Systems and methods for reducing loads induced in a floating offshore structure

Abstract

A floating offshore wind turbine includes a buoyant tension leg platform with radially extending braces. A tensioned mooring line and tensioning device is connected to each brace. A control system in communication with the tensioning devices determines determine a wind condition of wind acting on the wind turbine and, based on the wind condition, determines a set length of the mooring lines to induce a pitch offset in the tension leg platform and a lean angle of the tower into the wind The lean angle is computed to generate a gravity moment in the wind turbine that offsets a bending moment induced in the tower from the wind.

Description

SYSTEMS AND METHODS FOR REDUCING LOADS INDUCED IN A FLOATING OFFSHORE STRUCTURESTATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

[0001] This invention was made with Government support under Contract No. DE-AR0001177 awarded by the Department of Energy' (DOE). The Government has certain rights in the invention.FIELD

[0002] The present disclosure relates in general to floating offshore structures, and more particularly to a system and method for reducing loads in a tower structure supported by a floating tension leg platform (TLP).BACKGROUND

[0003] Floating offshore structures (e.g., offshore wind turbines and oil rigs) may utilize a buoyant platform that is tethered to the seabed, as opposed to structures that are directly embedded in or anchored to the seabed.

[0004] Several configurations have been proposed for the buoyant platform component of the offshore structures. For example, the buoyant platform may employ floater elements in the form of substantially hollow floater tanks that, in use, are arranged below the mean sea level and provide an excess buoyancy force to the structure. These buoyant structures are maintained floating under the mean sea level by taut mooring lines that are continuously tensioned by the excess buoyancy force. Designs have been developed such as the “taught leg buoy” floating wind turbine having a slender cylindrical buoy attached to two sets of tensioned mooring lines inclined relative to the seabed and connected to gravity anchors. Another example used for offshore wind turbines (and oil platforms) is the “tension leg platform” (TLP) floating structure with centralized or distributed buoyancy wherein tensioned mooring lines (vertical or inclined) are connected between gravity anchors on the seabed and arms extending radially outward from a central body with respect to the vertical axis of the wind turbine.

[0005] Structural and dynamic stability are important requirements for deep-water floating offshore structures in general, and offshore wind turbines in particular. Design load analysis criteria must be satisfied before an offshore wind turbine is certified for operation, such analysis can be conducted using aeroelastic and hydrodynamic simulation tools such as FAST (Fatigue, Aerodynamics, Structures, and Turbulence), OpenFAST, and other available simulation tools.

[0006] Wind turbines on floating support platforms are subject to significant aerodynamic loads from wind conditions and hydrodynamic loads from wave effects. These loads can significantly affect the operational lifespan of the wind turbine. For example, as offshore wind turbines become larger and larger, aerodynamic forces acting on the blades and rotor become more pronounced and induce detrimental bending moments in the lower sections of the tower and column components of the TLP platform. The industry is continuously seeking ways to minimize these tower / column fatigue loads without adversely affecting power production (AEP) from the wind turbine.BRIEF DESCRIPTION

[0007] Aspects and advantages of the disclosure will be set forth in part in the following description, or may be obvious from the description, or may be learned through practice of the disclosure.

[0008] An embodiment of the invention includes a floating offshore wind turbine system that includes a nacelle, a rotor with a plurality of blades, and a tower, wherein the nacelle and rotor are mounted atop the tower. The tower is supported on a buoyant tension leg platform (TLP) that includes a plurality of arms extending radially outward relative to a vertical axis of the tower. The TLP may include a buoyant central body, wherein the arms extend radially outward from the central body. A tensioned mooring line is connected to each of the braces, the mooring lines extending to a seabed anchor. A controllable tensioning device is configured with each of the mooring lines to adjust and maintain a length of the respective mooring line. A control system is in communication with each of the tensioning devices, wherein the control system is configured to perform the following functions: determine a wind condition of wind acting on the rotor and blades; based on the windcondition, determine a set length of one or more of the mooring lines to induce a pitch offset in the tension leg platform and a lean angle of the tower into the wind, wherein the lean angle is measured relative to the vertical axis of the tower in a zero wind condition and is computed to generate a gravity moment in the wind turbine that offsets a bending moment that would be induced in the tower from the wind; and control the tensioning devices to change the length of the one or more mooring lines to the set length.

[0009] In a particular embodiment, the wind condition is directly determined by measurement of any one or combination of: wind speed, wind direction, or wind turbulence. These parameters may be sensed or measured by local sensors mounted on the wind turbine or by a model-based tool. In one example, the wind condition may be an average wind speed computed over a predetermined time.

[0010] In another embodiment, the wind condition may be indirectly determined or inferred from other sensors, including rotor speed sensors, accelerometers, or blade root bending moment sensors.

[0011] The control system may be configured to perform the functions when the wind turbine is in various operational and shutdown states.

[0012] The tensioning devices may be variously configured. For example, a respective tensioning device may be located within each of the arms of the tension leg platform. Alternatively, the tensioning devices may be centrally located within the central body of the tension leg platform, wherein the mooring lines run from the tensioning devices through the braces.

[0013] Any manner of conventional powered devices may be utilized as a tensioning device. For example, the tensioning devices may be one or a combination of a powered windlass, capstan, or winch. The tensioning devices may be supplied with electrical power directly from the wind turbine.

[0014] In certain embodiments, the control system may be configured to determine which of the mooring lines is to be adjusted with the set length based on a sensed yaw position of the rotor or a sensed wind direction.

[0015] The control system may be variously configured. For example, the control system may include a dedicated controller for the tensioning devices that receives input from various sensors. Alternatively, this dedicated controller may be incommunication with and receive inputs from the wind turbine central controller. In still another embodiment, the wind turbine central controller may be configured to perform all of the functions of the control system, wherein the tensioning devices are in direct communication with the wind turbine central controller.

[0016] The present invention also encompasses various embodiments of a method for reducing mechanical loads in a tower or cylinder component of an offshore wind turbine, wherein the wind turbine includes: a nacelle; a rotor with a plurality of blades; a tower, the nacelle and rotor mounted atop the tower; a buoyant tension leg platform having a plurality of arms extending radially outward relative to a vertical axis of the tower; a tensioned mooring line connected to each of the arms, the mooring lines extending to a seabed anchor; and a controllable tensioning device configured with each of the mooring lines to adjust and maintain a length of the mooring line. The method includes determining a condition of wind acting on the rotor and blades; based on the wind condition, determining a set length of one or more of the mooring lines to induce a pitch offset in the tension leg platform and a lean angle of the tower into the wind, wherein the lean angle is measured relative to the vertical axis of the tower in a zero wind condition; computing the lean angle to generate a gravity moment in the wind turbine that offsets a bending moment induced in the tower from the wind; and controlling the tensioning devices to change the length of the one or more mooring lines to the set length.

[0017] Embodiments of the method may include determining the wind condition by measurement of any one or combination of: wind speed, wind direction, or wind turbulence. These parameters may be sensed or measured by local sensors mounted on the wind turbine or by a model-based tool. In one example, the wind condition may be an average wind speed computed over a predetermined time.

[0018] In another embodiment, the wind condition may be indirectly determined or inferred from other sensors, including rotor speed sensors, accelerometers, or blade root bending moment sensors.

[0019] When the wind turbine is in an operational power-producing state, the method may include determining the lean angle to compensate for a downwind thrust induced in the tower from operation of the wind turbine.

[0020] In some embodiments, the lean angles may be predetermined for different values of the wind condition and stored in a look-up table for access by a control system. Alternatively, the lead angle may be computed in near real time based on current sensed wind conditions.

[0021] Embodiments may also include compensating for hydro loads induced in the tower by detecting a sea state condition and determining an adjustment to the set length of the mooring lines based on the sea state condition to compensate for motion of the tension leg platform caused by the sea state. The motion of the tension leg platform caused by the sea state may be any one or combination of: roll, pitch, yaw, sway, surge, or heave of the platform and / or tower.

[0022] These and other features, aspects and advantages of the present disclosure will become better understood with reference to the following description and appended claims. The accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate embodiments of the disclosure and, together with the description, serve to explain the principles of the disclosure.BRIEF DESCRIPTION OF THE DRAWINGS

[0023] A full and enabling disclosure of the present disclosure, including the best mode thereof, directed to one of ordinary skill in the art, is set forth in the specification, which makes reference to the appended figures, in which:

[0024] Fig. 1 illustrates an embodiment of a tension leg platform wind turbine according to the present disclosure;

[0025] Fig. 2A illustrates a tension leg platform wind turbine in a standstill state and low wind conditions;

[0026] Fig. 2B illustrates the wind turbine of Fig. 2A in an operational state wherein a thrust surge in the downwind direction is induced in the wind turbine;

[0027] Fig. 3 illustrates the wind turbine of Fig. 2A with a lean angle into the wind in accordance with aspects of the present disclosure;

[0028] Fig. 4 illustrates movements induced on a tension leg platform wind turbine from sea state conditions; and

[0029] Fig. 5 is a block diagram of method embodiments according to the present disclosure.

[0030] Repeat use of reference characters in the present specification and drawings is intended to represent the same or analogous features or elements of the present disclosure.DETAILED DESCRIPTION

[0031] Reference now will be made in detail to embodiments of the disclosure, one or more examples of which are illustrated in the drawings. Each example is provided by way of explanation of the disclosure, not limitation of the disclosure. In fact, it will be apparent to those skilled in the art that various modifications and variations can be made in the present disclosure without departing from the scope or spirit of the disclosure. For instance, features illustrated or described as part of one embodiment can be used with another embodiment to yield a still further embodiment. Thus, it is intended that the present disclosure covers such modifications and variations as come within the scope of the appended claims and their equivalents.

[0032] Fig. 1 is a perspective view of an exemplary offshore wind turbine 10 supported on a tension leg platform (TLP) 60. The wind turbine 10 generates electrical power from wind energy. The wind turbine 10 described and illustrated herein is a horizontal-axis configuration. However, in some embodiments, the wind turbine 10 may have a vertical-axis configuration (not shown). In use, the wind turbine 10 may be coupled to an electrical load, such as a power grid, for receiving electrical power therefrom to drive operation of wind turbine 10 and / or its associated components and / or for supplying electrical power generated by the wind turbine 10 thereto. Although only one wind turbine 10 is shown in Fig. 1, a plurality of the wind turbines 10 may be grouped together, sometimes referred to as a “wind farm.”

[0033] The wind turbine 10 includes a body or nacelle 12 and a rotor (generally designated by 14) that rotates with respect to nacelle 12 about an axis of rotation 20. The nacelle 12 is mounted on a tower 16 having a suitable height to enable the wind turbine 10 to function as described herein. In the depicted embodiment, the wind turbine 10 is an offshore system configured to float in a body of water, as explained in greater detail below.

[0034] The rotor 14 includes a hub 22 and a plurality of blades 24 extending radially outwardly from the hub 22 for converting wind energy into rotational energy. The blades 24 each have a length that allows wind turbine 10 to function as described herein. For example, in some embodiments, the blades 24 may be between about fifty and about one-hundred meters long (or longer).

[0035] Still referring to Fig. 1, the wind turbine 10 includes an electrical generator 26 coupled to the rotor 14 for generating electrical power from the rotational energy generated by rotor 14. The generator 26 may be any suitable type of electrical generator, such as, but not limited to, a wound rotor induction generator, a double-fed induction generator (DFIG, also known as dual-fed asynchronous generators), a permanent magnet (PM) synchronous generator, an electrically-excited synchronous generator, and a switched reluctance generator. The rotor 14 includes a rotor shaft 28 coupled to rotor hub 22 for rotation therewith. The generator 26 in the depicted embodiment is a “direct-drive” generator coupled directly to the rotor shaft 28 without an intervening gearbox such such that rotation of rotor shaft 28 drives rotation of the generator rotor, and therefore operation of generator 26.

[0036] The wind turbine 10 may include a variable blade pitch system coupled to the hub 22 for controlling (e.g., changing) the pitch angle of the blades 24 with respect to a wind direction. A central system controller 44 may be coupled to the pitch system to control operation of the pitch system. Pitch actuators may include any suitable structure, configuration, arrangement, means, and / or components, whether described and / or shown herein, such as, but not limited to, electrical motors, hydraulic cylinders, springs, and / or servomechanisms. Moreover, the pitch actuators may be driven by any suitable means, whether described and / or shown herein, such as, but not limited to, hydraulic fluid, electrical power, electro-chemical power, and / or mechanical power, such as, but not limited to, spring force.

[0037] The central system controller 44 generally controls operation of the wind turbine 10, including individual components or systems thereof. The system controller 44 may be mounted within the nacelle 12 (shown in Fig. 1) or remote from the nacelle 12. The system controller 44 may be used for overall system monitoring and control including, without limitation, pitch and speed regulation, high-speed shaft and yaw brake application, yaw and pump motor application, and / or fault monitoring.Alternative distributed or centralized control architectures may be used in some embodiments.

[0038] The wind turbine 10 includes a plurality of sensors, for example, sensors 50, 52, 56, and 80 for detecting and measuring a variety of parameters including, operating conditions, atmospheric conditions, and sea state conditions. For example, one or more sensors 50 may be configured on the nacelle 12 or tower 16 for detecting wind speed and direction. The wind sensors 50 may be located remote from the wind turbine 10 and in communication with the controller 44. A sensor 52 may be configured to measure rotational speed of the rotor shaft 28, and / or an electrical output of generator 26. Each sensor may be an individual sensor or may include a plurality of sensors. The sensors are coupled to or otherwise in communication with the system controller 44 for transmitting one or more measurement signals to the system controller 44 for processing of the signals.

[0039] Referring to Fig. 1, the wind turbine 10 may also include a tower inclination sensor 56, such as an inclinometer and / or an acceleration sensor. The tower inclination sensor 56 measures an inclination or “lean” angle 75 shown in Fig. 3 (including lean direction). The tower inclination sensor 56 may be positioned on or within nacelle 12, on or within tower 16, and / or in any position on or within the wind turbine 10 that allows tower inclination sensor 56 to function as described herein.

[0040] The system controller 44 may include a bus or other communications device to communicate information. One or more processors are coupled to the bus to process information, including information from the various sensors. The processors may include at least one computer. As used herein, the term computer broadly refers to a processor, a microcontroller, a microcomputer, a programmable logic controller (PLC), an application specific integrated circuit, and other programmable circuits, and these terms are used interchangeably herein.

[0041] The system controller 44 may also include one or more random access memories (RAM) and / or other storage devices coupled to the bus to store and transfer information and instructions to be executed by the processors. The system controller may also include one or more read only memories (ROM) and / or other static storage devices coupled to bus to store and provide static (i.e., non-changing) information and instructions to the processor. The processors may process information transmittedfrom a plurality of electrical and electronic devices that may include speed and power transducers. Instructions that are executed may include resident conversion and / or comparator algorithms. The execution of sequences of instructions is not limited to any specific combination of hardware circuitry and software instructions.

[0042] The system controller 44 may also include a sensor interface that allows system controller 44 to communicate with the various sensors. The sensor interface may include one or more analog-to-digital converters that convert analog signals into digital signals that can be used by the processors.

[0043] Referring again to Fig. 1, the offshore wind turbine 10 is supported by a buoyant tension leg platform (TLP) 60. Various embodiments and configurations of a TLP are known and used in the industry, including centralized and distributed buoyancy configurations, and the present invention encompasses use of any conventional TLP. Generally, a centralized buoyancy TLP 60 as depicted in the figures includes a buoyant central body 62 having a cylindrical portion 64 and a submerged base 66. The cylindrical portion 64 is partially submerged and mates with the wind turbine tower 16 above the water. A plurality of submerged radially extending arms 68 extend from the base 66, for example in a star patern.

[0044] It should be appreciated that the TLP depicted in the present figures is for illustrative purposes only. The invention encompasses any TLP configuration having a plurality of arms and mooring lines.

[0045] A mooring line or tendon 70 is connected at the end of each arm 68 and extends in a generally vertical direction to an anchor 72 on the seabed 82. The mooring lines 70 may be any suitable type of chain, cable, rope, or the like. The excess buoyant force of the TLP maintains the lines 70 under a constant tension.

[0046] A controllable tensioning device 74 is associated with each mooring line 70 to adjust and maintain a set length 75 (Fig. 3) of the of the mooring line 70 from the end of the arm 68 to the seabed 82. A number of suitable devices are used in the marine environment for controlling and maintaining the length of a cable or chain, including electric or hydraulically operated winches, windlasses, and capstans. Any device or component that can be controlled to pay out or take in a line or cable can be used as the controllable tensioning device.

[0047] In an embodiment not shown in the figures, the tensioning devices 74 may be centrally located within the central body 62 of the TLP, wherein the mooring lines 70 would run through each of the arms 68 to the tensioning devices 74.

[0048] Each of the tensioning devices 74 is in communication with a controller or control system. For example, in Fig. 1 each tensioning device 74 is in communication with a controller 78 located within the central body 62 of the TLP. This controller 78 may, in turn, be in communication with the central wind turbine controller 44 discussed above. In an alternate embodiment, the control functions related to the tensioning devices 74 may be carried out directly by the central wind turbine controller 44, wherein the tensioning devices 74 are in direct communication with the wind turbine controller 44.

[0049] Referring to Figs. 1 and 2A, the tower 16 of the floating wind turbine 10 extends upright from a surface of the water and has a vertical axis 40. In a calm sea state and in low wind conditions, this axis 40 is essentially unaffected by aero and hydro forces and is normal to the water surface. In this state, the axis serves as a reference axis 40’ (Fig. 2B) for purposes of the present disclosure. As discussed, an inclination of the floating wind turbine 10 is generated by both wind (aero forces) and sea state (hydro forces). This inclination can be measured as an angle relative to the reference vertical axis 40’. For example, at zero degrees inclination, the tower axis 40 coincides with the vertical reference axis 40’. When the tower 16 “leans” (Fig.3), the tower axis 40 is at anon-zero angle of inclination relative to the vertical reference axis 40’.

[0050] Fig. 2B depicts the condition wherein wind is acting on the wind turbine 10, particularly affecting the rotor 14, tower 16, and cylinder 64 of the TLP. The wind turbine is “pushed” in a direction away from the wind, as indicated by the shift between the reference axis 40’ and tower axis 40.

[0051] Fig. 2B also indicates a condition referred to as “thrust surge” that occurs when the wind turbine is operational and the rotor 14 is rotating to produce power. Rotation of the rotor 14 may cause the wind turbine 10 to naturally shift in a direction away from the wind.

[0052] The states discussed above with respect to Fig. 2B generate significant aero-induced loads or bending moments in the tower 16 and cylinder component 64 of the TLP.

[0053] Fig. 3 depicts a state of the wind turbine 10 in accordance with aspects of the present disclosure wherein a lean angle 75 is induced in the tower 16 in the direction of the wind. In other words, the tower 16 is caused to lean into the wind. The lean angle 75 is measured between the axis 40 of the tower 16 and the reference axis 40’ discussed above. The lean angle 75 is computed so that that a “gravity moment” induced by the lean of the tower 16 essentially offsets the aero loads (bending moment) induced in the tower 16 and cylinder 64 from the wind and thrust surge. When the tower 16 is caused to lean as indicated in Fig. 3, the weight of the nacelle 12 and upper sections of the tower 16 is displaced laterally from the axis 40’. Gravity acting on this weight generates the “gravity moment” acting opposite to the bending moment from the wind and thrust surge. A maximum lean angle 75 setpoint can be set in the control system 78 / 44 to limit the stroke length of the tendon actuators.

[0054] The lean angle 75 is controlled by determining a wind condition acting on the wind turbine and, based on this wind condition, determining a set length of one or more of the mooring lines 70 to generate the lean angle 75. The tensioning devices 74 are then operated to obtain, maintain, and adjust the set lengths of the mooring lines 70. For example, in Fig. 4, it is appreciated that one or more of the mooring lines 70 may be shortened (the upwind lines 70) while one or more other lines 70 (the downwind lines 70) may be lengthened to change the orientation of the TLP and, thus, the inclination angle 75 of the tower 16.

[0055] The wind condition that is sensed and used to determine the set lengths of the mooring lines 70 may be any one of wind speed, wind direction, or wind turbulence. These conditions may be sensed by one or more sensors 50 on the wind turbine or by sensors that are remote from the wind turbine and in communication with the controller 78 and / or wind turbine controller 44. In a particular embodiment, the wind condition is an average wind speed computed over a predetermined time.

[0056] The wind direction or yaw position of the rotor relative to the wind direction may also be used as a variable in determining the set length of the mooringlines. For example, a rotor 14 that is yawed away from the wind direction will not be affected by wind conditions to the same degree as a rotor that is facing directly into the wind.

[0057] Fig. 4 depicts various movements and motions of a TLP offshore wind turbine 10 that may be induced by one or a combination of aero and hydro forces acting on the wind turbine. In addition to the aero forces and movements discussed above, the tower 16 and TLP 60 may also experience one or more of sway, roll, surge, pitch, heave, or yaw from wave motion or currents alone or in combination with aero forces. Embodiments of the present disclosure also include detecting and compensating for these motions as well by adjusting the set length of the mooring lines 70. One or more sensors 80 may be located on / in the TLP 60, or at ay other suitable location on the wind turbine 10, to detect these additional movements of the TLP 60 or wind turbine 10, wherein such sensors 80 are in communication with the platform controller 78 and / or the wind turbine central controller 44.

[0058] Fig. 5 depicts a flow chart of exemplary method embodiments in accordance with aspects of the present disclosure, wherein the process begins at step 100 with a TLP wind turbine discussed above.

[0059] At step 102, one or more wind conditions are detected by a sensor at the wind turbine or remote from the wind turbine. The wind conditions may include any one or combination of wind speed, wind direction, or wind turbulence.

[0060] At step 104, a set length of one or more of the mooring lines is determined based on the wind conditions, wherein the lengths of the mooring lines are computed to induce a lean angle in the tower to compensate for aero bending moments otherwise induced in the tower from the wind conditions, as discussed above.

[0061] At step 106, the controller / control system generates compensation control signals that are transmitted to the tensioning devices to adjust the length of one or more of the tensioning lines to induce the lean angle.

[0062] At step 110, the moorings lines are adjusted to the set lengths by the tensioning devices. At this point, the process repeats / continues based on continuous or periodic detection of the wind conditions at step 102.

[0063] At step 112, the lean angle is measured and the value of this measured in used in a feedback control loop wherein a feedback signal is combined with the comp control signal at the summing junction 108.

[0064] Steps 114-118 depict additional compensation for hydro-induced movements of the TLP and wind turbine, as discussed above. For example, at step 114, one or more sea state conditions are determined, such as wave height, current, wave period, or wave frequency. These conditions may be sensed and determined by one or more sensors on the TLP or wind turbine, or may be detected / sensed remotely. Based on the sea state conditions, hydro-induced movement / motions of the TLP and / or wind turbine can be inferred or predicted.

[0065] Alternatively, or in combination with step 114, hydro-induced movement / motion of the TLP can be detected directly by one or more sensors mounted on the TLP or wind turbine.

[0066] At step 118, the information from steps 114 and / or 116 are used by the controller / controller system to generate hydro compensation control signals for the tensioning devices to offset any one or more of the motions discussed above, such as sway, roll, surge, pitch, heave, or yaw. These hydro compensation signals can be combined with the aero compensation signals (and the feedback signal) at the summing junction 108.

[0067] This written description uses examples to disclose the disclosure, including the best mode, and also to enable any person skilled in the art to practice the disclosure, including making and using any devices or systems and performing any incorporated methods. The patentable scope of the disclosure is defined by the claims, and may include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they include structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal languages of the claims.

Claims

WHAT IS CLAIMED IS:

1. A floating offshore wind turbine, comprising: a nacelle; a rotor with a pl ural i ty of blades; a tower, the nacelle, and the rotor mounted atop the tower; a buoyant tension leg platform, the tower supported on the tension leg platform, the tension leg platform further comprising a plurality of arms extending radially outward relative to a vertical axis of the tower; a tensioned mooring line connected to each of the braces, the mooring lines extending to a seabed anchor; a controllable tensioning device configured with each of the mooring lines to adjust and maintain a length of the mooring line; a control system in communication with the tensioning devices, the control system configured to perform the following: determine a wind condition of wind acting on the rotor and blades; based on the wind condition, determine a set length of one or more of the mooring lines to induce a pitch offset in the tension leg platform and a lean angle of the tower into the wind, the lean angle measured relative to the vertical axis of the tower in a zero wind condition; wherein the lean angle is computed to generate a gravity moment in the wind turbine that offsets a bending moment induced in the tower from the wind; and control the tensioning devices to change the length of the one or more mooring lines to the set length.

2. The floating offshore wind turbine according to claim 1, wherein the wind condition is directly determined by measurement of any one or combination of: wind speed, wind direction, or wind turbulence.

3. The floating offshore wind turbine according to claim 1, wherein the wind condition is an average wind speed computed over a predetermined time.

4. The floating offshore wind turbine according to claim 1, wherein the wind condition is determined from sensor values including one or more of rotor speed, tower acceleration, or blade root bending moments.

5. The floating offshore wind turbine according to claim 1, wherein the control system is configured to perform the functions when the wind turbine is in an operational power-producing state.

6. The floating offshore wind turbine according to claim 1, wherein the tensioning devices are located within each of the arms of the tension leg platform.

7. The floating offshore wind turbine according to claim 1, wherein the tensioning devices are located within the central body of the tension leg platform.

8. The floating offshore wind turbine according to claim 1, wherein the tensioning devices comprise one of: a powered windlass, a powered capstan, or a powered winch.

9. The floating offshore wind turbine according to claim 1, wherein the control system is configured to determine the mooring lines to be adjusted with the set length based on a yaw position of the rotor or a sensed wind direction.

10. The floating offshore wind turbine according to claim 1, wherein the control system comprises a platform controller in communication with the tensioning devices and with a central wind turbine controller.

11. The floating offshore wind turbine according to claim 1 , wherein the control system comprises a central wind turbine controller in communication with the tensioning devices.

12. A method for reducing mechanical loads in a tower or cylinder component of an offshore wind turbine, wherein the wind turbine includes:a nacelle; a rotor with a plurality of blades; a tower, the nacelle and rotor mounted atop the tower; a buoyant tension leg platform, the tower supported one the tension leg platform, the tension leg platform further comprising a plurality of arms extending radially relative to a vertical axis of the tower; a tensioned mooring line connected to each of the braces, the mooring lines extending to a seabed anchor; a controllable tensioning device configured with each of the mooring lines to adjust and maintain a length of the mooring line; the method comprising: determining a wind condition of wind acting on the rotor and blades; based on the wind condition, determining a set length of one or more of the mooring lines to induce a pitch offset in the tension leg platform and a lean angle of the tower into the wind, wherein the lean angle is measured relative to the vertical axis of the tower in a zero wind condition; computing the lean angle to generate a gravity moment in the wind turbine that offsets a bending moment induced in the tower from the wind; and controlling the tensioning devices to change the length of the one or more mooring lines to the set length.

13. The method according to claim 12, wherein the wind condition is directly determined by measurement of any one or combination of: wind speed, an average wind speed computed over a predetermined time, wind direction, or wind turbulence.

14. The method according to claim 12, wherein the wind condition is determined from sensor values including one or more of rotor speed, tower acceleration, or blade root bending moments.

15. The method according to claim 12, wherein when the wind turbine is in an operational power-producing state, the lean angle is determined to compensate for a downwind thrust induced in the tower from operation of the wind turbine.

16. The method according to claim 12, wherein the lean angles are predetermined for different values of the wind condition and stored in a look-up table for access by a control system.

17. The method according to claim 12, further comprising detecting a sea state condition and determining an adjustment to the set length of the mooring lines based on the sea state condition to also compensate for motion of the tension leg platform caused by the sea state.

18. The method according to claim 17, wherein the motion of the tension leg platform caused by the sea state comprises any one or combination of: roll, pitch, yaw, sway, surge, or heave.

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