André Mermoud

Thank you for these reports of bugs and propositions. They have indeed been corrected for the next version 6.79.

PVsyst doesn't treat this case. It is extremely difficult as the reflexions are peculiar, so that the backside will be ununiformly irradiated. Remember that the current of a string is driven by the current of the worst irradiated cell. Moreover, this calculation would require a very accurate description of the reflectors, and would be very specific to this geometry.

If all your strings are identical (same number of modules in series), you should uncheck the case "Use multi-MPPT feature". The simulation will consider each inverter as a whole and will not share the Pnom on the MPPT inputs. Another way is to redefine your inverter as a 4-MPPT input device.

Please think globally. When keeping the battery charged and using the rest of the PVproduction, you have indeed less Unused energy at this time. But during the next night you will discharge the battery to a lesser extent (higher DOD) than if it was discharged during this episod. This means that during the next day you will reach the full charge earlier, and therefore have more unused energy. Globally, over a long period and if you don't reach the Loss-of-load, you cannot produce more energy than what you consume (neglecting the losses in the battery). This is the first principle of the thermodynamics: the conservation of the energy.

Basically the efficiency is the ratio of the produced electrical power, divided by the input power (irradiance). Therefore the efficiency of a PV module at STC will be : Effic = 0.001 * PNom [Wp] / Module Area [m2]. - The nominator is a power at STC - The denominator is indeed the STC Irradiance across the module area, i.e. 1000 W/m2 * Module Area [m2], which explains the units. Now we have different possibilities of defining the module area: - The Gross area is from the module's sizes: Length * Width. This includes the frame and spacing between cells. This is the most usual, always available in the database. - The Sensitive area may be defined in the PVsyst database, when defining the cell's area (facultative). In this case the module's sensitive area = NbCells * Cell area. This will lead to another efficiency related to the sensitive area, characteristic of the cell's technology. - In some cases we can define Tile modules (with mutual covering). In this case PVsyst defines the sizes of the "apparent" area for the evaluation of the efficiency. Use of the Efficiency The efficiency is never used in the calculations: in any electrical calculations (simulations, etc), PVsyst uses the "One diode model". The efficiency is only an indicator for display. In the Loss diagram, the mentioned efficiency is related to the Gross area of the PV system (sum of all modules), which is also mentioned on the plot. It allows to get a quick check of the "Array Nominal Energy at STC": EArrNom = GlobEff * System Area * Efficiency[%]/100 NB: The performance ratio (PR) doesn't depend on the efficiency in any way, as it is normalized to the Pnom value. If you have a better efficiency, you will have a better yield but a higher PNom at the denominator. Effects of the area on shadings The only part where the distinction of module area versus sensitive area could have an effect, is the calculation of the shadings. In PVsyst the fraction of light lost due to direct shadings is calculated by determining the shaded fraction on the PV surfaces in the 3D drawing (blue rectangles and polygons). These include typically the frames and spacings between PV modules. In some rare cases, this can lead to very small deviations, e.g. when the shadow touches only the frames. We deem that these deviations have no significant effect on the simulation results.

We cannot say anything without more information. Please send your whole project to support@pvsyst.com, in order that we can analyze the problem.

The ageing tool uses a "Monte-Carlo" method for the evaluation of the Mismatch loss parameter evolution along the years. The "Monte-carlo" method is a random process, which gives a different result at each execution. See the help "Project design > Array and system losses > Ageing, PV modules degradation".

Please explain what you mean by "those factors which cn affect actual transposition compare to PV Syst". What is the "actual transposition" ? There are no hidden factors in the transposition model: only the possibility of using the Hay or the Perez model (defined in the project's settings, or the Hidden parameters if you are not within a project).

It is clearly mentioned in the Help that at the moment, the model available in PVsyst only applies to "unlimited sheds"-like systems, and with a significant number of sheds. The edge effects are not taken into account, neither in with, nor in the perpendicular direction (i.e. number of sheds). The pitch and collector width are basic parameters of the model. This means that the model doesn't apply to a single module or table on a roof. This feature will be developed in a future version.

Yes, most of the usual Solar converters work with a "Stop / Start" behaviour, based in the battery state, as it is done in PVsyst. Some sophisticated converters use indeed a more complex charging strategy: when the battery is full (i.e. attains the charging OFF threshold), they don't cut, but reduce the voltage appplied to the battery, and maintain it at a value ensuring a little current (floating mode). This has not yet been implemented in the simulation of PVsyst, it should be done soon. This mode could indeed be used for ensuring your proposition, which is to maintain the PV production when it is sufficient for covering the user's needs. This will require a special operating mode of the controller, which is to exactly adjust the output power for ensuring this floating voltage. In the same way as when limiting the output power of grid inverters, this will be obtained by displacing the operating point on the I/V curve. However if your battery is sufficiently sized (2-3 days of consumption), as far as you don't have to cut the load because it is discharged, the balance of the unused energy will be exactly the same. Because the Solar PV system cannot produce more energy than the user's needs ! If the battery remains charged during what would otherwise be the "battery cut", it will not need to be charged afterwards. The only difference will be the battery wear due to cycling , and eventual battery efficiency losses. You could indeed observe a (very small) advantage if you have to cut the user due to a complete discharge of the battery.

I don't see the principle. If you don't have a battery, and a "constrained" consumption in your DC circuit, this will comsume this energy whatever the origin (PV or grid) at a given time. Now if you have 2 counters (grid injection and grid consumption): if the reinjection tariff is higher, you have always advantage of counting your PV electricity as reinjected. In the opposite case, you have advantage to auto-consume your PV energy. There is no better intermediate case. In this problem, no need to assume a 400VDC circuit: you can think in terms of energy (internal load). For this evaluation, you can therefore use the "Self-consumption" option.

The LID is an initial degradation of the PV module's performance, arising during the first hours of exposition. It is obviously not "recovered" at the end of the first year ! The degradation is permanent, this means that it has indeed to be applied to each simulation for each year.

Yes this is now available. When editing the report, please choose "Settings > Report preferences".

The GlobInc value is not correct. It should be expressed in kWh/m2/day. Not kW/m2. If you have measurements every 15 seconds, you have to calculate the average irradiance for each hour (or the order of 1000 W/m2 if at full sun). Then you add all the hourly irradiances [W/m2 = Wh/h/m2] of your day and divide by 1000 for getting [kWh/m2/day]. The result should be of the order off 7-9 kWh/m2/day for a clear day and south-facing plane.

You can indeed try to define an array of 2 trackers for the calculation of the backtracking angle. And add individual trackers at different locations and altitudes to your 3D scene. In this case the backtracking will not be correct, you will have some mutual shadings. However these shadings will be calculated quite correctly by the simulation. You will have to perform the electrical shadings calculations as well (in mode "according to module strings" should be sufficient).

The manufacturer's ageing values are a warranty, i.e. a worst case value for one (each) module. The definitions for the degradation concern the whole system, i.e. an average of all modules. This is not the same thing. Please see our FAQ How to interpret the warranty efficiency curve of the manufacturers ?

I don't understand well the question. This product 174 kWh/m2 * 386518 m2 * 17.03% gives 11453 MWh. I.e. a difference of 0.25% with the value shown. This is a rounding effect.

In the present time PVsyst treats 2 specific kinds of Bifacial systems, which may be modelled using maily 2D calculations: - "Unlimited sheds", or 3D scenes which can be approximated by unlimited sheds - "Unlimited trackers" with horizontal axis, or 3D scenes which can be approximated by unlimited trackers. In a next step we will implement bifacial systems for any 3D scene, which involves a 3D tratment, more complex. The extension to other kinds of tracker is not foreseen in a near future.

PVsyst doesn't manage the minimum starting voltage specified by some few manufacturers. Usually this is below the VmppMin and I don't understand well the mechanism. In your case of a value far above the VmppMin, we can understand that when the array is not operating, it is at Voc, not Vmpp, so that this constraint is perhaps less important. However, please ask the manufacturer for details about this behaviour.

You have indeed to perform a simulation before activating the Bifacial system. This was an error in the version 6.76. Corrected in the new versions.

This was an accident, just in the version 6.76. Sorry.

If the Mechanical Phi limits are +/-60°, and the Backtracking limits are, say, +/-63°, then - when the calculated Backtracking angle is between 60 and 63°, the trackers are clipped to 60°. - when the sun continues to go down, the backtracking angle diminishes and the tracker will follow the "true" backtracking orientation below 60°. You can observe this behaviour in the tool "Orientation > Unlimited trackers".

Yes, there are only some few video tutorials for specific topics edited by PVsyst. Especially concerning the shadings treatment. You have another more complete tutorial, in Text mode, within the software. The other videos (not listed) are provided by other users.

You can of course perform your simulation for any operating year, taking the ageing losses into account. You will get the corresponding loss diagram. Now you can also perform the simulation for the whole desired operating period, using "Advanced simulation > Ageing Tool". The yearly evolution will appear on the report. I don't see of which O&M factor you are talking about. This doesn't involve an energy loss, but only an additional cost. This cost may be defined in the Eonomic Evaluation.

Please try to avoid special characters in the Filename.