Right Sizing Integrity Digs with Desktop and Field Validation
- Integrity digs are essential for pipeline safety, but unnecessary digs can divert time and resources away from other integrity initiatives
- ILI Tools are incredible, but not infallible — using an experienced consultant to review tool data helps to ensure only injurious features are inspected and addressed
- Desktop validation is a time intensive step requiring a skilled practitioner but can provide a big return on investment by reducing dig crew time in the field
- A field-to-office feedback loop is key to right sizing your integrity digs program and ensuring that only necessary digs and repairs are completed
“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 HT Engineering 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.
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.”
Don’t fix what “ain’t” broke
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:
- Financial cost – For most of our clients, $100k – $150,000 per dig is a reasonable figure. Features requiring inspection in wetlands or difficult access areas (such as under railroad tracks or highway) can end up being multi-million-dollar projects.
- Opportunity cost – Integrity digs are not the only maintenance activities on a pipeline. Each year pipeline management must determine how to allocate resources to both required and discretionary maintenance activities. Digging unnecessary features for inspection may divert resources from other maintenance projects that would be of greater benefit to pipeline integrity.
- Construction risks – Just as no surgery is “routine” if it’s happening to you, no integrity dig is “routine” for pipelines. Although some digs are arguably straightforward, each time the pipeline is excavated there is a certain amount of inherent risk involved. Most contractors are extremely professional and skilled at their work, but there is never a zero percent chance that something could go wrong. Accidental line strikes on the pipeline or adjacent utilities, pipe movement from soil disturbance resulting in coating damage, or human damage occurring outside of work hours, whether by accident or on purpose, are all possible (although unlikely) when a pipeline is exposed.
- Neighbor relations – Many pipelines that were originally laid in farm field are now in the center of suburban sprawl. Although pipeline operators have every legal right (usually by easement) to maintain their pipeline, it can cause headaches for landowners who are understandably frustrated that they can’t use their yard, swimming pool or their kid’s outdoor jungle gym in peace for a period of time.
- Shutdown costs – Sometimes repair plans include features that cannot be excavated and inspected in the required timeframe. This can be due to any number of factors such as environmental and road permitting, coordination with railroads or other 3rd party utilities, or impossible-to-reach features that necessitate a pipe replacement by horizontal directional drill. In such instances, an operator may be required to reduce pressure or even shut down the pipeline until the feature is properly addressed via inspection, repair, and/or replacement.
- Indirect Costs – If an operator makes repairs on the pipeline that are aren’t truly required, it could result in increased risk down the road and/or unnecessary environmental impact. Many repairs can be completed while the line is still in service, but these repair techniques come with their own set of potential risks. Although individuals who install repair sleeves are highly trained, a deviation from the repair installation method could result in corrosion or other problems later on. And for gas lines, a repair may require a cut out where gas is vented to the atmosphere as part of the process.
With extra digs having so many potential drawbacks, you can see why the dedicated team at HT Engineering 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.
Necessary Digs (and Repairs) Only!
A successful integrity program identifies and repairs potential problem spots on the pipeline but leaves the line undisturbed where no injurious features exist. At HT Engineering, 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.
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.
The Office Side: Desktop Validation
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.
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:
- Previously Completed Repairs – Sometimes tools can “see” previous repairs on a pipeline (especially steel sleeves), but this is dependent on both tool type and repair type. There is nothing more frustrating to a dig crew than digging up a previously inspected and repaired feature. Some operators can easily cross reference previous repairs with new repair plans. but for others it takes a little more research. However, the extra effort expended on the front-end to remove digs that were previously repaired is a direct cost savings.
- Digless Tool Validation – Often, the feature measurements from previous inspections and repairs can be used on subsequent tool runs to validate the performance of an ILI tool for certain feature types. This not only reduces the number of digs required but allows for faster feedback to the tool vendor if adjustments are required in the tool processing algorithm.
- Incorrect Input Assumptions – Accurate remaining strength and time dependant feature evaluations require accurate inputs such as pipe wall thickness, Specified Minimum Yield Strength (SMYS), and fracture toughness values. As the saying goes, “garbage in, garbage out” and if input assumptions are nonsensical then the results will be too. If there is an error in the report data, then a feature could be improperly included or excluded from a dig plan. These errors can be the result of a mistake made by the operator, the tool, or the data analysist. Not only does this step ensure that the right digs are added to the plan, but it ensures that the field has accurate pipe data which in-turn allows them to verify they are inspecting the correct pipe joint.
- Overly Conservative Rupture Pressure Calculation – There are several different methods for calculating which features require inspection and repair that are all acceptable per code. There is also more than one way to ‘dimension’ a feature before that sizing is run through all of the necessary calculations. Picking the correct calculation method as well as feature dimensioning method requires an experienced engineer. Vendor reports sometimes list estimated rupture pressures below normal operating pressure, meaning that the associated feature should already have failed while the pipe was in service. This can mean that the input assumptions are flawed, or that the rupture model is overly conservative. For certain features, we request more granular information from the tool vendor to make a more accurate assessment. The details of how we evaluate specific features is beyond the scope of this article, but there have been many occasions where the elimination of unnecessary over-conservatism saved both time and effort for our clients.
- Run/Tool Comparison – Not all tools see the same data or at the same level of detail. As outlined in the opening story for this article, some tools cannot distinguish between injurious crack-like features and manufacturing flaws like irregular seam geometry. As already described, the information gained by doing a run/tool comparison can result in further elimination of unneeded digs.
- Multi-Discipline Data Coordination – The data from ILI tool runs is only one part of the picture. Close interval surveys and information from other integrity programs such as Depth of Cover must all be overlayed to get a true picture of the current state of a pipeline. Our team takes the time to get input from other groups within the operator’s integrity team and coordinate efforts so that we maximize the impact of the dig program. This step can result in more rather than less digs, but it’s worth the effort (and is expected by the regulators) to ensure pipeline safety.
- The Gut Check – When something just seems off, it may mean that there’s an error you’ve never seen before in the data. Recently, one tool report we received had burst pressures that were very low and didn’t make sense based on the pipeline history. After much back and forth with the vendor, we received a corrected report with a number of digs and calculated burst pressures that were in line with expectations for the line’s history. While we do not know what corrective actions the vendor took, we do know that our gut check prevented unnecessary digs for tool validation. Using a consultant with extensive experience reviewing ILI reports increases the likelihood that errors are caught and corrected.
The Field Side: Tool Validation & Repair Calls
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.
How Field Feedback Saved $4 million
HT Engineering 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 HT Engineering’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 HT Engineering can help you maximize effort on your tool runs and repair plans, saving both time and money.