Globally, large-scale photovoltaic (PV) systems are being installed to achieve maximum power generation efficiency. However, this often results in severe power fluctuations, impacting the stability of the power system. To enhance the power system stability, it is crucial to effectively distribute the times of maximum power output. This can be achieved by making changes to the inclination angle and azimuth of PV modules at power plants. The modeling results indicate a prediction error of 3.65% relative to the actual measurements. To assess system stability based on each installation method, new concepts called demand gradient (DG) and demand gradient average (DGA) were introduced and analyzed using the load pattern in Metropolitan Seoul. The electricity usage was categorized into four divisions: residential (dwelling), public, service, and manufacturing. The analysis revealed that optimal inclination angles for the dwelling, public, service, and manufacturing sectors were 60°, 30°, 30°, and 15°, respectively. As for installation azimuths, the optimal values were 0°, 80°, 160°, and 230°, respectively. When both the inclination angle and azimuth were varied simultaneously, their optimal installation methods included inclination angles of 60°, 60°, 35°, and 50°, and azimuths of 330°, 210°, 230°, and 190° for the dwelling, public, service, and manufacturing sectors, respectively. Among the various scenarios, the most significant improvement in grid stability was observed in the existing south-facing installation of DGA in the dwelling sector, demonstrating a remarkable 77% reduction from 0.1 to 0.057.

In this study, long-term reliability tests for high-power-density photovoltaic (PV) modules were introduced and analyzed in accordance with IEC 61215 and light-combined damp heat cycles, such as DIN 75220. The results indicated that post light soaking procedure, light-combined damp heat cycles caused a 3.51% power drop, while IEC standard tests (DH1000 and TC200) caused only 0.87% and 1.32% power drops, respectively. IEC 61215 failed to assess the long-term reliability of the high-power-density PV module, such as the passivated emitter rear cell. Additionally, based on the combined test, the latent heat ($Q_{mod}$) of the module was introduced to predict its degradation rate and to fit the prediction curve of the product guaranteed by the PV module manufacturers. $Q_{mod}$ facilitates in predicting a PV module’s lifespan according to the environmental factors of the actual installation area. The $Q_{mod}$ values of the PV stations in water environments, such as floating and/or marine PVs, indicated that they would last 7.2 years more than those on a rooftop, assuming that latent heat is the only cause of deterioration. Therefore, extending module life and improving power generation efficiency by determining installation sites to minimize latent heat would be advantageous.

In Floating PV (Photovoltaic) systems, PV modules are installed on water by utilizing the surface of idle water such as a reservoir and multipurpose dam. A floating PV system, therefore, has the advantage of efficiency in national land use and improved energy yield owing to cooling effect compared to on-land PV systems. Owing to the limitation of installation environment for a floating PV system, the system, however, has the disadvantage of an increase in transmission distance of DC (Direct current) cables. A longer transmission distance of a DC cable results in greater power loss due to a voltage drop. This leads to a decline in economic feasibility for the floating PV system. In this paper, the economic analysis for 10 floating PV systems installed in a reservoir has been conducted in terms of a change in annual power sales according to the variation of transmission losses depending on the factors affecting the voltage drop, such as transmission distance, cross-section area of underwater cable, the presence of joint box, and PV capacity.