“There’s no way that pipeline segment requires 60 digs,” we thought as we reviewed an ILI tool vendor’s final report. Our team at Acuren had worked on that line over the course of multiple integrity cycles and were very familiar with it. We had a pretty good idea of what to expect from an Ultrasonic Crack Detection (UTCD) tool on this pipeline, but this wasn’t it.
Rather than jumping to conclusions, we asked the tool vendor for more information and cross-referenced reports from different vendors on previous cycles. By compiling this data, we were able to eliminate half of the features as non-injurious manufacturing defects. We were down to 30 remaining features, but that still was much higher than expected on this line based on previous UTCD runs.
Once the vendor sent us detailed feature profiles, we were able to assess remaining strength as well as cycles to failure with greater realism. By eliminating unnecessary conservatism, we found that most of the 30 features were actually non-injurious leaving only two features requiring inspection. So, by conducting detailed research and resisting the urge to panic, we were able to eliminate the time and expense of 58 unnecessary excavations on the pipeline.
The cost of an inspection dig can vary depending on location, weather, and time of year
Integrity digs have a very high-cost variance due to differences in pipe diameter, location, soil type, and time of year in which the excavation occurs. On the low end we have managed digs that cost the operator as “little” as $25K. On the high end, digs can involve not only inspecting and repairing a feature or even replacing a portion of pipeline. For these more complex digs that price tag can increase in excess of 500%. Considering that an “average” dig for this line could be in the neighborhood of $120,000, taking a closer look at the tool vendor data allowed us to turn 60 digs with a potential price tag of $7 million into something closer to $240,000.
Of course, we don’t always achieve such a dramatic cost savings on behalf of our clients.
But it’s still surprising to us to hear that some pipeline operators will simply take the ILI vendor’s report, hand it to their dig contractor and say, “Get’er done! Send us the reports and let us know when the repairs are complete.”
Temporary access matting is often required in order to access the pipeline
Traditional “pig-and-dig” programs are critical to the safekeeping of our critical energy infrastructure. When implemented correctly, these programs allow operators to find and address threats to pipelines before those threats can cause problems.
For pipelines covered by PHMSA regulations, federal code requires inspection and — if necessary — repair of ILI features that meet a variety of criteria. Many operators have additional standards or best practices that go beyond the regulations to proactively keep the product in the pipeline. The public and the environment are safer today as a result.
However, digging any and every feature found by an inspection tool would result in many unnecessary digs causing additional cost and risk to pipeline operations.
Some of the drawbacks of digging unnecessary features are:
With extra digs having so many potential drawbacks, you can see why the dedicated team at Acuren strives to help our clients “right size” their pig-and-dig program by recommending excavation and inspection only after rigorously evaluating tool data and eliminating unnecessary digs.
A successful integrity program identifies and repairs potential problem spots on the pipeline but leaves the line undisturbed where no injurious features exist. At Acuren, we have processes in place for helping operators do exactly that.
In-Line Inspection tools are amazing examples of modern engineering achievement. It’s incredible that these tools can “see” a sub-centimeter flaw in the pipe wall while traveling at 3+ miles per hour in product across miles and miles of pipe. The data from the tools is processed by the vendor using both algorithms and skilled personnel trained in evaluating the raw signals recorded during inspection. These are amazing processes, but unfortunately neither the tools nor the humans involved in processing the data are infallible.
Laser scans can be used to accurately measure indications for comparison with tool data
Evaluating vendor data and potential inspection features is a two-sided coin. One side is an office-based desktop review handled by the integrity engineering team. Think of the desktop review as a ‘cold eyes’ review for both the tools and data analysis. The other side of the coin requires feedback from the field teams and interaction between field inspection and the integrity engineer.
Once the pipeline is exposed, trained Nondestructive Evaluation (NDE) technicians use a variety of methods, depending on the indicated feature, to find and measure the feature indicated by the tool. Field technicians can take the necessary time to evaluate a feature with multiple methods and from different angles, which is a luxury the in-line tools traveling with pipe flow don’t have. This field data provides our integrity engineers with the rest of the story necessary to make a call on whether or not the features identified require inspection.
Here is how we use this two-sided review process to tailor dig programs to focus only on the necessary digs.
When we receive a vendor report, the first thing our integrity engineers do is go through a quality assurance check to compare the tool output against reality. We align the data with prior in-line inspection listings, ensure that the vendor’s pipe properties assumptions (SMYS, wall thickness, seam type, etc.) make sense, and check mapping tool GPS coordinates against known locations that have been identified using field survey coordinates.
NDE data from the field is sent back to the integrity engineer for evaluation
Tool data isn’t helpful unless it can be tied to actual locations in the field. Although tool vendors do a good job managing the data, these reports can be hundreds of thousands of lines of data and as such there is always the chance that human error can disassociate columns. Occasionally we have found sections of the pipeline to be matched incorrectly or missing, and on one occasion the coordinates for the run showed anomalies in the middle of Lake Michigan.
After completing the initial data confirmation, we work through a series of steps to ensure that the features that end up on the repair plan are truly required. The following are some instances where this extra due diligence resulted in removal (or addition) of dig locations from the final plan:
Once a set of digs is passed to the field, communication becomes key. Increased communication and coordination between the inspectors in the ditch and the integrity engineers can result in greater efficiency both at the repair plan level and at the individual dig level.
Repair Plan Efficiencies from Tool Validation
Last year, one of our clients ran the exact same tool technology in two different pipelines. In one of the lines nearly every feature examined in the ditch measured dead on with the tool indications. In the other line the vendor report grossly overcalled depths and interaction groups. As further outlined in the “$4 million” story below, timely feedback to the integrity engineers prevented the removal of a large number of digs from the plan. Unity plots and detailed comparison between field and tool data is most effective if it happens sooner rather than later. Knowing a set of digs was unnecessary after the fact isn’t very helpful, but seeing a trend of overcalled features in real time may allow other locations to be removed from the plan before putting in the unnecessary effort.
Technician and Engineer Cooperation
Making a repair takes time, and as previously mentioned can have some measure of risk. I once heard a renowned pipeline welding expert say, “The safest weld on the pipeline is the one you don’t make.” This doesn’t mean that pipeline repairs are bad, but that they shouldn’t be done unnecessarily.
We prefer that the technicians in the ditch discuss what they are seeing directly with our engineers in real time. Although it can take a little longer to determine whether a repair is required, the additional discussion and analysis pays dividends.
3rd party damage found by ILI tool and repaired by the operator
How Field Feedback Saved $4 million
Acuren received an ILI report for one of our clients that just seemed “off.”
The pipeline was older and was laid mostly bare, so we knew there was a lot of “surface roughness.” However, our Senior Principal Engineer, Dan Cooper, had compiled repair plans on the same line over multiple cycles and had a fairly good idea of what to expect. So, when the final report had a significant number of 180-day corrosion features, we were both concerned and very curious.
Had something occurred to significantly accelerate corrosion?
Were previous tool runs under-reporting metal loss?
Did the pervasive surface roughness of this older line cause over-reporting of corrosion features?
What are we supposed to do next?
We decided to use laser scans of the pipeline from some “easy-to-get-to” locations to compare field found data with the tool run data.
Analysis by Acuren’s Steve Cooper of over 100 ILI indications against field data found that while the overall average showed good correlation, deeper ILI indicated pits had poor unity with field data. Ultimately, the tool vendor agreed with HT’s analysis and re-graded the report.
The re-grade removed over $4 million worth of digs from the repair plan. Not bad for a ~$40k investment of time and effort!
Having the background knowledge and ability to recognize when something’s not right can save significant time and expense. An experienced integrity team like Acuren can help you maximize effort on your tool runs and repair plans, saving both time and money.
Speak to our team about this project or to find out how we can help solve your complex challenges
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