The number of PV systems is increasing all over the Korea. But are all of these systems performing at the highest possible level, even after five, 10, or more years of operation? Here are some of the common signs and symptoms of under performing PV arrays—and their remedies.
Assessing Your System
Figuring out if your PV system is working properly can often be difficult, especially for owners of smaller residential PV systems who have never been given proper instruction on system monitoring. Many folks keep tabs on their grid-tied PV systems just by examining their monthly electric bills. They know roughly what the bills have been since their PV system was installed, and assume everything is fine if their payments stay about the same.
In areas with production-based incentives, a separate meter records PV system generation. This can make monthly comparisons of PV performance more straightforward from year to year. Any significant drops in production for a particular month from one year to the next should raise a red flag—while it could mean only that there was less sun than the previous year, it is a good idea to check the system for problems.
Net-metered PV systems can be difficult to pin down since the utility’s meter only shows excess PV energy produced after all of the home’s electrical usage. If the loads change from year to year, then the net production (if there is any) will change as well, even if the PV system is performing as in the past. Most grid-tied inverters display instantaneous power and energy production totals, but someone needs to check them regularly, record the readings, and compare them from year to year to really know if the system is performing to specifications. And what happens if the system was not installed properly in the first place and has never worked properly? We need a way to know if a system is doing what it is supposed to do.
System Spot-Check: Power Output
Let’s use a 3 kW net-metered PV system as an example. The system owners notice that their monthly electric bills are a lot higher than the previous year. Nothing looks amiss—the modules are still on the roof, and the inverter has a little green LED lit up when the sun shines. The inverter’s screen shows the array is producing 925 watts at about 3 p.m. Should this 3 kW array be producing more?
With a little math and a couple of measurements, we can get a pretty good idea of what an array should be producing any time there is full sun. Here are the parameters you can use to calculate PV system power output:
STC ratings. PV modules are factory-tested to determine their power output. When we talk about the size of a PV system or module, we are using the “STC ratings”—the numbers detailed on the back of the module and on its data sheet. STC, or “standard test conditions,” is a solar irradiance of 1,000 W per square meter and a module cell temperature of 25°C (77°F). Although both of these values impact a PV module’s output, its rating at STC rarely reflects real-world conditions. The result is that a PV module rated at 250 W STC will only produce 250 W under those specific conditions. In full sun and up on a rooftop, the actual conditions are usually much different. For instance, during the winter in an area with no snow and a slight haze, the irradiance will be lower (perhaps 700 W per square meter) and module cell temperature might be close to 25°C ( 77°F). In the summer, irradiance might be closer to 1,000 W per square meter, but module cell temperatures may be 60°C (140°F).
When calculating the power output, we’ll start with the STC rating of the PV array—in this case, 3,000 watts. Then we will include several derate factors, which will lead us to the array’s expected power output.
Module temperature. The higher its cell temperature, the lower the PV module’s voltage will be. With lower voltage comes less output (power). Even if it’s 25°C (77°F) outside, in direct sun modules will heat up much higher than the ambient temperature. Systems utilizing ground- and pole-mounted systems, and ones on elevated racks on low-slope roofs benefit from air circulation; in full sun, they tend to be 20°C to 25°C above the ambient air temperature. Systems that are flush-mounted on pitched rooftops have much less air flowing under the modules and can be 35°C to 40°C above ambient air temperature.
We could measure the air temperature with a thermometer and estimate the module cell temperature from the temperature adders above, but this would not be very accurate. A much better way is to use an infrared thermometer on the back of the module, if possible, since the glass front can cause skewed readings (see “Tools of the Trade” sidebar). It’s a good idea to take the temperature in a couple of places throughout the array and average the results. If the array is easily accessible, temperature sensors will provide the most accurate readings. Just be sure the sensors are measuring the module cell temperature, and not the ambient air or module frame temperature.
In our example, even though the air temperature is a moderate 18°C (65°F), we measure the module cell temperature at 53°C (127°F). Next, we need to convert this value into a temperature factor to use in our final calculation. First, find the difference between the module cell temperature and STC (25°C), converting Fahrenheit to Celsius:
Temperature difference = 53°C – 25°C = 28°C
Next, calculate the derate factor for the power we expect to lose from the increased temperature (it is preferable to use the specific module’s temperature coefficient of power instead of the estimated -0.5% per °C, which is quite conservative):
Temperature derate factor = 1 + (-0.5% per °C difference × 28°C) = 0.86
Our module cell temperature is higher than at STC, and the temperature factor should be less than one since the overall array power will be lower than at STC. If the module cell temperature is less than 25°C, then we should expect a temperature factor greater than one.
Irradiance. The more sunlight (irradiance) hitting the modules, the more current they will produce. Irradiance is measured with a handheld pyranometer. It needs to be placed at the exact same tilt angle and orientation as the PV array, ideally lined up adjacent to a module.
Many things affect the irradiance levels at the PV array, including time of day, season, elevation, cloud cover, and sometimes even reflection from snow. Unlike module cell temperature, irradiance levels can change very rapidly. A cloud passing by the sun can cause levels to spike, drop, and then return to normal (edge-of-cloud effect) in less than a minute! It’s important to look for a window of time, on a clear sunny day, when you can take a couple of readings that you expect to be similar, and record the inverter’s output power between the irradiance readings. Even better, have a friend assist, with one person recording irradiance and another recording inverter output simultaneously.
For our example, an irradiance reading of 875 W per square meter is recorded at 3 p.m. Although the sky is clear, there is a slight haze in the air. This was taken at the same time as the inverter output reading of 925 W (noted above). Since 875 W per square meter is less than the 1,000 W per square meter rating at STC, we should be seeing less power than the STC ratings, and an irradiance factor of less than one. To calculate, we simply divide our reading by 1,000:
Irradiance Factor = 875 ÷ 1,000 = 0.875
While irradiance levels of less than 1,000 W per square meter are common in most of the United States, at higher elevations, and with snow on the ground, higher irradiance levels are possible, yielding an irradiance factor greater than one.
“Other Losses” Factor
Depending on the PV system, other factors may affect PV system output. Here are some common ones used in NREL’s PVWatts calculator:
PV module nameplate DC rating: Testing has shown that module nameplate power ratings tend to be a bit optimistic, but by how much? A good place to start is the manufacturer’s power tolerance specification. For example, you might see “Pmax = 250 W, -5%/+10%” on the module data sheet, which means this module is warranted to produce between 237.5 and 275 W at STC. It’s generally best to use the lowest rating. In this example, we will use the -5% tolerance, for a nameplate rating factor of 0.95.
Inverter: We also need to account for the power it takes to convert the DC electricity from the PV array to AC, and we can do so by factoring in the inverter efficiency. While inverter specification sheets will list “maximum efficiency,” a more useful value is the “weighted efficiency,” which accounts for the percentage of time the inverter commonly spends at various power levels. This gives a better indication of the inverter’s real-world efficiency. Most grid-direct inverters have weighted efficiencies greater than 90%. You can find inverter weighted efficiency ratings on the Go Solar California website: (bit.ly/CAeligInv). In this example, we use 0.96 for our inverter efficiency factor.
Module mismatch: Include this factor unless the PV system has maximum power point tracking (MPPT) capability at the module level, using microinverters or DC optimizers. Due to slight differences in modules’ IV curves, or power output profiles, the one MPP used for an entire array or series string will not be a perfect fit for each individual module. A small power loss will result. If there are different makes and models of modules in the array, the power loss will be even greater. If individual series strings of modules have their own MPPT, the loss will be less. Most PV arrays with one kind of module and a single MPPT for the entire array will experience a 2% loss due to module mismatch, so we will use a 0.98 mismatch factor.
Wiring losses: Wire connections and the DC wire runs introduce losses due to resistance. Since we are measuring inverter output at the inverter, we should not include AC wire losses. Most well-designed systems will have about a 0.5% loss due to connections, and about a 2% loss in the DC wiring. If system designers did not account for voltage drop on a long wire run, or there are poor wire connections, these losses might be greater. We’ll assume our system fits the numbers stated above, for a total DC wiring loss of 2.5%, for a 0.975 wiring loss factor.
Soiling: Modules get dirty. In places with lots of dust, few significant rain storms, and buildup of other small debris, this factor can be significant. Modules set at a lower tilt tend to have more soiling. Let’s assume we’re in an area with “normal” dust, and our array is tilted to about 40° (steep enough to shed most gunk). The modules don’t look dirty from the ground, but it hasn’t rained in a while. We will use 0.97 for our soiling factor.
Age: On average, crystalline silicon modules lose about 0.5% of their output power capacity per year. A new installation would have no age-related losses. The array in our example was installed six years ago, so we’ll assume a 0.97 age factor. (Note that degradation rates may vary due to climate effects and may not be linear over time.)
Shading: Quantifying the effects of shading on annual production is fairly easy with site analysis tools. But accurately determining the effects of partial shade on an array at any one time is very difficult. Therefore, you need to choose a time when the array is not shaded to make your measurements.
Now that we have determined all of the other losses, we find the total by multiplying them together. This number will be our final factor:
Other losses factor = 0.95 × 0.96 × 0.98 × 0.975 × 0.97 × 0.97 = 0.82
Putting it All Together
Now we have enough information to calculate what our PV array should be producing by multiplying the STC watts by the three main loss factors:
Expected inverter output (W) = STC watts × Module temperature factor × Irradiance factor × Other losses factor = 3,000 W × 0.86 × 0.875 × 0.82 = 1,851 W
Recall that the output was 925 W as shown on the inverter display. According to calculations, this PV array should be producing about twice what the inverter was showing. This is not even close to the expected output. We need to find out what is wrong, but where do we start?
With troubleshooting, anything is possible. Although these procedures are a good place to start, don’t limit yourself to them. Common sense, experience, and keen observation can help find solutions.
Error codes on your inverter or remote monitor.This could be an LED light, a specific code flashing on the display, or a ground-fault indicator. Consult your installer or the inverter’s manual, or call technical support to determine what the code means. If there is indication of a ground fault, immediately contact your PV installer or other qualified person, as there could be danger of electric shock on parts that are not normally energized (such as metal conduit, module frames, ground wires, metal enclosures, etc.). Do not continue investigating the system by yourself if there is a ground fault!
Inspect your PV array. Is any of the glass cracked? Do you notice any missing parts? Make sure the modules are aligned and no corners are sticking up or down—heating and cooling cause expansion and contraction, which can lead to mechanical failure within the rack and modules. Look for loose bolts, bent frames, and cracked glass. Snow load can also damage an array.
Look for yellow or brown burn marks on both the front and the back of the modules. If you can’t easily access the array, you can do this inspection from the ground with binoculars. Diodes and solder connections within the module and its junction box can fail, causing areas to heat up and burn or melt.
Check underneath the array. Are there any loose, dangling wires? Expansion and contraction can also cause taut wires to pull loose from their connectors, or cause the connectors to partially open. Poor connections will create heat from increased resistance and can melt the connectors, junction boxes, or leave burn marks on the white back-sheet.
Is any of the wire insulation missing or damaged? Small animals will often build nests underneath arrays and seem to have an appetite for wire insulation. Has debris accumulated? Leaf litter buildup can create a place for moisture to collect, and loose connections contacting moisture can then cause intermittent faults (especially when the insulation is missing) and, eventually, corrosion.
Try to find problem strings or modules. If you have module-level monitoring, such as with microinverters or DC optimizers, it should be easy to see if one or more modules are underperforming. If your PV system doesn’t use this technology, each series string’s open-circuit voltage and operating voltage should be tested and recorded, as well as its operating current (using a clamp-on meter). You can then compare string or module measurements with each other or against calculated expectations to find any poor performers. Note that anywork or measurements on exposed energized parts should be done only by trained individuals. These are often high-voltage systems, which can kill or injure.
Using an infrared camera can also help spot problems within modules, but only if you can get your hands on one and know how to use it! (For more information, see the “Potential PV Problems & Tools for Troubleshooting” .
Check production history. Examining past electric bills, and inverter and system monitoring data can help you pin down when the array started under performing. Is the problem intermittent? This might be due to loose connections or wet debris facilitating a short. Was there a sudden drop in production, or did it seem to happen gradually? Has it always been this way? Perhaps a wire was pinched during the installation and the array has never been producing full power. Finding out the time of year or coordinating the loss of production with other events (storms, grid outages, roof repairs, etc.) can also provide clues about the underlying issue.
Take the problem area apart. If the array’s voltage and current meet specifications at the array output, but not at the inverter input, then the problem lies between these points. Check junction and combiner boxes for loose connections, compromised wiring, or blown fuses. Thermal cycling can cause wire connections to loosen; even properly installed wires can come loose over time. Check the inverter and disconnects for the same. If the inverter input meets specs, but its output does not, then it’s likely there is an issue within the inverter itself, and the manufacturer will need to be consulted.
If you’ve narrowed down the problem to the array, sometimes it’s necessary to inspect the array wiring and rack up close, as well as isolate and test modules. Check all of the module frames, junction boxes, connectors, glass, and backsheets. An IV curve tracer can be helpful in finding underperforming series strings (see “Tools of the Trade” sidebar) so the entire array does not need to be disassembled. Note: Only qualified individuals should work on the array, move modules, or expose or take apart any of the wiring.