Definitions & references

This page serves as a reference for all inputs to Solesca. It will help you understand all of the necessary inputs to create layouts and run accurate energy models.

First off, it's good to mention that we use NREL's System Advisor Model (SAM) on our backend for energy simulations. This guide will explain how to interface with the model via Solesca, but for any model-specific questions, you can reference the SAM Help (opens in a new tab) page or the SAM Photovoltaic Model Technical Reference (opens in a new tab). For convenience, we've linked specific parts of the SAM documentation where applicable. And as always, please reach out to us with any clarifying questions, we're here to help!

Field

Field height

If the field is representative of a structure (e.g. carport or building), should be the height of that structure. Otherwise, if the field is just the ground, this should be set to zero.

Azimuth

This has different meanings based on the racking type. In all cases, this is defined in degrees clockwise from north (e.g. N = 0º, E = 90º, S = 180º, W = 270º).

Fixed-tilt: The direction the panels face. In the Northern Hemisphere, default would be 180º (south); in the Southern Hemisphere, the default would be 0º (north). *Note: we do not currently automatically change this if you're in the Southern Hemisphere; this must be done manually.

Carport or flush mount: The direction the field (and, consequently, the panels) face. If there's a pre-existing structure (e.g. a pitched roof), should be determined by that structure; otherwise, the defaults from fixed-tilt apply.

Tracking and east-west: This is the direction of the long axis of the racking/tracking structure. The default is 180º, although there's not really a difference of setting it as 0º. Either value means the long axis is running north/south.

Layout alignment

This offers additional control over how the panel layout is created. There are four options:

Grid: All frames are aligned to one another in a rectangular fashion. Rows start and end at the same point, giving clean east/west and north/south lines for the layout.

Left: Aligns the panels off of the southern edge(s) of the field.

Center: Rows are centered within their slice of the field.

Right: Aligns the panels off of the northern edge(s) of the field.

Module & Electrical

Module

The photovoltaic module to use for this field. To add modules to your organization, you can select one of our library modules from the CEC or upload your own PAN file at Modules (opens in a new tab).

Bifacial transmission factor

The fraction of light that passes through the solar modules in the racking structure. Recommended to leave as the default value, 0.013. Only enabled if bifacial is on for this module.

The transmission fraction is meant to account for light that may pass through or around the modules in each row, so it should not be calculated based on the row spacing. The bifacial model calculates the space between rows based on the GCR and the geometry you specify on the Shading and Layout input page." -Paul Gilman, NREL (opens in a new tab)

Bifaciality

The ratio of rear side efficiency to front side efficiency. Found on most datasheets for bifacial modules, usually in the 0.7-0.8 range. Only enabled if bifacial is on for this module.

Inverter

The inverter to use for this field. To add inverters to your organization, you can select one of our library inverters from the CEC or upload your own OND file at Inverters (opens in a new tab).

Inverter count

How many inverters to use for this field. The inverter count times the inverter's nameplate power is equal to the AC nameplate power for the field. If the inverter count is locked (by clicking on the padlock icon), the inverter count will stay as-entered, and the DC/AC ratio will update based on the inverter count. Otherwise, if the inverter count is unlocked (with the unlocked padlock icon appearing next to it), it will automatically be updated based on the set DC/AC ratio. There is no default value in Solesca, since it changes based on field sizing, but it will automatically be calculated based on our default DC/AC ratio.

DC/AC ratio

The ratio of DC nameplate to AC nameplate for the field. It's common to slightly undersize inverters, resulting in this value being greater than 1 (usually in the 1.1-1.4 range). If the DC/AC ratio is locked (by clicking on the padlock icon), the DC/AC ratio will stay as-entered, and the inverter count will update based on the DC/AC ratio. Otherwise, if the DC/AC ratio is unlocked (with the unlocked padlock icon appearing next to it), it will automatically be updated based on the set inverter count.

Modules in string

The number of modules to wire together in series. A very rough calculation for minimum and maximum modules per string is to take the inverter's minimum and maximum voltages and divide them by the module's minimum (Vpmax) and maximum (Voc) voltages, respectively. These values can be found in the datagrid for modules (opens in a new tab) and inverters (opens in a new tab).

*This is a very important value to get correct when it comes to running energy simulations. We're going to be introducting an automatic calculator for it soon, but in the meantime, our default value of 20 likely needs to be changed, depending on the module and inverter you have selected.

Racking

Type

Solesca offers six different racking types, described below.

• Fixed-tilt: The modules are on a flat surface (ground or roof) and are at a set fixed tilt above horizontal.
• Flush mount: The modules are flush against a tilted (or flat, if tilt is set to 0º) surface, such as a pitched roof. The direction the roof is facing is determined by the azimuth angle. Modules will always have 0º of tilt relative to the underlying surface in this situation. See notes on flush mount vs. carport below.
• Carport: Exactly the same layout properties as flush mount, but has different thermal characteristics. Carport is modeled with an open back that allows for more airflow and better thermals, whereas flush mount is modeled with a closed back that is up against a surface. If you switch a flush mount project to the carport racking structure, you will notice that the carport structure has a slightly higher production because of these better thermals that allow for cooler and more performant modules.
• East-West: A "tent-like" fixed-tilt structure where in one row, half of the modules face east, and the other half face west, meeting at a peak at the top. Technially, the direction the modules face is determined by the azimuth angle set. If set to 180º, the modules will face the nominal east-west directions, but for example, if set to 90º (or 180º), the modules will face north-south. The only guarantee is that the other half will face 180º in the opposite direction as the first half. It's helpful to enter 3D mode to view this racking structure.
• Single-axis tracking: The most common tracking structure where the axis of tracking is aligned north-south (180º azimuth) and the modules rotate around that axis, starting in the east in the morning and finishing in the west at night. Like east-west racking, it's possible to change the azimuth angle to not be 180º, but is recommended to leave it as this value.
• Dual-axis tracking: A much less common racking structure where the panels can follow the sun with two degrees of freedom.

Tilt

Has a few different meanings, depending on racking structure, as described below.

• Fixed-tilt and east-west: The tilt of the panels above horizontal. E.g. 0º is flat, 90º is vertical.
• Flush mount and carport: The tilt of the underlying surface. Panels will be at 0º tilt relative to the underlying surface, i.e. flush. E.g. could be set to 30º to model a roof pitched at 30º above horizontal.
• Single/dual-axis tracking: Tilt has no meaning here and is not shown as an input.

Rotation limit

Only shown for single-axis tracking. The maximum degree limitation that trackers can tilt with respect to the horizontal. Usually between 45º-60º, depending on the manufacturer.

Backtracking

Only shown for single-axis tracking. Whether or not to enable backtracking in the energy simulation. Backtracking "flattens" out the angle of the panels in the early and late hours of the day to minimize self-shading losses, rather than directly following the sun, which would cause lots of shading when the sun is low in the horizon. If using single-axis tracking, this should be enabled if your trackers support it (they likely do) and you're using silicon PV modules. If using CdTe modules, such as First Solar's, consider disabling this.

Orientation

Which way the PV modules should be orientated in the racking structure. Portrait means long side horizontal, vertical means short side horizontal.

Module height

Has a few different meanings, depending on racking structure, as described below.

• Fixed-tilt and east-west: The height of the lowest edge of the modules to the ground/roof, i.e. clearance.
• Flush mount and carport: The offset distance of the modules, perpendicular to the underlying surface. E.g. 0ft will be flush, 1ft will be a one foot offset.
• Single/dual-axis tracking: Height of the center of rotation, i.e. torque tube height.

Frame · up

The number of modules "in portrait", or stacked on top of one another.

Frame · wide

The number of modules along the width of the frame. If set to one (and frame up is set to one as well), we'll lay out individual modules, which can be desirable for rooftop/carport projects. For tracking projects, it's recommended to set this to the number of modules in string / the length of the tracker in modules.

Vertical module spacing

The gap between modules in frame · up.

Horizontal module spacing

The gap between modules in frame · wide.

Peak spacing

Only shown for east-west racking. The gap between the peak of the modules.

Layout & simulation

Setback

The distance to inset modules from all edges from the field.

Albedo

The source for the monthly albedo (reflectivity) values for the energy simulation. By default, it will just use the values from the weatherfile, but you can override this on a per-field basis (Custom) or create an albedo template at Albedos (opens in a new tab) and select that. Matters the most for bifacial modules, but has an impact for monofacial modules as well because of ground reflectivity. 0 = black body, 1 = reflects all incident radiation.

GCR

Ground coverage ratio. A higher GCR means denser panel coverage, and vice versa. This has two different definitions, but the one we use is the projected frame up distance divided by row pitch. It can help to think of it this way: looking overhead, if you draw a box the width of a frame, starting at the front edge of one row and going to the front edge of the next row, the GCR will be the percentage that is covered by panels. Automatically updates if pitch or row spacing changes.

Span-to-rise

The ratio of "span" (row spacing) divided by "rise" (the vertical increase from the front of a frame to the back).

Pitch

Distance from the center of one row to the center of the next (alternatively, distance from the front edge of one row to the front edge of the next). A common misconception is that this is related to tilt somehow (such as pitched roofs). In realtiy, it is just a measure of distance, and has nothing to do with tilt. Automatically updates if GCR or row spacing changes.

Row spacing

The spacing between rows of panels from the rear edge of one row to the front edge of the next. Can be thought of as the amount of room to walk or drive between along rows.

Frame spacing

The gap between rows, along the axis of the row. Set to zero by default.

Weatherfile

The all-important weatherfile, which is the heart of the energy model. By default, we use the latest NSRDB file. If you have a SolarAnywhere subscription, you can input your API key at Integrations (opens in a new tab) and select that from the list of options as well.

Losses & Advanced Settings

Setting proper loss values is crucial to obtaining accurate energy numbers.

Soiling/snow loss

Soiling and snow losses account for the accumulation of dirt, snow, and/or other debris of the top of solar panels. These are set month-by-month. This loss reduces the plane-of-array (POA) irradiance by the percentage entered. A standard value of 2% is set as default. For areas the receive snow, consider increasing the values in the winter months. Frequently cleaning will reduce this number, and vice versa.

Per SAM docs (opens in a new tab):

Irradiance losses account for reduction in incident solar irradiance caused by dust or other seasonal soiling of the module surface that reduce the radiation incident on the subarray. Soiling losses cause a uniform reduction in the total irradiance incident on each subarray.

SAM calculates the nominal incident irradiance value for each time step using solar irradiance values from the weather file, and sun and subarray angles. When you specify soiling losses, SAM adjusts the nominal incident irradiance value by each soiling loss percentage that applies to the time step. You can see the effect of soiling losses in hourly results by comparing values of the nominal POA irradiance with the "after shading only" and "after shading and soiling" values. The radiation incident on the subarray is the POA total irradiance after shading and soling value (W/m2).

DC wiring loss

Resistive (ohmic) losses caused by DC cabling.

Per SAM docs (opens in a new tab):

Resistive losses in wiring on the DC side of the system.

Light-induced degradation loss

Light-induced degradation (LID) can happen to crystalline silicon solar modules after initial sun exposure.

In Solesca, this is combined with module quality loss to make up the nameplate loss, which is directly passed to SAM.

Module quality loss

Accounts for any difference between the manufacturer's specified nameplate value of the PV module vs. real-world performance. Can be either negative or positive, where a negative loss represents a gain, and a positive loss represents a regular loss.

In Solesca, this is combined with light-induced degradation loss to make up the nameplate loss, which is directly passed to SAM.

Module mismatch loss

Not all modules in a string are indentical. Since the lowest current of a module in the string determines the current of the entire string, this can cause losses.

Per SAM docs (opens in a new tab):

Slight differences in performance of individual modules in the array.

Diodes and connections loss

Per SAM docs (opens in a new tab):

Voltage drops across blocking diodes and electrical connections.

DC optimizer loss

Per SAM docs (opens in a new tab):

Accounts for power losses of any power conditioning equipment installed with the array. SAM does not explicitly model DC/DC conversion losses, but you can account for them here.

Tracking error loss

This only appears if you have one- or two-axis tracking selected. Generally speaking, you can leave this value as 0.

Per SAM docs (opens in a new tab):

Inaccuracies in the tracking mechanisms ability to keep the array oriented toward the sun. The default value of zero assumes a fixed array with no tracking.

Rear soiling loss

This only appears if you have bifacial mode enabled. If you have bifacial rear shading, you can enter it here as well.

Per SAM docs (opens in a new tab):

A percentage of the irradiance incident on the rear-side of the bifacial array to account for soiling on the rear side of the array. A percentage of the irradiance incident on the rear-side of the bifacial array to account for shadows of racking equipment on the rear side of the array. to account for soiling on the rear side of the array."

Bifacial electrical mismatch

Only appears if bifacial mode is enabled.

Per SAM docs (opens in a new tab):

For bifacial modules, accounts for electrical mismatch between modules in the array caused by variation of irradiance on the the rear-side of the array.

Transmission loss

Per SAM docs (opens in a new tab):

A reduction of the photovoltaic system's AC output due to wire losses in a transmission line.

AC wiring loss percent

Per SAM docs (opens in a new tab):

Loss to account for electrical losses in AC wiring between the inverter and the grid connection point.

Transformer no load loss

*Caveat: further research needs to be done for an exact PVsyst analog.

Per SAM docs (opens in a new tab):

The transformer's rated no load loss as a percentage of the total inverter AC capacity. This is a constant loss caused by the magnetizing current in the transformer's core."

Transformer load loss

*Caveat: further research needs to be done for an exact PVsyst analog.

Per SAM docs (opens in a new tab):

The transformer's rated load loss as a percentage of the inverter's AC output. These represent losses in the transformer's primary and secondary coil wiring that vary with the inverter's electrical output."

System unavailability loss

Accounts for unexpected system failures or maintenance. Applied direct as an AC loss adjustment. On the 8760, in the final column, "System net AC output power," this is averaged over the course of the year, even though this is not how the loss would work in reality (it would be a discrete period of time). This is to prevent random "holes" in the 8760.

Sky model

How diffuse (scattered) radiation is modeled. It's recommended to keep this as Perez.

Per SAM docs (opens in a new tab):

Isotropic The isotropic method assumes that diffuse radiation is uniformly distributed across the sky, called isotropic diffuse radiation.

HDKR The Hay-Davies-Kluchr-Reindl combination method accounts for the increased intensity of diffuse radiation in the area around the sun, called circumsolar diffuse radiation, in addition to isotropic diffuse radiation.

Perez The Perez method is the default value and is best for most analysis. It accounts for horizon brightening, circumsolar and isotropic diffuse radiation using a more complex computational method than the Reindl and Hay and Davies methods.

Shade mode

Controls the interrow shading model. NOTE: For carport and flush mount racking types, this is hard-coded to be None, since all of the modules exist on the same plane (near shading from the racking structures will still apply to adjacent rows). For east-west racking, it is also hard-coded to None, so that it can be replaced with our in-house east-west self-shading model.

Per SAM docs (opens in a new tab):

For the Standard (non-linear) option:

• The cell material is crystalline silicon, either mono-crystalline or poly-crystalline. The self-shading model does not work for modules with thin film cells. SAM indicates the cell material on the Module page under Physical Characteristics.
• Each module in the array consists of square cells arranged in a rectangular grid with three bypass diodes.
• The array uses the fixed or one-axis tracking option on the System Design page. The self-shading model does not work for two-axis or azimuth-axis tracking.

For the Thin film (linear) option, the subarray's DC output responds linearly to the reduction in plane-of-array irradiance.

Obstructions

Treat as a field obstruction

If you are just trying to remove a group of modules, it's generally a good idea to keep this disabled. This is the default behavior. If you are trying to remove a large chunk of the field, it usually makes sense to enable this. If the obstruction is not near the starting point of the layout (e.g. at the top of the field for a top-down layout), this will likely have no effect.

When enabled, the obstruction will be subtracted from the field before the layout is generated. This means that the obstruction will be taken into account when determining the starting point of the field, i.e. the layout may shift to be as close to the obstruction as possible.

When disabled, the layout will be generated first, and obstructions will only remove panels after it has been generated. This means that the layout will not shift due to the obstruction, rather any panels that intersect with the obstruction will be removed.

Obstruction Types

You can specify the obstruction type between the below obstructions. This will automatically set the height and setback based on the type. Also, it will update the name in the layers panel to easily identify your different obstructions.