Final Report Summary - INNWIND.EU (Innovative Wind Conversion Systems (10-20MW) for Offshore Applications)
Executive Summary:
INNWIND.EU was a project with a budget of nearly €20 million and with 28 partners. Its objectives include the conceptual design of beyond-state-of-the-art 10-20 MW offshore wind turbines and hardware demonstrators of their critical components. The project has developed several innovative rotor designs, drivetrain components, and fixed and floating substructures that greatly reduce the Levelized Cost of Energy (LCOE) for 10-20 MW offshore wind turbines. The essential part of the presented report is the relative reduction potential in terms of LCOE of the innovations envisaged and not the absolute cost numbers which are subjected to several hypotheses and simplifications. No technological “show-stoppers" for the development of wind turbines between 10-20 MW wind turbines were seen, but manufacturing processes for critical components such as the hub and blade bearings were not fully developed and needed to be matured.
An assessment of the entire wind turbine with different innovations has been made at the 10 MW and 20 MW scales by applying performance indicators and a comprehensive cost model developed in the project. Moving from conventional 5 MW offshore turbines with a reference LCoE value of 107 €/MWh to lightweight 10 MW-20 MW scale allowed a reduction in LCOE due to the larger turbine size along with the use of an efficient lightweight rotor and the shift from traditional three-stage geared drive trains to a medium speed drive. Significantly further reduction of LCOE can be expected for both 10 MW and 20 MW designs, due to the advanced concepts researched in INNWIND.EU getting LCOE close to 85 €/MWh for 10MW turbines and 80 €/MWh for 20MW turbines . This corresponded to an overall reduction of more than 30% in LCOE compared to the reference value of 107 €/MWh from to the conventional 5 MW turbines, thus bringing 20 MW offshore wind turbines closer to the market. Note that the above cost reduction potential only addressed LCOE contributors researched in the INNWIND.EU project (the turbine and its offshore support structure). Innovations addressing the reduction of balance of plant costs, increasing the electrical efficiency of the power plant, reducing the installation and operation and maintenance costs, along with the needed market boost, would further drive the LCOE down towards 50-60 €/MWh by 2025 in water depths near 50m, rendering offshore wind a subsidy-free clean energy production technology.
Some of the key promising innovations as developed in the project that reduce LCOE and increase efficiency included:
• The Low Induction Rotor (LIR), which constrains the extreme loads at the blade root and allows large rotor diameters with increased energy capture;
• Optimized aerodynamic and structural platforms of blades for reduced blade root fatigue and tower base fatigue;
• Active control with a focus on blade trailing edge flaps and blade trailing edge section morphing for load alleviation;
• High temperature superconducting generators to increase efficiency;
• Advanced optimal jacket designs at 50 m water depths to support wind turbines at 10 MW and 20 MW capacities;
• Guyed articulated sub structure at 50 m water depth that avoids resonant excitation for 2-bladed and 3-bladed rotors;
• Novel triple-spar semi-submersible floating wind turbine for 10 MW wind turbines.
Project Context and Objectives:
The overall objectives of the 5-year INNWIND.EU project was the high performance innovative design of a beyond-state-of-the-art 10-20MW offshore wind turbine and hardware demonstrators of some of the critical components. These ambitious primary objectives led to a set of secondary objectives, which were the specific innovations, new concepts, new technologies and proof of concepts at the sub system and turbine level.
The secondary project objectives delivered inputs to an iterated beyond-the-state-of-the-art wind turbine design, which fulfilled the goal of bringing the 10-20 MW offshore wind turbine to an acceptable performance level. The progress beyond the state of the art was envisaged as an integrated wind turbine concept with 1) a light weight rotor having a combination of adaptive characteristics from passive built-in geometrical and structural couplings between deformations and active distributed smart sensing and control, 2) an innovative, low-weight direct drive generator and 3) a standard mass-produced integrated tower and substructure that simplifies and unifies turbine structural dynamic characteristics at different water depths.
The project was divided into four scientific core work packages, each delivering different aspects of the overall program and supported by two non-core packages on dissemination/exploitation and project management. There was very close interaction and collaborations between the different work packages. There were three component-specific work packages (WP2-WP4) whose objectives were to deliver conceptual innovations and demonstrations of the core components of the 20MW wind turbine. Supporting these three component-specific work packages was an integrating work package (WP1) which was responsible for evaluating the innovations developed at the component level, integrating advanced controls for optimal performance, further innovations at the system level and integrating the conceptual designs of the innovative components into the turbine.
The exploitation of the innovations, focusing on accelerating time-to-the-market of the project deliverables, was explicitly dealt with along with the dissemination of the knowledge that was generated. The concepts were researched individually at the component level but also at the wind turbine system level. Their benefits were quantified through suitable performance indicators defined in WP1 and their market deployment opportunities were concretely established in a dedicated work package- (WP5).
Project Results:
Please see attached document for tables and figures!
The innovations developed for significantly reducing LCOE at the 10 MW and 20 MW capacities have been classified as Evolutionary (implying traditional designs), Radical (implying new types of designs) and Revolutionary (implying a complete change in design philosophy). A brief scientific description of the key innovations is given below.
The low induction rotor was developed with dedicated airfoils for the outer part of the blade which are designed for operation at a low lift coefficient of around 0.8 and whose aerodynamic characteristics were validated against wind tunnel measurements. Tools for the integrated design of aeroelastic tailoring with passive blade deflection couplings have been developed along with numerous solutions for an optimum combination of passive and active control. The TRL level of these rotor innovations have been moved from around 3 at the start of the project to TRL 5 at its closure. Innovative wind sensors such as a spinner anemometer and spinner LiDAR that measure high frequency wind time series either at a point on the spinner (anemometer) or at many points in front of the turbine (LiDAR) have been demonstrated. The Spinner anemometer allows ease of wind turbulence measurements as an input to controls enabling load mitigation or increasing energy capture.
High temperature superconducting generators with Magnesium DiBoride (MgB2) coils were investigated, along with coil testing which showed that the reliability of the coil windings had to improve to ensure low resistivity. The superconducting coil Yttrium Barium Copper Oxide (YBCO) was also tested, which though showing great potential, requires significant reductions in cost to enable commercial usage at 10-20 MW scales. Reducing the cost of high temperature superconducting wire by a factor of 4 and simultaneously increasing the critical current density by a factor of 4 is required for cost-effective generation for fixed base offshore wind turbines. The status of these superconducting generators is at a TRL of 4. This is because, even though the tower top weight may be reduced by 30% compared to a conventional drivetrain, this reduction in weight translates to insignificant benefits in LCOE due to the large cost fraction of the substructure, which remains relatively unchanged.
The PDD provides for magnetic gearing with a permanent magnet generator and has been tested in a lab at different scales of 5 kNm, 16 kNm and 200 kNm max torque values. It provides for high generation efficiencies of at least 95% at the small scales and is expected to reach 98% for the large generators. This increase in efficiency, along with moderate cost, is expected to contribute to about 4% lower LCOE. Its current status is at a TRL 4.
Fixed Substructure design at 50 m water depth is highly challenging for 10 MW wind turbines due to the 3P (3 times rotor speed) excitation of the sub structure for 3-bladed rotors and 2P (2 times rotor speed) excitation for 2-bladed rotors. An advanced optimal jacket was designed with a fatigue life of 25 years for the 10 MW turbine for 3-bladed rotors, while an innovative articulated joint sub structure was designed for the 2-bladed rotor. The TRL level of the jacket solution is relatively high, since jackets are already commercially used, while the TRL level of the articulated joint structure is at 3. At the 20 MW scale, it was found to be relatively easy to avoid rotor harmonic excitation, thereby enabling jacket substructure designs. Vertical axis (VAWT) and horizontal axis (HAWT) floating wind turbines have been designed for 10 MW capacities.
Technology roadmaps depicting the path to market for these innovations have been developed along with necessary standards to certify such wind turbines.
Size of commercial offshore turbines
When INNWIND.EU started in 2012, the maximum size of the commercial offshore turbines available in the market was 5-6 MW. Two characteristic members of this family were the GE 6 MW / 150.8m diameter Class IB Haliade and the Siemens 6 MW / 120m diameter turbines. Originally announced by Vestas as a 7 MW unit in 2011, the V164's has in the meantime been upgraded to 9+ MW. The first project using the V164, DONG Energy's Burbo Bank extension is currently under construction. In the meantime two additional 8MW turbines were put on the market, the ADWEN AD-180 is setting a new benchmark for blade length at 88.4 metres. The turbine has been selected for three of France's first six offshore projects, all of around 500 MW. Siemens has twice since upgraded its direct-drive offshore turbine to a power rating of 8 MW with an extended rotor diameter of 154 metres.
Increasing the turbine rating and size has an important impact on all main three LCOE drivers, CAPEX, OPEX and CF. A 2012 study conducted by BVG associates1 provided insight to the scaling laws ruling the different CAPEX contributors but also DECEX (decommissioning expenditure). The study considered a 500 MW offshore wind farm located at several distances from the nearest construction and operation port, comprising turbines of 4, 6 and 8 MW at different average water depths of between 25 and 45 m. The type C site of the BVG study is located 40 km from the port and has an average water depth of 45 m and average wind speed 9.7 m /s at 100 m above mean sea level. This is the site type closest to the external conditions of INNWIND.EU assumptions. The turbines at this site are supported by four-legged piled jackets with a separate tower. The results for a baseline wind farm are summarized in Table 1.
Table 1 CAPEX and DECEX dependence on the turbine rated power 16
From the individual CAPEX categories, turbine costs per MW are increasing with rated power while there is a decrease in the costs of support structure along with installation costs. This is in line with the project’s early finding that classical upscaling of a given turbine technology increases the turbine CAPEX by p3/2 while the BoP CAPEX by p1, where p is the nominal power ratio. Learning curve effect and innovation reduce both CAPEX exponents (3/2 and 1) considerably. Array cable costs seem turbine size independent. Decommissioning costs are also reducing for larger turbines, staying proportional to the installation costs (with a fixed ratio of 60%). Although decommissioning costs are quite high in absolute values, their contribution to LCOE is limited, since they are annualized with a small factor representing the fact that DECEX will not occur until the end of the project’s lifetime.
OPEX and turbine size
INNWIND.EU performed parametric calculations for a 500 MW wind farm using the O2M-Plus tool of DNV-GL. Introducing as free parameters the turbine rated power and reliability level we calculated direct O & M cost per MWh produced and the related wind farm availability losses. The through-life turbine reliability was modelled by means of a typical “bathtub” curve which addresses the three phases of the turbine service life: the early-life “bedding-in” period, the high reliability intermediate period and the end-of the-design-life period where failures due to wear and tear occur more frequently. Failures were classified into four categories depending on the severity of the required repair. A reference reliability level is that of a turbine suffering a typical number of failures per year (of all four categories mentioned above) where more than 60% of them simply require a visit for a manual restart. Better or worse reliability levels in our investigation are introduced by assuming a multiplier of the reference number of failures.
From the results of the O & M study it was seen that using larger turbines not only significantly reduces the O & M direct costs but also slightly increases the wind farm availability in benefit of the annual energy production. As expected, the increasing reliability of the wind turbines has positive effects on both availability and direct O & M costs.
Effect of upscaling on LCOE
Even classical up-scaling has a positive effect on the capacity factor of a large offshore wind farm. This effect was studied in the UPWIND Project where the (aerodynamic) wind farm capacity factor was calculated as a function of the WT rated power. The mean wind speed distribution used at the hub height of all designs was a Rayleigh with mean 10 m/s while the wind rose was assumed uniform direction-wise. Two wind farm sizes were considered, with 500 and 1000 MW installed capacity. The spacing of the turbines was 7D X 7D, leading to similar offshore area requirements for all turbine sizes.
The wind farm aerodynamic capacity factor (the production of all turbines including the wake effects) increases with the size of the single turbine. Going from 5 to 10 MW, we have a nearly linear increase of almost 2.5 percentage units, with an additional increase of 2.5 units from 10 to 20 MW. This effect is attributed to the reduction of wake effects due to the smaller number of turbines in the wind farm when the rated power of the individuals increases. This capacity factor improvement is not related to better wind resource available at larger distances from the shore (and deeper waters) or going at larger hub heights. These are additional factors that might further increase the farm capacity and are (indirectly) linked to the single turbine size.
Figure.1 Turbine size influence to LCOE and its main drivers. An indicative plot. The actual turbine size achieving minimum LCOE depends on the actual site conditions and, especially, the sea depth.
The synthesis of the above suggests that larger turbines increase the turbine CAPEX and the wind farm capacity factor while decreasing the BoP CAPEX, the OPEX and the DECEX. Given the state of the technology and the wind resource, there will always be an optimal turbine size that minimizes LCOE and which is water depth dependent. This optimal size increases with the depth. This is further illustrated in Figure.1. Note that the optimal size of 10 MW suggested by the figure is only indicative and the actual optimal size depends on the site conditions and the sea depth in particular.
Clearly, a quantitative decision on the optimal turbine size for a specific offshore site which also accounts for the technology evolution and the potential that innovation adds to LCOE reduction should be based on a proper cost model integrated to the LCOE calculator. Such a cost (and mass) model has been developed in INNWIND.EU to assess the innovative designs at the components and system level researched in the project. The model: i) is developed at the sub-components level, ii) is based on key turbine design parameters (Rated Power, Diameter, Hub-height, Rated Torque etc.) and operating conditions, (wind class, etc.), iii) is suitable and flexible enough for up-scaling studies too, taking account of technology learning curves, iv) account of variations in raw materials pricing, inflation and currency fluctuations so that cost data from different periods and markets can be synchronized, v) explores previous experience from earlier cost modelling works in WINDPACT (USA) and UPWIND (EU). The Input / Output section of the cost model is shown in Figure 2.
It must be clarified that the model was built aiming at the turbine and its support structure technology evaluation assessment and not for providing exact values for LCOE. This is because its BoP CAPEX part (installation costs, electrical infrastructure etc) and the OPEX entries are very roughly taken into account. To this end, the model results are valuable in the relative sense only, for evaluating the potential of INNWIND.EU research themes to LCOE reduction.
Figure 2 The I/O section of the INNWIND.EU cost model
External conditions for designing 10-20 MW offshore wind turbines
The establishment of a database that provides information on the wind speed and turbulence at higher atmospheres (above 150 m) and its connection with wave conditions is essential for designing large offshore wind turbines in the 10-20 MW range. There are several databases which contain wind parameter measurements for various near- and offshore sites across Europe. The locations of buoy measurements (black/white points) and met masts (red and yellow markers) in the North and Baltic Seas are shown in Figure 3.
Figure 3 Map of measurement locations in the North and Baltic seas.
One of the available datasets one, the FINO 3, has been further analysed to suit the project needs. The main argument for selecting FINO 3 is that both met mast and LiDAR data was available for the same time period. So, the LiDAR measurements can be evaluated up to a height of 100 m with reference to the data of the meteorological mast. This allows for a reliable investigation of wind conditions in tall atmospheres up to the maximum measuring height of the LiDAR system at 160 m. Furthermore, at FINO 3 there are available measurements of wave parameters from 2009.
In parallel to the FINO 3 dataset analysis, the project derived wind profile data up to 310 m height above mean sea level from high-resolution mesoscale simulations performed with the Weather Research and Forecasting (WRF) model. Simulations for 2007 and 2011 have been carried out for three nested domains with a grid resolution in the finest domain of 2 x 2 km² (Fig). The values of eight parameters – wind speed, wind direction, thermal stability parameters (inverse Obukhov length), pressure, temperature, humidity, turbulent kinetic energy and turbulence intensity – are given in the delivered data set for different heights (every 20 m from 30 m up to 310 m) as 10 minute time series’. Additionally, the time series for the following variables are given: the planetary boundary layer height, the sea surface roughness height, the wind shear parameter alpha and the sea surface skin temperature. To optimize the accuracy, test simulations with four different parameterization schemes for the planetary boundary layer have been carried out and have been compared to measured data of the met masts FINO1 and FINO3. The results underline the importance of atmospheric thermal stratification for the vertical profiles of the turbine design parameters.
Reference and Evolutionary Designs
Reference Turbines
Typical examples of evolutionary architecture are the 10 and 20 MW Reference turbines. Here the main issue was the upscaling to larger turbine size using mature technologies, taking advantage of the larger size whenever possible. As discussed earlier, the size of the turbine in itself is an important parameter for minimizing LCOE in deep offshore.
The two reference turbines have a classical 3-bladed, upwind, max power coefficient (Cpmax)-driven rotor design of high specific power (W/m2). Their all-glass blades are pre-bent, using thicker than usual profiles for improved structural efficiency without compromising their aerodynamic efficiency. This is a Reynolds-driven benefit which comes with very large turbines, as thicker airfoils operating at very high Reynolds can have similar performance with thinner operating at lower Reynolds levels.
The 10 MW RWT was designed as an IEC Class IA turbine to withstand increased fatigue loads mainly due to wake effects, since ambient turbulence offshore is well below subclass C. Fatigue is the design driver of some of the expensive subcomponents of offshore turbines, such as the supporting jacket. Given the fact that wake effects are reduced when larger turbines are deployed for a fixed wind farm capacity, we decided to design the 20 MW RWT as an IEC Class IC turbine.
The two reference turbines have a medium-speed drive train with gearing ratio ~1:50 and permanent magnets generator. For multi-MW turbines this selection performs well in terms of reliability and cost. Full range power conversion is possible.
A standard PI variable speed collective pitch controller is used in both turbines. Due to the 3-P resonance discussed above, the 10 MW RWT variable speed controller applies an exclusion zone at relatively low wind speeds. This has been avoided for the 20 MW RWT by slightly increasing its tip-speed-ratio and by using a taller tower that softens the first system’s global eigen-frequency.
The reference jackets are assumed classical designs in terms of architecture, materials used and manufacturing procedures. Their legs are piled to the seabed.
Basic data and technical specifications for the 10 and 20 MW Reference Wind Turbines are given in Table 2.
Table 2 Basic turbine data for the 10 and 20 MW RWT
Evolutionary Architectures
Τhe main features of the reference designs are maintained along with the reference drive trains. Innovative solutions are sought for the 3-bladed upwind rotors to improve their energy capture and structural efficiency. Given the fact that the rotors are shaping the AEP while their contribution to the overall offshore turbine CAPEX is relatively small, it appears that a larger (and more expensive) rotor than the reference may significantly reduce LCOE by increasing energy capture. Nevertheless, the extra yield has to come without overloading the downstream components, increasing the overall turbine CAPEX.
The project explores several ways for increasing the rotor size (lower specific power designs) while maintaining the system’s loads at their reference levels. One way is by optimizing the induction level in the aerodynamic design, aiming to achieve the best trade-off between power production and hub-loading. The optimization leads to a Low Induction Rotor (LIR) which can be best realized through a low solidity blade planform combined with low lift airfoils. Another, complementary, way is to apply passive or active load mitigation techniques, possibly combined with advanced control. Regarding passive loads alleviation, INNWIND.EU put a lot of effort in bend-twist coupling (BTC) technology. In BTC designs, when the blade bends out of plane, it simultaneously twists passively nose down, reducing aerodynamic loading. This is accomplished either geometrically, by back sweeping the blades, or through the structural design by exploring the anisotropic properties of the composite materials or properly placing the shear-centre of the blade sections in respect to the twisting axis. Advanced turbine control based combining cyclic and individual pitch control is also sought in evolutionary designs. Innovative blade structure designs are sought, using full carbon or hybrid glass-carbon elements, for increasing the stiffness and adjusting the natural frequencies of the longer blades as well as enhancing their local buckling resistance properties.
Advanced jacket designs for 10 MW wind turbines require that the support structure fundamental frequencies are away from rotation excitation, that is for a 3-blade rotor, away from 3P and 6P excitations. Such a design is often very difficult to achieve due to the stiff nature of the jacket structure. The reference jacket for the 10 MW reference wind turbine is a traditional design which has 3P excitation and therefore low fatigue life. The advanced jacket designs created in this project allow for an integrated design approach so that correct tubular member diameter and thickness is applied at joints so as to possess sufficient fatigue resistance. This provides a jacket design as given in Table 3. Furthermore, an effective optimization of the jacket structure to reduce the natural frequencies below the 3P excitation zone has also been made so that the design meets a target lifetime while still being cost-effective. The optimal jacket design configuration is provided in Table 4.
Table 3 Advanced Detailed Design Jacket parameters for the 10 MW RWT
Table 4 Optimized modular jacket parameters for the 10 MW RWT
Basic data and technical specifications for the 10 and 20 MW evolutionary designs are given in Table 5
Table 5 Basic turbine data for the 10 and 20 MW evolutionary designs: 285 m 20 MW (left), 178 m 10 MW (right)
New Platforms
Two platforms are discussed in this section. The first includes two-bladed designs, upwind and downwind, combined with a soft semi-floater in order to circumvent 2P-4P excitation consequences. The second platform addresses three-bladed upwind designs which, further to the innovations introduced earlier, explore possibilities for weight and cost reduction offered by non-conventional direct drive generators, superconducting and magnetic pseudo-direct drive (PDD), for bottom-fixed and floating designs.
Two-bladed upwind/downwind rotors with semi-floater
For two-bladed rotors, it is very important that there is no excitation of the support structure from 2P and 4P harmonics. Given that the 10 MW wind turbine has a rated RPM close to 9.6 the 2P frequency region is from 0.2 Hz. To 0.32 Hz, which band will result in resonant excitations for the jacket designs shown in Table 3.2 and Table 3.3. To avoid such excitation, a support structure with drastically reduced eigen-frequency is needed without moving to a floating solution since the water depth is still 50 m.
Figure 4: A two-bladed upwind 10 MW turbine placed on a semi-floater sub structure
The semi-floater concept provides such a viable solution for a 2-bladed rotor. It is a combination of the classic monopile substructure and the traditional spar-buoy floater. It is illustrated in Figure 4, where the concept consists of three main constituents: an articulated joint at the soil bed, the mooring system, and the floating system. The floating system is made of a buoyant chamber and the main cylindrical substructure. The buoyant chamber was developed as an ellipsoid of 30.0 m height and 11.0 m diameter cast out of glass fibre. The buoyant force for platform stability is provided by the buoyant chamber placed near sea level and from the buoyant force generated by the cylinder. Concrete ballast is attached to the base of the cylinder to lower its centre of gravity and the weight of the ballast is calibrated to ensure that the net steady vertical force is in equilibrium.
The substructure is connected to the sea-bed using an articulated (or universal) joint embedded into a reinforced concrete base. The reinforced concrete base is a short cylinder whose upper face has a hemispherical cavity. The reinforced concrete base works like a gravity based foundation providing fixity to the platform. The other contact points to the soil are the mooring lines anchorages. The catenary mooring lines are connected to the sub structure with delta connections, which have their fairleads attached to the buoyant chamber. The delta connection aims at providing torsion resistant effect to counter the turbine yaw motions.
Table 6: Masses and System level frequencies of the 2-bladed rotor on a semi-floater
Three-bladed upwind rotors with non-conventional direct drive, bottom-fixed or floating
Further to the evolutionary innovations introduced earlier, we here exploit possibilities for further loads reduction by deploying distributed flaps along the blades span. The optimal position and size, the integration in the blade structure, the activation techniques and the distributed control of such flaps are researched in the project. We also seek combination with advanced feedforward control concepts, fed by wind data from LiDAR or spinner anemometer. The development of control algorithms for innovative turbines (2-bladed rotor, 3 bladed pseudo magnetic direct drive, low induction rotor etc) at the 10 MW and 20 MW has been made with aeroelastic simulations which show their loads reduction potential and impact on LCOE. Two new wind sensors were investigated: the Spinner anemometer and the Spinner LiDAR. The spinner anemometer comprises 3 sonics (ultrasonic anemometers) which measure the instantaneous directional wind velocity at three positions on the spinner of the turbine. The Spinner LiDAR is a remote-sensing instrument for scanning the wind inflow at several points in a plane ahead of the wind turbine
Figure 5: Deploying flaps along the blade span for load alleviation at higher wind speeds or increase power capture at low mean wind speeds.
The demonstration of innovative adaptive blade flap control has been demonstrated in a wind tunnel and under free wind turbulence on a rotating test rig. The developed flap control was subsequently simulated on a Suzlon S111 wind turbine which showed 1.7% increase in AEP or blade root fatigue reduction of 9%.
Magnetic and superconducting drives are researched, along with dedicated power electronics that allow full range power conversion and their integration into the nacelle design. The magnetic pseudo direct-drive (PDD) generator is realizing the possibility of applying magnetic gears in wind turbines. In a PDD generator, the magnetic gear and the electrical generator are mechanically as well as magnetically integrated. Prototypes of PDD machines with a continuous torque output of 4 kNm to ~16 kNm have been designed, manufactured and tested. A 200kNm wind turbine generator is currently being manufactured and will be tested in 2018.
Superconducting coils in wind generators is a promising technology, because the high magnetic flux and current densities compared to conventional generators enable a considerable reduction of the generator weight and volume at large power levels which might be of particular importance for floating turbines. Additionally superconducting direct drive generators will have no or a 100 times smaller dependence on Rare Earth element metals compared to permanent magnet direct drive generators. In INNWIND.EU the use of different superconducting materials, with main focus on MgB2 and YBa2Cu3O7 along with their cryogenic cooling systems, has been considered and tested.
Design of King-Pin forward-mounted generator
The resulting designs for 10 MW superconducting direct drive and Pseudo Direct Drive are shown in Fig. 6 and Fig. 7 respectively.
To reduce the risk of large generator air gap deviations introduced by deflections of the main load carrying components, a separate generator bearing was introduced with the purpose to isolate the generator from these deflections. The rotor of the generator is connected to the hub via a torque-only connection.
Figure 6: Illustration of the 10 MW MgB2 superconducting direct drive generator with a diameter of Dgen = 8.4 m, a length of Lgen = 1.3 m and a weight of mgen = 286 ton mounted in front of turbine blades of the King-Pin nacelle (top) and behind the turbine blades(bottom).Both configurations seems possible to be scaled to power ratings up to 20 MW.
Figure 7: Illustration of 10 MW Pseudo Direct Drive generator with a diameter Dgen = 6.0m Lgen = 1.7m and a weight of mgen ~ 150 ton mounted in front of the turbine blades of the king-pin nacelle.
Innovative concepts researched regarding aerodynamic design
Low induction rotors
10 and 20 MW Low Induction Rotors have been designed and their performance and loading have been assessed against the reference wind turbines. Since the design procedures followed for the two turbine sizes are similar, we shall restrict this presentation to the 20 MW LIR.
Taking advantage of the higher Reynolds number at which a 20 MW turbine operates compared to a 10 MW one, new low lift 26% thick airfoils have been designed for the outer span of the 20 MW LIR blade with an aim toward increasing its structural performance without compromising power production. The assessment of the aerodynamic performance of the designed airfoils using high fidelity CFD-based tools demonstrated that such a 26% thick airfoil operating on a 20 MW rotor can indeed have similar performance with a 24% thick airfoil operating on a 10 MW rotor.
Using the CFD polars of the 26% airfoil the planform of a 20 MW LIR Rotor was redesigned. The LIR was optimized for increased annual energy capture constraining its blade root (mean) flap-bending loads. The optimization also resulted in a new rotational speed schedule, respecting the variable speed range of the 20 MW RWT.
The power performance of the 20 MW LIR versus the 20 MW RWT was then assessed using higher fidelity tools. Both CFD-RANS with free transition and a free-wake vortex method was used for this. Comparing LIR against the 20 MW RWT rotor we note that LIR blades are 13% longer and 7.6% heavier than the RWT. LIR increase the individual turbine capacity factor by 7.5% and the wind farm capacity factor by 9.8%. Overall, the anticipated reduction in LCoE in comparison to the 20 MW RWT is about 4%.
Two-bladed rotors
The two-bladed, downwind rotor concept has been explored from the beginning of the INNWIND.EU project because several studies in the past have shown that the concept might be competitive compared with the three-bladed rotor. Low frequency noise (LFN) from the downwind rotor due to the blade passage of the tower wake is known to be a major problem for such turbines. However for the off-shore application considered here it is not expected that LFN should cause problems.
A baseline 10 MW two-bladed RWT version derived by simple scaling rules from the three-bladed INNWIND.EU RWT was presented at an early stage in the project. The major influence on the cost is the saving of one blade and thus a decreased tower top mass. However, a major problem was considerably increased tower loading caused by the interaction of the 2p rotor frequency with the frequency of the 1st tower mode of vibration.
One innovative solution for offshore application is the use of the semi-floater supporting concept, as the 1st tower frequency for that design is much lower than a bottom-fixed structure with the tower on top of this.
In another design and optimization study of the two-bladed rotor, the inclusion of design parameters enabling passive load alleviation by a strong bend twist coupling (BTC) showed very promising results. The BTC is achieved by a different chordwise position of the spar caps on the suction and pressure side of the blade and by a forward movement of the elastic axis. All these characteristics originate from the numerical optimization and were not pre-determined. The most promising design is a blade with an 8% increase in blade length, a more slender planform and a reduction of about 8% in blade weight from 37.8 to 33.7 tons when compared with the two-bladed RWT. The AEP increases with 8% and the loads are within the envelope of the baseline. The tower clearance is kept within the limit by 2.5 degrees pre-cone. In another design, the blade was stretched by 12% with an 11.9% increase in AEP. With a pre-cone of 4.5 degrees, the tower clearance was kept within the limit. In this case, some of the loads exceeded the envelope. However, it might be that advanced control with IPC or flaps could bring the loads back within the envelope.
As concluding findings for the 2B rotor investigations, it can be stated that such a rotor has to be mounted on a flexible tower like the semi-floater design mentioned above in order to avoid the 2p excitation problem.
New airfoils
The rotor concept studies of INNWIND.EU showed the need for dedicated airfoil designs to realize the full potential of the new rotor designs. One of the overall tendencies in the new rotor designs is the use of more slender and longer blades. Slender blades can be achieved by using thicker airfoils which means that the chord can be decreased for the same load on the blade.
One study has focused on the design of a 30% thick airfoil for outboard application on a blade where a 24% airfoil is used on the 10 MW RWT. The new airfoil contour is shown to the left in Figure 8 together with the two FFA airfoils that it will replace. To the right in the same figure it can be seen that the new 30% airfoil has a lift-to-drag ratio that is almost the same as for the 24% airfoil it will replace. However, the detailed analysis of the airfoil characteristics has shown that the large roughness sensitivity of the new airfoil results in a larger penalty in terms of power coefficient decrease than with the FFA 24% airfoil.
Figure 8: The new 30% airfoil design in comparison with the two FFA airfoils (Left) and the lift-to-drag ratio for turbulent and transitional flow (Right)
LIR rotor designs, in particular, require dedicated airfoil designs as the low loading giving the low induction is achieved by operation at a low design lift, typically around 0.8. A complete airfoil family with a low lift 24% airfoil for the outboard part of the blade was designed for the 10 MW LIR. For the 20 MW LIR, the increase in Reynolds number made it possible to increase the thickness to 26% for a new low lift airfoil to be used outboard on the blade, Figure 9 left. The improved operational conditions at the higher Reynolds number made it possible to design the 26% airfoil so it has almost the same lift-to-drag ratio as the 24% airfoil used on the 10 MW rotor, Figure 9 right.
Figure 9: To the left, the new 26% (10-90) low lift airfoil for use on the outboard part of the 20 MW LIR rotor. To the right, the lift-to-drag characteristics.
Innovative concepts researched in structural design
Passive control through Bend-Twist-Coupling (BTC). Alternative ways of BTC.
Ten different structural solutions were presented with the aim to achieve passive load alleviation while maintaining the power output, reduce the cost of the wind turbine components, and thereupon reduce the cost of wind energy generation. In one design the structure of the blade was optimised, running the complete design circle to achieve a solution complying with all design requirements, including fatigue, while introducing passive load reduction through the incorporation of bend-twisting coupling. The optimal solutions when changing the angle in the spar cap (SC) of 3, 4, 5, 6 and 7deg and in the skin (SK) of 5, 10 and 15deg, are presented in Figure 10. The same figure shows the reduction of the LCOE with respect to the RWT. A 3% mass reduction was achieved with about 1% increase in annual energy production, leading to an approximate 1% reduction of the levelised cost of energy. Nevertheless, the effect of the load reduction achieved on other wind turbine components was not taken into account, leading to conservative results regarding the gain on LCOE.
In another part of the work seven different solutions were investigated, combining the concept of bend-twist coupling, swept blade, and single shear web (reduced torsional stiffness). The combination of all three passive control strategies in the same reference blade was found effective mainly with respect to the blade root flap-wise extreme and fatigue moments. The concept of bend-twist coupled blade was investigated from different perspectives. One solution studied is based on the same concept of introducing bend-twist couplings, yet in this case, the angle of the fibre orientation for the drive of the coupling is not constant along the blade length, but rather varies with the radial position, see Figure 4.7. Optimized coupling behaviour is achieved in this way, yet at a higher manufacturing cost. By combining tow-steered fibres and a variation of the spar geometry and orientation, the new blade design produced an induced elastic twist which better approximates the optimum twist of the blade across its entire operating range. At the rated wind speed, the concept adaptive design reduced the amplitude in flapwise bending oscillations by 16% compared to the reference blade.
Finally, focus was on the development of a tool that enables accurate prediction of the blade response in the presence of bend-twist coupling terms. The incorporation of the bend-twist coupling is performed by suitably adjusting the fibre orientation of the composite material at the spar cap. Using this tool the blade is then designed to achieve load alleviation in comparison to the reference blade design.
Figure 10: LCOE reduction compared to RWT for optimal solutions (Skin Angle (SK) 5, 10 and 15deg, Spar Cap Angle (SC) 3, 4, 5, 6 and 7deg).
Figure 11: A schematic design of the fibre path along the curved blade planform representative of the concept used to investigate bend twist coupling.
Innovations for Support Structures
New innovations for future cost-effective, mass-producible designs are investigated, such as new foundation types, soil-structure-interaction of large piles or suction buckets, innovative transition piece designs or designs using hybrid materials which have never been employed before in wind energy. In addition, design integration using jacket-specific controls and innovative fabrication and installation processes shall complete the overall cost saving potentials. Figure 12 illustrates the considered innovations for the fixed base support structure which are summarised as follows.
Figure 12: Considered innovations for the support structures of large offshore wind turbines
• Innovations of load mitigation
Novel 10-20 MW Offshore wind turbines need to have a lightweight design to reduce the material cost. The increased size of the rotor and tower height results in magnified vibration amplitudes which need to be reduced. In addition, the offshore wind turbine dynamics need to be reconsidered when upscaling the substructure design.
In principle, load mitigation strategies are classified under two main categories: control concepts and damping devices. Three dedicated load mitigation concepts are studied on the operational control level: speed exclusion zones, soft-cut out, and peak shaving.
Firstly, active load reduction technology has been implemented for the reduction of the thrust around rated wind speed by the so-called Peak Shaver. Also, a speed exclusion window to avoid resonances during operation is considered for the 10 MW design. Secondly, passive damping systems have been analysed for the support structure. The considered damping systems include the passive Tuned Vibration Absorbers (TVA), Tunde Mass Dampers (TMD) and Viscous Fluid Dampers (VFD) for the 10 MW wind turbine class. It has been shown that the passive dampers are more effective in a sideways direction while the effectiveness of these devices is marginal in fore-aft direction.
For the 20 MW wind turbine class, the application of passive TMD will become less effective and the integration into the available space in the tower top will become more difficult. Therefore, the employment of semi-active or active damping systems is becoming more attractive. Semi-active dampers operate in a broad frequency bandwidth and are more effective in both directions. The numerical modelling of a semi-active magnetorheological (MR) damper is implemented and integrated in both the jacket and the tower structure to mitigate loads. The study reveals the potential of MR dampers to alleviate fatigue damage in all conditions. Further investigations are required to propose an optimal configuration for reliable full-scale implementation in the field.
• Innovation of hybrid materials
The sandwich material for a monopile, as well as the chords and braces of a jacket sub-substructure, have never been used in the offshore wind industry. Sandwich tubes are rod-like structural components consisting of three components: two relatively thin steel tubes and a core made of ultra-high performance concrete (UHPC). Due to its high strength, UHPC is an appropriate solution to save material and weight. The project studied the numerical and experimental investigation of sandwich tubes, as well as the development of the pre-design methods for sandwich tubes and their application on the chords and braces of the jacket structure. The bearing capacity of sandwich tubes under combined axial loading and bending moments was also investigated.
Taking the basic geometric parameters into account, variations of the member parameters, such as the ratio of steel to sandwich material, were investigated and the effect on natural frequencies compared to the reference structure was evaluated. It should be noted that the current TRL of sandwich tubes for jacket sub-structures is 3. The estimations show that if the necessary manufacturing time is summed up, the steel tubes for hybrid jackets allow a saving of up to 50% in time in relation to the thicker common steel tubes.
The second innovation considered is the potential of adhesively bonding instead of welding. In this regard, the considered innovation is to adhesively bond the trusses connected to the main pillars in the jacket substructure connections. The main potential benefit is that an adhesively bonded connection can be less fatigue-sensitive than a welded connection. On the other hand, potential disadvantages are issues during installation (can the adhesive be applied in a controlled manner?), sensitivity to temperature and humidity influences during operation, as well as sensitivity to multi-axial strains during operation.
• Innovation of vibro-driven piles
Vibratory-driven (VD) technology, as an alternative to impact-driven (ID) technology, has the potential to significantly reduce the costs associated with installing piled foundation for offshore wind turbines. The economic advantages of this technology include: the absence of noise mitigation systems, the reduction of the installation time and the reduction of the fatigue load in the pile steel otherwise induced by impact hammers.
The results of an experimental campaign including two large-scale impact-driven piles have been presented and interpreted by using CPT methods. Soil profile and steel price were assumed and are regarded to be rather realistic values. The analysis carried out with loads referring to a 10 MW wind turbine reveals that, on the basis of the tests carried out, the price difference between impact-driven and vibro-drive piles is around €38k when adopting UWA-05, and around €47k when adopting ICP-05.
• Innovations of suction buckets
Jacket structures are usually founded on pre-installed piles. However, bucket foundations are an option that can decrease the overall cost and allow alternative installation strategies. Since wind turbines are dynamically sensitive structures, where stiffness requirements must be satisfied, an alternative design allowing increasing stiffness is the multi-bucket configuration, wherein loading response changes significantly with respect to a mono bucket. The following work is focused on loading of a multi-bucket foundation. The overturning bending moment is mainly transferred into vertical compression and tension loads in the buckets. For these reasons, it is important to understand the behaviour under tensile loading and improve the stiffness of the foundation so more correct design methods can be established. Experimental results of vertical axial loading cyclic tests of bucket foundation are conducted. The drained cyclic response was examined by simulating the long-term cyclic loading conditions for an offshore structure under the normal serviceability performance. Cyclic degradation was tested applying post-cyclic pull-out loads on the bucket foundation model.
• Innovations for floating wind turbines
Four different innovative floating concepts supporting the INNWIND.EU 10 MW reference wind turbine have been designed at a conceptual level to evaluate the advantages and disadvantages of the different designs.
A semi-floater design as described earlier is proposed combining the strengths of floating structures with those of bottom-fixed ones. This is a solution well suited for intermediate water depths (50-70m) where fixed sub structures may be too expensive and floating sub structures may not be used.
Two different torus-shape structures in concrete have been developed. The torus has the advantage of a reduced draft for an increased flexibility to the water depth and it significantly reduces the wave excitation due to the “moonpool” feature and the steel construction around water level, where wave forces are high. One of the designs has two dynamically linked floating bodies to reduce excitation from waves. The use of concrete as material can drastically reduce the cost of these designs.
Finally, there is an asymmetric semi-submersible floater which aims at reducing the need of lattice construction elements. The substructure is composed of three cylinders, connected by pontoons to form a geometrically simple shape. The function of the pontoons is not only structural, but also hydrodynamic: the pontoons work as heave plates to damp the motion of the offshore wind turbine. In addition, the wind turbine is mounted on one of the cylinders, instead of building a central structure to hold it in the platform centre. This allows for the simplification of the structure and reduction in manufacturing costs.The analysis of these concepts indicates that the semisubmersible design has good dynamic behaviour, together with manufacturing and installation advantages. On the other hand, the use of concrete can potentially reduce the cost of the platforms.
Different simulation tools for floating wind turbines with diverse complexity levels have been developed within the project. These tools can be applied at different stages of the design process, from conceptual design to a detailed analysis. The new features developed include coupled aeroelastic models considering the platform flexibility or advanced aerodynamic approaches such as the free vortex method. CFD codes have been also developed, including movable meshes that allow for the capturing of non-linear interaction between the fluid and the structure. This has particular importance in the analysis of cases with rough sea states. Other non-linear effects included in the existing integrated tools are mooring dynamics or fully non-linear wave models. These effects have particular importance in the analysis of TLP platform concepts.
The simulation tools developed in this project have been validated against experimental data. This leads the tools to a TRL of 6 and increases the reliability of the simulation codes, providing a unique set of tools that can accurately capture the coupled dynamics of real floating wind turbines. The experimental data are publicly available for researchers and code simulators, which is an important contribution for the offshore wind turbine modeller community.
The measured data were obtained in two test campaigns: one was performed at EHEEA Nantes, France on a semi-submersible concept and the second one was carried out at DHI, Denmark on a TLP. The use of these two concepts with different dynamics improves the quality of the validation. Two types of codes for performing coupled analysis of a floating wind turbine have been validated, namely aero-hydro-elastic integrated tools and high fidelity aerodynamic and hydrodynamic CFD. It is worth noticing that CFD is not dependent on prior calibration and measurements where accurately predicted. This kind of code has a high computational cost, but can be used for the tuning of lower complexity codes when no measured data are available.
An additional test campaign focused on submerged chain dynamics where performed for the validation of the dynamic model of the floating platform mooring system. The code showed a good prediction of the measurements even in highly dynamic situations.
The resulting tools are a comprehensive set of codes with very advanced capabilities for the analysis of the coupled dynamics of floating wind turbines and for the optimization of the design. These codes are also unique because they have been extensively validated against experimental measurements.
• Innovations of integrated methods for floating wind turbine control design
A methodology to optimize the main platform dimensions together with the control parameters has been developed. This is an innovative method, because it considers the control design from the very first steps of the design, improving the design process. Reduced models for the design of floating wind turbines have been created, including the main parameters of the floating wind turbine and a PI controller for the pitch and the rotor speed. The optimization of the system is done with adapted static and dynamic models through a stepwise narrowing of the design space according to the requirements of floating wind turbines. The integrated design results have been verified with detailed full FEM simulations in connection to critical load cases for controller testing, reaching a TRL 3. The designs (platform and controller) delivered by the integrated methodologies show improvements in platform stabilization and load alleviation. In addition, the integrated method for the design and optimization of the platform + controller system is applicable independently on the size of the WT, its class or conception: both horizontal and vertical axes WT can be analysed.
• Innovations of scaled testing methodologies for floating wind turbines
The correct design of experimental floating wind turbine models is a difficult procedure due to the interaction of the regarded system with two different environments – wind and waves – which require counteracting scaling procedures. While the hydrodynamic interactions can be correctly scaled using a constant ratio of the gravitational and inertial forces, aerodynamic interactions are usually scaled using a constant Reynolds number and thus maintaining the ratio between viscous and inertial forces. Both scaling methods cannot be satisfied in one and the same system.
For the scaling of aerodynamic loading during combined wave and wind scaled tests, a new methodology has been presented. The introduced method uses a ducted fan governed by a real time computation of the full rotor, coupled with the platform motions during the test. The so-called “Software-in-the-Loop” (SIL) approach enables the application of varying rotor thrust at the tower top of the floating model. Turbine control strategy, turbulent wind or wind gust can be modelled. This approach allows for time and cost savings in the preparation of the test campaign and is easily adaptable to changes in the scaled model. Another approach for modelling aerodynamic forces and coupled rotor dynamic effects during the scaled tests has been applied and verified. The method consists of the redesign of the scaled rotor for low Reynolds numbers which keeps roughly the tip-speed ratio and the Froude number, so that the dynamic response of the rotor is scaled adequately.
These methods have been applied to a semi-submersible and a TLP floating wind turbines design in scaled wave tank tests to verify its performance. The experimental results have been compared with computations and deliver a good correspondence.
Potential Impact:
Please see attached document for tables and figures!
IMPACT of INNOVATION on LCOE at COMPONENT AND Platform LEVEL
The comparison of the studied concepts in terms of the Performance Indicators (PIs) set for the INNWIND.EU project is presented in Table 7 and Table 8. The first table presents dimensional values of the PIs while the second shows percentage changes in comparison to the PI values of the 20 MW Reference Wind Turbine. Some promising combinations of the rotor/drive train/support structure concepts are also included in the tables. The essential part of the presented analysis is the relative reduction potential in terms of LCOE of the innovations envisaged and not the absolute cost numbers which are subjected to several hypotheses and simplifications.
Although the tables refer to 20 MW designs we have included for comparison the relevant PI values of the 10 MW RWT. Moving from 10 to 20 MW, it is noteworthy that there is a slight increase of the wind farm capacity factor due to less wake effects for the same installed capacity. There is also a significant reduction of O & M cost, from nearly €35/MWh to €28/MWh. Note that in the present analysis BoP (like turbine and support structure installation costs, cost of the electrical infrastructure and its efficiency, etc) and OPEX contribution to LCOE has been considered only approximately.
Table 7 Performance Indicators of the innovative concepts studied at 20MW Scale
Table 8 Percentage improvement of PIs in comparison to the 20 MW RWT
LIR concept. The new hybrid (glass-carbon) blade is lighter (16%) than the full-glass classically up-scaled 20 MW RWT blade, but it is also more expensive (7.3%). This is due to its longer span and the use of expensive carbon. Nevertheless, the overall increase in turbine CAPEX is 3.4% because in offshore wind the blades represent a small fraction of the turbine and support structure cost. Despite the higher CAPEX the larger, less loaded rotor, increases the turbine yield (capacity factor CF) by 7.5%. As stated earlier, a 4.5% comes from the LIR planform and another 3% from the dedicated low lift profiles. Even more important is the increase of the wind farm capacity factor by 9.7% due to the lower wake losses of LIR rotors. This is the highest value achieved among the different rotor concepts. Overall, LIR promises a 3.9% reduction of LCOE compared to the 20 MW RWT.
Bend-Twist Coupled Rotor. The conclusions here regarding the impact of the BTC concept on LCOE are similar to those extracted for 10 MW designs. No significant reduction in the cost of energy is expected maintaining the reference rotor diameter. Such designs may reduce the fatigue and the ultimate loading of the blade itself and, also, of the support structure having an indirect effect on CAPEX reduction which, however, is not taken into account here. The BTC blade is highly loaded (high Cp max design) and 8.5% lighter and cheaper than the RWT blade. The overall CAPEX and LCOE improvement is small (1%) leading to an LCOE reduction of 0.6%. Due to the assumptions made, we can consider that BTC improvements can be superimposed to LIR summing up their individual impacts to all PIs.
Magnetic Pseudo Direct Drive (PDD). The PDD generator with highly efficient power electronics promises a good LCOE performance (2 % lower than the reference) combined with a significant nacelle/drive train cost reduction of 7%. The nacelle mass is slightly increased by 4% while the capacity factor increases by 1.1 % which, along with the reduced CAPEX, is the reason of LCOE improvement. The improved capacity factor comes as a combination of the highly efficient 20 MW PDD generator (~ 98.5% at full load) and the highly efficient power electronics.
Bottom Mounted Offshore Support Structure An advanced design/manufacturing of the 20 MW RWT jacket is expected to reduce the original cost of ~14 M€ by 20%. Such a reduction would decrease the overall CAPEX by 4.3% translated to 3% reduction of the LCOE.
Advanced Control in 20 MW. An LCOE drop of 4% can be expected due to the mitigation of design loads of the turbine and its support structure offered by advanced control. In the present context advanced control was mainly targeted in reducing blade than support structure loads. Such a reduction can be used for increasing the rotor diameter and improve LCOE through better energy capturing. Alternatively, one can target on the reduction of the support structure fatigue loads which are the design drivers of the jacket. For jacket structures load reduction is nearly proportional to mass reduction. Since the offshore turbine support structure has a significant contribution to CAPEX, the reduction of the jacket fatigue loads through advanced control can also lead to an LCOE reduction of order 4% without increasing rotor diameter.
A simplified methodology for estimating the combined performance of the researched concepts would sum-up the percentage gains of the individual innovations as soon as they can be considered independently from each other. Some examples of such combinations are given in the lower parts of the PI Tables.
For bottom-mounted designs at INNWIND.EU’s 20 MW RWT conditions, the following expectations regarding LCOE reduction from new technology are presented:
• Low induction rotors with conventional inner structure 4.0%
• Aeroelastically tailored rotor 0.5%
• Drive train (reduced CAPEX, increased efficiency) 2.5%
• Advanced Jacket 3.0%
• Advanced control 4.0%
Expected Overall LCOE reduction 14.0%
Starting from the EWII LCOE value of €106.9/MWh corresponding to 5 MW turbine sizes, and considering more realistic O & M costs, this number dropped at €98.5/MWh (8.5% reduction) for the 10 MW RWT and €93.2/MWh (14.7% reduction) for the 20 MW wind turbine. These reductions were due to the larger turbine sizes, along with the use of a lightweight rotor with thick profiles, and the shift from traditional three-stage geared drive trains to medium speed drive while employing state of the art designed and manufactured jackets. An additional 14% reduction of LCOE can be expected for both 10 and 20 MW designs, thanks to the advanced concepts researched in INNWIND.EU getting LCOE close to €80/MWh for 20 MW turbines (and €85/MWh for 10 MW turbines).
Note that the above cost reduction potential only addresses LCOE contributors researched in the INNWIND.EU project. Innovations addressing the reduction of balance of plant costs, increasing the electrical efficiency of the power plant, suppressing the installation and operation and maintenance costs, along with the needed market boost, will further drive LCOE down by 2025 towards 50-60 €/MWh, rendering offshore wind energy a subsidy-free clean energy production technology.
A summary of key scientific findings is given below.
Rotors
➢ Large, high-tip speed rotors of moderate power density show a significant potential for LCOE reduction. This is partially due to the small contribution of the rotor CAPEX in offshore wind LCOE, but also facilitated by advanced control technology that mitigates higher loads from larger rotors.
➢ Special thick airfoil families optimized for the high Reynolds numbers of the MW machines can further improve turbine efficiency.
➢ Aero-elastically tailored blades with innovative inner structure, active aerodynamic control devices such as distributed flaps, combined with advanced wind measurement sensors (spinner anemometer or LiDAR for instance) and control strategies may significantly reduce turbine loading and therefore the weight and CAPEX of the load carrying components.
Drivetrain
➢ Reduction of tower top mass is not a significant factor in reducing the LCOE of bottom fixed large offshore wind turbines of 10 MW-20 MW capacities.
➢ Direct drive generators may improve the reliability and availability of offshore turbines. Superconducting generators may be an option for lightweight RNAs (when desired) with small dependence on rare earth materials, but appear to be extremely costly in present times (require to reduce the SC wire cost by 4 and increase its capacity by 4 to be competitive).
➢ Magnetic pseudo direct drives are competitive in terms of cost and performance, but vulnerable to magnetic material prices.
Substructure
➢ Jackets have a large cost reduction potential through design optimisation, use of cost-effective materials and improved –automated- manufacturing and installation practices.
➢ At 50m water depth, for 3-bladed 10MW turbines, 3P excitation of the support structure may compromise the turbine performance and fatigue life of the substructure, when jackets are used; to keep the support structure frequency low enough results in a jacket with a smaller footprint and higher mass and this is compounded if there are tower top mass reductions.
➢ For larger turbines nearing 20MW scale, there is no 3P excitation of the substructure due to the reduction in support structure frequencies at this size, hence savings in tower top mass are not penalized by rising support structure costs and the support structure design can be better optimized owing to less frequency constraint.
➢ Avoiding rotor-support structure resonance is rather impossible for efficient two-bladed rotors. Such rotors may only be combined with flexible sub-structures, such as the semi-floater at 50m-70m water depths.
➢ The optimal size of floating turbines is not yet mastered. A cost effective semi-submersible tripod floater has been designed and assessed for a 10MW turbine.
Overall the LCOE of the 20 MW offshore wind turbine was reduced by more than 30% as compared to the 2012 EWII basis of the 5 MW wind turbine. This evaluation of LCOE was primarily based on direct CAPEX savings and increase in AEP from the innovations combined with the larger capacities. Further savings in the LCOE due to OPEX reduction from lower fatigue loading and ease of maintenance is also expected.
List of Websites:
www.innwind.eu
INNWIND.EU was a project with a budget of nearly €20 million and with 28 partners. Its objectives include the conceptual design of beyond-state-of-the-art 10-20 MW offshore wind turbines and hardware demonstrators of their critical components. The project has developed several innovative rotor designs, drivetrain components, and fixed and floating substructures that greatly reduce the Levelized Cost of Energy (LCOE) for 10-20 MW offshore wind turbines. The essential part of the presented report is the relative reduction potential in terms of LCOE of the innovations envisaged and not the absolute cost numbers which are subjected to several hypotheses and simplifications. No technological “show-stoppers" for the development of wind turbines between 10-20 MW wind turbines were seen, but manufacturing processes for critical components such as the hub and blade bearings were not fully developed and needed to be matured.
An assessment of the entire wind turbine with different innovations has been made at the 10 MW and 20 MW scales by applying performance indicators and a comprehensive cost model developed in the project. Moving from conventional 5 MW offshore turbines with a reference LCoE value of 107 €/MWh to lightweight 10 MW-20 MW scale allowed a reduction in LCOE due to the larger turbine size along with the use of an efficient lightweight rotor and the shift from traditional three-stage geared drive trains to a medium speed drive. Significantly further reduction of LCOE can be expected for both 10 MW and 20 MW designs, due to the advanced concepts researched in INNWIND.EU getting LCOE close to 85 €/MWh for 10MW turbines and 80 €/MWh for 20MW turbines . This corresponded to an overall reduction of more than 30% in LCOE compared to the reference value of 107 €/MWh from to the conventional 5 MW turbines, thus bringing 20 MW offshore wind turbines closer to the market. Note that the above cost reduction potential only addressed LCOE contributors researched in the INNWIND.EU project (the turbine and its offshore support structure). Innovations addressing the reduction of balance of plant costs, increasing the electrical efficiency of the power plant, reducing the installation and operation and maintenance costs, along with the needed market boost, would further drive the LCOE down towards 50-60 €/MWh by 2025 in water depths near 50m, rendering offshore wind a subsidy-free clean energy production technology.
Some of the key promising innovations as developed in the project that reduce LCOE and increase efficiency included:
• The Low Induction Rotor (LIR), which constrains the extreme loads at the blade root and allows large rotor diameters with increased energy capture;
• Optimized aerodynamic and structural platforms of blades for reduced blade root fatigue and tower base fatigue;
• Active control with a focus on blade trailing edge flaps and blade trailing edge section morphing for load alleviation;
• High temperature superconducting generators to increase efficiency;
• Advanced optimal jacket designs at 50 m water depths to support wind turbines at 10 MW and 20 MW capacities;
• Guyed articulated sub structure at 50 m water depth that avoids resonant excitation for 2-bladed and 3-bladed rotors;
• Novel triple-spar semi-submersible floating wind turbine for 10 MW wind turbines.
Project Context and Objectives:
The overall objectives of the 5-year INNWIND.EU project was the high performance innovative design of a beyond-state-of-the-art 10-20MW offshore wind turbine and hardware demonstrators of some of the critical components. These ambitious primary objectives led to a set of secondary objectives, which were the specific innovations, new concepts, new technologies and proof of concepts at the sub system and turbine level.
The secondary project objectives delivered inputs to an iterated beyond-the-state-of-the-art wind turbine design, which fulfilled the goal of bringing the 10-20 MW offshore wind turbine to an acceptable performance level. The progress beyond the state of the art was envisaged as an integrated wind turbine concept with 1) a light weight rotor having a combination of adaptive characteristics from passive built-in geometrical and structural couplings between deformations and active distributed smart sensing and control, 2) an innovative, low-weight direct drive generator and 3) a standard mass-produced integrated tower and substructure that simplifies and unifies turbine structural dynamic characteristics at different water depths.
The project was divided into four scientific core work packages, each delivering different aspects of the overall program and supported by two non-core packages on dissemination/exploitation and project management. There was very close interaction and collaborations between the different work packages. There were three component-specific work packages (WP2-WP4) whose objectives were to deliver conceptual innovations and demonstrations of the core components of the 20MW wind turbine. Supporting these three component-specific work packages was an integrating work package (WP1) which was responsible for evaluating the innovations developed at the component level, integrating advanced controls for optimal performance, further innovations at the system level and integrating the conceptual designs of the innovative components into the turbine.
The exploitation of the innovations, focusing on accelerating time-to-the-market of the project deliverables, was explicitly dealt with along with the dissemination of the knowledge that was generated. The concepts were researched individually at the component level but also at the wind turbine system level. Their benefits were quantified through suitable performance indicators defined in WP1 and their market deployment opportunities were concretely established in a dedicated work package- (WP5).
Project Results:
Please see attached document for tables and figures!
The innovations developed for significantly reducing LCOE at the 10 MW and 20 MW capacities have been classified as Evolutionary (implying traditional designs), Radical (implying new types of designs) and Revolutionary (implying a complete change in design philosophy). A brief scientific description of the key innovations is given below.
The low induction rotor was developed with dedicated airfoils for the outer part of the blade which are designed for operation at a low lift coefficient of around 0.8 and whose aerodynamic characteristics were validated against wind tunnel measurements. Tools for the integrated design of aeroelastic tailoring with passive blade deflection couplings have been developed along with numerous solutions for an optimum combination of passive and active control. The TRL level of these rotor innovations have been moved from around 3 at the start of the project to TRL 5 at its closure. Innovative wind sensors such as a spinner anemometer and spinner LiDAR that measure high frequency wind time series either at a point on the spinner (anemometer) or at many points in front of the turbine (LiDAR) have been demonstrated. The Spinner anemometer allows ease of wind turbulence measurements as an input to controls enabling load mitigation or increasing energy capture.
High temperature superconducting generators with Magnesium DiBoride (MgB2) coils were investigated, along with coil testing which showed that the reliability of the coil windings had to improve to ensure low resistivity. The superconducting coil Yttrium Barium Copper Oxide (YBCO) was also tested, which though showing great potential, requires significant reductions in cost to enable commercial usage at 10-20 MW scales. Reducing the cost of high temperature superconducting wire by a factor of 4 and simultaneously increasing the critical current density by a factor of 4 is required for cost-effective generation for fixed base offshore wind turbines. The status of these superconducting generators is at a TRL of 4. This is because, even though the tower top weight may be reduced by 30% compared to a conventional drivetrain, this reduction in weight translates to insignificant benefits in LCOE due to the large cost fraction of the substructure, which remains relatively unchanged.
The PDD provides for magnetic gearing with a permanent magnet generator and has been tested in a lab at different scales of 5 kNm, 16 kNm and 200 kNm max torque values. It provides for high generation efficiencies of at least 95% at the small scales and is expected to reach 98% for the large generators. This increase in efficiency, along with moderate cost, is expected to contribute to about 4% lower LCOE. Its current status is at a TRL 4.
Fixed Substructure design at 50 m water depth is highly challenging for 10 MW wind turbines due to the 3P (3 times rotor speed) excitation of the sub structure for 3-bladed rotors and 2P (2 times rotor speed) excitation for 2-bladed rotors. An advanced optimal jacket was designed with a fatigue life of 25 years for the 10 MW turbine for 3-bladed rotors, while an innovative articulated joint sub structure was designed for the 2-bladed rotor. The TRL level of the jacket solution is relatively high, since jackets are already commercially used, while the TRL level of the articulated joint structure is at 3. At the 20 MW scale, it was found to be relatively easy to avoid rotor harmonic excitation, thereby enabling jacket substructure designs. Vertical axis (VAWT) and horizontal axis (HAWT) floating wind turbines have been designed for 10 MW capacities.
Technology roadmaps depicting the path to market for these innovations have been developed along with necessary standards to certify such wind turbines.
Size of commercial offshore turbines
When INNWIND.EU started in 2012, the maximum size of the commercial offshore turbines available in the market was 5-6 MW. Two characteristic members of this family were the GE 6 MW / 150.8m diameter Class IB Haliade and the Siemens 6 MW / 120m diameter turbines. Originally announced by Vestas as a 7 MW unit in 2011, the V164's has in the meantime been upgraded to 9+ MW. The first project using the V164, DONG Energy's Burbo Bank extension is currently under construction. In the meantime two additional 8MW turbines were put on the market, the ADWEN AD-180 is setting a new benchmark for blade length at 88.4 metres. The turbine has been selected for three of France's first six offshore projects, all of around 500 MW. Siemens has twice since upgraded its direct-drive offshore turbine to a power rating of 8 MW with an extended rotor diameter of 154 metres.
Increasing the turbine rating and size has an important impact on all main three LCOE drivers, CAPEX, OPEX and CF. A 2012 study conducted by BVG associates1 provided insight to the scaling laws ruling the different CAPEX contributors but also DECEX (decommissioning expenditure). The study considered a 500 MW offshore wind farm located at several distances from the nearest construction and operation port, comprising turbines of 4, 6 and 8 MW at different average water depths of between 25 and 45 m. The type C site of the BVG study is located 40 km from the port and has an average water depth of 45 m and average wind speed 9.7 m /s at 100 m above mean sea level. This is the site type closest to the external conditions of INNWIND.EU assumptions. The turbines at this site are supported by four-legged piled jackets with a separate tower. The results for a baseline wind farm are summarized in Table 1.
Table 1 CAPEX and DECEX dependence on the turbine rated power 16
From the individual CAPEX categories, turbine costs per MW are increasing with rated power while there is a decrease in the costs of support structure along with installation costs. This is in line with the project’s early finding that classical upscaling of a given turbine technology increases the turbine CAPEX by p3/2 while the BoP CAPEX by p1, where p is the nominal power ratio. Learning curve effect and innovation reduce both CAPEX exponents (3/2 and 1) considerably. Array cable costs seem turbine size independent. Decommissioning costs are also reducing for larger turbines, staying proportional to the installation costs (with a fixed ratio of 60%). Although decommissioning costs are quite high in absolute values, their contribution to LCOE is limited, since they are annualized with a small factor representing the fact that DECEX will not occur until the end of the project’s lifetime.
OPEX and turbine size
INNWIND.EU performed parametric calculations for a 500 MW wind farm using the O2M-Plus tool of DNV-GL. Introducing as free parameters the turbine rated power and reliability level we calculated direct O & M cost per MWh produced and the related wind farm availability losses. The through-life turbine reliability was modelled by means of a typical “bathtub” curve which addresses the three phases of the turbine service life: the early-life “bedding-in” period, the high reliability intermediate period and the end-of the-design-life period where failures due to wear and tear occur more frequently. Failures were classified into four categories depending on the severity of the required repair. A reference reliability level is that of a turbine suffering a typical number of failures per year (of all four categories mentioned above) where more than 60% of them simply require a visit for a manual restart. Better or worse reliability levels in our investigation are introduced by assuming a multiplier of the reference number of failures.
From the results of the O & M study it was seen that using larger turbines not only significantly reduces the O & M direct costs but also slightly increases the wind farm availability in benefit of the annual energy production. As expected, the increasing reliability of the wind turbines has positive effects on both availability and direct O & M costs.
Effect of upscaling on LCOE
Even classical up-scaling has a positive effect on the capacity factor of a large offshore wind farm. This effect was studied in the UPWIND Project where the (aerodynamic) wind farm capacity factor was calculated as a function of the WT rated power. The mean wind speed distribution used at the hub height of all designs was a Rayleigh with mean 10 m/s while the wind rose was assumed uniform direction-wise. Two wind farm sizes were considered, with 500 and 1000 MW installed capacity. The spacing of the turbines was 7D X 7D, leading to similar offshore area requirements for all turbine sizes.
The wind farm aerodynamic capacity factor (the production of all turbines including the wake effects) increases with the size of the single turbine. Going from 5 to 10 MW, we have a nearly linear increase of almost 2.5 percentage units, with an additional increase of 2.5 units from 10 to 20 MW. This effect is attributed to the reduction of wake effects due to the smaller number of turbines in the wind farm when the rated power of the individuals increases. This capacity factor improvement is not related to better wind resource available at larger distances from the shore (and deeper waters) or going at larger hub heights. These are additional factors that might further increase the farm capacity and are (indirectly) linked to the single turbine size.
Figure.1 Turbine size influence to LCOE and its main drivers. An indicative plot. The actual turbine size achieving minimum LCOE depends on the actual site conditions and, especially, the sea depth.
The synthesis of the above suggests that larger turbines increase the turbine CAPEX and the wind farm capacity factor while decreasing the BoP CAPEX, the OPEX and the DECEX. Given the state of the technology and the wind resource, there will always be an optimal turbine size that minimizes LCOE and which is water depth dependent. This optimal size increases with the depth. This is further illustrated in Figure.1. Note that the optimal size of 10 MW suggested by the figure is only indicative and the actual optimal size depends on the site conditions and the sea depth in particular.
Clearly, a quantitative decision on the optimal turbine size for a specific offshore site which also accounts for the technology evolution and the potential that innovation adds to LCOE reduction should be based on a proper cost model integrated to the LCOE calculator. Such a cost (and mass) model has been developed in INNWIND.EU to assess the innovative designs at the components and system level researched in the project. The model: i) is developed at the sub-components level, ii) is based on key turbine design parameters (Rated Power, Diameter, Hub-height, Rated Torque etc.) and operating conditions, (wind class, etc.), iii) is suitable and flexible enough for up-scaling studies too, taking account of technology learning curves, iv) account of variations in raw materials pricing, inflation and currency fluctuations so that cost data from different periods and markets can be synchronized, v) explores previous experience from earlier cost modelling works in WINDPACT (USA) and UPWIND (EU). The Input / Output section of the cost model is shown in Figure 2.
It must be clarified that the model was built aiming at the turbine and its support structure technology evaluation assessment and not for providing exact values for LCOE. This is because its BoP CAPEX part (installation costs, electrical infrastructure etc) and the OPEX entries are very roughly taken into account. To this end, the model results are valuable in the relative sense only, for evaluating the potential of INNWIND.EU research themes to LCOE reduction.
Figure 2 The I/O section of the INNWIND.EU cost model
External conditions for designing 10-20 MW offshore wind turbines
The establishment of a database that provides information on the wind speed and turbulence at higher atmospheres (above 150 m) and its connection with wave conditions is essential for designing large offshore wind turbines in the 10-20 MW range. There are several databases which contain wind parameter measurements for various near- and offshore sites across Europe. The locations of buoy measurements (black/white points) and met masts (red and yellow markers) in the North and Baltic Seas are shown in Figure 3.
Figure 3 Map of measurement locations in the North and Baltic seas.
One of the available datasets one, the FINO 3, has been further analysed to suit the project needs. The main argument for selecting FINO 3 is that both met mast and LiDAR data was available for the same time period. So, the LiDAR measurements can be evaluated up to a height of 100 m with reference to the data of the meteorological mast. This allows for a reliable investigation of wind conditions in tall atmospheres up to the maximum measuring height of the LiDAR system at 160 m. Furthermore, at FINO 3 there are available measurements of wave parameters from 2009.
In parallel to the FINO 3 dataset analysis, the project derived wind profile data up to 310 m height above mean sea level from high-resolution mesoscale simulations performed with the Weather Research and Forecasting (WRF) model. Simulations for 2007 and 2011 have been carried out for three nested domains with a grid resolution in the finest domain of 2 x 2 km² (Fig). The values of eight parameters – wind speed, wind direction, thermal stability parameters (inverse Obukhov length), pressure, temperature, humidity, turbulent kinetic energy and turbulence intensity – are given in the delivered data set for different heights (every 20 m from 30 m up to 310 m) as 10 minute time series’. Additionally, the time series for the following variables are given: the planetary boundary layer height, the sea surface roughness height, the wind shear parameter alpha and the sea surface skin temperature. To optimize the accuracy, test simulations with four different parameterization schemes for the planetary boundary layer have been carried out and have been compared to measured data of the met masts FINO1 and FINO3. The results underline the importance of atmospheric thermal stratification for the vertical profiles of the turbine design parameters.
Reference and Evolutionary Designs
Reference Turbines
Typical examples of evolutionary architecture are the 10 and 20 MW Reference turbines. Here the main issue was the upscaling to larger turbine size using mature technologies, taking advantage of the larger size whenever possible. As discussed earlier, the size of the turbine in itself is an important parameter for minimizing LCOE in deep offshore.
The two reference turbines have a classical 3-bladed, upwind, max power coefficient (Cpmax)-driven rotor design of high specific power (W/m2). Their all-glass blades are pre-bent, using thicker than usual profiles for improved structural efficiency without compromising their aerodynamic efficiency. This is a Reynolds-driven benefit which comes with very large turbines, as thicker airfoils operating at very high Reynolds can have similar performance with thinner operating at lower Reynolds levels.
The 10 MW RWT was designed as an IEC Class IA turbine to withstand increased fatigue loads mainly due to wake effects, since ambient turbulence offshore is well below subclass C. Fatigue is the design driver of some of the expensive subcomponents of offshore turbines, such as the supporting jacket. Given the fact that wake effects are reduced when larger turbines are deployed for a fixed wind farm capacity, we decided to design the 20 MW RWT as an IEC Class IC turbine.
The two reference turbines have a medium-speed drive train with gearing ratio ~1:50 and permanent magnets generator. For multi-MW turbines this selection performs well in terms of reliability and cost. Full range power conversion is possible.
A standard PI variable speed collective pitch controller is used in both turbines. Due to the 3-P resonance discussed above, the 10 MW RWT variable speed controller applies an exclusion zone at relatively low wind speeds. This has been avoided for the 20 MW RWT by slightly increasing its tip-speed-ratio and by using a taller tower that softens the first system’s global eigen-frequency.
The reference jackets are assumed classical designs in terms of architecture, materials used and manufacturing procedures. Their legs are piled to the seabed.
Basic data and technical specifications for the 10 and 20 MW Reference Wind Turbines are given in Table 2.
Table 2 Basic turbine data for the 10 and 20 MW RWT
Evolutionary Architectures
Τhe main features of the reference designs are maintained along with the reference drive trains. Innovative solutions are sought for the 3-bladed upwind rotors to improve their energy capture and structural efficiency. Given the fact that the rotors are shaping the AEP while their contribution to the overall offshore turbine CAPEX is relatively small, it appears that a larger (and more expensive) rotor than the reference may significantly reduce LCOE by increasing energy capture. Nevertheless, the extra yield has to come without overloading the downstream components, increasing the overall turbine CAPEX.
The project explores several ways for increasing the rotor size (lower specific power designs) while maintaining the system’s loads at their reference levels. One way is by optimizing the induction level in the aerodynamic design, aiming to achieve the best trade-off between power production and hub-loading. The optimization leads to a Low Induction Rotor (LIR) which can be best realized through a low solidity blade planform combined with low lift airfoils. Another, complementary, way is to apply passive or active load mitigation techniques, possibly combined with advanced control. Regarding passive loads alleviation, INNWIND.EU put a lot of effort in bend-twist coupling (BTC) technology. In BTC designs, when the blade bends out of plane, it simultaneously twists passively nose down, reducing aerodynamic loading. This is accomplished either geometrically, by back sweeping the blades, or through the structural design by exploring the anisotropic properties of the composite materials or properly placing the shear-centre of the blade sections in respect to the twisting axis. Advanced turbine control based combining cyclic and individual pitch control is also sought in evolutionary designs. Innovative blade structure designs are sought, using full carbon or hybrid glass-carbon elements, for increasing the stiffness and adjusting the natural frequencies of the longer blades as well as enhancing their local buckling resistance properties.
Advanced jacket designs for 10 MW wind turbines require that the support structure fundamental frequencies are away from rotation excitation, that is for a 3-blade rotor, away from 3P and 6P excitations. Such a design is often very difficult to achieve due to the stiff nature of the jacket structure. The reference jacket for the 10 MW reference wind turbine is a traditional design which has 3P excitation and therefore low fatigue life. The advanced jacket designs created in this project allow for an integrated design approach so that correct tubular member diameter and thickness is applied at joints so as to possess sufficient fatigue resistance. This provides a jacket design as given in Table 3. Furthermore, an effective optimization of the jacket structure to reduce the natural frequencies below the 3P excitation zone has also been made so that the design meets a target lifetime while still being cost-effective. The optimal jacket design configuration is provided in Table 4.
Table 3 Advanced Detailed Design Jacket parameters for the 10 MW RWT
Table 4 Optimized modular jacket parameters for the 10 MW RWT
Basic data and technical specifications for the 10 and 20 MW evolutionary designs are given in Table 5
Table 5 Basic turbine data for the 10 and 20 MW evolutionary designs: 285 m 20 MW (left), 178 m 10 MW (right)
New Platforms
Two platforms are discussed in this section. The first includes two-bladed designs, upwind and downwind, combined with a soft semi-floater in order to circumvent 2P-4P excitation consequences. The second platform addresses three-bladed upwind designs which, further to the innovations introduced earlier, explore possibilities for weight and cost reduction offered by non-conventional direct drive generators, superconducting and magnetic pseudo-direct drive (PDD), for bottom-fixed and floating designs.
Two-bladed upwind/downwind rotors with semi-floater
For two-bladed rotors, it is very important that there is no excitation of the support structure from 2P and 4P harmonics. Given that the 10 MW wind turbine has a rated RPM close to 9.6 the 2P frequency region is from 0.2 Hz. To 0.32 Hz, which band will result in resonant excitations for the jacket designs shown in Table 3.2 and Table 3.3. To avoid such excitation, a support structure with drastically reduced eigen-frequency is needed without moving to a floating solution since the water depth is still 50 m.
Figure 4: A two-bladed upwind 10 MW turbine placed on a semi-floater sub structure
The semi-floater concept provides such a viable solution for a 2-bladed rotor. It is a combination of the classic monopile substructure and the traditional spar-buoy floater. It is illustrated in Figure 4, where the concept consists of three main constituents: an articulated joint at the soil bed, the mooring system, and the floating system. The floating system is made of a buoyant chamber and the main cylindrical substructure. The buoyant chamber was developed as an ellipsoid of 30.0 m height and 11.0 m diameter cast out of glass fibre. The buoyant force for platform stability is provided by the buoyant chamber placed near sea level and from the buoyant force generated by the cylinder. Concrete ballast is attached to the base of the cylinder to lower its centre of gravity and the weight of the ballast is calibrated to ensure that the net steady vertical force is in equilibrium.
The substructure is connected to the sea-bed using an articulated (or universal) joint embedded into a reinforced concrete base. The reinforced concrete base is a short cylinder whose upper face has a hemispherical cavity. The reinforced concrete base works like a gravity based foundation providing fixity to the platform. The other contact points to the soil are the mooring lines anchorages. The catenary mooring lines are connected to the sub structure with delta connections, which have their fairleads attached to the buoyant chamber. The delta connection aims at providing torsion resistant effect to counter the turbine yaw motions.
Table 6: Masses and System level frequencies of the 2-bladed rotor on a semi-floater
Three-bladed upwind rotors with non-conventional direct drive, bottom-fixed or floating
Further to the evolutionary innovations introduced earlier, we here exploit possibilities for further loads reduction by deploying distributed flaps along the blades span. The optimal position and size, the integration in the blade structure, the activation techniques and the distributed control of such flaps are researched in the project. We also seek combination with advanced feedforward control concepts, fed by wind data from LiDAR or spinner anemometer. The development of control algorithms for innovative turbines (2-bladed rotor, 3 bladed pseudo magnetic direct drive, low induction rotor etc) at the 10 MW and 20 MW has been made with aeroelastic simulations which show their loads reduction potential and impact on LCOE. Two new wind sensors were investigated: the Spinner anemometer and the Spinner LiDAR. The spinner anemometer comprises 3 sonics (ultrasonic anemometers) which measure the instantaneous directional wind velocity at three positions on the spinner of the turbine. The Spinner LiDAR is a remote-sensing instrument for scanning the wind inflow at several points in a plane ahead of the wind turbine
Figure 5: Deploying flaps along the blade span for load alleviation at higher wind speeds or increase power capture at low mean wind speeds.
The demonstration of innovative adaptive blade flap control has been demonstrated in a wind tunnel and under free wind turbulence on a rotating test rig. The developed flap control was subsequently simulated on a Suzlon S111 wind turbine which showed 1.7% increase in AEP or blade root fatigue reduction of 9%.
Magnetic and superconducting drives are researched, along with dedicated power electronics that allow full range power conversion and their integration into the nacelle design. The magnetic pseudo direct-drive (PDD) generator is realizing the possibility of applying magnetic gears in wind turbines. In a PDD generator, the magnetic gear and the electrical generator are mechanically as well as magnetically integrated. Prototypes of PDD machines with a continuous torque output of 4 kNm to ~16 kNm have been designed, manufactured and tested. A 200kNm wind turbine generator is currently being manufactured and will be tested in 2018.
Superconducting coils in wind generators is a promising technology, because the high magnetic flux and current densities compared to conventional generators enable a considerable reduction of the generator weight and volume at large power levels which might be of particular importance for floating turbines. Additionally superconducting direct drive generators will have no or a 100 times smaller dependence on Rare Earth element metals compared to permanent magnet direct drive generators. In INNWIND.EU the use of different superconducting materials, with main focus on MgB2 and YBa2Cu3O7 along with their cryogenic cooling systems, has been considered and tested.
Design of King-Pin forward-mounted generator
The resulting designs for 10 MW superconducting direct drive and Pseudo Direct Drive are shown in Fig. 6 and Fig. 7 respectively.
To reduce the risk of large generator air gap deviations introduced by deflections of the main load carrying components, a separate generator bearing was introduced with the purpose to isolate the generator from these deflections. The rotor of the generator is connected to the hub via a torque-only connection.
Figure 6: Illustration of the 10 MW MgB2 superconducting direct drive generator with a diameter of Dgen = 8.4 m, a length of Lgen = 1.3 m and a weight of mgen = 286 ton mounted in front of turbine blades of the King-Pin nacelle (top) and behind the turbine blades(bottom).Both configurations seems possible to be scaled to power ratings up to 20 MW.
Figure 7: Illustration of 10 MW Pseudo Direct Drive generator with a diameter Dgen = 6.0m Lgen = 1.7m and a weight of mgen ~ 150 ton mounted in front of the turbine blades of the king-pin nacelle.
Innovative concepts researched regarding aerodynamic design
Low induction rotors
10 and 20 MW Low Induction Rotors have been designed and their performance and loading have been assessed against the reference wind turbines. Since the design procedures followed for the two turbine sizes are similar, we shall restrict this presentation to the 20 MW LIR.
Taking advantage of the higher Reynolds number at which a 20 MW turbine operates compared to a 10 MW one, new low lift 26% thick airfoils have been designed for the outer span of the 20 MW LIR blade with an aim toward increasing its structural performance without compromising power production. The assessment of the aerodynamic performance of the designed airfoils using high fidelity CFD-based tools demonstrated that such a 26% thick airfoil operating on a 20 MW rotor can indeed have similar performance with a 24% thick airfoil operating on a 10 MW rotor.
Using the CFD polars of the 26% airfoil the planform of a 20 MW LIR Rotor was redesigned. The LIR was optimized for increased annual energy capture constraining its blade root (mean) flap-bending loads. The optimization also resulted in a new rotational speed schedule, respecting the variable speed range of the 20 MW RWT.
The power performance of the 20 MW LIR versus the 20 MW RWT was then assessed using higher fidelity tools. Both CFD-RANS with free transition and a free-wake vortex method was used for this. Comparing LIR against the 20 MW RWT rotor we note that LIR blades are 13% longer and 7.6% heavier than the RWT. LIR increase the individual turbine capacity factor by 7.5% and the wind farm capacity factor by 9.8%. Overall, the anticipated reduction in LCoE in comparison to the 20 MW RWT is about 4%.
Two-bladed rotors
The two-bladed, downwind rotor concept has been explored from the beginning of the INNWIND.EU project because several studies in the past have shown that the concept might be competitive compared with the three-bladed rotor. Low frequency noise (LFN) from the downwind rotor due to the blade passage of the tower wake is known to be a major problem for such turbines. However for the off-shore application considered here it is not expected that LFN should cause problems.
A baseline 10 MW two-bladed RWT version derived by simple scaling rules from the three-bladed INNWIND.EU RWT was presented at an early stage in the project. The major influence on the cost is the saving of one blade and thus a decreased tower top mass. However, a major problem was considerably increased tower loading caused by the interaction of the 2p rotor frequency with the frequency of the 1st tower mode of vibration.
One innovative solution for offshore application is the use of the semi-floater supporting concept, as the 1st tower frequency for that design is much lower than a bottom-fixed structure with the tower on top of this.
In another design and optimization study of the two-bladed rotor, the inclusion of design parameters enabling passive load alleviation by a strong bend twist coupling (BTC) showed very promising results. The BTC is achieved by a different chordwise position of the spar caps on the suction and pressure side of the blade and by a forward movement of the elastic axis. All these characteristics originate from the numerical optimization and were not pre-determined. The most promising design is a blade with an 8% increase in blade length, a more slender planform and a reduction of about 8% in blade weight from 37.8 to 33.7 tons when compared with the two-bladed RWT. The AEP increases with 8% and the loads are within the envelope of the baseline. The tower clearance is kept within the limit by 2.5 degrees pre-cone. In another design, the blade was stretched by 12% with an 11.9% increase in AEP. With a pre-cone of 4.5 degrees, the tower clearance was kept within the limit. In this case, some of the loads exceeded the envelope. However, it might be that advanced control with IPC or flaps could bring the loads back within the envelope.
As concluding findings for the 2B rotor investigations, it can be stated that such a rotor has to be mounted on a flexible tower like the semi-floater design mentioned above in order to avoid the 2p excitation problem.
New airfoils
The rotor concept studies of INNWIND.EU showed the need for dedicated airfoil designs to realize the full potential of the new rotor designs. One of the overall tendencies in the new rotor designs is the use of more slender and longer blades. Slender blades can be achieved by using thicker airfoils which means that the chord can be decreased for the same load on the blade.
One study has focused on the design of a 30% thick airfoil for outboard application on a blade where a 24% airfoil is used on the 10 MW RWT. The new airfoil contour is shown to the left in Figure 8 together with the two FFA airfoils that it will replace. To the right in the same figure it can be seen that the new 30% airfoil has a lift-to-drag ratio that is almost the same as for the 24% airfoil it will replace. However, the detailed analysis of the airfoil characteristics has shown that the large roughness sensitivity of the new airfoil results in a larger penalty in terms of power coefficient decrease than with the FFA 24% airfoil.
Figure 8: The new 30% airfoil design in comparison with the two FFA airfoils (Left) and the lift-to-drag ratio for turbulent and transitional flow (Right)
LIR rotor designs, in particular, require dedicated airfoil designs as the low loading giving the low induction is achieved by operation at a low design lift, typically around 0.8. A complete airfoil family with a low lift 24% airfoil for the outboard part of the blade was designed for the 10 MW LIR. For the 20 MW LIR, the increase in Reynolds number made it possible to increase the thickness to 26% for a new low lift airfoil to be used outboard on the blade, Figure 9 left. The improved operational conditions at the higher Reynolds number made it possible to design the 26% airfoil so it has almost the same lift-to-drag ratio as the 24% airfoil used on the 10 MW rotor, Figure 9 right.
Figure 9: To the left, the new 26% (10-90) low lift airfoil for use on the outboard part of the 20 MW LIR rotor. To the right, the lift-to-drag characteristics.
Innovative concepts researched in structural design
Passive control through Bend-Twist-Coupling (BTC). Alternative ways of BTC.
Ten different structural solutions were presented with the aim to achieve passive load alleviation while maintaining the power output, reduce the cost of the wind turbine components, and thereupon reduce the cost of wind energy generation. In one design the structure of the blade was optimised, running the complete design circle to achieve a solution complying with all design requirements, including fatigue, while introducing passive load reduction through the incorporation of bend-twisting coupling. The optimal solutions when changing the angle in the spar cap (SC) of 3, 4, 5, 6 and 7deg and in the skin (SK) of 5, 10 and 15deg, are presented in Figure 10. The same figure shows the reduction of the LCOE with respect to the RWT. A 3% mass reduction was achieved with about 1% increase in annual energy production, leading to an approximate 1% reduction of the levelised cost of energy. Nevertheless, the effect of the load reduction achieved on other wind turbine components was not taken into account, leading to conservative results regarding the gain on LCOE.
In another part of the work seven different solutions were investigated, combining the concept of bend-twist coupling, swept blade, and single shear web (reduced torsional stiffness). The combination of all three passive control strategies in the same reference blade was found effective mainly with respect to the blade root flap-wise extreme and fatigue moments. The concept of bend-twist coupled blade was investigated from different perspectives. One solution studied is based on the same concept of introducing bend-twist couplings, yet in this case, the angle of the fibre orientation for the drive of the coupling is not constant along the blade length, but rather varies with the radial position, see Figure 4.7. Optimized coupling behaviour is achieved in this way, yet at a higher manufacturing cost. By combining tow-steered fibres and a variation of the spar geometry and orientation, the new blade design produced an induced elastic twist which better approximates the optimum twist of the blade across its entire operating range. At the rated wind speed, the concept adaptive design reduced the amplitude in flapwise bending oscillations by 16% compared to the reference blade.
Finally, focus was on the development of a tool that enables accurate prediction of the blade response in the presence of bend-twist coupling terms. The incorporation of the bend-twist coupling is performed by suitably adjusting the fibre orientation of the composite material at the spar cap. Using this tool the blade is then designed to achieve load alleviation in comparison to the reference blade design.
Figure 10: LCOE reduction compared to RWT for optimal solutions (Skin Angle (SK) 5, 10 and 15deg, Spar Cap Angle (SC) 3, 4, 5, 6 and 7deg).
Figure 11: A schematic design of the fibre path along the curved blade planform representative of the concept used to investigate bend twist coupling.
Innovations for Support Structures
New innovations for future cost-effective, mass-producible designs are investigated, such as new foundation types, soil-structure-interaction of large piles or suction buckets, innovative transition piece designs or designs using hybrid materials which have never been employed before in wind energy. In addition, design integration using jacket-specific controls and innovative fabrication and installation processes shall complete the overall cost saving potentials. Figure 12 illustrates the considered innovations for the fixed base support structure which are summarised as follows.
Figure 12: Considered innovations for the support structures of large offshore wind turbines
• Innovations of load mitigation
Novel 10-20 MW Offshore wind turbines need to have a lightweight design to reduce the material cost. The increased size of the rotor and tower height results in magnified vibration amplitudes which need to be reduced. In addition, the offshore wind turbine dynamics need to be reconsidered when upscaling the substructure design.
In principle, load mitigation strategies are classified under two main categories: control concepts and damping devices. Three dedicated load mitigation concepts are studied on the operational control level: speed exclusion zones, soft-cut out, and peak shaving.
Firstly, active load reduction technology has been implemented for the reduction of the thrust around rated wind speed by the so-called Peak Shaver. Also, a speed exclusion window to avoid resonances during operation is considered for the 10 MW design. Secondly, passive damping systems have been analysed for the support structure. The considered damping systems include the passive Tuned Vibration Absorbers (TVA), Tunde Mass Dampers (TMD) and Viscous Fluid Dampers (VFD) for the 10 MW wind turbine class. It has been shown that the passive dampers are more effective in a sideways direction while the effectiveness of these devices is marginal in fore-aft direction.
For the 20 MW wind turbine class, the application of passive TMD will become less effective and the integration into the available space in the tower top will become more difficult. Therefore, the employment of semi-active or active damping systems is becoming more attractive. Semi-active dampers operate in a broad frequency bandwidth and are more effective in both directions. The numerical modelling of a semi-active magnetorheological (MR) damper is implemented and integrated in both the jacket and the tower structure to mitigate loads. The study reveals the potential of MR dampers to alleviate fatigue damage in all conditions. Further investigations are required to propose an optimal configuration for reliable full-scale implementation in the field.
• Innovation of hybrid materials
The sandwich material for a monopile, as well as the chords and braces of a jacket sub-substructure, have never been used in the offshore wind industry. Sandwich tubes are rod-like structural components consisting of three components: two relatively thin steel tubes and a core made of ultra-high performance concrete (UHPC). Due to its high strength, UHPC is an appropriate solution to save material and weight. The project studied the numerical and experimental investigation of sandwich tubes, as well as the development of the pre-design methods for sandwich tubes and their application on the chords and braces of the jacket structure. The bearing capacity of sandwich tubes under combined axial loading and bending moments was also investigated.
Taking the basic geometric parameters into account, variations of the member parameters, such as the ratio of steel to sandwich material, were investigated and the effect on natural frequencies compared to the reference structure was evaluated. It should be noted that the current TRL of sandwich tubes for jacket sub-structures is 3. The estimations show that if the necessary manufacturing time is summed up, the steel tubes for hybrid jackets allow a saving of up to 50% in time in relation to the thicker common steel tubes.
The second innovation considered is the potential of adhesively bonding instead of welding. In this regard, the considered innovation is to adhesively bond the trusses connected to the main pillars in the jacket substructure connections. The main potential benefit is that an adhesively bonded connection can be less fatigue-sensitive than a welded connection. On the other hand, potential disadvantages are issues during installation (can the adhesive be applied in a controlled manner?), sensitivity to temperature and humidity influences during operation, as well as sensitivity to multi-axial strains during operation.
• Innovation of vibro-driven piles
Vibratory-driven (VD) technology, as an alternative to impact-driven (ID) technology, has the potential to significantly reduce the costs associated with installing piled foundation for offshore wind turbines. The economic advantages of this technology include: the absence of noise mitigation systems, the reduction of the installation time and the reduction of the fatigue load in the pile steel otherwise induced by impact hammers.
The results of an experimental campaign including two large-scale impact-driven piles have been presented and interpreted by using CPT methods. Soil profile and steel price were assumed and are regarded to be rather realistic values. The analysis carried out with loads referring to a 10 MW wind turbine reveals that, on the basis of the tests carried out, the price difference between impact-driven and vibro-drive piles is around €38k when adopting UWA-05, and around €47k when adopting ICP-05.
• Innovations of suction buckets
Jacket structures are usually founded on pre-installed piles. However, bucket foundations are an option that can decrease the overall cost and allow alternative installation strategies. Since wind turbines are dynamically sensitive structures, where stiffness requirements must be satisfied, an alternative design allowing increasing stiffness is the multi-bucket configuration, wherein loading response changes significantly with respect to a mono bucket. The following work is focused on loading of a multi-bucket foundation. The overturning bending moment is mainly transferred into vertical compression and tension loads in the buckets. For these reasons, it is important to understand the behaviour under tensile loading and improve the stiffness of the foundation so more correct design methods can be established. Experimental results of vertical axial loading cyclic tests of bucket foundation are conducted. The drained cyclic response was examined by simulating the long-term cyclic loading conditions for an offshore structure under the normal serviceability performance. Cyclic degradation was tested applying post-cyclic pull-out loads on the bucket foundation model.
• Innovations for floating wind turbines
Four different innovative floating concepts supporting the INNWIND.EU 10 MW reference wind turbine have been designed at a conceptual level to evaluate the advantages and disadvantages of the different designs.
A semi-floater design as described earlier is proposed combining the strengths of floating structures with those of bottom-fixed ones. This is a solution well suited for intermediate water depths (50-70m) where fixed sub structures may be too expensive and floating sub structures may not be used.
Two different torus-shape structures in concrete have been developed. The torus has the advantage of a reduced draft for an increased flexibility to the water depth and it significantly reduces the wave excitation due to the “moonpool” feature and the steel construction around water level, where wave forces are high. One of the designs has two dynamically linked floating bodies to reduce excitation from waves. The use of concrete as material can drastically reduce the cost of these designs.
Finally, there is an asymmetric semi-submersible floater which aims at reducing the need of lattice construction elements. The substructure is composed of three cylinders, connected by pontoons to form a geometrically simple shape. The function of the pontoons is not only structural, but also hydrodynamic: the pontoons work as heave plates to damp the motion of the offshore wind turbine. In addition, the wind turbine is mounted on one of the cylinders, instead of building a central structure to hold it in the platform centre. This allows for the simplification of the structure and reduction in manufacturing costs.The analysis of these concepts indicates that the semisubmersible design has good dynamic behaviour, together with manufacturing and installation advantages. On the other hand, the use of concrete can potentially reduce the cost of the platforms.
Different simulation tools for floating wind turbines with diverse complexity levels have been developed within the project. These tools can be applied at different stages of the design process, from conceptual design to a detailed analysis. The new features developed include coupled aeroelastic models considering the platform flexibility or advanced aerodynamic approaches such as the free vortex method. CFD codes have been also developed, including movable meshes that allow for the capturing of non-linear interaction between the fluid and the structure. This has particular importance in the analysis of cases with rough sea states. Other non-linear effects included in the existing integrated tools are mooring dynamics or fully non-linear wave models. These effects have particular importance in the analysis of TLP platform concepts.
The simulation tools developed in this project have been validated against experimental data. This leads the tools to a TRL of 6 and increases the reliability of the simulation codes, providing a unique set of tools that can accurately capture the coupled dynamics of real floating wind turbines. The experimental data are publicly available for researchers and code simulators, which is an important contribution for the offshore wind turbine modeller community.
The measured data were obtained in two test campaigns: one was performed at EHEEA Nantes, France on a semi-submersible concept and the second one was carried out at DHI, Denmark on a TLP. The use of these two concepts with different dynamics improves the quality of the validation. Two types of codes for performing coupled analysis of a floating wind turbine have been validated, namely aero-hydro-elastic integrated tools and high fidelity aerodynamic and hydrodynamic CFD. It is worth noticing that CFD is not dependent on prior calibration and measurements where accurately predicted. This kind of code has a high computational cost, but can be used for the tuning of lower complexity codes when no measured data are available.
An additional test campaign focused on submerged chain dynamics where performed for the validation of the dynamic model of the floating platform mooring system. The code showed a good prediction of the measurements even in highly dynamic situations.
The resulting tools are a comprehensive set of codes with very advanced capabilities for the analysis of the coupled dynamics of floating wind turbines and for the optimization of the design. These codes are also unique because they have been extensively validated against experimental measurements.
• Innovations of integrated methods for floating wind turbine control design
A methodology to optimize the main platform dimensions together with the control parameters has been developed. This is an innovative method, because it considers the control design from the very first steps of the design, improving the design process. Reduced models for the design of floating wind turbines have been created, including the main parameters of the floating wind turbine and a PI controller for the pitch and the rotor speed. The optimization of the system is done with adapted static and dynamic models through a stepwise narrowing of the design space according to the requirements of floating wind turbines. The integrated design results have been verified with detailed full FEM simulations in connection to critical load cases for controller testing, reaching a TRL 3. The designs (platform and controller) delivered by the integrated methodologies show improvements in platform stabilization and load alleviation. In addition, the integrated method for the design and optimization of the platform + controller system is applicable independently on the size of the WT, its class or conception: both horizontal and vertical axes WT can be analysed.
• Innovations of scaled testing methodologies for floating wind turbines
The correct design of experimental floating wind turbine models is a difficult procedure due to the interaction of the regarded system with two different environments – wind and waves – which require counteracting scaling procedures. While the hydrodynamic interactions can be correctly scaled using a constant ratio of the gravitational and inertial forces, aerodynamic interactions are usually scaled using a constant Reynolds number and thus maintaining the ratio between viscous and inertial forces. Both scaling methods cannot be satisfied in one and the same system.
For the scaling of aerodynamic loading during combined wave and wind scaled tests, a new methodology has been presented. The introduced method uses a ducted fan governed by a real time computation of the full rotor, coupled with the platform motions during the test. The so-called “Software-in-the-Loop” (SIL) approach enables the application of varying rotor thrust at the tower top of the floating model. Turbine control strategy, turbulent wind or wind gust can be modelled. This approach allows for time and cost savings in the preparation of the test campaign and is easily adaptable to changes in the scaled model. Another approach for modelling aerodynamic forces and coupled rotor dynamic effects during the scaled tests has been applied and verified. The method consists of the redesign of the scaled rotor for low Reynolds numbers which keeps roughly the tip-speed ratio and the Froude number, so that the dynamic response of the rotor is scaled adequately.
These methods have been applied to a semi-submersible and a TLP floating wind turbines design in scaled wave tank tests to verify its performance. The experimental results have been compared with computations and deliver a good correspondence.
Potential Impact:
Please see attached document for tables and figures!
IMPACT of INNOVATION on LCOE at COMPONENT AND Platform LEVEL
The comparison of the studied concepts in terms of the Performance Indicators (PIs) set for the INNWIND.EU project is presented in Table 7 and Table 8. The first table presents dimensional values of the PIs while the second shows percentage changes in comparison to the PI values of the 20 MW Reference Wind Turbine. Some promising combinations of the rotor/drive train/support structure concepts are also included in the tables. The essential part of the presented analysis is the relative reduction potential in terms of LCOE of the innovations envisaged and not the absolute cost numbers which are subjected to several hypotheses and simplifications.
Although the tables refer to 20 MW designs we have included for comparison the relevant PI values of the 10 MW RWT. Moving from 10 to 20 MW, it is noteworthy that there is a slight increase of the wind farm capacity factor due to less wake effects for the same installed capacity. There is also a significant reduction of O & M cost, from nearly €35/MWh to €28/MWh. Note that in the present analysis BoP (like turbine and support structure installation costs, cost of the electrical infrastructure and its efficiency, etc) and OPEX contribution to LCOE has been considered only approximately.
Table 7 Performance Indicators of the innovative concepts studied at 20MW Scale
Table 8 Percentage improvement of PIs in comparison to the 20 MW RWT
LIR concept. The new hybrid (glass-carbon) blade is lighter (16%) than the full-glass classically up-scaled 20 MW RWT blade, but it is also more expensive (7.3%). This is due to its longer span and the use of expensive carbon. Nevertheless, the overall increase in turbine CAPEX is 3.4% because in offshore wind the blades represent a small fraction of the turbine and support structure cost. Despite the higher CAPEX the larger, less loaded rotor, increases the turbine yield (capacity factor CF) by 7.5%. As stated earlier, a 4.5% comes from the LIR planform and another 3% from the dedicated low lift profiles. Even more important is the increase of the wind farm capacity factor by 9.7% due to the lower wake losses of LIR rotors. This is the highest value achieved among the different rotor concepts. Overall, LIR promises a 3.9% reduction of LCOE compared to the 20 MW RWT.
Bend-Twist Coupled Rotor. The conclusions here regarding the impact of the BTC concept on LCOE are similar to those extracted for 10 MW designs. No significant reduction in the cost of energy is expected maintaining the reference rotor diameter. Such designs may reduce the fatigue and the ultimate loading of the blade itself and, also, of the support structure having an indirect effect on CAPEX reduction which, however, is not taken into account here. The BTC blade is highly loaded (high Cp max design) and 8.5% lighter and cheaper than the RWT blade. The overall CAPEX and LCOE improvement is small (1%) leading to an LCOE reduction of 0.6%. Due to the assumptions made, we can consider that BTC improvements can be superimposed to LIR summing up their individual impacts to all PIs.
Magnetic Pseudo Direct Drive (PDD). The PDD generator with highly efficient power electronics promises a good LCOE performance (2 % lower than the reference) combined with a significant nacelle/drive train cost reduction of 7%. The nacelle mass is slightly increased by 4% while the capacity factor increases by 1.1 % which, along with the reduced CAPEX, is the reason of LCOE improvement. The improved capacity factor comes as a combination of the highly efficient 20 MW PDD generator (~ 98.5% at full load) and the highly efficient power electronics.
Bottom Mounted Offshore Support Structure An advanced design/manufacturing of the 20 MW RWT jacket is expected to reduce the original cost of ~14 M€ by 20%. Such a reduction would decrease the overall CAPEX by 4.3% translated to 3% reduction of the LCOE.
Advanced Control in 20 MW. An LCOE drop of 4% can be expected due to the mitigation of design loads of the turbine and its support structure offered by advanced control. In the present context advanced control was mainly targeted in reducing blade than support structure loads. Such a reduction can be used for increasing the rotor diameter and improve LCOE through better energy capturing. Alternatively, one can target on the reduction of the support structure fatigue loads which are the design drivers of the jacket. For jacket structures load reduction is nearly proportional to mass reduction. Since the offshore turbine support structure has a significant contribution to CAPEX, the reduction of the jacket fatigue loads through advanced control can also lead to an LCOE reduction of order 4% without increasing rotor diameter.
A simplified methodology for estimating the combined performance of the researched concepts would sum-up the percentage gains of the individual innovations as soon as they can be considered independently from each other. Some examples of such combinations are given in the lower parts of the PI Tables.
For bottom-mounted designs at INNWIND.EU’s 20 MW RWT conditions, the following expectations regarding LCOE reduction from new technology are presented:
• Low induction rotors with conventional inner structure 4.0%
• Aeroelastically tailored rotor 0.5%
• Drive train (reduced CAPEX, increased efficiency) 2.5%
• Advanced Jacket 3.0%
• Advanced control 4.0%
Expected Overall LCOE reduction 14.0%
Starting from the EWII LCOE value of €106.9/MWh corresponding to 5 MW turbine sizes, and considering more realistic O & M costs, this number dropped at €98.5/MWh (8.5% reduction) for the 10 MW RWT and €93.2/MWh (14.7% reduction) for the 20 MW wind turbine. These reductions were due to the larger turbine sizes, along with the use of a lightweight rotor with thick profiles, and the shift from traditional three-stage geared drive trains to medium speed drive while employing state of the art designed and manufactured jackets. An additional 14% reduction of LCOE can be expected for both 10 and 20 MW designs, thanks to the advanced concepts researched in INNWIND.EU getting LCOE close to €80/MWh for 20 MW turbines (and €85/MWh for 10 MW turbines).
Note that the above cost reduction potential only addresses LCOE contributors researched in the INNWIND.EU project. Innovations addressing the reduction of balance of plant costs, increasing the electrical efficiency of the power plant, suppressing the installation and operation and maintenance costs, along with the needed market boost, will further drive LCOE down by 2025 towards 50-60 €/MWh, rendering offshore wind energy a subsidy-free clean energy production technology.
A summary of key scientific findings is given below.
Rotors
➢ Large, high-tip speed rotors of moderate power density show a significant potential for LCOE reduction. This is partially due to the small contribution of the rotor CAPEX in offshore wind LCOE, but also facilitated by advanced control technology that mitigates higher loads from larger rotors.
➢ Special thick airfoil families optimized for the high Reynolds numbers of the MW machines can further improve turbine efficiency.
➢ Aero-elastically tailored blades with innovative inner structure, active aerodynamic control devices such as distributed flaps, combined with advanced wind measurement sensors (spinner anemometer or LiDAR for instance) and control strategies may significantly reduce turbine loading and therefore the weight and CAPEX of the load carrying components.
Drivetrain
➢ Reduction of tower top mass is not a significant factor in reducing the LCOE of bottom fixed large offshore wind turbines of 10 MW-20 MW capacities.
➢ Direct drive generators may improve the reliability and availability of offshore turbines. Superconducting generators may be an option for lightweight RNAs (when desired) with small dependence on rare earth materials, but appear to be extremely costly in present times (require to reduce the SC wire cost by 4 and increase its capacity by 4 to be competitive).
➢ Magnetic pseudo direct drives are competitive in terms of cost and performance, but vulnerable to magnetic material prices.
Substructure
➢ Jackets have a large cost reduction potential through design optimisation, use of cost-effective materials and improved –automated- manufacturing and installation practices.
➢ At 50m water depth, for 3-bladed 10MW turbines, 3P excitation of the support structure may compromise the turbine performance and fatigue life of the substructure, when jackets are used; to keep the support structure frequency low enough results in a jacket with a smaller footprint and higher mass and this is compounded if there are tower top mass reductions.
➢ For larger turbines nearing 20MW scale, there is no 3P excitation of the substructure due to the reduction in support structure frequencies at this size, hence savings in tower top mass are not penalized by rising support structure costs and the support structure design can be better optimized owing to less frequency constraint.
➢ Avoiding rotor-support structure resonance is rather impossible for efficient two-bladed rotors. Such rotors may only be combined with flexible sub-structures, such as the semi-floater at 50m-70m water depths.
➢ The optimal size of floating turbines is not yet mastered. A cost effective semi-submersible tripod floater has been designed and assessed for a 10MW turbine.
Overall the LCOE of the 20 MW offshore wind turbine was reduced by more than 30% as compared to the 2012 EWII basis of the 5 MW wind turbine. This evaluation of LCOE was primarily based on direct CAPEX savings and increase in AEP from the innovations combined with the larger capacities. Further savings in the LCOE due to OPEX reduction from lower fatigue loading and ease of maintenance is also expected.
List of Websites:
www.innwind.eu