Energy storage systems and distribution grids: A real case study in Italy

A notable spread of Dispersed Generation (DG) power plants, connected at Medium Voltage (MV) distribution grids, takes place in the Italian power system, with a big impact on the operation, both in normal and in emergency conditions, especially during transients determining frequency variations. Enel Distribuzione, the biggest Distribution System Operator (DSO) in Italy, proposed to install some special devices, on its distribution grid, to improve the effectiveness of management of DG and loads, during frequency transients in automatic way. The paper describes the solution proposed by Enel Distribuzione, that gives the possibility to better manage the DG and loads connected in MV in favor of the whole power system in presence of frequency transients, as the Italian Transmission System Operator (TSO) with its Defense Plan (DP) requires. Some numerical results for demonstrating the need and effectiveness of the application of the proposed solution in the real operation of the system are reported.

Peer-to-peer (P2P) energy trading has emerged as a novel approach to enhancing the coordination and utilization of distributed energy resources (DERs) within modern power distribution networks. This study presents a techno-economic analysis of different DER characteristics, focusing on the integration of photovoltaic (PV) systems and energy storage systems (ESS) within a community-based P2P energy trading framework in Aswan, Egypt, under a time-of-use (ToU) electricity tariff. Eight distinct cases are evaluated to assess the impact of different DER characteristics on P2P energy trading performance and an unbalanced low-voltage (LV) distribution network by varying the PV capacity, ESS capacity, and ESS charging power. To the best of the authors’ knowledge, this is the first study to comprehensively examine the effects of different DER characteristics on P2P energy trading and the associated impacts on an unbalanced distribution network. The findings demonstrate that integrating PV and ESS can substantially reduce operational costs—by 37.19% to 68.22% across the analyzed cases—while enabling more effective energy exchanges among peers and with the distribution system operator (DSO). Moreover, DER integration reduced grid energy imports by 30.09% to 63.21% and improved self-sufficiency, with 30.10% to 63.21% of energy demand covered by community DERs. However, the analysis also reveals that specific DER characteristics—particularly those with low PV capacity (1.5 kWp) and high ESS charging rates (e.g., ESS 13.5 kWh with 2.5 kW inverter)—can significantly increase transformer and line loading, reaching up to 19.90% and 58.91%, respectively, in Case 2. These setups also lead to voltage quality issues, such as increased voltage unbalance factors (VUFs), peaking at 1.261%, and notable phase voltage deviations, with the minimum Vb dropping to 0.972 pu and maximum Vb reaching 1.083 pu. These findings highlight the importance of optimal DER sizing and characteristics to balance economic benefits with technical constraints in P2P energy trading frameworks.

Ancillary services e.g., voltage control, congestion management and frequency control, require to be compensated increasingly from the Distributed Energy Resources (DERs). DERs are predominantly wind and photo-voltaic power plants, the major share of which are installed at the distribution grid level. Therefore, the previously passive distribution grids require transformation towards a more active role. Provision of ancillary services from the distribution grid level, requires assessment of active and reactive power flexibility (PQ-flexibility) potentials. Furthermore, increased renewable penetration correlates to increased responsibility of the Distribution System Operators (DSOs) for assessing the flexibility potentials. An aggregation of distribution grid potentials, subject to technical grid constraints and technological power limitations, is termed as Feasible Operating Region (FOR) of the distribution grid. The FOR effectively serves as an interface between the DSOs and the Transmission System Operators (TSO), for flexibility exchanges and planning of ancillary services provision. The determination of the FOR is established in current research, using different algorithms e.g stochastic methods, meta-heuristic programming and mathematical optimization techniques. In this paper, an FOR determination algorithm using successive linear programming (sLP) is proposed and validated against established optimization approaches on a uniform medium voltage (MV) grid model. Comparisons reveal competitiveness with established methods and an added advantage of fast calculation times, suitable for real time assessments. Further enhancement of the FOR is proposed, by integrating discrete transformer tap-changing operational flexibilities using a successive mixed integer linear programming (sMILP). Results demonstrate an increase in the flexibility potential from the distribution grid.

In the context of new policies promoting the use of distributed energy resources (DER) the number of distributed generation (DG) units connected to the medium voltage (MV) and low voltage (LV) distribution grids has largely increased. Distribution companies offer different prices to DG owners depending on the signal quality and time-slot, because the price of sale of generated energy is influenced by the curve of the demand. The use of energy storage systems can help for a larger integration of DG controlling the power flow in the point of common coupling (PCC). From the economical point of view, the possibility to store the electricity when the price is low to sell when it is high makes energy storage an interesting investment for DG owners. In this article is discussed the use of distributed energy storage (DES), paying attention on the control requirements for a larger DG penetration and the economical benefits. The aim of the article is to develop a control strategy to increase economical profits assuring supply quality, for energy storage systems working in parallel to DG units.

A microgrid (MG) is a discrete energy system consisting of an interconnection of distributed energy sources and loads capable of operating in parallel with or independently from the main power grid. The microgrid concept integrated with renewable energy generation and energy storage systems has gained significant interest recently, triggered by increasing demand for clean, efficient, secure, reliable and sustainable heat and electricity. However, the concept of efficient integration of energy storage systems faces many challenges (e.g., charging, discharging, safety, size, cost, reliability and overall management). Additionally, proper implementation and justification of these technologies in MGs cannot be done without energy management systems, which control various aspects of power management and operation of energy storage systems in microgrids. This review discusses different energy storage technologies that can have high penetration and integration in microgrids. Moreover, their working operations and characteristics are discussed. An overview of the controls of energy management systems for microgrids with distributed energy storage systems is also included in the scope of this review.

Distributed energy resources (DERs) and microgrids have seen tremendous growth and research activities in recent years. Flexible DERs and asynchronous microgrids (ASMG) can have many system-level benefits over fixed DERs and conventional microgrids. The key enabler for flexible DERs and ASMG is a power converter based power conditioning system (PCS) as the interface between DERs/microgrids and the medium voltage (MV) distribution grid. High voltage (HV, >3.3 kV) silicon carbide (SiC) based MV converter is now a promising solution for the PCS. This article presents development and testing of a 10 kV SiC MOSFET based MV PCS for 13.8 kV ASMG. MV PCS converter design addressing high dv/dt issue generated by fast switching of the 10 kV SiC MOSFET is presented. The developed PCS is successfully tested at 25 kV dc 13.8 kV ac voltages and 100 kVA power. Grid support functions are also demonstrated with the developed PCS prototype and hardware tests beds, validating HV SiC converter benefits for ASMG.

Design, control, reliability, economic and energy management of microgrid: A review

Single-phase ground faults are the most common faults in medium-voltage distribution grids. High-impedance grid grounding using a special four-leg transformer is discussed in the paper. The transformer's zero-sequence impedance differs from positive-sequence impedance and it is designed to compensate the earth faults currents in Medium Voltage (MV) distribution grids when single-phase ground fault occurs. The designed transformer can replace the traditional arc suppression coils (ASC) in the case where no distribution transformer neutral is available or distributed compensation is required. Alternatively, the transformer can operate in parallel with the ASC.

Modern active distribution grids are characterized by the increasing penetration of distributed energy resources (DERs). Proper coordination and scheduling of these DERs requires a local retail market which can operate at the distribution grid level. In this paper, we propose a retail market for optimally managing and scheduling DERs, and coordinating ancillary services in a distribution grid. Our proposed retail market leverages a recently proposed distributed proximal atomic coordination (PAC) algorithm which has several advantages over other distributed algorithms, with reduced local computational effort and enhanced privacy. We describe how the market can be implemented using a Distribution System Operator (DSO), whose representatives are located at the primary feeder level and workers are located at the substation level, and how the DSO will interact with the Wholesale Electricity Market. Finally, we extensively validate the performance of the proposed retail market via simulations of three networks: a real distribution grid in Tokyo, a balanced IEEE 123-bus distribution grid, and a modified IEEE 13-bus network. Our results show that the proposed market is practical and can be easily implemented in distribution grids, resulting in optimal real-time scheduling of DERs and compensation in the form of distributed locational marginal prices.

Integration of flow battery for resilience enhancement of advanced distribution grids

This paper proposes a two-stage decision-making tool to assess the impacts of energy storage systems (ESSs) and offshore wind farms (OSW) integration in the power grid. To quantify the potential impacts, various key performance indicators (KPIs) are incorporated. These KPIs gage the environmental, technical, and economical attributes of the integrated system. The proposed framework uses a unit commitment (UC) mixed-integer linear programming (MILP) model. Two case studies (one for New Jersey and one for New York) are examined with clean power transition targets. The uncertainties of the net-load and power generation from renewable energy sources (RESs) are characterized by Gaussian Process Regression (GPR) models. These models are fine-tuned using the base forecasts generated using our in-house load forecasting tool and the National Renewable Energy Laboratory’s (NREL) publicly available generation calculator. The results show that ESS installations almost always improve the performance of the grid, regardless of the location and configuration. Furthermore, the unequally distributed ESS installations show better impacts than standalone centralized ESSs; and the mixed ESS technologies outperform single-type ESS deployments.

In the current study, the costs and benefits of deploying energy storage system (ESS) are discussed, and the role of ESS in transmission expansion planning (TEP) is investigated. Based on the classical formulation of TEP, a new formulation is developed considering the simultaneous addition of new circuits and installation of ESS. The fictitious costs of ESS are set instead of actual costs in the proposed model, which can be used to determine the site and size of ESS for transmission investment reduction. The whole formulation is a mixed-integer linear programming problem and can be solved by the well-developed algorithms. The proposed TEP method, which considers the optimal deployment of ESS, has been simulated on three test systems. Test results show the effectiveness of the proposed method and illustrate the potential of installing ESS to reduce network investment costs.

Inverter-based resources (IBRs) are changing the dynamics of medium-voltage distribution grids (MVDGs), leading to concerns over slow-interaction converter-driven stability (SICDS). Although researchers have proposed numerous device-level solutions for IBR stability, culminating in the promotion of grid-forming (GFM) as opposed to grid-following (GFL) inverters, a system-level analysis from the point-of-view of the distribution system operator (DSO) is still lacking. As a first step toward standardization, this article provides some guiding principles for DSOs to prevent SICDS issues in MVDGs, by performing small-signal stability analysis and selecting a set of key parameters from state-of-the-art GFL and GFM models. By imposing bounds for these key parameters, DSOs could manage small-signal interactions between IBRs, as exemplified in the last section of this article over a 2-IBRs study case, later scaled to a multi-inverter configuration with five inverters in a CIGRE medium voltage distribution benchmark network.

This work proposes a method for optimal planning (sizing and siting) energy storage systems (ESSs) in power distribution grids while considering the option of curtailing photo-voltaic (PV) generation. More specifically, for a given PV generation capacity to install, this method evaluates whether curtailing PV generation might be more economical than installing ESS. Indeed, while curtailing excess PV generation might be considered a last resort to avoid grid violations during operations, it is typically neglected in the planning phase. The proposed method accounts for the constraints of the power grid (i.e., nodal voltages, lines, and substation transformer limits) modeled by linearized power flow equations to keep the problem formulation tractable. The planning problem minimizes the net investment costs of the ESSs, and the imported and exported electricity costs considering a planning horizon of 20 years. The results are presented for a medium voltage (MV) distribution grid with different levels of installed capacity of PV generation, reflecting future scenarios of PV generation development. The sensitivity of the ESSs’ sizes and investment costs to the electricity prices accounting for variable levels of PV production in the global generation mix is also investigated.

Expansion planning of joint medium- and low-voltage three-phase distribution networks considering the optimal integration of distributed energy resources