Dissertation Final (2)

20/03/2012

Honours Project2011/2012

Written By Ben PrestonSupervised by Tariq Muneer

“I have no doubt that we will be successful in

harnessing the sun's energy... If sunbeams were

weapons of war, we would have had solar energy

centuries ago.” Sir George Porter, 26th August 1973

2

Contents

Abstract..............................................................................................................................................1-7

1 Introduction................................................................................................................................1-9

2 Literature Review.....................................................................................................................2-11

2.1 Energy in Spain.................................................................................................................2-11

2.1.1 Energy Prices in Spain...............................................................................................2-12

2.1.2 Solar Irradiance as a Resource in Spain.....................................................................2-14

2.1.3 Subsidy Reductions...................................................................................................2-15

2.2 Photovoltaic Generation...................................................................................................2-16

2.2.1 PV cell structure........................................................................................................2-16

2.2.2 PV-IV Characteristic..................................................................................................2-19

2.2.3 Fixed Orientation, Single and Dual Axis tracking.......................................................2-20

2.2.4 Sky Clarity Index........................................................................................................2-23

2.2.5 Shading.....................................................................................................................2-24

3 The Site.....................................................................................................................................3-25

3.1 Electricity Usage...............................................................................................................3-27

4 Methodology............................................................................................................................4-28

4.1 Terms................................................................................................................................4-28

4.2 Formulae..........................................................................................................................4-28

4.3 Method.............................................................................................................................4-29

5 Daily Global Irradiation.............................................................................................................5-31

6 Hourly Global Irradiation..........................................................................................................6-32

6.1 Terms................................................................................................................................6-32

6.2 Formulae..........................................................................................................................6-32

6.3 Method.............................................................................................................................6-32

6.4 Results..............................................................................................................................6-34

7 Hourly Diffuse Irradiation.........................................................................................................7-35

Ben PrestonEdinburgh Napier University

3

7.1 Terms................................................................................................................................7-35

7.2 Formulae..........................................................................................................................7-35

7.3 Method.............................................................................................................................7-35

7.4 Results..............................................................................................................................7-37

8 Slope Irradiance........................................................................................................................8-39

8.1 Terms................................................................................................................................8-39

8.2 Formulae..........................................................................................................................8-39

8.3 Method.............................................................................................................................8-40

8.3.1 Fixed & Seasonal Tilting............................................................................................8-40

8.3.2 Tracking....................................................................................................................8-41

8.4 Results..............................................................................................................................8-43

9 Panel Selection.........................................................................................................................9-45

10 Power Output.....................................................................................................................10-46

10.1 Terms..............................................................................................................................10-46

10.2 Formulae........................................................................................................................10-46

10.3 Method...........................................................................................................................10-47

10.4 Results............................................................................................................................10-48

11 System Sizing......................................................................................................................11-50

12 System Performance..........................................................................................................12-51

12.1 Assumptions...................................................................................................................12-51

12.2 Findings..........................................................................................................................12-52

13 Conclusions.........................................................................................................................13-53

14 Recommendations..............................................................................................................14-55

15 Future Work.......................................................................................................................15-56

16 Appendices.........................................................................................................................16-57

16.1 Hourly Global Irradiation................................................................................................16-57

16.2 Hourly Diffuse Irradiation...............................................................................................16-58

16.3 Hourly Slope Irradiation..................................................................................................16-59


4

16.3.1 Fixed and Seasonal Calculation...............................................................................16-59

16.3.2 Seasonal Optimum Tilt............................................................................................16-60

16.3.3 Tracking..................................................................................................................16-60

16.4 Sanyo HIT-250E01 Data Sheet........................................................................................16-62

16.5 Power output..................................................................................................................16-64

16.6 Economics.......................................................................................................................16-64

16.6.1 Hardware Cost........................................................................................................16-64

16.6.2 Maintenance Cost...................................................................................................16-65

16.6.3 Payback...................................................................................................................16-66

17 References..........................................................................................................................17-67

18 Bibliography........................................................................................................................18-70

Table of Figures

Figure 1 – Olmedilla 60MW Photovoltaic Park, Seville (Scheuten Solar, 2007)..................................1-9

Figure 2 – European PV capacity (EurObserv'ER, 2011)......................................................................1-9

Figure 3 – Spain Import Dependency (European Commission, 2011)...............................................2-11

Figure 4 – Energy Generation, Spain (European Commission, 2011)................................................2-11

Figure 5 – Average Electricity Prices in Europe (European Commission - Eurostat, 2011)...............2-12

Figure 6 – Change in average electricity price (2009-2011) (European Commission - Eurostat, 2011) 2-

12

Figure 7 – GDP per Capita (International Monetary Fund, 2012).....................................................2-13

Figure 8 – Annual Irradiation in Spain (European Commission, 2012)..............................................2-14

Figure 9 – European PV Growth (Predicted and actual) (Solar Novus Today, 2009).........................2-14

Figure 10 – Poly-crystalline (Solar Energy at Home, n.d.) And Mono-crystalline (Direct Industry, n.d.)

Solar Cells.........................................................................................................................................2-16

Figure 11 – HIT Solar Cell Design (Sanyo Electric Co., Ltd., 2012).....................................................2-17

Figure 12 – HIT Panel Temperature Efficiency (Sanyo Electric Co., Ltd., 2012).................................2-18

Figure 13 – Typical PV-IV Curve (Aldali, et al., 2011)........................................................................2-19

Figure 14 – Tracked PV Installation spaced to avoid shading (McDermott, 2009)............................2-20

Figure 15 – An example of an East-West single-axis tilting system (W.B. Stine, 1986).....................2-20


5

Figure 16 – Comparison of various tracking systems in Albuquerque at winter solstice (W.B. Stine,

1986)................................................................................................................................................2-21

Figure 17 – Clarity Index Study (Cooke, 2007)..................................................................................2-23

Figure 18 – Effect of shading on power output (Solar Edge, 2010)..................................................2-24

Figure 19 – Installation Site (Google Inc., 2012)...............................................................................3-25

Figure 20 – Zoomed out installation site (Google Inc., 2012)...........................................................3-25

Figure 22 – Average Sky Clearness Index (Kt) for Murcia (Spain-Meteo, 1983-2005).......................3-26

Figure 21 – Ambient Temperature, Humidity and Wind-speed (Murcia, Spain) (Tutiempo, 1973 to

2012)................................................................................................................................................3-26

Figure 23 – Electricity usage per month...........................................................................................3-27

Figure 24 – Irradiation calculation steps...........................................................................................4-29

Figure 25 – Distance from data collection site to installation site (Institute for Energy and Transport

(IET), 2012).......................................................................................................................................5-31

Figure 26 – Horizontal and optimum slope irradiation (Institute for Energy and Transport (IET), 2012)

.........................................................................................................................................................5-31

Figure 27 – Calc.4.0.9 (Muneer, et al., 2000)....................................................................................6-33

Figure 28 – Monthly-averaged horizontal daily global irradiation converted to hourly global

irradiance.........................................................................................................................................6-34

Figure 29 – Calc4.0.8 (Muneer, et al., 2000).....................................................................................7-36

Figure 30 – Hourly Diffuse Irradiation per month.............................................................................7-37

Figure 31 – Average computer sky clearness index..........................................................................7-38

Figure 32 – Total Daily Irradiation....................................................................................................8-43

Figure 33 – Total Annual Irradiance by %.........................................................................................8-43

Figure 34 – Comparison of PV system slope irradiation - June.........................................................8-44

Figure 35 – Comparison of PV system slope irradiation - December................................................8-44

Figure 36 – PV System Total Annual Output...................................................................................10-48

Figure 37 – Power output by %......................................................................................................10-48

Figure 38 – Average monthly power output...................................................................................10-49

Figure 39 – Total 20-year electricity production.............................................................................12-52

Figure 40 – System Payback (years)................................................................................................12-52

Figure 41 - % of global irradiance occurring seasonally..................................................................13-53

Figure 42 – Calc.4.10 (Muneer, et al., 2000)...................................................................................16-59


6

Equations

Equation 1 – Calculation of hourly global irradiation.......................................................................4-28

Equation 2 – Calculation of cell temperature...................................................................................4-28

Equation 3 – Ratio of hourly to daily global irradiation (Muneer, et al., 2000)................................6-32

Equation 4 – Ratio of global to diffuse irradiation (Muneer, et al., 2000)........................................7-35

Equation 5 – Hourly sky clearness index (Muneer, et al., 2000).......................................................7-35

Equation 6 – Extra-terrestrial Irradiation (Muneer, et al., 2000)......................................................7-35

Equation 7 – Slope Irradiation (Muneer, et al., 2000)......................................................................8-39

Equation 8 – Tilted beam irradiation on a fixed slope (Muneer, et al., 2000)..................................8-39

Equation 9 – Ratio of angle of incidence to solar altitude (Muneer, et al., 2000)............................8-39

Equation 10 – Reflected Irradiance (Muneer, et al., 2000)...............................................................8-39

Equation 11 – Beam Irradiance (Muneer, et al., 2000).....................................................................8-39

Equation 12 – Slope Plane (N-S Tracking) before noon (Aldali, et al., 2011)....................................8-39

Equation 13 – Slope Plane (N-S Tracking) after noon (Aldali, et al., 2011).......................................8-39

Equation 14 – Angle of Incidence (N-S Tracking) (Aldali, et al., 2011)..............................................8-40

Equation 15 – Solar hour angle........................................................................................................8-40

Equation 16 – Tilted beam irradiance on a moving slope.................................................................8-40

Equation 17 – Cell Temperature at a given hour (Duffie & Beckham, 1991)..................................10-46

Equation 18 – Module efficiency if Tcell is above NOCT...................................................................10-46

Equation 19 – Module efficiency if Tcell is below NOCT...................................................................10-46

Equation 20 – Power output per module (Duffie & Beckham, 1991).............................................10-46


7

Abstract

This investigation details the design of a solar PV system in Murcia, Southern Spain. The system is

designed to meet an electricity demand of 620kWh in March.

3 systems are compared:

Building-integrated, fixed tilt

Free-standing, seasonal tilting

Free-standing, single-axis tracking

It was decided to discount the system using seasonal tilting, as calculations showed that it would

only produce a 1.82% increase in power output over the fixed tilt system. Of the two remaining

systems, the single-axis tracking system has been selected for implementation. This is due to a large

increase in the power output (19.67%) over the fixed system, combined with the similar cost.

The fixed system, while producing a fairly similar output at most times of the year, is out-done in

summer by the tracked system, despite the tracking system being of a smaller rating. As a result, the

fixed system requires a larger area to implement, and while it requires less funding per kWp, since

the single-axis tracking system requires less overall hardware and is more efficient, the initial

investment prices are roughly the same.

The two systems also pay off in a similar amount of time; 10.93 years for the fixed and 11.51 years

for the tracked system. As a result, the initial investment is recouped in a similar amount of time,

with the tracked system going on to produce a much larger income through incentives after pay-

back, and generating a larger amount of electricity over the life-time of the system.


8

Thanks to Tariq Muneer for his help and advice throughout

this report, and to Tariq and Yasser Aldali for their previous

work in the field which provided help countless times.


9

1 Introduction

Spain has more hours of sunshine per year than most European countries. As a result, the nation

thrived as a producer of solar power and technology, becoming the 4th largest producer of solar

power in the world.

The primary solar power technology in Spain until

recently was photovoltaic, and it stills plays a

major role in electricity production in Spain, with

its largest photovoltaic park (located in Seville,

Andalucía) being the largest plant of its kind upon

completion, operating with a capacity of 60MW.

Spain also contains another 21 photovoltaic parks

with over a 20MW capacity, with a total capacity

of 686.6MW through photovoltaic technology

alone. Projects like these contribute large

amounts of electricity to the Spanish grid system, taking pressure off the public to pay inflating

electricity prices caused by the nation’s dependency on energy imports. However, with the Spanish

governments recent decision to reduce the feed-in tariffs for both roof-based and free-standing PV

installations and to cap the maximum growth in capacity per year, the industry in Spain (and world-

wide as a result) has taken a major blow.


Figure 1 – Olmedilla 60MW Photovoltaic Park, Seville (Scheuten Solar, 2007)

Figure 2 – European PV capacity (EurObserv'ER, 2011)

10

Between 2007 and 2008, Spain’s PV capacity increased by 2688MW, while that capacity only

increased a further 779MW in the 3 years after 2008, just after the tariff reductions and growth caps

were introduced.

Spain is dependent on imports for almost 80% of its fuel used for electricity generation (European

Commission, 2011). As a result, energy prices in Spain have been consistently on the rise, and are

expected to continue rising. With an area of 505,782km2 and a population of 46.7 million, Spain is

also one of the least densely populated countries in Europe, resulting in large spaces of sparsely

populated land.

The increase in energy prices, combined with abundant and reliable sunshine and large,

unpopulated areas which could be utilized for PV and solar thermal electricity generation gives Spain

the means they need to move away from their dependency on imports.


11

2 Literature Review

2.1 Energy in Spain

Spain is a country situated in southern Europe which is strongly dependant on energy imports, with

the vast majority of its domestic energy production coming from nuclear power stations. Since 1990,

energy demand in Spain has increased dramatically, and continues to increase year on year.

In 2004 Spain was dependant on imports for 77.4% of its fuel supply (European Commission, 2011),

compared with the European average of 50.1%. As shown in figure 4, 38% of Spain’s electricity

generation comes from gases, while 6%

comes from petroleum products and 12%

from solid fuels. Of these fuels, nearly

100% of gases and petroleum fuels and

nearly 90% of solid fuels are imported. This

amounts to roughly 50% of Spain’s

electricity demand being reliant on imports

from other countries. As a result, the

prices of electricity in Spain have risen at a

faster rate than that of most other European countries; as world-wide fuel demand continues to


Figure 4 – Energy Generation, Spain (EuropeanCommission, 2011)

Figure 3 – Spain Import Dependency (European Commission, 2011)

12

increase, countries such as Spain that are dependent on fuel-purchases for electricity generation will

be forced to pay a premium to satisfy their needs.

2.1.1 Energy Prices in Spain

As a result of the dependency of Spain on imports for much of its electricity generation, the average price of electricity within the country has seen a sharp increase in recent years.

2009 2010 20110.1

0.12

0.14

0.16

0.18

0.2

0.22

0.24

0.26

0.28

0.3

Year

Aver

age

Price

of E

lect

ricity

(€/k

Wh)

Figure 5 – Average Electricity Prices in Europe (European Commission - Eurostat, 2011)

In the past 2 years, the electricity price in Spain has jumped from an average of just below

0.16€/kWh to 0.195€/kWh, and increase of over 20%. In 2009 Spain was relatively cheap for

electricity when compared with countries such as the Netherlands, Italy and Germany. Since then,

however, the average price per unit of electricity in these countries has dropped significantly while

Spain’s has risen drastically. Figure 6 shows the percentage change in average electricity price per


Figure 6 – Change in average electricity price (2009-2011) (European Commission - Eurostat, 2011)

13

unit, and shows that Spain’s has increased at a far sharper rate than any other European nation.

This is expected to increase even further in the next few years.

Spain also has a significantly lower GDP per capita than the majority of the other European countries

listed, as shown in Figure 7. As a result of the price of energy rising quicker than most other

European nations, and the general public having less money to spend (relatively) on these bills, it

seems that solar PV in Spain could provide some relief to residents.

2.1.2 Solar Irradiance as a Resource in Spain

Due to drastically increasing energy prices in Spain, renewable methods of electricity generation

which will allow the country to move away from dependency on imports for fuel could be the way

forward.

As a nation with an abundance of solar radiation at its disposal, Spain has always had the means to

become one of the European leaders in solar thermal and solar PV production and technology.

Indeed, for years it has been seen as forward thinking in this regard and coupled with its financial

resources has had the capacity to become one of the front-runners in world-wide PV electricity

production.


Figure 7 – GDP per Capita (International Monetary Fund, 2012)

14

For the majority of southern Spain, the annual irradiance exceeds 1500kWh/m2. This gives Spain

great potential to take advantage of photovoltaic technology and solar thermal technology as a

means to provide energy. This is especially true when compared with the likes of the UK where the

highest annual irradiance is roughly 1250kWh/m2, covering an extremely minor portion of the

country.

As a result of the availability of energy, Spain quickly established itself as one of the most advanced

countries in producing solar energy, reflected in the

growth of their grid-connected PV systems throughout

the 21st century (Figure 9).

Starting from 2006, Spain was at the fore-front of PV

growth, and was expanding its grid connected systems

at a rate far exceeding that of any other country. This

peaked in 2008, when Spain saw the increase in

capacity of grid-connected systems increase by 2.6GW

this year alone, taking their overall capacity to 3.5GW

and producing roughly 2% of the overall electricity

requirement. The money pouring into the industry in

Spain was also on the up, with investment in Spanish

PV project increasing nearly 500% (Scientific American, 2008) in 2007 from the previous year. Not

only was Spain profiting from the energy produced through solar means, but they were also

benefitting from the manufacture of solar power technology, and exports 80% of its manufacturing

output to Germany.

2.1.3 Subsidy Reductions

As a result of the financial crisis in 2008, the Spanish government took the decision to drastically cut

feed-in tariffs (by 25% for building-integrated systems, and up to a massive 45% for ground based

installations) afforded to grid-connected PV systems, and to limit the maximum capacity of systems

that can claim subsidies to 500MW per year, less than 20% of the growth in the previous year. This

drastically hindered the industry in Spain and had an impact on the industry world-wide, as seen in

2009 when their overall PV capacity increased much less than that of Italy (figure 9) as a result of

companies rethinking their plans to invest in the Spanish market with uncertainties over the future

of subsidies and hence the potential to cover costs and make a profit. In fact, in 2009 and 2010


Figure 9 – European PV Growth (Predicted and actual) (Solar Novus Today, 2009)

15

combined, 100MW of capacity was added to the Spanish grid-connected system, compared with

2600MW in 2008 alone (Scientific American, 2008).

Although the decision to reduce the feed-in tariffs on offer was largely expected, with other

European countries having done the same in the wake of the financial crisis, one controversial

aspect was the government’s decision to apply these cuts retro-actively. This would mean that large

solar farms set up years before the introduction of the new feed-in tariff would now have retro-

active payments to make based on the original feed-in tariffs, and could now expect to produce

money at a much slower rate when compared with the rates they were promised upon installation.

This resulted in sections of the solar industry in Spain going bankrupt, and further damaged investor

confidence, causing some to pull out of Spain completely and causing potential future investors to

flock to other countries where they could be afforded a more generous and predictable pay-back on

investment.

2.2 Photovoltaic Generation

2.2.1 PV cell structure

One of the most common specifications of a PV-module is the make-up of the silicon used. The

three most commonly used modules consist of:

Mono-crystalline: Produced from a single crystal of silicon.

Poly-crystalline: Produced from a piece of silicon containing many crystals.

Amorphous: Uses a thin-sheet of silicon wrapped around another material such as steel.

Amorphous panels are generally used for small scale

applications, such as on calculators and solar powered

lights, as they are much cheaper as a result of requiring

much less silicon (this can, however, be off-set by their low

power density, requiring a much larger area for equivalent

energy output). They also generally have much lower

efficiencies than either mono or poly-crystalline, but are


16

useful for situations requiring modules to run at high temperatures, as their efficiency remains

relatively constant at extreme heat.

Mono-crystalline panels are generally the most efficient modules available, but as a result of the

difficulty of extracting silicon as a single crystal, they tend to be much more expensive than poly-

crystalline, although again a portion of this cost can be off-set by the fact that they require less area

to produce the same amount of energy.

Poly-crystalline panels lie in between the efficiencies and cost of amorphous and mono-crystalline

panels, and as such tend to be the most commonly used for commercial and personal applications

where space is not the limiting factor. They are produced from a single piece of silicon containing

many different crystals, resulting in their lower cost as a result of the difficulties of extracting a single

intact silicon crystal. Another advantage to poly-crystalline panels is their recyclability. As they

don’t require a complete intact crystal, silicon from older panels (mono and poly-crystalline) can be

recycled and used to produce new poly-crystalline panels. In this way, it is possible to obtain poly-

crystalline panels cheaply second hand.

A new type of panel is currently being developed by Sanyo called HIT (Hetero-junction with Intrinsic

Thin layer) which has a number of advantages over conventional mono, poly-crystalline and

amorphous panels:

High energy conversion efficiency

Efficiency is preserved into much higher temperatures than mono or poly-crystalline

Considerable output under diffuse and low-light conditions

Essentially, these new panels use a thin layer of a thin layer of mono-crystalline silicon surrounded

by an even thinner layer of amorphous silicon (shown in figure 11). As with standard amorphous

panels, the layer of amorphous silicon preserves the efficiency at high temperatures, while the

mono-crystalline layer provides the increased efficiency of standard mono-crystalline panels,

granting the best of both technologies.


17

Figure 11 – HIT Solar Cell Design (Sanyo Electric Co., Ltd., 2012)

The most significant advantage of this design is the option to work in much higher operating

temperatures without drastically affecting the energy production of the system. This in turn can

negate the need for a cooling system and off-set the cost of the panels themselves. They may also

prove to provide a more reliable source of energy production due to their ability to operate well in

diffuse and low-light conditions.

Figure 12 gives a graphical representation into the

improvements in temperature performance over

standard crystalline silicon (c-Si). As shown, c-Si cells

drop in efficiency by roughly 0.5%/°c, compared with

only 0.3%/°c for HIT panels. This means that, taking cells

with a normal operating cell temperature (NOCT) of 50°c

and an efficiency of 15%, operating at 65°c standard c-Si

cells would be operating at roughly 7.5% efficiency, while

HIT cells would be operating at 11.5% efficiency. This can

help to provide a more stable source of energy

production, increase the energy production significantly

in places where the temperature can vary significantly

throughout the year and reduce the need for cooling systems to keep the cell temperature at

optimal conditions.


Figure 12 – HIT Panel Temperature Efficiency (Sanyo Electric Co., Ltd., 2012)

18

2.2.2 PV-IV Characteristic

The electrical output of a PV module is determined by its current-voltage characteristic, often shown

in the form of a graph provided by manufacturers. The related parameters on the IV curve of a PV

module are:

Current (I)

Voltage (V)

Irradiation (G)

Temperature

Figure 13 shows a typical PV-IV curve at a given temperature and value of irradiance. Manufacturers

will generally provide a similar graph with various curves at different irradiance and temperature

values, allowing accurate modelling of the IV curve for set conditions.

Due to Ohm’s Law (Power = Voltage x Current), as the voltage drops so does the power output. The

ideal position on the IV curve is the point at which the power output is at its shown in Figure 13 as

Pm.

To ensure PV systems are kept at their value for maximum power output as often as possible,

maximum power point tracking systems are often employs. These systems sample the output of the

solar cells and adjusts the resistant load on the circuit, in turn effecting the current and voltage

(Resistance = Voltage/Current), in order to keep the system at its maximum power output as often

as possible. Maximum power point tracking is absolutely essential to ensure the output of a PV

system is as stable and efficient as possible, and is being more commonly built in to inverters of grid-

connected systems.


Figure 13 – Typical PV-IV Curve (Aldali, et al., 2011)

19

2.2.3 Fixed Orientation, Single and Dual Axis tracking

One of the key decisions when designing a photovoltaic system is the orientation and tilt of the

system. Dependant on the location of the system, an optimal orientation is determined which will

allow maximisation of the radiation occurring on the surface. Panels located in the northern

hemisphere should face true south, while those located in the southern hemisphere should face true

north to maximise energy output. Note that true north and south are not the same as magnetic

north and south, and corrections will need to be made for the difference which varies by location.

The next key parameter is the

tilt of the panels from horizontal when using fixed panels. In general, this is taken as the latitude for

the site, however as a result of the varying height of the sun in summer and winter this can vary by

as much as -15° in summer and +15° in winter. As a result, when using fixed tilt systems it can be

beneficial to adjust the tilt angle of the system twice a year, once at the end of summer and once at

the end of winter to match

the optimum conditions at

that time of year.


Figure 15 – An example of an East-West single-axis tilting system (W.B. Stine,1986)

Figure 14 – Tracked PV Installation spaced to avoid shading (McDermott,2009)

20

Single axis systems generally track only to optimise the solar azimuth angle (the clock-wise angle of

the sun from north), while dual-axis systems track both the solar azimuth and the tilt angle from

horizontal. Compared to fixed tilt systems, increases in energy output for equivalently sized systems

of 27-40% can be expected. This, however, comes at the cost of simplicity. As a result of tracking

systems having more moving parts, sensors and added complexity, additional maintenance is

required and the risk of a problem arising is greater. Dual-axis tracking have additional complexity

over single-axis tracking, and thus are more liable to failure and to incur greater maintenance costs.

As a result, it is important to understand if the additional energy gains of using a dual-axis tracking

system over a single-axis are going to be of benefit, when taking into account the additional costs

and risks of failure.

It is well known that tracking system will out-perform a fixed angle PV system on annual energy

production, but taking into account the cost of the system, how feasible is it to install a tracking

system?


Figure 16 – Comparison of various tracking systems in Albuquerque at winter solstice (W.B. Stine, 1986)

21

A study was performed (Wattsun, 2010) comparing 4 different PV systems located in Madison,

Wisconsin, USA. The system types are listed in table 1. For the purposes of the report, the annual

electrical output was taken to be equivalent.

System 1 System 2 System 3 System 4Tracking? No No No Dual AxisOrientation 35° 55° 35° in

Summer/55° in Winter

N/A

DC Rating (kW) 4 4 4 3Annual AC Output (kWh)

4952 4758 5089 4852

Cost/DC Watt $8.63 $8.63 $8.63 $9.96System Cost $34,520 $34,520 $34,520 $31,872

Table 1 – System Comparison (Wattsun, 2010)

The cost per DC watt was calculated as follows:

$8.63 per installed DC watt (average installed cost of PV system in the USA)

Fixed racking price of $0.91 per DC watt

Dual Axis tracking rack price of $2.24 per DC watt

This amounts to a difference of $1.33 per DC watt between the fixed and tracking system

($2.24-$0.91)

Seasonal adjustments are a commonly used way to increase the output of fixed PV systems; the tilt

angle of the PV array is changed twice per year (summer and winter solstice) to match the optimum

angle at that time of year. System 3 makes use of seasonal adjustments, showing a slight increase in

power output over the fixed systems. This is a suitable way to increase output in situations where

finances do not permit a tracking system to be installed.

The finding from the report was that although a tracking system of equivalent physical size would

cost more than the fixed system, considering systems of the same electrical output the reduction in

system size (and hence cost through a reduction in the number of panels required) actually results in

a cheaper overall system. This is not taking into account the fact that if the system is to be ground-

based, less land will be required and hence there could be even further savings.

It should be noted that since this investigation was carried out in the USA, some aspects of it will

differ when applied to Europe (specifically Spain). However, the principle behind it remains the

same, and the information is as relevant to Europe as America regarding fixed tilt and tracked

systems. It should also be noted that this only takes dual-axis tracking systems into consideration.


22

2.2.4 Sky Clarity Index

The most important factor in determining the effectiveness of a dual-axis system over single-axis is

the sky-clarity index. This is a measure of how much pollution, clouds and weather absorb, reflect or

refract the suns energy. Essentially, it is a measurement of the level of the specular or direct sun-

light available, as opposed to the diffuse sun-light available during areas of cloud-cover or pollution.

A high sky-clarity index of around 0.7 to 0.8 or above is required for dual-axis trackers to realise their

potential enough to make them feasible. Essentially, when there is a large amount of diffuse light,

such as in the case of a lower sky clarity index, regardless of whether the panel is tilted along the

second axis the majority of energy can be used. This will result in increases of only 3-4% when using

dual-axis over single-axis, not enough to justify the increase in cost and decrease in reliability.

Conversely, in areas of high-sky clarity index where there is a large amount of direct light dual-axis

systems are capable of an increase of 40-45% over a fixed roof-based system, and of up to 20% or so

over single-axis tracking systems.

Figure 17 – Clarity Index Study (Cooke, 2007)

Figure 17 shows the outcome of a study performed by Dr David Lubitz of the University of Guelph,

Ontario, in which 180 solar sites throughout North America were studied in detail to gain an

accurate picture of their sky clarity index and its effect on the annual irradiation gains of tracking

systems relative to a south facing fixed tilt system.

It can be clearly seen that as the sky clarity index increases, as do the increases in irradiance felt by

dual-axis tracking panels over single-axis, hence making them more economically viable the higher


23

the index. It can also be seen that compared with fixed angle systems, even single axis tracking

systems with no seasonal tilting offer improvements of 25-27% in the Ontario area during summer,

and 23-25% in winter, which in turn will provide a huge improvement in energy input throughout the

life-time of the system for a (relatively) small initial outlay.

2.2.5 Shading

Since Solar PV panels are connected in series as part of a larger string, a loss in power output in one

module (be it the first or last in the chain) will result in a loss of powers in the others. For this

reason, shading on PV systems can cause large drops in the overall lifetime performance of a PV

system. Some systems can get around this problem by using an inverter which will bypass a panel in

partial shading, causing losses in that panel only. None-the-less, the energy loss throughout the

lifetime of the system will still be significant.

Figure 18 shows the effect of 25%

shading (loss of 25% of illuminance)

on the power output of a PV

system. The losses in this system

account for almost a third of the

overall panel output, which if

connected to the string in series can

result in the same loss over the

entire system.

Shading is generally avoided in the system design stage. Environmental shading can be avoided to a

degree by ensuring the panels are installed in a flat area, with no surrounding trees or other tall

objects which may cause a problem.

Self-shading of panels is another issue, especially problematic in the installation of tracked PV

systems. In this scenario, the panels block each other out as the sun shadows cast by them move

with the sun throughout the day. This effect can be compounded when the panels themselves also

move. To avoid this, shading analyses must be performed to ensure the panels are spaced

appropriately.


Figure – Effect of shading on power output (Solar Edge, 2010)

24

3 The Site

The site to be considered for PV installation is situated not far from Murcia, Spain. For the purposes

of this investigation, all irradiance data has been provided by PVGIS from San Javier, Murcia

(Latitude: 37.783, longitude: -0.8).

The property is a 4 bedroom detached holiday home

containing roof space facing all direction, although this space is limited. Due to Spain being situated

in the northern hemisphere, the most ideal section of roof is south facing, of which there is an area

of 30m2, pitched at 22°. According to PVGIS, the optimum fixed slope for the site is 34°; a mount will

be used to optimise the pitch angle on the roof to maximise the system output. For the ground-

based system, there is a large nearby area flat, arid landscape stretching for miles. The area would

be ideal for a ground-based PV installation due to the flat, barren landscape reducing the risk of

shading.


The home in Murcia to be fitted with

PV is highlighted here, with the most

suitable (south-facing) roof shown.

A zoomed out birds-eye view of the area surrounding

the home. The home is shown circled in red, while

the patch of land highlighted by the red rectangles

are flat, barren and disused pieces of land which

would be suitable for PV installation.

Figure 18 – Installation Site (Google Inc.,2012)

Figure 19 – Zoomed out installation site (GoogleInc., 2012)

N

25

Temperature, humidity and wind-speed data was gathered from Tutiempo which will be used to

determine the temperature of the chosen PV cells throughout the year and hence the efficiency of

the cells. The data taken from Tutiempo is an average of recorded data from 1973 to 2012.

An average

of the sky clearness index for Murcia from the years 1983 to 2005 is shown in figure 22. As

described in section 2.2.4, this information will be useful in determining the viability of installing

dual-axis tracking systems on the site.

According to the study detailed in 4.2.4, a sky clarity index of at least 0.7-0.8+ is required to make

dual-axis tracking viable. For this reason, only single-axis tracking will be considered.


Figure 201 – Ambient Temperature, Humidity and Wind-speed (Murcia, Spain) (Tutiempo, 1973 to 2012)

Figure 212 – Average Sky Clearness Index (Kt) for Murcia (Spain-Meteo, 1983-2005)

26

3.1 Electricity Usage

Details of the electricity usage of the property have been supplied for the year 2010 however due to

the property being used as a holiday home, occupancy can be sporadic. As such, some month’s

electricity usage is vastly higher than others (figure 23).

The average electricity usage per month is 827.17kWh, and the system will be designed with the aim

of providing 75% of this value in March.


January

Febru

aryMarc

hApril

MayJune

July

August

Septem

ber

October

November

December

Averag

e0

500

1000

1500

2000

2500

Elec

trici

ty U

sed

(kW

h)

Figure 22 – Electricity usage per month

27

4 Methodology

4.1 Terms

Ig - Global irradiation (W/m2)

Id - Diffuse irradiation (W/m2)

Ib - Beam irradiation (W/m2)

Ir – Reflected irradiation (W/m2)

Tc – Temperature of the PV cells (°c)

Ta – Ambient air temperature (°c)

Gt – Tilt Irradiance (W/m2)

τ – Transmittance of anything covering the cells (No units, ratio)

α – Fraction of radiation incident on the surface of the cells that is absorbed (No units, ratio)

ηc – Efficiency of the module in converting incident radiation to electrical energy (No units,

ratio)

4.2 Formulae

I g=I d+ I b+ I r

Equation 1 – Calculation of hourly global irradiation

Cell Temperature=T c=T a+(GT τα

U L

)(1−ηc

τα)

Equation 2 – Calculation of cell temperature


28

4.3 Method

Irradiation from the sun is found in four forms:

Ig: Global irradiation - The total irradiation on a surface.

Id: Diffuse irradiation – The indirect irradiation on a surface cause by scattering of direct

irradiation due molecules and particles in the atmosphere.

Ib: Beam irradiation – The direct irradiation on a surface.

Ir: Reflected irradiation – The irradiation on a surface from beam irradiation reflected from

the ground and other surroundings.

These are linked using the following equation: I g=I d+ I b+ I r

Figure 24 shows the steps to obtaining the irradiation required; the initial daily horizontal global irradiance is obtained from PVGIS (Institute for Energy and Transport (IET), 2012).


Figure 23 – Irradiation calculation steps

29

Once the hourly slope irradiance on the surfaces has been calculated, the temperature and wind-

speed data from Tutiempo (Tutiempo, 1973 to 2012) can be used to calculate the temperature of

the PV cells (Tcell). To do this, equation 23.3.3 from Solar Engineering of Thermal Processes was used

(Duffie & Beckham, 1991, p. 780), shown below.

T c=T a+(GT τα

U L

)(1−ηcτα

)

The ratio of τα/UL can be found using:

ταUL

=T c , NOCT−T a , NOCT

GT , NOCT

where the values of Tc, Ta and GT are at the normal operating cell temperature (NOCT). According to

Aldali et al., “This is defined as the cell or module temperature that is reached when the cells are

mounted in their normal way at a solar radiation level of GT = 800W/m2, a wind-speed of 1m/s, an

ambient temperature of 20°c and no-load operation (module efficiency ηc = 0).”

The tracking proposed tracking system for the site is single axis and tracks the suns movement along

the north-south axis. This allows the surface to be moved to the optimum tilt angle for each given

day of the year, maximising output.


Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Year0

1000

2000

3000

4000

5000

6000

7000

8000

Horizontal Irradiation (Ih,W/m2/day) Optimal Irradiation (Iopt,W/m2/day)

Figure 25 – Horizontal and optimum slope irradiation (Institute for Energy and Transport (IET),2012)

30

5 Daily Global Irradiation

The first step in this investigation was to gather irradiance data for the site, which was obtained from

the European Commission’s database for solar resource and photovoltaic potential (Institute for

Energy and Transport (IET), 2012), whose data is supplied by NASA. As the wind-speed, humidity and

temperature data was taken from San Javier airport in Murcia, the irradiance data has also been

taken from here.

At a distance of 17km the

environmental conditions will

not vary enough to have a large

impact on the outcome of the

investigation.

The optimum fixed slope at this location Is 34° although the output of a fixed system can be

improved through seasonal adjustments; adjusting the tilt of the system twice per year, once at the

winter solstice and once at the summer solstice.


Figure 24 – Distance from data collection site to installation site(Institute for Energy and Transport (IET), 2012)

17km

31

6 Hourly Global Irradiation

6.1 Terms

Ig – Hourly global irradiation (W/m2)ω – Hour from solar noon (Hours)ωs – Day-length (Hours)rG – Ratio of hourly to daily global irradiation (No units, ratio)

6.2 Formulae

rG=π24

(a'+b 'cosω)cosω−cosωs

cosωs−ωs cosωs

Equation 3 – Ratio of hourly to daily global irradiation (Muneer, et al., 2000)

6.3 Method

Muneer’s model (Muneer, et al., 2000, pp. 95-98) for analysis of irradiance has been used to convert

the average global irradiation per day of each month to hourly values. This was done using the

program providing in Windows in Buildings, Calc.4.0.9. For the purposes of these steps, the

horizontal values for global irradiation have been used, as the slope angle will be considered later.

As the calculations are time-consuming, analysis of irradiation has been performed for the middle

day of each month (16th of January, 14th of February etc) as this will give the most accurate

representation of the actual irradiance while drastically reducing the computations required.

Since the irradiance data provided by PVGIS is given in the format of average global irradiation for

each month, this must first be broken down into hourly values; Muneer et al. provide a method for

doing so. Muneer’s literature is aimed at the analysis of windows in building design, but many of the

same concepts apply and can be used in the case of photovoltaics.


32

Muneer cites the work of Whillier (1956), Liu and Jordan (1960) and Collares-Pereira and Rabl (1979)

as the key work in this field. The ratio of hourly to daily global irradiation can be calculated using:

rG=π24


cosωs−ωs cosωs

which was presented by Liu and Jordan (1960), where:a '=0.409+0.5016sin (ωs−1.047)

b '=0.6609+0.4767sin (ωs−1.047)

ω=Hour ¿ solarnoon

ωs=Day−length(hours)

Using this equation, the ratio of hourly to global irradiation is obtained, which can then be used to

convert the monthly-averaged daily irradiation values given by PVGIS into hourly values.

An equivalent method for calculating the hourly diffuse irradiation is provided, but is not needed

here.


Figure 26 – Calc.4.0.9 (Muneer, et al., 2000)

33

6.4 Results

The hourly horizontal global irradiation values for each month are shown in figure 28. As expected,

in the summer months (May, June, July and August) starting at 5am the irradiance increases

throughout the day, peaking at around midday, before falling again until it reaches zero at 6pm.

Irradiance isn’t felt on the horizontal until later in the day during other months, due to the sun being

closer to the horizon and hence not rising as high in the sky. The maximum irradiation on the

horizontal surface occurs in July, while the lowest occurs in December.


Figure 27 – Monthly-averaged horizontal daily global irradiation converted to hourly global irradiance

34

7 Hourly Diffuse Irradiation

7.1 Terms

Id – Hourly diffuse irradiation (W/m2)Ig – Hourly global irradiation (W/m2)Ie – Hourly extra-terrestrial irradiation (W/m2)DN – Day-number of the year (i.e. 14th of January = 14, 3rd of February = 34 etc.)SOLALT – The elevation angle of the sun from the horizon (°)Kt – Hourly Clearness Index (no units, ratio)

7.2 Formulae

I dI g

=1.006−0.371K t+3.1241K t2−12.7616K t

3+9.7166K t4

Equation 4 – Ratio of global to diffuse irradiation (Muneer, et al., 2000)

K t=I gI e

Equation 5 – Hourly sky clearness index (Muneer, et al., 2000)

I e=1367 [1+0.033cos (0.0172024DN ) ] sin (SOLALT )

Equation 6 – Extra-terrestrial Irradiation (Muneer, et al., 2000)

7.3 Method

The program provided by (Muneer, et al., 2000), Calc.4.0.8, was used to convert the hourly global

irradiation values into diffuse irradiation values. This program uses the ratio of global to diffuse

irradiation and its connection to the sky clearness index to calculate the diffuse irradiation.

I dI g

=1.006−0.371K t+3.1241K t2−12.7616K t

3+9.7166K t4

Since we know the hourly global irradiation and the sky clearness index can be estimated using the

equation:

K t=I gI e

Extra-terrestrial irradiation (Ie) is the solar irradiation directly outside the Earth’s atmosphere, it

remains relatively constant, but varies dependant on the solar altitude and day-number. It is given

by:


35


This allows calculation of Ie using site data for a given day, calculation of Kt and hence calculation of Id

by re-arranging equation 4 to give:

I d=(1.006−0.371K t+3.1241K t2−12.7616K t

3+9.7166K t4) I g


Figure 28 – Calc4.0.8 (Muneer, et al., 2000)

36

7.4 Results

Figure 30 shows the hourly diffuse irradiation values as calculated using calc.4.0.8. As shown, the

diffuse irradiation is much less predictable than the global irradiation. This is due to the dependency

of Id on Kt. The diffused irradiation is the indirect radiation on a surface caused by the break-up of

direct beam irradiation due to pollutants, particles and molecules in the atmosphere. As such, it is

highly dependent on the atmosphere, which changes over time. Due to the calculation for Ie, and

hence Kt not changing in a linear fashion throughout the year, Kt fluctuates in a similarly non-linear

way, resulting in some days a times having a higher or lower Kt value, and from that a higher or

lower Id. In reality, as Kt is so heavily dependent on a number of factors from pollutants in the air to

cloud cover on a given day, it is a difficult figure to assess accurately, and may fluctuate wildly from

one day of the year to the same day the year after.


Figure 29 – Hourly Diffuse Irradiation per month

37

Figure 31 shows an average of the sky clearness index as calculated using equations 5 and 6. As

shown, the calculated values for Kt average at 0.33 per year. This is compared with an average of the

recorded values shown in section 6, taken over a 22-year period (Spain-Meteo, 1983-2005).

As a result of

the Kt used being much lower than the actual, recorded value, it is likely that the diffuse irradiation

values calculated are higher than they would be in real life as a result of particles in the atmosphere

to scatter beam irradiation; this will also result in the beam irradiation likely being higher.


Figure 30 – Average computer sky clearness index

38

8 Slope Irradiance

8.1 Terms

Gt – Hourly slope irradiation (W/m2) Ig – Hourly global (total) irradiation (W/m2) Id,tlt – Hourly diffuse irradiation on a tilted surface (W/m2) Ib,tlt – Hourly beam irradiation on a tilted surface (W/m2) Iref,tlt – Hourly reflected irradiation on a tilted surface (W/m2) SOLALT - The elevation angle of the sun from the horizon (°) θ – Angle of Incidence of the sun’s rays (°) ρ – Albedo (No units, ratio) β – Tilt Angle of the surface (°) ϒ – Surface azimuth angle (°) φ – Site Latitude (°) ω – Solar hour angle (°) δ – Solar Declination (°)

8.2 Formulae

Gt=I b ,TLT+ I d ,TLT+ I ref ,TLT

Equation 7 – Slope Irradiation (Muneer, et al., 2000)

IB, TLT=IB rB

Equation 8 – Tilted beam irradiation on a fixed slope (Muneer, et al., 2000)

r B=max [0 ,cos (θ)/sin (SOLALT )]

Equation 9 – Ratio of angle of incidence to solar altitude (Muneer, et al., 2000)

I ref ,TLT=ρ∗I g∗sin ¿

Equation 10 – Reflected Irradiance (Muneer, et al., 2000)

I b=I g−I d

Equation 11 – Beam Irradiance (Muneer, et al., 2000)

β=tan−1[ cosδsinωsinϕsinδ+cosϕcosδcosω ]

Equation 12 – Slope Plane (N-S Tracking) before noon (Aldali, et al., 2011)

β=tan−1[ −cosδsinωsinϕsinδ+cosϕcosδcosω ]

Equation 13 – Slope Plane (N-S Tracking) after noon (Aldali, et al., 2011)


39

cosθ=[(sinϕsinδ+cosϕcosδcosω)2+cos2 δ sin2ω ]1/2

Equation 14 – Angle of Incidence (N-S Tracking) (Aldali, et al., 2011)

ω=[(12−hour )∗15 ]

Equation 15 – Solar hour angle

I b ,TLT=cosθ

sinSOLALT∗I b

Equation 16 – Tilted beam irradiance on a moving slope

8.3 Method

8.3.1 Fixed & Seasonal Tilting

Now that the hourly global and diffuse irradiation has been calculated for each hour of the middle day of each month on a horizontal surface, the hourly slope irradiation can be calculated. This is the irradiance on a tilted surface per hour.

For the fixed system, Calc.4.10 is used to determine the slope irradiation from Id and Ig. This program makes use of solar geometry to convert the slope and global irradiation on the horizontal to global and diffuse on a pitched slope; it also calculates the reflected irradiation by using a ground albedo (the amount of irradiance a surface will reflect) specified by the user. For the purposes of these calculations, a ground albedo of 0.6 has been used as the area is surrounded by light-coloured brick and soil.

The slope irradiation for the system utilizing tilting to the optimum angle for each half of the year (at the summer and winter solstices) is calculated using the same method, using different values for the solar inclination and tilt angle for each half of the year. The optimum angles for each part of the year have been calculated using two methods, detailed in the appendices (18.3.2).

The beam irradiation on the horizontal can be easily calculated using:

I b=I g−I d

From this, equation 8 can be used to calculate the beam irradiation on a tilted surface:

IB, TLT=IB rB

Where:

r B=max [0 ,cos (θ)/sin (SOLALT )]

The sloped diffuse irradiation is more complex to calculate as a result of its behaviour being more unpredictable. Since it is caused by the scattering of beam irradiance as it moves through particulates in the atmosphere, it is anisotropic in nature, moving independently in all directions. This makes it very difficult to calculate. Cited by Muneer are Moon and Spencer (1942) who used


40

measured data to demonstrate the anisotropic nature of the luminance distribution of overcast skies.

Muneer has developed a model (Saluja and Muneer, 1987) which has (for the sake of simplicity) been used here to obtain the slope diffuse irradiation; see (Muneer, et al., 2000, pp. 110-111) for more information on this subject.

The reflected irradiation is then calculated using equation 10:


Finally, the 3 irradiation values are added to give the total slope irradiation at a given hour:


8.3.2 Tracking

The slope irradiation for the tracking system has been estimated using a different method. The first

step is to calculate the angle of incidence and slope plane per hour.

The tracking system being evaluated is rotated about a horizontal North-South axis, and adjusted

continuously so that the direct solar beam makes the minimum angle of incidence with the modules

at all times. The surface azimuth angle (ϒ) = +90° before noon and -90° after noon.

First, the angle of the surface from horizontal is calculated at each hour. This can be calculated using

the equations below.

Before noon:

β=tan−1[ cosδsinωsinϕsinδ+cosϕcosδcosω ]

After noon:

β=tan−1[ −c osδsinωsinϕsinδ+cosϕcosδcosω ]

Next, the angle of incidence of the sun’s rays on the surface of the modules per hour is calculated:

cosθ=[(sinϕsinδ+cosϕcosδcosω)2+cos2 δ sin2ω ]1/2

The hour angle is calculated using:

ω=[(12−hour )∗15 ]


41

where the hour is the mid-point of the hour (i.e. 5.5 for the hour between 5am and 6am). The solar

declination (δ) was found using Calc.4.10.

Once the angle of incidence and tilt angle have been calculated per hour, the horizontal beam

irradiation per hour must be calculated using:

I b=I g−I d

From which the sloped beam irradiation can be calculated using:

I b ,TLT=cosθ

sinSOLALT∗I b

At this stage, the sloped diffuse and reflected irradiation should be calculated, but due to the

complexity of calculating these values accurately hour by hour, they have been estimated. The

values for diffuse irradiation on the horizontal have been used, and the reflected irradiance was

estimated by taking 10% of the sum of the beam and diffuse irradiation. The value of 10% was

acquired by taking an average of the ratio of reflected to global irradiation calculated using

Calc.4.10, which for the entire year was slightly over 10%.

The final step is to calculate the slope irradiation per hour:



42

8.4 Results

As expected, the system utilising single-axis tracking

can capture more of the sun’s energy over the

course of the year than the other two systems,

although the increase is not as large as expected.

Shown in figure 33, the single-axis system has access

to 19.91% more irradiance than the fixed system,

while the seasonal system only sees 2.1% more. The

tracking system that has been proposed maximises

the beam irradiance on the surface and allows the beam irradiance to be felt much earlier in the day,

so it is expected that in summer when there is a larger amount of beam irradiance it will capture

much more energy than the other two systems. It is surprising that the seasonally tilted system is

exposed to only marginally more irradiance than the fixed system, although this may be due to the

relatively low percentage of annual irradiance which occurs in the summer in Spain. According to an

article by Green Rhino Energy (Green Rhino Energy, 2011), seasonal tilting is most effective in areas

where the majority of irradiance is experienced in the summer (e.g. Germany, where 75% is


Figure 32 – Total Annual Irradiance by %

Figure 31 – Total Daily Irradiation

43

experienced between April and September). In Spain, summer irradiance only accounts for roughly

60% of the annual.

Figure 34 shows the irradiance on each surface throughout the 15th of June. As expected, the single-

axis system outperforms both systems throughout the day, with the tilt allowing the irradiation to

interact with the surface at a much earlier time of day.

The

maximum irradiance occurs between 11 and 12pm on all systems, with the fixed and seasonal

systems exposed to around 850W/m2 and the single-axis system exposed to just over 900W/m2.


Figure 33 – Comparison of PV system slope irradiation - June

44

As expected, in December the difference is much less pronounced, with the main increase from the

single axis system coming from its higher early morning exposure to irradiance. Shown in figure 35,

the irradiance on the seasonal plane is actually higher than the tracking system; in reality, a properly

designed tracking system will be at the optimum tilt angle for that day, and so will produce at-least

the same as the seasonal adjustment system. This inaccuracy must be caused by an error in the

calculations.

9 Panel Selection

As described in section 2.2.1, a number of panel types have been analysed. The most suitable type

found are Sanyo HIT panels, which combine the high efficiency of mono-crystalline panels with the

excellent high temperature performance of amorphous panels. The two main parameters looked at

during selection are:

Wp – Watt-peak rating, the nominal power of the module at laboratory test conditions, in

this case air mass of 1.5, irradiance = 800W/m2, air temperature = 20°C , wind speed 1 m/s

and NOCT = 44°c.

Module and cell efficiency.

Sanyo offer two variety of HIT panel:

HIT-250E01 – 250Wp, 20.8% cell efficiency and 18.0 module efficiency

HIT-245E01 – 245Wp, 20.4% cell efficiency and 17.7 module efficiency

The 250Wp panels have been selected, as there is limited roof-space available at the property, thus

maximising module output and efficiency will be important to ensure the system covers as much of

the properties electricity usage as possible.

The data sheet for the selected panels can be found in the appendices (section 17.4).


45

10 Power Output

10.1 Terms

Tcell – Cell-temperature under set conditions (K)Tc,NOCT – Cell-temperature at reference conditions (K)Ta – Ambient temperature (K) Gt – Slope Irradiance (W/m2)τ – Transmissivity of the module surface (No units, ratio)α – Absorptivity of the module surface (No units, ratio)ηm – Module efficiency at set conditions (No units, ratio) ηmp,ref – Maximum power point efficiency at reference conditions (No units, ratio) ηe – Efficiency of any power conditioning equipment (No units, ratio) μmp – Temperature co-efficient of MPPT efficiency (%/°c)Pi – Power output (W)Ac – Module area (m2)

10.2 Formulae

T cell=T a+(Gt∗τα

U L)∗(1− ηc

τα )Equation 17 – Cell Temperature at a given hour (Duffie & Beckham, 1991)

ηm=ηmp , ref∗(1− [Tc , NOCT−T cell ]∗μmp100 )

Equation 18 – Module efficiency if Tcell is above NOCT

ηm=ηmp , ref∗(1− [−Tc , NOCT−T cell ]∗μmp

100 )Equation 19 – Module efficiency if Tcell is below NOCT

Pi=Ac∗GT∗ηmp∗ηe

Equation 20 – Power output per module (Duffie & Beckham, 1991)


46

10.3 Method

The power output of each of the systems has been calculated using the following method.

First, the temperature of the PV cells at each hour must be calculated:


U L)∗(1− ηc

τα )With the cell temperature at each hour throughout the year, the efficiency of the modules at the

conditions of that hour is calculated using:

ηm=ηmp , ref∗(1− [Tc , NOCT−T cell ]∗μmp100 )

If the cell-temperature is above the NOCT (44°c) and:


100 )If the cell-temperature is below the NOCT.

Finally, the power output per module for that hour is found by:

Pi=Ac∗GT , i∗ηmp∗ηe


47

10.4 Results

The total annual power output of each of the systems is shown below:

Fixed angle – 390.4kWh/module

Seasonal adjustment – 397.51kWh/module

Single-axis tracking – 467.19kWh/module

As

expected, the PV system utilizing single-axis tracking outperforms both other systems, producing

19.67% more energy than the fixed system. Somewhat surprisingly, the system using seasonal

adjustments only produced 1.82% more energy per year than the fixed system. According to an

online study (Green Rhino Energy, 2011) this is likely due to a relatively small fraction of Spain’s total

annual irradiance occurring in summer.


Figure 36 – Power output by %

Figure 35 – PV System Total Annual Output

48

It can be seen that the difference between the powers generated by the systems is at its lowest

point in the winter months, with only a minor amount of extra electricity generated using the

tracking system. In the summer months, however, the difference becomes more pronounced, with

the tracking system producing significantly more electricity than either the fixed or seasonal

adjustment system. This is due to the height and motion of the sun in the summer months. In

summer the sun rises earlier and has a larger range of motion in the sky, thus the benefits from a

constantly optimised tilt are more pronounced.

Due to the extremely minor increases in output by making use of seasonal adjustments, the remainder of this report will focus solely on the use of single-axis tracking and fixed arrays.


Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec0

20

40

60

80

100

120

140

160Tracking Seasonal Fixed

Mon

thly

pow

er o

utpu

t (kw

/m2)

Figure 37 – Average monthly power output

49

11 System Sizing

The aim of the system is to provide 75% of the average monthly electricity requirement in March.

The average monthly electricity used by the property is 827.17kWh, so the system must be capable

of producing roughly 620kWh in March.

The monthly power output in March per module of the fixed and tracking system is 34kWh and

39.5kWh, respectively.

Number of modules required(¿)= UnitsrequiredUnits per module

= 62029.4

=21.09

Number of modules required( tracked)= Units requiredUnits permodule

= 62034.2

=18.13

And at 2.5Wp (Watt-peak) per module:

System¿(¿ , k W p¿)=Number of modules∗Module rating

1000=21.09∗250

1000

¿5.273kW p

System¿(tracked , kW p¿)=Number of modules∗Module rating

1000=18.13∗250

1000

¿4.53 kW p

So using tracking, to meet the electrical requirements of the property a 4.5kWp system will be

required, using 18 modules. At a fixed slope the system would need to be 5.25kWp, which will be

rounded to 4.5kWp, requiring 21 modules. In both cases, the systems will produce slightly less

energy than is required, but adding another panel would add additional cost and produce a large

amount of excess energy.


50

12 System Performance

12.1 Assumptions

Now that the system sizes are known, the electricity output and financial performance of the

systems can be calculated.

For these calculations the following assumptions have been made:

A drop in power output of 1% per year.

A 20 year system life-time.

Hardware Cost:

o Tracking – £14,150.

o Fixed - £16,500.

Mounts and wiring:

o Tracking - £5,660.

o Fixed - £3,300.

Installation:

o Tracking – £9,905.

o Fixed - £9,900.

Total Cost:

o Tracking - £29,715.

o Fixed - £29,700.

Feed-in tariff:

o Tracking (free-standing) – €0.32/kWh.

o Fixed (building integrated) – €0.34/kWh.

Maintenance costs (Jacobi & Starkweather, 2010):

o Tracking (free-standing) – €202.50/year.

o Fixed (free-standing) - €189/year.

Electricity cost of €0.18/kWh.

Annual currency inflation of 2.5% (Trading Economics, 2012).

Annual electricity price inflation of 3%.

Due to sporadic occupancy patterns, income from selling excess electricity back to the grid

has been neglected.


51

Details of the calculations can be found in the appendices (16.5 and 16.6).

12.2 Findings

It can be seen that in the summer months, the tracking system has a larger output, while the fixed

system produces more electricity in the winter months. Over the life-time of the system, the

tracking system produces slightly more electricity; 132515kWh compared to 129189.3kWh for the

fixed, building integrated system.

The total initial costs of the systems are also similar; despite fixed systems generally being cheaper in

terms of hardware, installation and maintenance, the increase in size of the system to match the

output of the tracking setup results in virtually identical initial outlay and only slightly reduced

maintenance costs per year (€189 per year for the fixed system, €202.50 for the tracking system).

The systems pay their initial costs back in a similar amount of time (tracking: 11.51 years, fixed:

10.93 years).


Figure 38 – Total 20-year electricity production

Figure 39 – System Payback (years)

52

13 Conclusions

As a result of the Kt used being much lower than the actual, recorded value, it is likely that

the diffuse irradiation values calculated are higher than they would be in real life as a result

of less material in the atmosphere to scatter beam irradiation; this will also result in the

beam irradiation likely being higher.

According to an online study (Green Rhino Energy, 2011), the effectiveness of adjusting the

tilt angle seasonally is dependent on the percentage of total annual irradiance which is felt in

the summer; the higher the percentage of irradiance occurring in summer, the more

effective such a system will be. They state that on average in Spain 60% of annual irradiance

occurs in summer, which makes seasonal adjustments less effective than in Germany where

summer irradiance accounts for 75% of the total. Figure 41 shows the percentage of

irradiance occurring in summer and winter at the site, with 67.46% occurring in summer.

This seems to contradict the online study, as the difference between the fixed and

seasonally tilted system was only 2.1%. There may be other problems with the calculations

leading to this discrepancy, as it is expected that the difference would be higher with this

level of irradiance occurring in the summer.

Although fixed systems are generally seen as being cheaper than tracked, due to the

increase in system size required to produce a relatively similar output, the costs are roughly


Figure 40 - % of global irradiance occurring seasonally

53

the same. As a result of the increase in size, it seems one of the main factors in whether a

tracked system should be used is if space is a concern, thus maximising output per m2 will be

essential.

The fixed system will pay-back in a slightly shorter amount of time than the tracking system

(10.93 vs 11.51 years), however due to the increase in energy output after the systems have

paid back, a much higher profit will be generated through incentives using the tracked

system, and a larger portion of the electricity demand will be provided.

An area of 24.95m2 is required for the building-integrated, fixed system. With an available

roof area of 30m2, this is potentially suitable. However, with the lack of space separating the

panels, shading could become a problem, diminishing the output of the modules.


54

14 Recommendations

The system recommended for installation on the site is a free-standing system utilizing single-axis

tracking. In comparison to a building-integrated, fixed slope system, the tracking system will only

cost marginally more to implement, but provide a much greater energy output throughout the life-

time of the system. Another reason for the implementation of the free-standing system is the

potential for expansion. The area surrounding the site is populated by a large number of homes,

populated largely by retirees. As a result of the increasing energy prices in Spain, the possibility of

having access to a free and natural source of energy may be an attractive prospect to many. It may

be a possibility to indicate to the nearby population the benefits of implementing such a system,

with the aim of encouraging people to consider the possibility of a solar PV system to power their

homes.

In this way, the system could be expanded to provide power to a large number of nearby homes,

decreasing the overall cost per installed kWp. For example, a 50kWp system could provide energy to

roughly 11 homes, providing an income of roughly €65,000 per home over the life-time of the

system, and costing in the region of €5000 per kWp, compared to €8000 for the smaller, single home

system.


55

15 Future Work

Future work to be considered:

Calculation of output from a system using dual-axis tracking, and comparison of that system

with both the single-axis and fixed systems.

Comparison of current system economic performance with the performance before the

Spanish feed-in cuts.

Calculation of CO2 savings as a result of the system.

Comparison of the economic performance of the system with that of a similar system in a

leading European solar nation.

Design of a larger scale, 50kWp+ system to power a larger number of homes in the area.


56

16 Appendices

16.1 Hourly Global Irradiation

First, the ratio of hourly to daily global irradiation is calculated:

rG=π24


cosωs−ωs cosωs

a '=0.409+0.5016sin (ωs−1.047)

b '=0.6609+0.4767sin (ωs−1.047)

rG=π24

([0.409+0.5016 sin (ωs−1.047 )]+[0.6609+0.4767sin (ωs−1.047 )]cosω)cosω−cosωs

cosωs−ωs cosωs

Where: ω = hour from solar noon and ωs = Day-length

For the purposes of this calculation, the day-length is taken at a set 12 hours while solar noon is

taken as 12pm (midday). In reality (and in Calc.4.0.9), solar noon is the time of the day at which the

sun is highest in the sky, and will vary throughout the year.

For example, at 8am (4 hours from solar noon):

rG=π24

([0.409+0.5016 sin (12−1.047 )]+[0.6609+0.4767sin (12−1.047 ) ]cos 4) cos4−cos12cos12−12cos12

¿ π24

([0.409+0.5016sin (10.953 )]+[0.6609+0.4767 sin (10.953 ) ]cos 4) cos 4−cos12cos 12−12co s12

¿ π24

(0.5043+0.7496) 0.9986−10.76

¿ π24

(1.2539 )−0.0928

¿ π241.1611

rG=π241.1611=0.152


57

So, at 8am with a 12 hour day-length, the ratio of hourly to daily global irradiation is 0.152:1. This allows the

irradiation at that hour to be simply calculated from the daily global irradiation provided by NASA (Institute for

Energy and Transport (IET), 2012). For example, taking 2.05kW/m2 as the total global irradiation that day:

2.05∗0.152=0.3116 kW /m2=311.6W /m2

16.2 Hourly Diffuse Irradiation

The first step in the calculations is to use equation 6 to calculate the extra-terrestrial irradiance on a given day.


For example, at between 12pm and 1pm on the 16th of January (day-number = 16 and Solar altitude = 30.8°):

I e=1367 [1+0.033cos (0.0172024∗16 ) ]sin (30.8 )=723.061W /m2

With the extra-terrestrial irradiance calculated, Kt can be calculated using the ratio of global to extra-terrestrial irradiance (equation 5):

K t=I gI e

=314.713723.061

=0.435

The ratio of global to diffuse irradiance is then calculated (equation 4):

I dI g

=1.006−0.371 (0.435 )+3.1241 (0.4352 )−12.7616 (0.4353 )+9.7166 (0.4354 )

¿1.006−0.161+0.591−1.05+0.348=0.7338

And finally, from re-arranging equation 4, the hourly diffuse irradiation is calculated:

I dI g

=0.7338=I d

314.713

I d=0.734∗I g=0.734∗314.713=230.94W /m2

Note that this differs slightly from the value computed using Calc4.0.8 (238W/m2) as the program

does not round values to decimal points, giving a more accurate outcome.


58

16.3 Hourly Slope Irradiation

16.3.1 Fixed and Seasonal Calculation

Taking the hour between 12 and 1pm of January 16th (note θ and SOLALT must be in radians):

r B=max [0 , cos (θ )sin (SOLALT ) ]=max [0 ,

cos (0.449 )sin (0.539 )

]=1.755

Ib, TLT can be calculated using:

IB, TLT=IB rB

Where:

IB=I g−I d=315−238¿77W /m2

IB, TLT=77∗1.755¿135.15W /m2

The calculation for Id, TLT is not

shown due to its complexity, but is

given as 239 using the program

provided by Muneer.

The reflected irradiation on the

tilted surface is then:


At the optimum tilt angle of 34° and using an albedo of 0.6:

I ref ,TLT=0.6∗315∗sin ¿

Finally, the slope irradiation is calculated for the hour:

I slope=135.15+239+9.503=383.653W /m2


Figure 41 – Calc.4.10 (Muneer, et al., 2000)

59

16.3.2 Seasonal Optimum Tilt

Two methods have been used to calculate the optimum tilt angle for each season. The first is a trial

and error approach, using Calc.4.10 to find the optimum slope of each individual month. Note that

taking an average of all 12 months yields a result of 34.08°, the same as the optimum annual tilt

provided by PVGIS. The difference between that month’s optimum slope and the annual optimum

of 34° is then calculated, with those months whose optimum tilt is above 34° benefitting from using

the relatively high winter optimum tilt, and those months whose optimum is below 34° benefitting

more from the lower summer tilt angle.

Finally the optimum seasonal tilt is calculated by taking an average of the optimum tilt for each

month that falls within that season. In this case, October to March is optimised for the winter angle

(51°), while April to September is optimised for the summer tilt angle (14°).

This information was backed up by using equations provided by MACS Lab (MACS Lab, Inc., 2012),

which calculate the optimum tilt angles of each season for latitudes between 25° and 50° using:

SummerOptimumTilt=(Latitude∗0.93)−21

WinterOptimumTilt=(Latitude∗0.875 )+19.2

Using this methods the calculated angles were 17° for summer and 52° for winter. By comparison,

17° provided more irradiation in summer, and 51° provided more in the winter, so these values have

be used.

16.3.3 Tracking

Again taking the hour between 12pm and 1pm on January 16th:

First, the hour angle is calculated:

ω=[ (12−12.5 )∗15 ]=−7.5°=−0.1309 rads

Since it is after noon:


60

β=tan−1[ −cosδsinωsinϕsinδ+cosϕcosδcosω ]

¿ tan−1[ −cos−0.368sin−0.1309sin 37.783sin−0.368+cos 37.783cos−0.368cos−0.1309 ]

¿ tan−1 0.1218−0.0303+0.9217

=0.136 rads=7.79 °

The angle of incidence from the sun can then be calculated using:

cosθ=[(sinϕsinδ+cosϕcosδcosω)2+cos2δ sin2ω ]12

¿ [(sin 37.783 sin−0.368+cos37.783cos−0.368cos0.136)2+cos2−0.368 sin20.136 ]12

¿−3.9351∗¿

¿0.4517 rads=25.881 °

Now that the angle of incidence is known for the hour, the horizontal beam irradiation is calculated

using:

I b=I g−I d=314.7133−238.063=76.6503W /m2

Using the angle of incidence and the beam irradiation, the beam irradiation on the tilted slope can

be calculated using the value of solar altitude obtained from Calc4.10:

I b ,TLT=cosθ

sinSOLALT∗I b

¿ cos0.4517sin 0.539

∗76.6503=134.358W /m2

And lastly the slope irradiation can be calculated, with the value for

I d , TLT=I d

And:

I ref ,TLT=(I b ,TLT+ I d ,TLT )∗0.1

I slope=I b ,TLT+ I d ,TLT+ I ref ,TLT=I b , TLT+ I d+[ ( I b ,tlt+ I d )∗0.1]


61

¿134.358+238.063+ [ (134.358+238.063 )∗0.1 ]

¿409.6631W /m2


62

16.4 Sanyo HIT-250E01 Data Sheet

This data sheet is provided courtesy of Sanyo (Sanyo Electric Co., Ltd., 2012).


63


64

16.5 Power output

The power output of each of the systems has been calculated using the following method.

First, the temperature of the PV cells at each hour must be calculated:


U L)∗(1− ηc

τα )With the cell temperature at each hour throughout the year, the efficiency of the modules at the

conditions of that hour is calculated using:

ηm=ηmp ,ℜ f∗(1− [T c , NOCT−T cell ]∗μmp

100 )if the cell-temperature is above the NOCT (44°c) and:


100 )if the cell-temperature is below the NOCT.

Finally, the power output per module for that hour is found by:

Pi=Ac∗GT , i∗ηmp∗ηe

16.6 Economics

16.6.1 Hardware Cost

The cost of the hardware for each system has been estimated using an online quote (Renewable

Savings, 2012). This quote gives the price (£12,550) of a 4kWp system using Sanyo HIT-H250E01 (x16)

panels, including inverters. The price of the system per module was calculated:

Systemcost permodule= System costNumber of modules

=1255016

=£784.38 /module

This cost was then added to the 4kWp system cost to get an estimate cost for each system:

Hardware cost=4kW p systemcost+ (extramodules∗cost per module )

¿with 21modules=12550+¿


65

Tracki ngwith 18modules=12550+¿

As these values are only estimated, they were rounded up to £16,500 and £14,150 respectively.

The cost of mounts and wiring was assumed at 20% of the initial hardware cost for the fixed system

and 40% for the tracked system (due to the increased price of tracking mounts).

¿=16500+(16500∗0.2)=£19,800

Tracking=14150+(14150∗0.4)=£ 19,810

The cost of installation of the panels has been assumed at 50% of the total initial cost:

Total initial cost (¿)=19800+(19800∗0.5)=£29,700

Total initial cost (tracking)=19810+(19810∗0.5)=£ 29,715

These values were then converted to euros at a rate of 1:1.203 (XE, 2012).

Total initial cost (¿ )=£29,700=€ 35,729

Total initial cost ( tracking)=£ 29,715=€ 35,747

16.6.2 Maintenance Cost

The next consideration was the cost of maintenance per year. An online document (Jacobi &

Starkweather, 2010) was used to estimate the cost of maintenance per year for each system.

O&M Costs ($/kW-year) Fixed-tilt (c-Si) Single-axis Tracking c-Si

Scheduled

Maintenance/Cleaning

$20 $30

Unscheduled Maintenance $2 $5

Inverter Replacement $10 $10

Subtotal $32 $45

Insurance, property taxes and

owner’s cost

$15 $15

Total $47 $60

Table 2 – Operation and Maintenance Costs (Jacobi & Starkweather, 2010)


66

The data from table 2 was used to calculate the maintenance costs per year for each system.

AnnualMaintenanceCost (¿ )=CostkW

∗kW=47∗5.25=$246.75

AnnualMaintenanceCost ( tracking)=CostkW

∗kW=60∗4.5=$ 270

These were then converted to euros at a rate of 1:0.7618 (XE, 2012).

AnnualMaintenanceCost (¿ )=246.75∗0.7618=€ 187.97

AnnualMaintenanceCost ( tracking)=270∗0.7618=€ 205.69

16.6.3 Payback

The income of the system was calculated next. This “income” takes into account the actual income

from feed-in tariffs (€0.34/kWh for the fixed system, €0.32/kWh for the tracking system (Wikipedia,

2012)), the value of the electricity produced at €0.18/kWh (so the money saved in not grid-importing

it (European Commission - Eurostat, 2011)), currency inflation at 2.5% per year (Trading Economics,

2012) and electricity cost inflation at 3% per year (assumed).

For the fixed system:

Income¿ feed−¿tariff= (annual electricity production∗0.34 )∗1.025

Value of electricity=(annual electricity production∗0.18 )∗1.025∗1.03

Total income per year=¿

(annual electricity production+ Income¿ free−¿ tariff )−maintenance costs

These values are calculated every year for 20 years, and the cumulative income over that time is

noted. The year of pay-back can then be visually seen on the spread-sheet as the year in which the

cumulative income surpasses the initial outlay, and is calculated more accurately by dividing the

difference between the cumulative income of the payback year and the initial cost by the difference


67

between the cumulative income of the payback year and the cumulative income the following year,

and adding the answer to the payback year:

Pay−back time ( years )

¿ Difference between payback year cumulative income∧initial costDifferencebetween payback year cumulative income∧following year cumulative income

+ payback− year

17 References

Aldali, Y., Henderson, D. & Muneer, T., 2011. 50MW very large-scale photovoltaic powerplant for Al-

Kufra, Lubya: energetic, economic and environmental impact analysis. International Journal of Low-

Carbon Technologies, 6(4), pp. 277-293.

Cooke, D., 2007. Single vs Dual Axis Solar Tracking, s.l.: Altenergymag.com.

Direct Industry, n.d. Photovoltaic Solar Cells. [Online]

Available at: http://www.directindustry.com/industrial-manufacturer/photovoltaic-solar-cell-

80157.html

[Accessed 2012].

Duffie, J. A. & Beckham, W. A., 1991. Solar Engineering of Thermal Processes. 2nd ed. s.l.:John Wiley

& Sons, Inc..

EurObserv'ER, 2011. EurObserv'ER, Database. [Online]

Available at: http://eurobserv-er.org/default.asp

[Accessed 2012].

European Commission - Eurostat, 2011. Eurostat. [Online]

Available at:

http://epp.eurostat.ec.europa.eu/statistics_explained/index.php/Energy_price_statistics#Database

[Accessed 2012].

European Commission, 2011. Energy, Publications, Statistics. [Online]

Available at: http://ec.europa.eu/energy/publications/statistics/statistics_en.htm

[Accessed 2012].

European Commission, 2012. Joint Research Centre. [Online]

Available at: http://ec.europa.eu/dgs/jrc/index.cfm

[Accessed 2012].


68

Google Inc., 2012. Google Maps. [Online]

Available at: http://maps.google.co.uk/

[Accessed 2012].

Green Rhino Energy, 2011. Radiation on tilted surface. [Online]

Available at: http://www.greenrhinoenergy.com/solar/radiation/tiltedsurface.php

Institute for Energy and Transport (IET), 2012. PVGIS. [Online]

Available at: http://re.jrc.ec.europa.eu/pvgis/

[Accessed 2012].

International Monetary Fund, 2012. Data and Statistics. [Online]

Available at: http://www.imf.org/external/data.htm

[Accessed 2012].

Jacobi, J. & Starkweather, R., 2010. Solar Photovoltaic Plant Operating and Maintenance Costs.

[Online]

Available at: http://www.scottmadden.com/insight/407/Solar-Photovoltaic-Plant-Operating-and-

Maintenance-Costs.html

[Accessed 2012].

MACS Lab, Inc., 2012. Optimum Tilt of Solar Panels. [Online]

Available at: http://www.macslab.com/optsolar.html

[Accessed 2012].

McDermott, M., 2009. Treehugger, Solar Power Vocab: Single & Dual Axis Solar Trackers. [Online]

Available at: http://www.treehugger.com/renewable-energy/solar-power-vocab-single-dual-axis-

solar-trackers.html

[Accessed 2012].

Muneer, T., Kubie, J. & Abodahad, N., 2000. Windows in Buildings. 1st ed. s.l.:Architectural Press.

Renewable Energy World, 2010. Spain's Solar Power Sector Falls into the Abyss. [Online]

Available at: http://www.renewableenergyworld.com/rea/news/article/2010/11/spains-solar-

power-sector-falls-into-the-abyss

[Accessed 15 11 2012].

Renewable Savings, 2012. Solar PV Panels 4 kWp Sanyo HIT-H250E01 250 Wp 18% Module Efficiency.

[Online]


69

Available at: http://www.renewablesavings.co.uk/ProductInfo.aspx?id=349

[Accessed 2012].

Sanyo Electric Co., Ltd., 2012. Sanyo HIT Technology. [Online]

Available at: http://us.sanyo.com/Solar/SANYO-HIT-Technology

[Accessed 11 2011].

Scheuten Solar, 2007. References, Olmedilla Cuenca. [Online]

Available at: http://www.scheutensolar.com/public/site/uploads/producten/calzada-

olmedilla_web3.jpg

[Accessed 2012].

Scientific American, 2008. Is the Sun Setting on Solar Power in Spain?. [Online]

Available at: http://www.scientificamerican.com/article.cfm?id=is-the-sun-setting-on-solar-power-

in-spain

[Accessed 2012].

Solar Edge, 2010. Sheding light on PV system shading. [Online]

Available at: http://www.solaredge.com/articles/pv-system-shading

Solar Energy at Home, n.d. Solar Cell Energy Basics. [Online]

Available at: http://www.solar-energy-at-home.com/solar-cell.html

[Accessed 2012].

Solar Novus Today, 2009. Study: Southern Europe Photovoltaic Market to Help Global Industry Back

to Growth. [Online]

Available at: http://www.solarnovus.com/index.php?

option=com_content&view=article&id=241:study-southern-europe-photovoltaic-markets-to-help-

global-industry-back-to-growth-&catid=37:business-news&Itemid=241

[Accessed 2012].

Spain-Meteo, 1983-2005. Clear Sky Insolation Clearness Index. [Online]

Available at: http://spain-meteo.ru/en/mursiya/years/clear-sky-insolation-index

[Accessed 2012].

Trading Economics, 2012. Euro area inflation rate. [Online]

Available at: http://www.tradingeconomics.com/euro-area/inflation-cpi

[Accessed 2012].


70

Tutiempo, 1973 to 2012. Tutiempo, Historical Climate Data. [Online]

Available at: http://www.tutiempo.net/en/Climate/Murcia_San_Javier/84330.htm

[Accessed 2012].

W.B. Stine, R. H., 1986. Solar Energy Systems Design. s.l.:John wiley and Sons, Inc.

Wattsun, 2010. Tracked vs Fixed: PV System Cost and AC Power Production Comparison, Madison,

WI: s.n.

Wikipedia, 2012. Feed-in Tariff. [Online]

Available at: http://en.wikipedia.org/wiki/Feed-in_tariff#Spain

[Accessed 2012].

XE, 2012. Currency Converter. [Online]

Available at: http://www.xe.com/ucc/

18 Bibliography

Muneer, T., Kubie, J. & Abodahad, N., 2000. Windows in Buildings. 1st ed. s.l.:Architectural Press.

Muneer, T., 2004. Solar Radiation and Daylight Models. 2nd ed: Elsevier Butterworth Heinemann.

Markvart, T., 2000. Solar Electricity. 2nd ed: John Wiley and sons, Inc.

W.B. Stine, R. H., 1986. Solar Energy Systems Design. s.l.:John wiley and Sons, Inc.

Duffie, J. A. & Beckham, W. A., 1991. Solar Engineering of Thermal Processes. 2nd ed. s.l.:John Wiley &

Sons, Inc..


Dissertation Final (2)

Documents

Transcript of Dissertation Final (2)