EUREC-NTUA Projects - Carlos Silva

84
Wind Farm Study – EUREC 2016 Carlos E. Silva NTUA Athens 2016

Transcript of EUREC-NTUA Projects - Carlos Silva

Page 1: EUREC-NTUA Projects - Carlos Silva

Wind Farm Study – EUREC 2016 Carlos E. Silva

NTUA Athens 2016

Page 2: EUREC-NTUA Projects - Carlos Silva

Wind Measurements Data Analysis

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Wind Measurement Data Analysis

1 year wind data (10 minutes averaged wind velocity)

Hub height

Wind Speed

Wind direction

Site wind provided by a R&D Energy Center.

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Wind Measurement Data Analysis

Avg. Probability and Wind Speed Roses.

0%

5%

10%

15%

20%N

NNE

NE

ENE

E

ESE

SE

SSE

S

SSW

SW

WSW

W

WNW

NW

NNW

Avg. Probability

-

2,0

4,0

6,0

8,0N

NNE

NE

ENE

E

ESE

SE

SSE

S

SSW

SW

WSW

W

WNW

NW

NNW

Avg. Wind Speed

• WNW - S = 80 % from Operational Time!

• NW – WNW = Strongest AWS (7.2 m/s)

• WSW – SSW = Highest Operational Demand! (6.8 m/s)

Wind Rose Parameters

No. Wind Segments 16 Total angle [°] 360

Angle/direction [°] 22,5

First Segment Angle [°] 348,75 Uave [m/s] 6,41

Std.Dev 3,35

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Wind Measurement Data Analysis

Wind Rose

0%

2%

4%

6%

8%

10%

12%

14%

16%

18%

N

NNE

NE

ENE

E

ESE

SE

SSE

S

SSW

SW

WSW

W

WNW

NW

NNW

Wind Rose

0 to 4

4 to 8

8 to 12

12 to 16

16 to 20

20 to 24

24 to 28

28 to 32

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-

1

2

3

4

5

6

7

8

9

Win

d S

pe

ed

[m

/s]

Month

Mean monthly wind speed variation

Wind Measurement Data Analysis

Mean monthly wind speed variation.

Month Uave [m/s]

January 7,33

February 7,52

March 6,18

April 5,40

May 6,58

June 6,51

July 6,99

August 8,23

September 5,38

October 6,13

November 6,39

December 4,23

Total

Uave 6,41

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Wind Measurement Data Analysis

Turbulence Intensity

0

0,1

0,2

0,3

0,4

0,5

0,6

0,7

0,8

0,9

1

0 5 10 15 20 25 30 35

Turb

ule

nce

In

ten

sity

%

Hub Wind Speed (m/s)

Turbulence Intensity per Hub Wind Speed

Determine the Wind Turbine Iref (A,B or C) using IEC 61400-1 Ed.3 Wind Classification

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Wind Measurement Data Analysis

Weibull Semi-Empirical, Least Square Fit method and Bins Probability

Bowden Semi-Empirical

Shape Factor K 2,02

Scale Factor C 7,23

Uave [m/s] 6,41

Least Square

Shape Factor K 1,85

Scale Factor C 7,52

Uave [m/s] 6,67

Semi Empirical

Least Square

0%

2%

4%

6%

8%

10%

12%

14%

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28

Pro

ba

bilit

y %

Wind Speed m/s

Weibull Distribution Comparison

Bowden Semi-Empirical Probability per bins Least Square

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Site Wind Turbine Selection

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Site Wind Turbine Selection

2MW Wind Turbine R&D Benchmark

Test Turbine Selection

Vave [m/s] 6,4

Hub Height [m] 90

Diameter [m] 90

Vmax[m/s] 32

Reference cost for the test turbine (€/kW) 950

TEST TURBINE

DESIGN CHARACTERISTICS

Power (kW) 2000

Diameter (m) 90,0

Max Tip Speed (m/s) 80,0

Drive Train Efficiency 94,00%

Omega Rotor max (rad/s) 1,78

RPM Rotor max 16,98

Rated Rotor Torque (kNm) 1197

x = 1,50

COMPONENTS MASS & COST

MASS (kg) COST (euro)

Three Blades 19.677 255.801

Gearbox 10.308 123.690

Generator 5.550 80.478

Cost of blades, Gearbox, Generator 459.969

Rest cost of drive train (nacelle, power electronics, pitch etc)459.969

Subtotal drive train 919.938

980.062

Total cost of wind turbine 1.900.000

Share of BL, GB, Gen in the total WT cost 24,2%

Cost of the hub

90 m diameter as a reference turbine!

Class III Wind Turbine!

ave refV 0.2V

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Site Wind Turbine Selection and Power Curves

What the competition has available for IEC III 2 MW Wind Turbines?

Project Wind Data

Vave [m/s] 6,41

C 7,23

Std.Dev 3,4

K 2,021

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Site Wind Turbine Selection

2MW Wind Turbine R&D Benchmark

90 m diameter as a reference turbine. + 80 and 100m diameters for industry

competition Go-To-Market!

3 Project testing diameters: 80, 90 and 100 m

IEC Class III (6 - 7.5 m/s)

80 m

90 m

100 m

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Site Wind Turbine Selection

NTUA – 2 MW PLATFORM ASSORTMENT

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Site Wind Turbine Selection

LCOE per 2 MW Product Range Diameters

Lowest LCOE !

Highest Annual Energy Output !

39,2 % Capacity Factor!

+14 % Wind Turbine Cost vs. 90m diameter!

Selection of our IEC III- NTUA/2MW 100 m diameter & tower height wind turbine:

WIN – WIN SOLUTION!!!!!

80 90 100 100 Vs. 80 100 Vs. 90

Avg. Wind Speed [m/s] 6,41 6,41 6,41

Avg. Power Output [kW] 592 697 783 32% 12%

Avg. Power Output per RA [kW/m^2] 0,03 0,03 0,02 -15% -9%

Annual Energy Output [GWh] 4,93 5,80 6,52 32% 12%

Capacity Factor (%) 29,6% 34,8% 39,2% 32% 12%

LCOE [€/kWh] 0,064 0,060 0,058 -9% -3%

LCOE [€/MWh] 63,86 59,56 57,93 -9% -3%

Wind Turbine Cost [€] 1.638.360 1.900.000 2.174.272 33% 14%

Wind Turbine Project IndicatorsWind Turbine Diameters 100 m diameter performace

2 MW Wind Turbines Range

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Site Wind Turbine Selection

LCOE per Technology

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Site Wind Turbine Selection

2 MW Vs. 3 MW Platform

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Site Wind Turbine Selection

3 MW Platform LCOE

X More Expensive LCOE vs 2 MW!

18% Higher Annual Energy Output vs. 2MW platform!

X 30,7 % Capacity Factor!

+17 % Wind Turbine Cost vs. 2 MW platform!

What happens If we upscale the wind turbine to a 3 MW platform!

2 MW 3 MW Difference

100 100 100 Vs. 80

Avg. Wind Speed [m/s] 6,41 6,41

Avg. Power Output [kW] 783 922 18%

Avg. Power Output per RA [kW/m^2] 0,02 0,03 18%

Annual Energy Output [GWh] 6,52 7,67 18%

Capacity Factor (%) 39,2% 30,7% -22%

LCOE [€/kWh] 0,058 0,063 9%

LCOE [€/MWh] 57,93 62,85 9%

Wind Turbine Cost [€] 2.174.272 2.543.076 17%

Wind Turbine Project Indicators

100 m diameter 2MW vs. 3MW Platform

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IEC III NTUA 100/2MW Wind Turbine Performance

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IEC III NTUA 100/2MW Wind Turbine Performance

Pitch Regulation and Variable Speed Design

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IEC III NTUA 100/2MW Wind Turbine Performance

Pitch Angle & Rotor Speed Variation per Wind Velocity

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IEC III NTUA 100/2MW Wind Turbine Performance

Thrust per wind speed

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IEC III NTUA 100/2MW Wind Turbine Performance

Power coefficient – Tip speed ratio

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IEC III NTUA 100/2MW Wind Turbine Performance

Thrust coefficient – Tip speed ratio

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IEC III NTUA 100/2MW Wind Turbine Performance

Variable Speed Power Output & Thrust

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IEC III NTUA 100/2MW Wind Turbine Performance

Rotor Aerodynamics

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IEC III NTUA 100/2MW Wind Turbine Performance

Angle of Attack per blade lenght

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IEC III NTUA 100/2MW Wind Turbine Performance

Axian Induction Factor per blade lenght

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IEC III NTUA 100/2MW Wind Turbine Performance

Tangential Induction Factor per blade lenght

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IEC III NTUA 100/2MW Wind Turbine Performance

Normal Force per blade lenght

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IEC III NTUA 100/2MW Wind Turbine Performance

Tangential Force per blade lenght

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Wind Penetration Limits for a non-interconnected power system

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Wind Penetration Limits

What is Wind Curltailment?

It means that wind was available, but the grid operator did not allow the wind farm to put power on the grid (not dispatched).

There are 2 kinds of dispatching rules: Physical Imperatives to keep the grid in balance: • Matching load • Not over-loading transmission lines • Taking into account how quickly

various plants can come on-line.

Economics and other non-physical issues: • Dispatching the least expensive

plants first • Giving renewables a favored

position in the line-up.

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Wind Penetration Limits

Off-Grid System Annual Electricity Demand

0

5

10

15

20

25

30

35

40

1 400 799 1198 1597 1996 2395 2794 3193 3592 3991 4390 4789 5188 5587 5986 6385 6784 7183 7582 7981 8380

De

man

d (

MW

)

Time (hr)

Power Demand

Demand characteristics

Maximum power demand 34,1 MW

Minimum power demand 6,7 MW

Annual electricity demand 118,04 GWh

Annual mean load 13,5 MW

Maximum Power Demand

Annual Mean Load

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Wind Penetration Limits

Simplified Diagram

6.4 m/S

76%

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Wind Penetration Limits

Simplified Diagram

Total Load Demand (MWh) 118.036 118.036 118.036

Average Load (MW) 13,5 13,5 13,5

Average Wind Speed (m/s) 6,4 6,4 6,4

Power Rated per Wind Turbine (MW) 2 2 2

Number of Wind Turbines 6 5 4

Total Wind Turbine Capacity (MW) 12 10 8

Wind Installed Capacity (%) 89% 74% 59%

Capacity Factor (%) 39,2% 39,2% 39,2%

Absorbed by the grid (%) 68% 76% 86%

Rejected by the grid (%) 32,0% 24,0% 14,0%

Total Wind Energy Production (MWh) 39.110 32.592 26.073

Total Wind Energy Absorbed by the grid (MWh) 26.595 24.770 22.423

Real Capacity Factor (%) 25% 28% 32%

Wind Supply (%) 23% 21% 19%

Simplified Diagram Tables

The right balance across installed wind capacity and the 20% wind energy annual energy supply is found at 10 MW (5 turbines), providing: • 24% curtailment • 28% capacity factor • 21% wind energy annual electricity supply

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Wind Penetration Limits

Probabilistic Approach

No. Turbines Rated Capacity (MW)

Data 5 2

Wind Capacity 10 MW

Wind capacity as percentage of the average load 74,2%

Number of diesel units 10

Rated power of diesel unit 3,5 MW

Diesel units technical minimum 40%

Diesel Total Capacity 35 MW

Diesel technical minimum capacity 14 MW

Wind and Diesel Capacity

Wind energy which could be produced 33645 MWh

Wind Absorbed + Rejected 34,04 GWh

Wind energy absorbed by the grid 23,5 GWh

Wind energy rejected 10,5 GWh

Percentage of rejected wind energy 30,8%

Conventional energy produced 94,49 MWh

Conv+Wind absorbed 118,04 MWh

Capacity factor available 38,41%

Capacity factor real 26,88%

% wind supply 20%

Results

Wind Penetration Limits

Maximum instantaneous wind supply "δ" 38%

With a 38% wind penetration: • We only require 5 turbines

with a total of 10 MW installed wind capacity.

• 74,2 % from the average

load.

The wind curtailment is 30,8 % and the capacity factor is 26,88 %.

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Capacity Credit For a non-interconnected power system

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Capacity Credit

Capacity Credit Calculation

Wind Installed Capacity (MW) 10,0

LOLE System before wind installations 0,053%

LOLE System after wind installations 0,053%

ELCC 1,5

CC 15%

Capacity Credit Calculation

Capacity credit is the level of conventional generation that can be replaced with wind generation. To perform such an analysis, it is important to define the way in which one type of resource can be substituted for another.

Number of units 10

Mean rated power of each unit 3,5 MW

Total conventional capacity 35 MW

Propability of each unit to be available 95%

Propability of each unit not to be available 5%

CONVENTIONAL CAPACITY DATA

For our case, we measured the system reliability with the loss-of-load expectation (LOLE), which is an indication of the statistically expected number of times within a given time period that the system could not provide the demand load. When the given level of wind-generating capacity can be substituted for conventional capacity, holding the reliability level constant, we obtained the measure of wind plant capacity credit with 15%

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Wake Effect Losses 5 turbines 100m/2MW - Flat Terrain

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Wake Effect Losses

Main Frecuency wind speed and wind sectors

As defined by the Wind Rose, our site 2 main operational wind speeds are coming from 3 main wind direction sectors: SSW, WSW and WNW (202.5, 247.5 and 292.5 deg). This is a decision factor to position our turbines and minimize the Wake Effect Losses.

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Wake Effect Losses

Analysis Wind Farm Proposal 1

6.195

5.717

7,71%

Wind Farm Losses

Wind Energy Production [MWh]

Wind Energy Production with Wake Effect [MWh]

Wake Losses

The first project proposal is arranged in order to take the biggest advantage of the SSW and WSW wind rose directions, the 2 biggest main sectors.

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Wake Effect Losses

Analysis Wind Farm Proposal 1

292,5 deg – 11,31%

frecuency

12,04 % losses

247,5 deg – 14,33%

frecuency

1,42 % losses

202,5 deg – 14,03%

frecuency

2,12 % losses

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Wake Effect Losses

Analysis Wind Farm Proposal 2

6.195

5.792

6,51%

Wind Farm Losses

Wind Energy Production [MWh]

Wind Energy Production with Wake Effect [MWh]

Wake Losses

The aim from the second project proposal is to look for a wind turbine arrangement able to reduce more drastically the losses generated by the 292,5 deg wind direction and the separation of wind turbines to have an even cleaner wind segments at the 2 main wind directions 247,5 and 202,5 deg.

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Wake Effect Losses

Analysis Wind Farm Proposal 2

292,5 deg – 11,31%

frecuency

8,94 % losses

247,5 deg – 14,33%

frecuency

0,92 % losses

202,5 deg – 14,03%

frecuency

1,05 % losses

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Wake Effect Losses

Analysis Wind Farm Proposal 3

6.195

5.819

6,07%

Wind Farm Losses

Wind Energy Production [MWh]

Wind Energy Production with Wake Effect [MWh]

Wake Losses

For the final proposal, witch is the project selection, the aim was to find the proper separation across turbines from the wind direction 292,5 deg that wont harm negatively the wind turbiness efficiency from the 247,5 and 202,5 deg wind sectors.

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Wake Effect Losses

Analysis Wind Farm Proposal 3

292,5 deg – 11,31%

frecuency

7,55 % losses

247,5 deg – 14,33%

frecuency

0,50 % losses

202,5 deg – 14,03%

frecuency

0,48 % losses

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Project Financial Evaluation

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Project Financial Evaluation

Financial Assessment

NPV (thousand €) IRR % PBP (years)

1.569 7,85% 12

Wind Turbines Capacity (MW) 2

Wind Turbines 5

Wind Farm Capacity (MW) 10

Load factor 0,27

Total Investment Cost (€) 16.111.359

Wind Turbine Cost (€) 2.174.272

Other Cost (€/kW) 524

Operational cost (% Inv.Cost) 3,0%

Tax (%) 35%

Depreciation rate (%) 10%

Interest rate (%) 6%

Feed-inTariff (€/MWh) 99

Discount rate (%) 6%

Salvage value (% Inv.Cost) 20%

Rate to local authorities (% Income) 0%

Availability (%) 98%

Electricity Production (MWh) 23073

Wake Losses 6,07%

Electricity Production (MWh) 21.673

FINANCIAL PARAMETERS

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Project Financial Evaluation

Sensitivity Analysis

Taxes NPV (thousand €) IRR % NPV % Change I IR % Change

20% 2.593 € 9% 36% 8%

25% 2.252 € 9% 18% 4%

30% 1.910 € 8% 0% 0%

35% 1.569 € 8% -18% -4%

40% 1.227 € 7% -36% -9%

Taxes Variation

Taxes Variation: the analysis was performed from 20 to 40% taxes band by 5% difference. Observing how if the goverment policies developed by a country support renewable energy wind projects with 20% taxes, that will improve +36% more the NPV. On the other hand, a bad policy desicion making to increase taxes, will devaluate our NPV to -36%.

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Project Financial Evaluation

Sensitivity Analysis

Interest Rate NPV (thousand €) IRR % NPV % Change I IR % Change

3,0% 2.844 € 10% 81% 22%

4,0% 2.419 € 9% 54% 14%

5,0% 1.994 € 8% 27% 7%

6,0% 1.569 € 8% 0% 0%

7,0% 1.143 € 7% -27% -7%

8,0% 718 € 7% -54% -13%

Interest Rate Variation

Interest Variation: Looking at the results, small increments on the interest rate by the banks will totally diminish the NPV of our project. Example from current 6% to 8% interest rate will reduce the NPV -54% their value.

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Project Financial Evaluation

Sensitivity Analysis

Energy

Price

(€/MWh)

NPV (thousand €) IRR % NPV % Change I IR % Change

79 -2.780 € 3% -277% -64%

89 -606 € 5% -139% -32%

99 1.569 € 8% 0% 0%

109 3.743 € 10% 139% 34%

119 5.917 € 13% 277% 68%

Energy Price Variation

Energy Price Variation: Having positive policies that provide and attractive feed in tariff retribution, example of values higher than 99 €/MWh, increases drastically our IRR% and NPV peformaces. On the other hand, an history of policy changes of excluding attractive feed in tariff retributions, minimizing them or avoiding them in order to pay current market price, will result in lower and even negative NPV´s. This will make investors look for other investment opportunities outside renewable energy projects.

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126/5MW Wind Turbine – (EOG) Extreme Operating Gust simulation at rated speed 11.4 m/s Carlos E. Silva

NTUA Athens May 2016

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GAST WORKSHOP

Input Information for the 126/5MW Wind Turbine

EOG at 11.4 m/s

• 11.4 m/s initial wind speed • 12 RPM initial rotor speed • Controler with a 80 sec simulation

• Wind shear 0.2 • IWINDC : 2 (extreme condition) • Time GUST (40 sec), Vref (42.5), Ti (0,16)

Vref = Reference wind speed average over 10 minutes, A = Designates the category for higher turbulence characteristics

NOTE: Gamesa similar turbine than the example analized.

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IEC 61400-1 Ed.3 Extreme Wind Conditions

It includes: • Wind shear events • Peak wind speeds due to storms • Rapid changes in wind speed and

direction.

It involves: Extreme wind speed model (EWM) Extreme operating gust (EOG) Extreme turbulence model (ETM) Extreme direction change (EDC) Extreme gust with direction change (ECD) Extreme wind shear (EWS)

• Extreme operating gust (EOG) Time GUST (40 sec), Vref (42.5), Ti (0,16)

Longitudinal turbulence scale parameter (89.56)r:

Hub height gust magnitude:

Turbulence standard deviation:

Wind profile (wind shear 0.2)

Wind speed:

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What happens at the wind blades with Extreme GUST?

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Looking at the wind behavior!

GUST effect at Hub velocity (m/s) – Class IIA 5MW Wind Turbine

42.5 sec

45.2 sec

48.1 sec

11.4 m/sec

15.7 m/sec

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Looking at the blades! Hub wind velocity vs. blade tip/middle section Effective velocity (m/s))

Hub velocity

Blade middle section

Blade tip section

Disk Induced flow (Axial induction factor)

Rotor rotation

Flow rotation (Tangential induction factor)

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Looking at the blades!

Pitch angle of blades (deg)

45.2 sec “pitch regulation kicks in”

47.6 sec

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Looking at the blades!

Pitch angle and Angle of Attack (deg)

Disk Induced flow (Axial induction factor)

Pitch Angle

Angle of Attack

45.2 sec

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Looking at the blades! Blade tip section - Axial and Tangential Induction Factor

Tangential Induction Factor

Axial Induction Factor

(Vel. Reduction Rate)

Disk Induced flow (Axial induction factor)

Rotor rotation

Flow rotation (Tangential induction factor)

45.2 sec

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Looking at the blades!

Total Aerodynamic Thrust (kN)

45.2 sec

48 sec

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Looking at the blades!

Tip - Flapwise deformation (m) – Max deformation!

45.2 sec 7.7m

48 sec Rotor plain position

Transient Response

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Looking at the blades!

Mx and Mz: moment at the root (kNm) – Max Moment!

45.2 sec 14,200 kNm

48 sec

Flapwise

Edgewise

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Looking at the blades!

Mx: x moment at the root (kNm) -> 3 blades

45.2 sec

48 sec

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Looking at the blades!

Mx: x moment at the root (kNm) -> 3 blades

45.2 sec 14,200 kNm

48 sec

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How the low speed shaft reacts to GUST?

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Looking at the low speed shaft!

Rotor speed (rad/s), wrt low speed shaft

43.5 sec

46.5 sec

12 RPM

13.1 RPM

11.7 RPM

11.26 RPM

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Looking at the low speed shaft!

Total Aerodynamic Torque (kNm) & Rotor Speed (rad/sec)

Total Aerodynamic Torque

Low Speed Shaft Rotor speed

42.5 sec

45.2 sec

48.1 sec

50 sec

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Looking at the low speed shaft!

Total Aerodynamic & Generator Torque Low Speed Shaft (kNm)

Total Aerodynamic Torque

Generator Torque Low Speed Shaft

42.5 sec

45.2 sec

48.1 sec

4,800 kNm

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What happens at the tower with Extreme GUST?

Lets pretend the Wind Turbine is generating electricity!

Will this guy fall if the tower

shakes too much?

If not at least he will be

fired……..Safety first!

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Looking at the tower!

X and Z Tower Displacement (m)

43.2 sec

45.5 sec 0.7 m

fore-aft

side-to-side

0.8 m displacement in 2 sec

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Looking at the tower!

Mx and Mz: moment at the tower base (kNm)

43.2 sec

45.5 sec 105,000 kNm

Fore Aft

Twisting

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Conclusions!

• 7.7m blade maximum flapwise deformation. • 14,200 kNm flapwise root moment. • 4,800 kNM max shaft torque. • 105.000 kNM tower base moment at the fore aft

direction.

As the wind turbine “control system” could not avoid the highest loads generated by the peak gust wind speed. The Wind turbine need to be designed to withstand:

Possible Solution: If the “control system” reaction gets faster, it will activate pitching before in order to reduce the maximum loads. However this needs to be analyzed after all the extreme cases are taken in to consideration for our turbine design.

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Wind Power Industry and its Global Players

by

Carlos E. Silva

NTUA Athens, May 2016

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Introduction

Global Energy Powerty!

We have serious global problems!

• 1 of 7 in the worlds population live without electricity!! (Around 1.3 billion people)

• 17%of global population lack access to electricity!

The world is melting!

• 2015 as the hottest year vs. preindustrial times!

• COP21 goal: Keep it lower than +2C.

• 2015 is already +1C higher.

• 2016 on their way to become 3rd hottest year in a row!

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Wind Power Industry and its Global Players - Presentation Content

1. Global Wind and Solar Resource

2. Market Development

3. Main Wind Industry Players

4. Manufacturers Competitive Analysis

5. General Conclusions

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1.Global Wind and Solar Resource

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2.Market Development

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3.Main Wind Industry Players

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4.Manufacturers Competitive Analysis

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5.General Conclusions