At deeper water sites, it might be more economical to use floating substructures, but the technology is at a nascent stage of development. The development of floating wind technology will dictate a new set of wind turbine design specifications to handle the coupled
hydrodynamic/aerodynamic forcing, as well as the added weight and buoyancy stability requirements. These new requirements will initially add a higher degree of technical risk but with a potentially high payoff in the long term. The major incentives to develop floating systems include the following:
• Potential for reducing costs through system design site independence and greater opportunities for mass production
• Greater potential for full-system assembly at quayside and reduced load-out cost
• Higher wind speeds and energy capture over deeper waters
• Reduced impacts on human activities and environmental ecosystems
• Tripling the U.S. resource potential past 60 m in depth.
In this study, the total deep water wind energy resource potential for the United States at a 90-m elevation was calculated to be 1,978 GW for annual average wind speeds greater than 8 m/s and inside 50 nm from shore (see Section 4). This represents about two-thirds of the total offshore wind resource in the United States.
For floating systems, the benefits derived from turbine weight reduction will increase and could spur a new class of novel, lightweight wind turbine technologies that might be economical only in the context of floating substructures. The marine industry has demonstrated that a large portion of the buoyancy structure is needed to support the mass above the waterline. In the case of wind energy, this is the tower and rotor-nacelle assembly. Further studies are needed to quantify the benefit of pursuing lighter weight wind turbine subsystems on integrated floating platform architectures that could support such turbines (Butterfield et al. 2007). Some examples
of novel concepts that have been previously rejected for land-based and fixed-bottom offshore substructures for economic reasons include lightweight composite towers, concrete aggregates that weigh 30% less than standard mixtures but can deliver the same strength (Holm and Ries 2006); multi-rotor concepts (Heronemus and Stoddard 2003; Jamieson 2003); high tip-speed rotors, downwind rotors, two-bladed designs, superconducting generators, and vertical axis rotors (Vita et al 2009). Cost-saving opportunities with the mooring and anchor systems could also be significant (Liu 2004; Ruinen 2004).
As a caution to manage expectations, note that revolutionary innovations often promise lower costs and optimized system performance, but the benefits may take longer to realize if the concept is a significant departure from conventional practice.
In June 2009, Statoil Hywind teamed with Siemens Wind Energy to install the world’s first full-scale floating wind turbine (Statoil 2009). Statoil will test the 2.3-MW Siemens wind turbine over a 2-year period. The project is a demonstration of the Hywind concept, which uses a ballasted spar type substructure. Statoil is investing around 400 million Norwegian krones (NOK) in the construction, testing, and R&D related to this wind turbine concept. This cost, which translates to approximately US$70 million 2009$, appears to make this technology look unreasonably expensive, but this project is the first of its kind and most of the costs are one-time investments associated with R&D and infrastructure to design the system, deploy it at sea, and monitor its behavior. Future cost projections by Statoil suggest that the mature commercial costs can be competitive with fixed-bottom offshore wind. Figure 5-9 shows two photos of the
Hywind turbine project as it appeared during load-out and after installation.
Figure 5-9. First operating deepwater floating wind turbine: Statoil Hywind 2.3-MW prototype during load-out (left) and installed on station (right) (Photos courtesy of Statoil)
Many of the issues governing the current knowledge about floating platforms for wind turbines can be described in terms of platform stability and system dynamics because it is logical that successful turbine platform systems will minimize the external loading introduced by the two equally important, simultaneously acting spectrums resulting from wind and waves, respectively.
This design space is a considerable departure from standard oil and gas platform designs, which are driven primarily by wave loading and static vertical payload capacity. Many of the same issues that govern oil and gas platforms will also influence the design of wind platforms, but the importance of each variable will be weighted differently.
A vast number of permutations of offshore wind turbine platform configurations are possible, considering the variety of available anchors, moorings, floater geometry, and ballast options. To help simplify the design process, the National Renewable Energy Laboratory (NREL) has developed a framework for generically plotting the design space for most floating platform designs. The method is referred to as the “stability triangle,” which classifies floating wind turbine platforms according to their method of achieving static stability (see Figure 5-10).
Figure 5-10. Stability triangle for classifying floating substructures according to method of achieving static stability
Three idealized structures were defined to plot the design space that corresponds to three methods for achieving static stability (Butterfield et al. 2007):
1. Buoyancy at the water plane (ideal barges) 2. Ballast (spars)
3. Mooring line tension (tension-leg platforms).
The optimum platform will probably be a balance between a platform that can deliver dynamic behavior to minimize loads and deflections while also minimizing the complexities of
installation, load-out, logistics, maintenance, and overall work at sea. Some of the variables to be considered are identified in the following list (Butterfield et al. 2007):
• Additional control requirements to limit motion
• Buoyancy tank cost and complexity
• Tank material and fabrication options
• Manufacturing automation and assembly options for mass production
• Mooring system cost and deployment complexity
• Load-out cost and complexity
• On-site installation requirements
• Decommissioning cost
• Maintainability and personnel access
• Corrosion resistance and exposure
• Degree of water depth independence
• Sensitivity to bottom conditions
• Required footprint (varies as a function of depth and mooring strategy)
• System weight and weight distribution (especially above the waterline)
• Degree of induced tower-top motions
• Wave loading and exposure at the waterline
• Allowable heel angle.
Figure 5-11 shows some examples of floating offshore platform architectures that are being considered.
Figure 5-11. Floating deepwater platform concepts: (1) semisubmersible Dutch tri-floater (Bulder et al. 2002); (2) spar buoy with two tiers of guy wires (Lee 2005); (3) three-arm mono-hull
tension-leg platform (TLP) by Glosten Associates (2010); (4) concrete TLP with gravity anchor (Fulton, Malcolm, and Moroz 2006); (5) deepwater spar (Sway 2010)
Most of the concepts shown in Figure 5-11 have not yet been demonstrated. The Dutch tri-floater concept (1) was developed in a design study in the Netherlands and uses buoyancy to achieve static stability, although mooring lines and heave plates add significant pitch and roll damping
1 2 3 4 5
for dynamic motion control. The spar shown in (2) was analyzed under an independent study at the Massachusetts Institute of Technology (MIT) and features a two-tiered guy-wire system using both mooring lines and ballast. The concept in (3) features a conventional TLP design with a single center buoyancy tank stabilized by mooring lines similar to the concept proposed by Glosten Associates (2010). Studies at NREL indicate that TLPs can be very stable but the expensive vertical load anchors used by the oil and gas industry may limit their
cost-effectiveness. Alternative TLP concepts like the one shown in (4) may reduce the cost of these expensive vertical load anchors. Fulton and colleagues (2006) performed this analysis under a U.S. Department of Energy (DOE) study in 2005. The classical deep-draft spar buoy, much like the Hywind concept described earlier, is shown in (5). This concept was developed by another Norwegian company, SWAY, which is partially owned by Statoil.
Floating platforms, mooring line systems, and anchor installation and deployment are all significant cost drivers. A new generation of drag embedment-type anchors or vertical-load anchors (VLA) should be developed to lower installation and deployment costs (Liu 2004;
Ruinen 2004). Deployable gravity anchors show promise for all platform types because they can be manufactured from low-cost materials and can be incorporated into simple float-out
installation systems. Concept Marine Associates analyzed a gravity-anchor concept for a TLP using concrete buoyancy tanks and deployable anchors (Fulton, Malcolm, and Moroz 2006).
Because offshore wind farms could consist of hundreds of turbines, developers can take advantage of economies of scale to streamline repetitive installation procedures and look for innovative tooling that cannot be justified in single-unit installations such as offshore oil rigs.
All floating designs should be fully evaluated in terms of the key variables that will determine survivability under extreme conditions, fatigue loading, and life-cycle costs. This comparison would allow the key issues that limit each platform type to be identified, guiding future study in this area. A floating substructure must have enough buoyancy to support the weight of the turbine and to restrain pitch, roll, and heave motions within acceptable limits. Although these limits have not yet been fully established, modeling results to date indicate that turbine loads and tower-top motions will probably be higher than those of conventional fixed-bottom turbines because of system-wide interactions. As one example, coupled turbine/platform dynamics add inertial loading, requiring turbines that are more dynamically tolerant.
Floating wind turbines in deeper water would be naturally located farther from shore with increased technical risk and development that would tend to drive costs upward, so the cost-competitiveness of floating systems depends on other factors. Floating wind systems enable major departures from fixed-bottom systems in their ability to partially decouple from the seabed. This offers a new degree of site independence that fixed foundations do not have, along with the ability to mass produce the platform and automate the system assembly at quayside.
Fabrication facilities could be strategically located near harbor facilities for mass production, onshore assembly, and rapid deployment with minimal dependence on large vessels and land-based transportation. Offshore floating systems could be loaded out fully assembled and installed with a reduced burden for large vessels and time spent at sea, which could significantly reduce project costs. Turbine/platform systems and offshore infrastructure could be designed to take advantage of this strategy. These new strategies could be integrated into the turbine design process at an early stage (Fulton, Malcolm, and Moroz 2006; Hansen 2005; Lindvig 2005;
Poulsen and Skjærbæk 2005).
The development of floating wind turbines comprises multiple technology challenges that will require more time, rigorous engineering discipline, broader skill sets, and more complex infrastructure. As such, the commercial development of this technology will take longer than shallow-water and transitional-water technology, but with the benefits of mass production and site independence, could open up a large new resource area at costs similar to those of shallow-water offshore wind.