Recent developments in wind turbine design

A critical review of wind turbine performance shows that outputs have steadily increased with the increases in wind turbine size.

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Sep 26, 2017
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Author(s): David Milborrow

Abstract

This article examines the increases in wind turbine size that have taken place and discusses the design options that have been used. 40 years ago wind was a nascent technology, but a number of large megawatt size machines, mostly government funded, were being constructed or planned. However, incentives in California and Denmark encouraged the construction of small wind turbines in large numbers and these evolved from the kilowatt size to the megawatt size and the trend is towards ever-larger machines. Focusing on performance issues and rating philosophy, the article shows that recent moves towards lower power ratings per unit area of rotor (the specific rating) have masked substantial reductions in wind turbine costs and given a misleading impression of increases in productivity.

The article concludes with a brief summary of the characteristics of the largest wind turbines currently available, and points to an increasing preference for variable speed designs and a continuing quest for larger machines.

Introduction

With over 400 GW of wind power installed, worldwide, by the end of 2015, wind capacity is second only to Hydro, among the renewables, in terms of installed capacity [1]. It has overtaken nuclear, though its lower-energy productivity – in kilowatt hour (kWh) per kW of capacity – means that the amount of electricity generated by wind is less.

Onshore wind is now close to being competitive with the conventional sources of electricity generation and can generate electricity at a lower cost than nuclear [2].

About 40 years ago, in 1976, there was very little use of wind power for electricity generation. The few turbines that were in operation were mostly small – tens of kilowatts in size – though in a number of states there were plans for megawatt-size machines, spurred on by the oil crises in the 1970s. The thinking was that the production of such large machines would lessen the number of structures required to match the output from conventional power stations. The research that was undertaken in association with these prototype machines contributed to an understanding of the key issues in aerodynamics, control, structural integrity and wake interactions.

The early development of wind power was pioneered by Denmark and California. In Demark, the main aim was to constrain carbon dioxide emissions and a series of incentives encouraged growth of the wind turbine market which delivered 12 machines in 1978, rising to 438 turbines 10 years later. By 1998, there were 5501 turbines, with a total capacity of 1473 MW [3]. The average size increased from just over 100 kW for machines installed in 1978 to 677 kW for machines installed in 1998.

The Californian oil crisis of 1981 was a powerful incentive that triggered the construction of several thousand small machines in the windy regions of central and southern California. Encouraged by financial incentives, more than 12,000 wind turbines were built between 1981 and 1985, with a capacity of 1000 MW [4]. Changes in the incentives slowed the growth rate after that, but by the end of 1994 there were 14,577 wind turbines in California, with a capacity of 1609 MW [5]. Just as in Denmark, sizes steadily increased.

During the 1980s, there was increasing interest in wind energy, worldwide. The improving reliability and falling costs of wind turbines, aided the growth though most developments needed financial support of some kind. By the turn of the century, there was just under 18,000 MW of installed wind power, worldwide and that had grown to around 430 GW by the end of 2015. That corresponds to a compound growth rate of 22%. In the early years of the present century it was higher than that, but is now slightly less. The growth of capacity since the turn of the century is illustrated in Fig 1.

Fig 1: World wind capacity, 2000–2015

The estimated average load factor of wind, worldwide in 2015, was 0.27 [6], so 430 GW of wind generates just over 1000 TWh/year. That is more than the electricity generated in the whole of Africa [7].

Early large machines

By the end of 1986 there were 27 turbines installed with a rotor diameter >40 m, and power outputs between 600 kW and 4 MW [8]. There was one vertical axis machine and all the remainder had horizontal axis rotors. The vertical axis machine was one of the machines with the highest rating – 4 MW. There was one one-bladed machine and 23 two-bladed machines. Three-blade machines – the type that was to become dominant – only had two representatives out of the 27, and these were both of the same type. The vertical axis machine was 64 m in diameter and the top of the rotor was 110 m high. The largest horizontal axis machine was 100 m in diameter, but was not the most powerful, being rated at 3 MW. The other 4 MW machine was 75 m diameter. This highlights the fact that there is no universal link between size and power rating – an issue that is explored later.

The quest for large machines

Although the early large machines did not generally spawn commercial designs, many were heavily instrumented and this enabled a better understanding to be gained of a wide range of issues that aided the design of subsequent wind turbines. The commercial, albeit subsidised, developments progressed on an evolutionary path that also led, more gradually, to the production of larger machines. This evolution is illustrated in Fig 2, based on data from long-established manufacturer, Vestas [9]. It shows how machine power outputs and sizes have increased over the years.

Fig 2: ‘Vestas turbine evolution’, based on data (simplified) in the Annual Report for 2015

Vestas’ 1979 wind turbine was 10 m diameter and had a rated output of 30 kW. Sizes and ratings slowly increased until 1997, when their flagship machine was 47 m diameter and rated at 660 kW. In 1999, they produced a 66 m diameter, 1750 kW machine, then an 80 m diameter 2000 kW machine in 2000, and a 90 m diameter 3000 kW machine in 2002. The current onshore range includes 90, 100 and 110 m diameter 2000 kW machines and several 3450 kW machines, with diameters ranging from 105 to 136 m. Within the most powerful bracket, the largest machines are used for low-wind speed sites (6–7.5 m/s) and the smaller machines for sites with annual mean wind speeds in the range 8.5–10 m/s.

For offshore use, even larger wind turbines are being used. The average rating of offshore wind turbines installed in Germany in 2015 was 4.145 MW [10] and there are a number of machines in the range 3–8 MW. The largest machine currently operational is a 164 m diameter, 8 MW machine, manufactured by MHI-Vestas (a joint-venture between Mitsubishi Heavy Industries and Vestas).

There are numerous reasons for the development of large machines. Minimising the number of turbines in a wind farm leads to lower expenditure on electrical interconnections, roads, numbers of foundations and transport movements. In addition, tall wind turbines intercept higher wind speeds and so deliver more electricity. To illustrate the significance of this latter effect, Fig 3 charts the energy delivered by all Danish wind turbines, as a function of their size, in the year 2015. Although the database clearly includes some wind turbines with poor availability, the rising trend is clear. The data has been analysed to determine energy productivity in kWh per square metre per year, as this is a more reliable parameter than the capacity factor that is widely used – for reasons that will be explained. The chart shows that production from machines around 20 m diameter was about 500 kWh/m 2/year and this doubles for machines around 60 m diameter. The most productive – and largest machines – delivered around 1500 kWh/m2/year.

Fig 3: Energy productivity of all Danish wind turbines in 2015. Source of data: Danish Energy Agency

Possible size limits

The fact that there may eventually be a size limit is often discussed. Musgrove [4] notes that this may arise when the cyclical reversing stresses due to the self-weight of the blades of horizontal axis turbines become dominant. In a simplified analysis, Miborrow [11] showed that the diameter at which this occurs may be beyond present aspirations. Blade weights, in theory, increase with the cube of the diameter and the extra blade weight and higher costs may start to outweigh the diminishing returns from the extra energy yields that come with increasing height. This reasoning is, however, simplistic, for various reasons. First, it is the load-bearing part of the blade that increases in weight with the cube of the diameter, not necessarily the fairings and second, blade materials have changed over the years, and so the overall trend appears to follow a lower exponent.

Fig 4 shows recent blade set weights as a function of rotor diameter, taking recent information from wind turbine manufacturers and other sources. The two largest wind turbines are conceptual and the information comes from the ‘UpWind’ [12] and ‘Innwind’ [13] projects. The largest blades on an operational turbine belong to the Vestas V164 8 MW turbine and weigh 33 t each, giving a blade set weight of 99 t [14].

Fig 4: Way in which rated power and blade set weights increase with rotor diameter

Although the data show that the weight exponent is 2.38, rather than 3, for reasons explained above, it may be noted that the data for the largest machine lies above the trend line, which suggests the cube law does hold. This may be reflected in turbine costs at 252 m diameter, but there are still likely to be cost savings in building a wind farm with machines of this size, as fewer will be needed, enabling savings to be made in the cost of the farm.

Wind turbine performance

The quest for large machines is probably the biggest single factor that is driving down the cost of wind energy. The performance of the machines themselves is important, but high availabilities have been the norm for many years now and only modest additional energy yields are likely to be gained by improvements in availability. The biggest challenge is offshore, where possible difficulties with access can result in significant losses of generation.

However, a scrutiny of performance data from the first six Danish offshore wind farms shows that, with two exceptions, their capacity factors all exhibit a rising trend. This suggests that availability improved over time. The data are shown in Fig 5. Linear regression analysis suggests a gradually rising trend in capacity factor for all the wind farms, except Copenhagen and Tuno Knob. As the latter will shortly be decommissioned, the low figure for 2015 is possibly to be expected.

Fig 5: Capacity factors for six Danish offshore wind farms built between 1992 and 2004. Source of data: Danish Energy Agency

As a further demonstration of improvements in wind turbine availability, Vestas [9] has collated data on the performance of its wind turbines. The analysis showed that the loss production factor across almost 19,000 wind turbines with performance guarantees was 1.6% in 2015, a figure that is roughly half what it was in 2011.

Design options

A wide variety of design options has been used for wind turbines, though in recent years there has been less diversity. Table 1 summarises some of the principal options. The most common options in 2016 are identified in bold, though new machines are continually coming in the market, so variable speed (VS) rotors may soon overtake fixed speed as the most common option.

Component

Options

blade number

1

2

3

rotor

upwind

downwind

speed

fixed

variable

control

pitch

stall

partial-span pitch

by yaw

drive

gearbox

direct

blades

stiff

teetered

flexible

tower

lattice

tubular

Table 1: Design options for key features

Number of blades and materials

Many of the early government-funded wind turbines had two blades, though the small commercial machines of the same era mostly had three. Three has now become the norm, though a few manufacturers offer two-blade machines. Blade materials are now generally of carbon fibre or glass fibre-reinforced plastic; steel blades are now uncommon and though there was considerable interest in wood epoxy blades in the 1990s, these are now less common.

Power control

The most common method of power control is currently by use of full-span pitch control, with other concepts including partial-span pitch control and ‘stall control’ falling out of favour, except for small machines. With stall control the blades could be fixed and in high winds they gradually moved into stall, thus limiting the output power. However, some form of air brake is needed to prevent the rotor from overspeeding should it become disconnected from the grid.

Drive train

One component of a wind turbine where the technology is still evolving is the drive train. Although some of the early large machines used sophisticated variable speed technology, most of the early commercial machines were of the fixed speed type and used induction generators. However, as turbines grew larger, so did the demands on the gearbox, as the step-up ratio became progressively larger (The larger the wind turbine, the slower the rotational speed). Gearbox problems have been responsible for significant amounts of downtime in some instances due to the difficulties in accessing them and, if necessary, replacing them. An analysis in 2011 showed that the downtime amongst 27,000 turbines due to gearbox problems was higher than that of any other component [15].

Direct-drive machines eliminate the gearbox, but these necessitate complex power electronics, which can be susceptible to faults. Despite the fact that gearboxes cause the highest downtime per failure, an analysis by the National Renewable Energy Laboratory (USA) concluded, ‘Benefits from direct-drive wind turbine (WTs) based on available data not conclusive and need more data to evaluate’ [16].

Specific ratings

One important characteristic of wind turbines that has changed in recent years is the ratio between the rated power and the size. The specific rating, in watts per square, is the rated power per unit swept area of the rotor. In the early days of wind turbine development, some manufacturers used specific ratings up to 600 W/m2, with the aim of squeezing as much energy as possible out of the rotor. However, on medium- and low-wind speed sites this meant that the rated power was only delivered for a few hours in the year. As generator and gearbox costs are closely related to their rated power, this was not necessarily economic. There was then a move toward offering machines with specific ratings that were better aligned to the wind speed regime for which they were intended. So, machines for low-wind speed sites would have ratings around 300 W/m2 and machines for high-wind speed sites in the 1990s would have higher ratings in the region of 400–500 W/m 2. There has been a tendency for specific ratings to come down in recent years, partly driven by external economic factors such as the cost of grid connections and system charges, both of which are generally related to the capacity of the generating plant. To illustrate the point, Vestas’ 1999 annual report summarised their product range and the wind turbines have specific ratings between 393 and 482 W/m 2. The latest annual report (for 2015) shows the current range of wind turbines has ratings between 237 and 398 W/m2.

The trend toward lower ratings is illustrated in Fig 6. This shows the weighted average specific rating of Danish and American wind turbines in the year that they were introduced. In Denmark, there was a decline from around 450 W/m2 for machines introduced in 2003 to 326 W/m2 in 2015. The majority of wind turbines in Denmark now have ratings of 450 W/m2 and below and only a small proportion of the total (about 10%) have ratings >500 W/m2.

Fig 6: Changes in the specific ratings of Danish and American turbines. Source of Danish data: Danish Energy Agency 

In the USA. Wiser and Bolinger [17] note that the average specific rating for turbines installed in 1998/1999 was 394 W/m2 and by 2015 this had fallen to 246 W/m2.

A similar trend is observable in Germany. In 2013, the average specific rating for onshore wind turbines was 366 W/m2 and that fell to 349 W/m2 in 2014 and 326 W/m2 in 2015 [18].

The lower the rating of a wind turbine, the more time it spends delivering rated power. Its capacity factor (the ratio of the mean power delivered to the rated power) therefore goes up. Conversely, wind turbines with high ratings spend less time at rated power and so the capacity factors are lower. This trend is illustrated in Fig 7, using published data for a number of commercial wind turbines. This figure shows that at a site with a mean wind speed of 7 m/s, the capacity factor of a wind turbine can be anything between 0.25 and 0.45. Capacity factor is therefore a very unreliable parameter to use when comparing the performance of wind turbines. Energy productivity in kWh per square metre of rotor area per year is more reliable – provided information is available on rotor sizes – but even that could be misleading, as wind turbines with high ratings deliver higher-energy productivity than machines with lower ratings.

Fig 7: Capacity factors as a function of wind speed, for turbines with different specific ratings

Implications of lower ratings

The fact that there has been a gradual change in rating philosophy over the past 10–15 years (toward lower ratings) means that capacity factors have moved upwards. These increases have been charted by the International Renewable Energy Agency [6], with data from China, Denmark, Germany, India and the USA. They also show that global capacity factors increased from 20% in 1990 to around 28% in 2015. Data from Denmark, as shown in Fig 8, show the annual capacity factor rose from 0.16 in 1999 to 0.28 in 2015. Apart from the influence of machines with lower ratings, the 2015 figure is likely to be influenced by the fact that 2015 was an exceptionally windy year throughout Europe [19].

Fig 8: Annual capacity factors in Danish onshore wind, 1997–2015. Source data from the Danish Energy Agency, calculations by the author

There is no evidence that improvements in aerodynamic performance or drive-train efficiency play a significant part in contributing to the increases in capacity factor. Although, in theory, the use of variable speed increases the energy output from the rotor by ∼6% [20], that is mitigated by the lower efficiency of ac–dc–ac conversion systems and the more complex control systems [21]. One detailed comparison between variable speed direct-drive and fixed speed systems suggested the former offered a small advantage in terms of overall drive-train efficiency [22].

A corollary of the change in rating philosophy is that the magnitude of the downward trend in wind turbine costs has been masked. Turbine prices in the year 2008 were about $1600 (2015)/kW and in 2015 they were about $1100/kW [17]. Specific ratings for new machines in 2008 in both the USA and Germany were about 400 W/m2 (Fig 6), so $1600/kW corresponded to $640/m2 of rotor area. In 2015, the average specific rating of machines installed in the USA was 246 W/m2 [17], so $1100/kW corresponded to $271/m2. So, the ‘apparent’ cost reduction was 1100/1600 or 31%, but a more realistic figure was 271/640 or 58%.

Apart from savings in generator, gearbox and transmission costs, lower-rated turbines also deliver more steady power (as they spend a higher proportion of time at the rated level). This is beneficial to the grid, possibly reducing the costs of extra balancing [23].

Apart from the influence of lower machine ratings, the increases in national and global capacity factors may also be due to the higher wind speeds intercepted by larger machines and possibly by more sophisticated ways of finding suitable sites. At one time, it was thought that the industry would ‘run out’ of suitable windy sites and, of necessity, move to lower wind speed sites, but there does not seem to be any evidence of this happening on a large scale.

Current large machines

Table 2 summarises the principal design features of some of the largest wind turbines currently available [24]. All have three blades, except one, and the trend toward variable speed is reflected in the fact that half the machines in this table are of this type. Specific ratings are also included in this table and it may be noted that all of these except one are below 400 W/m 2. This is perhaps surprising, inasmuch as the largest machines are more suited to offshore use, where higher wind speeds are encountered.

Maker/model

Rating, MW

Diameter, m

Specific rating, W/m 2

Tower height, m. Steel except where noted

Drive

In production

Adwen AD-180

8

180

314

90

geared

2018

Ming Yang super compact drive (SCD)

8

168, two-blade, downwind

361

n.a.

geared, synchronous permanent magnet (PM)

2012

MHI-Vestas V164-8.0 MW

a

164

379

site specific

geared, PMG

2015

Enercon E126

7.58

127

598

135 (concrete)

DD, VS

2011

Siemens SWT-7.0-154

7

154

376

site specific

DD, VS

2016

Senvion 6.2M152

6.15

152

339

up to 124

geared, DFIG, VS

2014

Sinovel SL6000

6

155

318

n.a.

geared, DFIG

2011

|GE Haliade

6

151

335

100

direct, PMG

2015

Donfang/Hyundai Heavy Industries (HHI) 5.5 MW

5.5

140

357

n.a.

geared, DD planned

2013

Nordex N131

3.3

131

245

99–164 concrete/steel

geared, VS DFIG

2015

Table 2: Key data for the largest wind turbines

The future

Two European union-funded projects have examined the prospects for 10 and 20 MW wind turbines. Upwind [12] produced a design for a 178 m diameter, 10 MW turbine that continued with the three-blade rotor concept, operating upwind of the tower. The reference design featured a multiple stage gearbox. The project concluded that a 20 MW design would require substantial innovations in design and manufacture in order to make it viable; otherwise, it is unlikely that it would be economic. The Innwind project [13] builds on this experience and is looking at innovations in blades, the power control and the electrical generator. The concept of a superconducting direct-drive generator is being examined, as well as a ‘magnetic pseudo direct-drive generator based on an integrated magnetic gearbox and an electrical machine’. Superconducting generators have been under discussion for many years; they offer advantages in reduced weight and higher efficiency, but at the expense of equipment needed for the cyrogenics.

In January 2016, Sandia National Laboratories in the USA announced they were to design 200 m blades that could help the development of a 50 MW offshore wind turbine. The blades would be segmented and run downwind, folding in high winds to alleviate loads on the blades and tower. Research on the extreme-scale ‘segmented ultralight morphing rotor’ is funded by the Department of Energy's Advanced Research Projects Agency-Energy programme. The team is led by the University of Virginia and includes Sandia, three universities and the National Renewable Energy Laboratory. Advisory partners from industry include Dominion Resources, General Electric Co., Siemens AG and Vestas Wind Systems.

The artist's impression accompanying the press release implies that a three-blade machine in envisaged. As the concept aims to deliver a wind turbine with a rating six times anything presently operating, and over twice the diameter, it represents a visionary jump into the future.

Conclusion

A review of trends in wind turbine design and performance shows that continuing increases in rotor size and rating look set to continue. Designs for 10 and 20 MW machines are being formulated, with diameters up to 250 m. The clear benefits of increasing size – in terms of energy productivity – have been quantified and a discussion of other design options shows that there is an increasing preference for variable speed wind turbines. However, a preference for three-blade turbines seems likely to continue though there are a few designs with two blades. Recent trends toward lower ratios of rated power to rotor size have masked significant reductions in cost and have also tended to exaggerate increases in performance.

With costs continuing to fall and performance improving, the USA Department of Energy suggests that wind will continue to develop at a steady rate – around 6% per annum – so that electricity production by 2040 will rise to about 2500 TWh/annum – 2.5 times the present level. That is about 25% of all renewable generation, which, in turn, may account for just under a third of world electricity generation [1].

Notes

aUprated to 8.3 MW for Horns Rev 3 wind farm. Modern Power Systems (web) 13 June 2016

Abbreviations: DD – direct drive; DFIG – double fed induction generator; PMG – permanent magnet generator; and VS – variable speed

References

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