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In this episode of the Hydrocarbon Engineering Podcast, John Zimmerman, Key Account Manager for Sherwin‑Williams Protective & Marine, covers an array of common corrosion challenges energy producers face and how to specify the ideal coatings to mitigate those threats.
From tank interiors to insulated piping, John covers the hidden – and not so hidden – costs of corrosion that hydrocarbon processing facilities face related to downtime and safety risks. He reviews what producers can do to reduce those risks, touching on the importance of:
- Using protective linings that ensure asset integrity and product purity, particularly for tanks housing more aggressive products such as biofuels and corrosive crude oil.
- Assessing high-temperature and high-corrosion environments to determine why existing coatings are failing and what solutions will work better.
- Collaborating with inspectors, contractors, and coatings manufacturers to ensure processes and commodities are understood so they can specify the optimal coatings for applications.
- Asking for help and involving technical service representatives from reputable suppliers when assessing and preparing specifications.
- Planning ahead for plant turnarounds and general maintenance activities so the most critical coatings needs can be addressed first.
Tune in to learn how to better battle corrosion throughout your facility with the right protective coatings solutions.
This episode of the Hydrocarbon Engineering Podcast is sponsored by Sherwin-Williams Protective & Marine.
Sherwin-Williams Protective & Marine delivers world-class industry subject matter expertise, unparalleled technical and specification service, and unmatched regional commercial team support to customers around the globe, including in the energy market. The company’s broad portfolio of high-performance coatings and systems – including protective liquid and powder coatings, as well as fire protection coatings – excel at combating corrosion and help customers achieve smarter, time-tested asset protection. For more information, visit protective.sherwin.com.
Creators and Guests
What is Hydrocarbon Engineering Podcast?
The Hydrocarbon Engineering podcast: a podcast series for professionals in the downstream refining, petrochemical and gas processing industries.
Hello and thanks for tuning in to the Hydrocarbon Engineering Podcast. Today we'll be covering the issue of common corrosion challenges encountered in the industry and we'll focus on how processors can best tackle those challenges to minimize the potential for corrosion to shorten the lives of operating assets. To enlighten us on this issue we have John Zimmerman, key account manager for Sherwin Williams Protective and Marine. I hope you enjoy the episode.
Advert:This episode of the Hydrocarbon Engineering Podcast is sponsored by Sherwin Williams Protective and Marine. Sherwin Williams Protective and Marine delivers world class industry subject matter expertise, unparalleled technical and specification service, and unmatched regional commercial team support to customers around the globe, including in the energy market. The company's broad portfolio of high performance coatings and systems, including protected liquid and powder coatings as well as fire protection coatings, excel at combating corrosion and help customers achieve smarter, time tested asset protection. For more information, visit protective.sherwin.com.
Callum O'Reilly:Hi, John. Many thanks for joining us. We always like to begin with some introductions for new guests on the podcast. So please can you tell us a little bit about Sherwin Williams Protective and Marine and your role at the company?
John Zimmerman:Thank you. So Sherwin Williams Protective and Marine makes protective coatings that are really designed to combat corrosion in a variety of industries. So in industries like the bridge and highway segment, and infrastructure building with water wastewater, one of the segments that I work in specifically is the energy segment. So this is going to be petroleum refining, renewable fuel refining, the transportation of those products through their midstream terminals and pipelines. And in that segment I'm what's called the key account manager.
John Zimmerman:Meaning I work with several of the major companies who do specifically the refining of petroleum and I work to help them technically to understand how they can best specify and have coatings as part of their corrosion control program. I've been with Sherwin Williams about twenty one years now with the majority of it being on the protective and marine side and with the last probably five or so years being focused on that energy segment.
Callum O'Reilly:Thank you very much for that John. So let's begin with a bit of a general question so obviously corrosion is a big threat in the industry It causes assets to deteriorate over time and can cost energy producers large sums of money to mitigate and correct. So what are some of the key reasons that make corrosion such a challenging and costly nuisance?
John Zimmerman:Sure, so corrosion is exceptionally persistent and it finds its way into nearly any steel asset, especially in the refining and petrochemical industry because environmental pollution, heat, moisture, and chemical exposure are everyday occurrences in that industry. Using coatings and other corrosion control methods can create a longer timeline before corrosion takes hold, which is precisely what you're after for your plant's assets, as preventing corrosion is always preferable to managing it. And one of the main tools we use to prevent and manage corrosion is a specification. The goal of a well written specification is to ensure that the coatings and linings are fit for all of the exposures that the asset and the coating will experience. The heat, chemistry, moisture, abrasion, and other factors that the asset will be exposed to can often be mitigated using protection coatings, but only when the right coatings are used and the service conditions are thoroughly understood.
John Zimmerman:When both the standard operating conditions and the potential upset conditions, or the conditions that are outside of those normal operating conditions, are thoroughly understood, the coatings can be appropriately selected and it will be reflected in lengthening the service life of the asset and reducing the risk of asset failure or unplanned maintenance. Being thorough in the specification process is especially important. The process conditions in commodities often vary or change throughout a coatings lifespan and any undisclosed or unexpected variables can drive early coating failure. This can lead to one of the biggest potential costs related to corrosion, which is downtime. No plant ever wants to have to shut down a process or full operations unexpectedly to address corrosion.
John Zimmerman:And it stings even more if that asset could have been addressed proactively. Unplanned stoppages are extremely costly. They might set a plant back by a million dollars a day or more when shutting down a refinery. As an example, recently there was a tank which developed some corrosion and a leak eventually due to the additive in a commodity that caused a significant pH drop. This drop in pH caused a failure of the lining and then corrosion through the tank wall, which resulted in a leak.
John Zimmerman:This leak became a fire. This fire affected two other tanks in the containment area and caused an evacuation that affected both the plant and the surrounding community. Even though the leak and the fire were contained, all three tanks had to be rebuilt and the cost of the refinery was millions of dollars. This is an example of a failure in one asset due to corrosion becoming a major hassle for a plant to overcome. One that brought significant operational costs and downtime to that assets and several others that were affected.
John Zimmerman:Now had the operations team identified the pH change and the coating deterioration sooner, or had there been a material specification in place that accounted for that change in pH, then the unplanned downtime may have been avoidable. Addressing this pH change through using coatings designed for that service could have been addressed during the original installation or a planned maintenance shutdown instead, which is a completely different scenario than when you must address assets that are shutdown due to a failure. A regular shutdown or turnaround is costly as well, but it's planned and expected stoppages that are meant to coincide with other maintenance activities are much less costly. So that cost of the shutdown ends up being spread over several assets across the facility and not just one asset in an emergency situation. Secondly, the contractors and materials can be scheduled to minimize the impact and the cost to them and ensure that a quick shutdown can happen and they can get those assets operating as quickly as possible.
Callum O'Reilly:Thanks John. So you mentioned specifications and the importance of getting those right so that the coatings that are used will offer the best possible performance. So how do you go about getting those specifications right?
John Zimmerman:Well first you always want to do your best to get them right initially as you mentioned. So you can realize the long intervals that you want before the first coating maintenance needs need to happen and not run into any emergency repairs. When you build a new plant or are improving a facility, it's extremely helpful to involve a coatings expert early in the design process before any decisions have been made. That's something that we encourage at Sherwin Williams. It's really helpful for us to be involved early on in the process so that we can have the opportunity to meet all of the stakeholders and get a complete understanding of the services and exposures.
John Zimmerman:Engineering, operations, reliability, and several other groups will all have a role in determining exactly what the operating conditions and exposures will be, and that information is vital to get the appropriate coating specified. For example, if you have a pipe rack operating in an enclosed condition building, a coatings representative may recommend a general high performance coating system. But the same equipment operating outdoors or in an especially corrosive C5 type environment like we see in refineries, that recommendation should be much more robust to account for the more corrosive conditions. The nuance of understanding what will work in one service and not another is essential for optimizing a plant's expenditures. Consider if the specification for the indoor service scenario was applied to the outdoor C5 operating environment.
John Zimmerman:The more durable system from the operating environment of C5 would be over engineered for the indoor scenario, which means the plant would be spending more money than necessary to combat corrosion there. On the opposite side, say the less robust system is specified for the more difficult environment. Well, won't last nearly as long as required and that system's poor performance may raise the risk of causing one of those unplanned shutdowns that we're trying to avoid. So the point here is that plants should avoid publishing blanket specs for every asset that meets the strictest possible needs. Instead, they should work with their coating supplier to optimize the specification to use the most appropriate products for given applications and thereby contain costs.
Callum O'Reilly:Now you focused here on getting specifications right from the outset, but as we know things don't always work out the way you'd expect them to. So let's suppose that a coating doesn't perform as well in service as you had initially hoped based on pre service assessments. In such cases,
John Zimmerman:are plants typically married to the original specification or is there room to learn and improve as you go along? Well there's definitely room for improvement on any specification especially as you go along and gather more info. You can make adjustments after an asset has been in service, and you should, particularly if that asset's service life was especially short before it needed maintenance, or if the exposure changed. I have a good example from the field that's related to fracking operation. Our customer was running into an issue of needing to replace 90 degree steel piping elbows that were located at fracking wellheads much sooner than they expected.
John Zimmerman:The elbows were coated proactively on the interior to minimize the steel erosion that was anticipated as the fracking fluid made its way through that 90 degree turn. At the well flow's contents are very abrasive and we knew that they would quickly wear through the coating and the piping if not protected. However, this grit content in the extracted fluid was causing the installed coatings to quickly degrade due to what was essentially a sandblasting type action. Well, the steel was of course eroding after those coatings were gone which introduced a potential safety risk and forced the customer to replace the elbows within a few months of beginning service. So, we met with them and once we understood the challenges, we got together with the customer's team to come up with a solution.
John Zimmerman:That collaboration led to Sherwin Williams going through the lengthy process of formulating and testing a new erosion resistant coating. That coating has greatly extended the customer's pipe elbow service life and reduced the frequency of replacements. Inviting our technical service resources in to collaborate with our team and assess the challenging services can open the door to better solutions. Whether that's something that we end up developing like this erosion resistant coating I mentioned, or something that we already have in our portfolio. In many cases our technical service resources will want to ask every question imaginable about the current operating conditions, potential upset conditions, cleaning procedures, failure mechanisms, and several other things.
John Zimmerman:Knowing what changes are foreseeable in the operating temperatures and pressures, chemicals and commodities, and pre and post installation environmental conditions can help us work through what the right coatings plan is to mitigate those challenges we identify. This is again where a thorough understanding of the asset service condition and how that asset in question performs can really help us identify the optimal solution that will meet the owners need for a long service life and then they can update their specifications so that they can get the repair procedures right moving forward.
Callum O'Reilly:So you've shared a few examples already but I'd like to dig into a couple more examples related to the idea of getting your specifications right either from the outset or after observing assets in service. So let's talk about tank linings and the more aggressive products the industry is encountering these days such as biofuels and corrosive crude oil. So what can energy producers do to get their lining specifications right when these especially corrosive commodities may be in play?
John Zimmerman:That's a great question as it's something we're encountering more and more frequently as the fuel industry shifts to using more sustainable fuels which have a different chemistry than standard crude oil. The standard for this is lipid based biofeedstocks. These are more aggressive and corrosive than their traditional fossil fuel counterparts due to their fatty acid content. Tanklines that were designed to mitigate corrosion due to the presence of sulfurous and sulfuric acids that are in fossil fuel feedstocks like crude oil are going to be less effective against the free fatty acids found in biofeedstocks like beef tallow or used cooking oil. So if these lipid based biofeedstocks are stored in a tank whose lining is designed for crude oil storage, then the lining will deteriorate much faster than expected which can lead to increased potential for pitting corrosion and reduce the tank's wall thickness potentially to the point that the owner needs to install patch plates or do major repairs.
John Zimmerman:That's the case where the tank should be retrofitted to include a more durable lining system designed to store the feedstocks and match the temperatures that it's going to be exposed to. In the case of Sherwin Williams, we'd likely point the tank owner to our MagnaLux 2,100 FF lighting. It's a vinyl ester Novolac and it has glass reinforcement. This is exceptionally acid and temperature resistant and it's well suited for the heat and low pH that's seen in this biofeedstock storage. We've done testing on it, and MagneLux 2,100 FF successfully mitigated the corrosive forces present in the biofeedstock storage tanks under both continuous and cyclic exposure, showing only surface discoloration in most testing scenarios and without degradation of the lining.
John Zimmerman:In addition, MagneLux 2,100 has achieved EI-fifteen 41 certification for use with sustainable aviation fuels, meaning processors can have the confidence that this lining will mitigate corrosion and prevent product contamination in sustainable aviation fuel storage. Another common practice that we're seeing is refiners adding corrosion inhibitors and biocides to their finished fuels to mitigate, microbely induced corrosion potential. But even these, solutions require careful thought, as certain biocides and corrosion inhibitors can concentrate and accelerate corrosion if they aren't monitored and managed appropriately. Understanding these factors is key to getting lining specification right and maximizing the service life of that storage tank. The best way to ensure that that happens is to engage a coating specialist and perform a tank line survey before every time you select a light.
Callum O'Reilly:Great, thank you for that John. Now we have time to cover one more example here and I wanted to focus in on high temperature applications for things like stacks, boilers and treaters. So how do you go about getting coating specifications right for these particularly difficult operating assets?
John Zimmerman:Well like other applications that I've covered, it's important to gather the information on the asset's operating environment including temperatures, humidity, and chemical exposures at the beginning. You need to understand how the heat will be managed with that asset. With items like stacks, we're talking about assets that are operating at temperatures often exceeding four fifty F or two thirty two Celsius, but in applications that are often kept away from plant personnel. In the case of a heater treater, the high temperature process it undergoes will likely necessitate the use of some sort of heat mitigation solution to protect plant personnel from getting burned if their skin were to accidentally make contact with the asset because they could reach this heater treater where the stack is kept far away. Traditionally, an insulation system would be used to both protect personnel and retain that process heat so the asset can stay at an elevated temperature without needing extra energy and help to protect people.
John Zimmerman:Regardless, that heat mitigation solution has traditionally been an insulation system featuring some sort of a mineral wool wrap encased in metal cladding. These barriers prevent the outside cladding surface from reaching a temperature that gets high enough for skin contact burns and they help to retain the process heat for that operating asset. However, the downside of mineral wool style insulation is that it creates conditions for corrosion under insulation, or CUI as we know it in the industry. CUI occurs at the substrate and insulation interface where moisture makes its way and breaks through the cladding and becomes trapped inside that mineral wool insulation. CUI has an accelerated corrosion rate due to the combination of heat and trapped moisture creating an environment that's exceptionally well suited to the formation and proliferation of corrosion cells.
John Zimmerman:In addition, the cladding keeps the substrate and corrosion hidden causing concerns with inspection and catching the corrosion before it becomes a major problem. Now we have a coating that can actually eliminate the potential for CUI in some temperature ranges, but I'll leave that discussion for another day. In cases in which the insulation systems will be used, asset owners need to plan for a robust protection of the asset's seal substrate to prevent that corrosion under insulation. One solution for very hot assets in the 450F to 1200F range like that stack we discussed is that we would point owners to our HeatFlex high tramp 1,200 plus coating. This has been proven not only to protect insulated assets from CUI, but also withstand a wide range of stressful conditions both before and after insulation such as sudden temperature changes, thermal shock, and environmental and mechanical damage.
John Zimmerman:DeepFlex 1,200, High Temp 1,200 is a silicone based multi polymeric matrix coating rather than the more rigid epoxy coatings that are often used for under insulation services below four fifty F. This more flexible formulation allows the coating to expand and contract along with the substrate of the asset that it's protecting during extreme temperature fluctuation. Therefore, unlike epoxies, the coating can perform well against the stresses of thermal shock. The challenge with flexible coatings is they're often soft and susceptible to mechanical damage. To overcome this, HeatFlex 1,200 plus was formulated with the addition of micaceous iron oxide or MIO.
John Zimmerman:This addition allows the coating to keep the required flexibility while significantly increasing its resistance to impact and mechanical damage that's common during transportation and installation. So when it comes to protecting stacks and other assets above 450F, HE Flex High Temp 1,200 plus is an excellent solution that can protect an owner's equipment, saving them money and preventing costly corrosion.
Callum O'Reilly:Great, thanks so much John. You've covered a lot of ground today about why protective coatings are so important for hydrocarbon operations and why it's so critical to get your specifications right to ensure the longest life possible for your assets. I really appreciate the discussion I'm sure our listeners do as well. And speaking of those listeners how should they go about learning more about protecting their assets from corrosion for the long haul?
John Zimmerman:Thank you so much Callum, I appreciate the time today. It's been a very fun and interesting conversation. Anyone listening that would like more information on Sherwin Williams products and services can visit our website at protective.sherwinwilliams.com
Callum O'Reilly:Great thanks again John, really appreciate your time today. My thanks again to John Zimmerman at Sherwin Williams Protective and Marine for sharing his expertise and real world insight into tackling corrosion across the sector. And thanks to you for listening. If you enjoyed this episode, sure to subscribe to the Hydrocarbon Engineering Podcast and stay tuned for more conversations with the people shaping the downstream sector.
Advert:This episode of the Hydrocarbon Engineering Podcast is sponsored by Sherwin Williams Protective and Marine. Sherwin Williams Protective and Marine delivers world class industry which very very performance coatings and systems, including protected liquid and powder coatings as well as fire protection coatings, excel at combating corrosion and help customers achieve smarter, time tested asset protection. For more information, visit protective.sherwin.com.