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The continuous increase of Renewable Energy Sources (RESs) connected to distribution networks requires a careful review of the current regulatory framework to enable the provision of Ancillary Services (ASs) by these small-scale units. One of the envisaged options for coordinating Transmission System Operators (TSOs) and Distribution System Operators (DSOs) is the agreement and regulation of a scheduled power profile at the Primary Substation (PS). This means assigning the balancing responsibility to DSOs and, consequently, reducing the unpredictability of the power exchanges with the upstream transmission grid. The paper proposes a novel procedure for the management of Distributed Energy Storages (DESs) in order to provide ASs to both the DSO (local regulation of distribution network and congestion management) and the TSO (control of the power profile at the PS). The methodology, based on a sliding time window approach, evaluates the actual availability of each storage unit in providing ASs, assigns a scheduled profile and corrects it during the real-time operation. In addition, for each DES, the scheduled State of Charge (SoC) is restored in accordance with network constraints. Simulations on a realistic case study network are carried out considering randomly perturbed power profiles for both loads and generators. Benefits associated with storage coordination (power exchange management at the PS and support to DSO in voltage regulation and congestion resolution) are evaluated and discussed.

A novel Optimal Power Flow (OPF) model, based on Semi-Definite Programming approach, for multi-phase active Distribution Networks (DNs) equipped with neutral conductor(s) and both wye- and delta-connected loads/Distributed Generators (DGs) is proposed in this paper. The coupled power injection across phase-neutral and phase-phase conductors is decoupled by modelling of a shunt load/DG through a correction current injection approach and, consequently, explicit power injections are obtained for each conductor of a node. Furthermore, the complete ZIP load representation is considered in the OPF model and two approximations, based on the first-order Taylor series and approximation of the first-order Taylor series, are introduced for the modelling of constant current component of a ZIP load in terms of an optimization variable. Simulations are carried out on several medium and low voltage active DNs under various parameters of the ZIP models for the minimization of either slack-bus power or network losses objective functions. It is successfully demonstrated that the proposed relaxation recovers the global optimal solution of the original OPF problem for both load types (wye and delta) under various combinations of ZIP parameters in the case of lightly or moderately unbalanced DNs, whereas in the case of highly unbalanced DNs, a rank-2 solution is obtained when constant current component dominates the other load components. Furthermore, the impact of unrealistic assumption of Kron reduction approach on the quality of the proposed relaxation for a single or multiple point grounded DNs is also discussed. From a computational point of view, the proposed methodology can be realized on a real-time basis for small DNs. However, for medium and large DNs, the incorporation of additional sparsity exploitation or distributed algorithm techniques are required for its real-time implementation.

Ground Potential Rise (GPR) evaluation under fault conditions is important for the evaluation of electrical safety risk to human beings who are present in and around electric installations. Current national and international standards recommend such evaluation is based on a set of ‘worst-case’ conditions that include a simplified fault current calculation procedure based on assuming a maximum value. Accordingly, this approach may lead to over-design of grounding systems in certain cases by overestimating individual risk. To address this and move towards a comprehensive probabilistic assessment of risk, a more detailed model of the electric network is required for fault current magnitude evaluation. This paper describes the application of the multi-conductor method to determine fault current distribution on transmission networks. First, a model of a portion of the UK transmission network is built and the fault current and its distribution among the phases, ground wire and ground is evaluated for three example fault positions. It is found that the position of the fault along the line, substation bus section status and proximity to generation affect greatly the current distribution. Then, a transmission model based on the national network is built, and the effects of system loading and generation on fault current magnitude were also considered. A complete frequency distribution of fault current magnitude is obtained and the results demonstrate the value of such description for the probabilistic assessment of human safety in grounding system design.