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Controlling Corrosion on Offshore Turbines with Coatings, Part 2

THURSDAY, APRIL 19, 2018

By Lee Wilson

In the first part of this two-part blog, we looked at corrosion control on offshore wind structures, and some of the environmental factors that make it a challenge. In our concluding section, we’ll discuss coating systems currently in use on these structures and the steps I think will help the industry to more effectively and efficiently control corrosion.

There are a number of different turbine types and structural configurations and designs, and these all have an impact on the protective coating system applied. The offshore wind turbines typically consist of the following designs:

  • Jacket: Sub Structure
  • Monopile: Sub Structure
  • Gravity Based: Substructure

On any type of structure, an offshore wind turbine has several zones, all requiring different protective coating systems and different levels of corrosion protection. The upper part of the tower is in atmospheric exposure; the "splash zone" near the water is subjected to off-and-on wetting due to waves and tides; the submerged section of the structure is completely underwater, and part of the structure is normally buried in the sea floor. (Except in the case of structures like the more recently developed "floating wind farms," which don't have a buried zone.)

Wind farm
© iStock.com / Ian Dyball

On any type of structure, an offshore wind turbine has several zones, all requiring different protective coating systems and different levels of corrosion protection.

Regarding the coating systems used for corrosion protection, Karsten Mühlberg of Hempel wrote in JPCL:

The majority of steel towers for wind turbines located offshore are metallized and painted on their outer surfaces. Inside the towers, only pure paint systems are typically used, except for the lower part where some specifications call for metallization plus paint.

• Metallization (e.g. Zn/Al, 85/15) 60-100 μm

• Epoxy paint 2 coats 100-120 μm (including flash coat)

• Polyurethane paint 50-80 μm

However, due to the demands for less time spent on painting, cost reduction, and good experience over years with paint systems, wind turbine structures may be metallized less often. More and more, high quality paint systems without metallizing (according to DIN EN ISO 12944, C5- Marine), at 320 μm dry film thickness (dft) for external protection, are going to be used. An example of such a paint system is an epoxy zinc dust primer applied at 60 μm dft; an epoxy mid- coat at 200 μm; and a polyurethane topcoat at 60 μm. Inside of steel towers, paint systems at 240 μm dft (C4) are going to be used. For example: epoxy zinc dust primer at 60 μm; epoxy paint at 180 μm; and another coating system used: epoxy zinc dust primer at 60 μm; epoxy midcoat at 120 μm; and a polyurethane topcoat at 60 μm.

Mühlberg goes on to add:

External (immersion and splash zone) use: specialized epoxy coat- ing, 2 to 3 coats, each at 200–250 μm*; polyurethane topcoat at 50–70 μm; specialized epoxy coating, 2 coats at 500 μm*; and polyurethane topcoat 50–70 μm.

• For permanently immersed areas: Epoxy coating, 2 coats at 200– 250 μm*

* The epoxy and specialized epoxy coatings above, depending on the design of the relevant structure, must be compatible with Impressed Current Cathodic Protection.

• For foundation structures insides (not air tight closed): epoxy coating, 2 coats, each at 200–250 μm are normally used.

Mühlberg, who wrote on the use of protective coating systems way back in 2010, was simply basing his requirements upon historical data and the Norsok M501-1 specification requirements for zonal areas—again adopted from the oil and gas industry.

I must add there has been very little change with regard to materials used since then, with a vast reduction in metallization. The DNV recommended code of practice DNV-RPO-0416 states that requirements for corrosion-protective coatings shall be specified in a dedicated document or in a section of some other relevant design document. At least for primary structural parts, generic types of coating systems and requirements to the qualification of manufacturer-specific materials (as defined in the data sheet by the coating supplier of the intended protection system) to be used for such systems shall be specified in the project design basis. Pre-qualification of these coating systems in accordance with a recognized standard (i.e., NORSOK M-501 or ISO 12944, which now includes what previously was known as ISO 20340) with the designated use for designated environment is mandatory.

Organic Coatings vs. Metallizing

There has been a trend to lean toward organic coating materials with a reduction in the use of metal spraying and galvanic protection through TSA and TSZ coatings. It has been clearly demonstrated that thermally sprayed aluminium and zinc coatings, which have been used for more than 40 years to protect offshore oil and gas platforms from seawater corrosion, can also reliably and cost-effectively extend the life of offshore wind turbine foundations to 20-40 years. The biggest advantage is offered in areas of highest risk. This includes areas subject to alternate wetting by the sea, i.e., the splash and tidal zone, as well as subsea. This has been overlooked my many owners and operators who have deemed this process to be time-consuming and ultimately expensive; however, this initial cost including production time is far less that the cost of offshore maintenance.

As stated by The Welding Institute:

With the cost of wind energy still double that of fossil fuels, a reduction in the through-life cost of wind farms is a high priority. Offshore wind turbine foundations represent 30% of the cost of a wind farm. They need effective protection from corrosion. This is usually provided by a combination of thick (>0.5 mm) organic paint/epoxy coatings, and cathodic protection. The coating helps reduce the load on the cathodic protection system. In the splash and tidal zone, however, where the corrosion rate is at its highest, cathodic protection is ineffective and the structure is totally reliant on the integrity of its coating.

With this said, owners and operators need to be looking at high-end, robust and durable products applied with full supervision and meticulous inspection and quality control in order to ensure long-term corrosion protection and reduce maintenance fees. In recent years unexpected corrosion-related issues have emerged, especially in relation to the monopile structures. It has to be remembered that offshore wind farms are typically designed with an anticipated service life of 25 years.

Earlier on, it was assumed that the internal side of foundations below the lower working platform was airtight. If airtight, corrosion was assumed to cease when the oxygen present inside the foundation was consumed. This assumption has been shown to not be fully valid, as both sea water and oxygen have access to the inside of the monopile under certain conditions—not the least on sites where large tidal variations exist (up to approximately 10 meters). This may result in active corrosion, which can compromise the durability of the wind farm and reduce the service life if not prevented.

Offshore wind tower
© iStock.com / teaa1946

The industry is lacking the experience in wind turbine fabrication and good inspectors are being overlooked for offshore wind farm maintenance and onshore fabrication due to a lack a lack of wind turbine experience.

Externally the corrosion in general is well understood and rather similar to the challenges observed across multiple offshore industries. Internally, in the closed compartments, the guidelines and standards, however, are inadequate—but data from inspections and surveys are becoming available. Issues such as fatigue life, internal (and external) cathodic protection design and internal cathodic protection and corrosion need to be considered. The same cannot be said for internal corrosion, as Kathy Riggs Larsen recently noted in Materials Performance:  

Industry experience has shown, however, that it is difficult in practice to completely seal compartments and render them airtight. If the closed-compartment structure is not properly sealed, direct ingress of air is possible. Seawater and oxygen ingress have been detected in foundations that are two to 10 years old, which increased the rate of corrosion and localized corrosion attacks. Furthermore, in some cases, the increasing water level has led to the internal aluminum ladder acting as a sacrificial anode.

These unexpected contradictions to design expectations were discovered during inspections and surveys related to grout failures that caused the settling of the transition piece on the monopile in a large number of northern European wind farms. In the case of oxygen ingress, the corrosion rate in the atmospheric zone initially may be high, but it will decrease in time. Below the water line, corrosion is caused by aeration differences between the upper layer of water and the active steel surface beneath. If the water level is completely stagnant, corrosion will be highly localized with limited coverage, so widespread corrosion is not expected at greater depths in the foundation or on the portion of the structure buried in sediment. 

There is also a risk of microbiologically influenced corrosion (MIC) in a closed-compartment foundation, with localized corrosion attacks on the submerged surface and in the portions of the monopile buried in the upper region of the sediment. Alternating aerobic and anaerobic conditions may also favor bacteria growth, and the risk of MIC depends on the bacteria species and the environmental conditions present. Sulfate-reducing bacteria (SRB) are expected to be present, and if growth conditions are favorable, then sulfide production can occur.

In my opinion, the offshore wind industry still has many challenges to face with regard to corrosion mitigation, control and protection. There must be more awareness and focus on long-term protection; a better understanding of corrosion mechanisms and deterioration of wind turbines; and better standards, codes of practices and specifications coupled with high-end engineering and quality control for assets.

I have recently attended several coating failure analysis investigations of a number of high-profile wind farms. Upon inspection it was determined that the vast majority of the failures were due to a lack of adhesion and inadequate curing of the initial protective coating system. This adds weight to my theory of mass-produced and rushed fabrication of turbines. The repair costs of these farms are to be substantial—and to think that these problems and issues could have easily been prevented. Subsequently the field owners now have to implement an unplanned and unscheduled maintenance/retrofit program.

I have seen an increase in the demand for QA/QC Inspectors for the offshore sector, which is promising from a quality perspective—however, I am well aware that the industry is lacking the experience in wind turbine fabrication and good inspectors are being overlooked for offshore wind farm maintenance and onshore fabrication due to a lack of wind turbine experience. This is a major mistake, as the specifications and standards all originated from the oil and gas sector. Oil and gas inspectors have vast experience with these systems specification and standard requirements. These are fairly straightforward and, in my opinion, easily transferable skills.

Owners really need to stress corrosion control at the design stage and ensure that their projects are well supervised, managed and inspected from front-end engineering through to engineering, procurement, construction and installation, or they will unfortunately keep hemorrhaging money and carrying out unnecessary offshore reworks—which is not an economically or viable solution to the world’s environmental problems.

ABOUT THE BLOGGER

Lee Wilson

Lee Wilson, CEng, FICorr, is a NACE Level 3-certified CIP Instructor, NACE Corrosion Specialist, NACE Protective Coating Specialist and Senior Corrosion Technologist, as well as an ICorr Level 3 Painting Inspector and Level 2 Insulation Inspector. The author of the best-selling Paint Inspector’s Field Guide, Lee was named one of JPCL Top Thinkers: The Clive Hare Honors in 2012. Contact Lee.

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Tagged categories: Corrosion; Corrosion protection; Offshore; Power; Wind Towers

Comment from Andreas Momber, (4/20/2018, 4:29 AM)

Daer Lee, I found that the first image in the blog is taken from DNVGL-RP-0416, 2016, page 16. Although you omitted some letters and changed "Atmospheric zone" into "Tower" (which, by the way, is not consistent with corrosion zones), it's the same image. I wonder if you could correct that and mention the copyright instead of claiming it as your image. Regards. Andreas


Comment from Andy Mulkerin, (4/20/2018, 4:55 PM)

Hi Andreas -- Thanks for the note; the inclusion and attribution of the original image you mention was a result of a miscommunication between Lee and myself as his editor. For clarity's sake we've removed the image in favor of another and an additional piece of text.


Comment from Lee Wilson, (4/22/2018, 3:19 PM)

Hi Andreas, Sorry about the Tower reference however in your technical paper "Performance and integrity of protective coating systems for offshore wind power structures" Fig 1 states the same quote " Fig 1 corrosion zones on offshore wind power structures investigated in this study (left)". The image describes the turbine in 3 locations as Foundation, Flange, Tower as !,2, and 3 with 3 being the Tower section in your technical paper as corrosion zones? Well done Andy and thanks for the clarification my esteemed colleague.


Comment from Lars Lichtenstein, (4/23/2018, 4:40 AM)

Hi Lee, I can follow most of you arguments, and standards and guidelines can always get better..., but I see our DNVGL-RP-0416 givins quite holistic recommendation towards long lasting corrosion protection. Of cause this has to be combined with sound engeneerign knowledge, quality control, and good workmanship. These documents are no cookbooks and the experience from oil and gas shall be used. So thanks for the article, improvement is always needed and I have a good feeling the major players have learned some lessons and are adapting. Best regards, Lars


Comment from Henry Begg, (4/23/2018, 5:31 AM)

Hi Lee, Thanks for two interesting blog posts! I’d just like to highlight the fact that the link you provide to TWI, relates to a project completed in 2014. We have recently completed another large TSA research project in collaboration with a number of offshore wind companies (https://www.twi-global.com/news-events/news/2018-02-collaborative-crown-project-commended-for-offshore-wind-corrosion-work/) and will continue this research with a follow-on project shortly. There is currently a lot of interest in the use of TSA for offshore wind structures, particularly now that Arkona project in the Baltic Sea has installed foundations using TSA for the primary corrosion protection. Regards, Henry


Comment from Lee Wilson, (4/23/2018, 6:42 AM)

Hi Lars and Henry great comments I am sure the great so called major players have also learned, we all learn on a daily basis. great to see the use of TSA is being used more predominantly in ones opinion its essential for long term corrosion control and mitigation particularly in these environments. its essential that asset integrity needs to be maintained throughout the lifespan of the assets taking into consideration long term economic corrosion control


Comment from Lee Wilson, (4/23/2018, 6:48 AM)

Looking at most of the technical papers that have been been produced it seems that its repeating oil and gas standards that have been in situ for decades "successfully if carried out correctly" The tests carried out by numerous papers have been published years ago with the same systems in the same environments! Pointless exercise in ones opinion as the deterioration rates are well recorded from the oil and gas sectors with far greater corrosion accelerators and worse corrosive cats


Comment from Lee Wilson, (4/23/2018, 6:51 AM)

The internal corrosion I do concur has been challenging for the renewable sector however the oil and gas sector have been dealing with this for decades


Comment from Lars Lichtenstein, (4/23/2018, 7:17 AM)

Oil and gas experience shall be used, but offshore wind is different as well! Monopiles with diameters of ~8m diameter leads to internal enviroments different to internals of jackets. And the fatigue loading of wind structures is unique and fatigue resistance is crucial and design driving. Corrosion allowance is much less impartant, but what S-N curve to apply for what time. Best regards, Lars PS: You will soon receive the offical note for using the picture from DNVGL-RP-0416, 2016, page 16.


Comment from Lee Wilson, (4/23/2018, 7:37 AM)

water depth ?, pressures, H2s, chlorides, sulphates, oil and gas in major quantities, major fatigue loads in oil and gas look at prelude FPSO example PS corrosion allowance is always important as a specialist for DNV I would of thought this of upmost importance


Comment from Lee Wilson, (4/23/2018, 7:45 AM)

The S N curve or the magnitude of an alternating stress versus the number of cycles to failure for a given material depends highly upon circumstances


Comment from Lee Wilson, (4/23/2018, 7:57 AM)

There is a major difference between oil and gas and wind energy standards, The former being the most controversial, whilst I appreciate the DNV recommendation we have to see it as it is ? As only a recommendation a good one I concur but is it not based upon oil and gas recommendations for corrosion zones?


Comment from Lee Wilson, (4/23/2018, 8:01 AM)

?


Comment from Lars Lichtenstein, (4/23/2018, 8:20 AM)

Hi Lee, please have a look here for more detailed regulations, as has been introduced by the BSH in Germany: https://www.vgb.org/_wind_download.html


Comment from Lee Wilson, (4/23/2018, 8:40 AM)

Hi lars thank you some really good links here and good food for thought keep up the good work my esteemed colleague


Comment from Lee Wilson, (4/23/2018, 8:59 AM)

I will say though that it is a great shame when an image of a wind turbine becomes the highlight of a blog between leading institutes taking into consideration that we are all looking for the same ulterior motives and directives i.e safety to our fellow colleagues


Comment from Mario Colica, (4/24/2018, 2:40 AM)

Many thanks to Lee We needed such a clear and complete analysis. Personally I'm involved in Zn/Al metallisation and I have appreciated too much his article www.colimet.it


Comment from Lee Wilson, (4/24/2018, 3:01 AM)

appreciated Mario I am aware of your systems continue the good work I am glad you enjoyed the blog as I say safety first my friend. its paramount that we control corrosion control through sharing experience and collaboration its vital for the future of our industry


Comment from Lee Wilson, (4/24/2018, 5:55 AM)

As can be seen there is a great deal of unprofessional attitudes towards information sharing and safety I have to question the morals of certain institutes in regards to corrosion control! is this not our priority?


Comment from Erik Andreassen, (9/4/2018, 1:37 AM)

I agree to what you are stating regarding the inspection personnel. I have been working in China on and off for the last 6 years along side of the tower fabrications. They are still to this day using a 4 coat system over a metallisation. The industry has progressed a long way in coating development since these towers came into service. How many qualified inspectors are out there saying that the systems are out dated and questioning, who is advising these so called designers. Talk to the coating companies guy's and take good advice from the offshore inspection people.Specifiers tend to stick to what was tried and tested from years ago..We have all moved on.Good report Lee.


Comment from Andreas Momber, (9/5/2018, 6:07 AM)

I have some comments: 1. A more recent and comprehensive review on OWEA coating systems can be found in our publication: "Protective coatings for offshore wind energy devices (OWEAs): a review", J.of Coating Research and Technology, 2018, https://link.springer.com/article/10.1007/s11998-017-9979-5. It covers all aspects of OWEA coatings, including standards, specifications, loads, testing, etc. 2. Corrosivioty category C5-M does not exist anymore in the revised version of ISO 12944. It's CX now for offshore structures. Please check the new part 9 of ISO 12944; it replaces ISO 20340. 3. Be careful with the spray metal designations. Mario Colina in his comment mentions Zn/Al alloys, and this is what we are talking about for OWEA towers (as duplex system with coating layers). TSA and TSZ are a different story. 4. Results of 750 OWEA inspection points on OWEA in the North Sea and Baltic Sea do not reveal many signs of lack in adhesion or inadequate curing. The majority of all damages to the coatings was due to mechanical loads and isufficient steel design (see: A. Momber: "Quantitative performance assessment of corrosion protection systems for offshore wind power transmission platforms", Renewable Energy, 2016; https://www.sciencedirect.com/science/article/pii/S0960148116302439). This is also verified by other authors. 5. In my opinion, industrial production of tower segments will increasae quality and effectivity! The use of paining robots, for example, contributes to these improvements; see: https://www.youtube.com/watch?v=iTP4KXwUlW0


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