Monday, November 17, 2014

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.


Monday, November 10, 2014

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

Monday, November 3, 2014

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.