Inline Pipeline Inspections: A Case Study Comparing Magnetic Flux Leakage (MFL) and Ultrasonic (UT) Assessment Tools

In the complex field of pipeline integrity management, it’s vital to select the right inspection technology to maintain safety and operational efficiency. Over time, it’s not uncommon for liquid pipelines to experience internal corrosion and pitting which can lead to structural integrity issues.

For many years, pipeline operators used traditional inspection methods such as magnetic flux leakage (MFL) to detect these anomalies. MFL relies on magnetic fields to identify areas of metal loss. Disruptions in the magnetic field point to potential defects, making MFL a valuable technique.

However, MFL’s effectiveness may be limited by factors like the material of the pipeline and environmental conditions. As a result, many pipeline operators sought more precise and reliable technologies capable of detecting subtle and complex issues.

In response, NDT Global pioneered the use of ultrasonic (UT) technologies to provide a more comprehensive assessment of pipeline conditions.

UT uses high-frequency ultrasonics to measure pipe wall thickness and identify any areas of corrosion or metal loss. UT excels in uncovering issues that may slip through MFL's grasp. For example, MFL may struggle with pit-in-pit corrosion, metal loss-on-metal loss corrosion, or metal loss with complex morphology.

Today, UT has become the go-to technology for many companies. The accuracy of UT and its sensitivity to pipeline flaws set it apart from other inspection methods.

The following case study compares the results and learnings from UT and MFL inspections of the same offshore pipeline to illustrate each inspection technology's advantages and potential limitations.

NDT Global’s Approach to Inline Pipeline Inspections

NDT Global understands that complex pipeline systems require precision inline inspection to ensure safety, quality, and cost-effective management. Our approach is simple and centers on giving our clients the “Power of Clarity.”

The Power of Clarity is about having the best people develop the best technology that collects and captures the best data. With superior diagnostic data, we can provide the best actionable insights into the true condition of pipeline assets. When our pipeline operator clients have the best insights, they can make the best decisions that ultimately deliver the best outcomes for communities, the industry, and the environment.

What Are Magnetic Flux Leakage (MFL) Tools and How Do They Work?

Magnetic Flux Leakage (MFL) tools establish a magnetic field circuit using the pipe wall as a conductor. Where metal loss is present, some of the magnetic field will leak out of the pipeline wall, where a sensor detects it. Calibration is then used to determine the feature size based on the amount of leaked magnetic flux. MFL tools may be oriented in two ways:

In axial MFL, the field is oriented parallel to the pipe axis. Axial MFL makes the tool more sensitive to the circumferential width of features or anomalies.
In circumferential MFL, the field is oriented around the circumference of the pipe. Circumferential MFL makes the tool more sensitive to the axial length of features or anomalies.

What are Ultrasonic (UT) Tools, and How Do They Work?

Ultrasonic (UT) tools use a pulse-echo technique to obtain a direct measurement of wall thickness. A piezoelectric sensor emits a sound wave that travels via a liquid coupling through the pipeline wall. As the sound wave hits the interface between the pipe wall and the outside surface, the signal bounces back due to a change in material property. Tracking the interface change between the inner pipe surface and the outer pipe surface makes it possible to precisely calculate the wall thickness.

Unlike MFL sensors that touch a pipeline’s walls, UT sensors are offset from the walls. This means they can measure the wall thickness as well as the standoff, i.e., the distance from the sensor to the internal surface, providing insight into whether features are internal or external.

MFL vs. UT – Key Differences

Use Cases

MFL does not require coupling, so it can be run in both gas and liquid lines. UT tools require a liquid medium in which the sound from the sensors can travel, so they’re not suitable for use in gas pipelines without adding some type of liquid or doing batch inspections. However, there are ultrasonic options for gas pipelines, like NDT Global's gas CD tools, which use ultrasonics and acoustic resonance to measure the wall thickness.

Cleaning Requirements

The techniques employed in MFL are less sensitive to residual dirt, so the pipes being inspected don’t necessarily need to be clean. However, UT tools require cleaning to ensure they can accurately capture the sound signals they rely on to gather pipeline integrity data.

Reporting Timelines

MFL relies on sizing algorithms and analysts to process the data it gathers. Human analysts may only have sight of certain features, so the turnaround time for generating MFL inspection reports is generally fast. When it comes to reporting, UT tools require an analyst to review all the features in the data, including highly complex ones, which means it can take longer to produce a report than when using an MFL tool.

Sizing Accuracy Relative to Wall Thickness

While MFL data is a relative measurement, UT data provides a direct measurement, and the tool’s tolerance is the same regardless of wall thickness. As the diagram below illustrates, as the wall thickness increases, the sizing accuracy band of the MFL tool widens, whereas it remains constant when using a UT tool.

Presentation of Data

One key difference you’ll notice when comparing MFL and UT findings is the number of boxes reported due to the different methodologies used to take measurements. For example, in the diagram below, the results of the UT inspection appear in the single yellow box. The 11 smaller white boxes represent the corresponding MFL data in the same metal loss area.

If you run these two types of inspections on the same infrastructure, your report visuals will look very different. It’s important to talk to your inline inspection provider to understand how your results are presented.

Case Study: MFL vs. UT Technology

As we delve deeper into comparing and contrasting the capabilities of MFL and UT tools for assessing pipeline integrity, it’s helpful to draw on the findings and learnings from a recent NDT client engagement.

The client approached NDT Global with a dilemma. Despite leveraging an integrity management program (IMP) that included three annual inspections using axial MFL tools, they discovered a leak in their pipeline. A different service provider had performed each yearly MFL inspection.

Because no leaks had been detected with MFL, they felt they needed a different picture and technology to address their concerns. They turned to NDT Global to inspect their pipeline using a UT tool.

The results painted a vastly different picture of the health of the pipeline walls.

Let’s start by comparing the results of our UT inspection of the client’s pipeline with those of the three previous MFL inspections using the diagram below:

The blue dots indicate the deepest point of every pipe joint along the distance of the pipeline inspected by the UT tool.
The UT inspection goes down to 90% depth—the deepest point and where the leak occurred.
The findings of the three MFL inspections are indicated in yellow, gray, and orange.
None of them could measure anything near this deepest point, and the results only hint at what might be the core of the problem, which, in this case, is the wall thickness.
Also interesting is that the UT data captured a distinct wave pattern trend in the depth of the features along the distance of the pipeline. MFL failed to capture this trend. It’s possible that the finding could be related to the elevation of the pipeline in this particular section. Whatever the reason, this might be a useful piece of information for the operator.

The following bar chart summarizes the differences between the MFL and UT inspections and depicts the average depth of all the features discovered in each inspection:

The UT tool measured an average feature depth of over 50%, whereas all three MFL tool inspections measured an average of around 20%.
The black line indicates the maximum and the minimum feature depth measured by each inspection. The deepest point measured by UT was 90%, whereas the deepest the MFL inspections were able to measure was between 50 and 60%.

Next, let's home in on the deepest point analyzed in the UT data and compare this to what the MFL inspection detected:

The red line indicates the UT wall thickness which traces the shape of the feature at its deepest point in the pipeline. It runs to a depth of 90% of the wall thickness (approximately three inches or 75 millimeters in length.)

In contrast, the first MFL inspection in 2019 found a feature roughly in this area, with a depth of just 20%. The second MFL in 2020 located a feature with a depth of 24%, and the third MFL inspection in 2021 located a feature with a depth of 18%.

So, while the MFL tool did detect the feature at its deepest spot, it did not record the correct depth. It’s likely that the MFL tool was unable to measure the depth correctly because it relies on calibration; it needs to know the wall thickness. When the wall thinning is not what the tool expects, MFL can deliver sub-optimal results. It's also possible that MFL, because it's a volumetric measurement, runs into problems with accuracy when the situation involves metal loss within metal loss, and the loss occurs around the entire circumference of the pipe, which was the case in this particular scenario.

As this case study illustrates, UT data gives pipeline operators an excellent view of the topography of the metal loss, even in complex situations. Moreover, since it provides a direct measurement, operators can be confident in the values, regardless of the pipeline’s wall thickness.

Another benefit of UT tools is that because they provide such a comprehensive view of corrosion conditions, they allow for precise corrosion monitoring and accurate calculation of expected corrosion growth rates over time. This is especially important when operators face complex corrosion scenarios or when they manage high-consequence pipelines.

Overlaying UT Insights with Corrosion Management Best Practices to Gauge Safe Operating Pressure and Pipeline Longevity

With a clear view of corrosion and metal loss within their pipelines delivered by UT technology, pipeline operators can apply industry best practices, specifically DNV-RP-F101, Appendix D, to calculate safe pipeline pressure capacity.

This methodology is designed for long-term management of long axial corrosion in pipelines, i.e., corrosion or channeling spanning multiple pipe joints.

In the case of long axial corrosion, you might think that taking the length of a joint and using the deepest feature is the appropriate starting point for an assessment. However, that approach would not capture the complexity of the metal loss in its entirety and would be too conservative.

For long axial corrosion, the topography of the corrosion needs to be considered along with river bottom profiles (RBPs), which are easily obtained using ultrasonic data. And because long axial corrosions often span multiple pipe joints or even kilometers of pipe joints, it's also important to take into account what’s called the system effect when calculating safe operating pressure capacity.

The system effect is designed to help operators quantify the presence of multiple pipe joints with low-pressure capacity potentially running over several kilometers of pipe joints.

The DNV standard allows you to calculate a safe operating pressure for a pipeline in this situation using probability of failure (PoF) metrics. It lets you mathematically combine individual PoFs for features, pipe joints, or segments to arrive at a pressure value representing the entire pipeline system.

This approach also allows pipeline operators to determine the remaining life of the pipeline by calculating the corrosion growth rates for the long axial channeling sections.

Here again, best practice involves looking at river bottom profiles. That’s because if you simply calculate corrosion growth rates joint by joint, the results are unlikely to be meaningful because the deepest point could change year-over-year, or your calculation might not take into account the fact that certain sections of pipe joints have higher corrosion growth rates than others.

So, by breaking pipes up into smaller, one and a half meter segments using actual wall thickness data, you get a more granular picture of joint corrosion growth rates, rather than an average value.

Once you have accurate corrosion growth rates, you can calculate the future system capacity by repeating the system effect calculation until the safe pressure is equal to the MAOP. This will also give you a clearer understanding of when a pipeline will likely need to be repaired.

Summing Up

Managing the integrity of pipelines by means of inline inspection is possible, but as we’ve explored, it is crucial that the right technology is chosen for the application.

MFL is a very useful tool; it’s less costly than UT tools and doesn’t require extensive pipeline cleaning. However, it can give pipe operators a false sense of security about the true condition of their pipelines.

Our case study underscored the fact that repeatedly running MFL inspections and trusting the results without getting a reality check from UT technology isn’t a wise move. We saw that MFL doesn’t always perform as expected, especially in cases where there’s extensive wall loss over the entire circumference of the pipeline or metal loss within metal loss.

UT tools, while more costly and have a cleaning requirement, offer repeatable, direct measurements under extremely challenging conditions. In addition, once you have ultrasonic data, you can use the DNV-RP-F101, Appendix D method to calculate the safe pressure capacity of a pipeline, considering the system effect in cases involving long axial corrosion with complex and/or extensive metal loss.

NDT Global is an industry leader in ultrasonic UT inspection methods. We can help you identify metal loss and other anomalies by leveraging the best people and technologies to deliver the best actionable insights into the true condition of a pipeline asset..

That's the Power of Clarity at work, delivering the best outcomes for your business, people, and the environment.

Contact NDT Global to learn how the Power of Clarity can help you make data-driven decisions across your organization.