management program included in the operators O&M procedures.

• Once measures are implemented to reduce risks, the plan must define the re-

evaluation time interval. It may not be practical to wait for a full plan review to determine if the implemented measures are effectively address the risk.

• After the two highest risk projects, the model ranks projects/replacements based on

cost-effectiveness. This really isn’t a true risk ranking. Cost-effectiveness is a criterion that operators must take into account in apportioning their resources, but the risk model results must provide a stand-alone list of what is most (to least) important to be used in conjunction with “what can we afford?”

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An example of Measures implemented to reduce the risk of some specific threats and the metrics used to measure the performance of the implemented measures. Metrics are required in 192.1007(3)(vi) to measure the performance of the implemented measures to ensure that they are performing as expected or else they should replaced by other measures implemented to address the threat in question.

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As a DIMP matures, good performance measurement should show positive trends towards improving integrity and safety culture, or changes to the DIMP should be implemented. Baselines have to be established for performance measures, and if data collection has just initiated, then the plan for data collection and analysis must be documented.

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192.1007(e) requires the operator to measure performance, monitor results, and evaluate the

program effectiveness. Operators must develop and monitor performance measures from an established baseline to evaluate the effectiveness of its IM program.

• Inspections have identified that Baselines for Performance Measures have not been established. It

is impossible to determine if the program charts the correct course if the starting point is not defined.

• Plan lack procedures to establish baselines. It is difficult to determine if the effectiveness

measurement is appropriate if the process used to establish the baseline is not provided.

• Plan should identify “trigger points” or “significant issues” to initiate new performance measures.

Example of a “newly identified” potential threat of directional boring is provided along with discussion:

Threat and Sub-threat: Third party damage caused by directional boring Trigger: A reportable incident or increase in damages caused by directional boring Risk Reduction Measure: On site contact with the excavator by a damage prevention specialist to discuss the potential for damage when a dig notice is received indicating that boring will take place that includes a discussion of best practices and conflict resolution. Baseline: The number of damages experienced by the operator in a selected time period prior to the performance measure. Performance Measure of effectiveness: The number of directional boring damages experienced each year once the mitigation measure is implemented

• Operators must identify acceptable risk reduction to be achieved by each implemented risk reduction
• measures. Each individual risk control measures does not have to have a unique performance
• measure. Some Operators have identified a single performance measure to evaluate the

effectiveness of multiple risk control measures. The “number of hazardous leaks either

eliminated or repaired, categorized by cause” can be used for measuring the significance of various threats to the integrity of a system and the performance of risk reduction measures. Also, measuring the number of leaks categorized by materials can provide information on a number of risk control measures that could be implemented to reduce the threat of material and

equipment failures. Corrosion cause – risk reduction measures include anode replacement, re- coating, replacement, more frequent CP surveys. Damage Prevention ratio is a single evaluation

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measure to evaluate the risks to the pipeline from poor locating, failure to adequately use one-call programs, no hand digging around pipe.

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192.1007(f) requires Periodic Evaluation and Improvement. 33

192.1007(f) requires Periodic Evaluation and Improvement.

• Plans lack procedures for conducting periodic evaluation in some plans
• inspected. Again, the who, what, when, where and how aspects must be

addressed to determine if the re-evaluation will produce acceptable results. A DIMP is a “living” document, and changes made to a periodic evaluation as an Operator implements this element in the future would handled with revisions.

• Procedures should provide for notifying operator personnel of changes to plan or

plan requirements. All affected personnel must be notified of significant changes that impact their duty areas and the performance of their job.

• Some Operators failed to incorporate pipe replacement into the Plan. This

would have a significant effect on the risk ranking and must be included as a mitigative measure. Future risk results will be affected by the removal of

vintage pipeline facilities.

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Operator’s plan must have procedures that include criteria for when re- evaluations are to be done based on timing (< 5 years) or events (e.g., replacement program completed, goals achieved, new significant threats identified). Plan re-evaluations may generate changes to the results of the risk ranking and risk mitigation measures needed to address risk. Operators should be cognizant of changes that occur in the DIMP as a result

• f the periodic plan evaluation.

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192.1007(g) requires operators to report, on an annual basis, the four measures

listed in paragraphs (e)(1)(i) through (e)(1)(iv) of this section, as part of the annual report required by §191.11. An operator also must report the four measures to the state pipeline safety authority if a state exercises jurisdiction over the operator's pipeline.

• Inspections discovered that Plans lacked procedures describing the collection of

Annual Report data. If the collection process is not defined it is nearly impossible to determine if all reporting requirements have been met or to assure accuracy and

• consistency. In once case the individual responsible for report was asked how the

conducted the collection and they stated that it was intuitive. It may be for that individual, but it may not be for their replacement or others within the organization. The process needs to be defined and shared.

• No instruction to send annual report to State agency, when required. Each year

State regulatory agencies are asked to verify that the operators are providing the required information. Many States require direct reporting. The plan must provide instruction to ensure that all reporting is conducted as required.

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§192.1011 What records must an operator keep? An operator must maintain records demonstrating compliance with the requirements of this subpart for at least 10 years. The records must include copies of superseded integrity management plans developed under this subpart.

• Early inspections have found plans missing a description as to how superseded

plans and back up data will be kept.

• Inspectors expect to be provided adequate revision logs, Plan version effective

dates, revision dates, etc.

• Statements in DIMP that “all Company records were used in the development of

the DIMP” should not be made. Only those records used to develop and implement the DIMP should be referenced as being records required to be maintained for 10 years.

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Our next section of the presentation is on Mechanical Fitting Failure Reporting and Data Analysis

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The next topic we want to talk about is mechanical fitting failure reporting. In the February 1, 2011, Mechanical Fitting Failure Reporting Requirements Final rule, PHMSA changed the term ‘‘Compression Coupling’’ to ‘‘Mechanical Fitting’’ and provided a definition for ‘‘Mechanical Fitting’’ which includes compression type couplings. Operators are required to submit a report on each mechanical fitting failure which results in a hazardous leak. They can do so as the failures occur, or they can report all failures occurring during a given year by March 15 (the Annual Report deadline) of the following year. Operators of master meter and small LPG systems are not required to report these failures on the form, but should retain information on any failures for use performing risk analysis.

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Recently, PHMSA has initiated changes to the MFFR Form to include a unique identifier for each report to support operators that are submitting multiple reports at a time. This will assist operators in retrieving draft reports when they have left them in that status pending additional information, for example. As stated before, it is the operators option to report these as they

• ccur throughout the year or all at once. Be sure you revisit any reports made

during the year and complete the process by submitting for finalization if you didn’t do so when the report was filled out.

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PHMSA has reviewed the data submitted through the end of 2013, and we will discuss some of that data during this presentation. Following the submittal of all 2013 data - required by March 15, 2014 - PHMSA will review and analyze the data in more depth, and information regarding those analyses should become available during May, 2012. It takes time to QA/QC the data and initiate the analysis process. Communication of Performance Data (Annual report and MFFR) will be through the DIMP web page in a manner similar to Liquid and Gas IM. Annual report IM Performance Data will be posted along with 2011 MFFR data (first year) around the first of May, 2012. There has been some discussion between Industry and NAPSR and PHMSA over which failures to report. The MFFR Instructions are being revised to better communicate that Operators are to report “all failures of compression type couplings, regardless of material, that result in a hazardous leak”. Revisions to the Form and Instructions have been published, and a PHMSA Advisory Bulletin is being issued that provides clarification on several points.

PHMSA has become aware of confusion over the handling of “Construction or Installation Defect” as a leak cause in “PART C – MECHANICAL FITTING FAILURE DATA, Section 15-Apparent Cause of Leak” in PHMSA F 7100.1-2. A construction or installation defect means that a component was installed

• incorrectly. It could be due to poor workmanship, the procedure was not followed, or

there were poor construction/installation procedures. Failures resulting from a construction or installation defect should be identified with the “Incorrect Operations” leak cause and not the “Material or Welds/Fusions” leak cause category (as is described in PHMSA F 7100.1-2 and the Instructions). It is PHMSA’s intent to capture failure data under the “Material or Welds/Fusions” leak cause category that is specific to the construction and design of the mechanical fitting.

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Make an entry in each block for which data are available. Some companies may have very old pipe for which installation records do not exist. Make a best effort at quantifying data. Avoid entering “Unknown” if possible.

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Another area I will present some data is by type of fitting. I have included some photos here of the four listed categories. “Other”, as used in this context, is intended to capture all mechanical fittings which do not fit into one of the other three categories.

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Communication of Performance Data is through the DIMP web page. To view MFFR data, go to: http://primis.phmsa.dot.gov/dimp/perfmeasures.htm Total Report Submitted Numbers: MFFRs submitted in 2011 – 8349 MFFRs submitted in 2012 – 7585 MFFRs submitted in 2013 – 9240 Data submitted for 2013 shows similar trends to previous 2 years of data collection. Again, to review and evaluate this data, go to the DIMP webpage noted above.

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The majority of mechanical fitting failures resulting in a hazardous leak involve nut- follower, coupling type fittings. Valves are involved in 14% of reported failures. Equipment failure is the leading reported cause of leaks (41%), and Natural forces is second (17%). The majority of leaks occur outside (98%), belowground (87%) involving service-to- service connections (60%). Steel fittings (62%) are involved the majority of reports, and plastic fittings are second (26%).

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Our next section of the presentation is on DIMP Inspection Forms

Regulators are interested in learning what measures operators are implementing to address identified risks, and this information is collected in the table of the PHMSA Inspection Forms 22 & 23. Regulators plan of identifying and compiling best practices and potential threats that have been identified by each operator for communication to Stakeholders.

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Now, let’s talk about the inspection forms we have prepared to do DIMP implementation inspections. The PHMSA DIMP Inspection Forms for 192.1007 and 192.1015 distribution

• perators are available at http://primis.phmsa.dot.gov/dimp/resources.htm .

Revisions were implemented in September, 2011 after Inspection Teams had some experience using the forms, and those changes made the forms more user friendly for Inspectors. There was no impact on the questions or verbiage in the Forms that would affect Operators. We consider the form to be stable at this time, and the form will be re-evaluated, based on stakeholder feedback, at the end of each calendar year.

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Please regularly use PHMSA websites as they are a primary form of communication PHMSA Office of Pipeline safety http://phmsa.dot.gov/pipeline DIMP Home Page http://primis.phmsa.dot.gov/dimp/index.htm Pipeline Safety Stakeholder Communications http://primis.phmsa.dot.gov/comm/ Also, please note the new Cast Iron Discussion Page at http://opsweb.phmsa.dot.gov/cast_iron/ [Note to presenter – If you have an internet connection, consider going to each of these pages during the presentation as many stakeholders have never seen them before. Also, Consider including State Pipeline Safety Program pages and their links here for live demonstrations.]

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DIMP Enforcement Guidance is publicly available and posted on PHMSA’s website with the other Enforcement Guidance documents currently posted at http://www.phmsa.dot.gov/foia/e-reading-room This posting allow Operators to understand Regulators’ expectations with regards to the DIMP Regulation

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We would be happy to respond to questions.

51 <Chris>