Michele Oliosi

Usually the weather data provider will provide the variability. It is already included in most TMYs on the market. For the climate change it is a bit more complicated. If you have a specific year of a time-series, you can ask yourself whether this year is above or below average and by how much (in terms of irradiance). For predictions we actually do not really know how to do this, an idea would be to look at multi-year trends for the location. Both are indeed used for P75 and P90. The P50 is controlled by the climate change % only, to shift the simulation value. You can use the aging tool (advanced simulation > aging tool) which allows you to simulate several years in a row and present the result in a formatted table / report. a 25-year-P90 is a concept we haven't implemented in PVsyst yet. You should not concatenate 1-year P90s, this approach is incorrect. Indeed, when taking longer sampling periods, the weather variability should decrease, by a factor 1/sqrt(n years) approximately. But note that the uncertainty does not decrease over the years. In practice after 25 years, you may get more or less 1.5-2% of variability + uncertainty.

in this case you should space the EW rows sufficiently to get try to get some ground reflection

It is not currently possible to simulate with PVsyst as this has two orientations (we handle only one for now, we will update this but not before 2024 I think). However the bifacial gain is usually negligible (there is no light arriving on the backside), unless the domes are high enough over the ground.

You can use the fraction for electrical effect for several purposes. One would be to mitigate the effect of shadings overall. Indeed if for some reason light is seeping through, the electrical shading losses may be mitigated you can use the fraction for that. That would work for a semi-opaque shading object. However for trees the shading patterns will be very sparse, I am not sure what the impact would be. If one of the cells is fully covered for example, then it the light seeping through to other cells won't increase the production. The main reason to consider the fraction for electrical effect is if your shadings are not due to row-to-row mutual shading (geometrically regular across tables) but impacts only some submodules in a row. E.g. a pole will cast a shadow on a couple submodules only, which should have less impact in terms of electrical shadings than mutual shadings, for which a whole row of submodules is impacted at a time.

Probably 7.3.4 was underestimating the losses in your case. I am not sure there's a solid reason to go back to a situation where the losses were underevaluated. But you can always reduce the shading factor further, even though we don't recommend it.

Do you mean vertical EW or EW domes ?

Actually it's the other way around, with the partition model the diffuse is accounted separately it does not suffer from the partitions electrical shading losses. However in reality, when the current is limited on 1/3 of the submodules, by using the bypass diodes you lose both direct and diffuse on those submodules. Therefore we need to increase the electrical shading losses in some way in the partition model (at least for this scenario). Currently we found that setting 2 partitions works quite well.

Currently the mixed orientation exists just for the orientations 1 and 2. I would recommend to use instead the multi-MPPT feature, and the power sharing according to the orientations: https://www.pvsyst.com/help/powersharing.htm in the chapter "2 sub-arrays with different orientations (for example with "domes") "

Yeah basically it is rather the following case: No this is not really related to optimizers, even if you had no optimizers I would recommend something similar. Optimizers will help if you have shadings that are different from (pair of) module to (pair of module) module in the same string of optimizers, and this is already handled by having separated tables and the partition model. Even though there are three submodules, since we apply the partition model only on the direct irradiance, we have to compensate for the diffuse that produces electrical energy in full in this approximation. In the end 2 partitions works well for this reason.

It is more accurate with the ground. If the ground blocks the sunlight in some way for your PV field, that should be included in the shading objects.

Ah I meant two rectangles in height, basically cutting the module in half. Sorry I notice that "partition" is not very explanatory by itself.

It is almost never problematic to split partitions across tables, especially when the two connected tables are side by side. This is because often the shadings on the two tables are similar, so it makes no difference whether it is a single table or two tables. Here I would recommend to act as if each table was a 1L string (the fact that there is a single module doesn't matter much). In this case I would put 2 partitions in height per table. I agree that intuitively 3 partitions (corresponding to the submodules) could seem to work, but when considering the details of the model over typical DHI/GHI ratios, we found that 2 partitions works better.

Ah yes, if you see the shading factor table you will notice that the 90° height is always 1, because the sun shines on the side of the table, which is considered full shading. The iso-shading diagram was aimed at interrow shading, so it does not handle this case well. You can disregard the shading lines in the isoshading diagram.

Regarding where the clipping losses, they are currently encapsuled in Lc : collection loss. This is because we evaluate it based on EArray, which occurs after displacement of the operating point by the inverter. The irradiation data is in the MET file. However the evaluation shown in the “overload loss” in figure 1 and 2, are just preevaluations, that are not yet very precise. The real value is in the simulation.

Hi, Is the PV module you are using in subarray "Onduleur 4.3" different than the one used in other projects / other sub-arrays ? The message is suggesting that there is an issue with that PAN file. If you are not sure you can send us the file at support@pvsyst.com

You can save the module as a pan file and open it with a text editor. One line corresponds to muGamma. There should be one more decimal there.

Hi, there is a bug with the "Month; Day; Hour;" option. Please use another one until we fix this bug. Sorry for the inconvenience.

You find that from the project window > Self-consumption > option "Load values from a CSV hourly / daily file" > Click on "Choose CSV file"

Honestly, I think the strategy was different there were more operations involved. But as mentioned you should ask the manufacturer directly. Currently I am not able to describe the full procedure.

Hi, at present you can simulate bifacial PV installations that have a single fixed or SAT orientation at least two rows of tables / trackers if you have a single row of tables, you should "duplicate" the scene, basically copy paste all relevant objects and place the copy at a large distance in the 3D scene. This will emulate the situation of a single row, because the original scene and the copy won't affect each other. Note: this is the current workaround. We will try to offer a solution for single row scenes in the future.

Hi, the iso shading diagram is exactly what the name says, it displays the sky positions that produce the same shading factor as a continuous lines. These iso-shading lines are akin to isolines on a map, which show you the points at a given altitude. In general you can read the lines as follows: take the 40% line: as long as the sun is positioned at a sky position below that line, there will be at least 40% of shaded surfaces. The iso-shading diagram just shows the direct shading factor. The diffuse one is computed separately. On a separate note, I have never seen an iso shading diagram like yours. Please make sure that all the objects in the 3D scene are well defined and do not intersect each other. Also make sure that all PV surfaces have the correct orientation.

1) That is correct. You can also adapt the number of partitions in length (X). If there are two strings side by side then you can put 2 partitions in X. 2) No in fact what matters here is that the strings in parallel on a given MPPT are on the same level, so probably will experience the same shading. In this case you should put 2 partitions in Y for 1 V, 4 partitions for 2 V, 6 for 3V, as for 1). In the help this case is named "1L". As above you can put 2 partitions in X. 3) First solar modules are somewhat resilient to shading due to the submodule structure. It is recommended to use "Linear shadings" which doesn't need any partitioning. 4) Yes by assigning strings to different MPPTs there is no change. Since there are two strings in X you can put 2 partitions in X. 5) When cabled horizontally, this is like case 2) i.e. 4 partitions. MPPT 1 in your drawing: in general mutual shading affects 1/6th of the submodules. If the voltage range of the inverter allows for it, the string can just function with 5/6 of the voltage (and power) by bypassing the shaded submodules. MPPT 3 in the drawing: in general mutual shading affects 1/3 of the submodules. This situation is less advantageous and produces a bit more losses. Note that MPPT 2 will be generally unshaded. You can ignore the warning, you are right we should update that. 6) same as 3)

both are the same I think.

The array virtual energy at MPP is before the displacement of the operating point away from the MPP. It is the maximum energy you could extract from your PV array if your inverter had no voltage / current / power limits.

@Whitley Forman indeed at the moment the backside irradiance calculation is based on a view factor model (in 2D) that is completely independent from the 3D shading scene, used for the front side. If there are shading objects close to the backside, you can include their effect in the parameter "Structure shading factor".