DEGRADATION OF DIFFERENT PHOTOVOLTAIC TECHNOLOGIES UNDER FIELD CONDITIONS

George Makrides1*, Bastian Zinsser

2,

George E. Georghiou 1, Markus Schubert

2 and Jürgen H. Werner

2

1. Department of Electrical and Computer Engineering, University of Cyprus 75 Kallipoleos Avenue, P.O. Box 20537, Nicosia, 1678, Cyprus

2. Institut für Physikalische Elektronik (ipe) Universität Stuttgart, Pfaffenwaldring 47, 70569 Stuttgart, Germany

*Corresponding Author

ABSTRACT

Over the past years a number of testing facilities have been monitoring the performance and degradation of PV systems according to the established standards of indoor and outdoor testing. The objective of this paper is to present the initial first year and longer-term rate of degradation of different PV technologies installed at the testing facility of the University of Cyprus, based on outdoor field measurements and methodologies. The first year degradation of the technologies was obtained using a data filtering technique of DC generated power at Maximum Power Point (MPP) at irradiation points of higher than 800 W/m

2 and normalising the measured power to

Standard Test Conditions (STC). Over the first year, mono-crystalline silicon technologies showed degradations in the range 2.12 % - 4.73 % while for multi-crystalline technologies the range was 1.47 % - 2.40 %. The amorphous silicon system demonstrated the highest first year decrease in power with an average degradation of 13.82 %. For validation purposes the first year degradation was also obtained using a second technique by evaluating outdoor measured data-sets under Air Mass (AM) 1.5 (morning and afternoon) conditions and during noon (high irradiance and temperature). In this case the evaluated results showed deviations of up to 6 % and 3 % for mono-crystalline and multi-crystalline technologies respectively whereas for thin-film this was 5 %. Finally, the longer-term degradation rates were evaluated by using the least-square fit method on average monthly data-set blocks of (i) Performance Ratio (PR), (ii) PR evaluated by filtering outage data-sets and restricting to high irradiance conditions and (iii) the Photovoltaic for Utility Systems Applications (PVUSA) rating methods, for the period June 2007 – June 2009.

INTRODUCTION

PV modules are usually guaranteed for 20 – 25 years by manufacturers which estimate this period through

accelerated indoor life-cycle tests during their design procedure. Degradation is the main reason for module loss of performance over time and as field experience has

indicated, losses have been associated with mechanisms external to the cells such as solder bonds, encapsulant browning, delamination and interconnect issues. Initial

light induced degradation (LID) is also one of the main

causes of degradation that can be attributed to the semiconductor device. Over the past years a number of degradation studies have

been performed and module losses of 1 - 2 % per year have been found in systems tested over a ten-year period from the mid-eighties [1]. Other investigations performed

by Sandia on multi-crystalline silicon PV modules for eight years have shown performance losses of about 0.5 % per year [2]. In more recent studies at the National Renewable Energy Laboratory (NREL) degradations of about 0.7 %

per year for both mono and multi-crystalline silicon modules have been measured [3]. Other studies have also been performed on thin film Copper Indium Diselenide (CIS) modules which were measured initially prior to

degradation for STC efficiency and temperature coefficients and were then compared after outdoor exposure. Both efficiency and temperature coefficients

have been found to decrease [4]. Other groups have also measured degradation through I-V measurements and have investigated amorphous silicon technologies [5]. The results show that the power degradation of the amorphous

silicon modules tested was 18 % to 33 % after one year of sunlight exposure [6]. For thin-film technologies stability remains a major issue and most of the degradation

mechanisms have been discussed in terms of either physical processes (electromigration, diffusion, defect generation) and general degradation patterns which are different from crystalline technologies. In particular, the

main degradation effect for amorphous silicon thin-film is the Staebler Wronski Effect (SWE) which refers to light-induced changes in the properties of the material [7].

In this work a comparison of the outdoor degradation rates of different grid-connected technologies (mono-crystalline, multi-crystalline, amorphous silicon and other thin-film

technologies) is presented. More specifically, the initial first year degradation of each technology was estimated using two methods, a data filtering technique to extract the DC MPP power at irradiation points over 800 W/m

2 and

normalising to STC conditions and secondly by comparing the outdoor extracted data of DC MPP power and normalising the results against STC irradiance,

temperature and module rated power. The rated power

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and temperature coefficients were obtained by employing (i) manufacturer datasheet parameters (MPP power and

temperature coefficients γMPP), (ii) solar simulator measured power of each technology and manufacturer power temperature coefficients of γMPP and (iii) solar simulator measured power of each technology and

outdoor evaluated γMPP obtained at the University of Cyprus [8]. Finally, the longer-term degradation for each respective technology over the 3 year period from

installation has been analysed by first evaluating the PR and PVUSA rating of each technology as a monthly average block. The PR is defined as the relationship between the actual energy yield produced and the

theoretical potential energy yield of a PV system. On the other hand the PVUSA rating method uses a regression model, the PV system performance and meteorological data to calculate the power at PVUSA Test Conditions

(PTC), which are defined as 1000 W/m2

plane-of-array irradiance, 20

°C ambient temperature, and 1 m/s wind

speed. PTC differs from STC in that its test conditions of

ambient temperature and wind speed will result in a cell temperature of about 50 °C, instead of 25 °C for STC [9]. Observing the slope of each PV technology linear least-square fit plot of the average monthly blocks against time,

provides a measure of the longer-term rate of degradation per year, an approach used in the past in a similar study at NREL [10].

OUTDOOR TEST FIELD INFRASTRUCTURE

PV Systems Description

The PV test site in Nicosia monitors different PV

technologies. The site consists of grid-connected PV

systems of nominal power 1 kWp, providing the opportunity

for direct comparisons under the same climatic conditions.

The installed PV technologies range from mono-crystalline

silicon and multi-crystalline silicon to thin film technologies.

All the systems are installed on mounting racks that are

oriented at the maximum annual energy yield of 27.5° for

the latitude of Nicosia. Below is a detailed description of

the installed systems (see Table 1).

Table 1. Installed photovoltaic technologies in Nicosia, Cyprus.

Manufacturer Technology

Atersa mono-crystalline silicon BP Solar mono-crystalline silicon (saturn-cell) Sanyo mono-crystalline silicon (HIT-cell) Suntechnics mono-crystalline silicon (back-contact) Schott Solar multi-crystalline silicon (MAIN-cell) Solon multi-crystalline silicon Schott Solar multi-crystalline EFG silicon Schott Solar Amorphous silicon First Solar Cadmium Telluride Würth Copper-(Indium-Gallium)-Diselenide

METHODOLOGY

The first-year degradation of the installed technologies

was evaluated using two methods that are based on data

analysis of outdoor collected measurements. The first

technique is based on the extraction of the DC power at

MPP (PMPP), module temperature and irradiance data-sets

at certain time periods for one week in June 2006 (1 – 7

June 2006) and one week in June 2007 (1 - 7 June 2007)

where the AM was equal to 1.5, found using an AM

simulation software and at noon (12:00) at high solar

irradiance and temperature and lower solar incident angle.

The data-sets were first extracted from the database and

all the measured points were then linearly corrected to

STC conditions of irradiance and temperature. The

irradiance was obtained from the Plane of Array (POA)

pyranometer while temperature measurements were

collected by the back-plate installed temperature sensors.

Eventhough, for both techniques angle of incidence losses

are accounted for by extracting data at the same time of

the same day, a limitation of the methodology is still the

effect of the spectrum as no account is made of the

clearness of the sky. Accordingly the data-sets for one day,

5th of June 2006 and 5

th of June 2007 (selected days of

good weather conditions) were first normalised using

manufacturer datasheet parameters (MPP power and

temperature coefficients γMPP). Subsequently, the same

data-sets were normalised to the measured power using a

solar simulator and the manufacturer power temperature

coefficients of γMPP and finally again normalised to the

power measured using a solar simulator and the outdoor

evaluated power temperature coefficients of γMPP. Apart

from the one day comparison of the 5th of June 2006 and

2007, an investigation was also performed on averaged

data-sets extracted from the period 1 - 7 June 2006 - 2007,

morning (AM 1.5), noon (12:00), afternoon (AM 1.5) and

normalised to solar simulator DC power and manufacturer

temperature coefficient γMPP.

The second method of evaluating the first-year

degradation was based on filtering irradiation data-sets

over 800 W/m2 during the period June 2006 – June 2007.

The extracted MPP power data were then normalised to

STC conditions of irradiance and temperature by applying

the manufacturer temperature coefficient (γMPP) and DC

power rating in order to obtain monthly average MPP

power blocks over the first-year period. The comparison of

June 2006 and June 2007 MPP power average value

provides an estimation of degradation. This technique is

an improvement over the afore mentioned first technique

as all the data-sets were selected at high irradiance levels

minimising in this way the temperature correction errors,

the angle of incidence and spectral effects.

Subsequently, longer-term degradation was found by first

evaluating the monthly 15 minute average PR and PVUSA

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power rating values over the period of June 2007 – June

2009 for each technology. Data-sets of MPP power and

irradiance when the systems were not operational had

been excluded as in this investigation the intention was

not to evaluate changes in the overall system performance

but the longer-term degradation. Data at irradiance levels

over 800 W/m2 were selected in order to minimise the

temperature loss effect (due to the tolerance of

temperature coefficients) on the PR, limiting the results to

clear sky days of high direct beam component and also

avoiding the poor performance of the PVUSA rating

system at low irradiance [10]. Outdoor measured data

were used to find the best-fit correlation for the PVUSA

rating system, according to the equation below:

P = IPOA(a + bIPOA + cTamb + dW) (1)

Where P is the DC power in W, IPOA is the POA irradiance

in W/m2, Tamb is the ambient temperature in °C, W is the

wind speed in m/s and a, b, c and d are the derived

regression coefficients. Each monthly block was obtained

by using the regression coefficients and normalising to

PTC. In order to obtain the rate of long-term degradation a

linear least-square fit plot was applied to the monthly

average blocks of the PR and PVUSA and the gradient of

the plot gave the degradation rate per year.

MEASUREMENT RESULTS

Degradation Accuracy and Weather Influence

The monthly and yearly variations of the performance

parameters are mainly attributed to solar radiation and

ambient temperature. The solar irradiation and average

ambient temperature over the period June 2006 – June

2009 are summarised in Table 3 [11].

Table 3. Solar irradiation and average ambient temperature over the period June 2006 – June 2009.

Period Solar

Irradiation (kWh/m

2)

Ambient Temperature

(°C)

June 2006 – June 2007 1997 18.7 June 2007 – June 2008 2050 19.6 June 2008 – June 2009 2037 19.5

It must be noted that the first year degradation found after

comparing the normalised power values of respective

years includes the manufacturer tolerance errors of power

and temperature coefficients and the effect of dust. A

drawback of the outdoor investigations of degradation is

that even though the modules were cleaned at regular

intervals, dust accumulation cannot be quantified for each

respective period of data collection. Another important

issue affecting the accuracy of the results is that although

data were extracted at simulated periods of AM 1.5 and

compared at exactly the same time and month for every

year, only the response to sunlight content changes due to

the angle of incidence (AOI) can be considered the same

for each technology but not the spectral content during

that time which could differ due to clouds and other

atmospheric spectral influences. This is a limitation of

using AM based simulated results and not real outdoor

spectral data. The spectral loss accuracy can be limited by

using noon extracted data-sets at the same time-periods

which for summer periods are usually of high irradiance

and therefore indicate clear sky conditions.

Degradation investigations based on the PR have the

advantage that this parameter is not influenced by solar

irradiation but varies with respect to seasonal temperature

deviations. On the other hand, the PVUSA rating method

is less influenced by solar radiation, ambient temperature

and wind speed values because of the regression

performed on these climatic parameters. Variations in the

PVUSA method can be attributed to the range of data over

which regression is performed, nonlinearities in PV

module performance and variations in the solar spectrum

[10]. In order to investigate the validity of using PR and the

PVUSA method for degradation analysis, the variation of

the average monthly PR for a typical mono-crystalline,

multi-crystalline and amorphous silicon system (Atersa

mono c-Si, Schott-Solar EFG multi c-Si and Schott-Solar

a-Si) were investigated for the period June 2006 – June

2009. The variation of the average annual PR values,

found from the monthly averages, for a confidence interval

of 95 % was 0.71 %, 0.96 % and 1.46 % for the mono,

multi and amorphous silicon technologies respectively.

This means that for the Atersa mono c-Si system, 95 % of

the yearly values are within 0.71 % of the average annual

value (see Fig. 1). The variability is mainly due to the

temperature effect. The monthly deviations for a

confidence interval of 95 % of the PR over the first year

were 2.36 %, 2.14 % and 2.03 % for the mono-crystalline,

multi-crystalline and amorphous silicon systems

investigated respectively.

June Ju

ly

Augus

t

Septe

mbe

r

Oct

ober

Nov

embe

r

Dec

embe

r

Janu

ary

Febr

uary

Mar

chApr

ilM

ayYea

r

Pe

rfo

rma

nce

Ra

tio [

%]

0

10

20

30

40

50

60

70

80

90

100

2006-2007

2007-2008

2008-2009

Average

95% Confidence interval for Annual values = Average ±0.71%

Fig. 1. Monthly PR that shows the influence of weather

conditions for the Atersa mono-crystalline system over the

period June 2006 – 2009.

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Accordingly for the PVUSA rating method at PTC the

annual deviation for a confidence interval of 95 % was

2.18 % for the Atersa mono c-Si system (see Fig. 2) while

the Schott-Solar EFG mutli and amorphous silicon

technologies showed annual deviations of 2.15 % and

2.70 % respectively. Accordingly, the monthly deviations

for a confidence interval of 95 % over the first year were

2.86 %, 2.89 % and 4.66 % for the mono-crystalline, multi-

crystalline and amorphous silicon systems investigated

respectively.

Consequently, due to the low variability between annual

average yearly results, both the PVUSA and PR methods

can detect longer-term degradation but can not be reliable

for first year degradation analysis due to the large

variation between monthly results. This is mainly due to

the range of values over which the regression is

performed and solar spectrum variations.

June

July

Augus

t

Septem

ber

Oct

ober

Nove

mber

Dec

embe

r

Janua

ry

Februa

ry

Mar

chApril

May

Year

PV

US

A R

atin

g [W

]

0

100

200

300

400

500

600

700

800

900

1000

2006-2007

2007-2008

2008-2009

Average

95% Confidence interval for Annual values = Average ±2.18%

Fig. 2. Monthly PVUSA power rating at PTC that shows

the influence of weather conditions for the Atersa mono-

crystalline system over the period June 2006 – 2009.

Initial Degradation

Significant variations have been observed when

comparing the first year initial degradation results obtained

at AM 1.5 (morning and afternoon) and during noon (high

irradiance) using the same normalisation technique of

manufacturer temperature coefficient (γMPP) and solar

simulator DC power (see Fig. 3). All technologies showed

lower losses when comparing the power as the day

progressed which can be attributed to the spectral

changes during the day.

Ate

rsa

Track

er m

ono-

c-Si

Aters

a m

ono-

c-Si

BP m

ono-

c-Si

Sany

o HIT

-Si

Sun

tech

nics

mon

o-c-

Si

Schot

t MAIN

-Si

Sch

ott E

FG-S

i

Sch

ott a

-Si(2

)

First S

olar

CdT

e

Wur

th C

IGS

No

rma

lise

d P

erc

en

tag

e P

ow

er

[%]

0

20

40

60

80

100

120Morning (AM 1.5)

Noon (12:00)

Afternoon (AM 1.5)

Fig. 3. Percentage DC MPP power of the installed

systems in Nicosia. Comparison for 1 - 7 June 2006 -2007,

morning (AM 1.5), noon (12:00), afternoon (AM 1.5)

normalised to manufacturer temperature coefficient (γMPP)

and solar simulator DC power.

Mono-crystalline and multi-crystalline technologies

showed deviations up to 6 % and 3 % respectively

whereas thin-film up to 5 %. When all the normalisation

techniques were considered for noon extracted data-sets,

it was clear that the Wurth CIGS system showed no

degradation over the first year. Multi-crystalline

technologies showed lower average degradation, 1 %, in

comparison to the average high efficiency mono-

crystalline and thin-film degradation of 4 %. The

comparisons for the first technique and for all

normalisation methods during the first year of operation

are shown in Fig. 4.

Aters

a Tra

cker

mon

o-c-

Si

Ate

rsa

mon

o-c-

Si

BP m

ono-

c-Si

San

yo H

IT-S

i

Sun

tech

nics

mon

o-c-Si

Sch

ott M

AIN

-Si

Schot

t EFG

-Si

Schot

t a-S

i(2)

First S

olar

CdT

e

Wur

th C

IGS

Norm

alis

ed P

erc

enta

ge P

ow

er

[%]

0

20

40

60

80

100

120

(i) Manufacturer power and γMPP

(ii) ipe solar simulator power and manufacturer γMPP

(iii) ipe solar simulator power and outdoor γMPP

(iv) AM 1.5 and noon average, ipe solar simulator power

and manufacturer γMPP

Fig. 4. Power MPP DC of the installed systems in Nicosia

for 5 June 2006 - 5 June 2007 with all normalisation

techniques.

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Accordingly when using the second technique of filtering

irradiation data-sets over 800 W/m2 and normalising MPP

power measured data to STC conditions, applying

manufacturer temperature coefficient (γMPP) and DC power

rating, the highest first-year decrease in DC power PMPP

was observed by Schott Solar amorphous silicon system

with an average degradation over the first year of 13.82 %.

This was obtained by comparing the average normalised

MPP power block of June 2006 to June 2007. The initial

light induced degradation Staebler-Wronski Effect clearly

was established during the first few months of operation.

Mono-crystalline silicon technologies showed first year

degradations in the range 2.12 % - 4.73 %. The Sanyo

HIT showed the highest degradation amongst the mono-

crystalline silicon technologies. Lower degradation was

measured for multi-crystalline technologies in the range of

1.47 % - 2.40 % (see Fig. 5). The first year degradation of

the installed systems obtained by the second technique

and the comparison of the average monthly values of MPP

DC power is summarised in Table 3.

Jun-06 Jul-06 Aug-06 Sep-06 Oct-06 Nov-06 Dec-06 Jan-07 Feb-07 Mar-07 Apr-07 May-07 Jun-07

No

rma

lise

d P

ow

er

[W/W

p]

0

200

400

600

800

1000

Tracker mono-c-Si

Atersa mono-c-Si

BP mono-c-Si

Sanyo HIT-Si

Suntechnics mono-c-Si

Schott MAIN-Si

Schott EFG-Si

Schott a-Si(2)

First Solar CdTe

Wurth CIGS

Solon multi c-Si

Fig. 5. Average monthly percentage DC MPP power

during the first year of the installed systems in Nicosia

normalised to manufacturer temperature coefficient (γMPP)

and DC power.*One of the Schott Solar Asiopak modules

has been broken since the 4th of October 2006.

Table 3. First year degradation for Installed photovoltaic technologies in Nicosia, Cyprus, from average monthly values of MPP power (Irradiance >800 W/m

2).

System First Year Degradation (%)

Sanyo mono c-Si HIT -4.73 Atersa mono c-Si -2.12 Suntechnics mono c-Si -2.19 BP mono c-Si -4.22 Solon multi c-Si -2.40 Schott multi c-Si EFG -1.47 Schott multi c-Si MAIN -1.57 Wurth CIGS -7.30 First Solar CdTe -6.16 Schott a-Si (2) -13.82

Longer-term Degradation

The evaluation of longer-term degradation over the period

June 2007 – June 2009, using the PR method evaluated

by filtering high irradiance data-points and excluding

outage periods, showed a degradation rate of 0.10 % and

0.09 % for the Sanyo HIP and BP Solar respectively. The

Suntechnics mono c-Si system showed an increase in

performance which is attributed to the replacement of the

drain resistance, which increased energy yield. The Schott

Solar EFG and MAIN multi-crystalline technologies

showed low degradation rates in the range 0.04 - 0.06 %

respectively, while thin-film technologies showed

degradation rates of 0.23 % to 0.32 %.

Similarly the investigation using PVUSA PTC rating values

revealed degradation rates of 1.40 %, 0.68 % and 1.10 %

for the Sanyo HIP, Atersa and BP Solar respectively while

the Suntechnics system showed an increase in

performance of 1.30 %. All multi-crystalline technologies

showed performance decreases in the range 0.90 % -

1.10 %. Higher degradation rates were observed by thin-

film technologies with the highest of 3.30 % for the First

Solar CdTe and lowest, 2.10 %, for the Schott Solar a-

Si(2) (see Table 4).

Table 4. Degradation rates for 2007-2009 for installed photovoltaic technologies in Nicosia, Cyprus, from monthly values of PR, PR (Irradiance >800 W/m

2 and outage

filtering) and PVUSA ratings. Degradation Rate (%/year)

System PR PR

(outage filtering ) PVUSA

Sanyo mono c-Si HIT -0.07 -0.10 -1.40 Atersa mono c-Si 0.09 0.06 -0.68 Suntechnics mono c-Si 0.17 0.21 1.30 BP mono c-Si -0.25 -0.09 -1.10 Solon multi c-Si -0.11 0.01 0.11 Schott multi c-Si EFG 0.001 -0.04 -0.90 Schott multi c-Si MAIN -0.01 -0.06 -1.10 Wurth CIGS -0.17 -0.26 -2.00 First Solar CdTe -0.27 -0.32 -3.34 Schott a-Si (2) -0.23 -0.23 -2.10

Figure 6 depicts the longer-term degradation rate of the Schott-Solar a-Si(2) system on the PR and by the PVUSA power rating.

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Jun-06 Dec-06 Jun-07 Dec-07 Jun-08 Dec-08 Jun-09

PR

(%

)

0

20

40

60

80

100

PV

US

A P

ow

er

Ra

ting (

W)

0

200

400

600

800

1000

PVUSA

PR

-2.10 % (per year)

-0.23 % (per year)

Fig. 6. Longer-term degradation using monthly PR, PR with outage filtering and G > 800 W/m

2 and PVUSA power

rating for Schott Solar Amorphous Silicon (2) system over the period June 2006 – June 2009.

CONCLUSION

The deviations in degradation obtained, clearly show that

careful selection of the analysis techniques must be

undertaken when performing degradation studies under

field conditions in order to obtain credible results. The

outdoor evaluation results show that thin-film amorphous

silicon demonstrates the highest degradation during the

first year due to the Staebler-Wronski effect. The mono-

crystalline technologies under test showed in most cases

higher first year degradation than multi-crystalline ones.

Through the PR and PVUSA rating analysis the highest degradation rates per year were observed for thin-film technologies whereas some mono-crystalline technologies showed no degradation over the period 2007-2009. Finally, from the outcome of the results it is clear that STC normalisation techniques are more appropriate for first year degradation evaluations than PR and PVUSA regression evaluations which were suitable for longer-term degradation. This is because both the PR and PVUSA power rating showed high monthly variations for each respective year and low annual variations.

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