André Mermoud

Module Quality Loss The Module quality loss is a parameter that should express your own confidence to the real module's performance, with respect to the manufacturer's specifications. It is at your entire disposal: you can put here any value (for example for keeping some reserve on the production warranty, or for somelong-term losses, etc). You can also put a negative value (corresponding to a gain) if you want to take the positive sorting into account. By default, PVsyst initializes the "Module Quality Loss" according to the PV module manufacturer's tolerance specification: PVsyst will choose a quarter of the difference between the lower and higher value. For example, with -3..+3%, it will be 1.5%, and with positive sorting 0..+3%, it will be -0.75% (i.e. a gain). NB: This value of a quarter between low and high tolerance is our own choice. We usually consider a conservative option (i.e. the modules will never be better than announced). I doesn't have any other background reasons. LID Loss The LID (Light Induced Degradation) loss appears in the first hours of the exposition to the sun. It is due to the quality of the si-Crystal, only for p-type wafer cells (i.e. traces of oxygen which recombine with doping centers). The one-diode model in PVsyst is based on the STC of the datasheets. You can apply a LID loss afterwards, in the "detailed Losses". By default in PVsyst, the LID losses are ignored (null), you should specify them explicitly in the "Detailed losses". It is not possible to set an "automatic" reasonable value, because some modules are not subject to the LID. On the other hand, PVsyst doesn't automatically put the manufacturer's value, as few manufacturers specify this value, so that they would be penalized. NB: At the output of the factory, the modules are sorted according to their effective (measured) STC values, and attributed to the corresponding Power class. Therefore the STC real values of the modules is accounted before LID.

The mismatch parameter concerns the electrical differences between the modules in an array. It reflects the fact that in a string of modules (or cells), the lowest current drives the current of the whole string. The mismatch is computed by adding the I/V characteristics of each module, in voltage for each string, and then in current for each string in parallel. After that it recalculate the final Pmpp on the reswulting I/V curve. Mismatch loss evaluation for modules characteristics dispersion The discrepancies are mainly the dispersion of individual I/V characteristics, ideally as measured at at the output of the factory. There is a tool for understanding, and statistically estimating the corresponding loss (button "Detailed calculation"), according to your effective distribution of "real" modules. This loss is a parameter that you have to fix in the simulation. This mismatch effect evaluation is a stochastic process, which cannot be very accurate. For crystalline modules, and a usual dispersion (RMS) of 2.5%, the tool (histogram on numerous calculations) will show an average loss of the order of 0.5%. However things are not so simple, because: - The modules may evolve (differently) after the installation (namely due to LID). - Any flash-test manufacturer will tell you that with the best Laboratory instrument (class AAA) you cannot wait for an accuracy much better than 2%. Now instruments used in production at the output of the factory have probably a much higher uncertainty, of 3% or more... With a RMS = 3% the mismatch loss will be of the order of 1%, and increases quickly with the RMS value. Proposed default value A recent study using results with "measured" optimizers on several dozens of PV systems seems to indicate that the real mismatch on the field is of the order of 2 to 2.5%. Therefore with the version 7, we set again the mismatch loss default value to 2%. In the version 5, this default was proposed as 2%, in accordance with most of the orther software. In the version 6, PVsyst proposed a value of 1% (reduced due to the narrow tolerance in the modern PV modules deliveries). But there is no "absolute value" of course. You can put here the value you can estimate according to your sample of modules. NB: You can improve a little bit the mismatch loss by sorting the modules of comparable powers (or ISC) into the same strings. However this doesn't apply to the Flash-test uncertainty (which is a main contribution of the Manufacturer's initial data error), and is only valid at the commissioning time. Mismatch between strings The distribution of wire lengths for each string of a sub-array induces in a voltage distribution at the MPPT input. This is namely to be analyzed when consdering central vs string inverters. However the I/V calculations show that the mismatch losses between strings of "reasonably" different voltages are very low. The discrepancies between these 2 options (central vs string) are of the order of 0.1 %. See How is treated the gain of string inverters with respect to centralized ones?. Mismatch and Ageing The tool "Degradation" tries to take the discrepancies in long-term degradation characteristics between modules into account. PVsyst proposes a mechanism (Monte-Carlo random process) for this evaluation. But sorry, the default values for the Mismatch evolution parameters are completely uncertain (only from my own "guess"). I don't know any study about the differential ageing between modules. The only available (and reliable) studies measure the real degradations of some very few modules, and find a degradation of around -0.3%/year as an average. I have chosen the default values for mismatch, in order to stay within the usual manufacturer's warranty after 20-25 years for a single module. In the results, the ageing mismatch loss is part of the general "Mismatch" loss. Mismatch due to partial shadings The mismatch due to shadings is accounted in another part, i.e. the calculation of the electrical shading loss. You have an "accurate" estimation with the "Module Layout" tool, or a more generic and incertain with the "according to module strings" mode. Now the electrical loss resulting from the I/V characteristics behavior under partial shadings is not only attributable to the electrical mismatch. There are two unrelated significant contribution: - When a few cells are shaded in one sub-module, the other cells receive indeed some irradiance, which cannot be used and is completely lost. - When a sub-module is shaded and the current is forced above its Isc value, the by-pass diode is activated. It consumes some energy (V diode * I string), provided by the rest of the array (therefore a loss). These 2 kinds of losses are not recoverable in any way, even with power optimizers at the module (or sub-module) level. Mix of different module samples It is sometimes necessary to mix some modules of different power classes on a same inverter input. This may be accounted for by defining an additional "Mismatch" loss contribution (to be added to the "normal" mismatch loss factor). However the effect of the mismatch between different strings (i.e. the voltage mismatch) is very low. Therefore you can simply perform the simulation with the higher module, and add a mismatch contribution corresponding to the weighted difference between the nominal powers. As an example: if you have a sample of 30% modules of 250 Wp, and 70% of 255 Wp (i.e. 2% difference), you can perform the simulation with the 255 Wp, and define an additional mismatch of 2% * 30% = 0.6%.

The wiring loss is computed using the equivalent Wiring Resistance Rw of the whole array as basic parameter (calculation R * I² at each hour). This resistance is calculated "as seen" from the inverter input, i.e.putting all strings, connected to all MPPT inputs of a sub-array, in parallel. This parameter may be determined in 3 different ways: - At an early stage, you can specify a generic loss as a percentage at STC conditions (default value 1.5%). - Then you can calculate this resistance of the array's wiring by yourself according to the effectve wiring properties of your system. - You have a tool for the evaluation of this resistivity (button "Detailed losses"). This tool asks for the average wire lenghts, allows to determine the wire sections at each stage, for a given loss target at STC. It also evaluates the copper mass, and eventually the wiring cost of your plant. You can define here intermediate junction boxes between strings and inverter inputs. NB: Wiring losses behave quadratically with the current (R·I²). The loss at 500 W/m² will be half the loss at 1000 W/m² (in %) or a quarter (in [W]). Therefore the yearly energetic losses may only be evaluated on an hourly basis during the simulation, and is depending on the power distribution. The energetic loss appearing in the arrow loss diagram is usually far below your STC definition (in %). The Yearly/STC loss ratio is usually around 60% for the middle-Europe systems.

I already had contacts with some manufacturers about this subject. This is not a simple problem as the procedures and specifications are not harmonized between manufacturers. If a relation between the ambient temperature and the Pmax were specified, it would be possible to take this into account (but not done in PVsyst now). This applies only for inverters installed outdoor. If the relation is given by respect to the device temperature (or the ambient around the inverter installed indoor) , this depends not only on the short "history" of the PV power, but also on the whole thermal behaviour of the building (ventilation, insulation, cooling mode of the inverter, etc). This is out of the scope of the software. Therefore in the present time output AC powers above the Pnom value (up to a specified Pmax) are not implemented in PVsyst. This may give a little bonus by respect to the simulation, especially for installations with very under-sized inverters. By the way, in highly undersized-sized systems the AC power limit is often motivated by a contractual limit with the grid manager (very rarely by the cost of the inverter). In these cases such a strategy of adapting PMax is obviously useless.

PVsyst is not suited for the study of any concentrating PV systems. Only the high concentration systems (CPV) are treated under some conditions (see below). Modelling concentration with sufficient accuracy and generality is a very difficult task, which requires probably a research project by itself. - The irradiance acceptance is strongly dependent on the real mirrors geometry and quality, and also on the exact irradiance angular distribution, which is usually not available in the PVsyst meteo models (should include variables like turbidity, humidity, etc). - The PV module or cells performances are strongly related to the irradiance distribution and its homogeneity. - It involves an accurate description of the mechanical structure and its control (a little tracking error may have drastic consequences), - The results are closely related to the beam part of the meteo, which should be known with precision. This is not the case with the usually available meteo data and models. Example: several months after the Pinatubo eruption, the high concentrating power plants in USA observed losses of 30% while the global irradiance only dropped by 2% ! Therefore concentrating is not foreseen in PVsyst at the moment in whole generality. Only the high concentration (500x) has been developed up to now (in collaboration with one specific user), as it doesn't involve special effects on the diffuse, simply it withdraws it. But this involves a doubtful model for the PV module, which is assumed as a "flat" module of the size of the mirror's aperture. The PVsyst model for cells has not been extended to high irradiances of 500 suns, and the optical effects in the module's parabolic mirrors is too specific to each product for being modelled in generality here. Several adjustments of the one-diode model have been stated by experiments and are available in the present version (derates according to DNI, air mass and ambient temperature). Without a close cooperation with the manufacturer, it is probably not possible to establish the parameters of this approximated model for the module.

When you choose two or several different orientations in the "Orientation" parameters, you will have, in the system definition, the opportunity of defining a sub-array with a "Mixed #1 and #2" orientation. The mixed array allows the definition of strings in both orientations, connected to the same inverter. During the simulation the I/V characteristics of strings in both orientations will be mixed. PVsyst accounts for the mismatch loss, which is the difference between the MPP of both sub-fields independently, and the MPP of the mixed I/V characteristics. When mixing I/V curves of strings with comparable voltages (i.e. same number of modules in serie), the mismatch is very low. However when putting modules of a same string in 2 different orientations leads to a the mismatch in current (due to different irradiances), which may be very important. This would be a very bad system and PVsyst doesn't allow it. This configuration would only be acceptable when using optimizers performing MPPT at the module level, but this is not yet implemented in PVsyst. NB: In the version 5, you can define only 2 different orientations in a given system (option "Heterognous orientation"), and 3 different kinds of sub-arrays: Orient#1, Orient#2 and #Mixed (for both orientation on the same inverter). If you have more orientations you should define different sub-systems and perform different simulations.

The inverter power sizing is not a trivial task. In the system definition dialog, the button "Show Sizing" opens a summary of all sizing conditions, dynamically bound to your definitions. The upper diagram shows the voltage limits for the number of modules in series: They also show in violet eventual current/power limitations of the inverter specifications, which are not mandatory, except if they are contractual (i.e. if they act on the warranty). The lower histogram shows an estimate of the power distribution available at the output of the array in your meteo and orientation conditions. If the inverter is of good quality, it will limit its power simply by displacing its operating point on the I/V curve of the array. In this way, the over-power has not to be dissipated: it is simply not produced. Therefore there is no technical danger to apply an oversized PV array to an inverter, this may operate at some occasions over its nominal power without problems. The diagram shows that even for undersized inverters by respect to the high-power edge of the distribution, the annual loss may stay very low. The optimal inverter sizing will correspond to a yearly loss between 0.2 and 3%. Above this limit the normal process considers it as unacceptable, but you can change this limit. The usual values of the PnomArray(DC)/PNomInv(AC) ratio are of the order of 1.25 to 1.30. This ratio is depending namely on the plane orientation: with a façade system, the maximum power is 2/3 of the maximum at 30° south. NB1: The nominal power at the DC input of the inverter is higher than the Pnom(AC), by a factor of (1/Efficiency). NB2: In this tool, the overload loss is only a quick estimation according to this histogram. The loss calculated by the detailed simulation will usually be lower, as the simulation takes other losses into account in the array behaviour.

In PVsyst, the criteria for the sizing of the inverter with respect to the array nominal power is to evaluate the foreseen yearly overload loss. Losses up to 3% are considered acceptable (warning "The inverter is slightly undersized in orange). Higher annual losses prevent performing the simulation (warning "The inverter is strongly undersized in red). Array sizing limitation For some special uses (for example output nominal power constraints for tariff, Grid power limitation, economical optimization, etc), you can modify this limitation. In the version 5: in the main menu, please choose "Preferences" / "Edit hidden parameters" / topic "Detailed Simulation Verification Conditions". Here you can increase the value "Limit Overload loss for design", which is fixed at 3% by default. in the version 6, the definition of this limitation has been moved in the Project's definitions, (so that it is valid for the project, not for the full software). When you are in the Project's definition, please press the button "Project settings" Be careful !!! When defining highly oversized arrays, the voltage displacement on the P/V curve of the array may overcome the VmppMax of the inverter, and in this case the system has to stop and the loss may become catastrophic ! With such systems you have to work at rather low voltage. Inverter limitation It is also possible that you get the error message: "The array maximum power is greater than the specified Inverter maximum power (or current)". Some Inverter manufacturers specify a maximun Nominal Power of the array connected to their inverter, or a maximum current (ISC value of the array). To my mind this is not really meaningful, as the operating power is controlled by the inverter input circuit, which will manage for not overcoming the limit values (power limitation by moving along the I/V curve). These values are not used during the simulation. If this messages appears in blue, no problem, it is just an information. If this message is in red, with the mention (contractual condition), it means that the manufacturer submits the warranty of his product to this condition (i.e. overcoming these values will cancel the warranty). Therefore PVsyst will prevent defining such a configuration. Now this "warranty" information is specified in the inverter's specifications, by a checkbox "Required" for the "Maximum PV Power (or current)". If desired, you can uncheck this checkbox, and save the inverter (under another filename). In practice, this is under your own responsibility.

There is indeed a problem with such inverters like the Tripower series of SMA, which have 2 different MPPT inputs: one for the main part of your system (usually 2-3 strings), and a secondary one where you can put the "remaining" of your modules in one string. With Version 5 PVsyst V5 is indeed not foreseen for treating such assymmetric MPPT inputs, and you will have Power limitation conditions. Nevertheles you can overcome the problem by modifying the number of MPPT inputs in the inverter definition. Please redefine your inverter with a number of MPPT inputs equal to your total number of strings (and save it under another file name). After that, you can define one "main" subfield by (N-1) strings on (N-1) MPPT inputs, and the remaining string on the last MPPT input. In the reality, the strings of the (N-1) first inputs will of course be connected together on the main "physical" MPPT input. With Version 6 This has been implemented: such inverters with unbalanced inputs have a "Main" and a "Secundary" input. In the "System" definitions, you should define 2 sub-arrays, one involving the "main" input (with usually several strings, all identical) and the other one the "Secondary" input (with usually one string, i.e. the "remaining" modules of the system). If you have several inverters, you can define several "Main" and several "Secondary" inputs of course, eventually in sub-arrays of different kinds. But be sure that for each inverterthe whole system is using both Main and Secundary inputs (identical total numbers). If you get a warning about the eventual oversizing: If the inverter is "slightly" undersized (orange warning), no problem, you can perform the simulation. If the inverter is "strongly" undersized (red warning) , you can modify the parameter for this warning, in the project's parameters, button "Albedo-Settings", item "Limit overload loss for design". This is not necessarily significant, because: - at the design time, the "nominal power" sharing between both inputs (for design criteria) is done according the the limit input current ratio of each input (for ex. 50A:12.5A, means 4:1 ratio). - at the simulation time, the power sharing is adjusted according to the nominal powers of the modules effectively connected to each input, so that the overpower conditions will be met by both inputs in the same operating conditions. This is probably nearer to the real behaviour of these inverters. You should perform the full simulation for getting realistic results. Example of use (version 6): Suppose you have to build a PV system using 155 PV modules of 250 Wp, i.e. 38.75 kWp. 1. - Choose the inverter(s), according to a reasonable PNom ratio of 1.25: you need inverters for PNom(ac) = 38.75 kW / 1.25 = 31 kW. 2 inverters with unbalanced MPPT, of PNom = 15 kW should be well suited. 2. - In the "System" part, Define 2 sub-arrays, 3. - First one: define "Main" input with 6 strings of 20 modules (i.e. 120 modules), and 2 "Main" inputs: you get a PNom ratio = 1.25, quite correct. 4. - There are 35 modules left to be attributed. This will correspond to 2 different "Secondary" inputs, so you have to increase the number of sub-array to 3. 5. - Sub-array #2, define 1 "secondary" input, and attribute 18 modules. 6. - Sub-array #3, define 1 "secondary" input, and attribute 17 modules. 7. - Now the Warning "The inverter power is strongly undersized" appears in red, because the Overload loss in over 5% (depending on the meteo). You have to increase the "Limit overload loss for design" in the project's definitions. Now your system is ready fort the simulation. NB: in the present time, with Unbalanced MPPT inputs you have to define one Main and one Secondary input for each inverter. However it seems that some manufacturers now allow for not using the secondary input, so we will suppress this requirement in a next version. NB: Some people want to use these inverters with unbalanced inputs with only one input. Although this seems to be allowed by some manufacturers, you are not advised to do that. Up to version 6.32, PVsyst required that you use each Main and each Secondary input of all inverters. If you wanted to define a configuration using one only input, you had to redefine a new inverter in the database, with only one MPPT input. Since version 6.33, you can inform PVsyst that you are using only the "Main" input using the button "Adjust".

The nominal power Pnom is the maximal output ac power of the inverter in any conditions. Some manufacturers define a maximum power Pmax , which is the maximum power attainable under specific conditions (they sometimes say "half an hour", but it is probably related to the temperature of the inverter). Now this temperature is very difficult to estimate, this would require a complete knowing of the environment of the inverter, ventilation conditions, etc. This is not done in PVsyst, and therefore the maximum power cannot be taken into account. By the way in "normal" systems correctly sized, this bonus is probably low. And in "strongly oversized array" systems, the maximum output power is detemined by the contractual acceptance of the grid, and this bonus doesn't apply. NB: perhaps in a future version, PVsyst will be able to take the Pmax value into account for inverters installed ourdoor. This will require additional specifications about thermal behaviour from the manufacturers.

In the database, bi-polar inverters are defined by the mention "Bipolar inputs" in the technology specifities box. With the bipolar inverters and in the system sizing tool, the voltages are clearly indicated with the +/- mention. The number of modules in series correspond to the full voltage (i.e. 600 V for +/-300V indications). The module Vmax should perhaps be modified. The module's datasheets usually specify that the module should not be implemented in installations overcoming 1000V. But it is not clear if this limit is applicaable to the full differential voltages in the system, or only the voltage by respect to the ground. You should contact the module's manufacturer for assessing this limit.

InvLoss Global inverter loss - This is the sum of all inverter losses. IL Oper Inverter Loss during operation (efficiency curve) - The inefficiency loss, computed according to the efficiency curve. IL Pmin Inverter Loss due to power threshold' - Loss when the power of the array is not sufficient for starting the inverter. IL Pmax Inverter Loss due to power overcharging - When the MPP power is over the input power required for obtaining the specified PNom(ac), the inverter displaces the operating point on the I/V curve in order to get exactly the required power for Pnom(ac). This IL Pmax loss value represents the difference between the Pmpp and this adjusted power. NB: The displacement is towards higher voltages. If the voltage exceeds the Vmaxmpp limit of the inverter, the inverter has to stop, and the Pmpp is fully lost. IL Vmin Inverter Loss due to low voltage MPP window IL Vmax Inverter Loss due to upper voltage MPP window - If the Vmpp is outside of the inverter's window (Vmppmin/VmppMax) the inverter will clip it to the limit value. This loss is the difference between Pmpp and the corresponding P of the I/V curve at the limit value.

You have defined Transformer losses. When connected to the grid, the transformer consumes some energy (iron losses), explaining this night negative energy. You have the opportunity of disconnecting the transfo during the periods when the inverter is OFF (in the rreality, this means a HV automatic switch on the grid).

We will organize courses as Webinars soon.

What do you mean by "3-dimentional 2-axis tracking systems" ? You can define 2-axis systems in the "Orientation" part, and for mutual shading calculations in the "Near shadings" editor.

This negative value is rather low (around 0.3% of Pmax) The simulation is performed on a complete hour, and therefore also the "Night disconnect" function. Now in for one hour the PV production doesn't compensate the iron loss of your transformer, you can have a negative balance over the whole hour.

PVsyst is developed under DELPHI, which is closely related to Windows. It cannot be run under other operating systems.

This is explained by the fact that - The mismatch loss is computed as a a percentage by respect to the STC power at each step. - The result in the loss diagram is displayed as the percentage of the remaining energy after the preceding loss. Therefore the reference is not the same so that the percentage changes between the parameter definition and the results. In your case, when increasing the Thermal loss, you increase the difference between the STC value and the remaining energy. NB: This calculation according to STC is not quite meaningful (it is an historical choice). In the future version 6 the loss will be computed by respect to the remaining energy, so that the Loss result will correspond to the specified loss parameter.

No sorry, in PVsyst you can simulate a mix of 2 orientations on a same inverter input (Orientation option "Heterogeneous fields"), but not 3. The only way (approximation) would be to simulate two orientations in a simulation with heterogeneous fileds, and perform in independent simulation with the third orientation. For doing this with this particular inverter you can redefine your inverter as 2 different devices: one with 2/3 nominal power, and another one with 1/3 (or the shares of your different arrays). In this way the mismatches between string 1+2 and string 3 will not be taklen into account; but their influence is probably not very high.

The transposition model (and therefore the gain) is highly dependent on the diffuse fraction in your meteo data. Please carefully check these values (in the Meteonorm data of PVsyst, you have 38.6% of diffuse in Bamako, and 35.2% in Marseille). The transposition values given by PVsyst are usually considered as realistic. Now we don't know how the manufacturer's data have been established.

PVsyst doesn't take the altitude correction for inverters into account. The correction - when necessary or specified by the manufacturers - is mainly related to cooling capabilities (air pressure) and results in a diminution of the Nominal outpout power. If you want to take this into account, you have to redefine your inverter with a new Pnom corresponding to your altitude (i.e. change the value, and save your inverter under another file name).

You can download the program PVsyst V 5.xx (last version) from www.pvsyst.com, and install it. It will run during 30 days with full possibilities, and then revert into DEMO mode. For getting your licence, please open our site www.pvsyst.com, and choose "Order" / "Purchase online" - You can pay directly by credit card. In this case we send you back your activation code, along with a paid invoice. - Or you can pay by bank transfer. When we receive your order, we send you back the invoice (valid 30 days), and we send the activation code as soon as we receive the payment. This may usually take 1 to 3 days.

The "Local number" is an identifier of your PVsyst installation on a given machine (more exactly a given Windows installation"). It is established by PVsyst: you cannot change it. You can find the "Local number" in the main menu "License" / "Code and Activation". You need an "Activation code" matching this "Local number" for using the program.

With version 5.xx There is a tool in PVsyst for transferring the code from one machine to another one. After installing the software on the target machine, please carefully read the "Local number" produced. Then you come back to the original (licensed) machine, open the tool ("License" / "Transfer to another machine"), which will ask for the new Local number and will deliver the corresponding code. Please note it carefully, and keep this information for the future. After that, the original machine will turn itself into DEMO mode. This procedure may be performed as often as desired. With version 6.xx In the main menu, open "License" / "Status and activation", press the button "Transfer" and follow the instructions. You will have to deactivate your license on our server, and then you will be able to reuse it on any other computer. NB: You will need your "Customer ID" for performing this transfer, which is mentioned on your invoice or the mail containing your activation key. If the computer where the license was activated is unavailable (reformatted, lost), you have to contact our administration admin@pvsyst.com, and explain the problem.

Please open PVsyst (at least once) with full administrator rights, i.e. by right-clicking the icon and choose "Run as an administrator". If this doesn't work, please ask your IT specialist to do so (with full administrator rights).