January 2021, Vol. 248, No. 1


Pipeline Integrity: History of Direct Assessment Process

By Joe Pikas, Corrosion Specialist, Technical Toolboxes  

Direct assessment (DA) is a process through which a pipeline operator determines a pipeline’s integrity through integrating knowledge of the physical characteristics and operating history of a pipeline with the results of diagnostic testing.  

The process is further validated by the physical examination of the pipeline, to verify that the interpretation of the diagnostic testing results matches the actual condition of the pipeline upon direct examination.  

External corrosion direct assessment (ECDA), like most other processes, is not without limitations in its application. Depending on available information about the pipeline, and the operating conditions the pipeline is, or has been, under, ECDA may provide all of the information that is needed to determine the integrity of the pipeline.   

Alternatively, ECDA may be used in conjunction with, or as an enhancement to, the findings of other available technologies, such as hydrostatic testing or smart pigging. Direct assessment is intended to be one of the valuable tools an operator has available to enhance the safety of their operations.  

Over the years, a variety of types of equipment and numerous indirect techniques have been enhanced to measure various parameters related to the condition of the pipeline. For a variety of reasons, these techniques were historically used in a stand-alone manner and for testing a single aspect of overall pipeline integrity.   

By selecting the correct complimentary techniques, the strengths of one technique will cover the weaknesses of another, versus assessing via stand-alone techniques.  

Using this best practice in ECDA also permits the integration of vast amounts of integrity-related knowledge and data into a tool that can be used to accurately determine the condition of the buried pipeline, as well as providing essential input for prioritizing remedial activities.   

The continuous improvement of the ECDA process provides the information needed to efficiently and safely decide to replace, repair, or accept and monitor each feature found.  

How It Started  

The DA process began in 1997 and was intended to be a functional equivalent assessment to pressure testing or inline inspection (ILI). At that time, it was called direct examination (DE), which involved doing a large number of investigative digs, which can be expensive and logistically challenging.   

For me, it started when the vice president of Operations entered my office in 1998 to ask if I would take his place on an industry task group to head up the DE process (which was not yet developed).   

Not knowing what to expect, I found out later that most of the face-to-face meetings were conducted on Capitol Hill with the Office of Pipeline Safety (OPS) [now Pipeline and Hazardous Materials Safety Administration (PHMSA)] and Interstate Natural Gas Association of America (INGAA), and with the rest of the team in either Columbus, Ohio, or Denver. The industry group consisted of researchers from Battelle, engineers from gas operators and independent contractors, and regulators, who monitored the team’s activities throughout the process, until they produced a process acceptable for industry.  

It soon became apparent that if anything were to be done, it would require working closely with congressional aides or staffers as well as working closely with PHMSA regulators.   

However, the directive for the industry panel was to “work closely,” but “not too closely,” with the regulators. We were politely told to work independently, comparing findings less frequently.   

While the meetings with regulators were occurring, the remainder of the industry group was able to change the name from Direct Examinations to External Corrosion Direct Assessment (ECDA) by working through the congressional aides.   

In order to navigate the complexity of working with a bureaucracy, and all the requirements and restrictions that were placed on the group, a comprehensive project plan was laid out, with responsibilities assigned to each member related to their respective specialties and disciplines.   

The first milestone was getting the definitions or acronyms to be consistent throughout the entire industry. This alone was a massive undertaking and required the approval of all major industry organizations that had any involvement with the pipeline industry.   

The next phase required performing research on items such as soil resistivities, survey types, testing and techniques and effectiveness, soil corrosivity, corrosion and coatings.   

To accomplish this, the practitioners met with researchers to determine the type of aboveground surveys that could be used, or not used, based on their effectiveness and limitations. It is worth noting that there was a deadline to have a process developed within two years.  

The team’s first draft of the ECDA process was produced within one year and consisted of 850 pages. While the team members were proud of themselves for producing this comprehensive document, they had concerns that the people in the industry who needed to implement the process would not be willing to read such a large document, or potentially be able to understand the intricacies buried within it.  

Capitol Hill agreed and the team was politely told after a meeting with the regulators and their consultants to reduce the size significantly and make it simpler. The team decided to regroup the next week in Columbus. This next phase started over dinner at a café in the Germantown section of Columbus and focused on ways to cull the document down to an understandable and manageable level.  

4-Step Process  

As with many projects, distractions of life and work complicate timelines. With many team members also having their “real job” to attend to, time went by without a plan of action on how to reduce the size of this document without losing its purpose.  

However, during a flight from Houston to Columbus for a team meeting, I had an idea for the framework of a four-step process, which consisted of the following:   

  • Pre-assessment – Is the DA process feasible to assess the threat or threats?  
  • Indirect assessment – What aboveground tool or tools can be used for ECDA?  
  • Direct assessment – Did the tools perform as expected with the right results?  
  • Post-assessment – What were the lessons learned and what was the effectiveness of the program?  

The next day, each of the industry members took another look at the 850 pages, and new assignments were given to each member. The team was able to reduce the size of the ECDA process document down to 60 pages within a few months.  

After approval by PHMSA and Cycla, the next step was to take it NACE to make it into standard practice. The team met with NACE staff and explained to them the time pressures. It was one of the fastest documents to be approved by NACE, since it was already created and needed only minor modification to meet their requirements. This document is now recognized as “Pipeline External Corrosion Direct Assessment Methodology, SP0502, Latest Edition.”  

In addition to this activity and taking no risks, the team also wrote up the ECDA process for ASME B31.8S as an interim step, should there be any delays in the process or approvals by others.  

Ongoing Improvement  

The fourth step in the ECDA process is the post-assessment, recognizing that continuous improvement is key to longevity and safety. This step takes a high-level perspective for determining the overall effectiveness of the application of the ECDA process for each assessment. The strengths and weaknesses of using the ECDA process are determined.   

For example, any discrepancy associated with the estimated depth of an indication is compared to the actual depths, based on direct examinations.   

If routinely used inspection/survey techniques are found to not deliver reliable results for most sections of the pipeline, those limitations should be noted, such that alternate inspection/survey instrumentation can be scheduled or used going forward.  

The post-assessment step is also used to determine the reassessment intervals. The reassessment interval is basically the time from the completion of the most current ECDA evaluation and the next, or follow-up, ECDA.   

It is determined from numerous factors such as the present wall thickness, estimated corrosion growth rate, maximum allowable operating pressure, pressure equating to the yield strength of the piping material, failure pressure and appropriate safety factors.   

This is a critical step, as it balances commercial profitability with the safety of people, property and the environment. Getting this balancing act wrong can result in either unsustainable operating costs or pipeline failure.  

Once the locations of corrosion-related defects have been identified, the remaining strength of the pipe wall is determined for the sections of pipe having indications. The structural integrity, including the remaining strength, can be calculated.   

The PRCI RSTRENG program predicts the failure pressure of corroded pipelines, based on the data gathered from a field study. It continues today as the primary assessment tool for ILI data interpretation.  

The logical next step is providing assessments that can be used to determine remaining life and reassessment intervals, and we have advanced the implementation of the ECDA process through the Technical Toolbox team that developed an ECDA software module for workflow automation in collaboration with one of North America’s biggest pipeline operator.  

Although the process started out for aboveground tools in external corrosion, it is not limited to these tool types. For example, the four processes can be applied to ILI, hydrostatic testing or any other testing methods to assess the integrity of the pipe.  

The process will guide the pipeline operator as to which tool or tools are best suited for determining the integrity of the pipeline. Combing this information through critical engineering assessments can determine the best course of action, such as repair, inspection and prevention into a true performance-based program.    

Author: Joe Pikas is a corrosion subject matter specialist at Technical Toolboxes with 54 years’ experience. He received a joint industry award in 2002 for his work on direct assessment from AGA, GTI, INGAA, NACE, OPS (now PHMSA) and PRCI. 

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