m04a re island-group2_report_200813

MBA RenewablesModule 04a, Advanced Practical RE & EE Implementation

Written Assignment Group 2

Renewable Energy Island

By

Sakthi GaneshRiikka Lauhkonen-Seitz

Mario MarasMattias SääksjärviAdriana Stefanac

20 August 2013

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Table of Contents

1. Introduction..................................................................................................................................... 2

2. Photovoltaic..................................................................................................................................... 2

2.1. Task 5.1 Installed PV capacities required to meet part of the island’s electricity demand ......... 2

2.2. Task 5.2 PV system design and LCOE ........................................................................................... 4

3. Wind ................................................................................................................................................ 7

3.1. Task 6.1 Installed wind capacities required to meet part of the island’s electricity demand ..... 7

3.2. Task 6.2 Wind system design and LCOE ..................................................................................... 11

4. Biogas ............................................................................................................................................ 12

4.1. Task 7.1 Installed biogas capacity required to meet 100% of the island’s electricity demand . 12

4.2. Task 7.2. Biogas system design and LCOE .................................................................................. 14

5. Hybrid System ............................................................................................................................... 16

6. Demand Side Management........................................................................................................... 18

7. Island hot water demand .............................................................................................................. 18

7.1. Task 10.1 Solar thermal system design and LCOE...................................................................... 18

7.2. Task 10.2 Effect on the Hybrid System of deducting the electricity requirement for hotel andhousehold hot water production from the electricity load profile................................................... 21

7.3. Task 10.3 Use of heat from the biogas plant.............................................................................. 24

Sources .................................................................................................................................................. 24

List of Figures......................................................................................................................................... 25

List of Tables.......................................................................................................................................... 25

List of Attachments ............................................................................................................................... 25

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1. Introduction

The objective of this report is to provide a site-specific technical concept of sustainable energy supply

for an island that is not connected to the grid. The concept consist of several renewable energy

technologies which combined meet the present electric energy consumption.

The technologies analysed in the report are photovoltaic (PV), wind, biogas and solar thermal. Based

on the available natural resources on the island combined with given economic parameters, different

combinations of renewable energy technologies (“Hybrid System”) are assessed and subsequently an

optimum combination chosen.

2. Photovoltaic

2.1. Task 5.1 Installed PV capacities required to meet part of the island’s electricitydemand

Subtask 5.1 a)

Based on the daytime demand for the whole year, a PV system of 3.746 kWp would be required to

satisfy the average demand for the year (cf. attached Excel file Updated-Island-PV-Design.xls, sheet

“Yield Calculations”). The useful energy generated by the above system would be able to meet 84%

of the total demand. Here the useful energy is considered the amount of energy that can be used at

any given hour. Anything above the demand for that hour is considered useless as storage is not

considered for this plant design.

It can be seen that as we move from lower to higher capacities, the output energy increases rapidly

at first but later at higher capacities it tends to flatten out, i.e. the difference in output may not be

justifiable in terms of investment required for a bigger plant. The various PV capacities and their

corresponding output percentages with respect to demand are shown in Figure 1 below as well as in

the graph “PV Capacity Vs Demand” in the Excel file Updated-Island-PV-Design.xls (sheet “Graphs”).

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Figure 1. Various PV capacities and their corresponding output percentages with respect to demand.

As mentioned above, with an installed capacity of 3.746 kWp, a maximum 84% of the total day time

electricity demand can be met.

Subtask 5.1 b)

It can be seen from the excel sheet calculations that even though the plant discussed above with a

capacity of 3.746 kWp is falling short of nearly 16% of the total day time demand, it is also producing

around 19% excess energy which is being wasted. From this aspect it may not be economical to go

with this capacity as there is a significant excess energy generation.

Multiple graphs depicting the total generation, useful generation, excess generation and shortfall

compared to demand for various capacities are shown in the Excel file Updated-Island-PV-Design.xls

(sheet “Graphs”).

A PV plat with a capacity of 1.800 kWp will generate electricity that would not exceed the daytime

demand at any given hour of the year. This is the capacity at which there will be zero wastage. This

plant will meet 50% of the total demand.

Subtask 5.1 c)

The PV plat with a capacity of 2.817 kWp is considered to be the optimum as,

1. it would meet around 74% of the annual demand;

2. it generates minimum excess energy (4%) that would be wasted;

3. plants with a higher capacity than this one do not make economic sense when compared to

the increase in electricity output. Lower capacity plants will produce significantly less output

energy.

Usefulgeneration

at 3746kWp

Usefulgeneration

at 3500kWp

Usefulgeneration

at 3150kWp

Usefulgeneration

at 2817kWp

Usefulgeneration

at 2500kWp

Usefulgeneration

at 2200kWp

Usefulgeneration

at 2000kWp

Usefulgeneration

at 1900kWp

Usefulgeneration

at 1800kWp

Datenreihen1 84,38% 82,13% 78,36% 73,74% 67,73% 60,54% 55,18% 52,43% 49,68%

0,00%

10,00%

20,00%

30,00%

40,00%

50,00%

60,00%

70,00%

80,00%

90,00%

Dem

and

PV Capacity Vs Demand

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The plant with a capacity of 2.817 kWp will be able to meet around 23% of the total electricity

demand of the island. Since PV plants produce zero electricity during the night, the contribution

seems to be low when the total demand instead of only the day time demand is considered.

2.2. Task 5.2 PV system design and LCOE

Subtask 5.2 a)

The calculated maximum number of poly-crystalline PV modules as well as Cadmium-Telluride thin-

film modules and the nominal power of both systems is to be found in the attached sheet ”5.2” (5.2

a)) of the Excel spreadsheet named 09_08_2013_Task 5.2_MM_rev AS_13 08 2013_v7.xls.

To calculate the maximum number of modules that can be mounted on the available roof area and

the nominal power of each system we use roof dimensions (200 x 200m), tilt angle of the modules

(32º), solar height (30º as derived from ”Figure 3: Sun path diagram for Tunis” in the Assignment

guidelines) as well as modules' nominal power (240 Wp for poly-crystalline PV and 87,5 Wp for CdTe

thin-film module) and modules' dimensions (length and width).

The modules will be mounted in landscape position to avoid potential shading losses. Therefore, by

dividing the width of the roof (200m) with the length of the modules (1,685 m for poly-crystalline PV

and 0,6 m for CdTe thin-film), the result is the number of modules that can be installed in one row

(118 poly-crystalline PV and 166 CdTe thin-film modules).

To calculate the number of module rows that can be installed on the roof area, the necessary

minimum distance between module rows has to be taken in to consideration. The following formula

is applied: D = L x (sinβ/tanα + cosβ)

where

D is the minimum distance between module rows,

L is the length of the modules (wiith the modules being mounted horizontally, the figure

used is the width of the modules),

β is the tilt angle of the modules and

α is the solar height.

By dividing the roof length (200 m) with the calculated minimum distance between module rows

(1,7535 m for poly-crystalline PV and 1,0595 m for CdTe thin-film modules), the number of module

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rows that can be installed on the available roof area is obtained (114 for poly-crystalline PV and 188

for CdTe thin-film modules). By multiplying the number of modules that can be installed in one row

with the number of module rows, the total number of modules that can be installed on the roof area

is obtained (13.452 poly-crystalline PV and 31.208 CdTe thin-film modules).

The nominal power of each system is then calculated by multiplying the total number of modules

with the nominal power of each module (240 Wp for poly-crystalline PV and 87,5 Wp for CdTe thin-

film modules). The result is a 3.228 kW poly-crystalline PV and 2.731 kW CdTe thin-film module

system.

Subtask 5.2 b)

The calculations in relation to how much electricity can be produced by the two alternative systems

(both total generation and useful generation) are to be found in the sheet ”Total Gen_Useful Gen” of

the Excel spreadsheet named 09_08_2013_Task 5.2_MM_rev AS_14 08 2013_v8.xls. The results are

as well shown in the sheet ”5.2” (5.2 b)) of the same spreadsheet.

By applying the Performance Ratio (PR) concept, that is by multiplying the PR, peak sun hours and

the nominal power of each of the two systems for each hour and by summing up the hourly values,

the total daytime electricity generation of each system for the entire year is obtained (4.231.427

kWh/a for the 3.228 kW poly-crystalline PV module system and 3.939.311 kWh/a for the 2.731 kW

CdTe thin-film module system).

By comparing total generation with the island's demand for each hour (taking into account that the

electricity that cannot be used in the hour when it is needed is wasted), the result is the useful

daytime electricity generation for the entire year (3.952.707 kWh/a for the 3.228 kW poly-crystalline

PV module system and 3.795.257 kWh/a for the 2.731 kW CdTe thin-film module system).

Subtask 5.2 c)

The PR is defined as = ∗ ∗ . It is affected by the cell temperature, hence thin-film

modules with their lower temperature coefficients perform better. Shading also affects the PR and

thin-film modules give a better output for the same shading area than poly-crystalline modules do.

Subtask 5.2 d)

The LCOE calculations for both systems and for both total and useful generation are to be found in

the sheet ”5.2” (5.2 d)) of the attached Excel file 09_08_2013_Task 5.2_MM_rev AS_14 08 2013_v8.

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It is in the interest of the island's inhabitants to install power plants that will generate electricity

when it is actually used. The calculations in task 5.1 show that useful generation growth rates

actually become smaller when increasing installed capacity, meaning that even though total

electricity generated by the system increases with increased installed capacity, not all of this

additional electricity is actually used and is therefore wasted. Due to this it is concluded that the

more reasonable basis for assessing different investments by comparing their LCOEs is the system's

useful generation. It should provide for a more realistic picture of the system's costs in relation to its

actual performance, i.e. the island's actual electricity needs.

In addition to the parameters given in the Assignment, the LCOE calculations are based on following

additional parameters and assumptions:

Given the sharp drop in PV module prices lately, the most recent module and inverter prices

available in Altevogt J 2013 (slide 59-60) were used to build the cost structure. In this

Assignment it is assumed that the island is not member of the EU and will want to decrease

their investment costs where possible, which is why the April 2013 price of crystalline

modules produced in China, 0,55 €/Wp, was chosen. The April 2013 price for thin-film

modules is as well 0,55 €/Wp and for three-phase string inverters 175 €/kW.

Additionally, the cost structure was built by using the cost breakdown by element given in a

recent publication by Goodrich A et al 2012 (p. 12). This cost breakdown shows that module

costs make for 45% of total investment costs, inverter costs for 8% and installation materials

for 14%.

By dividing the module price with its share in total PV system costs, system costs for both the

poly-crystalline and thin-film module system is 1,22 €/Wp. When multiplying system costs

with the nominal power of each system, the result are total investment costs. Hardware

costs are assumed to be 67% of total investment costs according to the cost breakdown

referenced above (i.e. 45% module costs plus 8% inverter costs plus 14% installation

materials).

Total inverter replacement costs are calculated by multiplying the inverter price per Wp with

the nominal power of each system. These costs are included in the cost structure based on

the inverter lifetime of 8 years and discounted separately from O&M costs to their present

value in the years 9, 17 and 25 when they are expected to occur.

The results are as follows:

LCOE Poly-crystalline PV total generation 0,1172 €/kWh,

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LCOE CdTe thin-film total generation 0,1064 €/kWh,

LCOE Poly-crystalline PV useful generation 0,1254 €/kWh and

LCOE CdTe thin-film useful generation 0,1105 €/kWh.

Subtask 5.2 e)

The same approach is used when calculating the LCOE with decreased turnkey system prices. The

calculations are to be found in the sheet ”5.2” (5.2e)) of the attached Excel spreadsheet

09_08_2013_Task 5.2_MM_rev AS_14 08 2013_v8.

The results are as follows:

LCOE Poly-crystalline PV total generation 0,0981 €/kWh,

LCOE CdTe thin-film total generation 0,0736 €/kWh,

LCOE Poly-crystalline PV useful generation 0,1156 €/kWh and

LCOE CdTe thin-film useful generation 0,0764 €/kWh.

3. Wind

3.1. Task 6.1 Installed wind capacities required to meet part of the island’s electricitydemand

Subtask 6.1 a)

The extrapolated wind speed data from the measured 50 m to the hub height of the wind turbines is

to be found in the sheet ”Input Wind speed” of the Excel spreadsheet named 2013

WIND_v6_130813_Adriana.xls enclosed to this report. For each of the given hub heights of the wind

turbines (45 m, 58 m and 70 m respectively) a separate column was added and the respective wind

speed calculated for each hour of the year by using the logarithmic law.

Example wind speed in m/s at 45 m hub height during 1st hour of the year:

2 = ln ℎ20 / ln ℎ10 × 1

h1 = 50 m, h2 = 45 m

v1 = 8,6750 m/s, z0 = 0,03

v2 = 8,5518 m/s

Subtask 6.1 b)

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By sorting all the data available after extrapolating wind speed data in the sheet ”Input Wind speed”

largest to smallest it can be seen that maximum wind speed is achieved at 70 m hub height during

hour 2701 of the year (on 22 April) and it amounts to v70 = 27,7172 m/s.

During this hour the wind speed at 50 m hub height is v50 = 26,5146 m/s;

the wind speed at 45 m hub height is v45 = 26,1381 m/s;

the wind speed at 58 m hub height is v58 = 27,0451 m/s.

By sorting all the data available after extrapolating wind speed data in the sheet ”Input Wind speed”

smallest to largest it can be seen that minimum wind speed is achieved at 45 m hub height during

hour 3967 of the year (on 14 June) and it amounts to v45 = 1,7210 m/s.

During this hour the wind speed at 50 m hub height is v50 = 1,7458 m/s;

the wind speed at 58 m hub height is v58 = 1,7807 m/s;

the wind speed at 70 m hub height is v70 = 1,8250 m/s.

According to the power curve of the GENERIC wind turbine G-830, rated power of 830 kW is achieved

at 14,00 m/s wind speed.

By filtering the data calculated at 45 m hub height (sheet ”Input Wind speed”, column D)

accordingly, it can be seen that the total number of hours with wind speeds greater than

rated power wind speed of the G-830 is 686.

Total number of hours with wind speeds greater than rated power wind speed and less than

cut-off wind speed of the G-830 is 677.

The total number of hours with wind speeds greater than rated power wind speed at 70 m

hub height (filtered data column F) is 922, whereas the total number of hours greater than

rated power and less than cut-off wind speed of the G-830 is 902.

According to the power curve of the GENERIC wind turbine G-878, rated power of 878 kW is

achieved at 14,00 m/s wind speed.

By filtering the data calculated at 58 m hub height (sheet ”Input Wind speed”, column E)

accordingly, it can be seen that the total number of hours with wind speeds greater than

rated power wind speed of the G-878 is 815.

Total number of hours with wind speeds greater than rated power wind speed and less than

cut-off wind speed of the G-878 is 807.

The total number of hours with wind speeds greater than rated power wind speed at 70 m

hub height (filtered data column F) is 922, whereas the total number of hours greater than

rated power and less than cut-off wind speed of the G-878 is 911.

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According to the power curve, cut-in wind speed of the GENERIC wind turbine G-830 is 3,00 m/s at

45 m hub height.

By filtering the data available at the respective hub height (sheet ”Input Wind speed”,

column D) accordingly, it can be seen that the total number of hours with wind speed below

cut-in wind speed is 459.

At 70 m hub height the total number of hours with wind speed below cut-in wind speed

(filtered data column F) is 379.

According to the power curve, cut-in wind speed of the GENERIC wind turbine G-878 is 4,00 m/s at

58 m hub height.


column E) accordingly, it can be seen that the total number of hours with wind speed below

cut-in wind speed is 1009.

At 70 m hub height the total number of hours with wind speed below cut-in wind speed


According to the power curve, cut-off wind speed of the GENERIC wind turbine G-830 is 22,00 m/s at

45 m hub height.


column D) accordingly, it can be seen that the total number of hours with wind speed above

cut-off wind speed is 9.

At 70 m hub height the total number of hours with wind speed above cut-off wind speed


According to the power curve, cut-off wind speed of the GENERIC wind turbine G-878 is 23,00 m/s at

58 m hub height.


column E) accordingly, it can be seen that the total number of hours with wind speed above

cut-off wind speed is 8.

At 70 m hub height the total number of hours with wind speed above cut-off wind speed


Subtask 6.1 c)

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The graphs showing the increasing wind installed capacities required to meet increasing amounts of

the electricity demand are given in the sheet ”6.1 c) Graphs” of the Excel spreadsheet named 2013

WIND_v6_130813_Adriana.xls.

Since is it is not possible to store any of the generated electricity, useful and not total generation of

wind turbines is considered in order to identify the reasonable number of wind turbines to meet the

annual electricity demand. With each of the different wind turbine options this number is 4.

Namely as can be read from the graphs with 4 wind turbines it is possible to meet a significant

amount of the island's electricity demand, while the excess generation is still far below the useful

generation. Further increase of installed capacity does not provide for a significant enough increase

in useful generation and creates enormous amounts of excess generation. For example in case of the

G-830 at 45 m hub height, with 4 wind turbines it is possible to meet 60,13% of the island's annual

electricity demand; 8 wind turbines would be able to meet 70,83% of the demand. This means that

by doubling the installed capacity only 10% more of the demand would be met, which is not

reasonable. The same conclusion can be drawn from the graphs for each of the different wind

turbine options.

With such reasoning the maximum percentage of the electricity demand that can be met is 63,81%

with 4 G-830 kW wind turbines at 70 m hub height. The corresponding wind installed capacity is

therefore 3,32 MW.

In case of 4 G-830 kW at 45 m hub height, and therefore wind installed capacity of again 3,32 MW, it

is possible to meet 60,13% of the island's annual electricity demand.

With 4 G-878 kW at 58 m hub height, and therefore wind installed capacity of 3,512 MW, 48,58% of

the demand would be met, whereas with the same wind installed capacity at 70 m hub height,

50,32% of the demand would be met.

Subtask 6.1 d)

The graphs showing total generation, useful generation, excess generation and shortfall for

increasing wind instaled capacities of each of the four different wind turbine options are given in the

sheet ”6.1 d) Graphs” of the Excel spreadsheet 2013_WIND_v6_130813_Adriana.xls.

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The maximum percentage of the electricity demand that can be met with zero wastage is 24,55%

with 1 G-830 kW wind turbine at 70 m hub height. The corresponding wind installed capacity is 830

kW.

Subtask 6.1 e)

The optimum wind installed capacity would be 4 G-830 kW wind turbines at 70 m hub height. As

explained in subtask 6.1 c) it provides for a large percentage of the island's annual electricity

demand, and the useful generation is still much higher than the wastage. It also has the lowest LCOE

which will be shown in task 6.2.

3.2. Task 6.2 Wind system design and LCOE

It is in the interest of the island's inhabitants to install power plants that will generate electricity

when it is actually used. The sheet ”6.1 d) Graphs” in the attached Excel file show that useful

generation growth rates actually become smaller when increasing installed capacity, meaning that

even though total electricity generated by the system increases with increased installed capacity, not

all of this additional electricity is actually used and is therefore wasted. Due to this it can be

concluded that the more reasonable basis for assessing different wind turbine options by comparing

their LCOEs is the system's useful generation. It should provide for a more realistic picture of the

system's costs in relation to its actual performance, i.e. the island's actual electricity needs.

Subtask 6.2 a)

The calculated total and useful electricity generation data for the different turbine options are to be

found in the sheet “Input Wind speed” of the Excel spreadsheet named

2013_WIND_v6_130813_Adriana.xls. The data are summarised in Table 1 below.

Turbine type Total electricity generation/a Useful electricity generation/a4 x G-830kW turbines at 45 m hub height 13.167.759 kWh 8.779.668 kWh4 x G-830kW turbines at 70 m hub height 14.337.380 kWh 9.316.559 kWh4 x G-878kW turbines at 58 m hub height 10.387.987 kWh 7.093.147 kWh4 x G-878 kW turbines at 70 m hub height 10.906.838 kWh 7.346.660 kWhTable 1. Total and useful annual electricity generation with the 4 different turbine options.

Subtask 6.2 b)

An average turbine installed in Europe has a total investment cost of around 1,23 million € per MW

(Morthorst PE et al 2009, p. 4). The turbine's share of the total cost is (which accounts for by far the

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largest part of the installed hardware), on average, around 76%. The LCOE was calculated based on

these assumptions and the parameters given in the Assignment guidelines and is shown in the sheet

”LCOE” of the Excel spreadsheet named 2013 WIND_v6_130813_Adriana.xls. For both total and

useful generation, the LCOE is lowest for the 4 G-830 kW wind turbines at 70 m hub height, 0,0311

€/kWh and 0,0479 €/kWh respectively.

4. Biogas

4.1. Task 7.1 Installed biogas capacity required to meet 100% of the island’s electricitydemand

Subtask 7.1 a)

To guarantee that electricity demand is met any given hour of the year, required installed electric

capacity of CHP plants has to equal the peak load. Peak load on the island takes place at hour 5341

and amounts to 3.021 kW (cf. attached Excel file M04a_Biogas_Group2.xls, sheet “Load data &

7.1h)”). Required installed capacity of CHP plants would thus be 3.021 kW, however, this has to be

rounded up to 3.250 kW given the restricted availability of standard CHP units with peak electrical

output of 250 kWe and 500 kWe respectively. Required installed capacity of CHP plants therefore

equals 3.250 kW.

Subtask 7.1 b)

Considering that only standard CHP units with peak electrical output of 250 kWe and 500 kWe

respectively are available, the optimum combination to cover the entire electricity demand was

determined by calculating the overall electric and thermal efficiencies of all possible CHP

combinations that equal the required installed capacity of 3.250 kW, and subsequently choosing the

best option for this project. Based on the calculations (cf. Excel file M04a_Biogas_Group2.xls, sheet

“7.1”), highest overall electrical efficiency (36,57%) is reached with a combination of 1 unit of

CHP250 and 6 units of CHP500. Highest thermal efficiency (49,00%) on the other hand is obtained

with a combination of 13 units of CHP250 and 0 units of CHP500. As the emphasis of this system

design exercise is on meeting island's electrical energy demand, the combination with highest

electrical efficiency is chosen, i.e. 1 x CHP250 and 6 x CHP500.

Subtask 7.1 c)

As already calculated in subtask 7.1b), overall efficiencies of the chosen combination of 1 x CHP250

and 6 x CHP500 are: electric efficiency 36,57% and thermal efficiency 46,43%.

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Subtask 7.1 d)

With the given availability of substrates (manure and organic waste), annual biogas production is

784.380,95 m3 and annual electricity production 1.807.143,12 kWh (cf. calculations in Excel file

M04a_Biogas_Group2.xls, sheet “7.1”).

Subtask 7.1 e)

The annual electricity production calculated in subtask 7.1d) is not enough to meet the entire

electricity demand on the island; the shortfall is 12.792.866,28 kWh. In order to cover this gap,

digestion of corn silage is required to produce additional biogas. Based on the calculations (cf. Excel

file M04a_Biogas_Group2.xls, sheet “7.1”), additional biogas production required to meet the entire

electricity demand is 5.552.676,22 m3.

Subtask 7.1 f)

To produce the additional biogas required calculated above in subtask 7.1e), 40.885,76 tonnes of

corn silage will be required per year (cf. Excel file M04a_Biogas_Group2.xls, sheet “7.1”).

Subtask 7.1 g)

To produce the amount of corn silage calculated above in subtask 7.1f), a total of 908,57 ha of arable

land would have to be assigned for corn silage production (cf. Excel file M04a_Biogas_Group2.xls,

sheet “7.1”).

Subtask 7.1 h)

In addition to electricity, a combined heat & power biogas plant produces thermal energy that can be

used for the plant’s own consumption and/or sold to heat customers. Since biogas can be used to

produce energy according to demand, electricity production of a CHP biogas plant can be assumed to

equal the hourly electricity load. As show on the Excel file M04a_Biogas_Group2.xls, sheet “Load

data & 7.1h”, based on the hourly electricity production and on the thermal efficiency calculated in

subtask 7.1c) it is possible to calculate the amount of thermal co-generation, the amount of heat that

is consumed by the biogas plant itself (as given in the Assignment guidelines, the plant consumes

30% of the thermal heat for heating the digesters), and subsequently the amount of heat that is left

for selling to heat consumers. The amounts of heat available every hour to sell to heat consumers are

shown in Figure 2 below.

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Figure 2. Hourly sellable thermal energy output in kWh.

Subtask 7.1 i)

To meet the annual peak electricity demand of 3.021 kW, the required digester volume is 9.234,95

m3 (cf. Excel file M04a_Biogas_Group2.xls, sheet “7.1”). In reality this would be rounded up to the

next available digester size depending on manufacturer (e.g. 9.300 m3 or 9.500 m3). For

simplification, in this Assignment the size is rounded up to 9.300 m3.

4.2. Task 7.2. Biogas system design and LCOE

Subtask 7.2 a)

As already stated in subtask 7.1a), to guarantee that electricity demand is met every hour of the

year, required installed electric capacity of CHP plants has to equal the peak load. This applies also

under the design constraints given in the Assignment. Similar to subtask 7.1a), peak load on the

island is 3.021 kW and to meet this, an installed capacity of 3.250 kW of CHP plants is required given

the availability of CHPs units with capacities of 250 kWe and 500 kWe respectively (cf. attached Excel

file M04a_Biogas_Group2.xls, sheet “7.2”).

Subtask 7.2 b)

Similar to subtask 7.1b), the optimum combination of CHP units to cover the electricity demand was

determined by calculating the overall electric and thermal efficiencies of all possible CHP

combinations that meet the required installed capacity of 3.250 kW, and subsequently choosing the

best option for this project. As shown on Excel file M04a_Biogas_Group2.xls, sheet “7.2”, the

combination with highest electrical efficiency is chosen, i.e. 1 x CHP250 and 6 x CHP500 (same

conclusion as in subtask 7.1b)).

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Subtask 7.1 h) Hourly sellable thermal energy output (kWh)

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Subtask 7.2 c)

As already calculated in subtask 7.1b), overall efficiencies of the chosen combination of 1 x CHP250

and 6 x CHP500 are: electric efficiency 36,57% and thermal efficiency 46,43% (cf. Excel file

M04a_Biogas_Group2.xls, sheet “7.2”).

Subtask 7.2 d)

Total annual biogas production from the available substrates including corn silage from arable land is

2.617.809,52 m3 and the total annual electricity production 6.031.197,54 kWh (cf. Excel file

M04a_Biogas_Group2.xls, sheet “7.2”),

Subtask 7.2 e)

For the decision about optimal biogas storage size for bridging 12 hours of electricity demand when

there is no wind and sun, 4 different sizing alternatives were analysed (cf. Excel file

M04a_Biogas_Group2.xls, sheet “7.2”):

1. storage sized to meet 12h of electricity demand when the system is running constantly at

peak load of 3.021 kW,

2. storage sized to meet 12h of electricity demand at average load of 1.667 kW,

3. storage sized to meet 12h of electricity demand when those 12 hours of the year with

highest loads are considered,

4. storage sized to meet 12h of electricity demand when the 12 hours around peak load are

considered (i.e. hours 5336-5347).

To guarantee that the storage really is large enough to meet the entire electricity demand at any

given 12 hour period, alternative 1 (i.e. peak load 3.021 kW as design basis) is considered optimum.

Times with no wind and sun may occur not only during windless nights/evenings, but also in the rare

case of a simultaneous downtime of wind turbines and PV plant. Only a storage that has been sized

to meet a demand when the system is running 12 hours at the peak load of 3.021 kW would be

sufficient for securing energy supply on the island. For the chosen alternative the required biogas

storage size is 15.734,99 m3.

Subtask 7.2 f)

The LCOE calculations on sheet “7.2” of the attached Excel file M04a_Biogas_Group2.xls are based

on the cost and income parameters given in the Assignment guidelines. For the biogas plant design in

question, the calculated LCOE is 0,3077 €/kWh. Although a CHP plant generates both electricity and

heat, the LCOE calculation only includes electric energy generation. Another approach would be to

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include both electrical and thermal energy in the LCOE calculation to show the actual contribution of

the combined heat & power installation to the overall energy performance. Calculated this way the

LCOE would naturally be lower. For comparing different energy sources this approach is however not

suitable as it is not sure if thermal energy generated by the CHP plant really can be sold to heat

consumers. The LCOE calculated for the chosen plant design therefore only includes electric energy.

5. Hybrid System

Subtask 8 a)

The suggested solution for meeting the two conditions in setting up a hybrid system is to use 4 units

of G-830 wind turbines at 70 meters hub height in combination with a biogas plant. For calculations

see attached file hybridsystemgroup2.xxl

Subtask 8 b)

For making a hybrid system we were given two conditions to be met. First the hybrid system needs

to be able to meet the energy demand during every hour throughout the year. The total cost per

year also needed to be minimised according to Cyear = ∑E wind x LCOEwind +∑Epv x LCOEpv +∑

Ebiogas x LCOEbiogas

The biogas plan also needed to be able to bridge 12 hours of no sun or wind.

Our solution was to set up a hybrid-system according to first determine which of the renewable

energy systems that held the highest amount of useful energy production to the lowest LCOE costs.

That system was going to be our primary energy resource, of which we wanted to maximise the

amount of useful energy production that we could meet towards the demand. Thereafter we would

look on a second and third renewable energy system to meet the rest of the demand.

In previous tasks we had the possibility to optimize each renewable energy system and compare

each one of these energy-productions towards the LCOE. After looking at these figures we found that

a wind-system of 4xG-830 at 70 m hub height had the lowest LCOE of 0,0479 € and met a good

amount, 63,81%, of our energy demand. Only after wind-energy was the most cost effective-system

PV of polycrystalline, on nominal power 3.229 kW, giving 81,0% of the day-time energy demand for

an LCOE of 0,1127 €. The most expensive system was biogas, with LCOE of 0,3077 € meeting an

electricity demand of 41,30%.

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In order to minimise the costs and generate as much of our total energy demand as possible,

14.600.009,40 kWh, we found the wind-system of 4xG-830 at 70 m to be our best option as primary

energy system. The total cost per year for this system would be € 446.263,18. We put significance to

the fact that wind-energy is able to meet a high part of our demand during both day and night-time,

as PV only can meet part of the day-time demand.

We now started comparing different PV-systems to meet the shortfall demand of each hour from

wind-energy without making it more expensive than using a hybrid-combination of only using two

RE-systems: wind+biogas (with a total cost per year of €1.584.341).

We compared PV-systems between 2.500 kWp down to 1.000 kWp and calculated both the total

generated energy, the useful energy (both total and during daytime) and shortfall of all kWp-

photovoltaic systems. We also calculated the combined wind and PV generated and useful energy

when putting our two systems together in hybrid. We rather soon found that a big excess-generation

in higher kWp PV-systems leading to rather high LCOEs. An hybrid system of 4xG-830 70 m wind

system combined with a 2.500kWp system would for example generate 45,22% of excess electricity

and only meet 73,29 % of the total demand, meaning we also needed a good amount of biogas-

resource. Even a rather low PV-system of 1.000 kWp together with our chosen wind-system would

generate 37,95 % of excess electricity but that system would only meet 68,38% of the total energy-

demand. We also did LCOE-calculations of a 2.500, 2.000, 1.500 and 1.000 kWp-system to compare it

to the LCOE cost of biogas. The LCOE-calculations of PV can be viewed on sheet “LCOE PV” and

“LCOE_PV_Total_Gen_Useful_Gen”.

After putting each of the PV-systems together with wind we compared each of the hybrid systems

with putting the rest of the demand to be met with biogas. For this we calculated the LCOE of the

demand left to be met by biogas for each of our comparing systems. This can be viewed on the slide

“LCOE Biogas”.

After calculating the costs of several hybrid combinations we compared them on slide “cost per year

comparison”. We decided to compare the LCOE according to “Total useful generation kWh” and not

“Total generated kWh”. While doing our hybrid-calculations we rather soon realized that we were to

have a rather high portion of excess-generated electricity. If using generated electricity in our cost-

calculations we would have gotten lower costs but without being able to use all of the generated

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electricity as we are not able to sell the remaining electricity to the grid. By using “total useful

generation kWh” we therefore got realistic costs per kWh.

To meet our two conditions with having as low costs of the hybrid system as possible in the end we

found that the economic differences were not too different depending on which PV-system we were

to use.

Still the most cost-effective hybrid system was a wind and biogas system without using PV, as noticed

on slide “costs per year comparison” making it 23.761 € less expensive than combining wind and

biogas with the lowest generated PV-system of 1.000 kWp. We therefore ended up with a hybrid

system of wind 4xG-830 at 70 m combined with biogas, as can be seen on slide “Optimised hybrid”.

6. Demand Side Management

7. Island hot water demand

7.1. Task 10.1 Solar thermal system design and LCOE

Calculations in relation to tasks in 10.1 are to be found in the sheet ”10.1” of the Excel spreadsheet

named 2013 SOLAR THERMAL_AS_140813.xls enclosed to this report.

Subtask 10.1 a)

In addition to the given targeted overall solar thermal efficiency and annual solar fraction, in order to

calculate the optimum collector area of the solar thermal system for the hotel complex, it is

necessary to identify the energy consumed for hot water provision as well as the solar irradiation at

the site.

Total annual irradiation at the location of the hotel complex is 2.150,88 kWh/m2 and it is obtained by

summing up the daily irradiation data provided in the spreadsheet '2013 PHOTOVOLTAICS_2.xls'

(provided as supporting documentation to the Assignment guidelines),

Total annual energy consumption for hot water provision is calculated based on total annual hot

water consumption, which is calculated by taking into account the peak daily hot water consumption

in the main building of the hotel complex (13 m3 at a temperature of 70ºC at the store, taking place

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in August and December; it is assumed that for every day in August and December this value is

consumed) and the share of the monthly hot water consumption given in the hot water consumption

profiles (cf. spreadsheet '2013 SOLAR THERMAL.xls' submitted as supporting documentation to the

Assignment guidelines). Additional parameters in this calculation are density of water, specific heat

capacity of water and the temperature difference between hot water and cold water. The result is

total annual energy consumption of 232.571 kWh.

The active collector area in m2 (Acoll) is then calculated by using the following formula

Acoll = Edemand x SF / Eirrad x ηsys

where

Edemand = daily domestic hot water demand kWh/day

SF = annual solar fraction

Eirrad = daily irradiation in kWh/day/m2

ηsys = system efficiency

and the result is a required collector area of 216,26 m2 to meet the hot water demand of the hotel

complex.

The solar store volume is estimated at 50 litres per m2 collector area, which gives a buffer store size

of 10.812,82 litres or 10,81 m3.

Subtask 10.1 b)

The number of collectors required for the optimum collector area is calculated for the Viessmann

Vitosol 200-F SV2 flat plate collector (high quality flat plate collector, Solar KEYMARK certificate,

product and price details enclosed to this report as attachments) as well as for the Sunrain

TZ58/1800-30R1 evacuated tube collector (given in the Assignment guidelines).

The optimum collector area is divided by the absorber surface area of the flat plate collector and the

aperture area of the evacuated tube collector. The results show that 93 flat plate collectors and 78

evacuated tube collectors are required to meet the optimum collector area.

When multiplying the number of each type of collectors required with their gross surface area (which

is defined by the outer dimensions of the collectors), the result is the total collector area of the solar

thermal system (233,43 m2 for flat plate and 382,28 m2 for evacuated tube collectors). It shows that

total collector area of each collector type is within the roof area constraint of 980 m2 (70 m x 14 m).

20

Sketches of the collector layouts on the available roof area, including the flow and return piping

according to the Tichelmann Principle, are shown in Figures 3 and 4.

Figure 3. Piping of Sunrain TZ58/1800-40R1 collector.

Figure 4. Piping of Vitosol 200-F SV21A collector.

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Subtask 10.1 c)

The annual useful energy yield is 80% of the total annual energy consumption for hot water

provision, which is 186.057 kWh.

Subtask 10.1 d)

The LCOE calculations for both systems are based on the LCOE parameters and solar thermal

installation cost breakdown given in the Assignment guidelines, as well as on following additional

parameters and assumptions:

The prices obtained by research are 534,52 € for the Viessmann Vitosol 200-F SV2 flat plate

collector and 1.250 US$ (or 942,54 € when applying the current USD/EUR exchange rate) for

the Sunrain TZ58/1800-30R1 evacuated tube collector. (Riikka to add sources)

According to the cost breakdown collectors make for 32% of total investment costs. Total

investment costs are obtained by dividing total collector costs (number of collectors

calculated in subtask 10.1 b) multiplied with the unit price) with its share in solar thermal

system installed costs.

Furthermore hardware costs (including collectors, collector array frame, collector array

pipework, other pipework, store & heat exchanger, controls) make for 77% of total

investment costs according to the cost breakdown, based on which it is then possible to

calculate annual O&M costs.

The results are an LCOE of 0,0819 €/kWh for the Viessmann Vitosol 200-F SV2 flat plate collector

system and 0,1212 €/kWh for the Sunrain TZ58/1800-30R1 evacuated tube collector system.

According to the results the preferred system would be the flat plate collector system. With a

considerably lower collector price it makes for a much lower investment and consequently lower

levelized costs of the energy produced for hot water provision of the hotel complex.

7.2. Task 10.2 Effect on the Hybrid System of deducting the electricity requirement forhotel and household hot water production from the electricity load profile

Calculations and charts in relation to task 10.2 are to be found in the sheet ”10.2” of the Excel

spreadsheet 2013 SOLAR THERMAL_AS_200813.xls enclosed to this report.

Subtask 10.2 a)

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Each household is consuming approximately 5 kWh per day for hot water provision. By multiplying

this figure with the number of households in the village on the south west of the island near the

hotel complex, the average daily energy consumption for heating water for the entire village is

obtained and it amounts to 6.000 kWh.

The average daily energy consumption for hot water for the hotel is 637 kWh. It is calculated based

on the monthly figures, which are calculated based on the volume of monthly hot water

consumption calculated in subtask 10.1 a).

By multiplying the daily energy consumption for hot water provision with their respective share in

consumption according to the daily consumption profiles for both household and hotel, the energy

consumption per hour is obtained.

By summing up the hourly values for the hotel and the 1200 households, the combined daily energy

consumption is obtained.

The combined daily energy consumption profile is obtained by calculating the share of the combined

energy consumption per hour in in the total combined daily energy consumption. It is also shown

graphically.

Subtask 10.2 b)

The change in system load for the five sample days is shown in the chart 'Island electricity demand

curve for 19th-23rd August (Days 231-235)' in sheet 10.2 of the Excel spreadsheet 2013 SOLAR

THERMAL_AS_190813.xls under 10.2 b).

Subtask 10.2 c)

According to the assignment guidelines it can be assumed that the sample 5 days from 19th to 23rd

August are indicative for the whole year. Hence based on the combined electricity consumption for

heating water for these five days, the hot water electricity consumption for hotel and the south west

village for the entire year can be calculated. If the electricity consumption is to be offset with solar

heat to heat water, the combined electricity consumption for the entire year can be deducted from

the annual electricity system load. The calculations show that total system load decreases by

2.422.492 kWh, that is by 17%.

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In the optimized hybrid system the contribution of wind to total system load is 64%, and that of

biogas 36%. With a reduced system load, the contribution of wind would increase by 13% and the

contribution of biogas decrease by 13%. Due to the fact that wind as a fuel is free and practically

available day and night, and that the LCOE for wind is in principal lower than that of biogas, wind is

still being used as the primary energy source. Hence the reduction in system load would mean a

reduction in the electricity output of the biogas plant only and the island would still use all of the

useful electricity generated by the 4 G-830kW wind turbines.

Subtask 10.2 d)

Since the useful electricity generation of wind does not change with the reduction in system load, the

LCOE remains unchanged as well (0,0479 €/kWh). On the other hand the LCOE of biogas increases to

0,2330 €/kWh due to the fact that the costs of the plant remain unchanged (the installed capacity of

the plant still needs to be 3.250 kW in order to be able to guarantee that the electricity demand is

met at any given hour of the year, i.e. when there is no wind or sun), however its electricity output

decreases.

Subtask 10.2 e)

If no arable land is available for growing corn to supply the biogas plant, it can generate electricity

only from available manure and organic waste. Total electricity production from these is 1.807.143

kWh as calculated in subtask 7.1 d). By subtracting the useful electricity generated by wind, the

electricity produced by the biogas plant from manure and organic waste only and the combined

electricity consumption offset with solar heat from the total system load, the required system load

reduction is obtained in the case that arable land is no longer available (1.053.814kWh).

Subtask 10.2 f)

Offsetting electricity with solar heat appears to be worthwhile from different perspectives. From the

economic perspective, with the LCOE for solar thermal systems (both flat-plate collector system

which is the preferred solution for the hotel, as well as the thermosyphon system which is the

proposed solution for the south west village households) being considerably lower than that of

biogas, total energy cost of the hybrid system (even with a small increase in biogas LCOE as

calculated in 10.2 d)) can be expected to be lower as well when compared to the optimized hybrid

system without solar heat.

Due to the fact that the biogas plant is using corn in addition to manure and organic waste to

produce the required electricity, which can be considered as competition to the island's food

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production, from the aspect of sustainability, it definitely makes sense to reduce the arable land that

is required to grow the corn and to use solar heat to heat water instead of electricity.

Subtask 10.2 g)

The LCOE calculation for the thermosyphon system is based on the assumptions and parameters

given in the assignment guidelines as well as on following additional parameters and assumptions:

The price obtained by research of a high quality certified thermosyphon system package is

2.587,20$ or 1.938,85€ according to the current currency exchange rate provided by the

European Central Bank (1€ = 1,3344$; 19 August 2013).

The hourly rate of installers obtained by research is 16,57€. A personday comprises 8 hours

of works, hence installation costs are assumed to be 133€.

By summing up thermosyphon system package costs, pipework costs and installation costs,

total investment costs are obtained.

Thermosyphon system package and pipework costs are assumed to make for the hardware

costs.

By multiplying the average daily energy consumption for hot water provision per household

in southwest village of 5 kWh with 365 days of the year, the energy that needs to be

generated by the thermosyphon system for hot water provision per household and year is

obtained.

The result is as follows:

LCOE Thermosyphon System 0,1344 €/kWh.

7.3. Task 10.3 Use of heat from the biogas plant

Sources

Altevogt J (2013). ”Photovoltaic energy”. MBA Renewables. Renewables Academy AG (RENAC).

Power Point presentation, 12 June 2013, Berlin. 80 slides.

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Goodrich A, James T and Woodhouse M (2012). “Residential, Commercial, and Utility-Scale

Photovoltaic (PV) System Prices in the United States: Current Drivers and Cost-Reduction

Opportunities”. National Renewable Energy Laboratory (NREL). Technical Report NREL/TP-6A20-

53347. 55 pages. Retrieved on 17 August 2013 at http://www.nrel.gov/docs/fy12osti/53347.pdf

Morthorst PE, Auer H, Garrad A and Blanco I (2009). “Wind Energy – The Facts. The Economics of

Wind Power”. 62 pages. Retrieved on 11 August 2013 at http://www.wind-energy-the-

facts.org/documents/download/Chapter3.pdf

List of Figures

Figure 1. Various PV capacities and their corresponding output percentages with respect to demand.

Figure 2. Hourly sellable thermal energy output in kWh.

Figure 3. Piping of Sunrain TZ58/1800-40R1 collector.

Figure 4. Piping of Vitosol 200-F SV21A collector.

List of Tables

Table 1. Total and useful annual electricity generation with the 4 different turbine options.

List of Attachments

Excel files

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vitosol-200-f-datasheet.pdf, retrieved on 13 August 2013 at

http://www.seconsolar.com/ekmps/shops/seconsolar/resources/Other/vitosol-200-f-datasheet.pdf

Vitosol 200-F certificate.pdf, retrieved on 13 August 2013 at

http://solarkey.dk/solarkeymarkdata/qCollectorCertificates/ShowQCollectorCertificatesTable.aspx

vitosol-200-f-price.pdf, retrieved on 13 August 2013 at http://www.raatschen.de/_pdf/50.pdf

m04a re island-group2_report_200813

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