1.1 Harvesting Wind Energy

Offshore wind power generation has established itself as a source of reliable energy rather than a symbolism of sustainability. It has been reported by National Grid of the United Kingdom (UK) that on 19 October 2014, 24% of the electricity supply in the United Kingdom was provided by offshore wind farms due to an unexpected fire in Didcot power station and when few of the nuclear power stations were offline due to maintenance and technical issues. Furthermore, National Grid also reported that on 21 October 2014, UK wind farms generated 14.2% of the electricity, which is more than the electricity generated by its nuclear power station (13.2%) for a 24‐hour period.

Before the details of engineering of these systems are discussed, it is considered useful to discuss the sustainability of wind resources as it is often noted that wind doesn't blow all the time. Wind, essentially atmospheric air in motion, is a secondary source of energy and is dependent on the sun. The electromagnetic radiation of the Sun unevenly heats the Earth's surface and creates a temperature gradient in the air, thereby also developing a density and pressure difference. The disparity in differential heating of the surface of the Earth is also a result of specific heat and absorption capacity of sand, clay, intermediate and mixed soils, rocks, water, and other materials. This also results in differential heating of air in different regions and at different rates. The physical process or mechanism that governs the air flow is convection. Common examples are land and sea breezes in coastal regions. The direction and velocity of wind are partly influenced by the rotation of the Earth and topography of the Earth's surface, and thus coastal areas are attractive locations for harvesting wind power. This above discussion shows the sustainability of the wind resource as it is related to the Sun and Earth's motion.

In 2017, Europe was the global leader for offshore wind energy, with the United Kingdom leading the field. This is partially due to the aspirations and policies of the European Union to reduce its greenhouse emissions from the 1990 levels by 20% by the year 2020 and then a further reduction of 80–95% by 2050. There is also an initiative in Europe to make its energy system clean, secure, and efficient.

Offshore wind farming is considered to be one of the most reliable ways to produce clean green energy for five reasons:

1. The average wind speed over sea is generally higher and more consistent than onshore, making the offshore wind farming more efficient.
2. The noise and vibrations from the wind turbines will have minimum impact on human beings due to their distance from land.
3. Large capacity can be installed offshore in comparison to an equivalent onshore wind farm. The reasons are that heavier wind turbine generators (WTGs) or towers can be easily transported and installed using sea routes. In contrast, transporting these large and heavy structures/components during construction will substantially disrupt the daily life for people who live in the vicinity of the wind farm due to blockage of roads.
4. Wave and current loading can be harvested alongside wind through the use of hybrid systems.
5. Wind turbine technology is relatively more mature than other forms of renewables.

1.2 Current Scenario

Currently, the United Kingdom is leading in offshore wind harvesting (currently generating around 3.6 GW). However, Denmark was the first country to build an offshore wind farm 2.5 km off the Danish coast at Vindeby. Figure 1.1a shows the cumulative offshore wind power capacity by country in 2013 and Figure 1.1 b displays the evolution of global offshore wind power capacity from 1993 to 2013. Construction of large‐scale offshore wind farms are on the rise – due to initiatives in many countries such as Germany, Spain, Portugal, South Korea, China, and Japan. The growth is further enhanced possibly due to diminishing public confidence following the 2011 Fukushima Dai‐ichi nuclear power plant (NPP) incident. Figure 1.2a shows the planned offshore wind farm development in the UK waters and Figure 1.2b shows some of the wind farms in Europe. Asian countries such as China, Taiwan, Japan, and South Korea are also fast progressing; see Figure 1.2c.

1.2.1 Case Study: Fukushima Nuclear Plant and Near‐Shore Wind Farms during the 2011 Tohoku Earthquake

A devastating earthquake of moment magnitude M_w9.0 struck the Tohoku and Kanto regions of Japan on 11 March at 2 :46 p.m., which also triggered a tsunami (see Figure 1.3 for the location of the earthquake and the operating wind farms). The earthquake and the associated effects such as liquefaction and tsunami caused great economic loss, loss of life, and tremendous damage to structures and national infrastructures but very little damage to the wind farms. Extensive damage was also caused by the massive tsunami in many cities and towns along the coast. Figure 1.4a shows photographs of a wind farm at Kamisu (Hasaki) after the earthquake and Figure 1.4b shows the collapse of pile‐supported building at Onagawa. At many locations (e.g. Natori, Oofunato, and Onagawa), tsunami heights exceeded 10 m, and sea walls and other coastal defence systems failed to prevent the disaster.

The earthquake and its associated effects (i.e. tsunami) also initiated the crisis of the Fukushima Dai‐ichi nuclear power plant. The tsunami, which arrived around 50 minutes following the initial earthquake, was 14 m high, which overwhelmed the 10 m high plant sea walls, flooding the emergency generator rooms and causing power failure to the active cooling system. Limited emergency battery power ran out on 12 March and subsequently led to the reactor heating up and melting down, which released harmful radioactive materials into the atmosphere. Power failure also meant that many of the safety control systems were not operational. The release of radioactive materials caused a large‐scale evacuation of over 300 000 people, and the clean‐up costs are expected to be in the tens of billions of dollars. On the other hand, following/during the earthquake, the wind turbines were automatically shut down (like all escalators or lifts), and following an inspection they were restarted.

1.2.2 Why Did the Wind Farms Survive?

Recorded ground acceleration time‐series data in two directions (north−south [NS] and east−west [EW]) at the Kamisu and Hiyama wind farms (FKSH 19 and IBRH20) are presented in Figure 1.5 in frequency domain. The dominant period ranges of the recorded ground motions at the wind farm sites were around 0.07–1.0 seconds and the period of offshore wind turbine systems are in the range of 3.0 seconds. Due to nonoverlapping, these structures will not get tuned and as a result, they are relatively insensitive to earthquake shaking. However, earthquake‐induced effects such as liquefaction may cause some damages. Further details can be found in Bhattacharya and Goda (2016)

1.3 Components of Wind Turbine Installation

The majority of wind turbines or wind energy converters conform to a generic arrangement, typically characterised by a three‐bladed turbine driving a horizontally mounted generator. To ease the understanding, the general terminology and components of a wind turbine are shown in Figures 1.6 and 1.7. Typically, a turbine manufacturer supplies rotor‐nacelle assembly (RNA) assembly and the tower, i.e. the components shown in Figure 1.6. The working principle is very simple: essentially, the kinetic energy of the flowing wind is converted into rotational kinetic energy in the turbine and then to electrical energy through a generator. Figure 1.8 displays the components inside the nacelle for a typical turbine.

Readers are referred to the specialised book for details of turbines, such as Burton et al. (2011) and Jameison (2018).

The nacelle, as shown in Figure 1.6, is mounted on the top of the tower and can have different shapes and sizes depending on the turbines. The nacelle contains the generator, which is driven by the high‐speed shaft. The high‐speed shaft is usually connected to the low‐speed shaft by a gearbox. The low‐speed shaft goes out of the nacelle and the rotor hub is placed on it. The blades are connected to the rotor hub. The low‐speed shaft rotates with the turbine blades and the typical speed is about 20 revolutions per minute (20 RPM). A typical gearbox has a speed ratio of about 1 : 100, and the high‐speed shaft drives the generator.

For economic viability of a site, it is necessary to estimate the expected power and energy output of each turbine. The wind power capture can be estimated using Eq. (1.1):

1.1

where

C_p

the power coefficient,

ρ

the density of air,

A

the area of the rotor swept area (with D being the rotor diameter),

U

the wind speed

Based on the relationship, it is clear that for a given swept area and for a particular wind speed and air density, there are two possible ways of increasing the output power:

1. increasing the power coefficient C_p
2. extending the rotor swept area (designing wind turbines with large rotor diameter) thereby increasing A.

1.4 Control Actions of Wind Turbine and Other Details

Wind speeds vary with time, and following Eq. ( 1.1), it is clear that this will cause a fluctuation in the power generation. This may pose a particular challenge to the power supplied to the electricity grid, and this is known as PTO (power take‐off) issues. Control system are in place in the RNA, and the main purpose is to have steady power by ensuring that the rotor turns at a constant rate. There are also issues such as changing the direction of wind, variation of loads in the hub due to unsteady blade aerodynamics, blade flapping, etc., which must be controlled to reduce the fatigue stresses.

The nacelle contains an anemometer to measure wind speeds. At the cut‐in wind speed (typically 4 m s⁻¹), the wind turbine starts producing power. At a certain wind speed, the rated power and rotational speed are reached. Typically, wind turbines reach the highest efficiency at the designed wind speed between 12 and 16 m s⁻¹. At this wind speed, the power output reaches its rated capacity. Above this wind speed, the power output of the rotor is limited to the rated capacity and is carried out by various means: stall regulation (constant rotational speed i.e. RPM) or pitch regulation.

Figure 1.10 shows schematically a wind turbine model, along with the definition of the tilt, yaw, and pitch. If the horizontal wind speed is perpendicular to the rotor plane, the wind turbine is in optimal position. The angle of the wind speed with the plane of the axis of the tower and the low speed shaft is called the yaw angle (θ_yaw). The turbine has a mechanism that tries to rotate itself in the optimal direction, so that the rotor is perpendicular to the wind. This control action is known as yawing.

Some wind turbines are capable of tilting motion, which means that the angle of the low‐speed shaft with the horizontal direction changes. The angle between the horizontal direction and the low‐speed shaft is called the tilt angle (θ_tilt). This tilt angle can be a deflection due to wind loading or the result of a control action called tilting.

When a wind turbine is producing power, usually a constant rotational speed is required. This can be done in multiple ways; the most common are yaw and pitch control. In pitch‐controlled wind turbines, the pitch angle (which is the angle of the blades around the axis that runs from the blade root to the blade tip) can be changed. With the change in the pitch, the angle of attack on the aerofoil profiles of the blades changes, causing a change in the lift force and therefore the rotational speed and power output. This control action is called pitching. The actual pitch angle is denoted by θ_pitch or θ_p.

The turbine blades are not perpendicular to the low‐speed shaft; usually, there is a small cone angle (θ_cone). This coning of the blades provides more stability against the wind, and also has an effect called centrifugal relief. This means that the blades are bent downwind by the wind loading on the blades, but the rotation of the turbine causes a centrifugal load, which is opposite to the load by the wind.

When considering blade loads, a thrust force and a tangential force are defined on the blades. The thrust force is the force acting in the direction normal to the rotor and the tangential force is the one acting in the rotor plane. The flapwise direction is the direction perpendicular to the chord of the aerofoil, and edgewise direction is parallel to the chord of the aerofoil cross section.

It must be mentioned that the tilt angle is fixed for a particular wind turbine installation. For example, the tilt angle for proposed 10 MW SeaTitan is 5°. Blades are very flexible (can be idealised as a cantilever) and will vibrate in flapwise and edgewise direction. The tilt is allowed so as to avoid the blades hitting the tower.

Considering energy extraction from wind, there is a wind speed below which wind turbines cannot be in operation, and there is a wind speed above which the wind turbine must be shut down to avoid serious damage to the blades and machinery. Between these levels lies the operational range of the wind turbine known as 1P range. It is to be noted that this range strongly depends on the size of the turbine, the method of regulation (yaw or pitch regulated), and the parameters of the wind turbine blades.

The definitions of a few terms often required in the design stage follow:

Start‐up speed: The wind speed at which the rotor and blade assembly begins to rotate.

Cut‐in speed: The wind speed at which the wind turbine starts generating usable power. Typically, 10–15 km h⁻¹ (2.8–4.1 m s⁻¹).

Rated speed: The minimum wind speed at which the wind turbine generates its rated power.

Cut‐out speed: The wind speed at which the wind turbine ceases power generation and shuts down because of safety reasons.

1P range: This is the rotor frequency range of the turbine. For example, following Table 1.1, Vestas V164‐8.0 MW turbine has an operating range of 4.8–12.1 RPM. Essentially, it means the turbine will operate within this range in its entire life cycle. At low wind speed duration, it is expected to operate at 4.8 RPM, and when the wind speed is high, it will operate at rated RPM − i.e. the maximum RPM of 12.1.

Structural design speed: A wind turbine is designed to survive very high wind speeds with 50 years mean recurrence interval without any damage.

There are four ways of shutting down the wind turbine:

1. Use of automatic break when the wind speed sensor measures the cut‐out wind speed
2. Pitching the blades to spill the wind
3. Use of spoilers mounted on the blade to increase drag and reduce the speed
4. Yawed out of wind (turning the blades sideways to the wind)

1.4.1 Power Curves for a Turbine

Based on the typical wind speeds, a wind turbine manufacturer can provide the so‐called power curves for their turbines. Power curve is essentially the power production of the turbines plotted with respect to wind speed. Power curves and rotational speed curves are available for a wind turbine and provided by the manufacturer. Typical examples are given in Figures 1.11–1.12 for a 2.5 and 6.2 MW turbine, respectively.

Figure 1.13 shows a photograph of overhang of a turbine.

1.4.3 Classification of Turbines

For the purpose relevant to civil engineering design, wind turbines can be classified (simplistically) into three types:

1. Having a gearbox. The main purpose of a gearbox is to amplify the slow‐moving blades. For example, Vestas V164‐8.0 MW has an operational range of 4.8–12.1 RPM. Assuming a speed ratio of 1 : 100, the blade rotation of 12 RPM can therefore be amplified 100 times to 1200 RPM, which would necessitate a small‐size generator.
2. Direct drive with no gear box. This option is attractive as this eliminates the failure of gearbox, which reduces the operational cost (OPEX) cost. For example, in 10 MW Direct Drive SeaTitan Wind Turbines, the cut‐in wind speed is 4 m s⁻¹ and the cut‐out is 30 m s⁻¹. The rated power is generated at wind speed of 11.5 m s⁻¹ at 10 RPM.
3. Hybrid, which is a mix of two systems having limited step gear box.

The 1P frequency range is important, as it imparts vibration to the system. For a gearbox‐wind turbines, one has to consider the vibration for the whole operational range (4.8–12.1RPM for V164‐8.0 MW turbines). On the other hand, for direct drive – only the particular RPM has to be considered.

Size of a turbine: With rated power, the size of a turbine also increases. For example, the size of Sinovel SL3000/113 size is 12.5 long × 5.0 m wide × 6.6 m height. On the other hand, the size of the 8 MW turbine is 24 m long × 12 m wide × 7.5 m high. Table 1.2 provides rotor diameter and masses of several turbines.

Turbine	Sinovel 3.0 MW (SL3000/113)	3.6 MW Siemens	4 MW Siemens	6 MW Siemens	8 MW Vestas
Rotor diameter	113 m	120 m	130 m	154 m	164 m
Nacelle weight	120 t	140 t	140 t	360 t	390 t
Rotor weight	41.5 t	100 t	100 t	81 t	105 t

^aThe values presented may change with improved design. Recently, the 8 MW with similar blade length is rated upwards to 9.5 MW.

Figure 1.14 shows relevant details from the manufacturer catalogue that are required for design.

1.5 Foundation Types

Foundations constitute the most important design consideration and often determines the financial viability of a project. Typically, foundations cost 25–34% of the whole project and there are attempts to get the costs down. Many aspects must be considered while choosing and designing the foundation for a particular site. They include: ease to install under most weather conditions, varying seabed conditions, aspects of installation including vessels and equipment required, and local regulations concerning the environment (noise). Figure 1.15 shows a schematic diagram of a wind turbines supported on a large‐diameter column inserted deep into the ground (known as monopile). This is the most used foundation so far in the offshore wind industry due to its simplicity.

Figure 1.16 shows the various types of foundations commonly used today for different depths of water. Monopiles (Figure 1.16c), gravity‐based foundations (Figure 1.16b), and suction caissons (Figure 1.16a) are currently being used or considered for water depths of about 30 m. For water depth between 30 and 60 m, jackets or seabed frame structures supported on piles or caissons are either used or planned. A floating system is being considered for deeper waters, typically more than 60 m. However, selection of foundations depends on seabed, site conditions, turbine and loading characteristics, and economics − not always on the water depth.

The substructure can be classified into two types, as described in the flowchart (Figure 1.17):

1. Grounded system or fixed structure where the structure is anchored to the seabed. Grounded system can be further subdivided in two types in the terminology of conventional foundation/geotechnical engineering: shallow foundation (gravity‐based solutions and suction caisson) and deep foundation.
2. Floating system where the system is allowed to float and is anchored to the seabed by a mooring system. Floating systems have certain ecological advantages in the sense that the foundations leave a very low seabed footprint, they are easy to decommission, and maintenance is easier as the system can be de‐anchored and floated out to the harbour.

1.5.1 Gravity‐Based Foundation System

The gravity‐based foundation is designed to avoid uplift or overturning, i.e. no tensile load between the support structure and the seabed. This is achieved by providing adequate dead load to stabilise the structure under the action of overturning moments. If the dead loads from the support structure and the superstructure (tower + RNA) is not sufficient, additional ballast will be necessary. The ballast consists of rock, iron ore, or concrete. Installation of these foundations often requires seabed preparation to avoid inclination. The gravity‐based structures in most cases are constructed in‐situ concrete or with precast concrete units. The gravity‐based concept can be classified into the two types, depending on the method of transportation and installation:

1. Crane‐free solution, also known as ‘float‐out and sink’ solution. These types of foundations will be floated (either self‐buoyant or with some mechanism) and towed to the offshore site. At the site, the foundation will be filled with ballast, causing it to sink to the seabed. This can be an attractive solution for sites having very hard or rocky soil conditions. This operation does not require a crane and thus is known as a crane‐free solution.
2. Crane‐assisted solution. In these types, the foundation does have the capacity to float and is therefore towed to the site on‐board a vessel. The foundation is then lowered to the seabed using cranes. An example is the Thornton Bank, shown in Figure 1.18b, where the shape of the gravity‐based substructure is compared to a champagne bottle. Table 1.3 provides some examples of gravity‐based foundations.

Year of commission	Project	Type of foundation	Depth of water in metres (m)	Distance from shore (km)
2001	Middelgrunden – 40 MW project	Gravity	3–5	2
2003	Nysted 1 (Rodsand I)	Gravity	6–10	10.8
2009	Thornton Bank phase 1	Gravity	12–27	26

1.5.1.1 Suction Caissons or Suction Buckets

Suction buckets (sometimes referred to as suction caissons) are similar in appearance to a gravity‐based foundation but with long skirts around the perimeter. Essentially, they are hybrid foundations taking design aspects from both shallow and pile foundation arrangements. A caisson consists of a ridged circular lid with a thin tubular skirt of finite length extending below, giving it the appearance of a bucket. Typically, such foundations will have a diameter‐to‐length ratio (D/Z) of around 1, making them significantly shorter than a pile but deeper than a shallow foundation. A sketch of a suction caisson with terminology can be seen in Figure 1.19a. Suction caissons themselves are a fairly recent development in the offshore industry. Caissons first came into use around 30 years ago as a foundation structure for offshore oil and gas production platforms.

1.5.1.2 Case Study: Use of Bucket Foundation in the Qidong Sea (Jiangsu Province, China)

The first suction bucket supporting offshore wind turbine was installed in the Qidong Sea area, Jiangsu province (China), in October 2010, see Figure 1.19c. The whole structure was designed to support a 2.5 MW wind turbine in approximately 6 m of water. The bucket is 30 m in diameter and 7 m deep. Fabrication of the caisson took around two months and the entire foundation structure was towed to site and installed with the aid of gas jetting around the caisson skirt. By constructing the caisson out of concrete, the fabrication cost of the structure was reduced in comparison to that of a similar steel design.

1.5.1.3 Dogger Bank Met Mast Supported on Suction Caisson

Suction caissons were used to support met mast at the Dogger Bank offshore wind farm; see Figure 1.19d.

1.5.2. Pile Foundations

Single large‐diameter steel tubular piles, also known as monopiles, are the most common form of foundation for supporting offshore wind turbines. Figure 1.20 shows the monopile type of foundation that is essentially a large steel pile (3–7 m in diameter) driven into the seabed with typical penetration depth of 25–40 m. A steel tube, commonly called the transition piece (TP), is connected to the steel pile and the tower is attached to it. The transition piece supports the boat landings and ladders used for entering the turbine. Currently, this type of foundation is extensively used for water depths up to 25–30 m.

These foundations can be reliability driven into the seabed using a steam or hydraulically driven hammer, and the practice is standardised due to offshore oil and gas industry. The handling and driving of these foundations require the use of either floating vessels or jack‐up, which must be equipped with large cranes, suite of hammers, and drilling equipment. If the ground profile at the site contains stiff clay or rock, drive‐drill‐drive procedures may need to be adopted. Pile‐driving results in noise and vibrations. Therefore, the turbine (nacelle and rotor) is always installed after the piling is carried out.

Often a group of small‐diameter piles can be used to support a wind turbine. Small‐diameter piles are also used to support a jacket, which, in turn, supports a tower and the WTG; see Figure 1.20b. Figure 1.20c shows the Shanghai Donghai Bay project where a group of piles is used – known as HRPC (high‐rise pile cap).

1.5.4 Floating Turbine System

The floating system can be classified into three main types (see Figure 1.26):

1. Mooring stabilised TLP (tension leg platform) concept. This type of system is stabilised with tensioned mooring and anchored to the seabed for buoyancy and stability; see Figure 1.26a.
2. Ballast stabilised Spar buoy concept with or without motion control stabiliser. This type of system will have a relatively deep cylindrical base providing the ballast, whereby the lower part of the structure is much heavier that the upper part. This would raise the centre of buoyancy about the center of gravity of the system. While these are simple structures having a low capex cost, they need a deeper draft (i.e. deeper water) and are not feasible in shallow water. Motion stabilisers can be used to reduce the overall tilt of the system, see Figure 1.26b.
3. Buoyancy stabilised semi‐submersible. This concept is a combination of ballasting and tensioning principle and consumes lot of steel; see Figure 1.26c.

There are varieties of anchors that can be used to moor the floating system, and they can be classified into surface anchors and embedded anchors. An example of surface anchors is a large, heavy box containing rocks or iron ore, and the holding capacity depends on the weight of the anchor itself and the friction between the base of the anchor and the seabed. On the other hand, examples of embedded anchors are anchor piles, such as shown in Figure 1.26c. Figure 1.26b,c are floating wind turbine concepts suitable for deeper waters with Figures 1.26a and 1.27a showing the floating concept (semi‐sub) implemented in a wind farm in Japan (offshore Fukushima). By contrast, Figure 1.27b shows the Hywind concept (spar concept). Figure 1.27c is a TLP concept developed by GICON.

1.6 Foundations in the Future

Foundations typically cost 15–35% of an overall offshore wind farm project, and in order to reduce the LCOE, new innovative foundations are constantly being researched. However, before any new type of foundation can actually be used in a project, a thorough technology review is often carried out to derisk it.

The European Commission defines this thorough technology readiness level (TRL) numbering, starting from 1 to 9; see Table 1.4 for different stages of the process. One of the early works that needs to be carried out is technology validation in the laboratory environment (TRL 4). In this context of foundations, it would mean carrying out tests to verify various performance criteria, including the long‐term performance. It must be realised that it is very expensive and operationally challenging to validate in a relevant environment, i.e. in an offshore environment, and therefore, laboratory‐based evaluation has to be robust so as to justify the next stages of investment.

To reduce the cost of offshore wind power, the Carbon Trust initiated a competition called ‘The Offshore Wind Accelerator’. The aim of this project was to reduce the cost of offshore wind by 10% by 2015. This cost reduction was to be achieved in a number of ways, including more cost‐effective foundation arrangements. A number of novel foundation solutions were proposed, and after evaluation and investigation, these were narrowed down to four arrangements for further development, as shown in Figures 1.28 and 1.29. These solutions consist of:

1. Keystone innovative jacket, also known as twisted jacket or inward battered guided structure (IBGS), see Figure 1.28 (a) and 1.28 (e)
2. Gifford/BMT/Freyssinet gravity structure see 1.28 (b)
3. SPT Offshore & Wood Group tri‐bucket (see Figure 1.30 for a schematic view) and 1.28 (c)
4. Universal foundations suction bucket monopile, see 1.28 (d)

For TRL 4 level work, small‐scale tests are carried out in a well‐controlled laboratory. For offshore wind turbine foundations, tests must be carried out for the following purposes:

1. Confirm and validate the mechanism of load transfer from superstructure to the ground through the foundation element. This is very important for a new concept of a foundation or a connection. For example, monopile type of foundation transfers load through overturning moments. On the other hand, jacket‐type structures transfer loads through axial push−pull action. Load transfer are discussed in Chapter 2.
2. Find out the modes of vibration of the structures. These are carried out through free vibration/perturbation tests or white noise testing. In Chapters 2 and 3, it will be shown that the natural frequency of wind turbine structures is very close to the forcing frequencies due to wave and 1P (rotor frequency), 3P (blade passing frequency, discussed in Chapter 2) and as a result, these structures are sensitive to dynamics. Modes of vibration can strongly influence the foundation design, fatigue life, and wear and tear of the mechanical components in the RNA.
3. Offshore wind turbine foundations are subjected to hundreds of millions of cycles load, which can be cyclic or dynamic in nature. Scaled model tests can reveal the expected trends of behaviour of the foundations due to cyclic and dynamic soil‐structure interaction. One of the uncertainties is the long‐term nonrecoverable tilt of the foundation. Excessive tilt may lead to shutdown of the turbine.
4. The loads on a foundation are very complex and can be one‐way cyclic or two‐cyclic. The long‐term effects of such one‐way cyclic loading can be identified through scaled model tests.
5. Due to dynamic sensitivity, offshore wind turbines need damping. Trends and sources of damping can be identified through carefully designed scale model tests.
6. To identify any ‘unknown‐unknowns’ for the problem under investigation through the tests. Experimental observations often unearth new design considerations.

1.6.2 Case Study of a Model Tests for Initial TRL Level (3–4)

Bhattacharya et al. (2013a,b) reported some aspects of TRL work for the foundation shown in Figures 1.28c and 1.30. Essentially, this is a seabed frame supported on three suction caissons. Three scaled models (1 : 100, 1 : 150, and 1 : 200) were constructed and tested in two types of ground (sand and clay). Free vibration tests were carried out to identify the modes of vibration and two closely spaced peaks were observed as shown in Figures 1.31a and 1.32. This was repetitive in all three models, which confirms a phenemenon later identified as rocking modes of vibration. This was later verified and validated through numerical modelling, which further showed that these foundation systems will vibrate about two principal axes due to the variability of the ground. For some foundation arrangement (symmetric), these two peaks will converge with cycles of loading due to ground‐reaching steady‐state behaviour. For asymmetric system, these peaks may not converge, and later chapters discuss how this will have negative outcome on the fatigue life. The readers are referred to Bhattacharya et al. (2013b) for further details on this TRL study.

1.7 On the Choice of Foundations for a Site

The choice of foundation will depend on the following: site condition, fabrication, installation, operation and maintenance, decommissioning, and economics. Bhattacharya (2017) defined an ideal foundation as follows:

1. A foundation that is capacity or ‘rated power’ (i.e. 5 or 8 MW rated power) specific but not turbine manufacturer specific. In other words, a foundation designed to support 5 MW turbine but can support turbines of any make. There are other advantages in the sense that turbines can be easily replaced.
2. Installation of foundation is not weather sensitive, i.e. not dependent of having a calm sea or a particular wind condition. The installation of the first offshore wind farm in the United States took more time due to the unavailability of a suitable weather window.
3. Low maintenance and operational costs, i.e. needs least amount of inspection. For example, a jacket‐type foundation needs inspection at the weld joints.

It is economical for a wind farm to have a large number of turbines due to economies of scales, but this requires a large area. If the continental shelf is very steep, grounded (fixed) turbines are not economically viable; a floating system is desirable. Figure 1.32 shows water depth plotted against distance from the shore for some oceans.

Monopiles are currently preferred for water depths up to 30 m. The simple geometry allows automation of the manufacturing and fabrication process. The typical cost (2018 European Steel Price) of monopile steel is €2 kg⁻¹ to manufacture. Welding can be carried out by robots and installation is simpler. However, if the diameter become larger (known as XL or XXL piles, which are over 8 m in diameter and weigh 1200 t), the transportation and installation becomes challenging and a limited number of installation contractors can carry out the work. Innovations are underway to install large‐diameter piles using the vibro method, where a foundation is installed through vibration of the soil, effectively liquefying the soil around it.

An alternative to large‐diameter monopiles is a three‐ or four‐legged jacket on small diameter piles. Steel for jackets cost around €5 kg⁻¹ to manufacture, which is more than double that of monopiles due to many tubular joints, and they are often welded manually.

Gravity‐based foundations are cheaper to manufacture as compared to steel, but they require a large fabrication yard and storing area. As concrete foundations will be much heavier than equivalent steel foundations, large crane, and vessels are required to install. For an offshore site where the surface ground is rock, a gravity‐based structure will be a preferred choice; see, for example, the French waters.

1.8 General Arrangement of a Wind Farm

Figure 1.33 shows the components of a typical wind farm. The turbines in a wind farm are connected by inter‐turbine cables (electrical collection system) and are connected to the offshore substation. There are export cables from offshore to the shore. Figure 1.34a shows the photograph of a wind farm with many wind turbines and a substation. Figure 1.34b shows the details of the substructure of a monopile with J tubes for the electrical collection system. Figure 1.35 shows the photograph of a jacket‐supported substation. Figure 1.36 shows the plan of Horns Rev wind farm.

1.8.1 Site Layout, Spacing of Turbines, and Geology of the Site

Wind turbines in a wind farm are spaced to maximise the amount of energy that can be generated without substantially increasing the CAPEX (Capital expenditure, i.e. upfront cost). If the farm is much spread out, i.e. large spacing of the turbines, the inter‐array cable length will increase. This spacing is therefore an optimization problem between compactness of the wind farm (which minimises the CAPEX cost due to subsea cables) and the adequate separations between turbines so as to minimise the energy loss due to wind shadowing from upstream turbines.

Figure 1.37 shows the aerial photo of wake turbulence behind individual wind turbines that can be seen in the fog of the Horns Rev wind farm off the Western coast of Denmark (Photo credit Vattenfall Wind Power, Denmark).

The geometric layout of a wind farm can be a single line of array, or a square or a rectangle configuration. Due to advanced methods for optimisation having different constraints as well as site conditions, different layout patterns are increasingly being used. Typically, the spacing between turbines is equivalent to 3–10 times the rotor diameter and depends on the prevailing wind direction. The spacing should be larger than 3−4 times the rotor diameter perpendicular to the prevailing wind direction and 8–10 times the diameters for direction parallel to the wind direction. For example, for a prevailing southwesterly wind direction (which is typical of Northern Ireland), a possible site layout for a wind farm located in the area is shown in Figure 1.38. The spacing along the wind direction is kept at 6 times the rotor diameter (6D) but for across the wind, the spacing can be kept bit lower (4D). For Nordsee Ost wind farm, the layout has more turbines in the first row.

Due to the large spacing of the turbines (typically 800–1200 m apart), a small to medium size wind farm would extend over a substantial area. A typical size for a modern‐day wind farm is 20 km × 6.5 km; see Figure 1.39 for the layout of the Sandbank wind farm of German North Sea. Due to the large coverage of area for a wind farm, there may be significant variation in the geological and subsurface conditions, as well as practical restraints. Examples include a sudden drop in the sea floor causing change in water depth, paleo channels, change in ground stratification, submarine slopes, presence of foreign objects such as shipwrecks, location of important utility lines (gas pipeline, fibre optic cables), etc. Detailed site investigation programmes consisting of geotechnical, geophysical are carried out to establish a 3D geological model, which often dictates the layout of the wind farm.

1.9 General Consideration for Site Selection

Currently, many of the wind farms are operating from the subsidy provided by the government. For example, in the United Kingdom, schemes such as contract for difference (cfD) are in use. However, in order to be sustainable, large wind farms must be constructed to achieve economies of scales with the aim to produce electricity at the lowest possible cost. Therefore, cost of electricity from different sources are compared using LCOE or SCOE (society's cost of energy). As much of the installation, operation, and maintenance (O & M) will be carried out in rougher waters, time in construction (TIC) is also a driving factor for site selection. Therefore, every cost increasing part of the construction has to be lowered in such a manner that an optimal method for the construction and installation will be established.

This section will detail the considerations for choosing a particular site. The main considerations are:

1. Wind resources. A thorough knowledge of wind resources in an area is fundamental, as it allows estimation to be made on the wind farm productive and therefore the financial viability of the project. As a rule of thumb, a project is not financially viable if the average wind speed at the hub height is below 6 m s⁻¹ and it is considered safe investment if the average wind speed at the hub is more than 8.5 m s⁻¹.
2. Marine aspects. Marine aspects would include water depth, wave spectrum at the site (wave height, wave period), current and tide data, exposure to waves and sediment transport, identification of scour‐related issues, and if scour protection is needed. Often, installation of foundations creates obstacles in the local flow pattern of water, which may create turbulence that leads to scour.
3. Environmental impact. For all wind farm, an environmental impact assessment (EIA) must be completed as a part of the planning process and it covers the physical, biological, and human environment. This would involve collecting all types of existing environmental data and assessing for all the potential impacts that could arise due to the construction and operation of the wind farm. The impacts can range from favourable to less favourable to detrimental. Potential aspects on the biological environment include marine mammals, sea birds that use the area on a regular basis, birds from nearby areas that pass through the area during flight, fish, etc. Other aspects include effect of flora and fauna during the construction (e.g. noise due to piling or operating noise), and electro‐magnetic field generated by subsea cable. The human environment includes change of landscape. Marine archaeology aspects such as shipwrecks are also taken in consideration. To carry out the assessment, seabed samples may be collected and analysed for worms, barnacles, or other species.
4. Power export/grid connection. One of the important deciding factors is the location of onshore grid connections. The deciding factors include the length of submarine cable required, which is dependent on the turbine layout, substation location, export cable routing (landfall), risk assessment of buried cables, and the transformer options – AC or DC.
5. Economics. Modelling of capital costs and LCOE is a function of many parameters: depth of water, distance from shore, wind speed at the site, port and harbour facilities near the site, socioeconomic conditions and access to skilled labour, location of national grid, and hinterland for the proposed development.
6. Navigation. This survey will investigate whether there is a need for exclusion zone due to fishing or navigation or military operations. Cables connecting the wind farms and the export cables are buried to depths of 2–3 m to avoid risk of entanglement with net. Navigation risk must be assessed.
7. Consents and legislations. Depending on the country, the consent requirements may change. For example, in the United Kingdom, any development more than 100 MW is classified as significant infrastructure project and requires development of a consent order from the Infrastructure Planning Commission (IPC). These rules are subject to amendment. Currently, the final decision rests with the Secretary of State for Energy and Climate Change.

1.10 Development of Wind Farms and the Input Required for Designing Foundations

Based on the discussion in the earlier sections, it is inevitable that the main design inputs for offshore wind turbines address these issues:

• Water depth at the specific location
• Turbine loads (dependent on size and weight)
• Ground profile at the specific location
• Site specific loads due to waves, current, tide, and earthquakes
• Other considerations are construction and installation costs
• Time in construction (TIC)

There can be conflicting requirements considering the site‐specific conditions such as water depth, soil properties and site‐specific loads and the requirements for a large number of wind turbines (economy of scales). Often, it is also necessary to avoid different support structures within one wind farm – so that one contractor and one installation vessel can be used. Therefore, optimization for the local site conditions through advanced layout for a large number of installations is necessary. Typically, one season of a year is suitable for offshore operations i.e. the installation of the wind turbines which asks for a fast and robust less risky installation method.

The key aspects for windfarm development are:

1. Turbine selection depending on the site condition and economic viability
2. Array design and the cable routing
3. Substructure and turbine design process
4. Selection of foundation
5. Electrical system
6. Cost modelling
7. Installation
8. Operation and maintenance (O & M)

1.11 Rochdale Envelope Approach to Foundation Design (United Kingdom Approach)

The design of offshore wind turbine foundations is an iterative process that requires many amendments and improvements as more data become available. It is therefore quite natural that in the consenting phase, the design is not finalised. This is because, detailed studies such as site investigation, EIA are not carried out until the business decision has been made. Also, this is a new industry and the pace of technological development is faster than the design cycle of offshore wind farms and as a result the appropriate turbine and foundation cannot be selected in advance. This results in the turbine, foundation type, foundation dimensions, appropriate transportation, installation technologies, etc. being not clearly defined at the consenting stage. For this reason, developers of almost all wind farms around the United Kingdom are using the Rochdale envelope approach.

Essentially, this methodology defines the turbine and foundation technology and design parameters very loosely so that necessary modifications throughout the design process can be made. This allows for changes in the following:

• Turbine type and size
• Number of turbines and rated power
• Wind farm layout
• Foundation type and size
• Seabed area usage together with sediment displacement volume

A simple example is introduced to explain the method. Assume that a certain area A of a fixed shape is available for the development of an offshore wind farm, with a given maximum water depth S, basic information about the seabed (e.g. bathymetry, soil types, and approximate layer thickness), and basic metocean data (e.g. 50‐year significant wave height expected for the area, wind rose, etc.). For these particular conditions, a conservative estimate for the parameters of the planned wind farm needs to be provided in the framework of the Rochdale envelope approach. This may look as follows:

• Turbine type and size. The chosen turbine may vary between 3 and 8 MW. The rotor diameter will be in the range 90–164 m and the total height of the turbine from mean sea level to blade tip between 100 and 200 m.
• Number of turbines and rated power. The target‐rated power output is 600 MW and this may be connected to an offshore substation with two transformers. Accordingly, the number of turbines may vary between 75 (75 × 8 MW) and 200 (200 × 3 MW). It is important to note here that larger turbines do not necessarily utilise the given offshore area better even if all other parameters like costs and installation times are constant. This is because the distance between turbines is a multiple of the turbine diameter, typically four to six times the rotor diameter. The power generated by a turbine is proportional to the square of the rotor diameter, i.e. P ∝ D². The number of turbines that can be placed on a line of certain length is inversely proportional to the rotor diameter. Arany (2017) showed that the energy density (i.e. energy per unit area, which is a measure of effective use of seas and oceans) in a large wind farm made up of many rows is actually independent of the chosen turbine size. Therefore, the selection of the best turbine for a given site is not straightforward, and is a matter of engineering and financial judgement, which changes as the project progresses.
• Wind farm layout. The wind farm layout shall be a grid with shifted rows. The number of rows will vary between 5 and 8, the number of turbines in each row will vary between 15 and 25. The two layouts with the highest and lowest number of turbines are shown in Figure 1.46.
• Foundation type, size, and numbers. The foundations chosen will be monopiles, jackets, or tripods. The maximum diameter of a monopile foundation will be 9 m given the limitations of manufacturing and available installation vessels. Depending on the water depth and hub‐height, the maximum leg spacing of a jacket will be 40 m and that of tripod maximum 50 m. The foundations may all be the same or different types combined throughout the wind farm. The number of foundations will vary between 75 and 200, based on the number of turbines.

The seabed area usage, sediment displacement volume, etc. can be determined similarly, aiming for a conservative estimate, as these are crucial for the consenting of the wind farm. Throughout the design cycle the foundations go through many design iterations, and the wide range of possibilities allowed in the Rochdale envelope. For this purpose, analysis have to be carried out on the expected sizes of support structures and foundations, as well as predicting the long‐term behaviour. This helps to arrive at rational decision based on economics and engineering judgement.

1.12 Offshore Oil and Gas Fixed Platform and Offshore Wind Turbine Structure

Constructing stable platforms in deeper water and further offshore is not new, and considering offshore oil and gas, this is a very matured industry. Experiences regarding safe offshore operations such as installation, piling, mooring, and anchoring can be used. While the experience gained from offshore oil and gas operations can be used, it is considered important to highlight the significant differences between these two types of structures, which deserve special attention. As this book is related to foundation design, the differences will be limited from the point of view of foundation design. Figure 1.47 shows a typical monopile supported wind turbine and a pile‐supported fixed offshore jacket structure. It is very clear that the ratio of horizontal load (P) to vertical load (V) is very high in offshore wind turbines when compared with fixed‐jacket structures. As a result, monopile is a moment‐resisting foundation.

Offshore wind turbine structures, due to their shape and form (i.e. a long slender column with a heavy mass as well as a rotating mass at the top) are dynamically sensitive because the natural frequencies of these slender structures are very close to the excitation frequencies imposed by the environmental and mechanical loads. For typical 3.6 MW turbines, the first natural frequency (eigen frequency) of the whole system is close to 0.3 Hz and for the corresponding 8 MW turbine is 0.22 Hz. The frequency of the rotor of the wind turbine is in the range of 0.2 Hz (see Table 1.1). Typical wind turbine blades weigh 30 t and as a result 90 t is rotating at the top of the tower. On the other hand, the natural frequencies of offshore oil and gas platforms is more than 0.6 Hz and the most important cyclic/dynamic loading is the wave having frequencies 0.1 Hz (typical North Sea value). As the forcing frequencies are not very close to the natural frequencies making oil and gas platforms less sensitive to dynamics.

There are, however, obvious differences between those two types of foundations:

1. Offshore oil and gas platforms are supported on many small diameter piles. Piles for offshore platform structures are typically 60–110 m long and 1.8–2.7 m in diameter and monopiles for offshore wind turbines are commonly 30–40 m long and 3.5–6 m in diameter.
2. The fixity or the boundary condition of oil and gas platform piles are very different from that of the monopiles. The oil and gas platform piles can under lateral loads translate laterally but cannot rotate. Therefore, degradation in the upper soil layers resulting from cyclic loading is less severe for offshore piles, which are significantly restrained from pile head rotation, whereas monopiles are free‐headed. Free‐headed piles allow more deformation and, as a result, high strain levels in the soil.
3. Beam on nonlinear Winkler springs (known as ‘p‐y’ method in American Petroleum Institute, API code or Det Norske Veritas, DNV code) is used to obtain pile‐head deflection under cyclic loading for offshore oil and gas piles, but its use is limited for wind turbines application for two reasons:
   1. The widely used API model is calibrated against response to a small number of cycles (maximum 200 cycles) for offshore fixed‐platform applications. In contrast, for real offshore wind turbines, 10⁷–10⁸ cycles of loading are expected over a lifetime of 20–25 years.
   2. Under cyclic loading, the API or DNV model always predicts degradation of foundation stiffness in sandy soil. However, recent work suggests that the foundation stiffness for a monopile in sandy soil will actually increase as a result of densification of the soil next to the pile.

1.13 Chapter Summary and Learning Points

The key lessons are:

1. From the turbine manufacturer, one needs the operating range of the turbine (1P range). This is necessary for setting the target natural frequency of the whole system. The theory for target frequency is discussed in Section 2.2 (Chapter 2). Practical examples to compute target frequency for the chosen turbine at a given location are shown in Examples 6.1 in Chapter 6.
2. For foundation design, one needs to know the mass of the RNA assembly and tower dimensions and mass. This will be provided by the turbine manufacturer.