MW Turbine Research Articles

Mesoscale modelling of North Sea wind resources with COSMO-CLM: model evaluation and impact assessment of future wind farm characteristics on cluster-scale wake losses

Abstract. As many coastal regions experience a rapid increase in offshore wind farm installations, inter-farm distances become smaller, with a tendency to install larger turbines at high capacity densities. It is, however, not clear how the wake losses in wind farm clusters depend on the characteristics and spacing of the individual wind farms. Here, we quantify this based on multiple COSMO-CLM simulations, each of which assumes a different, spatially invariant combination of the turbine type and capacity density in a projected, future wind farm layout in the North Sea. An evaluation of the modelled wind climate with mast and lidar data for the period 2008–2020 indicates that the frequency distributions of wind speed and wind direction at turbine hub height are skillfully modelled and the seasonal and inter-annual variations in wind speed are represented well. The wind farm simulations indicate that for a typical capacity density and for SW winds, inter-farm wakes can reduce the capacity factor at the inflow edge of wind farms from 59 % to between 54 % and 30 % depending on the proximity, size and number of the upwind farms. The efficiency losses due to intra- and inter-farm wakes become larger with increasing capacity density as the layout-integrated, annual capacity factor varies between 51.8 % and 38.2 % over the considered range of 3.5 to 10 MW km−2. Also, the simulated efficiency of the wind farm layout is greatly impacted by switching from 5 MW turbines to next-generation, 15 MW turbines, as the annual energy production increases by over 27 % at the same capacity density. In conclusion, our results show that the wake losses in future wind farm clusters are highly sensitive to the inter-farm distances and the capacity densities of the individual wind farms and that the evolution of turbine technology plays a crucial role in offsetting these wake losses.

Larger wind turbines as a solution to reduce environmental impacts

The EU aims for carbon neutrality by 2050, focusing on offshore wind energy. Investments in North Sea wind farms, with optimal wind resources, play a crucial role. We employed a high-resolution regional climate model, which incorporates a wind farm parametrization, to investigate and address potential mitigating impacts of large wind farms on power generation and air-sea fluxes. Specifically, we examined the effects of replacing 5 MW turbines with larger 15 MW turbines while maintaining total capacity. Our study found that substituting 15 MW turbines increases the capacity factor by 2–3%, enhancing efficiency. However, these turbines exhibit a slightly smaller impact on 10 m wind speed (1.2–1.5%) and near-surface kinetic energy (0.1–0.2%), leading to reduced effects on sea surface heat fluxes compared to 5 MW turbines. This was confirmed by a stronger reduction in net heat flux of about 0.6–1.3% in simulations with 5 MW compared to 15 MW wind turbines. Air-sea fluxes influence ocean dynamics and marine ecosystems; therefore, minimizing these impacts is crucial. Overall, deploying 15 MW turbines in offshore wind farms may offer advantages for ocean dynamics and marine ecosystems, supporting the EU's carbon–neutral objectives.

Seasonal variability of wake impacts on US mid-Atlantic offshore wind plant power production

Abstract. The mid-Atlantic will experience rapid wind plant development due to its promising wind resource located near large population centers. Wind turbines and wind plants create wakes, or regions of reduced wind speed, that may negatively affect downwind turbines and plants. We evaluate wake variability and annual energy production with the first yearlong modeling assessment using the Weather Research and Forecasting model, deploying 12 MW turbines across the domain at a density of 3.14 MW km−2, matching the planned density of 3 MW km−2. Using a series of simulations with no wind plants, one wind plant, and complete build-out of lease areas, we calculate wake effects and distinguish the effect of wakes generated internally within one plant from those generated externally between plants. We also provide a first step towards uncertainty quantification by testing the amount of added turbulence kinetic energy (TKE) by 0 % and 100 %. We provide a sensitivity analysis by additionally comparing 25 % and 50 % for a short case study period. The strongest wakes, propagating 55 km, occur in summertime stable stratification, just when New England's grid demand peaks in summer. The seasonal variability of wakes in this offshore region is much stronger than the diurnal variability of wakes. Overall, yearlong simulated wake impacts reduce power output by a range between 38.2 % and 34.1 % (for 0 %–100 % added TKE). Internal wakes cause greater yearlong power losses, from 29.2 % to 25.7 %, compared to external wakes, from 14.7 % to 13.4 %. The overall impact is different from the linear sum of internal wakes and external wakes due to non-linear processes. Additional simulations quantify wake uncertainty by modifying the added amount of turbulent kinetic energy from wind turbines, introducing power output variability of 3.8 %. Finally, we compare annual energy production to New England grid demand and find that the lease areas can supply 58.8 % to 61.2 % of annual load. We note that the results of this assessment are not intended to make nor are they suitable to make commercial judgments about specific wind projects.

Prospects of Hydrogen Application as a Fuel for Large-Scale Compressed-Air Energy Storages

A promising method of energy storage is the combination of hydrogen and compressed-air energy storage (CAES) systems. CAES systems are divided into diabatic, adiabatic, and isothermal cycles. In the diabatic cycle, thermal energy after air compression is discharged into the environment, and the scheme implies the use of organic fuel. Taking into account the prospects of the decarbonization of the energy industry, it is advisable to replace natural gas in the diabatic CAES scheme with hydrogen obtained by electrolysis using power-to-gas technology. In this article, the SENECA-1A project is considered as a high-power hybrid unit, using hydrogen instead of natural gas. The results show that while keeping the 214 MW turbines powered, the transition to hydrogen reduces carbon dioxide emissions from 8.8 to 0.0 kg/s, while the formation of water vapor will increase from 17.6 to 27.4 kg/s. It is shown that the adiabatic CAES SENECA-1A mode, compared to the diabatic, has 0.0 carbon dioxide and water vapor emission with relatively higher efficiency (71.5 vs. 62.1%). At the same time, the main advantage of the diabatic CAES is the possibility to produce more power in the turbine block (214 vs. 131.6 MW), having fewer capital costs. Thus, choosing the technology is a subject of complex technical, economic, and ecological study.

Loss Analysis in Radial Inflow Turbines for Supercritical CO2 Mixtures

Abstract Recent studies suggest that CO2 mixtures can reduce the costs of concentrated solar power plants. Radial inflow turbines (RIT) are considered suitable for small to medium-sized CO2 power plants (100 kW to 10 MW) due to aerodynamic and cost factors. This paper quantifies the impact of CO2 doping on RIT design by comparing 1D mean-line designs and aerodynamic losses of pure CO2 RITs with three CO2 mixtures: titanium tetrachloride (TiCl4), sulfur dioxide (SO2), and hexafluorobenzene (C6F6). Results show that turbine designs share similar rotor shapes and velocity diagrams for all working fluids. However, factors like clearance-to-blade height ratio, turbine pressure ratio, and fluid viscosity cause differences in turbine efficiency. When normalized for these factors, differences in total-to-static efficiency become less than 0.1%. However, imposing rotational speed limits reveals greater differences in turbine designs and efficiencies. The imposition of rotational speed limits reduces total-to-static efficiency across all fluids, with a maximum 15% reduction in 0.1 MW CO2 compared to a 3% reduction in CO2/TiCl4 turbines of the same power. Among the studied mixtures, CO2/TiCl4 turbines achieve the highest efficiency, followed by CO2/C6F6 and CO2/SO2. For example, 100 kW turbines achieve total-to-static efficiencies of 80.0%, 77.4%, 78.1%, and 75.5% for CO2/TiCl4, CO2/C6F6, CO2/SO2, and pure CO2, respectively. In 10 MW turbines, efficiencies are 87.8%, 87.3%, 87.5%, and 87.2% in the same order.

Thermodynamic Study on Decarbonization of Combined Cycle Power Plant

Integrating hydrogen firing and a carbon capture plant (CCP) into a natural gas combined cycle (NGCC) power plant is a promising strategy for reducing CO2. In this study, process simulation in Aspen PLUS of hydrogen co-firing in a 40 MW turbine gas combined cycle power plant was done at an identical gas turbine inlet temperature from 0%.cal to 30%.cal. The evaluated cases were hydrogen co-firing with CCP (H2 Co-firing + CCP) and hydrogen co-firing without CCP (H2 Co-firing). The results showed a 6% CO2 emission reduction per 5% increase in hydrogen, albeit with increased NOx emissions. H2 Co-firing experienced a decrease in net power with rising hydrogen co-firing, while H2 Co-firing + CCP saw an increase but remained below Case 2 due to the energy penalty from the carbon capture plant. The capital cost of H2 Co-firing + CCP exceeds that of H2 Co-firing due to CCP usage, impacting gross revenue. The sensitivity analysis indicated that the cost of hydrogen has higher sensitivity compared to the cost of CCP. Lowering hydrogen prices is recommended to effectively reduce CO2 emissions in NGCC.

A new similarity criterion for wind tunnel testing of floating wind turbines achieving dynamic aerodynamic characteristics similarity

Floating offshore wind turbines have rapidly advanced in recent years, prompting numerous experiments. Small-scale turbines require blade redesign with low Reynolds number airfoils due to the scale effect. Consequently, the chord length of these blades no longer corresponds to the length scale, leading to dissimilar dynamic aerodynamic phenomena during platform movement. To address this, a new criterion is proposed for wind tunnel tests of floating offshore wind turbines. The criterion incorporates reduced frequency correction and optimal tip speed ratio (TSR) matching. It ensures hydrodynamic similarity through Froude number similarity and avoids excessive low wind speed through wind speed correction. Optimal TSR matching ensures the model and prototype turbines operate within similar power curve intervals. Reduced frequency corrects the platform sine motion parameters, providing the model turbine with a dynamic aerodynamic effect similar to the prototype. The National Renewable Energy Laboratory’s 5 MW wind turbine is chosen as the prototype, and the model wind turbine blades are designed using NACA 4412 airfoil and the criterion of thrust coefficient similarity. The sub-module of the FAST, AeroDyn is employed to validate the new criterion for different surge motions between the NREL 5 MW and the model. Under the new similarity criterion, the model turbine exhibits a relative root mean square error of 4.61 % and 1.54 % in power coefficient and thrust coefficient, a significant improvement compared to the current similarity criterion's relative root mean square error of 24.74 % and 8.36 %. The results reveal a circular trend variation in both thrust coefficient and power coefficient with position. Notably, the new criterion demonstrates a closer alignment with the dynamic aerodynamic characteristics of the prototype when contrasted with the current similarity criterion. Furthermore, this model design, tailored for the NREL 5 MW turbine, can be applied to model experiments with various turbine configurations. It has been successfully verified for the IEA 15 MW turbine, exhibiting promising simulation results. The proposed similarity criterion is suitable for wind tunnel testing, addressing the problem that the current similarity criterion cannot reflect the dynamic aerodynamic characteristics of prototype wind turbines. Additionally, it enables experiments on different prototype configurations using a single model turbine, reducing wind tunnel testing costs.

A novel design of a hybrid glulam-steel substructure for the IEA 15-MW floating wind turbine

Wind energy has become increasingly recognised as a very promising type of renewable energy. In addition, floating offshore wind turbines have facilitated the development of electricity production in intermediate (45-150 m) and deep sea (>150 m) depths. Despite this, wind turbine manufacturing, installation, and operation may generate substantial greenhouse gas emissions. A novel hybrid glulam-steel floating substructure design is presented in this research, intended for the IEA 15 MW floating wind turbine. The objective is to contribute to advancing floating wind energy while minimising costs and carbon dioxide emissions. The objective of the novel design is to substitute steel with glued laminated lumber (glulam). It showcases an altered iteration of the UMaine VolturnUS-S semi-submersible platform originally created for the IEA 15 MW turbine. Before selecting one of three preliminary hybrid wood-steel models, the Ansys Workbench 2020 R1 is used to evaluate and appraise them per a set of criteria extracted from pertinent timber and steel standards. The chosen hybrid design conserves about 590 metric tonnes of steel mass compared to the UMaine VolturnUS-S semi-submersible platform. The selected model is then validated by executing a fully coupled aero-hydro-servo-elastic dynamic analysis with OpenFAST. Consideration is limited to the ultimate limit state design (ULS) for normal and severe operating situations. The utilisation factor of the glulam supporting structure for the IEA 15 MW turbine ranges from 74% to 94%, indicating that it is an effective load-bearing solution.

Comparing the Utility of Coupled Aero-Hydrodynamic Analysis Using a CFD Solver versus a Potential Flow Solver for Floating Offshore Wind Turbines

There has been a great effort towards development of renewable energy systems to combat global warming with significant interest towards research and development of floating offshore wind turbines (FOWTs). With commercial projects such as Hywind Scotland, Hywind Tampen and others, there is a shift of industry attention from bottom-fixed offshore turbines to FOWTs. In this work, we focus on comparing industry standard Potential Flow (PF) methods versus Computational Fluid Dynamics (CFD) solvers for a scaled version of the IEA 15 MW turbine and associated FOWT system. The results from the two solvers are compared/validated using experimental thrust values for the fixed turbine. The motions and the thrust for the FOWT system are then compared for the two solvers along with hydrodynamic properties of the floater hull. The wake features downstream of the turbine are analyzed for the fixed and floating turbine using the CFD solver. The wake from the CFD solver is also compared with a simplified PF model. Finally, a simplified cost-benefit analysis is presented for the two solvers to compare the usefulness and utility of a CFD solver as compared to presently used industry-standard PF methods.

Feasibility study of offshore wind energy on the coast of Sri Lanka

ABSTRACT Sri Lanka's energy issue is caused by underinvestment in renewable energy, resulting in rationing and power outages. Given its power output, offshore wind energy is a possible solution for a sustainable energy future. This study investigates the viability of an offshore wind farm by scrutinizing three potential sites, chosen based on wind speed, direction, and allied variables. Wind speed data from the ERA-5 repository and bathymetry information from the General Bathymetry Chart of Oceans support energy potential assessment for these locations. Employing the WAsP software, a technical analysis was performed to determine the energy output potential for water depths up to 50 m. Of the three sites, the western site emerged as the most productive, estimating an energy yield of 24.36 GWh from an 8 MW turbine. This calculation took into account a capacity utilization factor of 34.76%, with the levelized cost of energy approximating INR 7.70. The northern and southern sites trailed marginally, with estimated energy outputs of 20.31 GWh and 22.36 GWh, respectively. As evidenced by these findings, offshore wind energy holds promise as a dependable and steadfast energy source for Sri Lanka. It also highlights Sri Lanka's first offshore wind farm and future plans.

Wet steam flow in 1100 MW turbine

Wet steam flow in 1100 MW turbine

The impacts of atmospheric icing on performance and behavior of a controlled large-scale wind turbine

Icing degrades turbine performance by altering the geometry of blade airfoils, reducing turbine power output, and increasing structural loads. In this study, the impacts of atmospheric icing on the full performance and behavior of a controlled large-scale wind turbine are thoroughly investigated. Using the Mustafa Sahin bladed wind turbine simulation model, the National Renewable Energy Laboratory 5 MW turbine is simulated with and without iced blades. The turbine blades are considered fully covered by light icing at the leading edge, which causes a reduction of up to 9.27% in Cl and an increase of up to 48% in Cd data of blade airfoils. Turbine static performance and behavior are examined at different uniform winds between cut-in and cut-out wind speeds, while the dynamic performance and behavior are estimated under turbulent winds at below (region II) and above (region III) rated regions. Simulation results are presented in terms of various turbine parameters, such as rotor power, thrust, their coefficients, blade pitch angle, rotor speed, etc. Results show that such light icing alters the turbine's aerodynamic characteristics and dynamics, increasing the turbine's cut-in and rated wind speeds, and reducing the thrust and maximum power coefficients by 5.5% and 13.35%, respectively. Under the same uniform winds, due to icing, turbine static performance and behavior are drastically disrupted in below rated region, resulting in reduced rotor speed, turbine efficiency, thrust, and power output by up to 4.77%, 39.7%, 7.63%, and 40%, respectively. In region III, however, thrust increases by up to 15% although the power output, rotor speed, and turbine efficiency do not change considerably. When the dynamic responses are examined under turbulent wind with a mean of 7.9 m/s in region II, mean power and fluctuations reduce by 14.17% and 10.88%, respectively. The mean thrust decreases by 6.86%, while its fluctuations reduce by 11.33%. The mean rotor speed reduces by 3.83%, and its fluctuations decrease by 12.84%. Under turbulent wind with a mean of 15.7 m/s in region III, the mean power and fluctuations decrease by 0.053% and 1.95%, respectively. The mean thrust increases by 11.99% and its fluctuations drop by 0.84%. The mean rotor speed does not change much, but its fluctuations increase by 0.132%. The mean blade pitch angle reduces by 9.39%, while its fluctuations increase by 7.39%.

Analisis Teknis dan Ekonomi dalam Pemanfaatan Area Sekitar Anjungan Lepas Pantai di Laut Jawa untuk Memproduksi Listrik Hijau dengan Turbin Angin Lepas Pantai

Green electricity production with offshore wind turbines is a potential option to increase renewable energy penetration in Indonesia. Indonesia's geographical condition which has 70 percent of the ocean makes the offshore wind turbines interesting for further research. In this study, the area of the ocean that will be used is Papa's offshore platform, which from an operational economic point of view has decreased so that it can be converted into an offshore sub-station for an electricity substation before being sent to a sub-station on land with distance of 40 km and sea depth of 35 m. The study begins with an analysis of the meteo data conditions of the area around the offshore platform which produces an average wind speed of 5.5 m/s (for a height of 119 meters) and the greatest frequency of wind directions from the East Southeast (ESE) direction. Furthermore, the wind farm analysis shows that the best wind farm direction with the Vestas V162-7.2 MW turbine is in the East Northeast (ENE) - West Southwest (WSW) direction with an energy generation potential of 141,656.9 MWh/year and a wake loss of 10% for a generating capacity of 100 .8MW. To determine the economy, an analysis was carried out using LCOE and NPV which resulted in a green electricity production value (LCOE) of $0.192/kWh and in determining investment feasibility an NPV analysis was carried out which produced a selling value of green electricity with an offshore wind turbine of $0.271/kWh.

Calculation of Thermodynamic Wetness Loss in Steam Turbines Using Computational Fluid Dynamics Simulation

Abstract In the paper, the behavior of wet steam flow is described in three different steam turbines. The first one is the 1100 MW turbine in the nuclear power plant with the pressurized water reactor. The second one is the 660 MW turbine in the fossil fuel power plant with ultrasupercritical steam parameters at the turbine inlet. The last turbine has a nominal output of 34 MW and operates in the municipal waste-to-energy plant. However, this turbine can often also operate even at 2 MW or higher. In all three turbines in the last stage area passages are made for an optical probe to measure steam wetness and primary droplets size, and for a pneumatic probe to determine the pressures, velocities and flow directions. Based on experimentally obtained data, analyses of thermodynamic wetness loss for all three turbines are performed using numerical flow simulations considering equilibrium and nonequilibrium steam. The condensation model that includes the nucleation rate and droplet growth velocity used in ansyscfx is calibrated based on experimentally obtained data. It is evident that the obtained loss patterns depend fundamentally on the turbine type and operating parameters.

Analysis and multi-objective optimisation of wind turbine torque control strategies

Abstract. The combined wind speed estimator and tip-speed ratio (WSE–TSR) tracking wind turbine control scheme has seen recent and increased traction from the wind industry. The modern control scheme provides a flexible trade-off between power and load objectives. On the other hand, the Kω2 controller is often used based on its simplicity and steady-state optimality and is taken as a baseline here. This paper investigates the potential benefits of the WSE–TSR tracking controller compared to the baseline by analysis through a frequency-domain framework and by optimal calibration through a systematic procedure. A multi-objective optimisation problem is formulated for calibration with the conflicting objectives of power maximisation and torque fluctuation minimisation. The optimisation problem is solved by approximating the Pareto front based on the set of optimal solutions found by an explorative search. The Pareto fronts were obtained by mid-fidelity simulations with the National Renewable Energy Laboratory (NREL) 5 MW turbine under turbulent wind conditions for calibration of the baseline and for increasing fidelities of the WSE–TSR tracking controller. Optimisation results show that the WSE–TSR tracking controller does not provide further benefits in energy capture compared to the baseline Kω2 controller. There is, however, a trade-off in torque control variance and power capture with control bandwidth. By lowering the bandwidth at the expense of generated power of 2 %, the torque actuation effort reduces by 80 % with respect to the optimal calibration corresponding to the highest control bandwidth.

Aerodynamic rotor design for a 25 MW offshore downwind turbine

Continuously increasing offshore wind turbine scales require rotor designs that maximize power and performance. Downwind rotors offer advantages in lower mass due to reduced potential for tower strike, and is especially true at large scales, e.g., for a 25 MW turbine. In this study, three 25 MW downwind rotors, each with different prescribed lift coefficient distributions were designed (chord, geometry, and twist) and compared to maximize power production at unprecedented scales and Reynolds numbers, including a new approach to optimize rotor tilt and coning based on aeroelastic effects. To achieve this objective the design process was focused on achieving high power coefficients, while maximizing swept area and minimizing blade mass. Maximizing swept area was achieved by prescribing pre-cone and shaft tilt angles to ensure the aeroelastic orientation when the blades point upwards was nearly vertical at nearly rated conditions. Maximizing the power coefficient was achieved by prescribing axial induction factor and lift coefficient distributions which were then used as inputs for an inverse rotor design tool. The resulting rotors were then simulated to compare performance and subsequently optimized for minimum rotor mass. To achieve these goals, a high Reynolds number design space was developed using computational predictions as well as new empirical correlations for flatback airfoil drag and maximum lift. Within this design space, three rotors of small, medium and large chords were considered for clean airfoil conditions (effects of premature transition were also considered but did not significantly modify the design space). The results indicated that the medium chord design provided the best performance, producing the highest power in Region 2 from simulations while resulting in the lowest rotor mass, both of which support minimum LCOE. The methodology developed herein can be used for the design of other extreme-scale (upwind and downwind) turbines.

Yaw control strategies for 20 MW multi-rotor systems

In this paper, the control of an active yaw system for a 20 MW multi-rotor wind turbine system (MRS) is considered. The MRS under investigation consists of five 4 MW turbines in two rows, which are connected to the tower via a space frame. A central yaw bearing at the height of the lower rotors is provided for active yaw. The paper aims to show that active aerodynamic yaw is possible by changing the thrust of certain rotors and should be considered for further research in the field of yawing of an MRS. Two different simulation environments are used in the paper. The MRS is modeled and simulated in Matlab/Simulink. Simulink’s own control modules are used as controllers. In the other simulation approach, the same MRS is modeled and simulated in Bladed and controlled with an external controller based on C++. The use of Bladed and Matlab/Simulink enables the plausibility and verification of the results. Matlab/Simulink is faster based of its simpler models but Bladed is more sophisticated. This paper also briefly presents the state of the art for yaw systems and yaw control of conventional single rotor wind turbines and initial research literature on yaw control of MRS.

Integrated Studies of Electrophysical Processes in Steam Turbines

The paper deals with comprehensive research in the field of electrization of wet steam flow in a turbine. The experience of the conducted studies on laboratory stands and full-scale objects (CHP and TPP) in Ukraine and the USA is introduced and generalized. It was shown that in the process of steam electrization, the charge density in the flow can reach very high values (an order of magnitude appears to be higher than in a thundercloud), and this phenomenon mainly has a negative effect on the turbine operation. Statistical data on the charge formation of the steam flow in the low-pressure cylinder of the turbine are presented. Results of the research to establish the main electrophysical factors of influence on the surface strength of the blade, such as electric fields, charge density and their polarity, are presented. The research results showed that such factors as the presence of a positively charged steam flow, constant and variable electric fields, which were most often recorded at operating turbines of CHPs and TPPs, significantly (by two or more times) intensify erosion-corrosion processes on the metal surfaces of the blades, thus reducing their working resource. Thermodynamic processes are studied both under conditions of natural electrification of a high-speed flow, which reduce the efficiency by about 0.3–0.35%, and under the influence of artificially created electric charges, which make it possible to increase the efficiency of the steam expansion process in the turbine by 2 or more percent. Various options of local input of electrical energy for steam ionization in the turbine are considered. At the same time, it is noted that for the practical implementation of these approaches, further careful design improvements and tests on model and full-scale installations are required. Water chemistry regimes are also considered in the context of their influence on the flow charge formation process, as well as on reliability and efficiency indicators of the turbine. Experimentally at an 800 MW turbine plant in the USA, it was shown that a change in the pH of the medium affects the intensity and polarity of the charge formation of the steam flow. The paper introduces the physical features of this phenomenon and notes the importance of these processes influence on the strength characteristics of the blades. Information on new methods and technologies that could lead to an increase in the operational efficiency and reliability of wet steam turbines, such as methods for input and removal of electrical energy into the flow; rational choice of water chemistry regimes; space charge neutralization, etc., is provided. These comprehensive electrophysical studies, considered in conjunction with thermal processes, can be characterized as a new scientific direction in the theory of steam turbines – thermal electrophysics.

Resource assessment using a combination of seabed mounted and semi-stationary vessel-mounted ADCP measurements

Accurate resource assessment for tidal stream sites is crucial for calculation of the Levelized Cost of Energy (LCOE) of each project or turbine. The main method as recommended by the IEC’s technical specification on tidal stream resource assessment involves using a numerical model as well as several measurements using Acoustic Doppler Current Profilers (ADCP) mounted on the seabed. Ideally, once the locations of the turbines are known precisely, seabed mounted ADCP measurements will be undertaken at all turbine locations. For large tidal arrays this is however challenging, especially with project development constrained by time and budget. The MeyGen project is the largest planned tidal stream energy project in the world, aiming to develop up to 398 MW of installed power in the Pentland Firth, Scotland, with current velocities reaching up to 5 m/s. During Phase 1 of the project, four 1.5 MW turbines were installed. During Phase 2, site characterization campaigns were carried out to plan the deployment of additional turbines, representing 28 MW of tidal power capacity. Based on learning from Phase 1 around the need to accurately calibrate numerical models at a very detailed spatial resolution, and the costs and time to obtain seabed ADCP measurements at many turbine locations, a new measurement methodology was proposed. This method used semi-stationary vessel-mounted ADCP measurements to characterize the flow at the planned turbine locations, rather than relying on a few seabed-mounted ADCP measurements and a numerical model, or relying on seabed-mounted ADCPs at all the locations of the planned turbines.
 This works introduces the method used for calculating the tidal stream velocities at the planned turbine locations. A 35-day seabed mounted ADCP survey was conducted as a baseline within the area of planned turbines. It used a Teledyne SentinelV50 ADCP configured with 2Hz sampling rate, 5-beam velocities and 1 m depth cells. Using harmonic analysis and prediction, the current velocities were obtained for a 18.6 years period.
 Additionally, during seven days of spring tide, water velocities were measured using a vessel mounted ADCP. It used a Teledyne Workhorse 600kHz configured with circa 1Hz sampling rate and 1 m depth cells. The vessel mounted measurements were undertaken at each turbine location during 5 minutes every hour, for a 12-hour tidal cycle. During each 5 minutes the vessel kept its position within 15-meter radius around the nominal position. Similar vessel-mounted measurements were also undertaken above the seabed mounted ADCP, as well as continuously for 12 hours.
 The semi-stationary vessel mounted ADCP measurements were validated against the seabed-mounted ADCP measurements with the co-located 12-hour data. The current velocity magnitude obtained from the vessel mounted measurements at the turbine locations were then correlated with the simultaneous data from the seabed mounted ADCP. This correlation was finally combined with the 18.6 years timeseries predicted at the seabed-mounted ADCP location to obtain long-term times series and statistics for turbine locations. The final presentation and paper will provide the results of this study.

Tidal turbine wake characterization by vessel-mounted ADCP data analysis

Wakes generated downstream turbines are one of the key points to be considered for tidal stream energy farm layout design. Distance between consecutive turbines must be optimized considering available resource spatial distribution and the current velocity reduction caused by upstream turbines. Tidal turbine wake characteristics have been analyzed experimentally and numerically, however, there is still a lack of studies presenting data measured in the wake of large-size turbines in tidal sites.
 In this paper, the wake generated downstream of a SIMEC Atlantis Energy 0.5 MW turbine in Naru Strait (Nagasaki Prefecture, Japan) is analyzed using data measured with a vessel-mounted ADCP. This analysis is based on the comparison between data measured before turbine installation (September 2020) and during turbine operation (March 2021, May 2021, and September 2021). 
 Due to the difficulties that measuring at the same position and the same tide moment with a vessel-mounted ADCP would mean, a direct comparison between these four datasets is unviable. To solve this issue, data were pretreated to calculate a ratio (RD) resulting from the division of current velocity values at every vertical layer by the current velocity measured at the shallowest layer. After that, this ratio is interpolated to a regular 3D mesh. Assuming that the current velocity profile shape for one point does not change with time, resulting RD values interpolated from data measured in different fieldworks can be compared.
 The impact of tidal turbine operation on the current velocities is quantified with a variation ratio RV calculated by dividing RD during turbine operation (RD*) by RD before turbine installation (RD). These results show a clear velocity deficit even at 18D from the turbine, which clearly contrasts with results from other similar studies available in the literature, which may be related to the low turbulence intensity measured at the turbine installation point.