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Increasing use of distributed generation (DG), mainly roof‐top photovoltaic (PV) panels and electric vehicle (EV) charging would cause over‐ and under‐voltage problems generally at the remote sections of the low‐voltage (LV) distribution feeders. As these voltage problems are sustained for a few hours, power electronic compensators (PECs) with input voltage control, i.e. electric springs cannot be used due to the unavailability of non‐critical loads that can be subjected to non‐rated voltages for a long duration of time. However, PECs in output voltage control mode could be used to inject a controllable series voltage either somewhere on the feeder (mid‐feeder compensation, MFC) or between the feeder and each customer (point‐of‐load compensation, PoLC) both of which are effective in tackling the voltage problem without disrupting PV power output and EV charging. In this study, a comparison between the MFC and PoLC option is presented in terms of their voltage control capability, required compensator capacity, network losses, PV throughput, and demand response capability. The criteria for selection of the optimal location of these compensators are also discussed. Stochastic demand profile for different types of residential customers in the UK and a typical European LV network is used for the case study.

Microgrid technology is poised to transform the electricity industry. In the context of commercial/domestic buildings and data centers, where most loads are native direct current, DC microgrids are in fact a natural choice. Voltage stability and current/power‐sharing between sources within a DC microgrid have been studied extensively in recent years. DC voltage droop control is known to have its drawbacks in that current or power‐sharing is relatively poor. To eliminate this drawback, some have proposed to add a communication‐based consensus control in addition to the primary voltage droop control loop. The current sharing performance is improved, however, the voltage deviation inherent in droop control requires a further, slower control to achieve voltage quality control. To overcome this complication, and reduction in response time, a low latency communication‐based control technique that achieves proportional current sharing without significant voltage deviations is proposed in this work. The stability of the proposed control technique is compared to state‐of‐the‐art using eigenvalue and transient analyses. The negative impact of communication delays on proposed control is discussed in detail.

This study introduces a proposed control method for microgrids (MGs) in islanded (off‐grid) mode. The proposed control method is developed by modifying the droop control method using H‐infinity controller. In this control method, the droop control loop, current and voltage control loops are adjusted to respond to system load variation. The proposed method is an adaptive control one as it regulates the system voltage and frequency to their nominal values after system load variations. Also, it is a repetitive control method as it depends on the internal model principle that provides good performance for voltage and current error tracking. To prove the applicability and effectiveness of the proposed method, it is applied to a test system using MATLAB/Simulink under three different loading conditions. The results are compared with those of droop control and they prove the effectiveness of the proposed method in adjusting MGs under the off‐grid mode of operation. Also, a system stability analysis is performed based on root locus and system step response. Robustness analysis is performed to prove the ability of the proposed controller to restore the system performance after the fault clearance.

This paper presents a new data‐driven voltage control approach for distribution networks based on kernel methods. Voltage control becomes more and more challenging due to the increased penetration of Distributed Generation (DG), bidirectional power flow and faster voltage dynamics. State‐of‐art strategies for voltage control rely on physics model‐based Optimal Power Flow (OPF) solutions, which can be implemented in a centralized or distributed manner. Nevertheless, such strategies require a detailed model of the network, and often lack scalability due to the large number of nodes and the limited communication infrastructure in distribution networks. In order to achieve real‐time voltage control in distribution networks of meshed and radial topology, this paper presents a data‐driven approach, which relies on local or regional measurements and does not require accurate models of the grid or an advanced communication infrastructure. Specifically, the proposed data‐driven approach uses functional stochastic gradient descent in Reproducing Kernel Hilbert Spaces (RKHSs), to learn the control strategies for Distributed Generation (DG) units in real‐time that lead to near‐optimal operation costs, while maintaining adequate voltage profiles in the network and alleviating congestions for time‐varying load and generation conditions.

This paper proposes a control strategy for the stable operation of the micro-grid dluring different operating modes while providing the DC voltage control and well quality DC-Ioads supply. The proposed method adapts the battery energy storage system (BESS) to employ the same control architecture for grid-connected mode as well as the islanded operation with no need for knowing the micro-grid operating mode or switching between the corresponding control architectures. Furthermore, the control system presents effective charging of the battery in the micro-grid. When the system is grid connected and during normal operation, AC grid converter balances active power to ensure a constant DC voltage while the battery has the option to store energy for necessary usage. In order to achieve the system operation under islanding conditions, a coordinated strategy for the BESS, RES and load management including load shedding and considering battery state-of-charge (SoC) and battery power limitation is proposed. Seamless transition of the battery converter between charging and discharging, and that of grid side converter between rectification and inversion are ensured for different grid operating modes by the proposed control method. MATLAB/SIMULINK simulations and experimental results are provided to validate the effectiveness of the proposed battery control system.

This paper presents an improved droop-based control strategy for the active and reactive power-sharing on the large-scale Multi-Terminal High Voltage Direct Current (MT-HVDC) systems. As droop parameters enforce the stability of the DC grid, and allow the MT-HVDC systems to participate in the AC voltage and frequency regulation of the different AC systems interconnected by the DC grids, a communication-free control method to optimally select the droop parameters, consisting of AC voltage-droop, DC voltage-droop, and frequency-droop parameters, is investigated to balance the power in MT-HVDC systems and minimize AC voltage, DC voltage, and frequency deviations. A five-terminal Voltage-Sourced Converter (VSC)-HVDC system is modeled and analyzed in EMTDC/PSCAD and MATLAB software. Different scenarios are investigated to check the performance of the proposed droop-based control strategy. The simulation results show that the proposed droop-based control strategy is capable of sharing the active and reactive power, as well as regulating the AC voltage, DC voltage, and frequency of AC/DC grids in case of sudden changes, without the need for communication infrastructure. The simulation results confirm the robustness and effectiveness of the proposed droop-based control strategy.

In this study, a dual‐loop control strategy is applied to a highly distributed architecture of photovoltaic/battery‐based DC microgrid built through an interconnection of a cluster of multiple nanogrids. Typically, in these distributed architectures, resource sharing among the spatially distributed nanogrids is enabled via communication‐based control methodologies, which adds cost and complexity to the overall system. Alternately, a communication‐less and decentralised control methodology is proposed which utilises inner loop current control and outer loop voltage droop (V–I droop) control for the coordinated resource sharing among the distributed resources. The proposed control scheme adapts various modes based on the local measurements of bus voltage and battery state of charge, therefore, offers a distributed solution, omitting the need for centralised communication control. Various scenarios of power sharing among the contributing nanogrids are evaluated through the proposed multi‐mode adaptive control. The efficacy of the proposed control scheme is validated through simulations on MATLAB/Simulink and laboratory scale hardware prototype. Results show that the proposed decentralised control strategy is capable to ensure stable and coordinated operation without any dedicated layer of communication among the dispersed generation/storage resources.

This work proposes multi-objective two-stage distribution optimal power flow (D-OPF) to coordinate the use of smart inverters (SIs) and existing voltage control legacy devices. The first stage of multi-objective D-OPF aims to solve a mixed-integer nonlinear programming (MINLP) formulation that minimizes both voltage variation and active power loss, with SI modes, SI settings, voltage regulator (VR) taps, and capacitor bank (CB) status as control variables. The Pareto Optimal Solutions obtained from the first-stage MINLP are used to determine the optimal active–reactive power dispatch from the SIs by solving a nonlinear programming formulation in the second stage of the proposed D-OPF. This model guarantees that the setpoints for active–reactive power align with the droop characteristics of the SIs, ensuring practicability and the autonomous dispatch of active–reactive power by the SIs according to IEEE 1547-2018. The effectiveness of the proposed method is tested on the IEEE 123 distribution network by contrasting the two proposed D-OPF models, with one prioritizing SIs for voltage control and power loss minimization and the other not prioritizing SIs. The simulation results demonstrate that prioritizing SIs with optimal mode and droop settings can improve voltage control and power loss minimization. The proposed model (with SI prioritization) also reduces the usage of traditional grid control devices and optimizes the dispatch of active–reactive power. The POS also shows that the SI modes, droops, and legacy device settings can be effectively obtained based on the desired objective priority.

Growing penetrations of distributed photovoltaic (PV) generation in low‐voltage electrical networks are raising new challenges for electricity industry operation. Voltage rise is a particular concern and new distributed voltage management techniques have been proposed in the literature. In this study, a novel distributed voltage control method is presented. The method is designed to be used by both PV systems and controllable loads and uses both a voltage and a power set point to manage control. These set points, along with a voltage sensitivity measure, are then used to control PV system generation and load‐shedding. The objective of the control is to keep voltage levels within operational limits with reasonable accuracy. The method is practical; local measurements of net‐power and voltage are used with no additional communication infrastructure required. The proposed method is compared to a power set point only and a voltage set point only control method. Results show the proposed method improves on both methods in terms of both voltage accuracy and the equity of intervention.

A novel circuit topology is proposed for utility‐owned photovoltaic (PV) inverters with integrated battery energy storage system (BESS) and compared to two state‐of‐the‐art configurations. The proposed topology offers flexibility and can be applied to a range of distribution networks for tight voltage regulation. During BESS maintenance, the solar‐storage system reconfigures itself for a self‐run mode of operation, and actively compensates high penetration induced voltage fluctuation without activating overcurrent protection of the inverter, which is an added advantage of this strategy. This advantage is achieved by slightly increasing the inverter size to reserve a portion of inverter's current‐carrying capability. A dynamic model of the new configuration is also developed to analyse its performance in providing fast response for high ramp up/down solar irradiance variation. As the proposed control strategy is implemented at the device level, the local voltage regulation is quite guaranteed to be in the permissible range. Results from the analysis performed on a modified IEEE 33 bus medium voltage distribution network with multiple inverters show evidence that the proposed strategy has the potential to mitigate voltage fluctuation in several extreme cases.