Dumitru Toader

This paper presents a global solar irradiance measurement system developed at Politehnica University Timisoara (UPT), comprising a Kipp & Zonen CMP11 thermopile pyranometer (Kipp & Zonen, OTT HydroMet B.V., Delft, The Netherlands), a National Instruments myDAQ board (National Instruments Corporation, Austin, TX, USA), and a LabVIEW 2018 interface (National Instruments Corporation, Austin, TX, USA). The platform provides configurable acquisition, voltage-to-irradiance conversion, temporal averaging, data storage, and MATLAB R2024b-based analysis (The MathWorks, Inc., Natick, MA, USA). A preliminary operational validation was performed against ten-minute global-irradiance data supplied by the National Meteorological Administration of Romania (ANM) at the same site. The dataset comprised five non-consecutive days between December 2025 and May 2026, with 215 paired values. The global metrics were MBE = −0.33 W/m², MAE = 4.55 W/m², RMSE = 6.05 W/m², nRMSE = 1.29%, and MARE = 0.96%. Incident solar energy was 60.357 MJ/m² for UPT and 60.399 MJ/m² for ANM, a relative difference of −0.07%. Day-specific Bland–Altman analyses showed 0.00–4.65% of differences outside the corresponding limits of agreement. Regression of the differences against the pairwise mean irradiance identified an irradiance-dependent bias component in the combined dataset. The results demonstrate promising operational agreement under the tested conditions. Longer campaigns and traceable low-level characterization of the acquisition chain remain necessary for extended metrological assessment.

Photovoltaic (PV) module manufacturers typically provide electrical parameters at Standard Test Conditions (STCs), while real operation is strongly influenced by irradiance and module temperature. This paper presents a MATLAB-based numerical model that simulates the operation of a real PV string composed of 19 series-connected modules (8.645 kWp). Each module has 72 PV cells arranged as two parallel cell groups, each group consisting of 36 cells connected in series, and a rated maximum power of 455 Wp. The validated string belongs to a PV site comprising 140 modules (63.7 kWp); however, the experimental verification is intentionally performed at the string level to avoid aggregation effects. The model implements the single-diode equivalent circuit and computes the I–V and P–V characteristics at any time step, using 500 points for curve plotting. Measured irradiance and module temperature are used as inputs, while DC voltage, current, and power recorded at the inverter MPPT are used as reference quantities. Model performance is evaluated over two representative operating days, and the verification includes point-by-point comparisons between measured and simulated electrical quantities at 25 operating points, with accuracy quantified through MAE, RMSE, and MRE. The obtained errors are: MAE—power 92.94 W (1.08% of maximum power), voltage 8.33 V (1.07% of maximum voltage), current 0.12 A (1.17% of maximum current); RMSE—power 111.78 W (1.29%), voltage 10.15 V (1.30%), current 0.15 A (1.46%); and MRE—power 2.6%, voltage 1.18%, current 2.57%. These results indicate close agreement between simulated and measured string behavior under the tested conditions, supporting the use of the proposed approach for string-level performance analysis and diagnostic assessment when irradiance and temperature are available from measurements or scenario inputs, without extending conclusions to plant-level generalization beyond the validated subsystem. Photovoltaic panel manufacturers usually provide electrical parameters in a single operating condition, but in reality, PV cells operate under very diverse weather conditions. For this reason, the manufacturer’s information is not sufficient to determine the performance of PV plants.

The increasing complexity of electrical power installations requires more and more sophisticated mathematical models for the analysis of their operating regimes in relation to transient regimes. This requirement can be solved by using numerical mathematical models implemented in professional programming environments. MATLAB/Simulink is such a programming environment that allows for the analysis of transient regimes caused by faults occurring in electrical power installations. In this paper, the transient regime caused by the phase-to-ground fault is analyzed using a numerical model of a 20 kV nominal voltage power network, implemented in the MATLAB/Simulink programming environment. The numerical model was validated by comparing the obtained results with those experimentally determined in a real 20 kV network. Using the numerical model, we can analyze how the zero-sequence voltage of the 20 kV bus bars and the fault current in the 20 kV network, which are neutrally treated with a Petersen coil, are influenced by the following parameters: the initial phase of the voltage at the fault location; the regime in which the medium voltage network operates (resonance, under-compensated, or over-compensated); the insulation state (value of the electrical resistance of the insulation); and the value of the resistance at the fault location. The differences between the experimentally obtained results and those obtained using the numerical model are as follows: for the fault current, 6.67% if R_t = 8 Ω and 4.94% if R_t = 268 Ω; for the zero-sequence voltage, 3.21% if R_t = 8 Ω and 6.19% if R_t = 268 Ω.

The electrical energy supply of industrial equipment is provided by electrical power stations with high- (HT), medium- (MV) and low-voltage (LV) busbars. Consumers are connected to either MV or LV busbars. In this paper, a real power station was considered, through which the gasoline extraction from the well gas installation is powered. Electric consumers (electric motors) supplied by a MV busbar have active power of 13.54 MW, and those fed by a LV busbar have active power of 6.4 MW. Since electrical consumers operate in explosive environments, the design and operating conditions are more severe than in the case of electrical installations operating in non-explosive environments. The case of a single phase-to-ground fault occurring on the HV transmission lines feeding the power station has been analysed. First, the mathematical models for the calculation of the phase voltages, the dissymmetry and asymmetry coefficients, the reduction coefficient of the plus sequence component, and the effective values of the phase voltages were established. The influence of the source impedance (the equivalent impedance of the HV transmission lines) and of the neutral point configuration of the HV/MV medium-voltage transformer on the calculated quantities was analysed. Then, the results obtained using the established mathematical models were compared with those obtained experimentally by provoking a single-phase-to-ground fault near the HV busbars of the real power station. This study has shown that the de-symmetrisation of the phase voltages of the MV and LV busbars is lower when using the Y/Δ connection for the HV/MV transformer. As a result, it is recommended the Y/Δ connection be used for this transformer, instead of the Y₀/Δ connection.

The paper analyses how the characteristics of the medium-voltage network with insulated neutral and the conditions under which the single line-to-ground fault occurs (insulation condition and value of the fault resistance) influence the zero-sequence components of the voltage of the transformer station medium-voltage bus bar, the fault current, the currents of the faulted line and the currents of the other non-faulted power lines connected to the transformer station bus bars. Assuming the waveform of the medium voltage bus voltages in the transformer station is known, the influence of the fault resistance on the total distortion coefficient of the fault current is analysed. This establishes the conditions under which a single line-to-ground fault can be detected by controlling the total distortion coefficient of the fault current and the currents of the fault-free lines. It also examines the conditions under which a single line-to-ground fault can be selectively detected by checking the effective value and direction of flow of the zero-sequence currents of the medium-voltage lines during the fault. The results obtained by the calculation were verified experimentally in the medium voltage network considered in the study. The acceptable differences, considering the degree of accuracy with which the parameters of a medium voltage network are known, between the results obtained by calculation and those obtained experimentally show that the simplifying assumptions accepted for the mathematical models used in the calculation are correct.

One important problem in the operation of medium voltage networks is the detection of a single-line-to-ground fault in its incipient state, when the fault resistance values are very high. In a medium voltage (MV) distribution network with a neutral grounding resistor (NGR), one of the methods employed to discriminate a single line-to-ground fault is the use of an overcurrent relay with an operating characteristic adjusted according to the effective value of the current flowing through the limiting resistor. In case of a single line-to-ground fault with a high fault resistance value, the correct tripping settings of the protective relay require the precise computation of this current. In comparison to the assumptions made by the models from the literature—the three-phase voltage system of the medium voltage busbars is symmetrical and there are no active power losses in the network insulation—the model proposed in this paper considers the pre-fault zero-sequence voltage of the medium voltage busbars and the active power losses in the network insulation, which is necessary in certain fault conditions where the use of the former leads to unacceptable errors.

Settings of protection are essential to ensure the sensitivity and selectivity needed to detect defects. Making the correct settings requires the calculation of the fault currents with as little error as possible. Fault currents are influenced by the parameters of the electrical networks, including the state of the insulation and the Petersen coil, which changes during their operation electrical networks. This paper analyzes how the insulation parameters of medium voltage power lines, the parameters of the Petersen coil used to treat the neutral of the medium voltage electrical network and the value of the resistance at the fault location influence the fault current in the case of a single-phase fault. The large number of single-phase faults that occur in medium voltage electrical networks justifies this analysis. The symmetrical components method was used to calculate the fault current. The results obtained by calculation were verified experimentally by causing a single-phase-to-ground fault in a real medium voltage network. The paper presents the situations in which the analytical calculation of the single-phase-to-ground fault current can lead to inadmissibly large errors, even over 50%, but also the situations in which the errors fall below 3%.

The touch voltage and the step voltage in the case of a broken conductor from a medium voltage network is analyzed in this paper. The distribution of the electric field in the area of the broken and grounded conductor is studied using a FEM program.