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International audience; Given the exponential growth of deployed photovoltaic (PV) energy sources, we have to question how to make such growth sustainable. Transition at global scale from fossil fuels to mineral-based renewable energies will indeed induce a sharp turn in materials supply chains. The concept of critical materials covers various sources of supply tensions. More precisely in PV sector, concerns grow for the last few years about Silver price volatility, relative to its scarcity, or about Indium related to its availability.Raw material criticity definition is open to question. No consensus seems to arise yet from literature in order to define influencing factors on criticity. For this study, five supply hazard criteria are selected in order to represent accurately each material supply situation: geological, logistical, geopolitical, industrial and commercial. With those criteria, the materials (and their substitutes) used in PV modules interconnection are listed and for each one, criticity is assessed. List of those elements is the following: Aluminum, Bismuth, Copper, Indium, Nickel, Silver and Tin.Although different dynamics may be observed depending on the concerned material, the main conclusion is that, except Aluminum, all listed elements supplies should face supply tensions by 2050, or even 2030 for the most critical ones [1]. It is important to note that for most of these materials, PV sector has not triggered its critical status.Two material groups should be distinguished. In the first hand, high production and consumption volumes materials (Aluminum and Copper) should not restrict PV energy production capacity expansion projections in the short term but could adversely affect growth in the mid term: by 2050, Copper demand to electrify the whole society should deplete global reserves so its supply is unreliable; it is then compulsory to deeply rethink energy networks, as well as implement a circular approach (reduce, repair, reuse and finally recycle). Moreover, aluminum needed volume for PV on TW scale would induce huge CO2 emissions [2]. On the other hand, other materials (Bismuth, Indium, Silver, and Tin) are used in PV interconnection in dispersive ways: even though PV sector requires a limited amount, they are difficult to recover. These applications must evolve otherwise the known reserves will end around 2040.It draws one main conclusion in the specific case of PV sector: conception has to evolve from dispersive cells interconnection processes, such as low temperature soldering or conductive adhesive bonding. In general, conception step has to focus on end-of-life step to introduce more circular methodologies. Change may happen at three levels: process, material or architecture. Changing or optimizing the deposition process is largely covered in literature over the last 15 years and Silver consumption reduction potential seems to reach its limit [3]. Alternative materials have been rising for the last 5 years and could have a great impact on metallization criticity. In the meantime, critical materials consumption in interconnection could further shrink with a disruptive innovation in module architecture. A few innovation examples, from NICE concept to non-uniform metallization, will be presented.

38th European Photovoltaic Solar Energy Conference and Exhibition; 1096-1100, This work reports on the first results of a new concept for a flexible blanket based on weaving technology, which could potentially be employed as a carrier structure for the photovoltaic assembly (PVA) within a flexible solar array (SA) architecture. Though further away from current proposed solutions, the promising potential of such a weaving approach is describing the creation of an electrically functional and integrated flexible carrier with minimal weight and stowage volume.

38th European Photovoltaic Solar Energy Conference and Exhibition; 578-582, This paper proposes a grey box model for cell-level simulation of potential induced degradation of the shunting type (PID-s) by extending a physics-based energy yield simulation framework. The leakage current is first computed using a physics-based approach based on an equivalent frame-to-cell electric circuit composed of temperature and humidity dependent resistances. Then, the increase of PID-s degradation due to leakage current is retrieved from measurements of PID-s evolution performed on polycSi cells. Finally, IV-curves of cells affected by PID-s are approximated by modifying the IV-curve of a PID-free cell using measurements of short circuit current and open-circuit voltage decrease with PID-s. A first comparison of simulated versus measured final PID-s levels is reported for a PV string after nine years of operation. The advantage of our grey box model over an empirical model is the possibility to investigate changes in material properties without the need for new measurements and to provide quantitative energy yield loss estimates depending on climate and system design.

Potential-induced degradation rapidly and significantly affects the photovoltaic (PV) module's performance due to a high potential difference across the PV cell and the grounded module's frame.[1] PID has various types where PID of the shunting type (PID-s) is common within silicon PV cells.[2] Extensive research already points towards sodium (Na) ions as the root cause of the efficiency degradation under PID-s.[3] However, the origin of the Na ions is still under debate. Some publications state that the soda-lime glass (SLG) cover of the PV module is the main source of the Na ions. In contrast, others have proven to degrade solar cells in the absence of an encapsulation material and front cover glass. [3-6] With this work, we try to find an answer to the current debate and thus find the source of the Na ions causing PID-s.

In this presentation, one-year-long measurements from a test setup installed on the roof of EnergyVille (Genk, Belgium) are analysed and compared with simulations performed using the energy yield simulation framework developed at imec. Such experimental setup allows understanding of real-world expected performance of both monofacial and bifacial PV modules installed in a built environment, with an in-depth view onbothoptical, thermal and electrical behavior. It also allows to validate imec simulation framework performance and to understand what are the key features to take into account for accurate simulation, as well as to identifyeventual areas of improvement.

36th European Photovoltaic Solar Energy Conference and Exhibition; 1-5, In this paper an overview of interconnection technologies for bifacial and back-contacted (bifacial) cells in different stages of their development is reported, leading to a new technology suited for efficient interconnection of (bifacial) back-contact cells.

Nowadays, material manufacturers are engineering module materials to optimize the energy production of the PV modules. One of the elements which can be influenced is the optical scattering of a material. In this study, we quantified the effect of a scattering front encapsulant on the energy production of PV modules. First, a wavelength dependent scattering model was developed in the ray-tracing software PVlighthouse. This model was used to find the optimal scattering conditions, looking at the photo-generated current for a glass-glass PV module with flat front surface. It was shown that a gain of +0.63 mA/cm2 can be obtained for optimal scattering conditions. The scattering is mostly beneficial when the light strikes the module surface at a perpendicular angle. The outcome of the optimization study was implemented in IMEC’s energy yield simulation framework. This framework was used to estimate the energy gain of PV module with scattering front encapsulant when installed in Kuwait’s desert. It was shown that an energy production gain of 1.8% can be expected in case of a glass-glass module with flat front surface and ARC coating.

In this paper, an advanced module solar simulator based on LEDs as irradiation sources is described, and its performance concerning control of irradiation and temperature is measured. The spectral match to the standard AM1.5G spectrum is outstanding between 400 nm-1100 nm, with a maximum deviation in the spectral intervals where 1.6 m x 1 m area is currently 2.1%, which is just above the 2% limit for class A, but this can be improved by adjusting the LED beam directions slightly. The long-term irradiance instability is 0.09%, which is well below the 2% limit of class A. Since the high efficiency modules of today can still produce significant current below 400 nm and above 1100 nm, the updated IEC standard (expected by 2020) will extend the total spectral range to 300 nm-1200 nm for the new class A+. Introducing other LED types in future upgrades will enable the spectrum to be closely matching the AM1.5G spectrum also below 350 nm and above 1100 nm. Finally, actual module measurements at different temperature/irradiance combinations are presented to demonstrate the capabilities of the simulator.

35th European Photovoltaic Solar Energy Conference and Exhibition; 1127-1130, In order to reduce the negative effect of partial shading and other sources of current mismatch within a module, smart reconfigurable modules allow altering the connections between groups of cells (cell-strings). With a proper algorithm managing these connections, we can make sure that the majority of the cells are operating close to their MPP, even when a part of the module is shaded. Such a smart reconfigurable module consists of some extra components. Switches are needed to change the interconnection scheme. Small, local converters collect power from multiple cell-strings. They step-up the voltage to reduce the current on the central bus they are connected to. At the end where we connect to the string-level bus, a module converter further regulates the voltage for the grid or the PV array. This topology was presented before where we showed that a smart reconfigurable module could recover up to 70% of the power lost to partial shading. In this paper we take a closer look at the local DC-DC converter. More precisely, we present a cost-efficiency analysis of different converter topologies. Taking into account practical limitations (economical limitations, number of components, maximum switch currents, maximum capacitance values, etc..) we estimate efficiency and projected cost. We show that Dickson pump (CR3) with 30-35m switches is the best candidate. This would result in a chip cost of about €1.5

ispartof: https://www.eupvsec-proceedings.com/ ispartof: 35th European Photovoltaic Solar Energy Conference - EU PVSEC location:Brussels, Belgium date:24 Sep - 28 Sep 2018 status: published

There is an increasing interest towards bifacial PV modules because of their potential to reduce the Levelized Cost of Electricity (LCOE) thanks to the additional energy yield obtained from rear side light collection. It is understood that bifacial module energy yield gain over monofacial modules depends on the complex interplay of several installation parameters e.g. ground reflectance, module tilt, installation height, row spacing, climate, system size, etc... Different combinations of these parameters may produce bifacial gains ranging from 5 to 50%. Unfortunately, the deep understanding, as well as design tools are – to date – not established for accurately assessing bifacial gain, causing uncertainty in field performance and difficulties in financing. The complex phenomenon of rear side light collection can only be addressed using physics-based approaches, among which, ray tracing has the highest potential of accounting to all of the important phenomena. Currently, ray tracing is computationally very intensive, which hinders its application for designing and optimizing bifacial PV systems. The present work proposes to use the Daylight Coefficient method (available in the open source Radiance 5 software package), which – next to preserving the detailed scene description and physical representation of light transport from the sky to the PV module surface – promises to reduce computational times by a factor of 1000 approximately. Daily simulations indicate that the time needed for annual irradiance simulations at 1 minute resolution can be reduced from 6 months (with ray tracing) to only 2 hours (with Daylight Coefficients). Analysis at specific days shows that Ray tracing and Daylight Coefficient-calculated front side irradiance values are virtually identical and rear side irradiance values differ only by 1-2%.