A COMPARATIVE STUDY OF DIFFERENT PV TECHNOLOGIES FOR LARGE SCALE APPLICATIONS IN IRELAND

A COMPARATIVE STUDY OF DIFFERENT PV TECHNOLOGIES

FOR LARGE SCALE APPLICATIONS IN IRELAND

Department of Electrical Engineering Systems

COLLEGE OF ENGINEERING & BUILT ENVIRONMENT

Due Date: 7th

September 2012

MSc Energy Management 2012 Page i

Declaration

I hereby certify that the material, which is submitted in this assignment, is entirely my own

work and has not been submitted for any academic assessment other than as part fulfilment of

the assessment procedures for the program Master of Science in Energy Management (MSc)

(DT 711).

Signed............................................... Date................................................

MSc Energy Management 2012 Page ii

Acknowledgements

• I would firstly like to thank my supervisor Kevin O’ Farrell who provided all the recorded

data which made this study possible.

• I would also like to thank Dr Sarah Mc Cormack who provided me with measured data

from Dublin Airport which benefited my thesis greatly.

• I would also like to thank BNRG Renewables who offered to answer any questions I had

regarding the design and economics of PV systems as well as providing insights into the

operation of the large scale PV industry itself

• Finally I would like to thank anyone else that gave me assistance during the course of

this study.

MSc Energy Management 2012 Page iii

Abstract The purpose of this study was to determine the potential for installing multi megawatt ground

mounted PV systems in Ireland. Firstly a study was conducted to determine the best performing

PV technology type for Irish Climate conditions which was found to be a Sanyo HIT module.

Using PV design software in conjunction with recorded data it was then determined a 1MW

large scale PV system would produce 1012MWh annually and generate electricity at a price of

31.5c/kWh. Based on these findings it was concluded that a substantial support mechanism

would need to be put in place in order to make large scale PV generation viable in Ireland.

MSc Energy Management 2012 Page iv

Table of Contents

Chapter 1- Introduction ......................................................................................... 1

1.1 Introduction to area of research .................................................................................................... 1

1.2 Rational behind selected research topic ......................................................................................... 2

1.3 Aims .............................................................................................................................................. 3

1.4 Objectives ...................................................................................................................................... 3

1.5 Ethics ............................................................................................................................................. 3

Chapter 2 -Literature Review ................................................................................. 4

2.1 PV technology types ......................................................................................... 4

2.1.1 Crystalline Silicon PV (C-Si) .......................................................................................................... 4

2.1.2 Amorphous silicon (a-Si).............................................................................................................. 6

2.1.2.1Benefits of using a-Si modules in Irish climate ....................................................................... 7

2.1.3 Triple junction a-Si ...................................................................................................................... 7

2.1.4 Cadmium Telluride PV technology (CdTe) .................................................................................... 8

2.1.4.1Recycling solution and cost of CdTe ....................................................................................... 9

2.1.4.2 Future of CdTe ................................................................................................................... 10

2.2 Recorded module data ................................................................................... 10

2.2.1 HIT PV module .......................................................................................................................... 10

2.2.1.1 Temperature performance ................................................................................................. 11

2.2.1.2 Spectral response ............................................................................................................... 12

2.2.3 Kaneka a-Si module ................................................................................................................... 13

2.2.4 c-Si modules ............................................................................................................................. 13

2.3 Solar resource in Ireland ................................................................................ 14

2.3.1 The link between radiation and electrical power ................................................................... 14

2.3.2 Calculating the solar resource in Ireland ................................................................................ 15

2.3.4 Collection of data .................................................................................................................. 16

2.3.5 Comparison of data sources .................................................................................................. 17

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2.3.6 Diffuse radiation ................................................................................................................... 19

2.3.7Diffuse radiation estimation ................................................................................................... 20

2.4 Economic Viability .......................................................................................... 22

2.4.1 PV economic parameters .......................................................................................................... 22

2.4.2 Government support for large scale PV generation in Ireland .................................................... 23

2.4.3 UK PV support mechanisms ...................................................................................................... 24

2.4.4 ROC’s system ........................................................................................................................ 25

2.5 Design consideration for large scale PV.......................................................... 26

2.5.1 Inverter design ...................................................................................................................... 26

2.5.2 Reactive power and voltage stability ..................................................................................... 27

2.3.3 MPPT .................................................................................................................................... 28

2.5.4 Harmonic Content at inverter output .................................................................................... 29

2.5.5 Inverter Layout in large scale plant ............................................................................................ 30

2.5.6 Centralized inverter layout ........................................................................................................ 31

2.5.7 Sting inverter layout .................................................................................................................. 32

2.2.8 Single phase inverter layout .................................................................................................. 33

2.5.8 Three phase inverter approach ............................................................................................. 34

3.5.9 PV blocks within large scale layout ............................................................................................ 35

3.5.10 Wiring losses and cost ............................................................................................................. 36

Chapter 3- Methodology ...................................................................................... 39

3.1 Solar Resource assessment ............................................................................ 39

3.2 Software used to model performance ........................................................... 40

3.2.1 PVSYST .................................................................................................................................. 40

3.2.2 Validation of PVSYST model ...................................................................................................... 40

3.2.3 PVSYST 3-D shading tool ........................................................................................................ 41

3.2.4 Climate data base used for PVSYST study .............................................................................. 41

3.3 Models used in Comparative study ................................................................ 42

3.3.1 Recorded DIT data .................................................................................................................... 42

3.3.2 PVSYST Comparative model ...................................................................................................... 43

3.3.3 Large scale system performance ............................................................................................... 43

MSc Energy Management 2012 Page vi

3.4 Economic methodology ................................................................................. 43

Chapter 4-Results................................................................................................. 44

4.1 Initial assumptions within the PVSYST model ............................................................................... 44

4.2 PVSYST 1kWP comparative study .................................................................................................. 46

4.2.1 Sanyo modeled performance ................................................................................................ 48

4.2.2Kaneka modeled performance ............................................................................................... 49

4.2.4 Sharp modeled performance ................................................................................................. 50

4.2.5 Sunpower modeled performance .......................................................................................... 51

4.2.6 Sunteck modeled performance ............................................................................................ 52

4.3 PVSYST results for 1KW system .................................................................................................... 53

4.3.1 Irradiance loss ....................................................................................................................... 54

4.4 Recorded data results .................................................................................... 56

4.5 Economic consideration ................................................................................. 57

4.5.1 Retail price comparison............................................................................................................. 58

4.6 Large scale system PVSYST model .................................................................. 60

4.6.1 String shading diagram .............................................................................................................. 62

4.6.2 Wiring size calculation .............................................................................................................. 63

4.6.3 System performance ................................................................................................................. 64

4.6.4 Economic calculation ................................................................................................................ 65

Chapter 5 Conclusions ......................................................................................... 69

5.1Further research ........................................................................................................................... 70

References ........................................................................................................... 70

6.1 Standards .................................................................................................................................... 78

Appendix A ............................................................................................................ A

Kaneka PVsyst data .......................................................................................................................... A

Appendix B ............................................................................................................. B

Sanyo PVsyst data ............................................................................................................................ B

Appendix C ............................................................................................................. C

Sunpower PVsyst data ..................................................................................................................... C

MSc Energy Management 2012 Page vii

Appendix D ............................................................................................................ D

Sunteck PVsyst data .........................................................................................................................D

Appendix E ............................................................................................................. E

Sharp PVsyst data ............................................................................................................................ E

Appendix E .............................................................................................................. F

PVsyst W/m2 VS irradiance .............................................................................................................. F

Appendix F ............................................................................................................. H

PVsyst efficiency VS irradiance ........................................................................................................ H

Appendix G ............................................................................................................. J

A-Si triple data .................................................................................................................................. J

Appendix H ............................................................................................................ K

Recorded data ................................................................................................................................. K

MSc Energy Management 2012 Page viii

Table of figures

Table 1 Module manufacture data ............................................................................................... 13

Table 2: Reference prices for renewable generators ................................................................... 23

Table 3 Sanyo results .................................................................................................................... 48

Table 4 Kaneka modelled results .................................................................................................. 49

Table 5: Sharp modelled results ................................................................................................... 50

Table 6 Sunpower modelled results ............................................................................................. 51

Table 7: Sunteck modelled results ................................................................................................ 52

Table 8: Module comparison table ............................................................................................... 53

Table 9: Results from DIT recorded data ...................................................................................... 56

Table 10: Retail price comparison between technologies, 2012) ................................................ 59

Table 11: Voltage drop calculations for large scale system .......................................................... 64

Table 12: Total cost of 1MW plant. .............................................................................................. 66

Table 13: NPV analysis of large scale system ................................................................................ 68

MSc Energy Management 2012 Page 1

Chapter 1- Introduction This chapter will introduce the main area of research for this project and the relevance of the

research question chosen. Firstly a brief overview of the political and economic factors which

have contributed to the growth of PV generation in recent years will be given. The potential for

installing large scale ground mounted PV systems in Ireland as a means of reaching our

renewable generation goals will then be discussed.

1.1 Introduction to area of research

In recent years the use of renewable technologies such as wind and solar PV has grown

dramatically in line with European and global directives to reduce CO2 production. The 20 20 20

targets are one such initiative which aims to cut emissions by 20%, increase efficiency by 20%

and increase the use of renewable by 20% by 2020 (European Environment Agency 2010). As a

result of these targets many countries have been expanding the use of PV for large grid

connected systems in order to reduce C02 production. Germany is an excellent example of how

a country with a somewhat limited PV resource can produce large amounts of PV electricity

through introducing a structured feed in tariff for ground mounted PV systems (Suri et al,

2007).Germanys current installed capacity has now reached 25gigawatts (clean technica, 2012)

.As a result of the success of the German system similar policies have also been introduced in

other countries such as Spain, Italy Greece, Czech Republic and the UK (Marcel Suri et al, 2007).

Despite major growth in large scale PV generation in the UK with 366MW of PV capacity

registered with the DECC since they initiated a structured PV tariff in 2010 Ireland have yet to

recognize the potential of PV especially for large scale ground mounted systems and PV

generation as a whole is not included in any of the 3 REFIT schemes currently used by the

Department of Communications, Energy & Natural Resources to support new renewable

installations (EPIA 2012).

In spite of significant differences in government policy towards PV generation in the UK and

Ireland in terms of energy resource both locations offer similar potential with Ireland receiving

between 910-1100kWh/m2 as reported in (Dykes, 2011) and the UK receiving an average of


950kWh/m2 as seen in figure 1 (Sullivan, 2012). This result indicates that if Ireland’s policy

towards PV changes at government level PV generation could potentially become a significant

player in Ireland renewable generation portfolio.

Figure 1: UK and Ireland average radiation (Sullivan 2012)

1.2 Rational behind selected research topic

At present very little data is available regarding the potential of installing large scale multi

megawatt PV systems in Ireland. As described in (SEAI , 2012) natural gas currently accounts for

61% of all fuel used in electricity generation in Ireland, this dependency on foreign imports

reduces Irelands security of supply and also means that electricity prices are highly influenced

by price volatility in the gas market (SEAI , 2012) . As large scale PV generation could potentially

increase Ireland’s security of supply and help achieve our target of 40% renewable generation

by 2020 a detailed studied of the potential of this technology in terms of cost and performance

is required.


1.3 Aims

• The first aim of this study is to determine the performance of thin film and c-Si modules

under Irish Climate conditions.

• The second aim consists of determining which module type is best suited for use in large

scale ground mounted PV systems in Ireland in terms of both performance and cost.

• The 3rd

aim is to estimate the performance of a large scale PV system in Ireland.

• The final aim is to determine the economic viability of large scale PV in Ireland and

determine the magnitude of support mechanism needed to make the system viable if a

subsidy is required.

1.4 Objectives

• The first objective is to establish the level of solar resource in Ireland by analyzing a

combination of both ground measured data and satellite data.

• To establish which PV module type performs best under Irish climate conditions using

both recorded data from modules installed in DIT and modelled data from the PVsyst

software package (PVsyst, 2012).

• To study the performance of a large scale PV system by designing a 1MW theoretical

system in PVsyst.

• To determine the price of electricity (COE) the system would produce and the profit or

loss it would make over its lifetime by performing a Net Present Value (NPV) analysis.

1.5 Ethics

Good ethical behaviour was maintained throughout the completion of this study. All

paraphrased material was referenced using the Harvard referencing system, all recorded and

estimated data was obtained from reliable sources and this data was referenced accordingly.

All calculations were carried out using original data and the collected data was not modified in

order to present misleading results. Finally data was collected from as many sources as possible

to insure the information and results reported were not biased towards a particular outcome.


Chapter 2 -Literature Review

This chapter covers both the technical and economic consideration which must be made when designing

a large scale system. The chapter consists of 5 main topics which are outlined below.

• Overview of thin film and Crystalline PV.

• Overview of each of the 5 modules which were analyzed in this study.

• Solar resource in Ireland.

• Grid requirements and design of a large scale PV plant.

• Economics of large scale PV generation.

2.1 PV technology types

2.1.1 Crystalline Silicon PV (C-Si)

At present the dominant player in large scale PV generation has been Crystalline Silicon PV

which can be found in 2 main forms of technology. Mono-Crystalline PV cells are produced

when thin silicon wafers with a thickness of up to 200 microns are cut from a single crystal

ingot. Multi-Crystalline PV cells are produced when a large block of silicon is first cut into blocks

and then individual wafers are cut out. Although mono crystalline offers slightly more efficient

results in terms of electricity production the industry as a whole has seen a slight divergence

away from mono-crystalline because the manufacturing processes involved in mono crystalline

PV production are more complex and therefore more expensive. The breakdown of PV

generation as a whole can be seen in figure 2 where it can be seen that thin film PV only holds a

small percentage of overall market share (Willeke et al, 2008).


Figure 2: Market share of c-Si and thin film (Willeke et al, 2008).

Crystalline PV is often viewed as a mature technology as this industry has been developed

extensively over the last 30 years however recent reports have suggested that the technology is

still maturing which is highlighted by the fact that the payback period for multi-crystalline PV

has been dropping significantly since 2005 through major advancements in the manufacturing

processes involved in producing PV cells, these processes range from using thinner sawing wire

and producing thinner wafers which still operate at high efficiencies of around 18%.One of the

most important advancements was reported by the REC (Renewable Energy Convention) in

2005 where they suggested that switching from the costly manufacturing processes established

by Siemens to using fluidized bed reactors to produce high quality crystalline PV material could

dramatically decrease costs (Saurer, 2008). One report by the REC estimates potential savings


of 60% and the energy payback period for crystalline PV modules to drop from 2 to 1 year as

seen in Fig 4 (Saurer, 2008), (Moro, 2010).

Figure 3: Energy Payback Period with advancements in production (Saurer, 2008).

2.1.2 Amorphous silicon (a-Si)

Amorphous silicon has been investigated as a PV material since the 1970s and differs from

crystalline silicon in that some of the atoms within the material remain unbounded (Sturm, J.C

2011). The main advantage of this technology is that it requires a very small quantity of active

material when compared to other mono and multi crystalline silicon PV cells. This means the

cost of manufacturing these panels is not directly related to the cost of silicon as in crystalline

PV which reduces the overall cost of this material greatly. It has been estimated that with

current manufacturing processes the cost for these cells can be as little as 1€/WP with further

improvements obtainable if more efficient manufacturing processes are established. For large

scale use and durability issues the thin film PV array is mounted between glass panels (Doni,

2010). In terms of efficiency these types of cells still cannot compete with crystalline PV cells

which means for large scale developments a larger area is required to produce the same power


output as crystalline panels. The typical efficiency for an amorphous silicon panel is 7% (Sturm,

J.C, 2011).

2.1.2.1Benefits of using a-Si modules in Irish climate

One of the main advantages of a-Si modules in an Irish climate is the performance of these cells

under cloudy conditions and low irradiance levels. In (Jansen, 2006) it was estimated that for

UK climate conditions a-Si modules would see a 15-20% energy cost advantage over c-Si grid

connected systems. This result was again reinforced in (Krauter & Preiss, 2011) where the

energy yield of a-Si modules was found to be 2% higher than c-Si modules for Berlin local

conditions for the year of 2009.

2.1.3 Triple junction a-Si

Although single junction a-Si modules suffer from poor efficiency compared with c-Si modules

significant improvements in terms of performance can be achieved depositing a number of

layers of a a-Si material on top of each other to form double and triple junction devices. The

main benefit from this type of configuration is that each a-Si layer can extract energy from a

different portion of the electromagnetic spectrum increasing the ability of the module in terms

of radiation capture. An example of a typical a-Si triple junction cell is shown in figure 4, the

first section in the system is a-Si material with a band gap of approximately 1.8eV which is ideal

for extracting low wavelength blue light. The second section consists of an a-SiGe alloy made up

of approximately 85% a-Si and 15% Germanium which has a band gap of approximately 1.6eV

making it suitable for absorbing photons from the green spectrum. Finally the last layer also

consists of a-SiGe however in this case the Ge material makes up 50% of the material which

gives a band gap of 1.4eV allowing absorption of red light. The introduction of the oxide coating

on the bottom of the module also means that photons that are not absorbed as they initially

pass through the module are reflected back up through each layer which allows for additional

power output (SolarFocus, 2005). It was reported in (Wang, 2002) that an efficiency of 12.71%

was obtained using an a-Si triple junction module arrangement.


Figure 4: Triple junction module layout (SolarFocus, 2005)

2.1.4 Cadmium Telluride PV technology (CdTe)

Cadmium Telluride thin film panels have developed significantly in recent years and have

greater efficiency in terms of solar to electricity generation than A-SI PV panels and also cost

less to produce than typical silicon cells. Cadmium Telluride cells also provide a longer

operating life than A-Si cells and from a power production standpoint It can also be noted that

CdTe cells also handle cell temperature variations better than standard crystalline cells (Doni,

2010) . It has been reported that for crystalline PV panels if the cell temperature goes beyond

250/C there can be a significant drop in DC output power from the unit (Suri et al,

2007).Although this technology has many advantages over a-SI thin film it must also be noted

that Cadmium is a toxic element and therefore additional costs such as the disposal of the

material itself must also be considered when estimating the cost savings from switching from

silicon based PV to CdTe cells. Another issue that must also be considered is the availability of

Tellurium which is limited and therefore could prevent this type of technology from having a

significant impact on large scale PV electricity production. Many study’s have been carried out

to establish the cost of disposal and whether recycling the PV units could offer an economically

viable solution in dealing with PV cells which have reached the end of their operating life. In

terms of disposal it was determined that the cost was highly dependent on state and local


regulations on what is considered a “hazardous material”. Based on the Resource Conservation

and Recovery Act (RCRA) and the Hazardous Waste Control Law (HWCL) which are the two

main acts which control the recovery of waste in the United States it was found that most CdTe

PV panels exceeded the allowable limits of cadmium which means end of life disposal could be

extremely costly (Eberspacher et al, 2008).

2.1.4.1Recycling solution and cost of CdTe

As a result the recycling of these CdTe modules could offer an economical viable alternative to

direct disposal. The recycling process for CdTe cells at present is based on using chemical

compounds to separate the CdTe and Cds semiconductor films from the surrounding glass and

metal back plate in a process known as etching. The individual sections of the PV module can be

seen in figure 5 (Bohland et al., 1997).

Figure 5: CdTe module layers (Bohland et al., 1997)

Based on information from a pilot recycling plant set up by US Company Solar Cells Inc. it was

found that this method of recycling produces 4 usable materials which include saleable glass,

Cadmium carbonate, tellurium and ethylene-vinyl acetate at a cost of just 0.04$/watt. In

comparison the cost of disposal was estimated between $0.2/watt and $0.4/watt (Bohland et al

1997). Another advantage of recycling is that the process itself is not hugely energy intensive

and produces no hazardous byproducts as a result it was also suggested in this report that the

PV plant and recycling plant could be co-located reducing costs even further.


2.1.4.2 Future of CdTe

In order to determine if the CdTe PV is likely to become a major contributor in PV markets

Professor Stuart Irvine who is the chairman of the Director Centre for Solar Energy Research at

OpTIC Technium , Glyndwr University was contacted directly. He concluded that the market

share of CdTe has actually declined in the last 2 years due to continued expansion of c-SI

technologies however the annual output of CdTe has also continued to increase (Irvine, 2012).

“The annual output of CdTe PV modules has continued to grow year on year but the proportion

of the total market has declined over the past two years because of the very rapid growth in

crystalline silicon PV module production. The PV market remains very competitive with over

supply and is volatile but predicted trends are for expansion over all product types. Price

competition is fierce and will remain the key driver”

2.2 Recorded module data Recorded time series data for a number of modules currently installed in DIT and was used to

analysis the performance of both thin film and crystalline modules under Irish Climate

conditions. The data corresponded to radiation data from a Kipp and Zonen CM6B pyrometer

and corresponding current and voltage readings from a datalogger located in the DIT Focus

building (McGlynn, 2010). The technical details of each module currently installed in DIT are

discussed below.

2.2.1 HIT PV module

The first module which will be examined in this report is the Sanyo HIP-215NHE5 module which

has a maximum power output of 215WP based on testing at standard testing conditions (STC).

In terms of structure the panel itself contains a very thin a-Si intrinsic layer inserted between

p+- type or n+- type a-Si and n-type c-Si . This structure has been made possible by using low

temperature plasma processes to grow extremely high quality a-Si large area thin films and

solar cells (Taguchi, et al, 2005). One of the most beneficial features of this design is the

mitigation of surface defects in the in the c-SI material by the introduction of the a-SI material


which results in improved overall efficiency and significantly a high VOC which is important for

improving the efficiency for large grid connected systems (Taguchi, et al, 2005).

Figure 6: HIT PV cell (Maruyama, et al., 2006)

From the cell layout above it can be seen that the front a-SI layer is p-type a-SI and back layer n

type material. A transparent conductive oxide coating is also placed on top of both doped layers

which act as an anti reflective coating. The finger structure for the electrodes also insures that

that all solar cells within the module are symmetrical resulting in reduced thermal and

mechanical stresses (Taguchi, et al., 2005)

2.2.1.1 Temperature performance

As mentioned before the HIT design allows for a higher VOC than standard c-SI modules due to

the mitigation of defects in the c-Si layer. This result also has the added benefit of improving

the temperature coefficient of the module as VOC and temperature performance are related.

This means that the HIT cells can operate more efficiently at higher cell temperatures than

typical c-SI modules. It has been found that with a VOC of 680mv a temperature coefficient of –

0.33 %/ºC can be achieved while it was also documented that –0.25 %/ºC was obtainable by

changing the deposition conditions on both sides of the a-Si silicon wafers with clean surfaces

before they were deposited onto the c-Si substrate (Maruyama, et al., 2006), (Taguchi, et al.,

2005).


Figure 7: Improvement of temperature performance with new process (Maruyama, et al., 2006).

2.2.1.2 Spectral response

HIT modules also can be more effective than typical c-Si modules due to the ability of the a-Si

layer to capture energy of from shorter wavelengths as shown in figure 8. For the most part

these wavelengths correspond to diffuse radiation which has been scattered by clouds or

aerosols in the atmosphere and are in the range of 400-500nm. This means the HIT panels

could offer improved energy yield in climates where a large proportion of the global irradiation

is comprised of diffuse radiation such as in Ireland (Krauter & Preiss, 2011).

Figure 8: Spectral performance of different types of modules (Krauter & Preiss, 2011).


2.2.3 Kaneka a-Si module

The 2nd

module which will be used for calculations in this study is the Kaneka G-A060 which has

an STC power rating of 60W. Interestingly the Kaneka module has a VOC value of 91 volts which

is 40 volts more than the Sanyo HIT module and 70 volts greater than any of the c-SI modules

studied in this project. Many reports such as (Taguchi et al., 2005) have shown a good

correlation between high VOC and low power temperature coefficients which is also

demonstrated in this case with a power temperature coefficient value of just -0.26%/°C making

this module also suitable to high temperature conditions.

2.2.4 c-Si modules

In conjunction with the a-Si module and HIT modules located in DIT the I-V characteristics for 3

c-Si based modules currently installed in the college were also available and allow for detailed

comparison of both c-Si and a-Si technology’s. The c-Si modules installed consist of a Sharp

NE80E2E polycrystalline 80WP module specifically designed for large scale applications, a

Sunpower SPR-90 mono crystalline 90WP module and finally a Sunteck STP080B12/BEA mono

crystalline module with an 80WP power rating. The manufacturer data for all 5 panels was

collected and can be seen in full in table 1 below.

Manufacturer Model

VMP

(Volts)

IMP

(Amps)

PMAX Temp. Coefficient of

Power

Efficiency

(%) (Watts)

Kaneka G-EA060 67 0.9 60 -0.26%/°C 6.3

Sharp NE-80E2E 17.1 4.67 80 - 0.485%/°C 12.6

Sunpower SPR-90 17.7 5.1 90 -0.38%/°C 16.5

Suntech STP080B12/

BEA 17.5 4.58 80 -0.48 %/°C 12.4

Sanyo HIP-

215NKHE5 42 5.13 215 -0.3%/°C 17.2

Table 1 Module manufacture data (McGlynn, 2010)


2.3 Solar resource in Ireland

2.3.1 The link between radiation and electrical power

The feasibility of a large scale PV system is largely dependent on the solar resource available at

the location the system is being installed. As described in (Fontana, 2012) solar irradiation is

essentially the fuel of a PV plant that allows the creation of DC current flow when it falls on a

semiconductor material that exhibits the photoelectric effect. This effect can be described as

the absorption of energy contained within the incident light by electrons within the metal itself,

when an electron receives a photon of light energy greater than the band gap energy which for

silicon is approximately 1.1eV electron hole pairs can be formed which results in the generation

of DC current (Würfel, 2009). The band gap of a material affects what portion of the

electromagnetic spectrum a PV cell absorbs which makes it a significant factor in calculation of

a PV modules possible efficiency. The link between band gap energy and efficiency was defined

fully in (Shockley& Queisser, 1961) where it was determined that the max obtainable efficiency for SI

cells was 33.7%. Figure 9 shows the band gap and corresponding efficiency’s for a number of materials

currently used in the PV industry.

Figure 9: Band gap VS efficiency (Peter,L.M, 2011)


The amount of energy available in each photon of light was also defined in Einstein’s equation

shown below where the energy in each photon is proportional to the frequency of the light

multiplied by Planks constant of 6.626×10-34

J/s. This in turn can be related to the wavelength of

the light source by describing the frequency as a function of the wavelength as seen in equation

1 and 2 (PhysicLAB, 2002).

= Equation 1

= Equation 2

2.3.2 Calculating the solar resource in Ireland

As large scale PV projects require a significant long term financing sourced from both debt and

equity the initial resource assessment must be carried out using reliable data in order to insure

that the system operates successfully both from an economic and design point of view. A

methodology for carrying out an initial yield assessment was described in (FRV, 2012) where it

was suggested that the most optimal solution was the use on site data in conjunction with

other solar data basis. The structure of a typical solar resource assessment can be seen in figure

10 (FRV, 2012).


Figure 10: Resource estimation structure (FRV, 2012)

2.3.4 Collection of data

For this project 5 different sources were used to estimate the solar resource in the Dublin area.

3 software packages were used including Climate-SAF PVGIS which uses satellite images over a

period of 12 years to estimate results, PVGIS Classic which interpolates long term ground based

measurements taken from the closest weather stations to the requested location and

Meteonorm which also uses interpolated ground based measurements to estimate resource

(Meteonorm,2012),(PVGIS, 2012). Additional ground based hourly measurements from Dublin

Airport weather station from the years of 1977-2006 were supplied by Dr Sarah Mc Cormack

from the Dept of Civil, Structural and Environmental Engineering in Trinity College (Mc

Cormack, 2012). Data from the Focus building in DIT was also measured and analyzed in a

previous project using a Sunny SensorBox that measured global radiation on a horizontal plane

and provided the final data base for resource estimation (Duarte, 2011).


As the data from all software packages and Focus Building data was presented in kWh/m2/day it

was necessary to convert the hourly met Eireann data from j/cm2 to kWh/m

2/day. This was

achieved by first converting cm2 to m

2 and then converting joules to watts using the principle

that 1 watt is equal to 1 joule/second. The data was then analyzed using Excel and graphed as

seen below.

2.3.5 Comparison of data sources

Figure 11: Resource estimation results kWh/m2/day

It can be seen that there is strong correlation between all data used to estimate resource

however it can be noted the all software programmes over estimate solar resource slightly in

the months of May, June, July and August. The data used from the focus building indicates that

0

1

2

3

4

5

6

Nov Dec Feb Apr May Jul Aug Oct Dec Jan

PVGIS-SAF

PVGIS-CLASSIC

Meteonorm

Met Eireann

Focus Building(Duarte, 2011)

Sommerset

KW

h/m

2/d

ay

Time (months)


June has the highest energy resource on average with a value of 5.1kWh/m2/day being

observed. All other software packages estimate June to provide the highest resource with

values ranging from 4.7kWh/m2/day to 5.1kWh/m

2/day. Interesting the results from the Met

Eireann data indicate that May has the highest resource with an average value of

4.5kWh/m2/day observed. Overall the results from all 3 software packages used correlate well

with what was observed in the Focus building and Met Eireann data with PVGIS Classic and

Meteonorm providing the best fit to this data. The results from the satellite based programme

PVGIS-SAF also correlate with what was seen at the Focus building and Met Eireann data

however estimate the solar radiation to be 2% higher than all other data sources on an annual

basis. The solar resource for a location corresponding to Sommerset in the UK was also

estimated using PVGIS. This specific location was chosen because BNRG renewable have

recently constructed a 2MW PV plant at this site and therefore by comparing resources

between this location and Ireland the potential for large scale PV in Ireland can be examined

(BNRG, 2012). As can be seen in figure 11 the solar resource in both locations are evenly

matched with the highest radiation level experienced in Sommerset only 0.44kWh/m2/day

greater than the corresponding level of radiation in Dublin.

One of the most significant issues identified in figure 11 is the seasonal variations in solar

resource in Ireland where there is 4.4kWh/m2/day difference in radiation levels between June

and December if the data from Meteonorm was used. This seasonal variation can be attributed

to the fact that the earth’s axis of rotation is tilted approximately 23.5o compared to the plane

in which the sun is located. This causes the suns relative height above the horizon to change as

the earth orbits the sun. The relative sun heights for each month for a latitude of 53.1o North

corresponding to Dublin were modelled using PVsyst in order to show this variation graphically.

It can be seen from the results that the highest sun height annually is 63.5 which occurs at the

June solstice on the 22nd

June and the lowest height of just 16.50 occurs on the December

solstice on the 22 December. This graph also shows the significant variation in available sun

hours between summer and winter months.


Figure 12: PVsyst modelled sun paths (PVsyst 2012)

This variation is an important factor to be considered when designing grid connected plants

over 2MW connected to the sub-transmission or transmission network as the ability of the

plant to offer operational security, stability and power quality to the whole grid network is of

key importance (Marinopoulos et al, 2011).

2.3.6 Diffuse radiation

Another important point to consider when estimating the solar resource for a location is the

ratio of diffuse to global radiation. Diffuse radiation can be described as the scattering of direct

beam radiation by molecules and particles in the atmosphere. There are 2 key processes which

cause this effect. Rayleigh scattering can be described as the scattering of light by air molecules

such as oxygen and nitrogen which are more effective at scattering shorter wavelengths in the

region of 400nm. Mie scattering relates to the scattering of light by cloud droplets with a

diameter of approximately 20 micrometers (PVEducation, 2012).


Figure 13: Diffuse radiation diagram (Lorenzo, 2005)

2.3.7Diffuse radiation estimation

In order to estimate the percentage of diffuse radiation under Dublin climate conditions PVGIS-

SAF, PVGIS Classic, Meteonorm and Met Eireann data from Dublin Airport were again the main

sources of data used. Importantly all models used consisted of 10 or more years of climate data

which allowed direct comparison between each model. The data was then formatted in order

to calculate the average ratio of global to diffuse radiation for each month. Interestingly all

software packages estimated the diffuse component to be at least 6.5% more then what was

seen in the Met Eireann data on an annual basis. Overall PVGIS-SAF offers the best fit to the

monthly trend found in the Met Eireann data. The Meteonorm model provides the least

accurate results especially during the months of June and December where it over estimates

what was observed in the Met Eireann data substantially. This being said all models calculate

the average diffuse component to be between 55-62% which correlates well with what was

reported in other reports (SEAI(b), 2012).


Figure 14: Diffuse VS global radiation calculation

These results are a clear indicator that when considering PV technology for an Irish climate the

selected system must be able to extract energy from low irradiance penetration with a high

diffuse component. This information in conjunction with the studies carried out in (Krauter &

Preiss, 2011) and (Jansen, 2006) mean that a-SI modules and HIT modules could offer

advantages in terms of energy yield over c-SI modules especially in months where the ratio of

diffuse to global irradiance is high.

0.3

0.35

0.4

0.45

0.5

0.55

0.6

0.65

0.7

0.75

0.8

Nov Dec Feb Apr May Jul Aug Oct Dec Jan

pvgis saf

pvgis classic

meteonorm

met eireann

Time(Months)

rati

oo

f D

iffu

se/G

lob

al

Ira

dia

tio

n


2.4 Economic Viability

2.4.1 PV economic parameters

One of the most significant factors in determining the economic viability of any PV plant is the

cost at which electricity can be produced as this will determine if the technology can compete

with other renewable and non renewable generators in the electricity market. One approach to

estimating the price of electricity was identified in (Conlon, 2012) where the price of generated

electricity was defined as being dependent on 4 variables. These 4 parameters include CO&M

which is the annual expenditure on operation and maintenance, the FCR which is the fixed

charge rate and reflects interest rates, Ea which is the annual electricity production in kWh and

finally the total capital cost which is described by Cc. Equation 3 shows how these parameters

can be used to find the price of electricity in terms of €/kWh.

= ×& Equation 3

Another important factor which plays a role in weather a project is invested in or not is a

payback analysis which estimated the potential return on invested capital. In order to achieve

this a Net Present Value calculation must be carried out which can be described by a

summation of all present values of future income and expenditure. Equation 6 shows how the

present value of future income can be calculated where A is the annual revenue, r is the

discount rate and n is the project life time in years (Mukund R. Patel, 2010). The Net Present

Value (NPV) of the system can then be calculated by subtracting the initial capital investment

away from the present value of all future incomes, a positive NPV describes an overall profit on

initial investment however a negative NPV suggests that the system will make a loss on initial

investment.

= − + Equation 4


2.4.2 Government support for large scale PV generation in Ireland

In order to find out if there are any support mechanisms in place for large scale PV generation

at government level the Department of Communications, Energy and Natural Resources was

contacted directly. This led to contact with Gerald McTiernan who works in the Renewable and

Sustainable Energy Division of the Department and who gave a detailed account of the current

REFIT tariff for renewable installations in Ireland.

The current Irish REFIT scheme works on the basis of a reference price system. Each renewable

system supported by the scheme is set a certain reference price which they are guaranteed to

receive for their energy regardless of what is happing in the whole sale market price. This

allows renewable generators to operate with reduced financial risk. Additionally a balancing

payment of up to €9.90/MWh may be paid to the supplier for exporting the energy to the grid.

This balancing payment is only made to the supplier if certain conditions are met, the full

€9.90/MWh is made if the market price is less than or equal to the reference price for the given

technology, if the wholesale price is greater than the reference price and the balancing

payment combined then no balancing payment is awarded, the final scenario occurs when the

market price is greater than the reference price but is less than the sum of the reference price

and balancing payment, in this case a portion of the €9.90/MWh payment is made which

reflects the payment needed to insure that the renewable generator receives a total payment

equal to the sum of the reference price and €9.90/MWh balancing payment (DCENR, 2012). The

reference prices for each renewable technology can be seen in table 2.

Table 2: Reference prices for renewable generators (DCENR, 2012)


It was identified that PV generation is not included in any of the 3 REFIT schemes currently in

use under Irish legislation and therefore would not have a chance to compete with other

renewable energy technologies including hydro wind and biomass for government support. The

main support mechanisms for PV systems in Ireland have been in the microgeneration sector

with ESB being the first company to introduce a tariff at 10c/kWh which was approved by the

CER. Interestingly although all other suppliers were authorised to introduce their own tariff

systems by the CER when the ESB first introduced this scheme and as of the 4th

of April 2011

are eligible to introduce new tariffs Electric Ireland are still the only company to avail of this

opportunity. Other support mechanisms have also been implied at government level for

microgeneration PV including the Accelerated Capital Allowance scheme (ACA) which is aimed

at improving energy efficiency in company’s and allows organisations to claim 100% of the

initial capital cost of installing energy efficient technologies back from corporation tax and

which was passed through the Finance Act 2008 (McTiernan, 2012).

From the above information it is clear that large scale PV generation has not been considered

as an economically viable solution to meeting Irelands future renewable generation deadlines.

The attitude towards large scale pv generation in the UK has been much different to the

approach taken in Ireland and will be discussed in the next section.

2.4.3 UK PV support mechanisms

The UK government has implemented a structured PV tariff where installations are segmented

into groups by nature of their size. The scheme was first implemented on the 1st of April 2010

with installations between 500kw-5MW receiving a tariff of 30.7p/kWh (Ernst & Young 2011).

This scheme saw massive growth in PV installations with 366MW of PV capacity registered with

this scheme as of November 2011 resulting in the creation of an estimated 2,500 jobs within

the sector in 2010. Although the Department of Energy and Climate Change (DECC) decided to

reduce PV tariffs significantly in 2012 to just 8.5 p/KWh for installations in the 500Kw-5MW

range it still remains clear that PV generation will become a major part of the UK’s energy


portfolio with the climate change minister stating in 2011 that the original target of 2.7GW of

PV capacity by 2020 would now be increased to a new target of 22GW (EPIA 2012).

Figure 15: Growth in UK PV installed capacity (Ares,E, 2012)

2.4.4 ROC’s system

There is also a second option in place in order for PV generators to receive support in the UK,

the Renewable Obligation scheme was initially introduced in 2002 and puts an obligation on

suppliers to source a specified amount of electricity from renewable sources annually. As of

2011 each supplier must source 9.4% of electricity from renewable sources. The scheme is over

seen by Ofgem who issue renewable generators certificates on the basis of how much

renewable energy they generate. The current rate for PV generation is 2 ROC’s/MWh.

Generators can then sale these certificates to suppliers who in turn can use them to meet there

renewable obligation which mean the renewable generator receives both the wholesale price

for their electricity and an additional revenue from the sale of ROC’s (DECC, 2012). As the

current FIT does not fund projects over 5MW and has also been reduced to 8.5p/kWh for

systems over 500Kw ROC’s have become an attractive option to developers of large scale PV


plants in the UK with Lark energy announcing in June 2012 that they are currently designing a

30MW PV park which would be the biggest installation in the UK to date (Becky Beetz, 2012).

2.5 Design consideration for large scale PV

2.5.1 Inverter design

One of the most important components in a grid connected PV system is the inverter which is

used to convert the DC electricity produced by the panels into AC electricity which can be

utilized by the grid network. Grid tied inverters automatically synchronize the phase of the PV

system and grid, the frequency of the system with the frequency of the grid which in Ireland is

50hz and also insure the generated voltage from the system is the same as the voltage at the

designated connection point. A typical layout for PV grid tied inverter is shown in figure 15

which includes a disconnection switch on both the AC and DC side of the plant (NREL, 2010).

Figure 16: Typical DC/AC PV inverter (NREL, 2010)

In conjunction with meeting voltage, frequency and phase requirements large scale systems

connected to the medium voltage grid network may also be required to provide additional

services to insure network stability. These services may include the ability to remain connected

to the grid during low voltage levels or in the event of a fault and supply active power directly

after the fault in order to stabilize the system which is known as Low Voltage Ride Capability

(LVRC). In terms of large scale PV systems connected to the medium voltage and distribution

level the ability to supply reactive power to support voltage stability is becoming a key talking


point with countries such as France and Germany issuing strict requirements for reactive power

provision from large scale PV in 2008 and 2009 respectively (SMA, 2009).

2.5.2 Reactive power and voltage stability

In order to understand the importance of reactive power to grid stability the concept of

reactive power must be explained. In an electrical system when the voltage and current are out

of phase there are 2 components that make up the total apparent power(VA) in a system, the

first component consists of active or real power which is measured in watts and the second

component consists of reactive power which is measured in VARs. Although reactive power

does not provide energy it is vital to the operation of many loads that need to establish

magnetic fields in order to operate such as induction motors. Transformers and transmission

lines also produce inductance which opposes the flow of current and therefore to counteract

this reactive power is needed to maintain voltage levels and deliver active power. If the reactive

component isn’t large enough voltage sag and in extreme cases voltage collapse can occur due

to inability to supply loads with sufficient active power (Andersson et al 2005). Reactive power

can be explained graphically as shown in figure 17 where the angle ∅ corresponds to the

relative angle between the voltage and current. Changing this angle effectively changes the

ratio between active (W) and apparent power (VA) known as the power factor (PF) which

controls how much reactive power is being supplied to the grid as seen in figure 17 and

described in equation 5 (SMA, 2009). At present the majority of inverters do not have the

ability to change PF to suit grid requirements however some inverters including the SMA Sunny

Tripower 3 phase inverter have the ability to either supply or consume reactive power by

operating with a PF in the range of 0.8leading to 0.8lagging (SMA, 2009).

" = #$%∅ = &#'()*+$,*-.&++/-*0'+$,*-1&Equation 5


Figure 17: Reactive Power Triangle (SMA, 2009)

2.3.3 MPPT

As the I-V characteristics of a solar cell are nonlinear and vary with both irradiation and

temperature there is a point on the I-V curve that a PV array produces its maximum possible

power under given operating conditions. This point is referred to as the Maximum Power Point

(MPP).Figure 18 shows graphically the Maximum Power point for a typical c-SI module where it

can be seen that there is an I-V relationship which results in the module producing its maximum

possible power (Solmetric, 2011).

When comparing PV modules the Fill factor (FF) is often used to model the non linearity of a PV

cells I-V curve. The fill factor measures the relationship between the maximum power

production and the product of VOC and ISC as seen equation graphically in figure 18. This

performance parameter becomes especially important when measuring different types of PV

materials as often cells that display similar ISC and VOC can operate at a different maximum

power point due to the nature of their I-V characteristics. In general c-SI modules have a higher

FF then a-SI modules due to the fact that these cells have a squarer I-V curve which is closer to

ideal conditions (Solmetric, 2011).


Figure 18: MPP for a c-Si module (Solmetric, 2011).

In large scale systems an important function of the GTI is to insure that at any given condition

the MPP is obtained from the PV array. This is achieved through a system called Maximum

Power Point Tracking (MPPT) which is an electronic system that varies the electrical operating

point within of the PV array to insure it is operating at its MPP at any given instant (IFC, 2012).

2.5.4 Harmonic Content at inverter output

In a typical PV inverter Pulse Width Modulation (PWM) is used to control IGBT switches which

in turn generate AC output. Although this method of AC generation allows for accurate control

of both magnitude and frequency which is important for grid synchronization high order

harmonics and noise which are detrimental to system performance can also be produced due

to the high frequency switching of the IGBT’s. To remove these unwanted harmonics a series

inductive filter and capacitive shunt filter are generally used to filter out harmonics due to

switching transients and also harmonics produced by the electronic control section of the

inverter as seen in the inverter layout described in figure 16 (Enslin, 2003). Clause 10 of the EU

standard IEEE Std 519-1992 is the main document which regulates harmonic content from the

output of PV systems. The requirement of PV inverters under this standard is that the total

harmonic current distortion should be less than 5% of the fundamental component. Although

this is generally achieved when using 1 inverter the problem of harmonics can become more


complex when designing large scale PV plants that contain a large number of inverters

connected to the network (Enslin, 2003). When a large number of inverters are connected at

distribution level harmonic resonance can occur between the PV system and the grid in 2

different ways. Parallel resonance occurs due to resonance between the network capacitance

and the supply inductance and where the PV inverter is seen as the source of harmonic

distortion as seen in fig 123. This results in high impedance at the point of resonance which can

cause high voltage distortion at the PCC. Series resonance on the other hand occurs due voltage

distortion in the supply voltage itself which results in low impedance at the point of resonance

and high current distortion. These factors must be considered when connecting large amounts

of PV to the LV and Distribution networks as THD could breach the 5% limit under certain

conditions (Benhabib et al, 2007),(Enslin, 2003).

Figure 19: Parallel and Series resonance circuits (Enslin, 2003).

2.5.5 Inverter Layout in large scale plant

For large scale applications modules are typically connected in strings of series connected

panels in order to insure a significantly high input voltage to the inverter is achieved which

allows for greater DC/AC conversion efficiency (Giral et al., 2010),(SMA, 2010). In terms of inverter

layout within a large scale system there are 2 main kinds of inverter configuration which can be

considered


2.5.6 Centralized inverter layout

The first type of inverter layout and traditionally the most used design is the centralized

inverter system. In this system strings of series connected modules are constructed as

described above, a number of strings can then be connected in parallel in order to meet the

specific power requirement of the plant. A single centralized inverter is then used to connect

the paralleled strings to the grid as seen in figure 20. One of the advantages of a centralized

approach is that only a small amount of inverters are needed for the whole system which mean

in terms of initial capital investment the cost per watt is often lower than other inverter

layouts. From a design point of view these inverters also enable a more simplistic overall

system design and easier on site install. This being said in terms of performance this simplicity

comes at a price, the first problem arises from the fact that as all strings are connected in

parallel designers need to ensure that all strings have the same power output as there is only 1

MPPT system for the whole array. This can be a major disadvantage for designers as strings

cannot be constructed using different module types or varying orientation in order to maximize

performance. Shadowing can also be a major problem in this type of system. As all strings are in

parallel the maximum MMP of each module is limited to the power in the weakest module in

the system, this can be a significant problem in a large plant as if a section of the site is

shadowed by cloud cover or external factors the overall power production of the entire plant

would be reduced. Shadowing can also cause heat damage to modules due to the shadowed

cell or module in a string acting as a load on the system which in turn leads to current flowing

into the showed cell resulting in I2R losses in the form of heat (Giral et al, 2010).Another

disadvantage is that the warranty on large scale central inverters is typically only 5-10 years

which is much shorter than on small string inverters which often have 20 year warranty, this

results in the initial cost of the inverter being tripled over the lifetime of the plant (IFC, 2012).


Figure 20: Centralised layout (left), String layout (right),(IFC, 2012)

2.5.7 Sting inverter layout

The second configuration consists of using string inverters which convert each string of modules from

DC to AC individually rather than as a large group of parallel strings as seen in figure 20.Shadowing loss

and potential heat damage are both minimized in this case as MPPT is carried out on each string

allowing for optimum power production from each string. Another advantage of string inverter is due to

the size and cost compared to a central inverter it becomes economical to have 1 or more spare

inverters onsite which reduces down time in a fault situation. As mentioned before string inverters such

as the SMA Sunny Tripower series offer a 20 year warranty (SMA, 2010). One of the main advantages

of a string inverter system is that maximum power point tracking (MPPT) can be carried out for

each string of panels which means that if a section of the plant has reduced output power due

to shadowing effects only the power output of that group of panels will be effected and not the

efficiency of the entire system (Giral et al., 2010).The arrangement of strings becomes even more

significant in systems when strings are tilted and there is large seasonal variation in sun height

as is the case in Ireland. When there is shading between the strings themselves the efficiency of

the system can be improved greatly if all shaded areas have their own MPPT as seen in figure

21.


Figure 21: String shading and layout of MPPT area within string (Danfoss, 2009)

2.2.8 Single phase inverter layout

In terms of inverter choice designers can also choose between using 1 phase or 3 phase

inverters. One solution in large scale systems is to use single phase string inverters for each

string of modules. The single phase output of 3 inverters can then be connected through a

subfield junction box allowing for a 3 phase output for grid connection. In this type of system it

is imperative that the power is distributed between each phase evenly with no more than

4.6KVA difference between each phase. A power balancer may also be used to maintain even

power distribution however this requires extra cabling between each phase. Figure 22 shows a

layout of a 1.2MW large scale plant using a 1 phase inverter layout feeding into a 20Kv grid

network.


Figure 22: 1.2MW PV plant layout (SMA, 2010)

2.5.8 Three phase inverter approach

An alternative approach to the 1 phase layout is to use 3 phase inverters. By using 3 phase

inverters the inverter output can be fed directly to the main field junction point eliminating the

need for grouping inverters at sub field. This reduces the complexity and also the extra cabling

cost associated with a 1 phase approach. An example of a large scale PV plant using 3 phase

inverters is shown in figure 23 (SMA, 2010).


Figure 23: Example of a 3 phase PV plant design (SMA ,2010)

3.5.9 PV blocks within large scale layout

For multi megawatt installations a PV plant may be made up of individual blocks which can be

connected to the grid network using separate connection points for each block as shown in

figure 24. In order to get further information on the advantages and disadvantages of this

approach David Maguire from the solar development company BNRG Renewables with

headquarters based in the International Financial Service Centre (IFSC) in Dublin was contacted

directly. He explained that although using additional transformers increases system losses

slightly there are design benefits to building large scale PV plants in blocks. The first advantage

comes from the fact that if one block in a plant has a fault the other sections of the plant can

continue to produce power reducing the financial implications of a fault on the system. Another

advantage arises from the fact that each section of plant can be switched into the grid network

as soon as it is constructed and does not depend on the overall completion of the system. This

means that if the construction of the plant has to be completed under a strict deadline due to

changes in government FIT or other support mechanisms as seen in the UK in 2011 if the entire


plant cannot be completed the individual blocks that were complete within the deadline can

still be connected (Maguire, 2012)

Figure 24: PV system made up of blacks (Mitavachan, 2011)

3.5.10 Wiring losses and cost

Another important factor to consider when designing large scale plants is the length of the

cables needed on both the DC side of the plant between the modules and the inverter and on

the AC side of the plant between the inverter and transformer station (Danfoss, 2009). As all

cables have some internal resistance a certain amount of power is lost due to the fact that the

power in a circuit is proportional to I2×R. There is also a corresponding voltage drop which can

be calculated using ohms law as seen in equation in conjunction with the cable resistance which

is usually provided by the cable manufacture in Ω/km (Wiles, 2001).


" = 23 Equation 6

= 2 × Equation 7

if the distance between major components on the AC or DC side of the system is significant a

larger diameter cable may be needed in order to reduce voltage drop which results in a

increase in overall cable cost, therefore when designing a large scale it is imperative that the

system is designed in a way that minimizes cable distance on both the AC and DC side of the

plant. This being said when designing a PV system there is a balance between cable cost and

efficiency, in must designs a certain amount of power loss is accepted as long as the overall

cable loss is kept less than 1% of system output. In order to reduce the diameter of cable

needed in large scale plants it is optimal to have a high DC voltage in the range of 600-700 volts

which allows for small diameter cable to be used (Danfoss, 2009). Another point to consider is

the fact that generally the DC voltage will be larger than the corresponding AC voltage which

means in order to reduce system losses it may be preferable to design the system such that all

long cable paths are on the DC side. For most designs 4mm2 solar cable will be sufficient to

keep losses under 1% up to a distance of 200m on the DC side of the system, for any distances

longer than this 6mm2 may be required. There are a number of design options in terms of

inverter and transformer placement, the first design option and most efficient in terms of cable

loss on both the AC and DC side of the plant is a quadratic layout where a compact transformer

station is placed centrally in the plant and all inverters are placed together at a central point

near the transformer connection as seen in figure 25 (Danfoss, 2009). The use of compact

transformer stations in this configuration is generally the preferred option for plants connected

to the LV or MV system as cable length is minimized both on the AC and DC of the plant. As

mentioned above this type of layout also allows for direct connection from inverter to the

transformer station if there is a significantly high DC voltage which means there is no need for

an additional combiner box on the AC side of the plant. The second approach is to place the

inverters close to each string of modules as seen in figure 26. Although this approach decreases


cable length on the DC side between modules and inverter it often leads to much longer AC

cable runs which can result in higher losses.

Figure 25: Quadratic PV plant layout, (Danfoss, 2009)

Figure 26: PV plant design with inverters decentralised (Danfoss, 2009).


Chapter 3- Methodology

This section highlights the main tools used in this study to accurately determine the potential for large

scale PV generation in Ireland. In terms of methodology the study was broken up into 4 individual

sections which include an initial resource assessment, a comparison of PV technologies, the construction

of a large scale PV system model and finally an economic analysis .A methodology schematic diagram

can be seen below which shows each of the 4 sections and the corresponding tools that were employed

at each point of the study in order to achieve the aims and objects of the overall project.

3.1 Solar Resource assessment

5 data sources consisting of ground based measurements and satellite data were used to

complete the initial resource assessment as seen in section 2.3.2. The first parameter which

was modeled using this data was the total irradiation on a horizontal surface which was

calculated on a kWh/m2/day basis for every month of the year. The second parameter modeled

was the ratio of diffuse radiation to global radiation which was also modeled on a monthly

basis. All data analysis was carried out using Microsoft Excel and all relevant calculations can be

found on the data CD attached with this document.

Resource Assessment

Climate-SAF PVGIS

PVGIS Classic

Met Eireann

Focus building DIT

Meteonorm

Technology Comparison

PVSYST

DIT Recorded

Module Data

Large Scale Model

PVSYST

BNRG Renewables

Economic Study

NPD Solarbuzz Module Price Index

BNRG Renewables


3.2 Software used to model performance

3.2.1 PVSYST

In order to estimate the potential yield of each technology type the PVSYST software package

which was developed at the University of Geneva and is currently the most used PV estimation

software in Europe was used. The model itself contains a wide range of input parameters

including temperature coefficients, tilt angle, solar cell type, shading, module degradation,

mismatch losses, I-V characteristics and many other specifications making it one of the most

accurate yield assessment tools available to PV developers (Mermoud, 1995). Importantly the

software also has a large database of models corresponding to known PV panels and inverters

which includes models for the Kaneka a-SI module, Sanyo HIT module, Sharp NE-80E2E p-SI

module, Sunpower Spr-90 m-SI module and Sunteck STP m-SI module.

3.2.2 Validation of PVSYST model

As PVSYST uses manufacture data to estimate a modules potential power generation it was

imperative that all data being used was measured using the same operating conditions and was

calculated in accordance with all relevant standards. The main standard which governs the

measurement of a PV modules performance is IEC 60904 which lays down a set of standard test

conditions (STC) that all modules must be measured under. These STC can be defined by a

module temperature of 25°C at an irradiance level of 1000 W.m-2 under a reference spectral

distribution of AM 1.5. PVSYST also uses Normal Operating Cell Temperature (NOCT) as a

performance indicator which must be calculated under an irradiance of 800W/m2, ambient

temperature of 20oC and wind speed of 1m/s and as specified in both IEC 61215 and IEC 1646

for c-SI and Thin film PV respectively. Another set of significant parameters used in the PVSYST

model are the temperature coefficients of short circuit current ISC (α), open circuit voltage VOC

(β) and maximum power PMAX (δ). Standards IEC 61215 and IEC 1646 define the procedure for

measuring temperature coeffcients which involves recording these values either during cooling

down or heating up of the module over a 30°C sweep of 5°C intervals. An important point to

consider when using temperature coefficients as a performance indicator is that they are only

valid for the irradiance level at which the measurements were made unless the linearity of the

module is specified in which case the values for each temperature coefficient are valid over


±30% of the irradiance value they were recorded at and not over all irradiance levels. All

module manufacture data used in this study is in compliance with the standards set out above.

3.2.3 PVSYST 3-D shading tool

Within the PVSYST software a 3-D layout of the PV system can also be constructed which

allows for a detailed analysis of shadow loss due to external objects. This tool can also estimate

shading between different strings within a large scale system which means the optimum

distance between each shed of PV panels can be estimated. For a more detailed shading loss

calculation the layout of PV strings within the PV area can also be specified which means when

estimating power output only the shaded group of strings will be effected and not the entire

system. In the case where a section of a string is shaded completely the electrical output of the

whole string is deemed to be 0 (Mermoud, 1995).

3.2.4 Climate data base used for PVSYST study

In order to estimate energy yield from a particular module climate time series data including

horizontal global radiation, ambient temperature and diffuse radiation data was imported into

the PVSYST software. The database that will be used for this project is the Meteonorm global

meteorological database which is specifically designed to provide accurate data for solar

planners and engineers. For the purpose of direct comparison of all PV modules the same

climate location were used corresponding to an area in Dublin with the coordinates 53.07,53,4

North,-6.02,-6, 1 West. As PVSYT uses internal models to convert horizontal radiation data to

radiation on an inclined surface it was important to consider which model would achieve the

most accurate results. The 3 main models considered were Hay’s model, Reindl’s model and the

Perez model which are all designed to estimate diffuse radiation on inclined surfaces. As it was

reported that the Perez model has the lowest route mean squared error out of the 3 models

the Perez model was used in PVSYST for all calculations (Soga, Akasaka & Nimiya, 2009).


3.3 Models used in Comparative study

3.3.1 Recorded DIT data

The recorded current and voltage from each panel in conjunction with the corresponding

irradiance data allowed for the calculation of module efficiency at any given time. This was

achieved by calculating the MPP for each time interval which was then divided by the area of

the module which allowed each module to be compared on a W/m2 power base. The efficiency

of each panel could then be obtained by dividing the electrical energy on the DC side of the

system by the corresponding irradiation falling on the PV panel as seen in equation 8 (Jiang &

Lim, 2010).

45647% = 9" × ::Equation 8

As all panels consist of different sizes in terms of power output a second parameter was needed in order

compare performance. The PR ratio which shows the difference between the actual and

theoretical maximum power output for any given climate conditions was deemed the best way

to compare each module in this study and is widely regarded the best tool to compare different

types of PV systems. International standard IEC 61724 also considers the PR to be the most

effective tool to measure and compare PV performance from different systems. The 3 relevant

formulas needed for this calculation are shown below (Jiang & Lim, 2010).

" = 5;<7=>6?@56;A@ 66646@56;A@ Equation 9

@ = <7=>6?6B7C>C>2=>;;6A"DE645>7Equation 10

@ = 2";64>C;2A5>5D 666462A5>5D Equation 11


3.3.2 PVSYST Comparative model

As recorded data was only available for the months of June July and August from 2010 PVSYST

was used in conjunction with the recorded data in order to determine the seasonal variation in

module output over a full year. In order to estimate the area requirement for each technology a

theoretical 1kW system was created for each module type in PVSYST. The average PR and

efficiency was calculated for each 1KW system. This allowed direct comparison between all

modules tested. Additionally PVSYST allowed for the main losses in the system to be plotted

individually which resulted in a greater understanding of the performance of each module

under Irish Climate conditions. Using this function within PVSYST 2 addition plots were created

for each module. As module performance under low irradiance levels is a key factor for PV

installations in Ireland a graph showing module efficiency plotted against irradiance in W/m2

was created to show how irradiance level affects the efficiency of each module, in order to

isolate the loss due to irradiance level from other losses in the system a second graph was

created showing irradiance loss measured in watts plotted against irradiance level in W/m2.

3.3.3 Large scale system performance

In order to examine the performance of a large scale ground mounted system in Ireland a 1MW

PV system was constructed in PVSYST using the same climate conditions used for the 1KW

comparative study. In order to improve the accuracy of this model BNRG renewable were

contacted who provided information regarding standard practices within the large scale PV

industry. This included information regarding specific limits on losses within the system,

appropriate plant layout, grid connection point and guidelines for the acceptable levels of

performance expected from large scale systems.

3.4 Economic methodology As module price has dropped considerable since the 5 modules studied in this project were

installed the main source of data used to compare current module prices was the NPD

Solarbuzz Module Price Index which allowed mono-crystalline, multi-crystalline and thin film

modules to be compared in terms of €/WP based on 2012 retail prices.


For the large scale system 2 economic parameters were used to determine the economic

viability of the modelled 1MW PV plant. The cost of electricity (COE) produced was the first

parameter used in the study and was calculated using the equations shown in section 2.4.1 and

presented in both €/kWh and €/MWh. Secondly a NPV calculation was carried out in order to

determine the level of subsidy needed for the system to generate a profit over the estimated

25 year lifetime of the system. 2 separate NPV calculations were carried out using the

equations shown in 2.4.1 for discount rates of 8% and 10% respectively. BNRG Renewables also

provided prices for initial construction, operation and maintenance and external transformer

costs which allowed for greater accuracy in terms of capital cost estimation.

Chapter 4-Results

4.1 Initial assumptions within the PVSYST model

In order to compare each technology PVSYST was used to measure the performance of each

module under Irish climate conditions using a Dublin location with coordinates 53.07,53,4

North,-6.02,-6, 1 West as outlined in section 3.3.4.To insure all conditions were identical for all

modules initially the optimum tilt and azimuth angle of the panels for the location was chosen

based on maximizing irradiance capture throughout the year. From the optimization graph

below it can be seen that a tilt of 35o and azimuth angle of 0

o corresponding to directly south

resulted in the greatest annual irradiance capture for the location studied.

Figure 27: PVsyst model for optimum tilt and azimuth angle


For the next part of the calculation shading loss due to the position of the sun with respect to

the tilt of the panels was calculated. To achieve this estimation a sun height diagram was

constructed for every day in the year in PVsyst as seen in figure 29. The blue lines in this

diagram correspond to the points at which the suns angle passes behind the plane of the tilted

arrays and therefore no direct beam radiation falls on the modules. As a typical PV grid

connected system contains a number of modules connected in series or parallel for the purpose

of these calculations each of the PV module types were constructed into arrays which have an

AC nominal power output of 1kW. The 3-D drawing tool was then used in PVSYST in order to

estimate shading loss due to the layout of the arrays themselves. For simplicity a perfectly flat

surface was chosen with no surrounding obstacles in the form of buildings or tress and

therefore the only near shadings were at low sun angles when the sun was passing behind the

plain of the array and therefore a section of the array was not receiving radiation. The shading

loss at these points are shown by a series of black lines corresponding to different shading loss

percentages in figure 29 for a 1kW array containing 5 Sanyo HIT-215NHE5 panels.

Figure 28: Sanyo array layout within PVsyst (PVsyst, 2012)


Figure 29: Shading loss diagram for Sanyo array (PVsyst 2012)

4.2 PVSYST 1kWP comparative study

Using the method described in above 5 1kW systems corresponding to each module type

currently installed in the Focus building in DIT were modeled in PVSYST, the technical

specifications including inverter type, number of panels and I-V characteristics for each array

are shown in Appendix A,B,C,D, and Erespectively. the PV array loss factors for each 1kW

system were also included in the simulation and can also be seen in appendix A,B,C,D and E,

theses loses included mismatch loses due to each module in the string having slightly different

I-V characteristics which were set at 2% of the MPP, quality loss which shows the difference

between manufacture performance data and actual performance which was set at 2.5% and

finally incident angle modifier (IAM) loss which can be defined by the weakening of the

irradiation really reaching the PV cells's surface, with respect to irradiation under normal

incidence and which is effected by transmission and reflection of radiation on the protective

material on the front of the panels. PVSYST uses the ASHRAE model shown below which was

originally identified in Souka & Safat (1966) and is shown in equation 12 to estimate this loss.

The value of b0 determines the significance of the overall loss factor and was set at 0.05 based


on the recommendations for crystalline PV within PVSYST. The value of F corresponds to the

incident angle on the plane of the array.

2 = − GD × H #$%5 − IEquation 12


4.2.1 Sanyo modeled performance

Figure 30: Sanyo modelled output, (PVsyst, 2012)

Table 3 Sanyo results

No

rma

lize

d a

rra

y p

rod

uct

ion

KW

h/K

WP

/da

y


4.2.2Kaneka modeled performance

Figure 31: Kaneka modelled results (PVsyst, 2012)

Table 4 Kaneka modelled results (PVsyst, 2012)

No

rma

lize

d a

rra

y p

rod

uct

ion

KW

h/K

WP

/da

y


4.2.4 Sharp modeled performance

Figure 32: Sharp modelled results, (PVsyst, 2012)

Table 5: Sharp modelled results (PVsyst, 2012)

No

rma

lize

d a

rra

y p

rod

uct

ion

KW

h/K

WP

/da

y


4.2.5 Sunpower modeled performance

Figure 33: Sunpower modelled results (PVsyst 2012)

Table 6 Sunpower modelled results (PVsyst)

No

rma

lize

d a

rra

y p

rod

uct

ion

KW

h/K

WP

/da

y


4.2.6 Sunteck modeled performance

Figure 34: Sunteck modelled results (PVsyst 2012)

Table 7: Sunteck modelled results (PVsyst 2012)

No

rma

lize

d a

rra

y p

rod

uct

ion

KW

h/K

WP

/da

y


4.3 PVSYST results for 1KW system

As the inverter chosen for each array was different the associated system losses were different

for each array. Therefore in order to directly compare each modelled system the inverter losses

were added back into the final system yield which meant that the only losses which contributed

to system output were the array losses. The normalised output of each array was compared on

a kWh/KWP/day basis as seen in table 8.In terms of energy yield and efficiency the Sanyo

module performs the best with a final yield of 2.64kWh/KWP/day and an average annual

efficiency of 14.83%. These simulated values correlate well with what was found in (Ayompe et

al 2007) where a yield of 2.62kWh/KWP/day and average module efficiency of 14.9% were

recorded for a 1.72KwP Sanyo array installed in DIT. The Sunpower m-Si module was the second

best performing module with an array yield of 2.57kWh/KWP/day and an average efficiency

of14.71%. In terms of array losses which are affected by module temperature and irradiance

level the Sanyo module also performs the best with average array loss of 13%. Interestingly the

a-Si simulated array does not perform well under Irish climate conditions and has the highest

array loss of all simulated modules especially during the months of December and January

where an array loss of 25% was estimated as seen in figure 31. In terms of the area requirement

for each 1KW array it can be seen that the a-Si array requires over twice the land area to

produce the same power as the other 4 module which is a major disadvantage for large scale

PV applications. Finally it can be noted that the array loss for both the Sharp and Sunteck

modules increases during the summer months of May June and July, this behaviour can be

attributed to the fact that both these module have a temperature power coefficient of -0.48

%/°C which is 1% higher than any of the other 3 modules and leads to greater power loss at high module

temperatures.

Model Type kWh/kWp/day Efficiency Array area requirement (m2) PVSYST Array LC

Sanyo HIT 2.64 14.83 6.3 13

kaneka a-Si 2.41 5.03 17.1 20.3

Sharp poly 2.53 10.49 7.6 16.6

Sunpower m-Si 2.57 14.71 6.6 15.3

Sunteck m-Si 2.54 10.38 7.8 16.4

Table 8: Module comparison table


4.3.1 Irradiance loss

The performance of a PV module under low irradiance levels can significantly affect the final

energy yield from a system (Donovan et al, 2010). As a result of this when choosing a module

for an Irish system it is vital that the module used has the ability to extract energy at low

irradiance levels. In order to analyze the effect of irradiance level on module performance

PVSYST was used to isolate irradiance loss from other losses in the system. This allowed for the

creation of a graph showing incoming radiation measured in W/m2 plotted against irradiance

loss measured in watts. Loss due to irradiance level was estimated for all 5 modules currently

installed in DIT which meant each module could be compared in terms of low irradiance

performance. As the 1kW PVSYST study found that the Kaneka a-Si module performed the

worst of all modules under Irish Climate conditions a Biosol XXL 124 triple junction a-Si module

was also modelled in order to see if this type of module showed any significant performance

improvements compared to the single junction a-Si module. The results for all modules can be

seen in figure 35.As expected the Sanyo panel shows the best performance under low

irradiance and high irradiance conditions with a loss of just 12 watts at an irradiance level of

400W/m2 and a loss of just 2 watts at a level of 800W/m

2. The kaneka panel shows high losses

at all irradiance levels especially at levels between 300-600W/m2 where losses of 25-30 watts

are estimated. Interestingly the triple junction module shows the best performance out of all

modules at irradiance levels between 200-400W/m2 where losses are under 10 watts. All other

modules show similar losses over all irradiance levels.


PV

Lo

ss d

ue

to

irr

ad

ian

ce (

Wa

tts)

P

V L

oss

du

e t

o ir

rad

ian

ce (

Wa

tts)

Figure 35: (A: Kaneka a-SI), (B: Sunteck), (C: Sunpower), (D: Sanyo), (E: Sharp), (G: Biosol a-SI H triple)

A. B.

C. C.

D. E.

W/m2

W/m2

PV

Lo

ss d

ue

to

irra

dia

nce

(W

att

s)

PV

Lo

ss d

ue

to

irr

ad

ian

ce (

Wa

tts)

W/m2 W/m2

PV

Lo

ss d

ue

to

irra

dia

nce

(W

att

s)

PV

Lo

ss d

ue

to

irra

dia

nce

(W

att

s)

W/m2 W/m2

PV

Lo

ss d

ue

to

irra

dia

nce

(W

att

s)

PV

Lo

ss d

ue

to

irra

dia

nce

(W

att

s)


4.4 Recorded data results The recorded I-V characteristics for the 5 panels were analyzed in Microsoft Excel. The data was

arranged to show power measured in W/m2 plotted against corresponding radiation measured

in kW/m2 for all 5 modules using the methodology outlined in section 3.3.1, the efficiency

graphs for all 5 modules are shown in appendix 6.The average efficiency for each panel was

then estimated by dividing the module power by the incoming radiation. The PR was also

calculated for each module by dividing the actual array power calculated in W/m2 by the power

achievable at STC. The results of all calculations are table 9.

Manufacture Model Efficiency PVSYST % Recorded Efficiency% Recorded PR

Kaneka G-EA060 5.03 2.9 46.1

Sharp NE-80E2E 10.49 7.4 54.36

Sunpower SPR-90 14.71 10.46 63.41

Suntech STP080B12/BEA 10.35 7.358 59.34

Sanyo HIP-215NKHE5 14.83 10.63 61.882

Table 9: Results from DIT recorded data

From the table of results presented above it can be seen that the recorded data suggests a

lower overall efficiency for all 5 modules compared to the PVSYST results however this may be

attributed to the fact that the PVSYST model represents module performance in ideal

conditions with no external shading at an optimum tilt angle of 350, in contrast to this the

modules installed in DIT were monitored at a tilt angle of 530 and additionally are installed on

R² = 0.7679

0

10

20

30

40

50

60

70

0 0.2 0.4 0.6 0.8 1 1.2 1.4

Wa

tts/

sq.m

kW/sq.m

Kaneka


the roof of a building and therefore external shading could be an issue in regards to power loss.

This being said in the recorded data shows the same trend as the PVSYST results with the Sanyo

module operating at the highest efficiency of 10.63% closely followed by the m-Si Sunpower

module with 10.46% efficiency. Both the p-Si Sharp module and the Sunteck module are also

equally matched with recorded efficiencies of 7.4% and 7.3% respectively. Interestingly The

Sunpower module has a slightly better recorded PR at 63.4% compared to a PR of 61.8% for the

Sanyo module indicating the m-Si Sunpower panel is operating closer to its maximum

theoretical output on average. As with the PVSYT results the Kaneka module recorded results

are the worst with a PR of just 46.1% and average efficiency of 2.9%.

4.5 Economic consideration

As there has been a significant decrease in PV module cost since early 2008 the prices that the

modules studied above were purchased for in 2007 do not reflect the current costs associated

with PV generation. The first factor which has contributed to the fall in module price is the

expansion in the number of PV module suppliers within in the industry which has meant that

the once dominant European, US and Japanese market has seen more competition from

Chinese and Taiwanese producers. This increase in supply also occurred in conjunction with

Spain announcing a 500MW limit on their PV FIT and a global recession which meant that there

was significant over supply in the market. With this in mind the cost associated with each

technology will compared based on the current market price in terms of €/WP as opposed to

using the original 2007 costs for each module. The main source data with regards to module

pricing used in this study was the NPD Solarbuzz Retail Module Price Index which tracks retail

pricing data for PV modules for both the US and European market. Figure 36 shows retail price

trend from 2001-2012 where it can be seen that between 2007 and 2012 the average market

price for PV modules has dropped from 4.5€/WP to 2.17€/WP.


Figure 36: Solarbuzz Retail Module Price Index (Solarbuzz, 2012)

The Solarbuzz data also shows that 34% of modules currently on their data base of over 900

modules are retailing for under 1.54€/WP. The data also shows that the lowest priced mono

crystalline module currently in the European market is 0.81€/WP, the cheapest multi crystalline

module is 0.78€/WP and the cheapest thin film module cost 0.62€/WP. as shown in figure 37.

Figure 37: Solarbuzz Retail Module Price Index, short term (Solarbuzz, 2012)

4.5.1 Retail price comparison

In order to see whether the data presented by Solarbuzz is a true representation of what is

happening in the PV retail market the prices for a number of PV modules currently available

were sourced from online suppliers. A number of different types of technologies were


compared including poly crystalline, mono crystalline, a-Si and HIT modules. The corresponding

cost in €/WP was calculated for each module and all results were compared as seen in table 10.

Model Type Power (WP) price Efficiency €/WP

Sharp NU-185E1 mono 185 246 14.1 1.33

LG 250S1C mono 250 301.9 15.5 1.21

Schott Mono 195 mono 195 316 14.5 1.62

Suntech STP 195S-24/Ad+ poly 195 230.9 15.3 1.18

Schott Poly 235 poly 235 313 14.5 1.33

REC 245PE poly 245 303 14.8 1.24

Sanyo HIT-N235SE10 HIT 235 485 18.6 2.06

Kaneka GSA 60 a-Si 60 68 6.3 1.13

Table 10: Retail price comparison between technologies (GreenWorldInvestor 2012),(Solarshop-

Europe, 2012)

From the results shown above it can be seen from that both m-Si and p-Si modules and a-Si modules are

very evenly matched in terms of price and efficiency. This correlates well with the price trend in the

Solarbuzz data where it was found that there was only 0.03€/WP difference between the cheapest

m-Si and p-Si module. The Sanyo HIT module is the dearest module in terms of €/WP however

this in terms of efficiency performs 3% better than any of the other modules. The 2007 £/WP

prices for each of the 5 panels installed DIT were reported in (Mc Glynn 2010) where it was

concluded that all PV technology types retailed above 3£/WP. Based on the retail prices for

each of the modules above this indicates PV module prices have decreased by over 50% for

each technology type since 2007. It can also be noted from the module prices shown in table 10

that both p-Si and m-Si prices are moving closer to a-Si thin film prices which means a-Si no

longer has enough of a cost advantage over c-Si to compete in the market. The dramatic

reductions in cost in the c-Si sector coupled with the fact the a-SI producers are not able to

mass produce a-Si modules with a competitive cost have caused a downturn in a-Si production

which has been widely reported. a-Si has also failed to make enough improvements in terms of

cell efficiency to compete with other technologies (PV Insights, 2012).


4.6 Large scale system PVSYST model In order to estimate the potential of large scale generation in Ireland it was necessary to use

PVSYST to accurately model the performance of a large scale system. From the 1KWP

comparative study described in section 4.2 it was clear that the Sanyo HIT module performed

best under Irish climate conditions and was therefore the technology type chosen for the large

scale system. As the module installed in DIT is no longer being manufactured a Sanyo HIT-

N235SE10 module which is one of Sanyo’s current products was used in the PVsyst model

(Solarshop-Europe, 2012). The same co-ordinates, climate model and module orientation of 35o

used for the 1kwp study were again employed for the large scale system. In terms of power

output the plant was designed to achieve as close as possible to 1MWp. In line with what was

found in the literature review a quadratic system layout where the transformer is placed

centrally and all inverters are placed as close as possible to the transformer was deemed the

best design solution. With this in mind a system layout was constructed in PVSYST as shown in

figure 40.From this 3-D construction it can be seen that the PV plant has been broken up in 4

distinctly separate sub arrays containing 35 sheds each with 2 strings of PV panels per shed. In

order to improve conversion efficiency each string contains 17 Sanyo modules connected in

series which gives a Vmpp of 660V. A Sunny Tripower 15000 TL 3 phase string inverter was

chosen for DC/AC conversion as it contains 2 separate MPPT inputs and a rated power 15kw

which was required in this system. 2 parallel strings were connected to each MPPT input as

shown in figure 38 which meant each sub array had a max operating power of 271kWp giving a

total AC system output of 1.08MW. The system parameters for 1 of the 4 sub arrays are shown

in figure 39 which was taken directly from PVSYST. The total module area required for this

system was 6002m2.


Figure 38: Circuit diagram of 1 inverter with 2 MPPT inputs (PVsyst, 2012)

Figure 39:System parameters as defined in the PVsyst software for 1 sub array (PVsyst 2012)


Figure 40: PVsyst 1MW system design (PVsyst, 2012)

4.6.1 String shading diagram

After the initial system design stage was complete an estimation of shading loss due to both

sun height variation and shading between each PV shed was completed. As described in the

literature review shadow loss was estimated separately for each MPPT area. A shading loss

diagram was then created in PVSYST as seen below. From this diagram it can be seen that

shading between PV sheds has a significant effect during the months of December, January and

February especially in the early morning and in the evening with 20% shading loss between the

hours of 8.00-10.00 and 16.00-17.00.


Figure 41: Shadow loss or 1MW system

4.6.2 Wiring size calculation

As described in the literature review it is standard practice when designing large scale systems

to insure that the voltage drop on both the DC and AC cables is less than 1% of overall voltage.

The first step in terms of cable size estimation involved measuring the average distance

between the modules and the inverters and the inverters and transformer from the system

layout shown in figure 40.This resulted in an average DC cable length of 80 meters and an

average AC cable length of 10 meters. Voltage drop calculations were then carried out using the

ohm/km resistance rating for a number of different cable sizes. This resulted in 4mm2 copper

single core cable with a ohm/km rating of 4.61 being deemed the best size for DC cable

requirements with a percentage voltage drop of 0.676% .6mm2 4 core cable with a resistance

rating of 4.3ohm/km was deemed the best size of cable for the AC side with a voltage drop

percentage of just 0.95%.Equation 13 shows how the voltage drop for each cable was

calculated with all results shown in table 11.

%A = J2""× :::×K

"" L × ::Equation 13


Column1 cable size length ohm/km current (IMP) Vd % Vd

DC side 4mm2 80m 4.61 10.96 4.46 0.676

AC side 6mm2 10m 4.3 21.92 1.29 0.195

total Vd 0.872

Table 11: Voltage drop calculations for large scale system

4.6.3 System performance

The system performance of the plant was modelled using climate data imported from Meteonorm for a

Dublin location with co-ordinates 53.07,53,4 North, -6.02,-6, 1 West. The first parameter that was

modeled using PVSYST was the performance ratio of the plant. From figure 42 it can be seen

that the plant has an average annual performance ratio of 81.7% indicating that the system as a

whole is operating efficiently with an actual performance that is only 19% behind the max

theoretical energy output. In order to find out what PV designers typically aim for when

designing large scale systems BNRG Renewables were consulted and it was discovered that for

large scale systems they typically design their plants for a PR of 84% given current technologies

which is 3% greater than what was achieved with the 1MW system modeled in this study

(Maguire, 2012). For the next part of the study a detailed loss diagram was constructed in

PVSYST which estimated losses at all stages in the system as shown in figure 43.When system

losses are taken into consideration it can be seen that the annual AC electricity generation

which could be injected into the grid is 1012MWh/annum.

Figure 42: PVsyst 1MW system results (PVsyst, 2012)


Figure 43: Loss factors for 1MW system

4.6.4 Economic calculation

The main driving force that determines the feasibility of a large scale plant is the potential profitability

from electricity generation over the full lifetime of the plant. In order to carry out an accurate economic

analysis all major components that contribute to the capital and running costs of the plant must be

factored into all calculations. As the reliability of the data used in any economic study is crucial to the

accuracy of the results BNRG Renewables who have designed, installed and managed both commercial

and multi megawatt system in the UK and internationally were connected. From these discussions it was

concluded that for a 1MW plant the most optimal grid connection level from an economic standpoint

was 10KV as this reduced the cost of the external transformer considerable compared to connecting at

20KV. Based on the details of the plant and on past experience it was suggested that a refurbished

transformer would cost in the region of €50,000. Operation & Maintenance costs were also discussed


with BNRG Renewables who explained it was their policy to include this cost as an annual fixed cost

which varies between €20,000-25,000/MW/annum with costs usually closer to €25,000/MW/annum.

Initial construction cost was also found to be €100,000/MW however this value is based on the fact that

BNRG Renewables do not use concrete foundations for their systems and instead use ramming where

the module structures are inserted directly into the ground. The wiring cost shown in table 12 was

estimated using prices advertised by online suppliers in conjunction with the cable length required

based on measurements from the PVSYST scene view of the system (TCL, 2012). Although these factors

do have an effect on initial capital cost in terms of overall contribution the 2 most significant

parameters in a large scale PV plant are the modules and inverters as seen in the cost breakdown in

table 12.

Components Quantity Cost/Unit (€) Overall Cost (€)

Modules & Inverter

Sunny Tripower 15000Tl 72 €4,106 €295,632

Sanyo HIT module 5040 €485.92 2449036.8

Wiring

DC cable 4320 m €0.40/m 1728

Ac cable 1440 m €3.82/m 5500.8

Grid Connection Devices

Switch Gear 1 €10,000 10,000

External transformer 1 €50,000 50,000

Construction & Maintenance

Operation & Maintenance 1 €20-25,000/MW/annum 25,000

Initial construction 1 €100,000/MW 100,000

Total Cost 2936897.6

Table 12: Total cost of 1MW plant.

The COE and NPV were the 2 main parameters used to estimate the economic potential of large

scale PV in Ireland. In order to estimate the cost of PV equation 14 shown below was used. The

Fixed charge rate which reflects interest rates was set at 10%.It can be seen from the results

below that the cost of generating electricity from the 1MW PV system in Ireland is 0.315€/kWh

which equates to 315€/MWh. The average price for domestic PV generation in Ireland was estimated to

be 0.48€/KWh in (Ayome et al. 2008) which shows that the cost to produce electricity in Ireland has

fallen by approximately 0.17€/KWh based on 2012 figures. This being said the highest reference price


currently offered to any renewable system on the Irish REFIT scheme is 81.49€/MWh for Biomass landfill

gas. This means that if large scale PV was to be included on the REFIT scheme a reference price more

than 3 times higher than any other current technology would need to be set in order for large scale PV

to become viable.

= × ×& Equation 14

MNO = P.RSTUVVUWX×Y.Z×P[YYYZYZP×ZYYY = 0.315€/KWh

The next economic calculation which was carried out was a NPV analysis which involved finding

the present value of all future income and expenditures. As the discount rate used in an NPV

analysis can have a significant effect on whether a project is deemed to be viable or not a rate

of 8% which was estimated in (Muneer, 2011) and rate of 10% were used. A number of

different scenarios were considered in terms of the price the PV generator would receive for

power, the average estimated SMP for 2011 of 65€/MWh was considered the base case which

reflected the price the PV generator would receive if the system was competing in the wholesale market

with no tariffs (EIRGRID&SEAI, 2011). The second scenario was the estimated NPV if the generator

received the equivalent of the UK’s original fixed tariff from 2010 of 30.7p/kWh which equates

to 387€/MWh given current exchange rates. The 3rd scenario considered is the potential return if a fixed

tariff of 400€/MWh was implemented.


Figure 44: Average expected SMP 2011 (EIRGRID&SEAI, 2011)

Tariff Scenario Discount Rate NPV (€)

whole sale price 65€/MWh 8% -2754814.022

2010 UK Tariff 387€/MWh 8% 643814.4456

Fixed Tariff 400€/MWh 8% 784251.8011

whole sale price 65€/MWh 10% -2939809.908

2010 UK Tariff 387€/MWh 10% 18070.6609

Fixed Tariff 400€/MWh 10% 83025.95927

Table 13: NPV analysis of large scale system

From the results shown in table 13 it is clear based on the parameters used in this study large

scale PV generation in Ireland is not feasible if there is not significant subsidies in place. From

the NVP analysis it was found that if PV received the current average SMP this system would


make a loss of 2.7-2.9 million over an estimated 25 year lifespan. This being said if a fixed tariff

equivalent to the UKs original 2010 offering was employed in Ireland the system would

generate a positive NPV between €18070- €643,000. Finally a 400€/MWh fixed tariff would

result in a positive NPV in the range of €137488-€784252.

Chapter 5 Conclusions Firstly in terms of resource estimation it was shown that Ireland and the UK are very evenly matched in

terms of resource with only 0.44kWh/m2/day difference between the highest recorded radiation

levels for both locations .There is significant seasonal variation in terms of solar radiation in

Ireland with a 4.4kWh/m2/day difference resource between June and December. The diffuse

component of global radiation is also over 50% which means the type of technology chosen for

an Irish system must have the ability to extract harness energy in these conditions.

In terms of technology both the recorded and PVsyst modelled data show the best performing

panel in terms of efficiency is the Sanyo HIT module. This being said the m-Si Sun power

module comes a close second and the recorded data suggests the PR of the Sun power module

is slightly better. The a-Si module performs the worst especially at low irradiance levels which

was the opposite to what was suggested in the literature review. This being said the triple a-Si

panel modelled in PVsyst shows extremely good performance under low irradiance levels

between 300 and 500W/m2.In terms of space requirement the a-Si modelled array required

double the area of any of the other modules to produce the same power output which is a

major disadvantage in terms of a-Si being used for large scale systems. In terms of cost a-Si

technology doesn’t have the same cost advantage over c-Si that was reported in (Mcglynn

2010) and comparison of the prices originally paid for the panels in DIT and current retail prices

suggests that all technologies have fallen by over 50% in price.

Based on the results from the 1MW modelled system Large scale PV cannot compete in the

wholesale market without some type of support mechanism given that the COE is 0.315€/KWh.

However with a fixed tariff of 0.387€/KWh equivalent to the 2010 UK would provide a positive NPV. This

being said as the current highest reference price on the Irish REFIT scheme is 81.49€/MWh it is unlikely


the Irish government would implement a reference price high enough to make Large scale PV

economical given current costs especially as such a scheme would result in an increase in the PSO levy

which would be have to be paid by the consumer.

5.1Further research

• A Further study of a-Si triple technology under Irish climate conditions with recorded

data would be interesting given the results obtained in this report.

• An economic study on PV price to determine if the current downward price trend will

continue in the long term would be useful.

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MSc Energy Management 2012 Page A

Appendix A

Kaneka PVsyst data

MSc Energy Management 2012 Page B

Appendix B

Sanyo PVsyst data

MSc Energy Management 2012 Page C

Appendix C

Sunpower PVsyst data

MSc Energy Management 2012 Page D

Appendix D

Sunteck PVsyst data

MSc Energy Management 2012 Page E

Appendix E

Sharp PVsyst data

Sharp

MSc Energy Management 2012 Page F

Appendix E

PVsyst W/m2 VS irradiance

MSc Energy Management 2012 Page G


A. B.

C. D.

E. F.

No

rma

lize

d a

rra

y p

rod

uct

ion

KW

h/K

WP

/da

y

No

rma

lize

d a

rra

y p

rod

uct

ion

KW

h/K

WP

/da

y

No

rma

lize

d a

rra

y p

rod

uct

ion

KW

h/K

WP

/da

y

No

rma

lize

d a

rra

y p

rod

uct

ion

KW

h/K

WP

/da

y

No

rma

lize

d a

rra

y p

rod

uct

ion

KW

h/K

WP

/da

y

No

rma

lize

d a

rra

y p

rod

uct

ion

KW

h/K

WP

/da

y

MSc Energy Management 2012 Page H

Appendix F

PVsyst efficiency VS irradiance

MSc Energy Management 2012 Page I


A. B.

C. D.

E. F.

En

erg

y A

rra

y /

rou

gh

are

a

En

erg

y A

rra

y /

rou

gh a

rea

E

ne

rgy

Arr

ay

/ ro

ug

h a

rea

En

erg

y A

rra

y /

rou

gh

are

a

En

erg

y A

rra

y /

rou

gh

are

a

En

erg

y A

rra

y /

rou

gh

are

a

MSc Energy Management 2012 Page J

Appendix G

A-Si triple data

MSc Energy Management 2012 Page K

Appendix H

Recorded data

R² = 0.7093

0

20

40

60

80

100

120

140

0 0.2 0.4 0.6 0.8 1 1.2 1.4

sunteck

sunteck

Linear (sunteck)

R² = 0.7668

0

20

40

60

80

100

120

140

160

0 0.2 0.4 0.6 0.8 1 1.2 1.4

sanyo

sanyo

Linear (sanyo)

MSc Energy Management 2012 Page L

R² = 0.7679

0

10

20

30

40

50

60

70

0 0.2 0.4 0.6 0.8 1 1.2 1.4

Wa

tts/

sq.m

kW/sq.m

Kaneka

Linear

(Kaneka)

MSc Energy Management 2012 Page M

R² = 0.5908

0

50

100

150

200

250

0 0.5 1 1.5

Sunpower

Sunpower

Linear (Sunpower)

R² = 0.7035

0

20

40

60

80

100

120

140

160

0 0.2 0.4 0.6 0.8 1 1.2 1.4

Sharp

Sharp

Linear (Sharp)