reading

Cover
Title Page
Notes on Contributors
Foreword
Preface
Acronyms
Symbols (Individual Chapters)
About the companion Website
1 Introduction
1. 1.1 Development of Offshore Wind Energy
2. 1.2 Offshore Wind Technology
3. 1.3 Levelized Cost of Energy
4. 1.4 Future Offshore Wind Development
5. 1.5 References
2 Energy Conversion Systems for Offshore Wind Turbines
1. 2.1 Background
2. 2.2 Offshore Wind Turbine Technology Status
3. 2.3 Offshore Wind Turbine Generator Technology
4. 2.4 Wind Turbine Generator Architectures
5. 2.5 Generators for Offshore Wind Turbines
6. 2.6 Power Electronic Converters for MW Wind Turbine Generators
7. 2.7 Wind Generators Compared to Conventional Power Plant
8. 2.8 Acknowledgements
9. 2.9 References
3 Modelling and Analysis of Drivetrains in Offshore Wind Turbines
1. 3.1 Introduction
2. 3.2 Drivetrain Concepts
3. 3.3 Gearbox Failures
4. 3.4 State‐of‐the‐art Wind Turbine Gearbox Design Codes
5. 3.5 Drivetrain Modelling and Analysis
6. 3.6 Limit State Design
7. 3.7 Drivetrains in Floating Wind Turbines
8. 3.8 Condition Monitoring and Inspection
9. 3.9 Drivetrains in Fault Conditions
10. 3.10 5‐MW Reference Offshore Drivetrain
11. 3.11 References
4 Fixed and Floating Offshore Wind Turbine Support Structures
1. 4.1 Introduction
2. 4.2 Bottom‐fixed Support Structures
3. 4.3 Floating Support Structures
4. 4.4 Design Considerations
5. 4.5 Conceptual Design
6. 4.6 Loads in the Marine Environment
7. 4.7 Global Dynamic Analysis of Offshore Wind Turbines
8. 4.8 Conclusions
9. 4.9 References
5 Offshore Wind Turbine Controls
1. 5.1 Control Objectives, Sensors and Actuators
2. 5.2 Control Algorithms
3. 5.3 A Linear Aeroelastic Loads Model for Closed‐loop System Dynamics
4. 5.4 Basic Rotor Speed Control in Operating Regions I and II
5. 5.5 Active Damping and Load Reduction
6. 5.6 Power Command Tracking
7. 5.7 Conclusions
8. 5.8 References
6 Offshore Wind Farm Technology and Electrical Design
1. 6.1 AC Collectors for Offshore Wind Turbines
2. 6.2 DC Collectors for Offshore Wind Turbines
3. 6.3 Connection Layout Options for a Cluster of Offshore Wind Farms
4. 6.4 Protection of Offshore Wind Farms
5. 6.5 Acknowledgements
6. 6.6 References
7 Operation and Maintenance Modelling
1. 7.1 Introduction
2. 7.2 O&M Modelling for Offshore Wind Farms
3. 7.3 Decision Support Tools Developed by NOWITECH
4. 7.4 Application of Models – Examples and Case Studies
5. 7.5 Outlook
6. 7.6 References
8 Supervisory Wind Farm Control
1. 8.1 Background
2. 8.2 Control Objectives
3. 8.3 Sensory Systems
4. 8.4 Wind Farm System Model
5. 8.5 Control Strategies
6. 8.6 Wind Farm Controller for Improved Asset Management
7. 8.7 Acknowledgements
8. 8.8 References
9 Offshore Transmission Technology
1. 9.1 Introduction
2. 9.2 HVAC Transmission
3. 9.3 VSC‐HVDC Transmission
4. 9.4 Offshore Grid Systems
5. 9.5 Low‐Frequency Alternating Current (LFAC)
6. 9.6 Offshore Substations
7. 9.7 Reactive Power Compensation Equipment
8. 9.8 Subsea Cables
9. 9.9 Acknowledgement
10. 9.10 References
10 Grid Integration and Control for Power System Operation Support
1. 10.1 Power System Interconnection
2. 10.2 Operation and Control
3. 10.3 Performance Requirements and System Services (Including Grid Codes)
4. 10.4 Provision of System Services from Offshore Wind Farms
5. 10.5 References
11 Market Integration and System Operation
1. 11.1 Purpose and Overview of Electricity Markets
2. 11.2 Market Coupling and Transmission Allocation
3. 11.3 Offshore Wind as a Market Participant
4. 11.4 Support Schemes in an Integrated Market
5. 11.5 Challenges for Future Market Design
6. 11.6 References
Appendix
1. A A 10‐MW Offshore Reference Wind Turbine (ORT)
Index
End User License Agreement

List of Tables

Chapter 01
1. Table 1.1 Installed offshore wind capacity by the end of 2015. Data from GWEC (2016).
2. Table 1.2 Example calculation of LCOE for three characteristic cases.
Chapter 03
1. Table 3.1 Causes of wind turbine gearbox failure.
2. Table 3.2 MBS model recommendations (Source: Guo et al., 2015a, 2015b. Reproduced with permission of NREL.).
3. Table 3.3 Uncertainty models (Source: Nejad et al., 2014b. Reproduced with permission of Elsevier.).
4. Table 3.4 Floating wind turbines (Source: Nejad et al., 2015b. Reproduced with permission of Elsevier.).
5. Table 3.5 Environmental conditions (Source: Nejad et al., 2015b. Reproduced with permission of Elsevier.).
6. Table 3.6 Spar: fatigue damage comparison factor, χ % (Source: Nejad et al., 2015b. Reproduced with permission of Elsevier.).
7. Table 3.7 Semi‐1: fatigue damage comparison factor, χ % (Source: Nejad et al., 2015b. Reproduced with permission of Elsevier.).
8. Table 3.8 Semi‐2: fatigue damage comparison factor, χ % (Source: Nejad et al., 2015b. Reproduced with permission of Elsevier.).
9. Table 3.9 TLP: fatigue damage comparison factor, χ % (Source: Nejad et al., 2015b. Reproduced with permission of Elsevier.).
10. Table 3.10 Load cases.
11. Table 3.11 5‐MW Reference gearbox specifications.
12. Table 3.12 Geometrical specification of gears.
13. Table 3.13 Geometrical specification of bearings.
14. Table 3.14 Dynamic model parameters of gears.
15. Table 3.15 Dynamic model parameters of shafts.
16. Table 3.16 Dynamic model parameters of bearings.
Chapter 04
1. Table 4.1 Case study parameters.
2. Table 4.2 Natural periods of rigid body motions of floating offshore wind turbines. Typical values from Chen and Yu (2013) are given in parenthesis, follow by observed values from published studies of 5‐MW designs.
3. Table 4.3 Wind turbine upscaling based on length scale ratio, λ.
4. Table 4.4 Steel mass fraction for various steel FWT platforms.
5. Table 4.5 Case study parameters.
Chapter 05
1. Table 5.1 Filters employed in the controller.
2. Table 5.2 One primary, two significant and five other modes that contribute to the Region I dynamics of the ORT. Together these modes capture the dynamics relevant to the control of rotor speed and electrical power, up to a frequency of 1 Hz.
3. Table 5.3 The principal modes participating in the Region II control of rotor speed.
4. Table 5.4 The influence on the choice of degrees‐of‐freedom on the resonant peak in the rotor speed response.
5. Table 5.5 A recommended tuning for the 10‐MW ORT along its nominal steady‐state operating schedule. The frequency and damping ratio of the rotor speed control mode are listed, together with low frequency transfer functions from rotor‐average wind speed to rotor speed and blade pitch.
6. Table 5.6 The shape of the first torsional mode, normalized to the fluctuation in shaft speed.
7. Table 5.7 The dominant modes associated with damping of the driveshaft using generator torque.
8. Table 5.8 Tower modes without any active damping. (Table 5.9 contains a definition of the variables.)
9. Table 5.9 Tower and damping filter modes, once active side‐to‐side damping is activated and tuned.
10. Table 5.10 The influence of the gain on the modal properties.
11. Table 5.11 Mean power flows (in kW) due to the perturbations about the operating state for the system oscillating with unit amplitude in the tower side‐to‐side mode, listed in Table 5.9. Positive values indicate power removed from the structure.
12. Table 5.12 A mode representing primarily the notch filter at the tower frequency on the rotor speed control function, while fore–aft damping is inactive.
13. Table 5.13 The dominant modes characterizing the damping of tower fore–aft motion using blade pitch.
14. Table 5.14 The effect of engaging active fore–aft damping on the properties of the relevant modes.
15. Table 5.15 The influence of the fore–aft damping gain on the properties of the relevant modes.
16. Table 5.16 The dominant modes participating in the control of individual blade pitch for the rejection of asymmetric rotor yaw and tilt moments.
17. Table 5.17 Frequency and damping ratios of the modes in the isolated electric system.
Chapter 06
1. Table 6.1 Summary of the characteristics of different AC topologies.
Chapter 07
1. Table 7.1 Contribution of OPEX to LCoE.
2. Table 7.2 Key principles and attributes of asset management (BSI PAS 55‐2, 2008) and specific contributions to these principles/attributes through O&M models and tools.
3. Table 7.3 Overview of strategic O&M tools not included in the review by Hofmann (2011).
4. Table 7.4 Examples of decision problems and decision support by O&M modelling tools.
5. Table 7.5 General overview and relevant publications for the NOWITECH models.
6. Table 7.6 General differences and intended use of NOWIcob and vessel fleet optimization models.
7. Table 7.7 Differences in input parameters.
8. Table 7.8 Overview of participants and models in the ‘offshore wind O&M modelling group’.
9. Table 7.9 Operation and maintenance – Targets for 2020, 2030 and 2050 (TPWind 2014).
Chapter 09
1. Table 9.1 Power exchange between a STATCOM and the AC system.
Appendix
1. Table A.1 Some key dimensions and stiffness properties of the foundation and tower.
2. Table A.2 Parameters for a reference 10‐MW direct drive generator, with modifications from previous values. Previous values are obtained from, or computed for, the design described by Liseth and Nilssen (2011).
3. Table A.3 Physical parameters for the converter and transformer of the 10‐MW ORT.

List of Illustrations

Chapter 01
1. Figure 1.1 Global accumulated offshore wind capacity since 2000.
2. Figure 1.2 Illustration of the Hywind Scotland 30‐MW floating wind farm scheduled to be in operation by late 2017 about 25 km offshore from Peterhead. The turbines are each rated 6 MW and the water depth is 95–120 m (Statoil, 2015).
3. Figure 1.3 The London Array 630‐MW offshore wind farm in operation in the outer Thames estuary. The wind farm spans about 100 km² and includes 175 turbines each rated 3.6 MW installed in waters up to 25 m deep (London Array Limited, 2016).
4. Figure 1.4 The main elements of an offshore wind farm. (Not to scale, for illustration only.) The turbines are normally installed 5–10 rotor diameters apart. Graphic by Tande, SINTEF.
5. Figure 1.5 Metrics in calculation of LCOE.
6. Figure 1.6 Historical LCOE of offshore wind farms and projection as reported by IRENA (2016) compared with reported auction prices for three new offshore wind farms to be in operation by 2020 (star symbols). Costs for these three wind farms are, from the top, 72.7 EUR/MWh for Borssele (NL) 700 MW (Dong, 2016), 63.8 EUR/MWh for Vesterhav (DK) 350 MW (Vattenfall, 2016a) and 49.9 EUR/MWh for Kriegers Flak (DK) 600 MW (Vattenfall, 2016b). The graph is prepared converting data from IRENA (2016) to EUR/MWh assuming an exchange rate of 9 EUR = 10 USD for 2015.
7. Figure 1.7 Distribution of investment expenditures for a ‘representative’ offshore wind farm.
Chapter 02
1. Figure 2.1 Evolution in the size of commercial wind turbines.
2. Figure 2.2 Typical components in a wind turbine (both onshore and offshore).
3. Figure 2.3 Illustration of power coefficient/tip‐speed ratio curve, C_p/λ.
4. Figure 2.4 Power curve for a 2‐MW wind turbine.
5. Figure 2.5 Fixed‐speed induction generator wind turbine (FSIG, Type I)
6. Figure 2.6 Variable‐slip wind turbine generator (Type II).
7. Figure 2.7 Doubly‐fed induction generator wind turbine (DFIG, Type III).
8. Figure 2.8 State‐of‐the‐art electric generator and power converter configurations for the commercial WTGs
9. Figure 2.9 Type IV wind turbine generator with distributed drivetrain
10. Figure 2.10 Classification of BTB converters. (VSC: voltage source converter, NPC: neutral‐point clamped, FC: Flying capacitor, 2L: two‐level, 3L: three‐level, 4L: four‐level)
11. Figure 2.11 Type IV wind turbine generator with BTB 2L‐VSCs
12. Figure 2.12 Type III DFIG wind turbine generator with BTB 2L‐VSCs.
13. Figure 2.13 Type IV wind turbine generator with parallel‐connected BTB 2L‐VSCs and common DC‐link.
14. Figure 2.14 Type IV wind turbine generator with BTB NPC converters.
15. Figure 2.15 Type IV WTG with a diode rectifier and 2L‐VSC.
16. Figure 2.16 Type IV WTG with diode rectifier, 2L‐boost converter and 2L‐VSC.
17. Figure 2.17 Type IV wind turbine generator with six‐phase generator and parallel 2L‐VSC modules.
18. Figure 2.18 Type IV wind turbine generator with six‐phase generator, series connected 2L‐VSCs and 3L‐VSC.
19. Figure 2.19 Direct matrix converter application to variable‐speed wind turbine generators (Type III and Type IV)
Chapter 03
1. Figure 3.1 Annual failure rate and downtime per failure from German land‐based wind turbine failures database
2. Figure 3.2 Overall mass and relative cost of different gearbox configurations for a 2.5 MW wind turbine
3. Figure 3.3 Failure modes of wind turbine gears as a function of torque and pitch line velocity
4. Figure 3.4 Two‐mass model of the wind turbine drivetrain.
5. Figure 3.5 Drivetrain decoupled analysis method.
6. Figure 3.6 Spectrum of the gear angular acceleration (torsional) and bearing equivalent load for a 5‐MW gearbox
7. Figure 3.7 MBS model of the NREL GRC 750‐kW gearbox
8. Figure 3.8 MBS model of the 5‐MW reference gearbox
9. Figure 3.9 MBS topology of the first stage of a 5‐MW gearbox
10. Figure 3.10 Bearing stiffness models.
11. Figure 3.11 Line of action in a gear pair.
12. Figure 3.12 Sun gear orbit in the floating design with a misaligned planet gear
13. Figure 3.13 Limit state design of wind turbine gearbox
14. Figure 3.14 Contribution of different wind speeds in the long‐term exceedance probability of the expected annual extreme value (5‐MW gearbox)
15. Figure 3.15 Proposed modified ISO 6336‐6 procedure for wind turbine gear design with respect to the long‐term fatigue damage
16. Figure 3.16 Direct method versus Weibull fitted method
17. Figure 3.17 Cumulative distribution function (CDF) of the gear tooth root bending stress range for the 1st stage sun gear at rated wind speed.
18. Figure 3.18 Contribution of damages from each wind speed to the long‐term 20‐year damage
19. Figure 3.19 Flowchart of structural reliability analysis.
20. Figure 3.20 Illustration of model uncertainties used for gear tooth fatigue reliability analysis
21. Figure 3.21 Service life reliability index, β, and probability of failure, P_f, of gears
22. Figure 3.22 Floating wind turbine models: spar, TLP, semi‐submersible 1 and semi‐submersible 2 (Nejad et al., 2015b).
23. Figure 3.23 Mean and standard deviation of forces and moments applied on the main shaft in spar, TLP, semi‐1, semi‐2 and land‐based turbines
24. Figure 3.24 Fatigue damage comparison factor (χ) for INP‐B bearing in spar, TLP, semi‐1 and semi‐2 wind turbines.
25. Figure 3.25 Spectrum of INP‐B equivalent load for EC6.
26. Figure 3.26 Error function of the first stage gear, 750‐kW gearbox.
27. Figure 3.27 Bearing fault detection in the third stage, 750‐kW gearbox
28. Figure 3.28 Distribution fitted to fault and fault‐free data
29. Figure 3.29 Vulnerability map for the 750‐kW gearbox
30. Figure 3.30 Vulnerability map for the 5‐MW gearbox
31. Figure 3.31 Input loadings on the main shaft (LC1 is shown in darker gray).
32. Figure 3.32 Radial force on INP‐A and gear mesh force (LC1 is shown in lighter gray).
33. Figure 3.33 Gear mesh force in 2nd and 3rd stages (LC1 is shown in lighter gray).
34. Figure 3.34 Axial and radial forces on INP‐B (LC1 is shown in lighter gray).
35. Figure 3.35 5‐MW reference gearbox schematic layout.
36. Figure 3.36 5‐MW gearbox topology.
37. Figure 3.37 5‐MW gearbox MBS model.
38. Figure 3.38 5‐MW gearbox MBS model kinematic tree.
Chapter 04
1. Figure 4.1 Bottom‐fixed support structures (l–r): monopile, tripod, jacket, gravity‐based structure.
2. Figure 4.2 Traditional (left) and twisted jacket designs
3. Figure 4.3 Floating wind turbines. (a) Spar: Hywind from Statoil (Statoil, 2011). (b) Semi‐submersible: WindFloat from Principle Power (Principle Power, 2011). (c) Semi‐submersible: OO Star from Dr techn Olav Olsen (Personal communication with Trond Landbø). (d) Barge: from IDEOL (IDEOL, 2016). (e) TLP: from Glosten (Moon III and Nordstrom, 2010). (f) TLB: from IFE
4. Figure 4.4 Simplified model of the bottom‐fixed turbine.
5. Figure 4.5 Obtained frequencies for variable diameter, compared to 1p and 3p ranges and typical wave spectrum.
6. Figure 4.6 2‐D added mass for simple shapes (Newman, 1977). The x direction is denoted 1, while y is 2, and rotation about the z‐axis is 6.
7. Figure 4.7 OC4 semi‐submersible modelled in SIMA.
8. Figure 4.8 Obtained estimates of the natural frequencies of the OC4 semi‐submersible.
9. Figure 4.9 (Partial) time series and spectrum of thrust force from bottom‐fixed NREL 5‐MW OWT in turbulent wind, 15 m/s.
10. Figure 4.10 Yaw response of 5‐MW spar and TLP FWTs induced by a combined blade pitch fault and shutdown at t = 0, rated wind speed and corresponding long‐crested waves.
11. Figure 4.11 Example of wave elevation (left) and load effects (bending moment in the monopile near the free surface), comparing first and second order waves in 20 m water depth, H_s 6.5 m, T_p 13 s. Simulations in SIMA software (MARINTEK).
12. Figure 4.12 Comparison of the shear force in fore–aft direction at the mean sea level (MSL) under various load conditions. Ice thickness 0.4 m, ice drifting speed = 0.5 m/s, U_w 11.4 m/s, waterline diameter 8 m
13. Figure 4.13 Time domain realization (left) and spectra (right) of a short‐term wind and wave condition. Black curves show theoretical values of the spectra.
14. Figure 4.14 Example of global FE model strategy for a TLP FWT: structural model, external load models and active mode shapes in the tendons and tower (from pitch decay tests).
15. Figure 4.15 Nongeometric rotor scaling. Left: drag‐disk tests of a combined wind and wave energy converter. Right: (a) performance‐scaled low Reynolds number blade; (b) corresponding geometrically scaled blade
16. Figure 4.16 Hybrid testing
17. Figure 4.17 Real‐time hybrid model tests of floating wind turbines. Left: ducted fan approach ; right: actuator approach (Bachynski et al., 2016).
Chapter 05
1. Figure 5.1 Steady‐state aerodynamic (rotor torque times speed) and electrical (at the network‐side terminals of the transformer) power coefficients of the 10‐MW ORT. The electrical efficiency is a function of the power and speed, and the plot has been generated using a constant wind speed of 10 m/s.
2. Figure 5.2 The steady‐state operating schedule of the ORT, in terms of blade pitch angle versus tip‐speed ratio, overlayed on the C_P diagram. The wind speeds are listed beside the operating schedule curve.
3. Figure 5.3 Normalized spectra of the ocean wave load, rotor asymmetric yaw moment and rotor thrust, representative of normal operation.
4. Figure 5.4 A high‐level block diagram that could represent a wind turbine or wind power plant employing feedback control.
5. Figure 5.5 A controller consisting of a linear state observer (a typically low‐order embedded model of the wind turbine) and state‐based control law u = K_c ×_c.
6. Figure 5.6 The active power set‐point stage. Maximum power‐point tracking is active in Region I, and generator speed tracking is active when operating at the minimum rotor speed cut‐off.
7. Figure 5.7 The generator torque/current controller. This consists of a function that controls the generator in order to provide a commanded active power at the network‐side terminals of the turbine’s transformer, and a virtual induction generator for damping the driveshaft. Active damping of tower side‐to‐side resonance may also be implemented at this level of control.
8. Figure 5.8 The blade pitch controller. Not all the pathways shown in the rotor speed control function are active simultaneously. Either the speed reference is fed in externally, it is a function of the estimated windspeed (through , or the gains are set to zero. In the latter case the blade pitch may be prescribed directly as a function of the estimated windspeed.
9. Figure 5.9 Relative velocity components local to an aerofoil section, for computing the angle‐of‐attack. The vectors should properly be pointing at the one‐quarter chord location, but for the sake of clarity they are sketched with reference to the leading edge.
10. Figure 5.10 Topology and coordinate systems of the finite beam element model representing the wind turbine. Grey nodes are fixed, black nodes rotate with the rotor and white nodes are joints.
11. Figure 5.11 An equivalent circuit model of the wind turbine electrical system, suitable for predicting the power at the network‐side terminals of the transformer, at frequencies below the electrical frequency.
12. Figure 5.12 Linearization of steady‐state wind turbine aerodynamics about a mean operating wind speed of 10 m/s.
13. Figure 5.13 Spectra of blade root flapwise bending moments for a 5‐MW stall‐regulated wind turbine.
14. Figure 5.14 Spectra of blade root edgewise bending moments for a 5‐MW stall‐regulated wind turbine.
15. Figure 5.15 Spectra of rotor speed, fore–aft nacelle displacement and blade pitch angle or pitch acceleration, for the NREL 5‐MW wind turbine operating normally in winds of 16 m/s (at left) and 20 m/s (at right). The pitch angle spectrum at lower left reflects the fact that the blade abruptly hits the 0° limit at the control‐mode transition between Region I and II, which is, of course, not represented in the linear analysis, though the effect is amplified by the lack of a pitch actuator model for the NREL 5‐MW wind turbine.
16. Figure 5.16 Transfer functions from rotor‐average wind speed to electrical power and rotor speed, plotted alongside the spectrum of rotor‐average axial turbulence. The timescale of rotor speed and power tracking is faster than the high energy, low frequency fluctuations in the effective turbulence.
17. Figure 5.17 The torque control response to a rotor‐average wind speed input, comparing rigid and elastic structural models.
18. Figure 5.18 A control architecture that implements maximum power‐point tracking (Equation 5.52).
19. Figure 5.19 Projections of the transfer functions associated with each mode onto the phase of the overall transfer function, computed with a full set of modes. This indicates the degree to which the individual modes contribute to the net transfer function.
20. Figure 5.20 The transfer function from rotor‐average wind speed to generator torque, comparing models of three and eight modes against the full model (about 600 modes).
21. Figure 5.21 The elementary generator torque and blade pitch control functions considered in this section.
22. Figure 5.22 An example of the loop transfer function for rotor speed control.
23. Figure 5.23 Transfer functions (top) and spectra (bottom) of blade pitch angle and rotor speed for three values of the low‐pass filter corner frequency α_β.
24. Figure 5.24 Transfer functions from rotor‐average wind speed to blade pitch angle, rotor speed and generator torque. Magnitudes are plotted at the left and phases at the right.
25. Figure 5.25 The influence of gains on the blade pitch, rotor speed and tower fore–aft response to a rotor‐average wind speed input. The natural frequency and damping ratio of the rotor speed control (RSC) and speed integral (SI) modes are listed. Together, these indicate the properties of the resonant peak in the pitch and speed responses.
26. Figure 5.26 Transfer functions from rotor‐average wind speed to blade pitch and rotor speed, illustrating the prediction obtained using three modes.
27. Figure 5.27 A sketch of the first torsional mode of the ORT, when operating in a uniform 12 m/s wind. The deformed position of the rotor, oriented at an arbitrary azimuth angle of 0°, is drawn in black and the undeformed position in grey. The still waterline and seabed elevations are also indicated. The dimensions are to scale, although displacements are exaggerated.
28. Figure 5.28 Transfer functions from a (fictitious) torsional moment M applied at the hub to shaft speed and generator torque. Cases with and without active damping are compared, illustrating the trade‐off between the damping of shaft oscillations and fluctuations in generator torque.
29. Figure 5.29 Transfer functions between a torsional moment applied at the rotor hub and the shaft speed and generator torque response.
30. Figure 5.30 Band‐pass filter parameters.
31. Figure 5.31 Transfer functions from a side‐to‐side force at the mean waterline to nacelle side‐to‐side displacement and generator torque. Two modes predict the resonant response and control action.
32. Figure 5.32 Left: transfer functions from a side‐to‐side force at the mean waterline to tower base bending moments. The water depth of 30 m is evident in the low frequency asymptote of the side‐to‐side moment M_x. Right: transfer functions from wind speed to electric power and from waterline side‐to‐side force to electric power.
33. Figure 5.33 The response of the ORT under normal operation in a 12 m/s wind, where the waves are misaligned by 20°. The integrals indicate the variance (square of the standard deviation) of the signals.
34. Figure 5.34 Spectra in a case where the wind speed is near cut‐in and waves approach from 90°.
35. Figure 5.35 A control architecture for active damping of tower fore–aft resonance, in addition to the control of rotor speed in Region II.
36. Figure 5.36 Transfer functions from a fore–aft force applied at the mean waterline to nacelle fore–aft displacement and blade pitch.
37. Figure 5.37 Transfer functions from fore–aft waterline force to (left) the fore–aft bending moment at the tower base and (right) the blade pitch. Active damping decreases the moment and increases the pitch action.
38. Figure 5.38 Spectra during normal operation in a turbulent 12 m/s wind, showing the effect of active damping on the tower base bending moment and blade pitch action.
39. Figure 5.39 The backwards edgewise whirling mode, which is excited by asymmetric components of the wind speed relative to the rotor yaw axis.
40. Figure 5.40 Transfer functions from a fluctuating yaw imbalance in the rotor‐average wind speed, to yaw moments in the nacelle structure.
41. Figure 5.41 (A: Top) spectra of blade root flapwise and edgewise moments, units of MN²m²/Hz, for a single blade in the rotating frame. (B: Top) spectra of blade pitch for a single blade’s actuator, in the rotating frame. (A: Bottom) spectra of yaw bending moments in the nacelle; the tilt moment spectra are almost identical. (B: Bottom) spectra of fore–aft and side‐to‐side bending moments in the tower, at the mudline. Units of MN²m²/Hz.
42. Figure 5.42 Left: the steady‐state aerodynamic C_P(λ, β) characteristic of the ORT, with the basic operating schedule.Right: the same C_P contours showing the feasible bounds for curtailed operation, at three wind speeds.
43. Figure 5.43 Steady‐state electrical power versus rotor speed operating schedules. The power level (MW) and blade pitch (deg) are read to the Y axis. The corresponding wind speed in m/s is listed beside the power curve. The blade pitch is also shown. Upper left: the nominal operating schedule. Upper right: set‐point of 4 MW. Lower left: 20% reserve. Lower right: 3 MW delta.
44. Figure 5.44 The influence of integral gain on power command tracking performance, viewed in the frequency domain. A unit magnitude (plot on top) and near‐zero phase (plot on bottom) implies accurate tracking.
45. Figure 5.45 The influence of proportional gain on power command tracking performance.
46. Figure 5.46 Retuning of the controller to accommodate the addition of a notch filter at the first natural frequency of the tower.
47. Figure 5.47 The response of the ORT to a unit step command in the power when operating at . Tower displacements, rotor speed and blade pitch have been multiplied by . In the figure (upper left), the blade pitch eventually plateaus at about rad/W.
48. Figure 5.48 Power command tracking under (left) a 1‐s ramp and (right) a 5‐s ramp. The wind speed is 10 m/s and the turbine is operating initially at 90% of its nominal power.
Chapter 06
1. Figure 6.1 Radial cluster topology.
2. Figure 6.2 Single‐sided ring cluster topology.
3. Figure 6.3 Double‐sided ring topology.
4. Figure 6.4 Star topology.
5. Figure 6.5 Multiring topology (four strings).
6. Figure 6.6 Collector topology of the Horns Rev 1 offshore wind farm.
7. Figure 6.7 Collector topology of the Great Gabbard offshore wind farm.
8. Figure 6.8 Basic DC collector system.
9. Figure 6.9 Alternative DC collector system.
10. Figure 6.10 Series DC collector topology.
11. Figure 6.11 Hybrid DC topology.
12. Figure 6.12 The AC hub concept for offshore wind farms.
13. Figure 6.13 The DC general ring topology.
14. Figure 6.14 The DC star topology.
15. Figure 6.15 The DC star with a general ring topology.
16. Figure 6.16 The wind farm ring topology.
17. Figure 6.17 Single line diagram of the electrical circuit in the Horns Rev 3 offshore substation.
18. Figure 6.18 Switchgear configuration in the Horns Rev 1 wind turbines.
19. Figure 6.19 Switchgear configuration for high selectivity protection of offshore wind farms.
20. Figure 6.20 Protection zones of a wind farm.
21. Figure 6.21 Electronic circuit of the crowbar protection.
22. Figure 6.22 Electronic circuit of the DFIG DC chopper protection.
23. Figure 6.23 Circuit diagram of the DC chopper protection for fully‐rated converter wind turbines.
24. Figure 6.24 Circuit diagram of the DC series dynamic resistor for fully‐rated converter wind turbines.
25. Figure 6.25 Characteristic of the underimpedance relay for feeder protection.
26. Figure 6.26 Busbar protection configuration.
Chapter 07
1. Figure 7.1 Decision problems classified by time scale for offshore wind O&M.
2. Figure 7.2 Illustration of the distinction between simulation methods and mathematical programming methods for solving an optimization problem.
3. Figure 7.3 Concept sketch of O&M optimization by finding the optimal trade‐off between minimizing O&M costs and maximizing turbine availability.
4. Figure 7.4 Overview over operational, tactical and strategic decision support tools and concepts developed in NOWITECH and related projects, with examples of what problems they can address.
5. Figure 7.5 Schematic of inputs and outputs for the NOWIcob model.
6. Figure 7.6 Simplified flow scheme of the model
7. Figure 7.7 Overview of vessel fleet optimization tool.
8. Figure 7.8 Overview of a small offshore wind farm O&M routing and scheduling problem.
9. Figure 7.9 Possible solution for the small routing and scheduling example.
10. Figure 7.10 Illustration of possible synergetic interaction between vessel fleet optimization models and simulation model (NOWIcob).
11. Figure 7.11 Concept drawing of remote presence system in a wind turbine nacelle.
12. Figure 7.12 Results from NOWIcob cost‐benefit analysis.
13. Figure 7.13 Left: Prototype used in usability tests, Right: Laboratory with mock‐up industrial equipment used in usability tests.
14. Figure 7.14 Results from the last laboratory usability test. Top: Detection rates of error markers and paper clips for manned and remote inspections. Bottom: NASA‐TLX workload assessment results, where lower values indicate an advantageous low workload.
15. Figure 7.15 Left: Latest high fidelity prototype. Right: Sample image from pilot installation.
16. Figure 7.16 O&M cost contributions and lost revenue due to downtime for different O&M vessel fleets as estimated by NOWIcob.
17. Figure 7.17 Illustration of possible synergetic interaction between different decision support tools.
Chapter 08
1. Figure 8.1 A PI control strategy for active power control at the PCC.
2. Figure 8.2 Hierarchical structure of the wind farm controller.
3. Figure 8.3 Power adjusting controller (PAC) layout.
4. Figure 8.4 Internal structure of the PAC.
5. Figure 8.5 Design operating curve over the full envelope operation and the thresholds for the wind farm control strategy.
6. Figure 8.6 Adjusted versus unadjusted power.
7. Figure 8.7 Power outputs from each turbine.
8. Figure 8.8 Individual curtailment: curtailment of each turbine.
9. Figure 8.9 Adjusted power by individual curtailment versus adjusted power by the wind farm control strategy.
Chapter 09
1. Figure 9.1 Offshore wind energy system.
2. Figure 9.2 Choice of transmission technology for different wind farm capacity and distance from shore
3. Figure 9.3 Basic configuration of HVAC interconnection of offshore wind farm to the grid
4. Figure 9.4 Annual cable efficiency as function of wind farm maximum instantaneous production for different voltage regulation intervals (220 kV, 200 km cable).
5. Figure 9.5 Schematic of a typical VSC‐HVDC system
6. Figure 9.6 Equivalent circuit of a VSC‐HVDC transmission system.
7. Figure 9.7 Vector diagram representation of a VSC‐HVDC system: (a) sending end; (b) receiving end.
8. Figure 9.8 VSC‐HVDC circuit.
9. Figure 9.9 Block diagram of the VSC‐HVDC control system.
10. Figure 9.10 Block diagram of the inner controller.
11. Figure 9.11 Block diagram of the active and reactive controller.
12. Figure 9.12 Block diagram of the DC and AC voltage controller.
13. Figure 9.13 Automated design process of offshore grid applying Net‐Op. The illustration consider a case with a cluster of seven wind farms (w).
14. Figure 9.14 Examples of possible multiterminal configurations for wind farm integration: (a) double‐input single‐output configuration; (b) double‐input double‐output configuration.
15. Figure 9.15 Example of a four‐terminal network.
16. Figure 9.16 Multiterminal HVDC system for offshore wind farms, oil/gas platform and onshore network (Haileselassie et al., 2008).
17. Figure 9.17 Simplified LFAC transmission system.
18. Figure 9.18 Circuit diagram of a 36‐pulse cycloconverter.
19. Figure 9.19 Circuit diagram of a matrix converter.
20. Figure 9.20 Circuit diagram of a back‐to‐back converter.
21. Figure 9.21 An offshore substation
22. Figure 9.22 Typical structures of an SVC: (a) a TCR with a fixed capacitor; (b) TCR with a TSC.
23. Figure 9.23 Simplified voltage control block diagram of a typical SVC.
24. Figure 9.24 SVC capacitance and inductance values.
25. Figure 9.25 Schematic diagram of a STATCOM connected to an AC system.
26. Figure 9.26 A large FSIG‐based wind farm connected to the system with a STATCOM.
27. Figure 9.27 Network set up used to illustrate the contribution of a STATCOM plus energy storage to facilitate the integration of an FSIG‐based wind farm
Chapter 10
1. Figure 10.1 Main elements of large interconnected electric power systems.
2. Figure 10.2 Overview of the synchronous electrical grid areas in Europe constituting the five regional groups (From ENTSO‐E, 2015).
3. Figure 10.3 System frequency as a measure of power balance.
4. Figure 10.4 Tasks and timescales in power balancing control.
5. Figure 10.5 Typical shape of continuous and reduced output regions.
6. Figure 10.6 Typical steady‐state operating region
7. Figure 10.7 Typical shape of fault ride through capability plot
8. Figure 10.8 Control functions in an offshore wind energy system.
9. Figure 10.9 Outline of braking resistor control.
10. Figure 10.10 Control structure using measured rotational speed as input for determining the optimum power set‐point; the modulation signal, ΔP_ref, provides system support with input from system frequency.
11. Figure 10.11 Outline of control structure for the generator‐side converter with a PSS for damping torque oscillations.
12. Figure 10.12 Outline of system for controlling the reactive power output from the grid‐side converter.
Chapter 11
1. Figure 11.1 Overview of electricity markets and their time horizons in the Nordic power system (Grande et al., 2008).
2. Figure 11.2 Market coupling resulting in different zonal prices because of limited transfer capacity.
3. Figure 11.3 Illustration of the impact of wind power on market price.
Appendix
1. Figure A.1 A sketch of the nacelle and drivetrain topology; not to scale, and with structural details omitted. The blades (not shown), hub, driveshaft and generator rotor rotate, while the generator stator, nacelle nose and nacelle turret are stationary. Bearings are shaded grey. The driveshaft is supported by two main bearings inside the nacelle nose. The generator rotor is external. The rotor housing is supported by an additional bearing mounted outside the nacelle nose.
2. Figure A.2 Some key dimensions and stiffness properties of the driveshaft.
3. Figure A.3 Some key dimensions and stiffness properties of the nacelle nose.
4. Figure A.4 Key dimensions, in mm, of the 10‐MW generator. The outer section is the stator, showing the winding slots (but not the actual windings), while the inner section is the rotor, showing one full permanent magnet, 20 mm thick, and the gaps to the adjacent permanent magnets of opposite polarity. Only the electromagnetically active materials are shown; the mechanical support structure has not been designed. Detailed features of the stator tooth geometry are not available and are not included in the figure.
5. Figure A.5 Winding and phase sequence. The windings are wound around the tooth separating adjacent slots; the teeth enclosed by windings are shaded grey. There are two windings of the same phase in sequence. The tooth in between is not enclosed in a winding; these teeth are shown as white. Adjacent sequences of AAAA, BBBB, CCCC windings are wound in alternating directions. The arrow shows the direction of rotor motion such that the phase of A leads B. For each phase, there are six parallel paths consisting of six windings in series.

Offshore Wind Energy Technology