Traditionally designed monopile foundations comprise the actual pile and a transition piece (TP), which is aimed at compensating for inclination faults up to 0.5 degrees from the vertical during pile ramming. Semi-standard is a TP that fits loosely over the pile. The interface is a cylindrical-shaped gap several metres long that is filled by fast-curing concrete called grout, a solution originating from the offshore oil and gas sectors. But from 2009-2010 the first reports started appearing of failed monopile grout connections, also known as "pile slippage", which soon turned into a major issue impacting multiple wind projects and incurring substantial remedying costs.
The problem was that imperfectly grouted connections between the pile and TP were not holding fast during operation. Design rules developed by the certification organisation DNV (now DNV-GL) were considered at least partly responsible. The design code left it open to wind developers whether to follow the example of the oil and gas industries and use shear keys to increase the axial strength properties between the grout and steel. Most offshore developers chose not to use them on the grounds of time and cost, which proved an expensive mistake.
The issue of slippage
A rare example of monopiles with the TPs fitting inside the piles can be found at the 108MW OWEZ project on the Netherlands' North Sea coast. Dutch civil engineering contractor Ballast Nedam's design strategy was specifically aimed at steel input optimisation by reducing the surface area exposed to wave loading.
Although monopile slippage was officially reported in autumn 2009, the unusual design at least allowed for a straightforward fix. All the piles were filled from inside the towers with concrete up to a level where the TP's bottom section was embedded. The solution virtually eliminates future slippage risk through its strong steel-concrete interface. The remedying operation vessel, fitted with an Amplemann access system, also provided grouting hose support. But for common monopile foundations with external TPs, alternative solutions had to be employed and these generally proved more complex and costly.
Among several alternatives now adopted for improving traditional grout connections is welding shear keys inside the TP and outside the matching pile surface. However, more recent installation experiences indicate that today piles are hammered almost vertically into the seabed, leading some experts to suggest eliminating TPs entirely. One alternative is to mount the turbine tower directly to the pile via bolted flanges; another is to switch to a slip-joint between foundation and tower. Such slip-joints consist of a pile with a slight outer coning top section like a pencil point, with the tower section atop featuring an internal matching coning surface. Firm impact connection is achieved by dropping the upper onto the lower section.
Cost plays only a minor role for the typical single-piece structures used by the oil and gas industries. By contrast, wind turbine support structures face huge cost pressure right across the factory processing chain. The total period a component spends in the factory - from manufacturing and surface treatment to coating, curing and finishing - is considered a critical process parameter.
The piles, in theory at least, are protected against corrosion if they are fully submerged together with cathode protection, but that only applies to the bottom sections of TPs. For this reason they are coated, while for many years the piles were not. TP manufacturing process completion is followed by surface treatment prior to the actual coating, which includes removing welding spots and other imperfections. A smooth surface is of key importance because any welding spot sticking above the coating layer weakens the overall protection making it prone to a local corrosion start, points out marine corrosion expert Harald van der Mijle Meijer, business developer offshore wind for the Dutch research organisation TNO. His comment highlights the continuous conflict between the pressure to reduce cost with the simultaneous requirement for maintaining stringent quality standards.
Cumulative process time is heavily affected by the coating application and curing method. "Substantial time savings can be achieved by specific measures, like reducing the protective coating layers from three to one, which could easily save up to a full day in reduced curing time," says Van der Mijle Meijer. "The overall quality of coating protection and long-term durability depend especially upon coating type, application method, and the company conducting the actual job. Coatings suppliers often complain that application firms try to monopolise the overall process including in these areas where the focus is limited to the production process and warranty period. Wind farm operational lifetime is not considered."
Van der Mijle Meijer cites two infamous examples where things went badly wrong due to specific choices and insufficient application experience. One example is Horns Rev I (2002), the world's first large offshore wind farm comprising 80 Vestas 2MW turbines on monopile foundations. "The TP manufacturer aimed at optimising the coating process by choosing a single-layer coating finish, but process-wise consisting of two individual wet layers to be applied directly after each other," says van der Mijle Meijer. "This turned out to be an unfortunate choice for this specific application due to a combination of an imperfectly executed curing process and coating system selection. As a result the first coating blisters occurred after only six months of operation, requiring a costly remedying operation.
A second example of premature coating degradation occurred at Alpha Ventus, where Senvion turbine jacket foundation coating repair above sea level proved costly."
This was a bigger problem than it might sound, with van der Mijle Meijer pointing out that at Alpha Ventus even if only 3% of a jacket required repainting, it cost about as much as painting a similar complete structure onshore. On offshore coating remedial costs in general, he says EUR65/m2 is a realistic figure for a coating job on a sheltered onshore site. However, this cost rises by a factor of 100 to 1,000 when the same task is undertaken offshore, with the upper figure often the most realistic, especially when a given job exceeds one day's work.
An additional foundation protective method applied besides coating is cathode protection, with a basic choice between two functionally comparable principles. The first principle consists of zinc or aluminium anodes mounted on the TP's lower part and, depending on water depth, also at pile level. Each metal has its own unique corrosion potential in sea water. The natural (potential) energy difference between anode materials and the steel (cathode) induces an electric current with sea water acting as electrolyte, which gradually dissolves the anodes while protecting the steel.
"An alternative method that is increasingly applied is known as impressed current cathodic protection (ICCP)," says van der Mijle Meijer. "A difference with the first method is that it uses an external source to provide the electric current, so sacrificial anode metals are no longer necessary. Both principles offer the same steel structure protection potential, provided all the right conditions are in place."
Van der Mijle Meijer adds that the marine environment in general has proven far more corrosive than offshore developers initially thought. For adequate cathodic protection of the piles it is essential that these are at all times fully immersed, but in reality this has not always been the case. For this reason, and similar to oil and gas practices, the upper section of the pile is coated internally as well as externally to 5-6 metres below the low-tide water line. Another underestimated issue is the time taken to build large offshore projects. Corrosion protection is required during this non-operating phase, too. For such circumstances without external power supply ICCP is not suited, but conventional cathodic protection with anodes can be applied or a coating system, or a combination of the two.
Corrosion issues are not limited to the outer pile surfaces, says van der Mijle Meijer. "For a long time it was an accepted wind industry opinion that internal pile corrosion was not an issue because of it being a sealed-off confined space. In this perception corrosion would automatically cease once all available oxygen in the column has been consumed, but this has proven untrue."
One contributing reason is that specific micro-organisms in seawater, such as sulphur reducing bacteria (SRB) do not need oxygen to survive. If nutrients are sufficiently available they attack the metal from inside resulting in local pits. This failure mechanism is called bio-corrosion or microbial influenced corrosion (MIC). TNO has found dents up to 10mm deep created in only five years.
A possible remedial option, depending on the microbial active environment, could be the application of either a suitable protective coating or specific cathodic protection system or a combination of both.
A further alternative is treating the water with biocides, but this could fall foul of environmental and decomissioning constraints.
A further problem has been caused by some suppliers opting for infield cable passage from inside the tower into the pile, leaving the structure through a hole below the water line. This so-called "rate hole" is sealed, but has in practice proven inadequate, thus allowing continuous inflow of fresh seawater. "Generally used, cathodic protection for offshore wind substructures does not offer sufficient protection," says van der Mijle Meijer. "At the same time these issues are far from new, and in the oil and gas industries have been known for decades. With these cases in the back of my mind it sometimes seems as if all relevant textbooks have remained unopened for the wind industry," he adds.
Alternatives to monopiles
Monopiles remain the most widely used foundation, but other types have been making their mark. These include gravity-based concrete support structures installed mainly in shallow water projects, steel jackets (initially introduced by Senvion), steel tripods (adopted by Areva), and steel tripiles (developed in-house by Bard).
Key for all foundations is that they must endure harsh marine conditions over 20-25 years of operation.
"It is known that with monopiles and steel jackets the fatigue lifetime calculation methods used are rather conservative," says van der Mijle Meijer. "More advanced future foundation designs could therefore allow structures with reduced wall thicknesses. However, this holds a simultaneous risk for increasing the impact of coating-related failures to long-term foundation structural integrity."
An underestimated additional phenomenon is linked to mechanical surface damages of the coatings including those caused by boat landings. Design improvement measures and stronger coatings such as through adding glass fibres are part of the solution.
Van der Mijle Meijer further believes that future floating wind turbine structures could benefit from oil and gas experiences with floating production storage and offloading vessels, or FPSOs. "Several solutions and challenges are comparable including potential corrosion issues with ballast tanks, cables and mooring systems," he says.
The key for substantial continuous improvements across the value chain lies in a willingness to change current practices, now focused especially at reducing legal risks and capital expenditure.
"This should refocus towards tendering for best value budgets based upon recorded experience and examination on the basis of best technologies, and thus best practice for keeping things simple and sustainable," says Van der Mijle Meijer.