Monopiles are typically used in shallow water depths (ie, 20–40 m), but may become too flexible for water depths of between ∼30 and 40 m, in which case monopiles fitted with guy wires, or alternatively tripod and jacket/lattice structures, are considered as economical alternatives. For greater depths, time-consuming installation and the effect of soil degradation, which occurs around the pile shaft at seabed level, make monopile foundation solutions prohibitive (Irvine et al., 2003). Tripods consist of a large-diameter central, steel tubular section that is supported over its lower length by three braces (Fig. 20.1(d)), which are connected to the seabed using different foundation types, including gravity base, suction bucket or piles. In this manner, the loads applied to the OWT and its support structure are mostly transferred axially (via the braces) to the seabed foundation. Complete installation of a tripod foundation system having, for example, a water surface to seabed length of up to 50 m typically takes two to three working days, often requiring special equipment for driving/drilling and working underwater (Esteban et al., 2011; Fischer, 2011). A jacket structure (see Fig. 20.1(e)) is a lattice frame comprising small-diameter steel struts that, similar to the tripod, is anchored to the seabed using different foundation types. Complete installation of the jacket structure generally takes up to 3 days. These structures are particularly suited for severe maritime weather conditions because of the additional structural stiffness and larger moment arm (across the seabed) for reacting against the bending loads, compared with monopile foundations. Jacket/lattice structures are also more adaptable to the conditions encountered onsite, increasing their application range, with geometrical variations of the substructure achieved relatively simply, but without altering the stiffness of the overall structure (De Vries, 2007). It is estimated that by 2020, 50–60% of OWTs will be supported by monopiles, with a further 35–40% supported by jacket and tripod systems (Babcock and Brown Company, 2012). The main reason for this shift is the attraction of jacket and tripod systems for deeper sea locations that provide consistently higher wind speeds and hence greater wind-energy production, which is a cube function of the wind speed (Tempel and Molenaar, 2002).

In the future, it is anticipated that floating structures, which are currently at the research and development stage, will be commercially used, particularly for water depths greater than 50 m (Saleem, 2011). Such floating platforms for wind turbines will impose many new design challenges. Among these, tension-leg platform concepts (Fig. 20.1(f)) are currently considered as more economical (Fischer, 2011) since the rigid body modes of the floater are limited to horizontal translation (surge and sway) and rotation around the vertical axis (yaw). For spare floater systems (Fig. 20.1(g)), buoyancy is provided to the wind turbine structure by a long slender cylinder/capsule that protrudes well below the water line (De Vries, 2007; Esteban et al., 2011; Fischer, 2011). For barrage floater systems, the wind turbine structure is placed on a barrage and attached, via anchor lines, to the seabed. The design of floating offshore wind turbines is discussed in chapter ‘Energy storage for offshore wind farms’.

The wave loading (forces) acting on OWT structures is often greater than the wind loading. However, in terms of the overturning (bending) moments generated, the wave loading generally has only a minor role, compared with the rotor–thrust reaction to the wind loads. This occurs due to the smaller lever arm for the bending moment generated by the wave loading, as compared with the overall tower length, and longer lever arm of the rotor thrust in considering the overall overturning moment acting on the foundation system (LeBlance, 2009). For instance, for OWT monopiles installed in the North Sea, Byrne and Houlsby (2003) reported that the rotor thrust reaction contributed to approximately 25% of the total horizontal load, but generated approximately 75% of the total overturning moment. The density of the medium must also be considered when comparing wind and wave loading, with the density of sea water significantly greater than that of air. Hydrodynamic loads generally only become significant for greater water depths and (or) wave heights, which cause the lever arm of the wave load to increase, along with the intensity of the lateral load generated by the water (Fischer, 2011). Fluctuations in wind speed about a mean value impose repeated aerodynamic loads, although when considering the dynamic behaviour of offshore structures, this cyclic nature is generally insignificant compared with the repeated wave loads (Journée and Massie, 2001). Dynamic analysis of offshore structures that takes into account the fluctuating wind load is necessary in cases where the wind field contains energy at frequencies near the offshore structure's natural frequency, although for monopile foundations, the difference between these frequencies is usually high. When the loading frequency gets closer to the structure's natural frequency of vibration (API, 2010), the repeating load can be termed dynamic load. This tends to excite the structure dynamically, leading to resonance and the development of higher stresses in the support structure and foundation, but more significantly to a higher range of stresses; an unfavourable situation in considering fatigue life. A correct evaluation of the total hydrodynamic load acting on an offshore structure must consider the combined current flow and wave particle velocities. Morison et al. (1950) formulated an equation to predict the wave loads acting on a vertical pile exposed to horizontal sinusoidal oscillatory flow. In their equation, the linear inertial force and adapted quadratic drag force (from real flows and constant currents) are superimposed to obtain the resultant force acting on the projected area of the pile. Morison's formula is strictly limited for use with slender structural elements, characterized by D/λ < 0.2, where D is the diameter of the structural element between seabed level and the transition piece, and λ is the impinging wavelength of the ocean wave. For larger offshore structures (eg, gravity foundations and OWT monopiles), the wave field is significantly influenced and a diffraction regime emerges. Potential flow theory is more suitable for the calculation of wave loads on such structures (Batchelor, 1967). However, a significant number of existing offshore structure designs have employed Morison's equation even though the criterion of D/λ < 0.2 may not have been fully satisfied (Haritos, 2007).

For geotechnical design, the relative proportions and importance of the different types of loads applied essentially depend upon the kind of foundation system being considered. For gravity base foundations, potential failure modes are in bearing capacity or excessive settlement; hence the vertical (self-weight) loads are generally the major design consideration (Malhotra, 2010). For monopile foundations, the lateral deflection (rotation) response of the monopile largely controls the serviceability limit state of the whole structure. Hence, lateral loads and resulting moments are more critical compared with the vertical loads for monopile foundations. In other words, the monopile's response under repeated lateral loading is the major design consideration, with the monopile design dominated by considerations of its dynamic and fatigue responses under working loads, rather than its ultimate load-carrying capacity. For instance, existing OWTs have rotor diameters ranging between ∼90 and 120 m (power-generation capacities of 3–6 MW (Tong, 2010)) and produce gravitational loading in the range of ∼2–8 MN. For instance, Byrne and Houlsby (2003) reported vertical loading of 6 MN acting on the monopile foundation for an anticipated 3.5 MW OWT located in the North Sea, with lateral loading from wind and wave factors accounting for up to 66% of the vertical loading. The precise magnitude of these loads will vary with the size of the installation, the detailed design, and local environmental conditions. This scenario is more onerous when the repeating lateral loading occurs at varying frequency, load amplitude and direction (Arshad and O'Kelly, 2013). At some critical level of load amplitude and (or) frequency, the repeating lateral loads can cause significant reductions in the lateral soil resistance for a monopile foundation (Ramakrishna and Rao, 1999).

The monopile diameter and embedment length are primarily dependent on the OWT's power-generation capacity (an indirect measure of the applied loading), seabed characteristics/soil properties and severity of environmental loading. OWT monopiles invariably have slenderness (in terms of embedment length to diameter) ratio values of less than 10 (typically ranging from 5 to 6), and the embedded portion of the monopile is therefore considered to behave as a ‘rigid’ structure, for which rotation is prominent over bending (Tomlinson, 2001; Peng et al., 2011). In other words, the surrounding soil would fail in bearing capacity rather than the monopile failing over its embedded length by plastic hinges; ie, its structural behaviour under lateral loading is defined by its rotation as a rigid body. The embedment length must be sufficient for the monopile to meet design criteria, including vertical stability and limiting horizontal deflection/rotation over its design life. Limiting the rotation is more important for ‘rigid’ monopiles. As a general rule, under field loading, rotation of the monopile by up to 0.5 degree from its vertical alignment (Achmus et al., 2009; LeBlanc, 2009; LeBlanc et al., 2010; DNV, 2011) or lateral deflections occurring at seabed level of up to 120 mm (based on practical experience) (Malhotra, 2010) are considered as limiting values for the proper operation of the wind turbine. Transport of sediment from beneath the scour protection (typically rock/stone layers) zone around OWT monopiles may cause sinking of the scour protection, particularly for piles founded in sandy soil deposits. This alters the natural frequency of the dynamic response in an unfavourable manner (van der Tempel et al., 2004).

For a typical 5-MW OWT installed in the North Sea, a hub height of ∼95 m above mean sea level and rotor diameter of 125 m would produce the approximate quasi-static loading scenario (acting at the seabed level) given in Table 20.1. This example scenario demonstrates that for the monopile foundation, horizontal loading from wind and wave causes extremely high bending moments (resisted in lateral compression of the surrounding soil) and principally controls the foundation design. To ensure the monopile is torsionally stable, sufficient circumferential shear resistance must be mobilized at the pile–soil interface, although the torsional moment to be resisted is usually small (Table 20.1). Further, the connections between the tower and transition piece and between the transition piece and monopile foundation must be capable of transferring these bending and torsional moments, with adequate factors of safety.

Current design standards and guidelines on the serviceability of piles under cyclic lateral loading are limited. Over its service life, a typical 2-MW OWT structure is subjected to ∼100 cycles of 2.0-MN magnitude and 10⁷ cycles of 1.4-MN magnitude in lateral loading, which correspond to the serviceability limit state and fatigue limit state, respectively (GL, 2005). Factors affecting the cyclic response include the diameter and wall thickness of the monopile, its free spanning and embedded lengths, the soil properties, soil–pile relative stiffness, the characteristics of the applied loading and the pile installation method (Malhotra, 2010).