National Renewable Energy Laboratory 

Innovation for Our Energy Future 

A national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

NREL is operated by Midwest Research Institute ● Battelle Contract No. DE-AC36-99-GO10337 

WindPACT Turbine Rotor 

Design Study 

June 2000 — June 2002 

D.J. Malcolm 

Global Energy Concepts, LLC 

Kirkland, Washington 

A.C. Hansen 

Windward Engineering 

Salt Lake City, Utah 

Subcontract Report 

NREL/SR-500-32495 

Revised April 2006 
WindPACT Turbine Rotor 

Design Study 

June 2000 — June 2002 

D.J. Malcolm 

Global Energy Concepts, LLC 

Kirkland, Washington 

A.C. Hansen 

Windward Engineering 

Salt Lake City, Utah 

NREL Technical Monitor: A. Laxson 

Prepared under Subcontract No. YAT-0-30213-01 

Subcontract Report 

NREL/SR-500-32495 

Revised April 2006 

National Renewable Energy Laboratory 

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303-275-3000 • www.nrel.gov 

Operated for the U.S. Department of Energy 

Office of Energy Efficiency and Renewable Energy 

by Midwest Research Institute • Battelle 

Contract No. DE-AC36-99-GO10337
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Errata Sheet for 

WindPACT Turbine Rotor Design Study 

NREL/SR-500-32495 

CORRECTIONS 

Page 13 

Table 3-1. Summary of Cost Models Used for Major Components in Baseline Designs 

6th row, first column should read – 

Pitch bearings 

Not used for final costing 

7th row, first column should read – 

Pitch bearings 

(Tasks #2, #3, #5) 

7th row, fourth column should read – 

See text 

12th row, second column should read – 

Bearing mass = (D x 8/600 – 0.033) x 0.00920 x D^2.5 

Where D = rotor diam (m) 

12th row, third column, delete “U of Sunderland [6] and” 

Page 14 

Table 3-1 Continued 

13th row, second column should read 

$/kW = 3.38E-7*

Rating2 + 9.84E-4*Rating + 31.57 

Page 18 

Section 3.2.2.1 Pitch Bearings 

Starting with the second paragraph, the text in the section should be replaced with the 

following with the exception of the formula. The formula remains unchanged. 

An initial model for the total cost was: $/bearing = 0.0454*D2.98. This was found to 

correspond well with data obtained later from Avon Bearings (see Appendix C). These 

data included cost estimates for the range of ratings of interest and were based on initial 

estimates of peak moments. The mass and cost of the auxiliary pitch drive components 

were estimated to be equal to that of the pitch bearing itself and a factor of 2.0 was, 
therefore, added to the cost. However, as noted below, this model was not used for the 

final estimates in the costing and scaling efforts. 

Different bearing types were recommended by Avon at the different sizes because of the 

relatively small diameter of these bearings compared to the high loads they must carry. 

At 750 kW, a single-row ball bearing was selected, whereas at the 1.5 MW and higher 

ratings, triple-row bearings were recommended and quoted. The cost quoted for bearings 

for the 5-MW size did not fall on the same curve as for the others and it was therefore 

neglected in defining the cost model. 

A new cost model was defined for Tasks #2, #3, and #5 that reflected cost changes due to 

changes in the peak loads applied. Therefore, the Avon cost data was reformatted into the 

following form: 

NOTE – FORMULAS AS WRITTEN IN ORIGINAL SHOULD REMAIN 

UNCHANGED 

For Tasks #2, #3, and #5, it was again assumed that the cost of the remainder of the pitch 

system (motor, speed reducer, controller, etc.) is equal to the cost of the bearing. 

Page 19 

Section 3.2.3.2 Main Bearings – the text should be replaced with the following: 

The main bearing was assumed to be of a standard type and a formula for the mass was 

developed based on data, collected by Powertrain Engineers Inc., from wind turbines 

between 750 kW and 2000 kW. The second bearing was included in the gearbox 

assembly. The resulting expression for the bearing mass, in terms of the rotor diameter, 

D, was: 

Mass (kg) = (D x 8/600 – 0.033) x 0.00920 x D^2.5 

The mass of the bearing housing was assumed to be the same as that of the bearing itself 

and a rate of $17.60 per kg was used for both components. 

To download a corrected version of this report go to: 

http://www.nrel.gov/docs/fy06osti/32495.pdf 
i 

TABLE OF CONTENTS 

EXECUTIVE SUMMARY ........................................................................................................... v

Introduction.................................................................................................................................. v

Approach...................................................................................................................................... v

Results......................................................................................................................................... vi

Conclusions................................................................................................................................vii

Recommendations.....................................................................................................................viii

1. INTRODUCTION ................................................................................................................. 1

1.1 Background...................................................................................................................... 1

1.2 Objectives ........................................................................................................................ 1

1.3 Scope................................................................................................................................ 1

1.4 Results on Web Site ......................................................................................................... 2

2. METHODOLOGY ................................................................................................................ 3

2.1 Organization..................................................................................................................... 3

2.1.1 Work Plan ................................................................................................................ 3

2.1.2 Procedure ................................................................................................................. 4

2.1.2.1 Blade Design File................................................................................................. 6

2.1.2.2 Input Data File ..................................................................................................... 6

2.1.2.3 Output Data File................................................................................................... 7

2.1.2.4 Design and Cost Evaluation Process.................................................................... 7

2.1.3 Load Cases ............................................................................................................... 8

2.1.4 Design Methodology................................................................................................ 9

2.2 Specifications for Baseline Configurations...................................................................... 9

2.3 Simulation Software......................................................................................................... 9

2.4 Signals Recorded ........................................................................................................... 10

3. TASK #1. DESIGN AND COST MODELS ..................................................................... 12

3.1 General Approach .......................................................................................................... 12

3.2 Rotor Components ......................................................................................................... 15

3.2.1 Blade Design.......................................................................................................... 15

3.2.1.1 Aerodynamic Specifications .............................................................................. 15

3.2.1.2 Baseline Blade Design ....................................................................................... 15

3.2.1.3 Airfoil Schedule ................................................................................................. 16

3.2.2 Hub......................................................................................................................... 17

3.2.2.1 Pitch Bearings .................................................................................................... 18

3.2.2.2 Teetered Hub...................................................................................................... 18

3.2.3 Drive Train Components........................................................................................ 19

3.2.3.1 Main Shaft.......................................................................................................... 19

3.2.3.2 Main Bearings.................................................................................................... 19

3.2.3.3 Gearbox.............................................................................................................. 19

3.2.3.4 Generator............................................................................................................ 20

3.2.3.5 Power Electronics .............................................................................................. 20

3.2.3.6 Bedplate ............................................................................................................. 20

3.2.3.7 Nacelle Cover..................................................................................................... 20

3.2.3.8 Yaw System ....................................................................................................... 21

3.2.3.9 High-Speed Shaft, Coupler, Brakes ................................................................... 21

3.2.3.10 Hydraulics and Lubrication............................................................................ 21

3.2.3.11 Switchgear and Other Electrical..................................................................... 21
ii 

3.2.4 Tower ..................................................................................................................... 21

3.2.5 Balance of Station .................................................................................................. 22

3.2.5.1 Foundations........................................................................................................ 22

3.2.5.2 Operating Costs.................................................................................................. 22

3.3 Control Systems ............................................................................................................. 23

3.4 Cost of Energy Model.................................................................................................... 23

4. TASK #2. BASELINE DESIGNS...................................................................................... 24

4.1 Basic Specifications ....................................................................................................... 24

4.2 FAST_AD vs. ADAMS Results .................................................................................... 24

4.3 Annual Energy Production............................................................................................. 24

4.4 Material Properties......................................................................................................... 25

4.5 Pitch Control System ..................................................................................................... 25

4.6 Results from Design Process.......................................................................................... 25

4.7 Campbell Diagram ......................................................................................................... 29

4.8 Conclusions from Baseline Study .................................................................................. 29

5. TASK #3. CONFIGURATION VARIATIONS ............................................................... 30

5.1 Initial Matrix .................................................................................................................. 30

5.2 Selection Approach........................................................................................................ 30

5.3 FAST_AD vs. ADAMS ................................................................................................. 33

5.4 Results from Task #3 ..................................................................................................... 33

5.5 Observations from Task #3 results................................................................................. 36

6. TASK #5. DETAILED MODELING ................................................................................ 37

6.1 Approach........................................................................................................................ 37

6.2 Cost Models ................................................................................................................... 37

6.3 Preliminary Results........................................................................................................ 37

6.4 Results from 3-Bladed Upwind Rotors.......................................................................... 38

6.4.1 Campbell Diagram ................................................................................................. 39

6.4.2 Loads...................................................................................................................... 40

6.4.3 Costs....................................................................................................................... 40

6.5 Results for 2-Bladed Rotors........................................................................................... 42

6.5.1 Loads...................................................................................................................... 42

6.5.2 Costs....................................................................................................................... 43

6.6 Lessons from Task #5 .................................................................................................... 44

7. TASK #6. DESIGN BARRIERS........................................................................................ 45

7.1 Transportation ................................................................................................................ 45

7.2 Installation...................................................................................................................... 45

7.3 Blade Manufacturing...................................................................................................... 46

7.4 Acoustics........................................................................................................................ 46

7.5 Design Load Cases......................................................................................................... 46

7.6 Non-Turbine Costs......................................................................................................... 47

8. CONCLUSIONS .................................................................................................................. 48

8.1 Assumptions within the Study ....................................................................................... 48

8.2 Summary ........................................................................................................................ 48

8.3 Recommendations.......................................................................................................... 49

9. REFERENCES..................................................................................................................... 50

10. BIBLIOGRAPHY ............................................................................................................ 52
iii 

APPENDICES 

A Details from Task #3 Configuration Variations

B Details from Task #5 Final Designs

C Avon Bearing Costs

D Calculation of Fatigue Damage Equivalent Loads

E Description of the Blade Pitch Control System

LIST OF FIGURES 

Figure S-1. Cost of energy of baseline and final 3-bladed upwind designs...............................................vii

Figure S-2. Cost of energy for baseline and final 3- and 2-bladed designs at 1.5MW ..............................vii

Figure 2-1. Organization of project personnel .............................................................................................3

Figure 2-2. Tasks and approximate schedule...............................................................................................4

Figure 2-3. Flow of work between GEC and Windward Engineering.........................................................5

Figure 2-4. Configuration control scheme for models.................................................................................5

Figure 2-5. Flow of information in the design process ................................................................................7

Figure 2-6. Coordinates systems used and corresponding rotations ..........................................................11

Figure 3-1. Specific rating vs. rotor diameter for current commercial wind turbines................................15

Figure 3-2. Airfoils used for baseline 1.5-MW blade model .....................................................................17

Figure 4-1. Summary of cost-of-energy breakdown for baseline configurations ......................................26

Figure 4-2. Variation of root flapwise and edgewise moments with diameter ..........................................28

Figure 4-3. Natural frequencies vs. rotor speed (Campbell diagram) of baseline 1.5-MW model............29

Figure 5-1. Rotor configurations selected..................................................................................................30

Figure 5-2. Summary of cost of energy from all Task #3 configurations..................................................33

Figure 5-3. Cost-of-energy changes for 3-bladed configurations ..............................................................34

Figure 5-4. Cost-of-energy changes for 2-bladed configurations ..............................................................34

Figure 5-5. Summary of component costs for 3-bladed configurations.....................................................35

Figure 5-6. Summary of component costs for 2-bladed configurations.....................................................35

Figure 6-1. Natural frequencies vs. rpm (Campbell diagram) for Task #5 

1.5-MW 3-bladed upwind turbine.......................................................................................................39

Figure 6-2. Comparison of baseline loads with final Task #5 loads for 

1.5-MW 3-bladed upwind turbine.......................................................................................................40

Figure 6-3. Cost of energy of baseline and final 3-bladed 750-kW, 1.5-MW, 

and 3-MW configurations ...................................................................................................................41

Figure 6-4. Comparison of baseline and final costs of 3-bladed configurations by sub-assembly............41

Figure 6-5. Comparison of baseline and final Task #5 loads for 1.5-MW 2-bladed upwind turbine ........42

Figure 6-6. Comparison of baseline and final Task #5 loads for 1.5-MW 2-bladed downwind turbine ...43

Figure 6-7. Cost of energy for 2- and 3-bladed 1.5-MW configurations...................................................43

Figure 6-8. Comparison of baseline and final costs of 3- and 2-bladed 1.5-MW 

configurations by sub-assembly..........................................................................................................44

Figure E-1. Basic WindPACT rotor speed control system ...................................................................... E-4

Figure E-2. WindPACT speed control with tower acceleration feedback ............................................... E-5
iv 

LIST OF TABLES 

Table S-1. Summary of Baseline Design Properties and Cost of Energy...................................................vi

Table 2-1. Types of Files Used in Design Process.......................................................................................6

Table 2-2. Load Case Analyses Carried Out................................................................................................8

Table 2-3. Loads and Variables Recorded During Simulations.................................................................10

Table 3-1. Summary of Cost Models Used for Major Components in Baseline Designs..........................13

Table 3-2. Summary of Aerodynamic and Geometrical Design of Blades................................................17

Table 3-3. Items Included in Operations & Maintenance..........................................................................22

Table 4-1. Initial and Final Overall Specifications ....................................................................................24

Table 4-2. Material Properties Used in Design of Major Components (Task #2) .....................................25

Table 4-3. Characteristics of Final Baseline Configurations .....................................................................26

Table 4-4. Costs of All Wind Farm Items for Baseline Designs ...............................................................27

Table 4-5. Trends from Baseline Designs: Dependence on Diameter ......................................................28

Table 4-6. Critical Load Cases for Baseline Turbines ...............................................................................28

Table 5-1. Initial Table of Configurations for Examination in Task #3 ....................................................31

Table 5-2. Configuration Modifications Chosen for Study in Task #3......................................................32

Table 6-1. Changes Made to Cost Models for Task #5..............................................................................37

Table 6-2. Summary of Properties of the Baseline and Task #5 Final Configurations..............................39

Table 7-1. Transportation Costs vs. Rating................................................................................................45

Table 7-2. Installation Costs vs. Rating .....................................................................................................45

Table A-1. Relative Load Results from Task #3 Configurations.............................................................A-1

Table A-2. Governing Load Cases and Margins for Task #3 Configurations .........................................A-2

Table A-3. Costs and Cost of Energy Summary for All Task #3 Configurations....................................A-3

Table B-1. Comparison of Baseline and Final Loads for 3-Bladed Upwind Machines........................... B-1

Table B-2. Summary of Costs of Baseline and Final 3-Bladed Machines at 

750 kW, 1.5 MW, and 3.0 MW ........................................................................................................ B-2

Table B-3. Comparison of 1.5-MW Final Loads with Baseline Configurations ..................................... B-3

Table B-4. Comparison of Final Costs with 1.5-MW Baseline Configurations ...................................... B-4

Table B-5. Governing Load Cases and Margins for Baseline and Task #5 Final Configurations........... B-5
v 

EXECUTIVE SUMMARY 

Introduction 

This report presents the results of a study completed by Global Energy Concepts (GEC) as part of the 

U.S. Department of Energy’s (DOE’s) WindPACT (Wind Partnership for Advanced Component 

Technologies) project. The purpose of the WindPACT project is to identify technology improvements 

that will enable the cost of energy (COE) from wind turbines to fall to a target of 3.0¢/kWh in low-windspeed sites. Other parts of the project have examined blade scaling, logistics, balance-of-station costs, 

and drivetrain design, while this project was concerned with the effect of different rotor configurations 

and the effect of scale on those rotors. 

Approach

The original project statement of work discussed a very broad set of rotor systems to be examined. To 

focus the research on those areas most useful to the industry, a survey of industry participants was used to 

narrow the number of rotor systems evaluated. The rotor systems were grouped into four basic 

configurations (upwind 3-bladed, upwind 2-bladed, downwind 2-bladed, downwind 3-bladed). The rotor 

systems were defined by making modifications to parameters such as the root-hub attachment, the tip 

speed, the control system, the blade stiffness, etc. For each rotor system an aeroelastic model of the wind 

turbine with the appropriate properties was developed, and a series of simulations corresponding to the 

IEC 61400-1 design conditions were carried out. From these results, key loads were used to design all the 

major components using previously developed design methods in combination with cost models that were 

checked against current commercial data. The results of the analysis for each concept were compared to a 

baseline representative of current industry practice. 

This work was shared between Windward Engineering, LLC, who carried out most of the aeroelastic 

simulations, and GEC, who were the prime subcontractors and responsible for all design and costing 

work. In addition, consultants were used for aspects of blade design, controls, and gearbox and bearing 

design. The project was divided into four major tasks: 

1. Development of cost models (Task #1). 

2. Establishment of 3-bladed upwind, full-span pitch-to-feather, variable-speed baseline designs of 

750-kW, 1.5-MW, 3-MW, and 5-MW ratings (Task #2). 

3. Examination of a series of rotor configurations and modifications and their effects on the cost of 

energy (Task #3). 

4. Combination of the most promising features from Task #3 into final designs of 3-bladed and 

2-bladed upwind and 2-bladed downwind configurations (Task #5). 
vi 

Results

The Task #2 work resulted in the cost of energy for the four baseline designs shown in Table S-1. These 

results illustrate the increase in COE to be expected beyond 1.5 MW. 

Table S-1. Summary of Baseline Design Properties and Cost of Energy 

 750 kW 1.5 MW 3.0 MW 5.0 MW 

Rotor Diameter m 50 70 99 128 

Hub Height m 60 84 119 154 

Max Rotor Speed rpm 28.6 20.5 14.5 11.2 

Hub Overhang m 2.330 3.300 4.650 6.000 

Tower Base Diameter m 4.013 5.663 8.081 10.373 

Cost of Energy Contributions 

Rotor ¢/kWh 0.477 0.543 0.741 0.864 

Drive Train ¢/kWh 1.197 1.234 1.305 1.441 

Controls ¢/kWh 0.047 0.022 0.011 0.006 

Tower ¢/kWh 0.326 0.403 0.561 0.685 

Balance of Station ¢/kWh 1.021 0.852 0.889 1.432 

Replacement Costs ¢/kWh 0.499 0.467 0.434 0.414 

O&M ¢/kWh 0.800 0.800 0.800 0.800 

Total COE ¢/kWh 4.367 4.321 4.741 5.642 

The modifications of Task #3 were all applied to a 1.5-MW rating while maintaining the baseline’s 

variable speed with full-span pitch control features. A total of 23 rotor systems were examined. The 

following three modifications that reduced loads throughout the system and offered widespread benefits 

were identified: 

• Tower feedback in the control system 

• Passive flap-twist-to-feather coupling in the blades 

• Reduced blade chord in combination with increased tip speed. 

These features appeared to benefit each of the four basic rotor configurations. 

In Task #5, these three features were combined in an effort to arrive at the lowest COE. This was done to 

the 3-bladed and 2-bladed upwind and the 2-bladed downwind 1.5-MW configurations. It was also 

applied to the 750-kW and the 3-MW 3-bladed upwind configurations. The results of these analyses 

showed that substantial load reductions were obtained. Cost of energy estimates were made for each of 

these configurations and compared with their corresponding baseline versions (from Tasks #2 or #3), 

which are illustrated in Figures S-1 and S-2. 
3-bladed upwind 

0.0 

1.0 

2.0 

3.0 

4.0 

5.0 

6.0 

750 kW 

Baseline 

750 kW 

T#5 Final 

1.5 MW 

Baseline 

1.5 MW 

T#5 Final 

3.0 MW 

Baseline 

3.0 MW 

T#5 Final 

Cost of Energy, ¢/kWh 

O&M 

Replace't costs 

Balance of stn 

Tower 

Controls 

Drive train 

Rotor 

750 kW 1.5 MW 3.0 MW 

-10.8% -8.2% -12.9% 

Figure S-1. Cost of energy of baseline and final 3-bladed upwind designs. 

1.5 MW Rating 

0.0 

1.0 

2.0 

3.0 

4.0 

5.0 

6.0 

Baseline T#5 Final Baseline T#5 Final Baseline T#5 Final 

Cost of Energy, ¢/kWh 

O&M 

Replace't costs 

Balance of stn 

Tower 

Controls 

Drive train 

Rotor 

3-bladed 

upwind 

2-bladed 

upwind 

2-bladed 

downwind 

-8.2% -10.4% -3.7% 

Figure S-2. Cost of energy for baseline and final 3- and 2-bladed designs at 1.5MW. 

Conclusions 

• The cost of energy of the baseline designs has been reduced by up to 13%. 

• The cost of energy reduction is small relative to the magnitude of the loads reductions that 

occurred throughout the system. 

• More than 50% of the cost of energy is unaffected by rotor design and system loads. Further 

COE reductions may be achieved by addressing the balance-of-station costs. 

vii 
viii 

• Combinations of rotor improvements with parallel improvements in the drive train design and in 

the tower design must be pursued. Such combinations will bring the total COE reductions closer 

to the 30% target. 

• The cost of the rotor as a fraction of the total capital cost rises with increasing rotor size. 

Therefore, larger machines can benefit more from rotor improvements. 

• The cost of a 3-bladed rotor is greater than the equivalent 2-bladed rotor and, for the same reason, 

benefits more from rotor improvements. 

• No single rotor modification offered a solution to reduced rotor costs and lower system loads. 

Instead, there were a number of modifications that offered some general benefits, especially: 

• Inclusion of tower feedback to the blade pitch control system. 

• Incorporation of flap-twist coupling in the blade design. 

• Reduction of the blade chord combined with an increase in the tip speed. 

• The Task #5 improvements were of most benefit to the 3-MW, 3-bladed upwind machine. This 

narrowed the difference in COE within the 750-kW to 3-MW range. 

• The extensive use of carbon fibers was essential to the final blade design. Their greater stiffness 

(compared to glass fiber) was needed to achieve the required flap-twist coupling and to avoid 

contact with the tower. 

• Added costs of transportation and assembly adversely affect the COE for machines rated above 

1.5 MW. Alternatives to the use of conventional cranes and alternative tower designs will 

potentially benefit larger machines. 

• The inclusion of feedback from tower motion into the control system has reduced tower loads 

considerably. This feature has not been optimized, and further improvements may be possible. 

Other control system enhancements may also have beneficial effects. 

Recommendations 

• Combine the findings of this study with those of the parallel WindPACT drive train configuration 

study and the continuing study of the effect of specific rating. This combination may offer COE 

improvements that approach the target COE reduction identified by the WindPACT project. 

• Conduct more testing of material coupons and blade assemblies to support the use of bias-ply 

carbon fibers required for flap-twist coupling. 

• Study the acoustic penalties associated with higher tip speeds and ways of ameliorating them. 

• Develop further refinements of turbine control systems to reduce loads. 

• Study various approaches for reducing COE by changes in the balance-of-station costs and in the 

fixed charge rate. 
1 

1. INTRODUCTION 

1.1 Background 

Over the past 20 years, the cost of wind energy has decreased significantly and is now close to being 

competitive with conventional forms of energy. To achieve the further decrease in cost of energy (COE) 

necessary to make wind energy truly competitive with electricity generated from fossil fuels such as coal 

and natural gas, further reductions in COE of up to 30% are required. To achieve this reduction, a greater 

level of innovation will be required in the design of wind turbines. 

Over the past decades, many concepts have been proposed to reduce loads and to lower COE. However, 

most current commercial machines have converged toward a design consisting of an upwind 3-bladed 

rotor with full-span pitch control. It is difficult for a manufacturer to develop radically new designs in an 

aggressive market-driven environment in which availability of a product is more important than long-term 

innovation. In addition, there is doubt about how far the current trend toward large machines should go 

and where barriers to this trend will be encountered. 

To deal with these issues, the U.S. Department of Energy, through the National Renewable Energy 

Laboratory (NREL), has implemented the Wind Partnership for Advanced Component Technologies 

(WindPACT) project. The purpose of this project is to provide a vehicle for exploring advanced 

technologies for improving machine reliability and decreasing the overall cost of energy. One element of 

the WindPACT project has been a series of design studies aimed at each of the major subsystems of the 

wind turbine to study the effect of scale and of alternative design approaches. 

In June of 2000, Global Energy Concepts, LLC (GEC), was awarded contract number YAT-0-30213-01 

under the WindPACT project to examine the role of the rotor design on the overall cost of energy. 

1.2 Objectives 

There are three principal objectives of this study. 

1. Determine the impact on COE of changes to the rotor size and rating in the 750-kW to 5-MW 

range. 

2. Determine the effect of different rotor configurations and modifications on system loads and 

COE. 

3. Identify rotor design issues that may be barriers to the development of larger machines. 

1.3 Scope 

This report describes the approach and rationale used to reach the objectives of the study and the 

organization of the work between GEC and its subcontractors. It presents the work plan that was 

followed and describes the results of each task. 

Detailed results of all aspects of the calculations of the cost of energy are presented together with 

explanations of the appraisal system used to select the most promising configurations. A set of optimized 

configurations is identified and compared with the initial baseline designs. 
2 

1.4 Results on Web Site 

NREL plans to establish a Web site that will allow access to some of the detailed data related to this 

study. In addition to copies of this report, a number of input data files, ADAMS and FAST input files, 

and design evaluation files will be available. The Web site address is: www.nrel.gov/wind/windpact. 
3 

2. METHODOLOGY 

2.1 Organization 

The organization of the project and of the personnel is shown in Figure 2-1. 

NREL

Technical Monitor

NREL

Contract Administrator

Project Manager

Robert Poore

Co-Principal Investigator

Craig Hansen

(Windward Engineering)

NREL Applied

Research Group

GEC Technical Staff

Tim McCoy (design, data

processing)

Dayton Griffin (blade

design)

Co-Principal Investigator

David Malcolm

(GEC)

Windward Technical Staff

David Laino

Jeff Minnema

Other Project Consultants

Mike Zuteck (blade design)

Bill Holley (controls)

Mark Balas (controls)

Ed Hahlbeck (gearbox, bearings)

Rockwell Automation (power

electronics)

Figure 2-1. Organization of project personnel. 

2.1.1 Work Plan 

The project was divided into nine tasks that reflect the objectives and the organization. Figure 2-2 shows 

these tasks and their scheduling and gives a brief description of each. 

Task #1 was a review of existing cost and optimization studies and the selection of cost models suitable 

for this project. The task led to a kick-off meeting at which GEC and Windward Engineering presented 

their intended approach to NREL. 

In Task #2, a number of baseline configurations were developed in the range between 750 kW and 

5.0 MW. Aeroelastic models were built and analyzed under a number of load conditions, and the major 

components were designed and their costs estimated. 

In Task #3, a number of modifications to the rotor were selected and applied to 3-bladed upwind, 3-

bladed downwind, 2-bladed upwind, and 2-bladed downwind configurations. The COE associated with 

each was calculated, and the most promising modifications were identified. 
4 

Task #5 examined combinations of the results of Task #3 to arrive at optimized 3-bladed designs for 750-

kW, 1.5-MW, and 3-MW ratings. The 2-bladed configurations at 1.5 MW were also optimized. 

The remaining tasks identified particular barriers to development and to size and presented the results of 

the study. 

Process

July

2000

Task 1

Task 2

Task 3

Task 4

Task 5

Task 6

Task 7

Task 8

Task 9

1. Kick-off Meeting

Cost models

Select dynamic model

2. Baseline Models

0.75, 1.5,3.0, 5.0 MW

Standard 3-bladed

upwind

3. Configuration Study

Sweep all configs at 1.5

Select "best" configs

4. Config Design

Review

Configuration review

meeting

5. Detailed Modeling

Selected models. 3

basic configs, 3 sizes

6. Identify Design

Barriers

7. Final Design

Review

8. Final Report

9. Industry

Workshop

July

2001

Feb

2002

Figure 2-2. Tasks and approximate schedule. 

2.1.2 Procedure 

The work was divided between GEC and Windward Engineering. GEC initiated the designs and 

performed the evaluation and costing, while Windward carried out the majority of aeroelastic simulations. 

This relationship is illustrated in Figure 2-3. Excel spreadsheets were used to standardize much of the 

data storage and transfer. 

The project involved examining a large number of different turbine configurations, and it was important 

to have a system to efficiently process and track these. A system of configuration control was established 

based on the naming scheme shown in Figure 2-4. 
5 

Use standardized

spreadsheet to define

model properties

Translate into

FAST or ADAMS

input file

Add control system

Add inflow and

airfoil data

Analyze

Post process

output in CRUNCH

or Matlab

Put all output in

standardized

spreadsheet format

Extract peaks for

peak load design

Evaluate design

margins

Modify design

Combine rainflow

counts with SN

curves for fatigue

damage calculation

Global Energy Concepts Windward Enginering

Independent

aeroelastic analysis to

check results

(occasional)

Figure 2-3. Flow of work between GEC and Windward Engineering. 

x.x X xx Cxx Rxxxx Vxx

size/rating

in MW

revision

number control system

identifcation

number

run number

one of four

ratings:

.75, 1.5,3.0, 5.0

configuration

type ID

(A - Z)

This is a unique

4-digit number

which is

assigned to the

run

this ID number

defines the control

parameters and is

associated with

the configuration

This character

defines the type

of rotor (e.g. 3-

vs. 2-bladed)

blade number

revision of the

blade design

for this

version of

configuration

Figure 2-4. Configuration control scheme for models. 
6 

It was necessary to maintain a number of file types throughout the design process and to standardize the 

file formats for communications between GEC and Windward. These files are listed and described in 

Table 2-1. 

Table 2-1. Types of Files Used in Design Process 

File Type Purpose Format 

Blade design files Used to define the profile and structural 

properties of the blade 

Excel 

Input data files Used to define all details of the turbine 

configuration, from which the simulation 

model was constructed 

Excel 

Output data file Formulated by Windward to store all 

output from a certain configuration 

analysis 

Excel 

Design evaluation and cost Using input and output data files, carried 

out design and cost estimate of all 

components 

Excel 

File log Used to list and track all configurations 

and files listed above 

Excel 

ADAMS input file Constructed by Windward from the input 

file to submit to the ADAMS code 

*.adm 

FAST_AD input file Constructed by Windward from the input 

file to submit to the FAST_AD code 

text 

The relationship among the sets of files and how they were used in the design process and in the flow of 

information between GEC and Windward is shown in Figure 2-5. Information on each file was 

maintained in a central logging system, and samples of each file type are available through the NREL 

WindPACT Web site. Some details of the spreadsheet structure and format are given below. 

2.1.2.1 Blade Design File 

An Excel spreadsheet was prepared to supply the basic properties of the blade. The spreadsheet was 

based on the approach developed for the WindPACT Blade Scaling Project [3] and is described more 

fully in Section 3.2.1. 

The inputs to the spreadsheet were the design moments at key spanwise locations: the root, 25% span, 

50% span, and 75% span. The output from the spreadsheet comprised the required thickness of the box 

spar at those sections and the corresponding section properties and weights. 

2.1.2.2 Input Data File 

The input data file (see Figure 2-5) was used to transmit all information necessary to allow construction 

of a computer model of the entire turbine. The spreadsheet consisted of a Main Page on which all basic 

information was supplied and a number of pages on which further calculations were made and the data 

presented in a format suitable as input to the aeroelastic codes. There was one page each for definition of 

the blade and the tower. 
7 

BladeDesign

x.xXnnV00

InputData

x.xXnn

Windward

simulation

OutputData

x.xXnnCxxRxxxx

GEC

DesignEvaluation

x.xX01CnnRxxxxV00

suggested

modifications

new simulation

required?

BladeDesign

xxXnnV01

DesignEval

xxXnnCxxRxxxV01

BladeDesign

x.xXnn+1V00

InputData

x.xXnn+1

Yes

No

FileLog

FileLog

FileLog FileLog

Windward Engineering

Blade design

parameters, estimates of

design mts.

All other input

design parameters

Figure 2-5. Flow of information in the design process. 

2.1.2.3 Output Data File 

The output data file was received from Windward Engineering and contained all output results from the 

various simulations. This file consisted of: 

• One page with all statistics from all the required signals/loads for all the load cases. 

• One page containing rainflow distributions from all the signals at each of the mean wind speeds 

for normal operation in turbulent conditions. 

• One page with the durations spent at each range of drive train torques for each of the mean wind 

speeds for the normal operation. 

2.1.2.4 Design and Cost Evaluation Process 

This spreadsheet combined the configuration definition and the simulation outputs and determined 

whether the major components were adequately designed. Therefore the Main Page from the input data 

file was copied into the design spreadsheet along with all pages from the output data file. The design 

spreadsheet contained one page for design calculations for each of the following: blades, hub, low-speed 

shaft, gearbox, mainframe, and tower. 
8 

A sheet titled Materials contained all the design properties for all the materials used in the design. 

Another sheet titled Evaluation calculated the margin of safety in the various modes for all components. 

The calculation of the margin of safety for peak loads and for fatigue loading is shown below. 

1

characteri factor_safety_loading*load_stic

characteri factor_safety_material*strength_stic )loadspeak(safetyofinargm = −

margin of safety (fatigue loading) = 1 – (fraction of fatigue damage done by factored loads) 

A positive margin indicated that there was spare safety and that the component could be made lighter, 

whereas a margin of zero indicated that the design was critical. The intent was to adjust all components 

so that all margins of safety were at or very close to zero. Margins for peak loads indicated the amount by 

which the load and/or the static strength could be adjusted. Margins for fatigue load cases indicated the 

amount by which the fatigue life was over or below the 20-year target. 

The Evaluation sheet contained factors by which the major component dimensions could be adjusted. 

This allowed the user to make corrections until all the margins became zero. This process was valid if the 

adjustments were small (less than about 10%) and the required changes would not lead to any significant 

change in loads. However, if the required changes were more substantial, then a new simulation was 

carried out to ensure that the properties used in the aeroelastic analysis were consistent with the final 

configuration. 

2.1.3 Load Cases 

The load cases set out in IEC 61400-1 [1] were used as a basis for the loads simulated in the analysis. All 

the extreme events were simulated and are listed in Table 2-2. None of the fault conditions, such as 

overspeed and emergency stops, were included. The operation in turbulence was carried out with the 

standard IEC Kaimal spectrum [1] for IEC class 2, intensity option A, at mean wind speeds of 8, 12, 16, 

20, and 24 m/s. At each mean wind speed, three 10-minute periods were simulated using different 

random seeds. Emergency stops were added in Task #5. 

Table 2-2. Load Case Analyses Carried Out 

Type of Load Acronym Mean or Initial 

Wind Speeds (m/s) Directions Return Periods 

(Years) 

Normal turbulence 

model, IEC class 2a, 

Kaimal spectrum 

NTM 8, 12, 16, 20, 24 (@ 

3 seeds each) N/A N/A 

Extreme coherent gust 

with direction change ECD 12, 16, 20, 24 Positive, negative N/A 

Extreme coherent gust ECG 12, 16, 20, 24 N/A N/A 

Extreme direction 

change EDC 12, 16, 20, 24 Positive, negative 1, 50 years 

Extreme operating 

gust EOG 12, 16, 20, 24 N/A 1, 50 years 

Extreme vertical wind 

shear EWSV 12, 16, 20, 24 N/A N/A 

Extreme horizontal 

wind shear EWSH 12, 16, 20, 24 Positive, negative N/A 

Extreme wind model EWM 42.5 (@ 5 seeds) Turbulent 50 

Emergency stops 

(Task 5 only) Estop 12, 16, 20, 24 N/A N/A 
9 

2.1.4 Design Methodology 

The following rules were observed in the design process: 

• The limit states approach was used wherever applicable. 

• The partial safety factors for loads (load factors) were in accordance with IEC 61400-1 [1]. 

• The partial safety factors for material strength were in accordance with IEC 61400-1 [1] and with 

the applicable industry design codes. 

• For fiberglass blade design, the material factors from the Germanischer Lloyd regulations [2] 

were used. 

2.2 Specifications for Baseline Configurations 

The NREL Statement of Work included the following specifications for the baseline configurations: 

• Three blades 

• Upwind 

• Full-span variable-pitch control 

• Rigid hub 

• Blade flapwise natural frequency between 1.5 and 2.5 per revolution 

• Blade edgewise natural frequency greater than 1.5 times flapwise natural frequency 

• Rotor solidity between 2% and 5% 

• Variable-speed operation with maximum power coefficient = 0.50 

• Maximum tip speed <= 85 m/s 

• Air density = 1.225 kg/m3 

• Turbine hub height = 1.3 times rotor diameter 

• Annual mean wind speed at 10-m height = 5.8 m/s 

• Rayleigh distribution of wind speed 

• Vertical wind shear power exponent = 0.143 

• Rated wind speed = 1.5 times annual average at hub height 

• Cut-out wind speed = 3.5 times annual average at hub height 

• Dynamically soft-soft tower (natural frequency between 0.5 and 0.75 per revolution) 

• Yaw rate less than 1 degree per second. 

These initial specifications were modified and reinterpreted as the project progressed. The basic 

specifications were revised partway through Task #2; as a result, reference in this document will be made 

to the first and second sets of specifications. No comparisons were made between results using the two 

sets of specifications. All results in this report are based on the second set of specifications. 

2.3 Simulation Software 

There are several codes that are intended for or can be adapted to the aeroelastic analysis of a horizontalaxis wind turbine. The two that were considered for this project were the proprietary code ADAMSTM, 

available from MSC Software of Santa Ana, California (formerly Mechanical Dynamics of Ann Arbor, 

Michigan) [4], and FAST_AD [5], which has been developed by Oregon State University and NREL. 

The former has been used in conjunction with aerodynamic routines to provide a versatile tool able to 

represent any configuration and to include all nonlinear effects. FAST_AD works with the same 

aerodynamic routines but is limited in the types of rotor that can be modeled, and the deformation is 

limited to a number of preselected mode shapes. These limitations are balanced by shorter computer run 

times. 
10 

It was recognized that although FAST_AD would speed the analysis process, only ADAMS could model 

some of the intended configurations. In addition, FAST_AD had not been used in conjunction with any 

control systems, while there was some experience incorporating control systems into ADAMS models. 

For this reason, Task #1 included an item to modify the FAST_AD code for controlling the blade pitch 

and the electrical torque to simulate the modern variable-pitch, variable-speed wind turbine. 

2.4 Signals Recorded 

Table 2-3 lists the loads/measurements that were collected in the aeroelastic simulations, and Figure 2-6 

shows the various coordinate systems that are referenced. Note that the sign convention refers to the load 

applied to the part farther down the load path. For example, the blade root flapwise bending moment 

refers to the moment applied by the blade to the hub. 

Table 2-3. Loads and Variables Recorded During Simulations 

Variable Notation Units 

Time Seconds 

hub height wind speed WShh m/s 

hub height wind direction WDhh degrees (positive, yaw ccw about Z axis) 

low speed shaft speed RpmLss rpm (positive, cw about X axis) 

high speed shaft speed Rpmgen rpm 

aerodynamic power RotorPower kW 

generator electrical power GenPower kW 

yaw angle YawAng degrees (positive ccw about Z axis) 

pitch angle of blade #1 PitchAngB1 degrees (positive moves leading edge upwind) 

Azimuth angle AzimHub degrees (positive cw about X axis) 

out-of-plane displacement of blade tip #1 DxTipOutB1 m (positive downwind) 

in-plane displacement of blade tip #1 DyTipInB1 m (measured in hub coordinates) 

out-of-plane displacement of blade tip #2 DxTipOutB2 m (positive downwind) 

in-plane displacement of blade tip #2 DyTipInB2 m (measured in hub coordinates) 

out-of-plane displacement of blade tip #3 DxTipOutB3 m (positive downwind) 

in-plane displacement of blade tip #3 DyTipInB3 m (measured in hub coordinates) 

longitudinal displacement of tower top DxLongT m (positive downwind) 

lateral displacement of tower top DyLatT m 

edgewise bending moment at 75% span, blade #1 Mx75EdgeB1 kN m (positive, trailing edge in tension) 

Flapwise bending moment at 75% span, blade 

#1 

My75FlapB1 kN m (positive, upwind face in tension) 

edgewise bending moment at 50% span, blade #1 Mx50EdgeB1 kN m (positive, trailing edge in tension) 

Flapwise bending moment at 50% span, blade 

#1 

My50FlapB1 kN m (positive, upwind face in tension) 

edgewise bending moment at 25% span, blade #1 Mx25EdgeB1 kN m (positive, trailing edge in tension) 

Flapwise bending moment at 25% span, blade 

#1 

My25FlapB1 kN m (positive, upwind face in tension) 

Flapwise shear force at root of blade #1 FxRtFlapB1 kN (positive in blade x direction) 

edgewise shear force at root of blade #1 FyRtFlapB1 kN (positive in blade y direction) 

axial force at root of blade #1 FzRtExtB1 kN (positive in tension) 

edgewise bending moment at root of blade #1 MxRtEdgeB1 kN m (positive, trailing edge in tension) 

Flapwise bending moment at root of blade #1 MyRtFlapB1 kN m (positive, upwind face in tension) 

Flapwise shear force at root of blade #2 FxRtFlapB2 kN (positive in blade x direction) 

edgewise shear force at root of blade #2 FyRtFlapB2 kN (positive in blade y direction) 

axial force at root of blade #2 FzRtExtB2 kN (positive in tension) 

edgewise bending moment at root of blade #2 MxRtEdgeB2 kN m (positive, trailing edge in tension) 

Flapwise bending moment at root of blade #2 MyRtFlapB2 kN m (positive, upwind face in tension) 

Flapwise shear force at root of blade #3 FxRtFlapB3 kN (positive in blade x direction) 

edgewise shear force at root of blade #3 FyRtFlapB3 kN (positive in blade y direction) 

axial force at root of blade #3 FzRtExtB3 kN (positive in tension) 

edgewise bending moment at root of blade #3 MxRtEdgeB3 kN m (positive, trailing edge in tension) 
11 

Table 2-3 (Continued). Loads and Variables Recorded During Simulations 

Variable Notation Units 

Flapwise bending moment at root of blade #3 MyRtFlapB3 kN m (positive, upwind face in tension) 

axial thrust in low speed shaft FxThrustS kN 

shear force in shaft edgewise to blade #1 FyS kN 

shear force in shaft parallel to blade #1 FzS kN 

torque in low speed shaft MxTorqS kN m 

bending in low speed shaft at hub center about 

axis parallel to blade #1 chord 

MyS kN m 

bending in low speed shaft at hub center about 

axis parallel to blade #1 span 

MzS kN m 

bending in low speed shaft at main bearing about 

axis parallel to blade #1 chord 

MyBrgS kN m 

bending in low speed shaft at main bearing about 

axis parallel to blade #1 span 

MzBrgS kN m 

electrical torque applied to drive train GenTorq kN m 

downwind thrust at yaw bearing FxAxialN kN 

lateral thrust at yaw bearing FyLat kN 

Vertical load at yaw bearing FzVertN kN 

Pitching moment at yaw bearing MypitchN kN m 

yawing moment at yaw bearing MzYawN kN m 

lateral bending moment at base of tower MxLatT kN m 

longitudinal bending moment at base of tower MyLongT kN m 

torsional moment at base of tower MzYawT kN m 

Blade Pitch Rotation:

Blade coordinates relative

to hub coordinates

Hub Teeter Rotation:

Hub coordinates relative

to shaft coordinates

Shaft Rotation:

Shaft coordinates relative

to nacelle coordinates

Yaw Angle

Yaw Rotation:

Nacelle coordinates

relative to tower coordinates

Yt

Xt

Yn

Xn

Pitch Angle

Yh

Xh

Yb

Xb

Azimuth

Angle

Zn

Zs

Ys

Yn

Teeter Angle

Zs

Xs

Zh

Xh

Xt

Yt

Zt

Global / tower coordinates

Key:

t = tower

n = nacelle

s = shaft

h = hub

b = blade

Figure 2-6. Coordinates systems used and corresponding rotations.
12 

3. TASK #1. DESIGN AND COST MODELS 

3.1 General Approach 

In order to calculate the effect of rotor changes on the final cost of energy, it was necessary to be able to 

estimate the cost of all major wind turbine components and to know how those costs change with 

perturbations in the rotor design. Task #1 of the project consisted largely of developing these cost 

relations. 

The following general approaches and guidelines were used: 

• Apart from the rotor, all components or subassemblies were assumed to be of a “standard” 

design. 

• The wind farm was assumed to be of 50 MW rated power for all the turbine sizes considered. 

• The costs of all components corresponded to “mature production,” implying that further 

economies of scale of manufacture are not available. 

• It was important to obtain cost estimates that were realistic, but the exact cost of components was 

not as important as the changes due to rotor configuration changes. 

• In general, all components were checked for their adequacy under both peak and fatigue loads. 

• The cost of each major component was checked against at least one known commercial example. 

• For most components, the cost was considered to be a function of the weight. 

• The size and weight of many components were expressed as functions of the rotor diameter. 

• Expressions from other cost models were checked for their applicability to current designs. 

• Smooth functions were developed for all items, although the data from which they were derived 

may have contained discrete steps. 

Table 3-1 summarizes the approaches and formulas used for costing all items. 

As the project progressed, some of the initial cost models became inadequate. For example, during the 

Task #2 baseline study when different rotor sizes were being compared, it was important for the cost of 

items such as pitch bearings to reflect the changes in rotor diameter. However, in Task #3 when the effect 

of different configurations and associated load changes were being studied, a cost model that could reflect 

the effects of small changes in peak loads was required. For reasons such as this, some cost models were 

revised during the project. In these cases, Table 3-1 includes multiple entries for those items. 
13 

Table 3-1. Summary of Cost Models Used for Major Components in Baseline Designs 

Component Cost Model/Formula Verification/Comparison Comment 

Blades (Task #2) WindPACT blade scaling design [3], 

$10.95 /kg 

750 kW 

Class 1 wind: 2130 kg 

Class 2 wind: 1660 kg 

av. commercial: 2200 kg 

E-glass with 

structural spar 

Blades (Tasks #3, 

#5) 

$16.42/kg for hybrid carbon-glass spar 

$16.42/kg for bias-ply carbon-glass 

skins 

Costs from a range of 

commercial data [7] 

Hub (Tasks #2, 

#3) 

Static analysis using peak root mt with 

scale factor of 2.5 

$4.25 /kg 

Scale factor selected to give 

750kW weight = 3100 kg 

compared with a commercial 

750/50 machine 

Cast ductile iron 

sphere with 

openings, grade 65-

45-18 

Hub (Task #5) Static analysis using peak root mt. with 

scale factor of 1.92 

$4.25 /kg 

Scale factor selected to give 

better agreement with hub of 

47-m machine 

Teeter hub Static analysis of cylindrical tube using 

peak root mt with scale factor = 3.50. 

Mass x 2 for teeter and dampers. 

Overall $7.70/kg. 

Overall costs from AWT-27 Total mass less 

than 3-bladed hub, 

but cost is greater 

Pitch bearings 

Not used for final 

costing. 

$/bearing = 0.0454*D2.98 

Cost doubled for remaining system and 

drives 

Data from Avon bearings 

(Appendix C). 

750-kW costs and weights 

compared with commercial 

data 

See text 

Pitch bearings 

(Tasks #2, #3, #5) 

Mass [kg] = 0.0110 (mt/diam)1.489

cost[$] = 6.689*kg + 953 

Curve fit through Avon data See text 

Gear box Life_factor [1/Nm] = 0.1628*mass-1.340 

$/kg = 0.000647*rating[kW]+13.26 

Ed Hahlbeck/Powertrain 

Engineers Inc. [8]. 

Unit_stress vs. mass curve 

fitted to 4 point designs 

Final relationship: 

mass≅const*D2.2 

Generator (Tasks 

#2, #3) 

$65.00/kW rating 

mass[kg] = 3.3*rating[kW] + 471 

Mass model from U of 

Sunderland [6]. Cost checked 

with commercial data 

1800-rpm wound 

rotor induction 

motor with power 

electronics 

Generator (Task 

#5) 

$52.00/kW rating 

mass[kg] = 3.3*rating[kW] + 471 

Cost model made consistent 

with WindPACT Drive Train 

study [9] 

Main shaft $7.00/kg, length = 0.03*D, scale factor = 

4.0, ID = 0.5OD. Diameter kept constant 

in Task #3 changes and thereafter 

U of Sunderland [6] and 

current commercial designs 

Shaft often 

governed by 

stiffness rather than 

by strength 

Main bearings Bearing mass = (D x 8/600 – 0.033) x 

0.00920 x D^2.5 

Where D = rotor diam (m) 

cost = $17.60/kg 

Powertrain Engineers Inc. 

Bedplate Ductile iron casting, grade 60-45-18 

$4.25/kg 

Scale factor included to 

obtain agreement with 

industry (5800 kg for 750-kW 

turbine) 

Stress analysis of 

channel section 

using moments at 

yaw bearing 

Nacelle cover 

(Tasks #2, #3) 

Area = length2

length[m] = 2*yaw brg to outer main brg 

mass = 84.1 kg/m2

cost = $10.00/kg 

U of Sunderland formula for 

kg/m2

. Cost from Morrison 

Fiberglass 

Nacelle cover 

(Task #5) 

Area = length*(width+height) 

length[m] = 2*yaw brg to outer main brg 

mass = 84.1 kg/m2

Area formula modified to be 

less sensitive to length 

Note: Unless specified otherwise, quantities use the units of m, kg, kW, and kN m. 
14 

Table 3-1 (Continued). Summary of Cost Models Used for Major Components in Baseline Designs 

Component Cost Model/Formula Verification/Comparison Comment 

Hydraulics $4.50/kW GEC estimate 

Brakes, couplings Mass [kg] = 0.025*ratedHStorque[Nm] 

$10.00/kg 

Mass from U of Sunderland 

[6] 

Yaw system (Task 

#2) 

$/bearing = 0.0339*D2.96 

cost doubled for remaining system and 

drives 

Data from Avon bearings. 

Initial estimates from [6] 

See text 

Yaw system 

(Tasks #3, #5) 

Mass [kg] = 

0.0152(max_mt/bearing_diam – 36)1.489

$ = 6.689*mass + 953 

Mass and cost made 

dependent on peak load 

Switchgear $40.00/kW Industry data 

Power electronics 

(Tasks #2, #3) 

$67.00/kW (total electrical) U.S. manufacturing industry Variable-speed 

system using 

wound rotor 

induction motor 

Power electronics 

(Task #5) 

$54.00/kW (total electrical) Comparison with data from 

WindPACT Drive Train study 

[9] 

Controls $9500 + 10*D [6] 

Tower $1.50/kg Initial design tuned to agree 

with commercial 750/50 data 

Costs per U.S. steel 

fabricating industry 

Foundations 

(Task #2) 

$/kW = 584*Rating-0.377 Adjusted to agree with quotes 

from Patrick & Henderson for 

750- and 1500-kW machines 

The steel caisson 

design of P&H is 

cheaper than 

traditional concrete 

slab designs 

Foundations 

(Tasks #3, #5) 

$ = 510 * (Max_base_mt[kN m])0.465 Adjusted to agree with 

updated quotes from Patrick 

& Henderson for a range of 

machine sizes 

Includes influence 

of changes in base 

loads 

Transportation $/kW = 1.581E-5*Rating2 – 

0.0375*Rating + 54.7 

Obtained from WindPACT 

logistics study [12] 

Reflects large 

increases 

associated with 3- 

and 5-MW turbines 

Assembly, 

installation 

$/kW = 3.38E-7*Rating2 + 

9.84E-4*Rating + 31.57 

Obtained from WindPACT 

logistics study [12] 

Roads, civil works $/kW = 2.17E-6*Rating2 – 

0.0145*Rating + 69.54 

Obtained from WindPACT 

report [13] 

Modifications to 

width of roads and 

cost of crane pads 

Electrical interface $/kW = 3.49E-6*Rating2 – 

0.0221*Rating + 109.7 

Obtained from WindPACT 

report [13] 

Includes turbine 

transformers and 

cables to substation 

Permits, 

engineering 

$/kW = 9.94E-4*Rating + 20.31 Obtained from WindPACT 

report [13] 

Long-term 

replacement 

$15/kW/year Based on Danish survey of 

experience in that country 

[18] 

Replacement of 

blades, gearbox, 

generator, etc. 

Operations and 

maintenance 

$0.008/kWh Flat rate adopted so that 

other trends can be 

investigated later 

Excludes taxes, 

lease costs, and 

insurance 

Note: Unless specified otherwise, quantities use the units of m, kg, kW, and kN m. 
15 

3.2 Rotor Components 

3.2.1 Blade Design 

3.2.1.1 Aerodynamic Specifications 

The blades are at the focus of this project, and it was therefore necessary to model them in some detail. 

As part of the study, the blades in current use in the industry were reviewed, and the following guidelines 

were adopted as being typical of current commercial practice. 

• Maximum tip speed = 65 m/s 

• Ratio of maximum chord to rotor radius = 0.09 

• Tip speed ratio for maximum power coefficient = 7.0 

• Ratio of maximum (electrical) power to swept area = 0.44 kW/m2

 (“specific rating”) 

The data used to select the specific rating are illustrated in Figure 3-1, in which a value of 0.44 kW/m2 is 

close to an average value. The NREL specification relating the rated wind speed to the hub-height mean 

wind speed, combined with the presence of vertical wind shear, leads to a variation of specific rating with 

hub height and hence to rotor diameter. This relationship is also shown in Figure 3-1 and is close to the 

line representing commercial data. 

0.20

0.25

0.30

0.35

0.40

0.45

0.50

0.55

0.60

0.65

0.70

40 50 60 70 80 90 100 110 120

Rotor Diameter (m)

Specific Rating (kW/m2

)

Commercial Blade Data

Vrated = 1.5 Vmean

Linear (Commercial Blade Data)

Figure 3-1. Specific rating vs. rotor diameter for current commercial wind turbines. 

3.2.1.2 Baseline Blade Design 

The final design and cost of the blades were determined through an iterative process using the results of 

the loads from the aeroelastic simulations. However, an initial design model was needed. The design of 

the rotor blades for the baseline configurations followed the results from the WindPACT blade-scaling 

project [3] that was completed at GEC near the same time that this project began. The blade-scaling 

project examined the feasibility and cost of increasing the scale of “current technology” in blade design 

and was based on the following approach: 
16 

• The blades were assumed to consist of a fiberglass skin of largely triaxial material sandwiching a 

balsa core for stability. Each skin thickness was 1.78 mm. 

• Each blade included a longitudinal box spar that spanned from 0.15 of the chord position to 0.50 

of the chord. This spar was composed mainly of uniaxial glass fibers. This spar began at the 

25% span location (corresponding to maximum chord) and tapered off to zero at the tip. 

• The blade section was circular between the root at 5% span and 7% span, and then it transformed 

to the S818 30% airfoil shape at 25% span location. 

• The section was reinforced at the root to accommodate the attachment studs for which a weight 

estimate was made. 

• The loading used to obtain the first design estimate was the 50-year extreme wind on the 

stationary blade using the maximum lift coefficient along the entire blade. 

• Designs were generated for four sections: 7%, 25%, 50%, and 75%. 

• Designs for the required spar were based on interpolation between results for total spar thickness 

values of 0%, 5%, and 10% of the airfoil thickness. 

• Input to the blade design spreadsheet consisted of the material properties and a set of flapwise 

design moments. The output consisted of the spar thickness required to resist the design moments 

together with the corresponding section properties and the surface strains due to a unit bending 

moment. 

A number of weight and cost models are included in the University of Sunderland report [6], but we did 

not make use of these for the initial design since the model from the WindPACT Blade Scaling project [3] 

was available and could be tailored to this project. The WindPACT model is based on the extreme 

50-year gust, assuming that the maximum lift occurs simultaneously along the entire blade. It also 

includes a check for edgewise fatigue due to gravity loads plus the torque at rated power. 

The WindPACT blade-scaling study also considered the cost of tooling and the implications of the size of 

the production run. The current project assumes that all costs correspond to “mature production,” which 

means that at least 100 blades are produced per year. This value will be reached earlier when 750-kW 

machines are used than when 5-MW machines are involved. 

3.2.1.3 Airfoil Schedule 

The NREL S-series airfoils were used for the blade designs of this study. In the work of References [19] 

and [20], the S818/S825/S826 family was identified as having desirable aerodynamic properties. 

However, the airfoils were deemed to be too thin for efficient application to large blades (assuming 

current commercial materials were used). A more structurally suitable set of airfoil shapes was derived 

by scaling the S818/S825/S826 foils and by the addition of a finite-thickness trailing edge. The shape 

modifications and locations of airfoils along the blade are summarized in Table 3-2; the resulting airfoil 

shapes are shown in Figure 3-2. 

In Task #3 some of the configurations were composed of a hybrid carbon-glass spar. The cost of this 

construction was taken from [3]. In Task #5, the blade construction was further altered to include carbonglass skins with a bias angle to incorporate flap-twist coupling. The cost of this was based on estimates in 

[7]. 
17 

Table 3-2. Summary of Aerodynamic and Geometrical Design of Blades 

750 kW 1.5 MW 3.0 MW 5.0 MW 

Airfoils type / 

aspect ratios / 

twist (degrees) 

used 

@ 5% span 

@ 7% span 

@ 25% span 

@ 50% span 

@ 75% span 

@ 100% span 

cylinder / / 10.5 

cylinder / / 10.5 

S818 / 0.27 / 10.5 

S825 / 0.24 / 2.5 

S825 / 0.21 / 0.0 

S826 / 0.16 / -0.6 

cylinder / / 10.5 

cylinder / / 10.5 

S818 / 0.30 / 10.5 

S825 / 0.24 / 2.5 

S825 / 0.21 / 0.0 

S826 / 0.16 / -0.6 

cylinder / / 10.5 

cylinder / / 10.5 

S818 / 0.33 / 10.5 

S825 / 0.24 / 2.5 

S825 / 0.21 / 0.0 

S826 / 0.16 / -0.6 

cylinder / / 10.5 

cylinder / / 10.5 

S818 / 0.33 / 10.5 

S825 / 0.24 / 2.5 

S825 / 0.21 / 0.0 

S826 / 0.16 / -0.6 

Rotor diameter first 

specification 

46.6 66.0 93.0 120.0 

 second 

specification 

50.0 70.0 99.0 128.0 

Chord at 

25%/radius 

first 

specification 

0.09 0.09 0.09 0.09 

 Second 

specification 

0.08 0.08 0.08 0.08 

Tip speed ratio 

for max Cp 

 7.0 7.0 7.0 7.0 

Root section 

diameter 

 0.054*D 0.054*D 0.054*D 0.054*D 

Spanwise 

radius at root 

 0.025*D 0.025*D 0.025*D 0.025*D 

Note:D is the diameter of the rotor. 

-0.2

-0.1

0.0

0.1

0.2

0.0 0.2 0.4 0.6 0.8 1.0

x/c

y/c

Scaled S818 Scaled S825 Scaled S826

NREL S-series airfoils 

(scaled) with finite 

thickness trailing edge

Figure 3-2. Airfoils used for baseline 1.5-MW blade model. 

3.2.2 Hub 

Most current 3-bladed rotors use a hub made from a ductile iron casting in the shape of a sphere with 

openings for the blades and for the shaft connections. The stress analysis and design of these components 

are done by finite element analysis of multiple load cases, which this project could not attempt to 

duplicate. Instead, a simplified approach based on static analysis and a suitable “scale factor” was used. 

The approach consisted of calculating the membrane stress due to the maximum applied moment at the 
18 

opening as a function of sphere diameter, opening diameter, and shell thickness. This membrane stress 

was increased by a scale factor, which accounted for the stress concentrations around the opening, and 

combined with appropriate material properties to arrive at a design. 

The final mass was calculated as a complete sphere with the prescribed diameter and wall thickness. This 

implied that the reinforcements around the four openings were equivalent to a uniform sphere. The total 

mass of the hub obtained in this manner was compared with some commercial hubs and the scale factor 

was tuned so that the model and commercial values were in good agreement. Initial comparisons 

indicated that a scale factor of 2.5 was appropriate. Further comparisons carried out later in the project, 

during Task #3, suggested that this value was too high, and a value of 1.92 was adopted from then 

onwards. The lower value was used for all results presented in this report. 

3.2.2.1 Pitch Bearings 

It was assumed that each of the blades is pitched independently. The pitch system for each blade consists 

of a bearing, a speed reducer, an electric drive motor, a controller, and a power supply. Each blade is 

mounted to the hub via turntable bearings with an internal slewing ring for engagement with a drive 

pinion. The pinion is driven through a speed reducer by a high-rpm electric motor. 

An initial model for the total cost was: $/bearing = 0.0454*D2.98. This was found to correspond well with 

data obtained later from Avon Bearings (see Appendix C). These data included cost estimates for the 

range of ratings of interest and were based on initial estimates of peak moments. The mass and cost of the 

auxiliary pitch drive components were estimated to be equal to that of the pitch bearing itself and a factor 

of 2.0 was, therefore, added to the cost. However, as noted below, this model was not used for the final 

estimates in the costing and scaling efforts. 

Different bearing types were recommended by Avon at the different sizes because of the relatively small 

diameter of these bearings compared to the high loads they must carry. At 750 kW, a single-row ball 

bearing was selected, whereas at the 1.5 MW and higher ratings, triple-row bearings were recommended 

and quoted. The cost quoted for bearings for the 5-MW size did not fall on the same curve as for the 

others and it was therefore neglected in defining the cost model. 

A new cost model was defined for Tasks #2, #3, and #5 that reflected cost changes due to changes in the 

peak loads applied. Therefore, the Avon cost data was reformatted into the following form: 

953689.6*[$]cos

][

max_ ][_ 0110.0][

489.1

= +

⎟

⎟

⎠

⎞ ⎜

⎜

⎝

⎛ =

masst

mdiameter

applied mkNmoment kgmass

For Tasks #2, #3, and #5, it was again assumed that the cost of the remainder of the pitch system (motor, 

speed reducer, controller, etc.) is equal to the cost of the bearing. 

3.2.2.2 Teetered Hub 

The concept adopted for the design of the teetered hub was of a cylindrical tube that mated with the blade 

pitch bearings at either end and was attached to the shaft through a central teeter pin. The wall thickness 

of the tube was designed by the peak moment from the blade roots and was adjusted by a scale factor to 

give agreement with known data (the AWT-27) and to be comparable to the mass of the equivalent 3-

bladed hubs. The mass of the remaining items (modifications to the single tube, the teeter pin, the 

dampers, etc.) was assumed to be equal in weight to the cylindrical tube. The cost of the total assembly 

was calculated using a value of $7.70/kg, which was calculated from the known cost and mass of the 

AWT-27 turbine components. 
19 

A scale factor of 3.50 was used. This value resulted in total hub weights that were slightly less than the 

total weights of corresponding 3-bladed hubs. The cost of the teetered hub was higher than that of the 

3-bladed hub due to the costs involved in the teeter pin and damper units. 

3.2.3 Drive Train Components 

The drive train includes all components from the main shaft to the connection to the pad mount 

transformer including any power electronics and electrical switches. In addition to the mechanical and 

electrical power delivery and conversion equipment, all the structural components and auxiliary 

mechanical and electrical components between the hub and the tower top are included in the drive train 

group. The following sections address the sizing, weight, and cost modeling of these components. 

3.2.3.1 Main Shaft 

The main shaft was assumed to be a hollow cylinder with a flanged end for a bolted connection to the 

hub. The length was initially fixed at 0.03*(rotor diameter) and the inner-to-outer-diameter ratio was 

fixed at 0.5. Determination of the outer diameter was based on an analysis of the stress at the bearing 

closest to the rotor (the location of peak bending) with an added scale factor of 4.0 to allow for stress 

concentrations and to obtain initial agreement with current designs and with the University of Sunderland 

report [6]. Both peak stresses and fatigue were considered. The shaft was assumed to be made from 

high-strength steel with a characteristic yield of 828 MPa. The mass of the shaft, calculated from the 

length and diameter, was used to assess the cost at $7.00/kg. 

The cost of the main shaft was initially allowed to change with the changes in loads created in Task #3. 

However, it was determined that the shaft diameter was usually dictated by stiffness rather than strength 

considerations, so that the mass and cost of the main shaft should remain constant with these 

perturbations. This approach was adopted throughout Task #3 and for the remainder of the project. 

3.2.3.2 Main Bearings 

The main bearing was assumed to be of a standard type and a formula for the mass was developed based 

on data, collected by Powertrain Engineers Inc., from wind turbines between 750 kW and 2000 kW. The 

second bearing was included in the gearbox assembly. The resulting expression for the bearing mass, in 

terms of the rotor diameter, D, was: 

Mass (kg) = (D x 8/600 – 0.033) x 0.00920 x D^2.5 

The mass of the bearing housing was assumed to be the same as that of the bearing itself and a rate of 

$17.60 per kg was used for both components. 

3.2.3.3 Gearbox 

For the design of the gearbox, Ed Hahlbeck of Powertrain Engineers was contracted to provide point 

designs for the 750-kW, 1.5-MW, 3-MW and 5-MW baseline turbines. These design results included 

detailed fatigue analyses, mass estimates, and costs. Powertrain Engineers was given the baseline turbine 

parameters and a requirement to operate at rated torque for a lifetime of 200,000 hours. The analysis was 

based on the standard AGMA methodology combined with experience in wind turbine gearbox design. 

The analyses and results can be found in Reference [8]. 

 

GEC used a combination of the resulting gearbox masses and the intermediate stress results to develop a 

model of gearbox mass based on the torque histograms from the simulations at each turbine rating. The 

unit stresses from the gears with the lowest safety margins were curve fit to the total mass of the 
20 

corresponding four gearbox point designs. The critical unit stress in the gearbox could then be calculated 

from a gearbox mass estimate. This unit stress, when combined with the torque histogram from the 

simulations, was used in a fatigue analysis using standard AGMA SN curves. If the predicted life was 

above or below that required, the mass was adjusted and the stress and life recalculated until a converged 

mass estimate was reached. 

The life factor (stress divided by maximum allowable stress) is used in fatigue life calculations and was 

related to the gearbox mass by the following formula: 

 Life factor per unit torque [1/(N m)] = 0.1628*(gearbox mass[kg])-1.3405 

The gearing for large turbine ratings becomes very large and the costs per unit mass tend to rise and the 

cost function used was: (0.000647*rating[kW] + 13.26) $/kg. 

3.2.3.4 Generator 

The baseline turbine assumes a wound rotor induction generator with slip rings, which allows variablespeed operation. The generator mass model was taken from the University of Sunderland report [6] for an 

1800-rpm wound rotor with slip rings. The cost models were verified with data from commercial data. 

The initial models used were: 

mass [kg] = 3.3*rating[kW] + 471 

cost = $65.00 /kW 

In Task #5, this cost model was compared with information used in the parallel WindPACT Drive Train 

study [9]. In order to be compatible with the more detailed study of electrical components in that project, 

the generator cost was reduced to $52.00/kW. 

3.2.3.5 Power Electronics 

No mass estimates were made for the power electronic system because it is assumed that they are inside 

the tower at the base and do not affect the turbine dynamic simulation. 

The initial cost model used was $67.00/kW, where the kW is from the total system rating rather than the 

rating of the power electronics. This value was based on data related to a major manufacturer. Later in 

the project, this cost was also compared with information available from the WindPACT Drive Train 

study [9] and, as a result, the cost was reduced to $54.00/kW. 

3.2.3.6 Bedplate 

The bedplate was assumed to be a 60-45-18 grade ductile iron casting with a tapered channel shape. A 

stress function was developed based on bottom and side wall thickness, and cross section width and 

depth. The overhanging moment and yaw moment at the yaw bearing were used to calculate the required 

dimensions to meet both peak and fatigue analysis requirements. An additional scale factor of 9.0 was 

applied to the stress analysis to obtain agreement with current industry data. 

The cost of the bedplate was assessed by calculating the mass that satisfied the stress analysis and adding 

50% to cover additional material not directly required to support the rotor, such as the section for the 

generator, etc.. The cost function used was $4.25/kg, which includes casting and machining costs. 

3.2.3.7 Nacelle Cover 

The nacelle cover was assumed to be fiberglass and to cover the entire length of the nacelle. A mass per 

unit area equal to 84.1 kg/m2

 [6] and a cost of $10.00/kg was applied (as quoted by Morrison Molded 

Fiberglass). The estimated surface area was initially calculated as the square of the length where the 

length is twice the distance from the yaw axis to the outer main bearing [6]. 
21 

This formula for the cladding area is very sensitive to the length of the nacelle because the formula 

assumes that the width and the height also increase with the length. In Task #5, the mass model was 

changed to be dependent on the width and the height of the drive train, as well as the length. 

3.2.3.8 Yaw System 

The yaw system consists of a turntable bearing and slew ring driven by multiple electric drives that are 

connected to the slew ring through a speed reducer and pinion. The mass, calculated for use in the 

simulations, was estimated from the equation in the University of Sunderland report [6]. This equation is 

a function of the rotor diameter and the initial estimates for rotor thrust, tower head mass, and tower top 

diameter. 

The yaw bearing costs were based on quotes from Avon Bearings (see Appendix C) for the four baseline 

turbines. These quotes were curve fit to the rotor diameter, resulting in the following relation: 

 yaw bearing cost [$] = 0.0339*(Rotor diameter[m])2.96 

This formula is dependent only on the rotor diameter and was not suitable for reflecting cost changes due 

to changes in the loads for configurations having the same rotor diameter. The masses and costs from 

Avon Bearings were reexamined and reformatted to be dependent on the maximum moment applied. 

953689.6*mass[$]tcos

36

]m[diameter

max_ ]mkN[moment_applied 0152.0]kg[mass

489.1

= +

⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ = −

The diameter of the yaw bearing was calculated as 0.03 times the rotor diameter. The total cost of the 

yaw system was estimated to be equal to twice the cost of the bearing. 

3.2.3.9 High-Speed Shaft, Coupler, Brakes 

The mass of the high-speed shaft and coupler were estimated based on the equation in Reference [6] as 

follows: 

Mass [kg] = 0.025*rated HSS torque [N m] 

The mass of the brake calipers and additional disk mass on the coupler were estimated as an additional 

50% of the shaft and coupler mass. The cost for all of these items was assumed to average out to 

$10.00/kg. 

3.2.3.10 Hydraulics and Lubrication 

It was assumed that the hydraulic system is used only for the brakes and that the lubrication includes 

equipment for cooling the gearbox and bearings. 

Cost = $4.50/kW 

3.2.3.11 Switchgear and Other Electrical 

The cost of the electrical systems (switchgear, transformer, cables, cabinets) exclusive of controls and 

power electronics was assumed to increase directly with rating. The cost model used was $40.00/kW. 

3.2.4 Tower 

The tower was assumed to be a tapered steel tube and was designed for peak and fatigue bending 

moments at the base and at the top. The total mass was calculated using a linear taper of both diameter 

and wall thickness between the top and bottom, and a rate of $1.50/kg was used to arrive at a total cost. 
22 

This rate was obtained by consultation with members of the steel fabricating industry and by comparison 

with known costs of towers in the Turbine Verification Project [10]. 

The design check of the tower sections used a material yield stress of 350 MPa and a fatigue strength 

defined by BS7608 class D. A check was also carried out for local stability using formula 14.16 from 

[11]. In order to maintain the diameter/wall thickness ratio to values that are acceptable to manufacturers, 

a maximum ratio of 320 was adopted. In addition, the diameter of the top of the tower was specified to be 

no less than 0.5 of the base diameter. This was done for reasons of access, accommodation of the yaw 

bearing, and for aesthetics. 

3.2.5 Balance of Station 

The costs of most items in the balance-of-station category were obtained from the earlier WindPACT 

studies on logistics [12] and balance of station [13]. The scenarios used in these reports referred to a 

selected site in South Dakota and are appropriate for the current study. Trend lines were developed from 

the WindPACT results and were used in this project. The trend line formulas are listed in Table 3-1. 

The WindPACT values for Roads & Civil Works from [13] were considered unrealistic and were 

modified. The costs of the gravel pads for the cranes were reduced by a factor of 2, and the roads for the 

2.5-MW and 5-MW machines were adjusted to have a 40-ft (12-m) width. 

3.2.5.1 Foundations 

The costs of the foundations were based on information received from Patrick & Henderson, Inc. of 

Bakersfield, California. That company has developed a cost-effective system of wind turbine foundations 

utilizing a post-tensioned, concrete-filled steel caisson. Their costs were adjusted for the hub heights of 

the current project and were fit to a power curve resulting in the formula below. These costs assume soil 

conditions typical of the Great Plains. 

 $/kW = 584*Rating[kW]-0.377

This formula was found inadequate for Task #3 when the effects of small changes in loads were required. 

Therefore the costs were reevaluated and also updated with additional data from Patrick & Henderson to 

arrive at the following expression, which was used for Tasks #3 and #5: 

 Cost [$] = 510*(max_base_moment[kN m])0.465

3.2.5.2 Operating Costs 

There are several types of costs that are sometimes included in the category of “operations and 

maintenance.” They may be divided into those associated with operations and those associated with 

maintenance. 

Table 3-3. Items Included in Operations & Maintenance 

Class of O&M Cost 

Operations Maintenance 

Local property taxes Regular scheduled maintenance 

Insurance Unscheduled maintenance 

Land lease Long-term replacement 

Project administration 

Local utilities 
23 

A number of sources were used to survey current costs, and the results varied widely, in part because they 

did not all include the same items and because the circumstances of each information source are always 

different [16, 17]. In addition, operators are naturally reluctant to disclose information that may be 

proprietary. 

It was especially difficult to obtain data that could help to predict the effect of scale on O&M costs for 

which it is necessary to separate the effects of age from the effects of size. One source used was a report 

by Lemming & Morthorst [15]. 

In order to simplify this situation, the following decisions were made: 

• All the operations costs were included in the 10.6% financing charge rate (this was approved by 

the staff of the NWTC). 

• The long-term replacement costs were fixed at $15.00/kW/year (based on reports from Europe 

[18]). 

• The remaining operations costs were fixed at $0.008/kWh in accordance with NREL guidelines. 

No attempt was made to vary the costs with machine size. It is recognized that different models may 

affect the trends observed in this study. 

3.3 Control Systems 

The cost of the control and protection system must include the cost of the necessary sensors, the 

microprocessor, and the housing and interface equipment. The cost of the development and testing is not 

included here. 

These costs are affected very little by the size of the machine, which is reflected in the formula quoted in 

Table 3-2. 

3.4 Cost of Energy Model 

The formula used to calculate the cost of energy was specified by NREL and is given below. 

M&O

AEP

LCR)ICCxFCR( COE

net

+

+ =

where COE = Levelized cost of energy ($/kWh) 

 FCR = Fixed charge rate (0.106 /yr was used) 

 ICC = Initial capital cost ($) 

 LRC = Levelized replacement cost ($/yr) 

 AEPnet = Net annual energy production (kW/yr) 

 = AEPgross adjusted for availability, array losses, soiling, etc. 

 O&M = Operating and maintenance cost ($/kWh) 
24 

4. TASK #2. BASELINE DESIGNS 

The objective of Task #2 was to generate designs for four wind turbines with ratings from 750 kW to 

5.0 MW and to use these designs as standards to which later designs could be compared. Because the 

baseline designs did not involve unusual features, the FAST_AD code was initially used to generate 

results. However, ADAMS models were developed for some of the turbines, and results from the two 

sets of models were compared. It became apparent that some loads did not agree, and finally all turbines 

were analyzed using ADAMS. More details concerning this comparison are given in Section 4-2. 

4.1 Basic Specifications 

An initial set of configurations and the rationale for them were presented to NREL staff at the kick-off 

meeting in August 2000. These configurations were used in Task #2 until, in December 2000, the NREL 

project monitor questioned whether those specifications represented the class of rotor that was of most 

interest. The discussion that ensued resulted in the adoption of a second set of specifications and a second 

series of simulations and design evaluations. The two sets of specifications are listed in Table 4-1. 

Table 4-1. Initial and Final Overall Specifications 

Parameter Initial Specification Revised Specification 

Design wind regime IEC class 1 IEC class 2 

Rated tip speed 65 m/s 75 m/s 

Hub height 1.3 x rotor_diameter 1.2 x rotor_diameter 

Rotor diameters (m) 46.6, 66.0, 93.0, 120.0 50.0, 70.0, 99.0, 128.0 

Hub heights (m) 61.0, 86.0, 121.0, 156.0 60.0,84.0, 119.0,154.0 

Ratings (kW) 750, 1500, 3000, 5000 750, 1500, 3000, 5000 

4.2 FAST_AD vs. ADAMS Results 

The initial intention was to use the FAST_AD code for all of Task #2 and for as much as possible of 

Task #3. Therefore, Task #1 included the addition of a suitable PID controller routine into FAST_AD, 

and a number of additional output signals were added to FAST_AD in Task #2. 

Comparisons were made between equivalent FAST_AD and ADAMS models, and it was noticed that the 

results for axial and shear forces from FAST_AD were erratic and did not compare well. It was agreed 

that the axial and shear force results from FAST_AD should not be used in design. Later it was found 

that the tower base bending moments from FAST_AD were also substantially different from the ADAMS 

model results. The cause and resolution of the discrepancies were developed by Windward Engineering, 

but it was decided that all subsequent analyses in Task #2 would be made using ADAMS. The improved 

version of FAST_AD was used in a number of analyses in Task #3. 

4.3 Annual Energy Production 

For each blade design and schedule, the PROP code [14] was used to generate a table of powercoefficient against tip-speed ratios. This table was incorporated into a spreadsheet to calculate total 

annual energy production (AEP) under specified wind regimes, which were functions of the wind at the 

reference height of 10 m and the tower height. Sea-level density and the specified drive train efficiencies 

were used in the calculation of AEP, and the following additional losses were included: 

• Availability 95% 

• Blade soiling losses 2% 

• Array losses 5% 
25 

The AEP calculation assumed sharp transitions in the power curve with no smoothing. 

4.4 Material Properties 

The static strength, the fatigue strength details, and the partial safety factors used in the principal 

components are listed in Table 4-2. 

Table 4-2. Material Properties Used in Design of Major Components (Task #2) 

Partial Safety Factor, Material 

(including consequences of 

failure factor) Component Material Stress 

Ratio 

Static Design 

Strength/ 

Strain 

Fatigue 

Design SN 

Slope Static Fatigue 

Blade Fiberglass R=0 7586 με m = 8.0 2.9 1.93 

 R=-1 3620 με m =13.0 2.9 1.93 

 R=10 3620 με m = 16.0 2.9 1.93 

Hub Ductile 

iron 

 Yield stress = 

310 Mpa 

m = 16.8 1.1 1.25 

Shaft HS steel Yield stress = 

828 Mpa 

m = 6.5 1.1 1.25 

Mainframe Ductile 

iron 

 Yield stress = 

310 Mpa 

m = 16.8 1.1 1.25 

Tower Structural 

steel 

 Yield stress = 

350 Mpa 

BS 7608 class 

D 

m = 3 

1.1 1.25 

4.5 Pitch Control System 

All rotors used full-span collective pitch control to maintain constant rotor speed above rated wind speed. 

Details of the pitch controller are provided in Appendix E. 

A torque-speed look-up table was provided to the simulation, which maintained the rotor operating at 

maximum power coefficient in the variable-speed range. Above the rated torque value, the look-up table 

provided a near-constant torque with increasing rotor speed. Once the specified maximum speed or 

maximum power was reached, the rotor no longer operated at peak efficiency, and the blades were 

pitched to maintain the specified maximum speed. 

The pitch control system was provided with maximum and minimum values of the pitch angle. The 

minimum was chosen for peak aerodynamic efficiency, and the maximum value was set at approximately 

90 degrees (corresponding to fully feathered). The pitch rate was limited to 10 degrees/second. 

4.6 Results from Design Process 

Table 4-3 contains results of the configurations adopted for the four baseline machines. The 

corresponding costs, energy production, and the cost of energy are presented in Table 4-4 and are 

summarized in Figure 4-1. 
26 

Table 4-3. Characteristics of Final Baseline Configurations 

Units 750 kW 1.5 MW 3.0 MW 5.0 MW 

File Name .75A08C01V00c 1.5A08C01V03c

Adm 

3.0A08C01V02c 5.0A04C01V00c

Rotor diameter m 50 70 99 128 

Max rotor speed rpm 28.6 20.5 14.5 11.2 

Max tip speed m/s 75 75 75 75 

Rotor tilt degrees 5 5 5 5 

Blade coning degrees 0 0 0 0 

Max blade chord m 8% of radius 8% of radius 8% of radius 8% of radius 

Radius to blade root m 5% of radius 5% of radius 5% of radius 5% of radius 

Blade mass kg 1818 4230 12,936 27,239 

Rotor solidity 0.05 0.0500 0.05 0.05 

Hub mass kg 5086 15,104 50,124 101,014 

Total rotor mass kg 12,381 32,016 101,319 209,407 

Hub overhang m 2.330 3.300 4.650 6.000 

Shaft length x diam m 1.398 x 0.424 1.980 x 0.560 2.790 x 0.792 3.600 x 1.024 

Gearbox mass kg 4723 10,603 23,500 42,259 

Generator mass kg 2946 5421 10,371 16,971 

Mainframe mass kg 5048 15,057 45,203 102,030 

Total nacelle mass kg 20,905 52,839 132,598 270,669 

Hub height m 60 84 119 154 

Tower base diam x 

thickness 

mm 4013 x 12.9 5663 x 17.4 8081 x 25.5 10,373 x 33.2 

Tower top diam x 

thickness 

mm 2000 x 6.7 2823 x 8.7 4070 x 13.0 4851 x 17.6 

Tower mass kg 46,440 122,522 367,610 784,101 

0.00

0.01

0.02

0.03

0.04

0.05

0.06

750 kW 1.5 MW 3.0 MW 5.0 MW

Cost, $/kWh

O&M

Replace't costs

Balance of st'n

Tower

Controls

Drive train

Rotor

Figure 4-1. Summary of cost-of-energy breakdown for baseline configurations. 
27 

Table 4-4. Costs of All Wind Farm Items for Baseline Designs 

Rating kW 750 kW 1.5 MW 3.0 MW 5.0 MW 

Rotor $ 101,897 247,530 727,931 1,484,426 

Blades $ 64,074 147,791 437,464 905,903 

Hub $ 21,617 64,191 213,027 429,307 

Pitch mechanism and bearings $ 16,205 35,548 77,440 149,216 

Drive train, nacelle $ 255,631 562,773 1,282,002 2,474,260 

Low-speed shaft $ 8,433 19,857 56,263 120,903 

Bearings $ 3,794 12,317 41,436 101,834 

Gearbox $ 64,919 150,881 357,224 697,062 

Mechanical brake, HS coupling, etc. $ 1,492 2,984 5,968 9,947 

Generator $ 48,750 97,500 195,000 325,000 

Variable-speed electronics $ 50,250 100,500 201,000 335,000 

Yaw drive and bearing $ 5,268 12,092 28,213 109,705 

Main frame $ 21,452 63,992 192,115 433,627 

Electrical connections $ 30,000 60,000 120,000 200,000 

Hydraulic system $ 3,375 6,750 13,500 22,500 

Nacelle cover $ 17,898 35,901 71,283 118,682 

Control, safety system $ 10,000 10,200 10,490 10,780 

Tower $ 69,660 183,828 551,415 1,176,152 

Balance of station $ 217,869 388,411 873,312 2,458,244 

Foundations $ 34,919 48,513 76,765 108,094 

Transportation $ 26,586 51,004 253,410 1,312,150 

Roads, civil works $ 44,896 78,931 136,359 255,325 

Assembly and installation $ 24,374 50,713 112,714 224,790 

Electrical interface/connections $ 71,304 126,552 224,196 431,500 

Permits, engineering $ 15,790 32,698 69,868 126,385 

Initial capital cost (ICC) $ 655,057 1,392,741 3,445,150 7,603,862 

Initial capital cost (ICC) $/kW 873 928 1,148 1,520 

Net annual energy production kWh 2,254,463 4,816,715 10,371,945 18,132,994 

Rotor ¢/kWh 0.477 0.543 0.741 0.864 

Drive train ¢/kWh 1.197 1.234 1.305 1.441 

Controls ¢/kWh 0.047 0.022 0.011 0.006 

Tower ¢/kWh 0.326 0.403 0.561 0.685 

Balance of station ¢/kWh 1.021 0.852 0.889 1.432 

Replacement costs ¢/kWh 0.499 0.467 0.434 0.414 

O&M ¢/kWh 0.800 0.800 0.800 0.800 

Total COE ¢/kWh 4.367 4.321 4.741 5.642 

Table 4-5 shows how some of the key loads vary with rotor diameter. Most loads that are due mainly to 

aerodynamic forces vary approximately with the diameter to the power of 3.0; this agrees with simple 

estimates. Loads that involve gravity forces vary with the diameter to a greater power, which also is in 

keeping with expectations. For comparison, the energy yield of these systems varies with the diameter to 

the power 2.2, which is greater than 2.0 due to the increase in tower height and mean wind speed. 

There is a considerable difference in the dependence on rotor diameter for the flapwise and edgewise 

fatigue loads at the blade root. This leads to the trend of larger blades being governed by edgewise 

gravity forces in place of aerodynamic flapwise forces. Figure 4-2 illustrates how, for this series of 

baseline designs, the edgewise fatigue loading becomes critical between the 3- and the 5-MW sizes. 

Table 4-6 shows critical load cases for each component. It also shows the next critical load case and the 

available margin for that loading. 
28 

0

2,000

4,000

6,000

8,000

10,000

50 70 90 110 130

Rotor Diameter, m

Root Bending Moment, kN m

root flap mt, fatigue

root edge mt, fatigue

Figure 4-2. Variation of root flapwise and edgewise moments with diameter. 

Table 4-5. Trends from Baseline Designs: Dependence on Diameter 

Exponent of Diameter in Trend Line 

Load Peak Loads Equivalent Fatigue Loads 

Root flapwise bending moment 2.911 3.192 

Root edgewise bending moment 3.362 3.645 

50% span flapwise bending moment 2.946 3.053 

50% span edgewise bending moment 3.460 3.464 

Pitching moment at yaw bearing 3.317 2.924 

Fore-aft bending at tower base 3.266 2.959 

Table 4-6. Critical Load Cases for Baseline Turbines 

Machine rating 

750 kW 1.5 MW 3.0 MW 5.0 MW 

Component .75A08C01V01c 1.5A08C01V04c 3.0A08C01V03c 5.0A01C01V01c

governing load EWM EWM Fatigue (TE) Fatigue (TE) 

Blade root Next critical load Fatigue Fatigue EWM EWM 

margin to that load 2% 11% 1% 25% 

governing load Fatigue Fatigue Fatigue Fatigue (TE) 

Next critical load EWM EWM EWM EWM Blade @ 50% 

(flapwise mt) margin to that load 19% 45% 30% 31% 

governing load Fatigue Fatigue Fatigue Fatigue 

Next critical load EWM EWM EWM EWM Hub 

(blade root mt) margin to that load 41% 67% 68% 76% 

governing load Fatigue Fatigue Fatigue Fatigue 

Next critical load ECD ECD NTM ECD Mainframe 

(pitch bending) margin to that load 50% 27% 60% 10% 

governing load Fatigue Fatigue Fatigue Fatigue 

Next critical load EWM EWM EWM EOG Tower base 

(fore-aft mt) margin to that load 12% 35% 84% 21% 

Note: For the meaning of the loading acronyms, see Table 2-2. 

 TE indicates Trailing Edge (associated with edgewise bending in contrast to flapwise bending). 
29 

4.7 Campbell Diagram 

Figure 4-3 shows the predicted natural frequencies vs. rotor speed for the baseline model of the 1.5-MW 

configuration. The figure also shows the harmonic frequencies at 1P, 3P, and 6P and also shows the 

maximum operating speed of the rotor (20.5 rpm). The diagram shows the fundamental fore-aft mode to 

be close to the 1P excitation and also that the first blade mode is close to the 3P excitation at the 

maximum operating speed. 

Campbell Diagram for 15A08V08

0.0

0.5

1.0

1.5

2.0

2.5

0 5 10 15 20 25 30

Rotor Speed, rpm

Natural Frequency, Hz

1P

3P 6P

20.5 rpm

Figure 4-3. Natural frequencies vs. rotor speed 

(Campbell diagram) of baseline 1.5-MW model. 

4.8 Conclusions from Baseline Study 

The study of the baseline configuration at the range of sizes has led to the following observations: 

• The rotor cost comprises between 10% and 15% of the total cost of energy. A change of 10% in 

the rotor cost will therefore translate into only 1% to 1.5% change in the COE. 

• There are considerable costs that are affected only slightly or not at all by load variation. These 

include some electrical drive train costs and balance-of-station costs. Approximately 50% of the 

total costs are unaffected by changes in rotor loads. 

• Considerable reductions in COE may still be achieved by rotor changes if the load reductions 

affect the entire load path. 

• The rotors of the larger machines represent higher fractions of the total costs. This is because the 

mass and cost of the rotors increase with diameter faster than other costs, such as balance-ofstation costs. Improvements in rotor design will, therefore, benefit larger turbines more than 

smaller turbines. 
30 

5. TASK #3. CONFIGURATION VARIATIONS 

The purpose of Task #3 was to determine the effect on COE of changes to the rotor configuration. These 

changes were to the type of rotor (3 blades/2 blades, etc.) and to details of the rotor, such as the tip speed 

or the stiffness of the blade. The objective was to identify those configurations that had the most 

beneficial effect on COE and to determine how these effects were influenced by scale or rating. The 

changes were made one at a time so that, within a certain range, their effects could be superimposed. 

5.1 Initial Matrix 

Table 5-1 shows the list of configurations initially considered, requiring a total of 58 designs to be 

evaluated. It became apparent that resource limitations would prevent a thorough analysis of this number 

of configurations, and a process was therefore begun to reduce that number to a more manageable one. 

5.2 Selection Approach 

A questionnaire was sent to staff at the NWTC, at GEC, at Windward Engineering, and to participants at 

the WindPACT Workshop (in October 2000), to solicit opinions about what configurations were expected 

to be the most cost effective and what configurations might be deleted from consideration. The results of 

that survey indicated that the following were not favored: pitch-to-stall rotors; those with constant speed, 

teetered hubs with delta-3; or stiff towers. The decision was made to eliminate those options and also to 

remove the simulations at all four ratings for the three non-baseline configurations. It was agreed that the 

simulations of the reduced number of configurations of 1.5-MW rating should be followed by a study of 

the effect of certain selected configurations, or combination of configurations, on the range of ratings. 

The list of final configurations included upwind and downwind machines, although the preferred 

configurations tended to be the 3-bladed upwind and the 2-bladed downwind. This is reflected in the 

diagram of final selections illustrated in Figure 5-1 and in the accompanying list shown in Table 5-2. 

configuration

 space

3-bladed

2-bladed

upwind

downwind

3 configs

9 configs

>Variable speed

>Full-span pitch

>Tube towers

>Same airfoil family

upwind

downwind

11 configs

3 configs

Figure 5-1. Rotor configurations selected. 
31 

Table 5-1. Initial Table of Configurations for Examination in Task #3 

Rotor size (1.5 MW or all) 

Number of blades 

Orientation: upwind (Up) or downwind (Down) 

Hub type: rigid (R), teeter (T), flapping hinge (F), teeter with d3 (Td) 

Blade type: regular (R) or soft (S) 

Fixed pitch (F), pitch to feather (PF), pitch to stall (PS) 

Tip speed: standard (S) or modified (M) 

Diameter: standard (S) or modified (M) 

Variable (VS) or constant speed (CS) 

Tower stiffness: soft-soft (SS) or soft (S) 

Tower feedback to pitch control 

Yaw drive: active (A) or free (F) 

All 3 Up R R PF S S VS S No A 

1.5 S M 

M S 

1.5 S VS, CS 

 VS SS Yes 

SS, S, No 

S F, PF S 

All 3 Down R R PF S S VS S No A 

1.5 R R, S F, PF, PS SS Yes 

F R PF, PS S No 

R PF F 

All 2 Up T R PF S S A 

1.5 M 

S M 

R, S PF, PS S VS S 

R F VS 

PF SS Yes 

S S No 

All 2 Down T R PF S S VS S No F 

1.5 R, S F, PF, PS S No 

R PF M 

S M 

S SS Yes 

Td F S No F 

F F, PF, PS 

1.5 5 Down R F, PF A 

Total 

Note: A blank cell indicates that it is unchanged from the cell above. 
32 

Table 5-2. Configuration Modifications Chosen for Study in Task #3 

ID 

Letter 

No. of 

Blades 

Rotor 

Orientation Feature Modified Comments Results Su

A 3 Upwind Baseline B 3 Upwind 12% increase in rotor 

diameter 

Blade dimensions were increased by same ratio Loads in and cost of rotor incre

loads also increased 

C 3 Upwind 13% increase in tip speed Blade was unchanged from baseline Gearbox cost reduced, but all D 3 Upwind feedback from tower 

motion in control system 

See Appendix E Tower loads and cost down sig

largely unchanged 

E 3 Upwind soft-soft tower, feedback 

from tower, and increased tip speed 

Achieving a soft-soft tower led to a very thick tube. In E02, the soft-soft tower (with no other changes) was achieved by reducing the elastic modulus of the tower material 

Tower for config. E very expenloads were higher than in base

F 3 Upwind stiff blades Added stiffness was achieved through the use of 

carbon fiber in the spar 

Loads generally unchanged. Lrpm fluctuations 

G 3 Upwind blades with flap-twist 

coupling 

The stiffness matrices in the ADAMS models were adjusted (see Ref. [25]) to incorporate an “alpha” value of approximately 0.17 

Most loads were reduced signi

H 3 Upwind flap-pitch feedback in 

control system 

An attempt to incorporate the algorithm from Ref. 

[26]. Root flap mt from each blade compared to mean from all three blades 

Costs of all components were 

X 3 Upwind increased tip speed, 

reduced chord, high-strain blade material 

Material as in config. Y. Tip speed increased to 85 m/s. Max chord reduced from 8% to 6% of radius 

Significant decrease in the loa

Y 3 Upwind high-strain blade material Prepreg fiberglass has greater quality control; 

permissible strains are higher; fatigue SN curve is flatter 

Lower flapwise fatigue loads in but other costs unchanged 

J 3 Downwind intermediate baseline Similar to A but downwind with tower shadow All loads and costs up slightly 

K 3 Downwind soft blades Material as in configuration Y Blade softness reduced most b

loads 

L 3 Downwind hinged blades Flapwise hinges installed at blade roots, together 

with necessary restraints to ensure tower clearance 

Most blade loads reduced, but estimate. Tower clearance a p

M 2 Upwind intermediate baseline Max chord = 10% of radius Rotor cost much reduced from 

N 2 Upwind 12% increase in diameter Similar to configuration B All loads up, especially those d

P 2 Upwind 13% increase in tip speed Similar to configuration C Slight increase in rotor loads a

Q 2 Downwind intermediate baseline All downwind configurations incorporated free yaw All rotor loads increased from u

R 2 Downwind soft blades High strain blade material, as in Y Hub and nacelle loads increas

restraint forces 

S 2 Downwind 12% increase in diameter Similar to configuration B Higher rotor loads and cost ba

T 2 Downwind 13% increase in tip speed Similar to configuration C Higher loads and higher final C

U 2 Downwind feedback from tower 

included in control system

Similar to configuration D Tower loads reduced and othe

V 2 Downwind positive delta-3 For details of delta-3 feature, see Ref. [27] Some loads reduced but final C

W 2 Downwind hinged blades Flapwise hinges in each blade at root, together 

with necessary restraints for tower clearance 

High blade root loads required More sophisticated analysis an
33 

5.3 FAST_AD vs. ADAMS 

As described earlier (Sections 2-3, 4-2), two simulation codes were used: FAST_AD, and ADAMS. Care 

was taken to compare results only from the same code. 

5.4 Results from Task #3 

Details of the loads from selected locations from all the configurations studied are presented in Table A-1 

(Appendix A). In that table, the loads have been normalized with respect to appropriate baseline models 

to allow quick and meaningful evaluation. Some analyses were carried out using ADAMS and some 

using FAST_AD. This is noted, and the relevant normalization basis was selected. 

Table A-2 refers to the same load locations but gives the governing load case and the margin to the next 

critical load case. Table A-3 presents cost information from all subassemblies for all configurations. It 

includes the net annual energy production and the COE from each major assembly, as well as the final 

COE. 

Some of the important results of the configuration changes are included in Table 5-2. The final cost of 

energy from all the configurations is summarized in Figure 5-2. Figures 5-3 and 5-4 graphically present 

some of the same COE information but separate the 3- and 2-bladed results and show the COE changes 

relative to the baseline models. Figures 5-5 and 5-6 present similar COE information according to 

subassembly. 

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

Cost, ¢/kWh 

O&M

Repl't costs

Balance of stn

Tower

Controls

Drive train

Rotor

3-bladed upwind 3-bladed

 downwind

2-bladed

 upwind

2-bladed downwind

Figure 5-2. Summary of cost of energy from all Task #3 configurations. 
34 

-7%

-6%

-5%

-4%

-3%

-2%

-1%

0%

1%

2%

3%

4%

5%

A_Adm

A_Fst

BCD

E02

F 

G

HY

X

J

K

L

Configuration ID

Change in COE

3-bladed

upwind downwind

baseline cost

Figure 5-3. Cost-of-energy changes for 3-bladed configurations. 

-7%

-6%

-5%

-4%

-3%

-2%

-1%

0%

1%

2%

3%

4%

5%

M_Adm

M_Fst

NP

Q_Adm

Q_Fst

T02

T

RSUV

W

Configuration ID

Change in COE

upwind downwind 2-bladed

3-bladed baseline cost

2-bladed baseline cost

Figure 5-4. Cost-of-energy changes for 2-bladed configurations. 
35 

-40%

-30%

-20%

-10%

0%

10%

20%

30%

A_Adm

A_Fst

BCD

E02

F 

GH

Y

X

J

K

L

Configuration ID

Cost/kWh

rotor

drive train

tower

3-bladed upwind downwind

3-bladed baseline cost

Figure 5-5. Summary of component costs for 3-bladed configurations. 

-40%

-30%

-20%

-10%

0%

10%

20%

M_Adm

M_Fst

N

P

Q_Adm

Q_Fst

T02

T

R

S

U

V

W

Configuration ID

Cost/kWh

rotor

drive train

tower

upwind downwind 2-bladed

2-bladed baseline cost

Figure 5-6. Summary of component costs for 2-bladed configurations. 
36 

5.5 Observations from Task #3 results 

A number of principles should be kept in mind when evaluating the Task #3 results presented above. 

• The results should be regarded as indicating trends rather than absolute values. 

• Some of the trends can be applied in either direction. For example, the effects of decreasing the 

tip speed can be considered to be the opposite of the effects of increasing the tip speed. 

• Some results may not be realizable. For example, configurations X and Y show considerable cost 

reductions but also have blade-tower interference problems. In addition, the manner in which the 

flap-twist coupling would be implemented in configuration G and the cost involved have not been 

fully determined. Furthermore, the higher tip speeds adopted in configurations C and X may lead 

to unacceptable acoustic emissions. 

• Comparisons must be done using the same aeroelastic code. The differences between the two 

codes are of the same order as the differences between the configurations. 

• Several of the modifications need to be optimized for best performance. For example, the tower 

feedback in the controls could be refined for improved results. 

The following conclusions were drawn from the Task #3 results: 

• The final cost of energy is much more sensitive to the energy capture than it is to changes in the 

loads. The approximately 2% energy loss associated with changing from three to two blades (due 

to tip losses) is significant. 

• All of the basic configurations (upwind/downwind, 3-/2-bladed) are affected in a similar manner 

by some modifications. These include changes to the tip speed, the diameter, and tower feedback. 

• The analysis of the rotors with hinged blades (configurations L and W) requires much care 

because the results are very sensitive to the restraints offered to the flapping motion. A more 

complete analysis should give more attention to the transient conditions, such as emergency 

stops. Nevertheless, the load reductions obtained from these configurations did not exceed those 

that were offered by other modifications, and these configurations were not selected for further 

study in Task #5. This omission was not intended to detract from current attempts at 

commercializing such rotors; it was a reaction to the rigorous demands of this configuration. 

• Two-bladed teetered rotors are also sensitive to transients and peak load conditions because the 

restraining force from the teeter restraints may occur at these times. Downwind rotors would 

probably benefit from an increased hub overhang and a tuning of the teeter restraints. 

• The incorporation of soft blades (configuration K) did lead to some attenuation of loads. The 

relationship among tip flexibility, blade materials, and blade weight is not completely clear. 

• Although increasing the tip speed alone had deleterious effects (configuration C and P), the 

combination of increased tip speed with decreased blade chord (configuration X) had 

considerable benefits. The interpretation of these results is that it is more efficient for a blade of 

lower solidity to move faster and to do the same mechanical work with lower loads. 

• The following features were recommended for further study in Task #5 in all three basic 

configurations (3-bladed upwind, 2-bladed upwind, and 2-bladed downwind): 

• Tower feedback 

• Reduced chord with increased tip speed 

• Flap-twist coupling. 
37 

6. TASK #5. DETAILED MODELING 

6.1 Approach 

The purpose and approach of Task #5 was discussed and finalized at the Preliminary Design Review 

(PDR) meeting. The decision was made to consider separately the three basic configurations (3-bladed 

upwind, 2-bladed upwind, and 2-bladed downwind) because the results of Task #3 showed that the COE 

from all three could be improved by similar modifications. The most promising features identified in 

Task #3 were to be combined and applied to the three basic configurations at the 1.5-MW size. The effect 

of size would also be examined. 

In addition, it was agreed at the PDR that the cost models would be reviewed and that the power curve implied 

by the simulations would be compared with the results from aerodynamic models using the PROP code. 

6.2 Cost Models 

A review of the cost models resulted in the changes listed in Table 6-1. 

Table 6-1. Changes Made to Cost Models for Task #5 

Component Change in Cost or Design Model 

Hub Scale factor reduced to give hub weights and costs more consistent with a range of 

commercial data. This was applied to the spherical hub of the 3-bladed configurations 

and a corresponding change was made to the teetered hubs of the 2-bladed rotors. 

Nacelle cover Made dependent on width of nacelle, as well as length. This led to more realistic cost 

changes due to changes in the hub overhang. 

Generator The cost per kW was reduced from $65/kW to $52/kW to reflect costs used in the 

WindPACT drive train design study. 

Power electronics The cost per kW was reduced from $67/kW to $54/kW to reflect costs used in the 

WindPACT drive train design study. 

Foundations Algorithm adjusted upward to reflect the costs of foundations quoted more recently by 

Patrick and Henderson. 

Blades A price of $16.42/kg was adopted for material containing bias-ply carbon fibers. 

Adjustment was made in the spreadsheets to separate the inboard material (glass fiber) 

from the carbon-dominated spar and outboard skin. 

The same cost model changes were made to the corresponding baseline (Task #2) configurations so that 

comparisons of the two sets would be valid. 

6.3 Preliminary Results 

The results from Task #3 indicated that the following features had beneficial effects on loads and costs 

throughout the turbine system: 

• Tower feedback in the control system 

• Incorporation of flap-twist coupling in the blade 

• Reduced blade solidity in conjunction with higher tip speeds. 

There was little problem in implementing the first of these three features because no change was required 

from its implementation in Task #3. However, the application of flap-twist coupling in the blade used in 
38 

Task #3 lacked rigorous modeling of the necessary composites, and there was inadequate information for 

the accompanying cost models. It was, therefore, decided to delay incorporation of this feature until these 

deficiencies could be corrected. 

The results from studying the third feature, lower solidity and higher tip speed, in Task #3 showed lower 

loads but at the expense of a negative tower clearance margin. Therefore, in Task #5 some coning was 

added to the rotor and the extent of the lower solidity was reduced. Models of this 3-bladed upwind 

configuration, using hand lay-up fiberglass in the blades, indicated continued tower clearance problems 

and little or no reduction in loads. 

To address the problem of blade-tower clearance, the decision was made to change from using fiberglass 

to the same carbon-glass hybrid that was examined in Task #3 configuration F. It was found that this 

change permitted the incorporation of the full solidity reduction without any tower clearance problem so 

long as some coning was added to the blades and a modest addition was made to the hub overhang. 

The reduction in loads from combining the tower feedback with the reduced solidity led to a substantial 

reduction in the tower section and in the tower flexural stiffness. This, in turn, led to a lowering of the 

fundamental natural frequency of the turbine and to a resonance with the 1P excitation frequency. To 

address this, while not artificially strengthening some components, the decision was made to reduce the 

hub height from 84 m to 80 m, thereby restoring the natural frequency to approximately 1.2P. 

In parallel with these preliminary results, GEC staff made progress in the modeling of flap-twist blades 

and their fabrication costs. Work on adaptive blades on behalf of Sandia National Laboratories 

(Reference [7]) showed that the necessary coupling could best be achieved by incorporation of carbon 

fibers at 20° to the longitudinal axis. Furthermore, it appeared that the resulting blade could have the 

required overall flexural stiffness if the off-axis carbon fibers were placed in the skin while the spar was 

composed of uniaxial carbon-glass hybrid. 

Another parallel study for Sandia National Laboratories (Reference [22]) resulted in a procedure to 

extract the equivalent set of beam properties from a 3-dimensional finite element model of the blade. 

This meant that the exact lay-up of off-axis and uniaxial fibers could be modeled in ANSYS using the 

NuMAD interface (Reference [23]), and the equivalent beam properties could be extracted and included 

in the input file that was, in turn, converted into the ADAMS model. 

With these new design tools available, it was possible to combine all three of the chosen features and to 

ascribe accurate cost models to the blades. It was found that the combination of the three features further 

reduced the loads in the tower, allowing a smaller section, a softer tower, and allowing the hub height to 

be restored to 84 m in conjunction with a natural frequency comfortably below the 1P resonance. The 

models, therefore, also incorporated a soft-soft tower feature. 

The elastic twist that occurred due to the blade flap-twist coupling reduced the loads throughout the 

structure but also slightly reduced the energy captured. The maximum performance coefficient was 

reduced by up to 4%, which resulted in an annual energy production loss of up to 2%. To balance this 

effect, the initial twist schedule and the minimum pitch angle were modified so that the addition of the 

elastic twist during operation resulted in the desired optimum shape and pitch angle. In this manner the 

AEP was completely restored. 

6.4 Results from 3-Bladed Upwind Rotors 

Table 6-2 presents a summary of some of the properties of the final 3-bladed configurations developed in 

Task #5. 
39 

Table 6-2. Summary of Properties of the Baseline and Task #5 Final Configurations 

750 kW 1.5 MW 3.0 MW 

 Baseline Task #5 Final Baseline Task #5 Final Baseline Task #5 Final

.75A08C01V

00c 

.75AA04C01V

00 

1.5A08C01V03

cAdm 

1.5AA12C05V

00 

3.0A08C01V0

2c 

3.0AA02C01V

00 

Rotor diameter m 50 50 70 70 99 99 

Max rotor speed rpm 28.6 32.4 20.5 23.2 14.5 16.4 

Max tip speed m/s 75 85 75 85 75 85 

Rotor tilt Deg 5 5 5 5 5 5 

Blade coning Deg 0 3 0 3 0 3 

Max blade chord M 8% R 6% R 8% R 6% R 8% R 6% R 

Blade mass kg 1818 868 4230 2281 12,936 5463 

Rotor solidity 0.05 0.038 0.0500 0.038 0.05 0.038 

Hub mass kg 5086 2464 15,104 8063 50,124 21,270 

Total rotor mass kg 12,381 6063 32,016 17.882 101,319 49,498 

Hub overhang mm 2300 2330 3300 3500 4650 4950 

Shaft length x diam mm 1398 x 424 1398 x 400 1980 x 560 2185 x 560 2790 x 792 3100 x 800 

Gearbox mass kg 4723 4816 10,603 10,083 23,500 22,111 

Generator mass kg 2946 2949 5421 5421 10,371 10,371 

Mainframe mass kg 5048 3689 15,057 12,319 45,203 33,795 

Total nacelle mass kg 20,905 19,143 52,839 45,917 132,598 111,868 

Hub height m 60 60 84 84 119 119 

Tower base diam x 

thickness 

mm 4013 x 12.9 3296 x 10.4 5663 x 17.4 4969 x 15.4 8081 x 25.5 6691 x 21.3 

Tower top diam x 

thickness 

mm 2000 x 6.7 1525 x 4.8 2823 x 8.7 2461 x 7.6 4070 x 13.0 3280 x 10.2 

Tower mass kg 46,440 29,054 122,522 94,869 367,610 246,992 

6.4.1 Campbell Diagram 

Figure 6-1 shows the predicted natural frequencies vs. rotor speed for the final Task #5 model of the 

3-bladed upwind 1.5-MW configuration. The figure also shows the harmonic frequencies at 1P, 3P, and 

6P and shows the maximum operating speed of the rotor (23.2 rpm). 

Campbell Diagram for 15AA12

0.0

0.5

1.0

1.5

2.0

2.5

0 5 10 15 20 25 30

Rotor Speed, rpm

Natural Frequency, Hz

1P

6P 3P

23.2 rpm

Figure 6-1. Natural frequencies vs. rpm (Campbell diagram) for Task #5 

1.5-MW 3-bladed upwind turbine. 
40 

6.4.2 Loads 

A detailed compilation of system loads for the baseline and final Task #5 3-bladed upwind 750-kW, 1.5-

MW, and 3-MW configurations is presented in Appendix B as Table B-1. A sample of these results is 

shown in Figure 6-2, in which some loads from the 1.5-MW final configuration are compared with the 

corresponding baseline loads. As well as showing the final peak and equivalent fatigue loads normalized 

with respect to the baseline loads, Figure 6-1 indicates which load condition governs the baseline and 

Task #5 final designs. 

Figure 6-2 shows considerable reductions in all loads except for the peak loads at the tower base. That 

load is due to the extreme wind condition on the stationary rotor (EWM), which is unaffected by tower 

feedback and by flap-twist coupling. 

Task #5 final vs. baseline loads - 3-bladed upwind

0.4

0.5

0.6

0.7

0.8

0.9

1.0

1.1

1.2

1.3

1.4

Blade flap mt

@ root

Blade flap mt

@ 50%

Yaw brg My Tower base My

Fraction of baseline value

final peak lds

final fatigue lds

 Governing loads

fatigue fatigue fatigue fatigue Baseline

 displt displt fatigue EWM Task #5

Figure 6-2. Comparison of baseline loads with final Task #5 loads for 

1.5-MW 3-bladed upwind turbine. 

Table B-5 in Appendix B gives full information on which loads govern the baseline and final designs and 

how much margin there is to the next most critical load. 

6.4.3 Costs 

Details of the costs of all components for the baseline and final 3-bladed upwind machines for the 750-

kW, 1.5-MW, and 3-MW ratings are included in Table B-2 in Appendix B. The COE data are shown 

schematically in Figures 6-3 and 6-4. 
41 

3-bladed upwind

0.0

1.0

2.0

3.0

4.0

5.0

6.0

750 kW

Baseline

750 kW

T#5 Final

1.5 MW

Baseline

1.5 MW

T#5 Final

3.0 MW

Baseline

3.0 MW

T#5 Final

Cost of Energy, ¢/kWh

O&M

Replace't costs

Balance of stn

Tower

Controls

Drive train

Rotor

750 kW 1.5 MW 3.0 MW

-10.8% -8.2% -12.9%

Figure 6-3. Cost of energy of baseline and final 3-bladed 

750-kW, 1.5-MW, and 3-MW configurations. 

0.4

0.5

0.6

0.7

0.8

0.9

1.0

1.1

Rotor Drive train Tower B of stn

Fraction of baseline cost

final 3-bladed upwind, 750 kW

final 3-bladed upwind, 1.5 MW

final 3-bladed upwind, 3.0 MW

Figure 6-4. Comparison of baseline and final costs of 

3-bladed configurations by sub-assembly. 
42 

6.5 Results for 2-Bladed Rotors 

6.5.1 Loads 

A detailed compilation of system loads for the baseline and final Task #5 2-bladed upwind and downwind 

1.5-MW configurations is presented in Appendix B as Table B-3. Samples of these results are shown in 

Figures 6-5 and 6-6, in which selected loads from the final configurations are shown normalized by the 

corresponding baseline loads. As well as showing the final peak and equivalent fatigue loads, Figures 6-5 

and 6-6 indicate what load condition governs the baseline and Task #5 final designs. Figures 6-5 and 6-6 

show considerable reductions in peak and fatigue loads, especially to the fatigue load at the tower base. 

Task #5 final vs. baseline loads - 2-bladed upwind

0.4

0.5

0.6

0.7

0.8

0.9

1.0

1.1

1.2

1.3

1.4

Blade flap mt

@ root

Blade flap mt

@ 50%

Yaw brg My Tower base My

Fraction of baseline value

peak loads

fatigue loads

 Governing loads

fatigue fatigue fatigue fatigue Baseline

 displt displt fatigue Estop Task #5

Figure 6-5. Comparison of baseline and final Task #5 loads 

for 1.5-MW 2-bladed upwind turbine. 
43 

Task #5 final vs. loads - 2-bladed downwind

0.4

0.6

0.8

1.0

1.2

1.4

Blade flap mt

@ root

Blade flap mt

@ 50%

Yaw brg My Tower base My

Fraction of baseline value

peak loads

fatigue loads

 Governing loads

fatigue fatigue fatigue fatigue Baseline

displt displt fatigue EOGop Task #5

Figure 6-6. Comparison of baseline and final Task #5 loads for 

1.5-MW 2-bladed downwind turbine. 

6.5.2 Costs 

Full details of the costs and cost of energy for the baseline and final 2-bladed 1.5 MW configurations are 

given in Table B-3 in Appendix B. Summaries of this information are shown in Figures 6-7 and 6-8. 

1.5 MW Rating

0.0

1.0

2.0

3.0

4.0

5.0

6.0

Baseline T#5 Final Baseline T#5 Final Baseline T#5 Final

Cost of energy, ¢/kWh

O&M

Replace't costs

Balance of stn

Tower

Controls

Drive train

Rotor

3-bladed

upwind

2-bladed 

upwind

2-bladed 

downwind

-8.2% -10.4% -3.7%

Figure 6-7. Cost of energy for 2- and 3-bladed 1.5-MW configurations. 
44 

Comparison of Task #5 final with baseline costs - 1.5 MW

0.4

0.5

0.6

0.7

0.8

0.9

1.0

1.1

Rotor Drive train Tower B of stn

Fraction of baseline cost

final 3-bladed upwind

final 2-bladed upwind

final 2-bladed downwind

Figure 6-8. Comparison of baseline and final costs of 3- and 2-bladed 

1.5-MW configurations by sub-assembly. 

6.6 Lessons from Task #5 

The following observations can be made from the results presented above: 

• The combination of features adopted in Task #5 (tower feedback, flap-twist coupling, and 

reduced chord with higher tip speed) appears to be effective. 

• It has been necessary to incorporate a large amount of carbon fiber in the blade to successfully 

incorporate flap-twist coupling without incurring blade-tower clearance problems. 

• The blades have become governed by stiffness to avoid tower clearance problems. There is an 

uncertain balance between the cost of blades on one hand and the cost of additional hub overhang 

and the penalties of added tilt and/or coning. 

• There can be an energy loss associated with flap-twist coupling unless the initial twist and the 

minimum pitch of the blade are corrected. 

• Lower COE can be achieved by reducing the chord and increasing the tip speed with attention to 

the spanwise tapering of the blade. The optimum level for this approach must depend on further 

investigation of system design, especially the blade design, and must be balanced by 

consideration of the acoustic penalties. 

• It is possible that the inclusion of flap-twist coupling into a 2-bladed, teetered, free-yaw rotor is 

not as productive as when applied to a rotor with a rigid hub. The reason for this is that a teetered 

hub uses the 1 per rev loads due to yaw error to teeter into a new direction, which then allows the 

thrust to realign the nacelle in yaw. 

• The downwind 2-bladed rotors also experience strong harmonic loading from the tower shadow, 

which may excite natural frequencies. The identification of natural frequencies for 2-bladed 

rotors is more complex than for 3-bladed machines, and there were insufficient resources in this 

project to develop the Campbell diagram for these configurations. 
45 

7. TASK #6. DESIGN BARRIERS 

During execution of this project, it became apparent that some costs rose especially steeply with size. In 

addition, it was difficult to prescribe costs to some designs because they were novel and there was not a 

reliable base of information. These factors are possible barriers to the increased size of machines or to the 

reduction of costs of a given rating. They are discussed further in the subsequent sections. 

7.1 Transportation 

Reference [12] examines in detail the costs and logistics of transporting the various components for large 

wind turbines. These costs depend on the relative location of the manufacturer of these components and 

the site of the wind farm; for the current project, a site in the Midwest United States, such as South 

Dakota, has been assumed. 

The items that pose the most transportation problems are the tower sections, the nacelle, and the blades. 

Movement of these items is limited by weight, length, height, or width. Table 7-1 shows how the cost of 

transportation varies with machine rating: 

Table 7-1. Transportation Costs vs. Rating 

Rating Transportation Cost per 

Turbine Cost per kW 

750 kW $26,586 $35.4 

1.5 MW $51,004 $34.0 

3.0 MW $253,410 $84.4 

5.0 MW $1,312,150 $262.4 

It is clear from Table 7-1 that machines of 3.0 MW and greater are significantly penalized by 

transportation costs. To reduce these costs, the following changes would have to take place: 

• Tower sections can be transported in partial cylinders and fastened together on the site, or an 

alternative tower construction approach can be adopted. 

• Blades can be designed to be manufactured in parts that are assembled in the field or 

manufactured at a project site. 

• Nacelle parts can be transported separately and assembled on site. 

7.2 Installation 

The installation costs quoted in Table 4-6 were also obtained from Reference [12] and are summarized in 

Table 7-2. 

Table 7-2. Installation Costs vs. Rating 

Rating Installation cost per Turbine Cost per kW 

750 kW $24,374 $32.5 

1.5 MW $50,713 $33.8 

3.0 MW $112,714 $37.5 

5.0 MW $224,790 $44.9 
46 

The costs per kW of installed power increase only slightly up to ratings of 3.0 MW, but there is a more 

substantial increase at 5.0 MW. The reason for this is largely due to the cost of the crane required to lift 

parts into place. This cost could be reduced by incorporating a self-erecting tower scheme that would also 

allow installation of the nacelle and rotor parts. 

7.3 Blade Manufacturing 

Reference [3] concluded that the weights and costs of scaling up conventional blades increase 

approximately with the diameter to the power of 3.0, implying that the cost of the blades per kW will 

increase linearly with diameter. Hence the blade costs for larger machines will comprise a greater 

fraction of the total cost. However, the cost of the rotor is not greater than about 15% of the total cost so 

that a certain increase in rotor costs has only 0.15 of that effect on the final COE. 

Nevertheless, the design of the blade is important because the blades generate loads that are seen by all 

parts of the turbine. This has been illustrated in the current project by the introduction of lower solidity 

blades accompanied by flap-twist coupling in the blade material. The latter property raises questions of 

fabrication methods and final costs. Although this project was able to estimate the costs of fabrication of 

one type of construction, the subject of adaptive blades is one that is undergoing considerable study at 

present, and more information will be available in due course. In the meantime, uncertainty about costs 

and reliability of adaptive blades must be considered a barrier to implementing this technology. 

7.4 Acoustics 

Acoustic emission from wind turbines is a matter that is critical to the acceptance of the industry and is 

one that is subject to considerable research (Reference [21]). In general, much of the emission is from the 

blade tips and increases with the tip speed. Therefore, the proposal in Task #5 to increase the tip speed 

from 75 to 85 m/s is one that may be criticized for potentially increasing acoustic emission to an 

unacceptable level. 

The high tip speeds proposed may be more acceptable in regions such as the Midwest than in more 

populated areas. However, some Midwest residents may object to undue noise level, and it is 

recommended that research continue into the design of blade details that will attenuate the emissions. 

7.5 Design Load Cases 

All the simulations and the loads in this project have been based on use of the standard Kaimal spectrum 

of turbulence from Reference [1]. It is known that this spectrum (and the alternative von Karman 

spectrum) does not satisfactorily include all extreme events that may occur during operation, and this is 

why the separate inclusion of deterministic extreme events is also required. (This may change in the 

future when extrapolation techniques are improved.) Recent field studies (Reference [24]) have 

demonstrated that taller machines, especially in locations such as the Midwest, can be subject to a 

phenomenon known as the low-level jet stream. This phenomenon may subject a turbine to violent 

coherent turbulence and high loads. It is possible, therefore, that the loads used for design in this project 

may underestimate those that may occur in some locations, especially when combined with greater tower 

heights. 

However, this possibility does not invalidate the conclusions drawn from the project. The designs and 

modifications use the same loads, and the relative appraisal of the configurations will be unaffected. 
47 

7.6 Non-Turbine Costs 

Approximately 50% of the cost of energy is from items that are unaffected by rotor design. These are the 

balance of station, land, maintenance, replacement, etc. costs which may not be barriers to lowering the 

cost but do make it more difficult to bring about a reduced COE purely by improved rotor design. 

Another relevant fact is that changes to the various components of the wind turbine affect only part of the 

total COE equation, whereas a change to the aerodynamic performance and the annual energy production 

will have a direct effect on the COE. Hence, any rotor change that may reduce the energy production by 

even a small amount must be offset by a considerable reduction in material cost. 
48 

8. CONCLUSIONS 

8.1 Assumptions within the Study 

The basic assumptions used in this study must always be borne in mind. These include: 

• All the costs presented in this study are intended to be used to compare one set against another. 

They should not be regarded as absolute although much effort has been made to ensure that they 

are consistent with typical commercial costs. 

• All non-recurring manufacturing costs have been neglected. This includes all development, 

tooling, and marketing costs. 

• All costs assume that a mature production rate or number has been achieved. This will be harder 

to achieve for components for larger turbines than it will be for smaller turbines. 

• The emphasis in this study has been on the different configurations of the rotor. The 

configurations of the drive train and tower have been assumed to be of a standard type, and no 

effort has been made to optimize them. 

• This also applies to the operating and maintenance costs, which have been assumed to be a 

constant per kWh for all configurations and for all ratings. 

• A number of types of rotors and control strategies were eliminated at the start of Task #3. The 

remaining configurations have all featured full-span pitchable blades, continuously variable 

speed, and a pitch-to-feather control strategy. 

• The specific rating (rated power/swept area) of all configurations has been maintained at 

0.39 kW/m2

. This value was agreed on after reviewing common commercial practice and the 

apparent trends. 

8.2 Summary 

The cost of energy of the baseline designs has been reduced by no more than 13%, although considerable 

reductions have occurred to the loads throughout the system. In the course of achieving this, several 

trends and conclusions have become apparent. 

• More than 50% of the COE is unaffected by rotor design and system loads. Further COE 

reductions may be achieved by addressing the balance-of-station costs. 

• Combinations of rotor improvements with parallel improvements in the drive train design and in 

the tower design must be pursued. Such combinations will bring the total COE reductions closer 

to the 30% target. 

• The cost of the rotor as a fraction of the total capital cost rises with increasing rotor size. 

Therefore, larger machines can benefit more from rotor improvements. 

• The cost of a 3-bladed rotor is greater than the equivalent 2-bladed rotor and, for the same reason, 

benefits more from rotor improvements. 

• No single rotor modification offered a solution to reduced rotor costs and lower system loads. 

Instead there were a number of modifications that offered some general benefits. 

• The three modifications that resulted in the most general reductions in system loads and in a 

subsequent reduction in the cost of energy were: 

• Inclusion of tower feedback to the blade pitch control system. 

• Incorporation of flap-twist coupling in the blade design. 

• Reduction of the blade chord combined with an increase in the tip speed. 
49 

• Combination of these three modifications (in Task #5) resulted in further COE improvements in 

the 3-bladed upwind configuration. 

• The Task #5 improvements were of most benefit to the 3-MW 3-bladed upwind machine. This 

narrowed the difference in COE within the 750-kW to 3-MW range. 

• The selected rotor modifications benefited all three basic configurations. However, the benefit to 

the 2-bladed configurations, especially the downwind machine, was less than the benefit to the 

3-bladed configuration. 

• Several loads in the final 2-bladed downwind machine were higher than the corresponding loads 

in the baseline design. This is attributed to dynamic issues caused by the strong harmonic loading 

due to the tower shadow. It is likely that correct tuning will reduce the loads to be equal to or less 

than the baseline values. 

• The COE is very sensitive to changes in the annual energy production. Therefore, the added tip 

losses associated with larger chords penalize the 2-bladed rotors. 

• Likewise, the COE is sensitive to any performance loss due to the flap-twist coupling, and care 

must be taken to adjust the initial twist schedule to compensate for elastic deformations. 

• The extensive use of carbon fibers was essential to the final blade design. Their greater stiffness 

(compared to glass fiber) was needed to achieve the required flap-twist coupling and to avoid 

contact with the tower. 

• The use of carbon fiber was accompanied by a change from a fatigue-governed blade to one 

governed by peak loads or by deflection. 

• Added costs of transportation and assembly adversely affect the COE for machines rated above 

1.5 MW. Alternatives to the use of conventional cranes and alternative tower designs will benefit 

larger machines. 

• The inclusion of feedback from tower motion into the control system reduced tower loads 

considerably. This feature has not been optimized, and further improvements may be possible. 

Other control system enhancements may also have beneficial effects. 

8.3 Recommendations 

The following recommendations are made: 

• Combine the findings of this study with those of the parallel WindPACT drive train configuration 

study and the continuing study of the effect of specific rating. This combination may offer COE 

improvements that approach the target COE reduction identified by the WindPACT project. 

• Conduct more testing of material coupons and blade assemblies to support the use of bias-ply 

carbon fibers required for flap-twist coupling. 

• Study the acoustic penalties associated with higher tip speeds and ways of ameliorating them. 

• Develop further refinements of turbine control systems to reduce loads. 

• Study various approaches for reducing COE by changes in the balance-of-station costs and in the 

fixed charge rate. 
50 

9. REFERENCES 

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51 

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Appendix A 

Details from Task #3 Configuration Variations 
A-1 

Table A-1. Relative Load Results from Task #3 Configurations 

Configuration Load Location and Type 

Type 

Letter 

ID Model ID Description 

Code 

 Used 

Normalize 

Base Root Flap 

Blade 50% 

Flap 

Hub-Shaft 

My Shaft Torque 

Ya

peak fatig peak fatig peak fatig peak fatig pe

3-bld upwind A (Adm) 1.5A08C01V03cAdm baseline Adams A (Adm) 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.03-bld upwind A (Fst) 1.5A08C01_3V02c baseline FAST A(Adm) 0.92 1.11 1.36 1.15 1.19 1.12 1.06 1.07 1.03-bld upwind B 1.5B01C01V01e diam + 12% FAST A (Fst) 1.42 1.38 1.45 1.36 1.42 1.44 1.43 1.21 1.43-bld upwind C 1.5C02C01V01c tip spd + 13% FAST A (Fst) 0.99 1.07 1.01 1.06 1.05 1.14 0.99 0.92 1.03-bld upwind D 1.5D01C07V00c + twr feedback FAST A (Fst) 1.00 1.00 1.00 1.00 0.96 1.00 1.00 1.01 1.03-bld upwind E02 1.5E02C01V00c soft-soft tower FAST A (Fst) 0.96 1.01 1.01 1.01 1.02 1.02 0.96 0.99 1.03-bld upwind F 1.5F02C01V00c stiff blades FAST A (Fst) 0.99 0.90 1.00 0.98 0.95 0.94 0.97 1.19 0.93-bld upwind G 1.5G05C01V01 flap twist coupling Adams A (Adm) 0.92 0.84 0.90 0.80 0.79 0.81 0.81 1.03 0.83-bld upwind H 1.5H01C01V01c flap pitch feedback Adams A (Adm) 1.00 0.96 1.00 1.02 0.87 1.20 1.00 1.05 0.73-bld upwind Y 1.5Y01C01V01c high strain blades FAST A (Fst) 1.02 0.85 1.00 0.89 0.98 0.86 1.04 1.25 0.93-bld upwind X 1.5X01C01V01c 

high strain, low chrd, tp spd +13% FAST A (Fst) 0.77 0.76 0.77 0.75 0.77 0.73 0.74 1.17 0.6

3-bld dwnwind J 1.5J01C01V01c baseline, downwind FAST A (Fst) 1.07 1.14 1.02 1.10 1.16 1.17 0.96 1.34 1.23-bld downwin K 1.5K02C01V00c downwind, soft blades FAST A (Fst) 0.96 0.91 1.04 0.85 0.99 0.89 1.06 1.11 1.03-bld dwnwind L 1.5L01C01V01cAdm hinged blades Adams A (Adm) 1.19 0.80 0.79 0.82 0.81 1.19 1.13 1.17 0.82-bld upwind M 1.5M03C01V00c int. baseline FAST A (Fst) 0.93 0.98 0.88 1.03 0.80 0.58 0.70 1.19 0.52-bld upwind N 1.5N02C01V00c diam + 12% FAST M (Fst) 1.47 1.40 1.43 1.39 2.26 1.53 1.40 1.26 1.62-bld upwind P 1.5N02C01V00c tip spd + 13% FAST M (Fst) 1.47 1.40 1.43 1.39 2.26 1.53 1.40 1.26 1.62-bld dwnwind Q 1.5Q02C03V01cAdm int. baseline Adams A (Adm) 0.65 1.05 0.98 1.14 0.74 1.37 0.74 1.21 0.82-bld dwnwind Q 1.5Q02C01V01cFst int baseline FAST A (Adm) 0.92 1.09 1.00 1.21 0.71 1.27 0.70 1.66 0.72-bld dwnwind R 1.5R01C01V01c soft blade FAST Q (Fst) 0.96 1.05 0.93 0.93 2.01 1.37 1.03 1.24 1.62-bld dwnwind S 1.5S01C01V00c diam + 12% FAST Q (Fst) 1.44 1.40 1.33 1.40 1.82 1.46 1.47 1.32 1.42-bld dwnwind T 1.5T01C01V01cAdm Ti spd + 13% Adams Q (Adm) 1.50 1.27 1.19 1.22 1.34 0.81 1.04 0.89 1.22-bld dwnwind U 1.5U01C01V00c tower feedback FAST Q (Fst) 1.08 0.99 1.01 1.00 1.12 1.00 1.03 1.01 1.12-bld dwnwind V 1.5V01C07V02Adm positive delta-3 Adams Q (Adm) 1.42 1.04 1.34 1.05 1.37 1.08 1.20 0.99 1.12-bld dwnwind W 1.5W02C01V01 hinged blades Adams Q (Adm) 1.95 0.82 1.09 0.84 1.42 1.28 1.16 0.96 0.9
A-2 

Table A-2. Governing Load Cases and Margins for Task #3 Configurations 

Configuration Governing load case and margin to next critica

Type 

Letter 

ID Model ID Description 

Code 

 Used 

Root Flap 50% Flap Hub M

Gov 

load 

Next 

load 

Mrgn to 

nxt ld 

Gov 

load 

Next 

load 

Mrgn to 

nxt ld 

Gov 

load 

Next 

load 

Mrgn to 

nxt ld 

Gov 

load 

3-bld upwind A (Adm) 1.5A08C01V03cAdm baseline Adams fatigue ECD 52% fatigue EWM 45% fatigue EWM 67% fatigue 3-bld upwind A (Fst) 1.5A08C01_3V02c baseline FAST fatigue EWM 6.3% fatigue EWM 24% fatigue EWM 55% fatigue 3-bld upwind B 1.5B01C01V01c diam + 12% FAST fatigue EWM 3% fatigue EWM 16% fatigue EWM 43% fatigue 3-bld upwind C 1.5C02C01V01c tip spd + 13% FAST fatigue EWM 14% fatigue EWM 30% fatigue EWM 68% fatigue 3-bld upwind D 1.5D01C07V00c + twr feedback FAST fatigue EWM 6% fatigue EWM 24% fatigue EWM 55% fatigue 3-bld upwind E02 1.5E02C01V00c soft-soft tower FAST fatigue EWM 10% fatigue EWM 23% fatigue EWM 38% fatigue 3-bld upwind F 1.5F02C01V00c stiff blades FAST fatigue EOG 31% fatigue ECD 43% fatigue EWM 42% fatigue 3-bld upwind G 1.5G05C01V01 flap twist coupling Adams fatigue EOG ?? fatigue EWM 27% fatigue EWM 56% fatigue 3-bld upwind H 1.5H01C01V01c flap pitch feedback Adams fatigue EOG 53% fatigue EWM 48% fatigue EOG 112% fatigue 3-bld upwind Y 1.5Y01C01V01c high strain blades FAST EWM Fatigue 52% EWM ECD 17% fatigue EWM 23% fatigue 3-bld upwind X 1.5X01C01V01c 

high strain, low chrd, tp spd +13% FAST EWM NTM 22% EWM fatigue 12% fatigue EWM 49% fatigue 

3-bld dwnwind J 1.5J01C01V01c baseline, downwind FAST fatigue EWM 12% fatigue EWM 32% fatigue EWM 62% fatigue 3-bld dwnwind K 1.5K02C01V00c downwind, soft blades FAST EWM fatigue 23% EWM fatigue 18% fatigue EWM 54% fatigue 3-bld dwnwind L 1.5L01C01V01cAdm hinged blades Adams EWM ECD 117% fatigue ECD 43% fatigue EWM 150% fatigue 2-bld upwind M 1.5M03C01V00c int. baseline FAST fatigue EWM 10% fatigue EWM 45% fatigue EWM 55% fatigue 2-bld upwind N 1.5N02C01V00c diam + 12% FAST fatigue EWM 10% fatigue EWM 39% fatigue EWM 49% fatigue 2-bld upwind P 1.5N02C01V00c tip spd + 13% FAST fatigue EOG 17% fatigue EOG 49% fatigue EOG 66% fatigue 2-bld dwnwind Q 1.5Q02C03V01cAdm int. baseline Adams fatigue EOG 39% fatigue EOG 68% fatigue EOG 100% fatigue 2-bld dwnwind Q 1.5Q02C01V01cFst int baseline FAST fatigue EWM 3% fatigue NTM 76% fatigue EWM 48% fatigue 2-bld dwnwind R 1.5R01C01V01c soft blade FAST EWM fatigue 1% fatigue NTM 33% fatigue EWM 65% fatigue 2-bld dwnwind S 1.5S01C01V00c diam + 12% FAST fatigue EWM 1% fatigue EWM 86% fatigue EWM 43% fatigue 2-bld dwnwind T 1.5T01C01V01cAdm Ti spd + 13% Adams fatigue EWM 16% fatigue NTM 73% fatigue EWM 74% fatigue 2-bld dwnwind U 1.5U01C01V00c tower feedback FAST EWM fatigue 1% fatigue NTM 72% fatigue EWM 34% fatigue 2-bld dwnwind V 1.5V01C07V02Adm positive delta-3 Adams fatigue EWM 5% fatigue EWM 34% fatigue EWM 44% ECD 2-bld dwnwind W 1.5W02C01V01 hinged blades Adams EWM fatigue 39% fatigue ECD 35% EWM fatigue 22% fatigue 
A-3 

Table A-3. Costs and Cost of Energy Summary for All Task #3 Configurations 

Configuration 

A 

bslne 

3-bld 

upwnd 

A 

bslne 

3-bld 

upwnd 

B 

bslne  diam 

+12% 

C 

bslne 

tipspd 

+13% 

D 

bslne 

twr 

fdbck 

E02 

bslne + 

sft sft 

twr 

F 

bslne 

stiff 

bld 

s 

G 

bslne 

flptwst 

cplng

H 

bslne 

flpptch 

fdbck

Y 

bsln 

high 

strain 

blds 

X 

Tp spd

+13%

lwr 

chrd 

J 

3-bld 

dwnwnd

K 

3-bld 

dwnwnd

soft 

bld 

L 

3-bld 

hinged 

dwnwnd

M 

2-bld 

upwnd

M 

2-bld 

upwnd 

N 

2-bld 

upwnd 

diam 

+12%

P 

2-bld 

upwnd 

+13%

tpspd

Q 

2-bld 

dwnwnd

Q 

2-bld 

dwnwnd

T02 

2-bld 

dwnwnd

tp spd 

+13%

R 

2-bld 

dnwnd 

soft 

bld 

Model Used Adams FAST FAST FAST FAST FAST FAST Adams Adams FAST FAST FAST FAST Adams Adams FAST FAST FAST Adams FAST Adams FAST Rotor $k 248 265 346 276 265 263 222 223 249 185 167 285 219 301 195 202 277 206 192 205 229 171  Blades $k 148 162 214 171 162 162 125 140 148 95 90 173 115 138 98 100 134 104 97 100 113 64  Hub $k 64 71 89 73 71 71 64 51 63 58 52 77 71 118 81 85 119 86 83 86 98 90  Ptch mch, brngs $k 36 32 43 32 32 31 32 32 38 33 24 35 33 44 16 17 24 16 13 19 18 17 Drve trn, nacelle $k 563 571 602 559 571 571 574 555 570 572 549 581 586 563 549 551 586 535 559 554 561 576  Low-speed shaft $k 20 20 20 20 20 20 20 20 20 20 20 20 20 20 21 20 20 20 20 20 20 20  Bearings $k 12 12 12 12 12 12 12 12 12 12 12 12 12 12 13 12 12 12 12 12 12 12  Gearbox $k 151 154 169 142 154 154 159 151 160 158 146 160 166 159 155 159 176 146 155 155 146 162  Mech brk, cplng $k 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3  Generator $k 98 98 98 98 98 98 98 98 98 98 98 98 98 98 98 98 98 98 98 98 98 98  Var spd elctrncs $k 101 101 101 101 101 101 101 101 101 101 101 101 101 101 101 101 101 101 101 101 101 101  Yw drve, bearing $k 12 13 18 14 13 14 12 10 9 12 8 18 18 10 7 6 10 5 6 5 8 9  Main frame $k 64 68 79 68 68 68 67 59 65 65 59 67 66 59 49 51 64 48 62 58 71 69  Elctrcl cnnctns $k 60 60 60 60 60 60 60 60 60 60 60 60 60 60 60 60 60 60 60 60 60 60  Hydrlc system $k 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7  Nacelle cover $k 36 36 36 36 36 36 36 36 36 36 36 36 36 36 36 36 36 36 36 36 36 36 Control system $k 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 Tower $k 184 189 206 198 163 198 193 172 185 194 179 198 191 164 185 182 223 189 177 187 202 199 Balance of stn $k 388 388 397 389 388 393 388 386 388 388 385 389 389 385 384 384 391 384 384 383 386 384  Foundations $k 49 48 52 49 48 53 48 46 49 48 45 49 50 45 44 44 46 44 44 43 46 44  Transportation $k 51 51 51 51 51 51 51 51 51 51 51 51 51 51 51 51 51 51 51 51 51 51  Roads, civil wks $k 79 79 82 79 79 79 79 79 79 79 79 79 79 79 79 79 82 79 79 79 79 79  Assmbly, installtn $k 51 51 51 51 51 51 51 51 51 51 51 51 51 51 51 51 51 51 51 51 51 51  Elect interfc/cnnct $k 127 127 129 127 127 127 127 127 127 127 127 127 127 127 127 127 129 127 127 127 127 127  Permits, engnrng $k 33 33 33 33 33 33 33 33 33 33 33 33 33 33 33 33 33 33 33 33 33 33 Initial cap cost $k 1,393 1,424 1,562 1,433 1,398 1,435 1,387 1,346 1,403 1,349 1,289 1,463 1,396 1,424 1,323 1,329 1,488 1,325 1,322 1,338 1,388 1,341 Net ann energy MWh 4,817 4,817 5,397 4,819 4,817 4,817 4,819 4,817 4,817 4,817 4,818 4,817 4,817 4,817 4,707 4,707 5,318 4,741 4,707 4,707 4,741 4,707 Rotor c/kWh 0.543 0.582 0.677 0.604 0.582 0.576 0.485 0.490 0.547 0.407 0.365 0.625 0.481 0.660 0.438 0.453 0.549 0.459 0.431 0.459 0.510 0.384 Drive train c/kWh 1.234 1.251 1.179 1.225 1.251 1.253 1.257 1.217 1.249 1.253 1.204 1.274 1.285 1.235 1.232 1.237 1.165 1.192 1.255 1.242 1.249 1.293 Controls c/kWh 0.022 0.022 0.020 0.022 0.022 0.022 0.022 0.022 0.022 0.022 0.022 0.022 0.022 0.022 0.023 0.023 0.020 0.023 0.023 0.023 0.023 0.023 Tower c/kWh 0.403 0.415 0.404 0.434 0.358 0.434 0.423 0.377 0.406 0.425 0.391 0.433 0.419 0.360 0.415 0.408 0.443 0.422 0.396 0.419 0.451 0.446 Balance of stn c/kWh 0.852 0.851 0.777 0.852 0.851 0.861 0.851 0.845 0.852 0.850 0.844 0.852 0.854 0.844 0.861 0.861 0.777 0.856 0.861 0.858 0.860 0.861 Repl't costs c/kWh 0.467 0.467 0.417 0.467 0.467 0.467 0.467 0.467 0.467 0.467 0.467 0.467 0.467 0.467 0.478 0.478 0.423 0.475 0.478 0.478 0.475 0.478 O&M c/kWh 0.800 0.800 0.800 0.800 0.800 0.800 0.800 0.800 0.800 0.800 0.800 0.800 0.800 0.800 0.800 0.800 0.800 0.800 0.800 0.800 0.800 0.800 Total COE c/kWh 4.321 4.389 4.273 4.406 4.331 4.414 4.306 4.218 4.343 4.224 4.093 4.474 4.328 4.389 4.247 4.261 4.177 4.226 4.244 4.280 4.366 4.286 
Appendix B 

Details from Task #5 Final Designs 
B-1 

Table B-1. Comparison of Baseline and Final Loads for 3-Bladed Upwind Machines 

 750 kW 1.5 MW 3.0 MW 

 Baseline Final Design Baseline Final Design Baseline Final Design 

 

.75A08C01V

04cAdm 

.75AA04C01

V00 

1.5A08C01V

07cAdm 

1.5AA12C05

V00 

3.0A09C02

V01adm 

3.0AA02C01V

00 

Tilt deg 5.0 5.0 5.0 5.0 5.0 5.0 

Coning deg 0.0 3.0 0.0 3.0 0.0 3.0 

Angle of contact deg 0.0 0.0 0.0 0.0 0.0 0.0 

Tip out of pln displt max m 1.862 2.468 2.816 3.467 3.467 4.464 

 min m -1.377 -2.411 -1.711 -3.523 -2.520 -5.934 

Tip clearance mrgn 0.210 -0.082 0.138 -0.074 0.322 -0.003 

Blade rt flap mt max abs kN m 1,363 747 3,298 2,081 8,970 5,369 

 equiv fatigue kN m 465 275 1,237 889 3,956 2,380 

Blade rt edge mt max abs kN m 335 164 815 497 3,821 1,969 

 equiv fatigue kN m 278 115 847 369 3,578 1,215 

Blade 25% flap mt max abs kN m 527 335 1,350 1,056 3,917 2,791 

 equiv fatigue kN m 283 156 733 526 2,302 1,369 

Blade 25% edge mt max abs kN m 175 87 412 248 1,744 1,023 

 equiv fatigue kN m 127 59 382 176 1,590 557 

Blade 50% flap mt max abs kN m 216 140 553 456 1,622 1,173 

 equiv fatigue kN m 130 66 338 231 1,063 593 

Blade 50% edge mt max abs kN m 55 33 146 89 599 360 

 equiv fatigue kN m 43 22 126 68 502 206 

Blade 75% flap mt max abs kN m 53 32 133 108 433 275 

 equiv fatigue kN m 33 16 87 56 272 144 

Blade 75% edge mt max abs kN m 12 7 33 19 116 69 

 equiv fatigue kN m 8 5 23 13 83 42 

Shaft/hub My max abs kN m 909 438 2,105 1,360 7,129 3,835 

 equiv fatigue kN m 228 119 583 330 1,656 898 

Shaft/hub Mz max abs kN m 871 409 2,210 1,274 7,464 3,618 

 equiv fatigue kN m 230 120 579 330 1,655 895 

Shaft thrust max abs kN 159 128 324 283 797 590 

 equiv fatigue kN 25 16 44 37 89 71 

Shaft Mx max abs kN m 1,325 484 3,424 1,513 10,820 4,761 

 equiv fatigue kN m 31 33 83 83 235 263 

Yaw brg My max abs kN m 1,017 475 3,079 1,743 10,707 5,901 

 equiv fatigue kN m 184 93 468 266 1,389 769 

Yaw btg Mz max abs kN m 685 458 1,966 1,201 4,536 3,179 

 equiv fatigue kN m 182 98 473 279 1,429 801 

Tower base Mx max abs kN m 12,162 7,478 31,951 22,925 101,040 62,348 

 equiv fatigue kN m 710 526 2,058 1,644 6,944 5,087 

Tower base My max abs kN m 11,088 7,946 27,390 25,700 95,543 83,851 

 equiv fatigue kN m 2,314 1,095 5,482 3,736 15,129 10,185 

First system nat frequ P 0.68 1.18 0.8 0.87 

First blade nat. frequ P 2.72 3.66 3.38 3.51 
B-2 

Table B-2. Summary of Costs of Baseline and Final 3-Bladed Machines 

at 750 kW, 1.5 MW, and 3.0 MW 

 750 kW 1.5 MW 3.0 MW 

 Baseline Final Design Baseline Final Design Baseline Final Design 

 

.75A08C01V0

4cAdm 

.75AA04C01

V00 

1.5A08C01V

07cAdm 

1.5AA12C05V

00 

3.0A09C02V0

1adm 

3.0AA01C02

V00 

Rotor $k 100 66 236 167 654 394 

 Blades $k 63 44 152 112 413 262 

 Hub $k 18 10 48 34 157 90 

 Pitch mchnsm & bearings $k 19 11 36 21 85 42 

Drive train, nacelle $k 246 225 536 501 1,236 1,125 

 Low-speed shaft $k 7 7 20 22 58 64 

 Bearings $k 4 4 12 12 43 43 

 Gearbox $k 71 66 161 146 375 336 

 Mech brake, HS cpling, etc $k 1 1 3 3 6 6 

 Generator $k 39 39 78 78 156 156 

 Variable spd electronics $k 41 41 81 81 162 162 

 Yaw drive & bearing $k 5 3 12 6 42 18 

 Main frame $k 26 16 66 52 194 144 

 Electrical connections $k 30 30 60 60 120 120 

 Hydraulic system $k 3 3 7 7 14 14 

 Nacelle cover $k 19 15 36 33 67 63 

Control, safety system $k 10 10 10 10 10 10 

Tower $k 72 44 179 142 513 370 

Balance of station $k 223 216 403 397 905 896 

Foundations $k 41 33 63 57 108 99 

Transportation $k 27 27 51 51 253 253 

Roads, civil works $k 45 45 79 79 136 136 

Assembly & installation $k 24 24 51 51 113 113 

Elect interfc/connect $k 71 71 127 127 224 224 

Permits, engineering $k 16 16 33 33 70 70 

Initial capital cost (ICC) $k 652 561 1,365 1,217 3,318 2,797 

ICC per kW $/kW 869 748 910 811 1,106 932 

Net annual energy MWh 2,254 2,254 4,817 4,811 10,372 10,364 

Rotor 

c/kW

h 0.470 0.307 0.518 0.365 0.666 0.402 

Drive train 

c/kW

h 1.154 1.056 1.175 1.099 1.258 1.147 

Controls 

c/kW

h 0.047 0.047 0.022 0.022 0.011 0.011 

Tower 

c/kW

h 0.336 0.204 0.394 0.312 0.522 0.377 

Balance of station 

c/kW

h 1.047 1.013 0.884 0.872 0.921 0.913 

Repl't costs 

c/kW

h 0.499 0.499 0.467 0.468 0.434 0.434 

O&M 

c/kW

h 0.800 0.800 0.800 0.800 0.800 0.800 

Total COE 

c/kW

h 4.352 3.926 4.260 3.939 4.612 4.084 
B-3 

Table B-3. Comparison of 1.5-MW Final Loads with Baseline Configurations 

 3-Bladed Upwind 2-Bladed Upwind 2-Bladed Downwind 

 Baseline Final Design Baseline Final Design Baseline Final Design 

 

1.5A08C0

1V07cAd

m 

1.5AA12C05

V00 

1.5M03

C01V04

cAdm 

1.5AB05C02

V00 

1.5Q02C0

3V01cAd

m 

1.5AC02C01

V00 

Tilt deg 5.0 5.0 6.0 5.0 5.0 0.0 

Coning deg 0.0 3.0 0.0 2.0 2.0 2.0 

Angle of contact deg 0.0 0.0 2.7 2.7 2.0 2.7 

Tip out of pln displt max m 2.816 3.467 6.926 4.307 6.775 6.294 

 min m -1.711 -3.523 -4.003 -4.051 -0.429 -1.679 

Tip clearance mrgn 0.138 -0.074 -0.533 -0.166 0.041 -0.292 

Blade rt flap mt max abs kN m 3298 2081 2727 2264 2146 2403 

 equiv fatigue kN m 1237 889 1251 935 1264 1166 

Blade rt edge mt max abs kN m 815 497 1057 706 1146 802 

 equiv fatigue kN m 847 369 914 418 949 475 

Blade 25% flap mt max abs kN m 1350 1056 1625 1245 1255 1355 

 equiv fatigue kN m 733 526 772 560 766 670 

Blade 25% edg mt max abs kN m 412 248 460 365 510 408 

 equiv fatigue kN m 382 176 432 204 448 246 

Blade 50% flap mt max abs kN m 553 456 670 502 544 539 

 equiv fatigue kN m 338 231 372 252 368 275 

Blade 50% edg mt max abs kN m 146 89 173 126 190 163 

 equiv fatigue kN m 126 68 150 81 157 102 

Blade 75% flap mt max abs kN m 133 108 144 104 133 112 

 equiv fatigue kN m 87 56 97 58 95 62 

Blade 75% edg mt max abs kN m 33 19 32 26 36 31 

 equiv fatigue kN m 23 13 27 16 29 21 

Shaft/hub My max abs kN m 2105 1360 1417 1109 1562 1544 

 equiv fatigue kN m 583 330 354 310 727 532 

Shaft/hub Mz max abs kN m 2210 1274 35 52 182 132 

 equiv fatigue kN m 579 330 318 230 442 195 

Shaft thrust max abs kN 324 283 284 230 254 221 

 equiv fatigue kN 44 37 39 28 39 32 

Shaft Mx max abs kN m 3424 1513 2758 2010 2520 1760 

 equiv fatigue kN m 83 83 91 110 96 126 

Yaw brg My max abs kN m 3079 1743 2018 1268 2627 2644 

 equiv fatigue kN m 468 266 225 204 418 579 

Yaw btg Mz max abs kN m 1966 1201 1080 850 0 313 

 equiv fatigue kN m 473 279 215 212 9 4 

Tower base Mx max abs kN m 31,951 22,925 14,513 10,214 13,527 14,669 

 equiv fatigue kN m 2058 1644 2815 1150 5021 3373 

Tower base My max abs kN m 27,390 25,700 24,932 21,563 24,735 21,406 

 equiv fatigue kN m 5482 3736 5927 2609 5687 3091 

First syst nat freq P 1.18 0.803 ~1.2 0.78 ~1.2 0.822 

First blade nat. freq P 3.66 3.16 3.75 3.70 3.76 3.59 

Note: When clearance margins were negative, mass and cost were added to the blade to restore this 

margin to zero. 
B-4 

Table B-4. Comparison of Final Costs with 1.5-MW Baseline Configurations 

 3-Bladed Upwind 2-Bladed Upwind 2-Bladed Downwind 

 Baseline 

Final 

Design Baseline 

Final 

Design Baseline 

Final 

Design 

Filename 

1.5A08C01

V07cAdm 

1.5AA12C0

5V00 

1.5M03C01V0

4cAdm 

1.5AB05C0

2V00 

1.5Q02C03V0

4cAdm 

1.5AC01C0

2V00 

Rotor $k 236 167 171 133 168 146 

 Blades $k 152 112 98 70 97 70 

 Hub $k 48 34 57 48 58 60 

 Pitch mchnsm & bearings $k 36 21 16 15 13 16 

Drive train, nacelle $k 536 501 547 482 522 518 

 Low speed shaft $k 20 22 21 20 20 20 

Bearings $k 12 12 13 12 12 12 

 Gearbox $k 161 146 155 145 155 149 

 Mech brake, HS cpling etc $k 3 3 3 3 3 3 

 Generator $k 78 78 98 78 78 78 

Variable-speed electronics $k 81 81 101 81 81 81 

 Yaw drive & bearing $k 12 6 7 4 6 10 

Main frame $k 66 52 49 44 62 66 

 Electrical connections $k 60 60 60 60 60 60 

Hydraulic system $k 7 7 7 7 7 7 

 Nacelle cover $k 36 33 34 28 37 32 

Control, safety system $k 10 10 10 10 10 10 

Tower $k 179 142 185 115 177 139 

Balance of station $k 403 397 396 393 396 393 

Foundations $k 63 57 57 53 56 53 

Transportation $k 51 51 51 51 51 51 

Roads, civil works $k 79 79 79 79 79 79 

Assembly & installation $k 51 51 51 51 51 51 

Elect interfc/connect $k 127 127 127 127 127 127 

Permits, engineering $k 33 33 33 33 33 33 

Initial capital cost (ICC) $k 1,365 1,217 1,310 1,133 1,272 1,207 

Net annual energy MWh 4,817 4,811 4,707 4,708 4,707 4,708 

Rotor c/kWh 0.518 0.365 0.383 0.298 0.376 0.328 

Drive train c/kWh 1.175 1.099 1.227 1.081 1.170 1.163 

Controls c/kWh 0.022 0.022 0.023 0.023 0.023 0.023 

Tower c/kWh 0.394 0.312 0.415 0.257 0.396 0.312 

Balance of stn c/kWh 0.884 0.872 0.889 0.881 0.889 0.881 

Repl't costs c/kWh 0.467 0.468 0.478 0.478 0.478 0.478 

O&M c/kWh 0.800 0.800 0.800 0.800 0.800 0.800 

Total COE c/kWh 4.260 3.939 4.216 3.818 4.132 3.984 
B-5 

Table B-5. Governing Load Cases and Margins for 

Baseline and Task #5 Final Configurations 

 1.5 MW 750 kW 3.0 MW 

 3-Bladed Upwind 2-Bladed Upwind 2-Bladed Downwind 3-Bladed Upwind 3-Bladed Upwind

 Baseline Task 5 Baseline Task 5 Baseline Task 5 Baseline Task 5 Baseline Task 5 

 1.5A08C

01V07cA

dm 

1.5AA12

C05V00 

1.5M03C

01V04cA

dm 

1.5AB05

C02V01

1.5Q02C

03V04cA

dm 

1.5AC01

C01V02

.75A08C

01V04cA

dm 

.75AA04

C01V00 

3.0A09C

02V01Ad

m 

3.0AA02

C01v00

Governing 

load 

EWM Displ’t Fatigue Displ’t Fatigue Displ’t EWM Displ’t Fatigue Displ’t 

Blade 

root My 

Next 

critical 

Fatigue EDC EWM EWM EOG EWS Fatigue NTM EWM NTM 

margin 52% 33% 10% 10% 39% 44% 18% 14% 1% 50% 

 Governing 

load 

Fatigue Displ’t Fatigue Displ’t Fatigue Displ’t Fatigue Displ’t Fatigue Displ’t 

Blade 

50% My 

Next 

critical 

EWM EDC EWM EWSV EOG EWSV EWM EDC ECD NTM 

 margin 50% 12% 40% 7% 68% 35% 47% 10% 57% 6% 

Governing 

load 

Fatigue Fatigue Fatigue Fatigue Fatigue Fatigue Fatigue Fatigue Fatigue Fatigue

Hub Next 

critical 

EWM EDC EWM EWM EOG EWSV EWM NTM EWM NTM 

margin 22% 64% 55% 38% 71% 70% 68% 56% 90% 63% 

 Governing 

load 

Fatigue Fatigue Fatigue Fatigue Fatigue Fatigue Fatigue Fatigue Fatigue Fatigue

Mainframe 

Next 

critical 

ECD NTM ECD ECD EWM EWSV ECD ECD ECD ECD 

 margin 36% 30% 5% 49% 55% 84% 50% 64% 23% 20% 

Governing 

load 

Fatigue Fatigue Fatigue Fatigue Fatigue Fatigue Fatigue Fatigue Fatigue Fatigue

Tower 

base 

Next 

critical 

EWM NTM NTM Estop EOG EOG EWM EOG Estop Estop 

margin 40% 17% 78% 4% 71% 30% 47% 14% 29% 3% 
C-1 

Appendix C 

Avon Bearing Costs 

bolt circle maximum maximum equiv thrust thrust design machine quantity P/N Unit Cost Cost/50MW Weight [kg]

rotor diam diam moment thrust due to mt capacity margin rating per 50MW

m m kN m kN kN kN kW

46.6 1.45 1217 494.2 3357 4245 -0.00601 750 67 120B6 $3,331 $223,177 355

66 2.14 3773 1201 7052 8866 -0.02941 1500 33 1788B3 $6,374 $210,342 770

93 2.548 11826 2919 18565 21746 -0.08648 3000 17 TR15107B $29,105 $494,785 4000

120 4.086 27646 5616 27064 34121 -0.05386 5000 10 TR15168B $46,000 $460,000 6800

46.6 1.005 1440 6523 0.011709 750 200 2544B1 $4,045 $809,000 620

66 1.425 4071 10736 -0.16486 1500 100 TR1263B2 $13,795 $1,379,500 1850

93 2.000 11514 21976 -0.15173 3000 50 TR2086B1 $31,754 $1,587,700 4700

120 3.438 24775 28834 -0.11082 5000 30 TR15142B1 $0 5700

Specifications Avon Data

Pitch bearings

Yaw Bearings

Avon Bearing costs (f: WindPACT rotor scaling\task 1\bearingcostWtSummaryDM.xls) 
D-1 

Appendix D 

Calculation of Fatigue Damage Equivalent Loads 

Suppose that the fatigue strength of a material is given by the single relationship 

m

0

m

1

0

S

S N

or

NSS

−

−

⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ =

=

where S = load applied 

 S0= a constant 

 N = number of cycles at load level S 

 m = a constant 

According to Miners cumulative damage rule, the damage, D, done by a number of loads, Si, applied for 

ni cycles respectively, will be 

∑

∑

− =

=

m

ii m0

i

i

SnS

N

n D

Suppose that the same fatigue damage is done by a single load, Se, applied for ne cycles. Then 

m

1

m

ii

e

e

m

ii

m

0

m

0

e e

m

0

e e e

e

Sn

n

1 S

or

Sn

S

1

S

S

n

thatso

S

S

n N

n D

⎥

⎦

⎤ ⎢

⎣

⎡ =

⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ = ⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ ==

∑

∑

The last line is an expression for a load level that will cause the same fatigue damage as a combination of 

loads, Si, and is known as the equivalent fatigue load. It should be noted that this expression is valid only 

if the assumption is made of a single relationship between the load and fatigue strength. This corresponds 

to a single straight line on a log-log graph. 
Appendix E 

Description of the Blade Pitch Control System 
E-1 

Pitch Control Systems for the WindPACT Rotor Design Study 

C. Hansen 

Windward Engineering, LLC 

March 2, 2001 

This document briefly describes the pitch control systems used in the WindPACT Rotor Design Study. 

All the wind turbines under investigation in this study use full-span, collective pitch control in 

conjunction with variable-speed generators. Therefore, all the pitch controllers in this study have as their 

primary goal the control of generator speed. The systems attempt to operate at constant tip speed ratio 

(fixed pitch) when the wind is below rated. As the wind speed approaches the rated value, the pitch 

controller attempts to maintain constant rotor speed (“rated speed”). 

The generator/power-electronics systems in this study have torque proportional to the square of generator 

speed below rated, then constant (or very slowly increasing) torque above the rated generator speed. This 

makes it possible to operate at constant tip speed ratio below rated as long as the blade pitch remains 

constant. Above rated, the system power output will change only in proportion to rotor speed since the 

torque remains essentially constant. Hence, power regulation is entirely dependent upon speed regulation. 

The pitch control systems are implemented in the form of linear transfer functions in ADAMS and 

FAST_AD models. The same control subroutines and controller data files are used in both codes to 

calculate the pitch demand. In ADAMS, this pitch demand is sent to an actuator, which applies a pitching 

moment to the blade. In FAST_AD the pitching dynamics are not calculated directly. Instead, the 

actuator is represented as a linear transfer function between pitch demand and actual pitch. The ADAMS 

actuator and the FAST_AD actuators are selected to have essentially identical characteristics. 

Figure 1 shows the control diagram for the basic speed controller. Figure 2 is similar, but tower 

acceleration is input to the pitch demand controller in an attempt to damp longitudinal vibration of the 

tower. Both systems use basic PID control with gains denoted in the figures as KI, KP, and KD. When 

implemented numerically, we use a modified form of the derivative term, KDs/(1+τs), where τ is a time 

constant that is small compare with other significant time scales in the system. We implement all the 

controls in discrete time. The typical time step is 0.025 sec. 

Generator speed error is input to the basic controller. The PID controller determines the desired pitch 

angle, feathering the blade (increasing pitch) when the generator speed is too high. The pitch demand is 

limited to the range of θmin to 90°. θmin is the pitch angle at which optimum rotor aerodynamic 

performance is achieved when operating at constant tip speed ratio. When the rotor speed is below the 

desired setpoint, the pitch will remain constant at θmin. The generator torque characteristics must be 

matched to the rotor torque in order to actually achieve constant tip speed ratio operation. 

The presence of the pitch demand saturation function requires that integrator anti-windup be included in 

the controller. This is shown as the feedback with gain KAW in the figures. Note that this anti-windup 

term is fed back to the integrator only. This prevents the integrated speed error from accumulating when 

the rotor is operating in low winds, below rated speed. We have used a gain of 0.3 rpm/deg in all of our 

simulations. The results are insensitive to this gain when implemented in this manner. 

The rotor characteristics are a strong nonlinear function of wind speed, hence blade pitch. This requires 

that the PID gains be “scheduled” as a function of blade pitch angle. Each of the PID gains is multiplied 

by a function, GS, of the form: 
E-2 

 

1

1 2

2 2

1

p

p

GS a

a

θ θ

θ θ θθ

θ θθ

⎧ ⎫ < ⎪ ⎪ = ≤≤ ⎨ ⎬

⎪ ⎪ > ⎩ ⎭

where a, p, θ1, and θ2 are constants input by the user. Coefficients a and p must be selected such that 

1 1 p aθ = . The exponent p is negative. It should be selected such that the product of the gain schedule 

value, GS, and the rotor “gain”, Q

θ

∂

∂ (the sensitivity of rotor torque, Q, to blade pitch, θ), is nearly 

constant for all wind speeds in the operating range. 

The pitch actuator in the WindPACT models is a simple second order system: 

2

2 2 ( ) 2

n

a

n n

H s

s s

ω

ξω ω = + +

with ξ = 80% of critical damping and a natural frequency that is a multiple of the rotor speed. In most 

cases we have used ωn = 4Ω, where Ω is the rotor angular velocity. 

The turbine drive train is represented as a single torsion spring, k, between the generator inertia, Ig, and 

rotor inertia, Ir. The generator torque is represented as a linear function of generator speed, with slope = 

A. The resulting transfer function between rotor torque and generator speed is: 

3 2

( )

1

r

DT

g

g

r r

k

I H s

I Ak I s As ks

I I

= ⎛ ⎞

+ ++ + ⎜ ⎟ ⎝ ⎠

Many of the rotors we are modeling have a tower natural frequency close to 1 cycle per rotor revolution 

(1P). These systems experience substantial tower motion parallel to the wind direction. The tower 

motion appears as a cyclic wind speed input to the rotor and causes rotor speed oscillations, which in turn 

cause pitch oscillations. This motion can be exacerbated by a highly responsive pitch control system. We 

generally find it necessary to reduce the speed control effectiveness in order to avoid excessive tower 

fatigue loads. Finding the best balance between tower loads and effective speed control is subjective and 

largely a matter of trial and error with system simulations. 

To alleviate this problem, we have implemented tower acceleration feedback. This is illustrated in Figure 

2. The tower dynamics (in the “tower fore-aft motion” box) are represented as a transfer function from 

rotor thrust to tower-top velocity: 

2

2

( ) 2 1

t

T

t t

s

k H s

s

s ξ

ω ω

=

+ +
E-3 

Here kt is the effective stiffness of the tower, ωt is the natural frequency, and ξ is the structural damping 

ratio. The rotor thrust is a linear function of the blade pitch (at a given wind speed) with a slope of T

θ

∂

∂ , 

determined from steady-state aerodynamics calculations at the desired wind speed and pitch angle. 

The tower acceleration is input to a lag compensator to determine a change in pitch in response to the 

motion. This compensator is of the form: 

 

1

( ) 1 LC

s

T H s

s

αT

+

=

+

where α > 1 and T is a time scale related to the period of tower motion. 

Two additional derivatives are needed to run a simple linearized model of this system. The sensitivity of 

rotor thrust to changes in pitch angle, T

θ

∂

∂ , was mentioned above. We also need the sensitivity of rotor 

torque to wind speed (or tower speed), Q

V

∂

∂ . Using this technique, all of the aerodynamic characteristics 

of the system are represented by simple constants determined by steady-state simulations. Obviously this 

approximation neglects unsteady and nonlinear aerodynamic effects, which are know to be important to 

the system dynamics. As a result, the controllers must be verified and fine-tuned in full system 

simulations over the entire operating range of the system. 

We have found that we can use this feedback to reduce tower loads or to improve speed regulation 

without increasing tower loads. However, the selection of all the controller parameters remains at least in 

part a matter of trial and error. We select the constants using simple MATLAB models of these 

controllers. Then we run a series of turbine simulations in turbulent winds and estimate the fatigue 

damage at several locations on the turbine. We generally find that we can decrease loads in one area at 

the expense of increased loads elsewhere. Selection of the best design depends on the lowest cost of 

energy, obviously not a simple thing to evaluate. 
E-4 

KI / s

Ω d

+

-

pitch limits

actuator

KAW

θd θ 

dQ/dθ

-

+

+

+

-

+

θ = blade pitchΩ = generator speed

Q = rotor torque( )d = demand

Q

KP + KDs / (1 + τs)

pitch demand controller

gain scheduling uses

current pitch

Ω d - Ω

Figure E-1. Basic WindPACT rotor speed control system 
E-5 

KI / s

Ω d

+

-

pitch limits

actuator

KAW

θ d θ 

-

+

+

+

-

+

θ = blaΩ = ge

Q = ro( )d = 

T = roV = wx = tow

Q

KP + KDs / (1 + τs)

pitch demand controller

gain scheduling uses

current pitch

lag compensator

+

+

+

+

s

tower fore -

aft motion T

.

x

..

x

dQ

dV

dT

dθ

dQ

dθ Ω d - Ω

Figure E-2. WindPACT speed control with tower acceleration feedback 
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PLEASE DO NOT RETURN YOUR FORM TO THE ABOVE ORGANIZATION.

1. REPORT DATE (DD-MM-YYYY)

Revised April 2006 

2. REPORT TYPE

Subcontract Report 

3. DATES COVERED (From - To)

June 2000 – June 2002 

5a. CONTRACT NUMBER

DE-AC36-99-GO10337 

5b. GRANT NUMBER

4. TITLE AND SUBTITLE

WindPACT Turbine Rotor Design Study 

5c. PROGRAM ELEMENT NUMBER

5d. PROJECT NUMBER

NREL/SR-500-32495 

5e. TASK NUMBER

WE001510 and WER11510 

6. AUTHOR(S)

D.J Malcolm and A.C. Hansen 

5f. WORK UNIT NUMBER

7. PERFORMING ORGANIZATION NAME(S) AND ADDRESS(ES)

Global Energy Concepts, 5729 Lakeview Drive NE, #100, Kirkland, WA 98033

Windward Engineering, 4661 Holly Lane, Salt Lake City, UT 84117 

8. PERFORMING ORGANIZATION 

REPORT NUMBER

YAT-0-30213-01 

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NREL/SR-500-32495 

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14. ABSTRACT (Maximum 200 Words)

This report presents the results of the turbine rotor study completed by Global Energy Concepts (GEC) as part of the 

U.S. Department of Energy’s WindPACT (Wind Partnership for Advanced Component Technologies) project. The 

purpose of the WindPACT project is to identify technology improvements that will enable the cost of energy from wind 

turbines to fall to a target of 3.0 cents/kilowatt-hour in low wind speed sites. The study focused on different rotor 

configurations and the effect of scale on those rotors. 

15. SUBJECT TERMS

wind turbine rotor; wind energy; WindPACT; Global Energy Concepts 

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