Vertical Bifacial Photovoltaic System Model Validation: Study With Field Data, Various Orientations, and Latitudes

Abstract

Accurate modeling of photovoltaic (PV) systems is critical for the design, financial analysis, and monitoring of solar PV plants. For bifacial PV applications, models must additionally offer robust rear-side irradiance algorithms. However, bifacial PV irradiance models have yet to be sufficiently validated for east–west vertically oriented systems, where direct beam solar irradiation swaps at solar noon. Here, we validate five bifacial irradiance models with field data collected in Golden, CO, USA (40°N) and Fairbanks, AK, USA (65°N) for east–west vertical, north–south vertical, and south-tilted arrays. There is no clear best performer among subhourly models; Bifacial_radiance, bifacialVF, the System Advisor Model, and dual-sided energy tracer (DUET) comparably predict seasonal and daily changes in PV production, with root-mean-squared error (RMSE) falling in the range of 11–28% depending on the location and system orientation. PVSyst (v7.4.8), limited by hourly resolution, demonstrates RMSE in the range of 33–45%. The primary causes of high RMSE are similar for all models; using an irradiance cutoff of >100 W/m2, using clear-sky filtering, and removing time stamps with snow, lowers model RMSE to 4–13% for subhourly models and 12–25% for PVSyst. Regular meteorological station servicing is found to further decrease model RMSE by up to 3% abs. in Alaska. Finally, we model bifacial PV systems in over 250 locations between 15 and 85°N, finding that deviations between model-predicted annual insolation tend to be 2–3× higher for vertical PV systems than south-facing fixed-tilt systems. We discuss potential methods for improving vertical PV modeling and provide recommendations for high-quality field data collection in northern environments.