Browsing by Author "Chudinzow, Dimitrij"

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Modelling the energy yield of bifacial photovoltaic plants and their integration into European power supply systems
(Stuttgart : Universität Stuttgart, Institut für Energiewirtschaft und Rationelle Energieanwendung, 2022) Chudinzow, Dimitrij; Hufendiek, Kai (Prof. Dr.-Ing.)
Bifacial photovoltaic systems (B-PV) offer the advantage over conventional, monofacial photovoltaic systems (C-PV) that the irradiation hitting the back can also be converted into electricity. Thanks to this property, B-PV offer the possibility of significantly increasing the energy yield and reducing the cost of electricity. Furthermore, vertically installed bifacial PV systems (VBPV) facing east and west can achieve a generation profile complementary to C-PV, which can help to increase the economic efficiency of market-oriented PV systems and reduce integration costs in national power supply systems. Despite these promising features, B-PV has long played a minor role in research, development and application, leaving knowledge gaps in the areas of “energy yield simulation”, “field design” and “integration into power supply systems”. The present thesis contributes to closing these knowledge gaps. In the first step, the state of the art in energy yield modelling of B-PV as of 2016 was analysed. It was found that the adequate modelling of cast ground shadows, the irradiation absorbed from the front and the back, as well as the yield-reducing effects of the module rows on each other, represents a knowledge gap. Using a newly developed energy yield model, methods were developed to address this knowledge gap. This was essentially achieved by combining three-dimensional modelling of the PV system and methods from the field of irradiation exchange. This approach made it possible to quantify and classify the influence of important irradiation and installation parameters on the energy yield. In addition, a breakdown of the total absorbed irradiation into eight components became possible, which allows a site-dependent identification of the most important irradiation contributions. As a result, it was shown, among other things, that the presence of ground shadows can reduce the backside contribution to electricity generation by almost 30 % and the total annual electricity generation by up to 4 %. This illustrates the importance of thorough modelling of ground-reflected irradiance for a sound energy yield prediction. While decades of experience in field design of C-PV have led to reliable design guidelines on how to achieve minimum cost of electricity, this level of knowledge is not yet available to the same extent for B-PV. To contribute closing this knowledge gap, the second step was to use the newly developed model to investigate for eight European sites how different installation parameters affect the energy yield and cost of electricity of non-tracking and single-axis tracking B-PV. From this, general recommendations for the field design were derived, depending on latitude and irradiation conditions. The results showed, among other things, that with increasing latitude of the investigated site, an increase in the row spacing leads to an ever higher energy yield gain. If the energy yield is to be achieved by brightening the soil (e.g. with bright gravel), which is associated with additional costs, a reduction in the electricity generation costs is possible with a suitable overall configuration of the PV field. This illustrates that the complex interactions of radiation absorption must always be investigated holistically in order to find the cost optimum. A validation of the simulation model showed that the angle-dependent absorption of irradiation on the front side is well represented by the simulation model. Only at a tilt angle of 90° do larger deviations occur. The angle-dependent electricity generation (front + rear side) is also well captured by the model, with larger deviations occurring at a tilt angle of 0° (module is parallel to the ground). At cloudy weather, the model tends to overestimate the electricity generation by approx. 5 %, at sunnier weather the electricity generation is underpredicted by 10 %-15 %. The highest underprediction of generated electricity was observed at a tilt angle of 0° with a 20 % deviation. National power supply systems with high shares of installed C-PV capacity face the challenge of nearly simultaneous power generation from these systems because they are generally oriented towards the equator. This results in a generation peak at midday, while in the mornings and afternoons electricity generation is usually significantly lower. On the one hand, this simultaneity leads to decreasing electricity prices on the stock exchange, which endangers the profitability of PV systems. On the other hand, the total costs of power supply systems increase due to the need to maintain power plant reserves and electricity storage. VBPV enables feed-in profiles that have a peak in the morning and a peak in the afternoon. Consequently, in the third step, it was investigated which energetic and economic advantages could result from the use of VBPV compared to C-PV. The economic analyses from a business perspective were carried out for twelve locations in four European countries, while the cost-reducing effects in a power supply system were investigated with the help of a cost-minimising electricity market model using Germany as an example. It could be shown that above a latitude of 50°, VBPV always has a higher annual electricity generation than C-PV. An analysis of historical electricity prices in Germany showed that although C-PV always had a higher net present value, the difference to VBPV constantly decreased with decreasing electricity prices, which indicates an increasing competitiveness of VBPV. At the system level, VBPV was found to play an essential role in a cost-minimal electricity system with a high share of renewables and a high CO2-reduction. In the most ambitious of the climate scenarios investigated, VBPV would account for about 70 % of the total installed PV capacity and enable an annual system cost reduction of about 0.6 %.