André Mermoud

To my knowing this works quite well since a long time (probably more than one year). Previously there were slight over-powers in some very special conditions (some very few hours in a year). We have to analyze this. Please send us your full project, using "Files > Export project", to support@pvsyst.com.

No, it is not possible. In the present time PVsyst doesn't provide an API. The only way of performing several simulations with different parameters is the Batch mode (managed by an EXCEL file)

No. The Module Quality Loss is a constant factor, applied as constant derate factor at each step of the simulation. If you define a negative loss factor (for accounting for the positive sorting), this will give a gain. The tolerance is mentioned in the PAN file. This doesn't mean that it is accounted for in the simulation. Its only use in the software is indeed for the default of this parameter.

We have completely reviewed the management of SolarEdge products. This includes these new optimizers. This is now in version 6.64.

I am really aestonished about the Satellite data of 1957... This was just the year of the launching of the first satellite Sputnik (which was just able to send bip-bip-bip to the earth) !!! Are you sure you have read this in Meteonorm data ? For which site ??? Now the DLL presently imbedded in PVsyst (V6.62) is Meteonorm V 7.1. You can have slight differences with the nes Meteonorm V 7.2, as the models and database have been improved. Please have a look on the documentation on www.meteonorm.com.

When I developed the Histogram (a long time after the mismatch tool) I probably did not remember this option of cells mismatch, and I have not programmed it. In this case of cells within a module, the I/V characteristics plot is interesting, but the histogram is not really useful. By the way, I really didn't aware of the existence of this option of cells mismatch in PVsyst ...

When you tilt the base of the table, the angles change indeed. Please see our FAQ With sheds on a Tiklted roof, PVsyst changes my orientation

You are right, the default value of this parameter is not well managed in PVsyst. However this parameter is not known accurately (only measured by myself on a very old module, 20 years ago), but it doesn't have any significant impact in the PV module modelling. The only effect in the simulation would be an imperceptible difference in the electrical losses, only when one only cell is shaded in a sub-array. As soon as several cells are shaded, the resulting difference is null.

This problem has been fixed in the version 6.62.

You can change it in the Hidden parameters, topic "System design parameters", item "Soiling loss, default yearly average".

Why "should not have" PR and DiffHor ? This is a new presentation, that we thougt more informative than the Efficiencies. Now in a next version, we will give the opportunity of customizing some columns in the report. But I don't know when we will have time for that.

In PVsyst this is evaluated by applying the one-diode model. You have some formulas for computing the Pmpp with linear derates from the STC as function of temperature and irradiance, but to my knowledge not each point of the full I/V curve (or described in very specific papers). However these are approximations.

This means that your data are not correct. It could be a problem of units, or more probably the calibration of the solarimeter.

The development of a floating system is very similar to a normal terrestrial systems. We can identify two topics for which the treatment of floating systems may be slightly different: Temperature of the modules Unfortunately we don't have any information nor measurements about the temperature on the water. Due to the evaporation, the ambient temperature could eventually be slightly lower than the temperature measured on the ground area using the "Meteo standard" measurment (i.e. measure in a shelted box, at 2m above a ground of grass of at least 100 m2). Or the U-value could be slightly different. The module temperature may be strongly dependent on the technology of the supports: are the modules directly "seein" the water, or on a platform? etc... The only reliable way to determine these conditions would be to measure them on-site: see How is evaluated the Module temperature during simulation? NB: If you get such measured data, we (and the PV community) would be very interested to get the results ! Now in the simulation, if you want to decrease the operating array temperature you have to increase the Uc value in "Detailed Losses > Thermal Parameter". There is a limit to this parameter (50 W/m²K). If really necessary, you can increase it in the "Hidden Parameters", topic "System design parameters", item "Heat loss factor Maximum value". If necessary, we could indeed modify the thermal model for this specific situation, where the backside is "seiing" the water: perhaps develop a model involving the water temperature. We think about such a model, but we don't have any experimental data for establishing or assessing it in the present time. Remember that for crystalline modules, a decrease of 10 °C of the array temperature will increase the yield by about 3.5% to 4%. Albedo of a water surface The water absorbs a big part of the incident light. As amazing as it sounds, the albedo of the water is very low, some people propose about 0.06. Only when the sun is very low on the horizon, there is an important reflexion, but this is specular and its duration is rather short. By the way for a big installation in rows, the albedo is not significant as it is only "seen" by the first row. The shading factor on the albedo for the whole plant is (n-1)/n, where n is the number of rows. As an example a system of 100 rows will have a shading factor of 99%, i.e. it will "see" only 1% of the albedo contribution. Therefore the definition of the albedo parameter has no real importance. Tracking systems If your system is a floating disc following the azimuth of the sun during the day, you should use the option "Tracking with Vertical axis". From the future version 7.3, it will be possible to define a backtracking strategy for this situation.

These values are a result of the Clear day model. This model only depends on the geographic coordinates and the air mass, i.e. the solar geometry. Therefore you can calculate the values for any time.

The exposition to the sun is sufficient for enabling the LID degradation. However ths doesn't have any importance, as this concern the very beginning of the PV plant production, and therefoer a completely negligible amount of energy.

This is quite different: - the albedo mentioned in the project concerns the full "far" area in front of your installation. It is used in the transposition model. - The albedo of the Bifacial model describes the reflexion of the ground just under your PVsystem (roof, grass, rocks, painting, etc)

Since the version 6.60, we have implemented a model for the simulation of bi-facial systems. This model is for the moment restricted to shed-like systems, with the hypothesis of "unlimited sheds". We will develop models for other configurations later on. This tool becomes available in the software as soon as you choose a bi-facial PV module. In PVsyst, Bi-facial PV modules are characterized by one only parameter, the bifaciality factor, which is the ratio of the STC efficiency of the rear side with respect to the front side. For such a model, we have to evaluate the irradiance available on the ground, a reflexion parameter named "albedo", and the reemission to the back side of the PV array. This evaluation is done numerically, based on 2 basic hypothesis: the diffuse irradiance is isotropic, and the re-emission from a ground point is also isotropic. From V 6.64, the diffuse irradiance from sky on the rear side will also be taken into account. However this is a little contribution with reasonable tilts (less than 20°). Irradiance on the ground The irradiance available on the ground is calculated taking the shading of the PV system into account: - the beam component between the rows is obviously dependent on the sun's position, - for each point of the ground, the diffuse effectively reaching this point is calculated using the isotropy hypothesis of the diffuse (view factor of the sky). The diffuse distribution on the ground is independent on the sun's position. It is only related to the geometry of the system. Irradiance on the rear side The irradiance on each ground point is reemitted in all directions according to the Albedo factor. Again, using the isotropy hypothesis of the re-emission , we can calculate the fraction which is re-emitted to the PV array, and the quantity lost to the sky (view factor). The luminous energy available for each ground point is the sum of the diffuse component, only dependent on the geometry, and the beam component when this point is illuminated by the beam (depending on the sun position). We should emphasize here that the ground irradiance and reemission is dependent on the position below the array. NB: We have recently found a conceptual error in the Bi-facial model. Up to the V 6.63, we had considered the exchange between the ground and the rear side of the PV modules as an energy, when it is indeed an irradiance. This means that the reemitted energy to the rear side of the collectors should be renormalized by the involved surfaces. That is, the rear side irradiance should be multiplied by Pitch/Coll. width (1/GCR), which gives a factor of 2 or more! This has been corrected in the version 6.64. We have indeed: Energy(rear) = Albedo * ViewFactor * Energy(Ground) i.e. Irrad(Rear) * Coll area = Albedo * ViewFactor * Irrad(Ground) * GroundArea => Irrad(Rear) = Albedo * ViewFactor * Irrad(Ground) * GroundArea / CollArea Therefore Please use the version 6.64 and forget the results of the previous versions 6.60 .. 6.63 ! Other perturbations We should take several perturbations of this simple model into account: - a shading loss, which is characterized by a simple factor (could be the structures, the eventual junction box if on the rear side, etc ) - the rear side irradiance is not uniform, there is therefore a mismatch between sub-modules, leading to electrical losses. PVsyst doesn't have any reliable value to propose for this parameter in the present time, - The PV module may eventuially have some transparency (spacing between the cells - or even the modules): this will contribute to the ground irradiance. Now PVsyst provides a calculation framework - established with simple and well-defined hypothesis - which may be applied all over the year. This is a reasonable physical model, but we don't have any validation. Comparison with other studies However comparisons with existing experimental systems and publications is very difficult as: - Most of the experimental setups are made of one or two modules, above an "illimited" ground area. Therefore receving light from a big illuminated environment. The model in PVsyst supposes a realistic installation with Unlimited sheds, i.e. usual rows spacing and no additional albedo contribution from the edges of the system. - The results are often available for some specific conditions, not over a full year measurement. - The albedo conditions may be not realistic with respect to real systems (specific surfaces, variability when wet, ageing, etc).

PVsyst proposes a model, established according to well-specified hypothesis, either for the irradiance availability on the ground and for the Form factor. It gives detailed results about the ground availability and the rear side irradiance, along the whole year according to your meteo data. However we don't have any validation. In fact we didn't got any results registered in good conditions with a realistic PV system up to now. Now most of people studying this subject work with one or 2 modules on an "illimited" reflective area. This is the case of both papers you are referencing. Even if the simulation of the Universities of Konstanz and al. are done with 5 rows, you can observe that: - the extreme modules behave better due to the larger"seen" reflective area (on 4 edges) - the chosen inter-row is very large (if modules are 1 m wide, the "pitch" of PVsyst is 1 * cos(25°) + 2.5 m = 3.4 m, so that the GCR is 0.29. - the chosen albedo of 0.5 seems irrealistic in real conditions. Their only measurements are for one pair of module only, at 1.2 m altitude. They don't tell us how they have measured the albedo coefficient taken in the model, therefore it is difficult to have a full confidence in their validation. The PVsyst model tries to represents a realistic PV system, i.e. with the "unlimited sheds" hypothesis. Please see the fig 5 of the publication: with a reasonable (usual pitch (1m between rows, i.e. a GCR of 0.52), the gain is of the order of 8%, not so far from the results of PVsyst before shading and mismatch losses.

You are certainly using a version < 6.40, and trying to read a file (PV module, inverter) created by a version >=6.40.

This is because you have not defined the "rectangles" representing a string correctly. You have defined one rectangle as one submodule. In the option "According to module strings", one rectangle should correspond to one full string.

We could indeed increase the number of decimals here (and in many other places). This would make the reading of the report more heavy, without a significantly better accuracy. For your example, the "reading error" represents perhaps 10% of your wiring resistance loss (because it is very low, probably not realistic), but 0.05% of the system yield ! I doubt that your Rwiring evaluation is much better than this value.

Yes of course. The simulation of PVsyst is based on horizontal meteo data, and evaluates the POA using transposition models. An additional improvement for the accuracy would be to measure also the diffuse component on the horizontal plane.

It is indeed the definition of the Backtracking strategy to avoid mutual shadings. It does that by adjusting the plane tilt (phi angle) according to the sun's position. If you don't have near shadings you don't have electrical shading losses of course. Now I don't know how you evaluate the plane tilt during operation: this will highly depend on the sun's position. However if you construct the same system with fixed tilt, you should have exactly the same shading situation for the same plane tilt and same sun's position.

The nominal power of your inverters may be up to 1155 kW if the temperature around the inverter is less than 35°C. Please explain in detail how you observe an increase of 15 kW with respect to this value.