CoatingsPro Magazine

MAR 2017

CoatingsPro offers an in-depth look at coatings based on case studies, successful business operation, new products, industry news, and the safe and profitable use of coatings and equipment.

Issue link:

Contents of this Issue


Page 20 of 84

20 MARCH 2017 COATINGSPROMAG.COM A: ere are two possible reasons for this. First, are you zeroing your DFT gage on the blasted surface? If not, you will be off by the magnetic base reading, which is generally about ⅓ of the blast profile — or in your case, 25 microns (1.0 mils). On thick film coatings, this is minor and would probably not be noticed. But on a thin coating, it could be significant enough to notice. e second reason is that when you apply paint, part of the paint goes into filling up the blast profile. How much is a function of the surface profile height as well as the peak density. W hen you calculate wet film thickness, you need to take this into account. Again, the amount of paint it takes to fill the profile would be insignificant on a thick coating or on an intermediate or topcoat. But it could be significant on the prime coat, especially if it is applied close to the size of the profile. Remember, when you measure wet film thickness, the wet film gage sits on the peaks of the profile. It does not measure the paint below the peaks. If you did not zero your gage properly or account for the paint in the profile, you can compound the error you are seeing. ese errors are small and, with thicker film coatings, would not be noticeable. But they can be noticeable on thin film coatings. Submerged Pile Corrosion Q: We are facing an issue in our project for an offshore steel pile on a pier bridge. Originally, the steel pile was coated w ith approved epox y paint from the seabed (1 m, 3.3 ft., inside the seabed also) to the entire length. But inside the seabed portion, it was bare surface. During pile driving, some of the pile could not reach the previously designated pile drive length. T his resulted in some bare surface exposed in the water. T here were also damages to the painted surface sustained during the pile drive. Temporar y CP (cathodic protection) has already been installed, and it is running. We are going to install the permanent CP shortly. Do we have to paint the bare surface of the pile or not? Since under water painting is a ver y slow and difficult process, we want to avoid this if CP alone can ser ve this pur pose. We have also seen one test pile with a complete bare surface, driven two years ago. ere was no CP installed on this test pile. After it was withdrawn from the sea, the surface near the seabed showed little corro- sion, while the splash zone and the area exposed to the atmosphere was corroded considerably. W hat would be the reason for reduced corrosion in the submerged location? Is there any relation between the oxygen concentra- tion difference between the submerged and open-to-atmosphere area? A: With CP, you generally have to coat all bare steel surfaces in contact with the conducting medium — seawater, in this case — with a good coating that adheres well and has a good dielectric strength. e CP current flow will be too high if you leave areas of steel bare. As far as the second question, your test result was expected. e most severe corrosive environment is always the "splash zone," due to the high concentration of oxygen in the corro- sive medium (seawater) and physical impact by water and debris. Oxygen concentration in water decreases with depth — so at the seabed, the oxygen concentration would be the lowest. Hence, the corrosion would be at its slowest rate there, relative to near the surface of the water. Test for Contaminants Q: I was wondering if any of you know of a reliable field test that can be done to determine if a surface has oil or grease contamination, prior to sandblasting the surface? e UV (ultraviolet) black light test is not a conclusive test for oil or grease, as many oils and greases do not fluoresce or show up under UV light. A: An old trick is to just dump some potable water on the surface and see if it beads up. I don't know of an ASTM or International Organization for Standardization (ISO) test method for this, but it does work. A: It was always my understand- ing that sy nthetic oils would not generally f luoresce under U V or black light. Most hydrocarbons w ill f luoresce under U V and black light. It has been my experience that U V light at 365 nm gives the best results. Many years ago, when working in a refiner y, we were looking for a hydro- carbon leak using a black light w ith no success. (Black light is 400 to 450 nm, and is sometimes referred to as pur ple light.) W hen we sw itched to U V light, around 365 nm, the leak was found. T he U V comes in two bands — 300‒350 nm is considered U V short band, and 350‒400 nm is considered U V long band. e 365 nm is also the same frequency as lights used for weld inspection, and they are readily avail- able. e better lights range from about $600 up to a couple thousand dollars. Even with a good UV light, it works best in the dark. I generally recommend doing both tests, as neither is foolproof. A: T he Society for Protective Coatings (SSPC) Technolog y Update (TU) 11 standard for the inspection of f luorescent coating systems is one more guide that might help you. It covers in detail the use and safety issues of U V lights for inspection work of coatings contain- ing a f luorescent pigment. However, some people have used it as a recog- nized guide for the use of U V lights for a cleanliness inspection. A nd the latest version (2015) of SSPC Surface Preparation (SP) 1 includes the use of U V lights to check for oil in its notes section. Notes From the Blog

Articles in this issue

Links on this page

Archives of this issue

view archives of CoatingsPro Magazine - MAR 2017