By John Reynolds at Intertek. This article appears in the May/June 2004 issue of Inspectioneering Journal
CUI may be the most well known and widespread corrosion phenomena in our industry. It’s also one of the most difficult to prevent because by and large no matter what precautions we take, water eventually gets into the insulation and begins to do it’s dirty work, sometimes sight unseen until process leakage occurs. And it’s not isolated to just insulation. Corrosion under fire-proofing (CUF) is also prevalent in our industry and requires the same type of inspection planning, design prevention, and mitigation that is required for CUI. For the carbon and low alloy steels, CUI typically occurs between 25 degrees F (-4C) and 250 degrees F (121 C). However, there have been numerous cases of aggressive CUI reported up into the 300+ F range, so it really is a matter of making sure you don’t get water into insulation systems below 350 F, as the intermittent boiling and flashing that occurs above a metal temperature of 212 F (100 C) produces a fairly aggressive CUI environment.
CUI corrosion rates are difficult to predict and can be somewhat general in nature or more often highly localized. Corrosion rates may vary from 1-2 mpy to over 40 mpy, depending upon numerous circumstances that should be included in the probability of failure analysis of an RBI assessment. Effective coatings on the steel surface under insulation may last for many years before the coating breaks down and corrosion begins. An insulated system that lasted for 30 years before a CUI leak may not have corroded for 10-15 years (or even longer in some cases) before the coating broke down and allowed moisture to contact the steel substrate.
Issues that will lead to higher corrosion rates from CUI include: marine environments, hot/humid environments, climates with higher rainfall, steam tracing leaks, contaminants from the atmosphere or from the insulation (such as chlorides and sulfides) dissolving in the water, higher temperature ranges (just below boiling) where dissolved oxygen is a major factor, intermittent wet-dry conditions, systems that operate below the typical atmospheric dew point (sweating services), insulating materials that hold moisture, and insulation system designs that do not allow moisture drainage. As you can see from the foregoing, the probability of failure side of the risk equation is multifaceted, and difficult to predict. It’s not uncommon to strip 10 spots on equipment susceptible to CUI and only find one spot with significant corrosion. On the other hand, on the equipment with higher susceptibility, you can also find significant CUI in over half the spots where you strip insulation looking for CUI.
API 570, Piping Inspection Code - Inspection, Repair, Alteration, and Rerating of In-Service Piping Systems provides some excellent guidance on how to determine which piping systems are most susceptible to CUI (section 184.108.40.206). Additionally, the code also provides guidance on the most common locations to find CUI (section 220.127.116.11) on those systems that are determined to be susceptible to CUI. In spite of all the good guidance on where to look for CUI on susceptible equipment, it seems like some small amount of CUI is almost unpredictable and may be out in the middle of a column or in the middle of a vertical rise of piping with no insulation penetrations in the vicinity and no obvious moisture traps.
There are several inspection tools and techniques that can help us determine if we have CUI or CUF without removing the insulation, but none are fool-proof and most do not provide us with a good understanding of the maximum depth of the CUI damage. So often we are faced with the old “brutforce” method of simply stripping the insulation off the equipment to have a look. Unfortunately, this is a time-consuming, fairly expensive work process, especially if the insulation contains asbestos. The most common NDE technique in use for finding CUI without insulation removal is conventional radiography (including real-time RT and the newer digital RT). Some of the other NDE techniques for finding CUI that are in use within our industry include: pulsed eddy current (PEC), guided-wave ultrasonics, and ultrasonic thickness measurements from the inside diameter of the equipment. Some other techniques (neutron back scatter and infra-red thermography) can also help us to find moisture under insulation, which might then help us to find CUI. But sometimes with these tools we find wet insulation, but no CUI; and of course, the converse, we also find CUI where the insulation is currently dry, but was clearly very wet in the past.
So CUI is a fairly insidious form of corrosion, difficult to predict with certainty and difficult to find without 100% insulation removal. And for those reasons, CUI continues to be a bane for the process industry. But it cannot be ignored, as it will eventually produce process leakage and the attendant consequences. Hydrocarbon process facilities on the Gulf Coast of the US are spending multi- millions of USD on CUI inspection and mitigation. I’m aware of CUI projects at just one facility up to $70 million. Most sites have found that catch-up CUI programs need to be organized and funded as a project separate from run and maintain maintenance; otherwise funding tends to “disappear” into other short-term maintenance needs.
Do you know where your higher risk CUI exposure is? And do you have the needed resources applied to keeping your equipment that is susceptible to CUI safe and reliable?
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