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Using ECDA for Traceable, Verifiable, Complete Data Integration

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Unpiggable lines have long been a challenge to assess due to the nature of the line. In-line inspection (ILI) has generally been considered the go-to assessment technique for its ability to collect a large amount of data with multiple tools in one run. ILI runs have their own challenges, but generally have proven to provide quality data from which operators can make informed decisions regarding the integrity of the line.

With recent changes to regulatory requirements, including the addition of “moderate consequence areas,” the amount of pipeline that is required to assess is set to increase substantially. One option for assessment is hydrotesting. This method, however, can be both cost and time prohibitive. Another option is the External Corrosion Direct Assessment or ECDA approach. This tactic does not require the operator to shut down the line and provides specific dig locations to investigate as part of the process.

ECDA Process: An Overview

External Corrosion Direct Assessment (ECDA) is one of the most widely used and accepted methodologies for performing corrosion assessments on unpiggable lines. As per NACE SP0502, the ECDA process has four distinct parts: Pre-Assessment, Indirect Inspection, Direct Examination and Post-Assessment. This article will describe areas in each phase where operators have historically been deficient and provide solutions to ensure compliance with the applicable regulations.

The ECDA process is one of the few standards that is incorporated by reference in the regulations regarding corrosion control. Operators who choose to use the ECDA process should ensure that the procedure is adopted in as complete a manner as possible, making sure to follow specific portions referenced in code as prescribed in the NACE standard. To strengthen compliance, operators should use NACE SP0502 and ASME B31.8S (for gas pipelines only) as guidance for the development of ECDA procedures and protocols.

The ECDA process, like all procedures, must be documented in full within an operator’s operations and maintenance plan. Operators should identify each phase of the process clearly and include a corresponding record of the decision-making process to substantiate each decision.

The following items are the leading factors for violations related to an ECDA process:

  1. Lack of documented procedures.
  2. Incomplete procedures.
  3. Failure to include ECDA in the decision-making matrix for Integrity Management (IM) assessments.
  4. Failure to follow all parts of the ECDA process as defined in NACE SP0502.

Historically, lack of procedures and incomplete procedures have been the primary causes of violations issued by the state or federal inspectors.

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Operators not following NACE and other guidelines, or operators only performing the indirect inspection portion and calling it an ECDA assessment are often the source of these issues. Having some form of in-house procedures that document the process for performing an ECDA, and ensuring those procedures include all four required steps, is critical. Due to the standard being incorporated by reference, this is a mandatory function of any ECDA procedure.

Following is a summary of each of the four phases of the ECDA process, common areas of non- compliance and recommendations for compliance solutions for each phase.

ECDA can be a powerful tool

ECDA can be a powerful tool for pipelines unable to be assessed by other means, so long as it is performed accurately, by qualified personnel following a validated procedure. The process will help operators adhere to the PHMSA mantra of “traceable, verifiable, complete.”

Phase 1: Pre-Assessment

The pre-assessment process, as defined in NACE SP0502, must involve collecting and analyzing all relevant data. Pre-assessment procedures should be robust enough to ensure all pertinent data are captured, processed and integrated into the decision-making process. At an absolute minimum, the procedure must identify the required data to collect in order to determine the feasibility of performing the survey. Here operators must validate that their process is detailed enough to ensure the capture of all relevant data. Some of the pitfalls include:

  1. Failure to include more restrictive criteria for first time ECDA
    execution.
  2. Failure to include decision making for tool selection.
  3. Failure to include decision making for region identification or failure
    to identify regions.

The procedure for pre-assessment must define what data are required for feasibility determination and what data are only recommended. Operators should evaluate their data requirements for feasibility in conjunction with NACE Standard SP0502, Section 3.2. Any data required for feasibility but unavailable should be documented properly, and its impact on the survey evaluated. Operators must define the minimum requirements for feasibility to ensure a uniform approach to the current and future surveys. If not already incorporated, operators should also consider integrating data from other IM programs. Data such as third-party damage, encroachment and patrolling may provide valuable insight for segments currently being evaluated for feasibility.

Once data collection is completed and feasibility has been determined for the applicable segments of line, the procedures should address indirect inspection tool selection. Utilizing a table similar to that in NACE SP0502 Section 3.4 will help determine what tool may be appropriate for different types of survey/environment/construction that may be encountered. Anywhere decision-making can be standardized will ensure a more consistent application of the ECDA process.

Next, operators should begin to define inspection regions, being careful to define regions in accordance with NACE SP0502, Section 3.5. Factors for region selection should include, but are not limited to soil type, environment, coating type and condition, and operating history. Operators should select tools based on the conditions present, as well as the capabilities of the tools with respect to one another. Operators should document the technique/tool used for each region and application procedure. Operators must also ensure that at least two tools are selected for each region, based on region characteristics. NACE SP0502 provides a matrix for tool selection that should be a part of every operator’s procedures.

Region selection is one of the most often misunderstood or skipped portions of the pre-assessment phase. Operators will commonly call the entire segment to be surveyed one “region” and select two or more tools to use across the entire span. However, the NACE standard is very clear that operators should take the time to ensure that regions are chosen based on common characteristics, histories and other features that will allow for proper collection of current data. Regions are not required to be continuous but may stop and start as defined by the operator based on common characteristics.

From a compliance perspective, the most important part of the pre-assessment phase is documentation. As per the new PHMSA guidelines, this must be traceable, verifiable and complete. Thorough documentation and a clear, articulate procedure will help to demonstrate that the operator has stepped through the process as required and will help support future assessments.

Phase 2: Indirect Inspection

Once the pre-assessment phase has been completed in its entirety and ECDA deemed feasible, operators may move to Phase 2. In this phase, field data are collected in accordance with the plan developed during the pre-assessment phase. Here again, operators must have well-defined procedures for the execution of the field survey. Each tool chosen during the pre-assessment phase should have its own procedure, complete with data and documentation requirements.

Documentation of work continues to be the biggest issue for most operators. Frequently, this work is contracted out to third-party vendors to complete. Operators should ensure that the contractor is following the operator-specific procedures for data collection, analysis and reporting format.

This phase will entail data collection which will drive operator decisions to perform direct inspections on sites where corrosion may be imminent. This data and decision making must be documented fully to validate dig site selections. Other areas where operators have had difficulty include:

  1. Lack of procedure for classificationof anomalies found
  2. Lack of procedure for prioritization of anomalies found
  3. Lack of procedure for first time ECDA assessment which requires additional digs
  4. Failure to perform validation dig(s) as per requirement
  5. Failure to include calibration data for equipment used
  6. Failure to include operator qualification reports for any third party
  7. Failure to account for spatial errors
  8.  Not enough dig sites selected.

Primary drivers of non-compliance include the proper classification and prioritization of anomalies found, as well as validation dig identification. Indications should be classified and prioritized, as data overlaid from multiple tools will provide a more complete picture of the corrosion profile of the line. Operators should select dig sites in accordance with their procedures and the NACE standard. First-time ECDA surveys will result in additional digs, which is a NACE requirement that helps validate the operator’s process.

Operators should apply more stringent requirements for baseline assessments, such as utilizing stricter classification criteria for indications found and additional digs as required by the NACE standard.

Phase 3: Direct Examination

The direct examination phase provides a first-hand view of sections of the pipeline and validates the indirect inspection portion of the survey process. Prior to conducting digs, operators should ensure they have correctly utilized their algorithm for excavation prioritization and that all sites have been surveyed properly, with one-call notifications completed. At a minimum, one direct examination dig must be performed during each ECDA process.

During the direct examination phase, operators have had difficulty with the following:

  1. Failure to perform one-call notifications for dig locations
  2. Failure to follow procedures for cleaning pipe for evaluation
  3. Failure to establish/follow procedures for evaluation
    • Acceptable technologies
    • Training and qualification
    • Documentation
  4. Failure to re-coat pipe in accordance with approved procedures
  5. Failure to backfill in accordance with approved procedures
  6. Failure to establish/follow procedures for evaluation of pipe, including determination of remaining strength.
  7. Failure to establish/follow procedure for in-process evaluation

The primary functions where operators have been found non-compliant have been the failure to re-coat pipe properly and failure to establish a procedure for in-process evaluation during the direct examination phase.

In-process evaluation is required to assess the indirect inspection data against the remaining strength evaluations to determine the adequacy of categorization and prioritization criteria. Operators that find corrosion activity less severe may reassess and adjust the criteria used for classification. When corrosion activity is more severe than anticipated, operators must reassess and adjust the criteria for all other anomalies found during the indirect inspection phase. However, prioritization should not be downgraded for a first time ECDA.

ECDA is an approach that does not require the operator to shut down the pipeline

With recent changes to regulatory requirements, the amount of pipeline that is required to assess is set to increase substantially. ECDA is an approach that does not require the operator to shut down the pipeline and provides specific dig locations to investigate as part of the process.

Operators should also have procedures that ensure additional excavations for validation are included: one where corrosion could be present, and one where no indications were noted. This will provide the operator with valuable data to evaluate the effectiveness of the process.

Phase 4: Post-Assessment

The post-assessment phase is the review phase of the entire analysis. Key objectives include overall effectiveness evaluation, definition of reassessment intervals and determination for re-prioritization of indications.

During the Post-Assessment phase, operators have been found deficient in the following areas:

  1. Failure to use an approved method of determining remaining life calculations (RSTRENG, B31.8(s));
  2.  Failure to establish/follow procedures for effectiveness measurements and continual improvement;
  3. Failure to use data to determine re-assessment intervals.

One of the most prevalent causes of violations is an operator’s failure to determine the effectiveness of the procedure. Operators should utilize all data available to determine if their procedures were indeed effective in finding external corrosion, whether overly aggressive or not aggressive enough, and document any changes to the process based on the results of the assessment. Operators must establish criteria for assessing the long-term effectiveness of the process. Metrics such as the number of required reclassifications from inspection to inspection and repeatability of inspection results should be considered.

Conclusion

One of the biggest issues that operators face is documentation. The ECDA process relies heavily on documented decisions to ensure that the process was followed to the intent of the standard. Operators should ensure that their procedure identifies the required documentation during all phases. Utilizing aides such as a project closeout checklist to identify documentation requirements helps maximize compliance. Using GIS data to validate dig locations, or areas of indications with lower prioritization, as well as automated data integration from previous surveys can help operators perform more effective, compliant ECDA assessments.

An ECDA can be a powerful tool for lines unable to be assessed by other means, so long as it is performed accurately, by qualified personnel following a validated procedure. It is worth reiterating the PHMSA mantra of “traceable, verifiable, complete.” The more an operator can adhere to these guidelines, the better their program will be, and the easier it will be to demonstrate compliance.

About the Authors:

Roderick M. Rheaume, NACE CP Specialist, HMI Technical Solutions LLC has 29 years of experience in pipeline integrity and corrosion engineering. With over 15 years in pipeline integrity working for a natural gas transmission company, he has extensive experience as an operations liaison during PHMSA inspections.

Al Giordano, P.E., Former Project Manager, HMI Technical Solutions has more than 15 years of experience in both the public and private sector executing projects in oil and gas pipeline safety, compliance and operations, integrity management and maritime safety. A prior PHMSA auditor, he has considerable skill in regulatory compliance and project management.

M. Alex Bryant, TC Energy has five years of experience in pipeline integrity, with four years working specifically with Direct Assessment. As the Direct Assessment Lead for United States projects, he provides oversight to all DA projects. He also has experience as lead contact for DA projects during PHMSA inspections.

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