Is There A Cure For Corrosion Under Insulation?

Most facility managers, engineers, and maintenance and construction personnel now know that corrosion under insulation (CUI) exists and, left to its own devices, can cause serious problems and even catastrophic consequences.

It is also widely known that the results of CUI are costly. How costly? That is harder to define. Most studies on the topic involve all forms of corrosion and their associated costs without providing the individual cost of corrosion related to insulation.

What is clear, however, is that the cost of corrosion in the United States continues to increase. A study completed in 2001 by a research team of corrosion specialists enlisted by Congress titled, "Corrosion Costs and Preventative Strategies in the United States" reported the direct cost of corrosion to be $276 billion per year, with that number potentially doubling when indirect costs are also considered. Compare this to the first study conducted in 1975, which established the benchmark cost of corrosion at $70 billion. Factoring in inflation, this is actually an improvement if the data are compared to the gross domestic product, with 3.2 percent for 2001 versus 4.2 percent for the 1975 study.

CUI is typically difficult to identify because it lies hidden under insulation material, often until it becomes a serious problem. It is also expensive to inspect for or repair since that usually requires inspection by radiography, ultrasonic or other forms of inspection but in most cases requires the removal of the insulation system. This is especially true if the removal involves material with asbestos. A study done by ExxonMobile Chemical and presented to the European Federation of Corrosion in September 2003 indicated that:

• The highest incidence of leaks in the refining and chemical industries are due to CUI and not to process corrosion;
• Most piping leaks (81 percent) occur in diameters smaller than 4-inch nominal pipe size; and
• Between 40 and 60 percent of piping maintenance costs are related to CUI.

Finally, one of the largest chemical manufacturing companies in the world, E.I. DuPont de Numours and Company, estimates that the direct cost of CUI repairs and replacements well exceeds $10 million per year, which does not include normal preventative maintenance costs and indirect costs like loss of production and revenue. This is especially revealing since DuPont is known internationally as a company with world-class facility engineering, maintenance and workplace safety. Adding to this problem is the accepted belief that industrial facilities in the United States are aging, being operated and maintained by fewer personnel, and funded by reduced budgets.

It can therefore safely be determined that CUI remains a large problem for industry, even if it is not clear exactly how big the problem is today.

For CUI to form there must be two basic ingredients: moisture and warm temperatures. For iron products like carbon steel piping and equipment, oxygen is also needed. To have chloride stress corrosion (SCC) of 300 series stainless steel, there also must be the presence of chloride ions. Obviously, oxygen is fairly easy to find, but, maybe surprisingly, so are chloride ions, which are available in a great number of places from seawater, drinking and process water, and chloride chemical compounds to roadway de-icing salts. The presence of acids, acid gases, and bases like caustics and salts also can create and accelerate corrosion.

Source:http://www.insulation.org/articles/article.cfm?id=IO051101

When is it cost-effective to use thermal spray in petrochemical facilities?

Typically, thermal spray coatings are cost-effective in the petrochemical industry when you consider the cost of inspection, especially under insulation.

Even the best, most expensive paints must be inspected in 3-7 year cycles when used in CUI (Corrosion Under Insulation) conditions. Inspections most often mean scaffolding, removing all cladding and insulation, intensive inspection, including a lot if UT testing of pits, blasting, painting, re-insulating, re-cladding, removing scaffolding, etc. If thermal spray aluminum (TSA) is used instead of paint, these inspection cycles are pushed out to 25 years (ExxonMobil) to 40 years (Shell).

In this case, blasting and recoating is not required, just inspection, as it is known that a properly installed anodic TSA coating system will not corrode or “sacrifice” itself unless it is installed in such a way that the TSA has to provide anodic protection for a large cathode (unfavorable anode to cathode ratio) when an electrolyte (water or wet insulation) connects the TSA to a non-TSA coated area. We don’t do this in the petrochemical field, as we coat an entire vessel, column, or pipe (flange to flange) instead of just a tiny area and expect it to protect the entire structure.

Regarding the cost of thermal spray in a refinery, one must consider the entire erected costs (scaffolding, cladding, insulation, grit blasting and disposal, etc.) of a coating job and not just “the coating.”

Around 6 years ago, ExxonMobil reported that when the entire erected costs are considered, TSA coatings cost them 0.5%-1.5% more than liquid coatings; however, some of the paints used in CUI service have doubled and tripled in price since then. Many times, thermal spray can be applied at lower costs than wet paint when you consider factors like weather conditions, no VOC regulations, ease of or less need for touch-up, robust coatings that can be applied offsite and then installed, etc. As a pipeline applicator who did both wet paint and thermal spray coating, we charged less for thermal spray than a three-coat paint system.

Source:From James Weber of Sulzer Chemtech Tower Field Service on November 17, 2011

Case Study: Washington State Issues Record Fine in Tesoro Refinery Explosion

The Washington Department of Labor & Industries (L&I) determined that the explosion that killed seven workers at the Tesoro petroleum refinery in Anacortes, Washington could have been prevented. L&I fined the company $2.39 million for 39 “willful” violations and five “serious” violations of state workplace safety and health regulations. This is the largest fine in the agency’s history.

A heat exchanger at the refinery ruptured around 12:30 a.m., April 2, 2010, releasing hydrocarbon vapor that then ignited. The incident occurred during maintenance on the Naphtha Hydrotreater (NHT) process unit. During routine operations involving an on-line switching of unit heat exchanger feed trains, a feed-effluent heat exchanger catastrophically failed, due to high temperature hydrogen attack (HTHA), releasing a hot, pressurized flammable hydrocarbon/hydrogen mixture. Seven workers, five men and two women, died as a result. It is the worst industrial disaster in the 37 years that L&I has been enforcing the state’s workplace safety law, the Washington Industrial Safety and Health Act. 

The heat exchangers were nearly 40 years old and were subjected to extreme heat and pressure, wide temperature and pressure swings, extensive chemical exposure and a near doubling of production over the years. These are all stresses that can damage this equipment, including causing cracking.

Source:http://www.corrosionblog.com/2010/10/washington-state-issues-record-fine-in.html

For corrosion to occur, four conditions must be met simultaneously...

1. Operating temperatures in the range of 100°F – 300°F (38°C – 149°C)
2. Oxygen
3. Water must be present.  This water must be liquid water, not water vapor.  Water vapor does not contribute to corrosion.
4. Corrosive chemical(s)

If one of the above conditions is absent, corrosion will not occur; all four are required simultaneously. In a very large number of cases in industrial settings, the operating temperatures of pipes and equipment are above the 300°F (150°C) range.  Therefore, corrosion is not a worry on a day-in and day-out basis.  But the reality is that industrial equipment is periodically shut down for maintenance.  The shutdown process will take the equipment through the critical temperature range window of 100°F – 300°F (38°C – 149°C) initially as the unit is shut down, idled, and then again, as it is restarted and brought back up to its normal operating temperature range.  And since oxygen is approximately 21% of the air that we breathe, exposure to it cannot be avoided.

The bottom line is that we really cannot do too much to control the existence of the key temperature range, or the presence of oxygen.  But we can exercise control over the two remaining conditions:  the presence of water and chemicals.Typically, where water is present, it contains some chemical elements like chlorides, which might be dissolved salts found in rainwater.  So, of the four necessary conditions for corrosion to occur, the most obvious condition we can focus our efforts on preventing is the presence of water in contact with both the steel requiring protection and the insulation material it touches. There are four general areas in which the insulation industry and specifiers direct their efforts in order to control the presence of water:

• Selection of the insulation material
• Protective jacketing design
• Protective coatings
• Insulation system maintenance

Each of these areas has its limitations, and more often than not a combination of one or more of the methods is used. 

Source: http://www.sangwonkorea.co.kr/#!1/c172g

Article by Tony Fernandes: If I Were 22: Dream the Impossible..

What would I do if I were 22? My advice to those just starting out on their careers comes in three parts.

First: Dream the impossible.

I know it seems like an obvious thing to say, and I am sure you've heard it a thousand times before. But too often, people dream too small. Not because they can't dream big but

because they have been conditioned to play it safe.

Growing up, my father wanted me to be a doctor. He was a doctor and he wanted me to be one too. I wasn't keen but he wanted me to try anyway. So to make him happy, I went for the entrance exam. But instead of doing the paper, I took a nap and handed it in empty. I told my father, look I gave it a go but I failed.

Dreams are not enough, though. Everyone has dreams, not everyone works at them. That brings me to the second part of my advice.

Second: Have a plan.

If you know where you want to be, you should have an idea how to get there. You must work towards it. Otherwise, your dreams are just talk. Set yourself a goal, set yourself some targets and figure out how you are going to do it.

It's hard work, and it's not for the faint-hearted. But if you are passionate about it, it does not become work, it'll be a joy to do.

Third: Don't give up.

Dreams worth having are never easy to achieve, and more often than not, you will encounter disappointment.

Never let failure get you down. It really is better to have tried and failed than to have never tried at all. You will either learn learn something valuable from the experience, or be that much closer to your dream. Keep pursuing your passion and success will come chasing after you.

When I started AirAsia, everyone told me I was crazy, that it would never work. And, to be honest, I didn't always know how it would turn out.

But it was a risk worth taking. Now I can say if I get hit by a bus tomorrow, I will have no regrets because I have achieved what I set out to do.

And that is the only life worth living.

Source:https://www.linkedin.com/pulse/article/20140527112605-18376250-if-i-were-22-dream-the-impossible?trk=mp-reader-card

About Refractories

What Are Refractories?

Refractories are heat-resistant materials that constitute the linings for high-temperature furnaces and reactors and other processing units. In addition to being resistant to thermal stress and other physical phenomena induced by heat, refractories must also withstand physical wear and corrosion by chemical agents. Refractories are more heat resistant than metals and are required for heating applications above 1000°F (538°C).

While this definition correctly identifies the fundamental characteristics of refractories--their ability to provide containment of substances at high temperature--refractories comprise a broad class of materials having the above characteristics to varying degrees, for varying periods of time, and under varying conditions of use. There are a wide variety of refractory compositions fabricated in a vast variety of shapes and forms which have been adapted to a broad range of applications. The common denominator is that when used they will be subjected to temperatures above 1000°F (538°C) when in service. Refractory products fall into two categories: brick or fired shapes, and specialties or monolithic refractories. Refractory linings are made from these brick and shapes, or from specialties such as plastics, castables, gunning mixes or ramming mixes, or from a combination of both.

Many refractory products, in final shape, resemble a typical construction brick. However, there are many different shapes and forms. Some refractory parts are small and may possess a complex and delicate geometry; others are massive and may weigh several tons in the form of precast or fusion cast blocks.

What Are Refractories Made Of?

Refractories are produced from natural and synthetic materials, usually nonmetallic, or combinations of compounds and minerals such as alumina, fireclays, bauxite, chromite, dolomite, magnesite, silicon carbide, zirconia, and others.

What Are Refractories Used For?

In general, refractories are used to build structures subjected to high temperatures, ranging from the simple to sophisticated, e.g. fireplace brick linings to reentry heat shields for the space shuttle. In industry, they are used to line boilers and furnaces of all types--reactors, ladles, stills, kilns--and so forth.

Source:http://www.refractoriesinstitute.org/aboutrefractories.htm

Unexpected CUI Identification

The cold section of the unit operates at varying temperatures below freezing, depending on the stage of the process. Impact tested carbon steel piping was utilized for the majority of the piping that had a design temperature greater than -50˚F. The original construction specifications did not require any 

coating for piping designed to continuously operate below 20 ˚F. It was found that this criteria is acceptable, provided that the line is continuously operated below freezing. This is based on visual inspection of lines that were frozen, as they did not exhibit any significant signs of corrosion. The unexpected piping that was found with corrosion problems was not correctly identified based on 

operating temperatures specified. 

The original line list identified the operating temperature for the flowing case and did not consider normal operating temperatures based on stagnate flow. The cases presented below should have been originally identified as having a CUI potential. However based on the listed operating conditions, these piping systems were not identified to have a CUI potential and were not included in the inspection strategy. The first two cases represent intermittent flow conditions while the third case represents a deadleg condition. In the below cases, none of the piping was originally coated due to being identified as normally operating below 20 ˚F. The first case was identified in the background section which resulted in a through wall failure of an ethylene vapor line. The original specifications of theplant identified the line as operating at –12 ˚F. At this temperature, the line was not flagged to be included in the CUI inspection strategy. After investigation, it was found that the operating temperature was correct, when the pressure control valve was open and flowing. The normal operation of the valve was to be in the closed position, creating a stagnate leg with no flow. Under these conditions the typical temperature of the line was only slightly below ambient. 

After removing the insulation at the location of the leak, it was found that the corrosion extended beyond the area of the leak and traveled further down the pipe back to the 14 inch line. The insulation was removed to the 14 inch line, where a severe area of corrosion was found on the branch connection, Figures 2 and 3. 

The 14 inch line was also identified as having an operating temperature of –12 ˚F. The 14 inch line was the supply line to the system relief devices and under normal conditions was completely

stagnate, Figure 4. It is only under a pressure relieving event that the actual operating temperature reaches the specified –12 ˚F. The insulation on the entire length of the 14 inch line was removed for inspection. It was found that the first signs of frost rings, indicating that the temperature was below freezing did not occur until within 7 feet of the 24 inch main header. The leak location was approximately 20 feet from the where the piping was normally operating at or below freezing conditions. Based on the nominal wall thicknesses of the piping, the corrosion rates are estimated to be in the range of 0.004in/yr to 0.011in/yr. The corrosion rates are roughly the same for the 14 inch line and the 1-1/2 inch line.

With the 1-1/2 inch line requiring a smaller wall thickness, it was more susceptible to developing a through wall failure. The second case of CUI deals with a 1-1/2 inch carbon steel makeup line to the ethylene refrigeration system. The line branches off of the suction to the ethylene product pumps and runs to the ethylene refrigeration accumulator. This line was originally identified as operating at -11 ˚F. This line is in operation once per week, for approximately 3 hours, it is stagnate the remainder of the time. The piping orientation is shown in Figure 9.

The original specification for this line was to utilize impact carbon steel to a manual globe valve where a specification break to stainless steel occurs. The intent was to minimize the carbon steel piping while keeping the globe valve within sight of the accumulator; however due to the location of the vessel, this required approximately 140 feet of carbon steel piping before the specification break to stainless. The initial visual inspection of this line found several areas of damaged/missing insulation. After removing most of the insulation, the piping was assessed by profile radiography to determine the remaining wall thickness without having to disturb the scale, Figures 7 and 8. There were several areas that were identified as having less than 1/32 inch remaining wall thickness.

The worst section of piping was located the furthest from the main header and within approximately 30 feet of the specification break. The line was found to be frozen and free of corrosion within 20 feet of the main header. The third case of CUI deals with a ¾ inch carbon steel bleeder off of a 12 inch acetylene converter feed main header. The bleeder piping and valve were located within 1 foot of the main header. The main header was originally identified as operating at 21˚F and normally is at this temperature. The CUI was caught on a visual inspection of the line, were the stem of the bleed valve that protruded through the insulation showed noticeable corrosion and was observed to be sweating. After removal of the insulation, it was found that the main header was frozen and free of corrosion. The ¾ inch piping was frozen next to the main header and showed signs of sweating back to the valve. The piping was assessed by profile radiography, where it was determined that the remaining wall thickness was approximately 1/16 inch localized in areas, Figure 11 . It was determined that the piping was acceptable to be in service up to the next scheduled outage. This line was hand cleaned and coated to arrest the corrosion and is scheduled for replacement with stainless steel. 

Source:http://www.allriskengineering.com/library_files/AIChe_conferences/AIChe_2008/data/papers/P108061.pdf