PV Subarrays

The Flat Plate PV Subarrays page allows you to specify the number of strings, tracking and orientation, shading and soiling, and DC derate factors for up to four subarrays of modules.

Note. Before specifying parameters on the PV Subarray page, you should specify the number of modules and inverters and AC derate factors on the Array page.

To model a typical system with a single array, enable a single subarray (Subarray 1) and disable Subarrays 2, 3, and 4.

Modeling multiple subarrays may be useful for the following applications:

A residential or commercial rooftop system with modules installed on different roof surfaces with different orientations.

A ground-mounted system with groups of modules installed at different orientations, with different lengths of DC wiring, or exposed to different shading scenes or soiling conditions.

A system that combines different tracking systems.

Note. You cannot use subarrays to model a system that combines different types of modules or inverters. You can use the Multiple Subsystems analysis option to model a system as a combination of subsystems, which may consist of different types of modules and inverters.

To model a system with a single subarray of modules (typical):

1.On the Array page, either specify the desired array size, or specify the number of modules per string, number of strings in parallel, and number of inverters.

2.On the PV Subarrays page, disable Subarrays 2, 3, and 4.

3.On the PV Subarrays page, for Subarray 1, specify the array tracking and orientation parameters, DC derate factors and optional shading and soiling factors.

To model a system with a multiple subarrays of modules:

1.On the Array page, either specify the desired array size, or specify the number of modules per string, number of strings in parallel, and number of inverters.

2.On the PV Subarrays page, enable Subarrays 2, 3, and 4 as appropriate. Subarray 1 is always enabled.

3.On the PV Subarrays page, specify the array tracking and orientation parameters, DC derate factors and optional shading and soiling factors for each subarray.

String Configuration

By default, when you create a Flat Plate PV case, SAM assigns the Number of Strings in Parallel value from the Array page to the number of strings for Subarray 1, and enables only Subarray 1. If you are modeling a system as a single array, you do not need to enable any other subarrays.

To model a system that consists of multiple subarrays, check Enable for each additional Subarray 2, 3, or 4 that you want to include in the system, and type a number of strings to allocate to each subarray. SAM allocates remaining strings to Subarray 1.

For example, to configure strings for a 10 MW system consisting of SunPower SPR-305 modules, and Advanced Energy Solaron 333 inverters with two subarrays of 5 MW each:

1.On the Module and Inverter pages, choose the SunPower module and Solaron inverter.

2.On the Array page, choose Specify numbers of modules and inverters, and specify 8 modules per string, 440 strings in parallel, and 3 inverters.

3.On the PV Subarrays page, enable Subarray 2, and type 220 for the number of strings allocated Subarray 2.

Note. You can enable any combination of subarrays. For example, you can model a system with two subarrays by enabling Subarrays 1 and 3, and disabling Subarrays 2 and 4.

Tracking & Orientation

The four tracking options allow you specify whether and how modules in each subarray follow the movement of the sun across the sky.

Note. SAM does not adjust installation or operating costs on the System Costs page based on the tracking options you specify. Be sure to use appropriate costs for the type of tracking system you specify.

To specify subarray tracking and orientation:

1.For each enabled subarray, choose a tracking option: Fixed, 1 axis, 2 axis, or azimuth tracking.

If you use an option other than fixed, be sure that the Balance of System cost category on the PV System Costs page includes the cost of installing the tracking system, and that the Operation and Maintenance costs include the cost of maintaining the system.

2.Type a value for the subarray tilt angle in degrees from horizontal. Zero degrees is horizontal, 90 degrees is vertical.

If you are unsure of a value, you can use the location's latitude (displayed in the navigation menu under Location and Resource and on the Location and Resource page), or check Tilt = Latitude if you want SAM to automatically assign the value of the latitude from the weather file to the array tilt angle. Note that SAM does not display the tilt angle when you choose this option, but it does use the correct value in simulations.

3.If the subarray is oriented away from due south in the northern hemisphere, change the default azimuth angle to the desired value. For southern hemisphere locations, change the azimuth value to zero degrees for an array facing due north.

An azimuth angle of 180 degrees in the northern hemisphere, or zero in the southern hemisphere (facing the equator) usually maximizes energy production over the year.

Fixed

The subarray is fixed at the tilt and azimuth angles defined by the values of Tilt and Azimuth and does not follow the sun's movement.

IMG_PVArray-fixed-tilt

1 Axis

The subarray is fixed at the angle from the horizontal defined by the value of Tilt and rotates about the tilted axis from east in the morning to west in the evening to track the daily movement of the sun across the sky. Azimuth determines the array's orientation with respect to a line perpendicular to the equator. For a horizontal subarray with one-axis tracking, use a Tilt value of zero.

IMG_PVArray-one-axis

2 Axis

The subarray rotates from east in the morning to west in the evening to track the daily movement of the sun across the sky, and north-south to track the sun's seasonal movement throughout the year. For two-axis tracking, SAM ignores the values of Tilt and Azimuth.

IMG_PVArray-two-axis

Azimuth Axis

The subarray rotates in a horizontal plane to track the daily movement of the sun. SAM ignores the value of Azimuth.

IMG_PVArray-azimuth-axis

 

Note. For an example of how to use parametric analysis to optimize the tilt and azimuth angles, see Optimize Photovoltaic Array Tilt and Azimuth Angles.

Tilt = Latitude

Assigns the array tilt value with the latitude value stored in the weather file and displayed on the Location and Resource page. Note that SAM does not display the tilt value on the Array page, but does use the correct value during simulations.

Tilt, degrees

Applies only to fixed arrays and arrays with one-axis tracking. The array's tilt angle in degrees from horizontal, where zero degrees is horizontal, and 90 degrees is vertical and facing the equator (in both the southern and northern hemispheres.

As a rule of thumb, system designers sometimes use the location's latitude (shown on the Location and Resource page) as the optimal array tilt angle. The actual tilt angle will vary based on project requirements.

For a horizontal subarray, use a tilt angle of zero.

Azimuth, degrees

Applies only to fixed arrays with no tracking. The array's east-west orientation in degrees. An azimuth value of zero is facing north, 90 degrees = east, 180 degrees = south, and 270 degrees = west, regardless of whether the array is in the northern or southern hemisphere.

For systems north of the equator, a typical azimuth value would be 180 degrees. For systems south of the equator, a typical value would be 0 degrees.

Note. This convention is different than that used in older versions of SAM. Please be sure to use the correct array azimuth angle convention.

Tracker Rotation Limit, degrees

The maximum and minimum allowable rotation angle for one-axis tracking. The default value of 360 degrees allows the tracker to follow the full movement of the sun from horizon to horizon.

Shading mode for 1 axis tracking

Backtracking is a PV tracking strategy that attempts to avoid row-to-row shading of modules in an array with one-axis tracking.

Without backtracking, a tracking array typically points the modules directly at the sun. However, for an array with closely spaced rows, modules in adjacent rows may shade each other at certain sun angles, which can dramatically reduce the array's power output. With backtracking, under these conditions, the tracker will orient the modules away from the sun to avoid shading.

When you run a simulation with backtracking, SAM adjusts the tracking angle of different rows to minimize row-to-row shading. The following diagram illustrates how backtracking reduces row-to-row shading:

IMG_PVBacktracking-Description

These options are available only when you choose 1 Axis tracking:

Self-shaded models the array with no backtracking, but does estimate losses from self-shading caused by shading of modules in one row by modules in neighboring rows based on the GCR value you specify. This is an improvement over previous versions of SAM that assumed that rows in arrays with one-axis tracking were ideally spaced to have no self shading.

Backtracking adds backtracking to the self-shaded option, and adjusts the tracking angle to minimize shading.

None uses the approach of the previous versions of SAM. Because this option does not account for any self-shading, it tends to overestimate the array's production. We included this option to allow for comparison between the different options to see the effect of the self-shaded and backtracking options, and for comparison between results from this version and older versions of SAM.

Ground coverage ratio (GCR)

The ratio of the photovoltaic array area to the total ground area. An array with a low ground coverage ratio (closer to zero) has rows spaced further apart than an array with a high ground coverage ratio (closer to 1).

The ground coverage ratio must be a value greater than 0.01 and less than 0.99.

To see the effect of the ground coverage ratio, you can compare the hourly simulation results Subarray n Nominal POA total irradiance (kW/m2) and Subarray n POA total irradiance after shading only (kW/m2). You can also run a parametric analysis on the ground coverage ratio value to find its optimal value.

Note. The ground coverage ratio is completely independent from the Packing Factor variable on the Array page and has no effect on the Total Land Area value on the System Costs page. If your analysis uses costs in $/acre, you should choose a packing factor value that is consistent with the ground coverage ratio.

Shading & Soiling

The shading and soiling factors reduce the solar radiation incident on the subarray.

SAM calculates the nominal incident radiation value for each simulation time step using solar radiation values from the weather file, and sun and subarray angles. When you specify soiling or shading factors, SAM multiplies the nominal incident radiation value by each soiling and shading factor that applies to the time step.

You can see the effect of the derate factors in the hourly results (and in the monthly and annual averages) in the Tables on the Results page. In the hourly results:

Incident Beam = Nominal Incident Beam × Soiling Factor (the Soiling factor may be different for different months)

Incident Diffuse = Nominal Incident Diffuse × Soiling Factor (the Soiling factor may be different for different months)

Configure shading scene

The shading scene defines the effect of shadows from nearby objects on the subarray.

Click Edit shading to specify a set of shading factors for each subarray. See Shading for details.

Monthly soiling factors

You can use the soiling factors to represent incident radiation losses due to dust, snow or other seasonal soiling of the module surface that reduce the radiation incident on the subarray.

Soiling reduces the hourly total radiation incident on the array (plane-of-array irradiance) that SAM calculates from radiation data in the weather file, and array and sun angles.

Click Edit values to specify a set of monthly soiling factors.

Annual Average Soiling

The product of the twelve soiling derate factors.

Pre-inverter Derates (DC)

The pre-inverter DC derate factors account for DC electrical losses in the system that the module model does not calculate, such as electrical losses in the DC wiring that connects modules in the array.

The five DC derate factor categories (mismatch, diodes and connections, etc) are to help you keep track of factors influencing the total DC derate factor. The total DC derate factor is the product of the five factors. SAM uses the total DC derate factor in calculations.

You can see the effect of the DC derate factor in the hourly results (and in the monthly and annual averages) in the Tables on the Results page. In the hourly results:

Net DC Array Output = Gross DC Array Output × Estimated DC Power Derate 1
                         × Estimated DC Power Derate 2 × Estimated DC Power Derate 3 × Estimated DC Power Derate 4  

Note. For a discussion of derate factors in the context of the NREL PVWatts model that includes suggested values, see the Help system for the web version of PVWatts at http://pvwatts.nrel.gov/. Note that SAM only includes derate factors for losses that the module, inverter, and shading models do not calculate.

The five DC derate categories represent the following sources of DC electrical loss:

Mismatch

Slight differences in performance of individual modules in the array.

Diodes and connections

Voltage drops across blocking diodes and electrical connections.

DC wiring loss

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

Tracking error

Inaccuracies in the tracking mechanisms ability to keep the array oriented toward the sun. The default value of 100% assumes a fixed array with no tracking. Applies only to systems with one- or two-axis tracking arrays.

Nameplate

Accounts for accuracy of the manufacturer's nameplate rating, often for the performance degradation modules may experience after being exposed to light.

The total DC derate factor for each subarray represents the subarray's total DC electrical loss:

Estimated DC power derate

The total pre-inverter derate factor is the product of the five DC derate factor categories.

In the hourly simulation, SAM calculates the net DC array output at the inverter's input for each hour by multiplying the gross DC array output by the total estimated DC power derate. A derate factor of 1 is equivalent to no derating. A derate factor of 0.75 would reduce the calculated array DC output by 25%.

Subarray Mismatch

The subarray mismatch option is an advanced option that calculates the effect of voltage mismatch between subarrays for systems with two or more subarrays.

Because the number of modules per string is the same for all subarrays in the system, the subarrays have the same nominal string voltage. However, during operation each subarray is exposed to different radiation levels and wind speeds, which causes the cell temperatures in each subarray to differ. Because cell voltage depends on cell temperature, each subarray will have slightly different voltages. This voltage mismatch causes electrical losses so that the inverter input voltage is less than the array's maximum power voltage.

SAM uses two methods to estimate the inverter input voltage.

Averaging Method (check box clear)

SAM calculates each subarray's output at its maximum power point voltage (Vmp), and assumes that the inverter DC input voltage is the average of the subarray Vmp values.

This method is fast and works with both the Sandia and CEC module option.

Iterative Method (check box checked)

SAM tries many string voltages to find the value that results in the maximum power from the array.  For each test voltage, it finds the current from each subarray, and adds up the currents. Then the power is the summed current times the test voltage. The test voltage that yields the maximum power is used for each subarray to calculate the total output power, and this voltage is also the inverter DC input voltage.

This method takes on the order of 10-30 seconds for a system with two or more subarrays.

Notes.
 
The subarray mismatch option is only active with the CEC model option on the Module page.
 
The iterative method typically results in lower system output over the year than the averaging method. The averaging method is a reasonable approximation of mismatch losses, and is suitable for simulations where the main metric of interest is the system's total annual output for financial analysis. The difference in annual output between the two methods is often less than one percent.