Hotspots pose a significant long-term reliability challenge in photovoltaic (PV) modules that can have a detrimental impact on the efficiency, safety, and financial viability of a PV system. This paper aims to evaluate the endurance of hotspot stress in pristine and prestressed glass–glass (GG) modules. The accelerated prestressing was conducted for 600 thermal cycles (TC600) to represent decades of field exposure. GG modules are quickly becoming an alternative to the traditional glass–backsheet (GB) modules that have been the industry standard. Unlike other conventional studies that subject only pristine modules to hotspot stress, this paper evaluates the performance of an accelerated/simulated field-aged GG module (using TC600) and a pristine GG module. Pre- and post-characterizations were performed before and after each test to determine changes in electrical performance and observe any defects in GG modules. During the hotspot test, an approximately 200 °C maximum cell temperature was observed with a cell shading of 25% (the worst-case shading ratio). After the hotspot test, electroluminescence imaging indicated that most cells in the prestressed GG module exhibited severe damage whereas no significant defects were evident in the pristine GG module where the prestressed GG module degraded 8.2% and the pristine GG module degraded 1.5% in maximum power. These findings are critical for the industry, considering that GG bifacial modules will dominate the market.

This paper presents an extended, accelerated reliability evaluation of forty microinverters, module-level power electronic (MLPE) units for photovoltaic (PV) modules. The forty microinverters were stressed at two static temperatures (65 °C and 75 °C) with two input power profiles (fixed and cyclic power). These power profiles were employed to replicate field-use conditions closely. The accelerated testing was performed for an extended duration (over a period of 15,000 h) to determine the acceleration factor and estimate the service life of microinverters in field-use conditions. Electrical performance and thermal data were continuously monitored during the experiment for all the microinverters. The accelerated stress testing had no failures even after 15,000 h of operation. Using the Arrhenius life-stress model along with average field-measured temperature and military handbook-based analysis, it was estimated that the microinverters should be able to survive for 24–48 years during their service life in field conditions, with a reliability of 74%, having a lower one-sided confidence bound of 95%, obtained using the classical success run approach. Moreover, the lifetime of microinverters was statistically analyzed using a Weibull distribution model. Weibull slope factors were used to estimate a range of characteristic lifetime periods and the reliability of the microinverters with a 95% lower one-sided confidence limit, demonstrating a similar or even exceeding the lifetime of the associated PV modules of 25 years.

Hotspots can be a detrimental reliability issue that can adversely affect the long-term performance of (PV) modules in the field. The endurance of hotspot stress is usually evaluated on pristine modules, which do not represent the hotspot issues related to long-term field-aged modules. PV modules can become vulnerable to hotspots when exposed to long-term field operating conditions. Hence, in this study, we evaluated the endurance of hotspot stress of a fresh half-cell glass-backsheet (GB) module along with a prestressed half-cell GB module that was subjected to 600 accelerated thermal cycling stress. The maximum power (Pmax) of both GB modules (fresh and prestressed) experienced a negligible decrease of approximately 1% after the sequential thermal cycling followed by the hotspot stress test. This indicates that GB modules having half-cell GB configuration can potentially endure the hotspot stress even after being exposed to the field for over 30 years. However, these findings were derived from a sample size lacking statistical significance and, therefore, should not be generalized to encompass all half-cell GB modules.

Potential induced degradation (PID) mode is one of the most critical degradation modes in the photovoltaic (PV) modules. The PID issue is highly dependent on the conductivity of the materials (especially encapsulant and glass surface) and the adhesion strengths of interfaces (glass/encapsulant, encapsulant/cell and encapsulant/backsheet). In the field-aged modules, the material conductivity typically increases due to aging of materials, weakened interface and cemented soiling of glass surface. Currently, the PID tests are performed on the fresh modules as per IEC standards' requirements. In the fresh modules, the encapsulant conductivity is very low (compared to the field-aged modules) and the adhesion strengths of interfaces are high. Therefore, the PID loss in the current tests represent only the loss which would happen in the fresh modules and young modules, not in the long-term field-aged modules. In the current work, we have used two pre-stressed modules to represent the long-term field-aged PV modules. The pre-stressing was done on two glass/polymer modules for 2000 hours at 85°C/85%RH according to IEC 61215 standard. After the damp-heat prestressing, these two modules were subjected to PID (+ve PID on one module; -ve PID on the other module) in an environmental chamber at 1000 V, 60°C, and 85% RH, according to IEC 62804-1. These modules experienced 6.3-7.5% power degradation which is beyond the allowed limit of 5% by the standard. Based on these results, we believe that the PID tests may need to be performed on the unstressed/fresh and pre-stressed modules to appropriately represent the PID issue corresponding to the short-term and long-term field-aged modules, respectively.