College of Engineering & Informatics

Assignment Submission Page

Student/Group Name(s): Student(s) ID Number: Justin Conboy 10101683

Cathal Power 11413242

Joe Geraghty 10403221

Class and Year: 4th

Year Energy Systems Eng. (Mech)

Subject Code and Name: (eg ME117 CADD) GE400 Advanced Energy Systems

Lecturer Name: Dr. Rory Monaghan

Title of Assignment: Major Project: Leitir Gungaid Wind Farm

Submission Deadline 19th

November 2014

Submission Date:

Deduction imposed by Staff for late submission See Blackboard

Academic Integrity and Plagiarism

Plagiarism is the act of copying, including or directly quoting from, the work of another without

adequate acknowledgement. All work submitted by students for assessment purposes is

accepted on the understanding that it is their own work and written in their own words except

where explicitly referenced using the correct format. For example, you must NOT copy

information, ideas, portions of text, figures, designs, CAD drawings, computer programs, etc. from anywhere without giving a reference to the source. Sources include the internet, other students’ work, books, journal articles, etc.

You must ensure that you have read the University Regulations relating to plagiarism, which

can be found on the NUIG website: http://www.nuigalway.ie/engineering/plagiarism/

I have read and understood the University Code of Practice on plagiarism and

confirm that the content of this document is my own work and has not been

plagiarised.

Student’s signature Justin Conboy

Cathal Power

Joe Geraghty

Table of Contents

1. INTRODUCTION: 3

2. PROJECT OBJECTIVES: 3

3. BLADE DESIGN: 4

4. SIMULINK BLADE SIMULATION: 7

5. TURBINE LIMITING FACTORS: 13

6. COMPLETE TURBINE OVERVIEW: 14

7. CARBON OFFSET: 17

8. LEVELISED COST OF ELECTRICTY: 18

9. RESULTS: 20

10. CONCLUSION 24

11. ACKNOWLEDGMENTS 24

12. REFERENCES 24

1. Introduction: Leitir Gungaid Wind Farm is an array of wind turbines in Barna, Galway. The wind farm consists of 17

simular turbines but there are 3 different turbine power output-ratings between the 17. There are seven 3

Megawatt (MW) turbines, six 2.3 MW turbines and four 2 MW turbines on location at Leitir Gungaid Wind

Farm (Barna Wind Farm).

The farm was comissioned in March of 2014 and is Irelands newest wind farm. It is already fully

operational, but had caused quite a lot of contraversy with neigbours over the planning process. The main

concerns for residents were, noise, light flicker, and obstruction of cenery.

2. Project Objectives: Our obective is to model the 17 wind turbines in Barna Galway, to model the power output of each

tubine blade and, in-turn, each of the 3 types of individual turbine.

Also, to show the construction cost of the wind turbines and, using real time data and current

energy prices, to calculate the income produced by the turbines. We will show, for wind turbines in large

scale electricty production, the spacing between turbines.

Our project involves carrying out a “Matlab-Simulink” evaluation of the wind turbines at Barna,

Galway. The evaluation will take wind data from the previous year to present date in minutes. This data will

be applied to a Matlab replica model of the turbines. The blade profile of each of turbine is identical, but

each turbine will have a different make up, different torsional rating and different tip speed ratio. The

Matlab simulation will calculate the electricity produced by the wind turbine array using only the blade

configuration from the NACA database. This will give the value of energy produced in Euros at the current

market price. A cost benefit analysis will be produced as part of the project to validate the cost of the

turbine array and its impact on the area.

A “Levelised Cost of Electricity” (LCoE) will be carried out also, so as to show the actual payback

time of the wind farm

3. Turbines:

Enercon GmbH are based in Aurich in Germany. They

are one of the largest wind turbine manufacturer in the

world. Enercon has production facilities in Germany,

Brazil, India, Canada, Turkey, Sweeden and Portugal. In

recent years Enercon have set up their Irish

headquarters in Tralee, Co. Kerry, Ireland

The Turbines being uses at Barna are the

Enercon

Four: E-82 E2/2,000 kW

Six: E-82 E2/2,300 kW

Seven: E-82 E3/3,000 kW.

The Turbines are quite similar but have different sized

shafts and materials to transfer the different powers to

the generator.

Fig.1 Cross sectional drawing of nacelle E-82 E3.[1]

Fig.2 The Enercon E-82 E3/3000 kW turbine.[2]

Rated power: 3,000 kW

Rotor diameter: 82 m

Hub height: 78 m / 85 m / 98 m / 108 m / 138 m

Wind class (IEC): IEC/NVN IA und IEC/NVN IIA

Turbine concept: Gearless, variable speed, single blade adjustment

Rotor:

Type: Upwind rotor with active pitch control

Rotational direction: Clockwise

No. of blades: 3

Swept area: 5,281 m²

Blade material: GRP (epoxy resin); integrated lightning protection

Rotational speed: variable, 6 - 18.5 rpm

Pitch control: ENERCON single blade pitch system, one independent pitch system per rotor blade with allocated emergency supply

Drive train with generator

Main bearing: Double-row tapered / cylindrical roller bearings

Generator: ENERCON direct-drive annular generator

Grid feeding: ENERCON inverter

Brake systems: 3 independent pitch control systems with emergency power supply, rotor brake, rotor lock

Yaw control: Active via adjustment gears, load-dependent damping

Cut-out wind speed: 28 - 34 m/s (with ENERCON storm control)

Remote monitoring: ENERCON SCADA

Fig. 3 Data Table for the E82-E3

3.1 Blade Design:

The blade we are simulating is a NACA 4412 blade. The blade twists along the axes of the blade length. The

twist is there to counter act the increase forces along the blade length as the radius of the blade increases

away from the main shaft of the turbine.

Fig. 4 NACA 4412, Drawn on Inventor Pro

The blade twist is designed to create and even force all the way along the blade so at to keep reduce

bending moments as the radius increases along the blade length.

Fig. 5 NACA 4412 with a 22.7 degree blade profile turning: Drawn with Inventor Pro.

Fig. 6 NACA 4412 Coefficient of Drag and Lift profile averages, compiled from NACA data online.

The NACA 4412 has a maximum coefficient of Lift of 1.6 at the 16 degree point. This is our relative wind

angle for maximum power at the shaft end of the blade. As the radius increases we will rotate the degrees

of the blade so that the force acting on the blade will decrease.

This decrease in lift force will be proportional to the radius of the blade. This will cause torque, ie. Lift force

multiplied by the radius, to be even all along the blade points. After adjusting the blade angle along the

blade for optimisation, we should have a steady force acting on the blade for the entire length.

4. Simulink Blade Simulation: We have modelled the blade in 9 force sections with the 10 section being the shaft connector with no

force.

As can be seen from the representative model, the blade has been broken up into 9 sections. Each section

has a specific Pitch Angle. This is, again to evenly distribute the torque along the blade. We are only

modelling for 9 sections because this should be very sufficient to get a good overall view of the forces along

the blade.

The torques is all added up along the length of the blade and the sum is multiplied by 3. This is done simply

because there are 3 blades on each of the turbines.

The torque is then added and multiplied by the tip speed ratio to give the overall Power Output of the

turbine.

The resultant display at the far right of the model displays the total power output by the turbine.

Fig. 7 A Simulink model of the 3MW blade section run at full power. Not the 9 sections of the blade

Power Formula (Betz Power)

P = Nominal Power (W)

ρ = Density of Air (kg/m3)

A = Swept Area (m2)

V = Air Velocity(m/s)

BETZ POWER

V2/V1 0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

V1 9 9 9 9 9 9 9 9 9 9 9

V2 0 0.9 1.8 2.7 3.6 4.5 5.4 6.3 7.2 8.1 9

P/Po 0.5 0.5445 0.576 0.5915 0.588 0.5625 0.512 0.4335 0.324 0.1805 0

Graph 1. Power In/Power Output Optimisation.

Fig.8 Working of the calculations of the blade, the blades of the 2MW and 3MW turbine were calculated using the same process

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0 0.2 0.4 0.6 0.8 1 1.2

P/Po

P/Po

In order to calculate the power generated by the turbine we had to calculate the power generated

by each individual blade first. To do so we inputted the wind data given from the IRUSE, we then

implemented Betz Limit which says that the maximum power that can be extracted from the wind is 16/27

(0.593). This law was derived from the principal of conservation of mass and momentum of air flowing

through an actuator disk by Albert Betz in 1919. Figure 5 shows just how complex the calculation of the

power generated is factoring in all components of the blade.

Fig. 6 Displays the trigonometric function used in calculating the lift force

The trigonometric function shown above is a key component in calculating the lift force

experienced by the blade for an optimum relative wind angle. This function is child to its parent function

shown in fig. 5 which calculates the total power generated by the blade.

Fig 2. Derivation of Thrust and Torque Equations: Drawn on MS Paint by Justin Conboy

The lift and drag forces produced by the aerofoil do not act in the direction of the x-axis or the y-axis, these

forces must be decomposed into the components in the x and y direction. Once these components have

been found then the torque and axial thrust can be calculated provided the coefficients of lift and drag,

along with the platform area, are known. The green components of lift and drag are combined to provide

the torque and the red components are combined to provide the axial thrust.

Where is Torque , is Platform area (chord*section length), is Coefficient of lift, is

Coefficient of drag, is Angle of relative wind

Following from these equations one can see that the thrust force greatly increases as decreases. This is

the main reason for stipulating a low coefficient of lift for the tip profile as to attempt to decrease the axial

thrust.

4.1 Blade performance The formulas used for these calculations are as follows:

= Lift/Drag force (N)

= air density (kg/m3)

= wind velocity (m/s)

= section coefficient of lift/drag

Figure X: Lift Force blade points E83-3MW-9

Graph X shows the lift at point E83-3MW-9. This is the 9th calculated point of the blade and is at the tip end

of one of the 3MW turbine blades. It is located 41 meters towards the tip and the blade, has an angel of 7.3

degrees with a Relative wind angle of 1.397 degrees. The part can be seen as display 9 in the blade

summation block, below.

Figure X: Blade Summation Block

5. Turbine Limiting Factors:

Figure 7: 3 MW limiting factor used to calculate turbine cut speeds and cut out speeds.

A limiting factor is what determines the cut in speeds and cut out speeds for a wind turbine. The

cut out speeds also known as the survival speeds of commercial wind turbines varies on the size of the

turbines. As the power in the wind increases as the cube of the wind speed, wind turbines must be built to

withstand much higher loads such as gale force winds. There is certain ways of reducing the torque in high

winds in order to protect the wind turbine. If the rated wind speed is exceeded the power generated has to

be limited. This can be done by implementing a control system that consists of, sensors to process

variables, actuators to manipulate energy capture and component loading and control algorithms to

coordinate the actuators based on the information gathered by the sensors. Also, the cut in speeds will vary

depending on the size of the wind turbines. Although the cut in wind speeds pose no threat to integrity of

the turbine itself it is important to have such a speed because you would be generating such small and

inconsistent amounts of power is would be wasteful with respect to wear & tear of the machine.

At Barna the cut in/out speeds for each differently sized turbine is different, for the 2MW wind

turbine no power is generated if the wind speed is below 1.2 m/s and power generation is limited if the

wind speed rises above 13 m/s. For the 2.3MW wind turbine no power is generated if the wind speed is

below 1.2 m/s and power generation is limited if the wind speed rises above 14 m/s. And lastly for the

3MW wind turbine no power is generated if the wind speed is below 1.2 m/s and power generation is

limited if the wind speed rises above 17 m/s. Therefore for each wind turbine a factor of safety has been

applied to the limiting speed in order to protect them and avoid accidents. There is an overall shut down

speed of 31 m/s applied to all the turbines. This is the maximum safety seed allowed. The blades turn to a

pitch angle of 0 lift and a break is applied.

An example can be seen in the graph below. The input speed into the 3MW turbine varies from 0 to

36 m/s in a two cycle example. What we should expect is that the turbine produces 0 lift from the 0 to 1.2

m/s cycle and gradually increase with power until it hits 17 m/s. At this point it the saturation should kick in

and the blade should only produce 17 m/s worth of lift even going from 17 m/s to 31 m/s. At the 31 m/s

stage the blade’s should produce 0 force as the wind turbine is now in shut down mode.

Figure X: Wind speed on top ranging from 0 to 36m/s over two cycles. Usable wind on graph below.

6. Complete Turbine Overview: The representation below shows the process used in order to calculate the total turnover

generated by the turbines, it also shows the total power generated by the turbines along with the payback

period. Wind data from the area was read in from an excel file where a correctional gain optimises the data

to sync with the area, given the limiting factors for each turbine along with the blade geometry we could

sum the crucial information needed to estimate turnover given today’s energy prices, power and payback

period.

Fig.8 Displays the absolute power generated if the turbines operated at 100% capacity.

Fig.9 Displays each individual Turbine configuration.

The above representation displays how the blades for each turbine are configured, initially the

limiting factors for each turbine are set, these show how the turbines act above and below certain wind

speed. From there each of the turbines blade geometry calculates the power generated by each individual

model, this information is passed on to a multiplier where the total power generated by all of the turbines

is calculated and added allowing us to determine the turnover and payback period.

Fig. 10 Displays how energy prices, energy conversion and project costs are implemented to output the final results.

Fig. 11: Displays how the cost of the infrastructure was calculated.

Research on Barna showed that the infrastructure costs for each turbine was approximately

€100000 each, this infrastructure included foundations, cables and land costs. Using a simple multiplier of

17 the total number of turbines it allowed us to calculate total infrastructure cost, added to that the total

cost of the wind turbines was €40,000,000. We also established that the maintenance costs per turbine was

1.75% over a period of 11 years that calculated the total maintenance costs.

7. Carbon Offset: To calculate the complete carbon offset by the use of these turbines at Barna, it first needs to be

established the total power generated by the turbines over their entire lifespan. Each turbine is said to

have a lifespan of 20 – 25 years. At Barna it is said that each turbine should last a maximum of 25 years. To

calculate the carbon offset the following equation has been established:

(Annual Power Generated at Barna) x (Lifespan of the Turbines)x(C02 Emissions per fuel type)

= (kWh/y) x (No. of years) x ( gC02/kWh)

= gC02 offset by wind compared with different fuel types

Therefore the resultant of the above equation represents the amount of grams of C02 offset by the

production of clean electricity over the lifespan of all the wind turbines at Barna combined, (coloured in

yellow in the table below). In order to keep the numbers manageable it was converted back to tonnes of

C02 offset by the production of clean electricity over the lifespan of all the wind turbines at Barna

combined, (coloured in orange). The next task was to convert it back to the annual tonnes of C02 offset by

the 17 different turbines at Barna (coloured in green) as was specified at the beginning of the project.

Lastly it was required to show the C02 emissions offset per kWh (coloured in pink). To verify the results

shown below the average amount of C02 offset per turbine per year was estimated per fuel type and

compared with information from the Irish Wind Energy Association (coloured in purple).

Table. 1 Displays the Carbon offset at Barna from clean power generation when compared with

hydrocarbon forms of power generation.

To fully grasp the scale of the power generated at Barna, take a single 2.3MW wind turbine that will

produce approximately 5500MWh/y and a typical ‘A rated’ fridge freezer that consumes 408 kWh/y. That

single turbine could power (5,500,000/408 = 13479) fridges. Barna produces 112484312 kWh/y that would

amount to (112484312/408 = 275,697) fridge freezers for a year.

Fuel Emissions per fuel type (gC02/kWh)

Power at Barna (kWh/y)

Lifespan Overall Carbon Offset (gC02)

Natural Gas 360 112484312 25 1.01236E+12

Fuel Oil 754 112484312 25 2.12033E+12

Coal 811 112484312 25 2.28062E+12

Peat 1119 112484312 25 3.14675E+12

Overall Carbon Offset (tonnes)

Annual Offset (tonnes)

Emissions offset (tonnes C02/

kWh)

Average offset per turbine per annum

1012358.808 50617.9404 0.001095727 2977.525906

2120329.281 106016.4641 0.002294938 6236.262591

2280619.426 114030.9713 0.002468429 6707.704193

3146748.628 157337.4314 0.003405884 9255.143024

8. Levelised Cost of Electricity:

From the data obtained for system output a value for Levelised Cost of Electricity was calculated. A number

of parameters were entered which conform to calculated results and industry norms. The plants operating

life is twenty five years while a conservative estimate of 1.75% for maintenance is included in the

calculations. Initially a 1.75% rate did not seem to be that large but over the lifetime of the project this

amounts to €18,243,750 over the lifetime of the project.

The wind farms expected performance was also taken into account over its lifetime. This is known as the

degradation factor and reduces power output over the time period. Onshore wind farms performance can

be reduced by up to 16% over a twenty year period so an estimate of 1.5% per year was established.

Including this factor in calculations can increase the LCOE value by up to 9%. (ref1)

Two approaches were taken with regard to LCOE calculation. The first was assuming the investment costs

were paid up front and that finance was not needed for the project. The second was that a loan was

established to pay 90% of the total costs with the other 10% provided up front by the developer.

The second scenario is a much more realistic one as generally when a project is conceived, the developer

tries to find sources of investment to fund the project. This can entail approaching private investors or

entering in to a loan with a bank or other credit institution.

Loan repayments were spread out over the first ten years of the project with an interest rate of 3.0% which

is typical for a project of this proportion. These repayments were tabulated in excel along with

maintenance and other costs to produce a cumulative net cash flow chart.

Figure : shows revenue derived from electricity sold at the LCOE calculated of €.036 cents/Kwh. Capital

costs are also shown with construction in the first two years and production beginning in year 3.

Decommissioning costs of 5% were also included at the end of the 25 year life of the project.

-€23,000,000.00

-€18,000,000.00

-€13,000,000.00

-€8,000,000.00

-€3,000,000.00

€2,000,000.00

€7,000,000.00

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27

Re

ven

ue

/Exp

en

dit

ure

Revenue

Capital Cost

Expenditure

Figure : shows revenue derived from LCOE and loan repayments over a ten year period as opposed to full

capital outlay up front. Decommissioning costs are also shown again at a rate of 10% of initial investment.

From the figures analysed in the excel spreadsheet a value of .0399 cents was calculated which is derived

from scenario 2. This involves totalling all debt servicing and maintenance costs and taking values for

electricity produced with a degradation factor of 1.5% per year included. It should also be noted that this

accounts for an annual electricity escalation rate of 1.5% which again is in line with historic figures.

Figure : shows revenue received for selling electricity at the current rate of 9 cents per Kwh, with yearly

escalation of 1.5% included in calculations.

-€10,000,000.00

-€8,000,000.00

-€6,000,000.00

-€4,000,000.00

-€2,000,000.00

€0.00

€2,000,000.00

€4,000,000.00

€6,000,000.00

1 3 5 7 9 11 13 15 17 19 21 23 25

Re

ven

ue

/exp

en

dit

ure

Expenditure

Revenue

-€10,000,000.00

-€5,000,000.00

€0.00

€5,000,000.00

€10,000,000.00

€15,000,000.00

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26

Re

ven

ue

/Exp

en

dit

ure

Revenue

Expenditure

Decommissioning cost

Figure : shows net cumulative cash flow over the lifetime of the project. The cash flow is negative in the

opening years due to down payment costs. A noticeable decrease is observed after year 25 due to

decommissioning costs.

9. Area and Noise

This is a key factor in ensuring their safety, the space between each wind turbine is between 6 – 10 time

the rotor diameter depending on topography

10. Results:

Table 2 Displays, Accumulated Sales at €0.09 per kWh. Power Out (MW) and Wind Speeds (m/s).

-€10,000,000.00

-€5,000,000.00

€0.00

€5,000,000.00

€10,000,000.00

€15,000,000.00

€20,000,000.00

€25,000,000.00

1 3 5 7 9 11 13 15 17 19 21 23 25

Culumative Cash Flow

Wind Correction EXPLINATION

The wind data was split into 525104 minutes of wind speed information which was obtained from IRUSE[5].

The data was wind speed velocities from the start of October 2013 to the start of October 2014.

The reason why we added a correctional gain was to bring the wind speed from the data at hand up to the

wind speeds at the 70m elevated site at Barna.

The wind speed data was taken from weather station at NUI Galway which is located on the roof of The

Concourse. There are a huge amount of trees and buildings which reduce the wind speed before it gets to

the weather station.

During our research, we found that turbines in Galway are running at approximately 30% of maximum

capacity. With our wind data we found that we were hitting 32% less than the “30% of Maximum”.

We decided, for our project, to compensate for the 32% loss by adding a gain of 49.5%. This brought the

wind speed up to the “30% of Maximum”.

We tried to get wind data for the area, but this was considered a commercial secret. If wind speeds were

available for the exact area, we would simply set the correctional gain to 1.

Fig. 12 Displays the wind correctional gain multiplier.

0 1 2 3 4 5

Revenues

Power output (k/w/hr.) 1.29E+08 1.29E+08 1.29E+08 1.29E+08 1.29E+08

Avoided cost of electricity 0.0918 0.093636 0.09550872 0.097418894 0.099367272

Total Revenue €11,842,200.00 €12,079,044.00 €12,320,624.88 €12,567,037.38 €12,818,378.13

Expenditure

Initial Capital Expenditure €4,170,000.00

Amount financed €37,530,000.00

Total debt payment €4,556,028.00 €4,556,028.00 €4,556,028.00 €4,556,028.00 €4,556,028.00

Total maintenance costs €625,500.00 €625,500.00 €625,500.00 €625,500.00 €625,500.00

Total expenses €5,181,528.00 €5,181,528.00 €5,181,528.00 €5,181,528.00 €5,181,528.00

Net cash flow -€4,170,000.00 €6,660,672.00 €6,897,516.00 €7,139,096.88 €7,385,509.38 €7,636,850.13

Cumulative net cash flow -€4,170,000.00 €2,490,672.00 €13,558,188.00 €14,036,612.88 €14,524,606.26 €15,022,359.50

6 7 8 9 10

Revenues

Power output (k/w/hr) 1.29E+08 1.29E+08 1.29E+08 1.29E+08 1.29E+08

Avoided cost of electricity 0.101354618 0.10338171 0.105449344 0.107558331 0.109709498

Total Revenue €13,074,745.69 €13,336,240.60 €13,602,965.41 €13,875,024.72 €14,152,525.22

Expenditure

Initial Capital Expenditure

Amount financed

Total debt payment €4,556,028.00 €4,556,028.00 €4,556,028.00 €4,556,028.00 €4,556,028.00

Total maintenance costs €625,500.00 €625,500.00 €625,500.00 €625,500.00 €625,500.00

Total expenses €5,181,528.00 €5,181,528.00 €5,181,528.00 €5,181,528.00 €5,181,528.00

Net cash flow €7,893,217.69 €8,154,712.60 €8,421,437.41 €8,693,496.72 €8,970,997.22

Cumulative net cash flow €15,530,067.81 €16,047,930.29 €16,576,150.01 €17,114,934.14 €17,664,493.94

10. Conclusion The overall

11. Acknowledgments We would like to thank Dr. Magdalena Hajdukiewicz for acquiring the 1 year worth of wind data

information from IRUSE.

12. References 1. Wind turbine spacing - http://en.wikipedia.org/wiki/Wind_turbine

2. Carbon Offset - http://www.iwea.com/iweafactsvideo - reference point 4) & 10)

3. Carbon Comparission - http://www.carbonfootprint.com/energyconsumption.html

4. Pollutant Emissions – Dr Rory Monaghan College of engineering and informatics -

https://nuigalway.blackboard.com

5. http://www.iruse.ie/