EUREC-NTUA Projects - Carlos Silva

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

Wind Measurements Data Analysis

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.

Avg. Probability and Wind Speed Roses.
0%
5%
10%
15%
20%
N
NNE
NE
ENE
E
ESE
SE
SSE
S
SSW
SW
WS
W
W
WN
W
NW
NN
W
Avg. Probability
-
2,0
4,0
6,0
8,0
N
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

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

-
1
2
3
4
5
6
7
8
9
WindSpeed[m/s]
Month
Mean monthly wind speed variation
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

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
TurbulenceIntensity%
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

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
Probability%
Wind Speed m/s
Weibull Distribution Comparison
Bowden Semi-Empirical Probability per bins Least Square

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

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

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

NTUA – 2 MW PLATFORM ASSORTMENT

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 Indicators
Wind Turbine Diameters 100 m diameter performace
2 MW Wind Turbines Range

LCOE per Technology

2 MW Vs. 3 MW Platform

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

IEC III NTUA 100/2MW
Wind Turbine Performance

IEC III NTUA 100/2MW Wind Turbine Performance
Pitch Regulation and Variable Speed Design

Pitch Angle & Rotor Speed Variation per Wind Velocity

Thrust per wind speed

Power coefficient – Tip speed ratio

Thrust coefficient – Tip speed ratio

Variable Speed Power Output & Thrust

Rotor Aerodynamics

Angle of Attack per blade lenght

Axian Induction Factor per blade lenght

Tangential Induction Factor per blade lenght

Normal Force per blade lenght

Tangential Force per blade lenght

Wind Penetration Limits
for a non-interconnected power system

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.

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
Demand(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

Simplified Diagram
6.4 m/S
76%

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

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
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 %.

Capacity Credit
For a non-interconnected power system

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%

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

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.

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.

Wake Effect Losses
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

Wake Effect Losses
6.195
5.792
6,51%
Wind Farm Losses
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.

Wake Effect Losses
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

Wake Effect Losses
6.195
5.819
6,07%
Wind Farm Losses
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.

Wake Effect Losses
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

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

Sensitivity Analysis
Taxes NPV (thousand €) IRR % NPV % Change IIR % 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%.

Interest Rate NPV (thousand €) IRR % NPV % Change IIR % 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.

Energy
Price
(€/MWh)
NPV (thousand €) IRR % NPV % Change IIR % 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.

THANK YOU!!
Carlos E. Silva carlos.edmundo.silva@gmail.com
Linkedin: https://gr.linkedin.com/in/carlos-silva-1195a22b

126/5MW Wind Turbine – (EOG) Extreme
Operating Gust simulation at rated speed 11.4 m/s
Carlos E. Silva
NTUA Athens May 2016

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.

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:

What happens at the wind
blades with Extreme GUST?

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

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)

Pitch angle of blades (deg)
45.2 sec
“pitch regulation kicks in”
47.6
sec

Pitch angle and Angle of Attack (deg)
Disk Induced flow
Pitch Angle
Angle of Attack
45.2 sec

Blade tip section - Axial and Tangential Induction Factor
Tangential Induction
Factor
Axial Induction
Factor
(Vel. Reduction Rate)
Disk Induced flow
Rotor rotation
Flow rotation
(Tangential induction factor)
45.2 sec

Total Aerodynamic Thrust (kN)
45.2
sec
48
sec

Tip - Flapwise deformation (m) – Max deformation!
45.2 sec
7.7m
48 sec
Rotor plain position
Transient
Response

Mx and Mz: moment at the root (kNm) – Max Moment!
45.2 sec
14,200 kNm
48
sec
Flapwise
Edgewise

Mx: x moment at the root (kNm) -> 3 blades
45.2
sec
48
sec

Mx: x moment at the root (kNm) -> 3 blades
45.2 sec
14,200 kNm
48
sec

How the low speed shaft reacts to GUST?

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

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

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

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!

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

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

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.

Wind Power Industry and its Global Players
by
Carlos E. Silva
NTUA Athens, May 2016

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!

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

1.Global Wind and Solar
Resource

4.Manufacturers Competitive
Analysis

THANK YOU!!
Carlos E. Silva csilva.nem@gmail.com
Linkedin: https://gr.linkedin.com/in/carlos-silva-1195a22b

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