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Abstract:The recent growing diffusion of dispersed generation in low voltage (LV) distribution networks is entailing new rules to make local generators participate in network stability. Consequently, national and international grid codes, which define the connection rules for stability and safety of electrical power systems, have been updated requiring distributed generators and electrical storage systems to supply stabilizing contributions. In this scenario, specific attention to the uncontrolled islanding issue has to be addressed since currently required anti-islanding protection systems, based on relays locally measuring voltage and frequency, could no longer be suitable. In this paper, the effects on the interface protection performance of different LV generators' stabilizing functions are analysed. The study takes into account existing requirements, such as the generators' active power regulation (according to the measured frequency) and reactive power regulation (depending on the local measured voltage). In addition, the paper focuses on other stabilizing features under discussion, derived from the medium voltage (MV) distribution network grid codes or proposed in the literature, such as fast voltage support (FVS) and inertia emulation. Stabilizing functions have been reproduced in the DIgSILENT PowerFactory 2016 software environment, making use of its native programming language. Later, they are tested both alone and together, aiming to obtain a comprehensive analysis on their impact on the anti-islanding protection effectiveness. Through dynamic simulations in several network scenarios the paper demonstrates the detrimental impact that such stabilizing regulations may have on loss-of-main protection effectiveness, leading to an increased risk of unintentional islanding.

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In this paper a procedure that allows Distributed Generation plants (DGs) to be operated as a Virtual Power Plant (VPP), maintaining meanwhile the voltage profiles on Medium Voltage (MV) feeders within the permissible interval, is presented. To this aim a co-ordinated controller is proposed. It acts both on the On Line Tap Changer (OLTC) and on the reactive power production of specific plants so that voltage regulation is performed whatever the working condition (generation units disconnected or partially loaded or working at maximum power). In particular this controller can influence a VPP economic criteria dispatch by bounding, for example, the maximum active power generated by each unit in order to obtain the DG reactive generations required by the management of the distribution system. Thus, as a consequence some lower variable cost productions might have to limit their active outputs which represent a possible cost increase in VPP management. These automatic limitations, imposed by the controller, allow the Distribution System Operator (DSO) to control voltage on the whole distribution system and the DG plants to guarantee their connection to the network. Simulations on a realistic network case study are carried out to compare the VPP management impact on voltage profiles with a traditional voltage regulation (only OLTC action) and with a coordinated control system. Results demonstrate that the proposed procedure is able to preserve distribution network from dangerous under and over voltages with limited interferences with the VPP optimisation algorithm.

The Optimal Power Flow (OPF) model for low voltage active Distribution Networks (DNs), which are equipped with neutral conductors, requires an explicit representation of both phases and neutral conductors in its formulation to obtain complete information about the state variables related to these conductors. In this regard, a centralized OPF relaxation based on semi-definite programming is presented in this paper for neutral-equipped DNs hosting ZIP loads and neutral-ground impedance, and contain a significant level of unbalance. The major restriction in the development of an OPF model for these networks is the coupled power injection across the conductors which is successfully handled by deriving the explicit active and reactive power injections for each conductor through a network admittance matrixbased approach. The shortcomings of existing voltage magnitude-based technique for the modelling of ZIP loads are comprehensively reported and a novel complex voltage variable-based approach is proposed which successfully incorporates ZIP loads in the developed multi-phase OPF relaxation. For the handling of constant current load, a modelling approach based on the first-order-Taylor series is introduced as well. Furthermore, the impact of the application of Kron reduction approach on the global optimal solution of single-and multiple-point grounded DNs is discussed in detail. Three metrics, eigenvalue ratio, power mismatch and cumulative normalized constraint violation, are utilized to evaluate the exactness of proposed relaxation. Simulations, carried out on several medium and low voltage DNs, show that the proposed relaxation is numerically exact under several combinations of ZIP load parameters and a reasonable range of grounding impedance value for both time-varying and extreme system loading scenarios irrespective of the degree of unbalance in a network. INDEX TERMSActive distribution networks, optimal power flow, neutral conductor, semi-definite programming relaxation, ZIP loads. ACRONYM CCI Correction Currection Injection CNCV Cumulative Normalized Constraint Violation CT Computational Time DER Distributed Energy Resource DG Distributed Generator DN Distribution NetworkThe associate editor coordinating the review of this manuscript and approving it for publication was Ziang Zhang .

Abstract:The ever-growing penetration of local generation in distribution networks and the large diffusion of energy storage systems (ESSs) foreseen in the near future are bound to affect the effectiveness of interface protection systems (IPSs), with negative impact on the safety of medium voltage (MV) and low voltage (LV) systems. With the scope of preserving the main network stability, international and national grid connection codes have been updated recently. Consequently, distributed generators (DGs) and storage units are increasingly called to provide stabilizing functions according to local voltage and frequency. This can be achieved by suitably controlling the electronic power converters interfacing small-scale generators and storage units to the network. The paper focuses on the regulating functions required to storage units by grid codes currently in force in the European area. Indeed, even if such regulating actions would enable local units in participating to network stability under normal steady-state operating conditions, it is shown through dynamic simulations that they may increase the risk of unintentional islanding occurrence. This means that dangerous operating conditions may arise in LV networks in case dispersed generators and storage systems are present, even if all the end-users are compliant with currently applied connection standards.

Abstract:The ever-growing diffusion of renewables as electrical generation sources is forcing the electrical power system to face new and challenging regulation problems to preserve grid stability. Among these, the primary control reserve is reckoned to be one of the most important issues, since the introduction of generators based on renewable energies and interconnected through static converters, if relieved from the primary reserve contribution, reduces both the system inertia and the available power reserve in case of network events involving frequency perturbations. In this scenario, renewable plants such as hydroelectric run-of-river generators could be required to provide the primary control reserve ancillary service. In this paper, the integration between a multi-unit run-of-river power plant and a lithium-ion based battery storage system is investigated, suitably accounting for the ancillary service characteristics as required by present grid codes. The storage system is studied in terms of maximum economic profitability, taking into account its operating constraints. Dynamic simulations are carried out within the DIgSILENT PowerFactory 2016 software environment in order to analyse the plant response in case of network frequency contingencies, comparing the pure hydroelectric plant with the hybrid one, in which the primary reserve is partially or completely supplied by the storage system. Results confirm that the battery storage system response to frequency perturbations is clearly faster and more accurate during the transient phase compared to a traditional plant, since time delays due to hydraulic and mechanical regulations are overpassed. A case study, based on data from an existing hydropower plant and referring to the Italian context in terms of operational constraints and ancillary service remuneration, is presented.