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March 2015 Application Note - How to Design a SolarEdge System Using PVsyst As of version 5.20, PVsyst - the PV system design software - supports the design of SolarEdge systems. This application note details the SolarEdge-specific design steps. This application note assumes the reader has prior knowledge of the basic use of PVsyst. This document explains the unique SolarEdge design concepts as they are realized in PVsyst and guides the user through setting up a shading scenario using the SolarEdge system. Introduction The process of designing a SolarEdge system in PVsyst includes the following basic steps: 1 Project – define the location and meteorological data 2 Orientation – define module azimuth and tilt 3 System – choose the system modules, inverters and electrical design 4 Near Shadings – design the system layout in 3D and select shading calculation method 5 Simulation – view a summary of the system design and its energy output This document briefly covers steps 1, 2 and 5 (Project, Orientation and Simulation) which are done in the same manner for SolarEdge and non-SolarEdge systems, and describes in more detail steps 3 (System) and 4 (Near Shading), as they pertain to the design of a SolarEdge system in PVsyst. NOTE While PVsyst offers basic system validation, it is recommended that you always use the SolarEdge Site Designer software for design verification. Step 1: Project Choose “Project Design” and then “Grid Connected” in the main PVsyst screen. Click on “New Project” and then choose the correct project site and meteorological file (the meteorological file will often be automatically associated with the chosen site). In order to add a new site to PVsyst, click on “Databases” in the main PVsyst screen and then “Geographical Sites.” Choose “New” and locate your site on the interactive map, or type the geographical location in the search box. Click “Import” and then “Import” again (for the second Import, make sure to click on the button that has a sun icon). Click OK and then Save. When prompted to save the hourly values, click “Yes” and then “Close” and Exit”. You can now choose the new meteorological site for your project. 1 Step 2: Orientation Once the geographical location and climate file have been chosen, you will define the array’s azimuth and tilt. PVsyst offers different options to fit various types of projects, including simple fixed tilted plane, multiple orientations (up to 8 orientations), seasonal tilt adjustments, ‘unlimited sheds’ for large systems, sun shields (modules mounted to facades of buildings) as well as various kinds of tracking arrays, both single and double-axis. Step 3: System The main system parameters, including module and inverter model, system capacity, string lengths etc., are defined in this screen. This is where the SolarEdge system advantages become apparent. Basic Design After choosing a PV module, select the SolarEdge inverter applicable for your project. You can then use the drop down list below the modules to select the appropriate power optimizer. If you plan to connect more than one module per optimizer, use the following window to specify how many modules to connect and the type of connection (series/parallel): The Inverter Input tab in the SolarEdge interface lists the number of power optimizers per string, not the number of modules. Thus, for example, when connecting two modules per power optimizer the string length would be 20, meaning 40 modules: 2 Uneven String Design Unlike a traditional inverter, the SolarEdge system introduces a high level of design flexibility. A common limitation of a traditional system is that all strings connecting to an MPP tracker must be of the same length. The SolarEdge system has no such limitation since MPPT is performed at the module-level using the SolarEdge power optimizers. Multiple strings can be connected to one inverter, regardless of length, module azimuth, tilt or module type. In order to accommodate this capability, PVsyst has incorporated a feature called “fractional inputs.” This feature allows viewing strings as fractions of an inverter. By assigning different fractions of an inverter to different strings, the sum of these fractions adds up to the whole inverter. The following 3 examples explain this concept. NOTE Currently PVsyst can only design homogenous strings, that is, each string must have one orientation and module type. In practice, the SolarEdge system can be designed with non-homogenous strings. Example 1 Consider a SolarEdge inverter with 70 modules divided into 2 strings: one with 42 modules, and one with 28 modules. For this design, use 2 PVsyst subfields: one for each string. In the System screen, check “Uses fractional inputs” and in each subfield’s “Nb. of inverters” fill in the relative portion of that string. In this case, Subfield 1 has 0.6 inverters (42/70) and subfield 2 has 0.4 inverters (28/70). In the “Global system summary” field, verify the number of inverters is 1: Example 2 Consider a system with 3 SolarEdge inverters, each with one string of 35 modules and one string of 34 modules (69 modules per inverter). The system has 6 strings (3x35 + 3x34) and 207 modules. Conceptually, ‘half’ of the 3 inverters are connected to strings of 35 modules, and the other half are connected to strings of 34 modules. In this case create 2 subfields: one for each string length. One subfield will have 1.5 inverters: (35/69) X (the number of inverters = 3) where each inverter has a string of 35 modules, and the other subfield will have 1.5 inverters, and each inverter has a string of 34 modules (each subfield has 1.5 inverters because PVsyst rounds the fraction to the first digit, and here the difference 3 between the string lengths is small). The total ‘amount’ of inverters will be 3: Example 3 Consider a system with 16 SolarEdge inverters and the following design: 7 inverters, each with two strings of 34 modules 9 inverters, each with one string of 34 modules and one string of 35 modules Total number of modules in the system is 1097: 23 strings of 34 modules = 782 modules (71.285% of the total number of modules) 9 strings of 35 modules = 315 modules (28.715% of the total number of modules) In other words, 71.285% of the modules belong to strings of 34 and 28.715% of the modules belong to strings of 35. Thus: 71.285%*16 = 11.4 inverters connected to strings of 34 modules 28.715%*16 = 4.6 inverters connected to strings of 35 modules The 2 PVsyst subfields should look as follows: Step 4: Near Shadings The SolarEdge system minimizes the energy loss due to partial shading when compared to a traditional inverter. If the system in question has shading of any kind (trees, chimneys, inter-row shading) the 3D physical system layout should be designed to account for the energy loss due to shade. An accurate shading simulation will ensure the SolarEdge advantage is reflected in the annual energy output of the system. If needed, you can refer to the PVsyst help files for assistance in constructing a 3D shading scene. PVsyst can calculate the shading according to one of 2 methods: “linear” and “according to strings”. 1 In “Linear” shading calculation, the energy loss is linear to the PV area being directly shaded. This method does not take into account the electric interdependency of modules in a string, nor does it allow for the electrical behavior of a partially shaded single module (the protection of bypass diodes). 2 In shading calculation “According to module strings,” the energy loss due to shading takes into account the effects of partial shading on the entire string. Choosing this method requires division of the PV areas into rectangles corresponding to the size of the strings designed in the System section. This is a more realistic method and therefore more accurate. Use this method to compare a simulation of a traditional system vs. a SolarEdge system, as described below. 4 Unlike a traditional system, in which the production of whole strings is affected by partial shading of as little as one module, SolarEdge confines the effects of partial shading to the shaded modules only, thanks to its module-level MPPT. The way to simulate shading in a SolarEdge system in PVsyst is to divide the PV area into strings corresponding to the size of one bypass diode. Depending on the number of bypass diodes in the chosen module, this will usually result in 3-4 substrings per module, running along the long side of the module, as in the image below (module graphics have been inserted for clarity purposes). Once the shading scene is complete and the PV area has been divided into substrings, select the “According to module strings” option in the “Near shadings definition” screen. NOTE When designing the same system based on a traditional inverter, define the string division rectangles based on the number of modules per string, and not based on bypass diodes. Step 5: Simulation Once the system parameters have been defined correctly, click on “Simulation”. When clicking “Simulation” again the simulation will begin, and when finished a report will be available for viewing and printing. In addition, the Simulation screen allows you to change the time frame of the simulation (from one day to one year), as well as exporting hourly values of various parameters including energy, inverter efficiency, PV array’s electrical behavior and more. Depending on the complexity and size of the system, the simulation process may take from a few seconds to over an hour. 5 General Notes SolarEdge eliminates all losses that result from mismatch, compared to 2% in a traditional system. Mismatch losses are caused by manufacturing tolerance of the modules, temperature differences during operation, uneven soiling and other environmental factors such as overcast weather conditions. When selecting a SolarEdge inverter, PVsyst automatically sets the mismatch losses to zero. If more than 2% mismatch is indicated, change this parameter by clicking the “Detailed Losses” button at the bottom of the System screen of the traditional inverter. This parameter should always remain zero for SolarEdge. The Module Layout section in PVsyst is not yet implemented for SolarEdge, however may be used for traditional systems. Note that for some shading scenes, such as: very thin pole shading, light shading due to small roof protrusions, complex commercial systems etc., the Module Layout method may provide inaccurate shading losses. Appendix: PVsyst Loss Parameters PVsyst calculates several loss parameters during the simulation, as shown in the losses diagram below. This diagram appears at the end of each PVsyst report. Following is an overview of the loss parameters, calculated successively. Horizontal global irradiation: a combination of the global diffuse irradiance and the global beam irradiance calculated hourly over one year on a horizontal surface. Global incident in collection plane: using a transposition model (either Perez or Hay), PVsyst increases or decreases the horizontal global irradiation depending on the azimuth and tilt. This value represents the actual irradiation reaching the module. Near Shading: irradiance loss: the loss of energy due to direct shading (affecting the beam component of the irradiance) and diffuse shading (affecting the diffuse component of the irradiance. For example: nearby objects such as the next row of modules in a ground mounted system decrease the diffused light hitting the modules even if they do not cause direct shading). IAM factor on global: IAM (Incidence Angle Modifier) relates to the decrease of irradiance reaching the PV cell due to the sun rays’ refraction when passing through the PV module antireflective coating and glass. The higher the incident angle (with respect to the sun’s position) the higher the loss. Effective irradiance on collectors: the remaining irradiation following the previously detailed losses, multiplied by the PV area (the module area as defined in the *.PAN file). PV Conversion: the module efficiency at STC. Array nominal energy (at STC efficiency): the PV conversion efficiency multiplied by the effective irradiance on collectors. PV loss due to irradiance level: calculates the reduced module efficiency in low light conditions. 6 PV loss due to temperature: represents the reduced module performance due to temperature change. The module’s temperature coefficients as well as the thermal loss factor parameter affect this loss. The thermal loss factor is not a scientifically determined value; rather it is set by the system designer according to experience and previous estimations. A value of 20 W/m²k is acceptable for most systems. If the modules are embedded into a roof structure, the value can be set to 15. When the modules are free-standing in a cool and windy location, the value can be set to 29. Shading: electrical loss according to strings: in addition to the Near Shading irradiance loss, this represents the energy lost due to the electrical effect of shading. For example, in a system with strings connected in parallel, one shaded module can cause a whole string to be bypassed due to voltage mismatch. Module quality loss: This parameter makes use of the manufacturing tolerance values in the *.PAN file (i.e. ±2% tolerance). The formula used is: The lower tolerance plus a quarter of the difference between lower and higher tolerance. So for example, for a module with a ±2% tolerance, the quality loss is [-2%+(0.25 x 4%)] = -1% Module array mismatch loss: The energy loss due to mismatch between modules in a string. The 2% mismatch for traditional string inverters stems from manufacturing tolerance, un-even soiling, temperature differences between modules, tilt or azimuth differences within the string, etc. Ohmic wiring loss: The voltage drop due to wiring resistance is calculated as one value for the whole system. If there are differing conditions such as strings and combiner boxes with varying lengths of cable, it is not accounted for in the simulation. The default value of 1.5% loss from STC is recommended. This translates to a reasonable actual loss of around 0.6% on the DC side for most systems. Inverter loss during operation (efficiency): The inverter’s DC to AC conversion efficiency, weighted for variance in power levels over the year. Inverter loss over nominal inv. power: The power clipping in overloading conditions (where the array produces more DC power than the maximum AC output of the inverter). Inverter loss due to power threshold: The loss of energy when the array operates below the inverter’s minimum power threshold (defined in the *.OND file). Inverter loss over nominal inverter voltage: The energy loss when the array is producing voltage below the inverter’s MPP voltage range. Inverter loss due to voltage threshold: The energy loss when the array is producing voltage above the inverter’s MPP voltage range. AC ohmic loss: As with the DC wiring loss, a recommended value of 1% AC loss with respect to the STC value will produce around 0.5% actual energy loss. External transformer loss: Unless actual parameters are available, the default 0.1% iron loss and 1% resistive loss are recommended 7