The kinetic energy of the wind is transformed into mechanical energy by the rotors of wind turbines and then into electricity that is injected into the grid. Wind speed is the most important factor affecting wind turbine performance because the power that can be extracted from the wind is proportional to the cube of the wind speed, e.g. an increase in the long-term mean wind speed from, for example, 6 to 10 m/s (67 %), causes a 134 % increase in production [EWEA, 2009].
Wind speed varies depending on the season, location, orography and surface obstacles and generally increases with height, creating the wind shear profile. Surface obstacles, such as forests and buildings, decrease the wind speed, which accelerates on the windward side of hills and slows down in valleys. Annual variations up to 20 % are normal.
A wind turbine starts to capture energy at cut-in speeds of around 3 m/s (11 km/h) and the energy extracted increases roughly proportionately to reach the turbine rated power at about 12 m/s (43 km/h), remaining constant until strong winds put at risk its mechanical stability, thereby forcing the wind turbine to stop at cut-out speeds of around 25 m/s (90 km/h).
Once stopped and secured wind turbines are designed to withstand high wind speeds of above 60 m/s (216 km/h). Generally, utility-scale wind farm plants require minimum average wind speeds of 6 m/s. There are two main market sectors: onshore and off shore wind energy. The differences include complication of installation, working environment (saline and tougher at sea) and facility of access for installation and maintenance.
In addition, as the wind is stronger and more stable at sea, wind turbine electricity production is higher offshore. Current onshore wind
energy technology certainly has room for further improvement, e.g. locating in forests and facing extreme weather conditions, yet it is a mature technology.
Offshore wind power, however, still faces many challenges. There is a third sector, small wind turbines (up to 10 kW) for niche applications such as isolated dwellings, but this sector is unlikely to provide a significant share of the European electricity supply.
At the end of the last century, a wind turbine design (the three-bladed, horizontal-axis rotor) arose as the most cost-effective and efficient. The main technological characteristics of this design are: an upwind rotor with high blade and rotor efficiency, low acoustic noise, appropriate tip speed; active wind-speed pitch regulation; variable rotor speed with either a gearbox connected to a medium- or high-speed generator or direct rotor connection to a low-speed generator; and concrete, steel or mix towers.
An alternative design around a rotor with a vertical axis, e.g. Vertiwind [Technip] and Aerogenerator X,1 is meant to have key advantages in particular for offshore wind farms. The equipment is placed just above sea level which enormously facilitates installation and maintenance. However wind turbines based on this concept are yet to be built commercially.
The main driver for developing wind technology is to minimise the cost of energy (CoE) production, for which efforts focus on minimising capital costs and maximising reliability. These drivers translate into: design adapted to the wind characteristics; grid compatibility; aerodynamic performance; and adaptation for offshore. Technical considerations that cover several of these goals include windturbine weight reduction; larger rotors and advanced composite engineering leading to higher yields; and design for off shore installation, operation and maintenance.
Throughout the years the electricity grid codes in the EU-27 Member States (MS) have became stricter and now require that wind turbines highly support the grid by having, for example, fault ride-through capabilities, as well as a high-quality electricity output. The consequence is the evolution of wind turbine technology -as reflected by wind turbine configuration- from the initial machines’ fixed rotor speed with stall control (type A) through minimal variable-speed drive introducing pitch control (type B), then the doubly-fed induction generator (DFIG, type C) allowing higher variable speed configuration, and type D which allows the rotor to freely adapt its speed to the wind (thus maximising energy uptake) while using full power electronics converters, to provide the best-quality electricity
to the grid. The added market share of the last two configurations has increased from 44 % of installed capacity in 2000 to 84 % in 2009 [Llorente Iglesias et al., 2011].
The production of the magnetic field in wind turbine electricity generators is the object of another key technological evolution, from electromagnets to permanent magnets. The former included simple squirrel-cage (SCIG) and then wound-rotor (WRIG) induction generators, then compact DFIG and fullsize, low-speed electromagnet generators (LSEMG) in a wind turbine without a gearbox. New designs are substituting electromagnets with permanent magnets (PMG) on the grounds of increased reliability, higher partial-load effi ciency, and more flexibility of integration with compact gearboxes or power electronics.
However, this change is not without problems because of supply/demand unbalances of the basic raw materials needed for permanent magnets (rare earth elements) which lately have triggered escalating prices, and because the main world supplier, China, has set up tight export quotas. Last but not least, ores of rare earths are often found mixed with radioactive materials and its mining and the disposal of its waste presents additional environmental challenges.
Key issues for offshore wind power include: reducing maintenance stops; safe access for staff when the sea is rough (the technological evolution of the access vessels determines how rough a sea they can withstand and thus the number of days that they can guarantee access to turbines); improving the design of the coupling between foundation/installation vessels to reduce installation time and to increase the number of working days; cost effective foundations/installation for deeper waters and further-offshore sites; and reducing the cost of interconnection, currently about 20–25 % of the CapEx.
Interwoven with those issues is the reliability of offshore wind turbines: the more reliable they are the less access is needed for corrective maintenance. In addition, the development of floating foundations is accelerating and the first deep-water wind farm could be envisaged for 2015.
The trend towards ever larger wind turbines, which slowed in recent years, has resumed. The largest wind turbine now in commercial operation has a capacity of 7.5 MW, and most manufacturers have introduced designs of wind turbines in the 4.5 – 10 MW range (up to a total of 42 different designs) mostly for offshore use.
The recently presented large wind turbines, whilst 10 MW designs have been presented by Sway (Norway), Clipper (US) and AMSC Windtec (US-AT). Both industry and academia see even larger wind turbines (10 – 20 MW) as the future of offshore machines [TPWind, 2010].
Rotor diameters which, in general stabilised since 2004 at around 100 m, have, during the last two years, started to grow again and nowadays a significant number of wind turbine designs include rotors greater than 110 m. For rotor sizes between, for example, 115-120 m diameter, a very wide range of wind turbine electrical capacity from 2 to 6.5 MW is offered. The main reasons are commercial and the adaptation to local wind conditions.
Tip speed is limited by acoustic noise and wind turbines might be requested to operate at reduced speed in noise-sensitive areas. However, offshore, the tip speed can increase to above 80 m/s thus increasing electricity production. Pitch control is the technology of choice for controlling rotor speed, coupled with variable-speed regulation. Drive trains tend to reduce their weight and offshore wind turbines tend to stabilise hub heights at 80 – 100 m. This is because offshore wind power shear is lower and there is a trade-off between taller towers yielding slightly higher production but needing heavier, increased foundation loads involving higher tower and foundation costs [EWEA, 2009]. Offshore foundations for deeper waters (30-60m) are expected to diversify away from monopile steel into multi-member (jackets, tripods) and innovative designs such as tribucket, twisted jacket, suction bucket monopile and even concretebased structures [CT, 2011].
The cost of wind energy depends on the cost of raw materials; technology fundamentals; supply bottlenecks (e.g. limited competition in offshore cable supply); market supply/demand balance; administrative barriers (permit process etc., including those caused by NIMBYism); payments for wind electricity, e.g. feed-in tariff s (FiT), FiT premium, market + premium, competitive tender, cash grant, etc.; and on risks and uncertainties impacting on the investors and lenders.
Up to 2004, wind turbine prices declined, influenced by technology learning and the increasing volumes of production. Supply/demand imbalances and the increase of raw material and component pr ices pushed up onshore wind turbine prices to around €1150/kW in 2009, when the reduction in raw materials costs caused by the financial crisis, manufacturing over capacity and increasing competition pushed down prices to around €950/kW by mid-2011, with the Spanish and Italian markets showing the lowest prices [BNEF, 2011b].
Beyond Europe, the US at €790/kW (at 1 EUR = 1.4 USD) and China at €438/kW (at 1 EUR =9.2 CNY) showed lower prices [BNEF, 2011a, 2011b]. Price quotes include transport to the site but not installation. The high price of wind turbines did not turn into high profits for their manufacturers, as European wind turbine manufacturers published 2010 EBIT in the range of 4-7 %, whilst Chinese ones did much better at 14-16 % [BNEF, 2011a].
Offshore windturbine prices are in the range of €1500/kW [MML, 2011]. Similarly, European capital investment (CapEx) for onshore wind farm projects showed a reduction to €1 000/kW in 2003/4, and then climbed to reach its peak in 2008, then down to around €1 250/kW in 2010 [EU,2011]. In the USA, the DoE suggests for a CapEx level around €1 600/kW [DoE, 2011]. Offshore CapEx have been even more aff ected by supply-chain limitations and the difficulties of working offshore, and showed strong price increases from €2 200/kW in 2007 to €3 000–4 200/kW in 2011 with the upper end covered by farther off shore, deep-water wind farms [JRC].
MML [2011] suggests that raw material costs are not that significant but instead prices of offshore wind power include a market premium in the order of 20 %. This is notably higher than for onshore wind due to significant risks related to both construction and operation.
Onshore operation and maintenance (O&M) costs are estimated at €21/MWh (or €47/kW/yr at a 25% capacity factor) and, over a 20-year operation period, constitute 35–45 % of total costs. They have presented a declining trend from the €35/MWh for the old 55 kW wind turbines [EWEA, 2009]. Offshore O&M costs are in the €25-40/MWh (or €106/kW/yr at a 40% capacity factor) range with a European average of €30/MWh [EU, 2011] and towards the upper range for farther off shore installations.2
The cause of these high costs is mainly the high fixed cost of getting access to the wind turbines, even when the higher production partly compensates for the difference. Offshore insurance costs, on top of O&M, can be as high as €5–12/MWh.2
The technology learning effect is presented in terms of a wind turbine-cost progress ratio (PR), and a PR of 90% caused cost reductions up to 2003 [NEEDS, 2006; Junginger, 2007], but then this learning effect was overcome by market factors causing prices to
increase. It is very difficult to estimate the technology learning effect in offshore technology because market and project aspects (e.g. farther offshore wind farms) have had a much higher influence in wind turbine prices and project costs. Offshore wind power experienced a period of fierce competition (2000 -2004) which reflected in neutral PR and, since 2005, a PR above 100 % showed the continuous increase of capital costs [GH, 2009] in what can be seen as negating technology learning.
During the last six years, offshore technology R&D has focused on increasing the reliability of wind turbines which brought about an increase in capital cost – although the cost of energy benefi ted from the increased reliability.2
The expected capital investment trend is for onshore capital costs to reduce further due to non-technological factors – such as the entry into the competition of Chinese wind turbine suppliers and the increasing size of wind turbine blades – playing a significant role, and then to stabilise. Without doubt technology will continue to progress but, as wind turbines are viewed as some kind of commodity, it is likely that non-technological factors will have a stronger infl uence in the onshore turbine price.
Offshore wind power is expected to maintain high costs until 2015 but it has more room for factors including technology improvements (e.g. to reduce foundation and installation costs), learning-by-doing, improved supply chain and more competition which could lead to a reduction of 28 % by 2020 [MML, 2011].
The integration of wind energy into the electricity grid can occasionally involve other costs including the reinforcement of grids, the need for additional balancing power and ancillary services. The first two items have been evaluated in Denmark, per MWh of wind electricity, at €0.1–5 (for 30 % wind share) and €1–4 (20 % wind share), respectively [Krohn et al., 2009]. A range of studies in the US shows that costs for wind energy integration of up to 40 % are below €7.5/MWh, and often below €3.8/MWh [DoE, 2011].
These costs can be reduced through creating larger balancing areas, reducing the wholesale market gate-closure times to 4 – 6 hours, more frequent intra-day markets, intra-hour scheduling (e.g. 5-minute scheduling) and better forecasting used by system operators. There is also room for low-cost improvement by optimising the grid operational procedures [DoE, 2011].
Curtailment is a problem of increasing impact. Curtailment is the forced stopping of wind electricity generation following instructions from grid operators. This happens mostly in two cases, either there is excess (overall) electricity production compared to the existing demand (e.g. on a windy Saturday night), or the local wind power generation is larger than what can be absorbed by the transmission lines to the centres of demand.
Curtailment is not regularly quantified in Europe, and it is expected to remain limited, but elsewhere curtailment is having a strong impact: 17 % in Texas in 2009 reduced to 8 % in 2010 after a new line was built [DoE, 2011], as well as 17 % in Inner Mongolia in China [CCBIS, 2011].
The discussion on costs of generating wind energy often overlooks the fact that this energy is sold in wholesale markets where all electricity negotiated receives the price conceded to the marginal supplier, i.e. the most expensive supplier accepted to generate. In this context, zero-fuelcost technologies, such as wind, displace fuel dependent, expensive technologies and therefore reduce the marginal price applied to all electricity traded (and not just for wind power).
In periods of high fossil fuel prices, the resulting multiplying effect overcompensates for any subsidy that wind might receive. Calculations in Denmark quantified the related savings, over the period 2004 – 2007, at an average of €3.3/MWh of traded electricity. This figure, due to a 20 % wind share, is equivalent to a saving of €16.5/MWh for (only) wind-generated electricity [Krohn et al., 2009]. These benefits do not take into account the increased security of supply, reduction in price volatility and the oil-GDP effect, nor the cost of purchasing carbon under the European Trading Scheme.
The system availability of European onshore wind turbines is above 97 %, among the best of the electricity generation technologies [EWEA, 2009], although because malfunctions occur most when the wind is blowing strong this 3 % unavailability translates into a higher lost production of maybe 5 %.2
The typical capacity factors onshore wind farm are 1800– 2 200 full-load hours equivalent (in which a wind turbine produces at full capacity), and 3 000 – 3 800 offshore, for a European global average of 1960 hours.3 Technology progress tends to increase these fi gures but best sites onshore have already been taken and new wind farms are built at lower wind speed sites.
Market and industry status and potential
The global installed wind farm capacity grew at a 29 % annual average between 2000 and 2009, and added 39.4 GW in 2010 to total 199 GW (+24.7 %) [BTM, 2011]. The offshore sector grew by 52 % in 2010 to 1 100 MW [JRC], including shoreline and intertidal installations, although it still contributes no more than 1.6 % of global installed capacity. In the EU-27, wind installations increased 9.3 GW to reach 84.3 GW (+12.4 %) [GWEC, 2011], and offshore made up 11 % of these new installations. With an annual increase of 18.9 GW, China moved to first place in the ranking of cumulative installed capacity at 44.7 GW [CWEA, 2011a], ahead of the US which installed 5.11 GW for a cumulative 40.2 GW.
However, in terms of operational, i.e. grid-connected capacity, the US is still the world leader as it was estimated that around 34 % of Chinese installed capacity (15 GW) was not connected to the grid at the end of 2010 [ChinaDaily, 2011]. The status of the EU as the major world market is now part of history since 2004, when 70 % of newly installed capacity took place in the EU, this figure was reduced to 24 % over the succeeding six years. During 2010 wind farm installations accounted for 16.7 % of new electricity plant in the EU [EWEA, 2011] and 25 % in the US [DoE, 2011].
Consequently with this trend, top European wind turbine manufacturers suffered a reduction of their global market share from 67 % in 2007 [EWEA, 2009] to 40 % in 2010 [BTM-JRC, 2011], a trend that will continue this year as Chinese manufacturers continue to take advantage of their stronger market. The Top-10 manufacturers in 2010 included four Chinese (Sinovel, Goldwind, Dongfang and United Power), Vestas and Siemens (DK), Gamesa (ES), Enercon (DE), GE Wind (US) and Suzlon (IN).
In the EU-27 in 2010, the wind energy generation, estimated at the European average of 21.2 % load factor, was 148 TWh or 4.5 % of the
estimated 3 300 TWh of EU electricity demand. World wide wind supplied 357 TWh.3 The countries with the highest wind power share in the electricity mix in 2010 included Denmark (22 %), Portugal (17.1 %), Spain (16.6 %), Ireland (10 %) and Germany (6.2 %).3
The integration of 50 % wind power into an electricity system is seen as technically possible [EA, 2007]. Achieving the 2020 EU industry target of 230 GW, of which 40 GW is offshore, remains a realistic scenario. Electricity production would be 520 TWh, between 13 and 15 % of EU electricity demand [EWEA, 2011].3 The 2030 potential is 350 GW, of which 150 GW offshore, and would produce 880 TWh, between 21 and 24 % of EU demand.3
The economically competitive potential of 12 200 TWh by 2020 and 30 400 TWh by 2030 [EEA, 2009] is beyond reach. In the EU, in the long run, offshore wind power should reach 50 % of wind farm installed capacity.
According to the International Energy Agency, global onshore cumulative capacity could reach 670 GW by 2020, of which 109 GW is off shore, with 215 GW in China and 115 GW in the US. By 2030 global installed capacity could reach 1 024 GW of which 194 GW offshore, 270 GW in China, and 210 in the US, and generate 7 % of the then estimated world consumption of 32 700 TWh [IEA, 2010a, 2010b].
Wind energy is already competitive with fossil-fuel generation in high-wind sites such as Scotland. The expected rise in fossil fuel prices, along with wind technology improvements – fuelled by initiatives such as the SET-Plan [European Commission, 2007] – will make that at more and more sites, wind generates cheaper electricity than fossil fuels. Wind power is thus an insurance against fluctuating (and rising) energy prices in addition to creating security of supply and protection against unstable sources of fossil fuels.
Barriers to large-scale deployment
The main barriers preventing wind energy development have not changed much since the 2009 Technology Map [JRC, 2009], namely: a high-levelised cost of electricity (CoE) caused mainly by high capital costs and, especially offshore, high O&M costs; administrative barriers (lengthy permit process, etc.), social acceptance (often after individual visual perceptions mixed up with the NIMBY syndrome) or the lack of trained, experienced staff , in particular for the expected offshore development in the 2014 – 2020 period.
The group of economic barriers include: relatively high raw material (steel, concrete, copper, rare earths), component and turbine prices; low competition among second- and third-tier suppliers (drive shaft, brakes, drive-train bearings, etc.); high grid connection costs; limited grid transmission capability that is reinforced only slowly; scarcer sites with good resources and, since the financial crisis, very tight financing conditions.
Higher wind penetration is also prevented by lack of adequate interconnections, including international links, which are necessary also for the easing of balancing requirements that would be the result of a larger balancing area [EWEA, 2009]. Financing issues have some how eased during 2011 in that there are now more institutional actors (e.g. pension funds) ready to finance debt. However, the fi nancial stakeholders expect high internal rate of returns (IRR) for offshore wind which is causing a further increase in CoE, this high premium could be reduced through clear and long-term policy commitments as well as a structured effort to reduce risks and barriers faced by investors.2
Entry barriers to offshore wind have eased with regards to wind turbines, even if there are still only two clear market leaders, as nearly all manufacturers have commercialised or presented offshore wind turbines. Entry barriers remain for cabling manufacture though (HVAC/HVDC subsea cables), with few actors able to manufacture cable connections to the onshore grid, and – to a lesser extent – cable-laying and foundation-installation vessels.
Onshore grid expansion plans are disappointing [European Commission, 2011a]. In 2010, ENTSO-E prepared a pilot ten-year network development plan under the assumption of only a 25 % renewable energy penetration by 2020, when even the National Renewable Energy Action plans estimate more than 37 %. One of the greatest challenges remains the connection (both on- and offshore) of the very large off shore potential.
Finally, the group of administrative barriers include lengthy procedures, too many authorities involved, inexperienced civil servants, non-homogenous application of regulations, and an unclear administrative framework, among others [European Commission, 2011a].
RD&D priorities and current initiatives
The engine behind European RD&D is the European Wind Initiative (EWI) of the SET-Plan, composed of industry, EU Member States and the European Commission. The EWI has an estimated investment of EUR 6 billion shared between industry and public funding. Its steering group has approved the following R&D priorities suggested by the Wind Technology Platform [TPWind, 2010]: new wind turbines and components for on- and offshore deployment, large turbines, testing facilities; development and testing of new offshore foundations, and its massmanufacturing; grid integration including long distance HVDCs, connections offshore to at least two countries and multi-terminal solutions; and resource assessment including a new European wind atlas and spatial planning instruments.
While R&D programmes run by the European Commission are already adapting to these priorities, Member States are expected as well to align their R&D funding in the near future.
Public bodies could possibly have the largest impact in cost reduction if they focused in reducing the risks and uncertainties existing in the different phases of a wind farm project. Examples include identifying and reducing the uncertainty of wind energy yield calculations (which would result in lower risks for financial institutions providing debt); and reducing the risks of the permit process, e.g. through streamlining the permit schemes, public planning of preferred wind deployment areas, etc. Identifying why financial institutions require such a high IRR for off shore wind and subsequently taking action would help to ease the pressure on offshore CoE.
Wind energy depends on other sectors including: the electricity grid which is a fundamental enabler for higher wind penetration and is currently underdeveloped in particular regarding international interconnections; electricity storage (pumped or reservoir hydropower, compressed air, etc.); and manufacture of subsea HVAC/HVDC cables. The European installed capacity of hydro-pumping storage, currently at 40 GW, should be increased in order to allow for more system flexibility. More reservoir-hydro capacity would contribute to grid support and this would enable more wind and other non-firm renewables into the system.
The European society is still not aware of the full extent of the climate change problem and of the impact of wind energy to alleviate this problem. There is a need for the EU and individual Member States to raise awareness that reduce the “not in my back yard” syndrome toward wind farms and their required grid connections. Last but not least, there is a need for better cooperation among the European wind industry, academia and R&D institutions in research, education and training.
RD&D in advanced materials off ers synergies with a number of low-carbon industries (non-exhaustive): fibre-reinforced composites with the nuclear and solar energy; coatings with the solar power, biomass and electricity storage industries; special concretes with building and nuclear; high-temperature superconductors with the electricity transmission and storage sectors, etc. [European Commission, 2011b].
Synergies exist between the offshore sector and the oil and gas (O&G) industry in areas such as the manufacture of installation vessels. This sector can bring in experience and know-how to the offshore wind sector, in particular on substructure installations and on operation and maintenance issues. Some ocean energy projects share grid-related issues with off shore wind and even with onshore at a lower level. Exchange of technological knowhow with the aeronautics industry might result from the entry of EADS in the wind sector. Other sectors that have possible synergies with wind are the grid components, in particular for offshore installations, and electricity storage sectors. The latter, along with the auto industry for electric cars, and with the support of smart grids/metering, would create a demand-management scenario able to adapt and assimilate surplus wind electricity.
References
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