We spoke to fusion-bonded epoxy (FBE) expert, Alan Kehr, about specifying this material. Kehr has 40 years’ experience in the pipeline coatings industry, including R&D and technical service. He is currently the managing consultant for Alan Kehr Anti-Corrosion, LLC, and author of the book “Fusion-Bonded Epoxy (FBE): A Foundation for Pipeline Corrosion Protection,” published by NACE International.
When writing specifications for FBE coatings, what standards are most relied upon for high-temperature pipeline service?
The first internationally accepted standard for FBE pipeline coatings was CSA Z245.20. A few years later, NACE provided a standard that is now NACE SP0394-2013. In 2007, ISO released the standard ISO 21809-2. These three have acceptance in different parts of the world, all providing similar guidance. The CSA standard was the first one to come out in the early 90s, so it has the greatest acceptance. Once people accept a standard, it takes effort to change that decision. Most applicators are doing some work that references the CSA standard, but also one or both of the others.
How do the FBE standards differ from other coating standards?
There are tests specific to pipe coatings. One of the major ones is the cathodic disbondment test. And pipe coatings have to have a certain amount of flexibility, therefore there are bend tests very specific to the needs of the pipe coating industry.
All pipeline coatings, FBE or otherwise, still have to meet the flexibility test, for example. And if a coating is going to be able to compete, the manufacturer will have a disbondment test of some kind that gives results similar to what the FBE standard requires.
On the other hand, fittings, bends and girth welds will not be bent in the field, so they don’t need a coating with the same level of flexibility.
Do site conditions influence FBE specifications, for example, under the earth versus at the bottom of the ocean?
In general, the coating specification will be the same for underwater and underground pipelines. Having said that, the conditions and installation are somewhat different. (Related reading: Condition Survey – The Backbone of a Good Coating Specification.) For example, in deep water, the temperature is quite cold—near freezing—whereas on land, the ground and groundwater temperatures may be significantly higher.
Another factor that needs to be taken into account in the corrosion-protection design is that sea water is a good conductor for cathodic protection current. On land, the soil resistivity can vary greatly by location or by season. Finally, pipeline installation in the ocean—for example, reel barge lay—may require greater flexibility than on-land installation.
Measuring salt level using the Bresle patch method.
In the cleaning and surface preparation aspect of a specification, are there any special considerations for FBE in terms of contaminants such as salts?
All coatings benefit from good surface preparation. If a client wants the benefits of good FBE performance, they will require good cleaning. You should get oils and grease off the steel before blasting it. They can be wiped off using procedures like SSPC-SP 1, solvent cleaning.
In the case of salt contamination, the Canadian standard does state “external surfaces of the pipe shall be free of oil and grease and any injurious contaminants prior to the application of the coating”. It does not have specifics for salt-contamination limits.
However, individual companies may have a requirement that says, “Before you blast, you need to check for salts and if the salt level is about 4 micrograms per square centimeter, you must wash it off before you blast it.” That’s not a universal standard, rather an example of a company-specific requirement. The standards specify the amount of acceptable salts that can be present after blasting. For most, that requirement is less than 2 micrograms of salt per square centimeter after blasting. (For more ideas on this topic, see Understanding the Industry Shift To Wet Abrasive Blasting.)
Some companies specify the use of phosphoric acid wash after blasting to remove any residual salts from the surface. The ISO and NACE standards require a surface treatment if more than two micrograms per square centimeter are found after blasting. The 2010 version of the CSA standard allows surface treatment, but does not require it.
Are there specific requirements after blasting?
The three standards mentioned above have similar requirements. First, the appearance must be “near white”, e.g. ISO 8501-1:2007, grade Sa 2½. There is a requirement for the amount of residual dust, as measured by a tape test described in ISO 8502-3. To check that, put a clear tape on the pipe and rub it into the profile, remove it and place it on white paper. That makes it easy to see dust picked up by the tape. The standard has comparative examples and a maximum allowable level.
All of the standards have a surface profile requirement of approximately two to four mils (50 to 100 µm, CSA allows 40 to 110 µm). Typically they allow a choice of procedures to make that determination: either the ISO 8503-4 (stylus method), or ISO 8503-5 (replica tape method).
Can you tell us a bit about specifying cleaning materials, methods and equipment?
The standards don’t specify the blast media or hardness of the media, but do have requirements for the cleaned surface. The blast materials are covered by a number of tests specified in the standards. They do a conductivity test on the blast media, for example. In this test, the media is placed in water, which is later poured off for a conductivity test. The test provides information on the amount of dissolved salt on the media.
Most applicators today use two blast machines. The first machine may use shot (rounded blast media), a mixture of shot and grit, or just grit. This step is to clean the surface. The second machine uses a harder grit, like GL-18 or GL-25. Media with that designation has a hardness of Rockwell C 54 or higher. The actual hardness may vary slightly by grit manufacturer. The second machine establishes the anchor pattern.
Steel blasted with GL Grit to a Rockwell hardness range of C 55-60.
What considerations are important when selecting FBE coating materials?
NACE 394 includes tables of coating requirements, true also of the other two standards. Coatings must meet the requirements of that table as a baseline. Most pipeline owners also require a track record before they will use a specific coating material. This is a real "catch-22" for companies introducing new coating formulas.
How do coatings companies overcome this?
In the past, it could take up to 10 years to gain universal acceptance of a new coating. Typically most oil & gas companies had a corrosion department with one or two experts who had to be convinced. But today that’s not so true. These days, most companies have a spec and new coatings are viewed as generic materials, so it may not be quite so difficult.
Typically, a pipeline company is going to have three or so suppliers on its list and specific materials on their standard. That goes out to the applicator, and the applicator makes a choice based on a number of factors, such as delivery, quality history and past experience. Not surprisingly, a key factor in the decision-making process is cost.
What coating materials are allowed by international standards?
The standards have minimum requirements that each coating material must meet. Generally, that means that the commercially available materials at the time of the standard will meet the requirements. The standards do not list acceptable materials.
End users use the standards as implied—the minimum requirements. They often add more stringent requirements to their own specification, and often list specific coating materials by name or number.
So what about quality control?
As with industry in general, quality control for FBE pipe coatings has evolved. During one of my first visits to a coating plant—that was quite some time ago—one of the plant people said, “You will never see a better coating job than this one.” There was no way to argue. As near as I could see, the requirements were color and thickness with a holiday test at the end.
If there are no measurements, there are no failures. With time, we discovered that using a low level of scrutiny sometimes causes unpleasant results. With that experience, we developed tests to help prevent later problems with the coating during installation or on installed pipe. We also learned that testing only after the coating was applied was insufficient, so we now set up the application system in ways that prevent failure at the end of the application process. Measurements of those application steps are made along the way.
Details of the process are well-defined and documented. This may be an extreme, but on a recent project, the inspection and test plan (ITP) went on for 56 pages and spelled out documentation, specified tests and set strict requirements.
Do the application requirements for FBE differ much from other types of coatings used for high-temp pipeline service?
Each coating system has specific requirements to achieve optimum performance. That’s true whether the coating is a two-part liquid, a tape, a wax or an FBE. The application steps and controls now in place for FBE coatings are based on knowledge gained in the 55 years since the first commercial FBE pipeline coating was applied in 1960. While the principles are the same for all coatings, the specifics are unique for each.
Long-term coating performance on high-temperature pipelines requires even greater attention to detail than for normal operating temperatures. While new materials have been developed for high-temperature usage, the application steps are essentially the same. (For more on this topic, read Top 5 Considerations when Coating High-Heat Surfaces.)
The international standards lay out the groundwork, but owners’ specifications, operational procedures and quality/process controls are what ensure a successful outcome.
Any special requirements for specifying FBE dry film thickness?
With time, we’ve learned that increasing coating thickness results in fewer problems. The three standards we’ve discussed generally set an average of around 14 mils (350 microns) and a minimum, either 10 mils (250 microns) or 12 mils (300 microns). The language varies, but they generally instruct the owner to specify a minimum, nominal and maximum coating thickness. Most of the commercially available coatings can meet the specification flexibility requirements up to 40 mils (one mm) of thickness.
How do you handle coating damage that might occur during transport?
The standards we’re discussing cover the application process. Each of them has a section on repair that provides guidance and direction on methods for repairing holidays or coating damage. Generally, they allow two-part liquid coatings for repair or, for very small areas, hot-melt patch sticks. Some end users preclude the use of patch sticks.
While outside the scope of these standards, once the pipe leaves the applicator’s yard and is carried to the installation site, there are one or more places along the way where the coated pipe is holiday inspected and any damage repaired. Practices in the field follow the repair guidelines used in these standards.