Theo Knijff, owner and founder of KAI-Con and a former manager at Dow, has spent his industry career tackling problems related to corrosion under insulation (CUI).
CUI is widely viewed around the world as one of the biggest asset integrity threats in the petrochemical industry, and it is considered the largest contributor to maintenance budgets.
Knijff’s experience stems from 36 years in asset integrity at large companies such as Dow Chemical, most recently as senior asset integrity manager for the company’s hydrocarbon business. Today, he runs KAI-Con, an independent consultancy helping organizations improve their asset integrity.
CorrosionRADAR (Cambridge, England), a leading provider of predictive CUI monitoring solutions, recently asked Knijff for an expert’s view on mitigating CUI risks while drawing upon his career experience of implementing remote monitoring. The following is Knijff’s perspective.
Whether the climate is cold and wet or dry and arid, corrosion under insulation (CUI) risks the integrity of oil, gas, and petrochemical assets. It’s not just an issue for regions such as the Gulf and North Sea Coasts, and weather is just one of many factors that can accelerate CUI risks.
Much of the industry has struggled to understand how unpredictable CUI can be. It won’t necessarily develop near a damaged section of insulation. Instead, moisture can ingress further, making it challenging to predict where deterioration could happen.
Also, CUI isn’t just a risk when assets operate between minus 12 °C (10.4 °F) to plus 177 °C (350 °F). Other conditions and operations, such as cyclic or intermittent service, can create environments where equipment and piping are susceptible to CUI.
As an example, marine-based loading and unloading insulated carbon steel (CS) pipes typically operate intermittently. If they transport cold hydrocarbons, the normal operating condition can be below the CUI-susceptible temperature range. However, when not in service, these pipes can heat up due to sun radiation and become CUI-susceptible.
In this scenario, temperatures can cycle from -12 °C to above dewpoint and even up to 60 °C (140 °F). As a result, the assets will move in and out of the sweating zone, which can accelerate corrosion.
When the metal temperature is within this range, protrusions (such as drains, vents, and instrument connections) and components (such as fasteners, structural supports, dead legs, gasket parts, and valve components) on CS equipment and piping operating outside the CUI-susceptible temperature range can also be susceptible for CUI. Corrosion is especially likely when the asset operates below -20 °C (-4 °F), and it will be visible in areas where ice and rust build up.
CUI is, therefore, unpredictable. The industry must change its mindset and become more
innovative to outsmart CUI.
Moving to Remote CUI Monitoring
Back in 2000, in this sector, CUI caused a serious process safety issue for a company. After this issue, there was a companywide action to improve its mechanical integrity (MI) program. The company did this by focusing on execution while strictly following the inspection standards for equipment and piping. The move helped to minimize the risk of further incidents.
These MI standards align with industry standards and are based on the hazard properties of the process fluid. If the hazard is higher, a mandatory larger inspection scope is required.
Of course, there is always a minimal CUI risk despite having standards. Stripping 100% of the insulation would command a cost that no one in the industry could withstand. It would also impact production.
Inspection findings showed that operating conditions such as cyclic, intermittent, or sweating service can accelerate CUI behavior assets, making it even more difficult to predict.
The findings led this company to develop specific MI strategies for assets with very high CUI susceptibility and a high consequence of failure. It gave priority to cracked gas (CG) dryers in plants operating in cyclic service.
During the late 2010s, we looked for 24/7 CUI monitoring systems for this type of asset. This would help minimize the risk of having new Incidents.
This is how I became aware of the CUI monitoring system from CorrosionRADAR. Pipe field tests were carried out to pilot its moisture and corrosion sensors. With successful outcomes, the next step was to install these sensors on a CG dryer, also in the field.
Confidence grew within our team that 24/7 monitoring could effectively predict CUI behavior. Further CG dryers were selected, as well as their associated cyclic service pipe to install these monitoring systems on.
Soon after the COVID-19 pandemic, remote CUI monitoring proved its worth. After just six months of CUI monitoring on a refurbished piping circuit (including coating and insulation), the sensors detected moisture and CUI.
We decided to remove all insulation and perform a visual inspection, which would validate the data output of this monitoring system. The inspection confirmed everything. Water droplets were found on insulation and coated pipe, and the coating showed minor cracks and brown flash rust.
Both Short and Long-Term Benefits
Using CUI monitoring technology and our 24/7 data supply, I started learning far more about different assets and how they behaved in specific environments. I soon discovered (confirmed with inspections) that even a quality coating system can start degrading within six months. This enabled me to help steer our inspection strategy around data-driven intelligence.
Aside from these benefits, I could also see the potential for remote monitoring to save money on inspections over the asset lifecycle.
Global industry standards, like those from the American Petroleum Institute, include guidance on defining CUI inspection intervals (every five to 10 years) and the extent of inspection (e.g. inspecting 50% of the susceptible locations and 75% of the damaged areas). Of course, this must also align with the regulatory inspection requirements.
The cost of inspections can easily mount up to hundreds of thousands of dollars, once factoring in extensive scaffolding to reach inaccessible areas and labor to remove large swaths of insulation ahead of an inspection.
By using 24/7 remote monitoring to inform the inspection strategy, we could be far more targeted and let the data guide us. This would ultimately reduce our physical field inspections, and this can shift the approach to “do nothing until the system tells you to.”
From that point, it will act. Preferably, it will act by completing a scheduled repair (insulation and coating refurbishment or mechanical repair) with zero surprises.
It's important to remember that inspections will monitor and “repair” while improving mechanical integrity. By using remote CUI monitoring, users can reduce inspection costs and target highlighted areas, thereby reducing the risk of nasty surprises or process safety Incidents.
Coatings are Important but Don’t Eliminate Risk
Some organizations believe coatings are an appropriate mitigation strategy for CUI. Under this approach, coatings act as an isolator for the CUI electrochemical reaction. The belief is no “electrical current,” no CUI. And in the main, it’s true.
But, from my experience, even thermal spray aluminum (TSA)—considered one of the best (and most expensive) coatings—can still degrade and leave assets at risk. That may be after five years or even 20 years. The timeframe depends on process conditions, coating quality, and a quality assurance/quality control program.
By choosing TSA, organizations expect a longer service life. But they still need to inspect the asset every five to 10 years. And without a remote monitoring system, they may have to remove insulation from 50% of the suspect areas. This leads to substantial costs and value-destroying actions.
So, even when assets have been coated and are brand new, I would still use remote monitoring to effectively mitigate CUI inspections. The continually available data can steer an inspection program towards specific risk areas while significantly reducing costs.
Considering the Best Inspection Method
When it comes to CUI monitoring, there are two typical inspection strategies to consider: condition-based and risk-based (RBI). And I would add a third: 24/7 CUI monitoring.
So, what’s the best approach, from my experience? I like taking an RBI approach. Implementing this prompts users to perform a corrosion study, initially defining the damage and corrosion mechanisms.
CUI is just one corrosion mechanism. Users must also take operational conditions, such as cyclical or intermittent service, into account. Expert opinions on corrosion rates can be difficult to define and may change in the future depending on factors such as insulation conditions.
Defined intervals for condition-based inspection relate to the minimum of an asset’s half remaining life, based on corrosion rates from inspection findings. It can also relate to a pre-defined inspection interval, as defined in the standard.
All these inspection strategies benefit from combining 24/7 remote CUI monitoring. By doing so, users can better understand and define possible inspection locations and corrosion rates. For example, from using remote monitoring, RBI risk calculations will be more accurate, and RBI inspection intervals will be better defined.
In my opinion, the third strategy of 24/7 CUI monitoring should be implemented for selected high-risk assets that need continuous monitoring for corrosion throughout their life. Once data output reviews are scheduled, with protocols in place for accountability, users can shift from inspection to a more optimized repair strategy.
Repair actions will only be taken on needs and while using inspections to confirm data output. All should be documented and scheduled in a maintenance management system.
Total Reliance on Remote CUI Monitoring?
Looping back to one of the biggest industry challenges, I’ve shown that remote monitoring makes CUI more predictable. When we can accurately predict the location and rate of deterioration, we can make data-informed decisions to target inspection and repairs.
Several large oil, gas, and petrochemical companies use the technology to achieve exactly this. As a result, it is reducing the short-term risk of incidents caused by CUI. And they are saving money in the long term from performing fewer and more targeted inspections.
In the future, I hope we can develop industry standards for remote CUI monitoring, since it would be a huge step forward for the oil and gas industry. Once a validated, 24/7 CUI monitoring system is established, users can 100% rely on it.
Having spent so much time learning about and mitigating CUI, I want to educate and support the industry to embrace a more effective method of reducing risk by adopting this new technology. In doing so, organizations can improve their process safety performance and reduce inspection costs.
Source: CorrosionRADAR, www.corrosionradar.com.