Technology Projections

Future Performance:.Manufacturers are pursuing multiple design paths for year 2000 technology with the goal o f achieving the system-level cost eff ectiveness represented by the 2000 wind TC characterization. Performance indicators for year 2000 technology are based in part on information from the DOE Next Generation Turbine Development (NGTD) Project. Data from that project is based on designs still in the pre-prototype stage.

The following two turbines are currently being investigated under the NGTD Project. The turbine descriptions are for current concepts, but do not now represent actual turbines.

• The Wind Turbine Company WTC 1000 is a downwind two -speed, variable-pitch turbine rated at 1000 kW. The rotor incorporates variable rotor coning to attenuate loads and the drive train employs multipl e generators. The turbine employs a passive-yaw system to reduce mechanical complexity.

• The Zond Z-56 is an upwind, variable speed, variable-pitch turbine rated at approximately 1.1 MW. I t employs 3 blades in an upwind config uration, an active yaw system, a variable-speed, doubly-fed generator, and advanced NREL airfoils.

Table 6 details the projected performance gains for 2000 and each subsequent five-year interval up to 2030. The table lists gains as a percent of the 1996 baseline turbine and as a percent of the previous period's value. The table also shows the percent of incremental increases from the previous time period for each 5 year interval due to each driver. As shown in Table 6, the three largest drivers of incre ased energy in 2000 are taller towers, larger rotors, and reduced system losses from soiling. The energy estimate for the 2000 composite turbine assumes a variable speed generator system and a variable pitch rotor. However, because it is anticipated that variable speed systems will still be undergoing substantial development for wind turbine applications, it is assumed that the associated electronic power conversion system is not fully optimized. That is, due to limitations on individual component efficiencies, especially power-electronic conversion capabilities, it is assumed t hat introduction of variable speed operation will result in only modest net performance gains. A recent investigation concludes that realizing the benefits of increased energy output from variable speed operatio n requires advanced direct-drive architectures and more advanced power electronic conversion capabilities [33]. The table reflects these conclusions by showing zero-to-modest gains from variable speed in 2000, with substantial gains stil l possible in later years. This may be a conservative assumption, as industry is currently pursuing several differen t approaches to variable speed configurations and preliminary projections of the net performance/cost tradeoff for these vary.

A range of values is given in Table 6 for two primary reasons. The first is uncertainty related to technologica l development. The second, and larger, is that systems utilize an optimized combination of various subsystems involving tradeoffs between cost and performance of each subsystem. That is, subsystems are combined to maximize the cos t effectiveness of the system as a whole. Since tradeoffs must be considered when employing various subsystems an d design approaches, no single system can utilize every component or operational approach with the very highest individual performance characteristics.

The broader uncertainty range, associated with year 2000 performance estimates, listed in Table 1, reflects increase d technology-related uncertainty compared to the 1996 range. The low side is increased again in 2005 for the same reason.

Table 6. Performance improvement drivers.

Increase in Net kWh/m* (percent)

Percent of Incremental Increase from Previous Time Period (percent)1

Previous

Period

Taller Towers

Larger Rotors or Improved Aerodynamics

Lower

Assumed

Losses from

Soiling

Variable Speed + Drive Train & Power Conversion Efficiency Optimization1

2000

16-18

16-18

50-70

5-10

27-31

0-40

2005

22-28

6-10

30-50

5-10

11-20

30-60

2010

25-32

3-4

50-80

#

#

20-50

2020

29-37

4-5

70-90

#

#

10-30

2030

31-40

2-3

70-90

#

#

* Range for increases in energy estimates is for class 4 to class 6 sites f Range for contributions represents uncertainty and imprecision from using composite technolog y assumptions

1 Opinions differ on the potential for variable speed to increase energy capture. NREL and others ar e currently investigating this topic [33]

# Shaded boxes indicate small incremental improvements are possible

Generally, progression in rotor performance, from 1996 into the future, is characterized less by increases in roto r aerodynamic efficiency (peak power, or C p ) and more by maintenance of a relatively high efficiency over a larger wind speed range. Additionally, a lower turbine cut-in speed, made possible by larger, variable pitch rotors, is assumed as an advance in 2000 and beyond (the impact of this latter assumption was not evaluated separately). Generator, transmission and power electronics performance, efficiency, are not explicitly modeled, i.e, explicit estimates for these efficiencies are not developed. Currently, these efficiencies are embedded in the curves used to estimate energy output.

Increasing hub height/tower height is shown in Table 6 to be a primary driver of performance gains in 2005. Other first order drivers in 2005 include more efficient variable-speed operation; larger rotors, including aerodynamic rotor control for clipping gusts, which allows larger rotors to be used economically with a given generator rating to capture lower wind speeds; and further reduction of system losses.

Performance gains are expected to level off after 2005, with further improvements assumed to be incremental. Increasing tower height is the primary driver of performance increases during this period. Progress is also expected in areas outside cost and performance. More accurate micrositing models are expected to be developed, which will contribute to a reduction in windfarm array losses. Improvements modeled into the energy estimate calculations for all years includ e cost/performance tradeoffs including increased tower heights (costs) for improved performance.

Future Cost: As seen in Table 7, the major cost changes in 2000 are driven by large increases in the rotor diameter and tower height, elimination of the transmission, and introduction of variable-pitch rotors and new, advanced powe r electronics for variable-speed operation and power control. Other low cost designs will be present in the market in 2000 -a doubly-fed generator with a geared transmission is seen as one potent ial example. Lighter weight, more flexible systems are expected to appear, along with designs aimed at lower cost manufac turing techniques. Changes in specific subsystems include:

• Transmission - While many of the subsystem cost figures are composite valu es that describe trends, elimination of the geared transmission is a specific design feature that is explicitly assumed because it represents a large source of weight, and therefore offers a substantial cost reduction. This is the only subsystem that becomes a smaller fraction of the total cost for the 2000 system. The reduction from 22% to 7% of total system cost from 1996 to 2000 is based on a recent design study [21] which estimated the transmission to account for 75% of the cost in the "Transmission/Drive Train, Shaft Brakes, Nacelle" category.

• Towers - Although savings in tower costs are possible from reduced loads, new tower designs, and advanced materials, total tower costs still increase significantly in 2000 in both per-kW and absolute dollars. Thi s reflects the increase in height as well as increased thrust loads from the larger rotor. Tower cost is assumed to scale linearly with tower height and proportionately with the square of the rotor diameter [34]. However, calculation of the exact percentages of cost increase from each scaling effect, i.e., determination of coefficients in the scaling equation, is beyond the scope of this TC. Nonetheless, the costs in Table 7 are believed t o reasonably reflect engineering scaling principles. Peak thrust loads from hurricane or maximum anticipated winds tend to drive tower costs. Since it is assumed that these loads will not be reduced by rotor designs in year 2000, no cost reduction is included to represent the potential for load reduction that may be experienced during normal operation of new variable-speed, variable-geometry rotor systems emerging in year 2000.

• Rotors - Table 7 shows an absolute cost increase for the rotor subsystem from $93,000 to $135,000 per turbine, reflecting the diameter increase from 38 to 46 meters, and also a trend towards more complex, variable-pitch mechanisms. A percentage of rotor cost increases with the cube of the rotor diameter [34]. As was the case for estimated tower cost increases, scaling coefficients are not developed for this analysis. The tren d towards lighter rotors also has a downward influence on costs. The rotor cost, as a percentage of the total system cost, is at the high end of the preliminary estimates from the DOE NGTD Project.

• Electronics and Controls - Power and control electronics and other electrical costs show a significant increase in year 2000, as more expensive or more complex electronics are required to implement variable speed, direct drive generation.

• Generators - Generator costs are assumed to increase as a result of substituting higher performanc e technologies for off-the-shelf induction units. Sample technologies might be synchronous or doubly fe d generators in 2000.

• Reliability - It is assumed that it will be possible to design turbines for incrementally greater reliability based on a better understanding of wind inflow character istics and how these characteristics impact structural design, and appropriately improved modeling tools. It is expected that there will be improvements in turbine blades, particularly with respect to better integration of blade structural and aerodynamic design with appropriat e manufacturing processes. Resulting improvements in reliability are reflected in the decreasing O&M an d overhaul/replacement costs.

Table 7. Cost breakdown for 50 turbine windfarms (January 1996 $).

Major Subsystems

1996

2000

2005

2010

2020

2030

$/kW

Rotor Assembly (including hub)

185

180

190

160

150

140

Tower

145

145

185

195

215

235

Generator

50

45

55

50

45

40

Electrical/Power Electronics, Controls,

155

140

100

90

75

65

Instrumentation

Transmission/Drive Train, Shaft Brakes, Nacelle,

215

50

40

35

35

30

Yaw System

Turbine FOB (including profit)

50

560

570

530

520

510

Balance of Station (BOS)

250

190

150

145

135

125

Total Installed Cost ($/kW)

1,000

750

720

675

655

635

$/T

"urbine (i

>thousanc

s)

Rotor Assembly (including hub)

93

135

190

160

150

140

Tower

73

109

185

195

215

235

Generator

25

34

55

50

45

40

Electrical/Power Electronics, Controls,

78

105

100

90

75

65

Instrumentation

Transmission/Drive Train, Shaft Brakes, Nacelle,Yaw

108

38

40

35

35

30

System

Turbine FOB (including profit)

375

420

570

530

520

510

Balance of Station (BOS)

125

143

150

145

135

125

Total Installed Cost ($Thousands/Turbine)

500

563

720

675

655

635

Percent of Total Initia

Project Capital Cost

Rotor Assembly (including hub)

19

24

26

23

22

22

Tower

15

19

26

28

32

36

Generator

5

6

8

7

7

6

Electrical/Power Electronics, Controls,

16

19

14

14

13

12

Instrumentation

Transmission/Drive Train, Shaft Brakes,Nacelle, Yaw

22

7

6

5

5

5

System

Turbine FOB (including profit)

75

75

79

78

79

80

Balance of Station (BOS)

25

25

21

22

21

20

Total

100

100

100

100

100

100

Note: "Controls" includes yaw drives and gears. Numbers may not add to 100% due to rounding error.

Note: "Controls" includes yaw drives and gears. Numbers may not add to 100% due to rounding error.

The uncertainty bounds on cost in Table 1 are doubled for 2000 and beyond, reflecting the relative difficulty of projecting turbine and project prices. The maximum upper bound for 2000 i s assumed to be equal to the lower bound of 1996. This projection is conservative (higher) compared to preliminary estimates from the DOE NGTD Project. Project. The lower bound is also conservative (higher) compared to the lower bound of the NGTD Project estimates.

The key 2005 cost changes are driven by the combined effects of the inc rease in rotor diameter and tower height. Changes in specific subsystems include:

• Rotors - Cost increases from significantly larger diameters in 2005 begin to be offset from improve d manufacturing techniques resulting largely from the DOE/industry cost-shared Blade Manufacturing Project and to a lesser extent from increased production. The fact that the total rotor cost does not increase with the cube of the diameter also reflects the increasin g use of lower cost paths such as 2-bladed designs, lighter, more flexible structures, or pultruded blades.

• Electronics - Cost decreases result primarily from R&D advances in power electronics for variable spee d generation systems.

• Generators - As in year 2000, generator cost increases, per kW, as a result of a trend toward higher performance technologies such as permanent magnet generators, which may become cost effective in 2005.

Key cost drivers beyond 2005 include:

• Rotors - As production volume increases, it is assumed that industry will be able to support larger-scal e advanced manufacturing improvements for rotor blades. Also, R&D is assumed to improve the ability t o understand the connection between aerodynamic inputs and component fatigue loads, leading to use of lighter, more reliable components, and optimized control systems for lo west-cost approaches. These factors, combined with cost reductions from increased volume, account for the decrease in rotor costs in 2010 and beyond. Because blades are currently a custom-made subsystem, they have the potential to realize larger gains tha n mature technologies such as steel towers. Therefore, approximately a 10% cost reduction in the custom component of blade cost is expected for every doubling of cumulative production volume [35].

• Power Electronics and Controls - Power electronics and controls costs are projected to decrease significantly as a result of technical advances in components through R&D, wind turbine design advances, and increased volume.

• Generators - Incremental cost improvements from manufacturing, design, and volume effects are assumed to occur in permanent magnet generators after 2010.

• Towers - Cost per kW of towers increases at a rate lower than the tower height increases due to assumed advances in the ability to shed aerodynamic loads and design lighter towers.

The cost shown in Table 1 continues to decrease after 2000 because of three cost drivers: higher volume, advances in manufacturing resulting from R&D efforts, and technology advances from R&D. Therefore, the uncertainty percentage is kept fixed at +20% so that the absolute upper bound, i.e, the actual likely highest cost, is lower for each successive five-year period. The lower bound for 2005 is considered conservative because it is within the range of DOE NGTD Project estimates for 2000 technology cost.

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