PV module construction and materials: glass to junction box

A PV module looks simple from the outside: a sheet of glass, a frame, two cables. Underneath is a laminated stack of six or seven distinct materials, each chosen to survive 25-plus years of thermal cycling, UV exposure, humidity ingress and mechanical load, at a manufacturing cost that has to compete on cents per watt.

This is written for engineers, procurement staff and installers who need to understand what is inside a module well enough to read a datasheet critically, evaluate a bill of materials, or diagnose a field failure. It is not a manufacturing process guide; it is a materials and reliability guide.

Every material choice in the stack is a trade-off between cost, optical performance, and long-term durability. Cutting cost in one layer - a thinner backsheet, a cheaper encapsulant - often shows up as a warranty claim eight to fifteen years later, well after the original purchasing decision has been forgotten.

The layer stack

A standard glass-backsheet crystalline silicon module, from the sun-facing side inward, consists of: front glass, front encapsulant, interconnected solar cells, rear encapsulant, backsheet (or rear glass in glass-glass designs), aluminium frame, and a junction box with bypass diodes on the rear. Each layer is discussed below.

Front glass

Almost universally low-iron, tempered soda-lime glass, 2.0-3.2 mm thick, with an anti-reflective (AR) coating in most modern products. Iron content is minimised because iron oxide absorbs light in the near-infrared and gives glass a green tint, directly reducing transmittance. Tempering (thermal toughening) gives the mechanical strength needed to meet the 5,400 Pa (and increasingly 5,400-7,000 Pa for snow/wind-rated) load requirements in IEC 61215 without adding thickness. Textured glass surfaces reduce specular reflection and improve light trapping at the cost of slightly higher soiling retention in low-rainfall regions.

Encapsulant

The encapsulant bonds cells to glass and backsheet, provides electrical insulation, and excludes moisture and oxygen. Ethylene-vinyl acetate (EVA) remains the dominant material by volume, chosen for cost and process maturity. Its known weaknesses are acetic acid formation on hydrolysis (contributing to corrosion and delamination) and UV-driven yellowing that reduces transmittance over time. Polyolefin elastomer (POE) encapsulants have gained share, particularly in bifacial and glass-glass modules, because they have lower water vapour transmission rates and do not generate acetic acid, which matters for mitigating potential-induced degradation (see /blog/potential-induced-degradation-explained). POE costs more and can be marginally harder to process (lower tack, more sensitive lamination window).

Solar cells and interconnection

Cells are connected in series strings using copper ribbon (traditional busbar designs) or fine round wire (multi-wire/MBB designs) coated with a solder alloy, typically tin-lead-silver or lead-free alternatives where required by regulation. Cell-to-ribbon soldering is a common origin point for long-term reliability issues: thermal cycling (IEC 61215 TC200 test regime) stresses solder joints, and poor solder bonds develop resistive heating and eventually open circuits, visible as hot spots under thermal imaging.

Backsheet

In standard (non-glass-glass) modules, the backsheet is a multi-layer polymer sheet, commonly a fluoropolymer/polyester/fluoropolymer or polyester/polyester construction, providing electrical insulation, moisture barrier function, and UV/weather resistance from the rear. Backsheet material selection has been a significant source of industry-wide field failures: certain polyamide-based and some PET-based backsheets from the 2010-2016 period exhibited cracking and chalking under UV and thermal stress, leading to insulation resistance failures and, in some documented fleet cases, safety recalls. Glass-glass (dual-glass) modules avoid the backsheet entirely, trading its failure modes for higher weight and different mechanical mounting requirements.

Frame

Anodised aluminium frames provide mechanical rigidity, a grounding point, and a standard mounting interface. Frame corrosion is rare in properly anodised product but has been observed in coastal/high-salinity environments with inadequate coating thickness or damaged edges. Frameless (glass-glass, clamped) modules eliminate this failure mode and the associated potential-induced degradation current paths through frame grounding, at the cost of needing edge-clamping-compatible mounting hardware.

Junction box and bypass diodes

The junction box houses the string interconnections and bypass diodes, typically one diode per 18-24 cell substring. Bypass diodes route current around a shaded or failed substring, preventing localised hot-spot heating from a reverse-biased shaded cell. Diode failure (short or open) is a recognised field issue, often from thermal stress if the diode is undersized relative to fault current duration, or from poor thermal contact with the junction box heat sink. A shorted diode reduces module output for that substring's illuminated condition; a failed-open diode removes shading protection.

Bill of materials: indicative composition

For a standard 72-cell, 2.0 m2, glass-backsheet module (approximate, varies by manufacturer):

These proportions shift with polysilicon prices and aluminium prices; cell cost share has fluctuated considerably as upstream commodity prices moved through 2021-2023.

Worked example: estimating module weight and load

A 2.0 m x 1.0 m glass-backsheet module: 2.5 mm front glass (density ~2500 kg/m3) gives a glass mass of 2.0 x 1.0 x 0.0025 x 2500 = 12.5 kg. Adding an aluminium frame (~2.5 kg), encapsulant, cells, and backsheet (~2.0 kg combined), a typical total module mass comes to roughly 12.5 + 2.5 + 2.0 + 3.0 (cells/interconnect/junction box) = 20 kg, consistent with commercial datasheets that list 21-23 kg for this format. For a rooftop array of 20 such modules, the static dead load to check against structural capacity is 20 x 22 kg x 9.81 m/s2 = 4,316 N, before adding snow or wind load factors - a calculation that should always be checked with /calculators/system-sizing inputs and a structural engineer's sign-off, not assumed.

Failure modes by layer

• Glass: micro-cracking from impact or handling, reducing mechanical strength and creating moisture ingress paths.
• Encapsulant: yellowing (transmittance loss), delamination (bubbles, loss of adhesion), acetic acid corrosion of cell metallisation.
• Cells/interconnect: solder joint fatigue from thermal cycling, cell cracking from mechanical/thermal stress, snail trails (a visual, usually benign, discoloration linked to microcracks).
• Backsheet: cracking, chalking, delamination, loss of dielectric strength leading to insulation failure.
• Frame: corrosion in aggressive environments, sealant failure at frame-glass interface allowing moisture ingress.
• Junction box/diodes: diode failure (short/open), connector overheating from poor crimp quality, box detachment from adhesive failure.

Common mistakes

• Selecting modules on price per Wp without checking backsheet material history and bill-of-materials transparency.
• Assuming glass-glass modules are always superior; they are heavier and require compatible mounting hardware.
• Ignoring bypass diode configuration when designing strings with partial shading exposure.
• Treating snail trails as a defect requiring replacement without checking whether power output is actually affected.
• Overlooking structural load calculations when switching from a lighter to a heavier module format mid-project.

Frequently asked questions

Are glass-glass modules more reliable than glass-backsheet modules?

They eliminate backsheet-specific failure modes and generally show better resistance to potential-induced degradation, but they are heavier and more expensive. Reliability depends on the full material stack, not the glass configuration alone.

Why do some modules use POE instead of EVA encapsulant?

POE has lower water vapour permeability and does not produce acetic acid on degradation, which reduces corrosion risk and PID susceptibility. It costs more and is more common in bifacial and glass-glass products where the benefit is proportionally larger.

What causes yellowing in older modules?

UV exposure and thermal stress degrade EVA encapsulant chemically over years, producing chromophores that absorb visible light and reduce transmittance to the cells, slightly lowering output. It is primarily a cosmetic and minor performance issue rather than a safety one.

How many bypass diodes does a typical module have?

Most 60- to 72-cell modules use three bypass diodes, each protecting a substring of 20-24 cells. Half-cut cell designs often use six diodes across effectively doubled parallel substrings.

Can a cracked backsheet be repaired?

Minor surface cracking can sometimes be sealed as a temporary measure, but backsheet cracking that compromises insulation resistance is a safety issue and generally warrants module replacement under warranty rather than field repair.

Standards and references

• IEC 61215: Terrestrial photovoltaic (PV) modules - Design qualification and type approval.
• IEC 61730: Photovoltaic module safety qualification.
• IEC 60904 series: Photovoltaic device measurement standards.
• NREL, PV Reliability and materials degradation research programme publications.
• Fraunhofer ISE, "Photovoltaics Report" and module reliability studies.
• IEA PVPS Task 13, "Review of Failures of Photovoltaic Modules".

Related reading: /blog/solar-panel-efficiency-explained, /blog/potential-induced-degradation-explained, /blog/anti-reflective-coatings-and-module-glass, /glossary.