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developer_mh

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developer_mh last won the day on July 22

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  1. Hi Juliana, the reason for the error is that the grid voltage is set to 254.03 V. Our 3D environment can't handle that. Change it to 254 V (or any other value) and it should work. And of course you are free to contact us on any channel that you prefer (mail, forum, phone), but please consider that it might cause double effort for us if you contact us on two channels simultaneously. Kind regards, Martin
  2. Dear all, this is a bug that was introduced with the latest version, PV*SOL premium 2021 R7. It will be fixed in the upcoming bugfix release, R8. It affects mounted PV systems with various orientations, like east-west systems, on flat roofs. We are very sorry for the inconvenience caused and try to publish the bugfix release as soon as possible. Kind regards, Martin
  3. developer_mh

    Net metering

    Hi Faruk, in order to avoid grid feed in you can set the maximum power clipping to 0%: https://help.valentin-software.com/pvsol/en/pages/system-type-climate-and-grid/#ac-mains Hope that helps, kind regards, Martin
  4. Hi cjSPS199, if you are a manufacturer or licensed distributor and you wish to enter products in our database, you can contact our database team at database@valentin-software.com. Kind regards, Martin
  5. Hi Endika, in PV*SOL, you can only import hourly data. Data with one-minute resolution can be synthesized from it afterwards, but you can't import your own, I am afraid. When you import hourly data, and PV*SOL shows a hint that "Input data and clear sky data are not sync", it means that you irradiation data and the calculated position of the sun do not fit together. Most likely it is because of the time zone or other timestamp-related issues. The data must be in local time, without daylight saving time switch, and right-justified. That means the timestamp from e.g. Jan 01, 11:00 refers to data between 10:01 and 11:00. You can easily check if you imported hourly data is in sync with the sun position when you look at the imported irradiation and the elevation of the sun in the diagram editor. Search for a clear sky day, where the irradiation follows a nice bell-shaped curve, and see if the elevation follows approximately the same curve: Here, as an example, these data are not in sync, since the peak of the irradiation comes approx one hour before the peak of the sun's elevation: Here, the data are in sync: Hope that helps, kind regards, Martin
  6. Dear Gerhard, in PV*SOL you can only simulate one whole year. However, you can look at the simulation results in a very high resolution and flexibility afterwards. Use the diagram editor to show the results you like, over time (so you can see every morning as well): Or use the carpet plot, to analyse all mornings of one year at once: Or you can export the simulation results and analyse the data in another tool, e.g. MS Excel or LibreOffice. Hope that helps, kind regards, Martin
  7. Dear Aljaz, you can simulate very large PV farms in the 2D mode, no problem. We recommend to make a pre-simulation in 3D with a subset of the modules, e.g. with 1000, depending on your PV farm layout and setup. Then simulate it and write down the yield reduction due to shading: Then configure your complete PV farm in the 2D mode and enter the shading loss from the 3D simulation as shading loss in 2D: Or, follow point 3) from this answer here, but at your own risk: Hope that helps, kind regards, Martin
  8. Hi Endika, there are some lines in your file where data is missing: Other than that, the file should be fine. Kind regards, Martin
  9. Hi Vishnu, thank you for reporting this. Could you provide the project file please? I quickly checked it, and it seems to work as expected: Kind regards, Martin
  10. Hi apaec, the sizing factor is defined as the installed DC power of the PV modules in relation to the AC power of the inverter. So, if you have 100 kWp of PV modules, and an inverter of 100 kW AC output, you'll get a sizing factor of 100%. If you have 150 kWp PV module power connected to a 100 kW inverter, that would be a sizing factor of 150%. The sizing factor is a design choice. The higher the sizing factor, the smaller the inverter. Smaller inverters usually are cheaper than bigger ones, so you can save cost there. But then you'll have more down-regulation situations where the PV produces more than the inverter can handle. So the inverter will limit the output and "throw away" the excess energy, so you'll lose some portion of your PV energy. That effect will decrease the profitabitility of your project. So the planner of the PV system has to make a choice which inverter to connect to the PV array. With PV*SOL, you can easily see the impact on the energy yield a smaller inverter (higher sizing factor) would have. The limits of the sizing factor can be modified in the Options -> Configuration Limits: Hope that helps, kind regards, Martin
  11. Dear Daniel, concerning your first question, please have a look at this answer here: ad 2) There is no simple calculation formula here, I am afraid. What we do is really simulating the irradiance on the module surface, with diffuse and direct shadowing, down to substring level. Then we use an IV-model (two-diodes-model or our own "PVSOL" model) to calculate the I-V characteristics of the module under the given conditions. In addition we also calculate the IV characteristics of the module without shadow and remember this value, so that we can determine the losses due to module-specific partial shading afterwards. You can find more detail here on our help pages: https://help.valentin-software.com/pvsol/en/calculation/irradiation/ https://help.valentin-software.com/pvsol/en/calculation/pv-modules/ ad 3) The configuration or shading mismatch is the difference between the actual output power of an PV array (several modules connected together), not regarding ohmic losses, and the sum of the individual output power values of each module at each moment. When you have inhomogeneous shading on the modules, the resulting IV characteristics of the array may be such that it is not possible to hit the MPP for each module. Instead, the overall array MPP will be chosen, and this point may vary more or less from the per-module MPP. Hope that helps, kind regards, Martin
  12. Dear Paul, thank you for the project. The problem here is the limitation of the MC box (multicluster box). It can only connect to a maximum of 12 three-phase clusters of Sunny Islands and to a maximum of 360 kW of PV power. https://www.sma.de/en/products/battery-inverters/multicluster-boxes-for-sunny-island.html And PV*SOL doesn't support more than one MC box at a time. So I would suggest to break your 5MW project down into a smaller unit, let's say 250 kW, a 1/20th of your current project. You would calculate with 575 PV modules, smaller PV inverters, a load of 32,5 kW and then you can configure the battery system accordingly. Finally you would have to scale up the results by 20, manually. Sorry that we can't provide a different solution, but this is as it is right now. Kind regards, Martin
  13. Dear Douglas, we are working on it, as well as on the integration of other climate data sources, and we hope to be able to release it with the new major version, PV*SOL premium 2022 R1 in November. Kind regards, Martin
  14. Hi Lynette, when we simulate with an one-hour timestep, we can directly interpret the incoming irradiance values (in W/m²) from the climate data as irradiation values (in Wh/m²). When we simulate with one-minute values, you can see the output in the diagram editor or you can export them to csv on the presentation page. Here it is in W/m², when you export, you'll get kWh/m², depending on your export settings. The irradiation is only available on module level. The diffuse shading is applied on the whole module homogeneously while the direct shading affects the cells with varying intensity. But these different irradiation values (on cell or substring level) are not logged at the moment, it would lead to a huge amount of simulation data. Hope that helps, kind regards, Martin
  15. Hallo Patrice, danke vielmals für den Input. Du hast natürlich Recht, der "Preisänderungsfaktor Einspeisevergütung" sollte sich nicht auf die Abgaben beziehen. Ich nehme das mal in die Liste mit auf. Der andere Punkt, also das getrennte Anzeigen der Tarife, auch in der Cashflow-Tabelle, steht bereits auf der Liste. Und dort auch relativ weit oben. Danke für das Feedback, viele Grüße, Martin
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