Published on 03-Sep-2026
CUI: How the Industry Is Revealing Hidden Threats Non-Destructively
Table of Contents
- Session Overview
- Meet the Panel
- Why CUI Is Different from Every Other Corrosion Mechanism
- The CUI Toolbox: What Actually Detects Corrosion Under Insulation
- Real-Time Monitoring and Permanently Installed Sensors
- Robotic Digital Radiography: From Screening to Measurement
- Gulf Humidity vs Desert Condensation
- Corrosion Under Pipe Supports: A Blind Spot Inside a Blind Spot
- Validation, Misconceptions and the 50% Solution
- AI, Predictive Maintenance and Digital Twins
- What Comes Next: Radio-Frequency and Microwave Sensing
- Rapid Fire and Audience Questions
- Key Takeaways
- Frequently Asked Questions
1. Session Overview
Corrosion under insulation is the damage mechanism the industry has spent decades trying to see. It develops out of sight beneath insulation and cladding, and it can progress to a leak or a failure while the asset looks entirely healthy from the outside.
This session brought together an operator-side NDT veteran from the Gulf, a corrosion engineering department head in Oman, and the head of a research centre that develops CUI technologies. No panelist claimed a solved problem, and all three arrived independently at the same conclusion: CUI is not managed by choosing the right method, but by combining screening, quantification and confirmation into a deliberate toolbox. What decides which methods ever get used is rarely the technology — it is access, geometry, insulation thickness, environment, validation and cost.
NDT Talks Episode 5 — CUI: How the Industry Is Revealing Hidden Threats Non-Destructively:
2. Meet the Panel
3. Why CUI Is Different from Every Other Corrosion Mechanism
Process corrosion can be modelled. You know the fluid, the temperature and the chemistry, so you can predict where metal loss will occur. Mr. Venugopal, who spent roughly a decade working with Indian refineries on CUI, drew the distinction sharply.
Mr. Manoharan Venugopal — CEO, Centre for Non-Destructive Evaluation, IIT Madras
“Process corrosion can easily be modelled, and by monitoring the process we can exactly identify the problem. But corrosion under insulation is external corrosion, hidden under the insulation and the cladding. In a refinery, if you see the piping, it is hundreds of kilometres, and around 60% will be insulated. So where do you find it? It is hidden corrosion, it is a huge volume, and the locations are inaccessible. That is the real challenge in CUI inspection.”
That 60% figure is the heart of the problem. CUI is not a difficult measurement — once the insulation is off, it is ordinary external corrosion any inspector can size. The difficulty is entirely one of scale and access.
Mr. Mohammed Abufour — NDT specialist, oil, gas and energy; ASNT Lifetime Member
“From day one we know that CUI is hidden — you cannot see it. The company I work for has offshore, onshore, LNG and power plants. Especially here in my region, we live near the Gulf where humidity is high — we get 100% humidity. And this infrastructure was built in the last century, from the 1950s and above. So we did visual inspection, radiographic testing, profile shots in the areas we suspected — and we would be lucky to find something, because we cannot see it. It is really a threat to the operation.”
4. The CUI Toolbox: What Actually Detects Corrosion Under Insulation
Mr. Venugopal divided the available technology along the axis that matters operationally — what a method actually outputs.
Mr. Manoharan Venugopal — CEO, Centre for Non-Destructive Evaluation, IIT Madras
“I can divide it into two types of technology. One is where we can quantify the wall thickness measurement. The other is what can measure water ingress and moisture. Quantification can be spot or it can be over long range. For spot measurement we use computed radiography, a digital detector, or film radiography with tangential radiography — there are ISO standards available for that to accurately measure the wall thickness loss. Pulsed eddy current is another method used for quantification, but it gives the average thickness, which may miss the pitting corrosion. For long range, you take guided wave UT using piezo or magnetostrictive sensors. For moisture or ingress detection, microwave is one of the methods used, which can use the pipe as a coaxial waveguide.”
Mr. Manoharan Venugopal — CEO, Centre for Non-Destructive Evaluation, IIT Madras
“There are various technologies, but as I said, not a single technology will really solve the problem. It has to be an approach of a CUI toolbox, which can be continuous monitoring, moisture detection, with some spot thickness measurement. Radiography can only be used for pipe — for tanks and other big structures it is not suitable. In that case we have to use pulsed eddy current, or Compton backscatter imaging is another one.”
Dr. Talal Al Nabhani — Head of Materials and Corrosion Engineering, Petroleum Development Oman
“There are some areas where we can see almost real time — corrosion radar, pulsed eddy current, guided wave UT provide real-time data. However, we will need supportive NDT to quantify. It is a qualitative method rather than something that really gives you a thickness measurement and makes you confident. And sometimes you cannot do those inspections because of geometry restriction, or the area is difficult to get access to.”
Screening, Quantification and Confirmation
Treating these as three distinct jobs, rather than expecting one instrument to do all of them, is the structure the whole panel worked from.
CUI Detection Methods Compared
5. Real-Time Monitoring and Permanently Installed Sensors
An audience question on predictive CUI monitoring using permanently installed wire sensors produced one of the more practical exchanges of the session. Mr. Abufour's organisation now installs sensors as standard on new construction and retrofits them selectively in known problem zones.
Mr. Mohammed Abufour — NDT specialist, oil, gas and energy; ASNT Lifetime Member
“It is very easy to install those sensors — putting them there, and with the analytics and the workstation they send the information to the workstation and you can monitor it. Even with your mobile you download the app and you receive all the information. The good thing with those sensors is that the life of the sensor is 10 to 15 years. So your plant, your pipeline, your pipework will be monitored 24/7. If you get any problem, you can use digital radiography — it really helps you spot check to verify.”
Dr. Al Nabhani had trialled the same class of sensor under controlled conditions — installed on a line already known to have a problem, then opened after a period to check the data against reality.
Dr. Talal Al Nabhani — Head of Materials and Corrosion Engineering, Petroleum Development Oman
“From the trial we set up, yes, it was finding good results. They were able to prove it to us, because we know the line which has that issue, so we put those on the same line we know, and we opened it after a while. So the data almost helped. But those sensors could also have a limitation — if it stays for long, maybe because of scaling and corrosion, that may impact the readings. So we have to be careful. It is not one solution fits everything.”
The distinction that matters: a moisture sensor predicts nothing on its own. As Dr. Al Nabhani put it, it can predict that the moisture is there, but how much corrosion rate and how that is growing needs far more data. Rate and growth require historical context and a supporting quantification method before any prediction is defensible.
Permanently installed sensors are increasingly replacing periodic inspection, see our full guide to IoT-based continuous monitoring.
→ Read: IoT and NDT for Monitoring and Predictive Maintenance
6. Robotic Digital Radiography: From Screening to Measurement
The technology Mr. Abufour was most animated about was robotic crawlers carrying digital radiography along insulated lines, because it closes the gap between a screening result and an actionable number.
Mr. Mohammed Abufour — NDT specialist, oil, gas and energy; ASNT Lifetime Member
“I am in discussion now with one company that has robotics with digital radiography. We already use this robotic here in the Kingdom, which moves on the pipe, on the straight line, to verify whether we have corrosion or not. It provides a measurement of the wall thickness if there is any reduction. The sensors still have some limitation with complex geometry — elbows, reducers and others. But the robotics move on the pipe, and whenever there is suspicion of moisture or something, it can take a shot on that area and give you precise measurement. That is really a good move from screening, like guided wave, which verifies at maybe 20 to 50 metres whether we have corrosion or not.”
Mr. Mohammed Abufour — NDT specialist, oil, gas and energy; ASNT Lifetime Member
“We approved two companies. One from the US — they did only straight line, but the problem is they are limited to 14 in. The other one has no limit, even with 36 in, and we did tangential because some of our insulation is really thick. For ground level we use the profiler systems, and for those vertical or horizontal overhead lines we use robotics.”
Why coverage matters more than precision here: handheld pulsed eddy current and profiler systems work at ground level. A crawler travels the overhead and vertical lines that inspectors cannot reach without scaffolding. For overhead pipe racks, that difference decides whether an inspection programme is feasible at all. Mr. Abufour was candid that the technology is costly and available from very few suppliers worldwide.
7. Gulf Humidity vs Desert Condensation
One of the more useful contrasts of the session was between two operators in the same broad region facing structurally different versions of the same mechanism. Asked for a memorable CUI failure, Dr. Al Nabhani said he did not really have one.
Dr. Talal Al Nabhani — Head of Materials and Corrosion Engineering, Petroleum Development Oman
“To be honest we did not have CUI, because we are lucky that we are operating in a dry area. The purpose of the insulation is to maintain the heat of those pipes, and sometimes even to protect people. One thing happened recently — there was a leak and it touched pipes which are very hot and uninsulated, and at 170 or 180 it ignites fire. So now the team decided to insulate. Now it is the opposite. We used not to insulate because it is a dry area.”
Condensation Is the Desert Version of CUI
Dr. Talal Al Nabhani — Head of Materials and Corrosion Engineering, Petroleum Development Oman
“The only thing you worry about sometimes is condensation, which is really sometimes a challenge for us. When there is condensation you go and do inspection, and either you need to open the insulation and people really resist, because sometimes you need to shut down, or because of the temperature. Now we came up with the idea of a window — you make just one area to open and you check and you do the UT. We put it as part of an integrity operating window to ensure that condensation, if it happens, is already known because of the temperature difference. So we do it proactively rather than waiting until something bigger happens.”
Two practical measures came out of this: inspection windows, which remove much of the operational resistance of a full strip-down, and folding condensation risk into the integrity operating window so a temperature excursion triggers inspection rather than a calendar date. Many programmes treat rainfall as the water source and overlook the fact that a temperature differential produces water under the cladding on its own.
8. Corrosion Under Pipe Supports: A Blind Spot Inside a Blind Spot
Mr. Manoharan Venugopal — CEO, Centre for Non-Destructive Evaluation, IIT Madras
“One of the problems in CUI is corrosion under pipe support — that is something very unique. I think all the technology we talked about will not work there. For that, our centre worked on higher-order mode clusters. It is a guided wave technology, used specifically for corrosion under pipe support. They are providing it as a service globally.”
The geometry is the reason. At a support, the pipe is in contact with a structure, there is no line of sight for radiography, and the contact region traps water. The higher-order mode cluster technique, developed at the Centre for Non-Destructive Evaluation under Professor Krishnan Balasubramaniam, propagates a clustered guided wave mode through the support region and detects wall loss without requiring access to the contact area.
Practical implication: a CUI programme built around long-range screening plus spot radiography will systematically miss pipe supports unless CUPS is treated as a separate line item with its own method.
9. Validation, Misconceptions and the 50% Solution
Asked about common misconceptions, Mr. Abufour went straight to the gap between where a technology is developed and where it is deployed.
Mr. Mohammed Abufour — NDT specialist, oil, gas and energy; ASNT Lifetime Member
“It happens with all technologies. The developer — whether he is in Europe, the States, Asia or anywhere — will do it most of the time in the lab. Then later on he will take it to maybe one application, or two, or three, maximum five. But the environment here is a harsh environment. We have humidity, we have desert environment. So validation for the technology — many technologies have been introduced for CUI and we reject many. We really reject many. We ask the developer to go back and make sure it meets our requirement.”
His organisation runs a formal gate: desktop review against the actual challenge, then field validation under local conditions, then rejection back to the developer. The second misconception is the inverse — the belief that an imperfect method is not worth deploying.
Mr. Mohammed Abufour — NDT specialist, oil, gas and energy; ASNT Lifetime Member
“In my opinion, I do not want to stay with zero solution. If I get a 50% solution, that is much better than keeping our pipelines and pipework without any inspection. We also asked some developers for really good insulation — there are some insulations that can give you 25 or 30 years warranty that no moisture will be there.”
Asked what a facility typically spends on a monitoring programme, he declined to give a figure — spend is decided by whether the challenge is a corporate-level integrity risk or something the site can resolve internally. Anything reaching management requires validation results and a calculated cost saving before it is submitted at all.
10. AI, Predictive Maintenance and Digital Twins
Dr. Talal Al Nabhani — Head of Materials and Corrosion Engineering, Petroleum Development Oman
“The problem with oil and gas is that they are not very fast in the implementation of those technologies compared to other industries, and that is a fact. The world is going ahead, and if you are not trying to embrace it now, you will be left behind. But AI — do not expect it to replace the peer review and personal competency. It will not replace people. Some people have that worry, that if tomorrow I have AI I am not going to need any inspectors or engineers. That is not true, you need both. However, it will enable me to analyse huge data sets and patterns that need months of analysis, and sometimes the prediction of corrosion behaviour.”
His organisation has not yet deployed AI as a predictive inspection tool, but the raw material is not the constraint — thirty to forty years of inspection records exist. A digital twin programme is planned for next year, tied to permanently installed NDE and UT monitoring spots feeding data readable from the office.
Where Predictive Tools Change Inspection Economics
Dr. Talal Al Nabhani — Head of Materials and Corrosion Engineering, Petroleum Development Oman
“Inspection starts with time-based inspection first — every six months, every six years — and we do it regardless of the corrosivity of that area, just to get more assurance. Then it moved to risk-based inspection, where you calculate consequence, likelihood, previous inspection data, what happened to the environment. Now this predictive tool is more advanced. The challenge in the industry now is that if you have 600,000 tags to be inspected, that is a huge number. Those predictive tools tell you where you need to focus your inspection, based on the environment condition change, based on the ageing of that piece of pipe, based on the data collected before.”
Dr. Talal Al Nabhani — Head of Materials and Corrosion Engineering, Petroleum Development Oman
“The first thing to sacrifice when the oil barrel is very low is inspection — they say let us defer it, let us defer it. If you have this predictive tool, you know how to focus.”
The internal argument that lands: predictive inspection is not a technology upgrade, it is a defence of inspection budget during downturns — fewer crew exposed, lower unit operating cost, and a defensible reason not to defer.
AI-assisted interpretation is already established in radiography, see our deeper look at how it is applied to digital X-ray evaluation.
→ Read: AI Digital Radiography Interpretation
11. What Comes Next: Radio-Frequency and Microwave Sensing
Asked what is genuinely worth evaluating over the next five to ten years, Mr. Venugopal pointed to two developments built on radio-frequency and microwave physics, both aimed at the moisture side of the problem.
Mr. Manoharan Venugopal — CEO, Centre for Non-Destructive Evaluation, IIT Madras
“I worked almost for 10 years using microwave for moisture or water ingress detection in insulation. We used the pipe as a structure, and we were close to detecting water ingress over 30 metres. One of my friends who was working with me moved to the UK for his PhD, and after completing it he started this corrosion radar company. What they use is radio frequency, but they do not use the pipe as a waveguide. What they have done is a wire and a coaxial cable, and through that they send the radio frequency wave. These cables can be permanently installed over the pipe under the insulation. So if moisture enters at any location over almost 50 metres length, it will tell you where the water ingress happens.”
Mr. Manoharan Venugopal — CEO, Centre for Non-Destructive Evaluation, IIT Madras
“It is a sacrificial coaxial cable which they put in, so if corrosion starts happening it can give a signal where exactly corrosion activity is more and what is the rate of corrosion. What they do is use some predictive tools — they take this data and also the historical data of temperature, what type of coating, when the insulation was used, and then they predict where failure can happen. That is something very, very interesting. Another company uses microwave with the pipe as a waveguide — they send microwaves for water ingress detection and they also have some predictive tools. These two are the new technologies which are worth exploring.”
Mr. Davis noted the convergence from an unexpected direction: his own work applies microwave testing to fibreglass, including void content in wind turbine blades and water ingress in helicopter blades. The same physics is arriving at CUI from aerospace in parallel with oil and gas.
12. Rapid Fire and Audience Questions
What is the number one challenge in detecting CUI today?
Dr. Talal Al Nabhani — Head of Materials and Corrosion Engineering, Petroleum Development Oman
“In my opinion there is no one-stop solution. So you cannot say this method, I detect it, full stop. There was always mix-up and build-up, and confidence always brings you how confident you are. You need to try maybe two or three tools to complement each other, or the naked eye — you open it. But there is no one-stop solution where you can say I can give you assurance.”
Which corrosion mechanism is hardest to detect?
Mr. Mohammed Abufour — NDT specialist, oil, gas and energy; ASNT Lifetime Member
“I believe environmental corrosion cracking is worse than CUI, because whenever there is cracking it will lead to failure. Corrosion under insulation is a silent problem, but the other one, the cracking, is like a cancer. If it is there, you have to find it. Both are enemies to the operation, but environmental corrosion cracking is worse.”
Your go-to CUI technology?
Mr. Manoharan Venugopal — CEO, Centre for Non-Destructive Evaluation, IIT Madras
“It is water ingress detection — that is one thing. But I can say that I have worked with many customers, and I think whatever technology you suggest, finally they prefer to strip off the insulation and visually inspect.”
Mr. Mohammed Abufour — NDT specialist, oil, gas and energy; ASNT Lifetime Member
“Maybe I disagree. Now with the sensor there is no need to remove — you put the sensor looking just for moisture. But for the time being, robotics with digital radiography — at least I can cover most of the area that I can inspect and verify there is no corrosion, and it provides me a measurement if I have a reduction in wall thickness. Other than taking a guided wave, which is just screening, or eddy current, which is handheld so you will only do a small area at ground level. Digital radiography with robotics can move from ground level to the top overhead line.”
The split is instructive: the technology developer sees what customers ultimately trust; the asset owner sees what is physically achievable across thousands of metres of overhead pipe where stripping insulation is not an option. Both positions are defensible.
Can NDT distinguish CUI from chloride-induced or steam-leak corrosion?
An audience member working on marine steam systems asked what indicators can separate classic CUI, chloride-induced external corrosion, and corrosion driven by steam leakage or wet-dry thermal cycling. Mr. Davis doubted any single NDT modality could do it without opening the insulation. Mr. Abufour largely agreed.
Mr. Mohammed Abufour — NDT specialist, oil, gas and energy; ASNT Lifetime Member
“If you have digital radiography, it may help to distinguish, especially if you look at other parameters — what is the surface of the pipe, the type of material. But the bottom line, I am looking for corrosion — if I have corrosion or not corrosion. Then later on, remove the insulation and you can tell what type of corrosion you have. In some cases I can tell whether I have scattered or clustered corrosion, but exactly the type, other parameters will help me.”
The practical sequence: use NDT to answer whether corrosion is present and how much wall is lost, then open the insulation at that location and use morphology, material type and temperature history to identify the mechanism.
13. Key Takeaways
- CUI is a scale and access problem, not a measurement problem. Around 60% of refinery piping is insulated, and once insulation is removed it is ordinary external corrosion any inspector can size.
- No single technology solves CUI. All three panelists said this independently. Build a toolbox: screening to locate, quantification to size, insulation removal to confirm the mechanism.
- Separate screening from quantification. Guided wave UT, microwave, infrared and moisture sensors tell you where to look. Radiography and pulsed eddy current tell you how much wall is left.
- Pulsed eddy current returns an average thickness and may miss pitting — worth stating explicitly in inspection procedures.
- Permanently installed moisture sensors run 10 to 15 years and support remote monitoring, but they detect moisture, not metal loss, and readings may drift as scaling and corrosion develop.
- Robotic digital radiography was the most cited advance, because it reaches overhead and vertical lines and returns a wall thickness number rather than an indication. It is costly and available from few suppliers.
- Dry environments are not exempt. Condensation from temperature differentials produces CUI without external water, and an integrity operating window manages it better than a calendar interval.
- Validate technology in your own environment. Lab and limited-field validation does not transfer to 100% humidity or desert conditions, and rejecting technologies back to developers is normal practice.
- A partial solution beats no solution. A 50% capability deployed across uninspected pipework is more valuable than waiting for a complete one.
14. Frequently Asked Questions
What is corrosion under insulation (CUI)?
Corrosion under insulation is external corrosion of piping, vessels and equipment occurring beneath thermal insulation and cladding. Water reaches the metal through damaged cladding, joints, or condensation from temperature differentials, and corrodes the steel out of sight. Because the insulation conceals both the water and the damage, CUI can progress to leakage or failure while the asset appears sound externally.
Why is CUI harder to detect than other types of corrosion?
Process corrosion can be modelled and monitored because fluid chemistry, temperature and flow are known. CUI cannot. It is external, hidden, and driven by insulation condition and environment rather than process variables. In a refinery, roughly 60% of piping is insulated and much of it is inaccessible, so the challenge is deciding where to inspect across an enormous volume with no visual access.
Which NDT methods are used to detect corrosion under insulation?
The methods discussed include infrared thermography for wet insulation, tangential radiography using film, CR or digital detectors for wall thickness, pulsed eddy current for average thickness through insulation, guided wave ultrasonic testing for long-range screening, microwave for water ingress, permanently installed radio-frequency wire sensors for moisture and corrosion rate, Compton backscatter imaging for large structures, and robotic crawlers carrying digital radiography for overhead lines.
Can one NDT method detect CUI reliably on its own?
No. All three panelists stated independently that no single technology solves CUI. Screening methods such as guided wave UT, microwave and moisture sensors indicate where corrosion or water may be present but are qualitative. Quantification requires a second method such as tangential radiography or pulsed eddy current. Confirming the corrosion mechanism generally still requires removing insulation at the located area.
Does CUI occur in dry desert environments?
Yes, though the driver differs. In dry regions the main risk is condensation from temperature differentials between the process line and ambient conditions, producing water beneath the insulation with no external water source. Managing this through an integrity operating window — triggering inspection when conditions indicate condensation is likely — is more effective than a fixed calendar interval.
What is corrosion under pipe supports and how is it inspected?
Corrosion under pipe supports, sometimes abbreviated CUPS, occurs where a pipe rests on a support structure. The contact region traps water and offers no access or line of sight, so most conventional CUI methods do not work there. Higher-order mode cluster guided wave techniques were developed at the Centre for Non-Destructive Evaluation, IIT Madras specifically for this, and are offered as a commercial service.
How is AI being used in CUI and corrosion management?
Adoption in oil and gas is slower than in other industries, but the application is clear: analysing decades of inspection data to identify patterns, predict corrosion behaviour and prioritise inspection across very large tag populations. AI focuses inspection effort rather than replacing inspectors, peer review or engineering competency.
Where can I watch this NDT Talks session?
The full session is available on the OneStop NDT YouTube channel:
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