Toxta vs Botox | 5 Key Differences You Need to Know

The main differences between Toxta and Botox: 1. Brand origin (Toxta is from South Korea, Botox is from the United States); 2. Purity difference (Botox is 90%, Toxta is 85%); 3. Difference in diffusion (Toxta has a smaller diffusion range); 4. Price difference (Toxta is about 300/bottle, Botox is about 300/bottle, Botox is about 450); 5. Applicable population (Toxta is suitable for people with sensitive skin).

Sharp Decline in Power Generation

Last week, a bizarre incident occurred: the monitoring screen of a power station in Hebei suddenly turned red, with daily power generation plummeting from 38,000 kWh to 21,000 kWh. The O&M team rushed to the site with EL testers, only to discover entire rows of modules covered in dark spots resembling smartphone screen dead pixels. This wasn’t a simple screen replacement issue—every 1% increase in dark spot area on EL imaging correlates to 3.5% actual power loss (verified by SEMI PV22-028 data).

Veterans in PV know that sudden power generation drops typically stem from three culprits:

• Hot spot effect: When local cell temperatures exceed 85°C (common under shade or bird droppings), each 10°C increase causes 0.5% power loss
• Boron-oxygen complex defects: In P-type silicon cells, boron-oxygen pairing can slash minority carrier lifetime from 2.5μs to below 1μs
• Temperature coefficient backlash: With ambient at 38°C, module temperatures can hit 58°C, causing power degradation exceeding the nominal -0.35%/°C

A 2022 Jiangsu case exemplifies this: An N-type wafer manufacturer reduced argon flow in crystal growth furnaces from 120L/min to 90L/min. Oxygen content surged to 18ppma—2ppma above safety thresholds. Three months after installation, CTM losses (cell-to-module) jumped from 3% to 9.7%, extending ROI period by 6 years.

Modern O&M teams now carry dual detectors: IV curve testers for fill factor analysis and thermal cameras for temperature mapping. A recent Shandong project exposed modules labeled as 430W (72-cell) actually delivering median 398W output. Disassembly revealed yellowed EVA encapsulant with snail trails spreading along busbars.

Microcracks pose invisible threats. A Ningxia project passed visual inspection but showed 18% lower first-year generation than feasibility reports. Drone EL inspection later revealed 6.7% cell failures from transportation-induced microcracks, prompting new industry rules: 50MW+ projects now require 10% sampling (up from 5%) with dynamic mechanical load testing.

If your plant’s generation curve resembles bungee jumping, check these immediately: inverter input voltage below startup threshold, string current deviation >5%, or >8°C temperature difference within same mounting structure. Remember: PV modules have expiration dates too.

Module Yellowing

Last month in Zhejiang, O&M technician Zhang spotted tea-stain-like yellow edges on N-type TOPCon modules—only 8 months into their supposed 30-year linear warranty per SEMI PV22-019.

EL testing revealed yellowed areas operating 17-23°C hotter than normal. EVA encapsulant samples showed accelerated oxidation, degrading 40% faster than CPIA-2023 industry averages.

• A 182mm bifacial module manufacturer faced 37% yellowing within 14 months due to 72% EVA crosslinking (vs 78% safety threshold)
• Boron-oxygen complexes caused G12 wafer lines with quartz crucible oxygen exceeding the standard to yellow 4× faster

Thermal imaging recorded 89.7°C hotspots—31°C above adjacent areas. Per IEC 61215, every 10°C increase doubles power degradation rates.

A Jiangsu rooftop PERC system ignored palm-sized yellow spots, resulting in fill factor crash from 78.2% to 61.5%. EL inspection revealed snowflake-like microcracks in yellowed cells.

Current solutions: quarterly drone EL inspections and POE encapsulant replacement. A Shandong agrivoltaic project reduced yellowing from 17.3% to 2.1% after material upgrade.

Warning: Never pressure-wash yellowed modules—a northern plant caused 83% power loss by cracking cells. Proper protocol: infrared scanning first, then soft-brush cleaning with specialized solutions.

New research shows bifacial glass-glass modules yellow 40% slower than glass-backsheet due to dual UV protection. However, ensure aluminum frame sealant quality—one manufacturer faced 3cm edge yellowing from subpar weather-resistant adhesives.

Abnormal Heating

During a rooftop inspection, module backsheet thermometers showed 85°C hotspots—30°C above ambient, far exceeding SEMI PV22-076’s 15°C ΔT limit. Thermal imaging revealed egg-sized overheated zones—classic hot spot symptoms from cell defects.

Microcracks or poor busbar connections create current bottlenecks, similar to idling engines in traffic. A Zhejiang 5MW agrivoltaic project ignored this, resulting in 23% cells developing black cores and CTM losses surging from 1.8% to 7.3%.

A Shandong case saw 9% generation gap between inverters. EL imaging revealed burnt-leaf-patterned cells with radial cracks—30% power degradation requiring full module replacement.

Bifacial modules present new challenges: A Ningxia 200MW plant found rear-side heat accumulation raised temperatures 8-12°C above monofacial modules. Drone thermal imaging showed rack-bottom modules “steaming like baked sweet potatoes,” with EVA delamination. Lesson: Ensure adequate ventilation spacing for bifacial installations.

Key data point: 0.5% power loss per 10°C temperature rise. Combined with hot spots, this can slash 5%+ energy yield—similar to smartphones draining battery when overheated.