André Mermoud

Some answers to your questions: Module Mismatch Losses: Currently set to 1%. - This depends on the sample of PV modules you are installing. Not on the technology. String Voltage Mismatch Losses: Currently 0.1% - Idem, by the way this is an extremely small correction.. Module Quality Loss: Default. - This is a parameter at your disposal. You can put here what you want. But the default is based on the tolerance, it doesn't depend on the technology. LID Loss Factor: Set to 0% for N-type modules. It is indeed null for N-type cells. Otherwise the value should be set according to the manufacturer if available. For example, HPBC claims better shading performance — can mismatch losses be reduced? - This is indeed implemented in the ModuleLayout calcuation. But don't wait for a significant improvement of the shading loss ! (see the Help https://www.pvsyst.com/help/physical-models-used/pv-module-standard-one-diode-model/pv-module-reverse-lowvoltage.html?h=ibc Are there other parameters I should modify to better reflect these technologies? - If modifications are necessary, they will be in the PV module definition and modelling. We are currently studying this but we don't have definitive conclusions yet. The main workaround we can propose in the present time is to increase the Voc specified at STC when you cannot establish the one-diode model (i.e. when the RSerie cannot be specified for the required low-light performance).

Yes, sorry, I completely forgot mentioning this in my last post. The correction I had done in the program has not been taken into account for the published version 8.0.8. This should be corrected in the next version 8.0.9, to be released still this week. In the meantime, the only way of modifying this value is to set the parameter “Arev= 1000” directly in the PAN file. And with this PAN file you should not enter the page “Additional parameters” of the PV module definition dialog.

The energy stored in the battery during the year - mentioned on this Sankey diagram - is indeed the value calculated by the simulation for the actual battery capacity specified for this simulation. In the present time, the battery capacity decrease according to the ageing is not taken into account in the ageing tool (this feature is on our roadmap, but will not be implemented before several months). Therefore you can indeed perform a simulation for the last year of the battery life, with a battery capacity diminished by 20%. However don't wait for a big difference: the battery use during the simulation is not very sensitive to a diminution of 20%. NB: don't confuse the self-consumption with the capacity diminution, they have nothing to do with each other. The self-consumption may also be dependent on the age of the battery, but we don't have any information about this.

Answer to Kanagavel above. No, the ageing represents an ageing from year to year. There is no reason for being different during the first year. The first year differences should be accounted in other loss kinds like LID or Module quality loss.

Yes, the red behaviour indicates the global degradation to be applied for each year, taking the mismatch evolution into account. The black line is the warranty of the PV modules manufacturer, that you may define as you like. It is indicative.

Sorry, I don’t know what should be improved. The result is highly depending on your system. If more than 3 cells are shaded at a time within a submodule, you should not see any difference. Please carefully read the help https://www.pvsyst.com/help/physical-models-used/pv-module-standard-one-diode-model/pv-module-reverse-lowvoltage.html?h=ibc If your system is "regular", there are probably very few hours in the year concerned by this condition.

For the storage in batteries, PVsyst treats the AC production as a whole, without discrimination between inverters. But the problem is probably not here: as I understand you want to shift the PV production to hours where the tariff is more favorable. Sorry, this is not yet implemented in PVsyst. This will be done within some months.

The usual PV modules operate following the one-diode model, in the same way. The model covers the "extreme" conditions. There is no "special" behavior for some specific modules.

The LID loss is not related to the long-term degradation. The long-term degradation is applied to the module performance at the beginning of the simulation step. Now applying the LID loss before or after the long-term loss in the loss diagram has no real importance. However you are right: in the present time, during the simulation, the LID loss is accounted as a percentage of the degraded PV module, when it should remain as a percentage of the initial (not degraded) module. The error is very low, but we will correct this in the simulation for a next version.

The battery end of life is not a well-established criteria. As I said, the number of cycles guaranteed by the manufalctrers is sometimes based on 80% and sometimes on 70%. And the number of cycles you can accept for your own instalation depends on your requirements (kind or use of your system). We will consider to provide this as an option in a next version.

Please observe that the degradation specification of the PV module manufacturers is not the degradation factor. It is a warranty on the power of each PV module individually. The long-term degradation of the whole PV system is an average of the real degradations of all PV modules, which is indeed less than the warranty limit. Moreover, the LID is an initial degradation which has nothing to do with the long-term degradation. The initial value of this warranty curve (usually -2 or -3%) may represent sometimes the LID degradation, but also the uncertainty of the Power measurement (at factory) of each PV module. In PVsyst, the LID loss is specified independently in the "Detailed losses". It acts over the whole simulations (i.e. the whole life of the PV plant) as a permanent diminution of the real PV module efficiency. This is explained in detail in the help https://www.pvsyst.com/help/project-design/array-and-system-losses/ageing-pv-modules-degradation/index.html?h=degradation Now for the long-term degradation of a given year, the PVsyst simulation result represents the average degradation along this year, i.e. the average of the degradation value between the beginning and the end of the year. This is the reason why the degradation of the first year uses half the annual coefficient (and the next years use 1.5, 2.5, 3.5, etc).

The "loss" due to irradiance level is related to 2 factors: - The low-light performance of the PV module - The irradiance distribution along the period of simulation. Please check the low-light efficiency of your module ( PV module dialog, page "Model parameters => Rshunt-RSerie", option "Rel effic" 😞 The default of PVsyst (reasonable for most modules) is -3% at 200 W/m2. Now when distributing their own PAN files, most manufacturers set the Rserie parameter for boosting this value, to -2% or even -1% . In this case you have a large part of the curve with positive relative efficiency, i.e. a gain during the simulation at high irradiance.

The capacity slightly decreases when using the battery. The battery life (number of cycles specified by the manufacturer) is defined as the situation when the capacity drops below a given threshold. Traditionnally, this limit was usually 80%. Since some years, several manufacturers consider a drop down to 70% of the initial capacity. This is not always mentioned on the datasheets. The discrimination between input or output of the battery (efficiency, around 5%) doesn't make much sense as the uncertainty on the number of cycles is much much higher.

Thank your for sharing this very interesting experience of the real world when using batteries. However this is not really related to the simulation of systems by PVsyst.

This situation is fully explained in the help of PVsyst https://www.pvsyst.com/help/physical-models-used/grid-inverter/inverter-pnom-as-f-voltage.html?h=pnom The treatment of PVsyst is not exactly compliant with this specification, but the results should be close.

Please give some precisions about what you mean by "Night losses". You can define losses for feeding the auxiliary equipment (fans, HVAC, monitoring, etc) , which are usually drawn from the usual low-voltage grid. The Iron loss of the transformers is a completely different kind of "night" loss. In fact this is a permanent loss, acting as soon as your transformer is connected to the grid. When producing PV energy, this is substracted from the production. This loss may be suppressed by night, by installing a switch on the HV line.

The auxiliaries and night losses may be specified for the simulation, in the "Detailed losses" part, page "Auxiliaries". You have the opportunity of defining fixed values, with possibly a part proportional to the produced power, as the inverter losses will produce heat which has sometimes to be evacuated.

Sorry, this configuration of using the storage for shifting the delivery of power to anothe period of the day is not yet implemented in PVsyst. As a workaround for getting quantitative results, you can define a self-consumption system. You define a user's needs profile as the hours and power when you want to resell the electricity (this should be sufficient for completely discharging the battery). The results will give you the energy delivered to the user from the solar system, which is indeed the energy that you have reinjected into the grid.

Question 1: in PVsyst, the required power factor is fixed (yearly or monthly values). There is no dependency on the temperature. The inverter specification indicates wheter the Pnom is specified as Active power [kW] or apparent power [kVA]. In the inverter's definition, page "Output parameters": During the simulation, PVsyst will apply the PNom limit according to this definition. Question 2: In principle, the reactive power IS NOT a real power: you cannot produce movement or heat with it. Therefore the production of reactive power doesn't consume any active power. Now you talk about Reactive power generation during non-producing hours. This is a very special feature of some solar inverters. PVsyst doesn't treat this : the rective power is always generated proportionnally to the available active power.

If I understand well, you have a cluster of 8 MV transfos, and a line of 3 km up to the injection point or a HV transformer. You have probably a junction box, and a common line to the injection point. Sorry, this is not yet implemented as such in PVsyst. in the present time in PVsyst you can only define a line from each transformer individulally to the injection point. Therefore for each inverter you should define a line with a length of 3 km, but a section corresponding to the power of one transformer. In the future, we will implement the opportunity of defining a junction box, and a common cable transporting the global power of all MV transformers. Please see the help https://www.pvsyst.com/help/project-design/array-and-system-losses/ohmic-losses/transfo-in-cascade.html?h=mv+transfo for further details. NB: If you are working with the "relative" AC losses (i.e. defined as percentages), and you are waiting for a global loss of, say 1% for this 3 km line, you should define a loss of 1% for the line of each transfo.

In the loss diagram, the energies are always evaluated from the previous energy. In this case, the Stored energy sharing is evaluated from the charging energy rather than the discharging. You can evaluate the available solar energy as 20'443 MWh * (1-2.3%)*(1-0.5%)*(1-0.4%*(1-2.8%)*(1-1.0%) * (1-0.6%) = 18'933 MWh. Then: 18'933 MWn * 8.5% = 1609 MWh. This is the charging energy. The direct use is 8'933 MWh * 91.5% = 17'323 MWh. Here is the detailed calculation in EXCEL: you can check that the final result is very close to the loss diagram. NB: You can get the detailed calculations of the loss diagram directly in EXCEL. In the menu of the report, you can use "Export => Loss diagram values", that you can simply paste in EXCEL.

The energy provided by the Solar system may be used: - either for charging the battery, - or (mainly when the battery is full, but this depends on the kind of system) it is directly used, either for feeding the grid or the user's needs (this also depends on the system kind). This is what is named "E Direct Use", as a complement to "ECharging (from PV)".

This graph is the distribution of the output of the system, as a function of the output power. Each bin represents the total energy produced when the system is operating at the concerned power. Now if you have overload losses, these arise always at the PNom of the inverter (or the system). Therefore they are all accumulated in the class correspond to PNom. NB: when opening this diagram in "Detailed results => Predefined graphs", you have the opportunity of adjusting the vertical scale (up/down button on the top left of the frame) for getting a "usual" distribution plot.

Please check the definition of the PV module of your first simulation. The temperature behavior is certainly false. A temperature loss of 0.7% is completely out of expected range. Except of you are at th North pole, a temperature loss is always several percents. Your second simulation shows a a reasonable temperature loss.

When editing the report, please open "Report options" in the menu. Here you have the opportunity of defining the values you want in the monthly table. The TArrWtd value is not available on the report. You can get in in the detailed results, button "Tables". Here you can generate a table of monthly values with any chosen variable (option "Custom table").