Solar Module Inspection: 5 Common Issues Found

Solar inspections often find 5-8% efficiency drops from dust (clean if >3mm layer), 3% loss from corroded connections (>0.5Ω resistance), 10% output drop from cracks (>5mm length), hot spots at 120℃+ with faulty diodes, and unstable mounts due to >2mm frame deformation.

Micro-Cracks in Silicon Cells

Industry reports suggest that up to 20% of new modules may contain some level of micro-cracking originating from transportation, installation stress, or even manufacturing. These cracks can lead to a 0.5% to 3% annual power loss in affected modules, significantly impacting the long-term energy yield of a system.

l Power Output Reduction: Cracks disrupt the internal electrical pathways, increasing resistance and reducing current flow.

l Hotspot Formation: Severely cracked cells can become reverse-biased, overheating and potentially damaging the encapsulant.

l Structural Integrity Loss: Cracks can propagate over time, especially under thermal cycling between -40°C to +85°C, leading to complete cell failure.

During manufacturing, cell soldering and laminating apply pressure at temperatures exceeding 200°C. If the cooling rate differs between the silicon and the copper ribbon, stress fractures form. Post-production, rough handling during shipping or installation is a major culprit. A study of damaged modules showed that over 60% of cracks were due to improper transport, where panels were stacked without adequate padding or were subjected to vibrations exceeding 5 G-force.

The most effective tool for identifying micro-cracks is Electroluminescence (EL) imaging. This specialized camera system detects the infrared light emitted by a cell when a current passes through it. Healthy cells glow uniformly, while cracked cells show up as distinct, dark, branching lines. EL imaging can detect cracks as narrow as 2 micrometers. Visual inspection under sunlight is highly unreliable, with a detection rate of less than 15% for sub-visible cracks.

A single, small crack may cause a <1% power loss in that specific cell. However, a web of cracks covering over 10% of a cell's area can lead to a 5-8% power loss for that cell. Since cells are connected in series, the performance of the entire module is limited by its weakest cell. A single fully cracked cell can effectively disable a series string of 10-20 cells, reducing the module's voltage output. This cumulative effect can lead to a 4-6% reduction in a module's total power output over a 5-year period.

Hot Spots from Shaded Cells

When a single cell in a series string is shaded, the other 20 to 40 cells force their current through it, causing it to act as a high-resistance load and dissipate power as heat. Temperatures in these spots can skyrocket to over 150°C, compared to a normal operating temperature of ~45-65°C. This excessive heat carbonizes the encapsulant (EVA), delaminates the module, and can even melt the solder joints or the silicon itself, leading to permanent power loss and a significant fire hazard. Studies indicate that hot spots can accelerate power degradation by up to 30% per year in the affected module and are a root cause in over 15% of all field failures.

l Localized Overheating: Can create temperature differentials exceeding 85°C compared to non-shaded cells.

l Physical Damage: Permanent darkening (encapsulant carbonization), cell cracking, and solder bond degradation.

l Power Loss & Fire Risk: A single severe hot spot can reduce module power output by 5-10% and, in extreme cases, ignite surrounding materials.

Bypass diodes are installed in junction boxes to mitigate this by providing an alternative current path around a group of 18-24 cells. However, their effectiveness has limits. If shading covers more than 33% of a cell group, the diode may not fully activate, allowing a hot spot to form. The most common shading culprits are:

l Persistent Objects: Bird droppings, leaf litter, or accumulated dust blocking as little as 10% of a cell.

l Structural Elements: Adjacent racking, mounting hardware, or non-self-cleaning module frames.

l Temporary Debris: Snow, or shadows from nearby vegetation or structures during low-sun hours.

Hot spots are clearly visible under load, typically when the system is operating at >60% of its peak power. The temperature delta (ΔT) between the hot spot and the non-shaded cells is the critical metric. Industry standards like IEC 62446-3 recommend investigative action for a ΔT greater than 20°C. For a ΔT exceeding 35°C, immediate remediation is required. 

For residential setups, a visual inspection every 3 months is advised, especially after storms or high pollen seasons. Technicians should use drones equipped with thermal cameras for large-scale inspections, which can survey a 1 MWp plant in under 2 hours, identifying faulty modules with 95% accuracy. If a hot spot is detected, the first step is to safely remove the shading source and clean the module. If the discoloration is minor and the temperature normalizes, the module can remain in service with its output monitored. Modules with severe, permanent discoloration or a measured power loss above 5% should be replaced.

Discoloration of Encapsulant Material

This is a widespread issue, particularly in modules manufactured before 2015 and those operating in high-heat, high-humidity environments. Field studies show that over 30% of modules in climates with an average annual temperature above 25°C exhibit some level of discoloration within their 10-year mark. This is not a cosmetic flaw; it directly impedes light transmission. The browning acts as a filter, reducing the amount of photons reaching the silicon cells. The power output loss is directly correlated to the discoloration's darkness and coverage, typically ranging from a 5% decrease for light yellowing to a severe 30%+ drop for dark brown modules, drastically curtailing the system's energy yield and financial return.

Operating temperatures consistently exceeding 75°C and high humidity (above 75% RH). When moisture permeates the module, it reacts with acetic acid released from the EVA, creating a corrosive environment that yellows the material. Ultraviolet (UV) exposure acts as a catalyst, with modules receiving an average annual UV dose of 2800 MJ/m² degrading 35% faster than those in milder climates. The rate of browning is not linear; it follows an exponential curve, with the most severe degradation occurring in the first 5-7 years of exposure to peak conditions before potentially stabilizing.

A 2018 NREL study of a 100 MW portfolio found that modules with severe discoloration (rated Category 4 on a 1-5 scale) had a median power loss of 21.8%. The financial impact translated to an average lost revenue of 8,400 per MW per year,assuming an electricity rate of 0.05/k Wh.

The browning increases the encapsulant's optical density, selectively filtering out the blue spectrum (~450 nm wavelength) most effective for generating electricity. This reduces the cell's short-circuit current (Isc). For a module with 20% of its surface area uniformly discolored to a mid-level amber, expect a 6-8% power loss. If the discoloration is uneven, the resulting current mismatch between cells can force bypass diodes to activate more frequently, adding another 2-4% loss in energy production under partial shadow conditions. The performance decline accelerates as the browning darkens.

Identifying discoloration is straightforward through visual inspection, but assessing its severity is not. Technicians use standard color comparison charts (e.g., 1-5 scale, with 5 being the darkest) to categorize the extent. However, visual rating has a high ~20% inter-observer error rate. For a precise assessment, electroluminescence (EL) imaging is used. The discolored areas will appear darker in the EL image due to reduced current generation, providing a direct correlation to power loss. Spectrophotometers can measure the light transmittance loss of the encapsulant itself, which can drop from a pristine 91.5% down to 75% or lower in severely degraded modules, providing quantitative data to justify replacement.

Faulty Junction Box Seals

In high-humidity environments (over 70% RH), the failure rate of certain sealant designs can double within the first 5 years of operation. The immediate consequence is the corrosion of delicate electrical modules—diodes, terminals, and connectors. This corrosion increases electrical resistance, creates potential arc-fault points, and leads to a cascade of performance and safety issues, including a 2-5% annual power loss in the affected module and a significant fire hazard.

As the module heats to 65°C and cools down daily, the different materials of the plastic box, sealant, and glass backsheet expand and contract at different rates. This differential thermal expansion, which can create micron-sized gaps, slowly degrades the adhesive bond over hundreds of cycles. Simultaneously, prolonged UV exposure weakens the sealant polymer, reducing its elasticity by up to 40% and making it brittle. Once the seal is compromised, ambient humidity, especially in coastal regions with high airborne salinity, enters the box. The presence of moisture, measured as an increase in internal relative humidity from a standard <5% to over 50%, leads to rapid corrosion of the copper terminals and current-carrying parts.

A corroded terminal can have a resistance of >50 mΩ, compared to a clean connection of <1 mΩ. This resistance causes a measurable voltage drop and power loss, which can be identified during a IV curve trace as a reduction in fill factor (FF) by 5-10%. In severe cases, where moisture has caused a bypass diode to fail short-circuited, that entire section of the module (typically 18-24 cells) will be permanently bypassed, leading to a ~33% loss in the module's maximum power output whenever the sun is shining.

Any gap wider than 0.5 mm is a clear red flag. Second, infrared thermography under load is the most effective tool. A faulty junction box with high-resistance connections will show up as a distinct hotspot, often 15-20°C hotter than the surrounding, properly functioning boxes. For preventative maintenance, a insulation resistance test using a megohmmeter can reveal moisture ingress; a reading below 40 MΩ is a strong indicator of seal failure and requires immediate attention.

Frame Misalignment and Gaps

A gap as small as 0.5 mm between the frame and the glass laminate can compromise the entire module's seal, allowing moisture ingress. Industry surveys of large-scale solar farms indicate that roughly 8% of installed arrays exhibit some form of frame misalignment exceeding a 2 mm tolerance within the first 5 years. In regions with high thermal cycling (daily temperature swings of 35°C+), this rate can increase to 12%. The resulting stress concentrations can lead to glass cracking, while moisture penetration directly enables corrosion and potential ground faults, undermining the module's 25-year lifespan promise from the very beginning.

On the production line, an improperly set framing machine can apply uneven pressure, creating a weak adhesive bond on one side of the module. This bond, which should have a tensile strength exceeding 1.2 MPa, might be below 0.8 MPa in these weak spots. During installation, the most common error is the over-torquing of mounting bolts. Applying a torque greater than the manufacturer's specified 15 N-m on a bolt (e.g., torquing to 20 N-m) can induce a permanent >3 mm twist in the aluminum frame, especially on modules longer than 2 meters. This warping creates a gap and misaligns the entire module in the racking system. Furthermore, installing modules on an uneven rail system with a height deviation of more than ±1.5 mm pre-stresses the frames, leading to long-term fatigue failure.

A warped frame redistributes mechanical load unevenly across the glass surface. Under a 2400 Pa wind load, a twisted frame can increase stress concentration on the glass by over 30%, significantly raising the probability of crack formation. Electrically, the gaps provide a direct path for moisture. This can lower the insulation resistance between the live parts and the frame (which is typically grounded) from a required value of >40 MΩ to a dangerous <1 MΩ, creating a ground fault risk. In cold climates, ingested water can freeze within the frame channel, and since ice expands by 9% in volume, it can forcibly widen the gap by 0.1-0.2 mm per freeze-thaw cycle, causing progressive damage.

Technicians use a feeler gauge to check the seal between the glass and the frame; any gap that accepts a 0.5 mm blade is a failure. A digital torque wrench should be used to spot-check the torque of a sample of mounting bolts to ensure they are within ±2 N-m of the manufacturer's specification. For assessing misalignment across an array, a straightedge ruler longer than 1.5 meters is placed across the frames of adjacent modules. A gap larger than 2 mm between the ruler and any module frame indicates a problem that needs correction.