André Mermoud

I have found the problem. It is related to the Internationalization parameters of Windows. I have corrected it in the latest version 5.63. Hoping this corrects this problem for everybody...

PVsyst doesn't avail of a model for generating hourly values of wind velocity (I really don't know how to generate such data). Therefore the values cannot be imported from Daily values ,and the reslut is 0 I could indeed envisage to put the daily value as constant over the day. I will think about this for a next version.

The 3D shadings part doesn't recognize field orientations as "different" when the angle difference between their true orientation is less than 3°. You can modify this limit of 3° in the main menu "Preferences" / "Hiden parameters" / "Detailed Simulation Verification Conditions", topic "Shadings: max orientation difference between shading planes". NB: the "true" orientation is calculated in the 3D space by the scalar product between both orientation vectors. For example, if you have 10° tilt planes with 16° azimth difference, you have an orientation difference of 3°. This value is shown in the "Orientation" dialog, label "Angle between planes". NB: With such a low difference in orientation, you can also avoid using "heterogeneous planes" and choose a single average plane (say, at 8°oriention).

You can get such specific data from the companies SolarGIS or 3Tiers. If so, you should ask for the data in the PVsyst standard format. But these data are for pay.

I don't know exactly what you are doing. PVsyst cannot treat data of less than one day. If so the missing hours of the day will be filled by zero values. But in the Comparison tool (if you are using it) it is possible that the 4-hour sample leads to a crash. Please let me know the details of your problem (screenshot of the whole screen) when the error occurs.

The Photon database web format has indeed changed in June 2012, and this change has been taken into account since the version 5.58. If you reinstall PVsyst over your old installation you don't need a new code nor transferring your license. However if you have reinstalled it in another disk you should indeed ask for a new code.

You have to redefine your inverter as a device with 5 inputs, one for each string. After that you can define a system with 2 subfields: one with 4 strings (MPPT inputs) and one with 1 string. Please see "How to use inverters with very different MPPT input like SMA tripower ?"

Please explain what doesn't work with the import of PV modules. Be aware that the PHOTON database is not perfect. Sometimes some parameters are missing, so that PVsyst is not able to use the concerned module. Please carefully read the warning when importing the module. Which browser are you using ? Currently Internet Explorer, Firefox and GoogleChrome work quite well.

Yes of course. A single silicon cell has usually a Vmpp of about 0.5-0.51V at 25°C (up to 0.57V for the special Sunpower technology). The Sunpower modules of 435 Wp have 128 cells in series.

Did you read the first answer to this post ? What is still unclear ?

As mentioned in the help, we propose a model (energy balance) for the determination of the PV module temperature during the simulation, but we don't have assessed values for the parameters. The parameters Uc and Uv are to be specified by the user. They are highly dependent on the layout of the system and the wind measured values (just above the plant or meteorological at 10m). But we don't avail of reliable long-term measurements for these parameters in any conditions (free, insulated, with air duct, as function of the tilt, etc). The only values proposed are according to my own measurements on 2 or 3 installations, or the values proposed by a third party in the US for free-standing disposition: Uc = 25 W/m²·k, Uv = 1.2 W/m²·k / m/s But I am not able to provide evolution as a function of the tilt angle. To my mind, theoretical air circulation thermal models may help, but are not sufficiently reliable. This should be measured on-site (the parameters may be extracted from long-term measurements of TAmb, Tarray, Ginc and Vind velocity).

I don't have definitive answers. Which version are you using ? Until version 5.57, there were an error in the simulation process: when the Vmpp was lower than VmppMin (il_VMin loss), the overpower was not checked. This may have some effect in systems with low Vmpp value (by hot conditions). Since 5.58, this has been corrected: The overpower increases the Voper value, and is comptabilised first. Usually this brings the Voper over the VmppMin value. Now with highly oversized arrays and high Vmpp (more modules in series), you have the risk that the overpower correction leads to an operating voltage higher than VmppMax, and in this case the inverter has to stop completely (it cannot find a suitable operating point), leading to high overpower losses. The losses at very low irradiance are quite normal, I don't see where is the problem.

The exact term should be "Controller" indeed. I kept the term "Regulator" (from french) for historical reasons up to now. The functions of this device are: - management of the battery: cut the PV array when full, cut the load when empty. - eventually perform power management (MPPT or DC-DC controller). The inverter for delivering AC power to the user is not comprised in this device, and is not defined in PVsyst in the present time. The PVsyst load definition is specified in terms of energy needs. If you are using an inverter, you should take its efficiency and stand-by consumption into account externally.

The first assessment in red is indeed strange. It should be a warning in orange. The lower limit of 78 Strings corresponds to a PNom ratio (Parray/Pinv) = 1, which is a reasonable minimum. Usual Pnom ratios are of the order of 1.15 to 1.25 (see below). The upper limit is not clear, probably the specified available area. I have to check in the program. But the second warning “The inverter power is slightly oversized” is quite justified. Please see - the help "Project design > Grid-connected system definition > Inverter / Array sizing" (directly accessed by the little orange button right top of the box), - our FAQ on this forum What is the basic concept of Inverter sizing ?, - The tool "Show sizing" just next to your message. Now for the use of special inverters of the SMA series "tripower", please see How to use the inverters with very different MPPT inputs (Tripower of SMA) ?.

You have 2 possibilities: - either use the dedicated tools in the main menu "Files" / "Export whole projects" and /"Import whole projects" and "Export/Import database components". (see How to export/import projects or database components), - or copying the whole working directory (see Where are stored my working data of PVsyst ?).

>> Tools >> Solar tool box >> Tables / graphs of solar parameters >> is only a accessory tool, it is not the heart of thre program. And indeed I did not include the tracking calculations in this (very old) tool. I plan to do that in a "medium" future. For definig tracking systems, you have to define a full system, i.e. option "Project design". In the calculation version, button "Orientation", you have the opportunity of defining various kinds of tracking systems. You can also define tracking systems in the 3D editor, button "Near shadings". Now I don't understand your request: if you want irradiance "normal to the plane" you can't have a fixed tilt of 50°: at a given time, the plane tilt will be 90° - sun's height.

In PVsyst the time labels always correspomd to the beginning of the interval. See the FAQ on this forum How is labelled the time step in PVsyst ?

In PVsyst, the meteo data may be specified in 2 kinds: - SIT files, which define the location of a site (Site name, Country, Latitude, Longitude, Altitude, Time zone). In addition the Site includes meteo values (at least Global horizontal irradiation and temperature) in monthly values. - MET files, which define meteo data in hourly values. NB: The MET file includes an internal SIT object for the determination of the location. Now within a project, you begin by choosing a location, i.e. a site in the database. Then you choose a MET file for the hourly meteo data which will be used in the simulation. You can choose this MET file in your MET database if you avail of a specific meteo already imported from a given meteo source. If not, PVsyst will automatically create a synthetic file based on the monthly data of your project's site. The montly values of the SIT file of the project are not used in the simulation process. But they are important for 2 reasons: - If you don't avail of meteo hourly data, they will be used for the Synthetic generation, - Although not necessarily identical to your MET data, these values should be existing and realistic as they are used in the sizing tools like the orientation optimization or the histogram for the sizing of the inverter (i.e. only used for decision makings during the sizing process).

The thermal behaviour of the field - which strongly influences the electrical performances - is determined by an energy balance between cell's heating up due to incident irradiance and ambient temperature: U · (Tcell - Tamb) = Alpha · Ginc · (1 - Effic) where Alpha is the absorption coefficient of solar irradiation (or identically 1 - Reflexion), and Effic is the PV efficiency, i.e. represents the electrical energy removed from the module. The usual value of the Absorption coefficient Alpha is 0.9. It is eventually modifiable in the PV module definition dialog. When possible, the PV efficiency is calculated according to the operating conditions of the module. Otherwise it is taken as 10%. The thermal behaviour is characterised by a thermal loss factor designed here by U-value (formerly called K-value), which can be split into a constant component Uc and a factor proportional to the wind velocity Uv : U = Uc + Uv · v (U in [W/m²·k], v = wind velocity in [m/s]). These factors depend on the mounting mode of the modules (sheds, roofing, facade, etc...). As we don't have reliable coefficients for wind velocity (and the wind velocity is often not well assessed in hourly values), PVsyst proposes as default to take a fixed U-value (i.e. assuming a constant wind velocity). For free circulation around the modules, our measurements show a value of 29 W/m²K. This coefficient refers to both faces, i.e. twice the area of the module. If the module is thermally insulated on the back, the second face doesn't contribute, and we have half this value, i.e. 15 W/m²K. Intermediate cases with air circulation duct may have values from 18 to 25 W/m². We don't avail of assessed measurements. NB: Some people use the NOCT concept. You can get an equivalence between U factor and NOCT values by inputting the NOCT conditions in the above thermal balance. But to my mind this is confusing and should not be used. Measurement of Uc and Uv The measurement of these parameters is possible by using long-term data recorded on-site (several weeks or months). You should avail of measurements of the Module temperature, the ambient temperature, the irradiance on the PV plane, and eventually the wind velocity. You can plot the (Tarray-Tamb) difference as a function of the irradiance (may be negative during night by clear conditions, due to IR deficit with sky) Then you can extract the parameters from a bi-linear fit (with wind) or simple linear fit (without wind, Uv=0). PV array temperature measurement: According to our experience, the PV module (cell) temperature may be recorded using a temperature sensor (thermocouple or PT100) glued or fixed with thermal grease on the rear side of the PV module, with a 1 cm thick polystyrene cover of 7 x 7 cm2. The size of the thermal insulation is a compromise between a good insulation of the sensor with respect to external (in order that the heat flux is negligible), and the local perturbation of the local PV module temperature due to this insulation. This mounting mode optimization results from a diploma at the University of Geneva, where we had a special module with a thermocouple on the cell, included in the encapsulation, so that we had a reference for performing differential measurements. NB: Ensure a good mechanical "external" fixation of the polystyrene piece (a simple adhesive tape is usually not sufficient at medium or long term). NB: Some people propose to add 3°C to the rear-side measured temperature for taking into account the temperature drop due to a heat flux from the Cell to the sensor. This would be valid if the sensor is not recovered by an insulation. In this case we don't know what is really measured by the sensor: an intermediate temperature highly depending on the ratio between the heat resistance in the rear sheet, and the sensor with respect to the ambient. Moreover the difference between cell and sensor is obviously proportional to the heat flux, i.e. the (TArray-TAmb) temperature. Therefore I can't understand this fixed correction of 3°C. Please see the help about this subject ("Project design > Array losses in PVsyst > Array Thermal losses").

Some practicians - and most of PV module's catalogues - usually specify the NOCT coefficient (Normalized Operating Cell Temperature), which is defined in IEC 61836: it is the temperature attained by a PV module in specific conditions (800 W/m², T=20°C and wind speed=1 m/s), and this for a non-operating situation (open circuit), for a "nude" rack-mounted module with free air ventilation. Please don't use the NOCT approach, which is very confusing, but define a Heat Loss Factore U [W/m²K] for your PVsyst simulations. For me the NOCT value for a module is only dependent (slightly) on the cover (glass) and back kind of the module (glass, plastic), and is useless for the module temperature evaluation. This is the reason why I did not include it in the PVsyst parameters. As a confirmation of this, a team of the NREL in the USA measured side-by-side, at sun during several days, 3 modules with resp. 42.4°C, 49.7°C and 52.3°C NOCT manufacturer's values, and these 3 modules showed exactly the same temperature within 0.3°C ! On the other hand, the NOCT doesn't include any information about the mounting mode (free ventilated, integrated and insulated, etc). It is always given for a "nude" module. Moreover is is defined for open-circuit conditions, i.e. not-operating conditions; this doesn't make sense as the produced energy affects the energy balance. If you apply the U-value thermal balance equation to the NOCT conditions, you will obtain an equivalence between the U-factor and the NOCT for specific conditions. But this doesn't make much sense, and is very difficult to interpret. Please completely forget the NOCT approach !!!

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.