Determining one or more characteristics of a PV array

Abstract

This disclosure relates generally to determining one or more characteristics of a photovoltaic (PV) array using luminescence imaging. The PV array comprises a plurality of PV strings electrically connected in parallel, each PV string comprising a plurality of PV modules electrically connected in series. In one aspect, a processor determines at least one photoluminescence (PL) intensity value of one or more PV modules in at least one of the PV strings based on a PL image of the PV array when illuminated by solar radiation. The processor determines at least one current value in the at least one PV string when the PV array is in an open circuit condition or operating at an operating voltage above a maximum power point voltage of the PV array. The processor determines the one or more characteristics based on the at least one current value and / or the at least one PL intensity value.

Description

[0001] Determining one or more characteristics of a PV array

[0002] Cross-Reference to Related Applications

[0003] [1] The present application claims priority from Australian Provisional Patent Application No 2024901724 filed on 7 June 2024, the contents of which are incorporated herein by reference in their entirety.

[0004] Technical Field

[0005] [2] This disclosure relates generally to determining one or more characteristics of a photovoltaic (PV) array using luminescence imaging. More particularly but not necessarily exclusively, this disclosure relates to determining one or more characteristics of a PV array using photoluminescence (PL) or electroluminescence (EL) imaging.

[0006] Background

[0007] [3] Luminescence imaging is useful for characterisation of photovoltaic (PV) arrays, including determining the condition of a PV array, detecting defects, identifying degradation mechanisms, and quantifying module performance. Luminescence imaging uses the light emitted by the PV array, where analysis of the light captured in an image may be used for characterisation of the PV array. For example, photoluminescence (PL) imaging is a form of luminescence imaging used for the characterisation of photovoltaic devices including PV arrays, PV modules and PV cells. The technique involves detection of photons released by the relaxation of conduction band electrons to the valence band (referred to as radiative recombination), under the influence of external illumination. Solar irradiation may be used for the external illumination when PL imaging is performed outdoors, such as to characterise PV devices deployed outdoors. PL imaging performed outdoors may be referred to as daytime PL (DPL) imaging.

[0008] [4] Luminescence from a PV array may also be generated by electrically connecting the PV array to a power supply and applying a forward bias to the PV array. In other words, luminescence may be generated by injecting current into the PV array. In this case, the luminescence may be referred to as electroluminescence (EL). Electroluminescence may be generated and measured at nighttime or during the daytime, which may be two distinct ways of performing EL measurements on a PV array. Luminescence generated from a forward biased PV array during the day may also be a mixture of PL and EL.

[0009] [5] With its unique ability to provide spatial information about cell and module level defects, luminescence imaging is useful for quality testing of installed modules in operational solar systems such as PV arrays including in so-called “solar farms”. A PV array typically includes a plurality of PV strings electrically connected in parallel to each other, each PV string comprising a plurality of PV modules electrically connected in series to each other. Each PV module comprises a plurality of PV cells. A plurality of parallel connected PV strings is typically connected to an inverter.

[0010] [6] Any discussion of documents, acts, materials, devices, articles or the like which has been included in the present specification is not to be taken as an admission that any or all of these matters form part of the prior art base or were common general knowledge in the field relevant to the present disclosure as it existed before the priority date of each of the appended claims.

[0011] [7] Throughout this specification the word “comprise”, or variations such as “comprises” or “comprising”, will be understood to imply the inclusion of a stated element, integer or step, or group of elements, integers or steps, but not the exclusion of any other element, integer or step, or group of elements, integers or steps.

[0012] Summary

[0013] [8] Disclosed herein is a method and system for determining one or more characteristics of a photovoltaic (PV) array using luminescence imaging.

[0014] [9] In one aspect of the present disclosure the method and system uses photoluminescence (PL) imaging. PL images of PV arrays have been found by the present inverters to contain unique and quantitative information indicative of voltage mismatch between series connected strings of modules, resulting from performance variations between groups of PV modules. These performance variations and associated voltage mismatches can cause significant balancing currents to travel between PV strings of the PV array when no or only low power is extracted from the PV array. The disclosed system and method provide, for example, techniques to identify or account for voltage mismatches between PV strings including based on current values in one or more PV strings, and optionally to adjust or correct the PL image to provide more accurate information regarding the PV array.

[0015]

[0010] In another aspect of the present disclosure, the method and system for determining one or more characteristics of a photovoltaic (PV) array uses electroluminescence (EL) imaging.

[0016]

[0011] In accordance with the preceding aspects, in a broad aspect of the present disclosure, there is provided a method for determining one or more characteristics of a photovoltaic (PV) array, the PV array comprising a plurality of PV strings electrically connected in parallel to each other, each PV string comprising a plurality of PV modules electrically connected in series to each other, the method comprising: (i) determining at least one luminescence intensity value of one or more PV modules in at least one of the PV strings based on at least one luminescence image of the PV array capturing the PV array undergoing luminescence; (ii) determining at least one current value in the at least one PV string, the at least one current value being associated with the PV array undergoing luminescence; and (iii) determining the one or more characteristics of the PV array based on the at least one determined current value and / or the at least one luminescence intensity value.

[0017]

[0012] According to an aspect of the present disclosure, there is provided a method for determining one or more characteristics of a photovoltaic (PV) array, the PV array comprising a plurality of PV strings electrically connected in parallel to each other, each PV string comprising a plurality of PV modules electrically connected in series to each other, the method comprising:

[0018] (i) determining at least one PL intensity value of one or more PV modules in at least one of the PV strings based on at least one PL image of the PV array when illuminated by solar radiation;

[0019] (ii) determining at least one current value in the at least one PV string when the PV array is in an open circuit condition or operating at an operating voltage above a maximum power point voltage of the PV array; and (iii) determining the one or more characteristics of the PV array based on the at least one determined current value and / or the at least one determined PL intensity value.

[0020]

[0013] In some embodiments, the operating voltage above the maximum power point voltage results in a power extracted from the PV array that is < 20% of a power extracted from the PV array when the PV array is operating at the maximum power point voltage.

[0021]

[0014] In some embodiments, the operating voltage above the maximum power point voltage results in a power extracted from the PV array that is < 40% of a power extracted from the PV array when the PV array is operating at the maximum power point voltage.

[0022]

[0015] In some embodiments, the method further comprises adjusting the at least one determined PL intensity value of the one or more PV modules in the at least one PV string based on the at least one determined current value.

[0023]

[0016] In some embodiments, adjusting of the at least one determined PL intensity value comprises adjusting one or more features of the at least one PL image that are indicative of the at least one determined PL intensity.

[0024]

[0017] In some embodiments, the one or more features of the at least one PL image are one or more of brightness, digital count rate, colour and contrast.

[0025]

[0018] In some embodiments, adjusting the at least one determined PL intensity value of the one or more PV modules in the at least one PV string based on the at least one determined current value reduces or removes an effect on the at least one determined PL intensity value of balancing currents between PV strings of the PV array when the PV array is in an open circuit condition or operating at an operating voltage above a maximum power point voltage of the PV array.

[0026]

[0019] In some embodiments, the at least one determined PL intensity value of the one or more PV modules in the at least one PV string is adjusted based on a difference or ratio of: (i) the at least one current value in the at least one PV string determined when the PV array is in an open circuit condition or operating at an operating voltage above a maximum power point voltage of the PV array, and (ii) a short circuit current value of the at least one PV string.

[0027]

[0020] In some embodiments, the at least one determined PL intensity value (<pPL) of the one or more PV modules in the at least one PV string is adjusted to at least one corrected PL intensity value (<PpL,corr) based on the following equation (2), where Inis the current in the at least one PV string (n) determined when the PV array is in an open circuit condition or operating at an operating voltage above a maximum power point voltage of the PV array, Iscis a short circuit current of the at least one PV string and C2is a constant: equation (2).

[0028]

[0021] In some embodiments, the at least one determined current value in the at least one PV string is determined at least partially based on the at least one determined PL intensity value of the one or more PV modules.

[0029]

[0022] In some embodiments, the at least one determined current value of the at least one PV string is determined at least partially based on determined PL intensity values of all PV modules connected to an inverter of the PV array.

[0030]

[0023] In some embodiments, the at least one determined current value of the at least one PV string is determined at least partially based on a sum of cell diode voltages in the at least one string calculated from the at least one determined PL intensity value of the one or more PV modules in the at least one PV string.

[0031]

[0024] In some embodiments, the at least one determined current value of the at least one PV string is determined at least partially based on a mean of cell diode voltages of all cells in all PV modules connected to the inverter of the PV array.

[0032]

[0025] In some embodiments, the cell diode voltages (Vd) are determined at least partially from the at least one PL intensity value (<pPL), and based, at least partially, on the following generalised Planck equation (1), where kT / q is a thermal voltage and C1is a calibration constant: equation (1).

[0033]

[0026] In some embodiments, the at least one determined current value of the at least one PV string is determined at least partially based on a series resistance of at least one PV cell in one or more PV modules in one of the plurality of PV strings.

[0034]

[0027] In some embodiments, the method comprises determining the series resistance based on a measurement of a voltage of the one or more PV modules in the one of the plurality of PV strings via one or more y-connectors.

[0028] In some embodiments, the method comprises determining the series resistance based on a measurement of a voltage of a PV module similar and / or associated with the one or more PV modules in the one of the plurality of PV strings.

[0035]

[0029] In some embodiments, the at least one determined current value of the at least one PV string is determined at least partially based on a measured voltage across all of the PV strings of the PV array connected to an inverter of the PV array.

[0036]

[0030] In some embodiments, the method further comprises adjusting the at least one determined current value in the at least one PV string at least partially based on a direct current measurement from the at least one PV string.

[0037]

[0031] In some embodiments, the at least one determined current value in the at least one PV string is determined at least partially based on a direct current measurement from the at least one PV string or a different one of the plurality of PV strings.

[0038]

[0032] In some embodiments, the direct current measurement is obtained using one or more of: a clamp meter; a Hall effect current transducer; a current transformer; and a current shunt resistor.

[0039]

[0033] In some embodiments, the at least one determined current value of the at least one PV string is determined at least partially based on a temperature of one or more PV modules in the at least one PV string.

[0040]

[0034] In some embodiments, the temperature of the one or more PV modules in the at least one PV string is determined by thermal imaging of the one or more PV modules in the at least one PV string.

[0041]

[0035] In some embodiments, the at least one determined current value of the at least one PV string is determined at least partially based on a temperature of the one or more PV modules when (i) the PV array is operating substantially at maximum power point (MPP), and (ii) the PV array is operating in an open circuit condition or operating at an operating voltage above a maximum power point voltage of the PV array.

[0042]

[0036] In some embodiments, the at least one determined current value of the at least one PV string is determined at least partially based on a comparison between a temperature increase of the one or more PV modules in the at least one PV string caused at least partially by solar absorption when the PV array is operating substantially at maximum power point (MPP), and a temperature increase of the one or more PV modules in the at least one PV string caused at least partially by solar absorption when the PV array is operating in an open circuit condition or operating at an operating voltage above a maximum power point voltage of the PV array.

[0037] In some embodiments, the method comprises determining the PL image from an image difference between at least two images of the PV array, each of the at least two images corresponding to the PV array operating at a different operating condition.

[0043]

[0038] In some embodiments, the at least one determined current value of the at least one PV string is indicative of a voltage mismatch between at least two PV strings in the PV array, the at least two PV strings comprising the at least one PV string having the at least one determined current value.

[0044]

[0039] In some embodiments, the method further comprises: determining at least one junction box fault in the one or more PV modules in the at least one PV string based on the at least one PL image of the PV array; and adjusting the at least one determined PL intensity value based on the at least one determined junction box fault.

[0045]

[0040] In some embodiments, determining the at least one junction box fault comprises: determining at least one PL value of a portion of the one or more PV modules in the at least one PL image of the PV array; and determining that the at least one PL value of the portion has a value of about zero.

[0046]

[0041] In some embodiments, adjusting the at least one determined PL intensity value comprises adjusting the at least one determined PL intensity value based on a function of a number of determined junction box faults in the at least one PV string.

[0047]

[0042] In some embodiments, the at least one junction box fault comprises one or more of: a bypass diode in short circuit; and an open circuit PV module sub-string.

[0048]

[0043] In some embodiments, the one or more characteristics of the PV array comprises one or more of: an open circuit voltage; an operational voltage; an implied voltage; module performance; module quality; and a corrected PL image.

[0049]

[0044] In the above aspect, the at least one current value in the at least one PV string is determined when the PV array is in an open circuit condition or operating at an operating voltage above a maximum power point voltage of the PV array. However, in other aspects, the at least one current value in the at least one PV string may be determined when the PV array is in a different operating condition.

[0050]

[0045] According to another aspect of the present disclosure, there is provided a method for determining one or more characteristics of a photovoltaic (PV) array, the PV array comprising a plurality of PV strings electrically connected in parallel to each other, each PV string comprising a plurality of PV modules electrically connected in series to each other, the method comprising: (i) determining at least one photoluminescence (PL) intensity value of one or more PV modules in at least one of the PV strings based on at least one PL image of the PV array when illuminated by solar radiation; (ii) determining at least one current value in the at least one PV string when the PV array is operating at an operating voltage between an open circuit condition and an operating voltage above a maximum power point voltage of the PV array; and (iii) determining the one or more characteristics of the PV array based on the at least one determined current value and / or the at least one determined PL intensity value.

[0051]

[0046] The method according to this aspect may include any one or more features described with respect to the method according to the first aspect. For example, the method according to this aspect may further comprise adjusting the at least one determined PL intensity value of the one or more PV modules in the at least one PV string based on the at least one determined current value.

[0052]

[0047] According to an aspect of the present disclosure, there is provided a method for determining one or more characteristics of a photovoltaic (PV) array, the PV array comprising a plurality of PV strings electrically connected in parallel to each other, each PV string comprising a plurality of PV modules electrically connected in series to each other, the method comprising: (i) determining at least one electroluminescence (EL) intensity value of one or more PV modules in at least one of the PV strings from a group of PV strings based on at least one EL image of the PV array captured during current injection into the group of PV strings, the group of PV strings comprising two or more of the plurality of PV strings; (ii) determining at least one current value in the at least one PV string of the group of PV strings, the at least one current value being associated with current injection into the group of PV strings; and (iii) determining the one or more characteristics of the PV array based on the at least one determined current value and / or the at least one determined EL intensity value.

[0053]

[0048] In some embodiments, the method further comprises adjusting the at least one determined EL intensity value of the one or more PV modules in the at least one PV string based on the at least one determined current value.

[0054]

[0049] In some embodiments, adjusting of the at least one determined EL intensity value comprises adjusting one or more features of the at least one EL image that are indicative of the at least one determined EL intensity.

[0055]

[0050] In some embodiments, the one or more features of the at least one EL image are one or more of brightness, digital count rate, colour and contrast.

[0056]

[0051] In some embodiments, adjusting the at least one determined EL intensity value of the one or more PV modules in the at least one PV string based on the at least one determined current value reduces or removes an effect of current variations between the group of PV strings resulting from current injection into the group of PV strings.

[0052] In some embodiments, the at least one determined EL intensity value of the one or more PV modules in the at least one PV string is adjusted based on a difference or ratio of: the at least one determined EL intensity value and the at least one determined current value.

[0057]

[0053] In some embodiments, the at least one determined current value of the at least one PV string is determined at least partially based on the at least one determined EL intensity value of the one or more PV modules.

[0058]

[0054] In some embodiments, the at least one determined current value of the at least one PV string is determined at least partially based on a sum of cell diode voltages in the at least one PV string calculated from the at least one determined EL intensity value of the one or more PV modules in the at least one PV string.

[0059]

[0055] In some embodiments, the cell diode voltages (Vd) are determined at least partially from the at least one determined EL intensity value (PEL , and based, at least partially, on the following generalised Planck equation (5), where kT / q is a thermal voltage and C12is a calibration constant:

[0060] VEL = C12Ce^ kT ) equation (12).

[0061]

[0056] In some embodiments, the at least one determined current value of the at least one PV string is determined at least partially based on a series resistance of at least one PV cell in one or more PV modules in one of the group of PV strings.

[0062]

[0057] In some embodiments, the method comprises determining the series resistance by determining at least one EL intensity value of the one or more PV modules in the one of the group of PV strings at each of two or more current injection conditions, wherein the series resistance is based on a difference between the two or more current injection conditions.

[0063]

[0058] In some embodiments, determining the at least one EL intensity value at each of the two or more current injection conditions further comprises determining at least one voltage of the one or more PV modules in the one of the group of PV strings at each of two or more current injection conditions.

[0064]

[0059] In some embodiments, the method comprises determining the series resistance based on a measurement of a voltage of the one or more PV modules in the one of the group of PV strings via one or more y -connectors.

[0065]

[0060] In some embodiments, the method comprises determining the series resistance based on a measurement of a voltage of a PV module similar and / or associated with the one or more PV modules in the one of the group of PV strings.

[0061] In some embodiments, the method further comprises adjusting the at least one determined current value in the at least one PV string at least partially based on a direct current measurement from the at least one PV string.

[0066]

[0062] In some embodiments, the at least one determined current value in the at least one PV string is determined at least partially based on a direct current measurement from the at least one PV string.

[0067]

[0063] In some embodiments, the direct current measurement is obtained using one or more of: a clamp meter; a Hall effect current transducer; a current transformer; and a current shunt resistor.

[0068]

[0064] In some embodiments, the at least one determined current value of the at least one PV string is determined at least partially based on a temperature of one or more PV modules in the at least one PV string.

[0069]

[0065] In some embodiments, the temperature of the one or more PV modules in the at least one PV string is determined by thermal imaging of the one or more PV modules in the at least one PV string.

[0070]

[0066] In some embodiments, the method further comprises: determining at least one junction box fault in the one or more PV modules in the at least one PV string based on the at least one EL image of the PV array; and adjusting the at least one determined EL intensity value based on the at least one determined junction box fault.

[0071]

[0067] In some embodiments, determining the at least one junction box fault comprises: determining at least one EL value of a portion of the one or more PV modules in the at least one EL image of the PV array; and determining that the at least one EL value of the portion has a value of about zero.

[0072]

[0068] In some embodiments, adjusting the at least one determined EL intensity value comprises adjusting the at least one determined EL intensity value based on a function of a number of determined junction box faults in the at least one PV string.

[0073]

[0069] In some embodiments, determining the at least one junction box fault comprises determining a fault type of the at least one junction box fault by performing one or more of the following: determining at least one EL intensity value of the one or more PV modules in the at least one PV string comprising the at least one junction box fault being greater or lower than at least one EL intensity value of one or more PV modules in a different one of the group of PV strings; and determining a change of at least one EL intensity value of the at least one PV string comprising the at least one junction box fault.

[0074]

[0070] In some embodiments, determining the at least one junction box fault comprises: receiving at least one low current EL image of the PV array captured during low current injection into the group of PV strings; from the at least one low current EL image, identifying one of the group of PV strings comprising the at least one junction box fault by determining at least one EL intensity value of one or more PV modules in the one of the group of PV strings being lower than at least one EL intensity value of one or more PV modules in a different one of the group of PV strings; and determining the at least one junction box fault in the one of the group of PV strings based on the low current EL image.

[0075]

[0071] In some embodiments, the at least one junction box fault comprises one or more of: a bypass diode in short circuit; and an open circuit PV module sub-string.

[0076]

[0072] In some embodiments, the method further comprises adjusting the at least one determined EL intensity value of the one or more PV modules in the at least one PV string based on a number of PV modules in each of the group of PV strings.

[0077]

[0073] In some embodiments, the method further comprises adjusting the at least one determined EL intensity value of the one or more PV modules in the at least one PV string based on a number of disconnected PV strings of the group of PV strings.

[0078]

[0074] In some embodiments, the method further comprises adjusting a total current value based on a number of disconnected PV strings of the group of PV strings, and the total current value corresponding to a total current flowing into the group of PV strings during current injection.

[0079]

[0075] In some embodiments, the current injection into the group of PV strings is performed, at least partially, by: disconnecting one or more combiner boxes connected to the group of PV strings; and / or disconnecting one or more fuses connected to the group of PV strings.

[0080]

[0076] In some embodiments, the method further comprises configuring a device connected to the at least one PV string based on the at least one determined current value to reduce or remove an effect of current variations between the group of PV strings resulting from current injection.

[0081]

[0077] In some embodiments, the one or more characteristics of the PV array comprises one or more of: an open circuit voltage; an operational voltage; an implied voltage; module performance; module quality; and a corrected EL image.

[0082]

[0078] According to an aspect of the present disclosure, there is provided a non-transitory computer readable medium having a computer readable program code configured to implement the method according to the preceding aspects and optionally any one of the embodiments thereof.

[0083]

[0079] According to an aspect of the present disclosure, there is provided a system for determining one or more characteristics of a photovoltaic (PV) array, the system comprising at least one processor configured to perform the method according to the preceding aspects and optionally any one of the embodiments thereof. Brief Description of Drawings

[0084]

[0080] Example embodiments according to the present disclosure will now be described with reference to the following drawings:

[0085]

[0081] Fig. 1 shows a daylight photoluminescence (DPL) image of an inverter section of a solar farm containing approximately 1,600 photovoltaic (PV) modules, exhibiting significant voltage mismatch between modules and between strings of modules. No luminescence intensity is observed in the upper part of the image, since modules in this section of the solar farm are connected to a different inverter.

[0086]

[0082] Fig. 2 shows a close-up of a section of the DPE image shown in Fig. 1.

[0087]

[0083] Fig. 3 illustrates a system for determining one or more characteristics of a PV array.

[0088]

[0084] Fig. 4 illustrates a method for determining one or more characteristics of a PV array.

[0089]

[0085] Fig. 5 illustrates an example of a PV module comprising three module sub-strings, three junction boxes and three bypass diodes.

[0090]

[0086] Fig. 6 shows a DPE image, showing four examples of PV modules with a junction box fault.

[0091]

[0087] Fig. 7 shows simulated currents in a PV array containing 200 parallel strings of 27 series connected modules, including normal (solid lines) and underperforming (dashed lines) strings, as a function of the power being extracted from the system.

[0092]

[0088] Fig. 8 shows simulations for a symmetrical case, with 100 normal and 100 underperforming PV strings, for Rs= 0 and for the more realistic case Rs= 0.0025 Q.

[0093]

[0089] Fig. 9 shows the current voltage characteristics of normal (solid lines) and underperforming (dashed lines) PV strings for Rs= 0 and for Rs= 0.0025 Q.

[0094]

[0090] Fig. 10a shows a DPL image of a solar farm section containing normal, underperforming, and mixed PV strings, as measured.

[0095]

[0091] Fig. 10b shows a DPL image of a solar farm section containing normal, underperforming, and mixed strings, after correction for balancing currents.

[0096]

[0092] Fig. 11 shows measured and simulated current in a normal PV string and in an underperforming string as a function of the power extracted from the system for a system containing 139 normal and 73 underperforming PV strings.

[0097]

[0093] Fig. 12 shows a thermal image of the solar farm section shown in Fig. 1 under open circuit conditions.

[0098]

[0094] Fig. 13 illustrates dark current voltage characteristics for a normal PV string and an underperforming PV string.

[0095] Fig. 14 illustrates an example of an electrical layout of a section of a utility-scale PV array.

[0099]

[0096] Fig. 15 shows an aerial photo of a PV array section, showing the location of several combiner boxes.

[0100]

[0097] Fig. 16 illustrates a schematic simplified representation of an inverter section comprising three combiner boxes.

[0101]

[0098] Fig. 17 illustrates another method for determining one or more characteristics of a PV array.

[0102] Description of Embodiments

[0103]

[0099] In accordance with embodiments of the present disclosure, PL image data has been used to indicate the presence of significant voltage mismatch between series connected PV strings in PV arrays. The voltage mismatch results in balancing currents between PV strings under illumination and under low or zero load conditions. Balancing currents between PV strings may result in excessive heating of PV modules and therefore accelerated PV module degradation and may also make a PV array more susceptible to other problems such as blowing of string fuses. As recognised in the present disclosure, identifying voltage mismatch and / or balancing currents associated with voltage mismatch may provide valuable information regarding the performance of a PV array. Moreover, the present disclosure recognises that characterisation of PV arrays based on PL imaging techniques may be adjusted to account for voltage mismatch and / or balancing currents. Techniques according to the present disclosure may be utilised to provide quality testing of PV modules and enable improved operation and maintenance of solar assets. “Voltage mismatch” in the context of the present disclosure means that the PV strings have a different open circuit voltage.

[0104]

[0100] PL imaging of a PV array when illuminated by solar radiation, a technique also referred to as daylight PL (DPL) imaging, enabled by simultaneous switching of the electrical operating point of PV modules via an inverter of the PV array, has been found to provide unique insights into PV module quality across solar farms. Systematic quality variations have been observed in an Australian solar farm, including the presence of entire PV strings containing only or predominantly PV modules of two different quality groups, resulting in significant balancing currents between parallel connected PV strings when at operating points at or near open circuit (OC) conditions.

[0105]

[0101] It has been found, according to the present disclosure, that balancing currents affect PL intensities and create unusual PL intensity patterns, complicating the quantitative analysis of PL images in terms of cell and module voltage variations across a PV array. As such, identifying the presence and / or magnitude of these balancing currents may be used to correct PL images by compensating for the PL intensity variations caused by balancing currents, which may allow for more accurate characterisation of a PV array, or components thereof, using PL imaging. In this disclosure, an analytical model to correct PL images for the effects of voltage mismatch and balancing currents is provided, which has also been validated experimentally.

[0106]

[0102] Fig. 1 shows a DPL image of a solar farm containing approximately 1,600 PV modules, acquired by switching one central inverter to create different operating conditions associated with a PV array of the solar farm and performing a difference calculation on images acquired under the different conditions to construct the DPL image. Further information regarding the DPL image acquisition technique used to construct Fig. 1 can be found in J.W. Weber, O. Kunz, C. Knaack, D. Chung, A. Barson, A. Slade, Z. Ouyang, H. Gottlieb, T. Trupke, “Daylight photoluminescence imaging of photovoltaic systems using inverter-based switching”, Progress in Pho to voltaic s: Research and Applications 2024, 32, 643 -651, which is incorporated by reference in its entirety herein. Fig. 2 shows a closeup of Fig. 1, highlighting some unexpected DPL intensity variations between modules that, as will be shown, result from significant voltage mismatches between modules and between PV strings of the PV array.

[0107]

[0103] In Fig. 1, the PV modules located in the top section of the image exhibit no detected PL signal. This is expected since these modules are part of a PV array connected to a different inverter and are thus operating at a constant operating point, as determined by that inverter, for example close to maximum power point (MPP) conditions. These modules emit a small and constant PL signal which drops out in the image difference calculation, just like the constant ambient signal. In contrast, a distinct variation in luminescence intensity between modules is observed in the bottom section of the image corresponding to the PV array associated with the inverter switched between different operating conditions. The overall brighter intensity in the bottom right comer of the image is an artefact resulting from lens vignetting, an issue that may be addressed using flat field correction.

[0108]

[0104] The striped line in Fig. 2 marks the position of a boundary between series connected PV strings in this section of the solar farm, all of these PV strings being connected in parallel to the same inverter. The DPL image shown in Fig. 1 exhibits several interesting and unexpected luminescence intensity variations:

[0109] • Small groups of one to four modules (white arrows in Fig. 1) exhibit significantly reduced PL intensity compared to others;

[0110] • Individual modules, or small groups of modules exhibit significantly higher intensity than all other modules (striped arrows in Fig. 1, as well as the white arrows seen in Fig. 2); • Several complete strings (in the bottom left of Fig. 1) of modules consistently exhibit significantly lower PL signal compared to other strings;

[0111] • The dark modules on the right-hand side of the string boundary (for example the module labelled “2” in Fig. 2) appear with lower PL intensity compared to the dark modules on the left-hand side (e.g. the module labelled “1”) of the boundary.

[0112]

[0105] The common interpretation of PL intensities is based on the generalised Planck equation which predicts an exponential relationship between the luminescence intensity <pPLand the local cell diode voltage Vd. In simplified form that relationship can be written as

[0113] <PPL = C-j e^ kT ) equation (1) where kT / q is the so-called thermal voltage and C1is a calibration constant.

[0114]

[0106] Eq. 1 is commonly used for quantitative analysis of luminescence data in terms of implied voltages. The substantial luminescence intensity variations between modules that are observed in Fig. 1 and Fig. 2 could therefore naively be interpreted as local diode voltage variations that are caused entirely by variations in cell open circuit voltage between modules.

[0115]

[0107] As discussed in more detail in this disclosure, however, the physical mechanism for these PL image patterns is more complex, associated with balancing currents between strings of modules at certain operating points, particularly where the inverter holds a PV array at or near open circuit conditions.

[0116]

[0108] Further, in accordance with embodiments of the present disclosure, additionally or alternatively, electroluminescence (EL) imaging is used to determine one or more characteristics of a PV array. As will be discussed in this disclosure, EL imaging may be practically performed by injecting current into two or more PV strings at a time, which causes current variations between the two or more PV strings. The present disclosure recognises that characterisation of PV arrays based on EL imaging techniques may be adjusted to account for the current variation due to the current injection into two or more PV strings. Accordingly, throughout this disclosure, the term ‘luminescence’ may be used to refer to PL, EL or a mixture of EL and PL.

[0117] System

[0118]

[0109] Fig. 3 illustrates an example system 300 for determining one or more characteristics of a PV array 310 according to an embodiment of the present disclosure. The PV array 310 may also be referred to as a solar farm, solar array or the like. The PV array 310 comprises a plurality of PV strings 320, 330 (only first and second PV strings 320, 330 being shown in this embodiment) which are electrically connected in parallel to each other. Each of the PV strings 320, 330 comprises a plurality of PV modules electrically connected in series to each other. More specifically, first PV string 320 comprises a first set of PV modules 321, 322, 323, 324 electrically connected in series to each other, and second PV string 330 comprises a second set of PV modules 331, 332, 333, 334 electrically connected in series to each other. Each PV module 321, 322, 323, 324, 331, 332, 333, 334 comprises one or more PV cells 325 that are typically electrically connected in series to each other. However, practically, each PV cell in each PV module 321, 322, 323, 324, 331, 332, 333, 334 may be different with different electrical performance and may produce a different luminescence.

[0119]

[0110] The PV array 310 as depicted in Fig. 3 includes only two PV strings, each with four PV modules, each module with sixteen PV cells. However, this is only an example of a PV array 310. A PV array 310 may comprise any number of PV strings, and each PV string may comprise any number of PV modules, and each PV module may comprise any number of PV cells. For example, the PV array discussed in this disclosure, and as partially depicted in Fig. 1, comprises a plurality of PV strings, each with 27 series-connected PV modules, with 72 PV cells per PV module. More specifically, the PV modules are butterfly modules with 2 x 72 = 144 (half) PV cells each.

[0120]

[0111] The system 300 also comprises an inverter 340. In some embodiments, the PV strings 320, 330 are electrically connected to the inverter 340 in parallel, as depicted in Fig. 3, and may therefore have the same notional PV string voltage. The inverter 340 may be configured to change direct current (DC) to alternating current (AC) before feeding to an electrical grid. In some examples, the inverter 340 may be configured to measure the string voltage of the PV strings 320, 330 and / or the string current of the PV strings 320, 330. The system 300 may also comprise a power source 360 if electroluminescence is to be generated. In some examples, the inverter 340 may provide current to the PV strings 320, 330 and hence, the inverter 340 and the power source 360 may be the same entity.

[0121]

[0112] The system 300 comprises at least one device 350, which may be a smartphone, computer, tablet, a server device, or any other similar device. The device 350 may also be a programmable board or the like. The device 350 may comprise a processor 351. The device 350 may comprises memory 352, e.g., a non-volatile memory 353 and / or a volatile memory 354. The processor 351 may communicate with memory 352 by communicating with the non-volatile memory 353 and / or the volatile memory 354. The non-volatile memory 353 may be a non- transitory computer readable medium, which may be an optical disk drive, a hard disk drive, a solid-state drive, a flash memory, a storage server, a cloud storage or another equivalent type of memory. The volatile memory 354 may be cache, RAM or another equivalent type of memory.

[0122]

[0113] The memory 352 may store data to be retrieved for later use. For example, the memory 352 may store one or more PE intensity values (or one or more EE intensity values) based on a PL image (or an EL image) or may store a PL image (or an EL image) itself. The memory 352 may also store a value indicative of current in the at least one PV string (such as a determined current). The memory 352 may store one or more determined characteristics of a PV array. The data may be stored in the memory 352 in the form of a JSON format file, XML format file or another equivalent data format file. The PL image (or EL image) may be stored in memory 352 in the form of a Joint Photographic Experts Group (JPEG) file, RAW data format file, TIF data format, TXT format or another equivalent image data format file.

[0123]

[0114] Software, that is, an executable program stored on the non-volatile memory 353, may cause the processor 351 to perform methods for determining one or more characteristics of the PV array 310. While the singular of “processor” is used herein, it is meant to also encompass multiple processors that are individually or together configured (e.g., programmed) to perform the methods disclosed herein. As such, the processor 351 referenced herein may refer to multiple central processing units (CPUs) and / or graphical processing units (GPUs) that are configured to collectively perform the methods disclosed herein. Once executed, in accordance with methods according to embodiments of the present disclosure as discussed below, the software may cause the processor 351 to determine at least one PL intensity value (or at least one EL intensity value) of one or more of the PV modules 321, 322, 323, 324, 331, 332, 333, 334, determine at least one current value in at least one of the PV strings 320, 330, and / or determine one or more characteristics of the PV array 310.

[0124]

[0115] The system 300 may also comprise a camera 355, which may be configured to capture or construct image data of the PV array 310. More specifically, the camera 355 may be used to construct a PL image of a PV array 310 when the PV array 310 is or has been illuminated by solar radiation (i.e. a DPL image). The camera 355 may also be used to construct an EL image of a PV array 310 during current injection into a group of PV strings (such as the PV strings 320, 330). The camera 355 may capture an EL image either during the day (i.e., under ambient illumination conditions) or at nighttime. The camera 355 may be a shortwave infrared (SWIR) camera or the like. In other examples, the camera 355 may be a silicon CMOS camera, a silicon CCD camera, an InGaAs camera, or the like. The device 350 including the processor 351 may communicate with the camera 355 via an input / output (I / O) port 356. The camera 355 may also communicate with the device 350 via wireless communication, such as Bluetooth, LoRa or WiFi. In some embodiments, the camera 355 may be, or may additionally comprise, a thermal imaging device, configured to capture a thermal image of the PV array 310.

[0125]

[0116] The device 350 may comprise a user interface (such as a graphical user interface) that is presented to the user of the device 350. The user interface may be configured to accept input (via buttons or text fields etc) from the user, via a touch screen of the device 350 or via a peripheral item attached to the device 350 such as a keyboard or computer mouse. These peripheral items may also include a touchpad, an externally connected touchscreen, a joystick, a button, and a dial, for example. In an example, multiple PL images or EL images may be presented to a user on a screen and the user may choose one of the PL images (or EL images) to determine a PL intensity value (or an EL intensity value). Based on the user interaction, this may then cause the processor 351 to determine the one or more characteristics of the PV array 310 based on the PL intensity value (or the EL intensity value) from a PL image or EL image chosen by a user.

[0126]

[0117] The device 350 may communicate with the inverter 340 via I / O port 357. The device 350 may be remotely located from the inverter 340 or within the vicinity of or near the PV array 310. The device 350 may communicate with the inverter 340 through a wireless connection, such as by using a Wi-Fi network according to IEEE 802.11. The Wi-Fi network may be a decentralised ad-hoc network, such that no dedicated management infrastructure such as a router is required. Alternatively the Wi-Fi network may be a centralised network with a router or access point managing the network. In some examples, the device 350 may communicate with the inverter 340 using a short-range wireless technology standard such as Bluetooth or the like. In some cases, the device 350 may communicate with the inverter 340 using a wired connection, such as using Ethernet, or the like.

[0127]

[0118] As the device 350 may communicate with the inverter 340, the device 350 may be indicative of a control system. In particular, the device 350 may communicate with the inverter 340 to activate a switching of operational modes of PV array 310. In other words, the device 350 may actively drive the switching via the inverter 340. For example, the device 350 may cause the inverter 340 to be set to a switching mode, causing the inverter 340 to alter the operating point in fixed time intervals. This may be useful in DPL image acquisition or EL image acquisition during the daytime (i.e., DEL) as will be later discussed. In some examples, the device 350 may control or configure current injection into a group of PV strings for generation of electroluminescence.

[0128]

[0119] The system 300 may also comprise one or more sensors or one or more meters (not shown), which may be configured to perform direct measurements of one or more properties of the PV array 310. For example, the one or more meters may be a voltmeter, which directly measures the string voltage of a PV string 320, 330. The voltmeter may also direct measure individual PV modules or a plurality of the PV modules in the PV string 320, 330. In another example, the one or more meters may be a current meter (such as a current clamp), which directly measures the current flowing into or from any one of the PV strings 320, 330 or PV modules thereof. In some examples the one or more sensors may be a temperature sensor configured to determine the ambient or overall temperature of the PV array 310, or temperatures of individual PV modules 321, 322, 323, 324, 331, 332, 333, 334. The direct measurements from the one or more sensors, and / or the one or more meters may be used in conjunction with the information obtained from a PL image (or an EL image) of a PV array to assist in determining one or more characteristics of the PV array 310. The direct measurements may be stored in the memory 352. The one or more meters may be integrated into the PV array 310 or may be specifically added for the measurements and then later removed.

[0129] Photoluminescence-based method

[0130]

[0120] Fig. 4 illustrates a method 400, according to an embodiment of the present disclosure, for determining one or more characteristics of a PV array, the PV array comprising a plurality of PV strings electrically connected in parallel to each other, each PV string comprising a plurality of PV modules electrically connected in series to each other.

[0131]

[0121] At 401, the method 400 includes determining at least one PL intensity value of one or more PV modules in at least one of the PV strings based on at least one PL image of the PV array when illuminated by solar radiation.

[0132]

[0122] At 402, the method 400 includes determining at least one current value in the at least one PV string, for example when the PV array is in an open circuit condition or operating at an operating voltage above a maximum power point voltage of the PV array.

[0133]

[0123] At 403, the method 400 includes determining the one or more characteristics of the PV array based on the at least one determined current value and / or the at least one determined PL intensity value.

[0134]

[0124] The method may be carried out in relation to a PV array that is the same or similar to the PV array 310 depicted in Fig. 3, for example. To aid in explanation of the disclosed method 400, reference is made in subsequent discussions to “at least one of the PV strings” with reference to the PV string 320 of Fig. 3. However, this is not to mean that reference to “at least one of the PV strings” is limited to one particular PV string in a PV array. It is noted that steps of the disclosed method are equally applicable to PV string 330 or any other PV string that a PV array 310 may comprise.

[0135] Determinins at least one PL value

[0136]

[0125] The processor 351 may be used in the step 401 of determining at least one PL intensity value of one or more PV modules 321, 322, 323, 324 in at least one of the PV strings 320 based on at least one PL image of the PV array 310 when the array is illuminated by solar radiation. The at least one PL image captures the PV array 310 when illuminated by solar radiation (i.e., during illumination by solar radiation). In other words, the at least one PL image captures the PV array 310 while emitting light resulting from photoluminescence. The at least one PL image may capture the PV array 310 being illuminated by solar radiation as well as while undergoing photoluminescence.

[0137]

[0126] The PL image contains at least one PL intensity value that is determined by the processor 351. However, the PL image may also contain at least one EL intensity value. More specifically, the PL image may capture both photoluminescence (as a result of the PV array 310 being illuminated by solar radiation) and electroluminescence (as of result of injecting current into the PV array 310, e.g. from the inverter 340 or the power source 360). As such, “PL image” discussed in this disclosure (as well as “EL image” discussed in this disclosure) may be referred to more generally as a luminescence image. Hence, the “PL intensity value” (as well as the “EL intensity value”) discussed in this disclosure may be referred to more generally as a luminescence intensity value. In particular, the processor 351 may not distinguish between a PL intensity value and an EL intensity value in the at least one PL image.

[0138]

[0127] The processor 351 may receive the at least one PL image of the PV array 310 directly from the camera 355, or may construct the PL image based on signals from the camera 355. Additionally or alternatively, the at least one PL image may be stored in the memory 352 and the processor 351 may retrieve the PL image from memory 352. Additionally, or alternatively, the processor 351 may receive the at least one PL image from an external source such as a remote server. The terms “Photoluminescence image” or “PL image” in the context of the present disclosure may refer to an image (or image data) with at least one PL component. Such an image may include ambient light or even be dominated by ambient light. In some examples, the processor 351 may determine the PL intensity value based on the pixel values of one or more (or all) pixels in the PL image. For example, each pixel of a PL image may correspond to an PL intensity value. As such, the at least one determined PL intensity value of the one or more PV modules 321, 322, 323, 324 may be an average or weighted sum of the PL intensity values of the pixels corresponding to the one or more PV modules 321, 322, 323, 324 in the PL image.

[0139]

[0128] As the at least one PL image is captured when the PV array 310 is illuminated by solar radiation, the at least one PL image may be referred to as a daytime PL (DPL) image. To ameliorate the effect of ambient light on daylight luminescence imaging, either DPL or DEL imaging, the camera 355 may rely on atmospheric sunlight absorption and filtering, with single shot PL image acquisition possible using highly specialised ultranarrow bandpass filters that have pass bands as narrow as 5 nm or less, or 2 nm or less, or 1 nm or less, or even 0.5 nm or less, designed to coincide with a very narrow and deep atmospheric absorption band around 1135 nm. More information on this approach can be found in G. Rey, O. Kunz, M. Green, T. Trupke, “Luminescence imaging of solar modules in full sunlight using ultra narrow bandpass filters”, Progress in Photovoltaic s: Research and Applications 2022, 30, 1115-1121, which is incorporated by reference in its entirety herein. In contrast, the complication of ambient light may be avoided in nighttime electroluminescence (NEL) imaging. Preferably, the at least one PL image may be obtained using high quality DPL image acquisition using inverter-based electrical switching and may include image acquisition whereby the camera is mounted on a remote piloted aircraft (RPA) such as an aerial drone.

[0140]

[0129] Due to the ambient light, in some embodiments, the processor 351 determines the PL image from a difference between two images acquired with the PV array 310 at different operating points chosen to provide significantly different luminescence intensities. This may reduce the effect of ambient light which may cause background noise in a PL image otherwise. In a preferred embodiment, the PL image from which the at least one PL intensity value is determined is obtained as the difference between two images of the PV array 310 captured at two or more different operating conditions of the PV array 310. For example, there may be two different operating conditions, one with the luminescence turned ON (e.g. the open circuit condition) and one with the luminescence turned OFF (e.g., the maximum power point condition). More generally, the two different operating conditions may produce two different levels of luminescence, not necessarily fully ON or OFF (e.g., the two images may be captured under different bias conditions). Generally, this relies on controlling and manipulating the electrical operating point of modules in the PV array and thereby the operating voltage of the cells embedded within the modules. In some examples, the two different operating conditions are: the open circuit condition and an operating voltage above a maximum power point voltage of the PV array, as will be described below.

[0141]

[0130] An example of high quality DPL image acquisition using inverter-based electrical switching is now explained in further detail. The inverter 340 may be set to a switching mode to cause a switching between different operating conditions of the PV array 310. For example, the inverter 340 may be set to a two-step switching process, whereby the operating point of the PV array 310 is switched between the maximum power point (MPP), at which 100% of the available power is extracted and open circuit (OC), at which the DC current into the inverter 340 and the extracted power are zero. In another example, the operating point is switched in three distinct steps, including an interim step at which, say, 40% of the MPP current is extracted from the module, resulting in approximately 40% of the maximum power being extracted. An image of the PV array 310 at each state (i.e., after each switching event) may be captured and the processor 351 may then determine the PL image from an image difference between at least two images of the PV array 310. In other examples, the image difference may be based on at least two images of the PV array 310 captured at any two operating conditions.

[0131] This DPL method may be performed in a number of different ways: (1) without communication to the inverter 340; and (2) with communication to the inverter 340. It is noted that in the system 300 depicted in Fig. 3, the device 350 and the inverter 340 are in communication. However, in some embodiments of system 300, the device 350 may not be in communication with the inverter 340. In situation (1), where the device 350 and the inverter 340 are not in communication, the inverter 340 may be set to a switching mode, causing it to alter the operating point in fixed time intervals. The DPL image acquisition may be independent of the switching, e.g., at a higher (capture) rate than the switching. In the case of a two-step switching process, the interpretation of ON and OFF (e.g., MPP and zero extracted power (open circuit condition), respectively) can then be done in post processing by the processor 351, for example. The post processing may, in some instances, rely on the variation in the PL intensity value of the individual PL images to determine the switching of the inverter 340, i.e. the ON and OFF states. In situation (2), where the device 350 and the inverter 340 are in communication as depicted in Fig. 3, the device 350 may communicate with the inverter 340 to activate the switching through wireless communication, for example. In situation (3), the post processing may be performed live during the image capture. This may be performed by synchronising the camera 355 and the inverter 340. This could also be done prior to image capture via an image sequence or current clamp or other means, for example.

[0142] Determining at least one current value in the at least one PV string

[0143]

[0132] The processor 351 may be used in the step 402 of determining at least one current value in the at least one PV string 320 when the PV array 310 is in an open circuit condition or operating at an operating voltage above a MPP voltage of the PV array 310. In this regard, the processor 351 may determine the at least one current value when the PV array 310 is in one or more of the mentioned operating conditions (e.g., open circuit condition or operating at an operating voltage above a MPP voltage). Alternatively, the at least one current value may be determined subsequently, but based on information that was obtained when the PV array 310 was in one or more of the mentioned operating conditions.

[0144]

[0133] For example, as will be discussed below, the processor 351 may determine the at least one current value from a PL image of the PV array 310. This PL image may be captured when the PV array 310 is operating at an open circuit condition, or at an operating voltage above a MPP voltage. As such, the processor 351 may determine the at least one current value after the PV array 310 was operating at these operating conditions. In another example, direct measurements of the at least one current value may be made during one or more of the operating conditions. In this case, the processor 351 may determine the at least one current value at a time after the measurement was made. In some examples, the processor 351 may also receive the measurement directly after the measurement was made.

[0145]

[0134] By determining the at least one current value when there is minimal or no current being extracted from or injected into the PV array 310, the at least one determined current value may be indicative of a balancing current in the PV string 320 caused by a voltage mismatch between at least two PV strings (e.g., PV strings 320, 330) in the PV array 310.

[0146]

[0135] The MPP voltage is the voltage at which a PV module produces maximum power. Maximum power varies with solar radiation, ambient temperature and PV cell temperature, as well as the make and model of the PV cells that form the PV module. For example, a PV module may produce power with a MPP voltage of around 40 V when measured at a cell temperature of 25°C. The MPP voltage can drop to around 38 V on a hot day and it can also rise to 41 V on a cold day. A PV array 310 operating at an operating voltage above the MPP voltage may be indicative of a PV array 310 operating at or near open circuit conditions.

[0147]

[0136] In some embodiments, an operating voltage above the MPP voltage results in a power extracted from PV array 310 that is equal to or less than 20% of a power extracted from the PV array 310 when the PV array 310 is operating at the maximum power point voltage (which may be referred to as the MPP power). For example, if the MPP power is 1 MW, then the power extracted from PV array 310 (i.e., the reduced power) may be 0.2 MW or less. In some embodiments, an operating voltage above the MPP voltage results in a power extracted from the PV array 310 that is equal to or less than 40% of a power extracted from the PV array 310 when the PV array 310 is operating at the maximum power point voltage. In some embodiments, an operating voltage above the MPP voltage results in a power extracted from PV array 310 that is between 20% and 50% of a power extracted from the PV array 310 when the PV array 310 is operating at the maximum power point voltage.

[0148]

[0137] In some embodiments, the at least one current value in the at least one PV string may be determined when the PV array is in a different operating condition that is not the open circuit condition or operating voltage between an open circuit condition and an operating voltage above a maximum power point voltage of the PV array. In some embodiments, the processor 351 may determine at least one current value in the at least one PV string when the PV array is operating at an operating voltage between an open circuit condition and an operating voltage above a maximum power point voltage of the PV array. As described above, this operating voltage may correspond to an operating voltage above the maximum power point voltage that results in a power extracted from the PV array that is < 20% or < 40% of a power extracted from the PV array when the PV array is operating at the maximum power point voltage. This operating voltage may also correspond to an operating voltage above the maximum power point voltage that results in a power extracted from the PV array that is between 20% and 50% of a power extracted from the PV array when the PV array is operating at the maximum power point voltage.

[0149]

[0138] The PL intensity value determined from the PL image may be related to the current in the PV string 320. For example, as will be later discussed, the PL intensity value may be related to the cell diode voltage, which may be related to the current in the PV string 320. As such, in some embodiments, the at least one determined current value of the PV string 320 may be determined at least partially based on the at least one determined PL intensity value of one or more PV modules 321, 322, 323, 324. However, in other embodiments, the at least one determined current value of the PV string 320 may be determined at least partially based on determined PL intensity values of all PV modules 321, 322, 323, 324, 331, 332, 333, 334 connected to an inverter 340 of a PV array 310.

[0150]

[0139] As discussed above, the PL intensity value determined from a PL image may be related to the cell diode voltage. The term “cell diode voltage” in the context of PV cells may refer to the voltage across the p-n junction of the PV cell when it is operating as a diode (i.e., a semiconductor device that essentially acts as a one-way switch for current). In some examples, there may be a mathematical relationship between PL intensity value and the cell diode voltage. In particular, the PL intensity value may be an exponential of the cell diode voltage. More specifically, the PL intensity value may be based on a generalised Planck equation which predicts an exponential relationship between the PL intensity value and the local cell diode voltage. In some embodiments, the PL intensity value may be based on Eq. 1 discussed previously.

[0151]

[0140] The processor 351 may determine the at least one current value of the PV string 320 by directly analysing the PL image. For example, the processor 351 may determine the at least one current value by applying an algorithm or a machine learning model to the PL image. The output of the algorithm or the machine learning model may then correspond to the at least one current value of the PV string 320.

[0152]

[0141] In some embodiments, the at least one determined current value of the PV string 320 is determined at least partially based on cell diode voltages in the PV string 320. In some examples, the cell diode voltages in the PV string 320 may be calculated from the at least one determined PL intensity value of the one or more PV modules 321, 322, 323, 324 of the PV string 320. Hence, in some embodiments, the at least one determined current value of the PV string 320 is determined at least partially based on a sum of cell diode voltages in a PV string 320 calculated from the at least one determined PL intensity value of the one or more PV modules 321, 322, 323, 324 of the PV string 320.

[0142] In some embodiments, the processor 351 may determine the cell diode voltages in a PV string 320 from the at least one PL image. For example, the processor 351 may determine a value from the at least one PL image indicative of the cell diode voltages in a PV string 320. More specifically, the processor 351 may determine the cell diode voltages in a PV string 320 from the at least one PL intensity value determined from the at least one PL image. For example, the processor 351 may determine the cell diode voltages in the PV string 320 by applying an algorithm, mathematical operation or machine learning model to the at least one PL image. In a more specific example, processor 351 may determine the cell diode voltages in a PV string 320 based on the generalised Planck equation of Eq. 1, which can be rearranged to determine the cell diode voltage Vdusing the PL intensity value (<pPL). Hence, the processor 351 may determine the cell diode voltages in a PV string 320 based on the rearrangement of Eq. 1.

[0153]

[0143] The at least one determined current value of the PV string 320 may be based on the string voltage of the PV string 320. The string voltage of the PV string 320 may also be based on diode voltages of cells in the PV module 321, 322, 323, 324. For example, the string voltage of the PV string 320 may be based on a sum of diode voltages of cells in the PV module 321, 322, 323, 324. The diode voltages may be indicative of cell terminal voltages. The string voltage of the PV string 320 may also be based on the number of PV modules in the PV string 320 (for example, there are four PV modules per PV string depicted in Fig. 3). The string voltage of the PV string 320 may also be based on the number of PV cells in each of the PV modules 321, 322, 323, 324 (for example, there are sixteen PV cells in each of the PV modules 321, 322, 323, 324 depicted in Fig. 3).

[0154]

[0144] The at least one determined current value may be based on the overall system voltage of the PV array 310. The overall system voltage of the PV array 310 may be based on the cell diode voltages. For example, the overall system voltage may be determined based on a mathematical operation involving the cell diode voltages, such as a sum, mean or median of the cell diode voltages. As such, in some embodiments, the at least one determined current value of the PV string 320 is determined at least partially based on a mean of diode voltages of all cells in all PV modules 321, 322, 323, 324 connected to an inverter 340 of the PV array 310.

[0155]

[0145] In some embodiments, the at least one determined current value of the at least one PV string 320 is determined at least partially based on a series resistance of at least one PV cell in the one or more PV modules 331, 332, 333, 334 of one of the plurality of PV strings 330. The series resistance (which may also be referred to as the lumped series resistance) is a single-value representation of all the resistive losses (e.g., contact resistance, emitter resistance, and bulk resistance) that occur within a PV cell. The series resistance of a PV cell may for example be based on its materials, so that the series resistance may be based on the make and / or model of the PV cell. As discussed in this disclosure, the overall system voltage may be affected by the string current, the cell diode voltages in the string and the series resistance. In some examples, it may be assumed that the series resistances for each PV cell in each PV module 331, 332, 333, 334 of the one of the plurality of PV strings 330 are similar or equivalent. Similarly, it may be assumed that each PV module in the PV array 310 has a similar or equivalent series resistance. For explanatory purposes, determining the series resistance is described with reference to the PV string 330, noting that PV string 320 (or any other PV strings in the PV array) may be used.

[0156]

[0146] In some embodiments, the processor 351 may determine the series resistance based on a measurement of a voltage of the one or more PV modules 331, 332, 333, 334 in the one of the plurality of PV strings 330 via one or more y-connectors. A y-connector is a type of electrical connector used to combine or split the output of PV modules. A y-connector, which may also be referred to as a branch connector or a y-lead, may be used to connect PV modules in parallel. In some examples, the voltage at these PV modules may be measured by inserting a y-connector such as, but not limited to, a MC-4 y-connector of a type commonly used in PV systems to connect multiple PV modules. By using one or more y-connectors, only the series resistance contribution may be measured from the PV modules, while omitting the resistance that results from system wiring. The processor 351 may receive the measurement of the voltage by retrieving the measurement from a database, server, or via user input, for example. The processor 351 may also receive the measurement (i.e., the measured voltage value) directly as the measurement is performed.

[0157]

[0147] In some embodiments, processor 351 may determine the series resistance based on a measurement of a voltage of a PV module similar to and / or associated with the one or more PV modules 331, 332, 333, 334 in the one of the plurality of PV strings 330. A PV module that is similar to and / or associated with the one or more PV modules 331, 332, 333, 334 may be the same (or similar) make and / or model of the installed PV module. For example, the series resistance may be estimated using multiple current luminescence intensity values from an operations and maintenance (O&M) spare, i.e., a PV module that has not yet been deployed in the field but is kept in storage for future use. This may be advantageous as an inexpensive lab power supply can be used to determine this PV module’s series resistance, which can then be assumed to be similar or equivalent to that of the installed modules in the PV string 330. The processor 351 may receive the measurement of the voltage by retrieving the measurement from a database, server, or via user input, for example. The processor 351 may also receive the measurement (i.e., the measured voltage value) directly as the measurement is performed.

[0158]

[0148] As has been previously discussed, direct measurements of the PV array 310 may be carried out or obtained to assist in determining one or more characteristics of PV array 310. For example, the system 300 may comprise a voltmeter, which directly measures the string voltage of the at least one PV string 320, 330. The voltmeter may measure voltage across all of the PV strings 320, 330. In other examples, the measurement of the string voltage of the at least one PV string 320, 330 may be performed by the inverter 340. As such, in some embodiments, the at least one determined current value of PV string 320 is determined at least partially based on a measured voltage across all of the PV strings 320, 330 of PV array 310 connected to inverter 340 of PV array 310. In other embodiments, system 300 may comprise a meter (such as a current clamp) to measure the current directly. As such, the at least one determined current value of the PV string 320 may be determined at least partially based on a direct current measurement from PV string 320. The direct current measurement may be obtained using one or more of: a clamp meter; a Hall effect current transducer; a current transformer; and a current shunt resistor.

[0159]

[0149] The current in the PV string 320 may be determined using the current that is measured in another string e.g., the PV string 330. As such, in some embodiments, the at least one determined current value in the at least one PV string 320 is determined at least partially based on a direct current measurement from the at least one PV string 320 or a different one of the plurality of PV strings 330. While the PV array 310 only has two PV strings in this example, the current in one PV string may be determined using the current in any other PV string in the PV array. This is because the total current may be determined based on the inverter 340.

[0160]

[0150] The system 300 may comprise one or more temperature sensors to directly measure the temperature of one or more PV modules 321, 322, 323, 324 of PV string 320. The one or more temperature sensors may be a contact temperature sensor or an infra-red contactless temperature sensor, for example. The direct measurements of the PV array 310 may be obtained to assist in determining one or more characteristics of the PV array 310. In some embodiments, the at least one determined current value of PV string 320 may be determined at least partially based on a temperature of one or more PV modules 321, 322, 323, 324 of the PV string 320.

[0161]

[0151] The system 300 may comprise a thermal imaging device, configured to capture at least one thermal image of the PV array 310. As such, rather than using temperature sensors deployed within or near PV array 310, the temperature of one or more PV modules 321, 322, 323, 324 of the PV string 320 may be determined from the thermal image of PV array 310. As such, in some embodiments, the temperature of the one or more PV modules 321, 322, 323, 324 of PV string 320 is determined by thermal imaging of the one or more PV modules 321, 322, 323, 324 of PV string 320.

[0162]

[0152] In some embodiments, the processor 351 may determine the at least one current value of PV string 320 at least partially based on a temperature of the one or more PV modules 321, 322, 323, 324 when (i) PV array 310 is operating substantially at maximum power point (MPP), and (ii) PV array 310 is operating in an open circuit condition or operating at an operating voltage above a maximum power point voltage of PV array 310.

[0163]

[0153] In some embodiments, the processor 351 may determine the at least one current value of PV string 320 at least partially based on a comparison between a temperature increase of the one or more PV modules 321, 322, 323, 324 of the PV string 320 caused at least partially by solar absorption when the PV array 310 is operating substantially at maximum power point (MPP), and a temperature increase of the one or more PV modules 321, 322, 323, 324 of the PV string 320 caused at least partially by solar absorption when the PV array 310 is operating in an open circuit condition or operating at an operating voltage above a maximum power point voltage of PV array 310.

[0164] Determining the one or more characteristics of the PV array

[0165]

[0154] The processor 351 may be used in the step 403 of determining the one or more characteristics of the PV array 310 based on the at least one determined current value of the PV string 320 and / or the at least one PL intensity value. For example, the processor 351 may determine the one or more characteristics of the PV array 310 by applying an algorithm, mathematical operation or machine learning model to the at least one determined current value of the PV string 320 and / or the at least one PL intensity value. As such, the processor 351 may determine a numerical value which may be indicative of one or more characteristics of PV array 310. The numerical value may be a performance indicator of the PV array 310 and / or of one or more of the PV strings 320, 330, and / or of one or more of the PV modules 321, 322, 323, 324, 331, 332, 333, 334. The one or more characteristics of the PV array 310 may be one or more characteristics of part of the PV array 310, such as: one or more of the PV strings, one or more of the PV modules; and / or one or more of the PV cells.

[0166]

[0155] One of the one or more characteristics of the PV array 310 that may be determined by the disclosed method may be the performance of one or more of the PV modules 321, 322, 323, 324. For example, the characteristic of the PV array 310 may be a numerical value based on the at least one determined current value of PV string 320 and / or the at least one PL intensity value determined from the at least one PL image. The processor 351 may then compare the numerical value to a predetermined range to determine whether one or more PV modules 321, 322, 323, 324 are underperforming or performing normally. The processor 351 may also compare a numerical value to a threshold value to determine whether one or more PV modules 321, 322, 323, 324 are underperforming or performing normally, for example.

[0167]

[0156] One of the one or more characteristics of PV array 310 determined by the disclosed method may be an implied voltage of PV array 310. For example, the processor 351 may apply an algorithm, mathematical operation or machine learning model to the at least one determined current value and / or the at least one PL intensity value determined from the at least one PL image to determine the implied voltage of PV array 310, or the implied voltage of PV string 320. The algorithm may be indicative of a DPL analysis technique. One of the one or more characteristics of the PV array 310 determined by the disclosed method may be any other voltages in the PV array 310, such as one or more cell diode voltages, system voltages, terminal cell voltages, or the like.

[0168]

[0157] In some embodiments, the one or more characteristics of the PV array comprises one or more of: an open circuit voltage; an operational voltage; an implied voltage; module performance; module quality; and a corrected PL image. The open circuit voltage (Voc) of a PV array is the maximum voltage the array can produce when no load is connected to it, and this occurs at zero current. The operational voltage of a PV array is any voltage under which it is operating at a given point in time. The corrected PL image may correspond to a PL image in which one or more PL intensity values in the original image have been corrected, as will be discussed later in this disclosure.

[0169]

[0158] The one or more determined characteristics of the PV array 310 may be qualitative or quantitative information regarding one or more PV strings 320, 330, and / or or one or more PV modules 321, 322, 323, 324, 331, 332, 333, 334, and / or one or more PV cells, such as PV cell 325. For example, qualitative information may be indicative of the quality of PV modules 321, 322, 323, 324, 331, 332, 333, 334. Qualitative information may also be indicative of whether one or more PV modules 321, 322, 323, 324, 331, 332, 333, 334 are underperforming or performing normally. Qualitative information may also be indicative of whether one or more PV modules 321, 322, 323, 324, 331, 332, 333, 334 have degraded due to field exposure. Qualitative information may include whether there is a voltage mismatch between different PV strings 320, 330.

[0170]

[0159] Quantitative information may include the implied voltage of the PV array 310. The implied voltage is a parameter used to assess the potential performance of a PV array. The implied voltage may represent the open-circuit voltage or the maximum voltage available from the PV array 310, which occurs at zero current. An implied voltage may also be determined at non-open circuit conditions, such as current extraction or injection. The implied voltage is termed “implied”, as it is determined (e.g., calculated) indirectly, rather than being explicitly measured. The implied voltage of PV array 310 is the collective voltage potential of PV array 310, meaning that it is based on the implied voltage of the PV strings 320, 330. Moreover, the implied voltage of the PV strings 320, 330 is based on the voltages of the respective PV modules 321, 322, 323, 324, 331, 332, 333, 334 connected in series within that string. The implied voltage may be particularly useful for understanding the recombination properties and the quality of the material used in the PV cells or PV modules, even before the PV cells or PV modules are fully fabricated.

[0171]

[0160] The method of the embodiment according to Fig. 4 may provide a blueprint for a software program according to the present disclosure and may be implemented step-by-step, such that each step in Fig. 4 is represented by a function in a programming language, such as, but not limited to, Python, C++, Lab VIEW or Java. The resulting source code may then be compiled and stored as computer-executable instructions on the non-volatile memory 353, which causes the processor 351 (or multiple processors or a distributed computing architecture) to perform the method 400.

[0172] Adjusting the at least one determined PL intensity value

[0173]

[0161] From the at least one determined current value, the impact of the current on the PL intensity of the PV modules embedded in the respective PV string may be determined. As such, the originally determined PL intensity value may be adjusted to compensate for current in the PV string (e.g., a balancing current). The adjusted (or corrected) PL intensity value can then be used to determine more accurate characteristics of the PV array 310. Hence, in some embodiments, processor 351 may adjust the at least one determined PL intensity value of the one or more PV modules 321, 322, 323, 324 in the PV string 320 based on the at least one determined current value of PV string 320.

[0174]

[0162] In some examples, the processor 351 may adjust the at least one determined PL intensity value by adjusting one or more pixels in the at least one PL image. More specifically, if the at least one determined PL value corresponds to a PV module (such as PV module 321), then the processor 351 may adjust each pixel corresponding to the PV module 321 captured in the at least one PL image. The processor 351 may adjust the pixels corresponding to the PV module 321 e.g., by scaling using the same scaling factor. The processor 351 may perform this process for each PV module whose corresponding PL intensity value is to be adjusted.

[0175]

[0163] As discussed above, in some embodiments, the processor 351 may adjust the at least one determined PL intensity value of the one or more PV modules 321, 322, 323, 324 in the PV string 320 to reduce or remove an effect of a current (e.g., a balancing current) on the determined PL intensity value. More specifically, the processor 351 may adjust the at least one determined PL intensity value of the one or more PV modules 321, 322, 323, 324 in the PV string 320 based on the at least one determined current value to reduce or remove an effect on the at least one determined PL intensity value of balancing currents between PV strings 320, 330 of PV array 310, which may be identifiable when the PV array 310 is in an open circuit condition or operating at an operating voltage above a maximum power point voltage of the PV array 310.

[0176]

[0164] In some examples, the processor 351 may adjust the at least one determined PL intensity value by adjusting one or more features of the PL image that are indicative of the at least one determined PL intensity. The one or more features of the PL image may be image properties of the PL image. For example, the one or more features of the PL image may be one or more of digital count rates, brightness, colour, contrast, or the like. In some examples, the one or more PL images are grayscale images. As such, “colour” in this context may refer to “false colour” or pseudo-colour, i.e., one or more colours assigned to the grayscale image. The false colour may provide a better visual representation of the PL image of visual inspection of the PV array 310 captured in the PL image. Preferably, the processor 351 adjusts the count rates in the at least one PL image.

[0177]

[0165] The processor 351 may adjust the at least one determined PL intensity value by applying an algorithm, mathematical operation or machine learning model to the at least one determined PL intensity value. The processor 351 may also adjust the at least one determined PL intensity value based on other values, such as the string voltage or string current of the PV string 320, or other properties of the PV strings 320, 330 and the PV array 310. For example, the processor 351 may also adjust the at least one determined PL intensity value based on a PV cell’s short circuit current, which is the current through a PV cell when the voltage across the PV cell is zero. In particular, the processor 351 may also adjust the at least one determined PL intensity value based on a ratio of the string current to a cell’s short circuit current.

[0178]

[0166] In some embodiments, the at least one determined PL intensity value of the one or more PV modules 321, 322, 323, 324 in the PV string 320 is adjusted based on a difference or ratio of: (i) the at least one determined current value of the PV string 320 determined when the PV array 310 is in an open circuit condition or operating at an operating voltage above a maximum power point voltage of the PV array 310, and (ii) a short circuit current value of the PV string 320. The short circuit current value may be indicative of a short circuit current of the PV string 320, which may be an inherent property of PV string 320 or it may be the short circuit current under specific operating conditions, for example the current illumination conditions. The short circuit current value may be a measured short circuit current value e.g., the current value may be directly measured using a current clamp. The short circuit current value may by a nominal short circuit current value. The short circuit current value may be an estimated short circuit current value. The estimated short circuit current value may be obtained from the module data sheet and a measured or estimated illumination intensity.

[0167] In a more specific example, the at least one determined PL intensity value ((ppp) of the one or more PV modules 321, 322, 323, 324 in the at least one PV string 320 may be adjusted to at least one corrected PL intensity value (<PpL,corr) based on the following equation, where Inis the current in the at least one PV string (n) determined when the PV array is in an open circuit condition or operating at an operating voltage above a maximum power point voltage of PV array 310, Iscis a short circuit current of the at least one PV string and C2is a constant:

[0179]

[0168] Eq. 2 is based on a first order approximation, such that the PL intensity increases / decreases linearly with the current being injected / extracted. For accuracy of the approximation, Iscin Eq. 2 may be a PV cell’s short circuit current at the prevailing illumination conditions during DPL testing (i.e., not the nominal cell short circuit current). In other words, Iscmay be the short circuit current at the prevailing operating conditions, i.e., at the current solar irradiation level in the module plane, the module temperature, or the like. The constant C2may be based on the one or more operating conditions of the PV array 310 that are captured in the PL image. In some examples, when the operating conditions are the open circuit condition and the MPP voltage, C2may be equal to around 1. However, C2may be different if the operating conditions were between open circuit condition and the MPP voltage.

[0180]

[0169] In some embodiments, a direct current measurement (such as a measurement from a current clamp) of the current in one or more PV strings (such as the PV string 320) may be used to scale relative currents in all strings (i.e., the PV strings 320, 330) connected to the inverter 340 that may have been determined from other means. The other means may be the PL image or a thermal image, for example. As such, the processor 351 may adjust the at least one determined current value of the PV string 320 (e.g., as determined from the PL image of the PV array 310) at least partially based on a direct current measurement from the PV string 320.

[0181]

[0170] In some cases, the PV array 310 may contain PV strings that, intentionally or accidentally, contain different numbers of PV modules. For example, the PV string 320 may contain 26 series connected PV modules, while the PV string 320 may contain 27 PV modules. The effect of “missing” PV modules in the shorter string may be the same or similar as the effect of PV modules having lower voltage. In other words, if the same voltage is applied to all of these PV strings, the current in the shorter string may be significantly higher. Therefore, in some embodiments, the processor 351 adjusts the at least one determined PL or EL intensity value of the one or more PV modules 321, 322, 323, 324 in the at least one PV string 320 based on a number of PV modules in each of the plurality of PV strings. The processor 351 may apply an algorithm or mathematical expression to the at least one determined PL or EL intensity value based on the number of PV modules. For example, the processor 351 may determine a correction factor based on a ratio of the number of PV modules in each PV strings, then adjust the at least one PL or EL intensity value by multiplying the at least one PL or EL intensity value with the correction factor.

[0182] Junction box faults

[0183]

[0171] The PV modules 321, 322, 323, 324, 331, 332, 333, 334 may be configured with one or more junction boxes, often located on the back of the PV modules, for electrically connecting PV modules or groups of cells within a PV module. The PV modules 321, 322, 323, 324, 331, 332, 333, 334 may also be configured with one or more bypass diodes (BPDs) connected in parallel with groups of series-connected PV cells commonly referred to as module sub-strings. Each of the one or more BPDs may be housed in one of the junction boxes, for example. As such, there may be one BPD for each junction box. The one or more bypass diodes enable current to “bypass” a group of cells if one or more PV cells in the group becomes shaded, damaged, or otherwise non-functional. In an example PV module, the PV module may comprise three junction boxes, each with one BPD, which may be connected in parallel to 24 series-connected cells or to 48 series-connected half cells. The three separate sections of the PV module that are connected in parallel to each BPD correspond to the module sub-strings.

[0184]

[0172] Fig. 5 illustrates an example of a PV module 500 comprising three module sub-strings 510, 520, 530 denoted by the dashed lines. The PV module 500 also comprises three junction boxes 511, 521, 531, each of which comprises a bypass diode 512, 522, 532 respectively. The two outer junction boxes 511, 531 may also contain cabling to the PV module terminals, such as MC4 connectors, and the connection to the neighbouring substrings, while the middle junction box 521 may only comprise a bypass diode without further cabling. The bypass diodes 512, 522, 532 are each connected in parallel with one module sub-string 510, 520, 530. As described above, the bypass diodes 512, 522, 532 enable current to “bypass” a module sub-string 510, 520, 530 if one or more PV cells in that module sub-string become shaded, damaged, or otherwise non-functional. For example, if PV cell 515 of module sub-string 510 is damaged so as to prevent current flow through that cell, and in the absence of the bypass diode 512, current would not flow through the entire PV module 500 because the PV cells are connected in series.

[0185] However, the bypass diode 512 allows current to bypass the module sub-string 510, enabling current flow through the other sub-strings 520, 530 of the PV module 500 despite the PV cell 515 being damaged.

[0186]

[0173] Several junction box failure modes may be observed, which may affect the current in the PV array 310 and consequently the PL or EL intensity values in a PL or EL image acquired from a PV array 310 experiencing such failures. Moreover, these failures may affect the PV module overall by causing further damage to the module. As such, in some embodiments, the processor 351 may determine at least one junction box fault in the one or more PV modules 321, 322, 323, 324, in the at least one PV string 320 based on the at least one PL or EL image of the PV array 310. Further, in some embodiments, the processor 351 may adjust the at least one determined PL or EL intensity value based on the at least one determined junction box fault. This may involve determining how the junction box fault affects the current in the PV strings and adjusting the at least one determined PL or EL intensity value based on the current. Some junction box faults may be related to faults of the bypass diode they contain. However, other junction box faults may be possible, including: poor installation, environmental factors, or wear and tear. These junction box faults may cause similar issues for the PV modules as bypass diode faults, which are discussed in detail below.

[0187]

[0174] Junction box failures may include: i. BPDs in Open Circuit (equivalent to a module having a missing BPD); ii. BPDs in Short Circuit (e.g., a bypass diode internally short-circuited); and iii. Module sub-strings being electrically isolated (commonly referred to as lost module substrings or open circuit sub-strings).

[0188]

[0175] Failure mode i may have a minimal effect on the PL or EL intensity, as the current is flowing in forward direction and not via the BPD, so there is a minimal risk to the PV module. However, there is a risk of partial shading of the related substring, since this causes cells to go in reverse breakdown where they get very hot.

[0189]

[0176] In the case of a failure mode ii, a short-circuited BPD causes string Vocvariation (reduction) and therefore a current variation (increase) in the affected PV string in comparison to other parallel-connected PV strings under conditions of low power extraction from the PV array. As such, this may cause an increase in the PL or EL intensity value in the corresponding PV string, given that the PL or EL intensity value and the current are directly proportional to a first order. This current variation may be taken into account in DPL or DEL data analysis to correct measured PL intensities, in order to obtain comparable results between PV strings. However, this is the case is the short-circuited BPD has a low resistance. The short-circuited BPD may have a finite forward resistance that could have almost any value. If the short-circuited BPD has an intermediate resistance value, it could potentially lead to very high temperatures in the bypass diode that could damage the junction box or even cause a fire.

[0190]

[0177] Failure mode iii can also be problematic as, if one module sub-string is electrically disconnected (or very poorly connected), then the current will be forced to flow through the associated BPD in the reverse direction. This may cause the BPD to rapidly become hot and eventually fail. In the best case scenario, the affected BPD will fail by shorting out, i.e. converting mode iii to mode ii. However, the extreme heat at the affected BPD may constitute a safety risk, in the extreme case causing a fire. A large number of PV modules with failure mode iii have been observed during investigations of PV arrays in Australia.

[0191]

[0178] Fig. 6 shows a DPL image with four examples of PV modules having junction box faults. Fig. 6 also contains a close-up DPL image of one of these modules. As can be seen in Fig.

[0192] 6, the junction box fault may cause one-third of the PV module (one PV sub-string) to not emit a measurable luminescence signal. This is because the affected sub-string cannot be modulated to discriminate the luminescence intensity from ambient lighting. As such, the apparent absence of luminescence from a sub-string may be used to identify a junction box fault and its location in the PV array being inspected. Therefore, in some embodiments, the processor 351 may determine at least one PL value of a portion of the one or more PV modules 321, 322, 323, 324 in the at least one PL image of the PV array 310. The processor 351 may also determine that the at least one PL value of the portion has a value of about zero (i.e., the portion does not produce a measurable PL signal, thereby appearing as a black region in the PL image). A “portion” in the context of the present disclosure may refer to a part or region of the PV module, and may typically correspond to around one-third of the PV module depending on the make / model of the PV modules in the PV array.

[0193] Methodology

[0194]

[0179] The methodology used to obtain experimental results to demonstrate the identification of voltage mismatch and hence, balancing currents, within a PV array will now be discussed. In particular, the methodology discussed below was used to determine the cause of DPL intensity variations seen in Fig. 1 and Fig. 2, which were determined to be a result of voltage mismatch causing balancing currents within the PV modules.

[0195] Image acquisition

[0196]

[0180] DPL images were acquired in a 149 MWDC solar farm in Australia in November 2023. The solar farm became operational in March 2019 and contains monofacial half-cell passivation emitter rear contact (PERC) modules with a nominal open-circuit voltage (Voc) of 690 mV per cell, mounted on single axis trackers. The farm contains strings of 27 series-connected modules, connected in parallel to 2,750kVA SMA Sunny Central 2750-EV central inverters, which enables up to 3.2 kA DC current input. Existing functionality of these inverters was used to toggle the operating point of all modules connected to one specific inverter at a time.

[0197]

[0181] DPL measurements were performed using an Indium Gallium Arsenide (InGaAs) camera with a resolution of 1,280 x 1,024 pixels that was integrated into a DJI M600 hexacopter. A 25 nm bandpass filter with a centre wavelength of 1,137 nm was mounted in front of the camera lens for all measurements to exploit a broad atmospheric absorption band that coincides with the band-to-band emission spectrum from crystalline silicon at room temperature. This methodology was used to capture the images of Fig. 1 and Fig. 2.

[0198] Using thermal image information for PPL image correction

[0199]

[0182] In this section, it is described how to quantify balancing currents from the DPL image itself or in conjunction with measurements of the system voltage. A method to estimate balancing currents from thermal images is described.

[0200]

[0183] PV modules normally operate at significantly higher temperatures compared to ambient conditions. This is caused by PV modules absorbing typically around 1000 W / m2of power (one Sun equivalent) from the incident sunlight. Under normal operating conditions, for example at the maximum power point (MPP), that power is partially extracted from the modules as electrical energy. PV module efficiencies 77^ are typically on the order of 15% to 25%. For the following example, a 20% efficient module is assumed, meaning that 20% of the power being absorbed from sunlight will be extracted and 80% converted to heat. By contrast, when modules are operated at or near OC conditions, then all absorbed sunlight energy is converted to heat. As a first order approximation, it is assumed that the temperature increase in modules above ambient is proportional to the power dissipated as heat in the modules. That power is given as the absorbed power Pabs (typically around 1000 W / m2) minus the extracted power (efficiency of the module multiplied by Pabs). At MPP, the power dissipated is thus given as (l-T]eff)*Pabs.

[0201]

[0184] The increase in module temperature above ambient resulting from the sunlight absorption depends on many factors, including the actual solar irradiance, which varies by location and time of year, optical properties of the ground, and also weather conditions (such as windspeed). Silicon PV modules operate about 30 degrees Celsius above ambient under typical operating conditions, i.e., at or near MPP conditions. To estimate the temperature increase above ambient at OC conditions, the relative increase in power that is dissipated is considered. In the example of a 20% efficiency module, the actual power dissipated at OC will be l / (l-r)eff), i.e. 1.25 times higher. The temperature increase above ambient at OC is therefore 1.25 times the temperature increase at MPP, which equates to 37.5 degrees C instead of 30 degrees C in the above example. The extra temperature increase from about one Sun equivalent power of the module is thus estimated as 7.5°C.

[0202]

[0185] Balancing currents flowing into a module or into a string of modules cause extra heating. The power that is dissipated in the modules is extracted from the higher performance modules driving these currents. These balancing currents flow at zero or close to zero system power, i.e. at an operating voltage of the modules that is between the maximum power voltage and the open circuit voltage. As a first approximation, the power dissipated / extracted via balancing currents is proportional to the balancing currents. From the above analysis, it is seen that the extraction of the full maximum power current at the MPP voltage causes an estimated 7.5 °C temperature difference. This temperature difference may be referred to as the maximum power temperature variation ATMPP. Temperature variations resulting from balancing currents

[0203] ATpbaiance can be scaled against that:

[0204]

[0186] In other words, the temperature increase (or decrease) is proportional to the relative magnitude of the balancing current compared to the maximum power current. More sophisticated and more accurate models can be developed, for example taking into account the actual operating voltages rather than assuming that they match the MPP voltage.

[0205]

[0187] As an example, the MPP current in a module may be 10A. The balancing current flowing into a module under a specific scenario may be 3A. The heating from this extra current may cause an estimated additional temperature increase of 7.5 °C multiplied by 0.3 (3A / 10A), i.e. 2.25 °C. Eq. 3 can be rearranged to:

[0206]

[0188] Eq. 4 enables estimating the balancing current in a particular string balance) from a measured temperature difference Tj balance- It is worth noting that the above analysis is valid for both strings that feed current in and strings that receive current. The former operate cooler than they otherwise would, while the latter operate at higher temperature. That raises the question of what reference temperature the temperature difference AT j,aianceis to be measured against. To first approximation, a section of a solar farm connected to one inverter runs at the same average temperature as it would in the absence of balancing currents, since the power dissipated in some strings is extracted from others, ignoring Joule heat dissipated in wires and other resistive losses. The average temperature of all modules within one inverter section can therefore be used as the reference for the calculation of the balancing currents. In that case the temperature difference Tj balance inEq. 3 and in Eq. 4 is given as the temperature difference between modules in a specific string and that average temperature:

[0207] ^1, balance=Tn~ Tav(5) where Tnis the measured temperature of the string for which the balancing current is to be estimated and Tavis the average temperature across the solar farm section. It is worth noting that absolute temperature measurements, for example using thermal imaging systems, can be challenging due to the calibrations involved. The above analysis only uses temperature differences to be determined accurately, which means that an absolute temperature error, caused for example by an offset in the measurement system, has no impact on the accuracy of the results.

[0208]

[0189] Finally, balancing string currents can also be estimated from thermal images, as described above, and then scaled against measured currents in a few locations. For example, the above temperature -based analysis may predict currents of -2A, -6A, and +8A in three particular strings within a solar farm section. An actual measurement with a current clamp may provide - 1.8A for the first string. All other predicted currents would then be scaled accordingly, to -5.4A and +7.2A respectively.

[0209] Results

[0210] Circuit simulation

[0211]

[0190] To identify and confirm the root cause for the DPL intensity variations seen in Fig. 1 and Fig. 2, a solar farm was simulated containing 200 parallel strings, each string containing 27 series connected modules. Simulations were performed in the simulation program LT spice version 17.1.15 (https: / / www.analog.com / en / resources / design-tools-and-calculators / ltspice- simulator.html). Each PV module was configured as a 72 PV cell module with three bypass diodes, noting that the bypass diodes do not play any role in the explanation of the effects discussed in this section of the disclosure. The relevant cell parameters in the Spice simulation are the short-circuit current Isc(set to 10A in the base model), the emitter saturation current loi and the series resistance Rs of the individual cells. The value of loi determines the open circuit voltage Voc and was set to loi = IO-11A for what will be referred to below as normal cells and modules, resulting in an open circuit voltage per cell of Voc= 653 mV.

[0212]

[0191] For the simplest model, in which all cells and modules across the simulated solar system have the same properties, all cells have the same diode voltage and therefore will emit the same luminescence intensity.

[0213]

[0192] In the second step, a binary distribution of module quality (i.e., normal performing PV modules and underperforming PV modules) was included in the model. The system was simulated to contain variable numbers of what are referred to below as underperforming modules, containing cells with loi = 2xl0-11A, i.e. an loi value two times higher compared to normal cells. The two times higher loi results in 18 mV lower open circuit voltage per cell, 1.3 V lower module voltage (assuming that all cells in “underperforming” modules are identical) and 35.0 V lower string voltage (if all 27 modules in a string are “underperforming” modules). In the first set of simulations, the series resistance was set to zero (Rs= 0). The impact of series resistance will be discussed further below.

[0214]

[0193] The results of this simulation are shown in Fig. 7. In particular, Fig. 7 shows simulated currents in a solar farm containing 200 parallel strings of 27 series-connected modules, including normal (solid lines) and underperforming (dashed lines) strings, as a function of the power being extracted from the system. Numbers in the figure legend represent the number of normal and underperforming strings, respectively. The lower portion (e.g., below approximately 8A) of the graph represents voltages above the MPP.

[0215]

[0194] The simulated current flowing in normal and underperforming strings, respectively, is shown in Fig. 7 as a function of the total power that is extracted from the system. Solid lines represent the current in the normal strings, dashed lines the current in underperforming strings. Three scenarios were modelled, one with only one underperforming string (and 199 normal strings), one with 66 underperforming strings (134 normal strings) and one with 100 normal and 100 underperforming strings. The SC, OC and MPP labels in Fig. 7 indicate the operating point of the modules.

[0216]

[0195] Of interest here is the lower portion of the graph, which shows the performance of the strings at operating voltages above the MPP, i.e. at or near open circuit conditions. A large current of 10A is predicted in the underperforming string (dashed line) when the system is at open circuit, i.e. with no current being extracted. The 10A flowing into the underperforming string at zero external current extraction is delivered by 0.05A flowing from each of the 199 normal strings (solid line).

[0217]

[0196] The fact that the current flowing into the underperforming string (10A) is predicted to be identical to the short circuit current of the cells is not a coincidence. The saturation current loi in the underperforming cells is modelled as twice that of the normal cells. To reach the same voltage as the normal modules, the one-Sun equivalent photogeneration may therefore be complemented by one-Sun equivalent current driven into these modules.

[0218]

[0197] The 200: 1 ratio of currents reported above matches the ratio of the numbers of underperforming to normal strings. The same match is observed for other ratios of the numbers of normal to underperforming strings. When the ratio is 1: 1, i.e. with 100 strings of each type as shown in Fig. 7, the current from the normal strings (3.3OA, solid line) is matched by the opposite current (-3.3OA, dashed line) flowing into the underperforming strings.

[0219]

[0198] The balancing currents simulated above, and shown in Fig. 7, are a direct result of all strings in the simulated solar farm being connected in parallel (to the same inverter), with constant voltage across all strings at all operating points. Since the underperforming strings generate a lower open-circuit voltage (~35V lower) compared to normal strings, balancing currents therefore flow from the normal strings into the underperforming strings to satisfy the constant string voltage condition.

[0220]

[0199] Referring back to Fig. 1, several complete strings of modules with reduced DPL intensity can be identified in the lower left comer, as was discussed earlier in the disclosure, noting that this DPL image closely reflects the PL distribution under OC conditions. The lower DPL intensity observed from these modules in the experimental data suggests the presence of several strings containing only or primarily underperforming modules with lower open circuit voltage.

[0221]

[0200] However, as discussed above, balancing currents between strings result in constant string voltages and therefore constant module and cell voltages across the entire system. Again, referring to the expected exponential relationship between cell voltage and luminescence intensity (Eq. 1), one may therefore expect a uniform PL intensity distribution even in the presence of strong variations in module quality between strings. This is indeed what is predicted by the initial Spice model results shown in Fig. 7, but is clearly inconsistent with the experimental observations. The answer to this apparent discrepancy is associated with the series resistance Rs of the individual cells, which was set to zero in the first set of simulations, shown in Fig. 7 and discussed above. It is noted that any contributions to the series resistance from the system wiring may be negligible in comparison to the contributions from the cells.

[0222]

[0201] It is noted, in this context, that the luminescence intensity from solar cells is governed by the diode voltage Vdrather than the cell’s terminal voltage Vterm, which is the sum of the diode voltage and the voltage drop over the cell’s series resistance VRs-

[0223] Vterm = Vd+ VRs(6)

[0224]

[0202] The constant string voltage resulting from balancing currents, while consistent with constant module and cell terminal voltages, is associated with significant variations in diode voltages, since the currents in the normal and underperforming strings, respectively, flow in opposite directions. Fig. 8 shows simulations for the symmetrical case, i.e. with 100 normal and 100 underperforming strings, for Rs= 0 and for the more realistic case Rs= 0.0025 Q.

[0225]

[0203] In both cases the positive current from the normal strings at OC matches the negative current into the underperforming strings. The current is lower for the non-zero series resistance case, which is a result of the voltage drops across series resistances. The impact of the series resistances on a cell’s diode voltages is shown in Fig. 9, which contains the IV curves of normal (solid lines) and underperforming modules (dashed lines) with and without series resistance, as indicated in Fig. 9. In both scenarios the modules operate at the same terminal voltage. For Rs= 0 that operating point is highlighted in Fig. 9 by the vertical solid arrow 901. The terminal voltage is equivalent to the sum of the diode voltages in this case, corresponding to an equivalent PL signal between both PV modules.

[0226]

[0204] By contrast, for non-zero Rs, the operating point (defined by identical terminal voltage and opposite currents in the symmetrical case of 100 normal modules and 100 underperforming modules) is highlighted by the vertical dashed arrow. The equivalent diode voltages are found from the small horizontal dashed arrows. The diode voltage is higher than the terminal voltage (equivalent to higher PL signal) for the normal module and lower than the terminal voltage (equivalent to lower PL signal) for the underperforming modules. Note that the length of the vertical arrows in Fig. 9 matches the simulated currents flowing at OC shown in Fig. 8 (3.4A for Rs= 0, 1.9 A for Rs= 0.0025 Q). These variations in diode voltage, a result of the series resistance of the cells, are the underlying mechanism causing DPL intensity variations. The DPL intensity variations are thus ultimately caused by variations in module quality (in particular OC voltage), causing the balancing currents in the first place, in conjunction with voltage drops over cell's series resistances.

[0227]

[0205] Given the presence of balancing currents and of the impact of series resistance on the intensity variations in DPL images, as discussed above, the following qualitative conclusions can be made in relation to the four unexpected luminescence intensity variations noted above:

[0228] 1. The approximately two times lower DPL intensity that is observed from specific modules (white arrows in Fig. 1) reflects a voltage variation of about 18 mV per cell between these modules, consistent with the common interpretation of luminescence intensity variations. Balancing currents do not affect the interpretation of DPL intensity ratios from voltage variations between modules within the same string;

[0229] 2. Modules exhibiting the brightest luminescence, located on the left-hand side of the string border (striped arrows in Fig. 1), are embedded in strings that are dominated by underperforming modules. These bright modules in fact have comparable performance to the surrounding normal modules. The higher luminescence intensity is caused by balancing currents driving the relevant strings into forward bias causing higher luminescence emission;

[0230] 3. The underperforming strings containing only -or primarily- underperforming modules appear with lower DPL intensity as a result of voltage losses across the series resistances of the embedded cells, whereas the module- and cell-terminal voltages match for strings containing normal or underperforming modules, respectively; and

[0231] 4. The intensity difference between underperforming modules located on opposite sides of the string boundary (modules labelled “1” and “2” in Fig. 2) is explained by the fact that the specific reductions in DPL intensity are due to different mechanisms. Although the modules are of the same type and have comparable performance: a. The module labelled “2” is an underperforming module within a string containing primarily normal modules, so the intensity variation compared to normal strings reflects the difference in cell Vocbetween modules b. The module labelled “1” is an underperforming module within a string that contains only underperforming modules. The reduction of DPL intensity in this case is a series resistance effect, which depends on the value of Rs and on the difference in module Voc.

[0232] Analytical model

[0233]

[0206] In this section, an analytical model is derived that can be used to untangle the complicated interplay between variations in module quality, balancing currents and series resistance effects. In the derivation of this analytical model, it is assumed that all 72 cells in a given module are identical and characterised by a diode voltage Vd. The module voltage is thus given as 72 times the diode voltage. It is also assumed that all cells in all modules have the same series resistance Rs. Since all cells in a module are connected in series and all modules in a string are connected in series, the same current flows through all cells in a particular module string.

[0234] The string voltage in the nthstring VS nis given as the sum of the cell terminal voltages: the overall system voltage and Va.m.u is the diode voltage of cells in module m and in string n, nceu is the number of cells per module (here 72), nmodis the number of modules per string (here 27), Rsis the lumped series resistance per cell and Inthe current in the PV string. It is assumed, for simplicity, that all cells in one module have the same diode voltage, noting that the diode voltages Va,m,n are the diode voltages of cells embedded in the modules, as impacted by the balancing currents. The diode voltages of cells and the sum of diode voltages in each string can be obtained from the DPL image intensity <pPLitself using Eq. 1. Since the array is externally in open circuit, the sum of all currents is zero: where nstring is the number of strings connected in parallel to the inverter. Rearranging Eq. 7 provides:

[0207] As such, in some embodiments, processor 351 may determine the current in PV string 320 at least partially using Eq. 9. The system voltage is given as the mean value of the sums of diode voltages across all cells connected to the inverter:

[0235]

[0208] Using the system voltage Vs as calculated from Eq. 10, the current in each string Incan be calculated from Eq. 9.

[0236]

[0209] As seen above, the conversion of a PL signal into absolute diode voltage using Eq. 1 uses the proportionality constant C1. The choice of that constant, while relevant to getting accurate values for individual voltages, does not affect the calculation of the string currents via Eq. 9. An inaccurate choice of causes an offset in all calculated implied voltages, affecting both the system voltage Vs and the individual cell voltages Vd m n, so that the offset drops out in the numerator of Eq. 9.

[0237]

[0210] In practice, the system voltage can also be obtained from the DC input into the inverter or can be measured by other means. In that case the accurate conversion of PL signals into cell and module diode voltages matters, which however has the advantage that currents can then be obtained from the PL signals from all modules within just one string, not using PL intensity data from the entire solar farm section connected to the inverter. The relevant calibration constant may then be determined by measuring the actual string currents in a few selected strings and adjusting Crto match the measured current for those strings.

[0238]

[0211] From a string current In, the impact on the luminescence intensity of the modules embedded in that string can be estimated. A very good first order approximation is based on the ratio of the string current to the cell’s short circuit current at the prevailing illumination conditions during DPL testing (i.e. not the nominal cell short circuit current). The PL intensity, at first order approximation, increases / decreases linearly with the current being injected / extracted. The corrected PL signal (ppi.corr for all modules in string number n is given by Eq. 2.

[0239]

[0212] For example, assuming a cell short circuit current of Isc= 10A and assuming that the analysis above yields a positive string current of 2A (i.e. current flowing in) for a particular string, then the luminescence emission from cells within that string will be enhanced by 20%.

[0240] The corrected PL signal is given as the measured PL signal divided by 1.2. On the other hand, if the current analysis yields a negative current of -3A (i.e. current being extracted from the string), then the luminescence signal will be only 70% of the signal that would be expected without current extraction. The corrected luminescence signal in this case is given as the measured signal divided by 0.7. Experimental verification - PPL data

[0241]

[0213] The above analytical model, to be accurate, may utilise DPL image information from all modules connected to a specific inverter section if the system voltage Vs is inferred from the DPL data. The image shown in Fig. 1 shows only a partial view of the solar farm section connected to the inverter being manipulated. Additional DPL images, not shown here, show that the section of this solar farm connected to the inverter being switched contains approximately two thirds normal strings and one third underperforming strings, plus a small number of mixed strings containing modules of both types. This approximate 2:1 ratio of normal to underperforming strings matches the current measurements discussed below.

[0242]

[0214] The DPL image shown in Fig. 1 contains normal, underperforming and mixed strings, with unusual DPL intensity variations observed in mixed strings near the string boundary as discussed above. The DPL image was corrected based on the analytical model discussed in the previous section. The as-measured and corrected DPL images are shown in Fig. 10a and Fig. 10b respectively, using the same colour scale for the measured / corrected DPL count rates. More specifically, Fig. 10a shows a DPL image of a solar farm section containing normal, underperforming, and mixed strings as measured, while 10b shows the DPL image of that solar farm section after correction for balancing currents. Both Fig. 10a and 10b are shown on the same colour scale, representing the measured / corrected DPL count rate.

[0243]

[0215] The unusual patterns resulting from balancing currents, such as the relatively bright appearance of normal modules embedded in underperforming strings, have disappeared in the corrected image, showing that the analytical correction works well. As expected, the DPL intensity contrast between normal and underperforming modules is enhanced by correcting for balancing currents, i.e. underperforming modules appear darker and normal modules brighter in the corrected image of Fig. 10b. The DPL intensity ratio between the normal and underperforming modules, calculated by averaging over 20 images in each group, is 1.47 in the as-measured image and 1.98 in the current-corrected DPL image, corresponding to voltage differences per cell of 10.0 mV and 17.6mV respectively. The correction thus has a significant impact on the implied voltage analysis.

[0244]

[0216] Two modules, one normal module and one underperforming module, were removed from the system and underwent further testing under controlled laboratory conditions at the University of New South Wales (UNSW). IV testing of these modules provided an open circuit voltage difference per cell of 19.9mV. The corrected DPL analysis (predicting 17.6mV) thus provides implied voltage differences that are very representative of laboratory test data and much closer to the actual value than the data obtained from the as-measured image (10.0 mV). The remaining observed discrepancies are assigned to DPL image artefacts that reduce the overall image contrast, which is subject to ongoing investigations.

[0245]

[0217] The disclosed analytical DPL-based model uses the implied voltages from the DPL image itself to predict string voltages and resulting balancing currents. In this example, the model predicts currents from the normal strings of 1.62A and currents flowing into underperforming strings of 3.24A, with slightly different values for the mixed strings. These predicted currents, as will be shown in the following section, match measured currents exceptionally well. The magnitude of the currents in the analytical model depends on the choice of Rs, and it is expected that reasonably accurate estimates about suitable values can be used generically for the few different types of PV cells that can be expected to be mainstream in high volume production and for large scale deployment.

[0246] Experimental verification - current measurements

[0247]

[0218] The presence of balancing currents, predicted by the DPL images and by the simulations discussed herein, was verified experimentally by actively controlling the inverter power output from zero (solar farm section at OC conditions) to maximum power (here -2.52 MW) in lOOkW steps. The current in two adjacent modules / strings was measured at each power setting using a current clamp meter. The two modules on which current measurements were performed were embedded in module strings containing only normal modules and primarily under-performing modules respectively, highlighted in Fig. 2 with white arrows.

[0248]

[0219] Fig. 11 shows measured (symbols) and simulated (solid lines) current in a normal string and in an underperforming string as a function of the power extracted from the system for a system containing 139 normal and 73 underperforming strings. Open symbols in Fig. 11 represent the measured current as a function of the power output from the system in the normal string and in the underperforming string, as indicated by the legend in Fig. 11. The measurements confirm the balancing currents predicted by the model. At external open circuit conditions 3.5 A flow into the underperforming strings, provided by 1.8A flowing from the normal strings.

[0249]

[0220] The solid lines in Fig. 11 represent simulated data using the Spice simulation using Rs = 0.0018 Q and Isc= 10.5A. The ratio of normal strings and underperforming strings was chosen to match the current ratio measured at zero power output. The ratio of loi between the two cell types (normal and underperforming) was chosen to be two times, based on the corrected DPL image data shown in Fig. 10b. The DPL image has thus informed the choice of parameters in the Spice model, resulting in outstanding agreement between simulated and measured balancing currents. Experimental verification - thermal images

[0250]

[0221] Further confirmation for the presence of balancing currents was obtained from thermal images, which were acquired on site by a professional drone operator. Fig. 12 shows a thermal image of the solar farm section shown in Fig. 1 and Fig. 2 under open circuit conditions, after the farm had been switched to OC conditions approximately ten minutes earlier. Balancing currents between parallel strings cause higher temperature in the four strings containing primarily underperforming modules.

[0251]

[0222] Specular sunlight reflection causes an image artefact on the right-hand side of the image. A tripod used for ground-based DPL image acquisition at the time, and its shadow cast on the modules, are also visible near the centre of the thermal image. Moreover, four underperforming strings identified from the DPL images shown in Fig. 1, Fig. 2, Fig. 10a and Fig. 10b, respectively stand out in the thermal image, exhibiting higher temperature, resulting from the power dumped in these strings by the 3A balancing currents.

[0252] Discussion of results

[0253]

[0223] The presence of significant voltage mismatch, as determined from the DPL image in Fig. 1, is undesirable for various reasons, including the potential for damage and the incorrect interpretation of DPL images. Balancing currents between strings may flow continuously for extended periods of time, particularly in Australian solar farms which are frequently turned off during curtailment or times of negative electricity pricing. During these times balancing currents of several Amperes, first predicted here from DPL data and then confirmed experimentally by current measurements, lead to additional heating of underperforming strings by several degrees, which in turn can lead to excessive degradation, possibly creating a positive feedback loop. In addition, the presence of substantial balancing currents reduces the resilience of the system to other system problems. For example, the balancing currents may be additive to currents that flow into strings containing short-circuited bypass diodes, resulting in an increased likelihood of blowing string fuses.

[0254]

[0224] A practical solution to avoid balancing currents between strings resulting from string voltage mismatch, as discussed above, and the associated negative side effects, is the addition of blocking diodes to each string. This would not only render the PV system more resilient, but would also enable additional analytical DPL capabilities, which will be discussed elsewhere.

[0255]

[0225] The presence of significant balancing currents reported here results from systematic module voltage variations between module strings in a solar farm. An explanation for why the performance of modules should be systematically matched to the layout of the solar farm is also provided, i.e. why the number of underperforming modules would match the location of specific strings.

[0256]

[0226] It turns out that in this particular solar farm the number of modules per string (27) matches the number of modules on pallets delivered to the farm during construction. The farm was constructed one string at a time, with one pallet used per string. The mixed strings that were observed in some sections of the farm are likely a result of that systematic construction pattern getting out of sync occasionally. It is noted though, that all modules in this solar farm are from the same manufacturer, of the same type, from the same product series and with identical nameplate performance specifications, i.e., they should, in principle have very similar performance and hence luminescence emission.

[0257]

[0227] It is also worth noting that balancing currents, as discussed in this disclosure, can not only result from module voltage differences associated with quality variations of the solar cells. Other module faults, such as open circuited module sub-strings or shorted bypass diodes, which can significantly reduce the voltage of individual modules, would cause similar effects. The above analysis applies to these scenarios in a similar way.

[0258] Electroluminescence

[0259]

[0228] As previously discussed, luminescence can also be generated from PV cells and modules by electrical excitation or a combination of electrical and photo-excitation, enabling for example the capture of nighttime or daytime electroluminescence images (NEL or DEL images, respectively). Electroluminescence (EL) is typically generated from a PV device by applying a forward bias to, or injecting current into, the PV device (i.e., a PV cell, PV module etc). In a PV array, this may be performed by connecting one or more PV strings to a power source (power supply), which may involve disconnecting the one or more PV strings from the inverter (e.g., the inverter 340). In some examples, as will be discussed below, the inverter 340 may itself be a source of power. In some cases, EL imaging may be more advantageous than PL imaging. For example, EL imaging may be performed at nighttime, which reduces the ambient light captured in the EL image and may be performed when the PV array 310 is not in use (i.e., not generating power).

[0260]

[0229] The current- voltage (IV) curves in Fig. 13 represent a NEL scenario. More specifically, Fig. 13 illustrates dark current voltage characteristics of two different PV strings, with the curve 1110 representing a normal PV string and the curve 1120 representing an underperforming string. Higher (more negative) current flows in the underperforming PV string at the same system voltage.

[0230] To a good first order approximation, the electroluminescence intensity (pELfollows a linear relationship with the injected current 7, i.e.

[0261] VEL=17 (11) where C11is a proportionality constant. In other words, the electroluminescence intensity is directly proportional to the injected current to a first order. The electroluminescence intensity may be represented differently in more complicated scenarios, but for simplicity, it may be assumed that emitted EL intensity is proportional to the injected forward current.

[0262]

[0231] Fig. 14 illustrates an example of an electrical layout 1400 of a section of a utility PV array. Specifically, Fig. 14 shows 24 parallel PV strings 1402 (denoted as SI to S24, which may also be referred to as system strings), which are connected inside the same combiner box 1404, represented by a dashed rectangle. The combiner box 1404 comprises several 50A fuses (such as the fuse 1410), where each 50A fuse is connected to three PV strings 1402. Each PV string 1402 is connected to a 50A fuse via a string fuse (such as fuse 1408). Each PV string 1402 in this example contains 27 PV modules (denoted by label 1406). In another example, several of these combiner boxes 1404 may be connected in parallel to the same inverter, as can be seen in Fig. 15 which shows an aerial photo of a PV array section. The white arrows point to the location of several combiner boxes. Each combiner box of the PV array in Fig. 15 is connected to 24 series connected strings. In the example of Fig. 14, each individual string 1402 is protected by a 20A inline fuse (such as fuse 1408), which may be integrated into the cabling and may be difficult to access. In this example, three parallel strings 1402 are connected to each 50A fuse (such as the fuse 1410), which is located inside the combiner box 1404 and readily accessible. It is noted that other PV arrays may have different configurations to that of Fig. 14 and the electrical layout of Fig. 14 is only one example of a PV array 310.

[0263]

[0232] In one electroluminescence scenario, either NEL or DEL, the same current may be injected into each PV string individually. This may be achieved by connecting a constant current source to each PV string, for example. However, this would involve disconnecting that string from the system inverter. If multiple current sources are used, then each current source would have to be equivalent. This can be done but is often impractical and inefficient, especially if an entire PV array comprising many thousands PV strings is to be scanned.

[0264]

[0233] In another electroluminescence scenario, it may be conceivable, and more practicable (e.g., it may be faster and use less manual labour), for one power supply, such as a constant current source, to be simultaneously connected to several parallel PV strings rather than to each PV string individually. However, this may be difficult for a PV array comprising many parallel PV strings. For example, if a PV array contained 200 parallel PV strings and if each of these approximately 200 PV strings are electrically connected in parallel, this would require both a very larger power supply and a very large generator on site at the PV array.

[0265]

[0234] Practically, to connect all the PV strings to the same power source, a power supply may be connected to the input of a combiner box, or alternatively at the location of the inverter 340 to all parallel combiner boxes feeding into a specific inverter. Powering up a constant current source may then send current through all parallel PV strings connected to the power source. In the scenario where the power source is connected at the inverter input, this would mean that all PV strings are powered up simultaneously, which would require a very large power supply and generator.

[0266]

[0235] To address this problem of needing a very large power supply and generator, the majority of parallel PV strings may be de-activated by electrically disconnecting them, reducing the power requirement when the power source is connected at the input of the inverter 340. For the example of the configuration shown in Fig. 14, electrically disconnecting PV strings may be performed by one or more of the following means:

[0267] 1. Via the main isolator switch at a combiner box, which disconnects all strings connected in the specific combiner box. Only one combiner box could be left activated. In this scenario, a large power source may still be needed (approximately 100-350 kW);

[0268] 2. Via the 50A fuse that combines several strings (three in the example shown in Fig. 14 and Fig. 16 as discussed below). All 50A fuses in an inverter section may be deactivated, and only one at a time reactivated, in sync with the drone flight path to capture an electroluminescence image, for example. Since only three strings would be activated at any time, a comparatively small power supply may be needed (approximately 15-45 kW);

[0269] 3. Via the 20A fuses in series with each PV string, or at any point in a PV string via the module’s MC-4 connectors. All strings could be deactivated, then one at a time activated. The power supply could be three times smaller compared to method 2, but this procedure would be very labour intensive.

[0270]

[0236] In a more general case, all PV strings may be connected directly into a combiner box and have two 20A fuses inside the combiner box, i.e. in this case, there may be no 50A fuses. Rather, there may be 48 x 10A fuses and hence, 24 PV strings may be combined. In some examples, the fuses may not be configured as inline fuses but may be located inside the respective combiner box. Hence, in some embodiments, the power requirement may be reduced by removing / inserting fuses that connect individual or pluralities of PV strings.

[0271]

[0237] Fig. 16 illustrates a schematic simplified representation of an inverter section comprising combiner boxes CB-1, CB-2 and CB-3, with multiple combiner boxes (CBs) feeding into one inverter. However, this is only one possible configuration and other configurations are equally possible. Each CB has an isolator switch (e.g., CB-3 comprises the isolator switch 1610). In this simplified example, each CB has two 50A fuses, with three parallel PV strings feeding into each fuse. Each PV string also has its own 20A inline fuse. To generate electroluminescence, a power supply may be connected either across all CBs, e.g. at the location of the inverter. Alternatively, a power supply may be connected to just one CB in this example, e.g. behind the isolator switch 1610. Isolator switches may be used to connect individual CBs. Within each CB in this example, the 50A fuses may be used to connect or disconnect individual triplets of strings.

[0272]

[0238] In practice, electrically disconnecting the PV strings enables activation of selected PV strings, thereby reducing the size requirement of the power supply. For example, if the individual 20A fuses are easily accessible, then this provides a means for selectively injecting a specified current into each PV string, by turning each PV string on sequentially, one at a time. However, the 20A fuses are often installed as inline fuses and are typically difficult to access in the field. By contrast, the 50A fuses, which connect to two or more parallel strings are often readily accessible inside the combiner box. As such, an operator can conveniently switch off all PV strings first, by deactivating each 50A fuse, then switch individual 50A fuses on. For electroluminescence, this enables consecutive scanning of the entire PV array by synchronising the switching of the fuses (and thereby the strings) with a drone flight path to enable scanning of the PV array. In principle, it may also be possible to selectively power up complete combiner box sections, using the main isolator switches. However, this would require a power supply that can power up all PV strings connected to the combiner box. Such a power supply would be very heavy and expensive and it is unlikely that this procedure would be cost effective. The power supply may also to be deactivated whenever fuses or switches are operated, in order to avoid arcing or to address other safety concerns.

[0273]

[0239] In summary, for electroluminescence, the individual switching of PV strings via the 20A inline fuses may enable constant current to be injected into each PV string using a constant current source. However, such a method may be awkward, time consuming and expensive in practice. Methods that involve powering up two or more parallel PV strings at the same time are likely to be much more efficient and practical.

[0274]

[0240] However, an issue arises that simultaneously powering up two or more parallel PV strings results in different currents in different strings. Therefore, because EL intensity is proportional to the current, according to Eq. 11, the different currents in different strings will cause EL intensity variations that are not necessarily indicative of module performance or quality. As such, an EL image of the two or more parallel PV strings may show different EL intensities for the different PV strings. Similar to embodiments of the PL-based method previously disclosed (i.e., the method 400), the variation in EL intensity value due to the current variations may be corrected before determining one or more characteristics of the PV array from an EL image. In other words, the present disclosure recognises that characterisation of PV arrays based on EL imaging techniques may be adjusted to account for current variations when simultaneously powering up two or more PV strings.

[0275]

[0241] In any scenario in which several strings are forward biased (i.e., undergo current injection) simultaneously, different currents will flow into each PV string. This may result in EL intensity variations between PV strings that are purely a result of current variations, rather than module quality. Such EL intensity variations distort quantitative EL data analysis. It is an intention of the present disclosure to describe a method to address this limitation, i.e. to obtain more accurate EL intensities, either experimentally or via correction methods, which are more closely related to the actual module quality. The following disclosure will discuss this in detail.

[0276] Method of electroluminescence

[0277]

[0242] Fig. 17 illustrates a method 1700, according to an embodiment of the present disclosure, for determining one or more characteristics of a PV array, the PV array comprising a plurality of PV strings electrically connected in parallel to each other, each PV string comprising a plurality of PV modules electrically connected in series to each other. It is noted that many aspects of the description above in relation to a PL image may apply equally to an EL image. For example, the image analysis and image processing may be equivalent for a PL image and an EL image. More specifically, adjusting the at least one PL intensity value in some embodiments of the method 400 may be similar or equivalent to adjusting the at least one EL intensity value in some embodiments of the method 1700.

[0278]

[0243] It is noted that Fig. 17 may be similar to the method 400 of Fig. 4, as will be described below. As such, some embodiments of the method 1700 may also be similar and / or equivalent to embodiments of the method 400, and vice versa. The system 300 of Fig. 3 may be similarly configured to perform the method 1700. In other words, the method may be carried out in relation to a PV array that is the same or similar to the PV array 310 depicted in Fig. 3, for example. As such, the method 1700 will be described with reference to the system 300. Similar to the description of the method 400, to aid in explanation of the disclosed method 1700, reference is made in subsequent discussions to “at least one of the PV strings” with reference to the PV string 320 of Fig. 3. Certain aspects of the method 400 may also be performed in conjunction with certain aspects of the method 1700, and vice versa.

[0279]

[0244] At 1701, the method 1700 includes determining at least one electroluminescence (EL) intensity value of one or more PV modules in at least one of the PV strings from a group of PV strings based on at least one EL image of the PV array captured during current injection into the group of PV strings, the group of PV strings comprising two or more of the plurality of PV strings.

[0280]

[0245] At 1702, the method 1700 includes determining at least one current value in the at least one PV string of the group of PV strings, the at least one current value being associated with current injection into the group of PV strings.

[0281]

[0246] At 1703, the method 1700 includes determining one or more characteristics of the PV array based on the at least one determined current value and / or the at least one determined EL intensity value.

[0282] Determining at least one EL value

[0283]

[0247] The processor 351 may be used in the step 1701 of determining at least one EL intensity value of one or more PV modules 321, 322, 323, 324 in at least one of the PV strings 320 from a group of PV strings 320, 330 based on at least one EL image of the PV array 310 captured during current injection into the group of PV strings 320, 330. The current injection may occur during the daytime or during the nighttime. The processor 351 may determine the at least one EL intensity value after current was injected into the group of PV strings 320, 330, or during the current injection. The group of PV strings 320, 330 comprises two or more of the plurality of PV strings (i.e., at least two PV strings). “Electroluminescence (EL) image” in the context of the present disclosure may refer to an image (or image data) comprising a luminescence component resulting from a PV module being operated under forward bias (e.g., current injection) condition, possibly in addition to ambient light and luminescence caused by solar radiation.

[0284] Electroluminescence relies on the similar principle as a light emitting diode (LED), in which current is fed into a PV cell and radiative recombination of charge carriers causes light emission. The at least one EL image may comprise pixels where each pixel corresponds to an EL intensity value.

[0285]

[0248] Similar to photoluminescence, the EL image contains at least one EL intensity value that is determined by the processor 351. However, the EL image may also contain at least one PL intensity value. More specifically, the EL image may capture both photoluminescence (as a result of the PV array 310 being illuminated by solar radiation) and electroluminescence (as a result of injecting current into the PV array 310). As such, “EL image” discussed in this disclosure may be referred to more generally as a luminescence image. Hence, the “EL intensity value” discussed in this disclosure may be referred to more generally as a luminescence intensity value. In particular, the processor 351 may not distinguish between a PL intensity value and an EL intensity value in the at least one EL image.

[0249] The group of PV strings 320, 330 may be a subset of the plurality of PV strings of PV array 310. The group of PV strings 320, 330 may comprise two PV strings. However, the group of PV strings may comprise more than two PV strings. The group of PV strings 320, 330 may also comprise each of the plurality of PV strings of PV array 310. It is noted that the PV array 310 depicted in Fig. 3 comprises only two PV strings for illustrative purposes. However, in other embodiments, the PV array 310 may comprise more than two PV strings. Hence, while the group of PV strings 320, 330 corresponds to both PV strings in the PV array 310 in Fig. 3, in other embodiments, the group of PV strings may be less than the total number of PV strings in a PV array 310. In essence, in this disclosure, “group of PV strings” may refer to the PV strings (i.e., a subset of the plurality of PV strings) of the PV array 310 that receive current during the current injection.

[0286]

[0250] At least one EL image may be captured of the PV array 310 during current injection into the group of PV strings 320, 330. “Current injection” and variations thereof, in the context of the present disclosure, refers to injecting current into at least part of the PV array 310. Current injection may also be referred to as powering at least part of the PV array 310, or providing current to at least part of the PV array 310, or flowing current into at least part of the PV array 310. As such, the system 300 may further comprise a power source 360 proximal to the inverter 340. One or more of the PV strings 320, 330 may be connected to the power source 360. The power source 360 may be any type of power supply, such as a connection from a mains power grid and may comprise a transformer or voltage regulator, such as a buck / boost converter. The power source 360 may also be, but is not limited to, a power centre, a diesel generator, a portable substation or a battery.

[0287]

[0251] In some examples, the inverter 340 itself may be a power source. In this scenario, the inverter 340 may drive DC current into one, several, or all of the PV strings that are connected to it (e.g. PV strings 320, 330 in Fig. 3). The selection of strings that are powered up may be selectable at the inverter 340 itself, depending on how the PV strings 320, 330 are wired up to it, or via the switching of combiner boxes and / or fuses as is described elsewhere in the present disclosure. However, this may still involve more than one PV string being powered up simultaneously, causing a current variation between the PV strings. The inverter-based current injection may enable the powering up of an entire inverter section and, therefore, the acquisition of an EL image of an entire inverter section. This procedure may be a significant improvement compared to powering up smaller inverter sections via power supplies and inverter since it removes the need for large additional equipment and is much less labour intensive.

[0288]

[0252] As discussed above, current injection may be achieved by de-activating (or activating) or disconnecting (or connecting), at least electrically, one or more parts of the PV array 310, such as the fuses and / or the combiner boxes, before (or during) current injection. As such, in some embodiments, the current injection into the group of PV strings is performed, at least partially, by: disconnecting one or more combiner boxes connected to the group of PV strings; and / or disconnecting one or more fuses connected to the group of PV strings. For example, each of the one or more combiner boxes may be deactivated (disconnected) initially and hence, current injection may be performed by activating (connecting) a selected combiner box (by activating the relevant isolator switch, for example). In another example, each of the one or more combiner boxes may be activated (connected) initially and hence, current injection may be performed by de-activating (disconnecting) a selected combiner box (by deactivating the relevant isolator switch, for example). In the example of Fig. 14, activating a combinator box 1404 enables current to flow into six PV strings, if each of the 50A fuses are also connected. Current injection may be performed based on a connection state of the PV array 310, which may correspond to the initial state of the PV array 310 before capturing at least one EL image. One or more parts of the PV array 310 may be selectivity de-activated (or activated) to capture an EL image. For example, the de-activation (or activation) may be synchronised to a drone flight path, such that the drone may capture one or more EL images of the PV array 310 according to the selective de-activation (or activation). The selective de-activation (or activation) may also be referred to as selective switching of the PV strings 320, 330. The processor 351 may selectively de-activate (disconnect) or activate (connect) one or more parts of the PV array, for example. Such de-activating (or activating) or disconnecting (or connecting) may also be performed for photoluminescence, in some examples. In this case, sections of the inverter section may be deactivated, which means that only smaller sections are being switched. This may be advantageous in relation to safety, or other practicalities.

[0289]

[0253] Similar to the case with PL imaging, the processor 351 may receive the at least one EL image of the PV array 310 directly from the camera 355 (i.e., the camera 355 may be configured to construct the EL image), or the processor may construct the EL image based on signals from the camera 355. Additionally or alternatively, the at least one EL image may be stored in the memory 352 and the processor 351 may retrieve the EL image from memory 352. Additionally or alternatively, the processor 351 may receive the at least one EL image from an external source, such as a remote server. Ambient light will generally not be a concern for nighttime EL imaging, but will need to be dealt with for daytime EL imaging. As with daylight PL imaging, single shot daylight EL images may be captured with a camera equipped with a suitable ultranarrow bandpass filter. The camera 355 may be mounted on a drone which is configured to capture an aerial view of the PV array 310.

[0254] Similar to the previously described case with PL imaging, the processor 351 may also determine the at least one EL image using an image difference. In an image difference technique for electroluminescence (particularly daytime electroluminescence), the images in the image difference may be captured at any two different operating conditions of the PV array 310. For example, the two different operating conditions of the PV array 310 may be forward bias (e.g., during current injection) and MPP. In another example, the two different operating conditions may be forward bias and OC, two different forward bias points, or the like. In essence, the further away the two operating conditions are (i.e., the larger the voltage and current difference), the larger the signal that can be discriminated from ambient light. In that sense, a technique in which one point is MPP (i.e., a negative current) and one point is forward bias (i.e., a positive current) may be advantageous. Practical considerations may also affect the choice of the two operating conditions. For example, it may be a consideration as to what switching can be implemented in practice.

[0290] Determining at least one current value in the at least one PV string

[0291]

[0255] The processor 351 may be used in the step 1702 of determining at least one current value in the at least one PV string 320. The at least one current value may be associated with current injection into the group of PV strings 320, 330. For example, the at least one current value may correspond to current variations resulting from simultaneous current injection into the group of PV strings 320, 330. As such, each PV string in the group of PV strings 320, 330 may have a different current value, as a result of the current variation. In some embodiments, the processor 351 may determine 1702 the at least one current value when current is being injected into the group of PV strings 320, 330. The processor 351 may determine 1702 the at least one current value after current is injected into the group of PV strings 320, 330.

[0292]

[0256] Similar to the embodiments of the method 400, in some embodiments of method 1700, the at least one determined current value of the at least one PV string 320 is determined at least partially based on the at least one determined EL intensity value of the one or more PV modules 321, 322, 323, 324. In some embodiments, the at least one determined current value of the at least one PV string 320 is determined at least partially based on a sum of cell diode voltages in the at least one PV string 320 calculated from the at least one determined EL intensity value of the one or more PV modules 321, 322, 323, 324 of the at least one PV string 320. In some embodiments, the cell diode voltages (Vd) are determined at least partially from the at least one EL intensity value (<p£L), and based, at least partially, on the following generalised Planck equation (12), where kT / q is a thermal voltage and C12is a calibration constant:

[0293] (PEL=Ci2e^kT' (12).

[0257] As discussed above, the current variations may be inferred from the electroluminescence intensity distribution itself, similar to the embodiments of the method 400. Similar to photoluminescence, in electroluminescence the system voltage, i.e. the voltage that is supplied to the connected parallel strings, may be given by Eq. 7.

[0294]

[0258] Similar to the embodiments of the method 400, Eq. 9 enables the calculation of the current in PV string n using the cell diode voltages of the PV cells embedded in that PV string, the series resistance Rsof the cells and the system voltage. The cell diode voltages Vd m nmay be inferred for each PV cell from the measured luminescence intensity using Eq. 12, which may be rearranged to give: kT where Vocanbe calculated as 70= — — * Zn(C12). This analysis, therefore, has three generally unknown parameters, Rs, Voand l^. In some cases, the system voltage 1 may be known or measured at the source (e.g., power supply or system inverter). The total current Itotaiinto all PV strings may also be measured at the source. The currents into all individual parallel strings add up to the total system current:

[0295]

[0259] If one of the two remaining parameters is either known, or can be reasonably estimated, then the other can be determined via Eq. 7, since only one value may fulfill this condition. It is also possible to measure the current flowing into two or more strings having different string currents, e.g., using current clamp meters during one specific measurement, Rs, 70which determines the unknown parameters, which can then be used, assuming they are constant across the PV array 310.

[0296]

[0260] Similar to the embodiments of the method 400, in some embodiments the at least one determined current value in the at least one PV string 320 is determined at least partially from a series resistance of at least one PV cell in the one or more PV modules 321, 322, 323, 324 in one of the group of PV strings 320. As per Eq. 7 discussed above, the overall system voltage may be affected by the string current, the cell diode voltages in the string and the series resistance. As such, the string current and the series resistance may be related through Eq. 7. More specifically, the series resistance may be inversely proportional to the string current according to Eq. 9. In some examples, it may be assumed that the series resistances for each PV cell in each PV module 321, 322, 323, 324 of the at least one PV string 320 are similar or equivalent.

[0261] In some embodiments, processor 351 may determine the series resistance by determining at least one EL intensity value of one or more PV modules 321, 322, 323, 324 in the one of the group of PV strings 320 at each of two current injection conditions. The series resistance may be determined based on a difference between the two current injection conditions. Assuming that each PV cell in PV array 310 has a similar or equivalent series resistance, any one of the group of PV strings (i.e., the PV strings into which current is injected) may be used to determine the series resistance. In this embodiment, the current into one of the groups of PV strings may be measured at two different injection conditions (e.g., injecting currents of 4A and 8A), noting that any two different current injection conditions may be used. In this embodiment, the series resistance may be determined based on a change in cell diode voltages between the two different current injection conditions. The series resistance may also be determined based on a change in an EL intensity value. For example, in the case of the higher current flow, the sum of cell diode voltages may increase and so may the voltage drop at Rs(due to the higher current). If the system voltage is known, the increase in diode voltages can be calculated from the resulting EL intensity value increase via Eq. 9. The series resistance may be calculated from the difference in 14,', the sum of the diode voltages and the difference in current (4 A in this example) from Eq. 14.

[0297]

[0262] Similar to the embodiments of the method 400, in some embodiments, the processor 351 may determine the series resistance based on a measurement of a voltage of the one or more PV modules 321, 322, 323, 324 in the one of the groups of PV strings via one or more y- connectors. Similar to the embodiments of the method 400, in some embodiments processor 351 may determine the series resistance based on a measurement of a voltage of a PV module similar to and / or associated with one or more PV modules in one of the plurality of PV strings, e.g. an O&M spare. This may be done using multiple EL intensity values, for example.

[0298] Determinins the one or more characteristics of the PV array

[0299]

[0263] The processor 351 may be used in the step 1703 of determining the one or more characteristics of the PV array 310 based on the at least one determined current value of the PV string 320 and / or the at least one EL intensity value. For example, the processor 351 may determine the one or more characteristics of the PV array 310 by applying an algorithm, mathematical operation or machine learning model to the at least one determined current value of the PV string 320 and / or the at least one EL intensity value. As such, the processor 351 may determine a numerical value which may be indicative of one or more characteristics of PV array 310. The numerical value may be a performance indicator of the PV array 310 and / or of one or more of the PV strings 320, 330, and / or of one or more of the PV modules 321, 322, 323, 324, 331, 332, 333, 334. The one or more characteristics of the PV array 310 may be similar or equivalent to the one or more characteristics determined by the method 400. For example, one or more characteristics of the PV array 310 may be one or more of: an open circuit voltage; an operational voltage; an implied voltage; module performance; module quality; and a corrected EL image.

[0300]

[0264] The method of the embodiment according to Fig. 17 may provide a blueprint for a software program according to the present disclosure and may be implemented step-by-step, such that each step in Fig. 17 is represented by a function in a programming language, such as, but not limited to, Python, C++, Lab VIEW or Java. The resulting source code may then be compiled and stored as computer-executable instructions on the non-volatile memory 353, which causes the processor 351 (or multiple processors or a distributed computing architecture) to perform the method 1700.

[0301] Adjusting the at least one determined EL intensity value

[0302]

[0265] Similar to the embodiments of the method 400, the originally determined EL intensity value may be adjusted to compensate for current variations between the PV strings caused by current injection. The adjusted or corrected EL intensity value can then be used to determine more accurate characteristics of the PV array 310. Hence, in some embodiments, the processor 351 may adjust the at least one determined EL intensity value of the one or more PV modules 321, 322, 323, 324 in the PV string 320 based on the at least one determined current value of PV string 320. Adjusting the at least one determined EL intensity value of the one or more PV modules 321, 322, 323, 324 in the at least one PV string 320 based on the at least one determined current value may reduce or remove an effect of current variations between the group of PV strings. The processor 351 may adjust the at least one determined EL intensity value by adjusting the pixel value of the corresponding PV modules in the at least one EL image.

[0303]

[0266] In some embodiments, the processor 351 may configuring a device connected to the at least one PV string 320 based on the at least one determined current value to reduce or remove an effect of current variations between the group of PV strings resulting from current injection. For example, a device could be configured to ensure that the current in each PV string is the same. More specifically, an extra variable resistor could be added to each PV string that is adjusted based on the at least one determined current value to result in constant current. The device may also be attached to the inverter 340 or to a combiner box, to automatically adjust electronic circuits to achieve constant current in each PV string.

[0304]

[0267] Similar to the embodiments of the method 400, in some embodiments, the processor 351 may adjust the at least one determined EL intensity value by adjusting one or more features of the EL image that are indicative of the at least one determined EL intensity. The one or more features of the EL image may be image properties of the EL image. For example, the one or more features of the EL image may be one or more of digital count rates, brightness, colour (e.g., false colour or pseudo colour), contrast, or the like.

[0305]

[0268] In some embodiments, the at least one determined EL intensity value of the one or more PV modules 321, 322, 323, 324, in the at least one PV string 320 is adjusted based on a difference or ratio of the at least one determined EL intensity value and the at least one determined current value. In one example, the at least one EL intensity value in the at least one PV string 320 may be corrected for the variations in current (measured or inferred from other data) via the following equation: where PEL,corr,i refers to corrected luminescence intensities in any section of PV string i (such as one or more PV cells, or one or more PV modules), PEL,I is the EL intensity value in the section of the PV string i, and It is the current (measured or inferred) in PV string i. This correction may also be applied to the entire PV string, to individual modules in PV string i or to individual areas representing specific PV modules or module sections contained in that PV string.

[0306]

[0269] In some embodiments, the current correction may be done by normalising the actual current to the nominal current. For example, the desired current per string may be 10A, but the actual current in a particular string was 11 A. Hence, the at least one EL intensity would be corrected by multiplying by 10 / 11, or by the following equation: where It0is the nominal current in the PV string i.

[0307]

[0270] In some embodiments, the at least one determined EL intensity value of the one or more PV modules 321, 322, 323, 324 in the at least one PV string 320 is adjusted based on a difference or ratio of the at least one determined EL intensity value and the at least one determined current value of the at least one PV string 320 raised to the power of a correction factor. This may be to account for the current voltage characteristics not strictly being exponential, but may include another factor which may be referred to as a correction factor or an ideality factor. A first order approximation to include this effect is to correct the at least one EL intensity value via the following equation:

[0308] — ,Corr,i ~(P ,EnL' PELiv-t ' J ' where n is a correction facto that may be based on the specific situation. Examples include measurements at low current, where the correction factor of the PV cells may deviate significantly from unity, or high efficiency cells where Auger recombination causes deviations of n from unity. Other more comprehensive or complicated forms of corrections may also be applied based on the specific scenario.

[0309]

[0271] Similar to the embodiments of the method 400, in some embodiments, a direct current measurement (such as a measurement from a current clamp meter) of the current in one or more PV strings (such as the PV string 320) may be used to scale relative currents in all strings (i.e., the PV strings 320, 330) connected to the inverter 340 that may have been determined from other means. Directly measuring the current may be a built-in feature of the inverter (or a combiner box) to report the current in different PV strings, for example. In another embodiment, specific hardware could be added that enables current measurements in each string. The direct current measurement may be obtained using one or more of: a clamp meter; a Hall effect current transducer; a current transformer; and a current shunt resistor.

[0310]

[0272] The other means may be the EL image or a thermal image, for example, in which the at least one determined current value of the at least one PV string 320 is determined at least partially based on a temperature of one or more PV modules 321, 322, 323, 324 in the at least one PV string 320. As such, the processor 351 may adjust the at least one determined current value of the PV string 320 (e.g., as determined from the EL image of the PV array 310) at least partially based on a direct current measurement from the PV string 320.

[0311]

[0273] Similar to the embodiments of the method 400, in some embodiments, the processor 351 may adjust the at least one determined EL intensity value of the one or more PV modules 321, 322, 323, 324 in the at least one PV string 320 based on a number of PV modules in each of the group of PV strings, e.g. to account for missing or additional modules in a PV string.

[0312]

[0274] Another risk with EL imaging in the presence of significant system variations such as voltage variations, missing modules or shorted BPDs (which will be discussed later in the disclosure) is that these effects may become sufficiently significant that the currents in individual PV strings become larger than the compliance current of the corresponding PV string fuses. Each PV string may be configured to have a fuse, which may be rated at twice the short circuit current of the PV modules. For example, a PV string fuse may be rated at 20A. Variation in the string voltages may cause variations in PV string current. If an average current of 10A (by way of example) is selected for EL measurements in the PV array 310 containing, say, 100 parallel strings, then this is equivalent to a total of l,000A. This may cause the PV string fuse to blow.

[0313]

[0275] Blown PV string fuses may block any current from flowing in the relevant PV strings, causing the total current to spread across the remaining strings. This may increase the current, and therefore the EL intensity value, in these PV strings. This may be relevant in scenarios where a smaller number of PV strings is powered up. For example, if five strings are powered up with a nominal current of 10A each, and if one string fuse is blown, then 12.5A will flow into the four normal strings, causing a 25% higher current and therefore higher EL intensity value. The comparison of EL intensity value between modules in these four strings would be valid for determining one or more characteristics of the PV array 310. However, a comparison with PV modules in other PV strings may need to be adjusted beforehand.

[0314]

[0276] Therefore, in some embodiments, the processor 351 adjusts the at least one determined PL intensity value of the one or more PV modules 321, 322, 323, 324 in the at least one PV string 320 based on a number of disconnected PV strings. The disconnected PV strings may result from one or more blown string fuses, for example. However, PV strings may be disconnected in other manners, e.g. poor electrical connections, damage to the wiring connecting the PV strings etc. The at least one EL intensity value may be corrected for the number of disconnected PV strings using the following equation: where nstringsis the number of strings nominally connected to the power supply andnnormai strings isthe number of strings operating normally, i.e., strings without blown fuses. For example, if five parallel strings are connected to the power supply (nstrings= 5), but one string has a blown fuse then the number of strings operating normally is 4 (nnormai strtngs= 4).

[0315]

[0277] In some embodiments, the processor 351 adjusts a total current value based on a number of disconnected PV strings. The total current value may correspond to a total current flowing into the PV strings. For example, the total current flowing into parallel strings may be adjusted in proportion to the number of blown string fuses according to: where {adjusted, is the total current flowing into the parallel strings, I nominal isthe desired current in the absence of blown string fuses, nstringsis the number of parallel connected strings that would be powered up in the absence of blown string fuses and nnormai strtngsis the number of strings operating normally.

[0316]

[0278] As previously discussed, blown string fuses may block any current from flowing in the relevant PV strings. Therefore, the total current may spread across the remaining PV strings.

[0317] This may increase the current, thereby increasing the EL intensity value in these PV strings. This may be particularly relevant in scenarios where a smaller number of parallel PV strings are powered up (i.e., current is injected into a smaller number of parallel PV strings).

[0318] Junction box faults

[0319]

[0279] Similar to the embodiments of the method 400, one or more junction box faults may occur that affect the at least one EL image and hence may affect the at least one EL intensity value. As such, in some embodiments, the processor 351 may determine at least one junction box fault in the one or more PV modules 321, 322, 323, 324 in the at least one PV string 320 based on the at least one EL image of the PV array 310. Moreover, in some embodiments, the processor 351 may adjust the at least one determined EL intensity value based on the at least one determined junction box fault.

[0320]

[0280] Similar to the embodiments of the method 400, the same dark patterns (e.g., one third of a module appearing dark) appearing in the PL image of Fig. 6 may also appear in the at least one EL image. Therefore, in some embodiments, the processor 351 may determine the at least one junction box fault by determining at least one EL value of a portion of the one or more PV modules 321, 322, 323, 324 in the at least one EL image of the PV array 310; and determining that the at least one EL value of the portion has a value of about zero.

[0321]

[0281] Depending on whether the junction box fault is failure mode ii or iii, the voltage drop over the affected PV module may be different. This may affect at least one EL intensity value of all other PV modules in the same PV string, which may be used to determine the fault type. This is because in the case of failure mode ii, all other PV modules contained in the same string appear brighter than in other PV strings, whereas in failure mode iii, all other PV modules appear dimmer. Similar to the embodiments of the method 400, the processor 351 may determine a fault type of the at least one junction box fault by determining at least one EL intensity value of the one or more PV modules 321, 322, 323, 323 in the at least one PV string 320 comprising the at least one junction box fault being greater or lower than at least one EL intensity value of one or more PV modules in a different one of the group of PV strings (such as PV modules 331, 332, 333, 334 of the PV string 330).

[0322]

[0282] The processor 351 may determine a fault type of the at least one junction box fault by determining a change of at least one EL intensity value of the at least one PV string 320 containing the at least one junction box fault. As previously discussed, there is a scenario where failure mode iii switches to failure mode ii. This is because in a failure mode iii situation, the current flows through the BPD in the reverse direction at very large voltage (e.g. 50V), causing it to get very hot. At some point, the BPD will short and turn into a shorted BPD (i.e., failure mode ii). In that case, an intensity variation in the modules in that string from lower EL intensity value to higher EL intensity value would be observed, although this may be undesirable in the PV array 310.

[0323]

[0283] Similar to the embodiments of the method 400, the junction box fault may be a failure mode ii corresponding to a bypass diode in short circuit. For electroluminescence, in failure mode ii. the forward current of the current injection flows through the shorted BPD, rather than through the PV cells that are connected to it in parallel. With currents on the order of typically a few Amps, the voltage across a PV module in some EL scenarios (such as the scenario represented in Fig. 13) may be between 42 and 54V depending on the type of PV module. One third of that voltage (e.g. 14V to 18 V) may drop across each module sub-string. When the BPD is shorted, the current flow may cause a (close to zero) voltage drop across the relevant module sub-string instead of the usual 14-18 V. The total voltage across the module under forward bias (i.e., during current injection), therefore, drops by 14V to 18V. The voltage drop in the one module sub-string may be balanced by a voltage increase across the remainder of PV cells in the same PV string, since the total PV string voltage remains constant.

[0324]

[0284] Therefore, a shorted BPD may cause string Vocvariation (reduction) and therefore a current variation (increase) in the PV string in comparison to other parallel-connected PV strings. This current variation may be taken into account in the EL image analysis to correct the at least one EL intensity value, in order to get comparable results between PV strings. It is noted that the EL intensity comparison between PV modules in the same PV string may not be affected by this. Moreover, the zero or near zero EL intensity value may correctly reflect the zero voltage across the relevant PV cells. Similar to the embodiments of the method 400, in some embodiments the processor 351 may adjust the at least one EL intensity value based on a number of junction box faults in the at least one PV string 320. For example, the processor 351 may determine a number of instances of failure mode ii and adjust the at least one EL intensity value using this number.

[0325]

[0285] Similar to the embodiments of the method 400, the junction box fault may be a failure mode iii corresponding to an open circuit PV module sub-string. In forward bias (e.g., current injection), the current normally flows through the PV cells, causing them to emit EL. However, if one module sub-string is electrically disconnected, or very poorly connected, then the current is forced to flow through the BPD in reverse direction. BPDs typically break down around 60V and are not designed to carry such large currents in the reverse direction. In particular, this may lead to tens or hundreds of Watts being “dumped” in the BPD in this scenario. Note that in normal operation, the power dissipated by a BPD may be about 10W at most.

[0326]

[0286] In electroluminescence and in the presence of failure mode iii, the large power drop across a BPD means that it may rapidly become hot and eventually fail, possibly within seconds. In a best-case scenario, it fails by shorting out, i.e., failure mode iii is converted to failure mode ii. However, the extreme heat at the BPD may cause a safety risk, in the extreme case causing a fire. Another issue is that the current may flow through a short-circuited BPD when there is no current extracted from a PV string, e.g., during times of curtailment (enforced low energy production). This is the case since the corresponding module sub-string is permanently shorted. The BPD may be shorted or partly shorted corresponding to a low resistance and a high resistance, respectively. If the failure of the BPD is such that a comparatively high resistance (i.e., partly shorted) is present after it has failed, this could lead to excessive heating and destruction of the junction box, module, or even present a fire danger.

[0327]

[0287] In some embodiments, EL imaging may be performed initially at very low injection currents. If PV modules with failure mode iii exist in the PV array or string under test, then the corresponding PV strings would have much lower EL intensity value, due to the missing string voltage dropping at the BPD. As such, those PV strings containing junction box faults may be determined. EL imaging would also reveal the corresponding BPD, since the missing module substring will be completely dark (no current can flow in a disconnected substring). Thermal imaging may also be able to confirm which PV module has the “hot BPD” before it actually gets destroyed.

[0328]

[0288] As such, the processor 351 may determine the at least one junction box fault based on receiving at least one low current EL image of the PV array 310 captured during low current injection into the group of PV strings 320, 330. From the at least one low current EL image, the processor 351 may identify one of the group of PV strings 320, 330 containing at least one junction box fault by determining at least one EL intensity value of one or more PV modules in the one of the groups of PV strings (either the PV string 320 or the PV string 330, for example) being lower than at least one EL intensity value of one or more PV modules in a different one of the group of PV strings. The processor 351 may then determine the at least one junction box fault in the one of the group of PV strings based on the low current EL image (as the missing module substring will be dark). In some examples, the processor 351 may then determine the at least one junction box fault in the one of the group of PV strings based on thermal imaging. The processor 351 may receive a thermal image of the PV array 310 from a database or server, for example.

[0329]

[0289] It may be useful to investigate the PV array 310 before performing any EL imaging to ensure that no PV modules with mode iii are contained therein. Any PV strings containing such modules may be turned off (e.g., via switching fuses contained in the combiner boxes). Otherwise, such PV modules may simply be replaced upon detection of the junction box faults.

[0290] Open circuited strings due to blown fuses may be easily identified in EL, DPL and thermal images. Further, any of these methods can be used to determine blown fuses and then perform the corrections as described above. It is noted that an adjustment of the at least one EL intensity value may have to take into account all effects, including shorted BPD, missing modules and module quality variations.

[0330] Simulation

[0331]

[0291] A simulation of nighttime electroluminescence (NEL) was conducted with one or more BPD short-circuits (i.e., failure mode ii) for different current injection conditions. When BPDs are short-circuited, the PV string voltage is reduced. In the case of NEL imaging, this means that the corresponding PV strings may carry higher current than the average string current. The average string current may equal the total injected current divided by the number of PV strings. Table 1 below shows current values in various PV strings as a function of Rs, average PV string current (“Ave. String Current”) and the number of BPDs in short-circuit (“# of BPD of SC”). Table 1 also shows simulation results for a different number of PV modules per PV string, as represented by negative number of BPDs in short-circuit. The table elements with black background are fields where the 20A string fuse threshold is exceeded for the first time. In Table 1, simulation results are presented that are based on typical PV module parameters. The results were modelled for different average string currents and different normalised Rsvalues per cell (in 0hm*cm2).

[0332]

[0292] For example, as can be seen in Table 1, if 6A average current is injected into a PV array, then a PV string with three missing BPDs will carry 9.5A rather than 6A for an Rsof 0.75 Ohm*cm2. If a PV string is accidentally longer than the typical PV string length, i.e. it has more modules, then the current in that PV string may be reduced. Excess modules in a string are represented by negative numbers of BPDs in short-circuit in Table I. In one specific example, a PV string with an extra module (having three BPDs) at 8A average current injection and Rs= 1 Ohm*cm2will carry only 5.3A, i.e., about 34% less current.

[0333]

[0293] In some embodiments, the processor 351 may adjust the at least one determined EL intensity value of the one or more PV modules 321, 322, 323, 324 in the at least one PV string 320 based on the simulation described above. More specifically, to account for the faulty junction boxes, the processor 351 may adjust the at least one determined EL intensity value of the one or more PV modules 321, 322, 323, 324 in the at least one PV string 320 based on the simulation. In particular, rather than the more detailed analysis using measured currents or currents that may be determined from the at least one EL intensity value, the simulated currents of Table 1 may be used. The simulation may be extended to include series resistances or average string currents that are not specified in Table 1 (i.e., series resistances other than 0.50, 0.75 and 1.00, and average string currents of 10A, 8A, 6A, 4A, 2A and 1A). The current for other series resistances or average strings currents may also be interpolated or extrapolated using the results of Table 1.

[0334]

[0294] It will be appreciated by persons skilled in the art that numerous variations and / or modifications may be made to the above-described embodiments, without departing from the broad general scope of the present disclosure. The present embodiments are, therefore, to be considered in all respects as illustrative and not restrictive.

[0335] Avg.

[0336] String 10A 8A 6A 4A 2A 1A Current

[0337] Current in faulty Current in faulty Current in faulty Current in faulty Current in faulty Current in faulty string (A) string (A) string (A) string (A) string (A) string (A)

[0338] # of BPD Rs=Rs=Rs= Rs=Rs=Rs= Rs=Rs=Rs= Rs=Rs=Rs= Rs=Rs=Rs= Rs=Rs=Rs= in S 0.50 0.75 1.00 0.50 0.75 1.00 0.50 0.75 1.00 0.50 0.75 1.00 0.50 0.75 1.00 0.50 0.75 1.00

[0339] 15 57.4 44.8 37.9 52.2 40.6 34.2 46.2 35.8 30.0 38.7 30.0 25.1 27.8 21.9 18.7 15.2 13.0

[0340] 14 52.7 41.6 35.4 47.7 37.5 31.8 41.9 32.8 27.7 34.8 27.3 23.0 24.5 19.5 16.5 16.1 13.2 11.4

[0341] 13 48.3 38.5 33.0 43.5 34.5 29.4 37.9 30.0 25.5 31.1 24.7 20.9 21.4 17.3 14.8 13.7 11.5 10.0

[0342] 12 44.1 35.5 30.6 39.5 31.6 27.2 34.1 27.3 23.4 27.7 22.2 19.0 18.6 15.2 13.2 11.6 9.9 8.7

[0343] 11 40.1 32.6 28.4 35.7 28.9 25.1 30.6 24.8 21.4 24.5 19.9 17.2 16.0 13.3 11.6 9.7 8.4 7.5

[0344] 10 36.3 29.9 26.3 32.1 26.4 23.1 27.3 22.4 19.5 21.5 17.8 15.5 13.7 11.6 10.2 8.1 7.1 6.4 9 32.8 27.4 24.2 28.7 23.9 21.1 24.1 20.2 17.7 18.7 15.7 13.9 11.6 10.0 8.9 6.7 6.0 5.4 8 29.4 24.9 22.3 25.6 21.6 19.3 21.3 18.0 16.1 16.2 13.9 12.4 9.8 8.6 7.8 5.5 5.0 4.6 7 26.2 22.6 20.4 22.6 19.5 17.6 18.6 16.0 14.5 14.0 12.1 11.0 8.2 7.3 6.7 4.4 4.1 3.9

[0345] 6 23.3 20.4 18.7 19.9 17.4 15.9 16.1 14.2 13.0 11.9 10.6 9.7 6.8 6.2 5.7 3.6 3.4 3.2

[0346] 5 20.6 18.4 17.0 17.4 15.5 14.4 13.9 12.5 11.6 10.1 9.1 8.5 5.6 5.2 4.9 2.9 2.8 2.7

[0347] 4 18.0 16.4 15.4 15.1 13.8 12.9 11.9 10.9 10.3 8.5 7.8 7.4 4.6 4.3 4.1 2.3 2.3 2.2

[0348] 3 15.7 14.6 13.9 13.0 12.1 11.5 10.1 9.5 9.0 7.1 6.7 6.4 3.7 3.6 3.5 1.9 1.8 1.8

[0349] 2 13.6 13.0 12.5 11.1 10.6 10.3 8.6 8.2 7.9 5.9 5.7 5.5 3.0 3.0 2.9 1.5 1.5 1.5

[0350] 1 11.7 11.4 11.2 9.5 9.2 9.1 7.2 7.0 6.9 4.9 4.8 4.7 2.5 2.4 2.4 1.2 1.2 1.2

[0351] 0 10.0 10.0 10.0 8.0 8.0 8.0 6.0 6.0 6.0 4.0 4.0 4.0 2.0 2.0 2.0 1.0 1.0 1.0

[0352] -1 8.5 8.7 8.9 6.7 6.9 7.0 5.0 5.1 5.2 3.3 3.3 3.4 1.6 1.6 1.7 0.8 0.8 0.8

[0353] -2 7.2 7.5 7.8 5.6 5.9 6.1 4.1 4.3 4.4 2.7 2.8 2.9 1.3 1.3 1.4 0.7 0.7 0.7

[0354] -3 6.0 6.5 6.9 4.7 5.0 5.3 3.4 3.6 3.8 2.2 2.3 2.4 1.1 1.1 1.1 0.5 0.6 0.6

[0355] -4 5.0 5.5 6.0 3.9 4.2 4.5 2.8 3.0 3.2 1.8 1.9 2.0 0.9 0.9 0.9 0.5 0.5 0.5

[0356] -5 4.2 4.7 5.2 3.2 3.6 3.9 2.3 2.5 2.7 1.5 1.6 1.7 0.7 0.8 0.8 0.4 0.4 0.4

[0357] -6 3.5 4.0 4.5 2.7 3.0 3.3 1.9 2.1 2.3 1.2 1.3 1.4 0.6 0.6 0.6 0.3 0.3 0.3

[0358] Table 1: Current values in various PV strings as a function of series resistance Rs. average string current and number of bypass diodes in short-circuit.

Claims

1. CLAIMS:

1. A method for determining one or more characteristics of a photovoltaic (PV) array, the PV array comprising a plurality of PV strings electrically connected in parallel to each other, each PV string comprising a plurality of PV modules electrically connected in series to each other, the method comprising:(i) determining at least one photoluminescence (PL) intensity value of one or more PV modules in at least one of the PV strings based on at least one PL image of the PV array when illuminated by solar radiation;(ii) determining at least one current value in the at least one PV string when the PV array is in an open circuit condition or operating at an operating voltage above a maximum power point voltage of the PV array; and(iii) determining the one or more characteristics of the PV array based on the at least one determined current value and / or the at least one determined PL intensity value.

2. The method of claim 1, wherein the operating voltage above the maximum power point voltage results in a power extracted from the PV array that is < 20% or < 40% of a power extracted from the PV array when the PV array is operating at the maximum power point voltage.

3. The method of claim 1 or 2, wherein the method further comprises adjusting the at least one determined PL intensity value of the one or more PV modules in the at least one PV string based on the at least one determined current value.

4. The method of claim 3, wherein adjusting of the at least one determined PL intensity value comprises adjusting one or more features of the at least one PL image that are indicative of the at least one determined PL intensity.

5. The method of claim 4, wherein the one or more features of the at least one PL image are one or more of brightness, digital count rate, colour and contrast.

6. The method of claim 3, 4 or 5, wherein adjusting the at least one determined PL intensity value of the one or more PV modules in the at least one PV string based on the at least one determined current value reduces or removes an effect on the at least one determined PL intensity value of balancing currents between PV strings of the PV array when the PV array is inan open circuit condition or operating at an operating voltage above a maximum power point voltage of the PV array.

7. The method of any one of claims 3 to 6, wherein the at least one determined PL intensity value of the one or more PV modules in the at least one PV string is adjusted based on a difference or ratio of: (i) the at least one current value in the at least one PV string determined when the PV array is in an open circuit condition or operating at an operating voltage above a maximum power point voltage of the PV array, and (ii) a short circuit current value of the at least one PV string.

8. The method of claim 3, wherein the at least one determined PL intensity value ( pp ) of the one or more PV modules in the at least one PV string is adjusted to at least one corrected PL intensity value (<PpL,corr) based on the following equation (2), where Inis the current in the at least one PV string (n) determined when the PV array is in an open circuit condition or operating at an operating voltage above a maximum power point voltage of the PV array, Iscis a short circuit current of the at least one PV string and C2is a constant: equation (2).

9. The method of any one of the preceding claims, wherein the at least one determined current value in the at least one PV string is determined at least partially based on the at least one determined PL intensity value of the one or more PV modules.

10. The method of claim 9, wherein the at least one determined current value of the at least one PV string is determined at least partially based on determined PL intensity values of all PV modules connected to an inverter of the PV array.

11. The method of claim 9 or 10, wherein the at least one determined current value of the at least one PV string is determined at least partially based on a sum of cell diode voltages in the at least one string calculated from the at least one determined PL intensity value of the one or more PV modules in the at least one PV string.

12. The method of claim 9, 10 or 11, wherein the at least one determined current value of the at least one PV string is determined at least partially based on a mean of cell diode voltages of all cells in all PV modules connected to the inverter of the PV array.

13. The method of claim 11 or 12, wherein the cell diode voltages (7d) are determined at least partially from the at least one PL intensity value (<pPL), and based, at least partially, on the following generalised Planck equation (1), where kT / q is a thermal voltage and C1is a calibration constant:equation (1).

14. The method of any one of claims 9 to 13, wherein the at least one determined current value of the at least one PV string is determined at least partially based on a series resistance of at least one PV cell in one or more PV modules in one of the plurality of PV strings.

15. The method of claim 14, wherein the method comprises determining the series resistance based on a measurement of a voltage of the one or more PV modules in the one of the plurality of PV strings via one or more y-connectors.

16. The method of claim 14 or 15, wherein the method comprises determining the series resistance based on a measurement of a voltage of a PV module similar and / or associated with the one or more PV modules in the one of the plurality of PV strings.

17. The method of any one of the preceding claims, wherein the at least one determined current value of the at least one PV string is determined at least partially based on a measured voltage across all of the PV strings of the PV array connected to an inverter of the PV array.

18. The method of any one of the preceding claims, wherein the method further comprises adjusting the at least one determined current value in the at least one PV string at least partially based on a direct current measurement from the at least one PV string.

19. The method of any one of the preceding claims, wherein the at least one determined current value in the at least one PV string is determined at least partially based on a direct current measurement from the at least one PV string or a different one of the plurality of PV strings.

20. The method of claim 19, wherein the direct current measurement is obtained using one or more of: a clamp meter; a Hall effect current transducer; a current transformer; and a current shunt resistor.

21. The method of any one of the preceding claims, wherein the at least one determined current value of the at least one PV string is determined at least partially based on a temperature of one or more PV modules in the at least one PV string.

22. The method of claim 21, wherein the temperature of the one or more PV modules in the at least one PV string is determined by thermal imaging of the one or more PV modules in the at least one PV string.

23. The method of claim 21 or 22, wherein the at least one determined current value of the at least one PV string is determined at least partially based on a temperature of the one or more PV modules when (i) the PV array is operating substantially at maximum power point (MPP), and (ii) the PV array is operating in an open circuit condition or operating at an operating voltage above a maximum power point voltage of the PV array.

24. The method of claim 21 or 22, wherein the at least one determined current value of the at least one PV string is determined at least partially based on a comparison between a temperature increase of the one or more PV modules in the at least one PV string caused at least partially by solar absorption when the PV array is operating substantially at maximum power point (MPP), and a temperature increase of the one or more PV modules in the at least one PV string caused at least partially by solar absorption when the PV array is operating in an open circuit condition or operating at an operating voltage above a maximum power point voltage of the PV array.

25. The method of any one of the preceding claims, wherein the method comprises determining the PL image from an image difference between at least two images of the PV array, each of the at least two images corresponding to the PV array operating at a different operating condition.

26. The method of any one of the preceding claims, wherein the at least one determined current value of the at least one PV string is indicative of a voltage mismatch between at least two PV strings in the PV array, the at least two PV strings comprising the at least one PV string having the at least one determined current value.

27. The method of any one of the preceding claims, wherein the method further comprises: determining at least one junction box fault in the one or more PV modules in the at least one PV string based on the at least one PL image of the PV array; and adjusting the at least one determined PL intensity value based on the at least one determined junction box fault.

28. The method of claim 27, wherein determining the at least one junction box fault comprises: determining at least one PL value of a portion of the one or more PV modules in the at least one PL image of the PV array; and determining that the at least one PL value of the portion has a value of about zero.

29. The method of claim 27 or 28, wherein adjusting the at least one determined PL intensity value comprises adjusting the at least one determined PL intensity value based on a function of a number of determined junction box faults in the at least one PV string.

30. The method of any one of claims 27 to 29, wherein the at least one junction box fault comprises one or more of: a bypass diode in short circuit; and an open circuit PV module sub-string.

31. The method of any one of the preceding claims, wherein the one or more characteristics of the PV array comprises one or more of: an open circuit voltage; an operational voltage; an implied voltage; module performance; module quality; and a corrected PL image.

32. A method for determining one or more characteristics of a photovoltaic (PV) array, the PV array comprising a plurality of PV strings electrically connected in parallel to each other, each PV string comprising a plurality of PV modules electrically connected in series to each other, the method comprising:(i) determining at least one photoluminescence (PL) intensity value of one or more PV modules in at least one of the PV strings based on at least one PL image of the PV array when illuminated by solar radiation;(ii) determining at least one current value in the at least one PV string when the PV array is operating at an operating voltage between an open circuit condition and an operating voltage above a maximum power point voltage of the PV array; and(iii) determining the one or more characteristics of the PV array based on the at least one determined current value and / or the at least one determined PL intensity value.

33. A method for determining one or more characteristics of a photovoltaic (PV) array, the PV array comprising a plurality of PV strings electrically connected in parallel to each other, each PV string comprising a plurality of PV modules electrically connected in series to each other, the method comprising:(i) determining at least one electroluminescence (EL) intensity value of one or more PV modules in at least one of the PV strings from a group of PV strings based on at least one EL image of the PV array captured during current injection into the group of PV strings, the group of PV strings comprising two or more of the plurality of PV strings;(ii) determining at least one current value in the at least one PV string of the group of PV strings, the at least one current value being associated with current injection into the group of PV strings; and(iii) determining the one or more characteristics of the PV array based on the at least one determined current value and / or the at least one determined EL intensity value.

34. The method of claim 33, wherein the method further comprises adjusting the at least one determined EL intensity value of the one or more PV modules in the at least one PV string based on the at least one determined current value.

35. The method of claim 34, wherein adjusting of the at least one determined EL intensity value comprises adjusting one or more features of the at least one EL image that are indicative of the at least one determined EL intensity.

36. The method of claim 35, wherein the one or more features of the at least one EL image are one or more of brightness, digital count rate, colour and contrast.

37. The method of any one of claims 34 to 36, wherein adjusting the at least one determined EL intensity value of the one or more PV modules in the at least one PV string based on the at least one determined current value reduces or removes an effect of current variations between the group of PV strings resulting from current injection into the group of PV strings.

38. The method of any one of claims 34 to 37, wherein the at least one determined EL intensity value of the one or more PV modules in the at least one PV string is adjusted based on a difference or ratio of: the at least one determined EL intensity value and the at least one determined current value.

39. The method of any one of claims 34 to 38, wherein the at least one determined current value of the at least one PV string is determined at least partially based on the at least one determined EL intensity value of the one or more PV modules.

40. The method of claim 39, wherein the at least one determined current value of the at least one PV string is determined at least partially based on a sum of cell diode voltages in the at least one PV string calculated from the at least one determined EL intensity value of the one or more PV modules in the at least one PV string.

41. The method of claim 40, wherein the cell diode voltages (Vd) are determined at least partially from the at least one determined EL intensity value ((PEL), and based, at least partially, on the following generalised Planck equation (5), where kT / q is a thermal voltage and C12is a calibration constant:equation (12).

42. The method of any one of claims 39 to 41, wherein the at least one determined current value of the at least one PV string is determined at least partially based on a series resistance of at least one PV cell in one or more PV modules in one of the group of PV strings.

43. The method of claim 42, wherein the method comprises determining the series resistance by determining at least one EL intensity value of the one or more PV modules in the one of the group of PV strings at each of two or more current injection conditions, wherein the series resistance is based on a difference between the two or more current injection conditions.

44. The method of claim 43, wherein determining the at least one EL intensity value at each of the two or more current injection conditions further comprises determining at least one voltage of the one or more PV modules in the one of the group of PV strings at each of two or more current injection conditions.

45. The method of any one of claims 42 to 44, wherein the method comprises determining the series resistance based on a measurement of a voltage of the one or more PV modules in the one of the group of PV strings via one or more y-connectors.

46. The method of any one of claims 42 to 45, wherein the method comprises determining the series resistance based on a measurement of a voltage of a PV module similar and / or associated with the one or more PV modules in the one of the group of PV strings.

47. The method of any one of claims 33 to 46, wherein the method further comprises adjusting the at least one determined current value in the at least one PV string at least partially based on a direct current measurement from the at least one PV string.

48. The method of any one of claims 33 to 47, wherein the at least one determined current value in the at least one PV string is determined at least partially based on a direct current measurement from the at least one PV string.

49. The method of claim 47 or 48, wherein the direct current measurement is obtained using one or more of: a clamp meter; a Hall effect current transducer; a current transformer; and a current shunt resistor.

50. The method of any one of claims 33 to 49, wherein the at least one determined current value of the at least one PV string is determined at least partially based on a temperature of one or more PV modules in the at least one PV string.

51. The method of claim 50, wherein the temperature of the one or more PV modules in the at least one PV string is determined by thermal imaging of the one or more PV modules in the at least one PV string.

52. The method of any one of claims 33 to 51, wherein the method further comprises:determining at least one junction box fault in the one or more PV modules in the at least one PV string based on the at least one EL image of the PV array; and adjusting the at least one determined EL intensity value based on the at least one determined junction box fault.

53. The method of claim 52, wherein determining the at least one junction box fault comprises: determining at least one EL value of a portion of the one or more PV modules in the at least one EL image of the PV array; and determining that the at least one EL value of the portion has a value of about zero.

54. The method of claim 52 or 53, wherein adjusting the at least one determined EL intensity value comprises adjusting the at least one determined EL intensity value based on a function of a number of determined junction box faults in the at least one PV string.

55. The method of any of one claims 52 to 54, wherein determining the at least one junction box fault comprises determining a fault type of the at least one junction box fault by performing one or more of the following: determining at least one EL intensity value of the one or more PV modules in the at least one PV string comprising the at least one junction box fault being greater or lower than at least one EL intensity value of one or more PV modules in a different one of the group of PV strings; and determining a change of at least one EL intensity value of the at least one PV string comprising the at least one junction box fault.

56. The method of any one of claims 52 to 55, wherein determining the at least one junction box fault comprises: receiving at least one low current EL image of the PV array captured during low current injection into the group of PV strings; from the at least one low current EL image, identifying one of the group of PV strings comprising the at least one junction box fault by determining at least one EL intensity value of one or more PV modules in the one of the group of PV strings being lower than at least one EL intensity value of one or more PV modules in a different one of the group of PV strings; and determining the at least one junction box fault in the one of the group of PV strings based on the low current EL image.

57. The method of any one of claims 52 to 56, wherein the at least one junction box fault comprises one or more of: a bypass diode in short circuit; and an open circuit PV module sub-string.

58. The method of any one of claims 34 to 58, wherein the method further comprises adjusting the at least one determined EL intensity value of the one or more PV modules in the at least one PV string based on a number of PV modules in each of the group of PV strings.

59. The method of any one of claims 34 to 58, wherein the method further comprises adjusting the at least one determined EL intensity value of the one or more PV modules in the at least one PV string based on a number of disconnected PV strings of the group of PV strings.

60. The method of any one of claims 34 to 59, wherein the method further comprises adjusting a total current value based on a number of disconnected PV strings of the group of PV strings, and the total current value corresponding to a total current flowing into the group of PV strings during current injection.

61. The method of any one of claims 34 to 60, wherein the current injection into the group of PV strings is performed, at least partially, by: disconnecting one or more combiner boxes connected to the group of PV strings; and / or disconnecting one or more fuses connected to the group of PV strings.

62. The method of any one of claims 34 to 61, wherein the method further comprises configuring a device connected to the at least one PV string based on the at least one determined current value to reduce or remove an effect of current variations between the group of PV strings resulting from current injection.

63. The method of any one of the preceding claims, wherein the one or more characteristics of the PV array comprises one or more of: an open circuit voltage; an operational voltage; an implied voltage; module performance;module quality; and a corrected EL image.

64. A non-transitory computer readable medium having a computer readable program code configured to implement the method according to any one of the preceding claims.

65. A system for determining one or more characteristics of a photovoltaic (PV) array, the system comprising at least one processor configured to perform the method of any one of claims 1 to 63.

Images